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.

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.

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.

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."

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.

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.

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.

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 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.

(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.

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 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:

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

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

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

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

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.

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.

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.

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."

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

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.

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.

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.

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.

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:

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."

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.


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."


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:


		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."


		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.


		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."


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."

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 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.

			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	)

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):

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:

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.

	Our Predecessor															LRR Energy, L.P. Pro Forma

										Six Months Ended June 30,
	Year Ended December 31,
	Year Ended December 31,															Year Ended December 31, 2010			Six Months Ended June 30, 2011
	2008			2009			2010			2010			2011			Year Ended December 31, 2010			Six Months Ended June 30, 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

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.

		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

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.

		LRR Energy, L.P. Pro Forma

				Six Months Ended June 30,
		Year Ended December 31, 2010		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

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.

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 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.

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.

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 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.

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:

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

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:

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:

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, 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

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

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.

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

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

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.

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:

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.

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

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

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:

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

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:

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

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.

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 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

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:

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

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:

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:

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.

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

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 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

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

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.

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:

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.

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."

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.

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:

(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:

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.

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 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.

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.

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.

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 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.

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.

			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	%

(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

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.

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):

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

				Forecasted

				Three Months Ending
				Three Months Ending								Twelve Months Ending September 30, 2012
				December 31, 2011		March 31, 2012		June 30, 2012		September 30, 2012		Twelve Months Ending 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

			Forecasted

			Three Months Ending
			Three Months Ending								Twelve Months Ending September 30, 2012
			December 31, 2011		March 31, 2012		June 30, 2012		September 30, 2012		Twelve Months Ending 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.

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.

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

			(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

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

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:

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:

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:

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.

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

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

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:

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.

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:

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

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.

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

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

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.

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.

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

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

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."

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.

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

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.

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

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

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.

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.

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.

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

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

(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:

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"):

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

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.

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:

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.

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.

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:

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:

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.

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:

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:

Expiration of the Subordination Period Upon Removal of Our General Partner

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

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 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:

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:

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:

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.

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.

The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and our general partner based on the specified target distribution levels. The amounts set forth under "Marginal Percentage Interest in Distributions" are the percentage interests of our general partner and the unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column "Total Quarterly Distribution Per Unit Target Amount." The percentage interests shown for our unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for our general partner include its 0.1% general partner interest and assume that there are no arrearages on common units, our general partner has contributed any additional capital necessary to maintain its 0.1% general partner interest and our general partner has not transferred its incentive distribution rights.

Our general partner, as the initial holder of our incentive distribution rights, has the right under our partnership agreement to elect to relinquish the right to receive incentive distribution payments based on the initial cash target distribution levels and to reset, at higher levels, the minimum quarterly distribution amount and cash target distribution levels upon which the incentive distribution payments to our general partner would be set. If our general partner transfers all or a portion of our incentive distribution rights in the future, then the holder or holders of a majority of our incentive distribution rights will be entitled to exercise this right. The following discussion assumes that our general partner holds all of the incentive distribution rights at the time that a reset election is made. The right to reset the minimum quarterly distribution amount and the target distribution levels upon which the incentive distributions are based may be exercised, without approval of our unitholders or the conflicts committee, at any time when there are no subordinated units outstanding and we have made cash distributions to the holders of the incentive distribution rights at the highest level of incentive distribution for each of the prior four consecutive fiscal quarters. The reset minimum quarterly distribution amount and target

distribution levels will be higher than the minimum quarterly distribution amount and the target distribution levels prior to the reset such that there will be no incentive distributions paid under the reset target distribution levels until cash distributions per unit following this event increase as described below. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would otherwise not be sufficiently accretive to cash distributions per common unit, taking into account the existing levels of incentive distribution payments being made to our general partner.

In connection with the resetting of the minimum quarterly distribution amount and the target distribution levels and the corresponding relinquishment by our general partner of incentive distribution payments based on the target cash distributions prior to the reset, our general partner will be entitled to receive a number of newly issued common units based on a predetermined formula described below that takes into account the "cash parity" value of the average cash distributions related to the incentive distribution rights received by our general partner for the two quarters prior to the reset event as compared to the average cash distributions per common unit during that two-quarter period. In addition, our general partner will be issued the number of general partner units necessary to maintain our general partner's interest in us at the same level as existed immediately prior to the reset election.

The number of common units that our general partner would be entitled to receive from us in connection with a resetting of the minimum quarterly distribution amount and the target distribution levels then in effect would be equal to the quotient determined by dividing (x) the average aggregate amount of cash distributions received by our general partner in respect of its incentive distribution rights during the two consecutive fiscal quarters ended immediately prior to the date of such reset election by (y) the average of the amount of cash distributed per common unit during each quarter in that two-quarter period.

Following a reset election, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per unit for the two fiscal quarters immediately preceding the reset election (which amount we refer to as the "reset minimum quarterly distribution") and the target distribution levels will be reset to be correspondingly higher such that we would distribute all of our available cash from operating surplus for each quarter thereafter as follows:

The following table illustrates the percentage allocation of available cash from operating surplus between the unitholders and our general partner at various cash distribution levels (i) pursuant to the cash distribution provisions of our partnership agreement in effect at the closing of this offering, as well as (ii) following a hypothetical reset of the minimum quarterly distribution and target distribution levels based on the assumption that the average quarterly cash distribution amount per common unit during the two fiscal quarters immediately preceding the reset election was $0.60.

The following table illustrates the total amount of available cash from operating surplus that would be distributed to the unitholders and our general partner, including in respect of incentive distribution rights, based on an average of the amounts distributed each quarter for the two quarters immediately prior to the reset. The table assumes that immediately prior to the reset there would be 22,377,600 common units outstanding, our general partner has maintained its 0.1% general partner interest, and the average distribution to each common unit would be $0.60 for the two quarters prior to the reset.

The following table illustrates the total amount of available cash from operating surplus that would be distributed to the unitholders and our general partner, including in respect of its incentive distribution rights, with respect to the quarter in which the reset occurs. The table reflects that as a result of the reset there would be 22,712,338 common units outstanding, our general partner's 0.1% interest has been maintained, and the average distribution to each common unit would be $0.60. The number of common units to be issued to our general partner upon the reset was calculated by dividing (i) the average of the amounts received by our general partner in respect of its incentive distribution rights for the two quarters prior to the reset as shown in the table above, or $200,843, by (ii) the average available cash distributed on each common unit for the two quarters prior to the reset as shown in the table above, or $0.60.

Our general partner will be entitled to cause the minimum quarterly distribution amount and the target distribution levels to be reset on more than one occasion, provided that it may not make a reset election except at a time when it has received incentive distributions for the prior four consecutive fiscal quarters based on the highest level of incentive distributions that it is entitled to receive under our partnership agreement.

We will make distributions of available cash from capital surplus, if any, in the following manner:

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

Our partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from this initial public offering, which is a return of capital. The initial public offering price less any distributions of capital surplus per unit is referred to as the "unrecovered initial unit price." Each time a distribution of capital surplus is made, the minimum quarterly distribution and the target distribution levels will be reduced in the same proportion as the corresponding reduction in the unrecovered initial unit price. Because distributions of capital surplus will reduce the minimum quarterly distribution and target distribution levels after any of these distributions are made, it may be easier for our general partner to receive incentive distributions and for the subordinated units to convert into common units. However, any distribution of capital surplus before the unrecovered initial unit price is reduced to zero cannot be applied to the payment of the minimum quarterly distribution or any arrearages.

Once we distribute capital surplus on a unit issued in this offering in an amount equal to the initial unit price, our partnership agreement specifies that the minimum quarterly distribution and the target distribution levels will be reduced to zero. Our partnership agreement specifies that we then make all future distributions from operating surplus, with 76.9% being paid to the holders of units and 23.1% to our general partner. The percentage interests shown for our general partner include its 0.1% general partner interest and assume our general partner has not transferred the incentive distribution rights.

Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels

In addition to adjusting the minimum quarterly distribution and the target distribution levels to reflect a distribution of capital surplus, if we combine our common units into fewer common units or subdivide our common units into a greater number of common units, we will proportionately adjust:

For example, if a two-for-one split of the common units should occur, the minimum quarterly distribution, the target distribution levels and the unrecovered initial unit price would each be reduced to 50% of its initial level. If we combine our common units into a lesser number of units or subdivide our common units into a greater number of units, we will combine or subdivide our subordinated units and general partner units using the same ratio applied to the common units.

In addition, as a result of a change in law or interpretation thereof, we or any of our subsidiaries is treated as an association taxable as a corporation or is otherwise subject to additional taxation as an entity for U.S. federal, state, local or non-U.S. income or withholding tax purposes, our general partner may, in its sole discretion, reduce the minimum quarterly distribution and the target distribution levels for each quarter by multiplying each by a fraction, the numerator of which is available cash for that quarter (after deducting our general partner's estimate of our aggregate liability for the quarter for such income and withholding taxes payable by reason of such change in laws or interpretation) and the denominator of which is the sum of available cash for that quarter plus our general partner's estimate of our aggregate liability for the quarter for such income and withholding taxes payable by reason of such change in laws or interpretation. To the extent that the actual tax liability differs from the estimated tax liability for any quarter, the difference will be accounted for in subsequent quarters.

If we dissolve in accordance with the partnership agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will first apply the proceeds of liquidation to the payment of our creditors. We will distribute any remaining proceeds to our unitholders and our general partner, in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.

The allocations of gain and loss upon liquidation are intended, to the extent possible, to entitle the holders of outstanding common units to a preference over the holders of outstanding subordinated units upon our liquidation, to the extent required to permit common unitholders to receive the price paid for the common units issued in this offering, less any prior distributions of capital surplus in respect of common units issued in this offering, which we refer to as the "unrecovered initial unit price," plus the minimum quarterly distribution for the quarter during which liquidation occurs plus any unpaid arrearages in payment of the minimum quarterly distribution on the common units. However, there may not be sufficient gain upon our liquidation to enable the holders of common units to fully recover all of these amounts, even though there may be cash available for distribution to the holders of subordinated units. Any further net gain recognized upon liquidation will be allocated in a manner that takes into account the incentive distribution rights of our general partner.

The manner of the adjustment for gain is set forth in the partnership agreement. If our liquidation occurs before the end of the subordination period, we will allocate any gain to the partners in the following manner:

The percentage interests set forth above for our general partner include its 0.1% general partner interest and assume our general partner has not transferred the incentive distribution rights.

If our liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that clause (3) of the second bullet point above and all of the third bullet point above will no longer be applicable.

We may make special allocations of gain among the partners in a manner to create economic uniformity among the common units into which the subordinated units convert and the common units held by public unitholders.

If our liquidation occurs before the end of the subordination period, after making allocations of loss to the general partner and the unitholders in a manner intended to offset in reverse order the allocations of gains that have previously been allocated, we will generally allocate any loss to our general partner and the unitholders in the following manner:

If our liquidation occurs after the end of the subordination period, the distinction between common and subordinated units will disappear, so that all of the first bullet point above will no longer be applicable.

Our partnership agreement requires that we make adjustments to capital accounts upon the issuance of additional units. In this regard, our partnership agreement specifies that we allocate any unrealized and, for U.S. federal income tax purposes, unrecognized gain resulting from the adjustments to the unitholders and our general partner in the same manner as we allocate gain upon liquidation. In the event that we make positive adjustments to the capital accounts upon the issuance of additional units, our partnership agreement requires that we generally allocate any later negative adjustments to the capital accounts resulting from the issuance of additional units or upon our liquidation in a manner which results, to the extent possible, in the partners' capital account balances equaling the amount which they would have been if no earlier positive adjustments to the capital accounts had been made. By contrast to the allocations of gain, and except as provided above, we generally will allocate any unrealized and unrecognized loss resulting from the adjustments to capital accounts upon the issuance of additional units to the unitholders and our general partner based on their respective percentage ownership of us. In this manner, prior to the end of the subordination period, we generally will allocate any such loss equally with respect to our common and subordinated units. In the event we make negative adjustments to the capital accounts as a result of such loss, future positive adjustments resulting from the issuance of additional units will be allocated in a manner designed to reverse the prior negative adjustments, and special allocations will be made upon liquidation in a manner that results, to the extent possible, in our unitholders' capital account balances equaling the amounts they would have been if no earlier adjustments for loss had been made.

The selected 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 selected historical financial data as of December 31, 2006, 2007 and 2008 and for the years ended December 31, 2006 and 2007 are derived from audited historical combined financial statements not included herein. 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 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 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 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 "Prospectus Summary — 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.

			Predecessor																					LRR Energy, L.P. Pro Forma

																		Six Months Ended June 30,
																											Six Months Ended June 30, 2011
			Year Ended December 31,
			Year Ended December 31,																					Year Ended December 31, 2010
			2006			2007			2008			2009			2010			2010			2011			Year Ended December 31, 2010
																		(unaudited)						(unaudited)
			(in thousands)
Statement of Operations Data:
Revenues:
	Oil sales		$	2,850		$	5,722		$	58,852		$	34,604		$	52,670		$	25,969		$	34,661		$	31,850		$	20,171
	Natural gas sales			12,283			19,714			100,378			33,798			48,088			25,186			21,754			42,722			19,452
	Natural gas liquids sales			8			367			20,393			10,617			14,748			7,431			7,758			10,935			5,728
	Realized gain (loss) on commodity derivative instruments			2,455			3,622			(2,676	)		70,902			48,029			23,264			41			35,541			29
	Unrealized gain (loss) on commodity derivative instruments			5,967			(13,019	)		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		23,563			16,406			294,722			87,570			139,687			83,936			61,185			103,431			43,253
Operating expenses:
	Lease operating expenses			3,263			5,587			18,781			19,066			23,804			10,443			11,935			19,080			9,301
	Production and ad valorem taxes			1,401			1,956			13,899			6,731			9,320			5,067			3,020			7,755			1,632
	Depletion and depreciation			7,655			11,886			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			72			121			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			8,521			8,500			8,500			6,104			3,803			2,967			—			—
	General and administrative expenses			965			1,086			2,493			2,408			5,293			3,672			3,206			8,901			4,773

		Total operating expenses		21,856			29,157			245,652			92,739			113,218			64,182			42,743			89,057			31,769
Operating income (loss)				1,707			(12,751	)		49,070			(5,169	)		26,469			19,754			18,442			14,374			11,484
Other income (expense), net:
	Interest income			168			542			623			87			17			5			1			—			—
	Interest expense			(1,432	)		(792	)		(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			(1,264	)		(250	)		(2,288	)		(1,549	)		(4,103	)		(1,379	)		(693	)		(4,824	)		(2,412	)

Income (loss) before taxes				443			(13,001	)		46,782			(6,718	)		22,366			18,375			17,749			9,550			9,072
Income tax benefit (expense)				(150	)		—			(971	)		622			(32	)		59			(146	)		—			—

Net income (loss)			$	293		$	(13,001	)	$	45,811		$	(6,096	)	$	22,334		$	18,434			17,603		$	9,550		$	9,072

	Predecessor																					LRR Energy, L.P. Pro Forma

																Six Months Ended June 30,
																								Six Months Ended June 30, 2011
	Year Ended December 31,
	Year Ended December 31,																					Year Ended December 31, 2010
	2006			2007			2008			2009			2010			2010			2011			Year Ended December 31, 2010
																(unaudited)						(unaudited)
	(in thousands)
Other Financial Data:
Adjusted EBITDA	$	3,467		$	12,275		$	133,292		$	113,240		$	119,130		$	58,911		$	43,166		$	85,428	$	29,754
Cash Flow Data:
Net cash provided by (used in) operating activities	$	1,813		$	(6,437	)	$	139,236		$	108,148		$	121,269		$	58,187		$	37,994
Net cash used in investing activities		(147,176	)		(237,865	)		(217,986	)		(25,129	)		(125,846	)		(111,888	)		(23,585	)
Net cash provided by (used in) financing activities		176,696			224,479			117,758			(118,151	)		1,505			62,978			(20,831	)

For a discussion of the non-GAAP financial measure Adjusted EBITDA, please read "Prospectus Summary — Non-GAAP Financial Measures." The following table presents a reconciliation of Adjusted EBITDA to net income and net cash flows provided by operating activities, our most directly comparable GAAP financial performance and liquidity measures, for each of the periods indicated.

	Our Predecessor																					LRR Energy, L.P. Pro Forma

																Six Months Ended June 30,
																									Six Months Ended June 30, 2011
	Year Ended December 31,
	Year Ended December 31,																					Year Ended December 31, 2010
	2006			2007			2008			2009			2010			2010			2011			Year Ended December 31, 2010
																(unaudited)						(unaudited)
	(in thousands)
Net income (loss)	$	293		$	(13,001	)	$	45,811		$	(6,096	)	$	22,334		$	18,434		$	17,603		$	9,550		$	9,072
Income tax expense (benefit)		150			—			971			(622	)		32			(59	)		146			—			—
Interest expense — net, including realized and unrealized losses on interest rate derivative instruments		1,432			792			2,911			1,636			4,120			1,384			694			4,824			2,412
Depletion and depreciation		7,655			11,886			79,477			56,349			55,828			29,584			20,871			40,673			15,397
Accretion of asset retirement obligations		72			121			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		—			13,019			—			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		(168	)		(542	)		(623	)		(87	)		(17	)		(5	)		(1	)		—			—
Unrealized gain on commodity derivative instruments		(5,967	)		—			(117,757	)		—			—			(2,040	)		—			—			—

Adjusted EBITDA	$	3,467		$	12,275		$	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

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

This Management's Discussion and Analysis of Financial Condition and Results of Operations contains the following information:

For purposes of this prospectus, our predecessor is Fund I. The following Management's Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the "Selected Historical and Pro Forma Financial Data" and the accompanying financial statements and related notes included elsewhere in this prospectus. Unless otherwise indicated, all references to financial or operating data on a pro forma basis give effect to the transactions described under "Prospectus Summary — Formation Transactions and Partnership Structure" and in the unaudited pro forma condensed financial statements included elsewhere in this prospectus.

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. Upon completion of this offering, Fund I will sell and contribute to us (1) certain oil and natural gas properties and related net profits interests and operations, which we refer to as the Partnership Properties, and (2) 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.

Following the sale and contribution of the Partnership Properties to us, we will own and operate oil and natural gas producing properties located in New Mexico, Oklahoma and Texas. These properties consist of working interests in 857 gross (691 net) producing wells, of which we owned an approximate 81% average working interest. As of March 31, 2011, our total estimated proved reserves were approximately 30.3 MMBoe, of which approximately 37% were oil and NGLs as measured by volume and approximately 69% were proved developed producing and approximately 15% were proved developed non-producing. As of March 31, 2011, our estimated proved reserves had a standardized measure of $342.3 million. Based on our average pro forma 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 13.5 years.

Of our total estimated proved reserves as of March 31, 2011, 16.6 MMBoe, or approximately 55%, are located in the Permian Basin region; 10.1 MMBoe, or approximately 33%, are located in the Mid-Continent region; and 3.6 MMBoe, or approximately 12%, are located in the Gulf Coast region. On a

pro forma basis, our total estimated proved reserves represented approximately 90% of our predecessor's total estimated proved reserves as of March 31, 2011.

After giving effect to the sale and contribution of the Partnership Properties to us, Fund I will own total estimated proved reserves of 3.3 MMBoe as of March 31, 2011, of which approximately 76% are proved developed reserves, with a standardized measure of $66.2 million and interests in over 156 gross (58 net) active oil and natural gas wells, with pro forma net production of approximately 1,558 Boe/d for the six months ended June 30, 2011. The assets retained by Fund I will consist of properties with characteristics similar to the Partnership Properties. However, Lime Rock Resources has no obligation to offer or sell any of its properties to us following the consummation of this offering.

We use a variety of financial and operational metrics to assess the performance of our oil and natural gas operations, including:

The following table presents historical production volumes for our predecessor's properties for the years ended December 31, 2008, 2009 and 2010 and six months ended June 30, 2010 and 2011 and pro forma production volumes for the Partnership Properties for the year ended December 31, 2010 and six months ended June 30, 2010 and 2011:

Production volumes directly impact our results of operations. For more information about our predecessor's and our pro forma production volumes, please read "— Historical and Pro Forma Financial and Operating Data."

Factors Affecting the Sales Price of Oil, NGLs and Natural Gas. We will market our oil, NGLs and natural gas production to a variety of purchasers based on regional pricing. The relative prices of oil, NGLs and natural gas are determined by the factors impacting global and regional supply and demand dynamics, such as economic conditions, production levels, weather cycles and other events. In addition, relative prices are heavily influenced by product quality and location relative to consuming and refining markets.

Oil Prices. The NYMEX-WTI futures price is a widely used benchmark in the pricing of domestic and imported oil in the United States. The actual prices realized from the sale of oil differ from the quoted NYMEX-WTI price as a result of quality and location differentials. Quality differentials to NYMEX-WTI prices result from the fact that oils differ from one another in their molecular makeup, which plays an important part in their refining and subsequent sale as petroleum products. Among other things, there are two characteristics that commonly drive quality differentials: (1) the oil's American Petroleum Institute, or API, gravity and (2) the oil's percentage of sulfur content by weight. In general, lighter oil (with higher API gravity) produces a larger number of lighter products, such as gasoline, which have higher resale value, and, therefore, normally sells at a higher price than heavier oil. Oil with low sulfur content ("sweet" oil) is less expensive to refine and, as a result, normally sells at a higher price than high sulfur-content oil ("sour" oil).

Location differentials to NYMEX-WTI prices result from variances in transportation costs based on the produced oil's proximity to the major consuming and refining markets to which it is ultimately delivered. Oil that is produced close to major trading and refining markets, such as near Cushing, Oklahoma, is in higher demand as compared to oil that is produced farther from such markets. Consequently, oil that is produced close to major consuming and refining markets normally realizes a higher price (i.e., a lower location differential to NYMEX-WTI).

The oil produced from our properties is a combination of sweet and sour oil, varying by location. We sell our oil at the NYMEX-WTI price, which is adjusted for quality and transportation differential, depending primarily on location and purchaser. The differential varies, but our oil normally sells at a discount to the NYMEX-WTI price.

Natural Gas. The NYMEX-Henry Hub price of natural gas is a widely used benchmark for the pricing of natural gas in the United States. Similar to oil, the actual prices realized from the sale of natural gas differ from the quoted NYMEX-Henry Hub price as a result of quality and location differentials. Quality differentials to NYMEX-Henry Hub prices result from: (1) the Btu content of natural gas, which measures its heating value, and (2) the percentage of sulfur, CO2 and other inert content by volume. Wet natural gas with a high Btu content sells at a premium to low Btu content dry natural gas because it yields a greater quantity of NGLs. Natural gas with low sulfur and CO2 content sells at a premium to natural gas with high sulfur and CO2 content because of the added cost to separate the sulfur and CO2 from the natural gas to render it marketable. The wet natural gas is processed in third-party natural gas plants and residue natural gas as well as NGLs are recovered and sold. The dry natural gas residue from our Partnership Properties is generally sold based on index prices in the region from which it is produced.

Location differentials to NYMEX-Henry Hub prices result from variances in transportation costs based on the natural gas' proximity to the major consuming markets to which it is ultimately delivered. Also affecting the differential is the processing fee deduction retained by the natural gas processing plant generally in the form of percentage of proceeds. Generally, these index prices have historically been at a discount to NYMEX-Henry Hub natural gas prices. The differential varies, but our natural gas normally sells at a discount to the NYMEX-Henry Hub price.

NGLs. Gas produced from a well that is fused with NGLs is referred to as "wet gas." Wet gas is generally sold at the wellhead or transported to a gas processing plant where the NGLs are separated

from the wet gas leaving NGL component products and "dry gas" residue. Both the NGLs and dry gas residue are transported from or sold at a gas processing plant's "tailgate." The NGLs recovered from the processing of our wet gas are sold as blended NGL barrels at a Mont Belvieu or Conway posted price, which is representative of the weighted average market value of the five primary NGL component products. For the majority of the properties that we operate that produce wet gas, we have agreements in place with gas plants in the various regions to process this natural gas in order to receive the revenue benefit of the NGLs that are generated from processing.

In the past, oil and natural gas prices have been extremely volatile, and we expect this volatility to continue. For example, during the year ended December 31, 2010, the NYMEX-WTI oil price ranged from a high of $91.49 per Bbl to a low of $65.96 per Bbl, while the NYMEX-Henry Hub natural gas price ranged from a high of $7.50 per MMBtu to a low of $3.18 per MMBtu. 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.

Commodity Derivative Contracts. 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.

At the closing of this offering, Fund I intends to contribute to us, in conjunction with the sale and contribution of the Partnership Properties, certain commodity derivative contracts covering approximately 85% of our estimated production from total proved developed producing reserves for each of the years ending December 31, 2011 through 2015 based on production estimates in our reserve reports as of March 31, 2011. Please read "— Pro Forma Liquidity and Capital Resources — Partnership Commodity Derivative Contracts."

The following table reflects, with respect to these commodity derivative contracts to be contributed to us, the volumes of our production covered by commodity derivative contracts and the average prices at which the production will be hedged:

				Year Ending December 31,

		Fourth Quarter 2011		Year Ending December 31,
		Fourth Quarter 2011		2012		2013		2014		2015
Oil Derivative Contracts:
	Volume (Bbls/d)		795		688		793		680		602
	Average NYMEX-WTI price per Bbl	$	117.84	$	102.20	$	101.30	$	100.01	$	98.90
Natural Gas Derivative Contracts:
	Volume (MMBtu/d)		19,668		18,047		15,774		13,992		12,592
	Average NYMEX-Henry Hub price per MMBtu	$	6.94	$	5.56	$	5.59	$	5.76	$	5.96
NGL Derivative Contracts:
	Volume (Bbls/d)		516		450		—		—		—
	Average NYMEX-WTI equivalent price per Bbl	$	55.27	$	49.92	$	—	$	—	$	—

Lease Operating Expenses. We strive to increase our production levels to maximize our revenue and cash available for distribution. Lease operating expenses are the costs incurred in the operation of producing properties and workover costs. Expenses for utilities, direct labor, water injection and disposal, and materials and supplies comprise the most significant portion of our lease operating expenses. Lease operating expenses do not include general and administrative costs or production and other taxes.

Certain items, such as direct labor and materials and supplies, generally remain relatively fixed across broad production volume ranges, but can fluctuate depending on activities performed during a specific period. For instance, repairs to our pumping equipment or surface facilities result in increased lease operating expenses in periods during which they are performed.

A majority of our lease operating cost components are variable and increase or decrease as the level of produced hydrocarbons and water increases or decreases. For example, we incur power costs in connection with various production related activities such as pumping to recover oil, NGLs and natural gas, separation and treatment of water produced in connection with our oil, NGLs and natural gas production, and re-injection of water into the oil producing formation for disposal. As these costs are driven not only by volumes of oil, NGLs and natural gas produced but also volumes of water produced, fields that have a high percentage of water production relative to oil, NGLs and natural gas production, also known as a high water cut, will experience higher levels of power costs for each Bbl of oil or NGL or Mcf of natural gas produced. We believe that one of management's areas of core expertise lies in reducing these expenses, thus extending the economic life of the field and improving the cash margin of production.

We monitor our operations to ensure that we are incurring operating costs at the optimal level. Accordingly, we monitor our production expenses and operating costs per well to determine if any wells or properties should be shut in, recompleted or sold. We typically evaluate our oil, NGL and natural gas operating costs on a per Boe basis. This unit rate allows us to monitor these costs in certain fields and geographic areas to identify trends and to benchmark against other producers.

Production and Ad Valorem Taxes. The various states in which we operate regulate the development, production, gathering and sale of oil and natural gas, including imposing production taxes and requirements for obtaining drilling permits. New Mexico currently imposes a production tax on oil and natural gas producers at the rate of approximately 9.0% of the value of the gross product extracted, and the rate may be changed annually. For oil production, Texas currently imposes a production tax at 4.6% of the market value of the oil produced and ³/16 of one cent per Bbl produced. For natural gas, Texas currently imposes a production tax of 7.5% of the market value of the gas. However, a significant portion of the wells in Texas are either currently exempt from production tax due to high cost gas abatement or reduced rate for post production cost recoupment. Oklahoma currently imposes a production tax of 7.5% for oil and natural gas properties. 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 any 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 pursuant to which management, administrative and operating services will be provided to our general partner and us to manage and operate our business. Our general partner will reimburse Lime Rock Management and Lime Rock Resources Operating Company for all costs and services they incur on our general partner's and our behalf, including the $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, our general partner will reimburse each of Lime Rock Management and Lime Rock Resources Operating Company, on a monthly basis, for the allocable expenses it incurs in its performance under the services agreement. For further information regarding the services agreement, please read "Certain Relationships and Related Party Transactions — Agreements Governing the Transactions — Services Agreement"

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:

Adjusted EBITDA should not be considered an alternative to net income, operating income, net cash provided by 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. For further discussion of the non-GAAP financial measure Adjusted EBITDA, please read "Prospectus Summary — Non-GAAP Financial Measures."

Significant factors that may impact future commodity prices include the political and economic developments currently impacting Egypt, Libya and the Middle East in general; the extent to which members of the Organization of Petroleum Exporting Countries and other oil exporting nations are able to continue to manage oil supply through export quotas; and overall North American oil and natural gas supply and demand fundamentals. Although we cannot predict the occurrence of events that will affect future commodity prices or the degree to which these prices will be affected, the prices for any commodity that we produce will generally approximate market prices in the geographic region of the production.

Beginning in the second half of 2008, the United States and other industrialized countries experienced a significant economic slowdown, which led to a substantial decline in worldwide energy

demand. During this same period, North American natural gas supply was increasing as a result of the rise in domestic unconventional natural gas production. The combination of lower energy demand due to the economic slowdown and higher North American natural gas supply resulted in significant declines in oil, NGL and natural gas prices. While oil and NGL prices started to steadily increase beginning in the second quarter of 2009 through 2010, natural gas prices remained low in 2010, relative to much of 2007, 2008 and 2009, due to a continued increase in natural gas supply despite weaker offsetting demand growth. The outlook for a worldwide economic recovery remains uncertain for the foreseeable future, and the timing of a recovery in worldwide demand for energy is difficult to predict. As a result, it is likely that commodity prices will continue to be volatile for the remainder of 2011 and 2012. Sustained periods of low prices for oil or natural gas could materially and adversely affect our financial position, our results of operations, the quantities of oil and natural gas reserves that we can economically produce and our access to capital.

As an oil and natural gas company, we face the challenge of natural production declines. As initial reservoir pressures are depleted, oil and natural gas production from a given well or formation decreases. Our future growth will depend on our ability to continue to add estimated reserves in excess of our production. We plan to maintain our focus on adding reserves through acquisitions and exploitation projects and improving the economics of producing oil and natural gas from our existing fields in lieu of higher-risk exploration projects. We expect that these acquisition opportunities may come from Lime Rock Resources and possibly from Lime Rock Partners and its affiliates and also from unrelated third parties. Our ability to add estimated reserves through acquisitions and exploitation projects is dependent upon many factors, including our ability to successfully identify and close acquisitions, raise capital, obtain regulatory approvals and procure contract drilling rigs and personnel.

The following table sets forth selected historical combined financial and operating data of our predecessor and unaudited pro forma financial and operating data for us for the periods presented. The following table should be read in conjunction with "Selected Historical and Pro Forma Financial Data."

		Predecessor														LRR Energy, L.P. Pro Forma

											Six Months Ended June 30,								Six Months Ended June 30,
		Year Ended December 31,
		Year Ended December 31,														Year Ended December 31, 2010
		2008			2009			2010			2010		2011			Year Ended December 31, 2010			2010		2011
											(unaudited)					(unaudited)
Revenues (in thousands):
Oil sales		$	58,852		$	34,604		$	52,670		$	25,969	$	34,661		$	31,850		$	15,094	$	20,171
Natural gas sales			100,378			33,798			48,088			25,186		21,754			42,722			22,147		19,452
Natural gas liquids sales			20,393			10,617			14,748			7,431		7,758			10,935			5,236		5,728
Realized gain (loss) on commodity derivative instruments			(2,676	)		70,902			48,029			23,264		41			35,541			16,983		29
Unrealized gain (loss) on commodity derivative instruments			117,757			(62,375	)		(23,964	)		2,040		(3,109	)		(17,733	)		1,489		(2,207	)
Other income			18			24			116			46		80			116			46		80

Total revenue		$	294,722		$	87,570		$	139,687		$	83,936	$	61,185		$	103,431		$	60,995	$	43,253

Expenses (in thousands):
Lease operating expenses		$	18,781		$	19,066		$	23,804		$	10,443	$	11,935		$	19,080		$	8,598	$	9,301
Production and ad valorem taxes			13,899			6,731			9,320			5,067		3,020			7,755			3,951		1,632
Depletion and depreciation			79,477			56,349			55,828			29,584		20,871			40,673			20,333		15,397
Impairment of oil and natural gas properties			121,561			—			11,712			10,944		—			11,712			10,944		—
Management fees			8,500			8,500			6,104			3,803		2,967			—	(1)		—		—
General and administrative expenses			2,493			2,408			5,293	(2)		3,672		3,206			8,901	(2)(3)		5,498		4,773
Interest expense			2,131			1,274			3,223			728		559			4,824			2,412		2,412
Realized loss on interest rate derivative instruments			71			457			649			324		298			—			—		—
Production:
	Oil (MBbls)		627			602			698			346		371			424			202		220
	Natural gas (MMcf)		11,750			9,076			11,287			5,532		5,202			10,118			4,880		4,667
	NGLs (MBbls)		372			363			376			183		154			279			129		112

	Total (MBoe)		2,957			2,478			2,955			1,451		1,392			2,389			1,144		1,110
	Average net production (Boe/d)		8,080			6,788	(4)		8,096			8,017		7,691			6,546			6,320		6,133
Average sales price:
Oil (per Bbl):
	Sales price	$	93.86		$	57.48		$	75.46		$	75.05	$	93.43		$	75.12		$	74.72	$	91.69
	Effect of realized commodity derivative instruments(5)		1.16			61.18			23.15			24.64		(26.42	)		28.20			30.80		(31.64	)

	Realized price	$	95.02		$	118.66		$	98.61		$	99.69	$	67.01		$	103.32		$	105.52	$	60.05	(6)
Natural gas (per Mcf):
	Sales price	$	8.54		$	3.72		$	4.26		$	4.55	$	4.18		$	4.22		$	4.54	$	4.17
	Effect of realized commodity derivative instruments(5)		(0.29	)		3.75			2.82			2.66		1.89			2.33			2.20		1.50

	Realized price	$	8.25		$	7.47		$	7.08		$	7.21	$	6.07		$	6.55		$	6.74	$	5.67
NGLs (Per Bbl)		$	54.82		$	29.25		$	39.22		$	40.61	$	50.38		$	39.19		$	40.59	$	51.14
Average unit costs per Boe:
	Lease operating expenses	$	6.35		$	7.70		$	8.06		$	7.20	$	8.57		$	7.99		$	7.52	$	8.38
	Production and ad valorem taxes	$	4.70		$	2.72		$	3.15		$	3.49	$	2.17		$	3.25		$	3.45	$	1.47
	Management fees	$	2.87		$	3.43		$	2.07		$	2.62	$	2.13		$	—			—	$	—
	General and administrative expenses	$	0.84		$	0.97		$	1.79		$	2.53	$	2.30		$	3.73		$	4.81	$	4.30
	Depletion and depreciation	$	26.87		$	22.74		$	18.89		$	20.39	$	14.99		$	17.03		$	17.78	$	13.87

Factors Affecting the Comparability of the Pro Forma Results of Our Operations to the Historical Results of Operations of Our Predecessor

Our pro forma results of operations and our future results of operations may not be comparable to the historical results of operations of our predecessor for the periods presented, primarily for the reasons described below:

Pro Forma Six Months Ended June 30, 2011 Compared to Pro Forma Six Months Ended June 30, 2010

On a pro forma basis, we recorded net income of approximately $9.1 million for the six months ended June 30, 2011 compared to net income of $8.7 million for the six months ended June 30, 2010. Total revenues decreased from the six months ended June 30, 2010, as described below, including a decrease in gains on derivative instruments. Operating expenses decreased from the six months ended June 30, 2010, as described below, primarily due to an impairment charge of $10.9 million recorded in the six months ended June 30, 2010 and an overall decrease in depreciation expense.

Sales Revenues. On a pro forma basis, revenues from oil, NGLs and natural gas sales for the six months ended June 30, 2011 were $45.4 million as compared to $42.5 million for the six months ended June 30, 2010. The increase in revenues was due to an increase in the sale of oil to $20.2 million for the six months ended June 30, 2011 as compared to $15.1 million for the six months ended June 30, 2010. Revenues from the sale of natural gas declined from $22.1 million in the six months ended June 30, 2010 to $19.5 million for the six months ended June 30, 2011. Revenues from the sale of NGLs increased to $5.7 million for the six months ended June 30, 2011 from $5.2 million of revenues for the six months ended June 30, 2010. The overall increase in revenues was primarily driven by increases in oil commodity prices offset by slight declines in our production volumes from the previous period.

Our production volumes for the six months ended June 30, 2011 included 332 MBbls of oil and NGLs and 4,667 MMcf of natural gas, or 1,834 Bbl/d of oil and NGLs and 25,785 Mcf/d of natural gas. On an equivalent net basis, production for the six months ended June 30, 2011 was 1,110 MBoe, or 6,133 Boe/d. In comparison, our production volumes for the six months ended June 30, 2010 included 331 MBbls of oil and NGLs and 4,880 MMcf of natural gas, or 1,829 Bbl/d of oil and NGLs and 26,961 Mcf/d of natural gas. On an equivalent net basis, production for the six months ended June 30, 2010 was 1,144 MBoe, or 6,320 Boe/d.

Our average sales price per Bbl for oil and NGLs, excluding commodity derivative contracts, for the six months ended June 30, 2011 was $91.69 and $51.14, respectively, compared with $74.72 and $40.59, respectively, for the six months ended June 30, 2010. Similarly, our average sales price per Mcf of natural gas, excluding commodity derivative contracts, for the six months ended June 30, 2011 was $4.17 compared with $4.54 per Mcf for the comparable period in 2010.

Since late April 2011, approximately 2 MMcf/d of our predecessor's Pecos Slope field production has been curtailed due to the gas containing a nitrogen percentage greater than our predecessor's gas purchaser's specification. This amount of production represents approximately 35% of the total Pecos Slope field production and approximately 5% of our predecessor's average daily total production for the three months ended June 30, 2011. Our predecessor is actively working with its gas gatherer to reduce the nitrogen percentage to a level within specification. For example, a contract was recently signed for the installation of a nitrogen rejection (membrane) unit. Our predecessor resumed production of approximately 30% of the curtailed production at the end of the third quarter of 2011 when this unit was installed. Full restoration of production is currently expected to occur during the second quarter of 2012 after a fieldwide nitrogen rejection facility is installed by the gas gathering company. The actual timing and amount of resumed production may differ from these estimates.

Effects of Commodity Derivative Contracts. Due to changes in oil and natural gas prices and the termination of certain oil contracts, on a pro forma basis, we recorded a net loss from our commodity hedging program for the six months ended June 30, 2011 of approximately $2.2 million, which is composed of an immaterial realized gain which was offset by an unrealized loss of approximately $2.2 million. For the six months ended June 30, 2010, we recorded a net gain from our commodity hedging program of approximately $18.5 million, consisting of a realized gain of approximately $17.0 million and an unrealized gain of approximately $1.5 million.

Lease Operating Expenses. On a pro forma basis, our lease operating expenses were approximately $9.3 million for the six months ended June 30, 2011 as compared to $8.6 million for the six months ended June 30, 2010. The increase in lease operating expenses was primarily a result of additional expenses at one of our fields in New Mexico related to increased saltwater disposal costs. On a per Boe basis, our unit lease operating expenses increased to $8.38 per Boe produced for the six months ended June 30, 2011 from approximately $7.52 per Boe produced in the six months ended June 30, 2010.

Production and Ad Valorem Taxes. On a pro forma basis, our production and ad valorem taxes decreased to approximately $1.6 million for the six months ended June 30, 2011 compared to approximately $4.0 million for the six months ended June 30, 2010 primarily due to changes in the estimates of the appraisals on which our property taxes are calculated and a severance tax refund of approximately $0.8 million. On a per Boe basis, production and ad valorem taxes decreased to $1.47 per Boe for the six months ended June 30, 2011 as compared to $3.45 per Boe for the six months ended June 30, 2010.

Depletion and Depreciation. On a pro forma basis, our depletion and depreciation expenses were approximately $15.4 million or $13.87 per Boe for the six months ended June 30, 2011 as compared to $20.3 million or $17.78 per Boe for the six months ended June 30, 2010. The overall decrease was

primarily a result of a $10.9 million impairment charge recorded in the first quarter of 2010 and an increase in reserves during 2011.

Impairment of Oil and Natural Gas Properties. An impairment of $10.9 million was required during the six months ended June 30, 2010 due to a decline in commodity prices in the first quarter of 2010. No impairment was required during the six months ended June 30, 2011.

General and Administrative Expenses. On a pro forma basis, our general and administrative expenses were approximately $4.8 million for the six months ended June 30, 2011 as compared to $5.5 million for the six months ended June 30, 2010. The decrease was primarily driven by a $2.5 million finder's fee incurred in connection with the Potato Hills acquisition in 2010 offset by $2.0 million in transaction costs associated with this offering. The general and administrative costs were $4.30 per Boe produced for the six months ended June 30, 2011 compared to $4.81 per Boe produced for the six months ended June 30, 2010.

Interest Expense. On a pro forma basis, our interest expense is comprised of interest on our anticipated credit facility and debt issuance costs. The interest expense was $2.4 million for the six months ended June 30, 2011 and 2010.

We expect that our primary sources of liquidity and capital resources after the consummation of the offering will be cash flows generated by operating activities and borrowings under the new credit facility that we intend to enter into concurrently with the closing of this offering. We may also have the ability to issue additional equity and debt as needed.

We plan to enter into hedging arrangements to reduce the impact of commodity price volatility on our cash flow from operations. Under this strategy, we intend to enter 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 in time, although we may from time to time hedge more or less than this approximate range.

Our partnership agreement requires that we distribute all of our available cash (as defined in the partnership agreement) to our unitholders and the general partner. In making cash distributions, our general partner will attempt to avoid large variations in the amount we distribute from quarter to quarter. In order to facilitate this, our partnership agreement will permit our general partner to establish cash reserves to be used to pay distributions for any one or more of the next four quarters. In addition, our partnership agreement allows our general partner to borrow funds to make distributions.

We may borrow to make distributions to our 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 sustain our level of distributions. In addition, we plan to hedge a significant portion of our production. We generally will be required to settle our commodity hedge derivatives within five days of the end of the month. As is typical in the oil and gas industry, we do not generally receive the proceeds from the sale of our hedged production until 45 to 60 days following the end of the month. As a result, when commodity prices increase above the fixed price in the derivative contracts, we will be required to pay the derivative counterparty the difference between the fixed price in the derivative contract and the market price before we receive the proceeds from the sale of the hedged production. If this occurs, we may make working capital borrowings to fund our distributions. Because we will distribute all of our available cash, we will not have those amounts available to reinvest in our business to increase our proved reserves and production and as a result, we may not grow as quickly as other oil and gas entities or at all.

We plan to reinvest a sufficient amount of our cash flow to fund our exploitation and development capital expenditures in order to maintain our production, and we plan to primarily use 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 make acquisitions to further increase our production and proved reserves. Because our proved reserves and production decline continually over time and because we do not own any undeveloped properties or leasehold acreage, we will need to make acquisitions to sustain our level of distributions to unitholders over time.

If cash flow from operations does not meet our expectations, we may reduce our expected level of capital expenditures, reduce distributions to unitholders, and/or fund a portion of our capital expenditures using borrowings under our credit facility, issuances of debt and equity securities or from other sources, such as asset sales. We cannot assure you that needed capital will be available on acceptable terms or at all. Our ability to raise funds through the incurrence of additional indebtedness could be limited by the covenants in our credit facility. If we are unable to obtain funds when needed or on acceptable terms, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to maintain our production or proved reserves.

Maintenance capital expenditures are capital expenditures that we expect to make on an ongoing basis to maintain 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. The primary purpose of maintenance capital is to maintain our production at a steady level over the long term to maintain our distributions per unit. For the twelve months ending September 30, 2012, we have estimated our maintenance capital expenditures to be $18.0 million.

Growth capital expenditures are capital expenditures that we expect to increase our production and the size of our asset base. The primary purpose of growth capital expenditures is to acquire producing assets that will increase our distributions per unit and secondarily increase the rate of development and production of our existing properties in a manner that is expected to be accretive to our unitholders. Growth capital expenditures on existing properties may include projects on our existing asset base. Although we may make acquisitions during the twelve-month forecast period ending September 30, 2012, including potential acquisitions of producing properties from Lime Rock Resources, we have not estimated any growth capital expenditures related to potential opportunistic acquisitions because we cannot be certain that we will be able to identify attractive properties or, if identified, that we will be able to negotiate acceptable purchase contracts. For more information regarding our acquisition strategy, please read "Business and Properties — Our Business Strategies — Leverage our relationship with Lime Rock Resources to provide additional acquisition opportunities through drop-down transactions and joint acquisitions" and "— Our Principal Business Relationships — Our Relationship with Lime Rock Resources."

The amount and timing of our capital expenditures is largely discretionary and within our general partner's control, with the exception of certain projects managed by other operators. If oil and natural gas prices decline below levels we deem acceptable, our general partner may defer a portion of our planned capital expenditures until later periods. Accordingly, we routinely monitor and adjust our capital expenditures in response to changes in oil and natural gas prices, drilling and acquisition costs, industry conditions and internally generated cash flow. Matters outside of our control that could affect the timing of our capital expenditures include obtaining required permits and approvals in a timely manner and the availability of rigs and labor crews. Based on our current oil and natural gas price expectations, we anticipate that our cash flow from operations and available borrowing capacity under our new credit facility will exceed our planned capital expenditures and other cash requirements for the twelve months ending September 30, 2012. However, future cash flows are subject to a number of variables, including the level of our oil and natural gas production and the prices we receive for our oil and natural gas production, generally. There can be no assurance that our operations and other capital resources will provide cash in amounts that are sufficient to maintain our planned levels of capital expenditures.

Concurrently with the closing of this offering, we anticipate that we, as guarantor, our wholly owned subsidiary, LRE Operating, LLC, as borrower, and any other future subsidiaries, as guarantors, will enter into a new senior secured revolving credit facility. We expect the new credit facility to be a five-year, $500 million revolving credit facility with an initial borrowing base of $250 million.

Our new credit facility will be reserve-based, and thus we will be permitted to borrow under our new credit facility in an amount up to the borrowing base, which is primarily based on the estimated value of our oil, NGL and natural gas properties and our commodity derivative contracts as determined semi-annually by our lenders in their sole discretion. Our borrowing base will be subject to redetermination on a semi-annual basis based on an engineering report with respect to our estimated oil, NGL and natural gas reserves, which will take into account the prevailing oil, NGL and natural gas prices at such time, as adjusted for the impact of our commodity derivative contracts. Unanimous approval by the lenders will be required for any increase to the borrowing base. In the future, we may be unable to access sufficient capital under our new credit facility as a result of (i) a decrease in our borrowing base due to a subsequent borrowing base redetermination or (ii) an unwillingness or inability on the part of our lenders to meet their funding obligations.

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, or we could be required to pledge other oil and natural gas properties as additional collateral. We do not anticipate having any substantial unpledged properties, and we may not have the financial resources in the future to make any mandatory principal prepayments required under our new credit facility. Additionally, we will not be able to pay distributions to our unitholders in any such quarter in the event there exists a borrowing base deficiency or an event of default either before or after giving effect to such distribution or we are not in pro forma compliance with the credit facility after giving effect to such distribution.

Borrowings under the new credit facility will be secured by liens on substantially all of our properties, but in any event, not less than 80% of the PV-10 value of our oil and natural gas properties, and all of our equity interests in LRE Operating, LLC and any future guarantor subsidiaries and all of our other assets including personal property. Additionally, borrowings under the new credit facility will bear interest, at our option, at either (i) the greater of the prime rate as determined by the administrative agent, the federal funds effective rate plus 0.50%, and the 30-day adjusted LIBOR plus 1.0%, all of which would be subject to a margin that varies from 0.75% to 1.75% per annum according to the borrowing base usage (which is the ratio of outstanding borrowings and letters of credit to the borrowing base then in effect), or (ii) the applicable LIBOR plus a margin that varies from 1.75% to 2.75% per annum according to the borrowing base usage. The unused portion of the borrowing base will be subject to a commitment fee that varies from 0.375% to 0.50% per annum according to the borrowing base usage.

Our new credit facility will require maintenance of a ratio of Total Funded Indebtedness to Adjusted EBITDA (as each term is defined in the new credit facility), which we refer to as the leverage ratio, of not more than 4.0 to 1.0x, and a ratio of consolidated current assets to consolidated current liabilities, which we refer to as the current ratio, of not less than 1.0 to 1.0x.

Additionally, the new credit facility will contain various covenants and restrictive provisions which limit our ability to incur additional debt, guarantees or liens; consolidate, merge or transfer all or substantially all of our assets; make certain investments, acquisitions or other restricted payments; modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; to incur commodity hedges exceeding a certain percentage of our production; and prepay certain indebtedness.

Events of default under the credit facility shall include, but not be limited to, failure to make payments when due; breach of any covenants continuing beyond the cure period; default under any

other material debt; change in management or change of control; bankruptcy or other insolvency event; and certain material adverse effects on our business.

If we fail to perform our obligations under these and other covenants, the revolving credit commitments could be terminated and any outstanding indebtedness under the new credit facility, together with accrued interest, could be declared immediately due and payable.

Our predecessor has entered into commodity derivative contracts covering approximately 85% of our estimated production from total proved developed producing reserves for each of the years ending December 31, 2011 through 2015 based on estimates in our reserve reports as of March 31, 2011, and such contracts will be contributed to us at the closing of this offering. We also intend to enter into additional hedging arrangements in the future. We have allocated a portion of our historical derivative contracts to our pro forma financial statements for the year ended December 31, 2010 and the six months ended June 30, 2011 and 2010 based on a percentage of the revenues attributable to the properties contributed to us for the periods presented. Please see "Prospectus Summary — 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, although we may from time to time hedge more or less than this approximate range. As opposed to entering into commodity derivative contracts at predetermined times or on prescribed terms, we intend to enter into commodity derivative contracts in connection with material increases in our estimated reserves and at times when we believe market conditions or other circumstances suggest that it is prudent to do so. Additionally, we may take advantage of opportunities to modify our commodity derivative portfolio to change the percentage of our hedged production volumes when circumstances suggest that it is prudent to do so. These instruments limit our exposure to declines in prices, but also limit the benefits if prices increase. We do not specifically designate commodity derivative contracts as cash flow hedges; therefore, the mark-to-market adjustment reflecting the change in the unrealized gains or losses on these contracts is recorded in current period earnings. When prices for oil and natural gas are volatile, a significant portion of the effect of our hedging activities consists of non-cash income or expenses due to changes in the fair value of our commodity derivative contracts. Realized gains or losses only arise from payments made or received on monthly settlements or if a commodity derivative contracts is terminated prior to its expiration. Please read "— Pro Forma Liquidity and Capital Resources — Partnership Commodity Derivative Contracts."

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks.

The term "market risk" refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.

Our major market risk exposure is in the pricing that we receive for our oil, NGL and natural gas production. Realized pricing is primarily driven by the spot market prices applicable to our oil and natural gas production. Pricing for oil and natural gas has been volatile for several years, and we expect

this volatility to continue in the future. The prices we receive for our oil and natural gas production depend on many factors outside of our control, such as the strength of the global economy.

In order to reduce the impact of fluctuations in oil, NGL and natural gas prices on our revenues, or to protect the economics of property acquisitions, we intend to periodically enter into commodity derivative contracts with respect to a significant portion of our estimated production from total proved developed producing reserves through various transactions that fix the future prices received. These transactions may include price swaps whereby we will receive a fixed price for our production and pay a variable market price to the contract counterparty. Additionally, we may enter into collars, whereby we receive the excess, if any, of the fixed floor over the floating rate or we pay the excess, if any, of the floating rate over the fixed ceiling price. These hedging activities are intended to support oil, NGL and natural gas prices at targeted levels and to manage our exposure to oil, natural gas and NGL price fluctuations. We do not hold or issue derivative instruments for speculative trading purposes. We anticipate that our new credit facility will allow us to enter into financial swaps and financial collar contracts on not more than 85% of estimated production from total proved developed producing reserves.

Swaps. In a typical commodity swap agreement, including basis swaps, we receive the difference between a fixed price per unit of production and a price based on an agreed upon published third-party index, if the index price is lower than the fixed price. If the index price is higher than the fixed price, we pay the difference. By entering into swap agreements, we effectively fix the price that we will receive in the future for the hedged production. Our swaps are settled in cash on a monthly basis.

Collars. In a typical collar arrangement, we receive the excess, if any, of the floor price over the reference price, based on NYMEX quoted prices, and pay the excess, if any, of the reference price over the ceiling price.

By removing the price volatility from a significant portion of our oil, NGL and natural gas production, we expect to mitigate, but not eliminate, the potential effects of changing prices on our cash flow from operations. While mitigating negative effects of falling commodity prices, these derivative contracts will also limit the benefits we would receive from increases in commodity prices.

On a pro forma basis as of June 30, 2011, we had debt outstanding of $155.8 million, with an assumed weighted average interest rate of LIBOR plus 2.25%, or 2.55%. Assuming no change in the amount outstanding, the impact on interest expense of a 10% increase or decrease in the average interest rate would be approximately $0.4 million per year. In the future, we anticipate entering into interest rate derivative contracts on a portion of our outstanding debt to mitigate the risk of fluctuations in LIBOR.

Our oil and natural gas derivative contracts expose us to credit risk in the event of nonperformance by counterparties. While we will not require the counterparties to our derivative contracts to post collateral, it is our policy to enter into derivative contracts only with counterparties that are major, creditworthy financial institutions deemed by management as competent and competitive market makers. We will evaluate the credit standing of such counterparties as we deem appropriate. This evaluation includes reviewing a counterparty's credit rating and latest financial information. We expect that the counterparties to our derivative contracts will be lenders under our new credit facility, with investment grade ratings. We are likely to enter into future derivative contracts with these or other lenders under our new credit facility that also carry investment grade ratings.

We are also subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. However,

our customer base consists primarily of integrated and international oil and natural gas companies, as well as smaller processors and gatherers and we believe the credit quality of our customers is high.

Joint interest receivables arise from entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we drill. We have limited ability to control participation in our wells.

Factors Affecting the Comparability of the Historical Financial Results of Our Predecessor

The comparability of our predecessor's results of operations among the periods presented is impacted by:

As a result of the factors listed above, historical results of operations and period-to-period comparisons of these results and certain financial data may not be comparable or indicative of future results.

Six Months Ended June 30, 2011 Compared to the Six Months Ended June 30, 2010

Our predecessor recorded net income of approximately $17.6 million for the six months ended June 30, 2011 compared to net income of $18.4 million for the six months ended June 30, 2010. Total revenues decreased from the six months ended June 30, 2010, as described below, including a decrease in gains on derivative instruments. Operating expenses decreased from the six months ended June 30, 2010, as described below, primarily due to an impairment charge of $10.9 million recorded in the six months ended June 30, 2010 and an overall decrease in depreciation expense.

Sales Revenues. Revenues from oil, NGLs and natural gas sales for the six months ended June 30, 2011 were $64.2 million as compared to $58.6 million for the six months ended June 30, 2010. The increase in revenues was due to an increase in the sale of oil of $34.7 million for the six months ended June 30, 2011 as compared to $26.0 million for the six months ended June 30, 2010. Revenues from the sale of natural gas declined from $25.2 million in the six months ended June 30, 2010 to $21.8 million for the six months ended June 30, 2011. Revenues from the sale of NGLs of $7.8 million for the six months ended June 30, 2011 were consistent with $7.4 million of revenues for the six months ended June 30, 2010. The overall increase in revenues was primarily driven by increases in oil commodity prices offset by slight declines in our predecessor's production volumes from the previous period.

Our predecessor's production volumes for the six months ended June 30, 2011 included 525 MBbls of oil and NGLs and 5,202 MMcf of natural gas, or 2,901 Bbl/d of oil and NGLs and 28,740 Mcf/d of natural gas. On an equivalent net basis, production for the six months ended June 30, 2011 was

1,392 MBoe, or 7,691 Boe/d. In comparison, our predecessor's production volumes for the six months ended June 30, 2010 included 529 MBbls of oil and NGLs and 5,532 MMcf of natural gas, or 2,923 Bbl/d of oil and NGLs and 30,564 Mcf/d of natural gas. On an equivalent net basis, production for the six months ended June 30, 2010 was 1,451 MBoe, or 8,017 Boe/d.

Our predecessor's average sales price per Bbl for oil and NGLs, excluding commodity derivative contracts, for the six months ended June 30, 2011 was $93.43 and $50.38, respectively, compared with $75.05 and $40.61, respectively, for the six months ended June 30, 2010. Similarly, our predecessor's average sales price per Mcf of natural gas, excluding commodity derivative contracts, for the six months ended June 30, 2011 was $4.18 compared with $4.55 per Mcf for the comparable period in 2010.

Since late April 2011, approximately 2 MMcf/d of our predecessor's Pecos Slope field production has been curtailed due to the gas containing a nitrogen percentage greater than our predecessor's gas purchaser's specification. This amount of production represents approximately 35% of the total Pecos Slope field production and approximately 5% of our average daily total production for the three months ended June 30, 2011. Our predecessor is actively working with its gas gatherer to reduce the nitrogen percentage to a level within specification. For example, a contract was recently signed for the installation of a nitrogen rejection (membrane) unit. Our predecessor resumed production of approximately 30% of the curtailed production at the end of the third quarter of 2011 when this unit was installed. Full restoration of production is currently expected to occur during the second quarter of 2012 after a fieldwide nitrogen rejection facility is installed by the gas gathering company. The actual timing and amount of resumed production may differ from these estimates.

Effects of Commodity Derivative Contracts. Due to changes in oil and natural gas prices and the termination of certain oil contracts, our predecessor recorded a net loss from its commodity hedging program for the six months ended June 30, 2011 of approximately $3.1 million, which is composed of an immaterial realized gain that was offset by an unrealized loss of approximately $3.1 million. For the six months ended June 30, 2010, our predecessor recorded a net gain from its commodity hedging program of approximately $25.3 million, consisting of a realized gain of approximately $23.3 million and an unrealized gain of approximately $2.0 million.

Lease Operating Expenses. Our predecessor's lease operating expenses were approximately $11.9 million for the six months ended June 30, 2011 as compared to $10.4 million for the six months ended June 30, 2010. The increase in lease operating expenses was primarily a result of additional expenses at one of our fields in New Mexico related to increased saltwater disposal costs. On a per Boe basis, our predecessor's unit lease operating expenses increased to $8.57 per Boe produced for the six months ended June 30, 2011 from approximately $7.20 per Boe produced for the six months ended June 30, 2010.

Production and Ad Valorem Taxes. Production and ad valorem taxes decreased to approximately $3.0 million for the six months ended June 30, 2011 compared to approximately $5.1 million for the six months ended June 30, 2010 primarily due to changes in the estimates of the appraisals on which our property taxes are calculated and a severance tax refund of approximately $0.8 million. On a per Boe basis, production and ad valorem taxes decreased to $2.17 per Boe for the six months ended June 30, 2011 as compared to $3.49 per Boe for the six months ended June 30, 2010.

Depletion and Depreciation. Our predecessor's depletion and depreciation expenses were approximately $20.9 million or $14.99 per Boe for the six months ended June 30, 2011 as compared to $29.6 million or $20.39 per Boe for the six months ended June 30, 2010. The overall decrease was primarily a result of a $10.9 million impairment charge recorded in the first quarter of 2010 and an increase in reserves during 2011.

Management Fees. Our predecessor incurs a management fee paid to Lime Rock Management in addition to the direct general and administrative expenses it incurs. The management fee is determined by a formula based on the predecessor's limited partners' invested capital or the equity capital commitment in Fund I. The predecessor's management fees were approximately $3.0 million for the six months ended June 30, 2011 compared to approximately $3.8 million for the six months ended June 30, 2010. The overall decrease of $0.8 million was primarily a result of changing the formula based on equity capital commitments to invested capital due to meeting certain requirements as outlined in the predecessor's partnership agreements with its limited partners.

General and Administrative Expenses. Our predecessor's general and administrative expenses were approximately $3.2 million for the six months ended June 30, 2011 as compared to $3.7 million for the six months ended June 30, 2010. The decrease was primarily driven by a $2.5 million finder's fee incurred in connection with the Potato Hills acquisition in 2010 offset by $2.0 million in transaction costs associated with this offering. The general and administrative costs were $2.30 per Boe produced for the six months ended June 30, 2011 and $2.53 per Boe produced for the six months ended June 30, 2010.

Interest Expense. Our predecessor's interest expense is comprised of interest on its credit facility, debt issuance costs and realized gains (losses) on its interest rate derivative instruments. The interest expense was $0.9 million for the six months ended June 30, 2011 as compared to $1.1 million for the six months ended June 30, 2010.

Our predecessor recorded net income of approximately $22.3 million for the year ended December 31, 2010 compared to a net loss of $6.1 million for the year ended December 31, 2009. This increase in net income was primarily driven by an increase in revenues as described below, including an increase in gains on derivative instruments partially offset by an increase in operating costs, reflecting the change in size of operations during the year ended December 31, 2010.

Sales Revenues. Revenues from oil, NGLs and natural gas sales for the year ended December 31, 2010 were $115.5 million as compared to $79.0 million for the year ended December 31, 2009. The increase in revenues was due to an increase in the sale of oil, NGLs and natural gas of $52.7 million, $14.7 million and $48.1 million for the year ended December 31, 2010 as compared to $34.6 million, $10.6 million and $33.8 million for the year ended December 31, 2009. The overall increase in revenues was primarily driven by increases in commodity sales prices and our predecessor's production volumes, including the impact of the Potato Hills acquisition, which closed in February 2010 and resulted in increases in revenues of $15.0 million for the year ended December 31, 2010.

Our predecessor's production volumes for the year ended December 31, 2010 included 1,074 MBbls of oil and NGLs and 11,287 MMcf of natural gas, or 2,942 Bbl/d of oil and NGLs and 30,923 Mcf/d of natural gas. On an equivalent net basis, production for the year ended December 31, 2010 was 2,955 MBoe, or 8,096 Boe/d. In comparison, our predecessor's production volumes for the year ended December 31, 2009 included 965 MBbls of oil and NGLs and 9,076 MMcf of natural gas, or 2,643 Bbl/d of oil and NGLs and 24,866 Mcf/d of natural gas. On an equivalent net basis, production for the year ended December 31, 2009 was 2,478 MBoe, or 6,788 Boe/d. The primary driver behind the increase in overall production volumes was the Potato Hills acquisition completed in February 2010.

Our predecessor's average sales price per Bbl for oil and NGLs, excluding commodity derivative contracts, for the year ended December 31, 2010 was $75.46 and $39.22, respectively, compared with $57.48 and $29.25, respectively, for the year ended December 31, 2009. Similarly, our predecessor's average sales price per Mcf of natural gas, excluding commodity derivative contracts, for the year ended December 31, 2010 was $4.26 compared with $3.72 per Mcf for the year ended December 31, 2009.

Effects of Commodity Derivative Contracts. Due to changes in oil and natural gas prices, our predecessor recorded a net gain from its commodity hedging program for the year ended December 31, 2010 of approximately $24.0 million, which is composed of a realized gain of approximately $48.0 million, partially offset by an unrealized loss of approximately $24.0 million. For the year ended December 31, 2009, our predecessor recorded a net gain from its commodity hedging program of approximately $8.5 million, consisting of a realized gain of approximately $70.9 million, partially offset by an unrealized loss of approximately $62.4 million.

Lease Operating Expenses. Our predecessor's lease operating expenses were approximately $23.8 million for the year ended December 31, 2010 as compared to $19.1 million for the year ended

December 31, 2009. The increase in lease operating expenses was primarily a result of our predecessor's increased production volumes described above and $3.4 million in additional lease operating expenses as a result of the properties acquired in the Potato Hills acquisition. On a per Boe basis, our predecessor's unit lease operating expenses increased to $8.06 per Boe produced for the year ended December 31, 2010 from approximately $7.70 per Boe produced for the year ended December 31, 2009. The increased expenses were partially offset by the increased production volumes.

Production and Ad Valorem Taxes. Production and ad valorem taxes increased to approximately $9.3 million for the year ended December 31, 2010 compared to approximately $6.7 million for the year ended December 31, 2009 primarily due to an increase in revenues discussed above. On a per Boe basis, production and ad valorem taxes increased to $3.15 per Boe for the year ended December 31, 2010 as compared to $2.72 per Boe for the year ended December 31, 2009.

Depletion and Depreciation Expenses. Our predecessor's depletion and depreciation expenses were approximately $55.8 million, or $18.89 per Boe, for the year ended December 31, 2010 as compared to $56.3 million or $22.74 per Boe for the year ended December 31, 2009. The overall decrease was primarily a result of the 2010 impairment described below and the decline in commodity prices in the first quarter of 2010.

Impairment of Oil and Natural Gas Properties. An impairment of $11.7 million was required during the year ended December 31, 2010 due to a decline in commodity prices in the first quarter of 2010. No impairment was required in 2009.

Management Fees. Our predecessor incurs a management fee paid to Lime Rock Management in addition to the direct general and administrative expenses it incurs. The management fee is determined by a formula based on the predecessor's limited partners' invested capital or the equity capital commitment in Fund I. The predecessor's management fees were approximately $6.1 million for the year ended December 31, 2010 compared to approximately $8.5 million for the year ended December 31, 2009. The overall decrease of $2.4 million was primarily a result of changing the formula based on equity capital commitments to invested capital due to meeting certain requirements as outlined in the predecessor's partnership agreements with its limited partners.

General and Administrative Expenses. Our predecessor's general and administrative expenses were approximately $5.3 million for the year ended December 31, 2010 as compared to $2.4 million for the year ended December 31, 2009. The increase was primarily driven by a $2.5 million finder's fee incurred in connection with the Potato Hills acquisition in 2010. General and administrative expenses, on a per Boe basis, increased in 2010 for the reasons just discussed, but were partially decreased as a function of the higher production volumes. The general and administrative expenses per Boe were $1.79 for the year ended December 31, 2010 and $0.97 per Boe produced for the year ended December 31, 2009.

Interest Expense. Our predecessor's interest expense is comprised of interest on its credit facility, debt issuance and financing costs, and realized gains (losses) on its interest rate derivative instruments. The interest expense was $3.9 million for the year ended December 31, 2010 as compared to $1.7 million for the year ended December 31, 2009. This increase was primarily due to increased borrowings of $3.1 million and the refinancing of the credit facility.

Our predecessor recorded a net loss of approximately $6.1 million for the year ended December 31, 2009 compared to net income of approximately $45.8 million for the year ended December 31, 2008. The net loss of $6.1 million for the year ended December 31, 2009 was primarily driven by (i) substantial changes in average sales price for oil of $57.48 per Bbl for the year ended December 31, 2009 compared to $93.86 per Bbl for the year ended December 31, 2008; average sales price for natural gas of $3.72 per

Mcf for the year ended December 31, 2009 compared to $8.54 per Mcf for the year ended December 31, 2008; and average sales price for NGLs of $29.25 for the year ended December 31, 2009 compared to $54.82 for the year ended December 31, 2008 and (ii) $62.4 million of unrealized commodity losses for the year ended December 31, 2009 compared to unrealized commodity gains of $117.8 million for the year ended December 31, 2008. The losses for the year ended December 31, 2009 were partially offset by (i) a $70.9 million realized commodity gain for the year ended December 31, 2009 compared to a $2.7 million realized commodity loss for the year ended December 31, 2008, (ii) depletion and depreciation of $56.3 million for the year ended December 31, 2009 compared to $79.5 million for the year ended December 31, 2008, and (iii) no impairment of oil and natural gas properties for the year ended December 31, 2009 compared to $121.6 million for the year ended December 31, 2008.

Sales Revenues. Revenues from oil, NGLs and natural gas sales for the year ended December 31, 2009 were $79.0 million as compared to $179.6 million for the year ended December 31, 2008. The decrease in revenues was due to a decrease in the sale of oil, NGLs and natural gas of $34.6 million, $10.6 million and $33.8 million for the year ended December 31, 2009 as compared to $58.9 million, $20.4 million and $100.4 million for the year ended December 31, 2008. The overall decrease in oil and NGLs revenue was primarily driven by a significant decrease in sales prices for oil and NGLs, and the decrease in revenues from the sale of natural gas was primarily due to significantly lower natural gas prices and lower production volumes.

Our predecessor's production volumes for the year ended December 31, 2009 were 965 MBbls of oil and NGLs and 9,076 MMcf of natural gas. On an equivalent net basis, 2009 production was 2,478 MBoe, or 6,788 Boe/d. In comparison, our predecessor's production volumes for the year ended December 31, 2008 were 999 MBbls of oil and NGLs and 11,750 MMcf of natural gas. On an equivalent net basis, 2008 production was 2,957 MBoe, or 8,080 Boe/d. The primary driver behind the decrease in overall production volumes was the natural decline of our predecessor's reserves and decrease in commodity prices.

Our predecessor's average sales price per Bbl for oil and NGLs, excluding commodity derivative contracts, for the year ended December 31, 2009 was $57.48 and $29.25, respectively, compared with $93.86 and $54.82, respectively, for the year ended December 31, 2008. Average sales prices for natural gas, excluding commodity derivative contracts, was $3.72 and $8.54 per Mcf in 2009 and 2008, respectively.

Effects of Commodity Derivative Contracts. Due to changes in oil and natural gas prices, our predecessor recorded a net gain from its commodity hedging program for the year ended December 31, 2009 of approximately $8.5 million, which was comprised of a realized gain of approximately $70.9 million reduced by an unrealized loss of approximately $62.4 million. In contrast, our predecessor recorded a net gain of approximately $115.1 million from its commodity hedging program for the year ended December 31, 2008, which was comprised of an unrealized gain of approximately $117.8 million, partially offset by a realized loss of approximately $2.7 million.

Lease Operating Expenses. Our predecessor's lease operating expenses remained relatively flat on an aggregate basis at approximately $19.1 million, or $7.70 per Boe, in 2009 compared to approximately $18.8 million, or $6.35 per Boe, in 2008. The increase in the lease operating expenses per Boe was a function of the decreased volumes discussed above.

Production and Ad Valorem Taxes. Production and ad valorem taxes decreased to approximately $6.7 million for the year ended December 31, 2009 compared to approximately $13.9 million for the year ended December 31, 2008 primarily due to a decrease in revenues discussed above. On a per Boe basis, production and ad valorem taxes decreased to $2.72 per Boe for the year ended December 31, 2009 as compared to $4.70 per Boe for the year ended December 31, 2008.

Depletion and Depreciation Expenses. Our predecessor's depletion and depreciation expenses were approximately $56.3 million, or $22.74 per Boe produced, in 2009 as compared to $79.5 million, or

$26.87 per Boe produced, in 2008. The decrease is a direct result of the successful effort impairment recognized in 2008, which decreased the carrying amount of our predecessor's oil and natural gas properties subject to depletion by $121.6 million.

Impairment of Oil and Natural Gas Properties. No impairment was required for the year ended December 31, 2009. Our predecessor recorded a substantial impairment under the successful efforts impairment test of approximately $121.6 million in 2008, predominantly as a result of the low oil and natural gas price environment at the end of 2008.

Management Fees. Our predecessor incurs a management fee paid to Lime Rock Management in addition to its direct general and administrative expenses incurred. The management fee is determined by a formula based on the predecessor's limited partners' invested capital or the equity capital commitment in Fund I. The predecessor's management fees were flat at $8.5 million in both 2009 and 2008.

General and Administrative Expenses. Our predecessor's general and administrative expenses remained constant at approximately $2.4 million, or $0.97 per Boe produced, in 2009 as compared to approximately $2.5 million, or $0.84 on an aggregate basis per Boe produced, in 2008. For general and administrative expenses on a per Boe basis, the rate is higher in 2009 compared to 2008 due to lower production of 2,478 Mboe in 2009 compared to 2,957 Mboe in 2008.

Interest Expense. Our predecessor's interest expense is comprised of interest on its credit facility, debt issuance and financing costs and realized gains (losses) on its interest rate derivative instruments. Interest expense decreased to $1.7 million for the year ended December 31, 2009 from $2.2 million for the year ended December 31, 2008 primarily due to lower debt issuance costs in 2009 as compared to 2008.

Our predecessor's primary sources of capital and liquidity have been proceeds from capital contributions from the partners of its limited partnerships, bank borrowings, and cash flow from operations. To date, our predecessor's primary use of capital has been for the acquisition of oil and natural gas properties.

Net bank borrowings were approximately $27.3 million, $27.3 million, $24.2 million and $32.3 million, at June 30, 2011, December 31, 2010, 2009 and 2008, respectively. Net bank borrowings during those periods were used primarily to fund acquisitions of oil and natural gas properties. During 2010, our predecessor incurred approximately $8.0 million of indebtedness in connection with the Potato Hills acquisition.

Net cash provided by operating activities was approximately $121.3 million, $108.1 million, $139.2 million, $38.0 million and $58.2 million for the years ended December 31, 2010, 2009, and 2008 and six months ended June 30, 2011 and 2010, respectively. Revenues decreased significantly for the six months ended June 30, 2011 as compared to the six months ended June 30, 2010, and therefore our predecessor's net cash provided by operating activities decreased during that same period. Revenues increased significantly for the year ended December 31, 2010 as compared to the year ended December 31, 2009, and therefore our predecessor's net cash provided by operating activities increased during that same period. Cash provided by operating activities is impacted by the prices received for oil and natural gas sales and levels of production volumes. Our predecessor's production volumes in the future will in large part be dependent upon the dollar amount and results of future capital expenditures. Future levels of capital expenditures made by our predecessor may vary due to many factors, including drilling results, oil and natural gas prices, industry conditions, prices and availability of goods and services and the extent to which proved properties are acquired.

Net cash used in investing activities by our predecessor was approximately $125.8 million, $25.1 million, $218.0 million, $23.6 million and $111.9 million for the years ended December 31, 2010, 2009 and 2008 and the six months ended June 30, 2011 and 2010, respectively. The increased amount of cash used in investing activities in the six months ended June 30, 2010 and years ended December 31, 2010 and 2008 was principally due to the acquisitions of oil and natural gas properties, which included the Potato Hills acquisition in February 2010.

Net cash provided by (used in) financing activities by our predecessor was approximately $1.5 million, $(118.2) million, $117.8 million, $(20.8) million and $63.0 million for the years ended December 31, 2010, 2009 and 2008 and the six months ended June 30, 2011 and 2010, respectively. For the six months ended June 30, 2011, the cash used in financing activities was primarily related to distributions of $24.4 million offset by capital contributions of $3.6 million. For the six months ended June 30, 2010, the cash provided by financing activities included $107.9 million of net capital contributions and $4.7 million in borrowings related to the Potato Hill acquisition offset by $49.5 million in distributions. For 2010, the cash provided by financing activities primarily related to $128.9 million of capital contributions for acquisitions, debt borrowings of $8.6 million offset by distributions of $120.9 million, return of capital of $9.3 million and debt repayments of $5.5 million. For 2009, the cash used in financing activities primarily related to $124.0 million of distributions, $3.8 million of return of capital, debt repayments of $9.0 million offset by capital contributions of $17.8 million. For 2008, the cash provided by financing activities primarily related to $295.7 million of capital contributions for acquisitions, debt borrowings of $21.2 million offset by distributions of $64.0 million and return of capital of $135.0 million.

Our predecessor's working capital totaled $25.7 million, $33.2 million and $57.5 million at June 30, 2011, December 31, 2010 and December 31, 2009, respectively. Our predecessor's collection of receivables has historically been timely, and losses associated with uncollectible receivables have historically not been significant. Our predecessor's cash balances totaled $6.0 million, $12.5 million and $15.5 million at June 30, 2011, December 31, 2010 and December 31, 2009, respectively.

The following table summarizes, for the periods presented, the weighted average price and notional volumes of our predecessor's oil, NGL and natural gas swaps and collars in place as of June 30, 2011. The weighted average price is based on the swap price for oil, NGL and natural gas swaps and the floor price of oil and natural gas collars. Our predecessor uses swaps and collars as a mechanism for managing commodity price risks whereby it pays the counterparty floating prices and receives fixed prices from the counterparty. By entering into the hedge agreements, our predecessor mitigates the effect on its cash flows of changes in the prices it receives for its oil and natural gas production. These transactions are settled based upon the NYMEX-WTI price of oil and NYMEX-Henry Hub price of natural gas on the average of the three final trading days of the month, with settlement occurring on the fifth day of the production month.

The following table summarizes, for the periods presented, our predecessor's oil and natural gas basis swaps in place as of June 30, 2011. These contracts are designed to effectively fix a price differential between NYMEX-Henry Hub price and the index price at which the physical natural gas is sold.

LRR A's $45.0 million credit facility, entered into on November 23, 2010, has an aggregate maximum commitment of $45.0 million and an aggregate current borrowing base of $31.5 million as of June 30, 2011. The credit facility is secured by mortgages on substantially all of LRR A's oil and natural gas properties, including the Partnership Properties. We expect that the credit facility will be amended to permit the contribution of the Partnership Properties by our predecessor to us in connection with the closing of this offering.

The borrowing base is subject to review and adjustment on a semiannual basis and other interim adjustments as requested by the lenders of LRR A, as applicable. At the election of LRR A, amounts outstanding under the credit facility bear interest at specified margins over LIBOR of 2.00% to 2.75% or specified margins over the Alternate Base Rate of 1.00% to 1.75%. The Alternate Base Rate is the greater of the Prime Rate, the Fed Funds Rate plus ¹/2 of 1%, or the adjusted LIBOR for a one-month Interest Period plus 1%. Such margins will fluctuate based on the utilization of the credit facility.

As of June 30, 2011, the interest rate on LRR A's credit facility, taking into account LRR A's interest rate swaps, was an average of 4.74%. LRR A's borrowings under the credit facility totaled $27.3 million at June 30, 2011.

The credit facility contains financial and other covenants, including a current ratio test and an interest coverage test. LRR A was in compliance with all covenants under the credit facility at June 30, 2011.

A summary of our predecessor's contractual obligations as of December 31, 2010 is provided in the following table.

The table above excludes amounts associated with our oil and gas property asset retirement obligations. As of December 31, 2010, approximately $24.3 million of such obligations were recorded as

liabilities, $0.8 million of which was reflected as current liabilities. Additionally, our predecessor is not a party to any off-balance sheet arrangements that require disclosure in the table above.

Our predecessor is exposed to market risk, including the effects of adverse changes in commodity prices and interest rates as described below.

The primary objective of the following information is to provide quantitative and qualitative information about our predecessor's potential exposure to market risks. The term "market risk" refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. All of our predecessor's market risk sensitive instruments were entered into for purposes other than speculative trading.

Our predecessor's major market risk exposure is in the pricing that it receives for its oil and natural gas production. Realized pricing is primarily driven by the spot market prices applicable to its natural gas production and the prevailing price for oil. Pricing for oil and natural gas has been volatile and unpredictable for several years, and this volatility is expected to continue in the future. The prices our predecessor receives for its oil and natural gas production depend on many factors outside of its control, such as the strength of the global economy.

To reduce the impact of fluctuations in oil and natural gas prices on our predecessor's revenues, or to protect the economics of property acquisitions, our predecessor periodically enters into commodity derivative contracts with respect to a significant portion of its projected oil and natural gas production through various transactions that fix the future prices received. These transactions may include price swaps whereby our predecessor will receive a fixed price for its production and pay a variable market price to the contract counterparty. Additionally, our predecessor may enter into collars, whereby our predecessor receives the excess, if any, of the fixed floor over the floating rate or pays the excess, if any, of the floating rate over the fixed ceiling price. These hedging activities are intended to support oil and natural gas prices at targeted levels and to manage our predecessor's exposure to oil and natural gas price fluctuations. Our predecessor does not enter into derivative contracts for speculative trading purposes.

Swaps. In a typical commodity swap agreement, including basis swaps, our predecessor receives the difference between a fixed price per unit of production and a price based on an agreed upon published third-party index, if the index price is lower than the fixed price. If the index price is higher than the fixed price, our predecessor pays the difference. By entering into swap agreements, our predecessor effectively fixes the price that it will receive in the future for the hedged production. Our predecessor's swaps are settled in cash on a monthly basis.

For a summary of the oil and natural gas swaps and oil and natural gas swap prices, related basis swap prices and resulting adjusted swap prices in place as of June 30, 2011, please read "— Predecessor Liquidity and Capital Resources — Predecessor Commodity Derivative Contracts."

Collars. In a typical collar arrangement, our predecessor receives the excess, if any, of the floor price over the reference price, based on NYMEX quoted prices, and pay the excess, if any, of the reference price over the ceiling price.

For a summary of the oil and natural gas collars in place as of June 30, 2011, please read "— Predecessor Liquidity and Capital Resources — Predecessor Commodity Derivative Contracts."

At June 30, 2011, our predecessor had $27.3 million of debt outstanding under its credit facility, with an effective interest rate of 4.74% taking into account the predecessor's interest rate swaps. Assuming no change in the amount outstanding, the impact on interest expense of a 10% increase or decrease in the average interest rate, after giving effect to our predecessor's existing interest rate swaps, would be approximately $0.1 million per year.

Our predecessor's oil and natural gas derivative contracts expose our predecessor to credit risk in the event of nonperformance by counterparties. While our predecessor does not require its counterparties to its derivative contracts to post collateral, the predecessor does evaluate the credit standing of such counterparties as the predecessor deems appropriate. This evaluation includes reviewing a counterparty's credit rating and latest financial information. The counterparties to the predecessor's derivative contracts currently in place are lenders under our predecessor's credit facility, with investment grade ratings.

Our predecessor is also subject to credit risk due to the concentration of its oil and natural gas receivables with several significant customers. The inability or failure of our predecessor's significant customers to meet their obligations to our predecessor or their insolvency or liquidation may adversely affect our predecessor's financial results. However, the predecessor's customer base consists of major integrated and international oil and natural gas companies, as well as smaller processors and gatherers. The predecessor believes the credit quality of its customers is high.

Joint interest receivables arise from entities which own partial interests in the wells our predecessor operates. These entities participate in our predecessor's wells primarily based on their ownership in leases on which our predecessor drills. Our predecessor has limited ability to control participation in its wells.

Our and our predecessor's estimates of proved reserves are based on the quantities of oil and natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Miller and Lents, Ltd. and Netherland, Sewell & Associates, Inc., our and our predecessor's independent reserve engineering firms, prepare a fully-engineered reserve and economic evaluation of all our and our predecessor's properties on a lease, unit or well-by-well basis, depending on the availability of well-level production data. The estimates of the proved reserves attributable to the Partnership Properties as of December 31, 2010 and March 31, 2011 included in this prospectus are based on reserve reports prepared by Miller and Lents, Ltd. and Netherland, Sewell & Associates, Inc. On a going forward basis, we expect that Miller and Lents, Ltd., Netherland, Sewell & Associates, Inc., and/or another independent reserve engineering firm will prepare a reserve report as of December 31 of each year.

We and our predecessor prepare our reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines. Our independent engineering firm adheres to the same guidelines when preparing their reserve reports. The accuracy of our and our predecessor's reserve estimates is a function of many factors, including the quality and quantity of available data, the interpretation of that data, the accuracy of various economic assumptions, and the judgments of the individuals preparing the estimates.

Our and our predecessor's proved reserve estimates are also a function of many assumptions, all of which could deviate significantly from actual results. For example, when the price of oil and natural gas increases, the economic life of our and our predecessor's properties is extended, thus increasing

estimated proved reserve quantities and making certain projects economically viable. Likewise, if oil and natural gas prices decrease, the properties economic life is reduced and certain projects may become uneconomic, reducing estimated proved reserved quantities. Oil and natural gas price volatility adds to the uncertainty of our and our predecessor's reserve quantity estimates. As such, reserve estimates may materially vary from the ultimate quantities of oil, natural gas and natural gas liquids eventually recovered.

In January 2010, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2010-03 to align the oil and natural gas reserve estimation and disclosure requirements of Extractive Industries — Oil and Gas Topic of the Accounting Standards Codification with the requirements in the SEC's final rule, Modernization of the Oil and Gas Reporting Requirements. We implemented ASU 2010-03 as of December 31, 2009. Key items in the new rules include changes to the pricing used to estimate reserves whereby an unweighted average of the first-day-of-the-month price for each month within the applicable twelve-month period is used rather than a single day spot price, the use of new technology for determining reserves, the ability to include nontraditional resources in reserves and permitting disclosure of probable and possible reserves.

We and our predecessor account for oil and natural gas properties in accordance with the successful efforts method. In accordance with this method, all leasehold and development costs of proved properties are capitalized and amortized on a unit-of-production basis over the remaining life of the proved reserves and proved developed reserves, respectively.

Our predecessor evaluates the impairment of its proved oil and natural gas properties on a field-by-field basis whenever events or changes in circumstances indicate that the carrying value may not be recoverable. The carrying values of proved properties are reduced to fair value when the expected undiscounted future cash flows are less than net book value. The fair values of proved properties are measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of proved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. The underlying commodity prices embedded in the predecessor's estimated cash flows are the product of a process that begins with New York Mercantile Exchange ("NYMEX") forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that management believes will impact realizable prices. Costs of retired, sold or abandoned properties that constitute a part of an amortization base are charged or credited, net of proceeds, to accumulated depletion and depreciation unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized currently. Gains or losses from the disposal of other properties are recognized currently. Expenditures for maintenance and repairs necessary to maintain properties in operating condition are expensed as incurred. Estimated dismantlement and abandonment costs are capitalized, net of salvage, at their estimated net present value and amortized on a unit-of-production basis over the remaining life of the related proved developed reserves.

Costs related to unproved properties include costs incurred to acquire unproved reserves. Because these reserves do not meet the definition of proved reserves, the related costs are not classified as proved properties. Unproved leasehold costs are capitalized and amortized on a composite basis if individually insignificant, based on past success, experience and average lease-term lives. Individually significant leases are reclassified to proved properties if successful and expensed on a lease by lease basis if unsuccessful or the lease term expires. Unamortized leasehold costs related to successful exploratory drilling are reclassified to proved properties and depleted on a unit-of-production basis. The predecessor assesses unproved properties for impairment quarterly on the basis of its experience in

similar situations and other factors such as the primary lease terms of the properties, the average holding period of unproved properties, and the relative proportion of such properties on which proved reserves have been found in the past. The fair values of unproved properties are measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of unproved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. The market-based weighted average cost of capital rate is subjected to additional project-specific risking factors.

For the year ended December 31, 2010, our predecessor recorded a non cash impairment charge of approximately $11.7 million primarily associated with proved oil and natural gas properties related to unfavorable market conditions, including $10.9 million during the six months ended June 30, 2010. The carrying values of the impaired proved properties were reduced to fair value, estimated using inputs characteristic of a Level 3 fair-value measurement. For the year ended December 31, 2008, our predecessor recorded a noncash impairment charge, before and after tax, of approximately $121.6 million associated with proved oil and natural gas properties related to a decline in commodity prices. The charges are included in impairment of oil and natural gas properties in our predecessor's combined statements of operations. Our predecessor recorded no impairment charge of proved oil and natural gas properties for the six months ended June 30, 2011 and the year ended December 31, 2009.

The initial estimated asset retirement obligation associated with oil and natural gas properties is recognized as a liability, with a corresponding increase in the carrying value of oil and natural gas properties. Amortization expense is recognized over the estimated productive life of the related assets. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from revisions of estimated inflation rates, escalating retirement costs and changes in the estimated timing of settling asset retirement obligations.

Oil and natural gas revenues are recorded when title passes to the customer, net of royalties, discounts and allowances, as applicable. We and our predecessor account for oil and natural gas production imbalances using the sales method, whereby we and our predecessor recognize revenue on all natural gas and oil sold to our customers notwithstanding the fact that its ownership may be less than 100% of the oil and natural gas sold. Liabilities are recorded for imbalances greater than our respective proportionate shares of remaining estimated and oil natural gas reserves.

Current accounting rules require that all derivative contracts, other than those that meet specific exclusions, be recorded at fair value. Quoted market prices are the best evidence of fair value. If quotations are not available, management's best estimate of fair value is based on the quoted market price of derivatives with similar characteristics or on other valuation techniques.

Our predecessor's derivative contracts are either exchange-traded or transacted in an over-the-counter market. Valuation is determined by reference to readily available public data.

Our predecessor recognizes all of its derivative contracts as either assets or liabilities at fair value. The accounting for changes in the fair value (i.e., gains or losses) of a derivative contract depends on whether it has been designated and qualifies as part of a hedging relationship, and further, on the type of hedging relationship. For those derivative contracts that are designated and qualify as hedging

instruments, our predecessor designated the hedging instrument, based on the exposure being hedged, as either a fair value hedge or a cash flow hedge. For derivative contracts not designated as hedging instruments, the gain or loss is recognized in current earnings during the period of change. None of our predecessor's derivatives was designated as a hedging instrument during 2011, 2010, 2009 or 2008.

On July 21, 2010, the FASB issued ASU 2010-20 "Receivables (Topic 310) — Disclosures about the Credit Quality of Financial Receivables and the Allowance for Credit Losses." ASU 2010-20 requires disclosure of additional information to assist financial statement users to understand more clearly an entity's credit risk exposures to finance receivables and the related allowance for credit losses. ASU 2010-20 is effective for all public companies for interim and annual reporting periods ending on or after December 15, 2010, with specific items, such as the allowance rollforward and modification disclosures, effective for periods beginning after December 15, 2010. We do not expect the adoption of this new guidance to have an impact on our financial position, cash flows or results of operations.

In April 2010, the FASB issued ASU 2010-14, which amends the guidance on oil and natural gas reporting in Accounting Standards Codification 932.10.S99-1 by adding the Codification of SEC Regulation S-X, Rule 4-10 as amended by the SEC Final Rule 33-8995. Both ASU 2010-03 and ASU 2010-14 are effective for annual reporting periods ending on or after December 31, 2009. Application of the revised rules is prospective and companies are not required to change prior period presentation to conform to the amendments.

In January 2010, the FASB issued ASU 2010-06, "Improving Disclosures About Fair Value Measurements," which provides amendments to fair value disclosures. ASU 2010-06 requires additional disclosures and clarifications of existing disclosures for recurring and nonrecurring fair value measurements. The revised guidance for transfers into and out of Level 1 and Level 2 categories, as well as increased disclosures around inputs to fair value measurement, was adopted January 1, 2010, with the amendments to Level 3 disclosures effective beginning after January 1, 2011. ASU 2010-06 concerns disclosure only. The adoption did not have a material impact on our or our predecessor's financial position or results of operations.

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. The lack of adequate staffing levels contributed to several audit adjustments to the financial statements for the year ended December 31, 2010. In connection with the audit of our predecessor's financial statements 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 the design and execution of controls have not consistently resulted in effective review and supervision by individuals with financial reporting oversight roles given the lack of adequate staffing levels. 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 our predecessor's financial statements for the year ended December 31, 2010.

Prior to the completion of the 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 controls 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 controls 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 controls 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 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.

Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the years ended December 31, 2008, 2009 and 2010 and first six months of 2011. Although the impact of inflation has been insignificant in recent years, it is still a factor in the U.S. economy, and we tend to experience inflationary pressure on the cost of oilfield services and equipment, as increasing oil prices increase drilling activity in our areas of operations.

Currently, neither we nor our predecessor have any off-balance sheet arrangements.

The following Business and Properties discussion should be read in conjunction with the "Selected Historical and Pro Forma Financial Data" and the accompanying financial statements and related notes included elsewhere in this prospectus. Unless otherwise indicated, all references to financial or operating data on a pro forma basis give effect to the transactions described under "Prospectus Summary — Formation Transactions and Partnership Structure" and in the Unaudited Pro Forma Condensed Financial Statements included elsewhere in this prospectus. Unless otherwise indicated, all references to our properties and operations on a historical basis are to the properties and operations that will be contributed by Fund I to us in the transactions described under "Prospectus Summary — Formation Transactions and Partnership Structure."

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 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.

We believe our relationship with Lime Rock Resources will enhance our ability to grow our estimated proved reserves, production and cash distributions over time. After 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. Following its sale and contribution of the Partnership Properties to us in connection with this offering, Lime Rock Resources will own total estimated proved reserves of 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, Lime Rock Resources has no obligation to offer or sell any of its properties to us or share future joint acquisition opportunities with us following the consummation of this offering and any transactions with Lime Rock Resources would be subject to obtaining mutually agreeable terms. For more information about our relationship with Lime Rock Resources and its affiliates, please read "— Our Principal Business Relationships."

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

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

We believe our relationships with Lime Rock Management, Lime Rock Resources and Lime Rock Partners will increase our opportunities to acquire additional oil and natural gas properties from Lime Rock Resources and from Lime Rock Partners' portfolio companies in the future, and will maximize our opportunities to participate in suitable acquisitions from third parties that otherwise may not be available to us. Additionally, these relationships will provide us access to the management and operations team that manages and operates Lime Rock Resources. 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.

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. All of our executive officers are employees of Lime Rock Management and will provide services to us pursuant to a services agreement that we will enter into upon the closing of this offering with Lime Rock Management and Lime Rock Resources Operating Company, an affiliate of Lime Rock Resources. Mr. Jonathan Farber, a co-founder of Lime Rock Management and a Managing Director of Lime Rock Partners, and Mr. Townes Pressler, a Managing Director of Lime Rock Partners, will serve on the board of directors of our general partner. Certain of our executive officers own financial interests in Lime Rock Management.

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 Resources has successfully raised $456 million in Fund I and $410 million in Fund II and has a high quality team of 59 industry professionals who will provide services to us pursuant to a services agreement that we will enter into with Lime Rock Management and Lime Rock Resources Operating Company upon the closing of this offering. Since 2006, Lime Rock Resources has invested approximately (i) $416 million of Fund I equity and $277 million of Fund I leverage and (ii) $175 million of Fund II equity and $162 million of Fund II leverage in 12 major acquisitions of oil and natural gas properties in three diverse producing regions. Lime Rock Resources currently has approximately $520 million of additional acquisition capacity that it expects to deploy over the next two years. Fund I will sell and contribute the Partnership Properties to us upon the closing of this offering. Fund II will not contribute any of its oil and natural gas properties to us in connection with this offering but may do so in the future.

Lime Rock Resources is managed and operated by Lime Rock Management and Lime Rock Resources Operating Company. 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. Most of the executive officers of Lime Rock Resources, including Mr. Charles Adcock and Mr. Eric Mullins, Co-Chief Executive Officers of Lime Rock Resources, will serve as executive officers of our general partner. The members of the Lime Rock Resources management team who will also provide services to us have an average of 28 years of experience in the oil and natural gas industry and have demonstrated a successful track record of identifying, acquiring and exploiting long-lived oil and natural gas assets. In addition, our non-independent directors and executive officers, other than our Chief Financial Officer, own financial interests in Lime Rock Resources.

After giving effect to the sale and contribution of the Partnership Properties to us, Lime Rock Resources will retain (i) total estimated proved reserves of 15.3 MMBoe as of March 31, 2011, of which approximately 79% are proved developed reserves, with a standardized measure of $266.1 million as of March 31, 2011 and (ii) working interests in approximately 506 gross (358 net) oil and natural gas wells, with pro forma average net production of approximately 3,983 Boe/d for the six months ended June 30, 2011. The oil and natural gas properties retained by Lime Rock Resources will include properties with characteristics similar to the Partnership Properties and Lime Rock Resources expects to invest additional capital into the further development of these properties. Following their successful development, we believe the majority of these properties will 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 existing and future mature, onshore producing oil and natural gas properties and to offer us the opportunity to participate in potential joint acquisition opportunities. However, Lime Rock Resources has no obligation to offer or sell any of its properties to us or share future joint acquisition opportunities with us following the consummation of this offering and any transactions with Lime Rock Resources would be subject to agreeing upon mutually acceptable terms. In addition, Lime Rock Resources and its affiliates, including any future affiliated funds and the exploration and production portfolio companies of Lime Rock Partners, are not limited in their ability to compete with us, including with respect to future acquisition opportunities. Please see "Certain Relationships and Related Party Transactions — Review, Approval or Ratification of Transactions with Related Persons" and "Conflicts of Interest and Fiduciary Duties."

Given Lime Rock Resources' significant ownership in us following this offering, we believe Lime Rock Resources is positioned to directly benefit from selling additional oil and natural gas properties to us. As a result, we believe that we are well positioned to acquire additional oil and natural gas properties from Lime Rock Resources in the future in order to increase our reserves, production and cash distributions. If Lime Rock Resources fails to present us with acquisition opportunities, then we may not be able to replace or increase our estimated proved reserves, which would adversely affect our cash flow from operations and our ability to make cash distributions to our unitholders. For further information regarding potential conflicts of interest, please read "Conflicts of Interest and Fiduciary Duties."

Formed in 1998, Lime Rock Partners is a long-term investor of growth capital in energy companies worldwide. Lime Rock Partners' objective is to generate substantial long-term capital appreciation through investments of private growth capital in energy companies in three principal sectors: (i) exploration and production; (ii) energy service; and (iii) oil service technology. Lime Rock Partners consists of five funds: the first Lime Rock Partners fund, a $105 million fund established in October 1998; Lime Rock Partners II, L.P., a $320 million fund established in August 2002; Lime Rock Partners III, L.P., a $431 million fund established in November 2004; Lime Rock Partners IV, L.P., a $768 million fund established in September 2006; and Lime Rock Partners V, L.P., a $1.4 billion fund established in April 2008. Although Lime Rock Partners does not invest directly in oil and natural gas properties, its exploration and production portfolio companies do invest in those types of assets. However, those portfolio companies typically target less mature or unconventional properties with higher growth and exploration potential than the properties we seek to acquire.

The Lime Rock Partners investment team consists of approximately 25 professionals in four offices: Houston, Texas; Westport, Connecticut; Aberdeen, Scotland; and Dubai, United Arab Emirates. The employees who provide services to Lime Rock Partners are experienced energy professionals with expertise in finance and operations and broad technical skills in the oil and natural gas industry. In connection with the business of Lime Rock Partners, these employees review a large number of potential acquisitions. Although Lime Rock Partners is not obligated to do so, Lime Rock Partners may refer new acquisition opportunities to us or the portfolio companies of Lime Rock Partners may sell their mature, low-risk oil and natural gas assets to us if mutually acceptable terms can be agreed to. In addition, Lime Rock Partners' extensive investments in the energy service and oil service technology sectors may provide introductions, potential vendor relationships and industry intelligence that we believe will enable us to implement the latest services and technologies to increase production, maximize long-term reserve life and achieve cost containment. We believe we will benefit from the collective expertise of the employees who provide services to Lime Rock Partners, their extensive network of industry relationships and technologies, and the access to potential acquisition opportunities that would not otherwise be available to us.

Our properties consist of mature, low-risk onshore oil and natural gas properties 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.

As of March 31, 2011, our total estimated proved reserves were approximately 30.3 MMBoe, of which approximately 69% were proved developed producing reserves and approximately 15% were proved developed non-producing reserves. Although 63% of our reserves as measured by volume as of March 31, 2011 were natural gas, approximately 57% of our pro forma revenues for the six months ended June 30, 2011 were from oil and NGLs. As of March 31, 2011, we operated approximately 93% of our proved reserves and produced from approximately 754 gross (666 net) wells across our operated properties, with an average working interest of approximately 88%. 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, approximately 4.4 MMBoe, or approximately 15% of our estimated proved reserves, were proved developed non-producing reserves. Such estimated proved developed non-producing reserves were approximately 57% oil and NGLs and included 192 gross (158 net) recompletion, refracture stimulation and workover projects. In addition, as of March 31, 2011, approximately 4.7 MMBoe, or 16% of our estimated proved reserves, were proved undeveloped reserves. Our proved undeveloped reserves were approximately 68% oil and NGLs and included 213 gross (140 net) identified drilling locations.

Our properties are located in fields that generally have been producing for a long period of time, typically more than ten years. Observing the performance of these fields over many years allows for greater understanding of production and reservoir characteristics, making future performance more predictable. The production and corresponding decline rates attributable to properties of this type, in contrast with more recently drilled properties, can be forecasted with a greater degree of accuracy. Similarly, we use words such as "mature" or "low-risk" to describe our properties as having established operating, reservoir and production characteristics. The properties selected for inclusion among the Partnership Properties were chosen, in part, because we expect that the greater precision in forecasted production attributable to those properties will result in more stable cash flows.

The development and production of oil and natural gas has a number of uncertainties that pose substantial risk, even for mature properties. However, we view our properties as having less risk because many of the operational risks associated with oil and natural gas development and production (for example, drilling a well, whether one will encounter hydrocarbons capable of production in paying quantities and initial production decline rate) tend to occur earlier in the lifecycle of oil and natural gas properties. For a discussion of the risks inherent in oil and natural gas production, please read "Risk Factors — Risks Related to Our Business — 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."

The following table shows the estimated net proved oil and natural gas reserves of the Partnership Properties as of March 31, 2011, based on the reserve reports prepared by Miller and Lents and Netherland Sewell, our independent petroleum engineers, and certain unaudited information regarding such properties. Please read "Risk Factors" and "Management's Discussion and Analysis of Financial Condition and Results of Operations" in evaluating the material presented below.

																	Pro Forma Average Net Production for the Six Months Ended June 30, 2011

			Estimated Pro Forma Net Proved Reserves as of March 31, 2011(1)
																					Producing Wells as of March 31, 2011
																			Average Reserve-to- Production Ratio(2)
					% of Total Reserves			% Proved Developed			% Oil and NGLs			% Operated
			MBoe		% of Total Reserves			% Proved Developed			% Oil and NGLs			% Operated			(Boe/d)				Gross		Net
																			(years)
Permian Basin Region:
	Red Lake			9,620		32	%		66	%		86	%		99	%		1,383		19.1		167		147
	Pecos Slope			5,121		17	%		98	%		5	%		100	%		909		15.4		441		384
	Willow Lake, Grierson Springs & Spraberry			1,126		4	%		68	%		76	%		0	%		199		15.5		41		8
	Cowden Ranch			418		1	%		100	%		93	%		100	%		73		15.6		8		5
	Corbin and Vacuum			289		1	%		100	%		85	%		100	%		44		18.1		8		8

	Total Permian Basin Region			16,574		55	%		78	%		60	%		92	%		2,608		17.4		665		552

Mid-Continent Region:
	Potato Hills			8,482		28	%		93	%		0	%		100	%		1,689		13.8		44		31
	Reklaw			863		3	%		100	%		3	%		100	%		274		8.6		63		61
	Black Bayou-Doyle Creek			785		2	%		100	%		1	%		0	%		318		6.8		43		12

	Total Mid-Continent Region			10,130		33	%		94	%		0	%		92	%		2,281		12.2		150		104

Gulf Coast Region:
	New Years Ridge			2,468		8	%		84	%		30	%		100	%		973		6.9		19		18
	George West-Stratton			1,111		4	%		100	%		33	%		100	%		271		11.2		23		17

	Total 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

Approximately 55% of our estimated proved reserves as of March 31, 2011 and approximately 43% of our pro forma average daily net production for the six months ended June 30, 2011 were located in the Permian Basin region. Approximately 60% of our estimated net proved reserves in the Permian Basin region are oil and NGLs. The Permian Basin is one of the largest and most prolific oil and natural gas producing basins in the United States, extending over 100,000 square miles in West Texas and southeast New Mexico, and has produced over 24 billion barrels of oil since its discovery in 1921. The Permian Basin is characterized by oil and natural gas fields with long production histories, multiple producing formations and low rates of production decline. The majority of our current production in the Permian Basin region is primary recovery. However, waterflood operations exist in the same formations in nearby properties operated by others and the potential for similar operations exist in some of our wells that produce from the San Andres formation in our Red Lake area.

We own an 83% average working interest across 665 gross (552 net) wells and operate approximately 92% of our properties in the Permian Basin. Our estimated proved reserves for our Permian Basin properties as of March 31, 2011 totaled 16.6 MMBoe and had a standardized measure of $237.7 million, which represented 69% of the total standardized measure for all of our estimated proved reserves. Our Permian Basin properties have a proved developed producing production decline rate of approximately 12% per year over the next five years and 8% per year thereafter and a reserve-to-production ratio of approximately 17.4 years based on our reserve report as of March 31, 2011 and pro forma net production for the six months ended June 30, 2011. Based on our reserve report dated March 31, 2011, we expect to spend $17.8 million on 141 gross (110 net) recompletions, re-stimulations, workovers and 3 gross (3 net) facility upgrades to convert our 2.9 MMBoe of Permian Basin proved developed non-producing reserves to proved developed producing reserves and $88.1 million on drilling 172 gross (127 net) wells and a waterflood project to convert our 3.7 MMBoe of Permian Basin proved undeveloped reserves to proved developed producing.

Red Lake Area. We acquired our properties in the Red Lake area in two separate acquisitions, the first in 2006 and the second in 2008. The Red Lake area is an oil-weighted field located in Eddy County, New Mexico. Since 1970, our Red Lake properties have produced approximately 4.9 MMBoe. The primary producing formations are the San Andres and Yeso at a depth of approximately 2,000 to 5,000 feet.

We operate approximately 99% of our proved reserves in the Red Lake area, including 157 gross (144 net) producing wells in the field with an average working interest of 92%, and own a non-operated working interest in 10 gross (3 net) additional wells in the area with an average working interest of 31%. Our properties in the field contained 9.6 MMBoe of estimated net proved reserves as of March 31, 2011, approximately 86% of which are oil and NGLs, and generated average net production of 1,383 Boe/d for the six months ended June 30, 2011. These properties represented 32% of our total estimated proved reserves as of March 31, 2011 and 23% of our pro forma average net production for the six months ended June 30, 2011. In addition, these properties had a standardized measure of $163.3 million as of March 31, 2011, which represented 48% of the total standardized measure for all of our estimated proved reserves. Our Red Lake assets are fairly concentrated near the city of Artesia, New Mexico, which provides for relatively efficient operations. Since 2008, gross production has increased over 100% due to drilling and workovers. Development of the field has historically been with vertical drilling on twenty-acre and ten-acre spacing. Most wells penetrate numerous formations, which provide us with recompletion

opportunities. We have identified 122 gross (103 net) infill drilling locations and 89 gross (72 net) recompletes. Furthermore, recent re-stimulation of the Yeso formation has resulted in increases in current production. Consequently, we plan to perform 24 gross (21 net) additional re-stimulation workovers.

Pecos Slope Area. We acquired the majority of our properties in the Pecos Slope area in 2007 and interests in 31 additional wells in the Pecos Slope area in 2009. The Pecos Slope area is a gas-weighted field located in Eddy, Chaves, Lea and Roosevelt Counties, New Mexico. Since 1970, our Pecos Slope properties have produced approximately 44.5 MMBoe. The primary producing formation is the Abo at an average depth of approximately 3,500 feet. The Abo formation is a shallow tight rock resulting in a low rate of production but very long lived wells. Most of the wells in the Pecos Slope area were drilled in the 1980's, which is fairly representative of the entire asset base in this area.

We operate approximately 100% of our proved reserves in the Pecos Slope area, including 434 gross (382 net) producing wells in the field with an average working interest of 88%. Our properties in the field contained 5.1 MMBoe of estimated net proved reserves as of March 31, 2011, approximately 5% of which are oil and NGLs, and generated average net production of 909 Boe/d for the six months ended June 30, 2011. These properties represented 17% of our total estimated proved reserves as of March 31, 2011 and 15% of our pro forma average net production for the six months ended June 30, 2011. In addition, these properties had a standardized measure of $39.6 million as of March 31, 2011, which represented 12% of the total standardized measure for all of our estimated proved reserves. We have a high concentration of adjacent wells in the Pecos Slope area, which allows us to service the wells we operate with fewer employees, thereby allowing us to more efficiently operate the wells. We also expect to reduce operating costs as we optimize compression on our existing assets in the area, which we expect will enhance production.

Willow Lake, Grierson Springs and Spraberry Areas. We acquired our properties in the Willow Lake, Grierson Springs and Spraberry areas in 2008. The Willow Lake field is an oil-weighted field located in Eddy County, New Mexico. The producing formations are the Cherry Canyon members of the Delaware formation at an approximate depth of 4,800 feet. The Willow Lake field is primarily developed with horizontal wells that were drilled starting in 2002. The Grierson Springs field is a gas-weighted field in Reagan County, Texas, that produces from the Strawn reservoir. Our assets in the Spraberry field are located in Martin County, Texas. Production in this field is primarily from the Strawn, Wolfcamp, Spraberry and Dean formations.

There are 41 gross (8 net) producing wells in this area with an average non-operated working interest of 19%. Our properties in this combined area contained 1.1 MMBoe of estimated net proved reserves as of March 31, 2011, approximately 76% of which were oil and NGLs, and generated average net production of 199 Boe/d for the six months ended June 30, 2011. These properties represented 4% of our total estimated proved reserves as of March 31, 2011 and 3% of our pro forma average net production for the six months ended June 30, 2011. In addition, these properties had a standardized measure of $20.5 million as of March 31, 2011, which represented 6% of the total standardized measure for all of our estimated proved reserves. We have identified 3 gross (2 net) horizontal Delaware formation drilling locations in the Willow Lake field and 9 gross (4 net) re-stimulation workovers in the Willow Lake field. We have also identified 23 gross (2 net) drilling locations in the Spraberry field.

Cowden Ranch Area. We acquired our properties in the Cowden Ranch area in 2008. The Cowden Ranch area is an oil-weighted field located in Crane County, Texas. Since its discovery in 2001, our Cowden Ranch properties have produced approximately 0.9 MMBoe. Production from the field is primarily from the Upper Devonian formation at an average depth of approximately 6,200 feet.

We operate 100% of our proved reserves in the Cowden Ranch area, including 8 gross (approximately 5 net) producing wells in the field with an average working interest of 71%. Our properties in the field contained 0.4 MMBoe of estimated net proved reserves as of March 31, 2011, 93%

of which were oil and NGLs, and generated average net production of 73 Boe/d for the six months ended June 30, 2011. These properties represented 1% of our total estimated proved reserves as of March 31, 2011 and 1% of our pro forma average net production for the six months ended June 30, 2011. In addition, these properties had a standardized measure of $9.4 million as of March 31, 2011, which represented 3% of the total standardized measure for all of our estimated proved reserves.

Corbin and Vacuum Areas. We acquired our properties in the Corbin and Vacuum areas in 2008. The Corbin and Vacuum areas are located in Lea County, New Mexico. Since 1970, our Corbin properties have produced approximately 3.0 MMBoe. Since their discovery in 2000, our Vacuum properties have produced approximately 0.5 MMBoe. The Corbin field produces from the Abo formation at an approximate depth of 8,100 feet. Production in the Vacuum field is from the Blinebry formation at an average depth of approximately 7,200 feet.

We operate 100% of our proved reserves in the Corbin and Vacuum areas, including 8 gross (8 net) producing wells with an average working interest of 100%. Our properties in the areas contained 0.3 MMBoe of estimated net proved reserves as of March 31, 2011, approximately 85% of which were oil and NGLs, and generated average net production of 44 Boe/d for the six months ended June 30, 2011. These properties represented 1% of our total estimated proved reserves as of March 31, 2011 and 1% of our pro forma average net production for the six months ended June 30, 2011. In addition, these properties had a standardized measure of $5.0 million as of March 31, 2011, which represented 1% of the total standardized measure for all of our estimated proved reserves.

Approximately 33% of our estimated proved reserves as of March 31, 2011 and approximately 37% of our pro forma average daily net production for the six months ended June 30, 2011 were located in the Mid-Continent region. Approximately 100% of our estimated net proved reserves in the Mid-Continent region are natural gas. Our properties in the Mid-Continent Region are characterized by stratigraphic plays with multiple, stacked pay zones and more complex geology than our other operating areas. Similar to our other operating areas, the Mid-Continent region contains a number of fields with long production histories.

We own a 69% average working interest across 150 gross (104 net) wells and operate 92% of our properties in the Mid-Continent region. Our estimated proved reserves for our Mid-Continent region properties as of March 31, 2011 were 10.1 MMBoe and had a standardized measure of $62.0 million, which represented 18% of the total standardized measure for all of our estimated proved reserves. Our Mid-Continent properties have a proved developed producing production decline rate of approximately 11% per year over the next five years and 9% per year thereafter and a reserve-to-production ratio of approximately 12.2 years based on our reserve report as of March 31, 2011 and pro forma net production for the six months ended June 30, 2011. Based on our reserve report dated March 31, 2011, we expect to spend $2.7 million on 42 gross (40 net) recompletions and workovers to convert our 0.8 MMBoe of Mid-Continent proved developed non-producing reserves to proved developed producing reserves and $7.5 million on drilling 40 gross (13 net) wells to convert our 0.6 MMBoe of Mid-Continent proved undeveloped reserves to proved developed producing.

Potato Hills Area. We acquired our properties in the Potato Hills area in 2010. The Potato Hills area is an Arkoma Basin natural gas property located in Latimer and Pushmataha Counties in Southeast Oklahoma. Since 1998, our Potato Hills properties have produced approximately 37.0 MMBoe. One of our key producing wells in the field is the Morgan 1-5. Since its initial completion in February 2000, the Morgan 1-5 has produced over 32 Bcf of natural gas and is still producing. The primary producing formation is the Jackfork at a depth between approximately 4,000 and 7,000 feet. The interval is roughly 3,000 feet thick with the uppermost member of the sequence being the Ratcliff followed by the Cedar Creek, the Middle Jackfork, the Green and the Basal Orange. The reservoirs are highly fractured and extremely productive within structurally high wells.

We operate approximately 100% of our proved reserves in the Potato Hills area, including 42 gross (31 net) producing wells in the field with an average working interest of 74%. Our properties in the field contained 8.5 MMBoe of estimated net proved reserves as of March 31, 2011, 100% of which is natural gas with no hydrocarbon liquids, and generated average net production of 1,689 Boe/d for the six months ended June 30, 2011. These properties represented 28% of our total estimated proved reserves as of March 31, 2011 and 28% of our pro forma average net production for the six months ended June 30, 2011. In addition, these properties had a standardized measure of $51.7 million as of March 31, 2011, which represented 15% of the total standardized measure for all of our estimated proved reserves. In the near-term, we expect to enhance field production by optimizing gathering and compression facilities in the field. Also, we have two unproved recompletions budgeted in 2011 to test shallower zones in two inactive wellbores that if successful, could confirm shallower development opportunities in other wells.

Reklaw Area. We acquired our properties in the Reklaw area in 2006. The Reklaw area is primarily a natural gas-weighted field located in Cherokee County, Texas. Since 1980, our Reklaw properties have produced approximately 5.6 MMBoe. Production from the field is primarily from the Travis Peak formation at an average depth of approximately 9,500 feet, but the field has also produced from shallower formations including the Pettit, James Lime and Rodessa intervals.

We operate 100% of our proved reserves in the Reklaw area, including 63 gross (61 net) producing wells in the field with an average working interest of 97%. Our properties in the field contained 0.9 MMBoe of estimated net proved reserves as of March 31, 2011, approximately 3% of which are oil and NGLs, and generated average net production of approximately 274 Boe/d for the six months ended June 30, 2011. These properties represented 3% of our total estimated proved reserves as of March 31, 2011 and 4% of our pro forma average net production for the six months ended June 30, 2011. In addition, these properties had a standardized measure of $4.8 million as of March 31, 2011, which represented 1% of the total standardized measure for all of our estimated proved reserves. We have mitigated the production decline in the Reklaw area through the drilling of development wells, recompletion of shallower zones and optimization of artificial lift methods. We expect that development activity of the Reklaw area in the short-term will consist of various recompletion opportunities.

Black Bayou-Doyle Creek Area. We acquired our properties in the Black Bayou-Doyle Creek areas in 2006. The Black Bayou-Doyle Creek area is a natural gas-weighted field located in Angelina, Cherokee and Nacogdoches Counties, Texas, in close proximity to the Reklaw area. Since first production of these properties in 1988, our Black Bayou-Doyle Creek properties have produced approximately 4.9 MMBoe. Production from the field is primarily from the Travis Peak formation at an average depth of approximately 11,200 feet. Other wells in the field produce from the James Lime and Pettit formations, which are found at average depths of 9,800 feet and 10,200 feet, respectively. The Travis Peak producing wells are vertical and directional wells. Most James Lime completions are horizontal wells.

We have a non-operated interest in 43 gross (approximately 12 net) producing wells in the field with an average non-operated working interest of 26%. Our properties in the field contained 0.8 MMBoe of estimated net proved reserves as of March 31, 2011, approximately 1% of which are oil and NGLs, and generated average net production of 318 Boe/d for the six months ended June 30, 2011. These properties represented approximately 2% of our total estimated proved reserves as of March 31, 2011 and 5% of our pro forma average net production for the six months ended June 30, 2011. In addition, these properties had a standardized measure of $5.5 million as of March 31, 2011, which represented 2% of the total standardized measure for all of our estimated proved reserves. We are not the operator of our properties in this area. Historically, the operator has been very active in increasing production through drilling undeveloped acreage, mostly targeting 80-acre spacing in the Travis Peak formation. We expect that development activity of the Black Bayou-Doyle Creek area will consist of drilling 27 gross (8 net) additional 80-acre Travis Peak vertical and directional wells. Microseismic data also suggests 40-acre wells are needed in some areas of this field to fully exploit Travis Peak reserves, and we expect the operator will pursue these after fully developing the 80-acre locations.

Approximately 12% of our estimated proved reserves as of March 31, 2011 and approximately 20% of our pro forma average daily net production for the six months ended June 30, 2011 were located in the Gulf Coast region. Approximately 31% of our estimated net proved reserves in the Gulf Coast region are oil and NGLs. Although many assets in the Gulf Coast region exhibit high rates of production decline, our Gulf Coast properties consist primarily of large legacy fields with long producing histories and are characterized by relatively stable production profiles and long production histories.

We own an 82% average working interest across 42 gross (35 net) wells and operate 100% of our properties in the Gulf Coast region. Our estimated proved reserves as of March 31, 2011 totaled 3.6 MMBoe and had a standardized measure of $42.6 million as of March 31, 2011, which represented 12% of the total standardized measure for all of our estimated proved reserves. Our Gulf Coast properties have a proved developed producing production decline rate of approximately 17% per year over the next five years and 13% per year thereafter and a reserve-to-production ratio of approximately 7.9 years based on our reserve report as of March 31, 2011 and pro forma net production for the six months ended June 30, 2011. Based on our reserve report dated March 31, 2011, we expect to spend $1.4 million on 9 gross (8 net) recompletions and workovers to convert our 0.7 MMBoe of Gulf Coast proved developed non-producing reserves to proved developed producing reserves and $6.2 million on drilling 1 gross (1 net) well to convert our 0.4 MMBoe of Gulf Coast proved undeveloped reserves to proved developed producing.

New Years Ridge Area. We acquired our properties in the New Years Ridge area in 2007. The New Years Ridge area is a natural gas-weighted field located in DeWitt County, Texas. Since first production of these properties in 2005, our New Years Ridge properties have produced approximately 5.1 MMBoe. Production from the field is primarily from the Korth and Feller formations (Middle and Lower Wilcox) at an average depth of approximately 10,500 feet.

We operate 100% of our proved reserves in the New Years Ridge area, including 19 gross (18 net) producing wells in the field with an average working interest of 93%. Our properties in the field contained 2.5 MMBoe of estimated net proved reserves as of March 31, 2011, approximately 30% of which are oil and NGLs, and generated average net production of 973 Boe/d for the six months ended June 30, 2011. These properties represented 8% of our total estimated proved reserves as of March 31, 2011 and 16% of our pro forma average net production for the six months ended June 30, 2011. In addition, these properties had a standardized measure of $30.5 million as of March 31, 2011, which represented 9% of the total standardized measure for all of our estimated proved reserves. We have mitigated the production decline in the New Years Ridge area through drilling, workovers, recompletions and compression upgrades. We expect that development activity of the New Years Ridge area will consist of drilling 1 gross (1 net) additional horizontal wells in the Korth reservoir and recompleting 1 gross (1 net) additional well in the Feller reservoir.

George West-Stratton Areas. We acquired our properties in the George West-Stratton areas in 2010. The George West-Stratton areas consist of natural gas-weighted fields located in Live Oak and Hidalgo Counties, Texas. Since their discovery in 1981, our George West properties have produced approximately 11.7 MMBoe. The Stratton area was discovered in 2002 and our properties have produced approximately 2.3 MMBoe. Production from the George West area is primarily from the Wilcox formation at an average depth of approximately 7,000 to 12,000 feet. Production from the Stratton area is primarily from the Vicksburg formation at an average depth of approximately 8,000 to 11,000 feet.

We operate 100% of our proved reserves in the George West-Stratton areas, including 23 gross (17 net) producing wells in the George West-Stratton areas with an average working interest of 73%. As of March 31, 2011, our properties in the field contained 1.1 MMBoe of estimated net proved reserves, approximately 33% of which are oil and NGLs, and generated average net production of 271 Boe/d for the six months ended June 30, 2011. These properties represented 4% of our total estimated proved reserves as of March 31, 2011 and 4% of our pro forma average net production for the six months ended

June 30, 2011. In addition, these properties had a standardized measure of $12.1 million as of March 31, 2011, which represented 4% of the total standardized measure for all of our estimated proved reserves. Even though these areas are collectively a small asset, we have mitigated the production decline in the George West-Stratton areas through optimization of existing field facilities and lift mechanisms. We expect that development activity of the George West-Stratton areas will consist of continued field optimization and possible future testing of shallower zones in the various fields.

Our proved reserves are estimated at the well or unit level and compiled for reporting purposes by Lime Rock Resources Operating Company's corporate reservoir engineering staff, all of whom are independent of Lime Rock Resources Operating Company's operating teams. Lime Rock Resources Operating Company maintains internal evaluations of our reserves in a secure reserve engineering database. The corporate reservoir engineering staff interacts with Lime Rock Resources Operating Company's internal petroleum engineers and geoscience professionals in each of our operating areas and with operating, accounting and marketing employees to obtain the necessary data for the reserves estimation process. Reserves are reviewed and approved internally by our senior management on a semi-annual basis. Following the consummation of this offering, we anticipate that the audit committee of our general partner's board of directors will conduct a similar review on a semi-annual basis. We expect to have our reserve estimates evaluated by Miller and Lents and Netherland Sewell, our independent third-party reserve engineers, or another independent reserve engineering firm, at least annually.

Our internal professional staff works closely with Miller and Lents and Netherland Sewell to ensure the integrity, accuracy and timeliness of data that is furnished to them for their reserve estimation process. All of the reserve information maintained in our secure reserve engineering database is provided to the external engineers. In addition, we provide Miller and Lents and Netherland Sewell other pertinent data, such as seismic information, geologic maps, well logs, production tests, material balance calculations, well performance data, operating procedures and relevant economic criteria. We make all requested information, as well as our pertinent personnel, available to the external engineers as part of their evaluation of our reserves.

Under the SEC rules, proved reserves are those quantities of oil and natural gas that by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs, and under existing economic conditions, operating methods and government regulations. The term "reasonable certainty" implies a high degree of confidence that the quantities of oil and natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

To establish reasonable certainty with respect to our estimated proved reserves, Miller and Lents and Netherland Sewell employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, electrical logs, radioactivity logs, core analyses, geologic maps and available downhole and production data, seismic data and well test data. Reserves attributable to producing wells with sufficient production history were estimated using appropriate decline curves or other performance relationships. Reserves attributable to producing wells with limited production history and proved undeveloped locations and additions to proved undeveloped reserves were estimated using performance,

log and production data from analogous wells in the surrounding area and geologic data to assess the reservoir continuity. These wells were considered to be analogous based on production performance from the same formation and completion using similar techniques.

Internal Engineer. Christopher Butta, Vice President and Chief Engineer of our general partner, is the technical person primarily responsible for overseeing the preparation of our reserves estimates. Mr. Butta is also responsible for liaison with and oversight of our third-party reserve engineers. Mr. Butta has over 28 years of industry experience. From 1991 through 2005, Mr. Butta worked at Miller and Lents, an independent oil and gas consulting firm. During his 14 years at Miller and Lents, he rose from Consulting Engineer to Senior Vice President. From 1983 to 1991, Mr. Butta worked at ARCO Oil and Gas Company. He holds a Bachelor of Science degree in Petroleum Engineering from University of Missouri-Rolla.

Miller and Lents. Miller and Lents is an independent oil and natural gas consulting firm. No director, officer, or key employee of Miller and Lents has any financial ownership in us, Lime Rock Resources Operating Company, Lime Rock Resources or any of their respective affiliates. Miller and Lents' compensation for the required investigations and preparation of its report is not contingent upon the results obtained and reported, and Miller and Lents has not performed other work for Lime Rock Resources Operating Company, Lime Rock Resources or us that would affect its objectivity. The independent engineering analysis presented in the Miller and Lents report was overseen by Ms. Leslie Fallon. Ms. Fallon is an experienced reservoir engineer having been a practicing petroleum engineer since 1983. She has more than 28 years of experience in reserves evaluation. She has a Bachelor of Science Degree in Mechanical Engineering from The University of Texas at Austin and is a Registered Professional Engineer in the State of Texas.

Netherland Sewell. Netherland Sewell is an independent oil and natural gas consulting firm. No director, officer, or key employee of Netherland Sewell has any financial ownership in us, Lime Rock Resources Operating Company, Lime Rock Resources or any of their respective affiliates. Netherland Sewell's compensation for the required investigations and preparation of its report is not contingent upon the results obtained and reported, and Netherland Sewell has not performed other work for Lime Rock Resources Operating Company, Lime Rock Resources or us that would affect its objectivity. The independent engineering analysis presented in the Netherland Sewell report was overseen by Mr. Lee E. George. Mr. George is an experienced reservoir engineer having been a practicing petroleum engineer since 1981. He has more than 29 years of experience in reserves evaluation. He has a Bachelor of Science Degree in Civil Engineering from The University of Texas at Austin and is a Registered Professional Engineer in the State of Texas.

The following table presents the estimated net proved oil and natural gas reserves attributable to the Partnership Properties, and the standardized measure amounts associated with such reserves, as of December 31, 2010 and March 31, 2011, based on reserve reports prepared by Miller and Lents and Netherland Sewell, our independent reserve engineers. The standardized measure amounts shown in the table are not intended to represent the current market value of our estimated oil and natural gas reserves.

			Partnership Properties

			As of December 31, 2010		As of March 31, 2011
Reserve Data(1):
	Estimated proved reserves:
		Oil (MBbls)		4,312		7,362
		NGLs (MBbls)		2,498		3,764
		Natural gas (MMcf)		102,774		114,939

		Total estimated proved reserves (MBoe)(2)		23,939		30,283
	Estimated proved developed reserves:
		Oil (MBbls)		3,732		5,155
		NGLs (MBbls)		2,159		2,757
		Natural gas (MMcf)		99,656		105,819

		Total estimated proved developed reserves (MBoe)(2)		22,500		25,549
	Estimated proved undeveloped reserves:
		Oil (MBbls)		580		2,207
		NGLs (MBbls)		339		1,007
		Natural gas (MMcf)		3,118		9,120

		Total estimated proved undeveloped reserves (MBoe)(2)		1,439		4,734
	Standardized Measure (in millions)(3)		$	285.5	$	342.3

(1): Our estimated net proved reserves and related standardized measure were determined using index prices for oil and natural gas, without giving effect to commodity derivative contracts, held constant throughout the life of the properties. The unweighted arithmetic average first-day-of-the-month prices for the prior twelve months were $79.43/Bbl for NYMEX-WTI oil and NGLs and $4.38/MMBtu for NYMEX-Henry Hub natural gas at December 31, 2010 and $83.41/Bbl for NYMEX-WTI oil and NGLs and $4.10/MMBtu for NYMEX-Henry Hub natural gas at March 31, 2011. 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. For NGL pricing, a differential is applied to the unweighted arithmetic average first-day-of-the-month oil prices for the prior twelve months. 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.
(2): One Boe is equal to six Mcf of natural gas or one Bbl of oil or NGLs based on a rough energy equivalency. This is a physical correlation and does not reflect a value or price relationship between the commodities.
(3): Standardized measure is calculated in accordance with Statement of Financial Accounting Standards No. 69 Disclosures About Oil and Gas Producing Activities, as codified in ASC Topic 932, Extractive Activities — Oil and Gas. 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. For a description of our commodity derivative

The data in the table above represents estimates only. Oil and natural gas reserve engineering is inherently a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured exactly. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Accordingly, reserve estimates may vary from the quantities of oil and natural gas that are ultimately recovered. For a discussion of risks associated with reserve estimates, please read "Risk Factors — Risks Related to Our Business — 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."

Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. The standardized measure amounts shown above should not be construed as the current market value of our estimated oil and natural gas reserves. The 10% discount factor used to calculate standardized measure, which is required by Financial Accounting Standard Board pronouncements, is not necessarily the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate.

The following table represents a summary of activity within our predecessor's proved undeveloped reserve category for the year ended December 31, 2010:

Our predecessor incurred $22.1 million in capital to convert proved undeveloped reserves to proved developed reserves during the year ended December 31, 2010.

All of our proved undeveloped reserves as of March 31, 2011 are scheduled to be developed on a date that is five years or less from the date the reserves were initially booked as proved undeveloped. Historically, our predecessor's drilling and development programs were substantially funded from its cash flow from operations. Our expectation is to continue to fund our drilling and development programs primarily from our cash flow from operations. Based on our current expectations of our cash flows and drilling and development programs, which includes drilling of proved undeveloped locations, we believe that we can fund the drilling of our current inventory of proved undeveloped locations and our expansions, extensions and processing of our waterfloods in the next five years from our cash flow from operations and, if needed, our new credit facility. For a more detailed discussion of our pro forma liquidity position, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations — Pro Forma Liquidity and Capital Resources."

The following table sets forth information regarding combined net production of oil and natural gas and certain price and cost information (i) of our predecessor on a historical basis and (ii) attributable to the Partnership Properties on a pro forma basis for each of the periods presented:

			Our Predecessor						Partnership Properties

			Year Ended December 31,						Year Ended December 31,		Six Months Ended June 30,
			2008		2009		2010		2010		2010		2011
			(unaudited)
Production and operating data:
	Net production volumes(1)(2):
		Oil (MBbls)		627		602		698		424		202		220
		Natural gas (MMcf)		11,750		9,076		11,287		10,118		4,880		4,667
		NGLs (MBbls)		372		363		376		279		129		112
		Total (MBoe)		2,957		2,478		2,955		2,389		1,144		1,110
		Average net production (Boe/d)		8,080		6,788		8,096		6,546		6,320		6,133
	Average sales price (excluding derivates):
		Oil (per Bbl)	$	93.86	$	57.48	$	75.46	$	75.12	$	74.72	$	91.69
		Natural gas (per Mcf)	$	8.54	$	3.72	$	4.26	$	4.22	$	4.54	$	4.17
		NGLs (per Bbl)	$	54.82	$	29.25	$	39.22	$	39.19	$	40.59	$	51.14
		Average price per Boe	$	60.74	$	31.89	$	39.09	$	35.79	$	37.12	$	40.86
	Average sales price (including realized derivative gains/losses)(3):
		Oil (per Bbl)	$	95.02	$	118.66	$	98.61	$	103.32	$	105.52	$	60.05	(4)
		Natural gas (per Mcf)	$	8.25	$	7.47	$	7.08	$	6.55	$	6.74	$	5.67
		NGLs (per Bbl)	$	54.82	$	29.25	$	39.22	$	39.19	$	40.59	$	51.14
		Average price per Boe	$	59.84	$	60.50	$	55.34	$	50.66	$	51.96	$	40.89
	Average unit costs per Boe:
		Lease operating expenses	$	6.35	$	7.70	$	8.06	$	7.99	$	7.52	$	8.38
		Production and ad valorem taxes	$	4.70	$	2.72	$	3.15	$	3.25	$	3.45	$	1.47
		Management fees	$	2.87	$	3.43	$	2.07		—		—		—
		General and administrative expenses	$	0.84	$	0.97	$	1.79	$	3.73	$	4.81	$	4.30
		Depletion and depreciation	$	26.87	$	22.74	$	18.89	$	17.03	$	17.78	$	13.87

(1): The Red Lake area constituted approximately 32% of our estimated proved reserves as of March 31, 2011. Our predecessor's production from the Red Lake area was 192, 367 and 518 MBoe for the years ended December 31, 2008, 2009 and 2010, respectively. The 2008 production was comprised of 123 Mbls of oil, 413 MMcf of natural gas and 0 Mbls of NGLs. The 2009 production was comprised of 197 Mbls of oil, 343 MMcf of natural gas and 113 Mbls of NGLs. The 2010 production was comprised of 285 Mbls of oil, 544 MMcf of natural gas and 142 Mbls of NGLs.
(2): The Potato Hills field, which we acquired in February 2010, constituted approximately 28% of our estimated proved reserves as of March 31, 2011. Our predecessor's production from the Potato Hills area was 614.3 MBoe for the year ended December 31, 2010. The 2010 production was comprised of 3,686.0 MMcf of natural gas.
(3): Includes only the realized gains (losses) from our oil and natural gas derivatives.
(4): 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.

Drilling Activities. As of September 30, 2011, our predecessor was in the process of completing two new wells, recompleting two wells and conducting a capital workover on one well on the Partnership Properties. In addition, production testing was being conducted on two recently completed new wells.

Other Exploratory and Development Activities. As of September 30, 2011, our predecessor did not have any exploratory activities in progress on the Partnership Properties.

For more information about our predecessor's historical exploratory and development activities, please read " — Oil and Natural Gas Data and Operations — Our Predecessor — Drilling Activities." Our predecessor's historical exploratory and development activities should not be considered indicative of the future performance of our program.

The following table sets forth information at March 31, 2011 relating to the productive wells in which we, on a pro forma basis, owned a working interest as of that date. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we own an interest, and net wells are approximately the sum of our fractional working interests owned in gross wells.

The following table sets forth information as of March 31, 2011 relating to our pro forma leasehold acreage. Acreage related to royalty, overriding royalty and other similar interests is excluded from this summary. As of March 31, 2011, substantially all of our leasehold acreage was held by production.

We will have no delivery commitments with respect to our production upon the closing of this offering and the contribution of the Partnership Properties to us.

The following table sets forth information with respect to wells drilled and completed by our predecessor during the periods indicated. The information should not be considered indicative of future performance, nor should a correlation be assumed between the number of productive wells drilled, quantities of reserves found or economic value.

Reserve additions due to extensions and discoveries are primarily in the proved undeveloped reserve category. We use reserve replacement rate as a measure to indicate whether we are replacing our production at a rate that will enable us to sustain our long-term production profile. The reserve replacement rate does not indicate the producing profile or life of the reserves or economic value added. As of March 31, 2011, we have identified 192 gross (158 net) recompletion, refracture stimulation and workover projects and 213 gross (140 net) proved undeveloped drilling locations on the Partnership Properties. Excluding acquisitions, we anticipate capital expenditures of approximately $13.7 million during the twelve months ending September 30, 2012, including drilling 24 gross (12 net) development wells and executing 42 gross (35 net) recompletions, refracture stimulations and workover projects.

As of March 31, 2011, we operated approximately 93% of our proved reserves. We design and manage the development, recompletion or workover for all of the wells we operate and supervise operation and maintenance activities. We do not own the drilling rigs or other oil field services equipment used for drilling or maintaining wells on the properties we operate. Independent contractors provide all the equipment and personnel associated with these activities. Pursuant to the services agreement that we will enter into with Lime Rock Resources Operating Company and Lime Rock Management upon the closing of this offering, Lime Rock Resources Operating Company and Lime Rock Management will provide management, administrative and operational services to our general partner and us to manage and operate our business. Lime Rock Resources Operating Company employs production and reservoir engineers, geologists and other specialists, as well as field personnel. Please read " — Services Agreement" and "Certain Relationships and Related Party Transactions — Agreements

Governing the Transactions — Services Agreement." We charge the non-operating partners a contractual administrative overhead charge for operating the wells. Some of our non-operated wells are managed by third-party operators who are typically independent oil and natural gas companies.

Immediately prior to the closing of this offering, we will enter into a services agreement with Lime Rock Management and Lime Rock Resources Operating Company. Under this services agreement, our general partner will reimburse each of Lime Rock Management and Lime Rock Resources Operating Company, on a monthly basis, for the allocable expenses it incurs in its performance under the services agreement, and we will reimburse our general partner for such payments it makes to Lime Rock Management and Lime Rock Resources Operating Company. Lime Rock Management and Lime Rock Resources Operating Company will have substantial discretion to determine in good faith which expenses to incur on our behalf and what portion to allocate to us.

For a more detailed description of the Services Agreement, please read "Certain Relationships and Related Party Transactions — Agreements Governing the Transactions — Services Agreement."

The typical oil and natural gas lease agreement covering our properties provides for the payment of royalties to the mineral owner for all oil and natural gas produced from any wells drilled on the leased premises. The lessor royalties and other leasehold burdens on the Partnership Properties range from 6% to 54%, resulting in a net revenue interest to us ranging from 2% to 88%, or 65% on average for most of our leases.

Substantially all of our leases are held by production and are not subject to continuous drilling obligations.

For the year ended December 31, 2010, purchases by ConocoPhillips, Seminole Energy Services, Upstream Energy and Sunoco accounted for approximately 16%, 13%, 10% and 10%, respectively, of our predecessor's total sales revenues. For the six months ended June 30, 2011, ConocoPhillips, Seminole Energy Services and Sunoco accounted for approximately 19%, 12% and 15%, respectively, of our predecessor's total sales revenues. ConocoPhillips and Sunoco purchase the oil production from our predecessor pursuant to existing agreements with terms that are currently on "evergreen" status and renew on a month-to-month basis until either party gives 30-day advance written notice of non-renewal. Seminole Energy Services purchases natural gas production from our predecessor pursuant to an existing agreement that automatically renews on a year-to-year basis until either party gives six-month advance notice of termination prior to the end of such term, and Upstream Energy markets natural gas production from our predecessor pursuant to an existing marketing agreement that automatically renews quarterly until either party gives 30-day advance written notice of termination.

If we were to lose any one of our customers, the loss could temporarily delay production and sale of our oil and natural gas in the related producing region. If we were to lose any single customer, we believe we could identify a substitute customer to purchase the impacted production volumes. However, if one or more of our larger customers ceased purchasing oil or natural gas altogether and we are unable to identify a substitute customer, this could have a detrimental effect on our production volumes in general.

We operate in a highly competitive environment for acquiring properties and securing qualified personnel. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours, which can be particularly important in the areas in which we operate. As a result, our competitors may be able to pay more for productive oil and natural gas properties and

exploratory prospects, as well as evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Our ability to acquire additional properties and to find and develop reserves will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, there is substantial competition for capital available for investment in the oil and natural gas industry.

We are also affected by competition for drilling rigs, completion rigs, workover rigs, completion services and the availability of related equipment. In recent years, the United States onshore oil and natural gas industry has experienced shortages of drilling and completion rigs, equipment, pipe and personnel, which have delayed development drilling and other exploitation activities and caused significant increases in the prices for this equipment and personnel. We are unable to predict when, or if, such shortages may occur or how they would affect our development and exploitation programs.

In addition, Lime Rock Resources, Lime Rock Partners and their affiliates are not restricted from competing with us and such entities could be competing producers in all of our operating areas, as well as competitors for acquisition opportunities. Please read " — Our Principal Business Relationships" and "Certain Relationships and Related Party Transactions" and "Risk Factors — Risks Inherent in an Investment in Us — 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."

Prior to completing an acquisition of producing oil and natural gas properties, we perform title reviews on significant leases, and depending on the materiality of properties, we may obtain a title opinion or review previously obtained title opinions. As a result, title examinations have been obtained on a significant portion of our properties. After an acquisition, we review the assignments from the seller for scrivener's and other errors and execute and record corrective assignments as necessary.

As is customary in the oil and natural gas industry, we initially conduct only a cursory review of the titles to our properties on which we do not have proved reserves. Prior to the commencement of drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant defects. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property.

We believe that we have satisfactory title to all of our material properties. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens and encumbrances will materially detract from the value of these properties or from our interest in these properties or materially interfere with our use of these properties in the operation of our business. In addition, we believe that we have obtained sufficient rights-of-way grants and permits from public authorities and private parties for us to operate our business in all material respects as described in this prospectus.

Generally, but not always, the demand for natural gas decreases during the summer months and increases during the winter months, resulting in seasonal fluctuations in the price we receive for our natural gas production. Seasonal anomalies such as mild winters or hot summers sometimes lessen this fluctuation.

Hydraulic fracturing has been a part of the completion process for wells on all of our producing properties in New Mexico, Texas and Oklahoma, and all of our properties are dependent on our ability to hydraulically fracture the producing formations with the exception of our properties in the Cowden Ranch area of Texas. We are currently conducting hydraulic fracturing activity at our Red Lake area in New Mexico. All of our leasehold acreage is currently held by production from existing wells. Therefore, fracturing is not currently required to maintain this acreage but it will be required in the future to develop the proved non-producing and proved undeveloped reserves associated with this acreage. Nearly all of our proved non-producing and proved undeveloped reserves associated with future drilling, recompletion, and refracture stimulation projects, or 26% of our total estimated proved reserves as of March 31, 2011, will be subject to hydraulic fracturing. Of our $18.0 million of estimated maintenance capital expenditures for the twelve months ending September 30, 2012, approximately $8.0 million is expected to be attributable to hydraulic fracturing.

Almost all of our hydraulic fracturing operations are conducted on vertical wells. The fracture treatments on these wells are much smaller and utilize much less water than what is typically used on most of the shale gas wells that are being drilled throughout the United States. For example, a "typical" hydraulic fracture stimulation on a Marcellus shale well is pumped in five or more stages, utilizing a total of 4 million gallons of water and 1.5 million pounds of sand. In comparison, for our wells, a large hydraulic fracture stimulation on one of our new wells would be pumped in three stages utilizing a total of 350,000 gallons of water and 430,000 pounds of sand. Typical hydraulic fracture stimulation for a recompletion of one of our existing wells would be pumped in one stage, utilizing about 125,000 gallons of water and 150,000 pounds of sand.

We follow applicable industry standard practices and legal requirements for groundwater protection in our operations, subject to close supervision by state and federal regulators (including the Bureau of Land Management on federal acreage), which conduct many inspections during operations that include hydraulic fracturing. These protective measures include setting surface casing at a depth sufficient to protect fresh water zones as determined by regulatory agencies, and cementing the well to create a permanent isolating barrier between the casing pipe and surrounding geological formations. This aspect of well design essentially eliminates a pathway for the fracturing fluid to contact any aquifers during the hydraulic fracturing operations. For recompletions of existing wells, the production casing is pressure tested prior to perforating the new completion interval.

Injection rates and pressures are monitored instantaneously and in real time at the surface during our hydraulic fracturing operations. Pressure is monitored on both the injection string and the immediate annulus to the injection string. Hydraulic fracturing operations would be shut down immediately if an abrupt change occurred to the injection pressure or annular pressure.

Regulations applicable to our operating areas do not currently require, and we do not currently evaluate, the environmental impact of typical additives used in fracturing fluid. We note, however, that approximately 98% of the hydraulic fracturing fluids we use are made up of water and sand.

We minimize the use of water and dispose of it in a way that minimizes the impact to nearby surface water by disposing excess water and water that is produced back from the wells into approved disposal or injection wells. We currently do not discharge water to the surface. We intend to investigate the possibility of utilizing produced formation water or the fracturing fluid that is produced back from wells for use in hydraulic fracturing. However, the technology for treating these fluids for use in hydraulic fracturing is not readily available in our operating areas at this time.

For information regarding existing and proposed governmental regulations regarding hydraulic fracturing and related environmental matters, please read "Business and Properties — Environmental Matters and Regulation — Water Discharges — Hydraulic Fracturing Regulation." For related risks to our unitholders, please read "Risk Factors — Risks Related to Our Business — Federal and State legislative

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

We maintain insurance coverage against potential losses that we believe is customary in the industry. We currently maintain general liability insurance and excess liability insurance with limits of $1 million and $25 million per occurrence, respectively, and $2 million and $25 million in the aggregate, respectively. There is no deductible for our general liability insurance or our excess liability insurance. Our general liability insurance covers us for, among other things, legal and contractual liabilities arising out of property damage and bodily injury, for sudden or accidental pollution liability. Our excess liability insurance is in addition to and triggered if the general liability insurance policy limits are exceeded. In addition, we maintain control of well insurance with per occurrence limits ranging from $3 million to $7.5 million and retentions ranging from $100,000 to $150,000. Our control of well policy insures us for blowout risks associated with drilling, completing and operating our wells, including above ground pollution.

We do not currently have any insurance policies in effect that are intended to provide coverage for losses solely related to our hydraulic fracturing operations. However, we believe our general liability and excess liability insurance policies would cover third-party claims for property damage and bodily injury related to our hydraulic fracturing operations in accordance with, and subject to, the terms of such policies. These policies may not cover fines, penalties or costs and expenses related to government-mandated clean up of pollution. In addition, these policies do not provide coverage for all liabilities, and we cannot assure you that the insurance coverage will be adequate to cover claims that may arise, or 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.

We enter into master services agreements, or MSAs, with various fracturing service providers. These MSAs allocate potential liabilities and risks between the parties. Under certain MSAs, we indemnify the hydraulic fracturing service providers for pollution and contamination of any kind, damages to or losses from wells or underground formations and damages to property, including pipelines, storage or production facilities. Under other MSAs, the service providers indemnify us for pollution or contamination that originates above the surface and is caused by the service provider's equipment or services, unless such pollution or contamination is caused by our negligence or willful misconduct, and we indemnify the service providers for all other pollution or contamination that may occur during operations (including that which may result from seepage or any other uncontrolled flow of oil, natural gas or other fluids from the well), unless such pollution or contamination is caused by the service provider's gross negligence or willful misconduct. Generally, we also agree to indemnify the service providers against claims arising from our employees' personal injury or death to the extent that our employees are injured by such hydraulic fracturing operations, unless resulting from the service provider's gross negligence or willful misconduct. Similarly, the service providers agree to indemnify us for liabilities arising from personal injury to or death of any of their employees, unless resulting from our gross negligence or willful misconduct. In addition, the service providers generally agree to indemnify us for loss or destruction of property or equipment that they own, unless resulting from our gross negligence or willful misconduct. In turn, we agree to indemnify the service providers for loss or destruction of property or equipment we own, unless resulting from the service provider's gross negligence or willful misconduct.

Despite the general allocation of risk discussed above, we may not succeed in enforcing such contractual allocations, could incur an unforeseen liability falling outside the scope of such allocation or may be required to enter into a MSA with terms that vary from the above allocations of risk. As a result, we may incur substantial losses that could materially and adversely affect our financial position, results of operations and cash flows.

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

Any failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties, the imposition of corrective or remedial obligations, and the issuance of orders enjoining performance of some or all of our operations. Certain environmental statutes impose strict joint and several liability for costs required to clean up and restore sites where substances, hydrocarbons or wastes have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment.

These laws and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, the Congress and federal and state agencies frequently revise environmental laws and regulations, and any changes that result in more stringent and costly waste handling, disposal and cleanup requirements for the oil and natural gas industry could have a significant impact on our operating costs.

The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly waste handling, storage, transport, disposal, or remediation requirements could have a material adverse effect on our financial position and results of operations. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we cannot assure you that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons. While we believe that we are in substantial compliance with existing environmental laws and regulations and that continued compliance with existing requirements will not materially affect us, we can give no assurance that we will continue to be in compliance or that future compliance requirements will not become overly burdensome in the future.

The following is a summary of the more significant existing environmental, health and safety laws and regulations to which our business operations are subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.

The Resource Conservation and Recovery Act, as amended, or RCRA, and comparable state statutes and their implementing regulations, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices of the U.S. Environmental Protection Agency, or EPA, most states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Federal and state regulatory agencies can seek to impose administrative, civil and criminal penalties for alleged noncompliance with RCRA and analogous state requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, and production of oil or natural gas, if properly handled, are exempt from regulation as hazardous waste under Subtitle C of RCRA. These wastes, instead, are regulated under RCRA's less stringent solid waste provisions, state laws or other federal laws. However, it is possible that certain oil and natural gas exploration, development and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial position.

The Comprehensive Environmental Response, Compensation and Liability Act, as amended, or CERCLA, also known as the Superfund law, and comparable state laws impose liability, without regard to fault or legality of conduct, on classes of persons considered to be responsible for the release of a "hazardous substance" into the environment. These persons include the current and past owner or operator of the site where the release occurred, and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several, strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, neighboring landowners and other third-parties may file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. Despite the "petroleum exclusion" under CERCLA, we may generate materials in the course of our operations that may be regulated as hazardous substances.

We currently own, lease, or operate numerous properties that have been used for oil and natural gas exploration, production and processing for many years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or hydrocarbons may have been released on, under or from the properties owned or leased by us, or on, under or from other locations, including off-site locations, where such substances have been taken for disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons was not under our control. These properties and the substances disposed or released on, under or from them may be subject to CERCLA, RCRA, and analogous state laws. Under such laws, we could be required to undertake response or corrective measures, which could include removal of previously disposed substances and wastes, cleanup of contaminated property or performance of remedial plugging or pit closure operations to prevent future contamination. We are not currently aware of any facts, events or conditions relating to such requirements that could materially impact our financial condition or results of operations.

The Federal Water Pollution Control Act, as amended, also known as the Clean Water Act, and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including oil and hazardous substances, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or an analogous state agency. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. Spill prevention, control and countermeasure, or SPCC,

plan requirements imposed under the Clean Water Act require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws required individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. The Oil Pollution Act of 1990, as amended, or OPA, amends the Clean Water Act and establishes strict liability and natural resource damages liability for unauthorized discharges of oil into waters of the United States. OPA requires owners or operators of certain onshore facilities to prepare Facility Response Plans for responding to a worst case discharge of oil into waters of the United States.

Hydraulic Fracturing Regulation. It is customary to recover natural gas from deep shale formations through the use of hydraulic fracturing, combined with sophisticated horizontal drilling. Hydraulic fracturing involves the injection of water, sand and chemical additives under pressure into rock formations to stimulate natural gas production. Hydraulic fracturing is also used to complete conventional vertical oil and gas wells. Due to public concerns raised regarding the potential impacts of hydraulic fracturing on groundwater quality, legislative and regulatory efforts at the federal level and in some states have been initiated to require or make more stringent the permitting and compliance requirements for hydraulic fracturing operations. The U.S. Congress is considering legislation to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of "underground injection" and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process. Members of Congress have also been investigating the activities of certain companies that provide hydraulic fracturing services. EPA has commenced a multi-year study of the potential environmental impacts of hydraulic fracturing activities, the results of which are anticipated to be available by late 2012. On October 21, 2011, the EPA also 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. Several states have also proposed or adopted legislative or regulatory restrictions on hydraulic fracturing, including states in which we operate. For example, Texas recently passed a law requiring its Railroad Commission, or RRC, to establish a disclosure process for hydraulic fracturing fluids. On August 29, 2011, the RRC proposed regulations that describe the disclosure process. In addition, at least three local governments in Texas have imposed temporary moratoria on drilling permits within city limits so that local ordinances may be reviewed to assess their adequacy to address such activities. Disclosure of chemicals used in the hydraulic fracturing process could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. Adoption of legislation amending the Safe Drinking Water Act or of any implementing regulations placing restrictions on hydraulic fracturing activities could impose operational delays, increased operating costs and additional regulatory burdens on our exploration and production activities, which could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.

The federal Clean Air Act, and comparable state laws, regulate emissions of various air pollutants through air emissions standards, construction and operating permitting programs and the imposition of other compliance requirements. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions. The need to obtain permits has the potential to delay the development of oil and natural gas projects. We may be required to incur certain capital expenditures in the next few years for air pollution control equipment or other air emissions-related issues. For example, on August 23, 2011, the EPA published four sets of new rules that, if adopted, will impose new standards for air emissions from oil and natural gas development and production operations, which may require us to incur additional expenses to control air emissions from current

operations and during new well developments by installing emissions control technologies and adhering to a variety of work practice and other requirements. Though the regulations ultimately adopted may change, we do not believe that such requirements will have a material adverse effect on our operations.

Recent scientific studies have suggested that emissions of certain gases, commonly referred to as "greenhouse gases" and including carbon dioxide and methane, may be contributing to warming of the Earth's atmosphere. In response to the scientific studies, international negotiations to address climate change have occurred. The United Nations Framework Convention on Climate Change, also known as the "Kyoto Protocol," became effective on February 16, 2005 as a result of these negotiations, but the United States did not ratify the Kyoto Protocol. At the end of 2009, an international conference to develop a successor to the Kyoto Protocol issued a document known as the Copenhagen Accord. Pursuant to the Copenhagen Accord, the United States submitted a greenhouse gas emission reduction target of 17% compared to 2005 levels. We continue to monitor the international efforts to address climate change. Their effect on our operations cannot be determined with any certainty at this time.

On December 15, 2009, the EPA published its findings that emissions of carbon dioxide, or CO2, methane, and other greenhouse gases, or GHGs, present an endangerment to public heath and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth's atmosphere and other climate changes. These findings allow the EPA to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. On April 1, 2010, the EPA issued final rules limiting emissions of GHGs from motor vehicles beginning with the 2012 model year. The EPA has asserted that these final motor vehicle GHG emission standards trigger Clean Air Act construction and operating permit requirements for stationary sources, commencing when the motor vehicle standards took effect on January 2, 2011. On June 3, 2010, the EPA published its final rule to address the permitting of GHG emissions from stationary sources under the Prevention of Significant Deterioration, or "PSD," and Title V permitting programs. This rule "tailors" these permitting programs to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting. EPA has determined that facilities that are required to obtain PSD permits for their GHG emissions also will be required to reduce those emissions according to "best available control technology" standards for GHG that have yet to be developed. In addition, in October 2009, the EPA published a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the U.S. beginning in 2011 for emissions occurring in 2010. In November 2010, the EPA issued final rules that expand this GHG reporting rule to include onshore oil and natural gas production, processing, transmission, storage, and distribution facilities. Reporting of GHG emissions from such facilities is required on an annual basis, with reporting beginning in 2012 for emissions occurring in 2011.

In addition, both houses of Congress have actively considered legislation to reduce emissions of GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved. Because regulation of GHG emissions is relatively new, further regulatory, legislative and judicial developments are likely to occur. Such developments may affect how these GHG initiatives will impact us. In addition to these regulatory developments, recent judicial decisions have allowed certain tort claims alleging property damage to proceed against GHG emissions sources may increase our litigation risk for such claims. The adoption of any legislation or regulations that requires reporting of GHGs or otherwise limits emissions of GHGs from our equipment and operations could require us to incur costs to monitor and report on GHG emissions or reduce emissions of GHGs associated with our

operations, and such requirements also could adversely affect demand for the oil and natural gas that we produce.

Legislation or regulations that may be adopted to address climate change could also affect the markets for our products by making our products more or less desirable than competing sources of energy. To the extent that our products are competing with higher greenhouse gas emitting energy sources such as coal, our products would become more desirable in the market with more stringent limitations on greenhouse gas emissions. To the extent that our products are competing with lower greenhouse gas emitting energy sources such as solar and wind, our products would become less desirable in the market with more stringent limitations on greenhouse gas emissions. We cannot predict with any certainty at this time how these possibilities may affect our operations.

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

Oil and natural gas exploration, development and production activities on federal lands are subject to the National Environmental Policy Act, as amended, or NEPA. NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. Currently, we have production activities on federal lands. Governmental permits or authorizations that are subject to the requirements of NEPA are required for our current activities and any future or proposed development plans on federal lands. This process has the potential to delay the development of oil and natural gas projects in these areas.

Additionally, environmental laws such as the Endangered Species Act, as amended, or ESA, may impact exploration, development and production activities on public or private lands. ESA provides broad protection for species of fish, wildlife and plants that are listed as threatened or endangered in the U.S. and prohibits taking of endangered species. Federal agencies are required to ensure that any action authorized, funded or carried out by them is not likely to jeopardize the continued existence of listed species or modify their critical habitat. While some of our facilities may be located in areas that are designated as habitat for endangered or threatened species, we believe that we are in substantial compliance with ESA. However, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas.

We are subject to the requirements of the federal Occupational Safety and Health Act, as amended, or OSHA, and comparable state statutes whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the Emergency Planning and Community Right to Know Act and implementing regulations, and similar state statutes and regulations require that we organize and/or disclose information about hazardous materials used or produced in our operations and that this information be provided to employees, state and local governmental authorities and citizens. We believe that we are in substantial compliance with all applicable laws and regulations relating to worker health and safety.

The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Additionally, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the oil and natural gas industry with similar types, quantities and locations of production.

Legislation continues to be introduced in Congress, and the development of regulations continues in the Department of Homeland Security and other agencies concerning the security of industrial facilities, including oil and natural gas facilities. Our operations may be subject to such laws and regulations. Presently, we do not believe that compliance with these laws will have a material adverse impact on us.

Our operations are subject to various types of regulation at federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states, and some counties and municipalities, in which we operate also regulate one or more of the following:

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration, while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction.

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

Although natural gas prices are currently unregulated, Congress historically has been active in the area of natural gas regulation. We cannot predict whether new legislation to regulate natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on the operations of our properties.

Sales of crude oil, condensate and NGLs are not currently regulated and are made at market prices. However, Congress could reenact price controls in the future. Sales of crude oil are affected by the availability, terms and cost of transportation. The FERC also regulates interstate oil pipeline transportation rates.

State Regulation. The various states in which we own and operate properties regulate the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. For example, Texas currently imposes a 4.6% severance tax on oil production and a 7.5% severance tax on natural gas production. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amount of natural gas that may be produced from our wells and to limit the number of wells or locations we can drill.

The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us.

Our general partner has sole responsibility for conducting our business and for managing our operations. However, neither we, our general partner nor our operating subsidiary have any employees. At 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. Please read "Certain Relationships and Related Party Transactions — Agreements Governing the Transactions — Services Agreement."

As of June 30, 2011, Lime Rock Resources Operating Company had 62 employees, including six engineers, four geologists and six land professionals, who provide services to Lime Rock Resources and who will perform services for us. As of June 30, 2011, Lime Rock Management had 24 employees providing services to Lime Rock Resources, all of whom will perform services for us. Each of Lime Rock Resources Operating Company and Lime Rock Management has an agreement with Insperity PEO Services, L.P., a professional employer organization, pursuant to which Insperity provides them with full service human resources services in exchange for a service fee. As a result, all of the employees who will provide services to us will be co-employees of Insperity. None of these employees are represented by labor unions or covered by any collective bargaining agreement. We believe that relations between Lime Rock Resources Operating Company and Lime Rock Management and their employees are satisfactory. We will also contract for the services of independent consultants involved in land, engineering, regulatory, accounting, legal, financial and other disciplines as needed.

Lime Rock Management currently leases approximately 42,600 square feet of office space in Houston, Texas at 1111 Bagby Street, Suite 4600, Houston, Texas 77002. Lime Rock Management will allocate a portion of its lease expense to us for our proportionate share of the cost of the office space. The leases expire on or before December 31, 2015.

Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, neither we nor our general partner or predecessor is currently a party to any material legal proceedings. In addition, we are not aware of any significant legal or governmental proceedings against us or our general partner or predecessor, or contemplated to be brought against us or our general partner or predecessor, under the various environmental protection statutes to which we or they are subject.

Our general partner will manage our operations and activities on our behalf through its executive officers and board of directors. References in this prospectus to our officers and board of directors therefore refer to the officers and board of directors of our general partner. 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. As is commonly the case with publicly traded limited partnerships, we do not directly employ any of the persons responsible for the management or operations of our business. These functions are performed by the employees of Lime Rock Management and Lime Rock Resources Operating Company pursuant to a services agreement. As such, all of our general partner's executive officers are employees of Lime Rock Management. Such officers will devote their time as needed to conduct our business and affairs pursuant to the services agreement described below.

Our general partner is not elected by our unitholders and will not be subject to re-election on an annual or other continuing basis in the future. Further, our unitholders will not be entitled to elect the directors of our general partner, who will all be appointed by Lime Rock Management, or directly or indirectly participate in our management or operations. Our general partner owes a fiduciary duty to our unitholders. However, our partnership agreement contains provisions that reduce the fiduciary duties that our general partner owes to our unitholders. Please read "Conflicts of Interest and Fiduciary Duties — Fiduciary Duties."

Prior to the time our registration statement is declared effective, we expect that the board of directors of our general partner will have seven members, three of whom will be independent as defined under the independence standards established by the NYSE and SEC rules. The NYSE does not require a listed limited partnership like us to have a majority of independent directors on the board of directors of our general partner or to establish a compensation committee or a nominating and corporate governance committee. We are, however, required to have an audit committee of at least three members, all of which are required to meet the independence and experience standards established by the NYSE and SEC rules, subject to certain transitional relief during the one-year period following the consummation of this offering. Please see "— Director Independence" and "— Committees of the Board of Directors" below.

Services Agreement. Neither we nor our general partner will 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. Generally, the executive officers of our general partner (other than the Chief Financial Officer who is devoted full-time to our business) will allocate their time between managing our business and affairs and the business and affairs of Lime Rock Resources and its affiliates. These shared executive officers may face a conflict regarding the allocation of their time between our business and the other business interests of Lime Rock Resources and its affiliates. Pursuant to the services agreement, Lime Rock Management and Lime Rock Resources Operating Company intend to cause our executive officers and shared personnel to devote as much time to the management of our business and affairs as is necessary for the proper conduct of our business and affairs. However, it is anticipated that our executive officers, other than our Chief Financial Officer, and other shared personnel will devote less than a majority of their time to our business for the foreseeable future. Neither our general partner, Lime Rock Management nor Lime Rock Resources Operating Company will receive a management fee or other form of compensation in connection with the management and operation of our business or the provision of services and personnel pursuant to the services agreement, but we will reimburse them for all expenses they incur and payments they make on our behalf. Please read "— Reimbursement of Expenses of Our General

Partner" and "Certain Relationships and Related Party Transactions — Agreements Governing the Transactions — Services Agreement."

The following table sets forth certain information regarding the current directors, director nominees and executive officers of our general partner upon consummation of this offering.

Directors are elected for one-year terms by Lime Rock Management. Our general partner's directors hold office until the earlier of their death, resignation, removal or disqualification or until their successors have been appointed and qualified. Officers serve at the discretion of the board of directors. All of our executive officers, other than our Chief Financial Officer who is devoted full-time to our business, also serve as executive officers of Lime Rock Resources, an affiliate of our general partner. There are no familial relationships among any of our general partner's directors or executive officers. In evaluating director candidates, Lime Rock Management will assess whether a candidate possesses the integrity, judgment, knowledge, experience, skill and expertise that are likely to enhance the ability of the board of directors to manage and direct our affairs and business, including, when applicable, to enhance the ability of the committees of the board to fulfill their duties. While Lime Rock Management may consider diversity among other factors when considering director nominees, it did not apply any specific policy with regard to selecting and appointing directors to the board of directors. However, when appointing new directors, Lime Rock Management will consider each individual director's qualifications, skills, business experience and capacity to serve as a director, and the diversity of these attributes for the board of directors as a whole.

Eric D. Mullins — Co-Chief Executive Officer and Chairman. Eric D. Mullins was appointed Co-Chief Executive Officer and the Chairman of the board of directors of our general partner in May 2011. Mr. Mullins also serves as a Managing Director and Co-Chief Executive Officer of Lime Rock Resources, which positions he has held since April 2005 and October 2008, respectively. Prior to joining Lime Rock Resources, Mr. Mullins worked in the Investment Banking Division of The Goldman Sachs Group, Inc. from August 1990 to April 2005, serving as a Vice President from 1994 to 1999 and as a Managing Director from 1999 to April 2005. Mr. Mullins spent almost all of those 15 years at Goldman Sachs in the Energy & Power Group, where he led numerous financing, structuring, and strategic advisory transactions. Mr. Mullins also serves on the Board of Trustees of the YMCA Retirement Fund. Mr. Mullins is a graduate of Stanford University, with a Bachelor of Arts degree, and the Wharton School of the University of Pennsylvania, with a Master of Business Administration. We believe that Mr. Mullins' extensive experience in the investment banking industry related to energy transactions, as well as his relationships with Lime Rock Management and its affiliated funds, particularly his service as the Co-Chief Executive Officer of Lime Rock Resources, bring important experience and skill to the board of directors.

Charles W. Adcock — Co-Chief Executive Officer and Director. Charles W. Adcock was appointed Co-Chief Executive Officer and a member of the board of directors of our general partner in May 2011. Mr. Adcock also serves as a Managing Director and Co-Chief Executive Officer of Lime Rock Resources, which positions he has held since May 2005 and October 2008, respectively. From 1993 to 2004, Mr. Adcock worked in various positions at The Houston Exploration Company, a publicly traded independent North American oil and natural gas producer, serving as its Senior Vice President from 2001 through December 2004, at which time he retired, and the head of its Acquisitions group from 1993 to 2000. Prior to joining Houston Exploration, Mr. Adcock held various engineering and managerial positions with NERCO Oil & Gas, Union Texas Petroleum, Apache Corporation, American Natural Resources and Aminoil USA. Mr. Adcock is a graduate of Texas A&M University, with a Bachelor of Science degree in Civil Engineering, and the University of St. Thomas, with a Master of Business Administration. We believe that Mr. Adcock's 35 years of experience at independent exploration and production companies in the energy industry, as well as his relationships with Lime Rock Management and its affiliated funds, particularly his service as the Co-Chief Executive Officer of Lime Rock Resources, bring important experience and skill to the board of directors.

Christopher A. Butta — Vice President and Chief Engineer. Christopher A. Butta was appointed Vice President and Chief Engineer of our general partner in May 2011. Mr. Butta also serves as the Vice President of Engineering and Chief Engineer of Lime Rock Resources, which positions he has held since October 2008. From July 2005 to October 2008, Mr. Butta served as the Vice President of Engineering of Lime Rock Resources. From 1991 through July 2005, Mr. Butta worked for Miller and Lents, Ltd., a leading domestic and international consulting firm specializing in oil and gas reserve evaluations and economic analyses. During his 14 years at Miller and Lents, Mr. Butta rose from Consulting Engineer to Senior Vice President. In those capacities, he analyzed oil and gas reserves throughout the United States to provide engineering reserve estimates. Prior to that, Mr. Butta spent nine years as an operations/analytical engineer at ARCO Oil and Gas Company. Mr. Butta is a graduate of the University of Missouri-Rolla, with a Bachelor of Science degree in Petroleum Engineering.

Jaime R. Casas — Vice President, Chief Financial Officer and Secretary. Jaime R. Casas was appointed Vice President, Chief Financial Officer and Secretary of our general partner in July 2011. Prior to joining our general partner in June 2011, Mr. Casas served as Vice President, Chief Financial Officer of Laredo Energy, a privately held oil and gas company, from May 2009 to June 2011. While at Laredo Energy, Mr. Casas' primary responsibilities were managing accounting, finance and certain business development functions. From November 2008 until joining Laredo Energy in May 2009, Mr. Casas worked as an independent financial consultant. From 1999 to October 2008 and 1995 to 1997, Mr. Casas worked in various positions in the investment banking energy groups at Donaldson, Lufkin & Jenrette and at Credit Suisse following Credit Suisse's acquisition of DLJ, including as a Director, Vice President, Associate and Analyst. While at Credit Suisse, Mr. Casas' primary focus was on capital and advisory transactions for exploration and production companies. From 1993 to 1995, Mr. Casas worked for Accenture as a management information consultant in the energy group. Mr. Casas is a graduate of Texas A&M University, with a Bachelor of Business Administration degree, and the Wharton School of the University of Pennsylvania, with a Master of Business Administration.

C. Timothy Miller — Vice President and Chief Operating Officer. C. Timothy Miller was appointed Vice President and Chief Operating Officer of our general partner in May 2011. Mr. Miller also serves as the Vice President of Operations and Chief Operating Officer of Lime Rock Resources, which positions he has held since October 2008. From May 2005 to October 2008, Mr. Miller served as Vice President of Operations of Lime Rock Resources. From 1984 until April 2005, Mr. Miller worked for El Paso Corporation and for Coastal Oil and Gas Company before it merged with El Paso in 2001. During this time, Mr. Miller served in positions of increasing responsibility, working as a petroleum engineer and rising to the position of Vice President-Upper Gulf Coast Production for Coastal Oil and Gas Corporation in 1999. After Coastal's merger with El Paso, Mr. Miller served as Vice President-Gulf of Mexico Production, Vice President-Texas Gulf Coast Technical Group and finally Vice President,

Texas Gulf Coast Division, where he was responsible for all of El Paso Corporation's operations in the Gulf Coast area. From 1982 to 1984, Mr. Miller worked as a petroleum engineer for Petro-Lewis Corporation. Mr. Miller is a graduate of the University of Missouri-Rolla, with a Bachelor of Science degree in Petroleum Engineering, and Oklahoma City University, with a Master of Business Administration.

John A. Bailey — Director Nominee. We expect that Mr. Bailey will be appointed to serve on the board of directors of our general partner prior to the time that the registration statement is declared effective. Mr. Bailey has been Co-Portfolio Manager, Global Natural Resources, and a Senior Research Analyst at ING Investment Management since June 2011. Mr. Bailey was a founder and Managing Partner of 1859 Partners LLC, an energy investment partnership, from March 2009 until June 2011. From August 2008 until March 2009, Mr. Bailey was Managing Partner of J. Bailey & Co LLC, an energy industry consulting company. From May 2006 until its merger with Denbury Resources Inc. in March 2010, Mr. Bailey served on the board of directors and audit committee of Encore Acquisition Company, a NYSE listed oil and gas exploration and production company. From December 2006 until August 2008, Mr. Bailey was a Portfolio Manager, Global Energy, at Carlyle—Blue Wave Partners Management, LP, an investment partnership. Mr. Bailey served as a director of CrossPoint Energy, an oil and gas exploration and production company listed on the OTC Bulletin Board, from January 2005 until October 2007. From March 2005 to October 2006, Mr. Bailey was a Vice President, Energy at Amaranth Group LLC, an investment fund, and a consultant to Amaranth Group LLC from October 2004 until March 2005. From October 2000 until August 2004, Mr. Bailey was an equity research analyst and Vice President of Equity Research for Deutsche Bank Securities focusing on the exploration and production industry in North America. From May 1997 until October 2000, Mr. Bailey was part of the oil and natural gas equity research group at Donaldson, Lufkin & Jenrette, Inc. and from May 1993 until May 1997, Mr. Bailey was part of the economic fixed income research group at Donaldson, Lufkin & Jenrette, Inc. Mr. Bailey received a Bachelor of Arts degree in Economics and Government from Cornell University. The board of directors of our general partner believes that Mr. Bailey should be nominated as a director because of his prior financial and energy investment experience and board and audit committee service.

Milton Carroll — Director Nominee. We expect that Mr. Carroll will be appointed to serve on the board of directors of our general partner prior to the time that the registration statement is declared effective. Mr. Carroll is Chairman and founder of Instrument Products, Inc., an oil-tool manufacturing company in Houston, Texas. Mr. Carroll currently serves as Chairman of Houston-based CenterPoint Energy, Inc., where he has been a director since 1992. He has also served as a director of Halliburton Company since 2006, where he is a member of the compensation committee and the nominating and corporate governance committee; Western Gas Holdings, LLC, the general partner of Western Gas Partners, LP, since April 2008, where he is chairman of the special committee; and LyondellBasell Industries N.V. since July 2010, where he is the chairman of the compensation committee and a member of the nominating and governance committee, and formerly a member of the audit committee. Additionally, Mr. Carroll has served as a director of Healthcare Service Corporation, a Chicago-based company operating through its Blue Cross and Blue Shield divisions in Illinois, New Mexico, Oklahoma and Texas, since 1998 and as its chairman since 2002. Mr. Carroll previously served as a director of EGL, Inc. from 2003 to 2007; DCP Midstream GP, LLC, the general partner of DCP Midstream Partners, LP, from 2005 to 2006; Devon Energy Corporation from 2003 to 2005; and Texas Eastern Products Pipeline Company, LLC, the general partner of TEPPCO Partners, L.P., from 1997 to 2005. Mr. Carroll holds a Bachelor of Science degree in Industrial Technology from Texas Southern University. The board of directors of our general partner believes that Mr. Carroll should be nominated as a director because of his current and prior board and committee experience and his knowledge of the oil and natural gas industry.

Jonathan C. Farber — Director. Jonathan C. Farber was appointed as a member of the board of directors of our general partner in May 2011. Mr. Farber also serves as a Managing Director of Lime Rock Partners, a private equity firm he co-founded in 1998 to focus on investments of growth capital in

energy companies worldwide, as well as Manager of the general partner of Lime Rock Management and Fund II and Managing Member of the general partner of Fund I. Mr. Farber began his career in 1990 in the Investment Research Department of Goldman Sachs, rising from a securities analyst to Vice President in the Investment Banking Division, where he was involved in private equity and large merger and acquisition transactions. Mr. Farber currently serves on the board of directors of Arena Exploration, Augustus Energy Partners, Black Shire Energy, CrownRock, Laricina Energy, PDC Mountaineer, RMP Energy, and Vantage Energy. He previously served on the board of directors of Coronado Resources, Deer Creek Energy, LMP Exploration Holdings, Torex Resources, Slate River Resources, U.S. Exploration Holdings, and Venture Production. Mr. Farber is a graduate of the School of Foreign Service of Georgetown University, with a Bachelor of Science in Foreign Service degree. We believe that Mr. Farber's extensive financial, investment banking and private equity experience, as well as his experience on the boards of directors of public and numerous private energy companies, bring substantial leadership skill and experience to the board of directors.

Robert T. O'Connell — Director Nominee. We expect that Mr. O'Connell will be appointed to serve on the board of directors of our general partner prior to the time that the registration statement is declared effective. Mr. O'Connell served as a director of CenterPoint Energy, Inc., an energy delivery company listed on the NYSE, from 2004 until April 2011 when he retired, and also served, at various times during his tenure, as Chairman of the finance committee and on the audit committee of CenterPoint Energy. Mr. O'Connell also served as a director of GulfMark Offshore, Inc., a NYSE-listed provider of marine services to offshore exploration and production companies from 2006 to June 2011 when he retired, and also served on the audit committee of GulfMark during his tenure. From 1997 to 2003, Mr. O'Connell served as a director of RWD Technologies, Inc., a professional services company, and as its Chief Financial Officer from August 2000 to July 2001, and Senior Vice President of strategic business planning from August 1997 to July 2001. Mr. O'Connell served as Senior Vice President and Chief Staff Officer of EMC Corporation, a provider of intelligent enterprise storage and retrieval technology listed on the NYSE, from 1995 to 1997. Between 1965 and 1994, Mr. O'Connell held various positions at General Motors Corporation, a NYSE listed global automotive company, including Chief Financial Officer of General Motors Corporation from 1988 to 1992 and Chairman and Chief Executive Officer of General Motors Acceptance Corporation from 1992 to 1994. Beginning in 2003, he served two terms as a Governor-appointed member of the Boston Finance Commission which oversees the City of Boston. Mr. O'Connell earned a Bachelor of Arts degree in Economics from Yale University and a Master of Business Administration from Harvard Business School. The board of directors of our general partner believes that Mr. O'Connell should be nominated as a director because of his financial and executive management expertise, including his experience as the Chief Financial Officer of a major public corporation, and his prior board experience.

Townes G. Pressler, Jr. — Director. Townes G. Pressler, Jr. was appointed as a member of the board of directors of our general partner in May 2011. Mr. Pressler also serves as a Managing Director of Lime Rock Partners, a position he has held since joining Lime Rock Partners in 2007. From 2004 to 2007, Mr. Pressler served as Principal of Peregrine Oil & Gas LP, a private equity-backed independent oil and natural gas producer he co-founded focused on the Gulf of Mexico. From 2002 to 2004, Mr. Pressler worked for Harrison Lovegrove & Co. as a Managing Director. From 1996 to 2002, Mr. Pressler served in various capacities at Donaldson, Lufkin & Jenrette, later becoming Managing Director of the Global Energy Group of Credit Suisse after Credit Suisse's acquisition of DLJ. Prior to that time, Mr. Pressler worked for five years as an energy investment banker and three years as an energy commercial lender. Mr. Pressler currently serves on the board of directors of Black Shire Energy, Braden Exploration, Chinook Energy Inc., Lafayette Workboat Holdings and TAW Energy Services. He previously served on the board of directors of PDC Mountaineer. Mr. Pressler is a graduate of Washington & Lee University, with a Bachelor of Arts degree, and The University of Texas at Austin, with a Master of Business Administration. We believe that Mr. Pressler's considerable financial and energy investment banking experience, as well as his experience on the boards of directors of numerous private energy companies, bring important and valuable skills to the board of directors.

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. Our general partner will reimburse each of Lime Rock Management and Lime Rock Resources Operating Company, on a monthly basis, for the allocable expenses it incurs in its performance under the services agreement, and we will reimburse our general partner for such payments it makes to Lime Rock Management and Lime Rock Resources Operating Company. These expenses include, among other things, salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and other expenses allocated to our general partner. Lime Rock Management and Lime Rock Resources Operating Company will have substantial discretion to determine in good faith which expenses to incur on our behalf and what portion to allocate to us. In turn, our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. Please read "Certain Relationships and Related Transactions — Agreements Governing Transactions." For further discussion of the reimbursements that Lime Rock Management and Lime Rock Resources Operating Company will be entitled to receive relating to services provided in connection with the services agreement, please read "Certain Relationships and Related Party Transactions — Agreements Governing the Transactions — Services Agreement."

In accordance with the rules of the NYSE, Lime Rock Management must appoint at least one independent director prior to the listing of our common units on the NYSE, one additional member within three months of that listing, and one additional independent member within twelve months of that listing. We expect that Lime Rock Management will have appointed all three independent directors to the board of directors of our general partner by the date our common units first trade on the NYSE.

The board of directors of our general partner will have an audit committee and a conflicts committee. We do not expect that we will have a compensation committee, but rather that our board of directors or an appointed committee will approve equity grants to directors and employees. As noted above, the NYSE does not require a listed limited partnership to establish a compensation committee or a nominating and corporate governance committee.

We are required to have an audit committee of at least three members, and all its members are required to meet the independence and experience standards established by the NYSE and rules of the SEC, subject to certain transitional relief during the one-year period following consummation of this offering as described above. The audit committee will assist the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and partnership policies and controls. The audit committee will have the sole authority to (1) retain and terminate our independent registered public accounting firm, (2) approve all auditing services and related fees and the terms thereof performed by our independent registered public accounting firm and (3) pre-approve any non-audit services and tax services to be rendered by our independent registered

public accounting firm. The audit committee will also be responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm will be given unrestricted access to the audit committee and our management, as necessary.

Our partnership agreement requires that a conflicts committee be composed of entirely one or more independent members of the board of directors of our general partner. The conflicts committee will review specific matters that the board of directors believes may involve conflicts of interest (including certain transactions with affiliates of our general partner, including Lime Rock Resources and Lime Rock Partners) and that the board determines to submit to the conflicts committee for review. Our general partner may, but is not required to, seek approval from the conflicts committee of a resolution of a conflict of interest with our general partner or affiliates. The conflicts committee will determine if the resolution of the conflict of interest is fair and reasonable to us. The members of the conflicts committee may not be officers or employees of our general partner or directors, officers or employees of its affiliates, including Lime Rock Management, Lime Rock Resources and Lime Rock Partners, and must meet the independence standards established by the NYSE Listed Company Manual and the Securities Exchange Act to serve on an audit committee of a board of directors, and certain other requirements. Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders. Please read "Conflicts of Interest and Fiduciary Duties — Conflicts of Interest."

Leadership of our general partner's board of directors is vested in a Chairman of the board. Mr. Eric D. Mullins serves as the Chairman of the board and Co-Chief Executive Officer of our general partner. Our general partner's board of directors has determined that the combined roles of Chairman and Co-Chief Executive Officer allows the board to take advantage of the leadership skills of Mr. Mullins and is appropriate because Mr. Mullins works closely with our management team on a daily basis and is in the most knowledgeable position to determine the timing for board meetings and propose agendas for meetings. However, any director can establish agenda items for a board meeting. Our general partner's board of directors has also determined that having each of the Co-Chief Executive Officers serve as directors enhances understanding and communication between management and the board of directors, allows for better comprehension and evaluation of our operations and ultimately improves the ability of the board of directors to perform its oversight role. Because our Chairman is a member of management and not independent, the board will appoint a lead independent director to preside at separate meetings of the non-management directors.

The management of enterprise-level risk may be defined as the process of identification, management and monitoring of events that present opportunities and risks with respect to the creation of value for our unitholders. The board of directors of our general partner has delegated to management the primary responsibility for enterprise-level risk management, while retaining responsibility for oversight of our executive officers in that regard. Our executive officers will offer an enterprise-level risk assessment to the board of directors at least once every year.

We and our general partner were formed in April 2011. As such, our general partner did not accrue any obligations with respect to executive compensation for its directors and executive officers for the fiscal year ended December 31, 2010, or for any prior periods. Accordingly, we are not presenting any compensation for historical periods. We have not paid or accrued any amounts for executive compensation for the 2010 fiscal year.

All of the executive officers of our general partner are employed by Lime Rock Management and will manage the day-to-day affairs of our business. These executive officers intend to devote as much time to the management of our business as is necessary for the proper conduct of our business and affairs. However, we expect that the executive officers, other than our Chief Financial Officer who is devoted full-time to our business, will devote less than a majority of their time to us. Messrs. Adcock, Mullins and Butta will devote approximately 20% of their time to us, respectively, and Mr. Miller will devote approximately 25% of his time to us. The amount of time that each of our executive officers, other than our Chief Financial Officer, devotes to our business will be subject to change depending on our activities, the activities of Lime Rock Resources to which they also provide services, and any acquisitions or dispositions made by us or Lime Rock Resources.

Because the executive officers of our general partner are employees of Lime Rock Management, compensation will be paid by Lime Rock Management and reimbursed by our general partner. We will be obligated to reimburse our general partner for all payments it makes to Lime Rock Management and Lime Rock Resources Operating Company under the services agreement, which will include the annual compensation of Mr. Casas and the portion of the annual compensation of Messrs. Adcock, Mullins, Butta and Miller allocable to their service as executive officers of our general partner.

The executive officers of our general partner, as well as the employees of Lime Rock Resources Operating Company who provide services to us, may participate in employee benefit plans and arrangements sponsored by Lime Rock Management, including plans that may be established in the future. Neither Lime Rock Management nor our general partner has entered into, nor anticipates entering into, any employment agreements with any of our executive officers.

Effective upon completion of this offering, we expect our board of directors to grant 39,474 restricted units to Mr. Casas pursuant to our long-term incentive plan. These restricted units are expected to vest over three years in equal amounts (subject to rounding) on the anniversary date of the closing of this offering and will be entitled to receive quarterly distributions during the vesting period. In addition, any unvested restricted units will be subject to forfeiture upon termination of Mr. Casas' employment with Lime Rock Management for any reason other than death or disability. Following the closing of this offering, the board of directors of our general partner may grant awards to our other executive officers, key employees and our outside directors pursuant to the long-term incentive plan. However, the board of directors of our general partner has not made any determination as to the number of such awards, the type of awards or whether or when any such awards would be granted.

As a limited partnership, we are not required by the NYSE to establish a compensation committee. Although the board of directors of our general partner does not currently intend to establish a compensation committee, it may do so in the future.

All of our general partner's executive officers and other employees necessary to operate our business will be employed and compensated by Lime Rock Management and Lime Rock Resources Operating Company, subject to reimbursement by our general partner. We and our general partner were formed in April 2011; therefore, we incurred no cost or liability with respect to the compensation of our executive officers, nor has our general partner accrued any liabilities for management incentive or retirement benefits for our executive officers for the fiscal year ended December 31, 2010 or for any prior periods.

Our general partner's executive officers will manage and operate our business as part of the services provided by Lime Rock Management to our general partner under the services agreement. The

compensation for all of our executive officers will be indirectly paid by us to the extent provided for in partnership agreement because we will reimburse our general partner for payments it makes to Lime Rock Management and Lime Rock Resources Operating Company. Please read "Certain Relationships and Related Party Transactions — Agreements Governing the Transactions — Services Agreement" and "— Reimbursement of Expenses of Our General Partner."

Lime Rock Management, as the controlling member of our general partner and the employer of our executive officers, will have responsibility and authority for compensation related decisions for our Co-Chief Executive Officers and, upon consultation and recommendations by our Co-Chief Executive Officers, for our other executive officers. Equity grants pursuant to our long-term incentive plan will be administered by our board of directors or a committee thereof. Historically, all compensation decisions for Lime Rock Management, including those for the individuals who are executive officers of our general partner, have been made at the discretion of Mr. Jonathan Farber and Mr. John Reynolds, who control Lime Rock Management. Mr. Farber serves as a director of our general partner. Lime Rock Management has historically compensated its executive officers with base salary and cash bonuses. Historically, Messrs. Farber and Reynolds have determined the overall compensation philosophy and set the final compensation of the executive officers of Lime Rock Resources without the assistance of a compensation consultant. In connection with this offering, Lime Rock Management may consider the compensation structures and levels that it believes will be necessary for executive recruitment and retention for us as a public company. Lime Rock Management expects to examine the compensation practices of our peer companies and may also review compensation data from the exploration and production industry generally. None of our executive officers have employment agreements with us, Lime Rock Management or any of its affiliates.

Our general partner may in the future also grant equity-based awards to our executive officers pursuant to a long-term incentive plan as described below. We expect that annual bonuses will be determined based on our financial performance as measured across a fiscal year. However, incentive compensation in respect of services provided to us will not be tied in any way to the performance of entities other than our partnership. Specifically, any performance metrics will not be tied in any way to the performance of Lime Rock Management, Lime Rock Resources or Lime Rock Partners or any other affiliate of ours.

Although we will bear an allocated portion of Lime Rock Management's costs of providing compensation and benefits to the Lime Rock Management employees who serve as the executive officers of our general partner, we will have no control over such costs and will not establish or direct the compensation policies or practices of Lime Rock Management. Each of our executive officers, other than our Chief Financial Officer who is devoted full-time to our business, will continue to perform services for Lime Rock Management and its affiliates, including Lime Rock Resources, after the completion of this offering.

Lime Rock Management does not maintain a defined benefit or pension plan for its executive officers because it believes such plans primarily reward longevity rather than performance. Through its arrangement with Insperity PEO Services, L.P., Lime Rock Management and Lime Rock Resources Operating Company provide a basic benefits package generally to all employees, which includes a 401(k) plan and health, dental, and basic term life insurance, and personal accident and short and long-term disability coverage. Employees provided to us under the services agreement will be entitled to the same basic benefits.

In connection with this offering, the board of directors of our general partner intends to adopt a long-term incentive plan for employees, officers, consultants and directors of our general partner and affiliates, including Lime Rock Management and Lime Rock Resources Operating Company, who perform services for us. The long-term incentive plan will provide for the grant of restricted units,

phantom units, unit options, unit appreciation rights, distribution equivalent rights, other unit-based awards and unit awards as described below.

Officers or employees of our general partner or its affiliates, including Lime Rock Management, who also serve as directors will not receive additional compensation for their service as a director of our general partner. Our general partner anticipates that each director who is not an officer or employee of our general partner or its affiliates will receive an annual retainer of $50,000 payable quarterly, $2,500 per in-person attendance at regular and special meetings of the board of directors, as well as committee meetings, $1,500 per telephonic meeting at which a vote is taken and an annual equity grant pursuant to our long-term incentive plan which will vest equally over three years from the grant date. After completion of this offering, we expect our board of directors to grant the non-employee directors $100,000 of restricted units based on the price per common unit on the date of grant, pro rated for the remaining part of the year after the closing date of this offering. These initial grants will be subject to vesting in equal amounts over three years.

In addition, each director will be reimbursed for his out-of-pocket expenses in connection with attending meetings of the board of directors or committees. Each director will be fully indemnified by us for actions associated with being a director to the extent permitted under Delaware law.

Our general partner intends to adopt a long-term incentive plan for employees, officers, consultants and directors of our general partner and its affiliates, including Lime Rock Management and Lime Rock Resources Operating Company, who perform services for us. We expect that the long-term incentive plan will consist of the following components: restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights, other unit-based awards and unit awards. The purpose of awards under the long-term incentive plan is to provide additional incentive compensation, at the discretion of the board, to employees providing services to us, and to align the economic interests of such employees with the interests of our unitholders. The long-term incentive plan will initially limit the number of units that may be delivered pursuant to vested awards to 1,500,000 common units. Common units cancelled, forfeited or withheld to satisfy exercise prices or tax withholding obligations will be available for delivery pursuant to other awards. The plan will be administered by the board of directors of our general partner or a designated committee thereof, which we refer to as the plan administrator. The plan administrator may also delegate its duties as appropriate.

The plan administrator may terminate or amend the long-term incentive plan at any time with respect to any units for which a grant has not yet been made. The plan administrator also has the right to alter or amend the long-term incentive plan or any part of the plan from time to time, including increasing the number of units that may be granted subject to the requirements of the exchange upon which the common units are listed at that time. However, no change in any outstanding grant may be made that would materially reduce the rights or benefits of the participant without the consent of the participant. The plan will expire on the earliest to occur of (i) the date on which all common units available under the plan for grants have been paid to participants, (ii) termination of the plan by the plan administrator or (iii) the date 10 years following its date of adoption.

A restricted unit is a common unit that vests over a period of time, and during that time, is subject to forfeiture. Forfeiture provisions lapse at the end of the vesting period. The plan administrator may make grants of restricted units containing such terms as it shall determine, including the period over which restricted units will vest. The plan administrator, in its discretion, may base its determination

upon the achievement of specified financial or other performance objectives. Restricted units will be entitled to receive quarterly distributions during the vesting period.

We intend the restricted units under the plan to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of our common units. Therefore, it is expected that plan participants will not pay any consideration for restricted units they receive, and we will receive no remuneration for the restricted units.

A phantom unit is a notional common unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit or, in the discretion of the plan administrator, cash equivalent to the value of a common unit. The plan administrator may make grants of phantom units under the plan containing such terms as the plan administrator shall determine, including the period over which phantom units granted will vest. The plan administrator, in its discretion, may base its determination upon the achievement of specified financial or other performance objectives.

We intend the issuance of any common units upon vesting of the phantom units under the plan to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of our common units. Therefore, it is expected that plan participants will not pay any consideration for the common units they receive, and we will receive no remuneration for the common units.

The long-term incentive plan will permit the grant of options covering common units. Unit options represent the right to purchase a designated number of common units at a specified price. The plan administrator may make grants containing such terms as the plan administrator shall determine. Unit options will have an exercise price that is not less than the fair market value of the common units on the date of grant. In general, unit options granted will become exercisable over a period determined by the plan administrator.

The long-term incentive plan will permit the grant of unit appreciation rights. A unit appreciation right is an award that, upon exercise, entitles the participant to receive the excess of the fair market value of a common unit on the exercise date over the exercise price established for the unit appreciation right. Such excess will be paid in cash or common units. The plan administrator may make grants of unit appreciation rights containing such terms as the plan administrator shall determine. Unit appreciation rights will have an exercise price that is not less than the fair market value of the common units on the date of grant. In general, unit appreciation rights granted will become exercisable over a period determined by the plan administrator.

The plan administrator may, in its discretion, grant distribution equivalent rights, or DERs, in tandem with phantom unit awards or other awards under the long-term incentive plan. DERs entitle the participant to receive cash equal to the amount of any cash distributions made by us during the period that the right is outstanding. Payment of a DER issued in connection with another award may be subject to the same vesting terms as the award to which it relates or different vesting terms, in the discretion of the plan administrator.

The long-term incentive plan will permit the grant of other unit-based awards, which are awards that are based, in whole or in part, on the value or performance of a common unit. Upon vesting, the award may be paid in common units, cash or a combination thereof, as provided in the grant agreement.

The long-term incentive plan will permit the grant of common units that are not subject to vesting restrictions. Unit awards may be in lieu of or in addition to other compensation payable to the individual.

Awards under the long-term incentive plan will vest and/or become exercisable, as applicable, upon a "change in control" (as defined in the long-term incentive plan) of us or our general partner, unless provided otherwise by the plan administrator. The consequences of the termination of a grantee's employment, consulting arrangement or membership on the board of directors will be determined by the plan administrator in the terms of the relevant award agreement.

Common units to be delivered pursuant to awards under the long-term incentive plan may be common units already owned by our general partner or us or acquired by our general partner in the open market from any other person, directly from us or any combination of the foregoing. If we issue new common units upon the grant, vesting or payment of awards under the long-term incentive plan, the total number of common units outstanding will increase, and our general partner will remit the proceeds it receives from a participant, if any, upon exercise of an award to us. With respect to any awards settled in cash, our general partner will be entitled to reimbursement by us for the amount of the cash settlement.

We anticipate that our compensation policies and practices will reflect the same philosophy and approach as Lime Rock Management. Such policies and practices will be designed to provide rewards for short-term and long-term performance, both on an individual basis and at the entity level. In general, optimal financial and operational performance, particularly in a competitive business, requires some degree of risk taking. Accordingly, the use of compensation as an incentive for performance can foster the potential for management and others to take unnecessary or excessive risks to reach performance thresholds which qualify them for additional compensation. From a risk management perspective, our policy will be to conduct our commercial activities in a manner intended to control and minimize the potential for unwarranted risk taking. We expect to also routinely monitor and measure the execution and performance of our projects and acquisitions relative to expectations. Additionally, our compensation arrangements may include delaying the rewards and subjecting such rewards to forfeiture for terminations related to violations of our risk management policies and practices or of our code of conduct.

The following table sets forth the beneficial ownership of our common and subordinated units that, upon the consummation of this offering and the related transactions and assuming the underwriters do not exercise their option to purchase additional common units, will be owned by:

Name of Beneficial Owner(1)

Fund I(3)	6,249,600	39.9	%	6,720,000	100.0	%	58.0	%
Jonathan C. Farber(3)	6,249,600	39.9	%	6,720,000	100.0	%	58.0	%
John A. Bailey(4)	—	—		—	—		—
Milton Carroll(4)	—	—		—	—		—
Robert T. O'Connell(4)	—	—		—	—		—
Townes G. Pressler, Jr.	—	—		—	—		—
Charles W. Adcock	—	—		—	—		—
Eric D. Mullins	—	—		—	—		—
Jaime R. Casas(5)	—	—		—	—		—
C. Timothy Miller	—	—		—	—		—
Christopher A. Butta	—	—		—	—		—
All named executive officers, directors and director nominees as a group (ten persons)	6,249,600	39.9	%	6,720,000	100.0	%	58.0	%

(1): The address for all beneficial owners in this table is Heritage Plaza, 1111 Bagby Street, Suite 4600, Houston, Texas 77002. There are no options, warrants or other rights or obligations outstanding that are currently exercisable or exercisable within 60 days into common or subordinated units.
(2): Does not include any common units that may be purchased in a directed unit program.
(3): Fund I consists of 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 are controlled indirectly by Jonathan C. Farber, one of our general partner's directors, and John T. Reynolds. Messrs. Farber and Reynolds are managing members of LRR GP, LLC ("LRR"), which is the general partner of Lime Rock Resources GP, L.P. ("Lime Rock GP"), which is the sole member of each of Lime Rock Resources A GP, LLC ("Lime Rock A GP") and Lime Rock Resources C GP, LLC ("Lime Rock C GP"). Lime Rock A GP is the general partner of LRR A, Lime Rock GP is the general partner of LRR B and Lime Rock C GP is the general partner of LRR C.

Each of Messrs. Farber and Reynolds, LRR, Lime Rock GP, Lime Rock A GP and Lime Rock C GP may be deemed to share voting and dispositive power over the reported securities; thus, each may also be deemed to be the beneficial owner of these securities. Each of Messrs. Farber and Reynolds, LRR, Lime Rock GP, Lime Rock A GP and Lime Rock C GP disclaims beneficial ownership of the reported securities in excess of such entity's or person's respective pecuniary interest in the securities. LRR A, LRR B and LRR C will hold the following limited partner interests in us:

•: LRR A will own 893,030 common units and 960,247 subordinated units;
•: LRR B will own 296,082 common units and 318,368 subordinated units; and
•: LRR C will own 5,060,488 common units and 5,441,385 subordinated units.

Mr. Farber does not own directly any common units or subordinated units.

LRE GP, LLC, our general partner, owns all of our incentive distribution rights and a 0.1% general partner interest in us. The following table sets forth the beneficial ownership of equity interests in our general partner.

(a): Our general partner has three classes of member interests. LRR A, LRR B and LRR C own 14.2894%, 4.7376% and 80.9730%, respectively, of the Class B member interest in our general partner, which entitles them to an aggregate 80% of the distributions payable to our general partner with respect to the incentive distribution rights for a period of six years from the closing of the offering. In addition, Lime Rock Resources II-A, L.P. and Lime Rock Resources II-C, L.P. own 16.39% and 83.61%, respectively, of the Class C member interest in our general partner, which entitles them to an aggregate 20% of the distributions payable to our general partner with respect to the incentive distribution rights for a period of six years from the closing of the offering. After the six-year period, Lime Rock Management, as the Class A member, will be entitled to all distributions with respect to the incentive distribution rights in addition to the distributions with respect to our general partner's 0.1% general partner interest in us.
(b): Our general partner is controlled by Lime Rock Management, which is ultimately controlled by Jonathan C. Farber, one of our directors, and John T. Reynolds. As ultimate control persons of our general partner, Mr. Farber and Mr. Reynolds will share in distributions made by us with respect to interests held by our general partner in proportion to their respective pecuniary interests. Mr. Farber and Mr. Reynolds, by virtue of their ownership interest in our general partner, may be deemed to beneficially own the interests held by our general partner. Each of Mr. Farber and Mr. Reynolds disclaims beneficial ownership of the reported securities in excess of his pecuniary interest in such securities. In addition, our general partner's other non-independent directors and certain of our general partner's executive officers have financial interests in Lime Rock Management and its general partner.
(c): Fund I is controlled indirectly by Jonathan C. Farber and John T. Reynolds, as indicated in footnote (3) to the table above. Fund II is controlled indirectly by Jonathan C. Farber and John T. Reynolds.
(d): The address for Fund I and Fund II is Heritage Plaza, 1111 Bagby Street, Suite 4600, Houston, Texas 77002.

Upon the consummation of this offering, assuming the underwriters do not exercise their option to purchase additional common units, Lime Rock Resources will own 6,249,600 common units and 6,720,000 subordinated units representing an aggregate 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 with respect to our incentive distribution rights for a period of six years following the closing of this offering. In addition, our general partner will own a 0.1% general partner interest in us, evidenced by 22,400 general partner units. These percentages do not reflect any common units that may be issued under the long-term incentive plan that our general partner expects to adopt prior to the closing of this offering.

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


*Formation Stage*
The consideration received by our general partner and Lime Rock Resources prior to or in connection with this offering		• 6,249,600 common units;
		• 6,720,000 subordinated units;
		• 22,400 general partner units;
		• all of our incentive distribution rights; and
		• approximately $289.9 million in cash.
		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 Lime Rock Resources (as reflected in the first bullet above) will decrease 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 paid to Fund I as additional cash consideration for the Partnership Properties and as an additional cash distribution to Fund I.
*Operational Stage*
Distributions of available cash to our general partner and its affiliates		We will generally make cash distributions 99.9% to our unitholders pro rata, including Lime Rock Resources as the holder of approximately 58.0% of our limited partner interests, and 0.1% to our general partner, assuming it makes any capital contributions necessary to maintain its 0.1% general partner interest in us. In addition, if distributions exceed the minimum quarterly distribution and other higher target distribution levels, our general partner will be entitled to increasing percentages of the distributions, up to a maximum of 23.1% of the distributions above the highest target distribution level, including the general partner's 0.1% general partner interest.


		Assuming we have sufficient available cash to pay the full minimum quarterly distribution on all of our outstanding units for four quarters, our general partner would receive an annual distribution of approximately $0.1 million on its general partner units and Lime Rock Resources would receive an annual distribution of approximately $24.6 million on its common units and subordinated units.
Payments to our general partner and its affiliates		Our general partner will not receive a management fee or other compensation for its management of our partnership, but we will reimburse our general partner for all direct and indirect expenses it incurs and payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. Our partnership agreement does not set a limit on the amount of expenses for which our general partner 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 partnerships agreement provides that our general partner will determine in good faith the expenses that are allocable to us.
Withdrawal or removal of our general partner		In the event of removal of our general partner under circumstances where cause exists or withdrawal of our general partner where that withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the departing general partner's general partner interest and incentive distribution rights for a cash payment equal to the fair market value of those interests. Under all other circumstances where our general partner withdraws or is removed by the limited partners, the departing general partner will have the option to require the successor general partner to purchase the departing general partner's general partner interest in us and its incentive distribution rights for their fair market value or to convert such interests into common units.
*Liquidation Stage*
Liquidation		Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their respective capital account balances.

LRE GP, LLC, our general partner and a limited liability company ultimately controlled by the co-founders of Lime Rock Management, owns a 0.1% general partner interest in us. Upon the closing of this offering, our general partner will have the following three classes of member interests pursuant to its amended and restated limited liability company agreement:

Following the distribution period, 100% of the cash received by our general partner from us attributable to (i) distributions related to the incentive distribution rights and (ii) distributions related to any common units issued to our general partner in connection with any reset of the incentive distribution levels will be distributable to the Class A member. Except as described in the last paragraph of this section below, during and following the distribution period, the Class A member will be entitled to all proceeds received by the general partner pursuant to a sale or transfer of the incentive distribution rights or any common units into which the incentive distribution rights have been converted.

If Fund I or Fund II, as Class B and C members, respectively, elect to reduce the management fees payable by such member to Lime Rock Management pursuant to the limited partnership agreement applicable to such member, then the amount distributable to such member under the amended and restated limited liability company agreement will be reduced by such amount, and such amount will be distributed to Lime Rock Management as the Class A member.

Subject to certain conditions, a member may transfer, pledge or assign all or any portion of its member interest in our general partner at any time.

During the distribution period, our general partner may not sell or transfer any of its incentive distribution rights or any common units issued in connection with any reset of the incentive distribution levels unless the general partner agrees (i) to continue to distribute to the Class B and Class C members during the remainder of the distribution period such cash amounts as would be payable to such members under the amended and restated limited liability company agreement assuming no sale or transfer of the incentive distribution rights or common units issued pursuant to a reset had occurred, or (ii) to distribute to the Class B and Class C members, in a lump sum amount, such allocable portion of the purchase price received or value allocated in the sale or transfer of the incentive distribution rights or common units issued pursuant to a reset.

In connection with the closing of this offering, we, our general partner and its affiliates will enter into the various documents and agreements that will effect the transactions described in "Prospectus Summary — Formation Transactions and Partnership Structure" including the vesting of assets in, and the assumption of liabilities by, us and the application of the net proceeds of this offering. These agreements have been negotiated among affiliated parties and, consequently, are not the result of arm's-length negotiations. All of the transaction expenses incurred in connection with these transactions, including the expenses associated with transferring assets to us, will be paid from the proceeds of this offering.

Contemporaneously with 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 certain management, administrative and operating services and personnel will be provided to our general partner and us to manage and operate our business. Pursuant to this services agreement, our executive officers, all of whom are employees of Lime Rock Management and a majority of whom are also executive officers of Lime Rock Resources, will serve as our executive officers and Lime Rock Management and Lime Rock Resources Operating Company will provide certain management, administrative and operating services to operate our business. Under the services agreement, our general partner will reimburse Lime Rock Management and Lime Rock Resources Operating Company, on a monthly basis, for the allocable expenses they incur in their performance under the services agreement, and we will reimburse our general partner for such payments it makes to Lime Rock Management and Lime Rock Resources Operating Company. These expenses include, among other things, salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and other expenses allocated by Lime Rock Management and Lime Rock Resources Operating Company to us. Lime Rock Management and Lime Rock Resources Operating Company will have substantial discretion to determine in good faith which expenses to incur on our behalf and what portion to allocate to us. Lime Rock Management and Lime Rock Resources Operating Company will not be liable to us for their performance of, or failure to perform, services under the services agreement unless their acts or omissions constitute gross negligence or willful misconduct.

In connection with the closing of this offering, we will enter into a purchase, sale, contribution, conveyance and assumption agreement that will effect the transactions, including the transfer of the Partnership Properties to us, and the use of the net proceeds of this offering. While we believe this agreement will be on terms no less favorable to any party than those that could have been negotiated with an unaffiliated third party, it will not be the result of arm's-length negotiations. All of the

transaction expenses incurred in connection with these transactions will be paid from proceeds of this offering.

Upon the closing of this offering, we will enter into an omnibus agreement with affiliates of our general partner, including Fund I, that will address competition and indemnification matters.

Competition. Neither Lime Rock Resources nor its future affiliated funds or affiliates, including Lime Rock Management and Lime Rock Partners, will be restricted, under either our partnership agreement or the omnibus agreement, from competing with us. Lime Rock Resources, any future affiliated funds and its affiliates will be permitted to compete with us and may acquire or dispose of additional oil and natural gas properties or other assets in the future without any obligation to offer us the opportunity to purchase those assets.

Indemnification. Pursuant to the omnibus agreement, Fund I will indemnify us against (i) title defects, (ii) income taxes attributable to pre-closing ownership or operation of the contributed assets, including any income tax liabilities related to the formation transactions occurring on or prior to the closing, (iii) environmental claims, losses and expenses associated with the operation of our business prior to the closing, subject to a maximum of $10,000,000, (iv) all liabilities, other than covered environmental liabilities, relating to the operation of the contributed assets prior to the closing that were not disclosed in the most recent pro forma balance sheet included in the registration statement, or incurred in the ordinary course of business thereafter, and (v) losses resulting from the failure of Fund I to have on the closing date any consent, waiver or governmental permit that renders us unable to own, use or operate the contributed assets in substantially the same manner as prior to the closing.

Fund I's indemnification obligation will (i) survive for three years after the closing of this offering with respect to title defects, (ii) survive for one year after closing with respect to environmental claims, undisclosed liabilities and failure to have any consent, waiver or governmental permits, and (iii) terminate upon the shorter of (y) the expiration of the term of Fund I and (z) sixty days after the expiration of the applicable statute of limitations with respect to income taxes. All claims are subject to a $50,000 per claim de minimus exception, no claims may be made against Fund I unless such loss exceeds $500,000 in the aggregate, and Fund I will only be liable to the extent that such claims exceed $500,000.

Amended and Restated Limited Liability Company Agreement of Our General Partner

We expect that our general partner's Limited Liability Company Agreement will be amended and restated in connection with the closing of this offering. For a description of certain provisions of our general partner's amended and restated limited liability company agreement, please read "— Limited Liability Company Agreement of Our General Partner."

Prior to filing our registration statement relating to this offering, we, Fund I, Fund II, our general partner and other affiliates of Lime Rock Management entered into an agreement relating to:

We refer to this agreement as our "Stakeholders' Agreement" and have filed it as an exhibit to the registration statement of which this prospectus is a part. The distributions and payments to be made by us to our general partner and its affiliates in connection with our formation and ongoing operation and the issuance of interests in our general partner to Fund I and Fund II were determined by and among affiliated entities and, consequently, were not the result of arms-length negotiations.

Allocation of Residual Units. Pursuant to the terms of the Stakeholders' Agreement, at the closing of this offering, each fund comprising Fund I contributing and selling the Partnership Properties to us will be allocated common units and subordinated units pursuant to a formula based on each fund's ownership percentage in such Partnership Properties. Specifically, the Stakeholders' Agreement provides that upon the closing of this offering, the "residual units" of our partnership will be determined by subtracting the number of common units issued by us to the public unitholders (plus general partner units issued to our general partner) from the total number of units outstanding following the closing. The residual units will consist of the following: (a) subordinated units equal to thirty percent (30%) multiplied by the total outstanding units, (b) common units calculated by subtracting the general partner units, common units issued by us to the public, the residual subordinated units and the over-allotment units, if any, from the total number of units outstanding, and (c) any over-allotment units. Each of the contributors of Partnership Properties will receive:

If the underwriters do not exercise their option to purchase additional common units prior to the expiration of the option period, we will issue the balance of the residual common units to Fund I in accordance with each contributor's ownership percentage in the Partnership Properties. To the extent the underwriters exercise their option to purchase additional common units before the expiration of the option period, the number of common units purchased by the underwriters pursuant to such exercise will be issued to the public, and the remainder of the residual common units subject to the option, if any, will be issued to Fund I at the expiration of the option period in accordance with each contributor's ownership percentage in the Partnership Properties. The proceeds, after deducting the underwriters' commissions, discounts and fees and other expenses from any exercise of the underwriters' option to purchase additional common units will be paid and distributed to Fund I in accordance with each contributor's percentage interest in the Partnership Properties.

Payment and Distribution of Cash. Pursuant to the terms of the Stakeholders' Agreement, at the closing of this offering, each fund comprising Fund I will receive a cash payment and distribution based on such fund's respective ownership percentage in the Partnership Properties to be sold and contributed to us at the closing, subject to adjustment pursuant to a specified formula. The formula will adjust the amount of the cash payment and distribution payable to each fund based on the outstanding net profits interest balances. This cash payment and distribution to Fund I will be approximately $289.9 million, comprised of net proceeds from this offering and borrowings under our new credit facility, after deducting estimated underwriters' discounts, the structuring fee, offering expenses and fees associated with our new credit facility. We will assume approximately $27.3 million of LRR A's debt that currently burdens the Partnership Properties at the closing of this offering as described in "Prospectus Summary — Formation Transactions and Partnership Structure." We will use $27.3 million of the borrowings under our credit facility to repay such assumed debt in full at the closing of this offering.

General Partner Interests. Pursuant to the terms of the Stakeholders' Agreement, at the closing of this offering, our general partner will receive a number of general partner units equal to 0.1% of the total number of common, subordinated and general partner units to be outstanding following the closing, including the issuance of additional common units upon the exercise or expiration of the underwriters' option to purchase additional common units. Additionally, our general partner will receive incentive distribution rights that will entitle it to receive increasing percentages, up to 23.1% (including distributions on its 0.1% general partner interest), of the cash we distribute above $0.54625 per common unit. For a description of our general partner's incentive distribution rights, please read "Provisions of Our Partnership Agreement Relating to Cash Distributions — General Partner Interest and Incentive Distribution Rights" and "— General Partner's Right to Reset Incentive Distribution Levels."

The following table sets forth the consideration to be received by each fund comprising Fund I as consideration in respect of such fund's respective percentage interest in the Partnership Properties to be sold and contributed to us at the closing of this offering.

Registration Rights. The Stakeholders' Agreement provides that our amended and restated partnership agreement will grant registration rights to our general partner and its affiliates. Please read "The Partnership Agreement — Registration Rights."

Member Interests in Our General Partner. Pursuant to the Stakeholders' Agreement, upon the closing of this offering, our general partner will enter into an amended and restated limited liability company agreement pursuant to which Fund I and Fund II will receive Class B and Class C member interests in our general partner, which will entitle them to an aggregate 80% and 20%, respectively, of the distributions with respect to (i) the incentive distribution rights owned by our general partner and (ii) any common units issued by us to our general partner in connection with any incentive distribution reset, in each case, for a period of six years from the closing of this offering. For a description of our general partner's amended and restated limited liability company agreement, please read "— Limited Liability Company Agreement of Our General Partner."

We expect that we will adopt a Code of Business Conduct and Ethics that will set forth our policies for the review, approval and ratification of transactions with related persons. Upon our adoption of a Code of Business Conduct and Ethics, a director would be expected to bring to the attention of the Chief Executive Officer or the board of directors of our general partner any conflict or potential conflict of interest that may arise between the director or any affiliate of the director, on the one hand, and us or our general partner on the other. The resolution of any such conflict or potential conflict will be addressed in accordance with Fund I's and our general partner's organizational documents and the provisions of our partnership agreement. The resolution may be determined by disinterested directors, our general partner's board of directors, or the conflicts committee of our general partner's board of directors.

Upon our adoption of a Code of Business Conduct and Ethics, any executive officer of our general partner will be required to avoid conflicts of interest unless approved by the board of directors.

The board of directors of our general partner will have a standing conflicts committee comprised of entirely one or more independent directors. Our general partner may, but is not required to, seek the approval of the conflicts committee in connection with future acquisitions of oil and natural gas properties from Lime Rock Resources or its affiliates. In addition to acquisitions from Lime Rock Resources or its affiliates, the board of directors of our general partner will also determine whether to seek conflicts committee approval to the extent we act jointly to acquire additional oil and natural gas properties with Lime Rock Resources or its affiliates. In the case of any sale of equity or debt by us to an owner or affiliate of an owner of our general partner, we anticipate that our practice will be to obtain the approval of the conflicts committee of the board of directors of our general partner for the transaction. The conflicts committee will be entitled to hire its own financial and legal advisors in connection with any matters on which the board of directors of our general partner has sought the conflicts committee's approval.

Lime Rock Resources and its affiliates are free to offer properties to us on terms it deems acceptable, and the board of directors of our general partner (or the conflicts committee) is free to accept or reject any such offers, negotiating terms it deems acceptable to us. As a result, the board of directors of our general partner (or the conflicts committee) will decide, in its sole discretion, the appropriate value of any assets offered to us by Lime Rock Resources or its affiliates. In so doing, we expect the board of directors (or the conflicts committee) will consider a number of factors in its determination of value, including, without limitation, production and reserve data, operating cost structure, current and projected cash flows, financing costs, the anticipated impact on distributions to our unitholders, production decline profile, commodity price outlook, reserve life, future drilling inventory and the weighting of the expected production between oil and natural gas.

We expect that Lime Rock Resources and its affiliates will consider a number of the same factors considered by the board of directors of our general partner to determine the proposed purchase price of any assets it may offer to us in future periods. In addition to these factors, given that Lime Rock Resources, through Fund I, will be our largest unitholder following the consummation of this offering and through its interest in our general partner, will initially be entitled to 100% of the distributions with respect to the incentive distribution rights, Lime Rock Resources may consider the potential positive impact on its underlying investment in us by offering properties to us at attractive purchase prices. Likewise, Lime Rock Resources may consider the potential negative impact on its underlying investment in us if we are unable to acquire additional assets on favorable terms, including the negotiated purchase price.

Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates (including Lime Rock Resources, Lime Rock Management and Lime Rock Partners and their related and future funds) on the one hand, and us and our limited partners, on the other hand. The directors and officers of our general partner have fiduciary duties to manage the business of our general partner in a manner beneficial to its owners. In addition, all of the executive officers of our general partner, other than our Chief Financial Officer who is devoted full-time to our business, serve in similar and other capacities with Lime Rock Resources and all are employees of Lime Rock Management. Further certain of our general partner's non-independent directors and executive officers, other than our Chief Financial Officer, will continue to have economic interests, investments and other economic incentives in Lime Rock Management and funds affiliated with Lime Rock Resources and Lime Rock Partners, which may lead to additional conflicts of interest. At the same time, our general partner has a fiduciary duty to manage our partnership in a manner beneficial to us and our unitholders.

Whenever a conflict arises between our general partner or its affiliates, on the one hand, and us and our limited partners, on the other hand, our general partner will resolve that conflict. Our partnership agreement contains provisions that modify and limit our general partner's fiduciary duties to our unitholders. Our partnership agreement also restricts the remedies available to unitholders for actions taken that, without those limitations, might constitute breaches of fiduciary duty.

Our general partner will not be in breach of its obligations under our partnership agreement or its duties to us or our unitholders if the resolution of the conflict is:

As required by our partnership agreement, the conflicts committee must be comprised of entirely one or more independent directors. Our general partner may, but is not required to, seek approval from the conflicts committee of a resolution of a conflict of interest with our general partner or affiliates. If our general partner seeks approval from the conflicts committee, the conflicts committee will determine if the resolution of a conflict of interest with our general partner or its affiliates is fair and reasonable to us. Any matters approved by the conflicts committee in good faith will be conclusively deemed to be fair and reasonable to us, approved by all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders. If our general partner does not seek approval from the conflicts committee and its board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third or fourth bullet points above, then it will be presumed that, in making its decision, the 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. Unless the resolution of a conflict is specifically provided for in our partnership agreement, our general partner or the conflicts committee may consider any factors it determines in good faith to consider when resolving a conflict. When our partnership agreement requires someone to act in good faith, it requires that person to reasonably believe that he or she is acting in our best interest.

Conflicts of interest could arise in the situations described below, among others:

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.

Lime Rock Resources, Lime Rock Partners and their affiliates are not limited in their ability to compete with us, and are not restricted from owning assets or engaging in businesses that compete directly or indirectly with us. For example, Lime Rock Resources and any future affiliated funds, such as 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 Fund II expenses, and the portfolio companies of Lime Rock Partners may acquire, develop or dispose of additional 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 that it expects to invest in acquisition opportunities 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 oil and natural gas industry, and have resources greater than ours, which factors may make it more difficult for us to compete 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.

Neither Our Partnership Agreement Nor Any Other Agreement Requires Lime Rock Management, Lime Rock Resources or Lime Rock Partners to Pursue a Business Strategy That Favors Us or Uses Our Assets or Dictates What Markets to Pursue or Grow. The Officers and Directors of Lime Rock Management, Lime Rock Resources and Lime Rock Partners Have a Fiduciary Duty to Make These Decisions in the Best Interests of Its Respective Owners, Which May Be Contrary to Our Interests.

Because the non-independent directors and executive officers of our general partner, other than our Chief Financial Officer, serve in similar capacities with, and own economic interests, investments and other economic incentives in, Lime Rock Management, Lime Rock Resources, Lime Rock Partners and their affiliates, such officers and directors have fiduciary duties to such entities and other incentives that may cause them to pursue business strategies that disproportionately benefit Lime Rock Management, Lime Rock Resources, Lime Rock Partners and their affiliates or which otherwise are not in our best interests.

Pursuant to the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, shall not apply to our general partner or any of its affiliates, including its executive officers, directors, Lime Rock Resources, Lime Rock Partners or any of their affiliates. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. Therefore, Lime Rock Management, Lime Rock Resources, Lime Rock Partners and their affiliates may compete with us for investment opportunities.

Our General Partner and its Affiliates are Allowed to Take into Account the Interests of Parties Other Than Us in Resolving Conflicts of Interest.

Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. 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. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include our general partners limited call right, its registration rights, its determination whether or not to consent to any merger or consolidation involving us and its decision to convert its incentive distribution rights into common units.

All of the Executive Officers and Non-Independent Directors 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 natural gas properties. All of the executive officers and non-independent directors of our general partner, other than our Chief Financial Officer, hold similar positions with other entities, such as Lime Rock Resources and Lime Rock Partners, that are in the business, directly or indirectly, of identifying and acquiring oil and natural gas properties. For example, our general partner's non-independent directors, Mr. Jonathan Farber, who is a founder of Lime Rock Management, and Mr. Townes Pressler, are Managing Directors of Lime Rock Partners, have ownership interests in certain Lime Rock Resources and Lime Rock Partners funds, and serve on the investment committees of Lime Rock Resources and Lime Rock Partners, which have ultimate investment oversight over Lime Rock Resources and Lime Rock Partners. In addition, all of our executive officers, other than our Chief Financial Officer, hold similar positions with Lime Rock Resources and will continue to devote significant time to Lime Rock Resources' business. Further, certain of our 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, Lime Rock Resources and Lime Rock Partners. The existing positions held by these directors and officers may give rise to fiduciary duties that are in conflict with fiduciary duties they owe to us. We cannot assure our unitholders that these conflicts will be resolved in our favor. As officers and directors of our general partner, these individuals 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 and economic interests in these and other entities, they may have fiduciary obligations or incentives 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 other entities with which they are affiliated, and as a result, they may elect not to present them to us. For further discussion of our management's business affiliations and the potential conflicts of interest of which our unitholders should be aware, please read "Business and Properties — Our Principal Business Relationships" and "Management."

We Do Not Have Any Employees and Rely Solely on Lime Rock Management and Lime Rock Resources Operating Company To Manage Our Business. Lime Rock Management and 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 our business 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, one of our affiliates. Should Lime Rock Management 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 any other 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.

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.

By purchasing a common unit, a unitholder will become bound by the provisions in the partnership agreement, including the provisions discussed above. Please read "— Fiduciary Duties."

Except in Limited Circumstances, Our General Partner Has the Power and Authority to Conduct Our Business Without Unitholder Approval.

Under our partnership agreement, our general partner has full power and authority to do all things, other than those items that require unitholder approval or with respect to which our general partner has sought conflicts committee approval, on such terms as it determines to be necessary or appropriate to conduct our business, including, but not limited to, the following:

Our partnership agreement provides that our general partner must act in "good faith" when making decisions on our behalf, and our partnership agreement further 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 our best interests. Please read "The Partnership Agreement — Limited Voting Rights" for information regarding matters that require unitholder approval.

Our General Partner Determines the Amount and Timing of Asset Purchases and Sales, Capital Expenditures, Borrowings, Issuance of Additional Partnership Interests and the Creation, Reduction or Increase of Reserves, Each of Which Can Affect the Amount of Cash That Is Distributed to Our Unitholders.

The amount of cash that is available for distribution to unitholders is affected by decisions of our general partner regarding such matters as:

Our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or a growth capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and to our general partner and the ability of the subordinated units to convert into common units.

In addition, our general partner may use an amount, initially equal to $30.0 million, which would not otherwise constitute available cash from operating surplus, in order to permit the payment of cash distributions on its units and incentive distribution rights. All of these actions may affect the amount of cash distributed to our unitholders and our general partner and may facilitate the conversion of subordinated units into common units. Please read "Provisions of Our Partnership Agreement Relating to Cash Distributions."

In addition, borrowings by us and our affiliates do not constitute a breach of any duty owed by our general partner to our unitholders, including borrowings that have the purpose or effect of enabling our general partner or its affiliates to receive distributions on any subordinated units held by them or the incentive distribution rights, or accelerating the expiration of the subordination period.

For example, if we have not generated sufficient cash from our operations to pay the minimum quarterly distribution on our common units and subordinated units, our partnership agreement permits us to borrow funds, which would enable us to make this distribution on all outstanding units. Please read "Provisions of Our Partnership Agreement Relating to Cash Distributions — Subordination Period."

Our partnership agreement provides that we and our subsidiaries may borrow funds from our general partner and its affiliates. However, our general partner and its affiliates may not borrow funds from us or our operating subsidiaries.

Our General Partner Determines Which Costs Incurred By It Are Reimbursable By Us.

We will reimburse our general partner and its affiliates, including Lime Rock Management and Lime Rock Resources Operating Company, for costs incurred in managing and operating our business, including costs incurred in rendering staff and support services to us pursuant to our services agreement. Lime Rock Management and Lime Rock Resources Operating Company will have substantial discretion to determine in good faith which expenses to incur on our behalf and what portion to allocate

to us. In turn, our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. Please read "Certain Relationships and Related Transactions."

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 partnership agreement allows our general partner to determine, in good faith, any amounts to pay itself or its affiliates, including Lime Rock Management and Lime Rock Resources Operating Company, for any services rendered to us. Our general partner may also enter into additional contractual arrangements with any of its affiliates on our behalf. Neither our partnership agreement nor any of the other agreements, contracts or arrangements between us, on the one hand, and our general partner and its affiliates, on the other hand, that will be in effect as of the closing of this offering, will be the result of arm's-length negotiations. Similarly, agreements, contracts or arrangements between us and our general partner, Lime Rock Management, Lime Rock Resources Operating Company, Lime Rock Resources or Lime Rock Partners or their affiliates that are entered into following the closing of this offering may not be required to be negotiated on an arms-length basis, although, in some circumstances, our general partner may determine that the conflicts committee of our general partner may make a determination on our behalf with respect to one or more of these types of situations.

Our general partner will determine, in good faith, the terms of any of these transactions entered into after the sale of the common units offered in this offering.

Our general partner and its affiliates will have no obligation to permit us to use any facilities or assets of our general partner or its affiliates, except as may be provided in contracts entered into specifically dealing with that use. There is no obligation of our general partner or its affiliates to enter into any contracts of this kind.

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 the Board of Directors of Our General Partner or Our Unitholders. This Election May Result in Lower Distributions to Our Common Unitholders 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 target distribution levels at higher levels based on our cash distribution at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution will be reset to an amount equal to the average cash distribution 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.

We anticipate that our general partner would exercise this 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 we are experiencing declines in our aggregate cash distributions or at a time when our general partner expects that we will experience declines in our aggregate cash distributions in the foreseeable future. In such situations, our general partner may be experiencing, or may expect 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, which are entitled to specified priorities with respect to our distributions and which therefore may be more advantageous for

the general partner to own in lieu of the right to receive incentive distribution payments based on target distribution levels that are less certain to be achieved in the then current business environment. 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's incentive distribution rights. Please read "Provisions of Our Partnership Agreement Relating to Cash Distributions — General Partner's Right to Reset Incentive Distribution Levels."

Our General Partner May Exercise Its Right to Call and Purchase Common Units If It and Its Affiliates Own More Than 80% of the Common Units.

If at any time our general partner and its affiliates own more than 80% of the common units, our general partner may exercise its right to call and purchase common units as provided in the partnership agreement or assign this right to one of its affiliates or to us. Our general partner is not bound by fiduciary duty restrictions in determining whether to exercise this right. As a result, a common unitholder may have his common units purchased from him at an undesirable time or price. Please read "The Partnership Agreement — Limited Call Right."

Common Unitholders Will Have No Right to Enforce Obligations of Our General Partner and Its Affiliates Under Agreements with Us.

Any agreements between us, on the one hand, and our general partner, Lime Rock Resources, Lime Rock Management, Lime Rock Resources Operating Company and their respective affiliates, on the other, will not grant to the unitholders, separate and apart from us, the right to enforce the obligations of our general partner, Lime Rock Resources, Lime Rock Management, Lime Rock Resources Operating Company and their respective affiliates in our favor.

Our General Partner and Lime Rock Resources May Be Able to Amend Our Partnership Agreement without the Approval of Any Other Unitholder After the Subordination Period.

Our general partner has the discretion to propose amendments to our partnership agreement, certain of which may be made by our general partner without unitholder approval. Our partnership agreement generally may not be otherwise amended during the subordination period without the approval of a majority of our public common unitholders. However, after the subordination period has ended, our partnership agreement can 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 the consummation of this offering, affiliates of Lime Rock Resources will own our general partner and Lime Rock Resources will control the voting of 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. Assuming that Lime Rock Resources retains a sufficient number of its common units and that we do not issue additional common units, our general partner and Lime Rock Resources will have the ability to amend our partnership agreement without the approval of any other unitholder after the subordination period. Please read "The Partnership Agreement — Amendment of the Partnership Agreement."

Our General Partner Intends to Limit Its Liability Regarding Our Obligations.

Our general partner will enter into contractual arrangements on our behalf and intends to limit its liability under such contractual arrangements so that the other party has recourse only to our assets and not against our general partner or its assets. The partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner's fiduciary duties, even if we could have obtained more favorable terms without the limitation on liability.

Our General Partner Decides Whether to Retain Separate Counsel, Accountants or Others to Perform Services for Us.

The attorneys, independent accountants and others who have performed services for us regarding this offering have been retained by our general partner. The attorneys, independent accountants and others who perform services for us are selected by our general partner, or the conflicts committee of our general partner's board of directors, and may also perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the holders of common units in the event of a conflict of interest between our general partner and its affiliates, on the one hand, and us or the holders of common units, on the other, depending on the nature of the conflict. We do not intend to do so in most cases.

Our general partner is accountable to us and our unitholders as a fiduciary. Fiduciary duties owed to unitholders by our general partner are prescribed by law and the partnership agreement. The Delaware Revised Uniform Limited Partnership Act, which we refer to in this prospectus as the Delaware Act, provides that Delaware limited partnerships may, in their partnership agreements, modify, restrict or expand the fiduciary duties otherwise owed by a general partner to limited partners and the partnership.

Our partnership agreement contains various provisions modifying and restricting the fiduciary duties that might otherwise be owed by our general partner. We have adopted these restrictions to allow our general partner, Lime Rock Resources, Lime Rock Management, Lime Rock Partners and their respective affiliates to engage in transactions with us that would otherwise be prohibited by state-law fiduciary duty standards and to take into account the interests of other parties in addition to our interests when resolving conflicts of interest. Without these modifications, our general partner's ability to make decisions involving conflicts of interest would be restricted, and engaging in such transactions could result in violations of our general partner's state-law fiduciary standards. We believe these modifications are appropriate and necessary because our general partner's board of directors has fiduciary duties to manage our general partner in a manner beneficial to its owners, as well as to our unitholders. The modifications to the fiduciary standards enable our general partner to take into consideration the interests of all parties involved in the proposed action, so long as the resolution is fair and reasonable to us. These modifications also enable our general partner to attract and retain experienced and capable directors. These modifications are detrimental to our common unitholders because they restrict the rights and remedies that would otherwise be available to our unitholders for actions that, without those limitations, might constitute breaches of fiduciary duty, as described below, and permit our general partner to take into account the interests of third parties in addition to our interests when resolving conflicts of interest.

The following is a summary of the material restrictions of the fiduciary duties owed by our general partner to the limited partners:


Rights and remedies of unitholders		The Delaware Act generally provides that a limited partner may institute legal action on behalf of the partnership to recover damages from a third party where a general partner has refused to institute the action or where an effort to cause a general partner to do so is not likely to succeed. These legal actions include actions against a general partner for breach of fiduciary duty or the partnership agreement. In addition, the statutory or case law of some jurisdictions may permit a limited partner to institute legal action on behalf of himself and all other similarly situated limited partners to recover damages from a general partner for violations of its fiduciary duties to the limited partners.
Partnership agreement modified standards		Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates that might otherwise raise issues about compliance with fiduciary duties or applicable law. For example, our partnership agreement provides that when our general partner is acting in its capacity as our general partner, as opposed to in its individual capacity, it must act in "good faith" and will not be subject to any other standard under applicable law. In addition, when our general partner is acting in its individual capacity, as opposed to in its capacity as our general partner, it may act without any fiduciary obligation to us or the unitholders whatsoever. These standards reduce the obligations to which our general partner would otherwise be held.
		In addition to the other more specific provisions limiting the obligations of our general partner, our partnership agreement further provides that our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners for errors of judgment or for any acts or omissions unless there has been a final and non-appealable judgment 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 the knowledge that such conduct was unlawful.
		*Special Provisions Regarding Affiliated Transactions.* Our partnership agreement generally provides that affiliated transactions and resolutions of conflicts of interest that are not approved by a vote of unitholders and that are not approved by the conflicts committee of the board of directors of our general partner must be:
		• on terms no less favorable to us than those generally being provided to, or available from, unrelated third parties; or


		• "fair and reasonable" to us, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to us).
		If our general partner does not seek approval from the conflicts committee and the board of directors of our general partner determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the bullet points above, then it will be presumed that, in making its decision, the board of directors, which may include board members affected by the conflict of interest, 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. These standards reduce the obligations to which our general partner would otherwise be held.

By purchasing our common units, each common unitholder automatically agrees to be bound by the provisions in our partnership agreement, including the provisions discussed above. This is in accordance with the policy of the Delaware Act favoring the principle of freedom of contract and the enforceability of partnership agreements. The failure of a limited partner to sign a partnership agreement does not render our partnership agreement unenforceable against that person.

Under our partnership agreement, we must indemnify our general partner and its officers, directors, managers and certain other specified persons, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by our general partner or these other persons. We must provide this indemnification unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that these persons acted in bad faith or engaged in fraud or willful misconduct. We must also provide this indemnification for criminal proceedings unless our general partner or these other persons acted with knowledge that their conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it meets the requirements set forth above. To the extent these provisions purport to include indemnification for liabilities arising under the Securities Act of 1933, in the opinion of the SEC, such indemnification is contrary to public policy and, therefore, unenforceable. Please read "The Partnership Agreement — Indemnification."

The common units and the subordinated units are separate classes of limited partner interests in us. The holders of units are entitled to participate in partnership distributions and exercise the rights or privileges available to limited partners under our partnership agreement. For a description of the relative rights and preferences of holders of common units and subordinated units in and to partnership distributions, please read this section and "Our Cash Distribution Policy and Restrictions on Distributions." For a description of other rights and privileges of limited partners under our partnership agreement, including voting rights, please read "The Partnership Agreement."

Wells Fargo Shareowner Services will serve as registrar and transfer agent for the common units. We will pay all fees charged by the transfer agent for transfers of common units, except the following, which must be paid by our unitholders:

There will be no charge to our unitholders for disbursements of our cash distributions. We will indemnify the transfer agent, its agents and each of their respective stockholders, directors, officers and employees against all claims and losses that may arise out of their actions for their activities in that capacity, except for any liability due to any gross negligence or willful misconduct of the indemnitee.

The transfer agent may resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If no successor is appointed, our general partner may act as the transfer agent and registrar until a successor is appointed.

By transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission are reflected in our books and records. Each transferee:

Our general partner may request that a transferee of common units certify that such transferee is an Eligible Holder. As of the date of this prospectus, an Eligible Holder means:

In addition to other rights acquired upon transfer, the transferor gives the transferee the right to become a substituted limited partner in our partnership for the transferred common units. A transferee will become a substituted limited partner of our partnership for the transferred common units automatically upon the recording of the transfer on our books and records. Our general partner will cause any transfers to be recorded on our books and records no less frequently than quarterly.

Until a common unit has been transferred on our books, we and the transfer agent may treat the record holder of the unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

We may, at our discretion, treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holder's rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

Common units are securities and any transfers are subject to the laws governing transfers of securities.

The following is a summary of the material provisions of our partnership agreement. The form of our partnership agreement is included in this prospectus as Appendix A. We will provide prospective investors with a copy of our partnership agreement upon request at no charge.

We summarize the following provisions of our partnership agreement elsewhere in this prospectus:

Our partnership was organized in April 2011 and will have a perpetual existence unless terminated pursuant to the terms of our partnership agreement.

Our purpose under our partnership agreement is to engage in any business activity that is approved by our general partner and that lawfully may be conducted by a limited partnership organized under Delaware law. However, our general partner may not cause us to engage in any business activity that it determines would cause us to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes.

Although our general partner has the ability to cause us and our subsidiaries to engage in activities other than the ownership, acquisition, exploitation and development of oil and natural gas properties and the ownership, acquisition and operation of related assets, our general partner has no current plans to do so and may decline to do so free of any fiduciary duty or obligation whatsoever to us or our limited partners, including any duty to act in good faith or in the best interests of us or our limited partners. Our general partner is generally authorized to perform all acts it determines to be necessary or appropriate to carry out our purposes and to conduct our business.

Our partnership agreement specifies the manner in which we will make cash distributions to holders of our common units and other partnership interests as well as to our general partner in respect of its general partner interest and its incentive distribution rights. For a description of these cash distribution provisions, please read "Provisions of Our Partnership Agreement Relating to Cash Distributions."

Unitholders are not obligated to make additional capital contributions, except as described under "— Limited Liability."

For a discussion of our general partner's right to contribute capital to maintain its 0.1% general partner interest if we issue additional units, please read "— Issuance of Additional Interests."

The following is a summary of the unitholder vote required for each of the matters specified below.

By virtue of the exclusion of those common units held by our general partner and its affiliates from the required vote, and by their ownership of all of the subordinated units, during the subordination period, our general partner and its affiliates do not have the ability to ensure passage of, but do have the ability to ensure defeat of, any amendment that requires a unit majority.

In voting their common and subordinated units, our general partner and its affiliates will have no fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or our limited partners.


Issuance of additional units		No approval right. Please read "— Issuance of Additional Interests."
Amendment of the partnership agreement		Certain amendments may be made by our general partner without the approval of any limited partner. Other amendments generally require the approval of a unit majority. Please read "— Amendment of the Partnership Agreement."
Merger of our partnership or the sale of all or substantially all of our assets		Unit majority, in certain circumstances. Please read "— Merger, Consolidation, Sale or Other Disposition of Assets."
Dissolution of our partnership		Unit majority. Please read "— Dissolution."
Continuation of our business upon dissolution		Unit majority. Please read "— Dissolution."
Withdrawal of our general partner		Prior to December 31, 2021, under most circumstances, the approval of a majority of the common units, excluding common units held by our general partner and its affiliates, is required for the withdrawal of our general partner in a manner that would cause a dissolution of our partnership. Please read "— Withdrawal or Removal of Our General Partner."
Removal of our general partner		Not less than 66²/3 of the outstanding units, including units held by our general partner and its affiliates, voting as a single class. Please read "— Withdrawal or Removal of Our General Partner."


Transfer of our general partner interest		Our general partner may transfer without a vote of our unitholders all, but not less than all, of its general partner interest in us to an affiliate or another person (other than an individual) in connection with its merger or consolidation with or into, or sale of all, or substantially all, of its assets to, such person. The approval of a majority of the common units, excluding common units held by our general partner and its affiliates, is required in other circumstances for a transfer of the general partner interest to a third party prior to December 31, 2021. Please read "— Transfer of General Partner Units."
Transfer of incentive distribution rights		No approval rights. Please read "— Transfer of Incentive Distribution Rights."
Transfer of ownership interests in our general partner		No approval required at any time. Please read "— Transfer of Ownership Interests in Our General Partner."

Our partnership agreement is governed by Delaware law. Our partnership agreement requires that any claims, suits, actions or proceedings:

Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and that he otherwise acts in conformity with the provisions of our partnership agreement, his liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital he is obligated to contribute to us for his common units plus his

share of any undistributed profits and assets. If it were determined, however, that the right or exercise of the right by our limited partners as a group:

Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, would exceed the fair value of the assets of the limited partnership. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years. Under the Delaware Act, a substituted limited partner of a limited partnership is liable for the obligations of his assignor to make contributions to the partnership, except that such person is not obligated for liabilities unknown to him at the time he became a limited partner and that could not be ascertained from the partnership agreement.

Our operating subsidiary conducts business in New Mexico, Oklahoma and Texas, and we may have operating subsidiaries that conduct business in other states in the future. Maintenance of our limited liability as an owner of our operating subsidiary may require compliance with legal requirements in the jurisdictions in which our operating subsidiary conducts business, including qualifying our operating subsidiary to do business there.

Limitations on the liability of members or limited partners for the obligations of a limited liability company or limited partnership have not been clearly established in many jurisdictions. If, by virtue of our ownership in the operating company or otherwise, it were determined that we were conducting business in any state without compliance with the applicable limited partnership or limited liability company statute, or that the right or exercise of the right by our limited partners as a group to remove or replace our general partner, to approve some amendments to our partnership agreement, or to take other action under our partnership agreement constitutes or constituted "participation in the control" of our business for purposes of the statutes of any relevant jurisdiction, then our limited partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as our general partner under the circumstances. We will operate in a manner that our general partner considers reasonable and necessary or appropriate to preserve the limited liability of our limited partners.

Our partnership agreement authorizes us to issue an unlimited number of additional partnership interests for the consideration and on the terms and conditions determined by our general partner without the approval of our unitholders.

It is possible that we will fund acquisitions through the issuance of additional common units, subordinated units or other partnership interests. Holders of any additional common units we issue will be entitled to share equally with the then-existing holders of common units in our distributions of available cash. In addition, the issuance of additional common units or other partnership interests may dilute the value of the interests of the then-existing holders of common units in our net assets.

In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership interests that, as determined by our general partner, may have special voting rights to which the common units are not entitled. In addition, our partnership agreement does not prohibit the issuance by our subsidiaries of equity interests, which may effectively rank senior to our common units.

If we issue additional partnership interests (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 option to purchase additional common units, the issuance of partnership interests issued in connection with a reset of the incentive distribution target levels relating to our general partner's incentive distribution rights or the issuance of partnership interests upon conversion of outstanding partnership interests), our general partner will be entitled, but not required, to make additional capital contributions to the extent necessary to maintain its 0.1% general partner interest in us. Our general partner's 0.1% general partner interest in us will be reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its 0.1% general partner interest in us. Moreover, our general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units, subordinated units or other partnership interests whenever, and on the same terms that, we issue those interests to persons other than our general partner and its affiliates, to the extent necessary to maintain the aggregate percentage interest in us of our general partner and its affiliates, including such interest represented by common units and subordinated units, that existed immediately prior to each issuance. The holders of common units will not have preemptive rights to acquire additional common units or other partnership interests.

Amendments to our partnership agreement may be proposed only by our general partner. However, our general partner will have no duty or obligation to propose any amendment and may decline to do so free of any fiduciary duty or obligation whatsoever to us or our limited partners, including any duty to act in good faith or in the best interests of us or our limited partners. To adopt a proposed amendment, other than the amendments discussed below under "— No Unitholder Approval," our general partner is required to seek written approval of the holders of the number of units required to approve the amendment or call a meeting of our limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a unit majority.

The provision of our partnership agreement preventing the amendments having the effects described in any of the clauses above can be amended upon the approval of the holders of at least 90% of the outstanding units voting together as a single class (including units owned by our general partner and its affiliates). Upon the consummation of this offering, Lime Rock Resources will own an aggregate of approximately 39.9% of our outstanding common units and 100% of our subordinated units, representing an aggregate of approximately 58.0% of our outstanding limited partnership units.

Our general partner may generally make amendments to our partnership agreement without the approval of any limited partner to reflect:

In addition, our general partner may make amendments to our partnership agreement without the approval of any limited partner if our general partner determines that those amendments:

Our general partner will not be required to obtain an opinion of counsel that an amendment will not result in a loss of limited liability to our limited partners or result in our being treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes in connection with any of the amendments described above under "— No Unitholder Approval." No other amendments to our partnership agreement will become effective without the approval of holders of at least 90% of the outstanding units voting as a single class unless we first obtain an opinion of counsel to the effect that the amendment will not affect the limited liability under Delaware law of any of our limited partners.

In addition to the above restrictions, any amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding units in relation to other classes of units will require the approval of at least a majority of the type or class of units so affected, but no vote will be required by any class or classes or type or types of limited partners that our general partner determines are not adversely affected in any material respect. Any amendment that reduces the voting percentage required to take any action other than to remove the general partner or call a meeting of unitholders is required to be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the voting requirement sought to be reduced. Any amendment that would increase the percentage of units required to remove the general partner or call a meeting of unitholders must be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the percentage sought to be increased.

A merger or consolidation of us requires the prior consent of our general partner. However, our general partner will have no duty or obligation to consent to any merger or consolidation and may decline to do so free of any fiduciary duty or obligation whatsoever to us or our limited partners, including any duty to act in good faith or in the best interest of us or our limited partners.

In addition, our partnership agreement generally prohibits our general partner, without the prior approval of the holders of a unit majority, from causing us, among other things, to sell, exchange or otherwise dispose of all or substantially all of our and our subsidiaries' assets in a single transaction or a series of related transactions, including by way of merger, consolidation or other combination or sale of ownership interests of our subsidiaries. Our general partner may, however, mortgage, pledge, hypothecate or grant a security interest in all or substantially all of our assets without that approval.

Our general partner may also sell all or substantially all of our assets under a foreclosure or other realization upon those encumbrances without that approval. Finally, our general partner may consummate any merger or consolidation without the prior approval of our unitholders if we are the surviving entity in the transaction, our general partner has received an opinion of counsel regarding limited liability and tax matters, the transaction will not result in a material amendment to our partnership agreement (other than an amendment that the general partner could adopt without the consent of other partners), each of our units will be an identical unit of our partnership following the transaction, and the partnership interests to be issued do not exceed 20% of our outstanding partnership interests immediately prior to the transaction.

If the conditions specified in our partnership agreement are satisfied, our general partner may convert us or any of our subsidiaries into a new limited liability entity or merge us or any of our subsidiaries into, or convey all of our assets to, a newly formed entity, if the sole purpose of that conversion, merger or conveyance is to effect a mere change in our legal form into another limited liability entity, our general partner has received an opinion of counsel regarding limited liability and tax matters, and the governing instruments of the new entity provide our limited partners and our general partner with the same rights and obligations as contained in our partnership agreement. The unitholders are not entitled to dissenters' rights of appraisal under our partnership agreement or applicable Delaware law in the event of a conversion, merger or consolidation, a sale of substantially all of our assets or any other similar transaction or event.

We will continue as a limited partnership until dissolved under our partnership agreement. We will dissolve upon:

Upon a dissolution under the last clause above, the holders of a unit majority may also elect, within specific time limitations, to continue our business on the same terms and conditions described in our partnership agreement by appointing as a successor general partner an entity approved by the holders of a unit majority, subject to our receipt of an opinion of counsel to the effect that:

Upon our dissolution, unless our business is continued, the liquidator authorized to wind up our affairs will, acting with all of the powers of our general partner that are necessary or appropriate, liquidate our assets and apply the proceeds of the liquidation as described in "Provisions of Our Partnership Agreement Relating to Cash Distributions — Distributions of Cash Upon Liquidation." The liquidator may defer liquidation or distribution of our assets for a reasonable period of time or distribute

assets to partners in kind if it determines that a sale would be impractical or would cause undue loss to our partners.

Except as described below, our general partner has agreed not to withdraw voluntarily as our general partner prior to December 31, 2021 without obtaining the approval of the holders of at least a majority of our outstanding common units, excluding common units held by our general partner and its affiliates, and furnishing an opinion of counsel regarding limited liability and tax matters. On or after December 31, 2021, our general partner may withdraw as our general partner without first obtaining approval of any unitholder by giving at least 90 days' written notice, and that withdrawal will not constitute a violation of our partnership agreement. Notwithstanding the information above, our general partner may withdraw as our general partner without unitholder approval upon 90 days' notice to our limited partners if at least 50% of the outstanding common units are held or controlled by one person and its affiliates other than our general partner and its affiliates. In addition, our partnership agreement permits our general partner in some instances to sell or otherwise transfer all of its general partner interest in us without the approval of the unitholders. Please read "— Transfer of General Partner Units."

Upon withdrawal of our general partner under any circumstances, other than as a result of a transfer by our general partner of all or a part of its general partner interest in us, the holders of a unit majority may select a successor to the withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters is not obtained, we will be dissolved, wound up and liquidated, unless within a specified period of time after that withdrawal, the holders of a unit majority agree in writing to continue our business and to appoint a successor general partner. Please read "— Dissolution."

Our general partner may not be removed unless that removal is approved by the vote of the holders of not less than 66²/3% of our outstanding units, voting together as a single class, including units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of our general partner is also subject to the approval of a successor general partner by the vote of the holders of a majority of our outstanding common units, voting as a class, and the outstanding subordinated units, voting as a class. The ownership of more than 33¹/3% of our outstanding units by our general partner and its affiliates would give them the practical ability to prevent our general partner's removal. Upon the consummation of this offering, Lime Rock Resources will own an aggregate of approximately 39.9% of our outstanding common units and 100% of our subordinated units, representing approximately 58.0% of our outstanding limited partnership units.

Our partnership agreement also provides that if our general partner is removed as our general partner under circumstances where cause does not exist:

In the event of removal of our general partner under circumstances where cause exists or withdrawal of our general partner where that withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the departing general partner's general partner interest and incentive distribution rights for a cash payment equal to the fair market value of those interests. Under all other circumstances where our general partner withdraws or is removed by the limited

partners, the departing general partner will have the option to require the successor general partner to purchase the general partner interest of the departing general partner and its incentive distribution rights for fair market value. In each case, this fair market value will be determined by agreement between the departing general partner and the successor general partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing general partner and the successor general partner will determine the fair market value. If the departing general partner and the successor general partner cannot agree upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.

If the option described above is not exercised by either the departing general partner or the successor general partner, the departing general partner's general partner interest and its incentive distribution rights will automatically convert into common units equal to the fair market value of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.

In addition, we will be required to reimburse the departing general partner for all amounts due the departing general partner, including, without limitation, all employee-related liabilities, including severance liabilities, incurred for the termination of any employees employed by the departing general partner or its affiliates for our benefit.

Except for the transfer by our general partner of all, but not less than all, of its general partner units to:

Our general partner and its affiliates may at any time transfer common units or subordinated units to one or more persons without unitholder approval, except that they may not transfer subordinated units to us.

Our general partner or any other holder of incentive distribution rights may transfer any or all of its incentive distribution rights without unitholder approval.

At any time, the members of our general partner may sell or transfer all or part of their membership interests in our general partner to an affiliate or a third party without the approval of our unitholders.

Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove our general partner or otherwise change the management of our

general partner. If any person or group other than our general partner and its affiliates acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units from our general partner or its affiliates and any transferees of that person or group approved by our general partner or to any person or group who acquires the units with the prior approval of the board of directors of our general partner.

If our general partner is removed without cause and no units held by our general partner and its affiliates are voted in favor of that removal, our partnership agreement provides that, among other things, (i) all outstanding subordinated units will immediately convert into common units, (ii) any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished and (iii) our general partner will have the right to convert its general partner interest and incentive distribution rights into common units or receive cash in exchange for those interests.

If at any time our general partner and its affiliates own more than 80% of our then-issued and outstanding limited partner interests of any class, our general partner will have the right, which it may assign in whole or in part to any of its affiliates or to us, to acquire all, but not less than all, of the limited partner interests of the class held by unaffiliated persons as of a record date to be selected by our general partner, on at least 10 but not more than 60 days' notice. The purchase price in the event of this purchase is the greater of:

As a result of our general partner's right to purchase outstanding limited partner interests, a holder of limited partner interests may have his limited partner interests purchased at an undesirable time or price. The federal income tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his common units in the market. Please read "Material Tax Consequences — Disposition of Common Units."

Except as described below regarding a person or group owning 20% or more of any class of units then outstanding, record holders of common and subordinated units on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited. Units that are owned by Non-Eligible Holders will be voted by our general partner and our general partner will cast the votes on those units in the same ratios as the votes of limited partners on other units are cast.

Our general partner does not anticipate that any meeting of unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or without a meeting if consents in writing describing the action so taken are signed by holders of the number of units necessary to authorize or take that action at a meeting. Meetings of the unitholders may be called by our general partner or by unitholders owning at least 20% of the outstanding units of the class for which a meeting is proposed. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting has been called, represented in person or by proxy, will constitute a quorum unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage.

Each record holder of a unit has a vote according to his percentage interest in us, although additional limited partner interests having special voting rights could be issued. Please read "— Issuance of Additional Interests." However, if at any time any person or group, other than our general partner and its affiliates or a direct or subsequently approved transferee of our general partner or its affiliates and specifically approved by our general partner, acquires, in the aggregate, beneficial ownership of 20% or more of any class of units then outstanding, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum or for other similar purposes. Common units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and his nominee provides otherwise. Except as our partnership agreement otherwise provides, subordinated units will vote together with common units, as a single class.

Any notice, demand, request, report or proxy material required or permitted to be given or made to record holders of common units under our partnership agreement will be delivered to the record holder by us or by the transfer agent.

By transfer of any common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission is reflected in our books and records. Except as described under "— Limited Liability," the common units will be fully paid, and unitholders will not be required to make additional contributions.

We currently own interests in oil and natural gas leases on United States federal lands and may acquire additional interests in the future. To comply with certain U.S. laws relating to the ownership of interests in oil and natural gas leases on federal lands, our general partner, acting on our behalf, may request that any unitholders fill out a properly completed certificate certifying that the unitholder is an Eligible Holder. 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:

For the avoidance of doubt, 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. This certification can be changed in any manner our general partner determines is necessary or appropriate to implement its original purpose.

The purchase price will be paid in cash or delivery of a promissory note, as determined by our general partner. Any such promissory note will bear interest at the rate of 5% annually and be payable in three equal annual installments of principal and accrued interest, commencing one year after the redemption date.

Under our partnership agreement, in most circumstances, we will indemnify the following persons, to the fullest extent permitted by law, from and against all losses, claims, damages or similar events:

Any indemnification under these provisions will only be out of our assets. Unless it otherwise agrees, our general partner will not be personally liable for, or have any obligation to contribute or lend funds or assets to us to enable us to effectuate, indemnification. We may purchase insurance covering liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under our partnership agreement.

Our partnership agreement requires us to reimburse our general partner for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. 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 general partner is entitled to determine in good faith the expenses that are allocable to us.

Our general partner is required to keep appropriate books of our business at our principal offices. The books will be maintained for both tax and financial reporting purposes on an accrual basis. For financial reporting and tax purposes, our fiscal year end is December 31.

We will furnish or make available to record holders of common units, within 90 days after the close of each fiscal year, an annual report containing audited financial statements and a report on those financial statements by our independent registered public accounting firm. Except for our fourth quarter, we will also furnish or make available summary financial information within 45 days after the close of each quarter. We will be deemed to have made any such report available if we file such report with the SEC on EDGAR or make the report available on a publicly available website which we maintain.

We will furnish each record holder of a unit with information reasonably required for tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to our unitholders will depend on the cooperation of our unitholders in supplying us with specific information. Every unitholder will receive information to assist him in determining his federal and state tax liability and filing his federal and state income tax returns, regardless of whether he supplies us with information.

Our partnership agreement provides that a limited partner can, for a purpose reasonably related to his interest as a limited partner, upon reasonable written demand stating the purpose of such demand and at his own expense, obtain:

Our general partner may, and intends to, keep confidential from the limited partners trade secrets or other information the disclosure of which our general partner believes in good faith is not in our best interests or that we are required by law or by agreements with third parties to keep confidential.

Under our partnership agreement, our general partner and its affiliates have the right to cause us to register for resale under the Securities Act and applicable state securities laws any common units, subordinated units or other partnership interests proposed to be sold by our general partner or any of its affiliates or their assignees if an exemption from the registration requirements is not otherwise available. In addition, our general partner and its affiliates have the right to include such securities in a registration by us or any other unitholder, subject to customary exceptions. These registration rights continue for two years following any withdrawal or removal of our general partner. In addition, we are restricted from granting any superior piggyback registration rights during this two-year period. We will pay all expenses incidental to the registration, excluding underwriting fees and discounts. In connection with any registration of this kind, we will indemnify the unitholders participating in the registration and their officers, directors and controlling persons from and against specified liabilities, including under the Securities Act or any applicable state securities laws. Please read "Units Eligible for Future Sale."

After the sale of the common units offered hereby, Fund I will hold an aggregate of 6,249,600 common units and 6,720,000 subordinated units. All of the subordinated units will convert into common units at the end of the subordination period. The sale of these units could have an adverse impact on the price of the common units or on any trading market that may develop.

The common units sold in this offering will generally be freely transferable without restriction or further registration under the Securities Act, except that any common units owned by an "affiliate" of ours may not be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption under Rule 144 or otherwise. Rule 144 permits securities acquired by an affiliate of the issuer to be sold into the market in an amount that does not exceed, during any three-month period, the greater of:

Sales under Rule 144 are also subject to specific manner of sale provisions, holding period requirements, notice requirements and the availability of current public information about us. A unitholder who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned his common units for at least six months (provided we are in compliance with the current public information requirement) or one year (regardless of whether we are in compliance with the current public information requirement), would be entitled to sell his common units under Rule 144 without regard to the rule's public information requirements, volume limitations, manner of sale provisions and notice requirements.

Our partnership agreement does not restrict our ability to issue any partnership interests. Any issuance of additional common units or other equity interests would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the cash distributions to and market price of, our common units then outstanding. Please read "The Partnership Agreement — Issuance of Additional Interests."

Under our partnership agreement, our general partner and its affiliates have the right to cause us to register under the Securities Act and applicable state securities laws the offer and sale of any common units or other partnership interests that they hold, which we refer to as registerable securities. Subject to the terms and conditions of our partnership agreement, these registration rights allow our general partner and its affiliates or their assignees holding any registerable securities to require registration of such registerable securities and to include any such registerable securities in a registration by us of common units or other partnership interests, including common units or other partnership interests offered by us or by any unitholder. Our general partner and its affiliates will continue to have these registration rights for two years following the withdrawal or removal of our general partner.

Except as described below, our general partner and its affiliates may sell their common units or other partnership interests in private transactions at any time, subject to compliance with certain conditions and applicable laws.

We, our general partner and certain of its affiliates and the directors and executive officers of our general partner have agreed, subject to certain exceptions, not to sell any common units for a period of 180 days from the date of this prospectus. For a description of these lock-up provisions, please read "Underwriting — Lock-Up Agreements."

This section is a summary of the material U.S. federal, state and local tax consequences that may be relevant to prospective unitholders and, unless otherwise noted in the following discussion, is the opinion of Andrews Kurth LLP insofar as it describes legal conclusions with respect to matters of U.S. federal income tax law. Such statements are based on the accuracy of the representations made by our general partner and us to Andrews Kurth LLP, and statements of fact do not represent opinions of Andrews Kurth LLP. To the extent this section discusses U.S. federal income taxes, that discussion is based upon current provisions of the Internal Revenue Code of 1986, as amended (the "Internal Revenue Code"), existing and proposed Treasury regulations promulgated thereunder (the "Treasury Regulations"), and current administrative rulings and court decisions, all of which are subject to change. Changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to "us" or "we" are references to LRR Energy, L.P. and our subsidiaries.

This section does not address all U.S. federal, state and local tax matters that affect us or our unitholders. To the extent that this section relates to taxation by a state, local or other jurisdiction within the United States, such discussion is intended to provide only general information. We have not sought the opinion of legal counsel regarding U.S. state, local or other taxation and, thus, any portion of the following discussion relating to such taxes does not represent the opinion of Andrews Kurth LLP or any other legal counsel. Furthermore, this section focuses on unitholders who are individual citizens or residents of the United States, whose functional currency is the U.S. dollar and who hold common units as a capital asset (generally, property that is held as an investment). This section has only limited application to corporations, partnerships (and entities treated as partnerships for U.S. federal income tax purposes), estates, trusts, non-resident aliens or other unitholders subject to specialized tax treatment, such as tax-exempt institutions, non-U.S. persons, individual retirement accounts, employee benefit plans, real estate investment trusts or mutual funds. Accordingly, we encourage each prospective unitholder to consult such unitholder's own tax advisor in analyzing the U.S. federal, state, local and non-U.S. tax consequences particular to that unitholder resulting from his ownership or disposition of his common units.

No ruling has been or will be requested from the Internal Revenue Service (the "IRS") regarding any matter that affects us or our unitholders. Instead, we will rely on opinions and advice of Andrews Kurth LLP. Unlike a ruling, an opinion of counsel represents only that counsel's best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions and statements made herein may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for our common units and the prices at which such common units trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will result in a reduction in cash available for distribution to our unitholders and our general partner and thus will be borne indirectly by our unitholders and our general partner. Furthermore, our tax treatment, or the tax treatment of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.

For the reasons described below, Andrews Kurth LLP has not rendered an opinion with respect to the following specific U.S. federal income tax issues: (1) the treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units (please read "— Tax Consequences of Unit Ownership — Treatment of Short Sales"); (2) whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (please read "— Disposition of Common Units — Allocations Between Transferors and Transferees"); and (3) whether our method for depreciating Section 743 adjustments is sustainable in certain cases (please read "— Tax Consequences of Unit Ownership — Section 754 Election" and "— Uniformity of Common Units").

We will be treated as a partnership for U.S. federal income tax purposes and, therefore, generally will not be liable for U.S. federal income taxes. Instead, each of our unitholders will be required to take into account his respective share of our items of income, gain, loss and deduction in computing his U.S. federal income tax liability as if the unitholder had earned such income directly, even if no cash distributions are made to the unitholder. Distributions by us to a unitholder generally will not be taxable to the unitholder unless the amount of cash distributed to the unitholder exceeds the unitholder's tax basis in his common units.

Section 7704 of the Internal Revenue Code provides that publicly traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to as the "Qualifying Income Exception," exists with respect to publicly traded partnerships of which 90% or more of the gross income for every taxable year consists of "qualifying income." Qualifying income includes income and gains derived from exploration and production of certain natural resources, including oil, natural gas, and products thereof. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income. We estimate that less than 5% of our current gross income is not qualifying income; however, this estimate could change from time to time. Based upon and subject to this estimate, the factual representations made by us and our general partner, and a review of the applicable legal authorities, Andrews Kurth LLP is of the opinion that at least 90% of our current gross income constitutes qualifying income. The portion of our income that is qualifying income may change from time to time.

No ruling has been or will be sought from the IRS, and the IRS has made no determination as to our status or the status of our operating subsidiary for U.S. federal income tax purposes or whether our operations generate "qualifying income" under Section 7704 of the Internal Revenue Code. Instead, we will rely on the opinion of Andrews Kurth LLP on such matters. It is the opinion of Andrews Kurth LLP that we will be classified as a partnership and our operating subsidiary will be disregarded as an entity separate from us for U.S. federal income tax purposes.

In rendering its opinion, Andrews Kurth LLP has relied on factual representations made by us and our general partner. The representations made by us and our general partner upon which Andrews Kurth LLP has relied include, without limitation:

(a) neither we nor our operating subsidiary has elected or will elect to be treated as a corporation; and

(b) for each taxable year, including short taxable years occurring as a result of a constructive termination, more than 90% of our gross income has been and will be income that Andrews Kurth LLP has opined or will opine is "qualifying income" within the meaning of Section 7704(d) of the Internal Revenue Code.

We believe that these representations have been true in the past and expect that these representations will continue to be true in the future.

If we fail to meet the Qualifying Income Exception, unless such failure is determined by the IRS to be inadvertent and is cured within a reasonable time after discovery (in which case the IRS may also require us to make adjustments with respect to our unitholders or pay other amounts), we will be treated as if we had transferred all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we failed to meet the Qualifying Income Exception, in return for stock in that corporation and then distributed that stock to our unitholders in liquidation of their interests in us. This deemed contribution and liquidation should be tax-free to our unitholders and us so long as we, at that time, do not have liabilities in excess of the tax basis of our assets. Thereafter, we would be treated as a corporation for U.S. federal income tax purposes.

If we were taxed as a corporation for U.S. federal income tax purposes in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss and deduction would be reflected only on our tax return, rather than being passed through to our unitholders, and our net income would be taxed to us at corporate rates. In addition, any distribution made to a unitholder would be treated as taxable dividend income, to the extent of our current and accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital, to the extent of the unitholder's tax basis in our common units, or taxable capital gain, after the unitholder's tax basis in his common units is reduced to zero. Accordingly, taxation as a corporation would result in a material reduction in a unitholder's cash flow and after-tax return and thus would likely result in a substantial reduction of the value of our common units.

The discussion below is based on Andrews Kurth LLP's opinion that we will be classified as a partnership for U.S. federal income tax purposes.

Unitholders who are admitted as limited partners of LRR Energy, as well as unitholders whose common units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of common units, will be treated as partners of LRR Energy for U.S. federal income tax purposes. A beneficial owner of common units whose units have been transferred to a short seller to complete a short sale would appear to lose his status as a partner with respect to those units for U.S. federal income tax purposes. Please read "— Treatment of Short Sales." Unitholders who are not treated as partners in us as described above are urged to consult their own tax advisors with respect to the tax consequences applicable to them under the circumstances.

The references to "unitholders" in the discussion that follows are to persons who are treated as partners in LRR Energy for federal income tax purposes.

Subject to the discussion below under "— Entity-Level Collections of Unitholder Taxes," neither we nor our subsidiaries will pay any U.S. federal income tax. For U.S. federal income tax purposes, each unitholder will be required to report on his income tax return his share of our income, gains, losses and deductions without regard to whether we make cash distributions to such unitholder. Consequently, we may allocate income to a unitholder even if that unitholder has not received a cash distribution. Each unitholder will be required to include in income his allocable share of our income, gains, losses and deductions for his taxable year or years ending with or within our taxable year. Our taxable year ends on December 31.

Distributions made by us to a unitholder generally will not be taxable to the unitholder for federal income tax purposes, except to the extent the amount of any such cash distribution exceeds his tax basis in his common units immediately before the distribution. Cash distributions made by us to a unitholder in an amount in excess of the unitholder's tax basis in his common units generally will be considered to be gain from the sale or exchange of those common units, taxable in accordance with the rules described under "— Disposition of Common Units" below. Any reduction in a unitholder's share of our liabilities, including as a result of future issuances of additional common units, will be treated as a distribution of cash to that unitholder. To the extent that cash distributions made by us cause a unitholder's "at risk" amount to be less than zero at the end of any taxable year, that unitholder must recapture any losses deducted in previous years. Please read "— Limitations on Deductibility of Losses."

A decrease in a unitholder's percentage interest in us because of our issuance of additional common units will decrease his share of our nonrecourse liabilities, and thus will result in a corresponding deemed distribution of cash. This deemed distribution may constitute a non-pro rata distribution. A non-pro rata distribution of money or property, including a deemed distribution, may result in ordinary income to a unitholder, regardless of that unitholder's tax basis in its common units, if the distribution reduces the unitholder's share of our "unrealized receivables," including depreciation recapture, depletion recapture and/or substantially appreciated "inventory items," both as defined in Section 751 of the Internal Revenue Code, and collectively, "Section 751 Assets." To the extent of such reduction, a unitholder will be treated as having received his proportionate share of the Section 751 Assets and then having exchanged those assets with us in return for an allocable portion of the non-pro rata distribution made to such unitholder. This latter deemed exchange generally will result in the unitholder's realization of ordinary income in an amount equal to the excess of (1) the non-pro rata portion of that distribution over (2) the unitholder's tax basis (generally zero) in the Section 751 Assets deemed relinquished in the exchange.

We estimate that a purchaser of common units in this offering who owns those common units from the date of closing of this offering through the record date for distributions for the period ending December 31, 2014, will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be 30% or less of the cash distributed with respect to that period. Thereafter, we anticipate that the ratio of allocable taxable income to cash distributions to the unitholders will increase. These estimates are based upon the assumption that gross income from operations will approximate the amount required to make the minimum quarterly distribution on all common units and other assumptions with respect to capital expenditures, cash flow, net working capital and anticipated cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, legislative, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and tax reporting positions that we will adopt and with which the IRS could disagree. Accordingly, we cannot assure our unitholders that these estimates will prove to be correct. The actual percentage of distributions that will constitute taxable income could be higher or lower than expected, and any differences could be material and could materially affect the value of the common units. For example, the ratio of allocable taxable income to cash distributions to a purchaser of common units in this offering will be greater, and perhaps substantially greater, than our estimate with respect to the period described above if:

A unitholder's initial tax basis in his common units will be the amount he paid for those common units plus his share of our nonrecourse liabilities. That basis generally will be (i) increased by the unitholder's share of our income and by any increases in such unitholder's share of our nonrecourse liabilities, and (ii) decreased, but not below zero, by distributions to him, by his share of our losses, by depletion deductions taken by him to the extent such deductions do not exceed his proportionate share of the adjusted tax basis of the underlying properties, by any decreases in his share of our nonrecourse

liabilities and by his share of our expenditures that are not deductible in computing taxable income and are not required to be capitalized. A unitholder will have no share of our debt that is recourse to our general partner to the extent of the general partner's "net value" as defined in regulations under Section 752 of the Internal Revenue Code, but will have a share, generally, based on his share of our profits, of our nonrecourse liabilities. Please read "— Disposition of Common Units — Recognition of Gain or Loss."

The deduction by a unitholder of that unitholder's share of our losses will be limited to the lesser of (i) the tax basis such unitholder has in his common units, and (ii) in the case of an individual, estate, trust or corporate unitholder (if more than 50% of the corporate unitholder's stock is owned directly or indirectly by or for five or fewer individuals or some tax exempt organizations) to the amount for which the unitholder is considered to be "at risk" with respect to our activities. A unitholder subject to these limitations must recapture losses deducted in previous years to the extent that distributions cause the unitholder's at risk amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable as a deduction in a later year to the extent that the unitholder's tax basis or at risk amount, whichever is the limiting factor, is subsequently increased. Upon the taxable disposition of a unit, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at risk limitation but may not be offset by losses suspended by the basis limitation. Any loss previously suspended by the at risk limitation in excess of that gain would no longer be utilizable.

In general, a unitholder will be at risk to the extent of the tax basis of the unitholder's common units, excluding any portion of that basis attributable to the unitholder's share of our nonrecourse liabilities, reduced by (1) any portion of that basis representing amounts otherwise protected against loss because of a guarantee, stop loss agreement or other similar arrangement and (2) any amount of money the unitholder borrows to acquire or hold his common units, if the lender of those borrowed funds owns an interest in us, is related to another unitholder or can look only to the common units for repayment. A unitholder's at risk amount will increase or decrease as the tax basis of the unitholder's common units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in the unitholder's share of our liabilities.

The at risk limitation applies on an activity-by-activity basis, and in the case of oil and natural gas properties, each property is treated as a separate activity. Thus, a taxpayer's interest in each oil or natural gas property is generally required to be treated separately so that a loss from any one property would be limited to the at risk amount for that property and not the at risk amount for all the taxpayer's oil and natural gas properties. It is uncertain how this rule is implemented in the case of multiple oil and natural gas properties owned by a single entity treated as a partnership for federal income tax purposes. However, for taxable years ending on or before the date on which further guidance is published, the IRS will permit aggregation of oil or natural gas properties we own in computing a unitholder's at risk limitation with respect to us. If a unitholder were required to compute his at risk amount separately with respect to each oil or natural gas property we own, he might not be allowed to utilize his share of losses or deductions attributable to a particular property even though he has a positive at risk amount with respect to his common units as a whole.

In addition to the basis and at risk limitations on the deductibility of losses, the passive loss limitations generally provide that individuals, estates, trusts and some closely-held corporations and personal service corporations may deduct losses from passive activities, which are generally defined as trade or business activities in which the taxpayer does not materially participate, only to the extent of the taxpayer's income from those passive activities. The passive loss limitations are applied separately with respect to each publicly-traded partnership. Consequently, any passive losses we generate will only be available to offset our passive income generated in the future and will not be available to offset income from other passive activities or investments, including our investments or a unitholder's

investments in other publicly-traded partnerships, or a unitholder's salary or active business income. Passive losses that are not deductible because they exceed a unitholder's share of passive income we generate may be deducted in full when he disposes of his entire investment in us in a fully taxable transaction with an unrelated party. The passive loss limitations are applied after other applicable limitations on deductions, including the at risk rules and the basis limitation.

A unitholder's share of our net passive income may be offset by any of our suspended passive losses, but it may not be offset by any other current or carryover losses from other passive activities, including those attributable to other publicly traded partnerships.

The deductibility of a non-corporate taxpayer's "investment interest expense" is generally limited to the amount of that taxpayer's "net investment income." Investment interest expense includes:

The computation of a unitholder's investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment or (if applicable) qualified dividend income. The IRS has indicated that net passive income earned by a publicly-traded partnership will be treated as investment income to its unitholders for purposes of the investment interest expense limitation. In addition, the unitholder's share of our portfolio income will be treated as investment income.

If we are required or elect under applicable law to pay any U.S. federal, state, local or non-U.S. tax on behalf of any unitholder or our general partner or any former unitholder, we are authorized to pay those taxes from our funds. That payment, if made, will be treated as a distribution of cash to the unitholder on whose behalf the payment was made. If the payment is made on behalf of a unitholder whose identity cannot be determined, we are authorized to treat the payment as a distribution to all current unitholders. We are authorized to amend our partnership agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of common units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under our partnership agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of an individual unitholder in which event the unitholder would be required to file a claim in order to obtain a credit or refund.

In general, our items of income, gain, loss and deduction will be allocated among our general partner and the unitholders in accordance with their percentage interests in us. If we have a net loss for an entire taxable year, the loss will be allocated first to our general partner and the unitholders in accordance with their percentage interests in us to the extent of the unitholders' positive capital accounts as adjusted to take into account the unitholders' share of nonrecourse debt, and thereafter to our general partner. However, at any time that distributions are made to the common units in excess of distributions to the subordinated common units, or incentive distributions are made, gross income will be allocated to the recipients to the extent of these distributions.

Specified items of our income, gain, loss and deduction will be allocated to account for the difference between the tax basis and fair market value of our assets, a "Book Tax Disparity," at the time of this offering and any future offerings or certain other transactions. The effect of these allocations, referred to as Section 704(c) Allocations, to a unitholder acquiring common units in this offering will be essentially the same as if the tax bases of our assets were equal to their fair market values at the time of this offering. However, in connection with providing this benefit to any future unitholders, similar allocations will be made to all holders of partnership interests immediately prior to a future offering or certain other transactions, including purchasers of common units in this offering, to account for any Book Tax Disparity at the time of such transaction. In addition, items of recapture income will be allocated to the extent possible to the unitholder who was allocated the deduction giving rise to the treatment of that gain as recapture income in order to minimize the recognition of ordinary income by other unitholders.

An allocation of items of our income, gain, loss or deduction, other than an allocation required by the Internal Revenue Code to eliminate a Book-Tax Disparity, will generally be given effect for U.S. federal income tax purposes in determining a unitholder's share of an item of income, gain, loss or deduction only if the allocation has substantial economic effect. In any other case, a unitholder's share of an item will be determined on the basis of his interest in us, which will be determined by taking into account all the facts and circumstances, including:

Andrews Kurth LLP is of the opinion that, with the exception of the issues described in "— Section 754 Election" and "— Disposition of Common Units — Allocations Between Transferors and Transferees," allocations under our partnership agreement will be given effect for federal income tax purposes in determining a partner's share of an item of income, gain, loss or deduction.

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

Because there is no direct or indirect controlling authority on the issue relating to partnership interests, Andrews Kurth LLP has not rendered an opinion regarding the tax treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of our common units. 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 with their tax advisor about modifying any applicable brokerage account agreements to prohibit their brokers from borrowing and loaning their common units. The IRS has previously announced that it is studying issues relating to the tax treatment of short sales of partnership interests. Please read "— Disposition of Common Units — Recognition of Gain or Loss."

Each unitholder will be required to take into account the unitholder's distributive share of any items of our income, gain, loss or deduction for purposes of the alternative minimum tax. The current minimum tax rate for non-corporate taxpayers is 26% on the first $175,000 of alternative minimum taxable income in excess of the exemption amount and 28% on any additional alternative minimum taxable income. Prospective unitholders are urged to consult with their tax advisors with respect to the impact of an investment in our common units on their liability for the alternative minimum tax.

Under current law, the highest marginal U.S. federal income tax rate applicable to ordinary income of individuals is 35% and the highest marginal U.S. federal income tax rate applicable to long-term capital gains (generally, gains from the sale or exchange of certain investment assets held for more than one year) of individuals is 15%. However, absent new legislation extending the current rates, beginning January 1, 2013, the highest marginal U.S. federal income tax rate applicable to ordinary income and long-term capital gains of individuals will increase to 39.6% and 20%, respectively. These rates are subject to change by new legislation at any time.

Recently enacted legislation will impose a 3.8% Medicare tax on certain investment income earned by individuals, estates, and trusts for taxable years beginning after December 31, 2012. For these purposes, investment income generally includes a unitholder's allocable share of our income and gain realized by a unitholder from a sale of common units. In the case of an individual, the tax will be imposed on the lesser of (i) the unitholder's net investment income from all investments, or (ii) the amount by which the unitholder's modified adjusted gross income exceeds specified threshold levels depending on a unitholder's federal income tax filing status. In the case of an estate or trust, the tax will be imposed on the lesser of (i) undistributed net investment income, or (ii) the excess adjusted gross income over the dollar amount at which the highest income tax bracket applicable to an estate or trust begins.

We will make the election permitted by Section 754 of the Internal Revenue Code. That election is irrevocable without the consent of the IRS. That election will generally permit us to adjust a unit purchaser's tax basis in our assets ("inside basis") under Section 743(b) of the Internal Revenue Code to reflect the unitholder's purchase price. The Section 743(b) adjustment separately applies to any transferee of a unitholder who purchases outstanding common units from another unitholder based upon the values and bases of our assets at the time of the transfer to the transferee. The Section 743(b) adjustment does not apply to a person who purchases common units directly from us, and belongs only to the purchaser and not to other unitholders. Please read, however, "— Allocation of Income, Gain, Loss and Deduction." For purposes of this discussion, a unitholder's inside basis in our assets will be considered to have two components: (1) the unitholder's share of our tax basis in our assets ("common basis") and (2) the unitholder's Section 743(b) adjustment to that basis.

The timing and calculation of deductions attributable to Section 743(b) adjustments to our common basis will depend upon a number of factors, including the nature of the assets to which the adjustment is allocable, the extent to which the adjustment offsets any Internal Revenue Code Section 704(c) type gain or loss with respect to an asset and certain elections we make as to the manner in which we apply Internal Revenue Code Section 704(c) principles with respect to an asset to which the adjustment is applicable. Please read "— Allocation of Income, Gain, Loss and Deduction."

The timing of these deductions may affect the uniformity of our common units. Under our partnership agreement, our general partner is authorized to take a position to preserve the uniformity of common units even if that position is not consistent with these and any other Treasury Regulations or if the position would result in lower annual depreciation or amortization deductions than would otherwise

be allowable to some unitholders. Please read "— Uniformity of Common Units." Andrews Kurth LLP is unable to opine as to the validity of any such alternate tax positions because there is no direct or indirect controlling authority addressing the validity of these positions. A unitholder's basis in a unit is reduced by his share of our deductions (whether or not such deductions were claimed on an individual income tax return) so that any position that we take that understates deductions will overstate the unitholder's basis in his common units and may cause the unitholder to understate gain or overstate loss on any sale of such common units. Please read "— Uniformity of Common Units."

A Section 754 election is advantageous if the transferee's tax basis in his common units is higher than the common units' share of the aggregate tax basis of our assets immediately prior to the transfer. In that case, as a result of the election, the transferee would have, among other items, a greater amount of depreciation and depletion deductions and the transferee's share of any gain or loss on a sale of assets by us would be less. Conversely, a Section 754 election is disadvantageous if the transferee's tax basis in his common units is lower than those common units' share of the aggregate tax basis of our assets immediately prior to the transfer. Thus, the fair market value of the common units may be affected either favorably or unfavorably by the election. A basis adjustment is required regardless of whether a Section 754 election is made in the case of a transfer of an interest in us if we have a substantial built-in loss immediately after the transfer, or if we distribute property and have a substantial basis reduction. Generally a built-in loss or a basis reduction is substantial if it exceeds $250,000.

The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the fair market value of our assets and other matters. For example, the allocation of the Section 743(b) adjustment among our assets must be made in accordance with the Internal Revenue Code. The IRS could seek to reallocate some or all of any Section 743(b) adjustment we allocated to our tangible assets to goodwill instead. Goodwill, as an intangible asset, is generally either non-amortizable or amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure our unitholders that the determinations we make will not be successfully challenged by the IRS or that the resulting deductions will not be reduced or disallowed altogether. Should the IRS require a different basis adjustment to be made, and should our general partner determine the expense of compliance exceeds the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of common units may be allocated more income than such purchaser would have been allocated had the election not been revoked.

We will use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in income his share of our income, gain, loss and deduction for our taxable year ending within or with his taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of his common units following the close of our taxable year but before the close of his taxable year must include his share of our income, gain, loss and deduction in income for his taxable year, with the result that he will be required to include in income for his taxable year his share of more than one year of our income, gain, loss and deduction. Please read "— Disposition of Common Units — Allocations Between Transferors and Transferees."

Subject to the limitations on deductibility of losses discussed above (please read "— Tax Consequences of Unit Ownership — Limitations on Deductibility of Losses"), unitholders will be entitled to deductions for the greater of either cost depletion or (if otherwise allowable) percentage depletion with respect to our oil and natural gas interests. Although the Internal Revenue Code requires each

unitholder to compute his own depletion allowance and maintain records of his share of the adjusted tax basis of the underlying property for depletion and other purposes, we intend to furnish each of our unitholders with information relating to this computation for federal income tax purposes. Each unitholder, however, remains responsible for calculating his own depletion allowance and maintaining records of his share of the adjusted tax basis of the underlying property for depletion and other purposes.

Percentage depletion is generally available with respect to unitholders who qualify under the independent producer exemption contained in Section 613A(c) of the Internal Revenue Code. To qualify as an "independent producer" eligible for percentage depletion (and that is not subject to the intangible drilling and development cost deduction limits, please read "— Deductions for Intangible Drilling and Development Costs,") a unitholder, either directly or indirectly through certain related parties, may not be involved in the refining of more than 75,000 barrels of oil (or the equivalent amount of natural gas) on average for any day during the taxable year or in the retail marketing of oil and natural gas products exceeding $5 million per year in the aggregate. Percentage depletion is calculated as an amount generally equal to 15% (and, in the case of marginal production, potentially a higher percentage) of the unitholder's gross income from the depletable property for the taxable year. The percentage depletion deduction with respect to any property is limited to 100% of the taxable income of the unitholder from the property for each taxable year, computed without the depletion allowance. A unitholder that qualifies as an independent producer may deduct percentage depletion only to the extent the unitholder's average net daily production of domestic crude oil, or the natural gas equivalent, does not exceed 1,000 barrels. This depletable amount may be allocated between oil and natural gas production, with 6,000 cubic feet of domestic natural gas production regarded as equivalent to one barrel of crude oil. The 1,000-barrel limitation must be allocated among the independent producer and controlled or related persons and family members in proportion to the respective production by such persons during the period in question.

In addition to the foregoing limitations, the percentage depletion deduction otherwise available is limited to 65% of a unitholder's total taxable income from all sources for the year, computed without the depletion allowance, net operating loss carrybacks, or capital loss carrybacks. Any percentage depletion deduction disallowed because of the 65% limitation may be deducted in the following taxable year if the percentage depletion deduction for such year plus the deduction carryover does not exceed 65% of the unitholder's total taxable income for that year. The carryover period resulting from the 65% net income limitation is unlimited.

Unitholders that do not qualify under the independent producer exemption are generally restricted to depletion deductions based on cost depletion. Cost depletion deductions are calculated by (i) dividing the unitholder's share of the adjusted tax basis in the underlying mineral property by the number of mineral common units (barrels of oil and thousand cubic feet, or Mcf, of natural gas) remaining as of the beginning of the taxable year and (ii) multiplying the result by the number of mineral common units sold within the taxable year. The total amount of deductions based on cost depletion cannot exceed the unitholder's share of the total adjusted tax basis in the property.

All or a portion of any gain recognized by a unitholder as a result of either the disposition by us of some or all of our oil and natural gas interests or the disposition by the unitholder of some or all of his common units may be taxed as ordinary income to the extent of recapture of depletion deductions, except for percentage depletion deductions in excess of the tax basis of the property. The amount of the recapture is generally limited to the amount of gain recognized on the disposition.

The foregoing discussion of depletion deductions does not purport to be a complete analysis of the complex legislation and Treasury Regulations relating to the availability and calculation of depletion deductions by the unitholders. Further, because depletion is required to be computed separately by each unitholder and not by our partnership, no assurance can be given, and counsel is unable to express any opinion, with respect to the availability or extent of percentage depletion deductions to the unitholders

for any taxable year. Moreover, the availability of percentage depletion may be reduced or eliminated if recently proposed (or similar) tax legislation is enacted. For a discussion of such legislative proposals, please read "— Recent Legislative Developments." We encourage each prospective unitholder to consult his tax advisor to determine whether percentage depletion would be available to him.

We will elect to currently deduct intangible drilling and development costs (IDCs). IDCs generally include our expenses for wages, fuel, repairs, hauling, supplies and other items that are incidental to, and necessary for, the drilling and preparation of wells for the production of oil, natural gas, or geothermal energy. The option to currently deduct IDCs applies only to those items that do not have a salvage value.

Although we will elect to currently deduct IDCs, each unitholder will have the option of either currently deducting IDCs or capitalizing all or part of the IDCs and amortizing them on a straight-line basis over a 60-month period, beginning with the taxable month in which the expenditure is made. If a unitholder makes the election to amortize the IDCs over a 60-month period, no IDC preference amount in respect of those IDCs will result for alternative minimum tax purposes.

Integrated oil companies must capitalize 30% of all their IDCs (other than IDCs paid or incurred with respect to oil and natural gas wells located outside of the United States) and amortize these IDCs over 60 months beginning in the month in which those costs are paid or incurred. If the taxpayer ceases to be an integrated oil company, it must continue to amortize those costs as long as it continues to own the property to which the IDCs relate. An "integrated oil company" is a taxpayer that has economic interests in oil or natural gas properties and also carries on substantial retailing or refining operations. An oil or natural gas producer is deemed to be a substantial retailer or refiner if it is does not qualify as an independent producer under the rules disqualifying retailers and refiners from taking percentage depletion. Please read "— Depletion Deductions."

IDCs previously deducted that are allocable to property (directly or through ownership of an interest in a partnership) and that would have been included in the adjusted tax basis of the property had the IDC deduction not been taken are recaptured to the extent of any gain realized upon the disposition of the property or upon the disposition by a unitholder of interests in us. Recapture is generally determined at the unitholder level. Where only a portion of the recapture property is sold, any IDCs related to the entire property are recaptured to the extent of the gain realized on the portion of the property sold. In the case of a disposition of an undivided interest in a property, a proportionate amount of the IDCs with respect to the property is treated as allocable to the transferred undivided interest to the extent of any gain recognized. Please read "— Disposition of Common Units — Recognition of Gain or Loss."

The election to currently deduct IDCs may be restricted or eliminated if recently proposed (or similar) tax legislation is enacted. For a discussion of such legislative proposals, please read "— Recent Legislative Developments."

Subject to the limitations on the deductibility of losses discussed above and the limitation discussed below, unitholders will be entitled to a deduction, herein referred to as the Section 199 deduction, equal to 6% of our qualified production activities income that is allocated to such unitholder.

Qualified production activities income is generally equal to gross receipts from domestic production activities reduced by cost of goods sold allocable to those receipts, other expenses directly associated with those receipts, and a share of other deductions, expenses and losses that are not directly allocable to those receipts or another class of income. The products produced must be manufactured, produced, grown or extracted in whole or in significant part by the taxpayer in the United States.

For a partnership, the Section 199 deduction is determined at the partner level. To determine his Section 199 deduction, each unitholder will aggregate his share of the qualified production activities income allocated to him from us with the unitholder's qualified production activities income from other sources. Each unitholder must take into account his distributive share of the expenses allocated to him from our qualified production activities regardless of whether we otherwise have taxable income. However, our expenses that otherwise would be taken into account for purposes of computing the Section 199 deduction are taken into account only if and to the extent the unitholder's share of losses and deductions from all of our activities is not disallowed by the tax basis rules, the at risk rules or the passive activity loss rules. Please read "— Tax Consequences of Unit Ownership — Limitations on Deductibility of Losses."

The amount of a unitholder's Section 199 deduction for each year is limited to 50% of the IRS Form W-2 wages actually or deemed paid by the unitholder during the calendar year that are deducted in arriving at qualified production activities income. Each unitholder is treated as having been allocated IRS Form W-2 wages from us equal to the unitholder's allocable share of our wages that are deducted in arriving at qualified production activities income for that taxable year. It is not anticipated that we or our operating subsidiary will pay material wages that will be allocated to our unitholders, and thus a unitholder's ability to claim the Section 199 deduction may be limited.

This discussion of the Section 199 deduction does not purport to be a complete analysis of the complex legislation and Treasury authority relating to the calculation of domestic production gross receipts, qualified production activities income, or IRS Form W-2 wages, or how such items are allocated by us to unitholders. Further, because the Section 199 deduction is required to be computed separately by each unitholder, no assurance can be given, and counsel is unable to express any opinion, as to the availability or extent of the Section 199 deduction to the unitholders. Moreover, the availability of Section 199 deductions may be reduced or eliminated if recently proposed (or similar) tax legislation is enacted. For a discussion of such legislative proposals, please read "— Recent Legislative Developments." Each prospective unitholder is encouraged to consult his tax advisor to determine whether the Section 199 deduction would be available to him.

The cost of acquiring oil and natural gas lease or similar property interests is a capital expenditure that must be recovered through depletion deductions if the lease is productive. If a lease is proved worthless and abandoned, the cost of acquisition less any depletion claimed may be deducted as an ordinary loss in the year the lease becomes worthless. Please read "— Tax Treatment of Operations — Depletion Deductions."

The cost of geophysical exploration incurred in connection with the exploration and development of oil and natural gas properties in the United States are deducted ratably over a 24-month period beginning on the date that such expense is paid or incurred. The amortization period for certain geological and geophysical expenditures may be extended if recently proposed (or similar) tax legislation is enacted. For a discussion of such legislative proposals, please read "— Recent Legislative Developments."

Amounts paid for operating a producing well are deductible as ordinary business expenses, as are administrative costs, to the extent they constitute ordinary and necessary business expenses that are reasonable in amount.

The tax basis of our assets will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. The federal income tax burden associated with the difference between the fair market value of our assets and their tax basis immediately prior to an offering will be borne by our partners holding interests in us prior to such offering. Please read "— Tax Consequences of Unit Ownership — Allocation of Income, Gain, Loss and Deduction."

To the extent allowable, we may elect to use the depreciation and cost recovery methods, including bonus depreciation to the extent applicable, that will result in the largest deductions being taken in the early years after assets subject to these allowances are placed in service. We may not be entitled to any amortization deductions with respect to certain goodwill properties conveyed to us or held by us at the time of any future offering. Please read "— Uniformity of Common Units." Property we subsequently acquire or construct may be depreciated using accelerated methods permitted by the Internal Revenue Code.

If we dispose of depreciable property by sale, foreclosure or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of his interest in us. Please read "— Tax Consequences of Unit Ownership — Allocation of Income, Gain, Loss and Deduction" and "— Disposition of Common Units — Recognition of Gain or Loss."

The costs incurred in selling our common units (called "syndication expenses") must be capitalized and cannot be deducted currently, ratably or upon our termination. There are uncertainties regarding the classification of costs as organization expenses, which may be amortized by us, and as syndication expenses, which may not be amortized by us. The underwriting discounts we incur will be treated as syndication expenses.

The federal income tax consequences of the ownership and disposition of common units will depend in part on our estimates of the relative fair market values and the initial tax bases of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deduction previously reported by unitholders might change, and unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

Gain or loss will be recognized on a sale of common units equal to the difference between the unitholder's amount realized and the unitholder's tax basis for the common units sold. A unitholder's amount realized will equal the sum of the cash or the fair market value of other property he receives plus his share of our liabilities. Because the amount realized includes a unitholder's share of our liabilities, the gain recognized on the sale of common units could result in a tax liability in excess of any cash received from the sale.

Prior distributions from us that in the aggregate were in excess of the cumulative net taxable income allocated for a unit that decreased a unitholder's tax basis in that unit will, in effect, become

taxable income if the unit is sold at a price greater than the unitholder's tax basis in the unit, even if the price received is less than his original cost.

Except as noted below, gain or loss recognized by a unitholder on the sale or exchange of a unit held for more than one year will generally be taxable as long-term capital gain or loss. However, a portion of this gain or loss, which will likely be substantial, will be separately computed and taxed as ordinary income or loss under Section 751 of the Internal Revenue Code to the extent attributable to assets giving rise to depreciation recapture or other "unrealized receivables" or "inventory items" that we own. The term "unrealized receivables" includes potential recapture items, including depreciation, depletion or IDC recapture. Ordinary income attributable to unrealized receivables, inventory items and depreciation recapture may exceed net taxable gain realized on the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and a capital loss upon a sale of common units. Capital losses may offset capital gains and no more than $3,000 of ordinary income each year, in the case of individuals, and may only be used to offset capital gain in the case of corporations.

The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an "equitable apportionment" method, which generally means that the tax basis allocated to the interest sold equals an amount that bears the same relation to the partner's tax basis in his entire interest in the partnership as the value of the interest sold bears to the value of the partner's entire interest in the partnership. Treasury Regulations under Section 1223 of the Internal Revenue Code allow a selling unitholder who can identify common units transferred with an ascertainable holding period to elect to use the actual holding period of the common units transferred. Thus, according to the ruling discussed above, a unitholder will be unable to select high or low basis common units to sell as would be the case with corporate stock, but, according to the Treasury Regulations, he may designate specific common units sold for purposes of determining the holding period of common units transferred. A unitholder electing to use the actual holding period of common units transferred must consistently use that identification method for all subsequent sales or exchanges of our common units. A unitholder considering the purchase of additional common units or a sale of common units purchased in separate transactions is urged to consult his tax advisor as to the possible consequences of this ruling and application of the Treasury Regulations.

Specific provisions of the Internal Revenue Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an "appreciated" partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) into:

Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is also authorized to issue regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.

In general, our taxable income or loss will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of common units owned by each of them as of the opening of the applicable exchange on the first business day of the month (the "Allocation Date"). However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business will be allocated among the unitholders on the Allocation Date in the month in which that gain or loss is recognized. As a result, a unitholder transferring common units may be allocated income, gain, loss and deduction realized after the date of transfer.

Although there is no direct or indirect controlling authority on the issue, we intend to use our proration method because simplifying conventions are contemplated by the Internal Revenue Code and most publicly-traded partnerships use similar simplifying conventions. However, the use of this method may not be permitted under existing Treasury Regulations. Recently, the Department of the Treasury and the IRS issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly-traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders, although such tax items must be prorated on a daily basis. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. Existing publicly-traded partnerships are entitled to rely on those proposed Treasury Regulations; however, they are not binding on the IRS and are subject to change until the final Treasury Regulations are issued. Accordingly, Andrews Kurth LLP is unable to opine on the validity of this method of allocating income and deductions between transferee and transferor unitholders because the issue has not been finally resolved by the courts or the IRS. If this method is not allowed under the Treasury Regulations, or only applies to transfers of less than all of the unitholder's interest, our taxable income or losses might be reallocated among the unitholders. We are authorized to revise our method of allocation between transferee and transferor unitholders, as well as among unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations.

A unitholder who disposes of common units prior to the record date set for a cash distribution for any quarter will be allocated items of our income, gain, loss and deductions attributable to the month of sale but will not be entitled to receive that cash distribution.

A unitholder who sells any of his common units is generally required to notify us in writing of that sale within 30 days after the sale (or, if earlier, January 15 of the year following the sale). A purchaser of common units who purchases common units from another unitholder is also generally required to notify us in writing of that purchase within 30 days after the purchase. Upon receiving such notifications, we are required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. Failure to notify us of a transfer of common units may, in some cases, lead to the imposition of penalties. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the United States and who effects the sale or exchange through a broker who will satisfy such requirements.

We will be considered to have terminated our tax partnership for U.S. federal income tax purposes upon the sale or exchange of interests in us that, in the aggregate, constitute 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of measuring whether the 50% threshold has been met, multiple sales of the same unit are counted only once. A constructive termination results in the closing of our taxable year for all unitholders. 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 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 constructive termination occurring on a date

other than December 31 will result in us filing two tax returns (and unitholders could receive two Schedules K-1 if the relief discussed below is not available) for one fiscal year and the cost of the preparation of these returns will be borne by all unitholders. However, pursuant to an IRS relief procedure for publicly traded partnerships that have technically terminated, the IRS may allow, among other things, that we provide a single Schedule K-1 for the tax year in which a termination occurs. We would be required to make new tax elections after a termination, including a new election under Section 754 of the Internal Revenue Code, and a termination would result in a deferral of our deductions for depreciation. A termination could also result in penalties if we were unable to determine that the termination had occurred. Moreover, a termination might either accelerate the application of, or subject us to, any tax legislation enacted before the termination.

Because we cannot match transferors and transferees of common units and because of other reasons, we must maintain uniformity of the economic and tax characteristics of the common units to a purchaser of these common units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements, both statutory and regulatory. A lack of uniformity could result from a literal application of Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to apply to a material portion of our assets. Any non-uniformity could have a negative impact on the value of the common units. Please read "— Tax Consequences of Unit Ownership — Section 754 Election."

Our partnership agreement permits our general partner to take positions in filing our tax returns that preserve the uniformity of our common units even under circumstances like those described above. These positions may include reducing for some unitholders the depreciation, amortization or loss deductions to which they would otherwise be entitled or reporting a slower amortization of Section 743(b) adjustments for some unitholders than that to which they would otherwise be entitled. Andrews Kurth LLP is unable to opine as to validity of such filing positions as there is no direct or indirect controlling authority addressing the validity of these positions. A unitholder's basis in common units is reduced by his share of our deductions (whether or not such deductions were claimed on an individual income tax return) so that any position that we take that understates deductions will overstate the unitholder's basis in his common units, and may cause the unitholder to understate gain or overstate loss on any sale of such common units. Please read "— Disposition of Common Units — Recognition of Gain or Loss" and "— Tax Consequences of Unit Ownership — Section 754 Election." The IRS may challenge one or more of any positions we take to preserve the uniformity of common units. If such a challenge were sustained, the uniformity of common units might be affected, and, under some circumstances, the gain from the sale of common units might be increased without the benefit of additional deductions.

Ownership of common units by employee benefit plans, other tax-exempt organizations, non-resident aliens, non-U.S. corporations and other non-U.S. persons raises issues unique to those investors and, as described below, may have substantially adverse tax consequences to them. Prospective unitholders who are tax-exempt entities or non-U.S. persons should consult their tax advisor before investing in our common units.

Employee benefit plans and most other organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, are subject to federal income tax on unrelated business taxable income. Virtually all of our income allocated to a unitholder that is a tax-exempt organization will be unrelated business taxable income and will be taxable to it.

Non-resident aliens and foreign corporations, trusts or estates that own common units will be considered to be engaged in business in the United States because of the ownership of common units. As a consequence, they will be required to file federal tax returns to report their share of our income,

gain, loss or deduction and pay federal income tax at regular rates on their share of our net income or gain. Moreover, under rules applicable to publicly traded partnerships, distributions to non-U.S. unitholders are subject to withholding at the highest applicable effective tax rate. Each non-U.S. unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8BEN or applicable substitute form in order to obtain credit for these withholding taxes. A change in applicable law may require us to change these procedures.

In addition, because a foreign corporation that owns common units will be treated as engaged in a United States trade or business, that corporation may be subject to the United States branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our income and gain, as adjusted for changes in the foreign corporation's "U.S. net equity," which is effectively connected with the conduct of a United States trade or business. That tax may be reduced or eliminated by an income tax treaty between the United States and the country in which the foreign corporate unitholder is a "qualified resident." In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Internal Revenue Code.

A foreign unitholder who sells or otherwise disposes of a unit will be subject to U.S. federal income tax on gain realized from the sale or disposition of that unit to the extent the gain is effectively connected with a U.S. trade or business of the foreign unitholder. Under a ruling published by the IRS, interpreting the scope of "effectively connected income," a foreign unitholder would be considered to be engaged in a trade or business in the U.S. by virtue of the U.S. activities of the partnership, and part or all of that unitholder's gain would be effectively connected with that unitholder's indirect U.S. trade or business. Moreover, under the Foreign Investment in Real Property Tax Act, a foreign unitholder generally will be subject to U.S. federal income tax upon the sale or disposition of a unit if (i) he owned (directly or constructively applying certain attribution rules) more than 5% of our common units at any time during the five-year period ending on the date of such disposition and (ii) 50% or more of the fair market value of all of our assets consisted of U.S. real property interests at any time during the shorter of the period during which such unitholder held the common units or the 5-year period ending on the date of disposition. Currently, more than 50% of our assets consist of U.S. real property interests and we do not expect that to change in the foreseeable future. Therefore, foreign unitholders may be subject to federal income tax on gain from the sale or disposition of their common units.

We intend to furnish to each unitholder, within 90 days after the close of each taxable year, specific tax information, including a Schedule K-1, which describes his share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each unitholder's share of income, gain, loss and deduction. We cannot assure our unitholders that those positions will yield a result that conforms to the requirements of the Internal Revenue Code, Treasury Regulations or administrative interpretations of the IRS. Neither we, nor Andrews Kurth LLP can assure prospective unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the common units.

The IRS may audit our federal income tax information returns. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year's tax liability, and possibly may result in an audit of his own return. Any audit of a unitholder's return could result in adjustments not related to our returns as well as those related to our returns.

Partnerships generally are treated as separate entities for purposes of U.S. federal income tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership

proceeding rather than in separate proceedings with the partners. The Internal Revenue Code requires that one partner be designated as the "Tax Matters Partner" for these purposes. Our partnership agreement designates our general partner as our Tax Matters Partner.

The Tax Matters Partner will make some elections on our behalf and on behalf of unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review will go forward, and each unitholder with an interest in the outcome may participate in that action.

A unitholder must file a statement with the IRS identifying the treatment of any item on his federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.

Persons who hold an interest in us as a nominee for another person are required to furnish to us:

(1) the name, address and taxpayer identification number of the beneficial owner and the nominee;

(3) the amount and description of common units held, acquired or transferred for the beneficial owner; and

(4) specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from sales.

Brokers and financial institutions are required to furnish additional information, including whether they are U.S. persons and specific information on common units they acquire, hold or transfer for their own account. A penalty of $100 per failure, up to a maximum of $1,500,000 per calendar year, is imposed by the Internal Revenue Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the common units with the information furnished to us.

An additional tax equal to 20% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed by the Internal Revenue Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for the underpayment of that portion and that the taxpayer acted in good faith regarding the underpayment of that portion.

For individuals, a substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10% of the tax required to be shown on the return

for the taxable year or $5,000 ($10,000 for most corporations). The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:

(2) as to which there is a reasonable basis and the pertinent facts of that position are disclosed on the return.

If any item of income, gain, loss or deduction included in the distributive shares of unitholders might result in that kind of an "understatement" of income for which no "substantial authority" exists, we must disclose the pertinent facts on our return. In addition, we will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns and to take other actions as may be appropriate to permit unitholders to avoid liability for this penalty. More stringent rules apply to "tax shelters," which we do not believe includes us, or any of our investments, plans or arrangements.

A substantial valuation misstatement exists if (a) the value of any property, or the tax basis of any property, claimed on a tax return is 150% or more of the amount determined to be the correct amount of the valuation or tax basis, (b) the price for any property or services (or for the use of property) claimed on any such return with respect to any transaction between persons described in Internal Revenue Code Section 482 is 200% or more (or 50% or less) of the amount determined under Section 482 to be the correct amount of such price, or (c) the net Internal Revenue Code Section 482 transfer price adjustment for the taxable year exceeds the lesser of $5 million or 10% of the taxpayer's gross receipts. No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for a corporation other than an S Corporation or a personal holding company). The penalty is increased to 40% in the event of a gross valuation misstatement. We do not anticipate making any valuation misstatements.

In addition, the 20% accuracy-related penalty also applies to any portion of an underpayment of tax that is attributable to transactions lacking economic substance. To the extent that such transactions are not disclosed, the penalty imposed is increased to 40%. Additionally, there is no reasonable cause defense to the imposition of this penalty to such transactions.

If we were to engage in a "reportable transaction," we (and possibly our unitholders and others) would be required to make a detailed disclosure of the transaction to the IRS. A transaction may be a reportable transaction based upon any of several factors, including the fact that it is a type of tax avoidance transaction publicly identified by the IRS as a "listed transaction" or that it produces certain kinds of losses for partnerships, individuals, S corporations, and trusts in excess of $2 million in any single tax year, or $4 million in any combination of six successive tax years. Our participation in a reportable transaction could increase the likelihood that our federal income tax information return (and possibly our unitholders' tax return) would be audited by the IRS. Please read "— Administrative Matters — Information Returns and Audit Procedures."

Moreover, if we were to participate in a reportable transaction with a significant purpose to avoid or evade tax, or in any listed transaction, our unitholders may be subject to the following provisions of the American Jobs Creation Act of 2004:

Both President Obama's budget proposal for the Fiscal Year 2012 and the Administration's proposed American Jobs Act of 2011 recommend changes in federal income tax laws including the elimination of certain key U.S. federal income tax preferences relating to oil and natural gas exploration and development. Changes in the proposals 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 common units.

In addition, the Obama Administration is considering, and, in the last Congressional session, the U.S. House of Representatives passed, legislation that would provide for substantive changes to the definition of qualifying income and the treatment of certain types of income earned from profits interests in partnerships. It is possible that these legislative efforts could result in changes to the existing federal income tax laws that affect publicly traded partnerships. As previously proposed, we do not believe any such legislation would affect our tax treatment as a partnership. However, the proposed legislation could be modified in a way that could affect us. 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 common units.

In addition to U.S. federal income taxes, unitholders will be subject to other taxes, including state and local income taxes, unincorporated business taxes, and estate, inheritance or intangibles taxes that may be imposed by the various jurisdictions in which we conduct business or own property or in which the unitholder is a resident. We currently conduct business or own property in several states, most of which impose personal income taxes on individuals. Most of these states also impose an income tax on corporations and other entities. Moreover, we may also own property or do business in other states in the future that impose income or similar taxes on nonresident individuals. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact on his investment in us. A unitholder may be required to file state income tax returns and to pay state income taxes in any state in which we do business or own property, and such unitholder may be subject to penalties for failure to comply with those requirements. In some states, tax losses may not produce a tax benefit in the year incurred and also may not be available to offset income in subsequent taxable years. Some of the states may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the state. Withholding, the amount of which may be greater or less than a particular unitholder's income tax liability to the state, generally does not relieve a nonresident unitholder from the obligation to file an income tax return. Amounts withheld may be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. Please read "— Tax Consequences of Unit Ownership — Entity-Level Collections of Unitholder Taxes." Based on current law and our estimate of our future operations, we anticipate that any amounts required to be withheld will not be material.

It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent states and localities, of his investment in us. Andrews Kurth LLP has not rendered an opinion on the state, local, or non-U.S. tax consequences of an investment in us. We strongly recommend that each prospective unitholder consult, and depend on, his own tax counsel or other advisor with regard to those matters. It is the responsibility of each unitholder to file all tax returns that may be required of him.

An investment in us by an employee benefit plan is subject to additional considerations because the investments of these plans are subject to the fiduciary responsibility and prohibited transaction provisions of ERISA and the restrictions imposed by Section 4975 of the Internal Revenue Code and provisions under any federal, state, local, non-U.S. or other laws or regulations that are similar to such provisions of the Internal Revenue Code or ERISA (collectively, "Similar Laws"). For these purposes the term "employee benefit plan" includes, but is not limited to, qualified pension, profit-sharing and stock bonus plans, Keogh plans, simplified employee pension plans and tax deferred annuities or individual retirement accounts or annuities ("IRAs") established or maintained by an employer or employee organization, and entities whose underlying assets are considered to include "plan assets" of such plans, accounts and arrangements (collectively, "Employee Benefit Plans"). Among other things, consideration should be given to:

The person with investment discretion with respect to the assets of an Employee Benefit Plan, often called a fiduciary, should determine whether an investment in us is authorized by the appropriate governing instrument and is a proper investment for the plan.

Section 406 of ERISA and Section 4975 of the Internal Revenue Code prohibit Employee Benefit Plans, and IRAs that are not considered part of an Employee Benefit Plan, from engaging, either directly or indirectly, in specified transactions involving "plan assets" with parties that, with respect to the plan, are "parties in interest" under ERISA or "disqualified persons" under the Internal Revenue Code unless an exemption is available. A party in interest or disqualified person who engages in a non-exempt prohibited transaction may be subject to excise taxes and other penalties and liabilities under ERISA and the Internal Revenue Code. In addition, the fiduciary of the ERISA plan that engaged in such a non-exempt prohibited transaction may be subject to penalties and liabilities under ERISA and the Internal Revenue Code.

In addition to considering whether the purchase of common units is a prohibited transaction, a fiduciary should consider whether the plan will, by investing in us, be deemed to own an undivided interest in our assets, with the result that our general partner would also be a fiduciary of such plan and our operations would be subject to the regulatory restrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Internal Revenue Code, ERISA and any other applicable Similar Laws.

The Department of Labor regulations and Section 3(42) of ERISA provide guidance with respect to whether, in certain circumstances, the assets of an entity in which Employee Benefit Plans acquire equity interests would be deemed "plan assets." Under these rules, an entity's assets would not be considered to be "plan assets" if, among other things:

Our assets should not be considered "plan assets" under these regulations because it is expected that the investment will satisfy the requirements in the first two bullet points above.

In light of the serious penalties imposed on persons who engage in prohibited transactions or other violations, plan fiduciaries contemplating a purchase of common units should consult with their own counsel regarding the consequences under ERISA, the Internal Revenue Code and other Similar Laws.

Subject to the terms and conditions set forth in an underwriting agreement, we have agreed to sell to the underwriters named below, and the underwriters, for whom Wells Fargo Securities, LLC, Raymond James & Associates, Inc., Citigroup Global Markets Inc. and RBC Capital Markets, LLC are acting as joint-book running managers and representatives, have severally agreed to purchase, the respective number of common units appearing opposite their names below:

All of the common units to be purchased by the underwriters will be purchased from us.

The underwriting agreement provides that the obligations of the several underwriters are subject to various conditions, including approval of legal matters by counsel. The common units are offered by the underwriters, subject to prior sale, when, as and if issued to and accepted by them. The underwriters reserve the right to withdraw, cancel or modify the offer and to reject orders in whole or in part.

The underwriting agreement provides that the underwriters are obligated to purchase all the common units offered by this prospectus if any are purchased, other than those common units covered by the over-allotment option described below. If an underwriter defaults, the underwriting agreement provides that the purchase commitments of the non-defaulting underwriters may be increased or the underwriting agreement may be terminated.

We have granted the underwriters an option, exercisable for 30 days after the date of the underwriting agreement, to purchase up to an additional 1,411,200 common units from us at the initial public offering price less the underwriting discounts, as set forth on the cover page of this prospectus, and less any dividends or distributions declared, paid or payable on the common units that the underwriters have agreed to purchase from us but that are not payable on such additional common units, to cover over-allotments, if any. If the underwriters exercise this option in whole or in part, then the underwriters will be severally committed, subject to the conditions described in the underwriting agreement, to purchase the additional common units in proportion to their respective commitments set forth in the prior table.

To the extent the underwriters do exercise their option to purchase the additional common units, the number of common units issued to Fund I (as presented in this prospectus) will decrease by, and the number of common units issued to the public (as presented in this prospectus) 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 paid to Fund I as additional cash consideration for the Partnership Properties and as an additional cash distribution to Fund I.

The common units sold by the underwriters to the public will initially be offered at the initial public offering price set forth on the cover of this prospectus and to certain dealers at that price less a concession of not more than $0.7125 per common unit. After the initial offering, the public offering price, concession and reallowance to dealers may be changed.

The following table summarizes the underwriting discounts and the proceeds, before expenses, payable to us, both on a per unit basis and in total, assuming either no exercise or full exercise by the underwriters of their option to purchase additional common units:

We estimate that the expenses of this offering payable by us, not including underwriting discounts and a structuring fee, will be approximately $3.9 million. We will pay each of Wells Fargo Securities, LLC and Raymond James & Associates, Inc. a structuring fee equal to 0.20% and 0.05%, respectively, of the gross proceeds of this offering for the evaluation, analysis and structuring of our partnership.

The underwriting agreement provides that we will indemnify the underwriters against specified liabilities, including liabilities under the Securities Act, or contribute to payments that the underwriters may be required to make in respect of those liabilities.

We, our general partner and certain of its affiliates, the directors and executive officers of our general partner and each participant in the directed unit program who is a family member of a director or executive officer of our general partner or who purchases in excess of $100,000 of reserved units have agreed, subject to certain exceptions, that, without the prior written consent of Wells Fargo Securities, LLC and Raymond James & Associates, Inc., we and they will not, during the period beginning on and including the date of this prospectus through and including the date that is the 180th day after the date of this prospectus, directly or indirectly:

Notwithstanding the provisions set forth in the immediately preceding paragraph, we may, without the prior written consent of Wells Fargo Securities, LLC and Raymond James & Associates, Inc.:

Wells Fargo Securities, LLC and Raymond James & Associates, Inc. may, in their sole discretion and at any time or from time to time, release all or any portion of the common units or other securities subject to the lock-up agreements. Any determination to release any common units or other securities subject to the lock-up agreements would be based on a number of factors at the time of determination, which may include the market price of the common units, the liquidity of the trading market for the common units, general market conditions, the number of common units or other securities proposed to be sold or otherwise transferred and the timing, purpose and terms of the proposed sale or other transfer. Wells Fargo Securities, LLC and Raymond James & Associates, Inc. do not have any present intention, agreements or understandings, implicit or explicit, to release any of the common units or other securities subject to the lock-up agreements prior to the expiration of the lock-up period described above.

This prospectus and the registration statement of which this prospectus forms a part may be made available in electronic format on the websites maintained by one or more of the underwriters. The underwriters may agree to allocate a number of common units for sale to their online brokerage account holders. The common units will be allocated to underwriters that may make Internet distributions on the same basis as other allocations. In addition, common units may be sold by the underwriters to securities dealers who resell common units to online brokerage account holders.

Other than the information set forth in this prospectus and the registration statement of which this prospectus forms a part, information contained in any website maintained by an underwriter is not part of this prospectus or the registration statement of which this prospectus forms a part, has not been endorsed by us and should not be relied on by investors in deciding whether to purchase common units. The underwriters are not responsible for information contained in websites that they do not maintain.

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." The underwriters have undertaken to sell the minimum number of common units to the minimum number of beneficial owners necessary to meet the New York Stock Exchange distribution requirements for trading.

In order to facilitate this offering of our common units, the underwriters may engage in transactions that stabilize, maintain or otherwise affect the market price of our common units. Specifically, the underwriters may sell more common units than they are obligated to purchase under the underwriting agreement, creating a short position. A short sale is covered if the short position is no greater than the number of common units available for purchase by the underwriters under their option to purchase additional common units. The underwriters may close out a covered short sale by exercising their option to purchase additional common units or purchasing common units in the open market. In determining the source of common units to close out a covered short sale, the underwriters may consider, among other things, the market price of common units compared to the price payable under their option to purchase additional common units. The underwriters may also sell common units in excess of the number of common units available under their option to purchase additional common units, creating a naked short position. The underwriters must close out any naked short position by purchasing common units in the open market. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of the common units in the open market after the date of pricing of this offering that could adversely affect investors who purchase in this offering.

As an additional means of facilitating this offering, the underwriters may bid for, and purchase, common units in the open market to stabilize the price of our common units, so long as stabilizing bids do not exceed a specified maximum. The underwriting syndicate may also reclaim selling concessions allowed to an underwriter or a dealer for distributing common units in this offering if the underwriting syndicate repurchases previously distributed common units to cover syndicate short positions or to stabilize the price of the common units.

The foregoing transactions, if commenced, may raise or maintain the market price of our common stock above independent market levels or prevent or retard a decline in the market price of the common stock.

The foregoing transactions, if commenced, may be effected on the New York Stock Exchange or otherwise. Neither we nor any of the underwriters makes any representation that the underwriters will engage in any of these transactions and these transactions, if commenced, may be discontinued at any time without notice. Neither we nor any of the underwriters makes any representation or prediction as to the direction or magnitude of the effect that the transactions described above, if commenced, may have on the market price of our common stock.

The underwriters have informed us that they do not intend to confirm sales to accounts over which they exercise discretionary authority in excess of 5% of the total number of common units offered by them.

Prior to this offering, there has been no public market for our common units. Consequently, the initial public offering price for our common units will be determined between us and the representatives of the underwriters. The factors that may be considered in determining the initial public offering price include:

An active trading market for our common units may not develop. It is possible that the market price of our common units after this offering will be less than the initial public offering price.

At our request, the underwriters have reserved up to 5% of the common units being offered by this prospectus (excluding the common units that may be issued upon the underwriters' exercise of their option to purchase additional common units) 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. The sales will be made by Wells Fargo Securities, LLC through a directed unit program. The number of units available for sale to the general public will be reduced to the extent that these individuals purchase all or a portion of the reserved units. Any reserved units not so purchased will be offered by the underwriters to the general public on the same basis as the other units offered by this prospectus. We have agreed to indemnify Wells Fargo Securities, LLC and the underwriters in connection with the directed unit program, including for the failure of any participant to pay for its common units.

Certain of the underwriters and their affiliates have provided, and may in the future provide, various investment banking, commercial banking, financial advisory and other financial services to us and our affiliates for which they have received, and may in the future receive, customary fees. Additionally, certain of the underwriters and their affiliates have engaged, and may from time to time in the future engage, in transactions with us in the ordinary course of their business. An affiliate of Wells Fargo Securities, LLC is the administrative agent and a lender under LRR A's credit facility and will receive a portion of the net proceeds from this offering in connection with the repayment of the LRR A credit facility. For a description of LRR A's existing credit facility, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations — Predecessor Liquidity and Capital Resources — Predecessor Credit Facility." Additionally, affiliates of Wells Fargo Securities, LLC, Citigroup Global Markets Inc. and RBC Capital Markets, LLC will be lenders under our new credit facility.

This offering is being made in compliance with Rule 2310 of the Financial Industry Regulatory Authority, Inc., or FINRA, Rules. Investor suitability with respect to the common units should be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.

No action has been taken in any jurisdiction (except in the United States) that would permit a public offering of the securities, or the possession, circulation or distribution of this prospectus or any other material relating to us or the securities in any jurisdiction where action for that purpose is required. Accordingly, the securities may not be offered or sold, directly or indirectly, and none of this prospectus or any other offering material or advertisements in connection with the securities may be distributed or published, in or from any country or jurisdiction except in compliance with any applicable rules and regulations of any such country or jurisdiction.

Each of the underwriters may arrange to sell securities offered hereby in certain jurisdictions outside the United States, either directly or through affiliates, where they are permitted to do so. In that regard, Wells Fargo Securities, LLC may arrange to sell securities in certain jurisdictions through an affiliate, Wells Fargo Securities International Limited, or WFSIL. WFSIL is a wholly-owned indirect subsidiary of Wells Fargo & Company and an affiliate of Wells Fargo Securities, LLC. WFSIL is a U.K. incorporated investment firm regulated by the Financial Services Authority. Wells Fargo Securities is the trade name for certain corporate and investment banking services of Wells Fargo & Company and its affiliates, including Wells Fargo Securities, LLC and WFSIL.

The validity of our common units will be passed upon for us by Andrews Kurth LLP, Houston, Texas. Certain legal matters in connection with our common units offered hereby will be passed upon for the underwriters by Latham & Watkins LLP, Houston, Texas.

The balance sheet of LRR Energy, L.P. as of June 30, 2011 has been so included in reliance on the report of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.

The combined financial statements of Fund I (predecessor) as of December 31, 2010 and December 31, 2009 and for each of the three years in the period ended December 31, 2010 have been so included in reliance on the report of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.

Estimated quantities of our proved oil and natural gas reserves and the net present value of such reserves as of December 31, 2010 and March 31, 2011 set forth in this prospectus are based upon reserve reports prepared by each of Miller and Lents, Ltd. and Netherland, Sewell & Associates, Inc.

We have filed with the SEC a registration statement on Form S-l regarding our common units. This prospectus, which constitutes part of the registration statement, does not contain all of the information set forth in the registration statement. For further information regarding us and our common units offered in this prospectus, we refer you to the full registration statement, including its exhibits and schedules, filed under the Securities Act. The full registration statement, of which this prospectus forms a part, including its exhibits and schedules, may be inspected and copied at the public reference room maintained by the SEC at 100 F Street, NE, Room 1580, Washington, D.C. 20549. Copies of these materials may also be obtained from the SEC at prescribed rates by writing to the public reference room maintained by the SEC at 100 F Street, NE, Room 1580, Washington, D.C. 20549. The registration statement, of which this prospectus forms a part, can also be downloaded from the SEC's web site on the Internet at http://www.sec.gov. You may obtain information on the operation of the public reference room by calling the SEC at 1-800-SEC-0330.

We intend to furnish or make available to our unitholders annual reports containing our audited financial statements and furnish or make available quarterly reports containing our unaudited interim financial information, including the information required by Form 10-Q, for the first three fiscal quarters of each of our fiscal years. Additionally, we intend to file periodic reports with the SEC, as required by the Securities Exchange Act of 1934.

This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control, which may include statements about our:

These types of statements, other than statements of historical fact included in this prospectus, are forward-looking statements. These forward-looking statements may be found in "Prospectus Summary," "Risk Factors," "Our Cash Distribution Policy and Restrictions on Distributions," "Management's Discussion and Analysis of Financial Condition and Results of Operations," "Business and Properties" and other sections of this prospectus. In some cases, you can identify forward-looking statements by terminology such as "may," "could," "should," "expect," "plan," "project," "intend," "anticipate," "believe," "estimate," "predict," "potential," "pursue," "target," "continue," the negative of such terms or other comparable terminology.

The forward-looking statements contained in this prospectus are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management's assumptions about future events may prove to be inaccurate. All readers are cautioned that the forward-looking statements contained in this prospectus are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or that the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to factors described in "Risk Factors" and elsewhere in this prospectus. All forward-looking statements speak only as of the date of this prospectus. We do not intend to update or revise any forward-looking statements as a result of new information, future events or otherwise. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

The following unaudited pro forma condensed financial statements of LRR Energy, L.P. ("LRR Energy") reflect the audited historical combined results of Lime Rock Resources A, L.P., Lime Rock Resources B, L.P. and Lime Rock Resources C, L.P. (collectively "predecessor") on a pro forma basis to give effect to the "Contribution" and the "Offering" described below.

The Contribution. Effective upon the closing of the initial public offering of common units of LRR Energy, the predecessor will sell and contribute selected oil and natural gas properties and related net profits interests and operations to LRR Energy in exchange for newly issued common units and subordinated units representing limited partner interests in LRR Energy and cash consideration (the "Contribution").

The Offering. For purposes of the unaudited pro forma condensed financial statements, the "Offering" is defined as the issuance and sale to the public of 9,408,000 common units of LRR Energy, the borrowing of $155.8 million under a new revolving credit facility and the application by LRR Energy of the net proceeds from such issuance and borrowing as described in "Use of Proceeds."

The unaudited pro forma condensed balance sheet of LRR Energy is based on the unaudited historical combined balance sheet of the predecessor and includes pro forma adjustments to give effect to the Contribution and the Offering as if they occurred on June 30, 2011.

The unaudited pro forma condensed statement of operations of LRR Energy is based on the unaudited historical combined statements of operations of the predecessor for the six months ended June 30, 2011 and 2010 and the audited historical combined statement of operations of the predecessor for the year ended December 31, 2010 and includes pro forma adjustments to give effect to the Contribution and the Offering as if they occurred on January 1, 2010.

The unaudited pro forma condensed financial statements have been prepared on the basis that LRR Energy will be treated as a partnership for federal income tax purposes. The unaudited pro forma condensed financial statements should be read in conjunction with the notes accompanying these unaudited pro forma condensed financial statements and with the audited historical combined financial statements and related notes of the predecessor, found elsewhere in this prospectus.

The pro forma adjustments to the audited historical financial statements are based upon currently available information and certain estimates and assumptions. The actual effect of the transactions discussed in the accompanying notes ultimately may differ from the unaudited pro forma adjustments included herein. However, management believes that the assumptions utilized to prepare the pro forma adjustments provide a reasonable basis for presenting the significant effects of the transactions as currently contemplated and that the unaudited pro forma adjustments are factually supportable, give appropriate effect to the expected impact of events that are directly attributable to the transactions, and reflect those items expected to have a continuing impact on LRR Energy.

The unaudited pro forma condensed financial statements of LRR Energy are not necessarily indicative of the results that actually would have occurred if LRR Energy had completed the Contribution and the Offering on the dates indicated or that could be achieved in the future.

			Predecessor Historical			Predecessor Retained Operations(a)			LRR Energy Pro Forma			Offering Adjustments			LRR Energy Pro Forma, As Adjusted

			(in thousands)
ASSETS
Current assets:
	Cash and cash equivalents		$	6,033		$	(6,033	)	$	—		$	155,800	(f)	$	—
													178,752	(g)
													(289,882	)(h)
													(27,251	)(h)
													(17,419	)(i)
	Accounts receivable:
		Oil and natural gas sales		14,245			(14,245	)		—			—			—
		Trade and other		1,408			(1,408	)		—			—			—
	Commodity derivative instruments			15,001			(4,350	)		10,651	(b)		—			10,651
	Amounts due from affiliates			1,341			(1,341	)		—			—			—
	Prepaid expenses			3,973			(3,973	)		—			—			—

		Total current assets		42,001			(31,350	)		10,651			—			10,651
Property and equipment
	Oil and gas properties (successful efforts method)			802,477			(158,472	)		644,005	(c)		—			644,005
	Unproved properties			1,878			(465	)		1,413	(c)		—			1,413
	Other property and equipment			758			(114	)		644	(c)		—			644

				805,113			(159,051	)		646,062			—			646,062
	Accumulated depletion, depreciation and impairment			(363,271	)		97,502			(265,769)	(c)		—			(265,769	)

		Total property and equipment, net		441,842			(61,549	)		380,293			—			380,293
Commodity derivative instruments				8,838			(2,563	)		6,275	(b)		—			6,275
Deferred financing costs, net of accumulated amortization				272			(272	)		—			1,900	(i)		1,900

TOTAL ASSETS			$	492,953		$	(95,734	)	$	397,219		$	1,900		$	399,119

LIABILITIES AND PARTNERS' CAPITAL
Current liabilities:
	Trade accounts payable		$	1,083		$	(1,083	)	$	—		$	—		$	—
	Accrued liabilities			8,845			(8,845	)		—			—			—
	Accrued capital cost			3,802			(3,802	)		—			—			—
	Commodity derivative instruments			1,270			(368	)		902	(b)		—			902
	Interest rate derivative instruments			544			(544	)		—			—			—
	Asset retirement obligations			792			(86	)		706	(d)		—			706

		Total current liabilities		16,336			(14,728	)		1,608			—			1,608
Long-term liabilities
	Commodity derivative instruments			1,313			(381	)		932	(b)		—			932
	Interest rate derivative instruments			154			(154	)		—			—			—
	Revolving credit facility			27,251			—			27,251	(e)		155,800	(f)		155,800
													(27,251)	(h)
	Asset retirement obligations			24,248			(2,436	)		21,812	(d)		—			21,812
	Deferred tax liabilities			146			(146	)		—			—			—

		Total long-term liabilities		53,112			(3,117	)		49,995			128,549			178,544

		Total liabilities		69,448			(17,845	)		51,603			128,549			180,152
Partners' capital				423,505			(77,889	)		372,867	(e)		178,752	(g)		218,967
										(27,251	)(e)		(289,882	)(h)
													(15,519	)(i)

		Total partners' capital		423,505			(77,889	)		345,616			(126,649	)		218,967

TOTAL LIABILITIES AND PARTNERS' CAPITAL			$	492,953		$	(95,734	)	$	397,219		$	1,900		$	399,119

LRR Energy, L.P.
Pro Forma Condensed Statement of Operations
For the six months ended June 30, 2011
(Unaudited)

			Predecessor Historical			Predecessor Retained Operations(a)			LRR Energy Pro Forma			Offering and Other Adjustments			LRR Energy Pro Forma, As Adjusted

			(in thousands)
Revenues:
	Oil sales		$	34,661		$	(14,490	)	$	20,171	(j)	$	—		$	20,171
	Natural gas sales			21,754			(2,302	)		19,452	(j)		—			19,452
	Natural gas liquids sales			7,758			(2,030	)		5,728	(j)		—			5,728
	Realized gain on commodity derivative instruments			41			(12	)		29	(k)		—			29
	Unrealized loss on commodity derivative instruments			(3,109	)		902			(2,207)	(k)		—			(2,207	)
	Other income			80			—			80			—			80

		Total revenues		61,185			(17,932	)		43,253			—			43,253
Operating Expenses:
	Lease operating expenses			11,935			(2,634	)		9,301	(j)		—			9,301
	Production and ad valorem taxes			3,020			(1,388	)		1,632	(j)		—			1,632
	Depletion and depreciation			20,871			(5,474	)		15,397	(l)		—			15,397
	Accretion expense			744			(78	)		666	(l)		—			666
	Management fees			2,967			(2,967	)		—			—			—
	General and administrative expenses			3,206			(481	)		2,725	(m)		2,048	(n)		4,773

		Total operating expenses		42,743			(13,022	)		29,721			2,048			31,769
Operating income				18,442			(4,910	)		13,532			(2,048	)		11,484

Other income (expense), net
	Interest income			1			(1	)		—			—			—
	Interest expense			(559	)		559			—			(2,412)	(o)		(2,412	)
	Realized loss on interest rate derivative instruments			(298	)		298			—			—			—
	Unrealized gain on interest rate derivative instruments			163			(163	)		—			—			—

		Other income (expense), net		(693	)		693			—			(2,412	)		(2,412	)

Income before taxes				17,749			(4,217	)		13,532			(4,460	)		9,072
Income tax expense				(146	)		146			—			—			—

Net Income			$	17,603		$	(4,071	)	$	13,532		$	(4,460	)	$	9,072

Computation of net income per limited partner unit:
General partner's interest in net income															$	9

Limited partners' interest in net income															$	9,063

Net income per limited partner unit															$	0.40

Weighted average number of limited partner units outstanding																22,378

LRR Energy, L.P.
Pro Forma Condensed Statement of Operations
For the six months ended June 30, 2010
(Unaudited)

			Predecessor Historical			Predecessor Retained Operations(a)			LRR Energy Pro Forma			Offering and Other Adjustments			LRR Energy Pro Forma, As Adjusted

			(in thousands)
Revenues:
	Oil sales		$	25,969		$	(10,875	)	$	15,094	(j)	$	—		$	15,094
	Natural gas sales			25,186			(3,039	)		22,147	(j)		—			22,147
	Natural gas liquids sales			7,431			(2,195	)		5,236	(j)		—			5,236
	Realized gain on commodity derivative instruments			23,264			(6,281	)		16,983	(k)		—			16,983
	Unrealized gain on commodity derivative instruments			2,040			(551	)		1,489	(k)		—			1,489
	Other income			46			—			46			—			46

		Total revenues		83,936			(22,941	)		60,995			—			60,995
Operating Expenses:
	Lease operating expenses			10,443			(1,845	)		8,598	(j)		—			8,598
	Production and ad valorem taxes			5,067			(1,116	)		3,951	(j)		—			3,951
	Depletion and depreciation			29,584			(9,251	)		20,333	(l)		—			20,333
	Impairment of oil and natural gas properties			10,944			—			10,944						10,944
	Accretion expense			669			(80	)		589	(l)		—			589
	Management fees			3,803			(3,803	)		—			—			—
	General and administrative expenses			3,672			(176	)		3,496	(m)		2,002	(n)		5,498

		Total operating expenses		64,182			(16,271	)		47,911			2,002			49,913
Operating income				19,754			(6,670	)		13,084			(2,002	)		11,082

Other income (expense), net
	Interest income			5			(5	)		—			—			—
	Interest expense			(728	)		728			—			(2,412)	(o)		(2,412	)
	Realized loss on interest rate derivative instruments			(324	)		324			—			—			—
	Unrealized gain on interest rate derivative instruments			(332	)		332			—			—			—

		Other income (expense), net		(1,379	)		1,379			—			(2,412	)		(2,412	)

Income before taxes				18,375			(5,291	)		13,084			(4,414	)		8,670
Income tax expense				59			(59	)		—			—			—

Net Income			$	18,434		$	(5,350	)	$	13,084		$	(4,414	)	$	8,670

LRR Energy, L.P.
Pro Forma Condensed Statement of Operations
For the year ended December 31, 2010
(Unaudited)

				Predecessor Historical			Predecessor Retained Operations(a)			LRR Energy Pro Forma			Offering and Other Adjustments			LRR Energy Pro Forma, As Adjusted

				(in thousands)
Revenues:
	Oil sales			$	52,670		$	(20,820	)	$	31,850	(j)	$	—		$	31,850
	Natural gas sales				48,088			(5,366	)		42,722	(j)		—			42,722
	Natural gas liquids sales				14,748			(3,813	)		10,935	(j)		—			10,935
	Realized gain on commodity derivative instruments				48,029			(12,488	)		35,541	(k)		—			35,541
	Unrealized loss on commodity derivative instruments				(23,964	)		6,231			(17,733	)(k)		—			(17,733	)
	Other income				116			—			116			—			116

		Total revenues			139,687			(36,256	)		103,431			—			103,431
Operating expenses:
	Lease operating expenses				23,804			(4,724	)		19,080	(j)		—			19,080
	Production and ad valorem taxes				9,320			(1,565	)		7,755	(j)		—			7,755
	Depletion and depreciation				55,828			(15,155	)		40,673	(l)		—			40,673
	Impairment of oil and gas properties				11,712			—			11,712	(l)		—			11,712
	Accretion expense				1,366			(188	)		1,178	(l)		—			1,178
	(Gain) on settlement of asset retirement obligations				(209	)		(33	)		(242	)(l)		—			(242	)
	Management fees				6,104			(6,104	)		—			—			—
	General and administrative expenses				5,293			(1,158	)		4,135	(m)		4,766	(n)		8,901

		Total operating expenses			113,218			(28,927	)		84,291			4,766			89,057
Operating income					26,469			(7,329	)		19,140			(4,766	)		14,374

Other income (expense), net
	Interest income				17			(17	)		—			—			—
	Interest expense				(3,223	)		3,223			—			(4,824	)(o)		(4,824	)
	Realized (loss) on interest rate derivative instruments				(649	)		649			—			—			—
	Unrealized (loss) on interest rate derivative instruments				(248	)		248			—			—			—

			Other income (expense), net		(4,103	)		4,103			—			(4,824	)		(4,824	)

Income (loss) before taxes					22,366			(3,226	)		19,140			(9,590	)		9,550
Income tax benefit (expense)					(32	)		32			—			—			—

Net income (loss)				$	22,334		$	(3,194	)	$	19,140		$	(9,590	)	$	9,550

Computation of net income per limited partner unit:
General partner's interest in net income																$	10

Limited partners' interest in net income																$	9,540

Net income per limited partner unit																$	0.43

Weighted average number of limited partner units outstanding																	22,378

The unaudited pro forma condensed balance sheet of LRR Energy, L.P. ("LRR Energy") as of June 30, 2011 is based on the unaudited historical combined balance sheet of Lime Rock Resources A, L.P., Lime Rock Resources B, L.P., and Lime Rock Resources C, L.P. (collectively, the "predecessor") and includes pro forma adjustments to give effect to the Contribution and the Offering as described below as if they occurred on June 30, 2011.

The unaudited pro forma condensed statement of operations of LRR Energy is based on the unaudited historical combined statement of operations of the predecessor for the six months ended June 30, 2011 and 2010 and the audited historical combined statement of operations of the predecessor for the twelve months ended December 31, 2010 and includes pro forma adjustments to give effect to the Contribution and the Offering as described below as if they occurred on January 1, 2010.

The unaudited pro forma condensed financial statements give effect to the Contribution as follows:

Because the Partnership Properties are owned by the predecessor and an affiliate of the predecessor will control both the predecessor and LRR Energy, the sale and contribution of the Partnership Properties to LRR Energy has been accounted for as a combination of entities under common control, whereby the assets and liabilities sold and contributed will be recorded based on the predecessor's historical cost.

The unaudited pro forma condensed financial statements give effect to the Offering as follows:

(a) Adjustments to reflect the assets, liabilities, revenues and expenses that will be retained by the predecessor, and thus will not be sold or contributed to LRR Energy. With the exception of the fair value of commodity derivative contracts and the realized and unrealized gains (losses) on commodity derivative contracts, the adjustment was based on the carrying value of specific assets and liabilities and the specific direct operating revenues and expenses attributable to the Partnership Properties. General

LRR ENERGY, L.P.
NOTES TO UNAUDITED PRO FORMA CONDENSED FINANCIAL STATEMENTS (Continued)

and administrative expenses are allocated based on the proportion of oil and natural gas revenues attributable to the Partnership Properties and the oil and natural gas assets that will be retained by the predecessor. The adjustment to the fair value of commodity derivative contracts and to the unrealized and realized gains (losses) on commodity derivative contracts was based on a percentage of the revenues attributable to the properties contributed to LRR Energy for the period presented. This method of allocation was chosen because the ultimate goal of our hedging program is to reduce the impact of commodity price fluctuations on our revenues and corresponding cash flows.

(b) Pro forma adjustment to allocate the fair value of commodity derivative instruments contributed to LRR Energy by the predecessor at the closing of the Offering. The allocation was based on a percentage of the revenues attributable to the properties contributed to LRR Energy for the period presented. This method of allocation was chosen because the ultimate goal of our hedging program is to reduce the impact of commodity price fluctuations on our revenues and corresponding cash flows.

(c) Pro forma adjustments to reflect the Partnership Properties to be sold and contributed to LRR Energy by the predecessor. The net book value of these Partnership Properties utilizes the successful efforts method of accounting (for a further discussion see Note 2 of the predecessor's "Notes to Combined Financial Statements — Summary of Significant Accounting Policies — Oil and Natural Gas Properties") and have been allocated between LRR Energy and the predecessor based on the historical costs of the Partnership Properties.

(d) Pro forma adjustment to reflect the asset retirement obligations ("AROs") associated with the Partnership Properties to be sold and contributed to LRR Energy by the predecessor.

(e) Pro forma adjustment to reflect the issuance by LRR Energy of 6,249,600 common units, 6,720,000 subordinated units, and cash to the predecessor as consideration for the sale and contribution of the Partnership Properties and assumption by LRR Energy of $27.3 million in debt of the predecessor.

(f) Pro forma adjustment to reflect the cash proceeds related to borrowings by LRR Energy of $155.8 million under a new revolving credit facility. Pro forma adjustment reflects contribution of the predecessor's debt that is secured by the Partnership Properties. To the extent of such debt assumed, LRR Energy will retain an amount of net proceeds from the Offering that would otherwise be paid to the predecessor equal to the amount of such assumed debt and use the net proceeds retained by LRR Energy to repay in full any such assumed debt at the closing of the Offering.

(g) Pro forma adjustment to reflect gross cash proceeds of approximately $178.8 million from the issuance and sale of 9,408,000 common units by LRR Energy at an assumed initial public offering price of $19.00 per unit.

(h) Pro forma adjustment to record the use of the net proceeds from the Offering, after deducting an amount to repay $27.3 million in debt assumed per adjustment (e) and to make a $289.9 million cash distribution to the predecessor. For further discussion on the application of the net proceeds from the Offering, please read "Use of Proceeds."

(i) Pro forma adjustment to reflect estimated deferred financing costs of $1.9 million related to establishment of the new revolving credit facility, underwriting discounts of $11.2 million, a structuring fee of $0.4 million and estimated offering expenses of $3.9 million.

LRR ENERGY, L.P.
NOTES TO UNAUDITED PRO FORMA CONDENSED FINANCIAL STATEMENTS (Continued)

(j) Pro forma adjustment to reflect the revenues and direct operating expenses associated with the Partnership Properties. These adjustments are based on the actual results of the Partnership Properties. Historical lease operating statements by individual asset were used as the basis for the revenues and direct operating expense.

(k) Pro forma adjustment to allocate the historical realized and unrealized gain (loss) on derivative instruments contributed to LRR Energy by the predecessor at the closing of the Offering. The allocation was based on a percentage of the revenues attributable to the properties contributed to LRR Energy for the period presented. This method of allocation was chosen because the ultimate goal of our hedging program is to reduce the impact of commodity price fluctuations on our revenues and corresponding cash flows.

(l) Pro forma adjustment to reflect the depletion and depreciation, impairment of oil and natural gas properties, accretion expense, and gain (loss) on settlement of asset retirement obligations associated with the Partnership Properties. The calculations based on the allocated costs of the Partnership Properties and the associated production and reserves as if the Contribution had occurred on January 1, 2010.

(m) Pro forma adjustment to allocate general and administrative expenses related to the Partnership Properties. The adjustment is based on the predecessor's historical general and administrative expense, allocated based on a percentage of the relative fair value of the respective Partnership Properties and the oil and natural gas interests that will be retained by the predecessor.

(n) Pro forma adjustment to reflect estimated general and administrative expenses LRR Energy would have incurred if the Contribution had occurred on January 1, 2010.

(o) Pro forma adjustment to reflect interest expense and the amortization of deferred financing costs on $155.8 million of borrowings by LRR Energy under a new credit facility at LIBOR plus 2.25%, or 2.55%. A one-eighth percentage point change in the interest rate would change pro forma interest expense by $0.2 million for the year ended December 31, 2010. A one-eighth percentage point change in the interest rate would change pro forma interest expense by less than $0.1 million for each of the six months ended June 30, 2011 and 2010.

Pro forma net income per limited partner unit is determined by dividing the pro forma net income available to the holders of common units, after deducting the general partner's 0.1% interest in pro forma net income, by the number of common units and subordinated units expected to be outstanding at the closing of the Offering. For purposes of this calculation, management assumed the aggregate number of common units was 15,657,600 and subordinated units was 6,720,000. All units were assumed to have been outstanding since January 1, 2010. Basic and diluted pro forma net income per unit are equivalent because there will be no dilutive units at the date of the closing of the Offering.

LRR ENERGY, L.P.
NOTES TO UNAUDITED PRO FORMA CONDENSED FINANCIAL STATEMENTS (Continued)

Note 4 — Pro Forma Standardized Measure of Discounted Future Net Cash Flows

The following information summarizes the net estimated proved reserves of oil (including condensate and natural gas liquids (NGLs)) and natural gas and the present values thereof as of December 31, 2010 for the Partnership Properties. The following historical reserve information is based upon reports of the independent reserve engineering firms of Miller and Lents, Ltd. and Netherland, Sewell & Associates, Inc. The estimates are prepared in accordance with SEC regulations.

Management believes that (i) the reserve estimates presented herein are prepared in accordance with the standards set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information promulgated by the Society of Petroleum Engineers, (ii) the standards are consistently applied and (iii) the estimates are reasonable. However, there are numerous uncertainties inherent in estimating quantities and values of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond LRR Energy's control. Reserve engineering is a subjective process of estimating the recovery from underground accumulations of oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Because all reserve estimates are to some degree speculative, the quantities of oil and natural gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and natural gas sales prices may all differ from those assumed in these estimates. In addition, different reserve engineers may make different estimates of reserve quantities and cash flows based upon the same available data. Therefore, the standardized measure shown below represents estimates only and should not be construed as the current market value of the estimated oil and natural gas reserves attributable to the Partnership Properties.

Decreases in the prices of oil and natural gas have had, and could have in the future, an adverse effect on the carrying value of LRR Energy's estimated proved reserves and revenues, profitability and cash flow. As of December 31, 2010, based on evaluations prepared by Miller and Lents, Ltd. and Netherland, Sewell & Associates, Inc., LRR Energy's independent reserve engineers, the estimated proved reserves for the properties to be contributed to LRR Energy at the closing of the Offering were approximately 4,312 MBbls of oil, 102,774 MMcf of natural gas and 2,498 MBbls of NGLs, or 23,939 MBoe on a net equivalent basis.

LRR ENERGY, L.P.
NOTES TO UNAUDITED PRO FORMA CONDENSED FINANCIAL STATEMENTS (Continued)

The table below reflects the pro forma standardized measure of discounted future net cash flows related to LRR Energy's interest in proved reserves as of December 31, 2010:

The principal changes in the pro forma standardized measure of discounted future net cash flows attributable to LRR Energy's proved reserves as of December 31, 2010 are as follows:

	December 31, 2010

	(in thousands)
Beginning of period	$	157,694
Purchase of reserves in place		76,007
Sales of reserves in place		(535	)
Extensions and discoveries, net of future development costs		24,722
Revisions of quantity estimates		18,576
Changes in future development costs, net		(5,265	)
Development costs incurred that reduced future development costs		3,851
Net changes in prices		58,612
Oil, natural gas and NGL sales, net of production costs		(58,672	)
Changes in timing and other		(5,258	)
Accretion of discount		15,769

End of period	$	285,501

LRR ENERGY, L.P.
NOTES TO UNAUDITED PRO FORMA CONDENSED FINANCIAL STATEMENTS (Continued)

The standardized measure of future net cash flows relating to estimated proved oil and natural gas reserves is present below:

The standardized measure of discounted future net cash flows (discounted at 10%) from production of proved reserves was developed as follows:

In our opinion, the accompanying balance sheet presents fairly, in all material respects, the financial position of LRR Energy, L.P. (the "Company") at June 30, 2011 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on this financial statement based on our audit. We conducted our audit of this statement in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the balance sheet is free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the balance sheet, assessing the accounting principles used and significant estimates made by management, and evaluating the overall balance sheet presentation. We believe that our audit provides a reasonable basis for our opinion.

LRR Energy, L.P. (the "Partnership") is a Delaware limited partnership formed on April 28, 2011 to acquire selected oil and natural gas properties and related net profits interests and operations of Lime Rock Resources A, L.P., Lime Rock Resources B, L.P. and Lime Rock Resources C, L.P. (collectively, the "predecessor"). The Partnership intends to operate the acquired assets through a wholly owned limited liability company. In connection with its formation, the Partnership will issue (a) a 0.1% general partner interest to LRE GP, LLC, its general partner and (b) a 99.9% limited partner interest to Lime Rock Management L.P., its organizational limited partner.

LRE GP, LLC, as general partner, has committed to contribute $1 and Lime Rock Management L.P., as the organizational limited partner, has committed to contribute $999 to the Partnership as of June 30, 2011. The accompanying balance sheet reflects the financial position of the Partnership immediately subsequent to this initial capitalization. Subsequent to June 30, 2011, LRE GP, LLC and Lime Rock Management L.P. each funded their commitments to the Partnership.

				As of June 30, 2011			As of December 31, 2010

				(in thousands)
ASSETS
Current assets:
	Cash and cash equivalents			$	6,033		$	12,455
	Accounts receivable:
		Oil and natural gas sales			14,245			14,012
		Trade and other			1,408			2,531
	Commodity derivative instruments				15,001			23,819
	Amounts due from affiliates				1,341			59
	Prepaid expenses				3,973			1,722

		Total current assets			42,001			54,598
Property and equipment:
	Oil and natural gas properties (successful efforts method)				802,477			781,495
	Unproved properties				1,878			2,133
	Other property and equipment				758			718

					805,113			784,346
	Accumulated depletion, depreciation and impairment				(363,271	)		(342,400	)

		Total property and equipment, net			441,842			441,946
Commodity derivative instruments					8,838			7,767
Deferred financing costs, net of accumulated amortization					272			311

		TOTAL ASSETS		$	492,953		$	504,622

LIABILITIES AND PARTNERS' CAPITAL
Current liabilities:
	Trade accounts payable			$	1,083		$	3,354
	Accrued liabilities				8,845			8,141
	Accrued capital cost				3,802			6,620
	Commodity derivative instruments				1,270			1,888
	Interest rate derivative instruments				544			594
	Asset retirement obligations				792			792

			Total current liabilities		16,336			21,389
Long-term liabilities
	Commodity derivative instruments				1,313			5,333
	Interest rate derivative instruments				154			267
	Revolving credit facility				27,251			27,251
	Asset retirement obligations				24,248			23,504
	Deferred tax liabilities				146			145

		Total long-term liabilities			53,112			56,500

		Total liabilities			69,448			77,889
Partners' capital:					423,505			426,733

		TOTAL LIABILITIES AND PARTNERS' CAPITAL		$	492,953		$	504,622

			For the six months ended June 30,

			2011			2010
			(in thousands)
Revenues:
	Oil sales		$	34,661		$	25,969
	Natural gas sales			21,754			25,186
	Natural gas liquids sales			7,758			7,431
	Realized gain on commodity derivative instruments			41			23,264
	Unrealized gain (loss) on commodity derivative instruments			(3,109	)		2,040
	Other income			80			46

		Total revenues		61,185			83,936
Operating Expenses:
	Lease operating expenses			11,935			10,443
	Production and ad valorem taxes			3,020			5,067
	Depletion and depreciation			20,871			29,584
	Impairment of oil and natural gas properties			—			10,944
	Accretion expense			744			669
	Management fees			2,967			3,803
	General and administrative expenses			3,206			3,672

		Total operating expenses		42,743			64,182
Operating income				18,442			19,754
Other income (expense), net
	Interest income			1			5
	Interest expense			(559	)		(728	)
	Realized loss on interest rate derivative instruments			(298	)		(324	)
	Unrealized gain (loss) on interest rate derivative instruments			163			(332	)

		Other income (expense), net		(693	)		(1,379	)

Income before taxes				17,749			18,375
Income tax benefit (expense)				(146	)		59

Net income			$	17,603		$	18,434

Fund 1 (Predecessor)
Combined Condensed Statements of Changes in Partners' Capital
(Unaudited)

					For the six months ended June 30,

					2011			2010
					(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES
	Net income				$	17,603		$	18,434
		Adjustments to reconcile net income to net cash provided by operating activities:
			Depletion and depreciation			20,871			29,584
			Impairment of oil and natural gas properties			—			10,944
			Unrealized loss (gain) on derivative instruments, net			2,946			(1,708	)
			Accretion expense			744			669
			Amortization of deferred financing costs and other			40			58
	Operating Expenses:
			Change in oil and natural gas sales			(233	)		(4,464	)
			Change in trade and other			1,123			618
			Change in prepaid expenses			(2,251	)		3,242
			Change in trade accounts payable			(2,271	)		(2,324	)
			Change in amounts due from affiliates			(1,282	)		2,247
			Change in accrued liabilities			704			887

				Net cash provided by operating activities		37,994			58,187
CASH FLOWS FROM INVESTING ACTIVITIES
	Acquisition of oil and natural gas properties					(354	)		(96,584	)
	Development of oil and natural gas properties					(26,158	)		(15,270	)
	Disposition of oil and gas properties					2,967			—
	Expenditures for other property and equipment					(40	)		(34	)

				Net cash used in investing activities		(23,585	)		(111,888	)
CASH FLOWS FROM FINANCING ACTIVITIES
	Deferred financing costs					—			(23	)
	Borrowings under revolving credit facility					—			4,650
	Capital contributions					3,551			117,201
	Capital contributions returned					—			(9,318	)
	Distributions					(24,382	)		(49,532	)

				Net cash provided by (used in) financing activities		(20,831	)		62,978
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS						(6,422	)		9,277
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD						12,455			15,527

CASH AND CASH EQUIVALENTS, END OF PERIOD					$	6,033		$	24,804

Supplemental disclosure of cash flow information:
	Cash paid for interest during the period				$	402		$	485
Supplemental disclosure of non-cash items to reconcile:
	Investing and financing activities
	Property and equipment:
		Change in accrued capital costs				2,818			743
		Asset retirement obligations				—			(1,927	)

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") (LRR A, LRR B, and LRR C collectively "Fund I" or "predecessor") were formed by Lime Rock Management L.P. ("Lime Rock Management") pursuant to the laws of the State of Delaware on July 14, 2005 for the purpose of acquiring mature, low-risk producing oil and natural gas properties with long-lived production profiles. Fund I's underlying properties consist of working interests in certain oil and natural gas properties owned by LRR A located in New Mexico, Oklahoma and Texas and related net profits interests in these same oil and natural gas properties owned by LRR B and LRR C. Fund I is managed by Lime Rock Management and pays a management fee to Lime Rock Management. In addition, Fund I also receives administrative services from Lime Rock Resources Operating Company, Inc. Under their respective partnership agreements, LRR A, LRR B and LRR C have a 10-year term expiring on July 13, 2015, which can be extended by the general partner with the consent of the Advisory Committee for two successive periods of one year each.

In connection with the closing of the initial public offering of common units of LRR Energy, L.P., pursuant to a planned contribution and exchange agreement, LRR Energy, L.P. will acquire the working interests and related net profits interests and related operations in specified oil and natural gas properties (the "Common Control Properties") owned by LRR A, LRR B and LRR C in exchange for newly issued limited partner interests in LRR Energy, L.P. and cash consideration. Fund I is under common control with LRR Energy, L.P. Because the Common Control Properties are deemed to be under common control, accounting rules specify that Fund I and the Common Control Properties be combined from the earliest date they came under common control.

The accounting policies followed by the predecessor are set forth in Note 2 of the audited combined financial statements for the year ended December 31, 2010 included elsewhere in this prospectus, and are supplemented by the notes to these unaudited combined condensed financial statements. There have been no significant changes to these policies and it is suggested that these unaudited combined condensed financial statements be read in conjunction with the audited combined financial statements and notes for the year ended December 31, 2010.

These interim financial statements are unaudited and have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission ("SEC") regarding interim financial reporting. Accordingly, they do not include all of the information and notes required by accounting principles generally accepted in the United States of America ("GAAP") for complete combined financial statements and should be read in conjunction with the audited combined financial statements for the year ended December 31, 2010 included elsewhere in this prospectus. While the year-end balance sheet data was derived from audited financial statements, this interim report does not include all disclosures required by GAAP for annual periods. These unaudited interim combined condensed financial statements reflect all adjustments that are, in the opinion of management, necessary for a fair statement of the results for the periods presented.

In January 2010, the FASB issued Accounting Standards Update ("ASU") 2010-06, "Improving Disclosures About Fair Value Measurements" ("ASU 2010-06"), which amends the Fair Value Measurements and Disclosures Topic of the Accounting Standards Codification ("ASC Topic 820").

Fund I (Predecessor)
NOTES TO UNAUDITED COMBINED CONDENSED FINANCIAL STATEMENTS (Continued)

Among other provisions, ASC Topic 820 establishes a fair value hierarchy that prioritizes the relative reliability of inputs used in fair value measurements. The hierarchy gives highest priority to Level 1 inputs that represent unadjusted quoted market prices in active markets for identical assets and liabilities that the reporting entity has the ability to access at the measurement date. Level 2 inputs are directly or indirectly observable inputs other than quoted prices included within Level 1. Level 3 inputs are unobservable inputs and have the lowest priority in the hierarchy. This amendment requires new disclosures on the value of, and the reason for, transfers in and out of Levels 1 and 2 of the fair value hierarchy and additional disclosures about purchases, sales, issuances and settlements within Level 3 fair value measurements. ASU 2010-06 also clarifies existing disclosure requirements on levels of disaggregation and about inputs and valuation techniques. ASU 2010-06 was effective for interim and annual reporting periods beginning after December 15, 2009, except for the requirement to provide additional disclosures regarding Level 3 measurements which is effective for interim and annual reporting periods beginning after December 15, 2010. The additional disclosure requirements of ASU 2010-06 are included in the footnotes of these unaudited combined financial statements.

The predecessor acquires proved oil and natural gas properties that meet management's criteria with respect to reserve lives, development potential, production risk and other operational characteristics. The predecessor generally does not acquire assets other than oil and natural gas property interests. The predecessor assumes the liability for asset retirement obligations ("ARO") related to each acquisition and records the liability at fair value as of the date of closing.

The operating revenues and expenses of acquired properties are included in the predecessor's combined financial statements from the acquisition date. Transactions are financed through partner contributions and borrowings.

The 2010 acquisition discussed below was accounted for under the acquisition method of accounting. Accordingly, the predecessor conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while acquisition costs associated with the acquisitions were expensed as incurred. The predecessor did not acquire proved oil and natural gas properties during the six months ended June 30, 2011.

The fair values of oil and natural gas properties and ARO are measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate.

On February 23, 2010, the predecessor completed an acquisition of interests in 51 producing gas wells located in Oklahoma (Potato Hills) from a private independent oil and gas company for approximately $104.0 million in cash, subject to customary post-closing and title adjustments. Total proved reserves of the acquired properties were estimated at 10.0 million barrels of oil equivalent at the date of the acquisition.

Fund I (Predecessor)
NOTES TO UNAUDITED COMBINED CONDENSED FINANCIAL STATEMENTS (Continued)

The following table summarizes the values assigned to the assets acquired and liabilities assumed as of the acquisition date (in thousands):

This acquisition qualifies as a business combination, and as such, the predecessor estimated the fair value of these properties as of the acquisition date. The fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value measurements also utilize assumptions of market participants. In the estimation of fair value, the predecessor used a discounted cash flow model and made market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. These assumptions represent Level 3 inputs, as further discussed under Note 4 — Fair value measurements. After post-closing and title adjustments, the assets acquired and liabilities assumed approximate fair value for the acquisition.

Summarized below are the combined results of operations for the six months ended June 30, 2010, on an unaudited pro forma basis, as if the 2010 acquisition had occurred on January 1, 2010:

In May 2011, the predecessor completed the sale and purchase of its interests in certain oil and natural gas properties located in New Mexico to a third party for $2.9 million, subject to customary closing adjustments.

The predecessor's financial instruments, including cash and cash equivalents, accounts receivable and accounts payable, are carried at cost, which approximates fair value due to the short-term maturity of these instruments. The predecessor's financial and non-financial assets and liabilities that are being measured on a recurring basis are measured and reported at fair value.

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. GAAP establishes a three-tier fair value hierarchy, which prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or

Fund I (Predecessor)
NOTES TO UNAUDITED COMBINED CONDENSED FINANCIAL STATEMENTS (Continued)

liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of fair value hierarchy are as follows:

As required by GAAP, the predecessor utilizes the most observable inputs available for the valuation technique used. The financial assets and liabilities are classified in their entirety based on the lowest level of input that is of significance to the fair value measurement. The following table describes, by level within the hierarchy, the fair value of the predecessor's financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2011 and December 31, 2010.

		Level 1		Level 2		Level 3		Total

		(in thousands)
June 30, 2011
Assets:
	Commodity derivative instruments	$	—	$	—	$	23,839	$	23,839
Liabilities:
	Commodity derivative instruments		—		—		2,583		2,583
	Interest rate derivative instruments		—		—		698		698
December 31, 2010
Assets:
	Commodity derivative instruments	$	—	$	—	$	31,586	$	31,586
Liabilities:
	Commodity derivative instruments		—		—		7,221		7,221
	Interest rate derivative instruments		—		—		861		861

All fair values reflected in the table above and on the combined balance sheets have been adjusted for non-performance risk. The following methods and assumptions were used to estimate the fair values of the assets and liabilities in the table above.

Commodity Derivative Instruments — The fair value of the commodity derivative instruments is estimated using a combined income and market valuation methodology based upon forward commodity price and volatility curves. The curves are obtained from independent pricing services reflecting broker market quotes.

Interest Rate Derivative Instruments — The fair value of the interest rate derivative instruments is estimated using a combined income and market valuation methodology based upon forward interest rates and volatility curves. The curves are obtained from independent pricing services reflecting broker market quotes.

Fund I (Predecessor)
NOTES TO UNAUDITED COMBINED CONDENSED FINANCIAL STATEMENTS (Continued)

The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the six months ended June 30, 2011 and 2010:

For the six months ended June 30, 2010, due to a significant decline in future natural gas price curves across all future production periods, the predecessor performed an impairment analysis of its oil and natural gas properties and other non-current assets. For the six months ended June 30, 2010, the predecessor recorded a total non-cash impairment charge of approximately $10.9 million to impair the value of its proved oil and natural gas properties in the Gulf Coast. For the six months ended June 30, 2011, the predecessor did not record an impairment charge. These non-cash charges are included in "Impairment of oil and natural gas properties" in the Combined Condensed Statements of Operations. These impairments of proved Gulf Coast oil and natural gas properties were recorded because the net capitalized costs of the properties exceeded the fair value of the properties as measured by estimated cash flows reported in a third party reserve report. This report was based upon future oil and natural gas prices, which are based on observable inputs adjusted for basis differentials, which are Level 3 inputs. The fair values of proved properties are measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of proved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. The underlying commodity prices embedded in the predecessor's estimated cash flows are the product of a process that begins with New York Mercantile Exchange ("NYMEX") forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that management believes will impact realizable prices. Furthermore, significant assumptions in valuing the proved reserves included the reserve quantities, anticipated drilling and operating costs, anticipated production taxes, future expected natural gas prices and basis differentials, anticipated drilling schedules, anticipated production declines, and an appropriate discount rate commensurate with the risk of the underlying cash flow estimates. Cash flow estimates for the impairment testing excluded derivative instruments used to mitigate the risk of lower future natural gas prices. This asset impairment had no impact on the predecessor's cash flows, liquidity position, or debt covenants. If expected future oil and natural gas prices decline during 2011, the estimated undiscounted future cash flows for the proved oil and natural gas properties may not exceed the net capitalized costs for the predecessor's properties in the Gulf Coast and a non-cash impairment charge may be required to be recognized in future periods.

Fund I (Predecessor)
NOTES TO UNAUDITED COMBINED CONDENSED FINANCIAL STATEMENTS (Continued)

The following is a summary of the predecessor's ARO as of and for the six months ended June 30, 2011 and 2010:

	For the six months ended June 30,

	2011		2010
	(in thousands)
Beginning of period	$	24,296	$	19,194
Assumed in acquisitions		—		1,927
Divested properties		—		—
Revisions to previous estimates		—		—
Liabilities incurred		—		—
Liabilities settled		—		—
Accretion expense		744		669

End of period		25,040		21,790
Less: Current portion of asset retirement obligations		792		601

Asset retirement obligations — non-current	$	24,248	$	21,189

On February 2, 2006, LRR A entered into a $45 million credit facility that was syndicated to a group of lenders. On November 23, 2010, this credit facility was refinanced, and LRR A entered into a new $45 million credit facility that was syndicated to essentially the same group of lenders and with substantively the same material terms and conditions as the previous credit facility. In addition, certain interest rate swap instruments were novated and amended because the composition of lenders in the syndicate group changed. The amended and novated interest rate swap agreements are as follows:

As of June 30, 2011, LRR A's availability under the credit facility is restricted to the borrowing base of $31.5 million. The borrowing base is subject to review and adjustment on a semiannual basis and other interim adjustments as requested by the lenders or LRR A, as applicable. At the election of LRR A, amounts outstanding under the credit facility bear interest at specified margins over the LIBOR of 2.00% to 2.75% or specified margins over the Alternate Base Rate 1.00% to 1.75%. The Alternate Base Rate is the greatest of the Prime Rate, the Fed Funds Rate plus ¹/2 of 1%, or the adjusted LIBOR for a one-month Interest Period plus 1%. Such margins will fluctuate based on the utilization of the facility. As of June 30, 2011, the interest rate on LRR A's revolving line of credit, taking into account the Predecessor's interest rate swaps, was an average of 4.74%.

Fund I (Predecessor)
NOTES TO UNAUDITED COMBINED CONDENSED FINANCIAL STATEMENTS (Continued)

be calculated giving pro forma effect as if such acquisition occurred on the first day of such quarter. In addition, LRR A is subject to covenants limiting restricted payments, transactions with affiliates, incurrence of debt, asset sales, and liens on properties. LRR A was in compliance with all of the financial covenants as of June 30, 2011.

All amounts drawn under the credit facility are due and payable on November 23, 2014. As of June 30, 2011 and December 31, 2010, borrowings under the credit facility were $27.3 million and accrued interest payable was $0.1 million.

Objective and strategy — The predecessor is exposed to commodity price and interest rate risk and considers it prudent to periodically reduce the predecessor's exposure to cash flow variability resulting from commodity price changes and interest rate fluctuations. Accordingly, the predecessor enters into derivative instruments to manage its exposure to commodity price fluctuations, locational differences between a published index and the NYMEX futures on natural gas or crude oil productions, and interest rate fluctuations.

At June 30, 2011 and December 31, 2010, the predecessor's open positions consisted of (i) crude oil and natural gas financial collar contracts, (ii) crude oil and natural gas financial swaps, (iii) natural gas basis financial swaps, (iv) and interest rate swap agreements. These derivative instruments are with five counterparties that are also lenders in the predecessor's credit facility.

Swaps and options are used to manage the predecessor's exposure to commodity price risk and basis risk inherent in the predecessor's oil and natural gas production. Commodity price swap agreements are used to fix the price of expected future oil and natural gas sales at major industry trading locations such as Henry Hub Louisiana ("HH") for gas and Cushing Oklahoma ("WTI") for oil. Basis swaps are used to fix the price differential between the product price at one location versus another. Options are used to establish a floor and a ceiling price (collar) for expected oil or gas sales. Interest rate swaps are used to fix interest rates on existing indebtedness.

Under commodity swap agreements, the predecessor exchanges a stream of payments over time according to specified terms with another counterparty. Specifically for commodity price swap agreements, the predecessor agrees to pay an adjustable or floating price tied to an agreed upon index for the commodity, either gas or oil, and in return receives a fixed price based on notional quantities. Under basis swap agreements, the predecessor agrees to pay an adjustable or floating price tied to two agreed upon indices for gas and in return receives the differential between a floating index and fixed price based on notional quantities. A collar is a combination of a put purchased by the predecessor and a call option written by the predecessor. In a typical collar transaction, if the floating price based on a market index is below the floor price, the predecessor receives from the counterparty an amount equal to this difference multiplied by the specified volume, effectively a put option. If the floating price exceeds the floor price and is less than the ceiling price, no payment is required by either party. If the floating price exceeds the ceiling price, the predecessor must pay the counterparty an amount equal to the difference multiplied by the specific quantity, effectively a call option.

The interest rate swap agreements effectively fix the predecessor's interest rate on amounts borrowed under the credit facility. The purpose of these instruments is to mitigate the predecessor's existing exposure to unfavorable interest rate changes. Under interest rate swap agreements, the predecessor pays a fixed interest rate payment on a notional amount in exchange for receiving a floating amount based on LIBOR on the same notional amount.

Fund I (Predecessor)
NOTES TO UNAUDITED COMBINED CONDENSED FINANCIAL STATEMENTS (Continued)

The predecessor elected not to designate any positions as cash flow hedges for accounting purposes and, accordingly, recorded the net change in the mark-to-market valuation of these derivative contracts in the statements of operations. The predecessor records its derivative activities on a mark-to-market or fair value basis. Fair values are based on pricing models that consider the time value of money and volatility and are comparable to values obtained from counterparties. Pursuant to the accounting standard that permits netting of assets, liabilities, and collateral where the right of offset exists, the predecessor presents the fair value of derivative financial instruments on a net basis.

During the second quarter of 2011, the predecessor entered into oil, natural gas and NGL derivative contracts that will be contributed to LRR Energy, L.P. at the closing of the offering. These contracts are included in the summary of open derivative positions below. Additionally, in June 2011, the predecessor terminated certain commodity oil swaps totaling approximately 744,800 barrels for a total cost of approximately $11.5 million. These contracts are not included in the summary of open derivative positions below.

At June 30, 2011, the predecessor had the following commodity derivative open positions:

Period Sale of Natural Gas Production	Instrument Type		Weighted Average Price			Floor		Ceiling		Index

July — Dec 2011	Price Swaps	3,737,922	$	6.70						HH
Jan — Dec 2012	Price Swaps	3,684,189		6.21						HH
Jan — Dec 2013	Price Swaps	6,191,910		5.56						HH
Jan — Dec 2014	Price Swaps	5,464,908		5.75						HH
Jan — Dec 2015	Price Swaps	4,902,972		5.96						HH
July — Dec 2011	Basis Swaps	1,537,760		(0.34	)					HH/CEGT
Jan — Dec 2012	Basis Swaps	2,833,675		(0.38	)					HH/CEGT
Jan — Dec 2013	Basis swaps	2,564,231		(0.39	)					HH/CEGT
July — Dec 2011	Basis Swaps	1,086,960		(0.26	)					HH/WAHA
Jan — Dec 2012	Basis swaps	1,983,440		(0.31	)					HH/WAHA
Jan — Dec 2013	Basis Swaps	1,779,040		(0.32	)					HH/WAHA
July — Dec 2011	Basis Swaps	957,280		(0.12	)					HH/HSC
Jan — Dec 2012	Basis Swaps	1,602,560		(0.15	)					HH/HSC
Jan — Dec 2013	Basis Swaps	1,316,880		(0.16	)					HH/HSC
July — Dec 2011	Basis Swaps	255,040		(0.21	)					HH/TXOK
Jan — Dec 2013	Basis Swaps	464,800		(0.25	)					HH/TXOK
Jan — Dec 2013	Basis Swaps	417,120		(0.27	)					HH/TXOK
Jan — Dec 2012	Collar	3,375,741				$	4.64	$	7.16	HH

Fund I (Predecessor)
NOTES TO UNAUDITED COMBINED CONDENSED FINANCIAL STATEMENTS (Continued)

At December 31, 2010, the predecessor had the following commodity derivative open positions:

Period Sale of Natural Gas Production	Instrument Type		Weighted Average Price			Floor		Ceiling		Index

Jan — Dec 2011	Price swaps	7,837,761	$	6.73						HH
Jan — Dec 2012	Price swaps	3,684,189		6.21						HH
Jan — Dec 2013	Price swaps	2,904,560		5.86						HH
Jan — Dec 2014	Price swaps	902,048		6.60						HH
Jan — Dec 2011	Basis swaps	3,170,480		(0.34	)					HH/CEGT
Jan — Dec 2011	Basis swaps	2,062,560		(0.12	)					HH/HSC
Jan — Dec 2011	Basis swaps	528,720		(0.21	)					HH/TXOK
Jan — Dec 2011	Basis swaps	2,255,040		(0.26	)					HH/WAHA
Jan — Dec 2012	Basis swaps	2,833,680		(0.38	)					HH/CEGT
Jan — Dec 2012	Basis swaps	1,602,560		(0.15	)					HH/HSC
Jan — Dec 2012	Basis swaps	464,800		(0.25	)					HH/TXOK
Jan — Dec 2012	Basis swaps	1,983,440		(0.31	)					HH/WAHA
Jan — Dec 2013	Basis swaps	2,564,240		(0.39	)					HH/CEGT
Jan — Dec 2013	Basis swaps	1,316,880		(0.16	)					HH/HSC
Jan — Dec 2013	Basis swaps	417,120		(0.27	)					HH/TXOK
Jan — Dec 2013	Basis swaps	1,779,040		(0.32	)					HH/WAHA
Jan — Dec 2012	Collar	3,375,741		—		$	4.64	$	7.16	HH

At June 30, 2011, the predecessor had the following interest rate swap contracts:

Fund I (Predecessor)
NOTES TO UNAUDITED COMBINED CONDENSED FINANCIAL STATEMENTS (Continued)

At December 31, 2010, the predecessor had the following interest rate swap contracts:

The fair value of all oil and natural gas and interest rate derivative instruments as of June 30, 2011 is included in the table below:

		As of June 30, 2011

		Current Assets		Long-term Assets		Current Liabilities		Long-term Liabilities
		(in thousands)
Interest rate
	Swaps	$	—	$	—	$	544	$	154
Sale of Natural Gas Production
	Price swaps		11,056		7,780		—		—
	Basis swaps		—				942		911
	Collars		726		629		—		11
Sale of Crude Oil Production
	Price swaps		2,265		317		267		391
	Collars		954		—		—		—
Sale of NGL's
	Price swap		—		112		61		—

		$	15,001	$	8,838	$	1,814	$	1,467

Fund I (Predecessor)
NOTES TO UNAUDITED COMBINED CONDENSED FINANCIAL STATEMENTS (Continued)

The fair value of all oil and natural gas and interest rate derivative instruments as of December 31, 2010 is included in the table below:

The unrealized gain or loss amounts and classification related to derivative instruments for the six months ended June 30, 2011 and 2010 are as follows:

Credit Risk. All of the predecessor's derivative transactions have been carried out in the over-the-counter market. The use of derivative instruments involves the risk that the counterparties may be unable to meet the financial terms of the transactions. The predecessor monitors the creditworthiness of each of its counterparties and assesses the possibility of whether each counterparty to the derivative contract would default by failing to make any contractually required payments as scheduled in the derivative instrument in determining the fair value. The predecessor also has netting arrangements in

Fund I (Predecessor)
NOTES TO UNAUDITED COMBINED CONDENSED FINANCIAL STATEMENTS (Continued)

place with each counterparty to reduce credit exposure. The derivative transactions are placed with major financial institutions that present minimal credit risks to the predecessor. Additionally, the predecessor considers itself to be of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions.

Each of LRR A, LRR B and LRR C has a management agreement with Lime Rock Management, an affiliated entity, to provide management services for the operation and supervision of their respective funds. The management fee is determined by a formula based on the partners' invested capital or the equity capital commitment. During the six months ended June 30, 2011 and 2010, the predecessor paid $3.0 million and $3.8 million, respectively, to Lime Rock Management for management fees.

In the normal course of business, certain expenses of the predecessor may be paid by, and subsequently reimbursed to, Lime Rock Management. There were no outstanding amounts due to Lime Rock Management at June 30, 2011 or December 31, 2010.

In addition, through the normal course of business, certain expenses of the predecessor may be paid by, and subsequently reimbursed to, Lime Rock Resources Operating Company, Inc. pursuant to a services agreement. As of June 30, 2011 and December 31, 2010, the predecessor had a minimal amount due to or from Lime Rock Resources Operating Company, Inc.

For certain oil and natural gas properties where the predecessor is the operator, the predecessor receives income related to joint interest operations. For the six months ended June 30, 2011, the predecessor received $0.6 million of income, which reduced the management fee paid by the predecessor to Lime Rock Management. The predecessor did not record any such amounts during the six months ended June 30, 2010. All related party transactions are at amounts believed to be commensurate with an arm's-length transaction between parties and are stated at fair market value.

The predecessor has performed an evaluation of subsequent events through the date the financial statements were made available for issuance. No material events have occurred through this date.

In our opinion, the accompanying combined balance sheets and the related combined statements of operations, of changes in partners' capital and of cash flows present fairly, in all material respects, the financial position of Fund 1 (Predecessor) at December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 2 of the combined financial statements, Fund I (Predecessor) adopted Accounting Standards Update No. 2010-3, "Oil and Gas Reserve Estimation and Disclosures" on December 31, 2009.

				As of December 31,

				2010			2009
				(in thousands)
ASSETS
Current assets:
	Cash and cash equivalents			$	12,455		$	15,527
	Accounts receivable:
		Oil and natural gas sales			14,012			11,957
		Trade and other			2,531			3,018
	Commodity derivative instruments				23,819			36,244
	Amounts due from affiliates				59			712
	Prepaid expenses				1,722			6,215

		Total current assets			54,598			73,673
Property and equipment:
	Oil and natural gas properties (successful efforts method)				781,495			648,771
	Unproved properties				2,133			3,137
	Other property and equipment				718			597

					784,346			652,505
	Accumulated depletion, depreciation and impairment				(342,400	)		(275,748	)

		Total property and equipment, net			441,946			376,757
Commodity derivative instruments					7,767			15,100
Interest rate derivative instruments					—			61
Deferred financing costs, net of accumulated amortization					311			100

		TOTAL ASSETS		$	504,622		$	465,691

LIABILITIES AND PARTNERS' CAPITAL
Current liabilities:
	Trade accounts payable			$	3,354		$	2,324
	Accrued liabilities				8,141			6,861
	Accrued capital cost				6,620			3,682
	Commodity derivative instruments				1,888			2,130
	Interest rate derivative instruments				594			609
	Asset retirement obligations				792			601

			Total current liabilities		21,389			16,207
Long-term liabilities
	Commodity derivative instruments				5,333			885
	Interest rate derivative instruments				267			65
	Revolving credit facility				27,251			24,150
	Asset retirement obligations				23,504			18,593
	Deferred tax liabilities				145			145

			Total long-term liabilities		56,500			43,838

			Total liabilities		77,889			60,045
Contractual obligations and commitments (Note 11)
Partners' capital:					426,733			405,646

			TOTAL LIABILITIES AND PARTNERS' CAPITAL	$	504,622		$	465,691

			For the year ended December 31,

			2010			2009			2008
			(in thousands)
Revenues:
	Oil sales		$	52,670		$	34,604		$	58,852
	Natural gas sales			48,088			33,798			100,378
	Natural gas liquids sales			14,748			10,617			20,393
	Realized gain (loss) on commodity derivative instruments			48,029			70,902			(2,676	)
	Unrealized gain (loss) on commodity derivative instruments			(23,964	)		(62,375	)		117,757
	Other income			116			24			18

		Total revenues		139,687			87,570			294,722
Operating Expenses:
	Lease operating expenses			23,804			19,066			18,781
	Production and ad valorem taxes			9,320			6,731			13,899
	Depletion and depreciation			55,828			56,349			79,477
	Impairment of oil and natural gas properties			11,712			—			121,561
	Accretion expense			1,366			1,255			691
	(Gain) loss on settlement of asset retirement obligations			(209	)		(1,570	)		250
	Management fees			6,104			8,500			8,500
	General and administrative expenses			5,293			2,408			2,493

		Total operating expenses		113,218			92,739			245,652
Operating income (loss)				26,469			(5,169	)		49,070
Other income (expense), net
	Interest income			17			87			623
	Interest expense			(3,223	)		(1,274	)		(2,131	)
	Realized gain (loss) on interest rate derivative instruments			(649	)		(457	)		(71	)
	Unrealized gain (loss) on interest rate derivative instruments			(248	)		95			(709	)

		Other income (expense), net		(4,103	)		(1,549	)		(2,288	)

Income (loss) before taxes				22,366			(6,718	)		46,782
Income tax benefit (expense)				(32	)		622			(971	)

Net income (loss)			$	22,334		$	(6,096	)	$	45,811

		General Partner			Limited Partners			Class B Limited Partner			Total

		(in thousands)
Balance, December 31, 2007		$	4,073		$	317,019		$	58,152		$	379,244
	Capital contributions		2,313			173,492			119,850			295,655
	Distributions		(732	)		(54,866	)		(8,377	)		(63,975	)
	Capital contributions returned		(1,776	)		(133,175	)		—			(134,951	)
	Net income		582			32,104			13,125			45,811

Balance, December 31, 2008			4,460			334,574			182,750			521,784
	Capital contributions		48			12,629			5,100			17,777
	Distributions		(844	)		(63,208	)		(59,934	)		(123,986	)
	Capital contributions returned		(50	)		(3,783	)		—			(3,833	)
	Net loss		(78	)		(6,018	)		—			(6,096	)

Balance December 31, 2009			3,536			274,194			127,916			405,646
	Capital contributions		1,054			79,064			48,849			128,967
	Distributions		(1,057	)		(79,249	)		(40,590	)		(120,896	)
	Capital contributions returned		(123	)		(9,195	)		—			(9,318	)
	Net income		42			3,294			18,998			22,334

Balance December 31, 2010		$	3,452		$	268,108		$	155,173		$	426,733

					For the year ended December 31,

					2010			2009			2008
					(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES
	Net income (loss)				$	22,334		$	(6,096	)	$	45,811
		Adjustments to reconcile net income (loss) to net cash provided by operating activities:
			Depletion and depreciation			55,828			56,349			79,477
			Impairment of oil and natural gas properties			11,712			—			121,561
			Unrealized loss (gain) on derivative instruments, net			24,212			62,280			(117,048	)
			Accretion expense			1,366			1,255			691
			Amortization of deferred financing costs			138			117			51
			Deferred tax provision			—			(661	)		656
			(Gain) loss on settlement of asset retirement obligations			(209	)		(1,570	)		250
		Operating Expenses:
			Change in oil and natural gas sales			(2,055	)		4,009			342
			Change in trade and other			487			5,567			(368	)
			Change in prepaid expenses			4,493			(5,807	)		(189	)
			Change in trade accounts payable			1,030			(4,188	)		4,275
			Change in amounts due from affiliates			653			(387	)		(661	)
			Change in accrued liabilities			1,280			(2,720	)		4,388

				Net cash provided by operating activities		121,269			108,148			139,236
CASH FLOWS FROM INVESTING ACTIVITIES
			Acquisition of oil and natural gas properties			(105,209	)		(8,514	)		(190,455	)
			Development of oil and natural gas properties			(33,069	)		(19,645	)		(27,557	)
			Disposition of oil and natural gas properties			12,553			3,144			267
			Expenditures for other property and equipment			(121	)		(114	)		(241	)

				Net cash used in investing activities		(125,846	)		(25,129	)		(217,986	)
CASH FLOWS FROM FINANCING ACTIVITIES
			Deferred financing costs			(349	)		(9	)		(121	)
			Borrowings under revolving credit facility			8,620			900			21,150
			Principal payments on revolving credit facility			(5,519	)		(9,000	)		—
			Capital contributions			128,967			17,777			295,655
			Distributions			(120,896	)		(123,986	)		(63,975	)
			Capital contributions returned			(9,318	)		(3,833	)		(134,951	)

				Net cash provided by (used in) financing activities		1,505			(118,151	)		117,758
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS						(3,072	)		(35,132	)		39,008
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD						15,527			50,659			11,651

CASH AND CASH EQUIVALENTS, END OF PERIOD					$	12,455		$	15,527		$	50,659

Supplemental disclosure of cash flow information:
			Cash paid for taxes during the period		$	25		$	149		$	—
			Cash paid for interest during the period			928			1,382			1,749
Supplemental disclosure of non-cash items to reconcile:
			Investing and financing activities
			Property and equipment:
				Accrued capital costs		2,938			323			2,066
				Asset retirement obligations		3,736			925			9,164

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") (LRR A, LRR B, and LRR C collectively "Fund I" or "Predecessor") were formed by Lime Rock Management L.P. ("Lime Rock Management") pursuant to the laws of the State of Delaware on July 14, 2005 for the purpose of acquiring mature, low-risk producing oil and natural gas properties with long-lived production profiles. Fund I's underlying properties consist of working interests in certain oil and natural gas properties owned by LRR A located in New Mexico, Oklahoma and Texas and related net profits interests in these same oil and natural gas properties owned by LRR B and LRR C. Fund I is managed by Lime Rock Management and pays a management fee to Lime Rock Management. In addition, Fund I also receives administrative services from Lime Rock Resources Operating Company, Inc. Under their respective partnership agreements, LRR A, LRR B and LRR C have a 10-year term expiring on July 13, 2015, which can be extended by the general partner with the consent of the Advisory Committee for two successive periods of one year each.

The accompanying combined financial statements were derived from the historical accounting records of the Predecessor and reflect the historical financial position, results of operations and cash flows for the periods described herein. All intercompany transactions and account balances have been eliminated in the combination of accounts. The accompanying Combined Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America (GAAP). The Predecessor operates oil and natural gas properties as one business segment: the exploration, development and production of oil and natural gas. The Predecessor's management evaluates performance based on one business segment as there are not different economic environments within the operation of the oil and natural gas properties.

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates.

Depreciation, depletion and amortization of oil and natural gas properties and the impairment of oil and natural gas properties are determined using estimates of oil and natural gas reserves. There are numerous uncertainties in estimating the quantity of reserves and in projecting the future rates of production and timing of development expenditures, including future costs to dismantle, dispose, and restore the Predecessor's properties. Oil and natural gas reserve engineering must be recognized as a

subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way.

The Predecessor considers all highly liquid instruments purchased with a maturity when acquired of three months or less to be cash equivalents. The Predecessor continually monitors its positions with, and the credit quality of, the financial institutions with which it invests.

Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The Predecessor uses the specific identification method of providing allowances for doubtful accounts. At December 31, 2010 and 2009, the Predecessor did not have an allowance for doubtful accounts.

Revenues from oil and gas sales are recognized based on the sales method with revenue recognized on actual volumes sold to purchasers. Under this method of revenue recognition, a gas imbalance is created if the quantity sold is greater than or less than the Predecessor's entitlement share in any particular period. To the extent there are sufficient quantities of natural gas remaining to make up the gas imbalance, oil and natural gas reserves are adjusted to reflect the overproduced or underproduced position. In situations where there are insufficient reserves available to make up an overproduced imbalance, a liability is established. As of December 31, 2010 and 2009, the Predecessor had no significant production imbalances.

Financial instruments which potentially subject the Predecessor to credit risk consist principally of cash balances, accounts receivable and derivative financial instruments. The Predecessor maintains cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. The Predecessor has not experienced any significant losses from such investments. The Predecessor attempts to limit the amount of credit exposure to any one financial institution or company through procedures that include credit approvals, credit limits and terms, letters of credit, prepayments and rights of offset. The Predecessor's customer base consists primarily of major integrated and international oil and natural gas companies, as well as smaller processors and gatherers. The Predecessor believes the credit quality of its customer base is high and has not experienced significant write-downs in its accounts receivable balances.

For the year ended December 31, 2010, purchases by ConocoPhillips, Seminole Energy Services, Upstream Energy, and Sunoco accounted for 16%, 13%, 10% and 10%, respectively, of the Predecessor's total sales revenues. ConocoPhillips, Seminole, Upstream, and Sunoco purchase the oil production from the Predecessor pursuant to existing marketing agreements with terms that are currently on "evergreen" status and renew on a month-to-month basis until either party gives 30-days'advance written notice of non-renewal.

For the year ended December 31, 2009, purchases by Upstream Energy, ConocoPhillips, Square Mile Energy, and Sunoco accounted for 18%, 14%, 13% and 11%, respectively, of the Predecessor's total sales revenues.

For the year ended December 31, 2008, purchases by Upstream Energy and Square Mile Energy accounted for 29% and 27%, respectively, of the Predecessor's total sales revenues.

If the Predecessor were to lose any one of its customers, the loss could temporarily delay production and sale of oil and natural gas in the related producing region. If the Predecessor were to lose any single customer, the Predecessor believes that a substitute customer to purchase the impacted production volumes could be identified. However, if one or more of the Predecessor's larger customers ceased purchasing oil or natural gas altogether, the loss of such customer could have a detrimental effect on production volumes in general and on the ability to find substitute customers to purchase production volumes.

The Predecessor accounts for its oil and natural gas exploration, development and production activities in accordance with the successful efforts method. Under this method, all leasehold and development costs of proved properties are capitalized and amortized on a unit-of-production basis over the remaining life of the proved reserves and proved developed reserves, respectively.

The Predecessor evaluates the potential impairment of its proved oil and natural gas properties on a field-by-field basis whenever events or changes in circumstances indicate that the carrying value may not be recoverable. The Predecessor assesses impairment of capitalized costs of proved oil and natural gas properties by comparing net capitalized costs to estimated undiscounted future net cash flows using expected prices. The carrying values of proved properties are reduced to fair value when the expected undiscounted future cash flows are less than net book value. For the years ended December 31, 2010 and 2008, the Predecessor recorded non-cash impairment charges on proved oil and natural gas properties of $10.9 million, and $121.6 million, respectively. These charges are included in "impairment of oil and natural gas properties" on the combined statements of operations. No impairment was recorded for proved properties for the year ended December 31, 2009. Refer to Note 5 for additional information.

Costs of retired, sold or abandoned properties that constitute a part of an amortization base are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized currently. Gains or losses from the disposal of proved properties are recognized currently. Expenditures for maintenance and repairs necessary to maintain properties in operating condition are expensed as incurred. Estimated dismantlement and abandonment costs are capitalized, net of salvage, at their estimated net present value and amortized on a unit-of-production basis over the remaining life of the related proved developed reserves.

In January 2010, the FASB issued Accounting Standards Update 2010-03 ("ASU 2010-03"), "Oil and Gas Reserve Estimations and Disclosures." This update aligns the current oil and gas reserve estimation and disclosure requirements of ASC Topic 932, Extractive Activities—Oil and Gas, with the requirements in the Securities and Exchange Commission's final rule, Modernization of the Oil and Gas Reporting Requirements, which was issued on December 31, 2008 and was effective for the year ended December 31, 2009. The Modernization of the Oil and Gas Reporting Requirements final rule was designed to modernize and update the oil and gas disclosure requirements to align with current practices and changes in technology. Key provisions of ASU 2010-03 are as follows:

The Predecessor implemented ASU 2010-03 prospectively as a change in accounting principle inseparable from a change in accounting estimate at December 31, 2009. The Predecessor did not determine reserve levels at December 31, 2009 under the previous accounting rules due to the operational and technical challenges of preparing reserve reports under two sets of rules, and therefore it is not practicable to determine the impact of adopting this accounting principle.

Costs related to unproved properties include costs incurred to acquire unproved reserves. Because these reserves do not meet the definition of proved reserves, the related costs are not classified as proved properties. As of December 31, 2010 and 2009, $2.1 million and $3.1 million, respectively, of oil and natural gas property costs were related to unproved leasehold acquisitions costs and not subject to depletion. For the year ended December 31, 2010 and 2009, the Predecessor reclassified $0.2 million and $0.2 million, respectively, from unproved to proved properties.

The Predecessor assesses unproved properties for impairment on a quarterly basis. For the year ended December 31, 2010, the Predecessor recorded an impairment charge for unproved properties in the amount of $0.8 million. No impairments were recorded for unproved properties for the years ended December 31, 2009 and 2008. The impairments were based on the Predecessor's experience in similar situations and other factors such as the primary lease terms of the properties, the average holding period of unproved properties, and the relative proportion of such properties on which proved reserves have been found in the past. The fair values of unproved properties are measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of unproved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. The market-based weighted average cost of capital rate is subject to additional project-specific risk factors.

Other property and equipment is stated at historical cost less accumulated depreciation expense and is comprised primarily of software, computers and office equipment. Depreciation is calculated using the straight-line method based on useful lives of the assets ranging from three to five years. Other property and equipment is evaluated for impairment as necessary to determine if current circumstances and market conditions indicate that the carrying amounts of assets may not be recoverable. The

Predecessor did not recognize any impairment loss related to other property and equipment for the years ended December 31, 2010, 2009 and 2008.

The Predecessor has obligations under its lease agreements and federal regulations to remove equipment and restore land at the end of oil and natural gas production operations. These asset retirement obligations ("ARO") are primarily associated with plugging and abandoning wells. Determining the future restoration and removal requires management to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations. The Predecessor follows the guidance in ASC Topic 410, Asset Retirement and Environmental Obligations which requires entities to record the fair value of a liability for an ARO in the period in which it is incurred with a corresponding increase in the carrying amount of the related long-lived asset. The Predecessor typically incurs this liability upon acquiring or drilling a well. Over time, the liability is accreted each period toward its future value, and the capitalized cost is depleted as a component of development costs. Upon settlement of the liability, a gain or loss is recognized to the extent the actual costs differ from the recorded liability.

Inherent to the present value calculation are numerous estimates, assumptions and judgments, including the ultimate settlement amounts, inflation factors, credit adjusted risk-free rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the abandonment liability, management will make corresponding adjustments to both the ARO and the related oil and natural gas property asset balance. Increases in the discounted retirement obligation liability and related oil and natural gas assets resulting from the passage of time will be reflected as additional accretion and depreciation expense in the combined statements of operations.

The Predecessor's activities primarily consist of acquiring, owning, enhancing and producing oil and natural gas properties. The future results of the Predecessor's operations, cash flows and financial condition may be affected by changes in the market price of oil and natural gas. The availability of a ready market for oil and natural gas products in the future will depend on numerous factors beyond the control of the Predecessor, including weather, imports, marketing of competitive fuels, proximity and capacity of oil and natural gas pipelines and other transportation facilities, any oversupply or undersupply of oil, natural gas and liquid products, the regulatory environment, the economic environment and, other regional and political events, none of which can be predicted with certainty.

In order for the Predecessor to manage its exposure to oil and natural gas price volatility, the Predecessor enters into commodity derivative instruments such as futures contracts, swaps, or options. The Predecessor is also exposed to changes in interest rates, primarily as a result of variable rate borrowings under the credit facility. In an effort to reduce this exposure, the Predecessor has, from time to time, entered into derivative contracts (interest rate swaps) to mitigate the risk of interest rate fluctuations. For commodity derivatives, both realized and unrealized gains and losses are recorded as separate components of revenues. For interest rate derivatives, both realized and unrealized gains and losses are recorded as a component of other income (expense) in the combined statements of operations.

ASC Topic 815, Derivatives and Hedging, requires recognition of all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. Changes in the fair value of derivatives are recognized currently in earnings unless specific hedge accounting criteria are met. Realized gains and losses on derivative hedging instruments are recorded currently in earnings. Unrealized gains and losses on derivatives are also recorded currently in earnings unless the derivatives qualify and are appropriately designated as hedges. Unrealized gains or losses on derivative instruments that qualify and are designated as hedges are deferred in other comprehensive income until the related transaction occurs. The Predecessor has not designated any of its derivative instruments as hedges. As a result, the Predecessor marks its derivative instruments to fair value in accordance with the provisions of ASC Topic 815 and recognizes the changes in fair market value in earnings. Also see Note 4 — Fair Value Measurements and Note 8 — Derivatives for additional discussion.

Derivative financial instruments are generally executed with major financial institutions that expose the Predecessor to market and credit risks and which may, at times, be concentrated with certain counterparties or groups of counterparties. All of the Predecessor's derivatives at December 31, 2010 are with parties that are also lenders under the Predecessor's credit facility. The credit worthiness of the counterparties is subject to continual review. The Predecessor monitors the nonperformance risk of itself and of each of its counterparties and assesses the possibility of whether each counterparty to the derivative contract would default by failing to make any contractually required payments as scheduled in the derivative instrument in determining the fair value. The Predecessor also has netting arrangements in place with each counterparty to reduce credit exposure.

The Predecessor is not taxable for federal income tax purposes and does not directly pay federal income tax. Generally, all taxable federal income and losses of the Predecessor are reported on the income tax returns of the partners, and therefore, no provision for federal income taxes has been recorded in the Predecessor's accompanying combined financial statements.

The Predecessor records its obligations under the Texas gross margin tax as "Income tax" in the combined statements of operations. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period of rate change.

Costs incurred in connection with the execution or modification of the Predecessor's credit facility are capitalized and amortized using the effective interest method over the term of the credit facility.

In January 2010, the FASB issued Accounting Standards Update (ASU) 2010-06, "Improving Disclosures About Fair Value Measurements" (ASU 2010-06), which amends the Fair Value Measurements and Disclosures Topic of the ASC (ASC Topic 820). Among other provisions, ASC Topic 820 establishes a fair value hierarchy that prioritizes the relative reliability of inputs used in fair value measurements. The hierarchy gives highest priority to Level 1 inputs that represent unadjusted quoted market prices in active markets for identical assets and liabilities that the reporting entity has the ability to access at the measurement date. Level 2 inputs are directly or indirectly observable inputs other than

quoted prices included within Level 1. Level 3 inputs are unobservable inputs and have the lowest priority in the hierarchy. This amendment requires new disclosures on the value of, and the reason for, transfers in and out of Levels 1 and 2 of the fair value hierarchy and additional disclosures about purchases, sales, issuances and settlements within Level 3 fair value measurements. ASU 2010-06 also clarifies existing disclosure requirements on levels of disaggregation and about inputs and valuation techniques. ASU 2010-06 is effective for interim and annual reporting periods beginning after December 15, 2009, except for the requirement to provide additional disclosures regarding Level 3 measurements which is effective for interim and annual reporting periods beginning after December 15, 2010.

The Predecessor acquires proved oil and natural gas properties that meet management's criteria with respect to reserve lives, development potential, production risk and other operational characteristics. The Predecessor generally does not acquire assets other than oil and natural gas property interests. The Predecessor assumes the liability for ARO related to each acquisition and records the liability at fair value as of the date of closing.

The operating revenues and expenses of acquired properties are included in the Predecessor's combined financial statements from the acquisition date. Transactions are financed through partner contributions and borrowings.

The acquisitions discussed below were accounted for under the acquisition method of accounting. Accordingly, the Predecessor conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while acquisition costs associated with the acquisitions were expensed as incurred for 2010 and 2009 and were capitalized as additional costs of oil and natural gas properties for 2008.

Summarized below are the combined results of operations for the year ended December 31, 2010, on an unaudited pro forma basis, as if the 2010 and 2009 acquisitions had occurred on January 1, 2009:

The following table summarizes the values assigned to the assets acquired and liabilities assumed for the year ended December 31, 2010 as of the acquisition dates:

These acquisitions qualify as business combinations, and as such, the Predecessor estimated the fair value of these properties as of the acquisition dates. The fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value measurements also utilize assumptions of market participants. In the estimation of fair value, the Predecessor used a discounted cash flow model and made market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. These assumptions represent Level 3 inputs, as further discussed under Note 4 — Fair value measurements. After post-closing and title adjustments, the assets acquired and liabilities assumed approximate fair value for the acquisitions.

On February 23, 2010, the Predecessor completed an acquisition of interests in 51 producing gas wells located in Oklahoma (Potato Hills) from a private independent oil and gas company for approximately $104.0 million in cash, subject to customary post-closing and title adjustments. Total proved reserves of the acquired properties were estimated at 10.0 million barrels of oil equivalent at the date of the acquisition.

On August 31, 2010, the Predecessor completed the acquisition of certain oil and natural gas properties located in Texas from a private independent oil and gas company for a purchase price of approximately $7.5 million, subject to customary post-closing and title adjustments.

On October 14, 2010, the Predecessor also closed the acquisition of an additional interest in certain New Mexico wells in which it already held interests from a large public independent oil and gas company. The acquisition was valued at $1.8 million, subject to customary post-closing and title adjustments, and was in partial consideration for the divestiture of certain other New Mexico properties as discussed below under "Divestitures of non-core assets — 2010 and 2009".

On July 17, 2009, the Predecessor completed the acquisition of certain oil and natural gas properties located in New Mexico from a large public independent oil and gas company for a purchase price of approximately $3.7 million, subject to customary post-closing and title adjustments.

On December 2, 2009, the Predecessor completed the acquisitions of certain oil and natural gas properties located in DeWitt County, Texas from a private independent oil and gas company for an aggregate purchase price of approximately $6.1 million, subject to customary post-closing and title adjustments.

On August 15, 2008, the Predecessor completed an acquisition of interests in 94 producing wells located in New Mexico and Texas (Corral Canyon) from a large public independent oil and gas company for $160.4 million, subject to customary post-closing and title adjustments. The acquisition was funded through cash calls to partners combined with borrowings under the Predecessor's credit facility. Total proved reserves of the acquired properties were estimated at 4.5 million barrels of oil equivalent at the date of the acquisition.

On April 11, 2008 and May 26, 2008, the Predecessor closed two acquisitions of oil and natural gas properties located in New Mexico from a private independent oil and gas company for an aggregate purchase price of approximately $36.2 million in cash, subject to customary post-closing and title adjustments.

On March 17, 2008, the Predecessor completed the acquisition of certain oil and natural gas properties located in New Mexico from a private independent oil and gas company for a purchase price of approximately $4.5 million, subject to customary post-closing and title adjustments.

During 2010, the Predecessor sold its interests in certain oil and natural gas properties located in New Mexico with carrying values of approximately $14.3 million and received net cash proceeds of approximately $12.5 million and certain additional property interests valued at $1.8 million.

During 2009, the Predecessor sold its interests in certain oil and natural gas properties in Texas for $3.2 million, subject to customary post-closing adjustments.

In both 2010 and 2009, the sales of these non-core assets did not affect the unit-of-production amortization rate and, therefore, no gain or loss was recognized for the divestitures.

The Predecessor's financial instruments, including cash and cash equivalents, accounts receivable and accounts payable, are carried at cost, which approximates fair value due to the short-term maturity of these instruments. The Predecessor's financial and non-financial assets and liabilities that are being measured on a recurring basis are measured and reported at fair value.

Level 1 — Defined as inputs such as unadjusted quoted prices in active markets for identical assets or liabilities.

Level 2 — Defined as inputs other than quoted prices in active markets that are either directly or indirectly observable for the asset or liability.

Level 3 — Defined as unobservable inputs for use when little or no market data exists, requiring an entity to develop its own assumptions for the asset or liability.

As required by GAAP, the Predecessor utilizes the most observable inputs available for the valuation technique used. The financial assets and liabilities are classified in their entirety based on the lowest level of input that is of significance to the fair value measurement. The following table describes,

by level within the hierarchy, the fair value of the Predecessor's financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2010 and December 31, 2009.

		Level 1		Level 2		Level 3		Total

		(in thousands)
December 31, 2010
Assets:
	Commodity derivative instruments	$	—	$	—	$	31,586	$	31,586
Liabilities:
	Commodity derivative instruments		—		—		7,221		7,221
	Interest rate derivative instruments						861		861
December 31, 2009
Assets:
	Commodity derivative instruments	$	—	$	—	$	51,344	$	51,344
	Interest rate derivative instruments		—		—		61		61
Liabilities:
	Commodity derivative instruments		—		—		3,015		3,015
	Interest rate derivative instruments		—		—		674		674

The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the twelve months ended December 31, 2010 and 2009:

Property and equipment is stated at cost less accumulated depletion, depreciation and impairment and consisted of the following:

The Predecessor recorded $55.8 million, $56.3 million and $79.4 million of depletion and depreciation expense for the years ended December 31, 2010, 2009 and 2008, respectively.

For the years ended December 31, 2010 and 2008, due to a significant decline in future natural gas price curves across all future production periods, the Predecessor performed an impairment analysis of its oil and natural gas properties and other non-current assets. For the year ended December 31, 2010, the Predecessor recorded a total non-cash impairment charge of approximately $11.7 million, composed of $10.9 million and $0.8 million to impair the value of its proved and unproved oil and natural gas properties in the Gulf Coast, respectively. For the year ended December 31, 2008, the Predecessor recorded a total non-cash impairment charge of approximately $121.6 million to impair the value of its proved oil and natural gas properties in the Permian Basin. These non-cash charges are included in "Impairment of oil and natural gas properties" line item in the Combined Statements of Operations. These impairments of proved and unproved Gulf Coast and Permian Basin oil and natural gas properties were recorded because the net capitalized costs of the properties exceeded the fair value of the properties as measured by estimated cash flows reported in a third party reserve report. This report was based upon future oil and natural gas prices, which are based on observable inputs adjusted for basis differentials, which are Level 3 inputs. The fair values of proved properties are measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of proved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. The underlying commodity prices embedded in the Predecessor's estimated cash flows are the product of a process that begins with New York Mercantile Exchange ("NYMEX") forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that management believes will impact realizable prices. Furthermore, significant assumptions in valuing the proved reserves included the reserve quantities, anticipated drilling and operating costs, anticipated production taxes, future expected natural gas prices and basis differentials, anticipated drilling schedules, anticipated production declines, and an appropriate discount rate commensurate with the risk of the underlying cash flow estimates. The impairments were caused by the impact of lower future natural gas prices. Particularly during the first quarter of 2010 and the fourth quarter of 2008, future natural gas price curves shifted significantly lower in the Gulf Coast and Permian Basin, respectively. Cash flow estimates for the impairment testing excluded derivative instruments used to mitigate the risk of lower future natural gas prices. The Predecessor's unproved properties in the Gulf Coast were impaired based on the drilling locations for the probable and possible reserves becoming uneconomic at the lower future expected natural gas prices and the Predecessor's future expected

drilling schedules. Significant assumptions in valuing the unproved reserves included the evaluation of the probable and possible reserves included in the third party reserve report, future expected natural gas prices and basis differentials, and the Predecessor's anticipated drilling schedules. These asset impairments have no impact on the Predecessor's cash flows, liquidity position, or debt covenants. If expected future oil and natural gas prices continue to decline during 2011, the estimated undiscounted future cash flows for the proved oil and natural gas properties may not exceed the net capitalized costs for the Predecessor's properties in the Gulf Coast and a non-cash impairment charge may be required to be recognized in future periods.

The following is a summary of the Predecessor's ARO as of and for the twelve months ended December 31, 2010 and 2009:

	For The Year Ended December 31,

	2010			2009
	(in thousands)
Beginning of period	$	19,194		$	18,864
Assumed in acquisitions		2,994			797
Divested properties		(526	)		(3,035	)
Revisions to previous estimates		1,212			1,240
Liabilities incurred		550			491
Liabilities settled		(494	)		(418	)
Accretion expense		1,366			1,255

End of period		24,296			19,194
Less: Current portion of asset retirement obligations		792			601

Asset retirement obligations — non-current	$	23,504		$	18,593

As of December 31, 2010, LRR A's availability under the credit facility is restricted to the borrowing base of $31.5 million. The borrowing base is subject to review and adjustment on a semiannual basis and other interim adjustments as requested by the lenders or LRR A, as applicable. At the election of LRR A, amounts outstanding under the credit facility bear interest at specified margins over the LIBOR of 2.00% to 2.75% or specified margins over the Alternate Base Rate 1.00% to 1.75%. The Alternate Base Rate is the greatest of the Prime Rate, the Fed Funds Rate plus 1/2 of 1%, or the adjusted LIBOR for a one-month

Interest Period plus 1%. Such margins will fluctuate based on the utilization of the facility. As of December 31, 2010, the interest rate on LRR A's revolving line of credit, taking into account the Predecessor's interest rate swaps, was an average of 5.26%.

Borrowings under the credit facility are collateralized by a perfected, first-priority security interest in substantially all of the oil and natural gas properties owned by LRR A. LRR A is subject to financial covenants with respect to current ratio, interest coverage ratio, and ratio of debt to EBITDAX. EBITDAX is defined as net income plus interest, income taxes, depreciation, depletion, amortization, exploration expenses, and other noncash charges, and minus all noncash income. If a material acquisition (as defined in the credit facility) is made during the quarter, the credit facility provides that the EBITDAX be calculated giving pro forma effect as if such acquisition occurred on the first day of such quarter. In addition, LRR A is subject to covenants limiting restricted payments, transactions with affiliates, incurrence of debt, asset sales, and liens on properties. LRR A was in compliance with all of the financial covenants as of December 31, 2010, with the exception of the current ratio. LRR A obtained a waiver for the current ratio requirement at December 31, 2010.

All amounts drawn under the credit facility are due and payable on November 23, 2014. At December 31, 2010, borrowings under the credit facility were $27.3 million and accrued interest payable was $0.1 million.

Objective and strategy — The Predecessor is exposed to commodity price and interest rate risk and considers it prudent to periodically reduce the Predecessor's exposure to cash flow variability resulting from commodity price changes and interest rate fluctuations. Accordingly, the Predecessor enters into derivative instruments to manage its exposure to commodity price fluctuations, locational differences between a published index and the NYMEX futures on natural gas or crude oil productions, and interest rate fluctuations.

At December 31, 2010 and 2009, the Predecessor's open positions consisted of (i) crude oil and natural gas financial collar contracts, (ii) crude oil and natural gas financial swaps, (iii) natural gas basis financial swaps and (iv) interest rate swap agreements. These derivative instruments are with five counterparties that are also lenders in the Predecessor's credit facility.

Swaps and options are used to manage the Predecessor's exposure to commodity price risk and basis risk inherent in the Predecessor's oil and natural gas production. Commodity price swap agreements are used to fix the price of expected future oil and natural gas sales at major industry trading locations such as Henry Hub Louisiana ("HH") for gas and Cushing Oklahoma ("WTI") for oil. Basis swaps are used to fix the price differential between the product price at one location versus another. Options are used to establish a floor and a ceiling price (collar) for expected oil or gas sales. Interest rate swaps are used to fix interest rates on existing indebtedness.

Under commodity swap agreements, the Predecessor exchanges a stream of payments over time according to specified terms with another counterparty. Specifically for commodity price swap agreements, the Predecessor agrees to pay an adjustable or floating price tied to an agreed upon index for the commodity, either gas or oil, and in return receives a fixed price based on notional quantities. Under basis swap agreements, the Predecessor agrees to pay an adjustable or floating price tied to two agreed upon indices for gas and in return receives the differential between a floating index and fixed price based on notional quantities. A collar is a combination of a put purchased by the Predecessor and a call option written by the Predecessor. In a typical collar transaction, if the floating price based on a market index is below the floor price, the Predecessor receives from the counterparty an amount equal to this difference multiplied by the specified volume, effectively a put option. If the floating price

exceeds the floor price and is less than the ceiling price, no payment is required by either party. If the floating price exceeds the ceiling price, the Predecessor must pay the counterparty an amount equal to the difference multiplied by the specific quantity, effectively a call option.

The interest rate swap agreements effectively fix the Predecessor's interest rate on amounts borrowed under the credit facility. The purpose of these instruments is to mitigate the Predecessor's existing exposure to unfavorable interest rate changes. Under interest rate swap agreements, the Predecessor pays a fixed interest rate payment on a notional amount in exchange for receiving a floating amount based on LIBOR on the same notional amount.

The Predecessor elected not to designate any positions as cash flow hedges for accounting purposes and, accordingly, recorded the net change in the mark-to-market valuation of these derivative contracts in the statements of operations. The Predecessor records its derivative activities on a mark-to-market or fair value basis. Fair values are based on pricing models that consider the time value of money and volatility and are comparable to values obtained from counterparties. Pursuant to the accounting standard that permits netting of assets, liabilities, and collateral where the right of offset exists, the Predecessor presents the fair value of derivative financial instruments on a net basis.

At December 31, 2010, the Predecessor had the following commodity derivative open positions:

Period Sale of Natural Gas Production	Instrument Type		Weighted Average Price			Floor		Ceiling		Index

Jan-Dec 2011	Price swaps	7,837,761	$	6.73						HH
Jan-Dec 2012	Price swaps	3,684,189		6.21						HH
Jan-Dec 2013	Price swaps	2,904,560		5.86						HH
Jan-Dec 2014	Price swaps	902,048		6.60						HH
Jan-Dec 2011	Basis swaps	3,170,480		(0.34	)					HH/CEGT
Jan-Dec 2011	Basis swaps	2,062,560		(0.12	)					HH/HSC
Jan-Dec 2011	Basis swaps	528,720		(0.21	)					HH/TXOK
Jan-Dec 2011	Basis swaps	2,255,040		(0.26	)					HH/WAHA
Jan-Dec 2012	Basis swaps	2,833,680		(0.38	)					HH/CEGT
Jan-Dec 2012	Basis swaps	1,602,560		(0.15	)					HH/HSC
Jan-Dec 2012	Basis swaps	464,800		(0.25	)					HH/TXOK
Jan-Dec 2012	Basis swaps	1,983,440		(0.31	)					HH/WAHA
Jan-Dec 2013	Basis swaps	2,564,240		(0.39	)					HH/CEGT
Jan-Dec 2013	Basis swaps	1,316,880		(0.16	)					HH/HSC
Jan-Dec 2013	Basis swaps	417,120		(0.27	)					HH/TXOK
Jan-Dec 2013	Basis swaps	1,779,040		(0.32	)					HH/WAHA
Jan-Dec 2012	Collars	3,375,741		—		$	4.64	$	7.16	HH

At December 31, 2009, the Predecessor had the following commodity derivative open positions:

At December 31, 2010, the Predecessor had the following interest rate swap contracts:

At December 31, 2009, the Predecessor had the following interest rate swap contracts:

At December 31, 2010, the Predecessor's commodity derivative contracts had a net mark-to-market value of $24.4 million, of which $23.8 million was classified as a current asset, $7.8 million was classified as a long-term asset, $1.9 million was classified as a current liability, and $5.3 million was classified as a long-term liability. The Predecessor's interest rate derivative contracts had a negative net mark-to-market value of $0.9 million, of which $0.6 million was classified as a current liability and $0.3 million was classified as a long-term liability on the balance sheet at December 31, 2010.

At December 31, 2009, the Predecessor's commodity derivative contracts had a net mark-to-market value of $48.3 million, of which $36.2 million was classified as a current asset, $15.1 million was classified as a long-term asset, $2.1 million was classified as a current liability, and $0.9 million was classified as a long-term liability. The Predecessor's interest rate derivative contracts had a negative net mark-to-market value of $0.6 million, of which $0.1 million was classified as a long-term asset, $0.6 million classified as a

current liability, and $0.1 million was classified as a long-term liability on the balance sheet at December 31, 2009.

The fair values of all oil and natural gas and interest rate derivative instruments as of December 31, 2010 is included in the table below:

		Asset Derivatives As of December 31, 2010			Liability Derivatives As of December 31, 2010

		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
		(in thousands)
Interest rate
	Swaps				Current liabilities	$	594
	Swaps				Long-term liabilities		267
Sale of Natural Gas Production
	Price swaps	Current assets	$	16,929
	Price swaps	Long-term assets		6,590
	Basis swaps				Current liabilities		379
	Basis swaps				Long-term liabilities		621
	Collars	Long-term assets		1,177	Long-term liabilities		161
Sale of Crude Oil Production
	Price swaps	Current assets		4,694	Current liabilities		1,509
	Price swaps				Long-term liabilities		4,551
	Collars	Current assets		2,196

The fair value of all oil and natural gas and interest rate derivative instruments as of December 31, 2009 is included in the table below (in thousands):

		Asset Derivatives As of December 31, 2009			Liability Derivatives As of December 31, 2009

		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
		(in thousands)
Interest rate
	Swaps				Current liabilities	$	609
	Swaps	Long-term assets	$	61	Long-term liabilities		65
Sale of Natural Gas Production
	Price swaps	Current assets		20,632
	Price swaps	Long-term assets		5,284
	Basis swaps				Current liabilities		1,495
	Basis swaps
	Collars	Long-term assets		75
Sale of Crude Oil Production
	Price swaps	Current assets		9,027	Current liabilities		635
	Price swaps	Long-term assets		6,800	Long-term liabilities		885
	Collars	Current assets		6,585
	Collars	Long-term assets		2,941

The unrealized gain or loss amounts and classification related to derivative instruments for the years ended December 31, 2010, 2009 and 2008 are as follows (in thousands):

Settlements for the year ended December 31, 2010, 2009 and 2008 are as follows (in thousands):

Credit Risk. All of the Predecessor's derivative transactions have been carried out in the over-the-counter market. The use of derivative instruments involves the risk that the counterparties may be unable to meet the financial terms of the transactions. The Predecessor monitors the creditworthiness of each of its counterparties and assesses the possibility of whether each counterparty to the derivative contract would default by failing to make any contractually required payments as scheduled in the derivative instrument in determining the fair value. The Predecessor also has netting arrangements in place with each counterparty to reduce credit exposure. The derivative transactions are placed with

major financial institutions that present minimal credit risks to the Predecessor. Additionally, the Predecessor considers itself to be of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions.

Each of LRR A, LRR B and LRR C has a management agreement with Lime Rock Management, an affiliated entity, to provide management services for the operation and supervision of their respective funds. The management fee is determined by a formula based on the partners' invested capital or the equity capital commitment. During the years ended December 31, 2010, 2009 and 2008, the Predecessor paid $6.1 million, $8.5 million and $8.5 million, respectively, to Lime Rock Management for management fees.

In the normal course of business, certain expenses of the Predecessor may be paid by, and subsequently reimbursed to, Lime Rock Management. There were no outstanding amounts due to Lime Rock Management at December 31, 2010 and 2009, respectively.

In addition, through the normal course of business, certain expenses of the Predecessor may be paid by, and subsequently reimbursed to, the Lime Rock Resources Operating Company, Inc. At December 31, 2009, the Predecessor had a receivable from Lime Rock Resources Operating Company, Inc. in the amount of $0.7 million for overpayment the Predecessor made. At December 31, 2010, the amount due was minimal.

For certain oil and natural gas properties where the Predecessor is the operator, the Predecessor receives income related to joint interest operations. For the year ended December 31, 2010, the Predecessor received $1.0 million of income, which reduced the management fee paid by the Predecessor to Lime Rock Management. All related party transactions are at amounts believed to be commensurate with an arm's-length transaction between parties and are stated at fair market value.

LRR A, LRR B and LRR C have received equity commitments for limited partnership interests from their respective limited partners totaling an aggregate of $450 million as of December 31, 2010. The Fund I general partners have made an aggregate equity commitment of $6.0 million, which represents 1.32% of the total equity commitments received. The respective partnership agreements of LRR A, LRR B and LRR C provide that each general partner of Fund I can request funding of equity commitments with a minimum 10 business days notice. As of December 31, 2010, the general partners and limited partners had funded $426.7 million of the equity commitment to Fund I.

LRR C Preferred, L.P. (the "Class B Limited Partner") was formed in January 25, 2006 to serve and exercise all the rights and fulfill all the obligations of the Limited Partners — Class B of LRR C. The Class B Limited Partner's investment in LRR C includes its contributions to LRR C and is increased or decreased by any allocations of income, loss, or preferred return.

In the normal course of business, the Predecessor enters into contracts that contain a variety of representations and warranties and provide general indemnifications. The Predecessor's maximum exposure under these arrangements is unknown as this would involve future claims that may be made against the Predecessor that have not yet occurred. The Predecessor does not expect to suffer any material losses in connection with these contracts.

Various federal, state and local laws and regulations covering, among other things, the release of waste materials into the environment and state and local taxes affect the Predecessor's operations and costs. Management believes the Predecessor is in substantial compliance with applicable federal, state and local laws, and management expects that the ultimate resolution of any claims or legal proceedings instituted against the Predecessor will not have a material effect on its financial position or results of operations.

The Predecessor has performed an evaluation of subsequent events through May 4, 2011, which is the date the financial statements were made available for issuance. On April 18, 2011, the Predecessor entered into a derivative contract for natural gas financial swaps with a notional volume of 708,240 MMBtu for 2013 and 2,323,948 MMBtu for 2014 with a weighted average price of $5.245 and $5.575, respectively.

13. Supplemental Information on Oil and Natural Gas Exploration and Production Activities (Unaudited)

In December 2009, the Predecessor adopted revised oil and natural gas reserve estimation and disclosure requirements that conformed the definition of proved reserves to the Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting rules, issued by the SEC in 2008. An accounting standards update revised the definition of proved oil and natural gas reserves to require that the average first-day-of-the-month price during the 12-month period before the end of the year, rather than the year-end price, must be used when estimating whether reserve quantities are economic to produce. This same 12-month average price is also used in calculating the aggregate amount of (and changes in) future cash inflows related to the standardized measure of discounted future net cash flows. The rules also allow for the use of reliable technologies to estimate proved oil, natural gas and natural gas liquids (NGLs) reserves if those technologies have been demonstrated to result in reliable conclusions about reserve volumes.

The unaudited supplemental information on oil and natural gas exploration and production activities for 2010 and 2009 has been presented in accordance with the revised reserve estimation and disclosure rules, which were not applied retrospectively. The 2008 and prior data is presented in accordance with Financial Accounting Standards Board (FASB) oil and natural gas disclosure requirements effective during those periods.

Capitalized costs relating to oil and natural gas producing activities are as follows at December 31:

Costs Incurred in Oil and Natural Gas Property Acquisition and Development Activities

Costs incurred in oil and natural gas property acquisition and development activities are as follows for the years ended December 31:

Our predecessor had immaterial exploration costs for each of the years ended December 31, 2010, 2009 and 2008.

The reserve disclosures that follow reflect estimates of proved reserves, proved developed reserves and proved undeveloped reserves, net of third-party royalty interests, of natural gas, crude oil and condensate, and NGLs owned at each year end and changes in proved reserves during each of the last three years. Natural gas volumes are in millions of cubic feet (MMcf) at a pressure base of 14.73 pounds per square inch and volumes for oil, condensate and NGLs are in thousands of barrels (MBbls). Total volumes are presented in thousands of barrels of oil equivalent (MBOE). For this computation, one barrel of oil is assumed to be the equivalent of 6,000 cubic feet of natural gas. Shrinkage associated with NGLs has been deducted from the natural gas reserve volumes.

The Predecessor's estimates of proved reserves are made using available geological and reservoir data as well as production performance data. These estimates are reviewed annually by internal reservoir engineers and revised, either upward or downward, as warranted by additional data. Revisions are necessary due to changes in, among other things, reservoir performance, prices, economic conditions and governmental restrictions, as well as changes in the expected recovery associated with infill drilling.

The Predecessor's oil and natural gas properties and associated reserves are located in the continental United States. The following table presents the estimated remaining net proved, proved developed and proved undeveloped oil and natural gas reserves at December 31, 2010, 2009, and 2008, and the related summary of changes in estimated quantities of net remaining proved reserves during the year. The Predecessor's estimated reserves at December 31, 2010 were based on reserve reports prepared by the independent reserve engineers Miller and Lents, Ltd. and Netherland, Sewell &

Associates, Inc. The Predecessor's estimated reserves at December 31, 2009 and 2008 were based on evaluations prepared by the Predecessor's internal petroleum engineers and staff.

	2010									2009									2008

	Oil (MBbls)			NGL (MBbls)			Gas (MMcf)			Oil (MBbls)			NGL (MBbls)			Gas (MMcf)			Oil (MBbls)			NGL (MBbls)			Gas (MMcf)
Proved Reserves
Beginning of year		5,598			2,580			62,658			5,796			1,471			80,594			2,472			271			115,208
Revisions of previous estimates		92			315			6,681			(168	)		1,103			(13,178	)		1,284			1,309			(31,601	)
Extensions and discoveries		927			438			2,583			562			303			2,374			75			24			3,002
Acquisitions of minerals in place		40			97			49,560			16			66			2,629			2,592			239			5,735
Sales of minerals in place		(22	)		(9	)		(594	)		(7	)		—			(685	)		—			—			—
Production		(698	)		(376	)		(11,287	)		(602	)		(363	)		(9,076	)		(627	)		(372	)		(11,750	)

End of year		5,937			3,045			109,601			5,597			2,580			62,658			5,796			1,471			80,594

Proved developed reserves, end of year		4,970			2,605			105,465			4,398			2,191			60,668			4,601			1,037			77,547

Proved undeveloped reserves, end of year		967			440			4,136			1,199			389			1,990			1,195			434			3,047

Effective December 31, 2009, the Predecessor adopted the new requirements for oil and natural gas reserve estimation and disclosure which require that reserve estimates and discounted future net cash flows be based on the unweighted average market prices for sales of oil and natural gas on the first calendar day of each month during the year. Cash flows are adjusted for transportation fees and regional price differentials, to the estimated future production of proved oil and natural gas reserves less estimated future expenditures to be incurred in developing and producing the proved reserves, discounted using an annual rate of 10% to reflect the estimated timing of the future cash flows. Income taxes are excluded because the Predecessor is a non-taxable entity. Generally, all taxable income and losses of the Predecessor are reported on the income tax returns of the partners, and therefore, no provision for income taxes has been recorded in the Predecessor's accompanying combined financial statements. Extensive judgments are involved in estimating the timing of production and the costs that will be incurred throughout the remaining lives of the properties. Accordingly, the estimates of future net cash flows from proved reserves and the present value may be materially different from subsequent actual results. The standardized measure of discounted net cash flows does not purport to present, nor should it be interpreted to present, the fair value of the acquired properties' oil and natural gas reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, and anticipated future changes in prices and costs.

The table below reflects the standardized measure of discounted future net cash flows related to the Predecessor's interest in proved reserves as of December 31, 2010, 2009 and 2008.

The principal changes in the standardized measure of discounted future net cash flows attributable to the Predecessor's proved reserves as of December 31, 2010, 2009 and 2008 are as follows:

	Year ended December 31,

	2010			2009			2008
	(in thousands)
Beginning of period	$	192,948		$	246,567		$	315,198
Purchase of reserves in place		76,007			5,055			45,677
Sales of reserves in place		(535	)		(1,605	)		—
Extensions and discoveries, net of future development costs		46,947			18,675			9,504
Revisions of quantity estimates		23,467			(14,322	)		(31,375	)
Changes in future development costs, net		(5,148	)		4,122			73,576
Development costs incurred that reduced future development costs		4,013			1,210			5,565
Net changes in prices		77,696			(26,137	)		(64,239	)
Oil, natural gas and NGL sales, net of production costs		(82,382	)		(53,222	)		(146,943	)
Changes in timing and other		(3,910	)		(12,052	)		8,084
Accretion of discount		19,295			24,657			31,520

End of period	$	348,398		$	192,948		$	246,567

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

THIS FIRST AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF LRR ENERGY, L.P., dated as of , 2011, is entered into by and between LRE GP, LLC, a Delaware limited liability company, as the General Partner, and Lime Rock Management LP, as the Organizational Limited Partner, together with any other Persons who become Partners in the Partnership or parties hereto as provided herein. In consideration of the covenants, conditions and agreements contained herein, the parties hereto hereby agree as follows:

Section 1.1 Definitions. The following definitions shall be for all purposes, unless otherwise clearly indicated to the contrary, applied to the terms used in this Agreement.

"Acquisition" means any transaction in which any Group Member acquires (through an asset acquisition, merger, stock acquisition or other form of investment) control over all or a portion of the assets, properties or business of another Person for the purpose of increasing the production, over the long term, of the oil and gas properties owned by the Partnership Group or the operating capacity of the other assets owned by the Partnership Group from the production, over the long term, or operating capacity of the Partnership Group existing immediately prior to such transaction.

"Additional Book Basis" means the portion of any remaining Carrying Value of an Adjusted Property that is attributable to positive adjustments made to such Carrying Value as a result of Book-Up Events. For purposes of determining the extent that Carrying Value constitutes Additional Book Basis:

"Additional Book Basis Derivative Items" means any Book Basis Derivative Items that are computed with reference to Additional Book Basis. To the extent that the Additional Book Basis attributable to all of the Partnership's Adjusted Property as of the beginning of any taxable period exceeds the Aggregate Remaining Net Positive Adjustments as of the beginning of such period (the "Excess Additional Book Basis"), the Additional Book Basis Derivative Items for such period shall be reduced by the amount that bears the same ratio to the amount of Additional Book Basis Derivative Items determined without regard to this sentence as the Excess Additional Book Basis bears to the Additional Book Basis as of the beginning of such period. With respect to a Disposed of Adjusted Property, the Additional Book Basis Derivative Items shall be the amount of Additional Book Basis taken into account in computing gain or loss from the disposition of such Disposed of Adjusted Property.

"Adjusted Capital Account" means the Capital Account maintained for each Partner as of the end of each taxable period of the Partnership, (a) increased by any amounts that such Partner is obligated to

restore under the standards set by Treasury Regulation Section 1.704-1(b)(2)(ii)(c) (or is deemed obligated to restore under Treasury Regulation Sections 1.704-2(g) and 1.704-2(i)(5)) and (b) decreased by (i) the amount of all deductions in respect of depletion that, as of the end of such taxable period, are reasonably expected to be made to such Partner's Capital Account in respect of the oil and gas properties of the Partnership Group, (ii) the amount of all losses and deductions that, as of the end of such taxable period, are reasonably expected to be allocated to such Partner in subsequent taxable periods under Sections 704(e)(2) and 706(d) of the Code and Treasury Regulation Section 1.751-1(b)(2)(ii), and (iii) the amount of all distributions that, as of the end of such taxable period, are reasonably expected to be made to such Partner in subsequent taxable periods in accordance with the terms of this Agreement or otherwise to the extent they exceed offsetting increases to such Partner's Capital Account that are reasonably expected to occur during (or prior to) the taxable period in which such distributions are reasonably expected to be made (other than increases as a result of a minimum gain chargeback pursuant to Section 6.1(d)(i) or 6.1(d)(ii)). The foregoing definition of Adjusted Capital Account is intended to comply with the provisions of Treasury Regulation Section 1.704-1(b)(2)(ii)(d) and shall be interpreted consistently therewith. The "Adjusted Capital Account" of a Partner in respect of any Partnership Interest shall be the amount that such Adjusted Capital Account would be if such Partnership Interest were the only interest in the Partnership held by such Partner from and after the date on which such Partnership Interest was first issued.

"Adjusted Operating Surplus" means, with respect to any period, (a) Operating Surplus generated with respect to such period; (b) less (i) the amount of any net increase in Working Capital Borrowings (or the Partnership's proportionate share of any net increase in Working Capital Borrowings in the case of Subsidiaries that are not wholly owned) with respect to that period; and (ii) the amount of any net decrease in cash reserves (or the Partnership's proportionate share of any net decrease in cash reserves in the case of Subsidiaries that are not wholly owned) for Operating Expenditures with respect to such period not relating to an Operating Expenditure made with respect to such period; and (c) plus (i) the amount of any net decrease in Working Capital Borrowings (or the Partnership's proportionate share of any net decrease in Working Capital Borrowings in the case of Subsidiaries that are not wholly owned) with respect to that period; (ii) the amount of any net increase in cash reserves (or the Partnership's proportionate share of any net increase in cash reserves in the case of Subsidiaries that are not wholly owned) for Operating Expenditures with respect to such period required by any debt instrument for the repayment of principal, interest or premium; and (iii) 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 in Adjusted Operating Surplus in subsequent periods pursuant to clause (b)(ii) above. Adjusted Operating Surplus does not include that portion of Operating Surplus included in clause (a)(i) of the definition of Operating Surplus.

"Adjusted Property" means any property the Carrying Value of which has been adjusted pursuant to Section 5.5(d)(i) or 5.5(d)(ii).

"Affiliate" means, with respect to any Person, any other Person that directly or indirectly through one or more intermediaries controls, is controlled by or is under common control with, the Person in question. As used herein, the term "control" means the possession, direct or indirect, of the power to direct or cause the direction of the management and policies of a Person, whether through ownership of voting securities, by contract or otherwise.

"Aggregate Remaining Net Positive Adjustments" means, as of the end of any taxable period, the sum of the Remaining Net Positive Adjustments of all the Partners.

"Agreed Allocation" means any allocation, other than a Required Allocation, of an item of income, gain, loss or deduction pursuant to the provisions of Section 6.1, including a Curative Allocation (if appropriate to the context in which the term "Agreed Allocation" is used).

"Agreed Value" of any Contributed Property means the fair market value of such property at the time of contribution and in the case of an Adjusted Property, the fair market value of such Adjusted Property on the date of the revaluation event as described in Section 5.5(d), in both cases as determined by the General Partner.

"Agreement" means this First Amended and Restated Agreement of Limited Partnership of LRR Energy, L.P., as it may be amended, supplemented or restated from time to time.

"Associate" means, when used to indicate a relationship with any Person, (a) any corporation or organization of which such Person is a director, officer, manager, general partner or managing member or is, directly or indirectly, the owner of 20% or more of any class of voting stock or other voting interest; (b) any trust or other estate in which such Person has at least a 20% beneficial interest or as to which such Person serves as trustee or in a similar fiduciary capacity; and (c) any relative or spouse of such Person, or any relative of such spouse, who has the same principal residence as such Person.

"Available Cash" means, with respect to any Quarter ending prior to the Liquidation Date:

provided, however, that the General Partner may not establish cash reserves pursuant to clause (b)(iii) above unless the General Partner determines that the effect of such reserves would not be that the Partnership is unable to distribute the Minimum Quarterly Distribution on all Common Units, plus any Cumulative Common Unit Arrearage on all Common Units, with respect to such Quarter; and, provided further, that disbursements made by a Group Member or cash reserves established, increased or reduced after the end of any such Quarter but on or before the date of determination of Available Cash with respect to such Quarter shall be deemed to have been made, established, increased or reduced, for purposes of determining Available Cash, within such Quarter if the General Partner so determines.

Notwithstanding the foregoing, "Available Cash" with respect to the Quarter in which the Liquidation Date occurs and any subsequent Quarter shall equal zero.

"Board of Directors" means the board of directors or board of managers, as applicable, of the General Partner or, if the General Partner is a limited partnership, the board of directors or board of managers of the general partner of the General Partner.

"Book Basis Derivative Items" means any item of income, deduction, gain or loss that is computed with reference to the Carrying Value of an Adjusted Property (e.g., depreciation, depletion, or gain or loss with respect to an Adjusted Property).

"Book-Down Event" means an event that triggers a negative adjustment to the Capital Accounts of the Partners pursuant to Section 5.5(d).

"Book-Tax Disparity" means, with respect to any item of Contributed Property or Adjusted Property, as of the date of any determination, the difference between the Carrying Value of such Contributed Property or Adjusted Property and the adjusted basis thereof for federal income tax purposes as of such date. A Partner's share of the Partnership's Book-Tax Disparities in all of its Contributed Property and Adjusted Property will be reflected by the difference between such Partner's Capital Account balance as maintained pursuant to Section 5.5 and the hypothetical balance of such Partner's Capital Account computed as if it had been maintained strictly in accordance with federal income tax accounting principles.

"Book-Up Event" means an event that triggers a positive adjustment to the Capital Accounts of the Partners pursuant to Section 5.5(d).

"Business Day" means Monday through Friday of each week, except that a legal holiday recognized as such by the government of the United States of America or the State of Texas shall not be regarded as a Business Day.

"Capital Account" means the capital account maintained for a Partner pursuant to Section 5.5. The "Capital Account" of a Partner in respect of any Partnership Interest shall be the amount that such Capital Account would be if such Partnership Interest were the only interest in the Partnership held by such Partner from and after the date on which such Partnership Interest was first issued.

"Capital Contribution" means any cash, cash equivalents or the Net Agreed Value of Contributed Property that a Partner contributes to the Partnership or that is contributed or deemed contributed to the Partnership on behalf of a Partner (including, in the case of an underwritten offering of Units, the amount of any underwriting discounts or commissions).

"Capital Improvement" means any (a) addition or improvement to the capital assets owned by any Group Member, (b) acquisition of existing, or the construction of new or the improvement or replacement of existing, capital assets or (c) capital contribution by a Group Member to a Person that is not a Subsidiary in which a Group Member has, or after such capital contribution will have, an equity interest to fund such Group Member's pro rata share of the cost of the addition or improvement to or the acquisition of existing, or the construction of new, or the improvement or replacement of existing, capital assets by such Person, in each case if such addition, improvement, replacement, acquisition or construction is made to increase the production, over the long term, from oil and gas properties of the Partnership Group or the operating capacity of other assets of the Partnership Group, in the case of clauses (a) and (b), or such Person, in the case of clause (c), from the production, over the long term, or operating capacity of the Partnership Group or such Person, as the case may be, existing immediately prior to such addition, improvement, replacement, acquisition or construction.

"Capital Surplus" means Available Cash distributed by the Partnership in excess of Operating Surplus, as described in Section 6.3(a).

"Carrying Value" means (a) with respect to a Contributed Property or Adjusted Property, the Agreed Value of such property reduced (but not below zero) by all depreciation, Simulated Depletion, amortization and cost recovery deductions charged to the Partners' Capital Accounts in respect of such property and (b) with respect to any other Partnership property, the adjusted basis of such property for federal income tax purposes, all as of the time of determination; provided, however, that the Carrying Value of any property shall be adjusted from time to time in accordance with Section 5.5(d) and to

reflect changes, additions or other adjustments to the Carrying Value for dispositions and acquisitions of Partnership properties, as deemed appropriate by the General Partner.

"Cause" means a court of competent jurisdiction has entered a final, non-appealable judgment finding the General Partner liable for actual fraud or willful misconduct in its capacity as a general partner of the Partnership.

"Certificate" means a certificate in such form (including global form if permitted by applicable rules and regulations) as may be adopted by the General Partner, issued by the Partnership evidencing ownership of one or more Partnership Interests. The initial form of certificate approved by the General Partner for Common Units is attached as Exhibit A to this Agreement.

"Certificate of Limited Partnership" means the Certificate of Limited Partnership of the Partnership filed with the Secretary of State of the State of Delaware as referenced in Section 7.2, as such Certificate of Limited Partnership may be amended, supplemented or restated from time to time.

"Citizenship Certification" means a properly completed certificate in such form as may be specified by the General Partner by which a Limited Partner certifies that he (and if he is a nominee holding for the account of another Person, that to the best of his knowledge such other Person) is an Eligible Citizen Holder.

"class" or "classes" means the classes of Units into which Partnership Interests may be classified or divided from time to time by the General Partner in its sole discretion pursuant to the provisions of this Agreement. As of the date of this Agreement, the only classes are the Common Units and the Subordinated Units. Subclasses within a class shall not be separate classes for purposes of this Agreement. For all purposes hereunder and under the Act, only such classes expressly established under this Agreement, including by the General Partner in accordance with this Agreement, shall be deemed to be classes of Partnership Interests or Limited Partner Interests in the Partnership.

"Closing Date" means the closing date of the sale of Common Units in the Initial Public Offering.

"Closing Price" means, in respect of any class of Limited Partner Interests, as of the date of determination, the last sale price on such day, regular way, or in case no such sale takes place on such day, the average of the closing bid and asked prices on such day, regular way, in either case as reported in the principal consolidated transaction reporting system with respect to securities listed or admitted to trading on the principal National Securities Exchange on which the respective Limited Partner Interests are listed or admitted to trading or, if such Limited Partner Interests are not listed or admitted to trading on any National Securities Exchange, the last quoted price on such day or, if not so quoted, the average of the high bid and low asked prices on such day in the over-the-counter market, as reported by the primary reporting system then in use in relation to such Limited Partner Interests of such class, or, if on any such day such Limited Partner Interests of such class are not quoted by any such organization, the average of the closing bid and asked prices on such day as furnished by a professional market maker making a market in such Limited Partner Interests of such class selected by the General Partner, or if on any such day no market maker is making a market in such Limited Partner Interests of such class, the fair value of such Limited Partner Interests on such day as determined by the General Partner.

"Code" means the Internal Revenue Code of 1986, as amended and in effect from time to time. Any reference herein to a specific section or sections of the Code shall be deemed to include a reference to any corresponding provision of any successor law.

"Commences Commercial Service" means the date on which a Capital Improvement begins producing in paying quantities or is first placed into commercial service by a Group Member following completion of construction, acquisition, development and testing, as applicable.

"Commission" means the United States Securities and Exchange Commission or any successor agency having jurisdiction under the Securities Act.

"Common Unit" means a Partnership Interest representing a fractional part of the Partnership Interests of all Limited Partners and having the rights and obligations specified with respect to a Common Unit in this Agreement. The term "Common Unit" does not include a Subordinated Unit prior to its conversion into a Common Unit pursuant to the terms hereof.

"Common Unit Arrearage" means, with respect to any Common Unit, whenever issued, with respect to any Quarter within the Subordination Period, the excess, if any, of (a) the Minimum Quarterly Distribution with respect to a Common Unit in respect of such Quarter over (b) the sum of all Available Cash distributed with respect to a Common Unit in respect of such Quarter pursuant to Section 6.4(a)(i).

"Conflicts Committee" means a committee of the Board of Directors composed entirely of one or more directors who (a) are not (i) officers or employees of the General Partner, (ii) officers, directors or employees of any Affiliate of the General Partner (other than Group Members) or (iii) holders of any ownership interest in the General Partner or any of its Affiliates, including any Group Member other than Common Units, or securities exercisable, convertible into or exchangeable for Common Units and (b) also meet the independence standards required of directors who serve on an audit committee of a board of directors established by the Securities Exchange Act and the rules and regulations of the Commission thereunder and by the National Securities Exchange on which any class of Partnership Interests is listed or admitted to trading.

"Contributed Property" means each property, in such form as may be permitted by the Delaware Act, but excluding cash, contributed to the Partnership. Once the Carrying Value of a Contributed Property is adjusted pursuant to Section 5.5(d), such property shall no longer constitute a Contributed Property, but shall be deemed an Adjusted Property.

"Contribution Agreement" means that certain Purchase, Sale, Contribution, Conveyance and Assumption Agreement, dated as of , 2011, among the General Partner, the Partnership, LRE Operating and the other parties thereto, together with the additional conveyance documents and instruments contemplated or referenced thereunder, as such may be amended, supplemented or restated from time to time.

"Cumulative Common Unit Arrearage" means, with respect to any Common Unit, whenever issued, and as of the end of any Quarter, the excess, if any, of (a) the sum of the Common Unit Arrearages with respect to an Initial Common Unit for each of the Quarters within the Subordination Period ending on or before the last day of such Quarter over (b) the sum of any distributions theretofore made pursuant to Section 6.4(a)(ii) and the second sentence of Section 6.5 with respect to an Initial Common Unit (including any distributions to be made in respect of the last of such Quarters).

"Curative Allocation" means any allocation of an item of income, gain, deduction, loss or credit pursuant to the provisions of Section 6.1(d)(xi).

"Current Market Price" means, in respect of any class of Limited Partner Interests, as of the date of determination, the average of the daily Closing Prices per Limited Partner Interest of such class for the 20 consecutive Trading Days immediately prior to such date.

"Delaware Act" means the Delaware Revised Uniform Limited Partnership Act, 6 Del. C. Section 17-101, et. seq., as amended, supplemented or restated from time to time, and any successor to such statute.

"Deferred Issuance and Distribution" means both (a) the issuance by the Partnership of a number of additional Common Units that is equal to the excess, if any, of (x) 1,411,200 minus (y) the aggregate number, if any, of Common Units actually purchased by and issued to the Underwriters pursuant to the Over-Allotment Option on the Option Closing Date(s) and (b) the payment by the Partnership to the Fund Group of cash in an amount equal to the aggregate amount of cash, if any, contributed by the

Underwriters to the Partnership on or in connection with any Option Closing Date with respect to Common Units issued by the Partnership upon the applicable exercise of the Over-Allotment Option as described in Section 5.3(b), if any.

"Departing General Partner" means a former General Partner from and after the effective date of any withdrawal or removal of such former General Partner pursuant to Section 11.1 or Section 11.2.

"Economic Risk of Loss" has the meaning set forth in Treasury Regulation Section 1.752-2(a).

"Eligibility Certification" means a Citizenship Certification or a Rate Eligibility Certification.

"Eligible Citizen Holder" means (A) (i) a citizen of the United States; (ii) a corporation organized under the laws of the United States or of any state thereof; (iii) a public body of the United States, including a municipality of the United States; or (iv) 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, and (B) a Limited Partner whose nationality, citizenship or other related status would not, in the determination of the General Partner, create a substantial risk of cancellation or forfeiture of any property in which a Group Member has an interest.

"Estimated Maintenance Capital Expenditures" means an estimate made in good faith by the Board of Directors (with the concurrence of the Conflicts Committee) of the average quarterly Maintenance Capital Expenditures that the Partnership will need to incur to maintain production levels of the oil and gas properties of the Partnership Group over the long term or the operating capacity of the other assets of the Partnership Group over the long term (including the Partnership's proportionate share of the average quarterly Maintenance Capital Expenditures of its Subsidiaries that are not wholly owned) existing at the time the estimate is made. The Board of Directors (with the concurrence of the Conflicts Committee) will be permitted to make such estimate in any manner it determines reasonable. 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 future Estimated Maintenance Capital Expenditures. The Partnership shall disclose to its Partners any change in the amount of Estimated Maintenance Capital Expenditures in its reports made in accordance with Section 8.3 to the extent not previously disclosed. Any adjustments to Estimated Maintenance Capital Expenditures shall be prospective only.

"Excess Additional Book Basis" (as used in the definition of Additional Book Basis Derivative Items) is defined in the definition of Additional Book Basis Derivative Items.

"First Target Distribution" means $0.54625 per Unit per Quarter (or, with respect to periods of less than a full fiscal quarter, it means the product of such amount multiplied by a fraction of which the

numerator is the number of days in such period, and the denominator is the total number of days in such fiscal quarter), subject to adjustment in accordance with Sections 5.11, 6.6 and 6.9.

"Fully Diluted Basis" means, when calculating the number of Outstanding Units for any period, a basis that includes, in addition to the Outstanding Units, all Partnership Interests and options, rights, warrants and appreciation rights relating to an equity interest in the Partnership (a) that are convertible into or exercisable or exchangeable for Units that are senior to or pari passu with the Subordinated Units, (b) whose conversion, exercise or exchange price is less than the Current Market Price on the date of such calculation, (c) that may be converted into or exercised or exchanged for such Units prior to or during the Quarter immediately following the end of the period for which the calculation is being made without the satisfaction of any contingency beyond the control of the holder other than the payment of consideration and the compliance with administrative mechanics applicable to such conversion, exercise or exchange and (d) that were not converted into or exercised or exchanged for such Units during the period for which the calculation is being made; provided, however, that for purposes of determining the number of Outstanding Units on a Fully Diluted Basis when calculating whether the Subordination Period has ended or Subordinated Units are entitled to convert into Common Units pursuant to Section 5.7, such Partnership Interests, options, rights, warrants and appreciation rights shall be deemed to have been Outstanding Units only for the four Quarters that comprise the last four Quarters of the measurement period; provided, further, that if consideration will be paid to any Group Member in connection with such conversion, exercise or exchange, the number of Units to be included in such calculation shall be that number equal to the difference between (i) the number of Units issuable upon such conversion, exercise or exchange and (ii) the number of Units that such consideration would purchase at the Current Market Price.

"General Partner" means LRE GP, LLC, a Delaware limited liability company, and its successors and permitted assigns that are admitted to the Partnership as general partner of the Partnership, in its capacity as general partner of the Partnership (except as the context otherwise requires).

"General Partner Interest" means the ownership interest of the General Partner in the Partnership (in its capacity as a general partner without reference to any Limited Partner Interest held by it), which is evidenced by General Partner Units, and includes any and all benefits to which the General Partner is entitled as provided in this Agreement, together with all obligations of the General Partner to comply with the terms and provisions of this Agreement.

"General Partner Unit" means a fractional part of the General Partner Interest having the rights and obligations specified with respect to the General Partner Interest. A General Partner Unit is not a Unit.

"Gross Liability Value" means, with respect to any Liability of the Partnership described in Treasury Regulation Section 1.752-7(b)(3)(i), the amount of cash that a willing assignor would pay to a willing assignee to assume such Liability in an arm's-length transaction.

"Group" means a Person that with or through any of its Affiliates or Associates has any contract, arrangement, understanding or relationship for the purpose of acquiring, holding, voting (except voting pursuant to a revocable proxy or consent given to such Person in response to a proxy or consent solicitation made to 10 or more Persons), exercising investment power or disposing of any Partnership Interests with any other Person that beneficially owns, or whose Affiliates or Associates beneficially own, directly or indirectly, Partnership Interests.

"Group Member Agreement" means the partnership agreement of any Group Member, other than the Partnership, that is a limited or general partnership, the limited liability company agreement of any Group Member that is a limited liability company, the certificate of incorporation and bylaws or similar

organizational documents of any Group Member that is a corporation, the joint venture agreement or similar governing document of any Group Member that is a joint venture and the governing or organizational or similar documents of any other Group Member that is a Person other than a limited or general partnership, limited liability company, corporation or joint venture, as such may be amended, supplemented or restated from time to time.

"Growth Capital Expenditures" means cash expenditures for Acquisitions or Capital Improvements, and shall not include Maintenance Capital Expenditures or Investment Capital Expenditures. Growth Capital Expenditures shall include interest (and related fees) on debt incurred to finance the construction of a Capital Improvement and paid in respect of the period beginning on the date that a Group Member enters into a binding obligation to commence construction of a Capital Improvement and ending on the earlier to occur of the date that such Capital Improvement Commences Commercial Service and the date that such Capital Improvement is abandoned or disposed of. Debt incurred to fund such construction period interest payments or to fund distributions in respect of equity issued (including incremental Incentive Distributions related thereto) to fund the construction of a Capital Improvement as described in clause (a)(iv) of the definition of Operating Surplus shall also be deemed to be debt incurred to finance the construction of a Capital Improvement. Where capital expenditures are made in part for Growth Capital Expenditures and in part for other purposes, the General Partner shall determine the allocation between the amounts paid for each.

"Hedge Contract" means any exchange, swap, forward, cap, floor, collar, option or other similar agreement or arrangement entered into for the purpose of reducing the exposure of the Partnership Group to fluctuations in interest rates, the price of hydrocarbons, basis differentials or currency exchange rates in their operations and not for speculative purposes.

"Incentive Distribution Right" means a non-voting Limited Partner Interest, initially issued to the General Partner, which Limited Partner Interest will confer upon the holder thereof only the rights and obligations specifically provided in this Agreement with respect to Incentive Distribution Rights (and no other rights otherwise available to or other obligations of a holder of a Partnership Interest). Notwithstanding anything in this Agreement to the contrary, the holder of an Incentive Distribution Right shall not be entitled to vote such Incentive Distribution Right on any Partnership matter except as may otherwise be required by law.

"Incentive Distributions" means any amount of cash distributed to the holders of the Incentive Distribution Rights (in such capacity, but not in any other capacity) pursuant to Section 6.4(a)(v) and (vi) and 6.4(b)(iii) and (iv).

"Indemnitee" means (a) any General Partner, (b) any Departing General Partner, (c) any Person who is or was an Affiliate of the General Partner or any Departing General Partner, (d) any Person who is or was a manager, managing member, general partner, director, officer, employee, agent, fiduciary or trustee of any Group Member, a General Partner, any Departing General Partner or any of their respective Affiliates, (e) any Person who is or was serving at the request of a General Partner, any Departing General Partner or any of their respective Affiliates as an officer, director, manager, managing member, general partner, employee, agent, fiduciary or trustee of another Person owing a fiduciary duty to any Group Member; provided, however, that a Person shall not be an Indemnitee by reason of providing, on a fee-for-services basis, trustee, fiduciary or custodial services, (f) any Person who controls a General Partner or Departing General Partner and (g) any Person the General Partner designates as an "Indemnitee" for purposes of this Agreement because such Person's service, status or relationship exposes such Person to potential claims, demands, actions, suits or proceedings relating to the Partnership Group's business and affairs.

"Ineligible Citizen Holder" means a Person whom the General Partner has determined does not constitute an Eligible Citizen Holder and as to whose Partnership Interest the General Partner has become the substitute Limited Partner, pursuant to Section 4.9(a).

"Ineligible Holder" means an Ineligible Citizen Holder or a Rate Ineligible Holder.

"Initial Common Unit" means a Common Unit issued in the Initial Public Offering.

"Initial Limited Partners" means each of LRR-A, LRR-B, LRR-C, the General Partner (with respect to the Incentive Distribution Rights it holds) and the Underwriters, in each case upon being admitted to the Partnership in accordance with Section 10.1.

"Initial Public Offering" means the initial public offering of Common Units by the Partnership, as described in the Registration Statement, including any Common Units issued pursuant to the exercise of the Over-Allotment Option.

"Initial Unit Price" means (a) with respect to the Common Units and the Subordinated Units, the initial public offering price per Common Unit at which the Underwriters offered the Common Units to the public for sale as set forth on the cover page of the prospectus included as part of the Registration Statement and first issued at or after the time the Registration Statement first became effective or (b) with respect to any other class or series of Units, the price per Unit at which such class or series of Units is initially sold by the Partnership, as determined by the General Partner, in each case adjusted as the General Partner determines to be appropriate to give effect to any distribution, subdivision or combination of Units.

"Interim Capital Transactions" means the following transactions if they occur prior to the Liquidation Date: (a) borrowings, refinancings or refundings of indebtedness (other than Working Capital Borrowings and other than for items purchased on open account or for a deferred purchase price in the ordinary course of business) by any Group Member and sales of debt securities of any Group Member; (b) sales of equity interests of any Group Member (including the Common Units sold to the Underwriters in the Initial Public Offering); (c) sales or other voluntary or involuntary dispositions of any assets of any Group Member other than (i) sales or other dispositions of inventory, accounts receivable and other assets in the ordinary course of business, and (ii) sales or other dispositions of assets as part of normal retirements or replacements; (d) capital contributions received; and (e) corporate reorganizations or restructurings.

"Investment Capital Expenditures" means capital expenditures other than Maintenance Capital Expenditures and Growth Capital Expenditures.

"LRE Operating" means LRE Operating, LLC, a Delaware limited liability company, and any successors thereto.

"LRR-A" means Lime Rock Resources A, L.P., a Delaware limited partnership, and any successors thereto.

"LRR-B" means Lime Rock Resources B, L.P., a Delaware limited partnership, and any successors thereto.

"LRR-C" means Lime Rock Resources C, L.P., a Delaware limited partnership, and any successors thereto.

"Liability" means any liability or obligation of any nature, whether accrued, contingent or otherwise.

"Limited Partner" means, unless the context otherwise requires, (a) the Organizational Limited Partner prior to its withdrawal from the Partnership, each Initial Limited Partner, each additional Person that becomes a Limited Partner pursuant to the terms of this Agreement and any Departing General Partner upon the change of its status from General Partner to Limited Partner pursuant to Section 11.3,

in each case, in such Person's capacity as a limited partner of the Partnership; provided, however, that when the term "Limited Partner" is used herein in the context of any vote or other approval, including Articles XIII and XIV, such term shall not, solely for such purpose, include any holder of an Incentive Distribution Right (solely with respect to its Incentive Distribution Rights and not with respect to any other Limited Partner Interest held by such Person) except as may be required by law.

"Limited Partner Interest" means the ownership interest of a Limited Partner in the Partnership, which may be evidenced by Common Units, Subordinated Units, Incentive Distribution Rights or other Partnership Interests or a combination thereof or interest therein, and includes any and all benefits to which such Limited Partner is entitled as provided in this Agreement, together with all obligations of such Limited Partner to comply with the terms and provisions of this Agreement; provided, however, that when the term "Limited Partner Interest" is used herein in the context of any vote or other approval, including Articles XIII and XIV, such term shall not, solely for such purpose, include any Incentive Distribution Right except as may be required by law.

"Liquidation Date" means (a) in the case of an event giving rise to the dissolution of the Partnership of the type described in clauses (a) and (b) of the first sentence of Section 12.2, the date on which the applicable time period during which the holders of Outstanding Units have the right to elect to continue the business of the Partnership and appoint a successor General Partner has expired without such an election and appointment being made, and (b) in the case of any other event giving rise to the dissolution of the Partnership, the date on which such event occurs.

"Liquidator" means one or more Persons selected pursuant to Section 12.3 to perform the functions described in Section 12.4 as liquidating trustee of the Partnership within the meaning of the Delaware Act.

"Maintenance Capital Expenditures" means cash expenditures (including expenditures for the addition or improvement to or replacement of the capital assets owned by any Group Member or for the acquisition of existing, or the construction or development of new, capital assets) if such expenditures are made to maintain the current production levels of the oil and gas properties of the Partnership Group over the long term or the operating capacity of the other assets of the Partnership Group over the long term. Maintenance Capital Expenditures shall not include (a) Growth Capital Expenditures or (b) Investment Capital Expenditures. Maintenance Capital Expenditures shall include interest (and related fees) on debt incurred and distributions on equity issued (including Incentive Distributions), other than equity issued on the Closing Date or the Option Closing Date, in each case, to finance the construction or development of a replacement asset and paid during the period beginning on the date that a Group Member enters into a binding obligation to commence constructing or developing a replacement asset and ending on the earlier to occur of the date that such replacement asset Commences Commercial Service and the date that such replacement asset is abandoned or disposed of. Debt incurred to pay or equity issued (other than equity issued on the Closing Date or the Option Closing Date), to fund construction or development period interest payments, or such construction or development period distributions on equity, shall also be deemed to be debt or equity, as the case may be, incurred to finance the construction or development of a replacement asset and the incremental Incentive Distributions paid relating to newly issued equity shall be deemed to be distributions paid on equity issued to finance the construction or development of a replacement asset.

"Minimum Quarterly Distribution" means $0.4750 per Unit per Quarter (or with respect to periods of less than a full fiscal quarter, it means the product of such amount multiplied by a fraction of which the numerator is the number of days in such period and the denominator is the total number of days in such quarter), subject to adjustment in accordance with Sections 5.11, 6.6 and 6.9.

"National Securities Exchange" means an exchange registered with the Commission under Section 6(a) of the Securities Exchange Act (or any successor to such Section) and any other securities

exchange (whether or not registered with the Commission under Section 6(a) (or successor to such Section) of the Securities Exchange Act) that the General Partner shall designate as a National Securities Exchange for purposes of this Agreement.

"Net Agreed Value" means (a) in the case of any Contributed Property, the Agreed Value of such property reduced by any Liabilities either assumed by the Partnership upon such contribution or to which such property is subject when contributed and (b) in the case of any property distributed to a Partner by the Partnership, the Partnership's Carrying Value of such property (as adjusted pursuant to Section 5.5(d)(ii)) at the time such property is distributed, reduced by any Liabilities either assumed by such Partner upon such distribution or to which such property is subject at the time of distribution.

"Net Income" means, for any taxable period, the excess, if any, of the Partnership's items of income and gain (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable period over the Partnership's items of loss and deduction (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable period. The items included in the calculation of Net Income shall be determined in accordance with Section 5.5(b) and shall include Simulated Gain, but shall not include any items specially allocated under Section 6.1(d) or Section 6.1(e); provided that the determination of the items that have been specially allocated under Section 6.1(d) or Section 6.1(e) shall be made without regard to any reversal of such items under Section 6.1(d)(xii).

"Net Loss" means, for any taxable period, the excess, if any, of the Partnership's items of loss and deduction (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable period over the Partnership's items of income and gain (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable period. The items included in the calculation of Net Loss shall be determined in accordance with Section 5.5(b) and shall include Simulated Gain but shall not include any items specially allocated under Section 6.1(d) or Section 6.1(e); provided, however, that the determination of the items that have been specially allocated under Section 6.1(d) shall be made without regard to any reversal of such items under Section 6.1(d)(xii).

"Net Positive Adjustments" means, with respect to any Partner, the excess, if any, of the total positive adjustments over the total negative adjustments made to the Capital Account of such Partner pursuant to Book-Up Events and Book-Down Events.

"Net Termination Gain" means, for any taxable period, the sum, if positive, of all items of income, gain, loss or deduction (determined in accordance with Section 5.5(b)) that are (a) recognized by the Partnership (i) after the Liquidation Date or (ii) upon the sale, exchange or other disposition of all or substantially all of the assets of the Partnership Group, taken as a whole, in a single transaction or a series of related transactions (excluding any disposition to a member of the Partnership Group), or (b) deemed recognized by the Partnership pursuant to Section 5.5(d); provided the items included in the determination of Net Termination Gain shall include Simulated Gain, but shall not include any items of income, gain or loss specially allocated under Section 6.1(d) or Section 6.1(e).

"Net Termination Loss" means, for any taxable period, the sum, if negative, of all items of income, gain, loss or deduction (determined in accordance with Section 5.5(b)) that are (a) recognized by the Partnership (i) after the Liquidation Date or (ii) upon the sale, exchange or other disposition of all or substantially all of the assets of the Partnership Group, taken as a whole, in a single transaction or a series of related transactions (excluding any disposition to a member of the Partnership Group), or (b) deemed recognized by the Partnership pursuant to Section 5.5(d); provided, however, that, items included in the determination of Net Termination Loss shall include Simulated Gain, but shall not include any items of income, gain or loss specially allocated under Section 6.1(d) or Section 6.1(e).

"Nonrecourse Built-in Gain" means, with respect to any Contributed Properties or Adjusted Properties that are subject to a mortgage or pledge securing a Nonrecourse Liability, the amount of any

taxable gain that would be allocated to the Partners pursuant to Section 6.2(b) if such properties were disposed of in a taxable transaction in full satisfaction of such liabilities and for no other consideration.

"Nonrecourse Deductions" means any and all items of loss, deduction, expenditure (including any expenditure described in Section 705(a)(2)(B) of the Code), Simulated Depletion or Simulated Loss that, in accordance with the principles of Treasury Regulation Section 1.704-2(b), are attributable to a Nonrecourse Liability.

"Nonrecourse Liability" has the meaning set forth in Treasury Regulation Section 1.752-1(a)(2).

"Omnibus Agreement" means the Omnibus Agreement, dated as of the Closing Date, among the Partnership, the General Partner, LRE Operating, LRR-A, LRR-B, LRR-C and the other parties thereto, as such may be amended, supplemented or restated from time to time.

"Operating Expenditures" means all Partnership Group cash expenditures (or the Partnership's proportionate share of expenditures in the case of Subsidiaries that are not wholly owned), including taxes, reimbursements of expenses of the General Partner and its Affiliates, payments made in the ordinary course of business under any Hedge Contracts, officer compensation, repayment of Working Capital Borrowings, debt service payments and Estimated Maintenance Capital Expenditures, subject to the following:

"Operating Surplus" means, with respect to any period ending prior to the Liquidation Date, on a cumulative basis and without duplication,

provided, however, that disbursements made (including contributions to a Group Member or disbursements on behalf of a Group Member) or cash reserves established, increased or reduced after the end of such period but on or before the date of determination of Available Cash with respect to such period shall be deemed to have been made, established, increased or reduced, for purposes of determining Operating Surplus, within such period if the General Partner so determines.

Notwithstanding the foregoing, "Operating Surplus" with respect to the Quarter in which the Liquidation Date occurs and any subsequent Quarter shall equal zero. Cash receipts from an Investment Capital Expenditure shall be treated as cash receipts only to the extent they are a return on principal, but in no event shall a return of principal be treated as cash receipts.

"Opinion of Counsel" means a written opinion of counsel (who may be regular counsel to the Partnership or the General Partner or any of its Affiliates) acceptable to the General Partner.

"Option Closing Date" means the date or dates on which any Common Units are sold by the Partnership to the Underwriters upon exercise of the Over-Allotment Option.

"Organizational Limited Partner" means Lime Rock Management LP in its capacity as the organizational limited partner of the Partnership pursuant to this Agreement.

"Outstanding" means, with respect to Partnership Interests, all Partnership Interests that are issued by the Partnership and reflected as outstanding on the Partnership's books and records as of the date of determination; provided, however, that if at any time any Person or Group (other than the General Partner or its Affiliates) beneficially owns 20% or more of the Outstanding Partnership Interests of any class then Outstanding, all Partnership Interests owned by such Person or Group shall not be entitled to be voted on any matter and shall not be considered to be Outstanding when sending notices of a meeting of Limited Partners to vote on any matter (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under this

Agreement, except that Partnership Interests so owned shall be considered to be Outstanding for purposes of Section 11.1(b)(iv) (such Partnership Interests shall not, however, be treated as a separate class of Partnership Interests for purposes of this Agreement or the Delaware Act); provided, further, that the foregoing limitation shall not apply to (i) any Person or Group who acquired 20% or more of the Outstanding Partnership Interests of any class then Outstanding directly from the General Partner or its Affiliates (other than the Partnership), (ii) any Person or Group who acquired 20% or more of the Outstanding Partnership Interests of any class then Outstanding directly or indirectly from a Person or Group described in clause (i) provided, that the General Partner shall have notified such Person or Group in writing that such limitation shall not apply, or (iii) any Person or Group who acquired 20% or more of any Partnership Interests issued by the Partnership if the General Partner shall have notified such Person or Group in writing that such limitation shall not apply.

"Over-Allotment Option" means the over-allotment option granted to the Underwriters by the Partnership pursuant to the Underwriting Agreement.

"Partner Nonrecourse Debt" has the meaning set forth in Treasury Regulation Section 1.704-2(b)(4).

"Partner Nonrecourse Debt Minimum Gain" has the meaning set forth in Treasury Regulation Section 1.704-2(i)(2).

"Partner Nonrecourse Deductions" means any and all items of loss, deduction, expenditure (including any expenditure described in Section 705(a)(2)(B) of the Code), Simulated Depletion or Simulated Loss that, in accordance with the principles of Treasury Regulation Section 1.704-2(i), are attributable to a Partner Nonrecourse Debt.

"Partnership Group" means the Partnership and its Subsidiaries treated as a single consolidated entity.

"Partnership Interest" means any class or series of equity interest in the Partnership, which shall include the General Partner Interest and any Limited Partner Interests but shall exclude any options, rights, warrants and appreciation rights relating to any equity interest in the Partnership.

"Partnership Minimum Gain" means that amount determined in accordance with the principles of Treasury Regulation Section 1.704-2(d).

"Percentage Interest" means as of any date of determination (a) as to the General Partner, with respect to the General Partner Interest (calculated based upon a number of General Partner Units), and as to any Unitholder with respect to Units, the product obtained by multiplying (i) 100% less the percentage applicable to clause (b) below by (ii) the quotient obtained by dividing (A) the number of General Partner Units held by the General Partner or the number of Units held by such Unitholder, as the case may be, by (B) the total number of Outstanding Units and General Partner Units, and (b) as to the holders of other Partnership Interests issued by the Partnership in accordance with Section 5.6, the percentage established as a part of such issuance. The Percentage Interest with respect to an Incentive Distribution Right shall at all times be zero.

"Person" means an individual or a corporation, firm, limited liability company, partnership, joint venture, trust, unincorporated organization, association, government agency or political subdivision thereof or other entity.

"Per Unit Capital Amount" means, as of any date of determination, the Capital Account, stated on a per Unit basis, underlying any class of Units held by a Person other than the General Partner or any Affiliate of the General Partner who holds Units.

"Pro Rata" means (a) when used with respect to Units or any class thereof, apportioned equally among all designated Units in accordance with their relative Percentage Interests, (b) when used with respect to Partners or Record Holders, apportioned among all Partners or Record Holders in accordance with their relative Percentage Interests and (c) when used with respect to holders of Incentive Distribution Rights, apportioned equally among all holders of such Incentive Distribution Rights in accordance with the relative number or percentage of such Incentive Distribution Rights held by each such holder.

"Purchase Date" means the date determined by the General Partner as the date for purchase of all Outstanding Limited Partner Interests of a certain class (other than Limited Partner Interests owned by the General Partner and its Affiliates) pursuant to Article XV.

"Quarter" means, unless the context requires otherwise, a fiscal quarter of the Partnership, or, with respect to the fiscal quarter of the Partnership that includes the Closing Date, the portion of such fiscal quarter after the Closing Date.

"Rate Eligible Holder" means a Limited Partner whose federal income tax status would not, in the determination of the General Partner, have the material adverse effect described in Section 4.9(a)(i).

"Recapture Income" means any gain recognized by the Partnership (computed without regard to any adjustment required by Section 734 or Section 743 of the Code) upon the disposition of any property or asset of the Partnership, which gain is characterized as ordinary income because it represents the recapture of deductions previously taken with respect to such property or asset.

"Record Date" means the date established by the General Partner or otherwise in accordance with this Agreement for determining (a) the identity of the Record Holders entitled to notice of, or to vote at, any meeting of Limited Partners or entitled to vote by ballot or give approval of Partnership action in writing without a meeting or entitled to exercise rights in respect of any lawful action of Limited Partners or (b) the identity of Record Holders entitled to receive any report or distribution or to participate in any offer.

"Record Holder" means (a) the Person in whose name a Common Unit is registered on the books of the Transfer Agent as of the opening of business on a particular Business Day or (b) with respect to other Partnership Interests, the Person in whose name any such other Partnership Interest is registered on the books that the General Partner has caused to be kept as of the opening of business on such Business Day.

"Redeemable Interests" means any Partnership Interests for which a redemption notice has been given, and has not been withdrawn, pursuant to Section 4.10.

"Registration Statement" means the Partnership's Registration Statement on Form S-1 (Registration No. 333-174017) as it has been or as it may be amended or supplemented from time to time, filed by the Partnership with the Commission under the Securities Act to register the offering and sale of the Common Units in the Initial Public Offering.

"Remaining Net Positive Adjustments" means, as of the end of any taxable period, (i) with respect to the Unitholders holding Common Units or Subordinated Units, the excess of (a) the Net Positive Adjustments of the Unitholders holding Common Units or Subordinated Units as of the end of such period over (b) the sum of those Partners' Share of Additional Book Basis Derivative Items for each prior taxable period, (ii) with respect to the General Partner (as holder of the General Partner Interest), the excess of (a) the Net Positive Adjustments of the General Partner as of the end of such period over (b) the sum of the General Partner's Share of Additional Book Basis Derivative Items with respect to the General Partner Interest for each prior taxable period and (iii) with respect to the holders of Incentive

Distribution Rights, the excess of (a) the Net Positive Adjustments of the holders of Incentive Distribution Rights as of the end of such period over (b) the sum of the Share of Additional Book Basis Derivative Items of the holders of the Incentive Distribution Rights for each prior taxable period.

"Required Allocations" means any allocation of an item of income, gain, loss, deduction, Simulated Depletion or Simulated Loss pursuant to Section 6.1(d)(i), Section 6.1(d)(ii), Section 6.1(d)(iv), Section 6.1(d)(v), Section 6.1(d)(vi), Section 6.1(d)(vii), Section 6.1(d)(ix) or Section 6.1(e).

"Second Target Distribution" means $0.59375 per Unit per Quarter (or, with respect to periods of less than a full fiscal quarter, it means the product of such amount multiplied by a fraction of which the numerator is the number of days in such period, and the denominator is the total number of days in such fiscal quarter), subject to adjustment in accordance with Section 5.11, Section 6.6 and Section 6.9.

"Securities Act" means the Securities Act of 1933, as amended, supplemented or restated from time to time and any successor to such statute, as such may be amended, restated and supplemented from time to time.

"Securities Exchange Act" means the Securities Exchange Act of 1934, as amended, supplemented or restated from time to time and any successor to such statute, as such may be amended, restated and supplemented from time to time.

"Services Agreement" means the Services Agreement, dated as of the Closing Date, by and among the Partnership, the General Partner and the other parties thereto.

"Share of Additional Book Basis Derivative Items" means, in connection with any allocation of Additional Book Basis Derivative Items for any taxable period, (i) with respect to the Unitholders holding Common Units or Subordinated Units, the amount that bears the same ratio to such Additional Book Basis Derivative Items as the Unitholders' Remaining Net Positive Adjustments as of the end of such taxable period bears to the Aggregate Remaining Net Positive Adjustments as of that time, (ii) with respect to the General Partner (in respect of the General Partner Units), the amount that bears the same ratio to such Additional Book Basis Derivative Items as the General Partner's Remaining Net Positive Adjustments as of the end of such taxable period bears to the Aggregate Remaining Net Positive Adjustment as of that time, and (iii) with respect to the Partners holding Incentive Distribution Rights, the amount that bears the same ratio to such Additional Book Basis Derivative Items as the Remaining Net Positive Adjustments of the Partners holding the Incentive Distribution Rights as of the end of such period bears to the Aggregate Remaining Net Positive Adjustments as of that time.

"Simulated Basis" means the Carrying Value of any oil and gas property (as defined in Section 614 of the Code).

"Simulated Depletion" means, with respect to an oil and gas property (as defined in Section 614 of the Code), a depletion allowance computed in accordance with federal income tax principles (as if the Simulated Basis of the property was its adjusted tax basis) and in the manner specified in Treasury Regulation Section 1.704-1(b)(2)(iv)(k)(2). For purposes of computing Simulated Depletion with respect to any property, the Simulated Basis of such property shall be deemed to be the Carrying Value of such property, and in no event shall such allowance for Simulated Depletion, in the aggregate, exceed such Simulated Basis.

"Simulated Gain" means the excess, if any, of the amount realized from the sale or other disposition of an oil or gas property over the Carrying Value of such property.

"Simulated Loss" means the excess, if any, of the Carrying Value of an oil or gas property over the amount realized from the sale or other disposition of such property.

"Special Approval" means approval by a majority of the members of the Conflicts Committee.

"Subordinated Unit" means a Partnership Interest representing a fractional part of the Partnership Interests of all Limited Partners and having the rights and obligations specified with respect to Subordinated Units in this Agreement. The term "Subordinated Unit" does not refer to or include a Common Unit. A Subordinated Unit that is convertible into a Common Unit shall not constitute a Common Unit until such conversion occurs.

"Subordination Period" means the period commencing on the Closing Date and ending on the first to occur of:

"Subsidiary" means, with respect to any Person, (a) a corporation of which more than 50% of the voting power of shares entitled (without regard to the occurrence of any contingency) to vote in the election of directors or other governing body of such corporation is owned, directly or indirectly, at the date of determination, by such Person, by one or more Subsidiaries of such Person or a combination thereof, (b) a partnership (whether general or limited) in which such Person or a Subsidiary of such Person is, at the date of determination, a general or limited partner of such partnership, but only if more than 50% of the partnership interests of such partnership (considering all of the partnership interests of the partnership as a single class) is owned, directly or indirectly, at the date of determination, by such Person, by one or more Subsidiaries of such Person, or a combination thereof or (c) any other Person (other than a corporation or a partnership) in which such Person, one or more Subsidiaries of such Person, or a combination thereof, directly or indirectly, at the date of determination, has (i) at least a majority ownership interest or (ii) the power to elect or direct the election of a majority of the directors or other governing body of such other Person.

"Target Distributions" means, collectively, the First Target Distribution and Second Target Distribution.

"Trading Day" means, for the purpose of determining the Current Market Price of any class of Limited Partner Interests, a day on which the principal National Securities Exchange on which such class of Limited Partner Interests is listed or admitted to trading is open for the transaction of business or, if Limited Partner Interests of a class are not listed or admitted to trading on any National Securities Exchange, a day on which banking institutions in New York City generally are open.

"Transfer Agent" means such bank, trust company or other Person (including the General Partner or one of its Affiliates) as may be appointed from time to time by the Partnership to act as registrar and transfer agent for any class of Partnership Interests; provided, however, that if no Transfer Agent is specifically designated for any class of Partnership Interests, the General Partner shall act in such capacity.

"Underwriter" means each Person named as an underwriter in the Underwriting Agreement who purchases Common Units pursuant thereto.

"Underwriting Agreement" means the Underwriting Agreement, dated November 10, 2011, among the Underwriters, the Partnership, the General Partner and the other parties thereto, providing for the purchase of Common Units by the Underwriters.

"Unit" means a Partnership Interest that is designated as a "Unit" and shall include Common Units and Subordinated Units but shall not include (i) General Partner Units (or the General Partner Interest represented thereby) or (ii) Incentive Distribution Rights.

"Unit Majority" means (a) during the Subordination Period, at least a majority of the Outstanding Common Units (excluding Common Units owned by the General Partner and its Affiliates), voting as a separate class, and at least a majority of the Outstanding Subordinated Units, voting as a separate class, and (b) after the end of the Subordination Period, at least a majority of the Outstanding Common Units, voting as a single class.

"Unrealized Gain" attributable to any item of Partnership property means, as of any date of determination, the excess, if any, of (a) the fair market value of such property as of such date (as determined under Section 5.5(d)) over (b) the Carrying Value of such property as of such date (prior to any adjustment to be made pursuant to Section 5.5(d) as of such date).

"Unrealized Loss" attributable to any item of Partnership property means, as of any date of determination, the excess, if any, of (a) the Carrying Value of such property as of such date (prior to any adjustment to be made pursuant to Section 5.5(d) as of such date) over (b) the fair market value of such property as of such date (as determined under Section 5.5(d)).

"Unrecovered Initial Unit Price" means, at any time with respect to a Unit, the Initial Unit Price less the sum of all distributions constituting Capital Surplus theretofore made in respect of an Initial Common Unit and any distributions of cash (or the Net Agreed Value of any distributions in kind) in connection with the dissolution and liquidation of the Partnership theretofore made in respect of an Initial Common Unit, adjusted as the General Partner determines to be appropriate to give effect to any distribution, subdivision or combination of such Units.

"Unrestricted Person" means (a) each Indemnitee, (b) each Partner, (c) each Person who is or was a member, partner, director, officer, employee or agent of any Group Member, a General Partner or any Departing General Partner or any Affiliate of any Group Member, a General Partner or any Departing General Partner and (d) any Person the General Partner designates as an "Unrestricted Person" for purposes of this Agreement.

"U.S. GAAP" means United States generally accepted accounting principles, as in effect from time to time, consistently applied.

"Working Capital Borrowings" means borrowings used solely for working capital purposes or to pay distributions to Partners, made pursuant to a credit facility, commercial paper facility or similar financing arrangement; provided, however, that when such borrowings are incurred it is the intent of the borrower to repay such borrowings within 12 months from sources other than additional Working Capital Borrowings.

Section 1.2 Construction. Unless the context requires otherwise: (a) any pronoun used in this Agreement shall include the corresponding masculine, feminine or neuter forms, and the singular form of nouns, pronouns and verbs shall include the plural and vice versa; (b) references to Articles and Sections refer to Articles and Sections of this Agreement; (c) the terms "include," "includes," "including" or words of like import shall be deemed to be followed by the words "without limitation;" and (d) the terms "hereof," "herein" or "hereunder" refer to this Agreement as a whole and not to any particular

provision of this Agreement. The table of contents and headings contained in this Agreement are for reference purposes only, and shall not affect in any way the meaning or interpretation of this Agreement.

Section 2.1 Formation. The General Partner and the Organizational Limited Partner previously formed the Partnership as a limited partnership pursuant to the provisions of the Delaware Act and hereby amend and restate the Agreement of Limited Partnership of LRR Energy, L.P., dated as of May 5, 2011, in its entirety. This amendment and restatement shall become effective as of the date first set forth above. Except as expressly provided to the contrary in this Agreement, the rights, duties (including fiduciary duties), liabilities and obligations of the Partners and the administration, dissolution and termination of the Partnership shall be governed by the Delaware Act. All Partnership Interests shall constitute personal property of the owner thereof for all purposes.

Section 2.2 Name. The name of the Partnership shall be "LRR Energy, L.P." The Partnership's business may be conducted under any other name or names as determined by the General Partner, including the name of the General Partner. The words "Limited Partnership," "LP," "Ltd." or similar words or letters shall be included in the Partnership's name where necessary for the purpose of complying with the laws of any jurisdiction that so requires. The General Partner may change the name of the Partnership at any time and from time to time without the consent or approval of any Limited Partner and shall notify the Limited Partners of such change in the next regular communication to the Limited Partners.

Section 2.3 Registered Office; Registered Agent; Principal Office; Other Offices. Unless and until changed by the General Partner, the registered office of the Partnership in the State of Delaware shall be located at 1209 Orange Street, Wilmington, New Castle County, Delaware 19801, and the registered agent for service of process on the Partnership in the State of Delaware at such registered office shall be The Corporation Trust Company. The principal office of the Partnership shall be located at Heritage Plaza, 1111 Bagby Street, Suite 4600, Houston, Texas 77002, or such other place as the General Partner may from time to time designate by notice to the Limited Partners. The Partnership may maintain offices at such other place or places within or outside the State of Delaware as the General Partner determines to be necessary or appropriate. The address of the General Partner shall be Heritage Plaza, 1111 Bagby Street, Suite 4600, Houston, Texas 77002, or such other place as the General Partner may from time to time designate by notice to the Limited Partners.

Section 2.4 Purpose and Business. The purpose and nature of the business to be conducted by the Partnership shall be to (a) engage directly in, or enter into or form, hold and dispose of any corporation, partnership, joint venture, limited liability company or other arrangement to engage indirectly in, any business activity that is approved by the General Partner, in its sole discretion, and that lawfully may be conducted by a limited partnership organized pursuant to the Delaware Act and, in connection therewith, to exercise all of the rights and powers conferred upon the Partnership pursuant to the agreements relating to such business activity and (b) do anything necessary or appropriate to the foregoing, including the making of capital contributions or loans to a Group Member; provided, however, that the General Partner shall not cause the Partnership to engage, directly or indirectly, in any business activity that the General Partner determines would be reasonably likely to cause the Partnership to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes. To the fullest extent permitted by law, the General Partner shall have no duty or obligation to propose or approve, and may, in its sole discretion, decline to propose or approve, the conduct by the Partnership of any business free of any fiduciary duty or obligation whatsoever to the Partnership and any Limited Partner and, in declining to so propose or approve, shall not be required to act in good faith or pursuant to any other standard imposed by this Agreement, any Group Member Agreement, any

other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity.

Section 2.5 Powers. The Partnership shall be empowered to do any and all acts and things necessary, appropriate, proper, advisable, incidental to or convenient for the furtherance and accomplishment of the purposes and business described in Section 2.4 and for the protection and benefit of the Partnership.

Section 2.6 Term. The term of the Partnership commenced upon the filing of the Certificate of Limited Partnership in accordance with the Delaware Act and shall continue until the dissolution of the Partnership in accordance with the provisions of Article XII. The existence of the Partnership as a separate legal entity shall continue until the cancellation of the Certificate of Limited Partnership as provided in the Delaware Act.

Section 2.7 Title to Partnership Assets. Title to Partnership assets, whether real, personal or mixed and whether tangible or intangible, shall be deemed to be owned by the Partnership as an entity, and no Partner, individually or collectively, shall have any ownership interest in such Partnership assets or any portion thereof. Title to any or all of the Partnership assets may be held in the name of the Partnership, the General Partner, one or more of its Affiliates or one or more nominees, as the General Partner may determine. The General Partner hereby declares and warrants that any Partnership assets for which record title is held in the name of the General Partner or one or more of its Affiliates or one or more nominees shall be held by the General Partner or such Affiliate or nominee for the use and benefit of the Partnership in accordance with the provisions of this Agreement; provided, however, that the General Partner shall use reasonable efforts to cause record title to such assets (other than those assets in respect of which the General Partner determines that the expense and difficulty of conveyancing makes transfer of record title to the Partnership impracticable) to be vested in the Partnership as soon as reasonably practicable; provided, further, that, prior to the withdrawal or removal of the General Partner or as soon thereafter as practicable, the General Partner shall use reasonable efforts to effect the transfer of record title to the Partnership and, prior to any such transfer, will provide for the use of such assets in a manner satisfactory to the General Partner. All Partnership assets shall be recorded as the property of the Partnership in its books and records, irrespective of the name in which record title to such Partnership assets is held.

Section 3.1 Limitation of Liability. The Limited Partners shall have no liability under this Agreement except as expressly provided in this Agreement or the Delaware Act.

Section 3.2 Management of Business. No Limited Partner, in its capacity as such, shall participate in the operation, management or control (within the meaning of the Delaware Act) of the Partnership's business, transact any business in the Partnership's name or have the power to sign documents for or otherwise bind the Partnership. Any action taken by any Affiliate of the General Partner or any officer, director, employee, manager, member, general partner, agent or trustee of the General Partner or any of its Affiliates, or any officer, director, employee, manager, member, general partner, agent or trustee of a Group Member, in its capacity as such, shall not, to the fullest extent permitted by law, be deemed to be participation in the control of the business of the Partnership by a limited partner of the Partnership (within the meaning of Section 17-303(a) of the Delaware Act) and shall not affect, impair or eliminate the limitations on the liability of the Limited Partners under this Agreement.

Section 3.3 Outside Activities of the Limited Partners. Subject to the provisions of Section 7.5, which shall continue to be applicable to the Persons referred to therein, regardless of whether such Persons shall also be Limited Partners, any Limited Partner shall be entitled to and may have business

interests and engage in business activities in addition to those relating to the Partnership, including business interests and activities in direct competition with the Partnership Group. Neither the Partnership nor any of the other Partners shall have any rights by virtue of this Agreement in any business ventures of any Limited Partner.

(a) In addition to other rights provided by this Agreement or by applicable law, and except as limited by Section 3.4(b), each Limited Partner shall have the right, for a purpose reasonably related to such Limited Partner's interest as a Limited Partner in the Partnership, the reasonableness of which shall be determined by the General Partner, upon reasonable written demand stating the purpose of such demand, and at such Limited Partner's own expense, to obtain:

(b) To the fullest extent permitted by law, the General Partner may keep confidential from the Limited Partners, for such period of time as the General Partner deems reasonable, (i) any information that the General Partner reasonably believes to be in the nature of trade secrets or (ii) other information the disclosure of which the General Partner in good faith believes (A) is not in the best interests of the Partnership Group, (B) could damage the Partnership Group or its business or (C) that any Group Member is required by law or by agreement with any third party to keep confidential (other than agreements with Affiliates of the Partnership the primary purpose of which is to circumvent the obligations set forth in this Section 3.4).

ARTICLE IV

CERTIFICATES; RECORD HOLDERS; TRANSFER OF PARTNERSHIP INTERESTS;
REDEMPTION OF PARTNERSHIP INTERESTS

Section 4.1 Certificates. Notwithstanding anything to the contrary in this Agreement, unless the General Partner shall determine otherwise in respect of some or all of any or all classes of Partnership Interests, Partnership Interests shall not be evidenced by certificates. Certificates that may be issued shall be executed by the General Partner on behalf of the Partnership by the Chairman of the Board, Chief Executive Officer, President, Chief Financial Officer or any Vice President and the Secretary, any Assistant Secretary, or other authorized officer or director of the General Partner. If a Transfer Agent (other than the General Partner) has been appointed for a class of Partnership Interests, no Certificate for such class of Partnership Interests shall be valid for any purpose until it has been countersigned by the Transfer Agent; provided, however, that, if the General Partner elects to cause the Partnership to

issue Partnership Interests of such class in global form, the Certificate shall be valid upon receipt of a certificate from the Transfer Agent certifying that the Partnership Interests have been duly registered in accordance with the directions of the Partnership. Subject to the requirements of Section 6.7(c), if Common Units are evidenced by Certificates, on or after the date on which Subordinated Units are converted into Common Units pursuant to the terms of Section 5.7, the Record Holders of such Subordinated Units (i) if the Subordinated Units are evidenced by Certificates, may exchange such Certificates for Certificates evidencing Common Units, or (ii) if the Subordinated Units are not evidenced by Certificates, shall be issued Certificates evidencing Common Units.

(a) If any mutilated Certificate is surrendered to the Transfer Agent (for Common Units) or the General Partner (for Partnership Interests other than Common Units), the appropriate officers of the General Partner on behalf of the Partnership shall execute, and the Transfer Agent, if other than the General Partner, (for Common Units) or the General Partner (for Partnership Interests other than Common Units) shall countersign and deliver in exchange therefor, a new Certificate evidencing the same number and type of Partnership Interests as the Certificate so surrendered.

(b) The appropriate officers of the General Partner on behalf of the Partnership shall execute and deliver, and the Transfer Agent, if other than the General Partner (for Common Units) shall countersign, a new Certificate in place of any Certificate previously issued, or issue uncertificated Units, if the Record Holder of the Certificate:

If a Limited Partner fails to notify the General Partner within a reasonable period of time after such Limited Partner has notice of the loss, destruction or theft of a Certificate, and a transfer of the Limited Partner Interests represented by the Certificate is registered before the Partnership, the General Partner or the Transfer Agent receives such notification, the Limited Partner shall be precluded from making any claim against the Partnership, the General Partner or the Transfer Agent for such transfer or for a new Certificate or uncertificated Units.

(c) As a condition to the issuance of any new Certificate or uncertificated Units under this Section 4.2, the General Partner may require the payment of a sum sufficient to cover any tax or other governmental charge that may be imposed in relation thereto and any other expenses (including the fees and expenses of the Transfer Agent) reasonably connected therewith.

Section 4.3 Record Holders. The Partnership shall be entitled to recognize the Record Holder as the Partner with respect to any Partnership Interest and, accordingly, shall not be bound to recognize any equitable or other claim to, or interest in, such Partnership Interest on the part of any other Person, regardless of whether the Partnership shall have actual or other notice thereof, except as otherwise provided by law or any applicable rule, regulation, guideline or requirement of any National Securities Exchange on which such Partnership Interests are listed or admitted to trading. Without limiting the foregoing, when a Person (such as a broker, dealer, bank, trust company or clearing corporation or an

agent of any of the foregoing) is acting as nominee, agent or in some other representative capacity for another Person in acquiring and/or holding Partnership Interests, as between the Partnership on the one hand, and such other Persons on the other, such representative Person shall be (a) the Record Holder of such Partnership Interest and (b) bound by this Agreement and shall have the rights and obligations of a Partner hereunder as, and to the extent, provided herein.

(a) The term "transfer," when used in this Agreement with respect to a Partnership Interest, shall be deemed to refer to a transaction (i) by which the General Partner assigns its General Partner Units to another Person or by which a holder of Incentive Distribution Rights assigns its Incentive Distribution Rights to another Person, and includes a sale, assignment, gift, pledge, encumbrance, hypothecation, mortgage, exchange or any other disposition by law or otherwise or (ii) by which the holder of a Limited Partner Interest (other than an Incentive Distribution Right) assigns such Limited Partner Interest to another Person who is or becomes a Limited Partner, and includes a sale, assignment, gift, exchange or any other disposition by law or otherwise, excluding a pledge, encumbrance, hypothecation or mortgage but including any transfer upon foreclosure of any pledge, encumbrance, hypothecation or mortgage.

(b) No Partnership Interest shall be transferred, in whole or in part, except in accordance with the terms and conditions set forth in this Article IV. Any transfer or purported transfer of a Partnership Interest not made in accordance with this Article IV shall be, to the fullest extent permitted by law, null and void.

(c) Nothing contained in this Agreement shall be construed to prevent a disposition by any stockholder, member, partner or other owner of any Partner of any or all of the shares of stock, membership interests, partnership interests or other ownership interests in such Partner and the term "transfer" shall not mean any such disposition.

(a) The General Partner shall keep or cause to be kept on behalf of the Partnership a register in which, subject to such reasonable regulations as it may prescribe and subject to the provisions of Section 4.5(b), the Partnership will provide for the registration and transfer of Limited Partner Interests. The Transfer Agent is hereby appointed registrar and transfer agent for the purpose of registering Common Units and transfers of such Common Units as herein provided.

(b) The Partnership shall not recognize any transfer of Limited Partner Interests evidenced by Certificates until the endorsed Certificates evidencing such Limited Partner Interests are surrendered for registration of transfer. No charge shall be imposed by the General Partner for such transfer; provided, however, that as a condition to the issuance of any new Certificate under this Section 4.5, the General Partner may require the payment of a sum sufficient to cover any tax or other governmental charge that may be imposed with respect thereto. Upon surrender of a Certificate for registration of transfer of any Limited Partner Interests evidenced by a Certificate, and subject to the provisions hereof, the appropriate officers of the General Partner on behalf of the Partnership shall execute and deliver, and in the case of Certificates evidencing Limited Partner Interests for which a Transfer Agent (other than the General Partner) has been appointed the Transfer Agent shall countersign and deliver, in the name of the holder or the designated transferee or transferees, as required pursuant to the holder's instructions, one or more new Certificates evidencing the same aggregate number and type of Limited Partner Interests as was evidenced by the Certificate so surrendered.

(c) By acceptance of the transfer of a Limited Partner Interest in accordance with this Section 4.5 and except as otherwise provided in Section 4.9, each transferee of a Limited Partner Interest (including any nominee holder or an agent or representative acquiring such Limited Partner Interests for the account of another Person) (i) shall be admitted to the Partnership as a Limited Partner with respect to the Limited Partner Interests so transferred to such Person when any such transfer or admission is reflected in the books and records of the Partnership and such Limited Partner becomes the Record

Holder of the Limited Partner Interests so transferred, (ii) shall become bound, and shall be deemed to have agreed to be bound, by the terms of this Agreement, (iii) represents that the transferee has the capacity, power and authority to enter into this Agreement and (iv) makes the consents, acknowledgments and waivers contained in this Agreement, all with or without execution of this Agreement by such Person. The transfer of any Limited Partner Interests and the admission of any new Limited Partner shall not constitute an amendment to this Agreement.

(d) Subject to (i) the foregoing provisions of this Section 4.5, (ii) Section 4.3, (iii) Section 4.8, (iv) with respect to any class or series of Limited Partner Interests, the provisions of any statement of designations or an amendment to this Agreement establishing such class or series, (v) any contractual provisions binding on any Limited Partner and (vi) provisions of applicable law, including the Securities Act, Limited Partner Interests shall be freely transferable.

(e) The General Partner and its Affiliates shall have the right at any time to transfer their Subordinated Units and Common Units (whether issued upon conversion of the Subordinated Units or otherwise) to one or more Persons.

(a) Subject to Section 4.6(c) below, prior to December 31, 2021, the General Partner shall not transfer any General Partner Units to a Person unless such transfer (i) has been approved by the prior written consent or vote of the holders of at least a majority of the Outstanding Common Units (excluding Common Units held by the General Partner and its Affiliates) or (ii) is of all, but not less than all, of the General Partner Units to (A) an Affiliate of the General Partner (other than an individual) or (B) another Person (other than an individual) in connection with the merger or consolidation of the General Partner with or into such other Person or the transfer by the General Partner of all or substantially all of its assets to such other Person.

(b) Subject to Section 4.6(c) below, on or after December 31, 2021, the General Partner may at its option transfer the General Partner Units, in whole or in part, without Unitholder approval.

(c) Notwithstanding anything herein to the contrary, no transfer by the General Partner of all or any part of its General Partner Interest to another Person shall be permitted unless (i) the transferee agrees to assume the rights and duties of the General Partner under this Agreement and to be bound by the provisions of this Agreement, (ii) the Partnership receives an Opinion of Counsel that such transfer would not result in the loss of limited liability of any Limited Partner under the Delaware Act or cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not already so treated or taxed) and (iii) such transferee also agrees to purchase all (or the appropriate portion thereof, if applicable) of the partnership or membership interest held by the General Partner as the general partner or managing member, if any, of each other Group Member. In the case of a transfer pursuant to and in compliance with this Section 4.6, the transferee or successor (as the case may be) shall, subject to compliance with the terms of Section 10.2, be admitted to the Partnership as the General Partner effective immediately prior to the transfer of the General Partner Interest, and the business of the Partnership shall continue without dissolution.

Section 4.7 Transfer of Incentive Distribution Rights. The General Partner or any other holder of Incentive Distribution Rights may transfer any or all of its Incentive Distribution Rights without Unitholder approval. Notwithstanding anything herein to the contrary, (i) the transfer of Common Units issued pursuant to Section 5.11 shall not be treated as a transfer of all or any part of the Incentive Distribution Rights and (ii) no transfer of Incentive Distribution Rights to another Person shall be permitted unless the transferee agrees to be bound by the provisions of this Agreement.

(a) Except as provided in Section 4.8(e) below, but notwithstanding the other provisions of this Article IV, no transfer of any Partnership Interests shall be made if such transfer would (i) violate the then applicable federal or state securities laws or rules and regulations of the Commission, any state securities commission or any other governmental authority with jurisdiction over such transfer, (ii) terminate the existence or qualification of the Partnership under the laws of the jurisdiction of its formation or (iii) cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not already so treated or taxed).

(b) The General Partner may impose restrictions on the transfer of Partnership Interests if it receives an Opinion of Counsel that such restrictions are necessary or advisable to (i) avoid a significant risk of the Partnership becoming taxable as a corporation or otherwise becoming taxable as an entity for federal income tax purposes or (ii) preserve the uniformity of the Limited Partner Interests (or any class or classes thereof). The General Partner may impose such restrictions by amending this Agreement; provided, however, that any amendment that would result in the delisting or suspension of trading of any class of Limited Partner Interests on the principal National Securities Exchange on which such class of Limited Partner Interests is then listed or admitted to trading must be approved, prior to such amendment being effected, by the holders of at least a majority of the Outstanding Limited Partner Interests of such class.

(c) The transfer of a Common Unit that has been issued upon conversion of a Subordinated Unit shall be subject to the restrictions imposed by Section 6.7(b) and Section 6.7(c).

(d) The transfer of Common Units that have been issued upon conversion of Incentive Distribution Rights shall be subject to the restrictions imposed by Section 6.8(b).

(e) Nothing contained in this Article IV, or elsewhere in this Agreement, shall preclude the settlement of any transactions involving Partnership Interests entered into through the facilities of any National Securities Exchange on which such Partnership Interests are listed or admitted to trading.

(f) Each Certificate evidencing Partnership Interests shall bear a conspicuous legend in substantially the following form:

(g) The General Partner may request any Limited Partner to furnish to the General Partner, within 30 days after receipt of such request, an executed Citizenship Certification or such other information concerning such Limited Partner's nationality, citizenship or other related status (or, if the Limited Partner is a nominee holding for the account of another Person, the nationality, citizenship or other related status of such Person) as the General Partner may request. If a Limited Partner fails to furnish to the General Partner within the aforementioned 30-day period such Citizenship Certification or other requested information or if upon receipt of such Citizenship Certification or other requested information the General Partner determines that a Limited Partner is not an Eligible Citizen Holder, the Limited Partner Interests owned by such Limited Partner shall be subject to redemption in accordance with the provisions of Section 4.10. In addition, the General Partner may require that the status of any such Limited Partner be changed to that of an Ineligible Citizen Holder and, thereupon, such Ineligible Citizen Holder shall cease to be a Partner and shall have no voting rights (whether arising hereunder, under the Delaware Act, at law, in equity or otherwise) in respect of his Limited Partner Interests in the Partnership. The General Partner shall be substituted for such Ineligible Citizen Holder as the Limited Partner in respect of such Ineligible Citizen Holder's Limited Partner Interests and shall vote such Limited Partner Interests in accordance with Section 4.9(b).

(a) (i) If at any time the General Partner determines, with the advice of counsel, that the Partnership's status other than as an association taxable as a corporation for U.S. federal income tax purposes or the failure of the Partnership otherwise to be subject to an entity-level tax for U.S. federal, state or local income tax purposes, coupled with the tax status (or lack of proof of the U.S. federal income tax status) of one or more Limited Partners, has or will reasonably likely have a material adverse effect on the maximum applicable rate that can be charged to customers by Subsidiaries of the Partnership, then the General Partner may adopt such amendments to this Agreement as it determines to be necessary or advisable to obtain such proof of the federal income tax status of the Limited Partners and, to the extent relevant, their beneficial owners, as the General Partner determines to be necessary to establish those Limited Partners whose U.S. federal income tax status does not or would not have a material adverse effect on the maximum applicable rate that can be charged to customers by Subsidiaries of the Partnership.

(b) The General Partner shall, in exercising voting rights in respect of Limited Partner Interests held by it on behalf of Ineligible Holders, distribute the votes in the same ratios as the votes of Limited Partners (including the General Partner and its Affiliates) in respect of Limited Partner Interests other than those of Ineligible Holders are cast, either for, against or abstaining as to the matter.

(c) Upon dissolution of the Partnership, an Ineligible Holder shall have no right to receive a distribution in kind pursuant to Section 12.4 but shall be entitled to the cash equivalent thereof, and the Partnership shall provide cash in exchange for an assignment of the Ineligible Holder's share of any distribution in kind. Such payment and assignment shall be treated for Partnership purposes as a purchase by the Partnership from the Ineligible Holder of his Limited Partner Interest (representing his right to receive his share of such distribution in kind).

(d) At any time after an Ineligible Holder can and does certify that it has become an Eligible Holder, an Ineligible Holder may, upon application to the General Partner, request that with respect to any Limited Partner Interests of such Ineligible Holder not redeemed pursuant to Section 4.10, such Ineligible Holder be admitted as a Limited Partner, and upon approval of the General Partner, such Ineligible Holder shall be admitted as a Limited Partner and shall no longer constitute an Ineligible Holder and the General Partner shall cease to be deemed to be the Limited Partner in respect of the Ineligible Holder's Limited Partner Interests.

(a) If at any time a Limited Partner fails to furnish an Eligibility Certification or other information requested within the time period specified in Section 4.9(a) or in amendments adopted pursuant to Section 4.8(g), or if upon receipt of such Eligibility Certification or other information, the General Partner determines, with the advice of counsel, that a Limited Partner is an Ineligible Holder, the Partnership may, unless the Limited Partner establishes to the satisfaction of the General Partner that such Limited Partner is not an Ineligible Holder or has transferred his Limited Partner Interests to a Person who is an Eligible Holder and who furnishes an Eligibility Certification or other information, as the case may be, to the General Partner prior to the date fixed for redemption as provided below, redeem the Limited Partner Interest of such Limited Partner as follows:

(b) The provisions of this Section 4.10 shall also be applicable to Limited Partner Interests held by a Limited Partner as nominee of a Person determined to be an Ineligible Holder.

(c) Nothing in this Section 4.10 shall prevent the recipient of a notice of redemption from transferring his Limited Partner Interest before the redemption date if such transfer is otherwise permitted under this Agreement. Upon receipt of notice of such a transfer, the General Partner shall withdraw the notice of redemption, provided the transferee of such Limited Partner Interest certifies to the satisfaction of the General Partner that he is an Eligible Holder. If the transferee fails to make such certification, such redemption shall be effected from the transferee on the original redemption date.

Section 5.1 Organizational Contributions. In connection with the formation of the Partnership under the Delaware Act, the General Partner made an initial Capital Contribution to the Partnership in the amount of $1.00 in exchange for a General Partner Interest equal to a 0.1% Percentage Interest and was admitted as the General Partner of the Partnership and hereby continues in such capacity. The Organizational Limited Partner made an initial Capital Contribution to the Partnership in the amount of $999.00 in exchange for a Limited Partner Interest equal to a 99.9% Percentage Interest was admitted as a Limited Partner of the Partnership and hereby continues in such capacity. As of the Closing Date, and effective with the admission of another Limited Partner to the Partnership, the interest of the Organizational Limited Partner shall be redeemed as provided in the Contribution Agreement, the Organizational Limited Partner shall cease to be a limited partner of the Partnership and the initial Capital Contributions of (i) the Organizational Limited Partner and (ii) the General Partner shall thereupon be refunded. Ninety-nine and 9/10ths percent of any interest or other profit that may have resulted from the investment or other use of such initial Capital Contributions shall be allocated and distributed to the Organizational Limited Partner, and the balance thereof shall be allocated and distributed to the General Partner.

(a) On the Closing Date and pursuant to the Contribution Agreement: (i) the General Partner shall contribute to the Partnership, as a Capital Contribution, the LRM GP Contribution (as defined in the Contribution Agreement) in exchange for 22,400 General Partner Units, representing a continuation of its General Partner Interest with a 0.1% Percentage Interest (after giving effect to any exercise of the Over-Allotment Option and the Deferred Issuance and Distribution), subject to all of the rights, privileges and duties of the General Partner under this Agreement and (ii) the Fund Group shall contribute and sell to the Partnership, in part as a Capital Contribution, the MLP Assets (as defined in the Contribution Agreement) and the net profits interests that burden the MLP Assets in exchange for 6,249,600 Common Units, 6,720,000 Subordinated Units, the right to receive $289.9 million in part as reimbursement for certain capital expenditures and in part as payment for a portion of the net profits interests that burden the MLP Assets, the assumption of $27.3 million of LRR-A's indebtedness and the right to receive the Deferred Issuance and Distribution.

(b) Upon the issuance of any additional Limited Partner Interests by the Partnership (other than the Common Units issued in the Initial Public Offering, the Common Units issued pursuant to the Over-Allotment Option or the Deferred Issuance and Distribution, any Common Units issued upon conversion of the Subordinated Units or any Common Units issued pursuant to Section 5.11), the General Partner may, in exchange for a proportionate number of General Partner Units, make additional Capital Contributions in an amount equal to the product obtained by multiplying (i) the quotient determined by dividing (A) the General Partner's Percentage Interest by (B) 100 less the General

Partner's Percentage Interest times (ii) the amount contributed to the Partnership by the Limited Partners in exchange for such additional Limited Partner Interests. Except as set forth in Section 12.8, the General Partner shall not be obligated to make any additional Capital Contributions to the Partnership.

(a) On the Closing Date and pursuant to the Underwriting Agreement, each Underwriter shall contribute cash to the Partnership in exchange for the issuance by the Partnership of Common Units to each Underwriter, all as set forth in the Underwriting Agreement.

(b) Upon the exercise, if any, of the Over-Allotment Option, each Underwriter shall contribute cash to the Partnership in exchange for the issuance by the Partnership of Common Units to each Underwriter, all as set forth in the Underwriting Agreement.

(c) No Limited Partner will be required to make any additional Capital Contribution to the Partnership pursuant to this Agreement.

Except as provided in Section 5.1, no interest shall be paid by the Partnership on Capital Contributions. Except as provided in Section 5.1, no Partner shall be entitled to the withdrawal or return of its Capital Contribution, except to the extent, if any, that distributions made pursuant to this Agreement or upon dissolution of the Partnership may be considered as such by law and then only to the extent provided for in this Agreement. Except to the extent expressly provided in this Agreement, no Partner shall have priority over any other Partner either as to the return of Capital Contributions or as to profits, losses or distributions. Any such return shall be a compromise to which all Partners agree within the meaning of Section 17-502(b) of the Delaware Act.

(a) The Partnership shall maintain for each Partner (or a beneficial owner of Partnership Interests held by a nominee in any case in which the nominee has furnished the identity of such owner to the Partnership in accordance with Section 6031(c) of the Code or any other method acceptable to the General Partner) owning a Partnership Interest a separate Capital Account with respect to such Partnership Interest in accordance with the rules of Treasury Regulation Section 1.704-1(b)(2)(iv). Such Capital Account shall be increased by (i) the amount of all Capital Contributions made to the Partnership with respect to such Partnership Interest and (ii) all items of Partnership income and gain (including Simulated Gain and income and gain exempt from tax) computed in accordance with Section 5.5(b) and allocated with respect to such Partnership Interest pursuant to Section 6.1, and decreased by (x) the amount of cash or Net Agreed Value of all actual and deemed distributions of cash or property made with respect to such Partnership Interest and (y) all items of Partnership deduction and loss (including Simulated Depletion and Simulated Loss) computed in accordance with Section 5.5(b) and allocated with respect to such Partnership Interest pursuant to Section 6.1.

(b) For purposes of computing the amount of any item of income, gain, loss, deduction, Simulated Depletion, Simulated Gain or Simulated Loss that is to be allocated pursuant to Article VI and is to be reflected in the Partners' Capital Accounts, the determination, recognition and classification of any such item shall be the same as its determination, recognition and classification for U.S. federal income tax purposes (including any method of depreciation, cost recovery or amortization used for that purpose), provided, that:

(c) (i) A transferee of a Partnership Interest shall succeed to a Pro Rata portion of the Capital Account of the transferor relating to the Partnership Interest so transferred.

(d) (i) In accordance with Treasury Regulation Section 1.704-1(b)(2)(iv)(f), upon an issuance of additional Partnership Interests for cash or Contributed Property, the issuance of Partnership Interests as consideration for the provision of services, or the conversion of the Combined Interest to Common Units pursuant to Section 11.3(b), the Carrying Value of each Partnership property immediately prior to such issuance shall be adjusted upward or downward to reflect any Unrealized Gain or Unrealized Loss attributable to such Partnership property, and any such Unrealized Gain or Unrealized Loss shall be treated, for purposes of maintaining Capital Accounts, as if it had been recognized on an actual sale of each such property for an amount equal to its fair market value immediately prior to such issuance and had been allocated among the Partners at such time pursuant to Section 6.1(c) in the same manner as any item of gain, loss, Simulated Gain or Simulated Loss actually recognized following an event giving rise to the liquidation of the Partnership would have been allocated; provided, however, that in the event of an issuance of Partnership Interests for a de minimis amount of cash or Contributed Property, or in the event of an issuance of a de minimis amount of Partnership Interests as consideration for the provision of services, the General Partner may determine that such adjustments are unnecessary for the proper administration of the Partnership. In determining such Unrealized Gain or Unrealized Loss, the aggregate fair market value of all Partnership property (including cash or cash equivalents) immediately prior to the issuance of additional Partnership Interests shall be determined by the General Partner using such method of valuation as it may adopt. In making its determination of the fair market values of individual properties, the General Partner may determine that it is appropriate to first determine an aggregate value for the Partnership, based on the current trading price of the Common Units, and taking fully into account the fair market value of the Partnership Interests of all Partners at such time, and then allocate such aggregate value among the individual properties of the Partnership (in such manner as it determines appropriate).

(a) The Partnership may issue additional Partnership Interests and options, rights, warrants, restricted units, appreciation rights, phantom or tracking interests or other economic interests in the Partnership relating to the Partnership Interests for any Partnership purpose at any time and from time to time to such Persons for such consideration and on such terms and conditions as the General Partner shall determine, all without the approval of any Limited Partners.

(b) Each additional Partnership Interest or other security authorized to be issued by the Partnership pursuant to Section 5.6(a) may be issued in one or more classes, or one or more series of any such classes, with such designations, preferences, rights, powers and duties (which may be senior to existing classes and series of Partnership Interests or other securities), as shall be fixed by the General Partner, including (i) the right to share in Partnership profits and losses or items thereof; (ii) the right to share in Partnership distributions; (iii) the rights upon dissolution and liquidation of the Partnership; (iv) whether, and the terms and conditions upon which, the Partnership may or shall be required to redeem the Partnership Interest or other security (including sinking fund provisions); (v) whether such Partnership Interest or other security is issued with the privilege of conversion or exchange and, if so, the terms and conditions of such conversion or exchange; (vi) the terms and conditions upon which each Partnership Interest or other security will be issued, evidenced by certificates and assigned or transferred; (vii) the method for determining the Percentage Interest as to such Partnership Interest or other security; and (viii) the right, if any, of each such Partnership Interest or other security to vote on Partnership matters, including matters relating to the relative rights, preferences and privileges of such Partnership Interest or other security.

(c) The General Partner shall take all actions that it determines to be necessary or appropriate in connection with (i) each issuance of Partnership Interests and options, rights, warrants, restricted units, appreciation rights, phantom or tracking interests or other economic interests in the Partnership relating to Partnership Interests pursuant to this Section 5.6, Section 5.11(d) or Section 7.4(c), including Common Units issued in connection with the Deferred Issuance and Distribution, (ii) the conversion of the General Partner Interest (represented by General Partner Units) or any Incentive Distribution Rights into Units pursuant to the terms of this Agreement, (iii) the issuance of Common Units pursuant to Section 5.11, (iv) reflecting admission of such additional Limited Partners in the books and records of the Partnership as the Record Holder of such Limited Partner Interest and (v) all additional issuances of Partnership Interests or other securities. The General Partner shall determine the relative rights, powers and duties of the holders of the Units or other Partnership Interests or other securities being so issued. The General Partner shall do all things necessary to comply with the Delaware Act and is authorized and directed to do all things that it determines to be necessary or appropriate in connection with any future issuance of Partnership Interests or other securities or in connection with the conversion of the Combined Interest into Units pursuant to the terms of this Agreement, including compliance with any statute, rule, regulation or guideline of any federal, state or other governmental agency or any National Securities Exchange on which the Units or other Partnership Interests or other securities are listed or admitted to trading.

(a) All outstanding Subordinated Units shall convert into Common Units on a one-for-one basis on the first Business Day of any Quarter beginning after December 31, 2014 in respect of which:

(b) Notwithstanding Section 5.7(a), one-third of all Outstanding Subordinated Units shall convert into Common Units on a one-for-one basis on the first Business Day following the distribution of Available Cash to Partners pursuant to Section 6.3(a) in respect of any Quarter ending on or after December 31, 2012 in respect of which:

(c) Notwithstanding Section 5.7(a), an additional one-third of all Outstanding Subordinated Units shall convert into Common Units on a one-for-one basis on the first Business Day following the distribution of Available Cash to Partners pursuant to Section 6.3(a) in respect of any Quarter ending on or after December 31, 2013 in respect of which:

(d) Notwithstanding Section 5.7(a), the Subordination Period shall terminate and all Outstanding Subordinated Units shall convert into Common Units on a one-for-one basis on the first Business Day following the distribution of Available Cash to Partners pursuant to Section 6.3(a) in respect of any Quarter ending on or after December 31, 2013 in respect of which:

(e) Notwithstanding Section 5.7(a), the Subordination Period shall terminate and all Outstanding Subordinated Units shall convert into Common Units on a one-for-one basis on the first Business Day following the distribution of Available Cash to Partners pursuant to Section 6.3(a) in respect of any Quarter in respect of which:

(f) Notwithstanding any other provision of this Agreement, all of the then Outstanding Subordinated Units will automatically convert into Common Units on a one-for-one basis as set forth in, and pursuant to the terms of, Section 11.4.

(g) A Common Unit that has been issued upon conversion of a Subordinated Unit shall be subject to the provisions of Section 6.7(b) and Section 6.7(c).

Except as provided in this Section 5.8 and in Section 5.2 or as otherwise provided in a separate agreement by the Partnership, no Person shall have any preemptive, preferential or other similar right with respect to the issuance of any Partnership Interest or other security, whether unissued, held in the treasury or hereafter created. The General Partner shall have the right, in its sole discretion, which it may from time to time assign in whole or in part to any of its Affiliates or the beneficial owners thereof or any of their respective Affiliates, to purchase Partnership Interests from the Partnership whenever, and on the same terms that, the Partnership issues Partnership Interests to Persons other than the General Partner and its Affiliates or the beneficial owners thereof or any of their respective Affiliates, to the extent necessary to maintain the Percentage Interests of the General Partner and its Affiliates or the beneficial owners thereof or any of their respective Affiliates equal to any or all of those Percentage Interests that existed immediately prior to the issuance of such Partnership Interests.

(a) Subject to Section 5.9(d), Section 6.6 and Section 6.9 (dealing with adjustments of distribution levels), the Partnership may make a Pro Rata distribution of Partnership Interests to all Record Holders or may effect a subdivision or combination of Partnership Interests so long as, after any such event, each Partner shall have the same Percentage Interest in the Partnership as before such event, and any amounts calculated on a per Unit basis (including any Common Unit Arrearage or Cumulative Common Unit Arrearage) or stated as a number of Units are proportionately adjusted.

(b) Whenever such a Pro Rata distribution, subdivision or combination of Partnership Interests is declared, the General Partner shall select a Record Date as of which the distribution, subdivision or combination shall be effective and shall send notice thereof at least 20 days prior to such Record Date to each Record Holder as of a date not less than 10 days prior to the date of such notice. The General Partner also may cause a firm of independent public accountants selected by it to calculate the number of Partnership Interests to be held by each Record Holder after giving effect to such distribution, subdivision or combination. The General Partner shall be entitled to rely on any certificate provided by such firm as conclusive evidence of the accuracy of such calculation.

(c) Promptly following any such distribution, subdivision or combination, the Partnership may issue Certificates or uncertificated Partnership Interests to the Record Holders of Partnership Interests as of the applicable Record Date representing the new number of Partnership Interests held by such Record Holders, or the General Partner may adopt such other procedures that it determines to be necessary or appropriate to reflect such changes. If any such combination results in a smaller total number of Partnership Interests Outstanding, the Partnership shall require, as a condition to the delivery to a Record Holder of such new Certificate or uncertificated Partnership Interests, the surrender of any Certificate held by such Record Holder immediately prior to such Record Date.

(d) The Partnership shall not issue fractional Units upon any distribution, subdivision or combination of Units. If a distribution, subdivision or combination of Units would result in the issuance of fractional Units but for the provisions of Section 5.6(d) and this Section 5.9(d), each fractional Unit shall be rounded to the nearest whole Unit (and a 0.5 Unit shall be rounded to the next higher Unit).

All Limited Partner Interests issued pursuant to, and in accordance with the requirements of, this Article V shall be fully paid and non-assessable Limited Partner Interests in the Partnership, except as such non-assessability may be affected by Sections 17-303, 17-607 and 17-804 of the Delaware Act.

Section 5.11 Issuance of Common Units in Connection with Reset of Incentive Distribution Rights.

(a) Subject to the provisions of this Section 5.11, the holder of the Incentive Distribution Rights (or, if there is more than one holder of the Incentive Distribution Rights, the holders of a majority in interest of the Incentive Distribution Rights) shall have the right, at any time when there are no

Subordinated Units outstanding and the Partnership has made a distribution pursuant to Section 6.4(b)(iv) for each of the four most recently completed Quarters and the amount of each such distribution did not exceed Adjusted Operating Surplus for such Quarter, to make an election (the "IDR Reset Election") to cause the Minimum Quarterly Distribution and the Target Distributions to be reset in accordance with the provisions of Section 5.11(e) and, in connection therewith, the holder or holders of the Incentive Distribution Rights will become entitled to receive their respective proportionate share of a number of Common Units (the "IDR Reset Common Units") derived by dividing (i) the average of the aggregate amount of cash distributions made by the Partnership for each of the two full Quarters immediately preceding the giving of the Reset Notice (as defined in Section 5.11(b)) in respect of the Incentive Distribution Rights by (ii) the average cash distribution per Common Unit made by the Partnership for each of the two full Quarters immediately preceding the giving of the Reset Notice (the number of such Common Units so determined by such quotient are referred to herein as the "Aggregate Quantity of IDR Reset Common Units"). Upon the issuance of such IDR Reset Common Units, the Partnership will issue to the General Partner that number of additional General Partner Units equal to the product of (x) the quotient obtained by dividing (A) the Percentage Interest of the General Partner immediately prior to such issuance by (B) a percentage equal to 100% less such Percentage Interest and (y) the number of such IDR Reset Common Units, and the General Partner shall not be obligated to make any additional Capital Contribution to the Partnership in exchange for such issuance. The making of the IDR Reset Election in the manner specified in Section 5.11(b) shall cause the Minimum Quarterly Distribution and the Target Distributions to be reset in accordance with the provisions of Section 5.11(e) and, in connection therewith, the holder or holders of the Incentive Distribution Rights will become entitled to receive IDR Reset Common Units and the General Partner will become entitled to receive General Partner Units on the basis specified above, without any further approval required by the General Partner or the Unitholders, at the time specified in Section 5.11(c) unless the IDR Reset Election is rescinded pursuant to Section 5.11(d).

(b) To exercise the right specified in Section 5.11(a), the holder of the Incentive Distribution Rights (or, if there is more than one holder of the Incentive Distribution Rights, the holders of a majority in interest of the Incentive Distribution Rights) shall deliver a written notice (the "Reset Notice") to the Partnership. Within 10 Business Days after the receipt by the Partnership of such Reset Notice, the Partnership shall deliver a written notice to the holder or holders of the Incentive Distribution Rights of the Partnership's determination of the aggregate number of IDR Reset Common Units that each holder of Incentive Distribution Rights will be entitled to receive.

(c) The holder or holders of the Incentive Distribution Rights will be entitled to receive the Aggregate Quantity of IDR Reset Common Units and the General Partner will become entitled to receive related additional General Partner Units on the fifteenth Business Day after receipt by the Partnership of the Reset Notice; provided, however, that the issuance of the IDR Reset Common Units to the holder or holders of the Incentive Distribution Rights shall not occur prior to the approval of the listing or admission for trading of such IDR Reset Common Units by the principal National Securities Exchange upon which the Common Units are then listed or admitted for trading if any such approval is required pursuant to the rules and regulations of such National Securities Exchange.

(d) If the principal National Securities Exchange upon which the Common Units are then traded has not approved the listing or admission for trading of the Aggregate Quantity of IDR Reset Common Units on or before the 30th calendar day following the Partnership's receipt of the Reset Notice and such approval is required by the rules and regulations of such National Securities Exchange, then the holder of the Incentive Distribution Rights (or, if there is more than one holder of the Incentive Distribution Rights, the holders of a majority in interest of the Incentive Distribution Rights) shall have the right to either rescind the IDR Reset Election or elect to receive other Partnership Interests having such terms as the General Partner may approve, with the approval of a Conflicts Committee, that will provide (i) the same economic value, in the aggregate, as the Aggregate Quantity of IDR Reset Common Units would have had at the time of the Partnership's receipt of the Reset Notice, as determined by the General

Partner, and (ii) for the subsequent conversion (on terms acceptable to the National Securities Exchange upon which the Common Units are then traded) of such Partnership Interests into Common Units within not more than 12 months following the Partnership's receipt of the Reset Notice upon the satisfaction of one or more conditions that are reasonably acceptable to the holder of the Incentive Distribution Rights (or, if there is more than one holder of the Incentive Distribution Rights, the holders of a majority in interest of the Incentive Distribution Rights).

(e) The Minimum Quarterly Distribution, First Target Distribution and Second Target Distribution shall be adjusted at the time of the issuance of Common Units or other Partnership Interests pursuant to this Section 5.11 such that (i) the Minimum Quarterly Distribution shall be reset to equal the average cash distribution amount per Common Unit for the two Quarters immediately prior to the Partnership's receipt of the Reset Notice (the "Reset MQD"), (ii) the First Target Distribution shall be reset to equal 115% of the Reset MQD and (iii) the Second Target Distribution shall be reset to equal 125% of the Reset MQD.

For purposes of maintaining the Capital Accounts and in determining the rights of the Partners among themselves, the Partnership's items of income, gain, loss, deduction, Simulated Depletion, Simulated Gain and Simulated Loss (computed in accordance with Section 5.5(b)) for each taxable period shall be allocated among the Partners as provided herein below.

(a) Net Income. Net Income for each taxable period and all items of income, gain, loss, deduction, and Simulated Gain taken into account in computing Net Income for such taxable period shall be allocated as follows:

(b) Net Loss. Net Loss for each taxable period and all items of income, gain, loss, deduction and Simulated Gain taken into account in computing Net Loss for such taxable period shall be allocated as follows:

(c) Net Termination Gains and Losses. Net Termination Gain or Net Termination Loss (including a pro rata part of each item of income, gain, loss, deduction, and Simulated Gain taken into account in computing Net Termination Gain or Net Termination Loss) for such taxable period shall be allocated in the manner set forth in this Section 6.1(c). All allocations under this Section 6.1(c) shall be made after Capital Account balances have been adjusted by all other allocations provided under this Section 6.1 and after all distributions of Available Cash provided under Section 6.4 and Section 6.5 have

been made; provided, however, that solely for purposes of this Section 6.1(c), Capital Accounts shall not be adjusted for distributions made pursuant to Section 12.4.

(d) Special Allocations. Notwithstanding any other provision of this Section 6.1, the following special allocations shall be made for such taxable period:

(a) Except as otherwise provided herein, for federal income tax purposes, each item of income, gain, loss and deduction shall be allocated among the Partners in the same manner as its correlative item of "book" income, gain, loss or deduction is allocated pursuant to Section 6.1.

(b) The deduction for depletion with respect to each separate oil and gas property (as defined in Section 614 of the Code) shall be computed for federal income tax purposes separately by the Partners

rather than by the Partnership in accordance with Section 613A(c)(7)(D) of the Code. Except as provided in Section 6.2(c)(iii), for purposes of such computation (before taking into account any adjustments resulting from an election made by the Partnership under Section 754 of the Code), the adjusted tax basis of each oil and gas property (as defined in Section 614 of the Code) shall be allocated among the Partners Pro Rata. Each Partner shall separately keep records of his share of the adjusted tax basis in each oil and gas property, allocated as provided above, adjust such share of the adjusted tax basis for any cost or percentage depletion allowable with respect to such property, and use such adjusted tax basis in the computation of its cost depletion or in the computation of his gain or loss on the disposition of such property by the Partnership.

(c) Except as provided in Section 6.2(c)(iii), for the purposes of the separate computation of gain or loss by each Partner on the sale or disposition of each separate oil and gas property (as defined in Section 614 of the Code), the Partnership's allocable share of the "amount realized" (as such term is defined in Section 1001(b) of the Code) from such sale or disposition shall be allocated for federal income tax purposes among the Partners as follows:

(d) In an attempt to eliminate Book-Tax Disparities attributable to a Contributed Property or Adjusted Property, other than oil and gas properties pursuant to Section 6.2(c), items of income, gain, loss, depreciation, amortization and cost recovery deductions shall be allocated for federal income tax purposes among the Partners in the manner provided under Section 704(c) of the Code, and the Treasury Regulations promulgated under Section 704(b) and 704(c) of the Code, as determined appropriate by the General Partner (taking into account the General Partner's discretion under Section 6.1(d)(x)(D)); provided, however, that the General Partner shall apply the principles of Treasury Regulation Section 1.704-3(d) in all events.

(e) The General Partner may determine to depreciate or amortize the portion of an adjustment under Section 743(b) of the Code attributable to unrealized appreciation in any Adjusted Property (to the extent of the unamortized Book-Tax Disparity) using a predetermined rate derived from the depreciation or amortization method and useful life applied to the unamortized Book-Tax Disparity of such property, despite any inconsistency of such approach with Treasury Regulation Section 1.167(c)-l(a)(6) or any successor regulations thereto. If the General Partner determines that such reporting position cannot reasonably be taken, the General Partner may adopt depreciation and amortization conventions under which all purchasers acquiring Limited Partner Interests in the same month would receive depreciation and amortization deductions, based upon the same applicable rate as if they had purchased a direct interest in the Partnership's property. If the General Partner chooses not to utilize such aggregate method, the General Partner may use any other depreciation and amortization

conventions to preserve the uniformity of the intrinsic tax characteristics of any Limited Partner Interests, so long as such conventions would not have a material adverse effect on the Limited Partners or the Record Holders of any class or classes of Limited Partner Interests.

(f) In accordance with Treasury Regulation Sections 1.1245-1(e) and 1.1250-1(f), any gain allocated to the Partners upon the sale or other taxable disposition of any Partnership asset shall, to the extent possible, after taking into account other required allocations of gain pursuant to this Section 6.2, be characterized as Recapture Income in the same proportions and to the same extent as such Partners (or their predecessors in interest) have been allocated any deductions directly or indirectly giving rise to the treatment of such gains as Recapture Income.

(g) All items of income, gain, loss, deduction and credit recognized by the Partnership for federal income tax purposes and allocated to the Partners in accordance with the provisions hereof shall be determined without regard to any election under Section 754 of the Code that may be made by the Partnership; provided, however, that such allocations, once made, shall be adjusted (in the manner determined by the General Partner) to take into account those adjustments permitted or required by Sections 734 and 743 of the Code.

(h) Each item of Partnership income, gain, loss and deduction shall, for federal income tax purposes, be determined for each taxable period and prorated on a monthly basis and shall be allocated to the Partners as of the opening of the National Securities Exchange on which the Partnership Interests are listed or admitted to trading on the first Business Day of each month; provided, however, such items for the period beginning on the Closing Date and ending on the last day of the month in which the Over-Allotment Option is exercised in full or the expiration of the Over-Allotment Option occurs shall be allocated to the Partners as of the opening of the National Securities Exchange on which the Partnership Interests are listed or admitted to trading on the first Business Day of the next succeeding month; and provided further, that gain or loss on a sale or other disposition of any assets of the Partnership or any other extraordinary item of gross income, gain, loss or deduction as determined by the General Partner, shall be allocated to the Partners as of the opening of the National Securities Exchange on which the Partnership Interests are listed or admitted to trading on the first Business Day of the month in which such item is recognized for federal income tax purposes. The General Partner may revise, alter or otherwise modify such methods of allocation to the extent permitted or required by Section 706 of the Code and the regulations or rulings promulgated thereunder.

(i) Allocations that would otherwise be made to a Limited Partner under the provisions of this Article VI shall instead be made to the beneficial owner of Limited Partner Interests held by a nominee in any case in which the nominee has furnished the identity of such owner to the Partnership in accordance with Section 6031(c) of the Code or any other method determined by the General Partner.

Section 6.3 Requirement and Characterization of Distributions; Distributions to Record Holders.

(a) Within 45 days following the end of each Quarter commencing with the Quarter ending December 31, 2011, an amount equal to 100% of Available Cash with respect to such Quarter shall be distributed in accordance with this Article VI by the Partnership to the Partners as of the Record Date selected by the General Partner. All amounts of Available Cash distributed by the Partnership on any date from any source shall be deemed to be Operating Surplus until the sum of all amounts of Available Cash theretofore distributed by the Partnership to the Partners pursuant to Section 6.4 equals the Operating Surplus from the Closing Date through the close of the immediately preceding Quarter. Any remaining amounts of Available Cash distributed by the Partnership on such date shall, except as otherwise provided in Section 6.5, be deemed to be "Capital Surplus." Notwithstanding any provision to the contrary contained in this Agreement, the Partnership shall not make a distribution to any Partner on account of its interest in the Partnership if such distribution would violate the Delaware Act or any other applicable law.

(b) Notwithstanding Section 6.3(a), in the event of the dissolution and liquidation of the Partnership, all cash received during or after the Quarter in which the Liquidation Date occurs, other

than from Working Capital Borrowings, shall be applied and distributed solely in accordance with, and subject to the terms and conditions of, Section 12.4.

(c) The General Partner may treat taxes paid by the Partnership on behalf of, or amounts withheld with respect to, all or less than all of the Partners, as a distribution of Available Cash to such Partners.

(d) Each distribution in respect of a Partnership Interest shall be paid by the Partnership, directly or through the Transfer Agent or through any other Person or agent, only to the Record Holder of such Partnership Interest as of the Record Date set for such distribution. Such payment shall constitute full payment and satisfaction of the Partnership's liability in respect of such payment, regardless of any claim of any Person who may have an interest in such payment by reason of an assignment or otherwise.

(a) During Subordination Period. Except as otherwise required in respect of additional Partnership Interests or other securities issued pursuant to Section 5.6, Available Cash with respect to any Quarter within the Subordination Period that is deemed to be Operating Surplus pursuant to the provisions of Section 6.3 or Section 6.5 shall be distributed as follows:

provided, however, if the Minimum Quarterly Distribution, the First Target Distribution and the Second Target Distribution have been reduced to zero pursuant to the second sentence of Section 6.6(a), the distribution of Available Cash that is deemed to be Operating Surplus with respect to any Quarter will be made solely in accordance with Section 6.4(a)(vi).

(b) After Subordination Period. Except as otherwise required in respect of additional Partnership Interests or other securities issued pursuant to Section 5.6, Available Cash with respect to any Quarter after the Subordination Period that is deemed to be Operating Surplus pursuant to the provisions of Section 6.3 or Section 6.5 shall be distributed as follows:

Available Cash that is deemed to be Capital Surplus pursuant to the provisions of Section 6.3(a) shall be distributed as follows, unless the provisions of Section 6.3 require otherwise:

Section 6.6 Adjustment of Minimum Quarterly Distribution and Target Distribution Levels.

(a) The Minimum Quarterly Distribution, First Target Distribution, Second Target Distribution, Common Unit Arrearages and Cumulative Common Unit Arrearages shall be proportionately adjusted in the event of any distribution, combination or subdivision (whether effected by a distribution payable in Units or otherwise) of Units or other Partnership Interests in accordance with Section 5.9. In the event of a distribution of Available Cash that is deemed to be from Capital Surplus, the then applicable Minimum Quarterly Distribution, First Target Distribution and Second Target Distribution, shall be reduced in the same proportion that the distribution had to the fair market value of the Common Units

immediately prior to the announcement of the distribution. If the Common Units are publicly traded on a National Securities Exchange, the fair market value will be the Current Market Price before the ex-dividend date. If the Common Units are not publicly traded, the fair market value will be determined by the Board of Directors.

(b) The Minimum Quarterly Distribution, First Target Distribution and Second Target Distribution shall also be subject to adjustment pursuant to Section 5.11 and Section 6.9.

(a) Except with respect to the right to vote on or approve matters requiring the vote or approval of a percentage of the holders of Outstanding Common Units and the right to participate in allocations of income, gain, loss and deduction and distributions made with respect to Common Units, the holder of a Subordinated Unit shall have all of the rights and obligations of a Unitholder holding Common Units hereunder; provided, however, that immediately upon the conversion of Subordinated Units into Common Units pursuant to Section 5.7, the Unitholder holding a Common Unit that has been issued upon conversion of a Subordinated Unit shall possess all of the rights and obligations of a Unitholder holding Common Units hereunder, including the right to vote as a Common Unitholder and the right to participate in allocations of income, gain, loss and deduction and distributions made with respect to Common Units; provided, however, that such converted Common Units shall remain subject to the provisions of Sections 5.5(c)(ii), 6.1(d)(x), 6.7(b) and 6.7(c).

(b) A Unitholder shall not be permitted to transfer a Subordinated Unit or a Common Unit that has been issued upon conversion of a Subordinated Unit pursuant to Section 5.7 (other than a transfer to an Affiliate) if the remaining balance in the transferring Unitholder's Capital Account with respect to the retained Subordinated Units or Retained Converted Subordinated Units would be negative after giving effect to the allocation under Section 5.5(c)(ii)(B).

(c) A Unitholder holding a Common Unit that has resulted from the conversion of a Subordinated Unit pursuant to Section 5.7 shall not be issued a Common Unit Certificate pursuant to Section 4.1, if the Common Units are evidenced by Certificates, and shall not be permitted to transfer such Common Unit to a Person that is not an Affiliate of the holder, until such time as the General Partner determines, based on advice of counsel, that each such Common Unit should have, as a substantive matter, like intrinsic economic and federal income tax characteristics, in all material respects, to the intrinsic economic and federal income tax characteristics of an Initial Common Unit. In connection with the condition imposed by this Section 6.7(c), the General Partner may take whatever steps are required to provide economic uniformity to such Common Units in preparation for a transfer of such Common Units, including the application of Sections 5.5(c)(ii), 6.1(d)(x) and 6.7(b); provided, however, that no such steps may be taken that would have a material adverse effect on the other Unitholders holding Common Units.

Section 6.8 Special Provisions Relating to the Holders of Incentive Distribution Rights.

(a) Notwithstanding anything to the contrary set forth in this Agreement, the holders of the Incentive Distribution Rights shall (i) possess the rights and obligations provided in this Agreement with respect to a Limited Partner pursuant to Article III and Article VII and (ii) have a Capital Account as a Partner pursuant to Section 5.5 and all other provisions related thereto but shall not (iii) be entitled to vote on any matters requiring the approval or vote of the holders of Outstanding Units, except as provided by law, (iv) be entitled to any distributions other than as provided in Sections 6.4(a)(v) and (vi), Section 6.4(b)(iii) and (iv) and Section 12.4 or (v) be allocated items of income, gain, loss or deduction other than as specified in this Article VI.

(b) A Unitholder holding a Common Unit that has resulted from the conversion of Incentive Distribution Rights pursuant to Section 5.11 shall not be issued a Common Unit Certificate pursuant to Section 4.1 if the Common Units are evidenced by Certificates, and shall not be permitted to transfer such Common Units to a Person that is not an Affiliate of the holder until such time as the General Partner determines, based on advice of counsel, that each such Common Unit should have, as a

substantive matter, like intrinsic economic and U.S. federal income tax characteristics, in all material respects, to the intrinsic economic and U.S. federal income tax characteristics of an Initial Common Unit. In connection with the condition imposed by this Section 6.8(b), the General Partner may take whatever steps are required to provide economic uniformity to such Common Units in preparation for a transfer of such Common Units, including the application of Section 5.5(c)(iii), Section 6.1(d)(x)(B), or Section 6.1(d)(x)(C), provided, however, that no such steps may be taken that would have a material adverse effect on the Unitholders holding Common Units.

If legislation is enacted or the official interpretation of existing legislation is modified by a governmental authority, which after giving effect to such enactment or modification, results in a Group Member becoming subject to federal, state or local or non-U.S. income or withholding taxes in excess of the amount of such taxes due from the Group Member prior to such enactment or modification (including, for avoidance of doubt, any increase in the rate of such taxation applicable to the Group Member), then the General Partner may, in its sole discretion, reduce the Minimum Quarterly Distribution, the First Target Distribution and the Second Target Distribution by the amount of income or withholding taxes that are payable by reason of any such new legislation or interpretation (the "Incremental Income Taxes"), or any portion thereof selected by the General Partner, in the manner provided in this Section 6.9. If the General Partner elects to reduce the Minimum Quarterly Distribution, the First Target Distribution and the Second Target Distribution for any Quarter with respect to all or a portion of any Incremental Income Taxes, the General Partner shall estimate for such Quarter the Partnership Group's aggregate liability (the "Estimated Incremental Quarterly Tax Amount") for all (or the relevant portion of) such Incremental Income Taxes; provided, however, that any difference between such estimate and the actual liability for Incremental Income Taxes (or the relevant portion thereof) for such Quarter may, to the extent determined by the General Partner be taken into account in determining the Estimated Incremental Quarterly Tax Amount with respect to each Quarter in which any such difference can be determined. For each such Quarter, the Minimum Quarterly Distribution, First Target Distribution and Second Target Distribution shall be the product obtained by multiplying (a) the amounts therefor that are set out herein prior to the application of this Section 6.9 times (b) the quotient obtained by dividing (i) Available Cash with respect to such Quarter by (ii) the sum of Available Cash with respect to such Quarter and the Estimated Incremental Quarterly Tax Amount for such Quarter, as determined by the General Partner. For purposes of the foregoing, Available Cash with respect to a Quarter will be deemed reduced by the Estimated Incremental Quarterly Tax Amount for that Quarter.

(a) The General Partner shall conduct, direct and manage all activities of the Partnership. Except as otherwise expressly provided in this Agreement, all management powers over the business and affairs of the Partnership shall be exclusively vested in the General Partner, and no Limited Partner shall have any management power over the business and affairs of the Partnership. In addition to the powers now or hereafter granted a general partner of a limited partnership under applicable law or that are granted to the General Partner under any other provision of this Agreement, the General Partner, subject to Section 7.3, shall have full power and authority to do all things and on such terms as it determines to be necessary or appropriate to conduct the business of the Partnership, to exercise all powers set forth in Section 2.5 and to effectuate the purposes set forth in Section 2.4, including the following:

(b) Notwithstanding any other provision of this Agreement, any Group Member Agreement, the Delaware Act or any applicable law, rule or regulation, each of the Partners and each other Person who may acquire an interest in Partnership Interests or other economic interests in the Partnership or is otherwise bound by this Agreement hereby (i) approves, ratifies and confirms the execution, delivery and performance by the parties thereto of this Agreement, the Underwriting Agreement, the Contribution Agreement, the Services Agreement, the Omnibus Agreement and the other agreements described in or filed as exhibits to the Registration Statement that are related to the transactions contemplated by the Registration Statement (in each case other than this Agreement, without giving effect to any amendments, supplements or restatements after the date hereof); (ii) agrees that the General Partner (on its own or on behalf of the Partnership) is authorized to execute, deliver and perform the agreements referred to in clause (i) of this sentence and the other agreements, acts, transactions and matters described in or contemplated by the Registration Statement on behalf of the Partnership without any further act, approval or vote of the Partners or the other Persons who may acquire an interest in Partnership Interests or is otherwise bound by this Agreement; and (iii) agrees that the execution, delivery or performance by the General Partner, any Group Member or any Affiliate of any of them of this Agreement or any agreement authorized or permitted under this Agreement (including the exercise by the General Partner or any Affiliate of the General Partner of the rights accorded pursuant to Article XV) shall not constitute a breach by the General Partner of any duty that the General Partner may owe the Partnership or the Limited Partners or any other Persons under this Agreement (or any other agreements) or of any duty existing at law, in equity or otherwise.

The General Partner has caused the Certificate of Limited Partnership to be filed with the Secretary of State of the State of Delaware as required by the Delaware Act. The General Partner shall use all reasonable efforts to cause to be filed such other certificates or documents that the General Partner determines to be necessary or appropriate for the formation, continuation, qualification and operation of a limited partnership (or a partnership in which the limited partners have limited liability) in the State of Delaware or any other state in which the Partnership may elect to do business or own property. To the extent the General Partner determines such action to be necessary or appropriate, the General Partner shall file amendments to and restatements of the Certificate of Limited Partnership and do all things to maintain the Partnership as a limited partnership (or a partnership or other entity in which the limited partners have limited liability) under the laws of the State of Delaware or of any other state in which the Partnership may elect to do business or own property. Subject to the terms of Section 3.4(a), the General Partner shall not be required, before or after filing, to deliver or mail a copy of the Certificate of Limited Partnership, any qualification document or any amendment thereto to any Limited Partner.

Except as provided in Article XII and Article XIV, the General Partner may not sell, exchange or otherwise dispose of all or substantially all of the assets of the Partnership Group, taken as a whole, in a single transaction or a series of related transactions (including by way of merger, consolidation, other combination or sale of ownership interests of the Partnership's Subsidiaries) without the approval of holders of a Unit Majority; provided, however, that this provision shall not preclude or limit the General Partner's ability to mortgage, pledge, hypothecate or grant a security interest in all or substantially all of the assets of the Partnership Group and shall not apply to any forced sale of any or all of the assets of the Partnership Group pursuant to the foreclosure of, or other realization upon, any such encumbrance. Without the approval of holders of a Unit Majority, the General Partner shall not, on behalf of the Partnership, except as permitted under Section 4.6, Section 11.1 and Section 11.2, elect or cause the Partnership to elect a successor general partner of the Partnership.

(a) Except as provided in this Section 7.4 and elsewhere in this Agreement, the General Partner shall not be compensated for its services as a general partner or managing member of any Group Member.

(b) The General Partner shall be reimbursed on a monthly basis, or such other basis as the General Partner may determine, for (i) all direct and indirect expenses it incurs or payments it makes on behalf of the Partnership Group (including salary, bonus, incentive compensation, employment benefits and other amounts paid to any Person, including Affiliates of the General Partner to perform services for the Partnership Group or for the General Partner in the discharge of its duties to the Partnership Group), and (ii) all other expenses allocable to the Partnership Group or otherwise incurred by the General Partner in connection with operating the Partnership Group's business (including expenses allocated to the General Partner by its Affiliates). The General Partner shall determine the expenses that are allocable to the General Partner or the Partnership Group. Reimbursements pursuant to this Section 7.4 shall be in addition to any reimbursement to the General Partner as a result of indemnification pursuant to Section 7.7.

(c) Subject to the applicable rules and regulations of the National Securities Exchange on which the Common Units are listed, the General Partner, without the approval of the Limited Partners (who shall have no other right to vote in respect thereof under this Agreement), may propose and adopt on behalf of the Partnership employee benefit plans, employee programs and employee practices (including plans, programs and practices involving the issuance of Partnership Interests or options to purchase or rights, warrants or appreciation rights or phantom or tracking interests relating to Partnership Interests), or cause the Partnership to issue Partnership Interests in connection with, or pursuant to, any employee benefit plan, employee program or employee practice maintained or sponsored by the General Partner or any of its Affiliates in each case for the benefit of employees and directors of the General Partner or any of its Affiliates, in respect of services performed, directly or indirectly, for the benefit of the Partnership Group. The Partnership agrees to issue and sell to the General Partner or any of its Affiliates any Partnership Interests or other securities that the General Partner or such Affiliates are obligated to provide to any employees, officers and directors pursuant to any such employee benefit plans, employee programs or employee practices. Expenses incurred by the General Partner in connection with any such plans, programs and practices (including the net cost to the General Partner or such Affiliates of Partnership Interests or other securities purchased by the General Partner or such Affiliates from the Partnership to fulfill options or awards under such employee benefit plans, employee programs and employee practices) shall be reimbursed in accordance with Section 7.4(b). Any and all obligations of the General Partner under any employee benefit plans, employee programs or employee practices adopted by the General Partner as permitted by this Section 7.4(c) shall constitute obligations of the General Partner hereunder and shall be assumed by any successor General Partner approved pursuant to Section 11.1 or Section 11.2 or the transferee of or successor to all of the General Partner's General Partner Interest pursuant to Section 4.6.

(a) The General Partner, for so long as it is the General Partner of the Partnership, (i) agrees that its sole business will be to act as a general partner or managing member, as the case may be, of the Partnership and any other partnership or limited liability company of which the Partnership is, directly or indirectly, a partner or member and to undertake activities that are ancillary or related thereto (including being a Limited Partner in the Partnership) and (ii) shall not engage in any business or activity or incur any debts or liabilities except in connection with or incidental to (A) its performance as general partner or managing member, if any, of one or more Group Members or as described in or contemplated by the Registration Statement, (B) the acquiring, owning or disposing of debt securities or equity interests in any Group Member or (C) the guarantee of, and mortgage, pledge, or encumbrance of

any or all of its assets in connection with, any indebtedness of the General Partner or any of its Affiliates.

(b) Each Unrestricted Person (other than the General Partner) shall have the right to engage in businesses of every type and description and other activities for profit and to engage in and possess an interest in other business ventures of any and every type or description, whether in businesses engaged in or anticipated to be engaged in by any Group Member, independently or with others, including business interests and activities in direct competition with the business and activities of any Group Member, and none of the same shall constitute a breach of this Agreement or any duty otherwise existing at law, in equity or otherwise, to any Group Member or any Partner. None of any Group Member, any Limited Partner or any other Person shall have any rights by virtue of this Agreement, any Group Member Agreement, or the partnership relationship established hereby in any business ventures of any Unrestricted Person.

(c) Subject to the terms of Sections 7.5(a) and (b), but otherwise notwithstanding anything to the contrary in this Agreement, (i) the engaging in competitive activities by any Unrestricted Person (other than the General Partner) in accordance with the provisions of this Section 7.5 is hereby approved by the Partnership and all Partners, (ii) it shall be deemed not to be a breach of any fiduciary duty or any other obligation of any type whatsoever of the General Partner or any other Unrestricted Person for the Unrestricted Persons (other than the General Partner) to engage in such business interests and activities in preference to or to the exclusion of the Partnership and (iii) the Unrestricted Persons shall have no obligation hereunder or as a result of any duty otherwise existing at law, in equity or otherwise, to present business opportunities to the Partnership. Notwithstanding anything to the contrary in this Agreement, the doctrine of corporate opportunity, or any analogous doctrine, shall not apply to any Unrestricted Person (including the General Partner). No Unrestricted Person (including the General Partner) who acquires knowledge of a potential transaction, agreement, arrangement or other matter that may be an opportunity for the Partnership, shall have any duty to communicate or offer such opportunity to the Partnership, and such Unrestricted Person (including the General Partner) shall not be liable to the Partnership, to any Limited Partner or any other Person bound by this Agreement for breach of any fiduciary or other duty by reason of the fact that such Unrestricted Person (including the General Partner) pursues or acquires for itself, directs such opportunity to another Person or does not communicate such opportunity or information to the Partnership; provided, however, such Unrestricted Person does not engage in such business or activity as a result of or using confidential or proprietary information provided by or on behalf of the Partnership to such Unrestricted Person.

(d) The General Partner and each of its Affiliates may acquire Units or other Partnership Interests or securities in addition to those acquired on the Closing Date and, except as otherwise provided in this Agreement, shall be entitled to exercise, at their option, all rights relating to all Units and/or other Partnership Interests or securities acquired by them. The term "Affiliates" when used in this Section 7.5(d) with respect to the General Partner shall not include any Group Member.

(e) Notwithstanding anything to the contrary in this Agreement, (i) to the extent that any provision of this Agreement purports or is interpreted to have the effect of restricting or eliminating the fiduciary duties that might otherwise, as a result of Delaware or other applicable law, be owed by the General Partner to the Partnership and the Limited Partners, or to constitute a waiver or consent by the Limited Partners to any such restriction or elimination, such provisions shall be deemed to have been approved by the Partners, and (ii) nothing in this Agreement shall limit or otherwise affect any separate contractual obligation outside of this Agreement or any Person to the Partnership or any of its Affiliates.

Section 7.6 Loans from the General Partner; Loans or Contributions from the Partnership or Group Members.

(a) The General Partner or any of its Affiliates may, but shall be under no obligation to, lend to any Group Member, and any Group Member may borrow from the General Partner or any of its Affiliates, funds needed or desired by the Group Member for such periods of time and in such amounts

as the General Partner may determine; provided, however, that in any such case the lending party may not charge the borrowing party interest at a rate greater than the rate that would be charged the borrowing party or impose terms less favorable to the borrowing party than would be charged or imposed on the borrowing party by unrelated lenders on comparable loans made on an arm's-length basis (without reference to the lending party's financial abilities or guarantees), all as determined by the General Partner. The borrowing party shall reimburse the lending party for any costs (other than any additional interest costs) incurred by the lending party in connection with the borrowing of such funds. For purposes of this Section 7.6(a) and Section 7.6(b), the term "Group Member" shall include any Affiliate of a Group Member that is controlled by the Group Member.

(b) The Partnership may lend or contribute to any Group Member, and any Group Member may borrow from the Partnership, funds on terms and conditions determined by the General Partner. No Group Member may lend funds to the General Partner or any of its Affiliates (other than another Group Member)

(c) No borrowing by any Group Member or the approval thereof by the General Partner shall be deemed to constitute a breach of any duty hereunder or otherwise existing at law, in equity or otherwise, of the General Partner or its Affiliates to the Partnership or the Limited Partners by reason of the fact that the purpose or effect of such borrowing is directly or indirectly to (i) enable distributions to the General Partner or its Affiliates (including in their capacities as Limited Partners) to exceed the General Partner's Percentage Interest of the total amount distributed to all Partners or (ii) hasten the expiration of the Subordination Period or the conversion of any Subordinated Units into Common Units.

(a) To the fullest extent permitted by law but subject to the limitations expressly provided in this Agreement, all Indemnitees shall be indemnified and held harmless by the Partnership from and against any and all losses, claims, damages, liabilities, joint or several, expenses (including legal fees and expenses), judgments, fines, penalties, interest, settlements or other amounts arising from any and all threatened pending or contemplated claims, demands, actions, suits or proceedings, whether civil, criminal, administrative or investigative, and whether formal or informal and including appeals, in which any Indemnitee may be involved, or is threatened to be involved, as a party or otherwise, by reason of its status as an Indemnitee and acting (or refraining to act) in such capacity; provided, however, that the Indemnitee shall not be indemnified and held harmless if there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that, in respect of the matter for which the Indemnitee is seeking indemnification pursuant to this Section 7.7, the Indemnitee acted in bad faith or engaged in fraud, willful misconduct or, in the case of a criminal matter, acted with knowledge that the Indemnitee's conduct was unlawful; provided, further, no indemnification pursuant to this Section 7.7 shall be available to the General Partner or its Affiliates (other than a Group Member) with respect to its or their obligations incurred pursuant to the Underwriting Agreement, the Omnibus Agreement or the Contribution Agreement (other than obligations incurred by the General Partner on behalf of the Partnership). Any indemnification pursuant to this Section 7.7 shall be made only out of the assets of the Partnership, it being agreed that the General Partner shall not be personally liable for such indemnification and shall have no obligation to contribute or loan any monies or property to the Partnership to enable it to effectuate such indemnification.

(b) To the fullest extent permitted by law, expenses (including legal fees and expenses) incurred by an Indemnitee who is indemnified pursuant to Section 7.7(a) in appearing at, participating in or defending any claim, demand, action, suit or proceeding shall, from time to time, be advanced by the Partnership prior to a final and non-appealable judgment entered by a court of competent jurisdiction determining that, in respect of the matter for which the Indemnitee is seeking indemnification pursuant to this Section 7.7, the Indemnitee is not entitled to be indemnified upon receipt by the Partnership of any undertaking by or on behalf of the Indemnitee to repay such amount if it shall be ultimately determined that the Indemnitee is not entitled to be indemnified as authorized by this Section 7.7.

(c) The indemnification provided by this Section 7.7 shall be in addition to any other rights to which an Indemnitee may be entitled under any agreement, pursuant to any vote of the holders of Outstanding Limited Partner Interests, as a matter of law or otherwise, both as to actions in the Indemnitee's capacity as an Indemnitee and as to actions in any other capacity (including any capacity under the Underwriting Agreement), and shall continue as to an Indemnitee who has ceased to serve in such capacity and shall inure to the benefit of the heirs, successors, assigns and administrators of the Indemnitee.

(d) The Partnership may purchase and maintain (or reimburse the General Partner or its Affiliates for the cost of) insurance, on behalf of the General Partner, its Affiliates and such other Persons as the General Partner shall determine, against any liability that may be asserted against, or expense that may be incurred by, such Person in connection with the Partnership's activities or such Person's activities on behalf of the Partnership, regardless of whether the Partnership would have the power to indemnify such Person against such liability under the provisions of this Agreement.

(e) For purposes of this Section 7.7, the Partnership shall be deemed to have requested an Indemnitee to serve as fiduciary of an employee benefit plan whenever the performance by it of its duties to the Partnership also imposes duties on, or otherwise involves services by, it to the plan or participants or beneficiaries of the plan; excise taxes assessed on an Indemnitee with respect to an employee benefit plan pursuant to applicable law shall constitute "fines" within the meaning of Section 7.7(a); and action taken or omitted by it with respect to any employee benefit plan in the performance of its duties for a purpose reasonably believed by it to be in the best interest of the participants and beneficiaries of the plan shall be deemed to be for a purpose that is in the best interests of the Partnership.

(f) In no event may an Indemnitee subject the Limited Partners to personal liability by reason of the indemnification provisions set forth in this Agreement.

(g) An Indemnitee shall not be denied indemnification in whole or in part under this Section 7.7 because the Indemnitee had an interest in the transaction with respect to which the indemnification applies if the transaction was otherwise permitted by the terms of this Agreement.

(h) The provisions of this Section 7.7 are for the benefit of the Indemnitees and their heirs, successors, assigns, executors and administrators and shall not be deemed to create any rights for the benefit of any other Persons.

(i) No amendment, modification or repeal of this Section 7.7 or any provision hereof shall in any manner terminate, reduce or impair the right of any past, present or future Indemnitee to be indemnified by the Partnership, nor the obligations of the Partnership to indemnify any such Indemnitee under and in accordance with the provisions of this Section 7.7 as in effect immediately prior to such amendment, modification or repeal with respect to claims arising from or relating to matters occurring, in whole or in part, prior to such amendment, modification or repeal, regardless of when such claims may arise or be asserted.

(a) Notwithstanding anything to the contrary set forth in this Agreement, no Indemnitee shall be liable for monetary damages to the Partnership, the Limited Partners or any other Persons who have acquired Partnership Interests or are otherwise bound by this Agreement, for losses sustained or liabilities incurred as a result of any act or omission of an Indemnitee unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that, in respect of the matter in question, the Indemnitee acted in bad faith or engaged in fraud, willful misconduct or, in the case of a criminal matter, acted with knowledge that the Indemnitee's conduct was criminal.

(b) Subject to its obligations and duties as General Partner set forth in Section 7.1(a), the General Partner may exercise any of the powers granted to it by this Agreement and perform any of the duties imposed upon it hereunder either directly or by or through its agents, and the General Partner shall not be responsible for any misconduct or negligence on the part of any such agent appointed by the General Partner in good faith.

(c) To the extent that, at law or in equity, an Indemnitee has duties (including fiduciary duties) and liabilities relating thereto to the Partnership or to the Partners, the General Partner and any other Indemnitee acting in connection with the Partnership's business or affairs shall not be liable to the Partnership or to any Partner for its good faith reliance on the provisions of this Agreement.

(d) Any amendment, modification or repeal of this Section 7.8 or any provision hereof shall be prospective only and shall not in any way affect the limitations on the liability of the Indemnitees under this Section 7.8 as in effect immediately prior to such amendment, modification or repeal with respect to claims arising from or relating to matters occurring, in whole or in part, prior to such amendment, modification or repeal, regardless of when such claims may arise or be asserted.

Section 7.9 Resolution of Conflicts of Interest; Standards of Conduct and Modification of Duties.

(a) Unless otherwise expressly provided in this Agreement or any Group Member Agreement, whenever a potential conflict of interest exists or arises between the General Partner (in its individual capacity or its capacity as general partner or limited partner) or any of its Affiliates, on the one hand, and the Partnership, any Group Member or any Partner, on the other, any resolution or course of action by the General Partner or its Affiliates in respect of such conflict of interest shall be permitted and deemed approved by all Partners, and shall not constitute a breach of this Agreement, of any Group Member Agreement, of any agreement contemplated herein or therein, or of any duty stated or implied by law or equity, if the resolution or course of action in respect of such conflict of interest is (i) approved by Special Approval, (ii) approved by the vote of a majority of the Outstanding Common Units (excluding Common Units owned by the General Partner and its Affiliates), (iii) on terms no less favorable to the Partnership than those generally being provided to or available from unrelated third parties or (iv) fair and reasonable to the Partnership, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to the Partnership). The General Partner shall be authorized but not required in connection with its resolution of such conflict of interest to seek Special Approval or Unitholder approval of such resolution, and the General Partner may also adopt a resolution or course of action that has not received Special Approval or Unitholder approval. If Special Approval is sought, then, notwithstanding any other provision of this Agreement or applicable law, (A) any Conflicts Committee shall be authorized in connection with its determination of whether to provide Special Approval to consider any and all factors as it determines to be relevant or appropriate under the circumstances and shall have no duty or obligation to consider any other factors, and (B) it shall be presumed that, in making its decision, the Conflicts Committee acted in good faith, and if neither Special Approval or Unitholder approval is sought and the Board of Directors determines that the resolution or course of action taken with respect to a conflict of interest satisfies either of the standards set forth in clauses (iii) or (iv) above, then it shall be presumed that, in making its decision, the Board of Directors acted in good faith, and in either case, in any proceeding brought by any Limited Partner or by or on behalf of such Limited Partner or any other Limited Partner or the Partnership challenging such approval, the Person bringing or prosecuting such proceeding shall have the burden of overcoming such presumption. Notwithstanding anything to the contrary in this Agreement or any duty otherwise existing at law or equity, the existence of the conflicts of interest described in the Registration Statement are hereby approved by all Partners and shall not constitute a breach of this Agreement or of any duty hereunder or existing at law, in equity or otherwise.

(b) Whenever the General Partner, the Board of Directors or any committee thereof (including the Conflicts Committee) makes a determination or takes or declines to take any other action, or any of

its Affiliates causes the General Partner to do so, in the General Partner's capacity as the general partner of the Partnership as opposed to in its individual capacity, whether under this Agreement, any Group Member Agreement or any other agreement contemplated hereby or otherwise, then, unless another express standard is provided for in this Agreement, the General Partner, the Board of Directors, such committee or such Affiliates causing the General Partner to do so, shall make such determination or take or decline to take such other action in good faith and shall not be subject to any other or different standards (including fiduciary standards) imposed by this Agreement, any Group Member Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity. In order for a determination or other action to be in "good faith" for purposes of this Agreement, the Person or Persons making such determination or taking or declining to take such other action must believe that the determination or other action is in, or not opposed to, the best interests of the Partnership.

(c) Whenever the General Partner makes a determination or takes or declines to take any other action, or any of its Affiliates causes it to do so, in its individual capacity as opposed to in its capacity as the general partner of the Partnership, whether under this Agreement, any Group Member Agreement or any other agreement contemplated hereby or otherwise, then the General Partner, or such Affiliates causing it to do so, are entitled, to the fullest extent permitted by law, to make such determination or to take or decline to take such other action free of any duty (including any fiduciary duty) or obligation whatsoever to the Partnership, any Limited Partner and any other Person bound by this Agreement, and the General Partner, or such Affiliates causing it to do so, shall not, to the fullest extent permitted by law, be required to act in good faith or pursuant to any other standard imposed by this Agreement, any Group Member Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity. By way of illustration and not of limitation, whenever the phrases, "at the option of the General Partner," "in its sole discretion" or some variation of those phrases, are used in this Agreement, it indicates that the General Partner is acting in its individual capacity. For the avoidance of doubt, whenever the General Partner votes or transfers its Partnership Interests, or refrains from voting or transferring its Partnership Interests, or otherwise acts in its capacity as a limited partner or holder of Partnership Interests, it shall be acting in its individual capacity.

(d) The General Partner's organizational documents may provide that determinations to take or decline to take any action in its individual, rather than representative, capacity may or shall be determined by its members, if the General Partner is a limited liability company, stockholders, if the General Partner is a corporation, or the members or stockholders of the General Partner's general partner, if the General Partner is a partnership

(e) Notwithstanding anything to the contrary in this Agreement, the General Partner and its Affiliates shall have no duty or obligation, express or implied, to (i) sell or otherwise dispose of any asset of the Partnership Group other than in the ordinary course of business or (ii) permit any Group Member to use any facilities or assets of the General Partner and its Affiliates, except as may be provided in contracts entered into from time to time specifically dealing with such use. Any determination by the General Partner or any of its Affiliates to enter into such contracts shall be in its sole discretion.

(f) Except as expressly set forth in this Agreement, neither the General Partner nor any other Indemnitee shall have any duties or liabilities, including fiduciary duties, to the Partnership or any Limited Partner and the provisions of this Agreement, to the extent that they restrict, eliminate or otherwise modify the duties and liabilities, including fiduciary duties, of the General Partner or any other Indemnitee otherwise existing at law or in equity, are agreed by the Partners to replace such other duties and liabilities of the General Partner or such other Indemnitee.

(g) The Limited Partners hereby authorize the General Partner, on behalf of the Partnership as a partner or member of a Group Member, to approve of actions by the general partner or managing

member of such Group Member similar to those actions permitted to be taken by the General Partner pursuant to this Section 7.9.

(a) The General Partner may rely upon, and shall be protected in acting or refraining from acting upon, any resolution, certificate, statement, instrument, opinion, report, notice, request, consent, order, bond, debenture or other paper or document believed by it to be genuine and to have been signed or presented by the proper party or parties.

(b) The General Partner may consult with legal counsel, accountants, appraisers, management consultants, investment bankers and other consultants and advisers selected by it, and any act taken or omitted to be taken in reliance upon the advice or opinion (including an Opinion of Counsel) of such Persons as to matters that the General Partner reasonably believes to be within such Person's professional or expert competence shall be conclusively presumed to have been done or omitted in good faith and in accordance with such advice or opinion.

(c) The General Partner shall have the right, in respect of any of its powers or obligations hereunder, to act through any of its duly authorized officers, a duly appointed attorney or attorneys-in-fact or the duly authorized officers of the Partnership or any Group Member.

The General Partner may cause the Partnership to purchase or otherwise acquire Partnership Interests or other securities; provided, however, that, except as permitted pursuant to Section 4.10, the General Partner may not cause any Group Member to purchase Subordinated Units during the Subordination Period. As long as Partnership Interests or other securities are held by any Group Member, such Partnership Interests or other securities shall not be considered Outstanding for any purpose, except as otherwise provided herein. The General Partner or any Affiliate of the General Partner may also purchase or otherwise acquire and sell or otherwise dispose of Partnership Interests for its own account, subject to the provisions of Articles IV and X.

(a) If (i) the General Partner or any Affiliate of the General Partner, including the Fund Group (and also including, for purposes of this Section 7.12, any Person that is an Affiliate of the General Partner at the date hereof notwithstanding that it may later cease to be an Affiliate of the General Partner, but excluding any individual who is an Affiliate of the General Partner based on such individual's status as an officer, director or employee of the General Partner or an Affiliate of the General Partner), holds Partnership Interests that it desires to sell and (ii) Rule 144 of the Securities Act (or any successor rule or regulation to Rule 144) or another exemption from registration is not available to enable such holder of Partnership Interests (the "Holder") to dispose of the number of Partnership Interests it desires to sell at the time it desires to do so without registration under the Securities Act, then at the option and upon the request of the Holder, the Partnership shall file with the Commission as promptly as practicable after receiving such request, and use all commercially reasonable efforts to cause to become effective and remain effective for a period of not less than six months following its effective date or such shorter period as shall terminate when all Partnership Interests covered by such registration statement have been sold, a registration statement under the Securities Act registering the offering and sale of the number of Partnership Interests specified by the Holder; provided, however, that if the Conflicts Committee determines that a postponement of the requested registration would be in the best interests of the Partnership and its Partners due to a pending transaction, investigation or other event, the filing of such registration statement or the effectiveness thereof may be deferred until such time as the Conflicts Committee determines that such pending transaction, investigation or other event no longer requires such postponement; provided, however, that the Partnership shall not be required to effect more than three registrations pursuant to this Section 7.12(a); provided further, however, that such postponement shall not exceed more than six months. In connection with any registration pursuant to

the first sentence of this Section 7.12(a), the Partnership shall (i) promptly prepare and file (A) such documents as may be necessary to register or qualify the securities subject to such registration under the securities laws of such states as the Holder shall reasonably request; provided, however, that no such qualification shall be required in any jurisdiction where, as a result thereof, the Partnership would become subject to general service of process or to taxation or qualification to do business as a foreign corporation or partnership doing business in such jurisdiction solely as a result of such registration, and (B) such documents as may be necessary to apply for listing or to list the Partnership Interests subject to such registration on such National Securities Exchange as the Holder shall reasonably request and (ii) do any and all other acts and things that may be necessary or appropriate to enable the Holder to consummate a public sale of such Partnership Interests in such states. Except as set forth in Section 7.12(d) below, all costs and expenses of any such registration and offering (other than the underwriting fees, discounts and commissions) shall be paid by the Partnership, without reimbursement by the Holder.

(b) If any Holder holds Partnership Interests that it desires to sell and Rule 144 of the Securities Act (or any successor rule or regulation to Rule 144) or another exemption from registration is not available to enable such Holder to dispose of the number of Partnership Interests it desires to sell at the time it desires to do so without registration under the Securities Act, then at the option and upon the request of the Holder, the Partnership shall file with the Commission as promptly as practicable after receiving such request, and use all commercially reasonable efforts to cause to become effective and remain effective for a period of not less than six months following its effective date or such shorter period as shall terminate when all Partnership Interests covered by such shelf registration statement have been sold, a "shelf" registration statement covering the Partnership Interests specified by the Holder on an appropriate form under Rule 415 under the Securities Act, or any similar rule that may be adopted by the Commission; provided, however, that if a Conflicts Committee determines that it would be in the best interests of the Partnership and its Partners to suspend the filing of such shelf registration statement or any offering under, or use of any prospectus forming a part of, the shelf registration statement due to a pending transaction, investigation or other event, then the Partnership shall have the right to suspend such filing, offering or use until such time as a Conflicts Committee determines that such pending transaction, investigation or other event no longer requires such suspension; provided, however, that such suspension shall not exceed more than six months. In connection with any shelf registration pursuant to this Section 7.12(b), the Partnership shall (i) promptly prepare and file (A) such documents as may be necessary to register or qualify the securities subject to such shelf registration under the securities laws of such states as the Holder shall reasonably request; provided, however, that no such qualification shall be required in any jurisdiction where, as a result thereof, the Partnership would become subject to general service of process or to taxation or qualification to do business as a foreign corporation or partnership doing business in such jurisdiction solely as a result of such shelf registration, and (B) such documents as may be necessary to apply for listing or to list the Partnership Interests subject to such shelf registration on such National Securities Exchange as the Holder shall reasonably request, and (ii) do any and all other acts and things that may be necessary or appropriate to enable the Holder to consummate a public sale of such Partnership Interests in such states. Except as set forth in Section 7.12(d) below, all costs and expenses of any such shelf registration and offering (other than the underwriting fees, discounts and commissions) shall be paid by the Partnership, without reimbursement by the Holder.

(c) If the Partnership shall at any time propose to file a registration statement under the Securities Act for an offering of Partnership Interests for cash (other than a registration relating solely to a benefit plan, a registration statement relating solely to a Rule 145 transaction or on any registration form which does not permit secondary sales), the Partnership shall use all commercially reasonable efforts to include such number or amount of Partnership Interests held by any Holder in such registration statement as the Holder shall request; provided, however, that the Partnership is not required to make any effort or take any action to so include the Partnership Interests of the Holder once the registration statement becomes or is declared effective by the Commission, including any registration

statement providing for the offering from time to time of Partnership Interests pursuant to Rule 415 of the Securities Act. If the proposed offering pursuant to this Section 7.12(c) shall be an underwritten offering, then, in the event that the managing underwriter or managing underwriters of such offering advise the Partnership and the Holder in writing that in their opinion the inclusion of all or some of the Holder's Partnership Interests would adversely and materially affect the timing or success of the offering, the Partnership shall include in such offering only that number or amount, if any, of Partnership Interests held by the Holder that, in the opinion of the managing underwriter or managing underwriters, will not so adversely and materially affect the offering. Except as set forth in Section 7.12(d) below, all costs and expenses of any such registration and offering (other than the underwriting fees, discounts and commissions) shall be paid by the Partnership, without reimbursement by the Holder. During the two year period set forth in Section 7.12(e), the Partnership shall not grant to any other party registration rights similar to the rights set forth in this Section 7.12(c) that are superior to such rights without the consent of the General Partner (and any of its Affiliates).

(d) If underwriters are engaged in connection with any registration referred to in this Section 7.12, the Partnership shall provide indemnification, representations, covenants, opinions, comfort letters and other assurance to the underwriters in form and substance reasonably satisfactory to such underwriters. Further, in addition to and not in limitation of the Partnership's obligation under Section 7.7, the Partnership shall, to the fullest extent permitted by law, indemnify and hold harmless the Holder, its officers, directors and each Person who controls the Holder (within the meaning of the Securities Act) and any agent thereof (collectively, "Indemnified Persons") from and against any and all losses, claims, damages, liabilities, joint or several, expenses (including legal fees and expenses), judgments, fines, penalties, interest, settlements or other amounts arising from any and all claims, demands, actions, suits or proceedings, whether civil, criminal, administrative or investigative, in which any Indemnified Person may be involved, or is threatened to be involved, as a party or otherwise, under the Securities Act or otherwise (hereinafter referred to in this Section 7.12(d) as a "claim" and in the plural as "claims") based upon, arising out of or resulting from any untrue statement or alleged untrue statement of any material fact contained in any registration statement under which any Partnership Interests were registered under the Securities Act or any state securities or Blue Sky laws, in any preliminary prospectus (if used prior to the effective date of such registration statement), or in any summary or final prospectus or any free writing prospectus or in any amendment or supplement thereto (if used during the period the Partnership is required to keep the registration statement current), or arising out of, based upon or resulting from the omission or alleged omission to state therein a material fact required to be stated therein or necessary to make the statements made therein not misleading; provided, however, that the Partnership shall not be liable to any Indemnified Person to the extent that any such claim arises out of, is based upon or results from an untrue statement or alleged untrue statement or omission or alleged omission made in such registration statement, such preliminary, summary or final prospectus or any free writing prospectus or such amendment or supplement, in reliance upon and in conformity with written information furnished to the Partnership by or on behalf of such Indemnified Person specifically for use in the preparation thereof.

(e) The provisions of Section 7.12(a), Section 7.12(b) and Section 7.12(c) shall continue to be applicable with respect to the General Partner (and any of the General Partner's Affiliates) after it ceases to be a general partner of the Partnership, during a period of two years subsequent to the effective date of such cessation and for so long thereafter as is required for the Holder to sell all of the Partnership Interests with respect to which it has requested during such two-year period inclusion in a registration statement otherwise filed or that a registration statement be filed; provided, however, that the Partnership shall not be required to file successive registration statements covering the same Partnership Interests for which registration was demanded during such two-year period. The provisions of Section 7.12(d) shall continue in effect thereafter.

(f) The rights to cause the Partnership to register Partnership Interests pursuant to this Section 7.12 may be assigned (but only with all related obligations) by a Holder to a transferee or

assignee of such Partnership Interests, provided that (i) each such transferee or assignee (or group of transferees and assignees if affiliated) holds Partnership Interests representing at least 20% (after giving effect to such transfer or assignment) of the Partnership Interests held by such Holder as of the date hereof; (ii) the Partnership is given written notice prior to any said transfer or assignment, stating the name and address of such transferee or assignee and the Partnership Interests with respect to which such registration rights are being transferred or assigned; and (iii) such transferee or assignee agrees in writing to be bound by and subject to the terms set forth in this Section 7.12.

(g) Any request to register Partnership Interests pursuant to this Section 7.12 shall (i) specify the Partnership Interests intended to be offered and sold by the Person making the request, (ii) express such Person's present intent to offer such Partnership Interests for distribution, (iii) describe the nature or method of the proposed offer and sale of Partnership Interests, and (iv) contain the undertaking of such Person to provide all such information and materials and take all action as may be required in order to permit the Partnership to comply with all applicable requirements in connection with the registration of such Partnership Interests.

(h) The Partnership agrees to use its commercially reasonable efforts to take all actions and deliver, or cause to be delivered, all prospectuses, supplemental prospectuses and any free writing prospectuses to Holders, or as directed by Holders, as required by applicable law.

Notwithstanding anything to the contrary in this Agreement, any Person dealing with the Partnership shall be entitled to assume that the General Partner and any officer of the General Partner authorized by the General Partner to act on behalf of and in the name of the Partnership has full power and authority to encumber, sell or otherwise use in any manner any and all assets of the Partnership and to enter into any authorized contracts on behalf of the Partnership, and such Person shall be entitled to deal with the General Partner or any such officer as if it were the Partnership's sole party in interest, both legally and beneficially. Each Limited Partner hereby waives, to the fullest extent permitted by law, any and all defenses or other remedies that may be available against such Person to contest, negate or disaffirm any action of the General Partner or any such officer in connection with any such dealing. In no event shall any Person dealing with the General Partner or any such officer or its representatives be obligated to ascertain that the terms of this Agreement have been complied with or to inquire into the necessity or expedience of any act or action of the General Partner or any such officer or its representatives. Each and every certificate, document or other instrument executed on behalf of the Partnership by the General Partner or its representatives shall be conclusive evidence in favor of any and every Person relying thereon or claiming thereunder that (a) at the time of the execution and delivery of such certificate, document or instrument, this Agreement was in full force and effect, (b) the Person executing and delivering such certificate, document or instrument was duly authorized and empowered to do so for and on behalf of the Partnership and (c) such certificate, document or instrument was duly executed and delivered in accordance with the terms and provisions of this Agreement and is binding upon the Partnership.

The General Partner shall keep or cause to be kept at the principal office of the Partnership appropriate books and records with respect to the Partnership's business, including all books and records necessary to provide to the Limited Partners any information required to be provided pursuant to Section 3.4(a). Any books and records maintained by or on behalf of the Partnership in the regular course of its business, including the record of the Record Holders of Units or other Partnership Interests, books of account and records of Partnership proceedings, may be kept on, or be in the form of,

computer disks, hard drives, magnetic tape, photographs, micrographics or any other information storage device; provided, however, that the books and records so maintained are convertible into clearly legible written form within a reasonable period of time. The books of the Partnership shall be maintained, for financial reporting purposes, on an accrual basis in accordance with U.S. GAAP. The Partnership shall not be required to keep books maintained on a cash basis and the General Partner shall be permitted to calculate cash-based measures, including Operating Surplus and Adjusted Operating Surplus, by making such adjustments to its accrual basis books to account for non-cash items and other adjustments as the General Partner determines to be necessary or appropriate.

(a) As soon as practicable, but in no event later than 90 days after the close of each fiscal year of the Partnership, the General Partner shall cause to be mailed or made available, by any reasonable means to each Record Holder of a Unit as of a date selected by the General Partner, an annual report containing financial statements of the Partnership for such fiscal year of the Partnership, presented in accordance with U.S. GAAP, including a balance sheet and statements of operations, Partnership equity and cash flows, such statements to be audited by a firm of independent public accountants selected by the General Partner.

(b) As soon as practicable, but in no event later than 45 days after the close of each Quarter except the last Quarter of each fiscal year, the General Partner shall cause to be mailed or made available, by any reasonable means to each Record Holder of a Unit, as of a date selected by the General Partner, a report containing unaudited financial statements of the Partnership and such other information as may be required by applicable law, regulation or rule of any National Securities Exchange on which the Units are listed or admitted to trading, or as the General Partner determines to be necessary or appropriate.

(c) The General Partner shall be deemed to have made a report available to each Record Holder as required by this Section 8.3 if it has either (i) filed such report with the Commission via its Electronic Data Gathering, Analysis and Retrieval system and such report is publicly available on such system or (ii) made such report available on any publicly available website maintained by the Partnership.

The Partnership shall timely file all returns of the Partnership that are required for U.S. federal, state and local income tax purposes on the basis of the accrual method and the taxable period or years that it is required by law to adopt, from time to time, as determined by the General Partner. In the event the Partnership is required to use a taxable period other than a year ending on December 31, the General Partner shall use reasonable efforts to change the taxable period of the Partnership to a year ending on December 31. The tax information reasonably required by Record Holders for U.S. federal, state and local income tax reporting purposes with respect to a taxable period shall be furnished to them within 90 days of the close of the calendar year in which the Partnership's taxable period ends. The classification, realization and recognition of income, gain, losses and deductions and other items shall be on the accrual method of accounting for U.S. federal income tax purposes.

(a) The Partnership shall make the election under Section 754 of the Code in accordance with applicable regulations thereunder, subject to the reservation of the right to seek to revoke any such

election upon the General Partner's determination that such revocation is in the best interests of the Limited Partners. Notwithstanding any other provision herein contained, for the purposes of computing the adjustments under Section 743(b) of the Code, the General Partner shall be authorized (but not required) to adopt a convention whereby the price paid by a transferee of a Limited Partner Interest will be deemed to be the lowest quoted closing price of the Limited Partner Interests on any National Securities Exchange on which such Limited Partner Interests are listed or admitted to trading during the calendar month in which such transfer is deemed to occur pursuant to Section 6.2(h) without regard to the actual price paid by such transferee.

(b) Except as otherwise provided herein, the General Partner shall determine whether the Partnership should make any other elections permitted by the Code.

Subject to the provisions hereof, the General Partner is designated as the Tax Matters Partner (as defined in the Code) and is authorized and required to represent the Partnership (at the Partnership's expense) in connection with all examinations of the Partnership's affairs by tax authorities, including resulting administrative and judicial proceedings, and to expend Partnership funds for professional services and costs associated therewith. Each Partner agrees to cooperate with the General Partner and to do or refrain from doing any or all things reasonably required by the General Partner to conduct such proceedings.

(a) The General Partner may treat taxes paid by the Partnership on behalf of, all or less than all of the Partners, either as a distribution of cash to such Partners or as a general expense of the Partnership, as determined appropriate under the circumstances by the General Partner.

(b) Notwithstanding any other provision of this Agreement, the General Partner is authorized to take any action that may be required to cause the Partnership and other Group Members to comply with any withholding requirements established under the Code or any other federal, state or local law including pursuant to Sections 1441, 1442, 1445 and 1446 of the Code. To the extent that the Partnership is required or elects to withhold and pay over to any taxing authority any amount resulting from the allocation or distribution of income or from a distribution to any Partner (including by reason of Section 1446 of the Code), the General Partner may treat the amount withheld as a distribution of cash pursuant to Section 6.3 in the amount of such withholding from such Partner.

(a) By acceptance of the transfer of any Limited Partner Interests in accordance with Article IV or the acceptance of any Limited Partner Interests issued pursuant to Article V or pursuant to a merger or consolidation or conversion pursuant to Article XIV, and except as provided in Sections 4.8 or 7.11, each transferee of, or other such Person acquiring, a Limited Partner Interest (including any nominee holder or an agent or representative acquiring such Limited Partner Interests for the account of another Person) (i) shall be admitted to the Partnership as a Limited Partner with respect to the Limited Partner Interests transferred or issued to such Person when any such transfer or admission is reflected in the books and records of the Partnership and such Limited Partner becomes the Record Holder of the Limited Partner Interests so transferred, (ii) shall become bound by the terms of this Agreement, (iii) represents that the transferee has the capacity, power and authority to enter into this Agreement and (iv) makes the consents, acknowledgements and waivers contained in this Agreement, all with or without execution of this Agreement by such Person. A Person may become a Limited Partner or Record Holder of a Limited Partner Interest without the consent or approval of any of the Partners. The transfer

of any Limited Partner Interests and the admission of any new Limited Partner shall not constitute an amendment to this Agreement. A Person may not become a Limited Partner without acquiring a Limited Partner Interest and until such Person is reflected in the books and records of the Partnership as the Record Holder of such Limited Partner Interest. The rights and obligations of a Person who is an Ineligible Holder shall be determined in accordance with Section 4.8.

(b) The name and mailing address of each Limited Partner shall be listed on the books and records of the Partnership maintained for such purpose by the General Partner or the Transfer Agent. The General Partner shall update the books and records of the Partnership from time to time as necessary to reflect accurately the information therein (or shall cause the Transfer Agent to do so, as applicable). A Limited Partner Interest may be represented by a Certificate, as provided in Section 4.1.

(c) Any transfer of a Limited Partner Interest shall not entitle the transferee to share in the profits and losses, to receive distributions, to receive allocations of income, gain, loss, deduction or credit or any similar item or to any other rights to which the transferor was entitled until the transferee becomes a Limited Partner pursuant to Section 10.1(a).

A successor General Partner approved pursuant to Section 11.1 or Section 11.2 or the transferee of or successor to all or part of the General Partner Interest pursuant to Section 4.6 who is proposed to be admitted as a successor General Partner shall be admitted to the Partnership as the General Partner, effective immediately prior to the withdrawal or removal of the predecessor or transferring General Partner, pursuant to Section 11.1 or 11.2 or the transfer of the General Partner Interest pursuant to Section 4.6, provided, however, that no such Person shall be admitted to the Partnership as a successor or additional General Partner until compliance with the terms of Section 4.6 has occurred and such Person has executed and delivered such other documents or instruments as may be required to effect such admission, including a counterpart to this Agreement. Any such successor or additional General Partner is hereby authorized to, and shall, subject to the terms hereof, carry on the business of the members of the Partnership Group without dissolution.

To effect the admission to the Partnership of any Partner, the General Partner shall take all steps necessary or appropriate under the Delaware Act to amend the records of the Partnership to reflect such admission and, if necessary, to prepare as soon as practicable an amendment to this Agreement and, if required by law, the General Partner shall prepare and file an amendment to the Certificate of Limited Partnership.

(a) The General Partner shall be deemed to have withdrawn from the Partnership upon the occurrence of any one of the following events (each such event herein referred to as an "Event of Withdrawal"):

If an Event of Withdrawal specified in Section 11.1(a)(iv), (v) or (vi)(A), (B), (C) or (E) occurs, the withdrawing General Partner shall give notice to the Limited Partners within 30 days after such occurrence. The Partners hereby agree that only the Events of Withdrawal described in this Section 11.1 shall result in the withdrawal of the General Partner from the Partnership.

(b) Withdrawal of the General Partner from the Partnership upon the occurrence of an Event of Withdrawal shall not constitute a breach of this Agreement under the following circumstances: (i) at any time during the period beginning on the Closing Date and ending at 11:59 pm, prevailing Central Time, on December 31, 2021, the General Partner voluntarily withdraws by giving at least 90 days' advance notice of its intention to withdraw to the Limited Partners; provided, however, that prior to the effective date of such withdrawal, the withdrawal is approved by Unitholders holding at least a majority of the Outstanding Common Units (excluding Common Units held by the General Partner and its Affiliates) and the General Partner delivers to the Partnership an Opinion of Counsel ("Withdrawal Opinion of Counsel") that such withdrawal (following the selection of the successor General Partner) would not result in the loss of the limited liability under the Delaware Act of any Limited Partner or cause any Group Member to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not already so treated or taxed); (ii) at any time after 11:59 pm, prevailing Central Time, on December 31, 2021, the General Partner voluntarily withdraws by giving at least 90 days' advance notice to the Unitholders, such withdrawal to take effect on the date specified in such notice; (iii) at any time that the General Partner ceases to be the General Partner pursuant to Section 11.1(a)(ii) or is removed pursuant to Section 11.2; or (iv) notwithstanding clause (i) of this sentence, at any time that the General Partner voluntarily withdraws by giving at least 90 days' advance notice of its intention to withdraw to the Limited Partners, such withdrawal to take effect on the date specified in the notice, if at the time such notice is given one Person and its Affiliates (other than the General Partner and its Affiliates) own beneficially or of record or control at least 50% of the Outstanding Units. The withdrawal of the General Partner from the Partnership upon the occurrence of an Event of Withdrawal shall also constitute the withdrawal of the General Partner as general partner or managing member, if any, to the extent applicable, of the other Group Members. If the General Partner gives a notice of withdrawal pursuant to Section 11.1(a)(i), the holders of a Unit Majority, may, prior to the effective date of such withdrawal, elect a successor General Partner. The Person so elected as successor General Partner shall automatically become the successor general partner or managing member, to the extent applicable, of the other Group Members of which the General Partner is a general partner or a managing member. If, prior to the effective date of the General Partner's withdrawal

pursuant to Section 11.1(a), a successor is not selected by the Unitholders as provided herein or the Partnership does not receive a Withdrawal Opinion of Counsel, the Partnership shall be dissolved in accordance with Section 12.1 unless the business of the Partnership is continued pursuant to Section 12.2. Any successor General Partner elected in accordance with the terms of this Section 11.1 shall be subject to the provisions of Section 10.2.

The General Partner may be removed if such removal is approved by the Unitholders holding at least 66²/3% of the Outstanding Units (including Units held by the General Partner and its Affiliates) voting as a single class. Any such action by such holders for removal of the General Partner must also provide for the election of a successor General Partner by the Unitholders holding a majority of the outstanding Common Units voting as a separate class and a majority of the outstanding Subordinated Units (if any Subordinated Units are then Outstanding) voting as a separate class (including, in each case, Units held by the General Partner and its Affiliates). Such removal shall be effective immediately following the admission of a successor General Partner pursuant to Section 10.2. To the fullest extent permitted by law, the removal of the General Partner shall also automatically constitute the removal of the General Partner as general partner or managing member, to the extent applicable, of the other Group Members of which the General Partner is a general partner or a managing member. To the fullest extent permitted by law, if a Person is elected as a successor General Partner in accordance with the terms of this Section 11.2, such Person shall, upon admission pursuant to Section 10.2, automatically become a successor general partner or managing member, to the extent applicable, of the other Group Members of which the General Partner is a general partner or a managing member. The right of the holders of Outstanding Units to remove the General Partner shall not exist or be exercised unless the Partnership has received an opinion opining as to the matters covered by a Withdrawal Opinion of Counsel. Any successor General Partner elected in accordance with the terms of this Section 11.2 shall be subject to the provisions of Section 10.2.

Section 11.3 Interest of Departing General Partner and Successor General Partner.

(a) In the event of (i) withdrawal of the General Partner under circumstances where such withdrawal does not violate this Agreement or (ii) removal of the General Partner by the holders of Outstanding Units under circumstances where Cause does not exist, if the successor General Partner is elected in accordance with the terms of Section 11.1 or Section 11.2, the Departing General Partner shall have the option, exercisable prior to the effective date of the withdrawal or removal of such Departing General Partner, to require its successor to purchase its General Partner Interest and its or its Affiliates' general partner interest (or equivalent interest), if any, in the other Group Members and all of its or its Affiliates' Incentive Distribution Rights (collectively, the "Combined Interest") in exchange for an amount in cash equal to the fair market value of such Combined Interest, such amount to be determined and payable as of the effective date of its withdrawal or removal. If the General Partner is removed by the Unitholders under circumstances where Cause exists or if the General Partner withdraws under circumstances where such withdrawal violates this Agreement, and if a successor General Partner is elected in accordance with the terms of Section 11.1 or Section 11.2 (or if the business of the Partnership is continued pursuant to Section 12.2 and the successor General Partner is not the former General Partner), such successor shall have the option, exercisable prior to the effective date of the withdrawal or removal of such Departing General Partner (or, in the event the business of the Partnership is continued, prior to the date the business of the Partnership is continued), to purchase the Combined Interest in exchange for an amount in cash equal to the fair market value of such Combined Interest of the Departing General Partner. In either event, the Departing General Partner shall be entitled to receive all reimbursements due such Departing General Partner pursuant to Section 7.4, including any employee-related liabilities (including severance liabilities), incurred in connection with the termination of any employees employed by the Departing General Partner or its Affiliates (other than any Group Member) for the benefit of the Partnership or the other Group Members.

For purposes of this Section 11.3(a), the fair market value of the Combined Interest shall be determined by agreement between the Departing General Partner and its successor or, failing agreement within 30 days after the effective date of such Departing General Partner's withdrawal or removal, by an independent investment banking firm or other independent expert selected by the Departing General Partner and its successor, which, in turn, may rely on other experts, and the determination of which shall be conclusive as to such matter. If such parties cannot agree upon one independent investment banking firm or other independent expert within 45 days after the effective date of such withdrawal or removal, then the Departing General Partner shall designate an independent investment banking firm or other independent expert, the Departing General Partner's successor shall designate an independent investment banking firm or other independent expert, and such firms or experts shall mutually select a third independent investment banking firm or independent expert, which third independent investment banking firm or other independent expert shall determine the fair market value of the Combined Interest. In making its determination, such third independent investment banking firm or other independent expert may consider the value of the Units, including the then current trading price of Units on any National Securities Exchange on which Units are then listed or admitted to trading, the value of the Partnership's assets, the rights and obligations of the Departing General Partner, the value of the Incentive Distribution Rights and the General Partner Interest and other factors it may deem relevant.

(b) If the Combined Interest is not purchased in the manner set forth in Section 11.3(a), the Departing General Partner (or its transferee) shall become a Limited Partner and the Combined Interest shall be converted into Common Units pursuant to a valuation made by an investment banking firm or other independent expert selected pursuant to Section 11.3(a), without reduction in such Partnership Interest (but subject to proportionate dilution by reason of the admission of its successor). Any successor General Partner shall indemnify the Departing General Partner (or its transferee) as to all debts and liabilities of the Partnership arising on or after the date on which the Departing General Partner (or its transferee) becomes a Limited Partner. For purposes of this Agreement, conversion of the Combined Interest of the Departing General Partner to Common Units will be characterized as if the Departing General Partner (or its transferee) contributed the Combined Interest to the Partnership in exchange for the newly issued Common Units.

(c) If a successor General Partner is elected in accordance with the terms of Section 11.1 or Section 11.2 (or if the business of the Partnership is continued pursuant to Section 12.2 and the successor General Partner is not the former General Partner) and the option described in Section 11.3(a) is not exercised by the party entitled to do so, the successor General Partner shall, at the effective date of its admission to the Partnership, contribute to the Partnership cash in the amount equal to the product of (x) the quotient obtained by dividing (A) the Percentage Interest of the General Partner Interest of the Departing General Partner by (B) a percentage equal to 100% less the Percentage Interest of the General Partner Interest of the Departing General Partner and (y) the Net Agreed Value of the Partnership's assets on such date. In such event, such successor General Partner shall, subject to the following sentence, be entitled to its Percentage Interest of all Partnership allocations and distributions to which the Departing General Partner was entitled in respect of its General Partner Interest. In addition, the successor General Partner shall cause this Agreement to be amended to reflect that, from and after the date of such successor General Partner's admission, the successor General Partner's interest in all Partnership distributions and allocations shall be its Percentage Interest.

Section 11.4 Termination of Subordination Period, Conversion of Subordinated Units and Extinguishment of Cumulative Common Unit Arrearages.

Notwithstanding any provision of this Agreement, if the General Partner is removed as general partner of the Partnership under circumstances where Cause does not exist:

provided, however, that such converted Subordinated Units shall remain subject to the provisions of Sections 5.5(c)(ii), 6.1(d)(x) and 6.7.

No Limited Partner shall have any right to withdraw from the Partnership; provided, however, that when a transferee of a Limited Partner's Limited Partner Interest becomes a Record Holder of the Limited Partner Interest so transferred, such transferring Limited Partner shall cease to be a Limited Partner with respect to the Limited Partner Interest so transferred.

The Partnership shall not be dissolved by the admission of additional Limited Partners or by the admission of a successor or additional General Partner in accordance with the terms of this Agreement. Upon the removal or other event of withdrawal of the General Partner, if a successor General Partner is elected pursuant to Section 11.1, Section 11.2 or Section 12.2, the Partnership shall not be dissolved and such successor General Partner is hereby authorized to, and shall, continue the business of the Partnership. The Partnership shall dissolve, and (subject to Section 12.2) its affairs shall be wound up, upon:

Upon (a) dissolution of the Partnership following an Event of Withdrawal caused by the withdrawal or removal of the General Partner as provided in Section 11.1(a)(i) or (iii) and the failure of the Partners to select a successor to such Departing General Partner pursuant to Section 11.1 or Section 11.2, then, to the fullest extent permitted by law, within 90 days thereafter, or (b) dissolution of the Partnership upon an event constituting an Event of Withdrawal as defined in Section 11.1(a)(iv), (v) or (vi), then, to the maximum extent permitted by law, within 180 days thereafter, the holders of a Unit Majority may elect in writing to continue the business of the Partnership on the same terms and conditions set forth in this Agreement by appointing, effective as of the date of the Event of Withdrawal, as a successor General Partner a Person approved by the holders of a Unit Majority. Unless such an election is made within the

applicable time period as set forth above, the Partnership shall dissolve and conduct only activities necessary to wind up its affairs. If such an election is so made, then:

provided, that the right of the holders of a Unit Majority to approve a successor General Partner and to continue the business of the Partnership shall not exist and may not be exercised unless the Partnership has received an Opinion of Counsel that (x) the exercise of the right would not result in the loss of limited liability under the Delaware Act of any Limited Partner and (y) neither the Partnership nor any Group Member would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of such right to continue (to the extent not already so treated or taxed).

Upon dissolution of the Partnership, unless the business of the Partnership is continued pursuant to Section 12.2, the General Partner, or if none, the holders of a Unit Majority, shall select one or more Persons to act as Liquidator. The Liquidator (if other than the General Partner) shall be entitled to receive such compensation for its services as may be approved by holders of at least a majority of the Outstanding Common Units and Subordinated Units voting as a single class. The Liquidator (if other than the General Partner) shall agree not to resign at any time without 15 days' prior notice and may be removed at any time, with or without cause, by notice of removal approved by holders of at least a majority of the Outstanding Common Units and Subordinated Units voting as a single class. Upon dissolution, removal or resignation of the Liquidator, a successor and substitute Liquidator (who shall have and succeed to all rights, powers and duties of the original Liquidator) shall within 30 days thereafter be approved by holders of at least a majority of the Outstanding Common Units and Subordinated Units voting as a single class. The right to approve a successor or substitute Liquidator in the manner provided herein shall be deemed to refer also to any such successor or substitute Liquidator approved in the manner herein provided. Except as expressly provided in this Article XII, the Liquidator approved in the manner provided herein shall have and may exercise, without further authorization or consent of any of the parties hereto, all of the powers conferred upon the General Partner under the terms of this Agreement (but subject to all of the applicable limitations, contractual and otherwise, upon the exercise of such powers, other than the limitation on sale set forth in Section 7.3) necessary or appropriate to carry out the duties and functions of the Liquidator hereunder for and during the period of time required to complete the winding up and liquidation of the Partnership as provided for herein.

The Liquidator shall proceed to dispose of the assets of the Partnership, discharge its liabilities, and otherwise wind up its affairs in such manner and over such period as determined by the Liquidator, subject to Section 17-804 of the Delaware Act and the following:

Upon the completion of the distribution of Partnership cash and property as provided in Section 12.4 in connection with the liquidation of the Partnership, the Certificate of Limited Partnership and all qualifications of the Partnership as a foreign limited partnership in jurisdictions other than the State of Delaware shall be canceled and such other actions as may be necessary to terminate the Partnership shall be taken.

The General Partner shall not be personally liable for, and shall have no obligation to contribute or loan any money or property to the Partnership to enable it to effectuate, the return of the Capital Contributions of the Limited Partners or Unitholders, or any portion thereof, it being expressly understood that any such return shall be made solely from Partnership assets.

To the maximum extent permitted by law, each Partner hereby waives any right to partition of the Partnership property.

No Limited Partner shall have any obligation to restore any negative balance in its Capital Account upon liquidation of the Partnership. The General Partner shall be obligated to restore any negative balance in its Capital Account upon liquidation of its interest in the Partnership by the end of the taxable period of the Partnership during which such liquidation occurs, or, if later, within 90 days after the date of such liquidation.

Each Partner agrees that the General Partner, without the approval of any Partner, may amend any provision of this Agreement and execute, swear to, acknowledge, deliver, file and record whatever documents may be required in connection therewith, to reflect:

Except as provided in Section 13.1 and Section 13.3, all amendments to this Agreement shall be made in accordance with the requirements contained in this Section 13.2. Amendments to this Agreement may be proposed only by the General Partner; provided, however, to the fullest extent permitted by law, the General Partner shall have no duty or obligation to propose any amendment to this Agreement and may decline to do so free of any fiduciary duty or obligation whatsoever to the Partnership or any Limited Partner and, in declining to propose an amendment, to the fullest extent permitted by law shall not be required to act in good faith or pursuant to any other standard imposed by this Agreement, any Group Member Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity. A proposed amendment shall be effective upon its approval by the General Partner and the holders of a Unit Majority, unless a greater or different percentage is required under this Agreement. Each proposed amendment that requires the approval of the holders of a specified percentage of Outstanding Units shall be set forth in a writing that contains the text of the proposed amendment. If such an amendment is proposed, the General Partner shall seek the written approval of the requisite percentage of Outstanding Units or call a meeting of the Unitholders to consider and vote on such proposed amendment, in each case in accordance with the other provisions of this Article XIII. The General Partner shall notify all Record Holders upon final adoption of any such proposed amendments. The General Partner shall be deemed to have notified all Record Holders as required by this Section 13.2 if it has either (i) filed such amendment with the Commission via its Electronic Data Gathering, Analysis and Retrieval system and such amendment is publicly available on such system or (ii) made such amendment available on any publicly available website maintained by the Partnership.

(a) Notwithstanding the provisions of Section 13.1 and Section 13.2, no provision of this Agreement (other than a provision of the Delaware Act that becomes part of this Agreement by operation of law) that establishes a percentage of Outstanding Units (including Units deemed owned by the General Partner) required to take any action shall be amended, altered, changed, repealed or rescinded in any respect that would have the effect of (i) in the case of any provision of this Agreement other than Section 11.2 or Section 13.4, reducing such percentage or (ii) in the case of Section 11.2 or Section 13.4, increasing such percentage, unless such amendment is approved by the written consent or the affirmative vote of holders of Outstanding Units whose aggregate Outstanding Units constitute not less than the voting requirement sought to be reduced or increased, as applicable.

(b) Notwithstanding the provisions of Section 13.1 and Section 13.2, no amendment to this Agreement may (i) enlarge the obligations of (including requiring any holder of a class of Partnership Interests to make additional Capital Contributions to the Partnership) any Limited Partner without its consent, unless such shall be deemed to have occurred as a result of an amendment approved pursuant to Section 13.3(c), or (ii) enlarge the obligations of, restrict, change or modify in any way any action by

or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable to, the General Partner or any of its Affiliates without the General Partner's consent, which consent may be given or withheld in its sole discretion.

(c) Except as provided in Section 14.3 or Section 13.1(this Section 13.3(c) being subject to the General Partner's authority to adopt amendments to this Agreement without the approval of any other Partners as contemplated by Section 13.1) any amendment that would have a material adverse effect on the rights or preferences of any class of Partnership Interests in relation to other classes of Partnership Interests must be approved by the holders of not less than a majority of the Outstanding Partnership Interests of the class affected. If the General Partner determines an amendment does not satisfy the requirements of Section 13.1(d)(i) because it adversely affects one or more classes of Partnership Interests, as compared to other classes of Partnership Interests, in any material respect, such amendment shall only be required to be approved by the adversely affected class or classes.

(d) Notwithstanding any other provision of this Agreement, except for amendments pursuant to Section 13.1 and except as otherwise provided by Section 14.3(b), no amendments shall become effective without the approval of the holders of at least 90% of the Outstanding Units voting as a single class unless the Partnership obtains an Opinion of Counsel to the effect that such amendment will not affect the limited liability of any Limited Partner under applicable partnership law of the state under whose laws the Partnership is organized.

(e) Except as provided in Section 13.1, this Section 13.3 shall only be amended with the approval of the holders of at least 90% of the Outstanding Units.

All acts of Limited Partners to be taken pursuant to this Agreement shall be taken in the manner provided in this Article XIII. Special meetings of the Limited Partners may be called by the General Partner or by Limited Partners owning 20% or more of the Outstanding Units of the class or classes for which a meeting is proposed. Limited Partners shall call a special meeting by delivering to the General Partner one or more requests in writing stating that the signing Limited Partners wish to call a special meeting and indicating the general or specific purposes for which the special meeting is to be called. Within 60 days after receipt of such a call from Limited Partners or within such greater time as may be reasonably necessary for the Partnership to comply with any statutes, rules, regulations, listing agreements or similar requirements governing the holding of a meeting or the solicitation of proxies for use at such a meeting, the General Partner shall send a notice of the meeting to the Limited Partners either directly or indirectly through the Transfer Agent. A meeting shall be held at a time and place determined by the General Partner on a date not less than 10 days nor more than 60 days after the time notice of the meeting is given as provided in Section 16.1. Limited Partners shall not vote on matters that would cause the Limited Partners to be deemed to be taking part in the management and control of the business and affairs of the Partnership so as to jeopardize the Limited Partners' limited liability under the Delaware Act or the law of any other state in which the Partnership is qualified to do business.

Notice of a meeting called pursuant to Section 13.4 shall be given to the Record Holders of the class or classes of Units for which a meeting is proposed in writing by mail or other means of written communication in accordance with Section 16.1. The notice shall be deemed to have been given at the time when deposited in the mail or sent by other means of written communication.

For purposes of determining the Limited Partners entitled to notice of or to vote at a meeting of the Limited Partners or to give approvals without a meeting as provided in Section 13.11 the General Partner may set a Record Date, which shall not be less than 10 nor more than 60 days before (a) the

date of the meeting (unless such requirement conflicts with any rule, regulation, guideline or requirement of any National Securities Exchange on which the Units are listed or admitted to trading or U.S. federal securities laws, in which case the rule, regulation, guideline or requirement of such National Securities Exchange or U.S. federal securities laws shall govern) or (b) in the event that approvals are sought without a meeting, the date by which Limited Partners are requested in writing by the General Partner to give such approvals. If the General Partner does not set a Record Date, then (a) the Record Date for determining the Limited Partners entitled to notice of or to vote at a meeting of the Limited Partners shall be the close of business on the day next preceding the day on which notice is given and (b) the Record Date for determining the Limited Partners entitled to give approvals without a meeting shall be the date the first written approval is deposited with the Partnership in care of the General Partner in accordance with Section 13.11.

When a meeting is adjourned to another time or place, notice need not be given of the adjourned meeting and a new Record Date need not be fixed, if the time and place thereof are announced at the meeting at which the adjournment is taken, unless such adjournment shall be for more than 45 days. At the adjourned meeting, the Partnership may transact any business that might have been transacted at the original meeting. If the adjournment is for more than 45 days or if a new Record Date is fixed for the adjourned meeting, a notice of the adjourned meeting shall be given in accordance with this Article XIII.

The transactions of any meeting of Limited Partners, however called and noticed, and whenever held, shall be as valid as if it had occurred at a meeting duly held after regular call and notice, if a quorum is present either in person or by proxy. Attendance of a Limited Partner at a meeting shall constitute a waiver of notice of the meeting, except when the Limited Partner attends the meeting for the express purpose of objecting, at the beginning of the meeting, to the transaction of any business because the meeting is not lawfully called or convened; and except that attendance at a meeting is not a waiver of any right to disapprove the consideration of matters required to be included in the notice of the meeting, but not so included, if the disapproval is expressly made at the meeting.

The holders of a majority of the Outstanding Units of the class or classes for which a meeting has been called (including Outstanding Units deemed owned by the General Partner) represented in person or by proxy shall constitute a quorum at a meeting of Limited Partners of such class or classes unless any such action by the Limited Partners requires approval by holders of a greater percentage of such Units, in which case the quorum shall be such greater percentage. At any meeting of the Limited Partners duly called and held in accordance with this Agreement at which a quorum is present, the act of Limited Partners holding Outstanding Units that in the aggregate represent a majority of the Outstanding Units entitled to vote and be present in person or by proxy at such meeting shall be deemed to constitute the act of all Limited Partners, unless a greater or different percentage is required with respect to such action under the provisions of this Agreement, in which case the act of the Limited Partners holding Outstanding Units that in the aggregate represent at least such greater or different percentage shall be required. The Limited Partners present at a duly called or held meeting at which a quorum is present may continue to transact business until adjournment, notwithstanding the withdrawal of enough Limited Partners to leave less than a quorum, if any action taken (other than adjournment) is approved by the required percentage of Outstanding Units specified in this Agreement (including Outstanding Units deemed owned by the General Partner). In the absence of a quorum any meeting of Limited Partners may be adjourned from time to time by the affirmative vote of holders of at least a majority of the Outstanding Units present and entitled to vote at such meeting (including Outstanding Units deemed owned by the General Partner) represented either in person or by proxy, but no other business may be transacted, except as provided in Section 13.7.

The General Partner shall have full power and authority concerning the manner of conducting any meeting of the Limited Partners or solicitation of approvals in writing, including the determination of Persons entitled to vote, the existence of a quorum, the satisfaction of the requirements of Section 13.4, the conduct of voting, the validity and effect of any proxies and the determination of any controversies, votes or challenges arising in connection with or during the meeting or voting. The General Partner shall designate a Person to serve as chairman of any meeting and shall further designate a Person to take the minutes of any meeting. All minutes shall be kept with the records of the Partnership maintained by the General Partner. The General Partner may make such other regulations consistent with applicable law and this Agreement as it may deem advisable concerning the conduct of any meeting of the Limited Partners or solicitation of approvals in writing, including regulations in regard to the appointment of proxies, the appointment and duties of inspectors of votes and approvals, the submission and examination of proxies and other evidence of the right to vote, and the revocation of approvals in writing.

If authorized by the General Partner, any action that may be taken at a meeting of the Limited Partners may be taken without a meeting, without a vote and without prior notice, if an approval in writing setting forth the action so taken is signed by Limited Partners owning not less than the minimum percentage of the Outstanding Units (including Outstanding Units deemed owned by the General Partner) that would be necessary to authorize or take such action at a meeting at which all the Limited Partners were present and voted (unless such provision conflicts with any rule, regulation, guideline or requirement of any National Securities Exchange on which the Units are listed or admitted to trading, in which case the rule, regulation, guideline or requirement of such National Securities Exchange shall govern). Prompt notice of the taking of action without a meeting shall be given to the Limited Partners who have not approved the taking of such action in writing. The General Partner may specify that any written ballot, if any, submitted to Limited Partners for the purpose of taking any action without a meeting shall be returned to the Partnership within the time period, which shall be not less than 20 days, specified by the General Partner. If a ballot returned to the Partnership does not vote all of the Units held by the Limited Partners, the Partnership shall be deemed to have failed to receive a ballot for the Units that were not voted. If approval of the taking of any action by the Limited Partners is solicited by any Person other than by or on behalf of the General Partner, the written approvals shall have no force and effect unless and until (a) they are deposited with the Partnership in care of the General Partner and (b) an Opinion of Counsel is delivered to the General Partner to the effect that the exercise of such right and the action proposed to be taken with respect to any particular matter (i) will not cause the Limited Partners to be deemed to be taking part in the management and control of the business and affairs of the Partnership so as to jeopardize the Limited Partners' limited liability, and (ii) is otherwise permissible under the state statutes then governing the rights, duties and liabilities of the Partnership and the Partners. Nothing contained in this Section 13.11 shall be deemed to require the General Partner to solicit all Limited Partners in connection with a matter approved by the holders of the requisite percentage of Units acting by written consent without a meeting.

(a) Only those Record Holders of the Outstanding Units on the Record Date set pursuant to Section 13.6 (and also subject to the limitations contained in the definition of "Outstanding") shall be entitled to notice of, and to vote at, a meeting of Limited Partners or to act with respect to matters as to which the holders of the Outstanding Units have the right to vote or to act. All references in this Agreement to votes of, or other acts that may be taken by, the Outstanding Units shall be deemed to be references to the votes or acts of the Record Holders of such Outstanding Units.

(b) With respect to Units that are held for a Person's account by another Person (such as a broker, dealer, bank, trust company or clearing corporation, or an agent of any of the foregoing), in

whose name such Units are registered, such other Person shall, in exercising the voting rights in respect of such Units on any matter, and unless the arrangement between such Persons provides otherwise, vote such Units in favor of, and at the direction of, the Person who is the beneficial owner, and the Partnership shall be entitled to assume it is so acting without further inquiry. The provisions of this Section 13.12(b) (as well as all other provisions of this Agreement) are subject to the provisions of Section 4.3.

The Partnership may merge or consolidate with or into one or more corporations, limited liability companies, statutory trusts or associations, real estate investment trusts, common law trusts or unincorporated businesses, including a partnership (whether general or limited (including a limited liability partnership)) or convert into any such entity, whether such entity is formed under the laws of the State of Delaware or any other state of the United States of America, pursuant to a written plan of merger or consolidation ("Merger Agreement") or a written plan of conversion ("Plan of Conversion"), as the case may be, in accordance with this Article XIV.

(a) Merger, consolidation or conversion of the Partnership pursuant to this Article XIV requires the prior consent of the General Partner, provided, however, that, to the fullest extent permitted by law, the General Partner shall have no duty or obligation to consent to any merger, consolidation or conversion of the Partnership and may decline to do so free of any fiduciary duty or obligation whatsoever to the Partnership, any Limited Partner and, in declining to consent to a merger, consolidation or conversion, shall not be required to act in good faith or pursuant to any other standard imposed by this Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity.

(b) If the General Partner shall determine to consent to the merger or consolidation, the General Partner shall approve the Merger Agreement, which shall set forth:

(c) If the General Partner shall determine to consent to the conversion, the General Partner shall approve the Plan of Conversion, which shall set forth:

(a) Except as provided in Section 14.3(d), the General Partner, upon its approval of the Merger Agreement or the Plan of Conversion, as the case may be, shall direct that the Merger Agreement or the Plan of Conversion and the merger, consolidation or conversion contemplated thereby, as applicable, be submitted to a vote of Limited Partners, whether at a special meeting or by written consent, in either case in accordance with the requirements of Article XIII. A copy or a summary of the Merger Agreement or the Plan of Conversion, as the case may be, shall be included in or enclosed with the notice of a special meeting or the written consent.

(b) Except as provided in Sections 14.3(d) and 14.3(e), the Merger Agreement or Plan of Conversion, as the case may be, shall be approved upon receiving the affirmative vote or consent of the holders of a Unit Majority unless the Merger Agreement or Plan of Conversion, as the case may be, contains any provision that, if contained in an amendment to this Agreement, the provisions of this Agreement or the Delaware Act would require for its approval the vote or consent of the holders of a

greater percentage of the Outstanding Units or of any class of Limited Partners, in which case such greater percentage vote or consent shall be required for approval of the Merger Agreement or the Plan of Conversion, as the case may be.

(c) Except as provided in Sections 14.3(d) and 14.3(e), after such approval by vote or consent of the Limited Partners, and at any time prior to the filing of the certificate of merger or certificate of conversion pursuant to Section 14.4, the merger, consolidation or conversion may be abandoned pursuant to provisions therefor, if any, set forth in the Merger Agreement or Plan of Conversion, as the case may be.

(d) Notwithstanding anything else contained in this Article XIV or in this Agreement, the General Partner is permitted, without Limited Partner approval, to convert the Partnership or any Group Member into a new limited liability entity, to merge the Partnership or any Group Member into, or convey all of the Partnership's assets to, another limited liability entity that shall be newly formed and shall have no assets, liabilities or operations at the time of such conversion, merger or conveyance other than those it receives from the Partnership or other Group Member if (i) the General Partner has received an Opinion of Counsel that the conversion, merger or conveyance, as the case may be, would not result in the loss of the limited liability under the Delaware Act of any Limited Partner or cause the Partnership or any Group Member to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not already treated as such), (ii) the sole purpose of such conversion, merger, or conveyance is to effect a mere change in the legal form of the Partnership into another limited liability entity and (iii) the governing instruments of the new entity provide the Limited Partners and the General Partner with substantially the same rights and obligations as are herein contained.

(e) Additionally, notwithstanding anything else contained in this Article XIV or in this Agreement, the General Partner is permitted, without Limited Partner approval, to merge or consolidate the Partnership with or into another entity if (A) the General Partner has received an Opinion of Counsel that the merger or consolidation, as the case may be, would not result in the loss of the limited liability under the Delaware Act of any Limited Partner or cause the Partnership or any Group Member to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not already treated as such), (B) the merger or consolidation would not result in an amendment to this Agreement, other than any amendments that could be adopted pursuant to Section 13.1, (C) the Partnership is the Surviving Business Entity in such merger or consolidation, (D) each Unit outstanding immediately prior to the effective date of the merger or consolidation is to be an identical Unit of the Partnership after the effective date of the merger or consolidation, and (E) the number of Partnership Interests to be issued by the Partnership in such merger or consolidation does not exceed 20% of the Partnership Interests Outstanding (other than the Incentive Distribution Rights) immediately prior to the effective date of such merger or consolidation.

(f) Pursuant to Section 17-211(g) of the Delaware Act, an agreement of merger or consolidation approved in accordance with this Article XIV may (a) effect any amendment to this Agreement or (b) effect the adoption of a new partnership agreement for the Partnership if it is the Surviving Business Entity. Any such amendment or adoption made pursuant to this Section 14.3 shall be effective at the effective time or date of the merger or consolidation.

Upon the required approval by the General Partner and the Unitholders of a Merger Agreement or a Plan of Conversion, as the case may be, a certificate of merger or certificate of conversion, as applicable, shall be executed and filed with the Secretary of State of the State of Delaware in conformity with the requirements of the Delaware Act.

(a) Notwithstanding any other provision of this Agreement, if at any time the General Partner and its Affiliates hold more than 80% of the total Limited Partner Interests of any class then

Outstanding, the General Partner shall then have the right, which right it may assign and transfer in whole or in part to the Partnership or any Affiliate of the General Partner, exercisable in its sole discretion, to purchase all, but not less than all, of such Limited Partner Interests of such class then Outstanding held by Persons other than the General Partner and its Affiliates, at the greater of (x) the Current Market Price as of the date three days prior to the date that the notice described in Section 15.1(b) is mailed and (y) the highest price paid by the General Partner or any of its Affiliates for any such Limited Partner Interest of such class purchased during the 90-day period preceding the date that the notice described in Section 15.1(b) is mailed.

(b) If the General Partner, any Affiliate of the General Partner or the Partnership elects to exercise the right to purchase Limited Partner Interests granted pursuant to Section 15.1(a), the General Partner shall deliver to the Transfer Agent notice of such election to purchase (the "Notice of Election to Purchase") and shall cause the Transfer Agent to mail a copy of such Notice of Election to Purchase to the Record Holders of Limited Partner Interests of such class or classes (as of a Record Date selected by the General Partner) at least 10, but not more than 60, days prior to the Purchase Date. Such Notice of Election to Purchase shall also be published for a period of at least three consecutive days in at least two daily newspapers of general circulation printed in the English language and published in the Borough of Manhattan, New York. The Notice of Election to Purchase shall specify the Purchase Date and the price (determined in accordance with Section 15.1(a)) at which Limited Partner Interests will be purchased and state that the General Partner, its Affiliate or the Partnership, as the case may be, elects to purchase such Limited Partner Interests, upon surrender of Certificates representing such Limited Partner Interests in the case of Limited Partner Interests evidenced by Certificates, in exchange for payment, at such office or offices of the Transfer Agent as the Transfer Agent may specify, or as may be required by any National Securities Exchange on which such Limited Partner Interests are listed or admitted to trading. Any such Notice of Election to Purchase mailed to a Record Holder of Limited Partner Interests at his address as reflected in the records of the Transfer Agent shall be conclusively presumed to have been given regardless of whether the owner receives such notice. On or prior to the Purchase Date, the General Partner, its Affiliate or the Partnership, as the case may be, shall deposit with the Transfer Agent cash in an amount sufficient to pay the aggregate purchase price of all of such Limited Partner Interests to be purchased in accordance with this Section 15.1. If the Notice of Election to Purchase shall have been duly given as aforesaid at least 10 days prior to the Purchase Date, and if on or prior to the Purchase Date the deposit described in the preceding sentence has been made for the benefit of the holders of Limited Partner Interests subject to purchase as provided herein, then from and after the Purchase Date, notwithstanding that any Certificate shall not have been surrendered for purchase, all rights of the holders of such Limited Partner Interests (including any rights pursuant to Article III, Article IV, Article V, Article VI, and Article XII) shall thereupon cease, except the right to receive the purchase price (determined in accordance with Section 15.1(a)) for Limited Partner Interests therefor, without interest, upon surrender to the Transfer Agent of the Certificates representing such Limited Partner Interests in the case of Limited Partner Interests represented by Certificates, and such Limited Partner Interests shall thereupon be deemed to be transferred to the General Partner, its Affiliate or the Partnership, as the case may be, on the record books of the Transfer Agent and the Partnership, and the General Partner or any Affiliate of the General Partner, or the Partnership, as the case may be, shall be deemed to be the owner of all such Limited Partner Interests from and after the Purchase Date and shall have all rights as the owner of such Limited Partner Interests (including all rights as owner of such Limited Partner Interests pursuant to Article III, Article IV, Article V, Article VI and Article XII).

(c) In the case of Limited Partner Interests evidenced by Certificates, at any time from and after the Purchase Date, a holder of an Outstanding Limited Partner Interest subject to purchase as provided in this Section 15.1 may surrender his Certificate evidencing such Limited Partner Interest to the Transfer Agent in exchange for payment of the amount described in Section 15.1(a), therefor, without interest thereon.

(a) Any notice, demand, request, report or proxy materials required or permitted to be given or made to a Partner under this Agreement shall be in writing and shall be deemed given or made when delivered in person or when sent by first class United States mail or by other means of written communication to the Partner at the address described below. Any notice, payment or report to be given or made to a Partner hereunder shall be deemed conclusively to have been given or made, and the obligation to give such notice or report or to make such payment shall be deemed conclusively to have been fully satisfied, upon sending of such notice, payment or report to the Record Holder of such Partnership Interests at his address as shown on the records of the Transfer Agent or as otherwise shown on the records of the Partnership, regardless of any claim of any Person who may have an interest in such Partnership Interests by reason of any assignment or otherwise. Notwithstanding the foregoing, if (i) a Partner shall consent to receiving notices, demands, requests, reports or proxy materials via electronic mail or by the Internet or (ii) the rules of the Commission shall permit any report or proxy materials to be delivered electronically or made available via the Internet, any such notice, demand, request, report or proxy materials shall be deemed given or made when delivered or made available via such mode of delivery. An affidavit or certificate of making of any notice, payment or report in accordance with the provisions of this Section 16.1 executed by the General Partner, the Transfer Agent or the mailing organization shall be prima facie evidence of the giving or making of such notice, payment or report. If any notice, payment or report given or made in accordance with the provisions of this Section 16.1 is returned marked to indicate that such notice, payment or report was unable to be delivered, such notice, payment or report and, in the case of notices, payments or reports returned by the United States Postal Service (or other physical mail delivery mail service outside the United States of America), any subsequent notices, payments and reports shall be deemed to have been duly given or made without further mailing (until such time as such Record Holder or another Person notifies the Transfer Agent or the Partnership of a change in his address) or other delivery if they are available for the Partner at the principal office of the Partnership for a period of one year from the date of the giving or making of such notice, payment or report to the other Partners. Any notice to the Partnership shall be deemed given if received by the General Partner at the principal office of the Partnership designated pursuant to Section 2.3. The General Partner may rely and shall be protected in relying on any notice or other document from a Partner or other Person if believed by it to be genuine.

(b) The terms "in writing," "written communications," "written notice" and words of similar import shall be deemed satisfied under this Agreement by use of e-mail and other forms of electronic communication.

The parties shall execute and deliver all documents, provide all information and take or refrain from taking action as may be necessary or appropriate to achieve the purposes of this Agreement.

This Agreement shall be binding upon and inure to the benefit of the parties hereto and their heirs, executors, administrators, successors, legal representatives and permitted assigns.

This Agreement constitutes the entire agreement among the parties hereto pertaining to the subject matter hereof and supersedes all prior agreements and understandings pertaining thereto.

Except as provided in Section 16.7, none of the provisions of this Agreement shall be for the benefit of, or shall be enforceable by, any creditor of the Partnership.

No failure by any party to insist upon the strict performance of any covenant, duty, agreement or condition of this Agreement or to exercise any right or remedy consequent upon a breach thereof shall, to the fullest extent permitted by law, constitute waiver of any such breach of any other covenant, duty, agreement or condition.

Each Partner agrees that (a) any Indemnitee shall be entitled to assert rights and remedies hereunder as a third-party beneficiary hereto with respect to those provisions of this Agreement affording a right, benefit or privilege to such Indemnitee and (b) any Unrestricted Person shall be entitled to assert rights and remedies hereunder as a third-party beneficiary hereto with respect to those provisions of this Agreement affording a right, benefit or privilege to such Unrestricted Person.

This Agreement may be executed in counterparts, all of which together shall constitute an agreement binding on all the parties hereto, notwithstanding that all such parties are not signatories to the original or the same counterpart. Each party shall become bound by this Agreement immediately upon affixing its signature hereto or, in the case of a Person acquiring a Limited Partner Interest, pursuant to Section 10.1(a) without execution hereof.

(a) This Agreement shall be construed in accordance with and governed by the laws of the State of Delaware, without regard to the principles of conflicts of law.

(b) To the fullest extent permitted by law, each of the Partners and each Person holding any beneficial interest in the Partnership (whether through a broker, dealer, bank, trust company or clearing corporation or an agent of any of the foregoing or otherwise):

If any provision or part of a provision of this Agreement is or becomes for any reason, invalid, illegal or unenforceable in any respect, the validity, legality and enforceability of the remaining provisions and part thereof contained herein shall not be affected thereby and this Agreement shall, to the fullest extent permitted by law, be reformed and construed as if such invalid, illegal or unenforceable provision, or part of a provision, had never been contained herein, and such provision or part reformed so that it would be valid, legal and enforceable to the maximum extent possible.

Each Partner hereby expressly consents and agrees that, whenever in this Agreement it is specified that an action may be taken upon the affirmative vote or consent of less than all of the Partners, such action may be so taken upon the concurrence of less than all of the Partners and each Partner and each other Person bound by the provisions of this Agreement shall be bound by the results of such action.

The use of facsimile signatures affixed in the name and on behalf of the transfer agent and registrar of the Partnership on Certificates representing Units is expressly permitted by this Agreement.

IN WITNESS WHEREOF, the parties hereto have executed this Agreement as of the date first written above.

[Signature Page — First Amended and Restated Agreement of Limited Partnership of LLR Energy, L.P.]

EXHIBIT A
to the First Amended and Restated
Agreement of Limited Partnership of
LRR Energy, L.P.

Certificate Evidencing Common Units
Representing Limited Partner Interests in
LRR Energy, L.P.

In accordance with Section 4.1 of the First Amended and Restated Agreement of Limited Partnership of LRR Energy, L.P., as amended, supplemented or restated from time to time (the "Partnership Agreement"), LRR Energy, L.P., a Delaware limited partnership (the "Partnership"), hereby certifies that (the "Holder") is the registered owner of Common Units representing limited partner interests in the Partnership (the "Common Units") transferable on the books of the Partnership, in person or by duly authorized attorney, upon surrender of this Certificate properly endorsed. The rights, preferences and limitations of the Common Units are set forth in, and this Certificate and the Common Units represented hereby are issued and shall in all respects be subject to the terms and provisions of, the Partnership Agreement. Copies of the Partnership Agreement are on file at, and will be furnished without charge on delivery of written request to the Partnership at, the principal office of the Partnership located at Heritage Plaza, 1111 Bagby Street, Suite 4600, Houston, Texas 77002. Capitalized terms used herein but not defined shall have the meanings given them in the Partnership Agreement.

THE HOLDER OF THIS SECURITY ACKNOWLEDGES FOR THE BENEFIT OF LRR ENERGY, L.P. THAT THIS SECURITY MAY NOT BE SOLD, OFFERED, RESOLD, PLEDGED OR OTHERWISE TRANSFERRED IF SUCH TRANSFER WOULD (A) VIOLATE THE THEN APPLICABLE FEDERAL OR STATE SECURITIES LAWS OR RULES AND REGULATIONS OF THE SECURITIES AND EXCHANGE COMMISSION, ANY STATE SECURITIES COMMISSION OR ANY OTHER GOVERNMENTAL AUTHORITY WITH JURISDICTION OVER SUCH TRANSFER, (B) TERMINATE THE EXISTENCE OR QUALIFICATION OF LRR ENERGY, L.P. UNDER THE LAWS OF THE STATE OF DELAWARE, (C) CAUSE LRR ENERGY, L.P. TO BE TREATED AS AN ASSOCIATION TAXABLE AS A CORPORATION OR OTHERWISE TO BE TAXED AS AN ENTITY FOR FEDERAL INCOME TAX PURPOSES (TO THE EXTENT NOT ALREADY SO TREATED OR TAXED) OR (D) VIOLATE THE TERMS AND CONDITIONS OF THE PARTNERSHIP AGREEMENT. LRE GP, LLC, THE GENERAL PARTNER OF LRR ENERGY, L.P., MAY IMPOSE ADDITIONAL RESTRICTIONS ON THE TRANSFER OF THIS SECURITY IF IT RECEIVES AN OPINION OF COUNSEL THAT SUCH RESTRICTIONS ARE NECESSARY OR ADVISABLE TO AVOID A SIGNIFICANT RISK OF LRR ENERGY, L.P. BECOMING TAXABLE AS A CORPORATION OR OTHERWISE BECOMING TAXABLE AS AN ENTITY FOR FEDERAL INCOME TAX PURPOSES OR TO PRESERVE THE UNIFORMITY OF THE LIMITED PARTNER INTERESTS REPRESENTED BY THIS SECURITY (OR ANY CLASS OR CLASSES THEREOF). THE RESTRICTIONS SET FORTH ABOVE SHALL NOT PRECLUDE THE SETTLEMENT OF ANY TRANSACTIONS INVOLVING THIS SECURITY ENTERED INTO THROUGH THE FACILITIES OF ANY NATIONAL SECURITIES EXCHANGE ON WHICH THIS SECURITY IS LISTED OR ADMITTED TO TRADING.

The Holder, by accepting this Certificate, (i) shall bound by the Partnership Agreement, (ii) represents and warrants that the Holder has all right, power and authority and, if an individual, the capacity necessary to enter into the Partnership Agreement and (iii) makes the given and waivers the consents and approvals contained in the Partnership Agreement.

This Certificate shall not be valid for any purpose unless it has been countersigned and registered by the Transfer Agent and Registrar. This Certificate shall be governed by and construed in accordance with the laws of the State of Delaware.

The following abbreviations, when used in the inscription on the face of this Certificate, shall be construed as follows according to applicable laws or regulations:

Common Units representing limited partner interests evidenced by this Certificate, subject to the Partnership Agreement, and does hereby irrevocably constitute and appoint as its attorney-in-fact with full power of substitution to transfer the same on the books of LRR Energy, L.P.

No transfer of the Common Units evidenced hereby will be registered on the books of the Partnership, unless the Certificate evidencing the Common Units to be transferred is surrendered for registration or transfer.

The following includes a description of the meanings of some of the oil and gas industry terms used in this prospectus. The definitions of proved developed reserves, proved reserves and proved undeveloped reserves have been excerpted from the applicable definitions contained in Rule 4-10(a) of Regulation S-X.

Basin: A large depression on the earth's surface in which sediments accumulate.

Bbl: One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.

Boe: One barrel of oil equivalent, calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids.

Btu: One British thermal unit, the quantity of heat required to raise the temperature of a one-pound mass of water by one degree Fahrenheit.

Developed Acreage: The number of acres that are allocated or assignable to producing wells or wells capable of production.

Development Well: A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Dry Hole or Well: A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production would exceed production expenses and taxes.

Exploitation: Drilling or other projects that may target proven or unproven reserves (such as probable or possible reserves), but that generally has a lower risk than that associated with exploration projects.

Exploratory Well: A well drilled to find and produce oil and natural gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir.

Field: An area consisting of a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

Gross Acres or Gross Wells: The total acres or wells, as the case may be, in which we have working interest.

Net Acres or Net Wells: The sum of our fractional working interests owned in gross acres or gross wells, as the case may be.

Net Production: Production that is owned by us less royalties and production due others.

Net Revenue Interest: A working interest owner's gross working interest in production less the royalty, overriding royalty, production payment and net profits interests.

NGLs: The combination of ethane, propane, butane and natural gasolines that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.

Productive Well: A well that produces commercial quantities of hydrocarbons, exclusive of its capacity to produce at a reasonable rate of return.

Proved Developed Reserves: Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods.

Proved Reserves: Those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project, within a reasonable time. The area of the reservoir considered as proved includes (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons, LKH, as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil, HKO, elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be

determined. The price shall be the average price during the twelve-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Proved Undeveloped Reserves: Proved oil and natural gas reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

Realized Price: The cash market price less all expected quality, transportation and demand adjustments.

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

Reserve: That part of a mineral deposit which could be economically and legally extracted or produced at the time of the reserve determination.

Reservoir: A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reserves.

Spacing: The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres (e.g., 40-acre spacing) and is often established by regulatory agencies.

Spot Price: The cash market price without reduction for expected quality, transportation and demand adjustments.

Standardized Measure: The present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using prices and costs in effect as of the date of estimation), less future development, production and income tax expenses, and discounted at 10% per annum to reflect the timing of future net revenue. 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.

Undeveloped Acreage: Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

Wellbore: The hole drilled by the bit that is equipped for oil or natural gas production on a completed well. Also called well or borehole.

Working Interest: The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.

Workover: Operations on a producing well to restore or increase production.

At your request, Miller and Lents, Ltd. (MLL) performed an evaluation of the proved reserves and future net revenues attributable to interests owned by LRR Energy, L.P. (LRRE) in certain oil and gas properties located in Texas, New Mexico, and Oklahoma as of March 31, 2011. The report was prepared for LRRE's use in reserves and financial reporting and planning and was completed on April 1, 2011. This revised letter dated June 10, 2011 includes additional explanatory language in response to comments received by LRRE from the Securities and Exchange Commission (SEC) with no changes to the original reserves estimates as of March 31, 2011. MLL performed its evaluation, designated as the SEC Price Case, using prices, operating expenses, and capital expenditures provided by LRRE. The SEC Price Case assumes no future escalation of product prices, operating expenses or capital expenditures. The aggregate results of MLL's evaluation are as follows:

TWO HOUSTON CENTER • 909 FANNIN STREET, SUITE 1300 • HOUSTON, TEXAS 77010
TELEPHONE 713-651-9455 • TELEFAX 713-654-9914 • email: mail@millerandlents.com

The reserves were estimated in accordance with the definitions contained in SEC Regulation S-X, Rule 4-10(a) as shown in the Appendix. The estimates shown in this report are for proved reserves. As requested by LRRE, probable and possible reserves that exist for these properties have not been included.

Future net revenues, as used herein, are defined as the total revenues attributed to the evaluated interests less royalties, production and ad valorem taxes, operating expenses, and future capital expenditures. Future net revenues do not include deductions for federal income tax. The future net revenues were discounted at 10 percent per year (referenced later herein as "discounted future net revenues") in accordance with SEC rules and to illustrate the time value of future cash flows. Estimates of future net revenues and discounted future net revenues are not intended and should not be interpreted to represent fair market values for the estimated reserves.

MLL has evaluated 100 percent of the reserves in the operating areas referenced in this report. Of the total reserves reported by LRRE, MLL reviewed 85 percent. All reserves referenced in this report are in the United States and the properties are grouped by operating areas: Black Bayou/Doyle Creek, Corral Canyon Non-Operated, Corral Canyon Other Operated, Cowden Ranch Operated, Other Non-Operated Edge, Pecos Slope Operated, Potato Hills Operated, and Red Lake and North Bluff Operated properties. Separate evaluations were performed and presented for the operating areas. Each contains a summary of the proved reserves, annual projections of future production and future net revenues, and a one-line summary of the individual wells. Minor precision inconsistencies in subtotals or totals may exist in the report due to truncation or rounding of aggregated values.

Reserves estimates for producing wells were based on decline curve extrapolations. Reserves estimates for nonproducing wells and proved undeveloped wells were based on analogies derived from existing producers in the respective areas. Reserves estimates from analogies are often less certain than reserves estimates based on well performance obtained over a period during which a substantial portion of the reserves were produced.

Product prices were projected using selected spot price benchmarks (West Texas Intermediate crude oil sold at Cushing, Oklahoma and gas sold at the Henry Hub) with appropriate differentials applied for each well, lease, or area. The SEC prices applicable for this report are calculated for each product as the average of the prices existent on the first day of each of the 12 months prior to March 31, 2011. For our cash flow projections, constant prices were used throughout the life of production in accordance with SEC rules. The SEC-compliant benchmark prices used herein were $83.41 per barrel for oil and $4.10 per million Btu for gas. Price adjustments were supplied by LRRE. The actual average prices used in this report for proved reserves, after appropriate adjustments, were $78.70 per barrel for oil, $41.71 per barrel for NGLs, and $3.93 per Mcf for gas.

Operating expenses and capital costs were supplied by LRRE. In certain Black Bayou/Doyle Creek properties, capital costs adjustments were made to those wells that were subject to a five percent carried working interest to the tanks. No information was supplied concerning gas imbalances; therefore, no effect for gas imbalance amounts, if any, was included. No material abandonment costs exceeding salvage values were provided by LRRE. Future costs, if any, for restoration of the properties to satisfy environmental standards were not included in this evaluation.

The Black Bayou/Doyle Creek area is located in East Texas, in Black Bayou, Doyle Creek and Gates East fields. The majority of the wells produce from the Travis Peak formation with four wells producing in the James Lime. The Travis Peak well spacing is 40 acres based on state-wide field rules.

The Red Lake and North Bluff Operated and Other Non-Operated Edge areas are located in Eddy County, New Mexico, in East Artesia and Red Lake fields. The majority of the production is from the Yeso and Middle and Lower San Andres formations, with a general well spacing of 20 acres. The proved

undeveloped locations are 20-acre and 10-acre wells. Proved reserves for waterflooding the San Andres formation in the N.W. State Lease are included in this evaluation. A proved nonproducing case is included in this evaluation to model the operating expense savings associated with converting a well for disposal. There are no reserves associated with the conversion.

The Pecos Slope area is located in Chaves, Eddy, Lea, and Roosevelt counties in New Mexico. Production is primarily from the Abo formation in the Pecos Slope and West Pecos Slope fields. The Corral Canyon areas are located in Eddy and Lea counties, New Mexico and Martin and Reagan counties, Texas. The Cowden Ranch Operated area is located in Crane County, Texas. The Potato Hills area is located in Latimer and Pushmataha counties, Oklahoma.

In conducting this evaluation, MLL relied upon production histories; accounting and cost data; ownership; geological, geophysical, and engineering data; development plans supplied by LRRE; and upon non-confidential data from public records or commercial data services. These data were accepted as represented and are considered appropriate for the purpose served by the report. MLL used all methods, procedures, and assumptions as it considered necessary and appropriate under the circumstances in using the data provided to prepare the report.

The evaluations presented in this report, with the exceptions of those parameters specified by others, reflect our informed judgments and are subject to the inherent uncertainties associated with interpretation of geological, geophysical, and engineering information. These uncertainties include, but are not limited to, (1) the utilization of analogous or indirect data and (2) the application of professional judgments. Government policies and market conditions different from those employed in this study may cause (1) the total quantity of oil, natural gas liquids, or gas to be recovered, (2) actual production rates, (3) prices received, or (4) operating and capital costs to vary from those presented in this report. At this time, MLL is not aware of any regulations that would affect LRRE's ability to recover the estimated reserves.

Miller and Lents, Ltd. is an independent oil and gas consulting firm. No director, officer, or key employee of Miller and Lents, Ltd. has any financial ownership in LRRE or any affiliate of LRRE.

Our compensation for the required investigations and preparation of this report is not contingent on the results obtained and reported, and we have not performed other work that would affect our objectivity. Preparation of this report was supervised by Leslie A. Fallon, an officer of the firm who is a professionally qualified and licensed Professional Engineer in the State of Texas with more than 25 years of relevant experience in the estimation, assessment, and evaluation of oil and gas reserves.

Reserves Definitions In Accordance With
Securities and Exchange Commission Regulation S-X

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

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

Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an "analogous reservoir" refers to a reservoir that shares the following characteristics with the reservoir of interest:

Reservoir properties must, in aggregate, be no more favorable in the analog than in the reservoir of interest.

Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

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

Mr. Christopher A. Butta
Lime Rock Resources A, L.P.
1111 Bagby Street, Suite 4600
Houston, Texas 77002
Dear Mr. Butta:

In accordance with your request, we have estimated the proved reserves and future revenue, as of March 31, 2011, to the LRR Energy, L.P. (LRR Energy) proposed interest in certain oil and gas properties located in Texas. This is a revision of our report dated May 3, 2011. This report has been revised to address certain comments received by LRR Energy from the U.S. Securities and Exchange Commission (SEC); the estimates in this report are the same as those presented in our May 3 report. We completed our evaluation on March 31, 2011. It is our understanding that the proved reserves estimated in this report constitute approximately 15 percent of all proved reserves owned by LRR Energy. The estimates in this report have been prepared in accordance with the definitions and regulations of the SEC and conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities — Oil and Gas, except that per-well overhead expenses are excluded for operated properties and future income taxes are excluded for all properties. Definitions are presented immediately following this letter. This report has been prepared for LRR Energy's use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.

We estimate the net reserves and future net revenue to the LRR Energy proposed interest in these properties, as of March 31, 2011, to be:

The oil reserves shown include condensate only. Oil and natural gas liquid (NGL) volumes are expressed in barrels that are equivalent to 42 United States gallons. Gas volumes are expressed in thousands of cubic feet (MCF) at standard temperature and pressure bases.

The estimates shown in this report are for proved reserves. As requested, probable and possible reserves that exist for these properties have not been included. This report does not include any value that could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated. Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. The estimates of reserves and future revenue included herein have not been adjusted for risk.

Future gross revenue to the LRR Energy proposed interest is prior to deducting state production taxes and ad valorem taxes. Future net revenue is after deductions for these taxes, future capital costs, and operating expenses but before consideration of any income taxes. The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth, which is shown to indicate the effect of time on the value of money. Future net revenue presented in this report, whether discounted or undiscounted, should not be construed as being the fair market value of the properties.

For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and facilities. We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs due to such possible liability. No material abandonment costs exceeding salvage values were provided by LRR Energy; therefore, our estimates do not include such costs.

Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period April 2010 through March 2011. For oil and NGL volumes, the average Wall Street Journal West Texas Intermediate (Cushing) cash/spot price of $83.41 per barrel is adjusted by lease for quality, transportation fees, and regional price differentials. For gas volumes, the average Henry Hub spot price of $4.102 per MMBTU is adjusted by lease for energy content, transportation fees, and regional price differentials. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $82.68 per barrel of oil, $46.07 per barrel of NGL, and $4.003 per MCF of gas.

Lease and well operating costs used in this report are based on operating expense records of Lime Rock Resources A, L.P. (Lime Rock). For nonoperated properties, these costs include the per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels. As requested, lease and well operating costs for the operated properties include only direct lease- and field-level costs. For all properties, headquarters general and administrative overhead expenses of Lime Rock are not included. Lease and well operating costs are held constant throughout the lives of the properties. Capital costs are included as required for workovers, new development wells, and production equipment. The future capital costs are held constant to the date of expenditure.

We have made no investigation of potential gas volume and value imbalances resulting from overdelivery or underdelivery to the LRR Energy proposed interest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections are based on LRR Energy receiving its proposed net revenue interest share of estimated future gross gas production.

The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the reserves, and that our projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing this report.

For the purposes of this report, we used technical and economic data including, but not limited to, well logs, geologic maps, well test data, production data, historical price and cost information, and property ownership interests. The reserves in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). We used standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, and analogy, that we considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

The data used in our estimates were obtained from Lime Rock, public data sources, and the nonconfidential files of Netherland, Sewell & Associates, Inc. (NSAI) and were accepted as accurate. Supporting geoscience, performance, and work data are on file in our office. The titles to the properties have not been examined by NSAI, nor has the actual degree or type of interest owned been independently confirmed. The technical persons responsible for preparing the estimates presented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards; certificates of qualification are included after the definitions. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4-10(a). Also included is supplemental information from (1) the 2007 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) the FASB Accounting Standards Codification Topic 932, Extractive Activities — Oil and Gas, and (3) the SEC's Compliance and Disclosure Interpretations.

(1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers' fees, recording fees, legal costs, and other costs incurred in acquiring properties.

(2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an "analogous reservoir" refers to a reservoir that shares the following characteristics with the reservoir of interest:

Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.

(3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.

(4) Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

(5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

Supplemental definitions from the 2007 Petroleum Resources Management System:

Developed Producing Reserves — Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing Reserves — Developed Non-Producing Reserves include shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future recompletion prior to start of production. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

(7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

(8) Development project. A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

(9) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

(10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.

(11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.

(12) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

(13) Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.

(14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir.

(15) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms "structural feature" and "stratigraphic condition" are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a "terminal point", which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:

Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.

(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

(19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.

(21) Proved area. The part of a property to which proved reserves have been specifically attributed.

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

(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).



Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities — Oil and Gas:
932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity's interests in both of the following shall be disclosed as of the end of the year:
a.		Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)
b.		Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7).
The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes.
932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B:
a.		Future cash inflows. These shall be computed by applying prices used in estimating the entity's proved oil and gas reserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end.
b.		Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs.
c.		Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity's proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity's proved oil and gas reserves.
d.		Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows.
e.		Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves.
f.		Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount.

(27) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

(28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

(29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.

(30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as "exploratory type" if not drilled in a known area or "development type" if drilled in a known area.

(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.



From the SEC's Compliance and Disclosure Interpretations (October 26, 2009):
Although several types of projects — such as constructing offshore platforms and development in urban areas, remote locations or environmentally sensitive locations — by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take into consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should be the exception, and not the rule.
Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend past five years include, but are not limited to, the following:
•		The company's level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities);
•		The company's historical record at completing development of comparable long-term projects;
•		The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities;
•		The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); and
•		The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority).

I, Lee E. George, Registered Professional Engineer, 1221 Lamar Street, Suite 1200, Houston, Texas, 77010, hereby certify:

I, Mike K. Norton, Registered Licensed Geoscientist, 1221 Lamar Street, Suite 1200, Houston, Texas, 77010, hereby certify:

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 dealers' obligation to deliver a prospectus when acting as an underwriter and with respect to their unsold allotments or subscriptions.

	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


	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



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	%


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".


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


	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


	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

	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."

	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

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

			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


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

	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	%


Baird		Oppenheimer & Co.		Stifel Nicolaus Weisel

	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	)

				Minimum Quarterly Distribution

		Number of Units		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

	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	%

			Weighted Average Price			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%

			Weighted Average Price

NGLs:
October 2011 — September 2012	173,910		$	51.38
% of forecasted NGL production	61	%

			NGL Price $/Bbl				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

	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

	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	%

		Marginal Percentage Interest in Distributions

	Total Quarterly Distribution Per Unit Target Amount	Unitholders			General Partner
Minimum Quarterly Distribution	$0.4750		99.9	%		0.1	%
First Target Distribution	above $0.4750 up to $0.54625		99.9	%		0.1	%
Second Target Distribution	above $0.54625 up to $0.59375		86.9	%		13.1	%
Thereafter	above $0.59375		76.9	%		23.1	%

		Marginal Percentage Interest in Distributions

		Marginal Percentage Interest in Distributions									Quarterly Distribution Per Unit Following Hypothetical Reset
	Quarterly Distribution Per Unit Prior to Reset	Unitholders			0.1% General Partner Interest			Incentive Distribution Rights
Minimum Quarterly Distribution	$0.4750		99.9	%		0.1	%		—		$0.60000
First Target Distribution	above $0.4750 up to $0.54625		99.9	%		0.1	%		—		above $0.60000 up to $0.69000(1)
Second Target Distribution	above $0.54625 up to $0.59375		86.9	%		0.1	%		13	%	above $0.69000(1) up to $0.75000(2)
Thereafter	above $0.59375		76.9	%		0.1	%		23	%	above $0.75000

				Cash Distributions to General Partner Prior to Reset

		Cash Distributions to Common Unitholders Prior to Reset		Cash Distributions to General Partner Prior to Reset
	Quarterly Distribution Per Unit Prior to Reset	Cash Distributions to Common Unitholders Prior to Reset		Common Units		0.1% General Partner Interest		Incentive Distribution Rights		Total		Total Distribution
Minimum Quarterly Distribution	$0.4750	$	10,629,360	$	—	$	10,640	$	—	$	10,640	$	10,640,000
First Target Distribution	above $0.4750 up to $0.54625		1,594,404		—		1,596		—		1,596		1,596,000
Second Target Distribution	above $0.54625 up to $0.59375		1,062,936		—		1,223		159,012		160,235		1,223,171
Thereafter	above $0.59375		139,860		—		182		41,831		42,013		181,873

		$	13,426,560	$	—	$	13,641	$	200,843	$	214,484	$	13,641,044

				Cash Distributions to General Partner After Reset

		Cash Distributions to Common Unitholders After Reset		Cash Distributions to General Partner After Reset
	Quarterly Distribution Per Unit After Reset	Cash Distributions to Common Unitholders After Reset		Common Units		0.1% General Partner Interest		Incentive Distribution Rights		Total		Total Distribution
Minimum Quarterly Distribution	$0.6000	$	13,426,560	$	200,843	$	13,641	$	—	$	214,484	$	13,641,044
First Target Distribution	above $0.6000 up to $0.6900		—		—		—		—		—		—
Second Target Distribution	above $0.6900 up to $0.7500		—		—		—		—		—		—
Thereafter	above $0.7500		—		—		—		—		—		—

		$	13,426,560	$	200,843	$	13,641	$	—	$	214,484	$	13,641,044

	Oil (NYMEX-WTI) Weighted Average				NGL (NYMEX-WTI) Weighted Average				Natural Gas (NYMEX-Henry Hub) Weighted Average

Term	$/Bbl		Bbls/d		$/Bbl		Bbls/d		$/Mmbtu		Mmbtu/d
2011	$	106.22		1,360	$	55.27		726	$	6.70		20,315
2012	$	102.20		1,076	$	49.93		597	$	5.46		19,342
2013	$	101.30		1,139	$	—		—	$	5.56		16,964
2014	$	100.01		958	$	—		—	$	5.75		14,972
2015	$	98.90		833	$	—		—	$	5.96		13,433

	Obligations Due in Period


Contractual Obligation	2011		2012		2013		2014		2015		Thereafter		Total
	(in thousands)
Long-term debt	$	—	$	—	$	—	$	27,251	$	—	$	—	$	27,251
Interest on long-term debt(a)		760		760		760		760		—		—		3,040

Total contractual obligations	$	760	$	760	$	760	$	28,011	$	—	$	—	$	30,291



Proved undeveloped reserves-beginning of year	1,199		389		1,990		1,920
Transferred to proved developed through drilling	(356	)	(197	)	(617	)	(656	)
Increase (decrease) due to evaluation reassessments and drilling results, net	85		237		2,728		777
Acquisition of reserves	39		11		35		55
Reductions of proved developed reserves aged five or more years	—		—		—		—

Proved undeveloped reserves-end of year	967		440		4,136		2,096

		Developed Acreage(1)

		Gross(2)		Net(3)
Permian Basin			194,431		122,593
Mid-Continent			22,643		16,331
Gulf Coast			13,758		12,103

	Total		230,832		151,027

Name		Position with LRE GP, LLC

Eric D. Mullins	49	Co-Chief Executive Officer and Chairman
Charles W. Adcock	58	Co-Chief Executive Officer and Director
Christopher A. Butta	50	Vice President and Chief Engineer
Jaime R. Casas	41	Vice President, Chief Financial Officer and Secretary
C. Timothy Miller	51	Vice President and Chief Operating Officer
John A. Bailey	41	Director Nominee
Milton Carroll	61	Director Nominee
Jonathan C. Farber	43	Director
Robert T. O'Connell	73	Director Nominee
Townes G. Pressler, Jr.	48	Director

Name of Beneficial Owner

Lime Rock Management LP(b) 274 Riverside Avenue, 3rd Floor Westport, CT 06880	100	%	—		—
Fund I(c)(d)	—		100	%	—
Fund II(c)(d)	—		—		100	%

Fund I			Aggregate Value of Common and Subordinated Units

Lime Rock Resources A, L.P.	893,030	960,247	$	35,212,263
Lime Rock Resources B, L.P.	296,082	318,368	$	11,674,550
Lime Rock Resources C, L.P.	5,060,488	5,441,385	$	199,535,587


State-law fiduciary duty standards		Fiduciary duties are generally considered to include an obligation to act in good faith and with due care and loyalty. The duty of care, in the absence of a provision in a partnership agreement providing otherwise, would generally require a general partner to act for the partnership in the same manner as a prudent person would act on his own behalf. The duty of loyalty, in the absence of a provision in a partnership agreement providing otherwise, would generally prohibit a general partner of a Delaware limited partnership from taking any action or engaging in any transaction where a conflict of interest is present.

Underwriter

Wells Fargo Securities, LLC		2,116,800
Raymond James & Associates, Inc.		2,116,800
Citigroup Global Markets Inc.		1,928,640
RBC Capital Markets, LLC		1,928,640
Robert W. Baird & Co. Incorporated		376,320
Oppenheimer & Co. Inc.		376,320
Stifel, Nicolaus & Company, Incorporated		376,320
Williams Trading, LLC		188,160

	Total	9,408,000

Wells Fargo Securities

Raymond James

Citigroup

RBC Capital Markets