Exhibit 99.2

June 10, 2011

LRR Energy, L.P.

1111 Bagby Street, Suite 4600

Houston, Texas  77002

Attention:  Mr. Christopher A. Butta

Gentlemen:

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 December 31, 2010.  The report was prepared for LRRE’s use in reserves and financial reporting and planning and was completed on March 10, 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 December 31, 2010.  The aggregate results of our evaluations, using constant product prices determined under SEC rules for year-end 2010 are summarized below.

Reserves and Future Net Revenues as of December 31, 2010

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 83 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 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 year-end 2010 reserves disclosures are calculated for each product as the average of the prices existent on the first day of each month in 2010.  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 $79.43 per barrel for oil and $4.376 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 $75.08 per barrel for oil, $40.21 per barrel for NGLs, and $4.21 per Mcf for gas.

Operating 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.  A Travis Peak well spacing is 40 acres based on state-wide field rules.

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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 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 MLL’s informed judgments and are subject to inherent uncertainties associated with the interpretation of geological, geophysical, and engineering information.  These uncertainties include but are not limited to the utilization of indirect or imprecise data and the application of professional judgment in performing these evaluations.  Government policies and market conditions different from those employed in this study may cause the total quantity of oil or gas to be recovered, actual production rates, prices received, or 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 Lime Rock Resources or any related company.  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 an officer of Miller and Lents, Ltd., 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.

We appreciate this opportunity to be of service.  If you have any questions regarding this evaluation or if we can be of further assistance, please call.

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LAF/psh

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Appendix

Reserves Definitions In Accordance With

Securities and Exchange Commission Regulation S-X

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.

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

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.

1.                           The area of the reservoir considered as proved includes:

a.               The area identified by drilling and limited by fluid contacts, if any, and

b.              Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

2.                           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.

3.                           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.

4.                           Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

a.               Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

b.              The project has been approved for development by all necessary parties and entities, including governmental entities.

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

Developed Oil and Gas Reserves

Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

1.                           Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

2.                           Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

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.

1.                           Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

2.                           Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

3.                           Under no circumstances shall estimates for 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 projects in the same reservoir or an analogous reservoir, as defined below, or by other evidence using reliable technology establishing reasonable certainty.

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:

1.                     Same geological formation (but not necessarily in pressure communication with the reservoir of interest);

2.                     Same environment of deposition;

3.                     Similar geological structure; and

4.                     Same drive mechanism.

Reservoir properties must, in aggregate, be no more favorable in the analog than in the reservoir of interest.

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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.

1.                           When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

2.                           Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

3.                           Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

4.                           See also guidelines in Items 4 and 6 under Possible Reserves.

Possible Reserves

Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

1.                           When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

2.                           Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

3.                           Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

4.                           The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

5.                           Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir.  Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

6.                           Pursuant to Item 3 under Proved Oil and Gas Reserves, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology.  Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

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