Cautionary Note Regarding Forward-Looking Statements



This Quarterly Report on Form 10-Q 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:



†          business strategies;

†          ability to replace the reserves we produce through drilling and
property acquisitions;

†          drilling locations;

†          oil and natural gas reserves;

†          technology;

†          realized oil and natural gas prices;

†          production volumes;

†          lease operating expenses;

†          general and administrative expenses;

†          future operating results;

†          cash flows and liquidity;

†          availability of drilling and production equipment;

†          general economic conditions;

†          effectiveness of risk management activities; and

†          plans, objectives, expectations and intentions.

All statements, other than statements of historical fact, are forward-looking statements. These forward-looking statements can be identified by their use of terms and phrases such as "may," "predict," "pursue," "expect," "estimate," "project," "plan," "believe," "intend," "achievable," "anticipate," "target," "continue," "potential," "should," "could" and similar terms and phrases. Although we believe that the expectations reflected in these forward-looking statements are reasonable, they do involve certain assumptions, risks and uncertainties, some of which are beyond our control. Actual results could differ materially from those anticipated in these forward-looking statements. One should consider carefully the risk factors described in Item 1A. "Risk Factors" of our Annual Report on Form 10-K for the year ended December 31, 2011 which describe factors that could cause our actual results to differ from those anticipated in the forward-looking statements, including, but not limited to, the following factors:

† our ability to generate sufficient cash to pay the minimum quarterly distribution on our common units;

† our ability to replace the oil and natural gas reserves we produce;

† our substantial future capital expenditures, which may reduce our cash available for distribution and could materially affect our ability to make distributions on our common units;

†          a decline in, or substantial volatility of, oil, natural gas or NGL
prices;

†          the differential between the NYMEX or other benchmark prices of oil
and natural gas and the wellhead price we receive for our production;

†          the risk that our hedging strategy may be ineffective or may reduce
our income;

†          uncertainty inherent in estimating our reserves;

†          the risks and uncertainties involved in developing and producing oil

† risks related to potential acquisitions, including our ability to make accretive acquisitions on economically acceptable terms or to integrate acquired properties;

†          competition in the oil and natural gas industry;

†          cash flows and liquidity;

†          restrictions and financial covenants contained in the instruments
governing our existing indebtedness;

†          the availability of pipelines, transportation and gathering systems
and processing facilities owned by third parties;

†          electronic, cyber, and physical security breaches;

†          general economic conditions; and

† legislation and governmental regulations, including climate change legislation and federal or state regulation of hydraulic fracturing.

All forward-looking statements are expressly qualified in their entirety by the cautionary statements in this paragraph and elsewhere in this document and speak only as of the date of this report. Other than as required under the securities laws, we do not assume a duty to update these forward-looking statements, whether as a result of new information, subsequent events or circumstances, changes in expectations or otherwise.

LRR Energy, L.P. ("we," "us," "our," or the "Partnership") is a Delaware limited partnership formed in April 2011 by Lime Rock Management LP ("Lime Rock Management"), an affiliate 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"), to operate, acquire, exploit and develop producing oil and natural gas properties in North America with long-lived, predictable production profiles. LRR A, LRR B and LRR C were formed by Lime Rock Management in July 2005 for the purpose of acquiring mature, low-risk producing oil and natural gas properties with long-lived production profiles. As used herein, references to "Fund I" or "predecessor" refer collectively to LRR A, 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, and pays an administrative services fee to, Lime Rock Resources Operating Company, Inc.

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.

In connection with the completion of our IPO on November 16, 2011, pursuant to a contribution, conveyance and assumption agreement, we acquired specified oil and natural gas properties and related net profits interests and operations and certain commodity derivative contracts (the "Partnership Properties") owned by LRR A, LRR B, and LRR C.

Fund I received total consideration for the Partnership Properties of 5,049,600 common units, 6,720,000 subordinated units, $311.2 million in cash and the assumption of $27.3 million of LRR A's indebtedness. For further discussion regarding our IPO, please see Note 10 to the consolidated/combined condensed financial statements included in this report.

On June 1, 2012, we completed an acquisition from Fund I of certain oil and natural gas properties (the "Transferred Properties") located in the Permian Basin region of New Mexico and onshore Gulf Coast region of Texas for $65.1 million in cash consideration (the "Transaction"). The Transaction was effective as of March 1, 2012. In September 2012, we received $1.1 million in cash from Fund I related to post-closing adjustments to the purchase price for the acquisition.

Our discussion and analysis of the results of operations below discusses the Partnership's and predecessor's results of operations separately. Because the historical results of our predecessor include results for both the properties conveyed to us in connection with our IPO and properties retained by our predecessor, we do not consider the historical results of our predecessor to be indicative of our future results. Our discussion and analysis below includes a comparison of the three months ended September 30, 2012 to the three months ended June 30, 2012. We believe this comparison will enable the reader to assess material changes in our results of operations in calendar year 2012. We will first compare our results of operations between comparable interim periods beginning with our Quarterly Report on Form 10-Q for the quarter ending March 31, 2013.

Because Fund I and its affiliates own 100% of our general partner and because Fund I owns 5,049,600 common units and all of our 6,720,000 subordinated units, representing an aggregate 52.4% limited partner interest in us, each acquisition of assets from Fund I is considered a transfer of net assets between entities under common control.

As a result, we are required to revise our financial statements to include the activities of such assets for all periods presented, similar to a pooling of interests, to include the financial position, results of operations and cash flows of the assets acquired and liabilities assumed. The table set forth below includes selected recast historical financial information as if the Transferred Properties were owned by us for all periods presented.

                                                       Partnership                                              Predecessor
                               Three Months         Three Months            Nine Months             Three Months            Nine Months
                                  Ended                Ended                   Ended                   Ended                   Ended
                              June 30, 2012      September 30, 2012     September 30, 2012       September 30, 2011     September 30, 2011
Revenues (in thousands):
Oil sales                     $       15,555    $             16,502    $            47,415     $             16,677    $            51,338
Natural gas sales                      4,345                   5,691                 15,477                    9,699                 31,453
Natural gas liquids sales              2,713                   2,633                  8,403                    4,508                 12,266
Realized gain (loss) on
commodity derivative
instruments                            6,820                   5,808                 17,876                    6,029                  6,070
Unrealized gain (loss) on
commodity derivative
instruments                           10,997                 (21,463 )              (10,455 )                 29,253                 26,144
Other income                               -                      30                     33                       42                    122
Total revenues                        40,430                   9,201                 78,749                   66,208                127,393

Expenses (in thousands):
Lease operating expense                6,912                   6,919                 20,127                    6,797                 18,732
Production and ad valorem
taxes                                  1,700                   1,987                  5,348                    2,711                  5,731
Depletion and depreciation            10,559                   8,267                 28,126                   11,163                 32,034
Impairment of oil and
natural gas properties                     -                     451                  3,544                   16,765                 16,765
Management fees                            -                       -                      -                    1,579                  4,546
General and administrative
expense                                3,229                   2,294                  8,595                    1,208                  4,414
Interest expense                       1,332                   2,081                  4,541                      255                    814
Realized loss on interest
rate derivative
instruments                              108                     153                    294                      141                    439
Unrealized (gain) loss on
interest rate derivative
instruments                            2,852                   2,124                  4,171                     (134 )                 (297 )

Production:
Oil (MBbls)                              181                     192                    530                      192                    563
Natural gas (MMcf)                     2,021                   2,026                  6,098                    2,262                  7,464
NGLs (MBbls)                              70                      83                    214                       83                    237
Total (MBoe)                             588                     613                  1,760                      652                  2,044
Average net production
(Boe/d)                                6,462                   6,663                  6,423                    7,087                  7,487

Average sales price:
Oil (per Bbl)
Sales price                   $        85.94    $              85.95    $             89.46     $              86.86    $             91.19
Effect of realized
commodity derivative
instruments                             6.17                    5.54                   4.03                    10.31                 (13.90 )
Realized price                $        92.11    $              91.49    $             93.49     $              97.17    $             77.29
Natural gas (per Mcf)
Sales price                   $         2.15    $               2.81    $              2.54     $               4.29    $              4.21
Effect of realized
commodity derivative
instruments                             2.58                    2.04                   2.40                     1.79                   1.86
Realized price                $         4.73    $               4.85    $              4.94     $               6.08    $              6.07
NGLs (per Bbl)
Sales price                   $        38.76    $              31.72    $             39.27     $              54.31    $             51.76
Effect of realized
commodity derivative
instruments                             6.87                    7.30                   5.11                        -                      -
Realized price                $        45.63    $              39.02    $             44.38     $              54.31    $             51.76

                                               Partnership                                              Predecessor
                        Three Months        Three Months            Nine Months            Three Months            Nine Months
                           Ended                Ended                  Ended                   Ended                  Ended
                       June 30, 2012     September 30, 2012     September 30, 2012      September 30, 2011      September 30, 2011

Average unit cost
per Boe:
Lease operating
expenses               $        11.76    $             11.29    $             11.43     $             10.42    $               9.16
Production and ad
valorem taxes                    2.89                   3.24                   3.04                    4.16                    2.80
Depletion and
depreciation                    17.96                  13.49                  15.98                   17.12                   15.67
Management fees                     -                      -                      -                    2.42                    2.22
General and
administrative
expenses                         5.49                   3.74                   4.88                    1.85                    2.16

Our Results for the Three Months Ended September 30, 2012 Compared to the Three Months Ended June 30, 2012

We recorded a net loss of $15.6 million for the three months ended September 30, 2012 compared to net income of $13.4 million during the three months ended June 30, 2012, primarily related to $21.5 million of unrealized losses on commodity derivative contracts. The following discussion summarizes key components of the changes between periods.

Sales Revenues. A summary of increases (decreases) in our oil, natural gas and NGL revenues between June 30, 2012 and September 30, 2012 follows (in thousands):

Oil, natural gas and NGL revenues-prior period     $ 22,613
Increase (decrease)
Price realization
Oil                                                       2
Natural gas                                           1,333
NGLs                                                   (493 )
Sales volumes
Oil                                                     945
Natural gas                                              14
NGLs                                                    412
Oil, natural gas and NGL revenues-current period   $ 24,826

Sales revenues increased from $22.6 million for the three months ended June 30, 2012 to $24.8 million for the three months ended September 30, 2012, primarily driven by natural gas price realizations and increased oil and NGL production. Sales revenues for the three months ended September 30, 2012 consisted of oil sales of $16.5 million, natural gas sales of $5.7 million and NGL sales of $2.6 million. Sales revenues for the three months ended June 30, 2012 consisted of oil sales of $15.6 million, natural gas sales of $4.3 million and NGL sales of $2.7 million.

Our production volumes for the three months ended September 30, 2012 included 275 MBbls of oil and NGLs and 2,026 MMcf of natural gas, or 2,989 Bbl/d of oil and NGLs and 22,022 Mcf/d of natural gas. On an equivalent basis, production for the period was 613 MBoe, or 6,663 Boe/d. Our production volumes for the three months ended June 30, 2012 included 251 MBbls of oil and NGLs and 2,021 MMcf of natural gas, or 2,758 Bbl/d of oil and NGLs and 22,209 Mcf/d of natural gas. On an equivalent basis, production for the period was 588 MBoe, or 6,462 Boe/d. Increased oil and NGL volumes were primarily driven by increased production from new wells at our Red Lake and Pecos Slope fields.

Our average sales price per Bbl for oil and NGLs for the three months ended September 30, 2012, excluding the effect of commodity derivative contracts, was $85.95 and $31.72, respectively. Our average sales price per Mcf of natural gas for the three months ended September 30, 2012, excluding the effect of commodity derivative contracts, was $2.81. Our average sales price per Bbl for oil and NGLs for the three months ended June 30, 2012, excluding the effect of commodity derivative contracts, was $85.94 and $38.76, respectively. Our average sales price per Mcf of natural gas for the three months ended June 30, 2012, excluding the effect of commodity derivative contracts, was $2.15.

Relating to the Pecos Slope field curtailment previously disclosed in our periodic reports filed with the SEC, approximately 1.0 MMcf/d of production was curtailed during the third quarter of 2012 due to the gas containing a nitrogen percentage greater than our gas purchaser's specification. The curtailment is expected to remain at this level until a field-wide nitrogen rejection facility is installed in January 2013 by the third-party 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, we recorded a net loss from our commodity hedging program for the three months ended September 30, 2012 of approximately $15.7 million, which is comprised of a realized gain of approximately $5.8 million and an unrealized loss of approximately $21.5 million. For the three months ended June 30, 2012, we recorded a net gain from our commodity hedging program of approximately $17.8 million, which is comprised of a realized gain of approximately $6.8 million and an unrealized gain of approximately $11.0 million. Volatility in commodity prices has had a significant impact on our realized and unrealized gains and losses on commodity derivative contracts.

Lease Operating Expenses. Our lease operating expenses were approximately $6.9 million, or $11.29 per Boe, for the three months ended September 30, 2012 compared to approximately $6.9 million, or $11.76 per Boe, for the three months ended June 30, 2012.

Production and Ad Valorem Taxes. Our production and ad valorem taxes were approximately $2.0 million, or $3.24 per Boe, for the three months ended September 30, 2012 compared to approximately $1.7 million, or $2.89 per Boe, for the three months ended June 30, 2012. Production taxes accounted for approximately $1.8 million and ad valorem taxes for $0.2 million of the total taxes recorded during the three months ended September 30, 2012. Production taxes accounted for approximately $1.6 million and ad valorem taxes for $0.1 million of the total taxes recorded during the three months ended June 30, 2012.

Depletion and Depreciation. Our depletion and depreciation expense was approximately $8.3 million, or $13.49 per Boe, for the three months ended September 30, 2012 compared to approximately $10.6 million, or $17.96 per Boe, for the three months ended June 30, 2012. The decrease in depletion and depreciation expense and per Boe amount was primarily due to the $1.9 million adjustment recorded in the third quarter. See Note 2 to our unaudited consolidated/combined condensed financial statements.

Impairment of Oil and Natural Gas Properties. We recorded an impairment of approximately $0.5 million for the three months ended September 30, 2012 on our unproved properties during the period. We did not record an impairment charge in the three months ended June 30, 2012. If future oil or natural gas prices decline further, the estimated undiscounted future cash flows for our proved oil and natural gas properties may not exceed the net capitalized costs for such properties and a non-cash impairment charge may be required to be recognized in future periods. As of November 5, 2012, the NYMEX-WTI oil spot price was $85.65 per Bbl and the NYMEX-Henry Hub natural gas spot price was $3.40 per MMBtu.

General and Administration Expenses. Our general and administrative expenses were approximately $2.3 million, or $3.74 per Boe, for the three months ended September 30, 2012 compared to approximately $3.2 million, or $5.49 per Boe, for the three months ended June 30, 2012. The decrease in general and administrative expenses was primarily due to costs incurred in connection with the acquisition of the Transferred Properties in the second quarter of 2012.

Interest Expenses. Our interest expense is comprised of interest on our credit facility and term loan, amortization of debt issuance costs and realized gains (losses) on our interest rate derivative instruments. Interest expense was approximately $2.2 million and $1.4 million for the three months ended September 30, 2012 and June 30, 2012, respectively. The increase in interest expense was primarily due to the increased debt level at the end of the second quarter of 2012. Unrealized losses on interest rate derivative contracts were approximately $2.1 million for the three months ended September 30, 2012 compared to approximately $2.9 million for the three months ended June 30, 2012.

Our Results for the Nine Months Ended September 30, 2012

We recorded net income of $2.8 million for the nine months ended September 30, 2012.

Sales Revenues. Sales revenues of $71.3 million for the period consisted of oil sales of $47.4 million, natural gas sales of $15.5 million and NGL sales of $8.4 million. Our production volumes for the period included 744 MBbls of oil and NGLs and 6,098 MMcf of natural gas, or 2,715 Bbl/d of oil and NGLs and 22,255 Mcf/d of natural gas. On an equivalent basis, production for the period was 1,760 MBoe, or 6,423 Boe/d.

Our average sales price per Bbl for oil and NGLs for the period, excluding the effect of commodity derivative contracts, was $89.46 and $39.27, respectively. Our average sales price per Mcf of natural gas, excluding the effect of commodity derivative contracts, was $2.54.

During the third week in February 2012 and through the second week in March 2012, approximately 1,515 Bbls/d and 1.7 MMcf/d of our Red Lake field production was entirely shut-in due to a compression system upgrade at the third party gas plant that processes natural gas for our Red Lake field. The upgrade was initially expected to last 7 days, but it experienced delays and took 21 days to complete.

Relating to the Pecos Slope field curtailment previously disclosed in our periodic reports filed with the SEC, approximately 1.0 MMcf/d of production was curtailed during 2012 due to the gas containing a nitrogen percentage greater than our gas purchaser's specification. The curtailment is expected to remain at this level until a field-wide nitrogen rejection facility is installed in January 2013 by the third-party 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, we recorded a net gain from our commodity hedging program for the period of approximately $7.4 million, which is comprised of a realized gain of approximately $17.9 million and an unrealized loss of approximately $10.5 million.

Lease Operating Expenses. Our lease operating expenses were approximately $20.1 million, or $11.43 per Boe, for the period.

Production and Ad Valorem Taxes. Our production and ad valorem taxes were approximately $5.3 million, or $3.04 per Boe, for the period. Production taxes accounted for approximately $4.8 million and ad valorem taxes for $0.5 million of the total taxes recorded.

Depletion and Depreciation. Our depletion and depreciation expense was approximately $28.1 million, or $15.98 per Boe, for the period.

Impairment of Oil and Natural Gas Properties. We recorded impairment charges of approximately $3.5 million for the nine months ended September 30, 2012. Approximately $3.1 million of this amount related to a decline in natural gas prices impacting our proved properties during the first quarter of 2012, and the remaining $0.4 million related to impairments of unproved properties in the third quarter of 2012.

If future oil or natural gas prices decline further, the estimated undiscounted future cash flows for the proved oil and natural gas properties may not exceed the net capitalized costs for such properties and a non-cash impairment charge may be required to be recognized in future periods. As of November 5, 2012, the NYMEX-WTI oil spot price was $85.65 per Bbl and the NYMEX-Henry Hub natural gas spot price was $3.40 per MMBtu.

General and Administration Expenses. Our general and administrative expenses were approximately $8.6 million, or $4.88 per Boe, for the nine months ended September 30, 2012.

Interest Expense. Our interest expense is comprised of interest on our credit facility and term loan, amortization of debt issuance costs and realized gains (losses) on our interest rate derivative instruments. Interest expense was approximately $4.8 million for the nine months ended September 30, 2012. Unrealized losses on interest rate derivative contracts were approximately $4.2 million for the nine months ended September 30, 2012. The unrealized loss in the nine months ended September 30, 2012 was due to a decline in interest rates over the period.

Our Predecessor's Results for the Three Months Ended September 30, 2011

Our predecessor recorded net income of approximately $25.6 million for the three months ended September 30, 2011. Net income was driven by revenues and expenses as described below.

Sales Revenues. Sales revenues of $30.9 million for the three months ended September 30, 2011 consisted of oil sales of $16.7 million, natural gas sales of . . .