Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)

x      QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2011

OR

o         TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from           to           .

Commission File Number:  001-35344

LRR Energy, L.P.

(Exact name of registrant as specified in its charter)

Telephone Number:  (713) 292-9510

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.   Yes   o   No  x

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes  x  No  o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

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

There were 15,700,074 Common Units, 6,720,000 Subordinated Units and 22,400 General Partner Units outstanding as of December 19, 2011.  The Common Units trade on the New York Stock Exchange under the ticker symbol “LRE”.

Table of Contents

LRR Energy, L.P.

TABLE OF CONTENTS

Explanatory Note

The information contained in this report relates to periods that ended prior to the completion of the initial public offering of LRR Energy, L.P., and prior to the effective dates of the agreements discussed herein.  Consequently, the unaudited combined condensed financial statements and related discussion of financial condition and results of operations contained in this report pertain 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”, collectively with LRR A and LRR B, “Fund I” or “predecessor”).  Because the 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 these results of our predecessor to be indicative of our future results.  In connection with the closing of the initial public offering, LRR Energy, L.P. entered into a purchase, sale, contribution, conveyance and assumption agreement with Fund I pursuant to which LRR Energy, L.P. acquired specified oil and natural gas properties and related net profits interests and operations in exchange for newly issued limited partner interests in LRR Energy, L.P and cash consideration.  See Note 1 to the unaudited combined condensed financial statements for information regarding the initial public offering.

i

Table of Contents

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements.

Lime Rock Resources Fund I (Predecessor of LRR Energy, L.P.)

Combined Condensed Balance Sheets

(Unaudited)

See accompanying notes to the unaudited combined condensed financial statements

1

Table of Contents

Lime Rock Resources Fund I (Predecessor of LRR Energy, L.P.)

Combined Condensed Statements of Operations

(Unaudited)

See accompanying notes to the unaudited combined condensed financial statements

2

Table of Contents

Lime Rock Resources Fund I (Predecessor of LRR Energy, L.P.)

Combined Condensed Statements of Changes in Partners’ Capital

(Unaudited)

See accompanying notes to the unaudited combined condensed financial statements

3

Table of Contents

Lime Rock Resources Fund I (Predecessor of LRR Energy, L.P.)

Combined Condensed Statements of Cash Flows

(Unaudited)

See accompanying notes to the unaudited combined condensed financial statements

4

Table of Contents

Lime Rock Resources Fund I (Predecessor of LRR Energy, L.P.)

Notes to Unaudited Combined Condensed Financial Statements

1.              Description of Business

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.  As used herein, references to “Fund I” or “predecessor” refer collectively to LRR A, LRR B and LRR C.  References to “Lime Rock Resources” refer collectively to LRR A, LRR B, LRR C, Lime Rock Resources II-A, L.P. and Lime Rock Resources II-C, L.P.  The properties conveyed to us in connection with our initial public offering (“IPO”) (such conveyance described below) 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.  We conduct our operations through our wholly owned subsidiary, LRE Operating, LLC (“OLLC”).

Prior to and as of September 30, 2011, Fund I owned 100% of the properties conveyed to us in connection with our IPO.  On November 16, 2011, we completed our IPO of 9,408,000 common units representing limited partner interests in the Partnership at a price to the public of $19.00 per common unit, or $17.8125 per common unit after payment of the underwriting discount.  At the closing of our IPO, we entered into a purchase, sale, contribution, conveyance and assumption agreement with Fund I pursuant to which Fund I sold and contributed to us specified oil and natural gas properties and related net profits interests and operations and 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 (the “Common Control Properties”).   Fund I received 6,249,600 common units, 6,720,000 subordinated units representing limited partner interests in us, and $289.9 million in cash in exchange for these contributions to the Partnership.

Fund I is under common control with us.  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 accompanying unaudited combined condensed financial statements of Fund I reflect the predecessor financial statements of the Partnership and have been prepared from the separate financial records maintained by Fund I.  Because the 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 these results of our predecessor to be indicative of our future results.  Prior to such contribution, our financial statements consisted of total assets of $1,000 and we had not conducted any activity from our formation in April 2011 through September 30, 2011.  In addition, the effects of our IPO, related equity transfers and debt transactions that occurred in November 2011 are not reflected in these unaudited combined condensed financial statements.  See Note 10 for further discussion regarding the completion of our IPO and other related items occurring subsequent to the period ended September 30, 2011.

2.              Summary of Significant Accounting Policies

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 in our final prospectus dated November 10, 2011 (the “Prospectus”) included in our Registration Statement on Form S-1, as amended (SEC File No. 333-174017), and are supplemented by the notes to these unaudited combined condensed financial statements.  There have been no significant changes to these policies and these unaudited combined condensed financial statements should be read in conjunction with the audited combined financial statements and notes for the year ended December 31, 2010 included in the Prospectus.

5

Table of Contents

Basis of presentation

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 of our predecessor for the year ended December 31, 2010 included in our 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 financial statements reflect all adjustments that are, in the opinion of management, necessary for a fair statement of the results for the periods presented.

Recent accounting pronouncements

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”).  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 condensed financial statements.

3.              Acquisitions and Divestitures

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 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. The predecessor did not acquire proved oil and natural gas properties during the nine months ended September 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.

6

Table of Contents

2010 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.

The following table summarizes the values assigned to the assets acquired and liabilities assumed as of the acquisition date:

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 acquisition.

Summarized below are the combined results of operations for the three and nine months ended September 30, 2010, on an unaudited pro forma basis, as if the 2010 acquisitions had occurred on January 1, 2010:

2011 and 2010 divestitures of non-core assets

In May 2011, the predecessor sold 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.

In both 2011 and 2010, 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.

7

Table of Contents

4.              Fair Value Measurements

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 liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements).  The three levels of fair value hierarchy are as follows:

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 September 30, 2011 and December 31, 2010.

All fair values reflected in the table above and on the unaudited combined condensed 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.

8

Table of Contents

The curves are obtained from independent pricing services reflecting broker market quotes.

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 three and nine months ended September 30, 2011 and 2010:

5.              Property and Equipment

The components of property and equipment, net follow:

For the nine months ended September 30, 2011 and 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 nine months ended September 30, 2011, the predecessor recorded a total non-cash impairment charge of approximately $16.8 million to impair the value of its proved oil and natural gas properties in the Mid-Continent region.  For the nine months ended September 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 region. 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 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

9

Table of Contents

used to mitigate the risk of lower future natural gas prices. These asset impairments had no impact on the predecessor’s cash flows, liquidity position, or debt covenants. If expected future oil and natural gas prices decline or we experience a loss of reserves during the last quarter of 2011 or future periods, 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 and a non-cash impairment charge may be required to be recognized in future periods.

6.              Asset Retirement Obligations

The following is a summary of the predecessor’s ARO as of and for the nine months ended September 30, 2011:

7.              Long-Term Debt

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 September 30, 2011, LRR A’s availability under the credit facility was 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 LIBOR of 2.00% to 2.75% or specified margins over an Alternate Base Rate of 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 September 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 4.75%.

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. Except for the current ratio covenant, LRR A was in compliance with all of the financial covenants as of September 30, 2011.  LRR A received a waiver for non-compliance with this covenant.

10

Table of Contents

All amounts drawn under the credit facility are due and payable on November 23, 2014. As of September 30, 2011 and December 31, 2010, borrowings under the credit facility were $27.3 million and accrued interest payable was $0.1 million.

8.              Derivatives

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 September 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 natural 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 natural 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.

During the second quarter of 2011, the predecessor entered into oil, natural gas and NGL derivative contracts that were contributed to us at the closing of the IPO. 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.

11

Table of Contents

At September 30, 2011, the predecessor had the following commodity derivative open positions:

At December 31, 2010, the predecessor had the following commodity derivative open positions:

At September 30, 2011, the predecessor had the following interest rate swap contracts:

12

Table of Contents

At December 31, 2010, the predecessor had the following interest rate swap contracts: