Form 10-Q LRR Energy, L.P. For: Sep 30

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November 5, 2014 4:09 PM EST

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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, 2014

�

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)

�

Delaware	�	90-0708431
(State or other jurisdiction of incorporation or organization)	�	(I.R.S. Employer Identification No.)
�	�	�
Heritage Plaza 1111 Bagby, Suite�4600 Houston, Texas	�	77002
(Address of principal executive offices)	�	(Zip code)

�

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�x��No�o

�

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.

�

Large accelerated filer�o

�

Accelerated filer�x

�

Non-accelerated filer�o

�

Smaller reporting company�o

(Do not check if a smaller reporting company)

�

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 23,315,146 Common Units, 4,480,000 Subordinated Units and 22,400 General Partner Units outstanding as of October�31, 2014.� 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

�

�	Caption	�	Page
�	�	�	�
�	PART�I � FINANCIAL INFORMATION	�	�
�	�	�	�
Item 1.	Financial Statements.	�	�
�	Unaudited Consolidated Condensed Balance Sheets as of September�30, 2014 and December�31, 2013	�	1
�	Unaudited Consolidated Condensed Statements of Operations for the Three and Nine Months Ended September�30, 2014 and 2013	�	2
�	Unaudited Consolidated Condensed Statement of Changes in Unitholders� Equity as of September�30, 2014	�	3
�	Unaudited Consolidated Condensed Statements of Cash Flows for the Nine Months Ended September�30, 2014 and 2013	�	4
�	Notes to Unaudited Consolidated Condensed Financial Statements	�	5
Item 2.	Management�s Discussion and Analysis of Financial Condition and Results of Operations .	�	17
Item 3.	Quantitative and Qualitative Disclosures About Market Risk.	�	28
Item 4.	Controls and Procedures.	�	29
�	�	�	�
�	PART�II � OTHER INFORMATION	�	�
�	�	�	�
Item 1.	Legal Proceedings.	�	29
Item 1A.	Risk Factors.	�	29
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds.	�	29
Item 3.	Defaults Upon Senior Securities.	�	29
Item 4.	Mine Safety Disclosures.	�	29
Item 5.	Other Information.	�	29
Item 6.	Exhibits.	�	30
�	Signatures.	�	31

�

Table of Contents

�

PART�I�FINANCIAL INFORMATION

�

Item 1. Financial Statements.

�

LRR Energy, L.P.

Consolidated Condensed Balance Sheets

(Unaudited)

(in thousands, except unit amounts)

�

�	�	September�30,�2014		�	December�31,�2013		�
ASSETS	�	�		�	�		�
Current assets:	�	�		�	�		�
Cash and cash equivalents	�	$	10,751	�	$	4,417	�
Accounts receivable	�	9,269		�	9,867		�
Commodity derivative instruments	�	14,508		�	9,726		�
Due from affiliates	�	5,760		�	�		�
Prepaid expenses	�	2,858		�	1,603		�
Total current assets	�	43,146		�	25,613		�
Property and equipment (successful efforts method)	�	904,497		�	876,674		�
Accumulated depletion, depreciation and impairment	�	(457,732		)	(431,837		)
Total property and equipment, net	�	446,765		�	444,837		�
Commodity derivative instruments	�	7,722		�	16,746		�
Deferred financing costs, net of accumulated amortization and other	�	1,100		�	1,154		�
TOTAL ASSETS	�	$	498,733	�	$	488,350	�
LIABILITIES AND UNITHOLDERS� EQUITY	�	�		�	�		�
Current liabilities:	�	�		�	�		�
Accrued liabilities	�	$	4,094	�	$	2,300	�
Accrued capital cost	�	4,507		�	2,574		�
Due to affiliates	�	�		�	255		�
Commodity derivative instruments	�	510		�	2,217		�
Interest rate derivative instruments	�	1,781		�	648		�
Asset retirement obligations	�	510		�	488		�
Total current liabilities	�	11,402		�	8,482		�
Long-term liabilities:	�	�		�	�		�
Commodity derivative instruments	�	559		�	174		�
Interest rate derivative instruments	�	709		�	1,554		�
Term loan	�	50,000		�	50,000		�
Revolving credit facility	�	200,000		�	200,000		�
Asset retirement obligations	�	37,479		�	35,838		�
Deferred tax liabilities	�	88		�	44		�
Total long-term liabilities	�	288,835		�	287,610		�
Total liabilities	�	300,237		�	296,092		�
Unitholders� equity:	�	�		�	�		�
General partner (22,400 units issued and outstanding as of September�30, 2014 and December�31, 2013)	�	290		�	303		�
Public common unitholders (19,078,939 units issued and outstanding as of September�30, 2014 and 17,710,334 units issued and outstanding as of December�31, 2013)	�	193,516		�	181,290		�
Affiliated common unitholders (4,089,600 units issued and outstanding as of September�30, 2014 and 1,849,600 issued and outstanding as of December�31, 2013)	�	2,088		�	2,093		�
Subordinated unitholders (4,480,000 units issued and outstanding as of September�30, 2014 and 6,720,000 units issued and outstanding as of December�31, 2013)	�	2,602		�	8,572		�
Total unitholders� equity	�	198,496		�	192,258		�
TOTAL LIABILITIES AND UNITHOLDERS� EQUITY	�	$	498,733	�	$	488,350	�

�

See accompanying notes to the unaudited consolidated condensed financial statements.

�

Table of Contents

�

LRR Energy, L.P.

Consolidated Condensed Statements of Operations

(Unaudited)

(in thousands, except per unit amounts)

�

Three�Months�Ended�September�30,

�

Nine�Months�Ended�September�30,

�

2014

�

2013

�

2014

�

2013

�

Revenues:

�

Oil sales

�

19,258

�

22,239

�

59,768

�

56,714

�

Natural gas sales

�

6,542

�

6,564

�

22,206

�

20,364

�

Natural gas liquids sales

�

2,771

�

2,655

�

8,895

�

7,165

�

Gain (loss) on commodity derivative instruments, net

�

19,771

�

(6,282

)

821

�

Other income

�

111

�

106

�

Total revenues

�

48,382

�

25,195

�

91,801

�

84,354

�

Operating expenses:

�

Lease operating expense

�

6,024

�

6,005

�

18,688

�

18,072

�

Production and ad valorem taxes

�

2,172

�

2,434

�

6,820

�

6,478

�

Depletion and depreciation

�

8,711

�

9,533

�

25,856

�

29,772

�

Accretion expense

�

519

�

486

�

1,532

�

1,433

�

Loss (gain) on settlement of asset retirement obligations

�

)

�

334

�

General and administrative expense

�

2,629

�

2,669

�

8,510

�

8,866

�

Total operating expenses

�

20,065

�

21,126

�

61,477

�

64,955

�

Operating income (loss)

�

28,317

�

4,069

�

30,324

�

19,399

�

Other income (expense), net

�

Interest expense

�

(2,551

)

(2,349

)

(7,667

)

(6,863

)

Gain (loss) on interest rate derivative instruments, net

�

492

�

(1,401

)

(930

)

1,371

�

Other income (expense), net

�

(2,059

)

(3,750

)

(8,597

)

(5,492

)

�

Income (loss) before taxes

�

26,258

�

319

�

21,727

�

13,907

�

Income tax expense

�

(26

)

(35

)

(138

)

(102

)

Net income (loss)

�

26,232

�

284

�

21,589

�

13,805

�

Net (income) loss attributable to common control operations

�

(448

)

Net income (loss) available to unitholders

�

26,232

�

284

�

21,589

�

13,357

�

Computation of net income (loss) per limited partner unit:

�

General partner�s interest in net income (loss)

�

Limited partners� interest in net income (loss)

�

26,206

�

284

�

21,567

�

13,344

�

Net income (loss) per limited partner unit (basic and diluted)

�

0.95

�

0.01

�

0.80

�

0.53

�

Weighted average number of limited partner units outstanding (basic and diluted)

�

27,481

�

26,169

�

26,856

�

25,098

�

See accompanying notes to the unaudited consolidated condensed financial statements.

�

Table of Contents

�

LRR Energy, L.P.

Consolidated Condensed Statement of Changes in Unitholders� Equity

(Unaudited)

(in thousands)

�

Limited�Partners

�

General

�

Public

�

Affiliated

�

Partner

�

Common

�

Common

�

Subordinated

�

Total

�

Balance, December�31, 2013

�

303

�

181,290

�

2,093

�

8,572

�

192,258

�

Equity offering, net of expenses

�

23,419

�

23,419

�

Amortization of equity awards

�

819

�

819

�

Conversion of subordinated units

�

623

�

(623

)

�

Distribution

�

(33

)

(26,894

)

(3,856

)

(8,806

)

(39,589

)

Net income (loss)

�

14,882

�

3,228

�

3,459

�

21,589

�

Balance, September�30, 2014

�

290

�

193,516

�

2,088

�

2,602

�

198,496

�

See accompanying notes to the unaudited consolidated condensed financial statements.

�

Table of Contents

�

LRR Energy, L.P.

Consolidated Condensed Statements of Cash Flows

(Unaudited)

(in thousands)

�

�	�	Nine�Months�Ended�September�30,					�
�	�	2014		�	2013		�
CASH FLOWS FROM OPERATING ACTIVITIES	�	�		�	�		�
Net income (loss)	�	$	21,589	�	$	13,805	�
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:	�	�		�	�		�
Depletion and depreciation	�	25,856		�	29,772		�
Accretion expense	�	1,532		�	1,433		�
Amortization of equity awards	�	819		�	391		�
Amortization of derivative contracts	�	510		�	746		�
Amortization of deferred financing costs and other	�	313		�	290		�
Loss (gain) on settlement of asset retirement obligations	�	71		�	334		�
Changes in operating assets and liabilities:	�	�		�	�		�
Change in receivables	�	598		�	(3,317		)
Change in prepaid expenses	�	(1,515		)	(230		)
Change in derivative assets and liabilities	�	2,698		�	5,137		�
Change in amounts due to/from affiliates	�	(6,015		)	(4,270		)
Change in accrued liabilities and deferred tax liabilities	�	1,838		�	3,618		�
Net cash provided by (used in) operating activities	�	48,294		�	47,709		�
�	�	�		�	�		�
CASH FLOWS FROM INVESTING ACTIVITIES	�	�		�	�		�
Development of oil and natural gas properties	�	(25,840		)	(24,857		)
Disposition of oil and natural gas properties	�	50		�	�		�
Net cash provided by (used in) investing activities	�	(25,790		)	(24,857		)
�	�	�		�	�		�
CASH FLOWS FROM FINANCING ACTIVITIES	�	�		�	�		�
Borrowings under revolving credit facility	�	30,000		�	45,000		�
Principal payments on revolving credit facility	�	(30,000		)	(28,000		)
Equity offering, net of expenses	�	23,419		�	59,513		�
Distributions	�	(39,589		)	(36,125		)
Distribution to Lime Rock Resources	�	�		�	(60,672		)
Contribution to Lime Rock Resources	�	�		�	(734		)
Net cash provided by (used in) financing activities	�	(16,170		)	(21,018		)
�	�	�		�	�		�
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	�	6,334		�	1,834		�
�	�	�		�	�		�
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD	�	4,417		�	3,467		�
�	�	�		�	�		�
CASH AND CASH EQUIVALENTS, END OF PERIOD	�	$	10,751	�	$	5,301	�
�	�	�		�	�		�
Supplemental disclosure of non-cash items to reconcile investing and financing activities	�	�		�	�		�
Property and equipment:	�	�		�	�		�
Accrued capital costs	�	$	2,125	�	$	2,892	�
Asset retirement obligations	�	(235		)	(417		)

�

See accompanying notes to the unaudited consolidated condensed financial statements.

�

Table of Contents

�

LRR Energy, L.P.

Notes to Consolidated Condensed Financial Statements

(unaudited)

�

1.�� Organization and 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� refer collectively to LRR�A, LRR�B and LRR�C; references to �Fund II� refer collectively to Lime Rock Resources II-A, L.P. and Lime Rock Resources II-C, L.P.; and references to �Fund III� refer collectively to Lime Rock Resources III-A, L.P. and Lime Rock Resources III-C, L.P. References to �Lime Rock Resources� refer collectively to Fund I, Fund II and Fund III.

�

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. We conduct our operations through our wholly owned subsidiary, LRE Operating, LLC (�OLLC�).

�

We own 100% of LRE Finance Corporation (�LRE Finance�). LRE Finance was organized for the purpose of co-issuing our debt securities and has no material assets or liabilities other than as co-issuer of our debt securities, if and when issued. Its activities will be limited to co-issuing our debt securities and engaging in activities related thereto.

�

2.�� Summary of Significant Accounting Policies

�

Our accounting policies are set forth in the audited consolidated/combined financial statements in our Annual Report on Form�10-K for the year ended December�31, 2013 (�2013 Annual Report�) and are supplemented by the notes to these unaudited consolidated condensed financial statements. There have been no significant changes to these policies, and these unaudited consolidated condensed financial statements should be read in conjunction with the audited consolidated/combined financial statements and notes in our 2013 Annual Report.

�

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 consolidated financial statements and should be read in conjunction with the audited consolidated/combined financial statements in our 2013 Annual Report. While the year-end condensed 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 consolidated 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.

�

Certain reclassifications were made to the historical financial statements to conform to the 2014 presentation. The effects of the reclassification were not material to our unaudited interim consolidated condensed financial statements.

�

Recent accounting pronouncements

�

On May�28, 2014, the Financial Accounting Standards Board (�FASB�) issued Accounting Standards Update (�ASU�) 2014-09, �Revenue from Contracts with Customers.� ASU No.�2014-09 outlined a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance. The core principle of the revenue model is that an entity recognizes revenueto depict the transfer of promised goods or services to customers in an amount that reflects the consideration to

�

Table of Contents

�

which the entity expects to be entitled in exchange for those goods or services. ASU No.�2014-09 is effective for annual reporting periods beginning after December�15, 2016 and early adoption is not permitted. We are still evaluating the impact of our adoption of ASU No.�2014-09.

�

On August�27, 2014, the FASB issued ASU 2014-15, �Disclosure of Uncertainties about an Entity�s Ability to Continue as a Going Concern.� ASU No.�2014-15 provides guidance on determining when and how reporting entities must disclose going-concern uncertainties in their financial statements. The new standard requires management to perform interim and annual assessments of an entity�s financial statements (or within one year after the date on which the financial statements are available to be issued, when applicable). Further, an entity must provide certain disclosures if there is �substantial doubt about the entity�s ability to continue as a going concern.� ASU No.�2014-15 is effective for annual periods ending after December�15, 2016, and interim periods thereafter; early adoption is permitted. We do not expect the adoption of ASU No.�2014-15 to have a material impact on our financial statement disclosures.

�

3.�� Acquisitions

�

Acquisition between Entities under Common Control

�

On January�3, 2013, we completed an acquisition from Fund I of certain oil and natural gas properties located in the Mid-Continent region in Oklahoma for a purchase price of $21.0 million, subject to customary purchase price adjustments (the �January�2013 Acquisition�). In addition, as part of the January�2013 Acquisition, we acquired in the money commodity hedge contracts valued at approximately $1.7 million as of the closing of the January�2013 Acquisition. The January�2013 Acquisition was effective October�1, 2012. In June�2013, we paid $0.4 million in cash to Fund I related to post-closing adjustments to the purchase price. We funded the January�2013 Acquisition with borrowings under our revolving credit facility (Note 7).

�

The following table presents the net assets conveyed by Fund I to us in the January�2013 Acquisition (in thousands):

�

Property and equipment, net	�	$	23,998	�
Oil and natural gas commodity hedge contracts	�	1,742		�
Asset retirement obligations and other liabilities	�	(1,067		)
Net assets	�	$	24,673	�

�

On April�1, 2013, we completed an acquisition of certain oil and natural gas properties located in the Mid-Continent region in Oklahoma and crude oil hedges from Fund II for a purchase price of $38.2 million (the �April�2013 Acquisition�). As part of the April�2013 Acquisition, we acquired in the money crude oil hedges valued at approximately $0.4 million as of the closing of the April�2013 Acquisition. The April�2013 Acquisition was effective April�1, 2013. We funded the April�2013 Acquisition with proceeds from our equity offering (Note 10).

�

The following table presents the net assets conveyed by Fund II to us in the April�2013 Acquisition (in thousands):

�

Property and equipment, net	�	$	36,586	�
Oil and natural gas commodity hedge contracts	�	386		�
Asset retirement obligations and other liabilities	�	(990		)
Net assets	�	$	35,982	�

�

The net assets of the January�2013 Acquisition and April�2013 Acquisition were recorded using carryover book value of Fund I and Fund II, as the acquisitions were deemed transactions between entities under common control. Our historical financial statements were revised to include the results attributable to previous acquisitions from Fund I and Fund II as if we owned the properties for all periods presented in our consolidated condensed financial statements.

�

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�

4.�� Fair Value Measurements

�

Our financial instruments, including cash and cash equivalents and accounts receivable, are carried at cost, which approximates fair value due to the short-term maturity of these instruments. All such financial instruments are considered Level 1 instruments. The carrying value of our senior secured revolving credit facility and term loan, including the current portion, approximates fair value, as interest rates are variable based on prevailing market rates and are therefore considered Level 1 instruments. Our financial and non-financial assets and liabilities that are 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.

�

We utilize 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 our financial assets and liabilities that were accounted for at fair value on a recurring basis as of September�30, 2014 and December�31, 2013 (in thousands).

�

Level�1

�

Level�2

�

Level�3

�

Total

�

September�30, 2014

�

Assets:

�

Commodity derivative instruments

�

22,230

�

22,230

�

Liabilities:

�

Commodity derivative instruments

�

1,069

�

1,069

�

Interest rate derivative instruments

�

2,490

�

2,490

�

December�31, 2013

�

Assets:

�

Commodity derivative instruments

�

26,472

�

26,472

�

Liabilities:

�

Commodity derivative instruments

�

2,391

�

2,391

�

Interest rate derivative instruments

�

2,202

�

2,202

�

All fair values reflected in the table above and on the consolidated 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

�

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�

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.

�

5.�� Property and Equipment

�

Property and equipment is stated at cost less accumulated depletion, depreciation and impairment and consisted of the following (in thousands):

�

�	�	September�30,�2014		�	December�31,�2013		�
�	�	�		�	�		�
Oil and natural gas properties (successful efforts method)	�	$	902,988	�	$	875,126	�
Unproved properties	�	1,238		�	1,258		�
Other property and equipment	�	271		�	290		�
�	�	904,497		�	876,674		�
Accumulated depletion, depreciation and impairment	�	(457,732		)	(431,837		)
Total property and equipment, net	�	$	446,765	�	$	444,837	�

�

We recorded $8.7 million and $9.5 million of depletion and depreciation expense for the three months ended September�30, 2014 and 2013, respectively. We recorded $25.9 million and $29.8 million of depletion and depreciation expense for the nine months ended September�30, 2014 and 2013, respectively.

�

We perform an impairment analysis of our oil and natural gas properties on a quarterly basis due to the volatility in commodity prices. We did not record any impairment charges in the three or nine months ended September�30, 2014 or 2013. If future oil or natural gas prices or our reserves decline, the estimated undiscounted future cash flows for the oil and natural gas properties may not exceed the net capitalized costs for our 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 our asset retirement obligations as of and for the nine months ended September�30, 2014 (in thousands):

�

Beginning of period	�	$	36,326	�
Dispositions	�	(85		)
Liabilities incurred	�	235		�
Liabilities settled	�	(19		)
Accretion expense	�	1,532		�
End of period	�	37,989		�
Current portion of asset retirement obligations	�	(510		)
Asset retirement obligations�� non-current	�	$	37,479	�

�

7.�� Long-Term Debt

�

Credit Agreement

�

In July�2011, subject to consummation of our initial public offering, we, as guarantor, and our wholly owned subsidiary, OLLC, as borrower, entered into a five-year, $500.0 million senior secured revolving credit facility, as amended (the �Credit Agreement�), that matures in July�2016. The Credit Agreement is reserve-based and we are permitted to borrow under our credit facility an amount up to the borrowing base, which was $235.0 million as of September�30, 2014. Our borrowing base, which is primarily based on the estimated value of our oil, NGL, and natural gas properties and our commodity derivative contracts, is subject to redetermination semi-annually by our lenders at their sole discretion. As of September�30, 2014, we were in compliance with all covenants contained in the Credit Agreement. The Credit Agreement was amended in October�2014 (Note 14).

�

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�

Term Loan Agreement

�

On June�28, 2012, we, as parent guarantor, and our wholly owned subsidiary, OLLC, as borrower, entered into a Second Lien Credit Agreement (the �Term Loan Agreement�). The Term Loan Agreement provides for a $50.0 million senior secured second lien term loan to OLLC. OLLC borrowed $50.0 million under the Term Loan Agreement and used the borrowings to repay outstanding borrowings under the Credit Agreement. As of September�30, 2014, we were in compliance with all covenants contained in the Term Loan Agreement. The Term Loan Agreement was amended in October�2014 (Note 14).

�

The obligations under the Term Loan Agreement and the Credit Agreement are governed by an�Intercreditor Agreement with OLLC as borrower and the Partnership as parent guarantor, which (i)�provides that any liens on the assets and properties of OLLC, the Partnership or any of their subsidiaries securing the indebtedness under the Term Loan Agreement are subordinate to liens on the assets and properties of OLLC, the Partnership or any of their subsidiaries securing indebtedness under the�Credit Agreement and derivative contracts with lenders and their affiliates and (ii)�sets forth the respective rights, obligations and remedies of the lenders under the�Credit Agreement with respect to their first-priority liens and the lenders under the Term Loan Agreement with respect to their second-priority liens.

�

As of September�30, 2014, we had $250.0 million of outstanding debt and accrued interest was approximately $0.1 million. As of December�31, 2013, we had $250.0 million of outstanding debt and accrued interest was approximately $0.2 million.

�

Interest expense for the three months ended September�30, 2014 and 2013 was $2.6 million and $2.3 million, respectively. Interest expense for the nine months ended September�30, 2014 and 2013 was $7.7 million and $6.9 million, respectively. As of September�30, 2014 and December�31, 2013, our weighted average interest rate on our outstanding indebtedness was 4.18% and 3.88%, respectively. Please refer to Note 8 below for a discussion of our interest rate derivative contracts.

�

8.�� Derivatives

�

We are exposed to commodity price and interest rate risk and consider it prudent to periodically reduce our exposure to cash flow variability resulting from commodity price changes and interest rate fluctuations. Accordingly, we enter into derivative instruments to manage our 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.

�

Our open positions typically consist of contracts such as (i)�crude oil and natural gas financial collar contracts, (ii)�crude oil, natural gas liquids (�NGL�) and natural gas financial swaps, (iii)�crude oil and natural gas basis financial swaps, (iv)�crude oil and natural gas puts and (v)�interest rate swap agreements. Our derivative instruments are with the counterparties that are also lenders in our Credit Agreement.

�

Swaps and options are used to manage our exposure to commodity price risk and basis risk inherent in our 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, we exchange a stream of payments over time according to specified terms with another counterparty. Specifically for commodity price swap agreements, we agree to pay an adjustable or floating price tied to an agreed upon index for the commodity, either gas or oil, and in return receive a fixed price based on notional quantities. Under basis swap agreements, we agree to pay an adjustable or floating price tied to two agreed upon indices for gas and in return receive the differential between a floating index and fixed price based on notional quantities. A collar is a combination of a put purchased by us and a call option written by us. In a typical collar transaction, if the floating price based on a market index is below the floor price, we receive from the counterparty an amount equal to this difference multiplied by the specified volume, effectively a put option. If the

�

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�

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, we 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 our interest rate on amounts borrowed under the credit facility. The purpose of these instruments is to mitigate our existing exposure to unfavorable interest rate changes. Under interest rate swap agreements, we pay a fixed interest rate payment on a notional amount in exchange for receiving a floating amount based on LIBOR on the same notional amount.

�

We 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 consolidated condensed statements of operations. We record our derivative activities on a mark-to-market or fair value basis. Fair values are based on pricing models that consider various assumptions, including quoted forward prices for commodities, the time value of money and volatility, and are comparable to values obtained from counterparties. We present the fair value of derivative financial instruments on a net basis in the consolidated condensed balance sheets.

�

At September�30, 2014, we had the following open commodity derivative contracts:

�

Index

�

2014

�

2015

�

2016

�

2017

�

2018

�

Natural gas positions

�

Price swaps (MMBTUs)

�

NYMEX-HH

�

1,462,599

�

5,500,236

�

5,433,888

�

5,045,760

�

2,374,800

�

Weighted average price

�

5.61

�

5.72

�

4.29

�

4.61

�

4.28

�

Basis swaps (MMBTUs)

�

(1)

�

1,412,369

�

5,326,559

�

2,877,047

�

Weighted average price

�

(0.1534

)

(0.1661

)

(0.1115

)

�

Oil positions

�

Price swaps (BBLs)

�

NYMEX-WTI

�

204,595

�

757,321

�

610,131

�

266,574

�

65,280

�

Weighted average price

�

96.14

�

93.16

�

87.27

�

86.06

�

86.45

�

Basis swaps (BBLs)

�

Argus-

�

95,570

�

397,035

�

Weighted average price

�

Midland-Cushing

�

(1.0000

)

(3.4087

)

�

NGL positions

�

Price swaps (BBLs)

�

Mont Belvieu

�

66,569

�

236,149

�

Weighted average price

�

34.71

�

34.46

�

(1)�� Our natural gas basis swaps are traded on the following indices: Centerpoint East, Houston Ship Channel, WAHA and TEXOK.

�

At December�31, 2013, we had the following open commodity derivative contracts:

�

Index

�

2014

�

2015

�

2016

�

2017

�

Natural gas positions

�

Price swaps (MMBTUs)

�

NYMEX-HH

�

6,077,016

�

5,500,236

�

5,433,888

�

5,045,760

�

Weighted average price

�

5.53

�

5.72

�

4.29

�

4.61

�

Basis swaps (MMBTUs)

�

(1)

�

5,876,098

�

5,326,559

�

2,877,047

�

Weighted average price

�

(0.1521

)

(0.1661

)

(0.1115)

�

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�

Index

�

2014

�

2015

�

2016

�

2017

�

Oil positions

�

Price swaps (BBLs)

�

NYMEX-WTI

�

723,634

�

561,833

�

397,488

�

198,744

�

Weighted average price

�

95.76

�

93.16

�

86.02

�

85.75

�

Basis swaps (BBLs)

�

Argus-

�

410,400

�

Weighted average price

�

Midland-Cushing

�

(1.0000

)

�

NGL positions

�

Price swaps (BBLs)

�

Mont Belvieu

�

183,857

�

147,823

�

Weighted average price

�

34.11

�

34.50

�

(1)�� Our natural gas basis swaps are traded on the following indices: Centerpoint East, Houston Ship Channel, WAHA and TEXOK.

�

At September�30, 2014 and December�31, 2013, we had the following interest rate swap derivative contracts (in thousands):

�

�	�	�	�	Notional		�	�	�	�	�
Effective	�	Maturity	�	Amount		�	Average�%	�	Index	�
February�2012	�	February�2015	�	$	150,000	�	0.51750	%	LIBOR	�
February�2015	�	February�2017	�	75,000		�	1.72500	%	LIBOR	�
February�2015	�	February�2017	�	75,000		�	1.72750	%	LIBOR	�
June�2012	�	June�2015	�	70,000		�	0.52375	%	LIBOR	�
June�2015	�	June�2017	�	70,000		�	1.42750	%	LIBOR	�

�

Effect of Derivative Instruments � Balance Sheet

�

The fair value of our commodity and interest rate derivative instruments is included in the tables below (in thousands):

�

As�of�September�30,�2014

�

Current

�

Long-term

�

Current

�

Long-term

�

Assets

�

Assets

�

Liabilities

�

Liabilities

�

Interest rate

�

Swaps

�

1,781

�

791

�

Gross fair value

�

1,781

�

791

�

Netting arrangements

�

(82

)

�

(82

)

Net recorded fair value

�

1,781

�

709

�

Sale of natural gas production

�

Price swaps

�

9,310

�

5,283

�

Basis swaps

�

473

�

481

�

Sale of crude oil production

�

Price swaps

�

4,328

�

2,605

�

228

�

261

�

Basis swaps

�

875

�

Sale of NGLs

�

Price swaps

�

326

�

118

�

Gross fair value

�

14,839

�

8,005

�

841

�

842

�

Netting arrangements

�

(331

)

(283

)

(331

)

(283

)

Net recorded fair value

�

14,508

�

7,722

�

510

�

559

�

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�

As�of�December�31,�2013

�

Current

�

Long-term

�

Current

�

Long-term

�

Assets

�

Assets

�

Liabilities

�

Liabilities

�

Interest rate

�

Swaps

�

637

�

648

�

2,191

�

Gross fair value

�

637

�

648

�

2,191

�

Netting arrangements

�

(637

)

�

(637

)

Net recorded fair value

�

648

�

1,554

�

Sale of natural gas production

�

Price swaps

�

8,250

�

11,937

�

196

�

Basis swaps

�

211

�

317

�

Sale of crude oil production

�

Price swaps

�

1,564

�

5,042

�

1,519

�

331

�

Basis swaps

�

227

�

Sale of NGLs

�

Price swaps

�

106

�

662

�

153

�

Gross fair value

�

10,203

�

17,194

�

2,694

�

622

�

Netting arrangements

�

(477

)

(448

)

(477

)

(448

)

Net recorded fair value

�

9,726

�

16,746

�

2,217

�

174

�

Effect of Derivative Instruments � Statements of Operations

�

The net gain (loss) amounts and classification related to derivative instruments for the periods indicated are as follows (in thousands):

�

Three�Months�Ended�September�30,

�

Nine�Months�Ended�September�30,

�

2014

�

2013

�

2014

�

2013

�

Commodity derivatives (revenue)

�

19,771

�

(6,282

)

821

�

Interest rate derivatives (other income (expense), net)

�

492

�

(1,401

)

(930

)

1,371

�

Credit Risk

�

All of our 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. We monitor the creditworthiness of each of our counterparties and assess 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. We also have 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 us. Additionally, we consider ourselves to be of substantial credit quality and have the financial resources and willingness to meet our potential repayment obligations associated with the derivative transactions.

�

9.�� Related Parties

�

Ownership in Our General Partner by Lime Rock Management and its Affiliates

�

As of September�30, 2014, Lime Rock Management, an affiliate of Fund I, owned all of the Class�A member interests in our general partner, Fund I owned all of the Class�B member interests in our general partner and Fund II owned all of the Class�C member interests in our general partner. In addition, Fund I owned an aggregate of approximately 17.7% of our outstanding common units and all of our subordinated units, representing an approximate 31.0% limited partner interest in us. As of September�30, 2014, our general partner owned an approximate 0.1% general partner interest in us, represented by 22,400 general partner units, and all of our incentive distribution rights.

�

As more fully described in our 2013 Annual Report, three separate one-third tranches of the subordinated units

�

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�

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. We converted 2,240,000 subordinated units on a one-for-one basis into common units pursuant to the terms of our partnership agreement on May�16, 2014. We do not expect the second tranche of the subordinated units to convert pursuant to the provisions of our partnership agreement following our distribution for the third quarter of 2014 that will be paid on November�14, 2014. Each quarter, we will determine whether the test for conversion of the subordinated units has been met until the subordinated units convert pursuant to the provisions of our partnership agreement.

�

Contracts with our General Partner and its Affiliates

�

As more fully described in our 2013 Annual Report, we have entered into agreements with our general partner and its affiliates. For the three months ended September�30, 2014 and 2013, we paid Lime Rock Management approximately $0.5 million either directly or indirectly related to these agreements. For the nine months ended September�30, 2014 and 2013, we paid Lime Rock Management approximately $1.1 million and $1.0 million either directly or indirectly related to these agreements, respectively.

�

In connection with the management of our business, Lime Rock Resources Operating Company,�Inc. (�ServCo�), an affiliate of our general partner, provides services for invoicing and processing of payments to our vendors. Periodically, ServCo remits cash to us for the net working capital received on our behalf. Changes in the affiliates (payable)/receivable balances during the nine months ended September�30, 2014 are included below (in thousands):

�

�	�	�		�	Lime�Rock		�	�		�
�	�	ServCo		�	Resources		�	Total		�
�	�	�		�	�		�	�		�
Balance as of December�31, 2013	�	$	(518	)	$	263	�	$	(255	)
Expenditures	�	(76,677		)	�		�	(76,677		)
Cash paid for expenditures	�	98,911		�	�		�	98,911		�
Revenues and other	�	(16,217		)	(2		)	(16,219		)
Balance as of September�30, 2014	�	$	5,499	�	$	261	�	$	5,760	�

�

Distributions of Available Cash to Our General Partner and Affiliates

�

We will generally make cash distributions to our unitholders and our general partner pro rata. As of September�30, 2014, our general partner and its affiliates held 4,089,600 of our common units, all of our subordinated units and 22,400 general partner units. During the nine months ended September�30, 2014 and 2013, we paid cash distributions of $39.6 million and $36.1 million, respectively, to all unitholders as of the respective record dates.

�

We announced our third quarter 2014 distribution on October�17, 2014 as discussed in Note 14.

�

10.�� Unitholders� Equity

�

At-the-Market Offering Program

�

On February�4, 2014, we launched an �at-the-market� offering program (the �ATM Program�) with MLV�& Co. LLC (�MLV�) as sales agent. We may sell from time to time through MLV our common units representing limited partner interests having an aggregate offering amount of up to $75.0 million. Any sales of common units under the ATM Program may be made by any method permitted by law deemed to be an �at-the-market offering� defined by Rule�415 of the Securities Act, including, without limitation, sales made directly on the New York Stock Exchange, or any other existing trading market for our common units or to or through a market maker.

�

Our second lien term loan requires that 50% of the net cash proceeds from any equity offering be used to repay

�

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�

borrowings outstanding under the term loan. In October�2014, we entered into an amendment to our Term Loan to waive this requirement through March�31, 2015 (Note 14). During the nine months ended September�30, 2014, we received net proceeds from the sale of 1,375,239 newly issued common units of $23.4 million, after deducting underwriting discounts and commissions and offering expenses of approximately $0.7 million, and used the proceeds for general partnership purposes. During the nine months ended September�30, 2014, we paid approximately $0.5 million of aggregate compensation to MLV for sales under the ATM Program.

�

Equity Offering

�

On March�22, 2013, we closed a public equity offering of 3,700,000 common units representing limited partner interests in the Partnership at a price to the public of $16.84 per common unit, or $16.1664 per common unit after payment of the underwriting discount. We received net proceeds from the sale of 3,700,000 newly issued common units of $59.5 million, after deducting underwriting discounts and commissions and offering expenses of $0.3 million. We used the net proceeds of the offering to fund our April�2013 Acquisition discussed in Note 3 and repay borrowings outstanding on our Credit Agreement.

�

Fund I sold 3,200,000 common units in the equity offering at a price to the public of $16.84 per common unit, or $16.1664 per common unit after payment of the underwriting discount. We did not receive any proceeds from the sale of common units by Fund I; however, the equity balance of Fund I was adjusted for its reduced ownership interest in us.

�

Units Outstanding

�

As of September�30, 2014, we had 23,168,539 common units, 4,480,000 subordinated units and 22,400 general partner units outstanding. As of September�30, 2014, Fund I owned 4,089,600 common units and all of our subordinated units, representing an approximate 31.0% limited partner interest in us.

�

11.�� Net Income (Loss) Per Limited Partner Unit

�

The following sets forth the calculation of net income (loss) per limited partner unit for the following periods (in thousands, except per unit amounts):

�

Three�Months�Ended�September�30,

�

Nine�Months�Ended�September�30,

�

2014

�

2013

�

2014

�

2013

�

Net income (loss)

�

26,232

�

284

�

21,589

�

13,805

�

Net income (loss) attributable to common control operations

�

(448

)

Net income (loss) available to unitholders

�

26,232

�

284

�

21,589

�

13,357

�

Less: General partner�s interest in net (income) loss

�

(26

)

�

(22

)

(13

)

Limited partners� interest in net income (loss)

�

26,206

�

284

�

21,567

�

13,344

�

Weighted average limited partner units outstanding:

�

Common units

�

23,001

�

19,449

�

21,260

�

18,378

�

Subordinated units

�

4,480

�

6,720

�

5,596

�

6,720

�

Total

�

27,481

�

26,169

�

26,856

�

25,098

�

Net income (loss) per limited partner unit (basic and diluted)

�

0.95

�

0.01

�

0.80

�

0.53

�

Our subordinated units and restricted unit awards are considered to be participating securities for purposes of calculating our net income (loss) per limited partner unit, and accordingly, are included in basic computation as such. Net income (loss) per limited partner unit is determined by dividing the net income (loss) available to the common unitholders, after deducting our general partner�s approximate 0.1% interest in net income (loss), by the weighted average number of common units and subordinated units outstanding as of September�30, 2014 and 2013.

�

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�

The aggregate number of common units and subordinated units outstanding was 23,168,539 and 4,480,000, respectively, as of September�30, 2014. The aggregate number of common units and subordinated units outstanding was 19,448,539 and 6,720,000, respectively, as of September�30, 2013.

�

12.�� Equity-Based Compensation

�

On November�10, 2011, our General Partner adopted a long-term incentive plan (�2011 LTIP�) for employees, consultants and directors of our General Partner and its affiliates, including Lime Rock Management and ServCo, who perform services for us. The 2011 LTIP consists of unit options, restricted units, phantom units, unit appreciation rights, distribution equivalent rights, unit awards and other unit-based awards. The 2011 LTIP initially limits the number of units that may be delivered pursuant to vested awards to 1,500,000 common units. As of September�30, 2014, there were 1,304,300 units available for issuance under the 2011 LTIP. The 2011 LTIP is currently administered by our General Partner�s board of directors or a committee thereof.

�

The fair value of restricted units is determined based on the fair market value of the units on the date of grant. The outstanding restricted units vest in equal amounts (subject to rounding) over a three-year period following the date of grant and are entitled to receive quarterly distributions during the vesting period.

�

A summary of the status of the non-vested restricted units as of September�30, 2014, is presented below:

�

�	�	Number�of	�	Weighted�Average		�
�	�	Non-vested	�	Grant-Date		�
�	�	Restricted�Units	�	Fair�Value		�
Non-vested restricted units at December�31, 2013	�	165,265	�	$	16.73	�
Granted	�	7,057	�	17.71		�
Vested	�	(12,341	)	17.92		�
Forfeited	�	(13,691	)	16.54		�
Non-vested restricted units at September�30, 2014	�	146,290	�	16.69		�

�

As of September�30, 2014, there was approximately $1.6 million of unrecognized compensation cost related to non-vested restricted units. The cost is expected to be recognized over a weighted average period of approximately 2.0 years. There were 49,410 vested restricted units as of September�30, 2014.

�

13.�� Subsidiary Guarantors

�

We and LRE Finance, our 100 percent-owned subsidiary, filed a registration statement on Form�S-3 with the SEC on August�28, 2013, and the SEC declared the registration statement effective on September�10, 2013. Securities that may be offered and sold include debt securities that are to be offered on a delayed or continuous basis pursuant to Rule�415 under the Securities Act of 1933. LRE Finance may co-issue any debt securities issued by us pursuant to the registration statement. LRE Finance was formed solely for the purpose of co-issuing our debt securities and has no material assets or liabilities other than as co-issuer of our debt securities, if and when issued. OLLC, our 100 percent-owned subsidiary, may guarantee any debt securities issued by us and such guarantee will be full and unconditional, subject to customary release provisions. The guarantee will be released (i)�automatically upon any sale, exchange or transfer of our equity interests in OLLC, (ii)�automatically upon the liquidation and dissolution of OLLC, (iii)�following delivery of notice to the trustee under the indenture related to the debt securities of the release of OLLC of its obligations under our revolving credit facility, and (iv)�upon legal or covenant defeasance or other satisfaction of the obligations under the related debt securities. Other than LRE Finance, OLLC is our sole subsidiary, and thus, no other subsidiary will guarantee our debt securities.

�

Furthermore, we have no assets or operations independent of OLLC, and there are no significant restrictions upon the ability of OLLC to distribute funds to us by dividend or loan. Finally, none of our or OLLC�s assets represents restricted net assets pursuant to Rule�4-08(e)(3)�of Regulation S-X.

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�

14.�� Subsequent Events

�

Unit Distribution

�

On October�17, 2014, we announced that the board of directors of our general partner declared a cash distribution for the third quarter of 2014 of $0.4975 per outstanding unit, or $1.99 on an annualized basis. The distribution will be paid on November�14, 2014 to all unitholders of record as of the close of business on October�31, 2014. The aggregate amount of the distribution will be $13.8 million.

�

Commodity Hedges

�

Subsequent to September�30, 2014, we acquired the following commodity hedges:

�

�	�	Index	�	2017		�	2018		�
�	�	�	�	�		�	�		�
Oil positions	�	�	�	�		�	�		�
Price swaps (BBLs)	�	NYMEX-	�	118,286		�	497,242		�
Weighted average price	�	WTI	�	$	83.75	�	$	81.71	�

�

Stroud Field Acquisition

�

In August�2014, we entered into a definitive agreement to acquire oil and natural gas properties in the Stroud field located in Lincoln and Creek Counties, Oklahoma for a purchase price of $38.0 million, subject to customary purchase price adjustments. We financed the acquisition with borrowings under our Credit Agreement. The effective date of the transaction was September�1, 2014, and closing of the transaction occurred on October�1, 2014.

�

Amendments to Credit Agreement and Term Loan Agreement

�

On October�1, 2014, we entered into the Fourth Amendment (�Fourth Credit Agreement Amendment�) to the Credit Agreement. The Fourth Credit Agreement Amendment, among other things, (i)�reduced the interest rate margins applicable to the loans and other obligations thereunder, with margins ranging from 1.50% to 2.50% for eurodollar loans, and from 0.50% to 1.50% for base rate loans, in each case based on utilization of the credit facility, (ii)�extended the maturity date to October�1, 2019, (iii)�increased the maximum credit amount to $750,000,000, (iv)�increased the borrowing base to $260,000,000 and (v)�confirmed that, notwithstanding the increase to maximum credit amount, the obligations under Credit Agreement remain subject to a $500,000,000 first lien cap pursuant to the Intercreditor Agreement.

�

On October�1, 2014, we entered into the Fourth Amendment (�Fourth Term Loan Agreement Amendment�) to the Term Loan Agreement. The Fourth Term Loan Agreement Amendment, among other things, amended the Term Loan Agreement to exclude certain sales of common units representing limited partner interests in us made on and after October�1, 2014 and on and before March�31, 2015 from compliance with the mandatory prepayment provision under the Term Loan Agreement that requires us to use 50% of the net cash proceeds from any equity offering to repay borrowings outstanding under the Term Loan Agreement. The Fourth Term Loan Agreement Amendment also extended the maturity date of the Term Loan Agreement to April�1, 2020.

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Item 2.� Management�s Discussion and Analysis of Financial Condition and Results of Operations.

�

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, 2013 (�2013 Annual Report�) that 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 quarterly distributions 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 natural gas liquids (�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 and natural gas;

�� 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 in our credit facility and term loan;

�� 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

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�

�� 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.

�

Overview

�

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� refer collectively to LRR�A, LRR�B and LRR�C; references to �Fund II� refer collectively to Lime Rock Resources II-A, L.P. and Lime Rock Resources II-C, L.P; and references to �Fund III� refer collectively to Lime Rock Resources III-A, L.P. and Lime Rock Resources III-C, L.P. References to �Lime Rock Resources� refer collectively to Fund I, Fund II and Fund III.

�

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.

�

Contribution of Properties

�

On January�3, 2013, we completed an acquisition from Fund I of certain oil and natural gas properties located in the Mid-Continent region in Oklahoma for a purchase price of $21.0 million, subject to customary purchase price adjustments (the �January�2013 Acquisition�). In addition, as part of the January�2013 Acquisition, we acquired in the money commodity hedge contracts valued at approximately $1.7 million at the closing of the January�2013 Acquisition. The January�2013 Acquisition was effective October�1, 2012. In June�2013, we paid $0.4 million in cash to Fund I related to post-closing adjustments to the purchase price.

�

Results of Operations

�

Three�Months�Ended�September�30,

�

Nine�Months�Ended�September�30,

�

2014

�

2013

�

2014

�

2013

�

Revenues (in thousands):

�

Oil sales

�

19,258

�

22,239

�

59,768

�

56,714

�

Natural gas sales

�

6,542

�

6,564

�

22,206

�

20,364

�

Natural gas liquids sales

�

2,771

�

2,655

�

8,895

�

7,165

�

Gain (loss) on commodity derivative instruments, net

�

19,771

�

(6,282

)

821

�

Other income

�

111

�

106

�

Total revenues

�

48,382

�

25,195

�

91,801

�

84,354

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�

Three�Months�Ended�September�30,

�

Nine�Months�Ended�September�30,

�

2014

�

2013

�

2014

�

2013

�

Expenses (in thousands):

�

Lease operating expense

�

6,024

�

6,005

�

18,688

�

18,072

�

Production and ad valorem taxes

�

2,172

�

2,434

�

6,820

�

6,478

�

Depletion and depreciation

�

8,711

�

9,533

�

25,856

�

29,772

�

General and administrative expense

�

2,629

�

2,669

�

8,510

�

8,866

�

Interest expense

�

2,551

�

2,349

�

7,667

�

6,863

�

Loss (gain) on interest rate derivative instruments, net

�

(492

)

1,401

�

930

�

(1,371

)

Production:

�

Oil (MBbls)

�

219

�

216

�

653

�

614

�

Natural gas (MMcf)

�

1,609

�

1,849

�

4,897

�

5,500

�

NGLs (MBbls)

�

268

�

229

�

Total (MBoe)

�

580

�

608

�

1,737

�

1,760

�

Average net production (Boe/d)

�

6,304

�

6,609

�

6,363

�

6,447

�

Average sales price:

�

Oil (per Bbl):

�

Sales price

�

87.94

�

102.96

�

91.53

�

92.37

�

Effect of settled commodity derivative instruments

�

2.96

�

(9.76

)

(0.43

)

(2.92

)

Realized price

�

90.90

�

93.20

�

91.10

�

89.45

�

Natural gas (per Mcf):

�

Sales price

�

4.07

�

3.55

�

4.53

�

3.70

�

Effect of settled commodity derivative instruments

�

1.22

�

1.40

�

0.82

�

1.40

�

Realized price

�

5.29

�

4.95

�

5.35

�

5.10

�

NGLs (per Bbl):

�

Sales price

�

29.83

�

31.61

�

33.21

�

31.29

�

Effect of settled commodity derivative instruments

�

(0.22

)

3.83

�

(1.88

)

4.88

�

Realized price

�

29.61

�

35.44

�

31.33

�

36.17

�

Average unit cost per Boe:

�

Lease operating expenses

�

10.39

�

9.87

�

10.76

�

10.27

�

Production and ad valorem taxes

�

3.74

�

4.00

�

3.93

�

3.68

�

Depletion and depreciation

�

15.02

�

15.67

�

14.89

�

16.92

�

General and administrative expenses

�

4.53

�

4.39

�

4.90

�

5.04

�

Our Results for the Three Months Ended September�30, 2014 Compared to the Three Months Ended September�30, 2013

�

We recorded net income of $26.2 million for the three months ended September�30, 2014 compared to net income of $0.3 million during the three months ended September�30, 2013, primarily related to gains on commodity and interest rate derivative instruments and lower depletion and depreciation, offset by lower revenues from oil sales. 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 the three months ended September�30, 2013 and September�30, 2014 follows (in thousands):

�

Oil, natural gas and NGL revenues-prior period	�	$	31,458	�
Increase (decrease)	�	�		�
Price realization	�	�		�
Oil	�	(3,257		)
Natural gas	�	961		�
NGLs	�	(150		)
Sales volumes	�	�		�
Oil	�	264		�
Natural gas	�	(973		)
NGLs	�	268		�
Oil, natural gas and NGL revenues-current period	�	$	28,571	�

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Sales revenues decreased from $31.5 million for the three months ended September�30, 2013 to $28.6 million for the three months ended September�30, 2014, primarily due to lower oil price realizations and natural gas sales volumes offset by higher natural gas price realizations. Sales revenues for the three months ended September�30, 2014 consisted of oil sales of $19.3 million, natural gas sales of $6.5 million and NGL sales of $2.8 million. Sales revenues for the three months ended September�30, 2013 consisted of oil sales of $22.2 million, natural gas sales of $6.6 million and NGL sales of $2.7 million.

�

Our production volumes for the three months ended September�30, 2014 included 312 MBbls of oil and NGLs and 1,609 MMcf of natural gas, or 3,390 Bbl/d of oil and NGLs and 17,489 Mcf/d of natural gas. On an equivalent basis, production for the period was 580 MBoe, or 6,304 Boe/d. Our average net production for the three months ended September�30, 2014 was impacted by flaring at our Red Lake field of approximately 25 Boe/d. Due to flooding, production at our Corral Canyon field was negatively impacted by approximately 25 Boe/d during the three months ended September�30, 2014. Our production volumes for the three months ended September�30, 2013 included 300 MBbls of oil and NGLs and 1,849 MMcf of natural gas, or 3,261 Bbl/d of oil and NGLs and 20,098 Mcf/d of natural gas. On an equivalent basis, production for the period was 608 MBoe, or 6,609 Boe/d.

�

Our average sales price per Bbl for oil and NGLs for the three months ended September�30, 2014, excluding the effect of commodity derivative contracts, was $87.94 and $29.83, respectively. Our average sales price per Mcf of natural gas for the three months ended September�30, 2014, excluding the effect of commodity derivative contracts, was $4.07. Our average sales price per Bbl for oil and NGLs for the three months ended September�30, 2013, excluding the effect of commodity derivative contracts, was $102.96 and $31.61, respectively. Our average sales price per Mcf of natural gas for the three months ended September�30, 2013, excluding the effect of commodity derivative contracts, was $3.55.

�

Effects of Commodity Derivative Contracts.� Due to changes in oil and natural gas prices, we recorded a net gain on our commodity hedging program for the three months ended September�30, 2014 of $19.8 million, which was comprised of positive net cash settlements and amortization of approximately $2.6 million and positive fluctuations in the fair value of derivatives of approximately $17.2 million. For the three months ended September�30, 2013, we recorded a net loss from our commodity hedging program of $6.3 million, which was comprised of positive net cash settlements and amortization of approximately $0.8 million and declines in fair value of derivatives of approximately $7.1 million. Volatility in commodity prices had a significant impact on our gains and losses on commodity derivative contracts.

�

Lease Operating Expense.� Our lease operating expenses were $6.0 million, or $10.39 per Boe, for the three months ended September�30, 2014 compared to $6.0 million, or $9.87 per Boe, for the three months ended September�30, 2013.

�

Production and Ad Valorem Taxes.� Our production and ad valorem taxes were $2.2 million, or $3.74 per Boe, for the three months ended September�30, 2014 compared to $2.4 million, or $4.00 per Boe, for the three months ended September�30, 2013. Production taxes accounted for approximately $2.0 million and ad valorem taxes for approximately $0.1 million of the total taxes recorded during the three months ended September�30, 2014. Production taxes accounted for approximately $2.2 million and ad valorem taxes for approximately $0.2 million of the total taxes recorded during the three months ended September�30, 2013.

�

Depletion and Depreciation.� Our depletion and depreciation expense was $8.7 million, or $15.02 per Boe, for the three months ended September�30, 2014 compared to $9.5 million, or $15.67 per Boe, for the three months ended September�30, 2013. The decrease in depletion and depreciation expense and per Boe amounts was primarily related to lower property and equipment balances as of September�30, 2014.

�

Impairment of Oil and Natural Gas Properties.� We did not record an impairment charge in the three months ended September�30, 2014 and 2013. If future oil or natural gas prices or reserves decline, the estimated undiscounted future cash flows for our 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 October�31, 2014, the NYMEX-WTI oil spot price was $80.54 per Bbl and the NYMEX-Henry Hub natural gas spot price was $3.78 per MMBtu.

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General and Administrative Expenses.� Our general and administrative expenses were $2.6 million, or $4.53 per Boe, for the three months ended September�30, 2014 compared to $2.7 million, or $4.39 per Boe, for the three months ended September�30, 2013.

�

Interest Expense.� Our interest expense is comprised of interest on our credit facility and term loan and amortization of debt issuance costs. Interest expense was $2.6 million and $2.3 million for the three months ended September�30, 2014 and 2013, respectively.

�

Effects of Interest Rate Derivatives. Gain on interest rate derivative contracts, net, was $0.5 million for the three months ended September�30, 2014, including $0.2 million in negative cash settlements and $0.7 million in positive fluctuations in fair value of the derivatives. Loss on interest rate derivative contracts, net, was $1.4 million for the three months ended September�30, 2013, including $0.2 million in negative cash settlements and $1.2 million in declines in fair value of the derivatives.

�

Our Results for the Nine Months Ended September�30, 2014 Compared to the Nine Months Ended September�30, 2013

�

We recorded a net income of $21.6 million for the nine months ended September�30, 2014 compared to net income of $13.8 million during the nine months ended September�30, 2013, primarily related to increased revenues, gains on commodity derivative instruments, net, lower depletion and depreciation expense, offset by higher operating expenses and interest expense. 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 the nine months ended September�30, 2013 and September�30, 2014 follows (in thousands):

�

Oil, natural gas and NGL revenues-prior period	�	$	84,243	�
Increase (decrease)	�	�		�
Price realization	�	�		�
Oil	�	(516		)
Natural gas	�	4,569		�
NGLs	�	440		�
Sales volumes	�	�		�
Oil	�	3,570		�
Natural gas	�	(2,732		)
NGLs	�	1,295		�
Oil, natural gas and NGL revenues-current period	�	$	90,869	�

�

Sales revenues increased from $84.2 million for the nine months ended September�30, 2013 to $90.9 million for the nine months ended September�30, 2014, primarily due to higher natural gas price realizations and oil and NGL sales volumes offset by lower natural gas volumes. Sales revenues for the nine months ended September�30, 2014 consisted of oil sales of $59.8 million, natural gas sales of $22.2 million and NGL sales of $8.9 million. Sales revenues for the nine months ended September�30, 2013 consisted of oil sales of $56.7 million, natural gas sales of $20.3 million and NGL sales of $7.2 million.

�

Our production volumes for the nine months ended September�30, 2014 included 921 MBbls of oil and NGLs and 4,897 MMcf of natural gas, or 3,373 Bbl/d of oil and NGLs and 17,938 Mcf/d of natural gas. On an equivalent basis, production for the period was 1,737 MBoe, or 6,363 Boe/d. Our average net production for the nine months ended September�30, 2014 was impacted by flaring at our Red Lake field of approximately 40 Boe/d. Our production volumes for the nine months ended September�30, 2013 included 843 MBbls of oil and NGLs and 5,500 MMcf of natural gas, or 3,088 Bbl/d of oil and NGLs and 20,147 Mcf/d of natural gas. On an equivalent basis, production for the period was 1,760 MBoe, or 6,447 Boe/d. The increase in oil and NGL sales volumes was primarily driven by the continued drilling at our Red Lake field. Given our focus on drilling at the Red Lake field, the production at our natural gas properties has decreased due to the natural decline of the wells.

�

Our average sales price per Bbl for oil and NGLs for the nine months ended September�30, 2014, excluding the

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�

effect of commodity derivative contracts, was $91.53 and $33.21, respectively. Our average sales price per Mcf of natural gas for the nine months ended September�30, 2014, excluding the effect of commodity derivative contracts, was $4.53. Our average sales price per Bbl for oil and NGLs for the nine months ended September�30, 2013, excluding the effect of commodity derivative contracts, was $92.37 and $31.29, respectively. Our average sales price per Mcf of natural gas for the nine months ended September�30, 2013, excluding the effect of commodity derivative contracts, was $3.70.

�

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 nine months ended September�30, 2014 of $0.8 million, which was comprised of positive net cash settlements and amortization of approximately $3.2 million and declines in the fair value of derivatives of approximately $2.4 million. For the nine months ended September�30, 2013, we recorded a net gain from our commodity hedging program of less than $0.1 million, which was comprised of positive net cash settlements and amortization of approximately $7.1 million and declines in fair value of derivatives of approximately $7.0 million. Volatility in commodity prices had a significant impact on our gains and losses on commodity derivative contracts.

�

Lease Operating Expense.� Our lease operating expenses were $18.7 million, or $10.76 per Boe, for the nine months ended September�30, 2014 compared to $18.1 million, or $10.27 per Boe, for the nine months ended September�30, 2013.

�

Production and Ad Valorem Taxes.� Our production and ad valorem taxes were $6.8 million, or $3.93 per Boe, for the nine months ended September�30, 2014 compared to $6.5 million, or $3.68 per Boe, for the nine months ended September�30, 2013. Production taxes accounted for approximately $6.4 million and ad valorem taxes for $0.4 million of the total taxes recorded during the nine months ended September�30, 2014. Production taxes accounted for approximately $5.9 million and ad valorem taxes for $0.6 million of the total taxes recorded during the nine months ended September�30, 2013.

�

Depletion and Depreciation.� Our depletion and depreciation expense was $25.9 million, or $14.89 per Boe, for the nine months ended September�30, 2014 compared to $29.8 million, or $16.92 per Boe, for the nine months ended September�30, 2013. The decrease in depletion and depreciation expense and per Boe amounts was primarily related to lower property and equipment balances as of September�30, 2014.

�

Impairment of Oil and Natural Gas Properties.� We did not record an impairment charge in the nine months ended September�30, 2014 and 2013. If future oil or natural gas prices or reserves decline, the estimated undiscounted future cash flows for our 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 October�31, 2014, the NYMEX-WTI oil spot price was $80.54 per Bbl and the NYMEX-Henry Hub natural gas spot price was $3.78 per MMBtu.

�

General and Administrative Expenses.� Our general and administrative expenses were $8.5 million, or $4.90 per Boe, for the nine months ended September�30, 2014 compared to $8.9 million, or $5.04 per Boe, for the nine months ended September�30, 2013.

�

Interest Expense.� Our interest expense is comprised of interest on our credit facility and term loan and amortization of debt issuance costs. Interest expense was $7.7 million and $6.9 million for the nine months ended September�30, 2014 and 2013, respectively.

�

Effects of Interest Rate Derivatives. Loss on interest rate derivative contracts, net, was $0.9 million for the nine months ended September�30, 2014, including $0.6 million in negative cash settlements and $0.3 million in declines in fair value of the derivatives. Gain on interest rate derivative contracts, net, was $1.4 million for the nine months ended September�30, 2013, including $0.5 million in negative cash settlements and $1.9 million in positive fluctuations in fair value of the derivatives.

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�

Non-GAAP Financial Measures

�

Below we disclose the non-GAAP financial measures Adjusted EBITDA and Distributable Cash Flow for the periods presented and provide reconciliations of these items to net income (loss), our most directly comparable financial performance measure calculated and presented in accordance with GAAP. We define Adjusted EBITDA as net income (loss) plus or minus:

�

�� Income tax expense;

�� Interest expense-net, including loss (gain) on interest rate derivative instruments, net;

�� Depletion and depreciation;

�� Accretion of asset retirement obligations;

�� Amortization of equity awards;

�� Loss (gain) on settlement of asset retirement obligations;

�� Loss (gain) on commodity derivative instruments, net;

�� Commodity derivative instrument net cash settlements;

�� Impairment of oil and natural gas properties; and

�� Other non-recurring items that we deem appropriate.

�

Adjusted EBITDA is used as a supplemental financial measure by our management and by external users of our financial statements, such as investors, commercial banks, research analysts and others, to assess our financial performance as compared to that of other companies and partnerships in our industry, without regard to financing methods, capital structure or historical cost basis.

�

We define Distributable Cash Flow as Adjusted EBITDA less cash income tax expense, cash interest expense and estimated maintenance capital.

�

Distributable Cash Flow is a supplemental financial measure used by our management and by external users of our financial statements, such as investors, commercial banks, research analysts and others to compare basic cash flows generated by us (prior to the establishment of any retained cash reserve by our general partner) to the cash distributions we expect to pay our unitholders. Distributable Cash Flow is also an important financial measure for our unitholders as it serves as an indicator of our success in providing a cash return on investment. Specifically, distributable cash flow indicates to investors whether or not we are generating cash flow at a level that can sustain or support an increase in our quarterly distribution rates. Distributable Cash Flow is a quantitative standard used throughout the investment community with respect to publicly-traded partnerships and limited liability companies because the yield is based on the amount of cash distributions the entity pays to a unitholder compared to the unit price.

�

Our management believes that both Adjusted EBITDA and Distributable Cash Flow are useful to investors because these measures are used by many partnerships in the industry as measures of operating and financial performance and are commonly employed by financial analysts and others to evaluate the operating and financial performance from period to period and to compare it with the performance of other publicly traded partnerships within the industry. Adjusted EBITDA and Distributable Cash Flow should not be considered alternatives to net income (loss), operating income (loss), or any other measures of financial performance presented in accordance with GAAP. Our Adjusted EBITDA and Distributable Cash Flow may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA and Distributable Cash Flow in the same manner.

�

Our Adjusted EBITDA for the three months ended September�30, 2014 and 2013 was $20.8 million and $21.5 million, respectively. The decrease was primarily driven by lower revenues. Our Adjusted EBITDA for the nine months ended September�30, 2014 and 2013 was $61.5 million and $59.1 million, respectively. The increase was primarily driven by higher revenues.

�

Our Distributable Cash Flow for the three months ended September�30, 2014 and 2013 was $13.1 million and $14.0 million, respectively. The decrease in Distributable Cash Flow was driven by the decreased Adjusted EBITDA as discussed above and increased cash interest expense. Our Distributable Cash Flow for the nine months ended September�30, 2014 and 2013 was $38.3 million and $36.7 million, respectively. The increase in Distributable Cash Flow was driven by the increased Adjusted EBITDA as discussed above offset by increased cash interest expense.

�

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�

Reconciliation of Adjusted EBITDA and Distributable Cash Flow to Net Income (Loss)

�

The following table presents a reconciliation of Adjusted EBITDA and Distributable Cash Flow to net income (loss), our most directly comparable GAAP financial performance measure, for each of the periods indicated.

�

�	�	Three�Months�Ended�September�30,					�	Nine�Months�Ended�September�30,					�
(in thousands)	�	2014		�	2013		�	2014		�	2013		�
Net income (loss)	�	$	26,232	�	$	284	�	$	21,589	�	$	13,805	�
Income tax expense	�	26		�	35		�	138		�	102		�
Interest expense-net, including loss (gain) on interest rate derivative instruments, net	�	2,059		�	3,750		�	8,597		�	5,492		�
Depletion and depreciation	�	8,711		�	9,533		�	25,856		�	29,772		�
Accretion of asset retirement obligations	�	519		�	486		�	1,532		�	1,433		�
Amortization of equity awards	�	285		�	138		�	819		�	391		�
Loss (gain) on settlement of asset retirement obligations	�	10		�	(1		)	71		�	334		�
Loss (gain) on commodity derivative instruments, net	�	(19,771		)	6,282		�	(821		)	(5		)
Commodity derivative instrument net cash settlements	�	2,774		�	1,039		�	3,741		�	7,795		�
Impairment of oil and natural gas properties	�	�		�	�		�	�		�	�		�
Adjusted EBITDA	�	$	20,845	�	$	21,546	�	$	61,522	�	$	59,119	�
�	�	�		�	�		�	�		�	�		�
Adjusted EBITDA	�	20,845		�	21,546		�	61,522		�	59,119		�
Income tax expense	�	(9		)	(35		)	(97		)	(108		)
Cash interest expense	�	(2,717		)	(2,438		)	(8,118		)	(7,054		)
Estimated maintenance capital (1)	�	(5,000		)	(5,075		)	(15,000		)	(15,225		)
Distributable cash flow	�	$	13,119	�	$	13,998	�	$	38,307	�	$	36,732	�

�

(1)�� Amount represents pro-rated capital for the period. Estimated maintenance capital expenditures as defined by our partnership agreement represent our estimate of the amount of capital required on average per year to maintain our production over the long term.

�

Liquidity and Capital Resources

�

Our ability to finance our operations, including funding capital expenditures and acquisitions, to meet our indebtedness obligations, to refinance our indebtedness or to meet our collateral requirements depends on our ability to generate cash. Our ability to generate cash is subject to a number of factors, some of which are beyond our control, including commodity prices, particularly for oil and natural gas, weather and our ongoing efforts to manage operating costs and maintenance capital expenditures, as well as general economic, financial, competitive, legislative, regulatory and other factors.

�

Our primary sources of liquidity and capital resources are cash flows generated by operating activities and borrowings under our credit facility and term loan and equity offerings under our recently established �at-the-market� offering program (the �ATM Program�), described below. We may issue additional equity and debt as needed.

�

On February�4, 2014, we launched the ATM Program with MLV�& Co. LLC (�MLV�) as sales agent. We may sell from time to time through MLV our common units representing limited partner interests having an aggregate offering amount of up to $75.0 million. Any sales of common units under the ATM Program may be made by any method permitted by law deemed to be an �at-the-market offering� defined by Rule�415 of the Securities Act, including, without limitation, sales made directly on the New York Stock Exchange, on any other existing trading market for our common units or to or through a market maker. During the nine months ended September�30, 2014, we received net proceeds from the sale of 1,375,239 newly issued common units of $23.4 million, after deducting underwriting discounts and commissions and offering expenses of $0.7 million, and used the proceeds for general partnership purposes. During the nine months ended September�30, 2014, we paid approximately $0.5 million of aggregate compensation to MLV for sales under the ATM Program.

�

Table of Contents

�

Our second lien term loan requires that 50% of the net cash proceeds from any equity offering be used to repay borrowings outstanding under the term loan. In October�2014, we entered into an amendment to our term loan to waive this requirement for certain sales of common units through March�31, 2015.

�

We enter into hedging arrangements to reduce the impact of commodity price volatility on our cash flow from operations. Under this strategy, we 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 our general partner. In making cash distributions, our general partner attempts to avoid large variations in the amount we distribute from quarter to quarter. In order to facilitate this, our partnership agreement permits 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 intend to make cash distributions to our unitholders and our general partner at least at the minimum quarterly distribution rate of $0.4750 per unit per quarter ($1.90 per unit on an annualized basis). Based on the number of common units, subordinated units and general partner units outstanding as of October�31, 2014, quarterly distributions to all of our unitholders at our current quarterly distribution rate would total $13.8 million.

�

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, a significant portion of our production is hedged. We are generally 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 generally do not 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 are 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 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 are committed to reinvesting a sufficient amount of our cash flow to fund our exploitation and development capital expenditures in order to maintain our production, and we intend to use primarily external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, 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 or term loan, issuances of debt and equity securities or from other sources, such as asset sales. Our ability to raise funds through the incurrence of additional indebtedness could be limited by the covenants in our credit facility and term loan. 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.

�

Based upon current oil and natural gas price expectations and our commodity derivatives positions at September�30, 2014, which cover 74% of our estimated production from total proved developed producing reserves, we anticipate that our cash on hand, cash flow from operations, proceeds from our ATM Program and available borrowing capacity under our revolving credit facility will provide us sufficient working capital to fund our total planned 2014 capital expenditures and annualized cash distributions as described above.

�

Table of Contents

�

We expect to spend $35.0 million in total capital expenditures in 2014, of which $20.3 million represents maintenance capital expenditures on the development of our existing oil and natural gas properties.

�

We intend to pursue acquisitions of long-lived, low-risk producing oil and natural gas properties with reserve exploitation potential. We would expect to finance any significant acquisition of oil and natural gas properties in 2014 through external financing sources, including borrowings under our revolving credit facility and the issuance of debt and equity securities, including through our ATM Program.

�

Credit Agreement

�

In July�2011, subject to consummation of our initial public offering, we, as guarantor, and our wholly owned subsidiary, LRE Operating, LLC (�OLLC�), as borrower, entered into a five-year, $500.0 million senior secured revolving credit facility, as amended (the �Credit Agreement�), that matures in July�2016. The Credit Agreement is reserve-based and we are permitted to borrow under our credit facility an amount up to the borrowing base, which was $235.0 million as of September�30, 2014. Our borrowing base, which is primarily based on the estimated value of our oil and natural gas properties and our commodity derivative contracts, is subject to redetermination semi-annually by our lenders and once during the interim periods at their sole discretion.

�

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 Credit Agreement. 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 Agreement after giving effect to such distribution.

�

If we fail to perform our obligations under the covenants described in our 2013 Annual Report, the revolving credit commitments could be terminated and any outstanding indebtedness under the Credit Agreement, together with accrued interest, could be declared immediately due and payable. As of September�30, 2014, we were in compliance with our covenants contained in the Credit Agreement.

�

At September�30, 2014, we had $200.0 million of outstanding borrowings under our Credit Agreement and available borrowing capacity of $35.0 million. As of October�30, 2014, we had approximately $233.0 million of outstanding borrowings under our Credit Agreement and available borrowing capacity of approximately $27.0 million.

�

Term Loan Agreement

�

The Term Loan Agreement contains various covenants and restrictive provisions as described in our 2013 Annual Report. As of September�30, 2014, we were in compliance with all covenants contained in the Term Loan Agreement.

�

Table of Contents

�

On October�1, 2014, we entered into the Fourth Amendment (�Fourth Term Loan Agreement Amendment�) to the Term Loan Agreement. The Fourth Term Loan Agreement Amendment, among other things, amended the Term Loan Agreement to exclude certain sales of common units representing limited partner interests in us made on and after October�1, 2014 and on and before March�31, 2015 from compliance with the mandatory prepayment provision under the Term Loan Agreement that requires us to use 50% of the net cash proceeds from any equity offering to repay borrowings outstanding under the Term Loan Agreement.� The Fourth Term Loan Agreement Amendment also extended the maturity date of the Term Loan Agreement to April�1, 2020.

�

At September�30, 2014, we had $50.0 million of outstanding borrowings under our Term Loan Agreement and no available borrowing capacity.

�

Commodity Derivative Contracts

�

The following table summarizes, for the periods presented, the weighted average price and notional volumes of our oil, NGL and natural gas swaps and collars in place as of September�30, 2014. 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. We use swaps and collars as a mechanism for managing commodity price risks whereby we pay the counterparty floating prices and receive fixed prices from the counterparty. By entering into the hedge agreements, we mitigate the effect on our cash flows of changes in the prices we receive for our oil, NGL and natural gas production.

�

Oil

�

NGL

�

Natural�Gas

�

(NYMEX-WTI)

�

(Mount�Belvieu)

�

(NYMEX-Henry�Hub)

�

Weighted�Average

�

Weighted�Average

�

Weighted�Average

�

Term

�

$/Bbl

�

Bbls/d

�

$/Bbl

�

Bbls/d

�

$/Mmbtu

�

Mmbtu/d

�

2014

�

96.14

�

2,224

�

34.71

�

724

�

5.61

�

15,898

�

2015

�

93.16

�

2,075

�

34.46

�

647

�

5.72

�

15,069

�

2016

�

87.27

�

1,672

�

4.29

�

14,887

�

2017

�

86.06

�

730

�

4.61

�

13,824

�

2018

�

86.45

�

179

�

4.28

�

6,506

�

The following table summarizes, for the periods presented, our natural gas basis swaps in place as of September�30, 2014. These contracts are designed to effectively fix a price differential between the NYMEX-Henry Hub price and the index price at which the physical natural gas is sold.

�

�	�	Centerpoint�East				�	Houston�Ship�Channel				�	WAHA				�	TEXOK				�
Term	�	$/Mmbtu		�	Mmbtu/d	�	$/Mmbtu		�	Mmbtu/d	�	$/Mmbtu		�	Mmbtu/d	�	$/Mmbtu		�	Mmbtu/d	�
�	�	�		�	�	�	�		�	�	�	�		�	�	�	�		�	�	�
2014	�	$	(0.2137	)	6,202	�	$	(0.0841	)	3,260	�	$	(0.1292	)	5,008	�	$	(0.1233	)	883	�
2015	�	$	(0.2291	)	5,939	�	$	(0.0959	)	3,031	�	$	(0.1380	)	4,777	�	$	(0.1334	)	846	�
2016	�	$	�	�	�	�	$	(0.0810	)	2,691	�	$	(0.1326	)	4,408	�	$	(0.0975	)	784	�

�

The following table summarizes, for the periods presented, our oil basis swaps in place as of September�30, 2014. These contracts are designed to effectively fix a price differential between the NYMEX-WTI price and the index price at which the physical oil is sold.

�

�	�	Argus�� Midland-Cushing				�
Term	�	$/Bbl		�	Bbl/d	�
�	�	�		�	�	�
2014	�	$	(1.00	)	1,039	�
2015	�	$	(3.41	)	1,088	�

�

Table of Contents

�

Cash Flows

�

Cash flows provided by (used in) operating, investing and financing activities were as follows for the periods indicated (in thousands):

�

�	�	Nine�Months�Ended�September�30,					�
�	�	2014		�	2013		�
�	�	�		�	�		�
Net cash provided by (used in):	�	�		�	�		�
Operating activities	�	$	48,294	�	$	47,709	�
Investing activities	�	(25,790		)	(24,857		)
Financing activities	�	(16,170		)	(21,018		)

�

Operating Activities.

�

Net cash provided by operating activities was $48.3 million and $47.7 million for the nine months ended September�30, 2014 and 2013, respectively. Revenues fluctuate due to the volatility of commodity prices, and therefore our cash provided by operating activities is impacted by the prices received for oil and natural gas sales, as well as levels of production volumes and operating expenses.

�

Our working capital totaled $31.7 million and $17.1 million at September�30, 2014 and December�31, 2013, respectively. Our collection of receivables has historically been timely, and losses associated with uncollectible receivables have historically not been significant. Our cash balances totaled $10.8 million and $4.4 million at September�30, 2014 and December�31, 2013, respectively.

�

Investing Activities.

�

Net cash used in investing activities was $25.8 million and $24.9 million for the nine months ended September�30, 2014 and 2013, respectively, which primarily represented additions to our property and equipment balances during the periods.

�

Financing Activities.

�

Cash flows used in financing activities was $16.2 million for the nine months ended September�30, 2014, and consisted of net proceeds received from an equity offering of $23.4 million offset by distributions to unitholders of $39.6 million.

�

Cash flows used in financing activities was approximately $21.0 million for the nine months ended September�30, 2013, which consisted of net proceeds from the March�2013 equity offering of $59.5 million and net borrowings of $17.0 million offset by distributions paid to our unitholders of $36.1 million and contributions and distributions to Lime Rock Resources of $61.4 million.

�

Off-Balance Sheet Arrangements

�

As of September�30, 2014, we had no off-balance sheet arrangements.

�

Critical Accounting Policies and Estimates

�

There have been no material changes to our critical accounting policies from those described in our 2013 Annual Report.

�

Recently Issued Accounting Pronouncements

�

Refer to Note 2 of the consolidated condensed financial statements.

�

Item 3.� Quantitative and Qualitative Disclosures About Market Risk.

�

There have been no material changes to the commodity price risk, interest rate risk and counterparty and customer credit risk discussed in our 2013 Annual Report under the caption �Management�s Discussion and

�

Table of Contents

�

Analysis of Financial Condition and Results of Operations�Quantitative and Qualitative Disclosure About Market Risk.�

�

Item 4.� Controls and Procedures.

�

Evaluation of Disclosure Controls and Procedures

�

As required by Rule�13a-15(b)�of the Securities Exchange Act, as amended (the �Exchange Act�), we have evaluated, under the supervision and with the participation of our management, including our principal executive officers and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules�13a-15(e)�and 15d-15(e)�under the Exchange Act) as of the end of the period covered by this report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officers and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules�and forms of the SEC. Our principal executive officers and principal financial officer, with the participation of management, have concluded that our disclosure controls and procedures were effective at the reasonable assurance level as of September�30, 2014.

�

Changes in Internal Control over Financial Reporting

�

There were no changes in our internal control over financial reporting during the quarter ended September�30, 2014 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

�

PART�II�OTHER INFORMATION

�

Item 1.� Legal Proceedings.

�

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 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 contemplated to be brought against us or our general partner, under the various environmental protection statues to which we or our general partner is subject.

�

Item 1A.� Risk Factors.

�

There have been no material changes to the risk factors described in our 2013 Annual Report.

�

Item 2.� Unregistered Sales of Equity Securities and Use of Proceeds.

�

None.

�

Item 3.� Defaults Upon Senior Securities.

�

None.

�

Item 4.� Mine Safety Disclosures.

�

Not applicable.

�

Item 5.� Other Information.

�

None.

�

Table of Contents

�

Item 6.� Exhibits.

�

Exhibit�Number	�	Description
�	�	�
3.1	�	Certificate of Limited Partnership of LRR Energy, L.P. dated as of April�28, 2011 (incorporated by reference to Exhibit�3.1 to the Partnership�s Registration Statement on Form�S-1 (SEC File No.�333-174017), filed on May�6, 2011).
�	�	�
3.2	�	First Amended and Restated Agreement of Limited Partnership of LRR Energy, L.P. dated as of November�16, 2011 (incorporated by reference to Exhibit�3.2 to the Partnership�s Annual Report on Form�10-K (SEC File No.�001-35344), filed on March�27, 2012).
�	�	�
3.3	�	Certificate of Formation of LRE GP, LLC dated as of April�28, 2011 (incorporated by reference to Exhibit�3.4 to the Partnership�s Registration Statement on Form�S-1 (SEC File No.�333-174017), filed on May�6, 2011).
�	�	�
3.4	�	Amended and Restated Limited Liability Company Agreement of LRE GP, LLC dated as of November�16, 2011 (incorporated by reference to Exhibit�3.2 to the Partnership�s Current Report on Form�8-K (SEC File No.�001-35344), filed on November�22, 2011).
�	�	�
31.1*	�	Certification by Co-Chief Executive Officer pursuant to Rule�13a-14(a)�and 15d-14(a)�under the Securities Exchange Act of 1934.
�	�	�
31.2*	�	Certification by Co-Chief Executive Officer pursuant to Rule�13a-14(a)�and 15d-14(a)�under the Securities Exchange Act of 1934.
�	�	�
31.3*	�	Certification by Chief Financial Officer pursuant to Rule�13a-14(a)�and 15d-14(a)�under the Securities Exchange Act of 1934.
�	�	�
32.1*	�	Certification by Co-Chief Executive Officers and Chief Financial Officer pursuant to 18 U.S.C. Section�1350, as adopted pursuant to Section�906 of the Sarbanes-Oxley Act of 2002.
�	�	�
101.INS**	�	XBRL Instance Document.
�	�	�
101.SCH**	�	XBRL Taxonomy Extension Schema Document.
�	�	�
101.CAL**	�	XBRL Taxonomy Extension Calculation Linkbase Document.
�	�	�
101.DEF**	�	XBRL Taxonomy Extension Definition Linkbase Document.
�	�	�
101.LAB**	�	XBRL Taxonomy Extension Label Linkbase Document.
�	�	�
101.PRE**	�	XBRL Taxonomy Extension Presentation Linkbase Document.

�

*�� Filed herewith

**�� Submitted electronically herewith

�

Table of Contents

�

SIGNATURES

�

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

�

�	LRR Energy, L.P.
�	�
�	By:	LRE GP, LLC,
�	�	its General Partner
�	�
Date: November�5, 2014	By:	/s/ Eric Mullins
�	�	Eric Mullins
�	�	Co-Chief Executive Officer
�	�
Date: November�5, 2014	�
�	�
�	By:	/s/ Jaime R. Casas
�	�	Jaime R. Casas
�	�	Vice President, Chief Financial Officer and Secretary
�	�	(Principal Financial Officer)

�

Table of Contents

�

EXHIBIT�INDEX

�

Exhibit�Number	�	Description
�	�	�
3.1	�	Certificate of Limited Partnership of LRR Energy, L.P. dated as of April�28, 2011 (incorporated by reference to Exhibit�3.1 to the Partnership�s Registration Statement on Form�S-1 (SEC File No.�333-174017), filed on May�6, 2011).
�	�	�
3.2	�	First Amended and Restated Agreement of Limited Partnership of LRR Energy, L.P. dated as of November�16, 2011 (incorporated by reference to Exhibit�3.2 to the Partnership�s Annual Report on Form�10-K (SEC File No.�001-35344), filed on March�27, 2012).
�	�	�
3.3	�	Certificate of Formation of LRE GP, LLC dated as of April�28, 2011 (incorporated by reference to Exhibit�3.4 to the Partnership�s Registration Statement on Form�S-1 (SEC File No.�333-174017), filed on May�6, 2011).
�	�	�
3.4	�	Amended and Restated Limited Liability Company Agreement of LRE GP, LLC dated as of November�16, 2011 (incorporated by reference to Exhibit�3.2 to the Partnership�s Current Report on Form�8-K (SEC File No.�001-35344), filed on November�22, 2011).
�	�	�
31.1*	�	Certification by Co-Chief Executive Officer pursuant to Rule�13a-14(a)�and 15d-14(a)�under the Securities Exchange Act of 1934.
�	�	�
31.2*	�	Certification by Co-Chief Executive Officer pursuant to Rule�13a-14(a)�and 15d-14(a)�under the Securities Exchange Act of 1934.
�	�	�
31.3*	�	Certification by Chief Financial Officer pursuant to Rule�13a-14(a)�and 15d-14(a)�under the Securities Exchange Act of 1934.
�	�	�
32.1*	�	Certification by Co-Chief Executive Officers and Chief Financial Officer pursuant to 18 U.S.C. Section�1350, as adopted pursuant to Section�906 of the Sarbanes-Oxley Act of 2002.
�	�	�
101.INS**	�	XBRL Instance Document.
�	�	�
101.SCH**	�	XBRL Taxonomy Extension Schema Document.
�	�	�
101.CAL**	�	XBRL Taxonomy Extension Calculation Linkbase Document.
�	�	�
101.DEF**	�	XBRL Taxonomy Extension Definition Linkbase Document.
�	�	�
101.LAB**	�	XBRL Taxonomy Extension Label Linkbase Document.
�	�	�
101.PRE**	�	XBRL Taxonomy Extension Presentation Linkbase Document.

�

*�� Filed herewith

**�� Submitted electronically herewith

�

EXHIBIT�31.1

�

CERTIFICATION OF CO-CHIEF EXECUTIVE OFFICER

PURSUANT TO RULE 13A-14(A)�AND RULE 15D-14(A)

OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

�

I, Eric Mullins, certify that:

�

1.�� I have reviewed this quarterly report on Form�10-Q of LRR Energy, L.P.;

�

2.�� Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

�

3.�� Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

�

4.�� The registrant�s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules�13a-15(e)�and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules�13a-15(f)�and 15d-15(f)) for the registrant and have:

�

a)�� Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

�

b)�� Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

�

c)�� Evaluated the effectiveness of the registrant�s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

�

d)�� Disclosed in this report any change in the registrant�s internal control over financial reporting that occurred during the registrant�s most recent fiscal quarter (the registrant�s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant�s internal control over financial reporting; and

�

5.�� The registrant�s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant�s auditors and the audit committee of the registrant�s board of directors (or persons performing the equivalent functions):

�

a)�� All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant�s ability to record, process, summarize and report financial information; and

�

b)�� Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant�s internal control over financial reporting.

�

Date:�� November�5, 2014

�

�	�	/s/ Eric Mullins
�	Name:	Eric Mullins
�	Title:	Co-Chief Executive Officer of LRE GP, LLC, the
�	�	general partner of LRR Energy, L.P.

�

EXHIBIT�31.2

�

CERTIFICATION OF CO-CHIEF EXECUTIVE OFFICER

PURSUANT TO RULE 13A-14(A)�AND RULE 15D-14(A)

OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

�

I, Charles W. Adcock, certify that:

�

1.�� I have reviewed this quarterly report on Form�10-Q of LRR Energy, L.P.;

�

b)�� Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant�s internal control over financial reporting.

�

Date:�� November�5, 2014

�

�	�	/s/ Charles W. Adcock
�	Name:	Charles W. Adcock
�	Title:	Co-Chief Executive Officer of LRE GP, LLC, the
�	�	general partner of LRR Energy, L.P.

�

EXHIBIT�31.3

�

CERTIFICATION OF CHIEF FINANCIAL OFFICER

PURSUANT TO RULE 13A-14(A)�AND RULE 15D-14(A)

OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

�

I, Jaime R. Casas, certify that:

�

1.�� I have reviewed this quarterly report on Form�10-Q of LRR Energy, L.P.;

�

b)�� Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant�s internal control over financial reporting.

�

Date:�� November�5, 2014

�

�	�	/s/ Jaime R. Casas
�	Name:	Jaime R. Casas
�	Title:	Chief Financial Officer of LRE GP, LLC, the general
�	�	partner of LRR Energy, L.P.

�

EXHIBIT�32.1

�

SARBANES-OXLEY SECTION�906 CERTIFICATION

OF CO-CHIEF EXECUTIVE OFFICERS AND CHIEF FINANCIAL OFFICER

OF LRE GP, LLC, THE GENERAL PARTNER OF LRR ENERGY, L.P.

�

In connection with the Quarterly Report of LRR Energy, L.P. (the �Partnership�) on Form�10-Q for the quarter ended September�30, 2014, as filed with the Securities and Exchange Commission on the date hereof (the �Report�), each of the undersigned hereby certifies, in his capacity as an officer of LRE GP, LLC, the general partner of the Partnership (the �Company�), pursuant to 18 U.S.C. Section�1350, as adopted pursuant to Section�906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge:

�

(1)�� The Report fully complies with the requirements of Section�13(a)�or 15(d)�of the Securities Exchange Act of 1934; and

�

(2)�� The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

�

Date:�� November�5, 2014

�

�	/s/ Eric Mullins
�	Name:	Eric Mullins
�	Title:	Co-Chief Executive Officer of LRE GP, LLC,
�	�	the general partner of LRR Energy, L.P.
�	�	�
�	�	�
�	/s/ Charles W. Adcock
�	Name:	Charles W. Adcock
�	Title:	Co-Chief Executive Officer of LRE GP, LLC,
�	�	the general partner of LRR Energy, L.P.
�	�	�
�	�	�
�	/s/ Jaime R. Casas
�	Name:	Jaime R. Casas
�	Title:	Chief Financial Officer of LRE GP, LLC,
�	�	the general partner of LRR Energy, L.P.

�

A signed original of this written statement required by Section�906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

�

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Form 10-Q LRR Energy, L.P. For: Sep 30

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