LRR Energy 10-Q 4 Aug 15 2015 Q2 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2015	Jul. 31, 2015
Entity Registrant Name	LRR Energy, L.P.
Entity Central Index Key	1,519,632
Document Type	10-Q
Document Period End Date	Jun. 30, 2015
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Accelerated Filer
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	Q2
Common Units
Entity Common Stock, Shares Outstanding		28,074,433
General Partner Units
Entity Common Stock, Shares Outstanding		22,400

Balance Sheets

Balance Sheets - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 7,681	$ 3,576
Accounts receivable	8,659	11,124
Commodity derivative instruments	32,087	45,924
Due from affiliates	1,456	5,697
Prepaid expenses	1,240	1,840
Total current assets	51,123	68,161
Property and equipment (successful efforts method)	972,398	956,326
Accumulated depletion, depreciation and impairment	(559,893)	(506,368)
Total property and equipment, net	412,505	449,958
Commodity derivative instruments	37,159	38,540
Deferred financing costs, net of accumulated amortization and other assets	2,076	2,295
TOTAL ASSETS	502,863	558,954
Current liabilities:
Accrued liabilities	9,910	5,506
Accrued capital cost	7,642	9,176
Commodity derivative instruments	783	556
Interest rate derivative instruments	2,781	2,327
Asset retirement obligations	2,153	1,065
Total current liabilities	23,269	18,630
Long-term liabilities:
Commodity derivative instruments	94	232
Interest rate derivative instruments	960	817
Term loan	50,000	50,000
Revolving credit facility	235,000	230,000
Asset retirement obligations	40,558	40,539
Deferred tax liabilities		99
Total long-term liabilities	326,612	321,687
Total liabilities	349,881	340,317
Unitholders' equity:
General partner (22,400 units issued and outstanding as of June 30, 2015 and December 31, 2014)	(9,139)	310
Total unitholders' equity	152,982	218,637
TOTAL LIABILITIES AND UNITHOLDERS' EQUITY	502,863	558,954
Public Common
Unitholders' equity:
Limited partner	$ 162,121	208,273
Affiliated Common
Unitholders' equity:
Limited partner		4,643
Affiliated Subordinated
Unitholders' equity:
Limited partner		$ 5,411

Balance Sheets (Parenthetical)

Balance Sheets (Parenthetical) - shares	Jun. 30, 2015	Dec. 31, 2014
General partner, units issued (in units)	22,400	22,400
General partner, units outstanding (in units)	22,400	22,400
Public Common
Limited partner, units issued (in units)	19,504,833	19,492,291
Limited partner, units outstanding (in units)	19,504,833	19,492,291
Affiliated Common
Limited partner, units issued (in units)	8,569,600	4,089,600
Limited partner, units outstanding (in units)	8,569,600	4,089,600
Affiliated Subordinated
Limited partner, units issued (in units)		4,480,000
Limited partner, units outstanding (in units)		4,480,000

Statements of Operations

Statements of Operations - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Revenues:
Oil sales	$ 14,227	$ 20,354	$ 26,291	$ 40,510
Natural gas sales	3,720	7,565	7,986	15,664
Natural gas liquids sales	1,661	2,760	2,832	6,124
Gain (loss) on commodity derivative instruments, net	(8,927)	(13,328)	9,755	(18,950)
Other income	26	40	55	71
Total revenues	10,707	17,391	46,919	43,419
Operating expenses:
Lease operating expense	6,008	6,829	12,780	12,664
Production and ad valorem taxes	1,482	2,248	2,748	4,648
Depletion and depreciation	8,694	8,680	17,574	17,145
Impairment of oil and natural gas properties	256		35,962
Accretion expense	518	510	1,029	1,013
Loss (gain) on settlement of asset retirement obligations	4	21	68	61
General and administrative expense	12,673	2,699	16,464	5,881
Total operating expenses	29,635	20,987	86,625	41,412
Operating income (loss)	(18,928)	(3,596)	(39,706)	2,007
Other income (expense), net
Interest expense	(3,120)	(2,575)	(5,889)	(5,116)
Gain (loss) on interest rate derivative instruments, net	(322)	(1,128)	(1,673)	(1,422)
Other income (expense), net	(3,442)	(3,703)	(7,562)	(6,538)
Income (loss) before taxes	(22,370)	(7,299)	(47,268)	(4,531)
Income tax (expense) benefit	56	(38)	18	(112)
Net income (loss) available to unitholders	(22,314)	(7,337)	(47,250)	(4,643)
Computation of net income (loss) per limited partner unit:
General partners' interest in net income (loss)	(7,595)	(7)	(9,434)	(4)
Limited partners' interest in net income (loss)	$ (14,719)	$ (7,330)	$ (37,816)	$ (4,639)
Net income (loss) per limited partner unit (basic and diluted) (in dollars per unit)	$ (0.52)	$ (0.27)	$ (1.35)	$ (0.17)
Weighted average number of limited partner units outstanding (basic and diluted)	28,074	26,733	28,073	26,539

Consolidated Statement of Chang

Consolidated Statement of Changes in Unitholders' Equity - 6 months ended Jun. 30, 2015 - USD ($) $ in Thousands	General Partner	Limited PartnersPublic Common	Limited PartnersAffiliated Common	Limited PartnersAffiliated Subordinated	Total
Balance at Dec. 31, 2014	$ 310	$ 208,273	$ 4,643	$ 5,411	$ 218,637
Increase (Decrease) in Unitholders' Equity
Equity offering, net of expenses		3			3
Amortization of equity awards		838			838
Conversion of subordinated units			3,182	(3,182)
Distribution	(15)	(14,201)	(2,801)	$ (2,229)	(19,246)
Net income (loss)	(9,434)	(32,792)	$ (5,024)		(47,250)
Balance at Jun. 30, 2015	$ (9,139)	$ 162,121			$ 152,982

Statements of Cash Flows

Statements of Cash Flows - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$ (47,250)	$ (4,643)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depletion and depreciation	17,574	17,145
Impairment of oil and natural gas properties	35,962
Accretion expense	1,029	1,013
Amortization of equity awards	838	534
Amortization of derivative contracts	243	330
Amortization of deferred financing costs and other	341	208
Loss (gain) on settlement of asset retirement obligations	68	61
Changes in operating assets and liabilities:
Change in receivables	2,465	75
Change in prepaid expenses	483	(209)
Change in derivative assets and liabilities	15,659	20,605
Change in amounts due to/from affiliates	4,241	(5,992)
Net cash provided by (used in) operating activities	35,954	31,663
Change in accrued liabilities and deferred tax liabilities	4,301	2,536
CASH FLOWS FROM INVESTING ACTIVITIES
Development of oil and natural gas properties	(17,376)	(17,094)
Acquisition of oil and natural gas properties	(230)
Disposition of oil and natural gas properties		65
Net cash provided by (used in) investing activities	(17,606)	(17,029)
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings under revolving credit facility	10,000	20,000
Principal payments on revolving credit facility	(5,000)	(25,000)
Equity offering, net of expenses	3	14,810
Distributions	(19,246)	(25,990)
Net cash provided by (used in) financing activities	(14,243)	(16,180)
NET INCREASE IN CASH AND CASH EQUIVALENTS	4,105	(1,546)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD	3,576	4,417
CASH AND CASH EQUIVALENTS, END OF PERIOD	$ 7,681	$ 2,871

Organization and Description of

Organization and Description of Business	6 Months Ended
	Jun. 30, 2015
Organization and Description of Business
Organization and Description of Business	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 are limited to co-issuing our debt securities and engaging in activities related thereto. Merger with Vanguard Natural Resources, LLC On April 20, 2015, we entered into a Purchase Agreement and Plan of Merger (the “Merger Agreement”) with Vanguard Natural Resources, LLC (“Vanguard”), Lighthouse Merger Sub, LLC, a wholly owned indirect subsidiary of Vanguard (“Merger Sub” and together with Vanguard, the “Vanguard Entities”), Lime Rock Management, Fund I, Fund II (together with the Fund I and Lime Rock Management, the “GP Sellers”) and LRE GP, LLC (our “General Partner” and together with the GP Sellers and the Partnership, the “Partnership Entities”). Upon the terms and conditions set forth in the Merger Agreement, Merger Sub will be merged with and into the Partnership, with the Partnership continuing as the surviving entity and as a wholly owned subsidiary of Vanguard (the “Merger”) and, at the same time, all of the limited liability company interests in our General Partner will be acquired by Vanguard. Based upon the recommendation of the conflicts committee of the board of directors of our General Partner (the “Board”), the Board approved the Merger Agreement on April 20, 2015. At the effective time of the Merger (the “Effective Time”), each of our common units issued and outstanding immediately prior to the Effective Time will be converted into the right to receive 0.550 common units representing limited liability company interests in Vanguard (“Vanguard Units”) or, in the case of fractional Vanguard Units, cash (without interest and rounded up to the nearest whole cent) in an amount equal to the product of (i) such fractional part of a Vanguard Unit multiplied by (ii) the average closing price for a Vanguard Unit as reported on the NASDAQ Global Select Market (the “NASDAQ”) for the ten consecutive full trading days ending at the close of trading on the full trading day immediately preceding the closing date of the transactions contemplated by the Merger Agreement (the “Closing Date”). Each of our restricted common units that is outstanding pursuant to the 2011 LTIP will vest immediately prior to the Effective Time and be converted into the right to receive Vanguard Units. In addition, on the Closing Date, Vanguard will issue and deliver to the GP Sellers 12,320 Vanguard Units in exchange for all of the limited liability interests in our General Partner (the “GP Equity Consideration”). As a condition to closing of transactions contemplated under the Merger Agreement, the parties have agreed to execute and deliver a Termination and Continuing Obligations Agreement (the “Termination Agreement”) substantially in the form attached as an exhibit to the Merger Agreement. Pursuant to the Termination Agreement, (i) that certain Omnibus Agreement, entered into, and effective as of, November 16, 2011 (the “Omnibus Agreement”), by and among us, our General Partner, OLLC, Fund I, LRR GP, LLC, the ultimate general partner of each of the Fund I entities, and Lime Rock Management, will be terminated and (ii) the Fund I entities, severally and in proportion to each entity’s Property Contributor Percentage (as defined in the Omnibus Agreement), will agree to indemnify the Partnership, our General Partner, OLLC and all of our and their respective subsidiaries from and against any losses arising out of any federal, state or local income tax liabilities attributable to the ownership or operation of the oil and natural gas properties owned or leased by any of the Partnership, our General Partner, OLLC or our or their respective subsidiaries prior to the closing of our initial public offering. The indemnification obligations of Fund I under the Termination Agreement will survive until the first anniversary of the Closing Date. The Partnership Entities and the Vanguard Entities have each made certain representations and warranties and agreed to certain covenants in the Merger Agreement. Each of the Partnership, our General Partner and Vanguard has agreed, among other things, subject to certain exceptions, to conduct its respective business in the ordinary course during the period between the execution of the Merger Agreement and the Effective Time (unless the Merger Agreement is earlier terminated in accordance with its terms). In addition, we have agreed not to solicit alternative business combination transactions during such period, and, subject to certain exceptions, not to engage in discussions or negotiations regarding any alternative business combination transactions during such period. The closing of the Merger is subject to the satisfaction or waiver of certain customary conditions, including, among others, (i) the approval of the Merger Agreement by our unitholders; (ii) the registration statement on Form S-4 used to register the Vanguard Units to be issued in the Merger being declared effective by the Securities and Exchange Commission (the “SEC”); (iii) the approval for listing on the NASDAQ of the Vanguard Units to be issued in the Merger; (iv) subject to specified materiality standards, the accuracy of the representations and warranties of, and the performance of all covenants by, the parties; (v) the delivery of certain tax opinions; and (vi) entry into the Termination Agreement by the parties thereto. The Merger Agreement contains certain termination rights for each of the Partnership and Vanguard, including, among others, if (i) the Merger is not consummated on or before December 31, 2015; (ii) the requisite approval of the Merger Agreement by our unitholders is not obtained; and (iii) the other party breaches a representation, warranty or covenant, and such breach results in the failure of certain closing conditions to be satisfied (a “terminable breach”). The Merger Agreement also provides that (a) we may terminate the Merger Agreement to enter into a third party’s “superior proposal” and (b) Vanguard may terminate the Merger Agreement if the Board changes its recommendation to our unitholders to approve the Merger Agreement (a “Partnership Change in Recommendation”); provided, in each case, that we pay Vanguard the Termination Fee (as described below). The Merger Agreement provides for the payment of a termination fee of approximately $7.3 million (the “Termination Fee”) by the Partnership to Vanguard upon the termination of the Merger Agreement under specified circumstances, including if: (i) (a) prior to our unitholder meeting, a third party proposal has been publicly submitted, publicly proposed or publicly disclosed and has not been withdrawn at the time of such meeting, (b) thereafter, the Merger Agreement is terminated in accordance with its terms under specified circumstances, and (c) prior to the date that is 12 months after the date of the Merger Agreement is terminated, we enter into or consummate any definitive agreement related to a third party proposal; (ii) Vanguard terminates the Merger Agreement due to a Partnership Change in Recommendation; or (iii) we terminate the Merger Agreement to enter into a third party’s “superior proposal.” The Merger Agreement also provides that the non-terminating party may be required to pay the other party’s expenses (up to a maximum of approximately $1.2 million (the “Expenses”)) if either party terminates the Merger Agreement due to a terminable breach by the other party. If the Termination Fee is payable at a time when Vanguard has received or concurrently receives payment from us in respect of Expenses, the Termination Fee will be reduced by the amount of such Expenses received by Vanguard. The special meeting of unitholders to approve the Merger Agreement is scheduled to occur on September 10, 2015. Our unitholders of record at the close of business on July 24, 2015 will be entitled to receive notice of the special meeting and vote at the special meeting.

Summary of Significant Accounti

Summary of Significant Accounting Policies	6 Months Ended
	Jun. 30, 2015
Summary of Significant Accounting Policies
Summary of Significant Accounting Policies	2. Summary of Significant Accounting Policies Our accounting policies are set forth in the audited consolidated financial statements in our Annual Report on Form 10-K for the year ended December 31, 2014 (“2014 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 financial statements and notes in our 2014 Annual Report. Basis of presentation These interim financial statements are unaudited and have been prepared pursuant to the rules and regulations of the 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 financial statements in our 2014 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. Recent accounting pronouncements On April 10, 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014-08, “Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity.” ASU No. 2014-08 amends the definition of a discontinued operation and requires entities to provide additional disclosures about discontinued operations as well as disposal transactions that do not meet the discontinued-operations criteria. We adopted ASU No. 2014-08 on January 1, 2015. The adoption of ASU No. 2014-08 did not have a material impact on our consolidated condensed financial position, results of operations or cash flows. On May 28, 2014, the FASB issued ASU No. 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 revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In July 2015, the FASB approved a delay in adoption for public entities and ASU No. 2014-09 is effective for annual periods beginning after December 15, 2017.We are still evaluating the impact of our adoption of ASU No. 2014-09. On August 27, 2014, the FASB issued ASU No. 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. On February 18, 2015, the FASB issued No. ASU 2015-02, “Consolidation (Topic 810): Amendments to the Consolidation Analysis.” ASU No. 2015-02 applies to entities in all industries and provides a new scope exception to registered money market funds and similar unregistered money market funds. The standard makes targeted amendments to the current consolidation guidance and ends the deferral granted to investment companies from applying the variable interest entities guidance. ASU No. 2015-02 is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2015. We are still evaluating the impact of our adoption of ASU No. 2015-02. On April 7, 2015, the FASB issued ASU No. 2015-03, “Simplifying the Presentation of Debt Issuance Costs.” ASU No. 2015-03 changes the presentation of debt issuance costs in financial statements. The new standard requires entities to present debt issuance costs as a direct deduction from the related debt liability rather than as an asset. Amortization of the costs is reported as interest expense. ASU No. 2015-03 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015, and interim periods beginning after December 15, 2016. Early adoption is allowed for all entities for financial statements that have not been previously issued. Entities would apply the new guidance retrospectively to all prior periods. We do not expect the adoption of ASU No. 2015-03 to have a material impact on our financial statements or disclosures.

Acquisitions

Acquisitions	6 Months Ended
	Jun. 30, 2015
Acquisitions
Acquisitions	3. Acquisitions Third Party Acquisition On October 1, 2014, we completed an acquisition of 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 (the “October 2014 Acquisition”) from an unrelated third party. We paid total cash consideration of $38.2 million at closing. The October 2014 Acquisition was effective September 1, 2014. In January 2015, we paid $0.2 million in cash to the seller related to post-closing adjustments to the purchase price. We financed the acquisition with borrowings under our revolving credit facility (Note 7). The October 2014 Acquisition was accounted for under the acquisition method of accounting, whereby the purchase price was allocated to the assets acquired and liabilities assumed based on their fair values, with any excess of the purchase price over the estimated fair value of the identifiable net assets acquired recorded as goodwill (or shortfall of purchase price versus net fair value recorded as bargain purchase). Based on the purchase price allocation for October 2014 Acquisition, no goodwill or bargain purchase was recognized. The cash consideration paid for the October 2014 Acquisition and the assets and liabilities recognized are presented in the table below (in thousands, except for per unit amounts): Property and equipment, net $ Asset retirement obligations ) Net assets $ The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties included estimates of: (i) reserves, including risk adjustments for probable and possible reserves; (ii) production rates; (iii) future operating and development costs; (iv) future commodity prices; (v) future cash flows; and (vi) a market-based weighted average cost of capital rate. These inputs required significant judgments and estimates by our management at the time of the valuation and are subject to change. The following unaudited pro forma information shows the pro forma effects of the October 2014 Acquisition. The unaudited pro forma information assumes the transaction occurred on January 1, 2014. The pro forma results of operations have been prepared by adjusting our historical results to include the historical results of the acquired assets based on information provided by the seller, our knowledge of the acquired properties and the impact of our purchase price allocation. We believe the assumptions used provide a reasonable basis for reflecting the pro forma significant effects directly attributable to the acquisition. The pro forma results of operations do not include any cost savings or other synergies that may result from the October 2014 Acquisition or any estimated costs that have been or will be incurred to integrate the assets. The following unaudited pro forma information does not purport to represent what our results of operations would have been if such acquisition had occurred on January 1, 2014 (in thousands). Three Months Ended Six Months Ended June 30, 2014 June 30, 2014 Total revenues $ $ Net income (loss) available to unitholders ) ) Basic and diluted net income (loss) per unit ) )

Fair Value Measurements

Fair Value Measurements	6 Months Ended
	Jun. 30, 2015
Fair Value Measurements
Fair Value Measurements	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 June 30, 2015 and December 31, 2014 (in thousands). Level 1 Level 2 Level 3 Total June 30, 2015 Assets: Commodity derivative instruments $ — $ $ — $ Liabilities: Commodity derivative instruments — — Interest rate derivative instruments — — December 31, 2014 Assets: Commodity derivative instruments $ — $ $ — $ Liabilities: Commodity derivative instruments — — Interest rate derivative instruments — — 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 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.

Property and Equipment

Property and Equipment	6 Months Ended
	Jun. 30, 2015
Property and Equipment
Property and Equipment	5. Property and Equipment Property and equipment is stated at cost less accumulated depletion, depreciation and impairment and consisted of the following (in thousands): June 30, 2015 December 31, 2014 Oil and natural gas properties (successful efforts method) $ $ Unproved properties Other property and equipment Accumulated depletion, depreciation and impairment ) ) Total property and equipment, net $ $ We recorded $8.7 million of depletion and depreciation expense for each of the three months ended June 30, 2015 and 2014. We recorded $17.6 million and $17.1 million of depletion and depreciation expense for the six months ended June 30, 2015 and 2014, respectively. We perform an impairment analysis of our oil and natural gas properties on a quarterly basis due to the volatility in commodity prices. For the three months ended June 30, 2015, we recorded a total non-cash impairment charge of $0.3 million to impair the value of our proved oil and natural gas properties in the Mid-Continent region. We did not record any impairment charges in the three months ended June 30, 2014. For the six months ended June 30, 2015, we recorded a total non-cash impairment charge of $36.0 million to impair the value of our proved oil and natural gas properties in the Permian Basin, Gulf Coast, and the Mid-Continent regions. This impairment charge reduced the regions’ carrying values to an estimated fair value of $411.3 million as of June 30, 2015. We did not record any impairment charges in the six months ended June 30, 2014. These impairments of proved and unproved oil and natural gas properties were recorded because the net capitalized costs of the properties exceeded the fair value of the properties as measured by estimated cash flows reported in an internal reserve report. Further, our unproved properties were impaired based on the drilling locations for the probable and possible reserves becoming uneconomic at the lower future expected natural gas prices and our future expected drilling schedules. These reports are based upon future oil and natural gas prices, which are based on observable inputs, adjusted for basis differentials. These are classified as Level 3 fair value measurements. The fair values of our properties are measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of the properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. The underlying commodity prices embedded in the our estimated cash flows are the product of a process that begins with New York Mercantile Exchange (“NYMEX”) forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that management believes will impact realizable prices. Furthermore, significant assumptions in valuing the proved reserves included the reserve quantities, anticipated drilling and operating costs, anticipated production taxes, future expected natural gas prices and basis differentials, anticipated drilling schedules, anticipated production declines, and an appropriate discount rate commensurate with the risk of the underlying cash flow estimates. Cash flow estimates for the impairment testing excluded derivative instruments used to mitigate the risk of lower future natural gas prices. Significant assumptions in valuing the unproved reserves included the evaluation of the probable and possible reserves, future expected natural gas prices and basis differentials, and anticipated drilling schedules. These asset impairments have no impact on cash flows, liquidity positions, or debt covenants. If future oil or natural gas prices decline further, the estimated undiscounted future cash flows for the proved oil and natural gas properties may not exceed the net capitalized costs for our properties and a non-cash impairment charge may be required to be recognized in future periods.

Asset Retirement Obligations

Asset Retirement Obligations	6 Months Ended
	Jun. 30, 2015
Asset Retirement Obligations
Asset Retirement Obligations	6. Asset Retirement Obligations The following is a summary of our asset retirement obligations as of and for the six months ended June 30, 2015 (in thousands): Beginning of period $ Acquisitions Revisions to previous estimates Liabilities incurred Liabilities settled ) Accretion expense End of period Current portion of asset retirement obligations ) Asset retirement obligations — non-current $

Long-Term Debt

Long-Term Debt	6 Months Ended
	Jun. 30, 2015
Long-Term Debt
Long-Term Debt	7. Long-Term Debt Credit Agreement We, as guarantor, and our wholly owned subsidiary, OLLC, as borrower, are parties to a five-year, $750 million senior secured revolving credit facility, as amended (the “Credit Agreement”), that matures on October 1, 2019. The Intercreditor Agreement (as described below) limits the amount of indebtedness outstanding at any time under the Credit Agreement (including undrawn amounts under letters of credit) to an amount not to exceed $500 million in the aggregate. 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 $244 million as of June 30, 2015. Our borrowing base, which is primarily based on the estimated value of our oil, natural gas liquids (“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 June 30, 2015, we were in compliance with all covenants contained in the Credit Agreement. In May 2015, we entered into the Fifth Amendment (“Fifth Credit Agreement Amendment”) to our Credit Agreement. The Fifth Credit Agreement Amendment, among other things, (i) increased the interest rate margins applicable to the loans with margins ranging from 2.00% to 3.10% for Eurodollar loans, and from 1.00% to 2.10% for base rate loans, in each case based on utilization of the credit facility, (ii) increased the commitment fee applicable to the unused portion of the borrowing base with amounts ranging from 0.375% to 0.800% based on utilization of the credit facility, (iii) restricted the payments of distributions to $10.6 million through September 30, 2015; however, after October 1, 2015, distributions are subject to a minimum of 15% availability under a conforming borrowing base amount, and (iv) decreased the borrowing base to $245.0 million. Pursuant to the amendment, the borrowing base began to decrease in the amount of $1.0 million per month, beginning in June 2015 and continuing until the next redetermination of the borrowing base in the fall of 2015. The borrowing base of the Credit Agreement will revert to $195.0 million upon the earlier of November 1, 2015 and a termination of the Merger Agreement. Term Loan Agreement We, as parent guarantor, and our wholly owned subsidiary, OLLC, as borrower, are parties to a Second Lien Credit Agreement (the “Term Loan Agreement”). The Term Loan Agreement provides for a $50 million senior secured second lien term loan to OLLC. OLLC borrowed $50 million under the Term Loan Agreement and used the borrowings to repay outstanding borrowings under the Credit Agreement. The Term Loan Agreement contains various covenants and restrictive provisions as described in our 2014 Annual Report. As of June 30, 2015, we were in compliance with the leverage and current ratios contained in our Term Loan Agreement. We are required to test the asset coverage ratio at specified intervals as described in the Term Loan Agreement, including during the redetermination of our borrowing base under our Credit Agreement. We were not in compliance with the asset coverage ratio during the borrowing base redetermination in the second quarter of 2015; however, we received a waiver from our lender under the Term Loan Agreement for the asset coverage ratio covenant. 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. In May 2015, we entered into the Fifth Amendment (“Fifth Term Loan Amendment”) to our Term Loan Agreement. The Fifth Term Loan Amendment, among other things, amended the Term Loan Agreement to (i) increase the interest rate margins applicable to the loan with margins for Eurodollar loans and Alternate Base Rate loans increasing to 9.50% and 8.50%, respectfully, after September 30, 2015, and (ii) restrict the payments of distributions to $10.6 million through September 30, 2015; however, after October 1, 2015, distributions are subject to having a minimum of 15% availability under a conforming borrowing base amount. As of June 30, 2015, we had $285.0 million of outstanding debt and accrued interest was approximately $0.2 million. As of December 31, 2014, we had $280.0 million of outstanding debt and accrued interest was approximately $0.2 million. Interest expense for the three months ended June 30, 2015 and 2014 was $3.1 million and $2.6 million, respectively. Interest expense for the six months ended June 30, 2015 and 2014 was $5.9 million and $5.1 million, respectively. As of June 30, 2015 and December 31, 2014, our weighted average interest rate on our outstanding indebtedness was 5.27% and 3.81%, respectively. Please refer to Note 8 below for a discussion of our interest rate derivative contracts.

Derivatives

Derivatives	6 Months Ended
	Jun. 30, 2015
Derivatives
Derivatives	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. 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. 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. At June 30, 2015, we had the following open commodity derivative contracts: Index 2015 2016 2017 2018 Natural gas positions Price swaps (MMBtu) NYMEX-HH Weighted average price $ $ $ $ Basis swaps (MMBtu) (1) — — Weighted average price $ ) $ ) $ — $ — Oil positions Price swaps (Bbl) NYMEX-WTI Weighted average price $ $ $ $ Basis swaps (Bbl) Argus- — — Weighted average price Midland-Cushing $ ) $ ) $ — $ — NGL positions Price swaps (Bbl) Mont Belvieu — — — Weighted average price $ $ — $ — $ — (1) Our natural gas basis swaps are traded on the following indices: Centerpoint East, Houston Ship Channel, WAHA and TEXOK. At December 31, 2014, we had the following open commodity derivative contracts: Index 2015 2016 2017 2018 Natural gas positions Price swaps (MMBtu) NYMEX-HH Weighted average price $ $ $ $ Basis swaps (MMBtu) (1) — — Weighted average price $ ) $ ) $ — $ — Oil positions Price swaps (Bbl) NYMEX-WTI Weighted average price $ $ $ $ Basis swaps (Bbl) Argus- — — — Weighted average price Midland-Cushing $ ) $ — $ — $ — NGL positions Price swaps (Bbl) Mont Belvieu — — — Weighted average price $ $ — $ — $ — (1) Our natural gas basis swaps are traded on the following indices: Centerpoint East, Houston Ship Channel, WAHA and TEXOK. At June 30, 2015, we had the following interest rate swap derivative contracts (in thousands): Notional Effective Maturity Amount Average % Index February 2015 February 2017 % LIBOR February 2015 February 2017 % LIBOR June 2015 June 2017 % LIBOR At December 31, 2014, we had the following interest rate swap derivative contracts (in thousands): Notional Effective Maturity Amount Average % Index February 2012 February 2015 $ % LIBOR February 2015 February 2017 % LIBOR February 2015 February 2017 % LIBOR June 2012 June 2015 % LIBOR June 2015 June 2017 % 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 June 30, 2015 Current Long-term Current Long-term Assets Assets Liabilities Liabilities Interest rate Swaps $ — $ — $ $ Gross fair value — — Netting arrangements — — — — Net recorded fair value $ — $ — $ $ Sale of natural gas production Price swaps $ $ $ — $ — Basis swaps — — Sale of crude oil production Price swaps — — Basis swaps — Sale of NGLs Price swaps — — — Gross fair value Netting arrangements — ) — ) Net recorded fair value $ $ $ $ As of December 31, 2014 Current Long-term Current Long-term Assets Assets Liabilities Liabilities Interest rate Swaps $ — $ — $ $ Gross fair value — — Netting arrangements — — — — Net recorded fair value $ — $ — $ $ Sale of natural gas production Price swaps $ $ $ — $ — Basis swaps — Sale of crude oil production Price swaps — — Basis swaps — — — Sale of NGLs Price swaps — — — Gross fair value Netting arrangements ) — ) — Net recorded fair value $ $ $ $ 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 June 30, Six Months Ended June 30, 2015 2014 2015 2014 Commodity derivatives (revenue) $ ) $ ) $ $ ) Interest rate derivatives (other income (expense), net) ) ) ) ) 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.

Related Parties

Related Parties	6 Months Ended
	Jun. 30, 2015
Related Parties
Related Parties	9. Related Parties Ownership in Our General Partner by Lime Rock Management and its Affiliates As of June 30, 2015, 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 30.5% of our outstanding common units, representing their limited partner interest in us. As of June 30, 2015, 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 2014 Annual Report, 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 converted the remaining 4,480,000 subordinated units on a one-for-one basis into common units pursuant to the terms of our partnership agreement on February 13, 2015. Contracts with our General Partner and its Affiliates As more fully described in our 2014 Annual Report, we have entered into agreements with our general partner and its affiliates. For each of the three months ended June 30, 2015 and 2014, we paid Lime Rock Management approximately $0.4 million either directly or indirectly related to these agreements. For the six months ended June 30, 2015 and 2014, we paid Lime Rock Management approximately $0.8 million and $0.6 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 six months ended June 30, 2015 are included below (in thousands): Lime Rock ServCo Resources Total Balance as of December 31, 2014 $ $ $ Expenditures ) ) ) Cash paid for expenditures — Revenues and other ) ) Balance as of June 30, 2015 $ $ — $ ` 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 June 30, 2015, our general partner and its affiliates held 8,569,600 of our common units and 22,400 general partner units. During the six months ended June 30, 2015 and 2014, we paid cash distributions of $19.2 million and $26.0 million, respectively, to all unitholders as of the respective record dates. We announced our second quarter 2015 distribution on July 17, 2015 as discussed in Note 15.

Unitholders' Equity

Unitholders' Equity	6 Months Ended
	Jun. 30, 2015
Unitholders' Equity
Unitholders' Equity	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, subject to limitations as described in the Merger Agreement (described in Note 1). 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 of 1933, as amended, (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 borrowings outstanding under the term loan. During the six months ended June 30, 2015, we did not sell common units under the ATM Program. Units Outstanding As of June 30, 2015, we had 28,074,433 common units and 22,400 general partner units outstanding. As of June 30, 2015, Fund I owned 8,569,600 common units, representing a 30.5% limited partner interest in us. General Partner Allocation of Loss In accordance with our partnership agreement, the allocation of net loss cannot cause a unitholder to have a deficit balance. Deficit balances are carried by our general partner until net income is generated in a taxable period. Our general partner will recover losses from net income generated prior to the net income being allocated to the remaining unitholders.

Net Income (Loss) Per Limited P

Net Income (Loss) Per Limited Partner Unit	6 Months Ended
	Jun. 30, 2015
Net Income (Loss) Per Limited Partner Unit
Net Income (Loss) Per Limited Partner Unit	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 June 30, Six Months Ended June 30, 2015 2014 2015 2014 Net income (loss) available to unitholders $ ) $ ) $ ) $ ) Less: General partner’s interest in net (income) loss Limited partners’ interest in net income (loss) $ ) $ ) $ ) $ ) Weighted average limited partner units outstanding: Common units Subordinated units — Total Net income (loss) per limited partner unit (basic and diluted) $ ) $ ) $ ) $ ) 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 interest in net income (loss), by the weighted average number of common units and subordinated units outstanding as of June 30, 2015 and 2014. The aggregate number of common units outstanding was 28,074,433 , as of June 30, 2015. We did not have any subordinated units outstanding as of June 30, 2015. The aggregate number of common units and subordinated units outstanding was 22,674,390 and 4,480,000, respectively, as of June 30, 2014.

Equity-Based Compensation

Equity-Based Compensation	6 Months Ended
	Jun. 30, 2015
Equity-Based Compensation
Equity-Based Compensation	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 June 30, 2015, there were 1,025,013 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 June 30, 2015 is presented below: Number of Weighted Average Non-vested Grant-date Restricted Units Fair Value Non-vested restricted units at December 31, 2014 $ Granted Vested ) Forfeited — — Non-vested restricted units at June 30, 2015 As of June 30, 2015, there was approximately $2.3 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 2.1 years. There were 132,554 vested restricted units as of June 30, 2015. At the close of the Merger, all unvested restricted units will vest immediately.

Subsidiary Guarantors

Subsidiary Guarantors	6 Months Ended
	Jun. 30, 2015
Subsidiary Guarantors
Subsidiary Guarantors	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. 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.

Commitments and Contingencies

Commitments and Contingencies	6 Months Ended
	Jun. 30, 2015
Commitments and Contingencies Disclosure
Commitments and Contingencies	14. Commitments and Contingencies Litigation The following class action lawsuits (the “Lawsuits”) were filed in connection with the merger by purported LRR Energy, L.P. unitholders against us, our General Partner, our Board, Vanguard, Merger Sub and the other parties to the Merger Agreement (the ‘‘Defendants’’): · Barry Miller v. LRR Energy, L.P. et al., Case No. 11087-VCG , filed in the Court of Chancery of the State of Delaware on June 3, 2015 (“Miller Lawsuit”) · Christopher Tiberio v. LRR Energy, L.P. et al., Cause No. 2015-39864 , filed in the 334 th Judicial District Court of Harris County, Texas on July 10, 2015 (“Tiberio Lawsuit”) · Eddie Hammond v. LRR Energy, L.P. et al., Cause No. 2015-40154 , filed in the 295 th Judicial District Court of Harris County, Texas on July 13, 2015 (“Hammond Lawsuit”) · Ronald Krieger v. LRR Energy, L.P. et al., Civil Action No. 4:15-cv-2017 , filed in the United States District Court for the Southern District of Texas on July 14, 2015 (“Krieger Lawsuit”) On July 17, 2015, the Krieger Lawsuit was voluntarily dismissed without prejudice. On July 23, 2015, the Miller Lawsuit was also voluntarily dismissed without prejudice. On July 28, 2015, the Tiberio Lawsuit and the Hammond Lawsuit were both nonsuited without prejudice. Prior to their dismissals, the Lawsuits alleged that the merger (a) provided inadequate consideration to our unitholders and alleged that we and our Board breached certain fiduciary duties to the common unitholders by accepting such inadequate consideration and (b) contained contractual terms that would dissuade other potential merger partners from making alternative proposals for us, including, but not limited to, the requirement that certain of our unitholders enter into a voting and support agreement, adoption of an allegedly unreasonable no solicitation clause, the notice provisions, and allowing our Board to withdraw its favorable recommendation only under extremely limited circumstances. Prior to their dismissals, the Tiberio, Hammond, and Krieger Lawsuits also allege that the Vanguard Form S-4 Registration Statement filed with the SEC on June 16, 2015 failed to make all material disclosures and contained materially misleading statements about the merger in violation of Sections 14(a) and 20(a) of the Securities and Exchange Act of 1934 and SEC Rule 14a-9. The Lawsuits sought to be certified as class actions, and asked that the court, among other relief, enjoin the merger, or rescind the merger in the event it was consummated, and award damages, attorneys’ fees and costs. We and the other Defendants believed the Lawsuits were without merit, denied the allegations in their entirety and requested voluntary dismissal from each of the plaintiffs. They were each dismissed. Therefore, neither we nor our General Partner is currently a party to any material legal proceedings.

Subsequent Events

Subsequent Events	6 Months Ended
	Jun. 30, 2015
Subsequent Events
Subsequent Events	15. Subsequent Events Unit Distribution On July 17, 2015, we announced that the Board declared a cash distribution for the second quarter of 2015 of $0.1875 per outstanding unit, or $0.75 on an annualized basis. The distribution will be paid on August 14, 2015 to all unitholders of record as of the close of business on July 31, 2015. The aggregate amount of the distribution will be $5.3 million.

Summary of Significant Accoun22

Summary of Significant Accounting Policies (Policies)	6 Months Ended
	Jun. 30, 2015
Summary of Significant Accounting Policies
Basis of Presentation	Basis of presentation These interim financial statements are unaudited and have been prepared pursuant to the rules and regulations of the 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 financial statements in our 2014 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.
Recent accounting pronouncements	Recent accounting pronouncements On April 10, 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014-08, “Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity.” ASU No. 2014-08 amends the definition of a discontinued operation and requires entities to provide additional disclosures about discontinued operations as well as disposal transactions that do not meet the discontinued-operations criteria. We adopted ASU No. 2014-08 on January 1, 2015. The adoption of ASU No. 2014-08 did not have a material impact on our consolidated condensed financial position, results of operations or cash flows. On May 28, 2014, the FASB issued ASU No. 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 revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In July 2015, the FASB approved a delay in adoption for public entities and ASU No. 2014-09 is effective for annual periods beginning after December 15, 2017.We are still evaluating the impact of our adoption of ASU No. 2014-09. On August 27, 2014, the FASB issued ASU No. 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. On February 18, 2015, the FASB issued No. ASU 2015-02, “Consolidation (Topic 810): Amendments to the Consolidation Analysis.” ASU No. 2015-02 applies to entities in all industries and provides a new scope exception to registered money market funds and similar unregistered money market funds. The standard makes targeted amendments to the current consolidation guidance and ends the deferral granted to investment companies from applying the variable interest entities guidance. ASU No. 2015-02 is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2015. We are still evaluating the impact of our adoption of ASU No. 2015-02. On April 7, 2015, the FASB issued ASU No. 2015-03, “Simplifying the Presentation of Debt Issuance Costs.” ASU No. 2015-03 changes the presentation of debt issuance costs in financial statements. The new standard requires entities to present debt issuance costs as a direct deduction from the related debt liability rather than as an asset. Amortization of the costs is reported as interest expense. ASU No. 2015-03 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015, and interim periods beginning after December 15, 2016. Early adoption is allowed for all entities for financial statements that have not been previously issued. Entities would apply the new guidance retrospectively to all prior periods. We do not expect the adoption of ASU No. 2015-03 to have a material impact on our financial statements or disclosures.

Acquisitions (Tables)

Acquisitions (Tables)	6 Months Ended
	Jun. 30, 2015
Acquisitions
Summary of pro forma results of operations	The following unaudited pro forma information does not purport to represent what our results of operations would have been if such acquisition had occurred on January 1, 2014 (in thousands). Three Months Ended Six Months Ended June 30, 2014 June 30, 2014 Total revenues $ $ Net income (loss) available to unitholders ) ) Basic and diluted net income (loss) per unit ) )
Oil And Natural Gas Properties In Stroud Field In Oklahoma
Acquisitions
Net assets conveyed by entity under common control in acquisition	The cash consideration paid for the October 2014 Acquisition and the assets and liabilities recognized are presented in the table below (in thousands, except for per unit amounts): Property and equipment, net $ Asset retirement obligations ) Net assets $

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	6 Months Ended
	Jun. 30, 2015
Fair Value Measurements
Schedule of the fair value of the financial assets and liabilities that were accounted for at fair value on a recurring basis, by level within the hierarchy	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 June 30, 2015 and December 31, 2014 (in thousands). Level 1 Level 2 Level 3 Total June 30, 2015 Assets: Commodity derivative instruments $ — $ $ — $ Liabilities: Commodity derivative instruments — — Interest rate derivative instruments — — December 31, 2014 Assets: Commodity derivative instruments $ — $ $ — $ Liabilities: Commodity derivative instruments — — Interest rate derivative instruments — —

Property and Equipment (Tables)

Property and Equipment (Tables)	6 Months Ended
	Jun. 30, 2015
Property and Equipment
Schedule of property and equipment, net	Property and equipment is stated at cost less accumulated depletion, depreciation and impairment and consisted of the following (in thousands): June 30, 2015 December 31, 2014 Oil and natural gas properties (successful efforts method) $ $ Unproved properties Other property and equipment Accumulated depletion, depreciation and impairment ) ) Total property and equipment, net $ $

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	6 Months Ended
	Jun. 30, 2015
Asset Retirement Obligations
Summary of our asset retirement obligations	The following is a summary of our asset retirement obligations as of and for the six months ended June 30, 2015 (in thousands): Beginning of period $ Acquisitions Revisions to previous estimates Liabilities incurred Liabilities settled ) Accretion expense End of period Current portion of asset retirement obligations ) Asset retirement obligations — non-current $

Derivatives (Tables)

Derivatives (Tables)	6 Months Ended
	Jun. 30, 2015
Derivatives
Schedule of open commodity derivative contracts	At June 30, 2015, we had the following open commodity derivative contracts: Index 2015 2016 2017 2018 Natural gas positions Price swaps (MMBtu) NYMEX-HH Weighted average price $ $ $ $ Basis swaps (MMBtu) (1) — — Weighted average price $ ) $ ) $ — $ — Oil positions Price swaps (Bbl) NYMEX-WTI Weighted average price $ $ $ $ Basis swaps (Bbl) Argus- — — Weighted average price Midland-Cushing $ ) $ ) $ — $ — NGL positions Price swaps (Bbl) Mont Belvieu — — — Weighted average price $ $ — $ — $ — (1) Our natural gas basis swaps are traded on the following indices: Centerpoint East, Houston Ship Channel, WAHA and TEXOK. At December 31, 2014, we had the following open commodity derivative contracts: Index 2015 2016 2017 2018 Natural gas positions Price swaps (MMBtu) NYMEX-HH Weighted average price $ $ $ $ Basis swaps (MMBtu) (1) — — Weighted average price $ ) $ ) $ — $ — Oil positions Price swaps (Bbl) NYMEX-WTI Weighted average price $ $ $ $ Basis swaps (Bbl) Argus- — — — Weighted average price Midland-Cushing $ ) $ — $ — $ — NGL positions Price swaps (Bbl) Mont Belvieu — — — Weighted average price $ $ — $ — $ — (1) Our natural gas basis swaps are traded on the following indices: Centerpoint East, Houston Ship Channel, WAHA and TEXOK.
Schedule of interest rate swap derivative contracts	At June 30, 2015, we had the following interest rate swap derivative contracts (in thousands): Notional Effective Maturity Amount Average % Index February 2015 February 2017 % LIBOR February 2015 February 2017 % LIBOR June 2015 June 2017 % LIBOR At December 31, 2014, we had the following interest rate swap derivative contracts (in thousands): Notional Effective Maturity Amount Average % Index February 2012 February 2015 $ % LIBOR February 2015 February 2017 % LIBOR February 2015 February 2017 % LIBOR June 2012 June 2015 % LIBOR June 2015 June 2017 % LIBOR
Schedule of fair value of commodity and interest rate derivative contracts	The fair value of our commodity and interest rate derivative instruments is included in the tables below (in thousands): As of June 30, 2015 Current Long-term Current Long-term Assets Assets Liabilities Liabilities Interest rate Swaps $ — $ — $ $ Gross fair value — — Netting arrangements — — — — Net recorded fair value $ — $ — $ $ Sale of natural gas production Price swaps $ $ $ — $ — Basis swaps — — Sale of crude oil production Price swaps — — Basis swaps — Sale of NGLs Price swaps — — — Gross fair value Netting arrangements — ) — ) Net recorded fair value $ $ $ $ As of December 31, 2014 Current Long-term Current Long-term Assets Assets Liabilities Liabilities Interest rate Swaps $ — $ — $ $ Gross fair value — — Netting arrangements — — — — Net recorded fair value $ — $ — $ $ Sale of natural gas production Price swaps $ $ $ — $ — Basis swaps — Sale of crude oil production Price swaps — — Basis swaps — — — Sale of NGLs Price swaps — — — Gross fair value Netting arrangements ) — ) — Net recorded fair value $ $ $ $
Schedule of net gain (loss) amounts and classification related to derivative instruments	The net gain (loss) amounts and classification related to derivative instruments for the periods indicated are as follows (in thousands): Three Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 Commodity derivatives (revenue) $ ) $ ) $ $ ) Interest rate derivatives (other income (expense), net) ) ) ) )

Related Parties (Tables)

Related Parties (Tables)	6 Months Ended
	Jun. 30, 2015
Related Parties
Schedule of changes in the affiliates (payable)/receivable balances	Changes in the affiliates (payable)/receivable balances during the six months ended June 30, 2015 are included below (in thousands): Lime Rock ServCo Resources Total Balance as of December 31, 2014 $ $ $ Expenditures ) ) ) Cash paid for expenditures — Revenues and other ) ) Balance as of June 30, 2015 $ $ — $ `

Net Income (Loss) Per Limited29

Net Income (Loss) Per Limited Partner Unit (Tables)	6 Months Ended
	Jun. 30, 2015
Net Income (Loss) Per Limited Partner Unit
Schedule of calculation of 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 June 30, Six Months Ended June 30, 2015 2014 2015 2014 Net income (loss) available to unitholders $ ) $ ) $ ) $ ) Less: General partner’s interest in net (income) loss Limited partners’ interest in net income (loss) $ ) $ ) $ ) $ ) Weighted average limited partner units outstanding: Common units Subordinated units — Total Net income (loss) per limited partner unit (basic and diluted) $ ) $ ) $ ) $ )

Equity-Based Compensation (Tabl

Equity-Based Compensation (Tables)	6 Months Ended
	Jun. 30, 2015
Equity-Based Compensation
Summary of the non-vested restricted units	Number of Weighted Average Non-vested Grant-date Restricted Units Fair Value Non-vested restricted units at December 31, 2014 $ Granted Vested ) Forfeited — — Non-vested restricted units at June 30, 2015

Organization and Description 31

Organization and Description of Business (Details) - USD ($) $ in Millions	Apr. 20, 2015	Jun. 30, 2015
Vanguard | Merger Agreement
Description of Business
Termination fee that will be paid upon the termination of the Merger Agreement under specified circumstances	$ 7.3
The period prior to which and after the date of the Merger Agreement is terminated, termination fee is required to be paid if the entity enters into or consummates any definitive agreement related to a third party proposal	12 months
Maximum expenses the non-terminating party may be required to pay to the other party	$ 1.2
Vanguard | Common Units | Merger Agreement
Description of Business
Number of Vanguard Units that each common unit of the entity will be converted to at the effective time of the Merger	0.550
Threshold period of consecutive trading days within which the average closing price of Vanguard Units will be used as a multiplier to calculate the cash payment of fractional unit	10 days
Vanguard | General Partner | Merger Agreement
Description of Business
Aggregate number of Vanguard Units that will be issued on the Closing Date of the Merger, which represents the GP Equity Consideration	12,320
L R E Finance Corporation
Description of Business
Ownership interest held (as a percent)		100.00%

Acquisitions (Details)

Acquisitions (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended	6 Months Ended
	Jun. 30, 2014	Jun. 30, 2014	Jan. 31, 2015	Oct. 31, 2014	Oct. 01, 2014
Unaudited pro forma information
Total revenues	$ 19,770	$ 48,113
Net income (loss) available to unitholders	$ (6,049)	$ (2,052)
Basic and diluted net income (loss) per unit	$ (0.23)	$ (0.08)
Oil And Natural Gas Properties In Stroud Field In Oklahoma
Net assets conveyed by Fund I to the Partnership in the Transaction
Property and equipment, net				$ 38,848
Asset retirement obligations and other liabilities				(691)
Net assets				$ 38,157
Oil And Natural Gas Properties In Mid Continent Region In Oklahoma | Fund I
Acquisitions
Purchase price			$ 200		$ 38,000

Fair Value Measurements (Detail

Fair Value Measurements (Details) - Fair Value Measurements Recurring - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Level 2 | Commodity Contract
Fair Value Measurements
Assets	$ 69,246	$ 84,464
Liabilities	877	788
Level 2 | Interest Rate Contract
Fair Value Measurements
Liabilities	3,741	3,144
Estimate Of Fair Value Fair Value Disclosure | Commodity Contract
Fair Value Measurements
Assets	69,246	84,464
Liabilities	877	788
Estimate Of Fair Value Fair Value Disclosure | Interest Rate Contract
Fair Value Measurements
Liabilities	$ 3,741	$ 3,144

Property and Equipment (Details

Property and Equipment (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014
Property and Equipment
Oil and natural gas properties (successful efforts method)	$ 970,906		$ 970,906		$ 954,819
Unproved properties	1,220		1,220		1,235
Other property and equipment	272		272		272
Property and equipment, gross	972,398		972,398		956,326
Accumulated depletion, depreciation and impairment	(559,893)		(559,893)		(506,368)
Total property and equipment, net	412,505		412,505		$ 449,958
Depletion and depreciation expense	8,694	$ 8,680	17,574	$ 17,145
Non-cash impairment charges	256		35,962
Estimate fair value	$ 411,300		$ 411,300

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014
Asset retirement obligations
Beginning of period			$ 41,604
Acquisitions			13
Revisions to previous estimates			5
Liabilities incurred			106
Liabilities settled			(46)
Accretion expense	$ 518	$ 510	1,029	$ 1,013
End of period	42,711		42,711
Current portion of asset retirement obligations	(2,153)		(2,153)		$ (1,065)
Asset retirement obligation-non-current	$ 40,558		$ 40,558		$ 40,539

Long-Term Debt (Details)

Long-Term Debt (Details) - USD ($) $ in Thousands	Feb. 04, 2014	Jun. 28, 2012	Jun. 30, 2015	May. 31, 2015	Jul. 31, 2011	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014
Long-Term Debt
Outstanding debt			$ 285,000			$ 285,000		$ 285,000		$ 280,000
Accrued interest			$ 200			200		200		$ 200
Interest expense						$ 3,120	$ 2,575	$ 5,889	$ 5,116
Weighted average interest rate (as a percent)			5.27%			5.27%		5.27%		3.81%
Revolving Credit Facility
Long-Term Debt
Term of credit facility					5 years
Maximum borrowing capacity					$ 750,000
Restricted payment distributions				$ 10,600
Percentage of distributions subject to availability of borrowing base amount				15.00%
Borrowing capacity			$ 244,000	$ 245,000		$ 244,000		$ 244,000
Decrease in capacity per month			1,000
Revolving Credit Facility | Merger Agreement
Long-Term Debt
Borrowing capacity upon termination of merger agreement				$ 195,000
Revolving Credit Facility | Minimum
Long-Term Debt
Commitment fee on unused portion (as a percent)				0.375%
Revolving Credit Facility | Maximum
Long-Term Debt
Maximum limit on borrowing capacity			$ 500,000			$ 500,000		$ 500,000
Commitment fee on unused portion (as a percent)				0.80%
Revolving Credit Facility | Eurodollar | Minimum
Long-Term Debt
Interest rate added to base rate (as a percent)				2.00%
Revolving Credit Facility | Eurodollar | Maximum
Long-Term Debt
Interest rate added to base rate (as a percent)				3.10%
Revolving Credit Facility | Alternate Base Rate | Minimum
Long-Term Debt
Interest rate added to base rate (as a percent)				1.00%
Revolving Credit Facility | Alternate Base Rate | Maximum
Long-Term Debt
Interest rate added to base rate (as a percent)				2.10%
Secured Debt
Long-Term Debt
Restricted payment distributions				$ 10,600
Percentage of distributions subject to availability of borrowing base amount				15.00%
Face amount		$ 50,000
Amount borrowed		$ 50,000
Percentage of net cash proceeds from equity offering required to be used to repay borrowings outstanding	0.50%
Secured Debt | Eurodollar
Long-Term Debt
Interest rate (as percent)				9.50%
Secured Debt | Alternate Base Rate
Long-Term Debt
Interest rate (as percent)				8.50%

Derivatives (Details)

Derivatives (Details) $ in Thousands	6 Months Ended	12 Months Ended
	Jun. 30, 2015USD ($)MMBTUitem$ / Boe$ / MMBTUbbl	Dec. 31, 2014USD ($)MMBTU$ / Boe$ / MMBTUbbl
Commodity Basis Swap
Derivatives
Number of indices for gas on which floating price is based | item	2
Interest Rate Swap | February2012 To February2015 Term
Derivatives
Notional Amount | $		$ 150,000
Interest Rate Swap | February2012 To February2015 Term | London Interbank Offered Rate L I B O R
Derivatives
Average %		0.5175%
Interest Rate Swap | February2015 To February2017 Term One
Derivatives
Notional Amount | $	$ 75,000	$ 75,000
Interest Rate Swap | February2015 To February2017 Term One | London Interbank Offered Rate L I B O R
Derivatives
Average %	1.725%	1.725%
Interest Rate Swap | February2015 To February2017 Term Two
Derivatives
Notional Amount | $	$ 75,000	$ 75,000
Interest Rate Swap | February2015 To February2017 Term Two | London Interbank Offered Rate L I B O R
Derivatives
Average %	1.7275%	1.7275%
Interest Rate Swap | June2012 To June2015 Term
Derivatives
Notional Amount | $		$ 70,000
Interest Rate Swap | June2012 To June2015 Term | London Interbank Offered Rate L I B O R
Derivatives
Average %		0.52375%
Interest Rate Swap | June2015 To June2017 Term
Derivatives
Notional Amount | $	$ 70,000	$ 70,000
Interest Rate Swap | June2015 To June2017 Term | London Interbank Offered Rate L I B O R
Derivatives
Average %	1.4275%	1.4275%
Natural Gas Reserves | Commodity Price Swap | Derivative Contract Maturity In Year2015
Derivatives
Volume of commodity hedge (in MMBTU) | MMBTU	2,688,648	5,500,236
Weighted average price of commodity hedge (in dollars per MMBTU/BBL) | $ / MMBTU	5.75	5.72
Natural Gas Reserves | Commodity Price Swap | Derivative Contract Maturity In Year2016
Derivatives
Volume of commodity hedge (in MMBTU) | MMBTU	5,433,888	5,433,888
Weighted average price of commodity hedge (in dollars per MMBTU/BBL) | $ / MMBTU	4.29	4.29
Natural Gas Reserves | Commodity Price Swap | Derivative Contract Maturity In Year2017
Derivatives
Volume of commodity hedge (in MMBTU) | MMBTU	5,045,760	5,045,760
Weighted average price of commodity hedge (in dollars per MMBTU/BBL) | $ / MMBTU	4.61	4.61
Natural Gas Reserves | Commodity Price Swap | Derivative Contract Maturity In Year2018
Derivatives
Volume of commodity hedge (in MMBTU) | MMBTU	3,452,172	2,374,800
Weighted average price of commodity hedge (in dollars per MMBTU/BBL) | $ / MMBTU	4.05	4.28
Natural Gas Reserves | Commodity Basis Swap | Derivative Contract Maturity In Year2015
Derivatives
Volume of commodity hedge (in MMBTU) | MMBTU	2,601,807	5,326,559
Weighted average price of commodity hedge (in dollars per MMBTU/BBL) | $ / MMBTU	0.1666	0.1661
Natural Gas Reserves | Commodity Basis Swap | Derivative Contract Maturity In Year2016
Derivatives
Volume of commodity hedge (in MMBTU) | MMBTU	2,877,047	2,877,047
Weighted average price of commodity hedge (in dollars per MMBTU/BBL) | $ / MMBTU	0.1115	0.1115
Oil Reserves | Commodity Price Swap | Derivative Contract Maturity In Year2015
Derivatives
Volume of commodity hedge (in Bbl) | bbl	360,683	757,321
Weighted average price of commodity hedge (in dollars per MMBTU/BBL)	93.42	93.16
Oil Reserves | Commodity Price Swap | Derivative Contract Maturity In Year2016
Derivatives
Volume of commodity hedge (in Bbl) | bbl	610,131	610,131
Weighted average price of commodity hedge (in dollars per MMBTU/BBL)	87.27	87.27
Oil Reserves | Commodity Price Swap | Derivative Contract Maturity In Year2017
Derivatives
Volume of commodity hedge (in Bbl) | bbl	473,698	473,698
Weighted average price of commodity hedge (in dollars per MMBTU/BBL)	84.34	84.34
Oil Reserves | Commodity Price Swap | Derivative Contract Maturity In Year2018
Derivatives
Volume of commodity hedge (in Bbl) | bbl	562,524	562,524
Weighted average price of commodity hedge (in dollars per MMBTU/BBL)	82.26	82.26
Oil Reserves | Commodity Basis Swap | Derivative Contract Maturity In Year2015
Derivatives
Volume of commodity hedge (in Bbl) | bbl	187,000	397,035
Weighted average price of commodity hedge (in dollars per MMBTU/BBL)	3.2500	3.4087
Oil Reserves | Commodity Basis Swap | Derivative Contract Maturity In Year2016
Derivatives
Volume of commodity hedge (in Bbl) | bbl	364,800
Weighted average price of commodity hedge (in dollars per MMBTU/BBL)	1.05
Natural Gas Liquids Reserves | Commodity Price Swap | Derivative Contract Maturity In Year2015
Derivatives
Volume of commodity hedge (in Bbl) | bbl	112,877	236,149
Weighted average price of commodity hedge (in dollars per MMBTU/BBL)	34.45	34.46

Derivatives (Details 2)

Derivatives (Details 2) - Nondesignated - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Current Assets
Fair value of derivative instruments
Gross fair value of assets	$ 32,087	$ 45,925
Netting arrangements, assets		(1)
Net recorded fair value of assets	32,087	45,924
Long Term Assets
Fair value of derivative instruments
Gross fair value of assets	37,166	38,540
Netting arrangements, assets	(7)
Net recorded fair value of assets	37,159	38,540
Current Liabilities
Fair value of derivative instruments
Gross fair value of liabilities	783	557
Netting arrangements, liabilities		(1)
Net recorded fair value of liabilities	783	556
Long Term Liabilities
Fair value of derivative instruments
Gross fair value of liabilities	101	232
Netting arrangements, liabilities	(7)
Net recorded fair value of liabilities	94	232
Interest Rate Swap | Current Liabilities
Fair value of derivative instruments
Gross fair value of liabilities	2,781	2,327
Net recorded fair value of liabilities	2,781	2,327
Interest Rate Swap | Long Term Liabilities
Fair value of derivative instruments
Gross fair value of liabilities	960	817
Net recorded fair value of liabilities	960	817
Commodity Price Swap | Natural Gas Reserves | Current Assets
Fair value of derivative instruments
Gross fair value of assets	10,753	14,732
Commodity Price Swap | Natural Gas Reserves | Long Term Assets
Fair value of derivative instruments
Gross fair value of assets	11,022	9,170
Commodity Price Swap | Oil Reserves | Current Assets
Fair value of derivative instruments
Gross fair value of assets	19,662	27,544
Commodity Price Swap | Oil Reserves | Long Term Assets
Fair value of derivative instruments
Gross fair value of assets	26,137	29,370
Commodity Price Swap | Natural Gas Liquids Reserves | Current Assets
Fair value of derivative instruments
Gross fair value of assets	1,672	3,648
Commodity Basis Swap | Natural Gas Reserves | Current Assets
Fair value of derivative instruments
Gross fair value of assets		1
Commodity Basis Swap | Natural Gas Reserves | Current Liabilities
Fair value of derivative instruments
Gross fair value of liabilities	184	286
Commodity Basis Swap | Natural Gas Reserves | Long Term Liabilities
Fair value of derivative instruments
Gross fair value of liabilities	89	232
Commodity Basis Swap | Oil Reserves | Long Term Assets
Fair value of derivative instruments
Gross fair value of assets	7
Commodity Basis Swap | Oil Reserves | Current Liabilities
Fair value of derivative instruments
Gross fair value of liabilities	599	$ 271
Commodity Basis Swap | Oil Reserves | Long Term Liabilities
Fair value of derivative instruments
Gross fair value of liabilities	$ 12

Derivatives (Details 3)

Derivatives (Details 3) - Nondesignated - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Mar. 31, 2014	Jun. 30, 2015	Jun. 30, 2014
Commodity Contract | Sales
Unrealized and realized gain or loss amounts
Derivative instruments, gains (losses)	$ (8,927)	$ (13,328)	$ 9,755	$ (18,950)
Interest Rate Contract | Other Income and Expense
Unrealized and realized gain or loss amounts
Derivative instruments, gains (losses)	$ (322)	$ (1,128)	$ (1,673)	$ (1,422)

Related Parties (Details)

Related Parties (Details) $ in Thousands	May. 16, 2015shares	Feb. 13, 2015shares	Jun. 30, 2015USD ($)shares	Jun. 30, 2014USD ($)shares	Jun. 30, 2015USD ($)shares	Jun. 30, 2014USD ($)shares	Dec. 31, 2014shares
Related Parties
General partner units held | shares			22,400		22,400		22,400
Changes in the affiliates (payable)/receivable balances
Balance at the beginning of the period					$ 5,697
Expenditures					(90,859)
Cash paid for expenditures					93,084
Revenues and other					(6,466)
Balance at the end of the period			$ 1,456		1,456
Aggregate amount of distribution					$ 19,246	$ 26,000
Common Units
Changes in the affiliates (payable)/receivable balances
Limited partner units held | shares			28,074,433	22,674,390	28,074,433	22,674,390
Affiliated Subordinated
Related Parties
Subordinated units converted to common units | shares	2,240,000	4,480,000
Conversion ratio	1	1
Changes in the affiliates (payable)/receivable balances
Limited partner units held | shares				4,480,000		4,480,000	4,480,000
Fund I
Related Parties
Percentage of limited partner interest					30.50%
Fund I | Common Units
Related Parties
Percentage of limited partner interest					30.50%
Lime Rock Management L P
Related Parties
Payment made to related party			$ 400	$ 400	$ 800	$ 600
General Partner And Affiliates
Related Parties
Partnership interest (as a percent)					0.10%
General partner units held | shares			22,400		22,400
General Partner And Affiliates | Common Units
Changes in the affiliates (payable)/receivable balances
Limited partner units held | shares			8,569,600		8,569,600
ServCo
Changes in the affiliates (payable)/receivable balances
Balance at the beginning of the period					$ 5,436
Expenditures					(90,596)
Cash paid for expenditures					93,084
Revenues and other					(6,468)
Balance at the end of the period			$ 1,456		1,456
Lime Rock Resources
Changes in the affiliates (payable)/receivable balances
Balance at the beginning of the period					261
Expenditures					(263)
Revenues and other					$ 2

Unitholders' Equity (Details)

Unitholders' Equity (Details) - USD ($) $ in Millions	Feb. 04, 2014	Jun. 30, 2015	Dec. 31, 2014	Jun. 30, 2014
At-the-Market Offering Program
Aggregate offering amount	$ 75
Units Outstanding
General partner, units outstanding		22,400	22,400
Secured Debt
At-the-Market Offering Program
Percentage of net cash proceeds from equity offering required to be used to repay borrowings outstanding	0.50%
Fund I
Units Outstanding
Limited partner interest (as a percent)		30.50%
Common Units
Units Outstanding
Limited partner, units outstanding		28,074,433		22,674,390
Common Units | Fund I
Units Outstanding
Partner units held		8,569,600
Limited partner interest (as a percent)		30.50%

Net Income (Loss) Per Limited42

Net Income (Loss) Per Limited Partner Unit (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014
Net income (loss)			$ (47,250)	$ (4,643)
Net income (loss) available to unitholders	$ (22,314)	$ (7,337)	(47,250)	(4,643)
Less: General partner's interest in net income (loss)	7,595	7	9,434	4
Limited partners' interest in net income (loss)	$ (14,719)	$ (7,330)	$ (37,816)	$ (4,639)
Weighted average limited partner units outstanding	28,074,000	26,733,000	28,073,000	26,539,000
Net income (loss) per limited partner unit (basic and diluted) (in dollars per unit)	$ (0.52)	$ (0.27)	$ (1.35)	$ (0.17)
General Partner
Net income (loss)			$ (9,434)
Common Units
Weighted average limited partner units outstanding	28,074,000	21,121,000	26,984,000	20,376,000
Limited partner, units outstanding	28,074,433	22,674,390	28,074,433	22,674,390
Affiliated Subordinated
Weighted average limited partner units outstanding		5,612,000	1,089,000	6,163,000
Limited partner, units outstanding		4,480,000		4,480,000	4,480,000

Equity-Based Compensation (Deta

Equity-Based Compensation (Details) - Jun. 30, 2015 - USD ($) $ / shares in Units, $ in Millions	Total
Equity-Based Compensation
Number of units authorized	1,500,000
Number of units available for issuance	1,025,013
Restricted Stock
Equity-Based Compensation
Vesting period	3 years
Number of Non-vested Restricted Units
Non-vested restricted units at the beginning of the period	361,957
Granted (in units)	12,542
Vested (in units)	(32,066)
Non-vested restricted units at the end of the period	342,433
Weighted Average Grant-Date Fair Value
Non-vested restricted units at the beginning of the period	$ 9.38
Granted (in dollars per unit)	5.98
Vested (in dollars per unit)	12.53
Non-vested restricted units at the end of the period	$ 8.96
Unrecognized compensation cost related to non-vested restricted units	$ 2.3
Weighted average period over which unrecognized compensation cost is to be recognized	2 years 1 month 6 days
Number of units that have vested	132,554

Subsidiary Guarantors (Details)

Subsidiary Guarantors (Details)	6 Months Ended
	Jun. 30, 2015
L R E Finance Corporation
Subsidiary Guarantors
Ownership interest held (as a percent)	100.00%
L R E Operating L L C
Subsidiary Guarantors
Ownership interest held (as a percent)	100.00%

Subsequent Events (Details)

Subsequent Events (Details) - USD ($) $ / shares in Units, $ in Thousands	Jul. 17, 2015	Jun. 30, 2015	Jun. 30, 2014
Subsequent Events
Aggregate amount of distribution		$ 19,246	$ 26,000
Subsequent Event | Dividend Declared
Subsequent Events
Cash distribution declared per outstanding unit (in dollars per unit)	$ 0.1875
Cash distribution declared on an annualized basis (in dollars per unit)	$ 0.75
Aggregate amount of distribution	$ 5,300