LRR Energy Inactive 10-Q6 May 152015 Q1 Quarterly reportFinancial data

Company Profile

Document_and_Entity_Informatio

Document and Entity Information	3 Months Ended
Document and Entity Information	Mar. 31, 2015	1-May-15
Entity Registrant Name	LRR Energy, L.P.
Entity Central Index Key	1519632
Document Type	10-Q
Document Period End Date	31-Mar-15
Amendment Flag	FALSE
Current Fiscal Year End Date	-19
Entity Current Reporting Status	Yes
Entity Filer Category	Accelerated Filer
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	Q1
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 $)	Mar. 31, 2015	Dec. 31, 2014
In Thousands, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$2,740	$3,576
Accounts receivable	9,450	11,124
Commodity derivative instruments	43,368	45,924
Due from affiliates	6,351	5,697
Prepaid expenses	1,672	1,840
Total current assets	63,581	68,161
Property and equipment (successful efforts method)	963,400	956,326
Accumulated depletion, depreciation and impairment	-550,942	-506,368
Total property and equipment, net	412,458	449,958
Commodity derivative instruments	46,454	38,540
Deferred financing costs, net of accumulated amortization and other assets	2,295	2,295
TOTAL ASSETS	524,788	558,954
Current liabilities:
Accrued liabilities	3,613	5,506
Accrued capital cost	3,801	9,176
Commodity derivative instruments	866	556
Interest rate derivative instruments	2,750	2,327
Asset retirement obligations	1,079	1,065
Total current liabilities	12,109	18,630
Long-term liabilities:
Commodity derivative instruments	116	232
Interest rate derivative instruments	1,340	817
Term loan	50,000	50,000
Revolving credit facility	240,000	230,000
Asset retirement obligations	41,053	40,539
Deferred tax liabilities	99	99
Total long-term liabilities	332,608	321,687
Total liabilities	344,717	340,317
Unitholders' equity:
General partner (22,400 units issued and outstanding as of March 31, 2015 and December 31, 2014)	-1,540	310
Total unitholders' equity	180,071	218,637
TOTAL LIABILITIES AND UNITHOLDERS' EQUITY	524,788	558,954
Public Common
Unitholders' equity:
Limited partner	181,611	208,273
Affiliated Common
Unitholders' equity:
Limited partner		4,643
Affiliated Subordinated
Unitholders' equity:
Limited partner		$5,411

Balance_Sheets_Parenthetical

Balance Sheets (Parenthetical)	Mar. 31, 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 $)	3 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Revenues:
Oil sales	$12,064	$20,156
Natural gas sales	4,266	8,099
Natural gas liquids sales	1,171	3,364
Gain (loss) on commodity derivative instruments, net	18,682	-5,622
Other income	29	31
Total revenues	36,212	26,028
Operating expenses:
Lease operating expense	6,772	5,835
Production and ad valorem taxes	1,266	2,400
Depletion and depreciation	8,880	8,465
Impairment of oil and natural gas properties	35,706
Accretion expense	511	503
Loss (gain) on settlement of asset retirement obligations	64	40
General and administrative expense	3,791	3,182
Total operating expenses	56,990	20,425
Operating income (loss)	-20,778	5,603
Other income (expense), net
Interest expense	-2,769	-2,541
Gain (loss) on interest rate derivative instruments, net	-1,351	-294
Other income (expense), net	-4,120	-2,835
Income (loss) before taxes	-24,898	2,768
Income tax expense	-38	-74
Net income (loss)	-24,936	2,694
Net income (loss) available to unitholders	-24,936	2,694
Computation of net income (loss) per limited partner unit:
General partners' interest in net income (loss)	-1,839	3
Limited partners' interest in net income (loss)	($23,097)	$2,691
Net income (loss) per limited partner unit (basic and diluted) (in dollars per unit)	($0.82)	$0.10
Weighted average number of limited partner units outstanding (basic and diluted)	28,072	26,342

Consolidated_Statement_of_Chan

Consolidated Statement of Changes in Unitholders' Equity (USD $)	General Partner	Limited Partners	Limited Partners	Limited Partners	Total
In Thousands, unless otherwise specified	General Partner	Public Common	Affiliated Common	Affiliated 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		345			345
Conversion of subordinated units			3,182	-3,182
Distribution	-11	-9,704	-2,034	-2,229	-13,978
Net income (loss)	-1,839	-17,306	-5,791		-24,936
Balance at Mar. 31, 2015	($1,540)	$181,611			$180,071

Statements_of_Cash_Flows

Statements of Cash Flows (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	($24,936)	$2,694
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depletion and depreciation	8,880	8,465
Impairment of oil and natural gas properties	35,706
Accretion expense	511	503
Amortization of equity awards	345	285
Amortization of derivative contracts	114	157
Amortization of deferred financing costs and other	170	102
Loss (gain) on settlement of asset retirement obligations	64	40
Changes in operating assets and liabilities:
Change in receivables	1,674	-996
Change in prepaid expenses	-2	377
Change in derivative assets and liabilities	-4,331	6,082
Change in amounts due to/from affiliates	-654	-4,412
Net cash provided by (used in) operating activities	15,648	16,126
Change in accrued liabilities and deferred tax liabilities	-1,893	2,829
CASH FLOWS FROM INVESTING ACTIVITIES
Development of oil and natural gas properties	-12,280	-6,803
Acquisition of oil and natural gas properties	-229
Disposition of oil and natural gas properties		65
Net cash provided by (used in) investing activities	-12,509	-6,738
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings under revolving credit facility	10,000	10,000
Principal payments on revolving credit facility		-10,000
Equity offering, net of expenses	3	4,237
Distributions	-13,978	-12,884
Net cash provided by (used in) financing activities	-3,975	-8,647
NET INCREASE IN CASH AND CASH EQUIVALENTS	-836	741
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD	3,576	4,417
CASH AND CASH EQUIVALENTS, END OF PERIOD	$2,740	$5,158

Organization_and_Description_o

Organization and Description of Business	3 Months Ended
Organization and Description of Business	Mar. 31, 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.

Summary_of_Significant_Account

Summary of Significant Accounting Policies	3 Months Ended
Summary of Significant Accounting Policies	Mar. 31, 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 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 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”) 2014-08, “Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity.” ASU 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 2014-08 on January 1, 2015. The adoption of ASU 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 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. 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.

	On February 18, 2015, the FASB issued 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 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	3 Months Ended
	Mar. 31, 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	$	38,848
	Asset retirement obligations	(691		)
	Net assets	$	38,157

	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
		March 31, 2014
	Total revenues	$	28,343
	Net income (loss) available to unitholders	3,997
	Basic and diluted net income (loss) per unit	0.15

Fair_Value_Measurements

Fair Value Measurements	3 Months Ended
	Mar. 31, 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 March 31, 2015 and December 31, 2014 (in thousands).

		Level 1		Level 2		Level 3		Total
	March 31, 2015
	Assets:
	Commodity derivative instruments	$	—	$	89,822	$	—	$	89,822
	Liabilities:
	Commodity derivative instruments	—		982		—		982
	Interest rate derivative instruments	—		4,090		—		4,090
	December 31, 2014
	Assets:
	Commodity derivative instruments	$	—	$	84,464	$	—	$	84,464
	Liabilities:
	Commodity derivative instruments	—		788		—		788
	Interest rate derivative instruments	—		3,144		—		3,144

	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	3 Months Ended
	Mar. 31, 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):

		March 31, 2015			December 31, 2014
	Oil and natural gas properties (successful efforts method)	$	961,907		$	954,819
	Unproved properties	1,221			1,235
	Other property and equipment	272			272
		963,400			956,326
	Accumulated depletion, depreciation and impairment	(550,942		)	(506,368		)
	Total property and equipment, net	$	412,458		$	449,958

	We recorded $8.9 million and $8.5 million of depletion and depreciation expense for the three months ended March 31, 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 March 31, 2015, we recorded a total non-cash impairment charge of $35.7 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 $411.2 million as of March 31, 2015. We did not record any impairment charges in the three months ended March 31, 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, 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	3 Months Ended
	Mar. 31, 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 three months ended March 31, 2015 (in thousands):

	Beginning of period	$	41,604
	Acquisitions	14
	Revisions to previous estimates	5
	Liabilities settled	(2		)
	Accretion expense	511
	End of period	42,132
	Current portion of asset retirement obligations	(1,079		)
	Asset retirement obligations — non-current	$	41,053

LongTerm_Debt

Long-Term Debt	3 Months Ended
Long-Term Debt	Mar. 31, 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 $260 million as of March 31, 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 March 31, 2015, we were in compliance with all covenants contained in the Credit Agreement.

	In the second quarter of 2015, primarily as a result of significantly lower commodity prices, our borrowing base was reduced to $245.0 million under an amendment to our Credit Agreement. Pursuant to the amendment, the borrowing base will decrease by $1.0 million per month beginning in June 2015 and continuing until the next borrowing base redetermination in November 2015. The amendment is discussed in Note 14.

	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 March 31, 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.

	As of March 31, 2015, we had $290.0 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 March 31, 2015 and 2014 was $2.8 million and $2.5 million, respectively. As of March 31, 2015 and December 31, 2014, our weighted average interest rate on our outstanding indebtedness was 4.60% and 3.81%, respectively. Please refer to Note 8 below for a discussion of our interest rate derivative contracts.

Derivatives

Derivatives	3 Months Ended
Derivatives	Mar. 31, 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 March 31, 2015, we had the following open commodity derivative contracts:

			Index		2015			2016			2017		2018
	Natural gas positions
	Price swaps (MMBTUs)		NYMEX-HH		4,078,287			5,433,888			5,045,760		3,452,172
	Weighted average price				$	5.73		$	4.29		$	4.61	$	4.05

	Basis swaps (MMBTUs)			-1	3,948,029			2,877,047			—		—
	Weighted average price				$	(0.1663	)	$	(0.1115	)	$	—	$	—

	Oil positions
	Price swaps (BBLs)		NYMEX-WTI		553,718			610,131			473,698		562,524
	Weighted average price				$	93.27		$	87.27		$	84.34	$	82.26

	Basis swaps (BBLs)		Argus-		288,575			—			—		—
	Weighted average price		Midland-Cushing		$	(3.3556	)	$	—		$	—	$	—

	NGL positions
	Price swaps (BBLs)		Mont Belvieu		173,042			—			—		—
	Weighted average price				$	34.45		$	—		$	—	$	—


		-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 (MMBTUs)		NYMEX-HH		5,500,236			5,433,888			5,045,760		2,374,800
	Weighted average price				$	5.72		$	4.29		$	4.61	$	4.28

	Basis swaps (MMBTUs)			-1	5,326,559			2,877,047			—		—
	Weighted average price				$	(0.1661	)	$	(0.1115	)	$	—	$	—

	Oil positions
	Price swaps (BBLs)		NYMEX-WTI		757,321			610,131			473,698		562,524
	Weighted average price				$	93.16		$	87.27		$	84.34	$	82.26

	Basis swaps (BBLs)		Argus-		397,035			—			—		—
	Weighted average price		Midland-Cushing		$	(3.4087	)	$	—		$	—	$	—

	NGL positions
	Price swaps (BBLs)		Mont Belvieu		236,149			—			—		—
	Weighted average price				$	34.46		$	—		$	—	$	—


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

	At March 31, 2015, we had the following interest rate swap derivative contracts (in thousands):

					Notional
	Effective		Maturity		Amount		Average %		Index
	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

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		$	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 March 31, 2015
		Current			Long-term			Current			Long-term
		Assets			Assets			Liabilities			Liabilities
Interest rate
Swaps		$	—		$	—		$	2,750		$	1,340
Gross fair value		—			—			2,750			1,340
Netting arrangements		—			—			—			—
Net recorded fair value		$	—		$	—		$	2,750		$	1,340

Sale of natural gas production
Price swaps		$	13,536		$	12,897		$	—		$	—
Basis swaps		35			—			140			116
Sale of crude oil production
Price swaps		27,181			33,557			—			—
Basis swaps		—			—			749			—
Sale of NGLs
Price swaps		2,639			—			—			—
Gross fair value		43,391			46,454			889			116
Netting arrangements		(23		)	—			(23		)	—
Net recorded fair value		$	43,368		$	46,454		$	866		$	116

		As of December 31, 2014
		Current			Long-term			Current			Long-term
		Assets			Assets			Liabilities			Liabilities
Interest rate
Swaps		$	—		$	—		$	2,327		$	817
Gross fair value		—			—			2,327			817
Netting arrangements		—			—			—			—
Net recorded fair value		$	—		$	—		$	2,327		$	817

Sale of natural gas production
Price swaps		$	14,732		$	9,170		$	—		$	—
Basis swaps		1			—			286			232
Sale of crude oil production
Price swaps		27,544			29,370			—			—
Basis swaps		—			—			271			—
Sale of NGLs
Price swaps		3,648			—			—			—
Gross fair value		45,925			38,540			557			232
Netting arrangements		(1		)	—			(1		)	—
Net recorded fair value		$	45,924		$	38,540		$	556		$	232

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 March 31,
		2015			2014
Commodity derivatives (revenue)		$	18,682		$	(5,622	)
Interest rate derivatives (other income (expense), net)		(1,351		)	(294		)

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	3 Months Ended
	Mar. 31, 2015
Related Parties
Related Parties
	9.Related Parties

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

	As of March 31, 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 March 31, 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 the three months ended March 31, 2015 and 2014, we paid Lime Rock Management approximately $0.4 million and $0.2 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 three months ended March 31, 2015 are included below (in thousands):

					Lime Rock
		ServCo			Resources			Total

	Balance as of December 31, 2014	$	5,436		$	261		$	5,697
	Expenditures	(46,820		)	(263		)	(47,083		)
	Cash paid for expenditures	50,837			—			50,837
	Revenues and other	(3,102		)	2			(3,100		)
	Balance as of March 31, 2015	$	6,351		$	—		$	6,351

	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 March 31, 2015, our general partner and its affiliates held 8,569,600 of our common units and 22,400 general partner units. During the three months ended March 31, 2015 and 2014, we paid cash distributions of $14.0 million and $12.9 million, respectively, to all unitholders as of the respective record dates.

	We announced our first quarter 2015 distribution on April 20, 2015 as discussed in Note 14.

Unitholders_Equity

Unitholders' Equity	3 Months Ended
Unitholders' Equity	Mar. 31, 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 14). 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 three months ended March 31, 2015, we did not sell common units under the ATM Program.

	Units Outstanding

	As of March 31, 2015, we had 28,074,433 common units and 22,400 general partner units outstanding. As of March 31, 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_Pa

Net Income (Loss) Per Limited Partner Unit	3 Months Ended
	Mar. 31, 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 March 31,
		2015			2014
	Net income (loss) available to unitholders	$	(24,936	)	$	2,694
	Less: General partner’s interest in net (income) loss	1,839			(3		)
	Limited partners’ interest in net income (loss)	$	(23,097	)	$	2,691

	Weighted average limited partner units outstanding:
	Common units	25,882			19,622
	Subordinated units	2,190			6,720
	Total	28,072			26,342

	Net income (loss) per limited partner unit (basic and diluted)	$	(0.82	)	$	0.1

	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 March 31, 2015 and 2014. The aggregate number of common units outstanding was 28,074,433, as of March 31, 2015. We did not have any subordinated units outstanding as of March 31, 2015. The aggregate number of common units and subordinated units outstanding was 19,812,246 and 6,720,000, respectively, as of March 31, 2014.

EquityBased_Compensation

Equity-Based Compensation	3 Months Ended
	Mar. 31, 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 March 31, 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 March 31, 2015 is presented below:

		Number of		Weighted Average
		Non-vested		Grant-date
		Restricted Units		Fair Value
	Non-vested restricted units at December 31, 2014	361,957		$	9.38
	Granted	12,542		5.98
	Vested	(11,203	)	18.01
	Forfeited	—		—
	Non-vested restricted units at March 31, 2015	363,296		9

	As of March 31, 2015, there was approximately $2.8 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 2.3 years. There were 111,691 vested restricted units as of March 31, 2015.

Subsidiary_Guarantors

Subsidiary Guarantors	3 Months Ended
Subsidiary Guarantors	Mar. 31, 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.

Subsequent_Events

Subsequent Events	3 Months Ended
Subsequent Events	Mar. 31, 2015
Subsequent Events
Subsequent Events	14.Subsequent Events

	Unit Distribution

	On April 20, 2015, we announced that the board of directors of our general partner declared a cash distribution for the first quarter of 2015 of $0.1875 per outstanding unit, or $0.75 on an annualized basis. The distribution will be paid on May 15, 2015 to all unitholders of record as of the close of business on May 1, 2015. The aggregate amount of the distribution will be $5.3 million.

	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 our General Partner (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.

	Amendments to the Credit Agreement and Term Loan Agreement

	On May 4, 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 having a minimum of 15% availability under a conforming borrowing base amount after the distribution has been paid, and (iv) decreased the borrowing base to $245.0 million. Pursuant to the amendment, the borrowing base will 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. If the next scheduled redetermination has not occurred by November 1, 2015, the borrowing base shall decrease to $195.0 million until the scheduled redetermination is completed.

	On May 4, 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. In connection with the Fifth Term Loan Amendment, we received a waiver on our asset coverage test ratio as discussed in Note 7.

Summary_of_Significant_Account1

Summary of Significant Accounting Policies (Policies)	3 Months Ended
Summary of Significant Accounting Policies (Policies)	Mar. 31, 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 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 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”) 2014-08, “Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity.” ASU 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 2014-08 on January 1, 2015. The adoption of ASU 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 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. 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.

	On February 18, 2015, the FASB issued 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 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)	3 Months Ended
	Mar. 31, 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
		March 31, 2014
	Total revenues	$	28,343
	Net income (loss) available to unitholders	3,997
	Basic and diluted net income (loss) per unit	0.15


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	$	38,848
	Asset retirement obligations	(691		)
	Net assets	$	38,157

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	3 Months Ended
	Mar. 31, 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 March 31, 2015 and December 31, 2014 (in thousands).

		Level 1		Level 2		Level 3		Total
	March 31, 2015
	Assets:
	Commodity derivative instruments	$	—	$	89,822	$	—	$	89,822
	Liabilities:
	Commodity derivative instruments	—		982		—		982
	Interest rate derivative instruments	—		4,090		—		4,090
	December 31, 2014
	Assets:
	Commodity derivative instruments	$	—	$	84,464	$	—	$	84,464
	Liabilities:
	Commodity derivative instruments	—		788		—		788
	Interest rate derivative instruments	—		3,144		—		3,144

Property_and_Equipment_Tables

Property and Equipment (Tables)	3 Months Ended
	Mar. 31, 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):

		March 31, 2015			December 31, 2014
	Oil and natural gas properties (successful efforts method)	$	961,907		$	954,819
	Unproved properties	1,221			1,235
	Other property and equipment	272			272
		963,400			956,326
	Accumulated depletion, depreciation and impairment	(550,942		)	(506,368		)
	Total property and equipment, net	$	412,458		$	449,958

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	3 Months Ended
	Mar. 31, 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 three months ended March 31, 2015 (in thousands):

	Beginning of period	$	41,604
	Acquisitions	14
	Revisions to previous estimates	5
	Liabilities settled	(2		)
	Accretion expense	511
	End of period	42,132
	Current portion of asset retirement obligations	(1,079		)
	Asset retirement obligations — non-current	$	41,053

Derivatives_Tables

Derivatives (Tables)	3 Months Ended
Derivatives (Tables)	Mar. 31, 2015
Derivatives
Schedule of open commodity derivative contracts
	At March 31, 2015, we had the following open commodity derivative contracts:

			Index		2015			2016			2017			2018
	Natural gas positions
	Price swaps (MMBTUs)		NYMEX-HH		4,078,287			5,433,888			5,045,760			3,452,172
	Weighted average price				$	5.73		$	4.29		$	4.61		$	4.05

	Basis swaps (MMBTUs)			-1	3,948,029			2,877,047			—			—
	Weighted average price				$	(0.1663	)	$	(0.1115	)	$	—		$	—

	Oil positions
	Price swaps (BBLs)		NYMEX-WTI		553,718			610,131			473,698			562,524
	Weighted average price				$	93.27		$	87.27		$	84.34		$	82.26

	Basis swaps (BBLs)		Argus-		288,575			—			—			—
	Weighted average price		Midland-Cushing		$	(3.3556	)	$	—		$	—		$	—

	NGL positions
	Price swaps (BBLs)		Mont Belvieu		173,042			—			—			—
	Weighted average price				$	34.45		$	—		$	—		$	—


		-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 (MMBTUs)		NYMEX-HH		5,500,236			5,433,888			5,045,760			2,374,800
	Weighted average price				$	5.72		$	4.29		$	4.61		$	4.28

	Basis swaps (MMBTUs)			-1	5,326,559			2,877,047			—			—
	Weighted average price				$	(0.1661	)	$	(0.1115	)	$	—		$	—

	Oil positions
	Price swaps (BBLs)		NYMEX-WTI		757,321			610,131			473,698			562,524
	Weighted average price				$	93.16		$	87.27		$	84.34		$	82.26

	Basis swaps (BBLs)		Argus-		397,035			—			—			—
	Weighted average price		Midland-Cushing		$	(3.4087	)	$	—		$	—		$	—

	NGL positions
	Price swaps (BBLs)		Mont Belvieu		236,149			—			—			—
	Weighted average price				$	34.46		$	—		$	—		$	—


		-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 March 31, 2015, we had the following interest rate swap derivative contracts (in thousands):

					Notional
	Effective		Maturity		Amount		Average %		Index
	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

	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		$	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


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 March 31, 2015
			Current			Long-term			Current			Long-term
			Assets			Assets			Liabilities			Liabilities
	Interest rate
	Swaps		$	—		$	—		$	2,750		$	1,340
	Gross fair value		—			—			2,750			1,340
	Netting arrangements		—			—			—			—
	Net recorded fair value		$	—		$	—		$	2,750		$	1,340

	Sale of natural gas production
	Price swaps		$	13,536		$	12,897		$	—		$	—
	Basis swaps		35			—			140			116
	Sale of crude oil production
	Price swaps		27,181			33,557			—			—
	Basis swaps		—			—			749			—
	Sale of NGLs
	Price swaps		2,639			—			—			—
	Gross fair value		43,391			46,454			889			116
	Netting arrangements		(23		)	—			(23		)	—
	Net recorded fair value		$	43,368		$	46,454		$	866		$	116

			As of December 31, 2014
			Current			Long-term			Current			Long-term
			Assets			Assets			Liabilities			Liabilities
	Interest rate
	Swaps		$	—		$	—		$	2,327		$	817
	Gross fair value		—			—			2,327			817
	Netting arrangements		—			—			—			—
	Net recorded fair value		$	—		$	—		$	2,327		$	817

	Sale of natural gas production
	Price swaps		$	14,732		$	9,170		$	—		$	—
	Basis swaps		1			—			286			232
	Sale of crude oil production
	Price swaps		27,544			29,370			—			—
	Basis swaps		—			—			271			—
	Sale of NGLs
	Price swaps		3,648			—			—			—
	Gross fair value		45,925			38,540			557			232
	Netting arrangements		(1		)	—			(1		)	—
	Net recorded fair value		$	45,924		$	38,540		$	556		$	232


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 March 31,
			2015			2014
	Commodity derivatives (revenue)		$	18,682		$	(5,622	)
	Interest rate derivatives (other income (expense), net)		(1,351		)	(294		)

Related_Parties_Tables

Related Parties (Tables)	3 Months Ended
	Mar. 31, 2015
Related Parties
Schedule of changes in the affiliates (payable)/receivable balances
	Changes in the affiliates (payable)/receivable balances during the three months ended March 31, 2015 are included below (in thousands):

					Lime Rock
		ServCo			Resources			Total

	Balance as of December 31, 2014	$	5,436		$	261		$	5,697
	Expenditures	(46,820		)	(263		)	(47,083		)
	Cash paid for expenditures	50,837			—			50,837
	Revenues and other	(3,102		)	2			(3,100		)
	Balance as of March 31, 2015	$	6,351		$	—		$	6,351

Net_Income_Loss_Per_Limited_Pa1

Net Income (Loss) Per Limited Partner Unit (Tables)	3 Months Ended
	Mar. 31, 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 March 31,
		2015			2014
	Net income (loss) available to unitholders	$	(24,936	)	$	2,694
	Less: General partner’s interest in net (income) loss	1,839			(3		)
	Limited partners’ interest in net income (loss)	$	(23,097	)	$	2,691

	Weighted average limited partner units outstanding:
	Common units	25,882			19,622
	Subordinated units	2,190			6,720
	Total	28,072			26,342

	Net income (loss) per limited partner unit (basic and diluted)	$	(0.82	)	$	0.1

EquityBased_Compensation_Table

Equity-Based Compensation (Tables)	3 Months Ended
Equity-Based Compensation (Tables)	Mar. 31, 2015
Equity-Based Compensation
Summary of the non-vested restricted units
	A summary of the status of the non-vested restricted units as of March 31, 2015 is presented below:

		Number of		Weighted Average
		Non-vested		Grant-date
		Restricted Units		Fair Value
	Non-vested restricted units at December 31, 2014	361,957		$	9.38
	Granted	12,542		5.98
	Vested	(11,203	)	18.01
	Forfeited	—		—
	Non-vested restricted units at March 31, 2015	363,296		9

Organization_and_Description_o1

Organization and Description of Business (Details) (L R E Finance Corporation)	3 Months Ended
	Mar. 31, 2015
L R E Finance Corporation
Description of Business
Ownership interest held (as a percent)	100.00%

Acquisitions_Details

Acquisitions (Details) (USD $)	3 Months Ended
Acquisitions (Details) (USD $)	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014	Oct. 31, 2014	Jan. 31, 2015	Oct. 01, 2014
Acquisitions
Payments of Capital Distribution	$13,978,000	$12,884,000
Net assets conveyed by Fund I to the Partnership in the Transaction
Assets	524,788,000		558,954,000
Outstanding debt	290,000,000		280,000,000
Asset retirement obligations	42,132,000		41,604,000
Results of operations attributable to acquisition
Revenues	36,212,000	26,028,000
Net income (loss)	-24,936,000	2,694,000
Unaudited pro forma information
Total revenues		28,343,000
Net income (loss) available to unitholders		3,997,000
Basic and diluted net income (loss) per unit		$0.15
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				38,848,000
Asset retirement obligations and other liabilities				-691,000
Net assets				38,157,000
Oil And Natural Gas Properties In Mid Continent Region In Oklahoma \| Fund I
Acquisitions
Purchase price					$200,000	$38,000,000

Fair_Value_Measurements_Detail

Fair Value Measurements (Details) (Fair Value Measurements Recurring, USD $)	Mar. 31, 2015	Dec. 31, 2014
In Thousands, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Level 2 \| Commodity Contract
Fair Value Measurements
Assets	$89,822	$84,464
Liabilities	982	788
Level 2 \| Interest Rate Contract
Fair Value Measurements
Liabilities	4,090	3,144
Estimate Of Fair Value Fair Value Disclosure [Member] \| Commodity Contract
Fair Value Measurements
Assets	89,822	84,464
Liabilities	982	788
Estimate Of Fair Value Fair Value Disclosure [Member] \| Interest Rate Contract
Fair Value Measurements
Liabilities	$4,090	$3,144

Property_and_Equipment_Details

Property and Equipment (Details) (USD $)	3 Months Ended
Property and Equipment (Details) (USD $)	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014
Property and Equipment
Oil and natural gas properties (successful efforts method)	$961,907,000		$954,819,000
Unproved properties	1,221,000		1,235,000
Other property and equipment	272,000		272,000
Property and equipment, gross	963,400,000		956,326,000
Accumulated depletion, depreciation and impairment	-550,942,000		-506,368,000
Total property and equipment, net	412,458,000		449,958,000
Depletion and depreciation expense	8,880,000	8,465,000
Non-cash impairment charges	35,706,000
Estimate fair value	$411,200,000

Asset_Retirement_Obligations_D

Asset Retirement Obligations (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014
Asset retirement obligations
Beginning of period	$41,604
Acquisitions	14
Revisions to previous estimates	5
Liabilities settled	-2
Accretion expense	511	503
End of period	42,132
Current portion of asset retirement obligations	-1,079		-1,065
Asset retirement obligation-non-current	$41,053		$40,539

LongTerm_Debt_Details

Long-Term Debt (Details) (USD $)	3 Months Ended		1 Months Ended		0 Months Ended
Long-Term Debt (Details) (USD $)	Mar. 31, 2015	Mar. 31, 2014	Jul. 31, 2011	Jun. 30, 2015	4-May-15	Feb. 04, 2014	Jun. 28, 2012	Dec. 31, 2014
Long-Term Debt
Outstanding debt	$290,000,000							$280,000,000
Accrued interest	200,000							200,000
Interest expense	2,769,000	2,541,000
Weighted average interest rate (as a percent)	4.60%							3.81%
Revolving Credit Facility
Long-Term Debt
Term of credit facility			5 years
Maximum borrowing capacity			750,000,000
Borrowing capacity	260,000,000
Revolving Credit Facility \| Subsequent Event
Long-Term Debt
Borrowing capacity				245,000,000	245,000,000
Decrease in capacity per month				1,000,000
Revolving Credit Facility \| Minimum \| Subsequent Event
Long-Term Debt
Commitment fee on unused portion (as a percent)					0.38%
Revolving Credit Facility \| Maximum
Long-Term Debt
Maximum limit on borrowing capacity	500,000,000
Revolving Credit Facility \| Maximum \| Subsequent Event
Long-Term Debt
Commitment fee on unused portion (as a percent)					0.80%
Secured Debt
Long-Term Debt
Face amount							50,000,000
Amount borrowed							$50,000,000
Percentage of net cash proceeds from equity offering required to be used to repay borrowings outstanding						0.50%

Derivatives_Details

Derivatives (Details) (USD $)	3 Months Ended	12 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
	MMBTU	MMBTU
Commodity Basis Swap
Derivatives
Number of indices for gas on which floating price is based	2
Interest Rate Swap [Member] \| February2012 To February2015 Term [Member]
Derivatives
Notional Amount		$150,000
Interest Rate Swap [Member] \| February2012 To February2015 Term [Member] \| London Interbank Offered Rate L I B O R
Derivatives
Average %		0.52%
Interest Rate Swap [Member] \| February2015 To February2017 Term One [Member]
Derivatives
Notional Amount	75,000	75,000
Interest Rate Swap [Member] \| February2015 To February2017 Term One [Member] \| London Interbank Offered Rate L I B O R
Derivatives
Average %	1.73%	1.73%
Interest Rate Swap [Member] \| February2015 To February2017 Term Two [Member]
Derivatives
Notional Amount	75,000	75,000
Interest Rate Swap [Member] \| February2015 To February2017 Term Two [Member] \| London Interbank Offered Rate L I B O R
Derivatives
Average %	1.73%	1.73%
Interest Rate Swap [Member] \| June2012 To June2015 Term [Member]
Derivatives
Notional Amount	70,000	70,000
Interest Rate Swap [Member] \| June2012 To June2015 Term [Member] \| London Interbank Offered Rate L I B O R
Derivatives
Average %	0.52%	0.52%
Interest Rate Swap [Member] \| June2015 To June2017 Term [Member]
Derivatives
Notional Amount	$70,000	$70,000
Interest Rate Swap [Member] \| June2015 To June2017 Term [Member] \| London Interbank Offered Rate L I B O R
Derivatives
Average %	1.43%	1.43%
Natural Gas Reserves \| Commodity Price Swap \| Derivative Contract Maturity In Year2015
Derivatives
Volume of commodity hedge (in MMBTUs)	4,078,287	5,500,236
Weighted average price of commodity hedge (in dollars per MMBTU/BBL)	5.73	5.72
Natural Gas Reserves \| Commodity Price Swap \| Derivative Contract Maturity In Year2016
Derivatives
Volume of commodity hedge (in MMBTUs)	5,433,888	5,433,888
Weighted average price of commodity hedge (in dollars per MMBTU/BBL)	4.29	4.29
Natural Gas Reserves \| Commodity Price Swap \| Derivative Contract Maturity In Year2017 [Member]
Derivatives
Volume of commodity hedge (in MMBTUs)	5,045,760	5,045,760
Weighted average price of commodity hedge (in dollars per MMBTU/BBL)	4.61	4.61
Natural Gas Reserves \| Commodity Price Swap \| Derivative Contract Maturity In Year2018 [Member]
Derivatives
Volume of commodity hedge (in MMBTUs)	3,452,172	2,374,800
Weighted average price of commodity hedge (in dollars per MMBTU/BBL)	4.05	4.28
Natural Gas Reserves \| Commodity Basis Swap \| Derivative Contract Maturity In Year2015
Derivatives
Volume of commodity hedge (in MMBTUs)	3,948,029	5,326,559
Weighted average price of commodity hedge (in dollars per MMBTU/BBL)	-0.1663	-0.1661
Natural Gas Reserves \| Commodity Basis Swap \| Derivative Contract Maturity In Year2016
Derivatives
Volume of commodity hedge (in MMBTUs)	2,877,047	2,877,047
Weighted average price of commodity hedge (in dollars per MMBTU/BBL)	-0.1115	-0.1115
Oil Reserves \| Commodity Price Swap \| Derivative Contract Maturity In Year2015
Derivatives
Volume of commodity hedge (in BBLs)	553,718	757,321
Weighted average price of commodity hedge (in dollars per MMBTU/BBL)	93.27	93.16
Oil Reserves \| Commodity Price Swap \| Derivative Contract Maturity In Year2016
Derivatives
Volume of commodity hedge (in BBLs)	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 [Member]
Derivatives
Volume of commodity hedge (in BBLs)	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 [Member]
Derivatives
Volume of commodity hedge (in BBLs)	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 BBLs)	288,575	397,035
Weighted average price of commodity hedge (in dollars per MMBTU/BBL)	-3.3556	-3.4087
Natural Gas Liquids Reserves \| Commodity Price Swap \| Derivative Contract Maturity In Year2015
Derivatives
Volume of commodity hedge (in BBLs)	173,042	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 $)	Mar. 31, 2015	Dec. 31, 2014
In Thousands, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Current Assets [Member]
Fair value of derivative instruments
Gross fair value of assets	$43,391	$45,925
Netting arrangements, assets	-23	-1
Net recorded fair value of assets	43,368	45,924
Long Term Assets [Member]
Fair value of derivative instruments
Gross fair value of assets	46,454	38,540
Net recorded fair value of assets	46,454	38,540
Current Liabilities [Member]
Fair value of derivative instruments
Gross fair value of liabilities	889	557
Netting arrangements, liabilities	-23	-1
Net recorded fair value of liabilities	866	556
Long Term Liabilities [Member]
Fair value of derivative instruments
Gross fair value of liabilities	116	232
Net recorded fair value of liabilities	116	232
Interest Rate Swap [Member] \| Current Liabilities [Member]
Fair value of derivative instruments
Gross fair value of liabilities	2,750	2,327
Net recorded fair value of liabilities	2,750	2,327
Interest Rate Swap [Member] \| Long Term Liabilities [Member]
Fair value of derivative instruments
Gross fair value of liabilities	1,340	817
Net recorded fair value of liabilities	1,340	817
Commodity Price Swap \| Natural Gas Reserves \| Current Assets [Member]
Fair value of derivative instruments
Gross fair value of assets	13,536	14,732
Commodity Price Swap \| Natural Gas Reserves \| Long Term Assets [Member]
Fair value of derivative instruments
Gross fair value of assets	12,897	9,170
Commodity Price Swap \| Oil Reserves \| Current Assets [Member]
Fair value of derivative instruments
Gross fair value of assets	27,181	27,544
Commodity Price Swap \| Oil Reserves \| Long Term Assets [Member]
Fair value of derivative instruments
Gross fair value of assets	33,557	29,370
Commodity Price Swap \| Natural Gas Liquids Reserves \| Current Assets [Member]
Fair value of derivative instruments
Gross fair value of assets	2,639	3,648
Commodity Basis Swap \| Natural Gas Reserves \| Current Assets [Member]
Fair value of derivative instruments
Gross fair value of assets	35	1
Commodity Basis Swap \| Natural Gas Reserves \| Current Liabilities [Member]
Fair value of derivative instruments
Gross fair value of liabilities	140	286
Commodity Basis Swap \| Natural Gas Reserves \| Long Term Liabilities [Member]
Fair value of derivative instruments
Gross fair value of liabilities	116	232
Commodity Basis Swap \| Oil Reserves \| Current Liabilities [Member]
Fair value of derivative instruments
Gross fair value of liabilities	$749	$271

Derivatives_Details_3

Derivatives (Details 3) (Nondesignated, USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Commodity Contract \| Sales
Unrealized and realized gain or loss amounts
Derivative instruments, gains (losses)	$18,682	($5,622)
Interest Rate Contract \| Other Income and Expense
Unrealized and realized gain or loss amounts
Derivative instruments, gains (losses)	($1,351)	($294)

Related_Parties_Details

Related Parties (Details) (USD $)	3 Months Ended		0 Months Ended
Related Parties (Details) (USD $)	Mar. 31, 2015	Mar. 31, 2014	16-May-15	Feb. 13, 2015	Dec. 31, 2014
Related Parties
General partner units held	22,400				22,400
Changes in the affiliates (payable)/receivable balances
Balance at the beginning of the period	$5,697,000
Expenditures	-47,083,000
Cash paid for expenditures	50,837,000
Revenues and other	-3,100,000
Balance at the end of the period	6,351,000
Aggregate amount of distribution	13,978,000	12,900,000
Common Units
Changes in the affiliates (payable)/receivable balances
Limited partner units held	28,074,433	19,812,246
Affiliated Subordinated
Related Parties
Subordinated units converted to common units			2,240,000	4,480,000
Conversion ratio			1	1
Changes in the affiliates (payable)/receivable balances
Limited partner units held		6,720,000			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	400,000	200,000
General Partner And Affiliates
Related Parties
Partnership interest (as a percent)	0.10%
General partner units held	22,400
General Partner And Affiliates \| Common Units
Changes in the affiliates (payable)/receivable balances
Limited partner units held	8,569,600
ServCo
Changes in the affiliates (payable)/receivable balances
Balance at the beginning of the period	5,436,000
Expenditures	-46,820,000
Cash paid for expenditures	50,837,000
Revenues and other	-3,102,000
Balance at the end of the period	6,351,000
Lime Rock Resources
Changes in the affiliates (payable)/receivable balances
Balance at the beginning of the period	261,000
Expenditures	-263,000
Revenues and other	$2,000

Unitholders_Equity_Details

Unitholders' Equity (Details) (USD $)	3 Months Ended		0 Months Ended
Unitholders' Equity (Details) (USD $)	Mar. 31, 2015	Mar. 31, 2014	Feb. 04, 2014	Dec. 31, 2014	Jul. 31, 2011
At-the-Market Offering Program
Aggregate offering amount			75,000,000
Net proceeds from the sale of common units in equity offering	3,000
Borrowings under revolving credit facility	10,000,000	10,000,000
Distributions	13,978,000	12,884,000
Units Outstanding
General partner, units outstanding	22,400			22,400
Revolving Credit Facility
At-the-Market Offering Program
Maximum borrowing capacity					$750,000,000
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	19,812,246
Common Units \| Fund I
Units Outstanding
Partner units held	8,569,600
Limited partner interest (as a percent)	30.50%
Affiliated Subordinated
Units Outstanding
Limited partner, units outstanding		6,720,000		4,480,000

Net_Income_Loss_Per_Limited_Pa2

Net Income (Loss) Per Limited Partner Unit (Details) (USD $)	3 Months Ended
In Thousands, except Share data, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014
Net income (loss)	-24,936	2,694
Net income (loss) available to unitholders	-24,936	2,694
Less: General partner's interest in net income (loss)	1,839	-3
Limited partners' interest in net income (loss)	-23,097	2,691
Weighted average limited partner units outstanding	28,072,000	26,342,000
Net income (loss) per limited partner unit (basic and diluted) (in dollars per unit)	-0.82	0.1
General Partner
Net income (loss)	-1,839
Common Units
Weighted average limited partner units outstanding	25,882,000	19,622,000
Limited partner, units outstanding	28,074,433	19,812,246
Affiliated Subordinated
Weighted average limited partner units outstanding	2,190,000	6,720,000
Limited partner, units outstanding		6,720,000	4,480,000

EquityBased_Compensation_Detai

Equity-Based Compensation (Details) (USD $)	3 Months Ended
In Millions, except Share data, unless otherwise specified	Mar. 31, 2015
Equity-Based Compensation
Number of units authorized	1,500,000
Number of units available for issuance	1,025,013
Restricted Stock [Member]
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)	-11,203
Non-vested restricted units at the end of the period	363,296
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)	$18.01
Non-vested restricted units at the end of the period	$9
Unrecognized compensation cost related to non-vested restricted units	$2.80
Weighted average period over which unrecognized compensation cost is to be recognized	2 years 3 months 18 days
Number of units that have vested	111,691

Subsidiary_Guarantors_Details

Subsidiary Guarantors (Details)	3 Months Ended
Subsidiary Guarantors (Details)	Mar. 31, 2015
L R E Finance Corporation
Subsidiary Guarantors
Ownership interest held (as a percent)	100.00%
L R E Operating L L C [Member]
Subsidiary Guarantors
Ownership interest held (as a percent)	100.00%

Subsequent_Events_Details

Subsequent Events (Details) (USD $)	3 Months Ended		0 Months Ended	1 Months Ended	0 Months Ended
Subsequent Events (Details) (USD $)	Mar. 31, 2015	Mar. 31, 2014	4-May-15	Jun. 30, 2015	Apr. 20, 2015
Subsequent Events
Aggregate amount of distribution	$13,978,000	$12,900,000
General Partner
Subsequent Events
Aggregate amount of distribution	11,000
Revolving Credit Facility
Subsequent Events
Borrowing capacity	260,000,000
Subsequent Event \| Revolving Credit Facility
Subsequent Events
Restricted payment distributions			10,600,000
Percentage of distributions subject to availability of borrowing base amount			15.00%
Borrowing capacity			245,000,000	245,000,000
Decrease in capacity per month				1,000,000
Subsequent Event \| Revolving Credit Facility \| Maximum
Subsequent Events
Fee on unused portion of borrowing base (as a percent)			0.80%
Subsequent Event \| Revolving Credit Facility \| Minimum
Subsequent Events
Fee on unused portion of borrowing base (as a percent)			0.38%
Subsequent Event \| Revolving Credit Facility \| Merger Agreement
Subsequent Events
Borrowing capacity upon termination of merger agreement			195,000,000
Subsequent Event \| Revolving Credit Facility \| Eurodollar \| Maximum
Subsequent Events
Interest rate margin (as a percent)			3.10%
Subsequent Event \| Revolving Credit Facility \| Eurodollar \| Minimum
Subsequent Events
Interest rate margin (as a percent)			2.00%
Subsequent Event \| Revolving Credit Facility \| Alternate Base Rate \| Maximum
Subsequent Events
Interest rate margin (as a percent)			2.10%
Subsequent Event \| Revolving Credit Facility \| Alternate Base Rate \| Minimum
Subsequent Events
Interest rate margin (as a percent)			1.00%
Subsequent Event \| Secured Debt
Subsequent Events
Restricted payment distributions			10,600,000
Percentage of distributions subject to availability of borrowing base amount			15.00%
Subsequent Event \| Secured Debt \| Eurodollar
Subsequent Events
Interest rate (as percent)			9.50%
Subsequent Event \| Secured Debt \| Alternate Base Rate
Subsequent Events
Interest rate (as percent)			8.50%
Subsequent Event \| Vanguard \| Merger Agreement
Subsequent Events
Termination fee that will be paid upon the termination of the Merger Agreement under specified circumstances					7,300,000
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					1,200,000
Subsequent Event \| Vanguard \| Common Units \| Merger Agreement
Subsequent Events
Number of Vanguard Units that each common unit of the entity will be converted to at the effective time of the Merger					0.55
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
Subsequent Event \| Vanguard \| General Partner \| Merger Agreement
Subsequent Events
Aggregate number of Vanguard Units that will be issued on the Closing Date of the Merger, which represents the GP Equity Consideration					12,320
Subsequent Event \| Dividend Declared
Subsequent Events
Cash distribution declared per outstanding unit (in dollars per unit)					$0.19
Cash distribution declared on an annualized basis (in dollars per unit)					$0.75
Aggregate amount of distribution					$5,300,000