LRR Energy Inactive 10-K12 Mar 142013 FY Annual reportFinancial data

Company Profile

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
Document and Entity Information (USD $)	Dec. 31, 2013	Mar. 07, 2014	Jun. 28, 2013
Entity Registrant Name	'LRR Energy, L.P.	'	'
Entity Central Index Key	'0001519632	'	'
Document Type	'10-K	'	'
Document Period End Date	31-Dec-13	'	'
Amendment Flag	'false	'	'
Current Fiscal Year End Date	'--12-31	'	'
Entity Well-known Seasoned Issuer	'No	'	'
Entity Voluntary Filers	'No	'	'
Entity Current Reporting Status	'Yes	'	'
Entity Filer Category	'Accelerated Filer	'	'
Entity Public Float	'	'	$256,216,070
Entity Common Stock, Shares Outstanding	'	0	'
Document Fiscal Year Focus	'2013	'	'
Document Fiscal Period Focus	'FY	'	'
Partnership Interest \| General Partner	'	'	'
Entity Common Stock, Shares Outstanding	'	22,400	'
Partnership Interest \| Limited Partners \| Common Units	'	'	'
Entity Common Stock, Shares Outstanding	'	19,667,295	'
Partnership Interest \| Limited Partners \| Subordinated Units	'	'	'
Entity Common Stock, Shares Outstanding	'	6,720,000	'

Balance_Sheets

Balance Sheets (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Current assets:	'	'
Cash and cash equivalents	$4,417	$3,467
Accounts receivable	9,867	7,250
Commodity derivative instruments	9,726	16,484
Prepaid expenses	1,603	748
Total current assets	25,613	27,949
Property and equipment (successful efforts method)	876,674	840,736
Accumulated depletion, depreciation and impairment	-431,837	-324,774
Total property and equipment, net	444,837	515,962
Commodity derivative instruments	16,746	20,000
Deferred financing costs, net of accumulated amortization and other	1,154	1,559
TOTAL ASSETS	488,350	565,470
Current liabilities:	'	'
Accrued liabilities	2,300	1,415
Accrued capital cost	2,574	2,361
Due to affiliates	255	1,977
Commodity derivative instruments	2,217	1,671
Interest rate derivative instruments	648	659
Asset retirement obligations	488	500
Total current liabilities	8,482	8,583
Long-term liabilities:	'	'
Commodity derivative instruments	174	874
Interest rate derivative instruments	1,554	3,526
Term loan	50,000	50,000
Revolving credit facility	200,000	178,000
Asset retirement obligations	35,838	33,591
Deferred tax liabilities	44	120
Total long-term liabilities	287,610	266,111
Total liabilities	296,092	274,694
Contractual obligations and commitments (Note 13)	'	'
Unitholders' equity:	'	'
Predecessors' capital	'	60,941
General partner (22,400 units issued and outstanding as of December 31, 2013 and 2012)	303	396
Total unitholders equity	192,258	290,776
TOTAL LIABILITIES AND UNITHOLDERS' EQUITY	488,350	565,470
Public common unitholders	'	'
Unitholders' equity:	'	'
Limited partner	181,290	169,919
Affiliated common unitholders	'	'
Unitholders' equity:	'	'
Limited partner	2,093	25,563
Subordinated unitholders	'	'
Unitholders' equity:	'	'
Limited partner	$8,572	$33,957

Balance_Sheets_Parenthetical

Balance Sheets (Parenthetical)	Dec. 31, 2013	Dec. 31, 2012
General partner, units issued (in units)	22,400	22,400
General partner, units outstanding (in units)	22,400	22,400
Public common unitholders	'	'
Limited partner, units issued (in units)	17,710,334	10,676,742
Limited partner, units outstanding (in units)	17,710,334	10,676,742
Affiliated common unitholders	'	'
Limited partner, units issued (in units)	1,849,600	5,049,600
Limited partner, units outstanding (in units)	1,849,600	5,049,600
Subordinated unitholders	'	'
Limited partner, units issued (in units)	6,720,000	6,720,000
Limited partner, units outstanding (in units)	6,720,000	6,720,000

Statements_of_Operations

Statements of Operations (USD $)	1 Months Ended	12 Months Ended		10 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2013	Dec. 31, 2012	Nov. 15, 2011
	Dec. 31, 2011	Dec. 31, 2013	Dec. 31, 2012	Predecessor
Revenues:	'	'	'	'
Oil sales	$9,766	$77,181	$72,916	$59,605
Natural gas sales	3,976	26,800	23,502	35,883
Natural gas liquids sales	1,976	10,147	11,627	14,500
Gain on commodity derivative instruments, net	12,287	781	12,748	22,027
Other income	'	186	45	159
Total revenues	28,005	115,095	120,838	132,174
Operating expenses:	'	'	'	'
Lease operating expense	3,193	25,397	29,069	21,391
Production and ad valorem taxes	1,076	8,614	7,790	7,763
Depletion and depreciation	5,876	43,420	46,928	37,206
Impairment on oil and natural gas properties	'	63,663	3,544	16,765
Accretion expense	191	1,924	1,575	1,290
Loss (gain) on settlement of asset retirement obligations	'	358	-31	496
Management fees	'	'	'	5,435
General and administrative expense	1,892	11,965	13,758	5,149
Total operating expenses	12,228	155,341	102,633	95,495
Operating (loss) income	15,777	-40,246	18,205	36,679
Other income (expense), net:	'	'	'	'
Interest expense	-604	-9,235	-6,596	-918
Gain (loss) on interest rate derivative instruments, net	'	1,256	-4,650	-133
Other income (expense), net	-604	-7,979	-11,246	-1,051
(Loss) income before taxes	15,173	-48,225	6,959	35,628
Income tax (expense) benefit	-48	-56	-172	76
Net (loss) income	15,125	-48,281	6,787	35,704
Net income attributable to common control acquisitions	-2,975	-448	-6,790	'
Net (loss) income available to unitholders	12,150	-48,729	-3	'
Computation of net (loss) income per limited partner unit:	'	'	'	'
General partners' interest in net (loss) income	12	-49	'	'
Limited partners' interest in net (loss) income	$12,138	($48,680)	($3)	'
Net (loss) income per limited partner unit (basic and diluted) (in dollars per unit)	$0.54	($1.92)	$0	'
Weighted average number of limited partner units outstanding (in units)	22,418	25,372	22,425	'

Consolidated_Statement_of_Chan

Consolidated Statement of Changes in Unitholders' Equity (USD $)	Total	Predecessor	Predecessors' Capital	General Partner	General Partner	Limited Partners	Limited Partners	Limited Partners	Limited Partners	Class B Limited Partner
In Thousands, unless otherwise specified	Total	Predecessor	Predecessors' Capital	General Partner	Predecessor	Predecessor	Public Common	Affiliated Common	Affiliated Subordinated	Predecessor
Balance at Dec. 31, 2010	'	$426,733	'	'	$3,452	$268,108	'	'	'	$155,173
Increase (Decrease) in Unitholders' Equity	'	'	'	'	'	'	'	'	'	'
Capital contributions	'	5,353	'	'	70	5,283	'	'	'	'
Distribution	'	-43,353	'	'	-471	-35,295	'	'	'	-7,587
Net income (loss)	'	35,704	'	'	487	27,630	'	'	'	7,587
Balance at Nov. 15, 2011	505,383	424,437	505,383	'	3,538	265,726	'	'	'	155,173
Increase (Decrease) in Unitholders' Equity	'	'	'	'	'	'	'	'	'	'
Contribution to Lime Rock Resources	-3,350	'	-3,350	'	'	'	'	'	'	'
Book value of transferred properties contributed by Lime Rock Resources	'	'	-386,361	'	'	'	'	165,899	220,462	'
Initial public offering (Note 10)	188,451	'	'	'	'	'	188,451	'	'	'
Transaction costs	-4,716	'	'	'	'	'	-4,716	'	'	'
Contribution from general partner	426	'	'	426	'	'	'	'	'	'
Amortization of equity awards	31	'	'	'	'	'	31	'	'	'
Distribution to Lime Rock Resources (Note 3)	-311,200	'	'	'	'	'	'	-133,626	-177,574	'
Distribution	0	'	'	'	'	'	'	'	'	'
Net income (loss)	15,125	'	2,975	12	'	'	5,771	2,734	3,633	'
Balance at Dec. 31, 2011	390,150	'	118,647	438	'	'	189,537	35,007	46,521	'
Increase (Decrease) in Unitholders' Equity	'	'	'	'	'	'	'	'	'	'
Contribution to Lime Rock Resources	-9,890	'	-5,174	-5	'	'	-2,241	-1,061	-1,409	'
Book value of transferred properties contributed by Lime Rock Resources	-59,322	'	-59,322	'	'	'	'	'	'	'
Amortization of equity awards	313	'	'	'	'	'	313	'	'	'
Distribution	-37,262	'	'	-37	'	'	-17,689	-8,382	-11,154	'
Net income (loss)	6,787	'	6,790	'	'	'	-1	-1	-1	'
Balance at Dec. 31, 2012	290,776	'	60,941	396	'	'	169,919	25,563	33,957	'
Increase (Decrease) in Unitholders' Equity	'	'	'	'	'	'	'	'	'	'
Contribution to Lime Rock Resources	-751	'	-734	'	'	'	-445	337	91	'
Book value of transferred properties contributed by Lime Rock Resources	-60,655	'	-60,655	'	'	'	'	'	'	'
Equity offering, net of expenses	59,513	'	'	'	'	'	59,513	'	'	'
Equity offering by limited partners	'	'	'	'	'	'	15,281	-15,281	'	'
Amortization of equity awards	549	'	'	'	'	'	549	'	'	'
Distribution	-48,893	'	'	-44	'	'	-30,732	-5,115	-13,002	'
Net income (loss)	-48,281	'	448	-49	'	'	-32,795	-3,411	-12,474	'
Balance at Dec. 31, 2013	$192,258	'	'	$303	'	'	$181,290	$2,093	$8,572	'

Statements_of_Cash_Flows

Statements of Cash Flows (USD $)	1 Months Ended	12 Months Ended		10 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2013	Dec. 31, 2012	Nov. 15, 2011
	Dec. 31, 2011	Dec. 31, 2013	Dec. 31, 2012	Predecessor
CASH FLOWS FROM OPERATING ACTIVITES	'	'	'	'
Net (loss) income	$15,125	($48,281)	$6,787	$35,704
Adjustments to reconcile net (loss) income to net cash provided by operating activities	'	'	'	'
Depletion and depreciation	5,876	43,420	46,928	37,206
Impairment of oil and natural gas properties	'	63,663	3,544	16,765
Accretion expense	191	1,924	1,575	1,290
Amortization of equity awards	31	549	313	'
Amortization of derivative contracts	'	1,002	20	'
Amortization of deferred financing costs and other	50	394	367	59
Loss (gain) on settlement of asset retirement obligations	'	358	-31	496
Purchase of derivative contracts	'	'	-59	'
Changes in operating assets and liabilities	'	'	'	'
Change in receivables	-12,924	-2,617	5,674	1,711
Change in prepaid expenses	-578	-855	-170	357
Change in derivative assets and liabilities	-8,272	6,897	14,787	-13,115
Change in trade accounts payable	2,707	'	-2,707	4,292
Change in amounts due from affiliates	536	-1,722	1,441	1,114
Change in accrued liabilities	2,746	885	-1,331	-1,771
Change in deferred tax liability	35	-76	85	-81
Net cash provided by operating activities	5,523	65,541	77,223	84,027
CASH FLOWS FROM INVESTING ACTIVITIES	'	'	'	'
Acquisition of oil and natural gas properties	-14	'	-10,020	-392
Development of oil and natural gas properties	-741	-35,805	-30,397	-47,410
Disposition of oil and natural gas properties	'	'	'	2,956
Expenditures for other property and equipment	'	'	-16	-45
Net cash used in investing activities	-755	-35,805	-40,433	-44,891
CASH FLOWS FROM FINANCING ACTIVITIES	'	'	'	'
Proceeds from IPO	188,451	'	'	'
Contribution by general partner	426	'	'	'
Transaction costs	-4,716	'	'	'
Contribution to Lime Rock Resources	-3,350	-734	-5,174	'
Deferred financing costs	-1,415	'	-562	'
Borrowings under revolving credit facility	155,800	60,000	77,200	'
Principal payments on revolving credit facility	-27,251	-38,000	-55,000	'
Borrowings under term loan	'	'	50,000	'
Equity offering, net of expenses	'	59,513	'	'
Capital contributions	'	'	'	5,353
Distribution to Lime Rock Resources	-311,200	-60,672	-64,038	'
Distributions	0	-48,893	-37,262	-43,353
Net cash used in financing activities	-3,255	-28,786	-34,836	-38,000
NET INCREASE IN CASH AND CASH EQUIVALENTS	1,513	950	1,954	1,136
CASH AND CASH EQUIVALENTS, BEGINNING OF THE PERIOD	'	3,467	1,513	12,455
CASH AND CASH EQUIVALENTS, END OF PERIOD	1,513	4,417	3,467	13,591
Supplemental disclosure of cash flow information	'	'	'	'
Cash paid for taxes during the period	'	132	86	603
Cash paid for interest during the period	31	8,786	6,547	4
Property and equipment:	'	'	'	'
Accrued capital costs	-1,421	1,663	940	5,791
Asset retirement obligations	($353)	($476)	($364)	($241)

Organization_and_Description_o

Organization and Description of Business	12 Months Ended
Organization and Description of Business	Dec. 31, 2013
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” or “predecessor” refer collectively to LRR A, LRR B and LRR C; references to “Fund II” refer collectively to Lime Rock Resources II-A, L.P. and Lime Rock Resources II-C, L.P.; and references to “Fund III” refer collectively to Lime Rock Resources III-A, L.P. and Lime Rock Resources III-C, L.P. References to “Lime Rock Resources” refer collectively to Fund I, Fund II and Fund III.

	Our properties are located in the Permian Basin region in West Texas and southeast New Mexico, the Mid-Continent region in Oklahoma and East Texas and the Gulf Coast region in Texas. We conduct our operations through our wholly owned subsidiary, LRE Operating, LLC (“OLLC”).

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

	Prior to our initial public offering (“IPO”) on November 16, 2011, Fund I owned 100% of the properties conveyed to us in connection with our IPO. At the closing of our IPO, we entered into a purchase, sale, contribution, conveyance and assumption agreement with Fund I pursuant to which Fund I sold and contributed to us specified oil and natural gas properties and related net profits interests and operations and certain commodity derivative contracts (the “Partnership Properties”). Fund I received total consideration for the Partnership Properties of 5,049,600 common units, 6,720,000 subordinated units, $311.2 million in cash and the assumption of $27.3 million of LRR A’s indebtedness. Please refer to Notes 3 and 10 for additional disclosures regarding the Partnership Properties and IPO.

	In connection with our IPO, we also restated or entered into the following agreements:

	Amended and Restated Agreement of Limited Partnership. We amended and restated our agreement of limited partnership which provides, among other things, for registration rights for the benefit of our general partner and Fund I.

	Amended and Restated Limited Liability Company Agreement of our General Partner. Our general partner also amended and restated its limited liability company agreement. The amendments to the agreement included provisions regarding, among other things, the issuance of additional classes of membership interests, the rights of the members of the general partner, distributions and allocations and management by the board of directors of our general partner.

	Credit Agreement. Please refer to Note 7 for a description of our credit agreement.

	Services Agreement. We entered into a services agreement (the “Services Agreement”) by and among Lime Rock Management, Lime Rock Resources Operating Company, Inc. (“ServCo”), LRE GP, LLC (the “General Partner”), the Partnership and OLLC, pursuant to which Lime Rock Management and ServCo provide certain management, administrative and operating services and personnel to our general partner and us to manage and operate our business. Under the Services Agreement, our general partner reimburses Lime Rock Management and ServCo, on a monthly basis, for the allocable expenses they incur in their performance under the Services Agreement, and we reimburse our general partner for such payments it makes to Lime Rock Management and ServCo. These expenses include, among other things, salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and other expenses allocated by Lime Rock Management and ServCo to us. Lime Rock Management and ServCo have discretion to determine in good faith the proper allocation of costs and expenses to our general partner for their services. Lime Rock Management and ServCo will not be liable to us for their performance of, or failure to perform, services under the Services Agreement unless their acts or omissions constitute gross negligence or willful misconduct. Please refer to Note 9 for amounts paid to affiliates.

	Omnibus Agreement. We entered into an omnibus agreement (the “Omnibus Agreement”) with our general partner, OLLC, LRR A, LRR B, LRR C, LRR GP, LLC and Lime Rock Management. Under the Omnibus Agreement, none of the parties or their respective affiliates have any obligation to offer, or provide any opportunity to pursue, purchase or invest in, any business opportunity to any other party or their affiliates. The Omnibus Agreement does not restrict any of the parties and their respective affiliates from competing with either Fund I or us, our general partner, OLLC and all of their respective subsidiaries.

	Pursuant to the Omnibus Agreement, each entity of Fund I indemnified us, our general partner, OLLC and their respective subsidiaries against (i) title defects, (ii) income taxes attributable to pre-closing ownership or operation of the contributed assets, including any income tax liabilities related to the formation transactions that occurred on or prior to the closing of the IPO, (iii) environmental claims, losses and expenses associated with the operation of our business prior to the closing of the IPO, subject to a maximum of $10,000,000, (iv) all liabilities, other than liabilities covered under the preceding clause, (iii) relating to the operation of the contributed assets prior to the closing that were not disclosed in the most recent pro forma balance sheet included in our Registration Statement on Form S-1, as amended (File No. 333-174017) or incurred in the ordinary course of business thereafter, and (v) losses resulting from the failure of Fund I to have on the closing date any consent, waiver or governmental permit that renders us, general partner, OLLC and their respective subsidiaries unable to own, use or operate the contributed assets in substantially the same manner as they were owned, used or operated immediately prior to the closing of the IPO.

	Fund I’s indemnification obligation (i) survives for three years after the closing of the IPO with respect to title defects, (ii) survives for one year after closing with respect to environmental claims, undisclosed liabilities and failure to have any consent, waiver or governmental permits, and (iii) terminates upon the earlier of (y) the expiration of the term of Fund I and (z) sixty days after the expiration of the applicable statute of limitations with respect to income taxes. All claims are subject to a $50,000 per claim de minimus exception, and no claims may be made against Fund I unless such losses exceed $500,000 in the aggregate; thereafter, each entity of Fund I will be liable, severally, in proportion to its contribution percentage, only to the extent that such losses exceed $500,000.

	Long-Term Incentive Plan. Please refer to Note 12 for a description on our Long-Term Incentive Plan.

Summary_of_Significant_Account

Summary of Significant Accounting Policies	12 Months Ended
Summary of Significant Accounting Policies	Dec. 31, 2013
Summary of Significant Accounting Policies	'
Summary of Significant Accounting Policies	'
	2. Summary of Significant Accounting Policies

	The accompanying financial statements and related notes present our consolidated financial position as of December 31, 2013 and 2012. These financial statements include the results of our operations, cash flows and changes in unitholders’ equity for the years ended December 31, 2013 and 2012 and the period of November 16 to December 31, 2011. The financial statements also include the results of our predecessor’s operations, cash flows and changes in partners’ capital for the period of January 1 to November 15, 2011. The combined financial statements of Fund I reflect the predecessor financial statements of the Partnership and have been prepared from the separate financial records maintained by Fund I. Because the results of our predecessor include results for both the properties conveyed to us in connection with our IPO and properties retained by our predecessor, we do not consider these results of our predecessor to be indicative of our future results.

	These consolidated/combined financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and all intercompany transactions and account balances have been eliminated. We operate oil and natural gas properties as one business segment: the exploration, development and production of oil and natural gas. Our management evaluates performance based on one business segment as there are not different economic environments within the operation of the oil and natural gas properties.

	Acquisitions of assets from Lime Rock Resources were deemed transactions between entities under common control and the net assets acquired during 2013, 2012 and 2011 were recorded using carryover book value of Lime Rock Resources. Our historical financial statements were revised to include the results attributable to previous acquisitions from Lime Rock Resources as if we owned the properties for all periods presented in our consolidated financial statements.

	The revised historical consolidated financial statements for periods prior to our acquisitions have been prepared from Lime Rock Resources’ historical cost-basis accounts and may not necessarily be indicative of the actual results of operations that would have occurred if we had owned the assets during the periods reported. See our accounting policy below under “Transactions between Entities under Common Control.”

	Net income attributable to common control acquisitions periods prior to the Partnership’s acquisition of such assets was not available for distribution to our unitholders. Therefore, this income was not allocated to the limited partners for the purpose of calculating net income per common unit.

	Transactions between Entities under Common Control

	Master limited partnerships (“MLPs”) enter into transactions whereby the MLP receives a transfer of certain assets from its sponsor or predecessor for consideration of either cash, units, assumption of debt, or any combination thereof. We account for the net assets received using the carryover book value of Lime Rock Resources as these were considered to be transactions between entities under common control. Our historical financial statements have been revised to include the results attributable to the assets contributed from Lime Rock Resources as if we owned such assets for all periods presented by us. The following financial statement items were impacted:

	Oil and Natural Gas Properties Received. The book value and related activity of oil and natural gas properties received from Lime Rock Resources is determined using the carrying value of the specific assets contributed.

	Commodity Derivative Instruments. Reflects the fair value of the commodity derivative contracts associated with the properties acquired from Lime Rock Resources.

	Asset Retirement Obligations Received. The book value and related activity of asset retirement obligations received from Lime Rock Resources was determined by using the carrying value of the specific liabilities attributable to the assets contributed.

	Oil, Natural Gas and NGL Revenues and Expenses. Oil, natural gas and NGL revenues and expenses related to the properties acquired are based on the actual results of the acquired properties. Historical lease operating statements by individual asset were used as the basis for revenues and direct operating expenses.

	Gain on Commodity Derivative Contracts, Net. Reflects the net gain on commodity derivative contracts associated with the properties acquired assuming the contracts were in place as of the date acquired by Lime Rock Resources.

	General and Administrative Expense. The general and administrative expense attributable to the properties acquired was determined by the ratio of production for the properties acquired to the total respective Lime Rock Resources’ production for the period presented.

	Use of estimates

	The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates.

	Depreciation, depletion and amortization of oil and natural gas properties and the impairment of oil and natural gas properties are determined using estimates of oil and natural gas reserves. There are numerous uncertainties in estimating the quantity of reserves and in projecting the future rates of production and timing of development expenditures, including future costs to dismantle, dispose, and restore our properties. Oil and natural gas reserve engineering must be recognized as a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way.

	Cash and cash equivalents

	We consider all highly liquid instruments purchased with a maturity when acquired of three months or less to be cash equivalents. We continually monitor our positions with, and the credit quality of, the financial institutions with which we invest.

	Accounts receivable

	Trade accounts receivable are recorded at the invoiced amount and do not bear interest. We use the specific identification method of providing allowances for doubtful accounts. At December 31, 2013 and 2012, we did not have an allowance for doubtful accounts.

	Revenue recognition

	Revenues from oil and gas sales are recognized based on the sales method with revenue recognized on actual volumes sold to purchasers. Under this method of revenue recognition, a gas imbalance is created if the quantity sold is greater than or less than our entitlement share in any particular period. To the extent there are sufficient quantities of natural gas remaining to make up the gas imbalance, oil and natural gas reserves are adjusted to reflect the overproduced or underproduced position. In situations where there are insufficient reserves available to make up an overproduced imbalance, a liability is established. As of December 31, 2013 and 2012, we had no significant production imbalances.

	Concentrations of credit and significant customers

	Financial instruments which potentially subject us to credit risk consist principally of cash balances, accounts receivable and derivative financial instruments. We maintain cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. We have not experienced any significant losses from such investments. We attempt to limit the amount of credit exposure to any one financial institution or company through procedures that include credit approvals, credit limits and terms, letters of credit, prepayments and rights of offset. Our customer base consists primarily of major integrated and international oil and natural gas companies, as well as smaller processors and gatherers. We believe the credit quality of our customer base is high and have not experienced significant write-downs in our accounts receivable balances.

	For the year ended December 31, 2013, purchases by ConocoPhillips, Holly Frontier, Sunoco and Seminole Energy Services accounted for 18%, 15%, 14% and 10% respectively, of our total sales revenues.

	For the year ended December 31, 2012, purchases by Sunoco, ConocoPhillips, and Shell Trading Company accounted for 17%, 16% and 10%, respectively, of our total sales revenues.

	For the period from November 16 to December 31, 2011, purchases by ConocoPhillips, Seminole Energy Services and Upstream Energy accounted for 25%, 16% and 12%, respectively, of our total sales revenues.

	For the period from January 1 to November 15, 2011, purchases by ConocoPhillips, Seminole Energy Services and Sunoco accounted for 18%, 12% and 16%, respectively, of our predecessor’s total sales revenues.

	If we were to lose any one of our customers, the loss could temporarily delay production and sale of oil and natural gas in the related producing region. If we were to lose any single customer, we believe that a substitute customer to purchase the impacted production volumes could be identified. However, if one or more of our larger customers ceased purchasing oil or natural gas altogether, the loss of such customer could have a detrimental effect on production volumes in general and on the ability to find substitute customers to purchase production volumes.

	Oil and natural gas properties

	Proved properties. We account for our oil and natural gas exploration, development and production activities in accordance with the successful efforts method. Under this method, all leasehold and development costs of proved properties are capitalized and amortized on a unit-of-production basis over the remaining life of the proved reserves and proved developed reserves, respectively.

We evaluate the potential impairment of our proved oil and natural gas properties on a field-by-field basis whenever events or changes in circumstances indicate that the carrying value may not be recoverable. We assess impairment of capitalized costs of proved oil and natural gas properties by comparing net capitalized costs to estimated undiscounted future net cash flows using expected prices. The carrying values of proved properties are reduced to fair value when the expected undiscounted future cash flows are less than net book value.

For the years ended December 31, 2013 and 2012, we recorded non-cash impairment charges on proved oil and natural gas properties of $63.7 million and $3.1 million, respectively. For the period from January 1 to November 15, 2011, our predecessor recorded non-cash impairment charges on proved oil and natural gas properties of $16.8 million. These charges are included in “impairment of oil and natural gas properties” on the consolidated/combined statements of operations. No impairment was recorded for proved properties for the period from November 16 to December 31, 2011. Refer to Note 5 for additional information.

Costs of retired, sold or abandoned properties that constitute a part of an amortization base are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized currently. Gains or losses from the disposal of proved properties are recognized currently. Expenditures for maintenance and repairs necessary to maintain properties in operating condition are expensed as incurred. Estimated dismantlement and abandonment costs are capitalized, net of salvage, at their estimated net present value and amortized on a unit-of-production basis over the remaining life of the related proved developed reserves.

Unproved properties. Costs related to unproved properties include costs incurred to acquire unproved reserves. Because these reserves do not meet the definition of proved reserves, the related costs are not classified as proved properties. As of December 31, 2013 and 2012, $1.3 million of oil and natural gas property costs were related to unproved leasehold acquisitions costs and not subject to depletion. We did not reclassify any material amounts from unproved to proved properties during the years ended December 31, 2013 and 2012.

We assess unproved properties for impairment on a quarterly basis. For the year ended December 31, 2012, we recorded an impairment charge for unproved properties in the amount of $0.4 million. No impairments were recorded for unproved properties during 2013 or 2011. The impairment was based on our experience in similar situations and other factors such as the primary lease terms of the properties, the average holding period of unproved properties, and the relative proportion of such properties on which proved reserves have been found in the past. The fair values of unproved 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 unproved 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 market-based weighted average cost of capital rate is subject to additional project-specific risk factors.

Other property and equipment

Other property and equipment is stated at historical cost less accumulated depreciation expense and is comprised primarily of software, computers and office equipment. Depreciation is calculated using the straight-line method based on useful lives of the assets ranging from three to five years. Other property and equipment is evaluated for impairment as necessary to determine if current circumstances and market conditions indicate that the carrying amounts of assets may not be recoverable. We did not recognize any impairment loss related to other property and equipment during 2013, 2012 and 2011.

Asset retirement obligations

We have obligations under our lease agreements and federal regulations to remove equipment and restore land at the end of oil and natural gas production operations. These asset retirement obligations (“ARO”) are primarily associated with plugging and abandoning wells. Determining the future restoration and removal requires management to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations. We record the fair value of a liability for an ARO in the period in which it is incurred with a corresponding increase in the carrying amount of the related long-lived asset. We typically incur this liability upon acquiring or drilling a well. Over time, the liability is accreted each period toward its future value, and the capitalized cost is depleted as a component of development costs. Upon settlement of the liability, a gain or loss is recognized to the extent the actual costs differ from the recorded liability.

Inherent to the fair value calculation are numerous estimates, assumptions and judgments, including the ultimate settlement amounts, inflation factors, credit adjusted risk-free rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the abandonment liability, management will make corresponding adjustments to both the ARO and the related oil and natural gas property asset balance. Increases in the discounted retirement obligation liability and related oil and natural gas assets resulting from the passage of time will be reflected as additional accretion and depreciation expense in the consolidated/combined statements of operations.

Derivatives

Our activities primarily consist of acquiring, owning, enhancing and producing oil and natural gas properties. The future results of our operations, cash flows and financial condition may be affected by changes in the market price of oil and natural gas. The availability of a ready market for oil and natural gas products in the future will depend on numerous factors beyond our control, including weather, imports, marketing of competitive fuels, proximity and capacity of oil and natural gas pipelines and other transportation facilities, any oversupply or undersupply of oil, natural gas and liquid products, the regulatory environment, the economic environment and, other regional and political events, none of which can be predicted with certainty.

In order for us to manage our exposure to oil and natural gas price volatility, we enter into commodity derivative instruments such as futures contracts, swaps, or options. We are also exposed to changes in interest rates, primarily as a result of variable rate borrowings under the credit facility. In an effort to reduce this exposure, we have, from time to time, entered into derivative contracts (interest rate swaps) to mitigate the risk of interest rate fluctuations. For commodity derivatives, the net gain or loss on commodity derivative contracts is recorded as a separate component of revenues. For interest rate derivatives, the net gain or loss on interest rate derivatives is recorded as a component of other income (expense) in the consolidated/combined statements of operations.

All derivative instruments are recognized on the balance sheet as either assets or liabilities measured at fair value. Settlements on derivative hedging instruments and changes in the fair value of derivatives are recorded in earnings unless the derivatives qualify and are appropriately designated as hedges. We have not designated any of our derivative instruments as hedges. As a result, we mark our derivative instruments to fair value and recognize the changes in fair market value in earnings. Refer to Note 8 for additional information.

Derivative financial instruments are generally executed with major financial institutions that expose us to market and credit risks and which may, at times, be concentrated with certain counterparties or groups of counterparties. All of our derivatives at December 31, 2013 are with parties that are also lenders under our credit facility. The credit worthiness of the counterparties is subject to continual review. We monitor the nonperformance risk of ourselves and of each of our counterparties and assesses 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 master netting arrangements in place with each counterparty to reduce credit exposure.

Equity-based compensation

We have granted restricted unit awards which we account for at fair value. Restricted unit awards, net of estimated forfeitures, are expensed over the requisite service period. As each award vests, an adjustment is made to compensation cost for any difference between the estimated forfeitures and the actual forfeitures related to the vested awards. We record these compensation costs as general and administrative expenses. Refer to Note 12 for additional information.

Income taxes

We are not taxable for federal income tax purposes and do not directly pay federal income tax. Generally, all of our taxable federal income and losses are reported on the income tax returns of our unitholders or partners, and therefore, no provision for federal income taxes has been recorded in our accompanying consolidated/combined financial statements.

We record our obligations under the Texas gross margin tax as “Income tax expense (benefit)” in the consolidated/combined statements of operations. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period of rate change.

Deferred financing costs

Costs incurred in connection with the execution or modification of our credit facility are capitalized and amortized using the effective interest method over the term of the credit facility.

Recent accounting pronouncements

In December 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2011-11, “Disclosures about Offsetting Assets and Liabilities.” ASU No. 2011-11 required entities to disclose both gross information and net information about instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a master netting arrangement. The objective of the disclosure is to facilitate comparison between those entities that prepare their financial statements on the basis of GAAP and those entities that prepare their financial statements on the basis of International Financial Reporting Standards. In January 2013, the FASB issued ASU 2013-01, “Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities,” which clarified the scope of these disclosures to include bifurcated embedded derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions that are either offset or subject to an enforceable master netting arrangement or similar agreement. We adopted this guidance effective January 1, 2013. This guidance did not have a material impact on our consolidated financial position, results of operations or cash flows.

Acquisitions

Acquisitions	12 Months Ended
	Dec. 31, 2013
Acquisitions	'
Acquisitions	'
	3. Acquisitions

	Acquisition between Entities under Common Control

	At the closing of our IPO, as consideration for the Partnership Properties, we issued to Fund I 5,049,600 common units and 6,720,000 subordinated units; paid $311.2 million in cash; and assumed $27.3 million of LRR

	A’s indebtedness. The following table presents the net assets conveyed by Fund I to the Partnership immediately prior to the closing of IPO including the debt assumption (in thousands):

	Property and equipment, net	$	400,056
	Derivative instruments	36,705
	Total assets	$	436,761

	Long-term debt	$	27,251
	Derivative instruments	476
	Asset retirement obligations	22,673
	Total liabilities	$	50,400

	Net assets	$	386,361

	On June 1, 2012, we completed an acquisition from Fund I of certain oil and natural gas properties located in the Permian Basin region of New Mexico and onshore Gulf Coast region of Texas for $65.1 million in cash (the “June 2012 Acquisition”). The June 2012 Acquisition was effective March 1, 2012. In September 2012, we received $1.1 million in cash from Fund I related to post-closing adjustments to the purchase price. We funded the acquisition with borrowings under our revolving credit facility (Note 7).

	The following table presents the net assets conveyed by Fund I to us in the June 2012 Acquisition (in thousands):

	Property and equipment, net	$	60,365
	Asset retirement obligations and other liabilities	(1,043		)
	Net assets	$	59,322

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

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

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

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

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

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

	The net assets of the IPO, June 2012 Acquisition, January 2013 Acquisition and April 2013 Acquisition were recorded using carryover book value of Fund I and Fund II as the acquisitions were deemed transactions between entities under common control. Our historical financial statements were revised to include the results attributable to previous acquisitions from Fund I and Fund II as if we owned the properties for all periods presented in our consolidated financial statements.

Fair_Value_Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2013
Fair Value Measurements	'
Fair Value Measurements	'
	4. Fair Value Measurements

	Our financial instruments, including cash and cash equivalents, accounts receivable and accounts payable, are carried at cost, which approximates fair value due to the short-term maturity of these instruments. 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 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 December 31, 2013 and 2012(in thousands).

		Level 1		Level 2		Level 3		Total
	December 31, 2013
	Assets:
	Commodity derivative instruments	$	—	$	26,472	$	—	$	26,472
	Liabilities:
	Commodity derivative instruments	—		2,391		—		2,391
	Interest rate derivative instruments	—		2,202		—		2,202
	December 31, 2012
	Assets:
	Commodity derivative instruments	$	—	$	36,484	$	—	$	36,484
	Liabilities:
	Commodity derivative instruments	—		2,545		—		2,545
	Interest rate derivative instruments	—		4,185		—		4,185

	All fair values reflected in the table above and on the consolidated 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	12 Months Ended
	Dec. 31, 2013
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):

		December 31, 2013			December 31, 2012
	Oil and natural gas properties (successful efforts method)	$	875,126		$	839,154
	Unproved properties	1,258			1,264
	Other property and equipment	290			318
		876,674			840,736
	Accumulated depletion, depreciation and impairment	(431,837		)	(324,774		)
	Total property and equipment, net	$	444,837		$	515,962

	We recorded $43.4 million, $46.9 million and $5.9 million of depletion and depreciation expense for the years ended December 31, 2013 and 2012 and the period from November 16 to December 31, 2011, respectively. Our predecessor recorded $37.2 million of depletion and depreciation expense for the period from January 1 to November 15, 2011.

	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 year ended December 31, 2013, we recorded a total non-cash impairment charge of $63.7 million to impair the value of our proved oil and natural gas properties in the Permian Basin and the Gulf Coast regions. This impairment charge reduced the region’s carrying values to an estimated fair value of $76.2 million as of December 31, 2013. For the year ended December 31, 2012, we recorded a total non-cash impairment charge of $3.5 million to impair the value of our unproved properties and proved oil and natural gas properties in the Mid-Continent region. We did not record any impairment charges for the period from November 16 to December 31, 2011. For the year to date period ending November 15, 2011, our predecessor recorded a total non-cash impairment charge of $16.8 million to impair the value of our proved oil and natural gas properties in the Mid-Continent region. These non-cash charges are included in “Impairment of oil and natural gas properties” line item in our consolidated/combined statements of operations.

	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 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 included in the reserve reports, 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	12 Months Ended
	Dec. 31, 2013
Asset Retirement Obligations	'
Asset Retirement Obligations	'
	6. Asset Retirement Obligations

	The following is a summary of our ARO as of and for the years indicated (in thousands):

		December 31, 2013			December 31, 2012
	Beginning of period	$	34,091		$	26,353
	Revisions to previous estimates	197			6,291		-1
	Liabilities incurred	476			364
	Liabilities settled	(362		)	(492		)
	Accretion expense	1,924			1,575
	End of period	36,326			34,091
	Current portion of ARO	(488		)	(500		)
	Asset retirement obligation-non-current	$	35,838		$	33,591

	(1) The revisions are primarily related to the accelerated timing of expected settlement of our ARO as it relates to our natural gas properties due to significantly lower natural gas prices during 2012.

LongTerm_Debt

Long-Term Debt	12 Months Ended
Long-Term Debt	Dec. 31, 2013
Long-Term Debt	'
Long-Term Debt	'
	7. Long-Term Debt

	Credit Agreement

	In July 2011, subject to consummation of our IPO, we, as guarantor, and our wholly owned subsidiary, OLLC, as borrower, entered into a five-year, $500 million senior secured revolving credit facility, as amended, (the “Credit Agreement”) that matures in July 2016. The Credit Agreement is reserve-based and we are permitted to borrow under our credit facility an amount up to the borrowing base, which was $250 million as of December 31, 2013. Our borrowing base, which is primarily based on the estimated value of our oil, NGL and natural gas properties and our commodity derivative contracts, is subject to redetermination semi-annually by our lenders at their sole discretion. Unanimous approval by the lenders is required for any increase to the borrowing base.

	Borrowings under the Credit Agreement are secured by liens on at least 80% of the PV-10 value of our and our subsidiaries’ oil and natural gas properties and all of our equity interests in OLLC and any future guarantor subsidiaries and all of our and our subsidiaries’ other assets including personal property. Borrowings under the Credit Agreement bear interest, at OLLC’s option, at either (i) the greater of the prime rate as determined by the Administrative Agent, the federal funds effective rate plus 0.50%, and the 30-day adjusted LIBOR plus 1.0%, all of which is subject to a margin that varies from 0.75% to 1.75% per annum according to the borrowing base usage (which is the ratio of outstanding borrowings and letter of credit exposure to the borrowing base then in effect), or (ii) the applicable reserve-adjusted LIBOR plus a margin that varies from 1.75% to 2.75% per annum according to the borrowing base usage. The unused portion of the borrowing base is subject to a commitment fee that varies from 0.375% to 0.50% per annum according to the borrowing base usage.

	The Credit Agreement requires us to maintain a leverage ratio of Total Debt to EBITDAX (as each term is defined in the Credit Agreement) of not more than 4.0 to 1.0x, and a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0x.

	Additionally, the Credit Agreement contains various covenants and restrictive provisions which limit our, OLLC’s and any of our subsidiaries’ ability to incur additional debt, guarantees or liens; consolidate, merge or transfer all or substantially all of our assets; make certain investments, acquisitions or other restricted payments; modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; incur commodity hedges exceeding a certain percentage of our production; and prepay certain indebtedness. As of December 31, 2013, we were in compliance with all covenants contained in the Credit Agreement.

	Term Loan Agreement

	On June 28, 2012, we, as parent guarantor, and our wholly owned subsidiary, OLLC, as borrower, entered into a Second Lien Credit Agreement (the “Term Loan Agreement”). The Term Loan Agreement provides for a $50 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 obligations under the Term Loan Agreement are guaranteed on a joint and several basis by us. The obligations are secured by a second priority mortgage and security interest in all assets of OLLC and us that secure OLLC’s and our existing indebtedness under the Credit Agreement.

	Borrowings under the Term Loan Agreement mature on January 20, 2017, and, subject to the terms of the Intercreditor Agreement (as described below), OLLC has the ability at any time to prepay the Term Loan Agreement without premium or penalty. Borrowings under the Term Loan Agreement bear interest, at OLLC’s option, at either

	· the greatest of (i) the prime rate as defined in the Term Loan Agreement, (ii) the federal funds effective rate plus 0.50% and (iii) the 30-day adjusted LIBOR plus 1.0%, all of which is subject to an applicable margin as follows:
	· 4.50% through March 31, 2013;
	· 6.00% from April 1, 2013 to December 31, 2013; and
	· 7.50% from January 1, 2014 to January 20, 2017; or

	· the applicable reserve-adjusted LIBOR plus an applicable margin as follows:
	· 5.50% through March 31, 2013;
	· 7.00% from April 1, 2013 to December 31, 2013; and
	· 8.50% from January 1, 2014 to January 20, 2017.

	Additionally, the Term Loan Agreement provides for an upfront fee of one percent of the aggregate maximum commitment amount, or $500,000.

	The Term Loan Agreement contains various covenants and restrictive provisions which limit the ability of OLLC, us or any of our subsidiaries to incur additional debt, guarantees or liens; consolidate, merge or transfer all or substantially all of its assets; make certain investments, acquisitions or other restricted payments; modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; incur commodity hedges exceeding a certain percentage of production; prepay certain indebtedness; and amend the Credit Agreement or grant any liens to secure any indebtedness under the Credit Agreement.

	The Term Loan Agreement also contains covenants that, among other things, require OLLC and us to maintain specified ratios including leverage ratio of Total Debt to EBITDAX of not more than 4.25 to 1.00x; a current ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0x; and an asset coverage ratio of Total Proved PV-10 to Total Debt of not less than 1.50 to 1.00x. As of December 31, 2013, we were in compliance with all covenants contained in the Term Loan Agreement.

	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 December 31, 2013, we had $250.0 million of outstanding debt and accrued interest was $0.2 million. As of December 31, 2012, we had $228.0 million of outstanding debt and accrued interest was $0.2 million. Our outstanding debt increased primarily due to our January 2013 acquisition of oil and natural gas properties from Fund I for approximately $21.0 million and working capital borrowings.

	Interest expense for the years ended December 31, 2013 and 2012 and period from November 16 to December 31, 2011 was $9.2 million, $6.6 million and $0.6 million, respectively. Interest expense related to LRR A’s credit facility for the period from January 1 to November 15, 2011 was $0.9 million. As of December 31, 2013 and 2012, our weighted average interest rate on our outstanding indebtedness was 3.88% and 3.47%, respectively. Please refer to Note 8 below for a discussion of our interest rate derivative contracts.

Derivatives

Derivatives	12 Months Ended
Derivatives	Dec. 31, 2013
Derivatives	'
Derivatives	'
	8. Derivatives

	Objective and strategy—We are exposed to commodity price and interest rate risk and consider it prudent to periodically reduce our exposure to cash flow variability resulting from commodity price changes and interest rate fluctuations. Accordingly, we enter into derivative instruments to manage our exposure to commodity price fluctuations, locational differences between a published index and the NYMEX futures on natural gas or crude oil productions, and interest rate fluctuations.

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

	Swaps and options are used to manage our exposure to commodity price risk and basis risk inherent in our oil and natural gas production. Commodity price swap agreements are used to fix the price of expected future oil and natural gas sales at major industry trading locations such as Henry Hub Louisiana (“HH”) for gas and Cushing Oklahoma (“WTI”) for oil. Basis swaps are used to fix the price differential between the product price at one location versus another. Options are used to establish a floor and a ceiling price (collar) for expected oil or gas sales. Interest rate swaps are used to fix interest rates on existing indebtedness.

	Under commodity swap agreements, we exchange a stream of payments over time according to specified terms with another counterparty. Specifically for commodity price swap agreements, we agree to pay an adjustable or floating price tied to an agreed upon index for the commodity, either gas or oil, and in return receives a fixed price based on notional quantities. Under basis swap agreements, we agree to pay an adjustable or floating price tied to two agreed upon indices for gas and in return receive the differential between a floating index and fixed price based on notional quantities. A collar is a combination of a put purchased by us and a call option written by us. In a typical collar transaction, if the floating price based on a market index is below the floor price, we receive from the counterparty an amount equal to this difference multiplied by the specified volume, effectively a put option. If the floating price exceeds the floor price and is less than the ceiling price, no payment is required by either party. If the floating price exceeds the ceiling price, we must pay the counterparty an amount equal to the difference multiplied by the specific quantity, effectively a call option.

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

	We elected not to designate any positions as cash flow hedges for accounting purposes and, accordingly, recorded the net change in the mark-to-market valuation of these derivative contracts in the consolidated/combined statements of operations. We record our derivative activities on a mark-to-market or fair value basis. Fair values are based on pricing models that consider various assumptions, including quoted forward prices for commodities, the time value of money and volatility, and are comparable to values obtained from counterparties. We present the fair value of derivative financial instruments on a net basis in the consolidated balance sheets.

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

			Index		2014			2015			2016			2017
	Natural gas positions
	Price swaps (MMBTUs)		NYMEX-HH		6,077,016			5,500,236			5,433,888			5,045,760
	Weighted average price				$	5.53		$	5.72		$	4.29		$	4.61

	Basis swaps (MMBTUs)		NYMEX		5,876,098			5,326,559			2,877,047			—
	Weighted average price				$	(0.1521	)	$	(0.1661	)	$	(0.1115	)	$	—

	Oil positions
	Price swaps (BBLs)		NYMEX-WTI		723,634			561,833			397,488			198,744
	Weighted average price				$	95.76		$	93.16		$	86.02		$	85.75

	Basis swaps (BBLs)		Argus-		410,400			—			—			—
	Weighted average price		Midland-Cushing		$	(1.00	)	$	—		$	—		$	—

	NGL positions
	Price swaps (BBLs)		Mont Belvieu		183,857			147,823			—			—
	Weighted average price				$	34.11		$	34.5		$	—		$	—

	At December 31, 2012, we had the following open commodity derivative contracts:

			Index		2013			2014			2015			2016			2017
	Natural gas positions
	Price swaps (MMBTUs)		NYMEX-HH		7,516,540			6,077,016			5,500,236			4,878,990			4,605,396
	Weighted average price				$	5.16		$	5.53		$	5.72		$	4.28		$	4.61

	Basis swaps (MMBTUs)		NYMEX		7,446,301			5,876,098			5,326,559			2,877,047			—
	Weighted average price				$	(0.1361	)	$	(0.1521	)	$	(0.1661	)	$	(0.1115	)	$	—

	Puts (MMBTUs)		NYMEX-HH		178,710			—			—			—			—
	Strike price				$	3		$	—		$	—		$	—		$	—

	Oil positions
	Price swaps (BBLs)		NYMEX-WTI		698,816			519,102			420,381			397,488			198,744
	Weighted average price				$	95.95		$	96.61		$	94.72		$	86.02		$	85.75

	NGL positions
	Price swaps (BBLs)		Mont Belvieu		144,323			—			—			—			—
	Weighted average price				$	50.49		$	—		$	—		$	—		$	—

	At December 31, 2013 and 2012, we had the following interest rate swap derivative contracts (in thousands):

					Notional
	Effective		Maturity		Amount			Average %		Index
	February 2012		February 2015		$	150,000		0.5175	%	LIBOR
	February 2015		February 2017		75,000			1.725	%	LIBOR
	February 2015		February 2017		75,000			1.7275	%	LIBOR
June 2012		June 2015		70,000			0.52375	%	LIBOR
June 2015		June 2017		70,000			1.4275	%	LIBOR


Effect of Derivative Instruments — Balance Sheets

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

		As of December 31, 2013
		Current			Long-term			Current			Long-term
		Assets			Assets			Liabilities			Liabilities

Interest rate
Swaps		$	—		$	637		$	648		$	2,191
Gross fair value		—			637			648			2,191
Netting arrangements		—			(637		)	—			(637		)
Net recorded fair value		$	—		$	—		$	648		$	1,554

Sale of natural gas production
Price swaps		$	8,250		$	11,937		$	196		$	73
Basis swaps		56			211			317			65
Sale of crude oil production
Price swaps		1,564			5,042			1,519			331
Basis swaps		227			—			—			—
Sale of NGLs
Price swaps		106			4			662			153
Gross fair value		10,203			17,194			2,694			622
Netting arrangements		(477		)	(448		)	(477		)	(448		)
Net recorded fair value		$	9,726		$	16,746		$	2,217		$	174

		As of December 31, 2012
		Current			Long-term			Current			Long-term
		Assets			Assets			Liabilities			Liabilities

Interest rate
Swaps		$	—		$	13		$	659		$	3,539
Gross fair value		—			13			659			3,539
Netting arrangements		—			(13		)	—			(13		)
Net recorded fair value		$	—		$	—		$	659		$	3,526

Sale of natural gas production
Price swaps		$	12,185		$	17,460		$	155		$	1,073
Basis swaps		18			27			317			470
Sale of crude oil production
Price swaps		3,949			5,248			2,061			2,066
Sale of NGLs
Price swaps		1,209			—			15			—
Gross fair value		17,361			22,735			2,548			3,609
Netting arrangements		(877		)	(2,735		)	(877		)	(2,735		)
Net recorded fair value		$	16,484		$	20,000		$	1,671		$	874

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):

		Partnership										Predecessor
		Year Ended			Year Ended			November 16 to				January 1 to
		December 31,			December 31,			December 31,				November 15,
		2013			2012			2011				2011
Commodity derivatives (revenue)		$	781		$	12,748		$	12,287			$	22,027
Interest rate derivatives (other income/expense)		1,256			(4,650		)	—				(133		)


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 we believe 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	12 Months Ended
	Dec. 31, 2013
Related Parties	'
Related Parties	'
	9. Related Parties

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

	As of December 31, 2013 and 2012, 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 9.5% of our outstanding common units and all of our subordinate units, representing a 32.6% limited partner interest in us as of December 31, 2013. Fund I owned an aggregate of 32.1% of our outstanding common units and all of our subordinate units, representing a 52.4% limited partner interest in us as of December 31, 2012. As of December 31, 2013 and 2012, 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.

	Contracts with our General Partner and its Affiliates

	We have entered into agreements with our general partner and its affiliates. Refer to Note 1 for a description of those agreements. For the years ended December 31, 2013 and 2012, we paid Lime Rock Management $1.8 million and $2.1 million either directly or indirectly related to these agreements, respectively.

	In connection with the management of our business, 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 as of and for the years indicated are included below (in thousands):

					Lime Rock
		ServCo			Resources			Total

	Balance as of December 31, 2011	$	—		$	(536	)	$	(536	)
	Expenditures	(74,765		)	(11,708		)	(86,473		)
	Cash paid for expenditures	62,844			4,423			67,267
	Revenues and other	9,692			8,073			17,765
	Balance as of December 31, 2012	$	(2,229	)	$	252		$	(1,977	)
	Expenditures	(99,124		)	(1,019		)	(100,143		)
	Cash paid for expenditures	95,685			1,275			96,960
	Revenues and other	5,151			(246		)	4,905
	Balance as of December 31, 2013	$	(517	)	$	262		$	(255	)

	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 December 31, 2013, our general partner and its affiliates held 1,849,600 of our common units, all of our subordinated units and 22,400 general partner units. As of December 31, 2012, our general partner and its affiliates held 5,049,600 of our common units, all of our subordinated units and 22,400 general partner units. During the years ended December 31, 2013 and 2012, we paid cash distributions of $48.9 million and $37.3 million, respectively, to all unitholders as of the respective record dates. No cash distributions were made from November 16 to December 31, 2011.

	We announced our fourth quarter 2013 distribution on January 17, 2014 as discussed in Note 15.

	Predecessor Related Parties

	Each of LRR A, LRR B and LRR C has a management agreement with Lime Rock Management, an affiliated entity, to provide management services for the operation and supervision of their respective funds. The management fee was determined by a formula based on the partners’ invested capital or the equity capital commitment. During the period from January 1 to November 15, 2011, our predecessor expensed $5.4 million in management fees to Lime Rock Management.

	For certain oil and natural gas properties where our predecessor is the operator, our predecessor receives income related to joint interest operations. For the period from January 1 to November 15, 2011, our predecessor received $0.9 million, of income, which reduced the management fee paid by our predecessor to Lime Rock Management. All related party transactions are at amounts believed to be commensurate with an arm’s-length transaction between parties and are stated at fair market value.

Unitholders_Equity

Unitholders' Equity	12 Months Ended
	Dec. 31, 2013
Unitholders' Equity	'
Unitholders' Equity	'
	10. Unitholders’ Equity

	Equity Offering

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

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

	Initial Public Offering

	On November 16, 2011, we completed our IPO of 9,408,000 common units representing limited partner interests in the Partnership at a price to the public of $19.00 per common unit, or $17.8125 per common unit after payment of the underwriting discount. Total net proceeds from the sale of common units in our IPO were $167.2 million ($178.8 million less $11.2 million for the underwriting discount and a $0.4 million structuring fee). IPO costs were $4.7 million. We reimbursed Fund I for all costs they paid related to our IPO ($3.2 million). Net proceeds of the offering, along with $155.8 million of borrowings under our new $500 million senior secured revolving credit agreement were utilized to make cash distributions and payments to Fund I of $289.9 million and repay $27.3 million of LRR A’s debt that we assumed at closing.

	On December 14, 2011, we closed the partial exercise of the underwriters’ option to purchase additional units and as a result, issued an additional 1,200,000 common units to the public. We used the net proceeds from the sale of the additional common units of $21.3 million, after deducting underwriting discounts and a structuring fee, to pay additional cash consideration for the properties purchased from Fund I in connection with the IPO and to make additional distributions to Fund I. In connection with our IPO, Fund I received total consideration for the Partnership Properties of 5,049,600 common units, 6,720,000 subordinated units, $311.2 million in cash and the assumption of $27.3 million of LRR A’s indebtedness.

	Units Outstanding

	As of December 31, 2013, we had 19,559,934 common units, 6,720,000 subordinated units and 22,400 general partner units outstanding. In addition, as of December 31, 2013, Fund I owned 1,849,600 common units and all of our subordinated units, representing a 32.6% limited partner interest in us.

	As of December 31, 2012, we had 15,726,342 common units, 6,720,000 subordinated units and 22,400 general partner units outstanding. In addition, as of December 31, 2012, Fund I owned 5,049,600 common units and all of our subordinated units, representing a 52.4% limited partner interest in us.

	Common Units

	The common units have limited voting rights as set forth in our partnership agreement.

	Subordinated Units

	The principal difference between our common units and subordinated units is that in any quarter during the subordination period, the subordinated units are entitled to receive the minimum quarterly distribution only after the common units have received their minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Accordingly, holders of subordinated units may receive a smaller distribution than holders of common units or no distribution at all. Subordinated units will not accrue arrearages.

	The subordination period will extend until the first business day of any quarter after December 31, 2014 that we have earned and paid from operating surplus, in the aggregate, distributions on each outstanding common unit, subordinated unit and general partner unit and any other partnership interests that are senior or equal in right of distribution to the subordinated units equaling or exceeding the minimum quarterly distribution payable with respect to a period of twelve consecutive quarters immediately preceding such date, provided there are no arrearages in the minimum quarterly distribution on our common units at that time. However, three separate one third tranches of subordinated units may convert on the first business day after the distribution to unitholders in respect of any quarter ending on or after December 31, 2012, December 31, 2013 and December 31, 2014, respectively, provided that an aggregate amount equal to the minimum quarterly distribution payable with respect to all units that would be payable on four, eight or twelve consecutive quarters, as applicable, has been earned and paid prior to the applicable date, in each case provided there are no arrearages in the minimum quarterly distribution on our common units at that time. One third of the subordinated units did not convert pursuant to the provisions of our partnership agreement following our distribution for the fourth quarter of 2013 that was paid on February 14, 2014. Each quarter, we will determine whether the test for conversion of the subordinated units has been met until the subordinated units convert pursuant to the provisions of our partnership agreement.

	In addition, the subordination period will end on the first business day after we have earned and paid from operating surplus at least (i) $0.54625 per quarter (115% of the minimum quarterly distribution, which is $2.185 on an annualized basis) on each outstanding common and subordinated unit and the corresponding distributions on our general partner’s approximate 0.1% interest and the incentive distribution rights for any four quarter period ending on or after December 31, 2013, or (ii) $0.59375 per quarter (125% of the minimum quarterly distribution, which is $2.375 on an annualized basis) on each outstanding common and subordinated unit and the corresponding distributions on our general partner’s approximate 0.1% interest and the incentive distribution rights for any four quarter period, in each case provided there are no arrearages in the minimum quarterly distribution on our common units at that time.

	The subordination period will also end upon the removal of our general partner other than for cause if the units held by our general partner and its affiliates are not voted in favor of such removal. When the subordination period ends, all subordinated units will convert into common units on a one-for-one basis, and all common units thereafter will no longer be entitled to arrearages.

	General Partner Interest

	Our general partner owns an approximate 0.1% interest in us. This interest entitles our general partner to receive distributions of available cash from operating surplus as discussed further below under Cash Distributions. Our partnership agreement sets forth the calculation to be used to determine the amount and priority of cash distributions that the common unitholders, subordinated unitholders and our general partner will receive.

	Our general partner has sole responsibility for conducting our business and managing our operations. Our general partner’s board of directors and executive officers will make decisions on our behalf.

	Allocation of Net Income

	Net income is allocated between our general partner and the common and subordinated unitholders in proportion to their pro rata ownership during the period.

	Cash Distributions

	Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash to unitholders of record on the applicable record date.

	Available cash, for any quarter, consists of all cash and cash equivalents on hand at the end of that quarter:

	· less, the amount of cash reserves established by our general partner at the date of determination of available cash for the quarter to:

	· provide for the proper conduct of our business, which could include, but is not limited to, amounts reserved for capital expenditures, working capital and operating expenses;
	· comply with applicable law, any of our debt instruments or other agreements; or
	· provide funds for distributions to our unitholders (including our general partner) for any one or more of the next four quarters (provided that our general partner may not establish cash reserves for future distributions on our subordinated units unless it determines that the establishment of reserves will not prevent us from distributing the minimum quarterly distribution on all common units and any cumulative arrearages on such common units for such quarter);

	· plus, if our general partner so determines, all or a portion of cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter.

	Upon the closing of our initial public offering, Fund I received an aggregate of 6,720,000 subordinated units. During the subordination period, the common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $0.4750 per common unit, which amount is defined in our partnership agreement as the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. These units are deemed “subordinated” because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions from operating surplus until the common units have received the minimum quarterly distribution plus any arrearages from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be available cash from operating surplus to be distributed on the common units.

	The subordination period will extend until the first business day of any quarter after December 31, 2014 that we have earned and paid from operating surplus, in the aggregate, distributions on each outstanding common unit, subordinated unit and general partner unit and any other partnership interests that are senior or equal in right of distribution to the subordinated units equaling or exceeding the minimum quarterly distribution payable with respect to a period of twelve consecutive quarters immediately preceding such date, provided there are no arrearages in the minimum quarterly distribution on our common units at that time. However, three separate one third tranches of subordinated units may convert on the first business day after the distribution to unitholders in respect of any quarter ending on or after December 31, 2012, December 31, 2013 and December 31, 2014, respectively, provided that an aggregate amount equal to the minimum quarterly distribution payable with respect to all units that would be payable on four, eight or twelve consecutive quarters, as applicable, has been earned and paid prior to the applicable date, in each case provided there are no arrearages in the minimum quarterly distribution on our common units at that time.

	In addition, the subordination period will end on the first business day after we have earned and paid from operating surplus at least (i) $0.54625 per quarter (115% of the minimum quarterly distribution, which is $2.185 on an annualized basis) on each outstanding common and subordinated unit and the corresponding distributions on our general partner’s 0.1% interest and the incentive distribution rights for any four quarter period ending on or after December 31, 2013, or (ii) $0.59375 per quarter (125% of the minimum quarterly distribution, which is $2.375 on an annualized basis) on each outstanding common and subordinated unit and the corresponding distributions on our general partner’s 0.1% interest and the incentive distribution rights for any four quarter period, in each case provided there are no arrearages in the minimum quarterly distribution on our common units at that time.

The subordination period will also end, with respect to subordinated Units held by any person, upon the removal of our general partner other than for cause if the units held by such person and its affiliates are not voted in favor of such removal and such person is not an affiliate of the successor to the general partner.

When the subordination period ends, all subordinated units will convert into common units on a one-for-one basis, and all common units thereafter will no longer be entitled to arrearages.

During Subordination Period. Assuming our general partner maintains its approximate 0.1% general partner interest in us, our partnership agreement requires us to distribute all of our available cash from operating surplus for each quarter in the following manner during the subordination period:

· first, 99.9% to the common unitholders, pro rata, and 0.1% to our general partner, until we distribute for each common unit an amount equal to the minimum quarterly distribution for that quarter;
· second, 99.9% to the common unitholders, pro rata, and 0.1% to our general partner, until we distribute for each common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period;
· third, 99.9% to the subordinated unitholders, pro rata, and 0.1% to our general partner, until we distribute for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and
· fourth, 99.9% to all unitholders pro rata, and 0.1% to our general partner, until each unitholder receives a total of $0.54625 per unit for that quarter.

If cash distributions to our unitholders exceed $0.54625 per common unit and subordinated unit in any quarter, our unitholders and our general partner will receive distributions according to the following percentage allocations:

Total Quarterly Distribution		Marginal Percentage
		Interest in Distributions
Target Amount		Unitholders		General Partner
above $0.54625 up to $0.59375		86.9	%	13.1	%
above $0.59375		76.9	%	23.1	%

The percentage interests shown for our general partner include its approximate 0.1% general partner interest. We refer to the additional increasing distributions to our general partner in excess of its approximate 0.1% general partner interest as “incentive distributions.”

After Subordination Period. Our partnership agreement requires us to distribute all of our available cash from operating surplus each quarter in the following manner after the subordination period:

· first, 99.9% to the common unitholders, pro rata, and 0.1% to our general partner, until we distribute for each common unit an amount equal to the minimum quarterly distribution for that quarter;
· second, 99.9% to all unitholders, pro rata, and 0.1% to our general partner, until each unitholder receives a total of $0.54625 per unit for that quarter.
· thereafter, as provided in the table above.

Net_Loss_Income_Per_Limited_Pa

Net (Loss) Income Per Limited Partner Unit	12 Months Ended
	Dec. 31, 2013
Net (Loss) Income Per Limited Partner Unit	'
Net (Loss) Income Per Limited Partner Unit	'
	11. Net (Loss) Income Per Limited Partner Unit

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

		Year Ended December 31,						November 16 to
		2013			2012			December 31, 2011

	Net (loss) income	$	(48,281	)	$	6,787		$	15,125
	Net income attributable to predecessor operations	(448		)	(6,790		)	(2,975		)
	Net (loss) income available to unitholders	(48,729		)	(3		)	12,150
	Less: General partner’s approximate 0.1% interest in net loss (income)	49			—			(12		)
	Limited partners’ interest in net (loss) income	$	(48,680	)	$	(3	)	$	12,138

	Weighted average limited partner units outstanding:
	Common units	18,652			15,705			15,698
	Subordinated units	6,720			6,720			6,720
	Total	25,372			22,425			22,418

	Net (loss) income per limited partner unit (basic and diluted)	$	(1.92	)	$	(0.00	)	$	0.54

	Our subordinated units and restricted unit awards are considered to be participating securities for purposes of calculating our net (loss) income per limited partner unit, and accordingly, are included in basic computation as such. Net (loss) income per limited partner unit is determined by dividing the net (loss) income available to the common unitholders, after deducting our general partner’s approximate 0.1% interest in net (loss) income, by the number of common units and subordinated units outstanding as of December 31, 2013 and 2012. The aggregate number of common units and subordinated units was 19,559,934 and 6,720,000 as of December 31, 2013. The aggregate number of common units and subordinated units was 15,726,342 and 6,720,000 as of December 31, 2012. The majority of the units were outstanding since November 16, 2011.

EquityBased_Compensation

Equity-Based Compensation	12 Months Ended
	Dec. 31, 2013
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 December 31, 2013, there were 1,297,666 units available for issuance under the 2011 LTIP. The 2011 LTIP will be 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 over three years in equal amounts (subject to rounding) on the date of grant and are entitled to receive quarterly distributions during the vesting period.

	A summary of the non-vested units for the year ended December 31, 2013 is presented below:

				Weighted
		Number of		Average
		Non-vested		Grant-Date
		Units		Fair Value
	Non-vested restricted units at December 31, 2012	54,584		$	—
	Granted	133,592		16.32
	Vested	(22,914	)	18.58
	Forfeited	—		—
	Non-vested units at December 31, 2013	165,262


	As of December 31, 2013, there was $2.6 million of unrecognized compensation cost related to non-vested restricted units. The cost is expected to be recognized over a weighted average period of approximately 2.6 years. There were 37,072 vested restricted units as of December 31, 2013.

Contractual_Obligations_and_Co

Contractual Obligations and Commitments	12 Months Ended
Contractual Obligations and Commitments	Dec. 31, 2013
Contractual Obligations and Commitments	'
Contractual Obligations and Commitments	'
	13. Contractual Obligations and Commitments

	In the normal course of business, we enter into contracts that contain a variety of representations and warranties and provide general indemnifications. Our maximum exposure under these arrangements is unknown as this would involve future claims that may be made against us that have not yet occurred. We do not expect to suffer any material losses in connection with these contracts.

	Various federal, state and local laws and regulations covering, among other things, the release of waste materials into the environment and state and local taxes affect our operations and costs. Our management believes we are in substantial compliance with applicable federal, state and local laws, and management expects that the ultimate resolution of any claims or legal proceedings instituted against us will not have a material effect on our financial position or results of operations.

Subsidiary_Guarantors

Subsidiary Guarantors	12 Months Ended
Subsidiary Guarantors	Dec. 31, 2013
Subsidiary Guarantors	'
Subsidiary Guarantors	'
	14. Subsidiary Guarantors

	We and LRE Finance, our 100 percent-owned subsidiary, filed a registration statement on Form S-3 with the Securities and Exchange Commission (“SEC”) on August 28, 2013, and the SEC declared the registration statement effective on September 10, 2013. Securities that may be offered and sold include debt securities that are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933. LRE Finance may co-issue any debt securities issued by us pursuant to the registration statement. LRE Finance was formed solely for the purpose of co-issuing our debt securities and has no material assets or liabilities other than as co-issuer of our debt securities. 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 the Partnership’s 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 assets or OLLC represents restricted net assets pursuant to Rule 4-08(e)(3) of Regulation S-X.

Subsequent_Events

Subsequent Events	12 Months Ended
	Dec. 31, 2013
Subsequent Events	'
Subsequent Events	'
	15. Subsequent Events

	Unit Distribution

	On January 17, 2014, we announced that the board of directors of our general partner declared a cash distribution for the fourth quarter of 2013 of $0.4900 per outstanding unit, or $1.96 on an annualized basis. The distribution was paid on February 14, 2014 to all unitholders of record as of the close of business on January 31, 2014. The aggregate amount of the distribution was $12.9 million.

	At-the-Market Issuance Sales Program

	On February 4, 2014, we launched an “at-the-market” offering program (the “ATM”) with MLV & Co. LLC (“MLV”). We may sell from time to time through MLV, as sales agent, our common units representing limited partner interests having an aggregate offering amount of up to $75,000,000. Sales of common units under the ATM Program, if any, will be made by any method permitted by law deemed to be an “at-the-market offering” defined by Rule 415 of the Securities Act, including, without limitation, sales made directly on the New York Stock Exchange, or any other existing trading market for our common units or to or through a market maker.

	Our second lien term loan requires that 50% of the net cash proceeds from any equity offering be used to repay borrowings outstanding under the term loan. On February 12, 2014, we entered into an amendment to our Term Loan to waive this requirement through June 30, 2014. We plan to use the net proceeds from any offering under the ATM Program for general partnership purposes, including the repayment of borrowings outstanding under our revolving credit facility.

	Commodity Hedges

	Subsequent to December 31, 2013, we acquired the following commodity hedges:

		Index	2014

	NGL positions
	Price swaps (BBLs)	Mont Belvieu	60,112
	Weighted average price		$	35.07

Supplemental_Information_on_Oi

Supplemental Information on Oil and Natural Gas Exploration and Production Activities (Unaudited)	12 Months Ended
	Dec. 31, 2013
Supplemental Information on Oil and Natural Gas Exploration and Production Activities (Unaudited)	'
Supplemental Information on Oil and Natural Gas Exploration and Production Activities (Unaudited)	'
	16. Supplemental Information on Oil and Natural Gas Exploration and Production Activities (Unaudited)

	Oil and Natural Gas Capitalized Costs

	Capitalized costs relating to oil and natural gas producing activities are as follows at December 31 (in thousands):

			2013			2012

	Proved oil and natural gas properties		$	875,126		$	839,154
	Unproved oil and natural gas properties		1,258			1,264
			876,384			840,418
	Accumulated depletion and depreciation		(431,636		)	(324,630		)
	Net capitalized costs		$	444,748		515,788


	Costs Incurred in Oil and Natural Gas Property Acquisition and Development Activities

	Costs incurred in oil and natural gas property acquisition and development activities are as follows (in thousands):

			Partnership										Predecessor
			Year Ended			Year Ended			November 16 to				January 1 to
			December 31, 2013			December 31, 2012			December 31, 2011				November 15, 2011

	Acquisition of oil and natural gas properties
	Proved		$	10		$	9,795		$	56			$	392
	Unproved		—			—			—				—
	Development costs		36,484			31,598			2,461				48,702
	Total		$	36,494		41,393			$	2,517			$	49,094


	We had immaterial exploration costs for each of the periods during 2013, 2012 and 2011.

	Oil and Natural Gas Reserves

	The reserve disclosures that follow reflect estimates of proved reserves, proved developed reserves and proved undeveloped reserves, net of third-party royalty interests, of natural gas, crude oil and condensate, and NGLs owned at each year end and changes in proved reserves during each of those periods. Natural gas volumes are in millions of cubic feet (MMcf) at a pressure base of 14.73 pounds per square inch and volumes for oil, condensate and NGLs are in thousands of barrels (MBbls). Total volumes are presented in thousands of barrels of oil equivalent (MBOE). For this computation, one barrel of oil is assumed to be the equivalent of 6,000 cubic feet of natural gas. Shrinkage associated with NGLs has been deducted from the natural gas reserve volumes.

	Our estimates of proved reserves are made using available geological and reservoir data as well as production performance data. These estimates are reviewed on a periodic basis throughout the year by internal reservoir engineers and revised, either upward or downward, as warranted by additional data. Revisions are necessary due to changes in, among other things, reservoir performance, prices, economic conditions and governmental restrictions, as well as changes in the expected recovery associated with infill drilling.

	Our oil and natural gas properties and associated reserves are located in the continental United States. The following table presents the estimated remaining net proved, proved developed and proved undeveloped oil and natural gas reserves as of the periods indicated, and the related summary of changes in estimated quantities of net remaining proved reserves during those periods. Our estimated reserves at December 31, 2013, 2012 and 2011 were based on reserve reports prepared by the independent reserve engineers Miller and Lents, Ltd. and Netherland, Sewell & Associates, Inc.

			Oil		NGL		Gas
			(MBbls)		(MBbls)		(MMcf)
	Partnership:
	Balance, November 16, 2011		—		—		—
	Contribution from predecessor		10,053		3,637		119,204
	Production		(104	)	(35	)	(1,156	)
	Balance, December 31, 2011		9,949		3,602		118,048
	Revision of previous estimates		1,776		379		(14,630	)(1)
	Extensions and discoveries		546		134		606
	Acquisition of minerals in place		268	-2	—		—
	Sales of minerals in place		—		—		—
	Production		(834	)	(311	)	(8,487	)
	Balance, December 31, 2012		11,705		3,804		95,537
	Revision of previous estimates		(288	)	443		4,150
	Extensions and discoveries		118		37		181
	Acquisition of minerals in place		—		—		—
	Sales of minerals in place		—		—		—
	Production		(837	)	(315	)	(7,246	)
	Balance, December 31, 2013		10,698		3,969		92,622

	Proved developed reserves:
	December 31, 2011		7,607		2,787		108,227
	December 31, 2012		8,588		2,936		89,803
December 31, 2013		8,548		3,252		88,172
Proved undeveloped reserves:
December 31, 2011		2,342		815		9,821
December 31, 2012		3,117		868		5,734
December 31, 2013		2,150		717		4,450

(1) The decrease in natural gas reserves was primarily due to significantly lower natural gas prices during 2012.
(2) Represents an purchase of reserves by Fund II related to our April 2013 Acquisition.

		Oil		NGL		Gas
		(MBbls)		(MBbls)		(MMcf)
Predecessor:
Balance, December 31, 2010		5,937		3,045		109,601
Revision of previous estimates		126		(196	)	10,359
Extensions and discoveries		3,902		1,094		7,243
Acquisition of minerals in place		—		—		—
Sales of minerals in place		(29	)	—		(75	)
Production		(657	)	(269	)	(8,606	)
Balance, November 15, 2011		9,279		3,674		118,522

Standardized Measure of Discounted Future Net Cash Flows

Oil and natural gas reserve estimation and disclosure regulations require that reserve estimates and discounted future net cash flows are based on the unweighted average market prices for sales of oil and natural gas on the first calendar day of each month during the year. Cash flows are adjusted for transportation fees and regional price differentials, to the estimated future production of proved oil and natural gas reserves less estimated future expenditures to be incurred in developing and producing the proved reserves, discounted using an annual rate of 10% to reflect the estimated timing of the future cash flows. Income taxes are excluded because we and the Predecessor are non-taxable entities. Generally, all taxable income and losses are reported on the income tax returns of the unitholders and partners, and therefore, no provision for income taxes has been recorded in the accompanying

combined financial statements. Extensive judgments are involved in estimating the timing of production and the costs that will be incurred throughout the remaining lives of the properties. Accordingly, the estimates of future net cash flows from proved reserves and the present value may be materially different from subsequent actual results. The standardized measure of discounted net cash flows does not purport to present, nor should it be interpreted to present, the fair value of the acquired properties’ oil and natural gas reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, and anticipated future changes in prices and costs.

The standardized measure of discounted future net cash flows related to our interest in proved reserves as of the periods indicated are as follows (in thousands):

		Partnership									Predecessor
		Year Ended			Year Ended			November 16 to			January 1 to
		December 31, 2013			December 31, 2012			December 31, 2011			November 15, 2011

Future cash inflows		$	1,450,007		$	1,488,912		$	1,573,150		$	1,497,384
Future costs:
Development		(120,339		)	(163,316		)	(156,909		)	(157,048		)
Production		(526,523		)	(521,378		)	(508,204		)	(467,401		)
Texas margin tax		(1,187		)	—			—			—
Future net cash flows		801,958			804,218			908,037			872,935
10% discount to reflect timing of cash flows		(409,401		)	(416,322		)	(472,248		)	(454,253		)
Standardized measure of discounted future net cash flows		$	392,557		$	387,896		$	435,789		$	418,682

The principal changes in the standardized measure of discounted future net cash flows attributable to our proved reserves as of the periods indicated are as follows (in thousands):

		Partnership										Predecessor
		Year Ended			Year Ended			November 16 to				January 1 to
		December 31, 2013			December 31, 2012			December 31, 2011				November 15, 2011

Beginning of period		$	387,896		$	435,789		$	—			$	348,398
Contribution from predecessor		—			—			447,238				—
Purchase of reserves in place		—			5,866		-1	—				—
Sales of reserves in place		—			—			—				(676		)
Extensions and discoveries, net of future development costs		2,034			19,381			—				120,120
Revisions of quantity estimates		11,054			(1,373		)	—				17,326
Changes in future development costs, net		16,600			(871		)	—				1,125
Development costs incurred that reduce future development costs		25,408			12,164			—				4,331
Net changes in prices		4,363			(36,843		)	—				15,374
Change in future Texas margin tax		(570		)	—			—				—
Oil, natural gas and NGL sales, net of production costs		(80,117		)	(71,186		)	(11,449		)		(96,585		)
Changes in timing and other		(12,901		)	(18,610		)	—				(25,571		)
Accretion of discount		38,790			43,579			—				34,840
End of period		$	392,557		$	387,896		$	435,789			$	418,682

(1) Represents a purchase of reserves by Fund II related to our April 2013 Acquisition.

Selected_Quarterly_Financial_I

Selected Quarterly Financial Information (Unaudited)	12 Months Ended
	Dec. 31, 2013
Selected Quarterly Financial Information (Unaudited)	'
Selected Quarterly Financial Information (Unaudited)	'
	17. Selected Quarterly Financial Information (Unaudited)

	Quarterly financial data was as follows for the periods indicated (in thousands):

		First			Second		Third			Fourth
		Quarter			Quarter		Quarter			Quarter
	2013
	Revenues	$	17,780		$	41,379	$	25,195		$	30,741
	Operating (loss) income	(4,847		)	20,177		4,069			(59,645		)
	Net (loss) income	(7,002		)	20,523		284			(62,086		)
	Net (loss) income available to common unitholders	(7,450		)	20,523		284			(62,086		)
	Net (loss) income per limited partner unit	$	(0.32	)	$	0.78	$	0.01		$	(2.37	)

	2012
	Revenues	$	32,356		$	46,264	$	11,894		$	30,324
	Operating income (loss)	6,127			20,491		(10,900		)	2,487
	Net income (loss)	5,645			16,175		(15,279		)	246
	Net income (loss) available to common unitholders	3,849			12,205		(15,558		)	(499		)
	Net income (loss) per limited partner unit	$	0.17		$	0.54	$	(0.69	)	$	(0.02	)

Summary_of_Significant_Account1

Summary of Significant Accounting Policies (Policies)	12 Months Ended
Summary of Significant Accounting Policies (Policies)	Dec. 31, 2013
Summary of Significant Accounting Policies	'
Transactions between Entities under Common Control	'
	Transactions between Entities under Common Control

	Master limited partnerships (“MLPs”) enter into transactions whereby the MLP receives a transfer of certain assets from its sponsor or predecessor for consideration of either cash, units, assumption of debt, or any combination thereof. We account for the net assets received using the carryover book value of Lime Rock Resources as these were considered to be transactions between entities under common control. Our historical financial statements have been revised to include the results attributable to the assets contributed from Lime Rock Resources as if we owned such assets for all periods presented by us. The following financial statement items were impacted:

	Oil and Natural Gas Properties Received. The book value and related activity of oil and natural gas properties received from Lime Rock Resources is determined using the carrying value of the specific assets contributed.

	Commodity Derivative Instruments. Reflects the fair value of the commodity derivative contracts associated with the properties acquired from Lime Rock Resources.

	Asset Retirement Obligations Received. The book value and related activity of asset retirement obligations received from Lime Rock Resources was determined by using the carrying value of the specific liabilities attributable to the assets contributed.

	Oil, Natural Gas and NGL Revenues and Expenses. Oil, natural gas and NGL revenues and expenses related to the properties acquired are based on the actual results of the acquired properties. Historical lease operating statements by individual asset were used as the basis for revenues and direct operating expenses.

	Gain on Commodity Derivative Contracts, Net. Reflects the net gain on commodity derivative contracts associated with the properties acquired assuming the contracts were in place as of the date acquired by Lime Rock Resources.

	General and Administrative Expense. The general and administrative expense attributable to the properties acquired was determined by the ratio of production for the properties acquired to the total respective Lime Rock Resources’ production for the period presented.
Use of estimates	'
	Use of estimates

	The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates.

	Depreciation, depletion and amortization of oil and natural gas properties and the impairment of oil and natural gas properties are determined using estimates of oil and natural gas reserves. There are numerous uncertainties in estimating the quantity of reserves and in projecting the future rates of production and timing of development expenditures, including future costs to dismantle, dispose, and restore our properties. Oil and natural gas reserve engineering must be recognized as a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way.
Cash and cash equivalents	'
	Cash and cash equivalents

	We consider all highly liquid instruments purchased with a maturity when acquired of three months or less to be cash equivalents. We continually monitor our positions with, and the credit quality of, the financial institutions with which we invest.
Accounts receivable	'
	Accounts receivable

	Trade accounts receivable are recorded at the invoiced amount and do not bear interest. We use the specific identification method of providing allowances for doubtful accounts. At December 31, 2013 and 2012, we did not have an allowance for doubtful accounts.
Revenue recognition	'
	Revenue recognition

	Revenues from oil and gas sales are recognized based on the sales method with revenue recognized on actual volumes sold to purchasers. Under this method of revenue recognition, a gas imbalance is created if the quantity sold is greater than or less than our entitlement share in any particular period. To the extent there are sufficient quantities of natural gas remaining to make up the gas imbalance, oil and natural gas reserves are adjusted to reflect the overproduced or underproduced position. In situations where there are insufficient reserves available to make up an overproduced imbalance, a liability is established. As of December 31, 2013 and 2012, we had no significant production imbalances.
Concentrations of credit and significant customers	'
	Concentrations of credit and significant customers

	Financial instruments which potentially subject us to credit risk consist principally of cash balances, accounts receivable and derivative financial instruments. We maintain cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. We have not experienced any significant losses from such investments. We attempt to limit the amount of credit exposure to any one financial institution or company through procedures that include credit approvals, credit limits and terms, letters of credit, prepayments and rights of offset. Our customer base consists primarily of major integrated and international oil and natural gas companies, as well as smaller processors and gatherers. We believe the credit quality of our customer base is high and have not experienced significant write-downs in our accounts receivable balances.

	For the year ended December 31, 2013, purchases by ConocoPhillips, Holly Frontier, Sunoco and Seminole Energy Services accounted for 18%, 15%, 14% and 10% respectively, of our total sales revenues.

	For the year ended December 31, 2012, purchases by Sunoco, ConocoPhillips, and Shell Trading Company accounted for 17%, 16% and 10%, respectively, of our total sales revenues.

	For the period from November 16 to December 31, 2011, purchases by ConocoPhillips, Seminole Energy Services and Upstream Energy accounted for 25%, 16% and 12%, respectively, of our total sales revenues.

	For the period from January 1 to November 15, 2011, purchases by ConocoPhillips, Seminole Energy Services and Sunoco accounted for 18%, 12% and 16%, respectively, of our predecessor’s total sales revenues.

	If we were to lose any one of our customers, the loss could temporarily delay production and sale of oil and natural gas in the related producing region. If we were to lose any single customer, we believe that a substitute customer to purchase the impacted production volumes could be identified. However, if one or more of our larger customers ceased purchasing oil or natural gas altogether, the loss of such customer could have a detrimental effect on production volumes in general and on the ability to find substitute customers to purchase production volumes.
Oil and natural gas properties	'
	Oil and natural gas properties

	Proved properties. We account for our oil and natural gas exploration, development and production activities in accordance with the successful efforts method. Under this method, all leasehold and development costs of proved properties are capitalized and amortized on a unit-of-production basis over the remaining life of the proved reserves and proved developed reserves, respectively.

	We evaluate the potential impairment of our proved oil and natural gas properties on a field-by-field basis whenever events or changes in circumstances indicate that the carrying value may not be recoverable. We assess impairment of capitalized costs of proved oil and natural gas properties by comparing net capitalized costs to estimated undiscounted future net cash flows using expected prices. The carrying values of proved properties are reduced to fair value when the expected undiscounted future cash flows are less than net book value.

	For the years ended December 31, 2013 and 2012, we recorded non-cash impairment charges on proved oil and natural gas properties of $63.7 million and $3.1 million, respectively. For the period from January 1 to November 15, 2011, our predecessor recorded non-cash impairment charges on proved oil and natural gas properties of $16.8 million. These charges are included in “impairment of oil and natural gas properties” on the consolidated/combined statements of operations. No impairment was recorded for proved properties for the period from November 16 to December 31, 2011. Refer to Note 5 for additional information.

	Costs of retired, sold or abandoned properties that constitute a part of an amortization base are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized currently. Gains or losses from the disposal of proved properties are recognized currently. Expenditures for maintenance and repairs necessary to maintain properties in operating condition are expensed as incurred. Estimated dismantlement and abandonment costs are capitalized, net of salvage, at their estimated net present value and amortized on a unit-of-production basis over the remaining life of the related proved developed reserves.

	Unproved properties. Costs related to unproved properties include costs incurred to acquire unproved reserves. Because these reserves do not meet the definition of proved reserves, the related costs are not classified as proved properties. As of December 31, 2013 and 2012, $1.3 million of oil and natural gas property costs were related to unproved leasehold acquisitions costs and not subject to depletion. We did not reclassify any material amounts from unproved to proved properties during the years ended December 31, 2013 and 2012.

	We assess unproved properties for impairment on a quarterly basis. For the year ended December 31, 2012, we recorded an impairment charge for unproved properties in the amount of $0.4 million. No impairments were recorded for unproved properties during 2013 or 2011. The impairment was based on our experience in similar situations and other factors such as the primary lease terms of the properties, the average holding period of unproved properties, and the relative proportion of such properties on which proved reserves have been found in the past. The fair values of unproved 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 unproved 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 market-based weighted average cost of capital rate is subject to additional project-specific risk factors.
Other property and equipment	'
	Other property and equipment

	Other property and equipment is stated at historical cost less accumulated depreciation expense and is comprised primarily of software, computers and office equipment. Depreciation is calculated using the straight-line method based on useful lives of the assets ranging from three to five years. Other property and equipment is evaluated for impairment as necessary to determine if current circumstances and market conditions indicate that the carrying amounts of assets may not be recoverable. We did not recognize any impairment loss related to other property and equipment during 2013, 2012 and 2011.
Asset retirement obligations	'
	Asset retirement obligations

	We have obligations under our lease agreements and federal regulations to remove equipment and restore land at the end of oil and natural gas production operations. These asset retirement obligations (“ARO”) are primarily associated with plugging and abandoning wells. Determining the future restoration and removal requires management to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations. We record the fair value of a liability for an ARO in the period in which it is incurred with a corresponding increase in the carrying amount of the related long-lived asset. We typically incur this liability upon acquiring or drilling a well. Over time, the liability is accreted each period toward its future value, and the capitalized cost is depleted as a component of development costs. Upon settlement of the liability, a gain or loss is recognized to the extent the actual costs differ from the recorded liability.

	Inherent to the fair value calculation are numerous estimates, assumptions and judgments, including the ultimate settlement amounts, inflation factors, credit adjusted risk-free rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the abandonment liability, management will make corresponding adjustments to both the ARO and the related oil and natural gas property asset balance. Increases in the discounted retirement obligation liability and related oil and natural gas assets resulting from the passage of time will be reflected as additional accretion and depreciation expense in the consolidated/combined statements of operations.
Derivatives	'
	Derivatives

	Our activities primarily consist of acquiring, owning, enhancing and producing oil and natural gas properties. The future results of our operations, cash flows and financial condition may be affected by changes in the market price of oil and natural gas. The availability of a ready market for oil and natural gas products in the future will depend on numerous factors beyond our control, including weather, imports, marketing of competitive fuels, proximity and capacity of oil and natural gas pipelines and other transportation facilities, any oversupply or undersupply of oil, natural gas and liquid products, the regulatory environment, the economic environment and, other regional and political events, none of which can be predicted with certainty.

	In order for us to manage our exposure to oil and natural gas price volatility, we enter into commodity derivative instruments such as futures contracts, swaps, or options. We are also exposed to changes in interest rates, primarily as a result of variable rate borrowings under the credit facility. In an effort to reduce this exposure, we have, from time to time, entered into derivative contracts (interest rate swaps) to mitigate the risk of interest rate fluctuations. For commodity derivatives, the net gain or loss on commodity derivative contracts is recorded as a separate component of revenues. For interest rate derivatives, the net gain or loss on interest rate derivatives is recorded as a component of other income (expense) in the consolidated/combined statements of operations.

	All derivative instruments are recognized on the balance sheet as either assets or liabilities measured at fair value. Settlements on derivative hedging instruments and changes in the fair value of derivatives are recorded in earnings unless the derivatives qualify and are appropriately designated as hedges. We have not designated any of our derivative instruments as hedges. As a result, we mark our derivative instruments to fair value and recognize the changes in fair market value in earnings. Refer to Note 8 for additional information.

	Derivative financial instruments are generally executed with major financial institutions that expose us to market and credit risks and which may, at times, be concentrated with certain counterparties or groups of counterparties. All of our derivatives at December 31, 2013 are with parties that are also lenders under our credit facility. The credit worthiness of the counterparties is subject to continual review. We monitor the nonperformance risk of ourselves and of each of our counterparties and assesses 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 master netting arrangements in place with each counterparty to reduce credit exposure.
Equity-based compensation	'
	Equity-based compensation

	We have granted restricted unit awards which we account for at fair value. Restricted unit awards, net of estimated forfeitures, are expensed over the requisite service period. As each award vests, an adjustment is made to compensation cost for any difference between the estimated forfeitures and the actual forfeitures related to the vested awards. We record these compensation costs as general and administrative expenses. Refer to Note 12 for additional information.
Income taxes	'
	Income taxes

	We are not taxable for federal income tax purposes and do not directly pay federal income tax. Generally, all of our taxable federal income and losses are reported on the income tax returns of our unitholders or partners, and therefore, no provision for federal income taxes has been recorded in our accompanying consolidated/combined financial statements.

	We record our obligations under the Texas gross margin tax as “Income tax expense (benefit)” in the consolidated/combined statements of operations. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period of rate change.
Deferred financing costs	'
	Deferred financing costs

	Costs incurred in connection with the execution or modification of our credit facility are capitalized and amortized using the effective interest method over the term of the credit facility.
Recent accounting pronouncements	'
	Recent accounting pronouncements

	In December 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2011-11, “Disclosures about Offsetting Assets and Liabilities.” ASU No. 2011-11 required entities to disclose both gross information and net information about instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a master netting arrangement. The objective of the disclosure is to facilitate comparison between those entities that prepare their financial statements on the basis of GAAP and those entities that prepare their financial statements on the basis of International Financial Reporting Standards. In January 2013, the FASB issued ASU 2013-01, “Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities,” which clarified the scope of these disclosures to include bifurcated embedded derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions that are either offset or subject to an enforceable master netting arrangement or similar agreement. We adopted this guidance effective January 1, 2013. This guidance did not have a material impact on our consolidated financial position, results of operations or cash flows.

Acquisitions_Tables

Acquisitions (Tables)	12 Months Ended
Acquisitions (Tables)	Dec. 31, 2013
Acquisitions	'
Schedule of net assets conveyed by Fund I to the Partnership prior to closing of IPO	'
	The following table presents the net assets conveyed by Fund I to the Partnership immediately prior to the closing of IPO including the debt assumption (in thousands):

	Property and equipment, net	$	400,056
	Derivative instruments	36,705
	Total assets	$	436,761

	Long-term debt	$	27,251
	Derivative instruments	476
	Asset retirement obligations	22,673
	Total liabilities	$	50,400

	Net assets	$	386,361
Fund I as related party \| Acquisition of oil and natural gas properties located in the Permian Basin region of New Mexico and onshore Gulf Coast region of Texas	'
Acquisitions	'
Net assets conveyed by entity under common control in acquisition	'
	The following table presents the net assets conveyed by Fund I to us in the June 2012 Acquisition (in thousands):

	Property and equipment, net	$	60,365
	Asset retirement obligations and other liabilities	(1,043		)
	Net assets	$	59,322
Fund I as related party \| Acquisition of oil and natural gas properties located in the mid-continent region in Oklahoma	'
Acquisitions	'
Net assets conveyed by entity under common control in acquisition	'
	The following table presents the net assets conveyed by Fund I to us in the January 2013 Acquisition (in thousands):

	Property and equipment, net	$	23,998
	Oil and natural gas commodity hedge contracts	1,742
	Asset retirement obligations and other liabilities	(1,067		)
	Net assets	$	24,673
Fund II as related party \| Acquisition of oil and natural gas properties located in the mid-continent region in Oklahoma	'
Acquisitions	'
Net assets conveyed by entity under common control in acquisition	'
	The following table presents the net assets conveyed by Fund II to us in the April 2013 Acquisition (in thousands):

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

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2013
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 December 31, 2013 and 2012(in thousands).

		Level 1		Level 2		Level 3		Total
	December 31, 2013
	Assets:
	Commodity derivative instruments	$	—	$	26,472	$	—	$	26,472
	Liabilities:
	Commodity derivative instruments	—		2,391		—		2,391
	Interest rate derivative instruments	—		2,202		—		2,202
	December 31, 2012
	Assets:
	Commodity derivative instruments	$	—	$	36,484	$	—	$	36,484
	Liabilities:
	Commodity derivative instruments	—		2,545		—		2,545
	Interest rate derivative instruments	—		4,185		—		4,185

Property_and_Equipment_Tables

Property and Equipment (Tables)	12 Months Ended
	Dec. 31, 2013
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):

		December 31, 2013			December 31, 2012
	Oil and natural gas properties (successful efforts method)	$	875,126		$	839,154
	Unproved properties	1,258			1,264
	Other property and equipment	290			318
		876,674			840,736
	Accumulated depletion, depreciation and impairment	(431,837		)	(324,774		)
	Total property and equipment, net	$	444,837		$	515,962

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2013
Asset Retirement Obligations	'
Summary of ARO	'
	The following is a summary of our ARO as of and for the years indicated (in thousands):

		December 31, 2013			December 31, 2012
	Beginning of period	$	34,091		$	26,353
	Revisions to previous estimates	197			6,291		-1
	Liabilities incurred	476			364
	Liabilities settled	(362		)	(492		)
	Accretion expense	1,924			1,575
	End of period	36,326			34,091
	Current portion of ARO	(488		)	(500		)
	Asset retirement obligation-non-current	$	35,838		$	33,591

	(1) The revisions are primarily related to the accelerated timing of expected settlement of our ARO as it relates to our natural gas properties due to significantly lower natural gas prices during 2012.

Derivatives_Tables

Derivatives (Tables)	12 Months Ended
Derivatives (Tables)	Dec. 31, 2013
Derivatives	'
Schedule of open commodity derivative contracts	'
	At December 31, 2013, we had the following open commodity derivative contracts:

		Index		2014			2015			2016			2017
	Natural gas positions
	Price swaps (MMBTUs)	NYMEX-HH		6,077,016			5,500,236			5,433,888			5,045,760
	Weighted average price			$	5.53		$	5.72		$	4.29		$	4.61

	Basis swaps (MMBTUs)	NYMEX		5,876,098			5,326,559			2,877,047			—
	Weighted average price			$	(0.1521	)	$	(0.1661	)	$	(0.1115	)	$	—

	Oil positions
	Price swaps (BBLs)	NYMEX-WTI		723,634			561,833			397,488			198,744
	Weighted average price			$	95.76		$	93.16		$	86.02		$	85.75

	Basis swaps (BBLs)	Argus-		410,400			—			—			—
	Weighted average price	Midland-Cushing		$	(1.00	)	$	—		$	—		$	—

	NGL positions
	Price swaps (BBLs)	Mont Belvieu		183,857			147,823			—			—
	Weighted average price			$	34.11		$	34.5		$	—		$	—

	At December 31, 2012, we had the following open commodity derivative contracts:

		Index		2013			2014			2015			2016			2017
	Natural gas positions
	Price swaps (MMBTUs)	NYMEX-HH		7,516,540			6,077,016			5,500,236			4,878,990			4,605,396
	Weighted average price			$	5.16		$	5.53		$	5.72		$	4.28		$	4.61

	Basis swaps (MMBTUs)	NYMEX		7,446,301			5,876,098			5,326,559			2,877,047			—
	Weighted average price			$	(0.1361	)	$	(0.1521	)	$	(0.1661	)	$	(0.1115	)	$	—

	Puts (MMBTUs)	NYMEX-HH		178,710			—			—			—			—
	Strike price			$	3		$	—		$	—		$	—		$	—

	Oil positions
	Price swaps (BBLs)	NYMEX-WTI		698,816			519,102			420,381			397,488			198,744
	Weighted average price			$	95.95		$	96.61		$	94.72		$	86.02		$	85.75

	NGL positions
	Price swaps (BBLs)	Mont Belvieu		144,323			—			—			—			—
	Weighted average price			$	50.49		$	—		$	—		$	—		$	—

Schedule of interest rate swap derivative contracts	'
	At December 31, 2013 and 2012, we had the following interest rate swap derivative contracts (in thousands):

				Notional
	Effective	Maturity		Amount			Average %		Index
	February 2012	February 2015		$	150,000		0.5175	%	LIBOR
	February 2015	February 2017		75,000			1.725	%	LIBOR
	February 2015	February 2017		75,000			1.7275	%	LIBOR
	June 2012	June 2015		70,000			0.52375	%	LIBOR
	June 2015	June 2017		70,000			1.4275	%	LIBOR

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

		As of December 31, 2013
		Current			Long-term			Current			Long-term
		Assets			Assets			Liabilities			Liabilities

	Interest rate
	Swaps	$	—		$	637		$	648		$	2,191
	Gross fair value	—			637			648			2,191
	Netting arrangements	—			(637		)	—			(637		)
	Net recorded fair value	$	—		$	—		$	648		$	1,554

	Sale of natural gas production
	Price swaps	$	8,250		$	11,937		$	196		$	73
	Basis swaps	56			211			317			65
	Sale of crude oil production
	Price swaps	1,564			5,042			1,519			331
	Basis swaps	227			—			—			—
	Sale of NGLs
	Price swaps	106			4			662			153
	Gross fair value	10,203			17,194			2,694			622
	Netting arrangements	(477		)	(448		)	(477		)	(448		)
	Net recorded fair value	$	9,726		$	16,746		$	2,217		$	174

		As of December 31, 2012
		Current			Long-term			Current			Long-term
		Assets			Assets			Liabilities			Liabilities

	Interest rate
	Swaps	$	—		$	13		$	659		$	3,539
	Gross fair value	—			13			659			3,539
	Netting arrangements	—			(13		)	—			(13		)
	Net recorded fair value	$	—		$	—		$	659		$	3,526

	Sale of natural gas production
	Price swaps	$	12,185		$	17,460		$	155		$	1,073
	Basis swaps	18			27			317			470
	Sale of crude oil production
	Price swaps	3,949			5,248			2,061			2,066
	Sale of NGLs
	Price swaps	1,209			—			15			—
	Gross fair value	17,361			22,735			2,548			3,609
	Netting arrangements	(877		)	(2,735		)	(877		)	(2,735		)
	Net recorded fair value	$	16,484		$	20,000		$	1,671		$	874

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):

		Partnership										Predecessor
		Year Ended			Year Ended			November 16 to				January 1 to
		December 31,			December 31,			December 31,				November 15,
		2013			2012			2011				2011
	Commodity derivatives (revenue)	$	781		$	12,748		$	12,287			$	22,027
	Interest rate derivatives (other income/expense)	1,256			(4,650		)	—				(133		)

Related_Parties_Tables

Related Parties (Tables)	12 Months Ended
	Dec. 31, 2013
Related Parties	'
Schedule of changes in the affiliates (payable)/receivable balances	'
	Changes in the affiliates (payable)/receivable balances as of and for the years indicated are included below (in thousands):

					Lime Rock
		ServCo			Resources			Total

	Balance as of December 31, 2011	$	—		$	(536	)	$	(536	)
	Expenditures	(74,765		)	(11,708		)	(86,473		)
	Cash paid for expenditures	62,844			4,423			67,267
	Revenues and other	9,692			8,073			17,765
	Balance as of December 31, 2012	$	(2,229	)	$	252		$	(1,977	)
	Expenditures	(99,124		)	(1,019		)	(100,143		)
	Cash paid for expenditures	95,685			1,275			96,960
	Revenues and other	5,151			(246		)	4,905
	Balance as of December 31, 2013	$	(517	)	$	262		$	(255	)

Unitholders_Equity_Tables

Unitholders' Equity (Tables)	12 Months Ended
	Dec. 31, 2013
Unitholders' Equity	'
Schedule of percentage allocations for cash distributions in excess of $0.54625 per common unit and subordinated unit in any quarter	'


	Total Quarterly Distribution	Marginal Percentage
		Interest in Distributions
	Target Amount	Unitholders		General Partner
	above $0.54625 up to $0.59375	86.9	%	13.1	%
	above $0.59375	76.9	%	23.1	%

Net_Loss_Income_Per_Limited_Pa1

Net (Loss) Income Per Limited Partner Unit (Tables)	12 Months Ended
	Dec. 31, 2013
Net (Loss) Income Per Limited Partner Unit	'
Schedule of calculation of net (loss) income per limited partner unit	'
	The following sets forth the calculation of net (loss) income per limited partner unit for the following periods (in thousands, except per unit amounts):

		Year Ended December 31,						November 16 to
		2013			2012			December 31, 2011

	Net (loss) income	$	(48,281	)	$	6,787		$	15,125
	Net income attributable to predecessor operations	(448		)	(6,790		)	(2,975		)
	Net (loss) income available to unitholders	(48,729		)	(3		)	12,150
	Less: General partner’s approximate 0.1% interest in net loss (income)	49			—			(12		)
	Limited partners’ interest in net (loss) income	$	(48,680	)	$	(3	)	$	12,138

	Weighted average limited partner units outstanding:
	Common units	18,652			15,705			15,698
	Subordinated units	6,720			6,720			6,720
	Total	25,372			22,425			22,418

	Net (loss) income per limited partner unit (basic and diluted)	$	(1.92	)	$	(0.00	)	$	0.54

EquityBased_Compensation_Table

Equity-Based Compensation (Tables)	12 Months Ended
Equity-Based Compensation (Tables)	Dec. 31, 2013
Equity-Based Compensation	'
Summary of the non-vested units	'


				Weighted
		Number of		Average
		Non-vested		Grant-Date
		Units		Fair Value
	Non-vested restricted units at December 31, 2012	54,584		$	—
	Granted	133,592		16.32
	Vested	(22,914	)	18.58
	Forfeited	—		—
	Non-vested units at December 31, 2013	165,262

Subsequent_Events_Tables

Subsequent Events (Tables)	12 Months Ended
Subsequent Events (Tables)	Dec. 31, 2013
Subsequent Events	'
Schedule of commodity hedges	'
	Subsequent to December 31, 2013, we acquired the following commodity hedges:

		Index	2014

	NGL positions
	Price swaps (BBLs)	Mont Belvieu	60,112
	Weighted average price		$	35.07

Supplemental_Information_on_Oi1

Supplemental Information on Oil and Natural Gas Exploration and Production Activities (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2013
Supplemental Information on Oil and Natural Gas Exploration and Production Activities (Unaudited)	'
Schedule of capitalized costs relating to oil and natural gas producing activities	'
	Capitalized costs relating to oil and natural gas producing activities are as follows at December 31 (in thousands):

		2013			2012

	Proved oil and natural gas properties	$	875,126		$	839,154
	Unproved oil and natural gas properties	1,258			1,264
		876,384			840,418
	Accumulated depletion and depreciation	(431,636		)	(324,630		)
	Net capitalized costs	$	444,748		515,788

Schedule of costs incurred in oil and natural gas property acquisition and development activities	'
	Costs incurred in oil and natural gas property acquisition and development activities are as follows (in thousands):

		Partnership										Predecessor
		Year Ended			Year Ended			November 16 to				January 1 to
		December 31, 2013			December 31, 2012			December 31, 2011				November 15, 2011

	Acquisition of oil and natural gas properties
	Proved	$	10		$	9,795		$	56			$	392
	Unproved	—			—			—				—
	Development costs	36,484			31,598			2,461				48,702
	Total	$	36,494		41,393			$	2,517			$	49,094
Schedule of estimated remaining net proved, proved developed and proved undeveloped oil and natural gas reserves and changes in estimated quantities of net remaining proved reserves	'


		Oil		NGL		Gas
		(MBbls)		(MBbls)		(MMcf)
	Partnership:
	Balance, November 16, 2011	—		—		—
	Contribution from predecessor	10,053		3,637		119,204
	Production	(104	)	(35	)	(1,156	)
	Balance, December 31, 2011	9,949		3,602		118,048
	Revision of previous estimates	1,776		379		(14,630	)(1)
	Extensions and discoveries	546		134		606
	Acquisition of minerals in place	268	-2	—		—
	Sales of minerals in place	—		—		—
	Production	(834	)	(311	)	(8,487	)
	Balance, December 31, 2012	11,705		3,804		95,537
	Revision of previous estimates	(288	)	443		4,150
	Extensions and discoveries	118		37		181
	Acquisition of minerals in place	—		—		—
	Sales of minerals in place	—		—		—
	Production	(837	)	(315	)	(7,246	)
	Balance, December 31, 2013	10,698		3,969		92,622

	Proved developed reserves:
	December 31, 2011	7,607		2,787		108,227
	December 31, 2012	8,588		2,936		89,803
	December 31, 2013	8,548		3,252		88,172
	Proved undeveloped reserves:
	December 31, 2011	2,342		815		9,821
	December 31, 2012	3,117		868		5,734
	December 31, 2013	2,150		717		4,450

	(1) The decrease in natural gas reserves was primarily due to significantly lower natural gas prices during 2012.
	(2) Represents an purchase of reserves by Fund II related to our April 2013 Acquisition.

		Oil		NGL		Gas
		(MBbls)		(MBbls)		(MMcf)
	Predecessor:
	Balance, December 31, 2010	5,937		3,045		109,601
	Revision of previous estimates	126		(196	)	10,359
	Extensions and discoveries	3,902		1,094		7,243
	Acquisition of minerals in place	—		—		—
	Sales of minerals in place	(29	)	—		(75	)
	Production	(657	)	(269	)	(8,606	)
	Balance, November 15, 2011	9,279		3,674		118,522

Schedule of standardized measure of discounted future net cash flows related to interest in proved reserves	'
	The standardized measure of discounted future net cash flows related to our interest in proved reserves as of the periods indicated are as follows (in thousands):

		Partnership									Predecessor
		Year Ended			Year Ended			November 16 to			January 1 to
		December 31, 2013			December 31, 2012			December 31, 2011			November 15, 2011

	Future cash inflows	$	1,450,007		$	1,488,912		$	1,573,150		$	1,497,384
	Future costs:
	Development	(120,339		)	(163,316		)	(156,909		)	(157,048		)
	Production	(526,523		)	(521,378		)	(508,204		)	(467,401		)
	Texas margin tax	(1,187		)	—			—			—
	Future net cash flows	801,958			804,218			908,037			872,935
	10% discount to reflect timing of cash flows	(409,401		)	(416,322		)	(472,248		)	(454,253		)
	Standardized measure of discounted future net cash flows	$	392,557		$	387,896		$	435,789		$	418,682

Schedule of principal changes in the standardized measure of discounted future net cash flows attributable to proved reserves	'
	The principal changes in the standardized measure of discounted future net cash flows attributable to our proved reserves as of the periods indicated are as follows (in thousands):

		Partnership										Predecessor
		Year Ended			Year Ended			November 16 to				January 1 to
		December 31, 2013			December 31, 2012			December 31, 2011				November 15, 2011

	Beginning of period	$	387,896		$	435,789		$	—			$	348,398
	Contribution from predecessor	—			—			447,238				—
	Purchase of reserves in place	—			5,866		-1	—				—
	Sales of reserves in place	—			—			—				(676		)
	Extensions and discoveries, net of future development costs	2,034			19,381			—				120,120
	Revisions of quantity estimates	11,054			(1,373		)	—				17,326
	Changes in future development costs, net	16,600			(871		)	—				1,125
	Development costs incurred that reduce future development costs	25,408			12,164			—				4,331
	Net changes in prices	4,363			(36,843		)	—				15,374
	Change in future Texas margin tax	(570		)	—			—				—
	Oil, natural gas and NGL sales, net of production costs	(80,117		)	(71,186		)	(11,449		)		(96,585		)
	Changes in timing and other	(12,901		)	(18,610		)	—				(25,571		)
	Accretion of discount	38,790			43,579			—				34,840
	End of period	$	392,557		$	387,896		$	435,789			$	418,682

	(1) Represents a purchase of reserves by Fund II related to our April 2013 Acquisition.

Selected_Quarterly_Financial_I1

Selected Quarterly Financial Information (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2013
Selected Quarterly Financial Information (Unaudited)	'
Schedule of quarterly financial data	'
	Quarterly financial data was as follows for the periods indicated (in thousands):

		First			Second		Third			Fourth
		Quarter			Quarter		Quarter			Quarter
	2013
	Revenues	$	17,780		$	41,379	$	25,195		$	30,741
	Operating (loss) income	(4,847		)	20,177		4,069			(59,645		)
	Net (loss) income	(7,002		)	20,523		284			(62,086		)
	Net (loss) income available to common unitholders	(7,450		)	20,523		284			(62,086		)
	Net (loss) income per limited partner unit	$	(0.32	)	$	0.78	$	0.01		$	(2.37	)

	2012
	Revenues	$	32,356		$	46,264	$	11,894		$	30,324
	Operating income (loss)	6,127			20,491		(10,900		)	2,487
	Net income (loss)	5,645			16,175		(15,279		)	246
	Net income (loss) available to common unitholders	3,849			12,205		(15,558		)	(499		)
	Net income (loss) per limited partner unit	$	0.17		$	0.54	$	(0.69	)	$	(0.02	)

Organization_and_Description_o1

Organization and Description of Business (Details) (LRE Finance)	12 Months Ended
	Dec. 31, 2013
LRE Finance	'
Description of Business	'
Ownership interest held (as a percent)	100.00%

Organization_and_Description_o2

Organization and Description of Business (Details 2) (USD $)

1 Months Ended

12 Months Ended

0 Months Ended

10 Months Ended

0 Months Ended

10 Months Ended

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 14, 2011

Nov. 17, 2011

Nov. 15, 2011

Nov. 17, 2011

Nov. 15, 2011

Fund I as related party

Fund I (as predecessor)

Acquisition of the Partnership Properties in connection with the IPO

Common Units

Subordinated Units

Fund I as related party

Fund I (as predecessor)

Common Units

Subordinated Units

Acquisitions

Percentage of ownership held prior to the IPO in the properties conveyed to the entity in connection with the IPO

100.00%

Capital units issued as consideration for properties conveyed

5,049,600

6,720,000

5,049,600

6,720,000

Distributions

$48,893,000

$37,262,000

$43,353,000

$311,200,000

Assumption of debt as consideration for properties conveyed

$27,300,000

Organization_and_Description_o3

Organization and Description of Business (Details 3) (Fund I (as predecessor), USD $)	12 Months Ended
	Dec. 31, 2013
Omnibus Agreement	'
Amount per claim subject to de minimus exception	$50,000
Aggregate losses to be exceeded for indemnification claims to be made	500,000
Aggregate losses in excess of which each entity of Fund I will be liable	500,000
Environmental claims, losses and expenses associated with operation of the business prior to closing of the IPO	'
Omnibus Agreement	'
Maximum amount indemnified by related party	$10,000,000
Title defects	'
Omnibus Agreement	'
Indemnification period following closing of IPO	'3 years
Environmental claims, undisclosed liabilities and failure to have any consent, waiver or governmental permits	'
Omnibus Agreement	'
Indemnification period following closing of IPO	'1 year
Income taxes	'
Omnibus Agreement	'
Indemnification period following expiration of statue of limitations	'60 days

Summary_of_Significant_Account2

Summary of Significant Accounting Policies (Details)	12 Months Ended
	Dec. 31, 2013
	item
Summary of Significant Accounting Policies	'
Number of operating segment	1

Summary_of_Significant_Account3

Summary of Significant Accounting Policies (Details 2)	1 Months Ended	10 Months Ended	12 Months Ended
Summary of Significant Accounting Policies (Details 2)	Dec. 31, 2011	Nov. 15, 2011	Dec. 31, 2013	Dec. 31, 2012
ConocoPhillips	'	'	'	'
Concentrations of credit and significant customers	'	'	'	'
Total sales revenues (as a percent)	25.00%	18.00%	18.00%	16.00%
Holly Frontier	'	'	'	'
Concentrations of credit and significant customers	'	'	'	'
Total sales revenues (as a percent)	'	'	15.00%	'
Seminole Energy Services	'	'	'	'
Concentrations of credit and significant customers	'	'	'	'
Total sales revenues (as a percent)	16.00%	12.00%	10.00%	'
Upstream Energy	'	'	'	'
Concentrations of credit and significant customers	'	'	'	'
Total sales revenues (as a percent)	12.00%	'	'	'
Sunoco	'	'	'	'
Concentrations of credit and significant customers	'	'	'	'
Total sales revenues (as a percent)	'	16.00%	14.00%	17.00%
Shell Trading Company	'	'	'	'
Concentrations of credit and significant customers	'	'	'	'
Total sales revenues (as a percent)	'	'	'	10.00%

Summary_of_Significant_Account4

Summary of Significant Accounting Policies (Details 3) (USD $)

12 Months Ended

10 Months Ended

1 Months Ended

12 Months Ended

10 Months Ended

1 Months Ended

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Nov. 15, 2011

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Nov. 15, 2011

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Predecessor

Proved properties

Unproved properties

Other property and equipment

Predecessor

Minimum

Maximum

Oil and natural gas and other properties

Non-cash impairment charge

$63,663,000

$3,544,000

$16,765,000

$63,700,000

$3,100,000

$16,800,000

$400,000

Unproved leasehold acquisitions costs not subject to depletion

1,300,000

Property and equipment, useful life

'3 years

'5 years

Income taxes

Provision for federal income taxes

Acquisitions_Details

Acquisitions (Details) (USD $)

1 Months Ended

12 Months Ended

0 Months Ended

1 Months Ended

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 14, 2011

Nov. 17, 2011

Jun. 30, 2013

Jan. 03, 2013

Apr. 01, 2013

Nov. 17, 2011

Jun. 02, 2012

Sep. 30, 2012

Fund I as related party

Acquisition of oil and natural gas properties located in the mid-continent region in Oklahoma

Acquisition of the Partnership Properties in connection with the IPO

Acquisition of oil and natural gas properties located in the Permian Basin region of New Mexico and onshore Gulf Coast region of Texas

Common Units

Subordinated Units

Fund I as related party

Fund II as related party

Fund I as related party

Fund II as related party

Common Units

Subordinated Units

Acquisitions

Purchase price

$400,000

$21,000,000

$38,200,000

$65,100,000

Cash received related to post-closing adjustments to purchase price

1,100,000

Capital units issued as consideration for properties conveyed

5,049,600

6,720,000

5,049,600

6,720,000

Distributions

48,893,000

37,262,000

311,200,000

Assumption of debt as consideration for properties conveyed

27,300,000

Net assets conveyed by Fund I to the Partnership in the Transaction

Property and equipment, net

444,748,000

515,788,000

23,998,000

36,586,000

400,056,000

60,365,000

Derivative instruments

36,705,000

TOTAL ASSETS

488,350,000

565,470,000

436,761,000

Long-term debt

250,000,000

228,000,000

27,251,000

Derivative instruments

476,000

Asset retirement obligations

26,353,000

36,326,000

34,091,000

22,673,000

Total liabilities

296,092,000

274,694,000

50,400,000

Oil and natural gas commodity hedge contracts

1,742,000

386,000

Asset retirement obligations and other liabilities

-1,067,000

-990,000

-1,043,000

Net assets

$24,673,000

$35,982,000

$386,361,000

$59,322,000

Fair_Value_Measurements_Detail

Fair Value Measurements (Details) (Recurring, USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Level 2 \| Commodity derivative instruments	'	'
Fair Value Measurements	'	'
Assets	$26,472	$36,484
Liabilities	2,391	2,545
Level 2 \| Interest rate derivative instruments	'	'
Fair Value Measurements	'	'
Liabilities	2,202	4,185
Total \| Commodity derivative instruments	'	'
Fair Value Measurements	'	'
Assets	26,472	36,484
Liabilities	2,391	2,545
Total \| Interest rate derivative instruments	'	'
Fair Value Measurements	'	'
Liabilities	$2,202	$4,185

Property_and_Equipment_Details

Property and Equipment (Details) (USD $)	1 Months Ended	12 Months Ended		10 Months Ended	1 Months Ended	12 Months Ended		10 Months Ended	1 Months Ended	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2013	Dec. 31, 2012	Nov. 15, 2011	Dec. 31, 2011	Dec. 31, 2013	Dec. 31, 2012	Nov. 15, 2011	Dec. 31, 2011	Dec. 31, 2013	Dec. 31, 2012
				Predecessor	Proved properties	Proved properties	Proved properties	Proved properties	Unproved properties	Unproved properties	Unproved properties
								Predecessor
Property and Equipment	'	'	'	'	'	'	'	'	'	'	'
Oil and natural gas properties (successful efforts method)	'	$875,126,000	$839,154,000	'	'	'	'	'	'	'	'
Unproved properties	'	1,258,000	1,264,000	'	'	'	'	'	'	'	'
Other property and equipment	'	290,000	318,000	'	'	'	'	'	'	'	'
Property and equipment, gross	'	876,674,000	840,736,000	'	'	'	'	'	'	'	'
Accumulated depletion, depreciation and impairment	'	-431,837,000	-324,774,000	'	'	'	'	'	'	'	'
Total property and equipment, net	'	444,837,000	515,962,000	'	'	'	'	'	'	'	'
Property and equipment, impairment	'	'	'	'	'	'	'	'	'	'	'
Depletion and depreciation expense	5,876,000	43,420,000	46,928,000	37,206,000	'	'	'	'	'	'	'
Non-cash impairment charge	'	63,663,000	3,544,000	16,765,000	0	63,700,000	3,100,000	16,800,000	0	0	400,000
Estimated fair value	'	'	'	'	'	$76,200,000	'	'	'	'	'

Asset_Retirement_Obligations_D

Asset Retirement Obligations (Details) (USD $)	1 Months Ended	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2013	Dec. 31, 2012
Asset retirement obligations	'	'	'
Beginning of period	'	$34,091	$26,353
Revisions to previous estimates	'	197	6,291
Liabilities incurred	'	476	364
Liabilities settled	'	-362	-492
Accretion expense	191	1,924	1,575
End of period	26,353	36,326	34,091
Current portion of ARO	'	-488	-500
Asset retirement obligation-non-current	'	$35,838	$33,591

LongTerm_Debt_Details

Long-Term Debt (Details) (USD $)

1 Months Ended

12 Months Ended

10 Months Ended

0 Months Ended

1 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Nov. 15, 2011

Jan. 02, 2013

Jul. 31, 2011

Nov. 17, 2011

Dec. 31, 2013

Jun. 28, 2012

Dec. 31, 2013

Predecessor

Acquisition of the Transferred Properties from Fund I

Senior secured revolving credit facility (Credit Agreement)

Second Lien Credit Agreement (Term Loan Agreement)

Minimum

Maximum

Option one variable rate

Prime rate

Federal funds effective rate

30-day adjusted LIBOR

Reserve-adjusted LIBOR

Minimum

Maximum

Option one variable rate

Prime rate

Federal funds effective rate

30-day adjusted LIBOR

Reserve-adjusted LIBOR

Minimum

Maximum

Minimum

Maximum

Through March 31, 2013

From April 1, 2013 to December 31, 2013

From January 1, 2014 to January 20, 2017

Through March 31, 2013

From April 1, 2013 to December 31, 2013

From January 1, 2014 to January 20, 2017

Long-Term Debt

Term of credit facility

'5 years

Maximum borrowing capacity

$500,000,000

Borrowing capacity

250,000,000

Percentage of PV-10 value of oil and gas interests serving as collateral

80.00%

Description of variable rate

'prime rate

'federal funds effective rate

'30-day adjusted LIBOR

'Reserve-adjusted LIBOR

'Prime rate

'Federal funds effective rate

'30-day adjusted LIBOR

'Reserve-adjusted LIBOR

Interest rate added to base rate (as a percent)

0.50%

1.00%

1.75%

2.75%

0.50%

1.00%

5.50%

7.00%

8.50%

Interest margin to calculate base rate (as a percent)

0.75%

1.75%

4.50%

6.00%

7.50%

Commitment fee on unused portion (as a percent)

0.38%

0.50%

Leverage ratio of Total Debt to EBITDAX

4.25

Ratio of consolidated current assets to consolidated current liabilities

Asset coverage ratio of total proved PV-10 to total debt

1.5

Face amount

50,000,000

Amount borrowed

50,000,000

Upfront fee as percentage of the aggregate maximum commitment amount

1.00%

Upfront fee

500,000

Outstanding debt

250,000,000

228,000,000

Accrued interest

200,000

Interest expense

604,000

9,235,000

6,596,000

918,000

Increase in outstanding debt

$21,000,000

Weighted average interest rate (as a percent)

3.88%

3.47%

Derivatives_Details

Derivatives (Details) (USD $)

12 Months Ended

0 Months Ended

In Thousands, unless otherwise specified

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Basis swaps

Interest rate swap

Natural gas positions

Oil positions

NGL positions

item

February 2012 - February 2015

February 2015 - February 2017, one

February 2015 - February 2017, two

June 2012 - June 2015

June 2015 - June 2017

Price swaps

Basis swaps

Puts

Price swaps

Basis swaps

Price swaps

2013

2014

2015

2016

2017

2013

2014

2015

2016

2013

2014

2015

2016

2017

2014

2013

2014

2015

MMBTU

bbl

Derivatives

Number of indices for gas on which floating price is based

Volume of commodity hedge (in MMBTUs)

7,516,540

6,077,016

5,500,236

5,433,888

4,878,990

5,045,760

4,605,396

7,446,301

5,876,098

5,326,559

2,877,047

178,710

Volume of commodity hedge (in BBLs)

698,816

723,634

519,102

561,833

420,381

397,488

198,744

410,400

144,323

183,857

147,823

Weighted average price of commodity hedge (in dollars per MMBTU/BBL)

5.16

5.53

5.72

4.29

4.28

4.61

-0.1361

-0.1521

-0.1661

-0.1115

95.95

95.76

96.61

93.16

94.72

86.02

85.75

-1

50.49

34.11

34.5

Strike price (in dollars per MMBTU)

Notional Amount

$150,000

$75,000

$70,000

Average %

0.52%

1.73%

0.52%

1.43%

Index

'LIBOR

Derivatives_Details_2

Derivatives (Details 2) (Not designated as hedges, USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Current Assets	'	'
Fair value of derivative instruments	'	'
Gross fair value of assets	$10,203	$17,361
Netting arrangements, assets	-477	-877
Net recorded fair value of assets	9,726	16,484
Long-term Assets	'	'
Fair value of derivative instruments	'	'
Gross fair value of assets	17,194	22,735
Netting arrangements, assets	-448	-2,735
Net recorded fair value of assets	16,746	20,000
Current Liabilities	'	'
Fair value of derivative instruments	'	'
Gross fair value of liabilities	2,694	2,548
Netting arrangements, liabilities	-477	-877
Net recorded fair value of liabilities	2,217	1,671
Long-term Liabilities	'	'
Fair value of derivative instruments	'	'
Gross fair value of liabilities	622	3,609
Netting arrangements, liabilities	-448	-2,735
Net recorded fair value of liabilities	174	874
Interest rate swap \| Long-term Assets	'	'
Fair value of derivative instruments	'	'
Gross fair value of assets	637	13
Netting arrangements, assets	-637	-13
Interest rate swap \| Current Liabilities	'	'
Fair value of derivative instruments	'	'
Gross fair value of liabilities	648	659
Net recorded fair value of liabilities	648	659
Interest rate swap \| Long-term Liabilities	'	'
Fair value of derivative instruments	'	'
Gross fair value of liabilities	2,191	3,539
Netting arrangements, liabilities	-637	-13
Net recorded fair value of liabilities	1,554	3,526
Price swaps \| Sale of natural gas production \| Current Assets	'	'
Fair value of derivative instruments	'	'
Gross fair value of assets	8,250	12,185
Price swaps \| Sale of natural gas production \| Long-term Assets	'	'
Fair value of derivative instruments	'	'
Gross fair value of assets	11,937	17,460
Price swaps \| Sale of natural gas production \| Current Liabilities	'	'
Fair value of derivative instruments	'	'
Gross fair value of liabilities	196	155
Price swaps \| Sale of natural gas production \| Long-term Liabilities	'	'
Fair value of derivative instruments	'	'
Gross fair value of liabilities	73	1,073
Price swaps \| Sale of crude oil production \| Current Assets	'	'
Fair value of derivative instruments	'	'
Gross fair value of assets	1,564	3,949
Price swaps \| Sale of crude oil production \| Long-term Assets	'	'
Fair value of derivative instruments	'	'
Gross fair value of assets	5,042	5,248
Price swaps \| Sale of crude oil production \| Current Liabilities	'	'
Fair value of derivative instruments	'	'
Gross fair value of liabilities	1,519	2,061
Price swaps \| Sale of crude oil production \| Long-term Liabilities	'	'
Fair value of derivative instruments	'	'
Gross fair value of liabilities	331	2,066
Price swaps \| Sale of NGLs \| Current Assets	'	'
Fair value of derivative instruments	'	'
Gross fair value of assets	106	1,209
Price swaps \| Sale of NGLs \| Long-term Assets	'	'
Fair value of derivative instruments	'	'
Gross fair value of assets	4	'
Price swaps \| Sale of NGLs \| Current Liabilities	'	'
Fair value of derivative instruments	'	'
Gross fair value of liabilities	662	15
Price swaps \| Sale of NGLs \| Long-term Liabilities	'	'
Fair value of derivative instruments	'	'
Gross fair value of liabilities	153	'
Basis swaps \| Sale of natural gas production \| Current Assets	'	'
Fair value of derivative instruments	'	'
Gross fair value of assets	56	18
Basis swaps \| Sale of natural gas production \| Long-term Assets	'	'
Fair value of derivative instruments	'	'
Gross fair value of assets	211	27
Basis swaps \| Sale of natural gas production \| Current Liabilities	'	'
Fair value of derivative instruments	'	'
Gross fair value of liabilities	317	317
Basis swaps \| Sale of natural gas production \| Long-term Liabilities	'	'
Fair value of derivative instruments	'	'
Gross fair value of liabilities	65	470
Basis swaps \| Sale of crude oil production \| Current Assets	'	'
Fair value of derivative instruments	'	'
Gross fair value of assets	$227	'

Derivatives_Details_3

Derivatives (Details 3) (Not designated as hedges, USD $)	1 Months Ended	12 Months Ended				10 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Nov. 15, 2011	Nov. 15, 2011
	Commodity derivatives	Commodity derivatives	Commodity derivatives	Interest rate derivatives	Interest rate derivatives	Predecessor	Predecessor
	Revenue	Revenue	Revenue	Other income/expense	Other income/expense	Commodity derivatives	Interest rate derivatives
						Revenue	Other income/expense
Unrealized and realized gain or loss amounts	'	'	'	'	'	'	'
Derivative instruments, gains losses	$12,287	$781	$12,748	$1,256	($4,650)	$22,027	($133)

Related_Parties_Details

Related Parties (Details) (USD $)

1 Months Ended

12 Months Ended

10 Months Ended

0 Months Ended

12 Months Ended

10 Months Ended

12 Months Ended

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Nov. 15, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 14, 2011

Nov. 17, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Nov. 15, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Fund I (as predecessor)

Common units

Fund I as related party

Lime Rock Management LP

General partner and its affiliates

ServCo

Lime Rock Resources

Common units

Fund I (as predecessor)

Common units

Related Parties

Partnership interest (as a percent)

9.50%

32.10%

0.10%

Percentage of limited partner interest

32.60%

52.40%

General partner units held

22,400

Payment made to related party

$1,800,000

$2,100,000

Changes in the affiliates (payable)/receivable balances

Balance at the beginning of the period

-1,977,000

-536,000

-2,229,000

252,000

-536,000

Expenditures

-100,143,000

-86,473,000

-99,124,000

-74,765,000

-1,019,000

-11,708,000

Cash paid for expenditures

96,960,000

67,267,000

95,685,000

62,844,000

1,275,000

4,423,000

Revenues and other

4,905,000

17,765,000

5,151,000

9,692,000

-246,000

8,073,000

Balance at the end of the period

-536,000

-255,000

-1,977,000

-517,000

-2,229,000

262,000

252,000

Limited partner units held

19,559,934

15,726,342

1,849,600

5,049,600

Aggregate amount of distribution

48,893,000

37,262,000

43,353,000

311,200,000

289,900,000

Related party management fees

5,400,000

Related party revenue

$900,000

Unitholders_Equity_Details

Unitholders' Equity (Details) (USD $)

1 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

0 Months Ended

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Nov. 17, 2011

Jul. 31, 2011

Dec. 14, 2011

Nov. 17, 2011

Dec. 31, 2013

Dec. 31, 2012

Mar. 22, 2013

Dec. 14, 2011

Nov. 17, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Mar. 22, 2013

Nov. 17, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Nov. 17, 2011

Dec. 31, 2013

General Partner

First priority for cash distributions during the subordination period

Second priority for cash distributions during the subordination period

Third priority for cash distributions during the subordination period

Fourth priority for cash distributions during the subordination period

Cash distributions above $0.54625 up to $0.59375

Cash distributions above $0.59376

First priority for cash distributions after the subordination period

Second priority for cash distributions after the subordination period

Senior secured revolving credit agreement

Fund I as related party

Common Units

Subordinated Units

General Partner

Unitholders

General Partner

Maximum

Unitholders

General Partner

Minimum

Maximum

Unitholders

General Partner

Minimum

General Partner

Unitholders

General Partner

Maximum

First priority for cash distributions during the subordination period

Second priority for cash distributions during the subordination period

First priority for cash distributions after the subordination period

Fund I as related party

item

Third priority for cash distributions during the subordination period

Fund I as related party

Equity offering

Number of shares issued

3,700,000

1,200,000

9,408,000

Share price of units issued in equity offering (in dollars per unit)

$16.84

$19

$16.84

Share price of units issued in equity offering after payment of underwriting discount (in dollars per unit)

$16.17

$17.81

$16.17

Net proceeds from the sale of common units in equity offering

$59,513,000

$59,500,000

$21,300,000

$167,200,000

Offering expenses

4,716,000

300,000

4,700,000

Gross proceeds from the sale of common units in IPO

178,800,000

Underwriting discount

11,200,000

Structuring fee

400,000

Reimbursement by Partnership for costs incurred in connection with the IPO

3,200,000

Borrowings under revolving credit facility

155,800,000

60,000,000

77,200,000

155,800,000

Maximum borrowing capacity

500,000,000

Distributions

48,893,000

37,262,000

Capital units issued as consideration for properties conveyed

5,049,600

6,720,000

Assumption of debt as consideration for properties conveyed

27,300,000

Assumption of debt as consideration for properties sold to the Partnership

$311,200,000

Number of units sold by the related party as part of the equity offering

3,200,000

Units Outstanding

Limited partner, units outstanding

19,559,934

15,726,342

6,720,000

General partner, units outstanding

22,400

Partner units held

18,496,000

5,049,600

6,720,000

Limited partner interest (as a percent)

32.60%

52.40%

Number of consecutive quarters of minimum quarterly distribution to end subordination period

Number of tranches in which subordinated units may convert to common units

Percentage conversion per tranche

0.33

Number of consecutive quarters of minimum quarterly distribution to end subordination period, tranche one

Number of consecutive quarters of minimum quarterly distribution to end subordination period, tranche two

Number of consecutive quarters of minimum quarterly distribution to end subordination period, tranche three

Portion of subordinated units not converted (as a percent)

33.00%

Distribution per unit for four quarter period ending on or after December 31, 2013, to end subordination period

$0.55

Distribution per unit for four quarter period ending on or after December 31, 2013, to end subordination period (as a percent)

115.00%

Distribution per unit for four quarter period ending on or after December 31, 2013, to end subordination period, annualized

$2.19

Distribution per unit for any four quarter period to end subordination period

$0.59

Distribution per unit for any four quarter period to end subordination period (as a percent)

125.00%

Distribution per unit for any four quarter period to end subordination period, annualized

$2.38

Number of quarters of quarterly distribution meeting specified level above the minimum, to end subordination period

Conversion ratio

Partner's interest in net income (as a percent)

0.10%

9.50%

32.10%

Cash Distributions

Period within which available cash is distributed to unitholders

'45 days

Cash distributions paid per outstanding unit (in dollars per unit)

$0.55

$0.59

$0.55

Minimum quarterly cash distribution per unit (in dollars per unit)

$0.48

Percentage of operating surplus distributed to unitholders

0.10%

99.90%

0.10%

86.90%

13.10%

76.90%

23.10%

0.10%

99.90%

0.10%

99.90%

Net_Loss_Income_Per_Limited_Pa2

Net (Loss) Income Per Limited Partner Unit (Details) (USD $)	1 Months Ended	3 Months Ended								12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012
Net (loss) income	$15,125	($62,086)	$284	$20,523	($7,002)	$246	($15,279)	$16,175	$5,645	($48,281)	$6,787
Net income attributable to predecessor operations	-2,975	'	'	'	'	'	'	'	'	-448	-6,790
Net (loss) income available to unitholders	12,150	-62,086	284	20,523	-7,450	-499	-15,558	12,205	3,849	-48,729	-3
Less: General partner's approximate 0.1% interest in net loss (income)	-12	'	'	'	'	'	'	'	'	49	'
Limited partners' interest in net (loss) income	12,138	'	'	'	'	'	'	'	'	-48,680	-3
Weighted average limited partner units outstanding	22,418,000	'	'	'	'	'	'	'	'	25,372,000	22,425,000
Net (loss) income per limited partner unit (basic and diluted) (in dollars per unit)	$0.54	($2.37)	$0.01	$0.78	($0.32)	($0.02)	($0.69)	$0.54	$0.17	($1.92)	$0
General partner	'	'	'	'	'	'	'	'	'	'	'
Net (loss) income	$12	'	'	'	'	'	'	'	'	($49)	'
Partner's interest in net loss (income) (as a percent)	'	'	'	'	'	'	'	'	'	0.10%	'
Common Units	'	'	'	'	'	'	'	'	'	'	'
Weighted average limited partner units outstanding	15,698,000	'	'	'	'	'	'	'	'	18,652,000	15,705,000
Limited partner, units outstanding	'	19,559,934	'	'	'	15,726,342	'	'	'	19,559,934	15,726,342
Subordinated Units	'	'	'	'	'	'	'	'	'	'	'
Weighted average limited partner units outstanding	6,720,000	'	'	'	'	'	'	'	'	6,720,000	6,720,000
Limited partner, units outstanding	'	6,720,000	'	'	'	6,720,000	'	'	'	6,720,000	6,720,000

EquityBased_Compensation_Detai

Equity-Based Compensation (Details) (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2013
Equity-Based Compensation	'
Number of units authorized	1,500,000
Number of units available for issuance	1,297,666
Restricted units	'
Equity-Based Compensation	'
Vesting period	'3 years
Number of Non-vested Units	'
Non-vested restricted units at the beginning of the period	54,584
Granted (in units)	133,592
Vested (in units)	-22,914
Non-vested restricted units at the end of the period	165,262
Weighted Average Grant-Date Fair Value	'
Granted (in dollars per unit)	$16.32
Vested (in dollars per unit)	$18.58
Unrecognized compensation cost related to non-vested restricted units	$2.60
Weighted average period over which unrecognized compensation cost is to be recognized	'2 years 7 months 6 days
Number of units granted under the 2011 LTIP, that have vested	37,072

Subsidiary_Guarantors_Details

Subsidiary Guarantors (Details)	12 Months Ended
Subsidiary Guarantors (Details)	Dec. 31, 2013
LRE Finance	'
Subsidiary Guarantors	'
Ownership interest held (as a percent)	100.00%
OLLC	'
Subsidiary Guarantors	'
Ownership interest held (as a percent)	100.00%

Subsequent_Events_Details

Subsequent Events (Details) (USD $)	1 Months Ended	12 Months Ended		0 Months Ended		0 Months Ended
	Dec. 31, 2011	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Feb. 04, 2014	Feb. 04, 2014	Jan. 02, 2014	Jan. 17, 2014
				2014	Subsequent event	Subsequent event	Subsequent event	Subsequent event
				NGL positions		Second lien term loan	2014	Cash distribution declared
				Price swaps			NGL positions
				bbl			Price swaps
							bbl
Subsequent Events	'	'	'	'	'	'	'	'
Cash distribution declared per outstanding unit (in dollars per unit)	'	'	'	'	'	'	'	$0.49
Cash distribution declared on an annualized basis (in dollars per unit)	'	'	'	'	'	'	'	$1.96
Aggregate amount of distribution	$0	$48,893,000	$37,262,000	'	'	'	'	$12,900,000
At-the-Market Issuance Sales Program	'	'	'	'	'	'	'	'
Aggregate offering amount	'	'	'	'	$75,000,000	'	'	'
Percentage of net cash proceeds from equity offering required to be used to repay borrowings outstanding	'	'	'	'	'	50.00%	'	'
Volume of commodity hedge (in BBLs)	'	'	'	183,857	'	'	60,112	'
Weighted average price of commodity hedge (in dollars per MMBTU/BBL)	'	'	'	34.11	'	'	35.07	'

Supplemental_Information_on_Oi2

Supplemental Information on Oil and Natural Gas Exploration and Production Activities (Unaudited) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Capitalized costs relating to oil and natural gas producing activities	'	'
Proved oil and natural gas properties	$875,126	$839,154
Unproved oil and natural gas properties	1,258	1,264
Total capitalized costs	876,384	840,418
Accumulated depletion and depreciation	-431,636	-324,630
Net capitalized costs	$444,748	$515,788

Supplemental_Information_on_Oi3

Supplemental Information on Oil and Natural Gas Exploration and Production Activities (Unaudited) (Details 2) (USD $)	1 Months Ended	12 Months Ended		10 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2013	Dec. 31, 2012	Nov. 15, 2011
	Dec. 31, 2011	Dec. 31, 2013	Dec. 31, 2012	Predecessor
Acquisition of oil and natural gas properties	'	'	'	'
Proved	$56	$10	$9,795	$392
Development costs	2,461	36,484	31,598	48,702
Total	$2,517	$36,494	$41,393	$49,094

Supplemental_Information_on_Oi4

Supplemental Information on Oil and Natural Gas Exploration and Production Activities (Unaudited) (Details 3)

1 Months Ended

12 Months Ended

10 Months Ended

1 Months Ended

12 Months Ended

10 Months Ended

1 Months Ended

12 Months Ended

10 Months Ended

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Nov. 15, 2011

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Nov. 15, 2011

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Nov. 15, 2011

Oil

NGL

Gas

MBbls

Predecessor

MBbls

Predecessor

MMcf

item

MMcf

Predecessor

MBbls

MMcf

Oil and Natural Gas Reserves

Pressure base of gas volume

14.73

Changes in estimated remaining net proved, proved developed and proved undeveloped oil and natural gas reserves

Balance at the beginning of the period

11,705

9,949

5,937

3,804

3,602

3,045

95,537

118,048

109,601

Contribution from predecessor

10,053

3,637

119,204

Revision of previous estimates

-288

1,776

126

443

379

-196

4,150

-14,630

10,359

Extensions and discoveries

118

546

3,902

134

1,094

181

606

7,243

Acquisition of minerals in place

268

Sales of minerals in place

-29

-75

Production

-104

-837

-834

-657

-35

-315

-311

-269

-1,156

-7,246

-8,487

-8,606

Balance at the end of the period

9,949

10,698

11,705

9,279

3,602

3,969

3,804

3,674

118,048

92,622

95,537

118,522

Proved developed reserves:

7,607

8,548

8,588

2,787

3,252

2,936

108,227

88,172

89,803

Proved undeveloped reserves:

2,342

2,150

3,117

815

717

868

9,821

4,450

5,734

Supplemental_Information_on_Oi5

Supplemental Information on Oil and Natural Gas Exploration and Production Activities (Unaudited) (Details 4) (USD $)	1 Months Ended	12 Months Ended		10 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2013	Dec. 31, 2012	Nov. 15, 2011
	Dec. 31, 2011	Dec. 31, 2013	Dec. 31, 2012	Predecessor
Standardized measure of discounted future net cash flows related to interest in proved reserves	'	'	'	'
Future cash inflows	$1,573,150	$1,450,007	$1,488,912	$1,497,384
Future costs:	'	'	'	'
Future development costs	-156,909	-120,339	-163,316	-157,048
Future production costs	-508,204	-526,523	-521,378	-467,401
Future Texas margin tax	'	-1,187	'	'
Future net cash flows	908,037	801,958	804,218	872,935
10% discount to reflect timing of cash flows	-472,248	-409,401	-416,322	-454,253
Standardized measure of discounted future net cash flows	435,789	392,557	387,896	418,682
Principal changes in the standardized measure of discounted future net cash flows attributable to proved reserves	'	'	'	'
Beginning of period	'	387,896	435,789	348,398
Contribution from predecessor	447,238	'	'	'
Purchase of reserves in place	'	'	5,866	'
Sales of reserves in place	'	'	'	-676
Extensions and discoveries, net of future development costs	'	2,034	19,381	120,120
Revisions of quantity estimates	'	11,054	-1,373	17,326
Changes in future development costs, net	'	16,600	-871	1,125
Development costs incurred that reduce future development costs	'	25,408	12,164	4,331
Net changes in prices	'	4,363	-36,843	15,374
Change in future Texas margin tax	'	-570	'	'
Oil, natural gas and NGL sales, net of production costs	-11,449	-80,117	-71,186	-96,585
Changes in timing and other	'	-12,901	-18,610	-25,571
Accretion of discount	'	38,790	43,579	34,840
End of period	$435,789	$392,557	$387,896	$418,682

Selected_Quarterly_Financial_I2

Selected Quarterly Financial Information (Unaudited) (Details) (USD $)	1 Months Ended	3 Months Ended								12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012
Revenues	$28,005	$30,741	$25,195	$41,379	$17,780	$30,324	$11,894	$46,264	$32,356	$115,095	$120,838
Operating (loss) income	15,777	-59,645	4,069	20,177	-4,847	2,487	-10,900	20,491	6,127	-40,246	18,205
Net (loss) income	15,125	-62,086	284	20,523	-7,002	246	-15,279	16,175	5,645	-48,281	6,787
Net (loss) income available to common unitholders	$12,150	($62,086)	$284	$20,523	($7,450)	($499)	($15,558)	$12,205	$3,849	($48,729)	($3)
Net (loss) income per limited partner unit (basic and diluted) (in dollars per unit)	$0.54	($2.37)	$0.01	$0.78	($0.32)	($0.02)	($0.69)	$0.54	$0.17	($1.92)	$0