LRR Energy 8-K Other Events

Exhibit 99.3

ITEM 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

INDEX TO CONSOLIDATED/COMBINED FINANCIAL STATEMENTS

LRR ENERGY, L.P. AUDITED CONSOLIDATED FINANCIAL STATEMENTS

Reports of Management and Independent Registered Public Accounting Firm	2
Consolidated Balance Sheets as of December 31, 2012 and 2011	5
Statements of Operations for the Year Ended December 31, 2012 (consolidated), Periods from November 16, 2011 to December 31, 2011 (consolidated) and January 1, 2011 to November 15, 2011 (combined) and the Year ended December 31, 2010 (combined)	7
Consolidated Statement of Changes in Unitholders’ Equity for the Year Ended December 31, 2012 and the Period from November 16, 2011 to December 31, 2011	8
Combined Statement of Changes in Partners’ Capital for the Period from January 1, 2011 to November 15, 2011 and the Year ended December 31, 2010	9
Statements of Cash Flows for the Year Ended December 31, 2012 (consolidated), the Periods from November 16, 2011 to December 31, 2011 (consolidated) and from January 1, 2010 to November 15, 2011 (combined) and the Year ended December 31, 2010 (combined)	10
Notes to Consolidated/Combined Financial Statements	12

1

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934, as amended.  Our internal control over financial reporting is a process designed under the supervision of our Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements for external purposes in accordance with accounting principles generally accepted in the United States.

Because of its inherent limitations, internal control over financial reporting may not detect or prevent misstatements. Also, projections of any evaluation of the effectiveness to future periods are subject to risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

As of December 31, 2012, our management assessed the effectiveness of the Company’s internal control over financial reporting based on the criteria for effective internal control over financial reporting established in Internal Control — Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the assessment, management determined that we maintained effective internal control over financial reporting as of December 31, 2012, based on those criteria.

PricewaterhouseCoopers LLP, the independent registered public accounting firm that audited the consolidated financial statements of the Company included herein, has issued a report on the effectiveness of the Company’s internal control over financial reporting as of December 31, 2012, which is included herein.

/s/ Eric Mullins	/s/ Charles W. Adcock	/s/ Jaime R. Casas
Eric Mullins	Charles W. Adcock	Jaime R. Casas
Co-Chief Executive Officer and	Co-Chief Executive Officer and	Vice President, Chief Financial
Chairman of LRE GP, LLC	Director of LRE GP, LLC	Officer and Secretary of
		LRE GP, LLC

2

Report of Independent Registered Public Accounting Firm

To the Board of Directors of LRE GP, LLC and Unitholders of LRR Energy, L.P.:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, of changes in unitholders’ equity, and of cash flows present fairly, in all material respects, the financial position of LRR Energy, L.P. and its subsidiaries (the “Partnership”) at December 31, 2012 and 2011, and the results of their operations and their cash flows for the year ended December 31, 2012 and for the period from November 16, 2011 to December 31, 2011 in conformity with accounting principles generally accepted in the United States of America.  Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on criteria established in  Internal Control - Integrated Framework  issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).  The Partnership’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting.  Our responsibility is to express opinions on these financial statements and on the Company’s internal control over financial reporting based on our audits (which was an integrated audit in 2012).  We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects.  Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation.  Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk.  Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.  A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.  Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

August 28, 2013

3

Report of Independent Registered Public Accounting Firm

To the Board of Directors of LRE GP, LLC and Unitholders of LRR Energy, L.P.:

In our opinion, the accompanying combined balance sheet and the related combined statement of operations, changes in partners’ capital and cash flows present fairly, in all material respects, the financial position of Fund I (the “Predecessor”) at December 31, 2010 and the results of their operations and their cash flows for the period from January 1, 2011 to November 15, 2011 and for each of the two years in the period ended December 31, 2010 in conformity with accounting principles generally accepted in the United States of America.  These financial statements are the responsibility of the Predecessor’s management.  Our responsibility is to express an opinion on these financial statements based on our audits.  We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

March 27, 2012

4

LRR Energy, L.P.

Balance Sheets

(in thousands, except unit amounts)

(consolidated)

	December 31, 2012			December 31, 2011
ASSETS
Current assets:
Cash and cash equivalents	$	3,467		$	1,513
Accounts receivable:
Oil and natural gas sales	7,249			11,801
Trade and other	1			1,123
Commodity derivative instruments	16,484			16,064
Prepaid expenses	748			578
Total current assets	27,949			31,079
Property and equipment (successful efforts method)	840,736			793,762
Accumulated depletion, depreciation and impairment	(324,774		)	(274,896		)
Total property and equipment, net	515,962			518,866
Commodity derivative instruments	20,000			28,624
Deferred financing costs, net of accumulated amortization	1,559			1,365
TOTAL ASSETS	$	565,470		$	579,934
LIABILITIES AND UNITHOLDERS’ EQUITY
Current liabilities:
Trade accounts payable	$	—		$	2,707
Accrued liabilities	1,415			2,746
Accrued capital cost	2,361			1,421
Commodity derivative instruments	1,671			186
Due to affiliates	1,977			536
Interest rate derivative instruments	659			—
Asset retirement obligations	500			359
Total current liabilities	8,583			7,955
Long-term liabilities:
Commodity derivative instruments	874			—
Interest rate derivative instruments	3,526			—
Term loan	50,000			—
Revolving credit facility	178,000			155,800
Asset retirement obligations	33,591			25,994
Deferred tax liabilities	120			35
Total long-term liabilities	266,111			181,829
Total liabilities	274,694			189,784
Contractual obligations and commitments (Note 13)

5

LRR Energy, L.P.

Balance Sheets

(in thousands, except unit amounts)

(consolidated)

(continued)

	December 31, 2012		December 31, 2011
Unitholders’ equity:
Predecessors’ capital	$	60,941	$	118,647
General partner (22,400 units issued and outstanding as of December 31, 2012 and 2011)	396		438
Public common unitholders (10,676,742 units issued and outstanding as of December 31, 2012 and 10,608,000 units issued and outstanding as of December 31, 2011)	169,919		189,537
Affiliated common unitholders (5,049,600 units issued and outstanding as of December 31, 2012 and 2011)	25,563		35,007
Subordinated unitholders (6,720,000 units issued and outstanding as of December 31, 2012 and 2011)	33,957		46,521
Total unitholders equity	290,776		390,150
TOTAL LIABILITIES AND UNITHOLDERS’ EQUITY	$	565,470	$	579,934

See accompanying notes to the consolidated/combined financial statements.

6

LRR Energy, L.P.

Statements of Operations

(in thousands, except per unit amounts)

	Partnership						Predecessor
	Year Ended			November 16 to			January 1 to			Year Ended
	December 31, 2012			December 31, 2011			November 15, 2011			December 31, 2010
	(consolidated)						(combined)
Revenues:
Oil sales	$	72,916		$	9,766		$	59,605		$	52,670
Natural gas sales	23,502			3,976			35,883			48,088
Natural gas liquids sales	11,627			1,976			14,500			14,748
Realized gain on commodity derivative instruments	23,350			4,015			9,353			48,029
Unrealized gain (loss) on commodity derivative instruments	(10,602		)	8,272			12,674			(23,964		)
Other income	45			—			159			116
Total revenues	120,838			28,005			132,174			139,687
Operating Expenses:
Lease operating expense	29,069			3,193			21,391			23,804
Production and ad valorem taxes	7,790			1,076			7,763			9,320
Depletion and depreciation	46,928			5,876			37,206			55,828
Impairment on oil and natural gas properties	3,544			—			16,765			11,712
Accretion expense	1,575			191			1,290			1,366
(Gain) loss on settlement of asset retirement obligations	(31		)	—			496			(209		)
Management fees	—			—			5,435			6,104
General and administrative expense	13,758			1,892			5,149			5,293
Total operating expenses	102,633			12,228			95,495			113,218
Operating income	18,205			15,777			36,679			26,469
Other income (expense), net
Interest income	—			—			1			17
Interest expense	(6,596		)	(604		)	(919		)	(3,223		)
Realized loss on interest rate derivative instruments	(465		)	—			(574		)	(649		)
Unrealized gain (loss) on interest rate derivative instruments	(4,185		)	—			441			(248		)
Other income (expense), net	(11,246		)	(604		)	(1,051		)	(4,103		)
Income before taxes	6,959			15,173			35,628			22,366
Income tax benefit (expense)	(172		)	(48		)	76			(32		)
Net income	$	6,787		$	15,125		$	35,704		$	22,334
Net income attributable to predecessor operations	(6,790		)	(2,975		)
Net income (loss) available to unitholders	$	(3	)	$	12,150
Computation of net income (loss) per limited partner unit:
General partners’ interest in net income (loss)	$	—		$	12
Limited partners’ interest in net income (loss)	$	(3	)	$	12,138
Net income (loss) per limited partner unit (basic and diluted)	$	(0.00	)	$	0.54
Weighted average number of limited partner units outstanding	22,425			22,418

See accompanying notes to the consolidated/combined financial statements.

7

LRR Energy, L.P.

Consolidated Statement of Changes in Unitholders’ Equity

(in thousands)

							Limited Partners
	Predecessors’			General			Public			Affiliated
	Capital			Partner			Common			Common			Subordinated			Total
Balance, November 16, 2011	$	505,383		$	—		$	—		$	—		$	—		$	505,383
Book value of net assets contributed by the predecessor (Note 1)	(386,361		)	—			—			165,899			220,462			—
Initial public offering (Note 1)	—			—			188,451			—			—			188,451
Transaction costs	—			—			(4,716		)	—			—			(4,716		)
Contribution from general partner	—			426			—			—			—			426
Contribution from predecessor	(3,350		)	—			—			—						(3,350		)
Amortization of equity awards	—			—			31			—			—			31
Distribution to Fund I (Note 1)	—			—			—			(133,626		)	(177,574		)	(311,200		)
Net income	2,975			12			5,771			2,734			3,633			15,125
Balance, December 31, 2011	$	118,647		$	438		$	189,537		$	35,007		$	46,521		$	390,150
Contribution from predecessor	(5,174		)	(5		)	(2,241		)	(1,061		)	(1,409		)	(9,890		)
Book value of transferred properties contributed by predecessor	(59,322		)	—			—			—			—			(59,322		)
Amortization of equity awards	—			—			313			—			—			313
Distribution	—			(37		)	(17,689		)	(8,382		)	(11,154		)	(37,262		)
Net income	6,790			—			(1		)	(1		)	(1		)	6,787
Balance, December 31, 2012	$	60,941		$	396		$	169,919		$	25,563		$	33,957		$	290,776

See accompanying notes to the consolidated/combined financial statements.

8

Predecessor-Fund I

Combined Statements of Changes in Partners’ Capital

(in thousands)

	General			Limited			Class B
	Partner			Partners			Limited Partner			Total
Balance, December 31, 2009	$	3,536		$	274,194		$	127,916		$	405,646
Capital contributions	1,054			79,064			48,849			128,967
Distributions	(1,057		)	(79,249		)	(40,590		)	(120,896		)
Capital contributions returned	(123		)	(9,195		)	—			(9,318		)
Net income	42			3,294			18,998			22,334
Balance, December 31, 2010	3,452			268,108			155,173			426,733
Capital contributions	70			5,283			—			5,353
Distributions	(471		)	(35,295		)	(7,587		)	(43,353		)
Net income	487			27,630			7,587			35,704
Balance, November 15, 2011	$	3,538		$	265,726		$	155,173		$	424,437

See accompanying notes to the consolidated/combined financial statements.

9

LRR Energy, L.P.

Statements of Cash Flows

(in thousands)

	Partnership						Predecessor
	Year Ended December 31, 2012			November 16 to December 31, 2011			January 1 to November 15, 2011			Year Ended December 31, 2010
	(consolidated)						(combined)
CASH FLOWS FROM OPERATING ACTIVITES
Net income	$	6,787		$	15,125		$	35,704		22,334
Adjustments to reconcile net income to net cash provided by operating activities
Depletion and depreciation	46,928			5,876			37,206			55,828
Impairment of oil and natural gas properties	3,544			—			16,765			11,712
Unrealized loss (gain) on derivative instruments, net	14,787			(8,272		)	(13,115		)	24,212
Accretion expense	1,575			191			1,290			1,366
Amortization of equity awards	313			31			—			—
Amortization of deferred financing costs and other	387			50			59			138
(Gain) loss on settlement of asset retirement obligations	(31		)	—			496			(209		)
Purchase of derivative contracts	(59		)	—			—			—
Changes in operating assets and liabilities
Change in oil and natural gas sales	4,552			(11,801		)	5,159			(2,055		)
Change in trade and other	1,122			(1,123		)	(3,448		)	487
Change in prepaid expenses	(170		)	(578		)	357			4,493
Change in trade accounts payable	(2,707		)	2,707			4,292			1,030
Change in amounts due from affiliates	1,441			536			1,114			653
Change in accrued liabilities	(1,331		)	2,746			(1,771		)	1,280
Change in deferred tax liability	85			35			(81		)	—
Net cash provided by operatingactivities	77,223			5,523			84,027			121,269
CASH FLOWS FROM INVESTING ACTIVITIES
Acquisition of oil and natural gas properties	(10,020		)	(14		)	(392		)	(105,209		)
Development of oil and natural gas properties	(30,397		)	(741		)	(47,410		)	(33,069		)
Disposition of oil and natural gas properties	—			—			2,956			12,553
Expenditures for other property and equipment	(16		)	—			(45		)	(121		)
Net cash used in investing activities	$	(40,433	)	$	(755	)	$	(44,891	)	$	(125,846	)

10

LRR Energy, L.P.

Statements of Cash Flows

(in thousands)

(continued)

	Partnership						Predecessor
	Year Ended			November 16 to			January 1 to			Year Ended
	December 31, 2012			December 31, 2011			November 15, 2011			December 31, 2010
	(consolidated)						(combined)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from IPO	$	—		$	188,451		$	—		$	—
Contribution by general partner	—			426			—			—
Transaction costs	—			(4,716		)	—			—
Contribution to Fund I	(5,174		)	(3,350		)	—			—
Deferred financing costs	(562		)	(1,415		)	—			(349		)
Borrowings under revolving credit facility	77,200			155,800			—			8,620
Principal payments on revolving credit facility	(55,000		)	(27,251		)	—			(5,519		)
Borrowings under term loan	50,000
Capital contributions	—			—			5,353			128,967
Distribution to Fund I	(64,038		)	—
Distributions	(37,262		)	(311,200		)	(43,353		)	(120,896		)
Capital contributions returned	—			—			—			(9,318		)
Net cash provided by (used in) financing activities	(34,836		)	(3,255		)	(38,000		)	1,505
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	1,954			1,513			1,136			(3,072		)
CASH AND CASH EQUIVALENTS, BEGINNING OF THE PERIOD	1,513			—			12,455			15,527
CASH AND CASH EQUIVALENTS, END OF PERIOD	$	3,467		$	1,513		$	13,591		$	12,455
Supplemental disclosure of cash flow information
Cash paid for taxes during the period	$	86		$	—		$	603		$	25
Cash paid for interest during the period	6,547			31			4			928
Supplemental disclosure of non-cash items to reconcile investing and financing activities
Property and equipment:
Accrued capital costs	940			(1,421		)	5,791			2,938
Asset retirement obligations	(364		)	(353		)	(241		)	3,736

See accompanying notes to the consolidated/combined financial statements.

11

LRR Energy, L.P.

Notes to Consolidated/Combined Financial Statements

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 and references to “Fund II” refer collectively to Lime Rock Resources II-A, L.P. and Lime Rock Resources II-C, L.P. References to “Lime Rock Resources” refer collectively to Fund I and Fund II. The properties conveyed to us in connection with our initial public offering (“IPO”) on November 16, 2011 (such conveyance described below) are located in the Permian Basin region in West Texas and southeast New Mexico, the Mid-Continent region in Oklahoma and East Texas and the Gulf Coast region in Texas. We conduct our operations through our wholly owned subsidiary, LRE Operating, LLC (“OLLC”).

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. Its activities will be limited to co-issuing our debt securities and engaging in activities related thereto. As of December 31, 2012, LRE Finance did not co-issue any debt securities.

Prior to our IPO, 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.

After reviewing applicable accounting literature, we consider the Partnership Properties to be under common control with Fund I. We have presented the combined historical financial statements of Fund I as our historical financial statements because we believe them to be “informative” to our investors and representative of our management’s ability to manage the Partnership Properties. The financial data and operations of Fund I are referred to herein as “predecessor.” Additionally, we have determined that transactions with Fund II are deemed acquisitions between entities under common control; however, Fund II is not included in our predecessor financial statements.

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 (the “Transferred Properties”) located in the Permian Basin region of New Mexico and onshore Gulf Coast region of Texas for $65.1 million in cash (the “Transaction”). The Transaction was effective as of March 1, 2012. We funded the acquisition with borrowings under our revolving credit facility (Note 7). Please refer to Notes 2 and 3 regarding the recast of financial information for acquisitions between entities under common control.

12

The following table presents the net assets conveyed by Fund I to us in the Transaction (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.

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 from Fund II of certain oil and natural gas properties located in the Mid-Continent region in Oklahoma 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 following table presents the net assets conveyed by Fund II to us in the April 2013 Acquisition (in thousands):

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

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

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.

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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.

2.Summary of Significant Accounting Policies

The accompanying financial statements and related notes present our consolidated financial position as of December 31, 2012 and 2011. These financial statements include the results of our operations, cash flows and changes in unitholders’ equity for the year ended December 31, 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 and the year ended December 31, 2010. 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

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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.

Because Fund I affiliates own 100% of our general partner and because Fund I owns 5,049,600 common units and all of our 6,720,000 subordinated units, representing an aggregate 52.4% limited partner interest in us, each acquisition of assets from Fund I is considered a transfer of net assets between entities under common control. We also consider acquisitions of assets from Fund II to be a transfer of net assets between entities under common control.  Fund II does not own any of our common or subordinated units. As a result, we are required to revise our financial statements to include the activities of such assets for all periods presented, similar to a pooling of interests, to include the financial position, results of operations and cash flows of the assets acquired and liabilities assumed.

Accordingly, our historical financial statements include the results attributable to acquisitions of assets between entities under common control as if the Partnership owned such assets for all periods presented. The consolidated financial statements for periods prior to the acquisitions between entities under common control have been prepared from Fund I and Fund II’s 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 “Acquisitions Between Entities Under Common Control.”

Net income attributable to the acquisitions between entities under common control for 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.

Acquisitions 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 Fund I and Fund II as these are transactions between entities under common control. Our historical financial statements have been revised to include the results attributable to the assets contributed from Fund I and Fund II 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 Fund I and Fund II is determined using the carrying value of the specific assets contributed.

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

Commodity Derivative Instruments.  The fair value of the commodity derivative contracts associated with the properties acquired from Fund I and Fund II.

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.

Unrealized Gain (Loss) on Commodity Derivative Contracts.  Reflects the unrealized gain (loss) on commodity derivative contracts associated with the properties acquired assuming the contracts had been in place as of the date acquired by Fund I and Fund II.

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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 Fund I or Fund II 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, 2012 and 2011, 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, 2012 and 2011, 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, 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.

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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.

For the year ended December 31, 2010, purchases by ConocoPhillips, Seminole Energy Services, Upstream Energy, and Sunoco accounted for 16%, 13%, 10% and 10%, 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 year ended December 31, 2012 we recorded non-cash impairment charges on proved oil and natural gas properties of $3.1 million. For the period from January 1 to November 15, 2011, the predecessor recorded non-cash impairment charges on proved oil and natural gas properties of $16.8 million. For the year ended December 31, 2010, the predecessor recorded non-cash impairment charges on proved oil and natural gas properties of $10.9 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, 2012 and 2011, $1.3 million and $1.7 million, respectively, 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 year ended December 31, 2012 and the period from November 16 to December 31, 2011. For the year to date period ended November 15, 2011, the predecessor reclassified $0.3 million from unproved to proved properties.

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. For the year ended December 31, 2010, the predecessor recorded an impairment charge for unproved properties in the amount of $0.8 million. No impairments were recorded for unproved properties during 2011. The impairments were 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

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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 2012, 2011 and 2010.

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 follow the guidance in ASC Topic 410, Asset Retirement and Environmental Obligations which requires entities to 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 present 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 present 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, both realized and unrealized gains and losses are recorded as separate components of revenues. For interest rate derivatives, both realized and unrealized gains and losses are recorded as a component of other income (expense) in the consolidated/combined statements of operations.

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ASC Topic 815, Derivatives and Hedging, requires recognition of all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. Changes in the fair value of derivatives are recognized currently in earnings unless specific hedge accounting criteria are met. Realized gains and losses on derivative hedging instruments are recorded currently in earnings. Unrealized gains and losses on derivatives are also recorded currently in earnings unless the derivatives qualify and are appropriately designated as hedges. Unrealized gains or losses on derivative instruments that qualify and are designated as hedges are deferred in other comprehensive income until the related transaction occurs. We have not designated any of our derivative instruments as hedges. As a result, we mark our derivative instruments to fair value in accordance with the provisions of ASC Topic 815 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, 2012 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 ourself 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” 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 May 2011, the FASB issued ASU No. 2011-04, “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS.” The Amendments explain how to measure fair value and change the wording used to describe many of the fair value requirements in GAAP, but do not require additional fair value measurements. The guidance became effective for interim and annual periods beginning on or after December 15, 2011. We adopted these amendments on January 1, 2012 and they did not have a material impact on our consolidated financial position, results of operations or cash flows.

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In December 2011, the FASB issued ASU No. 2011-11, “Disclosures about Offsetting Assets and Liabilities.” The amendments in this update require enhanced disclosures around financial instruments and derivative instruments that are either (1) offset in accordance with either ASC 210-20-45 or ASC 815-10-45 or (2) subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset in accordance with either ASC 210-20-45 or ASC 815-10-45. An entity should provide the disclosures required by those amendments retrospectively for all comparative periods presented. The amendments are effective during interim and annual periods beginning on or after January 1, 2013. We do not expect this guidance to have a material impact on our consolidated financial position, results of operations or cash flows.

3.Acquisitions and Divestitures

Acquisition Between Entities Under Common Control

On June 1, 2012, we completed the acquisition of the Transferred Properties from Fund I for a total purchase price of $65.1 million, after giving effect to purchase price adjustments from the effective date of the Transaction (March 1, 2012). The post closing adjustments to the purchase price for the acquisition were finalized in September 2012, and we received $1.1 million in cash from Fund I. We financed the Transaction with borrowings under our existing credit facility as discussed in Note 7. The net assets were recorded using carryover book value of Fund I as the acquisition was a transaction between entities under common control. Our historical financial statements were revised to include the results attributable to the Transferred Properties as if we owned the properties for all periods presented in our consolidated condensed financial statements. See Note 2 for further disclosures regarding the Transaction.

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 existing revolving credit facility.

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 March 2013 equity offering.

Third-Party Acquisitions

We acquire proved oil and natural gas properties that meet management’s criteria with respect to reserve lives, development potential, production risk and other operational characteristics. We generally do not acquire assets other than oil and natural gas property interests. We assume the liability for ARO related to each acquisition and record the liability at fair value as of the date of closing.

The operating revenues and expenses of acquired properties are included in the predecessor’s combined financial statements from the acquisition date. Transactions are financed through partner contributions and borrowings.

The acquisitions discussed below were accounted for under the acquisition method of accounting. Accordingly, we conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while acquisition costs associated with the acquisitions were expensed as incurred.

The fair values of oil and natural gas properties and ARO are measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties

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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.

We did not acquire any significant third-party properties during either 2012 or 2011. Our predecessor had the following acquisitions during 2010.

Significant acquisition — Potato Hills.  On February 23, 2010, our predecessor completed an acquisition of interests in 51 producing gas wells located in Oklahoma (Potato Hills) from a private independent oil and gas company for approximately $104.0 million in cash, subject to customary post-closing and title adjustments. Total proved reserves of the acquired properties were estimated at 10.0 million barrels of oil equivalent at the date of the acquisition.

Other acquisitions.  On August 31, 2010, our predecessor completed the acquisition of certain oil and natural gas properties located in Texas from a private independent oil and gas company for a purchase price of approximately $7.5 million, subject to customary post-closing and title adjustments.

On October 14, 2010, our predecessor also closed the acquisition of an additional interest in certain New Mexico wells in which it already held interests from a large public independent oil and gas company. The acquisition was valued at $1.8 million, subject to customary post-closing and title adjustments, and was in partial consideration for the divestiture of certain other New Mexico properties as discussed below under “Divestitures of non-core assets.”

Summarized below are the combined results of operations of our predecessor for the periods presented, on an unaudited pro forma basis, as if the 2010 acquisitions had occurred on January 1, 2010 (in thousands):

	Year ended
	December 31, 2010
	Actual		Pro Forma
Revenue	$	139,687	$	145,193
Net income (loss)	$	22,334	$	26,494

The following table summarizes the values assigned to the assets acquired and liabilities assumed for the year ended December 31, 2010 as of the acquisition dates (in thousands):

				Other			Total-2010
	Potato Hills			Acquisitions			Acquisitions
Oil and natural gas properties	$	97,488		$	7,721		$	105,209
Asset retirement obligations assumed	(1,927		)	(1,067		)	(2,994		)
Identifiable net assets	$	95,561		$	6,654		$	102,215

These acquisitions qualify as business combinations, and as such, our predecessor estimated the fair value of these properties as of the acquisition dates. The fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value measurements also utilize assumptions of market participants. In the estimation of fair value, we used a discounted cash flow model and made market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. These assumptions represent Level 3 inputs, as further discussed under Note 4. After post-closing and title adjustments, the assets acquired and liabilities assumed approximate fair value for the acquisitions.

Divestitures of non-core assets

We did not divest of any significant non-core assets during either 2012 or 2011. During 2010, our predecessor sold its interests in certain oil and natural gas properties located in New Mexico with carrying values of approximately $14.3 million and received net cash proceeds of approximately $12.5 million and certain additional

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property interests valued at $1.8 million. The sales of these non-core assets did not affect the unit-of-production amortization rate and, therefore, no gain or loss was recognized for the divestitures.

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. 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.

As required by GAAP, 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, 2012 and 2011(in thousands).

	Level 1		Level 2		Level 3		Total
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
December 31, 2011
Assets:
Commodity derivative instruments	$	—	$	44,688	$	—	$	44,688
Liabilities:
Commodity derivative instruments	—		186		—		186

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

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The curves are obtained from independent pricing services reflecting broker market quotes. We did not have any outstanding interest rate derivative instruments at December 31, 2011.

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, 2012			December 31, 2011
Oil and natural gas properties (successful efforts method)	$	839,154		$	791,737
Unproved properties	1,264			1,723
Other property and equipment	318			302
	840,736			793,762
Accumulated depletion, depreciation and impairment	(324,774		)	(274,896		)
Total property and equipment, net	$	515,962		$	518,866

We recorded $46.9 million and $5.9 million of depletion and depreciation expense for the year ended December 31, 2012 and the period from November 16 to December 31, 2011, respectively. The predecessor recorded $37.2 million and $55.8 million of depletion and depreciation expense for the period from January 1 to November 15, 2011 and the year ended December 31, 2010, respectively.

We perform an impairment analysis of our oil and natural gas properties on a quarterly basis due to the volatility in commodity prices. For the year ended December 31, 2012, we recorded a total non-cash impairment charge of approximately $3.5 million to impair the value of our unproved properties and proved oil and natural gas properties in the Mid-Continent region. For the year to date period ending November 15, 2011, we recorded a total non-cash impairment charge of approximately $16.8 million to impair the value of our proved oil and natural gas properties in the Mid-Continent region. For the year ended December 31, 2010, we recorded a total non-cash impairment charge of approximately $11.7 million, composed of $10.9 million and $0.8 million to impair the value of our proved and unproved oil and natural gas properties in the Gulf Coast, respectively. 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 non-cash charges are included in “Impairment of oil and natural gas properties” line item in the predecessor’s combined statements of operations. We did not record any impairment charges in the period from November 16 to December 31, 2011.

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 or third party reserve report. These reports are based upon future oil and natural gas prices, which are based on observable inputs adjusted for basis differentials, which are Level 3 inputs. The fair values of proved properties are measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of proved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. The underlying commodity prices embedded in the predecessor’s estimated cash flows are the product of a process that begins with New York Mercantile Exchange (“NYMEX”) forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that management believes will impact realizable prices. Furthermore, significant assumptions in valuing the proved reserves included the reserve quantities, anticipated drilling and operating costs, anticipated production taxes, future expected natural gas prices and basis differentials, anticipated drilling schedules, anticipated production declines, and an appropriate discount rate commensurate with the risk of the underlying cash flow estimates. Cash flow estimates for the impairment testing excluded derivative instruments 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 further, the estimated undiscounted future cash flows for the proved oil and natural gas

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properties may not exceed the net capitalized costs for our properties and a non-cash impairment charge may be required to be recognized in future periods.

6.Asset Retirement Obligations

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

	Partnership						Predecessor
				November 16, 2011			For the Year to
	Year Ended			to			Date Period Ending
	December 31, 2012			December 31, 2011			November 15, 2011
Beginning of period	$	26,353		$	25,809		$	24,296
Assumed in acquisitions	—			—			202
Divested properties	—			—			—
Revisions to previous estimates	6,291		(1)	—			—
Liabilities incurred	364			353			—
Liabilities settled	(492		)	—			(443		)
Accretion expense	1,575			191			1,290
End of period	34,091			26,353			25,345
Current portion of ARO	(500		)	(359		)	(359		)
Asset retirement obligation- non-current	$	33,591		$	25,994		$	24,986

(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.

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, 2012. 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

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commodity hedges exceeding a certain percentage of our production; and prepay certain indebtedness. As of December 31, 2012, 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, 2012, 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.

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As of December 31, 2012, we had approximately $228.0 million of outstanding debt and accrued interest was approximately $0.2 million. As of December 31, 2011, we had approximately $155.8 million of outstanding debt and accrued interest was approximately $0.5 million. Our outstanding debt increased primarily due to our June 2012 acquisition of oil and natural gas properties from Fund I for approximately $65.1 million and working capital borrowings.

Interest expense for the year ended December 31, 2012 and period from November 16 to December 31, 2011 was $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 11, 2011 and year ended December 31, 2010 was approximately $0.9 million and $3.2 million, respectively. As of December 31, 2012 and 2011, our weighted average interest rate on our outstanding indebtedness was 3.47% and 2.86%, respectively. Please refer to Note 8 below for a discussion of our interest rate derivative contracts.

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.

At December 31, 2012 and 2011, our open positions consisted of contracts such as (i) crude oil and natural gas financial collar contracts, (ii) crude oil, NGL and natural gas financial swaps, (iii) 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 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 the time value of money and volatility and are comparable to values obtained from counterparties. Pursuant to the accounting standard that permits netting of assets, liabilities, and collateral where the right of offset exists, we present the fair value of derivative financial instruments on a net basis.

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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		$	3.00		$	—		$	—		$	—		$	—
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, 2011, we had the following commodity derivative open positions:

	Index	2012		2013		2014		2015
Natural gas positions
Price swaps (MMBTUs)	NYMEX-HH	3,684,189		6,006,595		5,307,971		4,769,881
Weighted average price		$	6.21	$	5.57	$	5.76	$	5.96
Collars (MMBTUs)	NYMEX-HH	2,902,801		—		—		—
Floor-Ceiling price		$	4.75-7.31	$	—	$	—	$	—
Oil positions
Price swaps (BBLs)	NYMEX-WTI	251,005		367,367		306,325		241,785
Weighted average price		$	102.20	$	101.45	$	99.83	$	98.90
NGL positions
Price swaps (BBLs)	Mont Belvieu	164,220		—		—		—
Weighted average price		$	49.92	$	—	$	—	$	—

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

Effective	Maturity	Notional Amount		Average %		Index
February 2012	February 2015	$	150,000	0.5175	%	LIBOR
February 2015	February 2017	75,000		1.7250	%	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

We did not have any outstanding interest rate swap derivative contracts as of December 31, 2011.

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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, 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

	As of December 31, 2011
	Current			Long-term		Current			Long-term
	Assets			Assets		Liabilities			Liabilities
Sale of natural gas production
Price swaps	$	10,762		$	22,959	$	—		$	—
Basis swaps	—			—		—			—
Collars	4,464			—		—			—
Sale of Crude Oil Production
Price swaps	838			5,665		—			—
Sale of NGLs
Price swaps	254			—		440			—
Gross fair value	16,318			28,624		440			—
Netting arrangements	(254		)	—		(254		)	—
Net recorded fair value	$	16,064		$	28,624	$	186		$	—

Effect of Derivative Instruments — Statements of Operations

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

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	Partnership					Predecessor
	Year Ended			November 16 to		January 1 to			Year Ended
	December 31,			December 31,		November 15,			December 31,
	2012			2011		2011			2010
Realized gains (losses):
Commodity derivatives (revenue)	$	23,350		$	4,015	$	9,353		$	48,029
Interest rate derivatives (other income/expense)	(465		)	—		(574		)	(649		)
Unrealized gains (losses):
Commodity derivatives (revenue)	(10,602		)	8,272		12,674			(23,964		)
Interest rate derivatives (other income/expense)	(4,185		)	—		441			(248		)

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 master 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.

9.Related Parties

Ownership in Our General Partner by the Management of Fund I and its Affiliates

As of December 31, 2012, Lime Rock Management, an affiliate of Fund I owned 100% of our general partner and Fund I owned an aggregate of approximately 32.1% of our outstanding common units and all of our subordinated units representing limited partner interests in us. As of December 31, 2011, Lime Rock Management owned 100% of our general partner and Fund I owned an aggregate of approximately 32.2% of our outstanding common units and all of our subordinated units representing limited partner interests in us. In addition, our general partner owned an approximate 0.1% general partner interest in us, represented by 22,400 general partner units, and all of our incentive distribution rights as of December 31, 2012 and 2011.

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 year ended December 31, 2012 and the period from November 16 to December 31, 2011, we paid Lime Rock Management approximately $2.1 million and $0.6 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 during the year ended December 31, 2012 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	)

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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, 2012 and 2011, 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 year ended December 31, 2012, we paid cash distributions of $37.3 million 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 2012 distribution on January 18, 2013 as discussed in Note 14.

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 is 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, the predecessor expensed $5.4 million in management fees to Lime Rock Management. The predecessor expensed $6.1 million related to management fees to Lime Rock Management for the year ended December 31, 2010.

For certain oil and natural gas properties where the predecessor is the operator, the predecessor receives income related to joint interest operations. For the period from January 1 to November 15, 2011, the predecessor received $0.9 million, of income, which reduced the management fee paid by the predecessor to Lime Rock Management. The predecessor did not record any such amounts during the year ended December 31, 2010. 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.

10.Unitholders’ Equity

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 approximately $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 approximately $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, 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.

As of December 31, 2011, we had 15,700,074 common units, 6,720,000 subordinated units and 22,400 general partner units outstanding. In addition, as of December 31, 2011, Fund I owned 5,049,600 common units and all of our subordinated units, representing a 52.4% limited partner interest in us.

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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 2012 that was paid on February 14, 2013. 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.

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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

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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 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.

11.Net Income Per Limited Partner Unit

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

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	Year Ended			November 16 to
	December 31, 2012			December 31, 2011
Net income	$	6,787		$	15,125
Net income attributable to predecessor operations	(6,790		)	(2,975		)
Net income (loss) available to unitholders	(3		)	12,150
Less: General partner’s approximate 0.1% interest in net income (loss)	—			(12		)
Limited partners’ interest in net income (loss)	$	(3	)	$	12,138
Weighted average limited partner units outstanding:
Common units	15,705			15,698
Subordinated units	6,720			6,720
Total	22,425			22,418
Net income (loss) per limited partner unit (basic and diluted)	$	(0.00	)	$	0.54

Our subordinated units and restricted unit awards are considered to be participating securities for purposes of calculating our net income per limited partner unit, and accordingly, are included in basic computation as such. Net income per limited partner unit is determined by dividing the net income available to the common unitholders, after deducting our general partner’s approximate 0.1% interest in net income, by the number of common units and subordinated units outstanding as of December 31, 2012 and 2011. The aggregate number of common units and subordinated units was 15,726,342 and 6,720,000 as of December 31, 2012. The aggregate number of common units and subordinated units was 15,700,074 and 6,720,000 as of December 31, 2011. The majority of the units were outstanding since November 16, 2011.

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, 2012, there were 1,431,258 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, 2012 and the period from November 16 to December 31, 2011, is presented below:

			Weighted
	Number of		Average
	Non-vested		Grant-Date
	Units		Fair Value
Non-vested restricted units at November 16, 2011	—		$	—
Granted	42,474		18.88
Vested	—		—
Forfeited	—		—
Non-vested units at December 31, 2011	42,474
Granted	26,268		18.10
Vested	(14,157	)	18.88
Forfeited	—		—
Non-vested units at December 31, 2012	54,585

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As of December 31, 2012, there was approximately $0.9 million of unrecognized compensation cost related to non-vested restricted units. The cost is expected to be recognized over a weighted average period of approximately 2.3 years. There were 14,157 vested restricted units as of December 31, 2012.

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.

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 December 10, 2012, and the SEC declared the registration statement effective on January 16, 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.

15.Subsequent Events

Acquisition Between Entities Under Common Control

On January 3, 2013, we completed the acquisition of oil and natural gas properties in the Mid-Continent region in Oklahoma from Fund I for a purchase price of $21.0 million subject to customary purchase price adjustments. In addition, as part of the transaction, we acquired in the money commodity hedge contracts valued at approximately $1.8 million. LRE funded the acquisition with borrowings under its revolving credit facility.

Unit Distribution

On January 18, 2013, we announced that the board of directors of our general partner declared a cash distribution for the fourth quarter of 2012 of $0.4800 per outstanding unit, or $1.92 on an annualized basis. The distribution was paid on February 14, 2013 to all unitholders of record as of the close of business on January 30, 2013. The aggregate amount of the distribution was approximately $10.8 million.

Derivative Instruments

Subsequent to December 31, 2012, we entered into the following commodity hedges.

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	Index	2013			2014
Oil Positions
Basis swaps (Bbls)	Midland — WTI Cushing	419,425			410,400
Weighted average price		$	(1.25	)	$	(1.00	)

As part of the 2013 acquisition described above, we also acquired the following crude oil and natural gas hedges:

	Index	2013		2014		2015
Natural gas positions
Price swaps (MMBTUs)	NYMEX-HH	248,950		200,916		173,676
Weighted average price		$	5.23	$	5.58	$	5.96
Oil positions
Price swaps (BBLs)	NYMEX-WTI	39,794		28,176		22,128
Weighted average price		$	101.30	$	100.01	$	98.90

Restricted Unit Grant

On March 5, 2013, the board of directors of our general partner granted Mr. Casas 20,760 restricted units under the LTIP. These restricted units vest in equal one-third increments over a 36-month period (i.e., approximately 33.3% vest at each one-year anniversary of the date of grant), so that the restricted units granted will be 100% vested on March 5, 2016 and provided that he has continuously provided services to us, our general partner or any of our respective affiliates, without interruption, from the date of grant through each applicable vesting date.

Material Subsequent Events Occurring after the Initial Filing of the Form 10-K on March 13, 2013

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 approximately $59.6 million, after deducting underwriting discounts and commissions and estimated offering expenses of approximately $0.2 million. We used the net proceeds of the offering to fund our acquisition discussed in Note 14 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.

On April 1, 2013, we completed the acquisition of oil and natural gas properties in the Mid-Continent region in Oklahoma and crude oil hedges from Fund II for a purchase price of $38.2 million, subject to customary purchase price adjustments. We funded the acquisition with proceeds from our equity offering described in Note 10.

As part of the transaction, we acquired the following crude oil hedges which were estimated to be valued at approximately $0.4 million as of the close of the transaction:

	Index	2013		2014
Oil positions
Price swaps (BBLs)	NYMEX-WTI	38,250		30,000
Weighted average price		$	102.75	$	98.20

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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):

	2012			2011
Proved oil and natural gas properties	$	839,154		$	791,737
Unproved oil and natural gas properties	1,264			1,723
	840,418			793,460
Accumulated depletion and depreciation	(324,630		)	(274,880		)
Net capitalized costs	$	515,788		518,580

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		November 16 to		January 1 to		Year Ended
	December 31, 2012		December 31, 2011		November 15, 2011		December 31, 2010
Acquisition of oil and natural gas properties
Proved	$	9,795	$	56	$	392	$	105,209
Unproved	—		—		—		—
Development costs	31,598		2,461		48,702		44,680
Total	$	41,393	2,517		$	49,094	$	149,889

We had immaterial exploration costs for each of the periods during 2012, 2011 and 2010.

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, 2012, 2011 and 2010 were

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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	8,730		3,360		113,972
Production	(87	)	(32	)	(1,086	)
Balance, December 31, 2011	8,643		3,328		112,886
Revision of previous estimates	1,172		266		(16,935	)(1)
Extensions and discoveries	546		134		606
Acquisition of minerals in place	—		—		—
Sales of minerals in place	—		—		—
Production	(696	)	(287	)	(7,942	)
Balance, December 31, 2012	9,665		3,441		88,615

(1)The decrease in natural gas reserves was primarily due to significantly lower natural gas prices during 2012.

	Oil		NGL		Gas
	(MBbls)		(MBbls)		(MMcf)
Predecessor:
Balance, December 31, 2009	5,598		2,580		62,658
Revision of previous estimates	92		315		6,681
Extensions and discoveries	927		438		2,583
Acquisition of minerals in place	40		97		49,560
Sales of minerals in place	(22	)	(9	)	(594	)
Production	(698	)	(376	)	(11,287	)
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
Proved developed reserves:
December 31, 2010 (predecessor)	4,970		2,605		105,465
December 31, 2011 (partnership)	6,410		2,580		103,679
December 31, 2012 (partnership)	6,979		2,716		84,747
Proved undeveloped reserves:
December 31, 2010 (predecessor)	967		440		4,136
December 31, 2011 (partnership)	2,233		748		9,207
December 31, 2012 (partnership)	2,686		725		3,868

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

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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			November 16 to			January 1 to			Year Ended
	December 31, 2012			December 31, 2011			November 15, 2011			December 31, 2010
Future cash inflows	$	1,267,735		$	1,420,166		$	1,497,384		$	1,039,219
Future costs:
Development	(149,274		)	(151,487		)	(157,048		)	(40,659		)
Production	(435,200		)	(442,491		)	(467,401		)	(354,350		)
Future net cash flows	683,261			826,188			872,935			644,210
10% discount to reflect timing of cash flows	(358,020		)	(435,174		)	(454,253		)	(295,812		)
Standardized measure of discounted future net cash flows	$	325,241		$	391,014		$	418,682		$	348,398

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):

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	Partnership						Predecessor
	Year Ended			November 16 to			January 1 to			Year Ended
	December 31, 2012			December 31, 2011			November 15, 2011			December 31, 2010
Beginning of period	$	391,014		$	400,988		$	348,398		$	192,948
Contribution from predecessor	—			—			—
Purchase of reserves in place	—			—			—			76,007
Sales of reserves in place	—			—			(676		)	(535		)
Extensions and discoveries, net of future development costs	19,380			—			120,120			46,947
Revisions of quantity estimates	(20,132		)	—			17,326			23,467
Changes in future development costs, net	(871		)	—			1,125			(5,148		)
Development costs incurred that reduce future development costs	12,364			—			4,331			4,013
Net changes in prices	(41,311		)	—			15,374			77,696
Oil, natural gas and NGL sales, net of production costs	(60,737		)	(9,974		)	(96,585		)	(82,382		)
Changes in timing and other	(13,567		)	—			(25,571		)	(3,910		)
Accretion of discount	39,101			—			34,840			19,295
End of period	$	325,241		$	391,014		$	418,682		$	348,398

17.Selected Quarterly Financial Information (Unaudited)

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

	Partnership
	First Quarter		Second Quarter		Third Quarter			FourthQuarter
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	)

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	Predecessor										Partnership
	First Quarter			Second Quarter		Third Quarter		Fourth Quarter (1)			Fourth Quarter (1)
2011
Revenues	$	18,650		$	42,535	$	66,208	$	4,781		$	28,005
Operating income (loss)	(5,856		)	24,298		25,578		(7,341		)	15,777
Net income (loss)	(6,210		)	23,813		25,582		(7,481		)	15,125
Net income (loss) available to common unitholders	—			—		—		—			12,150
Net income per limited partner unit	n/a			n/a		n/a		n/a			$	0.54

(1)Fourth quarter 2011 results are split 46 days each under predecessor and partnership to reflect the closing of the IPO.

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