Vanguard Natural Resources, Inc. - FORM 8-K/A - EX-99.1 - EXHIBIT 99.1

Vanguard Natural Resources, Inc. - FORM 8-K/A - EX-99.1 - EXHIBIT 99.1 - November 25, 2015

Attached files

Attached files

Vanguard Natural Resources, Inc. Reports

file	filename
8-K/A - 8-K/A - Vanguard Natural Resources, Inc.	vnr8-ka093015eroc_lrefinan.htm
EX-99.2 - EXHIBIT 99.2 - Vanguard Natural Resources, Inc.	exhibit992eroc093015financ.htm
EX-99.3 - EXHIBIT 99.3 - Vanguard Natural Resources, Inc.	exhibit993lre_erocxupdated.htm

Exhibit 99.1



LRR Energy, L.P.
Consolidated Condensed Balance Sheets
(Unaudited)
(in thousands, except unit amounts)
		September 30, 2015			December 31, 2014
ASSETS
Current assets:
Cash and cash equivalents	$	13,145		$	3,576
Accounts receivable		10,298			11,124
Commodity derivative instruments		37,305			45,924
Due from affiliates		-			5,697
Prepaid expenses		1,390			1,840
Total current assets		62,138			68,161
Property and equipment (successful efforts method)		977,964			956,326
Accumulated depletion, depreciation and impairment		(666,428	)		(506,368	)
Total property and equipment, net		311,536			449,958
Commodity derivative instruments		47,938			38,540
Deferred financing costs, net of accumulated amortization and other assets		1,480			2,295
TOTAL ASSETS	$	423,092		$	558,954
LIABILITIES AND UNITHOLDERS’ EQUITY
Current liabilities:
Accrued liabilities	$	7,269		$	5,506
Accrued capital cost		2,276			9,176
Distribution payable		3,511			-
Due to affiliates		1,339			-
Commodity derivative instruments		707			556
Interest rate derivative instruments		2,779			2,327
Asset retirement obligations		1,840			1,065
Total current liabilities		19,721			18,630
Long-term liabilities:
Commodity derivative instruments		127			232
Interest rate derivative instruments		900			817
Term loan		50,000			50,000
Revolving credit facility		240,000			230,000
Asset retirement obligations		41,149			40,539
Deferred tax liabilities		-			99
Total long-term liabilities		332,176			321,687
Total liabilities		351,897			340,317
Unitholders’ equity:
General partner (22,400 units issued and outstanding as of September 30, 2015
and December 31, 2014)		(32,656	)		310
Public common unitholders (19,495,575 units issued and outstanding
as of September 30, 2015 and 19,492,291 units issued and outstanding
as of December 31, 2014)		103,851			208,273
Affiliated common unitholders (8,569,600 units issued and outstanding as of
September 30, 2015 and 4,089,600 units issued and outstanding as of
December 31, 2014)		-			4,643
Subordinated unitholders (4,480,000 units issued and outstanding as of
December 31, 2014)		-			5,411
Total unitholders’ equity		71,195			218,637
TOTAL LIABILITIES AND UNITHOLDERS’ EQUITY	$	423,092		$	558,954

See accompanying notes to the unaudited consolidated condensed financial statements.



LRR Energy, L.P.
Consolidated Condensed Statements of Operations
(Unaudited)
(in thousands, except per unit amounts)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Revenues:
Oil sales	$	13,277		$	19,258		$	39,568		$	59,768
Natural gas sales		4,111			6,542			12,097			22,206
Natural gas liquids sales		971			2,771			3,803			8,895
Gain (loss) on commodity
derivative instruments, net		29,193			19,771			38,948			821
Other income		16			40			71			111
Total revenues		47,568			48,382			94,487			91,801

Operating expenses:
Lease operating expense		5,961			6,024			18,741			18,688
Production and ad valorem taxes		1,369			2,172			4,117			6,820
Depletion and depreciation		10,015			8,711			27,589			25,856
Impairment of oil and natural gas
properties		96,334			-			132,296			-
Accretion expense		527			519			1,556			1,532
Loss (gain) on settlement of asset
retirement obligations		57			10			125			71
General and administrative expense		2,591			2,629			19,055			8,510
Total operating expenses		116,854			20,065			203,479			61,477

Operating income (loss)		(69,286	)		28,317			(108,992	)		30,324

Other income (expense), net
Interest expense		(3,261	)		(2,551	)		(9,150	)		(7,667	)
Gain (loss) on interest rate
derivative instruments, net		(748	)		492			(2,421	)		(930	)
Other income (expense), net		(4,009	)		(2,059	)		(11,571	)		(8,597	)

Income (loss) before taxes		(73,295	)		26,258			(120,563	)		21,727
Income tax (expense) benefit		(34	)		(26	)		(16	)		(138	)
Net income (loss) available to unitholders	$	(73,329	)	$	26,232		$	(120,579	)	$	21,589

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

General partner’s interest in net income
(loss)	$	(23,510	)	$	26		$	(32,944	)	$	22

Limited partners’ interest in net income
(loss)	$	(49,819	)	$	26,206		$	(87,635	)	$	21,567

Net income (loss) per limited partner unit



(basic and diluted)	$	(1.77	)	$	0.95	$	(3.12	)	$	0.80

Weighted average number of limited
partner units outstanding (basic and
diluted)		28,073			27,481		28,073			26,856

See accompanying notes to the unaudited consolidated condensed financial statements.



LRR Energy, L.P.
Consolidated Condensed Statement of Changes in Unitholders’ Equity
(Unaudited)
(in thousands)

				Limited Partners
	General			Public			Affiliated
	Partner			Common			Common			Subordinated			Total
Balance, December 31, 2014	$	310		$	208,273		$	4,643		$	5,411		$	218,637
Equity offering, net of expenses		-			2			-			-			2
Amortization of equity awards		-			1,160			-			-			1,160
Conversion of subordinated units		-			-			3,182			(3,182	)		-
Distribution		(22	)		(21,902	)		(3,872	)		(2,229	)		(28,025	)
Net income (loss)		(32,944	)		(83,682	)		(3,953	)		-			(120,579	)
Balance, September 30, 2015	$	(32,656	)	$	103,851		$	-		$	-		$	71,195

See accompanying notes to the unaudited consolidated condensed financial statements.



LRR Energy, L.P.
Consolidated Condensed Statements of Cash Flows
(Unaudited)
(in thousands)

		Nine Months Ended September 30,
		2015			2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	(120,579	)	$	21,589
Adjustments to reconcile net income (loss) to net cash provided by
(used in) operating activities:
Depletion and depreciation		27,589			25,856
Impairment of oil and natural gas properties		132,296			-
Accretion expense		1,556			1,532
Amortization of equity awards		1,160			819
Amortization of derivative contracts		373			510
Amortization of deferred financing costs and other		511			313
Loss (gain) on settlement of asset retirement obligations		125			71
Changes in operating assets and liabilities:
Change in receivables		825			598
Change in prepaid expenses		484			(1,515	)
Change in derivative assets and liabilities		(570	)		2,698
Change in amounts due to/from affiliates		7,036			(6,015	)
Change in accrued liabilities and deferred tax liabilities		5,171			1,838
Change in distributions payable		(3,511	)		-
Net cash provided by (used in) operating activities		52,466			48,294

CASH FLOWS FROM INVESTING ACTIVITIES
Development of oil and natural gas properties		(28,156	)		(25,840	)
Acquisition of oil and natural gas properties		(229	)		-
Disposition of oil and natural gas properties		-			50
Net cash provided by (used in) investing activities		(28,385	)		(25,790	)

CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings under revolving credit facility		15,000			30,000
Principal payments on revolving credit facility		(5,000	)		(30,000	)
Equity offering, net of expenses		2			23,419
Distributions		(24,514	)		(39,589	)
Net cash provided by (used in) financing activities		(14,512	)		(16,170	)

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		9,569			6,334

CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD		3,576			4,417

CASH AND CASH EQUIVALENTS, END OF PERIOD	$	13,145		$	10,751

See accompanying notes to the unaudited consolidated condensed financial statements.

LRR Energy, L.P.

Notes to Consolidated Condensed Financial Statements

(unaudited)


1.	Organization and Description of Business

LRR Energy, L.P. (“we,” “us,” “our,” or the “Partnership”) is a Delaware limited partnership formed in April 2011 by Lime Rock Management LP (“Lime Rock Management”), an affiliate of Lime Rock Resources A, L.P. (“LRR A”), Lime Rock Resources B, L.P. (“LRR B”) and Lime Rock Resources C, L.P. (“LRR C”), to operate, acquire, exploit and develop producing oil and natural gas properties in North America with long-lived, predictable production profiles. As used herein, references to “Fund I” refer collectively to LRR A, LRR B and LRR C; references to “Fund II” refer collectively to Lime Rock Resources II-A, L.P. and Lime Rock Resources II-C, L.P.; and references to “Fund III” refer collectively to Lime Rock Resources III-A, L.P. and Lime Rock Resources III-C, L.P. References to “Lime Rock Resources” refer collectively to Fund I, Fund II and Fund III.

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

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

Merger with Vanguard Natural Resources, LLC

On April 20, 2015, we entered into a Purchase Agreement and Plan of Merger (the “Merger Agreement”) with Vanguard Natural Resources, LLC (“Vanguard”), Lighthouse Merger Sub, LLC, a wholly owned indirect subsidiary of Vanguard (“Merger Sub” and together with Vanguard, the “Vanguard Entities”), Lime Rock Management, Fund I, Fund II (together with the Fund I and Lime Rock Management, the “GP Sellers”) and LRE GP, LLC (our “General Partner” and together with the GP Sellers and the Partnership, the “Partnership Entities”). Upon the terms and conditions set forth in the Merger Agreement, Merger Sub will be merged with and into the Partnership, with the Partnership continuing as the surviving entity and as a wholly owned subsidiary of Vanguard (the “Merger”) and, at the same time, all of the limited liability company interests in our General Partner will be acquired by Vanguard. Based upon the recommendation of the conflicts committee of the board of directors of our General Partner (the “Board”), the Board approved the Merger Agreement on April 20, 2015.

On October 5, 2015, the effective time of the Merger (the “Effective Time”), each of our common units issued and outstanding immediately prior to the Effective Time converted into 0.550 common units representing limited liability company interests in Vanguard (“Vanguard Units”) or, in the case of fractional Vanguard Units, cash (without interest and rounded up to the nearest whole cent) in an amount equal to the product of (i) such fractional part of a Vanguard Unit multiplied by (ii) the average closing price for a Vanguard Unit as reported on the NASDAQ Global Select Market (the “NASDAQ”) for the ten consecutive full trading days ending at the close of trading on the full trading day immediately preceding the closing date of the transactions contemplated by the Merger Agreement (the “Closing Date”). Each of our restricted common units that was outstanding pursuant to the 2011 LTIP vested immediately prior to the Effective Time and converted into Vanguard Units. In addition, on the Closing Date, Vanguard issued and delivered to the GP Sellers 12,320 Vanguard Units in exchange for all of the limited liability interests in our General Partner (the “GP Equity Consideration”).

The parties executed a Termination and Continuing Obligations Agreement (the “Termination Agreement”) substantially in the form attached as an exhibit to the Merger Agreement. Pursuant to the Termination Agreement, (i) that certain Omnibus Agreement, entered into, and effective as of, November 16, 2011 (the “Omnibus Agreement”), by and among us, our General Partner, OLLC, Fund I, LRR GP, LLC, the ultimate general partner of each of the

Fund I entities, and Lime Rock Management, was terminated and (ii) the Fund I entities, severally and in proportion to each entity’s Property Contributor Percentage (as defined in the Omnibus Agreement), agreed to indemnify the Partnership, our General Partner, OLLC and all of our and their respective subsidiaries from and against any losses arising out of any federal, state or local income tax liabilities attributable to the ownership or operation of the oil and natural gas properties owned or leased by any of the Partnership, our General Partner, OLLC or our or their respective subsidiaries prior to the closing of our initial public offering. The indemnification obligations of Fund I under the Termination Agreement will survive until the first anniversary of the Closing Date.


2.	Summary of Significant Accounting Policies

Our accounting policies are set forth in the audited consolidated financial statements in our Annual Report on Form 10-K for the year ended December 31, 2014 (“2014 Annual Report”) and are supplemented by the notes to these unaudited consolidated condensed financial statements. There have been no significant changes to these policies, and these unaudited consolidated condensed financial statements should be read in conjunction with the audited consolidated financial statements and notes in our 2014 Annual Report.

Basis of presentation

These interim financial statements are unaudited and have been prepared pursuant to the rules and regulations of the SEC regarding interim financial reporting. Accordingly, they do not include all of the information and notes required by accounting principles generally accepted in the United States of America (“GAAP”) for complete consolidated financial statements and should be read in conjunction with the audited consolidated financial statements in our 2014 Annual Report. While the year-end condensed balance sheet data was derived from audited financial statements, this interim report does not include all disclosures required by GAAP for annual periods. These unaudited interim consolidated condensed financial statements reflect all adjustments that are, in the opinion of management, necessary for a fair statement of the results for the periods presented.

Recent accounting pronouncements

On April 10, 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014-08, “Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity.” ASU No. 2014-08 amends the definition of a discontinued operation and requires entities to provide additional disclosures about discontinued operations as well as disposal transactions that do not meet the discontinued-operations criteria. We adopted ASU No. 2014-08 on January 1, 2015. The adoption of ASU No. 2014-08 did not have a material impact on our consolidated condensed financial position, results of operations or cash flows.

On May 28, 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers.” ASU No. 2014-09 outlined a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance. The core principle of the revenue model is that an entity recognizes revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In August 2015, the FASB approved a delay in adoption for public entities and ASU No. 2014-09 is effective for annual periods beginning after December 15, 2017.We are still evaluating the impact of our adoption of ASU No. 2014-09.

On August 27, 2014, the FASB issued ASU No. 2014-15, “Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern.” ASU No. 2014-15 provides guidance on determining when and how reporting entities must disclose going concern uncertainties in their financial statements. The new standard requires management to perform interim and annual assessments of an entity’s financial statements (or within one year after the date on which the financial statements are available to be issued, when applicable). Further, an entity must provide certain disclosures if there is “substantial doubt about the entity’s ability to continue as a going concern.” ASU No. 2014-15 is effective for annual periods ending after December 15, 2016, and interim periods thereafter;

early adoption is permitted. We do not expect the adoption of ASU No. 2014-15 to have a material impact on our financial statement disclosures.

On February 18, 2015, the FASB issued No. ASU 2015-02, “Consolidation (Topic 810): Amendments to the Consolidation Analysis.” ASU No. 2015-02 applies to entities in all industries and provides a new scope exception to registered money market funds and similar unregistered money market funds. The standard makes targeted amendments to the current consolidation guidance and ends the deferral granted to investment companies from applying the variable interest entities guidance. ASU No. 2015-02 is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2015. We are still evaluating the impact of our adoption of ASU No. 2015-02.

On April 7, 2015, the FASB issued ASU No. 2015-03, “Simplifying the Presentation of Debt Issuance Costs.” ASU No. 2015-03 changes the presentation of debt issuance costs in financial statements. The new standard requires entities to present debt issuance costs as a direct deduction from the related debt liability rather than as an asset. Amortization of the costs is reported as interest expense. ASU No. 2015-03 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015, and interim periods beginning after December 15, 2016. Early adoption is allowed for all entities for financial statements that have not been previously issued. Entities would apply the new guidance retrospectively to all prior periods.

On August 16, 2015, the FASB issued ASU No. 2015-15, “Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of Credit Arrangements: Amendments to the Securities and Exchange Commission (the “SEC”) Paragraphs Pursuant to Staff Announcement at June 18, 2015 EITF Meeting.” ASU No. 2015-15 clarifies the SEC staff’s position on presenting and measuring debt issuance costs incurred in connection with line-of-credit arrangements given the lack of guidance on this topic in ASU 2015-03. The SEC staff has announce that it would “not object to an entity deferring and presenting debt issuance costs as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement.” ASU No. 2015-15 is effective upon issuance. We do not expect the adoption of ASU No. 2015-03 or ASU No. 2015-15 to have a material impact on our financial statements or disclosures.


3.	Acquisitions

Third Party Acquisition

On October 1, 2014, we completed an acquisition of oil and natural gas properties in the Stroud field located in Lincoln and Creek Counties, Oklahoma for a purchase price of $38.0 million, subject to customary purchase price adjustments (the “October 2014 Acquisition”) from an unrelated third party. We paid total cash consideration of $38.2 million at closing. The October 2014 Acquisition was effective September 1, 2014. In January 2015, we paid $0.2 million in cash to the seller related to post-closing adjustments to the purchase price. We financed the acquisition with borrowings under our revolving credit facility (Note 7).

The October 2014 Acquisition was accounted for under the acquisition method of accounting, whereby the purchase price was allocated to the assets acquired and liabilities assumed based on their fair values, with any excess of the purchase price over the estimated fair value of the identifiable net assets acquired recorded as goodwill (or shortfall of purchase price versus net fair value recorded as bargain purchase). Based on the purchase price allocation for October 2014 Acquisition, no goodwill or bargain purchase was recognized. The cash consideration paid for the October 2014 Acquisition and the assets and liabilities recognized are presented in the table below (in thousands, except for per unit amounts):

The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties included estimates of: (i) reserves, including risk adjustments for probable and possible reserves; (ii) production rates; (iii) future operating and development costs; (iv) future commodity prices; (v) future cash flows; and (vi) a market-based weighted average cost of capital rate. These inputs required significant judgments and estimates by our management at the time of the valuation and are subject to change.

The following unaudited pro forma information shows the pro forma effects of the October 2014 Acquisition. The unaudited pro forma information assumes the transaction occurred on January 1, 2014. The pro forma results of operations have been prepared by adjusting our historical results to include the historical results of the acquired assets based on information provided by the seller, our knowledge of the acquired properties and the impact of our purchase price allocation. We believe the assumptions used provide a reasonable basis for reflecting the pro forma significant effects directly attributable to the acquisition. The pro forma results of operations do not include any cost savings or other synergies that may result from the October 2014 Acquisition or any estimated costs that have been or will be incurred to integrate the assets. The following unaudited pro forma information does not purport to represent what our results of operations would have been if such acquisition had occurred on January 1, 2014 (in thousands).



		Three Months Ended		Nine Months Ended
		September 30, 2014		September 30, 2014
Total revenues	$	50,729	$	98,842
Net income (loss) available to unitholders		27,528		25,476
Basic and diluted net income (loss) per unit		1.00		0.95


4.	Fair Value Measurements

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

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. GAAP establishes a three-tier fair value hierarchy, which prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of fair value hierarchy are as follows:

Level 1—Defined as inputs such as unadjusted quoted prices in active markets for identical assets or liabilities.

Level 2—Defined as inputs other than quoted prices in active markets that are either directly or indirectly observable for the asset or liability.

Level 3—Defined as unobservable inputs for use when little or no market data exists, requiring an entity to develop its own assumptions for the asset or liability.

We utilize the most observable inputs available for the valuation technique used. The financial assets and liabilities are classified in their entirety based on the lowest level of input that is of significance to the fair value measurement. The following table describes, by level within the hierarchy, the fair value of our financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2015 and December 31, 2014 (in thousands).




		Level 1		Level 2		Level 3		Total
September 30, 2015
Assets:
Commodity derivative instruments	$	-	$	85,243	$	-	$	85,243
Liabilities:
Commodity derivative instruments		-		834		-		834
Interest rate derivative instruments		-		3,679		-		3,679
December 31, 2014
Assets:
Commodity derivative instruments	$	-	$	84,464	$	-	$	84,464
Liabilities:
Commodity derivative instruments		-		788		-		788
Interest rate derivative instruments		-		3,144		-		3,144

All fair values reflected in the table above and on the consolidated condensed balance sheets have been adjusted for non-performance risk. The following methods and assumptions were used to estimate the fair values of the assets and liabilities in the table above.

Commodity Derivative Instruments—The fair value of the commodity derivative instruments is estimated using a combined income and market valuation methodology based upon forward commodity price and volatility curves. The curves are obtained from independent pricing services reflecting broker market quotes.

Interest Rate Derivative Instruments—The fair value of the interest rate derivative instruments is estimated using a combined income and market valuation methodology based upon forward interest rates and volatility curves. The curves are obtained from independent pricing services reflecting broker market quotes.


5.	Property and Equipment

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



		September 30, 2015			December 31, 2014

Oil and natural gas properties (successful efforts method)	$	976,011		$	954,819
Unproved properties		1,221			1,235
Other property and equipment		732			272
		977,964			956,326
Accumulated depletion, depreciation and impairment		(666,428	)		(506,368	)
Total property and equipment, net	$	311,536		$	449,958

We recorded $10.0 million and $8.7 million of depletion and depreciation expense for each of the three months ended September 30, 2015 and 2014. We recorded $27.6 million and $25.9 million of depletion and depreciation expense for the nine months ended September 30, 2015 and 2014, respectively.

We perform an impairment analysis of our oil and natural gas properties on a quarterly basis due to the volatility in commodity prices. For the three months ended September 30, 2015, we recorded a total non-cash impairment charge of $96.3 million to impair the value of our proved oil and natural gas properties in the Permian Basin and the Mid-Continent region. We did not record any impairment charges in the three months ended September 30, 2014. For the nine months ended September 30, 2015, we recorded a total non-cash impairment charge of $132.3 million to impair the value of our proved oil and natural gas properties in the Permian Basin, Gulf Coast, and the Mid-Continent regions. These impairment charges reduced the regions’ carrying values to an estimated fair value of $310.0 million as of September 30, 2015. We did not record any impairment charges in the nine months ended September 30, 2014. These asset impairments have no impact on cash flows, liquidity positions, or debt covenants.

These impairments of proved and unproved oil and natural gas properties were recorded because the net capitalized costs of the properties exceeded the fair value of the properties as measured by estimated cash flows reported in an internal reserve report. Further, our unproved properties were impaired based on the drilling locations for the probable and possible reserves becoming uneconomic at the lower future expected natural gas prices and our future expected drilling schedules. These reports are based upon future oil and natural gas prices, which are based on observable inputs, adjusted for basis differentials. These are classified as Level 3 fair value measurements. The fair values of our properties are measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of the properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market‑based weighted average cost of capital rate. The underlying commodity prices embedded in the our estimated cash flows are the product of a process that begins with New York Mercantile Exchange (“NYMEX”) forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that management believes will impact realizable prices. Furthermore, significant assumptions in valuing the proved reserves included the reserve quantities, anticipated drilling and operating costs, anticipated production taxes, future expected natural gas prices and basis differentials, anticipated drilling schedules, anticipated production declines, and an appropriate discount rate commensurate with the risk of the underlying cash flow estimates. Cash flow estimates for the impairment testing excluded derivative instruments used to mitigate the risk of lower future natural gas prices. Significant assumptions in valuing the unproved reserves included the evaluation of the probable and possible reserves, future expected natural gas prices and basis differentials, and anticipated drilling schedules.


6.	Asset Retirement Obligations

The following is a summary of our asset retirement obligations as of and for the nine months ended September 30, 2015 (in thousands):



Beginning of period	$	41,604
Acquisitions		13
Revisions to previous estimates		5
Liabilities incurred		186
Liabilities settled		(375	)
Accretion expense		1,556
End of period		42,989
Current portion of asset retirement obligations		(1,840	)
Asset retirement obligations — non-current	$	41,149


7.	Long-Term Debt

Credit Agreement

We, as guarantor, and our wholly owned subsidiary, OLLC, as borrower, are parties to a five-year, $750 million senior secured revolving credit facility, as amended (the “Credit Agreement”), that matures on October 1, 2019. The Intercreditor Agreement (as described below) limits the amount of indebtedness outstanding at any time under the Credit Agreement (including undrawn amounts under letters of credit) to an amount not to exceed $500 million in the aggregate. The Credit Agreement is reserve-based and we are permitted to borrow under our credit facility an amount up to the borrowing base, which was $241 million as of September 30, 2015. Our borrowing base, which is primarily based on the estimated value of our oil, natural gas liquids (“NGL”), and natural gas properties and our commodity derivative contracts, is subject to redetermination semi-annually by our lenders at their sole discretion. As of September 30, 2015, we were in compliance with all covenants contained in the Credit Agreement.

In May 2015, we entered into the Fifth Amendment (“Fifth Credit Agreement Amendment”) to our Credit Agreement. The Fifth Credit Agreement Amendment, among other things, (i) increased the interest rate margins applicable to the loans with margins ranging from 2.00% to 3.10% for Eurodollar loans, and from 1.00% to 2.10% for base rate loans, in each case based on utilization of the credit facility, (ii) increased the commitment fee applicable to the unused portion of the borrowing base with amounts ranging from 0.375% to 0.800% based on utilization of the credit facility, (iii) restricted the payments of distributions to $10.6 million through September 30, 2015; however, after October 1, 2015, distributions are subject to a minimum of 15% availability under a conforming borrowing base amount, and (iv) decreased the borrowing base to $245.0 million. Pursuant to the amendment, the borrowing base began to decrease in the amount of $1.0 million per month, beginning in June 2015 and continuing until the next redetermination of the borrowing base in the fall of 2015. The borrowing base of the Credit Agreement will revert to $195.0 million upon the earlier of November 1, 2015 and a termination of the Merger Agreement.

In September 2015, we entered into an amended and restated consent letter agreement (the “Amended & Restated Credit Agreement Consent”) to the our Credit Agreement dated as of July 22, 2011, among OLLC, the Partnership, as parent guarantor, the lenders party thereto and Wells Fargo Bank, National Association, as administrative agent. The Amended & Restated Credit Agreement Consent, among other things, permitted the Partnership to announce a cash distribution in an aggregate amount not to exceed $3.6 million to be paid to its transfer agent for the benefit of its unitholders no sooner than one business day after the Closing Date (as defined in the Merger Agreement), provided that the announcement of the distribution must provide that the payment of the cash distribution be conditioned and contingent upon the consummation of the Transactions (as defined in the Merger Agreement) and the occurrence of the Closing Date, including, without limitation, the indefeasible repayment in full, in cash, of all Indebtedness (as defined in the Credit Agreement) and the termination of the Credit Agreement as well as other conditions described in the Amended & Restated Credit Agreement Consent.

On October 5, 2015, in connection with the closing of the Merger, the Credit Agreement was terminated.

Term Loan Agreement

We, as parent guarantor, and our wholly owned subsidiary, OLLC, as borrower, are parties to a Second Lien Credit Agreement (the “Term Loan Agreement”). The Term Loan Agreement provides for a $50 million senior secured second lien term loan to OLLC. OLLC borrowed $50 million under the Term Loan Agreement and used the borrowings to repay outstanding borrowings under the Credit Agreement.

The Term Loan Agreement contains various covenants and restrictive provisions as described in our 2014 Annual Report. As of September 30, 2015, we were in compliance with the leverage and current ratios contained in our Term Loan Agreement. We are required to test the asset coverage ratio at specified intervals as described in the Term Loan Agreement, including during the redetermination of our borrowing base under our Credit Agreement.

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

In May 2015, we entered into the Fifth Amendment (“Fifth Term Loan Amendment”) to our Term Loan Agreement. The Fifth Term Loan Amendment, among other things, amended the Term Loan Agreement to (i) increase the interest rate margins applicable to the loan with margins for Eurodollar loans and Alternate Base Rate loans increasing to 9.50% and 8.50%, respectfully, after September 30, 2015, and (ii) restrict the payments of distributions to $10.6 million through September 30, 2015.

In September 2015, the Partnership also entered into an amended and restated consent letter agreement (the “Amended & Restated Term Loan Agreement Consent”) to the Second Lien Credit Agreement dated as of June 28, 2012 by and among the Partnership, as parent guarantor, OLLC, as borrower, the lenders from time to time party thereto and Wells Fargo Energy Capital, Inc., as administrative agent (“Second Lien Agent”). The Amended & Restated Term Loan Agreement Consent, among other things, permitted the Partnership to announce a cash distribution in an aggregate amount not to exceed $3.6 million to be paid to its transfer agent for the benefit of its unitholders no sooner than one business day after the Closing Date (as defined in the Merger Agreement), provided that the announcement of the distribution must provide that the payment of the cash distribution be conditioned and contingent upon the consummation of the Transactions (as defined in the Merger Agreement) and the occurrence of the Closing Date, including, without limitation, the indefeasible repayment in full, in cash, of all Indebtedness (as defined in the Term Loan Agreement) and the termination of the Term Loan Agreement as well as other conditions described in the Amended & Restated Term Loan Agreement Consent.

On October 5, 2015, in connection with the closing of the Merger, the Term Loan Agreement was terminated.

As of September 30, 2015, we had $290.0 million of outstanding debt and accrued interest was approximately $0.1 million. As of December 31, 2014, we had $280.0 million of outstanding debt and accrued interest was approximately $0.2 million.

Interest expense for the three months ended September 30, 2015 and 2014 was $3.3 million and $2.6 million, respectively. Interest expense for the nine months ended September 30, 2015 and 2014 was $9.2 million and $7.7 million, respectively. As of September 30, 2015 and December 31, 2014, our weighted average interest rate on our outstanding indebtedness was 5.23% and 3.81%, respectively. Please refer to Note 8 below for a discussion of our interest rate derivative contracts.


8.	Derivatives

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

Under commodity swap agreements, we exchange a stream of payments over time according to specified terms with another counterparty. Specifically for commodity price swap agreements, we agree to pay an adjustable or floating price tied to an agreed upon index for the commodity, either gas or oil, and in return receive a fixed price based on notional quantities. Under basis swap agreements, we agree to pay an adjustable or floating price tied to two agreed upon indices for gas and in return receive the differential between a floating index and fixed price based on notional quantities.

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

At September 30, 2015, we had the following open commodity derivative contracts:



	Index		2015			2016			2017		2018
Natural gas positions
Price swaps (MMBtu)	NYMEX-HH		1,329,699			5,433,888			5,045,760		3,452,172
Weighted average price		$	5.77		$	4.29		$	4.61	$	4.05

Basis swaps (MMBtu)	⁽¹⁾		1,286,278			2,877,047			-		-
Weighted average price		$	(0.1669	)	$	(0.1115	)	$	-	$	-

Oil positions
Price swaps (Bbl)	NYMEX-WTI		176,630			610,131			473,698		562,524
Weighted average price		$	93.49		$	87.27		$	84.34	$	82.26

Basis swaps (Bbl)	Argus-		91,205			364,800			-		-
Weighted average price	Midland-Cushing	$	(3.25	)	$	(1.05	)	$	-	$	-

NGL positions
Price swaps (Bbl)	Mont Belvieu		55,335			-			-		-
Weighted average price		$	34.45		$	-		$	-	$	-


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

At December 31, 2014, we had the following open commodity derivative contracts:



	Index		2015			2016			2017		2018
Natural gas positions
Price swaps (MMBtu)	NYMEX-HH		5,500,236			5,433,888			5,045,760		2,374,800
Weighted average price		$	5.72		$	4.29		$	4.61	$	4.28

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

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

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

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


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

At September 30, 2015, we had the following interest rate swap derivative contracts (in thousands):



		Notional
Effective	Maturity	Amount	Average %		Index
February 2015	February 2017	75,000	1.72500	%	LIBOR
February 2015	February 2017	75,000	1.72750	%	LIBOR
June 2015	June 2017	70,000	1.42750	%	LIBOR

At December 31, 2014, we had the following interest rate swap derivative contracts (in thousands):



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

Effect of Derivative Instruments – Balance Sheet

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



	As of September 30, 2015
		Current		Long-term		Current		Long-term
		Assets		Assets		Liabilities		Liabilities
Interest rate
Swaps	$	-	$	-	$	2,779	$	900
Gross fair value		-		-		2,779		900
Netting arrangements		-		-		-		-
Net recorded fair value	$	-	$	-	$	2,779	$	900

Sale of natural gas production
Price swaps	$	10,397	$	13,182	$	-	$	-
Basis swaps		-		-		149		28
Sale of crude oil production
Price swaps		25,991		34,756		-		-
Basis swaps		-		-		558		99
Sale of NGLs
Price swaps		917		-		-		-
Gross fair value		37,305		47,938		707		127
Netting arrangements		-		-		-		-
Net recorded fair value	$	37,305	$	47,938	$	707	$	127



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

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

Effect of Derivative Instruments – Statements of Operations

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



	Three Months Ended September 30,					Nine Months Ended September 30,
	2015			2014		2015			2014
Commodity derivatives (revenue)	$	29,193		$	19,771	$	38,948		$	821
Interest rate derivatives (other
income (expense), net)		(748	)		492		(2,421	)		(930	)

Credit Risk

All of our derivative transactions have been carried out in the over-the-counter market. The use of derivative instruments involves the risk that the counterparties may be unable to meet the financial terms of the transactions. We monitor the creditworthiness of each of our counterparties and assess the possibility of whether each counterparty to the derivative contract would default by failing to make any contractually required payments as scheduled in the derivative instrument in determining the fair value. We also have netting arrangements in place with each counterparty to reduce credit exposure. The derivative transactions are placed with major financial institutions that present minimal credit risks to us. Additionally, we consider ourselves to be of substantial credit quality and have the financial resources and willingness to meet our potential repayment obligations associated with the derivative transactions.


9.	Related Parties

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

As of September 30, 2015, Lime Rock Management, an affiliate of Fund I, owned all of the Class A member interests in our general partner, Fund I owned all of the Class B member interests in our general partner and Fund II owned all of the Class C member interests in our general partner. In addition, Fund I owned an aggregate of approximately 30.5% of our outstanding common units, representing their limited partner interest in us. As of September 30, 2015, our general partner owned an approximate 0.1% general partner interest in us, represented by 22,400 general partner units, and all of our incentive distribution rights.

As more fully described in our 2014 Annual Report, we converted 2,240,000 subordinated units on a one-for-one basis into common units pursuant to the terms of our partnership agreement on May 16, 2014. We converted the remaining 4,480,000 subordinated units on a one-for-one basis into common units pursuant to the terms of our partnership agreement on February 13, 2015.

Contracts with our General Partner and its Affiliates

As more fully described in our 2014 Annual Report, we have entered into agreements with our general partner and its affiliates. For each of the three months ended September 30, 2015 and 2014, we paid Lime Rock Management approximately $0.5 million either directly or indirectly related to these agreements. For the nine months ended September 30, 2015 and 2014, we paid Lime Rock Management approximately $1.3 million and $1.1 million either directly or indirectly related to these agreements, respectively.

In connection with the management of our business, Lime Rock Resources Operating Company, Inc. (“ServCo”), an affiliate of our general partner, provides services for invoicing and processing of payments to our vendors. Periodically, ServCo remits cash to us for the net working capital received on our behalf. Changes in the affiliates (payable)/receivable balances during the nine months ended September 30, 2015 are included below (in thousands):



					Lime Rock
		ServCo			Resources			Total

Balance as of December 31, 2014	$	5,436		$	261		$	5,697
Expenditures		(154,767	)		(263	)		(155,030	)
Cash paid for expenditures		157,013			-			157,013
Revenues and other		(9,021	)		2			(9,019	)
Balance as of September 30, 2015	$	(1,339	)	$	-		$	(1,339	)

On October 5, 2015, in connection with the Merger, we settled the $1.3 million due to affiliates with ServCo.

Distributions of Available Cash to Our General Partner and Affiliates

We will generally make cash distributions to our unitholders and our general partner pro rata. As of September 30, 2015, our general partner and its affiliates held 8,569,600 of our common units and 22,400 general partner units. During the nine months ended September 30, 2015 and 2014, we paid cash distributions of $24.5 million and $39.6 million, respectively, to all unitholders as of the respective record dates. As of September 30, 2015, we accrued $3.5 million of distribution for the prorated cash distribution for the third quarter of 2015 for the months of July and August. Refer to Note 15 for additional information.


10.	Unitholders’ Equity

At-the-Market Offering Program

On February 4, 2014, we launched an “at-the-market” offering program (the “ATM Program”) with MLV & Co. LLC (“MLV”) as sales agent. We may sell from time to time through MLV our common units representing limited partner interests having an aggregate offering amount of up to $75.0 million, subject to limitations as described in the Merger Agreement (described in Note 1). Any sales of common units under the ATM Program may be made by any method permitted by law deemed to be an “at-the-market offering” defined by Rule 415 of the Securities Act of 1933, as amended, (the “Securities Act”), including, without limitation, sales made directly on the New York Stock Exchange, or any other existing trading market for our common units or to or through a market maker.

Our second lien term loan requires that 50% of the net cash proceeds from any equity offering be used to repay borrowings outstanding under the term loan. During the nine months ended September 30, 2015, we did not sell common units under the ATM Program.

Units Outstanding

As of September 30, 2015, we had 28,065,175 common units and 22,400 general partner units outstanding. As of September 30, 2015, Fund I owned 8,569,600 common units, representing a 30.5% limited partner interest in us.

General Partner Allocation of Loss

In accordance with our partnership agreement, the allocation of net loss cannot cause a unitholder to have a deficit balance. Deficit balances are carried by our general partner until net income is generated in a taxable period. Our general partner will recover losses from net income generated prior to the net income being allocated to the remaining unitholders.


11.	Net Income (Loss) Per Limited Partner Unit

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Net income (loss) available to
unitholders	$	(73,329	)	$	26,232		$	(120,579	)	$	21,589
Less: General partner’s interest in
net (income) loss		23,510			(26	)		32,944			(22	)
Limited partners’ interest in net
income (loss)	$	(49,819	)	$	26,206		$	(87,635	)	$	21,567

Weighted average limited partner
units outstanding:
Common units		28,073			23,001			27,351			21,260
Subordinated units		-			4,480			722			5,596
Total		28,073			27,481			28,073			26,856

Net income (loss) per limited partner
unit (basic and diluted)	$	(1.77	)	$	0.95		$	(3.12	)	$	0.80

Our subordinated units and restricted unit awards are considered to be participating securities for purposes of calculating our net income (loss) per limited partner unit, and accordingly, are included in basic computation as such. Net income (loss) per limited partner unit is determined by dividing the net income (loss) available to the common unitholders, after deducting our general partner’s interest in net income (loss), by the weighted average number of common units and subordinated units outstanding as of September 30, 2015 and 2014. The aggregate number of common units outstanding was 28,065,175, as of September 30, 2015. We did not have any subordinated units outstanding as of September 30, 2015. The aggregate number of common units and subordinated units outstanding was 23,168,539 and 4,480,000, respectively, as of September 30, 2014.


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 consisted of unit options, restricted units, phantom units, unit appreciation rights, distribution equivalent rights, unit awards and other unit-based awards. The 2011 LTIP limited the number of units that may be delivered pursuant to vested awards to 1,500,000 common units. As of September 30, 2015, there were 1,034,271 units available for issuance under the 2011 LTIP. The 2011 LTIP was administered by our General Partner’s board of directors or a committee thereof. The 2011 LTIP was terminated in connection with the Merger.

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

A summary of the status of the non-vested restricted units as of September 30, 2015 is presented below:



	Number of			Weighted Average
	Non-vested			Grant-date
	Restricted Units			Fair Value
Non-vested restricted units at December 31, 2014		361,957		$	9.38
Granted		12,542			5.98
Vested		(33,414	)		12.77
Forfeited		(9,258	)		9.00
Non-vested restricted units at September 30, 2015		331,827			8.92

As of September 30, 2015, there was approximately $2.0 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 1.9 years. There were 133,902 vested restricted units as of September 30, 2015. At the close of the Merger, all unvested restricted units vested and we recognized $2.1 million in compensation expense.


13.	Subsidiary Guarantors

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

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


14.	Commitments and Contingencies

Litigation

The following class action lawsuits were filed in connection with the Merger by purported LRR Energy, L.P. unitholders:


•	Barry Miller v. LRR Energy, L.P. et al., Case No. 11087-VCG, filed in the Court of Chancery of the State of Delaware on June 3, 2015 (“Miller Lawsuit”)


•	Christopher Tiberio v. LRR Energy, L.P. et al., Cause No. 2015-39864, filed in the 334^th Judicial District Court of Harris County, Texas on July 10, 2015 (“Tiberio Lawsuit”)


•	Eddie Hammond v. LRR Energy, L.P. et al., Cause No. 2015-40154, filed in the 295^th Judicial District Court of Harris County, Texas on July 13, 2015 (“Hammond Lawsuit”)


•	Ronald Krieger v. LRR Energy, L.P. et al., Civil Action No. 4:15-cv-2017, filed in the United States District Court for the Southern District of Texas on July 14, 2015 (“Krieger Lawsuit”)


•	Robert Hurwitz v. Eric Mullens et al., Civil Action No. 1:15-cv-00711-UNA, filed in the United States

District Court for the District of Delaware on August 18, 2015 (the “Hurwitz Lawsuit”).

The Miller Lawsuit, Tiberio Lawsuit, Hammond Lawsuit, and Krieger Lawsuit were filed against us, our

General Partner, our Board, Vanguard, Merger Sub and the other parties to the Merger Agreement. The Hurwitz Lawsuit is filed against our Board, Vanguard, and Merger Sub (the “Defendants”).

On July 17, 2015, the Krieger Lawsuit was voluntarily dismissed without prejudice. On July 23, 2015 the Miller Lawsuit was also voluntarily dismissed without prejudice. On July 28, 2015 the Tiberio Lawsuit and the Hammond Lawsuit were both nonsuited without prejudice.

The Hurwitz Lawsuit alleges that the Defendants violated Sections 14(a) and/or 20(a) of the Securities and

Exchange Act of 1934 and Rule 14a-9 promulgated thereunder. In general, the Hurwitz Lawsuit alleges that the proxy statement/prospectus filed in connection with the Merger failed, among other things, to disclose allegedly material details concerning (i) the background of the Merger, (ii) the financial analyses conducted by the

Partnership’s and our conflicts committee’s financial advisors in connection with the Merger, (iii) the Partnership’s and Vanguard’s financial and operational projections, and (iv) alleged conflicts of interest held by one of our financial advisors.

The Hurwitz Lawsuit seeks, among other relief, to rescind the Merger and an award of attorneys’ fees and costs.

The plaintiff in the Hurwitz Lawsuit has not yet served the Defendants, and the Defendants’ date to answer, move to dismiss, or otherwise respond to the Hurwitz Lawsuit has not yet been set.


15.	Subsequent Events

Unit Distribution

On September 18, 2015, we announced that the Board declared a prorated cash distribution for the third quarter of 2015 for the months of July and August of $0.1250 per outstanding unit, or $0.75 on an annualized basis. The distribution was paid on October 15, 2015 to all unitholders of record as of the close of business on October 1, 2015. The aggregate amount of the distribution was $3.5 million.

Close of Merger

On October 5, 2015, we held a special meeting of unitholders in connection with the previously announced merger with Vanguard. At the special meeting, our unitholders voted and approved the Merger Agreement. As a result of the transaction, LRR Energy and its general partner became wholly owned subsidiaries of Vanguard (Note 1).

Property and equipment, net

Asset retirement obligations

Net assets