8-K/A

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K/A

CURRENT REPORT

PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

Date of Report (Date of earliest event reported): November 25, 2015 (October 5, 2015)

Vanguard Natural Resources, LLC

(Exact name of registrant specified in its charter)

Delaware	001-33756	61-1521161
(State or Other Jurisdiction	(Commission	(IRS Employer
Of Incorporation)	File Number)	Identification No.)

5847 San Felipe, Suite 3000

Houston, TX 77057

(Address of principal executive offices, zip code)

Registrant’s telephone number, including area code: (832) 327-2255

(Former name or former address, if changed since last report.)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

oWritten communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

oSoliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

oPre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

oPre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Introductory Note

As reported in a Current Report on Form 8-K filed with the Securities and Exchange Commission by Vanguard on October 5, 2015 (the “Original LRE Form 8-K”), on October 5, 2015, Vanguard Natural Resources, LLC, a Delaware limited liability company (“Vanguard”), completed the previously announced transactions contemplated by the Purchase Agreement and Plan of Merger, dated as of April 20, 2015 (the “LRE Merger Agreement”), by and among Vanguard, Lighthouse Merger Sub, LLC, a wholly owned subsidiary of Vanguard (“Lighthouse Merger Sub”), Lime Rock Management LP (“LR Management”), Lime Rock Resources A, L.P. (“LRR A”), Lime Rock Resources B, L.P. (“LRR B”), Lime Rock Resources C, L.P. (“LRR C”), Lime Rock Resources II-A, L.P. (“LRR II-A”), Lime Rock Resources II-C, L.P. (“LRR II-C,” and, together with LRR A, LRR B, LRR C, LRR II-A and LR Management, the “GP Sellers”), LRR Energy, L.P. (“LRE”) and LRE GP, LLC (“LRE GP”). Pursuant to the terms of the LRE Merger Agreement, Lighthouse Merger Sub was merged with and into LRE, with LRE continuing as the surviving entity and as a wholly owned subsidiary of Vanguard (the “LRE Merger”), and, at the same time, Vanguard acquired all of the limited liability company interests in LRE GP from the GP Sellers in exchange for common units representing limited liability company interests in Vanguard (“Vanguard Common Units”).

The LRE Merger was completed following approval, at a special meeting of LRE unitholders on October 5, 2015, of the LRE Merger Agreement and the LRE Merger by holders of a majority of the outstanding common units representing limited partner interests in LRE (“LRE Common Units”). As a result of the LRE Merger, (i) each outstanding LRE Common Unit was converted into the right to receive 0.550 newly issued Vanguard Common Units or, in the case of fractional Vanguard Common Units, cash (without interest and rounded up to the nearest whole cent) and (ii) Vanguard purchased all of the outstanding limited liability company interests in LRE GP in exchange for 12,320 newly issued Vanguard Common Units.

In addition, as reported in a Current Report on Form 8-K filed with the Securities and Exchange Commission by Vanguard on October 8, 2015 (the “Original Eagle Rock Form 8-K”), on October 8, 2015, Vanguard completed the previously announced transactions contemplated by the Agreement and Plan of Merger, dated as of May 21, 2015 (the “Eagle Rock Merger Agreement”), by and among Vanguard, Talon Merger Sub, LLC, an indirect wholly owned subsidiary of Vanguard (“Talon Merger Sub”), Eagle Rock Energy Partners, L.P. (“Eagle Rock”) and Eagle Rock Energy GP, L.P. (“Eagle Rock GP”). Pursuant to the terms of the Eagle Rock Merger Agreement, Talon Merger Sub was merged with and into Eagle Rock with Eagle Rock continuing as the surviving entity and as an indirect wholly owned subsidiary of Vanguard (the “Eagle Rock Merger”).

The Eagle Rock Merger was completed following (i) approvalby holders of a majority of the outstanding common units representing limited partner interests in Eagle Rock (“Eagle Rock Common Units”), at a special meeting of Eagle Rock unitholders on October 5, 2015, of the Eagle Rock Merger Agreement and the Eagle Rock Merger and (ii) approval by Vanguard unitholders, at Vanguard’s 2015 Annual Meeting of unitholders, of the issuance of Vanguard Common Units to be issued as merger consideration to the holders of Eagle Rock Common Units in connection with the Eagle Rock Merger. As a result of the Eagle Rock Merger, each outstanding Eagle Rock Common Unit was converted into the right to receive 0.185 newly issuedVanguard Common Units or, in the case of fractional Vanguard Common Units, cash.

This Current Report on Form 8-K/A is being filed to (i) provide updated unaudited quarterly financial statements of LRE and Eagle Rock and (ii) provide updated unaudited pro forma financial information related to the LRE Merger and the Eagle Rock Merger, in each case as required by Item 9.01 of Form 8-K of the Original LRE Form 8-K and the Original Eagle Rock Form 8-K, respectively.

Item 9.01    Financial Statements and Exhibits

(a) Financial Statements of Businesses Acquired

The unaudited consolidated condensed balance sheets of LRE as of September 30, 2015 and December 31, 2014, the unaudited consolidated condensed statements of operations for the three and nine months ended September 30, 2015 and 2014, the unaudited consolidated condensed statement of changes in unitholders’ equity as of September 30, 2015, the unaudited consolidated condensed statements of cash flows for the nine months ended September 30, 2015 and 2014, and the notes related thereto, are attached hereto as Exhibit 99.1 and incorporated by reference herein.

The unaudited condensed consolidated balance sheets of Eagle Rock as of September 30, 2015 and December 31, 2014, the unaudited condensed consolidated statements of operations and comprehensive income for the three and nine months ended September 30, 2015 and 2014, the unaudited condensed consolidated statement of members’ equity for the nine months ended September 30, 2015, the unaudited condensed consolidated statements of cash flows for the nine months ended September 30, 2015 and 2014, and the notes related thereto, are attached hereto as Exhibit 99.2 and incorporated by reference herein.

(b) Pro Forma Financial Information.

The unaudited pro forma condensed combined consolidated financial information of Vanguard, as adjusted for the LRE Merger and the Eagle Rock Merger, as of and for the nine months ended September 30, 2015 and for the year ended December 31, 2014, and the notes related thereto, are attached hereto as Exhibit 99.3 and incorporated herein by reference.

(d) Exhibits.

Exhibit Number	Description
Exhibit 99.1	The unaudited consolidated condensed balance sheets of LRR Energy, L.P. as of September 30, 2015 and December 31, 2014, the unaudited consolidated condensed statements of operations for the three and nine months ended September 30, 2015 and 2014, the unaudited consolidated condensed statement of changes in unitholders’ equity as of September 30, 2015, the unaudited consolidated condensed statements of cash flows for the nine months ended September 30, 2015 and 2014, and the notes related thereto
Exhibit 99.2	The unaudited condensed consolidated balance sheets of Eagle Rock Energy Partners, L.P. as of September 30, 2015 and December 31, 2014, the unaudited condensed consolidated statements of operations and comprehensive income for the three and nine months ended September 30, 2015 and 2014, the unaudited condensed consolidated statement of members’ equity for the nine months ended September 30, 2015, the unaudited condensed consolidated statements of cash flows for the nine months ended September 30, 2015 and 2014, and the notes related thereto
Exhibit 99.3	Unaudited pro forma condensed combined consolidated financial information of Vanguard, as adjusted for the LRE Merger and the Eagle Rock Merger, as of and for the nine months ended September 30, 2015 and for the year ended December 31, 2014

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

	VANGUARD NATURAL RESOURCES, LLC
Dated: November 25, 2015	By:	/s/ Richard A. Robert
		Name:	Richard A. Robert
		Title:	Executive Vice President and Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)

EXHIBIT INDEX

Exhibit Number	Description
Exhibit 99.1	The unaudited consolidated condensed balance sheets of LRR Energy, L.P. as of September 30, 2015 and December 31, 2014, the unaudited consolidated condensed statements of operations for the three and nine months ended September 30, 2015 and 2014, the unaudited consolidated condensed statement of changes in unitholders’ equity as of September 30, 2015, the unaudited consolidated condensed statements of cash flows for the nine months ended September 30, 2015 and 2014, and the notes related thereto
Exhibit 99.2	The unaudited condensed consolidated balance sheets of Eagle Rock Energy Partners, L.P. as of September 30, 2015 and December 31, 2014, the unaudited condensed consolidated statements of operations and comprehensive income for the three and nine months ended September 30, 2015 and 2014, the unaudited condensed consolidated statement of members’ equity for the nine months ended September 30, 2015, the unaudited condensed consolidated statements of cash flows for the nine months ended September 30, 2015 and 2014, and the notes related thereto
Exhibit 99.3	Unaudited pro forma condensed combined consolidated financial information of Vanguard, as adjusted for the LRE Merger and the Eagle Rock Merger, as of and for the nine months ended September 30, 2015 and for the year ended December 31, 2014

EX-99.1

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.

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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

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(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.

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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.

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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.

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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

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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;

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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):

Property and equipment, net	$	38,848
Asset retirement obligations		(691	)
Net assets	$	38,157

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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.

9

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

10

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

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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.

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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.

13

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:

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	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

15

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

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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):

17

					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

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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:

19

	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”).

20

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).

21

EX-99.2

Exhibit 99.2

Item 1.	Financial Statements
	Unaudited Condensed Consolidated Balance Sheets as of September 30, 2015 and December 31, 2014
	Unaudited Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2015 and 2014
	Unaudited Condensed Consolidated Statements of Comprehensive Income for the three and nine months ended September 30, 2015 and 2014
	Unaudited Condensed Consolidated Statement of Members' Equity for the nine months ended September 30, 2015
	Unaudited Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2015 and 2014
	Notes to Unaudited Condensed Consolidated Financial Statements

1

Item 1. Financial Statements

EAGLE ROCK ENERGY PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except unit amounts)

	September 30, 2015		December 31, 2014
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	20	$	1,343
Short-term investments	—		153,448
Accounts receivable (a)	25,802		39,596
Risk management assets	50,724		44,805
Prepayments and other current assets	8,569		9,911
Total current assets	85,115		249,103
PROPERTY, PLANT AND EQUIPMENT — Net	430,973		487,988
INTANGIBLE ASSETS — Net	2,925		3,072
DEFERRED TAX ASSET	2,237		2,315
RISK MANAGEMENT ASSETS	44,438		46,490
OTHER ASSETS	4,512		5,307
TOTAL	$	570,200	$	794,275
LIABILITIES AND MEMBERS' EQUITY
CURRENT LIABILITIES:
Accounts payable	$	42,176	$	49,226
Accrued liabilities	8,348		8,053
Taxes payable	29		2,246
Total current liabilities	50,553		59,525
LONG-TERM DEBT	151,801		263,343
ASSET RETIREMENT OBLIGATIONS	48,403		47,907
DEFERRED TAX LIABILITY	27,851		30,321
OTHER LONG TERM LIABILITIES	4,603		4,709
COMMITMENTS AND CONTINGENCIES (Note 12)
MEMBERS' EQUITY (b)	286,989		388,470
TOTAL	$	570,200	$	794,275

________________________

(a) Net of allowance for bad debt of $2,049 as of September 30, 2015 and $1,023 as of December 31, 2014.

(b) 149,563,456 and 150,154,909common units were issued and outstanding as of September 30, 2015 and December 31, 2014, respectively. These amounts do not include unvested restricted common units granted under the Partnership's long-term incentive plan of 3,423,262 and 2,419,750 as of September 30, 2015 and December 31, 2014, respectively.

See accompanying notes to unaudited condensed consolidated financial statements.

2

EAGLE ROCK ENERGY PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per unit amounts)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
REVENUE:
Natural gas, natural gas liquids, oil, condensate and sulfur	$	29,651		$	53,626		$	92,376		$	160,677
Commodity risk management gains (losses), net	39,849			27,967			50,914			(147		)
Other revenue	146			(369		)	144			(59		)
Total revenue	69,646			81,224			143,434			160,471
COSTS AND EXPENSES:
Operations and maintenance	10,754			10,707			33,590			33,112
Taxes other than income	1,264			3,184			3,990			10,571
General and administrative	11,652			12,235			34,047			37,530
Impairment	6,969			17,305			75,313			17,305
Depreciation, depletion and amortization	16,391			22,259			47,426			62,964
Total costs and expenses	47,030			65,690			194,366			161,482
OPERATING INCOME (LOSS)	22,616			15,534			(50,932		)	(1,011		)
OTHER (EXPENSE) INCOME:
Interest expense, net	(2,038		)	(3,188		)	(6,477		)	(12,890		)
Interest rate risk management gains (losses), net	(3,626		)	(81		)	(5,728		)	(942		)
Losses on short-term investments	—			—			(5,754		)	—
Other income, net	4			4,080			3,207			4,083
Total other expense	(5,660		)	811			(14,752		)	(9,749		)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	16,956			16,345			(65,684		)	(10,760		)
INCOME TAX BENEFIT	(968		)	(886		)	(2,489		)	(2,636		)
INCOME (LOSS) FROM CONTINUING OPERATIONS	17,924			17,231			(63,195		)	(8,124		)
DISCONTINUED OPERATIONS, NET OF TAX	(27		)	249,057			(1,001		)	212,808
NET INCOME (LOSS)	$	17,897		$	266,288		$	(64,196	)	$	204,684

NET INCOME (LOSS) PER COMMON UNIT—BASIC AND DILUTED:
Income (Loss) from Continuing Operations
Common units - Basic	$	0.12	$	0.11	$	(0.42	)	$	(0.05	)
Common units - Diluted	$	0.12	$	0.11	$	(0.42	)	$	(0.05	)
Discontinued Operations
Common units - Basic	$	—	$	1.56	$	(0.01	)	$	1.34
Common units - Diluted	$	—	$	1.56	$	(0.01	)	$	1.34
Net Income (Loss)
Common units - Basic	$	0.12	$	1.67	$	(0.43	)	$	1.29
Common units - Diluted	$	0.12	$	1.67	$	(0.43	)	$	1.29
Weighted Average Units Outstanding
Common units - Basic	149,563		157,375		149,337			156,995
Common units - Diluted	149,563		158,400		149,337			157,624

 See accompanying notes to unaudited condensed consolidated financial statements.

3

EAGLE ROCK ENERGY PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In thousands)

	Three Months Ended September 30,				Nine Months Ended September 30,
	2015		2014		2015			2014
Net income (loss)	$	17,897	$	266,288	$	(64,196	)	$	204,684
Other comprehensive income:
Gain on short-term investments	—		3,381		3,603			3,381
Loss on short-term investments	—		—		(3,603		)	—
COMPREHENSIVE INCOME (LOSS)	$	17,897	$	269,669	$	(64,196	)	$	208,065

 See accompanying notes to unaudited condensed consolidated financial statements.

UNAUDITED CONDENSED CONSOLIDATED STATEMENT OF MEMBERS’ EQUITY

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2015

(In thousands, except unit amounts)

	Number of Common Units		Common Units			Total
BALANCE — December 31, 2014	150,154,909		$	388,470		$	388,470
Net loss	—		(64,196		)	(64,196		)
Distributions	—		(38,967		)	(38,967		)
Vesting of restricted units	754,010		—			—
Repurchase of common units	(1,345,463	)	(3,046		)	(3,046		)
Equity based compensation	—		4,728			4,728
BALANCE — September 30, 2015	149,563,456		$	286,989		$	286,989

 See accompanying notes to unaudited condensed consolidated financial statements.

4

EAGLE ROCK ENERGY PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

	Nine Months Ended September 30,
	2015			2014
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(64,196	)	$	204,684
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Discontinued operations	1,001			(212,808		)
Depreciation, depletion and amortization	47,426			62,964
Impairment	75,313			17,305
Amortization of debt issuance costs	831			1,878
(Gain) loss from risk management activities, net	(45,187		)	1,089
Settlement of risk management instruments	44,156			(4,047		)
Equity-based compensation	4,728			6,990
Loss on short-term investments	5,754			—
Other	(2,390		)	(68		)
Changes in assets and liabilities—net of acquisitions:
Accounts receivable	7,721			(16,398		)
Prepayments and other current assets	1,342			(4,906		)
Accounts payable	(15,335		)	(7,414		)
Accrued liabilities	1,574			(2,402		)
Other assets	20			(88		)
Other current liabilities	(5,172		)	718
Net cash provided by operating activities	57,586			47,497
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment	(62,577		)	(106,664		)
Proceeds from sale of short-term investments	153,980			—
Net cash provided by (used in) investing activities	91,403			(106,664		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	92,900			416,700
Repayment of long-term debt	(204,500		)	(897,800		)
Payment of debt issuance costs	—			(410		)
Settlement of risk management instruments	(2,836		)	(5,163		)
Repurchase of common units	(3,046		)	(1,171		)
Distributions to members and affiliates	(31,829		)	(23,801		)
Net cash used in financing activities	(149,311		)	(511,645		)
CASH FLOWS FROM DISCONTINUED OPERATIONS:
Operating activities	(1,001		)	31,070
Investing activities	—			540,259
Net cash (used in) provided by discontinued operations	(1,001		)	571,329
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS	(1,323		)	517
CASH AND CASH EQUIVALENTS—Beginning of period	1,343			76
CASH AND CASH EQUIVALENTS—End of period	$	20		$	593
NONCASH INVESTING AND FINANCING ACTIVITIES:
Units received in divestiture	$	—		$	265,599
Investments in property, plant and equipment, not paid	$	13,476		$	10,811
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Interest paid—net of amounts capitalized	$	4,701		$	40,394
Cash paid for taxes	$	2,141		$	—

See accompanying notes to unaudited condensed consolidated financial statements.

5

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. ORGANIZATION AND DESCRIPTION OF BUSINESS

Description of Business—Eagle Rock Energy Partners, L.P. ("Eagle Rock Energy" or the "Partnership") is a growth-oriented master limited partnership engaged in (a) the exploitation, development and production of oil and natural gas properties and (b) ancillary gathering, compressing, treating, processing and marketing services with respect to its production of natural gas, natural gas liquids ("NGLs"), condensate and crude oil. The Partnership's assets, located primarily in Alabama (where it also operates the associated gathering and processing assets), Texas, Oklahoma, Mississippi and Arkansas, are characterized by long-lived, high-working interest properties with extensive production histories and development opportunities.

On July 1, 2014, the Partnership contributed its business of gathering, compressing, treating, processing, transporting, marketing and trading natural gas, fractionating, transporting and marketing NGLs and crude oil and condensate logistics and marketing (collectively, the “Midstream Business”) to Regency Energy Partners LP ("Regency") (such contribution, the "Midstream Business Contribution"). Accordingly, prior periods have been retrospectively adjusted to reflect the Midstream Business's operations as discontinued (see Note 16) in the financial statements included in this report. As a result of this transaction, the Partnership only reports as one segment.

The general partner of Eagle Rock Energy is Eagle Rock Energy GP, L.P., and the general partner of Eagle Rock Energy GP, L.P. is Eagle Rock Energy G&P, LLC (our "general partner"), both of which are wholly owned subsidiaries of the Partnership.

Recent Developments—On October 8, 2015, the Partnership completed its previously announced Agreement and Plan of Merger, dated as of May 21, 2015 (the "Merger Agreement"), with Vanguard Natural Resources, LLC ("Vanguard"), pursuant to which a subsidiary of Vanguard merged into the Partnership (the "Merger"). As a result of the Merger, the Partnership is a wholly owned indirect subsidiary of Vanguard. The transaction was a tax-free unit-for-unit transaction with an exchange ratio of 0.185 Vanguard common units per Eagle Rock Energy common unit and Vanguard's assumption of Eagle Rock Energy's debt.

NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation and Principles of Consolidation—The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP"). These unaudited condensed consolidated financial statements should be read in conjunction with the consolidated financial statements presented in the Partnership's Annual Report on Form 10-K for the year ended December 31, 2014 (the "2014 10-K"). In the opinion of management, the accompanying unaudited condensed consolidated financial statements contain all appropriate adjustments, all of which are normally recurring adjustments unless otherwise noted, considered necessary to present fairly the financial position of the Partnership and its consolidated subsidiaries and the results of operations and cash flows for the respective periods. Operating results for the three and nine months ended September 30, 2015 are not necessarily indicative of the results that may be expected for the full year ending December 31, 2015.

All intercompany accounts and transactions are eliminated in the unaudited condensed consolidated financial statements.

The Partnership has provided a discussion of significant accounting policies in its 10-K. Certain items from that discussion are repeated or updated below as necessary to assist in the understanding of these financial statements.

6

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 reported period. Significant estimates are required for proved oil and natural gas reserves, which can affect the carrying value of oil and natural gas properties. The Partnership evaluates its estimates and assumptions on a regular basis. The Partnership bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results could differ from those estimates and such differences could be material.

Short-term Investments— A portion of the consideration received for the Midstream Business Contribution included Regency common units. During the second quarter of 2015, Regency merged with Energy Transfer Partners, L.P. ("ETP") and the Regency common units were subsequently converted into ETP common units (the as-converted units referred to with the original units as "Regency Common Units"). These securities have a readily determinable fair value, were classified as available-for-sale equity securities and recorded as short-term investments on the unaudited condensed consolidated balance sheets. Unrealized gains and losses associated with increases and decreases in the fair value of these securities are included in other comprehensive income until such time that the gains and losses become realized and then will be included in the unaudited condensed consolidated statements of operations. Losses from declines in fair value determined to be other than temporary are recorded in the unaudited condensed consolidated statements of operations as a loss on short-term investments. Distributions received as a result of holding these common units are recorded as other income on the unaudited condensed consolidated statements of operations.

For the nine months ended September 30, 2015, the Partnership received and recorded distributions of $3.2 million and recorded losses of $5.8 million as a result of the sale of the Regency Common Units. No distributions or losses were recorded during the three months ended September 30, 2015. As of September 30, 2015, the Partnership held no Regency Common Units.

Impairment of Long-Lived Assets—Management evaluates whether the carrying value of non-oil and natural gas long-lived assets has been impaired when circumstances indicate the carrying value of those assets may not be recoverable. This evaluation is based on undiscounted cash flow projections. The carrying amount is not recoverable if it exceeds the undiscounted sum of cash flows expected to result from the use and eventual disposition of the assets. Management considers various factors when determining if these assets should be evaluated for impairment, including, but not limited to:

• significant adverse changes in legal factors or in the business climate;

• a current-period operating or cash flow loss combined with a history of operating or cash flow losses or a projection or forecast which demonstrates continuing losses associated with the use of a long-lived asset;

• an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of a long-lived asset;

• significant adverse changes in the extent or manner in which an asset is used or in its physical condition;

• a significant change in the market value of an asset; or

• a current expectation that, more likely than not, an asset will be sold or otherwise disposed of before the end of its estimated useful life.

For its oil and natural gas long-lived assets, the Partnership reviews its proved properties at the field level when management determines that events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. Such events include a negative revision or unfavorable projection of future oil and natural gas reserves that will be produced from a field and/or forward prices resulting from this future production, the timing of this future production, future costs to produce the oil and natural gas, and future inflation levels.

7

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

If the carrying value is not recoverable on an undiscounted basis, the impairment loss is measured as the excess of the asset's carrying value over its fair value. Management assesses the fair value of long-lived assets using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales, internally developed discounted cash flow analysis and analysis from outside advisors. Significant changes in market conditions resulting from events such as the condition of an asset or a change in management's intent to utilize the asset would generally require management to reassess the cash flows related to the long-lived assets.

See Note 4 for further discussion on impairment charges.

Revenue Recognition—Revenues associated with sales of natural gas, NGLs, crude oil, condensate and sulfur are recognized when title passes to the customer, which is when the risk of ownership passes to the customer and physical delivery occurs.

Revenues from the Partnership's Midstream Business included the sale of natural gas, NGLs, crude oil, condensate, sulfur and helium and from the compression, gathering, processing, treating and transportation of natural gas. Revenues associated with transportation and processing fees were recognized in the period when the services were provided. These revenues have been classified as discontinued operations within the unaudited condensed consolidated statements of operations.

Natural gas revenues produced from the Partnership's natural gas interests are based on the amount of natural gas sold to purchasers. The volumes of natural gas sold may differ from the volumes to which the Partnership is entitled based on its interests in the properties. Differences between volumes sold and volumes based on entitlements create natural gas imbalances. Imbalances are reflected as adjustments to reported natural gas reserves and future cash flows.  The Partnership had long-term imbalance payables totaling $0.4 million and $0.3 million as of September 30, 2015 and December 31, 2014, respectively.

Derivatives—Authoritative guidance establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. It requires an entity to recognize all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. The guidance provides that normal purchase and sale contracts, when appropriately designated, are not subject to the guidance. Normal purchase and sales are contracts which provide for the purchase or sale of something, other than a financial instrument or derivative instrument, which will be delivered in quantities expected to be used or sold by the reporting entity over a reasonable period in the normal course of business. The Partnership's forward natural gas and crude oil purchase and sales contracts are designated as normal purchases and normal sales. The Partnership uses financial instruments such as swaps, collars and other derivatives to mitigate the risks to cash flows resulting from changes in commodity prices and interest rates. The Partnership recognizes these financial instruments on its unaudited condensed consolidated balance sheet at the instrument's fair value with changes in fair value reflected in the unaudited condensed consolidated statement of operations, as the Partnership has not designated any of these derivative instruments as hedges. The cash flows from derivatives are reported as cash flows from operating activities unless the derivative contract is deemed to contain a financing element. Derivatives deemed to contain a financing element are reported as a financing activity in the unaudited condensed consolidated statement of cash flows. See Note 10 for a description of the Partnership's risk management activities.

Other Reclassifications—Certain prior period financial statement balances have been reclassified to conform to current year presentation. These reclassifications had no effect on the recorded net income.

8

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 3. NEW ACCOUNTING PRONOUNCEMENTS

Discontinued Operations - On April 10, 2014, the Financial Accounting Standards Board ("FASB") issued new guidance which amends the definition of a discontinued operation and requires entities to provide additional disclosures about disposal transactions that do not meet the discontinued operations criteria. Under the new guidance, a discontinued operation is defined as a disposal of a component or group of components that is disposed of or is classified as held for sale and represents a strategic shift that has or will have a major effect on an entity's operations and financial results. The new guidance is effective prospectively for all disposals (except disposals classified as held for sale before the adoption date) or components initially classified as held for sale in periods beginning on or after December 15, 2014, with early adoption permitted. The Partnership decided to early adopt this guidance in relation to the Midstream Business Contribution (see Notes 1 and 16).

Revenue Recognition - On May 28, 2014, the FASB issued new guidance related to revenue from contracts with customers. This new guidance outlines a single comprehensive model for entities to use and supersedes most current revenue recognition guidance, including industry-specific guidance. On July 9, 2015, the FASB agreed to defer this guidance by one year to be effective for annual reporting periods (including interim reporting periods within those periods) beginning after December 15, 2017. Early adoption of the guidance is permitted, but not before the original effective date (annual reporting periods beginning after December 15, 2016). The Partnership is currently evaluating the potential impact, if any, of the adoption of this new guidance on its financial statements.

Going Concern - On August 27, 2014, the FASB issued new guidance on determining how to perform going concern assessments and when to disclose going concern uncertainties in the financial statements. The new guidance requires management to perform interim and annual assessments of an entity's ability to continue as a going concern within one year after the date the financial statements are issued. An entity must provide certain disclosures if conditions or events raise substantial doubt about the entity's ability to continue as a going concern. This guidance is effective for annual periods ending after December 15, 2016, with early adoption permitted. The Partnership is currently evaluating the potential impact, if any, of the adoption of this new guidance on its financial statements.

Consolidation - On February 18, 2015, the FASB issued new guidance which amends the consolidation requirements. The new guidance changes the way entities evaluate consolidation of limited partnerships and other variable interest entities ("VIEs"), fees paid to a decision maker or service provider and variable interests in a VIE held by related parties. The new consolidation guidance is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2015. Early adoption is permitted using either a full retrospective or a modified retrospective adoption approach. The Partnership is currently evaluating the potential impact, if any, of the adoption of this new guidance on its financial statements.

Debt Issuance Costs- On April 7, 2015, the FASB issued new guidance which changes the presentation of debt issuance costs in the financial statements. Under the new guidance, debt issuance costs are presented on the balance sheet as a direct deduction from the related debt liability rather than as an asset. Amortization of the costs is reported as interest expense. The new guidance is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2015. Early adoption is permitted for financial statements that have not been previously issued. The new guidance will be retrospectively applied to all prior periods. The Partnership is currently evaluating the potential impact of the adoption of this new guidance on its financial statements.

9

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 4. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment consisted of the following:

	September 30, 2015			December 31, 2014
	($ in thousands)
Equipment and machinery	$	101		$	101
Vehicles and transportation equipment	212			212
Office equipment, furniture and fixtures	3,020			3,020
Computer equipment	15,023			13,234
Proved properties	891,836			905,622
Unproved properties	6,780			7,512
Work in progress	43			1,195
	917,015			930,896
Less: accumulated depreciation, depletion and amortization	(486,042		)	(442,908		)
Net property, plant and equipment	$	430,973		$	487,988

The following table sets forth the total depreciation, depletion and impairment expense by type of asset within the Partnership's unaudited condensed consolidated statements of operations:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
	($ in thousands)
Depreciation	$	551	$	665	$	1,917	$	2,251
Depletion	$	14,982	$	20,736	$	43,428	$	59,742
Impairment expense:
Proved properties (a)	$	6,969	$	17,305	$	75,313	$	17,305

________________________________

(a) During the three and nine months endedSeptember 30, 2015, the Partnership incurred impairment charges related to certain proved properties in its Mid-Continent, Alabama, East Texas and Permian regions, primarily due to lower commodity prices. During the three and nine months ended September 30, 2014, the Partnership incurred impairment charges related to certain proved properties in our East Texas and Permian regions due to lower commodity prices, higher operating costs and lower well performance.

The table above does not include amounts related to the Partnership's Midstream Business, as these amounts have been classified as part of discontinued operations within the unaudited condensed consolidated statement of operations (see Note 16).

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EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 5. ASSET RETIREMENT OBLIGATIONS

The Partnership recognizes asset retirement obligations associated with the retirement of tangible long-lived assets that result from the acquisition, construction and development of the assets. The Partnership records the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. The Partnership makes estimates of property abandonment costs that, in some cases, will not be incurred until a substantial number of years in the future. Such cost estimates could be subject to significant revisions in subsequent years due to increases in current abandonment costs, changes in regulatory requirements, technological advances and other factors that may be difficult to predict. Although uncertainty about the timing and/or method of settlement may exist and may be conditional upon a future event, the obligation to perform the asset retirement activity is unconditional. Accordingly, the Partnership is required to recognize a liability for the fair value of a conditional asset retirement obligation upon initial recognition if the fair value of the liability can be reasonably estimated. The fair value of additions to the asset retirement obligation is estimated using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of (i) remediation costs, (ii) remaining lives, (iii) future inflation factors and (iv) a credit-adjusted risk free interest rate.

A reconciliation of the Partnership's liability for asset retirement obligations is as follows:

	2015			2014
	($ in thousands)
Asset retirement obligations—January 1 (a)	$	50,873		$	48,564
Additional liabilities	99			29
Liabilities settled	(3,396		)	(1,218		)
Revision to liabilities	106			(105		)
Accretion expense	2,408			2,428
Asset retirement obligations—September 30 (a)	$	50,090		$	49,698

_____________________________________

(a) As of September 30, 2015 and December 31, 2014, $1.7 million and $3.0 million, respectively, were included within accrued liabilities in the unaudited condensed consolidated balance sheets.

The table above does not include the activity related to asset retirement obligations associated with the Partnership's Midstream Business, as these amounts have been classified as discontinued operations within the unaudited condensed consolidated statement of operations (see Note 16).

During the nine months ended September 30, 2015 and 2014, the Partnership made increase revisions of $0.1 million and decrease revisions of $0.1 million, respectively, to certain asset retirement obligations due to changes in the estimated costs to remediate.

NOTE 6. INTANGIBLE ASSETS

Intangible assets consist of rights-of-way and easements, which the Partnership amortizes over the estimated useful life of 20 years.

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EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Intangible assets consisted of the following:

	September 30, 2015			December 31, 2014
	($ in thousands)
Rights-of-way and easements—at cost	$	3,920		$	3,920
Less: accumulated amortization	(995		)	(848		)
Net intangible assets	$	2,925		$	3,072

The following table sets forth amortization expense by type of intangible asset within the Partnership's unaudited condensed consolidated statements of operations:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
	($ in thousands)
Amortization	$	49	$	49	$	147	$	147

The table above does not include amounts related to the Partnership's Midstream Business, as these amounts have been classified as part of discontinued operations within the unaudited condensed consolidated statement of operations (see Note 16).

Estimated future amortization expense related to the intangible assets at September 30, 2015 is as follows (in thousands):

Year ending December 31,
2015	$	49
2016	$	196
2017	$	196
2018	$	196
2019	$	196
Thereafter	$	2,092

NOTE 7. LONG-TERM DEBT

Long-term debt consisted of the following:

	September 30, 2015			December 31, 2014
	($ in thousands)
Revolving credit facility:	$	101,000		$	212,600
Senior Notes:
8.375% Senior Notes due 2019	51,120			51,120
Unamortized bond discount	(319		)	(377		)
Total Senior Notes	50,801			50,743
Total long-term debt	$	151,801		$	263,343

Revolving Credit Facility

On October 10, 2014, the Partnership entered into the Fifth Amendment (the "Fifth Amendment") to its Amended and Restated Credit Agreement (as amended, the "Credit Agreement"). The Fifth Amendment, among other items, provided for

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EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

commitments totaling $320 million, with the ability to increase commitments up to a total aggregate amount of $1.2 billion. The Fifth Amendment coincided with the semi-annual borrowing base redetermination by the Partnership's commercial lenders. The amendment extended the maturity to October 2019. In addition, as a result of the completion of the Midstream Business Contribution, the Partnership's borrowing base under the Credit Agreement is now strictly based on the value of its oil and natural gas properties and its commodity derivative contracts, which was formerly referred to as the upstream component of the borrowing base.

On April 1, 2015, the borrowing base under the Partnership's credit facility decreased from $320 million to $270 million as part of its regularly scheduled semi-annual redetermination by the Partnership's commercial lenders.

As of September 30, 2015, the Partnership had approximately $169.0 million of availability under the credit facility, based on its borrowing base on that date. The Partnership currently pays a 0.375% commitment fee (based on the Partnership's borrowing base utilization percentage) per year on the difference between total commitments and the amount drawn under the credit facility. The Credit Agreement includes a sub-limit for the issuance of standby letters of credit for a total of $50.0 million. As of September 30, 2015, the Partnership had no outstanding letters of credit.

The following table presents the debt covenant levels specified in the Partnership's revolving credit facility and the actual covenant ratios as of September 30, 2015:

	Debt Covenant	Actual Covenant Ratio as of September 30, 2015
Maximum total leverage ratio	4.0	1.4
Minimum current ratio	1.0	4.0

As of September 30, 2015, the Partnership was in compliance with the financial covenants under the Credit Agreement.

8.375 % Senior Notes due 2019 (the "Senior Notes")

Following the Midstream Business Contribution, $51.1 million of the Senior Notes remain outstanding under an amended indenture with substantially all of the restrictive covenants and certain events of default eliminated.

NOTE 8. MEMBERS’ EQUITY

At September 30, 2015 and December 31, 2014, there were 149,563,456 and 150,154,909 unrestricted common units outstanding, respectively. In addition, there were 3,423,262 and 2,419,750 unvested restricted common units outstanding at September 30, 2015 and December 31, 2014, respectively.

On May 31, 2012, the Partnership announced a program through which it may issue common units, from time to time, with an aggregate market value of up to $100 million. The Partnership is under no obligation to issue equity under the program and the Partnership has not issued common units under this program since 2013.

On October 27, 2014, the Partnership announced a common unit repurchase program of up to $100 million through which the Partnership may, at its discretion, repurchase outstanding common units from time to time at prevailing prices on the open market or in privately negotiated transactions. The program commenced following the filing of the Partnership's Quarterly Report on Form 10-Q for the quarter ended September 30, 2014 and will conclude by March 31, 2016. The repurchase program does not obligate the Partnership to acquire any, or any specific number of, units and may be discontinued at any time. The

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EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Partnership intends to cancel any units it repurchases under the repurchase program. During the nine months ended September 30, 2015, 1,171,584 units were repurchased under this program for approximately $2.6 million.

The table below summarizes the distributions paid or payable and declared for the quarters listed below:

Quarter Ended	Distribution per Common Unit		Record Date*	Payment Date
December 31, 2014+	$	0.0700	February 6, 2015	February 13, 2015
March 31, 2015+	$	0.0700	May 8, 2015	May 15, 2015
June 30, 2015+	$	0.0700	August 6, 2015	August 14, 2015
September 30, 2015**	$	0.0467	October 5, 2015	October 15, 2015

_____________________________

+ The distribution excludes certain restricted units under the LTIP (as defined in Note 14 below).

* Means the close of business on each of the listed Record Dates.

** Represents a prorated third quarter 2015 distribution for the months of July and August.

NOTE 9. RELATED PARTY TRANSACTIONS

The following table summarizes transactions between the Partnership and certain affiliated entities:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
Affiliates of Natural Gas Partners:	($ in thousands)
Natural gas purchases from affiliates	$	—	$	—	$	—	$	2,091

The transactions above were all related to the Partnership's Midstream Business and have been classified as part of discontinued operations within the unaudited condensed consolidated statement of operations (see Note 16).

NOTE 10. RISK MANAGEMENT ACTIVITIES

Interest Rate Swap Derivative Instruments

To mitigate its interest rate risk, the Partnership enters into various interest rate swaps. These swaps convert the variable-rate term loan into a fixed-rate obligation. The purpose of entering into these swaps is to eliminate interest rate variability by converting LIBOR-based variable-rate payments to fixed-rate payments. Amounts received or paid under these swaps were recorded as reductions or increases in interest expense.

For accounting purposes, the Partnership has not designated any of its interest rate derivative instruments as hedges; instead it marks these derivative contracts to fair value (see Note 11).  Changes in fair values of the interest rate derivative instruments are recorded as an adjustment to the mark-to-market gains (losses) on risk management transactions within other income (expense).

The following table sets forth certain information regarding the Partnership's interest rate swaps as of September 30, 2015:

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EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Effective Date	Expiration Date	Notional Amount		Fixed Rate
12/31/2014	12/31/2019	$	175,000,000	2.3195	%

Commodity Derivative Instruments

The prices of crude oil, natural gas and NGLs are subject to fluctuations in response to changes in supply, demand, market uncertainty and a variety of additional factors which are beyond the Partnership's control.  These risks can cause significant changes in the Partnership's cash flows and affect its ability to achieve its distribution objectives and comply with the covenants of its Credit Agreement.  In order to manage the risks associated with changes in the future prices of crude oil, natural gas and NGLs on its forecasted equity production, the Partnership engages in risk management activities that take the form of commodity derivative instruments.  The Partnership has determined that it is necessary to hedge a substantial portion of its expected production in order to meaningfully reduce its future cash flow volatility.  The Partnership generally limits its hedging levels to less than its total expected future production. While hedging at this level of production does not eliminate all of the volatility in the Partnership's cash flows, it allows the Partnership to mitigate the risk of situations where a modest loss of production would not put it in an over-hedged position.  At times, the Partnership may enter into or assume (in connection with acquisitions) hedges with strike prices above current future prices or resetting existing hedges to higher price levels in order to meet its cash flow objectives.   In addition, the Partnership may also terminate or unwind hedges or portions of hedges when the expected future volumes do not support the level of hedges.  Expected future production is derived from the proved reserves, adjusted for certain price-dependent expenses and revenue deductions. The Partnership applies the appropriate contract terms to these projections to determine its expected future equity share of the commodities.

The Partnership uses fixed-price swaps, costless collars and put options to achieve its hedging objectives. Historically, the Partnership has hedged its expected future commodity volumes either with derivatives of the same commodity ("direct hedges") or with derivatives of another commodity which the Partnership expects will correlate well with the underlying commodity ("proxy hedges").  For example, the Partnership has often hedged the changes in future NGL prices using crude oil hedges because NGL prices have been highly correlated to crude oil prices and hedging NGLs directly is usually less attractive due to the relative illiquidity in the NGL forward market.  The Partnership may use natural gas hedges to hedge a portion of its expected future ethane production because forward prices for ethane are often heavily discounted from its current prices. Also, natural gas prices provide support for ethane prices because in many processing plants ethane can be recombined with the residue gas stream and sold as natural gas.  When the Partnership uses proxy hedges, it converts the expected volumes of the underlying commodity to equivalent volumes of the hedged commodity.

For accounting purposes, the Partnership has not designated any of its commodity derivative instruments as hedges; instead it marks these derivative contracts to fair value (see Note 11).  Changes in fair values of the commodity derivative instruments are recorded as an adjustment to the mark-to-market gains (losses) on risk management transactions within revenue.

By using derivative instruments to economically hedge exposure to changes in commodity prices, the Partnership exposes itself to counterparty credit risk. Historically, the Partnership's counterparties have all been participants or affiliates of participants within its Credit Agreement (see Note 7), which is secured by substantially all of the assets of the Partnership. Therefore, the Partnership is not currently required to post any collateral, nor does it require collateral from its counterparties. The Partnership minimizes the credit risk in derivative instruments by limiting exposure to any single counterparty and monitoring the creditworthiness of its counterparties on an ongoing basis. In addition, the Partnership's derivative contracts for certain counterparties are subject to counterparty netting agreements governing such derivatives, and when possible, the Partnership nets the open positions of each counterparty. See Note 11 for the impact to the Partnership's unaudited condensed consolidated balance sheets of the netting of these derivative contracts.

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EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following tables set forth certain information regarding the Partnership's commodity derivatives. Within the table, some trades of the same commodities with the same tenors have been aggregated and shown as weighted averages.

Commodity derivatives, as of September 30, 2015, that will mature through 2019:

Underlying	Type	Notional Volumes (units) (a)	Floor Strike Price ($/unit)(b)		Cap Strike Price ($/unit)(b)
Portion of Contracts Maturing in 2015
Natural Gas	Swap (Pay Floating/Receive Fixed)	2,700,000	$	4.07
Crude Oil	Costless Collar	120,000	$	90.00	$	97.55
Crude Oil	Swap (Pay Floating/Receive Fixed)	157,500	$	89.78
IsoButane	Swap (Pay Floating/Receive Fixed)	748,440	$	0.69
Natural Gasoline	Swap (Pay Floating/Receive Fixed)	894,600	$	1.21
Normal Butane	Swap (Pay Floating/Receive Fixed)	1,423,800	$	0.68
Propane	Swap (Pay Floating/Receive Fixed)	3,540,600	$	0.57
Contracts Maturing in 2016
Natural Gas	Swap (Pay Floating/Receive Fixed)	9,480,000	$	4.25
Crude Oil	Swap (Pay Floating/Receive Fixed)	936,000	$	84.66
Crude Oil (c)	Basis Swap	91,500	$	1.20
IsoButane	Swap (Pay Floating/Receive Fixed)	1,713,600	$	0.72
Natural Gas	Swap (Pay Floating/Receive Fixed)	1,864,800	$	1.31
Normal Butane	Swap (Pay Floating/Receive Fixed)	3,074,400	$	0.72
Propane	Swap (Pay Floating/Receive Fixed)	7,610,400	$	0.61
Contracts Maturing in 2017
Crude Oil	Swap (Pay Floating/Receive Fixed)	444,000	$	89.24
Natural Gas	Swap (Pay Floating/Receive Fixed)	2,040,000	$	3.34
Contracts Maturing in 2018
Crude Oil	Swap (Pay Floating/Receive Fixed)	396,000	$	88.78
Contracts Maturing in 2019
Crude Oil	Swap (Pay Floating/Receive Fixed)	348,000	$	88.39

_______________________

(a) Volumes of natural gas are measured in MMbtu, volumes of crude oil are measured in barrels and volumes of NGLs are measured in gallons.

(b) Amounts represent the weighted average price. The weighted average prices are in $/MMbtu for natural gas, $/barrel for crude oil and $/gallon for NGLs.

(c) Floor price represents the spread between Argus-Midland oil prices and NYMEX-WTI oil prices.

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EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Fair Value of Interest Rate and Commodity Derivatives

The following tables set forth the fair values of interest rate and commodity derivative instruments not designated as hedging instruments and their location within the unaudited condensed consolidated balance sheet as of September 30, 2015 and December 31, 2014:

	As of September 30, 2015
	Derivative Assets				Derivative Liabilities
	Balance Sheet Classification	Fair Value			Balance Sheet Classification	Fair Value
	($ in thousands)
Interest rate derivatives - liabilities	Current assets	$	(3,347	)	Current liabilities	$	—
Interest rate derivatives - liabilities	Long-term assets	(5,351		)	Long-term liabilities	—
Commodity derivatives - assets	Current assets	54,147			Current liabilities	—
Commodity derivatives - assets	Long-term assets	49,817			Long-term liabilities	—
Commodity derivatives - liabilities	Current assets	(75		)	Current liabilities	—
Commodity derivatives - liabilities	Long-term assets	(29		)	Long-term liabilities	—
Total derivatives		$	95,162			$	—
	As of December 31, 2014
	Derivative Assets				Derivative Liabilities
	Balance Sheet Classification	Fair Value			Balance Sheet Classification	Fair Value
	($ in thousands)
Interest rate derivatives - liabilities	Current assets	$	(3,165	)	Current liabilities	$	—
Interest rate derivatives - liabilities	Long-term assets	(2,641		)	Long-term liabilities	—
Commodity derivatives - assets	Current assets	47,971			Current liabilities	—
Commodity derivatives - assets	Long-term assets	49,130			Long-term liabilities	—
Total derivatives		$	91,295			$	—

The following table sets forth the location of gains and losses for derivatives not designated as hedging instruments within the Partnership's unaudited condensed consolidated statement of operations:

Amount of Gain (Loss) Recognized in Income on Derivatives		Three Months Ended September 30,						Nine Months Ended September 30,
		2015			2014			2015			2014
		($ in thousands)
Interest rate derivatives	Interest rate risk management losses, net	$	(3,626	)	$	(81	)	$	(5,728	)	$	(942	)
Commodity derivatives	Commodity risk management gains (losses), net	39,849			27,967			50,914			(147		)
Commodity derivatives	Discontinued operations	—			—			—			(15,879		)
Commodity derivatives - trading	Discontinued operations	—			—			—			(2,404		)
	Total	$	36,223		$	27,886		$	45,186		$	(19,372	)

NOTE 11. FAIR VALUE OF FINANCIAL INSTRUMENTS

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). The Partnership utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk inherent in the inputs to the valuation technique. The authoritative guidance establishes a fair value hierarchy that 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).

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EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The three levels of the fair value hierarchy are as follows:

Level 1 – Quoted prices are available in active markets for identical assets and liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide information on an ongoing basis.

Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the market place throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management's best estimate of fair value.

As of September 30, 2015, the Partnership has recorded its interest rate swaps and commodity derivative instruments (see Note 10), which includes crude oil, natural gas and NGLs, at fair value. The Partnership reviews the classification of the inputs at the end of each period and, following such review for the period ended September 30, 2015, classified the inputs to measure the fair value of its interest rate swaps, crude oil derivatives, NGL derivatives and natural gas derivatives as Level 2.  In addition, the Partnership recorded its investments in equity securities at fair value, and classified the inputs as Level 1.

The following tables disclose the fair value of the Partnership's derivative instruments and equity investments as of September 30, 2015 and December 31, 2014: 

	As of September 30, 2015
	Level 1		Level 2			Level 3		Netting (a)			Total
	($ in thousands)
Assets:
Crude oil derivatives	$	—	$	82,810		$	—	$	(104	)	$	82,706
Natural gas derivatives	—		18,242			—		—			18,242
NGL derivatives	—		2,912			—		—			2,912
Interest rate swaps	—		—			—		(8,698		)	(8,698		)
Total	$	—	$	103,964		$	—	$	(8,802	)	$	95,162
Liabilities:
Crude oil derivatives	$	—	$	(104	)	$	—	$	104		$	—
Natural gas derivatives	—		—			—		—			—
NGL derivatives	—		—			—		—			—
Interest rate swaps	—		(8,698		)	—		8,698			—
Total	$	—	$	(8,802	)	$	—	$	8,802		$	—

____________________________

(a) Represents counterparty netting under the agreement governing such derivative contracts.

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EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

	As of December 31, 2014
	Level 1		Level 2			Level 3		Netting (a)			Total
	($ in thousands)
Assets:
Crude oil derivatives	$	—	$	78,516		$	—	$	—		$	78,516
Natural gas derivatives	—		18,585			—		—			18,585
Interest rate swaps	—		—			—		(5,806		)	(5,806		)
Equity investments	153,448		—			—		—			153,448
Total	$	153,448	$	97,101		$	—	$	(5,806	)	$	244,743
Liabilities:
Interest rate swaps	$	—	$	(5,806	)	$	—	$	5,806		$	—
Total	$	—	$	(5,806	)	$	—	$	5,806		$	—

____________________________

(a) Represents counterparty netting under the agreement governing such derivative contracts.

Gains and losses from continuing operations related to the interest rate derivatives are recorded as part of interest rate risk management gains and losses in the unaudited condensed consolidated statements of operations.  Gains and losses from continuing operations related to the Partnership's commodity derivatives are recorded as a component of revenue in the unaudited condensed consolidated statements of operations.

Fair Value of Assets and Liabilities Measured on a Non-recurring Basis

For periods in which impairment charges have been incurred, the Partnership is required to write down the value of the impaired asset to its fair value. See Note 4 for a further discussion of the impairment charges recorded during the three and nine months ended September 30, 2015. The following table discloses the fair value of the Partnership's assets measured at fair value on a nonrecurring basis during the nine months ended September 30, 2015:

	Nine Months Ended September 30,
	2015		Level 1		Level 2		Level 3		Total Losses
	($ in thousands)
Proved properties	$	49,840	$	—	$	—	$	49,840	$	75,313

The Partnership calculated the fair value of the impaired assets using a discounted cash flow analysis to determine the excess of the asset's carrying value over its fair value. Significant inputs to the valuation of fair value of the proved properties, plant, pipeline and intangible assets includes estimates of (i) future cash flows, including revenue, expenses and capital expenditures, (ii) timing of cash flows, (iii) forward commodity prices, adjusted for estimate location differentials and (iv) a discount rate reflective of our cost of capital.

The carrying amounts of cash equivalents, accounts receivable and accounts payable are believed to approximate their fair values because of the short-term nature of these instruments.

As of September 30, 2015, the outstanding debt associated with the Credit Agreement bore interest at a floating rate; as such, the Partnership believes that the carrying value of this debt approximates its fair value. The Senior Notes bore interest at a fixed rate; based on the market price of the Senior Notes as of September 30, 2015 and December 31, 2014, the Partnership estimates that the fair value of the Senior Notes was $33.7 million and $47.0 million, respectively. Fair value of the Senior Notes was estimated based on prices quoted from third-party financial institutions, which are characteristic of Level 2 fair value measurement inputs.

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EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 12. COMMITMENTS AND CONTINGENCIES

Litigation—The Partnership and its operating subsidiaries are subject to lawsuits which arise from time to time in the ordinary course of business. The Partnership had no accruals as of September 30, 2015 or December 31, 2014 related to legal matters and current lawsuits are not expected to have a material adverse effect on the Partnership's financial position, results of operations or cash flows.

In May and June 2015, alleged Eagle Rock Energy unitholders filed two derivative and class action lawsuits in the District Court of Harris County, Texas (the "state lawsuits"). An additional class action lawsuit was filed in June by another alleged Eagle Rock Energy unitholder in the United States District Court for the Southern District of Texas (the "federal lawsuit" and, together with the state lawsuits, the "lawsuits"). The federal lawsuit names Eagle Rock Energy, Eagle Rock Energy GP, L.P., our general partner, our board of directors, Vanguard, and Talon Merger Sub, LLC, a wholly owned indirect subsidiary of Vanguard, as defendants. The federal lawsuit alleges a variety of causes of action challenging the Merger, including alleged breaches of fiduciary or contractual duties and alleged aiding and abetting these alleged breaches of duty. The federal lawsuit alleges that the Merger (a) provided inadequate consideration to our unitholders, (b) was not subject to minority unitholder approval due to the voting and support agreement between Vanguard, Natural Gas Partners VIII, L.P., and certain of its affiliates, and (c) contained contractual terms (e.g., the no-solicitation, matching rights, and termination fee provisions) that may have dissuaded other potential merger partners from making alternative proposals. The federal lawsuit also alleges that defendants have violated Section 14(a) of the Securities Exchange Act of 1934 and Rule 14a-9 promulgated thereunder. In general, the federal lawsuit alleges that the registration statement filed in connection with the Merger failed, among other things, to disclose allegedly material details concerning (a) Eagle Rock’s and Vanguard’s financial and operational projections, (b) the analyses of the Merger conducted by Eagle Rock’s and Vanguard’s financial advisors, and (c) the background of the Merger. Based on these allegations, the federal lawsuit seeks to have the Merger rescinded. The federal lawsuit also seeks monetary damages and attorneys' fees. On November 11, 2015, the state lawsuits were voluntarily dismissed without prejudice. Prior to their dismissal, the state lawsuits alleged similar claims against the same defendants as the federal lawsuit, except that the state lawsuits did not allege claims under Section 14(a) of the Securities Exchange Act of 1934 or Rule 14a-9 promulgated thereunder. The Partnership believes that the lawsuits are without merit.

On October 29, 2015, a wholly owned subsidiary of the Partnership received written letters from EPA Region 4 (“EPA”) of a proposed civil penalty under the Risk Management Program (“RMP”), 40 CFR Part 68, Clean Air Act §112(r)(7), and the Emergency Planning and Community Right-to-Know Act (EPCRA), EPCRA Section 312, 42 U.S.C. § 11022, concerning alleged violations at the Big Escambia Creek Gas Plant, a gas processing facility in Atmore, Alabama (the “Big Escambia Creek facility”). A contractor inspected the Big Escambia Creek facility in April 2014 on behalf of EPA, and EPA identified certain potential violations under the RMP and EPCRA.  EPA proposed a penalty of approximately $116,625 combined ($90,300 for RMP and $26,325 for EPCRA). The wholly owned subsidiary of the Partnership has timely sought clarification from the EPA on EPCRA reporting and also requested lower penalties. EPA granted the extension of responding to the letters while they are still in the process of responding to the requests of the wholly owned subsidiary of the Partnership. The wholly owned subsidiary of the Partnership will respond to these two letters promptly upon receiving clarification on EPCRA reporting and a decision on penalty reduction from EPA.

Insurance—The Partnership covers its operations and assets with insurance which management believes is consistent with that in force for other companies engaged in similar commercial operations with similar type properties.  This insurance includes: (1) commercial general liability insurance covering liabilities to third parties for bodily injury, property damage and pollution arising out of the Partnership's operations; (2) workers’ compensation liability coverage for employees to required statutory limits; (3) automobile liability insurance covering liability to third parties for bodily injury and property damage arising out of the operation of all owned, hired and non-owned vehicles by its employees on company business; (4) property

20

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

insurance covering the replacement cost of all owned real and personal property, including coverage for losses due to boiler and machinery breakdown, earthquake, flood and consequent business interruption/extra expense; (5) control of well/operator's extra expense insurance for operated and non-operated wells; and (6) corporate liability insurance, including coverage for directors and officers and employment practices liabilities.  In addition, the Partnership maintains excess liability insurance providing limits in excess of the established primary limits for commercial general liability and automobile liability insurance.

All coverages are subject to industry accepted policy terms, conditions, limits and deductibles comparable to that obtained by other energy companies with similar operations. The cost of insurance for the energy industry continued to fluctuate over the past year, reflecting the changing conditions in the insurance markets.

Environmental—The Partnership's business involves acquiring, developing and producing oil and natural gas working interests, and certain associated gathering and processing activities for our interests in Alabama. The Partnership's operations and those of the Partnership's lease operators are subject to stringent and complex federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection or safety. The Partnership must comply with United States laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste management and disposal and other environmental matters. The cost of developing and producing our oil and natural gas working interests as well as planning, designing and operating our associated processing facility in Alabama, must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements and the issuance of injunctions or restrictions on operation. Management believes that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on the Partnership's combined results of operations, financial position or cash flows. At September 30, 2015 and December 31, 2014, the Partnership had accrued approximately $2.6 million and $2.8 million, respectively, for environmental matters.

Retained Revenue Interest—Certain of the Partnership's assets are subject to retained revenue interests.  These interests were established under purchase and sale agreements that were executed by the Partnership's predecessors in title.  The terms of these agreements entitle the owners of the retained revenue interests to a portion of the revenues received from the sale of the hydrocarbons above specified base oil and natural gas prices.  These retained revenue interests do not represent a real property interest in the hydrocarbons.  The Partnership's reported revenues are reduced to account for the retained revenue interests on a monthly basis.

The retained revenue interests affect the Partnership's interest in the Big Escambia Creek, Flomaton and Fanny Church fields in Escambia County, Alabama. With respect to the Partnership's Flomaton and Fanny Church fields, these retained revenue interests are in effect for any calendar year in which the Partnership surpasses certain average net production rates. The Partnership did not surpass such rates in 2014 and does not anticipate exceeding these rates in future years. With respect to the Partnership's Big Escambia Creek field, the retained revenue interest commenced in 2010 and continues through the end of 2019.

Other Commitments—The Partnership utilizes assets under operating leases for its corporate office, certain rights-of-way and facilities locations, vehicles and in several areas of its operations. Rental expense from continuing operations, including leases with no continuing commitment, amounted to approximately $0.3 million, $1.1 million and $0.4 million, $2.0 million, respectively, for the three and nine months ended September 30, 2015 and 2014, respectively. Rental expense for leases with escalation clauses is recognized on a straight-line basis over the initial lease term.

NOTE 13. INCOME TAXES

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EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Provision for Income Taxes -The Partnership is a limited partnership for federal and state income tax purposes, in which income tax liabilities and/or benefits of the Partnership are passed through to its unitholders. In the State of Texas, limited partnerships are directly subject to the Texas margin tax, which liability is not passed through to the Partnership's unitholders. In addition, certain of the Partnership's subsidiaries are Subchapter C-corporations subject to federal and state income taxes. During the three and nine months ended September 30, 2015 and September 30, 2014, the Partnership recognized an income tax benefit of $1.0 million, $2.5 million, $0.9 million and $2.6 million, respectively. The change in the Partnership's tax benefit from period to period is primarily due to changes in income generated by the Partnership's taxable entities.

NOTE 14. EQUITY-BASED COMPENSATION

Long-Term Incentive Plan

Eagle Rock Energy G&P, LLC has a long-term incentive plan (as amended, the "LTIP"), for its employees, directors and consultants who provide services to the Partnership and its subsidiaries and affiliates. The LTIP provides for the issuance of an aggregate of up to 14,500,000 common units to be granted either as options, restricted units or phantom units, of which, as of September 30, 2015, a total of 3,394,477 common units remained available for issuance (which calculation reserves the maximum common units (i.e., 200%) that may potentially be earned and vested in respect of the outstanding performance units). Grants under the LTIP are made at the discretion of the board and to date have been made in the form of restricted units and performance units (i.e., phantom units subject to performance conditions). Distributions declared and paid on outstanding restricted units, where such restricted units are eligible to receive distributions, are paid directly to the holders of the restricted units. With respect to the performance units (as described below), distributions declared and paid will be grossed-up by an additional number of performance units as determined in the performance unit agreement. No options have been issued to date.

Restricted Units

Grants of restricted units eligible to receive distributions are valued at the market price as of the date issued, while grants of restricted units not eligible to receive distributions are valued at the market price as of the date issued less the present value of the expected distribution stream over the vesting period using the risk-free interest rate. The awards generally vest over three years on the basis of one-third of the award vesting each year.

The Partnership recognizes compensation expense on a straight-line basis over the requisite service period for the restricted unit grants. During the restriction period, distributions associated with the grants of restricted units eligible to receive distributions are distributed to the awardees.

A summary of the changes in outstanding restricted common units for the nine months ended September 30, 2015 is provided below:

	Number of Restricted Units		Weighted Average Fair Value
Outstanding at December 31, 2014	2,419,750		$	6.06
Granted	2,116,034		$	2.54
Vested	(754,010	)	$	7.05
Forfeited	(358,512	)	$	6.30
Outstanding at September 30, 2015	3,423,262		$	3.64

Performance Units

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EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Performance units are described in the LTIP as phantom units subject to restrictions that lapse based on the performance of the Partnership, as measured by total unitholder return in comparison to a peer group of upstream master limited partnerships and a continued service requirement that spans a three-year period.

The performance units represent hypothetical common units of the Partnership and therefore do not carry any of the rights and privileges (including voting privileges) associated with actual common units. Performance units settle in common units rather than cash. The fair value of the performance units is estimated using a Monte Carlo simulation at the grant date. The Partnership recognizes compensation expense for the performance unit grants over the three-year vesting period.

The amount of performance units subject to an award that vests will be determined on each vesting date based on a two-step approach. The right to receive actual common units in settlement of the performance units depends first on the relative level of total unitholder return attained by the Partnership over the applicable performance period (for grants made prior to April 21, 2015, generally July 1, 2014 through June 30, 2016, and for grants made on or after April 21, 2015, generally a specified three-year period), as measured against the Partnership's peer group. The number of units that may be earned will either be 0% of the target performance units subject to the award for performance at anything less than the 50th percentile of the peer group, or in the range of 70% to 200% of the target performance units subject to the award for performance from the 50th percentile to the 100th percentile of the peer group over the performance period. Second, the right to receive actual common units with respect to the earned performance units depends on the satisfaction of a continued service requirement, which, for grants made prior to April 21, 2015, is generally continued service through June 30, 2016 for two-thirds of the performance units and through June 30, 2017 for the remaining one-third of the performance units, and for grants made on or after April 21, 2015, is generally aligned with the applicable performance period.

In the event the Partnership pays any distributions in respect of its outstanding units, the target performance units and any earned performance units will be grossed-up to reflect such distribution by an additional number of target performance units or earned performance units, as applicable. Any target performance units that do not become earned performance units or any earned performance units for which the continued service requirement is not satisfied shall terminate, expire and otherwise be forfeited by the awardee on the last day of the applicable performance period. Any earned performance units that vest (based on fulfillment of the continued service requirement) shall be settled in actual common units.

A summary of the changes in outstanding performance units for the nine months ended September 30, 2015 is provided below:

	Number of Performance Units		Weighted Average Fair Value
Outstanding at December 31, 2014	647,788		$	3.63
Granted	871,931		$	2.61
Forfeited	(123,175	)	$	3.59
Outstanding at September 30, 2015	1,396,544		$	3.00

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EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Equity-Based Compensation

For the three and nine months ended September 30, 2015 and September 30, 2014, the Partnership recorded non-cash compensation expense of approximately $1.7 million, $4.7 million and $2.9 million, $7.0 million, respectively, related to the granted restricted units and performance units as general and administrative expense on the unaudited condensed consolidated statements of operations.

As of September 30, 2015, unrecognized compensation costs related to the outstanding restricted units and performance units under the LTIP totaled approximately $11.7 million. The remaining expense is to be recognized over a weighted average of 2.08 years. At the close of the Merger all of the outstanding unvested restricted units and performance units either vested immediately or were converted to Vanguard restricted units under the Vanguard Long Term Incentive Plan and will be fully vested by May 2016.

In connection with the vesting of certain restricted units during the three months ended September 30, 2015, the Partnership cancelled 173,879 of the newly-vested common units in satisfaction of $0.4 million of minimum employee tax liability paid by the Partnership. Pursuant to the terms of the LTIP, these cancelled units are available for future grants under the LTIP.

24

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 15. EARNINGS PER UNIT

Basic earnings per unit is computed by dividing the net income (loss) by the weighted average number of units outstanding during a period. To determine net income (loss) allocated to each class of ownership (common and restricted common units), the Partnership first allocates net income (loss) in accordance with the amount of distributions made for the quarter by each class, if any. The remaining net income is allocated to each class in proportion to the class weighted average number of units outstanding for a period as compared to the weighted average number of units for all classes for the period, with the exception of net losses. Net losses are allocated to just the common units.

As of September 30, 2015 and 2014, the Partnership had unvested restricted common units outstanding, which are considered dilutive securities. These units are considered in the diluted weighted average common units outstanding number in periods of net income. In periods of net losses, these units are excluded from the diluted weighted average common units outstanding number.

The majority of the restricted units granted under the LTIP, as discussed in Note 14, contain non-forfeitable rights to the distributions declared by the Partnership and therefore meet the definition of participating securities. Participating securities are required to be included in the computation of earnings per unit pursuant to the two-class method. Restricted units granted in 2013 to certain senior executives and members of the board of directors are not eligible to receive the distributions declared by the Partnership and therefore do not meet the definition of participating securities.

The following table presents the Partnership's calculation of basic and diluted units outstanding for the periods indicated:

	Three Months Ended September 30,		Nine Months Ended September 30,
	2015	2014	2015	2014
	(in thousands)
Weighted average units outstanding during period:
Common units - Basic	149,563	157,375	149,337	156,995
Effect of Dilutive Securities:
Restricted Units (non-participating securities)	—	63	—	35
Restricted Units (participating securities)	—	962	—	594
Common units - Diluted	149,563	158,400	149,337	157,624

For the three and nine months ended September 30, 2014, the Partnership determined that it was more dilutive to apply the two-class method versus the treasury stock method in calculating dilutive earnings per unit. Thus, the unvested restricted common units are included in the computation of the diluted weighted average common units outstanding, but the denominator in the computation of diluted earnings per unit only includes the basic weighted average common units and restricted units (non-participating securities) outstanding.

25

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table presents the Partnership's basic and diluted loss per unit for the three months ended September 30, 2015:

	Total			Common Units			Restricted Common Units*
	($ in thousands, except for per unit amounts)
Loss from continuing operations	$	17,924
Distributions	7,138			$	6,985		$	153
Assumed loss from continuing operations after distribution to be allocated	10,786			10,786			—
Assumed allocation of loss from continuing operations	17,924			17,771			153
Discontinued operations	(27		)	(27		)	—
Assumed net loss to be allocated	$	17,897		$	17,744		$	153
Basic loss from continuing operations per unit				$	0.12
Basic discontinued operations per unit				$	—
Basic loss per unit				$	0.12
Diluted loss from continuing operations per unit				$	0.12
Diluted discontinued operations per unit				$	—
Diluted loss per unit				$	0.12

_____________________________

* Restricted common units granted under the LTIP that contain non-forfeitable rights to the distributions declared by the Partnership.

The following table presents the Partnership's basic and diluted loss per unit for the three months ended September 30, 2014:

	Total		Common Units		Restricted Common Units*
	($ in thousands, except for per unit amounts)
Income from continuing operations	$	17,231
Distributions	11,183		$	11,018	$	165
Assumed income from continuing operations after distribution to be allocated	6,048		5,967		81
Assumed allocation of income from continuing operations	17,231		16,985		246
Discontinued operations	249,057		245,701		3,356
Assumed net income to be allocated	$	266,288	$	262,686	$	3,602
Basic income from continuing operations per unit			$	0.11
Basic discontinued operations per unit			$	1.56
Basic income per unit			$	1.67
Diluted income from continuing operations per unit			$	0.11
Diluted discontinued operations per unit			$	1.56
Diluted income per unit			$	1.67

_____________________________

* Restricted common units granted under the LTIP that contain non-forfeitable rights to the distributions declared by the Partnership.

26

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table presents the Partnership's basic and diluted loss per unit for the nine months ended September 30, 2015:

	Total			Common Units			Restricted Common Units*
	($ in thousands, except for per unit amounts)
Loss from continuing operations	$	(63,195	)
Distributions	28,394			$	27,886		$	508
Assumed loss from continuing operations after distribution to be allocated	(91,589		)	(91,589		)	—
Assumed allocation of loss from continuing operations	(63,195		)	(63,703		)	508
Discontinued operations, net of tax	(1,001		)	(1,001		)	—
Assumed net loss to be allocated	$	(64,196	)	$	(64,704	)	$	508
Basic loss from continuing operations per unit				$	(0.42	)
Basic discontinued operations per unit				$	(0.01	)
Basic loss per unit				$	(0.43	)
Diluted loss from continuing operations per unit				$	(0.42	)
Diluted discontinued operations per unit				$	(0.01	)
Diluted loss per unit				$	(0.43	)

_____________________________

* Restricted common units granted under the LTIP that contain non-forfeitable rights to the distributions declared by the Partnership.

The following table presents the Partnership's basic and diluted loss per unit for the nine months ended September 30, 2014:

	Total			Common Units			Restricted Common Units*
	($ in thousands, except for per unit amounts)
Loss from continuing operations	$	(8,124	)
Distributions	11,183			$	11,018		$	165
Assumed loss from continuing operations after distribution to be allocated	(19,307		)	(19,307		)	—
Assumed allocation of loss from continuing operations	(8,124		)	(8,289		)	165
Discontinued operations, net of tax	212,808			210,199			2,609
Assumed net income to be allocated	$	204,684		$	201,910		$	2,774
Basic loss from continuing operations per unit				$	(0.05	)
Basic discontinued operations per unit				$	1.34
Basic income per unit				$	1.29
Diluted loss from continuing operations per unit				$	(0.05	)
Diluted discontinued operations per unit				$	1.34
Diluted income per unit				$	1.29

_____________________________

* Restricted common units granted under the LTIP that contain non-forfeitable rights to the distributions declared by the Partnership.

27

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 16. DIVESTITURE RELATED ACTIVITIES

As discussed in Note 1, on July 1, 2014, the Partnership completed the Midstream Business Contribution. As a result of this transaction, the operations of the Midstream Business have been classified as discontinued.

The following table is the reconciliation of major classes of line items classified as discontinued operations for the Midstream Business for the three and nine months ended September 30, 2015 and 2014:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
							($ in thousands)
Class of statement of operations line item of discontinued operations:
Revenue	$	—		$	4,493		$	—		$	552,574
Cost of natural gas, NGLs, condensate and helium	—			2,846			—			447,519
Operations, maintenance and taxes other than income	—			27			—			50,154
General and administrative	27			4,055			1,001			18,044
Depreciation, amortization and impairment	—			—			—			41,936
Interest expense	—			—			—			(27,350		)
Other expense	—			—			—			(68		)
Operating loss from discontinued operations before taxes	(27		)	(2,435		)	(1,001		)	(32,497		)
Gain on sale of assets	—			249,856			—			243,637
Income tax benefit	—			(1,636		)	—			(1,668		)
Discontinued operations, net of tax	$	(27	)	$	249,057		$	(1,001	)	$	212,808

Allocation of Interest Expense

Per accounting guidance provided by the FASB related to discontinued operations, interest on debt that is to be assumed by the buyer and interest on debt that is required to be repaid as a result of a disposal transaction should be allocated to discontinued operations. Per the Partnership's Credit Agreement, as a result of the Midstream Business Contribution, the Partnership is required to pay down outstanding debt to the amount of the upstream portion of the borrowing base. Thus, interest expense in the table above includes the interest expense related to the portion of the Partnership's unsecured Senior Notes exchanged for Regency unsecured senior notes on July 1, 2014 and interest related to the difference between the total amount outstanding under the Credit Agreement and the upstream portion of the borrowing base for periods prior to July 1, 2014.

Restructuring Activities

In connection with the Midstream Business Contribution, the Partnership incurred one-time employee termination benefits and lease payments of the partial abandonment of an operating lease during the year ended December 31, 2014. The accruals are recorded as part of accrued liabilities within the unaudited condensed consolidated balance sheets, while the expenses are recorded as part of discontinued operations within the unaudited condensed consolidated statement of operations. During the nine months ended September 30, 2015, the Partnership adjusted its accrual related to the lease payments of the partial abandonment of an operating lease to account for the softening of the sublease market. The following table summarizes activity related to liabilities associated with the Partnership's restructuring activities during the nine months ended September 30, 2015.

28

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

	Employee Related Costs			Facility and Other Costs		Total
	($ in thousands)
Balance at December 31, 2014	$	835		$	490	$	1,325
Payments and other adjustments, net	(835		)	785		(50		)
Balance at September 30, 2015	$	—		$	1,275	$	1,275

29

NOTE 17. SUBSIDIARY GUARANTORS

The Partnership has issued registered debt securities guaranteed by its subsidiaries.  As of September 30, 2015, all guarantors were wholly owned or available to be pledged and such guarantees were joint and several and full and unconditional.  Although the guarantees of the Partnership's subsidiary guarantors are considered full and unconditional, the guarantees are subject to certain customary release provisions. Such guarantees may be released in the following customary circumstances:

• in connection with any sale or other disposition of all or substantially all of the properties or assets of that guarantor (including by way of merger or consolidation) to a person that is not (either before or after giving effect to such transaction) an issuer or a restricted subsidiary of the Partnership;

• in connection with any sale or other disposition of capital stock of that guarantor to a person that is not (either before or after giving effect to such transaction) an issuer or a restricted subsidiary of us, such that, the guarantor ceases to be a restricted subsidiary of us as a result of the sale or other disposition;

• if the Partnership designates any restricted subsidiary that is a guarantor to be an unrestricted subsidiary in accordance with the applicable provisions of the indenture;

• upon legal defeasance or satisfaction and discharge of the indenture;

• upon the liquidation or dissolution of such guarantor provided no default or event of default has occurred that is continuing;

• at such time as such guarantor ceases to guarantee any other indebtedness of either of the issuers or any guarantor; or

• upon such guarantor consolidating with, merging into or transferring all of its properties or assets to us or another guarantor, and as a result of, or in connection with, such transaction such guarantor dissolving or otherwise ceasing to exist.

In accordance with Rule 3-10 of the Securities and Exchange Commission Regulation S-X, the Partnership has prepared unaudited condensed consolidating financial statements as supplemental information.  The following unaudited condensed consolidated balance sheets at September 30, 2015 and December 31, 2014, and unaudited condensed consolidated statements of operations for the three and nine months ended September 30, 2015 and 2014, and unaudited condensed consolidated statements of cash flows for the nine months ended September 30, 2015 and 2014, present financial information for Eagle Rock Energy as the parent on a stand-alone basis (carrying any investments in subsidiaries under the equity method), financial information for the co-issuer and the subsidiary guarantors, which are all 100% owned by the Partnership, on a stand-alone basis, and the consolidation and elimination entries necessary to arrive at the information for the Partnership on a consolidated basis.  The subsidiary guarantors are not restricted from making distributions to the Partnership.

30

Unaudited Condensed Consolidating Balance Sheet

September 30, 2015

	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Consolidating Entries			Total
	($ in thousands)
ASSETS:
Accounts receivable – related parties	$	840,249		$	—	$	—		$	(840,249	)	$	—
Other current assets	59,040			1		26,074			—			85,115
Total property, plant and equipment, net	1,054			—		429,919			—			430,973
Investment in subsidiaries	(501,647		)	—		—			501,647			—
Total other long-term assets	48,960			—		5,152			—			54,112
Total assets	$	447,656		$	1	$	461,145		$	(338,602	)	$	570,200
LIABILITIES AND EQUITY:
Accounts payable – related parties	$	—		$	—	$	840,249		$	(840,249	)	$	—
Other current liabilities	8,497			—		42,056			—			50,553
Other long-term liabilities	369			—		80,488			—			80,857
Long-term debt	151,801			—		—			—			151,801
Equity	286,989			1		(501,648		)	501,647			286,989
Total liabilities and equity	$	447,656		$	1	$	461,145		$	(338,602	)	$	570,200

Unaudited Condensed Consolidating Balance Sheet

December 31, 2014

	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Consolidating Entries			Total
	($ in thousands)
ASSETS:
Accounts receivable – related parties	$	838,656		$	—	$	—		$	(838,656	)	$	—
Other current assets	211,213			1		37,889			—			249,103
Total property, plant and equipment, net	1,334			—		486,654			—			487,988
Investment in subsidiaries	(413,023		)	—		—			413,023			—
Total other long-term assets	52,272			—		4,912			—			57,184
Total assets	$	690,452		$	1	$	529,455		$	(425,633	)	$	794,275
LIABILITIES AND EQUITY:
Accounts payable – related parties	$	—		$	—	$	838,656		$	(838,656	)	$	—
Other current liabilities	37,850			—		21,675			—			59,525
Other long-term liabilities	789			—		82,148			—			82,937
Long-term debt	263,343			—		—			—			263,343
Equity	388,470			1		(413,024		)	413,023			388,470
Total liabilities and equity	$	690,452		$	1	$	529,455		$	(425,633	)	$	794,275

31

Unaudited Condensed Consolidating Statement of Operations

For the Three Months Ended September 30, 2015

	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Consolidating Entries			Total
	($ in thousands)
Total revenues	$	38,368		$	—	$	31,278		$	—		$	69,646
Operations and maintenance	—			—		10,754			—			10,754
Taxes other than income	—			—		1,264			—			1,264
General and administrative	3,334			—		8,318			—			11,652
Depreciation, depletion and amortization	206			—		16,185			—			16,391
Impairment	—			—		6,969			—			6,969
Income (loss) from operations	34,828			—		(12,212		)	—			22,616
Interest expense, net	(2,038		)	—		—			—			(2,038		)
Other non-operating income	2,144			—		2,359			(4,499		)	4
Other non-operating expense	(5,106		)	—		(3,019		)	4,499			(3,626		)
Income (loss) before income taxes	29,828			—		(12,872		)	—			16,956
Income tax benefit	(217		)	—		(751		)	—			(968		)
Equity in earnings of subsidiaries	(12,148		)	—		—			12,148			—
Income (loss) from continuing operations	17,897			—		(12,121		)	12,148			17,924
Discontinued operations, net of tax	—			—		(27		)	—			(27		)
Net Income (loss)	$	17,897		$	—	$	(12,148	)	$	12,148		$	17,897

Unaudited Condensed Consolidating Statement of Operations

For the Three Months Ended September 30, 2014

	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Consolidating Entries			Total
	($ in thousands)
Total revenues	$	27,951		$	—	$	53,273		$	—		$	81,224
Operations and maintenance	—			—		10,707			—			10,707
Taxes other than income	—			—		3,184			—			3,184
General and administrative	2,956			—		9,279			—			12,235
Depreciation, depletion and amortization	149			—		22,110			—			22,259
Impairment	—			—		17,305			—			17,305
Income (loss) from operations	24,846			—		(9,312		)	—			15,534
Interest expense, net	(3,188		)	—		—			—			(3,188		)
Other non-operating income	2,177			—		2,292			(4,469		)	—
Other non-operating expense	2,542			—		(3,012		)	4,469			3,999
Income (loss) before income taxes	26,377			—		(10,032		)	—			16,345
Income tax provision (benefit)	(1,962		)	—		1,076			—			(886		)
Equity in earnings of subsidiaries	(333,798		)	—		—			333,798			—
Loss from continuing operations	(305,459		)	—		(11,108		)	333,798			17,231
Discontinued operations, net of tax	571,747			—		(322,690		)	—			249,057
Net income (loss)	$	266,288		$	—	$	(333,798	)	$	333,798		$	266,288

32

Unaudited Condensed Consolidating Statement of Operations

For the Nine Months Ended September 30, 2015

	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Consolidating Entries			Total
	($ in thousands)
Total revenues	$	46,912		$	—	$	96,522		$	—		$	143,434
Operations and maintenance	—			—		33,590			—			33,590
Taxes other than income	—			—		3,990			—			3,990
General and administrative	9,339			—		24,708			—			34,047
Depreciation, depletion and amortization	616			—		46,810			—			47,426
Impairment	—			—		75,313			—			75,313
Income (loss) from operations	36,957			—		(87,889		)	—			(50,932		)
Interest expense, net	(6,477		)	—		—			—			(6,477		)
Other non-operating income	9,576			—		6,899			(13,268		)	3,207
Other non-operating expense	(15,729		)	—		(9,021		)	13,268			(11,482		)
Income (loss) before income taxes	24,327			—		(90,011		)	—			(65,684		)
Income tax benefit	(88		)	—		(2,401		)	—			(2,489		)
Equity in earnings of subsidiaries	(88,611		)	—		—			88,611			—
Income (loss) from continuing operations	(64,196		)	—		(87,610		)	88,611			(63,195		)
Discontinued operations, net of tax	—			—		(1,001		)	—			(1,001		)
Net Income (loss)	$	(64,196	)	$	—	$	(88,611	)	$	88,611		$	(64,196	)

Unaudited Condensed Consolidating Statement of Operations

For the Nine Months Ended September 30, 2014

	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-Guarantor Investments			Consolidating Entries			Total
	($ in thousands)
Total revenues	$	(163	)	$	—	$	160,634		$	—		$	—		$	160,471
Operations and maintenance	3			—		33,109			—			—			33,112
Taxes other than income	—			—		10,571			—			—			10,571
General and administrative	7,917			—		29,613			—			—			37,530
Depreciation, depletion and amortization	497			—		62,467			—			—			62,964
Impairment	—			—		17,305			—			—			17,305
(Loss) income from operations	(8,580		)	—		7,569			—			—			(1,011		)
Interest expense, net	(12,888		)	—		(2		)	—			—			(12,890		)
Other non-operating income	6,561			—		6,884			—			(13,445		)	—
Other non-operating expense	(1,161		)	—		(9,143		)	—			13,445			3,141
(Loss) income before income taxes	(16,068		)	—		5,308			—			—			(10,760		)
Income tax benefit	(2,147		)	—		(489		)	—			—			(2,636		)
Equity in earnings of subsidiaries	(305,787		)	—		—			—			305,787			—
(Loss) income from continuing operations	(319,708		)	—		5,797			—			305,787			(8,124		)
Discontinued operations, net of tax	524,392			—		(311,575		)	(9		)	—			212,808
Net income (loss)	$	204,684		$	—	$	(305,778	)	$	(9	)	$	305,787		$	204,684

33

Unaudited Condensed Consolidating Statement of Cash Flows

For the Nine Months Ended September 30, 2015

	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Consolidating Entries		Total
	($ in thousands)
Net cash flows (used in) provided by operating activities	$	(3,096	)	$	—	$	60,682		$	—	$	57,586
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment	(337		)	—		(62,240		)	—		(62,577		)
Proceeds from sale of short-term investments	153,980			—		—			—		153,980
Net cash flows provided by (used in) investing activities	153,643			—		(62,240		)	—		91,403
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	92,900			—		—			—		92,900
Repayment of long-term debt	(204,500		)	—		—			—		(204,500		)
Payments for derivative contracts	(2,836		)	—		—			—		(2,836		)
Repurchase of common units	(3,046		)	—		—			—		(3,046		)
Distributions to members and affiliates	(31,829		)	—		—			—		(31,829		)
Net cash flows used in financing activities	(149,311		)	—		—			—		(149,311		)
Net cash flows used in discontinued operations	—			—		(1,001		)	—		(1,001		)
Net increase (decrease) in cash and cash equivalents	1,236			—		(2,559		)	—		(1,323		)
Cash and cash equivalents at beginning of period	2,686			1		(1,344		)	—		1,343
Cash and cash equivalents at end of period	$	3,922		$	1	$	(3,903	)	$	—	$	20

34

Unaudited Condensed Consolidating Statement of Cash Flows

For the Nine Months Ended September 30, 2014

	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-Guarantor Investments		Consolidating Entries		Total
	($ in thousands)
Net cash flows (used in) provided by operating activities	$	(23,181	)	$	—	$	70,678		$	—	$	—	$	47,497
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment	348			—		(107,012		)	—		—		(106,664		)
Net cash flows provided by (used in) investing activities	348			—		(107,012		)	—		—		(106,664		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	416,700			—		—			—		—		416,700
Repayment of long-term debt	(897,800		)	—		—			—		—		(897,800		)
Payment of debt issuance cost	(410		)	—		—			—		—		(410		)
Payments for derivative contracts	(5,163		)	—		—			—		—		(5,163		)
Repurchase of common units	(1,171		)	—		—			—		—		(1,171		)
Distributions to members and affiliates	(23,801		)	—		—			—		—		(23,801		)
Net cash flows used in financing activities	(511,645		)	—		—			—		—		(511,645		)
Net cash flows provided by discontinued operations	536,883			—		34,424			22		—		571,329
Net increase (decrease) in cash and cash equivalents	2,405			—		(1,910		)	22		—		517
Cash and cash equivalents at beginning of period	1,237			1		(1,389		)	227		—		76
Cash and cash equivalents at end of period	$	3,642		$	1	$	(3,299	)	$	249	$	—	$	593

35

EX-99.3

EXHIBIT 99.3

Unaudited pro forma condensed combined consolidated financial information of Vanguard, as adjusted for the LRE Merger and the Eagle Rock Merger, as of and for the nine months ended September 30, 2015 and for the year ended December 31, 2014

On January 31, 2014, Vanguard Natural Resources, LLC ("Vanguard" or the "Company") and its wholly owned subsidiary, Encore Energy Partners Operating, LLC, completed the Pinedale Acquisition, whereby Vanguard acquired certain natural gas and oil assets in the Pinedale and Jonah fields located in Southwestern Wyoming for approximately $555.6 million in cash.

On September 30, 2014, Vanguard and its wholly owned subsidiary, Vanguard Operating, LLC, completed the Piceance Acquisition, whereby Vanguard acquired natural gas, oil and NGL assets in the Piceance Basin located in Colorado for approximately $496.4 million.

On October 5, 2015, Vanguard completed the previously announced transactions contemplated by the Purchase Agreement and Plan of Merger, dated as of April 20, 2015 (the “LRE Merger Agreement”), by and among Vanguard, Lighthouse Merger Sub, LLC, a wholly owned subsidiary of Vanguard (“Lighthouse Merger Sub”), Lime Rock Management LP (“LR Management”), Lime Rock Resources A, L.P. (“LRR A”), Lime Rock Resources B, L.P. (“LRR B”), Lime Rock Resources C, L.P. (“LRR C”), Lime Rock Resources II-A, L.P. (“LRR II-A”), Lime Rock Resources II-C, L.P. (“LRR II-C,” and, together with LRR A, LRR B, LRR C, LRR II-A and LR Management, the “GP Sellers”), LRR Energy, L.P. (“LRE”) and LRE GP, LLC (“LRE GP”). Pursuant to the terms of the Merger Agreement, Lighthouse Merger Sub was merged with and into LRE, with LRE continuing as the surviving entity and as a wholly owned subsidiary of Vanguard (the “LRE Merger”), and, at the same time, Vanguard acquired all of the limited liability company interests in LRE GP from the GP Sellers in exchange for common units representing limited liability company interests in Vanguard (“Vanguard Common Units”).

Under the terms of the LRE Merger Agreement, (i) each outstanding common unit representing limited partner interests in LRE (“LRE Common Units”) was converted into the right to receive 0.550 newly issued Vanguard Common Units or, in the case of fractional Vanguard Common Units, cash (without interest and rounded up to the nearest whole cent) (the “LRE Merger Consideration”) and (ii) Vanguard purchased all of the outstanding limited liability company interests in LRE GP in exchange for 12,320 newly issued Vanguard Common Units. Further, in connection with the LRE Merger Agreement, each award of restricted LRE Common Units issued under LRE’s long-term incentive plan that was subject to time-based vesting and that was outstanding and unvested immediately prior to the effective time of the Merger became fully vested and was deemed to be a LRE Common Unit with the right to receive the LRE Merger Consideration.

Pursuant to the LRE Merger, Vanguard issued (i) approximately 15.44 million Vanguard Common Units as the LRE Merger Consideration and (ii) 12,320 Vanguard Common Units as consideration for Vanguard’s purchase of the limited liability company interests in LRE GP.

The LRE Merger was completed following approval, at a Special Meeting of LRE unitholders on October 5, 2015, of the LRE Merger Agreement and the LRE Merger by holders of a majority of the outstanding LRE Common Units.

On October 8, 2015, Vanguard completed the previously announced transactions contemplated by the Agreement and Plan of Merger, dated as of May 21, 2015 (the “Eagle Rock Merger Agreement”), by and among Vanguard, Talon Merger Sub, LLC, a wholly owned subsidiary of Vanguard (“Talon Merger Sub”), Eagle Rock Energy Partners, L.P. (“Eagle Rock”) and Eagle Rock Energy GP, L.P. (“Eagle Rock GP”). Pursuant to the terms of the EROC Merger Agreement, Talon Merger Sub was merged with and into Eagle Rock with Eagle Rock continuing as the surviving entity and as a wholly owned subsidiary of Vanguard (the “Eagle Rock Merger”).

Under the terms of theEagle Rock Merger Agreement, (i) each common unit representing limited partner interests in Eagle Rock (“Eagle Rock Common Unit”) was converted into the right to receive 0.185 (the “Exchange

Ratio”) newly issued common units representing limited liability company interests in Vanguard (“Vanguard Common Units”) or, in the case of fractional Vanguard Common Units, cash (without interest and rounded up to the nearest whole cent) (the “Eagle Rock Merger Consideration”). Further, in connection with theEagle Rock Merger Agreement, Vanguard adopted Eagle Rock’s long-term incentive plan and each outstanding award of Eagle Rock Common Units issued under such plan was converted into a new award of restricted units based on Vanguard Common Units. However, any outstanding Eagle Rock Common Units held by employees and officers of Eagle Rock and members of the board of directors of Eagle Rock who did not receive offers from Vanguard or who received “Unqualified Offers” (as such term is defined in theEagle Rock Merger Agreement) and did not accept such offers accelerated upon the effective time of theEagle Rock Merger and was converted into the right to receive theEagle Rock Merger Consideration, with the vesting of performance-based restricted units determined based upon Eagle Rock’s actual performance through the effective time of theEagle Rock Merger (subject to Vanguard’s good faith review).

    Pursuant to the Eagle Rock Merger, Vanguard issued (i) approximately 28.26 million Vanguard Common Units as the Eagle Rock Merger Consideration.

The Eagle Rock Merger was completed following (i) approvalby holders of a majority of the outstanding Eagle Rock Common Units, at a Special Meeting of Eagle Rock unitholders on October 5, 2015, of the Eagle Rock Merger Agreement and the Eagle Rock Merger and (ii) approval by Vanguard unitholders, at Vanguard’s 2015 Annual Meeting of Unitholders, of the issuance of Vanguard Common Units to be issued as Eagle Rock Merger Consideration to the holders of Eagle Rock Common Units in connection with the Eagle Rock Merger.

The pro forma financial statements presented below have been prepared using the acquisition method of accounting for business combinations under U.S. GAAP. Under the acquisition method of accounting, the assets acquired and liabilities assumed from LRE and Eagle Rock will be recorded as of the acquisition date at their respective fair values.

The historical financial information included in the columns entitled “Vanguard” presented was derived from the unaudited financial statements included in Vanguard’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2015 and its Annual Report on Form 10-K for the year ended December 31, 2014. The historical financial information included in the columns entitled “LRE” was derived from LRE’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2015 and its Annual Report on Form 10-K for the year ended December 31, 2014. The historical financial information included in the columns entitled “Eagle Rock” was derived from Eagle Rock’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2015 and its Annual Report on Form 10-K for the year ended December 31, 2014.

Vanguard’s unaudited pro forma combined balance sheet at September 30, 2015 has been presented to show the effect as if the LRE Merger, the Eagle Rock Merger and the pro forma adjustments had occurred on September 30, 2015. The Pinedale Acquisition and the Piceance Acquisition were included in Vanguard’s historical balance sheet at September 30, 2015, and, as such, there are no pro forma adjustments related to the Pinedale Acquisition and the Piceance Acquisition.

Vanguard’s unaudited pro forma combined statements of operations for the nine months ended September 30, 2015 and for the year ended December 31, 2014 have been presented based on Vanguard’s individual statements of operations, and reflect the pro forma operating results attributable to the LRE Merger, the Eagle Rock Merger, the Pinedale Acquisition and the Piceance Acquisition as if the LRE Merger, the Eagle Rock Merger and acquisitions and the related transactions had occurred on January 1, 2014. Vanguard’s historical statements of operations include operating results from the Pinedale Acquisition and the Piceance Acquisition for the nine months ended September 30, 2015 and, as such, there are no pro forma adjustments related to the Pinedale Acquisition and the Piceance Acquisition for this period.

The unaudited pro forma combined financial information presented includes adjustments to conform LRE’s and Eagle Rock’s accounting for oil and natural gas properties to the full cost method. Vanguard follows the full cost method of accounting for oil and natural gas properties while LRE and Eagle Rock follow the successful efforts method of accounting for oil and natural gas properties. Certain costs that are capitalized under the full cost

method are expensed under the successful efforts method. These costs consist primarily of unsuccessful exploration drilling costs, geological and geophysical costs, delay rental on leases, abandonment costs and general and administrative expenses directly related to exploration and development activities. Under the successful efforts method of accounting, proved property acquisition costs are amortized on a unit-of-production basis over total proved reserves and costs of wells, related equipment and facilities are depreciated over the life of the proved developed reserves that will utilize those capitalized assets on a field-by-field basis. Under the full cost method of accounting, property acquisition costs, costs of wells, related equipment and facilities and future development costs are included in a single full cost pool, which is amortized on a unit-of-production basis over total proved reserves.

Pro forma data is based on currently available information and certain estimates and assumptions as explained in the notes to the unaudited pro forma combined financial statements. Pro forma data is not necessarily indicative of the financial results that would have been attained had the LRE Merger, the Eagle Rock Merger, the Pinedale Acquisition and the Piceance Acquisition occurred on January 1, 2014. As actual adjustments may differ from the pro forma adjustments, the pro forma amounts presented should not be viewed as indicative of operations in future periods.

The unaudited pro forma combined financial information presented is based on assumptions that Vanguard believes are reasonable under the circumstances and are intended for informational purposes only. Actual results may differ from the estimates and assumptions used. The unaudited pro forma combined financial information presented is not necessarily indicative of the financial results that would have occurred if these transactions had taken place on the dates indicated, nor is it indicative of future consolidated results.

Vanguard Natural Resources, LLC and Subsidiaries

Unaudited Pro Forma Combined Balance Sheet

As of September 30, 2015

	Historical						Pro Forma Adjustments (Note 2)				Historical			Pro Forma Adjustments (Note 2)				Vanguard/ LRE/Eagle Rock Pro Forma Combined
	Vanguard			LRE							Eagle Rock
Assets
Current assets
Cash and cash equivalents	$	19,490		$	13,145		$	(3,499	)	(e)	$	20		$	—			$	29,156
Trade accounts receivable, net	66,200			10,298			—				25,802			—				102,300
Derivative assets	139,901			37,305			—				50,724			—				227,930
Prepaid expenses	—			1,390			(47		)	(a)	—			—				1,343
Other current assets	11,119			—			—				8,569			—				19,688
Total current assets	236,710			62,138			(3,546		)		85,115			—				380,417
Oil and natural gas properties, at cost	4,257,859			977,232			(665,980		)	(a)	848,708			(422,821		)	(g)	4,933,662
							(101,517		)	(a)				40,181			(g)
Accumulated depletion, amortization and impairment	(2,695,554		)	(665,980		)	665,980			(a)	(422,821		)	422,821			(g)	(2,695,554		)
Oil and natural gas properties evaluated, net – full cost method	1,562,305			311,252			(101,517		)		425,887			40,181				2,238,108
Other assets
Goodwill	420,955			—			153,122			(a)	—			—				574,077
Derivative assets	62,890			47,938			—				44,438			—				155,266
Deferred financing costs, net of accumulated amortization and other assets	—			1,480			(1,480		)	(a)	—			—				—
Other assets	30,529			284			(17		)	(a)	14,760			(4,788		)	(g)	40,768
Total assets	$	2,313,389		$	423,092		$	46,562			$	570,200		$	35,393			$	3,388,636
Liabilities and members’ equity
Current liabilities
Accounts payable:
Trade	$	17,682		$	—		$	—			$	10,380		$	4,400		(k)	$	32,462
Affiliates	1,512			—			—				—			—				1,512
Accrued liabilities:
Lease operating	13,152			1,740			—				3,165			—				18,057
Development capital	9,274			2,276			—				14,003			—				25,553
Interest	21,987			147			—				1,315			—				23,449
Production and other taxes	47,155			30			—				82			—				47,267
Derivative liabilities	636			3,486			—				—			—				4,122
Oil and natural gas revenue payable	22,192			670			—				6,463			—				29,325
Distributions payable	11,241			3,511			—				7,138			—				21,890
Other	20,770			7,861			1,713			(a)	8,007			14,000			(l)	53,551
							1,200			(f)
Total current liabilities	165,601			19,721			2,913				50,553			18,400				257,188
Term Loan				50,000			(50,000		)	(b)	—			—				—
Revolving credit facility				240,000			(240,000		)	(b)	—			—				—
Long-term debt	1,889,674			—			290,000			(b)	151,801			(101,000		)	(h)	2,314,414

													101,000			(h)
													(17,061		)	(g)
Derivative liabilities	473			1,027			—				—		—				1,500
Asset retirement obligations, net of current portion	173,898			41,149			(4,835		)	(a)	48,403		16,977			(g)	275,592
Deferred tax liabilities				—			—				27,851		—				27,851
Other long-term liabilities	730			—			—				4,603		—				5,333
Total liabilities	2,230,376			351,897			(1,922		)		283,211		18,316				2,881,878
Commitments and contingencies
Members’ equity
Cumulative Preferred units	335,444			—			—				—		—				335,444
Common units	(260,046		)	—			123,178			(c)	286,989		(286,989		)	(j)	163,699
							(3,499		)	(e)			45,349			(g)
													263,117			(i)
													(4,400		)	(k)
Class B units	7,615			—			—				—		—				7,615
General Partner	—			(32,656		)	32,656			(d)	—		—				—
Public common unitholders	—			103,851			(103,851		)	(d)	—		—				—
Total members’ equity	83,013			71,195			48,484				286,989		17,077				506,758
Total liabilities and members’ equity	$	2,313,389		$	423,092		$	46,562			$	570,200	$	35,393			$	3,388,636

See accompanying notes to consolidated financial statements

Unaudited Pro Forma Combined Statement of Operations

 For the Nine Months Ended September 30, 2015

(in thousands, except per unit data)	Historical						Pro Forma reclassification adjustments (Note 3)				Pro Forma adjustments (Note 3)				Historical			Pro Forma reclassification adjustments (Note 3)				Pro Forma adjustments (Note 3)				Vanguard/ LRE/Eagle Rock Pro Forma Combined
	Vanguard			LRE											Eagle Rock
Revenues:
Oil sales	$	113,425		$	39,568		$	—			$	—			$	—		$	52,791		(j)	$	—			$	205,784
Natural gas sales	146,502			12,097			71			(a)	—				—			25,953			(j)	—				184,767
																		144			(k)	—
NGLs sales	25,635			3,803			—				—				—			13,632			(j)	—				43,070
Natural gas, natural gas condensate and sulfur	—			—			—				—				92,376			(92,376		)	(j)	—				—
Net gains (losses) on commodity derivative contracts	102,561			38,948			—				—				50,914			—				—				192,423
Other income				71			(71		)	(a)	—				144			(144		)	(k)	—				—
Total revenues	388,123			94,487			—				—				143,434			—				—				626,044
Costs and expenses:
Production:
Lease operating expenses	101,247			18,741			—				(281		)	(c)	33,590			—				—				153,297
Production and other taxes	31,262			4,117			—				—				3,990			—				—				39,369
Depreciation, depletion, amortization, and accretion	182,443			27,589			—				(27,589		)	(d)	47,426			—				(43,428		)	(m)	228,613
											12,535			(d)				—				28,944			(m)
											1,198			(e)				—				(505		)	(n)
Impairment of oil and natural gas properties	1,357,462			132,296			—				—				75,313			—				—				1,565,071
Accretion expense	—			1,556			—				(1,556		)	(e)	—			—				—
Loss on settlement of asset retirement obligations	—			125			—				(125		)	(f)	—			—				—
Selling, general and administrative expenses	26,239			19,055			16			(b)	(20		)	(g)	34,047			—				(412		)	(o)	78,925
Total costs and expenses	1,698,653			203,479			16				(15,838		)		194,366			—				(15,401		)		2,065,275
Income (loss) from operations	(1,310,530		)	(108,992		)	(16		)		15,838				(50,932		)	—				15,401				(1,439,231		)
Other income (expense):
Interest expense	(61,693		)	(9,150		)	—				9,150			(h)	(6,477		)	—				2,337			(p)	(73,662		)
											(5,329		)	(h)								(2,500		)	(p)
Net losses on interest rate derivative contracts	(2,291		)	(2,421		)	—				—				(5,728		)	—				—				(10,440		)
Net loss on acquisition of oil and natural gas properties	(284		)	—			—				—				—			—				—				(284		)
Net income (loss) from short term investments	—			—			—				—				(5,754		)	3,179			(l)	—				(2,575		)
Other	46			—			—				—				3,207			(3,179		)	(l)	—				74
Total other income (expense)	(64,222		)	(11,571		)	—				3,821				(14,752		)	—				(163		)		(86,887		)
Income (loss) before taxes	(1,374,752		)	(120,563		)	(16		)		19,659				(65,684		)	—				15,238				(1,526,118		)

Income tax benefit (expense)	—			(16		)	16		(b)	—			2,489			—		—			2,489
Loss from continuing operations	(1,374,752		)	(120,579		)	—			19,659			(63,195		)	—		15,238			(1,523,629		)
Distributions to Preferred unitholders	(20,070		)	—			—			—			—			—		—			(20,070		)
Loss from continuing operations attributable to Common and Class B unitholders	$	(1,394,822	)	$	(120,579	)	$	—		$	19,659		$	(63,195	)	$	—	$	15,238		$	(1,543,699	)
Loss from continuing operations per Common and Class B unit
Basic and Diluted	$	(16.25	)																		$	(11.92	)
Weighted average Common units outstanding
Common units – basic & diluted	85,414									15,436		(i)						28,262		(q)	129,112
Class B units – basic & diluted	420																				420

See accompanying notes to consolidated financial statements

Unaudited Pro Forma Combined  Statement of Operations

 For the Year Ended December 31, 2014

	Vanguard As Adjusted (Note 4)			LRE Historical			Pro Forma reclassification adjustments (Note 3)				Pro Forma adjustments (Note 3)				Eagle Rock Historical			Pro Forma reclassification adjustments (Note 3)				Pro Forma adjustments (Note 3)				Vanguard/ LRE/Eagle Rock Pro Forma Combined
Revenues:
Oil sales	$	285,918		$	76,662		$	—			$	—			$	—		$	113,363		(j)	$	—			$	475,943
Natural gas sales	351,404			28,521			121			(a)	—				—			51,252			(j)	—				431,279
																		(19		)	(k)	—
NGLs sales	101,309			11,362			—				—				—			39,177			(j)	—				151,848
Natural gas, natural gas condensate and sulfur	—			—			—				—				203,792			(203,792		)	(j)	—				—
Net gains (losses) on commodity derivative contracts	163,452			71,235			—				—				94,431			—				—				329,118
Other income				125			(125		)	(a)	—				(19		)	19			(k)	—				—
Total revenues	902,083			187,905			(4		)		—				298,204			—				—				1,388,188
Costs and expenses:
Production:
Lease operating expenses	149,765			25,821			—				(322		)	(c)	43,670			—				—				218,934
Production and other taxes	68,749			8,738			—				—				12,925			—				—				90,412
Depreciation, depletion, amortization, and accretion	267,091			36,729			—				(36,729		)	(d)	85,579			—				(80,810		)	(m)	340,524
											23,089			(d)				—				44,650			(m)
											1,554			(e)				—				(629		)	(n)
Impairment of oil and natural gas properties	194,280			37,758			—				—				395,892			—				—				627,930
Accretion expense	—			2,071			—				(2,071		)	(e)	—			—				—
Loss on settlement of asset retirement obligations	—			151			—				(151		)	(f)	—			—				—
Selling, general and administrative expenses	30,839			11,447			186			(b)	(31		)	(g)	47,193			—				(584		)	(o)	89,050
Total costs and expenses	710,724			122,715			186				(14,661		)		585,259			—				(37,373		)		1,366,850
Income (loss) from operations	191,359			65,190			(190		)		14,661				(287,055		)	—				37,373				21,338
Other income (expense):
Interest expense	(78,994		)	(10,472		)	—				10,472			(h)	(15,247		)	—				13,857			(p)	(96,188		)
											(6,264		)	(h)								(9,540		)	(p)
Net losses on interest rate derivative contracts	(1,933		)	(1,790		)	—				—				(1,734		)	—								(5,457		)
Gain on acquisition of oil and natural gas properties	2,836			—			—				—				—			—				—				2,836
Net income (loss) from short term investments	—			—			—				—				(62,028		)	8,041			(l)					(53,987		)

Other	54			—			4			(a)	—			8,294			(8,041		)	(l)				311
Total other expense	(78,037		)	(12,262		)	4				4,208			(70,715		)	—				4,317			(152,485		)
Income (loss) before taxes	113,322			52,928			(186		)		18,869			(357,770		)	—				41,690			(131,147		)
Income tax benefit (expense)	—			(186		)	186			(b)	—			5,403			—				—			5,403
Income (loss) from continuing operations	113,322			52,742			—				18,869			(352,367		)	—				41,690			(125,744		)
Distributions to Preferred unitholders	(18,197		)	—			—				—			—			—				—			(18,197		)
Income (loss) from continuing operations attributable to Common and Class B unitholders	$	95,125		$	52,742		$	—			$	18,869		$	(352,367	)	$	—			$	41,690		$	(143,941	)
Income (loss) from continuing operations per Common and Class B unit
Basic	$	1.16																						$	(1.15	)
Diluted	$	1.14																						$	(1.15	)
Weighted average Common units outstanding
Common units – basic	81,611										15,436		(i)								28,262		(q)	125,309
Common units – diluted	82,039																							125,309
Class B units – basic & diluted	420																							420

See accompanying notes to consolidated financial statements

Notes to the Unaudited Pro Forma Combined Financial Statements

Note 1 Basis of Presentation

On January 31, 2014, Vanguard Natural Resources, LLC ("Vanguard" or the "Company") and its wholly owned subsidiary, Encore Energy Partners Operating, LLC, completed the Pinedale Acquisition, whereby Vanguard acquired certain natural gas and oil assets in the Pinedale and Jonah fields located in Southwestern Wyoming for approximately $555.6 million in cash.

On September 30, 2014, Vanguard and its wholly owned subsidiary, Vanguard Operating, LLC, completed the Piceance Acquisition, whereby Vanguard acquired natural gas, oil and NGL assets in the Piceance Basin located in Colorado for approximately $496.4 million.

On October 5, 2015, Vanguard completed the previously announced transactions contemplated by the Purchase Agreement and Plan of Merger, dated as of April 20, 2015 (the “LRE Merger Agreement”), by and among Vanguard, Lighthouse Merger Sub, LLC, a wholly owned subsidiary of Vanguard (“Lighthouse Merger Sub”), Lime Rock Management LP (“LR Management”), Lime Rock Resources A, L.P. (“LRR A”), Lime Rock Resources B, L.P. (“LRR B”), Lime Rock Resources C, L.P. (“LRR C”), Lime Rock Resources II-A, L.P. (“LRR II-A”), Lime Rock Resources II-C, L.P. (“LRR II-C,” and, together with LRR A, LRR B, LRR C, LRR II-A and LR Management, the “GP Sellers”), LRR Energy, L.P. (“LRE”) and LRE GP, LLC (“LRE GP”). Pursuant to the terms of the Merger Agreement, Lighthouse Merger Sub was merged with and into LRE, with LRE continuing as the surviving entity and as a wholly owned subsidiary of Vanguard (the “LRE Merger”), and, at the same time, Vanguard acquired all of the limited liability company interests in LRE GP from the GP Sellers in exchange for common units representing limited liability company interests in Vanguard (“Vanguard Common Units”).

Under the terms of the LRE Merger Agreement, (i) each outstanding common unit representing limited partner interests in LRE (“LRE Common Units”) was converted into the right to receive 0.550 newly issued Vanguard Common Units or, in the case of fractional Vanguard Common Units, cash (without interest and rounded up to the nearest whole cent) (the “LRE Merger Consideration”) and (ii) Vanguard purchased all of the outstanding limited liability company interests in LRE GP in exchange for 12,320 newly issued Vanguard Common Units. Further, in connection with the LRE Merger Agreement, each award of restricted LRE Common Units issued under LRE’s long-term incentive plan that was subject to time-based vesting and that was outstanding and unvested immediately prior to the effective time of the Merger became fully vested and was deemed to be a LRE Common Unit with the right to receive the LRE Merger Consideration.

Pursuant to the LRE Merger, Vanguard issued (i) approximately 15.44 million Vanguard Common Units as the LRE Merger Consideration and (ii) 12,320 Vanguard Common Units as consideration for Vanguard’s purchase of the limited liability company interests in LRE GP.

The LRE Merger was completed following approval, at a Special Meeting of LRE unitholders on October 5, 2015, of the LRE Merger Agreement and the LRE Merger by holders of a majority of the outstanding LRE Common Units.

On October 8, 2015, Vanguard completed the previously announced transactions contemplated by the Agreement and Plan of Merger, dated as of May 21, 2015 (the “Eagle Rock Merger Agreement”), by and among Vanguard, Talon Merger Sub, LLC, a wholly owned subsidiary of Vanguard (“Talon Merger Sub”), Eagle Rock Energy Partners, L.P. (“Eagle Rock”) and Eagle Rock Energy GP, L.P. (“Eagle Rock GP”). Pursuant to the terms of the EROC Merger Agreement, Talon Merger Sub was merged with and into Eagle Rock with Eagle Rock continuing as the surviving entity and as a wholly owned subsidiary of Vanguard (the “Eagle Rock Merger”).

Under the terms of theEagle Rock Merger Agreement, (i) each common unit representing limited partner interests in Eagle Rock (“Eagle Rock Common Unit”) was converted into the right to receive 0.185 (the “Exchange Ratio”) newly issued common units representing limited liability company interests in Vanguard (“Vanguard Common Units”) or, in the case of fractional Vanguard Common Units, cash (without interest and rounded up to the nearest whole cent) (the “Eagle Rock Merger Consideration”). Further, in connection with theEagle Rock Merger Agreement, Vanguard adopted Eagle Rock’s long-term incentive plan and each outstanding award of Eagle Rock Common Units issued under such plan was converted into a new award of restricted units based on Vanguard Common Units. However, any outstanding Eagle Rock Common Units held by employees and officers of Eagle Rock and members of the board of directors of Eagle Rock who did not receive offers from Vanguard or who received “Unqualified Offers” (as such term is

defined in theEagle Rock Merger Agreement) and did not accept such offers accelerated upon the effective time of theEagle Rock Merger and was converted into the right to receive theEagle Rock Merger Consideration, with the vesting of performance-based restricted units determined based upon Eagle Rock’s actual performance through the effective time of theEagle Rock Merger (subject to Vanguard’s good faith review).

    Pursuant to the Eagle Rock Merger, Vanguard issued (i) approximately 28.26 million Vanguard Common Units as the Eagle Rock Merger Consideration.

The Eagle Rock Merger was completed following (i) approvalby holders of a majority of the outstanding Eagle Rock Common Units, at a Special Meeting of Eagle Rock unitholders on October 5, 2015, of the Eagle Rock Merger Agreement and the Eagle Rock Merger and (ii) approval by Vanguard unitholders, at Vanguard’s 2015 Annual Meeting of Unitholders, of the issuance of Vanguard Common Units to be issued as Eagle Rock Merger Consideration to the holders of Eagle Rock Common Units in connection with the Eagle Rock Merger.

The LRE Merger and the Eagle Rock Merger will be accounted for in accordance with Accounting Standards Board’s Accounting Standards Codification Topic 805 - Business Combinations, which is referred to as FASB ASC 805.

Vanguard’s unaudited pro forma combined balance sheet at September 30, 2015 has been presented to show the effect as if the LRE Merger, the Eagle Rock Merger and the pro forma adjustments had occurred on September 30, 2015. The Pinedale Acquisition and the Piceance Acquisition were included in Vanguard’s historical balance sheet at September 30, 2015, and, as such, there are no pro forma adjustments related to the Pinedale Acquisition and the Piceance Acquisition.

Vanguard’s unaudited pro forma combined statements of operations for the nine months ended September 30, 2015 and for the year ended December 31, 2014 have been presented based on Vanguard’s individual statements of operations, and reflect the pro forma operating results attributable to the LRE Merger, the Eagle Rock Merger, the Pinedale Acquisition and the Piceance Acquisition as if the LRE Merger, the Eagle Rock Merger and acquisitions and the related transactions had occurred on January 1, 2014. Vanguard’s historical statements of operations include operating results from the Pinedale Acquisition and the Piceance Acquisition for the nine months ended September 30, 2015 and, as such, there are no pro forma adjustments related to the Pinedale Acquisition and the Piceance Acquisition for this period.

The unaudited pro forma combined financial information presented includes adjustments to conform LRE’s and Eagle Rock’s accounting for oil and natural gas properties to the full cost method. Vanguard follows the full cost method of accounting for oil and natural gas properties while LRE and Eagle Rock follow the successful efforts method of accounting for oil and natural gas properties. Certain costs that are capitalized under the full cost method are expensed under the successful efforts method. These costs consist primarily of unsuccessful exploration drilling costs, geological and geophysical costs, delay rental on leases, abandonment costs and general and administrative expenses directly related to exploration and development activities. Under the successful efforts method of accounting, proved property acquisition costs are amortized on a unit-of-production basis over total proved reserves and costs of wells, related equipment and facilities are depreciated over the life of the proved developed reserves that will utilize those capitalized assets on a field-by-field basis. Under the full cost method of accounting, property acquisition costs, costs of wells, related equipment and facilities and future development costs are included in a single full cost pool, which is amortized on a unit-of-production basis over total proved reserves.

Pro forma data is based on currently available information and certain estimates and assumptions as explained in the notes to the unaudited pro forma combined financial statements. Pro forma data is not necessarily indicative of the financial results that would have been attained had the LRE Merger, the Eagle Rock Merger, the Pinedale Acquisition and the Piceance Acquisition occurred on January 1, 2014. As actual adjustments may differ from the pro forma adjustments, the pro forma amounts presented should not be viewed as indicative of operations in future periods.

The unaudited pro forma combined financial information presented is based on assumptions that Vanguard believes are reasonable under the circumstances and are intended for informational purposes only. Actual results may differ from the estimates and assumptions used. The unaudited pro forma combined financial information presented is not necessarily indicative of the financial results that would have occurred if these transactions had taken place on the dates indicated, nor is it indicative of future consolidated results.

Note 2 Unaudited Pro forma Combined Balance Sheet

LRE Merger

The consideration transferred, fair value of assets acquired and liabilities assumed and resulting goodwill in connection with the LRE Merger were calculated as follows (in thousands):

Pro forma consideration
Market value of Vanguard’s common units issued to LRE unitholders(c)	$	123,178
Long-term debt assumed	290,000
	413,178
Add: fair value of liabilities assumed
Accounts payable and accrued liabilities	4,193
Current derivative liabilities	3,486
Other current liabilities	10,774
Asset retirement obligations	36,314
Distributions payable	4,181
Long-term derivative liabilities	1,027
Amount attributable to liabilities assumed	$	59,975

Less: fair value of assets acquired
Cash	13,145
Trade accounts receivable	10,298
Current derivative assets	37,305
Other current assets	1,343
Oil and natural gas properties	209,735
Long-term derivative assets	47,938
Other assets	267
Amount attributable assets acquired	$	320,031
Goodwill	$	153,122

The total consideration for the LRE Merger comprising the fair value of Vanguard’s common units issued to LRE unitholders and fair value of long-term debt assumed was assigned to the assets acquired and liabilities assumed based on a preliminary assessment of the estimated fair value of the assets acquired and liabilities assumed at September 30, 2015 using currently available information. The final determination of fair value for certain assets and liabilities will be completed as soon as the information necessary to complete the analysis obtained. These amounts will be finalized as soon as possible, but no later than one year from the date of the LRE Merger.

Goodwill is calculated as the excess of the total consideration over the estimated fair value of net assets acquired. The total consideration for the LRE Merger was based on the market capitalization of LRE, as applicable, with an added control premium which resulted in a higher value compared to the fair value of the net assets acquired. The resulting goodwill is attributable to Vanguard’s qualitative assumptions of long-term factors that the acquisition creates for its unitholders. These assumptions include:

• the acquisition of long-life, low-decline, mature oil and natural gas exploration and production assets that are well-suited for Vanguard’s upstream MLP model and its stated corporate strategy to grow via accretive acquisitions;

• additional scale and efficiencies in Vanguard’s current operating basins;

• increased scale of operations which will permit Vanguard to compete more effectively and facilitate future development projects and acquisitions through increased cash flow and lower cost of capital investment in the current reduced commodity price environment. Vanguard also expects the combined business to realize substantial operating and administrative synergies;

• the addition of a balanced production and reserves product mix that Vanguard believes provides an advantage in light of the better expected profit margins for oil and NGLs production than natural gas production as reflected in the short-term and long-term market prices for oil versus natural gas; and

• improvement in a number of Vanguard’s financial ratios commonly used to assess its credit rating. The predominantly unit-for-unit nature of the transaction is expected to allow Vanguard to reduce leverage and strengthen its balance sheet. In addition, because size is a key contributor to credit ratings for oil and natural gas exploration and production companies, increased scale could result in improved credit ratings for the combined entity.

Eagle Rock Merger

The consideration transferred, fair value of assets acquired and liabilities assumed and resulting bargain purchase gain in connection with the Eagle Rock Merger were calculated as follows (in thousands):

Pro forma consideration
Market value of Vanguard’s common units issued to Eagle Rock unitholders(i)	$	263,117
Long-term debt assumed	134,740
	397,857
Add: fair value of liabilities assumed
Accounts payable and accrued liabilities	35,408
Other current liabilities	22,007
Distributions payable	7,138
Asset retirement obligations	65,380
Deferred tax liability	27,851
Other Long-term liabilities	4,603
Amount attributable to liabilities assumed	$	162,387
Less: fair value of assets acquired
Cash	20
Trade accounts receivable	25,802
Current derivative assets	50,724
Other current assets	8,569
Oil and natural gas properties	466,068
Long-term derivative assets	44,438
Other assets	9,972
Amount attributable assets acquired	$	605,593
Bargain Purchase Gain	$	(45,349	)

The total consideration for the Eagle Rock Merger comprising the fair value of Vanguard’s common units issued to Eagle Rock unitholders and fair value of long-term debt assumed was assigned to the assets acquired and liabilities assumed based on a preliminary assessment of the estimated fair value of the assets acquired and liabilities assumed at September 30, 2015 using currently available information. The final determination of fair value for certain assets and liabilities will be completed as soon as the information necessary to complete the analysis obtained. These amounts will be finalized as soon as possible, but no later than one year from the date of the Eagle Rock Merger.

As a result of the consideration transferred being less than the fair value of net assets acquired, Vanguard is required to analyze the purchase price allocation and the potential reasonableness of reflecting a bargain purchase. Vanguard reassessed whether it had fully identified all of the assets and liabilities obtained in the acquisition. As part of its reassessment, Vanguard also reevaluated the consideration transferred and whether there were any non-controlling interests in the acquired property. No additional assets or liabilities were identified. Vanguard also determined that there were no non-controlling interests in the acquired property.

Vanguard determined that the bargain purchase gain was primarily attributable to unfavorable market trends resulting in the decline of Vanguard’s share price. Although the depressed oil and gas market also affected the fair value of Eagle Rock’s oil and gas properties, it had a more significant impact on Vanguard’s share price compared to the resulting decrease in the fair value of those properties. As a result, the fair value of the net assets acquired in the Eagle Rock Merger, including the oil and gas properties, exceeded the total consideration paid.

Vanguard believes the estimates used in the fair market valuation and purchase price allocation are reasonable and that the significant effects of the LRE Merger and Eagle Rock Merger are properly reflected.

The final purchase price allocation and the resulting effect on results of operations and financial position may significantly differ from the pro forma amounts included herein.

The purchase price allocation is preliminary and subject to change due to several factors including changes in the estimated fair values of LRE’s or Eagle Rock's assets and liabilities as of the close date of each of the mergers.

Pro Forma Adjustment to the Unaudited Pro Forma Combined Balance Sheet

LRE Merger

(a)Represents pro forma adjustments to:

•adjust the assets acquired and liabilities assumed to their estimated fair values as of the closing date;

•eliminate LRE’s historical accumulated depreciation, depletion and amortization balances;

•adjust asset retirement obligations using Vanguard’s estimates; and

•eliminate deferred financing costs on LRE’s term loan and credit facility.

(b) Represents the termination of LRE’s credit agreement and term loan agreement and the extinguishment of the related debt outstanding using Vanguard’s borrowings under its reserve-based credit facility.

(c) Represents the increase in Vanguard’s common units resulting from the issuance of Vanguard’s common units to LRE to effect the LRE merger as follows (in thousands, except merger exchange ratio and closing share price):

LRE common units owned by public unitholders	19,473
LRE common units owned by affiliated unitholders	8,570
LRE common units owned by the owners of LRE GP	22
Total LRE common units acquired by Vanguard	28,065
Merger exchange ratio of Vanguard common units for each LRE common unit	0.55
Vanguard common units issued	15,436
Closing price of Vanguard common unit on October 5, 2015	$	7.98
Vanguard common unit consideration	$	123,178

(d) Represents the elimination of LRE’s historical equity in connection with the acquisition method of accounting.

(e) Represents the estimated $3.5 million of legal and advisory fees to be incurred by Vanguard that are reflected in the unaudited pro forma combined balance sheet as a reduction of equity as these costs are considered direct costs incurred to effect the Merger.

(f) Represents cash severance payment to an executive officer of LRE GP to be paid immediately prior to the closing of the merger.

Eagle Rock Merger

(g) Represents pro forma adjustments to:

•adjust the assets acquired and liabilities assumed to their estimated fair values as of the closing date;

•eliminate Eagle Rock’s historical accumulated depreciation, depletion and amortization balances;

•adjust asset retirement obligations using Vanguard’s estimates; and

•eliminate deferred financing costs on Eagle Rock’s credit facility and senior notes.

(h) Represents the termination of Eagle Rock’s revolving credit agreement and the extinguishment of the related debt outstanding using Vanguard’s borrowings under its reserve-based credit facility.

(i) Represents the increase in Vanguard’s common units resulting from the issuance of Vanguard’s common units to Eagle Rock to effect the Eagle Rock Merger as follows (in thousands, except merger exchange ratio and closing share price):

Estimated Eagle Rock common units owned by public unitholders	149,563
Estimated Eagle Rock unvested performance units that will vest upon closing	3,203
Total Eagle Rock common units acquired by Vanguard	152,766
Merger exchange ratio of Vanguard common units for each Eagle Rock common unit	0.185
Vanguard common units	28,262
Closing price of Vanguard common unit on October 8, 2015	$	9.31
Vanguard common unit consideration	$	263,117

(j) Represents the elimination of Eagle Rock’s historical equity in connection with the acquisition method of accounting.

(k) Represents the estimated $4.4 million of legal and advisory fees to be incurred by Vanguard that are reflected in the unaudited pro forma combined balance sheet as a reduction of equity as these costs are considered direct costs incurred to effect the Merger.

(l) Represents cash severance payment to certain employees, executive officers and directors of Eagle Rock GP that were paid immediately prior to the closing of the Eagle Rock merger.

Reclassifications were made to the historical LRE and Eagle Rock assets and liabilities to conform to Vanguard’s presentation. Those reclassifications did not impact the total historical LRE and Eagle Rock assets or liabilities.

Note 3 Pro Forma Adjustments to the Unaudited Combined Statements of Operations

LRE Merger

Adjustments (a) − (b) to the unaudited pro forma combined statement of operations for the nine months ended September 30, 2015 and for the year ended December 31, 2014 include reclassifications required to conform LRE’s revenue and expense items to Vanguard’s presentation as follows:

(a) Represents the reclassification of LRE’s other income sales to conform to Vanguard’s natural gas product sales presentation.

(b) Represents the reclassification of LRE’s income tax expense to conform to Vanguard’s presentation.

Adjustments (c) − (i) to the unaudited pro forma combined statements of operations for the nine months ended September 30, 2015 and for the year ended December 31, 2014 are to reflect the merger with LRE and the conversion of LRE’s method of accounting for oil and natural gas properties from the successful efforts method of

accounting to the full cost method of accounting.

(c) Represents the capitalization of unsuccessful exploration costs, geological and geophysical costs and delay rentals attributable to the development of oil and natural gas properties in accordance with the full cost method of accounting for oil and natural gas properties.

(d) Represents the change in depreciation, depletion and amortization primarily resulting from the pro forma calculation of the combined entity’s depletion expense under the full cost method of accounting for oil and natural gas properties.

(e) Represents the change in accretion expense using Vanguard’s asset retirement obligations estimates.

(f) Represents the adjustment to eliminate the loss on settlement of asset retirement obligations to conform to Vanguard’s full cost method of accounting for oil and natural gas properties.

(g) Represents the elimination of certain general and administrative expenses resulting from LRE not being a separate public company after the completion of the Merger, including NYSE listing fees and SEC filing fees.

(h) Represents the adjustment to interest expense arising from borrowings under Vanguard’s reserve-based credit facility used to terminate LRE’s credit agreement and term loan agreement and the extinguishment of the related debt outstanding. We eliminated the interest expense recorded by LRE and calculated pro forma interest expense based on the long-term debt assumed of $290.0 million and Vanguard’s variable interest rate as of September 30, 2015 of 2.45%. The effect on net income of a 1/8 percent variance in interest rates would be $0.7 million and $0.8 million for the nine months ended September 30, 2015 and for the year ended December 31, 2014, respectively.

(i) Represents the adjustment for the weighted average number of units from the issuance of approximately 15.45 million Vanguard common units under the terms of the Merger, which consists of 15.44 million common units issued to the former LRE unitholders and 12,320 common units issued to the former members of LRE GP, whereby LRE’s public unitholders received 0.550 Vanguard common units for each LRE common unit held at closing.

Eagle Rock Merger

Adjustments (j) − (l) to the unaudited pro forma combined statements of operations for the nine months ended September 30, 2015 and for the year ended December 31, 2014 include reclassifications required to conform Eagle Rock’s revenue and expense items to Vanguard’s presentation as follows:

(j) Represents the reclassification of Eagle Rock’s natural gas, natural gas liquids, oil, condensate and sulfur revenues to conform to Vanguard’s oil sales, natural gas sales and NGLs sales presentation.

(k) Represents the reclassification of Eagle Rock’s other income sales to conform to Vanguard’s natural gas product sales presentation.

(l) Represents the reclassification of Eagle Rock’s income on short term investments to conform to Vanguard’s presentation.

Adjustments (m) − (q) to the unaudited pro forma combined statements of operations for the nine months ended September 30, 2015 and for the year ended December 31, 2014 are to reflect the merger with Eagle Rock.

(m) Represents the change in depreciation, depletion and amortization primarily resulting from the pro forma calculation of the combined entity’s depletion expense under the full cost method of accounting for oil and natural gas properties.

(n) Represents the change in accretion expense using Vanguard’s asset retirement obligations estimates.

(o) Represents the elimination of certain general and administrative expenses resulting from Eagle Rock not being a separate public company after the completion of the Merger, including NASDAQ listing fees and SEC filing fees.

(p) Represents the adjustment to interest expense arising from borrowings under Vanguard’s reserve-based credit facility used to terminate Eagle Rock’s credit agreement and term loan agreement and the extinguishment of the

related debt outstanding. Interest expense recorded by Eagle Rock included interest for its senior notes and revolving credit facility. We eliminated the interest expense recorded by Eagle Rock related to the revolving credit facility only and calculated pro forma interest expense. Since Eagle Rock had a more significant debt balance in 2014, we applied Vanguard’s monthly variable interest rate, which ranged from 1.9% to 2.17% in 2014, and 2.18% to 2.45% in 2015, to Eagle Rock’s monthly outstanding balance to calculate the pro forma interest expense adjustment. The effect on net income of a 1/8 percent variance in interest rates would be $0.3 million and $1.2 million for the nine months ended September 30, 2015 and for the year ended December 31, 2014, respectively.

(q) Represents the adjustment for the weighted average number of units from the issuance of approximately 28.26 million Vanguard common units under the terms of the Eagle Rock merger, whereby Eagle Rock’s public unitholders received 0.185 Vanguard common units for each Eagle Rock common unit held at closing. Since the combined results of operations after giving effect to the merger and the Eagle Rock merger results in a net loss, 0.43 million Vanguard phantom units were excluded from the calculation of pro forma diluted earnings per unit due to their anti-dilutive effect.

Note 4 Adjustments for Pinedale and Piceance Acquisitions

On January 31, 2014, Vanguard and its wholly owned subsidiary, Encore Energy Partners Operating, LLC, completed the acquisition of certain natural gas and oil assets in the Pinedale and Jonah fields located in Southwestern Wyoming for approximately $555.6 million in cash (the ‘‘Pinedale Acquisition’’), and, on September 30, 2014, Vanguard and its wholly owned subsidiary, Vanguard Operating, LLC, completed the acquisition of natural gas, oil and NGL assets in the Piceance Basin located in Colorado for approximately $496.4 million (the ‘‘Piceance Acquisition’’).

The Vanguard As Adjusted column in the Unaudited Pro Forma Combined Statement of Operations Data for Year Ended December 31, 2014 presented above, incorporates the following financial information related to the Pinedale Acquisition and the Piceance Acquisition:

(in thousands, except per unit data)	Vanguard Historical			Pinedale Acquisition Adjustments				Piceance Acquisition Adjustments				Vanguard Pro forma
Revenues:
Oil sales	$	268,685		$	2,145		(a)	$	15,088		(f)	$	285,918
Natural gas sales	285,439			8,533			(a)	57,432			(f)	351,404
NGLs sales	70,489			3,581			(a)	27,239			(f)	101,309
Net losses on commodity derivative contracts	163,452			—				—				163,452
Total revenues	788,065			14,259				99,759				902,083
Costs and expenses:
Production:
Lease operating expenses	132,515			4,178			(b)	13,072			(g)	149,765
Production and other taxes	61,874			1,607			(b)	5,268			(g)	68,749
Depreciation, depletion, amortization and accretion	226,937			5,904			(c)	34,250			(h)	267,091
Impairment of oil and natural gas properties	234,434			(5,904		)	(c)	(34,250		)	(h)	194,280
Selling, general and administrative expenses	30,839			—				—				30,839
Total costs and expenses	686,599			5,785				18,340				710,724
Income from operations	101,466			8,474				81,419				191,359
Other income (expense):
Interest expense	(69,765		)	(988		)	(d)	(8,241		)	(i)	(78,994		)
Net losses on interest rate derivative contracts	(1,933		)	—				—				(1,933		)
Gain on acquisition of oil and natural gas properties	34,523			(32,114		)	(e)	427			(j)	2,836
Other	54			—				—				54
Total other expense	(37,121		)	(33,102		)		(7,814		)		(78,037		)
Net income (loss)	64,345			(24,628		)		73,605				113,322
Less: Distributions to Preferred unitholders	(18,197		)	—				—				(18,197		)
Net income (loss) attributable to Common and Class B unitholders	$	46,148		$	(24,628	)		$	73,605			$	95,125
Net income per Common and Class B unit:
Basic	$	0.56										$	1.16
Diluted	$	0.55										$	1.14
Weighted average units outstanding:
Common units – basic	81,611											81,611
Common units – diluted	82,039											82,039
Class B units – basic & diluted	420											420

The measurement of the fair value at acquisition date of the assets acquired in the Pinedale Acquisition as compared to the fair value of consideration transferred, adjusted for purchase price adjustments, resulted in a gain of $32.1 million, as reflected in the table below, primarily due to the increase in natural gas prices between the date the purchase and sale agreement was entered into and the closing date.

Fair value of assets and liabilities acquired:	(in thousands)
Oil and natural gas properties	$	600,123
Inventory	244
Asset retirement obligations	(12,404		)
Imbalance liabilities	(171		)
Other	(125		)
Total fair value of assets and liabilities acquired	587,667
Fair value of consideration transferred	555,553
Gain on acquisition	$	32,114

The measurement of the fair value at acquisition date of the assets acquired in the Piceance Acquisition as compared to the fair value of consideration transferred, adjusted for purchase price adjustments, resulted in goodwill of $0.4 million, calculated in the following table, which was immediately impaired and recorded as a loss in current period earnings. The loss resulted primarily from the changes in oil and natural gas prices between the date the purchase and sale agreement was entered into and the closing date, which were used to value the reserves acquired.

Fair value of assets and liabilities acquired:	(in thousands)
Oil and natural gas properties	$	523,537
Asset retirement obligations	(19,452		)
Production and ad valorem taxes payable	(7,552		)
Suspense liabilities	(445		)
Other	(124		)
Total fair value of assets and liabilities acquired	495,964
Fair value of consideration transferred	496,391
Loss on acquisition	$	(427	)

The unaudited pro forma combined statement of operations for the year ended December 31, 2014 include adjustments to reflect the following:

(a) Represents the increase in oil, natural gas and natural gas liquids sales resulting from the Pinedale Acquisition.

(b) Represents the increase in lease operating expenses and production and other taxes resulting from the Pinedale Acquisition.

(c) Represents the increase in depreciation, depletion, amortization and accretion resulting from the Pinedale Acquisition and the corresponding reduction in the impairment recognized in the fourth quarter of 2014.

(d) Represents the pro forma interest expense related to borrowings under the reserve-based credit facility to fund the Pinedale Acquisition.

(e) Represents the elimination of the nonrecurring gain from the acquisition of oil, natural gas and natural gas liquids properties in the Pinedale Acquisition.

(f) Represents the increase in oil, natural gas and natural gas liquids sales resulting from the Piceance Acquisition.

(g) Represents the increase in lease operating expenses and production and other taxes resulting from the Piceance Acquisition.

(h) Represents the increase in depreciation, depletion, amortization and accretion resulting from the Piceance Acquisition and the corresponding reduction in the impairment recognized in the fourth quarter of 2014.

(i) Represents the pro forma interest expense related to borrowings under the reserve-based credit facility to fund the Piceance Acquisition.

(j) Represents the elimination of the nonrecurring loss from the impairment of the goodwill recognized in the acquisition of oil, natural gas and natural gas liquids properties in the Piceance Acquisition.

Note 5 Supplemental Oil and Gas Information (Unaudited)

The following tables set forth summary pro forma information with respect to Vanguard’s pro forma combined estimated net proved and proved developed natural gas, oil and natural gas liquids reserves for the year ended December 31, 2014. The pro forma information for the year ended December 31, 2014 gives effect to the Pinedale Acquisition, the Piceance Acquisition, the LRE Merger, and the Eagle Rock Merger as if they occurred on January 1, 2014. Future

exploration, exploitation and development expenditures, as well as future commodity prices and service costs, will affect the reserve volumes attributable to the acquired properties and the standardized measure of discounted future net cash flows.

The completion of the Eagle Rock merger is not a condition to the completion of the merger and there can be no assurance that the transactions contemplated by the Eagle Rock merger agreement will be completed.

Estimated changes in the quantities of natural gas, oil and natural gas liquids reserves for the year ended December 31, 2014 are as follows:

	Natural Gas (in MMcf)
	Vanguard Historical		Pinedale Acquisition Adjustments		Piceance Acquisition Adjustments		Pro Forma Adjustments(a)		Vanguard As Adjusted		LRE Historical		Eagle Rock Historical		Vanguard/LRE/Eagle Rock Pro forma Combined
Net proved reserves
January 1, 2014	586,489		573,755		294,000		—		1,454,244		92,622		177,226		1,724,092
Revisions of previous estimates	(66,797	)	52,272		(12,679	)	—		(27,204	)	7,484		(19,897	)	(39,617	)
Extensions, discoveries and other	2,927		—		—		—		2,927		1,138		22,990		27,055
Purchases of reserves	1,036,285		—		—		(889,961	)	146,324		1,948		769		149,041
Production	(83,037	)	(29,478	)	(19,799	)	31,890		(100,424	)	(6,467	)	(11,995	)	(118,886	)
December 31, 2014	1,475,867		596,549		261,522		(858,071	)	1,475,867		96,725		169,093		1,741,685

	Oil (in MBbls)
	Vanguard Historical		Pinedale Acquisition Adjustments		Piceance Acquisition Adjustments		Pro Forma Adjustments(a)		Vanguard As Adjusted		LRE Historical		Eagle Rock Historical		Vanguard/LRE/Eagle Rock Pro forma Combined
Net proved reserves
January 1, 2014	45,316		4,852		2,477		—		52,645		10,698		13,542		76,885
Revisions of previous estimates	(2,910	)	585		(83	)	—		(2,408	)	434		(2,618	)	(4,592	)
Extensions, discoveries and other	465		—		—		—		465		573		1,080		2,118
Purchases of reserves	12,873		—		—		(7,640	)	5,233		2,305		326		7,864
Sales of reserves in place	(2,394	)	—		—		—		(2,394	)	—		—		(2,394	)
Production	(3,301	)	(270	)	(216	)	295		(3,492	)	(904	)	(1,313	)	(5,709	)
December 31, 2014	50,049		5,167		2,178		(7,345	)	50,049		13,106		11,017		74,172

	Natural Gas Liquids (in MBbls)
	Vanguard Historical		Pinedale Acquisition Adjustments		Piceance Acquisition Adjustments		Pro Forma Adjustments(a)		Vanguard As Adjusted		LRE Historical		Eagle Rock Historical		Vanguard/LRE/Eagle Rock Pro forma Combined
Net proved reserves
January 1, 2014	29,195		20,044		12,340		—		61,579		3,969		14,637		80,185
Revisions of previous estimates	(10,769	)	(5,752	)	(828	)	—		(17,349	)	635		(2,039	)	(18,753	)
Extensions, discoveries and other	22		—		—		—		22		182		2,224		2,428
Purchases of reserves	26,840		—		—		(24,740	)	2,100		198		170		2,468
Production	(2,759	)	(1,243	)	(1,186	)	1,365		(3,823	)	(366	)	(1,158	)	(5,347	)
December 31, 2014	42,529		13,049		10,326		(23,375	)	42,529		4,618		13,834		60,981

(a) To adjust the amount of purchases of reserves representing the Pinedale Acquisition and Piceance Acquisition during 2014 included in Vanguard’s historical information. The pro forma effect of each acquisition is presented separately in the table above.

Estimated quantities of natural gas, oil and natural gas liquids reserves as of December 31, 2014 are as follows:

	Vanguard Historical(a)	LRE Historical	Eagle Rock Historical	Vanguard/LRE/Eagle Rock Pro Forma Combined(c)
Estimated proved reserves:
Natural Gas (MMcf)	1,475,867	96,725	169,093	1,741,685
Oil (MBbls)	50,049	13,106	11,017	74,172
Natural Gas Liquids (MBbls)	42,529	4,618	13,834	60,981
MMcfe	2,031,335	203,069	318,199	2,552,603

Estimated proved developed reserves:
Natural Gas (MMcf)	970,714	88,265	126,783	1,185,762
Oil (MBbls)	39,143	10,962	9,595	59,700
Natural Gas Liquids (MBbls)	28,678	3,956	10,895	43,529
MMcfe	1,377,640	177,773	249,723	1,805,136

(a) The historical standardized measure includes Vanguard, the Pinedale Acquisition and the Piceance Acquisition as of December 31, 2014.

(b) Includes Vanguard’s, the Pinedale Acquisition’s, the Piceance Acquisition’s and LRE’s estimated net proved and proved developed oil, natural gas and natural gas liquids reserves as of December 31, 2014.

(c) Includes Vanguard’s, the Pinedale Acquisition’s, the Piceance Acquisition’s, LRE’s and Eagle Rock’s estimated net proved and proved developed oil, natural gas and natural gas liquids reserves as of December 31, 2014.

The standardized measure of discounted future net cash flows relating to the combined proved oil, natural gas and natural gas liquids reserves at December 31, 2014 is as follows (in thousands):

	Vanguard Historical(a)			LRE Historical			Eagle Rock Historical			Vanguard/LRE/Eagle Rock Pro Forma Combined(c)
Future cash inflows	$	11,225,973		$	1,749,346		$	2,187,346		$	15,162,665
Future production costs	(3,999,460		)	(688,333		)	(760,799		)	(5,448,592		)
Future development costs	(845,872		)	(117,473		)	(240,886		)	(1,204,231		)
Future net cash flows	6,380,641			943,540			1,185,661			8,509,842
10% annual discount for estimated timing of cash flows	(3,404,914		)	(501,869		)	(591,421		)	(4,498,204		)
Standard measure of discounted future cash flows	$	2,975,727		$	441,671		$	594,240		$	4,011,638

(a) The historical standardized measure includes Vanguard, the Pinedale Acquisition and the Piceance Acquisition.

For the December 31, 2014 calculations in the preceding table, estimated future cash inflows from estimated future production of proved reserves were computed using the average oil and natural gas price based upon the 12-month average price of $94.87 and $94.99 per barrel of crude oil and $4.36 and $4.35 per MMBtu for natural gas for Vanguard Historical and LRE, respectively, adjusted for quality, transportation fees and a regional price differential, and the volume-weighted average price of $35.35 and $33.11 per barrel of natural gas liquids for Vanguard Historical and LRE, respectively. The natural gas liquids prices were calcu- lated using the differentials for each property to West Texas Intermediate reference price of $94.87 and $94.99 for Vanguard Historical and LRE, respectively. Vanguard may receive amounts different than the standardize measure of discounted cash flow for a number of reasons, including price changes and the effects of Vanguard’s hedging activities.

The following are the principal sources of change in the combined standardized measure of discounted future net cash flows on a pro forma basis for the year ended December 31, 2014 (in thousands):

	Vanguard Historical			Pinedale Acquisition Adjustments			Piceance Acquisition Adjustments			Pro Forma Adjustments(a)			Vanguard As Adjusted			LRE Historical			Eagle Rock Historical			Vanguard/LRE/Eagle Rock Pro forma Combined(b)
Sales and transfers, net of production costs	$	(430,224	)	$	(116,408	)	$	(96,653	)	$	123,169		$	(520,116	)	$	(81,986	)	$	(152,097	)	$	(754,199	)
Net changes in prices and production costs	11,138			311,334			(132,576		)	—			189,896			584			(63,142		)	127,338
Extensions discoveries and improved recovery, less related costs	24,841			—			—			—			24,841			17,979			74,684			117,504
Changes in estimated future development costs	36,564			(115,401		)	(13,728		)	—			(92,565		)	(11,897		)	71,800			(32,662		)
Previously estimated development costs incurred during the period	68,817			74,685			352			—			143,854			27,073			49,409			220,336
Revision of previous quantity estimates	(292,454		)	26,854			(20,726		)	—			(286,326		)	30,256			(149,993		)	(406,063		)
Accretion of discount	183,397			46,010			53,471						282,878			39,313			59,818			382,009
Purchases of reserves in place	1,621,571			—			—			(1,257,662		)	363,909			45,665			11,904			421,478
Sales of reserves	(48,163		)	—			—			—			(48,163		)	—			—			(48,163		)
Change in production rates, timing and other	(33,731		)	57,008			65,465			—			88,742			(17,873		)	41,351			112,220
Net change in standardized measure	1,141,756			284,082			(144,395		)	(1,134,493		)	146,950			49,114			(56,266		)	139,798
Standardized measure, January 1, 2014	1,833,971			460,099			534,707			—			2,828,777			392,557			650,506			3,871,840
Standardized measure, December 31, 2014	$	2,975,727		$	744,181		$	390,312		$	(1,134,493	)	$	2,975,727		$	441,671		$	594,240		$	4,011,638

(a) To adjust the amount of purchases of reserves representing the Pinedale Acquisition and Piceance Acquisition during 2014 included in Vanguard’s historical information. The pro forma effect of each acquisition is presented separately in the table above.

(b) The pro forma standardized measure includes Vanguard, the Pinedale Acquisition, the Piceance Acquisition, the LRE Merger and the Eagle Rock Merger.