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): October 9, 2015 (October 8, 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 (the “SEC”) by Vanguard Natural Resources, LLC, a Delaware limited liability company (“Vanguard”) on October 8, 2015 (the “Original 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 “Merger Agreement”), by and among Vanguard, Talon Merger Sub, LLC, a wholly owned indirect subsidiary of Vanguard (“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 Merger Agreement, Merger Sub was merged with and into Eagle Rock with Eagle Rock continuing as the surviving entity and as a wholly owned indirect subsidiary of Vanguard (the “Merger”).

The 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 Merger Agreement and the Merger and (ii) approval by Vanguard unitholders, at Vanguard’s 2015 Annual Meeting of unitholders, of the issuance of common units representing limited liability company interests in Vanguard (“Vanguard Common Units”) to be issued as merger consideration to the holders of Eagle Rock Common Units in connection with the Merger. As a result of the 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 amend Item 9.01 of the Original Form 8-K to provide the required audited and unaudited financial statements of Eagle Rock.

Item 9.01    Financial Statements and Exhibits

(a) Financial Statements of Businesses Acquired.

The audited consolidated balance sheets of Eagle Rock as of December 31, 2014 and 2013 and the annual consolidated statement of operations, consolidated statements of comprehensive income, consolidated statements of members’ equity, and consolidated statements of cash flows of Eagle Rock for each of the years ended December 31, 2014, 2013 and 2012, and the notes related thereto, are attached hereto as Exhibit 99.1 and incorporated herein by reference.

The report of Independent Registered Public Accounting Firm, issued by KPMG LLP, dated March 2, 2015 relating to Eagle Rock’s financial statements described above, is attached hereto as Exhibit 99.2 and incorporated herein by reference.

The unaudited condensed consolidated balance sheets of Eagle Rock as of June 30, 2015 and December 31, 2014, the unaudited condensed consolidated statements of operations and comprehensive income for the three and six months ended June 30, 2015 and 2014, the unaudited condensed consolidated statement of members’ equity for the six months ended June 30, 2015, the unaudited condensed consolidated statements of cash flows for the six months ended June 30, 2015 and 2014, and the notes related thereto, are attached hereto as Exhibit 99.3 and incorporated by reference herein.

The financial statements of Eagle Rock attached hereto as Exhibit 99.1 and Exhibit 99.3 are identical to the

financial statements of Eagle Rock incorporated by reference into Vanguard’s Registration Statement on Form S-4 (File No. 333-204982) filed with the SEC on August 31, 2015.

(b) Pro Forma Financial Information.

The pro forma financial information required by this item will be filed by amendment to this Current Report on Form 8-K/A within 71 calendar days after the date on which the Original Form 8-K was required to be filed.

(d) Exhibits.

Exhibit Number	Description
Exhibit 23.1	Consent of KPMG LLP
Exhibit 23.2	Consent of Cawley, Gillespie & Associates, Inc.
Exhibit 99.1	The audited consolidated balance sheets of Eagle Rock Energy Partners, L.P. as of December 31, 2014 and 2013, and the annual consolidated statement of operations, consolidated statements of comprehensive income, consolidated statements of members’ equity, and consolidated statements of cash flows of Eagle Rock Energy Partners, L.P. for each of the years ended December 31, 2014, 2013 and 2012, and the notes related thereto
Exhibit 99.2	Report of Independent Registered Public Accounting Firm, issued by KPMG LLP, dated March 2, 2015, relating to those Eagle Rock Energy Partners, L.P. financial statements described in Exhibit 99.1
Exhibit 99.3	The unaudited condensed consolidated balance sheets of Eagle Rock Energy Partners, L.P. as of June 30, 2015 and December 31, 2014, the unaudited condensed consolidated statements of operations and comprehensive income for the three and six months ended June 30, 2015 and 2014, the unaudited condensed consolidated statement of members’ equity for the six months ended June 30, 2015, the unaudited condensed consolidated statements of cash flows for the six months ended June 30, 2015 and 2014, and the notes related thereto

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: October 9, 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 23.1	Consent of KPMG LLP
Exhibit 23.2	Consent of Cawley, Gillespie & Associates, Inc.
Exhibit 99.1	The audited consolidated balance sheets of Eagle Rock Energy Partners, L.P. as of December 31, 2014 and 2013, and the annual consolidated statement of operations, consolidated statements of comprehensive income, consolidated statements of members’ equity, and consolidated statements of cash flows of Eagle Rock Energy Partners, L.P. for each of the years ended December 31, 2014, 2013 and 2012, and the notes related thereto
Exhibit 99.2	Report of Independent Registered Public Accounting Firm, issued by KPMG LLP, dated March 2, 2015, relating to those Eagle Rock Energy Partners, L.P. financial statements described in Exhibit 99.1
Exhibit 99.3	The unaudited condensed consolidated balance sheets of Eagle Rock Energy Partners, L.P. as of June 30, 2015 and December 31, 2014, the unaudited condensed consolidated statements of operations and comprehensive income for the three and six months ended June 30, 2015 and 2014, the unaudited condensed consolidated statement of members’ equity for the six months ended June 30, 2015, the unaudited condensed consolidated statements of cash flows for the six months ended June 30, 2015 and 2014, and the notes related thereto

EX-23.1

Exhibit 23.1

KPMG LLP 811 Main Street Houston, TX 77002

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in (i) the Registration Statement on Form S-3 of Vanguard Natural Resources, LLC, filed with the Securities and Exchange Commission on February 13, 2015 (File No. 333-202064) and (ii) the Registration Statement on Form S-8 of Vanguard Natural Resources, LLC, filed with the Securities and Exchange Commission on July 24, 2013 (File No. 333-190102) of our reports dated March 2, 2015, with respect to the consolidated balance sheets of Eagle Rock Energy Partners, L.P. as of December 31, 2014 and 2013, and the related consolidated statements of operations, comprehensive income, members’ equity, and cash flows for each of the years in the three-year period ended December 31, 2014, which appear in this Current Report on Form 8-K of Vanguard Natural Resources, LLC.

/s/ KPMG LLP

KPMG LLP

Houston, Texas

October 8, 2015

EX-23.2

Exhibit 23.2

CONSENT OF CAWLEY, GILLESPIE & ASSOCIATES, INC.

We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-202064) and the Registration Statement on Form S-8 (No. 333-190102) of Vanguard Natural Resources, LLC of the Annual Report on Form 10-K of Eagle Rock Energy Partners, L.P. for the year ended December 31, 2014, which uses the name Cawley, Gillespie & Associates, Inc., refers to Cawley, Gillespie & Associates, Inc., and incorporates information contained in our letter dated March 2, 2015, as of the year ended December 31, 2014, on the proved oil, natural gas liquids, and natural gas reserves of Eagle Rock Energy Partners, L.P. dated February 11, 2015. We further consent to all references to our firm and information from the report appearing in this Current Report on Form 8-K of Vanguard Natural Resources, LLC.

Very truly yours,

/s/ Cawley, Gillespie & Associates, Inc.

Cawley, Gillespie & Associates, Inc.

Fort Worth, Texas

October 8, 2015

EX-99.1

Exhibit 99.1

EAGLE ROCK ENERGY PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

AS OF DECEMBER 31, 2014 AND 2013

(In thousands, except unit amounts)

	December 31, 2014		December 31, 2013
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	1,343	$	76
Short-term investments	153,448		—
Accounts receivable (a)	39,596		17,250
Risk management assets	44,805		5,559
Prepayments and other current assets	9,911		6,123
Assets held for sale	—		1,259,382
Total current assets	249,103		1,288,390
PROPERTY, PLANT AND EQUIPMENT — Net	487,988		824,451
INTANGIBLE ASSETS — Net	3,072		3,268
DEFERRED TAX ASSET	2,315		1,438
RISK MANAGEMENT ASSETS	46,490		3,871
OTHER ASSETS	5,307		6,132
TOTAL	$	794,275	$	2,127,550
LIABILITIES AND MEMBERS' EQUITY
CURRENT LIABILITIES:
Accounts payable	$	49,226	$	50,158
Accrued liabilities	8,053		23,162
Taxes payable	2,246		149
Risk management liabilities	—		8,360
Liabilities held for sale	—		637,738
Total current liabilities	59,525		719,567
LONG-TERM DEBT	263,343		757,480
ASSET RETIREMENT OBLIGATIONS	47,907		37,306
DEFERRED TAX LIABILITY	30,321		34,097
RISK MANAGEMENT LIABILITIES	—		2,826
OTHER LONG TERM LIABILITIES	4,709		2,395
COMMITMENTS AND CONTINGENCIES (Note 13)
MEMBERS' EQUITY (b)	388,470		573,879
TOTAL	$	794,275	$	2,127,550

________________________ 

(a) Net of allowance for bad debt of $1,023 as of December 31, 2014 and $931 as of December 31, 2013.

(b) 150,154,909 and 156,644,153 common units were issued and outstanding as of December 31, 2014 and December 31, 2013, respectively. These amounts do not include unvested restricted common units granted under the Partnership's long-term incentive plan of 2,419,750 and 2,743,807 as of December 31, 2014 and December 31, 2013, respectively.

See accompanying notes to consolidated financial statements.  

1

EAGLE ROCK ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF OPERATIONS

FOR THE YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012

(In thousands, except per unit amounts)

	Year Ended December 31,
	2014			2013			2012
REVENUE:
Natural gas, natural gas liquids, oil, condensate, and sulfur	$	203,792		$	200,608		$	201,719
Commodity risk management gains (losses), net	94,431			(3,937		)	28,110
Other revenue	(19		)	701			1,486
Total revenue	298,204			197,372			231,315
COSTS AND EXPENSES:
Operations and maintenance	43,670			41,426			41,391
Taxes other than income	12,925			12,928			15,343
General and administrative	47,193			53,131			50,990
Impairment and other	395,892			214,286			45,289
Depreciation, depletion and amortization	85,579			89,444			90,510
Total costs and expenses	585,259			411,215			243,523
OPERATING LOSS	(287,055		)	(213,843		)	(12,208		)
OTHER (EXPENSE) INCOME:
Interest expense, net	(15,247		)	(18,789		)	(16,276		)
Interest rate risk management losses, net	(1,734		)	(1,104		)	(4,727		)
Loss on short-term investments	(62,028		)	—			—
Other income (expense), net	8,294			(30		)	(28		)
Total other (expense) income	(70,715		)	(19,923		)	(21,031		)
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(357,770		)	(233,766		)	(33,239		)
INCOME TAX BENEFIT	(5,403		)	(5,595		)	(1,093		)
LOSS FROM CONTINUING OPERATIONS	(352,367		)	(228,171		)	(32,146		)
DISCONTINUED OPERATIONS, NET OF TAX	212,460			(49,808		)	(118,456		)
NET LOSS	$	(139,907	)	$	(277,979	)	$	(150,602	)

NET LOSS PER COMMON UNIT—BASIC AND DILUTED:
Loss from Continuing Operations
Common units - Basic	$	(2.25	)	$	(1.50	)	$	(0.26	)
Common units - Diluted	$	(2.25	)	$	(1.50	)	$	(0.26	)
Discontinued Operations
Common units - Basic	$	1.36		$	(0.32	)	$	(0.87	)
Common units - Diluted	$	1.36		$	(0.32	)	$	(0.87	)
Net Loss
Common units - Basic	$	(0.89	)	$	(1.82	)	$	(1.13	)
Common units - Diluted	$	(0.89	)	$	(1.82	)	$	(1.13	)
Weighted Average Units Outstanding (in thousands)
Common units - Basic	156,700			153,562			135,609
Common units - Diluted	156,700			153,562			135,609

See accompanying notes to consolidated financial statements.  

2

EAGLE ROCK ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

FOR THE YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012

(In thousands)

	Year Ended December 31,
	2014		2013		2012
Net loss	(139,907	)	(277,979	)	(150,602	)
Other comprehensive income:
Gain on short-term investments	3,381		—		—
(Loss) on short-term investments	(3,381	)	—		—
COMPREHENSIVE LOSS	(139,907	)	(277,979	)	(150,602	)

See accompanying notes to consolidated financial statements.  

3

EAGLE ROCK ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF MEMBERS’ EQUITY

FOR THE YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012

(in thousands, except unit amounts)

	Number of Common Units		Common Units			Total
BALANCE — January 1, 2012	127,606,229		$	1,007,347		$	1,007,347
Net loss	—		(150,602		)	(150,602		)
Distributions	—		(119,211		)	(119,211		)
Vesting of restricted units	1,101,323		—			—
Exercised warrants	5,300,588		31,804			31,804
Repurchase of common units	(286,716	)	(2,501		)	(2,501		)
Equity based compensation	—		9,882			9,882
Common units issued in equity offering	10,954,327		96,173			96,173
Unit issuance costs for equity offering	—		(4,518		)	(4,518		)
BALANCE — December 31, 2012	144,675,751		868,374			868,374
Net loss	—		(277,979		)	(277,979		)
Distributions	—		(125,911		)	(125,911		)
Vesting of restricted units	1,203,822		—			—
Repurchase of common units	(272,179	)	(1,858		)	(1,858		)
Equity based compensation	—		13,384			13,384
Common units issued in equity offering	11,036,759		102,388			102,388
Unit issuance costs for equity offering	—		(4,519		)	(4,519		)
BALANCE — December 31, 2013	156,644,153		573,879			573,879
Net loss	—		(139,907		)	(139,907		)
Distributions	—		(34,982		)	(34,982		)
Vesting of restricted units	1,305,433		—			—
Repurchase of common units	(7,794,677	)	(20,505		)	(20,505		)
Equity based compensation	—		9,985			9,985
BALANCE — December 31, 2014	150,154,909		$	388,470		$	388,470

 See accompanying notes to consolidated financial statements.  

F- 6

EAGLE ROCK ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012

($ in thousands)

	Year Ended December 31,
	2014			2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES:
Net (loss) income	$	(139,907	)	$	(277,979	)	$	(150,602	)
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Discontinued operations	(212,460		)	49,808			118,456
Depreciation, depletion and amortization	85,579			89,444			90,510
Impairment and other	395,892			214,286			45,289
Amortization of debt issuance costs	2,241			2,151			1,735
Loss (gain) from risk management activities, net	(92,697		)	5,041			(23,383		)
Derivative settlements	4,669			7,478			5,368
Equity-based compensation	8,198			10,392			7,719
(Gain) loss on sale of assets	—			(76		)	—
Loss on short-term investments	62,028			—			—
Other	(2,574		)	(1,197		)	(592		)
Changes in assets and liabilities—net of acquisitions:
Accounts receivable	(20,428		)	14,280			(26,742		)
Prepayments and other current assets	(3,788		)	1,838			2,087
Risk management activities	—			—			(6,607		)
Accounts payable	(5,023		)	1,738			14,198
Accrued liabilities	(4,138		)	(964		)	2,519
Other assets	(6		)	143			(2,985		)
Other current liabilities	540			(2,140		)	(1,634		)
Net cash provided by operating activities	78,126			114,243			75,336
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment	(136,694		)	(149,944		)	(167,907		)
Proceeds from sale of assets	—			76			15,398
Proceeds from sale of short-term investments	43,836			—			—
Net cash used in investing activities	(92,858		)	(149,868		)	(152,509		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	472,500			601,400			1,043,750
Repayment of long-term debt	(966,700		)	(503,100		)	(916,750		)
Proceeds from senior notes	—			—			22,889
Payment of debt issuance costs	(1,984		)	—			(614		)
Proceeds from derivative contracts	(5,022		)	1,323			14,449
Common units issued in equity offerings	—			102,388			96,173
Issuance costs for equity offerings	—			(4,519		)	(4,518		)
Exercise of warrants	—			—			31,804
Repurchase of common units	(19,170		)	(1,858		)	(2,501		)
Distributions to members and affiliates	(34,982		)	(125,911		)	(119,211		)
Net cash (used in) provided by financing activities	(555,358		)	69,723			165,471
CASH FLOWS FROM DISCONTINUED OPERATIONS:
Operating activities	31,098			63,133			70,165
Investing activities	540,259			(97,180		)	(376,161		)
Financing activities	—			—			216,846
Net cash provided by (used in) discontinued operations	571,357			(34,047		)	(89,150		)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	1,267			51			(852		)
CASH AND CASH EQUIVALENTS—Beginning of period	76			25			877
CASH AND CASH EQUIVALENTS—End of period	$	1,343		$	76		$	25
NONCASH INVESTING AND FINANCING ACTIVITIES:
Units received in divestiture	$	265,599		$	—		$	—
Investments in property, plant and equipment, not paid	$	12,154		$	9,469		$	29,568
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Interest paid—net of amounts capitalized	$	43,705		$	65,309		$	45,614
Cash paid for taxes	$	—		$	59		$	1,085

See accompanying notes to consolidated financial statements.

F- 7

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2014, 2013 AND 2012

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, 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 natural gas liquids ("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"). The consideration received by the Partnership pursuant to the Midstream Business Contribution included: (i) $576.2 million of cash; (ii) 8,245,859 Regency common units (valued at approximately$265.6 million based on the closing price of Regency common units on June 30, 2014) and (iii) the exchange of $498.9 million face amount of the Partnership's outstanding unsecured senior notes ("Senior Notes") for an equivalent amount of Regency unsecured senior notes. $51.1 million of the Partnership's Senior Notes did not exchange and remain outstanding under an amended indenture with substantially all of the restrictive covenants and certain events of default eliminated.

Accordingly, prior periods have been retrospectively adjusted to reflect the Midstream Business's assets and liabilities as held-for-sale and operations as discontinued (see Note 18) 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, both of which are wholly-owned subsidiaries of the Partnership.

NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation and Principles of Consolidation—The accompanying audited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP").

All intercompany accounts and transactions are eliminated in the 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.

Cash and Cash Equivalents—Cash and cash equivalents include certificates of deposit and other highly liquid investments with maturities of three months or less at the time of purchase.

Short-term Investments— A portion of the consideration received for the Midstream Business Contribution included Regency common units, as further described in Note 1. These common units have a readily determinable fair value, are being classified as available-for-sale equity securities and are recorded as short-term investments on the 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 consolidated statements of operations. Losses from declines in fair value determined to be other than temporary are recorded in the consolidated statement of operations. This loss is included in the consolidated statement of operations as a loss on short-term investments. Distributions received from Regency as a result of holding these common units are recorded as other income on the consolidated statement of operations. For the twelve months ended December 31, 2014, the Partnership received and recorded distributions from Regency of $8.0 million. During the fourth quarter of 2014, the Partnership recorded a $62.0 million loss associated with losses as the result of sale of common units and the decrease in the fair value of these securities that

F- 8

was deemed to be other than temporary and the sale of common units. As of December 31, 2014, the Partnership still held 6,393,657 Regency common units, which does not include the transactions to sell 262,496 Regency common units that had not settled as of December 31, 2014 and for which a receivable of $6.3 million was recorded as part accounts receivable in the consolidated balance sheet.

Concentration and Credit Risk—Concentration and credit risk for the Partnership principally consists of cash and cash equivalents and accounts receivable.

The Partnership places its cash and cash equivalents with high-quality institutions and in money market funds. The Partnership derives its revenue from customers primarily in the natural gas industry. Industry concentrations have the potential to impact the Partnership's overall exposure to credit risk, either positively or negatively, in that the Partnership's customers could be affected by similar changes in economic, industry or other conditions. However, the Partnership believes the risk posed by this industry concentration is offset by the creditworthiness of the Partnership's customer base. The Partnership's portfolio of accounts receivable is comprised primarily of mid-size to large domestic corporate entities.  

The following is the activity within the Partnership's allowance for doubtful accounts during the years ended December 31, 2014, 2013 and 2012.

	2014			2013			2012
($ in thousands)
Balance at beginning of period	$	931		$	753		$	670
Charged to bad debt expense	249			458			175
Write-offs/adjustments charged to allowance	(157		)	(280		)	(92		)
Balance at end of period	$	1,023		$	931		$	753

The table above does not include amounts related to the Partnership's Midstream Business, as these amounts have been classified as part of assets held for sale within the audited consolidated balance sheets and discontinued operations within the audited consolidated statements of operations (see Note 18).

Certain Other Concentrations—For the year ended December 31, 2014, NGL Energy Partners LP, CVR Refining, LP and Oneok Partners, LP, the Partnership's largest customers, represented 15%, 12% and 11%, respectively, of its total sales revenue (excluding its commodity risk management gains and losses and revenue amounts classified as part of discontinued operations).

Inventory—Inventory is stated at the lower of cost or market, with cost being determined using the average cost method. At December 31, 2013, the Partnership had $1.0 million of crude oil finished goods inventory, which is recorded as part of assets held for sale within the audited consolidated balance sheet.

Property, Plant and Equipment—Property, plant and equipment, including amounts classified as held for sale, consists primarily of gas gathering systems, gas processing plants, NGL pipelines, conditioning and treating facilities and other related facilities, and oil and natural gas properties, which are carried at cost less accumulated depreciation, depletion and amortization. The Partnership charges repairs and maintenance against income when incurred and capitalizes renewals and betterments, which extend the useful life or expand the capacity of the assets. The Partnership capitalizes interest costs on major projects during extended construction time periods. Such interest costs are allocated to property, plant and equipment and amortized over the estimated useful lives of the related assets. The Partnership calculates depreciation on the straight-line method over estimated useful lives of the Partnership's newly developed or acquired assets. The weighted average useful lives are as follows:

Plant assets	20 years
Pipelines and equipment	20 years
Gas processing and equipment	20 years
Office furniture and equipment	5 years

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Plant assets, pipelines and equipment, gas process and equipment and certain office furniture and equipment related to the Partnership's Midstream Business have been classified as assets held for sale within the audited consolidated balance sheets. Depreciation expense related to these assets has been recorded as part of discontinued operations within the audited consolidated statements of operations (see Note 18).

Oil and Natural Gas Properties—The Partnership utilizes the successful efforts method of accounting for its oil and natural gas properties. Leasehold costs are capitalized when incurred. Costs incurred to drill and complete development wells are capitalized. Geological and geophysical expenses and delay rentals are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if the well is determined to be unsuccessful. The Partnership carries the costs of an exploratory well as an asset if the well is found to have a sufficient quantity of reserves to justify its capitalization as a producing well as long as the Partnership is making sufficient progress towards assessing the reserves and the economic and operating viability of the project.

Depletion of producing oil and natural gas properties is recorded based on units of production. Unit rates are computed for unamortized drilling and development costs using proved developed reserves and for acquisition costs using all proved reserves. Authoritative guidance requires that acquisition costs of proved properties be amortized on the basis of all proved reserves (developed and undeveloped), and that capitalized development costs (wells and related equipment and facilities) be amortized on the basis of proved developed reserves.

Upon sale or retirement of complete fields of depreciable or depleted property, the book value thereof, less proceeds or salvage value, is charged or credited to income.

Costs related to unproved properties include costs incurred to acquire unproved reserves.  Because these reserves do not meet the definition of proved reserves, the related costs are not classified as proved properties.  Unproved leasehold costs are capitalized and amortized on a composite basis if individually insignificant, based on past success, experience, drilling plans and average lease-term lives.  Unamortized leasehold costs related to successful exploratory drilling are reclassified to proved properties and depleted on a units of production basis.  Unproved properties (both individually significant and insignificant) are assessed periodically within specific geographic areas and, if necessary, impairments are charged to expense.

Other Assets— As of December 31, 2014 and 2013, other assets, excluding amounts classified as held for sale (see Note 18), primarily consist of costs associated with debt issuance costs, net of amortization, of $5.3 million and $6.1 million, respectively.

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 and/or forward prices that will be produced from a field, the timing of this future production, future costs to produce the oil and natural gas, and future inflation levels.

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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 5 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 for 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 $0.3 million and $0.3 million as of December 31, 2014 and December 31, 2013.

Transportation and Exchange Imbalances—In the course of transporting natural gas and NGLs for others, the Partnership may receive for redelivery different quantities of natural gas or NGLs than the quantities actually delivered. These transactions result in transportation and exchange imbalance receivables or payables which are recovered or repaid through the receipt or delivery of natural gas or NGLs in future periods, if not subject to cash out provisions. Imbalance receivables are included in accounts receivable and imbalance payables are included in accounts payable on the audited consolidated balance sheets and marked-to-market using current market prices in effect for the reporting period of the outstanding imbalances. As of December 31, 2013, the Partnership had imbalance receivables totaling $0.7 million and imbalance payables totaling $1.6 million. All transportation and exchange imbalance receivables and imbalance payables have been classified as assets and liabilities held for sale, respectively, within the audited consolidated balance sheets. Changes in market value and the settlement of any such imbalance at a price greater than or less than the recorded imbalance results in either an upward or downward adjustment, as appropriate, to the cost of natural gas sold, and have been classified as discontinued operations within the audited consolidated statements of operations.

Environmental Expenditures—Environmental expenditures are expensed or capitalized as appropriate, depending upon the future economic benefit. Expenditures which relate to an existing condition caused by past operations and do not generate current or future revenue are expensed. Liabilities for these expenditures are recorded on an undiscounted basis when environmental assessments and/or clean-ups are probable and the costs can be reasonably estimated.

Income Taxes—Provision for income taxes is primarily applicable to the Partnership's state tax obligations under the Revised Texas Franchise Tax (the “Revised Texas Franchise Tax”) and certain federal and state tax obligations of Eagle Rock Energy Acquisition Co., Inc., Eagle Rock Acquisition Co. II, Inc., Eagle Rock Upstream Development Company, Inc. and Eagle Rock Upstream Development Company II, Inc., all of which are consolidated subsidiaries. Deferred income tax assets and liabilities are recognized for temporary differences between the assets and liabilities of the tax paying entities for financial reporting and tax purposes.

In general, legal entities that conduct business in Texas are subject to the Revised Texas Franchise Tax. In May 2006, the State of Texas expanded its pre-existing franchise tax to include limited partnerships, limited liability companies, corporations and limited liability partnerships. As a result of the change in tax law, the Partnership's tax status in the State of Texas changed from non-taxable to taxable effective with the 2007 tax year.

Since the Partnership is structured as a pass-through entity, it is not subject to federal income taxes. As a result, its partners are individually responsible for paying federal and certain income taxes on their share of the Partnership's taxable

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income. Since the Partnership does not have access to information regarding each partner's tax basis, it cannot readily determine the total difference in the basis of the Partnership's net assets for financial and tax reporting purposes.

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 purchases and sales are contracts which provide for the purchase or sale of something, other than a financial instrument or derivative instrument that 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 consolidated balance sheet at the instrument's fair value with changes in fair value reflected in the 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 consolidated statement of cash flows. See Note 11 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 period presentation. These reclassifications had no effect on the recorded net income.

NOTE 3. NEW ACCOUNTING PRONOUNCEMENTS

In February 2013, the Financial Accounting Standards Board ("FASB") issued new guidance related to obligations resulting from joint and several liability arrangements. The new guidance provides for the recognition, measurement, and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date. The amendments in this update are effective for fiscal years, and interim periods within those years, beginning after December 15, 2013 and did not have a material impact on the Partnership’s consolidated financial statements.

On April 10, 2014, the 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 its transaction to contribute its Midstream Business to Regency (see Notes 1 and 18).

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. This guidance is effective for annual reporting periods (including interim reporting periods within those periods) beginning after December 15, 2016. Early application of the guidance is not permitted. The Partnership is currently evaluating the potential impact, if any, of the adoption of this new guidance on its financial statements.

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.

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NOTE 4. ACQUISITIONS

Acquisition of Additional Working Interests

On December 9, 2014, the Partnership acquired certain additional interests in the Big Escambia Creek Field from LP 224 LLC for approximately $10.4 million. These interests are in wells in which the Partnership currently owns significant interest and are nearly 100% operated by the Partnership. The entire purchase price was allocated to proved properties.

Acquisition of Midstream Assets in the Texas Panhandle

On October 1, 2012, the Partnership completed the acquisition of two of BP America Production Company's ("BP") gas processing facilities, and the associated gathering systems, that are located in the Texas Panhandle. The aggregate purchase price of the system was $230.6 million, which the Partnership funded from borrowings under its revolving credit facility. The results of the operations of the system have been included in the consolidated financial statements since the acquisition date. The Partnership incurred $0.5 million of acquisition related expenses, which are included within discontinued operations for the year ended December 31, 2012. The Partnership incurred $0.1 million of acquisition related expenses, which are included within discontinued operations for the year ended December 31, 2013.

This acquisition was accounted for under the acquisition method of accounting. Accordingly, the Partnership conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while transaction and integration costs associated with the acquisitions were expensed as incurred. The initial accounting for the business combinations is not complete and adjustments to provisional amounts, or recognition of additional assets acquired or liabilities assumed, may occur as more detailed analyses are completed and additional information is obtained about the facts and circumstances that existed as of the acquisition dates.

The following presents the purchase price allocation for the system assets, based on estimates of fair value (in thousands):

Current assets	$	779
Property, plant, and equipment	206,849
Rights-of-way and easements	27,232
Current liabilities	(1,705		)
Asset retirement obligations	(2,600		)
	$	230,555

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 value of property, plant and equipment, rights-of-way and easements 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 property, plant and equipment include estimates of: (i) replacement costs; (ii) useful and remaining lives; (iii) physical deterioration; and (iv) functional and technical obsolescence. These inputs require significant judgments and estimates by the Partnership's management at the time of the valuation and are the most sensitive and subject to change.

Pro forma data for the year ended December 31, 2012 has been deemed to be impracticable as BP did not separately manage its gathering and processing facilities with the activities of the acquired assets being integrated (financially and operationally) within its exploration and production segment. The amounts of revenue and net income generated by the acquired processing plants and gathering systems that are included within the Partnership's audited consolidated statement of operations for the year ended December 31, 2012 are as follows.

	Revenue		Net Income
	($ in thousands)
Actual from October 1, 2012 to December 31, 2012	$	81,013	$	5,057

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Assets acquired and liabilities assumed as part of this acquisition have been classified as part of assets and liabilities held for sale within the audited consolidated balance sheets. Operations related to these assets have been classified as part of discontinued operations within the audited consolidated statements of operations.

NOTE 5. PROPERTY, PLANT AND EQUIPMENT

Fixed assets consisted of the following:

	December 31, 2014			December 31, 2013
	($ in thousands)
Equipment and machinery	$	101		$	101
Vehicles and transportation equipment	212			212
Office equipment, furniture, and fixtures	3,020			1,391
Computer equipment	13,234			12,247
Proved properties	905,622			1,156,895
Unproved properties	7,512			10,022
Construction in progress	1,195			6,636
	930,896			1,187,504
Less: accumulated depreciation, depletion and amortization	(442,908		)	(363,053		)
Net property plant and equipment	$	487,988		$	824,451

Amounts in the table above do not include the property, plant and equipment related to the Partnership's Midstream Business, as these amounts have been classified as assets held for sale within the audited consolidated balance sheets (See Note 18).

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

	Year Ended December 31,
	2014		2013		2012
	($ in thousands)
Depreciation	$	2,971	$	2,018	$	1,795
Depletion	$	80,810	$	87,230	$	88,413
Impairment expense:
Proved properties (a)	$	395,892	$	207,085	$	38,943
Unproved properties (b)	$	—	$	7,201	$	785

__________________________________

(a) During the year ended December 31, 2014, the Partnership incurred impairment charges related to certain proved properties in all of its regions due primarily to lower commodity prices, higher operating costs and lower well performance. During the year ended December 31, 2013, the Partnership incurred impairment charges related primarily to certain proved properties, primarily in the Cana Shale in the Mid-Continent region and the Permian region, due to lower reserve forecasts. During the year ended December 31, 2012, the Partnership incurred impairment charges related to its proved properties in the Barnett Shale, East Texas and Permian regions that experienced reduced cash flows resulting from lower natural gas prices and continuing high operating costs associated with gas compression.

(b) During the year ended December 31, 2013, the Partnership incurred impairment charges related to certain leaseholds in the Mid-Continent regions that we expected to expire undrilled in 2014. During the year ended December 31, 2012, the Partnership incurred impairment charges related to certain unproved property leaseholds expected to expire undrilled in 2013.

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 audited consolidated statements of operations (see Note 18).

NOTE 6. 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 obligations is estimated using valuation techniques that covert 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:

	2014			2013			2012
	($ in thousands)
Asset retirement obligations—January 1	$	48,564		$	38,991		$	26,227
Additional liabilities	237			1,076			1,400
Liabilities settled	(1,347		)	(2,240		)	(1,664		)
Revision to liabilities	168			7,654			11,146
Accretion expense	3,251			3,083			1,882
Asset retirement obligations—December 31 (a)	$	50,873		$	48,564		$	38,991

_____________________________________

(a)    As of December 31, 2014 and 2013, $3.0 million and $11.3 million, respectively, were included within accrued liabilities in the audited consolidated balance sheets.

The table above does not include the balances or activity related to asset retirement obligations related to the Partnership's Midstream Business, as these amounts have been classified as liabilities held for sale within the audited consolidated balance sheets and discontinued operations within the audited consolidated statements of operations (see Note 18).

NOTE 7. INTANGIBLE ASSETS

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

Intangible assets consisted of the following: 

	December 31, 2014			December 31, 2013
	($ in thousands)
Rights-of-way and easements—at cost	$	3,920		$	3,920
Less: accumulated amortization	(848		)	(652		)
Net intangible assets	$	3,072		$	3,268

Amounts in the table above do not include the intangible assets related to the Partnership's Midstream Business, as these amounts have been classified as assets held for sale within the audited consolidated balance sheets (See Note 18).

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The following table sets forth the total amortization expense within the Partnership's audited consolidated statements of operations:

	Year Ended December 31,
	2014		2013		2012
	($ in thousands)
Amortization	$	196	$	196	$	302

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 audited consolidated statements of operations (see Note 18).

Estimated future amortization expense related to the intangible assets at December 31, 2014, is as follows (in thousands):

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

The table above does not included amounts related to the Partnership's Midstream Business, as amortization expense ceases once assets have been classified as held for sale.

NOTE 8. LONG-TERM DEBT

Long-term debt consisted of the following:

	December 31, 2014			December 31, 2013
	($ in thousands)
Revolving credit facility:	$	212,600		$	706,800
Senior Notes:
8.375% Senior Notes due 2019	51,120			51,120
Unamortized bond discount	(377		)	(440		)
Total Senior Notes	50,743			50,680
Total long-term debt	$	263,343		$	757,480

Amounts in the table above do not include the portion of the Senior Notes that were exchanged for Regency unsecured senior notes upon the completion of the Midstream Business Contribution on July 1, 2014 (see Note 1). These notes have been classified as part of liabilities held for sale within the unaudited condensed consolidated balance sheet for December 31, 2013 and were exchanged on July 1, 2014 (see Note 18).

On July 1, 2014, the Partnership used the cash received from Regency for the Midstream Business Contribution (see Note 1) to paydown $570.4 million outstanding under its Credit Agreement.

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 current 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, and

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the next redetermination will be in April 2015. 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.

In connection with the Credit Agreement, the Partnership incurred debt issuance costs of $1.6 million and recorded a charge of $0.6 million to write off a portion of the unamortized debt issuance costs related to the Prior Credit Agreement. As of December 31, 2014, the Partnership had unamortized debt issuance costs of $4.6 million.

As of December 31, 2014, the Partnership had approximately $107.4 million of availability under the credit facility based on its borrowing base on that date. The Partnership currently pays a 0.50% 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 December 31, 2014, the Partnership had no outstanding letters of credit.

At the Partnership's election, interest will accrue on the credit facility at either LIBOR plus a margin ranging from 1.50% to 2.50% (currently 2.00% per annum based on the Partnership's borrowing base utilization percentage) or the base rate plus a margin ranging from 0.50% to 1.50% (currently 1.00% per annum based on the Partnership's borrowing base utilization percentage). The applicable margin is determined based on the utilization of the then existing borrowing base. The borrowings under the Credit Agreement may be prepaid, without any premium or penalty, at any time. The base rate is generally the highest of the federal funds rate plus 0.5%, the prime rate as announced from time to time by the Administrative Agent, or daily LIBOR for a term of one month plus 1.0%. As of December 31, 2014, the weighted average interest rate (excluding the impact of interest rate swaps) on the Partnership's outstanding debt under its revolving credit facility was 2.17%.

The obligations under the Credit Agreement are secured by first priority liens on substantially all of the Partnership’s material assets, including a pledge of all of the equity interests of each of the Partnership’s material subsidiaries, but excluding the equity interests in Regency owned by the Partnership and the sales proceeds thereof.

The Credit Agreement requires the Partnership and certain of its subsidiaries to make certain representations and warranties that are customary for credit facilities of this type. The Credit Agreement also contains affirmative and negative covenants that are customary for credit facilities of this type, including compliance with financial covenants. The financial covenants prohibit the Partnership from exceeding defined limits with respect to:

• As of any fiscal quarter-end, the ratio of Total Funded Indebtedness (as defined in the Credit Agreement) to Consolidated EBITDA for the four fiscal quarter period ending with such fiscal quarter (the “Total Leverage Ratio”).; and

• As of any fiscal quarter-end the ratio of the Partnership’s consolidated current assets (including availability under the Credit Agreement up to the Loan Limit (as defined within the Credit Agreement), but excluding non-cash assets under the accounting guidance for derivatives) to consolidated current liabilities (excluding non-cash obligations under the accounting guidance for derivatives and current maturities under the Credit Agreement) (the “Current Ratio”).

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The following table presents the debt covenant levels specified in our revolving credit facility as of December 31, 2014:

Quarter Ended	Total Leverage Ratio(a)	Current Ratio(b)
December 31, 2014 and Thereafter until Maturity (October 2019)	4.0	1.0

_____________________

(a) Amount represents the maximum ratio for the period presented.

(b) Amount represents the minimum ratio for the period presented.

The following table presents our actual covenant ratios as of December 31, 2014:

Total leverage ratio	2.2
Current ratio	5.2

As of December 31, 2013, the Partnership was in compliance with the financial covenants under the Credit Agreement.

Senior Notes

On May 27, 2011 and July 13, 2012, the Partnership, along with its subsidiary, Eagle Rock Energy Finance Corp. ("Finance Corp"), as co-issuer and certain subsidiary guarantors, issued $300.0 million and $250.0 million, respectively, of senior unsecured notes (the "Senior Notes"), that bear a coupon of 8.375%, through private placement and all of which are treated as a single series. The Senior Notes will mature on June 1, 2019, and interest is payable on each June 1 and December 1. After the original discount of $2.2 million and $3.7 million, respectively, and excluding related offering expenses, the Partnership received net proceeds of approximately $297.8 million and $246.3 million, respectively, which were used to repay borrowings outstanding under its revolving credit facility.

As of December 31, 2014, the Partnership had unamortized debt issuance costs of $0.8 million and an unamortized debt discount of $0.4 million, which is recorded as an offset to the principal amount of the Senior Notes. As discussed above and within Note 1, a portion of the Senior Notes have been classified as part of liabilities held for sale within the audited consolidated balance sheets (see Note 18).

The Senior Notes are general unsecured senior obligations and rank equally in right of payment with all of the Partnership's existing and future senior indebtedness and rank senior in right of payment to any of the Partnership's future subordinated indebtedness. The Senior Notes are effectively junior in right of payment to all of the Partnership's existing and future secured indebtedness and other obligations, including borrowings outstanding under the Partnership's Credit Agreement, to the extent of the value of the assets securing such indebtedness and other obligations. The Senior Notes are jointly and severally guaranteed on a senior unsecured basis by the Partnership's existing and future subsidiaries, who are referred to as the "subsidiary guarantors," that guarantee the Partnership's credit facility or other indebtedness.

As discussed in Note 1, the consideration received by the Partnership for the Midstream Business Contribution included the exchange of $498.9 million face amount of the Partnership's Senior Notes for an equivalent amount of Regency unsecured senior notes. $51.1 million of the Partnership's Senior Notes did not exchange and remain outstanding under an amended indenture with substantially all of the restrictive covenants and certain events of default eliminated.

The Partnership has the option to redeem all or a portion of the Senior Notes at any time on or after June 1, 2015 at the redemption prices specified in the indenture plus accrued and unpaid interest. The Partnership may also redeem the Senior Notes, in whole or in part, at a "make-whole" redemption price specified in the indenture, plus accrued and unpaid interest, at any time prior to June 1, 2015.

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Scheduled maturities of long-term debt as of December 31, 2014, were as follows: 

	Principal Amount
	($ in thousands)
2015	$	—
2016	—
2017	—
2018	—
2019	263,720
2020 and after	—
	$	263,720

NOTE 9. MEMBERS’ EQUITY

At December 31, 2014, there were 150,154,909 common units outstanding. In addition, there were 2,419,750 unvested restricted common units outstanding.

On June 1, 2010, the Partnership launched its rights offering to the holders of its common and general partner units as of close of business on May 27, 2010, the record date. Each Right entitled the holder (including holders of Rights acquired during the subscription period) to purchase (i) one common unit and (ii) one warrant to purchase one additional common unit at $6.00 on certain specified days beginning on August 15, 2010 and ending on May 15, 2012. During the years endedDecember 31, 2013 and 20125,300,588 and 14,957,540 warrants, respectively, were exercised for an equivalent number of newly issued common units. The final exercise date for the warrants was May 15, 2012, and on that date the remaining unexercised warrants expired.

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. During the year ended December 31, 2014, no units were issued under this program. As of December 31, 2014, 686,759 units had been issued under this program for net proceeds of approximately $5.6 million.

On August 17, 2012, the Partnership closed an underwritten public offering of 10,120,000 common units, which included the full exercise of the underwriters' option to purchase additional common units to cover over-allotments, for net proceeds of approximately $84.3 million.

On March 12, 2013, the Partnership closed an underwritten public offering of 10,350,000 common units for net proceeds of approximately $92.3 million.

On October 27, 2014, the Partnership announced that the Board of Directors authorized a common unit repurchase program of up to $100 million through which repurchases may be made from time to time at prevailing prices on the open market or in privately negotiated transactions. The program was authorized to commence following the filing of the Partnership's Quarterly Report on Form 10-Q for the quarter ending 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 Partnership intends to cancel any units it repurchases under the repurchase program. As of December 31, 2014, the Partnership had repurchased a total of 7,455,887 of its common units under this program for approximately $19.2 million, of which, transactions to repurchase 641,400 units had not settled as of December 31, 2014 and for which a liability of $1.3 million was recorded as part of accounts payable in the consolidated balance sheet.

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The table below summarizes the distributions paid or payable for the last three years

Quarter Ended	Distribution per Unit		Record Date**	Payment Date
March 31, 2012+	$	0.2200	May 8, 2012	May 15, 2012
June 30, 2012+	$	0.2200	August 7, 2012	August 14, 2012
September 30, 2012+	$	0.2200	November 7, 2012	November 14, 2012
December 31, 2012+	$	0.2200	February 7, 2013	February 14, 2013
March 31, 2013+*	$	0.2200	May 7, 2013	May 15, 2013
June 30, 2013+*	$	0.2200	August 7, 2013	August 14, 2013
September 30, 2013+*	$	0.1500	November 7, 2013	November 14, 2013
December 31, 2013+*	$	0.1500	February 7, 2014	February 14, 2014
March 31, 2014***	$	—	N/A	N/A
June 30, 2014***	$	—	N/A	N/A
September 30, 2014+*	$	0.07	November 7, 2014	November 14, 2014
December 31, 2014+*	$	0.07	February 6, 2015	February 13, 2015

_____________________________

+ The distribution per unit represents distributions made only on common units, including restricted common units issued under our Long Term Incentive Plan ("LTIP"). Since July 30, 2010, the only other class of equity we have outstanding is a non-economic general partner interest.

* The distribution excludes certain restricted units under the LTIP.

** The "Record Date" set forth in the table above means the close of business on each of the listed Record Dates.

*** No distribution was declared or paid for this period.

NOTE 10. RELATED PARTY TRANSACTIONS

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

	Year Ended December 31,
	2014		2013		2012
Affiliates of Natural Gas Partners:	($ in thousands)
Natural gas purchases from affiliates	$	2,091	$	2,938	$	2,713
Payable as of December 31 (related to natural gas purchases)	$	—	$	18	$	428

The transactions above are all related to the Partnership's Midstream Business and have been classified as part of discontinued operations within the consolidated statements of operations and liabilities held for sale within the consolidated balance sheet (see Note 18).    

In connection with the closing of the acquisition of certain fee minerals, royalties, overriding royalties and non-operated working interest properties from Montierra Minerals & Production, L.P. ("Montierra") and NGP-VII Co-Investment Opportunities, L.P. ("Co-Invest") on April 30, 2007, the Partnership entered into registration rights agreements with Montierra and Co-Invest. In the registration rights agreements, the Partnership agreed, for the benefit of Montierra and Co-Invest, to register the common units it holds, the common units issuable upon conversion of the subordinated units that it holds and any common units or other equity securities issuable in exchange for the common units and subordinated units it holds. The registration rights agreement is still in effect and the Partnership is in compliance with all obligations of the agreement.

In connection with the closing of the acquisition of all of the outstanding members interests of CC Energy II L.L.C. (together with its subsidiaries, "Crow Creek Energy"), a portfolio company of Natural Gas Partners, VIII, L.P. ("NGP VIII"), the Partnership entered into a registration rights agreement ("Registration Rights Agreement") with NGP VIII. The Registration Rights Agreement grants NGP VIII and certain of its affiliates registration rights with respect to the common units acquired pursuant to the Partnership's acquisition of Crow Creek Energy and their outstanding warrants to purchase common units that were previously acquired by NGP VIII and certain of its affiliates in connection with the Partnership's previously completed recapitalization transaction. Pursuant to the Registration Rights Agreement, NGP VIII and certain of its affiliates have the ability to demand that the Partnership register for resale their common units acquired pursuant to the acquisition of Crow Creek Energy and their existing warrants to purchase common units. This registration may be an underwritten offering at the discretion of NGP VIII and certain of its affiliates. NGP VIII and certain of its affiliates may demand up to four such

F- 19

registrations, subject to an increase to up to seven if the registration rights are amended. Additionally, the Registration Rights Agreement provides that NGP VIII and certain of its affiliates have piggyback registration rights in certain circumstances, which would require inclusion of their common units and warrants on registration statements that the Partnership files, subject to certain customer exceptions. There are no limits on the number of times NGP VIII and certain of its affiliates can exercise these piggyback registration rights.

NOTE 11. 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 12).  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).

In November 2014, to align its interest rate swaps with the amendment to its revolving credit facility (see Note 8), the Partnership entered into the following transaction,

• Reduced the notional value of its interest rate swaps from $250 million to $175 million;

• Extended the original maturity date of June 22, 2015 to a new maturity date of December 31, 2019; and

• Blended the existing swap rate for this extended swap with the then prevailing interest rate swap rate, which lowered the rate from 2.95% to 2.3195%.

There was no cost associated with this transaction.

The following table sets forth certain information regarding the Partnership's various interest rate swaps as of December 31, 2014:

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

 Commodity Derivative Instruments - Corporate

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 revolving credit facility.  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's strategy may involve entering into hedges with strike prices above current future prices or resetting existing hedges to higher price levels in order to meet its cash flow objectives or to stay in compliance with the covenants under its revolving credit facility.  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 for its Upstream Business is derived from the proved reserves, adjusted for 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.

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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 will often hedge 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. In the case of NGLs hedged with crude oil derivatives,

these conversions are based on the historical relationship of the prices of the two commodities and management's judgment

regarding future price relationships of the commodities. In the case where ethane is hedged with natural gas derivatives, the

conversion is based on the thermal content of ethane. In recent quarters, the correlation of price changes in crude oil and NGLs

has weakened relative to longer-term averages as NGL prices have fallen while crude index prices have risen. This dynamic has

negatively impacted our hedging objectives

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 12).  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 corporate derivative counterparties have all been participants or affiliates of participants within its revolving credit facility (see Note 8), 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 12 for the impact to the Partnership's audited consolidated balance sheets of the netting of these derivative contracts.

The Partnership's commodity derivative counterparties as of December 31, 2014, included Wells Fargo Bank N.A., Comerica Bank, Bank of America Merrill Lynch, ING Capital Markets LLC, Regions Financial Corporation and CITIBANK, N.A.

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.

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Commodity derivatives, as of December 31, 2014, that will mature during the years ended December 31, 2015, 2016, 2017, 2018 and 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)	10,800,000	$	4.07
Crude Oil	Costless Collar	480,000	$	90.00	$	97.55
Crude Oil	Swap (Pay Floating/Receive Fixed)	630,000	$	89.78
Portion of 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
Portion of Contracts Maturing in 2017
Crude Oil	Swap (Pay Floating/Receive Fixed)	444,000	$	89.24
Portion of Contracts Maturing in 2018
Crude Oil	Swap (Pay Floating/Receive Fixed)	396,000	$	88.78
Portion of 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 natural gas liquids 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 natural gas liquids.

Commodity Derivative Instruments - Marketing & Trading

Prior to the consummation of the Midstream Business Contribution, the Partnership conducted natural gas marketing and trading activities intended to capitalize on favorable price differentials between various receipt and delivery locations. This business was contributed to Regency as part of the Midstream Business Contribution completed on July 1, 2014. The assets and liabilities associated with this business have been classified as held for sale within the consolidated balance sheets and the operations as discontinued within the consolidated statements of operations (see Note 18).

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Fair Value of Interest Rate and Commodity Derivatives

Fair values of interest rate and commodity derivative instruments not designated as hedging instruments in the consolidated balance sheet as of December 31, 2014 and December 31, 2013:

	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	—
Commodity derivatives - assets	Assets held for sale	—			Liabilities held for sale	—
Commodity derivatives - liabilities	Current assets	—			Current liabilities	—
Commodity derivatives - liabilities	Long-term assets	—			Long-term liabilities	—
Commodity derivatives - liabilities	Assets held for sale	—			Liabilities held for sale	—
Total derivatives		$	91,295			$	—
	As of December 31, 2013
	Derivative Assets				Derivative Liabilities
	Balance Sheet Classification	Fair Value			Balance Sheet Classification	Fair Value
	($ in thousands)
Interest rate derivatives - liabilities	Current assets	$	—		Current liabilities	$	(6,210	)
Interest rate derivatives - liabilities	Long-term assets	—			Long-term liabilities	(2,885		)
Commodity derivatives - assets	Current assets	6,841			Current liabilities	1,043
Commodity derivatives - assets	Long-term assets	4,669			Long-term liabilities	202
Commodity derivatives - assets	Assets held for sale	6,017			Liabilities held for sale	1,973
Commodity derivatives - liabilities	Current assets	(1,282		)	Current liabilities	(3,193		)
Commodity derivatives - liabilities	Long-term assets	(798		)	Long-term liabilities	(143		)
Commodity derivatives - liabilities	Assets held for sale	(824		)	Liabilities held for sale	(5,658		)
Total derivatives		$	14,623			$	(14,871	)

The following table sets forth the location of gains and losses for derivatives not designated as hedging instruments within the Partnership's audited consolidated statement of operations (in thousands):

Amount of Gain (Loss) Recognized in Income on Derivatives		Year Ended December 31,
		2014			2013			2012
Interest rate derivatives	Interest rate risk management losses, net	$	(1,734	)	$	(1,104	)	$	(4,727	)
Commodity derivatives	Commodity risk management gains (losses), net	94,431			(3,937		)	28,110
Commodity derivatives	Discontinued operations	(15,477		)	(14,596		)	29,784
Commodity derivatives -trading	Discontinued operations	(2,404		)	315			(192		)
	Total	$	74,816		$	(19,322	)	$	52,975

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NOTE 12. 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).

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 December 31, 2014, the Partnership has recorded its interest rate swaps and commodity derivative instruments (see Note 11), 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 has classified the inputs to measure the fair value of its interest rate swaps, crude oil 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.

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The following table discloses the fair value of the Partnership's derivative instruments and equity investments as of December 31, 2014 and 2013: 

	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 agreement governing such derivative contracts.

	As of December 31, 2013
	Level 1		Level 2			Level 3		Netting (a)			Total
	($ in thousands)
Assets:
Crude oil derivatives	$	—	$	6,151		$	—	$	(1,716	)	$	4,435
Natural gas derivatives	—		6,562			—		(1,567		)	4,995
NGL derivatives	—		42			—		(42		)	—
Total	$	—	$	12,755		$	—	$	(3,325	)	$	9,430
Liabilities:
Crude oil derivatives	$	—	$	(1,792	)	$	—	$	1,716		$	(76	)
Natural gas derivatives	—		(2,503		)	—		1,567			(936		)
NGL derivatives	—		(1,121		)	—		42			(1,079		)
Interest rate swaps	—		(9,095		)	—		—			(9,095		)
Total	$	—	$	(14,511	)	$	—	$	3,325		$	(11,186	)

____________________________

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

The tables above do not include the fair value of the derivative contracts that have been classified as assets and liabilities held for sale within the audited consolidated balance sheet (see Note 18).

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 audited 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 audited consolidated statements of operations. 

Gains and losses associated with our short-term investments considered to be other than temporary are recorded in the audited consolidated statements of operations.

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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 5 for a further discussion of the impairment charges recorded during the year ended December 31, 2014. The following table discloses the fair value of the Partnership's assets measured at fair value on a nonrecurring basis for the year ended December 31, 2014:

	December 31, 2014		Level 1		Level 2		Level 3		Total Losses
	($ in thousands)
Proved properties	$	305,006	$	—	$	—	$	305,006	$	395,892
Plant assets	$	52	$	—	$	—	$	52	$	132
Pipeline assets	$	746	$	—	$	—	$	746	$	1,904
Rights-of-way	$	24	$	—	$	—	$	24	$	61

The plant, pipeline and rights-of-way assets and related impairment losses included in the table above are all attributable to the Partnership's Midstream Business and have been classified as discontinued operations within the consolidated statement of operations (see Note 18).

The Partnership calculated the fair value of the impaired assets using 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 estimated location differentials, as of the impairment date and (iv) a discount rate reflective of the Partnership's cost of capital.

The carrying amount of cash equivalents is believed to approximate their fair values because of the short maturities of these instruments. The fair value of accounts receivable and accounts payable are not materially different from their carrying amounts because of the short-term nature of these instruments.

As of December 31, 2014, 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 outstanding debt associated with the Senior Notes bore interest at a fixed rate; based on the market price of the Senior Notes as of December 31, 2014 and 2013, the Partnership estimates that the fair value of the Senior Notes, including amounts classified as held for sale, was $47.0 million and $599.5 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.

NOTE 13. COMMITMENTS AND CONTINGENT LIABILITIES

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 December 31, 2014 and 2013 related to legal matters and current lawsuits are not expected to have a material adverse effect on our financial position, results of operations or cash flows. Lawsuits the Partnership and/or its operating subsidiaries were subject to relating to the Partnership's midstream business were assumed by Regency on July 1, 2014 as part of the Midstream Business Contribution.

In March and April 2014, alleged unitholders of the Partnership filed three class action lawsuits in the United States District Court for the Southern District of Texas on behalf of the Partnership's public unitholders.  Plaintiffs in each lawsuit alleged a variety of causes of action challenging the Midstream Business Contribution, including alleged breaches of fiduciary or contractual duties, alleged aiding and abetting these alleged breaches of duty, and alleged violations of the Securities Exchange Act of 1934 (the "Exchange Act"). The plaintiffs sought to have the sale rescinded and receive monetary damages and attorneys’ fees. In August 2014, the court consolidated the lawsuits into an action styled In re Eagle Rock Energy Partners, L.P. Securities Litigation and appointed a lead plaintiff and co-lead counsel. On November 19, 2014, the court dismissed the action without prejudice.

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 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—Our business involves acquiring, developing and producing oil and natural gas working interests, and certain associated gathering and processing activities for our interests in Alabama.  Our operations and those of our 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 December 31, 2014 and 2013, the Partnership had accrued approximately $2.8 million and $2.5 million, respectively, for environmental matters. As of July 1, 2014, in connection with the Midstream Business Contribution, Regency agreed to indemnify the Partnership for losses arising from the Midstream Business, including potential losses associated with these laws and regulations and the Partnership agreed to use commercially reasonable efforts to mitigate such losses. Environmental accruals related to the Partnership's Midstream Business have been classified as liabilities held-for-sale within the consolidated balance sheet (see Note 18).

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

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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 at 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 $2.6 million, $2.4 million and $3.8 million for the years endedDecember 31, 2014, 2013 and 2012, respectively. Rental expense for leases with escalation clauses is recognized on a straight-line basis over the initial lease term.

At December 31, 2014, commitments under long-term non-cancelable operating leases for the next five years are as follows (in thousands):

Year ending December 31,
2015	$	5,853
2016	$	3,899
2017	$	2,799
2018	$	438
2019	$	—

NOTE 14. EMPLOYEE BENEFIT PLAN

The Partnership offers a defined contribution benefit plan to its employees. For the three years ended December 31, 2014, the plan provided for a dollar for dollar matching contribution by the Partnership of up to 4% of an employee's contribution and 50% of additional contributions up to an additional 2%. Additionally, the Partnership may, at its sole discretion and election, contribute up to 6% of a participating employee's base salary annually, subject to vesting requirements. Expenses under the plan for the years ended December 31, 2014, 2013 and 2012 were approximately $1.1 million, $1.2 million and $0.8 million, respectively.

NOTE 15. INCOME TAXES

The Partnership's provision for income taxes relates to (i) state taxes for the Partnership and (ii) federal taxes for Eagle Rock Energy Acquisition Co., Inc, (acquiring entity of Redman Energy Holdings, L.P. and Redman Energy Holdings II, L.P. and certain assets owned by NGP Income Co-Investment Opportunities Fund II, L.P. (collectively the "Redman Acquisition") in 2007)  and Eagle Rock Energy Acquisition Co. II, Inc. (acquiring entity of certain entities acquired in the Stanolind Acquisition in 2008) and their wholly owned corporations, Eagle Rock Upstream Development Company, Inc., (successor entity of certain entities acquired in the Redman acquisition) and Eagle Rock Upstream Development Company II, Inc. (successor entity of certain entities acquired in the Stanolind acquisition), which are subject to federal income taxes (the “C Corporations”).   In addition, the Partnership has become a taxable entity in the state of Texas. On May 18, 2006, the State of Texas enacted House Bill 3 which revised the pre-existing state franchise tax. In general, legal entities that conduct business in Texas are subject to the Revised Texas Franchise Tax, including previously non-taxable entities such as limited partnerships and limited liability partnerships. The tax is assessed on Texas sourced taxable margin which is defined as the lesser of (i) 70% of total revenue or (ii) total revenue less (a) cost of goods sold or (b) compensation and benefits. Although the bill states that the Revised Texas Franchise Tax is not an income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers both revenues and expenses.

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The Partnership's federal and state income tax provision is summarized below (in thousands): 

	For the Year Ended December 31,
	2014			2013			2012
Current:
Federal	$	(475	)	$	(105	)	$	621
State	8			—			18
Total current provision	(467		)	(105		)	639
Deferred:
Federal	(2,593		)	(3,837		)	(2,776		)
State	(2,343		)	(1,653		)	1,044
Total deferred	(4,936		)	(5,490		)	(1,732		)
Total (benefit) provision for income taxes	$	(5,403	)	$	(5,595	)	(1,093		)

The effective rates for the years ended December 31, 2014, 2013 and 2012 are shown in the table below. In 2014, 2013 and 2012, the federal and state based income taxes were applied against book losses which resulted in effective tax rates of 1.5%, 2.4% and 3.3%, respectively.   A reconciliation of the provision for income taxes with amounts determined by applying the statutory U.S. federal income tax rate to income before income taxes is as follows (in thousands):

	For the Year Ended December 31,
	2014			2013			2012
Pre-tax net book (loss) income from continuing operations	(357,770		)	(233,766		)	(33,239		)
State income tax current and deferred	(2,335		)	(1,653		)	1,062
Federal income taxes computed by applying the federal statutory rate to NBI of corporate entities	(2,680		)	(4,160		)	(2,155		)
Tax attributes used	(388		)	218			—
Benefit for income taxes from continuing operations	$	(5,403	)	$	(5,595	)	$	(1,093	)
Effective income tax rate on continuing operations	1.5		%	2.4		%	3.3		%

Significant components of deferred tax liabilities and deferred tax assets as of December 31, 2014 and 2013 are as follows (in thousands):

	December 31, 2014			December 31, 2013
Deferred Tax Assets:
Statutory depletion carryover	$	1,842		$	1,438
Property, plant, equipment & amortizable assets	473			—
Total Deferred Tax Assets	2,315			1,438
Deferred Tax Liabilities:
Property, plant, equipment & amortizable assets	—			(2,011		)
Hedging transactions	(424		)	—
Book/tax differences from partnership investment	(29,897		)	(32,086		)
Total Deferred Tax Liabilities	(30,321		)	(34,097		)
Total Net Deferred Tax Liabilities	(28,006		)	(32,659		)
Current portion of total net deferred tax liabilities	—			—
Long-term portion of total net deferred tax liabilities	$	(28,006	)	$	(32,659	)

The largest single component of the Partnership's deferred tax liabilities is related to federal income taxes of the C Corporations described above, where the book/tax differences were created by the Redman and Stanolind Acquisitions. These book/tax temporary differences will be reduced as allocation of built-in gain in proportion to the assets contributed brings the

F- 28

book and tax basis closer together over time. This net deferred tax liability was recognized in conjunction with the purchase accounting adjustments for long term assets.  

Due to the enactment of the Revised Texas Franchise Tax, the Partnership recorded a net deferred tax asset related to the book/tax differences in property, plant and equipment and hedging transactions.

In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment. At December 31, 2014, based upon the level of historical taxable income and projections for future taxable income over the periods in which the deferred tax assets are deductible, management believes it is more likely than not that the Partnership will realize the benefits of these deductible differences. The amount of deferred tax assets considered realizable could be reduced in the future if estimates of future taxable income during the carryforward period are reduced.

The Partnership adopted authoritative guidance related to accounting for uncertainty in income taxes on January 1, 2007.  The Partnership has taken a position which is deemed to be “more likely than not” to be upheld upon review, if any, with respect to the deductibility of certain costs for the purpose of its franchise tax liability on a state franchise return.   The Partnership has recorded a provision for the portion of this tax liability equal to the probability of recognition. In addition, the Partnership has accrued interest and penalties associated with these liabilities and has recorded these amounts within its state deferred income tax expense. The amount stated below relates to the tax returns filed for years ending 2012, 2011 and 2010 which are still open under current statute.

A reconciliation of the beginning and ending amount of the unrecognized tax benefits (liabilities) is as follows (in thousands): 

	2014			2013			2012
Balance at beginning of period	$	(649	)	$	(830	)	$	(735	)
Increases related to current year tax positions	—			(128		)	(53		)
Increases related to tax interest and penalties	—			(39		)	(42		)
Decreases related to statutory limitations	226			267			—
Decreases related to tax interest and penalties	58			81			—
Balance at end of period	$	(365	)	$	(649	)	$	(830	)

NOTE 16. EQUITY-BASED COMPENSATION

Eagle Rock Energy G&P, LLC, the general partner of the general partner of the Partnership, has a long-term incentive plan, (as amended “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 December 31, 2014, a total of 6,475,632 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 weighted average fair value of the units granted during the years endedDecember 31, 2014, 2013 and 2012 was $4.44, $9.16 and $9.50, respectively. The awards generally vest over three years on the basis of one third of the award 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 year endedDecember 31, 2014 is provided below:

	Number of Restricted Units		Weighted Average Fair Value
Outstanding at December 31, 2013	2,743,807		$	9.37
Granted	1,903,333		$	4.44
Vested	(1,305,433	)	$	9.60
Forfeited	(921,957	)	$	8.12
Outstanding at December 31, 2014	2,419,750		$	6.06

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Performance Units

On August 19, 2014, the Board of Directors of Eagle Rock Energy G&P, LLC, upon the recommendation of its compensation committee, approved a grant of 715,263 target performance unit awards to the Partnership's executive officers subject to performance and service-based vesting conditions pursuant to the LTIP. 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 to vest each year for the three-year vesting period will be determined on each vesting date based on a two-step approach. The right to receive units with respect to the performance units depends first on the level of total unitholder return attained by the Partnership over the applicable performance period (generally July 1, 2014 through June 30, 2016), as measured against the Partnership's peer group. The number of units that may be earned will either by 0% for performance at anything less than the 50th percentile of the peer group, or in the range of 70% to 200% 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 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.

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 shall terminate, expire and otherwise be forfeited by the named executive officer on the last day of the performance periods. Any earned performance units that vest (based on fulfillment of the continued service requirement) shall be converted into actual common units. Any earned performance units that do not vest (based on fulfillment of the continued service requirement) shall terminate, expire and otherwise be forfeited by the named executive officer.

A summary of the changes in outstanding performance units for the year endedDecember 31, 2014 is provided below:

	Number of Performance Units		Weighted Average Fair Value
Outstanding at December 31, 2013	—		$	—
Granted	715,263		$	3.63
Forfeited	(67,475	)	3.59
Outstanding at December 31, 2014	647,788		3.63

Equity Based Compensation

For the years endedDecember 31, 2014, 2013 and 2012, non-cash compensation expense of approximately $8.2 million, $10.4 million and $7.7 million, respectively, was recorded related to the granted restricted units and performance units as general and administrative expense on the consolidated statements of operations.

As of December 31, 2014, unrecognized compensation costs related to the outstanding restricted units and performance units under the LTIP totaled approximately $12.2 million. The remaining expense is to be recognized over a weighted average of 2.0 years.

In connection with the vesting of certain restricted units during the years endedDecember 31, 2014, 2013 and 2012, 338,790, 272,179 and 286,716, respectively, of the newly-vested common units were cancelled by the Partnership in

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satisfaction of $1.4 million, $1.9 million and $2.5 million, respectively, 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.

NOTE 17. 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 December 31, 2014, 2013 and 2012, the Partnership had unvested restricted common units outstanding, which are considered dilutive securities. These units are considered in the diluted weighted average common unit outstanding number in periods of net income. In periods of net losses, these units are excluded from the diluted weighted average common unit outstanding number.

The majority of the restricted units granted under the LTIP, as discussed in Note 16, 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:

	Year Ended December 31,
	2014	2013	2012
	(in thousands)
Weighted average units outstanding during period:
Common units - Basic	156,700	153,562	135,609
Common units - Diluted	156,700	153,562	135,609

The following table presents the Partnership's basic and diluted income (loss) per unit for the year endedDecember 31, 2014:

	Total			Common Units			Restricted Common Units
	($ in thousands, except for per unit amounts)
Loss from continuing operations	$	(352,367	)
Distributions	21,763			$	21,464		$	299
Assumed loss from continuing operations after distribution to be allocated	(374,130		)	(374,130		)	—
Assumed allocation of loss from continuing operations	(352,367		)	(352,666		)	299
Discontinued operations, net of tax	212,460			212,460			—
Assumed net loss to be allocated	$	(139,907	)	$	(140,206	)	$	299
Basic loss from continuing operations per unit				$	(2.25	)
Basic discontinued operations per unit				$	1.36
Basic net loss per unit				$	(0.89	)
Diluted loss from continuing operations per unit				$	(2.25	)
Diluted discontinued operations per unit				$	1.36
Diluted net loss per unit				$	(0.89	)

F- 31

The following table presents the Partnership's basic and diluted income per unit for the year endedDecember 31, 2013:

	Total			Common Units			Restricted Common Units
	($ in thousands, except for per unit amounts)
Loss from continuing operations	$	(228,171	)
Distributions	117,294			$	115,351		$	1,943
Assumed loss from continuing operations after distribution to be allocated	(345,465		)	(345,465		)	—
Assumed allocation of loss from continuing operations	(228,171		)	(230,114		)	1,943
Discontinued operations, net of tax	(49,808		)	(49,808		)	—
Assumed net loss to be allocated	$	(277,979	)	$	(279,922	)	$	1,943
Basic loss from continuing operations per unit				$	(1.50	)
Basic discontinued operations per unit				$	(0.32	)
Basic net loss per unit				$	(1.82	)
Diluted loss from continuing operations per unit				$	(1.50	)
Diluted discontinued operations per unit				$	(0.32	)
Diluted net loss per unit				$	(1.82	)

The following table presents the Partnership's basic and diluted income per unit for the year endedDecember 31, 2012:

	Total			Common Units			Restricted Common Units
	($ in thousands, except for per unit amounts)
Loss from continuing operations	$	(32,146	)
Distributions	124,235			$	121,504		$	2,731
Assumed loss from continuing operations after distribution to be allocated	(156,381		)	(156,381		)	—
Assumed allocation of loss from continuing operations	(32,146		)	(34,877		)	2,731
Discontinued operations, net of tax	(118,456		)	(118,456		)	—
Assumed net loss to be allocated	$	(150,602	)	$	(153,333	)	$	2,731
Basic loss from continuing operations per unit				$	(0.26	)
Basic discontinued operations per unit				$	(0.87	)
Basic net loss per unit				$	(1.13	)
Diluted loss from continuing operations per unit				$	(0.26	)
Diluted discontinued operations per unit				$	(0.87	)
Diluted net loss per unit				$	(1.13	)

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NOTE 18.   DIVESTITURE RELATED ACTIVITIES

As discussed in Note 1, on July 1, 2014, the Partnership completed the contribution of its Midstream Business to Regency. As a result of this transaction, the assets and liabilities of the Partnership's Midstream Business have been classified as held for sale and the operations as discontinued (See Note 1).

On December 20, 2012, the Partnership sold its Barnett Shale properties (which was accounted for in its Upstream Business). The Partnership received net proceeds of $14.8 million, which resulted in a loss on the sale of $4.5 million. The loss is included within impairment expense in the audited consolidated statement of operations. In addition, as this transaction did not meet the criteria for discontinued operations, the operations related to these assets are not included in the discontinued operations table below.

The following is the reconciliation of the major classes of assets and liabilities classified as held for sale.

	December 31, 2014		December 31, 2013
	($ in thousands)
Assets held-for-sale
Accounts Receivable	$	—	$	128,713
Property, plant and equipment	—		1,004,317
Intangible assets	—		102,352
Other current assets	—		5,663
Other long-term assets	—		18,337
Total assets held-for-sale	$	—	$	1,259,382
Liabilities held-for-sale
Long-term debt	$	—	$	494,582
Accounts payable and accrued liabilities	—		119,966
Other current liabilities	—		9,471
Other long-term liabilities	—		13,719
Total liabilities held-for-sale	$	—	$	637,738

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The following table represents the reconciliation of major classes of line items classified as discontinued operations for midstream business for the years ended December 31, 2014, 2013 and 2012:

	December 31, 2014			December 31, 2013			December 31, 2012
	($ in thousands)
Class of statement of operations line item of discontinued operations:
Revenues	$	552,574		$	997,907		$	752,644
Cost of natural gas, natural gas liquids, condensate and helium	447,519			790,618			532,719
Operations, maintenance and taxes other than income	50,154			101,121			82,526
General and administrative	18,392			28,083			19,004
Depreciation, amortization and impairment	41,936			77,726			202,249
Interest expense	27,350			49,973			35,202
Other (expense) income	(68		)	287			(10		)
Operating loss from discontinued operations before taxes	(32,845		)	(49,327		)	(119,066		)
Gain on sale of assets	243,637			—			—
Income tax expense	(1,668		)	481			(610		)
Discontinued operations, net of tax	$	212,460		$	(49,808	)	$	(118,456	)

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 contribution of the Midstream Business, 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 the interest expense related to the portion of the Partnership's unsecured Senior Notes exchanged for Regency unsecured senior notes on July 1, 2014 (see Note 1) and interest related to the difference between the total amount outstanding under the Credit Agreement and the upstream portion of the borrowing base.

Restructuring activities

In connection with the contribution of the Midstream Business to Regency, the Partnership accrued one-time employee termination benefits and lease payments of the partial abandonment of an operating lease of $4.0 million and $0.6 million during the year endedDecember 31, 2014. The accruals are recorded as part of accrued liabilities within the unaudited condensed consolidated balance sheet, while the expenses are recorded as part of discontinued operations within the unaudited condensed consolidated statement of operations. The following table summarizes activity related to liabilities associated with the Partnership's restructuring activities during the year endedDecember 31, 2014.

	Employee Related Costs			Facility and Other Costs			Total
	($ in thousands)
Balance at December 31, 2013	$	—		$	—		$	—
Additions	4,033			563			4,596
Payments and other adjustments	(3,198		)	(73		)	(3,271		)
Balance at December 31, 2014	$	835		$	490		$	1,325

In addition, in connection with the contribution of the Midstream Business, the Partnership incurred expenses of $1.7 million during the year endedDecember 31, 2014 to write-off certain software licenses used by the Midstream Business that were not acquired by Regency.

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NOTE 19. SUBSIDIARY GUARANTORS

The Partnership has issued registered debt securities guaranteed by its subsidiaries.  As of December 31, 2014, 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 our subsidiary guarantors are considered full and unconditional, the guarantees are subject to certain customary release provisions. Such guarantees will be released in the following 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 us;

• 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 we designate 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 Regulation S-X, the Partnership has prepared Condensed Consolidating Financial Statements as supplemental information.  The following condensed consolidating balance sheets at December 31, 2014 and December 31, 2013, condensed consolidating statements of operations for the years endedDecember 31, 2014, 2013 and 2012, and condensed consolidating statements of cash flows for the years endedDecember 31, 2014, 2013 and 2012, 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 Parent, 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. Pursuant to the Contribution of the Midstream Business, all of the Partnership's Midstream Subsidiaries were contributed to Regency on July 1, 2014 and released from their guarantees under the indenture and Credit Agreement.

F- 35

Condensed Consolidating Balance Sheet

December 31, 2014

	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-guarantor investments		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

Condensed Consolidating Balance Sheet

December 31, 2013

	Parent Issuer		Co-Issuer		Subsidiary Guarantors		Non-guarantor investments		Consolidating Entries			Total
	($ in thousands)
ASSETS:
Accounts receivable – related parties	$	691,588	$	—	$	—	$	—	$	(691,588	)	$	—
Assets held for sale	8,762		—		1,250,620		—		—			1,259,382
Other current assets	6,927		1		22,080		—		—			29,008
Total property, plant and equipment, net	2,318		—		822,133		—		—			824,451
Investment in subsidiaries	1,133,217		—		—		908		(1,134,125		)	—
Total other long-term assets	10,012		—		4,697		—		—			14,709
Total assets	$	1,852,824	$	1	$	2,099,530	$	908	$	(1,825,713	)	$	2,127,550
LIABILITIES AND EQUITY:
Accounts payable – related parties	$	—	$	—	$	691,588	$	—	$	(691,588	)	$	—
Liabilities held for sale	500,291		—		137,447		—		—			637,738
Other current liabilities	15,688		—		66,141		—		—			81,829
Other long-term liabilities	5,486		—		71,138		—		—			76,624
Long-term debt	757,480		—		—		—		—			757,480
Equity	573,879		1		1,133,216		908		(1,134,125		)	573,879
Total liabilities and equity	$	1,852,824	$	1	$	2,099,530	$	908	$	(1,825,713	)	$	2,127,550

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Condensed Consolidating Statement of Operations

For the Year Ended December 31, 2014

	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-guarantor investments			Consolidating Entries			Total
	($ in thousands)
Total revenues	$	93,940		$	—	$	204,264		$	—		$	—		$	298,204
Operations and maintenance	3			—		43,667			—			—			43,670
Taxes other than income	—			—		12,925			—			—			12,925
General and administrative	9,654			—		37,539			—			—			47,193
Depreciation, depletion and amortization	641			—		84,938			—			—			85,579
Impairment and other	—			—		395,892			—			—			395,892
Income (loss) from operations	83,642			—		(370,697		)	—			—			(287,055		)
Interest expense, net	(15,247		)	—		—			—			—			(15,247		)
Other non-operating income	16,998			—		4,741			—			(13,445		)	8,294
Other non-operating expense	(7,396		)	—		(7,783		)	—			13,445			(1,734		)
Loss on short term investments	(62,028		)	—		—			—			—			(62,028		)
Income (loss) before income taxes	15,969			—		(373,739		)	—			—			(357,770		)
Income tax benefit	(3,791		)	—		(1,612		)	—			—			(5,403		)
Equity in earnings of subsidiaries	(683,371		)	—		—			—			683,371			—
Loss from continuing operations	(663,611		)	—		(372,127		)	—			683,371			(352,367		)
Discontinued operations, net of tax	523,704			—		(311,235		)	(9		)	—			212,460
Net loss	$	(139,907	)	$	—	$	(683,362	)	$	(9	)	$	683,371		$	(139,907	)

Condensed Consolidating Statement of Operations

For the Year Ended December 31, 2013

	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-guarantor investments			Consolidating Entries			Total
	($ in thousands)
Total revenues	$	(3,937	)	$	—	$	201,309		$	—		$	—		$	197,372
Operations and maintenance	—			—		41,426			—			—			41,426
Taxes other than income	—			—		12,928			—			—			12,928
General and administrative	13,145			—		39,986			—			—			53,131
Depreciation, depletion and amortization	454			—		88,990			—			—			89,444
Impairment	—			—		214,286			—			—			214,286
Loss from operations	(17,536		)	—		(196,307		)	—			—			(213,843		)
Interest expense, net	(17,891		)	—		(898		)	—			—			(18,789		)
Other non-operating income	9,025			—		9,298			—			(18,323		)	—
Other non-operating expense	(6,904		)	—		(12,553		)	—			18,323			(1,134		)
Loss before income taxes	(33,306		)	—		(200,460		)	—			—			(233,766		)
Income tax provision (benefit)	(1,653		)	—		(3,942		)	—			—			(5,595		)
Equity in earnings of subsidiaries	(191,071		)	—		—			—			191,071			—
Loss from continuing operations	(222,724		)	—		(196,518		)	—			191,071			(228,171		)
Discontinued operations, net of tax	(55,255		)	—		5,457			(10		)	—			(49,808		)
Net loss	$	(277,979	)	$	—	$	(191,061	)	$	(10	)	$	191,071		$	(277,979	)

F- 37

Condensed Consolidating Statement of Operations

For the Year Ended December 31, 2012

	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-guarantor investments			Consolidating Entries			Total
	($ in thousands)
Total revenues	$	28,110		$	—	$	203,205		$	—		$	—		$	231,315
Operations and maintenance	—			—		41,391			—			—			41,391
Taxes other than income	—			—		15,343			—			—			15,343
General and administrative	8,745			—		42,245			—			—			50,990
Depreciation, depletion and amortization	296			—		90,214			—			—			90,510
Impairment	—			—		45,289			—			—			45,289
Income (loss) from operations	19,069			—		(31,277		)	—			—			(12,208		)
Interest expense, net	(16,299		)	—		23			—			—			(16,276		)
Other non-operating income	9,039			—		10,961			—			(20,000		)	—
Other non-operating expense	(12,189		)	—		(12,566		)	—			20,000			(4,755		)
Loss before income taxes	(380		)	—		(32,859		)	—			—			(33,239		)
Income tax provision (benefit)	1,041			—		(2,134		)	—			—			(1,093		)
Equity in earnings of subsidiaries	(113,200		)	—		—			—			113,200			—
Loss from continuing operations	(114,621		)	—		(30,725		)	—			113,200			(32,146		)
Discontinued operations, net of tax	(35,981		)	—		(82,457		)	(18		)	—			(118,456		)
Net loss	$	(150,602	)	$	—	$	(113,182	)	$	(18	)	$	113,200		$	(150,602	)

F- 38

Condensed Consolidating Statement of Cash Flows

For the Year Ended December 31, 2014

	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-guarantor investments		Consolidating Entries		Total
	($ in thousands)
Net cash flows (used in) provided by operating activities	$	(28,661	)	$	—	$	106,787		$	—	$	—	$	78,126
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment	344			—		(137,038		)	—		—		(136,694		)
Proceeds from sale of short-term investments	43,836			—		—			—		—		43,836
Net cash flows provided by (used in) investing activities	44,180			—		(137,038		)	—		—		(92,858		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	472,500			—		—			—		—		472,500
Repayment of long-term debt	(966,700		)	—		—			—		—		(966,700		)
Payment of debt issuance cost	(1,984		)	—		—			—		—		(1,984		)
Proceeds from derivative contracts	(5,022		)	—		—			—		—		(5,022		)
Repurchase of common units	(19,170		)	—		—			—		—		(19,170		)
Distributions to members and affiliates	(34,982		)	—		—			—		—		(34,982		)
Net cash flows used in financing activities	(555,358		)	—		—			—		—		(555,358		)
Net cash flows provided by discontinued operations	541,288			—		30,047			22		—		571,357
Net increase (decrease) in cash and cash equivalents	1,449			—		(204		)	22		—		1,267
Cash and cash equivalents at beginning of year	1,237			1		(1,389		)	227		—		76
Cash and cash equivalents at end of year	$	2,686		$	1	$	(1,593	)	$	249	$	—	$	1,343

F- 39

Condensed Consolidating Statement of Cash Flows

For the Year Ended December 31, 2013

	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-guarantor Investments		Consolidating Entries		Total
	($ in thousands)
Net cash flows (used in) provided by operating activities	$	(34,610	)	$	—	$	148,853		$	—	$	—	$	114,243
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment	(115		)	—		(149,829		)	—		—		(149,944		)
Proceeds from sale of asset	—			—		76			—		—		76
Net cash flows used in investing activities	(115		)	—		(149,753		)	—		—		(149,868		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	601,400			—		—			—		—		601,400
Repayment of long-term debt	(503,100		)	—		—			—		—		(503,100		)
Proceeds from derivatives contracts	1,323			—		—			—		—		1,323
Common unit issued in equity offerings	102,388			—		—			—		—		102,388
Issuance costs for equity offerings	(4,519		)	—		—			—		—		(4,519		)
Repurchase of common units	(1,858		)	—		—			—		—		(1,858		)
Distributions to members and affiliates	(125,911		)	—		—			—		—		(125,911		)
Net cash flows provided by financing activities	69,723			—		—			—		—		69,723
Net cash flows provided by (used in) discontinued operations	(35,431		)	—		1,343			41		—		(34,047		)
Net (decrease) increase in cash and cash equivalents	(433		)	—		443			41		—		51
Cash and cash equivalents at beginning of year	1,670			1		(1,832		)	186		—		25
Cash and cash equivalents at end of year	$	1,237		$	1	$	(1,389	)	$	227	$	—	$	76

F- 40

Condensed Consolidating Statement of Cash Flows

For the Year Ended December 31, 2012

	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-guarantor Investments		Consolidating Entries			Total
	($ in thousands)
Net cash flows (used in) provided by operating activities	$	(108,061	)	$	—	$	183,397		$	—	$	—		$	75,336
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment	(1,551		)	—		(166,356		)	—		—			(167,907		)
Proceeds from sale of asset	—			—		15,398			—		—			15,398
Contribution to subsidiaries	(236,971		)	—		—			—		236,971			—
Net cash flows used in investing activities	(238,522		)	—		(150,958		)	—		236,971			(152,509		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	1,043,750			—		—			—		—			1,043,750
Repayment of long-term debt	(916,750		)	—		—			—		—			(916,750		)
Proceed from senior notes	22,889			—		—			—		—			22,889
Payments of debt issuance cost	(614		)	—		—			—		—			(614		)
Proceeds from derivative contracts	14,449			—		—			—		—			14,449
Common unit issued in equity offerings	96,173			—		—			—		—			96,173
Issuance costs for equity offerings	(4,518		)	—		—			—		—			(4,518		)
Exercise of Warrants	31,804			—		—			—		—			31,804
Repurchase of common units	(2,501		)	—		—			—		—			(2,501		)
Distributions to members and affiliates	(119,211		)	—		—			—		—			(119,211		)
Net cash flows provided by financing activities	165,471			—		—			—		—			165,471
Net cash flows provided by (used in) discontinued operations	181,463			—		(33,699		)	57		(236,971		)	(89,150		)
Net increase (decrease) in cash and cash equivalents	351			—		(1,260		)	57		—			(852		)
Cash and cash equivalents at beginning of year	1,319			1		(572		)	129		—			877
Cash and cash equivalents at end of year	$	1,670		$	1	$	(1,832	)	$	186	$	—		$	25

NOTE 20. SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)

Oil and Natural Gas Reserves

Users of this information should be aware that the process of estimating quantities of proved oil and natural gas reserves is very complex, and requires significant subjective decisions in the evaluation of the available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and changing operating and market conditions. As a result, revisions to reserve estimates may occur from time to time. Although reasonable effort is made to ensure the reported reserve estimates are accurate, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.

There are numerous uncertainties inherent in estimating the quantities of proved reserves, the future rates of production and the timing of development expenditures. Reserves data represent estimates only and should not be construed as being exact. Moreover, the Standardized Measure of Oil and Gas (“SMOG”) should not be construed as the current market value of the proved oil and natural gas reserves or as the costs that would be incurred to obtain equivalent reserves. A market value determination would include many additional factors including (a) anticipated future changes in natural gas and crude oil prices, production and development costs, (b) an allowance for return on investment, (c) the value of additional reserves, not considered proved at present, which may be recovered as a result of further exploration and development activities, and (d) other business risks.

Proved Reserves Summary

The following table illustrates the Partnership's estimated net proved reserves, including changes, and proved developed reserves for the periods indicated, as estimated by Cawley, Gillespie and Associates. Oil and natural gas liquids prices applied for 2014 are based on an average of the prior twelve months first-of-month spot prices of West Texas Intermediate ($94.99 per barrel) and are adjusted for quality, transportation fees, and price differentials. Likewise, natural gas prices applied for 2014 are based on an average of the prior twelve months first-of-month spot prices of Henry Hub natural gas ($4.35 per MMBtu) and are adjusted for energy content, transportation fees, and regional price differentials. All prices are held constant in accordance with SEC guidelines.  

As shown in the following reconciliation table, the Partnership recognized significant negative revisions to its estimates of proved reserves in 2014. These revisions to previous estimates were primarily the result of recategorizing a number of undeveloped locations from proved to probable reserves due to poor expected economic performance (a decrease of 3.0 Bcfe), recategorizing other proved undeveloped locations as contingent resources since they were non-commercial at the time (a decrease of 0.2 Bcfe), and other factors including increased costs, negative changes to forecast performance expectations and widening product price differentials (a decrease of 44.6 Bcfe).

F- 41

	Proved Reserves
	Oil (MBbls)		Gas (MMcf)		Natural Gas Liquids (MBbls)
Proved reserves, January 1, 2012	11,522		234,022		11,347
Extensions and discoveries	1,405		31,524		2,136
Purchase of minerals in place	104		128		18
Production	(1,184	)	(16,443	)	(1,121	)
Sales of mineral in place	—		(13,331	)	—
Revision of previous estimates	1,137		(41,471	)	486
Proved reserves, December 31, 2012	12,984		194,429		12,866
Extensions and discoveries	2,712		29,137		3,180
Purchase of minerals in place	—		—		—
Production	(1,222	)	(12,804	)	(1,156	)
Revision of previous estimates	(932	)	(33,536	)	(253	)
Proved reserves, December 31, 2013	13,542		177,226		14,637
Extensions and discoveries	1,080		22,990		2,224
Purchase of minerals in place	326		769		170
Production	(1,313	)	(11,995	)	(1,158	)
Revision of previous estimates	(2,618	)	(19,897	)	(2,039	)
Proved reserves, December 31, 2014	11,017		169,093		13,834
Proved Developed Reserves
Proved developed reserves, January 1, 2012	10,271		165,269		9,307
Proved developed reserves, December 31, 2012	10,993		136,545		10,445
Proved developed reserves, December 31, 2013	10,153		126,950		10,766
Proved developed reserves, December 31, 2014	9,595		126,783		10,895
Proved Undeveloped Reserves
Proved undeveloped reserves, January 1, 2012	1,251		68,753		2,040
Proved undeveloped reserves, December 31, 2012	1,991		57,884		2,421
Proved undeveloped reserves, December 31, 2013	3,389		50,276		3,871
Proved undeveloped reserves, December 31, 2014	1,412		42,310		2,939

The primary drivers, other than production, behind the changes to our proved reserves for the years endedDecember 31, 2012, 2013 and 2014 are described in more detail below.

2012:

• Purchase of minerals in place were insignificant in 2012;

• extensions and discoveries were primarily related to drilling by us and other operators in the Golden Trend area and the nearby SCOOP Play in Oklahoma;

• sales of minerals in place were related to the sale of our Barnett Shale assets in December 2012; and

• revisions of previous estimates were primarily the result of lower natural gas prices which reduced the economic life and reserves of many wells.

2013:

• Purchases and sales of minerals in place did not occur in 2013;

F- 42

• extensions and discoveries were primarily related to drilling by us and other operators in the Golden Trend area and the nearby SCOOP Play in Oklahoma; and

• revisions of previous estimates were the result of recategorizing a number of undeveloped locations from proved to probable reserves due to poor expected economic performance (a decrease of 27.8 Bcfe), recategorizing other proved undeveloped locations as contingent resources since they were non-commercial at the time (a decrease of 8.1Bcfe), changes in ownership of interests including those that occurred when third party owners elected to not participate in future drilling activities for certain wells (an increase of 1.6 Bcfe) and other factors including changes to costs (an increase of 2.5 Bcfe). All of these revisions were primarily in the Mid-Continent Region.

2014:

• Purchases of minerals in place in 2014 included 3.7 Bcfe of proved developed producing reserves in the Big Escambia Creek field in Alabama, but there were no sales of minerals in place;

• extensions and discoveries were primarily related to drilling by us and other operators in the Golden Trend area and the nearby SCOOP Play in Oklahoma and in addition, a number of well locations primarily in the Mid-Continent Region were moved to proved developed non-producing and proved undeveloped as a result of becoming economic at higher gas prices; and

• revisions of previous estimates were the result of recategorizing a number of undeveloped locations from proved to probable reserves due to poor expected economic performance (a decrease of 3.0 Bcfe), recategorizing other proved undeveloped locations as contingent resources since they were non-commercial at the time (a decrease of 0.2Bcfe), and other factors including changes to costs, forecast performance expectations and product price differentials (a decrease of 44.6 Bcfe).

Capitalized Costs Relating to Oil and Natural Gas Producing Activities

The following table illustrates the total amount of capitalized costs relating to oil and natural gas producing activities and the total amount of related accumulated depreciation, depletion and amortization at December 31, 2014, 2013 and 2012:

	As of December 31, 2014			As of December 31, 2013			As of December 31, 2012
($ in thousands)
Proved properties	$	905,622		$	1,156,895		$	1,213,622
Unproved properties—excluded from depletion	7,512			10,022			31,823
Gross oil and gas properties	913,134			1,166,917			1,245,445
Accumulated depreciation, depletion, amortization	(431,555		)	(353,679		)	(269,376		)
Net oil and gas properties	$	481,579		$	813,238		$	976,069

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

Costs incurred in property acquisition, exploration and development activities were as follows for the years ended December 31, 2014, 2013 and 2012:

	Year Ended December 31,
	2014		2013		2012
($ in thousands)
Property acquisition costs, proved	$	10,861	$	—	$	2,582
Development costs	122,387		124,032		135,692
Total costs	$	133,248	$	124,032	$	138,274

F- 43

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves

The following information has been developed utilizing authoritative guidance procedures and is based on oil and natural gas reserves estimated by the Partnership's independent reserves engineer. It can be used for some comparisons, but should not be the only method used to evaluate the Partnership or its performance. Further, the information in the following table may not represent realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flow be viewed as representative of the current value of the Partnership.

The Partnership believes that the following factors should be taken into account when reviewing the following information:

• future costs and selling prices will probably differ from those required to be used in these calculations;

• due to future market conditions and governmental regulations, actual rates of production in future years may vary significantly from the rate of production assumed in the calculations; and

• a 10% discount rate may not be reasonable as a measure of the relative risk inherent in realizing future net oil and natural gas revenues.

Under the Standardized Measure, future cash inflows were estimated by applying year-end oil and natural gas prices to the estimated future production of year-end proved reserves. Estimates of future income taxes were computed using current statutory income tax rates including consideration for estimated future statutory depletion and tax credits. The resulting net cash flows were reduced to present value amounts by applying a 10% discount factor.

The Partnership's hydrocarbon reserves in Alabama and East Texas contain hydrogen sulfide that must be removed from the natural gas stream before the hydrocarbons are sold. As part of the process to remove the hydrogen sulfide, the Partnership produces and sells elemental sulfur. The Partnership generated revenue from the sale of sulfur of $8.2 million, $8.1 million and $14.0 million in 2014, 2013 and 2012, respectively. The cost of removing the sulfur is included in the future production costs in the Standardized Measure table below. However, since sulfur is not considered a hydrocarbon, revenues from the sale of sulfur are excluded from the computation of the Standardized Measure.

The Standardized Measure is as follows as of December 31, 2014, 2013 and 2012:

	As of December 31, 2014			As of December 31, 2013			As of December 31, 2012
($ in thousands)
Future cash inflows	$	2,187,346		$	2,423,350		$	2,279,735
Future production costs	(759,966		)	(737,468		)	(767,004		)
Future development costs	(240,886		)	(318,778		)	(354,690		)
Future net cash flows before income taxes	1,186,494			1,367,104			1,158,041
Future income tax (expense) benefit	(833		)	(1,212		)	(1,086		)
Future net cash flows before 10% discount	1,185,661			1,365,892			1,156,955
10% annual discount for estimated timing of cash flows	(591,421		)	(715,386		)	(621,826		)
Total standardized measure of discounted future net cash flows	$	594,240		$	650,506		$	535,129

Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves

The following is a summary of the changes in the Standardized Measure of discounted future net cash flows for the Partnership's proved oil and natural gas reserves for the years ended December 31, 2014, 2013 and 2012:

F- 44

	Year Ended December 31,
	2014			2013			2012
($ in thousands)
Beginning of year	$	650,506		$	535,129		$	642,586
Sale of oil and gas produced, net of production costs	(152,097		)	(150,457		)	(132,451		)
Net changes in prices and production costs	(63,142		)	2,720			(78,247		)
Extensions, discoveries and improved recovery, less related costs	74,684			136,464			66,460
Previously estimated development costs incurred during the period	49,409			21,470			53,111
Net changes in future development costs	71,800			107,951			36,914
Revisions of previous quantity estimates	(149,993		)	(103,351		)	(76,434		)
Purchases of property	11,904			—			2,811
Sales of property	—			—			(5,063		)
Accretion of discount	59,818			49,233			60,734
Net changes in income taxes	169			(36		)	317
Other	41,182			51,383			(35,609		)
End of year	$	594,240		$	650,506		$	535,129

F- 45

Results of Operations

The following are the results of operations for the Partnership's oil and natural gas producing activities for the years ended December 31, 2014, 2013 and 2012:

	Year Ended December 31,
	2014			2013			2012
($ in thousands)
Revenues:
Sales to third parties	$	190,057		$	146,210		$	135,842
Intercompany sales	5,475			47,048			53,343
Total revenues	195,532			193,258			189,185
Costs and expenses:
Production costs	56,595			54,354			56,734
General and administrative	8,166			11,419			12,162
Depreciation, depletion, and amortization	81,030			87,456			88,777
Impairment and other	395,892			214,286			45,289
Total costs and expenses	541,683			367,515			202,962
Total result of operations	$	(346,151	)	$	(174,257	)	$	(13,777	)

* * * *

F- 46

EX-99.2

Exhibit 99.2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors of Eagle Rock Energy G&P, LLC and Unitholders of Eagle Rock Energy Partners, L.P.:

We have audited the accompanying consolidated balance sheets of Eagle Rock Energy Partners, L.P. and subsidiaries (collectively, the “Partnership”) as of December 31, 2014 and 2013, and the related consolidated statements of operations, comprehensive income, members’ equity, and cash flows for each of the years in the three‑year period ended December 31, 2014. These consolidated financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Partnership as of December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the years in the three‑year period ended December 31, 2014, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Eagle Rock Energy Partners, L.P.’s internal control over financial reporting as of December 31, 2014, based on the criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 2, 2015 expressed an unqualified opinion on the effectiveness of the Partnership’s internal control over financial reporting.

/s/ KPMG LLP

Houston, Texas

March 2, 2015

F- 2

EX-99.3

Exhibit 99.3

EAGLE ROCK ENERGY PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except unit amounts)

	June 30, 2015		December 31, 2014
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	20	$	1,343
Short-term investments	—		153,448
Accounts receivable (a)	27,087		39,596
Risk management assets	36,169		44,805
Prepayments and other current assets	11,594		9,911
Total current assets	74,870		249,103
PROPERTY, PLANT AND EQUIPMENT — Net	438,867		487,988
INTANGIBLE ASSETS — Net	2,974		3,072
DEFERRED TAX ASSET	2,210		2,315
RISK MANAGEMENT ASSETS	38,469		46,490
OTHER ASSETS	4,788		5,307
TOTAL	$	562,178	$	794,275
LIABILITIES AND MEMBERS' EQUITY
CURRENT LIABILITIES:
Accounts payable	$	40,994	$	49,226
Accrued liabilities	7,079		8,053
Taxes payable	2,232		2,246
Total current liabilities	50,305		59,525
LONG-TERM DEBT	144,781		263,343
ASSET RETIREMENT OBLIGATIONS	48,335		47,907
DEFERRED TAX LIABILITY	28,589		30,321
OTHER LONG TERM LIABILITIES	4,960		4,709
COMMITMENTS AND CONTINGENCIES (Note 12)
MEMBERS' EQUITY (b)	285,208		388,470
TOTAL	$	562,178	$	794,275

________________________ 

(a) Net of allowance for bad debt of $1,540 as of June 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 June 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 June 30, 2015 and December 31, 2014, respectively.

See accompanying notes to unaudited condensed consolidated financial statements.  

1

EAGLE ROCK ENERGY PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per unit amounts)

	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
REVENUE:
Natural gas, natural gas liquids, oil, condensate and sulfur	$	33,212		$	51,967		$	62,725		$	107,051
Commodity risk management gains (losses), net	(11,535		)	(18,081		)	11,065			(28,114		)
Other revenue	(11		)	158			(2		)	310
Total revenue	21,666			34,044			73,788			79,247
COSTS AND EXPENSES:
Operations and maintenance	12,754			10,907			22,836			22,405
Taxes other than income	1,338			3,596			2,726			7,387
General and administrative	11,406			12,005			22,395			25,295
Impairment	—			—			68,344			—
Depreciation, depletion and amortization	16,390			20,299			31,035			40,705
Total costs and expenses	41,888			46,807			147,336			95,792
OPERATING LOSS	(20,222		)	(12,763		)	(73,548		)	(16,545		)
OTHER (EXPENSE) INCOME:
Interest expense, net	(2,121		)	(4,948		)	(4,439		)	(9,702		)
Interest rate risk management gains (losses), net	964			(571		)	(2,102		)	(861		)
Losses on short-term investments	(3,750		)	—			(5,754		)	—
Other income, net	1,068			2			3,203			3
Total other expense	(3,839		)	(5,517		)	(9,092		)	(10,560		)
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(24,061		)	(18,280		)	(82,640		)	(27,105		)
INCOME TAX BENEFIT	(695		)	(885		)	(1,521		)	(1,750		)
LOSS FROM CONTINUING OPERATIONS	(23,366		)	(17,395		)	(81,119		)	(25,355		)
DISCONTINUED OPERATIONS, NET OF TAX	(8		)	(25,646		)	(974		)	(36,249		)
NET LOSS	$	(23,374	)	$	(43,041	)	$	(82,093	)	$	(61,604	)

NET LOSS PER COMMON UNIT—BASIC AND DILUTED:
Loss from Continuing Operations
Common units - Basic	$	(0.16	)	$	(0.11	)	$	(0.54	)	$	(0.16	)
Common units - Diluted	$	(0.16	)	$	(0.11	)	$	(0.54	)	$	(0.16	)
Discontinued Operations
Common units - Basic	$	—		$	(0.16	)	$	(0.01	)	$	(0.23	)
Common units - Diluted	$	—		$	(0.16	)	$	(0.01	)	$	(0.23	)
Net Loss
Common units - Basic	$	(0.16	)	$	(0.27	)	$	(0.55	)	$	(0.39	)
Common units - Diluted	$	(0.16	)	$	(0.27	)	$	(0.55	)	$	(0.39	)
Weighted Average Units Outstanding
Common units - Basic	149,301			156,955			149,221			156,802
Common units - Diluted	149,301			156,955			149,221			156,802

 See accompanying notes to unaudited condensed consolidated financial statements.

2

EAGLE ROCK ENERGY PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In thousands)

	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
Net loss	$	(23,374	)	$	(43,041	)	$	(82,093	)	$	(61,604	)
Other comprehensive income:
Gain on short-term investments	3,603			—			3,603			—
Loss on short-term investments	—			—			(3,603		)	—
COMPREHENSIVE LOSS	$	(19,771	)	$	(43,041	)	$	(82,093	)	$	(61,604	)

 See accompanying notes to unaudited condensed consolidated financial statements.

UNAUDITED CONDENSED CONSOLIDATED STATEMENT OF MEMBERS’ EQUITY

FOR THE SIX MONTHS ENDED JUNE 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	—		(82,093		)	(82,093		)
Distributions	—		(21,123		)	(21,123		)
Vesting of restricted units	754,010		—			—
Repurchase of common units	(1,345,463	)	(3,046		)	(3,046		)
Equity based compensation	—		3,000			3,000
BALANCE — June 30, 2015	149,563,456		$	285,208		$	285,208

 See accompanying notes to unaudited condensed consolidated financial statements.  

3

EAGLE ROCK ENERGY PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

	Six Months Ended June 30,
	2015			2014
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(82,093	)	$	(61,604	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Discontinued operations	974			36,249
Depreciation, depletion and amortization	31,035			40,705
Impairment	68,344			—
Amortization of debt issuance costs	546			1,269
(Gain) loss from risk management activities, net	(8,963		)	28,975
Settlement of risk management instruments	27,505			(5,314		)
Equity-based compensation	3,000			4,042
Loss on short-term investments	5,754			—
Other	(1,625		)	(139		)
Changes in assets and liabilities—net of acquisitions:
Accounts receivable	6,436			(17,535		)
Prepayments and other current assets	(1,683		)	(7,193		)
Accounts payable	(12,442		)	7,704
Accrued liabilities	(783		)	(496		)
Other assets	9			(15		)
Other current liabilities	(784		)	(974		)
Net cash provided by operating activities	35,230			25,674
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment	(44,905		)	(63,789		)
Proceeds from sale of short-term investments	153,980			—
Net cash provided by (used in) investing activities	109,075			(63,789		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	66,600			315,150
Repayment of long-term debt	(185,200		)	(252,950		)
Payment of debt issuance costs	—			(410		)
Settlement of risk management instruments	(1,885		)	(3,425		)
Repurchase of common units	(3,046		)	(1,084		)
Distributions to members and affiliates	(21,123		)	(23,801		)
Net cash (used in) provided by financing activities	(144,654		)	33,480
CASH FLOWS FROM DISCONTINUED OPERATIONS:
Operating activities	(974		)	29,580
Investing activities	—			(24,280		)
Net cash (used in) provided by discontinued operations	(974		)	5,300
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS	(1,323		)	665
CASH AND CASH EQUIVALENTS—Beginning of period	1,343			76
CASH AND CASH EQUIVALENTS—End of period	$	20		$	741
NONCASH INVESTING AND FINANCING ACTIVITIES:
Investments in property, plant and equipment, not paid	$	16,540		$	22,304
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Interest paid—net of amounts capitalized	$	4,005		$	35,020
Cash paid for taxes	$	141		$	—

See accompanying notes to unaudited condensed consolidated financial statements.  

4

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 May 21, 2015, the Partnership announced an Agreement and Plan of Merger (the "Merger Agreement") with Vanguard Natural Resources, LLC ("Vanguard"), pursuant to which a subsidiary of Vanguard will merge into the Partnership (the "Merger"). As a result of the Merger, the Partnership will become a wholly owned indirect subsidiary of Vanguard. The transaction, which has been approved by the boards of directors of our general partner and Vanguard, will be 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. Eagle Rock Energy and Vanguard will coordinate to ensure that each Eagle Rock Energy unitholder receives, either from Eagle Rock Energy or Vanguard, a distribution for each month leading up to the Merger. The Merger is subject to customary closing conditions, including the approval by both Vanguard and Eagle Rock Energy unitholders of record as of August 6, 2015. Both unitholder meetings are scheduled for September 17, 2015.

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 six months endedJune 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.

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

5

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 three and six months endedJune 30, 2015, the Partnership received and recorded distributions of $1.0 million and $3.2 million, respectively, and recorded losses of $3.8 million and $5.8 million, respectively, as a result of the sale of the Regency Common Units. As of June 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.

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.

6

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 $0.5 million and $0.3 million as of June 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.

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.

7

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED 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.

NOTE 4. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment consisted of the following:

	June 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	14,958			13,234
Proved properties	884,836			905,622
Unproved properties	6,952			7,512
Work in progress	42			1,195
	910,121			930,896
Less: accumulated depreciation, depletion and amortization	(471,254		)	(442,908		)
Net property, plant and equipment	$	438,867		$	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 June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
	($ in thousands)
Depreciation	$	807	$	889	$	1,366	$	1,586
Depletion	$	14,727	$	19,334	$	28,446	$	39,006
Impairment expense:
Proved properties (a)	$	—	$	—	$	68,344	$	—

________________________________

(a) During the six months endedJune 30, 2015, the Partnership incurred impairment charges related to certain proved properties in Mid-Continent, East Texas and Permian regions primarily due to lower commodity prices.

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).

8

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	10			21
Liabilities settled	(1,497		)	(826		)
Revision to liabilities	124			(105		)
Accretion expense	1,600			1,620
Asset retirement obligations—June 30 (a)	$	51,110		$	49,274

_____________________________________

(a) As of June 30, 2015 and December 31, 2014, $2.8 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 six months endedJune 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.

Intangible assets consisted of the following:

	June 30, 2015			December 31, 2014
	($ in thousands)
Rights-of-way and easements—at cost	$	3,920		$	3,920
Less: accumulated amortization	(946		)	(848		)
Net intangible assets	$	2,974		$	3,072

9

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
	($ in thousands)
Amortization	$	49	$	49	$	98	$	98

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 June 30, 2015 is as follows (in thousands):

Year ending December 31,
2015	$	98
2016	$	196
2017	$	196
2018	$	196
2019	$	196
Thereafter	$	2,092

NOTE 7. LONG-TERM DEBT

Long-term debt consisted of the following:

	June 30, 2015			December 31, 2014
	($ in thousands)
Revolving credit facility:	$	94,000		$	212,600
Senior Notes:
8.375% Senior Notes due 2019	51,120			51,120
Unamortized bond discount	(339		)	(377		)
Total Senior Notes	50,781			50,743
Total long-term debt	$	144,781		$	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 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. The Partnership's next borrowing base redetermination is scheduled for October 1, 2015.

As of June 30, 2015, the Partnership had approximately $176.0 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 June 30, 2015, the Partnership had no outstanding letters of credit.

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EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

	Debt Covenant	Actual Covenant Ratio as of June 30, 2015
Maximum total leverage ratio	4.0	1.2
Minimum current ratio	1.0	4.3

As of June 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 June 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 June 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 $100.0 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 Partnership intends to cancel any units it repurchases under the repurchase program. During the six months endedJune 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+	$	0.07	February 6, 2015	February 13, 2015
March 31, 2015+	$	0.07	May 8, 2015	May 15, 2015
June 30, 2015+	$	0.07	August 6, 2015	August 14, 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.

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EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 9. RELATED PARTY TRANSACTIONS

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
Affiliates of Natural Gas Partners:	($ in thousands)
Natural gas purchases from affiliates	$	—	$	949	$	—	$	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 June 30, 2015:

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

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 June 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)	5,400,000	$	4.07
Crude Oil	Costless Collar	240,000	$	90.00		$	97.55
Crude Oil	Swap (Pay Floating/Receive Fixed)	315,000	$	89.78
IsoButane	Swap (Pay Floating/Receive Fixed)	1,625,400	$	0.68
Natural Gasoline	Swap (Pay Floating/Receive Fixed)	1,869,000	$	1.19
Normal Butane	Swap (Pay Floating/Receive Fixed)	2,961,000	$	0.67
Propane	Swap (Pay Floating/Receive Fixed)	7,383,600	$	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 June 30, 2015 and December 31, 2014:

	As of June 30, 2015
	Derivative Assets				Derivative Liabilities
	Balance Sheet Classification	Fair Value			Balance Sheet Classification	Fair Value
	($ in thousands)
Interest rate derivatives - liabilities	Current assets	$	(3,366	)	Current liabilities	$	—
Interest rate derivatives - liabilities	Long-term assets	(2,657		)	Long-term liabilities	—
Commodity derivatives - assets	Current assets	39,634			Current liabilities	—
Commodity derivatives - assets	Long-term assets	41,191			Long-term liabilities	—
Commodity derivatives - liabilities	Current assets	(99		)	Current liabilities	—
Commodity derivatives - liabilities	Long-term assets	(65		)	Long-term liabilities	—
Total derivatives		$	74,638			$	—
	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 June 30,						Six Months Ended June 30,
		2015			2014			2015			2014
		($ in thousands)
Interest rate derivatives	Interest rate risk management losses, net	$	964		$	(571	)	$	(2,102	)	$	(861	)
Commodity derivatives	Commodity risk management gains (losses), net	(11,535		)	(18,081		)	11,065			(28,114		)
Commodity derivatives	Discontinued operations	—			(10,968		)	—			(15,879		)
Commodity derivatives - trading	Discontinued operations	—			(1,416		)	—			(2,404		)
	Total	$	(10,571	)	$	(31,036	)	$	8,963		$	(47,258	)

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 June 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 June 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 June 30, 2015 and December 31, 2014: 

	As of June 30, 2015
	Level 1		Level 2			Level 3		Netting (a)			Total
	($ in thousands)
Assets:
Crude oil derivatives	$	—	$	63,109		$	—	$	(25	)	$	63,084
Natural gas derivatives	—		16,366			—		(56		)	16,310
NGL derivatives	—		1,350			—		(83		)	1,267
Interest rate swaps	—		—			—		(6,023		)	(6,023		)
Total	$	—	$	80,825		$	—	$	(6,187	)	$	74,638
Liabilities:
Crude oil derivatives	$	—	$	(25	)	$	—	$	25		$	—
Natural gas derivatives	—		(56		)	—		56			—
NGL derivatives	—		(83		)	—		83			—
Interest rate swaps	—		(6,023		)	—		6,023			—
Total	$	—	$	(6,187	)	$	—	$	6,187		$	—

____________________________

(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 six months endedJune 30, 2015. The following table discloses the fair value of the Partnership's assets measured at fair value on a nonrecurring basis during the six months endedJune 30, 2015:

	Six Months Ended June 30,
	2015		Level 1		Level 2		Level 3		Total Losses
	($ in thousands)
Proved properties	$	44,658	$	—	$	—	$	44,658	$	68,344

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 June 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 June 30, 2015 and December 31, 2014, the Partnership estimates that the fair value of the Senior Notes was $51.1 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 June 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 lawsuits name 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. Plaintiffs in the lawsuits allege 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 lawsuits allege that the Merger (a) provides inadequate consideration to our unitholders, (b) is not subject to minority unitholder approval due to (i) the absence of a majority-of-the-minority vote requirement and (ii) the voting and support agreement between Vanguard, Natural Gas Partners VIII, L.P., and certain of its affiliates, (c) contains contractual terms (e.g., the no-solicitation, matching rights, and termination fee provisions) that will dissuade other potential merger partners from making alternative proposals and (d) does not include a collar to protect our unitholders against declines in Vanguard’s unit price. 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 fails, 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 lawsuits seek to enjoin us from proceeding with or consummating the Merger. To the extent that the Merger is consummated before injunctive relief is granted, the plaintiffs seek to have the Merger rescinded. The plaintiffs seek attorneys' fees, and the plaintiff in the federal lawsuit also seeks monetary damages. The Partnership believes that the lawsuits are without merit.

On July 30, 2015, a wholly owned subsidiary of the Partnership received verbal notice 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), 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 the Emergency Planning and Community Right to Know Act (“EPCRA”), 40 CFR Parts 304, 307 and 372 (“EPCRA”). EPA proposed a penalty of approximately $106,000. The wholly owned subsidiary of the Partnership is awaiting written notice from EPA, and is evaluating EPA's stated basis for the penalty and alleged violations, and EPA's calculation of the proposed penalty.

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 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

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EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 June 30, 2015 and December 31, 2014, the Partnership had accrued approximately $2.7 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, $0.8 million and $0.8 million, $1.6 million, respectively, for the three and six months endedJune 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

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 six months endedJune 30, 2015 and June 30, 2014, the Partnership recognized an income tax benefit of $0.7 million, $1.5 million, $0.9 million and $1.8 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 June 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.

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EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 six months endedJune 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 June 30, 2015	3,423,262		$	3.64

Performance Units

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.

20

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

A summary of the changes in outstanding performance units for the six months endedJune 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 June 30, 2015	1,396,544		$	3.00

Equity-Based Compensation

For the three and six months endedJune 30, 2015 and June 30, 2014, the Partnership recorded non-cash compensation expense of approximately $1.1 million, $3.0 million and $1.5 million, $4.0 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 June 30, 2015, unrecognized compensation costs related to the outstanding restricted units and performance units under the LTIP totaled approximately $13.4 million. The remaining expense is to be recognized over a weighted average of 2.28 years.

In connection with the vesting of certain restricted units during the three months endedJune 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.

21

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 June 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 June 30,		Six Months Ended June 30,
	2015	2014	2015	2014
	(in thousands)
Weighted average units outstanding during period:
Common units - Basic	149,301	156,955	149,221	156,802
Common units - Diluted	149,301	156,955	149,221	156,802

22

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 June 30, 2015:

	Total			Common Units			Restricted Common Units*
	($ in thousands, except for per unit amounts)
Loss from continuing operations	$	(23,366	)
Distributions	10,699			$	10,469		$	230
Assumed loss from continuing operations after distribution to be allocated	(34,065		)	(34,065		)	—
Assumed allocation of loss from continuing operations	(23,366		)	(23,596		)	230
Discontinued operations	(8		)	(8		)	—
Assumed net loss to be allocated	$	(23,374	)	$	(23,604	)	$	230
Basic loss from continuing operations per unit				$	(0.16	)
Basic discontinued operations per unit				$	—
Basic loss per unit				$	(0.16	)
Diluted loss from continuing operations per unit				$	(0.16	)
Diluted discontinued operations per unit				$	—
Diluted loss per unit				$	(0.16	)

_____________________________

* 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 June 30, 2014:

	Total			Common Units			Restricted Common Units*
	($ in thousands, except for per unit amounts)
Loss from continuing operations	$	(17,395	)
Distributions**	—			$	—		$	—
Assumed loss from continuing operations after distribution to be allocated	(17,395		)	(17,395		)	—
Assumed allocation of loss from continuing operations	(17,395		)	(17,395		)	—
Discontinued operations	(25,646		)	(25,646		)	—
Assumed net loss to be allocated	$	(43,041	)	$	(43,041	)	$	—
Basic loss from continuing operations per unit				$	(0.11	)
Basic discontinued operations per unit				$	(0.16	)
Basic and diluted loss per unit				$	(0.27	)
Diluted loss from continuing operations per unit				$	(0.11	)
Diluted discontinued operations per unit				$	(0.16	)
Diluted loss per unit				$	(0.27	)

_____________________________

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

** No distribution was declared or paid for this period as the distribution was suspended for this period.

23

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 six months ended June 30, 2015:

	Total			Common Units			Restricted Common Units*
	($ in thousands, except for per unit amounts)
Loss from continuing operations	$	(81,119	)
Distributions	21,256			$	20,902		$	354
Assumed loss from continuing operations after distribution to be allocated	(102,375		)	(102,375		)	—
Assumed allocation of loss from continuing operations	(81,119		)	(81,473		)	354
Discontinued operations, net of tax	(974		)	(974		)	—
Assumed net loss to be allocated	$	(82,093	)	$	(82,447	)	$	354
Basic loss from continuing operations per unit				$	(0.54	)
Basic discontinued operations per unit				$	(0.01	)
Basic loss per unit				$	(0.55	)
Diluted loss from continuing operations per unit				$	(0.54	)
Diluted discontinued operations per unit				$	(0.01	)
Diluted loss per unit				$	(0.55	)

_____________________________

* 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 six months ended June 30, 2014:

	Total			Common Units			Restricted Common Units*
	($ in thousands, except for per unit amounts)
Loss from continuing operations	$	(25,355	)
Distributions**	—			$	—		$	—
Assumed loss from continuing operations after distribution to be allocated	(25,355		)	(25,355		)	—
Assumed allocation of loss from continuing operations	(25,355		)	(25,355		)	—
Discontinued operations, net of tax	(36,249		)	(36,249		)	—
Assumed net loss to be allocated	$	(61,604	)	$	(61,604	)	$	—
Basic income from continuing operations per unit				$	(0.16	)
Basic discontinued operations per unit				$	(0.23	)
Basic loss per unit				$	(0.39	)
Diluted income from continuing operations per unit				$	(0.16	)
Diluted discontinued operations per unit				$	(0.23	)
Diluted income per unit				$	(0.39	)

_____________________________

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

** No distribution was declared or paid for this period as the distribution was suspended for this period.

24

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 six months endedJune 30, 2015 and 2014:

	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
							($ in thousands)
Class of statement of operations line item of discontinued operations:
Revenue	$	—		$	245,210		$	—		$	548,081
Cost of natural gas, NGLs, condensate and helium	—			199,700			—			444,673
Operations, maintenance and taxes other than income	—			25,078			—			50,127
General and administrative	8			12,107			974			20,208
Depreciation, amortization and impairment	—			19,737			—			41,936
Interest expense	—			(14,118		)	—			(27,350		)
Other expense	—			(60		)	—			(68		)
Operating loss from discontinued operations before taxes	(8		)	(25,590		)	(974		)	(36,281		)
Income tax expense (benefit)	—			56			—			(32		)
Discontinued operations, net of tax	$	(8	)	$	(25,646	)	$	(974	)	$	(36,249	)

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 three months ended June 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 three months ended June 30, 2015.

	Employee Related Costs			Facility and Other Costs		Total
	($ in thousands)
Balance at December 31, 2014	$	835		$	490	$	1,325
Payments and other adjustments	(835		)	1,152		317
Balance at June 30, 2015	$	—		$	1,642	$	1,642

NOTE 17. SUBSIDIARY GUARANTORS

The Partnership has issued registered debt securities guaranteed by its subsidiaries.  As of June 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 June 30, 2015 and December 31, 2014, and unaudited condensed consolidated statements of operations for the three and six months endedJune 30, 2015 and 2014, and unaudited condensed consolidated statements of cash flows for the six months endedJune 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.

25

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Balance Sheet

June 30, 2015

	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Consolidating Entries			Total
	($ in thousands)
ASSETS:
Accounts receivable – related parties	$	838,125		$	—	$	—		$	(838,125	)	$	—
Other current assets	40,055			1		34,814			—			74,870
Total property, plant and equipment, net	1,260			—		437,607			—			438,867
Investment in subsidiaries	(489,500		)	—		—			489,500			—
Total other long-term assets	43,267			—		5,174			—			48,441
Total assets	$	433,207		$	1	$	477,595		$	(348,625	)	$	562,178
LIABILITIES AND EQUITY:
Accounts payable – related parties	$	—		$	—	$	838,125		$	(838,125	)	$	—
Other current liabilities	2,853			—		47,452			—			50,305
Other long-term liabilities	365			—		81,519			—			81,884
Long-term debt	144,781			—		—			—			144,781
Equity	285,208			1		(489,501		)	489,500			285,208
Total liabilities and equity	$	433,207		$	1	$	477,595		$	(348,625	)	$	562,178

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

26

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Statement of Operations

For the Three Months EndedJune 30, 2015

	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Consolidating Entries			Total
	($ in thousands)
Total revenues	$	(12,683	)	$	—	$	34,349		$	—		$	21,666
Operations and maintenance	—			—		12,754			—			12,754
Taxes other than income	—			—		1,338			—			1,338
General and administrative	3,923			—		7,483			—			11,406
Depreciation, depletion and amortization	274			—		16,116			—			16,390
Loss from operations	(16,880		)	—		(3,342		)	—			(20,222		)
Interest expense, net	(2,121		)	—		—			—			(2,121		)
Other non-operating income	3,175			—		2,276			(4,383		)	1,068
Other non-operating expense	(4,164		)	—		(3,005		)	4,383			(2,786		)
Loss before income taxes	(19,990		)	—		(4,071		)	—			(24,061		)
Income tax (expense) benefit	33			—		(728		)	—			(695		)
Equity in earnings of subsidiaries	(3,353		)	—		—			3,353			—
Loss from continuing operations	(23,376		)	—		(3,343		)	3,353			(23,366		)
Discontinued operations, net of tax	2			—		(10		)	—			(8		)
Net loss	$	(23,374	)	$	—	$	(3,353	)	$	3,353		$	(23,374	)

27

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Statement of Operations

For the Three Months EndedJune 30, 2014

	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-Guarantor Investments			Consolidating Entries			Total
	($ in thousands)
Total revenues	$	(18,081	)	$	—	$	52,125		$	—		$	—		$	34,044
Operations and maintenance	3			—		10,904			—			—			10,907
Taxes other than income	—			—		3,596			—			—			3,596
General and administrative	2,064			—		9,941			—			—			12,005
Depreciation, depletion and amortization	295			—		20,004			—			—			20,299
(Loss) income from operations	(20,443		)	—		7,680			—			—			(12,763		)
Interest expense, net	(4,946		)	—		(2		)	—			—			(4,948		)
Other non-operating income	2,163			—		2,291			—			(4,454		)	—
Other non-operating expense	(1,987		)	—		(3,036		)	—			4,454			(569		)
(Loss) income before income taxes	(25,213		)	—		6,933			—			—			(18,280		)
Income tax provision (benefit)	82			—		(967		)	—			—			(885		)
Equity in earnings of subsidiaries	9,377			—		—			—			(9,377		)	—
(Loss) income from continuing operations	(15,918		)	—		7,900			—			(9,377		)	(17,395		)
Discontinued operations, net of tax	(27,123		)	—		1,479			(2		)	—			(25,646		)
Net (loss) income	$	(43,041	)	$	—	$	9,379		$	(2	)	$	(9,377	)	$	(43,041	)

Unaudited Condensed Consolidating Statement of Operations

For the Six Months EndedJune 30, 2015

	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Consolidating Entries			Total
	($ in thousands)
Total revenues	$	8,544		$	—	$	65,244		$	—		$	73,788
Operations and maintenance	—			—		22,836			—			22,836
Taxes other than income	—			—		2,726			—			2,726
General and administrative	6,005			—		16,390			—			22,395
Depreciation, depletion and amortization	410			—		30,625			—			31,035
Impairment	—			—		68,344			—			68,344
Income (loss) from operations	2,129			—		(75,677		)	—			(73,548		)
Interest expense, net	(4,439		)	—		—			—			(4,439		)
Other non-operating income	7,432			—		4,540			(8,769		)	3,203
Other non-operating expense	(10,623		)	—		(6,002		)	8,769			(7,856		)
Loss before income taxes	(5,501		)	—		(77,139		)	—			(82,640		)
Income tax expense (benefit)	129			—		(1,650		)	—			(1,521		)
Equity in earnings of subsidiaries	(76,463		)	—		—			76,463			—
Loss from continuing operations	(82,093		)	—		(75,489		)	76,463			(81,119		)
Discontinued operations, net of tax	—			—		(974		)	—			(974		)
Net loss	$	(82,093	)	$	—	$	(76,463	)	$	76,463		$	(82,093	)

28

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Statement of Operations

For the Six Months EndedJune 30, 2014

	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-Guarantor Investments			Consolidating Entries			Total
	($ in thousands)
Total revenues	$	(28,114	)	$	—	$	107,361		$	—		$	—		$	79,247
Operations and maintenance	3			—		22,402			—			—			22,405
Taxes other than income	—			—		7,387			—			—			7,387
General and administrative	4,961			—		20,334			—			—			25,295
Depreciation, depletion and amortization	348			—		40,357			—			—			40,705
(Loss) income from operations	(33,426		)	—		16,881			—			—			(16,545		)
Interest expense, net	(9,700		)	—		(2		)	—			—			(9,702		)
Other non-operating income	4,384			—		4,592			—			(8,976		)	—
Other non-operating expense	(3,703		)	—		(6,131		)	—			8,976			(858		)
(Loss) income before income taxes	(42,445		)	—		15,340			—			—			(27,105		)
Income tax benefit	(185		)	—		(1,565		)	—			—			(1,750		)
Equity in earnings of subsidiaries	28,011			—		—			—			(28,011		)	—
Loss from continuing operations	(14,249		)	—		16,905			—			(28,011		)	(25,355		)
Discontinued operations, net of tax	(47,355		)	—		11,115			(9		)	—			(36,249		)
Net (loss) income	$	(61,604	)	$	—	$	28,020		$	(9	)	$	(28,011	)	$	(61,604	)

29

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Statement of Cash Flows

For the Six Months EndedJune 30, 2015

	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Consolidating Entries		Total
	($ in thousands)
Net cash flows (used in) provided by operating activities	$	(10,873	)	$	—	$	46,103		$	—	$	35,230
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment	(337		)	—		(44,568		)	—		(44,905		)
Proceeds from sale of short-term investments	153,980			—		—			—		153,980
Net cash flows provided by (used in) investing activities	153,643			—		(44,568		)	—		109,075
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	66,600			—		—			—		66,600
Repayment of long-term debt	(185,200		)	—		—			—		(185,200		)
Payments for derivative contracts	(1,885		)	—		—			—		(1,885		)
Repurchase of common units	(3,046		)	—		—			—		(3,046		)
Distributions to members and affiliates	(21,123		)	—		—			—		(21,123		)
Net cash flows used in financing activities	(144,654		)	—		—			—		(144,654		)
Net cash flows used in discontinued operations	—			—		(974		)	—		(974		)
Net (decrease) increase in cash and cash equivalents	(1,884		)	—		561			—		(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	$	802		$	1	$	(783	)	$	—	$	20

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EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Statement of Cash Flows

For the Six Months EndedJune 30, 2014

	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-Guarantor Investments		Consolidating Entries		Total
	($ in thousands)
Net cash flows provided by operating activities	$	2,594		$	—	$	23,080		$	—	$	—	$	25,674
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment	4			—		(63,793		)	—		—		(63,789		)
Net cash flows provided by (used in) investing activities	4			—		(63,793		)	—		—		(63,789		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	315,150			—		—			—		—		315,150
Repayment of long-term debt	(252,950		)	—		—			—		—		(252,950		)
Payment of debt issuance cost	(410		)	—		—			—		—		(410		)
Payments for derivative contracts	(3,425		)	—		—			—		—		(3,425		)
Repurchase of common units	(1,084		)	—		—			—		—		(1,084		)
Distributions to members and affiliates	(23,801		)	—		—			—		—		(23,801		)
Net cash flows provided by financing activities	33,480			—		—			—		—		33,480
Net cash flows (used in) provided by discontinued operations	(34,973		)	—		40,251			22		—		5,300
Net increase (decrease) in cash and cash equivalents	1,105			—		(462		)	22		—		665
Cash and cash equivalents at beginning of period	1,237			1		(1,389		)	227		—		76
Cash and cash equivalents at end of period	$	2,342		$	1	$	(1,851	)	$	249	$	—	$	741

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