10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2015

OR

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number 001-33016

EAGLE ROCK ENERGY PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

Delaware	68-0629883
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification Number)

1415 Louisiana Street, Suite 2700

Houston, Texas 77002

(Address of principal executive offices, including zip code)

(281) 408-1200

(Registrant's telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes  x No  o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes  x    No  o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated Filer  x	Accelerated Filer  o
Non-accelerated Filer  o	Smaller reporting company  o

 (Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  o    No  x

The issuer had 152,986,718 common units outstanding as of July 28, 2015.

TABLE OF CONTENTS

		Page
PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements	2
	Unaudited Condensed Consolidated Balance Sheets as of June 30, 2015 and December 31, 2014	2
	Unaudited Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2015 and 2014	3
	Unaudited Condensed Consolidated Statements of Comprehensive Income for the three and six months ended June 30, 2015 and 2014	4
	Unaudited Condensed Consolidated Statement of Members' Equity for the six months ended June 30, 2015	4
	Unaudited Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2015 and 2014	5
	Notes to Unaudited Condensed Consolidated Financial Statements	6
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	34
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	49
Item 4.	Controls and Procedures	50
PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	51
Item 1A.	Risk Factors	51
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	53
Item 3.	Defaults Upon Senior Securities	53
Item 4.	Mine Safety Disclosures	53
Item 5.	Other Information	53
Item 6.	Exhibits	53

1

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

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.  

2

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.

3

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.  

4

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.  

5

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. ORGANIZATION AND DESCRIPTION OF BUSINESS

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

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

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

Recent Developments—On 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

6

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.

7

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.

8

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).

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EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 5. ASSET RETIREMENT OBLIGATIONS

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

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

	2015			2014
	($ in thousands)
Asset retirement obligations—January 1 (a)	$	50,873		$	48,564
Additional liabilities	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

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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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EAGLE ROCK ENERGY PARTNERS, L.P.

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.

21

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.

22

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

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 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.

24

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.

25

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

26

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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.

27

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

28

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	)

29

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	)

30

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	)

31

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

32

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

33

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This report includes “forward-looking statements” as defined by federal securities laws. All statements, other than statements of historical facts, included in this report that address activities, events or developments that we expect, believe or anticipate will or may occur in the future are forward-looking statements. These statements are based on certain assumptions made by us based on our experience and perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate under the circumstances. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond our control, which may cause our actual results to differ materially from those implied or expressed by the forward-looking statements. Except as required by law, we do not assume any obligation to update such forward-looking statements following the date of this report. For a complete description of known material risks, please read our risk factors set forth in our Annual Report on Form 10-K for the year ended December 31, 2014 (the "2014 10-K") and in "Part II. Item 1A. Risk Factors," as well as any other risks described elsewhere in this report. These factors include but are not limited to:

• Risks related to the Merger (as defined below);

• Drilling and geological/exploration risks;

• Assumptions regarding oil and natural gas reserve levels and costs to exploit and timing of development;

• Volatility or continued low or further declining commodity prices;

• Ability to make favorable acquisitions and integrate operations from such acquisitions;

• Our existing indebtedness;

• Hedging activities;

• Ability to obtain credit and access capital markets;

• Ability to remain in compliance with the covenants set forth in our revolving credit facility;

• Conditions in the securities and/or capital markets;

• Availability and cost of processing and transporting of natural gas liquids ("NGLs");

• Competition in the oil and natural gas industry;

• Relevant legislative or regulatory changes, including retroactive royalty or production tax regimes, changes in environmental, health and safety regulation, hydraulic fracturing regulation, environmental risks and liability under federal, state, local and foreign environmental laws and regulations;

• Shortages of personnel and equipment;

• Increases in interest rates;

• Creditworthiness of our counterparties;

• Weather, including the occurrence of any adverse weather conditions and/or natural disasters affecting our business;

• Any other factors that impact or could impact the exploration of oil or natural gas resources, including but not limited to the geology of a resource, the total amount and costs to develop recoverable reserves, legal title, regulatory, natural gas administration, marketing and operations factors relating to the extraction of oil and natural gas;

• Tax risk associated with pass-through investment, including proposed qualifying income regulations, potential reduction in tax shield or creation of phantom income in the event distributions are not enough to support the tax burden; and

• Impact of cyber-security threats and related disruptions.

34

OVERVIEW

The following discussion analyzes our financial condition and results of operations, which should be read in conjunction with our unaudited condensed consolidated financial statements and notes thereto included elsewhere in this report, as well as the 2014 10-K filed with the Securities and Exchange Commission. For a description of oil and natural gas terms, see the 2014 10-K.

Results Overview

We are a domestically focused, growth-oriented, publicly traded Delaware master limited partnership engaged in developing and producing oil and natural gas property interests. Our interests include operated and non-operated wells located in the Mid-Continent (which includes areas in Oklahoma, Arkansas and the Texas Panhandle); Alabama (which also includes one treating facility and one natural gas processing plant and related gathering system); Permian (which includes areas in West Texas); East Texas; South Texas; and Mississippi.

On July 1, 2014, we contributed our 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 in the financial statements included in this report. As a result of this transaction, we only report as one segment.

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 collectively referred to with the original units as "Regency Common Units").   

Results for the three and six months endedJune 30, 2015, included the following:

• revenues, excluding the impact of commodity risk management gains (losses), were $33.2 million and $62.7 million for the three and six months endedJune 30, 2015, respectively, compared to $52.1 million and $107.4 million for the three and six months endedJune 30, 2014, respectively;

• commodity risk management losses were $11.5 million for the three months endedJune 30, 2015 and commodity risk management gains were $11.1 million for the six months endedJune 30, 2015, compared to commodity risk management losses of $18.1 million and $28.1 million for the three and six months endedJune 30, 2014, respectively;

• no impairment charge for the three months endedJune 30, 2015 and a $68.3 million impairment charge for the six months endedJune 30, 2015, compared to no impairment charges for each of the three and six months endedJune 30, 2014;

• operating losses were $20.2 million and $73.5 million for the three and six months endedJune 30, 2015, respectively, compared to operating losses of $12.8 million and $16.5 million for the three and six months endedJune 30, 2014, respectively;

• average daily production was 81 MMcfe/d for the six months endedJune 30, 2015, compared to 72 MMcfe/d for the six months endedJune 30, 2014; and

• capital expenditures were $22.1 million and $49.1 million for the three and six months endedJune 30, 2015, respectively, compared to $36.1 million and $76.9 million for the three and six months endedJune 30, 2014, respectively.

Recent Developments

On May 21, 2015, we 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

35

Rock Energy's net 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.

Impairment

We did not record any impairment charges during the three months endedJune 30, 2015. We recorded an impairment charge of $68.3 million during the six months endedJune 30, 2015 related to certain proved properties in our Mid-Continent, East Texas and Permian regions primarily due to lower commodity prices. During the three and six months endedJune 30, 2014, we recorded an impairment charge of $2.1 million in our Midstream Business due to the loss of two customers. Impairment charges related to our Midstream Business have been recorded as part of discontinued operations within the statements of operations. Absent significant increases during the remainder of 2015, the lower oil and natural gas prices experienced in the second half of 2014 and the current year will continue to impact our proved reserves adversely as the prices used for such estimates under SEC rules are based on the trailing 12-month unweighted average prices. Lower prices used in estimating proved reserves may result in a reduction in volumes due to economic limits or render undeveloped reserves non-economic, which in turn, without significant additions to proved reserves, may cause us to incur additional impairment charges in the future, which could have a material adverse effect on our results of operations and financial position in the periods in which such charges are taken.

Pursuant to accounting principles generally accepted in the United States of America ("GAAP"), our impairment analysis does not take into account the value of our commodity derivative instruments, which generally increase as the estimates of future prices decline.  To calculate the estimated cash flows used in our impairment tests, we use the forward strip prices as of the date of the impairment.

36

RESULTS OF OPERATIONS

Summary of Consolidated Operating Results

Below is a table of a summary of our consolidated operating results for the three and six months endedJune 30, 2015and 2014.

	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
	($ in thousands)
Revenues:
Oil and condensate	$	18,234		$	26,493		$	31,563		$	53,627
Natural gas	7,936			12,899			16,510			27,498
NGLs	4,911			10,247			10,030			21,713
Sulfur	2,131			2,328			4,622			4,213
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		)
Loss 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 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	)
Adjusted EBITDA(a)	$	25,701		$	24,899		$	51,251		$	50,995

________________________

(a) Adjusted EBITDA is not a measure calculated in accordance with GAAP. See "—Liquidity and Capital Resources — Non-GAAP Financial Measures" for a definition and reconciliation to GAAP.

37

	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
Realized average prices:
Oil and condensate (per Bbl)	$	49.61	$	88.21	$	44.04	$	86.85
Natural gas (per Mcf)	$	2.37	$	4.38	$	2.56	$	4.66
NGLs (per Bbl)	$	14.61	$	35.38	$	15.11	$	38.55
Sulfur (per Long ton)	$	87.55	$	91.09	$	95.91	$	84.22
Production volumes:
Oil and condensate (Bbl)	367,533		300,330		716,754		617,456
Natural gas (Mcf)	3,343,594		2,943,718		6,453,828		5,895,866
NGLs (Bbl)	336,226		289,639		663,707		563,312
Total (Mcfe)	7,566,148		6,483,532		14,736,594		12,980,474
Sulfur (Long ton)	24,342		25,554		48,189		50,015
Capital expenditures ($ in thousands)	$	22,076	$	36,106	$	49,079	$	76,941

Production Revenues. For the three and six months endedJune 30, 2015, our production revenues, which exclude commodity risk management gains (losses), decreased by $18.9 million and $44.6 million, respectively, as compared to the three and six months endedJune 30, 2014.  The decrease in production revenues for the three months endedJune 30, 2015 compared to the three months endedJune 30, 2014 was due to lower realized commodity prices and sulfur volumes, partially offset by higher oil, natural gas and NGL volumes. The decrease in production revenues for the six months endedJune 30, 2015 compared to the six months endedJune 30, 2014 was due to lower realized oil, natural gas and NGL prices and lower sulfur revenues, partially offset by higher oil, natural gas and NGL volumes and higher sulfur prices.

Production volumes during the three and six months endedJune 30, 2015 were positively impacted by strong production from both operated and non-operated wells drilled since June 30, 2014.

In April 2015, we completed a scheduled turnaround of our Big Escambia Creek facility to make certain equipment repairs and routine inspections of equipment. The turnaround took approximately 12 days to complete. We estimate the net revenue impact of the lost production was approximately $1.1 million and the net turnaround expense was approximately $3.4 million. The turnaround reduced our production in the three months ended June 30, 2015 by approximately 19 MBbls of oil, 39 MMcf of residue gas, 9 MBbls of NGLs and 2,100 long ton of sulfur.

Commodity Risk Management Gains (Losses), net. During the three months endedJune 30, 2015, lossesin our commodity derivative portfolio decreased by $6.5 million as compared to the three months endedJune 30, 2014. During the six months endedJune 30, 2015, gains in our commodity derivative portfolio increased by $39.2 million as compared to the six months endedJune 30, 2014. During the three and six months endedJune 30, 2015, our gains due to the change in the mark-to-market value of our derivative contracts decreased $8.8 million and increased $6.4 million, respectively, as compared to the three and six months endedJune 30, 2014 primarily due to decreases in prices on the natural gas, NGL and crude oil forward curves. Our commodity risk management gains from derivative contracts that settled during the three and six months endedJune 30, 2015 increased by $15.3 million and $32.8 million, respectively, compared to the three and six months endedJune 30, 2014. This increase was due to lower natural gas, NGL and crude oil index prices in relation to the strike prices of our settled contracts as compared to the same period in the prior year.

Given the uncertainty surrounding future commodity prices, and the general inability to predict future commodity prices as they relate to the strike prices at which we have hedged our exposure, it is difficult to predict the magnitude and impact that marking our hedges to market will have on our income from operations in future periods.

Operations and Maintenance. Operations and maintenance expenses increased by $1.8 million and $0.4 million, respectively, for the three and six months endedJune 30, 2015 as compared to the three and six months endedJune 30, 2014.  The increase was primarily due to the expenses incurred for the turnaround of our Big Escambia Creek facility (discussed above) and increases due to additional wells drilled, partially offset by decreased lease operating expenses and lower expenses related to workovers.

38

Taxes Other Than Income. Taxes other than income, which includes severance and ad valorem taxes, for the three and six months endedJune 30, 2015, decreased by $2.3 million and $4.7 million, respectively, as compared to the three and six months endedJune 30, 2014. The decrease was primarily due to lower estimated severance taxes resulting from decreased production revenue.

General and Administrative Expenses. General and administrative expenses decreased by $0.6 million and $2.9 million, respectively, for the three and six months endedJune 30, 2015 as compared to the same period in 2014. This decrease was primarily due to lower compensation and benefit expenses due to the reduction in headcount as a result of the Midstream Business Contribution and lower equity-based compensation expense due to an increases made to the estimated forfeiture rate during 2014. The forfeiture rate is used to calculate the amount of equity-based compensation expense. These declines were offset by approximately $2.6 million of professional fees incurred during the three and six months endedJune 30, 2015 related to the potential merger with Vanguard.

Depletion, Depreciation and Amortization. Depletion, depreciation and amortization expense decreased by $3.9 million and $9.7 million, respectively, for the three and six months endedJune 30, 2015 as compared to the same period in the prior year.  The decrease was primarily a result of the impairment charges recorded during fourth quarter of 2014 and the first quarter of 2015.

Impairment. During the six months endedJune 30, 2015, we incurred an impairment charge of $68.3 million related to certain proved properties in our Mid-Continent, East Texas and Permian regions primarily due to lower commodity prices. We did not incur an impairment charge during the three months endedJune 30, 2015 and the three and six months endedJune 30, 2014.

Interest Expense, Net. Interest expense decreased by $2.8 million and $5.3 million, respectively, during the three and six months endedJune 30, 2015 as compared to the three and six months endedJune 30, 2014.  Interest expense is shown before the impact of our interest rate derivatives, which convert a portion of our outstanding debt from variable-rate interest obligations to fixed-rate interest obligations.  The decrease in interest expense is primarily due to the repayment of borrowings outstanding under our revolving credit facility.

Interest Rate Risk Management Gains (Losses), Net. During the three and six months endedJune 30, 2015, our interest rate risk management losses decreased by $1.5 million and increased by $1.2 million, respectively, as compared to the three and six months endedJune 30, 2014 due to changes in the forward interest rate curve.

Loss on Short-Term Investments. During the three and six months endedJune 30, 2015, we incurred losses on the sales of the common units we held as short-term investments (see Note 2 to the unaudited condensed consolidated financial statements).

Other Income, Net. During the three and six months endedJune 30, 2015, we received distributions of $1.0 million and $3.2 million, respectively, related to common units we held as short-term investments.

Income Tax Benefit. Income tax benefit for 2015 and 2014 relates to (i) state taxes due by us and (ii) federal taxes due by Eagle Rock Energy Acquisition Co., Inc. and Eagle Rock Energy Acquisition Co. II, Inc. and their wholly-owned subsidiary corporations, Eagle Rock Upstream Development Company, Inc. and Eagle Rock Upstream Development Company II, Inc., all of which are subject to federal income taxes.

Discontinued Operations, Net of Tax. On July 1, 2014, we completed our Midstream Business Contribution to Regency and the operations related to our Midstream Business have been classified as discontinued. See Note 16 to the unaudited condensed consolidated financial statements for the major line items that comprise discontinued operations.

Capital Expenditures.  Capital expenditures decreased by $14.0 million and $27.9 million, respectively, for the three and six months endedJune 30, 2015 as compared to the three and six months endedJune 30, 2014. The decrease in capital expenditures was primarily due to decreased spending on our drilling program.

During the three months endedJune 30, 2015, we participated in thirteen gross (1.2 net) non-operated wells in the Mid-Continent region. We did not drill and complete any operated wells. Additionally, during the three months ended June 30, 2015, we conducted one gross (0.6 net) capital workover.

39

Adjusted EBITDA

Adjusted EBITDA, as defined under "— Non-GAAP Financial Measures," from continuing operations increased by $0.8 million from $24.9 million for the three months endedJune 30, 2014 to $25.7 million for the three months endedJune 30, 2015. Adjusted EBITDA from continuing operations increased by $0.3 million from $51.0 million for the six months endedJune 30, 2014 to $51.3 million for the six months endedJune 30, 2015. The following table presents the changes in operations impacting Adjusted EBITDA:

	Three Months Ended June 30,								Six Months Ended June 30,
	2015		2014			Change			2015		2014			Change
	($ in thousands)
Revenues (a)	$	33,258	$	52,124		$	(18,866	)	$	62,906	$	107,354		$	(44,448	)
Commodity derivative settlements	13,135		(2,176		)	15,311			27,505		(5,314		)	32,819
Operating expenses	14,092		14,503			(411		)	25,562		29,792			(4,230		)
General and administrative expenses (b)	7,645		10,546			(2,901		)	16,777		21,253			(4,476		)
Distributions received on short-term investments	1,045		—			1,045			3,179		—			3,179
Adjusted EBITDA (c)	$	25,701	$	24,899		$	802		$	51,251	$	50,995		$	256

_________________________

(a) Excludes the impact of imbalances.

(b) Excludes non-cash compensation charges related to our long-term incentive program and other non-recurring charges incurred during the three and six months ended June 30, 2015 related to the potential merger with Vanguard.

(c) Adjusted EBITDA is not a measure calculated in accordance with GAAP. See "— Non-GAAP Financial Measures" for a definition and reconciliation to GAAP.

40

LIQUIDITY AND CAPITAL RESOURCES

Historically, our sources of liquidity have included cash generated from operations, issuances of equity and debt securities, borrowings under our Credit Agreement (as defined below) and asset sales. Our primary cash requirements have included general and administrative expenses, operating expenses, maintenance and growth capital expenditures, short-term working capital needs, interest payments on our outstanding debt, distributions to our unitholders and acquisitions of new assets or businesses.

In connection with the consummation of the Midstream Business Contribution, we were able to improve our liquidity position by paying down our borrowings under our Credit Agreement, resulting in increased borrowing availability, and exchanging $498.9 million of our 8.375% Senior Notes due 2019 (the "Senior Notes"), resulting in significantly decreased debt levels. In addition, we received 8,245,859 Regency common units as part of the consideration received for the Midstream Business Contribution. As of June 30, 2015, we have sold all of the units received as consideration for the Midstream Business Contribution.

We believe that our improved liquidity position as a result of the Midstream Business Contribution and our historical sources of liquidity will be sufficient to satisfy our short-term liquidity needs and to fund our committed capital expenditures for at least the next twelve months. Absent the Merger, our growth strategy entails pursuing attractive upstream acquisitions and organic drilling opportunities. We may utilize any of various available financing sources, including liquidity from the consummation of the Midstream Business Contribution, proceeds from the issuance of equity or debt securities or borrowings under our Credit Agreement to fund all or a portion of our potential acquisitions and organic growth expenditures. Our ability to complete future offerings of equity or debt securities and the timing of these offerings will depend upon various factors, including prevailing market conditions and our financial condition.

Capital Expenditures

The energy business can be capital intensive, requiring significant investment for the acquisition or development of new facilities. We categorize our capital expenditures as (and, as necessary, allocate the attributable portion of our capital expenditures between) either:

• growth capital expenditures, defined as expenditures to grow our natural gas, NGL, crude or sulfur production; or

• maintenance capital expenditures, defined as expenditures necessary to maintain our natural gas, NGL, crude or sulfur production.

With respect to maintenance capital expenditures, we estimate these amounts based on current projections and expectations, and do not undertake to adjust any historical amounts based on the actual impact of such expenditures on production. As a result, the included amount of maintenance capital expenditures could fail to maintain production if actual performance does not meet our projections and expectations, including, without limitation, on account of: (i) unanticipated mechanical issues; (ii) unanticipated delays; (iii) poorer than expected production performance of our new wells and recompletions; and/or (iv) unanticipated loss of, or higher than anticipated decline in, existing production.

The primary impact of this categorization is that we reduce the amount of cash we consider available for distribution by the amount of our maintenance capital expenditures.

We anticipate that our capital expenditures for the remainder of 2015 will be approximately $34.6 million, of which we expect approximately $20.0 million to be categorized as maintenance capital expenditures and $14.6 million to be categorized as growth capital expenditures.

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Our capital expenditures were approximately $22.1 million and $49.1 million for the three and six months endedJune 30, 2015, respectively, of which $10.1 million and $20.4 million were related to maintenance capital expenditures and $12.0 million and $28.7 million were related to growth capital expenditures.

In order to lower sulfur dioxide ("SO₂") emissions from our Big Escambia Creek facility, as required by our existing air emissions permit, our operating subsidiary initiated the first phase of an SO₂ emissions reduction project at our Big Escambia Creek facility in December 2011. This phase of the project involved adding a Superclaus reactor to the existing sulfur recovery unit to achieve the desired reduction in SO₂ emissions. The new unit began operations on December 17, 2012, and through June 30, 2015 had resulted in increased sulfur production and reductions in SO₂ emissions to levels within the required permitted levels.

The second and final phase of our SO₂ emissions reduction project involves replacing or upgrading certain components of our existing sulfur recovery unit at the Big Escambia Creek facility. This phase is designed to improve the operational reliability of the processing facility, further increase the quantity of marketable sulfur recovered from the inlet gas stream, reduce the frequency of facility turnarounds, extend the facility's operating life and achieve cost savings across our operations in Alabama. In the first of these planned upgrades, we expect to replace the incinerator portion of the sulfur recovery unit in 2020 at a cost of approximately $7 million net to our interest. The facility will require further upgrades to repair or replace certain sulfur recovery unit components beyond 2020.

Distribution Policy

Our distribution policy is to distribute to our unitholders, on a quarterly basis, all of our available cash, if any, in the manner described below and as further described in our partnership agreement. Available cash generally means, for any quarter ending prior to liquidation, all cash and cash equivalents on hand at the end of that quarter (or, if our general partner chooses, on the date of determination) less the amount of cash reserves established by our general partner to:

• provide for the proper conduct of our business, including for future capital expenditures and credit and other needs;

• comply with applicable law or any of our debt instruments or other agreements; or

• provide funds for distributions to unitholders in respect of any one or more of the next four quarters.

Pursuant to our distribution policy, the actual distributions we declare are subject to our operating performance, prevailing market conditions (including forward oil, condensate, natural gas, NGL and sulfur prices), the impact of unforeseen events and the approval of our Board of Directors. 

Revolving Credit Facility

On October 10, 2014, we entered into the Fifth Amendment (the "Fifth Amendment") to our 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 our commercial lenders and extended the maturity to October 2019. In addition, as a result of the completion of the Midstream Business Contribution, our borrowing base under the Credit Agreement is now strictly based on the value of our oil and natural gas properties and our commodity derivative contracts. The recent decline in oil and natural gas prices impacted the value of our estimated proved reserves and, in turn, the market value used by our lenders to determine our borrowing base. Accordingly, on April 1, 2015, our commercial lenders reduced our borrowing base from $320 million to $270 million as part of our regularly scheduled semi-annual redetermination. As of June 30, 2015, based on our current borrowings, we had approximately $176.0 million of availability under the Credit Agreement.

For a further discussion of our Credit Agreement and current availability, see Note 7 to our unaudited condensed consolidated financial statements.

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Senior Unsecured Notes

On July 1, 2014, as part of the Midstream Business Contribution, $498.9 million face amount of newly issued Regency unsecured senior notes due 2019 were exchanged for $498.9 million face amount of the Senior Notes. As of June 30, 2015, only $51.1 million face amount of the Senior Notes remained outstanding.

Debt Covenants

The Credit Agreement requires us to maintain certain leverage and current ratios. As of June 30, 2015, we were in compliance with all of our debt covenants. The following table presents the debt covenant levels specified in the Credit Agreement and the actual covenant ratios as of June 30, 2015:

	Debt Covenant	Actual Covenant Ratio as of June 30, 2015
Total leverage ratio	< 4.0x	1.2
Current ratio	> 1.0x	4.3

Our long-term target is to maintain our ratio of total outstanding debt to Adjusted EBITDA, or "total leverage ratio," at or below 3.5 to 1.0 on a long-term basis, while acknowledging that at times this ratio may exceed our targeted levels, particularly following acquisitions or major development projects.

Our Senior Notes that did not exchange as part of the Midstream Business Contribution remain outstanding under an amended indenture with substantially all of the restrictive covenants and certain events of default eliminated. At June 30, 2015, we were in compliance with the covenants under the Credit Agreement and our Senior Notes indenture.

For a further discussion of the Senior Notes, see Note 7 to our unaudited condensed consolidated financial statements.

Common Unit Repurchase Program

On October 27, 2014, we announced a common unit repurchase program of up to $100 million through which we may, at our 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 our 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 us to acquire any, or any specific number of, units and may be discontinued at any time. We have cancelled, and will continue to cancel, units repurchased under the repurchase program. We have funded repurchases with the proceeds of our sales of Regency Common Units. As of June 30, 2015, a total of 8,627,471 of our common units had been repurchased under this program for approximately $21.8 million. In order to preserve liquidity for potential acquisition opportunities, we have not repurchased any units since January 27, 2015.

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Equity Offerings

On May 31, 2012, we announced a program through which we may issue common units, from time to time, with an aggregate market value of up to $100 million. We are under no obligation to issue equity under the program. We have used the net proceeds from prior sales (and intend to use the net proceeds from any future sales) under the program for general partnership purposes, which may include, among other things, repayment of indebtedness, acquisitions, capital expenditures and additions to working capital. As of June 30, 2015, a total of 1,521,086 units had been issued under this program for net proceeds of approximately $12.9 million. No sales were made under the program during the three and six months endedJune 30, 2015. The last time units were issued under this program was in 2013.

Cash Flows

Cash Distributions

On January 26, 2015, we declared our fourth quarter 2014 cash distribution of $0.07 per unit to our common unitholders of record as of the close of business on February 6, 2015 (excluding certain restricted common unit grants). The distribution was paid on February 13, 2015.

On April 21, 2015, we declared our first quarter 2015 cash distribution of $0.07 per unit to our common unitholders of record as of close of business on May 8, 2015 (excluding certain ineligible restricted common units). The distribution was paid on May 15, 2015.

On July 21, 2015, we declared our second quarter 2015 cash distribution of $0.07 per unit to our common unitholders of record as of close of business on August 6, 2015 (excluding certain ineligible restricted common units). The distribution will be paid on August 14, 2015.

Working Capital

Working capital is the amount by which current assets exceed current liabilities. As of June 30, 2015, working capital was a positive $24.6 million as compared to a positive $189.6 million as of December 31, 2014.

The net decrease in working capital of $165.0 million from December 31, 2014 to June 30, 2015, resulted primarily from the following factors:

• short-term investments decreased by $153.4 million as a result of selling all remaining common units received from the Midstream Business Contribution;

• trade accounts receivable decreased by $12.5 million, primarily from the timing of the receipt of payments;

• risk management net working capital balance decreased by $8.6 million as a result of changes in the current portion of mark-to-market unrealized positions as a result of decreases to the forward natural gas, oil and NGL price curves; and

• cash and cash equivalents decreased by $1.3 million primarily due to the timing of payments and the receipt of cash.

The decrease was partially offset by:

• accounts payable decreased by $8.2 million primarily as a result of the timing of payments of unbilled expenditures;

• prepayment and other current assets increased by $1.7 million primarily due to the payment of insurance premiums; and

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• accrued liabilities decreased by $1.0 million primarily as a result of lower interest and compensation accruals.

Cash Flows for the Six Months EndedJune 30, 2015, Compared to the Six Months EndedJune 30, 2014

Cash Flow from Operating Activities. Cash flows from operating activities increased $9.6 million during the six months endedJune 30, 2015 as compared to the six months endedJune 30, 2014.

The increase was driven by the:

• timing of cash payments and cash receipts; and

• increased commodity risk management settlements, offset by a decline in commodity revenues due to lower commodity prices.

Cash Flows from Investing Activities. Cash flows provided by investing activities increased $172.9 million during the six months endedJune 30, 2015 as compared to the six months endedJune 30, 2014. The increase was due to proceeds from the sale of common units and lower capital expenditures.

Cash Flows from Financing Activities. Cash flows used in financing activities increased $178.1 million during the six months endedJune 30, 2015 as compared to the six months endedJune 30, 2014.

The increase was driven by:

• increase in net repayments of long-term debt of $180.8 million; and

• increased repurchases of common units of $2.0 million.

This increase was partially offset by:

• decreased distributions of $2.7 million;

• proceeds from derivative contracts decreased by $1.5 million; and

• decreased debt issuance costs of $0.4 million.

Hedging Strategy

We use a variety of hedging instruments such as fixed-price swaps, costless collars and put options to manage our risks related to our commodity price and interest rate exposure. At times our hedging strategy may involve adjusting strike prices of existing hedges to better reflect current market conditions or to meet other corporate objectives.  To the extent we adjust the prices upward, these transactions increase our exposure to the counterparties through which we execute the hedges. In addition, we may also terminate or unwind hedges or portions of hedges when the expected future volumes do not support the level of hedges or otherwise. Terminations or unwinds of hedge transactions will negatively impact our liquidity in the event that the hedged price is greater than the current futures price such that we are required to pay the present value of the difference between the hedged price and the current futures price. The inverse is true in the event that the hedged price is less than the current futures price.

For further description of our hedging activity, see Notes 10 and 11 to our unaudited condensed consolidated financial statements.

OFF-BALANCE SHEET OBLIGATIONS

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We had no off-balance sheet transactions or obligations as of June 30, 2015. 

RECENT ACCOUNTING PRONOUNCEMENTS

For recent accounting pronouncements, please see Note 3 of our unaudited condensed consolidated financial statements.

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NON-GAAP FINANCIAL MEASURES

We include in this report Adjusted EBITDA, a financial measure not calculated in accordance with GAAP. We provide reconciliations of this non-GAAP financial measure to its most directly comparable financial measures as calculated and presented in accordance with GAAP.

We define Adjusted EBITDA as net income (loss) plus or (minus) income tax provision (benefit); interest-net, including (gains) and losses from interest rate risk management instruments that settled during the period and other expense; depreciation, depletion and amortization expense; impairment expense; other operating and general and administrative expense, non-recurring, including certain expenses incurred in connection with our potential merger with Vanguard; other non-cash operating and general and administrative expenses, including non-cash compensation related to our equity-based compensation program; (gains) and losses on commodity and interest rate risk management related instruments; gains and (losses) from risk management instruments that settled during the period; (gains) losses on non-cash mark-to-market imbalances; (gains) losses on discontinued operations; losses on short-term investments; and other (income), excluding distributions received on short-term investments. 

We use Adjusted EBITDA as a measure of our core profitability to assess the financial performance of our assets. Adjusted EBITDA is also used as a supplemental financial measure by external users of our financial statements such as investors, commercial banks and research analysts.  For example, the compliance covenant used by our lenders under our Credit Agreement, which is designed to measure our viability and our ability to perform under the terms of our Credit Agreement, uses a variant of our Adjusted EBITDA.  We believe that investors benefit from having access to the same financial measures that our management team uses in evaluating performance.  Adjusted EBITDA is useful in determining our ability to sustain or increase distributions. By excluding non-cash, mark-to-market gains and losses, which represent the change in fair market value of our executed risk management instruments and is independent of our assets’ performance or cash flow generating ability, we believe Adjusted EBITDA provides additional information on our ability to generate cash sufficient to pay interest costs, support our level of indebtedness, make cash distributions to our unitholders and general partner and finance our maintenance capital expenditures. We further believe that Adjusted EBITDA also provides additional information on the underlying performance of our operating assets by isolating the performance of our operating assets from the impact of an unrealized, non-cash measure designed to describe the fluctuating inherent value of a financial asset. Similarly, by excluding the impact of non-recurring discontinued operations, Adjusted EBITDA provides users of our financial statements additional information on our current assets’ cash generation ability, independent from assets that are no longer a part of our operations. Our Adjusted EBITDA definition may not be comparable to Adjusted EBITDA or similarly titled measures of other entities, as other entities may not calculate Adjusted EBITDA in the same manner as us.

Adjusted EBITDA does not include interest expense, income taxes or depreciation and amortization expense. Because we have borrowed money to finance our operations, interest expense is a necessary element of our costs and our ability to generate net income. Because we use capital assets, depreciation and amortization are also necessary elements of our costs. Therefore, any measures that exclude these elements have material limitations. To compensate for these limitations, we believe that it is important to consider both net income (loss) and net cash flows provided by operating activities determined in accordance with GAAP, as well as Adjusted EBITDA, to evaluate our performance and liquidity.

Adjusted EBITDA should not be considered an alternative to net income, cash flows provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP.

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The following table provides a reconciliation of Adjusted EBITDA to net cash flows provided by operating activities and net income (loss):

	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
	($ in thousands)
Reconciliation of Adjusted EBITDA to net cash flows provided by operating activities and net loss:
Net cash flows provided by operating activities	$	20,503		$	2,077		$	35,230		$	25,674
Add (deduct):
Discontinued operations, net of tax	(8		)	(25,646		)	(974		)	(36,249		)
Depreciation, depletion, amortization and impairment	(16,390		)	(20,299		)	(99,379		)	(40,705		)
Amortization of debt issuance costs	(282		)	(610		)	(546		)	(1,269		)
Gain (loss) from risk management activities, net	(10,571		)	(18,652		)	8,963			(28,975		)
Settlement of risk management instruments	(13,135		)	2,176			(27,505		)	5,314
Other	(406		)	(1,375		)	(1,375		)	(3,903		)
Loss on short-term investments	(3,750		)	—			(5,754		)	—
Accounts receivable and other current assets	(2,567		)	3,998			(4,753		)	24,728
Accounts payable and accrued liabilities	3,235			12,223			13,225			(7,208		)
Other assets and liabilities	(3		)	3,067			775			989
Net loss	(23,374		)	(43,041		)	(82,093		)	(61,604		)
Add (deduct):
Interest expense, net	3,066			6,663			6,324			13,124
Depreciation, depletion, amortization and impairment	16,390			20,299			99,379			40,705
Income tax benefit	(695		)	(885		)	(1,521		)	(1,750		)
EBITDA	(4,613		)	(16,964		)	22,089			(9,525		)
Add (deduct):
(Gain) loss from risk management activities, net	10,571			18,652			(8,963		)	28,975
Settlement of risk management instruments	12,190			(3,893		)	25,620			(8,739		)
Restricted unit compensation expense	1,144			1,459			3,000			4,042
Non-cash mark-to-market imbalances	57			(1		)	183			(7		)
Discontinued operations, net of tax	8			25,646			974			36,249
Losses on short-term investments	3,750			—			5,754			—
Other income	(23		)	—			(23		)	—
Other (a)	2,617			—			2,617			—
ADJUSTED EBITDA	$	25,701		$	24,899		$	51,251		$	50,995

________________________

(a) Includes $2.6 million of non-recurring general and administrative expenses incurred during the three and six months ended June 30, 2015 related to potential merger with Vanguard.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

Risk and Accounting Policies

We are exposed to market risks associated with adverse changes in commodity prices, interest rates and counterparty credit. We may use financial instruments such as swaps, put and call options and other derivatives to mitigate the effects of the identified risks. Adverse effects on our cash flow from changes in crude oil, natural gas, NGL prices or interest rates could adversely impact our ability to make distributions to our unitholders, meet debt service obligations, fund required capital expenditures and satisfy other similar requirements. Our management has established a review of our market risks and has developed risk management policies and procedures to monitor and manage these market risks. Our general partner is responsible for the overall approval of market risk management policies, delegation of transaction authority levels and for the establishment of a Financial Risk Management Committee (the "RMC"). The RMC is composed of officers (including, on an ex officio basis, our chief executive officer) who receive regular briefings on positions and exposures, credit exposures and overall risk management in the context of market activities. The RMC is responsible for creating and implementing a sound approach to managing our credit, commodity price and interest rate risk with respect to our budgetary exposure and stated risk tolerance.

Under our financial risk management policy, management may execute hedging instruments, which may include swaps, collars, options and other derivatives, in order to reduce exposure to substantial adverse changes in commodity prices and interest rates. Senior level executives in our operations, finance and legal departments monitor and ensure compliance with this policy.

We have not designated our contracts as accounting hedges based on authoritative guidance. As a result, we mark our derivatives to market with the resulting change in fair value being included in our statement of operations.

We continually monitor our hedging and contract portfolio and expect to continue to adjust our hedge position as conditions warrant.

Commodity Price Risk

We are exposed to market fluctuations in the prices of crude oil, natural gas, NGLs and other commodities. Our profitability and cash flow are affected by changes in prices of these commodities. These prices are impacted by changes in the supply of and demand for these commodities, as well as market uncertainty and other factors beyond our control.

We manage this commodity price exposure through an integrated strategy that includes management of our contract portfolio, matching sales prices of commodities with purchases, optimization of our portfolio by monitoring basis and other price differentials in our areas of operations and the use of derivative contracts.

We frequently use financial derivatives, which may include swaps, puts and call options, among others, to reduce our exposure to commodity price risk. These hedges are only intended to mitigate our commodity price risk.

As of June 30, 2015, our commodity hedge portfolio totaled a net asset position of $80.7 million, consisting of assets aggregating $80.8 million and $0.2 million of liabilities. For additional information about our hedging activities and related fair values, see Notes 10 and 11 to our unaudited condensed consolidated financial statements.

Interest Rate Risk

We are exposed to variable interest rate risk as a result of borrowings under our Credit Agreement. To mitigate our interest rate risk, we have entered into an interest rate swap that eliminates interest rate variability by effectively converting LIBOR-based variable-rate payments to fixed-rate payments. Amounts received or paid under this swap were recorded as reductions or increases in interest expense.

As of June 30, 2015, the fair value liability of this swap was approximately $6.0 million. For additional information about our swap and related fair value, see Notes 10 and 11 to our unaudited condensed consolidated financial statements.

As of June 30, 2015, the notional amount of our interest rate swap was in excess of the outstanding borrowings under our Credit Agreement by approximately $81.0 million. Absent any change to our near-term borrowing expectations, we may evaluate lowering the notional amount.

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Credit Risk

Our principal natural gas sales customers are large industrial, commercial and utility companies. With respect to the sale of our NGLs and condensates, our principal customers are large NGL purchasers, fractionators and marketers and large condensate aggregators that typically sell to large multi-national petrochemical and refining companies. We also sell a small amount of propane to medium sized, local distributors.

This concentration of credit risk may affect our overall credit risk in that these customers may be similarly affected by changes in the natural gas, NGLs, petrochemical and other segments of the energy industry, the economy in general, the regulatory environment and other factors.

Our derivative counterparties at June 30, 2015 included Wells Fargo Bank, N.A., Comerica Bank, Bank of America Merrill Lynch, J. Aron & Company (an affiliate of Goldman Sachs), ING Capital Markets LLC, Regions Financial Corporation and CITIBANK, N.A.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Based on the evaluation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the "Exchange Act")) required by Exchange Act Rules 13a-15(b) or 15d-15(b), our principal executive officer and principal financial officer have concluded that as of the end of the period covered by this report, our disclosure controls and procedures were effective at the reasonable assurance level to ensure that information we are required to disclose in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms, and include controls and procedures designed to ensure that information required to be disclosed by us in such reports is accumulated and communicated to our management, including the principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d - 15(f) under the Exchange Act) that occurred during our most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

Our operations are subject to a variety of risks and disputes normally incident to our business. As a result, we are and may, at any given time, be a party to various legal proceedings and litigation arising in the ordinary course of business.

Further, we maintain insurance policies with insurers in amounts and with coverage and deductibles that we, with the advice of our insurance advisors and brokers, believe are reasonable and prudent. We cannot, however, assure that this insurance will be adequate to protect us from all material expenses related to potential future claims for personal and property damage or that these levels of insurance will be available in the future at economical prices.

In May and June 2015, alleged Eagle Rock 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 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 us, our general partner, our general partner's 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. We believe that the lawsuits are without merit.

On July 30, 2015, a wholly owned subsidiary of ours 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. Our wholly owned subsidiary 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.

Item 1A. Risk Factors

In addition to the other information set forth in this report, you should carefully consider the risks discussed in the 2014 10-K, under the headings “Item 1. Business,” “Item 1A. Risk Factors,” “Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations” and “Item 7A. Quantitative and Qualitative Disclosures About Market Risk,” which risks could materially affect our business, financial condition or future results. Except for the risk factors set forth below, there have been no material changes in our risk factors from those described in the 2014 10-K.

We are subject to litigation related to the Merger

We are subject to litigation related to the Merger, see "Part II. Item 1. Legal Proceedings" of this report. It is possible that additional claims beyond those that have already been filed will be brought by the current plaintiffs or by others in an effort to enjoin the Merger or seek monetary relief from us. We cannot predict the outcome of these lawsuits, or others, nor can we predict the amount of time and expense that will be required to resolve these lawsuits. An unfavorable resolution of any such litigation surrounding the Merger could delay or prevent the consummation of the Merger. In addition, the cost to us defending the litigation, even if resolved in our favor, could be substantial. Such litigation could also divert the attention of our management and our resources from day-to-day operations.

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There can be no assurance that the Merger will be completed in the anticipated time frame, or at all. The failure to complete the Merger could adversely affect the price of our common units and otherwise have an adverse effect on us.

The completion of the Merger is not assured and is subject to a number of conditions and risks, including the risk that approval of the Merger by our unitholders and the risk that approval of the Vanguard common unit issuance by Vanguard unitholders is not obtained. If the Merger is not completed, or if there are significant delays in completing the merger, the trading price of our common units and our future business and financial results could be adversely affected.

A failed transaction may result in negative publicity or a negative impression of us in the investment community and may affect our relationship with employees, vendors, creditors and other business partners. Accordingly, if the Merger is not completed, the price of our common units may be adversely affected.

In the event of a failed transaction, we will still have to pay certain costs associated with the Merger, which will be significant and will primarily consist of legal fees, accounting fees, financial printing and other related costs. These costs could adversely affect our operations and cash flows available for distributions to our unitholders.

In addition, pursuant to the Merger Agreement, in certain specified circumstances if the Merger is not consummated we may be required to pay Vanguard a termination fee in the amount of $20 million, which would adversely affect our operations and cash flows available for distributions to our unitholders.

The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes or differing interpretations, possibly applied on a retroactive basis.

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. For example, the Obama administration's budget proposal for fiscal year 2016 recommends that certain publicly traded partnerships earning income from activities related to fossil fuels be taxed as corporations beginning in 2021. From time to time, members of Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships. If successful, the Obama administration's proposal or other similar proposals could eliminate the qualifying income exception to the treatment of all publicly traded partnerships as corporations upon which we rely for our treatment as a partnership for U.S. federal income tax purposes.

In addition, the IRS, on May 5, 2015, issued proposed regulations concerning which activities give rise to qualifying income within the meaning of Section 7704 of the Internal Revenue Code. Based on the proposed regulations, we do not expect that finalized regulations will affect our ability to qualify as a publicly traded partnership or the amount of our gross income that we are able to treat as qualifying income. However, finalized regulations could modify the amount of our gross income that we are able to treat as qualifying income for the purposes of the qualifying income requirement.

Any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.

Combining the Partnership and Vanguard may be more difficult, costly, or time consuming than expected and the anticipated benefits and cost savings of the Merger may not be realized.

The Partnership and Vanguard have operated and, until the completion of the Merger, will continue to operate, independently. The success of the Merger, including anticipated benefits and cost savings, will depend, in part, on Vanguard’s ability to successfully combine and integrate our businesses. It is possible that the pending nature of the Merger and/or the integration process could result in the loss of key employees; higher than expected costs; diversion of Vanguard’s and our management’s attention; the disruption of either the Partnership or Vanguard’s ongoing businesses; or inconsistencies in standards, controls, procedures and policies that adversely affect the combined company’s ability to maintain relationships with customers, suppliers, employees and other business partners or to achieve the anticipated benefits and cost savings of the

52

Merger. If Vanguard experiences difficulties with the integration process, the anticipated benefits of the Merger may not be realized fully or at all, or may take longer to realize than expected. Integration efforts between the Partnership and Vanguard will also divert management’s attention and resources. These integration matters could have an adverse effect on each of us and Vanguard during this transition period and for an undetermined period after completion of the Merger on the combined company. In addition, the actual cost savings and other benefits of the Merger could be less than anticipated.

The value of the Merger consideration is subject to changes based on fluctuations in the value of Vanguard common units.

The market value of Vanguard common units will fluctuate during the period before the date of the special meeting of our unitholders to vote on approval of the Merger Agreement and will continue to fluctuate during the period prior to the effective time of the Merger, as well as thereafter.

Upon completion of the Merger, holders of our common units will have the right to receive 0.185 Vanguard common unit for each Eagle Rock Energy common unit. It is impossible to accurately predict the market price of Vanguard common units at the effective time and therefore impossible to accurately predict the value of the Vanguard common units that holders of our common units will receive in the Merger.

The market price of Vanguard common units after the Merger will continue to fluctuate and may be affected by factors different from those affecting our common units currently.

Upon completion of the Merger, holders of our common units will become holders of Vanguard common units. The market price of Vanguard common units may fluctuate significantly following consummation of the Merger and holders of our common units could lose some or all of the value of their investment in Vanguard common units. In addition, the stock market, particularly for companies in the oil and gas industry, has experienced significant price and volume fluctuations in recent times, which could have a material adverse effect on the market for, or liquidity of, the Vanguard common units, regardless of Vanguard’s actual operating performance. In addition, Vanguard’s business differs in important respects from ours, and accordingly, the results of operations of the combined company and the market price of Vanguard common units after the completion of the Merger may be affected by factors different from those currently affecting the independent results of our operations and Vanguard’s operations.

Issuance and Sales of Vanguard common units before, at and after the completion of the Merger may cause the market price of Vanguard common units to fall.

The issuance of new Vanguard common units in connection with the Merger could have the effect of depressing the market price for Vanguard common units. In addition, holders of our common units may decide not to hold the Vanguard common units they will receive in the Merger, and holders of Vanguard common units prior to the consummation of the Merger may determine to sell such units prior to, or following, the Merger. Such sales of Vanguard common units could have the effect of depressing the market price for Vanguard common units, and such sales by our common unitholders in particular may take place promptly following the Merger.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

The following table sets forth certain information with respect to repurchases of common units during the three months endedJune 30, 2015:

Period	Total Number of Units Purchased	Average Price Paid Per Unit		Total Number of Units Purchased as Part of Publicly Announced Plans or Programs	Maximum Number (or Approximate Dollar Value) of Units that May Yet Be Purchased Under the Plans or Programs
April 1, 2015 - April 30, 2015	—	—		—	78,227,181
May 1, 2015 - May 31, 2015	157,277	2.44		—	78,227,181
June 1, 2015 - June 30, 2015	—	—		—	78,227,181
Total	157,277	$	2.44	—	78,227,181

The units not repurchased under the publicly announced program were surrendered by employees to pay tax withholding in connection with the vesting of restricted common units. As a result, we are including the units surrendered in the "Total Number of Units Purchased" column. For a description of our common unit repurchase program, please see “Management’s Discussion and Analysis of Financial Conditions and Results of Operations — Liquidity and Capital Resources — Common Unit Repurchase Program.”

Item 3. Defaults Upon Senior Securities

Not applicable.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

Not applicable.

53

Item 6. Exhibits

Exhibit Number	Description
2.1***	Agreement and Plan of Merger by and among Vanguard Natural Resources, LLC, Talon Merger Sub, LLC, Eagle Rock Energy Partners, L.P. and Eagle Rock Energy GP, L.P., dated as of May 21, 2015 (incorporated by reference to Exhibit 2.1 of the registrant's current report on Form 8-K filed with the Commission on May 22, 2015).
2.2***	Voting and Support Agreement by and among Vanguard Natural Resources, LLC, Montierra Minerals & Production, L.P., Montierra Management LLC, Natural Gas Partners VII, L.P., Natural Gas Partners VIII, L.P., NGP Income Management L.L.C., Eagle Rock Holdings NGP 7, LLC, Eagle Rock Holdings NGP 8, LLC, ERH NGP 7 SPV, LLC, ERH NGP 8 SPV, LLC, NGP Income Co-Investment Opportunities Fund II, L.P., NGP Energy Capital Management, L.L.C., and, solely for the purpose of certain specified sections, Eagle Rock Energy Partners, L.P. and Eagle Rock Energy GP, L.P., dated as of May 21, 2015 (incorporated by reference to Exhibit 2.2 of the registrant's current report on Form 8-K filed with the Commission on May 22, 2015).
3.1	Certificate of Limited Partnership of Eagle Rock Energy Partners, L.P. (incorporated by reference to Exhibit 3.1 of the registrant's registration statement on Form S-1 (File No. 333-134750)).
3.2	Second Amended and Restated Agreement of Limited Partnership of Eagle Rock Energy Partners, L.P. (incorporated by reference to Exhibit 3.1 of the registrant's current report on Form 8-K filed with the SEC on May 25, 2010).
3.3	Certificate of Limited Partnership of Eagle Rock Energy GP, L.P. (incorporated by reference to Exhibit 3.3 of the registrant's registration statement on Form S-1 (File No. 333-134750)).
3.4	Limited Partnership Agreement of Eagle Rock Energy GP, L.P. (incorporated by reference to Exhibit 3.4 of the registrant’s registration statement on Form S-1 (File No. 333-134750)).
3.5	Certificate of Formation of Eagle Rock Energy G&P, LLC (incorporated by reference to Exhibit 3.5 of the registrant's registration statement on Form S-1 (File No. 333-134750)).
3.6	Third Amended and Restated Limited Liability Company Agreement of Eagle Rock Energy G&P, LLC (incorporated by reference to Exhibit 42 of the registrant's current report on Form 8-K filed with the SEC on July 30, 2010).
3.7	Amendment No. 1 to the Second Amended and Restated Agreement of Limited Partnership of Eagle Rock Energy Partners, L.P. (incorporated by reference to Exhibit 4.1 of the registrant's current report on Form 8-K filed with the SEC on July 30, 2010).
10.1	Amendment, dated May 21, 2015, to Confidentiality and Noncompete Agreement by and between Eagle Rock Energy G&P, LLC and Joseph A. Mills dated August 3, 2012 (incorporated by reference to Exhibit 10.1 of the registrant's current report on Form 8-K filed with the Commission on May 22, 2015).
10.2	Amendment, dated May 21, 2015, to Confidentiality, Non-Competition and Non-Solicitation Agreement by and between Eagle Rock Energy G&P, LLC and Roger A. Fox dated March 26, 2012 (incorporated by reference to Exhibit 10.2 of the registrant's current report on Form 8-K filed with the Commission on May 22, 2015).
10.3	Amendment, dated May 21, 2015, to Confidentiality and Non-Solicitation Agreement by and between Eagle Rock Energy G&P, LLC and Robert M. Haines (incorporated by reference to Exhibit 10.3 of the registrant's current report on Form 8-K filed with the Commission on May 22, 2015).
10.4	Amendment, dated May 21, 2015, to Confidentiality and Non-Solicitation Agreement by and between Eagle Rock Energy G&P, LLC and Charles C. Boettcher (incorporated by reference to Exhibit 10.4 of the registrant's current report on Form 8-K filed with the Commission on May 22, 2015).
10.5	Form of Restricted Unit Agreement for Officers under the Amended and Restated Eagle Rock Energy Partners Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 of the registrant's current report on Form 8-K filed with the Commission on April 24, 2015).
10.6	Form of Performance Unit Agreement for Officers under the Amended and Restated Eagle Rock Energy Partners Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 of the registrant's current report on Form 8-K filed with the Commission on April 24, 2015).
31.1*	Certification of Periodic Financial Reports by Joseph A. Mills in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Periodic Financial Reports by Robert M. Haines in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**	Certification of Periodic Financial Reports by Joseph A. Mills in satisfaction of Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**	Certification of Periodic Financial Reports by Robert M. Haines in satisfaction of Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*	XBRL Instance Document
101.SCH*	XBRL Taxonomy Extension Schema Document
101.CAL*	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*	XBRL Taxonomy Extension Label Linkbase Document
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase Document

* Filed herewith.

** Furnished herewith.

*** Certain schedules and exhibits have been omitted pursuant to Item 601(b)(2) of Regulation S-K. A copy of any omitted schedule and/or exhibit will be furnished supplementally to the SEC upon request.

54

55

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, thereunto duly authorized, on July 31, 2015.

EAGLE ROCK ENERGY PARTNERS, L.P.
By:	Eagle Rock Energy GP, L.P., its general partner
By:	Eagle Rock Energy G&P, LLC, its general partner
By:	/s/ ROBERT M. HAINES
Name:	Robert M. Haines
Title:	Senior Vice President and Chief Financial Officer

56

Index to Exhibits

Exhibit Number	Description
2.1***	Agreement and Plan of Merger by and among Vanguard Natural Resources, LLC, Talon Merger Sub, LLC, Eagle Rock Energy Partners, L.P. and Eagle Rock Energy GP, L.P., dated as of May 21, 2015 (incorporated by reference to Exhibit 2.1 of the registrant's current report on Form 8-K filed with the Commission on May 22, 2015).
2.2***	Voting and Support Agreement by and among Vanguard Natural Resources, LLC, Montierra Minerals & Production, L.P., Montierra Management LLC, Natural Gas Partners VII, L.P., Natural Gas Partners VIII, L.P., NGP Income Management L.L.C., Eagle Rock Holdings NGP 7, LLC, Eagle Rock Holdings NGP 8, LLC, ERH NGP 7 SPV, LLC, ERH NGP 8 SPV, LLC, NGP Income Co-Investment Opportunities Fund II, L.P., NGP Energy Capital Management, L.L.C., and, solely for the purpose of certain specified sections, Eagle Rock Energy Partners, L.P. and Eagle Rock Energy GP, L.P., dated as of May 21, 2015 (incorporated by reference to Exhibit 2.2 of the registrant's current report on Form 8-K filed with the Commission on May 22, 2015).
3.1	Certificate of Limited Partnership of Eagle Rock Energy Partners, L.P. (incorporated by reference to Exhibit 3.1 of the registrant's registration statement on Form S-1 (File No. 333-134750)).
3.2	Second Amended and Restated Agreement of Limited Partnership of Eagle Rock Energy Partners, L.P. (incorporated by reference to Exhibit 3.1 of the registrant's current report on Form 8-K filed with the SEC on May 25, 2010).
3.3	Certificate of Limited Partnership of Eagle Rock Energy GP, L.P. (incorporated by reference to Exhibit 3.3 of the registrant's registration statement on Form S-1 (File No. 333-134750)).
3.4	Limited Partnership Agreement of Eagle Rock Energy GP, L.P. (incorporated by reference to Exhibit 3.4 of the registrant’s registration statement on Form S-1 (File No. 333-134750)).
3.5	Certificate of Formation of Eagle Rock Energy G&P, LLC (incorporated by reference to Exhibit 3.5 of the registrant's registration statement on Form S-1 (File No. 333-134750)).
3.6	Third Amended and Restated Limited Liability Company Agreement of Eagle Rock Energy G&P, LLC (incorporated by reference to Exhibit 42 of the registrant's current report on Form 8-K filed with the SEC on July 30, 2010).
3.7	Amendment No. 1 to the Second Amended and Restated Agreement of Limited Partnership of Eagle Rock Energy Partners, L.P. (incorporated by reference to Exhibit 4.1 of the registrant's current report on Form 8-K filed with the SEC on July 30, 2010).
10.1	Amendment, dated May 21, 2015, to Confidentiality and Noncompete Agreement by and between Eagle Rock Energy G&P, LLC and Joseph A. Mills dated August 3, 2012 (incorporated by reference to Exhibit 10.1 of the registrant's current report on Form 8-K filed with the Commission on May 22, 2015). .
10.2	Amendment, dated May 21, 2015, to Confidentiality, Non-Competition and Non-Solicitation Agreement by and between Eagle Rock Energy G&P, LLC and Roger A. Fox dated March 26, 2012 (incorporated by reference to Exhibit 10.2 of the registrant's current report on Form 8-K filed with the Commission on May 22, 2015).
10.3	Amendment, dated May 21, 2015, to Confidentiality and Non-Solicitation Agreement by and between Eagle Rock Energy G&P, LLC and Robert M. Haines (incorporated by reference to Exhibit 10.3 of the registrant's current report on Form 8-K filed with the Commission on May 22, 2015).
10.4	Amendment, dated May 21, 2015, to Confidentiality and Non-Solicitation Agreement by and between Eagle Rock Energy G&P, LLC and Charles C. Boettcher (incorporated by reference to Exhibit 10.4 of the registrant's current report on Form 8-K filed with the Commission on May 22, 2015).
10.5	Form of Restricted Unit Agreement for Officers under the Amended and Restated Eagle Rock Energy Partners Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 of the registrant's current report on Form 8-K filed with the Commission on April 24, 2015).
10.6	Form of Performance Unit Agreement for Officers under the Amended and Restated Eagle Rock Energy Partners Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 of the registrant's current report on Form 8-K filed with the Commission on April 24, 2015).
31.1*	Certification of Periodic Financial Reports by Joseph A. Mills in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Periodic Financial Reports by Robert M. Haines in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**	Certification of Periodic Financial Reports by Joseph A. Mills in satisfaction of Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**	Certification of Periodic Financial Reports by Robert M. Haines in satisfaction of Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*	XBRL Instance Document
101.SCH*	XBRL Taxonomy Extension Schema Document
101.CAL*	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*	XBRL Taxonomy Extension Label Linkbase Document
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase Document

* Filed herewith.

** Furnished herewith.

*** Certain schedules and exhibits have been omitted pursuant to Item 601(b)(2) of Regulation S-K. A copy of any omitted schedule and/or exhibit will be furnished supplementally to the SEC upon request.

EX-31.1

Exhibit 31.1

I, Joseph A. Mills, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Eagle Rock Energy Partners, L.P.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a - 15(f) and 15d - 15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	July 31, 2015	/s/ JOSEPH A. MILLS
		Joseph A. Mills
		Chief Executive Officer of Eagle Rock Energy G&P, LLC,
		General Partner of Eagle Rock Energy GP, L.P.,
		General Partner of Eagle Rock Energy Partners, L.P.

EX-31.2

Exhibit 31.2

I, Robert M. Haines, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Eagle Rock Energy Partners, L.P.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a - 15(f) and 15d - 15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	July 31, 2015	/s/ ROBERT M. HAINES
		Robert M. Haines
		Senior Vice President
		Chief Financial Officer of Eagle Rock
		Energy G&P, LLC, General Partner of Eagle Rock
		Energy GP, L.P., General Partner of Eagle Rock
		Energy Partners, L.P.

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

(18 U.S.C. SECTION 1350)

In connection with the accompanying Quarterly Report on Form 10-Q for the three months ended June 30, 2015 as filed with the Securities and Exchange Commission on the date hereof (the Report), I, Joseph A. Mills, Chief Executive Officer of Eagle Rock Energy G&P, LLC, the general partner of Eagle Rock Energy GP, L.P., the general partner of the Partnership, hereby certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. § 1350), that:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as amended; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

Date:	July 31, 2015	/s/ JOSEPH A. MILLS
		Joseph A. Mills
		Chief Executive Officer of Eagle Rock Energy G&P, LLC,
		General Partner of Eagle Rock Energy GP, L.P.,
		General Partner of Eagle Rock Energy Partners, L.P.

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

(18 U.S.C. SECTION 1350)

In connection with the accompanying Quarterly Report on Form 10-Q for the three months ended June 30, 2015 as filed with the Securities and Exchange Commission on the date hereof (the Report), I, Robert M. Haines, Senior Vice President and Chief Financial Officer of Eagle Rock Energy G&P, LLC, the general partner of Eagle Rock Energy GP, L.P., the general partner of the Partnership, hereby certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. § 1350), that:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as amended; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

Date:	July 31, 2015	/s/ Robert M. Haines
		Robert M. Haines
		Senior Vice President
		Chief Financial Officer of Eagle Rock
		Energy G&P, LLC, General Partner of Eagle Rock
		Energy GP, L.P., General Partner of Eagle Rock
		Energy Partners, L.P.

XML

Summary of Significant Accounting Policies Narrative (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014
Losses on short-term investments	$ (3,750)	$ 0	$ (5,754)	$ 0
Distributions received from short term investments	$ 1,000		$ 3,200
Investment Owned, Balance, Shares	0		0
Gas Balancing Payable	$ 500		$ 500		$ 300

XML

Risk Management Activities Commodity Derivatives (Details) - Jun. 30, 2015		bbl MMbtu $ / bbl $ / MMbtu
Natural Gas Contract [Member] | Swap [Member] | Portion of contracts settling in 2015 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMbtu	[1]	5,400,000
Derivative, Average Floor Price | $ / MMbtu	[2]	4.07
Natural Gas Contract [Member] | Swap [Member] | Portion of contracts settling in 2016 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	[1]	9,480,000
Derivative, Average Floor Price	[2]	4.25
Natural Gas Contract [Member] | Swap [Member] | Portion of contracts settling in 2017 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	[1]	2,040,000
Derivative, Average Floor Price	[2]	3.34
Crude Oil Contract [Member] | Costless Collar [Member] | Portion of contracts settling in 2015 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	[1]	240,000
Derivative, Average Floor Price	[2]	90.00
Derivative, Average Cap Price	[2]	97.55
Crude Oil Contract [Member] | Swap [Member] | Portion of contracts settling in 2015 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	[1]	315,000
Derivative, Average Floor Price	[2]	89.78
Crude Oil Contract [Member] | Swap [Member] | Portion of contracts settling in 2016 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	[1]	936,000
Derivative, Average Floor Price	[2]	84.66
Crude Oil Contract [Member] | Swap [Member] | Portion of contracts settling in 2017 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	[1]	444,000
Derivative, Average Floor Price	[2]	89.24
Crude Oil Contract [Member] | Swap [Member] | Portion of contracts settling in 2018 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	[1]	396,000
Derivative, Average Floor Price	[2]	88.78
Crude Oil Contract [Member] | Swap [Member] | Portion of contracts settling in 2019 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	[1]	348,000
Derivative, Average Floor Price	[2]	88.39
Crude Oil Contract [Member] | Basis Swap [Member] | Portion of contracts settling in 2016 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	[1],[3]	91,500
Derivative, Average Floor Price	[2],[3]	(1.20)
Propane Contract [Member] | Swap [Member] | Portion of contracts settling in 2015 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMbtu	[1]	7,383,600
Derivative, Average Floor Price	[2]	0.57
Propane Contract [Member] | Swap [Member] | Portion of contracts settling in 2016 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	[1]	7,610,400
Derivative, Average Floor Price	[2]	0.61
IsoButane Contract [Member] | Swap [Member] | Portion of contracts settling in 2015 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMbtu	[1]	1,625,400
Derivative, Average Floor Price	[2]	0.68
IsoButane Contract [Member] | Swap [Member] | Portion of contracts settling in 2016 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	[1]	1,713,600
Derivative, Average Floor Price	[2]	0.72
Natural Gasoline Contract [Member] | Swap [Member] | Portion of contracts settling in 2015 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMbtu	[1]	1,869,000
Derivative, Average Floor Price	[2]	1.19
Normal Butane Contract [Member] | Swap [Member] | Portion of contracts settling in 2015 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMbtu	[1]	2,961,000
Derivative, Average Floor Price	[2]	0.67
Normal Butane Contract [Member] | Swap [Member] | Portion of contracts settling in 2016 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	[1]	3,074,400
Derivative, Average Floor Price	[2]	0.72

[1] Volumes of natural gas are measured in MMbtu, volumes of crude oil are measured in barrels and volumes of NGLs are measured in gallons.

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

[3] Floor price represents the spread between Argus-Midland oil prices and NYMEX-WTI oil prices.

XML

Long Term Debt Debt Covenants (Details)	Jun. 30, 2015
Total Leverage Ratio [Member]
Schedule of Debt Covenants [Line Items]
Line of Credit Facility, Covenant Ratio	1.2
Current Ratio [Member]
Schedule of Debt Covenants [Line Items]
Line of Credit Facility, Covenant Ratio	4.3
Maximum [Member] | Total Leverage Ratio [Member]
Schedule of Debt Covenants [Line Items]
Line of Credit Facility, Covenant Ratio	4.0
Minimum [Member] | Current Ratio [Member]
Schedule of Debt Covenants [Line Items]
Line of Credit Facility, Covenant Ratio	1.0

XML

Subsidiary Guarantors Subsidiary Guarantors Condensed Consolidating Income Statement (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Subsidiary Guarantors [Line Items]
Total revenues	$ 21,666	$ 34,044	$ 73,788	$ 79,247
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
Depreciation, depletion and amortization	16,390	20,299	31,035	40,705
Impairment	0	0	68,344	0
OPERATING LOSS	(20,222)	(12,763)	(73,548)	(16,545)
Interest expense, net	(2,121)	(4,948)	(4,439)	(9,702)
Other non-operating income	1,068	0	3,203	0
Other (expense) income	(2,786)	(569)	(7,856)	(858)
Income (loss) before income taxes	(24,061)	(18,280)	(82,640)	(27,105)
INCOME TAX BENEFIT	(695)	(885)	(1,521)	(1,750)
Equity in earnings of subsidiaires	0	0	0	0
LOSS FROM CONTINUING OPERATIONS	(23,366)	(17,395)	(81,119)	(25,355)
Discontinued operations	(8)	(25,646)	(974)	(36,249)
Net income (loss)	(23,374)	(43,041)	(82,093)	(61,604)
Parent Company [Member]
Subsidiary Guarantors [Line Items]
Total revenues	(12,683)	(18,081)	8,544	(28,114)
Operations and maintenance	0	3	0	3
Taxes other than income	0	0	0	0
General and administrative	3,923	2,064	6,005	4,961
Depreciation, depletion and amortization	274	295	410	348
Impairment			0
OPERATING LOSS	(16,880)	(20,443)	2,129	(33,426)
Interest expense, net	(2,121)	(4,946)	(4,439)	(9,700)
Other non-operating income	3,175	2,163	7,432	4,384
Other (expense) income	(4,164)	(1,987)	(10,623)	(3,703)
Income (loss) before income taxes	(19,990)	(25,213)	(5,501)	(42,445)
INCOME TAX BENEFIT	33	82	129	(185)
Equity in earnings of subsidiaires	(3,353)	9,377	(76,463)	28,011
LOSS FROM CONTINUING OPERATIONS	(23,376)	(15,918)	(82,093)	(14,249)
Discontinued operations	2	(27,123)	0	(47,355)
Net income (loss)	(23,374)	(43,041)	(82,093)	(61,604)
Co-issuer [Member]
Subsidiary Guarantors [Line Items]
Total revenues	0	0	0	0
Operations and maintenance	0	0	0	0
Taxes other than income	0	0	0	0
General and administrative	0	0	0	0
Depreciation, depletion and amortization	0	0	0	0
Impairment			0
OPERATING LOSS	0	0	0	0
Interest expense, net	0	0	0	0
Other non-operating income	0	0	0	0
Other (expense) income	0	0	0	0
Income (loss) before income taxes	0	0	0	0
INCOME TAX BENEFIT	0	0	0	0
Equity in earnings of subsidiaires	0	0	0	0
LOSS FROM CONTINUING OPERATIONS	0	0	0	0
Discontinued operations		0	0	0
Net income (loss)	0	0	0	0
Guarantor Subsidiaries [Member]
Subsidiary Guarantors [Line Items]
Total revenues	34,349	52,125	65,244	107,361
Operations and maintenance	12,754	10,904	22,836	22,402
Taxes other than income	1,338	3,596	2,726	7,387
General and administrative	7,483	9,941	16,390	20,334
Depreciation, depletion and amortization	16,116	20,004	30,625	40,357
Impairment			68,344
OPERATING LOSS	(3,342)	7,680	(75,677)	16,881
Interest expense, net	0	(2)	0	(2)
Other non-operating income	2,276	2,291	4,540	4,592
Other (expense) income	(3,005)	(3,036)	(6,002)	(6,131)
Income (loss) before income taxes	(4,071)	6,933	(77,139)	15,340
INCOME TAX BENEFIT	(728)	(967)	(1,650)	(1,565)
Equity in earnings of subsidiaires	0	0	0	0
LOSS FROM CONTINUING OPERATIONS	(3,343)	7,900	(75,489)	16,905
Discontinued operations	(10)	1,479	(974)	11,115
Net income (loss)	(3,353)	9,379	(76,463)	28,020
Non-Guarantor Subsidiaries [Member]
Subsidiary Guarantors [Line Items]
Total revenues		0		0
Operations and maintenance		0		0
Taxes other than income		0		0
General and administrative		0		0
Depreciation, depletion and amortization		0		0
OPERATING LOSS		0		0
Interest expense, net		0		0
Other non-operating income		0		0
Other (expense) income		0		0
Income (loss) before income taxes		0		0
INCOME TAX BENEFIT		0		0
Equity in earnings of subsidiaires		0		0
LOSS FROM CONTINUING OPERATIONS		0		0
Discontinued operations		(2)		(9)
Net income (loss)		(2)		(9)
Consolidation, Eliminations [Member]
Subsidiary Guarantors [Line Items]
Total revenues	0	0	0	0
Operations and maintenance	0	0	0	0
Taxes other than income	0	0	0	0
General and administrative	0	0	0	0
Depreciation, depletion and amortization	0	0	0	0
Impairment			0
OPERATING LOSS	0	0	0	0
Interest expense, net	0	0	0	0
Other non-operating income	(4,383)	(4,454)	(8,769)	(8,976)
Other (expense) income	4,383	4,454	8,769	8,976
Income (loss) before income taxes	0	0	0	0
INCOME TAX BENEFIT	0	0	0	0
Equity in earnings of subsidiaires	3,353	(9,377)	76,463	(28,011)
LOSS FROM CONTINUING OPERATIONS	3,353	(9,377)	76,463	(28,011)
Discontinued operations	0	0	0	0
Net income (loss)	$ 3,353	$ (9,377)	$ 76,463	$ (28,011)

XML

Risk Management Activities Schedule of Derivative Instruments in the Statement of Financial Position (Details) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Derivatives, Fair Value [Line Items]
Derivative assets, Current	$ 36,169	$ 44,805
Derivative assets, Noncurrent	38,469	46,490
Derivative Assets	74,638	91,295
Derivative Liabilities	0	0
Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member] | Current Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Liabilities, Current	(3,366)	(3,165)
Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member] | Long-term Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Liabilities, Noncurrent	(2,657)	(2,641)
Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member] | Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liabilities, Current	0	0
Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member] | Long-term Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liabilities, Noncurrent	0	0
Commodity Contract [Member] | Not Designated as Hedging Instrument [Member] | Current Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Liabilities, Current	(99)
Derivative assets, Current	39,634	47,971
Commodity Contract [Member] | Not Designated as Hedging Instrument [Member] | Long-term Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Liabilities, Noncurrent	(65)
Derivative assets, Noncurrent	41,191	49,130
Commodity Contract [Member] | Not Designated as Hedging Instrument [Member] | Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liabilities, Current	0
Derivative assets, Current	0	0
Commodity Contract [Member] | Not Designated as Hedging Instrument [Member] | Long-term Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liabilities, Noncurrent	0
Derivative assets, Noncurrent	$ 0	$ 0

XML

Intangible Assets Narrative (Details)	6 Months Ended
	Jun. 30, 2015
Use Rights [Member]
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Asset, Useful Life	20 years

XML

Fair Value of Financial Instruments Fair Value of Financial Instruments (Tables)

6 Months Ended

Jun. 30, 2015

Fair Value Disclosures [Abstract]

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]

he 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.

	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.

Fair Value Measurements, Nonrecurring [Table Text Block]

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

XML

Fair Value of Financial Instruments Fair Value, Assets and Liabilities Measured on a Recurring Basis (Details) - USD ($) $ in Thousands		Jun. 30, 2015	Dec. 31, 2014
Assets:
Derivative Assets		$ 74,638	$ 91,295
Short-term investments		0	153,448
Liabilities:
Derivative Liabilities		0	0
Fair Value, Measurements, Recurring [Member]
Assets:
Derivative Assets		74,638	244,743
Derivative Asset, Fair Value, Gross Liability	[1]	(6,187)	(5,806)
Liabilities:
Derivative Liabilities		0	0
Derivative Liability, Fair Value, Gross Asset	[1]	6,187	5,806
Fair Value, Measurements, Recurring [Member] | Crude Oil Contract [Member]
Assets:
Derivative Assets		63,084	78,516
Derivative Asset, Fair Value, Gross Liability	[1]	25	0
Liabilities:
Derivative Liabilities		0
Derivative Liability, Fair Value, Gross Asset	[1]	(25)
Fair Value, Measurements, Recurring [Member] | Natural Gas Contract [Member]
Assets:
Derivative Assets		16,310	18,585
Derivative Asset, Fair Value, Gross Liability	[1]	56	0
Liabilities:
Derivative Liabilities		0
Derivative Liability, Fair Value, Gross Asset	[1]	(56)
Fair Value, Measurements, Recurring [Member] | Natural Gas Liquids Contract [Member]
Assets:
Derivative Assets		1,267
Derivative Asset, Fair Value, Gross Liability	[1]	(83)
Liabilities:
Derivative Liabilities		0
Derivative Liability, Fair Value, Gross Asset	[1]	83
Fair Value, Measurements, Recurring [Member] | Interest Rate Contract [Member]
Assets:
Derivative Assets		6,023	5,806
Derivative Asset, Fair Value, Gross Liability	[1]	(6,023)	(5,806)
Liabilities:
Derivative Liabilities		0	0
Derivative Liability, Fair Value, Gross Asset	[1]	6,023	5,806
Fair Value, Measurements, Recurring [Member] | Short-term Investments [Member]
Assets:
Derivative Asset, Fair Value, Gross Liability	[1]		0
Short-term investments			153,448
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset		0	153,448
Assets:
Derivative Asset, Fair Value, Gross Liability		0
Liabilities:
Derivative Liability, Fair Value, Gross Liability			0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Crude Oil Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset		0	0
Liabilities:
Derivative Liabilities		0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Natural Gas Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset		0	0
Liabilities:
Derivative Liabilities		0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Natural Gas Liquids Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset		0
Assets:
Derivative Asset, Fair Value, Gross Liability		0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Interest Rate Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset		0	0
Assets:
Derivative Asset, Fair Value, Gross Liability		0
Liabilities:
Derivative Liability, Fair Value, Gross Liability			0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Short-term Investments [Member]
Assets:
Short-term investments			153,448
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset		80,825	97,101
Assets:
Derivative Asset, Fair Value, Gross Liability		(6,187)
Liabilities:
Derivative Liability, Fair Value, Gross Liability			5,806
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Crude Oil Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset		63,109	78,516
Liabilities:
Derivative Liabilities		(25)
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Natural Gas Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset		16,366	18,585
Liabilities:
Derivative Liabilities		(56)
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Natural Gas Liquids Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset		1,350
Assets:
Derivative Asset, Fair Value, Gross Liability		(83)
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Interest Rate Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset		0	0
Assets:
Derivative Asset, Fair Value, Gross Liability		(6,023)
Liabilities:
Derivative Liability, Fair Value, Gross Liability			5,806
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Short-term Investments [Member]
Assets:
Short-term investments			0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset		0	0
Assets:
Derivative Asset, Fair Value, Gross Liability		0
Liabilities:
Derivative Liability, Fair Value, Gross Liability			0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Crude Oil Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset		0	0
Liabilities:
Derivative Liabilities		0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Natural Gas Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset		0	0
Liabilities:
Derivative Liabilities		0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Natural Gas Liquids Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset		0
Assets:
Derivative Asset, Fair Value, Gross Liability		0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Interest Rate Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset		0	0
Assets:
Derivative Asset, Fair Value, Gross Liability		$ 0
Liabilities:
Derivative Liability, Fair Value, Gross Liability			0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Short-term Investments [Member]
Assets:
Short-term investments			$ 0

[1] Represents counterparty netting under the agreement governing such derivative contracts.

XML

Subsidiary Guarantors Subsidiary Guarantor Condensed Consolidating Statements of Cash Flows (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014
Subsidiary Guarantors [Line Items]
Net cash flows provided by operating activities	$ 35,230	$ 25,674
Additions to property, plant and equipment	(44,905)	(63,789)
Proceeds from sale of short-term investments	153,980	0
Net cash provided by (used in) investing activities	109,075	(63,789)
Proceeds from long-term debt	66,600	315,150
Repayment of long-term debt	(185,200)	(252,950)
Payment of debt issuance costs	0	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
Net Cash Provided by (Used in) Discontinued Operations	(974)	5,300
Net 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
Parent Company [Member]
Subsidiary Guarantors [Line Items]
Net cash flows provided by operating activities	(10,873)	2,594
Additions to property, plant and equipment	(337)	4
Proceeds from sale of short-term investments	153,980
Net cash provided by (used in) investing activities	153,643	4
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
Net Cash Provided by (Used in) Discontinued Operations	0	(34,973)
Net increase in cash and cash equivalents	(1,884)	1,105
CASH AND CASH EQUIVALENTS—Beginning of period	2,686	1,237
CASH AND CASH EQUIVALENTS—End of period	802	2,342
Co-issuer [Member]
Subsidiary Guarantors [Line Items]
Net cash flows provided by operating activities	0	0
Additions to property, plant and equipment	0	0
Proceeds from sale of short-term investments	0
Net cash provided by (used in) investing activities	0	0
Proceeds from long-term debt	0	0
Repayment of long-term debt	0	0
Payment of debt issuance costs		0
Settlement of risk management instruments	0	0
Repurchase of common units	0	0
Distributions to members and affiliates	0	0
Net cash (used in) provided by financing activities	0	0
Net Cash Provided by (Used in) Discontinued Operations	0	0
Net increase in cash and cash equivalents	0	0
CASH AND CASH EQUIVALENTS—Beginning of period	1	1
CASH AND CASH EQUIVALENTS—End of period	1	1
Guarantor Subsidiaries [Member]
Subsidiary Guarantors [Line Items]
Net cash flows provided by operating activities	46,103	23,080
Additions to property, plant and equipment	(44,568)	(63,793)
Proceeds from sale of short-term investments	0
Net cash provided by (used in) investing activities	(44,568)	(63,793)
Proceeds from long-term debt	0	0
Repayment of long-term debt	0	0
Payment of debt issuance costs		0
Settlement of risk management instruments	0	0
Repurchase of common units	0	0
Distributions to members and affiliates	0	0
Net cash (used in) provided by financing activities	0	0
Net Cash Provided by (Used in) Discontinued Operations	(974)	40,251
Net increase in cash and cash equivalents	561	(462)
CASH AND CASH EQUIVALENTS—Beginning of period	(1,344)	(1,389)
CASH AND CASH EQUIVALENTS—End of period	(783)	(1,851)
Non-Guarantor Subsidiaries [Member]
Subsidiary Guarantors [Line Items]
Net cash flows provided by operating activities		0
Additions to property, plant and equipment		0
Net cash provided by (used in) investing activities		0
Proceeds from long-term debt		0
Repayment of long-term debt		0
Payment of debt issuance costs		0
Settlement of risk management instruments		0
Repurchase of common units		0
Distributions to members and affiliates		0
Net cash (used in) provided by financing activities		0
Net Cash Provided by (Used in) Discontinued Operations		22
Net increase in cash and cash equivalents		22
CASH AND CASH EQUIVALENTS—Beginning of period		227
CASH AND CASH EQUIVALENTS—End of period		249
Consolidation, Eliminations [Member]
Subsidiary Guarantors [Line Items]
Net cash flows provided by operating activities	0	0
Additions to property, plant and equipment	0	0
Proceeds from sale of short-term investments	0
Net cash provided by (used in) investing activities	0	0
Proceeds from long-term debt	0	0
Repayment of long-term debt	0	0
Payment of debt issuance costs		0
Settlement of risk management instruments	0	0
Repurchase of common units	0	0
Distributions to members and affiliates	0	0
Net cash (used in) provided by financing activities	0	0
Net Cash Provided by (Used in) Discontinued Operations	0	0
Net increase in cash and cash equivalents	0	0
CASH AND CASH EQUIVALENTS—Beginning of period	0	0
CASH AND CASH EQUIVALENTS—End of period	$ 0	$ 0

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Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Policies)

6 Months Ended

Jun. 30, 2015

Accounting Policies [Abstract]

Basis of Presentation and Principles of Consolidation [Text Block]

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, Policy [Policy Text Block]

Use of Estimates—The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reported period. Significant estimates are required for proved oil and natural gas reserves, which can affect the carrying value of oil and natural gas properties. The Partnership evaluates its estimates and assumptions on a regular basis. The Partnership bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results could differ from those estimates and such differences could be material.

Short-term Investments [Policy Text Block]

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, Policy [Policy Text Block]

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, Policy [Policy Text Block]

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

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

Sales Method or Entitlements Method, Policy [Policy Text Block]

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, Policy [Policy Text Block]

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, Policy [Policy Text Block]

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.

Asset Retirement Obligations, Policy [Policy Text Block]

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.

Intangible Assets, Finite-Lived, Policy [Policy Text Block]

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

Earnings Per Share, Policy [Policy Text Block]

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.

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Members' Equity Narrative (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2015	Dec. 31, 2014
Capital Unit [Line Items]
Limited Partners' Capital Account, Units Outstanding	149,563,456	150,154,909
Unvested Restricted Units granted	3,423,262	2,419,750
Equity Issuance, Market Value	$ 100.0
Stock Repurchase Program, Authorized Amount	$ 100.0
Stock Repurchased and Retired During Period, Shares	1,171,584
Repurchase of common units	$ 2.6

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Asset Retirement Obligations Schedule of Change in Asset Retirement Obligation (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2015		Jun. 30, 2014	Dec. 31, 2014
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset Retirement Obligation - Beginning of Period	$ 50,873	[1]	$ 48,564
Additional liabilities	10		21
Liabilities settled	(1,497)		(826)
Revision to liabilities	124		(105)
Accretion expense	1,600		1,620
Asset Retirement Obligation - End of Period	51,110		$ 49,274
Asset Retirement Obligation, Current	$ 2,800			$ 3,000

[1] 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.

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Subsidiary Guarantors Subsidiary Guarantors (Tables)

6 Months Ended

Jun. 30, 2015

SUBSIDIARY GUARANTORS [Abstract]

Subsidiary Guarantor Consolidating Balance Sheet [Table Text Block]

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

Subsidiary Guarantors Consolidating Statements of Operations [Table Text Block]

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	)

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	)

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	)

Subsidiary Guarantor Consolidating Statements of Cash Flows [Table Text Block]

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

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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Related Party Transactions Schedule of Related Party Transactions (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Related Party Transaction [Line Items]
Natural gas purchases from affiliates	$ 0	$ 949	$ 0	$ 2,091

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Divestiture Related Activities Divestiture Related Activities - Asset & Liabilities Held for Sale and Discontinued Operations (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Class of statement of operations line item of discontinued operations:
Revenue	$ 0	$ 245,210	$ 0	$ 548,081
Cost of natural gas, natural gas liquids, condensate and helium	0	199,700	0	444,673
Operations and maintenance	0	25,078	0	50,127
General and administrative	8	12,107	974	20,208
Depreciation, amortization and impairment	0	19,737	0	41,936
Interest expense	0	14,118	0	(27,350)
Other expense	0	60	0	(68)
Operating income (loss) from discontinued operations before taxes	(8)	(25,590)	(974)	(36,281)
Income tax expense (benefit)	0	56	0	(32)
Discontinued operations	$ (8)	$ (25,646)	$ (974)	$ (36,249)

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Commitments and Contingencies Operating Leases (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Operating leases [Line Items]
Operating Leases, Rent Expense	$ 0.3	$ 0.8	$ 0.8	$ 1.6

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Long Term Debt Long-Term Debt (Details) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Revolving credit facility:	$ 94,000	$ 212,600
8 3/8% senior notes due 2019	51,120	51,120
Unamortized bond discount senior notes due 2019	(339)	(377)
Senior Notes	50,781	50,743
LONG-TERM DEBT	$ 144,781	$ 263,343

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Summary of Significant Accounting Policies

6 Months Ended

Jun. 30, 2015

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

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 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.

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.

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Income Taxes Schedule of Income Tax Expense (Benefit) (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
INCOME TAX BENEFIT	$ (695)	$ (885)	$ (1,521)	$ (1,750)

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Intangible Assets Intangible Assets (Details) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Acquired Finite-Lived Intangible Assets [Line Items]
Rights-of-way and easements—at cost	$ 3,920	$ 3,920
Less: accumulated amortization	(946)	(848)
Intangible Assets — Net	$ 2,974	$ 3,072

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Long Term Debt Long-Term Debt (Tables)

6 Months Ended

Jun. 30, 2015

Long-term Debt, by Current and Noncurrent [Abstract]

Schedule of Long-term Debt Instruments [Table Text Block]

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

Schedule of Debt Covenants [Table Text Block]

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

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Intangible Assets Intangible Assets (Tables)

6 Months Ended

Jun. 30, 2015

Goodwill and Intangible Assets Disclosure [Abstract]

Schedule of Finite-Lived Intangible Assets [Table Text Block]

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

Schedule of Impaired Intangible Assets [Table Text Block]

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).

Schedule of Finite-Lived Intangible Assets, Future Amortization Expense [Table Text Block]

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

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Risk Management Activities Schedule of Derivative Instruments, Gain (Loss) in Statement of Financial Performance (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Derivative Instruments, Gain (Loss) [Line Items]
Interest rate risk management gains (losses), net	$ 964	$ (571)	$ (2,102)	$ (861)
Commodity risk management (losses) gains	(11,535)	(18,081)	11,065	(28,114)
Derivative Instruments, Gain (Loss) Recognized in Income, Net	(10,571)	(31,036)	8,963	(47,258)
Interest Rate Contract [Member] | Other Expense [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Interest rate risk management gains (losses), net	964	(571)	(2,102)	(861)
Commodity Contract [Member] | Commodity Risk Management Gains (Losses) [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Commodity risk management (losses) gains	(11,535)	(18,081)	11,065	(28,114)
Commodity Contract [Member] | Discontinued Operations [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Commodity risk management (losses) gains	0	(10,968)	0	(15,879)
Commodity Contract [Member] | Forward Contracts [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Commodity risk management (losses) gains	$ 0	$ (1,416)	$ 0	$ (2,404)

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Intangible Assets Amortization and Impairment (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Amortization	$ 49	$ 49	$ 98	$ 98

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Members' Equity Members' Equity (Tables)

6 Months Ended

Jun. 30, 2015

Distributions Made to Members or Limited Partners [Abstract]

Distributions Made to Limited Partners, by Distribution [Table Text Block]

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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Related Party Transactions Related Party Transactions (Tables)

6 Months Ended

Jun. 30, 2015

Related Party Transactions [Abstract]

Schedule of Related Party Transactions [Table Text Block]

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).

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Organization and Description of Business

6 Months Ended

Jun. 30, 2015

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization and Description of Business

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.

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Risk Management Activities Risk Management Activities (Tables)

6 Months Ended

Jun. 30, 2015

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Interest Rate Derivatives [Table Text Block]

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	%

Schedule of Price Risk Derivatives [Table Text Block]

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.

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block]

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			$	—

Schedule of Derivative Instruments, Gain (Loss) in Statement of Financial Performance [Table Text Block]

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	)

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Property, Plant and Equipment Property, Plant and Equipment (Details) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment - Gross	$ 910,121	$ 930,896
Accumulated depreciation, depletion and amortization	(471,254)	(442,908)
Property, Plant and Equipment — Net	438,867	487,988
Equipment [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment - Gross	101	101
Vehicles [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment - Gross	212	212
Office Equipment [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment - Gross	3,020	3,020
Computer Equipment [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment - Gross	14,958	13,234
Proved Oil and Gas Properties [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment - Gross	884,836	905,622
Unproved Oil and Gas Properties [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment - Gross	6,952	7,512
Asset under Construction [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment - Gross	$ 42	$ 1,195

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Risk Management Activities Interest Rate Derivatives (Details) - Jun. 30, 2015 - Effective Date, 12/31/2014 [Member] - Interest Rate Swap [Member] - USD ($)	Total
Derivative [Line Items]
Derivative, Maturity Date	Dec. 31, 2019
Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Notional Amount	$ 175,000,000
Derivative, Average Fixed Interest Rate	2.3195%

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Consolidated Balance Sheets - USD ($) $ in Thousands		Jun. 30, 2015	Dec. 31, 2014
CURRENT ASSETS:
Cash and cash equivalents		$ 20	$ 1,343
Short-term investments		0	153,448
Accounts receivable (a)	[1]	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
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)	[2]	$ 285,208	$ 388,470
TOTAL		$ 562,178	$ 794,275

[1] Net of allowance for bad debt of $1,540 as of June 30, 2015 and $1,023 as of December 31, 2014.

[2] 149,563,456 and 150,154,909 common 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.

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Intangible Assets Future Amortization Expense (Details) $ in Thousands	Jun. 30, 2015 USD ($)
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Amortization Expense, Remainder of Fiscal Year	$ 98
Finite-Lived Intangible Assets, Amortization Expense, Year Two	196
Finite-Lived Intangible Assets, Amortization Expense, Year Three	196
Finite-Lived Intangible Assets, Amortization Expense, Year Four	196
Finite-Lived Intangible Assets, Amortization Expense, Year Five	196
Finite-Lived Intangible Assets, Amortization Expense, after Year Five	$ 2,092

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Consolidated Statement of Member's Equity - 6 months ended Jun. 30, 2015 - USD ($) $ in Thousands	Total	Number of Common Units [Member]	Common Units [Member]
Beginning Balance - Units Outstanding at Dec. 31, 2014	150,154,909	150,154,909
Members' Equity - Beginning Balance at Dec. 31, 2014	$ 388,470		$ 388,470
Increase (Decrease) in Members' Equity [Roll Forward]
Net loss	(82,093)		(82,093)
Distributions	(21,123)		(21,123)
Vesting of restricted units		754,010
Stock Repurchased During Period, Shares		1,345,463
Stock Repurchased During Period, Value	3,046		3,046
Share Based Compensation, Aggregate Amount	$ 3,000		3,000
Ending Balance - Units Outstanding at Jun. 30, 2015	149,563,456	149,563,456
Members' Equity - Ending Balance at Jun. 30, 2015	$ 285,208		$ 285,208

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Fair Value of Financial Instruments Narrative (Details) - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014
Fair Value Disclosures [Abstract]
Notes Payable, Fair Value Disclosure	$ 51.1	$ 47.0

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Earnings Per Unit Earnings Per Unit (Tables)

6 Months Ended

Jun. 30, 2015

Earnings Per Unit [Abstract]

Schedule of Weighted Average Number of Shares [Table Text Block]

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

Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]

	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.

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	)

XML

Earnings Per Unit Schedule of Weighted Average Number of Units(Details) - shares shares in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Weighted average common units outstanding - Basic	149,301	156,955	149,221	156,802
Weighted average common units outstanding - Diluted	149,301	156,955	149,221	156,802

XML

Earnings Per Unit

6 Months Ended

Jun. 30, 2015

Earnings Per Unit [Abstract]

Earnings Per Unit

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

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.

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	)

XML

Divestiture Related Activities Divestiture Related Activites(Tables)

6 Months Ended

Jun. 30, 2015

Discontinued Operations and Disposal Groups [Abstract]

Schedule of Disposal Groups, Including Discontinued Operations, Income Statement, Balance Sheet and Additional Disclosures [Table Text Block]

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	)

Restructuring and Related Costs [Table Text Block]

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

XML

Subsidiary Guarantors

6 Months Ended

Jun. 30, 2015

SUBSIDIARY GUARANTORS [Abstract]

Subsidiary Guarantors

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.

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

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	)

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	)

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	)

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

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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Divestiture Related Activities Divestiture Related Activities - Restructuring Charges (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2015	Dec. 31, 2014
Restructuring Cost and Reserve [Line Items]
Restructuring and Related Cost, Incurred Cost	$ 317
Restructuring Reserve, Current	1,642	$ 1,325
One-time Termination Benefits [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring and Related Cost, Incurred Cost	(835)
Restructuring Reserve, Current	0	835
Facility Closing [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring and Related Cost, Incurred Cost	1,152
Restructuring Reserve, Current	$ 1,642	$ 490

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Consolidated Statements of Cash Flows - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2015	Jun. 30, 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	0
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	0
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	0
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	0	410
Settlement of risk management instruments	(1,885)	(3,425)
Repurchase of common units	(3,046)	(1,084)
Payments of Distributions to 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	0	(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	$ 0

XML

Consolidated Balance Sheets Parenthetical - Class of Stock [Domain] - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Allowance for doubtful accounts	$ 1,540	$ 1,023
Common stock, units issued	149,563,456	150,154,909
Common stock, units outstanding	149,563,456	150,154,909
Unvested Restricted Units granted	3,423,262	2,419,750

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Risk Management Activities

6 Months Ended

Jun. 30, 2015

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Risk Management Activities

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 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.

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.

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	)

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Document and Entity Information Document - shares	6 Months Ended
	Jun. 30, 2015	Jul. 28, 2015
Entity Information [Line Items]
Entity Registrant Name	EAGLE ROCK ENERGY PARTNERS L P
Entity Central Index Key	0001364541
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-Q
Document Period End Date	Jun. 30, 2015
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	Q2
Amendment Flag	false
Entity Common Stock, Shares Outstanding		152,986,718

XML

Fair Value of Financial Instruments

6 Months Ended

Jun. 30, 2015

Fair Value Disclosures [Abstract]

Fair Value of Financial Instruments

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 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.

	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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Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 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	0	0	68,344	0
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)	0	(5,754)	0
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:
Income (loss) from continuing operations per common unit - Basic	$ (0.16)	$ (0.11)	$ (0.54)	$ (0.16)
Income (loss) from continuing operations per common unit - Diluted	(0.16)	(0.11)	(0.54)	(0.16)
Discontinued operations per common unit - Basic	0.00	(0.16)	(0.01)	(0.23)
Discontinued operations per common unit - Diluted	0.00	(0.16)	(0.01)	(0.23)
Net income (loss) per common unit - Basic	(0.16)	(0.27)	(0.55)	(0.39)
Net income (loss) per common unit - Diluted	$ (0.16)	$ (0.27)	$ (0.55)	$ (0.39)
Weighted Average Number of Shares Outstanding Basic and Diluted
Weighted average common units outstanding - Basic	149,301	156,955	149,221	156,802
Weighted average common units outstanding - Diluted	149,301	156,955	149,221	156,802

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Asset Retirement Obligations

6 Months Ended

Jun. 30, 2015

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

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.

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Property, Plant and Equipment

6 Months Ended

Jun. 30, 2015

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment Disclosure

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).

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Divestiture Related Activities Divestiture Related Activites (Notes)

6 Months Ended

Jun. 30, 2015

Discontinued Operations and Disposal Groups [Abstract]

Disposal Groups, Including Discontinued Operations, Disclosure [Text Block]

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

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Commitments and Contingencies

6 Months Ended

Jun. 30, 2015

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

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 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.

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Members' Equity

6 Months Ended

Jun. 30, 2015

Partners' Capital [Abstract]

Members' Equity

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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Commitments and Contingencies Loss Contingencies (Details) - USD ($)	Jul. 30, 2015	Jun. 30, 2015	Dec. 31, 2014
Loss Contingencies [Line Items]
Accrual for Environmental Loss Contingencies		$ 2,700,000	$ 2,800,000
Subsequent Event [Member]
Loss Contingencies [Line Items]
EPA Penalty Amount	$ 106,000

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Intangible Assets

6 Months Ended

Jun. 30, 2015

Intangible Assets, Net (Excluding Goodwill) [Abstract]

Intangible Assets

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

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

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Long Term Debt

6 Months Ended

Jun. 30, 2015

Long-term Debt, by Current and Noncurrent [Abstract]

Long-term Debt [Text Block]

 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.

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.

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Related Party Transactions

6 Months Ended

Jun. 30, 2015

Related Party Transactions [Abstract]

Related Party Transactions

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).

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Equity Based Compensation Narrative (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Percentage of performance units earned			0.00%
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	14,500,000		14,500,000
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant	3,394,477		3,394,477
Equity-based compensation			$ 3,000	$ 4,042
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	$ 13,400		$ 13,400
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition			2 years 3 months 12 days
Common Units [Member]
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Shares cancelled during period, value			$ 420
Number of Common Units [Member]
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Shares cancelled during period			173,879
Continuing Operations [Member]
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Equity-based compensation	$ 1,100	$ 1,500	$ 3,000	$ 4,000
Performance Shares [Member]
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Grants in Period			871,931
Maximum [Member]
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Percentage of performance units earned			200.00%
Minimum [Member]
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Percentage of performance units earned			70.00%

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Earnings Per Unit Calculation of basic and diluted earnings per unit (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended				6 Months Ended
	Jun. 30, 2015		Jun. 30, 2014		Jun. 30, 2015		Jun. 30, 2014
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Income (Loss) from Continuing Operations Attributable to Parent	$ (23,366)		$ (17,395)		$ (81,119)		$ (25,355)
Distributions	10,699		0	[1]	21,256		0	[2]
Assumed income (loss) from continuing operations after distribution to be allocated	(34,065)		(17,395)		(102,375)		(25,355)
DISCONTINUED OPERATIONS, NET OF TAX	(8)		(25,646)		(974)		(36,249)
Net loss	$ (23,374)		$ (43,041)		$ (82,093)		$ (61,604)
Income (loss) from continuing operations per common unit - Basic	$ (0.16)		$ (0.11)		$ (0.54)		$ (0.16)
Discontinued operations per common unit - Basic	0.00		(0.16)		(0.01)		(0.23)
Net income (loss) per common unit - Basic	(0.16)		(0.27)		(0.55)		(0.39)
Net income (loss) per common unit - Diluted	$ (0.16)		$ (0.27)		$ (0.55)		$ (0.39)
Common Units [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Income (Loss) from Continuing Operations Attributable to Parent	$ (23,596)		$ (17,395)		$ (81,473)		$ (25,355)
Distributions	10,469		0	[1]	20,902		0	[2]
Assumed income (loss) from continuing operations after distribution to be allocated	(34,065)		(17,395)		(102,375)		(25,355)
DISCONTINUED OPERATIONS, NET OF TAX	(8)		(25,646)		(974)		(36,249)
Net loss	$ (23,604)		$ (43,041)		$ (82,447)		$ (61,604)
Income (loss) from continuing operations per common unit - Basic	$ (0.16)		$ (0.11)		$ (0.54)		$ (0.16)
Discontinued operations per common unit - Basic	0.00		(0.16)		(0.01)		(0.23)
Net income (loss) per common unit - Basic	(0.16)		(0.27)		(0.55)		(0.39)
Income (loss) from continuing operations per common unit - Diluted	(0.16)		(0.11)		(0.54)		(0.16)
Discontinued operations per common unit - Diluted	0.00		(0.16)		(0.01)		(0.23)
Net income (loss) per common unit - Diluted	$ (0.16)		$ (0.27)		$ (0.55)		$ (0.39)
Restricted Stock Units (RSUs) [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Income (Loss) from Continuing Operations Attributable to Parent	$ 230	[3]	$ 0	[4]	$ 354	[5]	$ 0	[5]
Distributions	230	[3]	0	[1],[4]	354	[5]	0	[2],[5]
Assumed income (loss) from continuing operations after distribution to be allocated	0	[3]	0	[4]	0	[5]	0	[5]
DISCONTINUED OPERATIONS, NET OF TAX	0	[3]	0	[4]	0	[5]	0	[5]
Net loss	$ 230	[3]	$ 0	[4]	$ 354	[5]	$ 0	[5]

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

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

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

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

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

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Equity Based Compensation Share-based Compensation Rollforward (Details) - 6 months ended Jun. 30, 2015 - $ / shares	Total
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Outstanding [Roll Forward]
Unvested Restricted Units Outstanding - Beginning Balance	2,419,750
Unvested Restricted Units Outstanding - Ending Balance	3,423,262
Restricted Stock Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Outstanding [Roll Forward]
Unvested Restricted Units Outstanding - Beginning Balance	2,419,750
Grants in Period	2,116,034
Vesting of restricted units	754,010
Forfeited in Period	(358,512)
Unvested Restricted Units Outstanding - Ending Balance	3,423,262
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Roll Forward]
Weighted Average Grant Date Fair Value	$ 6.06
Grants in Period, Weighted Average Grant Date Fair Value	2.54
Vested in Period, Weighted Average Grant Date Fair Value	7.05
Forfeitures in Period, Weighted Average Grant Price	6.30
Weighted Average Grant Date Fair Value - Ending	$ 3.64
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Outstanding [Roll Forward]
Unvested Restricted Units Outstanding - Beginning Balance	647,788
Grants in Period	871,931
Forfeited in Period	(123,175)
Unvested Restricted Units Outstanding - Ending Balance	1,396,544
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Roll Forward]
Weighted Average Grant Date Fair Value	$ 3.63
Grants in Period, Weighted Average Grant Date Fair Value	2.61
Forfeitures in Period, Weighted Average Grant Price	3.59
Weighted Average Grant Date Fair Value - Ending	$ 3.00

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Equity Based Compensation Equity Based Compensation (Tables)

6 Months Ended

Jun. 30, 2015

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Schedule of Share-based Compensation, Stock Options, Activity [Table Text Block]

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

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

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Members' Equity Distributions (Details) - $ / shares	3 Months Ended
	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014
Dividends Payable [Line Items]
Common Stock, Dividends, Per Share, Cash Paid	$ 0.07	$ 0.07	$ 0.07
Distribution Made to Limited Partner, Date of Record	Aug. 06, 2015	May 08, 2015	Feb. 06, 2015
Distribution Made to Limited Partner, Distribution Date	Aug. 14, 2015	May 15, 2015	Feb. 13, 2015

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Equity Based Compensation

6 Months Ended

Jun. 30, 2015

Share-based Compensation [Abstract]

Equity-based Compensation

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.

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.

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.

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Property, Plant and Equipment Property, Plant and Equipment (Tables)

6 Months Ended

Jun. 30, 2015

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment [Table Text Block]

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).

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Long Term Debt Narrative (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2015	Apr. 01, 2015	Dec. 31, 2014	Oct. 10, 2014
Debt Instrument [Line Items]
Letters of Credit Outstanding, Amount	$ 0
Revolving credit facility:	$ 94,000		$ 212,600
Line of Credit Facility, Commitment Fee Percentage	0.375%
Letters of Credit Sub-limit	$ 50,000
Line of Credit Facility, Remaining Borrowing Capacity	$ 176,000
Line of Credit Facility, Current Borrowing Capacity		$ 270,000		$ 320,000
Debt Instrument, Covenant Compliance	As of June 30, 2015, the Partnership was in compliance with the financial covenants under the Credit Agreement.
Line of Credit Facility, Maximum Borrowing Capacity				$ 1,200,000
8 3/8% senior notes due 2019	$ 51,120		$ 51,120

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Property, Plant and Equipment Depreciation, Depletion, Amortization and Impairment (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Depreciation	$ 807	$ 889	$ 1,366	$ 1,586
Depletion	14,727	19,334	28,446	39,006
Oil and Gas Properties [Member]
Impairment of Long-Lived Assets Held-for-use	$ 0	$ 0	$ 68,344	$ 0

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Consolidated Statements of Comprehensive Income Statement - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Net loss	$ (23,374)	$ (43,041)	$ (82,093)	$ (61,604)
Gain on short-term investments	(3,603)	0	3,603	0
Loss on short-term investments	0	0	(3,603)	0
COMPREHENSIVE LOSS	$ (19,771)	$ (43,041)	$ (82,093)	$ (61,604)

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New Accounting Pronouncements

6 Months Ended

Jun. 30, 2015

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

New Accounting Pronouncements

NEW ACCOUNTING PRONOUNCEMENTS

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

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

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

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

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

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Fair Value of Financial Instruments Fair Value, Assets and Liabilities Measured on a Nonrecurring Basis (Details) - Oil and Gas Properties [Member] - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Property, Plant, and Equipment, Fair Value Disclosure	$ 44,658		$ 44,658
Impairment of Long-Lived Assets Held-for-use	0	$ 0	68,344	$ 0
Fair Value, Measurements, Nonrecurring [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Property, Plant, and Equipment, Fair Value Disclosure	0		0
Fair Value, Measurements, Nonrecurring [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Property, Plant, and Equipment, Fair Value Disclosure	0		0
Fair Value, Measurements, Nonrecurring [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Property, Plant, and Equipment, Fair Value Disclosure	$ 44,658		$ 44,658

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Subsidiary Guarantors Subsidiary Guarantors Condensed Consolidating Balance Sheets (Details) - USD ($) $ in Thousands		Jun. 30, 2015	Dec. 31, 2014
Subsidiary Guarantors [Line Items]
Accounts receivable – related parties		$ 0	$ 0
Other current assets		74,870	249,103
PROPERTY, PLANT AND EQUIPMENT — Net		438,867	487,988
Investment in subsidiaries		0	0
Total other long-term assets		48,441	57,184
TOTAL		562,178	794,275
Accounts payable – related parties		0	0
Other current liabilities		50,305	59,525
Other long-term liabilities		81,884	82,937
LONG-TERM DEBT		144,781	263,343
MEMBERS' EQUITY (b)	[1]	285,208	388,470
TOTAL		562,178	794,275
Parent Company [Member]
Subsidiary Guarantors [Line Items]
Accounts receivable – related parties		838,125	838,656
Other current assets		40,055	211,213
PROPERTY, PLANT AND EQUIPMENT — Net		1,260	1,334
Investment in subsidiaries		(489,500)	(413,023)
Total other long-term assets		43,267	52,272
TOTAL		433,207	690,452
Accounts payable – related parties		0	0
Other current liabilities		2,853	37,850
Other long-term liabilities		365	789
LONG-TERM DEBT		144,781	263,343
MEMBERS' EQUITY (b)		285,208	388,470
TOTAL		433,207	690,452
Co-issuer [Member]
Subsidiary Guarantors [Line Items]
Accounts receivable – related parties		0	0
Other current assets		1	1
PROPERTY, PLANT AND EQUIPMENT — Net		0	0
Investment in subsidiaries		0	0
Total other long-term assets		0	0
TOTAL		1	1
Accounts payable – related parties		0	0
Other current liabilities		0	0
Other long-term liabilities		0	0
LONG-TERM DEBT		0	0
MEMBERS' EQUITY (b)		1	1
TOTAL		1	1
Guarantor Subsidiaries [Member]
Subsidiary Guarantors [Line Items]
Accounts receivable – related parties		0	0
Other current assets		34,814	37,889
PROPERTY, PLANT AND EQUIPMENT — Net		437,607	486,654
Investment in subsidiaries		0	0
Total other long-term assets		5,174	4,912
TOTAL		477,595	529,455
Accounts payable – related parties		838,125	838,656
Other current liabilities		47,452	21,675
Other long-term liabilities		81,519	82,148
LONG-TERM DEBT		0	0
MEMBERS' EQUITY (b)		(489,501)	(413,024)
TOTAL		477,595	529,455
Consolidation, Eliminations [Member]
Subsidiary Guarantors [Line Items]
Accounts receivable – related parties		(838,125)	(838,656)
Other current assets		0	0
PROPERTY, PLANT AND EQUIPMENT — Net		0	0
Investment in subsidiaries		489,500	413,023
Total other long-term assets		0	0
TOTAL		(348,625)	(425,633)
Accounts payable – related parties		(838,125)	(838,656)
Other current liabilities		0	0
Other long-term liabilities		0	0
LONG-TERM DEBT		0	0
MEMBERS' EQUITY (b)		489,500	413,023
TOTAL		$ (348,625)	$ (425,633)

[1] 149,563,456 and 150,154,909 common 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.

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Asset Retirement Obligations Asset Retirement Obligations (Tables)

6 Months Ended

Jun. 30, 2015

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Change in Asset Retirement Obligation [Table Text Block]

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).

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Organization and Description of Business Narrative (Details)	May. 21, 2015
Business Combinations [Abstract]
Unit Conversion Rate	0.185

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Income Taxes

6 Months Ended

Jun. 30, 2015

Income Tax Disclosure [Abstract]

Income Taxes

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.