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 March 31, 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 152,990,305 common units outstanding as of April 28, 2015.

TABLE OF CONTENTS

		Page
PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements	2
	Unaudited Condensed Consolidated Balance Sheets as of March 31, 2015 and December 31, 2014	2
	Unaudited Condensed Consolidated Statements of Operations for the three months ended March 31, 2015 and 2014	3
	Unaudited Condensed Consolidated Statements of Comprehensive Income for the three months ended March 31, 2015 and 2014	4
	Unaudited Condensed Consolidated Statement of Members' Equity for the three months ended March 31, 2015	4
	Unaudited Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 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	29
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	43
Item 4.	Controls and Procedures	44
PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	45
Item 1A.	Risk Factors	45
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	45
Item 3.	Defaults Upon Senior Securities	45
Item 4.	Mine Safety Disclosures	45
Item 5.	Other Information	45
Item 6.	Exhibits	45

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)

	March 31, 2015		December 31, 2014
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	37	$	1,343
Short-term investments	72,924		153,448
Accounts receivable (a)	32,931		39,596
Risk management assets	47,392		44,805
Prepayments and other current assets	11,764		9,911
Total current assets	165,048		249,103
PROPERTY, PLANT AND EQUIPMENT — Net	432,291		487,988
INTANGIBLE ASSETS — Net	3,023		3,072
DEFERRED TAX ASSET	1,805		2,315
RISK MANAGEMENT ASSETS	50,007		46,490
OTHER ASSETS	5,063		5,307
TOTAL	$	657,237	$	794,275
LIABILITIES AND MEMBERS' EQUITY
CURRENT LIABILITIES:
Accounts payable	$	38,145	$	49,226
Accrued liabilities	7,575		8,053
Taxes payable	2,212		2,246
Total current liabilities	47,932		59,525
LONG-TERM DEBT	212,762		263,343
ASSET RETIREMENT OBLIGATIONS	47,575		47,907
DEFERRED TAX LIABILITY	28,921		30,321
OTHER LONG TERM LIABILITIES	5,270		4,709
COMMITMENTS AND CONTINGENCIES (Note 12)
MEMBERS' EQUITY (b)	314,777		388,470
TOTAL	$	657,237	$	794,275

________________________ 

(a) Net of allowance for bad debt of $1,263 as of March 31, 2015 and $1,023 as of December 31, 2014.

(b) 149,027,423 and 150,154,909common units were issued and outstanding as of March 31, 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 2,121,963 and 2,419,750 as of March 31, 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 March 31,
	2015			2014
REVENUE:
Natural gas, natural gas liquids, oil, condensate and sulfur	$	29,513		$	55,084
Commodity risk management gains (losses), net	22,600			(10,033		)
Other revenue	9			152
Total revenue	52,122			45,203
COSTS AND EXPENSES:
Operations and maintenance	10,082			11,498
Taxes other than income	1,388			3,791
General and administrative	10,989			13,290
Impairment	68,344			—
Depreciation, depletion and amortization	14,645			20,406
Total costs and expenses	105,448			48,985
OPERATING LOSS	(53,326		)	(3,782		)
OTHER (EXPENSE) INCOME:
Interest expense, net	(2,318		)	(4,754		)
Interest rate risk management losses, net	(3,066		)	(290		)
Loss on short-term investments	(2,004		)	—
Other income, net	2,135			1
Total other (expense) income	(5,253		)	(5,043		)
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(58,579		)	(8,825		)
INCOME TAX BENEFIT	(826		)	(865		)
LOSS FROM CONTINUING OPERATIONS	(57,753		)	(7,960		)
DISCONTINUED OPERATIONS, NET OF TAX	(966		)	(10,603		)
NET LOSS	$	(58,719	)	$	(18,563	)

NET LOSS PER COMMON UNIT—BASIC AND DILUTED:
Loss from Continuing Operations
Common units - Basic	$	(0.39	)	$	(0.05	)
Common units - Diluted	$	(0.39	)	$	(0.05	)
Discontinued Operations
Common units - Basic	$	(0.01	)	$	(0.07	)
Common units - Diluted	$	(0.01	)	$	(0.07	)
Net Loss
Common units - Basic	$	(0.40	)	$	(0.12	)
Common units - Diluted	$	(0.40	)	$	(0.12	)
Weighted Average Units Outstanding
Common units - Basic	149,143			156,644
Common units - Diluted	149,143			156,644

 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 March 31,
	2015			2014
Net loss	$	(58,719	)	$	(18,563	)
Other comprehensive income:
Loss on short-term investments	(3,603		)	—
COMPREHENSIVE LOSS	$	(62,322	)	$	(18,563	)

 See accompanying notes to unaudited condensed consolidated financial statements.

UNAUDITED CONDENSED CONSOLIDATED STATEMENT OF MEMBERS’ EQUITY

FOR THE THREE MONTHS ENDED MARCH 31, 2015

(In thousands, except unit amounts)

	Number of Common Units		Common Units			Accumulated Other Comprehensive Income			Total
BALANCE — December 31, 2014	150,154,909		$	388,470		$	—		$	388,470
Net loss	—		(58,719		)	—			(58,719		)
Loss on short-term investments	—		—			(3,603		)	(3,603		)
Distributions	—		(10,565		)	—			(10,565		)
Vesting of restricted units	60,700		—			—			—
Repurchase of common units	(1,188,186	)	(2,662		)	—			(2,662		)
Equity based compensation	—		1,856			—			1,856
BALANCE — March 31, 2015	149,027,423		$	318,380		$	(3,603	)	$	314,777

 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)

	Three Months Ended March 31,
	2015			2014
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(58,719	)	$	(18,563	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Discontinued operations	966			10,603
Depreciation, depletion and amortization	14,645			20,406
Impairment	68,344			—
Amortization of debt issuance costs	264			659
(Gain) loss from risk management activities, net	(19,534		)	10,323
Derivative settlements	14,370			(3,138		)
Equity-based compensation	1,856			2,583
Loss on short-term investments	2,004			—
Other	(887		)	151
Changes in assets and liabilities—net of acquisitions:
Accounts receivable	4,039			(11,636		)
Prepayments and other current assets	(1,853		)	(6,068		)
Accounts payable	(9,555		)	2,795
Accrued liabilities	(435		)	16,636
Other assets	(3		)	(117		)
Other current liabilities	(775		)	(831		)
Net cash provided by operating activities	14,727			23,803
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment	(28,055		)	(42,282		)
Proceeds from sale of short-term investments	77,755			—
Net cash provided by (used in) investing activities	49,700			(42,282		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	45,300			144,250
Repayment of long-term debt	(95,900		)	(127,050		)
Payment of debt issuance costs	—			(205		)
Payments for derivative contracts	(940		)	(1,708		)
Repurchase of common units	(2,662		)	—
Distributions to members and affiliates	(10,565		)	(23,801		)
Net cash used in financing activities	(64,767		)	(8,514		)
CASH FLOWS FROM DISCONTINUED OPERATIONS:
Operating activities	(966		)	44,750
Investing activities	—			(12,210		)
Net cash (used in) provided by discontinued operations	(966		)	32,540
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS	(1,306		)	5,547
CASH AND CASH EQUIVALENTS—Beginning of period	1,343			76
CASH AND CASH EQUIVALENTS—End of period	$	37		$	5,623
NONCASH INVESTING AND FINANCING ACTIVITIES:
Investments in property, plant and equipment, not paid	$	10,627		$	6,241
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Interest paid—net of amounts capitalized	$	999		$	5,558
Cash paid for taxes	$	98		$	—

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.

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 months endedMarch 31, 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 2014 annual report on Form 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.

6

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Short-term Investments— A portion of the consideration received for the Midstream Business Contribution included Regency common units. These common units have a readily determinable fair value, are being classified as available-for-sale equity securities and are recorded as short-term investments on the 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 from Regency as a result of holding these common units are recorded as other income on the unaudited condensed consolidated statements of operations.

For the three months endedMarch 31, 2015, the Partnership received and recorded distributions from Regency of $2.1 million, recorded a $2.0 million loss as a result of the sale of Regency common units and recorded a $3.6 million unrealized loss resulting from the decrease in the fair value, which the Partnership deemed to be temporary, of the remaining Regency common units. As of March 31, 2015, the Partnership held 3,188,624 Regency common units, which did not include sales of 150,000 Regency common units that had not settled as of March 31, 2015 and for which a receivable of $3.4 million was recorded as part of accounts receivable in the unaudited condensed consolidated balance sheets.

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.

7

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

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

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:

	March 31, 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	13,583			13,234
Proved properties	863,565			905,622
Unproved properties	7,066			7,512
Work in progress	1,201			1,195
	888,748			930,896
Less: accumulated depreciation, depletion and amortization	(456,457		)	(442,908		)
Net property, plant and equipment	$	432,291		$	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 March 31,
		2015		2014
	($ in thousands)
Depreciation		$	559	$	707
Depletion		$	13,719	$	19,672
Impairment expense:
Proved properties (a)		$	68,344	$	—

________________________________

(a)During the three months endedMarch 31, 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).

9

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	9			16
Liabilities settled	(1,302		)	(682		)
Revision to liabilities	124			(105		)
Accretion expense	793			812
Asset retirement obligations—March 31 (a)	$	50,497		$	48,605

_____________________________________

(a) As of March 31, 2015 and December 31, 2014, $2.9 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 three months endedMarch 31, 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:

	March 31, 2015			December 31, 2014
	($ in thousands)
Rights-of-way and easements—at cost	$	3,920		$	3,920
Less: accumulated amortization	(897		)	(848		)
Net intangible assets	$	3,023		$	3,072

10

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 March 31,
		2015		2014
	($ in thousands)
Amortization		$	49	$	49

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 March 31, 2015 is as follows (in thousands):

Year ending December 31,
2015	$	147
2016	$	196
2017	$	196
2018	$	196
2019	$	196
Thereafter	$	2,092

NOTE 7. LONG-TERM DEBT

Long-term debt consisted of the following:

	March 31, 2015			December 31, 2014
	($ in thousands)
Revolving credit facility:	$	162,000		$	212,600
Senior Notes:
8.375% Senior Notes due 2019	51,120			51,120
Unamortized bond discount	(358		)	(377		)
Total Senior Notes	50,762			50,743
Total long-term debt	$	212,762		$	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 current commitments totaling $320 million, with the ability to increase commitments up to a total aggregate amount of $1.2 billion. The Fifth Amendment coincided with the semi-annual borrowing base redetermination by the Partnership's commercial lenders. 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.

As of March 31, 2015, the Partnership had approximately $158.0 million of availability under the credit facility, based on its borrowing base on that date. The Partnership currently pays a 0.50% commitment fee (based on the Partnership's borrowing base utilization percentage) per year on the difference between total commitments and the amount drawn under the credit facility. The Credit Agreement includes a sub-limit for the issuance of standby letters of credit for a total of $50.0 million. As of March 31, 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 March 31, 2015:

	Debt Covenant	Actual Covenant Ratio as of March 31, 2015
Maximum total leverage ratio	4.0	1.8
Minimum current ratio	1.0	5.8

As of March 31, 2015, the Partnership was in compliance with the financial covenants under the Credit Agreement.

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.

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 March 31, 2015 and December 31, 2014, there were 149,027,423 and 150,154,909 unrestricted common units outstanding, respectively. In addition, there were 2,121,963 and 2,419,750 unvested restricted common units outstanding at March 31, 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 repurchases may be made 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 ending September 30, 2014 and will conclude by March 31, 2016. The repurchase program does not obligate the Partnership to acquire any, or any specific number of, units and may be discontinued at any time. The Partnership intends to cancel any units it repurchases under the repurchase program. During the three months endedMarch 31, 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

_____________________________

+ 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 March 31,
	2015		2014
Affiliates of Natural Gas Partners:	($ in thousands)
Natural gas purchases from affiliates	$	—	$	1,142

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 March 31, 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 March 31, 2015, that will mature during the years ended December 31, 2015 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)	8,100,000	$	4.07
Crude Oil	Costless Collar	360,000	$	90.00	$	97.55
Crude Oil	Swap (Pay Floating/Receive Fixed)	472,500	$	89.78
IsoButane	Swap (Pay Floating/Receive Fixed)	1,591,800	$	0.66
Natural Gasoline	Swap (Pay Floating/Receive Fixed)	1,251,600	$	1.13
Normal Butane	Swap (Pay Floating/Receive Fixed)	1,234,800	$	0.66
Propane	Swap (Pay Floating/Receive Fixed)	3,952,200	$	0.54
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
Contracts Maturing in 2017
Crude Oil	Swap (Pay Floating/Receive Fixed)	444,000	$	89.24
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.

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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 March 31, 2015 and December 31, 2014:

	As of March 31, 2015
	Derivative Assets				Derivative Liabilities
	Balance Sheet Classification	Fair Value			Balance Sheet Classification	Fair Value
	($ in thousands)
Interest rate derivatives - liabilities	Current assets	$	(3,220	)	Current liabilities	$	—
Interest rate derivatives - liabilities	Long-term assets	(4,712		)	Long-term liabilities	—
Commodity derivatives - assets	Current assets	50,624			Current liabilities	—
Commodity derivatives - assets	Long-term assets	54,718			Long-term liabilities	—
Commodity derivatives - liabilities	Current assets	(11		)	Current liabilities	—
Total derivatives		$	97,399			$	—
	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 March 31,
		2015			2014
		($ in thousands)
Interest rate derivatives	Interest rate risk management losses, net	$	(3,066	)	$	(290	)
Commodity derivatives	Commodity risk management gains (losses), net	22,600			(10,033		)
Commodity derivatives	Discontinued operations	—			(4,911		)
Commodity derivatives - trading	Discontinued operations	—			(987		)
	Total	$	19,534		$	(16,221	)

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 March 31, 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 March 31, 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 March 31, 2015 and December 31, 2014: 

	As of March 31, 2015
	Level 1		Level 2			Level 3		Netting (a)			Total
	($ in thousands)
Assets:
Crude oil derivatives	$	—	$	84,171		$	—	$	—		$	84,171
Natural gas derivatives	—		21,049			—		—			21,049
NGL derivatives	—		122			—		(11		)	111
Interest rate swaps	—		—			—		(7,932		)	(7,932		)
Equity investments	72,924		—			—		—			72,924
Total	$	72,924	$	105,342		$	—	$	(7,943	)	$	170,323
Liabilities:
NGL derivatives	—		(11		)	—		11			—
Interest rate swaps	—		(7,932		)	—		7,932			—
Total	$	—	$	(7,943	)	$	—	$	7,943		$	—

____________________________

(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 months endedMarch 31, 2015. The following table discloses the fair value of the Partnership's assets measured at fair value on a nonrecurring basis during the three months endedMarch 31, 2015:

	Three Months Ended March 31,
	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 March 31, 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 outstanding debt associated with the Senior Notes bore interest at a fixed rate; based on the market price of the Senior Notes as of March 31, 2015 and December 31, 2014, the Partnership estimates that the fair value of the Senior Notes was $49.1 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 March 31, 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.

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 March 31, 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 $0.5 million and $0.8 million for the three months endedMarch 31, 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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EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 months endedMarch 31, 2015 and March 31, 2014, the Partnership recognized an income tax benefit of $0.8 million and $0.9 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 March 31, 2015, a total of 6,975,671 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 three months endedMarch 31, 2015 is provided below:

	Number of Restricted Units		Weighted Average Fair Value
Outstanding at December 31, 2014	2,419,750		$	6.06
Granted	23,000		$	2.37
Vested	(60,700	)	$	4.46
Forfeited	(260,087	)	$	6.69
Outstanding at March 31, 2015	2,121,963		$	5.99

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

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EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 three months endedMarch 31, 2015 is provided below:

	Number of Performance Units		Weighted Average Fair Value
Outstanding at December 31, 2014	647,788		$	3.63
Forfeited	(123,175	)	$	3.59
Outstanding at March 31, 2015	524,613		$	3.64

Equity-Based Compensation

For the three months endedMarch 31, 2015 and March 31, 2014, the Partnership recorded non-cash compensation expense of approximately $1.9 million and $2.6 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 March 31, 2015, unrecognized compensation costs related to the outstanding restricted units and performance units under the LTIP totaled approximately $8.6 million. The remaining expense is to be recognized over a weighted average of 1.91 years.

In connection with the vesting of certain restricted units during the three months endedMarch 31, 2015, the Partnership cancelled 16,602 of the newly-vested common units in satisfaction of less than $0.1 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.

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 March 31, 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 March 31,
		2015	2014
	(in thousands)
Weighted average units outstanding during period:
Common units - Basic		149,143	156,644
Common units - Diluted		149,143	156,644

21

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 March 31, 2015:

	Total			Common Units			Restricted Common Units*
	($ in thousands, except for per unit amounts)
Loss from continuing operations	$	(57,753	)
Distributions	10,561			$	10,432		$	129
Assumed loss from continuing operations after distribution to be allocated	(68,314		)	(68,314		)	—
Assumed allocation of loss from continuing operations	(57,753		)	(57,882		)	129
Discontinued operations, net of tax	(966		)	(966		)	—
Assumed net loss to be allocated	$	(58,719	)	$	(58,848	)	$	129
Basic loss from continuing operations per unit				$	(0.39	)
Basic discontinued operations per unit				$	(0.01	)
Basic loss per unit				$	(0.40	)
Diluted loss from continuing operations per unit				$	(0.39	)
Diluted discontinued operations per unit				$	(0.01	)
Diluted loss per unit				$	(0.40	)

_____________________________

* 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 March 31, 2014:

	Total			Common Units			Restricted Common Units*
	($ in thousands, except for per unit amounts)
Loss from continuing operations	$	(7,960	)
Distributions**	—			$	—		$	—
Assumed loss from continuing operations after distribution to be allocated	(7,960		)	(7,960		)	—
Assumed allocation of loss from continuing operations	(7,960		)	(7,960		)	—
Discontinued operations, net of tax	(10,603		)	(10,603		)	—
Assumed net loss to be allocated	$	(18,563	)	$	(18,563	)	$	—
Basic income from continuing operations per unit				$	(0.05	)
Basic discontinued operations per unit				$	(0.07	)
Basic loss per unit				$	(0.12	)
Diluted income from continuing operations per unit				$	(0.05	)
Diluted discontinued operations per unit				$	(0.07	)
Diluted income per unit				$	(0.12	)

_____________________________

* 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.

22

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 months endedMarch 31, 2015 and 2014:

	Three Months Ended March 31,
	2015			2014
	($ in thousands)
Class of statement of operations line item of discontinued operations:
Revenue	$	—		$	302,871
Cost of natural gas, NGLs, condensate and helium	—			244,973
Operations, maintenance and taxes other than income	—			25,049
General and administrative	966			8,101
Depreciation, amortization and impairment	—			22,199
Interest expense	—			(13,232		)
Other expense	—			(8		)
Operating loss from discontinued operations before taxes	(966		)	(10,691		)
Income tax benefit	—			(88		)
Discontinued operations, net of tax	$	(966	)	$	(10,603	)

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 of $4.0 million and $0.6 million, respectively, 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 March 31, 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 March 31, 2015.

	Employee Related Costs			Facility and Other Costs		Total
	($ in thousands)
Balance at December 31, 2014	$	835		$	490	$	1,325
Payments and other adjustments	(183		)	1,026		843
Balance at March 31, 2015	$	652		$	1,516	$	2,168

23

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 March 31, 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 March 31, 2015 and December 31, 2014, and unaudited condensed consolidated statements of operations for the three months endedMarch 31, 2015 and 2014, and unaudited condensed consolidated statements of cash flows for the three months endedMarch 31, 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.

24

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Balance Sheet

March 31, 2015

	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Consolidating Entries			Total
	($ in thousands)
ASSETS:
Accounts receivable – related parties	$	865,930		$	—	$	—		$	(865,930	)	$	—
Other current assets	129,008			1		36,039			—			165,048
Total property, plant and equipment, net	1,531			—		430,760			—			432,291
Investment in subsidiaries	(486,135		)	—		—			486,135			—
Total other long-term assets	55,072			—		4,826			—			59,898
Total assets	$	565,406		$	1	$	471,625		$	(379,795	)	$	657,237
LIABILITIES AND EQUITY:
Accounts payable – related parties	$	—		$	—	$	865,930		$	(865,930	)	$	—
Other current liabilities	37,497			—		10,435			—			47,932
Other long-term liabilities	370			—		81,396			—			81,766
Long-term debt	212,762			—		—			—			212,762
Equity	314,777			1		(486,136		)	486,135			314,777
Total liabilities and equity	$	565,406		$	1	$	471,625		$	(379,795	)	$	657,237

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

25

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Statement of Operations

For the Three Months EndedMarch 31, 2015

	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Consolidating Entries			Total
	($ in thousands)
Total revenues	$	21,227		$	—	$	30,895		$	—		$	52,122
Operations and maintenance	—			—		10,082			—			10,082
Taxes other than income	—			—		1,388			—			1,388
General and administrative	2,082			—		8,907			—			10,989
Depreciation, depletion and amortization	136			—		14,509			—			14,645
Impairment	—			—		68,344			—			68,344
Income (loss) from operations	19,009			—		(72,335		)	—			(53,326		)
Interest expense, net	(2,318		)	—		—			—			(2,318		)
Other non-operating income	4,257			—		2,264			(4,386		)	2,135
Other non-operating expense	(6,459		)	—		(2,997		)	4,386			(5,070		)
Income (loss) before income taxes	14,489			—		(73,068		)	—			(58,579		)
Income tax expense (benefit)	96			—		(922		)	—			(826		)
Equity in earnings of subsidiaries	(73,110		)	—		—			73,110			—
Loss from continuing operations	(58,717		)	—		(72,146		)	73,110			(57,753		)
Discontinued operations, net of tax	(2		)	—		(964		)	—			(966		)
Net loss	$	(58,719	)	$	—	$	(73,110	)	$	73,110		$	(58,719	)

Unaudited Condensed Consolidating Statement of Operations

For the Three Months EndedMarch 31, 2014

	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-Guarantor Investments			Consolidating Entries			Total
	($ in thousands)
Total revenues	$	(10,033	)	$	—	$	55,236		$	—		$	—		$	45,203
Operations and maintenance	—			—		11,498			—			—			11,498
Taxes other than income	—			—		3,791			—			—			3,791
General and administrative	2,897			—		10,393			—			—			13,290
Depreciation, depletion and amortization	53			—		20,353			—			—			20,406
Loss from operations	(12,983		)	—		9,201			—			—			(3,782		)
Interest expense, net	(4,754		)	—		—			—			—			(4,754		)
Other non-operating income	2,221			—		2,301			—			(4,522		)	—
Other non-operating expense	(1,716		)	—		(3,095		)	—			4,522			(289		)
Loss before income taxes	(17,232		)	—		8,407			—			—			(8,825		)
Income tax benefit	(267		)	—		(598		)	—			—			(865		)
Equity in earnings of subsidiaries	18,634			—		—			—			(18,634		)	—
Loss from continuing operations	1,669			—		9,005			—			(18,634		)	(7,960		)
Discontinued operations, net of tax	(20,232		)	—		9,636			(7		)	—			(10,603		)
Net loss	$	(18,563	)	$	—	$	18,641		$	(7	)	$	(18,634	)	$	(18,563	)

26

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Statement of Cash Flows

For the Three Months EndedMarch 31, 2015

	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Consolidating Entries		Total
	($ in thousands)
Net cash flows provided by operating activities	$	(14,013	)	$	—	$	28,740		$	—	$	14,727
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment	(334		)	—		(27,721		)	—		(28,055		)
Proceeds from sale of short-term investments	77,755			—		—			—		77,755
Net cash flows provided by investing activities	77,421			—		(27,721		)	—		49,700
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	45,300			—		—			—		45,300
Repayment of long-term debt	(95,900		)	—		—			—		(95,900		)
Payments for derivative contracts	(940		)	—		—			—		(940		)
Repurchase of common units	(2,662		)	—		—			—		(2,662		)
Distributions to members and affiliates	(10,565		)	—		—			—		(10,565		)
Net cash flows used in financing activities	(64,767		)	—		—			—		(64,767		)
Net cash flows used in discontinued operations	(2		)	—		(964		)	—		(966		)
Net decrease in cash and cash equivalents	(1,361		)	—		55			—		(1,306		)
Cash and cash equivalents at beginning of period	2,686			1		(1,344		)	—		1,343
Cash and cash equivalents at end of period	$	1,325		$	1	$	(1,289	)	$	—	$	37

27

EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Statement of Cash Flows

For the Three Months EndedMarch 31, 2014

	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-Guarantor Investments		Consolidating Entries		Total
	($ in thousands)
Net cash flows provided by operating activities	$	30,293		$	—	$	(6,490	)	$	—	$	—	$	23,803
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment	(336		)	—		(41,946		)	—		—		(42,282		)
Net cash flows used in investing activities	(336		)	—		(41,946		)	—		—		(42,282		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	144,250			—		—			—		—		144,250
Repayment of long-term debt	(127,050		)	—		—			—		—		(127,050		)
Payment of debt issuance cost	(205		)	—		—			—		—		(205		)
Payments for derivative contracts	(1,708		)	—		—			—		—		(1,708		)
Distributions to members and affiliates	(23,801		)	—		—			—		—		(23,801		)
Net cash flows used in financing activities	(8,514		)	—		—			—		—		(8,514		)
Net cash flows provided by discontinued operations	(17,154		)	—		49,678			16		—		32,540
Net increase in cash and cash equivalents	4,289			—		1,242			16		—		5,547
Cash and cash equivalents at beginning of period	1,237			1		(1,389		)	227		—		76
Cash and cash equivalents at end of period	$	5,526		$	1	$	(147	)	$	243	$	—	$	5,623

28

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." These factors include but are not limited to:

• Drilling and geological/exploration risks;

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

• Volatility or declines (including sustained declines) in 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 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.

29

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.   

Results for the three months endedMarch 31, 2015, included the following:

• revenues, excluding the impact of commodity risk management gains (losses), were $29.5 million for the three months endedMarch 31, 2015, compared to $55.2 million for the three months endedMarch 31, 2014;

• commodity risk management gains were $22.6 million for the three months endedMarch 31, 2015, compared to commodity risk management losses of $10.0 million for the three months endedMarch 31, 2014;

• impairment charge of $68.3 million for the three months endedMarch 31, 2015, compared to no impairment charge for the three months endedMarch 31, 2014;

• operating losses were $53.3 million for the three months endedMarch 31, 2015, compared to operating losses of $3.8 million for the three months endedMarch 31, 2014;

• average daily production was 80 MMcfe/d for the three months endedMarch 31, 2015, compared to 72 MMcfe/d for the three months endedMarch 31, 2014; and

• capital expenditures were $27.0 million for the three months endedMarch 31, 2015, compared to $40.8 million for the three months endedMarch 31, 2014.

Impairment

We recorded an impairment charge of $68.3 million during the three months endedMarch 31, 2015 related to certain proved properties in our Mid-Continent, East Texas and Permian regions primarily due to lower commodity prices. During the three months endedMarch 31, 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. Further and/or sustained declines in oil and natural gas prices from the March 31, 2015 prices 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.

30

Subsequent Events

On April 1, 2015, the borrowing base under our credit facility was decreased from $320 million to $270 million as part of our regularly scheduled semi-annual redetermination by our commercial lenders. Our next borrowing base redetermination is scheduled for October 1, 2015.

31

RESULTS OF OPERATIONS

Summary of Consolidated Operating Results

Below is a table of a summary of our consolidated operating results for the three months endedMarch 31, 2015and 2014.

		Three Months Ended March 31,
		2015			2014
	($ in thousands)
Revenues:
Oil and condensate		$	13,329		$	27,134
Natural gas		8,574			14,599
NGLs		5,119			11,466
Sulfur		2,491			1,885
Commodity risk management gains (losses), net		22,600			(10,033		)
Other revenue		9			152
Total revenue		52,122			45,203
Costs and expenses:
Operations and maintenance		10,082			11,498
Taxes other than income		1,388			3,791
General and administrative		10,989			13,290
Impairment		68,344			—
Depreciation, depletion and amortization		14,645			20,406
Total costs and expenses		105,448			48,985
Operating loss		(53,326		)	(3,782		)
Other (expense) income:
Interest expense, net		(2,318		)	(4,754		)
Interest rate risk management losses, net		(3,066		)	(290		)
Loss on short-term investments		(2,004		)	—
Other income, net		2,135			1
Total other (expense) income		(5,253		)	(5,043		)
Loss before income taxes		(58,579		)	(8,825		)
Income tax benefit		(826		)	(865		)
Loss from continuing operations		(57,753		)	(7,960		)
Discontinued operations, net of tax		(966		)	(10,603		)
Net loss		$	(58,719	)	$	(18,563	)
Adjusted EBITDA(a)		$	25,549		$	26,096

________________________

(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.

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	Three Months Ended March 31,
	2015		2014
Realized average prices:
Oil and condensate (per Bbl)	$	38.17	$	85.56
Natural gas (per Mcf)	$	2.76	$	4.95
NGLs (per Bbl)	$	15.63	$	41.90
Sulfur (per Long ton)	$	104.44	$	77.05
Production volumes:
Oil and condensate (Bbl)	349,221		317,126
Natural gas (Mcf)	3,110,234		2,952,149
NGLs (Bbl)	327,481		273,673
Total (Mcfe)	7,170,446		6,496,943
Sulfur (Long ton)	23,847		24,461
Capital expenditures ($ in thousands)	$	27,003	$	40,835

Production Revenues. For the three months endedMarch 31, 2015, our production revenues, which exclude commodity risk management gains (losses), decreased by $25.7 million as compared to the three months endedMarch 31, 2014.  The decrease in revenues for the three months endedMarch 31, 2015 compared to the three months endedMarch 31, 2014 was due to lower realized oil, natural gas and NGL prices and higher corresponding volumes, partially offset by lower sulfur volumes and higher sulfur prices.

Production volumes during the three months endedMarch 31, 2015 were positively impacted by strong production from both operated and non-operated wells drilled since March 31, 2014.

Commodity Risk Management Gains (Losses), net. During the three months endedMarch 31, 2015, gains in our commodity derivative portfolio increased by $32.6 million as compared to the three months endedMarch 31, 2014. During the three months endedMarch 31, 2015, our gains due to the change in the mark-to-market value of our derivative contracts increased $15.1 million as compared to the three months endedMarch 31, 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 months endedMarch 31, 2015 increased by $17.5 million compared to the three months endedMarch 31, 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.

Operating Expenses. Operating expenses decreased $1.4 million for the three months endedMarch 31, 2015 as compared to the three months endedMarch 31, 2014.  The decrease was primarily due to decreased plant operating expenses and lower expenses related to workovers, offset in part by increases due to additional wells drilled.

Taxes Other Than Income. Taxes other than income, which includes severance and ad valorem taxes, for the three months endedMarch 31, 2015, decreased by $2.4 million as compared to the three months endedMarch 31, 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 $2.3 million for the three months endedMarch 31, 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.

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Depletion, Depreciation and Amortization. Depletion, depreciation and amortization expense decreased by $5.8 million for the three months endedMarch 31, 2015 as compared to the same period in the prior year.  The decrease was primarily a result of the impairment charges recorded during 2014.

Impairment. During the three months endedMarch 31, 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. During the three months endedMarch 31, 2014, we did not record an impairment charge.

Total Other (Expense) Income.  Total other (expense) income primarily consists of distributions from Regency related to its common units that we hold as a short-term investment, gains and losses from our interest rate swaps and interest expense related to our senior secured credit facility and our Senior Notes. During the three months endedMarch 31, 2015, we received total distributions of $2.1 million on the Regency common units. Our interest rate risk management losses increased by $2.8 million during the three months endedMarch 31, 2015 as compared to the three months endedMarch 31, 2014. These increases were due to decreases in the forward interest rate curve.

Interest Expense. Interest expense decreased by $2.4 million during the three months endedMarch 31, 2015 as compared to the three months endedMarch 31, 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.

Loss on Short-Term Investments. During the three months endedMarch 31, 2015, we incurred a loss on short-term investments related to the Regency common units we received as partial consideration for the Midstream Business Contribution. This loss is a result of losses incurred on the sales of the Regency common units.

Income Tax Benefit Provision. Income tax provision 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. 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 $13.8 million for the three months endedMarch 31, 2015 as compared to the three months endedMarch 31, 2014. The decrease in capital expenditures was primarily due to decreased spending on our drilling program.

During the three months endedMarch 31, 2015, we drilled and completed four gross (2.7 net) operated wells and participated in sixteen gross (0.5 net) non-operated wells in the Mid-Continent region. Additionally, during the three months ended March 31, 2015, we conducted one gross (1.0 net) capital workover.

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Adjusted EBITDA

Adjusted EBITDA, as defined under "—Liquidity and Capital Resources — Non-GAAP Financial Measures," from continuing operations decreased by $0.5 million from $26.1 million for the three months endedMarch 31, 2014 to $25.5 million for the three months endedMarch 31, 2015. The following table presents the changes in operations impacting Adjusted EBITDA:

	Three Months Ended March 31,
	2015		2014			Change
	($ in thousands)
Revenues (a)	$	29,648	$	55,230		$	(25,582	)
Commodity derivative settlements	14,370		(3,138		)	17,508
Operating expenses	11,470		15,289			(3,819		)
General and administrative expenses (b)	9,133		10,707			(1,574		)
Distributions received from Regency	2,134		—			2,134
Adjusted EBITDA (c)	$	25,549	$	26,096		$	(547	)

_________________________

(a) Excludes the impact of imbalances.

(b) Excludes non-cash compensation charges related to our long-term incentive program.

(c) 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.

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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 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. During 2014, we sold 1,852,202 Regency common units for net proceeds of $50.1 million and during the first quarter of 2015, we sold an additional 3,205,033 Regency common units for net proceeds of $74.9 million. During April 2015, we sold an additional 671,059 Regency common units for net proceeds of $15.3 million and as of April 28, 2015, we held 2,517,565 Regency common units (valued at approximately $56.3 million (based on the closing price of Regency common units on April 28, 2015).

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. 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, sales of Regency common units or borrowings under our Credit Agreement (as defined below) 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, sales of Regency common units and the timing of these offerings and sales will depend upon various factors, including prevailing market conditions and our financial condition. On April 1, 2015, the borrowing base under our credit facility was decreased from $320 million to $270 million as part of our regularly scheduled semi-annual redetermination by our commercial lenders. As of April 28, 2015, our total liquidity was approximately $164.3 million, comprised of approximately $108 million of availability under our senior secured credit facility and approximately 2.5 million Regency common units valued at approximately $56.3 million.

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 $47.6 million, of which we expect approximately $30.0 million to be categorized as maintenance capital expenditures and $17.6 million to be categorized as growth capital expenditures.

Our capital expenditures were approximately $27.0 million for the three months endedMarch 31, 2015, of which $10.3 million was related to maintenance capital expenditures and $16.7 million was related to growth capital expenditures.

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In order to lower sulfur dioxide ("SO₂") emissions from our Big Escambia Creek processing facility in Alabama, 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 processing 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 March 31, 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 processing 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 2017 at a cost of approximately $6 million net to our interest. The facility will require further upgrades to repair or replace certain sulfur recovery unit components beyond 2017.

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, which was formerly referred to as the upstream component of the borrowing base. The decline in oil and natural gas prices during the fourth quarter of 2014 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.

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

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 July 1, 2014, only $51.1 million face amount of the Senior Notes remained outstanding.

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

Debt Covenants

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The Credit Agreement requires us to maintain certain leverage and current ratios. As of March 31, 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 March 31, 2015:

	Debt Covenant	Actual Covenant Ratio as of March 31, 2015
Total leverage ratio	< 4.0x	1.8
Current ratio	> 1.0x	5.8

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 March 31, 2015, we were in compliance with the covenants under our Senior Notes indenture.

For a further discussion of the Credit Agreement and 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 repurchases may be made 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, and intend to fund any future repurchases, with the proceeds of our sales of Regency common units. The use of these sales proceeds is expressly permitted under our Credit Agreement. As of March 31, 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.

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 March 31, 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 months endedMarch 31, 2015. The last time units were issued under this program was during 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 will be paid on May 15, 2015.

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Working Capital

Working capital is the amount by which current assets exceed current liabilities. As of March 31, 2015, working capital was a positive $117.1 million as compared to a positive $189.6 million as of December 31, 2014.

The net decrease in working capital of $72.5 million from December 31, 2014 to March 31, 2015, resulted primarily from the following factors:

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

• short-term investments decreased by $80.5 million as a result of sales of Regency common units and the downward adjustment of the carrying value of the remaining units we hold;

• trade accounts receivable decreased by $6.7 million, primarily from the timing of the receipt of payments;

• prepayment and other current assets increased by $1.9 million primarily due to the payment of insurance premiums;

• accounts payable decreased by $11.1 million primarily as a result of the timing of payments of unbilled expenditures;

• risk management net working capital balance increased by $2.6 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

• accrued liabilities decreased by $0.5 million primarily as a result of lower interest and compensation accruals.

Cash Flows for the Three Months EndedMarch 31, 2015, Compared to the Three Months EndedMarch 31, 2014

Cash Flow from Operating Activities. Cash flows from operating activities decreased $9.1 million during the three months endedMarch 31, 2015 as compared to the three months endedMarch 31, 2014.

The decrease was driven by the:

• Timing of cash payments and cash receipts; and

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

Cash Flows from Investing Activities. Cash flows provided by investing activities increased $92.0 million during the three months endedMarch 31, 2015 as compared to the three months endedMarch 31, 2014. The increase was due to proceeds from the sale of Regency common units and lower capital expenditures.

Cash Flows from Financing Activities. Cash flows used in financing activities increased $56.3 million during the three months endedMarch 31, 2015 as compared to the three months endedMarch 31, 2014.

The increase was driven by:

• Increase in net repayments of long-term debt of $67.8 million during the three months endedMarch 31, 2015 as compared to the same period in 2014; and

• Increased repurchases of common units of $2.7 million during the three months endedMarch 31, 2015 as compared to the same period in 2014.

This increase was partially offset by:

• Decreased distributions of $13.2 million during the three months endedMarch 31, 2015 as compared to the same period in 2014.

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• Proceeds from derivative contracts decreased by $0.8 million during the three months endedMarch 31, 2015 as compared to the same period in 2014; and

• Decreased debt issuance costs of $0.2 million during the three months endedMarch 31, 2015 as compared to the same period in 2014.

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. Of course, the inverse will be true in the event that the hedged price is less than the current futures price.

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

Off-Balance Sheet Obligations

We had no off-balance sheet transactions or obligations as of March 31, 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 non-GAAP financial measure, which does not comply 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 expense, non-recurring; other non-cash operating and general and administrative expenses, including non-cash compensation related to our equity-based compensation program; mark-to-market (gains) losses on commodity and interest rate risk management related instruments; gains (losses) on discontinued operations; and other (income) expense. 

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 unrealized derivative gains (losses), a non-cash, mark-to-market benefit (charge), which represents the change in fair market value of our executed derivative instruments and is independent of our assets’ performance or cash flow generating ability, we believe Adjusted EBITDA provides additional information of 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, operating income, cash flows provided by operating activities or any other measure of financial performance 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 March 31,
		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		$	14,727		$	23,803
Add (deduct):
Discontinued operations, net of tax		(966		)	(10,603		)
Depreciation, depletion, amortization and impairment		(82,989		)	(20,406		)
Amortization of debt issuance costs		(264		)	(659		)
Gain (loss) from risk management activities, net		19,534			(10,323		)
Derivative settlements - operating		(14,370		)	3,138
Other		(969		)	(2,734		)
Loss on short-term investments		(2,004		)	—
Accounts receivable and other current assets		(2,186		)	17,704
Accounts payable and accrued liabilities		9,990			(19,431		)
Other assets and liabilities		778			948
Net loss		(58,719		)	(18,563		)
Add (deduct):
Interest expense, net		3,257			6,461
Depreciation, depletion, amortization and impairment		82,989			20,406
Income tax benefit		(826		)	(865		)
EBITDA		26,701			7,439
Add (deduct):
(Gain) loss from risk management activities, net		(19,534		)	10,323
Total derivative settlements		13,430			(4,846		)
Restricted unit compensation expense		1,856			2,583
Non-cash mark-to-market imbalances		126			(6		)
Discontinued operations, net of tax		966			10,603
Loss on short-term investments		2,004			—
ADJUSTED EBITDA		$	25,549		$	26,096

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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 ("hedges"), 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 March 31, 2015, our commodity hedge portfolio totaled a net asset position of $105.3 million, consisting of assets aggregating $105.3 million and no 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 various interest rate swaps that eliminate interest rate variability by effectively 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.

As of March 31, 2015, the fair value liability of these interest rate contracts totaled approximately $7.9 million. For additional information about our interest rate swaps and related fair values, see Notes 10 and 11 to our unaudited condensed consolidated financial statements.

As of March 31, 2015, the notional amount of our interest rate swap was in excess of the outstanding borrowings under our Credit Agreement by approximately $13.0 million. Absent any change to our near term borrowing expectations, we may evaluate lowering the notional amount.

43

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 March 31, 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.

44

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.

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. There have been no material changes in our risk factors from those described in the 2014 10-K.

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 endedMarch 31, 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
January 1, 2015 - January 31, 2015	1,171,584	$	2.24	1,171,584	78,227,181
February 1, 2015 - February 28, 2015	—	$	—	—	78,227,181
March 1, 2015 - March 31, 2015	16,602	$	2.39	—	78,227,181
Total	1,188,186	$	2.24	1,171,584	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.

45

Item 6. Exhibits

Exhibit Number	Description
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	Separation and Release Agreement, effective February 24, 2015 between Steven G. Hendrickson and Eagle Rock Energy G&P, LLC (incorporated by reference to Exhibit 10.1 of the registrant's current report on Form 8-K filed with the SEC on February 27, 2015).
10.2+	Eagle Rock Energy G&P, LLC 2015 Short Term Incentive Bonus Plan (incorporated by reference to Exhibit 10.1 of the registrant's current report on Form 8-K filed with the SEC on February 23, 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

+ Portions of this exhibit have been omitted pursuant to a request for confidential treatment.

* Filed herewith.

** Furnished herewith.

46

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 May 1, 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

47

Index to Exhibits

Exhibit Number	Description
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	Separation and Release Agreement, effective February 24, 2015 between Steven G. Hendrickson and Eagle Rock Energy G&P, LLC (incorporated by reference to Exhibit 10.1 of the registrant's current report on Form 8-K filed with the Commission on February 27, 2015).
10.2+	Eagle Rock Energy G&P, LLC 2015 Short Term Incentive Bonus Plan (incorporated by reference to Exhibit 10.1 of the registrant's current report on Form 8-K filed with the SEC on February 23, 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

+ Portions of this exhibit have been omitted pursuant to a request for confidential treatment.    

* Filed herewith.

** Furnished herewith.

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:	May 1, 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:	May 1, 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 March 31, 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:	May 1, 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 March 31, 2015 as filed with the Securities and Exchange Commission on the date hereof (the Report), I, Robert M. Haines, 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:	May 1, 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

Property, Plant and Equipment Property, Plant and Equipment (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment - Gross	$ 888,748	$ 930,896
Accumulated depreciation, depletion and amortization	(456,457)	(442,908)
Property, Plant and Equipment — Net	432,291	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	13,583	13,234
Proved Oil and Gas Properties [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment - Gross	863,565	905,622
Unproved Oil and Gas Properties [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment - Gross	7,066	7,512
Asset under Construction [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment - Gross	$ 1,201	$ 1,195

XML

Risk Management Activities Schedule of Derivative Instruments in the Statement of Financial Position (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Derivatives, Fair Value [Line Items]
Derivative assets, Current	$ 47,392	$ 44,805
Derivative assets, Noncurrent	50,007	46,490
Derivative Assets	97,399	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	(3,220)	(3,165)
Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member] | Long-term Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Liabilities, Noncurrent	(4,712)	(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	(11)
Derivative assets, Current	50,624	47,971
Commodity Contract [Member] | Not Designated as Hedging Instrument [Member] | Long-term Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets, Noncurrent	54,718	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 assets, Noncurrent	$ 0	$ 0

XML

Long Term Debt Narrative (Details) (USD $)	3 Months Ended
	Mar. 31, 2015 Rate	Dec. 31, 2014	Oct. 10, 2014	Apr. 01, 2015
Debt Instrument [Line Items]
Letters of Credit Outstanding, Amount	$ 0
Revolving credit facility:	162,000,000	212,600,000
Line of Credit Facility, Commitment Fee Percentage	0.50%
Letters of Credit Sub-limit	50,000,000
Line of Credit Facility, Remaining Borrowing Capacity	158,000,000
Line of Credit Facility, Current Borrowing Capacity			320,000,000
Debt Instrument, Covenant Compliance	As of March 31, 2015, the Partnership was in compliance with the financial covenants under the Credit Agreement.
Line of Credit Facility, Maximum Borrowing Capacity			1,200,000,000
8 3/8% senior notes due 2019	51,120,000	51,120,000
Subsequent Event [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Current Borrowing Capacity				$ 270,000,000

XML

Subsidiary Guarantors Subsidiary Guarantor Condensed Consolidating Statements of Cash Flows (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Subsidiary Guarantors [Line Items]
Net cash flows provided by operating activities	$ 14,727	$ 23,803
Additions to property, plant and equipment	(28,055)	(42,282)
Proceeds from Sale of Short-term Investments	77,755	0
Net cash provided by (used in) investing activities	49,700	(42,282)
Proceeds from long-term debt	45,300	144,250
Repayment of long-term debt	(95,900)	(127,050)
Payment of debt issuance costs	0	205
Proceeds from derivative contracts	(940)	(1,708)
Repurchase of common units	(2,662)	0
Distributions to members and affiliates	(10,565)	(23,801)
Net cash used in financing activities	(64,767)	(8,514)
Net Cash Provided by (Used in) Discontinued Operations	(966)	32,540
Net increase in cash and cash equivalents	(1,306)	5,547
CASH AND CASH EQUIVALENTS—Beginning of period	1,343	76
CASH AND CASH EQUIVALENTS—End of period	37	5,623
Parent Company [Member]
Subsidiary Guarantors [Line Items]
Net cash flows provided by operating activities	(14,013)	30,293
Additions to property, plant and equipment	(334)	(336)
Proceeds from Sale of Short-term Investments	77,755
Net cash provided by (used in) investing activities	77,421	(336)
Proceeds from long-term debt	45,300	144,250
Repayment of long-term debt	(95,900)	(127,050)
Payment of debt issuance costs		205
Proceeds from derivative contracts	(940)	(1,708)
Repurchase of common units	(2,662)
Distributions to members and affiliates	(10,565)	(23,801)
Net cash used in financing activities	(64,767)	(8,514)
Net Cash Provided by (Used in) Discontinued Operations	(2)	(17,154)
Net increase in cash and cash equivalents	(1,361)	4,289
CASH AND CASH EQUIVALENTS—Beginning of period	2,686	1,237
CASH AND CASH EQUIVALENTS—End of period	1,325	5,526
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
Proceeds from derivative contracts	0	0
Repurchase of common units	0
Distributions to members and affiliates	0	0
Net cash used in 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	28,740	(6,490)
Additions to property, plant and equipment	(27,721)	(41,946)
Proceeds from Sale of Short-term Investments	0
Net cash provided by (used in) investing activities	(27,721)	(41,946)
Proceeds from long-term debt	0	0
Repayment of long-term debt	0	0
Payment of debt issuance costs		0
Proceeds from derivative contracts	0	0
Repurchase of common units	0
Distributions to members and affiliates	0	0
Net cash used in financing activities	0	0
Net Cash Provided by (Used in) Discontinued Operations	(964)	49,678
Net increase in cash and cash equivalents	55	1,242
CASH AND CASH EQUIVALENTS—Beginning of period	(1,344)	(1,389)
CASH AND CASH EQUIVALENTS—End of period	(1,289)	(147)
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
Proceeds from derivative contracts		0
Distributions to members and affiliates		0
Net cash used in financing activities		0
Net Cash Provided by (Used in) Discontinued Operations		16
Net increase in cash and cash equivalents		16
CASH AND CASH EQUIVALENTS—Beginning of period		227
CASH AND CASH EQUIVALENTS—End of period		243
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
Proceeds from derivative contracts	0	0
Repurchase of common units	0
Distributions to members and affiliates	0	0
Net cash used in 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

XML

Risk Management Activities Schedule of Derivative Instruments, Gain (Loss) in Statement of Financial Performance (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Derivative Instruments, Gain (Loss) [Line Items]
Interest rate risk management losses, net	$ (3,066)	$ (290)
Commodity risk management (losses) gains	22,600	(10,033)
Derivative Instruments, Gain (Loss) Recognized in Income, Net	19,534	(16,221)
Interest Rate Contract [Member] | Other Expense [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Interest rate risk management losses, net	(3,066)	(290)
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	22,600	(10,033)
Commodity Contract [Member] | Discontinued Operations [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Commodity risk management (losses) gains	0	(4,911)
Commodity Contract [Member] | Forward Contracts [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Commodity risk management (losses) gains	$ 0	$ (987)

XML

Long Term Debt Long-Term Debt (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Revolving credit facility:	$ 162,000	$ 212,600
8 3/8% senior notes due 2019	51,120	51,120
Unamortized bond discount senior notes due 2019	(358)	(377)
Senior Notes	50,762	50,743
LONG-TERM DEBT	$ 212,762	$ 263,343

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

3 Months Ended

Mar. 31, 2015

Fair Value Disclosures [Abstract]

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

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

	As of March 31, 2015
	Level 1		Level 2			Level 3		Netting (a)			Total
	($ in thousands)
Assets:
Crude oil derivatives	$	—	$	84,171		$	—	$	—		$	84,171
Natural gas derivatives	—		21,049			—		—			21,049
NGL derivatives	—		122			—		(11		)	111
Interest rate swaps	—		—			—		(7,932		)	(7,932		)
Equity investments	72,924		—			—		—			72,924
Total	$	72,924	$	105,342		$	—	$	(7,943	)	$	170,323
Liabilities:
NGL derivatives	—		(11		)	—		11			—
Interest rate swaps	—		(7,932		)	—		7,932			—
Total	$	—	$	(7,943	)	$	—	$	7,943		$	—

____________________________

(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 three months endedMarch 31, 2015:

	Three Months Ended March 31,
	2015		Level 1		Level 2		Level 3		Total Losses
	($ in thousands)
Proved properties	$	44,658	$	—	$	—	$	44,658	$	68,344

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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, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Property, Plant, and Equipment, Fair Value Disclosure	$ 44,658
Impairment of Long-Lived Assets Held-for-use	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
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
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

XML

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

3 Months Ended

Mar. 31, 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 months endedMarch 31, 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 2014 annual report on Form 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. These common units have a readily determinable fair value, are being classified as available-for-sale equity securities and are recorded as short-term investments on the 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 from Regency as a result of holding these common units are recorded as other income on the unaudited condensed consolidated statements of operations.

For the three months endedMarch 31, 2015, the Partnership received and recorded distributions from Regency of $2.1 million, recorded a $2.0 million loss as a result of the sale of Regency common units and recorded a $3.6 million unrealized loss resulting from the decrease in the fair value, which the Partnership deemed to be temporary, of the remaining Regency common units. As of March 31, 2015, the Partnership held 3,188,624 Regency common units, which did not include sales of 150,000 Regency common units that had not settled as of March 31, 2015 and for which a receivable of $3.4 million was recorded as part of accounts receivable in the unaudited condensed consolidated balance sheets.

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 $0.4 million and $0.3 million as of March 31, 2015 and December 31, 2014, respectfully.

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 March 31, 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 Distributions (Details) (USD $)	3 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Dividends Payable [Line Items]
Common Stock, Dividends, Per Share, Cash Paid	$ 0.07	$ 0.07
Distribution Made to Limited Partner, Date of Record	May 08, 2015	Feb. 06, 2015
Distribution Made to Limited Partner, Distribution Date	May 15, 2015	Feb. 13, 2015

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Intangible Assets Intangible Assets (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Acquired Finite-Lived Intangible Assets [Line Items]
Intangible Assets — Net	$ 3,023	$ 3,072
Use Rights [Member]
Acquired Finite-Lived Intangible Assets [Line Items]
Rights-of-way and easements—at cost	3,920	3,920
Less: accumulated amortization	$ (897)	$ (848)

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Subsidiary Guarantors Subsidiary Guarantors (Tables)

3 Months Ended

Mar. 31, 2015

SUBSIDIARY GUARANTORS [Abstract]

Subsidiary Guarantor Consolidating Balance Sheet [Table Text Block]

Condensed Consolidating Balance Sheet

March 31, 2015

	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Consolidating Entries			Total
	($ in thousands)
ASSETS:
Accounts receivable – related parties	$	865,930		$	—	$	—		$	(865,930	)	$	—
Other current assets	129,008			1		36,039			—			165,048
Total property, plant and equipment, net	1,531			—		430,760			—			432,291
Investment in subsidiaries	(486,135		)	—		—			486,135			—
Total other long-term assets	55,072			—		4,826			—			59,898
Total assets	$	565,406		$	1	$	471,625		$	(379,795	)	$	657,237
LIABILITIES AND EQUITY:
Accounts payable – related parties	$	—		$	—	$	865,930		$	(865,930	)	$	—
Other current liabilities	37,497			—		10,435			—			47,932
Other long-term liabilities	370			—		81,396			—			81,766
Long-term debt	212,762			—		—			—			212,762
Equity	314,777			1		(486,136		)	486,135			314,777
Total liabilities and equity	$	565,406		$	1	$	471,625		$	(379,795	)	$	657,237

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 EndedMarch 31, 2015

	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Consolidating Entries			Total
	($ in thousands)
Total revenues	$	21,227		$	—	$	30,895		$	—		$	52,122
Operations and maintenance	—			—		10,082			—			10,082
Taxes other than income	—			—		1,388			—			1,388
General and administrative	2,082			—		8,907			—			10,989
Depreciation, depletion and amortization	136			—		14,509			—			14,645
Impairment	—			—		68,344			—			68,344
Income (loss) from operations	19,009			—		(72,335		)	—			(53,326		)
Interest expense, net	(2,318		)	—		—			—			(2,318		)
Other non-operating income	4,257			—		2,264			(4,386		)	2,135
Other non-operating expense	(6,459		)	—		(2,997		)	4,386			(5,070		)
Income (loss) before income taxes	14,489			—		(73,068		)	—			(58,579		)
Income tax expense (benefit)	96			—		(922		)	—			(826		)
Equity in earnings of subsidiaries	(73,110		)	—		—			73,110			—
Loss from continuing operations	(58,717		)	—		(72,146		)	73,110			(57,753		)
Discontinued operations, net of tax	(2		)	—		(964		)	—			(966		)
Net loss	$	(58,719	)	$	—	$	(73,110	)	$	73,110		$	(58,719	)

Unaudited Condensed Consolidating Statement of Operations

For the Three Months EndedMarch 31, 2014

	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-Guarantor Investments			Consolidating Entries			Total
	($ in thousands)
Total revenues	$	(10,033	)	$	—	$	55,236		$	—		$	—		$	45,203
Operations and maintenance	—			—		11,498			—			—			11,498
Taxes other than income	—			—		3,791			—			—			3,791
General and administrative	2,897			—		10,393			—			—			13,290
Depreciation, depletion and amortization	53			—		20,353			—			—			20,406
Loss from operations	(12,983		)	—		9,201			—			—			(3,782		)
Interest expense, net	(4,754		)	—		—			—			—			(4,754		)
Other non-operating income	2,221			—		2,301			—			(4,522		)	—
Other non-operating expense	(1,716		)	—		(3,095		)	—			4,522			(289		)
Loss before income taxes	(17,232		)	—		8,407			—			—			(8,825		)
Income tax benefit	(267		)	—		(598		)	—			—			(865		)
Equity in earnings of subsidiaries	18,634			—		—			—			(18,634		)	—
Loss from continuing operations	1,669			—		9,005			—			(18,634		)	(7,960		)
Discontinued operations, net of tax	(20,232		)	—		9,636			(7		)	—			(10,603		)
Net loss	$	(18,563	)	$	—	$	18,641		$	(7	)	$	(18,634	)	$	(18,563	)

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

Unaudited Condensed Consolidating Statement of Cash Flows

For the Three Months EndedMarch 31, 2015

	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Consolidating Entries		Total
	($ in thousands)
Net cash flows provided by operating activities	$	(14,013	)	$	—	$	28,740		$	—	$	14,727
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment	(334		)	—		(27,721		)	—		(28,055		)
Proceeds from sale of short-term investments	77,755			—		—			—		77,755
Net cash flows provided by investing activities	77,421			—		(27,721		)	—		49,700
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	45,300			—		—			—		45,300
Repayment of long-term debt	(95,900		)	—		—			—		(95,900		)
Payments for derivative contracts	(940		)	—		—			—		(940		)
Repurchase of common units	(2,662		)	—		—			—		(2,662		)
Distributions to members and affiliates	(10,565		)	—		—			—		(10,565		)
Net cash flows used in financing activities	(64,767		)	—		—			—		(64,767		)
Net cash flows used in discontinued operations	(2		)	—		(964		)	—		(966		)
Net decrease in cash and cash equivalents	(1,361		)	—		55			—		(1,306		)
Cash and cash equivalents at beginning of period	2,686			1		(1,344		)	—		1,343
Cash and cash equivalents at end of period	$	1,325		$	1	$	(1,289	)	$	—	$	37

Unaudited Condensed Consolidating Statement of Cash Flows

For the Three Months EndedMarch 31, 2014

	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-Guarantor Investments		Consolidating Entries		Total
	($ in thousands)
Net cash flows provided by operating activities	$	30,293		$	—	$	(6,490	)	$	—	$	—	$	23,803
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment	(336		)	—		(41,946		)	—		—		(42,282		)
Net cash flows used in investing activities	(336		)	—		(41,946		)	—		—		(42,282		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	144,250			—		—			—		—		144,250
Repayment of long-term debt	(127,050		)	—		—			—		—		(127,050		)
Payment of debt issuance cost	(205		)	—		—			—		—		(205		)
Payments for derivative contracts	(1,708		)	—		—			—		—		(1,708		)
Distributions to members and affiliates	(23,801		)	—		—			—		—		(23,801		)
Net cash flows used in financing activities	(8,514		)	—		—			—		—		(8,514		)
Net cash flows provided by discontinued operations	(17,154		)	—		49,678			16		—		32,540
Net increase in cash and cash equivalents	4,289			—		1,242			16		—		5,547
Cash and cash equivalents at beginning of period	1,237			1		(1,389		)	227		—		76
Cash and cash equivalents at end of period	$	5,526		$	1	$	(147	)	$	243	$	—	$	5,623

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Risk Management Activities Interest Rate Derivatives (Details) (Effective Date, 12/31/2014 [Member], Interest Rate Swap [Member], USD $)	3 Months Ended
	Mar. 31, 2015
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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Divestiture Related Activities Divestiture Related Activities - Restructuring Charges (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Restructuring Cost and Reserve [Line Items]
Restructuring and Related Cost, Incurred Cost	$ 843
Restructuring Reserve, Current	2,168	1,325
One-time Termination Benefits [Member]
Restructuring Cost and Reserve [Line Items]
Increase (Decrease) in Restructuring Reserve		3,975
Restructuring and Related Cost, Incurred Cost	(183)
Restructuring Reserve, Current	652	835
Facility Closing [Member]
Restructuring Cost and Reserve [Line Items]
Increase (Decrease) in Restructuring Reserve		563
Restructuring and Related Cost, Incurred Cost	1,026
Restructuring Reserve, Current	$ 1,516	$ 490

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Income Taxes Schedule of Income Tax Expense (Benefit) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
INCOME TAX BENEFIT	$ (826)	$ (865)

XML

Long Term Debt Debt Covenants (Details)	Mar. 31, 2015
Total Leverage Ratio [Member]
Schedule of Debt Covenants [Line Items]
Line of Credit Facility, Covenant Ratio	1.8
Current Ratio [Member]
Schedule of Debt Covenants [Line Items]
Line of Credit Facility, Covenant Ratio	5.8
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

Summary of Significant Accounting Policies

3 Months Ended

Mar. 31, 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 months endedMarch 31, 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 2014 annual report on Form 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. These common units have a readily determinable fair value, are being classified as available-for-sale equity securities and are recorded as short-term investments on the 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 from Regency as a result of holding these common units are recorded as other income on the unaudited condensed consolidated statements of operations.

For the three months endedMarch 31, 2015, the Partnership received and recorded distributions from Regency of $2.1 million, recorded a $2.0 million loss as a result of the sale of Regency common units and recorded a $3.6 million unrealized loss resulting from the decrease in the fair value, which the Partnership deemed to be temporary, of the remaining Regency common units. As of March 31, 2015, the Partnership held 3,188,624 Regency common units, which did not include sales of 150,000 Regency common units that had not settled as of March 31, 2015 and for which a receivable of $3.4 million was recorded as part of accounts receivable in the unaudited condensed consolidated balance sheets.

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 $0.4 million and $0.3 million as of March 31, 2015 and December 31, 2014, respectfully.

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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Equity Based Compensation Share-based Compensation Rollforward (Details) (USD $)	3 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
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	2,121,963	2,419,750
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	23,000
Vesting of restricted units	60,700
Forfeited in Period	(260,087)
Unvested Restricted Units Outstanding - Ending Balance	2,121,963
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	$ 2.37
Vested in Period, Weighted Average Grant Date Fair Value	$ 4.46
Forfeitures in Period, Weighted Average Grant Price	$ 6.69
Weighted Average Grant Date Fair Value - Ending	$ 5.99
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
Forfeited in Period	(123,175)
Unvested Restricted Units Outstanding - Ending Balance	524,613
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
Forfeitures in Period, Weighted Average Grant Price	$ 3.59
Weighted Average Grant Date Fair Value - Ending	$ 3.64

XML

Intangible Assets Amortization and Impairment (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Amortization	$ 49	$ 49

XML

Long Term Debt Long-Term Debt (Tables)

3 Months Ended

Mar. 31, 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:

	March 31, 2015			December 31, 2014
	($ in thousands)
Revolving credit facility:	$	162,000		$	212,600
Senior Notes:
8.375% Senior Notes due 2019	51,120			51,120
Unamortized bond discount	(358		)	(377		)
Total Senior Notes	50,762			50,743
Total long-term debt	$	212,762		$	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 March 31, 2015:

	Debt Covenant	Actual Covenant Ratio as of March 31, 2015
Maximum total leverage ratio	4.0	1.8
Minimum current ratio	1.0	5.8

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Intangible Assets Intangible Assets (Tables)

3 Months Ended

Mar. 31, 2015

Goodwill and Intangible Assets Disclosure [Abstract]

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

Intangible assets consisted of the following:

	March 31, 2015			December 31, 2014
	($ in thousands)
Rights-of-way and easements—at cost	$	3,920		$	3,920
Less: accumulated amortization	(897		)	(848		)
Net intangible assets	$	3,023		$	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 March 31,
		2015		2014
	($ in thousands)
Amortization		$	49	$	49

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 March 31, 2015 is as follows (in thousands):

Year ending December 31,
2015	$	147
2016	$	196
2017	$	196
2018	$	196
2019	$	196
Thereafter	$	2,092

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Fair Value of Financial Instruments Fair Value, Assets and Liabilities Measured on a Recurring Basis (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2015		Dec. 31, 2014
Assets:
Derivative Assets	$ 97,399		$ 91,295
Short-term investments	72,924		153,448
Liabilities:
Derivative Liabilities	0		0
Fair Value, Measurements, Recurring [Member]
Assets:
Derivative Assets	170,323		244,743
Derivative Asset, Fair Value, Gross Liability	(7,943)	[1]	(5,806)	[1]
Liabilities:
Derivative Liabilities	0		0
Derivative Liability, Fair Value, Gross Asset	7,943	[1]	5,806	[1]
Fair Value, Measurements, Recurring [Member] | Crude Oil Contract [Member]
Assets:
Derivative Assets	84,171		78,516
Derivative Asset, Fair Value, Gross Liability	0	[1]	0	[1]
Fair Value, Measurements, Recurring [Member] | Natural Gas Contract [Member]
Assets:
Derivative Assets	21,049		18,585
Derivative Asset, Fair Value, Gross Liability	0	[1]	0	[1]
Fair Value, Measurements, Recurring [Member] | Natural Gas Liquids Contract [Member]
Assets:
Derivative Assets	111
Derivative Asset, Fair Value, Gross Liability	(11)	[1]
Liabilities:
Derivative Liabilities	0
Derivative Liability, Fair Value, Gross Asset	11	[1]
Fair Value, Measurements, Recurring [Member] | Interest Rate Contract [Member]
Assets:
Derivative Assets	7,932		5,806
Derivative Asset, Fair Value, Gross Liability	(7,932)	[1]	(5,806)	[1]
Liabilities:
Derivative Liabilities	0		0
Derivative Liability, Fair Value, Gross Asset	7,932	[1]	5,806	[1]
Fair Value, Measurements, Recurring [Member] | Short-term Investments [Member]
Assets:
Short-term investments	72,924		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	72,924		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
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
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	72,924		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	105,342		97,101
Assets:
Derivative Asset, Fair Value, Gross Liability	(7,943)
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	84,171		78,516
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	21,049		18,585
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	122
Assets:
Derivative Asset, Fair Value, Gross Liability	(11)
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	(7,932)
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		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
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
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		$ 0

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

XML

Intangible Assets Future Amortization Expense (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2015
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Amortization Expense, Remainder of Fiscal Year	$ 147
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

XML

Members' Equity Members' Equity (Tables)

3 Months Ended

Mar. 31, 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

_____________________________

+ 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.

XML

Related Party Transactions Related Party Transactions (Tables)

3 Months Ended

Mar. 31, 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 March 31,
	2015		2014
Affiliates of Natural Gas Partners:	($ in thousands)
Natural gas purchases from affiliates	$	—	$	1,142

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

3 Months Ended

Mar. 31, 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.

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Risk Management Activities Risk Management Activities (Tables)

3 Months Ended

Mar. 31, 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 March 31, 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 March 31, 2015, that will mature during the years ended December 31, 2015 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)	8,100,000	$	4.07
Crude Oil	Costless Collar	360,000	$	90.00	$	97.55
Crude Oil	Swap (Pay Floating/Receive Fixed)	472,500	$	89.78
IsoButane	Swap (Pay Floating/Receive Fixed)	1,591,800	$	0.66
Natural Gasoline	Swap (Pay Floating/Receive Fixed)	1,251,600	$	1.13
Normal Butane	Swap (Pay Floating/Receive Fixed)	1,234,800	$	0.66
Propane	Swap (Pay Floating/Receive Fixed)	3,952,200	$	0.54
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
Contracts Maturing in 2017
Crude Oil	Swap (Pay Floating/Receive Fixed)	444,000	$	89.24
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.

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 March 31, 2015 and December 31, 2014:

	As of March 31, 2015
	Derivative Assets				Derivative Liabilities
	Balance Sheet Classification	Fair Value			Balance Sheet Classification	Fair Value
	($ in thousands)
Interest rate derivatives - liabilities	Current assets	$	(3,220	)	Current liabilities	$	—
Interest rate derivatives - liabilities	Long-term assets	(4,712		)	Long-term liabilities	—
Commodity derivatives - assets	Current assets	50,624			Current liabilities	—
Commodity derivatives - assets	Long-term assets	54,718			Long-term liabilities	—
Commodity derivatives - liabilities	Current assets	(11		)	Current liabilities	—
Total derivatives		$	97,399			$	—
	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 March 31,
		2015			2014
		($ in thousands)
Interest rate derivatives	Interest rate risk management losses, net	$	(3,066	)	$	(290	)
Commodity derivatives	Commodity risk management gains (losses), net	22,600			(10,033		)
Commodity derivatives	Discontinued operations	—			(4,911		)
Commodity derivatives - trading	Discontinued operations	—			(987		)
	Total	$	19,534		$	(16,221	)

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Property, Plant and Equipment Depreciation, Depletion, Amortization and Impairment (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Depreciation	$ 559	$ 707
Depletion	13,719	19,672
Oil and Gas Properties [Member]
Impairment of Long-Lived Assets Held-for-use	$ 68,344	$ 0

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Risk Management Activities Commodity Derivatives (Details)	Mar. 31, 2015 MMbtu
Natural Gas Contract [Member] | Swap [Member] | Portion of contracts settling in 2015 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	8,100,000	[1]
Derivative, Average Floor Price	4.07	[2]
Natural Gas Contract [Member] | Swap [Member] | Portion of contracts settling in 2016 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	9,480,000	[1]
Derivative, Average Floor Price	4.25	[2]
Crude Oil Contract [Member] | Costless Collar [Member] | Portion of contracts settling in 2015 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	360,000	[1]
Derivative, Average Floor Price	90.00	[2]
Derivative, Average Cap Price	97.55	[2]
Crude Oil Contract [Member] | Swap [Member] | Portion of contracts settling in 2015 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	472,500	[1]
Derivative, Average Floor Price	89.78	[2]
Crude Oil Contract [Member] | Swap [Member] | Portion of contracts settling in 2016 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	936,000	[1]
Derivative, Average Floor Price	84.66	[2]
Crude Oil Contract [Member] | Swap [Member] | Portion of contracts settling in 2017 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	444,000	[1]
Derivative, Average Floor Price	89.24	[2]
Crude Oil Contract [Member] | Swap [Member] | Portion of contracts settling in 2018 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	396,000	[1]
Derivative, Average Floor Price	88.78	[2]
Crude Oil Contract [Member] | Swap [Member] | Portion of contracts settling in 2019 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	348,000	[1]
Derivative, Average Floor Price	88.39	[2]
Propane Contract [Member] | Swap [Member] | Portion of contracts settling in 2015 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	3,952,200	[1]
Derivative, Average Floor Price	0.54	[2]
IsoButane Contract [Member] | Swap [Member] | Portion of contracts settling in 2015 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	1,591,800	[1]
Derivative, Average Floor Price	0.66	[2]
Natural Gasoline Contract [Member] | Swap [Member] | Portion of contracts settling in 2015 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	1,251,600	[1]
Derivative, Average Floor Price	1.13	[2]
Normal Butane Contract [Member] | Swap [Member] | Portion of contracts settling in 2015 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	1,234,800	[1]
Derivative, Average Floor Price	0.66	[2]

[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.

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Consolidated Balance Sheets (USD $) In Thousands, unless otherwise specified	Mar. 31, 2015		Dec. 31, 2014
CURRENT ASSETS:
Cash and cash equivalents	$ 37		$ 1,343
Short-term investments	72,924		153,448
Accounts receivable (a)	32,931	[1]	39,596	[1]
Risk management assets	47,392		44,805
Prepayments and other current assets	11,764		9,911
Total current assets	165,048		249,103
PROPERTY, PLANT AND EQUIPMENT — Net	432,291		487,988
INTANGIBLE ASSETS — Net	3,023		3,072
DEFERRED TAX ASSET	1,805		2,315
RISK MANAGEMENT ASSETS	50,007		46,490
OTHER ASSETS	5,063		5,307
TOTAL	657,237		794,275
CURRENT LIABILITIES:
Accounts payable	38,145		49,226
Accrued liabilities	7,575		8,053
Taxes payable	2,212		2,246
Total current liabilities	47,932		59,525
LONG-TERM DEBT	212,762		263,343
ASSET RETIREMENT OBLIGATIONS	47,575		47,907
DEFERRED TAX LIABILITY	28,921		30,321
OTHER LONG TERM LIABILITIES	5,270		4,709
COMMITMENTS AND CONTINGENCIES (Note 12)
MEMBERS' EQUITY (b)	314,777	[2]	388,470	[2]
TOTAL	$ 657,237		$ 794,275

[1] Net of allowance for bad debt of $1,263 as of March 31, 2015 and $1,023 as of December 31, 2014.

[2] 149,027,423 and 150,154,909 common units were issued and outstanding as of March 31, 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 2,121,963 and 2,419,750 as of March 31, 2015 and December 31, 2014, respectively.

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Intangible Assets Narrative (Details) (Use Rights [Member])	3 Months Ended
	Mar. 31, 2015
Use Rights [Member]
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Asset, Useful Life	20 years

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Consolidated Statement of Member's Equity (USD $) In Thousands, except Share data, unless otherwise specified	Total USD ($)	Number of Common Units [Member]	Common Units [Member] USD ($)	Accumulated Other Comprehensive Income (Loss) [Member] USD ($)
Members' Equity - Beginning Balance at Dec. 31, 2014	$ 388,470		$ 388,470	$ 0
Beginning Balance - Units Outstanding at Dec. 31, 2014	150,154,909	150,154,909
Increase (Decrease) in Members' Equity [Roll Forward]
Net loss	(58,719)		(58,719)
Other Comprehensive Income (Loss), Available-for-sale Securities Adjustment, Net of Tax	(3,603)
Distributions	(10,565)		(10,565)
Vesting of restricted units		60,700
Stock Repurchased During Period, Shares		1,188,186
Stock Repurchased During Period, Value	2,662		2,662
Share Based Compensation, Aggregate Amount	1,856		1,856
Members' Equity - Ending Balance at Mar. 31, 2015	$ 314,777		$ 318,380	$ (3,603)
Ending Balance - Units Outstanding at Mar. 31, 2015	149,027,423	149,027,423

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Commitments and Contingencies Loss Contingencies (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Loss Contingencies [Line Items]
Accrual for Environmental Loss Contingencies	$ 2.7	$ 2.8

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Earnings Per Unit Earnings Per Unit (Tables)

3 Months Ended

Mar. 31, 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 March 31,
		2015	2014
	(in thousands)
Weighted average units outstanding during period:
Common units - Basic		149,143	156,644
Common units - Diluted		149,143	156,644

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

The following table presents the Partnership's basic and diluted loss per unit for the three months ended March 31, 2015:

	Total			Common Units			Restricted Common Units*
	($ in thousands, except for per unit amounts)
Loss from continuing operations	$	(57,753	)
Distributions	10,561			$	10,432		$	129
Assumed loss from continuing operations after distribution to be allocated	(68,314		)	(68,314		)	—
Assumed allocation of loss from continuing operations	(57,753		)	(57,882		)	129
Discontinued operations, net of tax	(966		)	(966		)	—
Assumed net loss to be allocated	$	(58,719	)	$	(58,848	)	$	129
Basic loss from continuing operations per unit				$	(0.39	)
Basic discontinued operations per unit				$	(0.01	)
Basic loss per unit				$	(0.40	)
Diluted loss from continuing operations per unit				$	(0.39	)
Diluted discontinued operations per unit				$	(0.01	)
Diluted loss per unit				$	(0.40	)

_____________________________

* 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 March 31, 2014:

	Total			Common Units			Restricted Common Units*
	($ in thousands, except for per unit amounts)
Loss from continuing operations	$	(7,960	)
Distributions**	—			$	—		$	—
Assumed loss from continuing operations after distribution to be allocated	(7,960		)	(7,960		)	—
Assumed allocation of loss from continuing operations	(7,960		)	(7,960		)	—
Discontinued operations, net of tax	(10,603		)	(10,603		)	—
Assumed net loss to be allocated	$	(18,563	)	$	(18,563	)	$	—
Basic income from continuing operations per unit				$	(0.05	)
Basic discontinued operations per unit				$	(0.07	)
Basic loss per unit				$	(0.12	)
Diluted income from continuing operations per unit				$	(0.05	)
Diluted discontinued operations per unit				$	(0.07	)
Diluted income per unit				$	(0.12	)

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Earnings Per Unit Calculation of basic and diluted earnings per unit (Details) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2015		Mar. 31, 2014
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Income (Loss) from Continuing Operations Attributable to Parent	$ (57,753)		$ (7,960)
Distributions	10,561		0	[1]
Assumed income (loss) from continuing operations after distribution to be allocated	(68,314)		(7,960)
DISCONTINUED OPERATIONS, NET OF TAX	(966)		(10,603)
Net loss	(58,719)		(18,563)
Income (loss) from continuing operations per common unit - Basic	$ (0.39)		$ (0.05)
Discontinued operations per common unit - Basic	$ (0.01)		$ (0.07)
Net income (loss) per common unit - Basic	$ (0.40)		$ (0.12)
Net income (loss) per common unit - Diluted	$ (0.40)		$ (0.12)
Common Units [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Income (Loss) from Continuing Operations Attributable to Parent	(57,882)		(7,960)
Distributions	10,432		0	[1]
Assumed income (loss) from continuing operations after distribution to be allocated	(68,314)		(7,960)
DISCONTINUED OPERATIONS, NET OF TAX	(966)		(10,603)
Net loss	(58,848)		(18,563)
Income (loss) from continuing operations per common unit - Basic	$ (0.39)		$ (0.05)
Discontinued operations per common unit - Basic	$ (0.01)		$ (0.07)
Net income (loss) per common unit - Basic	$ (0.40)		$ (0.12)
Income (loss) from continuing operations per common unit - Diluted	$ (0.39)		$ (0.05)
Discontinued operations per common unit - Diluted	$ (0.01)		$ (0.07)
Net income (loss) per common unit - Diluted	$ (0.40)		$ (0.12)
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	129	[2]	0	[2]
Distributions	129	[2]	0	[1],[2]
Assumed income (loss) from continuing operations after distribution to be allocated	0	[2]	0	[2]
DISCONTINUED OPERATIONS, NET OF TAX	0	[2]	0	[2]
Net loss	$ 129	[2]	$ 0	[2]

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

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

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Earnings Per Unit

3 Months Ended

Mar. 31, 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 March 31, 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 March 31,
		2015	2014
	(in thousands)
Weighted average units outstanding during period:
Common units - Basic		149,143	156,644
Common units - Diluted		149,143	156,644

The following table presents the Partnership's basic and diluted loss per unit for the three months ended March 31, 2015:

	Total			Common Units			Restricted Common Units*
	($ in thousands, except for per unit amounts)
Loss from continuing operations	$	(57,753	)
Distributions	10,561			$	10,432		$	129
Assumed loss from continuing operations after distribution to be allocated	(68,314		)	(68,314		)	—
Assumed allocation of loss from continuing operations	(57,753		)	(57,882		)	129
Discontinued operations, net of tax	(966		)	(966		)	—
Assumed net loss to be allocated	$	(58,719	)	$	(58,848	)	$	129
Basic loss from continuing operations per unit				$	(0.39	)
Basic discontinued operations per unit				$	(0.01	)
Basic loss per unit				$	(0.40	)
Diluted loss from continuing operations per unit				$	(0.39	)
Diluted discontinued operations per unit				$	(0.01	)
Diluted loss per unit				$	(0.40	)

_____________________________

* 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 March 31, 2014:

	Total			Common Units			Restricted Common Units*
	($ in thousands, except for per unit amounts)
Loss from continuing operations	$	(7,960	)
Distributions**	—			$	—		$	—
Assumed loss from continuing operations after distribution to be allocated	(7,960		)	(7,960		)	—
Assumed allocation of loss from continuing operations	(7,960		)	(7,960		)	—
Discontinued operations, net of tax	(10,603		)	(10,603		)	—
Assumed net loss to be allocated	$	(18,563	)	$	(18,563	)	$	—
Basic income from continuing operations per unit				$	(0.05	)
Basic discontinued operations per unit				$	(0.07	)
Basic loss per unit				$	(0.12	)
Diluted income from continuing operations per unit				$	(0.05	)
Diluted discontinued operations per unit				$	(0.07	)
Diluted income per unit				$	(0.12	)

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Divestiture Related Activities Divestiture Related Activites(Tables)

3 Months Ended

Mar. 31, 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 months endedMarch 31, 2015 and 2014:

	Three Months Ended March 31,
	2015			2014
	($ in thousands)
Class of statement of operations line item of discontinued operations:
Revenue	$	—		$	302,871
Cost of natural gas, NGLs, condensate and helium	—			244,973
Operations, maintenance and taxes other than income	—			25,049
General and administrative	966			8,101
Depreciation, amortization and impairment	—			22,199
Interest expense	—			(13,232		)
Other expense	—			(8		)
Operating loss from discontinued operations before taxes	(966		)	(10,691		)
Income tax benefit	—			(88		)
Discontinued operations, net of tax	$	(966	)	$	(10,603	)

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 March 31, 2015.

	Employee Related Costs			Facility and Other Costs		Total
	($ in thousands)
Balance at December 31, 2014	$	835		$	490	$	1,325
Payments and other adjustments	(183		)	1,026		843
Balance at March 31, 2015	$	652		$	1,516	$	2,168

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Subsidiary Guarantors

3 Months Ended

Mar. 31, 2015

SUBSIDIARY GUARANTORS [Abstract]

Subsidiary Guarantors

SUBSIDIARY GUARANTORS

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

March 31, 2015

	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Consolidating Entries			Total
	($ in thousands)
ASSETS:
Accounts receivable – related parties	$	865,930		$	—	$	—		$	(865,930	)	$	—
Other current assets	129,008			1		36,039			—			165,048
Total property, plant and equipment, net	1,531			—		430,760			—			432,291
Investment in subsidiaries	(486,135		)	—		—			486,135			—
Total other long-term assets	55,072			—		4,826			—			59,898
Total assets	$	565,406		$	1	$	471,625		$	(379,795	)	$	657,237
LIABILITIES AND EQUITY:
Accounts payable – related parties	$	—		$	—	$	865,930		$	(865,930	)	$	—
Other current liabilities	37,497			—		10,435			—			47,932
Other long-term liabilities	370			—		81,396			—			81,766
Long-term debt	212,762			—		—			—			212,762
Equity	314,777			1		(486,136		)	486,135			314,777
Total liabilities and equity	$	565,406		$	1	$	471,625		$	(379,795	)	$	657,237

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 EndedMarch 31, 2015

	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Consolidating Entries			Total
	($ in thousands)
Total revenues	$	21,227		$	—	$	30,895		$	—		$	52,122
Operations and maintenance	—			—		10,082			—			10,082
Taxes other than income	—			—		1,388			—			1,388
General and administrative	2,082			—		8,907			—			10,989
Depreciation, depletion and amortization	136			—		14,509			—			14,645
Impairment	—			—		68,344			—			68,344
Income (loss) from operations	19,009			—		(72,335		)	—			(53,326		)
Interest expense, net	(2,318		)	—		—			—			(2,318		)
Other non-operating income	4,257			—		2,264			(4,386		)	2,135
Other non-operating expense	(6,459		)	—		(2,997		)	4,386			(5,070		)
Income (loss) before income taxes	14,489			—		(73,068		)	—			(58,579		)
Income tax expense (benefit)	96			—		(922		)	—			(826		)
Equity in earnings of subsidiaries	(73,110		)	—		—			73,110			—
Loss from continuing operations	(58,717		)	—		(72,146		)	73,110			(57,753		)
Discontinued operations, net of tax	(2		)	—		(964		)	—			(966		)
Net loss	$	(58,719	)	$	—	$	(73,110	)	$	73,110		$	(58,719	)

Unaudited Condensed Consolidating Statement of Operations

For the Three Months EndedMarch 31, 2014

	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-Guarantor Investments			Consolidating Entries			Total
	($ in thousands)
Total revenues	$	(10,033	)	$	—	$	55,236		$	—		$	—		$	45,203
Operations and maintenance	—			—		11,498			—			—			11,498
Taxes other than income	—			—		3,791			—			—			3,791
General and administrative	2,897			—		10,393			—			—			13,290
Depreciation, depletion and amortization	53			—		20,353			—			—			20,406
Loss from operations	(12,983		)	—		9,201			—			—			(3,782		)
Interest expense, net	(4,754		)	—		—			—			—			(4,754		)
Other non-operating income	2,221			—		2,301			—			(4,522		)	—
Other non-operating expense	(1,716		)	—		(3,095		)	—			4,522			(289		)
Loss before income taxes	(17,232		)	—		8,407			—			—			(8,825		)
Income tax benefit	(267		)	—		(598		)	—			—			(865		)
Equity in earnings of subsidiaries	18,634			—		—			—			(18,634		)	—
Loss from continuing operations	1,669			—		9,005			—			(18,634		)	(7,960		)
Discontinued operations, net of tax	(20,232		)	—		9,636			(7		)	—			(10,603		)
Net loss	$	(18,563	)	$	—	$	18,641		$	(7	)	$	(18,634	)	$	(18,563	)

Unaudited Condensed Consolidating Statement of Cash Flows

For the Three Months EndedMarch 31, 2015

	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Consolidating Entries		Total
	($ in thousands)
Net cash flows provided by operating activities	$	(14,013	)	$	—	$	28,740		$	—	$	14,727
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment	(334		)	—		(27,721		)	—		(28,055		)
Proceeds from sale of short-term investments	77,755			—		—			—		77,755
Net cash flows provided by investing activities	77,421			—		(27,721		)	—		49,700
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	45,300			—		—			—		45,300
Repayment of long-term debt	(95,900		)	—		—			—		(95,900		)
Payments for derivative contracts	(940		)	—		—			—		(940		)
Repurchase of common units	(2,662		)	—		—			—		(2,662		)
Distributions to members and affiliates	(10,565		)	—		—			—		(10,565		)
Net cash flows used in financing activities	(64,767		)	—		—			—		(64,767		)
Net cash flows used in discontinued operations	(2		)	—		(964		)	—		(966		)
Net decrease in cash and cash equivalents	(1,361		)	—		55			—		(1,306		)
Cash and cash equivalents at beginning of period	2,686			1		(1,344		)	—		1,343
Cash and cash equivalents at end of period	$	1,325		$	1	$	(1,289	)	$	—	$	37

Unaudited Condensed Consolidating Statement of Cash Flows

For the Three Months EndedMarch 31, 2014

	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-Guarantor Investments		Consolidating Entries		Total
	($ in thousands)
Net cash flows provided by operating activities	$	30,293		$	—	$	(6,490	)	$	—	$	—	$	23,803
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment	(336		)	—		(41,946		)	—		—		(42,282		)
Net cash flows used in investing activities	(336		)	—		(41,946		)	—		—		(42,282		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	144,250			—		—			—		—		144,250
Repayment of long-term debt	(127,050		)	—		—			—		—		(127,050		)
Payment of debt issuance cost	(205		)	—		—			—		—		(205		)
Payments for derivative contracts	(1,708		)	—		—			—		—		(1,708		)
Distributions to members and affiliates	(23,801		)	—		—			—		—		(23,801		)
Net cash flows used in financing activities	(8,514		)	—		—			—		—		(8,514		)
Net cash flows provided by discontinued operations	(17,154		)	—		49,678			16		—		32,540
Net increase in cash and cash equivalents	4,289			—		1,242			16		—		5,547
Cash and cash equivalents at beginning of period	1,237			1		(1,389		)	227		—		76
Cash and cash equivalents at end of period	$	5,526		$	1	$	(147	)	$	243	$	—	$	5,623

XML

Subsidiary Guarantors Subsidiary Guarantors Condensed Consolidating Balance Sheets (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2015		Dec. 31, 2014
Subsidiary Guarantors [Line Items]
Accounts receivable – related parties	$ 0		$ 0
Other current assets	165,048		249,103
PROPERTY, PLANT AND EQUIPMENT — Net	432,291		487,988
Investment in subsidiaries	0		0
Total other long-term assets	59,898		57,184
TOTAL	657,237		794,275
Accounts payable – related parties	0		0
Other current liabilities	47,932		59,525
Other long-term liabilities	81,766		82,937
LONG-TERM DEBT	212,762		263,343
MEMBERS' EQUITY (b)	314,777	[1]	388,470	[1]
TOTAL	657,237		794,275
Parent Company [Member]
Subsidiary Guarantors [Line Items]
Accounts receivable – related parties	865,930		838,656
Other current assets	129,008		211,213
PROPERTY, PLANT AND EQUIPMENT — Net	1,531		1,334
Investment in subsidiaries	(486,135)		(413,023)
Total other long-term assets	55,072		52,272
TOTAL	565,406		690,452
Accounts payable – related parties	0		0
Other current liabilities	37,497		37,850
Other long-term liabilities	370		789
LONG-TERM DEBT	212,762		263,343
MEMBERS' EQUITY (b)	314,777		388,470
TOTAL	565,406		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	36,039		37,889
PROPERTY, PLANT AND EQUIPMENT — Net	430,760		486,654
Investment in subsidiaries	0		0
Total other long-term assets	4,826		4,912
TOTAL	471,625		529,455
Accounts payable – related parties	865,930		838,656
Other current liabilities	10,435		21,675
Other long-term liabilities	81,396		82,148
LONG-TERM DEBT	0		0
MEMBERS' EQUITY (b)	(486,136)		(413,024)
TOTAL	471,625		529,455
Consolidation, Eliminations [Member]
Subsidiary Guarantors [Line Items]
Accounts receivable – related parties	(865,930)		(838,656)
Other current assets	0		0
PROPERTY, PLANT AND EQUIPMENT — Net	0		0
Investment in subsidiaries	486,135		413,023
Total other long-term assets	0		0
TOTAL	(379,795)		(425,633)
Accounts payable – related parties	(865,930)		(838,656)
Other current liabilities	0		0
Other long-term liabilities	0		0
LONG-TERM DEBT	0		0
MEMBERS' EQUITY (b)	486,135		413,023
TOTAL	$ (379,795)		$ (425,633)

[1] 149,027,423 and 150,154,909 common units were issued and outstanding as of March 31, 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 2,121,963 and 2,419,750 as of March 31, 2015 and December 31, 2014, respectively.

XML

Consolidated Statements of Cash Flows (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$ (58,719)	$ (18,563)
Adjustments to reconcile net loss to net cash provided by operating activities:
Discontinued operations	966	10,603
Depreciation, depletion and amortization	14,645	20,406
Impairment	68,344	0
Amortization of debt issuance costs	264	659
(Gain) loss from risk management activities, net	(19,534)	10,323
Derivative settlements	14,370	(3,138)
Equity-based compensation	1,856	2,583
Loss on short-term investments	2,004	0
Other	(887)	151
Changes in assets and liabilities—net of acquisitions:
Accounts receivable	4,039	(11,636)
Prepayments and other current assets	(1,853)	(6,068)
Accounts payable	(9,555)	2,795
Accrued liabilities	(435)	16,636
Other assets	(3)	(117)
Other current liabilities	(775)	(831)
Net cash provided by operating activities	14,727	23,803
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment	(28,055)	(42,282)
Proceeds from Sale of Short-term Investments	77,755	0
Net cash provided by (used in) investing activities	49,700	(42,282)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	45,300	144,250
Repayment of long-term debt	(95,900)	(127,050)
Payment of debt issuance costs	0	205
Proceeds from derivative contracts	(940)	(1,708)
Repurchase of common units	(2,662)	0
Distributions to members and affiliates	(10,565)	(23,801)
Net cash used in financing activities	(64,767)	(8,514)
CASH FLOWS FROM DISCONTINUED OPERATIONS:
Operating activities	(966)	44,750
Investing activities	0	(12,210)
Net cash (used in) provided by discontinued operations	(966)	32,540
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS	(1,306)	5,547
CASH AND CASH EQUIVALENTS—Beginning of period	1,343	76
CASH AND CASH EQUIVALENTS—End of period	37	5,623
NONCASH INVESTING AND FINANCING ACTIVITIES:
Investments in property, plant and equipment, not paid	10,627	6,241
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Interest paid—net of amounts capitalized	999	5,558
Cash paid for taxes	$ 98	$ 0

XML

Consolidated Balance Sheets Parenthetical (USD $) In Thousands, except Share data, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Allowance for doubtful accounts	$ 1,263	$ 1,023
Common stock, units issued	149,027,423	150,154,909
Common stock, units outstanding	149,027,423	150,154,909
Unvested Restricted Units granted	2,121,963	2,419,750

XML

Risk Management Activities

3 Months Ended

Mar. 31, 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 March 31, 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 March 31, 2015, that will mature during the years ended December 31, 2015 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)	8,100,000	$	4.07
Crude Oil	Costless Collar	360,000	$	90.00	$	97.55
Crude Oil	Swap (Pay Floating/Receive Fixed)	472,500	$	89.78
IsoButane	Swap (Pay Floating/Receive Fixed)	1,591,800	$	0.66
Natural Gasoline	Swap (Pay Floating/Receive Fixed)	1,251,600	$	1.13
Normal Butane	Swap (Pay Floating/Receive Fixed)	1,234,800	$	0.66
Propane	Swap (Pay Floating/Receive Fixed)	3,952,200	$	0.54
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
Contracts Maturing in 2017
Crude Oil	Swap (Pay Floating/Receive Fixed)	444,000	$	89.24
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.

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 March 31, 2015 and December 31, 2014:

	As of March 31, 2015
	Derivative Assets				Derivative Liabilities
	Balance Sheet Classification	Fair Value			Balance Sheet Classification	Fair Value
	($ in thousands)
Interest rate derivatives - liabilities	Current assets	$	(3,220	)	Current liabilities	$	—
Interest rate derivatives - liabilities	Long-term assets	(4,712		)	Long-term liabilities	—
Commodity derivatives - assets	Current assets	50,624			Current liabilities	—
Commodity derivatives - assets	Long-term assets	54,718			Long-term liabilities	—
Commodity derivatives - liabilities	Current assets	(11		)	Current liabilities	—
Total derivatives		$	97,399			$	—
	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 March 31,
		2015			2014
		($ in thousands)
Interest rate derivatives	Interest rate risk management losses, net	$	(3,066	)	$	(290	)
Commodity derivatives	Commodity risk management gains (losses), net	22,600			(10,033		)
Commodity derivatives	Discontinued operations	—			(4,911		)
Commodity derivatives - trading	Discontinued operations	—			(987		)
	Total	$	19,534		$	(16,221	)

XML

Document and Entity Information Document	3 Months Ended
	Mar. 31, 2015	Apr. 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	Mar. 31, 2015
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	Q1
Amendment Flag	false
Entity Common Stock, Shares Outstanding		152,990,305

XML

Fair Value of Financial Instruments

3 Months Ended

Mar. 31, 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 March 31, 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 March 31, 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 March 31, 2015 and December 31, 2014: 

	As of March 31, 2015
	Level 1		Level 2			Level 3		Netting (a)			Total
	($ in thousands)
Assets:
Crude oil derivatives	$	—	$	84,171		$	—	$	—		$	84,171
Natural gas derivatives	—		21,049			—		—			21,049
NGL derivatives	—		122			—		(11		)	111
Interest rate swaps	—		—			—		(7,932		)	(7,932		)
Equity investments	72,924		—			—		—			72,924
Total	$	72,924	$	105,342		$	—	$	(7,943	)	$	170,323
Liabilities:
NGL derivatives	—		(11		)	—		11			—
Interest rate swaps	—		(7,932		)	—		7,932			—
Total	$	—	$	(7,943	)	$	—	$	7,943		$	—

____________________________

(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 months endedMarch 31, 2015. The following table discloses the fair value of the Partnership's assets measured at fair value on a nonrecurring basis during the three months endedMarch 31, 2015:

	Three Months Ended March 31,
	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 March 31, 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 outstanding debt associated with the Senior Notes bore interest at a fixed rate; based on the market price of the Senior Notes as of March 31, 2015 and December 31, 2014, the Partnership estimates that the fair value of the Senior Notes was $49.1 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.

XML

Consolidated Statements of Operations (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
REVENUE:
Natural gas, natural gas liquids, oil, condensate and sulfur	$ 29,513	$ 55,084
Commodity risk management gains (losses), net	22,600	(10,033)
Other revenue	9	152
Total revenue	52,122	45,203
COSTS AND EXPENSES:
Operations and maintenance	10,082	11,498
Taxes other than income	1,388	3,791
General and administrative	10,989	13,290
Impairment	68,344	0
Depreciation, depletion and amortization	14,645	20,406
Total costs and expenses	105,448	48,985
OPERATING LOSS	(53,326)	(3,782)
OTHER (EXPENSE) INCOME:
Interest expense, net	(2,318)	(4,754)
Interest rate risk management losses, net	(3,066)	(290)
Loss on short-term investments	(2,004)	0
Other income, net	2,135	1
Total other (expense) income	(5,253)	(5,043)
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(58,579)	(8,825)
INCOME TAX BENEFIT	(826)	(865)
LOSS FROM CONTINUING OPERATIONS	(57,753)	(7,960)
DISCONTINUED OPERATIONS, NET OF TAX	(966)	(10,603)
NET LOSS	$ (58,719)	$ (18,563)
NET LOSS PER COMMON UNIT—BASIC AND DILUTED:
Income (loss) from continuing operations per common unit - Basic	$ (0.39)	$ (0.05)
Income (loss) from continuing operations per common unit - Diluted	$ (0.39)	$ (0.05)
Discontinued operations per common unit - Basic	$ (0.01)	$ (0.07)
Discontinued operations per common unit - Diluted	$ (0.01)	$ (0.07)
Net income (loss) per common unit - Basic	$ (0.40)	$ (0.12)
Net income (loss) per common unit - Diluted	$ (0.40)	$ (0.12)
Weighted Average Number of Shares Outstanding Basic and Diluted
Weighted average common units outstanding - Basic	149,143	156,644
Weighted average common units outstanding - Diluted	149,143	156,644

XML

Asset Retirement Obligations

3 Months Ended

Mar. 31, 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	9			16
Liabilities settled	(1,302		)	(682		)
Revision to liabilities	124			(105		)
Accretion expense	793			812
Asset retirement obligations—March 31 (a)	$	50,497		$	48,605

_____________________________________

(a) As of March 31, 2015 and December 31, 2014, $2.9 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 three months endedMarch 31, 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

3 Months Ended

Mar. 31, 2015

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment Disclosure

PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment consisted of the following:

	March 31, 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	13,583			13,234
Proved properties	863,565			905,622
Unproved properties	7,066			7,512
Work in progress	1,201			1,195
	888,748			930,896
Less: accumulated depreciation, depletion and amortization	(456,457		)	(442,908		)
Net property, plant and equipment	$	432,291		$	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 March 31,
		2015		2014
	($ in thousands)
Depreciation		$	559	$	707
Depletion		$	13,719	$	19,672
Impairment expense:
Proved properties (a)		$	68,344	$	—

________________________________

(a)During the three months endedMarch 31, 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)

3 Months Ended

Mar. 31, 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 months endedMarch 31, 2015 and 2014:

	Three Months Ended March 31,
	2015			2014
	($ in thousands)
Class of statement of operations line item of discontinued operations:
Revenue	$	—		$	302,871
Cost of natural gas, NGLs, condensate and helium	—			244,973
Operations, maintenance and taxes other than income	—			25,049
General and administrative	966			8,101
Depreciation, amortization and impairment	—			22,199
Interest expense	—			(13,232		)
Other expense	—			(8		)
Operating loss from discontinued operations before taxes	(966		)	(10,691		)
Income tax benefit	—			(88		)
Discontinued operations, net of tax	$	(966	)	$	(10,603	)

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 of $4.0 million and $0.6 million, respectively, 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 March 31, 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 March 31, 2015.

	Employee Related Costs			Facility and Other Costs		Total
	($ in thousands)
Balance at December 31, 2014	$	835		$	490	$	1,325
Payments and other adjustments	(183		)	1,026		843
Balance at March 31, 2015	$	652		$	1,516	$	2,168

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Commitments and Contingencies

3 Months Ended

Mar. 31, 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 March 31, 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.

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 March 31, 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 $0.5 million and $0.8 million for the three months endedMarch 31, 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

3 Months Ended

Mar. 31, 2015

Partners' Capital [Abstract]

Members' Equity

MEMBERS’ EQUITY

At March 31, 2015 and December 31, 2014, there were 149,027,423 and 150,154,909 unrestricted common units outstanding, respectively. In addition, there were 2,121,963 and 2,419,750 unvested restricted common units outstanding at March 31, 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 repurchases may be made 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 ending September 30, 2014 and will conclude by March 31, 2016. The repurchase program does not obligate the Partnership to acquire any, or any specific number of, units and may be discontinued at any time. The Partnership intends to cancel any units it repurchases under the repurchase program. During the three months endedMarch 31, 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

_____________________________

+ 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 Operating Leases (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Operating leases [Line Items]
Operating Leases, Rent Expense	$ 0.5	$ 0.8

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Intangible Assets

3 Months Ended

Mar. 31, 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:

	March 31, 2015			December 31, 2014
	($ in thousands)
Rights-of-way and easements—at cost	$	3,920		$	3,920
Less: accumulated amortization	(897		)	(848		)
Net intangible assets	$	3,023		$	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 March 31,
		2015		2014
	($ in thousands)
Amortization		$	49	$	49

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 March 31, 2015 is as follows (in thousands):

Year ending December 31,
2015	$	147
2016	$	196
2017	$	196
2018	$	196
2019	$	196
Thereafter	$	2,092

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Long Term Debt

3 Months Ended

Mar. 31, 2015

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

Long-term Debt [Text Block]

 LONG-TERM DEBT

Long-term debt consisted of the following:

	March 31, 2015			December 31, 2014
	($ in thousands)
Revolving credit facility:	$	162,000		$	212,600
Senior Notes:
8.375% Senior Notes due 2019	51,120			51,120
Unamortized bond discount	(358		)	(377		)
Total Senior Notes	50,762			50,743
Total long-term debt	$	212,762		$	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 current commitments totaling $320 million, with the ability to increase commitments up to a total aggregate amount of $1.2 billion. The Fifth Amendment coincided with the semi-annual borrowing base redetermination by the Partnership's commercial lenders. 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.

As of March 31, 2015, the Partnership had approximately $158.0 million of availability under the credit facility, based on its borrowing base on that date. The Partnership currently pays a 0.50% commitment fee (based on the Partnership's borrowing base utilization percentage) per year on the difference between total commitments and the amount drawn under the credit facility. The Credit Agreement includes a sub-limit for the issuance of standby letters of credit for a total of $50.0 million. As of March 31, 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 March 31, 2015:

	Debt Covenant	Actual Covenant Ratio as of March 31, 2015
Maximum total leverage ratio	4.0	1.8
Minimum current ratio	1.0	5.8

As of March 31, 2015, the Partnership was in compliance with the financial covenants under the Credit Agreement.

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.

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

3 Months Ended

Mar. 31, 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 March 31,
	2015		2014
Affiliates of Natural Gas Partners:	($ in thousands)
Natural gas purchases from affiliates	$	—	$	1,142

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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Earnings Per Unit Schedule of Weighted Average Number of Units(Details) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Weighted average common units outstanding - Basic	149,143	156,644
Weighted average common units outstanding - Diluted	149,143	156,644

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Divestiture Related Activities Divestiture Related Activities - Asset & Liabilities Held for Sale and Discontinued Operations (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Class of statement of operations line item of discontinued operations:
Revenue	$ 0	$ 302,871
Cost of natural gas, natural gas liquids, condensate and helium	0	244,973
Operations and maintenance	0	25,049
General and administrative	966	8,101
Depreciation, amortization and impairment	0	22,199
Interest expense	0	(13,232)
Other expense	0	(8)
Operating income (loss) from discontinued operations before taxes	(966)	(10,691)
Income tax expense (benefit)	0	(88)
Discontinued operations	$ (966)	$ (10,603)

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Equity Based Compensation Narrative (Details) (USD $)	3 Months Ended
	Mar. 31, 2015	Mar. 31, 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
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant	6,975,671
Equity-based compensation	$ 1,856,000	$ 2,583,000
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	8,600,000
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition	1 year 10 months 27 days
Common Units [Member]
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Shares cancelled during period, value	40,000
Number of Common Units [Member]
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Shares cancelled during period	16,602
Continuing Operations [Member]
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Equity-based compensation	$ 1,856,000	$ 2,583,000
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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Equity Based Compensation Equity Based Compensation (Tables)

3 Months Ended

Mar. 31, 2015

Share-based Compensation [Abstract]

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

A summary of the changes in outstanding restricted common units for the three months endedMarch 31, 2015 is provided below:

	Number of Restricted Units		Weighted Average Fair Value
Outstanding at December 31, 2014	2,419,750		$	6.06
Granted	23,000		$	2.37
Vested	(60,700	)	$	4.46
Forfeited	(260,087	)	$	6.69
Outstanding at March 31, 2015	2,121,963		$	5.99

A summary of the changes in outstanding performance units for the three months endedMarch 31, 2015 is provided below:

	Number of Performance Units		Weighted Average Fair Value
Outstanding at December 31, 2014	647,788		$	3.63
Forfeited	(123,175	)	$	3.59
Outstanding at March 31, 2015	524,613		$	3.64

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Related Party Transactions Schedule of Related Party Transactions (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Related Party Transaction [Line Items]
Natural gas purchases from affiliates	$ 0	$ 1,142

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Equity Based Compensation

3 Months Ended

Mar. 31, 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 March 31, 2015, a total of 6,975,671 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 three months endedMarch 31, 2015 is provided below:

	Number of Restricted Units		Weighted Average Fair Value
Outstanding at December 31, 2014	2,419,750		$	6.06
Granted	23,000		$	2.37
Vested	(60,700	)	$	4.46
Forfeited	(260,087	)	$	6.69
Outstanding at March 31, 2015	2,121,963		$	5.99

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 three months endedMarch 31, 2015 is provided below:

	Number of Performance Units		Weighted Average Fair Value
Outstanding at December 31, 2014	647,788		$	3.63
Forfeited	(123,175	)	$	3.59
Outstanding at March 31, 2015	524,613		$	3.64

Equity-Based Compensation

For the three months endedMarch 31, 2015 and March 31, 2014, the Partnership recorded non-cash compensation expense of approximately $1.9 million and $2.6 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 March 31, 2015, unrecognized compensation costs related to the outstanding restricted units and performance units under the LTIP totaled approximately $8.6 million. The remaining expense is to be recognized over a weighted average of 1.91 years.

In connection with the vesting of certain restricted units during the three months endedMarch 31, 2015, the Partnership cancelled 16,602 of the newly-vested common units in satisfaction of less than $0.1 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)

3 Months Ended

Mar. 31, 2015

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment [Table Text Block]

Property, plant and equipment consisted of the following:

	March 31, 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	13,583			13,234
Proved properties	863,565			905,622
Unproved properties	7,066			7,512
Work in progress	1,201			1,195
	888,748			930,896
Less: accumulated depreciation, depletion and amortization	(456,457		)	(442,908		)
Net property, plant and equipment	$	432,291		$	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 March 31,
		2015		2014
	($ in thousands)
Depreciation		$	559	$	707
Depletion		$	13,719	$	19,672
Impairment expense:
Proved properties (a)		$	68,344	$	—

________________________________

(a)During the three months endedMarch 31, 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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Members' Equity Narrative (Details) (USD $)	3 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Capital Unit [Line Items]
Limited Partners' Capital Account, Units Outstanding	149,027,423	150,154,909
Unvested Restricted Units granted	2,121,963	2,419,750
Equity Issuance, Market Value	$ 100,000,000
Equity Units, Issued	0
Stock Repurchase Program, Authorized Amount	100,000,000
Stock Repurchased and Retired During Period, Shares	1,171,584
Repurchase of common units	$ 2,622,000

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Asset Retirement Obligations Schedule of Change in Asset Retirement Obligation (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015		Mar. 31, 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	9		16
Liabilities settled	(1,302)		(682)
Revision to liabilities	124		(105)
Accretion expense	793		812
Asset Retirement Obligation - End of Period	50,497		48,605
Asset Retirement Obligation, Current	$ 2,923			$ 2,966

[1] As of March 31, 2015 and December 31, 2014, $2.9 million and $3.0 million, respectively, were included within accrued liabilities in the unaudited condensed consolidated balance sheets.

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Consolidated Statements of Comprehensive Income Statement (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Net loss	$ (58,719)	$ (18,563)
Loss on short-term investments	(3,603)	0
COMPREHENSIVE LOSS	$ (62,322)	$ (18,563)

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New Accounting Pronouncements

3 Months Ended

Mar. 31, 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. This guidance is effective for annual reporting periods (including interim reporting periods within those periods) beginning after December 15, 2016. Early adoption of the guidance is not permitted. The Partnership is currently evaluating the potential impact, if any, of the adoption of this new guidance on its financial statements.

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 Narrative (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Fair Value Disclosures [Abstract]
Notes Payable, Fair Value Disclosure	$ 49.1	$ 47.0

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Subsidiary Guarantors Subsidiary Guarantors Condensed Consolidating Income Statement (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Subsidiary Guarantors [Line Items]
Total revenues	$ 52,122	$ 45,203
Operations and maintenance	10,082	11,498
Taxes other than income	1,388	3,791
General and administrative	10,989	13,290
Depreciation, depletion and amortization	14,645	20,406
Impairment	68,344	0
OPERATING LOSS	(53,326)	(3,782)
Interest expense, net	(2,318)	(4,754)
Other non-operating income	2,135	0
Other (expense) income	(5,070)	(289)
Income (loss) before income taxes	(58,579)	(8,825)
INCOME TAX BENEFIT	(826)	(865)
Equity in earnings of subsidiaires	0	0
LOSS FROM CONTINUING OPERATIONS	(57,753)	(7,960)
Discontinued operations	(966)	(10,603)
Net income (loss)	(58,719)	(18,563)
Parent Company [Member]
Subsidiary Guarantors [Line Items]
Total revenues	21,227	(10,033)
Operations and maintenance	0	0
Taxes other than income	0	0
General and administrative	2,082	2,897
Depreciation, depletion and amortization	136	53
Impairment	0
OPERATING LOSS	19,009	(12,983)
Interest expense, net	(2,318)	(4,754)
Other non-operating income	4,257	2,221
Other (expense) income	(6,459)	(1,716)
Income (loss) before income taxes	14,489	(17,232)
INCOME TAX BENEFIT	96	(267)
Equity in earnings of subsidiaires	(73,110)	18,634
LOSS FROM CONTINUING OPERATIONS	(58,717)	1,669
Discontinued operations	(2)	(20,232)
Net income (loss)	(58,719)	(18,563)
Co-issuer [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
Impairment	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	0	0
Net income (loss)	0	0
Guarantor Subsidiaries [Member]
Subsidiary Guarantors [Line Items]
Total revenues	30,895	55,236
Operations and maintenance	10,082	11,498
Taxes other than income	1,388	3,791
General and administrative	8,907	10,393
Depreciation, depletion and amortization	14,509	20,353
Impairment	68,344
OPERATING LOSS	(72,335)	9,201
Interest expense, net	0	0
Other non-operating income	2,264	2,301
Other (expense) income	(2,997)	(3,095)
Income (loss) before income taxes	(73,068)	8,407
INCOME TAX BENEFIT	(922)	(598)
Equity in earnings of subsidiaires	0	0
LOSS FROM CONTINUING OPERATIONS	(72,146)	9,005
Discontinued operations	(964)	9,636
Net income (loss)	(73,110)	18,641
Non-Guarantor Subsidiaries [Member]
Subsidiary Guarantors [Line Items]
Total revenues		0
Operations and maintenance		0
Taxes other than income		0
General and administrative		0
Depreciation, depletion and amortization		0
OPERATING LOSS		0
Interest expense, net		0
Other non-operating income		0
Other (expense) income		0
Income (loss) before income taxes		0
INCOME TAX BENEFIT		0
Equity in earnings of subsidiaires		0
LOSS FROM CONTINUING OPERATIONS		0
Discontinued operations		(7)
Net income (loss)		(7)
Consolidation, Eliminations [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
Impairment	0
OPERATING LOSS	0	0
Interest expense, net	0	0
Other non-operating income	(4,386)	(4,522)
Other (expense) income	4,386	4,522
Income (loss) before income taxes	0	0
INCOME TAX BENEFIT	0	0
Equity in earnings of subsidiaires	73,110	(18,634)
LOSS FROM CONTINUING OPERATIONS	73,110	(18,634)
Discontinued operations	0	0
Net income (loss)	$ 73,110	$ (18,634)

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Asset Retirement Obligations Asset Retirement Obligations (Tables)

3 Months Ended

Mar. 31, 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	9			16
Liabilities settled	(1,302		)	(682		)
Revision to liabilities	124			(105		)
Accretion expense	793			812
Asset retirement obligations—March 31 (a)	$	50,497		$	48,605

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(a) As of March 31, 2015 and December 31, 2014, $2.9 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 three months endedMarch 31, 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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Summary of Significant Accounting Policies Narrative (Details) (USD $)	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014
Loss on short-term investments	$ (2,004,000)	$ 0
Other Comprehensive Income (Loss), Available-for-sale Securities Adjustment, Net of Tax	(3,603,000)	0
Distributions received from short term investments	2,134,000
Investment Owned, Balance, Shares	3,188,624
Regency units not settled at period end	150,000
Receivable from sale of short-term investments	3,449,000
Gas Balancing Payable	$ 400,000		$ 300,000

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Income Taxes

3 Months Ended

Mar. 31, 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 months endedMarch 31, 2015 and March 31, 2014, the Partnership recognized an income tax benefit of $0.8 million and $0.9 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.