Eagle Rock Energy Partners L P (EROC) 10-K 2 Mar 15 2014 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information Document (USD $)	12 Months Ended
	Dec. 31, 2014	Feb. 26, 2015	Jun. 30, 2014
Document Information [Line Items]
Entity Registrant Name	EAGLE ROCK ENERGY PARTNERS L P
Entity Central Index Key	1364541
Current Fiscal Year End Date	-19
Entity Filer Category	Accelerated Filer
Document Type	10-K
Document Period End Date	31-Dec-14
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY
Amendment Flag	FALSE
Entity Common Stock, Shares Outstanding		151,223,977
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$514,751,744

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Dec. 31, 2014		Dec. 31, 2013
In Thousands, unless otherwise specified
CURRENT ASSETS:
Cash and cash equivalents	$1,343		$76
Short-term Investments	153,448		0
Accounts receivable	39,596	[1]	17,250	[1]
Risk management assets, current	44,805		5,559
Prepayments and other current assets	9,911		6,123
Assets held for sale	0		1,259,382
Total current assets	249,103		1,288,390
Property, Plant and Equipment — Net	487,988		824,451
Intangible Assets — Net	3,072		3,268
Deferred Tax Asset	2,315		1,438
Risk Management Assets	46,490		3,871
Other Assets	5,307		6,132
Total assets	794,275		2,127,550
CURRENT LIABILITIES:
Accounts payable	49,226		50,158
Accrued liabilities	8,053		23,162
Taxes payable	2,246		149
Risk management liabilities	0		8,360
Disposal Group, Including Discontinued Operation, Accounts Payable	0		637,738
Total current liabilities	59,525		719,567
Long-term debt	263,343		757,480
Asset Retirement Obligations	47,907		37,306
Deferred Tax Liability	30,321		34,097
Risk Management Liabilities	0		2,826
Other long-term liabilities	4,709		2,395
Commitments and Contingencies (Note 13)
Members' Equity	388,470	[2]	573,879	[2]
Total liabilities and equity	$794,275		$2,127,550
[1]	Net of allowance for bad debt of $1,023 as of December 31, 2014 and $931 as of December 31, 2013.
[2]	156,644,153 common units were issued and outstanding as of December 31, 2014 and December 31, 2013, respectively. These amounts do not include unvested restricted common units granted under the Partnership's long-term incentive plan of 2,419,750 and 2,743,807 as of December 31, 2014 and December 31, 2013, respectively.

Consolidated_Balance_Sheets_Ba

Consolidated Balance Sheets Balance Sheet Parentheticals (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, except Share data, unless otherwise specified
Allowance for Doubtful Accounts Receivable, Current	1,023	931
Common Class A [Member]
Limited Partners' Capital Account, Units Outstanding	150,154,909	156,644,153
General Partners' Capital Account, Units Issued	150,154,909	156,644,153

Consolidated_Statements_of_Ope

Consolidated Statements of Operations (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Revenues:
Natural gas, natural gas liquids, oil, condensate, sulfur and helium sales	$203,792	$200,608	$201,719
Commodity risk management gains (losses), net	94,431	-3,937	28,110
Other revenue	-19	701	1,486
Total revenue	298,204	197,372	231,315
COSTS AND EXPENSES:
Operations and maintenance	43,670	41,426	41,391
Taxes other than income	12,925	12,928	15,343
General and administrative	47,193	53,131	50,990
Impairment	395,892	214,286	45,289
Depreciation, Depletion and Amortization	85,579	89,444	90,510
Total costs and expenses	585,259	411,215	243,523
OPERATING INCOME (LOSS)	-287,055	-213,843	-12,208
OTHER INCOME (EXPENSE):
Interest expense, net	15,247	18,789	16,276
Interest rate risk management gains (losses), net	-1,734	-1,104	-4,727
Loss on short term investments	-62,028	0	0
Other (expense) income	8,294	-30	-28
Total other (expense) income	-70,715	-19,923	-21,031
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	-357,770	-233,766	-33,239
Income Tax Expense (Benefit)	-5,403	-5,595	-1,093
INCOME (LOSS) FROM CONTINUING OPERATIONS	-352,367	-228,171	-32,146
Discontinued operations, net of tax	212,460	-49,808	-118,456
Net income (loss)	($139,907)	($277,979)	($150,602)
NET INCOME PER COMMON UNIT—BASIC AND DILUTED:
Net Income (loss) from continuing operations per common unit - basic	($2.25)	($1.50)	($0.26)
Net Income (loss) from continuing operations per common units - diluted	($2.25)	($1.50)	($0.26)
Discontinued operations per common unit - basic	$1.36	($0.32)	($0.87)
Discontinued operations per common unit - diluted	$1.36	($0.32)	($0.87)
Net income (loss) per common unit - basic	($0.89)	($1.82)	($1.13)
Net income (loss) per common unit - diluted	($0.89)	($1.82)	($1.13)
Weighted Average Number of Shares Outstanding Basic and Diluted
Weighted average common units outstanding - basic	156,700	153,562	135,609
Weighted Average common units outstanding - diluted	156,700	153,562	135,609

Consolidated_Statement_of_Memb

Consolidated Statement of Member's Equity (USD $)	Total	Common Class A [Member]	Common Units [Member]
In Thousands, except Share data, unless otherwise specified
Members' Equity - Beginning Balance at Dec. 31, 2011	$1,007,347		$1,007,347
Beginning Balance - Units Outstanding at Dec. 31, 2011		127,606,229
Increase (Decrease) in Members' Equity [Roll Forward]
Net income (loss)	-150,602		-150,602
Distributions	-119,211		-119,211
Vesting of restricted units - Units		1,101,323
Exercise of Warrants - Units		5,300,588
Exercise of Warrants	31,804		31,804
Repurchase of common units - Units		-286,716
Repurchase of common units	-2,501		-2,501
Equity-based Compensation	7,719
Share Based Compensation, Aggregate Amount	9,882		9,882
Stock Issued During Period, Shares, New Issues		10,954,327
Stock Issued During Period, Value, New Issues	96,173		96,173
Issuance costs for equity offerings	-4,518		-4,518
Members' Equity - Ending Balance at Dec. 31, 2012	868,374		868,374
Ending Balance - Units Outstanding at Dec. 31, 2012		144,675,751
Increase (Decrease) in Members' Equity [Roll Forward]
Net income (loss)	-277,979
Distributions	-125,911		-125,911
Vesting of restricted units - Units		1,203,822
Exercise of Warrants	0
Repurchase of common units - Units		-272,179
Repurchase of common units	-1,858		-1,858
Equity-based Compensation	10,392
Share Based Compensation, Aggregate Amount	13,384		13,384
Stock Issued During Period, Shares, New Issues	10,120,000	11,036,759
Stock Issued During Period, Value, New Issues	102,388		102,388
Issuance costs for equity offerings	-4,519		-4,519
Members' Equity - Ending Balance at Dec. 31, 2013	573,879		573,879
Ending Balance - Units Outstanding at Dec. 31, 2013		156,644,153
Increase (Decrease) in Members' Equity [Roll Forward]
Net income (loss)	-139,907		-139,907
Distributions	-34,982		-34,982
Vesting of restricted units - Units		1,305,433
Exercise of Warrants	0
Repurchase of common units - Units		-7,794,677
Repurchase of common units		-20,505
Equity-based Compensation	8,198
Share Based Compensation, Aggregate Amount	9,985		9,985
Stock Issued During Period, Shares, New Issues	10,350,000
Issuance costs for equity offerings	0
Members' Equity - Ending Balance at Dec. 31, 2014	$388,470		$388,470
Ending Balance - Units Outstanding at Dec. 31, 2014		150,154,909

Consolidated_Statements_of_Cas

Consolidated Statements of Cash Flows (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	($139,907)	($277,979)	($150,602)
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Discontinued operations, net of tax	-212,460	49,808	118,456
Depreciation, Depletion and Amortization	85,579	89,444	90,510
Impairment	395,892	214,286	45,289
Amortization of debt issuance costs	2,241	2,151	1,735
Loss (gain) from risk management activities, net	-92,697	5,041	-23,383
Derivative settlements	4,669	7,478	5,368
Equity-based compensation	8,198	10,392	7,719
Loss (gain) of sale of assets	0	-76	0
Loss on short-term investments	-62,028	0	0
Other	-2,574	-1,197	-592
Changes in assets and liabilities—net of acquisitions:
Accounts receivable	-20,428	14,280	-26,742
Prepayments and other current assets	-3,788	1,838	2,087
Risk management activities	0	0	-6,607
Accounts payable	-5,023	1,738	14,198
Accrued liabilities	-4,138	-964	2,519
Other assets	-6	143	-2,985
Other current liabilities	540	-2,140	-1,634
Net cash provided by (used in) operating activities	78,126	114,243	75,336
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment	-136,694	-149,944	-167,907
Proceeds from sale of asset	0	76	15,398
Proceeds from sale of Short-term Investments	43,836	0	0
Net cash provided by (used in) investing activities	-92,858	-149,868	-152,509
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	472,500	601,400	1,043,750
Repayment of long-term debt	-966,700	-503,100	-916,750
Proceeds from Senior Notes	0	0	22,889
Payment of debt issuance costs	-1,984	0	-614
Proceeds from derivative contracts	-5,022	1,323	14,449
Common unit issued in equity offerings	0	102,388	96,173
Issuance costs for equity offerings	0	-4,519	-4,518
Exercise of Warrants	0	0	31,804
Repurchase of common units	19,170	1,858	2,501
Distributions to members and affiliates	-34,982	-125,911	-119,211
Net cash provided by (used in) financing activities	-555,358	69,723	165,471
CASH FLOWS FROM DISCONTINUED OPERATIONS:
Operating activities from discontinued operations	31,098	63,133	70,165
Investing activities from discontinued operations	540,259	-97,180	-376,161
Financing activities from discontinued operations	0	0	216,846
Net cash provided by (used in) discontinued operations	571,357	-34,047	-89,150
Net increase in cash and cash equivalents	1,267	51	-852
CASH AND CASH EQUIVALENTS—Beginning of period	76	25	877
CASH AND CASH EQUIVALENTS—End of period	1,343	76	25
NONCASH INVESTING AND FINANCING ACTIVITIES:
Noncash or Part Noncash Divestiture, Amount of Consideration Received	265,599	0	0
Investments in property, plant and equipment, not paid	12,154	9,469	29,568
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Interest paid—net of amounts capitalized	43,705	65,309	45,614
Cash paid for taxes	$0	$59	$1,085

Consolidated_Statement_of_Othe

Consolidated Statement of Other Comprehensive Income Statement (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Statement of Comprehensive Income [Abstract]
Net income (loss)	($139,907)	($277,979)	($150,602)
Available-for-sale Securities, Gross Unrealized Gain	3,381	0	0
Available-for-sale Securities, Gross Unrealized Loss	-3,381	0	0
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	($139,907)	($277,979)	($150,602)

Organization_and_Description_o

Organization and Description of Business	12 Months Ended
	Dec. 31, 2014
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, condensate and crude oil. The Partnership's assets, located primarily in Alabama (where it also operates the associated gathering and processing assets), Texas, Oklahoma, Mississippi and Arkansas, are characterized by long-lived, high-working interest properties with extensive production histories and development opportunities.
	On July 1, 2014, the Partnership contributed its business of gathering, compressing, treating, processing, transporting, marketing and trading natural gas, fractionating, transporting and marketing natural gas liquids ("NGLs") and crude oil and condensate logistics and marketing (collectively, the “Midstream Business”) to Regency Energy Partners LP ("Regency") (such contribution, the "Midstream Business Contribution"). The consideration received by the Partnership pursuant to the Midstream Business Contribution included: (i) $576.2 million of cash; (ii) 8,245,859 Regency common units (valued at approximately$265.6 million based on the closing price of Regency common units on June 30, 2014) and (iii) the exchange of $498.9 million face amount of the Partnership's outstanding unsecured senior notes ("Senior Notes") for an equivalent amount of Regency unsecured senior notes. $51.1 million of the Partnership's Senior Notes did not exchange and remain outstanding under an amended indenture with substantially all of the restrictive covenants and certain events of default eliminated.
	Accordingly, prior periods have been retrospectively adjusted to reflect the Midstream Business's assets and liabilities as held-for-sale and operations as discontinued (see Note 18) in the financial statements included in this report. As a result of this transaction, the Partnership only reports as one segment.
	The general partner of Eagle Rock Energy is Eagle Rock Energy GP, L.P., and the general partner of Eagle Rock Energy GP, L.P. is Eagle Rock Energy G&P, LLC, both of which are wholly-owned subsidiaries of the Partnership.

Summary_of_Significant_Account

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
	Basis of Presentation and Principles of Consolidation—The accompanying audited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP").
	All intercompany accounts and transactions are eliminated in the consolidated financial statements.
	Use of Estimates—The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reported period. Significant estimates are required for proved oil and natural gas reserves, which can affect the carrying value of oil and natural gas properties. The Partnership evaluates its estimates and assumptions on a regular basis. The Partnership bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results could differ from those estimates and such differences could be material.
	Cash and Cash Equivalents—Cash and cash equivalents include certificates of deposit and other highly liquid investments with maturities of three months or less at the time of purchase.
	Short-term Investments— A portion of the consideration received for the Midstream Business Contribution included Regency common units, as further described in Note 1. These common units have a readily determinable fair value, are being classified as available-for-sale equity securities and are recorded as short-term investments on the consolidated balance sheets. Unrealized gains and losses associated with increases and decreases in the fair value of these securities are included in other comprehensive income until such time that the gains and losses become realized and then will be included in the consolidated statements of operations. Losses from declines in fair value determined to be other than temporary are recorded in the consolidated statement of operations. This loss is included in the consolidated statement of operations as a loss on short-term investments. Distributions received from Regency as a result of holding these common units are recorded as other income on the consolidated statement of operations. For the twelve months ended December 31, 2014, the Partnership received and recorded distributions from Regency of $8.0 million. During the fourth quarter of 2014, the Partnership recorded a $62.0 million loss associated with losses as the result of sale of common units and the decrease in the fair value of these securities that was deemed to be other than temporary and the sale of common units. As of December 31, 2014, the Partnership still held 6,393,657 Regency common units, which does not include the transactions to sell 262,496 Regency common units that had not settled as of December 31, 2014 and for which a receivable of $6.3 million was recorded as part accounts receivable in the consolidated balance sheet.
	Concentration and Credit Risk—Concentration and credit risk for the Partnership principally consists of cash and cash equivalents and accounts receivable.
	The Partnership places its cash and cash equivalents with high-quality institutions and in money market funds. The Partnership derives its revenue from customers primarily in the natural gas industry. Industry concentrations have the potential to impact the Partnership's overall exposure to credit risk, either positively or negatively, in that the Partnership's customers could be affected by similar changes in economic, industry or other conditions. However, the Partnership believes the risk posed by this industry concentration is offset by the creditworthiness of the Partnership's customer base. The Partnership's portfolio of accounts receivable is comprised primarily of mid-size to large domestic corporate entities.
	The following is the activity within the Partnership's allowance for doubtful accounts during the years ended December 31, 2014, 2013 and 2012.
		2014			2013			2012
	($ in thousands)
	Balance at beginning of period	$	931		$	753		$	670
	Charged to bad debt expense	249			458			175
	Write-offs/adjustments charged to allowance	(157		)	(280		)	(92		)
	Balance at end of period	$	1,023		$	931		$	753
	The table above does not include amounts related to the Partnership's Midstream Business, as these amounts have been classified as part of assets held for sale within the audited consolidated balance sheets and discontinued operations within the audited consolidated statements of operations (see Note 18).
	Certain Other Concentrations—For the year ended December 31, 2014, NGL Energy Partners LP, CVR Refining, LP and Oneok Partners, LP, the Partnership's largest customers, represented 15%, 12% and 11%, respectively, of its total sales revenue (excluding its commodity risk management gains and losses and revenue amounts classified as part of discontinued operations).
	Inventory—Inventory is stated at the lower of cost or market, with cost being determined using the average cost method. At December 31, 2013, the Partnership had $1.0 million of crude oil finished goods inventory, which is recorded as part of assets held for sale within the audited consolidated balance sheet.
	Property, Plant and Equipment—Property, plant and equipment, including amounts classified as held for sale, consists primarily of gas gathering systems, gas processing plants, NGL pipelines, conditioning and treating facilities and other related facilities, and oil and natural gas properties, which are carried at cost less accumulated depreciation, depletion and amortization. The Partnership charges repairs and maintenance against income when incurred and capitalizes renewals and betterments, which extend the useful life or expand the capacity of the assets. The Partnership capitalizes interest costs on major projects during extended construction time periods. Such interest costs are allocated to property, plant and equipment and amortized over the estimated useful lives of the related assets. The Partnership calculates depreciation on the straight-line method over estimated useful lives of the Partnership's newly developed or acquired assets. The weighted average useful lives are as follows:
	Plant assets	20 years
	Pipelines and equipment	20 years
	Gas processing and equipment	20 years
	Office furniture and equipment	5 years
	Plant assets, pipelines and equipment, gas process and equipment and certain office furniture and equipment related to the Partnership's Midstream Business have been classified as assets held for sale within the audited consolidated balance sheets. Depreciation expense related to these assets has been recorded as part of discontinued operations within the audited consolidated statements of operations (see Note 18).
	Oil and Natural Gas Properties—The Partnership utilizes the successful efforts method of accounting for its oil and natural gas properties. Leasehold costs are capitalized when incurred. Costs incurred to drill and complete development wells are capitalized. Geological and geophysical expenses and delay rentals are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if the well is determined to be unsuccessful. The Partnership carries the costs of an exploratory well as an asset if the well is found to have a sufficient quantity of reserves to justify its capitalization as a producing well as long as the Partnership is making sufficient progress towards assessing the reserves and the economic and operating viability of the project.
	Depletion of producing oil and natural gas properties is recorded based on units of production. Unit rates are computed for unamortized drilling and development costs using proved developed reserves and for acquisition costs using all proved reserves. Authoritative guidance requires that acquisition costs of proved properties be amortized on the basis of all proved reserves (developed and undeveloped), and that capitalized development costs (wells and related equipment and facilities) be amortized on the basis of proved developed reserves.
	Upon sale or retirement of complete fields of depreciable or depleted property, the book value thereof, less proceeds or salvage value, is charged or credited to income.
	Costs related to unproved properties include costs incurred to acquire unproved reserves.  Because these reserves do not meet the definition of proved reserves, the related costs are not classified as proved properties.  Unproved leasehold costs are capitalized and amortized on a composite basis if individually insignificant, based on past success, experience, drilling plans and average lease-term lives.  Unamortized leasehold costs related to successful exploratory drilling are reclassified to proved properties and depleted on a units of production basis.  Unproved properties (both individually significant and insignificant) are assessed periodically within specific geographic areas and, if necessary, impairments are charged to expense.
	Other Assets— As of December 31, 2014 and 2013, other assets, excluding amounts classified as held for sale (see Note 18), primarily consist of costs associated with debt issuance costs, net of amortization, of $5.3 million and $6.1 million, respectively.
	Impairment of Long-Lived Assets—Management evaluates whether the carrying value of non-oil and natural gas long-lived assets has been impaired when circumstances indicate the carrying value of those assets may not be recoverable. This evaluation is based on undiscounted cash flow projections. The carrying amount is not recoverable if it exceeds the undiscounted sum of cash flows expected to result from the use and eventual disposition of the assets. Management considers various factors when determining if these assets should be evaluated for impairment, including, but not limited to:
	•	significant adverse changes in legal factors or in the business climate;
	•	a current-period operating or cash flow loss combined with a history of operating or cash flow losses or a projection or forecast which demonstrates continuing losses associated with the use of a long-lived asset;
	•	an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of a long-lived asset;
	•	significant adverse changes in the extent or manner in which an asset is used or in its physical condition;
	•	a significant change in the market value of an asset; or
	•	a current expectation that, more likely than not, an asset will be sold or otherwise disposed of before the end of its estimated useful life.
	For its oil and natural gas long-lived assets, the Partnership reviews its proved properties at the field level when management determines that events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. Such events include a negative revision or unfavorable projection of future oil and natural gas reserves and/or forward prices that will be produced from a field, the timing of this future production, future costs to produce the oil and natural gas, and future inflation levels.
	If the carrying value is not recoverable on an undiscounted basis, the impairment loss is measured as the excess of the asset's carrying value over its fair value. Management assesses the fair value of long-lived assets using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales, internally developed discounted cash flow analysis and analysis from outside advisors. Significant changes in market conditions resulting from events such as the condition of an asset or a change in management's intent to utilize the asset would generally require management to reassess the cash flows related to the long-lived assets.
	See Note 5 for further discussion on impairment charges.
	Revenue Recognition—Revenues associated with sales of natural gas, NGLs, crude oil, condensate and sulfur are recognized when title passes to the customer, which is when the risk of ownership passes to the customer and physical delivery occurs.
	Revenues for the Partnership's Midstream Business included the sale of natural gas, NGLs, crude oil, condensate, sulfur and helium and from the compression, gathering, processing, treating and transportation of natural gas. Revenues associated with transportation and processing fees were recognized in the period when the services were provided. These revenues have been classified as discontinued operations within the unaudited condensed consolidated statements of operations.
	Natural gas revenues produced from the Partnership's natural gas interests are based on the amount of natural gas sold to purchasers. The volumes of natural gas sold may differ from the volumes to which the Partnership is entitled based on its interests in the properties. Differences between volumes sold and volumes based on entitlements create natural gas imbalances. Imbalances are reflected as adjustments to reported natural gas reserves and future cash flows. The Partnership had long-term imbalance payables totaling $0.3 million and $0.3 million as of December 31, 2014 and December 31, 2013.
	Transportation and Exchange Imbalances—In the course of transporting natural gas and NGLs for others, the Partnership may receive for redelivery different quantities of natural gas or NGLs than the quantities actually delivered. These transactions result in transportation and exchange imbalance receivables or payables which are recovered or repaid through the receipt or delivery of natural gas or NGLs in future periods, if not subject to cash out provisions. Imbalance receivables are included in accounts receivable and imbalance payables are included in accounts payable on the audited consolidated balance sheets and marked-to-market using current market prices in effect for the reporting period of the outstanding imbalances. As of December 31, 2013, the Partnership had imbalance receivables totaling $0.7 million and imbalance payables totaling $1.6 million. All transportation and exchange imbalance receivables and imbalance payables have been classified as assets and liabilities held for sale, respectively, within the audited consolidated balance sheets. Changes in market value and the settlement of any such imbalance at a price greater than or less than the recorded imbalance results in either an upward or downward adjustment, as appropriate, to the cost of natural gas sold, and have been classified as discontinued operations within the audited consolidated statements of operations.
	Environmental Expenditures—Environmental expenditures are expensed or capitalized as appropriate, depending upon the future economic benefit. Expenditures which relate to an existing condition caused by past operations and do not generate current or future revenue are expensed. Liabilities for these expenditures are recorded on an undiscounted basis when environmental assessments and/or clean-ups are probable and the costs can be reasonably estimated.
	Income Taxes—Provision for income taxes is primarily applicable to the Partnership's state tax obligations under the Revised Texas Franchise Tax (the “Revised Texas Franchise Tax”) and certain federal and state tax obligations of Eagle Rock Energy Acquisition Co., Inc., Eagle Rock Acquisition Co. II, Inc., Eagle Rock Upstream Development Company, Inc. and Eagle Rock Upstream Development Company II, Inc., all of which are consolidated subsidiaries. Deferred income tax assets and liabilities are recognized for temporary differences between the assets and liabilities of the tax paying entities for financial reporting and tax purposes.
	In general, legal entities that conduct business in Texas are subject to the Revised Texas Franchise Tax. In May 2006, the State of Texas expanded its pre-existing franchise tax to include limited partnerships, limited liability companies, corporations and limited liability partnerships. As a result of the change in tax law, the Partnership's tax status in the State of Texas changed from non-taxable to taxable effective with the 2007 tax year.
	Since the Partnership is structured as a pass-through entity, it is not subject to federal income taxes. As a result, its partners are individually responsible for paying federal and certain income taxes on their share of the Partnership's taxable income. Since the Partnership does not have access to information regarding each partner's tax basis, it cannot readily determine the total difference in the basis of the Partnership's net assets for financial and tax reporting purposes.
	Derivatives—Authoritative guidance establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. It requires an entity to recognize all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. The guidance provides that normal purchase and sale contracts, when appropriately designated, are not subject to the guidance. Normal purchases and sales are contracts which provide for the purchase or sale of something, other than a financial instrument or derivative instrument that will be delivered in quantities expected to be used or sold by the reporting entity over a reasonable period in the normal course of business. The Partnership's forward natural gas and crude oil purchase and sales contracts are designated as normal purchases and normal sales. The Partnership uses financial instruments such as swaps, collars and other derivatives to mitigate the risks to cash flows resulting from changes in commodity prices and interest rates. The Partnership recognizes these financial instruments on its consolidated balance sheet at the instrument's fair value with changes in fair value reflected in the consolidated statement of operations, as the Partnership has not designated any of these derivative instruments as hedges. The cash flows from derivatives are reported as cash flows from operating activities unless the derivative contract is deemed to contain a financing element. Derivatives deemed to contain a financing element are reported as a financing activity in the consolidated statement of cash flows. See Note 11 for a description of the Partnership's risk management activities.
	Other Reclassifications—Certain prior period financial statement balances have been reclassified to conform to current period presentation. These reclassifications had no effect on the recorded net income.

New_Accounting_Pronouncements

New Accounting Pronouncements	12 Months Ended
	Dec. 31, 2014
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
New Accounting Pronouncements	NEW ACCOUNTING PRONOUNCEMENTS
	In February 2013, the Financial Accounting Standards Board ("FASB") issued new guidance related to obligations resulting from joint and several liability arrangements. The new guidance provides for the recognition, measurement, and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date. The amendments in this update are effective for fiscal years, and interim periods within those years, beginning after December 15, 2013 and did not have a material impact on the Partnership’s consolidated financial statements.
	On April 10, 2014, the FASB issued new guidance which amends the definition of a discontinued operation and requires entities to provide additional disclosures about disposal transactions that do not meet the discontinued-operations criteria. Under the new guidance, a discontinued operation is defined as a disposal of a component or group of components that is disposed of or is classified as held for sale and represents a strategic shift that has or will have a major effect on an entity's operations and financial results. The new guidance is effective prospectively for all disposals (except disposals classified as held for sale before the adoption date) or components initially classified as held for sale in periods beginning on or after December 15, 2014, with early adoption permitted. The Partnership decided to early adopt this guidance in relation to its transaction to contribute its Midstream Business to Regency (see Notes 1 and 18).
	On May 28, 2014, the FASB issued new guidance related to revenue from contracts with customers. This new guidance outlines a single comprehensive model for entities to use and supersedes most current revenue recognition guidance, including industry-specific guidance. This guidance is effective for annual reporting periods (including interim reporting periods within those periods) beginning after December 15, 2016. Early application of the guidance is not permitted. The Partnership is currently evaluating the potential impact, if any, of the adoption of this new guidance on its financial statements.
	On August 27, 2014, the FASB issued new guidance on determining how to perform going concern assessments and when to disclose going concern uncertainties in the financial statements. The new guidance requires management to perform interim and annual assessments of an entity's ability to continue as a going concern within one year after the date the financial statements are issued. An entity must provide certain disclosures if conditions or events raise substantial doubt about the entity's ability to continue as a going concern. This guidance is effective for annual periods ending after December 15, 2016, with early adoption permitted. The Partnership is currently evaluating the potential impact, if any, of the adoption of this new guidance on its financial statements.

Acquisitions

Acquisitions	12 Months Ended
	Dec. 31, 2014
Business Combinations [Abstract]
Acquisitions	ACQUISITIONS
	Acquisition of Additional Working Interests
	On December 9, 2014, the Partnership acquired certain additional interests in the Big Escambia Creek Field from LP 224 LLC for approximately $10.4 million. These interests are in wells in which the Partnership currently owns significant interest and are nearly 100% operated by the Partnership. The entire purchase price was allocated to proved properties.
	Acquisition of Midstream Assets in the Texas Panhandle
	On October 1, 2012, the Partnership completed the acquisition of two of BP America Production Company's ("BP") gas processing facilities, and the associated gathering systems, that are located in the Texas Panhandle. The aggregate purchase price of the system was $230.6 million, which the Partnership funded from borrowings under its revolving credit facility. The results of the operations of the system have been included in the consolidated financial statements since the acquisition date. The Partnership incurred $0.5 million of acquisition related expenses, which are included within discontinued operations for the year ended December 31, 2012. The Partnership incurred $0.1 million of acquisition related expenses, which are included within discontinued operations for the year ended December 31, 2013.
	This acquisition was accounted for under the acquisition method of accounting. Accordingly, the Partnership conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while transaction and integration costs associated with the acquisitions were expensed as incurred. The initial accounting for the business combinations is not complete and adjustments to provisional amounts, or recognition of additional assets acquired or liabilities assumed, may occur as more detailed analyses are completed and additional information is obtained about the facts and circumstances that existed as of the acquisition dates.
	The following presents the purchase price allocation for the system assets, based on estimates of fair value (in thousands):
	Current assets	$	779
	Property, plant, and equipment	206,849
	Rights-of-way and easements	27,232
	Current liabilities	(1,705		)
	Asset retirement obligations	(2,600		)
		$	230,555
	The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair value of property, plant and equipment, rights-of-way and easements and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of property, plant and equipment include estimates of: (i) replacement costs; (ii) useful and remaining lives; (iii) physical deterioration; and (iv) functional and technical obsolescence. These inputs require significant judgments and estimates by the Partnership's management at the time of the valuation and are the most sensitive and subject to change.
	Pro forma data for the year ended December 31, 2012 has been deemed to be impracticable as BP did not separately manage its gathering and processing facilities with the activities of the acquired assets being integrated (financially and operationally) within its exploration and production segment. The amounts of revenue and net income generated by the acquired processing plants and gathering systems that are included within the Partnership's audited consolidated statement of operations for the year ended December 31, 2012 are as follows.
		Revenue			Net Income
		($ in thousands)
	Actual from October 1, 2012 to December 31, 2012	$	81,013		$	5,057
	Assets acquired and liabilities assumed as part of this acquisition have been classified as part of assets and liabilities held for sale within the audited consolidated balance sheets. Operations related to these assets have been classified as part of discontinued operations within the audited consolidated statements of operations.

Property_Plant_and_Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2014
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment Disclosure	PROPERTY, PLANT AND EQUIPMENT
	Fixed assets consisted of the following:
		December 31,			December 31,
		2014			2013
		($ in thousands)
	Equipment and machinery	$	101		$	101
	Vehicles and transportation equipment	212			212
	Office equipment, furniture, and fixtures	3,020			1,391
	Computer equipment	13,234			12,247
	Proved properties	905,622			1,156,895
	Unproved properties	7,512			10,022
	Construction in progress	1,195			6,636
		930,896			1,187,504
	Less: accumulated depreciation, depletion and amortization	(442,908		)	(363,053		)
	Net property plant and equipment	$	487,988		$	824,451
	Amounts in the table above do not include the property, plant and equipment related to the Partnership's Midstream Business, as these amounts have been classified as assets held for sale within the audited consolidated balance sheets (See Note 18).
	The following table sets forth the total depreciation, depletion and impairment expense by type of asset within the Partnership's audited consolidated statements of operations:
		Year Ended December 31,
		2014			2013			2012
		($ in thousands)
	Depreciation	$	2,971		$	2,018		$	1,795
	Depletion	$	80,810		$	87,230		$	88,413
	Impairment expense:
	Proved properties (a)	$	395,892		$	207,085		$	38,943
	Unproved properties (b)	$	—		$	7,201		$	785
	__________________________________
	(a)	During the year ended December 31, 2014, the Partnership incurred impairment charges related to certain proved properties in all of its regions due primarily to lower commodity prices, higher operating costs and lower well performance. During the year ended December 31, 2013, the Partnership incurred impairment charges related primarily to certain proved properties, primarily in the Cana Shale in the Mid-Continent region and the Permian region, due to lower reserve forecasts. During the year ended December 31, 2012, the Partnership incurred impairment charges related to its proved properties in the Barnett Shale, East Texas and Permian regions that experienced reduced cash flows resulting from lower natural gas prices and continuing high operating costs associated with gas compression.
	(b)	During the year ended December 31, 2013, the Partnership incurred impairment charges related to certain leaseholds in the Mid-Continent regions that we expected to expire undrilled in 2014. During the year ended December 31, 2012, the Partnership incurred impairment charges related to certain unproved property leaseholds expected to expire undrilled in 2013.
	The table above does not include amounts related to the Partnership's Midstream Business, as these amounts have been classified as part of discontinued operations within the audited consolidated statements of operations (see Note 18).

Asset_Retirement_Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2014
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 obligations is estimated using valuation techniques that covert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of (i) remediation costs, (ii) remaining lives, (iii) future inflation factors and (iv) a credit-adjusted risk free interest rate.
	A reconciliation of the Partnership's liability for asset retirement obligations is as follows:
		2014			2013			2012
		($ in thousands)
	Asset retirement obligations—January 1	$	48,564		$	38,991		$	26,227
	Additional liabilities	237			1,076			1,400
	Liabilities settled	(1,347		)	(2,240		)	(1,664		)
	Revision to liabilities	168			7,654			11,146
	Accretion expense	3,251			3,083			1,882
	Asset retirement obligations—December 31 (a)	$	50,873		$	48,564		$	38,991
	_____________________________________
	(a)    As of December 31, 2014 and 2013, $3.0 million and $11.3 million, respectively, were included within accrued liabilities in the audited consolidated balance sheets.
	The table above does not include the balances or activity related to asset retirement obligations related to the Partnership's Midstream Business, as these amounts have been classified as liabilities held for sale within the audited consolidated balance sheets and discontinued operations within the audited consolidated statements of operations (see Note 18).

Intangible_Assets

Intangible Assets	12 Months Ended
	Dec. 31, 2014
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:
		December 31,			December 31,
		2014			2013
		($ in thousands)
	Rights-of-way and easements—at cost	$	3,920		$	3,920
	Less: accumulated amortization	(848		)	(652		)
	Net intangible assets	$	3,072		$	3,268
	Amounts in the table above do not include the intangible assets related to the Partnership's Midstream Business, as these amounts have been classified as assets held for sale within the audited consolidated balance sheets (See Note 18).
	The following table sets forth the total amortization expense within the Partnership's audited consolidated statements of operations:
		Year Ended December 31,
		2014			2013			2012
		($ in thousands)
	Amortization	$	196		$	196		$	302
	The table above does not include amounts related to the Partnership's Midstream Business, as these amounts have been classified as part of discontinued operations within the audited consolidated statements of operations (see Note 18).
	Estimated future amortization expense related to the intangible assets at December 31, 2014, is as follows (in thousands):
	Year ending December 31,
	2015	$	196
	2016	$	196
	2017	$	196
	2018	$	196
	2019	$	196
	Thereafter	$	2,092
	The table above does not included amounts related to the Partnership's Midstream Business, as amortization expense ceases once assets have been classified as held for sale.

Long_Term_Debt

Long Term Debt	12 Months Ended
	Dec. 31, 2014
Long-term Debt, by Current and Noncurrent [Abstract]
Long-term Debt [Text Block]	LONG-TERM DEBT
	Long-term debt consisted of the following:
		December 31,			December 31,
		2014			2013
		($ in thousands)
	Revolving credit facility:	$	212,600		$	706,800
	Senior Notes:
	8.375% Senior Notes due 2019	51,120			51,120
	Unamortized bond discount	(377		)	(440		)
	Total Senior Notes	50,743			50,680
	Total long-term debt	$	263,343		$	757,480
	Amounts in the table above do not include the portion of the Senior Notes that were exchanged for Regency unsecured senior notes upon the completion of the Midstream Business Contribution on July 1, 2014 (see Note 1). These notes have been classified as part of liabilities held for sale within the unaudited condensed consolidated balance sheet for December 31, 2013 and were exchanged on July 1, 2014 (see Note 18).
	On July 1, 2014, the Partnership used the cash received from Regency for the Midstream Business Contribution (see Note 1) to paydown $570.4 million outstanding under its Credit Agreement.
	Revolving Credit Facility
	On October 10, 2014, the Partnership entered into the Fifth Amendment (the "Fifth Amendment") to its Amended and Restated Credit Agreement (as amended, the "Credit Agreement"). The Fifth Amendment, among other items, provided for current commitments totaling $320 million , with the ability to increase commitments up to a total aggregate amount of $1.2 billion. The Fifth Amendment coincided with the semi-annual borrowing base redetermination by the Partnership's commercial lenders, and the next redetermination will be in April 2015. The amendment extended the maturity to October 2019. In addition, as a result of the completion of the Midstream Business contribution, the Partnership's borrowing base under the Credit Agreement is now strictly based on the value of its oil and natural gas properties and its commodity derivative contracts, which was formerly referred to as the upstream component of the borrowing base.
	In connection with the Credit Agreement, the Partnership incurred debt issuance costs of $1.6 million and recorded a charge of $0.6 million to write off a portion of the unamortized debt issuance costs related to the Prior Credit Agreement. As of December 31, 2014, the Partnership had unamortized debt issuance costs of $4.6 million.
	As of December 31, 2014, the Partnership had approximately $107.4 million of availability under the credit facility based on its borrowing base on that date. The Partnership currently pays a 0.50% commitment fee (based on the Partnership's borrowing base utilization percentage) per year on the difference between total commitments and the amount drawn under the credit facility. The Credit Agreement includes a sub-limit for the issuance of standby letters of credit for a total of $50.0 million. As of December 31, 2014, the Partnership had no outstanding letters of credit.
	At the Partnership's election, interest will accrue on the credit facility at either LIBOR plus a margin ranging from 1.50% to 2.50% (currently 2.00% per annum based on the Partnership's borrowing base utilization percentage) or the base rate plus a margin ranging from 0.50% to 1.50% (currently 1.00% per annum based on the Partnership's borrowing base utilization percentage). The applicable margin is determined based on the utilization of the then existing borrowing base. The borrowings under the Credit Agreement may be prepaid, without any premium or penalty, at any time. The base rate is generally the highest of the federal funds rate plus 0.5%, the prime rate as announced from time to time by the Administrative Agent, or daily LIBOR for a term of one month plus 1.0%. As of December 31, 2014, the weighted average interest rate (excluding the impact of interest rate swaps) on the Partnership's outstanding debt under its revolving credit facility was 2.17%.
	The obligations under the Credit Agreement are secured by first priority liens on substantially all of the Partnership’s material assets, including a pledge of all of the equity interests of each of the Partnership’s material subsidiaries, but excluding the equity interests in Regency owned by the Partnership and the sales proceeds thereof.
	The Credit Agreement requires the Partnership and certain of its subsidiaries to make certain representations and warranties that are customary for credit facilities of this type. The Credit Agreement also contains affirmative and negative covenants that are customary for credit facilities of this type, including compliance with financial covenants. The financial covenants prohibit the Partnership from exceeding defined limits with respect to:
	•	As of any fiscal quarter-end, the ratio of Total Funded Indebtedness (as defined in the Credit Agreement) to Consolidated EBITDA for the four fiscal quarter period ending with such fiscal quarter (the “Total Leverage Ratio”).; and
	•	As of any fiscal quarter-end the ratio of the Partnership’s consolidated current assets (including availability under the Credit Agreement up to the Loan Limit (as defined within the Credit Agreement), but excluding non-cash assets under the accounting guidance for derivatives) to consolidated current liabilities (excluding non-cash obligations under the accounting guidance for derivatives and current maturities under the Credit Agreement) (the “Current Ratio”).
	The following table presents the debt covenant levels specified in our revolving credit facility as of December 31, 2014:
	Quarter Ended	Total Leverage Ratio(a)	Current Ratio(b)
	December 31, 2014 and Thereafter until Maturity (October 2019)	4	1
	_____________________
	(a)	Amount represents the maximum ratio for the period presented.
	(b)	Amount represents the minimum ratio for the period presented.
	The following table presents our actual covenant ratios as of December 31, 2014:
	Total leverage ratio	2.2
	Current ratio	5.2
	As of December 31, 2013, the Partnership was in compliance with the financial covenants under the Credit Agreement.
	Senior Notes
	On May 27, 2011 and July 13, 2012, the Partnership, along with its subsidiary, Eagle Rock Energy Finance Corp. ("Finance Corp"), as co-issuer and certain subsidiary guarantors, issued $300.0 million and $250.0 million, respectively, of senior unsecured notes (the "Senior Notes"), that bear a coupon of 8.375%, through private placement and all of which are treated as a single series. The Senior Notes will mature on June 1, 2019, and interest is payable on each June 1 and December 1. After the original discount of $2.2 million and $3.7 million, respectively, and excluding related offering expenses, the Partnership received net proceeds of approximately $297.8 million and $246.3 million, respectively, which were used to repay borrowings outstanding under its revolving credit facility.
	As of December 31, 2014, the Partnership had unamortized debt issuance costs of $0.8 million and an unamortized debt discount of $0.4 million, which is recorded as an offset to the principal amount of the Senior Notes. As discussed above and within Note 1, a portion of the Senior Notes have been classified as part of liabilities held for sale within the audited consolidated balance sheets (see Note 18).
	The Senior Notes are general unsecured senior obligations and rank equally in right of payment with all of the Partnership's existing and future senior indebtedness and rank senior in right of payment to any of the Partnership's future subordinated indebtedness. The Senior Notes are effectively junior in right of payment to all of the Partnership's existing and future secured indebtedness and other obligations, including borrowings outstanding under the Partnership's Credit Agreement, to the extent of the value of the assets securing such indebtedness and other obligations. The Senior Notes are jointly and severally guaranteed on a senior unsecured basis by the Partnership's existing and future subsidiaries, who are referred to as the "subsidiary guarantors," that guarantee the Partnership's credit facility or other indebtedness.
	As discussed in Note 1, the consideration received by the Partnership for the Midstream Business Contribution included the exchange of $498.9 million face amount of the Partnership's Senior Notes for an equivalent amount of Regency unsecured senior notes. $51.1 million of the Partnership's Senior Notes did not exchange and remain outstanding under an amended indenture with substantially all of the restrictive covenants and certain events of default eliminated.
	The Partnership has the option to redeem all or a portion of the Senior Notes at any time on or after June 1, 2015 at the redemption prices specified in the indenture plus accrued and unpaid interest. The Partnership may also redeem the Senior Notes, in whole or in part, at a "make-whole" redemption price specified in the indenture, plus accrued and unpaid interest, at any time prior to June 1, 2015.
	Scheduled maturities of long-term debt as of December 31, 2014, were as follows:
		Principal Amount
		($ in thousands)
	2015	$	—
	2016	—
	2017	—
	2018	—
	2019	263,720
	2020 and after	—
		$	263,720

Members_Equity

Members' Equity	12 Months Ended
	Dec. 31, 2014
Partners' Capital [Abstract]
Members' Equity	MEMBERS’ EQUITY
	At December 31, 2014, there were 150,154,909 common units outstanding. In addition, there were 2,419,750 unvested restricted common units outstanding.
	On June 1, 2010, the Partnership launched its rights offering to the holders of its common and general partner units as of close of business on May 27, 2010, the record date. Each Right entitled the holder (including holders of Rights acquired during the subscription period) to purchase (i) one common unit and (ii) one warrant to purchase one additional common unit at $6.00 on certain specified days beginning on August 15, 2010 and ending on May 15, 2012. During the years ended December 31, 2013 and 2012 5,300,588 and 14,957,540 warrants, respectively, were exercised for an equivalent number of newly issued common units. The final exercise date for the warrants was May 15, 2012, and on that date the remaining unexercised warrants expired.
	On May 31, 2012, the Partnership announced a program through which it may issue common units, from time to time, with an aggregate market value of up to $100 million. The Partnership is under no obligation to issue equity under the program. During the year ended December 31, 2014, no units were issued under this program. As of December 31, 2014, 686,759 units had been issued under this program for net proceeds of approximately $5.6 million.
	On August 17, 2012, the Partnership closed an underwritten public offering of 10,120,000 common units, which included the full exercise of the underwriters' option to purchase additional common units to cover over-allotments, for net proceeds of approximately $84.3 million.
	On March 12, 2013, the Partnership closed an underwritten public offering of 10,350,000 common units for net proceeds of approximately $92.3 million.
	On October 27, 2014, the Partnership announced that the Board of Directors authorized a common unit repurchase program of up to $100 million through which repurchases may be made from time to time at prevailing prices on the open market or in privately negotiated transactions. The program was authorized to commence following the filing of the Partnership's Quarterly Report on Form 10-Q for the quarter ending September 30, 2014 and will conclude by March 31, 2016. The repurchase program does not obligate the Partnership to acquire any, or any specific number of, units and may be discontinued at any time. The Partnership intends to cancel any units it repurchases under the repurchase program. As of December 31, 2014, the Partnership had repurchased a total of 7,455,887 of its common units under this program for approximately $19.2 million, of which, transactions to repurchase 641,400 units had not settled as of December 31, 2014 and for which a liability of $1.3 million was recorded as part of accounts payable in the consolidated balance sheet.
	The table below summarizes the distributions paid or payable for the last three years
	Quarter Ended		Distribution		Record Date**	Payment Date
			per Unit
	March 31, 2012+		$	0.22	May 8, 2012	May 15, 2012
	June 30, 2012+		$	0.22	August 7, 2012	August 14, 2012
	September 30, 2012+		$	0.22	November 7, 2012	November 14, 2012
	December 31, 2012+		$	0.22	February 7, 2013	February 14, 2013
	March 31, 2013+*		$	0.22	May 7, 2013	May 15, 2013
	June 30, 2013+*		$	0.22	August 7, 2013	August 14, 2013
	September 30, 2013+*		$	0.15	November 7, 2013	November 14, 2013
	December 31, 2013+*		$	0.15	February 7, 2014	February 14, 2014
	March 31, 2014***		$	—	N/A	N/A
	June 30, 2014***		$	—	N/A	N/A
	September 30, 2014+*		$	0.07	November 7, 2014	November 14, 2014
	December 31, 2014+*		$	0.07	February 6, 2015	February 13, 2015
	_____________________________
	+	The distribution per unit represents distributions made only on common units, including restricted common units issued under our Long Term Incentive Plan ("LTIP"). Since July 30, 2010, the only other class of equity we have outstanding is a non-economic general partner interest.
	*	The distribution excludes certain restricted units under the LTIP.
	**	The "Record Date" set forth in the table above means the close of business on each of the listed Record Dates.
	***	No distribution was declared or paid for this period.

Related_Party_Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2014
Related Party Transactions [Abstract]
Related Party Transactions	RELATED PARTY TRANSACTIONS
	The following table summarizes transactions between the Partnership and certain affiliated entities:
		Year Ended December 31,
		2014		2013		2012
	Affiliates of Natural Gas Partners:	($ in thousands)
	Natural gas purchases from affiliates	$	2,091	$	2,938	$	2,713
	Payable as of December 31 (related to natural gas purchases)	$	—	$	18	$	428
	The transactions above are all related to the Partnership's Midstream Business and have been classified as part of discontinued operations within the consolidated statements of operations and liabilities held for sale within the consolidated balance sheet (see Note 18).
	In connection with the closing of the acquisition of certain fee minerals, royalties, overriding royalties and non-operated working interest properties from Montierra Minerals & Production, L.P. ("Montierra") and NGP-VII Co-Investment Opportunities, L.P. ("Co-Invest") on April 30, 2007, the Partnership entered into registration rights agreements with Montierra and Co-Invest. In the registration rights agreements, the Partnership agreed, for the benefit of Montierra and Co-Invest, to register the common units it holds, the common units issuable upon conversion of the subordinated units that it holds and any common units or other equity securities issuable in exchange for the common units and subordinated units it holds. The registration rights agreement is still in effect and the Partnership is in compliance with all obligations of the agreement.
	In connection with the closing of the acquisition of all of the outstanding members interests of CC Energy II L.L.C. (together with its subsidiaries, "Crow Creek Energy"), a portfolio company of Natural Gas Partners, VIII, L.P. ("NGP VIII"), the Partnership entered into a registration rights agreement ("Registration Rights Agreement") with NGP VIII. The Registration Rights Agreement grants NGP VIII and certain of its affiliates registration rights with respect to the common units acquired pursuant to the Partnership's acquisition of Crow Creek Energy and their outstanding warrants to purchase common units that were previously acquired by NGP VIII and certain of its affiliates in connection with the Partnership's previously completed recapitalization transaction. Pursuant to the Registration Rights Agreement, NGP VIII and certain of its affiliates have the ability to demand that the Partnership register for resale their common units acquired pursuant to the acquisition of Crow Creek Energy and their existing warrants to purchase common units. This registration may be an underwritten offering at the discretion of NGP VIII and certain of its affiliates. NGP VIII and certain of its affiliates may demand up to four such registrations, subject to an increase to up to seven if the registration rights are amended. Additionally, the Registration Rights Agreement provides that NGP VIII and certain of its affiliates have piggyback registration rights in certain circumstances, which would require inclusion of their common units and warrants on registration statements that the Partnership files, subject to certain customer exceptions. There are no limits on the number of times NGP VIII and certain of its affiliates can exercise these piggyback registration rights.

Risk_Management_Activities

Risk Management Activities	12 Months Ended
	Dec. 31, 2014
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 12).  Changes in fair values of the interest rate derivative instruments are recorded as an adjustment to the mark-to-market gains (losses) on risk management transactions within other income (expense).
	In November 2014, to align its interest rate swaps with the amendment to its revolving credit facility (see Note 8), the Partnership entered into the following transaction,
	•	Reduced the notional value of its interest rate swaps from $250 million to $175 million;
	•	Extended the original maturity date of June 22, 2015 to a new maturity date of December 31, 2019; and
	•	Blended the existing swap rate for this extended swap with the then prevailing interest rate swap rate, which lowered the rate from 2.95% to 2.3195%.
	There was no cost associated with this transaction.
	The following table sets forth certain information regarding the Partnership's various interest rate swaps as of December 31, 2014:
	Effective Date		Expiration		Notional			Fixed
			Date		Amount			Rate
	12/31/14		12/31/19		$	175,000,000		2.3195	%
	Commodity Derivative Instruments - Corporate
	The prices of crude oil, natural gas and NGLs are subject to fluctuations in response to changes in supply, demand, market uncertainty and a variety of additional factors which are beyond the Partnership's control.  These risks can cause significant changes in the Partnership's cash flows and affect its ability to achieve its distribution objectives and comply with the covenants of its revolving credit facility.  In order to manage the risks associated with changes in the future prices of crude oil, natural gas and NGLs on its forecasted equity production, the Partnership engages in risk management activities that take the form of commodity derivative instruments.  The Partnership has determined that it is necessary to hedge a substantial portion of its expected production in order to meaningfully reduce its future cash flow volatility.  The Partnership generally limits its hedging levels to less than its total expected future production. While hedging at this level of production does not eliminate all of the volatility in the Partnership's cash flows, it allows the Partnership to mitigate the risk of situations where a modest loss of production would not put it in an over-hedged position.  At times, the Partnership's strategy may involve entering into hedges with strike prices above current future prices or resetting existing hedges to higher price levels in order to meet its cash flow objectives or to stay in compliance with the covenants under its revolving credit facility.  In addition, the Partnership may also terminate or unwind hedges or portions of hedges when the expected future volumes do not support the level of hedges.  Expected future production for its Upstream Business is derived from the proved reserves, adjusted for price-dependent expenses and revenue deductions.  The Partnership applies the appropriate contract terms to these projections to determine its expected future equity share of the commodities.
	The Partnership uses fixed-price swaps, costless collars and put options to achieve its hedging objectives. Historically, the Partnership has hedged its expected future commodity volumes either with derivatives of the same commodity ("direct hedges") or with derivatives of another commodity which the Partnership expects will correlate well with the underlying commodity ("proxy hedges"). For example, the Partnership will often hedge the changes in future NGL prices using crude oil hedges because NGL prices have been highly correlated to crude oil prices and hedging NGLs directly is usually less attractive due to the relative illiquidity in the NGL forward market. The Partnership may use natural gas hedges to hedge a portion of its expected future ethane production because forward prices for ethane are often heavily discounted from its current prices. Also, natural gas prices provide support for ethane prices because in many processing plants ethane can be recombined with the residue gas stream and sold as natural gas. When the Partnership uses proxy hedges, it converts the expected volumes of the underlying commodity to equivalent volumes of the hedged commodity. In the case of NGLs hedged with crude oil derivatives,
	these conversions are based on the historical relationship of the prices of the two commodities and management's judgment
	regarding future price relationships of the commodities. In the case where ethane is hedged with natural gas derivatives, the
	conversion is based on the thermal content of ethane. In recent quarters, the correlation of price changes in crude oil and NGLs
	has weakened relative to longer-term averages as NGL prices have fallen while crude index prices have risen. This dynamic has
	negatively impacted our hedging objectives
	For accounting purposes, the Partnership has not designated any of its commodity derivative instruments as hedges; instead it marks these derivative contracts to fair value (see Note 12).  Changes in fair values of the commodity derivative instruments are recorded as an adjustment to the mark-to-market gains (losses) on risk management transactions within revenue.
	By using derivative instruments to economically hedge exposure to changes in commodity prices, the Partnership exposes itself to counterparty credit risk. Historically, the Partnership's corporate derivative counterparties have all been participants or affiliates of participants within its revolving credit facility (see Note 8), which is secured by substantially all of the assets of the Partnership. Therefore, the Partnership is not currently required to post any collateral, nor does it require collateral from its counterparties. The Partnership minimizes the credit risk in derivative instruments by limiting exposure to any single counterparty and monitoring the creditworthiness of its counterparties on an ongoing basis. In addition, the Partnership's derivative contracts for certain counterparties are subject to counterparty netting agreements governing such derivatives, and when possible, the Partnership nets the open positions of each counterparty. See Note 12 for the impact to the Partnership's audited consolidated balance sheets of the netting of these derivative contracts.
	The Partnership's commodity derivative counterparties as of December 31, 2014, included Wells Fargo Bank N.A., Comerica Bank, Bank of America Merrill Lynch, ING Capital Markets LLC, Regions Financial Corporation and CITIBANK, N.A.
	The following tables set forth certain information regarding the Partnership's commodity derivatives. Within the table, some trades of the same commodities with the same tenors have been aggregated and shown as weighted averages.
	Commodity derivatives, as of December 31, 2014, that will mature during the years ended December 31, 2015, 2016, 2017, 2018 and 2019:
	Underlying		Type		Notional		Floor				Cap
					Volumes		Strike				Strike
					(units) (a)		Price				Price
							($/unit)(b)				($/unit)(b)
	Portion of Contracts Maturing in 2015
	Natural Gas		Swap (Pay Floating/Receive Fixed)		10,800,000		$	4.07
	Crude Oil		Costless Collar		480,000		$	90			$	97.55
	Crude Oil		Swap (Pay Floating/Receive Fixed)		630,000		$	89.78
	Portion of Contracts Maturing in 2016
	Natural Gas		Swap (Pay Floating/Receive Fixed)		9,480,000		$	4.25
	Crude Oil		Swap (Pay Floating/Receive Fixed)		936,000		$	84.66
	Portion of Contracts Maturing in 2017
	Crude Oil		Swap (Pay Floating/Receive Fixed)		444,000		$	89.24
	Portion of Contracts Maturing in 2018
	Crude Oil		Swap (Pay Floating/Receive Fixed)		396,000		$	88.78
	Portion of Contracts Maturing in 2019
	Crude Oil		Swap (Pay Floating/Receive Fixed)		348,000		$	88.39
	_______________________
	(a)	Volumes of natural gas are measured in MMbtu, volumes of crude oil are measured in barrels, and volumes of natural gas liquids are measured in gallons.
	(b)	Amounts represent the weighted average price. The weighted average prices are in $/MMbtu for natural gas, $/barrel for crude oil and $/gallon for natural gas liquids.
	Commodity Derivative Instruments - Marketing & Trading
	Prior to the consummation of the Midstream Business Contribution, the Partnership conducted natural gas marketing and trading activities intended to capitalize on favorable price differentials between various receipt and delivery locations. This business was contributed to Regency as part of the Midstream Business Contribution completed on July 1, 2014. The assets and liabilities associated with this business have been classified as held for sale within the consolidated balance sheets and the operations as discontinued within the consolidated statements of operations (see Note 18).
	Fair Value of Interest Rate and Commodity Derivatives
	Fair values of interest rate and commodity derivative instruments not designated as hedging instruments in the consolidated balance sheet as of December 31, 2014 and December 31, 2013:
		As of
		31-Dec-14
		Derivative Assets					Derivative Liabilities
		Balance Sheet Classification		Fair Value			Balance Sheet Classification		Fair Value
		($ in thousands)
	Interest rate derivatives - liabilities	Current assets		$	(3,165	)	Current liabilities		$	—
	Interest rate derivatives - liabilities	Long-term assets		(2,641		)	Long-term liabilities		—
	Commodity derivatives - assets	Current assets		47,971			Current liabilities		—
	Commodity derivatives - assets	Long-term assets		49,130			Long-term liabilities		—
	Commodity derivatives - assets	Assets held for sale		—			Liabilities held for sale		—
	Commodity derivatives - liabilities	Current assets		—			Current liabilities		—
	Commodity derivatives - liabilities	Long-term assets		—			Long-term liabilities		—
	Commodity derivatives - liabilities	Assets held for sale		—			Liabilities held for sale		—
	Total derivatives			$	91,295				$	—
	As of
	31-Dec-13
	Derivative Assets					Derivative Liabilities
	Balance Sheet Classification		Fair Value			Balance Sheet Classification		Fair Value
	($ in thousands)
Interest rate derivatives - liabilities	Current assets		$	—		Current liabilities		$	(6,210	)
Interest rate derivatives - liabilities	Long-term assets		—			Long-term liabilities		(2,885		)
Commodity derivatives - assets	Current assets		6,841			Current liabilities		1,043
Commodity derivatives - assets	Long-term assets		4,669			Long-term liabilities		202
Commodity derivatives - assets	Assets held for sale		6,017			Liabilities held for sale		1,973
Commodity derivatives - liabilities	Current assets		(1,282		)	Current liabilities		(3,193		)
Commodity derivatives - liabilities	Long-term assets		(798		)	Long-term liabilities		(143		)
Commodity derivatives - liabilities	Assets held for sale		(824		)	Liabilities held for sale		(5,658		)
Total derivatives			$	14,623				$	(14,871	)
The following table sets forth the location of gains and losses for derivatives not designated as hedging instruments within the Partnership's audited consolidated statement of operations (in thousands):
Amount of Gain (Loss) Recognized in Income on Derivatives			Year Ended December 31,
			2014			2013				2012
Interest rate derivatives	Interest rate risk management losses, net		$	(1,734	)	$	(1,104	)		$	(4,727	)
Commodity derivatives	Commodity risk management gains (losses), net		94,431			(3,937		)		28,110
Commodity derivatives	Discontinued operations		(15,477		)	(14,596		)		29,784
Commodity derivatives -trading	Discontinued operations		(2,404		)	315				(192		)
	Total		$	74,816		$	(19,322	)		$	52,975

Fair_Value_of_Financial_Instru

Fair Value of Financial Instruments	12 Months Ended
	Dec. 31, 2014
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 December 31, 2014, the Partnership has recorded its interest rate swaps and commodity derivative instruments (see Note 11), which includes crude oil, natural gas and NGLs, at fair value. The Partnership reviews the classification of the inputs at the end of each period and has classified the inputs to measure the fair value of its interest rate swaps, crude oil derivatives and natural gas derivatives as Level 2. In addition, the Partnership recorded its investments in equity securities at fair value, and classified the inputs as Level 1.
	The following table discloses the fair value of the Partnership's derivative instruments and equity investments as of December 31, 2014 and 2013:
		As of
		31-Dec-14
		Level 1		Level 2			Level 3		Netting (a)			Total
		($ in thousands)
	Assets:
	Crude oil derivatives	$	—	$	78,516		$	—	$	—		$	78,516
	Natural gas derivatives	—		18,585			—		—			18,585
	Interest rate swaps	—		—			—		(5,806		)	(5,806		)
	Equity investments	153,448		—			—		—			153,448
	Total	$	153,448	$	97,101		$	—	$	(5,806	)	$	244,743
	Liabilities:
	Interest rate swaps	$	—	$	(5,806	)	$	—	$	5,806		$	—
	Total	$	—	$	(5,806	)	$	—	$	5,806		$	—
	____________________________
	(a)	Represents counterparty netting under agreement governing such derivative contracts.
		As of
		31-Dec-13
		Level 1		Level 2			Level 3		Netting (a)			Total
		($ in thousands)
	Assets:
	Crude oil derivatives	$	—	$	6,151		$	—	$	(1,716	)	$	4,435
	Natural gas derivatives	—		6,562			—		(1,567		)	4,995
	NGL derivatives	—		42			—		(42		)	—
	Total	$	—	$	12,755		$	—	$	(3,325	)	$	9,430
	Liabilities:
	Crude oil derivatives	$	—	$	(1,792	)	$	—	$	1,716		$	(76	)
	Natural gas derivatives	—		(2,503		)	—		1,567			(936		)
	NGL derivatives	—		(1,121		)	—		42			(1,079		)
	Interest rate swaps	—		(9,095		)	—		—			(9,095		)
	Total	$	—	$	(14,511	)	$	—	$	3,325		$	(11,186	)
	____________________________
	(a)	Represents counterparty netting under agreement governing such derivative contracts.
	The tables above do not include the fair value of the derivative contracts that have been classified as assets and liabilities held for sale within the audited consolidated balance sheet (see Note 18).
	Gains and losses, from continuing operations, related to the interest rate derivatives are recorded as part of interest rate risk management gains and losses in the audited consolidated statements of operations.  Gains and losses, from continuing operations, related to the Partnership's commodity derivatives are recorded as a component of revenue in the audited consolidated statements of operations.
	Gains and losses associated with our short-term investments considered to be other than temporary are recorded in the audited consolidated statements of operations.
	Fair Value of Assets and Liabilities Measured on a Non-recurring Basis
	For periods in which impairment charges have been incurred, the Partnership is required to write down the value of the
	impaired asset to its fair value. See Note 5 for a further discussion of the impairment charges recorded during the year ended December 31, 2014. The following table discloses the fair value of the Partnership's assets measured at fair value on a nonrecurring basis for the year ended December 31, 2014:
		December 31,		Level 1			Level 2		Level 3			Total Losses
		2014
		($ in thousands)
	Proved properties	$	305,006	$	—		$	—	$	305,006		$	395,892
	Plant assets	$	52	$	—		$	—	$	52		$	132
	Pipeline assets	$	746	$	—		$	—	$	746		$	1,904
	Rights-of-way	$	24	$	—		$	—	$	24		$	61
	The plant, pipeline and rights-of-way assets and related impairment losses included in the table above are all attributable to the Partnership's Midstream Business and have been classified as discontinued operations within the consolidated statement of operations (see Note 18).
	The Partnership calculated the fair value of the impaired assets using discounted cash flow analysis to determine the excess of the asset's carrying value over its fair value. Significant inputs to the valuation of fair value of the proved properties, plant, pipeline and intangible assets includes estimates of (i) future cash flows, including revenue, expenses and capital expenditures, (ii) timing of cash flows, (iii) forward commodity prices, adjusted for estimated location differentials, as of the impairment date and (iv) a discount rate reflective of the Partnership's cost of capital.
	The carrying amount of cash equivalents is believed to approximate their fair values because of the short maturities of these instruments. The fair value of accounts receivable and accounts payable are not materially different from their carrying amounts because of the short-term nature of these instruments.
	As of December 31, 2014, the outstanding debt associated with the Credit Agreement bore interest at a floating rate; as such, the Partnership believes that the carrying value of this debt approximates its fair value. The outstanding debt associated with the Senior Notes bore interest at a fixed rate; based on the market price of the Senior Notes as of December 31, 2014 and 2013, the Partnership estimates that the fair value of the Senior Notes, including amounts classified as held for sale, was $47.0 million and $599.5 million, respectively. Fair value of the senior notes was estimated based on prices quoted from third-party financial institutions, which are characteristic of Level 2 fair value measurement inputs.

Commitments_and_Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	COMMITMENTS AND CONTINGENT LIABILITIES
	Litigation—The Partnership and its operating subsidiaries are subject to lawsuits which arise from time to time in the ordinary course of business. The Partnership had no accruals as of December 31, 2014 and 2013 related to legal matters and current lawsuits are not expected to have a material adverse effect on our financial position, results of operations or cash flows. Lawsuits the Partnership and/or its operating subsidiaries were subject to relating to the Partnership's midstream business were assumed by Regency on July 1, 2014 as part of the Midstream Business Contribution.
	In March and April 2014, alleged unitholders of the Partnership filed three class action lawsuits in the United States District Court for the Southern District of Texas on behalf of the Partnership's public unitholders.  Plaintiffs in each lawsuit alleged a variety of causes of action challenging the Midstream Business Contribution, including alleged breaches of fiduciary or contractual duties, alleged aiding and abetting these alleged breaches of duty, and alleged violations of the Securities Exchange Act of 1934 (the "Exchange Act"). The plaintiffs sought to have the sale rescinded and receive monetary damages and attorneys’ fees. In August 2014, the court consolidated the lawsuits into an action styled In re Eagle Rock Energy Partners, L.P. Securities Litigation and appointed a lead plaintiff and co-lead counsel. On November 19, 2014, the court dismissed the action without prejudice.
	Insurance—The Partnership covers its operations and assets with insurance which management believes is consistent with that in force for other companies engaged in similar commercial operations with similar type properties.  This insurance includes: (1) commercial general liability insurance covering liabilities to third parties for bodily injury, property damage and pollution arising out of the Partnership's operations; (2) workers’ compensation liability coverage for employees to required statutory limits; (3) automobile liability insurance covering liability to third parties for bodily injury and property damage arising out of the operation of all owned, hired and non-owned vehicles by its employees on company business; (4) property insurance covering the replacement cost of all owned real and personal property, including coverage for losses due to boiler and machinery breakdown, earthquake, flood and consequent business interruption/extra expense; (5) control of well/operator's extra expense insurance for operated and non-operated wells; and (6) corporate liability insurance including coverage for directors and officers and employment practices liabilities.  In addition, the Partnership maintains excess liability insurance providing limits in excess of the established primary limits for commercial general liability and automobile liability insurance.
	All coverages are subject to industry accepted policy terms, conditions, limits and deductibles comparable to that obtained by other energy companies with similar operations. The cost of insurance for the energy industry continued to fluctuate over the past year, reflecting the changing conditions in the insurance markets.
	Environmental—Our business involves acquiring, developing and producing oil and natural gas working interests, and certain associated gathering and processing activities for our interests in Alabama.  Our operations and those of our lease operators are subject to stringent and complex federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection or safety. The Partnership must comply with United States laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste management and disposal and other environmental matters. The cost of developing and producing our oil and natural gas working interests, as well as planning, designing and operating our associated processing facility in Alabama, must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements and the issuance of injunctions or restrictions on operation. Management believes that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on the Partnership's combined results of operations, financial position or cash flows. At December 31, 2014 and 2013, the Partnership had accrued approximately $2.8 million and $2.5 million, respectively, for environmental matters. As of July 1, 2014, in connection with the Midstream Business Contribution, Regency agreed to indemnify the Partnership for losses arising from the Midstream Business, including potential losses associated with these laws and regulations and the Partnership agreed to use commercially reasonable efforts to mitigate such losses. Environmental accruals related to the Partnership's Midstream Business have been classified as liabilities held-for-sale within the consolidated balance sheet (see Note 18).
	Retained Revenue Interest—Certain of the Partnership's assets are subject to retained revenue interests.  These interests were established under purchase and sale agreements that were executed by the Partnership's predecessors in title.  The terms of these agreements entitle the owners of the retained revenue interests to a portion of the revenues received from the sale of the hydrocarbons above specified base oil and natural gas prices.  These retained revenue interests do not represent a real property interest in the hydrocarbons.  The Partnership's reported revenues are reduced to account for the retained revenue interests on a monthly basis.
	The retained revenue interests affect the Partnership's interest at the Big Escambia Creek, Flomaton and Fanny Church fields in Escambia County, Alabama. With respect to the Partnership's Flomaton and Fanny Church fields, these retained revenue interests are in effect for any calendar year in which the Partnership surpasses certain average net production rates. The Partnership did not surpass such rates in 2014 and does not anticipate exceeding these rates in future years. With respect to the Partnership's Big Escambia Creek field, the retained revenue interest commenced in 2010 and continues through the end of 2019.
	Other Commitments—The Partnership utilizes assets under operating leases for its corporate office, certain rights-of-way and facilities locations, vehicles and in several areas of its operations. Rental expense from continuing operations, including leases with no continuing commitment, amounted to approximately $2.6 million, $2.4 million and $3.8 million for the years ended December 31, 2014, 2013 and 2012, respectively. Rental expense for leases with escalation clauses is recognized on a straight-line basis over the initial lease term.
	At December 31, 2014, commitments under long-term non-cancelable operating leases for the next five years are as follows (in thousands):
	Year ending December 31,
	2015	$	5,853
	2016	$	3,899
	2017	$	2,799
	2018	$	438
	2019	$	—

Employee_Benefit_Plan

Employee Benefit Plan	12 Months Ended
	Dec. 31, 2014
Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]
Pension and Other Postretirement Benefits Disclosure [Text Block]	EMPLOYEE BENEFIT PLAN
	The Partnership offers a defined contribution benefit plan to its employees. For the three years ended December 31, 2014, the plan provided for a dollar for dollar matching contribution by the Partnership of up to 4% of an employee's contribution and 50% of additional contributions up to an additional 2%. Additionally, the Partnership may, at its sole discretion and election, contribute up to 6% of a participating employee's base salary annually, subject to vesting requirements. Expenses under the plan for the years ended December 31, 2014, 2013 and 2012 were approximately $1.1 million, $1.2 million and $0.8 million, respectively.

Income_Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Income Taxes	INCOME TAXES
	The Partnership's provision for income taxes relates to (i) state taxes for the Partnership and (ii) federal taxes for Eagle Rock Energy Acquisition Co., Inc, (acquiring entity of Redman Energy Holdings, L.P. and Redman Energy Holdings II, L.P. and certain assets owned by NGP Income Co-Investment Opportunities Fund II, L.P. (collectively the "Redman Acquisition") in 2007)  and Eagle Rock Energy Acquisition Co. II, Inc. (acquiring entity of certain entities acquired in the Stanolind Acquisition in 2008) and their wholly owned corporations, Eagle Rock Upstream Development Company, Inc., (successor entity of certain entities acquired in the Redman acquisition) and Eagle Rock Upstream Development Company II, Inc. (successor entity of certain entities acquired in the Stanolind acquisition), which are subject to federal income taxes (the “C Corporations”).   In addition, the Partnership has become a taxable entity in the state of Texas. On May 18, 2006, the State of Texas enacted House Bill 3 which revised the pre-existing state franchise tax. In general, legal entities that conduct business in Texas are subject to the Revised Texas Franchise Tax, including previously non-taxable entities such as limited partnerships and limited liability partnerships. The tax is assessed on Texas sourced taxable margin which is defined as the lesser of (i) 70% of total revenue or (ii) total revenue less (a) cost of goods sold or (b) compensation and benefits. Although the bill states that the Revised Texas Franchise Tax is not an income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers both revenues and expenses.
	The Partnership's federal and state income tax provision is summarized below (in thousands):
		For the Year Ended December 31,
		2014			2013			2012
	Current:
	Federal	$	(475	)	$	(105	)	$	621
	State	8			—			18
	Total current provision	(467		)	(105		)	639
	Deferred:
	Federal	(2,593		)	(3,837		)	(2,776		)
	State	(2,343		)	(1,653		)	1,044
	Total deferred	(4,936		)	(5,490		)	(1,732		)
	Total (benefit) provision for income taxes	$	(5,403	)	$	(5,595	)	(1,093		)
	The effective rates for the years ended December 31, 2014, 2013 and 2012 are shown in the table below. In 2014, 2013 and 2012, the federal and state based income taxes were applied against book losses which resulted in effective tax rates of 1.5%, 2.4% and 3.3%, respectively.   A reconciliation of the provision for income taxes with amounts determined by applying the statutory U.S. federal income tax rate to income before income taxes is as follows (in thousands):
		For the Year Ended December 31,
		2014			2013			2012
	Pre-tax net book (loss) income from continuing operations	(357,770		)	(233,766		)	(33,239		)
	State income tax current and deferred	(2,335		)	(1,653		)	1,062
	Federal income taxes computed by applying the federal statutory rate to NBI of corporate entities	(2,680		)	(4,160		)	(2,155		)
	Tax attributes used	(388		)	218			—
	Benefit for income taxes from continuing operations	$	(5,403	)	$	(5,595	)	$	(1,093	)
	Effective income tax rate on continuing operations	1.5		%	2.4		%	3.3		%
	Significant components of deferred tax liabilities and deferred tax assets as of December 31, 2014 and 2013 are as follows (in thousands):
		December 31, 2014			December 31, 2013
	Deferred Tax Assets:
	Statutory depletion carryover	$	1,842		$	1,438
	Property, plant, equipment & amortizable assets	473			—
	Total Deferred Tax Assets	2,315			1,438
	Deferred Tax Liabilities:
	Property, plant, equipment & amortizable assets	—			(2,011		)
	Hedging transactions	(424		)	—
	Book/tax differences from partnership investment	(29,897		)	(32,086		)
	Total Deferred Tax Liabilities	(30,321		)	(34,097		)
	Total Net Deferred Tax Liabilities	(28,006		)	(32,659		)
	Current portion of total net deferred tax liabilities	—			—
	Long-term portion of total net deferred tax liabilities	$	(28,006	)	$	(32,659	)
	The largest single component of the Partnership's deferred tax liabilities is related to federal income taxes of the C Corporations described above, where the book/tax differences were created by the Redman and Stanolind Acquisitions. These book/tax temporary differences will be reduced as allocation of built-in gain in proportion to the assets contributed brings the book and tax basis closer together over time. This net deferred tax liability was recognized in conjunction with the purchase accounting adjustments for long term assets.
	Due to the enactment of the Revised Texas Franchise Tax, the Partnership recorded a net deferred tax asset related to the book/tax differences in property, plant and equipment and hedging transactions.
	In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment. At December 31, 2014, based upon the level of historical taxable income and projections for future taxable income over the periods in which the deferred tax assets are deductible, management believes it is more likely than not that the Partnership will realize the benefits of these deductible differences. The amount of deferred tax assets considered realizable could be reduced in the future if estimates of future taxable income during the carryforward period are reduced.
	The Partnership adopted authoritative guidance related to accounting for uncertainty in income taxes on January 1, 2007.  The Partnership has taken a position which is deemed to be “more likely than not” to be upheld upon review, if any, with respect to the deductibility of certain costs for the purpose of its franchise tax liability on a state franchise return.   The Partnership has recorded a provision for the portion of this tax liability equal to the probability of recognition. In addition, the Partnership has accrued interest and penalties associated with these liabilities and has recorded these amounts within its state deferred income tax expense. The amount stated below relates to the tax returns filed for years ending 2012, 2011 and 2010 which are still open under current statute.
	A reconciliation of the beginning and ending amount of the unrecognized tax benefits (liabilities) is as follows (in thousands):
		2014			2013			2012
	Balance at beginning of period	$	(649	)	$	(830	)	$	(735	)
	Increases related to current year tax positions	—			(128		)	(53		)
	Increases related to tax interest and penalties	—			(39		)	(42		)
	Decreases related to statutory limitations	226			267			—
	Decreases related to tax interest and penalties	58			81			—
	Balance at end of period	$	(365	)	$	(649	)	$	(830	)

Equity_Based_Compensation

Equity Based Compensation	12 Months Ended
	Dec. 31, 2014
Share-based Compensation [Abstract]
Equity-based Compensation	EQUITY-BASED COMPENSATION
	Eagle Rock Energy G&P, LLC, the general partner of the general partner of the Partnership, has a long-term incentive plan, (as amended “LTIP”), for its employees, directors and consultants who provide services to the Partnership and its subsidiaries and affiliates. The LTIP provides for the issuance of an aggregate of up to 14,500,000 common units to be granted either as options, restricted units or phantom units, of which, as of December 31, 2014, a total of 6,475,632 common units remained available for issuance (which calculation reserves the maximum common units (i.e., 200%) that may potentially be earned and vested in respect of the outstanding performance units). Grants under the LTIP are made at the discretion of the board and to date have been made in the form of restricted units and performance units (i.e., phantom units subject to performance conditions). Distributions declared and paid on outstanding restricted units, where such restricted units are eligible to receive distributions, are paid directly to the holders of the restricted units. With respect to the performance units (as described below), distributions declared and paid will be grossed-up by an additional number of performance units as determined in the performance unit agreement. No options have been issued to date.
	Restricted Units
	Grants of restricted units eligible to receive distributions are valued at the market price as of the date issued, while grants of restricted units not eligible to receive distributions are valued at the market price as of the date issued less the present value of the expected distribution stream over the vesting period using the risk-free interest rate. The weighted average fair value of the units granted during the years ended December 31, 2014, 2013 and 2012 was $4.44, $9.16 and $9.50, respectively. The awards generally vest over three years on the basis of one third of the award each year.
	The Partnership recognizes compensation expense on a straight-line basis over the requisite service period for the restricted unit grants. During the restriction period, distributions associated with the grants of restricted units eligible to receive distributions are distributed to the awardees.
	A summary of the changes in outstanding restricted common units for the year ended December 31, 2014 is provided below:
		Number of		Weighted
		Restricted		Average
		Units		Fair Value
	Outstanding at December 31, 2013	2,743,807		$	9.37
	Granted	1,903,333		$	4.44
	Vested	(1,305,433	)	$	9.6
	Forfeited	(921,957	)	$	8.12
	Outstanding at December 31, 2014	2,419,750		$	6.06
	Performance Units
	On August 19, 2014, the Board of Directors of Eagle Rock Energy G&P, LLC, upon the recommendation of its compensation committee, approved a grant of 715,263 target performance unit awards to the Partnership's executive officers subject to performance and service-based vesting conditions pursuant to the LTIP. Performance units are described in the LTIP as phantom units subject to restrictions that lapse based on the performance of the Partnership, as measured by total unitholder return in comparison to a peer group of upstream master limited partnerships and a continued service requirement that spans a three-year period.
	The performance units represent hypothetical common units of the Partnership and therefore do not carry any of the rights and privileges (including voting privileges) associated with actual common units. Performance units settle in common units rather than cash. The fair value of the performance units is estimated using a Monte Carlo simulation at the grant date. The Partnership recognizes compensation expense for the performance unit grants over the three-year vesting period.
	The amount to vest each year for the three-year vesting period will be determined on each vesting date based on a two-step approach. The right to receive units with respect to the performance units depends first on the level of total unitholder return attained by the Partnership over the applicable performance period (generally July 1, 2014 through June 30, 2016), as measured against the Partnership's peer group. The number of units that may be earned will either by 0% for performance at anything less than the 50th percentile of the peer group, or in the range of 70% to 200% for performance from the 50th percentile to the 100th percentile of the peer group over the performance period. Second, the right to receive actual common units with respect to the earned performance units depends on the satisfaction of a continued service requirement, which is generally continued service through June 30, 2016 for two-thirds of the performance units and through June 30, 2017 for the remaining one-third of the performance units.
	In the event the Partnership pays any distributions in respect of its outstanding units, the target performance units and any earned performance units will be grossed-up to reflect such distribution by an additional number of target performance units or earned performance units, as applicable. Any target performance units that do not become earned performance units shall terminate, expire and otherwise be forfeited by the named executive officer on the last day of the performance periods. Any earned performance units that vest (based on fulfillment of the continued service requirement) shall be converted into actual common units. Any earned performance units that do not vest (based on fulfillment of the continued service requirement) shall terminate, expire and otherwise be forfeited by the named executive officer.
	A summary of the changes in outstanding performance units for the year ended December 31, 2014 is provided below:
		Number of		Weighted
		Performance		Average
		Units		Fair Value
	Outstanding at December 31, 2013	—		$	—
	Granted	715,263		$	3.63
	Forfeited	(67,475	)	3.59
	Outstanding at December 31, 2014	647,788		3.63
	Equity Based Compensation
	For the years ended December 31, 2014, 2013 and 2012, non-cash compensation expense of approximately $8.2 million, $10.4 million and $7.7 million, respectively, was recorded related to the granted restricted units and performance units as general and administrative expense on the consolidated statements of operations.
	As of December 31, 2014, unrecognized compensation costs related to the outstanding restricted units and performance units under the LTIP totaled approximately $12.2 million. The remaining expense is to be recognized over a weighted average of 2.0 years.
	In connection with the vesting of certain restricted units during the years ended December 31, 2014, 2013 and 2012, 338,790, 272,179 and 286,716, respectively, of the newly-vested common units were cancelled by the Partnership in satisfaction of $1.4 million, $1.9 million and $2.5 million, respectively, of minimum employee tax liability paid by the Partnership. Pursuant to the terms of the LTIP, these cancelled units are available for future grants under the LTIP.

Earnings_Per_Unit

Earnings Per Unit	12 Months Ended
	Dec. 31, 2014
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 December 31, 2014, 2013 and 2012, the Partnership had unvested restricted common units outstanding, which are considered dilutive securities. These units are considered in the diluted weighted average common unit outstanding number in periods of net income. In periods of net losses, these units are excluded from the diluted weighted average common unit outstanding number.
	The majority of the restricted units granted under the LTIP, as discussed in Note 16, contain non-forfeitable rights to the distributions declared by the Partnership and therefore meet the definition of participating securities. Participating securities are required to be included in the computation of earnings per unit pursuant to the two-class method. Restricted units granted in 2013 to certain senior executives and members of the board of directors are not eligible to receive the distributions declared by the Partnership and therefore do not meet the definition of participating securities.
	The following table presents the Partnership's calculation of basic and diluted units outstanding for the periods indicated:
		Year Ended December 31,
		2014			2013		2012
		(in thousands)
	Weighted average units outstanding during period:
	Common units - Basic	156,700			153,562		135,609
	Common units - Diluted	156,700			153,562		135,609
	The following table presents the Partnership's basic and diluted income (loss) per unit for the year ended December 31, 2014:
			Total			Common Units			Restricted Common Units
			($ in thousands, except for per unit amounts)
	Loss from continuing operations		$	(352,367	)
	Distributions		21,763			$	21,464		$	299
	Assumed loss from continuing operations after distribution to be allocated		(374,130		)	(374,130		)	—
	Assumed allocation of loss from continuing operations		(352,367		)	(352,666		)	299
	Discontinued operations, net of tax		212,460			212,460			—
	Assumed net loss to be allocated		$	(139,907	)	$	(140,206	)	$	299
	Basic loss from continuing operations per unit					$	(2.25	)
	Basic discontinued operations per unit					$	1.36
	Basic net loss per unit					$	(0.89	)
	Diluted loss from continuing operations per unit					$	(2.25	)
	Diluted discontinued operations per unit					$	1.36
	Diluted net loss per unit					$	(0.89	)
	The following table presents the Partnership's basic and diluted income per unit for the year ended December 31, 2013:
			Total			Common Units			Restricted Common Units
			($ in thousands, except for per unit amounts)
	Loss from continuing operations		$	(228,171	)
	Distributions		117,294			$	115,351		$	1,943
	Assumed loss from continuing operations after distribution to be allocated		(345,465		)	(345,465		)	—
	Assumed allocation of loss from continuing operations		(228,171		)	(230,114		)	1,943
	Discontinued operations, net of tax		(49,808		)	(49,808		)	—
	Assumed net loss to be allocated		$	(277,979	)	$	(279,922	)	$	1,943
	Basic loss from continuing operations per unit					$	(1.50	)
	Basic discontinued operations per unit					$	(0.32	)
	Basic net loss per unit					$	(1.82	)
	Diluted loss from continuing operations per unit					$	(1.50	)
	Diluted discontinued operations per unit					$	(0.32	)
	Diluted net loss per unit					$	(1.82	)
	The following table presents the Partnership's basic and diluted income per unit for the year ended December 31, 2012:
			Total			Common Units			Restricted Common Units
			($ in thousands, except for per unit amounts)
	Loss from continuing operations		$	(32,146	)
	Distributions		124,235			$	121,504		$	2,731
	Assumed loss from continuing operations after distribution to be allocated		(156,381		)	(156,381		)	—
	Assumed allocation of loss from continuing operations		(32,146		)	(34,877		)	2,731
	Discontinued operations, net of tax		(118,456		)	(118,456		)	—
	Assumed net loss to be allocated		$	(150,602	)	$	(153,333	)	$	2,731
	Basic loss from continuing operations per unit					$	(0.26	)
	Basic discontinued operations per unit					$	(0.87	)
	Basic net loss per unit					$	(1.13	)
	Diluted loss from continuing operations per unit					$	(0.26	)
	Diluted discontinued operations per unit					$	(0.87	)
	Diluted net loss per unit					$	(1.13	)

Divestiture_Related_Activities

Divestiture Related Activities	12 Months Ended
	Dec. 31, 2014
Discontinued Operations and Disposal Groups [Abstract]
Divestiture Related Activities	DIVESTITURE RELATED ACTIVITIES
	As discussed in Note 1, on July 1, 2014, the Partnership completed the contribution of its Midstream Business to Regency. As a result of this transaction, the assets and liabilities of the Partnership's Midstream Business have been classified as held for sale and the operations as discontinued (See Note 1).
	On December 20, 2012, the Partnership sold its Barnett Shale properties (which was accounted for in its Upstream Business). The Partnership received net proceeds of $14.8 million, which resulted in a loss on the sale of $4.5 million. The loss is included within impairment expense in the audited consolidated statement of operations. In addition, as this transaction did not meet the criteria for discontinued operations, the operations related to these assets are not included in the discontinued operations table below.
	The following is the reconciliation of the major classes of assets and liabilities classified as held for sale.
		December 31,				December 31,
		2014				2013
		($ in thousands)
	Assets held-for-sale
	Accounts Receivable	$	—			$	128,713
	Property, plant and equipment	—				1,004,317
	Intangible assets	—				102,352
	Other current assets	—				5,663
	Other long-term assets	—				18,337
	Total assets held-for-sale	$	—			$	1,259,382
	Liabilities held-for-sale
	Long-term debt	$	—			$	494,582
	Accounts payable and accrued liabilities	—				119,966
	Other current liabilities	—				9,471
	Other long-term liabilities	—				13,719
	Total liabilities held-for-sale	$	—			$	637,738
	The following table represents the reconciliation of major classes of line items classified as discontinued operations for midstream business for the years ended December 31, 2014, 2013 and 2012:
			December 31, 2014				December 31, 2013				December 31, 2012
			($ in thousands)
	Class of statement of operations line item of discontinued operations:
	Revenues		$	552,574			$	997,907			$	752,644
	Cost of natural gas, natural gas liquids, condensate and helium		447,519				790,618				532,719
	Operations, maintenance and taxes other than income		50,154				101,121				82,526
	General and administrative		18,392				28,083				19,004
	Depreciation, amortization and impairment		41,936				77,726				202,249
	Interest expense		27,350				49,973				35,202
	Other (expense) income		(68		)		287				(10		)
	Operating loss from discontinued operations before taxes		(32,845		)		(49,327		)		(119,066		)
	Gain on sale of assets		243,637				—				—
	Income tax expense		(1,668		)		481				(610		)
	Discontinued operations, net of tax		$	212,460			$	(49,808	)		$	(118,456	)
	Allocation of interest expense
	Per accounting guidance provided by the FASB related to discontinued operations, interest on debt that is to be assumed by the buyer and interest on debt that is required to be repaid as a result of a disposal transaction should be allocated to discontinued operations. Per the Partnership's Credit Agreement, as a result of the contribution of the Midstream Business, the Partnership is required to pay down outstanding debt to the amount of the upstream portion of the borrowing base. Thus, interest expense in the table above includes the the interest expense related to the portion of the Partnership's unsecured Senior Notes exchanged for Regency unsecured senior notes on July 1, 2014 (see Note 1) and interest related to the difference between the total amount outstanding under the Credit Agreement and the upstream portion of the borrowing base.
	Restructuring activities
	In connection with the contribution of the Midstream Business to Regency, the Partnership accrued one-time employee termination benefits and lease payments of the partial abandonment of an operating lease of $4.0 million and $0.6 million during the year ended December 31, 2014. The accruals are recorded as part of accrued liabilities within the unaudited condensed consolidated balance sheet, while the expenses are recorded as part of discontinued operations within the unaudited condensed consolidated statement of operations. The following table summarizes activity related to liabilities associated with the Partnership's restructuring activities during the year ended December 31, 2014.
		Employee Related Costs				Facility and Other Costs				Total
		($ in thousands)
	Balance at December 31, 2013	$	—			$	—			$	—
	Additions	4,033				563				4,596
	Payments and other adjustments	(3,198		)		(73		)		(3,271		)
	Balance at December 31, 2014	$	835			$	490			$	1,325
	In addition, in connection with the contribution of the Midstream Business, the Partnership incurred expenses of $1.7 million during the year ended December 31, 2014 to write-off certain software licenses used by the Midstream Business that were not acquired by Regency.

Subsidiary_Guarantors

Subsidiary Guarantors	12 Months Ended
	Dec. 31, 2014
SUBSIDIARY GUARANTORS [Abstract]
Subsidiary Guarantors	SUBSIDIARY GUARANTORS
	The Partnership has issued registered debt securities guaranteed by its subsidiaries.  As of December 31, 2014, all guarantors were wholly-owned or available to be pledged and such guarantees were joint and several and full and unconditional.  Although the guarantees of our subsidiary guarantors are considered full and unconditional, the guarantees are subject to certain customary release provisions. Such guarantees will be released in the following circumstances:
	•	in connection with any sale or other disposition of all or substantially all of the properties or assets of that guarantor (including by way of merger or consolidation) to a person that is not (either before or after giving effect to such transaction) an issuer or a restricted subsidiary of us;
	•	in connection with any sale or other disposition of capital stock of that guarantor to a person that is not (either before or after giving effect to such transaction) an issuer or a restricted subsidiary of us, such that, the guarantor ceases to be a restricted subsidiary of us as a result of the sale or other disposition;
	•	if we designate any restricted subsidiary that is a guarantor to be an unrestricted subsidiary in accordance with the applicable provisions of the indenture;
	•	upon legal defeasance or satisfaction and discharge of the indenture;
	•	upon the liquidation or dissolution of such guarantor provided no default or event of default has occurred that is continuing;
	•	at such time as such guarantor ceases to guarantee any other indebtedness of either of the issuers or any guarantor; or
	•	upon such guarantor consolidating with, merging into or transferring all of its properties or assets to us or another guarantor, and as a result of, or in connection with, such transaction such guarantor dissolving or otherwise ceasing to exist.
	In accordance with Rule 3-10 of Regulation S-X, the Partnership has prepared Condensed Consolidating Financial Statements as supplemental information.  The following condensed consolidating balance sheets at December 31, 2014 and December 31, 2013, condensed consolidating statements of operations for the years ended December 31, 2014, 2013 and 2012, and condensed consolidating statements of cash flows for the years ended December 31, 2014, 2013 and 2012, present financial information for Eagle Rock Energy as the Parent on a stand-alone basis (carrying any investments in subsidiaries under the equity method), financial information for the co-issuer and the subsidiary guarantors, which are all 100% owned by the Parent, on a stand-alone basis, and the consolidation and elimination entries necessary to arrive at the information for the Partnership on a consolidated basis.  The subsidiary guarantors are not restricted from making distributions to the Partnership. Pursuant to the Contribution of the Midstream Business, all of the Partnership's Midstream Subsidiaries were contributed to Regency on July 1, 2014 and released from their guarantees under the indenture and Credit Agreement.
	Condensed Consolidating Balance Sheet
	December 31, 2014
		Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-guarantor investments			Consolidating			Total
													Entries
		($ in thousands)
	ASSETS:
	Accounts receivable – related parties	$	838,656		$	—	$	—		$	—		$	(838,656	)	$	—
	Other current assets	211,213			1		37,889			—			—			249,103
	Total property, plant and equipment, net	1,334			—		486,654			—			—			487,988
	Investment in subsidiaries	(413,023		)	—		—			—			413,023			—
	Total other long-term assets	52,272			—		4,912			—			—			57,184
	Total assets	$	690,452		$	1	$	529,455		$	—		$	(425,633	)	$	794,275
	LIABILITIES AND EQUITY:
	Accounts payable – related parties	$	—		$	—	$	838,656		$	—		$	(838,656	)	$	—
	Other current liabilities	37,850			—		21,675			—			—			59,525
	Other long-term liabilities	789			—		82,148			—			—			82,937
	Long-term debt	263,343			—		—			—			—			263,343
	Equity	388,470			1		(413,024		)	—			413,023			388,470
	Total liabilities and equity	$	690,452		$	1	$	529,455		$	—		$	(425,633	)	$	794,275
	Condensed Consolidating Balance Sheet
	December 31, 2013
		Parent Issuer			Co-Issuer		Subsidiary			Non-guarantor investments			Consolidating Entries			Total
							Guarantors
		($ in thousands)
	ASSETS:
	Accounts receivable – related parties	$	691,588		$	—	$	—		$	—		$	(691,588	)	$	—
	Assets held for sale	8,762			—		1,250,620			—			—			1,259,382
	Other current assets	6,927			1		22,080			—			—			29,008
	Total property, plant and equipment, net	2,318			—		822,133			—			—			824,451
	Investment in subsidiaries	1,133,217			—		—			908			(1,134,125		)	—
	Total other long-term assets	10,012			—		4,697			—			—			14,709
	Total assets	$	1,852,824		$	1	$	2,099,530		$	908		$	(1,825,713	)	$	2,127,550
	LIABILITIES AND EQUITY:
	Accounts payable – related parties	$	—		$	—	$	691,588		$	—		$	(691,588	)	$	—
	Liabilities held for sale	500,291			—		137,447			—			—			637,738
	Other current liabilities	15,688			—		66,141			—			—			81,829
	Other long-term liabilities	5,486			—		71,138			—			—			76,624
	Long-term debt	757,480			—		—			—			—			757,480
	Equity	573,879			1		1,133,216			908			(1,134,125		)	573,879
	Total liabilities and equity	$	1,852,824		$	1	$	2,099,530		$	908		$	(1,825,713	)	$	2,127,550
	Condensed Consolidating Statement of Operations
	For the Year Ended December 31, 2014
		Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-guarantor investments			Consolidating			Total
													Entries
		($ in thousands)
	Total revenues	$	93,940		$	—	$	204,264		$	—		$	—		$	298,204
	Operations and maintenance	3			—		43,667			—			—			43,670
	Taxes other than income	—			—		12,925			—			—			12,925
	General and administrative	9,654			—		37,539			—			—			47,193
	Depreciation, depletion and amortization	641			—		84,938			—			—			85,579
	Impairment and other	—			—		395,892			—			—			395,892
	Income (loss) from operations	83,642			—		(370,697		)	—			—			(287,055		)
	Interest expense, net	(15,247		)	—		—			—			—			(15,247		)
	Other non-operating income	16,998			—		4,741			—			(13,445		)	8,294
Other non-operating expense	(7,396		)	—		(7,783		)	—			13,445			(1,734		)
Loss on short term investments	(62,028		)	—		—			—			—			(62,028		)
Income (loss) before income taxes	15,969			—		(373,739		)	—			—			(357,770		)
Income tax benefit	(3,791		)	—		(1,612		)	—			—			(5,403		)
Equity in earnings of subsidiaries	(683,371		)	—		—			—			683,371			—
Loss from continuing operations	(663,611		)	—		(372,127		)	—			683,371			(352,367		)
Discontinued operations, net of tax	523,704			—		(311,235		)	(9		)	—			212,460
Net loss	$	(139,907	)	$	—	$	(683,362	)	$	(9	)	$	683,371		$	(139,907	)
Condensed Consolidating Statement of Operations
For the Year Ended December 31, 2013
	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-guarantor investments			Consolidating Entries			Total
	($ in thousands)
Total revenues	$	(3,937	)	$	—	$	201,309		$	—		$	—		$	197,372
Operations and maintenance	—			—		41,426			—			—			41,426
Taxes other than income	—			—		12,928			—			—			12,928
General and administrative	13,145			—		39,986			—			—			53,131
Depreciation, depletion and amortization	454			—		88,990			—			—			89,444
Impairment	—			—		214,286			—			—			214,286
Loss from operations	(17,536		)	—		(196,307		)	—			—			(213,843		)
Interest expense, net	(17,891		)	—		(898		)	—			—			(18,789		)
Other non-operating income	9,025			—		9,298			—			(18,323		)	—
Other non-operating expense	(6,904		)	—		(12,553		)	—			18,323			(1,134		)
Loss before income taxes	(33,306		)	—		(200,460		)	—			—			(233,766		)
Income tax provision (benefit)	(1,653		)	—		(3,942		)	—			—			(5,595		)
Equity in earnings of subsidiaries	(191,071		)	—		—			—			191,071			—
Loss from continuing operations	(222,724		)	—		(196,518		)	—			191,071			(228,171		)
Discontinued operations, net of tax	(55,255		)	—		5,457			(10		)	—			(49,808		)
Net loss	$	(277,979	)	$	—	$	(191,061	)	$	(10	)	$	191,071		$	(277,979	)
Condensed Consolidating Statement of Operations
For the Year Ended December 31, 2012
	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-guarantor investments			Consolidating			Total
												Entries
	($ in thousands)
Total revenues	$	28,110		$	—	$	203,205		$	—		$	—		$	231,315
Operations and maintenance	—			—		41,391			—			—			41,391
Taxes other than income	—			—		15,343			—			—			15,343
General and administrative	8,745			—		42,245			—			—			50,990
Depreciation, depletion and amortization	296			—		90,214			—			—			90,510
Impairment	—			—		45,289			—			—			45,289
Income (loss) from operations	19,069			—		(31,277		)	—			—			(12,208		)
Interest expense, net	(16,299		)	—		23			—			—			(16,276		)
Other non-operating income	9,039			—		10,961			—			(20,000		)	—
Other non-operating expense	(12,189		)	—		(12,566		)	—			20,000			(4,755		)
Loss before income taxes	(380		)	—		(32,859		)	—			—			(33,239		)
Income tax provision (benefit)	1,041			—		(2,134		)	—			—			(1,093		)
Equity in earnings of subsidiaries	(113,200		)	—		—			—			113,200			—
Loss from continuing operations	(114,621		)	—		(30,725		)	—			113,200			(32,146		)
Discontinued operations, net of tax	(35,981		)	—		(82,457		)	(18		)	—			(118,456		)
Net loss	$	(150,602	)	$	—	$	(113,182	)	$	(18	)	$	113,200		$	(150,602	)
Condensed Consolidating Statement of Cash Flows
For the Year Ended December 31, 2014
	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-guarantor investments			Consolidating Entries			Total
	($ in thousands)
Net cash flows (used in) provided by operating activities	$	(28,661	)	$	—	$	106,787		$	—		$	—		$	78,126
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment	344			—		(137,038		)	—			—			(136,694		)
Proceeds from sale of short-term investments	43,836			—		—			—			—			43,836
Net cash flows provided by (used in) investing activities	44,180			—		(137,038		)	—			—			(92,858		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	472,500			—		—			—			—			472,500
Repayment of long-term debt	(966,700		)	—		—			—			—			(966,700		)
Payment of debt issuance cost	(1,984		)	—		—			—			—			(1,984		)
Proceeds from derivative contracts	(5,022		)	—		—			—			—			(5,022		)
Repurchase of common units	(19,170		)	—		—			—			—			(19,170		)
Distributions to members and affiliates	(34,982		)	—		—			—			—			(34,982		)
Net cash flows used in financing activities	(555,358		)	—		—			—			—			(555,358		)
Net cash flows provided by discontinued operations	541,288			—		30,047			22			—			571,357
Net increase (decrease) in cash and cash equivalents	1,449			—		(204		)	22			—			1,267
Cash and cash equivalents at beginning of year	1,237			1		(1,389		)	227			—			76
Cash and cash equivalents at end of year	$	2,686		$	1	$	(1,593	)	$	249		$	—		$	1,343
Condensed Consolidating Statement of Cash Flows
For the Year Ended December 31, 2013
	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-guarantor Investments			Consolidating Entries			Total
	($ in thousands)
Net cash flows (used in) provided by operating activities	$	(34,610	)	$	—	$	148,853		$	—		$	—		$	114,243
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment	(115		)	—		(149,829		)	—			—			(149,944		)
Proceeds from sale of asset	—			—		76			—			—			76
Net cash flows used in investing activities	(115		)	—		(149,753		)	—			—			(149,868		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	601,400			—		—			—			—			601,400
Repayment of long-term debt	(503,100		)	—		—			—			—			(503,100		)
Proceeds from derivatives contracts	1,323			—		—			—			—			1,323
Common unit issued in equity offerings	102,388			—		—			—			—			102,388
Issuance costs for equity offerings	(4,519		)	—		—			—			—			(4,519		)
Repurchase of common units	(1,858		)	—		—			—			—			(1,858		)
Distributions to members and affiliates	(125,911		)	—		—			—			—			(125,911		)
Net cash flows provided by financing activities	69,723			—		—			—			—			69,723
Net cash flows provided by (used in) discontinued operations	(35,431		)	—		1,343			41			—			(34,047		)
Net (decrease) increase in cash and cash equivalents	(433		)	—		443			41			—			51
Cash and cash equivalents at beginning of year	1,670			1		(1,832		)	186			—			25
Cash and cash equivalents at end of year	$	1,237		$	1	$	(1,389	)	$	227		$	—		$	76
Condensed Consolidating Statement of Cash Flows
For the Year Ended December 31, 2012
	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-guarantor Investments			Consolidating Entries			Total
	($ in thousands)
Net cash flows (used in) provided by operating activities	$	(108,061	)	$	—	$	183,397		$	—		$	—		$	75,336
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment	(1,551		)	—		(166,356		)	—			—			(167,907		)
Proceeds from sale of asset	—			—		15,398			—			—			15,398
Contribution to subsidiaries	(236,971		)	—		—			—			236,971			—
Net cash flows used in investing activities	(238,522		)	—		(150,958		)	—			236,971			(152,509		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	1,043,750			—		—			—			—			1,043,750
Repayment of long-term debt	(916,750		)	—		—			—			—			(916,750		)
Proceed from senior notes	22,889			—		—			—			—			22,889
Payments of debt issuance cost	(614		)	—		—			—			—			(614		)
Proceeds from derivative contracts	14,449			—		—			—			—			14,449
Common unit issued in equity offerings	96,173			—		—			—			—			96,173
Issuance costs for equity offerings	(4,518		)	—		—			—			—			(4,518		)
Exercise of Warrants	31,804			—		—			—			—			31,804
Repurchase of common units	(2,501		)	—		—			—			—			(2,501		)
Distributions to members and affiliates	(119,211		)	—		—			—			—			(119,211		)
Net cash flows provided by financing activities	165,471			—		—			—			—			165,471
Net cash flows provided by (used in) discontinued operations	181,463			—		(33,699		)	57			(236,971		)	(89,150		)
Net increase (decrease) in cash and cash equivalents	351			—		(1,260		)	57			—			(852		)
Cash and cash equivalents at beginning of year	1,319			1		(572		)	129			—			877
Cash and cash equivalents at end of year	$	1,670		$	1	$	(1,832	)	$	186		$	—		$	25

Supplemental_Oil_and_Gas_Infor

Supplemental Oil and Gas Information (Unaudited)	12 Months Ended
	Dec. 31, 2014
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Oil and Gas Exploration and Production Industries Disclosures [Text Block]	SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)
	Oil and Natural Gas Reserves
	Users of this information should be aware that the process of estimating quantities of proved oil and natural gas reserves is very complex, and requires significant subjective decisions in the evaluation of the available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and changing operating and market conditions. As a result, revisions to reserve estimates may occur from time to time. Although reasonable effort is made to ensure the reported reserve estimates are accurate, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.
	There are numerous uncertainties inherent in estimating the quantities of proved reserves, the future rates of production and the timing of development expenditures. Reserves data represent estimates only and should not be construed as being exact. Moreover, the Standardized Measure of Oil and Gas (“SMOG”) should not be construed as the current market value of the proved oil and natural gas reserves or as the costs that would be incurred to obtain equivalent reserves. A market value determination would include many additional factors including (a) anticipated future changes in natural gas and crude oil prices, production and development costs, (b) an allowance for return on investment, (c) the value of additional reserves, not considered proved at present, which may be recovered as a result of further exploration and development activities, and (d) other business risks.
	Proved Reserves Summary
	The following table illustrates the Partnership's estimated net proved reserves, including changes, and proved developed reserves for the periods indicated, as estimated by Cawley, Gillespie and Associates. Oil and natural gas liquids prices applied for 2014 are based on an average of the prior twelve months first-of-month spot prices of West Texas Intermediate ($94.99 per barrel) and are adjusted for quality, transportation fees, and price differentials. Likewise, natural gas prices applied for 2014 are based on an average of the prior twelve months first-of-month spot prices of Henry Hub natural gas ($4.35 per MMBtu) and are adjusted for energy content, transportation fees, and regional price differentials. All prices are held constant in accordance with SEC guidelines.
	As shown in the following reconciliation table, the Partnership recognized significant negative revisions to its estimates of proved reserves in 2014. These revisions to previous estimates were primarily the result of recategorizing a number of undeveloped locations from proved to probable reserves due to poor expected economic performance (a decrease of 3.0 Bcfe), recategorizing other proved undeveloped locations as contingent resources since they were non-commercial at the time (a decrease of 0.2 Bcfe), and other factors including increased costs, negative changes to forecast performance expectations and widening product price differentials (a decrease of 44.6 Bcfe).
		Proved Reserves
		Oil			Gas			Natural Gas
		(MBbls)			(MMcf)			Liquids (MBbls)
	Proved reserves, January 1, 2012	11,522			234,022			11,347
	Extensions and discoveries	1,405			31,524			2,136
	Purchase of minerals in place	104			128			18
	Production	(1,184	)		(16,443	)		(1,121	)
	Sales of mineral in place	—			(13,331	)		—
	Revision of previous estimates	1,137			(41,471	)		486
	Proved reserves, December 31, 2012	12,984			194,429			12,866
	Extensions and discoveries	2,712			29,137			3,180
	Purchase of minerals in place	—			—			—
	Production	(1,222	)		(12,804	)		(1,156	)
	Revision of previous estimates	(932	)		(33,536	)		(253	)
	Proved reserves, December 31, 2013	13,542			177,226			14,637
	Extensions and discoveries	1,080			22,990			2,224
	Purchase of minerals in place	326			769			170
	Production	(1,313	)		(11,995	)		(1,158	)
	Revision of previous estimates	(2,618	)		(19,897	)		(2,039	)
	Proved reserves, December 31, 2014	11,017			169,093			13,834
	Proved Developed Reserves
	Proved developed reserves, January 1, 2012	10,271			165,269			9,307
	Proved developed reserves, December 31, 2012	10,993			136,545			10,445
	Proved developed reserves, December 31, 2013	10,153			126,950			10,766
	Proved developed reserves, December 31, 2014	9,595			126,783			10,895
	Proved Undeveloped Reserves
	Proved undeveloped reserves, January 1, 2012	1,251			68,753			2,040
	Proved undeveloped reserves, December 31, 2012	1,991			57,884			2,421
	Proved undeveloped reserves, December 31, 2013	3,389			50,276			3,871
	Proved undeveloped reserves, December 31, 2014	1,412			42,310			2,939
	The primary drivers, other than production, behind the changes to our proved reserves for the years ended December 31, 2012, 2013 and 2014 are described in more detail below.
	2012:00:00
	•	Purchase of minerals in place were insignificant in 2012;
	•	extensions and discoveries were primarily related to drilling by us and other operators in the Golden Trend area and the nearby SCOOP Play in Oklahoma;
	•	sales of minerals in place were related to the sale of our Barnett Shale assets in December 2012; and
	•	revisions of previous estimates were primarily the result of lower natural gas prices which reduced the economic life and reserves of many wells.
	2013:00:00
	•	Purchases and sales of minerals in place did not occur in 2013;
	•	extensions and discoveries were primarily related to drilling by us and other operators in the Golden Trend area and the nearby SCOOP Play in Oklahoma; and
	•	revisions of previous estimates were the result of recategorizing a number of undeveloped locations from proved to probable reserves due to poor expected economic performance (a decrease of 27.8 Bcfe), recategorizing other proved undeveloped locations as contingent resources since they were non-commercial at the time (a decrease of 8.1Bcfe), changes in ownership of interests including those that occurred when third party owners elected to not participate in future drilling activities for certain wells (an increase of 1.6 Bcfe) and other factors including changes to costs (an increase of 2.5 Bcfe). All of these revisions were primarily in the Mid-Continent Region.
	2014:00:00
	•	Purchases of minerals in place in 2014 included 3.7 Bcfe of proved developed producing reserves in the Big Escambia Creek field in Alabama, but there were no sales of minerals in place;
	•	extensions and discoveries were primarily related to drilling by us and other operators in the Golden Trend area and the nearby SCOOP Play in Oklahoma and in addition, a number of well locations primarily in the Mid-Continent Region were moved to proved developed non-producing and proved undeveloped as a result of becoming economic at higher gas prices; and
	•	revisions of previous estimates were the result of recategorizing a number of undeveloped locations from proved to probable reserves due to poor expected economic performance (a decrease of 3.0 Bcfe), recategorizing other proved undeveloped locations as contingent resources since they were non-commercial at the time (a decrease of 0.2Bcfe), and other factors including changes to costs, forecast performance expectations and product price differentials (a decrease of 44.6 Bcfe).
	Capitalized Costs Relating to Oil and Natural Gas Producing Activities
	The following table illustrates the total amount of capitalized costs relating to oil and natural gas producing activities and the total amount of related accumulated depreciation, depletion and amortization at December 31, 2014, 2013 and 2012:
		As of				As of				As of
		31-Dec-14				31-Dec-13				31-Dec-12
	($ in thousands)
	Proved properties	$	905,622			$	1,156,895			$	1,213,622
	Unproved properties—excluded from depletion	7,512				10,022				31,823
	Gross oil and gas properties	913,134				1,166,917				1,245,445
	Accumulated depreciation, depletion, amortization	(431,555		)		(353,679		)		(269,376		)
	Net oil and gas properties	$	481,579			$	813,238			$	976,069
	Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities
	Costs incurred in property acquisition, exploration and development activities were as follows for the years ended December 31, 2014, 2013 and 2012:
		Year Ended December 31,
	2014				2013				2012
($ in thousands)
Property acquisition costs, proved	$	10,861			$	—			$	2,582
Development costs	122,387				124,032				135,692
Total costs	$	133,248			$	124,032			$	138,274
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves
The following information has been developed utilizing authoritative guidance procedures and is based on oil and natural gas reserves estimated by the Partnership's independent reserves engineer. It can be used for some comparisons, but should not be the only method used to evaluate the Partnership or its performance. Further, the information in the following table may not represent realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flow be viewed as representative of the current value of the Partnership.
The Partnership believes that the following factors should be taken into account when reviewing the following information:
•	future costs and selling prices will probably differ from those required to be used in these calculations;
•	due to future market conditions and governmental regulations, actual rates of production in future years may vary significantly from the rate of production assumed in the calculations; and
•	a 10% discount rate may not be reasonable as a measure of the relative risk inherent in realizing future net oil and natural gas revenues.
Under the Standardized Measure, future cash inflows were estimated by applying year-end oil and natural gas prices to the estimated future production of year-end proved reserves. Estimates of future income taxes were computed using current statutory income tax rates including consideration for estimated future statutory depletion and tax credits. The resulting net cash flows were reduced to present value amounts by applying a 10% discount factor.
The Partnership's hydrocarbon reserves in Alabama and East Texas contain hydrogen sulfide that must be removed from the natural gas stream before the hydrocarbons are sold. As part of the process to remove the hydrogen sulfide, the Partnership produces and sells elemental sulfur. The Partnership generated revenue from the sale of sulfur of $8.2 million, $8.1 million and $14.0 million in 2014, 2013 and 2012, respectively. The cost of removing the sulfur is included in the future production costs in the Standardized Measure table below. However, since sulfur is not considered a hydrocarbon, revenues from the sale of sulfur are excluded from the computation of the Standardized Measure.
The Standardized Measure is as follows as of December 31, 2014, 2013 and 2012:
	As of				As of				As of
	31-Dec-14				31-Dec-13				31-Dec-12
($ in thousands)
Future cash inflows	$	2,187,346			$	2,423,350			$	2,279,735
Future production costs	(759,966		)		(737,468		)		(767,004		)
Future development costs	(240,886		)		(318,778		)		(354,690		)
Future net cash flows before income taxes	1,186,494				1,367,104				1,158,041
Future income tax (expense) benefit	(833		)		(1,212		)		(1,086		)
Future net cash flows before 10% discount	1,185,661				1,365,892				1,156,955
10% annual discount for estimated timing of cash flows	(591,421		)		(715,386		)		(621,826		)
Total standardized measure of discounted future net cash flows	$	594,240			$	650,506			$	535,129
Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves
The following is a summary of the changes in the Standardized Measure of discounted future net cash flows for the Partnership's proved oil and natural gas reserves for the years ended December 31, 2014, 2013 and 2012:
	Year Ended December 31,
	2014				2013				2012
($ in thousands)
Beginning of year	$	650,506			$	535,129			$	642,586
Sale of oil and gas produced, net of production costs	(152,097		)		(150,457		)		(132,451		)
Net changes in prices and production costs	(63,142		)		2,720				(78,247		)
Extensions, discoveries and improved recovery, less related costs	74,684				136,464				66,460
Previously estimated development costs incurred during the period	49,409				21,470				53,111
Net changes in future development costs	71,800				107,951				36,914
Revisions of previous quantity estimates	(149,993		)		(103,351		)		(76,434		)
Purchases of property	11,904				—				2,811
Sales of property	—				—				(5,063		)
Accretion of discount	59,818				49,233				60,734
Net changes in income taxes	169				(36		)		317
Other	41,182				51,383				(35,609		)
End of year	$	594,240			$	650,506			$	535,129
Results of Operations
The following are the results of operations for the Partnership's oil and natural gas producing activities for the years ended December 31, 2014, 2013 and 2012:
		Year Ended December 31,
		2014				2013				2012
($ in thousands)
Revenues:
Sales to third parties		$	190,057			$	146,210			$	135,842
Intercompany sales		5,475				47,048				53,343
Total revenues		195,532				193,258				189,185
Costs and expenses:
Production costs		56,595				54,354				56,734
General and administrative		8,166				11,419				12,162
Depreciation, depletion, and amortization		81,030				87,456				88,777
Impairment and other		395,892				214,286				45,289
Total costs and expenses		541,683				367,515				202,962
Total result of operations		$	(346,151	)		$	(174,257	)		$	(13,777	)
* * * *

Summary_of_Significant_Account1

Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
Basis of Accounting [Text Block]	Basis of Presentation and Principles of Consolidation—The accompanying audited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP").
	All intercompany accounts and transactions are eliminated in the consolidated financial statements.
Use of Estimates, 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.
Cash and Cash Equivalents, Policy [Policy Text Block]	Cash and Cash Equivalents—Cash and cash equivalents include certificates of deposit and other highly liquid investments with maturities of three months or less at the time of purchase.
Concentration Risk Disclosure [Text Block]	Concentration and Credit Risk—Concentration and credit risk for the Partnership principally consists of cash and cash equivalents and accounts receivable.
	The Partnership places its cash and cash equivalents with high-quality institutions and in money market funds. The Partnership derives its revenue from customers primarily in the natural gas industry. Industry concentrations have the potential to impact the Partnership's overall exposure to credit risk, either positively or negatively, in that the Partnership's customers could be affected by similar changes in economic, industry or other conditions. However, the Partnership believes the risk posed by this industry concentration is offset by the creditworthiness of the Partnership's customer base. The Partnership's portfolio of accounts receivable is comprised primarily of mid-size to large domestic corporate entities.
	The following is the activity within the Partnership's allowance for doubtful accounts during the years ended December 31, 2014, 2013 and 2012.
		2014			2013			2012
	($ in thousands)
	Balance at beginning of period	$	931		$	753		$	670
	Charged to bad debt expense	249			458			175
	Write-offs/adjustments charged to allowance	(157		)	(280		)	(92		)
	Balance at end of period	$	1,023		$	931		$	753
	The table above does not include amounts related to the Partnership's Midstream Business, as these amounts have been classified as part of assets held for sale within the audited consolidated balance sheets and discontinued operations within the audited consolidated statements of operations (see Note 18).
	Certain Other Concentrations—For the year ended December 31, 2014, NGL Energy Partners LP, CVR Refining, LP and Oneok Partners, LP, the Partnership's largest customers, represented 15%, 12% and 11%, respectively, of its total sales revenue (excluding its commodity risk management gains and losses and revenue amounts classified as part of discontinued operations).
Inventory Finished Goods, Policy [Policy Text Block]	Inventory—Inventory is stated at the lower of cost or market, with cost being determined using the average cost method. At December 31, 2013, the Partnership had $1.0 million of crude oil finished goods inventory, which is recorded as part of assets held for sale within the audited consolidated balance sheet.
Property, Plant and Equipment, Policy [Policy Text Block]	Property, Plant and Equipment—Property, plant and equipment, including amounts classified as held for sale, consists primarily of gas gathering systems, gas processing plants, NGL pipelines, conditioning and treating facilities and other related facilities, and oil and natural gas properties, which are carried at cost less accumulated depreciation, depletion and amortization. The Partnership charges repairs and maintenance against income when incurred and capitalizes renewals and betterments, which extend the useful life or expand the capacity of the assets. The Partnership capitalizes interest costs on major projects during extended construction time periods. Such interest costs are allocated to property, plant and equipment and amortized over the estimated useful lives of the related assets. The Partnership calculates depreciation on the straight-line method over estimated useful lives of the Partnership's newly developed or acquired assets. The weighted average useful lives are as follows:
	Plant assets	20 years
	Pipelines and equipment	20 years
	Gas processing and equipment	20 years
	Office furniture and equipment	5 years
	Plant assets, pipelines and equipment, gas process and equipment and certain office furniture and equipment related to the Partnership's Midstream Business have been classified as assets held for sale within the audited consolidated balance sheets. Depreciation expense related to these assets has been recorded as part of discontinued operations within the audited consolidated statements of operations (see Note 18).
Full Cost or Successful Efforts, Policy [Policy Text Block]	Oil and Natural Gas Properties—The Partnership utilizes the successful efforts method of accounting for its oil and natural gas properties. Leasehold costs are capitalized when incurred. Costs incurred to drill and complete development wells are capitalized. Geological and geophysical expenses and delay rentals are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if the well is determined to be unsuccessful. The Partnership carries the costs of an exploratory well as an asset if the well is found to have a sufficient quantity of reserves to justify its capitalization as a producing well as long as the Partnership is making sufficient progress towards assessing the reserves and the economic and operating viability of the project.
	Depletion of producing oil and natural gas properties is recorded based on units of production. Unit rates are computed for unamortized drilling and development costs using proved developed reserves and for acquisition costs using all proved reserves. Authoritative guidance requires that acquisition costs of proved properties be amortized on the basis of all proved reserves (developed and undeveloped), and that capitalized development costs (wells and related equipment and facilities) be amortized on the basis of proved developed reserves.
	Upon sale or retirement of complete fields of depreciable or depleted property, the book value thereof, less proceeds or salvage value, is charged or credited to income.
	Costs related to unproved properties include costs incurred to acquire unproved reserves.  Because these reserves do not meet the definition of proved reserves, the related costs are not classified as proved properties.  Unproved leasehold costs are capitalized and amortized on a composite basis if individually insignificant, based on past success, experience, drilling plans and average lease-term lives.  Unamortized leasehold costs related to successful exploratory drilling are reclassified to proved properties and depleted on a units of production basis.  Unproved properties (both individually significant and insignificant) are assessed periodically within specific geographic areas and, if necessary, impairments are charged to expense.
Other Assets Disclosure [Text Block]	Other Assets— As of December 31, 2014 and 2013, other assets, excluding amounts classified as held for sale (see Note 18), primarily consist of costs associated with debt issuance costs, net of amortization, of $5.3 million and $6.1 million, respectively.
Impairment or Disposal 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 and/or forward prices that will be produced from a field, the timing of this future production, future costs to produce the oil and natural gas, and future inflation levels.
	If the carrying value is not recoverable on an undiscounted basis, the impairment loss is measured as the excess of the asset's carrying value over its fair value. Management assesses the fair value of long-lived assets using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales, internally developed discounted cash flow analysis and analysis from outside advisors. Significant changes in market conditions resulting from events such as the condition of an asset or a change in management's intent to utilize the asset would generally require management to reassess the cash flows related to the long-lived assets.
	See Note 5 for further discussion on impairment charges.
Revenue Recognition, 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 for the Partnership's Midstream Business included the sale of natural gas, NGLs, crude oil, condensate, sulfur and helium and from the compression, gathering, processing, treating and transportation of natural gas. Revenues associated with transportation and processing fees were recognized in the period when the services were provided. These revenues have been classified as discontinued operations within the unaudited condensed consolidated statements of operations.
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 $0.3 million and $0.3 million as of December 31, 2014 and December 31, 2013.
Gas Balancing Arrangements, Policy [Policy Text Block]	Transportation and Exchange Imbalances—In the course of transporting natural gas and NGLs for others, the Partnership may receive for redelivery different quantities of natural gas or NGLs than the quantities actually delivered. These transactions result in transportation and exchange imbalance receivables or payables which are recovered or repaid through the receipt or delivery of natural gas or NGLs in future periods, if not subject to cash out provisions. Imbalance receivables are included in accounts receivable and imbalance payables are included in accounts payable on the audited consolidated balance sheets and marked-to-market using current market prices in effect for the reporting period of the outstanding imbalances. As of December 31, 2013, the Partnership had imbalance receivables totaling $0.7 million and imbalance payables totaling $1.6 million. All transportation and exchange imbalance receivables and imbalance payables have been classified as assets and liabilities held for sale, respectively, within the audited consolidated balance sheets. Changes in market value and the settlement of any such imbalance at a price greater than or less than the recorded imbalance results in either an upward or downward adjustment, as appropriate, to the cost of natural gas sold, and have been classified as discontinued operations within the audited consolidated statements of operations.
Environmental Costs, Policy [Policy Text Block]	Environmental Expenditures—Environmental expenditures are expensed or capitalized as appropriate, depending upon the future economic benefit. Expenditures which relate to an existing condition caused by past operations and do not generate current or future revenue are expensed. Liabilities for these expenditures are recorded on an undiscounted basis when environmental assessments and/or clean-ups are probable and the costs can be reasonably estimated.
Income Tax, Policy [Policy Text Block]	Income Taxes—Provision for income taxes is primarily applicable to the Partnership's state tax obligations under the Revised Texas Franchise Tax (the “Revised Texas Franchise Tax”) and certain federal and state tax obligations of Eagle Rock Energy Acquisition Co., Inc., Eagle Rock Acquisition Co. II, Inc., Eagle Rock Upstream Development Company, Inc. and Eagle Rock Upstream Development Company II, Inc., all of which are consolidated subsidiaries. Deferred income tax assets and liabilities are recognized for temporary differences between the assets and liabilities of the tax paying entities for financial reporting and tax purposes.
	In general, legal entities that conduct business in Texas are subject to the Revised Texas Franchise Tax. In May 2006, the State of Texas expanded its pre-existing franchise tax to include limited partnerships, limited liability companies, corporations and limited liability partnerships. As a result of the change in tax law, the Partnership's tax status in the State of Texas changed from non-taxable to taxable effective with the 2007 tax year.
	Since the Partnership is structured as a pass-through entity, it is not subject to federal income taxes. As a result, its partners are individually responsible for paying federal and certain income taxes on their share of the Partnership's taxable income. Since the Partnership does not have access to information regarding each partner's tax basis, it cannot readily determine the total difference in the basis of the Partnership's net assets for financial and tax reporting purposes.
Derivatives, 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 purchases and sales are contracts which provide for the purchase or sale of something, other than a financial instrument or derivative instrument that will be delivered in quantities expected to be used or sold by the reporting entity over a reasonable period in the normal course of business. The Partnership's forward natural gas and crude oil purchase and sales contracts are designated as normal purchases and normal sales. The Partnership uses financial instruments such as swaps, collars and other derivatives to mitigate the risks to cash flows resulting from changes in commodity prices and interest rates. The Partnership recognizes these financial instruments on its consolidated balance sheet at the instrument's fair value with changes in fair value reflected in the consolidated statement of operations, as the Partnership has not designated any of these derivative instruments as hedges. The cash flows from derivatives are reported as cash flows from operating activities unless the derivative contract is deemed to contain a financing element. Derivatives deemed to contain a financing element are reported as a financing activity in the consolidated statement of cash flows. See Note 11 for a description of the Partnership's risk management activities.
Reclassifications [Text Block]	Other Reclassifications—Certain prior period financial statement balances have been reclassified to conform to current period presentation. These reclassifications had no effect on the recorded net income.
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 obligations is estimated using valuation techniques that covert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of (i) remediation costs, (ii) remaining lives, (iii) future inflation factors and (iv) a credit-adjusted risk free interest rate.
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 December 31, 2014, 2013 and 2012, the Partnership had unvested restricted common units outstanding, which are considered dilutive securities. These units are considered in the diluted weighted average common unit outstanding number in periods of net income. In periods of net losses, these units are excluded from the diluted weighted average common unit outstanding number.
	The majority of the restricted units granted under the LTIP, as discussed in Note 16, contain non-forfeitable rights to the distributions declared by the Partnership and therefore meet the definition of participating securities. Participating securities are required to be included in the computation of earnings per unit pursuant to the two-class method. Restricted units granted in 2013 to certain senior executives and members of the board of directors are not eligible to receive the distributions declared by the Partnership and therefore do not meet the definition of participating securities.
Short-term Investments [Policy Text Block]	Short-term Investments— A portion of the consideration received for the Midstream Business Contribution included Regency common units, as further described in Note 1. These common units have a readily determinable fair value, are being classified as available-for-sale equity securities and are recorded as short-term investments on the consolidated balance sheets. Unrealized gains and losses associated with increases and decreases in the fair value of these securities are included in other comprehensive income until such time that the gains and losses become realized and then will be included in the consolidated statements of operations. Losses from declines in fair value determined to be other than temporary are recorded in the consolidated statement of operations. This loss is included in the consolidated statement of operations as a loss on short-term investments. Distributions received from Regency as a result of holding these common units are recorded as other income on the consolidated statement of operations. For the twelve months ended December 31, 2014, the Partnership received and recorded distributions from Regency of $8.0 million. During the fourth quarter of 2014, the Partnership recorded a $62.0 million loss associated with losses as the result of sale of common units and the decrease in the fair value of these securities that was deemed to be other than temporary and the sale of common units. As of December 31, 2014, the Partnership still held 6,393,657 Regency common units, which does not include the transactions to sell 262,496 Regency common units that had not settled as of December 31, 2014 and for which a receivable of $6.3 million was recorded as part accounts receivable in the consolidated balance sheet.

Summary_of_Significant_Account2

Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
Movement in Valuation Allowances and Reserves [Roll Forward]	The following is the activity within the Partnership's allowance for doubtful accounts during the years ended December 31, 2014, 2013 and 2012.
		2014			2013			2012
	($ in thousands)
	Balance at beginning of period	$	931		$	753		$	670
	Charged to bad debt expense	249			458			175
	Write-offs/adjustments charged to allowance	(157		)	(280		)	(92		)
	Balance at end of period	$	1,023		$	931		$	753

Acquisitions_Acquisitions_Tabl

Acquisitions Acquisitions (Tables)	12 Months Ended
	Dec. 31, 2014
Business Combinations [Abstract]
Schedule of Business Acquisitions, by Acquisition [Table Text Block]	The following presents the purchase price allocation for the system assets, based on estimates of fair value (in thousands):
	Current assets	$	779
	Property, plant, and equipment	206,849
	Rights-of-way and easements	27,232
	Current liabilities	(1,705		)
	Asset retirement obligations	(2,600		)
		$	230,555
Business Acquisition, Pro Forma Information [Table Text Block]	The amounts of revenue and net income generated by the acquired processing plants and gathering systems that are included within the Partnership's audited consolidated statement of operations for the year ended December 31, 2012 are as follows.
		Revenue			Net Income
		($ in thousands)
	Actual from October 1, 2012 to December 31, 2012	$	81,013		$	5,057

Property_Plant_and_Equipment_P

Property, Plant and Equipment Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2014
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment [Table Text Block]	Fixed assets consisted of the following:
		December 31,			December 31,
		2014			2013
		($ in thousands)
	Equipment and machinery	$	101		$	101
	Vehicles and transportation equipment	212			212
	Office equipment, furniture, and fixtures	3,020			1,391
	Computer equipment	13,234			12,247
	Proved properties	905,622			1,156,895
	Unproved properties	7,512			10,022
	Construction in progress	1,195			6,636
		930,896			1,187,504
	Less: accumulated depreciation, depletion and amortization	(442,908		)	(363,053		)
	Net property plant and equipment	$	487,988		$	824,451
	Amounts in the table above do not include the property, plant and equipment related to the Partnership's Midstream Business, as these amounts have been classified as assets held for sale within the audited consolidated balance sheets (See Note 18).
	The following table sets forth the total depreciation, depletion and impairment expense by type of asset within the Partnership's audited consolidated statements of operations:
		Year Ended December 31,
		2014			2013			2012
		($ in thousands)
	Depreciation	$	2,971		$	2,018		$	1,795
	Depletion	$	80,810		$	87,230		$	88,413
	Impairment expense:
	Proved properties (a)	$	395,892		$	207,085		$	38,943
	Unproved properties (b)	$	—		$	7,201		$	785
	__________________________________
	(a)	During the year ended December 31, 2014, the Partnership incurred impairment charges related to certain proved properties in all of its regions due primarily to lower commodity prices, higher operating costs and lower well performance. During the year ended December 31, 2013, the Partnership incurred impairment charges related primarily to certain proved properties, primarily in the Cana Shale in the Mid-Continent region and the Permian region, due to lower reserve forecasts. During the year ended December 31, 2012, the Partnership incurred impairment charges related to its proved properties in the Barnett Shale, East Texas and Permian regions that experienced reduced cash flows resulting from lower natural gas prices and continuing high operating costs associated with gas compression.
	(b)	During the year ended December 31, 2013, the Partnership incurred impairment charges related to certain leaseholds in the Mid-Continent regions that we expected to expire undrilled in 2014. During the year ended December 31, 2012, the Partnership incurred impairment charges related to certain unproved property leaseholds expected to expire undrilled in 2013.
	The table above does not include amounts related to the Partnership's Midstream Business, as these amounts have been classified as part of discontinued operations within the audited consolidated statements of operations (see Note 18).

Asset_Retirement_Obligations_A

Asset Retirement Obligations Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2014
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:
		2014			2013			2012
		($ in thousands)
	Asset retirement obligations—January 1	$	48,564		$	38,991		$	26,227
	Additional liabilities	237			1,076			1,400
	Liabilities settled	(1,347		)	(2,240		)	(1,664		)
	Revision to liabilities	168			7,654			11,146
	Accretion expense	3,251			3,083			1,882
	Asset retirement obligations—December 31 (a)	$	50,873		$	48,564		$	38,991
	_____________________________________
	(a)    As of December 31, 2014 and 2013, $3.0 million and $11.3 million, respectively, were included within accrued liabilities in the audited consolidated balance sheets.
	The table above does not include the balances or activity related to asset retirement obligations related to the Partnership's Midstream Business, as these amounts have been classified as liabilities held for sale within the audited consolidated balance sheets and discontinued operations within the audited consolidated statements of operations (see Note 18).

Intangible_Assets_Intangible_A

Intangible Assets Intangible Assets (Tables)	12 Months Ended
	Dec. 31, 2014
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of Finite-Lived Intangible Assets by Major Class [Table Text Block]	Intangible assets consisted of the following:
		December 31,			December 31,
		2014			2013
		($ in thousands)
	Rights-of-way and easements—at cost	$	3,920		$	3,920
	Less: accumulated amortization	(848		)	(652		)
	Net intangible assets	$	3,072		$	3,268
	Amounts in the table above do not include the intangible assets related to the Partnership's Midstream Business, as these amounts have been classified as assets held for sale within the audited consolidated balance sheets (See Note 18).
Schedule of Impaired Intangible Assets [Table Text Block]	The following table sets forth the total amortization expense within the Partnership's audited consolidated statements of operations:
		Year Ended December 31,
		2014			2013			2012
		($ in thousands)
	Amortization	$	196		$	196		$	302
	The table above does not include amounts related to the Partnership's Midstream Business, as these amounts have been classified as part of discontinued operations within the audited consolidated statements of operations (see Note 18).
Schedule of Finite-Lived Intangible Assets, Future Amortization Expense [Table Text Block]	Estimated future amortization expense related to the intangible assets at December 31, 2014, is as follows (in thousands):
	Year ending December 31,
	2015	$	196
	2016	$	196
	2017	$	196
	2018	$	196
	2019	$	196
	Thereafter	$	2,092

Long_Term_Debt_LongTerm_Debt_T

Long Term Debt Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2014
Long-term Debt, by Current and Noncurrent [Abstract]
Schedule of Debt Covenants [Table Text Block]	The following table presents the debt covenant levels specified in our revolving credit facility as of December 31, 2014:
	Quarter Ended	Total Leverage Ratio(a)	Current Ratio(b)
	December 31, 2014 and Thereafter until Maturity (October 2019)	4	1
	_____________________
	(a)	Amount represents the maximum ratio for the period presented.
	(b)	Amount represents the minimum ratio for the period presented.
	The following table presents our actual covenant ratios as of December 31, 2014:
	Total leverage ratio	2.2
	Current ratio	5.2
Schedule of Long-term Debt Instruments [Table Text Block]	Long-term debt consisted of the following:
		December 31,			December 31,
		2014			2013
		($ in thousands)
	Revolving credit facility:	$	212,600		$	706,800
	Senior Notes:
	8.375% Senior Notes due 2019	51,120			51,120
	Unamortized bond discount	(377		)	(440		)
	Total Senior Notes	50,743			50,680
	Total long-term debt	$	263,343		$	757,480
	Amounts in the table above do not include the portion of the Senior Notes that were exchanged for Regency unsecured senior notes upon the completion of the Midstream Business Contribution on July 1, 2014 (see Note 1). These notes have been classified as part of liabilities held for sale within the unaudited condensed consolidated balance sheet for December 31, 2013 and were exchanged on July 1, 2014 (see Note 18).
	On July 1, 2014, the Partnership used the cash received from Regency for the Midstream Business Contribution (see Note 1) to paydown $570.4 million outstanding under its Credit Agreement.
Schedule of Maturities of Long-term Debt [Table Text Block]	Scheduled maturities of long-term debt as of December 31, 2014, were as follows:
		Principal Amount
		($ in thousands)
	2015	$	—
	2016	—
	2017	—
	2018	—
	2019	263,720
	2020 and after	—
		$	263,720

Members_Equity_Members_Equity_

Members' Equity Members' Equity (Tables)	12 Months Ended
	Dec. 31, 2014
Partners' Capital [Abstract]
Schedule of Distributions Made to Members or Limited Partners, by Distribution [Table Text Block]	On October 27, 2014, the Partnership announced that the Board of Directors authorized a common unit repurchase program of up to $100 million through which repurchases may be made from time to time at prevailing prices on the open market or in privately negotiated transactions. The program was authorized to commence following the filing of the Partnership's Quarterly Report on Form 10-Q for the quarter ending September 30, 2014 and will conclude by March 31, 2016. The repurchase program does not obligate the Partnership to acquire any, or any specific number of, units and may be discontinued at any time. The Partnership intends to cancel any units it repurchases under the repurchase program. As of December 31, 2014, the Partnership had repurchased a total of 7,455,887 of its common units under this program for approximately $19.2 million, of which, transactions to repurchase 641,400 units had not settled as of December 31, 2014 and for which a liability of $1.3 million was recorded as part of accounts payable in the consolidated balance sheet.
	The table below summarizes the distributions paid or payable for the last three years
	Quarter Ended		Distribution		Record Date**	Payment Date
			per Unit
	March 31, 2012+		$	0.22	May 8, 2012	May 15, 2012
	June 30, 2012+		$	0.22	August 7, 2012	August 14, 2012
	September 30, 2012+		$	0.22	November 7, 2012	November 14, 2012
	December 31, 2012+		$	0.22	February 7, 2013	February 14, 2013
	March 31, 2013+*		$	0.22	May 7, 2013	May 15, 2013
	June 30, 2013+*		$	0.22	August 7, 2013	August 14, 2013
	September 30, 2013+*		$	0.15	November 7, 2013	November 14, 2013
	December 31, 2013+*		$	0.15	February 7, 2014	February 14, 2014
	March 31, 2014***		$	—	N/A	N/A
	June 30, 2014***		$	—	N/A	N/A
	September 30, 2014+*		$	0.07	November 7, 2014	November 14, 2014
	December 31, 2014+*		$	0.07	February 6, 2015	February 13, 2015
	_____________________________
	+	The distribution per unit represents distributions made only on common units, including restricted common units issued under our Long Term Incentive Plan ("LTIP"). Since July 30, 2010, the only other class of equity we have outstanding is a non-economic general partner interest.
	*	The distribution excludes certain restricted units under the LTIP.
	**	The "Record Date" set forth in the table above means the close of business on each of the listed Record Dates.
	***	No distribution was declared or paid for this period.

Related_Party_Transactions_Rel

Related Party Transactions Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2014
Related Party Transactions [Abstract]
Schedule of Related Party Transactions [Table Text Block]	The following table summarizes transactions between the Partnership and certain affiliated entities:
		Year Ended December 31,
		2014		2013		2012
	Affiliates of Natural Gas Partners:	($ in thousands)
	Natural gas purchases from affiliates	$	2,091	$	2,938	$	2,713
	Payable as of December 31 (related to natural gas purchases)	$	—	$	18	$	428
	The transactions above are all related to the Partnership's Midstream Business and have been classified as part of discontinued operations within the consolidated statements of operations and liabilities held for sale within the consolidated balance sheet (see Note 18).

Risk_Management_Activities_Ris

Risk Management Activities Risk Management Activities (Tables)	12 Months Ended
	Dec. 31, 2014
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 various interest rate swaps as of December 31, 2014:
	Effective Date		Expiration		Notional			Fixed
			Date		Amount			Rate
	12/31/14		12/31/19		$	175,000,000		2.3195	%
Schedule of Price Risk Derivatives [Table Text Block]	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 December 31, 2014, that will mature during the years ended December 31, 2015, 2016, 2017, 2018 and 2019:
	Underlying		Type		Notional		Floor				Cap
					Volumes		Strike				Strike
					(units) (a)		Price				Price
							($/unit)(b)				($/unit)(b)
	Portion of Contracts Maturing in 2015
	Natural Gas		Swap (Pay Floating/Receive Fixed)		10,800,000		$	4.07
	Crude Oil		Costless Collar		480,000		$	90			$	97.55
	Crude Oil		Swap (Pay Floating/Receive Fixed)		630,000		$	89.78
	Portion of Contracts Maturing in 2016
	Natural Gas		Swap (Pay Floating/Receive Fixed)		9,480,000		$	4.25
	Crude Oil		Swap (Pay Floating/Receive Fixed)		936,000		$	84.66
	Portion of Contracts Maturing in 2017
	Crude Oil		Swap (Pay Floating/Receive Fixed)		444,000		$	89.24
	Portion of Contracts Maturing in 2018
	Crude Oil		Swap (Pay Floating/Receive Fixed)		396,000		$	88.78
	Portion of Contracts Maturing in 2019
	Crude Oil		Swap (Pay Floating/Receive Fixed)		348,000		$	88.39
	_______________________
	(a)	Volumes of natural gas are measured in MMbtu, volumes of crude oil are measured in barrels, and volumes of natural gas liquids are measured in gallons.
	(b)	Amounts represent the weighted average price. The weighted average prices are in $/MMbtu for natural gas, $/barrel for crude oil and $/gallon for natural gas liquids.
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block]
	Fair values of interest rate and commodity derivative instruments not designated as hedging instruments in the consolidated balance sheet as of December 31, 2014 and December 31, 2013:
		As of
		31-Dec-14
		Derivative Assets					Derivative Liabilities
		Balance Sheet Classification		Fair Value			Balance Sheet Classification		Fair Value
		($ in thousands)
	Interest rate derivatives - liabilities	Current assets		$	(3,165	)	Current liabilities		$	—
	Interest rate derivatives - liabilities	Long-term assets		(2,641		)	Long-term liabilities		—
	Commodity derivatives - assets	Current assets		47,971			Current liabilities		—
	Commodity derivatives - assets	Long-term assets		49,130			Long-term liabilities		—
	Commodity derivatives - assets	Assets held for sale		—			Liabilities held for sale		—
	Commodity derivatives - liabilities	Current assets		—			Current liabilities		—
	Commodity derivatives - liabilities	Long-term assets		—			Long-term liabilities		—
	Commodity derivatives - liabilities	Assets held for sale		—			Liabilities held for sale		—
	Total derivatives			$	91,295				$	—
		As of
		31-Dec-13
		Derivative Assets					Derivative Liabilities
		Balance Sheet Classification		Fair Value			Balance Sheet Classification		Fair Value
		($ in thousands)
	Interest rate derivatives - liabilities	Current assets		$	—		Current liabilities		$	(6,210	)
	Interest rate derivatives - liabilities	Long-term assets		—			Long-term liabilities		(2,885		)
	Commodity derivatives - assets	Current assets		6,841			Current liabilities		1,043
	Commodity derivatives - assets	Long-term assets		4,669			Long-term liabilities		202
	Commodity derivatives - assets	Assets held for sale		6,017			Liabilities held for sale		1,973
	Commodity derivatives - liabilities	Current assets		(1,282		)	Current liabilities		(3,193		)
	Commodity derivatives - liabilities	Long-term assets		(798		)	Long-term liabilities		(143		)
	Commodity derivatives - liabilities	Assets held for sale		(824		)	Liabilities held for sale		(5,658		)
	Total derivatives			$	14,623				$	(14,871	)
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 audited consolidated statement of operations (in thousands):
	Amount of Gain (Loss) Recognized in Income on Derivatives			Year Ended December 31,
				2014			2013				2012
	Interest rate derivatives	Interest rate risk management losses, net		$	(1,734	)	$	(1,104	)		$	(4,727	)
	Commodity derivatives	Commodity risk management gains (losses), net		94,431			(3,937		)		28,110
	Commodity derivatives	Discontinued operations		(15,477		)	(14,596		)		29,784
	Commodity derivatives -trading	Discontinued operations		(2,404		)	315				(192		)
		Total		$	74,816		$	(19,322	)		$	52,975

Fair_Value_of_Financial_Instru1

Fair Value of Financial Instruments Fair Value of Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2014
Fair Value Disclosures [Abstract]
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]	The following table discloses the fair value of the Partnership's derivative instruments and equity investments as of December 31, 2014 and 2013:
		As of
		31-Dec-14
		Level 1		Level 2			Level 3		Netting (a)			Total
		($ in thousands)
	Assets:
	Crude oil derivatives	$	—	$	78,516		$	—	$	—		$	78,516
	Natural gas derivatives	—		18,585			—		—			18,585
	Interest rate swaps	—		—			—		(5,806		)	(5,806		)
	Equity investments	153,448		—			—		—			153,448
	Total	$	153,448	$	97,101		$	—	$	(5,806	)	$	244,743
	Liabilities:
	Interest rate swaps	$	—	$	(5,806	)	$	—	$	5,806		$	—
	Total	$	—	$	(5,806	)	$	—	$	5,806		$	—
	____________________________
	(a)	Represents counterparty netting under agreement governing such derivative contracts.
		As of
		31-Dec-13
		Level 1		Level 2			Level 3		Netting (a)			Total
		($ in thousands)
	Assets:
	Crude oil derivatives	$	—	$	6,151		$	—	$	(1,716	)	$	4,435
	Natural gas derivatives	—		6,562			—		(1,567		)	4,995
	NGL derivatives	—		42			—		(42		)	—
	Total	$	—	$	12,755		$	—	$	(3,325	)	$	9,430
	Liabilities:
	Crude oil derivatives	$	—	$	(1,792	)	$	—	$	1,716		$	(76	)
	Natural gas derivatives	—		(2,503		)	—		1,567			(936		)
	NGL derivatives	—		(1,121		)	—		42			(1,079		)
	Interest rate swaps	—		(9,095		)	—		—			(9,095		)
	Total	$	—	$	(14,511	)	$	—	$	3,325		$	(11,186	)
	____________________________
	(a)	Represents counterparty netting under agreement governing such derivative contracts.
	The tables above do not include the fair value of the derivative contracts that have been classified as assets and liabilities held for sale within the audited consolidated balance sheet (see Note 18).
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis [Table Text Block]	The following table discloses the fair value of the Partnership's assets measured at fair value on a nonrecurring basis for the year ended December 31, 2014:
		December 31,		Level 1			Level 2		Level 3			Total Losses
		2014
		($ in thousands)
	Proved properties	$	305,006	$	—		$	—	$	305,006		$	395,892
	Plant assets	$	52	$	—		$	—	$	52		$	132
	Pipeline assets	$	746	$	—		$	—	$	746		$	1,904
	Rights-of-way	$	24	$	—		$	—	$	24		$	61

Commitments_and_Contingencies_

Commitments and Contingencies Non-Cancelable Operating Lease Schedule (Tables)	12 Months Ended
	Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
Schedule of Future Minimum Rental Payments for Operating Leases [Table Text Block]	At December 31, 2014, commitments under long-term non-cancelable operating leases for the next five years are as follows (in thousands):
	Year ending December 31,
	2015	$	5,853
	2016	$	3,899
	2017	$	2,799
	2018	$	438
	2019	$	—

Income_Taxes_Income_Taxes_Tabl

Income Taxes Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]	The Partnership's federal and state income tax provision is summarized below (in thousands):
		For the Year Ended December 31,
		2014			2013			2012
	Current:
	Federal	$	(475	)	$	(105	)	$	621
	State	8			—			18
	Total current provision	(467		)	(105		)	639
	Deferred:
	Federal	(2,593		)	(3,837		)	(2,776		)
	State	(2,343		)	(1,653		)	1,044
	Total deferred	(4,936		)	(5,490		)	(1,732		)
	Total (benefit) provision for income taxes	$	(5,403	)	$	(5,595	)	(1,093		)
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]	A reconciliation of the provision for income taxes with amounts determined by applying the statutory U.S. federal income tax rate to income before income taxes is as follows (in thousands):
		For the Year Ended December 31,
		2014			2013			2012
	Pre-tax net book (loss) income from continuing operations	(357,770		)	(233,766		)	(33,239		)
	State income tax current and deferred	(2,335		)	(1,653		)	1,062
	Federal income taxes computed by applying the federal statutory rate to NBI of corporate entities	(2,680		)	(4,160		)	(2,155		)
	Tax attributes used	(388		)	218			—
	Benefit for income taxes from continuing operations	$	(5,403	)	$	(5,595	)	$	(1,093	)
	Effective income tax rate on continuing operations	1.5		%	2.4		%	3.3		%
Schedule of Deferred Tax Assets and Liabilities [Table Text Block]	Significant components of deferred tax liabilities and deferred tax assets as of December 31, 2014 and 2013 are as follows (in thousands):
		December 31, 2014			December 31, 2013
	Deferred Tax Assets:
	Statutory depletion carryover	$	1,842		$	1,438
	Property, plant, equipment & amortizable assets	473			—
	Total Deferred Tax Assets	2,315			1,438
	Deferred Tax Liabilities:
	Property, plant, equipment & amortizable assets	—			(2,011		)
	Hedging transactions	(424		)	—
	Book/tax differences from partnership investment	(29,897		)	(32,086		)
	Total Deferred Tax Liabilities	(30,321		)	(34,097		)
	Total Net Deferred Tax Liabilities	(28,006		)	(32,659		)
	Current portion of total net deferred tax liabilities	—			—
	Long-term portion of total net deferred tax liabilities	$	(28,006	)	$	(32,659	)
Summary of Income Tax Contingencies [Table Text Block]	A reconciliation of the beginning and ending amount of the unrecognized tax benefits (liabilities) is as follows (in thousands):
		2014			2013			2012
	Balance at beginning of period	$	(649	)	$	(830	)	$	(735	)
	Increases related to current year tax positions	—			(128		)	(53		)
	Increases related to tax interest and penalties	—			(39		)	(42		)
	Decreases related to statutory limitations	226			267			—
	Decreases related to tax interest and penalties	58			81			—
	Balance at end of period	$	(365	)	$	(649	)	$	(830	)

Equity_Based_Compensation_Equi

Equity Based Compensation Equity Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2014
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 year ended December 31, 2014 is provided below:
		Number of		Weighted
		Restricted		Average
		Units		Fair Value
	Outstanding at December 31, 2013	2,743,807		$	9.37
	Granted	1,903,333		$	4.44
	Vested	(1,305,433	)	$	9.6
	Forfeited	(921,957	)	$	8.12
	Outstanding at December 31, 2014	2,419,750		$	6.06
	A summary of the changes in outstanding performance units for the year ended December 31, 2014 is provided below:
		Number of		Weighted
		Performance		Average
		Units		Fair Value
	Outstanding at December 31, 2013	—		$	—
	Granted	715,263		$	3.63
	Forfeited	(67,475	)	3.59
	Outstanding at December 31, 2014	647,788		3.63

Earnings_Per_Unit_Earnings_Per

Earnings Per Unit Earnings Per Unit (Tables)	12 Months Ended
	Dec. 31, 2014
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:
		Year Ended December 31,
		2014			2013		2012
		(in thousands)
	Weighted average units outstanding during period:
	Common units - Basic	156,700			153,562		135,609
	Common units - Diluted	156,700			153,562		135,609
Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]	The following table presents the Partnership's basic and diluted income (loss) per unit for the year ended December 31, 2014:
			Total			Common Units			Restricted Common Units
			($ in thousands, except for per unit amounts)
	Loss from continuing operations		$	(352,367	)
	Distributions		21,763			$	21,464		$	299
	Assumed loss from continuing operations after distribution to be allocated		(374,130		)	(374,130		)	—
	Assumed allocation of loss from continuing operations		(352,367		)	(352,666		)	299
	Discontinued operations, net of tax		212,460			212,460			—
	Assumed net loss to be allocated		$	(139,907	)	$	(140,206	)	$	299
	Basic loss from continuing operations per unit					$	(2.25	)
	Basic discontinued operations per unit					$	1.36
	Basic net loss per unit					$	(0.89	)
	Diluted loss from continuing operations per unit					$	(2.25	)
	Diluted discontinued operations per unit					$	1.36
	Diluted net loss per unit					$	(0.89	)
	The following table presents the Partnership's basic and diluted income per unit for the year ended December 31, 2013:
			Total			Common Units			Restricted Common Units
			($ in thousands, except for per unit amounts)
	Loss from continuing operations		$	(228,171	)
	Distributions		117,294			$	115,351		$	1,943
	Assumed loss from continuing operations after distribution to be allocated		(345,465		)	(345,465		)	—
	Assumed allocation of loss from continuing operations		(228,171		)	(230,114		)	1,943
	Discontinued operations, net of tax		(49,808		)	(49,808		)	—
	Assumed net loss to be allocated		$	(277,979	)	$	(279,922	)	$	1,943
	Basic loss from continuing operations per unit					$	(1.50	)
	Basic discontinued operations per unit					$	(0.32	)
	Basic net loss per unit					$	(1.82	)
	Diluted loss from continuing operations per unit					$	(1.50	)
	Diluted discontinued operations per unit					$	(0.32	)
	Diluted net loss per unit					$	(1.82	)
	The following table presents the Partnership's basic and diluted income per unit for the year ended December 31, 2012:
			Total			Common Units			Restricted Common Units
			($ in thousands, except for per unit amounts)
	Loss from continuing operations		$	(32,146	)
	Distributions		124,235			$	121,504		$	2,731
	Assumed loss from continuing operations after distribution to be allocated		(156,381		)	(156,381		)	—
	Assumed allocation of loss from continuing operations		(32,146		)	(34,877		)	2,731
	Discontinued operations, net of tax		(118,456		)	(118,456		)	—
	Assumed net loss to be allocated		$	(150,602	)	$	(153,333	)	$	2,731
	Basic loss from continuing operations per unit					$	(0.26	)
	Basic discontinued operations per unit					$	(0.87	)
	Basic net loss per unit					$	(1.13	)
	Diluted loss from continuing operations per unit					$	(0.26	)
	Diluted discontinued operations per unit					$	(0.87	)
	Diluted net loss per unit					$	(1.13	)

Divestiture_Related_Activities1

Divestiture Related Activities Divestiture Related Activities (Tables)	12 Months Ended
	Dec. 31, 2014
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 is the reconciliation of the major classes of assets and liabilities classified as held for sale.
		December 31,				December 31,
		2014				2013
		($ in thousands)
	Assets held-for-sale
	Accounts Receivable	$	—			$	128,713
	Property, plant and equipment	—				1,004,317
	Intangible assets	—				102,352
	Other current assets	—				5,663
	Other long-term assets	—				18,337
	Total assets held-for-sale	$	—			$	1,259,382
	Liabilities held-for-sale
	Long-term debt	$	—			$	494,582
	Accounts payable and accrued liabilities	—				119,966
	Other current liabilities	—				9,471
	Other long-term liabilities	—				13,719
	Total liabilities held-for-sale	$	—			$	637,738
	The following table represents the reconciliation of major classes of line items classified as discontinued operations for midstream business for the years ended December 31, 2014, 2013 and 2012:
			December 31, 2014				December 31, 2013				December 31, 2012
			($ in thousands)
	Class of statement of operations line item of discontinued operations:
	Revenues		$	552,574			$	997,907			$	752,644
	Cost of natural gas, natural gas liquids, condensate and helium		447,519				790,618				532,719
	Operations, maintenance and taxes other than income		50,154				101,121				82,526
	General and administrative		18,392				28,083				19,004
	Depreciation, amortization and impairment		41,936				77,726				202,249
	Interest expense		27,350				49,973				35,202
	Other (expense) income		(68		)		287				(10		)
	Operating loss from discontinued operations before taxes		(32,845		)		(49,327		)		(119,066		)
	Gain on sale of assets		243,637				—				—
	Income tax expense		(1,668		)		481				(610		)
	Discontinued operations, net of tax		$	212,460			$	(49,808	)		$	(118,456	)
Schedule of Restructuring Reserve by Type of Cost [Table Text Block]	The following table summarizes activity related to liabilities associated with the Partnership's restructuring activities during the year ended December 31, 2014.
		Employee Related Costs				Facility and Other Costs				Total
		($ in thousands)
	Balance at December 31, 2013	$	—			$	—			$	—
	Additions	4,033				563				4,596
	Payments and other adjustments	(3,198		)		(73		)		(3,271		)
	Balance at December 31, 2014	$	835			$	490			$	1,325

Divestiture_Related_Activities2

Divestiture Related Activities Divestiture Related Activities - Restructuring Charges (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Restructuring Cost and Reserve [Line Items]
Increase (Decrease) in Restructuring Reserve	$4,596
Restructuring and Related Cost, Incurred Cost	-3,271
Restructuring Reserve, Current	1,325	0
One-time Termination Benefits [Member]
Restructuring Cost and Reserve [Line Items]
Increase (Decrease) in Restructuring Reserve	4,033
Restructuring and Related Cost, Incurred Cost	-3,198
Restructuring Reserve, Current	835	0
Facility Closing [Member]
Restructuring Cost and Reserve [Line Items]
Increase (Decrease) in Restructuring Reserve	563
Restructuring and Related Cost, Incurred Cost	-73
Restructuring Reserve, Current	490	0
Software and Software Development Costs [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring and Related Cost, Cost Incurred to Date	$1,724

Subsidiary_Guarantors_Subsidia

Subsidiary Guarantors Subsidiary Guarantors (Tables)	12 Months Ended
	Dec. 31, 2014
SUBSIDIARY GUARANTORS UNAUDITED CONSOLIDATING BALANCE SHEET [Abstract]
Subsidiary Guarantor Consolidating Balance Sheet [Table Text Block]	Condensed Consolidating Balance Sheet
	December 31, 2014
		Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-guarantor investments			Consolidating			Total
													Entries
		($ in thousands)
	ASSETS:
	Accounts receivable – related parties	$	838,656		$	—	$	—		$	—		$	(838,656	)	$	—
	Other current assets	211,213			1		37,889			—			—			249,103
	Total property, plant and equipment, net	1,334			—		486,654			—			—			487,988
	Investment in subsidiaries	(413,023		)	—		—			—			413,023			—
	Total other long-term assets	52,272			—		4,912			—			—			57,184
	Total assets	$	690,452		$	1	$	529,455		$	—		$	(425,633	)	$	794,275
	LIABILITIES AND EQUITY:
	Accounts payable – related parties	$	—		$	—	$	838,656		$	—		$	(838,656	)	$	—
	Other current liabilities	37,850			—		21,675			—			—			59,525
	Other long-term liabilities	789			—		82,148			—			—			82,937
	Long-term debt	263,343			—		—			—			—			263,343
	Equity	388,470			1		(413,024		)	—			413,023			388,470
	Total liabilities and equity	$	690,452		$	1	$	529,455		$	—		$	(425,633	)	$	794,275
	Condensed Consolidating Balance Sheet
	December 31, 2013
		Parent Issuer			Co-Issuer		Subsidiary			Non-guarantor investments			Consolidating Entries			Total
							Guarantors
		($ in thousands)
	ASSETS:
	Accounts receivable – related parties	$	691,588		$	—	$	—		$	—		$	(691,588	)	$	—
	Assets held for sale	8,762			—		1,250,620			—			—			1,259,382
	Other current assets	6,927			1		22,080			—			—			29,008
	Total property, plant and equipment, net	2,318			—		822,133			—			—			824,451
	Investment in subsidiaries	1,133,217			—		—			908			(1,134,125		)	—
	Total other long-term assets	10,012			—		4,697			—			—			14,709
	Total assets	$	1,852,824		$	1	$	2,099,530		$	908		$	(1,825,713	)	$	2,127,550
	LIABILITIES AND EQUITY:
	Accounts payable – related parties	$	—		$	—	$	691,588		$	—		$	(691,588	)	$	—
	Liabilities held for sale	500,291			—		137,447			—			—			637,738
	Other current liabilities	15,688			—		66,141			—			—			81,829
	Other long-term liabilities	5,486			—		71,138			—			—			76,624
	Long-term debt	757,480			—		—			—			—			757,480
	Equity	573,879			1		1,133,216			908			(1,134,125		)	573,879
	Total liabilities and equity	$	1,852,824		$	1	$	2,099,530		$	908		$	(1,825,713	)	$	2,127,550
Subsidiary Guarantors Consolidating Statements of Operations [Table Text Block]	Condensed Consolidating Statement of Operations
	For the Year Ended December 31, 2014
		Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-guarantor investments			Consolidating			Total
													Entries
		($ in thousands)
	Total revenues	$	93,940		$	—	$	204,264		$	—		$	—		$	298,204
	Operations and maintenance	3			—		43,667			—			—			43,670
	Taxes other than income	—			—		12,925			—			—			12,925
	General and administrative	9,654			—		37,539			—			—			47,193
	Depreciation, depletion and amortization	641			—		84,938			—			—			85,579
	Impairment and other	—			—		395,892			—			—			395,892
	Income (loss) from operations	83,642			—		(370,697		)	—			—			(287,055		)
	Interest expense, net	(15,247		)	—		—			—			—			(15,247		)
	Other non-operating income	16,998			—		4,741			—			(13,445		)	8,294
	Other non-operating expense	(7,396		)	—		(7,783		)	—			13,445			(1,734		)
	Loss on short term investments	(62,028		)	—		—			—			—			(62,028		)
	Income (loss) before income taxes	15,969			—		(373,739		)	—			—			(357,770		)
	Income tax benefit	(3,791		)	—		(1,612		)	—			—			(5,403		)
	Equity in earnings of subsidiaries	(683,371		)	—		—			—			683,371			—
	Loss from continuing operations	(663,611		)	—		(372,127		)	—			683,371			(352,367		)
	Discontinued operations, net of tax	523,704			—		(311,235		)	(9		)	—			212,460
	Net loss	$	(139,907	)	$	—	$	(683,362	)	$	(9	)	$	683,371		$	(139,907	)
	Condensed Consolidating Statement of Operations
	For the Year Ended December 31, 2013
		Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-guarantor investments			Consolidating Entries			Total
		($ in thousands)
	Total revenues	$	(3,937	)	$	—	$	201,309		$	—		$	—		$	197,372
	Operations and maintenance	—			—		41,426			—			—			41,426
	Taxes other than income	—			—		12,928			—			—			12,928
	General and administrative	13,145			—		39,986			—			—			53,131
	Depreciation, depletion and amortization	454			—		88,990			—			—			89,444
	Impairment	—			—		214,286			—			—			214,286
	Loss from operations	(17,536		)	—		(196,307		)	—			—			(213,843		)
	Interest expense, net	(17,891		)	—		(898		)	—			—			(18,789		)
	Other non-operating income	9,025			—		9,298			—			(18,323		)	—
	Other non-operating expense	(6,904		)	—		(12,553		)	—			18,323			(1,134		)
	Loss before income taxes	(33,306		)	—		(200,460		)	—			—			(233,766		)
	Income tax provision (benefit)	(1,653		)	—		(3,942		)	—			—			(5,595		)
	Equity in earnings of subsidiaries	(191,071		)	—		—			—			191,071			—
	Loss from continuing operations	(222,724		)	—		(196,518		)	—			191,071			(228,171		)
	Discontinued operations, net of tax	(55,255		)	—		5,457			(10		)	—			(49,808		)
	Net loss	$	(277,979	)	$	—	$	(191,061	)	$	(10	)	$	191,071		$	(277,979	)
	Condensed Consolidating Statement of Operations
	For the Year Ended December 31, 2012
		Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-guarantor investments			Consolidating			Total
													Entries
		($ in thousands)
	Total revenues	$	28,110		$	—	$	203,205		$	—		$	—		$	231,315
	Operations and maintenance	—			—		41,391			—			—			41,391
	Taxes other than income	—			—		15,343			—			—			15,343
	General and administrative	8,745			—		42,245			—			—			50,990
	Depreciation, depletion and amortization	296			—		90,214			—			—			90,510
	Impairment	—			—		45,289			—			—			45,289
	Income (loss) from operations	19,069			—		(31,277		)	—			—			(12,208		)
	Interest expense, net	(16,299		)	—		23			—			—			(16,276		)
	Other non-operating income	9,039			—		10,961			—			(20,000		)	—
	Other non-operating expense	(12,189		)	—		(12,566		)	—			20,000			(4,755		)
	Loss before income taxes	(380		)	—		(32,859		)	—			—			(33,239		)
	Income tax provision (benefit)	1,041			—		(2,134		)	—			—			(1,093		)
	Equity in earnings of subsidiaries	(113,200		)	—		—			—			113,200			—
	Loss from continuing operations	(114,621		)	—		(30,725		)	—			113,200			(32,146		)
	Discontinued operations, net of tax	(35,981		)	—		(82,457		)	(18		)	—			(118,456		)
	Net loss	$	(150,602	)	$	—	$	(113,182	)	$	(18	)	$	113,200		$	(150,602	)
Subsidiary Guarantor Consolidating Statements of Cash Flows [Table Text Block]	Condensed Consolidating Statement of Cash Flows
	For the Year Ended December 31, 2014
		Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-guarantor investments			Consolidating Entries			Total
		($ in thousands)
	Net cash flows (used in) provided by operating activities	$	(28,661	)	$	—	$	106,787		$	—		$	—		$	78,126
	CASH FLOWS FROM INVESTING ACTIVITIES:
	Additions to property, plant and equipment	344			—		(137,038		)	—			—			(136,694		)
	Proceeds from sale of short-term investments	43,836			—		—			—			—			43,836
	Net cash flows provided by (used in) investing activities	44,180			—		(137,038		)	—			—			(92,858		)
	CASH FLOWS FROM FINANCING ACTIVITIES:
	Proceeds from long-term debt	472,500			—		—			—			—			472,500
	Repayment of long-term debt	(966,700		)	—		—			—			—			(966,700		)
	Payment of debt issuance cost	(1,984		)	—		—			—			—			(1,984		)
	Proceeds from derivative contracts	(5,022		)	—		—			—			—			(5,022		)
	Repurchase of common units	(19,170		)	—		—			—			—			(19,170		)
	Distributions to members and affiliates	(34,982		)	—		—			—			—			(34,982		)
	Net cash flows used in financing activities	(555,358		)	—		—			—			—			(555,358		)
	Net cash flows provided by discontinued operations	541,288			—		30,047			22			—			571,357
	Net increase (decrease) in cash and cash equivalents	1,449			—		(204		)	22			—			1,267
	Cash and cash equivalents at beginning of year	1,237			1		(1,389		)	227			—			76
	Cash and cash equivalents at end of year	$	2,686		$	1	$	(1,593	)	$	249		$	—		$	1,343
	Condensed Consolidating Statement of Cash Flows
	For the Year Ended December 31, 2013
		Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-guarantor Investments			Consolidating Entries			Total
		($ in thousands)
	Net cash flows (used in) provided by operating activities	$	(34,610	)	$	—	$	148,853		$	—		$	—		$	114,243
	CASH FLOWS FROM INVESTING ACTIVITIES:
	Additions to property, plant and equipment	(115		)	—		(149,829		)	—			—			(149,944		)
	Proceeds from sale of asset	—			—		76			—			—			76
	Net cash flows used in investing activities	(115		)	—		(149,753		)	—			—			(149,868		)
	CASH FLOWS FROM FINANCING ACTIVITIES:
	Proceeds from long-term debt	601,400			—		—			—			—			601,400
	Repayment of long-term debt	(503,100		)	—		—			—			—			(503,100		)
	Proceeds from derivatives contracts	1,323			—		—			—			—			1,323
	Common unit issued in equity offerings	102,388			—		—			—			—			102,388
	Issuance costs for equity offerings	(4,519		)	—		—			—			—			(4,519		)
	Repurchase of common units	(1,858		)	—		—			—			—			(1,858		)
	Distributions to members and affiliates	(125,911		)	—		—			—			—			(125,911		)
	Net cash flows provided by financing activities	69,723			—		—			—			—			69,723
	Net cash flows provided by (used in) discontinued operations	(35,431		)	—		1,343			41			—			(34,047		)
	Net (decrease) increase in cash and cash equivalents	(433		)	—		443			41			—			51
	Cash and cash equivalents at beginning of year	1,670			1		(1,832		)	186			—			25
	Cash and cash equivalents at end of year	$	1,237		$	1	$	(1,389	)	$	227		$	—		$	76
	Condensed Consolidating Statement of Cash Flows
	For the Year Ended December 31, 2012
		Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-guarantor Investments			Consolidating Entries			Total
		($ in thousands)
	Net cash flows (used in) provided by operating activities	$	(108,061	)	$	—	$	183,397		$	—		$	—		$	75,336
	CASH FLOWS FROM INVESTING ACTIVITIES:
	Additions to property, plant and equipment	(1,551		)	—		(166,356		)	—			—			(167,907		)
	Proceeds from sale of asset	—			—		15,398			—			—			15,398
	Contribution to subsidiaries	(236,971		)	—		—			—			236,971			—
	Net cash flows used in investing activities	(238,522		)	—		(150,958		)	—			236,971			(152,509		)
	CASH FLOWS FROM FINANCING ACTIVITIES:
	Proceeds from long-term debt	1,043,750			—		—			—			—			1,043,750
	Repayment of long-term debt	(916,750		)	—		—			—			—			(916,750		)
	Proceed from senior notes	22,889			—		—			—			—			22,889
	Payments of debt issuance cost	(614		)	—		—			—			—			(614		)
	Proceeds from derivative contracts	14,449			—		—			—			—			14,449
	Common unit issued in equity offerings	96,173			—		—			—			—			96,173
	Issuance costs for equity offerings	(4,518		)	—		—			—			—			(4,518		)
	Exercise of Warrants	31,804			—		—			—			—			31,804
	Repurchase of common units	(2,501		)	—		—			—			—			(2,501		)
	Distributions to members and affiliates	(119,211		)	—		—			—			—			(119,211		)
Net cash flows provided by financing activities	165,471			—		—			—			—			165,471
Net cash flows provided by (used in) discontinued operations	181,463			—		(33,699		)	57			(236,971		)	(89,150		)
Net increase (decrease) in cash and cash equivalents	351			—		(1,260		)	57			—			(852		)
Cash and cash equivalents at beginning of year	1,319			1		(572		)	129			—			877
Cash and cash equivalents at end of year	$	1,670		$	1	$	(1,832	)	$	186		$	—		$	25

Supplemental_Oil_and_Gas_Infor1

Supplemental Oil and Gas Information (Unaudited) Supplemental Oil and Gas Information (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2014
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities [Table Text Block]	Proved Reserves Summary
	The following table illustrates the Partnership's estimated net proved reserves, including changes, and proved developed reserves for the periods indicated, as estimated by Cawley, Gillespie and Associates. Oil and natural gas liquids prices applied for 2014 are based on an average of the prior twelve months first-of-month spot prices of West Texas Intermediate ($94.99 per barrel) and are adjusted for quality, transportation fees, and price differentials. Likewise, natural gas prices applied for 2014 are based on an average of the prior twelve months first-of-month spot prices of Henry Hub natural gas ($4.35 per MMBtu) and are adjusted for energy content, transportation fees, and regional price differentials. All prices are held constant in accordance with SEC guidelines.
	As shown in the following reconciliation table, the Partnership recognized significant negative revisions to its estimates of proved reserves in 2014. These revisions to previous estimates were primarily the result of recategorizing a number of undeveloped locations from proved to probable reserves due to poor expected economic performance (a decrease of 3.0 Bcfe), recategorizing other proved undeveloped locations as contingent resources since they were non-commercial at the time (a decrease of 0.2 Bcfe), and other factors including increased costs, negative changes to forecast performance expectations and widening product price differentials (a decrease of 44.6 Bcfe).
		Proved Reserves
		Oil			Gas			Natural Gas
		(MBbls)			(MMcf)			Liquids (MBbls)
	Proved reserves, January 1, 2012	11,522			234,022			11,347
	Extensions and discoveries	1,405			31,524			2,136
	Purchase of minerals in place	104			128			18
	Production	(1,184	)		(16,443	)		(1,121	)
	Sales of mineral in place	—			(13,331	)		—
	Revision of previous estimates	1,137			(41,471	)		486
	Proved reserves, December 31, 2012	12,984			194,429			12,866
	Extensions and discoveries	2,712			29,137			3,180
	Purchase of minerals in place	—			—			—
	Production	(1,222	)		(12,804	)		(1,156	)
	Revision of previous estimates	(932	)		(33,536	)		(253	)
	Proved reserves, December 31, 2013	13,542			177,226			14,637
	Extensions and discoveries	1,080			22,990			2,224
	Purchase of minerals in place	326			769			170
	Production	(1,313	)		(11,995	)		(1,158	)
	Revision of previous estimates	(2,618	)		(19,897	)		(2,039	)
	Proved reserves, December 31, 2014	11,017			169,093			13,834
	Proved Developed Reserves
	Proved developed reserves, January 1, 2012	10,271			165,269			9,307
	Proved developed reserves, December 31, 2012	10,993			136,545			10,445
	Proved developed reserves, December 31, 2013	10,153			126,950			10,766
	Proved developed reserves, December 31, 2014	9,595			126,783			10,895
	Proved Undeveloped Reserves
	Proved undeveloped reserves, January 1, 2012	1,251			68,753			2,040
	Proved undeveloped reserves, December 31, 2012	1,991			57,884			2,421
	Proved undeveloped reserves, December 31, 2013	3,389			50,276			3,871
	Proved undeveloped reserves, December 31, 2014	1,412			42,310			2,939
	The primary drivers, other than production, behind the changes to our proved reserves for the years ended December 31, 2012, 2013 and 2014 are described in more detail below.
	2012:00:00
	•	Purchase of minerals in place were insignificant in 2012;
	•	extensions and discoveries were primarily related to drilling by us and other operators in the Golden Trend area and the nearby SCOOP Play in Oklahoma;
	•	sales of minerals in place were related to the sale of our Barnett Shale assets in December 2012; and
	•	revisions of previous estimates were primarily the result of lower natural gas prices which reduced the economic life and reserves of many wells.
	2013:00:00
	•	Purchases and sales of minerals in place did not occur in 2013;
	•	extensions and discoveries were primarily related to drilling by us and other operators in the Golden Trend area and the nearby SCOOP Play in Oklahoma; and
	•	revisions of previous estimates were the result of recategorizing a number of undeveloped locations from proved to probable reserves due to poor expected economic performance (a decrease of 27.8 Bcfe), recategorizing other proved undeveloped locations as contingent resources since they were non-commercial at the time (a decrease of 8.1Bcfe), changes in ownership of interests including those that occurred when third party owners elected to not participate in future drilling activities for certain wells (an increase of 1.6 Bcfe) and other factors including changes to costs (an increase of 2.5 Bcfe). All of these revisions were primarily in the Mid-Continent Region.
	2014:00:00
	•	Purchases of minerals in place in 2014 included 3.7 Bcfe of proved developed producing reserves in the Big Escambia Creek field in Alabama, but there were no sales of minerals in place;
	•	extensions and discoveries were primarily related to drilling by us and other operators in the Golden Trend area and the nearby SCOOP Play in Oklahoma and in addition, a number of well locations primarily in the Mid-Continent Region were moved to proved developed non-producing and proved undeveloped as a result of becoming economic at higher gas prices; and
	•	revisions of previous estimates were the result of recategorizing a number of undeveloped locations from proved to probable reserves due to poor expected economic performance (a decrease of 3.0 Bcfe), recategorizing other proved undeveloped locations as contingent resources since they were non-commercial at the time (a decrease of 0.2Bcfe), and other factors including changes to costs, forecast performance expectations and product price differentials (a decrease of 44.6 Bcfe).
Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure [Table Text Block]	The following table illustrates the total amount of capitalized costs relating to oil and natural gas producing activities and the total amount of related accumulated depreciation, depletion and amortization at December 31, 2014, 2013 and 2012:
		As of				As of				As of
		31-Dec-14				31-Dec-13				31-Dec-12
	($ in thousands)
	Proved properties	$	905,622			$	1,156,895			$	1,213,622
	Unproved properties—excluded from depletion	7,512				10,022				31,823
	Gross oil and gas properties	913,134				1,166,917				1,245,445
	Accumulated depreciation, depletion, amortization	(431,555		)		(353,679		)		(269,376		)
	Net oil and gas properties	$	481,579			$	813,238			$	976,069
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure [Table Text Block]	Costs incurred in property acquisition, exploration and development activities were as follows for the years ended December 31, 2014, 2013 and 2012:
		Year Ended December 31,
		2014				2013				2012
	($ in thousands)
	Property acquisition costs, proved	$	10,861			$	—			$	2,582
	Development costs	122,387				124,032				135,692
	Total costs	$	133,248			$	124,032			$	138,274
Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure [Table Text Block]	The Standardized Measure is as follows as of December 31, 2014, 2013 and 2012:
		As of				As of				As of
		31-Dec-14				31-Dec-13				31-Dec-12
	($ in thousands)
	Future cash inflows	$	2,187,346			$	2,423,350			$	2,279,735
	Future production costs	(759,966		)		(737,468		)		(767,004		)
	Future development costs	(240,886		)		(318,778		)		(354,690		)
	Future net cash flows before income taxes	1,186,494				1,367,104				1,158,041
	Future income tax (expense) benefit	(833		)		(1,212		)		(1,086		)
	Future net cash flows before 10% discount	1,185,661				1,365,892				1,156,955
	10% annual discount for estimated timing of cash flows	(591,421		)		(715,386		)		(621,826		)
	Total standardized measure of discounted future net cash flows	$	594,240			$	650,506			$	535,129
Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows [Table Text Block]	Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves
	The following is a summary of the changes in the Standardized Measure of discounted future net cash flows for the Partnership's proved oil and natural gas reserves for the years ended December 31, 2014, 2013 and 2012:
		Year Ended December 31,
		2014				2013				2012
	($ in thousands)
	Beginning of year	$	650,506			$	535,129			$	642,586
	Sale of oil and gas produced, net of production costs	(152,097		)		(150,457		)		(132,451		)
	Net changes in prices and production costs	(63,142		)		2,720				(78,247		)
	Extensions, discoveries and improved recovery, less related costs	74,684				136,464				66,460
	Previously estimated development costs incurred during the period	49,409				21,470				53,111
	Net changes in future development costs	71,800				107,951				36,914
	Revisions of previous quantity estimates	(149,993		)		(103,351		)		(76,434		)
	Purchases of property	11,904				—				2,811
	Sales of property	—				—				(5,063		)
	Accretion of discount	59,818				49,233				60,734
	Net changes in income taxes	169				(36		)		317
	Other	41,182				51,383				(35,609		)
	End of year	$	594,240			$	650,506			$	535,129
Results of Operations for Oil and Gas Producing Activities Disclosure [Table Text Block]	Results of Operations
	The following are the results of operations for the Partnership's oil and natural gas producing activities for the years ended December 31, 2014, 2013 and 2012:
			Year Ended December 31,
			2014				2013				2012
	($ in thousands)
	Revenues:
	Sales to third parties		$	190,057			$	146,210			$	135,842
	Intercompany sales		5,475				47,048				53,343
	Total revenues		195,532				193,258				189,185
	Costs and expenses:
	Production costs		56,595				54,354				56,734
	General and administrative		8,166				11,419				12,162
	Depreciation, depletion, and amortization		81,030				87,456				88,777
	Impairment and other		395,892				214,286				45,289
	Total costs and expenses		541,683				367,515				202,962
	Total result of operations		$	(346,151	)		$	(174,257	)		$	(13,777	)

Organization_and_Description_o1

Organization and Description of Business Narrative (Details) (USD $)	Dec. 31, 2014	Jul. 01, 2014	Dec. 31, 2013
Subordinated Long-term Debt, Noncurrent	$51,120,000	$51,100,000	$51,120,000
Total Midstream Segments [Member]
Disposal Group, Including Discontinued Operation, Consideration, Cash		576,000,000
Disposal Group, Including Discontinued Operations, Consideration, Equity Interests Received, Shares		8,245,859
Disposal Group, Including Discontinued Operation, Consideration, Equity Interests Received		266,000,000
Disposal Group, Including Discontinued Operation, Consideration, Debt Exchanged		$498,900,000

Summary_of_Significant_Account3

Summary of Significant Accounting Policies Allowance for Doubtful Accounts (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Movement in Valuation Allowances and Reserves [Roll Forward]
Valuation Allowances and Reserves, Beginning Balance	$931	$753	$670
Valuation Allowances and Reserves, Charged to Cost and Expense	249	458	175
Valuation Allowances and Reserves, Deductions	-157	-280	-92
Valuation Allowances and Reserves, Ending Balance	$1,023	$931	$753

Summary_of_Significant_Account4

Summary of Significant Accounting Policies Narrative (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Distributionsreceivedfromshortterminvestments	$8,000,000
Inventory, Finished Goods		1,000,000
Unamortized Debt Issuance Expense	5,300,000	6,100,000
Gas Balancing Payable	300,000	300,000
Transportation and exchanges imbalance, receivable		700,000
Transportation and exchange imbalance, payable		1,600,000
Loss on short-term investments	-62,028,000	0	0
Disposal Group, Including Discontinued Operations, Consideration, Equity Interests Received, Shares	6,393,657
Regency units not settled at period end	262,496
Receivable from Sale of Short-term Investments	$6,300,000
NGL Energy Partnership LP [Member]
Entity-wide revenue, major customer, percent	15.00%
Coffeyville [Member]
Entity-wide revenue, major customer, percent	12.00%
Oneok, Inc. [Member]
Entity-wide revenue, major customer, percent	11.00%
Natural Gas Processing Plant [Member]
Property, Plant and Equipment, Useful Life	20 years
Pipelines [Member]
Property, Plant and Equipment, Useful Life	20 years
Gas Gathering and Processing Equipment [Member]
Property, Plant and Equipment, Useful Life	20 years
Furniture and Fixtures [Member]
Property, Plant and Equipment, Useful Life	5 years

Acquisitions_Purchase_Price_Al

Acquisitions Purchase Price Allocation (Details) (BP Texas Panhandle Acquisition [Member], USD $)	Oct. 02, 2012
In Thousands, unless otherwise specified
BP Texas Panhandle Acquisition [Member]
Business Acquisition [Line Items]
Current assets	$779
Property, Plant and Equipment — Net	206,849
Rights-of-way and easements	27,232
Current liabilities	-1,705
Other liabilities	-2,600
Total purchase price	$230,555

Acquisitions_Aggregate_Purchas

Acquisitions Aggregate Purchase Price (Details) (USD $)	3 Months Ended		12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2012
Aspect Acquisition [Member]
Business Acquisition, Equity Interests Issued or Issuable [Line Items]
Total purchase price	$10.40
BP Texas Panhandle Acquisition [Member]
Business Acquisition, Equity Interests Issued or Issuable [Line Items]
Total purchase price		230.6
Transaction fees			$0.10	$0.50

Acquisitions_Pro_Forma_Informa

Acquisitions Pro Forma Information (Details) (USD $)	12 Months Ended			3 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2012
Subsidiary or Equity Method Investee [Line Items]
Revenues	$298,204	$197,372	$231,315
Net Income (Loss) Attributable to Parent	-139,907	-277,979	-150,602
BP Texas Panhandle Acquisition [Member]
Subsidiary or Equity Method Investee [Line Items]
Revenues				81,013
Net Income (Loss) Attributable to Parent				$5,057

Property_Plant_and_Equipment_P1

Property, Plant and Equipment Property, Plant and Equipment (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment — Gross	$930,896	$1,187,504
Accumulated depreciation, depletion and amortization	-442,908	-363,053
Property, Plant and Equipment — Net	487,988	824,451
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	1,391
Computer Equipment [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment — Gross	13,234	12,247
Proved Oil and Gas Properties [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment — Gross	905,622	1,156,895
Unproved Oil and Gas Properties [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment — Gross	7,512	10,022
Construction in Progress [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment — Gross	$1,195	$6,636

Property_Plant_and_Equipment_D

Property, Plant and Equipment Depreciation, Depletion, Amortization and Impairment (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Depreciation	$2,971		$2,018		$1,795
Depletion	80,810		87,230		88,413
Proved Oil and Gas Properties [Member]
Impairment of Long-Lived Assets Held-for-use	395,892	[1]	207,085	[1]	38,943	[1]
Unproved Oil and Gas Property or Major Project [Domain]
Impairment of Long-Lived Assets Held-for-use	$0	[2]	$7,201	[2]	$785	[2]
[1]	During the year ended December 31, 2014, the Partnership incurred impairment charges related to certain proved properties in all of its regions due primarily to lower commodity prices, higher operating costs and lower well performance. During the year ended December 31, 2013, the Partnership incurred impairment charges related primarily to certain proved properties, primarily in the Cana Shale in the Mid-Continent region and the Permian region, due to lower reserve forecasts. During the year ended December 31, 2012, the Partnership incurred impairment charges related to its proved properties in the Barnett Shale, East Texas and Permian regions that experienced reduced cash flows resulting from lower natural gas prices and continuing high operating costs associated with gas compression.
[2]	During the year ended December 31, 2013, the Partnership incurred impairment charges related to certain leaseholds in the Mid-Continent regions that we expected to expire undrilled in 2014. During the year ended December 31, 2012, the Partnership incurred impairment charges related to certain unproved property leaseholds expected to expire undrilled in 2013.

Asset_Retirement_Obligations_S

Asset Retirement Obligations Schedule of Change in Asset Retirement Obligation (Details) (USD $)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligations — Beginning balance	$48,564,000	[1]	$38,991,000		$26,227,000
Additional liabilities	237,000		1,076,000		1,400,000
Liabilities settled	-1,347,000		-2,240,000		-1,664,000
Revision to liabilities	168,000		7,654,000		11,146,000
Accretion expense	3,251,000		3,083,000		1,882,000
Asset retirement obligations — Ending balance	50,873,000	[1]	48,564,000	[1]	38,991,000
Asset Retirement Obligation, Current	$3,000,000		$11,300,000
[1]	(a) As of December 31, 2014 and 2013, $3.0 million and $11.3 million, respectively, were included within accrued liabilities in the audited consolidated balance sheets.

Intangible_Assets_Intangible_A1

Intangible Assets Intangible Assets (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Acquired Finite-Lived Intangible Assets [Line Items]
Intangible Assets — Net	$3,072	$3,268
Use Rights [Member]
Acquired Finite-Lived Intangible Assets [Line Items]
Rights-of-way and easements—at cost	3,920	3,920
Less: accumulated amortization	($848)	($652)

Intangible_Assets_Impaired_Int

Intangible Assets Impaired Intangible Assets (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Amortization of Intangible Assets	$196	$196	$302

Intangible_Assets_Future_Amort

Intangible Assets Future Amortization Expense (Details) (USD $)	Dec. 31, 2014
In Thousands, unless otherwise specified
Finite-Lived Intangible Assets [Line Items]
Future Amortization Expense, Year One	$196
Future Amortization Expense, Year Two	196
Future Amortization Expense, Year Three	196
Future Amortization Expense, Year Four	196
Future Amortization Expense, Year Five	196
Future Amortization Expense, after Year Five	$2,092

Intangible_Assets_Narrative_De

Intangible Assets Narrative (Details) (Use Rights [Member])	12 Months Ended
	Dec. 31, 2014
Use Rights [Member]
Statement [Line Items]
Finite-Lived Intangible Asset, Useful Life	20 years

Long_Term_Debt_LongTerm_Debt_D

Long Term Debt Long-Term Debt (Details) (USD $)	Dec. 31, 2014	Jul. 01, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Debt Instrument [Line Items]
Revolving credit facility:	$212,600		$706,800
8.375% Senior Notes due 2019	51,120	51,100	51,120
Unamortized bond discount	-377		-440
Senior Notes	50,743		50,680
Long-term debt	$263,343		$757,480

Long_Term_Debt_Revolving_Credi

Long Term Debt Revolving Credit Facility Narrative (Details) (USD $)	3 Months Ended	12 Months Ended
	Sep. 30, 2014	Dec. 31, 2014	Dec. 31, 2013
		Rate
Debt Instrument [Line Items]
Repayments of Debt	$570,400,000
Line of Credit Facility, Maximum Borrowing Capacity		1,200,000,000
Debt Issuance Cost		1,600,000
Write-off of debt issuance costs		600,000
Unamortized Debt Issuance Expense		5,300,000	6,100,000
Line of Credit Facility, Current Borrowing Capacity		320,000,000
Line of Credit Facility, Remaining Borrowing Capacity		107,400,000
Line of Credit Facility, Commitment Fee Percentage		0.50%
Letters of Credit Sub-limit		50,000,000
Letters of Credit Outstanding, Amount		0
Debt, Weighted Average Interest Rate		2.17%
Debt Instrument, Covenant Compliance		As of December 31, 2013, the Partnership was in compliance with the financial covenants under the Credit Agreement.
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Unamortized Debt Issuance Expense		$4,554,000
Total Leverage Ratio [Member]
Debt Instrument [Line Items]
Debt Instrument, Covenant Description		As of any fiscal quarter-end, the ratio of Total Funded Indebtedness (as defined in the Credit Agreement) to Consolidated EBITDA for the four fiscal quarter period ending with such fiscal quarter (the “Total Leverage Ratio”).
Current Ratio [Member]
Debt Instrument [Line Items]
Debt Instrument, Covenant Description		As of any fiscal quarter-end the ratio of the Partnership’s consolidated current assets (including availability under the Credit Agreement up to the Loan Limit (as defined within the Credit Agreement), but excluding non-cash assets under the accounting guidance for derivatives) to consolidated current liabilities (excluding non-cash obligations under the accounting guidance for derivatives and current maturities under the Credit Agreement) (the “Current Ratio”).
London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate		2.00%
Debt Instrument, Basis Spread on Base Rate		1.00%
Base Rate [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate		1.00%
Federal Funds Purchased [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Base Rate		0.50%
Minimum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate		1.50%
Minimum [Member] | Base Rate [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate		0.50%
Maximum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate		2.50%
Maximum [Member] | Base Rate [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate		1.50%

Long_Term_Debt_Debt_Covenants_

Long Term Debt Debt Covenants (Details)	Dec. 31, 2014
Total Leverage Ratio [Member]
Schedule of Debt Covenants [Line Items]
Line of Credit Facility, Covenant Ratio	2.2
Current Ratio [Member]
Schedule of Debt Covenants [Line Items]
Line of Credit Facility, Covenant Ratio	5.2
Minimum [Member] | Current Ratio [Member]
Schedule of Debt Covenants [Line Items]
Line of Credit Facility, Covenant Ratio	1	[1]
Maximum [Member] | Total Leverage Ratio [Member]
Schedule of Debt Covenants [Line Items]
Line of Credit Facility, Covenant Ratio	4	[2]
[1]	(b)Amount represents the minimum ratio for the period presented.
[2]	(a)Amount represents the maximum ratio for the period presented.

Long_Term_Debt_Scheduled_Matur

Long Term Debt Scheduled Maturities of Debt (Details) (USD $)	Dec. 31, 2014
In Thousands, unless otherwise specified
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months	$0
Long-term Debt, Maturities, Repayments of Principal in Year Two	0
Long-term Debt, Maturities, Repayments of Principal in Year Three	0
Long-term Debt, Maturities, Repayments of Principal in Year Four	0
Long-term Debt, Maturities, Repayments of Principal in Year Five	263,720
Long-term Debt, Maturities, Repayments of Principal after Year Five	0
Total Repayments of Long-Term Debt	$263,720

Long_Term_Debt_Senior_Notes_Na

Long Term Debt Senior Notes Narrative (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Jul. 01, 2014
Debt Instrument [Line Items]
Proceeds from Issuance of Subordinated Long-term Debt	$0	$0	$22,889,000
Unamortized Debt Issuance Expense	5,300,000	6,100,000
Debt Instrument, Unamortized Discount (Premium), Net	377,000	440,000
Subordinated Long-term Debt, Noncurrent	51,120,000	51,120,000		51,100,000
Debt Instrument, Call Feature	The Partnership has the option to redeem all or a portion of the Senior Notes at any time on or after June 1, 2015 at the redemption prices specified in the indenture plus accrued and unpaid interest. The Partnership may also redeem the Senior Notes, in whole or in part, at a "make-whole" redemption price specified in the indenture, plus accrued and unpaid interest, at any time prior to June 1, 2015.
Senior Notes [Member]
Debt Instrument [Line Items]
Unamortized Debt Issuance Expense	800,000
2011 Debt Issuance [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	300,000,000
Debt Instrument, Interest Rate, Stated Percentage	8.38%
Debt Instrument, Unamortized Discount	2,200,000
Proceeds from Issuance of Subordinated Long-term Debt	297,800,000
2012 Debt Issuance [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	250,000,000
Debt Instrument, Unamortized Discount	3,700,000
Proceeds from Issuance of Subordinated Long-term Debt	246,300,000
Total Midstream Segments [Member]
Debt Instrument [Line Items]
Disposal Group, Including Discontinued Operation, Consideration, Debt Exchanged				$498,900,000

Members_Equity_Narrative_Detai

Members' Equity Narrative (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Capital Unit [Line Items]
Stock Repurchase Program, Authorized Amount	$100,000,000
Stock Repurchased and Retired During Period, Shares	7,455,887
Warrant Exercise Price	6
Stockholders' Equity, Other Shares		5,300,588	14,957,540
Equity Issuance, Market Value	100,000,000
Equity Units, Issued	686,759
Equity Proceeds, Net of Offering Costs	5,600,000
Stock Issued During Period, Shares, New Issues	10,350,000	10,120,000
Partners' Capital Account, Public Sale of Units Net of Offering Costs	92,300,000	84,300,000
Payments for Repurchase of Equity	19,151,000
Repurchases unsettled at period end	641,400
Payable from repurchase of units unsettled at period end	$1,300,000
Common Class A [Member]
Capital Unit [Line Items]
Limited Partners' Capital Account, Units Outstanding	150,154,909	156,644,153	144,675,751	127,606,229
Stock Issued During Period, Shares, New Issues		11,036,759	10,954,327

Members_Equity_Distributions_D

Members' Equity Distributions (Details) (USD $)

3 Months Ended

Dec. 31, 2014

Sep. 30, 2014

Jun. 30, 2014

Mar. 31, 2014

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dividends Payable [Line Items]

Common Stock, Dividends, Per Share, Cash Paid

$0.07

[1],[2]

$0.07

[1],[2]

$0

[3]

$0

[3]

$0.15

[1],[2]

$0.15

[1],[2]

$0.22

[1],[2]

$0.22

[1],[2]

$0.22

[1]

$0.22

[1]

$0.22

[1]

$0.22

[1]

Distribution Made to Limited Partner, Date of Record

6-Feb-15

[1],[2],[4]

7-Nov-14

[1],[2],[4]

7-Feb-14

[1],[2]

7-Nov-13

[1],[2]

7-Aug-13

[1],[2]

7-May-13

[1],[2]

7-Feb-13

[1]

7-Nov-12

[1]

7-Aug-12

[1]

8-May-12

[1]

Distribution Made to Limited Partner, Distribution Date

13-Feb-15

[1],[2]

14-Nov-14

[1],[2]

14-Feb-14

[1],[2]

14-Nov-13

[1],[2]

14-Aug-13

[1],[2]

15-May-13

[1],[2]

14-Feb-13

[1]

14-Nov-12

[1]

14-Aug-12

[1]

15-May-12

[1]

[1]

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

[2]

The distribution excludes certain restricted units under the LTIP.

[3]

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

[4]

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

Related_Party_Transactions_Sch

Related Party Transactions Schedule of Related Party Transactions (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Related Party Transaction [Line Items]
Natural gas purchases from affiliates	$2,091	$2,938	$2,713
Due to Related Parties, Current	$0	$18	$428

Risk_Management_Activities_Int

Risk Management Activities Interest Rate Derivatives (Details) (Interest Rate Swap [Member], Interest Rate Swap [Member], USD $)	60 Months Ended
	Dec. 31, 2019	Dec. 31, 2014
		Rate
Effective Date, 6/22/2011 [Member]
Derivative [Line Items]
Derivative, Notional Amount		$250,000,000
Derivative, Average Fixed Interest Rate		2.95%
Effective Date, 12/31/2014 [Member]
Derivative [Line Items]
Derivative, Notional Amount		$175,000,000
Derivative, Average Fixed Interest Rate		2.32%
Scenario, Forecast [Member] | Effective Date, 12/31/2014 [Member]
Derivative [Line Items]
Derivative, Maturity Date	31-Dec-19

Risk_Management_Activities_Com

Risk Management Activities Commodity Derivatives (Details)	Dec. 31, 2014
	MMbtu
Natural Gas Contract [Member] | Swap [Member] | Portion of contracts settling in 2015 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	10,800,000	[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	480,000	[1]
Derivative, Average Floor Price	90	[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	630,000	[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]
[1]	Volumes of natural gas are measured in MMbtu, volumes of crude oil are measured in barrels, and volumes of natural gas liquids are measured in gallons
[2]	Amounts represent the weighted average price. The weighted average prices are in $/MMbtu for natural gas, $/barrel for crude oil and $/gallon for natural gas liquids

Risk_Management_Activities_Sch

Risk Management Activities Schedule of Derivative Instruments in the Statement of Financial Position (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Derivatives, Fair Value [Line Items]
Derivative Liabilities, Current	$0	($8,360)
Derivative Liabilities, noncurrent	0	-2,826
Derivative assets, current	44,805	5,559
Derivative assets, noncurrent	46,490	3,871
Derivative Financial Instruments, Assets, Fair Value Disclosure	91,295	14,623
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0	-14,871
Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member] | Current Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Liabilities, Current	-3,165	0
Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member] | Long-term Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Liabilities, noncurrent	-2,641	0
Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member] | Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liabilities, Current	0	-6,210
Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member] | Long-term Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liabilities, noncurrent	0	-2,885
Commodity Contract [Member] | Not Designated as Hedging Instrument [Member] | Current Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Liabilities, Current	0	-1,282
Derivative assets, current	47,971	6,841
Commodity Contract [Member] | Not Designated as Hedging Instrument [Member] | Long-term Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Liabilities, noncurrent	0	-798
Derivative assets, noncurrent	49,130	4,669
Commodity Contract [Member] | Not Designated as Hedging Instrument [Member] | Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liabilities, Current	0	-3,193
Derivative assets, current	0	1,043
Commodity Contract [Member] | Not Designated as Hedging Instrument [Member] | Long-term Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liabilities, noncurrent	0	-143
Derivative assets, noncurrent	0	202
Commodity Contract [Member] | Not Designated as Hedging Instrument [Member] | Assets Held-for-sale [Member]
Derivatives, Fair Value [Line Items]
Derivative Liabilities, Current	0	-824
Derivative assets, current	0	6,017
Commodity Contract [Member] | Not Designated as Hedging Instrument [Member] | Liabilities held for sale [Member]
Derivatives, Fair Value [Line Items]
Derivative Liabilities, Current	0	-5,658
Derivative assets, current	$0	$1,973

Risk_Management_Activities_Sch1

Risk Management Activities Schedule of Derivative Instruments, Gain (Loss) in Statement of Financial Performance (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Derivative Instruments, Gain (Loss) [Line Items]
Interest rate risk management gains (losses), net	($1,734)	($1,104)	($4,727)
Commodity risk management gains (losses), net	94,431	-3,937	28,110
Derivative Instruments, Gain (Loss) Recognized in Income, Net	74,816	-19,322	52,975
Interest Rate Contract [Member] | Other Expense [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Interest rate risk management gains (losses), net	-1,734	-1,104	-4,727
Commodity Contract [Member] | Commodity Risk Management Gains (Losses) [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Commodity risk management gains (losses), net	94,431	-3,937	28,110
Commodity Contract [Member] | Discontinued Operations [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Commodity risk management gains (losses), net	-15,477	-14,596	29,784
Commodity Contract [Member] | Sales [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Commodity risk management gains (losses), net	($2,404)	$315	($192)

Fair_Value_of_Financial_Instru2

Fair Value of Financial Instruments Fair Value, Assets and Liabilities Measured on a Recuring Basis (Details) (USD $)	Dec. 31, 2014		Dec. 31, 2013
In Thousands, unless otherwise specified
Assets:
Derivative Financial Instruments, Assets, Fair Value Disclosure	$91,295		$14,623
Short-term Investments	153,448		0
Liabilities:
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0		-14,871
Fair Value, Measurements, Recurring [Member]
Assets:
Derivative Financial Instruments, Assets, Fair Value Disclosure	244,743		9,430
Liabilities:
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0		-11,186
Fair Value, Measurements, Recurring [Member] | Crude Oil Contract [Member]
Assets:
Derivative Financial Instruments, Assets, Fair Value Disclosure	78,516		4,435
Liabilities:
Derivative Financial Instruments, Liabilities, Fair Value Disclosure			-76
Fair Value, Measurements, Recurring [Member] | Natural Gas Contract [Member]
Assets:
Derivative Financial Instruments, Assets, Fair Value Disclosure	18,585		4,995
Liabilities:
Derivative Financial Instruments, Liabilities, Fair Value Disclosure			-936
Fair Value, Measurements, Recurring [Member] | Natural Gas Liquids Contract [Member]
Assets:
Derivative Financial Instruments, Assets, Fair Value Disclosure			0
Liabilities:
Derivative Financial Instruments, Liabilities, Fair Value Disclosure			-1,079
Fair Value, Measurements, Recurring [Member] | Interest Rate Contract [Member]
Assets:
Derivative Financial Instruments, Assets, Fair Value Disclosure	-5,806
Liabilities:
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0		-9,095
Fair Value, Measurements, Recurring [Member] | Short-term Investments [Member]
Assets:
Derivative Financial Instruments, Assets, Fair Value Disclosure	153,448
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
Assets:
Derivative Financial Instruments, Assets, Fair Value Disclosure	153,448		0
Liabilities:
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0		0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Crude Oil Contract [Member]
Assets:
Derivative Financial Instruments, Assets, Fair Value Disclosure	0		0
Liabilities:
Derivative Financial Instruments, Liabilities, Fair Value Disclosure			0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Natural Gas Contract [Member]
Assets:
Derivative Financial Instruments, Assets, Fair Value Disclosure	0		0
Liabilities:
Derivative Financial Instruments, Liabilities, Fair Value Disclosure			0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Natural Gas Liquids Contract [Member]
Assets:
Derivative Financial Instruments, Assets, Fair Value Disclosure			0
Liabilities:
Derivative Financial Instruments, Liabilities, Fair Value Disclosure			0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Interest Rate Contract [Member]
Assets:
Derivative Financial Instruments, Assets, Fair Value Disclosure	0
Liabilities:
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0		0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Assets:
Derivative Financial Instruments, Assets, Fair Value Disclosure	97,101		12,755
Liabilities:
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	-5,806		-14,511
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Crude Oil Contract [Member]
Assets:
Derivative Financial Instruments, Assets, Fair Value Disclosure	78,516		6,151
Liabilities:
Derivative Financial Instruments, Liabilities, Fair Value Disclosure			-1,792
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Natural Gas Contract [Member]
Assets:
Derivative Financial Instruments, Assets, Fair Value Disclosure	18,585		6,562
Liabilities:
Derivative Financial Instruments, Liabilities, Fair Value Disclosure			-2,503
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Natural Gas Liquids Contract [Member]
Assets:
Derivative Financial Instruments, Assets, Fair Value Disclosure			42
Liabilities:
Derivative Financial Instruments, Liabilities, Fair Value Disclosure			-1,121
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Interest Rate Contract [Member]
Assets:
Derivative Financial Instruments, Assets, Fair Value Disclosure	0
Liabilities:
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	-5,806		-9,095
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Short-term Investments [Member]
Assets:
Derivative Financial Instruments, Assets, Fair Value Disclosure	0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]
Assets:
Derivative Financial Instruments, Assets, Fair Value Disclosure	0		0
Liabilities:
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0		0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Crude Oil Contract [Member]
Assets:
Derivative Financial Instruments, Assets, Fair Value Disclosure	0		0
Liabilities:
Derivative Financial Instruments, Liabilities, Fair Value Disclosure			0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Natural Gas Contract [Member]
Assets:
Derivative Financial Instruments, Assets, Fair Value Disclosure	0		0
Liabilities:
Derivative Financial Instruments, Liabilities, Fair Value Disclosure			0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Natural Gas Liquids Contract [Member]
Assets:
Derivative Financial Instruments, Assets, Fair Value Disclosure			0
Liabilities:
Derivative Financial Instruments, Liabilities, Fair Value Disclosure			0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Interest Rate Contract [Member]
Assets:
Derivative Financial Instruments, Assets, Fair Value Disclosure	0
Liabilities:
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0		0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Short-term Investments [Member]
Assets:
Derivative Financial Instruments, Assets, Fair Value Disclosure	0
Fair Value, Measurements, Recurring [Member] | Netting [Member]
Assets:
Derivative Financial Instruments, Assets, Fair Value Disclosure	-5,806	[1]	-3,325	[1]
Liabilities:
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	-5,806	[1]	3,325	[1]
Fair Value, Measurements, Recurring [Member] | Netting [Member] | Crude Oil Contract [Member]
Assets:
Derivative Financial Instruments, Assets, Fair Value Disclosure	0	[1]	-1,716	[1]
Liabilities:
Derivative Financial Instruments, Liabilities, Fair Value Disclosure			1,716	[1]
Fair Value, Measurements, Recurring [Member] | Netting [Member] | Natural Gas Contract [Member]
Assets:
Derivative Financial Instruments, Assets, Fair Value Disclosure	0	[1]	-1,567	[1]
Liabilities:
Derivative Financial Instruments, Liabilities, Fair Value Disclosure			1,567	[1]
Fair Value, Measurements, Recurring [Member] | Netting [Member] | Natural Gas Liquids Contract [Member]
Assets:
Derivative Financial Instruments, Assets, Fair Value Disclosure			-42	[1]
Liabilities:
Derivative Financial Instruments, Liabilities, Fair Value Disclosure			42	[1]
Fair Value, Measurements, Recurring [Member] | Netting [Member] | Interest Rate Contract [Member]
Assets:
Derivative Financial Instruments, Assets, Fair Value Disclosure	-5,806	[1]
Liabilities:
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	-5,806	[1]	0	[1]
Fair Value, Measurements, Recurring [Member] | Netting [Member] | Short-term Investments [Member]
Assets:
Derivative Financial Instruments, Assets, Fair Value Disclosure	$0	[1]
[1]	Represents counterparty netting under agreement governing such derivative contracts.

Fair_Value_of_Financial_Instru3

Fair Value of Financial Instruments Fair Value, Assets and Liabilitites, Measured on a Non-recurring Basis (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Proved Oil and Gas Properties [Member]
Assets [Abstract]
Property, Plant, and Equipment, Fair Value Disclosure	$305,006
Impairment of Long-Lived Assets Held-for-use	395,892	[1]	207,085	[1]	38,943	[1]
Proved Oil and Gas Properties [Member] | Fair Value, Measurements, Nonrecurring [Member]
Assets [Abstract]
Impairment of Long-Lived Assets Held-for-use	395,892
Proved Oil and Gas Properties [Member] | Fair Value, Measurements, Nonrecurring [Member] | Fair Value, Inputs, Level 1 [Member]
Assets [Abstract]
Property, Plant, and Equipment, Fair Value Disclosure	0
Proved Oil and Gas Properties [Member] | Fair Value, Measurements, Nonrecurring [Member] | Fair Value, Inputs, Level 2 [Member]
Assets [Abstract]
Property, Plant, and Equipment, Fair Value Disclosure	0
Proved Oil and Gas Properties [Member] | Fair Value, Measurements, Nonrecurring [Member] | Fair Value, Inputs, Level 3 [Member]
Assets [Abstract]
Property, Plant, and Equipment, Fair Value Disclosure	305,006
Natural Gas Processing Plant [Member]
Assets [Abstract]
Property, Plant, and Equipment, Fair Value Disclosure	52
Natural Gas Processing Plant [Member] | Fair Value, Measurements, Nonrecurring [Member]
Assets [Abstract]
Impairment of Long-Lived Assets Held-for-use	132
Natural Gas Processing Plant [Member] | Fair Value, Measurements, Nonrecurring [Member] | Fair Value, Inputs, Level 1 [Member]
Assets [Abstract]
Property, Plant, and Equipment, Fair Value Disclosure	0
Natural Gas Processing Plant [Member] | Fair Value, Measurements, Nonrecurring [Member] | Fair Value, Inputs, Level 2 [Member]
Assets [Abstract]
Property, Plant, and Equipment, Fair Value Disclosure	0
Natural Gas Processing Plant [Member] | Fair Value, Measurements, Nonrecurring [Member] | Fair Value, Inputs, Level 3 [Member]
Assets [Abstract]
Property, Plant, and Equipment, Fair Value Disclosure	52
Pipelines [Member]
Assets [Abstract]
Property, Plant, and Equipment, Fair Value Disclosure	746
Pipelines [Member] | Fair Value, Measurements, Nonrecurring [Member]
Assets [Abstract]
Impairment of Long-Lived Assets Held-for-use	1,904
Pipelines [Member] | Fair Value, Measurements, Nonrecurring [Member] | Fair Value, Inputs, Level 1 [Member]
Assets [Abstract]
Property, Plant, and Equipment, Fair Value Disclosure	0
Pipelines [Member] | Fair Value, Measurements, Nonrecurring [Member] | Fair Value, Inputs, Level 2 [Member]
Assets [Abstract]
Property, Plant, and Equipment, Fair Value Disclosure	0
Pipelines [Member] | Fair Value, Measurements, Nonrecurring [Member] | Fair Value, Inputs, Level 3 [Member]
Assets [Abstract]
Property, Plant, and Equipment, Fair Value Disclosure	746
Use Rights [Member]
Assets [Abstract]
Finite-lived Intangible Assets, Fair Value Disclosure	24
Use Rights [Member] | Fair Value, Measurements, Nonrecurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment of Intangible Assets, Finite-lived	61
Use Rights [Member] | Fair Value, Measurements, Nonrecurring [Member] | Fair Value, Inputs, Level 1 [Member]
Assets [Abstract]
Finite-lived Intangible Assets, Fair Value Disclosure	0
Use Rights [Member] | Fair Value, Measurements, Nonrecurring [Member] | Fair Value, Inputs, Level 2 [Member]
Assets [Abstract]
Finite-lived Intangible Assets, Fair Value Disclosure	0
Use Rights [Member] | Fair Value, Measurements, Nonrecurring [Member] | Fair Value, Inputs, Level 3 [Member]
Assets [Abstract]
Finite-lived Intangible Assets, Fair Value Disclosure	$24
[1]	During the year ended December 31, 2014, the Partnership incurred impairment charges related to certain proved properties in all of its regions due primarily to lower commodity prices, higher operating costs and lower well performance. During the year ended December 31, 2013, the Partnership incurred impairment charges related primarily to certain proved properties, primarily in the Cana Shale in the Mid-Continent region and the Permian region, due to lower reserve forecasts. During the year ended December 31, 2012, the Partnership incurred impairment charges related to its proved properties in the Barnett Shale, East Texas and Permian regions that experienced reduced cash flows resulting from lower natural gas prices and continuing high operating costs associated with gas compression.

Fair_Value_of_Financial_Instru4

Fair Value of Financial Instruments Narrative (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Fair Value Disclosures [Abstract]
Notes Payable, Fair Value Disclosure	$47	$599.50

Commitments_and_Contingencies_1

Commitments and Contingencies Loss Contingencies (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Loss Contingencies [Line Items]
Accrual for Environmental Loss Contingencies	$2.80	$2.50

Commitments_and_Contingencies_2

Commitments and Contingencies Operating Leases (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Operating leases [Line Items]
Operating Leases, Rent Expense	$2,587	$2,424	$3,754
Operating Leases, Future Minimum Payments Due	5,853
Operating Leases, Future Minimum Payments, Due in Two Years	3,899
Operating Leases, Future Minimum Payments, Due in Three Years	2,799
Operating Leases, Future Minimum Payments, Due in Four Years	438
Operating Leases, Future Minimum Payments, Due in Five Years	$0

Employee_Benefit_Plan_Narrativ

Employee Benefit Plan Narrative (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Defined Benefit Plan Disclosure [Line Items]
Percentage of Performance Units Earned	0.00%
Description of Defined Contribution Pension and Other Postretirement Plans	For the three years ended December 31, 2014, the plan provided for a dollar for dollar matching contribution by the Partnership of up to 4% of an employee's contribution and 50% of additional contributions up to an additional 2%. Additionally, the Partnership may, at its sole discretion and election, contribute up to 6% of a participating employee's base salary annually, subject to vesting requirements.
Defined Contribution Plan, Cost Recognized	$1.10	$1.20	$0.80
Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Percentage of Performance Units Earned	70.00%

Income_Taxes_Schedule_of_Compo

Income Taxes Schedule of Components of Income Tax Expense (Benefit) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Current:
Federal	($475)	($105)	$621
State	8	0	18
Total current provision	-467	-105	639
Deferred:
Federal	-2,593	-3,837	-2,776
State	-2,343	-1,653	1,044
Total deferred	-4,936	-5,490	-1,732
Income Tax Expense (Benefit)	($5,403)	($5,595)	($1,093)

Income_Taxes_Schedule_of_Effec

Income Taxes Schedule of Effective Income Tax Rate Reconciliation (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income (Loss) from Continuing Operations before Income Taxes, Domestic	($357,770)	($233,766)	($33,239)
State Income Tax current and deferred	-2,335	-1,653	1,062
Federal income taxes computed by applying the federal statutory rate to NBI of corporate entities	-2,680	-4,160	-2,155
Tax attributes used	-388	218	0
Income Tax Expense (Benefit)	($5,403)	($5,595)	($1,093)
Effective Income Tax Rate, Continuing Operations	1.50%	2.40%	3.30%

Income_Taxes_Schedule_of_Defer

Income Taxes Schedule of Deferred Tax Assets and Liabilities (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Deferred Tax Assets:
Statutory depletion carryover	$1,842	$1,438
Deferred Tax Assets, Property, Plant and Equipment	473	0
Total Deferred Tax Assets	2,315	1,438
Deferred Tax Liabilities:
Unrealized hedging transactions	-424	0
Deferred Tax Liabilities, Property, Plant and Equipment	0	-2,011
Book/tax differences from partnership investment	-29,897	-32,086
Total Deferred Tax Liabilities	-30,321	-34,097
Total Net Deferred Tax Liabilities	-28,006	-32,659
Deferred Tax Assets (Liabilities), Net [Abstract]
Current potion of total net deferred tax liabilities	0	0
Long-term portion of total net deferred tax liabilities	($28,006)	($32,659)

Income_Taxes_Unrecognized_Tax_

Income Taxes Unrecognized Tax Benefits (Liabilities) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized Tax Benefits, Beginning Balance				($735)
Unrecognized Tax Benefits, Ending Balance	-365	-649	-830	-735
Current Period Tax Position [Member]
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Increases Resulting from Current Period Tax Positions	0	-128	-53
Income Tax Penalties and Interest Expense	0	39	42
Lapse of Applicable Statute of Limitations [Member]
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Income Tax Penalties and Interest Expense	58	81	0
Unrecognized Tax Benefits, Reduction Resulting from Lapse of Applicable Statute of Limitations	$226	$267	$0

Equity_Based_Compensation_Shar

Equity Based Compensation Share-based Compensation Rollforward (Details) (USD $)	9 Months Ended	12 Months Ended
	Sep. 30, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
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	0	0
Grants in Period		715,263
Forfeited in Period		-67,475
Unvested Restricted Units Outstanding, Ending Balance		647,788
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Intrinsic Value [Roll Forward]
Weighted Average Grant Date Fair Value, Beginning	$0	$0
Grants in Period, Weighted Average Grant Date Fair Value	$3.63
Forfeitures in Period, Weighted Average Grant Price	$3.59
Weighted Average Grant Date Fair Value, Ending	$3.63
Restricted Common Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Outstanding [Roll Forward]
Unvested Restricted Units Outstanding, Beginning Balance	2,743,807	2,743,807
Grants in Period		1,903,333
Vesting of restricted units - Units		-1,305,433
Forfeited in Period		-921,957
Unvested Restricted Units Outstanding, Ending Balance		2,419,750	2,743,807
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Intrinsic Value [Roll Forward]
Weighted Average Grant Date Fair Value, Beginning	$9.37	$9.37
Grants in Period, Weighted Average Grant Date Fair Value		$4.44	$9.16	$9.50
Vested in Period, Weighted Average Grant Date Fair Value		$9.60
Forfeitures in Period, Weighted Average Grant Price		$8.12
Weighted Average Grant Date Fair Value, Ending		$6.06	$9.37

Equity_Based_Compensation_Narr

Equity Based Compensation Narrative (Details) (USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
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	6,475,632
Equity-based compensation	$8,198	$10,392	$7,719
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	12,181
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition	2 years 0 months 1 day
Shares cancelled during period, value	1,354
Repurchase of common units		-1,858	-2,501
Percentage of Performance Units Earned	0.00%
Common Class A [Member]
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Shares cancelled during period	338,790
Repurchase of common units - Units	-7,794,677	-272,179	-286,716
Repurchase of common units	($20,505)
Performance Shares [Member]
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Grants in Period	715,263
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%

Earnings_Per_Unit_Schedule_of_

Earnings Per Unit Schedule of Weighted Average Number of Units(Details)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Weighted average common units outstanding - basic	156,700	153,562	135,609
Weighted Average common units outstanding - diluted	156,700	153,562	135,609

Earnings_Per_Unit_Calculation_

Earnings Per Unit Calculation of basic and diluted earnings per unit (Details) (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Income (Loss) from Continuing Operations Attributable to Parent	($352,367)	($228,171)	($32,146)
Distributions	21,763	117,294	124,235
Assumed income (loss) from continuing operations after distribution to be allocated	-374,130	-345,465	-156,381
Discontinued operations, net of tax	212,460	-49,808	-118,456
Net income (loss)	-139,907	-277,979	-150,602
Net Income (loss) from continuing operations per common unit - basic	($2.25)	($1.50)	($0.26)
Discontinued operations per common unit - basic	$1.36	($0.32)	($0.87)
Net income (loss) per common unit - basic	($0.89)	($1.82)	($1.13)
Net Income (loss) from continuing operations per common units - diluted	($2.25)	($1.50)	($0.26)
Discontinued operations per common unit - diluted	$1.36	($0.32)	($0.87)
Net Income (Loss), Per Outstanding Limited Partnership Unit, Diluted	$0.89	$1.82	$1.13
Common Stock [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Income (Loss) from Continuing Operations Attributable to Parent	-352,666	-230,114	-34,877
Distributions	21,464	115,351	121,504
Assumed income (loss) from continuing operations after distribution to be allocated	-374,130	-345,465	-156,381
Discontinued operations, net of tax	212,460	-49,808	-118,456
Net income (loss)	-140,206	-279,922	-153,333
Net Income (loss) from continuing operations per common unit - basic	($2.25)	($1.50)	($0.26)
Discontinued operations per common unit - basic	$1	($0.32)	($0.87)
Net income (loss) per common unit - basic	($0.89)	($1.82)	($1.13)
Net Income (loss) from continuing operations per common units - diluted	($2.25)	($1.50)	($0.26)
Discontinued operations per common unit - diluted	$1.36	($0.32)	($0.87)
Net Income (Loss), Per Outstanding Limited Partnership Unit, Diluted	$0.89	$1.82	$1.13
Restricted Common Units [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Income (Loss) from Continuing Operations Attributable to Parent	299	1,943	2,731
Distributions	299	1,943	2,731
Assumed income (loss) from continuing operations after distribution to be allocated	0	0	0
Discontinued operations, net of tax	0	0	0
Net income (loss)	$299	$1,943	$2,731

Divestiture_Related_Activities3

Divestiture Related Activities Schedule of Disposal Groups, Including Discontinued Operations, Income Statement, Balance Sheet and Additional Disclosures(Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Assets held-for-sale
Accounts Receivable	$0	$128,713
Property, plant and equipment	0	1,004,317
Intangible assets	0	102,352
Other current assets	0	5,663
Other long-term assets	0	18,337
Total assets held-for-sale	0	1,259,382
Liabilities held-for-sale
Long-term debt	0	494,582
Accounts payable and accrued liabilities	0	119,966
Other current liabilities	0	9,471
Other long-term liabilities	0	13,719
Total liabilities held-for-sale	0	637,738
Gain (loss) from disposal	243,637	0
Proceeds from sale of asset	0	76	15,398
Discontinued operations, net of tax	212,460	-49,808	-118,456
Barnett Shale [Member]
Liabilities held-for-sale
Gain (loss) from disposal			-4,500
Proceeds from sale of asset			14,800
Total Midstream Segments [Member]
Liabilities held-for-sale
Revenue attributable to disposal group	552,574	997,907	752,644
Cost of natural gas, natural gas liquids, condensate and helium	447,519	790,618	532,719
Operations, maintenance and taxes other than income	50,154	101,121	82,526
General and administrative	18,392	28,083	19,004
Depreciation, amortization and impairment	41,936	77,726	202,249
Interest expense	27,350	49,973	35,202
Disposal Group, Including Discontinued Operation, Other Income		-287
Operating income (loss) attibutable to disposal group	-32,845	-49,327	-119,066
Gain (loss) from disposal			0
Income tax expense	-1,668	481	-610
Discontinued operations, net of tax	$212,460	($49,808)	($118,456)

Subsidiary_Guarantors_Subsidia1

Subsidiary Guarantors Subsidiary Guarantors Condensed Consolidating Balance Sheets (Details) (USD $)	Dec. 31, 2014		Dec. 31, 2013
In Thousands, unless otherwise specified
Subsidiary Guarantors [Line Items]
Accounts receivable – related parties	$0		$0
Assets of Disposal Group, Including Discontinued Operation	0		1,259,382
Other current assets	249,103		29,008
Property, Plant and Equipment — Net	487,988		824,451
Investment in subsidiaries	0		0
Total other long-term assets	57,184		14,709
Total assets	794,275		2,127,550
Accounts payable – related parties	0		0
Liabilities held for sale	0		637,738
Other current liabilities	59,525		81,829
Other long-term liabilities	82,937		76,624
Long-term debt	263,343		757,480
Members' Equity	388,470	[1]	573,879	[1]
Total liabilities and equity	794,275		2,127,550
Parent Company [Member]
Subsidiary Guarantors [Line Items]
Accounts receivable – related parties	838,656		691,588
Assets of Disposal Group, Including Discontinued Operation			8,762
Other current assets	211,213		6,927
Property, Plant and Equipment — Net	1,334		2,318
Investment in subsidiaries	-413,023		1,133,217
Total other long-term assets	52,272		10,012
Total assets	690,452		1,852,824
Accounts payable – related parties	0		0
Liabilities held for sale			500,291
Other current liabilities	37,850		15,688
Other long-term liabilities	789		5,486
Long-term debt	263,343		757,480
Members' Equity	388,470		573,879
Total liabilities and equity	690,452		1,852,824
Co-issuer [Member]
Subsidiary Guarantors [Line Items]
Accounts receivable – related parties	0		0
Assets of Disposal Group, Including Discontinued Operation			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 assets	1		1
Accounts payable – related parties	0		0
Liabilities held for sale			0
Other current liabilities	0		0
Other long-term liabilities	0		0
Long-term debt	0		0
Members' Equity	1		1
Total liabilities and equity	1		1
Guarantor Subsidiaries [Member]
Subsidiary Guarantors [Line Items]
Accounts receivable – related parties	0		0
Assets of Disposal Group, Including Discontinued Operation			1,250,620
Other current assets	37,889		22,080
Property, Plant and Equipment — Net	486,654		822,133
Investment in subsidiaries	0		0
Total other long-term assets	4,912		4,697
Total assets	529,455		2,099,530
Accounts payable – related parties	838,656		691,588
Liabilities held for sale			137,447
Other current liabilities	21,675		66,141
Other long-term liabilities	82,148		71,138
Long-term debt	0		0
Members' Equity	-413,024		1,133,216
Total liabilities and equity	529,455		2,099,530
Non-Guarantor Subsidiaries [Member]
Subsidiary Guarantors [Line Items]
Accounts receivable – related parties	0		0
Assets of Disposal Group, Including Discontinued Operation			0
Other current assets	0		0
Property, Plant and Equipment — Net	0		0
Investment in subsidiaries	0		908
Total other long-term assets	0		0
Total assets	0		908
Accounts payable – related parties	0		0
Liabilities held for sale			0
Other current liabilities	0		0
Other long-term liabilities	0		0
Long-term debt	0		0
Members' Equity	0		908
Total liabilities and equity	0		908
Consolidation, Eliminations [Member]
Subsidiary Guarantors [Line Items]
Accounts receivable – related parties	-838,656		-691,588
Assets of Disposal Group, Including Discontinued Operation			0
Other current assets	0		0
Property, Plant and Equipment — Net	0		0
Investment in subsidiaries	413,023		-1,134,125
Total other long-term assets	0		0
Total assets	-425,633		-1,825,713
Accounts payable – related parties	-838,656		-691,588
Liabilities held for sale			0
Other current liabilities	0		0
Other long-term liabilities	0		0
Long-term debt	0		0
Members' Equity	413,023		-1,134,125
Total liabilities and equity	($425,633)		($1,825,713)
[1]	156,644,153 common units were issued and outstanding as of December 31, 2014 and December 31, 2013, respectively. These amounts do not include unvested restricted common units granted under the Partnership's long-term incentive plan of 2,419,750 and 2,743,807 as of December 31, 2014 and December 31, 2013, respectively.

Subsidiary_Guarantors_Subsidia2

Subsidiary Guarantors Subsidiary Guarantors Condensed Consolidating Income Statement (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Subsidiary Guarantors [Line Items]
Total revenues	$298,204	$197,372	$231,315
Operations and maintenance	43,670	41,426	41,391
Taxes other than income	12,925	12,928	15,343
General and administrative	47,193	53,131	50,990
Depreciation, Depletion and Amortization	85,579	89,444	90,510
Impairment	395,892	214,286	45,289
OPERATING INCOME (LOSS)	-287,055	-213,843	-12,208
Interest expense, net	-15,247	-18,789	-16,276
Other non-operating income	8,294	0	0
Other (expense) income	-1,734	-1,134	-4,755
Loss on short term investments	-62,028	0	0
Income (loss) before income taxes	-357,770	-233,766	-33,239
Income Tax Expense (Benefit)	-5,403	-5,595	-1,093
Equity in earnings of subsidiaires	0	0	0
INCOME (LOSS) FROM CONTINUING OPERATIONS	-352,367	-228,171	-32,146
Discontinued operations, net of tax	212,460	-49,808	-118,456
Net income (loss)	-139,907	-277,979	-150,602
Parent Company [Member]
Subsidiary Guarantors [Line Items]
Total revenues	93,940	-3,937	28,110
Operations and maintenance	3	0	0
Taxes other than income	0	0	0
General and administrative	9,654	13,145	8,745
Depreciation, Depletion and Amortization	641	454	296
Impairment	0	0	0
OPERATING INCOME (LOSS)	83,642	-17,536	19,069
Interest expense, net	-15,247	-17,891	-16,299
Other non-operating income	16,998	9,025	9,039
Other (expense) income	-7,396	-6,904	-12,189
Loss on short term investments	-62,028
Income (loss) before income taxes	15,969	-33,306	-380
Income Tax Expense (Benefit)	-3,791	-1,653	1,041
Equity in earnings of subsidiaires	-683,371	-191,071	-113,200
INCOME (LOSS) FROM CONTINUING OPERATIONS	-663,611	-222,724	-114,621
Discontinued operations, net of tax	523,704	-55,255	-35,981
Net income (loss)	-139,907	-277,979	-150,602
Co-issuer [Member]
Subsidiary Guarantors [Line Items]
Total revenues	0	0	0
Operations and maintenance	0	0	0
Taxes other than income	0	0	0
General and administrative	0	0	0
Depreciation, Depletion and Amortization	0	0	0
Impairment	0	0	0
OPERATING INCOME (LOSS)	0	0	0
Interest expense, net	0	0	0
Other non-operating income	0	0	0
Other (expense) income	0	0	0
Loss on short term investments	0
Income (loss) before income taxes	0	0	0
Income Tax Expense (Benefit)	0	0	0
Equity in earnings of subsidiaires	0	0	0
INCOME (LOSS) FROM CONTINUING OPERATIONS	0	0	0
Discontinued operations, net of tax	0	0	0
Net income (loss)	0	0	0
Guarantor Subsidiaries [Member]
Subsidiary Guarantors [Line Items]
Total revenues	204,264	201,309	203,205
Operations and maintenance	43,667	41,426	41,391
Taxes other than income	12,925	12,928	15,343
General and administrative	37,539	39,986	42,245
Depreciation, Depletion and Amortization	84,938	88,990	90,214
Impairment	395,892	214,286	45,289
OPERATING INCOME (LOSS)	-370,697	-196,307	-31,277
Interest expense, net	0	-898	23
Other non-operating income	4,741	9,298	10,961
Other (expense) income	-7,783	-12,553	-12,566
Loss on short term investments	0
Income (loss) before income taxes	-373,739	-200,460	-32,859
Income Tax Expense (Benefit)	-1,612	-3,942	-2,134
Equity in earnings of subsidiaires	0	0	0
INCOME (LOSS) FROM CONTINUING OPERATIONS	-372,127	-196,518	-30,725
Discontinued operations, net of tax	-311,235	5,457	-82,457
Net income (loss)	-683,362	-191,061	-113,182
Non-Guarantor Subsidiaries [Member]
Subsidiary Guarantors [Line Items]
Total revenues	0	0	0
Operations and maintenance	0	0	0
Taxes other than income	0	0	0
General and administrative	0	0	0
Depreciation, Depletion and Amortization	0	0	0
Impairment	0	0	0
OPERATING INCOME (LOSS)	0	0	0
Interest expense, net	0	0	0
Other non-operating income	0	0	0
Other (expense) income	0	0	0
Loss on short term investments	0
Income (loss) before income taxes	0	0	0
Income Tax Expense (Benefit)	0	0	0
Equity in earnings of subsidiaires	0	0	0
INCOME (LOSS) FROM CONTINUING OPERATIONS	0	0	0
Discontinued operations, net of tax	-9	-10	-18
Net income (loss)	-9	-10	-18
Consolidation, Eliminations [Member]
Subsidiary Guarantors [Line Items]
Total revenues	0	0	0
Operations and maintenance	0	0	0
Taxes other than income	0	0	0
General and administrative	0	0	0
Depreciation, Depletion and Amortization	0	0	0
Impairment	0	0	0
OPERATING INCOME (LOSS)	0	0	0
Interest expense, net	0	0	0
Other non-operating income	-13,445	-18,323	-20,000
Other (expense) income	13,445	18,323	20,000
Loss on short term investments	0
Income (loss) before income taxes	0	0	0
Income Tax Expense (Benefit)	0	0	0
Equity in earnings of subsidiaires	683,371	191,071	113,200
INCOME (LOSS) FROM CONTINUING OPERATIONS	683,371	191,071	113,200
Discontinued operations, net of tax	0	0	0
Net income (loss)	$683,371	$191,071	$113,200

Subsidiary_Guarantors_Subsidia3

Subsidiary Guarantors Subsidiary Guarantor Condensed Consolidating Statements of Cash Flows (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Subsidiary Guarantors [Line Items]
Proceeds from sale of asset	$0	$76	$15,398
Net cash flows provided by operating activities	78,126	114,243	75,336
Additions to property, plant and equipment	-136,694	-149,944	-167,907
Proceeds from sale of Short-term Investments	43,836	0	0
Contribution to subsidiaries			0
Net cash provided by (used in) investing activities	-92,858	-149,868	-152,509
Proceeds from long-term debt	472,500	601,400	1,043,750
Repayment of long-term debt	-966,700	-503,100	-916,750
Proceeds from Senior Notes	0	0	22,889
Payment of debt issuance costs	-1,984	0	-614
Proceeds from derivative contracts	-5,022	1,323	14,449
Common unit issued in equity offerings	0	102,388	96,173
Issuance costs for equity offerings	0	-4,519	-4,518
Exercise of Warrants	0	0	31,804
Repurchase of common units	-19,170	-1,858	-2,501
Distributions to members and affiliates	-34,982	-125,911	-119,211
Net cash provided by (used in) financing activities	-555,358	69,723	165,471
Net Cash Provided by (Used in) Discontinued Operations	571,357	-34,047	-89,150
Net increase in cash and cash equivalents	1,267	51	-852
CASH AND CASH EQUIVALENTS—Beginning of period	76	25	877
CASH AND CASH EQUIVALENTS—End of period	1,343	76	25
Parent Company [Member]
Subsidiary Guarantors [Line Items]
Proceeds from sale of asset		0	0
Net cash flows provided by operating activities	-28,661	-34,610	-108,061
Additions to property, plant and equipment	344	-115	-1,551
Proceeds from sale of Short-term Investments	43,836
Contribution to subsidiaries			-236,971
Net cash provided by (used in) investing activities	44,180	-115	-238,522
Proceeds from long-term debt	472,500	601,400	1,043,750
Repayment of long-term debt	-966,700	-503,100	-916,750
Proceeds from Senior Notes			22,889
Payment of debt issuance costs	-1,984		-614
Proceeds from derivative contracts	-5,022	1,323	14,449
Common unit issued in equity offerings		102,388	96,173
Issuance costs for equity offerings		-4,519	-4,518
Exercise of Warrants			31,804
Repurchase of common units	-19,170	-1,858	-2,501
Distributions to members and affiliates	-34,982	-125,911	-119,211
Net cash provided by (used in) financing activities	-555,358	69,723	165,471
Net Cash Provided by (Used in) Discontinued Operations		-35,431	181,463
Net increase in cash and cash equivalents	1,449	-433	351
CASH AND CASH EQUIVALENTS—Beginning of period	1,237	1,670	1,319
CASH AND CASH EQUIVALENTS—End of period	2,686	1,237	1,670
Co-issuer [Member]
Subsidiary Guarantors [Line Items]
Proceeds from sale of asset		0	0
Net cash flows provided by operating activities	0	0	0
Additions to property, plant and equipment	0	0	0
Proceeds from sale of Short-term Investments	0
Contribution to subsidiaries			0
Net cash provided by (used in) investing activities	0	0	0
Proceeds from long-term debt	0	0	0
Repayment of long-term debt	0	0	0
Proceeds from Senior Notes			0
Payment of debt issuance costs	0		0
Proceeds from derivative contracts	0	0	0
Common unit issued in equity offerings		0	0
Issuance costs for equity offerings		0
Exercise of Warrants			0
Repurchase of common units	0	0	0
Distributions to members and affiliates	0	0	0
Net cash provided by (used in) financing activities	0	0	0
Net Cash Provided by (Used in) Discontinued Operations	0	0	0
Net increase in cash and cash equivalents	0	0	0
CASH AND CASH EQUIVALENTS—Beginning of period	1	1	1
CASH AND CASH EQUIVALENTS—End of period	1	1	1
Guarantor Subsidiaries [Member]
Subsidiary Guarantors [Line Items]
Proceeds from sale of asset		76	15,398
Net cash flows provided by operating activities	106,787	148,853	183,397
Additions to property, plant and equipment	-137,038	-149,829	-166,356
Proceeds from sale of Short-term Investments	0
Contribution to subsidiaries			0
Net cash provided by (used in) investing activities	-137,038	-149,753	-150,958
Proceeds from long-term debt	0	0	0
Repayment of long-term debt	0	0	0
Proceeds from Senior Notes			0
Payment of debt issuance costs	0		0
Proceeds from derivative contracts	0	0	0
Common unit issued in equity offerings		0	0
Issuance costs for equity offerings		0	0
Exercise of Warrants			0
Repurchase of common units	0	0	0
Distributions to members and affiliates	0	0	0
Net cash provided by (used in) financing activities	0	0	0
Net Cash Provided by (Used in) Discontinued Operations	30,047	1,343	-33,699
Net increase in cash and cash equivalents	-204	443	-1,260
CASH AND CASH EQUIVALENTS—Beginning of period	-1,389	-1,832	-572
CASH AND CASH EQUIVALENTS—End of period	-1,593	-1,389	-1,832
Non-Guarantor Subsidiaries [Member]
Subsidiary Guarantors [Line Items]
Proceeds from sale of asset		0	0
Net cash flows provided by operating activities	0	0	0
Additions to property, plant and equipment	0	0	0
Proceeds from sale of Short-term Investments	0
Contribution to subsidiaries			0
Net cash provided by (used in) investing activities	0	0	0
Proceeds from long-term debt	0	0	0
Repayment of long-term debt	0	0	0
Proceeds from Senior Notes			0
Payment of debt issuance costs	0		0
Proceeds from derivative contracts	0	0	0
Common unit issued in equity offerings		0	0
Issuance costs for equity offerings		0	0
Exercise of Warrants			0
Repurchase of common units	0	0	0
Distributions to members and affiliates	0	0	0
Net cash provided by (used in) financing activities	0	0	0
Net Cash Provided by (Used in) Discontinued Operations	22	41	57
Net increase in cash and cash equivalents	22	41	57
CASH AND CASH EQUIVALENTS—Beginning of period	227	186	129
CASH AND CASH EQUIVALENTS—End of period	249	227	186
Consolidation, Eliminations [Member]
Subsidiary Guarantors [Line Items]
Proceeds from sale of asset		0	0
Net cash flows provided by operating activities	0	0	0
Additions to property, plant and equipment	0	0	0
Proceeds from sale of Short-term Investments	0
Contribution to subsidiaries			236,971
Net cash provided by (used in) investing activities	0	0	236,971
Proceeds from long-term debt	0	0	0
Repayment of long-term debt	0	0	0
Proceeds from Senior Notes			0
Payment of debt issuance costs	0		0
Proceeds from derivative contracts	0	0	0
Common unit issued in equity offerings		0	0
Issuance costs for equity offerings		0	0
Exercise of Warrants			0
Repurchase of common units	0	0	0
Distributions to members and affiliates	0	0	0
Net cash provided by (used in) financing activities	0	0	0
Net Cash Provided by (Used in) Discontinued Operations	0	0	-236,971
Net increase in cash and cash equivalents	0	0	0
CASH AND CASH EQUIVALENTS—Beginning of period	0	0	0
CASH AND CASH EQUIVALENTS—End of period	0	0	0
Parent [Member]
Subsidiary Guarantors [Line Items]
Net Cash Provided by (Used in) Discontinued Operations	$541,288

Supplemental_Oil_and_Gas_Infor2

Supplemental Oil and Gas Information (Unaudited) Proved Reserves Summary (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	MBbls	MBbls	MBbls	MBbls
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Purchases of Minerals in Place	4
Twelve month average oil price	94.99
Twelve month average natural gas price	4.35
Oil [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Net	13,542	12,984	11,522
Proved Developed and Undeveloped Reserves, Extensions, Discoveries, and Additions	1,080	2,712	1,405
Proved Developed and Undeveloped Reserves, Purchases of Minerals in Place	326	0	104
Proved Developed and Undeveloped Reserves, Production	-1,313	-1,222	-1,184
Proved Developed and Undeveloped Reserves, Sales of Minerals in Place			0
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	-2,618	-932	1,137
Proved Developed and Undeveloped Reserves, Net	11,017	13,542	12,984
Proved Developed Reserves (Volume)	9,595	10,153	10,993	10,271
Proved Undeveloped Reserve (Volume)	1,412	3,389	1,991	1,251
Natural Gas [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Net	177,226	194,429	234,022
Proved Developed and Undeveloped Reserves, Extensions, Discoveries, and Additions	22,990	29,137	31,524
Proved Developed and Undeveloped Reserves, Purchases of Minerals in Place	769	0	128
Proved Developed and Undeveloped Reserves, Production	-11,995	-12,804	-16,443
Proved Developed and Undeveloped Reserves, Sales of Minerals in Place			-13,331
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	-19,897	-33,536	-41,471
Proved Developed and Undeveloped Reserves, Net	169,093	177,226	194,429
Proved Developed Reserves (Volume)	126,783	126,950	136,545	165,269
Proved Undeveloped Reserve (Volume)	42,310	50,276	57,884	68,753
Natural Gas Liquids [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Net	14,637	12,866	11,347
Proved Developed and Undeveloped Reserves, Extensions, Discoveries, and Additions	2,224	3,180	2,136
Proved Developed and Undeveloped Reserves, Purchases of Minerals in Place	170	0	18
Proved Developed and Undeveloped Reserves, Production	-1,158	-1,156	-1,121
Proved Developed and Undeveloped Reserves, Sales of Minerals in Place			0
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	-2,039	-253	486
Proved Developed and Undeveloped Reserves, Net	13,834	14,637	12,866
Proved Developed Reserves (Volume)	10,895	10,766	10,445	9,307
Proved Undeveloped Reserve (Volume)	2,939	3,871	2,421	2,040
Revisions due to poor economic performance [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	-3	-28

Supplemental_Oil_and_Gas_Infor3

Supplemental Oil and Gas Information (Unaudited) Capitalized Costs Relating to Oil and Gas Producing Activities (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Evaluated properties	$905,622	$1,156,895	$1,213,622
Unevaluated properties—excluded from depletion	7,512	10,022	31,823
Gross oil and gas properties	913,134	1,166,917	1,245,445
Accumulated depreciation, depletion, amortization	-431,555	-353,679	-269,376
Net oil and gas properties	$481,579	$813,238	$976,069

Supplemental_Oil_and_Gas_Infor4

Supplemental Oil and Gas Information (Unaudited) Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Property acquisition costs, proved	$10,861	$0	$2,582
Development costs	122,387	124,032	135,692
Total costs	$133,248	$124,032	$138,274

Supplemental_Oil_and_Gas_Infor5

Supplemental Oil and Gas Information (Unaudited) Standarized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	$2,187,346	$2,423,350	$2,279,735
Future production costs	-759,966	-737,468	-767,004
Future development costs	-240,886	-318,778	-354,690
Future net cash flows before income taxes	1,186,494	1,367,104	1,158,041
Future income tax (expense) benefit	-833	-1,212	-1,086
Future net cash flows before 10% discount	1,185,661	1,365,892	1,156,955
10% annual discount for estimated timing of cash flows	-591,421	-715,386	-621,826
Total standardized measure of discounted future net cash flows	$594,240	$650,506	$535,129

Supplemental_Oil_and_Gas_Infor6

Supplemental Oil and Gas Information (Unaudited) Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]
Beginning of year	$650,506	$535,129	$642,586
Sale of oil and gas produced, net of production costs	-152,097	-150,457	-132,451
Net changes in prices and production costs	-63,142	2,720	-78,247
Extensions, discoveries and improved recovery, less related costs	74,684	136,464	66,460
Previously estimated development costs incurred during the period	49,409	21,470	53,111
Net changes in future development costs	71,800	107,951	36,914
Revisions of previous quantity estimates	-149,993	-103,351	-76,434
Purchases of property	11,904	0	2,811
Sales of property	0	0	-5,063
Accretion of discount	59,818	49,233	60,734
Net changes in income taxes	169	-36	317
Other	41,182	51,383	-35,609
End of year	$594,240	$650,506	$535,129

Supplemental_Oil_and_Gas_Infor7

Supplemental Oil and Gas Information (Unaudited) Results of Operations (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Revenues:
Sales to third parties	$190,057	$146,210	$135,842
Intercompany sales	5,475	47,048	53,343
Total revenues	195,532	193,258	189,185
Costs and expenses:
Production costs	56,595	54,354	56,734
General and administrative	8,166	11,419	12,162
Depreciation, depletion, and amortization	81,030	87,456	88,777
Impairment	395,892	214,286	45,289
Total costs and expenses	541,683	367,515	202,962
Total result of operations	($346,151)	($174,257)	($13,777)

Supplemental_Oil_and_Gas_Infor8

Supplemental Oil and Gas Information (Unaudited) Narrative (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
	MBbls
Proved Developed and Undeveloped Reserves, Purchases of Minerals in Place	4
Results of Operations, Revenue, Other	$8.20	$8.10	$14
Revisions due to changes in ownership interest [Member]
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates		2
Revisions due to other factors [Member]
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	-45	3
Revisions due to poor economic performance [Member]
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	-3	-28
Revisions due to non-commercial determination [Member]
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	0	-8