Eagle Rock Energy Partners L P (EROC) 10-Q 2 May 14 2014 Q1 Quarterly report Financial data

Document_and_Entity_Informatio

Document and Entity Information Document	3 Months Ended
	Mar. 31, 2014	Apr. 28, 2014
Entity Information [Line Items]	'	'
Entity Registrant Name	'EAGLE ROCK ENERGY PARTNERS L P	'
Entity Central Index Key	'0001364541	'
Current Fiscal Year End Date	'--12-31	'
Entity Filer Category	'Large Accelerated Filer	'
Document Type	'10-Q	'
Document Period End Date	31-Mar-14	'
Document Fiscal Year Focus	'2014	'
Document Fiscal Period Focus	'Q1	'
Amendment Flag	'false	'
Entity Common Stock, Shares Outstanding	'	159,759,188

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Mar. 31, 2014		Dec. 31, 2013
In Thousands, unless otherwise specified
CURRENT ASSETS:	'		'
Cash and cash equivalents	$5,623		$76
Accounts receivable	165,852	[1]	145,963	[1]
Risk management assets, current	5,740		9,162
Prepayments and other current assets	12,601		8,183
Total current assets	189,816		163,384
Property, Plant and Equipment — Net	1,838,925		1,828,768
Intangible Assets — Net	104,149		105,620
Deferred Tax Asset	2,224		1,438
Risk Management Assets	1,451		5,461
Other Assets	18,753		22,879
Total assets	2,155,318		2,127,550
CURRENT LIABILITIES:	'		'
Accounts payable	202,693		170,124
Accrued liabilities	42,442		29,970
Taxes payable	0		149
Risk management liabilities	15,334		11,023
Total current liabilities	260,469		211,266
Long-term debt	1,269,433		1,252,062
Asset Retirement Obligations	46,269		45,849
Deferred Tax Liability	38,164		37,953
Risk Management Liabilities	878		3,848
Other long-term liabilities	5,258		2,693
Commitments and Contingencies (Note 12)	'		'
Members' Equity	534,847	[2]	573,879	[2]
Total liabilities and equity	$2,155,318		$2,127,550
[1]	Net of allowance for bad debt of $985 as of March 31, 2014 and $1,188 as of December 31, 2013.
[2]	156,644,153 and 156,644,153 common units were issued and outstanding as of March 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 2,754,383 and 2,743,807 as of March 31, 2014 and December 31, 2013, respectively.

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets Parenthetical (USD $)	Mar. 31, 2014	Dec. 31, 2013
In Thousands, except Share data, unless otherwise specified
Allowance for Doubtful Accounts Receivable, Current	$985	$1,188
Limited Partners' Capital Account, Units Issued	156,644,153	156,644,153
Limited Partners' Capital Account, Units Outstanding	156,644,153	156,644,153
Unvested Restricted Units Outstanding	2,754,383	2,743,807

Consolidated_Statements_of_Ope

Consolidated Statements of Operations (USD $)	3 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Revenues:	'	'
Natural gas, natural gas liquids, oil, condensate, sulfur and helium sales	$340,465	$254,200
Gathering, compression, processing and treating fees	22,397	20,942
Commodity risk management gains (losses)	-14,944	-17,908
Other revenue	156	497
Total revenue	348,074	257,731
COSTS AND EXPENSES:	'	'
Cost of natural gas, natural gas liquids, condensate and helium	244,973	179,988
Operations and maintenance	34,671	32,219
Taxes other than income	5,667	3,866
General and administrative	21,391	18,847
Impairment	2,097	0
Depreciation, Depletion and Amortization	40,508	40,237
Total costs and expenses	349,307	275,157
Operating income (loss)	-1,233	-17,426
OTHER INCOME (EXPENSE):	'	'
Interest expense	-17,986	-17,084
Interest rate risk management losses	-290	-156
Other (expense) income	-7	-8
Total other (expense) income	-18,283	-17,248
Income (loss) from continuing operations before income taxes	-19,516	-34,674
Income Tax Expense (Benefit)	-953	-1,160
Net income (loss)	($18,563)	($33,514)
NET INCOME PER COMMON UNIT—BASIC AND DILUTED:	'	'
Net income (loss) per common unit - basic and diluted	($0.12)	($0.23)
Weighted Average Number of Shares Outstanding Basic and Diluted	'	'
Weighted average common units outstanding - basic and diluted	156,644	146,171

Consolidated_Statement_of_Memb

Consolidated Statement of Member's Equity (USD $)	Total	Number of Common Units [Member]	Common Units [Member]
In Thousands, except Share data, unless otherwise specified	USD ($)		USD ($)
Members' Equity - Beginning Balance at Dec. 31, 2013	$573,879	'	$573,879
Beginning Balance - Units Outstanding at Dec. 31, 2013	156,644,153	156,644,153	'
Increase (Decrease) in Members' Equity [Roll Forward]	'	'	'
Net income (loss)	-18,563	'	-18,563
Distributions	-23,801	'	-23,801
Equity-based Compensation	3,332	'	3,332
Members' Equity - Ending Balance at Mar. 31, 2014	$534,847	'	$534,847
Ending Balance - Units Outstanding at Mar. 31, 2014	156,644,153	156,644,153	'

Consolidated_Statements_of_Cas

Consolidated Statements of Cash Flows (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
CASH FLOWS FROM OPERATING ACTIVITIES:	'	'
Net income (loss)	($18,563)	($33,514)
Adjustments to reconcile net (loss) income to net cash provided by operating activities:	'	'
Depreciation, Depletion and Amortization	40,508	40,237
Impairment	2,097	0
Amortization of debt issuance costs	1,228	1,036
Loss (gain) from risk management activities, net	-16,221	-19,214
Derivative settlements	-5,740	6,406
Equity-based compensation	3,332	2,647
Other	222	1,048
Changes in assets and liabilities—net of acquisitions:	'	'
Accounts receivable	-19,889	-4,296
Prepayments and other current assets	-4,418	-255
Accounts payable	35,797	-40
Accrued liabilities	15,339	8,551
Other assets	3,250	436
Other current liabilities	-831	-628
Net cash provided by (used in) operating activities	68,553	40,842
CASH FLOWS FROM INVESTING ACTIVITIES:	'	'
Additions to property, plant and equipment	-53,938	-70,137
Purchase of intangible assets	-554	-1,006
Net cash provided by (used in) investing activities	-54,492	-71,143
CASH FLOWS FROM FINANCING ACTIVITIES:	'	'
Proceeds from long-term debt	144,250	171,300
Repayment of long-term debt	-127,050	-202,000
Payment of debt issuance costs	205	0
Proceeds from derivative contracts	-1,708	1,044
Common unit issuance	0	96,359
Payments of Unit Issuance Costs	0	-3,948
Distributions to members and affiliates	-23,801	-32,419
Net cash provided by (used in) financing activities	-8,514	30,336
Net increase in cash and cash equivalents	5,547	35
CASH AND CASH EQUIVALENTS—Beginning of period	76	25
CASH AND CASH EQUIVALENTS—End of period	5,623	60
NONCASH INVESTING AND FINANCING ACTIVITIES:	'	'
Investments in property, plant and equipment, not paid	6,241	16,580
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:	'	'
Interest paid—net of amounts capitalized	5,558	5,310
Cash paid for taxes	$0	$2

Organization_and_Description_o

Organization and Description of Business	3 Months Ended
	Mar. 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 limited partnership engaged in (i) the 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 (the “Midstream Business”); and (ii) the business of developing and producing interests in oil and natural gas properties (the “Upstream Business”). The Partnership's midstream assets are strategically located in four productive, mature natural gas producing regions: the Texas Panhandle; East Texas/Louisiana; South Texas; and the Gulf of Mexico. The Partnership's natural gas pipelines gather natural gas from designated points near producing wells and transport these volumes to third-party pipelines, the Partnership's gas processing plants, utilities and industrial consumers. Natural gas transported to the Partnership's gas processing plants, either in the Partnership's pipelines or third party pipelines, is treated to remove contaminants and conditioned or processed into marketable natural gas and NGLs. The Partnership reports its Midstream Business results through three segments: the Texas Panhandle Segment; the East Texas and Other Midstream Segment; and the Marketing and Trading Segment.  The Partnership's upstream assets are characterized by long-lived, high-working interest properties with extensive production histories and development opportunities. Its upstream assets are located primarily in South Alabama (where it also operates the associated gathering and processing assets), Texas, Oklahoma, Mississippi and Arkansas. The Partnership reports its Upstream Business through 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.
	Recent Developments—On December 23, 2013, the Partnership announced that it had entered into a definitive agreement to contribute its Midstream Business (the "Midstream Business Contribution") to Regency Energy Partners LP ("Regency") for total consideration of up to $1.325 billion, consisting of $200 million of newly issued Regency common units (8,245,859 common units, calculated by taking the volume-weighted average price of a single Regency common unit for the ten trading days immediately preceding the announcement date) and a combination of cash and assumed debt, subject to certain closing conditions. As part of the transaction, Regency is conducting an offer to exchange the Partnership's $550 million of outstanding senior unsecured notes for an equivalent amount of Regency senior unsecured notes with the same tenor, coupon and a comparable covenant package. The cash portion of the purchase price will be reduced by the amount of notes exchanged subject to a 10% adjustment factor, such that if all $550 million of bonds are exchanged, the total consideration will equal $1.27 billion ($1.325 billion less $55 million) consisting of $200 million in Regency units, $550 million of assumed debt and $520 million of cash proceeds.
	The Midstream Business Contribution was approved by the Partnership's common unitholders on April 29, 2014. As of that date, all significant closing conditions for the transaction had been satisfied other than the approval from the Federal Trade Commissions ("FTC") anti-trust review. On February 27, 2014, the Partnership and Regency received a Request for Additional Information and Documentary Materials ("Second Request") from the FTC in connection with the Midstream Business Contribution. On April 30, 2014, the Partnership and Regency certified their substantial compliance with the FTC's Second Request and entered into a timing agreement with the FTC agreeing to extend the FTC's review period until June 30, 2014, unless the FTC completes its investigation earlier.
	As the sale of the Midstream Business at March 31, 2014 remained conditioned upon, among other things, the approval of the Partnership's common unitholders (see above and Note 18) and the expiration or termination of all applicable waiting periods under the Hart-Scott-Rodino Antitrust Improvement Act of 1976, as amended, the Partnership has not classified the assets of its Midstream Business as assets-held-for-sale or the operations as discontinued.

Summary_of_Significant_Account

Summary of Significant Accounting Policies	3 Months Ended
	Mar. 31, 2014
Accounting Policies [Abstract]	'
Summary of Significant Accounting Policies	'
	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
	Basis of Presentation and Principles of Consolidation—The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP"). These unaudited condensed consolidated financial statements should be read in conjunction with the consolidated financial statements presented in the Partnership's Annual Report on Form 10-K for the year ended December 31, 2013. In the opinion of management, the accompanying unaudited condensed consolidated financial statements contain all appropriate adjustments, all of which are normally recurring adjustments unless otherwise noted, considered necessary to present fairly the financial position of the Partnership and its consolidated subsidiaries and the results of operations and cash flows for the respective periods. Operating results for the three months ended March 31, 2014 are not necessarily indicative of the results that may be expected for the full year ending December 31, 2014.
	Eagle Rock Energy is the owner of non-operating undivided interests in certain gas processing plants and gas gathering systems. Eagle Rock Energy owns these interests as tenants-in-common with the majority owner-operator of the facilities. Accordingly, Eagle Rock Energy includes its pro-rata share of assets, liabilities, revenues and expenses related to these assets in its financial statements. All intercompany accounts and transactions are eliminated in the unaudited condensed consolidated financial statements.
	The Partnership has provided a discussion of significant accounting policies in its Annual Report on Form 10-K for the year ended December 31, 2013. Certain items from that discussion are repeated or updated below as necessary to assist in the understanding of these financial statements.
	Use of Estimates—The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reported period. Significant estimates are required for proved oil and natural gas reserves, which can affect the carrying value of oil and natural gas properties. The Partnership evaluates its estimates and assumptions on a regular basis. The Partnership bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results could differ from those estimates and such differences could be material.
	Inventory—Inventory is stated at the lower of cost or market, with cost being determined using the average cost method. At March 31, 2014 and December 31, 2013, the Partnership had $0.3 million and $1.0 million, respectively, of crude oil finished goods inventory, which is recorded as part of Other Current Assets within the unaudited condensed consolidated balance sheet.
	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, accounted for utilizing the successful efforts method, the Partnership reviews its proved properties at the depletion unit 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 to the proved reserves estimates, unfavorable projections of future prices, the timing of future production and estimates of future costs to produce the oil and natural gas. Unproved properties (both individually significant and insignificant) are assessed periodically within specific geographic areas and, if necessary, impairments are charged to expense.
	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 Notes 4 and 6 for further discussion on impairment charges.
	Revenue Recognition—The Partnership's primary types of sales and service activities reported as operating revenue include:
	•	sales of natural gas, NGLs, crude oil, condensate, sulfur and helium;
	•	natural gas gathering, processing and transportation, from which the Partnership generates revenues primarily through the compression, gathering, treating, processing and transportation of natural gas; and
	•	NGL transportation from which the Partnership generates revenues from transportation fees.
	Revenues associated with sales of natural gas, NGLs, crude oil, condensate, sulfur and helium are recognized when title passes to the customer, which is when the risk of ownership passes to the customer and physical delivery occurs. Revenues associated with transportation and processing fees are recognized in the period when the services are provided.
	For gathering and processing services, the Partnership either receives fees or commodities from natural gas producers under various types of contracts including percentage-of-proceeds, fixed recovery and percent-of-index arrangements. The Partnership also recognizes fee-based service revenues for services such as transportation, compression and processing.
	The Partnership's Upstream Segment recognizes natural gas revenues 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. Material imbalances are reflected as adjustments to reported natural gas reserves and future cash flows.  For the Upstream Segment, the Partnership had long-term imbalance payables totaling $0.3 million and $0.3 million as of March 31, 2014 and December 31, 2013, respectively.
	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 unaudited condensed consolidated balance sheets and marked-to-market using current market prices in effect for the reporting period of the outstanding imbalances. For the Midstream Business, as of March 31, 2014, the Partnership had imbalance receivables totaling $1.8 million and imbalance payables totaling $0.6 million. For the Midstream Business, as of December 31, 2013, the Partnership had imbalance receivables totaling $0.7 million and imbalance payables totaling $1.6 million. 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.
	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, with the exception of certain contracts with it's natural gas trading and marketing business. The Partnership uses financial instruments such as swaps, collars and other derivatives to mitigate the risks to cash flows resulting from changes in commodity prices and interest rates. The Partnership recognizes these financial instruments on its unaudited condensed consolidated balance sheet at the instrument's fair value with changes in fair value reflected in the unaudited condensed consolidated statement of operations, as the Partnership has not designated any of these derivative instruments as hedges. The cash flows from derivatives are reported as cash flows from operating activities unless the derivative contract is deemed to contain a financing element. Derivatives deemed to contain a financing element are reported as a financing activity in the unaudited condensed consolidated statement of cash flows. See Note 10 for a description of the Partnership's risk management activities.
	Other Reclassifications—The prior period within the unaudited condensed consolidated statements of cash flows has been reclassified to conform to current period presentation. Amounts have been reclassified to new rows titled “Loss from risk management activities, net” that combines settled and mark-to-market gains/losses on derivative instruments and “Derivative settlements” that includes cash attributable to derivative instruments that settled during the periods. The revisions to the cash flow presentation had no impact on “Net cash provided by operating activities.”

New_Accounting_Pronouncements

New Accounting Pronouncements	3 Months Ended
	Mar. 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 unaudited condensed 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 is currently evaluating the potential impact, if any, of the adoption of this new guidance on its financial statements.

Property_Plant_and_Equipment

Property, Plant and Equipment	3 Months Ended
	Mar. 31, 2014
Property, Plant and Equipment [Abstract]	'
Property, Plant and Equipment Disclosure	'
	PROPERTY, PLANT AND EQUIPMENT
	Fixed assets consisted of the following:
		March 31,			December 31,
		2014			2013
		($ in thousands)
	Land	$	2,877		$	2,877
	Plant	519,392			521,103
	Gathering and pipeline	782,577			777,446
	Equipment and machinery	58,153			53,999
	Vehicles and transportation equipment	4,017			4,001
	Office equipment, furniture, and fixtures	1,328			1,309
	Computer equipment	17,117			14,806
	Linefill	5,142			5,180
	Proved properties	1,195,188			1,156,896
	Unproved properties	10,276			10,022
	Construction in progress	25,457			33,824
		2,621,524			2,581,463
	Less: accumulated depreciation, depletion and amortization	(782,599		)	(752,695		)
	Net property, plant and equipment	$	1,838,925		$	1,828,768
	The following table sets forth the total depreciation, depletion, capitalized interest costs and impairment expense by type of asset within the Partnership's unaudited condensed consolidated statements of operations:
			Three Months Ended
			March 31,
			2014			2013
		($ in thousands)
	Depreciation		$	18,861		$	16,395
	Depletion		$	19,672		$	20,871
	Capitalized interest costs		$	144		$	355
	Impairment expense:
	Plant assets (a)		$	132		$	—
	Pipeline assets (a)		$	1,904		$	—
	________________________________
	(a)	During the three months ended March 31, 2014, the Partnership incurred impairment charges in its Midstream Business related to certain plants and pipelines in its East Texas and Other Segment due to the loss of two customers.

Asset_Retirement_Obligations

Asset Retirement Obligations	3 Months Ended
	Mar. 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 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 convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of (i) remediation costs, (ii) remaining lives, (iii) future inflation factors and (iv) a credit-adjusted risk free interest rate.
	A reconciliation of the Partnership's liability for asset retirement obligations is as follows:
		2014			2013
		($ in thousands)
	Asset retirement obligations—January 1 (a)	$	58,964		$	48,755
	Additional liabilities	39			746
	Liabilities settled	(682		)	(570		)
	Revision to liabilities	(105		)	—
	Accretion expense	980			840
	Asset retirement obligations—March 31 (a)	$	59,196		$	49,771
	_____________________________________
	(a)	As of March 31, 2014 and December 31, 2013, $12.9 million and $13.1 million, respectively, were included within accrued liabilities in the Unaudited Condensed Consolidated Balance Sheets.
	During the three months ended March 31, 2014, the Partnership made revisions of $0.1 million to decrease certain asset retirement obligations due to changes in the estimated costs to remediate.

Intangible_Assets

Intangible Assets	3 Months Ended
	Mar. 31, 2014
Intangible Assets, Net (Excluding Goodwill) [Abstract]	'
Intangible Assets	'
	INTANGIBLE ASSETS
	Intangible assets consist of rights-of-way and easements and acquired customer contracts, which the Partnership amortizes over the term of the agreement or estimated useful life. The amortization period for the Partnership's rights-of-way and easements is 20 years. The amortization periods for contracts range from 5 to 20 years.
	Intangible assets consisted of the following:
		March 31,			December 31,
		2014			2013
		($ in thousands)
	Rights-of-way and easements—at cost	$	131,580		$	131,088
	Less: accumulated amortization	(37,846		)	(36,228		)
	Contracts	22,742			22,742
	Less: accumulated amortization	(12,327		)	(11,982		)
	Net intangible assets	$	104,149		$	105,620
	The following table sets forth amortization and impairment expense by type of intangible asset within the Partnership's unaudited condensed consolidated statements of operations:
			Three Months Ended
			March 31,
			2014			2013
		($ in thousands)
	Amortization		$	1,964		$	2,961
	Impairment expense:
	Rights-of-way (a)		$	61		$	—
	_____________________________________
	(a)	During the three months ended March 31, 2014, the Partnership incurred impairment charges in its Midstream Business related to certain rights-of-way in its East Texas and Other Segment due to the loss of two customers.
	Estimated future amortization expense related to the intangible assets at March 31, 2014, is as follows (in thousands):
	Year ending December 31,
	2014	$	5,936
	2015	$	7,914
	2016	$	7,913
	2017	$	7,912
	2018	$	7,911
	Thereafter	$	66,563

Long_Term_Debt

Long Term Debt	3 Months Ended
	Mar. 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:
		March 31,				December 31,
		2014				2013
		($ in thousands)
	Revolving credit facility:	$	724,000			$	706,800
	Senior notes:
	8.375% Senior Notes due 2019	550,000				550,000
	Unamortized bond discount	(4,567		)		(4,738		)
	Total Senior Notes	545,433				545,262
	Total long-term debt	$	1,269,433			$	1,252,062
	The Partnership currently pays an annual fee of 0.50% on the unused commitment under the revolving credit facility. As of March 31, 2014, the Partnership had approximately $21.7 million of outstanding letters of credit and approximately $69.1 million of availability under its revolving credit facility, based on its borrowing base of $815 million. The revolving credit facility matures on June 22, 2016.
	On February 26, 2014, the Partnership entered into an amended credit agreement with its lender group which allowed for greater liquidity under the senior secured credit facility and for greater covenant flexibility for the first quarter of 2014. Specifically, the amendment provides for: (i) an increase in the Total Leverage Ratio and Senior Secured Leverage Ratio (as defined in the Credit Agreement) for the quarter ended March 31, 2014; (ii) the exclusion of fees and expenses associated with the strategic review and disposition of the Partnership’s Midstream Business from the calculation of Consolidated EBITDA (as defined in the Credit Agreement); (iii) deferring the redetermination of the Upstream Borrowing Base until June 1, 2014; and (iv) the option for the Partnership, at its election, to expand the multiplier for the Midstream Borrowing Base from 3.75x to 4.00x. The Partnership exercised this option to expand the multiplier for the Midstream Borrowing Base on March 31, 2014.
	The following table presents the debt covenant levels specified in our revolving credit facility as of March 31, 2014:
	Quarter Ended	Total Leverage Ratio (a)	Senior Secured Leverage Ratio (a)	Interest Coverage Ratio (b)	Current Ratio (b)
	31-Mar-14	5.85	3.4	2.5	1
	30-Jun-14	5	3.05	2.5	1
	30-Sep-14	4.75	2.95	2.5	1
	Thereafter	4.5	N/A	2.5	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 the Partnership's actual covenant ratios as of March 31, 2014:
	Interest coverage ratio	3.1
	Total leverage ratio	5.4
	Senior secured leverage ratio	3.06
	Current ratio	1.1
	As of March 31, 2014, the Partnership was in compliance with the financial covenants under the revolving credit facility. The Partnership expects to remain in compliance with its financial covenants under the Credit Agreement throughout 2014 assuming the Midstream Business Contribution to Regency closes prior to July 1, 2014. The Midstream Business Contribution will substantially improve the Partnership’s liquidity and debt ratios through the elimination of significant debt currently outstanding under its revolving credit facility and the proposed assumption of all of its senior unsecured notes via an exchange offer conducted by Regency. Should the Midstream Business Contribution closing date extend beyond the second quarter of 2014, the Partnership may need to seek additional amendments to its Credit Agreement from the lender group.
	The Partnership received unitholder approval of the Midstream Business Contribution on April 29, 2014, however, the completion of the Midstream Business Contribution remains subject to regulatory approval. On February 27, 2014, the Partnership and Regency received a Request for Additional Information and Documentary Material ("Second Request") from the Federal Trade Commission ("FTC") in connection with the Midstream Business Contribution. On April 30, the Partnership and Regency certified substantial compliance with the Second Request and entered into a timing agreement with the FTC pursuant to which the Partnership and Regency agreed not to close the transaction prior to June 30, 2014, unless the FTC completes its investigation earlier. At this time, the Partnership can provide no assurance that the Midstream Business Contribution will be completed within its anticipated time frame, or at all. If the Midstream Business Contribution is not consummated by July 31, 2014, each party has the right to terminate the transaction without penalty. Should the Midstream Business Contribution not be consummated, the Partnership intends to explore alternative means to reduce its leverage ratios to comply with the financial covenants, which may include asset sales or purchases, equity financings, the separation of its upstream and midstream businesses or other alternatives.

Members_Equity

Members' Equity	3 Months Ended
	Mar. 31, 2014
Partners' Capital [Abstract]	'
Members' Equity	'
	MEMBERS’ EQUITY
	At March 31, 2014 and December 31, 2013, there were 156,644,153 and 156,644,153 unrestricted common units outstanding, respectively. In addition, there were 2,754,383 and 2,743,807 unvested restricted common units outstanding at March 31, 2014 and December 31, 2013, respectively.
	On May 31, 2012, the Partnership announced a program through which it may issue common units, from time to time, with an aggregate market value of up to $100 million. The Partnership is under no obligation to issue equity under the program. During the three months ended March 31, 2014, no units were issued under this program.
	The table below summarizes the distributions paid or payable and declared for the three months ended March 31, 2014.
	Quarter Ended		Distribution		Record Date*	Payment Date
			per Common Unit
	December 31, 2013+*		$	0.15	February 7, 2014	February 14, 2014
	March 31, 2014**		$	—	N/A	N/A
	_____________________________
	+	The distribution excludes certain restricted unit grants.
	*	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 as the distribution was suspended for this period in advance of the closing the Midstream Business Contribution.

Related_Party_Transactions

Related Party Transactions	3 Months Ended
	Mar. 31, 2014
Related Party Transactions [Abstract]	'
Related Party Transactions	'
	RELATED PARTY TRANSACTIONS
	The following table summarizes transactions between the Partnership and certain affiliated entities:
			Three Months Ended
			March 31,
			2014			2013
	Affiliates of Natural Gas Partners:	($ in thousands)
	Natural gas purchases from affiliates		$	1,142		$	123
		March 31, 2014			December 31, 2013
	Affiliates of Natural Gas Partners:	($ in thousands)
	Payable (related to natural gas purchases)	$	—		$	18

Risk_Management_Activities

Risk Management Activities	3 Months Ended
	Mar. 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 has entered into interest rate swaps. These swaps convert a portion of the Partnership's obligations under it's variable-rate revolving credit facility into a fixed-rate obligation. The purpose of entering into these swaps is to eliminate interest rate variability by converting LIBOR-based variable-rate payments to fixed-rate payments. Amounts received or paid under these swaps were recorded as reductions or increases in interest expense.
	For accounting purposes, the Partnership has not designated any of its interest rate derivative instruments as hedges; instead it marks these derivative contracts to fair value (see Note 11).  Changes in fair values of the interest rate derivative instruments are recorded as an adjustment to the mark-to-market gains (losses) on risk management transactions within other income (expense).
	The following table sets forth certain information regarding the Partnership's interest rate swaps as of March 31, 2014:
	Effective Date		Expiration		Notional			Fixed
			Date		Amount			Rate
	6/22/11		6/22/15		$	250,000,000		2.95	%
	Commodity Derivative Instruments
	The prices of crude oil, natural gas and NGLs are subject to fluctuations in response to changes in supply, demand, market uncertainty and a variety of additional factors which are beyond the Partnership's control.  These risks can cause significant changes in the Partnership's cash flows and affect its ability to achieve its distribution objectives and comply with the covenants of its 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.  Historically, the Partnership has hedged a substantial portion of its expected production in an attempt 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 attempt to 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.  For the Midstream Business, expected future production is based on the expected production from wells currently flowing to the Partnership's processing plants, plus additional volumes the Partnership expects to receive from future drilling activity by its producer customer base.  The Partnership's expectations for its Midstream Business volumes associated with future drilling are based on information it receives from its producer customer base and historical observations. 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 11).  Changes in fair values of the commodity derivative instruments are recorded as an adjustment to the mark-to-market gains (losses) on risk management transactions within revenue.
	By using derivative instruments to economically hedge exposure to changes in commodity prices, the Partnership exposes itself to counterparty credit risk. Historically, the Partnership's counterparties have all been participants or affiliates of participants within its revolving credit facility, which is secured by substantially all of the assets of the Partnership. Therefore, the Partnership is not currently required to post any collateral, nor does it require collateral from its counterparties. The Partnership minimizes the credit risk in derivative instruments by limiting exposure to any single counterparty and monitoring the creditworthiness of its counterparties on an ongoing basis. In addition, the Partnership's derivative contracts for certain counterparties are subject to counterparty netting agreements governing such derivatives, and when possible, the Partnership nets the open positions of each counterparty. See Note 11 for the impact to the Partnership's unaudited condensed consolidated balance sheets of the netting of these derivative contracts.
	The following tables set forth certain information regarding the Partnership's commodity derivatives. Within each table, some trades of the same commodities with the same tenors have been aggregated and shown as weighted averages.
	Commodity derivatives, as of March 31, 2014, that will mature during the years ended December 31, 2014, 2015 and 2016:
	Underlying		Type		Notional		Floor				Cap
					Volumes		Strike				Strike
					(units) (a)		Price				Price
							($/unit)(b)				($/unit)(b)
	Portion of Contracts Maturing in 2014
	Natural Gas		Swap (Pay Floating/Receive Fixed)		12,600,000		$	4.38
	Crude Oil		Costless Collar		180,000		$	90			$	106
	Crude Oil		Swap (Pay Floating/Receive Fixed)		1,650,000		$	96.51
	Crude Oil		Swap (Pay Fixed/Receive Floating)		218,676		92.54
	Propane		Swap (Pay Floating/Receive Fixed)		12,852,000		1.09
	IsoButane		Swap (Pay Floating/Receive Fixed)		1,701,000		1.31
	Normal Butane		Swap (Pay Floating/Receive Fixed)		3,099,600		1.3
	Contracts Maturing in 2015
	Natural Gas		Swap (Pay Floating/Receive Fixed)		12,000,000		$	4.1
	Crude Oil		Costless Collar		480,000		$	90			$	97.55
	Crude Oil		Swap (Pay Floating/Receive Fixed)		1,110,000		$	88.7
	Contracts Maturing in 2016
	Natural Gas		Swap (Pay Floating/Receive Fixed)		9,480,000		$	4.25
	Crude Oil		Swap (Pay Floating/Receive Fixed)		1,416,000		$	84.6
	_______________________
	(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 in $/MMbtu for natural gas, $/barrel for crude oil and $/gallon for natural gas liquids.
	Commodity Derivative Instruments - Marketing & Trading
	The Partnership conducts natural gas marketing and trading activities intended to capitalize on favorable price differentials between various receipt and delivery locations. The Partnership's natural gas marketing and trading activities are governed by its risk policy.
	As part of its natural gas marketing and trading activities, the Partnership enters into both financial derivatives and physical contracts. These financial derivatives, primarily basis swaps, are transacted: (i) to economically hedge subscribed capacity exposed to market rate fluctuations; and (ii) to mitigate the price risk related to other purchase and sales of natural gas. By entering into a basis swap, one pricing index is exchanged for another, effectively locking in the margin between the natural gas purchase and sale by removing index spread risk on the combined physical and financial transaction.
	A commodity-related derivative contract may be designated as a "normal" purchase or sale if the commodity is to be physically received or delivered for use or sale in the normal course of business. If designated as "normal," the derivative contract is accounted for under the accrual method of accounting (not marked-to-market) with no balance sheet or income statement recognition of the contract until settlement. Commodity-related contracts that do not qualify for the normal designation are accounted for as derivatives and are marked-to-market each period.
	Through the Partnership's natural gas marketing activity, the Partnership has credit exposure to additional counterparties. The Partnership minimizes the credit risk associated with natural gas marketing by limiting its exposure to any single counterparty and monitoring the creditworthiness of its counterparties on an ongoing basis. In addition, the Partnership's natural gas purchase and sale contracts for certain counterparties are subject to counterparty netting agreements governing settlement under such natural gas purchase and sales contracts, and when possible, the Partnership nets the open positions of each counterparty. See Note 11 for the impact to the Partnership's unaudited condensed consolidated balance sheets of the netting of these contracts.
	Marketing and Trading commodity derivative instruments, as of March 31, 2014, that will mature during the year ended December 31, 2014 and beyond:
	Type		Notional Volumes (MMbtu)
	Portion of Contracts Maturing in 2014
	Index Swap - Purchases		1,950,000
	Index Swap - Sales		600,000
	Swap (Pay Fixed/ Receive Floating) - Purchases		750,000
	Swap (Pay Floating/ Receive Fixed) - Sales		3,525,000
	Forward purchase contract - index		9,315,450
	Forward sales contract - index		16,300,200
	Forward purchase contract - fixed price		3,747,000
	Forward sales contract - fixed price		1,575,000
	Basis Swaps - Purchases		8,155,000
	Basis Swaps - Sales		3,650,000
	Portion of Contracts Maturing in 2015 and beyond
	Basis Swaps - Purchases		13,280,000
	Basis Swaps - Sales		13,280,000
	Changes in the fair value of these financial and physical contracts are recorded as adjustments to natural gas sales.
	Fair Value of Interest Rate and Commodity Derivatives
	The following tables set forth the fair values of interest rate and commodity derivative instruments not designated as hedging instruments and their location within the unaudited condensed consolidated balance sheet as of March 31, 2014 and December 31, 2013:
		As of March 31, 2014
		Derivative Assets					Derivative Liabilities
	Balance Sheet Classification		Fair Value			Balance Sheet Classification		Fair Value
	($ in thousands)
Interest rate derivatives - liabilities	Current assets		$	—		Current liabilities		$	(6,310	)
Interest rate derivatives - liabilities	Long-term assets		—			Long-term liabilities		(1,368		)
Commodity derivatives - assets	Current assets		7,863			Current liabilities		1,657
Commodity derivatives - assets	Long-term assets		2,361			Long-term liabilities		1,322
Commodity derivatives - liabilities	Current assets		(2,123		)	Current liabilities		(10,681		)
Commodity derivatives - liabilities	Long-term assets		(910		)	Long-term liabilities		(832		)
Total derivatives			$	7,191				$	(16,212	)
	As of December 31, 2013
	Derivative Assets					Derivative Liabilities
	Balance Sheet Classification		Fair Value			Balance Sheet Classification		Fair Value
	($ in thousands)
Interest rate derivatives - liabilities	Current assets		$	—		Current liabilities		$	(6,210	)
Interest rate derivatives - liabilities	Long-term assets		—			Long-term liabilities		(2,885		)
Commodity derivatives - assets	Current assets		11,268			Current liabilities		1,730
Commodity derivatives - assets	Long-term assets		6,259			Long-term liabilities		1,488
Commodity derivatives - liabilities	Current assets		(2,106		)	Current liabilities		(6,543		)
Commodity derivatives - liabilities	Long-term assets		(798		)	Long-term liabilities		(2,451		)
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 unaudited condensed consolidated statement of operations:
Amount of Gain (Loss) Recognized in Income on Derivatives			Three Months Ended
			March 31,
			2014			2013
			($ in thousands)
Interest rate derivatives	Interest rate risk management losses, net		$	(290	)	$	(156	)
Commodity derivatives	Commodity risk management losses, net		(14,944		)	(17,908		)
Commodity derivatives - trading	Natural gas, natural gas liquids, oil, condensate and sulfur sales		(987		)	(1,150		)
	Total		$	(16,221	)	$	(19,214	)

Fair_Value_of_Financial_Instru

Fair Value of Financial Instruments	3 Months Ended
	Mar. 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 March 31, 2014, the Partnership recorded its interest rate swaps and commodity derivative instruments (see Note 10), which includes crude oil, natural gas and NGLs, at fair value. The Partnership reviews the classification of the inputs at the end of each period and classified the inputs to measure the fair value of its interest rate swaps, crude oil derivatives, NGL derivatives and natural gas derivatives as Level 2.
	The following tables disclose the fair value of the Partnership's derivative instruments as of March 31, 2014 and December 31, 2013:
		As of March 31, 2014
		Level 1		Level 2			Level 3		Netting (a)			Total
		($ in thousands)
	Assets:
	Crude oil derivatives	$	—	$	4,920		$	—	$	(2,282	)	$	2,638
	Natural gas derivatives	—		7,786			—		(3,233		)	4,553
	NGL derivatives	—		497			—		(497		)	—
	Total	$	—	$	13,203		$	—	$	(6,012	)	$	7,191
	Liabilities:
	Crude oil derivatives	$	—	$	(5,553	)	$	—	$	2,282		$	(3,271	)
	Natural gas derivatives	—		(8,712		)	—		3,233			(5,479		)
	NGL derivatives	—		(281		)	—		497			216
	Interest rate swaps	—		(7,678		)	—		—			(7,678		)
	Total	$	—	$	(22,224	)	$	—	$	6,012		$	(16,212	)
	____________________________
	(a)	Represents counterparty netting under the agreement governing such derivative contracts.
		As of December 31, 2013
		Level 1		Level 2			Level 3		Netting (a)			Total
		($ in thousands)
	Assets:
	Crude oil derivatives	$	—	$	9,804		$	—	$	(2,003	)	$	7,801
	Natural gas derivatives	—		10,899			—		(4,077		)	6,822
	NGL derivatives	—		42			—		(42		)	—
	Total	$	—	$	20,745		$	—	$	(6,122	)	$	14,623
	Liabilities:
	Crude oil derivatives	$	—	$	(3,930	)	$	—	$	2,003		$	(1,927	)
	Natural gas derivatives	—		(6,847		)	—		4,077			(2,770		)
	NGL derivatives	—		(1,121		)	—		42			(1,079		)
	Interest rate swaps	—		(9,095		)	—		—			(9,095		)
	Total	$	—	$	(20,993	)	$	—	$	6,122		$	(14,871	)
	____________________________
	(a)	Represents counterparty netting under the agreement governing such derivative contracts.
	Gains and losses related to the interest rate derivatives are recorded as part of interest rate risk management gains and losses in the unaudited condensed consolidated statements of operations.  Gains and losses related to the Partnership's commodity derivatives are recorded as a component of revenue in the unaudited condensed consolidated statements of operations.
	Fair Value of Assets and Liabilities Measured on a Non-recurring Basis
	For periods in which impairment charges have been incurred, the Partnership is required to write down the value of the impaired asset to its fair value. See Note 4 and 6 for a further discussion of the impairment charges recorded during the three months ended March 31, 2014. The following table discloses the fair value of the Partnership's assets measured at fair value on a nonrecurring basis during the three months ended March 31, 2014:
		Three Months Ended
		March 31,
		2014		Level 1			Level 2		Level 3			Total Losses
		($ in thousands)
	Plant assets	$	52	$	—		$	—	$	52		$	132
	Pipeline assets	$	746	$	—		$	—	$	746		$	1,904
	Rights-of-way	$	24	$	—		$	—	$	24		$	61
	The Partnership calculated the fair value of the impaired assets using a discounted cash flow analysis to determine the excess of the asset's carrying value over its fair value. Significant inputs to the valuation of fair value of the plant, pipeline and intangible assets includes estimates of (i) future cash flows, including revenue, expenses and capital expenditures, (ii) timing of cash flows, (iii) forward commodity prices, adjusted for estimate location differentials and (iv) a discount rate reflective of our cost of capital.
	The carrying 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 March 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 bears interest at a fixed rate; based on the market price of the Senior Notes as of March 31, 2014 and December 31, 2013, the Partnership estimates that the fair value of the Senior Notes was $597.4 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	3 Months Ended
	Mar. 31, 2014
Commitments and Contingencies Disclosure [Abstract]	'
Commitments and Contingencies	'
	COMMITMENTS AND CONTINGENCIES
	Litigation—The Partnership is subject to lawsuits which arise from time to time in the ordinary course of business, such as the interpretation and application of contractual terms related to the calculation of payment for liquids and natural gas proceeds. The Partnership had no accruals as of March 31, 2014 or December 31, 2013 related to legal matters, and current lawsuits are not expected to have a material adverse effect on the Partnership's financial position, results of operations or cash flows. The Partnership has been indemnified up to a certain dollar amount for two lawsuits. If there ultimately is a finding against the Partnership in these two indemnified cases, the Partnership would expect to make a claim for indemnification up to the contractual limits.
	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. The lawsuits name the Partnership, its Board of Directors, Regency Energy Partners, L.P. (“Regency”), and Regal Midstream LLC as defendants. One of the lawsuits also names the Partnership's general partner and its general partner’s general partner as defendants. Plaintiffs in each lawsuit allege a variety of causes of action challenging Regency’s acquisition of the Partnership's midstream assets, 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 lawsuits allege that the Partnership (i) sold its midstream assets for inadequate value, (ii) engaged in an unfair sales process, (iii) agreed to contractual terms (the no-solicitation, fiduciary out, superior proposal, and termination fee provisions and the voting and support agreement) that would dissuade other potential acquirors from seeking to purchase the midstream assets, and (iv) failed to disclose material information in its definitive proxy statement concerning the analysis of our financial advisors, potential conflicts of the advisors (and directors), management’s financial projections, strategic alternatives, other potential acquirors, the bases for certain actions, and the background of the transaction. Based on these allegations, the plaintiffs seek in each case to enjoin the Partnership from proceeding with or consummating the sale of its midstream assets. To the extent that the sale is consummated before injunctive relief is granted, the plaintiffs seek to have the sale rescinded. The plaintiffs also seek monetary damages and attorneys’ fees. The Partnership believe that the lawsuits are without merit.
	The Partnership is the defendant in a lawsuit filed by a plaintiff who is alleging an entitlement to participate in various wells drilled by the Partnership in a defined area of land. The Partnership is disputing this claim, and believes the lawsuit is without merit. Because it is early in the course of proceedings, the Partnership believes that an estimate of the reasonably possible loss, or range of possible losses, if any, associated with this lawsuit cannot be made at this point.
	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 in the Upstream Segment; 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.
	Environmental—The operation of pipelines, plants and other facilities for gathering, transporting, processing, treating, or storing natural gas, NGLs and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of these facilities, 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 planning, designing, constructing and operating pipelines, plants, and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements and the issuance of injunctions or restrictions on operation. Management believes that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on the Partnership's combined results of operations, financial position or cash flows. At March 31, 2014 and December 31, 2013, the Partnership had accrued approximately $3.1 million and $3.2 million for environmental matters, respectively.
	Retained Revenue Interest—Certain assets of the Partnership's Upstream Segment are subject to retained revenue interests.  These interests were established under purchase and sale agreements that were executed by the Partnership's predecessors in title.  The terms of these agreements entitle the owners of the retained revenue interests to a portion of the revenues received from the sale of the hydrocarbons above specified base oil and natural gas prices.  These retained revenue interests do not represent a real property interest in the hydrocarbons.  The Partnership's reported revenues are reduced to account for the retained revenue interests on a monthly basis.
	The retained revenue interests affect the Partnership's interest in the Big Escambia Creek, Flomaton and Fanny Church fields in Escambia County, Alabama. With respect to the Partnership's Flomaton and Fanny Church fields, these retained revenue interests are in effect for any calendar year in which the Partnership surpasses certain average net production rates. The Partnership did not surpass such rates in 2013 and does not anticipate doing so in 2014. 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, including leases with no continuing commitment, amounted to approximately $2.9 million and $2.1 million for the three months ended March 31, 2014 and 2013, respectively. Rental expense for leases with escalation clauses is recognized on a straight-line basis over the initial lease term.

Segments

Segments	3 Months Ended
	Mar. 31, 2014
Segment Reporting [Abstract]	'
Segments	'
	SEGMENTS
	Based on the Partnership’s approach to managing its assets, the Partnership believes its operations consist of three segments in its Midstream Business, one Upstream Segment and one Corporate and Other Segment:
	(i)    Midstream—Texas Panhandle Segment: gathering, compressing, treating, processing and transporting natural gas; fractionating, transporting and marketing NGLs;
	(ii)    Midstream—East Texas and Other Midstream Segment: gathering, compressing, processing and treating natural gas and marketing of natural gas, NGLs and condensate in South Texas, East Texas, Louisiana, Gulf of Mexico and inland waters of Texas;
	(iii)    Midstream—Marketing and Trading Segment: crude oil and condensate logistics and marketing in the Texas Panhandle; and natural gas marketing and trading;
	(iv)    Upstream Segment: crude oil, condensate, natural gas, NGLs and sulfur production from operated and non-operated wells; and
	(v)    Corporate and Other Segment: risk management, intersegment eliminations and other corporate activities such as general and administrative expenses.
	The Partnership's chief operating decision maker ("CODM") currently reviews its operations using these segments. The CODM evaluates segment performance based on segment operating income or loss from continuing operations. Summarized financial information concerning the Partnership's reportable segments is shown in the following tables:
	Three Months Ended March 31, 2014		Texas		East Texas and Other			Marketing			Total			Upstream		Corporate				Total
			Panhandle		Midstream			and Trading Segment			Midstream			Segment		and Other Segment				Segments
			Segment		Segment						Business
	($ in thousands)
	Sales to external customers		$	159,835	$	46,473		$	104,422		$	310,730		$	52,288	$	(14,944	)	(a)	$	348,074
	Intersegment sales		72,959		17,861			(93,772		)	(2,952		)	2,948		4				—
	Cost of natural gas and natural gas liquids		189,904		55,069			—			244,973			—		—				244,973
	Intersegment cost of natural gas, oil and condensate		63		—			681			744			—		(744		)		—
	Operating costs and other expenses		20,317		4,724			8			25,049			15,289		21,391				61,729
	Depreciation, depletion and amortization		15,626		4,334			119			20,079			19,725		704				40,508
	Impairment		—		2,097			—			2,097			—		—				2,097
	Operating income (loss)		$	6,884	$	(1,890	)	$	9,842		$	14,836		$	20,222	$	(36,291	)		$	(1,233	)
	Capital Expenditures		$	8,363	$	1,851		$	3		$	10,217		$	39,258	$	1,577			$	51,052
	Segment Assets		$	949,909	$	244,014		$	73,398		$	1,267,321		$	872,604	$	15,393		(b)	$	2,155,318
	Three Months Ended March 31, 2013		Texas		East Texas and Other			Marketing			Total			Upstream		Corporate				Total
			Panhandle		Midstream			and Trading Segment			Midstream			Segment		and Other Segment				Segments
			Segment		Segment						Business
	($ in thousands)
	Sales to external customers		$	118,915	$	35,746		$	86,776		$	241,437		$	34,202	$	(17,908	)	(a)	$	257,731
	Intersegment sales		49,135		8,538			(59,468		)	(1,795		)	13,100		(11,305		)		—
	Cost of natural gas and natural gas liquids		132,226		33,234			14,528			179,988			—		—				179,988
	Intersegment cost of natural gas, oil and condensate		19		—			11,093			11,112			—		(11,112		)		—
	Operating costs and other expenses		17,134		4,829			6			21,969			14,116		18,847				54,932
	Depreciation, depletion and amortization		13,845		5,002			84			18,931			20,929		377				40,237
	Operating income (loss)		$	4,826	$	1,219		$	1,597		$	7,642		$	12,257	$	(37,325	)		$	(17,426	)
	Capital Expenditures		$	18,303	$	1,776		$	154		$	20,233		$	34,050	$	1,667			$	55,950
	Segment Assets		$	924,894	$	246,458		$	55,331		$	1,226,683		$	1,030,091	$	43,837		(b)	$	2,300,611
	______________________________
	(a)	Represents results of the Partnership's commodity risk management activity, excluding activity associated with its natural gas marketing and trading activities.
	(b)	Includes elimination of intersegment transactions.

Income_Taxes

Income Taxes	3 Months Ended
	Mar. 31, 2014
Income Tax Disclosure [Abstract]	'
Income Taxes	'
	INCOME TAXES
	Provision for 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. and Eagle Rock Energy Acquisition Co. II, Inc. and their wholly-owned subsidiary corporations, Eagle Rock Upstream Development Company, Inc. and Eagle Rock Upstream Development Company II, Inc., all of which are subject to federal income taxes.
	Effective Rate - The effective rate for the three months ended March 31, 2014 was 4.9% compared to 3.3% for the three months ended March 31, 2013. Due to the fact that the effective rate is a ratio of total tax expense to pre-tax book net income, the change in tax benefit is due primarily to book and tax temporary differences for the three months ended March 31, 2014 as compared to the three months ended March 31, 2013.

Equity_Based_Compensation

Equity Based Compensation	3 Months Ended
	Mar. 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, the "LTIP"), for its employees, directors and consultants who provide services to the Partnership and its subsidiaries and affiliates. The LTIP provides for the issuance of an aggregate of up to 7,000,000 common units to be granted either as options, restricted units or phantom units, of which, as of March 31, 2014, a total of 903,218 common units remained available for issuance. Grants under the LTIP are made at the discretion of the board and to date have only been made in the form of restricted units. 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. No options or phantom units have been issued to date.
	Grants of restricted units eligible to receive distributions are valued at the market price as of the date issued, while grants of restricted units not eligible to receive distributions are valued at the market price as of the date issued less the present value of the expected distribution stream over the vesting period using the risk-free interest rate. The awards generally vest over three years on the basis of one-third of the award 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 granted awards are distributed to the awardees.
	A summary of the changes in outstanding restricted common units for the three months ended March 31, 2014 is provided below:
		Number of		Weighted
		Restricted		Average
		Units		Fair Value
	Outstanding at December 31, 2013	2,743,807		$	9.37
	Granted	50,500		$	5.52
	Forfeited	(39,924	)	$	9.85
	Outstanding at March 31, 2014	2,754,383		$	9.3
	For the three months ended March 31, 2014 and 2013, non-cash compensation expense of approximately $3.3 million and $2.6 million, respectively, was recorded related to the granted restricted units as general and administrative expense on the unaudited condensed consolidated statements of operations.
	As of March 31, 2014, unrecognized compensation costs related to the outstanding restricted units under the LTIP totaled approximately $14.1 million. The remaining expense is to be recognized over a weighted average of 1.50.

Earnings_Per_Unit

Earnings Per Unit	3 Months Ended
	Mar. 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 March 31, 2014 and 2013, the Partnership had unvested restricted common units outstanding, which are considered dilutive securities. These units are considered in the diluted weighted average common units outstanding number in periods of net income. In periods of net losses, these units are excluded from the diluted weighted average common units outstanding number.
	The majority of the restricted units granted under the LTIP, as discussed in Note 15, contain non-forfeitable rights to the distributions declared by the Partnership and therefore meet the definition of participating securities. Participating securities are required to be included in the computation of earnings per unit pursuant to the two-class method. Restricted units granted in 2013 to certain senior executives and members of the board of directors are not eligible to receive the distributions declared by the Partnership and therefore do not meet the definition of participating securities.
	The following table presents the Partnership's calculation of basic and diluted units outstanding for the periods indicated:
			Three Months Ended
			March 31,
			2014			2013
		(in thousands)
	Weighted average units outstanding during period:
	Common units - Basic and diluted		156,644			146,171
	Due to the distribution being suspended until after the closing of the Midstream Business Contribution (see Notes 1 and 18) and the Partnership generating a net loss during the period, earnings per unit for the three months ended March 31, 2014 was only calculated for the common units as the net loss was only allocated to the common units.
	The following table presents the Partnership's basic and diluted income per unit for the three months ended March 31, 2014:
			Total				Common Units			Restricted Common Units*
			($ in thousands, except for per unit amounts)
	Net loss		$	(18,563	)
	Distributions **		—				$	—		$	—
	Assumed net loss after distribution to be allocated		(18,563		)		(18,563		)	—
	Net loss to be allocated		$	(18,563	)		$	(18,563	)	$	—
	Basic and diluted loss per unit						$	(0.12	)
	_____________________________
	*	Restricted common units granted under the LTIP that contain non-forfeitable rights to the distributions declared by the Partnership.
	**	No distribution was declared or paid for this period as the distribution was suspended for this period in advance of the closing the Midstream Business Contribution.
	The following table presents the Partnership's basic and diluted income per unit for the three months ended March 31, 2013:
			Total				Common Units			Restricted Common Units
			($ in thousands, except for per unit amounts)
	Net loss		$	(33,514	)
	Distributions		34,694				$	34,106		$	588
	Assumed net loss after distribution to be allocated		(68,208		)		(68,208		)	—
	Net loss to be allocated		$	(33,514	)		$	(34,102	)	$	588
	Basic and diluted loss per unit						$	(0.23	)

Subsidiary_Guarantors

Subsidiary Guarantors	3 Months Ended
	Mar. 31, 2014
SUBSIDIARY GUARANTORS [Abstract]	'
Subsidiary Guarantors	'
	SUBSIDIARY GUARANTORS
	The Partnership has issued registered debt securities guaranteed by its subsidiaries.  As of March 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 may be released in the following customary circumstances:
	•	in connection with any sale or other disposition of all or substantially all of the properties or assets of that guarantor (including by way of merger or consolidation) to a person that is not (either before or after giving effect to such transaction) an issuer or a restricted subsidiary of 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 SEC Regulation S-X, the Partnership has prepared Unaudited Condensed Consolidating Financial Statements as supplemental information.  The following unaudited condensed consolidating balance sheets at March 31, 2014 and December 31, 2013, and unaudited condensed consolidating statements of operations for the three months ended March 31, 2014 and 2013, and unaudited condensed consolidating statements of cash flows for the three months ended March 31, 2014 and 2013, 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.
	Unaudited Condensed Consolidating Balance Sheet
	March 31, 2014
		Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-Guarantor Investments			Consolidating			Total
													Entries
		($ in thousands)
	ASSETS:
	Accounts receivable – related parties	$	663,758		$	—	$	—		$	—		$	(663,758	)	$	—
	Other current assets	8,290			1		181,525			—			—			189,816
	Total property, plant and equipment, net	2,601			—		1,836,324			—			—			1,838,925
	Investment in subsidiaries	1,151,844			—		—			894			(1,152,738		)	—
	Total other long-term assets	16,193			—		110,384			—			—			126,577
	Total assets	$	1,842,686		$	1	$	2,128,233		$	894		$	(1,816,496	)	$	2,155,318
	LIABILITIES AND EQUITY:
	Accounts payable – related parties	$	—		$	—	$	663,758		$	—		$	(663,758	)	$	—
	Other current liabilities	31,281			—		229,188			—			—			260,469
	Other long-term liabilities	7,125			—		83,444			—			—			90,569
	Long-term debt	1,269,433			—		—			—			—			1,269,433
	Equity	534,847			1		1,151,843			894			(1,152,738		)	534,847
	Total liabilities and equity	$	1,842,686		$	1	$	2,128,233		$	894		$	(1,816,496	)	$	2,155,318
	Unaudited 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	)	$	—
	Other current assets	5,868			1		157,515			—			—			163,384
	Total property, plant and equipment, net	2,318			—		1,826,450			—			—			1,828,768
	Investment in subsidiaries	1,133,217			—		—			908			(1,134,125		)	—
	Total other long-term assets	19,833			—		115,565			—			—			135,398
	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	)	$	—
	Other current liabilities	17,390			—		193,876			—			—			211,266
	Other long-term liabilities	9,493			—		80,850			—			—			90,343
	Long-term debt	1,252,062			—		—			—			—			1,252,062
	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
	Unaudited Condensed Consolidating Statement of Operations
	For the Three Months Ended March 31, 2014
		Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-Guarantor Investments			Consolidating			Total
													Entries
		($ in thousands)
	Total revenues	$	(13,520	)	$	—	$	361,594		$	—		$	—		$	348,074
	Cost of natural gas and natural gas liquids	—			—		244,973			—			—			244,973
	Operations and maintenance	—			—		34,671			—			—			34,671
	Taxes other than income	—			—		5,667			—			—			5,667
	General and administrative	6,411			—		14,980			—			—			21,391
	Depreciation, depletion and amortization	53			—		40,455			—			—			40,508
	Impairment	—			—		2,097			—			—			2,097
	(Loss) income from operations	(19,984		)	—		18,751			—			—			(1,233		)
	Interest expense, net	(17,985		)	—		(1		)	—			—			(17,986		)
	Other non-operating income	2,221			—		2,301			—			(4,522		)	—
Other non-operating expense	(1,716		)	—		(3,096		)	(7		)	4,522			(297		)
(Loss) income before income taxes	(37,464		)	—		17,955			(7		)	—			(19,516		)
Income tax benefit	(267		)	—		(686		)	—			—			(953		)
Equity in earnings of subsidiaries	18,634			—		—			—			(18,634		)	—
Net (loss) income	$	(18,563	)	$	—	$	18,641		$	(7	)	$	(18,634	)	$	(18,563	)
Unaudited Condensed Consolidating Statement of Operations
For the Three Months Ended March 31, 2013
	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-Guarantor Investments			Consolidating Entries			Total
	($ in thousands)
Total revenues	$	(4,522	)	$	—	$	262,253		$	—		$	—		$	257,731
Cost of natural gas and natural gas liquids	—			—		179,988			—			—			179,988
Operations and maintenance	—			—		32,219			—			—			32,219
Taxes other than income	—			—		3,866			—			—			3,866
General and administrative	3,012			—		15,835			—			—			18,847
Depreciation, depletion and amortization	47			—		40,190			—			—			40,237
Loss from operations	(7,581		)	—		(9,845		)	—			—			(17,426		)
Interest expense, net	(16,304		)	—		(780		)	—			—			(17,084		)
Other non-operating income	2,281			—		2,334			—			(4,615		)	—
Other non-operating expense	(1,616		)	—		(3,158		)	(5		)	4,615			(164		)
Loss before income taxes	(23,220		)	—		(11,449		)	(5		)	—			(34,674		)
Income tax benefit	(575		)	—		(585		)	—			—			(1,160		)
Equity in earnings of subsidiaries	(10,869		)	—		—			—			10,869			—
Net loss	$	(33,514	)	$	—	$	(10,864	)	$	(5	)	$	10,869		$	(33,514	)
Unaudited Condensed Consolidating Statement of Cash Flows
For the Three Months Ended March 31, 2014
	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-Guarantor Investments			Consolidating Entries			Total
	($ in thousands)
Net cash flows provided by operating activities	$	13,139		$	—	$	55,398		$	16		$	—		$	68,553
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment	(336		)	—		(53,602		)	—			—			(53,938		)
Purchase of intangible assets	—			—		(554		)	—			—			(554		)
Net cash flows used in investing activities	(336		)	—		(54,156		)	—			—			(54,492		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	144,250			—		—			—			—			144,250
Repayment of long-term debt	(127,050		)	—		—			—			—			(127,050		)
Proceed from senior notes	(205		)	—		—			—			—			(205		)
Proceeds from derivative contracts	(1,708		)	—		—			—			—			(1,708		)
Distributions to members and affiliates	(23,801		)	—		—			—			—			(23,801		)
Net cash flows used in financing activities	(8,514		)	—		—			—			—			(8,514		)
Net increase (decrease) in cash and cash equivalents	4,289			—		1,242			16			—			5,547
Cash and cash equivalents at beginning of period	1,237			1		(1,389		)	227			—			76
Cash and cash equivalents at end of period	$	5,526		$	1	$	(147	)	$	243		$	—		$	5,623
Unaudited Condensed Consolidating Statement of Cash Flows
For the Three Months Ended March 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	$	(31,952	)	$	—	$	72,785		$	9		$	—		$	40,842
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment	(54		)	—		(70,083		)	—			—			(70,137		)
Purchase of intangible assets	—			—		(1,006		)	—			—			(1,006		)
Net cash flows used in investing activities	(54		)	—		(71,089		)	—			—			(71,143		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	171,300			—		—			—			—			171,300
Repayment of long-term debt	(202,000		)	—		—			—			—			(202,000		)
Proceeds from derivative contracts	1,044			—		—			—			—			1,044
Common unit issued in equity offerings	96,359			—		—			—			—			96,359
Issuance costs for equity offerings	(3,948		)	—		—			—			—			(3,948		)
Distributions to members and affiliates	(32,419		)	—		—			—			—			(32,419		)
Net cash flows provided by financing activities	30,336			—		—			—			—			30,336
Net (decrease) increase in cash and cash equivalents	(1,670		)	—		1,696			9			—			35
Cash and cash equivalents at beginning of period	1,670			1		(1,832		)	186			—			25
Cash and cash equivalents at end of period	$	—		$	1	$	(136	)	$	195		$	—		$	60

Subsequent_Events

Subsequent Events	3 Months Ended
	Mar. 31, 2014
Subsequent Events [Abstract]	'
Subsequent Events [Text Block]	'
	SUBSEQUENT EVENTS
	Contribution of Midstream Business to Regency
	On April 29, 2014, the Partnership conducted a special meeting of its common unitholders in which the unitholders approved the transaction to contribute the Midstream Business to Regency. The transaction remains subject to regulatory approval. On February 27, 2014, the Partnership and Regency received a Request for Additional Information and Documentary Materials ("Second Request") from the FTC in connection with the Midstream Business Contribution. On April 30, 2014, the Partnership and Regency certified their substantial compliance with the FTC's Second Request, and Eagle Rock and Regency have agreed with the FTC not to close the proposed transaction before June 30, 2014, unless the FTC first closes its investigation.
	As the sale of the Midstream Business at March 31, 2014 remained conditioned upon, among other things, the approval of the Partnership's common unitholders (see above) and the expiration or termination of all applicable waiting periods under the Hart-Scott-Rodino Antitrust Improvement Act of 1976, as amended, the Partnership has not classified the assets of its Midstream Business as assets-held-for-sale or the operations as discontinued.
	If the Partnership had met the criteria for assets-held-for-sale as of March 31, 2014, it would have presented the following (in thousands):
	Assets-Held-For-Sale:
	Property, plant and equipment, net	$	993,973
	Accounts receivable	136,966
	Intangible assets, net	100,930
	Other assets	17,103
	Total assets-held-for-sale	$	1,248,972
	Liabilities-held-for-sale
	Long-term debt	$	545,433
	Accounts payable	151,181
	Other liabilities	19,123
	Total liabilities-held-for-sale	$	715,737

Summary_of_Significant_Account1

Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Policies)	3 Months Ended
	Mar. 31, 2014
Accounting Policies [Abstract]	'
Basis of Accounting [Text Block]	'
	Basis of Presentation and Principles of Consolidation—The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP"). These unaudited condensed consolidated financial statements should be read in conjunction with the consolidated financial statements presented in the Partnership's Annual Report on Form 10-K for the year ended December 31, 2013. In the opinion of management, the accompanying unaudited condensed consolidated financial statements contain all appropriate adjustments, all of which are normally recurring adjustments unless otherwise noted, considered necessary to present fairly the financial position of the Partnership and its consolidated subsidiaries and the results of operations and cash flows for the respective periods. Operating results for the three months ended March 31, 2014 are not necessarily indicative of the results that may be expected for the full year ending December 31, 2014.
	Eagle Rock Energy is the owner of non-operating undivided interests in certain gas processing plants and gas gathering systems. Eagle Rock Energy owns these interests as tenants-in-common with the majority owner-operator of the facilities. Accordingly, Eagle Rock Energy includes its pro-rata share of assets, liabilities, revenues and expenses related to these assets in its financial statements. All intercompany accounts and transactions are eliminated in the unaudited condensed consolidated financial statements.
	The Partnership has provided a discussion of significant accounting policies in its Annual Report on Form 10-K for the year ended December 31, 2013. Certain items from that discussion are repeated or updated below as necessary to assist in the understanding of these financial statements.
Use of Estimates, Policy [Policy Text Block]	'
	Use of Estimates—The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reported period. Significant estimates are required for proved oil and natural gas reserves, which can affect the carrying value of oil and natural gas properties. The Partnership evaluates its estimates and assumptions on a regular basis. The Partnership bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results could differ from those estimates and such differences could be material.
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 March 31, 2014 and December 31, 2013, the Partnership had $0.3 million and $1.0 million, respectively, of crude oil finished goods inventory, which is recorded as part of Other Current Assets within the unaudited condensed consolidated balance sheet.
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, accounted for utilizing the successful efforts method, the Partnership reviews its proved properties at the depletion unit 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 to the proved reserves estimates, unfavorable projections of future prices, the timing of future production and estimates of future costs to produce the oil and natural gas. Unproved properties (both individually significant and insignificant) are assessed periodically within specific geographic areas and, if necessary, impairments are charged to expense.
	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 Notes 4 and 6 for further discussion on impairment charges.
Revenue Recognition, Policy [Policy Text Block]	'
	Revenue Recognition—The Partnership's primary types of sales and service activities reported as operating revenue include:
	•	sales of natural gas, NGLs, crude oil, condensate, sulfur and helium;
	•	natural gas gathering, processing and transportation, from which the Partnership generates revenues primarily through the compression, gathering, treating, processing and transportation of natural gas; and
	•	NGL transportation from which the Partnership generates revenues from transportation fees.
	Revenues associated with sales of natural gas, NGLs, crude oil, condensate, sulfur and helium are recognized when title passes to the customer, which is when the risk of ownership passes to the customer and physical delivery occurs. Revenues associated with transportation and processing fees are recognized in the period when the services are provided.
	For gathering and processing services, the Partnership either receives fees or commodities from natural gas producers under various types of contracts including percentage-of-proceeds, fixed recovery and percent-of-index arrangements. The Partnership also recognizes fee-based service revenues for services such as transportation, compression and processing.
Sales Method or Entitlements Method, Policy [Policy Text Block]	'
	The Partnership's Upstream Segment recognizes natural gas revenues 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. Material imbalances are reflected as adjustments to reported natural gas reserves and future cash flows.  For the Upstream Segment, the Partnership had long-term imbalance payables totaling $0.3 million and $0.3 million as of March 31, 2014 and December 31, 2013, respectively.
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 unaudited condensed consolidated balance sheets and marked-to-market using current market prices in effect for the reporting period of the outstanding imbalances. For the Midstream Business, as of March 31, 2014, the Partnership had imbalance receivables totaling $1.8 million and imbalance payables totaling $0.6 million. For the Midstream Business, as of December 31, 2013, the Partnership had imbalance receivables totaling $0.7 million and imbalance payables totaling $1.6 million. 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.
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, with the exception of certain contracts with it's natural gas trading and marketing business. The Partnership uses financial instruments such as swaps, collars and other derivatives to mitigate the risks to cash flows resulting from changes in commodity prices and interest rates. The Partnership recognizes these financial instruments on its unaudited condensed consolidated balance sheet at the instrument's fair value with changes in fair value reflected in the unaudited condensed consolidated statement of operations, as the Partnership has not designated any of these derivative instruments as hedges. The cash flows from derivatives are reported as cash flows from operating activities unless the derivative contract is deemed to contain a financing element. Derivatives deemed to contain a financing element are reported as a financing activity in the unaudited condensed consolidated statement of cash flows. See Note 10 for a description of the Partnership's risk management activities.
Reclassification, Policy [Policy Text Block]	'
	Other Reclassifications—The prior period within the unaudited condensed consolidated statements of cash flows has been reclassified to conform to current period presentation. Amounts have been reclassified to new rows titled “Loss from risk management activities, net” that combines settled and mark-to-market gains/losses on derivative instruments and “Derivative settlements” that includes cash attributable to derivative instruments that settled during the periods. The revisions to the cash flow presentation had no impact on “Net cash provided by operating activities.”
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 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 convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of (i) remediation costs, (ii) remaining lives, (iii) future inflation factors and (iv) a credit-adjusted risk free interest rate.
Intangible Assets, Finite-Lived, Policy [Policy Text Block]	'
	Intangible assets consist of rights-of-way and easements and acquired customer contracts, which the Partnership amortizes over the term of the agreement or estimated useful life. The amortization period for the Partnership's rights-of-way and easements is 20 years. The amortization periods for contracts range from 5 to 20 years.
Earnings Per Share, Policy [Policy Text Block]	'
	Basic earnings per unit is computed by dividing the net income (loss) by the weighted average number of units outstanding during a period. To determine net income (loss) allocated to each class of ownership (common and restricted common units), the Partnership first allocates net income (loss) in accordance with the amount of distributions made for the quarter by each class, if any. The remaining net income is allocated to each class in proportion to the class weighted average number of units outstanding for a period, as compared to the weighted average number of units for all classes for the period, with the exception of net losses. Net losses are allocated to just the common units.
	As of March 31, 2014 and 2013, the Partnership had unvested restricted common units outstanding, which are considered dilutive securities. These units are considered in the diluted weighted average common units outstanding number in periods of net income. In periods of net losses, these units are excluded from the diluted weighted average common units outstanding number.
	The majority of the restricted units granted under the LTIP, as discussed in Note 15, 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.

Property_Plant_and_Equipment_P

Property, Plant and Equipment Property, Plant and Equipment (Tables)	3 Months Ended
	Mar. 31, 2014
Property, Plant and Equipment [Abstract]	'
Property, Plant and Equipment [Table Text Block]	'
	Fixed assets consisted of the following:
		March 31,			December 31,
		2014			2013
		($ in thousands)
	Land	$	2,877		$	2,877
	Plant	519,392			521,103
	Gathering and pipeline	782,577			777,446
	Equipment and machinery	58,153			53,999
	Vehicles and transportation equipment	4,017			4,001
	Office equipment, furniture, and fixtures	1,328			1,309
	Computer equipment	17,117			14,806
	Linefill	5,142			5,180
	Proved properties	1,195,188			1,156,896
	Unproved properties	10,276			10,022
	Construction in progress	25,457			33,824
		2,621,524			2,581,463
	Less: accumulated depreciation, depletion and amortization	(782,599		)	(752,695		)
	Net property, plant and equipment	$	1,838,925		$	1,828,768
	The following table sets forth the total depreciation, depletion, capitalized interest costs and impairment expense by type of asset within the Partnership's unaudited condensed consolidated statements of operations:
			Three Months Ended
			March 31,
			2014			2013
		($ in thousands)
	Depreciation		$	18,861		$	16,395
	Depletion		$	19,672		$	20,871
	Capitalized interest costs		$	144		$	355
	Impairment expense:
	Plant assets (a)		$	132		$	—
	Pipeline assets (a)		$	1,904		$	—
	________________________________
	(a)	During the three months ended March 31, 2014, the Partnership incurred impairment charges in its Midstream Business related to certain plants and pipelines in its East Texas and Other Segment due to the loss of two customers.

Asset_Retirement_Obligations_A

Asset Retirement Obligations Asset Retirement Obligations (Tables)	3 Months Ended
	Mar. 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
		($ in thousands)
	Asset retirement obligations—January 1 (a)	$	58,964		$	48,755
	Additional liabilities	39			746
	Liabilities settled	(682		)	(570		)
	Revision to liabilities	(105		)	—
	Accretion expense	980			840
	Asset retirement obligations—March 31 (a)	$	59,196		$	49,771
	_____________________________________
	(a)	As of March 31, 2014 and December 31, 2013, $12.9 million and $13.1 million, respectively, were included within accrued liabilities in the Unaudited Condensed Consolidated Balance Sheets.
	During the three months ended March 31, 2014, the Partnership made revisions of $0.1 million to decrease certain asset retirement obligations due to changes in the estimated costs to remediate.

Intangible_Assets_Intangible_A

Intangible Assets Intangible Assets (Tables)	3 Months Ended
	Mar. 31, 2014
Goodwill and Intangible Assets Disclosure [Abstract]	'
Schedule of Finite-Lived Intangible Assets [Table Text Block]	'
	Intangible assets consisted of the following:
		March 31,			December 31,
		2014			2013
		($ in thousands)
	Rights-of-way and easements—at cost	$	131,580		$	131,088
	Less: accumulated amortization	(37,846		)	(36,228		)
	Contracts	22,742			22,742
	Less: accumulated amortization	(12,327		)	(11,982		)
	Net intangible assets	$	104,149		$	105,620
Schedule of Impaired Intangible Assets [Table Text Block]	'
	The following table sets forth amortization and impairment expense by type of intangible asset within the Partnership's unaudited condensed consolidated statements of operations:
			Three Months Ended
			March 31,
			2014			2013
		($ in thousands)
	Amortization		$	1,964		$	2,961
	Impairment expense:
	Rights-of-way (a)		$	61		$	—
	_____________________________________
	(a)	During the three months ended March 31, 2014, the Partnership incurred impairment charges in its Midstream Business related to certain rights-of-way in its East Texas and Other Segment due to the loss of two customers.
Schedule of Finite-Lived Intangible Assets, Future Amortization Expense [Table Text Block]	'
	Estimated future amortization expense related to the intangible assets at March 31, 2014, is as follows (in thousands):
	Year ending December 31,
	2014	$	5,936
	2015	$	7,914
	2016	$	7,913
	2017	$	7,912
	2018	$	7,911
	Thereafter	$	66,563

Long_Term_Debt_LongTerm_Debt_T

Long Term Debt Long-Term Debt (Tables)	3 Months Ended
	Mar. 31, 2014
Long-term Debt, by Current and Noncurrent [Abstract]	'
Schedule of Long-term Debt Instruments [Table Text Block]	'
	Long-term debt consisted of the following:
		March 31,				December 31,
		2014				2013
		($ in thousands)
	Revolving credit facility:	$	724,000			$	706,800
	Senior notes:
	8.375% Senior Notes due 2019	550,000				550,000
	Unamortized bond discount	(4,567		)		(4,738		)
	Total Senior Notes	545,433				545,262
	Total long-term debt	$	1,269,433			$	1,252,062
Schedule of Debt Covenants [Table Text Block]	'
	The following table presents the debt covenant levels specified in our revolving credit facility as of March 31, 2014:
	Quarter Ended	Total Leverage Ratio (a)	Senior Secured Leverage Ratio (a)	Interest Coverage Ratio (b)	Current Ratio (b)
	31-Mar-14	5.85	3.4	2.5	1
	30-Jun-14	5	3.05	2.5	1
	30-Sep-14	4.75	2.95	2.5	1
	Thereafter	4.5	N/A	2.5	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 the Partnership's actual covenant ratios as of March 31, 2014:
	Interest coverage ratio	3.1
	Total leverage ratio	5.4
	Senior secured leverage ratio	3.06
	Current ratio	1.1

Members_Equity_Members_Equity_

Members' Equity Members' Equity (Tables)	3 Months Ended
	Mar. 31, 2014
Distributions Made to Members or Limited Partners [Abstract]	'
Distributions Made to Limited Partners, by Distribution [Table Text Block]	'
	The table below summarizes the distributions paid or payable and declared for the three months ended March 31, 2014.
	Quarter Ended		Distribution		Record Date*	Payment Date
			per Common Unit
	December 31, 2013+*		$	0.15	February 7, 2014	February 14, 2014
	March 31, 2014**		$	—	N/A	N/A
	_____________________________
	+	The distribution excludes certain restricted unit grants.
	*	The "Record Date" set forth in the table above means the close of business on each of the listed Record Dates.

Related_Party_Transactions_Rel

Related Party Transactions Related Party Transactions (Tables)	3 Months Ended
	Mar. 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:
			Three Months Ended
			March 31,
			2014			2013
	Affiliates of Natural Gas Partners:	($ in thousands)
	Natural gas purchases from affiliates		$	1,142		$	123
		March 31, 2014			December 31, 2013
	Affiliates of Natural Gas Partners:	($ in thousands)
	Payable (related to natural gas purchases)	$	—		$	18

Risk_Management_Activities_Ris

Risk Management Activities Risk Management Activities (Tables)	3 Months Ended
	Mar. 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 interest rate swaps as of March 31, 2014:
	Effective Date		Expiration		Notional			Fixed
			Date		Amount			Rate
	6/22/11		6/22/15		$	250,000,000		2.95	%
Schedule of Price Risk Derivatives [Table Text Block]	'
	Commodity derivatives, as of March 31, 2014, that will mature during the years ended December 31, 2014, 2015 and 2016:
	Underlying		Type		Notional		Floor				Cap
					Volumes		Strike				Strike
					(units) (a)		Price				Price
							($/unit)(b)				($/unit)(b)
	Portion of Contracts Maturing in 2014
	Natural Gas		Swap (Pay Floating/Receive Fixed)		12,600,000		$	4.38
	Crude Oil		Costless Collar		180,000		$	90			$	106
	Crude Oil		Swap (Pay Floating/Receive Fixed)		1,650,000		$	96.51
	Crude Oil		Swap (Pay Fixed/Receive Floating)		218,676		92.54
	Propane		Swap (Pay Floating/Receive Fixed)		12,852,000		1.09
	IsoButane		Swap (Pay Floating/Receive Fixed)		1,701,000		1.31
	Normal Butane		Swap (Pay Floating/Receive Fixed)		3,099,600		1.3
	Contracts Maturing in 2015
	Natural Gas		Swap (Pay Floating/Receive Fixed)		12,000,000		$	4.1
	Crude Oil		Costless Collar		480,000		$	90			$	97.55
	Crude Oil		Swap (Pay Floating/Receive Fixed)		1,110,000		$	88.7
	Contracts Maturing in 2016
	Natural Gas		Swap (Pay Floating/Receive Fixed)		9,480,000		$	4.25
	Crude Oil		Swap (Pay Floating/Receive Fixed)		1,416,000		$	84.6
	_______________________
	(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 in $/MMbtu for natural gas, $/barrel for crude oil and $/gallon for natural gas liquids.
	Marketing and Trading commodity derivative instruments, as of March 31, 2014, that will mature during the year ended December 31, 2014 and beyond:
	Type		Notional Volumes (MMbtu)
	Portion of Contracts Maturing in 2014
	Index Swap - Purchases		1,950,000
	Index Swap - Sales		600,000
	Swap (Pay Fixed/ Receive Floating) - Purchases		750,000
	Swap (Pay Floating/ Receive Fixed) - Sales		3,525,000
	Forward purchase contract - index		9,315,450
	Forward sales contract - index		16,300,200
	Forward purchase contract - fixed price		3,747,000
	Forward sales contract - fixed price		1,575,000
	Basis Swaps - Purchases		8,155,000
	Basis Swaps - Sales		3,650,000
	Portion of Contracts Maturing in 2015 and beyond
	Basis Swaps - Purchases		13,280,000
	Basis Swaps - Sales		13,280,000
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block]	'
	The following tables set forth the fair values of interest rate and commodity derivative instruments not designated as hedging instruments and their location within the unaudited condensed consolidated balance sheet as of March 31, 2014 and December 31, 2013:
		As of March 31, 2014
		Derivative Assets					Derivative Liabilities
		Balance Sheet Classification		Fair Value			Balance Sheet Classification		Fair Value
		($ in thousands)
	Interest rate derivatives - liabilities	Current assets		$	—		Current liabilities		$	(6,310	)
	Interest rate derivatives - liabilities	Long-term assets		—			Long-term liabilities		(1,368		)
	Commodity derivatives - assets	Current assets		7,863			Current liabilities		1,657
	Commodity derivatives - assets	Long-term assets		2,361			Long-term liabilities		1,322
	Commodity derivatives - liabilities	Current assets		(2,123		)	Current liabilities		(10,681		)
	Commodity derivatives - liabilities	Long-term assets		(910		)	Long-term liabilities		(832		)
	Total derivatives			$	7,191				$	(16,212	)
		As of December 31, 2013
		Derivative Assets					Derivative Liabilities
		Balance Sheet Classification		Fair Value			Balance Sheet Classification		Fair Value
		($ in thousands)
	Interest rate derivatives - liabilities	Current assets		$	—		Current liabilities		$	(6,210	)
	Interest rate derivatives - liabilities	Long-term assets		—			Long-term liabilities		(2,885		)
	Commodity derivatives - assets	Current assets		11,268			Current liabilities		1,730
	Commodity derivatives - assets	Long-term assets		6,259			Long-term liabilities		1,488
	Commodity derivatives - liabilities	Current assets		(2,106		)	Current liabilities		(6,543		)
	Commodity derivatives - liabilities	Long-term assets		(798		)	Long-term liabilities		(2,451		)
	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 unaudited condensed consolidated statement of operations:
	Amount of Gain (Loss) Recognized in Income on Derivatives			Three Months Ended
				March 31,
				2014			2013
				($ in thousands)
	Interest rate derivatives	Interest rate risk management losses, net		$	(290	)	$	(156	)
	Commodity derivatives	Commodity risk management losses, net		(14,944		)	(17,908		)
	Commodity derivatives - trading	Natural gas, natural gas liquids, oil, condensate and sulfur sales		(987		)	(1,150		)
		Total		$	(16,221	)	$	(19,214	)

Fair_Value_of_Financial_Instru1

Fair Value of Financial Instruments Fair Value of Financial Instruments (Tables)	3 Months Ended
	Mar. 31, 2014
Fair Value Disclosures [Abstract]	'
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]	'
	The following tables disclose the fair value of the Partnership's derivative instruments as of March 31, 2014 and December 31, 2013:
		As of March 31, 2014
		Level 1		Level 2			Level 3		Netting (a)			Total
		($ in thousands)
	Assets:
	Crude oil derivatives	$	—	$	4,920		$	—	$	(2,282	)	$	2,638
	Natural gas derivatives	—		7,786			—		(3,233		)	4,553
	NGL derivatives	—		497			—		(497		)	—
	Total	$	—	$	13,203		$	—	$	(6,012	)	$	7,191
	Liabilities:
	Crude oil derivatives	$	—	$	(5,553	)	$	—	$	2,282		$	(3,271	)
	Natural gas derivatives	—		(8,712		)	—		3,233			(5,479		)
	NGL derivatives	—		(281		)	—		497			216
	Interest rate swaps	—		(7,678		)	—		—			(7,678		)
	Total	$	—	$	(22,224	)	$	—	$	6,012		$	(16,212	)
	____________________________
	(a)	Represents counterparty netting under the agreement governing such derivative contracts.
		As of December 31, 2013
		Level 1		Level 2			Level 3		Netting (a)			Total
		($ in thousands)
	Assets:
	Crude oil derivatives	$	—	$	9,804		$	—	$	(2,003	)	$	7,801
	Natural gas derivatives	—		10,899			—		(4,077		)	6,822
	NGL derivatives	—		42			—		(42		)	—
	Total	$	—	$	20,745		$	—	$	(6,122	)	$	14,623
	Liabilities:
	Crude oil derivatives	$	—	$	(3,930	)	$	—	$	2,003		$	(1,927	)
	Natural gas derivatives	—		(6,847		)	—		4,077			(2,770		)
	NGL derivatives	—		(1,121		)	—		42			(1,079		)
	Interest rate swaps	—		(9,095		)	—		—			(9,095		)
	Total	$	—	$	(20,993	)	$	—	$	6,122		$	(14,871	)
	____________________________
	(a)	Represents counterparty netting under the agreement governing such derivative contracts.
Fair Value Measurements, Nonrecurring [Table Text Block]	'
	The following table discloses the fair value of the Partnership's assets measured at fair value on a nonrecurring basis during the three months ended March 31, 2014:
		Three Months Ended
		March 31,
		2014		Level 1			Level 2		Level 3			Total Losses
		($ in thousands)
	Plant assets	$	52	$	—		$	—	$	52		$	132
	Pipeline assets	$	746	$	—		$	—	$	746		$	1,904
	Rights-of-way	$	24	$	—		$	—	$	24		$	61

Segments_Segments_Tables

Segments Segments (Tables)	3 Months Ended
	Mar. 31, 2014
Segment Reporting [Abstract]	'
Schedule of Segment Reporting Information, by Segment [Table Text Block]	'
	Summarized financial information concerning the Partnership's reportable segments is shown in the following tables:
	Three Months Ended March 31, 2014		Texas		East Texas and Other			Marketing			Total			Upstream		Corporate				Total
			Panhandle		Midstream			and Trading Segment			Midstream			Segment		and Other Segment				Segments
			Segment		Segment						Business
	($ in thousands)
	Sales to external customers		$	159,835	$	46,473		$	104,422		$	310,730		$	52,288	$	(14,944	)	(a)	$	348,074
	Intersegment sales		72,959		17,861			(93,772		)	(2,952		)	2,948		4				—
	Cost of natural gas and natural gas liquids		189,904		55,069			—			244,973			—		—				244,973
	Intersegment cost of natural gas, oil and condensate		63		—			681			744			—		(744		)		—
	Operating costs and other expenses		20,317		4,724			8			25,049			15,289		21,391				61,729
	Depreciation, depletion and amortization		15,626		4,334			119			20,079			19,725		704				40,508
	Impairment		—		2,097			—			2,097			—		—				2,097
	Operating income (loss)		$	6,884	$	(1,890	)	$	9,842		$	14,836		$	20,222	$	(36,291	)		$	(1,233	)
	Capital Expenditures		$	8,363	$	1,851		$	3		$	10,217		$	39,258	$	1,577			$	51,052
	Segment Assets		$	949,909	$	244,014		$	73,398		$	1,267,321		$	872,604	$	15,393		(b)	$	2,155,318
	Three Months Ended March 31, 2013		Texas		East Texas and Other			Marketing			Total			Upstream		Corporate				Total
			Panhandle		Midstream			and Trading Segment			Midstream			Segment		and Other Segment				Segments
			Segment		Segment						Business
	($ in thousands)
	Sales to external customers		$	118,915	$	35,746		$	86,776		$	241,437		$	34,202	$	(17,908	)	(a)	$	257,731
	Intersegment sales		49,135		8,538			(59,468		)	(1,795		)	13,100		(11,305		)		—
	Cost of natural gas and natural gas liquids		132,226		33,234			14,528			179,988			—		—				179,988
	Intersegment cost of natural gas, oil and condensate		19		—			11,093			11,112			—		(11,112		)		—
	Operating costs and other expenses		17,134		4,829			6			21,969			14,116		18,847				54,932
	Depreciation, depletion and amortization		13,845		5,002			84			18,931			20,929		377				40,237
	Operating income (loss)		$	4,826	$	1,219		$	1,597		$	7,642		$	12,257	$	(37,325	)		$	(17,426	)
	Capital Expenditures		$	18,303	$	1,776		$	154		$	20,233		$	34,050	$	1,667			$	55,950
	Segment Assets		$	924,894	$	246,458		$	55,331		$	1,226,683		$	1,030,091	$	43,837		(b)	$	2,300,611
	______________________________
	(a)	Represents results of the Partnership's commodity risk management activity, excluding activity associated with its natural gas marketing and trading activities.
	(b)	Includes elimination of intersegment transactions.

Equity_Based_Compensation_Equi

Equity Based Compensation Equity Based Compensation (Tables)	3 Months Ended
	Mar. 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 three months ended March 31, 2014 is provided below:
		Number of		Weighted
		Restricted		Average
		Units		Fair Value
	Outstanding at December 31, 2013	2,743,807		$	9.37
	Granted	50,500		$	5.52
	Forfeited	(39,924	)	$	9.85
	Outstanding at March 31, 2014	2,754,383		$	9.3

Earnings_Per_Unit_Earnings_Per

Earnings Per Unit Earnings Per Unit (Tables)	3 Months Ended
	Mar. 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:
			Three Months Ended
			March 31,
			2014			2013
		(in thousands)
	Weighted average units outstanding during period:
	Common units - Basic and diluted		156,644			146,171
Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]	'
	The following table presents the Partnership's basic and diluted income per unit for the three months ended March 31, 2014:
			Total				Common Units			Restricted Common Units*
			($ in thousands, except for per unit amounts)
	Net loss		$	(18,563	)
	Distributions **		—				$	—		$	—
	Assumed net loss after distribution to be allocated		(18,563		)		(18,563		)	—
	Net loss to be allocated		$	(18,563	)		$	(18,563	)	$	—
	Basic and diluted loss per unit						$	(0.12	)
	_____________________________
	*	Restricted common units granted under the LTIP that contain non-forfeitable rights to the distributions declared by the Partnership.
	**	No distribution was declared or paid for this period as the distribution was suspended for this period in advance of the closing the Midstream Business Contribution.
	The following table presents the Partnership's basic and diluted income per unit for the three months ended March 31, 2013:
			Total				Common Units			Restricted Common Units
			($ in thousands, except for per unit amounts)
	Net loss		$	(33,514	)
	Distributions		34,694				$	34,106		$	588
	Assumed net loss after distribution to be allocated		(68,208		)		(68,208		)	—
	Net loss to be allocated		$	(33,514	)		$	(34,102	)	$	588
	Basic and diluted loss per unit						$	(0.23	)

Subsidiary_Guarantors_Subsidia

Subsidiary Guarantors Subsidiary Guarantors (Tables)	3 Months Ended
	Mar. 31, 2014
SUBSIDIARY GUARANTORS [Abstract]	'
Subsidiary Guarantor Consolidating Balance Sheet [Table Text Block]	'
	Condensed Consolidating Balance Sheet
	March 31, 2014
		Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-Guarantor Investments			Consolidating			Total
													Entries
		($ in thousands)
	ASSETS:
	Accounts receivable – related parties	$	663,758		$	—	$	—		$	—		$	(663,758	)	$	—
	Other current assets	8,290			1		181,525			—			—			189,816
	Total property, plant and equipment, net	2,601			—		1,836,324			—			—			1,838,925
	Investment in subsidiaries	1,151,844			—		—			894			(1,152,738		)	—
	Total other long-term assets	16,193			—		110,384			—			—			126,577
	Total assets	$	1,842,686		$	1	$	2,128,233		$	894		$	(1,816,496	)	$	2,155,318
	LIABILITIES AND EQUITY:
	Accounts payable – related parties	$	—		$	—	$	663,758		$	—		$	(663,758	)	$	—
	Other current liabilities	31,281			—		229,188			—			—			260,469
	Other long-term liabilities	7,125			—		83,444			—			—			90,569
	Long-term debt	1,269,433			—		—			—			—			1,269,433
	Equity	534,847			1		1,151,843			894			(1,152,738		)	534,847
	Total liabilities and equity	$	1,842,686		$	1	$	2,128,233		$	894		$	(1,816,496	)	$	2,155,318
	Unaudited 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	)	$	—
	Other current assets	5,868			1		157,515			—			—			163,384
	Total property, plant and equipment, net	2,318			—		1,826,450			—			—			1,828,768
	Investment in subsidiaries	1,133,217			—		—			908			(1,134,125		)	—
	Total other long-term assets	19,833			—		115,565			—			—			135,398
	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	)	$	—
	Other current liabilities	17,390			—		193,876			—			—			211,266
	Other long-term liabilities	9,493			—		80,850			—			—			90,343
	Long-term debt	1,252,062			—		—			—			—			1,252,062
	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]	'
	Unaudited Condensed Consolidating Statement of Operations
	For the Three Months Ended March 31, 2014
		Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-Guarantor Investments			Consolidating			Total
													Entries
		($ in thousands)
	Total revenues	$	(13,520	)	$	—	$	361,594		$	—		$	—		$	348,074
	Cost of natural gas and natural gas liquids	—			—		244,973			—			—			244,973
	Operations and maintenance	—			—		34,671			—			—			34,671
	Taxes other than income	—			—		5,667			—			—			5,667
	General and administrative	6,411			—		14,980			—			—			21,391
	Depreciation, depletion and amortization	53			—		40,455			—			—			40,508
	Impairment	—			—		2,097			—			—			2,097
	(Loss) income from operations	(19,984		)	—		18,751			—			—			(1,233		)
	Interest expense, net	(17,985		)	—		(1		)	—			—			(17,986		)
	Other non-operating income	2,221			—		2,301			—			(4,522		)	—
	Other non-operating expense	(1,716		)	—		(3,096		)	(7		)	4,522			(297		)
	(Loss) income before income taxes	(37,464		)	—		17,955			(7		)	—			(19,516		)
	Income tax benefit	(267		)	—		(686		)	—			—			(953		)
	Equity in earnings of subsidiaries	18,634			—		—			—			(18,634		)	—
	Net (loss) income	$	(18,563	)	$	—	$	18,641		$	(7	)	$	(18,634	)	$	(18,563	)
	Unaudited Condensed Consolidating Statement of Operations
	For the Three Months Ended March 31, 2013
		Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-Guarantor Investments			Consolidating Entries			Total
		($ in thousands)
	Total revenues	$	(4,522	)	$	—	$	262,253		$	—		$	—		$	257,731
	Cost of natural gas and natural gas liquids	—			—		179,988			—			—			179,988
	Operations and maintenance	—			—		32,219			—			—			32,219
	Taxes other than income	—			—		3,866			—			—			3,866
	General and administrative	3,012			—		15,835			—			—			18,847
	Depreciation, depletion and amortization	47			—		40,190			—			—			40,237
	Loss from operations	(7,581		)	—		(9,845		)	—			—			(17,426		)
	Interest expense, net	(16,304		)	—		(780		)	—			—			(17,084		)
	Other non-operating income	2,281			—		2,334			—			(4,615		)	—
	Other non-operating expense	(1,616		)	—		(3,158		)	(5		)	4,615			(164		)
	Loss before income taxes	(23,220		)	—		(11,449		)	(5		)	—			(34,674		)
	Income tax benefit	(575		)	—		(585		)	—			—			(1,160		)
	Equity in earnings of subsidiaries	(10,869		)	—		—			—			10,869			—
	Net loss	$	(33,514	)	$	—	$	(10,864	)	$	(5	)	$	10,869		$	(33,514	)
Subsidiary Guarantor Consolidating Statements of Cash Flows [Table Text Block]	'
	Unaudited Condensed Consolidating Statement of Cash Flows
	For the Three Months Ended March 31, 2014
		Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-Guarantor Investments			Consolidating Entries			Total
		($ in thousands)
	Net cash flows provided by operating activities	$	13,139		$	—	$	55,398		$	16		$	—		$	68,553
	CASH FLOWS FROM INVESTING ACTIVITIES:
	Additions to property, plant and equipment	(336		)	—		(53,602		)	—			—			(53,938		)
	Purchase of intangible assets	—			—		(554		)	—			—			(554		)
	Net cash flows used in investing activities	(336		)	—		(54,156		)	—			—			(54,492		)
	CASH FLOWS FROM FINANCING ACTIVITIES:
	Proceeds from long-term debt	144,250			—		—			—			—			144,250
	Repayment of long-term debt	(127,050		)	—		—			—			—			(127,050		)
	Proceed from senior notes	(205		)	—		—			—			—			(205		)
	Proceeds from derivative contracts	(1,708		)	—		—			—			—			(1,708		)
	Distributions to members and affiliates	(23,801		)	—		—			—			—			(23,801		)
	Net cash flows used in financing activities	(8,514		)	—		—			—			—			(8,514		)
	Net increase (decrease) in cash and cash equivalents	4,289			—		1,242			16			—			5,547
	Cash and cash equivalents at beginning of period	1,237			1		(1,389		)	227			—			76
	Cash and cash equivalents at end of period	$	5,526		$	1	$	(147	)	$	243		$	—		$	5,623
	Unaudited Condensed Consolidating Statement of Cash Flows
	For the Three Months Ended March 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	$	(31,952	)	$	—	$	72,785		$	9		$	—		$	40,842
	CASH FLOWS FROM INVESTING ACTIVITIES:
	Additions to property, plant and equipment	(54		)	—		(70,083		)	—			—			(70,137		)
	Purchase of intangible assets	—			—		(1,006		)	—			—			(1,006		)
	Net cash flows used in investing activities	(54		)	—		(71,089		)	—			—			(71,143		)
	CASH FLOWS FROM FINANCING ACTIVITIES:
	Proceeds from long-term debt	171,300			—		—			—			—			171,300
	Repayment of long-term debt	(202,000		)	—		—			—			—			(202,000		)
	Proceeds from derivative contracts	1,044			—		—			—			—			1,044
	Common unit issued in equity offerings	96,359			—		—			—			—			96,359
	Issuance costs for equity offerings	(3,948		)	—		—			—			—			(3,948		)
	Distributions to members and affiliates	(32,419		)	—		—			—			—			(32,419		)
	Net cash flows provided by financing activities	30,336			—		—			—			—			30,336
	Net (decrease) increase in cash and cash equivalents	(1,670		)	—		1,696			9			—			35
	Cash and cash equivalents at beginning of period	1,670			1		(1,832		)	186			—			25
	Cash and cash equivalents at end of period	$	—		$	1	$	(136	)	$	195		$	—		$	60

Organization_and_Description_o1

Organization and Description of Business Narrative (Details) (USD $)	Mar. 31, 2014	Dec. 31, 2013
Disposal Group, Including Discontinued Operations, Consideration, Equity Interests Received, Shares	8,245,859	'
Subordinated Long-term Debt, Noncurrent	$550,000,000	$550,000,000
Scenario, Adjustment [Member]	'	'
Disposal Group, Including Discontinued Operation, Consideration, Adjustment	55,000,000	'
Total Midstream Segments [Member]	'	'
Disposal Group, Including Discontinued Operation, Consideration	1,325,000,000	'
Disposal Group, Including Discontinued Operation, Consideration, Equity Interests Received	200,000,000	'
Disposal Group, Including Discontinue Operation, Consideration, Cash	520,000,000	'
Total Midstream Segments [Member] | Scenario, Adjustment [Member]	'	'
Disposal Group, Including Discontinued Operation, Consideration	$1,270,000,000	'

Summary_of_Significant_Account2

Summary of Significant Accounting Policies Narrative (Details) (USD $)	Mar. 31, 2014	Dec. 31, 2012
In Millions, unless otherwise specified
Inventory, Finished Goods, Gross	$0.30	$1
Gas Balancing Payable	0.3	0.3
Transportation and exchange imbalance, receivable	1.8	0.7
Transportation and exchange imbalance, payable	$0.60	$1.60

Property_Plant_and_Equipment_P1

Property, Plant and Equipment Property, Plant and Equipment (Details) (USD $)	Mar. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Property, Plant and Equipment [Line Items]	'	'
Property, Plant and Equipment - Gross	$2,621,524	$2,581,463
Accumulated depreciation, depletion and amortization	-782,599	-752,695
Property, Plant and Equipment — Net	1,838,925	1,828,768
Land [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Property, Plant and Equipment - Gross	2,877	2,877
Natural Gas Processing Plant [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Property, Plant and Equipment - Gross	519,392	521,103
Pipelines [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Property, Plant and Equipment - Gross	782,577	777,446
Equipment [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Property, Plant and Equipment - Gross	58,153	53,999
Vehicles [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Property, Plant and Equipment - Gross	4,017	4,001
Office Equipment [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Property, Plant and Equipment - Gross	1,328	1,309
Computer Equipment [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Property, Plant and Equipment - Gross	17,117	14,806
LInefill [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Property, Plant and Equipment - Gross	5,142	5,180
Oil and Gas Properties [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Property, Plant and Equipment - Gross	1,195,188	'
Proved Oil and Gas Properties [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Property, Plant and Equipment - Gross	'	1,156,896
Unproved Oil and Gas Properties [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Property, Plant and Equipment - Gross	10,276	10,022
Construction in Progress [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Property, Plant and Equipment - Gross	$25,457	$33,824

Property_Plant_and_Equipment_D

Property, Plant and Equipment Depreciation, Depletion, Amortization and Impairment (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2014		Mar. 31, 2013
Depreciation	$18,861		$16,395
Depletion	19,672		20,871
Capitalized interest costs	144		355
Natural Gas Processing Plant [Member]	'		'
Impairment of Long-Lived Assets Held-for-use	132	[1]	0
Pipelines [Member]	'		'
Impairment of Long-Lived Assets Held-for-use	$1,904	[1]	$0
[1]	During the three months ended March 31, 2014, the Partnership incurred impairment charges in its Midstream Business related to certain plants and pipelines in its East Texas and Other Segment due to the loss of two customers.

Asset_Retirement_Obligations_S

Asset Retirement Obligations Schedule of Change in Asset Retirement Obligation (Details) (USD $)	3 Months Ended
	Mar. 31, 2014		Mar. 31, 2013	Dec. 31, 2013
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]	'		'	'
Asset Retirement Obligation - Beginning of Period	$58,964,000	[1]	$48,755,000	'
Additional liabilities	39,000		746,000	'
Liabilities settled	-682,000		-570,000	'
Revision to liabilities	-105,000		0	'
Accretion expense	980,000		840,000	'
Asset Retirement Obligation - End of Period	59,196,000	[1]	49,771,000	'
Asset Retirement Obligation, Current	$12,900,000		'	$13,100,000
[1]	As of March 31, 2014 and December 31, 2013, $12.9 million and $13.1 million, respectively, were included within accrued liabilities in the Unaudited Condensed Consolidated Balance Sheets.

Intangible_Assets_Intangible_A1

Intangible Assets Intangible Assets (Details) (USD $)	Mar. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Acquired Finite-Lived Intangible Assets [Line Items]	'	'
Intangible Assets — Net	$104,149	$105,620
Use Rights [Member]	'	'
Acquired Finite-Lived Intangible Assets [Line Items]	'	'
Rights-of-way and easements—at cost	131,580	131,088
Less: accumulated amortization	-37,846	-36,228
Contractual Rights [Member]	'	'
Acquired Finite-Lived Intangible Assets [Line Items]	'	'
Contracts	22,742	22,742
Less: accumulated amortization	($12,327)	($11,982)

Intangible_Assets_Amortization

Intangible Assets Amortization and Impairment (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2014		Mar. 31, 2013
Amortization	$1,964		$2,961
Use Rights [Member]	'		'
Impairment of Intangible Assets, Finite-lived	$61	[1]	$0
[1]	During the three months ended March 31, 2014, the Partnership incurred impairment charges in its Midstream Business related to certain rights-of-way in its East Texas and Other Segment due to the loss of two customers.

Intangible_Assets_Future_Amort

Intangible Assets Future Amortization Expense (Details) (USD $)	Mar. 31, 2014
In Thousands, unless otherwise specified
Finite-Lived Intangible Assets [Line Items]	'
Finite-Lived Intangible Assets, Amortization Expense, Remainder of Fiscal Year	$5,936
Finite-Lived Intangible Assets, Amortization Expense, Year Two	7,914
Finite-Lived Intangible Assets, Amortization Expense, Year Three	7,913
Finite-Lived Intangible Assets, Amortization Expense, Year Four	7,912
Finite-Lived Intangible Assets, Amortization Expense, Year Five	7,911
Finite-Lived Intangible Assets, Amortization Expense, after Year Five	$66,563

Intangible_Assets_Narrative_De

Intangible Assets Narrative (Details)	3 Months Ended
	Mar. 31, 2014
Use Rights [Member]	'
Finite-Lived Intangible Assets [Line Items]	'
Finite-Lived Intangible Asset, Useful Life	'20 years
Minimum [Member] | Contractual Rights [Member]	'
Finite-Lived Intangible Assets [Line Items]	'
Finite-Lived Intangible Asset, Useful Life	'5 years
Maximum [Member] | Contractual Rights [Member]	'
Finite-Lived Intangible Assets [Line Items]	'
Finite-Lived Intangible Asset, Useful Life	'20 years

Long_Term_Debt_LongTerm_Debt_D

Long Term Debt Long-Term Debt (Details) (USD $)	Mar. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Debt Instrument [Line Items]	'	'
Revolving credit facility:	$724,000	$706,800
8 3/8% senior notes due 2019	550,000	550,000
Unamortized bond discount senior notes due 2019	-4,567	-4,738
Senior Notes	545,433	545,262
Long-term debt	$1,269,433	$1,252,062

Long_Term_Debt_Debt_Covenants_

Long Term Debt Debt Covenants (Details)

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Dec. 31, 2014

Sep. 30, 2014

Jun. 30, 2014

Sep. 30, 2014

Jun. 30, 2014

Dec. 31, 2014

Sep. 30, 2014

Jun. 30, 2014

Dec. 31, 2014

Sep. 30, 2014

Jun. 30, 2014

Total Leverage Ratio [Member]

Senior Secured Leverage Ratio [Member]

Interest Coverage Ratio [Member]

Current Ratio [Member]

Maximum [Member]

Maximum [Member]

Minimum [Member]

Minimum [Member]

Scenario, Forecast [Member]

Scenario, Forecast [Member]

Scenario, Forecast [Member]

Scenario, Forecast [Member]

Scenario, Forecast [Member]

Scenario, Forecast [Member]

Scenario, Forecast [Member]

Scenario, Forecast [Member]

Scenario, Forecast [Member]

Scenario, Forecast [Member]

Scenario, Forecast [Member]

Total Leverage Ratio [Member]

Senior Secured Leverage Ratio [Member]

Interest Coverage Ratio [Member]

Current Ratio [Member]

Maximum [Member]

Maximum [Member]

Maximum [Member]

Maximum [Member]

Maximum [Member]

Minimum [Member]

Minimum [Member]

Minimum [Member]

Minimum [Member]

Minimum [Member]

Minimum [Member]

Total Leverage Ratio [Member]

Total Leverage Ratio [Member]

Total Leverage Ratio [Member]

Senior Secured Leverage Ratio [Member]

Senior Secured Leverage Ratio [Member]

Interest Coverage Ratio [Member]

Interest Coverage Ratio [Member]

Interest Coverage Ratio [Member]

Current Ratio [Member]

Current Ratio [Member]

Current Ratio [Member]

Schedule of Debt Covenants [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Line of Credit Facility, Covenant Ratio

5.4

3.06

3.1

1.1

5.85

[1]

3.4

[1]

2.5

[2]

1

[2]

4.5

[1]

4.75

[1]

5

[1]

2.95

[1]

3.05

[1]

2.5

[2]

2.5

[2]

2.5

[2]

1

[2]

1

[2]

1

[2]

[1]

Amount represents the maximum ratio for the period presented.

[2]

Amount represents the minimum ratio for the period presented.

Long_Term_Debt_Narrative_Detai

Long Term Debt Narrative (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
	Rate
Debt Instrument [Line Items]	'	'
Line of Credit Facility, Commitment Fee Percentage	0.50%	'
Letters of Credit Outstanding, Amount	$21.70	'
Line of Credit Facility, Remaining Borrowing Capacity	69.1	'
Line of Credit Facility, Current Borrowing Capacity	$815	'
Borrowing Base Multiplier	4	3.75
Debt Instrument, Covenant Compliance	'As of March 31, 2014, the Partnership was in compliance with the financial covenants under the revolving credit facility.	'

Members_Equity_Narrative_Detai

Members' Equity Narrative (Details) (USD $)	3 Months Ended
In Millions, except Share data, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Capital Unit [Line Items]	'	'
Limited Partners' Capital Account, Units Outstanding	156,644,153	156,644,153
Unvested Restricted Units Outstanding	2,754,383	2,743,807
Equity Issuance, Market Value	$100	'
Equity Units, Issued	0	'

Members_Equity_Distributions_D

Members' Equity Distributions (Details) (USD $)	3 Months Ended
	Mar. 31, 2014		Dec. 31, 2013
Dividends Payable [Line Items]	'		'
Common Stock, Dividends, Per Share, Cash Paid	$0	[1]	$0.15	[2]
Record date	'		7-Feb-14	[3]
Payment Date	'		14-Feb-14
[1]	No distribution was declared or paid for this period as the distribution was suspended for this period in advance of the closing the Midstream Business Contribution.
[2]	The distribution excludes certain restricted unit grants.
[3]	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 $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013	Dec. 31, 2013
Related Party Transaction [Line Items]	'	'	'
Natural gas purchases from affiliates	$1,142	$123	'
Due to Related Parties, Current	$0	'	$18

Risk_Management_Activities_Int

Risk Management Activities Interest Rate Derivatives (Details) (Effective Date, 6/22/2011 [Member], Interest Rate Swap [Member], USD $)	45 Months Ended
	Sep. 30, 2015	Mar. 31, 2014
		Rate
Effective Date, 6/22/2011 [Member] | Interest Rate Swap [Member]	'	'
Derivative [Line Items]	'	'
Derivative, Maturity Date	22-Jun-15	'
Derivative, Notional Amount	'	$250,000,000
Derivative, Average Fixed Interest Rate	'	2.95%

Risk_Management_Activities_Com

Risk Management Activities Commodity Derivatives (Details)	Mar. 31, 2014
	MMbtu
Natural Gas Contract [Member] | Swap [Member] | Portion of contracts settling in 2014 [Member]	'
Derivative [Line Items]	'
Derivative, Nonmonetary Notional Amount	12,600,000	[1]
Derivative, Average Floor Price	4.38	[2]
Natural Gas Contract [Member] | Swap [Member] | Portion of contracts settling in 2015 [Member]	'
Derivative [Line Items]	'
Derivative, Nonmonetary Notional Amount	12,000,000	[1]
Derivative, Average Floor Price	4.1	[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 2014 [Member]	'
Derivative [Line Items]	'
Derivative, Nonmonetary Notional Amount	180,000	[1]
Derivative, Average Floor Price	90	[2]
Derivative, Average Cap Price	106	[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 2014 [Member]	'
Derivative [Line Items]	'
Derivative, Nonmonetary Notional Amount	1,650,000	[1]
Derivative, Average Floor Price	96.51	[2]
Crude Oil Contract [Member] | Swap [Member] | Portion of contracts settling in 2015 [Member]	'
Derivative [Line Items]	'
Derivative, Nonmonetary Notional Amount	1,110,000	[1]
Derivative, Average Floor Price	88.7	[2]
Crude Oil Contract [Member] | Swap [Member] | Portion of contracts settling in 2016 [Member]	'
Derivative [Line Items]	'
Derivative, Nonmonetary Notional Amount	1,416,000	[1]
Derivative, Average Floor Price	84.6	[2]
Crude Oil Contract [Member] | Swap, Pay Fixed, Receive Floating [Member] | Portion of contracts settling in 2014 [Member]	'
Derivative [Line Items]	'
Derivative, Nonmonetary Notional Amount	218,676	[1]
Derivative, Average Floor Price	92.54	[2]
Propane Contract [Member] | Swap [Member] | Portion of contracts settling in 2014 [Member]	'
Derivative [Line Items]	'
Derivative, Nonmonetary Notional Amount	12,852,000	[1]
Derivative, Average Floor Price	1.09	[2]
IsoButane Contract [Member] | Swap [Member] | Portion of contracts settling in 2014 [Member]	'
Derivative [Line Items]	'
Derivative, Nonmonetary Notional Amount	1,701,000	[1]
Derivative, Average Floor Price	1.31	[2]
Normal Butane Contract [Member] | Swap [Member] | Portion of contracts settling in 2014 [Member]	'
Derivative [Line Items]	'
Derivative, Nonmonetary Notional Amount	3,099,600	[1]
Derivative, Average Floor Price	1.3	[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 in $/MMbtu for natural gas, $/barrel for crude oil and $/gallon for natural gas liquids.

Risk_Management_Activities_Sch

Risk Management Activities Schedule of Marketing and Trading Derivative Instruments (Details) (Natural Gas Contract [Member])	Mar. 31, 2014
	MMbtu
Portion of contracts settling in 2014 [Member] | Index Swap, Purchases [Member]	'
Derivative [Line Items]	'
Derivative, Nonmonetary Notional Amount	1,950,000
Portion of contracts settling in 2014 [Member] | Index Swap, Sales [Member]	'
Derivative [Line Items]	'
Derivative, Nonmonetary Notional Amount	600,000
Portion of contracts settling in 2014 [Member] | Swap, Pay Fixed, Receive Floating [Member]	'
Derivative [Line Items]	'
Derivative, Nonmonetary Notional Amount	750,000
Portion of contracts settling in 2014 [Member] | Swap, Pay Floating, Receive Fixed [Member]	'
Derivative [Line Items]	'
Derivative, Nonmonetary Notional Amount	3,525,000
Portion of contracts settling in 2014 [Member] | Forward Contract, Purchases - Index [Member]	'
Derivative [Line Items]	'
Derivative, Nonmonetary Notional Amount	9,315,450
Portion of contracts settling in 2014 [Member] | Forward Contract, Sales - Index[Member]	'
Derivative [Line Items]	'
Derivative, Nonmonetary Notional Amount	16,300,200
Portion of contracts settling in 2014 [Member] | Forward Contract, Purchases - Fixed Price [Member]	'
Derivative [Line Items]	'
Derivative, Nonmonetary Notional Amount	3,747,000
Portion of contracts settling in 2014 [Member] | Forward Contract, Sales - Fixed Price [Member]	'
Derivative [Line Items]	'
Derivative, Nonmonetary Notional Amount	1,575,000
Portion of contracts settling in 2014 [Member] | Basis Swap, Purchases [Member]	'
Derivative [Line Items]	'
Derivative, Nonmonetary Notional Amount	8,155,000
Portion of contracts settling in 2014 [Member] | Basis Swap, Sales [Member]	'
Derivative [Line Items]	'
Derivative, Nonmonetary Notional Amount	3,650,000
Portion of contracts settling thereafter [Member] | Basis Swap, Purchases [Member]	'
Derivative [Line Items]	'
Derivative, Nonmonetary Notional Amount	13,280,000
Portion of contracts settling thereafter [Member] | Basis Swap, Sales [Member]	'
Derivative [Line Items]	'
Derivative, Nonmonetary Notional Amount	13,280,000

Risk_Management_Activities_Sch1

Risk Management Activities Schedule of Derivative Instruments in the Statement of Financial Position (Details) (USD $)	Mar. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Derivatives, Fair Value [Line Items]	'	'
Derivative Liabilities, Current	($15,334)	($11,023)
Derivative Liabilities, Noncurrent	-878	-3,848
Derivative assets, Current	5,740	9,162
Derivative assets, Noncurrent	1,451	5,461
Derivative Assets	7,191	14,623
Derivative Liabilities	-16,212	-14,871
Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member] | Current Assets [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative Liabilities, Current	0	0
Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member] | Long-term Assets [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative Liabilities, Noncurrent	0	0
Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member] | Current Liabilities [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative Liabilities, Current	-6,310	-6,210
Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member] | Long-term Liabilities [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative Liabilities, Noncurrent	-1,368	-2,885
Commodity Contract [Member] | Not Designated as Hedging Instrument [Member] | Current Assets [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative Liabilities, Current	-2,123	-2,106
Derivative assets, Current	7,863	11,268
Commodity Contract [Member] | Not Designated as Hedging Instrument [Member] | Long-term Assets [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative Liabilities, Noncurrent	-910	-798
Derivative assets, Noncurrent	2,361	6,259
Commodity Contract [Member] | Not Designated as Hedging Instrument [Member] | Current Liabilities [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative Liabilities, Current	-10,681	-6,543
Derivative assets, Current	1,657	1,730
Commodity Contract [Member] | Not Designated as Hedging Instrument [Member] | Long-term Liabilities [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative Liabilities, Noncurrent	-832	-2,451
Derivative assets, Noncurrent	$1,322	$1,488

Risk_Management_Activities_Sch2

Risk Management Activities Schedule of Derivative Instruments, Gain (Loss) in Statement of Financial Performance (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Derivative Instruments, Gain (Loss) [Line Items]	'	'
Interest rate risk management losses	($290)	($156)
Commodity risk management (losses) gains	-14,944	-17,908
Derivative Instruments, Gain (Loss) Recognized in Income, Net	-16,221	-19,214
Interest Rate Contract [Member] | Other Expense [Member] | Not Designated as Hedging Instrument [Member]	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'
Interest rate risk management losses	-290	-156
Commodity Contract [Member] | Commodity Risk Management Gains (Losses) [Member] | Not Designated as Hedging Instrument [Member]	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'
Commodity risk management (losses) gains	-14,944	-17,908
Commodity Contract [Member] | Sales [Member] | Not Designated as Hedging Instrument [Member]	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'
Commodity risk management (losses) gains	($987)	($1,150)

Fair_Value_of_Financial_Instru2

Fair Value of Financial Instruments Fair Value, Assets and Liabilities Measured on a Recurring Basis (Details) (USD $)	Mar. 31, 2014		Dec. 31, 2013
In Thousands, unless otherwise specified
Assets:	'		'
Derivative Assets	$7,191		$14,623
Liabilities:	'		'
Derivative Liabilities	-16,212		-14,871
Fair Value, Measurements, Recurring [Member]	'		'
Assets:	'		'
Derivative Assets	7,191		14,623
Liabilities:	'		'
Derivative Liabilities	-16,212		-14,871
Fair Value, Measurements, Recurring [Member] | Crude Oil Contract [Member]	'		'
Assets:	'		'
Derivative Assets	2,638		7,801
Liabilities:	'		'
Derivative Liabilities	-3,271		-1,927
Fair Value, Measurements, Recurring [Member] | Natural Gas Contract [Member]	'		'
Assets:	'		'
Derivative Assets	4,553		6,822
Liabilities:	'		'
Derivative Liabilities	-5,479		-2,770
Fair Value, Measurements, Recurring [Member] | Natural Gas Liquids Contract [Member]	'		'
Assets:	'		'
Derivative Assets	0		0
Liabilities:	'		'
Derivative Liabilities	216		1,079
Fair Value, Measurements, Recurring [Member] | Interest Rate Contract [Member]	'		'
Liabilities:	'		'
Derivative Liabilities	-7,678		-9,095
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]	'		'
Assets:	'		'
Derivative Assets	0		0
Liabilities:	'		'
Derivative Liabilities	0		0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Crude Oil Contract [Member]	'		'
Assets:	'		'
Derivative Assets	0		0
Liabilities:	'		'
Derivative Liabilities	0		0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Natural Gas Contract [Member]	'		'
Assets:	'		'
Derivative Assets	0		0
Liabilities:	'		'
Derivative Liabilities	0		0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Natural Gas Liquids Contract [Member]	'		'
Assets:	'		'
Derivative Assets	0		0
Liabilities:	'		'
Derivative Liabilities	0		0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Interest Rate Contract [Member]	'		'
Liabilities:	'		'
Derivative Liabilities	0		0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]	'		'
Assets:	'		'
Derivative Assets	13,203		20,745
Liabilities:	'		'
Derivative Liabilities	-22,224		-20,993
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Crude Oil Contract [Member]	'		'
Assets:	'		'
Derivative Assets	4,920		9,804
Liabilities:	'		'
Derivative Liabilities	-5,553		-3,930
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Natural Gas Contract [Member]	'		'
Assets:	'		'
Derivative Assets	7,786		10,899
Liabilities:	'		'
Derivative Liabilities	-8,712		-6,847
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Natural Gas Liquids Contract [Member]	'		'
Assets:	'		'
Derivative Assets	497		42
Liabilities:	'		'
Derivative Liabilities	-281		1,121
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Interest Rate Contract [Member]	'		'
Liabilities:	'		'
Derivative Liabilities	-7,678		-9,095
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]	'		'
Assets:	'		'
Derivative Assets	0		0
Liabilities:	'		'
Derivative Liabilities	0		0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Crude Oil Contract [Member]	'		'
Assets:	'		'
Derivative Assets	0		0
Liabilities:	'		'
Derivative Liabilities	0		0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Natural Gas Contract [Member]	'		'
Assets:	'		'
Derivative Assets	0		0
Liabilities:	'		'
Derivative Liabilities	0		0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Natural Gas Liquids Contract [Member]	'		'
Assets:	'		'
Derivative Assets	0		0
Liabilities:	'		'
Derivative Liabilities	0		0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Interest Rate Contract [Member]	'		'
Liabilities:	'		'
Derivative Liabilities	0		0
Fair Value, Measurements, Recurring [Member] | Netting [Member]	'		'
Assets:	'		'
Derivative Assets	-6,012	[1]	-6,122	[1]
Liabilities:	'		'
Derivative Liabilities	6,012	[1]	6,122	[1]
Fair Value, Measurements, Recurring [Member] | Netting [Member] | Crude Oil Contract [Member]	'		'
Assets:	'		'
Derivative Assets	-2,282	[1]	-2,003	[1]
Liabilities:	'		'
Derivative Liabilities	2,282	[1]	2,003	[1]
Fair Value, Measurements, Recurring [Member] | Netting [Member] | Natural Gas Contract [Member]	'		'
Assets:	'		'
Derivative Assets	-3,233	[1]	-4,077	[1]
Liabilities:	'		'
Derivative Liabilities	3,233	[1]	4,077	[1]
Fair Value, Measurements, Recurring [Member] | Netting [Member] | Natural Gas Liquids Contract [Member]	'		'
Assets:	'		'
Derivative Assets	-497	[1]	-42	[1]
Liabilities:	'		'
Derivative Liabilities	497	[1]	-42	[1]
Fair Value, Measurements, Recurring [Member] | Netting [Member] | Interest Rate Contract [Member]	'		'
Liabilities:	'		'
Derivative Liabilities	$0	[1]	$0	[1]
[1]	Represents counterparty netting under the agreement governing such derivative contracts.

Fair_Value_of_Financial_Instru3

Fair Value of Financial Instruments Fair Value, Assets and Liabilities Measured on a Nonrecurring Basis (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2014		Mar. 31, 2013
Pipelines [Member]	'		'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
Property, Plant, and Equipment, Fair Value Disclosure	$746		'
Impairment of Long-Lived Assets Held-for-use	1,904	[1]	0
Pipelines [Member] | Fair Value, Measurements, Nonrecurring [Member] | Fair Value, Inputs, Level 1 [Member]	'		'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
Property, Plant, and Equipment, Fair Value Disclosure	0		'
Pipelines [Member] | Fair Value, Measurements, Nonrecurring [Member] | Fair Value, Inputs, Level 2 [Member]	'		'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
Property, Plant, and Equipment, Fair Value Disclosure	0		'
Pipelines [Member] | Fair Value, Measurements, Nonrecurring [Member] | Fair Value, Inputs, Level 3 [Member]	'		'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
Property, Plant, and Equipment, Fair Value Disclosure	746		'
Natural Gas Processing Plant [Member]	'		'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
Property, Plant, and Equipment, Fair Value Disclosure	52		'
Impairment of Long-Lived Assets Held-for-use	132	[1]	0
Natural Gas Processing Plant [Member] | Fair Value, Measurements, Nonrecurring [Member] | Fair Value, Inputs, Level 1 [Member]	'		'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
Property, Plant, and Equipment, Fair Value Disclosure	0		'
Natural Gas Processing Plant [Member] | Fair Value, Measurements, Nonrecurring [Member] | Fair Value, Inputs, Level 2 [Member]	'		'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
Property, Plant, and Equipment, Fair Value Disclosure	0		'
Natural Gas Processing Plant [Member] | Fair Value, Measurements, Nonrecurring [Member] | Fair Value, Inputs, Level 3 [Member]	'		'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
Property, Plant, and Equipment, Fair Value Disclosure	52		'
Use Rights [Member]	'		'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
Property, Plant, and Equipment, Fair Value Disclosure	24		'
Impairment of Long-Lived Assets Held-for-use	61		'
Use Rights [Member] | Fair Value, Measurements, Nonrecurring [Member] | Fair Value, Inputs, Level 1 [Member]	'		'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
Property, Plant, and Equipment, Fair Value Disclosure	0		'
Use Rights [Member] | Fair Value, Measurements, Nonrecurring [Member] | Fair Value, Inputs, Level 2 [Member]	'		'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
Property, Plant, and Equipment, Fair Value Disclosure	0		'
Use Rights [Member] | Fair Value, Measurements, Nonrecurring [Member] | Fair Value, Inputs, Level 3 [Member]	'		'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
Property, Plant, and Equipment, Fair Value Disclosure	$24		'
[1]	During the three months ended March 31, 2014, the Partnership incurred impairment charges in its Midstream Business related to certain plants and pipelines in its East Texas and Other Segment due to the loss of two customers.

Fair_Value_of_Financial_Instru4

Fair Value of Financial Instruments Narrative (Details) (USD $)	Mar. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Notes Payable, Fair Value Disclosure	$597.40	$599.50

Commitments_and_Contingencies_

Commitments and Contingencies Loss Contingencies (Details) (USD $)	Mar. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Loss Contingencies [Line Items]	'	'
Accrual for Environmental Loss Contingencies	$3.10	$3.20

Commitments_and_Contingencies_1

Commitments and Contingencies Operating Leases (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Operating leases [Line Items]	'	'
Operating Leases, Rent Expense	$2.90	$2.10

Segments_Schedule_of_Segment_R

Segments Schedule of Segment Reporting Information, by Segment (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2014		Mar. 31, 2013		Dec. 31, 2013
Segment Reporting Information [Line Items]	'		'		'
Revenues	$348,074		$257,731		'
Cost of natural gas, natural gas liquids, condensate and helium	244,973		179,988		'
Depreciation, Depletion and Amortization	40,508		40,237		'
Impairment	2,097		0		'
Operating income (loss)	-1,233		-17,426		'
Capital Expenditures	53,938		70,137		'
Segment Assets	2,155,318		'		2,127,550
Operating Segments [Member]	'		'		'
Segment Reporting Information [Line Items]	'		'		'
Revenues	348,074		257,731		'
Intersegment Sales	0		0		'
Cost of natural gas, natural gas liquids, condensate and helium	244,973		179,988		'
Intersegment costs of sales	0		0		'
Operating Expenses	61,729		54,932		'
Depreciation, Depletion and Amortization	40,508		40,237		'
Impairment	2,097		'		'
Operating income (loss)	-1,233		-17,426		'
Capital Expenditures	51,052		55,950		'
Segment Assets	2,155,318		2,300,611		'
Panhandle Segment [Member]	'		'		'
Segment Reporting Information [Line Items]	'		'		'
Revenues	159,835		118,915		'
Intersegment Sales	72,959		49,135		'
Cost of natural gas, natural gas liquids, condensate and helium	189,904		132,226		'
Intersegment costs of sales	63		19		'
Operating Expenses	20,317		17,134		'
Depreciation, Depletion and Amortization	15,626		13,845		'
Impairment	0		'		'
Operating income (loss)	6,884		4,826		'
Capital Expenditures	8,363		18,303		'
Segment Assets	949,909		924,894		'
East Texas and Other Midstream Segment	'		'		'
Segment Reporting Information [Line Items]	'		'		'
Revenues	46,473		35,746		'
Intersegment Sales	17,861		8,538		'
Cost of natural gas, natural gas liquids, condensate and helium	55,069		33,234		'
Intersegment costs of sales	0		0		'
Operating Expenses	4,724		4,829		'
Depreciation, Depletion and Amortization	4,334		5,002		'
Impairment	2,097		'		'
Operating income (loss)	-1,890		1,219		'
Capital Expenditures	1,851		1,776		'
Segment Assets	244,014		246,458		'
Marketing and Trading Segment	'		'		'
Segment Reporting Information [Line Items]	'		'		'
Revenues	104,422		86,776		'
Intersegment Sales	-93,772		-59,468		'
Cost of natural gas, natural gas liquids, condensate and helium	0		14,528		'
Intersegment costs of sales	681		11,093		'
Operating Expenses	8		6		'
Depreciation, Depletion and Amortization	119		84		'
Impairment	0		'		'
Operating income (loss)	9,842		1,597		'
Capital Expenditures	3		154		'
Segment Assets	73,398		55,331		'
Total Midstream Segments [Member]	'		'		'
Segment Reporting Information [Line Items]	'		'		'
Revenues	310,730		241,437		'
Intersegment Sales	-2,952		-1,795		'
Cost of natural gas, natural gas liquids, condensate and helium	244,973		179,988		'
Intersegment costs of sales	744		11,112		'
Operating Expenses	25,049		21,969		'
Depreciation, Depletion and Amortization	20,079		18,931		'
Impairment	2,097		'		'
Operating income (loss)	14,836		7,642		'
Capital Expenditures	10,217		20,233		'
Segment Assets	1,267,321		1,226,683		'
Upstream Segment [Member]	'		'		'
Segment Reporting Information [Line Items]	'		'		'
Revenues	52,288		34,202		'
Intersegment Sales	2,948		13,100		'
Cost of natural gas, natural gas liquids, condensate and helium	0		0		'
Intersegment costs of sales	0		0		'
Operating Expenses	15,289		14,116		'
Depreciation, Depletion and Amortization	19,725		20,929		'
Impairment	0		'		'
Operating income (loss)	20,222		12,257		'
Capital Expenditures	39,258		34,050		'
Segment Assets	872,604		1,030,091		'
Corporate and Other Segment [Member]	'		'		'
Segment Reporting Information [Line Items]	'		'		'
Revenues	-14,944	[1]	-17,908	[1]	'
Intersegment Sales	4		-11,305		'
Cost of natural gas, natural gas liquids, condensate and helium	0		0		'
Intersegment costs of sales	-744		-11,112		'
Operating Expenses	21,391		18,847		'
Depreciation, Depletion and Amortization	704		377		'
Impairment	0		'		'
Operating income (loss)	-36,291		-37,325		'
Capital Expenditures	1,577		1,667		'
Segment Assets	$15,393	[2]	$43,837	[2]	'
[1]	Represents results of the Partnership's commodity risk management activity, excluding activity associated with its natural gas marketing and trading activities.
[2]	Includes elimination of intersegment transactions.

Income_Taxes_Schedule_of_Effec

Income Taxes Schedule of Effective Income Tax Rate Reconciliation (Details)	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
	Rate	Rate
Effective Income Tax Rate, Continuing Operations	4.90%	3.30%

Equity_Based_Compensation_Shar

Equity Based Compensation Share-based Compensation Rollforward (Details) (USD $)	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2014
			Restricted Stock Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Outstanding [Roll Forward]	'	'	'
Unvested Restricted Units Outstanding - Beginning Balance	2,754,383	2,743,807	2,743,807
Grants in Period	'	'	50,500
Forfeited in Period	'	'	-39,924
Unvested Restricted Units Outstanding - Ending Balance	2,754,383	2,743,807	2,754,383
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Roll Forward]	'	'	'
Weighted Average Grant Date Fair Value	'	'	$9.37
Grants in Period, Weighted Average Grant Date Fair Value	'	'	$5.52
Forfeitures in Period, Weighted Average Grant Price	'	'	$9.85
Weighted Average Grant Date Fair Value - Ending	'	'	$9.30

Equity_Based_Compensation_Narr

Equity Based Compensation Narrative (Details) (USD $)	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
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	7,000,000	'
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant	903,218	'
Equity-based compensation	$3,332,000	$2,647,000
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	14,100,000	'
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition	'1 year 6 months 0 days	'
Common Units [Member]	'	'
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]	'	'
Equity-based compensation	$3,332,000	'

Earnings_Per_Unit_Schedule_of_

Earnings Per Unit Schedule of Weighted Average Number of Units(Details)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Weighted average common units outstanding - basic and diluted	156,644	146,171

Earnings_Per_Unit_Calculation_

Earnings Per Unit Calculation of basic and diluted earnings per unit (Details) (USD $)	3 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Mar. 31, 2014		Mar. 31, 2013
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]	'		'
Income (Loss) from Continuing Operations Attributable to Parent	($18,563)		($33,514)
Distributions	0	[1]	34,694
Assumed income (loss) from continuing operations after distribution to be allocated	-18,563		-68,208
Net income (loss)	-18,563		-33,514
Net income (loss) per common unit - basic and diluted	($0.12)		($0.23)
Common Units [Member]	'		'
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]	'		'
Distributions	0	[1]	34,106
Assumed income (loss) from continuing operations after distribution to be allocated	-18,563		-68,208
Net income (loss)	-18,563		-34,102
Net income (loss) per common unit - basic and diluted	($0.12)		($0.23)
Restricted Common Units [Member]	'		'
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]	'		'
Distributions	0	[1],[2]	588
Assumed income (loss) from continuing operations after distribution to be allocated	0	[2]	0
Net income (loss)	$0	[2]	$588
[1]	No distribution was declared or paid for this period as the distribution was suspended for this period in advance of the closing the Midstream Business Contribution.
[2]	Restricted common units granted under the LTIP that contain non-forfeitable rights to the distributions declared by the Partnership

Subsidiary_Guarantors_Subsidia1

Subsidiary Guarantors Subsidiary Guarantors Condensed Consolidating Balance Sheets (Details) (USD $)	Mar. 31, 2014		Dec. 31, 2013
In Thousands, unless otherwise specified
Subsidiary Guarantors [Line Items]	'		'
Accounts receivable – related parties	$0		$0
Other current assets	189,816		163,384
Property, Plant and Equipment — Net	1,838,925		1,828,768
Investment in subsidiaries	0		0
Total other long-term assets	126,577		135,398
Total assets	2,155,318		2,127,550
Accounts payable – related parties	0		0
Other current liabilities	260,469		211,266
Other long-term liabilities	90,569		90,343
Long-term debt	1,269,433		1,252,062
Members' Equity	534,847	[1]	573,879	[1]
Total liabilities and equity	2,155,318		2,127,550
Parent Company [Member]	'		'
Subsidiary Guarantors [Line Items]	'		'
Accounts receivable – related parties	663,758		691,588
Other current assets	8,290		5,868
Property, Plant and Equipment — Net	2,601		2,318
Investment in subsidiaries	1,151,844		1,133,217
Total other long-term assets	16,193		19,833
Total assets	1,842,686		1,852,824
Accounts payable – related parties	0		0
Other current liabilities	31,281		17,390
Other long-term liabilities	7,125		9,493
Long-term debt	1,269,433		1,252,062
Members' Equity	534,847		573,879
Total liabilities and equity	1,842,686		1,852,824
Co-issuer [Member]	'		'
Subsidiary Guarantors [Line Items]	'		'
Accounts receivable – related parties	0		0
Other current assets	1		1
Property, Plant and Equipment — Net	0		0
Investment in subsidiaries	0		0
Total other long-term assets	0		0
Total assets	1		1
Accounts payable – related parties	0		0
Other current liabilities	0		0
Other long-term liabilities	0		0
Long-term debt	0		0
Members' Equity	1		1
Total liabilities and equity	1		1
Guarantor Subsidiaries [Member]	'		'
Subsidiary Guarantors [Line Items]	'		'
Accounts receivable – related parties	0		0
Other current assets	181,525		157,515
Property, Plant and Equipment — Net	1,836,324		1,826,450
Investment in subsidiaries	0		0
Total other long-term assets	110,384		115,565
Total assets	2,128,233		2,099,530
Accounts payable – related parties	663,758		691,588
Other current liabilities	229,188		193,876
Other long-term liabilities	83,444		80,850
Long-term debt	0		0
Members' Equity	1,151,843		1,133,216
Total liabilities and equity	2,128,233		2,099,530
Non-Guarantor Subsidiaries [Member]	'		'
Subsidiary Guarantors [Line Items]	'		'
Accounts receivable – related parties	0		0
Other current assets	0		0
Property, Plant and Equipment — Net	0		0
Investment in subsidiaries	894		908
Total other long-term assets	0		0
Total assets	894		908
Accounts payable – related parties	0		0
Other current liabilities	0		0
Other long-term liabilities	0		0
Long-term debt	0		0
Members' Equity	894		908
Total liabilities and equity	894		908
Consolidation, Eliminations [Member]	'		'
Subsidiary Guarantors [Line Items]	'		'
Accounts receivable – related parties	-663,758		-691,588
Other current assets	0		0
Property, Plant and Equipment — Net	0		0
Investment in subsidiaries	-1,152,738		-1,134,125
Total other long-term assets	0		0
Total assets	-1,816,496		-1,825,713
Accounts payable – related parties	-663,758		-691,588
Other current liabilities	0		0
Other long-term liabilities	0		0
Long-term debt	0		0
Members' Equity	-1,152,738		-1,134,125
Total liabilities and equity	($1,816,496)		($1,825,713)
[1]	156,644,153 and 156,644,153 common units were issued and outstanding as of March 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 2,754,383 and 2,743,807 as of March 31, 2014 and December 31, 2013, respectively.

Subsidiary_Guarantors_Subsidia2

Subsidiary Guarantors Subsidiary Guarantors Condensed Consolidating Income Statement (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Subsidiary Guarantors [Line Items]	'	'
Total revenues	$348,074	$257,731
Cost of natural gas, natural gas liquids, condensate and helium	244,973	179,988
Operations and maintenance	34,671	32,219
Taxes other than income	5,667	3,866
General and administrative	21,391	18,847
Depreciation, depletion and amortization	40,508	40,237
Impairment	2,097	0
Operating income (loss)	-1,233	-17,426
Interest expense	-17,986	-17,084
Other non-operating income	0	0
Other (expense) income	-297	-164
Income (loss) before income taxes	-19,516	-34,674
Income Tax Expense (Benefit)	-953	-1,160
Equity in earnings of subsidiaires	0	0
Net income (loss)	-18,563	-33,514
Parent Company [Member]	'	'
Subsidiary Guarantors [Line Items]	'	'
Total revenues	-13,520	-4,522
Cost of natural gas, natural gas liquids, condensate and helium	0	0
Operations and maintenance	0	0
Taxes other than income	0	0
General and administrative	6,411	3,012
Depreciation, depletion and amortization	53	47
Impairment	0	'
Operating income (loss)	-19,984	-7,581
Interest expense	-17,985	-16,304
Other non-operating income	2,221	2,281
Other (expense) income	-1,716	-1,616
Income (loss) before income taxes	-37,464	-23,220
Income Tax Expense (Benefit)	-267	-575
Equity in earnings of subsidiaires	18,634	-10,869
Net income (loss)	-18,563	-33,514
Co-issuer [Member]	'	'
Subsidiary Guarantors [Line Items]	'	'
Total revenues	0	0
Cost of natural gas, natural gas liquids, condensate and helium	0	0
Operations and maintenance	0	0
Taxes other than income	0	0
General and administrative	0	0
Depreciation, depletion and amortization	0	0
Impairment	0	'
Operating income (loss)	0	0
Interest expense	0	0
Other non-operating income	0	0
Other (expense) income	0	0
Income (loss) before income taxes	0	0
Income Tax Expense (Benefit)	0	0
Equity in earnings of subsidiaires	0	0
Net income (loss)	0	0
Guarantor Subsidiaries [Member]	'	'
Subsidiary Guarantors [Line Items]	'	'
Total revenues	361,594	262,253
Cost of natural gas, natural gas liquids, condensate and helium	244,973	179,988
Operations and maintenance	34,671	32,219
Taxes other than income	5,667	3,866
General and administrative	14,980	15,835
Depreciation, depletion and amortization	40,455	40,190
Impairment	2,097	'
Operating income (loss)	18,751	-9,845
Interest expense	-1	-780
Other non-operating income	2,301	2,334
Other (expense) income	-3,096	-3,158
Income (loss) before income taxes	17,955	-11,449
Income Tax Expense (Benefit)	-686	-585
Equity in earnings of subsidiaires	0	0
Net income (loss)	18,641	-10,864
Non-Guarantor Subsidiaries [Member]	'	'
Subsidiary Guarantors [Line Items]	'	'
Total revenues	0	0
Cost of natural gas, natural gas liquids, condensate and helium	0	0
Operations and maintenance	0	0
Taxes other than income	0	0
General and administrative	0	0
Depreciation, depletion and amortization	0	0
Impairment	0	'
Operating income (loss)	0	0
Interest expense	0	0
Other non-operating income	0	0
Other (expense) income	-7	-5
Income (loss) before income taxes	-7	-5
Income Tax Expense (Benefit)	0	0
Equity in earnings of subsidiaires	0	0
Net income (loss)	-7	-5
Consolidation, Eliminations [Member]	'	'
Subsidiary Guarantors [Line Items]	'	'
Total revenues	0	0
Cost of natural gas, natural gas liquids, condensate and helium	0	0
Operations and maintenance	0	0
Taxes other than income	0	0
General and administrative	0	0
Depreciation, depletion and amortization	0	0
Impairment	0	'
Operating income (loss)	0	0
Interest expense	0	0
Other non-operating income	-4,522	-4,615
Other (expense) income	4,522	4,615
Income (loss) before income taxes	0	0
Income Tax Expense (Benefit)	0	0
Equity in earnings of subsidiaires	-18,634	10,869
Net income (loss)	($18,634)	$10,869

Subsidiary_Guarantors_Subsidia3

Subsidiary Guarantors Subsidiary Guarantor Condensed Consolidating Statements of Cash Flows (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Subsidiary Guarantors [Line Items]	'	'
Net cash flows provided by operating activities	$68,553	$40,842
Additions to property, plant and equipment	-53,938	-70,137
Purchase of intangible assets	-554	-1,006
Net cash provided by (used in) investing activities	-54,492	-71,143
Proceeds from long-term debt	144,250	171,300
Repayment of long-term debt	-127,050	-202,000
Proceeds from derivative contracts	-1,708	1,044
Common unit issuance	0	96,359
Payments of Unit Issuance Costs	0	-3,948
Distributions to members and affiliates	-23,801	-32,419
Net cash provided by (used in) financing activities	-8,514	30,336
Net increase in cash and cash equivalents	5,547	35
CASH AND CASH EQUIVALENTS—Beginning of period	76	25
CASH AND CASH EQUIVALENTS—End of period	5,623	60
Parent Company [Member]	'	'
Subsidiary Guarantors [Line Items]	'	'
Net cash flows provided by operating activities	13,139	-31,952
Additions to property, plant and equipment	-336	-54
Purchase of intangible assets	0	0
Net cash provided by (used in) investing activities	-336	-54
Proceeds from long-term debt	144,250	171,300
Repayment of long-term debt	-127,050	-202,000
Proceeds from derivative contracts	-1,708	1,044
Common unit issuance	'	96,359
Payments of Unit Issuance Costs	'	-3,948
Distributions to members and affiliates	-23,801	-32,419
Net cash provided by (used in) financing activities	-8,514	30,336
Net increase in cash and cash equivalents	4,289	-1,670
CASH AND CASH EQUIVALENTS—Beginning of period	1,237	1,670
CASH AND CASH EQUIVALENTS—End of period	5,526	0
Co-issuer [Member]	'	'
Subsidiary Guarantors [Line Items]	'	'
Net cash flows provided by operating activities	0	0
Additions to property, plant and equipment	0	0
Purchase of intangible assets	0	0
Net cash provided by (used in) investing activities	0	0
Proceeds from long-term debt	0	0
Repayment of long-term debt	0	0
Proceeds from derivative contracts	0	0
Common unit issuance	'	0
Payments of Unit Issuance Costs	'	0
Distributions to members and affiliates	0	0
Net cash provided by (used in) financing activities	0	0
Net increase in cash and cash equivalents	0	0
CASH AND CASH EQUIVALENTS—Beginning of period	1	1
CASH AND CASH EQUIVALENTS—End of period	1	1
Guarantor Subsidiaries [Member]	'	'
Subsidiary Guarantors [Line Items]	'	'
Net cash flows provided by operating activities	55,398	72,785
Additions to property, plant and equipment	-53,602	-70,083
Purchase of intangible assets	-554	-1,006
Net cash provided by (used in) investing activities	-54,156	-71,089
Proceeds from long-term debt	0	0
Repayment of long-term debt	0	0
Proceeds from derivative contracts	0	0
Common unit issuance	'	0
Payments of Unit Issuance Costs	'	0
Distributions to members and affiliates	0	0
Net cash provided by (used in) financing activities	0	0
Net increase in cash and cash equivalents	1,242	1,696
CASH AND CASH EQUIVALENTS—Beginning of period	-1,389	-1,832
CASH AND CASH EQUIVALENTS—End of period	-147	-136
Non-Guarantor Subsidiaries [Member]	'	'
Subsidiary Guarantors [Line Items]	'	'
Net cash flows provided by operating activities	16	9
Additions to property, plant and equipment	0	0
Purchase of intangible assets	0	0
Net cash provided by (used in) investing activities	0	0
Proceeds from long-term debt	0	0
Repayment of long-term debt	0	0
Proceeds from derivative contracts	0	0
Common unit issuance	'	0
Payments of Unit Issuance Costs	'	0
Distributions to members and affiliates	0	0
Net cash provided by (used in) financing activities	0	0
Net increase in cash and cash equivalents	16	9
CASH AND CASH EQUIVALENTS—Beginning of period	227	186
CASH AND CASH EQUIVALENTS—End of period	243	195
Consolidation, Eliminations [Member]	'	'
Subsidiary Guarantors [Line Items]	'	'
Net cash flows provided by operating activities	0	0
Additions to property, plant and equipment	0	0
Purchase of intangible assets	0	0
Net cash provided by (used in) investing activities	0	0
Proceeds from long-term debt	0	0
Repayment of long-term debt	0	0
Proceeds from derivative contracts	0	0
Common unit issuance	'	0
Payments of Unit Issuance Costs	'	0
Distributions to members and affiliates	0	0
Net cash provided by (used in) financing activities	0	0
Net increase in cash and cash equivalents	0	0
CASH AND CASH EQUIVALENTS—Beginning of period	0	0
CASH AND CASH EQUIVALENTS—End of period	$0	$0

Subsequent_Events_Assets_and_l

Subsequent Events Assets and liabilities held-for-sale (Details) (USD $)	Mar. 31, 2014
In Thousands, unless otherwise specified
Assets of Disposal Group, Including Discontinued Operation [Abstract]	'
Property, Plant, and Equipment, Net	$993,973
Accounts Receivable	136,966
Intangible Assets, Net	100,930
Other Assets	17,103
Total assets-held-for-sale	1,248,972
Liabilities of Disposal Group, Including Discontinued Operation [Abstract]	'
Long-term debt	545,433
Accounts Payable	151,181
Other Liabilities	19,123
Total liabilities held-for-sale	$715,737