Eagle Rock Energy Partners L P (EROC) 10-K 3 Mar 14 2013 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information Document (USD $)	12 Months Ended
	Dec. 31, 2013	Feb. 25, 2014	Jun. 30, 2013
Document 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-K	'	'
Document Period End Date	31-Dec-13	'	'
Document Fiscal Year Focus	'2013	'	'
Document Fiscal Period Focus	'FY	'	'
Amendment Flag	'false	'	'
Entity Common Stock, Shares Outstanding	'	159,405,268	'
Entity Well-known Seasoned Issuer	'Yes	'	'
Entity Voluntary Filers	'No	'	'
Entity Current Reporting Status	'Yes	'	'
Entity Public Float	'	'	$812,447,684

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Dec. 31, 2013		Dec. 31, 2012
In Thousands, unless otherwise specified
CURRENT ASSETS:	'		'
Cash and cash equivalents	$76		$25
Accounts receivable	145,963	[1]	138,732	[1]
Risk management assets, current	9,162		33,340
Prepayments and other current assets	8,183		9,867
Total current assets	163,384		181,964
Property, Plant and Equipment — Net	1,828,768		1,968,206
Intangible Assets — Net	105,620		111,515
Deferred Tax Asset	1,438		1,656
Risk Management Assets	5,461		7,953
Other Assets	22,879		22,922
Total assets	2,127,550		2,294,216
CURRENT LIABILITIES:	'		'
Accounts payable	170,124		160,473
Accrued liabilities	29,970		19,764
Taxes payable	149		46
Risk management liabilities	11,023		1,231
Total current liabilities	211,266		181,514
Long-term debt	1,252,062		1,153,103
Asset Retirement Obligations	45,849		44,814
Deferred Tax Liability	37,953		43,000
Risk Management Liabilities	3,848		1,700
Other long-term liabilities	2,693		1,711
Commitments and Contingencies (Note 13)	'		'
Members' Equity	573,879	[2]	868,374	[2]
Total liabilities and equity	$2,127,550		$2,294,216
[1]	Net of allowance for bad debt of $1,188 as of December 31, 2013 and $972 as of December 31, 2012.
[2]	156,644,153 and 144,675,751 common units were issued and outstanding as of December 31, 2013 and December 31, 2012, respectively. These amounts do not include unvested restricted common units granted under the Partnership's long-term incentive plan of 2,743,807 and 2,608,035 as of December 31, 2013 and December 31, 2012, respectively.

Consolidated_Balance_Sheets_Ba

Consolidated Balance Sheets Balance Sheet Parentheticals (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, except Share data, unless otherwise specified
Allowance for Doubtful Accounts Receivable, Current	1,188	972
Common Class A [Member]	'	'
Limited Partners' Capital Account, Units Issued	156,644,153	144,675,751
Limited Partners' Capital Account, Units Outstanding	156,644,153	144,675,751

Consolidated_Statements_of_Ope

Consolidated Statements of Operations (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Revenues:	'	'	'
Natural gas, natural gas liquids, oil, condensate, sulfur and helium sales	$1,129,333	$864,884	$977,952
Gathering, compression, processing and treating fees	83,659	56,831	47,770
Commodity risk management gains (losses), net	-18,533	57,894	32,510
Other revenue	820	4,350	1,676
Total revenue	1,195,279	983,959	1,059,908
COSTS AND EXPENSES:	'	'	'
Cost of natural gas, natural gas liquids, and condensate	790,618	532,719	633,184
Operations and maintenance	135,205	119,828	93,048
Taxes other than income	20,270	19,432	19,148
General and administrative	81,214	69,994	57,891
Other operating income	0	0	-2,893
Impairment	214,286	177,003	16,288
Depreciation, Depletion and Amortization	167,170	161,045	131,611
Total costs and expenses	1,408,763	1,080,021	948,277
OPERATING INCOME (LOSS)	-213,484	-96,062	111,631
OTHER INCOME (EXPENSE):	'	'	'
Interest expense, net	68,762	51,478	29,622
Interest rate risk management gains (losses), net	-1,104	-4,727	-11,401
Other (expense) income	257	-38	-184
Total other (expense) income	-69,609	-56,243	-41,207
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	-283,093	-152,305	70,424
Income Tax Expense (Benefit)	-5,114	-1,703	-2,432
INCOME (LOSS) FROM CONTINUING OPERATIONS	-277,979	-150,602	72,856
Discontinued operations, net of tax	0	0	276
Net income (loss)	($277,979)	($150,602)	$73,132
NET INCOME PER COMMON UNIT—BASIC AND DILUTED:	'	'	'
Net Income (loss) from continuing operations per common unit - basic	($1.82)	($1.13)	$0.65
Net Income (loss) from continuing operations per common units - diluted	($1.82)	($1.13)	$0.61
Discontinued operations per common unit - basic	$0	$0	$0
Discontinued operations per common unit - diluted	$0	$0	$0
Net income (loss) per common unit - basic	($1.82)	($1.13)	$0.65
Net income (loss) per common unit - diluted	($1.82)	($1.13)	$0.62
Weighted Average Number of Shares Outstanding Basic and Diluted	'	'	'
Weighted average common units outstanding - basic	153,562	135,609	110,435
Weighted Average common units outstanding - diluted	153,562	135,609	116,941

Consolidated_Statement_of_Memb

Consolidated Statement of Member's Equity (USD $)	Total	Common Class A [Member]	Common Units [Member]
In Thousands, except Share data, unless otherwise specified	USD ($)		USD ($)
Members' Equity - Beginning Balance at Dec. 31, 2010	$579,113	'	$579,113
Beginning Balance - Units Outstanding at Dec. 31, 2010	'	83,425,378	'
Increase (Decrease) in Members' Equity [Roll Forward]	'	'	'
Net income (loss)	73,132	'	73,132
Distributions	-74,512	'	-74,512
Vesting of restricted units - Units	'	608,122	'
Exercise of Warrants - Units	'	14,957,540	'
Exercise of Warrants	89,745	'	89,745
Repurchase of common units - Units	'	137,985	'
Repurchase of common units	-1,401	'	-1,401
Equity-based Compensation	5,145	'	5,145
Issuance costs for equity offerings	0	'	'
Units issued for acquisitions - Units	'	28,753,174	'
Units issued for acquisitions	336,125	'	336,125
Members' Equity - Ending Balance at Dec. 31, 2011	1,007,347	'	1,007,347
Ending Balance - Units Outstanding at Dec. 31, 2011	'	127,606,229	'
Increase (Decrease) in Members' Equity [Roll Forward]	'	'	'
Net income (loss)	-150,602	'	-150,602
Distributions	-119,211	'	-119,211
Vesting of restricted units - Units	'	1,101,323	'
Exercise of Warrants - Units	'	5,300,588	'
Exercise of Warrants	31,804	'	31,804
Repurchase of common units - Units	'	286,716	'
Repurchase of common units	-2,501	'	-2,501
Equity-based Compensation	9,882	'	9,882
Stock Issued During Period, Shares, New Issues	10,120,000	10,954,327	'
Stock Issued During Period, Value, New Issues	96,173	'	96,173
Issuance costs for equity offerings	-4,518	'	-4,518
Units issued for acquisitions	0	'	'
Members' Equity - Ending Balance at Dec. 31, 2012	868,374	'	868,374
Ending Balance - Units Outstanding at Dec. 31, 2012	'	144,675,751	'
Increase (Decrease) in Members' Equity [Roll Forward]	'	'	'
Net income (loss)	-277,979	'	-277,979
Distributions	-125,911	'	-125,911
Vesting of restricted units - Units	'	1,203,822	'
Exercise of Warrants - Units	'	0	'
Exercise of Warrants	0	'	0
Repurchase of common units - Units	'	272,179	'
Repurchase of common units	-1,858	'	-1,858
Equity-based Compensation	13,384	'	13,384
Stock Issued During Period, Shares, New Issues	10,350,000	11,036,759	'
Stock Issued During Period, Value, New Issues	102,388	'	102,388
Issuance costs for equity offerings	-4,519	'	-4,519
Units issued for acquisitions	0	'	'
Members' Equity - Ending Balance at Dec. 31, 2013	$573,879	'	$573,879
Ending Balance - Units Outstanding at Dec. 31, 2013	'	156,644,153	'

Consolidated_Statements_of_Cas

Consolidated Statements of Cash Flows (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
CASH FLOWS FROM OPERATING ACTIVITIES:	'	'	'
Net income (loss)	($277,979)	($150,602)	$73,132
Adjustments to reconcile net (loss) income to net cash provided by operating activities:	'	'	'
Discontinued operations, net of tax	0	0	-276
Depreciation, Depletion and Amortization	167,170	161,045	131,611
Impairment	214,286	177,003	16,288
Amortization of debt issuance costs	4,465	3,483	2,415
Loss (gain) from risk management activities, net	19,322	-53,387	-21,573
Derivative settlements	17,965	27,068	-43,937
Equity-based compensation	13,384	9,882	5,145
Loss (gain) of sale of assets	-190	-28	166
Other operating income	0	0	-2,893
Other	-80	-703	-929
Changes in assets and liabilities—net of acquisitions:	'	'	'
Accounts receivable	-7,102	-39,823	-5,418
Prepayments and other current assets	1,684	3,872	-7,976
Risk management activities	0	-7,664	-25,510
Accounts payable	29,750	16,087	-2,067
Accrued liabilities	952	1,437	1,878
Other assets	-4,111	575	-1,216
Other current liabilities	-2,140	-2,744	-1,040
Net cash provided by (used in) operating activities	177,376	145,501	117,800
CASH FLOWS FROM INVESTING ACTIVITIES:	'	'	'
Additions to property, plant and equipment	-243,430	-306,024	-154,916
Acquisitions, net of cash acquired	0	-230,640	-220,326
Proceeds from sale of asset	285	15,398	5,712
Purchase of intangible assets	-3,903	-7,404	-4,406
Net cash provided by (used in) investing activities	-247,048	-528,670	-373,936
CASH FLOWS FROM FINANCING ACTIVITIES:	'	'	'
Proceeds from long-term debt	601,400	1,043,750	964,279
Repayment of long-term debt	-503,100	-916,750	-1,012,779
Proceeds from Senior Notes	0	246,253	297,837
Payment of debt issuance costs	0	-7,132	-17,466
Proceeds from derivative contracts	1,323	14,449	6,267
Common unit issued in equity offerings	102,388	96,173	0
Issuance costs for equity offerings	-4,519	-4,518	0
Exercise of Warrants	0	31,804	89,745
Repurchase of common units	1,858	2,501	1,401
Distributions to members and affiliates	-125,911	-119,211	-74,512
Net cash provided by (used in) financing activities	69,723	382,317	251,970
CASH FLOWS FROM DISCONTINUED OPERATIONS:	'	'	'
Operating activities from discontinued operations	0	0	994
Net cash provided by (used in) discontinued operations	0	0	994
Net increase in cash and cash equivalents	51	-852	-3,172
CASH AND CASH EQUIVALENTS—Beginning of period	25	877	4,049
CASH AND CASH EQUIVALENTS—End of period	76	25	877
NONCASH INVESTING AND FINANCING ACTIVITIES:	'	'	'
Units issued for acquisitions	0	0	336,125
Investments in property, plant and equipment, not paid	9,469	29,568	31,374
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:	'	'	'
Interest paid—net of amounts capitalized	65,309	45,614	24,682
Cash paid for taxes	$59	$1,085	$1,516

Organization_and_Description_o

Organization and Description of Business	12 Months Ended
	Dec. 31, 2013
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, and its 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 in the United States, primarily in South Alabama (where it also operates the associated gathering and processing assets), Texas, Oklahoma 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 became wholly-owned subsidiaries of the Partnership on July 30, 2010. The transaction with Eagle Rock Energy GP, L.P. was accounted for by the Partnership as a recapitalization. The acquisition of Eagle Rock Energy G&P, LLC was accounted for as an acquisition of entities under common control, which requires the Partnership to present its financial statements as if the two entities had always been combined, similar to the pooling of interests method.
	Recent Developments—On December 23, 2013, the Partnership announced that it had entered into a definitive agreement to contribute its Midstream Business 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 and a combination of cash and assumed debt, subject to certain closing conditions. As part of this transaction, Regency will conduct 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 transaction is subject to the approval of the Partnership's unitholders, Hart-Scott-Rodino Antitrust Improvements Act of 1976 approval and other customary closing conditions.
	As the sale of the Midstream Business is conditioned upon the approval of the Partnership's common unitholders, 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	12 Months Ended
	Dec. 31, 2013
Accounting Policies [Abstract]	'
Summary of Significant Accounting Policies	'
	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
	Basis of Presentation and Principles of Consolidation—The accompanying audited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (GAAP). 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 consolidated financial statements.
	Use of Estimates—The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reported period. Significant estimates are required for proved oil and natural gas reserves, which can affect the carrying value of oil and natural gas properties. The Partnership evaluates its estimates and assumptions on a regular basis. The Partnership bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results could differ from those estimates and such differences could be material.
	Cash and Cash Equivalents—Cash and cash equivalents include certificates of deposit and other highly liquid investments with maturities of three months or less at the time of purchase.
	Concentration and Credit Risk—Concentration and credit risk for the Partnership principally consists of cash and cash equivalents and accounts receivable.
	The Partnership places its cash and cash equivalents with high-quality institutions and in money market funds. The Partnership derives its revenue from customers primarily in the natural gas industry. Industry concentrations have the potential to impact the Partnership's overall exposure to credit risk, either positively or negatively, in that the Partnership's customers could be affected by similar changes in economic, industry or other conditions. However, the Partnership believes the risk posed by this industry concentration is offset by the creditworthiness of the Partnership's customer base. The Partnership's portfolio of accounts receivable is comprised primarily of mid-size to large domestic corporate entities.
	The following is the activity within the Partnership's allowance for doubtful accounts during the years ended December 31, 2013, 2012 and 2011.
		2013			2012			2011
	($ in thousands)
	Balance at beginning of period	$	972		$	1,347		$	4,496
	Charged to bad debt expense	291			58			54
	Write-offs/adjustments charged to allowance	(75		)	(433		)	(3,203		)
	Balance at end of period	$	1,188		$	972		$	1,347
	During the year ended December 31, 2011, the write off charged to the allowance related to the payment the Partnership received related to the sale of its 503(b)(9) claims related to SemGroup, L.P. ("SemGroup"). This amount relates to the non-503(b)(9) claims and the portion of the receivables sold in August 2009 (see Note 20 for further discussion).
	Certain Other Concentrations—The Partnership relies on natural gas producers for its Midstream Business's natural gas and natural gas liquid supply, with the top two producers (by segment) accounting for 36% of its natural gas supply in the Texas Panhandle Segment and 25% of its natural gas supply in the East Texas and Other Midstream Segment for the year ended December 31, 2013. While there are numerous natural gas and natural gas liquid producers, and some of these producers are subject to long-term contracts, the Partnership may be unable to negotiate extensions or replacements of these contracts on favorable terms, if at all. If the Partnership were to lose all or even a portion of the natural gas volumes supplied by these producers and was unable to acquire comparable volumes, the Partnership's results of operations and financial position could be materially adversely affected. These percentages are calculated based on natural gas volumes gathered during the year ended December 31, 2013. For the year ended December 31, 2013, Oneok, Inc. and Chevron Corporation, the Partnership's largest customers, represented 22% and 11%, respectively, of its total sales revenue (including its commodity risk management gains and losses).
	Inventory—Inventory is stated at the lower of cost or market, with cost being determined using the average cost method. At December 31, 2013 and December 31, 2012, the Partnership had $1.0 million and $0.8 million, respectively, of crude oil finished goods inventory which is recorded as part of Other Current Assets within the audited consolidated balance sheet.
	Property, Plant and Equipment—Property, plant and equipment consists primarily of gas gathering systems, gas processing plants, NGL pipelines, conditioning and treating facilities and other related facilities, and oil and natural gas properties, which are carried at cost less accumulated depreciation, depletion and amortization. The Partnership charges repairs and maintenance against income when incurred and capitalizes renewals and betterments, which extend the useful life or expand the capacity of the assets. The Partnership capitalizes interest costs on major projects during extended construction time periods. Such interest costs are allocated to property, plant and equipment and amortized over the estimated useful lives of the related assets. The Partnership calculates depreciation on the straight-line method over estimated useful lives of the Partnership's newly developed or acquired assets. The weighted average useful lives are as follows:
	Plant Assets	20 years
	Pipelines and equipment	20 years
	Gas processing and equipment	20 years
	Office furniture and equipment	5 years
	Oil and Natural Gas Properties—The Partnership utilizes the successful efforts method of accounting for its oil and natural gas properties. Leasehold costs are capitalized when incurred. Costs incurred to drill and complete development wells are capitalized. Geological and geophysical expenses and delay rentals are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if the well is determined to be unsuccessful. The Partnership carries the costs of an exploratory well as an asset if the well is found to have a sufficient quantity of reserves to justify its capitalization as a producing well as long as the Partnership is making sufficient progress towards assessing the reserves and the economic and operating viability of the project.
	Depletion of producing oil and natural gas properties is recorded based on units of production. Unit rates are computed for unamortized drilling and development costs using proved developed reserves and for acquisition costs using all proved reserves. Authoritative guidance requires that acquisition costs of proved properties be amortized on the basis of all proved reserves (developed and undeveloped), and that capitalized development costs (wells and related equipment and facilities) be amortized on the basis of proved developed reserves.
	Upon sale or retirement of complete fields of depreciable or depleted property, the book value thereof, less proceeds or salvage value, is charged or credited to income.
	Costs related to unproved properties include costs incurred to acquire unproved reserves.  Because these reserves do not meet the definition of proved reserves, the related costs are not classified as proved properties.  Unproved leasehold costs are capitalized and amortized on a composite basis if individually insignificant, based on past success, experience, drilling plans and average lease-term lives.  Unamortized leasehold costs related to successful exploratory drilling are reclassified to proved properties and depleted on a units of production basis.  Unproved properties (both individually significant and insignificant) are assessed periodically within specific geographic areas and, if necessary, impairments are charged to expense.
	Other Assets— As of December 31, 2013, other assets primarily consist of costs associated with debt issuance costs, net of amortization, of $15.4 million; business deposits to various providers and state or regulatory agencies of $6.5 million; and investment in unconsolidated affiliates of $0.9 million. As of December 31, 2012, other assets primarily consist of costs associated with debt issuance costs, net of amortization, of $19.5 million; business deposits to various providers and state or regulatory agencies of $2.2 million; and investment in unconsolidated affiliates of $0.9 million.
	Impairment of Long-Lived Assets—Management evaluates whether the carrying value of non-oil and natural gas long-lived assets has been impaired when circumstances indicate the carrying value of those assets may not be recoverable. This evaluation is based on undiscounted cash flow projections. The carrying amount is not recoverable if it exceeds the undiscounted sum of cash flows expected to result from the use and eventual disposition of the assets. Management considers various factors when determining if these assets should be evaluated for impairment, including, but not limited to:
	•	significant adverse changes in legal factors or in the business climate;
	•	a current-period operating or cash flow loss combined with a history of operating or cash flow losses or a projection or forecast which demonstrates continuing losses associated with the use of a long-lived asset;
	•	an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of a long-lived asset;
	•	significant adverse changes in the extent or manner in which an asset is used or in its physical condition;
	•	a significant change in the market value of an asset; or
	•	a current expectation that, more likely than not, an asset will be sold or otherwise disposed of before the end of its estimated useful life.
	For its oil and natural gas long-lived assets, the Partnership reviews its proved properties at the field level when management determines that events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. Such events include a negative revision or unfavorable projection of future oil and natural gas reserves and/or forward prices that will be produced from a field, the timing of this future production, future costs to produce the oil and natural gas, and future inflation levels.
	If the carrying value is not recoverable on an undiscounted basis, the impairment loss is measured as the excess of the asset's carrying value over its fair value. Management assesses the fair value of long-lived assets using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales, internally developed discounted cash flow analysis and analysis from outside advisors. Significant changes in market conditions resulting from events such as the condition of an asset or a change in management's intent to utilize the asset would generally require management to reassess the cash flows related to the long-lived assets.
	See Note 5 for further discussion on impairment charges.
	Revenue Recognition—Eagle Rock Energy's primary types of sales and service activities reported as operating revenue include:
	•	sales of natural gas, NGLs, crude oil, condensate and sulfur;
	•	natural gas gathering, processing and transportation, from which Eagle Rock Energy 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 and sulfur are recognized when title passes to the customer, which is when the risk of ownership passes to the customer and physical delivery occurs. Revenues 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. Imbalances are reflected as adjustments to reported natural gas reserves and future cash flows.  For the Upstream Segment, as of December 31, 2013 and December 31, 2012, the Partnership had long-term imbalance payables of $0.3 million and $0.6 million, 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 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 December 31, 2013, the Partnership had imbalance receivables totaling $0.7 million and imbalance payables totaling $1.6 million. For the Midstream Business, as of December 31, 2012, the Partnership had imbalance receivables totaling $0.9 million and imbalance payables totaling $2.1 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.
	Environmental Expenditures—Environmental expenditures are expensed or capitalized as appropriate, depending upon the future economic benefit. Expenditures which relate to an existing condition caused by past operations and do not generate current or future revenue are expensed. Liabilities for these expenditures are recorded on an undiscounted basis when environmental assessments and/or clean-ups are probable and the costs can be reasonably estimated.
	Income Taxes—Provision for income taxes is primarily applicable to the Partnership's state tax obligations under the Revised Texas Franchise Tax (the “Revised Texas Franchise Tax”) and certain federal and state tax obligations of Eagle Rock Energy Acquisition Co., Inc., Eagle Rock Acquisition Co. II, Inc., Eagle Rock Upstream Development Company, Inc. and Eagle Rock Upstream Development Company II, Inc., all of which are consolidated subsidiaries. Deferred income tax assets and liabilities are recognized for temporary differences between the assets and liabilities of the tax paying entities for financial reporting and tax purposes.
	In general, legal entities that conduct business in Texas are subject to the Revised Texas Franchise Tax. In May 2006, the State of Texas expanded its pre-existing franchise tax to include limited partnerships, limited liability companies, corporations and limited liability partnerships. As a result of the change in tax law, the Partnership's tax status in the State of Texas changed from non-taxable to taxable effective with the 2007 tax year.
	Since the Partnership is structured as a pass-through entity, it is not subject to federal income taxes. As a result, its partners are individually responsible for paying federal and certain income taxes on their share of the Partnership's taxable income. Since the Partnership does not have access to information regarding each partner's tax basis, it cannot readily determine the total difference in the basis of the Partnership's net assets for financial and tax reporting purposes.
	Derivatives—Authoritative guidance establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. It requires an entity to recognize all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. The guidance provides that normal purchase and sale contracts, when appropriately designated, are not subject to the guidance. Normal purchases and sales are contracts which provide for the purchase or sale of something, other than a financial instrument or derivative instrument that will be delivered in quantities expected to be used or sold by the reporting entity over a reasonable period in the normal course of business. The Partnership's forward natural gas and crude oil purchase and sales contracts are designated as normal purchases and normal sales, with the exception of certain contracts with our 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 consolidated balance sheet at the instrument's fair value with changes in fair value reflected in the consolidated statement of operations, as the Partnership has not designated any of these derivative instruments as hedges. The cash flows from derivatives are reported as cash flows from operating activities unless the derivative contract is deemed to contain a financing element. Derivatives deemed to contain a financing element are reported as a financing activity in the statement of cash flows. See Note 11 for a description of the Partnership's risk management activities.
	Other Reclassifications—The prior period within the audited 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	12 Months Ended
	Dec. 31, 2013
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]	'
New Accounting Pronouncements	'
	NEW ACCOUNTING PRONOUNCEMENTS
	In December 2011, the FASB issued new guidance related to disclosure requirements about the nature of an entity's rights of set-off and related arrangements associated with its financial instruments and derivative instruments. The new disclosures are designed to make financial statements that are prepared under U.S. GAAP more comparable to those prepared under IFRS. To better facilitate comparison between financial statements prepared under U.S. GAAP and IFRS, the new disclosures will give financial statement users information about both gross and net exposures. The disclosure requirements are effective for annual reporting periods beginning on or after January 1, 2013, and did not have a material impact on the Partnership's financial statements for the year ended December 31, 2013. See Notes 11 and 12 for the disclosures related to the Partnership's rights of set-off and the gross and net exposure related to its derivative instruments.
	In February 2013, the 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 is not expected to have a material impact on the Partnership’s consolidated financial statements.

Acquisitions

Acquisitions	12 Months Ended
	Dec. 31, 2013
Business Combinations [Abstract]	'
Acquisitions	'
	ACQUISITIONS
	Acquisition of Midstream Assets in the Texas Panhandle
	On October 1, 2012, the Partnership completed the acquisition of two of BP America Production Company's ("BP") gas processing facilities, and the associated gathering systems, that are located in the Texas Panhandle. The aggregate purchase price of the system was $230.6 million, which the Partnership funded from borrowings under its revolving credit facility. The results of the operations of the system have been included in the consolidated financial statements since the acquisition date. The Partnership incurred $0.5 million of acquisition related expenses, which are included within general and administrative expenses for the year ended December 31, 2012. The Partnership incurred $0.1 million of acquisition related expenses, which are included within general and administrative expenses for the year ended December 31, 2013.
	This acquisition was accounted for under the acquisition method of accounting. Accordingly, the Partnership conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while transaction and integration costs associated with the acquisitions were expensed as incurred. The initial accounting for the business combinations is not complete and adjustments to provisional amounts, or recognition of additional assets acquired or liabilities assumed, may occur as more detailed analyses are completed and additional information is obtained about the facts and circumstances that existed as of the acquisition dates.
	The following presents the purchase price allocation for the system assets, based on estimates of fair value (in thousands):
	Current assets	$	779
	Property, plant, and equipment	206,849
	Rights-of-way and easements	27,232
	Current liabilities	(1,705		)
	Asset retirement obligations	(2,600		)
		$	230,555
	The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair value of property, plant and equipment, rights-of-way and easements and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of property, plant and equipment include estimates of: (i) replacement costs; (ii) useful and remaining lives; (iii) physical deterioration; and (iv) functional and technical obsolescence. These inputs require significant judgments and estimates by the Partnership's management at the time of the valuation and are the most sensitive and subject to change.
	Pro forma data for the years ended December 31, 2012 and 2011 has been deemed to be impracticable as BP did not separately manage its gathering and processing facilities with the activities of the acquired assets being integrated (financially and operationally) within its exploration and production segment. The amounts of revenue and net income generated by the acquired processing plants and gathering systems that are included within the Partnership's audited consolidated statement of operations for the year ended December 31, 2012 are as follows.
		Revenue			Net Income
		($ in thousands)
	Actual from October 1, 2012 to December 31, 2012	$	81,013		$	5,057
	Acquisition of CC Energy II L.L.C.
	On May 3, 2011, the Partnership completed the acquisition (the "Mid-Continent Acquisition") of all of the outstanding membership interests of CC Energy II L.L.C (together with its subsidiaries, "Crow Creek Energy"), a portfolio company of Natural Gas Partners, VIII, L.P. ("NGP VIII"). Crow Creek Energy has oil and natural gas properties located in multiple basins across Oklahoma, north Texas and Arkansas (the "Mid-Continent" properties) and provides the Partnership with an extensive inventory of low-risk development prospects in established plays such as the Golden Trend field and developing plays such as the Cana Shale. The aggregate purchase price has been calculated as follows (in thousands, except unit and per unit amounts):
	Number of Partnership Common Units Issued	28,753,174
	Closing common unit price on May 3, 2011	$	11.69
	Value of common units issued	$	336,125
	Crow Creek Energy outstanding debt assumed	212,638
	Cash	14,945
	Total purchase price	$	563,708
	The number of common units of the Partnership issued was determined based on the value of the equity issued to the sellers of $301.9 million divided by $10.50, the ceiling price of the agreed upon range in the contribution agreement between the Partnership and Crow Creek Energy. The cash portion of the acquisition consideration and the repayment of Crow Creek Energy’s outstanding debt were funded through borrowings under the Partnership’s revolving credit facility. In addition, the Partnership incurred $2.3 million of acquisition related expenses, which are included within general and administrative expenses for the year ended December 31, 2011.
	This acquisition was accounted for under the acquisition method of accounting. Accordingly, the Partnership conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while transaction and integration costs associated with the acquisitions were expensed as incurred.
	The following presents the purchase price allocation for the Crow Creek Energy assets, based on estimates of fair value (in thousands):
	Current assets	$	25,329
	Oil and gas properties	572,097
	Property, plant and equipment	4,463
	Rights-of-way and easements	3,192
	Other assets	450
	Derivatives	3,355
	Current liabilities	(37,032		)
	Asset retirement obligations	(4,394		)
	Deferred tax liability	(2,312		)
	Other liabilities	(1,440		)
		$	563,708
	The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair value of oil and natural gas properties and asset retirement obligation were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties include estimate of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; (iv) estimated future cash flows; and (v) a market-based weighted average cost of capital rate. These inputs require significant judgments and estimates by the Partnership's management at the time of the valuation and are the most sensitive and subject to change.
	The amounts of Crow Creek Energy's revenue and net income included within the Partnership's audited consolidated statement of operations for the year ended December 31, 2011, and the pro forma revenue and net income of the combined entity had the acquisition date been January 1, 2010, are as follows:
		Revenue			Net Income		Net Income Per Diluted Common Unit
		($ in thousands)
	Actual from May 3, 2011 to December 31, 2011	$	68,168		$	29,835
	Supplemental pro forma from January 1, 2011 to December 31, 2011	$	1,080,964		$	78,591	$	0.62

Property_Plant_and_Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2013
Property, Plant and Equipment [Abstract]	'
Property, Plant and Equipment Disclosure	'
	PROPERTY PLANT AND EQUIPMENT
	Fixed assets consisted of the following:
		December 31,			December 31,
		2013			2012
		($ in thousands)
	Land	$	2,877		$	2,876
	Plant	521,103			444,023
	Gathering and pipeline	777,446			753,009
	Equipment and machinery	53,999			39,889
	Vehicles and transportation equipment	4,001			4,021
	Office equipment, furniture, and fixtures	1,309			1,285
	Computer equipment	14,806			11,431
	Linefill	5,180			4,328
	Proved properties	1,156,896			1,213,622
	Unproved properties	10,022			31,823
	Construction in progress	33,824			60,870
		2,581,463			2,567,177
	Less: accumulated depreciation, depletion and amortization	(752,695		)	(598,971		)
	Net property plant and equipment	$	1,828,768		$	1,968,206
	The following table sets forth the total depreciation, depletion, capitalized interest costs and impairment expense by type of asset within the Partnership's audited consolidated statements of operations:
		Year Ended December 31,
		2013			2012			2011
		($ in thousands)
	Depreciation	$	69,449		$	61,390		$	54,606
	Depletion	$	87,230		$	88,413		$	65,380
	Capitalized interest costs	$	963		$	1,311		$	451
	Impairment expense:
	Proved properties (a)	$	207,085		$	38,943		$	11,239
	Unproved properties (b)	$	7,201		$	785		$	489
	Plant assets (c)	$	—		$	57,527		$	4,560
	Pipeline assets (c)	$	—		$	52,537		$	—
	__________________________________
	(a)	During the year ended December 31, 2013, the Partnership incurred impairment charges in its Upstream Business related primarily to certain proved properties, primarily in the Cana Shale in the Mid-Continent region and the Permian region, due to lower reserve forecasts. During the year ended December 31, 2012, the Partnership incurred impairment charges in its Upstream Business related to its proved properties in the Barnett Shale, East Texas and Permian regions that experienced reduced cash flows resulting from lower natural gas prices and continuing high operating costs associated with gas compression. During the year ended December 31, 2011, the Partnership incurred impairment charges in its Upstream Business related to certain proved properties in the Jourdanton field in South Texas, which included plans for five future drilling locations that the Partnership has determined not to pursue due to the current natural gas price environment.
	(b)	During the year ended December 31, 2013, the Partnership incurred impairment charges in its Upstream Business related to certain leaseholds in the Mid-Continent regions that we expect to expire undrilled in 2014. During the year ended December 31, 2012, the Partnership incurred impairment charges in its Upstream Business related to certain unproved property leaseholds expected to expire undrilled in 2013. During the year ended December 31, 2011, the Partnership incurred impairment charges related to certain drilling locations in its unproved properties which the Partnership no longer intends to develop based on the performance of offsetting wells.
	(c)	During the year ended December 31, 2012, the Partnership incurred impairment charges in its Midstream Business related to certain plants and pipelines in its East Texas and Other Midstream Segment due to (i) reduced throughput volumes as its producer customers curtailed their drilling activity in response to the continued depressed natural gas price environment (ii) the loss of significant gathering contracts on its Panola and other systems and (iii) the substantial damage incurred at the Yscloskey processing plant as a result of Hurricane Isaac in August 2012. The value of assets for both the Panola system and the Yscloskey plant have been fully written down. During the year ended December 31, 2011, the Partnership recorded an impairment charge in its Texas Panhandle Segment to fully write-down its idle Turkey Creek plant.

Asset_Retirement_Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2013
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. For its producing oil and natural gas properties, the Partnership makes estimates of property abandonment costs that, in some cases, will not be incurred until a substantial number of years in the future. Such cost estimates could be subject to significant revisions in subsequent years due to increases in current abandonment costs, changes in regulatory requirements, technological advances and other factors that may be difficult to predict. The Partnership recognizes asset retirement obligations for its midstream assets in accordance with the term “conditional asset retirement obligation,” which refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional upon a future event that may or may not be within the Partnership's control. Although uncertainty about the timing and/or method of settlement may exist and may be conditional upon a future event, the obligation to perform the asset retirement activity is unconditional. Accordingly, the Partnership is required to recognize a liability for the fair value of a conditional asset retirement obligation upon initial recognition if the fair value of the liability can be reasonably estimated. The fair value of additions to the asset retirement obligations is estimated using valuation techniques that covert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of (i) remediation costs, (ii) remaining lives, (iii) future inflation factors and (iv) a credit-adjusted risk free interest rate.
	A reconciliation of the Partnership's liability for asset retirement obligations is as follows:
		2013			2012			2011
		($ in thousands)
	Asset retirement obligations—January 1	$	48,755		$	33,303		$	24,711
	Additional liabilities	1,140			1,721			159
	Liabilities settled	(2,240		)	(2,755		)	(465		)
	Revision to liabilities	7,603			11,471			2,339
	Additional liability related to acquisitions	—			2,650			4,413
	Accretion expense	3,706			2,365			2,146
	Asset retirement obligations—December 31 (a)	$	58,964		$	48,755		$	33,303
	_____________________________________
	(a)    As of December 31, 2013 and 2012, $13.1 million and $3.9 million , respectively, were included within accrued liabilities in the Consolidated Balance Sheets.

Intangible_Assets

Intangible Assets	12 Months Ended
	Dec. 31, 2013
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 period for contracts ranges from 5 to 20 years.  Intangible assets consisted of the following:
		December 31,			December 31,
		2013			2012
		($ in thousands)
	Rights-of-way and easements—at cost	$	131,088		$	127,375
	Less: accumulated amortization	(36,228		)	(29,959		)
	Contracts	22,742			38,009
	Less: accumulated amortization	(11,982		)	(23,910		)
	Net intangible assets	$	105,620		$	111,515
	The following table sets forth the total amortization and impairment expense by type of intangible assets within the Partnership's audited consolidated statements of operations:
		Year Ended December 31,
		2013			2012			2011
		($ in thousands)
	Amortization	$	10,078		$	11,205		$	11,588
	Impairment expense:
	Rights-of-way (a)	$	—		$	5,266		$	—
	Contracts (a)	$	—		$	16,384		$	—
	_____________________________________
	(a)	During the year ended December 31, 2012, the Partnership incurred impairment charges in its Midstream Business related to certain rights-of-way and contracts in its East Texas and Other Midstream Segment due to (i) reduced throughput volumes as its producer customers curtailed their drilling activities due to the continued decline in natural gas prices during the first three months of 2012 and (ii) the termination of significant gathering contracts on its Panola system during the year ended December 31, 2012. The value of the contracts and rights-of-way related to the Panola system have been fully written down.
	Estimated future amortization expense related to the intangible assets at December 31, 2013, is as follows (in thousands):
	Year ending December 31,
	2014	$	7,958
	2015	$	7,957
	2016	$	7,957
	2017	$	7,956
	2018	$	7,955
	Thereafter	$	65,837

Long_Term_Debt

Long Term Debt	12 Months Ended
	Dec. 31, 2013
Long-term Debt, by Current and Noncurrent [Abstract]	'
Long-term Debt [Text Block]	'
	LONG-TERM DEBT
	Long-term debt consisted of the following:
		December 31,				December 31,
		2013				2012
		($ in thousands)
	Revolving credit facility:	$	706,800			$	608,500
	Senior notes:
	8.375% senior notes due 2019	550,000				550,000
	Unamortized bond discount	(4,738		)		(5,397		)
	Total senior notes	545,262				544,603
	Total long-term debt	$	1,252,062			$	1,153,103
	Revolving Credit Facility
	On June 22, 2011, the Partnership entered into an Amended and Restated Credit Agreement, as amended on December 28, 2012 (the “Credit Agreement”) with Wells Fargo Bank, National Association, as administrative and documentation agent and swingline lender, Bank of America, N.A. and The Royal Bank of Scotland plc, as co-syndication agents, and the other lenders who are parties to the Credit Agreement. The Credit Agreement amended and restated the Partnership’s prior $1.2 billion Credit Agreement (the “Prior Credit Agreement”). Upon the effectiveness of the Credit Agreement, all commitments of the lenders party to the Prior Credit Agreement were terminated and all loans and other indebtedness of the Partnership under the Prior Credit Agreement were renewed and extended, inclusive of new lender commitments, on the terms and conditions of the Credit Agreement. The Credit Agreement matures on June 22, 2016.
	In connection with the Credit Agreement, the Partnership incurred debt issuance costs of $9.8 million and recorded a charge of $0.4 million to write off a portion of the unamortized debt issuance costs related to the Prior Credit Agreement. As of December 31, 2013, the Partnership had unamortized debt issuance costs of $5.2 million.
	On December 28, 2012, the Partnership received increased commitments from its lending group under the Credit Agreement. Aggregate commitments increased from $675 million to $820 million. The Partnership has the option to request further increases in commitments, subject to the terms and conditions of the Credit Agreement, up to an aggregate total amount of $1.2 billion. Availability under the credit facility is subject to a borrowing base comprised of two components: the upstream component and the midstream component. The upstream component of the borrowing base is determined semi-annually as an amount equal to the loan value of the proved oil and gas reserves of the Partnership and its subsidiaries as determined by the lenders party to the Credit Agreement. The midstream component of the borrowing base is determined quarterly as an amount equal to the lesser of (i) 55% of the total borrowing base (subject to increase for certain periods following certain material acquisitions up to 60% of the total borrowing base) and (ii) 3.75 times Consolidated EBITDA (as defined in the Credit Agreement) attributable to the midstream assets of the Partnership and its subsidiaries for the trailing four fiscal quarters. Pro forma adjustments to each component of the borrowing base, and thus total availability under the credit facility, are made upon the occurrence of certain events including material acquisitions and dispositions. Availability under the Credit Agreement is based on the lower of the current borrowing base and the total commitments. As of December 31, 2013, the Partnership had approximately $49.2 million of availability under the credit facility based on its borrowing base on that date. The Partnership currently pays a 0.50% commitment fee (based on the Partnership's borrowing base utilization percentage) per year on the difference between total commitments and the amount drawn under the credit facility. The Credit Agreement includes a sub-limit for the issuance of standby letters of credit for a total of $150.0 million. As of December 31, 2013, the Partnership had $19.2 million of outstanding letters of credit.
	At the Partnership's election, interest will accrue on the credit facility at either LIBOR plus a margin ranging from 1.75% to 2.75% (currently 2.50% per annum based on the Partnership's borrowing base utilization percentage) or the base rate plus a margin ranging from 0.75% to 1.75% (currently 1.50% per annum based on the Partnership's borrowing base utilization percentage). The applicable margin is determined based on the utilization of the then existing borrowing base. The borrowings under the Credit Agreement may be prepaid, without any premium or penalty, at any time. The base rate is generally the highest of the federal funds rate plus 0.5%, the prime rate as announced from time to time by the Administrative Agent, or daily LIBOR for a term of one month plus 1.0%. As of December 31, 2013, the weighted average interest rate (excluding the impact of interest rate swaps) on the Partnership's outstanding debt under its revolving credit facility was 2.67%.
	The obligations under the Credit Agreement are secured by first priority liens on substantially all of the Partnership’s (and its material subsidiaries') material assets, including a pledge of all of the equity interests of each of the Partnership’s material subsidiaries.
	The Credit Agreement requires the Partnership and certain of its subsidiaries to make certain representations and warranties that are customary for credit facilities of this type. The Credit Agreement also contains affirmative and negative covenants that are customary for credit facilities of this type, including compliance with financial covenants. The financial covenants prohibit the Partnership from exceeding defined limits with respect to:
	•	As of any fiscal quarter-end, the ratio of Consolidated EBITDA (as defined in the Credit Agreement) for the four fiscal quarter period ending with such fiscal quarter to Consolidated Interest Expense (as defined in the Credit Agreement) for such four fiscal quarter period (the "Interest Coverage Ratio").;
	•	As of any fiscal quarter-end, the ratio of Total Funded Indebtedness (as defined in the Credit Agreement) to Consolidated EBITDA for the four fiscal quarter period ending with such fiscal quarter (the “Total Leverage Ratio”).;
	•	As of the fiscal quarter-end for the fiscal quarters ending December 31, 2013 through September 30, 2014, the ratio of Senior Secured Debt (as defined in the Credit Agreement) to Consolidated EBITDA for the four fiscal quarter period ending with such fiscal quarter (the “Senior Secured Leverage Ratio”).; and
	•	As of any fiscal quarter-end the ratio of the Partnership’s consolidated current assets (including availability under the Credit Agreement up to the Loan Limit (as defined within the Credit Agreement), but excluding non-cash assets under the accounting guidance for derivatives) to consolidated current liabilities (excluding non-cash obligations under the accounting guidance for derivatives and current maturities under the Credit Agreement) (the “Current Ratio”).
	The following table presents the debt covenant levels specified in our revolving credit facility as of December 31, 2013:
	Quarter Ended	Total Leverage Ratio	Senior Secured Leverage Ratio	Interest Coverage Ratio	Current Ratio
	31-Dec-13	5.5	3.15	2.5	1
	31-Mar-14	5.25	3.1	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	NA	2.5	1
	The following table presents the Partnership's actual covenant ratios as of December 31, 2013:
	Interest coverage ratio	3.1
	Total leverage ratio	5.4
	Senior secured leverage ratio	3.06
	Current ratio	1.1
	As of December 31, 2013, the Partnership was in compliance with the financial covenants under the Credit Agreement.  The Partnership expects compliance with financial covenants under the Credit Agreement through 2014 because the Midstream Business Contribution to Regency will substantially improve the Partnership’s liquidity and debt ratios through the elimination of significant debt currently outstanding under our revolving credit facility and the proposed assumption of all of it's senior unsecured notes via an exchange offer to be conducted by Regency. The completion of the Midstream Business Contribution is subject to regulatory and unitholder approvals. As a result, the Partnership can provide no assurance that the Midstream Business Contribution will be completed within its anticipated time frame, or at all. 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.
	On February 26, 2014, the Partnership and its lender group amended the Credit Agreement to, among other items, allow for a temporary step-up in the Total Leverage Ratio and Senior Secured Leverage Ratio, and allow for additional liquidity at its election. For a further discussion of the Credit Agreement amendment, see Note 22.
	Senior Notes
	On May 27, 2011, the Partnership, along with its subsidiary, Eagle Rock Energy Finance Corp. ("Finance Corp"), as co-issuer and certain subsidiary guarantors, issued $300.0 million of senior unsecured notes (the "Senior Notes"), that bear a coupon of 8.375%, through a private placement. The Senior Notes will mature on June 1, 2019, and interest is payable on each June 1 and December 1, commencing December 1, 2011. After the original discount of $2.2 million and excluding related offering expenses, the Partnership received net proceeds of approximately $297.8 million, which were used to repay borrowings outstanding under the Prior Credit Agreement.
	On July 13, 2012, the Partnership, along with its subsidiary, Finance Corp, as co-issuer and certain subsidiary guarantors, completed the sale of an additional $250.0 million of 8.375% senior unsecured notes due 2019 through a private placement exempt from the registration requirements of the Securities Act of 1933. After the original issue discount of $3.7 million and excluding related offering expenses, the Partnership received net proceeds of approximately $246.3 million, which were used to repay borrowings outstanding under its revolving credit facility. This issuance supplemented the Partnership's prior $300.0 million of Senior Notes issued in May 2011, all of which are treated as a single series. As of December 31, 2013, the Partnership had unamortized debt issuance costs of $10.3 million and an unamortized debt discount of $4.7 million, which is recorded as an offset to the principal amount of the Senior Notes.
	The Senior Notes are general unsecured senior obligations and rank equally in right of payment with all of the Partnership's existing and future senior indebtedness and rank senior in right of payment to any of the Partnership's future subordinated indebtedness. The Senior Notes are effectively junior in right of payment to all of the Partnership's existing and future secured indebtedness and other obligations, including borrowings outstanding under the Partnership's Credit Agreement, to the extent of the value of the assets securing such indebtedness and other obligations. The Senior Notes are jointly and severally guaranteed on a senior unsecured basis by the Partnership's existing and future subsidiaries, who are referred to as the "subsidiary guarantors," that guarantee the Partnership's credit facility or other indebtedness.
	The indenture governing the Senior Notes, among other things, restricts the Partnership's ability and the ability of the Partnership's restricted subsidiaries to: (i) incur, assume or guarantee additional indebtedness or issue redeemable stock; (ii) pay dividends on stock, repurchase stock or redeem subordinated debt; (iii) make certain investments; (iv) enter into certain transactions with affiliates; (v) create liens on their assets; (vi) sell or otherwise dispose of certain assets, including capital stock of subsidiaries; (vii) restrict dividends, loans or other asset transfers from the Partnership's restricted subsidiaries; (viii) enter into new lines of business; and (ix) consolidate with or merge with or into, or sell all or substantially all of their properties (taken as a whole) to another person.
	The Partnership has the option to redeem all or a portion of the Senior Notes at any time on or after June 1, 2015 at the redemption prices specified in the indenture plus accrued and unpaid interest. The Partnership may also redeem the Senior Notes, in whole or in part, at a "make-whole" redemption price specified in the indenture, plus accrued and unpaid interest, at any time prior to June 1, 2015. In addition, the Partnership may redeem up to 35% of the Senior Notes prior to June 1, 2014 under certain circumstances with the net cash proceeds from certain equity offerings at 108.375% of the principal amount of the notes redeemed.
	Scheduled maturities of long-term debt as of December 31, 2013, were as follows:
		Principal Amount
		($ in thousands)
	2014	$	—
	2015	—
	2016	706,800
	2017	—
	2018	—
	2019 and after	550,000
		$	1,256,800

Members_Equity

Members' Equity	12 Months Ended
	Dec. 31, 2013
Partners' Capital [Abstract]	'
Members' Equity	'
	MEMBERS’ EQUITY
	At December 31, 2013, there were 156,644,153 common units outstanding. In addition, there were 2,743,807 unvested restricted common units outstanding.
	On June 1, 2010, the Partnership launched its rights offering to the holders of its common and general partner units as of close of business on May 27, 2010, the record date. Each Right entitled the holder (including holders of Rights acquired during the subscription period) to purchase (i) one common unit and (ii) one warrant to purchase one additional common unit at $6.00 on certain specified days beginning on August 15, 2010 and ending on May 15, 2012. During the years ended December 31, 2012 and 2011 5,300,588 and 14,957,540 warrants, respectively, were exercised for an equivalent number of newly issued common units. The final exercise date for the warrants was May 15, 2012, and on that date the remaining unexercised warrants expired.
	On May 31, 2012, the Partnership announced a program through which it may issue common units, from time to time, with an aggregate market value of up to $100 million. The Partnership is under no obligation to issue equity under the program. As of December 31, 2013, 686,759 units had been issued under this program for net proceeds of approximately $5.6 million.
	On August 17, 2012, the Partnership closed an underwritten public offering of 10,120,000 common units, which included the full exercise of the underwriters' option to purchase additional common units to cover over-allotments, for net proceeds of approximately $84.3 million.
	On March 12, 2013, the Partnership closed an underwritten public offering of 10,350,000 common units for net proceeds of approximately $92.3 million.
	The Partnership has declared a cash distribution for each quarter since its initial public offering. The table below summarizes these distributions for the last three years.
	Quarter Ended		Distribution		Record Date**	Payment Date
			per Unit
	March 31, 2011+		$	0.15	May 9, 2011	May 13, 2011
	June 30, 2011+		$	0.1875	August 5, 2011	August 12, 2011
	September 30, 2011+		$	0.2	November 4, 2011	November 14, 2011
	December 31, 2011+		$	0.21	February 7, 2012	February 14, 2012
	March 31, 2012+		$	0.22	May 8, 2012	May 15, 2012
	June 30, 2012+		$	0.22	August 7, 2012	August 14, 2012
	September 30, 2012+		$	0.22	November 7, 2012	November 14, 2012
	December 31, 2012+		$	0.22	February 7, 2013	February 14, 2013
	March 31, 2013+*		$	0.22	May 7, 2013	May 15, 2013
	June 30, 2013+*		$	0.22	August 7, 2013	August 14, 2013
	September 30, 2013+*		$	0.15	November 7, 2013	November 14, 2013
	December 31, 2013+*		$	0.15	February 7, 2014	February 14, 2014
	_____________________________
	+	The distribution per unit represents distributions made only on common units, including restricted common units issued under our Long Term Incentive Plan. Since July 30, 2010, the only other class of equity we have outstanding is a non-economic general partner interest.
	*	The distribution excludes certain restricted 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

Related Party Transactions	12 Months Ended
	Dec. 31, 2013
Related Party Transactions [Abstract]	'
Related Party Transactions	'
	RELATED PARTY TRANSACTIONS
	The following table summarizes transactions between the Partnership and affiliated entities:
		Year Ended December 31,
		2013		2012		2011
	Affiliates of NGP:	($ in thousands)
	Natural gas purchases from affiliates	$	2,938	$	2,713	$	6,097
	Payable as of December 31,	$	18	$	428
	In connection with the closing of the acquisition of certain fee minerals, royalties, overriding royalties and non-operated working interest properties from Montierra Minerals & Production, L.P. ("Montierra") and NGP-VII Co-Investment Opportunities, L.P. ("Co-Invest") on April 30, 2007, the Partnership entered into registration rights agreements with Montierra and Co-Invest. In the registration rights agreements, the Partnership agreed, for the benefit of Montierra and Co-Invest, to register the common units it holds, the common units issuable upon conversion of the subordinated units that it holds and any common units or other equity securities issuable in exchange for the common units and subordinated units it holds. The registration rights agreement is still in effect and the Partnership is in compliance with all obligations of the agreement.
	On May 3, 2011, the Partnership completed the Mid-Continent Acquisition. Due to Crow Creek Energy being a portfolio company of NGP VIII and NGP's ownership interest in the Partnership and Board of Directors representation, the Board of Directors of the general partner of the Partnership's general partner, authorized its Conflicts Committee to review, evaluate, and, if determined appropriate, approve the Mid-Continent Acquisition, due to the potential conflict of interest among the Partnership, the NGP and the Partnership's public unitholders. The Conflicts Committee, consisting of independent directors of the Partnership, determined that the Mid-Continent Acquisition was fair and reasonable to the Partnership and its public unitholders and recommended to the Board of Directors that the transaction be approved and authorized. In determining the consideration for the acquisition of Crow Creek Energy, the Conflicts Committee, with the assistance of a third-party, considered the valuation of the properties involved in the transaction, the valuation of the units to be offered as consideration in the transaction and the cash flows of Crow Creek Energy.
	In connection with the closing of the Mid-Continent Acquisition, the Partnership entered into a registration rights agreement ("Registration Rights Agreement") with NGP VIII. The Registration Rights Agreement grants NGP VIII and certain of its affiliates registration rights with respect to the common units acquired pursuant to the Partnership's acquisition of Crow Creek Energy and their outstanding warrants to purchase common units that were previously acquired by NGP VIII and certain of its affiliates in connection with the Partnership's previously completed recapitalization transaction. Pursuant to the Registration Rights Agreement, NGP VIII and certain of its affiliates have the ability to demand that the Partnership register for resale their common units acquired pursuant to the acquisition of Crow Creek Energy and their existing warrants to purchase common units. This registration may be an underwritten offering at the discretion of NGP VIII and certain of its affiliates. NGP VIII and certain of its affiliates may demand up to four such registrations, subject to an increase to up to seven if the registration rights are amended. Additionally, the Registration Rights Agreement provides that NGP VIII and certain of its affiliates have piggyback registration rights in certain circumstances, which would require inclusion of their common units and warrants on registration statements that the Partnership files, subject to certain customer exceptions. There are no limits on the number of times NGP VIII and certain of its affiliates can exercise these piggyback registration rights.

Risk_Management_Activities

Risk Management Activities	12 Months Ended
	Dec. 31, 2013
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'
Risk Management Activities	'
	RISK MANAGEMENT ACTIVITIES
	Interest Rate Swap Derivative Instruments
	To mitigate its interest rate risk, the Partnership enters into various interest rate swaps. These swaps convert the variable-rate term loan into a fixed-rate obligation. The purpose of entering into these swaps is to eliminate interest rate variability by converting LIBOR-based variable-rate payments to fixed-rate payments. Amounts received or paid under these swaps were recorded as reductions or increases in interest expense.
	For accounting purposes, the Partnership has not designated any of its interest rate derivative instruments as hedges; instead it marks these derivative contracts to fair value (see Note 12).  Changes in fair values of the interest rate derivative instruments are recorded as an adjustment to the mark-to-market gains (losses) on risk management transactions within other income (expense).
	The following table sets forth certain information regarding the Partnership's various interest rate swaps as of December 31, 2013:
	Effective Date		Expiration		Notional			Fixed
			Date		Amount			Rate
	6/22/11		6/22/15		$	250,000,000		2.95	%
	Commodity Derivative Instruments - Corporate
	The prices of crude oil, natural gas and NGLs are subject to fluctuations in response to changes in supply, demand, market uncertainty and a variety of additional factors which are beyond the Partnership's control.  These risks can cause significant changes in the Partnership's cash flows and affect its ability to achieve its distribution objectives and comply with the covenants of its revolving credit facility.  In order to manage the risks associated with changes in the future prices of crude oil, natural gas and NGLs on its forecasted equity production, the Partnership engages in risk management activities that take the form of commodity derivative instruments.  The Partnership has determined that it is necessary to hedge a substantial portion of its expected production in order to meaningfully reduce its future cash flow volatility.  The Partnership generally limits its hedging levels to less than its total expected future production. While hedging at this level of production does not eliminate all of the volatility in the Partnership's cash flows, it allows the Partnership to mitigate the risk of situations where a modest loss of production would not put it in an over-hedged position.  At times, the Partnership's strategy may involve entering into hedges with strike prices above current future prices or resetting existing hedges to higher price levels in order to meet its cash flow objectives or to stay in compliance with the covenants under its revolving credit facility.  In addition, the Partnership may also terminate or unwind hedges or portions of hedges when the expected future volumes do not support the level of hedges.  Expected future production for its Upstream Business is derived from the proved reserves, adjusted for price-dependent expenses and revenue deductions.  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 12).  Changes in fair values of the commodity derivative instruments are recorded as an adjustment to the mark-to-market gains (losses) on risk management transactions within revenue.
	By using derivative instruments to economically hedge exposure to changes in commodity prices, the Partnership exposes itself to counterparty credit risk. Historically, the Partnership's corporate derivative counterparties have all been participants or affiliates of participants within its revolving credit facility (see Note 8), which is secured by substantially all of the assets of the Partnership. Therefore, the Partnership is not currently required to post any collateral, nor does it require collateral from its counterparties. The Partnership minimizes the credit risk in derivative instruments by limiting exposure to any single counterparty and monitoring the creditworthiness of its counterparties on an ongoing basis. In addition, the Partnership's derivative contracts for certain counterparties are subject to counterparty netting agreements governing such derivatives, and when possible, the Partnership nets the open positions of each counterparty. See Note 12 for the impact to the Partnership's audited consolidated balance sheets of the netting of these derivative contracts.
	The Partnership's commodity derivative counterparties as of December 31, 2013, not including counterparties of its marketing and trading business, included BNP Paribas, Wells Fargo Bank, National Association, Comerica Bank, Bank of Nova Scotia, The Royal Bank of Scotland plc, Bank of America N.A., J Aron and Company (an affiliate of Goldman Sachs), ING Capital Markets LLC, BBVA Compass Bank, Royal Bank of Canada, Regions Financial Corporation and CITIBANK, N.A.
	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 December 31, 2013, 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)		16,800,000		$	4.38
	Crude Oil		Costless Collar		240,000		$	90			$	106
	Crude Oil		Swap (Pay Floating/Receive Fixed)		2,208,000		$	96.51
	Crude Oil		Swap (Pay Fixed/Receive Floating)		199,140		$	92.53
	Propane		Swap (Pay Floating/Receive Fixed)		9,576,000		$	1.06
	IsoButane		Swap (Pay Floating/Receive Fixed)		2,268,000		$	1.31
	Normal Butane		Swap (Pay Floating/Receive Fixed)		4,132,800		$	1.3
	Portion of 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
	Portion of Contracts Maturing in 2016
	Natural Gas		Swap (Pay Floating/Receive Fixed)		9,480,000		$	4.25
	Crude Oil		Swap (Pay Floating/Receive Fixed)		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. The weighted average prices are in $/MMbtu for natural gas, $/barrel for crude oil and $/gallon for natural gas liquids.
	Commodity Derivative Instruments - Marketing & Trading
	The Partnership conducts natural gas marketing and trading activities. The Partnership engages in activities intended to capitalize on favorable price differentials between various receipt and delivery locations. The Partnership's 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 will have 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 12 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 December 31, 2013, that will mature during the years ended December 31, 2014 and 2015 and beyond:
	Type		Notional Volumes (MMbtu)
	Portion of Contracts Maturing in 2014
	Basis Swaps - Purchases		6,955,000
	Basis Swaps - Sales		2,675,000
	Index Swap - Purchases		620,000
	Index Swap - Sales		1,365,000
	Swap (Pay Fixed/Receive Floating) - Purchases		930,000
	Swap (Pay Floating/Received Fixed) - Sales		465,000
	Forward purchase contract - index		13,090,332
	Forward sales contract - index		18,873,397
	Forward purchase contract - fixed price		2,263,000
	Forward sales contract - fixed price		2,728,000
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
Fair values of interest rate and commodity derivative instruments not designated as hedging instruments in the consolidated balance sheet as of December 31, 2013 and December 31, 2012:
	As of
	31-Dec-13
	Derivative Assets					Derivative Liabilities
	Balance Sheet Classification		Fair Value			Balance Sheet Classification		Fair Value
	($ in thousands)
Interest rate derivatives - liabilities	Current assets		$	—		Current liabilities		$	(6,210	)
Interest rate derivatives - liabilities	Long-term assets		—			Long-term liabilities		(2,885		)
Commodity derivatives - assets	Current assets		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	)
	As of
	31-Dec-12
	Derivative Assets					Derivative Liabilities
	Balance Sheet Classification		Fair Value			Balance Sheet Classification		Fair Value
	($ in thousands)
Interest rate derivatives - liabilities	Current assets		$	(4,844	)	Current liabilities		$	(1,201	)
Interest rate derivatives - liabilities	Long-term assets		(7,002		)	Long-term liabilities		(1,700		)
Commodity derivatives - assets	Current assets		39,182			Current liabilities		19
Commodity derivatives - assets	Long-term assets		17,338			Long-term liabilities		—
Commodity derivatives - liabilities	Current assets		(998		)	Current liabilities		(49		)
Commodity derivatives - liabilities	Long-term assets		(2,383		)	Long-term liabilities		—
Total derivatives			$	41,293				$	(2,931	)
The following table sets forth the location of gains and losses for derivatives not designated as hedging instruments within the Partnership's audited consolidated statement of operations (in thousands):
Amount of Gain (Loss) Recognized in Income on Derivatives			Year Ended December 31,
			2013			2012				2011
Interest rate derivatives	Interest rate risk management losses, net		$	(1,104	)	$	(4,727	)		$	(11,401	)
Commodity derivatives	Commodity risk management gains (losses), net		(18,533		)	57,894				32,510
Commodity derivatives -trading	Natural gas, natural gas liquids, oil, condensate and sulfur sales		315			(192		)		772
	Total		$	(19,322	)	$	52,975			$	21,881

Fair_Value_of_Financial_Instru

Fair Value of Financial Instruments	12 Months Ended
	Dec. 31, 2013
Fair Value Disclosures [Abstract]	'
Fair Value of Financial Instruments	'
	FAIR VALUE OF FINANCIAL INSTRUMENTS
	Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Partnership utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk inherent in the inputs to the valuation technique. The authoritative guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements).
	The three levels of the fair value hierarchy are as follows:
	Level 1 – Quoted prices are available in active markets for identical assets and liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide information on an ongoing basis.
	Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the market place throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.
	Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management's best estimate of fair value.
	As of December 31, 2013, the Partnership has recorded its interest rate swaps and commodity derivative instruments (see Note 11), which includes crude oil, natural gas and NGLs, at fair value. The Partnership reviews the classification of the inputs at the end of each period and has classified the inputs to measure the fair value of its interest rate swaps, crude oil derivatives and natural gas derivatives as Level 2.  In prior periods, the Partnership has classified the inputs to measure its NGL derivatives as Level 3 as the NGL market was considered to be less liquid and thinly traded. As of September 30, 2011, the Partnership concluded that the inputs for its NGL derivatives were considered to be more observable due to the NGL market being more liquid through the term of our contracts and has classified these inputs as Level 2. The following table discloses the fair value of the Partnership's derivative instruments as of December 31, 2013 and 2012:
		As of
		31-Dec-13
		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 agreement governing such derivative contracts.
		As of
		31-Dec-12
		Level 1		Level 2			Level 3			Netting (a)			Total
		($ in thousands)
	Assets:
	Crude oil derivatives	$	—	$	19,410		$	—		$	(1,814	)	$	17,596
	Natural gas derivatives	—		27,340			—			(1,586		)	25,754
	NGL derivatives	—		9,789			—			—			9,789
	Interest rate swaps	—		—			—			(11,846		)	(11,846		)
	Total	$	—	$	56,539		$	—		$	(15,246	)	$	41,293
	Liabilities:
	Crude oil derivatives	$	—	$	(1,814	)	$	—		$	1,814		$	—
	Natural gas derivatives	—		(1,616		)	—			1,586			(30		)
	Interest rate swaps	—		(14,747		)	—			11,846			(2,901		)
	Total	$	—	$	(18,177	)	$	—		$	15,246		$	(2,931	)
	____________________________
	(a)	Represents counterparty netting under agreement governing such derivative contracts.
	The following table sets forth a reconciliation of changes in the fair value of the Level 3 NGL derivatives during the years ended December 31, 2013, 2012 and 2011 (in thousands):
		Year Ended December 31,
		2013		2012			2011
	Net liability beginning balance	$	—	$	—		$	(5,733	)
	Settlements	—		—			15,562
	Total gains or losses	—		—			(12,784		)
	Transfers out of Level 3	—		—			2,955
	Net liability ending balance	$	—	$	—		$	—
	The Partnership values its Level 3 NGL derivatives using forward curves, interest rate curves, and volatility parameters, when applicable. In addition, the impact of counterparty credit risk is factored into the value of derivative assets, and the Partnership's credit risk is factored into the value of derivative liabilities.
	Gains and losses losses related to the interest rate derivatives are recorded as part of interest rate risk management gains and losses in the audited consolidated statements of operations.  Gains and losses related to the Partnership's commodity derivatives are recorded as a component of revenue in the audited consolidated statements of operations.
	Fair Value of Assets and Liabilities Measured on a Non-recurring Basis
	For periods in which impairment charges have been incurred, the Partnership is required to write down the value of the
	impaired asset to its fair value. See Note 5 for a further discussion of the impairment charges recorded during the year ended. The following table discloses the fair value of the Partnership's assets measured at fair value on a nonrecurring basis for the year ended December 31, 2013:
		December 31,		Level 1			Level 2			Level 3			Total Losses
		2013
		($ in thousands)
	Proved properties	$	91,346	$	—		$	—		$	91,346		$	207,085
	The Partnership calculated the fair value of the impaired assets using discounted cash flow analysis to determine the excess of the asset's carrying value over its fair value. Significant inputs to the valuation of fair value of the proved properties included estimates of (i) reserves, (ii) future operating and development costs (ii) forward commodity prices and (iii) a discount rate reflective of the Partnership's cost of capital. For the other assets impaired by the partnership during the year ended December 31, 2013, the assets were fully written down and are thus not included in the table above. See Notes 5 for a further discussion of the impairment charges.
	The carrying amount of cash equivalents is believed to approximate their fair values because of the short maturities of these instruments. The fair value of accounts receivable and accounts payable are not materially different from their carrying amounts because of the short-term nature of these instruments.
	As of December 31, 2013, 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 December 31, 2013 and 2012, the Partnership estimates that the fair value of the Senior Notes is $599.5 million and $561.0 million, respectively. Fair value of the senior notes was estimated based on prices quoted from third-party financial institutions, which are characteristic of Level 2 fair value measurement inputs.

Commitments_and_Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2013
Commitments and Contingencies Disclosure [Abstract]	'
Commitments and Contingencies	'
	COMMITMENTS AND CONTINGENT LIABILITIES
	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 December 31, 2013 and 2012 related to legal matters, and current lawsuits are not expected to have a material adverse effect on our financial position, results of operations or cash flows. 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 against the indemnification up to limits of the indemnification.
	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 Eagle Rock Energy 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.
	All coverages are subject to industry accepted policy terms, conditions, limits and deductibles comparable to that obtained by other energy companies with similar operations. The cost of insurance for the energy industry continued to fluctuate over the past year, reflecting the changing conditions in the insurance markets.
	Environmental—The 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 December 31, 2013 and 2012, the Partnership had accrued approximately $3.2 million and $2.8 million, respectively, for environmental matters.
	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 at the Big Escambia Creek, Flomaton and Fanny Church fields in Escambia County, Alabama. With respect to the Partnership's Flomaton and Fanny Church fields, these retained revenue interests are in effect for any calendar year in which the Partnership surpasses certain average net production rates. The Partnership did not surpass such rates in 2013 and does not anticipate exceeding these rates in future years. With respect to the Partnership's Big Escambia Creek field, the retained revenue interest commenced in 2010 and continues through the end of 2019.
	Other Commitments—The Partnership utilizes assets under operating leases for its corporate office, certain rights-of-way and facilities locations, vehicles and in several areas of its operations. Rental expense, including leases with no continuing commitment, amounted to approximately $9.5 million, $8.9 million and $7.8 million for the years ended December 31, 2013, 2012 and 2011, respectively. Rental expense for leases with escalation clauses is recognized on a straight-line basis over the initial lease term. At December 31, 2013, commitments under long-term non-cancelable operating leases for the next five years are as follows (in thousands):
	Year ending December 31,
	2014	$	7,060
	2015	$	6,045
	2016	$	4,997
	2017	$	2,848
	2018	$	438

Segments

Segments	12 Months Ended
	Dec. 31, 2013
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 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 Alabama; 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:
			Texas			East Texas and Other				Marketing				Total				Upstream				Corporate					Total
	Year Ended December 31, 2013		Panhandle			Midstream				and Trading Segment				Midstream				Segment				and Other Segment					Segments
			Segment			Segment								Business
	($ in thousands)
	Sales to external customers		$	538,492		$	136,637			$	384,422			$	1,059,551			$	154,261			$	(18,533	)	(a)		$	1,195,279
	Intersegment sales		226,576			37,716				(272,116		)		(7,824		)		47,048				(39,224		)			—
	Cost of natural gas and natural gas liquids		594,125			131,966				64,527				790,618				—				—					790,618
	Intersegment cost of natural gas, oil and condensate		200			—				38,844				39,044				—				(39,044		)			—
	Operating costs and other expenses		81,186			19,943				(8		)		101,121				54,354				81,214					236,689
	Depreciation, depletion, amortization		57,781			19,476				428				77,685				87,456				2,029					167,170
	Impairment		—			—				—				—				214,286				—					214,286
	Operating income (loss) from continuing operations		$	31,776		$	2,968			$	8,515			$	43,259			$	(154,787	)		$	(101,956	)			$	(213,484	)
	Capital Expenditures		$	81,590		$	7,827			$	309			$	89,726			$	129,099			$	5,336				$	224,161
	Segment Assets		$	950,092		$	243,493			$	73,918			$	1,267,503			$	842,246			$	17,801		(b)		$	2,127,550
	Year Ended December 31, 2012		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		$	362,902	(c)		$	156,529			$	256,772			$	776,203			$	149,862			$	57,894		(a)		$	983,959
	Intersegment sales		105,759				39,099				(154,992		)		(10,134		)		53,343				(43,209		)			—
	Cost of natural gas and natural gas liquids		332,792				147,493				52,434				532,719				—				—					532,719
	Intersegment cost of natural gas,oil and condensate		83				—				44,317				44,400				—				(44,400		)			—
	Operating costs and other expenses		60,884				21,762				2				82,648				56,612				69,994					209,254
	Intersegment operations and maintenance		—				—				—				—				122				(122		)			—
	Depreciation, depletion, amortization		44,451				25,771				273				70,495				88,777				1,773					161,045
	Impairment		—				131,714				—				131,714				45,289				—					177,003
	Operating income (loss) from continuing operations		$	30,451			$	(131,112	)		$	4,754			$	(95,907	)		$	12,405			$	(12,560	)			$	(96,062	)
	Capital Expenditures		$	131,928			$	9,328			$	5,489			$	146,745			$	160,330			$	3,645				$	310,720
	Segment Assets		$	922,281			$	250,916			$	43,417			$	1,216,614			$	1,018,927			$	58,675		(b)		$	2,294,216
			Texas			East Texas and Other				Marketing				Total				Upstream					Corporate					Total
	Year Ended December 31, 2011		Panhandle			Midstream				and Trading Segment				Midstream				Segment					and Other Segment					Segments
			Segment			Segment								Business
	($ in thousands)
	Sales to external customers		$	395,991		$	274,361			$	200,939			$	871,291			$	156,107		(d)		$	32,510		(a)		$	1,059,908
	Intersegment sales		60,237			16,654				(82,378		)		(5,487		)		48,203					(42,716		)			—
	Cost of natural gas and natural gas liquids		327,775			231,642				73,767				633,184				—					—					633,184
	Intersegment cost of natural gas, oil and condensate		—			—				41,382				41,382				—					(41,382		)			—
	Operating costs and other expenses		41,749			22,790				—				64,539				47,657					54,998					167,194
	Intersegment operations and maintenance		—			—				—				—				66					(66		)			—
	Depreciation, depletion, amortization		37,034			27,629				—				64,663				65,531					1,417					131,611
	Impairment		4,560			—				—				4,560				11,728					—					16,288
	Operating income (loss) from continuing operations		$	45,110		$	8,954			$	3,412			$	57,476			$	79,328				$	(25,173	)			$	111,631
	Capital Expenditures		$	71,351		$	10,860			$	2,205			$	84,416			$	92,660				$	2,132				$	179,208
	Segment Assets		$	599,688		374,030				$	40,173			$	1,013,891			$	979,331				$	52,466		(b)		$	2,045,688
	______________________________
	(a)	Represents results of the Partnership's commodity risk management activity.
	(b)	Includes elimination of intersegment transactions.
	(c)	Sales to external customers in the Texas Panhandle Segment for the year ended December 31, 2012, includes 2.9 million of business interruption insurance recovery related to damage sustained by the Partnership's Cargray processing facility due to severe winter weather in 2011, which is recognized as part of Other Revenue in the consolidated statements of operations.
	(d)	Sales to external customers for the years ended December 31, 2011 includes $2.0 million, respectively, of business interruption insurance recovery related to the shutdown of the Eustace plant in 2010 in the Upstream Segment, which is recognized as part of Other revenue in the consolidated statement of operations.

Employee_Benefit_Plan

Employee Benefit Plan	12 Months Ended
	Dec. 31, 2013
Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]	'
Pension and Other Postretirement Benefits Disclosure [Text Block]	'
	EMPLOYEE BENEFIT PLAN
	The Partnership offers a defined contribution benefit plan to its employees. For the three years ended December 31, 2012, the plan provided for a dollar for dollar matching contribution by the Partnership of up to 4% of an employee's contribution and 50% of additional contributions up to an additional 2%. Additionally, the Partnership may, at its sole discretion and election, contribute up to 6% of a participating employee's base salary annually, subject to vesting requirements. Expenses under the plan for the years ended December 31, 2013, 2012 and 2011 were approximately $2.5 million, $1.8 million and $1.0 million, respectively.

Income_Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2013
Income Tax Disclosure [Abstract]	'
Income Taxes	'
	INCOME TAXES
	The Partnership's provision for income taxes relates to (i) state taxes for the Partnership and (ii) federal taxes for Eagle Rock Energy Acquisition Co., Inc, (acquiring entity of Redman Energy Holdings, L.P. and Redman Energy Holdings II, L.P. and certain assets owned by NGP Income Co-Investment Opportunities Fund II, L.P. (collectively the "Redman Acquisition") in 2007)  and Eagle Rock Energy Acquisition Co. II, Inc. (acquiring entity of certain entities acquired in the Stanolind Acquisition in 2008) and their wholly owned corporations, Eagle Rock Upstream Development Company, Inc., (successor entity of certain entities acquired in the Redman acquisition) and Eagle Rock Upstream Development Company II, Inc. (successor entity of certain entities acquired in the Stanolind acquisition), which are subject to federal income taxes (the “C Corporations”).   In addition, the Partnership has become a taxable entity in the state of Texas. On May 18, 2006, the State of Texas enacted House Bill 3 which revised the pre-existing state franchise tax. In general, legal entities that conduct business in Texas are subject to the Revised Texas Franchise Tax, including previously non-taxable entities such as limited partnerships and limited liability partnerships. The tax is assessed on Texas sourced taxable margin which is defined as the lesser of (i) 70% of total revenue or (ii) total revenue less (a) cost of goods sold or (b) compensation and benefits. Although the bill states that the Revised Texas Franchise Tax is not an income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers both revenues and expenses.
	The Partnership's federal and state income tax provision is summarized below (in thousands):
		For the Year Ended December 31,
		2013			2012			2011
	Current:
	Federal	$	(105	)	$	621		$	1,092
	State	—			18			61
	Total current provision	(105		)	639			1,153
	Deferred:
	Federal	(3,837		)	(2,776		)	(3,862		)
	State	(1,172		)	434			277
	Total deferred	(5,009		)	(2,342		)	(3,585		)
	Total (benefit) provision for income taxes	$	(5,114	)	$	(1,703	)	(2,432		)
	The effective rates for the years ended December 31, 2013, 2012 and 2011 are shown in the table below.  For 2011, the effective tax rate is attributable to the state and federal taxes being applied to their book income. In 2013 and 2012, the federal and state based income taxes were applied against book losses which resulted in effective tax rates of 1.8% and 1.1%, respectively.   A reconciliation of the provision for income taxes with amounts determined by applying the statutory U.S. federal income tax rate to income before income taxes is as follows (in thousands):
		For the Year Ended December 31,
		2013			2012			2011
	Pre-tax net book income (loss) from continuing operations	(283,093		)	(152,305		)	70,424
	State income tax current and deferred	(1,172		)	452			338
	Federal income taxes computed by applying the federal statutory rate to NBI of corporate entities	(4,160		)	(2,155		)	(2,232		)
	Tax attributes used	218			—			(538		)
	Benefit for income taxes from continuing operations	$	(5,114	)	$	(1,703	)	$	(2,432	)
	Effective income tax rate on continuing operations	1.8		%	1.1		%	(3.5		)%
	Significant components of deferred tax liabilities and deferred tax assets as of December 31, 2013 and 2012 are as follows (in thousands):
		December 31, 2013			December 31, 2012
	Deferred Tax Assets:
	Statutory depletion carryover	$	1,438		$	1,599
	AMT credit carryforward	—			57
	Total Deferred Tax Assets	1,438			1,656
	Deferred Tax Liabilities:
	Property, plant, equipment & amortizable assets	(5,867		)	(6,585		)
	Hedging transactions	—			(271		)
	Book/tax differences from partnership investment	(32,086		)	(36,144		)
	Total Deferred Tax Liabilities	(37,953		)	(43,000		)
	Total Net Deferred Tax Liabilities	(36,515		)	(41,344		)
	Current portion of total net deferred tax liabilities	—			—
	Long-term portion of total net deferred tax liabilities	$	(36,515	)	$	(41,344	)
	The largest single component of the Partnership's deferred tax liabilities is related to federal income taxes of the C Corporations described above, where the book/tax differences were created by the Redman and Stanolind Acquisitions. These book/tax temporary differences will be reduced as allocation of built-in gain in proportion to the assets contributed brings the book and tax basis closer together over time. This net deferred tax liability was recognized in conjunction with the purchase accounting adjustments for long term assets.
	Due to the enactment of the Revised Texas Franchise Tax, the Partnership recorded a net deferred tax liability related to the book/tax differences in property, plant and equipment and hedging transactions.
	In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment. At December 31, 2013, based upon the level of historical taxable income and projections for future taxable income over the periods in which the deferred tax assets are deductible, management believes it is more likely than not that the Partnership will realize the benefits of these deductible differences. The amount of deferred tax assets considered realizable could be reduced in the future if estimates of future taxable income during the carryforward period are reduced. The AMT credit carryforward presented above does not have an expiration date.
	The Partnership adopted authoritative guidance related to accounting for uncertainty in income taxes on January 1, 2007.  The Partnership has taken a position which is deemed to be “more likely than not” to be upheld upon review, if any, with respect to the deductibility of certain costs for the purpose of its franchise tax liability on a state franchise return.   The Partnership has recorded a provision for the portion of this tax liability equal to the probability of recognition. In addition, the Partnership has accrued interest and penalties associated with these liabilities and has recorded these amounts within its state deferred income tax expense. The amount stated below relates to the tax returns filed for 2013, 2012 and 2011, which are still open under current statute.
	A reconciliation of the beginning and ending amount of the unrecognized tax benefits (liabilities) is as follows (in thousands):
		2013			2012			2011
	Balance at beginning of period	$	(830	)	$	(735	)	$	(569	)
	Increases related to current year tax positions	(128		)	(53		)	(132		)
	Increases related to tax interest and penalties	(39		)	(42		)	(34		)
	Decreases related to statutory limitations	267			—			—
	Decreases related to tax interest and penalties	81			—			—
	Balance at end of period	$	(649	)	$	(830	)	$	(735	)

Equity_Based_Compensation

Equity Based Compensation	12 Months Ended
	Dec. 31, 2013
Share-based Compensation [Abstract]	'
Equity-based Compensation	'
	EQUITY-BASED COMPENSATION
	Eagle Rock Energy G&P, LLC, the general partner of the general partner of the Partnership, has a long-term incentive plan, as amended (“LTIP”), for its employees, directors and consultants who provide services to the Partnership and its subsidiaries and affiliates. The LTIP provides for the issuance of an aggregate of up to 7,000,000 common units, to be granted either as options, restricted units or phantom units, of which, as of December 31, 2013, a total of 913,794 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.
	The restricted units granted are valued at the market price as of the date issued. The weighted average fair value of the units granted during the years ended December 31, 2013, 2012 and 2011 was $9.16, $9.50 and $10.13, respectively. The awards generally vest over three years on the basis of one third of the award each year. The Partnership recognizes compensation expense on a straight-line basis over the requisite service period for the restricted unit grants. During the restriction period, distributions associated with the granted awards will be distributed to the awardees.
	A summary of the restricted common units’ activity for the year ended December 31, 2013 is provided below:
		Number of		Weighted
		Restricted		Average
		Units		Fair Value
	Outstanding at December 31, 2012	2,608,035		$	9.38
	Granted	1,623,939		$	9.16
	Vested	(1,203,822	)	$	8.98
	Forfeited	(284,345	)	$	9.9
	Outstanding at December 31, 2013	2,743,807		$	9.37
	For the years ended December 31, 2013, 2012 and 2011, non-cash compensation expense of approximately $13.4 million, $9.9 million and $5.1 million, respectively, was recorded related to the granted restricted units as general and administrative expense on the consolidated statements of operations.
	As of December 31, 2013, unrecognized compensation costs related to the outstanding restricted units under the LTIP totaled approximately $17.1 million. The remaining expense is to be recognized over a weighted average of 1.6 years.
	In connection with the vesting of certain restricted units during the years ended December 31, 2013, 2012 and 2011, 272,179, 286,716 and 137,985, respectively, of the newly-vested common units were cancelled by the Partnership in satisfaction of $1.9 million, $2.5 million and $1.4 million, respectively, of minimum employee tax liability paid by the Partnership. Pursuant to the terms of the LTIP, these cancelled units are available for future grants under the LTIP.

Earnings_Per_Unit

Earnings Per Unit	12 Months Ended
	Dec. 31, 2013
Earnings Per Unit [Abstract]	'
Earnings Per Unit	'
	EARNINGS PER UNIT
	Basic earnings per unit is computed by dividing the net income (loss) by the weighted average number of units outstanding during a period. To determine net income (loss) allocated to each class of ownership (common and restricted common units), the Partnership first allocates net income (loss) in accordance with the amount of distributions made for the quarter by each class, if any. The remaining net income is allocated to each class in proportion to the class weighted average number of units outstanding for a period, as compared to the weighted average number of units for all classes for the period, with the exception of net losses. Net losses are allocated to just the common units.
	As of December 31, 2013, 2012 and 2011, the Partnership had unvested restricted common units outstanding, which are considered dilutive securities. These units will be considered in the diluted weighted average common unit outstanding number in periods of net income. In periods of net losses, these units are excluded from the diluted weighted average common unit outstanding number.
	Any warrants outstanding during the period are considered to be dilutive securities. These outstanding warrants will be considered in the diluted weighted average common units outstanding number in periods of net income, except if the exercise price of the outstanding warrants is greater than the average market price of the common units for such periods. In periods of net losses, the outstanding warrants are excluded from the diluted weighted average common units outstanding.
	The following table presents the Partnership's calculation of basic and diluted units outstanding for the periods indicated:
		Year Ended December 31,
		2013			2012		2011
		(in thousands)
	Weighted average units outstanding during period:
	Common units - Basic	153,562			135,609		110,435
	Effect of Dilutive Securities:
	Warrants	—			—		5,727
	Restricted Units	—			—		779
	Common units - Diluted	153,562			135,609		116,941
	The restricted common units granted under the LTIP, as discussed in Note 17, 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. For the year ended December 31, 2011, the Partnership determined that it is more dilutive to apply the two-class method versus the treasury stock method in calculating dilutive earnings per unit. Thus, the unvested restricted common units are included in the computation of the diluted weighted average common unit outstanding calculation, but the denominator in the computation of diluted earnings per common unit only includes the basic weighted average common units outstanding and weighted average warrants outstanding.
	The following table presents the Partnership's basic income per unit for the year ended December 31, 2013:
			Total			Common Units			Restricted Common Units
			($ in thousands, except for per unit amounts)
	Net loss		$	(277,979	)
	Distributions		117,294			$	115,351		$	1,943
	Assumed loss from continuing operations after distribution to be allocated		(395,273		)	(395,273		)	—
	Assumed net (loss) income to be allocated		$	(277,979	)	$	(279,922	)	$	1,943
	Basic and diluted loss per unit					$	(1.82	)
	The following table presents the Partnership's basic and diluted income per unit for the year ended December 31, 2012:
			Total			Common Units			Restricted Common Units
			($ in thousands, except for per unit amounts)
	Loss from continuing operations		$	(150,602	)
	Distributions		124,235			$	121,504		$	2,731
	Assumed loss from continuing operations after distribution to be allocated		(274,837		)	(274,837		)	—
	Assumed net income to be allocated		$	(150,602	)	$	(153,333	)	$	2,731
	Basic and diluted loss per unit					$	(1.13	)
	The following table presents the Partnership's basic and diluted income per unit for the year ended December 31, 2011:
			Total			Common Units			Restricted Common Units
			($ in thousands, except for per unit amounts)
	Loss from continuing operations		$	72,856
	Distributions		89,062			$	87,525		$	1,537
	Assumed loss from continuing operations after distribution to be allocated		(16,206		)	(16,206		)	—
	Assumed allocation of loss from continuing operations		72,856			71,319			1,537
	Discontinued operations, net of tax		276			276			—
	Assumed net income to be allocated		$	73,132		$	71,595		$	1,537
	Basic income from continuing operations per unit					$	0.65
	Basic discontinued operations per unit					$	—
	Basic net income per unit					$	0.65
	Diluted income from continuing operations per unit					$	0.61
	Diluted discontinued operations per unit					$	—
	Diluted net income per unit					$	0.62

Divestiture_Related_Activities

Divestiture Related Activities	12 Months Ended
	Dec. 31, 2013
Discontinued Operations and Disposal Groups [Abstract]	'
Divestiture Related Activities	'
	DIVESTITURE RELATED ACTIVITIES
	The following table represents activity from divestiture related activities for the years ended December 31, 2013, 2012 and 2011:
			Barnett Shale (a)			Wildhorse System (b)			Minerals Business (c)
	($ in thousands)
	Year Ended December 31, 2012:
	Loss from the sale		$	(4,460	)	$	—		$	—
	Proceeds from sale		$	14,841		$	—		$	—
	Year Ended December 31, 2011:
	Revenues		$	—		$	6,859		$	—
	(Loss) income from Operations		$	—		$	548		$	—
	Discontinued operations, net of tax		$	—		$	(180	)	$	456
	Loss from the sale		$	—		$	(718	)	—
	Proceeds from sale		$	—		$	5,712		—
	_____________________________
	(a)	On December 20, 2012, the Partnership sold its Barnett Shale properties (which was accounted for in its Upstream Segment). In 2012, the Partnership incurred a loss from sale which is included within impairment expense in the Consolidated Statement of Operations.
	(b)	On May 20, 2011, the Partnership sold its Wildhorse Gathering System (which was accounted for in its East Texas and Other Midstream Segment).
	(c)	On May 24, 2010, the Partnership completed the sale of its Minerals Business. During the year ended December 31, 2011, the Partnership received payments related to pre-effective date operations and recorded this amount as part of discontinued operations for the period.

Other_Operating_Income

Other Operating Income	12 Months Ended
	Dec. 31, 2013
Other Income and Expenses [Abstract]	'
Other Operating Income	'
	OTHER OPERATING INCOME
	In July 2008, SemGroup, L.P. and certain of its subsidiaries (“SemGroup”) filed petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code. The Partnership historically sold portions of its condensate production from its Texas Panhandle and East Texas midstream systems to SemGroup. In August 2009, the Partnership sold $3.9 million of its outstanding receivables from SemGroup, which represented its 20-day administrative claims under 503(b)(9) of the United States Bankruptcy Code, for which it received a payment of $3.0 million. Due to certain repurchase obligations under the assignment agreement, the Partnership recorded the payment as a current liability within accounts payable as of December 31, 2010 and maintained the balance as a liability until it was clear that the repurchase obligations can no longer be triggered. Due to the expiration of the repurchase obligations during the year ended December 31, 2011, the Partnership released its reserve for these receivables and recorded other operating income of $2.9 million related to these reserves.

Subsidiary_Guarantors

Subsidiary Guarantors	12 Months Ended
	Dec. 31, 2013
SUBSIDIARY GUARANTORS [Abstract]	'
Subsidiary Guarantors	'
	SUBSIDIARY GUARANTORS
	The Partnership has issued registered debt securities guaranteed by its subsidiaries.  As of December 31, 2013, all guarantors were wholly-owned or available to be pledged and such guarantees were joint and several and full and unconditional.  Although the guarantees of our subsidiary guarantors are considered full and unconditional, the guarantees are subject to certain customary release provisions. Such guarantees will be released in the following circumstances:
	•	in connection with any sale or other disposition of all or substantially all of the properties or assets of that guarantor (including by way of merger or consolidation) to a person that is not (either before or after giving effect to such transaction) an issuer or a restricted subsidiary of us;
	•	in connection with any sale or other disposition of capital stock of that guarantor to a person that is not (either before or after giving effect to such transaction) an issuer or a restricted subsidiary of us, such that, the guarantor ceases to be a restricted subsidiary of us as a result of the sale or other disposition;
	•	if we designate any restricted subsidiary that is a guarantor to be an unrestricted subsidiary in accordance with the applicable provisions of the indenture;
	•	upon legal defeasance or satisfaction and discharge of the indenture;
	•	upon the liquidation or dissolution of such guarantor provided no default or event of default has occurred that is continuing;
	•	at such time as such guarantor ceases to guarantee any other indebtedness of either of the issuers or any guarantor; or
	•	upon such guarantor consolidating with, merging into or transferring all of its properties or assets to us or another guarantor, and as a result of, or in connection with, such transaction such guarantor dissolving or otherwise ceasing to exist.
	In accordance with Rule 3-10 of Regulation S-X, the Partnership has prepared Condensed Consolidating Financial Statements as supplemental information.  The following condensed consolidating balance sheets at December 31, 2013 and December 31, 2012, condensed consolidating statements of operations for the years ended December 31, 2013, 2012 and 2011, and condensed consolidating statements of cash flows for the years ended December 31, 2013, 2012 and 2011, 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.
	Condensed Consolidating Balance Sheet
	December 31, 2013
		Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-guarantor investments			Consolidating			Total
													Entries
		($ 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
	Condensed Consolidating Balance Sheet
	December 31, 2012
		Parent Issuer			Co-Issuer		Subsidiary			Non-guarantor investments			Consolidating Entries			Total
							Guarantors
		($ in thousands)
	ASSETS:
	Accounts receivable – related parties	$	660,898		$	—	$	—		$	—		$	(660,898	)	$	—
	Other current assets	27,688			1		154,275			—			—			181,964
	Total property, plant and equipment, net	2,657			—		1,965,549			—			—			1,968,206
	Investment in subsidiaries	1,324,293			—		—			958			(1,325,251		)	—
	Total other long-term assets	22,061			—		121,985			—			—			144,046
	Total assets	$	2,037,597		$	1	$	2,241,809		$	958		$	(1,986,149	)	$	2,294,216
	LIABILITIES AND EQUITY:
	Accounts payable – related parties	$	—		$	—	$	660,898		$	—		$	(660,898	)	$	—
	Other current liabilities	6,734			—		174,780			—			—			181,514
	Other long-term liabilities	9,386			—		81,839			—			—			91,225
	Long-term debt	1,153,103			—		—			—			—			1,153,103
	Equity	868,374			1		1,324,292			958			(1,325,251		)	868,374
	Total liabilities and equity	$	2,037,597		$	1	$	2,241,809		$	958		$	(1,986,149	)	$	2,294,216
	Condensed Consolidating Statement of Operations
	For the Year Ended December 31, 2013
		Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-guarantor investments			Consolidating			Total
													Entries
		($ in thousands)
	Total revenues	$	(4,168	)	$	—	$	1,199,447		$	—		$	—		$	1,195,279
	Cost of natural gas and natural gas liquids	—			—		790,618			—			—			790,618
	Operations and maintenance	(1		)	—		135,206			—			—			135,205
	Taxes other than income	—			—		20,270			—			—			20,270
	General and administrative	17,716			—		63,498			—			—			81,214
	Depreciation, depletion and amortization	454			—		166,716			—			—			167,170
	Impairment and other	—			—		214,286			—			—			214,286
	Loss from operations	(22,337		)	—		(191,147		)	—			—			(213,484		)
	Interest expense, net	(67,864		)	—		(898		)	—			—			(68,762		)
	Other non-operating income	9,025			—		9,298			—			(18,323		)	—
Other non-operating expense	(6,904		)	—		(12,256		)	(10		)	18,323			(847		)
Loss before income taxes	(88,080		)	—		(195,003		)	(10		)	—			(283,093		)
Income tax benefit	(1,172		)	—		(3,942		)	—			—			(5,114		)
Equity in earnings of subsidiaries	(191,071		)	—		—			—			191,071			—
Net loss	$	(277,979	)	$	—	$	(191,061	)	$	(10	)	$	191,071		$	(277,979	)
Condensed Consolidating Statement of Operations
For the Year Ended December 31, 2012
	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-guarantor investments			Consolidating Entries			Total
	($ in thousands)
Total revenues	$	28,884		$	—	$	955,075		$	—		$	—		$	983,959
Cost of natural gas and natural gas liquids	—			—		532,719			—			—			532,719
Operations and maintenance	—			—		119,828			—			—			119,828
Taxes other than income	—			—		19,432			—			—			19,432
General and administrative	10,908			—		59,086			—			—			69,994
Depreciation, depletion and amortization	296			—		160,749			—			—			161,045
Impairment	—			—		177,003			—			—			177,003
Income (loss) from operations	17,680			—		(113,742		)	—			—			(96,062		)
Interest expense, net	(51,501		)	—		23			—			—			(51,478		)
Other non-operating income	9,039			—		10,961			—			(20,000		)	—
Other non-operating expense	(12,189		)	—		(12,558		)	(18		)	20,000			(4,765		)
Loss before income taxes	(36,971		)	—		(115,316		)	(18		)	—			(152,305		)
Income tax provision (benefit)	431			—		(2,134		)	—			—			(1,703		)
Equity in earnings of subsidiaries	(113,200		)	—		—			—			113,200			—
Net loss	$	(150,602	)	$	—	$	(113,182	)	$	(18	)	$	113,200		$	(150,602	)
Condensed Consolidating Statement of Operations
For the Year Ended December 31, 2011
	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-guarantor investments			Consolidating			Total
												Entries
	($ in thousands)
Total revenues	$	36,095		$	—	$	1,023,813		$	—		$	—		$	1,059,908
Cost of natural gas and natural gas liquids	—			—		633,184			—			—			633,184
Operations and maintenance	—			—		93,048			—			—			93,048
Taxes other than income	—			—		19,148			—			—			19,148
General and administrative	5,299			—		52,592			—			—			57,891
Other operating income	—			—		(2,893		)	—			—			(2,893		)
Depreciation, depletion and amortization	196			—		131,415			—			—			131,611
Impairment	—			—		16,288			—			—			16,288
Income from operations	30,600			—		81,031			—			—			111,631
Interest expense, net	(29,614		)	—		(8		)	—			—			(29,622		)
Other non-operating income	8,779			—		5,607			—			(14,386		)	—
Other non-operating expense	(28,589		)	—		2,628			(10		)	14,386			(11,585		)
Income (loss) before income taxes	(18,824		)	—		89,258			(10		)	—			70,424
Income tax provision (benefit)	339			—		(2,771		)	—			—			(2,432		)
Equity in earnings of subsidiaries	92,295			—		—			—			(92,295		)	—
Income (loss) from continuing operations	73,132			—		92,029			(10		)	(92,295		)	72,856
Discontinued operations, net of tax	—			—		276			—			—			276
Net income (loss)	$	73,132		$	—	$	92,305		$	(10	)	$	(92,295	)	$	73,132
Condensed Consolidating Statement of Cash Flows
For the Year Ended December 31, 2013
	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-guarantor investments			Consolidating Entries			Total
	($ in thousands)
Net cash flows (used in) provided by operating activities	$	(70,041	)	$	—	$	247,376		$	41		$	—		$	177,376
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment	(115		)	—		(243,315		)	—			—			(243,430		)
Proceeds from sale of asset	—			—		285			—			—			285
Purchase of intangible assets	—			—		(3,903		)	—			—			(3,903		)
Net cash flows used in investing activities	(115		)	—		(246,933		)	—			—			(247,048		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	601,400			—		—			—			—			601,400
Repayment of long-term debt	(503,100		)	—		—			—			—			(503,100		)
Proceeds from derivative contracts	1,323			—		—			—			—			1,323
Common unit issued in equity offerings	102,388			—		—			—			—			102,388
Issuance costs for equity offerings	(4,519		)	—		—			—			—			(4,519		)
Repurchase of common units	(1,858		)	—		—			—			—			(1,858		)
Distributions to members and affiliates	(125,911		)	—		—			—			—			(125,911		)
Net cash flows provided by financing activities	69,723			—		—			—			—			69,723
Net increase (decrease) in cash and cash equivalents	(433		)	—		443			41			—			51
Cash and cash equivalents at beginning of year	1,670			1		(1,832		)	186			—			25
Cash and cash equivalents at end of year	$	1,237		$	1	$	(1,389	)	$	227		$	—		$	76
Condensed Consolidating Statement of Cash Flows
For the Year Ended December 31, 2012
	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-guarantor Investments			Consolidating Entries			Total
	($ in thousands)
Net cash flows (used in) provided by operating activities	$	(143,444	)	$	—	$	288,888		$	57		$	—		$	145,501
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment	(1,551		)	—		(304,473		)	—			—			(306,024		)
Acquisitions, net of cash acquired	—			—		(230,640		)	—			—			(230,640		)
Proceeds from sale of asset	—			—		15,398			—			—			15,398
Purchase of intangible assets	—			—		(7,404		)	—			—			(7,404		)
Contributions to subsidiaries	(236,971		)	—		—			—			236,971			—
Net cash flows used in investing activities	(238,522		)	—		(527,119		)	—			236,971			(528,670		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	1,043,750			—		—			—			—			1,043,750
Repayment of long-term debt	(916,750		)	—		—			—			—			(916,750		)
Proceed from senior notes	246,253			—		—			—			—			246,253
Payments of debt issuance cost	(7,132		)	—		—			—			—			(7,132		)
Proceeds from derivatives contracts	14,449			—		—			—			—			14,449
Common unit issued in equity offerings	96,173			—		—			—			—			96,173
Issuance costs for equity offerings	(4,518		)	—		—			—			—			(4,518		)
Exercise of warrants	31,804			—		—			—			—			31,804
Repurchase of common units	(2,501		)	—		—			—			—			(2,501		)
Distributions to members and affiliates	(119,211		)	—		—			—			—			(119,211		)
Contributions from parent	—			—		236,971			—			(236,971		)	—
Net cash flows provided by financing activities	382,317			—		236,971			—			(236,971		)	382,317
Net (decrease) increase in cash and cash equivalents	351			—		(1,260		)	57			—			(852		)
Cash and cash equivalents at beginning of year	1,319			1		(572		)	129			—			877
Cash and cash equivalents at end of year	$	1,670		$	1	$	(1,832	)	$	186		$	—		$	25
Condensed Consolidating Statement of Cash Flows
For the Year Ended December 31, 2011
	Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-guarantor Investments			Consolidating Entries			Total
	($ in thousands)
Net cash flows (used in) provided by operating activities	$	(27,569	)	$	—	$	145,283		$	86		$	—		$	117,800
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment	(389		)	—		(154,527		)	—			—			(154,916		)
Acquisitions, net of cash acquired	—			—		(220,326		)	—			—			(220,326		)
Proceeds from sale of asset	—			—		5,712			—			—			5,712
Purchase of intangible assets	—			—		(4,406		)	—			—			(4,406		)
Contribution to subsidiaries	(227,583		)	—		—			—			227,583			—
Net cash flows used in investing activities	(227,972		)	—		(373,547		)	—			227,583			(373,936		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	964,279			—		—			—			—			964,279
Repayment of long-term debt	(1,012,779		)	—		—			—			—			(1,012,779		)
Proceed from senior notes	297,837			—		—			—			—			297,837
Payments of debt issuance cost	(17,466		)	—		—			—			—			(17,466		)
Proceeds from derivative contracts	6,267			—		—			—			—			6,267
Exercise of Warrants	89,745			—		—			—			—			89,745
Repurchase of common units	(1,401		)	—		—			—			—			(1,401		)
Distributions to members and affiliates	(74,512		)	—		—			—			—			(74,512		)
Contributions from parent	—			—		227,583			—			(227,583		)	—
Net cash flows provided by financing activities	251,970			—		227,583			—			(227,583		)	251,970
Net cash flows provided by discontinued operations	—			—		994			—			—			994
Net increase (decrease) in cash and cash equivalents	(3,571		)	—		313			86			—			(3,172		)
Cash and cash equivalents at beginning of year	4,890			1		(885		)	43			—			4,049
Cash and cash equivalents at end of year	$	1,319		$	1	$	(572	)	$	129		$	—		$	877

Subsequent_Events_Subsequent_E

Subsequent Events Subsequent Events (Notes)	12 Months Ended
	Dec. 31, 2013
Subsequent Events [Abstract]	'
Subsequent Events [Text Block]	'
	SUBSEQUENT EVENTS
	In February 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) to 5.85x and 3.40x, respectively, 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.
	On February 28, 2014, the Partnership announced that itself and Regency had received a request for additional information and documents from the Federal Trade Commission in connection with the proposed contribution of the Partnership's Midstream Business to Regency.

Supplemental_Oil_and_Gas_Infor

Supplemental Oil and Gas Information (Unaudited)	12 Months Ended
	Dec. 31, 2013
Oil and Gas Exploration and Production Industries Disclosures [Abstract]	'
Oil and Gas Exploration and Production Industries Disclosures [Text Block]	'
	SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)
	Oil and Natural Gas Reserves
	Users of this information should be aware that the process of estimating quantities of proved oil and natural gas reserves is very complex, and requires significant subjective decisions in the evaluation of the available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and changing operating and market conditions. As a result, revisions to reserve estimates may occur from time to time. Although reasonable effort is made to ensure the reported reserve estimates are accurate, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.
	There are numerous uncertainties inherent in estimating the quantities of proved reserves, the future rates of production and the timing of development expenditures. Reserves data represent estimates only and should not be construed as being exact. Moreover, the Standardized Measure of Oil and Gas (“SMOG”) should not be construed as the current market value of the proved oil and natural gas reserves or as the costs that would be incurred to obtain equivalent reserves. A market value determination would include many additional factors including (a) anticipated future changes in natural gas and crude oil prices, production and development costs, (b) an allowance for return on investment, (c) the value of additional reserves, not considered proved at present, which may be recovered as a result of further exploration and development activities, and (d) other business risks.
	Proved Reserves Summary
	The following table illustrates the Partnership's estimated net proved reserves, including changes, and proved developed reserves for the periods indicated, as estimated by Cawley, Gillespie and Associates. Oil and natural gas liquids prices applied for 2013 are based on an average of the prior twelve months first-of-month spot prices of West Texas Intermediate ($96.94 per barrel) and are adjusted for quality, transportation fees, and regional price differentials. Likewise, natural gas prices applied for 2013 are based on an average of the prior twelve months first-of-month spot prices of Henry Hub natural gas ($3.66 per MMBtu) and are adjusted for energy content, transportation fees, and regional price differentials. All prices are held constant in accordance with SEC guidelines.
	As shown in the following reconciliation table, the Partnership recognized significant negative revisions to its estimates of proved natural gas reserves in 2013. These negative revisions were due in large part to the Partnership's decision to remove a number of undeveloped locations from its Five Year Development Plan. These undeveloped locations were expected to generate lower-than-acceptable economic performance given our current outlook for commodity prices, and/or were undeveloped locations on non-operated acreage for which we lacked reasonable certainty of development. These undeveloped locations were recategorized as probable reserves. We also recategorized some undeveloped locations as contingent resources because our revised production and cost forecasts indicated these locations were non-commercial under SEC guidelines at the time of determination.
		Proved Reserves
		Oil			Gas			Natural Gas
		(MBbls)			(MMcf)			Liquids (MBbls)
	Proved reserves, January 1, 2011	8,696			38,382			6,176
	Extensions and discoveries	215			14,523			903
	Purchase of minerals in place	3,830			198,826			4,815
	Production	(1,118	)		(12,636	)		(805	)
	Revision of previous estimates	(101	)		(5,073	)		258
	Proved reserves, December 31, 2011	11,522			234,022			11,347
	Extensions and discoveries	1,405			31,524			2,136
	Purchase of minerals in place	104			128			18
	Production	(1,184	)		(16,443	)		(1,121	)
	Sales of mineral in place	—			(13,331	)		—
	Revision of previous estimates	1,137			(41,471	)		486
	Proved reserves, December 31, 2012	12,984			194,429			12,866
	Extensions and discoveries	2,712			29,137			3,180
	Production	(1,222	)		(12,804	)		(1,156	)
	Revision of previous estimates	(932	)		(33,536	)		(253	)
	Proved reserves, December 31, 2013	13,542			177,226			14,637
	Proved Developed Reserves
	Proved developed reserves, January 1, 2011	8,299			29,686			5,758
	Proved developed reserves, December 31, 2011	10,271			165,269			9,307
	Proved developed reserves, December 31, 2012	10,993			136,545			10,445
	Proved developed reserves, December 31, 2013	10,153			126,950			10,766
	Proved Undeveloped Reserves
	Proved undeveloped reserves, January 1, 2011	397			8,696			418
	Proved undeveloped reserves, December 31, 2011	1,251			68,753			2,040
	Proved undeveloped reserves, December 31, 2012	1,991			57,884			2,421
	Proved undeveloped reserves, December 31, 2013	3,389			50,276			3,871
	The primary drivers behind the changes to our proved reserves for the years ended December 31, 2011, 2012 and 2013 are described in more detail below.
	2011:00:00
	•	purchases of minerals in place were significant in 2011 and were almost entirely related to the Crow Creek Acquisition;
	•	extensions and discoveries were related to drilling by us and other operators on our Crow Creek assets, primarily in the Cana Play and Golden Trend area in Oklahoma; and
	•	revisions to previous estimates were relatively small and were primarily due to reductions caused by changes in condensate and NGL yields at our Big Escambia Creek field, and well performance at our Ward Estes and Ginger fields, partially offset by higher prices which extended the economic life and reserves of some wells.
	2012:00:00
	•	Purchase of minerals in place were insignificant in 2012;
	•	extensions and discoveries were primarily related to drilling by us and other operators in the Golden Trend area and the nearby SCOOP Play in Oklahoma;
	•	sales of minerals in place were related to the sale of our Barnett Shale assets in December 2012; and
	•	revisions to previous estimates were primarily the result of lower natural gas prices which reduced the economic life and reserves of many wells.
	2013:00:00
	•	Purchases and sales of minerals in place did not occur in 2013;
	•	extensions and discoveries were primarily related to drilling by us and other operators in the Golden Trend area and the nearby SCOOP Play in Oklahoma; and
	•	revisions to previous estimates were primarily the result of updating our Five Year Development Plan to recategorize as probable reserves those undeveloped wells that we are not reasonably certain of drilling in five years due to their expected economic performance, or because they are operated by others and we do have assurance from the operators of their intent to develop them; and because we recategorized other proved undeveloped reserves as contingent resources due to revised performance expectations and other factors. All of these revisions were primarily in the Mid-Continent Region.
	Capitalized Costs Relating to Oil and Natural Gas Producing Activities
	The following table illustrates the total amount of capitalized costs relating to oil and natural gas producing activities and the total amount of related accumulated depreciation, depletion and amortization at December 31, 2013, 2012 and 2011:
		As of				As of				As of
		31-Dec-13				31-Dec-12				31-Dec-11
	($ in thousands)
	Proved properties	$	1,156,896			$	1,213,622			$	1,050,872
	Unproved properties—excluded from depletion	10,022				31,823				91,363
	Gross oil and gas properties	1,166,918				1,245,445				1,142,235
	Accumulated depreciation, depletion, amortization	(353,679		)		(269,376		)		(190,833		)
	Net oil and gas properties	$	813,239			$	976,069			$	951,402
	Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities
	Costs incurred in property acquisition, exploration and development activities were as follows for the years ended December 31, 2013, 2012 and 2011:
		Year Ended December 31,
	2013				2012				2011
($ in thousands)
Property acquisition costs, proved	$	—			$	2,582			$	465,088
Property acquisition costs, unproved	—				—				103,337
Development costs	124,032				135,692				90,418
Total costs	$	124,032			$	138,274			$	658,843
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves
The following information has been developed utilizing authoritative guidance procedures and is based on oil and natural gas reserves estimated by the Partnership's independent reserves engineer. It can be used for some comparisons, but should not be the only method used to evaluate the Partnership or its performance. Further, the information in the following table may not represent realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flow be viewed as representative of the current value of the Partnership.
The Partnership believes that the following factors should be taken into account when reviewing the following information:
•	future costs and selling prices will probably differ from those required to be used in these calculations;
•	due to future market conditions and governmental regulations, actual rates of production in future years may vary significantly from the rate of production assumed in the calculations; and
•	a 10% discount rate may not be reasonable as a measure of the relative risk inherent in realizing future net oil and natural gas revenues.
Under the Standardized Measure, future cash inflows were estimated by applying year-end oil and natural gas prices to the estimated future production of year-end proved reserves. Estimates of future income taxes were computed using current statutory income tax rates including consideration for estimated future statutory depletion and tax credits. The resulting net cash flows were reduced to present value amounts by applying a 10% discount factor.
The Partnership's hydrocarbon reserves in Alabama and East Texas contain hydrogen sulfide that must be removed from the natural gas stream before the hydrocarbons are sold. As part of the process to remove the hydrogen sulfide, the Partnership produces and sells elemental sulfur. The Partnership generated revenue from the sale of sulfur of $8.1 million, $14.0 million and $17.8 million in 2013, 2012 and 2011, respectively. The cost of removing the sulfur is included in the future production costs in the Standardized Measure table below. In prior years, the Partnership included the expected revenues from the sale of sulfur as part of the Standardized Measure computation. The Partnership changed that practice in 2013 and now includes only the sale of hydrocarbons in the computation. The Standardized Measure presented as of December 31, 2012 and 2011 in the following table has been adjusted to reflect this change in methodology. No reserve volumes have been booked for sulfur, and the impact of sulfur revenues on the economic limit of reserves in prior years is considered immaterial.
The Standardized Measure is as follows as of December 31, 2013, 2012 and 2011:
	As of				As of				As of
	31-Dec-13				31-Dec-12				31-Dec-11
					(As Adjusted)				(As Adjusted)
($ in thousands)
Future cash inflows	$	2,423,350			$	2,279,735			$	2,516,812
Future production costs	(737,468		)		(767,004		)		(845,530		)
Future development costs	(318,778		)		(354,690		)		(315,019		)
Future net cash flows before income taxes	1,367,104				1,158,041				1,356,263
Future income tax (expense) benefit	(1,212		)		(1,086		)		(1,831		)
Future net cash flows before 10% discount	1,365,892				1,156,955				1,354,432
10% annual discount for estimated timing of cash flows	(715,386		)		(621,826		)		(711,846		)
Total standardized measure of discounted future net cash flows	$	650,506			$	535,129			$	642,586
The tables below present the Partnership’s previously-disclosed SMOG values, the revised values (which exclude sulfur revenues), and the differences between them for years ending December 31, 2012 and 2011.  The differences between the two sets of values are most pronounced in the future cash inflows and future production costs.  The change in future cash inflows is due to a shortening of the economic life of certain properties when sulfur revenues are excluded. The change in future production costs is the result of the exclusion of sulfur revenues, which were historically shown as an offset to the cost to transport and market the sulfur.  In some prior years, the cost to transport and market the sulfur exceeded the total sulfur revenues, resulting in a net cost. In other prior years, sulfur revenues exceeded the cost to transport and market the sulfur, resulting in net positive cash flows. In order to maintain consistency across periods and to show only hydrocarbon revenues as as future cash inflows, the Partnership reported the net impact from the sale of sulfur in all periods within future production costs.
The following summarizes the revisions to the Standardized Measure for fiscal years 2012 and 2011:
	As of
	31-Dec-12
	As Reported				Revisions				As Adjusted
($ in thousands)
Future cash inflows	$	2,315,266			$	(35,531	)		$	2,279,735
Future production costs	(669,896		)		(97,108		)		(767,004		)
Future development costs	(359,154		)		4,464				(354,690		)
Future net cash flows before income taxes	1,286,216				(128,175		)		1,158,041
Future income tax (expense) benefit	(1,321		)		235				(1,086		)
Future net cash flows before 10% discount	1,284,895				(127,940		)		1,156,955
10% annual discount for estimated timing of cash flows	(680,855		)		59,029				(621,826		)
Total standardized measure of discounted future net cash flows	$	604,040			$	(68,911	)		$	535,129
	As of
	31-Dec-11
	As Reported				Revisions				As Adjusted
($ in thousands)
Future cash inflows	$	2,562,650			$	(45,838	)		$	2,516,812
Future production costs	(742,749		)		(102,781		)		(845,530		)
Future development costs	(317,405		)		2,386				(315,019		)
Future net cash flows before income taxes	1,502,496				(146,233		)		1,356,263
Future income tax (expense) benefit	(2,379		)		548				(1,831		)
Future net cash flows before 10% discount	1,500,117				(145,685		)		1,354,432
10% annual discount for estimated timing of cash flows	(778,520		)		66,674				(711,846		)
Total standardized measure of discounted future net cash flows	$	721,597			$	(79,011	)		$	642,586
Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves
The following is a summary of the changes in the Standardized Measure of discounted future net cash flows for the Partnership's proved oil and natural gas reserves for the years ended December 31, 2013, 2012 and 2011:
	Year Ended December 31,
	2013				2012				2011
					(As Adjusted)				(As Adjusted)
($ in thousands)
Beginning of year	$	535,129			$	642,586			$	284,687
Sale of oil and gas produced, net of production costs	(150,457		)		(132,451		)		(138,860		)
Net changes in prices and production costs	2,720				(78,247		)		143,023
Extensions, discoveries and improved recovery, less related costs	136,464				66,460				40,832
Previously estimated development costs incurred during the period	21,470				53,111				90,418
Net changes in future development costs	107,951				36,914				(119,121		)
Revisions of previous quantity estimates	(103,351		)		(76,434		)		(34,497		)
Purchases of property	—				2,811				324,652
Sales of property	—				(5,063		)		—
Accretion of discount	49,233				60,734				26,225
Net changes in income taxes	(36		)		317				(519		)
Other	51,383				(35,609		)		25,746
End of year	$	650,506			$	535,129			$	642,586
The following summarizes the revisions to the changes in the Standardized Measure for fiscal years 2012 and 2011.
	Year Ended December 31, 2012
	As Reported				Revisions				As Adjusted
($ in thousands)
Beginning of year	$	721,597			$	(79,011	)		$	642,586
Sale of oil and gas produced, net of production costs	(132,451		)		—				(132,451		)
Net changes in prices and production costs	(76,759		)		(1,488		)		(78,247		)
Extensions, discoveries and improved recovery, less related costs	66,460				—				66,460
Previously estimated development costs incurred during the period	53,111				—				53,111
Net changes in future development costs	36,503				411				36,914
Revisions of previous quantity estimates	(85,176		)		8,742				(76,434		)
Purchases of property	2,811				—				2,811
Sales of property	(5,063		)		—				(5,063		)
Accretion of discount	67,956				(7,222		)		60,734
Net changes in income taxes	564				(247		)		317
Other	(45,513		)		9,904				(35,609		)
End of year	$	604,040			$	(68,911	)		$	535,129
	Year Ended December 31, 2011
	As Reported				Revisions				As Adjusted
($ in thousands)
Beginning of year	$	333,993			$	(49,306	)		$	284,687
Sale of oil and gas produced, net of production costs	(138,860		)		—				(138,860		)
Net changes in prices and production costs	170,917				(27,894		)		143,023
Extensions, discoveries and improved recovery, less related costs	40,832				—				40,832
Previously estimated development costs incurred during the period	90,418				—				90,418
Net changes in future development costs	(117,783		)		(1,338		)		(119,121		)
Revisions of previous quantity estimates	(26,447		)		(8,050		)		(34,497		)
Purchases of property	324,652				—				324,652
Accretion of discount	30,728				(4,503		)		26,225
Net changes in income taxes	(621		)		102				(519		)
Other	13,768				11,978				25,746
End of year	$	721,597			$	(79,011	)		$	642,586
Results of Operations
The following are the results of operations for the Partnership's oil and natural gas producing activities for the years ended December 31, 2013, 2012 and 2011:
		Year Ended December 31,
		2013				2012				2011
($ in thousands)
Revenues:
Sales to third parties		$	146,210			$	135,842			$	138,383
Intercompany sales		47,048				53,343				48,203
Total revenues		193,258				189,185				186,586
Costs and expenses:
Production costs		54,354				56,734				47,726
General and administrative		11,419				12,162				11,124
Depreciation, depletion, and amortization		87,456				88,777				65,531
Impairment and other		214,286				45,289				11,728
Total costs and expenses		367,515				202,962				136,109
Total result of operations		$	(174,257	)		$	(13,777	)		$	50,477
* * * *

Summary_of_Significant_Account1

Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2013
Accounting Policies [Abstract]	'
Basis of Accounting [Text Block]	'
	Basis of Presentation and Principles of Consolidation—The accompanying audited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (GAAP). 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 consolidated financial statements.
Use of Estimates, Policy [Policy Text Block]	'
	Use of Estimates—The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reported period. Significant estimates are required for proved oil and natural gas reserves, which can affect the carrying value of oil and natural gas properties. The Partnership evaluates its estimates and assumptions on a regular basis. The Partnership bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results could differ from those estimates and such differences could be material.
Cash and Cash Equivalents, Policy [Policy Text Block]	'
	Cash and Cash Equivalents—Cash and cash equivalents include certificates of deposit and other highly liquid investments with maturities of three months or less at the time of purchase.
Concentration Risk Disclosure [Text Block]	'
	Concentration and Credit Risk—Concentration and credit risk for the Partnership principally consists of cash and cash equivalents and accounts receivable.
	The Partnership places its cash and cash equivalents with high-quality institutions and in money market funds. The Partnership derives its revenue from customers primarily in the natural gas industry. Industry concentrations have the potential to impact the Partnership's overall exposure to credit risk, either positively or negatively, in that the Partnership's customers could be affected by similar changes in economic, industry or other conditions. However, the Partnership believes the risk posed by this industry concentration is offset by the creditworthiness of the Partnership's customer base. The Partnership's portfolio of accounts receivable is comprised primarily of mid-size to large domestic corporate entities.
	The following is the activity within the Partnership's allowance for doubtful accounts during the years ended December 31, 2013, 2012 and 2011.
		2013			2012			2011
	($ in thousands)
	Balance at beginning of period	$	972		$	1,347		$	4,496
	Charged to bad debt expense	291			58			54
	Write-offs/adjustments charged to allowance	(75		)	(433		)	(3,203		)
	Balance at end of period	$	1,188		$	972		$	1,347
	During the year ended December 31, 2011, the write off charged to the allowance related to the payment the Partnership received related to the sale of its 503(b)(9) claims related to SemGroup, L.P. ("SemGroup"). This amount relates to the non-503(b)(9) claims and the portion of the receivables sold in August 2009 (see Note 20 for further discussion).
	Certain Other Concentrations—The Partnership relies on natural gas producers for its Midstream Business's natural gas and natural gas liquid supply, with the top two producers (by segment) accounting for 36% of its natural gas supply in the Texas Panhandle Segment and 25% of its natural gas supply in the East Texas and Other Midstream Segment for the year ended December 31, 2013. While there are numerous natural gas and natural gas liquid producers, and some of these producers are subject to long-term contracts, the Partnership may be unable to negotiate extensions or replacements of these contracts on favorable terms, if at all. If the Partnership were to lose all or even a portion of the natural gas volumes supplied by these producers and was unable to acquire comparable volumes, the Partnership's results of operations and financial position could be materially adversely affected. These percentages are calculated based on natural gas volumes gathered during the year ended December 31, 2013. For the year ended December 31, 2013, Oneok, Inc. and Chevron Corporation, the Partnership's largest customers, represented 22% and 11%, respectively, of its total sales revenue (including its commodity risk management gains and losses).
Inventory Finished Goods, Policy [Policy Text Block]	'
	Inventory—Inventory is stated at the lower of cost or market, with cost being determined using the average cost method. At December 31, 2013 and December 31, 2012, the Partnership had $1.0 million and $0.8 million, respectively, of crude oil finished goods inventory which is recorded as part of Other Current Assets within the audited consolidated balance sheet.
Property, Plant and Equipment, Policy [Policy Text Block]	'
	Property, Plant and Equipment—Property, plant and equipment consists primarily of gas gathering systems, gas processing plants, NGL pipelines, conditioning and treating facilities and other related facilities, and oil and natural gas properties, which are carried at cost less accumulated depreciation, depletion and amortization. The Partnership charges repairs and maintenance against income when incurred and capitalizes renewals and betterments, which extend the useful life or expand the capacity of the assets. The Partnership capitalizes interest costs on major projects during extended construction time periods. Such interest costs are allocated to property, plant and equipment and amortized over the estimated useful lives of the related assets. The Partnership calculates depreciation on the straight-line method over estimated useful lives of the Partnership's newly developed or acquired assets. The weighted average useful lives are as follows:
	Plant Assets	20 years
	Pipelines and equipment	20 years
	Gas processing and equipment	20 years
	Office furniture and equipment	5 years
Full Cost or Successful Efforts, Policy [Policy Text Block]	'
	Oil and Natural Gas Properties—The Partnership utilizes the successful efforts method of accounting for its oil and natural gas properties. Leasehold costs are capitalized when incurred. Costs incurred to drill and complete development wells are capitalized. Geological and geophysical expenses and delay rentals are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if the well is determined to be unsuccessful. The Partnership carries the costs of an exploratory well as an asset if the well is found to have a sufficient quantity of reserves to justify its capitalization as a producing well as long as the Partnership is making sufficient progress towards assessing the reserves and the economic and operating viability of the project.
	Depletion of producing oil and natural gas properties is recorded based on units of production. Unit rates are computed for unamortized drilling and development costs using proved developed reserves and for acquisition costs using all proved reserves. Authoritative guidance requires that acquisition costs of proved properties be amortized on the basis of all proved reserves (developed and undeveloped), and that capitalized development costs (wells and related equipment and facilities) be amortized on the basis of proved developed reserves.
	Upon sale or retirement of complete fields of depreciable or depleted property, the book value thereof, less proceeds or salvage value, is charged or credited to income.
	Costs related to unproved properties include costs incurred to acquire unproved reserves.  Because these reserves do not meet the definition of proved reserves, the related costs are not classified as proved properties.  Unproved leasehold costs are capitalized and amortized on a composite basis if individually insignificant, based on past success, experience, drilling plans and average lease-term lives.  Unamortized leasehold costs related to successful exploratory drilling are reclassified to proved properties and depleted on a units of production basis.  Unproved properties (both individually significant and insignificant) are assessed periodically within specific geographic areas and, if necessary, impairments are charged to expense.
Other Assets Disclosure [Text Block]	'
	Other Assets— As of December 31, 2013, other assets primarily consist of costs associated with debt issuance costs, net of amortization, of $15.4 million; business deposits to various providers and state or regulatory agencies of $6.5 million; and investment in unconsolidated affiliates of $0.9 million. As of December 31, 2012, other assets primarily consist of costs associated with debt issuance costs, net of amortization, of $19.5 million; business deposits to various providers and state or regulatory agencies of $2.2 million; and investment in unconsolidated affiliates of $0.9 million.
Impairment or Disposal of Long-Lived Assets, Policy [Policy Text Block]	'
	Impairment of Long-Lived Assets—Management evaluates whether the carrying value of non-oil and natural gas long-lived assets has been impaired when circumstances indicate the carrying value of those assets may not be recoverable. This evaluation is based on undiscounted cash flow projections. The carrying amount is not recoverable if it exceeds the undiscounted sum of cash flows expected to result from the use and eventual disposition of the assets. Management considers various factors when determining if these assets should be evaluated for impairment, including, but not limited to:
	•	significant adverse changes in legal factors or in the business climate;
	•	a current-period operating or cash flow loss combined with a history of operating or cash flow losses or a projection or forecast which demonstrates continuing losses associated with the use of a long-lived asset;
	•	an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of a long-lived asset;
	•	significant adverse changes in the extent or manner in which an asset is used or in its physical condition;
	•	a significant change in the market value of an asset; or
	•	a current expectation that, more likely than not, an asset will be sold or otherwise disposed of before the end of its estimated useful life.
	For its oil and natural gas long-lived assets, the Partnership reviews its proved properties at the field level when management determines that events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. Such events include a negative revision or unfavorable projection of future oil and natural gas reserves and/or forward prices that will be produced from a field, the timing of this future production, future costs to produce the oil and natural gas, and future inflation levels.
	If the carrying value is not recoverable on an undiscounted basis, the impairment loss is measured as the excess of the asset's carrying value over its fair value. Management assesses the fair value of long-lived assets using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales, internally developed discounted cash flow analysis and analysis from outside advisors. Significant changes in market conditions resulting from events such as the condition of an asset or a change in management's intent to utilize the asset would generally require management to reassess the cash flows related to the long-lived assets.
	See Note 5 for further discussion on impairment charges.
Revenue Recognition, Policy [Policy Text Block]	'
	Revenue Recognition—Eagle Rock Energy's primary types of sales and service activities reported as operating revenue include:
	•	sales of natural gas, NGLs, crude oil, condensate and sulfur;
	•	natural gas gathering, processing and transportation, from which Eagle Rock Energy 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 and sulfur are recognized when title passes to the customer, which is when the risk of ownership passes to the customer and physical delivery occurs. Revenues 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. Imbalances are reflected as adjustments to reported natural gas reserves and future cash flows.  For the Upstream Segment, as of December 31, 2013 and December 31, 2012, the Partnership had long-term imbalance payables of $0.3 million and $0.6 million, 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 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 December 31, 2013, the Partnership had imbalance receivables totaling $0.7 million and imbalance payables totaling $1.6 million. For the Midstream Business, as of December 31, 2012, the Partnership had imbalance receivables totaling $0.9 million and imbalance payables totaling $2.1 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.
Environmental Costs, Policy [Policy Text Block]	'
	Environmental Expenditures—Environmental expenditures are expensed or capitalized as appropriate, depending upon the future economic benefit. Expenditures which relate to an existing condition caused by past operations and do not generate current or future revenue are expensed. Liabilities for these expenditures are recorded on an undiscounted basis when environmental assessments and/or clean-ups are probable and the costs can be reasonably estimated.
Income Tax, Policy [Policy Text Block]	'
	Income Taxes—Provision for income taxes is primarily applicable to the Partnership's state tax obligations under the Revised Texas Franchise Tax (the “Revised Texas Franchise Tax”) and certain federal and state tax obligations of Eagle Rock Energy Acquisition Co., Inc., Eagle Rock Acquisition Co. II, Inc., Eagle Rock Upstream Development Company, Inc. and Eagle Rock Upstream Development Company II, Inc., all of which are consolidated subsidiaries. Deferred income tax assets and liabilities are recognized for temporary differences between the assets and liabilities of the tax paying entities for financial reporting and tax purposes.
	In general, legal entities that conduct business in Texas are subject to the Revised Texas Franchise Tax. In May 2006, the State of Texas expanded its pre-existing franchise tax to include limited partnerships, limited liability companies, corporations and limited liability partnerships. As a result of the change in tax law, the Partnership's tax status in the State of Texas changed from non-taxable to taxable effective with the 2007 tax year.
	Since the Partnership is structured as a pass-through entity, it is not subject to federal income taxes. As a result, its partners are individually responsible for paying federal and certain income taxes on their share of the Partnership's taxable income. Since the Partnership does not have access to information regarding each partner's tax basis, it cannot readily determine the total difference in the basis of the Partnership's net assets for financial and tax reporting purposes.
Derivatives, Policy [Policy Text Block]	'
	Derivatives—Authoritative guidance establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. It requires an entity to recognize all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. The guidance provides that normal purchase and sale contracts, when appropriately designated, are not subject to the guidance. Normal purchases and sales are contracts which provide for the purchase or sale of something, other than a financial instrument or derivative instrument that will be delivered in quantities expected to be used or sold by the reporting entity over a reasonable period in the normal course of business. The Partnership's forward natural gas and crude oil purchase and sales contracts are designated as normal purchases and normal sales, with the exception of certain contracts with our 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 consolidated balance sheet at the instrument's fair value with changes in fair value reflected in the consolidated statement of operations, as the Partnership has not designated any of these derivative instruments as hedges. The cash flows from derivatives are reported as cash flows from operating activities unless the derivative contract is deemed to contain a financing element. Derivatives deemed to contain a financing element are reported as a financing activity in the statement of cash flows. See Note 11 for a description of the Partnership's risk management activities.
Reclassifications [Text Block]	'
	Other Reclassifications—The prior period within the audited 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. For its producing oil and natural gas properties, the Partnership makes estimates of property abandonment costs that, in some cases, will not be incurred until a substantial number of years in the future. Such cost estimates could be subject to significant revisions in subsequent years due to increases in current abandonment costs, changes in regulatory requirements, technological advances and other factors that may be difficult to predict. The Partnership recognizes asset retirement obligations for its midstream assets in accordance with the term “conditional asset retirement obligation,” which refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional upon a future event that may or may not be within the Partnership's control. Although uncertainty about the timing and/or method of settlement may exist and may be conditional upon a future event, the obligation to perform the asset retirement activity is unconditional. Accordingly, the Partnership is required to recognize a liability for the fair value of a conditional asset retirement obligation upon initial recognition if the fair value of the liability can be reasonably estimated. The fair value of additions to the asset retirement obligations is estimated using valuation techniques that covert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of (i) remediation costs, (ii) remaining lives, (iii) future inflation factors and (iv) a credit-adjusted risk free interest rate.
Intangible Assets, Finite-Lived, Policy [Policy Text Block]	'
	Intangible assets consist of rights-of-way and easements 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 period for contracts ranges from 5 to 20 years.
Earnings Per Share, Policy [Policy Text Block]	'
	As of December 31, 2013, 2012 and 2011, the Partnership had unvested restricted common units outstanding, which are considered dilutive securities. These units will be considered in the diluted weighted average common unit outstanding number in periods of net income. In periods of net losses, these units are excluded from the diluted weighted average common unit outstanding number.
	Any warrants outstanding during the period are considered to be dilutive securities. These outstanding warrants will be considered in the diluted weighted average common units outstanding number in periods of net income, except if the exercise price of the outstanding warrants is greater than the average market price of the common units for such periods. In periods of net losses, the outstanding warrants are excluded from the diluted weighted average common units outstanding.

Summary_of_Significant_Account2

Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2013
Accounting Policies [Abstract]	'
Movement in Valuation Allowances and Reserves [Roll Forward]	'
	The following is the activity within the Partnership's allowance for doubtful accounts during the years ended December 31, 2013, 2012 and 2011.
		2013			2012			2011
	($ in thousands)
	Balance at beginning of period	$	972		$	1,347		$	4,496
	Charged to bad debt expense	291			58			54
	Write-offs/adjustments charged to allowance	(75		)	(433		)	(3,203		)
	Balance at end of period	$	1,188		$	972		$	1,347

Acquisitions_Acquisitions_Tabl

Acquisitions Acquisitions (Tables)	12 Months Ended
	Dec. 31, 2013
Business Combinations [Abstract]	'
Schedule of Business Acquisitions, by Acquisition [Table Text Block]	'
	The following presents the purchase price allocation for the Crow Creek Energy assets, based on estimates of fair value (in thousands):
	Current assets	$	25,329
	Oil and gas properties	572,097
	Property, plant and equipment	4,463
	Rights-of-way and easements	3,192
	Other assets	450
	Derivatives	3,355
	Current liabilities	(37,032		)
	Asset retirement obligations	(4,394		)
	Deferred tax liability	(2,312		)
	Other liabilities	(1,440		)
		$	563,708
	The following presents the purchase price allocation for the system assets, based on estimates of fair value (in thousands):
	Current assets	$	779
	Property, plant, and equipment	206,849
	Rights-of-way and easements	27,232
	Current liabilities	(1,705		)
	Asset retirement obligations	(2,600		)
		$	230,555
	On May 3, 2011, the Partnership completed the acquisition (the "Mid-Continent Acquisition") of all of the outstanding membership interests of CC Energy II L.L.C (together with its subsidiaries, "Crow Creek Energy"), a portfolio company of Natural Gas Partners, VIII, L.P. ("NGP VIII"). Crow Creek Energy has oil and natural gas properties located in multiple basins across Oklahoma, north Texas and Arkansas (the "Mid-Continent" properties) and provides the Partnership with an extensive inventory of low-risk development prospects in established plays such as the Golden Trend field and developing plays such as the Cana Shale. The aggregate purchase price has been calculated as follows (in thousands, except unit and per unit amounts):
	Number of Partnership Common Units Issued	28,753,174
	Closing common unit price on May 3, 2011	$	11.69
	Value of common units issued	$	336,125
	Crow Creek Energy outstanding debt assumed	212,638
	Cash	14,945
	Total purchase price	$	563,708
Business Acquisition, Pro Forma Information [Table Text Block]	'
	The amounts of Crow Creek Energy's revenue and net income included within the Partnership's audited consolidated statement of operations for the year ended December 31, 2011, and the pro forma revenue and net income of the combined entity had the acquisition date been January 1, 2010, are as follows:
		Revenue			Net Income		Net Income Per Diluted Common Unit
		($ in thousands)
	Actual from May 3, 2011 to December 31, 2011	$	68,168		$	29,835
	Supplemental pro forma from January 1, 2011 to December 31, 2011	$	1,080,964		$	78,591	$	0.62
	The amounts of revenue and net income generated by the acquired processing plants and gathering systems that are included within the Partnership's audited consolidated statement of operations for the year ended December 31, 2012 are as follows.
		Revenue			Net Income
		($ in thousands)
	Actual from October 1, 2012 to December 31, 2012	$	81,013		$	5,057

Property_Plant_and_Equipment_P

Property, Plant and Equipment Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2013
Property, Plant and Equipment [Abstract]	'
Property, Plant and Equipment [Table Text Block]	'
	Fixed assets consisted of the following:
		December 31,			December 31,
		2013			2012
		($ in thousands)
	Land	$	2,877		$	2,876
	Plant	521,103			444,023
	Gathering and pipeline	777,446			753,009
	Equipment and machinery	53,999			39,889
	Vehicles and transportation equipment	4,001			4,021
	Office equipment, furniture, and fixtures	1,309			1,285
	Computer equipment	14,806			11,431
	Linefill	5,180			4,328
	Proved properties	1,156,896			1,213,622
	Unproved properties	10,022			31,823
	Construction in progress	33,824			60,870
		2,581,463			2,567,177
	Less: accumulated depreciation, depletion and amortization	(752,695		)	(598,971		)
	Net property plant and equipment	$	1,828,768		$	1,968,206
	The following table sets forth the total depreciation, depletion, capitalized interest costs and impairment expense by type of asset within the Partnership's audited consolidated statements of operations:
		Year Ended December 31,
		2013			2012			2011
		($ in thousands)
	Depreciation	$	69,449		$	61,390		$	54,606
	Depletion	$	87,230		$	88,413		$	65,380
	Capitalized interest costs	$	963		$	1,311		$	451
	Impairment expense:
	Proved properties (a)	$	207,085		$	38,943		$	11,239
	Unproved properties (b)	$	7,201		$	785		$	489
	Plant assets (c)	$	—		$	57,527		$	4,560
	Pipeline assets (c)	$	—		$	52,537		$	—
	__________________________________
	(a)	During the year ended December 31, 2013, the Partnership incurred impairment charges in its Upstream Business related primarily to certain proved properties, primarily in the Cana Shale in the Mid-Continent region and the Permian region, due to lower reserve forecasts. During the year ended December 31, 2012, the Partnership incurred impairment charges in its Upstream Business related to its proved properties in the Barnett Shale, East Texas and Permian regions that experienced reduced cash flows resulting from lower natural gas prices and continuing high operating costs associated with gas compression. During the year ended December 31, 2011, the Partnership incurred impairment charges in its Upstream Business related to certain proved properties in the Jourdanton field in South Texas, which included plans for five future drilling locations that the Partnership has determined not to pursue due to the current natural gas price environment.
	(b)	During the year ended December 31, 2013, the Partnership incurred impairment charges in its Upstream Business related to certain leaseholds in the Mid-Continent regions that we expect to expire undrilled in 2014. During the year ended December 31, 2012, the Partnership incurred impairment charges in its Upstream Business related to certain unproved property leaseholds expected to expire undrilled in 2013. During the year ended December 31, 2011, the Partnership incurred impairment charges related to certain drilling locations in its unproved properties which the Partnership no longer intends to develop based on the performance of offsetting wells.
	(c)	During the year ended December 31, 2012, the Partnership incurred impairment charges in its Midstream Business related to certain plants and pipelines in its East Texas and Other Midstream Segment due to (i) reduced throughput volumes as its producer customers curtailed their drilling activity in response to the continued depressed natural gas price environment (ii) the loss of significant gathering contracts on its Panola and other systems and (iii) the substantial damage incurred at the Yscloskey processing plant as a result of Hurricane Isaac in August 2012. The value of assets for both the Panola system and the Yscloskey plant have been fully written down. During the year ended December 31, 2011, the Partnership recorded an impairment charge in its Texas Panhandle Segment to fully write-down its idle Turkey Creek plant.

Asset_Retirement_Obligations_A

Asset Retirement Obligations Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2013
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:
		2013			2012			2011
		($ in thousands)
	Asset retirement obligations—January 1	$	48,755		$	33,303		$	24,711
	Additional liabilities	1,140			1,721			159
	Liabilities settled	(2,240		)	(2,755		)	(465		)
	Revision to liabilities	7,603			11,471			2,339
	Additional liability related to acquisitions	—			2,650			4,413
	Accretion expense	3,706			2,365			2,146
	Asset retirement obligations—December 31 (a)	$	58,964		$	48,755		$	33,303
	_____________________________________
	(a)    As of December 31, 2013 and 2012, $13.1 million and $3.9 million , respectively, were included within accrued liabilities in the Consolidated Balance Sheets.

Intangible_Assets_Intangible_A

Intangible Assets Intangible Assets (Tables)	12 Months Ended
	Dec. 31, 2013
Goodwill and Intangible Assets Disclosure [Abstract]	'
Schedule of Finite-Lived Intangible Assets by Major Class [Table Text Block]	'
	Intangible assets consisted of the following:
		December 31,			December 31,
		2013			2012
		($ in thousands)
	Rights-of-way and easements—at cost	$	131,088		$	127,375
	Less: accumulated amortization	(36,228		)	(29,959		)
	Contracts	22,742			38,009
	Less: accumulated amortization	(11,982		)	(23,910		)
	Net intangible assets	$	105,620		$	111,515
Schedule of Impaired Intangible Assets [Table Text Block]	'
	The following table sets forth the total amortization and impairment expense by type of intangible assets within the Partnership's audited consolidated statements of operations:
		Year Ended December 31,
		2013			2012			2011
		($ in thousands)
	Amortization	$	10,078		$	11,205		$	11,588
	Impairment expense:
	Rights-of-way (a)	$	—		$	5,266		$	—
	Contracts (a)	$	—		$	16,384		$	—
	_____________________________________
	(a)	During the year ended December 31, 2012, the Partnership incurred impairment charges in its Midstream Business related to certain rights-of-way and contracts in its East Texas and Other Midstream Segment due to (i) reduced throughput volumes as its producer customers curtailed their drilling activities due to the continued decline in natural gas prices during the first three months of 2012 and (ii) the termination of significant gathering contracts on its Panola system during the year ended December 31, 2012. The value of the contracts and rights-of-way related to the Panola system have been fully written down.
Schedule of Finite-Lived Intangible Assets, Future Amortization Expense [Table Text Block]	'
	Estimated future amortization expense related to the intangible assets at December 31, 2013, is as follows (in thousands):
	Year ending December 31,
	2014	$	7,958
	2015	$	7,957
	2016	$	7,957
	2017	$	7,956
	2018	$	7,955
	Thereafter	$	65,837

Long_Term_Debt_LongTerm_Debt_T

Long Term Debt Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2013
Long-term Debt, by Current and Noncurrent [Abstract]	'
Schedule of Debt Covenants [Table Text Block]	'
	The following table presents the debt covenant levels specified in our revolving credit facility as of December 31, 2013:
	Quarter Ended	Total Leverage Ratio	Senior Secured Leverage Ratio	Interest Coverage Ratio	Current Ratio
	31-Dec-13	5.5	3.15	2.5	1
	31-Mar-14	5.25	3.1	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	NA	2.5	1
	The following table presents the Partnership's actual covenant ratios as of December 31, 2013:
	Interest coverage ratio	3.1
	Total leverage ratio	5.4
	Senior secured leverage ratio	3.06
	Current ratio	1.1
Schedule of Long-term Debt Instruments [Table Text Block]	'
	Long-term debt consisted of the following:
		December 31,				December 31,
		2013				2012
		($ in thousands)
	Revolving credit facility:	$	706,800			$	608,500
	Senior notes:
	8.375% senior notes due 2019	550,000				550,000
	Unamortized bond discount	(4,738		)		(5,397		)
	Total senior notes	545,262				544,603
	Total long-term debt	$	1,252,062			$	1,153,103
Schedule of Maturities of Long-term Debt [Table Text Block]	'
	Scheduled maturities of long-term debt as of December 31, 2013, were as follows:
		Principal Amount
		($ in thousands)
	2014	$	—
	2015	—
	2016	706,800
	2017	—
	2018	—
	2019 and after	550,000
		$	1,256,800

Members_Equity_Members_Equity_

Members' Equity Members' Equity (Tables)	12 Months Ended
	Dec. 31, 2013
Partners' Capital [Abstract]	'
Schedule of Distributions Made to Members or Limited Partners, by Distribution [Table Text Block]	'
	The Partnership has declared a cash distribution for each quarter since its initial public offering. The table below summarizes these distributions for the last three years.
	Quarter Ended		Distribution		Record Date**	Payment Date
			per Unit
	March 31, 2011+		$	0.15	May 9, 2011	May 13, 2011
	June 30, 2011+		$	0.1875	August 5, 2011	August 12, 2011
	September 30, 2011+		$	0.2	November 4, 2011	November 14, 2011
	December 31, 2011+		$	0.21	February 7, 2012	February 14, 2012
	March 31, 2012+		$	0.22	May 8, 2012	May 15, 2012
	June 30, 2012+		$	0.22	August 7, 2012	August 14, 2012
	September 30, 2012+		$	0.22	November 7, 2012	November 14, 2012
	December 31, 2012+		$	0.22	February 7, 2013	February 14, 2013
	March 31, 2013+*		$	0.22	May 7, 2013	May 15, 2013
	June 30, 2013+*		$	0.22	August 7, 2013	August 14, 2013
	September 30, 2013+*		$	0.15	November 7, 2013	November 14, 2013
	December 31, 2013+*		$	0.15	February 7, 2014	February 14, 2014
	_____________________________
	+	The distribution per unit represents distributions made only on common units, including restricted common units issued under our Long Term Incentive Plan. Since July 30, 2010, the only other class of equity we have outstanding is a non-economic general partner interest.
	*	The distribution excludes certain restricted 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)	12 Months Ended
	Dec. 31, 2013
Related Party Transactions [Abstract]	'
Schedule of Related Party Transactions [Table Text Block]	'
	The following table summarizes transactions between the Partnership and affiliated entities:
		Year Ended December 31,
		2013		2012		2011
	Affiliates of NGP:	($ in thousands)
	Natural gas purchases from affiliates	$	2,938	$	2,713	$	6,097
	Payable as of December 31,	$	18	$	428

Risk_Management_Activities_Ris

Risk Management Activities Risk Management Activities (Tables)	12 Months Ended
	Dec. 31, 2013
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'
Schedule of Interest Rate Derivatives [Table Text Block]	'
	The following table sets forth certain information regarding the Partnership's various interest rate swaps as of December 31, 2013:
	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 December 31, 2013, 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)		16,800,000		$	4.38
	Crude Oil		Costless Collar		240,000		$	90			$	106
	Crude Oil		Swap (Pay Floating/Receive Fixed)		2,208,000		$	96.51
	Crude Oil		Swap (Pay Fixed/Receive Floating)		199,140		$	92.53
	Propane		Swap (Pay Floating/Receive Fixed)		9,576,000		$	1.06
	IsoButane		Swap (Pay Floating/Receive Fixed)		2,268,000		$	1.31
	Normal Butane		Swap (Pay Floating/Receive Fixed)		4,132,800		$	1.3
	Portion of 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
	Portion of Contracts Maturing in 2016
	Natural Gas		Swap (Pay Floating/Receive Fixed)		9,480,000		$	4.25
	Crude Oil		Swap (Pay Floating/Receive Fixed)		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. The weighted average prices are in $/MMbtu for natural gas, $/barrel for crude oil and $/gallon for natural gas liquids
	Marketing and Trading commodity derivative instruments, as of December 31, 2013, that will mature during the years ended December 31, 2014 and 2015 and beyond:
	Type		Notional Volumes (MMbtu)
	Portion of Contracts Maturing in 2014
	Basis Swaps - Purchases		6,955,000
	Basis Swaps - Sales		2,675,000
	Index Swap - Purchases		620,000
	Index Swap - Sales		1,365,000
	Swap (Pay Fixed/Receive Floating) - Purchases		930,000
	Swap (Pay Floating/Received Fixed) - Sales		465,000
	Forward purchase contract - index		13,090,332
	Forward sales contract - index		18,873,397
	Forward purchase contract - fixed price		2,263,000
	Forward sales contract - fixed price		2,728,000
	Portion of Contracts Maturing in 2015 and beyond
	Basis Swaps - Purchases		13,280,000
	Basis Swaps - Sales		13,280,000
	Changes in the fair value of these financial and physical contracts are recorded as adjustments to natural gas sales.
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block]	'
	Fair values of interest rate and commodity derivative instruments not designated as hedging instruments in the consolidated balance sheet as of December 31, 2013 and December 31, 2012:
		As of
		31-Dec-13
		Derivative Assets					Derivative Liabilities
		Balance Sheet Classification		Fair Value			Balance Sheet Classification		Fair Value
		($ in thousands)
	Interest rate derivatives - liabilities	Current assets		$	—		Current liabilities		$	(6,210	)
	Interest rate derivatives - liabilities	Long-term assets		—			Long-term liabilities		(2,885		)
	Commodity derivatives - assets	Current assets		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	)
		As of
		31-Dec-12
		Derivative Assets					Derivative Liabilities
		Balance Sheet Classification		Fair Value			Balance Sheet Classification		Fair Value
		($ in thousands)
	Interest rate derivatives - liabilities	Current assets		$	(4,844	)	Current liabilities		$	(1,201	)
	Interest rate derivatives - liabilities	Long-term assets		(7,002		)	Long-term liabilities		(1,700		)
	Commodity derivatives - assets	Current assets		39,182			Current liabilities		19
	Commodity derivatives - assets	Long-term assets		17,338			Long-term liabilities		—
	Commodity derivatives - liabilities	Current assets		(998		)	Current liabilities		(49		)
	Commodity derivatives - liabilities	Long-term assets		(2,383		)	Long-term liabilities		—
	Total derivatives			$	41,293				$	(2,931	)
Schedule of Derivative Instruments, Gain (Loss) in Statement of Financial Performance [Table Text Block]	'
	The following table sets forth the location of gains and losses for derivatives not designated as hedging instruments within the Partnership's audited consolidated statement of operations (in thousands):
	Amount of Gain (Loss) Recognized in Income on Derivatives			Year Ended December 31,
				2013			2012				2011
	Interest rate derivatives	Interest rate risk management losses, net		$	(1,104	)	$	(4,727	)		$	(11,401	)
	Commodity derivatives	Commodity risk management gains (losses), net		(18,533		)	57,894				32,510
	Commodity derivatives -trading	Natural gas, natural gas liquids, oil, condensate and sulfur sales		315			(192		)		772
		Total		$	(19,322	)	$	52,975			$	21,881

Fair_Value_of_Financial_Instru1

Fair Value of Financial Instruments Fair Value of Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2013
Fair Value Disclosures [Abstract]	'
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]	'
	The following table discloses the fair value of the Partnership's derivative instruments as of December 31, 2013 and 2012:
		As of
		31-Dec-13
		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 agreement governing such derivative contracts.
		As of
		31-Dec-12
		Level 1		Level 2			Level 3			Netting (a)			Total
		($ in thousands)
	Assets:
	Crude oil derivatives	$	—	$	19,410		$	—		$	(1,814	)	$	17,596
	Natural gas derivatives	—		27,340			—			(1,586		)	25,754
	NGL derivatives	—		9,789			—			—			9,789
	Interest rate swaps	—		—			—			(11,846		)	(11,846		)
	Total	$	—	$	56,539		$	—		$	(15,246	)	$	41,293
	Liabilities:
	Crude oil derivatives	$	—	$	(1,814	)	$	—		$	1,814		$	—
	Natural gas derivatives	—		(1,616		)	—			1,586			(30		)
	Interest rate swaps	—		(14,747		)	—			11,846			(2,901		)
	Total	$	—	$	(18,177	)	$	—		$	15,246		$	(2,931	)
	____________________________
	(a)	Represents counterparty netting under agreement governing such derivative contracts.
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Table Text Block]	'
	The following table sets forth a reconciliation of changes in the fair value of the Level 3 NGL derivatives during the years ended December 31, 2013, 2012 and 2011 (in thousands):
		Year Ended December 31,
		2013		2012			2011
	Net liability beginning balance	$	—	$	—		$	(5,733	)
	Settlements	—		—			15,562
	Total gains or losses	—		—			(12,784		)
	Transfers out of Level 3	—		—			2,955
	Net liability ending balance	$	—	$	—		$	—
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis [Table Text Block]	'
	The following table discloses the fair value of the Partnership's assets measured at fair value on a nonrecurring basis for the year ended December 31, 2013:
		December 31,		Level 1			Level 2			Level 3			Total Losses
		2013
		($ in thousands)
	Proved properties	$	91,346	$	—		$	—		$	91,346		$	207,085

Segments_Segments_Tables

Segments Segments (Tables)	12 Months Ended
	Dec. 31, 2013
Segment Reporting [Abstract]	'
Schedule of Segment Reporting Information, by Segment [Table Text Block]	'
	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:
			Texas			East Texas and Other				Marketing				Total				Upstream				Corporate					Total
	Year Ended December 31, 2013		Panhandle			Midstream				and Trading Segment				Midstream				Segment				and Other Segment					Segments
			Segment			Segment								Business
	($ in thousands)
	Sales to external customers		$	538,492		$	136,637			$	384,422			$	1,059,551			$	154,261			$	(18,533	)	(a)		$	1,195,279
	Intersegment sales		226,576			37,716				(272,116		)		(7,824		)		47,048				(39,224		)			—
	Cost of natural gas and natural gas liquids		594,125			131,966				64,527				790,618				—				—					790,618
	Intersegment cost of natural gas, oil and condensate		200			—				38,844				39,044				—				(39,044		)			—
	Operating costs and other expenses		81,186			19,943				(8		)		101,121				54,354				81,214					236,689
	Depreciation, depletion, amortization		57,781			19,476				428				77,685				87,456				2,029					167,170
	Impairment		—			—				—				—				214,286				—					214,286
	Operating income (loss) from continuing operations		$	31,776		$	2,968			$	8,515			$	43,259			$	(154,787	)		$	(101,956	)			$	(213,484	)
	Capital Expenditures		$	81,590		$	7,827			$	309			$	89,726			$	129,099			$	5,336				$	224,161
	Segment Assets		$	950,092		$	243,493			$	73,918			$	1,267,503			$	842,246			$	17,801		(b)		$	2,127,550
	Year Ended December 31, 2012		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		$	362,902	(c)		$	156,529			$	256,772			$	776,203			$	149,862			$	57,894		(a)		$	983,959
	Intersegment sales		105,759				39,099				(154,992		)		(10,134		)		53,343				(43,209		)			—
	Cost of natural gas and natural gas liquids		332,792				147,493				52,434				532,719				—				—					532,719
	Intersegment cost of natural gas,oil and condensate		83				—				44,317				44,400				—				(44,400		)			—
	Operating costs and other expenses		60,884				21,762				2				82,648				56,612				69,994					209,254
	Intersegment operations and maintenance		—				—				—				—				122				(122		)			—
	Depreciation, depletion, amortization		44,451				25,771				273				70,495				88,777				1,773					161,045
	Impairment		—				131,714				—				131,714				45,289				—					177,003
	Operating income (loss) from continuing operations		$	30,451			$	(131,112	)		$	4,754			$	(95,907	)		$	12,405			$	(12,560	)			$	(96,062	)
	Capital Expenditures		$	131,928			$	9,328			$	5,489			$	146,745			$	160,330			$	3,645				$	310,720
	Segment Assets		$	922,281			$	250,916			$	43,417			$	1,216,614			$	1,018,927			$	58,675		(b)		$	2,294,216
			Texas			East Texas and Other				Marketing				Total				Upstream					Corporate					Total
	Year Ended December 31, 2011		Panhandle			Midstream				and Trading Segment				Midstream				Segment					and Other Segment					Segments
			Segment			Segment								Business
	($ in thousands)
	Sales to external customers		$	395,991		$	274,361			$	200,939			$	871,291			$	156,107		(d)		$	32,510		(a)		$	1,059,908
	Intersegment sales		60,237			16,654				(82,378		)		(5,487		)		48,203					(42,716		)			—
	Cost of natural gas and natural gas liquids		327,775			231,642				73,767				633,184				—					—					633,184
	Intersegment cost of natural gas, oil and condensate		—			—				41,382				41,382				—					(41,382		)			—
	Operating costs and other expenses		41,749			22,790				—				64,539				47,657					54,998					167,194
	Intersegment operations and maintenance		—			—				—				—				66					(66		)			—
	Depreciation, depletion, amortization		37,034			27,629				—				64,663				65,531					1,417					131,611
	Impairment		4,560			—				—				4,560				11,728					—					16,288
	Operating income (loss) from continuing operations		$	45,110		$	8,954			$	3,412			$	57,476			$	79,328				$	(25,173	)			$	111,631
	Capital Expenditures		$	71,351		$	10,860			$	2,205			$	84,416			$	92,660				$	2,132				$	179,208
	Segment Assets		$	599,688		374,030				$	40,173			$	1,013,891			$	979,331				$	52,466		(b)		$	2,045,688
	______________________________
	(a)	Represents results of the Partnership's commodity risk management activity.
	(b)	Includes elimination of intersegment transactions.
	(c)	Sales to external customers in the Texas Panhandle Segment for the year ended December 31, 2012, includes 2.9 million of business interruption insurance recovery related to damage sustained by the Partnership's Cargray processing facility due to severe winter weather in 2011, which is recognized as part of Other Revenue in the consolidated statements of operations.
	(d)	Sales to external customers for the years ended December 31, 2011 includes $2.0 million, respectively, of business interruption insurance recovery related to the shutdown of the Eustace plant in 2010 in the Upstream Segment, which is recognized as part of Other revenue in the consolidated statement of operations.

Income_Taxes_Income_Taxes_Tabl

Income Taxes Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2013
Income Tax Disclosure [Abstract]	'
Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]	'
	The Partnership's federal and state income tax provision is summarized below (in thousands):
		For the Year Ended December 31,
		2013			2012			2011
	Current:
	Federal	$	(105	)	$	621		$	1,092
	State	—			18			61
	Total current provision	(105		)	639			1,153
	Deferred:
	Federal	(3,837		)	(2,776		)	(3,862		)
	State	(1,172		)	434			277
	Total deferred	(5,009		)	(2,342		)	(3,585		)
	Total (benefit) provision for income taxes	$	(5,114	)	$	(1,703	)	(2,432		)
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]	'
	A reconciliation of the provision for income taxes with amounts determined by applying the statutory U.S. federal income tax rate to income before income taxes is as follows (in thousands):
		For the Year Ended December 31,
		2013			2012			2011
	Pre-tax net book income (loss) from continuing operations	(283,093		)	(152,305		)	70,424
	State income tax current and deferred	(1,172		)	452			338
	Federal income taxes computed by applying the federal statutory rate to NBI of corporate entities	(4,160		)	(2,155		)	(2,232		)
	Tax attributes used	218			—			(538		)
	Benefit for income taxes from continuing operations	$	(5,114	)	$	(1,703	)	$	(2,432	)
	Effective income tax rate on continuing operations	1.8		%	1.1		%	(3.5		)%
Schedule of Deferred Tax Assets and Liabilities [Table Text Block]	'
	Significant components of deferred tax liabilities and deferred tax assets as of December 31, 2013 and 2012 are as follows (in thousands):
		December 31, 2013			December 31, 2012
	Deferred Tax Assets:
	Statutory depletion carryover	$	1,438		$	1,599
	AMT credit carryforward	—			57
	Total Deferred Tax Assets	1,438			1,656
	Deferred Tax Liabilities:
	Property, plant, equipment & amortizable assets	(5,867		)	(6,585		)
	Hedging transactions	—			(271		)
	Book/tax differences from partnership investment	(32,086		)	(36,144		)
	Total Deferred Tax Liabilities	(37,953		)	(43,000		)
	Total Net Deferred Tax Liabilities	(36,515		)	(41,344		)
	Current portion of total net deferred tax liabilities	—			—
	Long-term portion of total net deferred tax liabilities	$	(36,515	)	$	(41,344	)
Summary of Income Tax Contingencies [Table Text Block]	'
	A reconciliation of the beginning and ending amount of the unrecognized tax benefits (liabilities) is as follows (in thousands):
		2013			2012			2011
	Balance at beginning of period	$	(830	)	$	(735	)	$	(569	)
	Increases related to current year tax positions	(128		)	(53		)	(132		)
	Increases related to tax interest and penalties	(39		)	(42		)	(34		)
	Decreases related to statutory limitations	267			—			—
	Decreases related to tax interest and penalties	81			—			—
	Balance at end of period	$	(649	)	$	(830	)	$	(735	)

Equity_Based_Compensation_Equi

Equity Based Compensation Equity Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2013
Share-based Compensation [Abstract]	'
Schedule of Share-based Compensation, Stock Options, Activity [Table Text Block]	'
	A summary of the restricted common units’ activity for the year ended December 31, 2013 is provided below:
		Number of		Weighted
		Restricted		Average
		Units		Fair Value
	Outstanding at December 31, 2012	2,608,035		$	9.38
	Granted	1,623,939		$	9.16
	Vested	(1,203,822	)	$	8.98
	Forfeited	(284,345	)	$	9.9
	Outstanding at December 31, 2013	2,743,807		$	9.37

Earnings_Per_Unit_Earnings_Per

Earnings Per Unit Earnings Per Unit (Tables)	12 Months Ended
	Dec. 31, 2013
Earnings Per Unit [Abstract]	'
Schedule of Weighted Average Number of Shares [Table Text Block]	'
	The following table presents the Partnership's calculation of basic and diluted units outstanding for the periods indicated:
		Year Ended December 31,
		2013			2012		2011
		(in thousands)
	Weighted average units outstanding during period:
	Common units - Basic	153,562			135,609		110,435
	Effect of Dilutive Securities:
	Warrants	—			—		5,727
	Restricted Units	—			—		779
	Common units - Diluted	153,562			135,609		116,941
Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]	'
	The following table presents the Partnership's basic income per unit for the year ended December 31, 2013:
			Total			Common Units			Restricted Common Units
			($ in thousands, except for per unit amounts)
	Net loss		$	(277,979	)
	Distributions		117,294			$	115,351		$	1,943
	Assumed loss from continuing operations after distribution to be allocated		(395,273		)	(395,273		)	—
	Assumed net (loss) income to be allocated		$	(277,979	)	$	(279,922	)	$	1,943
	Basic and diluted loss per unit					$	(1.82	)
	The following table presents the Partnership's basic and diluted income per unit for the year ended December 31, 2012:
			Total			Common Units			Restricted Common Units
			($ in thousands, except for per unit amounts)
	Loss from continuing operations		$	(150,602	)
	Distributions		124,235			$	121,504		$	2,731
	Assumed loss from continuing operations after distribution to be allocated		(274,837		)	(274,837		)	—
	Assumed net income to be allocated		$	(150,602	)	$	(153,333	)	$	2,731
	Basic and diluted loss per unit					$	(1.13	)
	The following table presents the Partnership's basic and diluted income per unit for the year ended December 31, 2011:
			Total			Common Units			Restricted Common Units
			($ in thousands, except for per unit amounts)
	Loss from continuing operations		$	72,856
	Distributions		89,062			$	87,525		$	1,537
	Assumed loss from continuing operations after distribution to be allocated		(16,206		)	(16,206		)	—
	Assumed allocation of loss from continuing operations		72,856			71,319			1,537
	Discontinued operations, net of tax		276			276			—
	Assumed net income to be allocated		$	73,132		$	71,595		$	1,537
	Basic income from continuing operations per unit					$	0.65
	Basic discontinued operations per unit					$	—
	Basic net income per unit					$	0.65
	Diluted income from continuing operations per unit					$	0.61
	Diluted discontinued operations per unit					$	—
	Diluted net income per unit					$	0.62

Divestiture_Related_Activities1

Divestiture Related Activities Divestiture Related Activities (Tables)	12 Months Ended
	Dec. 31, 2013
Discontinued Operations and Disposal Groups [Abstract]	'
Schedule of Disposal Groups, Including Discontinued Operations, Income Statement, Balance Sheet and Additional Disclosures [Table Text Block]	'
	The following table represents activity from divestiture related activities for the years ended December 31, 2013, 2012 and 2011:
			Barnett Shale (a)			Wildhorse System (b)			Minerals Business (c)
	($ in thousands)
	Year Ended December 31, 2012:
	Loss from the sale		$	(4,460	)	$	—		$	—
	Proceeds from sale		$	14,841		$	—		$	—
	Year Ended December 31, 2011:
	Revenues		$	—		$	6,859		$	—
	(Loss) income from Operations		$	—		$	548		$	—
	Discontinued operations, net of tax		$	—		$	(180	)	$	456
	Loss from the sale		$	—		$	(718	)	—
	Proceeds from sale		$	—		$	5,712		—
	_____________________________
	(a)	On December 20, 2012, the Partnership sold its Barnett Shale properties (which was accounted for in its Upstream Segment). In 2012, the Partnership incurred a loss from sale which is included within impairment expense in the Consolidated Statement of Operations.
	(b)	On May 20, 2011, the Partnership sold its Wildhorse Gathering System (which was accounted for in its East Texas and Other Midstream Segment).
	(c)	On May 24, 2010, the Partnership completed the sale of its Minerals Business. During the year ended December 31, 2011, the Partnership received payments related to pre-effective date operations and recorded this amount as part of discontinued operations for the period.

Subsidiary_Guarantors_Subsidia

Subsidiary Guarantors Subsidiary Guarantors (Tables)	12 Months Ended
	Dec. 31, 2013
SUBSIDIARY GUARANTORS UNAUDITED CONSOLIDATING BALANCE SHEET [Abstract]	'
Subsidiary Guarantor Consolidating Balance Sheet [Table Text Block]	'
	Condensed Consolidating Balance Sheet
	December 31, 2013
		Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-guarantor investments			Consolidating			Total
													Entries
		($ 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
	Condensed Consolidating Balance Sheet
	December 31, 2012
		Parent Issuer			Co-Issuer		Subsidiary			Non-guarantor investments			Consolidating Entries			Total
							Guarantors
		($ in thousands)
	ASSETS:
	Accounts receivable – related parties	$	660,898		$	—	$	—		$	—		$	(660,898	)	$	—
	Other current assets	27,688			1		154,275			—			—			181,964
	Total property, plant and equipment, net	2,657			—		1,965,549			—			—			1,968,206
	Investment in subsidiaries	1,324,293			—		—			958			(1,325,251		)	—
	Total other long-term assets	22,061			—		121,985			—			—			144,046
	Total assets	$	2,037,597		$	1	$	2,241,809		$	958		$	(1,986,149	)	$	2,294,216
	LIABILITIES AND EQUITY:
	Accounts payable – related parties	$	—		$	—	$	660,898		$	—		$	(660,898	)	$	—
	Other current liabilities	6,734			—		174,780			—			—			181,514
	Other long-term liabilities	9,386			—		81,839			—			—			91,225
	Long-term debt	1,153,103			—		—			—			—			1,153,103
	Equity	868,374			1		1,324,292			958			(1,325,251		)	868,374
	Total liabilities and equity	$	2,037,597		$	1	$	2,241,809		$	958		$	(1,986,149	)	$	2,294,216
Subsidiary Guarantors Consolidating Statements of Operations [Table Text Block]	'
	Condensed Consolidating Statement of Operations
	For the Year Ended December 31, 2013
		Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-guarantor investments			Consolidating			Total
													Entries
		($ in thousands)
	Total revenues	$	(4,168	)	$	—	$	1,199,447		$	—		$	—		$	1,195,279
	Cost of natural gas and natural gas liquids	—			—		790,618			—			—			790,618
	Operations and maintenance	(1		)	—		135,206			—			—			135,205
	Taxes other than income	—			—		20,270			—			—			20,270
	General and administrative	17,716			—		63,498			—			—			81,214
	Depreciation, depletion and amortization	454			—		166,716			—			—			167,170
	Impairment and other	—			—		214,286			—			—			214,286
	Loss from operations	(22,337		)	—		(191,147		)	—			—			(213,484		)
	Interest expense, net	(67,864		)	—		(898		)	—			—			(68,762		)
	Other non-operating income	9,025			—		9,298			—			(18,323		)	—
	Other non-operating expense	(6,904		)	—		(12,256		)	(10		)	18,323			(847		)
	Loss before income taxes	(88,080		)	—		(195,003		)	(10		)	—			(283,093		)
	Income tax benefit	(1,172		)	—		(3,942		)	—			—			(5,114		)
	Equity in earnings of subsidiaries	(191,071		)	—		—			—			191,071			—
	Net loss	$	(277,979	)	$	—	$	(191,061	)	$	(10	)	$	191,071		$	(277,979	)
	Condensed Consolidating Statement of Operations
	For the Year Ended December 31, 2012
		Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-guarantor investments			Consolidating Entries			Total
		($ in thousands)
	Total revenues	$	28,884		$	—	$	955,075		$	—		$	—		$	983,959
	Cost of natural gas and natural gas liquids	—			—		532,719			—			—			532,719
	Operations and maintenance	—			—		119,828			—			—			119,828
	Taxes other than income	—			—		19,432			—			—			19,432
	General and administrative	10,908			—		59,086			—			—			69,994
	Depreciation, depletion and amortization	296			—		160,749			—			—			161,045
	Impairment	—			—		177,003			—			—			177,003
	Income (loss) from operations	17,680			—		(113,742		)	—			—			(96,062		)
	Interest expense, net	(51,501		)	—		23			—			—			(51,478		)
	Other non-operating income	9,039			—		10,961			—			(20,000		)	—
	Other non-operating expense	(12,189		)	—		(12,558		)	(18		)	20,000			(4,765		)
	Loss before income taxes	(36,971		)	—		(115,316		)	(18		)	—			(152,305		)
	Income tax provision (benefit)	431			—		(2,134		)	—			—			(1,703		)
	Equity in earnings of subsidiaries	(113,200		)	—		—			—			113,200			—
	Net loss	$	(150,602	)	$	—	$	(113,182	)	$	(18	)	$	113,200		$	(150,602	)
	Condensed Consolidating Statement of Operations
	For the Year Ended December 31, 2011
		Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-guarantor investments			Consolidating			Total
													Entries
		($ in thousands)
	Total revenues	$	36,095		$	—	$	1,023,813		$	—		$	—		$	1,059,908
	Cost of natural gas and natural gas liquids	—			—		633,184			—			—			633,184
	Operations and maintenance	—			—		93,048			—			—			93,048
	Taxes other than income	—			—		19,148			—			—			19,148
	General and administrative	5,299			—		52,592			—			—			57,891
	Other operating income	—			—		(2,893		)	—			—			(2,893		)
	Depreciation, depletion and amortization	196			—		131,415			—			—			131,611
	Impairment	—			—		16,288			—			—			16,288
	Income from operations	30,600			—		81,031			—			—			111,631
	Interest expense, net	(29,614		)	—		(8		)	—			—			(29,622		)
	Other non-operating income	8,779			—		5,607			—			(14,386		)	—
	Other non-operating expense	(28,589		)	—		2,628			(10		)	14,386			(11,585		)
	Income (loss) before income taxes	(18,824		)	—		89,258			(10		)	—			70,424
	Income tax provision (benefit)	339			—		(2,771		)	—			—			(2,432		)
	Equity in earnings of subsidiaries	92,295			—		—			—			(92,295		)	—
	Income (loss) from continuing operations	73,132			—		92,029			(10		)	(92,295		)	72,856
	Discontinued operations, net of tax	—			—		276			—			—			276
	Net income (loss)	$	73,132		$	—	$	92,305		$	(10	)	$	(92,295	)	$	73,132
Subsidiary Guarantor Consolidating Statements of Cash Flows [Table Text Block]	'
	Condensed Consolidating Statement of Cash Flows
	For the Year Ended December 31, 2013
		Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-guarantor investments			Consolidating Entries			Total
		($ in thousands)
	Net cash flows (used in) provided by operating activities	$	(70,041	)	$	—	$	247,376		$	41		$	—		$	177,376
	CASH FLOWS FROM INVESTING ACTIVITIES:
	Additions to property, plant and equipment	(115		)	—		(243,315		)	—			—			(243,430		)
	Proceeds from sale of asset	—			—		285			—			—			285
	Purchase of intangible assets	—			—		(3,903		)	—			—			(3,903		)
	Net cash flows used in investing activities	(115		)	—		(246,933		)	—			—			(247,048		)
	CASH FLOWS FROM FINANCING ACTIVITIES:
	Proceeds from long-term debt	601,400			—		—			—			—			601,400
	Repayment of long-term debt	(503,100		)	—		—			—			—			(503,100		)
	Proceeds from derivative contracts	1,323			—		—			—			—			1,323
	Common unit issued in equity offerings	102,388			—		—			—			—			102,388
	Issuance costs for equity offerings	(4,519		)	—		—			—			—			(4,519		)
	Repurchase of common units	(1,858		)	—		—			—			—			(1,858		)
	Distributions to members and affiliates	(125,911		)	—		—			—			—			(125,911		)
	Net cash flows provided by financing activities	69,723			—		—			—			—			69,723
	Net increase (decrease) in cash and cash equivalents	(433		)	—		443			41			—			51
	Cash and cash equivalents at beginning of year	1,670			1		(1,832		)	186			—			25
	Cash and cash equivalents at end of year	$	1,237		$	1	$	(1,389	)	$	227		$	—		$	76
	Condensed Consolidating Statement of Cash Flows
	For the Year Ended December 31, 2012
		Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-guarantor Investments			Consolidating Entries			Total
		($ in thousands)
	Net cash flows (used in) provided by operating activities	$	(143,444	)	$	—	$	288,888		$	57		$	—		$	145,501
	CASH FLOWS FROM INVESTING ACTIVITIES:
	Additions to property, plant and equipment	(1,551		)	—		(304,473		)	—			—			(306,024		)
	Acquisitions, net of cash acquired	—			—		(230,640		)	—			—			(230,640		)
	Proceeds from sale of asset	—			—		15,398			—			—			15,398
	Purchase of intangible assets	—			—		(7,404		)	—			—			(7,404		)
	Contributions to subsidiaries	(236,971		)	—		—			—			236,971			—
	Net cash flows used in investing activities	(238,522		)	—		(527,119		)	—			236,971			(528,670		)
	CASH FLOWS FROM FINANCING ACTIVITIES:
	Proceeds from long-term debt	1,043,750			—		—			—			—			1,043,750
	Repayment of long-term debt	(916,750		)	—		—			—			—			(916,750		)
	Proceed from senior notes	246,253			—		—			—			—			246,253
	Payments of debt issuance cost	(7,132		)	—		—			—			—			(7,132		)
	Proceeds from derivatives contracts	14,449			—		—			—			—			14,449
	Common unit issued in equity offerings	96,173			—		—			—			—			96,173
	Issuance costs for equity offerings	(4,518		)	—		—			—			—			(4,518		)
	Exercise of warrants	31,804			—		—			—			—			31,804
	Repurchase of common units	(2,501		)	—		—			—			—			(2,501		)
	Distributions to members and affiliates	(119,211		)	—		—			—			—			(119,211		)
	Contributions from parent	—			—		236,971			—			(236,971		)	—
	Net cash flows provided by financing activities	382,317			—		236,971			—			(236,971		)	382,317
	Net (decrease) increase in cash and cash equivalents	351			—		(1,260		)	57			—			(852		)
	Cash and cash equivalents at beginning of year	1,319			1		(572		)	129			—			877
	Cash and cash equivalents at end of year	$	1,670		$	1	$	(1,832	)	$	186		$	—		$	25
	Condensed Consolidating Statement of Cash Flows
	For the Year Ended December 31, 2011
		Parent Issuer			Co-Issuer		Subsidiary Guarantors			Non-guarantor Investments			Consolidating Entries			Total
		($ in thousands)
	Net cash flows (used in) provided by operating activities	$	(27,569	)	$	—	$	145,283		$	86		$	—		$	117,800
	CASH FLOWS FROM INVESTING ACTIVITIES:
	Additions to property, plant and equipment	(389		)	—		(154,527		)	—			—			(154,916		)
	Acquisitions, net of cash acquired	—			—		(220,326		)	—			—			(220,326		)
	Proceeds from sale of asset	—			—		5,712			—			—			5,712
	Purchase of intangible assets	—			—		(4,406		)	—			—			(4,406		)
	Contribution to subsidiaries	(227,583		)	—		—			—			227,583			—
	Net cash flows used in investing activities	(227,972		)	—		(373,547		)	—			227,583			(373,936		)
	CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	964,279			—		—			—			—			964,279
Repayment of long-term debt	(1,012,779		)	—		—			—			—			(1,012,779		)
Proceed from senior notes	297,837			—		—			—			—			297,837
Payments of debt issuance cost	(17,466		)	—		—			—			—			(17,466		)
Proceeds from derivative contracts	6,267			—		—			—			—			6,267
Exercise of Warrants	89,745			—		—			—			—			89,745
Repurchase of common units	(1,401		)	—		—			—			—			(1,401		)
Distributions to members and affiliates	(74,512		)	—		—			—			—			(74,512		)
Contributions from parent	—			—		227,583			—			(227,583		)	—
Net cash flows provided by financing activities	251,970			—		227,583			—			(227,583		)	251,970
Net cash flows provided by discontinued operations	—			—		994			—			—			994
Net increase (decrease) in cash and cash equivalents	(3,571		)	—		313			86			—			(3,172		)
Cash and cash equivalents at beginning of year	4,890			1		(885		)	43			—			4,049
Cash and cash equivalents at end of year	$	1,319		$	1	$	(572	)	$	129		$	—		$	877

Supplemental_Oil_and_Gas_Infor1

Supplemental Oil and Gas Information (Unaudited) Supplemental Oil and Gas Information (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2013
Oil and Gas Exploration and Production Industries Disclosures [Abstract]	'
Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities [Table Text Block]	'
	Proved Reserves Summary
	The following table illustrates the Partnership's estimated net proved reserves, including changes, and proved developed reserves for the periods indicated, as estimated by Cawley, Gillespie and Associates. Oil and natural gas liquids prices applied for 2013 are based on an average of the prior twelve months first-of-month spot prices of West Texas Intermediate ($96.94 per barrel) and are adjusted for quality, transportation fees, and regional price differentials. Likewise, natural gas prices applied for 2013 are based on an average of the prior twelve months first-of-month spot prices of Henry Hub natural gas ($3.66 per MMBtu) and are adjusted for energy content, transportation fees, and regional price differentials. All prices are held constant in accordance with SEC guidelines.
	As shown in the following reconciliation table, the Partnership recognized significant negative revisions to its estimates of proved natural gas reserves in 2013. These negative revisions were due in large part to the Partnership's decision to remove a number of undeveloped locations from its Five Year Development Plan. These undeveloped locations were expected to generate lower-than-acceptable economic performance given our current outlook for commodity prices, and/or were undeveloped locations on non-operated acreage for which we lacked reasonable certainty of development. These undeveloped locations were recategorized as probable reserves. We also recategorized some undeveloped locations as contingent resources because our revised production and cost forecasts indicated these locations were non-commercial under SEC guidelines at the time of determination.
		Proved Reserves
		Oil			Gas			Natural Gas
		(MBbls)			(MMcf)			Liquids (MBbls)
	Proved reserves, January 1, 2011	8,696			38,382			6,176
	Extensions and discoveries	215			14,523			903
	Purchase of minerals in place	3,830			198,826			4,815
	Production	(1,118	)		(12,636	)		(805	)
	Revision of previous estimates	(101	)		(5,073	)		258
	Proved reserves, December 31, 2011	11,522			234,022			11,347
	Extensions and discoveries	1,405			31,524			2,136
	Purchase of minerals in place	104			128			18
	Production	(1,184	)		(16,443	)		(1,121	)
	Sales of mineral in place	—			(13,331	)		—
	Revision of previous estimates	1,137			(41,471	)		486
	Proved reserves, December 31, 2012	12,984			194,429			12,866
	Extensions and discoveries	2,712			29,137			3,180
	Production	(1,222	)		(12,804	)		(1,156	)
	Revision of previous estimates	(932	)		(33,536	)		(253	)
	Proved reserves, December 31, 2013	13,542			177,226			14,637
	Proved Developed Reserves
	Proved developed reserves, January 1, 2011	8,299			29,686			5,758
	Proved developed reserves, December 31, 2011	10,271			165,269			9,307
	Proved developed reserves, December 31, 2012	10,993			136,545			10,445
	Proved developed reserves, December 31, 2013	10,153			126,950			10,766
	Proved Undeveloped Reserves
	Proved undeveloped reserves, January 1, 2011	397			8,696			418
	Proved undeveloped reserves, December 31, 2011	1,251			68,753			2,040
	Proved undeveloped reserves, December 31, 2012	1,991			57,884			2,421
	Proved undeveloped reserves, December 31, 2013	3,389			50,276			3,871
	The primary drivers behind the changes to our proved reserves for the years ended December 31, 2011, 2012 and 2013 are described in more detail below.
	2011:00:00
	•	purchases of minerals in place were significant in 2011 and were almost entirely related to the Crow Creek Acquisition;
	•	extensions and discoveries were related to drilling by us and other operators on our Crow Creek assets, primarily in the Cana Play and Golden Trend area in Oklahoma; and
	•	revisions to previous estimates were relatively small and were primarily due to reductions caused by changes in condensate and NGL yields at our Big Escambia Creek field, and well performance at our Ward Estes and Ginger fields, partially offset by higher prices which extended the economic life and reserves of some wells.
	2012:00:00
	•	Purchase of minerals in place were insignificant in 2012;
	•	extensions and discoveries were primarily related to drilling by us and other operators in the Golden Trend area and the nearby SCOOP Play in Oklahoma;
	•	sales of minerals in place were related to the sale of our Barnett Shale assets in December 2012; and
	•	revisions to previous estimates were primarily the result of lower natural gas prices which reduced the economic life and reserves of many wells.
	2013:00:00
	•	Purchases and sales of minerals in place did not occur in 2013;
	•	extensions and discoveries were primarily related to drilling by us and other operators in the Golden Trend area and the nearby SCOOP Play in Oklahoma; and
	•	revisions to previous estimates were primarily the result of updating our Five Year Development Plan to recategorize as probable reserves those undeveloped wells that we are not reasonably certain of drilling in five years due to their expected economic performance, or because they are operated by others and we do have assurance from the operators of their intent to develop them; and because we recategorized other proved undeveloped reserves as contingent resources due to revised performance expectations and other factors. All of these revisions were primarily in the Mid-Continent Region.
Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure [Table Text Block]	'
	The following table illustrates the total amount of capitalized costs relating to oil and natural gas producing activities and the total amount of related accumulated depreciation, depletion and amortization at December 31, 2013, 2012 and 2011:
		As of				As of				As of
		31-Dec-13				31-Dec-12				31-Dec-11
	($ in thousands)
	Proved properties	$	1,156,896			$	1,213,622			$	1,050,872
	Unproved properties—excluded from depletion	10,022				31,823				91,363
	Gross oil and gas properties	1,166,918				1,245,445				1,142,235
	Accumulated depreciation, depletion, amortization	(353,679		)		(269,376		)		(190,833		)
	Net oil and gas properties	$	813,239			$	976,069			$	951,402
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure [Table Text Block]	'
	Costs incurred in property acquisition, exploration and development activities were as follows for the years ended December 31, 2013, 2012 and 2011:
		Year Ended December 31,
		2013				2012				2011
	($ in thousands)
	Property acquisition costs, proved	$	—			$	2,582			$	465,088
	Property acquisition costs, unproved	—				—				103,337
	Development costs	124,032				135,692				90,418
	Total costs	$	124,032			$	138,274			$	658,843
Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure [Table Text Block]	'
	The Standardized Measure is as follows as of December 31, 2013, 2012 and 2011:
		As of				As of				As of
		31-Dec-13				31-Dec-12				31-Dec-11
						(As Adjusted)				(As Adjusted)
	($ in thousands)
	Future cash inflows	$	2,423,350			$	2,279,735			$	2,516,812
	Future production costs	(737,468		)		(767,004		)		(845,530		)
	Future development costs	(318,778		)		(354,690		)		(315,019		)
	Future net cash flows before income taxes	1,367,104				1,158,041				1,356,263
	Future income tax (expense) benefit	(1,212		)		(1,086		)		(1,831		)
	Future net cash flows before 10% discount	1,365,892				1,156,955				1,354,432
	10% annual discount for estimated timing of cash flows	(715,386		)		(621,826		)		(711,846		)
	Total standardized measure of discounted future net cash flows	$	650,506			$	535,129			$	642,586
	The tables below present the Partnership’s previously-disclosed SMOG values, the revised values (which exclude sulfur revenues), and the differences between them for years ending December 31, 2012 and 2011.  The differences between the two sets of values are most pronounced in the future cash inflows and future production costs.  The change in future cash inflows is due to a shortening of the economic life of certain properties when sulfur revenues are excluded. The change in future production costs is the result of the exclusion of sulfur revenues, which were historically shown as an offset to the cost to transport and market the sulfur.  In some prior years, the cost to transport and market the sulfur exceeded the total sulfur revenues, resulting in a net cost. In other prior years, sulfur revenues exceeded the cost to transport and market the sulfur, resulting in net positive cash flows. In order to maintain consistency across periods and to show only hydrocarbon revenues as as future cash inflows, the Partnership reported the net impact from the sale of sulfur in all periods within future production costs.
	The following summarizes the revisions to the Standardized Measure for fiscal years 2012 and 2011:
		As of
		31-Dec-12
		As Reported				Revisions				As Adjusted
	($ in thousands)
	Future cash inflows	$	2,315,266			$	(35,531	)		$	2,279,735
	Future production costs	(669,896		)		(97,108		)		(767,004		)
	Future development costs	(359,154		)		4,464				(354,690		)
	Future net cash flows before income taxes	1,286,216				(128,175		)		1,158,041
	Future income tax (expense) benefit	(1,321		)		235				(1,086		)
	Future net cash flows before 10% discount	1,284,895				(127,940		)		1,156,955
	10% annual discount for estimated timing of cash flows	(680,855		)		59,029				(621,826		)
	Total standardized measure of discounted future net cash flows	$	604,040			$	(68,911	)		$	535,129
		As of
		31-Dec-11
		As Reported				Revisions				As Adjusted
	($ in thousands)
	Future cash inflows	$	2,562,650			$	(45,838	)		$	2,516,812
	Future production costs	(742,749		)		(102,781		)		(845,530		)
	Future development costs	(317,405		)		2,386				(315,019		)
	Future net cash flows before income taxes	1,502,496				(146,233		)		1,356,263
	Future income tax (expense) benefit	(2,379		)		548				(1,831		)
	Future net cash flows before 10% discount	1,500,117				(145,685		)		1,354,432
	10% annual discount for estimated timing of cash flows	(778,520		)		66,674				(711,846		)
	Total standardized measure of discounted future net cash flows	$	721,597			$	(79,011	)		$	642,586
Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows [Table Text Block]	'
	Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves
	The following is a summary of the changes in the Standardized Measure of discounted future net cash flows for the Partnership's proved oil and natural gas reserves for the years ended December 31, 2013, 2012 and 2011:
		Year Ended December 31,
		2013				2012				2011
						(As Adjusted)				(As Adjusted)
	($ in thousands)
	Beginning of year	$	535,129			$	642,586			$	284,687
	Sale of oil and gas produced, net of production costs	(150,457		)		(132,451		)		(138,860		)
	Net changes in prices and production costs	2,720				(78,247		)		143,023
	Extensions, discoveries and improved recovery, less related costs	136,464				66,460				40,832
	Previously estimated development costs incurred during the period	21,470				53,111				90,418
	Net changes in future development costs	107,951				36,914				(119,121		)
	Revisions of previous quantity estimates	(103,351		)		(76,434		)		(34,497		)
	Purchases of property	—				2,811				324,652
	Sales of property	—				(5,063		)		—
	Accretion of discount	49,233				60,734				26,225
	Net changes in income taxes	(36		)		317				(519		)
	Other	51,383				(35,609		)		25,746
	End of year	$	650,506			$	535,129			$	642,586
	The following summarizes the revisions to the changes in the Standardized Measure for fiscal years 2012 and 2011.
		Year Ended December 31, 2012
		As Reported				Revisions				As Adjusted
	($ in thousands)
	Beginning of year	$	721,597			$	(79,011	)		$	642,586
	Sale of oil and gas produced, net of production costs	(132,451		)		—				(132,451		)
	Net changes in prices and production costs	(76,759		)		(1,488		)		(78,247		)
	Extensions, discoveries and improved recovery, less related costs	66,460				—				66,460
	Previously estimated development costs incurred during the period	53,111				—				53,111
	Net changes in future development costs	36,503				411				36,914
	Revisions of previous quantity estimates	(85,176		)		8,742				(76,434		)
	Purchases of property	2,811				—				2,811
	Sales of property	(5,063		)		—				(5,063		)
	Accretion of discount	67,956				(7,222		)		60,734
	Net changes in income taxes	564				(247		)		317
	Other	(45,513		)		9,904				(35,609		)
	End of year	$	604,040			$	(68,911	)		$	535,129
		Year Ended December 31, 2011
		As Reported				Revisions				As Adjusted
	($ in thousands)
	Beginning of year	$	333,993			$	(49,306	)		$	284,687
	Sale of oil and gas produced, net of production costs	(138,860		)		—				(138,860		)
	Net changes in prices and production costs	170,917				(27,894		)		143,023
	Extensions, discoveries and improved recovery, less related costs	40,832				—				40,832
	Previously estimated development costs incurred during the period	90,418				—				90,418
	Net changes in future development costs	(117,783		)		(1,338		)		(119,121		)
	Revisions of previous quantity estimates	(26,447		)		(8,050		)		(34,497		)
	Purchases of property	324,652				—				324,652
	Accretion of discount	30,728				(4,503		)		26,225
	Net changes in income taxes	(621		)		102				(519		)
	Other	13,768				11,978				25,746
	End of year	$	721,597			$	(79,011	)		$	642,586
Results of Operations for Oil and Gas Producing Activities Disclosure [Table Text Block]	'
	Results of Operations
	The following are the results of operations for the Partnership's oil and natural gas producing activities for the years ended December 31, 2013, 2012 and 2011:
			Year Ended December 31,
			2013				2012				2011
	($ in thousands)
	Revenues:
	Sales to third parties		$	146,210			$	135,842			$	138,383
	Intercompany sales		47,048				53,343				48,203
	Total revenues		193,258				189,185				186,586
	Costs and expenses:
	Production costs		54,354				56,734				47,726
	General and administrative		11,419				12,162				11,124
	Depreciation, depletion, and amortization		87,456				88,777				65,531
	Impairment and other		214,286				45,289				11,728
	Total costs and expenses		367,515				202,962				136,109
	Total result of operations		$	(174,257	)		$	(13,777	)		$	50,477

Organization_and_Description_o1

Organization and Description of Business Narrative (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Subordinated Long-term Debt, Noncurrent	$550,000,000	$550,000,000
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 Discontinued Operation, Consideration, Adjustment	55,000,000	'
Disposal Group, Including Discontinued Operation, Consideration, Cash	520,000,000	'
Scenario, Adjustment [Member] | Total Midstream Segments [Member]	'	'
Disposal Group, Including Discontinued Operation, Consideration	$1,270,000,000	'

Summary_of_Significant_Account3

Summary of Significant Accounting Policies Allowance for Doubtful Accounts (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Movement in Valuation Allowances and Reserves [Roll Forward]	'	'	'
Valuation Allowances and Reserves, Beginning Balance	$972	$1,347	$4,496
Valuation Allowances and Reserves, Charged to Cost and Expense	291	58	54
Valuation Allowances and Reserves, Deductions	-75	-433	-3,203
Valuation Allowances and Reserves, Ending Balance	$1,188	$972	$1,347

Summary_of_Significant_Account4

Summary of Significant Accounting Policies Narrative (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013
In Millions, unless otherwise specified			Oneok, Inc. [Member]	Chevron Corporation, Inc. [Member]	Panhandle Segment [Member]	East Texas and Other Midstream Segment [Member]	Natural Gas Processing Plant [Member]	Pipelines [Member]	Gas Gathering and Processing Equipment [Member]	Furniture and Fixtures [Member]
Major producer, percentage	'	'	'	'	36.00%	25.00%	'	'	'	'
Entity-wide revenue, major customer, percent	'	'	22.00%	11.00%	'	'	'	'	'	'
Inventory, Finished Goods	$1	$0.80	'	'	'	'	'	'	'	'
Property, Plant and Equipment, Useful Life	'	'	'	'	'	'	'20 years	'20 years	'20 years	'5 years
Unamortized Debt Issuance Expense	15.4	19.5	'	'	'	'	'	'	'	'
Other Assets, Miscellaneous	6.5	2.2	'	'	'	'	'	'	'	'
Equity Method Investments	0.9	0.9	'	'	'	'	'	'	'	'
Gas Balancing Payable	0.3	0.6	'	'	'	'	'	'	'	'
Transportation and exchanges imbalance, receivable	0.7	0.9	'	'	'	'	'	'	'	'
Transportation and exchange imbalance, payable	$1.60	$2.10	'	'	'	'	'	'	'	'

Acquisitions_Purchase_Price_Al

Acquisitions Purchase Price Allocation (Details) (USD $)	Oct. 02, 2012	3-May-11	3-May-11	3-May-11
In Thousands, unless otherwise specified	BP Texas Panhandle Acquisition [Member]	Crow Creek Acquisition [Member]	Crow Creek Acquisition [Member]	Crow Creek Acquisition [Member]
			Asset Retirement Obligation Costs [Member]	Other Noncurrent Liabilities [Member]
Business Acquisition [Line Items]	'	'	'	'
Current assets	$779	$25,329	'	'
Oil and gas properties	'	572,097	'	'
Property, Plant and Equipment — Net	206,849	4,463	'	'
Rights-of-way and easements	27,232	3,192	'	'
Other assets	'	450	'	'
Derivatives	'	3,355	'	'
Current liabilities	-1,705	-37,032	'	'
Other liabilities	-2,600	'	-4,394	-1,440
Deferred tax liability	'	-2,312	'	'
Total purchase price	$230,555	$563,708	'	'

Acquisitions_Aggregate_Purchas

Acquisitions Aggregate Purchase Price (Details) (USD $)	3 Months Ended	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	3-May-12	3-May-11
	BP Texas Panhandle Acquisition [Member]	BP Texas Panhandle Acquisition [Member]	BP Texas Panhandle Acquisition [Member]	Crow Creek Acquisition [Member]	Crow Creek Acquisition [Member]	Crow Creek Acquisition [Member]
Business Acquisition, Equity Interests Issued or Issuable [Line Items]	'	'	'	'	'	'
Payments to Acquire Businesses, Gross	'	'	'	$14,945,000	'	'
Number of Partnership Common Units Issued	'	'	'	'	'	28,753,174
Closing common unit price on May 3, 2011	'	'	'	'	'	$11.69
Value of common units issued	'	'	'	'	'	336,125,000
Long-term debt	'	'	'	'	'	212,638,000
Total purchase price	230,600,000	'	'	563,708,000	'	'
Value of the Equity Issued to Sellers	'	'	'	'	301,900,000	'
Ceiling price	'	'	'	'	$10.50	'
Transaction fees	'	$100,000	$500,000	$2,300,000	'	'

Acquisitions_Pro_Forma_Informa

Acquisitions Pro Forma Information (Details) (USD $)	12 Months Ended			3 Months Ended	8 Months Ended	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2012	Dec. 31, 2012	Dec. 31, 2011
				BP Texas Panhandle Acquisition [Member]	Crow Creek Acquisition [Member]	Crow Creek Acquisition [Member]
Subsidiary or Equity Method Investee [Line Items]	'	'	'	'	'	'
Revenues	$1,195,279	$983,959	$1,059,908	$81,013	$68,168	'
Net Income (Loss) Attributable to Parent	-277,979	-150,602	73,132	5,057	29,835	'
Business Acquisition, Pro Forma Revenue	'	'	'	'	'	1,080,964
Business Acquisition, Pro Forma Net Income (Loss)	'	'	'	'	'	$78,591
Business Acquisition, Pro Forma Earnings Per Share, Diluted	'	'	'	'	'	$0.62

Property_Plant_and_Equipment_P1

Property, Plant and Equipment Property, Plant and Equipment (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Property, Plant and Equipment [Line Items]	'	'
Property, Plant and Equipment — Gross	$2,581,463	$2,567,177
Accumulated depreciation, depletion and amortization	-752,695	-598,971
Property, Plant and Equipment — Net	1,828,768	1,968,206
Land [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Property, Plant and Equipment — Gross	2,877	2,876
Natural Gas Processing Plant [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Property, Plant and Equipment — Gross	521,103	444,023
Gathering and Pipelines [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Property, Plant and Equipment — Gross	777,446	753,009
Equipment [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Property, Plant and Equipment — Gross	53,999	39,889
Vehicles [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Property, Plant and Equipment — Gross	4,001	4,021
Office Equipment [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Property, Plant and Equipment — Gross	1,309	1,285
Computer Equipment [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Property, Plant and Equipment — Gross	14,806	11,431
Linefill [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Property, Plant and Equipment — Gross	5,180	4,328
Proved Oil and Gas Properties [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Property, Plant and Equipment — Gross	1,156,896	1,213,622
Unproved Oil and Gas Properties [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Property, Plant and Equipment — Gross	10,022	31,823
Construction in Progress [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Property, Plant and Equipment — Gross	$33,824	$60,870

Property_Plant_and_Equipment_D

Property, Plant and Equipment Depreciation, Depletion, Amortization and Impairment (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Depreciation	$69,449		$61,390		$54,606
Depletion	87,230		88,413		65,380
Capitalized interest costs	963		1,311		451
Proved Oil and Gas Properties [Member]	'		'		'
Impairment of Long-Lived Assets Held-for-use	207,085	[1]	38,943	[1]	11,239	[1]
Unproved Oil and Gas Property or Major Project [Domain]	'		'		'
Impairment of Long-Lived Assets Held-for-use	7,201	[2]	785	[2]	489	[2]
Natural Gas Processing Plant [Member]	'		'		'
Impairment of Long-Lived Assets Held-for-use	0		57,527	[3]	4,560	[3]
Gathering and Pipelines [Member]	'		'		'
Impairment of Long-Lived Assets Held-for-use	$0		$52,537	[3]	$0
[1]	During the year ended December 31, 2013, the Partnership incurred impairment charges in its Upstream Business related primarily to certain proved properties, primarily in the Cana Shale in the Mid-Continent region and the Permian region, due to lower reserve forecasts. During the year ended December 31, 2012, the Partnership incurred impairment charges in its Upstream Business related to its proved properties in the Barnett Shale, East Texas and Permian regions that experienced reduced cash flows resulting from lower natural gas prices and continuing high operating costs associated with gas compression. During the year ended December 31, 2011, the Partnership incurred impairment charges in its Upstream Business related to certain proved properties in the Jourdanton field in South Texas, which included plans for five future drilling locations that the Partnership has determined not to pursue due to the current natural gas price environment.
[2]	During the year ended December 31, 2013, the Partnership incurred impairment charges in its Upstream Business related to certain leaseholds in the Mid-Continent regions that we expect to expire undrilled in 2014. During the year ended December 31, 2012, the Partnership incurred impairment charges in its Upstream Business related to certain unproved property leaseholds expected to expire undrilled in 2013. During the year ended December 31, 2011, the Partnership incurred impairment charges related to certain drilling locations in its unproved properties which the Partnership no longer intends to develop based on the performance of offsetting wells.
[3]	During the year ended December 31, 2012, the Partnership incurred impairment charges in its Midstream Business related to certain plants and pipelines in its East Texas and Other Midstream Segment due to (i) reduced throughput volumes as its producer customers curtailed their drilling activity in response to the continued depressed natural gas price environment (ii) the loss of significant gathering contracts on its Panola and other systems and (iii) the substantial damage incurred at the Yscloskey processing plant as a result of Hurricane Isaac in August 2012. The value of assets for both the Panola system and the Yscloskey plant have been fully written down. During the year ended December 31, 2011, the Partnership recorded an impairment charge in its Texas Panhandle Segment to fully write-down its idle Turkey Creek plant.

Asset_Retirement_Obligations_S

Asset Retirement Obligations Schedule of Change in Asset Retirement Obligation (Details) (USD $)	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]	'		'		'
Asset retirement obligations — Beginning balance	$48,755,000	[1]	$33,303,000		$24,711,000
Additional liabilities	1,140,000		1,721,000		159,000
Liabilities settled	-2,240,000		-2,755,000		-465,000
Revision to liabilities	7,603,000		11,471,000		2,339,000
Additional liability related to acquisitions	0		2,650,000		4,413,000
Accretion expense	3,706,000		2,365,000		2,146,000
Asset retirement obligations — Ending balance	58,964,000	[1]	48,755,000	[1]	33,303,000
Asset Retirement Obligation, Current	$13,100,000		$3,900,000		'
[1]	(a) As of December 31, 2013 and 2012, $13.1 million and $3.9 million , respectively, were included within accrued liabilities in the Consolidated Balance Sheets.

Intangible_Assets_Intangible_A1

Intangible Assets Intangible Assets (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Acquired Finite-Lived Intangible Assets [Line Items]	'	'
Intangible Assets — Net	$105,620	$111,515
Use Rights [Member]	'	'
Acquired Finite-Lived Intangible Assets [Line Items]	'	'
Rights-of-way and easements—at cost	131,088	127,375
Less: accumulated amortization	-36,228	-29,959
Contractual Rights [Member]	'	'
Acquired Finite-Lived Intangible Assets [Line Items]	'	'
Less: accumulated amortization	-11,982	-23,910
Contracts	$22,742	$38,009

Intangible_Assets_Impaired_Int

Intangible Assets Impaired Intangible Assets (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012		Dec. 31, 2011
Amortization of Intangible Assets	$10,078	$11,205		$11,588
Use Rights [Member]	'	'		'
Impairment of Intangible Assets, Finite-lived	0	5,266	[1]	0
Contractual Rights [Member]	'	'		'
Impairment of Intangible Assets, Finite-lived	$0	$16,384	[1]	$0
[1]	During the year ended December 31, 2012, the Partnership incurred impairment charges in its Midstream Business related to certain rights-of-way and contracts in its East Texas and Other Midstream Segment due to (i) reduced throughput volumes as its producer customers curtailed their drilling activities due to the continued decline in natural gas prices during the first three months of 2012 and (ii) the termination of significant gathering contracts on its Panola system during the year ended December 31, 2012. The value of the contracts and rights-of-way related to the Panola system have been fully written down.

Intangible_Assets_Future_Amort

Intangible Assets Future Amortization Expense (Details) (USD $)	Dec. 31, 2013
In Thousands, unless otherwise specified
Finite-Lived Intangible Assets [Line Items]	'
Future Amortization Expense, Year One	$7,958
Future Amortization Expense, Year Two	7,957
Future Amortization Expense, Year Three	7,957
Future Amortization Expense, Year Four	7,956
Future Amortization Expense, Year Five	7,955
Future Amortization Expense, after Year Five	$65,837

Intangible_Assets_Narrative_De

Intangible Assets Narrative (Details)	12 Months Ended
	Dec. 31, 2013
Use Rights [Member]	'
Statement [Line Items]	'
Finite-Lived Intangible Asset, Useful Life	'20 years
Minimum [Member] | Contractual Rights [Member]	'
Statement [Line Items]	'
Finite-Lived Intangible Asset, Useful Life	'5 years
Maximum [Member] | Contractual Rights [Member]	'
Statement [Line Items]	'
Finite-Lived Intangible Asset, Useful Life	'20 years

Long_Term_Debt_LongTerm_Debt_D

Long Term Debt Long-Term Debt (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Debt Instrument [Line Items]	'	'
Revolving credit facility:	$706,800	$608,500
8.375% Senior Notes due 2019	550,000	550,000
Unamortized bond discount	-4,738	-5,397
Senior Notes	545,262	544,603
Long-term debt	$1,252,062	$1,153,103

Long_Term_Debt_Revolving_Credi

Long Term Debt Revolving Credit Facility Narrative (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Feb. 28, 2014	Sep. 30, 2012	Dec. 31, 2011
	Rate
Debt Instrument [Line Items]	'	'	'	'	'
Line of Credit Facility, Maximum Borrowing Capacity	$1,200,000,000	'	'	'	$1,200,000,000
Debt Issuance Cost	'	9,800,000	'	'	'
Write-off of debt issuance costs	'	400,000	'	'	'
Unamortized Debt Issuance Expense	15,400,000	19,500,000	'	'	'
Line of Credit Facility, Current Borrowing Capacity	'	820,000,000	'	675,000,000	'
Borrowing Base Multiplier	3.75	'	4	'	'
Line of Credit Facility, Remaining Borrowing Capacity	49,200,000	'	'	'	'
Line of Credit Facility, Commitment Fee Percentage	0.50%	'	'	'	'
Letters of Credit Sub-limit	150,000,000	'	'	'	'
Letters of Credit Outstanding, Amount	19,200,000	'	'	'	'
Debt, Weighted Average Interest Rate	2.67%	'	'	'	'
Debt Instrument, Covenant Compliance	'As of December 31, 2013, the Partnership was in compliance with the financial covenants under the Credit Agreement.	'	'	'	'
Revolving Credit Facility [Member]	'	'	'	'	'
Debt Instrument [Line Items]	'	'	'	'	'
Unamortized Debt Issuance Expense	$5,200,000	'	'	'	'
Interest Coverage Ratio [Member]	'	'	'	'	'
Debt Instrument [Line Items]	'	'	'	'	'
Debt Instrument, Covenant Description	'As of any fiscal quarter-end, the ratio of Consolidated EBITDA (as defined in the Credit Agreement) for the four fiscal quarter period ending with such fiscal quarter to Consolidated Interest Expense (as defined in the Credit Agreement) for such four fiscal quarter period (the "Interest Coverage Ratio").	'	'	'	'
Total Leverage Ratio [Member]	'	'	'	'	'
Debt Instrument [Line Items]	'	'	'	'	'
Debt Instrument, Covenant Description	'As of any fiscal quarter-end, the ratio of Total Funded Indebtedness (as defined in the Credit Agreement) to Consolidated EBITDA for the four fiscal quarter period ending with such fiscal quarter (the “Total Leverage Ratio”).	'	'	'	'
Senior Secured Leverage Ratio [Member]	'	'	'	'	'
Debt Instrument [Line Items]	'	'	'	'	'
Debt Instrument, Covenant Description	'As of the fiscal quarter-end for the fiscal quarters ending December 31, 2013 through September 30, 2014, the ratio of Senior Secured Debt (as defined in the Credit Agreement) to Consolidated EBITDA for the four fiscal quarter period ending with such fiscal quarter (the “Senior Secured Leverage Ratio”).	'	'	'	'
Current Ratio [Member]	'	'	'	'	'
Debt Instrument [Line Items]	'	'	'	'	'
Debt Instrument, Covenant Description	'As of any fiscal quarter-end the ratio of the Partnership’s consolidated current assets (including availability under the Credit Agreement up to the Loan Limit (as defined within the Credit Agreement), but excluding non-cash assets under the accounting guidance for derivatives) to consolidated current liabilities (excluding non-cash obligations under the accounting guidance for derivatives and current maturities under the Credit Agreement) (the “Current Ratio”).	'	'	'	'
London Interbank Offered Rate (LIBOR) [Member]	'	'	'	'	'
Debt Instrument [Line Items]	'	'	'	'	'
Debt Instrument, Basis Spread on Variable Rate	2.50%	'	'	'	'
Debt Instrument, Basis Spread on Base Rate	1.00%	'	'	'	'
Base Rate [Member]	'	'	'	'	'
Debt Instrument [Line Items]	'	'	'	'	'
Debt Instrument, Basis Spread on Variable Rate	1.50%	'	'	'	'
Federal Funds Purchased [Member]	'	'	'	'	'
Debt Instrument [Line Items]	'	'	'	'	'
Debt Instrument, Basis Spread on Base Rate	0.50%	'	'	'	'
Minimum [Member] | London Interbank Offered Rate (LIBOR) [Member]	'	'	'	'	'
Debt Instrument [Line Items]	'	'	'	'	'
Debt Instrument, Basis Spread on Variable Rate	1.75%	'	'	'	'
Minimum [Member] | Base Rate [Member]	'	'	'	'	'
Debt Instrument [Line Items]	'	'	'	'	'
Debt Instrument, Basis Spread on Variable Rate	0.75%	'	'	'	'
Maximum [Member] | London Interbank Offered Rate (LIBOR) [Member]	'	'	'	'	'
Debt Instrument [Line Items]	'	'	'	'	'
Debt Instrument, Basis Spread on Variable Rate	2.75%	'	'	'	'
Maximum [Member] | Base Rate [Member]	'	'	'	'	'
Debt Instrument [Line Items]	'	'	'	'	'
Debt Instrument, Basis Spread on Variable Rate	1.75%	'	'	'	'
Total Midstream Segments [Member]	'	'	'	'	'
Debt Instrument [Line Items]	'	'	'	'	'
Borrowing Base Rate	55.00%	'	'	'	'
Material Business Acquisition [Member] | Total Midstream Segments [Member]	'	'	'	'	'
Debt Instrument [Line Items]	'	'	'	'	'
Borrowing Base Rate	60.00%	'	'	'	'

Long_Term_Debt_Debt_Covenants_

Long Term Debt Debt Covenants (Details)

Feb. 28, 2014

Dec. 31, 2013

Feb. 28, 2014

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2014

Sep. 30, 2014

Jun. 30, 2014

Mar. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Sep. 30, 2014

Jun. 30, 2014

Mar. 31, 2014

Dec. 31, 2013

Sep. 30, 2014

Jun. 30, 2014

Mar. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Sep. 30, 2014

Jun. 30, 2014

Mar. 31, 2014

Dec. 31, 2013

Senior Secured Leverage Ratio [Member]

Senior Secured Leverage Ratio [Member]

Total Leverage Ratio [Member]

Total Leverage Ratio [Member]

Current Ratio [Member]

Interest Coverage Ratio [Member]

Minimum [Member]

Minimum [Member]

Minimum [Member]

Minimum [Member]

Minimum [Member]

Minimum [Member]

Minimum [Member]

Minimum [Member]

Minimum [Member]

Minimum [Member]

Maximum [Member]

Maximum [Member]

Maximum [Member]

Maximum [Member]

Maximum [Member]

Maximum [Member]

Maximum [Member]

Maximum [Member]

Maximum [Member]

Current Ratio [Member]

Current Ratio [Member]

Current Ratio [Member]

Current Ratio [Member]

Current Ratio [Member]

Interest Coverage Ratio [Member]

Interest Coverage Ratio [Member]

Interest Coverage Ratio [Member]

Interest Coverage Ratio [Member]

Interest Coverage Ratio [Member]

Senior Secured Leverage Ratio [Member]

Senior Secured Leverage Ratio [Member]

Senior Secured Leverage Ratio [Member]

Senior Secured Leverage Ratio [Member]

Total Leverage Ratio [Member]

Total Leverage Ratio [Member]

Total Leverage Ratio [Member]

Total Leverage Ratio [Member]

Total Leverage Ratio [Member]

Schedule of Debt Covenants [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Line of Credit Facility, Covenant Ratio

3.4

3.06

5.85

5.4

1.1

3.1

1

1

1

1

1

2.5

2.5

2.5

2.5

2.5

2.95

3.05

3.1

3.15

4.5

4.75

5

5.25

5.5

Long_Term_Debt_Scheduled_Matur

Long Term Debt Scheduled Maturities of Debt (Details) (USD $)	Dec. 31, 2013
In Thousands, unless otherwise specified
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months	$0
Long-term Debt, Maturities, Repayments of Principal in Year Two	0
Long-term Debt, Maturities, Repayments of Principal in Year Three	706,800
Long-term Debt, Maturities, Repayments of Principal in Year Four	0
Long-term Debt, Maturities, Repayments of Principal in Year Five	0
Long-term Debt, Maturities, Repayments of Principal after Year Five	550,000
Total Repayments of Long-Term Debt	$1,256,800

Long_Term_Debt_Senior_Notes_Na

Long Term Debt Senior Notes Narrative (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	Rate
Debt Instrument [Line Items]	'	'	'
Debt Instrument, Interest Rate, Stated Percentage	8.38%	'	'
Proceeds from Issuance of Subordinated Long-term Debt	$0	$246,253,000	$297,837,000
Unamortized Debt Issuance Expense	15,400,000	19,500,000	'
Debt Instrument, Unamortized Discount (Premium), Net	4,738,000	5,397,000	'
Debt Instrument, Call Feature	'The Partnership has the option to redeem all or a portion of the Senior Notes at any time on or after June 1, 2015 at the redemption prices specified in the indenture plus accrued and unpaid interest. The Partnership may also redeem the Senior Notes, in whole or in part, at a "make-whole" redemption price specified in the indenture, plus accrued and unpaid interest, at any time prior to June 1, 2015.	'	'
Debt Instrument, Redemption Price, Percentage of Principal Amount Redeemed	35.00%	'	'
Debt Instrument, Redemption Price, Percentage	108.38%	'	'
Senior Notes [Member]	'	'	'
Debt Instrument [Line Items]	'	'	'
Unamortized Debt Issuance Expense	10,300,000	'	'
2011 Debt Issuance [Member]	'	'	'
Debt Instrument [Line Items]	'	'	'
Debt Instrument, Face Amount	300,000,000	'	'
Debt Instrument, Unamortized Discount	2,200,000	'	'
Proceeds from Issuance of Subordinated Long-term Debt	297,800,000	'	'
2012 Debt Issuance [Member]	'	'	'
Debt Instrument [Line Items]	'	'	'
Debt Instrument, Face Amount	250,000,000	'	'
Debt Instrument, Unamortized Discount	3,700,000	'	'
Proceeds from Issuance of Subordinated Long-term Debt	$246,300,000	'	'

Members_Equity_Narrative_Detai

Members' Equity Narrative (Details) (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
				Common Class A [Member]	Common Class A [Member]	Common Class A [Member]	Common Class A [Member]
Capital Unit [Line Items]	'	'	'	'	'	'	'
Limited Partners' Capital Account, Units Outstanding	'	'	'	156,644,153	144,675,751	127,606,229	83,425,378
Warrant Exercise Price	6	'	'	'	'	'	'
Stockholders' Equity, Other Shares	'	5,300,588	14,957,540	'	'	'	'
Equity Issuance, Market Value	$100	'	'	'	'	'	'
Equity Units, Issued	686,759	'	'	'	'	'	'
Equity Proceeds, Net of Offering Costs	5.6	'	'	'	'	'	'
Stock Issued During Period, Shares, New Issues	10,350,000	10,120,000	'	11,036,759	10,954,327	'	'
Partners' Capital Account, Public Sale of Units Net of Offering Costs	$92.30	$84.30	'	'	'	'	'

Members_Equity_Distributions_D

Members' Equity Distributions (Details) (USD $)

3 Months Ended

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2011

Sep. 30, 2011

Jun. 30, 2011

Mar. 31, 2011

Dividends Payable [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

Common Stock, Dividends, Per Share, Cash Paid

$0.15

[1],[2]

$0.15

[1],[2]

$0.22

[1],[2]

$0.22

[1],[2]

$0.22

[1]

$0.22

[1]

$0.22

[1]

$0.22

[1]

$0.21

[1]

$0.20

[1]

$0.19

[1]

$0.15

[1]

Distribution Made to Limited Partner, Date of Record

7-Feb-14

[3]

7-Nov-13

[3]

7-Aug-13

[3]

7-May-13

[3]

7-Feb-13

[3]

7-Nov-12

[3]

7-Aug-12

[3]

8-May-12

[3]

7-Feb-12

[3]

4-Nov-11

[3]

5-Aug-11

[3]

9-May-11

[3]

Distribution Made to Limited Partner, Distribution Date

14-Feb-14

14-Nov-13

14-Aug-13

15-May-13

14-Feb-13

14-Nov-12

14-Aug-12

15-May-12

14-Feb-12

14-Nov-11

12-Aug-11

13-May-11

[1]

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

[2]

The distribution excludes certain restricted 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 $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Related Party Transaction [Line Items]	'	'	'
Natural gas purchases from affiliates	$2,938	$2,713	$6,097
Due to Related Parties, Current	$18	$428	'

Risk_Management_Activities_Int

Risk Management Activities Interest Rate Derivatives (Details) (Interest Rate Swap [Member], Interest Rate Swap [Member], Effective Date, 6/22/2011 [Member], USD $)	29 Months Ended
	Jun. 15, 2015	Dec. 31, 2013
		Rate
Interest Rate Swap [Member] | Interest Rate Swap [Member] | Effective Date, 6/22/2011 [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)	Dec. 31, 2013
	MMbtu
Natural Gas Contract [Member] | Swaps, Pay Fixed, Receive Floating [Member] | Portion of contracts settling in 2014 [Member]	'
Derivative [Line Items]	'
Derivative, Nonmonetary Notional Amount	930,000
Natural Gas Contract [Member] | Swap [Member] | Portion of contracts settling in 2014 [Member]	'
Derivative [Line Items]	'
Derivative, Nonmonetary Notional Amount	16,800,000	[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	240,000	[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] | Swaps, Pay Fixed, Receive Floating [Member] | Portion of contracts settling in 2014 [Member]	'
Derivative [Line Items]	'
Derivative, Nonmonetary Notional Amount	199,140	[1]
Derivative, Average Floor Price	92.53	[2]
Crude Oil Contract [Member] | Swap [Member] | Portion of contracts settling in 2014 [Member]	'
Derivative [Line Items]	'
Derivative, Nonmonetary Notional Amount	2,208,000	[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]
Propane Contract [Member] | Swap [Member] | Portion of contracts settling in 2014 [Member]	'
Derivative [Line Items]	'
Derivative, Nonmonetary Notional Amount	9,576,000	[1]
Derivative, Average Floor Price	1.06	[2]
IsoButane Contract [Member] | Swap [Member] | Portion of contracts settling in 2014 [Member]	'
Derivative [Line Items]	'
Derivative, Nonmonetary Notional Amount	2,268,000	[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	4,132,800	[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. The weighted average prices are in $/MMbtu for natural gas, $/barrel for crude oil and $/gallon for natural gas liquids

Risk_Management_Activities_Sch

Risk Management Activities Schedule of Marketing and Trading Derivative Instruments (Details) (Natural Gas Contract [Member])	Dec. 31, 2013
	MMbtu
Portion of contracts settling in 2014 [Member] | Index Swap, Sales [Member]	'
Derivative [Line Items]	'
Derivative, Nonmonetary Notional Amount	1,365,000
Portion of contracts settling in 2014 [Member] | Swaps, Pay Fixed, Receive Floating [Member]	'
Derivative [Line Items]	'
Derivative, Nonmonetary Notional Amount	930,000
Portion of contracts settling in 2014 [Member] | Swaps, Pay Floating, Receive Fixed [Member]	'
Derivative [Line Items]	'
Derivative, Nonmonetary Notional Amount	465,000
Portion of contracts settling in 2014 [Member] | Forward Contract, Purchases - Index [Member]	'
Derivative [Line Items]	'
Derivative, Nonmonetary Notional Amount	13,090,332
Portion of contracts settling in 2014 [Member] | Forward Contract, Sales - Index [Member]	'
Derivative [Line Items]	'
Derivative, Nonmonetary Notional Amount	18,873,397
Portion of contracts settling in 2014 [Member] | Forward Contracs, Purchases - Fixed Price [Member]	'
Derivative [Line Items]	'
Derivative, Nonmonetary Notional Amount	2,263,000
Portion of contracts settling in 2014 [Member] | Forward Contracs, Sales - Fixed Price [Member]	'
Derivative [Line Items]	'
Derivative, Nonmonetary Notional Amount	2,728,000
Portion of contracts settling in 2014 [Member] | Basis Swap, Purchases [Member]	'
Derivative [Line Items]	'
Derivative, Nonmonetary Notional Amount	6,955,000
Portion of contracts settling in 2014 [Member] | Basis Swap, Sales [Member]	'
Derivative [Line Items]	'
Derivative, Nonmonetary Notional Amount	2,675,000
Portion of contracts settling in 2014 [Member] | Index Swap, Purchases [Member]	'
Derivative [Line Items]	'
Derivative, Nonmonetary Notional Amount	620,000
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 $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Derivatives, Fair Value [Line Items]	'	'
Derivative Liabilities, Current	$11,023	$1,231
Derivative Liabilities, noncurrent	3,848	1,700
Derivative assets, current	9,162	33,340
Derivative assets, noncurrent	5,461	7,953
Derivative Financial Instruments, Assets, Fair Value Disclosure	14,623	41,293
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	-14,871	-2,931
Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member] | Current Assets [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative Liabilities, Current	0	-4,844
Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member] | Long-term Assets [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative Liabilities, noncurrent	0	-7,002
Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member] | Current Liabilities [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative Liabilities, Current	-6,210	-1,201
Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member] | Long-term Liabilities [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative Liabilities, noncurrent	-2,885	-1,700
Commodity Contract [Member] | Not Designated as Hedging Instrument [Member] | Current Assets [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative Liabilities, Current	-2,106	-998
Derivative assets, current	11,268	39,182
Commodity Contract [Member] | Not Designated as Hedging Instrument [Member] | Long-term Assets [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative Liabilities, noncurrent	-798	-2,383
Derivative assets, noncurrent	6,259	17,338
Commodity Contract [Member] | Not Designated as Hedging Instrument [Member] | Current Liabilities [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative Liabilities, Current	-6,543	-49
Derivative assets, current	1,730	19
Commodity Contract [Member] | Not Designated as Hedging Instrument [Member] | Long-term Liabilities [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative Liabilities, noncurrent	-2,451	0
Derivative assets, noncurrent	$1,488	$0

Risk_Management_Activities_Sch2

Risk Management Activities Schedule of Derivative Instruments, Gain (Loss) in Statement of Financial Performance (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Interest rate risk management gains (losses), net	($1,104)	($4,727)	($11,401)
Commodity risk management gains (losses), net	-18,533	57,894	32,510
Derivative Instruments, Gain (Loss) Recognized in Income, Net	-19,322	52,975	21,881
Interest Rate Contract [Member] | Other Expense [Member] | Not Designated as Hedging Instrument [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Interest rate risk management gains (losses), net	-1,104	-4,727	-11,401
Commodity Contract [Member] | Commodity Risk Management Gains (Losses) [Member] | Not Designated as Hedging Instrument [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Commodity risk management gains (losses), net	-18,533	57,894	32,510
Commodity Contract [Member] | Sales [Member] | Not Designated as Hedging Instrument [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Commodity risk management gains (losses), net	$315	($192)	$772

Fair_Value_of_Financial_Instru2

Fair Value of Financial Instruments Fair Value, Assets and Liabilities Measured on a Recuring Basis (Details) (USD $)	Dec. 31, 2013		Dec. 31, 2012
In Thousands, unless otherwise specified
Assets:	'		'
Derivative Financial Instruments, Assets, Fair Value Disclosure	$14,623		$41,293
Liabilities:	'		'
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	-14,871		-2,931
Fair Value, Measurements, Recurring [Member]	'		'
Assets:	'		'
Derivative Financial Instruments, Assets, Fair Value Disclosure	14,623		41,293
Liabilities:	'		'
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	-14,871		-2,931
Fair Value, Measurements, Recurring [Member] | Crude Oil Contract [Member]	'		'
Assets:	'		'
Derivative Financial Instruments, Assets, Fair Value Disclosure	7,801		17,596
Liabilities:	'		'
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	-1,927		0
Fair Value, Measurements, Recurring [Member] | Natural Gas Contract [Member]	'		'
Assets:	'		'
Derivative Financial Instruments, Assets, Fair Value Disclosure	6,822		25,754
Liabilities:	'		'
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	-2,770		-30
Fair Value, Measurements, Recurring [Member] | Natural Gas Liquids Contract [Member]	'		'
Assets:	'		'
Derivative Financial Instruments, Assets, Fair Value Disclosure	0		9,789
Liabilities:	'		'
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	-1,079		'
Fair Value, Measurements, Recurring [Member] | Interest Rate Contract [Member]	'		'
Assets:	'		'
Derivative Financial Instruments, Assets, Fair Value Disclosure	'		-11,846
Liabilities:	'		'
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	-9,095		-2,901
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]	'		'
Assets:	'		'
Derivative Financial Instruments, Assets, Fair Value Disclosure	0		0
Liabilities:	'		'
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0		0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Crude Oil Contract [Member]	'		'
Assets:	'		'
Derivative Financial Instruments, Assets, Fair Value Disclosure	0		0
Liabilities:	'		'
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0		0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Natural Gas Contract [Member]	'		'
Assets:	'		'
Derivative Financial Instruments, Assets, Fair Value Disclosure	0		0
Liabilities:	'		'
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0		0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Natural Gas Liquids Contract [Member]	'		'
Assets:	'		'
Derivative Financial Instruments, Assets, Fair Value Disclosure	0		0
Liabilities:	'		'
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0		'
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Interest Rate Contract [Member]	'		'
Assets:	'		'
Derivative Financial Instruments, Assets, Fair Value Disclosure	'		0
Liabilities:	'		'
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0		0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]	'		'
Assets:	'		'
Derivative Financial Instruments, Assets, Fair Value Disclosure	20,745		56,539
Liabilities:	'		'
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	-20,993		-18,177
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Crude Oil Contract [Member]	'		'
Assets:	'		'
Derivative Financial Instruments, Assets, Fair Value Disclosure	9,804		19,410
Liabilities:	'		'
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	-3,930		-1,814
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Natural Gas Contract [Member]	'		'
Assets:	'		'
Derivative Financial Instruments, Assets, Fair Value Disclosure	10,899		27,340
Liabilities:	'		'
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	-6,847		-1,616
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Natural Gas Liquids Contract [Member]	'		'
Assets:	'		'
Derivative Financial Instruments, Assets, Fair Value Disclosure	42		9,789
Liabilities:	'		'
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	-1,121		'
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Interest Rate Contract [Member]	'		'
Assets:	'		'
Derivative Financial Instruments, Assets, Fair Value Disclosure	'		0
Liabilities:	'		'
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	-9,095		-14,747
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]	'		'
Assets:	'		'
Derivative Financial Instruments, Assets, Fair Value Disclosure	0		0
Liabilities:	'		'
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0		0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Crude Oil Contract [Member]	'		'
Assets:	'		'
Derivative Financial Instruments, Assets, Fair Value Disclosure	0		0
Liabilities:	'		'
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0		0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Natural Gas Contract [Member]	'		'
Assets:	'		'
Derivative Financial Instruments, Assets, Fair Value Disclosure	0		0
Liabilities:	'		'
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0		0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Natural Gas Liquids Contract [Member]	'		'
Assets:	'		'
Derivative Financial Instruments, Assets, Fair Value Disclosure	0		0
Liabilities:	'		'
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0		'
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Interest Rate Contract [Member]	'		'
Assets:	'		'
Derivative Financial Instruments, Assets, Fair Value Disclosure	'		0
Liabilities:	'		'
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0		0
Fair Value, Measurements, Recurring [Member] | Netting [Member]	'		'
Assets:	'		'
Derivative Financial Instruments, Assets, Fair Value Disclosure	-6,122	[1]	-15,246	[1]
Liabilities:	'		'
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	6,122	[1]	15,246	[1]
Fair Value, Measurements, Recurring [Member] | Netting [Member] | Crude Oil Contract [Member]	'		'
Assets:	'		'
Derivative Financial Instruments, Assets, Fair Value Disclosure	-2,003	[1]	-1,814	[1]
Liabilities:	'		'
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	2,003	[1]	1,814	[1]
Fair Value, Measurements, Recurring [Member] | Netting [Member] | Natural Gas Contract [Member]	'		'
Assets:	'		'
Derivative Financial Instruments, Assets, Fair Value Disclosure	-4,077	[1]	-1,586	[1]
Liabilities:	'		'
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	4,077	[1]	1,586	[1]
Fair Value, Measurements, Recurring [Member] | Netting [Member] | Natural Gas Liquids Contract [Member]	'		'
Assets:	'		'
Derivative Financial Instruments, Assets, Fair Value Disclosure	-42	[1]	0	[1]
Liabilities:	'		'
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	42	[1]	'
Fair Value, Measurements, Recurring [Member] | Netting [Member] | Interest Rate Contract [Member]	'		'
Assets:	'		'
Derivative Financial Instruments, Assets, Fair Value Disclosure	'		-11,846	[1]
Liabilities:	'		'
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	$0	[1]	$11,846	[1]
[1]	Represents counterparty netting under agreement governing such derivative contracts.

Fair_Value_of_Financial_Instru3

Fair Value of Financial Instruments Fair Value of Level 3 Derivatives(Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]	'	'	'
Liability Value, Beginning Balance	$0	$0	($5,733)
Settlements	0	0	15,562
Gain (Loss) Included in Earnings (Realized and Unrealized)	0	0	-12,784
Transfers out of Level 3	0	0	2,955
Liability Value, Ending Balance	$0	$0	$0

Fair_Value_of_Financial_Instru4

Fair Value of Financial Instruments Fair Value, Assets and Liabilitites, Measured on a Non-recurring Basis (Details) (Proved Oil and Gas Properties [Member], USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Assets [Abstract]	'		'		'
Property, Plant, and Equipment, Fair Value Disclosure	$91,346		'		'
Impairment of Long-Lived Assets Held-for-use	207,085	[1]	38,943	[1]	11,239	[1]
Fair Value, Measurements, Nonrecurring [Member]	'		'		'
Assets [Abstract]	'		'		'
Impairment of Long-Lived Assets Held-for-use	207,085		'		'
Fair Value, Measurements, Nonrecurring [Member] | Fair Value, Inputs, Level 1 [Member]	'		'		'
Assets [Abstract]	'		'		'
Property, Plant, and Equipment, Fair Value Disclosure	0		'		'
Fair Value, Measurements, Nonrecurring [Member] | Fair Value, Inputs, Level 2 [Member]	'		'		'
Assets [Abstract]	'		'		'
Property, Plant, and Equipment, Fair Value Disclosure	0		'		'
Fair Value, Measurements, Nonrecurring [Member] | Fair Value, Inputs, Level 3 [Member]	'		'		'
Assets [Abstract]	'		'		'
Property, Plant, and Equipment, Fair Value Disclosure	$91,346		'		'
[1]	During the year ended December 31, 2013, the Partnership incurred impairment charges in its Upstream Business related primarily to certain proved properties, primarily in the Cana Shale in the Mid-Continent region and the Permian region, due to lower reserve forecasts. During the year ended December 31, 2012, the Partnership incurred impairment charges in its Upstream Business related to its proved properties in the Barnett Shale, East Texas and Permian regions that experienced reduced cash flows resulting from lower natural gas prices and continuing high operating costs associated with gas compression. During the year ended December 31, 2011, the Partnership incurred impairment charges in its Upstream Business related to certain proved properties in the Jourdanton field in South Texas, which included plans for five future drilling locations that the Partnership has determined not to pursue due to the current natural gas price environment.

Fair_Value_of_Financial_Instru5

Fair Value of Financial Instruments Narrative (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Notes Payable, Fair Value Disclosure	$599.50	$561

Commitments_and_Contingencies_

Commitments and Contingencies Loss Contingencies (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Loss Contingencies [Line Items]	'	'
Accrual for Environmental Loss Contingencies	$3.20	$2.80

Commitments_and_Contingencies_1

Commitments and Contingencies Operating Leases (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Operating leases [Line Items]	'	'	'
Operating Leases, Rent Expense	$9,500,000	$8,900,000	$7,800,000
Operating Leases, Future Minimum Payments Due	7,060,000	'	'
Operating Leases, Future Minimum Payments, Due in Two Years	6,045,000	'	'
Operating Leases, Future Minimum Payments, Due in Three Years	4,997,000	'	'
Operating Leases, Future Minimum Payments, Due in Four Years	2,848,000	'	'
Operating Leases, Future Minimum Payments, Due in Five Years	$438,000	'	'

Segments_Schedule_of_Segment_R

Segments Schedule of Segment Reporting Information, by Segment (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Segment Reporting Information [Line Items]	'		'		'
Revenues	$1,195,279		$983,959		$1,059,908
Intersegment revenues	0		0		0
Cost of natural gas, natural gas liquids, and condensate	790,618		532,719		633,184
Intersegment costs of sales	0		0		0
Operating Expenses	236,689		209,254		167,194
Intersegment operations and maintenance expense	'		0		0
Depreciation, Depletion and Amortization	167,170		161,045		131,611
Impairment	214,286		177,003		16,288
OPERATING INCOME (LOSS)	-213,484		-96,062		111,631
Capital Expenditures	224,161		310,720		179,208
Segment Assets	2,127,550		2,294,216		2,045,688
Texas Panhandle [Member]	'		'		'
Segment Reporting Information [Line Items]	'		'		'
Revenues	538,492		362,902	[1]	395,991
Intersegment revenues	226,576		105,759		60,237
Cost of natural gas, natural gas liquids, and condensate	594,125		332,792		327,775
Intersegment costs of sales	200		83		0
Operating Expenses	81,186		60,884		41,749
Intersegment operations and maintenance expense	'		0		0
Depreciation, Depletion and Amortization	57,781		44,451		37,034
Impairment	0		0		4,560
OPERATING INCOME (LOSS)	31,776		30,451		45,110
Capital Expenditures	81,590		131,928		71,351
Segment Assets	950,092		922,281		599,688
East Texas and Other Midstream Segment	'		'		'
Segment Reporting Information [Line Items]	'		'		'
Revenues	136,637		156,529		274,361
Intersegment revenues	37,716		39,099		16,654
Cost of natural gas, natural gas liquids, and condensate	131,966		147,493		231,642
Intersegment costs of sales	0		0		0
Operating Expenses	19,943		21,762		22,790
Intersegment operations and maintenance expense	'		0		0
Depreciation, Depletion and Amortization	19,476		25,771		27,629
Impairment	0		131,714		0
OPERATING INCOME (LOSS)	2,968		-131,112		8,954
Capital Expenditures	7,827		9,328		10,860
Segment Assets	243,493		250,916		374,030
Marketing and Trading Segment	'		'		'
Segment Reporting Information [Line Items]	'		'		'
Revenues	384,422		256,772		200,939
Intersegment revenues	-272,116		-154,992		-82,378
Cost of natural gas, natural gas liquids, and condensate	64,527		52,434		73,767
Intersegment costs of sales	38,844		44,317		41,382
Operating Expenses	-8		2		0
Intersegment operations and maintenance expense	'		0		0
Depreciation, Depletion and Amortization	428		273		0
Impairment	0		0		0
OPERATING INCOME (LOSS)	8,515		4,754		3,412
Capital Expenditures	309		5,489		2,205
Segment Assets	73,918		43,417		40,173
Total Midstream Segments [Member]	'		'		'
Segment Reporting Information [Line Items]	'		'		'
Revenues	1,059,551		776,203		871,291
Intersegment revenues	-7,824		-10,134		-5,487
Cost of natural gas, natural gas liquids, and condensate	790,618		532,719		633,184
Intersegment costs of sales	39,044		44,400		41,382
Operating Expenses	101,121		82,648		64,539
Intersegment operations and maintenance expense	'		0		0
Depreciation, Depletion and Amortization	77,685		70,495		64,663
Impairment	0		131,714		4,560
OPERATING INCOME (LOSS)	43,259		-95,907		57,476
Capital Expenditures	89,726		146,745		84,416
Segment Assets	1,267,503		1,216,614		1,013,891
Upstream Segment [Member]	'		'		'
Segment Reporting Information [Line Items]	'		'		'
Revenues	154,261		149,862		156,107	[2]
Intersegment revenues	47,048		53,343		48,203
Cost of natural gas, natural gas liquids, and condensate	0		0		0
Intersegment costs of sales	0		0		0
Operating Expenses	54,354		56,612		47,657
Intersegment operations and maintenance expense	'		122		66
Depreciation, Depletion and Amortization	87,456		88,777		65,531
Impairment	214,286		45,289		11,728
OPERATING INCOME (LOSS)	-154,787		12,405		79,328
Capital Expenditures	129,099		160,330		92,660
Segment Assets	842,246		1,018,927		979,331
Corporate and Other Segment [Member]	'		'		'
Segment Reporting Information [Line Items]	'		'		'
Revenues	-18,533	[3]	57,894	[3]	32,510	[3]
Intersegment revenues	-39,224		-43,209		-42,716
Cost of natural gas, natural gas liquids, and condensate	0		0		0
Intersegment costs of sales	-39,044		-44,400		-41,382
Operating Expenses	81,214		69,994		54,998
Intersegment operations and maintenance expense	'		-122		-66
Depreciation, Depletion and Amortization	2,029		1,773		1,417
Impairment	0		0		0
OPERATING INCOME (LOSS)	-101,956		-12,560		-25,173
Capital Expenditures	5,336		3,645		2,132
Segment Assets	$17,801	[4]	$58,675	[4]	$52,466	[4]
[1]	Sales to external customers in the Texas Panhandle Segment for the year ended December 31, 2012, includes 2.9 million of business interruption insurance recovery related to damage sustained by the Partnership's Cargray processing facility due to severe winter weather in 2011, which is recognized as part of Other Revenue in the consolidated statements of operations.
[2]	Sales to external customers for the years ended December 31, 2011 includes $2.0 million, respectively, of business interruption insurance recovery related to the shutdown of the Eustace plant in 2010 in the Upstream Segment, which is recognized as part of Other revenue in the consolidated statement of operations.
[3]	Represents results of the Partnership's commodity risk management activity.
[4]	Includes elimination of intersegment transactions.

Segments_Narrative_Details

Segments Narrative (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2011
	Texas Panhandle [Member]	Upstream Segment [Member]
Gain on Business Interruption Insurance Recovery	$2.90	$2

Employee_Benefit_Plan_Narrativ

Employee Benefit Plan Narrative (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Description of Defined Contribution Pension and Other Postretirement Plans	'For the three years ended December 31, 2012, the plan provided for a dollar for dollar matching contribution by the Partnership of up to 4% of an employee's contribution and 50% of additional contributions up to an additional 2%. Additionally, the Partnership may, at its sole discretion and election, contribute up to 6% of a participating employee's base salary annually, subject to vesting requirements.	'	'
Defined Contribution Plan, Cost Recognized	$2.50	$1.80	$1

Income_Taxes_Schedule_of_Compo

Income Taxes Schedule of Components of Income Tax Expense (Benefit) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Current:	'	'	'
Federal	($105)	$621	$1,092
State	0	18	61
Total current provision	-105	639	1,153
Deferred:	'	'	'
Federal	-3,837	-2,776	-3,862
State	-1,172	434	277
Total deferred	-5,009	-2,342	-3,585
Income Tax Expense (Benefit)	($5,114)	($1,703)	($2,432)

Income_Taxes_Schedule_of_Effec

Income Taxes Schedule of Effective Income Tax Rate Reconciliation (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income (Loss) from Continuing Operations before Income Taxes, Domestic	($283,093)	($152,305)	$70,424
State Income Tax current and deferred	-1,172	452	338
Federal income taxes computed by applying the federal statutory rate to NBI of corporate entities	-4,160	-2,155	-2,232
Tax attributes used	218	0	-538
Income Tax Expense (Benefit)	($5,114)	($1,703)	($2,432)
Effective Income Tax Rate, Continuing Operations	1.80%	1.10%	-3.50%

Income_Taxes_Schedule_of_Defer

Income Taxes Schedule of Deferred Tax Assets and Liabilities (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Deferred Tax Assets:	'	'
Statutory depletion carryover	$1,438	$1,599
AMT credit carryforward	0	57
Total Deferred Tax Assets	1,438	1,656
Deferred Tax Liabilities:	'	'
Property, plant, equipment & amortizable assets	-5,867	-6,585
Unrealized hedging transactions	0	-271
Book/tax differences from partnership investment	-32,086	-36,144
Total Deferred Tax Liabilities	-37,953	-43,000
Total Net Deferred Tax Liabilities	-36,515	-41,344
Deferred Tax Assets (Liabilities), Net [Abstract]	'	'
Current potion of total net deferred tax liabilities	0	0
Long-term portion of total net deferred tax liabilities	($36,515)	($41,344)

Income_Taxes_Unrecognized_Tax_

Income Taxes Unrecognized Tax Benefits (Liabilities) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
In Thousands, unless otherwise specified					Current Period Tax Position [Member]	Current Period Tax Position [Member]	Current Period Tax Position [Member]	Lapse of Applicable Statute of Limitations [Member]	Lapse of Applicable Statute of Limitations [Member]	Lapse of Applicable Statute of Limitations [Member]
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]	'	'	'	'	'	'	'	'	'	'
Unrecognized Tax Benefits, Beginning Balance	($649)	($830)	($735)	($569)	'	'	'	'	'	'
Increases Resulting from Current Period Tax Positions	'	'	'	'	-128	-53	-132	'	'	'
Income Tax Penalties and Interest Expense	'	'	'	'	-39	-42	-34	81	0	0
Unrecognized Tax Benefits, Reduction Resulting from Lapse of Applicable Statute of Limitations	'	'	'	'	'	'	'	267	0	0
Unrecognized Tax Benefits, Ending Balance	($649)	($830)	($735)	($569)	'	'	'	'	'	'

Equity_Based_Compensation_Shar

Equity Based Compensation Share-based Compensation Rollforward (Details) (Restricted Common Units [Member], USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Restricted Common Units [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Outstanding [Roll Forward]	'	'	'
Unvested Restricted Units Outstanding, Beginning Balance	2,608,035	'	'
Grants in Period	1,623,939	'	'
Vesting of restricted units - Units	-1,203,822	'	'
Forfeited in Period	-284,345	'	'
Unvested Restricted Units Outstanding, Ending Balance	2,743,807	2,608,035	'
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Intrinsic Value [Roll Forward]	'	'	'
Weighted Average Grant Date Fair Value, Beginning	$9.38	'	'
Grants in Period, Weighted Average Grant Date Fair Value	$9.16	$9.50	$10.13
Vested in Period, Weighted Average Grant Date Fair Value	$8.98	'	'
Forfeitures in Period, Weighted Average Grant Price	$9.90	'	'
Weighted Average Grant Date Fair Value, Ending	$9.37	$9.38	'

Equity_Based_Compensation_Narr

Equity Based Compensation Narrative (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
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	913,794	'	'
Equity-based compensation	$13,384,000	$9,882,000	$5,145,000
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	17,100,000	'	'
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition	'1 year 7 months 18 days	'	'
Repurchase of common units	($1,858,000)	($2,501,000)	($1,401,000)
Common Class A [Member]	'	'	'
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]	'	'	'
Repurchase of common units - Units	-272,179	-286,716	-137,985

Earnings_Per_Unit_Schedule_of_

Earnings Per Unit Schedule of Weighted Average Number of Units(Details)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Weighted average common units outstanding - basic	153,562	135,609	110,435
Effect of dilutive securities - Warrants	0	0	5,727
Effect of dilutive securities - restricted units	0	0	779
Weighted Average common units outstanding - diluted	153,562	135,609	116,941

Earnings_Per_Unit_Calculation_

Earnings Per Unit Calculation of basic and diluted earnings per unit (Details) (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]	'	'	'
Income (Loss) from Continuing Operations Attributable to Parent	($277,979)	($150,602)	$72,856
Distributions	117,294	124,235	89,062
Assumed income (loss) from continuing operations after distribution to be allocated	-395,273	-274,837	-16,206
Discontinued operations, net of tax	0	0	276
Net income (loss)	-277,979	-150,602	73,132
Net Income (loss) from continuing operations per common unit - basic	($1.82)	($1.13)	$0.65
Discontinued operations per common unit - basic	$0	$0	$0
Net income (loss) per common unit - basic	($1.82)	($1.13)	$0.65
Net Income (loss) from continuing operations per common units - diluted	($1.82)	($1.13)	$0.61
Discontinued operations per common unit - diluted	$0	$0	$0
Net Income (Loss), Per Outstanding Limited Partnership Unit, Diluted	$1.82	$1.13	($0.62)
Common Stock [Member]	'	'	'
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]	'	'	'
Income (Loss) from Continuing Operations Attributable to Parent	'	'	71,319
Distributions	115,351	121,504	87,525
Assumed income (loss) from continuing operations after distribution to be allocated	-395,273	-274,837	-16,206
Discontinued operations, net of tax	'	'	276
Net income (loss)	-279,922	-153,333	71,595
Net Income (loss) from continuing operations per common unit - basic	'	'	$0.65
Discontinued operations per common unit - basic	'	'	$0
Net income (loss) per common unit - basic	($1.82)	($1.13)	$0.65
Net Income (loss) from continuing operations per common units - diluted	'	'	$0.61
Discontinued operations per common unit - diluted	'	'	$0
Net Income (Loss), Per Outstanding Limited Partnership Unit, Diluted	'	'	($0.62)
Restricted Common Units [Member]	'	'	'
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]	'	'	'
Income (Loss) from Continuing Operations Attributable to Parent	'	'	1,537
Distributions	1,943	2,731	1,537
Assumed income (loss) from continuing operations after distribution to be allocated	0	0	0
Discontinued operations, net of tax	'	'	0
Net income (loss)	$1,943	$2,731	$1,537

Divestiture_Related_Activities2

Divestiture Related Activities Schedule of Disposal Groups, Including Discontinued Operations, Income Statement, Balance Sheet and Additional Disclosures(Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012		Dec. 31, 2011
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]	'	'		'
Proceeds from sale of asset	$285	$15,398		$5,712
Barnett Shale [Member]	'	'		'
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]	'	'		'
Gain (loss) from disposal	'	-4,460	[1]	'
Proceeds from sale of asset	'	14,841	[1]	'
Wildhorse System [Member]	'	'		'
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]	'	'		'
Revenue attributable to disposal group	'	'		6,859	[2]
Operating income (loss) attibutable to disposal group	'	'		548	[2]
Discontinued operations, net of tax	'	'		-180	[2]
Gain (loss) from disposal	'	0		-718	[2],[3]
Proceeds from sale of asset	'	0		5,712	[2]
Minerals Business [Member]	'	'		'
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]	'	'		'
Revenue attributable to disposal group	'	'		0	[3]
Operating income (loss) attibutable to disposal group	'	'		0	[3]
Discontinued operations, net of tax	'	'		456	[3]
Gain (loss) from disposal	'	0		0
Proceeds from sale of asset	'	$0		$0
[1]	On December 20, 2012, the Partnership sold its Barnett Shale properties (which was accounted for in its Upstream Segment). In 2012, the Partnership incurred a loss from sale which is included within impairment expense in the Consolidated Statement of Operations.
[2]	On May 20, 2011, the Partnership sold its Wildhorse Gathering System (which was accounted for in its East Texas and Other Midstream Segment).
[3]	On May 24, 2010, the Partnership completed the sale of its Minerals Business. During the year ended December 31, 2011, the Partnership received payments related to pre-effective date operations and recorded this amount as part of discontinued operations for the period.

Other_Operating_Income_Narrati

Other Operating Income Narrative (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Accounts Receivable, Gross	'	'	'	$3,900,000
Proceeds from Sale of Other Receivables	'	'	'	3,000,000
Other Nonrecurring Income	$0	$0	$2,893,000	'

Subsidiary_Guarantors_Subsidia1

Subsidiary Guarantors Subsidiary Guarantors Condensed Consolidating Balance Sheets (Details) (USD $)	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
In Thousands, unless otherwise specified
Subsidiary Guarantors [Line Items]	'		'		'
Accounts receivable – related parties	$0		$0		'
Other current assets	163,384		181,964		'
Property, Plant and Equipment — Net	1,828,768		1,968,206		'
Investment in subsidiaries	0		0		'
Total other long-term assets	135,398		144,046		'
Total assets	2,127,550		2,294,216		2,045,688
Accounts payable – related parties	0		0		'
Other current liabilities	211,266		181,514		'
Other long-term liabilities	90,343		91,225		'
Long-term debt	1,252,062		1,153,103		'
Members' Equity	573,879	[1]	868,374	[1]	'
Total liabilities and equity	2,127,550		2,294,216		'
Parent Company [Member]	'		'		'
Subsidiary Guarantors [Line Items]	'		'		'
Accounts receivable – related parties	691,588		660,898		'
Other current assets	5,868		27,688		'
Property, Plant and Equipment — Net	2,318		2,657		'
Investment in subsidiaries	1,133,217		1,324,293		'
Total other long-term assets	19,833		22,061		'
Total assets	1,852,824		2,037,597		'
Accounts payable – related parties	0		0		'
Other current liabilities	17,390		6,734		'
Other long-term liabilities	9,493		9,386		'
Long-term debt	1,252,062		1,153,103		'
Members' Equity	573,879		868,374		'
Total liabilities and equity	1,852,824		2,037,597		'
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	157,515		154,275		'
Property, Plant and Equipment — Net	1,826,450		1,965,549		'
Investment in subsidiaries	0		0		'
Total other long-term assets	115,565		121,985		'
Total assets	2,099,530		2,241,809		'
Accounts payable – related parties	691,588		660,898		'
Other current liabilities	193,876		174,780		'
Other long-term liabilities	80,850		81,839		'
Long-term debt	0		0		'
Members' Equity	1,133,216		1,324,292		'
Total liabilities and equity	2,099,530		2,241,809		'
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	908		958		'
Total other long-term assets	0		0		'
Total assets	908		958		'
Accounts payable – related parties	0		0		'
Other current liabilities	0		0		'
Other long-term liabilities	0		0		'
Long-term debt	0		0		'
Members' Equity	908		958		'
Total liabilities and equity	908		958		'
Consolidation, Eliminations [Member]	'		'		'
Subsidiary Guarantors [Line Items]	'		'		'
Accounts receivable – related parties	-691,588		-660,898		'
Other current assets	0		0		'
Property, Plant and Equipment — Net	0		0		'
Investment in subsidiaries	-1,134,125		-1,325,251		'
Total other long-term assets	0		0		'
Total assets	-1,825,713		-1,986,149		'
Accounts payable – related parties	-691,588		-660,898		'
Other current liabilities	0		0		'
Other long-term liabilities	0		0		'
Long-term debt	0		0		'
Members' Equity	-1,134,125		-1,325,251		'
Total liabilities and equity	($1,825,713)		($1,986,149)		'
[1]	156,644,153 and 144,675,751 common units were issued and outstanding as of December 31, 2013 and December 31, 2012, respectively. These amounts do not include unvested restricted common units granted under the Partnership's long-term incentive plan of 2,743,807 and 2,608,035 as of December 31, 2013 and December 31, 2012, respectively.

Subsidiary_Guarantors_Subsidia2

Subsidiary Guarantors Subsidiary Guarantors Condensed Consolidating Income Statement (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Subsidiary Guarantors [Line Items]	'	'	'
Total revenues	$1,195,279	$983,959	$1,059,908
Cost of natural gas, natural gas liquids, and condensate	790,618	532,719	633,184
Operations and maintenance	135,205	119,828	93,048
Taxes other than income	20,270	19,432	19,148
General and administrative	81,214	69,994	57,891
Other operating income	'	'	-2,893
Depreciation, Depletion and Amortization	167,170	161,045	131,611
Impairment	214,286	177,003	16,288
OPERATING INCOME (LOSS)	-213,484	-96,062	111,631
Interest expense, net	-68,762	-51,478	-29,622
Other non-operating income	0	0	0
Other (expense) income	-847	-4,765	-11,585
Income (loss) before income taxes	-283,093	-152,305	70,424
Income Tax Expense (Benefit)	-5,114	-1,703	-2,432
Equity in earnings of subsidiaires	0	0	0
INCOME (LOSS) FROM CONTINUING OPERATIONS	-277,979	-150,602	72,856
Discontinued operations, net of tax	'	'	276
Net income (loss)	-277,979	-150,602	73,132
Parent Company [Member]	'	'	'
Subsidiary Guarantors [Line Items]	'	'	'
Total revenues	-4,168	28,884	36,095
Cost of natural gas, natural gas liquids, and condensate	0	0	0
Operations and maintenance	-1	0	0
Taxes other than income	0	0	0
General and administrative	17,716	10,908	5,299
Other operating income	'	'	0
Depreciation, Depletion and Amortization	454	296	196
Impairment	0	0	0
OPERATING INCOME (LOSS)	-22,337	17,680	30,600
Interest expense, net	-67,864	-51,501	-29,614
Other non-operating income	9,025	9,039	8,779
Other (expense) income	-6,904	-12,189	-28,589
Income (loss) before income taxes	-88,080	-36,971	-18,824
Income Tax Expense (Benefit)	-1,172	431	339
Equity in earnings of subsidiaires	-191,071	-113,200	92,295
INCOME (LOSS) FROM CONTINUING OPERATIONS	'	'	73,132
Discontinued operations, net of tax	'	'	0
Net income (loss)	-277,979	-150,602	73,132
Co-issuer [Member]	'	'	'
Subsidiary Guarantors [Line Items]	'	'	'
Total revenues	0	0	0
Cost of natural gas, natural gas liquids, and condensate	0	0	0
Operations and maintenance	0	0	0
Taxes other than income	0	0	0
General and administrative	0	0	0
Other operating income	'	'	0
Depreciation, Depletion and Amortization	0	0	0
Impairment	0	0	0
OPERATING INCOME (LOSS)	0	0	0
Interest expense, net	0	0	0
Other non-operating income	0	0	0
Other (expense) income	0	0	0
Income (loss) before income taxes	0	0	0
Income Tax Expense (Benefit)	0	0	0
Equity in earnings of subsidiaires	0	0	0
INCOME (LOSS) FROM CONTINUING OPERATIONS	'	'	0
Discontinued operations, net of tax	'	'	0
Net income (loss)	0	0	0
Guarantor Subsidiaries [Member]	'	'	'
Subsidiary Guarantors [Line Items]	'	'	'
Total revenues	1,199,447	955,075	1,023,813
Cost of natural gas, natural gas liquids, and condensate	790,618	532,719	633,184
Operations and maintenance	135,206	119,828	93,048
Taxes other than income	20,270	19,432	19,148
General and administrative	63,498	59,086	52,592
Other operating income	'	'	-2,893
Depreciation, Depletion and Amortization	166,716	160,749	131,415
Impairment	214,286	177,003	16,288
OPERATING INCOME (LOSS)	-191,147	-113,742	81,031
Interest expense, net	-898	23	-8
Other non-operating income	9,298	10,961	5,607
Other (expense) income	-12,256	-12,558	2,628
Income (loss) before income taxes	-195,003	-115,316	89,258
Income Tax Expense (Benefit)	-3,942	-2,134	-2,771
Equity in earnings of subsidiaires	0	0	0
INCOME (LOSS) FROM CONTINUING OPERATIONS	'	'	92,029
Discontinued operations, net of tax	'	'	276
Net income (loss)	-191,061	-113,182	92,305
Non-Guarantor Subsidiaries [Member]	'	'	'
Subsidiary Guarantors [Line Items]	'	'	'
Total revenues	0	0	0
Cost of natural gas, natural gas liquids, and condensate	0	0	0
Operations and maintenance	0	0	0
Taxes other than income	0	0	0
General and administrative	0	0	0
Other operating income	'	'	0
Depreciation, Depletion and Amortization	0	0	0
Impairment	0	0	0
OPERATING INCOME (LOSS)	0	0	0
Interest expense, net	0	0	0
Other non-operating income	0	0	0
Other (expense) income	-10	-18	-10
Income (loss) before income taxes	-10	-18	-10
Income Tax Expense (Benefit)	0	0	0
Equity in earnings of subsidiaires	0	0	0
INCOME (LOSS) FROM CONTINUING OPERATIONS	'	'	-10
Discontinued operations, net of tax	'	'	0
Net income (loss)	-10	-18	-10
Consolidation, Eliminations [Member]	'	'	'
Subsidiary Guarantors [Line Items]	'	'	'
Total revenues	0	0	0
Cost of natural gas, natural gas liquids, and condensate	0	0	0
Operations and maintenance	0	0	0
Taxes other than income	0	0	0
General and administrative	0	0	0
Other operating income	'	'	0
Depreciation, Depletion and Amortization	0	0	0
Impairment	0	0	0
OPERATING INCOME (LOSS)	0	0	0
Interest expense, net	0	0	0
Other non-operating income	-18,323	-20,000	-14,386
Other (expense) income	18,323	20,000	14,386
Income (loss) before income taxes	0	0	0
Income Tax Expense (Benefit)	0	0	0
Equity in earnings of subsidiaires	191,071	113,200	-92,295
INCOME (LOSS) FROM CONTINUING OPERATIONS	'	'	-92,295
Discontinued operations, net of tax	'	'	0
Net income (loss)	$191,071	$113,200	($92,295)

Subsidiary_Guarantors_Subsidia3

Subsidiary Guarantors Subsidiary Guarantor Condensed Consolidating Statements of Cash Flows (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Subsidiary Guarantors [Line Items]	'	'	'
Net cash flows provided by operating activities	$177,376	$145,501	$117,800
Additions to property, plant and equipment	-243,430	-306,024	-154,916
Acquisitions, net of cash acquired	0	-230,640	-220,326
Proceeds from sale of asset	285	15,398	5,712
Purchase of intangible assets	-3,903	-7,404	-4,406
Contribution to subsidiaries	'	0	0
Net cash provided by (used in) investing activities	-247,048	-528,670	-373,936
Proceeds from long-term debt	601,400	1,043,750	964,279
Repayment of long-term debt	-503,100	-916,750	-1,012,779
Proceeds from Senior Notes	0	246,253	297,837
Payment of debt issuance costs	0	-7,132	-17,466
Proceeds from derivative contracts	1,323	14,449	6,267
Common unit issued in equity offerings	102,388	96,173	0
Issuance costs for equity offerings	-4,519	-4,518	0
Exercise of Warrants	0	31,804	89,745
Repurchase of common units	-1,858	-2,501	-1,401
Distributions to members and affiliates	-125,911	-119,211	-74,512
Contribution from parent	'	0	0
Net cash provided by (used in) financing activities	69,723	382,317	251,970
Net Cash Provided by (Used in) Discontinued Operations	0	0	994
Net increase in cash and cash equivalents	51	-852	-3,172
CASH AND CASH EQUIVALENTS—Beginning of period	25	877	4,049
CASH AND CASH EQUIVALENTS—End of period	76	25	877
Parent Company [Member]	'	'	'
Subsidiary Guarantors [Line Items]	'	'	'
Net cash flows provided by operating activities	-70,041	-143,444	-27,569
Additions to property, plant and equipment	-115	-1,551	-389
Acquisitions, net of cash acquired	'	0	0
Proceeds from sale of asset	0	0	0
Purchase of intangible assets	0	0	0
Contribution to subsidiaries	'	-236,971	-227,583
Net cash provided by (used in) investing activities	-115	-238,522	-227,972
Proceeds from long-term debt	601,400	1,043,750	964,279
Repayment of long-term debt	-503,100	-916,750	-1,012,779
Proceeds from Senior Notes	'	246,253	297,837
Payment of debt issuance costs	'	-7,132	-17,466
Proceeds from derivative contracts	1,323	14,449	6,267
Common unit issued in equity offerings	102,388	96,173	'
Issuance costs for equity offerings	-4,519	-4,518	'
Exercise of Warrants	'	31,804	89,745
Repurchase of common units	-1,858	-2,501	-1,401
Distributions to members and affiliates	-125,911	-119,211	-74,512
Contribution from parent	'	0	0
Net cash provided by (used in) financing activities	69,723	382,317	251,970
Net Cash Provided by (Used in) Discontinued Operations	'	'	0
Net increase in cash and cash equivalents	-433	351	-3,571
CASH AND CASH EQUIVALENTS—Beginning of period	1,670	1,319	4,890
CASH AND CASH EQUIVALENTS—End of period	1,237	1,670	1,319
Co-issuer [Member]	'	'	'
Subsidiary Guarantors [Line Items]	'	'	'
Net cash flows provided by operating activities	0	0	0
Additions to property, plant and equipment	0	0	0
Acquisitions, net of cash acquired	'	0	0
Proceeds from sale of asset	0	0	0
Purchase of intangible assets	0	0	0
Contribution to subsidiaries	'	0	0
Net cash provided by (used in) investing activities	0	0	0
Proceeds from long-term debt	0	0	0
Repayment of long-term debt	0	0	0
Proceeds from Senior Notes	'	0	0
Payment of debt issuance costs	'	0	0
Proceeds from derivative contracts	0	0	0
Common unit issued in equity offerings	0	0	'
Issuance costs for equity offerings	0	0	'
Exercise of Warrants	'	0	0
Repurchase of common units	0	0	0
Distributions to members and affiliates	0	0	0
Contribution from parent	'	0	0
Net cash provided by (used in) financing activities	0	0	0
Net Cash Provided by (Used in) Discontinued Operations	'	'	0
Net increase in cash and cash equivalents	0	0	0
CASH AND CASH EQUIVALENTS—Beginning of period	1	1	1
CASH AND CASH EQUIVALENTS—End of period	1	1	1
Guarantor Subsidiaries [Member]	'	'	'
Subsidiary Guarantors [Line Items]	'	'	'
Net cash flows provided by operating activities	247,376	288,888	145,283
Additions to property, plant and equipment	-243,315	-304,473	-154,527
Acquisitions, net of cash acquired	'	-230,640	-220,326
Proceeds from sale of asset	285	15,398	5,712
Purchase of intangible assets	-3,903	-7,404	-4,406
Contribution to subsidiaries	'	0	0
Net cash provided by (used in) investing activities	-246,933	-527,119	-373,547
Proceeds from long-term debt	0	0	0
Repayment of long-term debt	0	0	0
Proceeds from Senior Notes	'	0	0
Payment of debt issuance costs	'	0	0
Proceeds from derivative contracts	0	0	0
Common unit issued in equity offerings	0	0	'
Issuance costs for equity offerings	0	0	'
Exercise of Warrants	'	0	0
Repurchase of common units	0	0	0
Distributions to members and affiliates	0	0	0
Contribution from parent	'	236,971	227,583
Net cash provided by (used in) financing activities	0	236,971	227,583
Net Cash Provided by (Used in) Discontinued Operations	'	'	994
Net increase in cash and cash equivalents	443	-1,260	313
CASH AND CASH EQUIVALENTS—Beginning of period	-1,832	-572	-885
CASH AND CASH EQUIVALENTS—End of period	-1,389	-1,832	-572
Non-Guarantor Subsidiaries [Member]	'	'	'
Subsidiary Guarantors [Line Items]	'	'	'
Net cash flows provided by operating activities	41	57	86
Additions to property, plant and equipment	0	0	0
Acquisitions, net of cash acquired	'	0	0
Proceeds from sale of asset	0	0	0
Purchase of intangible assets	0	0	0
Contribution to subsidiaries	'	0	0
Net cash provided by (used in) investing activities	0	0	0
Proceeds from long-term debt	0	0	0
Repayment of long-term debt	0	0	0
Proceeds from Senior Notes	'	0	0
Payment of debt issuance costs	'	0	0
Proceeds from derivative contracts	0	0	0
Common unit issued in equity offerings	0	0	'
Issuance costs for equity offerings	0	0	'
Exercise of Warrants	'	0	0
Repurchase of common units	0	0	0
Distributions to members and affiliates	0	0	0
Contribution from parent	'	0	'
Net cash provided by (used in) financing activities	0	0	0
Net Cash Provided by (Used in) Discontinued Operations	'	'	0
Net increase in cash and cash equivalents	41	57	86
CASH AND CASH EQUIVALENTS—Beginning of period	186	129	43
CASH AND CASH EQUIVALENTS—End of period	227	186	129
Consolidation, Eliminations [Member]	'	'	'
Subsidiary Guarantors [Line Items]	'	'	'
Net cash flows provided by operating activities	0	0	0
Additions to property, plant and equipment	0	0	0
Acquisitions, net of cash acquired	'	0	0
Proceeds from sale of asset	0	0	0
Purchase of intangible assets	0	0	0
Contribution to subsidiaries	'	236,971	227,583
Net cash provided by (used in) investing activities	0	236,971	227,583
Proceeds from long-term debt	0	0	0
Repayment of long-term debt	0	0	0
Proceeds from Senior Notes	'	0	0
Payment of debt issuance costs	'	0	0
Proceeds from derivative contracts	0	0	0
Common unit issued in equity offerings	0	0	'
Issuance costs for equity offerings	0	0	'
Exercise of Warrants	'	0	0
Repurchase of common units	0	0	0
Distributions to members and affiliates	0	0	0
Contribution from parent	'	-236,971	-227,583
Net cash provided by (used in) financing activities	0	-236,971	-227,583
Net Cash Provided by (Used in) Discontinued Operations	'	'	0
Net increase in cash and cash equivalents	0	0	0
CASH AND CASH EQUIVALENTS—Beginning of period	0	0	0
CASH AND CASH EQUIVALENTS—End of period	$0	$0	$0

Subsequent_Events_Subsequent_E1

Subsequent Events Subsequent Events (Details)	Feb. 28, 2014	Dec. 31, 2013
Subsequent Event [Line Items]	'	'
Borrowing Base Multiplier	4	3.75
Total Leverage Ratio [Member]	'	'
Subsequent Event [Line Items]	'	'
Line of Credit Facility, Covenant Ratio	5.85	5.4
Senior Secured Leverage Ratio [Member]	'	'
Subsequent Event [Line Items]	'	'
Line of Credit Facility, Covenant Ratio	3.4	3.06

Supplemental_Oil_and_Gas_Infor2

Supplemental Oil and Gas Information (Unaudited) Proved Reserves Summary (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
	MBbls	MBbls	MBbls	MBbls
Reserve Quantities [Line Items]	'	'	'	'
Twelve month average oil price	96.94	'	'	'
Twelve month average natural gas price	3.66	'	'	'
Oil [Member]	'	'	'	'
Reserve Quantities [Line Items]	'	'	'	'
Proved Developed and Undeveloped Reserves, Net	12,984	11,522	8,696	'
Proved Developed and Undeveloped Reserves, Extensions, Discoveries, and Additions	2,712	1,405	215	'
Proved Developed and Undeveloped Reserves, Purchases of Minerals in Place	'	104	3,830	'
Proved Developed and Undeveloped Reserves, Production	-1,222	-1,184	-1,118	'
Proved Developed and Undeveloped Reserves, Sales of Minerals in Place	'	0	'	'
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	-932	1,137	-101	'
Proved Developed and Undeveloped Reserves, Net	13,542	12,984	11,522	'
Proved Developed Reserves (Volume)	10,153	10,993	10,271	8,299
Proved Undeveloped Reserve (Volume)	3,389	1,991	1,251	397
Natural Gas [Member]	'	'	'	'
Reserve Quantities [Line Items]	'	'	'	'
Proved Developed and Undeveloped Reserves, Net	194,429	234,022	38,382	'
Proved Developed and Undeveloped Reserves, Extensions, Discoveries, and Additions	29,137	31,524	14,523	'
Proved Developed and Undeveloped Reserves, Purchases of Minerals in Place	'	128	198,826	'
Proved Developed and Undeveloped Reserves, Production	-12,804	-16,443	-12,636	'
Proved Developed and Undeveloped Reserves, Sales of Minerals in Place	'	-13,331	'	'
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	-33,536	-41,471	-5,073	'
Proved Developed and Undeveloped Reserves, Net	177,226	194,429	234,022	'
Proved Developed Reserves (Volume)	126,950	136,545	165,269	29,686
Proved Undeveloped Reserve (Volume)	50,276	57,884	68,753	8,696
Natural Gas Liquids [Member]	'	'	'	'
Reserve Quantities [Line Items]	'	'	'	'
Proved Developed and Undeveloped Reserves, Net	12,866	11,347	6,176	'
Proved Developed and Undeveloped Reserves, Extensions, Discoveries, and Additions	3,180	2,136	903	'
Proved Developed and Undeveloped Reserves, Purchases of Minerals in Place	'	18	4,815	'
Proved Developed and Undeveloped Reserves, Production	-1,156	-1,121	-805	'
Proved Developed and Undeveloped Reserves, Sales of Minerals in Place	'	0	'	'
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	-253	486	258	'
Proved Developed and Undeveloped Reserves, Net	14,637	12,866	11,347	'
Proved Developed Reserves (Volume)	10,766	10,445	9,307	5,758
Proved Undeveloped Reserve (Volume)	3,871	2,421	2,040	418

Supplemental_Oil_and_Gas_Infor3

Supplemental Oil and Gas Information (Unaudited) Capitalized Costs Relating to Oil and Gas Producing Activities (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
In Thousands, unless otherwise specified
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]	'	'	'
Evaluated properties	$1,156,896	$1,213,622	$1,050,872
Unevaluated properties—excluded from depletion	10,022	31,823	91,363
Gross oil and gas properties	1,166,918	1,245,445	1,142,235
Accumulated depreciation, depletion, amortization	-353,679	-269,376	-190,833
Net oil and gas properties	$813,239	$976,069	$951,402

Supplemental_Oil_and_Gas_Infor4

Supplemental Oil and Gas Information (Unaudited) Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]	'	'	'
Property acquisition costs, proved	$0	$2,582	$465,088
Property acquisition costs, unproved	0	0	103,337
Development costs	124,032	135,692	90,418
Total costs	$124,032	$138,274	$658,843

Supplemental_Oil_and_Gas_Infor5

Supplemental Oil and Gas Information (Unaudited) Standarized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]	'	'	'
Future cash inflows	$2,423,350	$2,279,735	$2,516,812
Future production costs	-737,468	-767,004	-845,530
Future development costs	-318,778	-354,690	-315,019
Future net cash flows before income taxes	1,367,104	1,158,041	1,356,263
Future income tax (expense) benefit	-1,212	-1,086	-1,831
Future net cash flows before 10% discount	1,365,892	1,156,955	1,354,432
10% annual discount for estimated timing of cash flows	-715,386	-621,826	-711,846
Total standardized measure of discounted future net cash flows	650,506	535,129	642,586
Reported [Member]	'	'	'
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]	'	'	'
Future cash inflows	'	2,315,266	2,562,650
Future production costs	'	-669,896	-742,749
Future development costs	'	-359,154	-317,405
Future net cash flows before income taxes	'	1,286,216	1,502,496
Future income tax (expense) benefit	'	-1,321	-2,379
Future net cash flows before 10% discount	'	1,284,895	1,500,117
10% annual discount for estimated timing of cash flows	'	-680,855	-778,520
Total standardized measure of discounted future net cash flows	'	604,040	721,597
Revisions [Member]	'	'	'
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]	'	'	'
Future cash inflows	'	-35,531	-45,838
Future production costs	'	-97,108	-102,781
Future development costs	'	4,464	2,386
Future net cash flows before income taxes	'	-128,175	-146,233
Future income tax (expense) benefit	'	235	548
Future net cash flows before 10% discount	'	-127,940	-145,685
10% annual discount for estimated timing of cash flows	'	59,029	66,674
Total standardized measure of discounted future net cash flows	'	-68,911	-79,011
Adjusted [Member]	'	'	'
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]	'	'	'
Future cash inflows	'	2,279,735	2,516,812
Future production costs	'	-767,004	-845,530
Future development costs	'	-354,690	-315,019
Future net cash flows before income taxes	'	1,158,041	1,356,263
Future income tax (expense) benefit	'	-1,086	-1,831
Future net cash flows before 10% discount	'	1,156,955	1,354,432
10% annual discount for estimated timing of cash flows	'	-621,826	-711,846
Total standardized measure of discounted future net cash flows	'	$535,129	$642,586

Supplemental_Oil_and_Gas_Infor6

Supplemental Oil and Gas Information (Unaudited) Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]	'	'	'
Beginning of year	$535,129	$642,586	$284,687
Sale of oil and gas produced, net of production costs	-150,457	-132,451	-138,860
Net changes in prices and production costs	2,720	-78,247	143,023
Extensions, discoveries and improved recovery, less related costs	136,464	66,460	40,832
Previously estimated development costs incurred during the period	21,470	53,111	90,418
Net changes in future development costs	107,951	36,914	-119,121
Revisions of previous quantity estimates	-103,351	-76,434	-34,497
Purchases of property	0	2,811	324,652
Sales of property	0	-5,063	0
Accretion of discount	49,233	60,734	26,225
Net changes in income taxes	-36	317	-519
Other	51,383	-35,609	25,746
End of year	650,506	535,129	642,586
Reported [Member]	'	'	'
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]	'	'	'
Beginning of year	'	721,597	333,993
Sale of oil and gas produced, net of production costs	'	-132,451	-138,860
Net changes in prices and production costs	'	-76,759	170,917
Extensions, discoveries and improved recovery, less related costs	'	66,460	40,832
Previously estimated development costs incurred during the period	'	53,111	90,418
Net changes in future development costs	'	36,503	-117,783
Revisions of previous quantity estimates	'	-85,176	-26,447
Purchases of property	'	2,811	324,652
Sales of property	'	-5,063	'
Accretion of discount	'	67,956	30,728
Net changes in income taxes	'	564	-621
Other	'	-45,513	13,768
End of year	'	604,040	721,597
Revisions [Member]	'	'	'
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]	'	'	'
Beginning of year	'	-79,011	-49,306
Sale of oil and gas produced, net of production costs	'	0	0
Net changes in prices and production costs	'	-1,488	-27,894
Extensions, discoveries and improved recovery, less related costs	'	0	0
Previously estimated development costs incurred during the period	'	0	0
Net changes in future development costs	'	411	-1,338
Revisions of previous quantity estimates	'	8,742	-8,050
Purchases of property	'	0	0
Sales of property	'	0	'
Accretion of discount	'	-7,222	-4,503
Net changes in income taxes	'	-247	102
Other	'	9,904	11,978
End of year	'	-68,911	-79,011
Adjusted [Member]	'	'	'
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]	'	'	'
Beginning of year	'	642,586	284,687
Sale of oil and gas produced, net of production costs	'	-132,451	-138,860
Net changes in prices and production costs	'	-78,247	143,023
Extensions, discoveries and improved recovery, less related costs	'	66,460	40,832
Previously estimated development costs incurred during the period	'	53,111	90,418
Net changes in future development costs	'	36,914	-119,121
Revisions of previous quantity estimates	'	-76,434	-34,497
Purchases of property	'	2,811	324,652
Sales of property	'	-5,063	'
Accretion of discount	'	60,734	26,225
Net changes in income taxes	'	317	-519
Other	'	-35,609	25,746
End of year	'	$535,129	$642,586

Supplemental_Oil_and_Gas_Infor7

Supplemental Oil and Gas Information (Unaudited) Results of Operations (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Revenues:	'	'	'
Sales to third parties	$146,210	$135,842	$138,383
Intercompany sales	47,048	53,343	48,203
Total revenues	193,258	189,185	186,586
Costs and expenses:	'	'	'
Production costs	54,354	56,734	47,726
General and administrative	11,419	12,162	11,124
Depreciation, depletion, and amortization	87,456	88,777	65,531
Impairment	214,286	45,289	11,728
Total costs and expenses	367,515	202,962	136,109
Total result of operations	($174,257)	($13,777)	$50,477

Supplemental_Oil_and_Gas_Infor8

Supplemental Oil and Gas Information (Unaudited) Narrative (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Results of Operations, Revenue, Other	$8.10	$14	$17.80