Resources Connection 10-Q 8 May 14 2014 Q1 Quarterly report Financial data

Document_and_Entity_Informatio

Document and Entity Information Document	3 Months Ended
	Mar. 31, 2014	1-May-14
Entity Information	'	'
Document Type	'10-Q	'
Amendment Flag	'false	'
Document Period End Date	31-Mar-14	'
Document Fiscal Year Focus	'2014	'
Document Fiscal Period Focus	'Q1	'
Trading Symbol	'RGP	'
Entity Registrant Name	'Regency Energy Partners LP	'
Entity Central Index Key	'0001338613	'
Current Fiscal Year End Date	'--12-31	'
Entity Filer Category	'Large Accelerated Filer	'
Entity Common Stock, Shares Outstanding	'	356,547,665

Condensed_Consolidated_Balance

Condensed Consolidated Balance Sheets (USD $)	Mar. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Current Assets:	'	'
Cash and cash equivalents	$13	$19
Trade accounts receivable, net	446	292
Related party receivables	24	28
Inventories	57	42
Other current assets	20	19
Total current assets	560	400
Property, plant and equipment	8,033	5,050
Less accumulated depreciation and depletion	-712	-632
Property, plant and equipment, net	7,321	4,418
Investment in unconsolidated affiliates	2,178	2,097
Other, net of accumulated amortization of debt issuance costs of $26 and $24	84	57
Intangible assets, net of accumulated amortization of $116 and $107	3,568	682
Goodwill	1,486	1,128
TOTAL ASSETS	15,197	8,782
Current Liabilities:	'	'
Drafts payable	17	26
Trade accounts payable	393	291
Related party payables	57	69
Accrued interest	94	38
Other current liabilities	108	51
Total current liabilities	669	475
Long-term derivative liabilities	20	19
Other long-term liabilities	49	30
Long-term debt, net	5,564	3,310
Commitments and contingencies	'	'
Series A preferred units, redemption amounts of $38 and $38	32	32
Partners’ capital and noncontrolling interest:	'	'
Common units	7,835	3,886
Class F units	148	146
General partner interest	783	782
Total partners’ capital	8,766	4,814
Noncontrolling interest	97	102
Total partners’ capital and noncontrolling interest	8,863	4,916
TOTAL LIABILITIES AND PARTNERS’ CAPITAL AND NONCONTROLLING INTEREST	$15,197	$8,782

Condensed_Consolidated_Balance1

Condensed Consolidated Balance Sheets Balance Sheet (Paranthetical) (USD $)	Mar. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Paranthetical [Abstract]	'	'
Other, accumulated amortization of debt issuance costs	$26	$24
Intangible assets, net of accumulated amortization	116	107
Series A preferred units, redemption amount	$38	$38

Condensed_Consolidated_Stateme

Condensed Consolidated Statements Of Operations (USD $)	3 Months Ended
In Millions, except Share data, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
REVENUES	'	'
Gas sales, including related party amounts of $13 and $5	$335	$167
NGL sales, including related party amounts of $50 and $25	331	235
Gathering, transportation and other fees, including related party amounts of $6 and $7	172	127
Net realized and unrealized loss from derivatives	-13	-3
Other	38	14
Total revenues	863	540
OPERATING COSTS AND EXPENSES	'	'
Cost of sales, including related party amounts of $10 and $9	638	387
Operation and maintenance	78	69
General and administrative	33	33
(Gain) loss on asset sales, net	-2	1
Depreciation, depletion and amortization	94	65
Total operating costs and expenses	841	555
OPERATING INCOME (LOSS)	22	-15
Income from unconsolidated affiliates	43	35
Interest expense, net	-56	-37
Other income and deductions, net	2	-14
INCOME (LOSS) BEFORE INCOME TAXES	11	-31
Income tax benefit	-1	-2
NET INCOME (LOSS)	12	-29
Net income attributable to noncontrolling interest	-3	0
NET INCOME (LOSS) ATTRIBUTABLE TO REGENCY ENERGY PARTNERS LP	9	-29
Amounts attributable to Series A preferred units	1	2
General partner’s interest, including IDRs	5	2
Beneficial conversion feature for Class F units	2	0
Pre-acquisition loss from SUGS allocated to predecessor equity	0	-24
Limited partners’ interest in net income (loss)	1	-9
Basic and diluted net income (loss) per common unit:	'	'
Weighted average number of common units outstanding	226,046,232	170,952,804
Basic income (loss) per common unit	$0	($0.06)
Diluted income (loss) per common unit	$0	($0.06)
Distributions per common unit	$0.48	$0.46
Amount allocated to Class F units due to beneficial conversion feature	$2	$0
Total number of Class F units outstanding	6,274,483	0
Income per Class F unit due to beneficial conversion feature	$0.27	$0

Condensed_Consolidated_Stateme1

Condensed Consolidated Statements Of Operations Statements of Operations (Paranthetical) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Paranthetical [Abstract]	'	'
Gas sales, related party amounts	$13	$5
NGL sales, related party amounts	50	25
Gathering, transportation and other fees, related party amounts	6	7
Cost of sales, related party amounts	$10	$9

Condensed_Consolidated_Stateme2

Condensed Consolidated Statements Of Comprehensive Income (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Net income (loss)	$12	($29)
Total other comprehensive income (loss)	0	0
Comprehensive income (loss)	12	-29
Comprehensive income attributable to noncontrolling interest	3	0
Comprehensive income (loss) attributable to Regency Energy Partners LP	$9	($29)

Condensed_Consolidated_Stateme3

Condensed Consolidated Statements Of Cash Flows (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
OPERATING ACTIVITIES:	'	'
Net income (loss)	$12	($29)
Reconciliation of net income (loss) to net cash flows provided by operating activities:	'	'
Depreciation, depletion and amortization, including debt issuance cost amortization and bond premium write-off and amortization	97	67
Income from unconsolidated affiliates	-43	-35
Derivative valuation changes	17	18
(Gain) loss on asset sales, net	-2	1
Unit-based compensation expenses	2	2
Cash flow changes in current assets and liabilities:	'	'
Trade accounts receivable and related party receivables	-21	-14
Other current assets and other current liabilities	35	85
Trade accounts payable and related party payables	48	-47
Distributions of earnings received from unconsolidated affiliates	43	36
Cash flow changes in other assets and liabilities	-1	-1
Net cash flows provided by operating activities	187	83
INVESTING ACTIVITIES:	'	'
Capital expenditures	-215	-273
Capital contributions to unconsolidated affiliates	-40	-43
Distributions in excess of earnings of unconsolidated affiliates	9	16
Acquisitions, net of cash received	-213	0
Proceeds from asset sales	5	12
Net cash flows used in investing activities	-454	-288
FINANCING ACTIVITIES:	'	'
(Repayments) borrowings under revolving credit facility, net	-519	179
Proceeds from issuances of senior notes	886	0
Debt issuance costs	-16	0
Drafts payable	-8	5
Partner distributions and distributions on unvested unit awards	-107	-83
Common units issued under equity distribution program, net of costs	34	0
Distributions to Series A preferred units	-1	-2
Noncontrolling interest (distributions) contributions	-8	11
Contributions from previous parent	0	86
Net cash flows provided by financing activities	261	196
Net change in cash and cash equivalents	-6	-9
Cash and cash equivalents at beginning of period	19	53
Cash and cash equivalents at end of period	13	44
Supplemental cash flow information:	'	'
Accrued capital expenditures	24	62
Interest paid, net of amounts capitalized	29	18
Issuance of common units in connection with PVR and Hoover Acquisitions	4,015	0
Accrued capital contribution to unconsolidated affiliate	0	8
Long-term debt assumed in PVR Acquisition	$1,887	$0

Condensed_Consolidated_Stateme4

Condensed Consolidated Statement of Partners' Capital and Noncontrolling Interest (USD $)	Total	Common Units [Member]	Class F Units [Member]	General Partner Interest	Noncontrolling Interest
In Millions
Balance at Dec. 31, 2013	$4,916	$3,886	$146	$782	$102
Issuance of common units under equity distribution program, net of costs	34	34	0	0	0
Issuance of common units in connection with Hoover Acquisition	109	109	0	0	0
Issuance of common units in connection with PVR Acquisition	3,906	3,906	0	0	0
Unit-based compensation expenses	2	2	0	0	0
Partner distributions and distributions on unvested unit awards	-107	-103	0	-4	0
Noncontrolling interest distributions	-8	0	0	0	-8
Net income	12	2	2	5	3
Distributions to Series A Preferred Units	-1	-1	0	0	0
Balance at Mar. 31, 2014	$8,863	$7,835	$148	$783	$97

Organization_And_Summary_Of_Si

Organization And Summary Of Significant Accounting Policies (Notes)	3 Months Ended
	Mar. 31, 2014
Organization And Summary Of Significant Accounting Policies	'
Organization And Summary Of Significant Accounting Policies	'
	Organization and Summary of Significant Accounting Policies
	Organization. The unaudited condensed consolidated financial statements presented herein contain the results of Regency Energy Partners LP and its subsidiaries (the “Partnership”), a Delaware limited partnership. The Partnership and its subsidiaries are engaged in the business of gathering and processing, compression, treating and transportation of natural gas; the transportation, fractionation and storage of NGLs; the gathering, transportation and terminaling of oil (crude and/or condensate, a lighter oil) received from producers; and the management of coal and natural resource properties in the United States. Regency GP LP is the Partnership’s general partner and Regency GP LLC (collectively the “General Partner”) is the managing general partner of the Partnership and the general partner of Regency GP LP.
	SUGS Acquisition. On April 30, 2013, the Partnership and Regency Western acquired SUGS from Southern Union, a wholly-owned subsidiary of Holdco, for $1.5 billion (the “SUGS Acquisition”).
	The Partnership accounted for the acquisition in a manner similar to the pooling of interests method of accounting as it was a transaction between commonly controlled entities. The Partnership retrospectively adjusted its March 31, 2013 financial statements to include the operations of SUGS for periods prior to April 30, 2013. The SUGS Acquisition did not impact historical earnings per unit as pre-acquisition earnings were allocated to predecessor equity.
	The following table presents the revenues and net income for the previously separate entities and the combined amounts presented herein:
		Three Months Ended March 31, 2013
	Revenues:
	Partnership	$	349
	SUGS	191
	Combined	$	540
	Net loss:
	Partnership	$	(5	)
	SUGS	(24		)
	Combined	$	(29	)
	Basis of Presentation. The unaudited financial information included in this Form 10-Q has been prepared on the same basis as the audited consolidated financial statements included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2013. In the opinion of the Partnership’s management, such financial information reflects all adjustments necessary for a fair presentation of the financial position and the results of operations for such interim periods in accordance with GAAP. All inter-company items and transactions have been eliminated in consolidation. Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with GAAP have been omitted pursuant to the rules and regulations of the SEC.
	Use of Estimates. The unaudited condensed consolidated financial statements have been prepared in conformity with GAAP, which includes the use of estimates and assumptions made by management that affect the reported amounts of assets, liabilities, revenues, expenses and disclosure of contingent assets and liabilities that exist at the date of the condensed consolidated financial statements. Although these estimates are based on management’s available knowledge of current and expected future events, actual results could be different from those estimates.
	Equity Method Investments. Even though there is a presumption of a controlling financial interest in Aqua - PVR (because of our 51% ownership), our partner in this joint venture has substantive participating rights and management authority that preclude us from controlling the joint venture. Therefore, it is accounted for as an equity method investment.
	Coal Royalties Revenues and Deferred Income. The Partnership recognizes coal royalties revenues on the basis of tons of coal sold by its lessees and the corresponding revenues from those sales. The Partnership does not have access to actual production and revenues information until 30 days following the month of production. Therefore, financial results include estimated revenues and accounts receivable for the month of production. The Partnership records any differences between the actual amounts ultimately received or paid and the original estimates in the period they become finalized. Most lessees must make minimum monthly or annual payments that are generally recoverable over certain time periods. These minimum payments are recorded as deferred income. If the lessee recovers a minimum payment through production, the deferred income attributable to the minimum payment is recognized as coal royalties revenues. If a lessee fails to meet its minimum production for certain pre-determined time periods, the deferred income attributable to the minimum payment is recognized as minimum rental revenues, which is a component of other revenues on our consolidated statements of operations. Other liabilities on the balance sheet also include deferred unearned income from a coal services facility lease, which is recognized as other income as it is earned.

Partners_Capital_and_Distribut

Partners' Capital and Distributions (Notes)	3 Months Ended
	Mar. 31, 2014
Partners’ Capital and Distributions [Abstract]	'
Partners' Capital Notes Disclosure [Text Block]	'
	Partners’ Capital and Distributions
	Beneficial Conversion Feature. The beneficial conversion feature, incurred as a result of the issuance of Class F units, is reflected in income per unit using the effective yield method over the period the Class F units are outstanding, as indicated on the statement of operations in the line item entitled “beneficial conversion feature for Class F units.” The Class F units will convert to common units on a one-for-one basis on May 8, 2015.
	Equity Distribution Agreement. In June 2012, the Partnership entered into an equity distribution agreement with Citi under which the Partnership may offer and sell common units having an aggregate offering price of up to $200 million, from time to time through Citi, as sales agent for the Partnership. As of March 31, 2014, no amounts were available to be issued under this agreement. Sales of these units made from time to time under the equity distribution agreement were made by means of ordinary brokers’ transactions on the New York Stock Exchange at market prices, in block transactions, or as otherwise agreed upon by the Partnership and Citi. The Partnership used the net proceeds from the sale of these common units for general partnership purposes. During the three months ended March 31, 2014, the Partnership received net proceeds of $34 million from common units sold pursuant to this equity distribution agreement.
	Units Activity. The change in common and Class F units during the three months ended March 31, 2014 was as follows:
		Common		Class F
	Balance - December 31, 2013	210,850,232		6,274,483
	Issuance of common units under LTIP, net of forfeitures and tax withholding	10,126		—
	Issuance of common units under the equity distribution agreement	1,255,572		—
	Issuance of common units in connection with Hoover Acquisition	4,040,471		—
	Issuance of common units in connection with PVR Acquisition	140,388,382		—
	Balance - March 31, 2014	356,544,783		6,274,483
	Quarterly Distributions of Available Cash. Following are distributions declared by the Partnership subsequent to December 31, 2013:
	Quarter Ended		Record Date	Payment Date	Cash Distributions
					(per common unit)
	December 31, 2013		February 7, 2014	February 14, 2014	$0.48
	March 31, 2014		May 8, 2014	May 15, 2014	$0.48

Income_Loss_Per_Limited_Partne

Income (Loss) Per Limited Partner Unit	3 Months Ended
	Mar. 31, 2014
Earnings Per Share [Abstract]	'
Income (Loss) Per Limited Partner Unit	'
	Income (Loss) per Common Unit
	The following tables provide a reconciliation of the numerator and denominator of the basic and diluted earnings per common unit computations for the three months ended March 31, 2014 and 2013:
		Three Months Ended March 31,
		2014					2013
		Income		Units	Per-Unit		Loss			Units	Per-Unit
		(Numerator)		(Denominator)	Amount		(Numerator)			(Denominator)	Amount
	Basic income (loss) per unit
	Amount allocated to common units	$	1	226,046,232	$	0	$	(9	)	170,952,804	$	(0.06	)
	Effect of Dilutive Securities:
	Common unit options	—		22,787			—			—
	Phantom units	—		424,332			—			—
	Series A preferred units	—		2,054,217			—			—
	Diluted income (loss) per unit	$	1	228,547,568	$	0	$	(9	)	170,952,804	$	(0.06	)
	The following data show securities that could potentially dilute earnings per unit in the future that were not included in the computation of diluted earnings per unit because to do so would have been antidilutive for the periods presented:
		Three Months Ended March 31, 2013
	Common unit options	12,854
	Phantom units	267,820
	Series A preferred units	4,665,683

Acquisitions_Notes

Acquisitions (Notes)	3 Months Ended
	Mar. 31, 2014
Business Combinations [Abstract]	'
Mergers, Acquisitions and Dispositions Disclosures [Text Block]	'
	Acquisitions
	2014
	PVR Acquisition. On March 21, 2014, the Partnership acquired PVR for a total purchase price of $5.7 billion (based on the Partnership’s closing price of $27.82 per unit on March 21, 2014), including $1.8 billion principal amount of assumed debt (“PVR Acquisition”). PVR unitholders received (on a per unit basis) 1.02 Partnership common units and a one-time cash payment of $36.1 million, which was funded through borrowings under the Partnership’s revolving credit facility. The PVR Acquisition enhances the Partnership’s geographic diversity with a strategic presence in the Marcellus and Utica shales in the Appalachian Basin and the Granite Wash in the Mid-Continent region. The Partnership accounted for the PVR Acquisition using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their fair values as of the acquisition date. From March 21, 2014 through March 31, 2014, revenues and net income attributable to PVR’s operations of $37 million and $2 million, respectively, are included in the Partnership’s results of operations.
	Management’s evaluation of the assigned fair values is ongoing. The table below represents a preliminary allocation of the total purchase price:
		At March 21, 2014
	Current assets	$	150
	Property, plant and equipment	2,687
	Investment in unconsolidated affiliates	62
	Goodwill and intangible assets	3,079
	Total assets acquired	$	5,978
	Current liabilities	166
	Long-term debt	1,887
	Asset retirement obligations	3
	Net assets acquired	$	3,922
	Hoover Energy Acquisition. On February 3, 2014, the Partnership acquired certain subsidiaries of Hoover for a total purchase price of $293.2 million, consisting of (i) 4,040,471 common units issued to Hoover and (ii) $183.6 million in cash, and (iii) $2 million in asset retirement obligations assumed (the “Hoover Acquisition”). The Hoover Acquisition increases the Partnership’s fee-based revenue, expanding its existing footprint in the southern portion of the Delaware Basin in west Texas, and its services to producers into crude and water gathering. A portion of the consideration is being held in escrow as security for certain indemnification claims. The Partnership financed the cash portion of the purchase price through borrowings under its revolving credit facility. The Partnership accounted for the Hoover Acquisition using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their fair values as of the acquisition date. From February 3, 2014 through March 31, 2014, revenues and net income attributable to Hoover’s operations of $5 million and $2 million, respectively, are included in the Partnership’s results of operations.
	Management’s evaluation of the assigned fair values is ongoing. The table below represents a preliminary allocation of the total purchase price:
		At February 3, 2014
	Current assets	$	5
	Property, plant and equipment	114
	Goodwill and intangible assets	181
	Total assets acquired	$	300
	Current liabilities	5
	Asset retirement obligations	2
	Net assets acquired	$	293
	Pro Forma Results of Operations
	The following unaudited pro forma consolidated results of operations for the three months ended March 31, 2014 and 2013 are presented as if the PVR and Hoover acquisitions had been completed on January 1, 2013, and assumes there were no other changes in operations. This pro forma information does not necessarily reflect the actual results that would have occurred had the acquisitions occurred on January 1, 2013, nor is it indicative of future results of operations.
		Three Months Ended March 31,
		2014			2013
	Revenues	$	1,145		$	810
	Net loss attributable to the Partnership	(29		)	(60		)
	Basic net loss per Limited Partner unit	$	(0.10	)	$	(0.20	)
	Diluted net loss per Limited Partner unit	$	(0.10	)	$	(0.20	)
	The pro forma consolidated results of operations include adjustments to reflect incremental expenses associated with the fair value adjustments recorded as a result of applying the acquisition method of accounting and incremental interest expense related to the financing of a portion of the purchase price.
	The pro forma information is not necessarily indicative of the results of operations that would have occurred had the transactions been made at the beginning of the periods presented or the future results of the combined operations.
	Eagle Rock Acquisition. In December, 2013, the Partnership entered into an agreement to purchase Eagle Rock’s midstream business (the “Eagle Rock Midstream Acquisition”) for approximately $1.3 billion. This acquisition is expected to complement the Partnership’s core gathering and processing business and, when combined with the PVR Acquisition, is expected to further diversify the Partnership’s basin exposure in the Texas Panhandle, east Texas and south Texas. On April 29, 2014, Eagle Rock’s unitholders approved the Eagle Rock Midstream Acquisition. After receiving that approval, all significant closing conditions have been met with the exception of the Federal Trade Commission’s (“FTC”) antitrust approval. On April 30, 2014, the Partnership and Eagle Rock certified substantial compliance with the FTC in response to its Request for Additional Information and Documentary Material  regarding the Eagle Rock Midstream Acquisition.  In order to facilitate the FTC’s review, Eagle Rock and the Partnership have agreed with the FTC to not close the proposed transaction before June 30, 2014, unless the FTC first closes its investigation.

Investment_In_Unconsolidated_A

Investment In Unconsolidated Affiliates	3 Months Ended
	Mar. 31, 2014
Investment In Unconsolidated Subsidiaries [Abstract]	'
Investment In Unconsolidated Affiliates	'
	Investment in Unconsolidated Affiliates
	As of March 31, 2014, the Partnership has a 49.99% general partner interest in HPC, a 50% membership interest in MEP, a 30% membership interest in Lone Star, a 33.33% membership interest in Ranch JV, a 51% membership interest in Aqua - PVR, and a 50% interest in Coal Handling. The Partnership’s interest in the Aqua - PVR and Coal Handling joint ventures was acquired in the PVR Acquisition. The equity income received from the investments in Aqua - PVR and Coal Handling from March 21, 2014 (the acquisition date) to March 31, 2014 was not material. In March 2014, the Partnership entered into a settlement agreement, whereby the Partnership’s 50% interest in Grey Ranch was assigned to SandRidge Midstream, Inc., resulting in a cash settlement of $4 million and a loss of $1 million recorded to income from unconsolidated affiliates. The carrying value of the Partnership’s investment in each of the unconsolidated affiliates as of March 31, 2014 and December 31, 2013 is as follows:
		March 31, 2014			December 31, 2013
	HPC	$	439		$	442
	MEP	541			548
	Lone Star	1,097			1,070
	Ranch JV	38			36
	Aqua - PVR	51			—
	Coal Handling	12			—
	Grey Ranch	—			1
	Total	$	2,178		$	2,097
	The following tables summarize the Partnership’s investment activities in each of the unconsolidated affiliates for the three months ended March 31, 2014 and 2013:
		Three Months Ended March 31, 2014
		HPC			MEP			Lone Star			Ranch JV		Grey Ranch
	Contributions to unconsolidated affiliates	$	—		$	—		$	27		$	—	$	—
	Distributions from unconsolidated affiliates	(10		)	(18		)	(25		)	—		—
	Share of earnings of unconsolidated affiliates’ net income (loss)	7			11			25			2		(1		)
	Amortization of excess fair value of investment	(1		)	—			—			—		—
		Three Months Ended March 31, 2013
		HPC			MEP			Lone Star			Ranch JV
	Contributions to unconsolidated affiliates	$	—		$	—		$	27		$	1
	Distributions from unconsolidated affiliates	(16		)	(19		)	(17		)	—
	Share of earnings of unconsolidated affiliates’ net income	10			10			16			—
	Amortization of excess fair value of investment	(1		)	—			—			—
	The following tables present selected income statement data for each of the unconsolidated affiliates, on a 100% basis, for the three months ended March 31, 2014 and 2013:
		Three Months Ended March 31, 2014
		HPC			MEP			Lone Star			Ranch JV
	Total revenues	$	37		$	66		$	813		$	9
	Operating income	18			34			84			7
	Net income	15			21			83			6
		Three Months Ended March 31, 2013
		HPC			MEP			Lone Star			Ranch JV
	Total revenues	$	40		$	65		$	358		$	3
	Operating income	20			34			56			—
	Net income	20			21			55			—

Derivative_Instruments

Derivative Instruments	3 Months Ended
	Mar. 31, 2014
Derivative Instruments [Abstract]	'
Derivative Instruments	'
	Derivative Instruments
	Policies. The Partnership established comprehensive risk management policies and procedures to monitor and manage the market risks associated with commodity prices, counterparty credit and interest rates. The General Partner is responsible for delegation of transaction authority levels, and the Audit and Risk Committee of the General Partner is responsible for overseeing the management of these risks, including monitoring exposure limits. The Audit and Risk Committee receives regular briefings on exposures and overall risk management in the context of market activities.
	Commodity Price Risk. The Partnership is a net seller of NGLs, condensate and natural gas as a result of its gathering and processing operations. The prices of these commodities are impacted by changes in supply and demand as well as market forces. Both the Partnership’s profitability and cash flow are affected by the inherent volatility of these commodities which could adversely affect its ability to make distributions to its unitholders. The Partnership manages this commodity price exposure through an integrated strategy that includes management of its contract portfolio, matching sales prices of commodities with purchases, optimization of its portfolio by monitoring basis and other price differentials in operating areas, and the use of derivative contracts. In some cases, the Partnership may not be able to match pricing terms or cover its risk to price exposure with financial hedges, and it may be exposed to commodity price risk. Speculative positions with derivative contracts are prohibited under the Partnership’s policies.
	Interest Rate Risk. The Partnership is exposed to variable interest rate risk as a result of borrowings under its revolving credit facility. As of March 31, 2014, the Partnership had $606 million of outstanding borrowings exposed to variable interest rate risk.
	Credit Risk. The Partnership’s resale of NGLs, condensate and natural gas exposes it to credit risk, as the margin on any sale is generally a very small percentage of the total sales price. Therefore, a credit loss can be very large relative to overall profitability on these transactions. The Partnership attempts to ensure that it issues credit only to credit-worthy counterparties and that in appropriate circumstances any such extension of credit is backed by adequate collateral, such as a letter of credit or parental guarantee from a parent company with potentially better credit.
	The Partnership is exposed to credit risk from its derivative contract counterparties. The Partnership does not require collateral from these counterparties. The Partnership deals primarily with financial institutions when entering into financial derivatives, and utilizes master netting agreements that allow for netting of swap contract receivables and payables in the event of default by either party. If the Partnership’s counterparties failed to perform under existing swap contracts, the Partnership’s maximum loss as of March 31, 2014 would be $3 million, which would be reduced by $2 million, due to the netting features. The Partnership has elected to present assets and liabilities under master netting agreements gross on the condensed consolidated balance sheets.
	Embedded Derivatives. The Series A preferred units contain embedded derivatives which are required to be bifurcated and accounted for separately, such as the holders’ conversion option and the Partnership’s call option. These embedded derivatives are accounted for using mark-to-market accounting. The Partnership does not expect the embedded derivatives to affect its cash flows.
	The Partnership’s derivative assets and liabilities, including credit risk adjustments, as of March 31, 2014 and December 31, 2013 are detailed below:
		Assets						Liabilities
		March 31, 2014			December 31, 2013			March 31, 2014		December 31, 2013
	Derivatives not designated as cash flow hedges
	Current amounts
	Commodity contracts	$	2		$	3		$	11	$	9
	Long-term amounts
	Commodity contracts	1			1			—		—
	Embedded derivatives in Series A preferred units	—			—			20		19
	Total derivatives	$	3		$	4		$	31	$	28
	The Partnership’s statements of operations for the three months ended March 31, 2014 and 2013 were impacted by derivative instruments activities as follows:
				Three Months Ended March 31,
				2014			2013
	Derivatives not designated in a hedging relationship		Location of Gain/(Loss)	Amount of Gain/(Loss) Recognized
			Recognized in Income	in Income on Derivatives
	Commodity derivatives		Revenues	$	(13	)	$	(3	)
	Embedded derivatives in Series A preferred units		Other income &  deductions, net	(1		)	(14		)
				$	(14	)	$	(17	)

LongTerm_Debt

Long-Term Debt	3 Months Ended
	Mar. 31, 2014
Long-Term Debt Disclosure [Abstract]	'
Long-Term Debt	'
	Long-term Debt
	Obligations in the form of senior notes and borrowings under the revolving credit facility are as follows:
		March 31, 2014			December 31, 2013
	Senior notes	$	4,873		$	2,800
	Revolving loans	606			510
	Unamortized premium and discounts	85			—
	Long-term debt	$	5,564		$	3,310
	Availability under revolving credit facility:
	Total credit facility limit	$	1,500		$	1,200
	Revolving loans	(606		)	(510		)
	Letters of credit	(21		)	(14		)
	Total available	$	873		$	676
	Long-term debt maturities as of March 31, 2014 for each of the next five years are as follows:
	Years Ending December 31,		Amount
	2014 (remainder)		$	—
	2015		—
	2016		—
	2017		—
	2018		900
	Thereafter		4,579
	Total *		$	5,479
	*	Excludes a $99 million unamortized premium on the PVR senior notes assumed by the Partnership and a $14 million unamortized discount on the 2022 Notes.
	Revolving Credit Facility
	In February 2014, RGS entered into the First Amendment to the Sixth Amended and Restated Credit Agreement (as amended, the “Credit Agreement”) to, among other things, expressly permit the pending PVR and Eagle Rock Midstream acquisitions, and to increase the commitment to $1.5 billion and increase the uncommitted incremental facility to $500 million. The amendment specifically allows the Partnership to assume the series of PVR senior notes that mature prior to the Credit Agreement.
	The weighted average interest rate on the total amounts outstanding under the Partnership’s revolving credit facility was 2.41% as of March 31, 2014.
	Senior Notes
	In February 2014, the Partnership and Finance Corp. issued $900 million of senior notes that mature on March 1, 2022 (the “2022 Notes”). The 2022 Notes bear interest at 5.875% with interest payable semi-annual in arrears on September 1 and March 1. At any time prior to December 1, 2021, the Partnership may redeem some or all of the notes at 100% of the principal amount thereof, plus a “make-whole” redemption price and accrued and unpaid interest, if any, to the redemption date. On or after December 1, 2021, the Partnership may redeem some or all of the notes at a redemption price equal to 100% of the principal amount thereof, plus accrued and unpaid interest, if any, to the redemption date. If the Partnership undergoes certain change of control transactions, the Partnership may be required to offer to purchase the notes from holders. The 2022 Notes are guaranteed by the Partnership’s existing consolidated subsidiaries except Finance Corp and ELG. The 2022 Notes rank equally in right of payment with all of the Partnership’s existing and future senior unsecured debt, including the Partnership’s other outstanding Senior Notes, and contain the same covenants as the Partnership’s other existing Senior Notes.
	In March 2014, in connection with the PVR Acquisition, the Partnership assumed $1.2 billion in aggregate principal amount of PVR’s outstanding senior notes, consisting of $300 million of 8.25% senior notes that mature on April 15, 2018 (the “2018 PVR Notes”), $400 million of 6.5% senior notes that mature on May 15, 2021 (the “2021 PVR Notes”), and $473 million of 8.375% senior notes that mature on June 1, 2020 (the “2020 PVR Notes”). In April 2014, the Partnership redeemed all of the 2018 PVR Notes for $313 million at a price of 104.125% plus accrued and unpaid interest paid to the redemption date. Interest on the 2021 PVR Notes and the 2020 PVR Notes accrue semi-annually on May 15 and November 15 and June 1 and December 1, respectively.
	On March 24, 2014, in accordance with our obligations under the indentures governing the 2020 PVR Notes and the 2021 PVR Notes, we commenced change of control offers pursuant to which holders of such notes were entitled to require us to repurchase all or a portion of their notes at a purchase price of 101% of the principal amount thereof, plus accrued and unpaid interest to the repurchase date. The change of control offers for the 2020 PVR Notes and the 2021 PVR Notes expired on April 22, 2014 and, on April 23, 2014, we accepted for purchase less than one million in aggregate principal amount of 2021 PVR Notes.
	In April 2014, the Partnership and Finance Corp. commenced a private offer to eligible holders to exchange any and all outstanding 8.375% Senior Notes due 2019 (the “Eagle Rock Notes”) of Eagle Rock and Eagle Rock Energy Finance Corp., of which $550 million in aggregate principal amount is outstanding, for 8.375% Senior Notes due 2019 to be issued by the Partnership and Finance Corp. (the “New Partnership Notes”). The exchange of New Partnership Notes for the Eagle Rock Notes (the “Exchange Offer”) will be conducted on a par-for-par basis, and the New Partnership Notes will have substantially the same economic terms as the outstanding Eagle Rock Notes, including interest rate, interest payment dates, optional redemption terms and maturity. In addition, holders of Eagle Rock Notes accepted for exchange will receive a cash payment from Eagle Rock for accrued and unpaid interest on such notes from the last interest payment date to, but not including, the settlement date for the Exchange Offer. The New Partnership Notes will rank equally with the Partnership’s existing Senior Notes. This Exchange Offer is contingent upon the closing of the Eagle Rock Midstream Acquisition. On April 28, 2014, the Partnership extended the expiration date of the Exchange Offer to May 28, 2014, unless further extended or terminated.
	At March 31, 2014, the Partnership was in compliance with all material covenants under the indentures governing the Senior Notes.
	Finance Corp. has no operations and will not have revenues other than as may be incidental as co-issuer of the Senior Notes. Since the Senior Notes are fully and unconditionally guaranteed on a joint basis by its subsidiaries, except for minor subsidiaries, the Partnership has not included condensed consolidated financial information of the guarantors of the Senior Notes.

Commitments_And_Contingencies

Commitments And Contingencies	3 Months Ended
	Mar. 31, 2014
Commitments And Contingencies [Abstract]	'
Commitments And Contingencies	'
	Commitments and Contingencies
	Legal. The Partnership is involved in various claims, lawsuits and audits by taxing authorities incidental to its business. These claims and lawsuits in the aggregate are not expected to have a material adverse effect on the Partnership’s business, financial condition, results of operations or cash flows.
	PVR Shareholder Litigation. Five putative class action lawsuits challenging the PVR Acquisition are currently pending. All of the cases name PVR, PVR GP and the current directors of PVR GP, as well as the Partnership and the General Partner (collectively, the "Regency Defendants"), as defendants. Each of the lawsuits has been brought by a purported unitholder of PVR, both individually and on behalf of a putative class consisting of public unitholders of PVR. The lawsuits generally allege, among other things, that the directors of PVR GP breached their fiduciary duties to unitholders of PVR, that PVR GP, PVR and the Regency Defendants aided and abetted the directors of PVR GP in the alleged breach of these fiduciary duties, and, as to the actions in federal court, that some or all of PVR, PVR GP, and the directors of PVR GP violated Section 14(a) of the Exchange Act and Rule 14a-9 promulgated thereunder and Section 20(a) of the Exchange Act. The lawsuits purport to seek, in general, (i) injunctive relief, (ii) disclosure of certain additional information concerning the transaction, (iii) in the event the merger is consummated, rescission or an award of rescissory damages, (iv) an award of plaintiffs’ costs and (v) the accounting for damages allegedly causes by the defendants to these actions, and, (iv) such further relief as the court deems just and proper. The styles of the pending cases are as follows: David Naiditch v. PVR Partners, L.P., et al. (Case No. 9015-VCL) in the Court of Chancery of the State of Delaware); Charles Monatt v. PVR Partners, LP, et al. (Case No. 2013-10606) and Saul Srour v. PVR Partners, L.P., et al. (Case No. 2013-011015), each pending in the Court of Common Pleas for Delaware County, Pennsylvania; Stephen Bushansky v. PVR Partners, L.P., et al. (C.A. No. 2:13-cv-06829-HB); and Mark Hinnau v. PVR Partners, L.P., et al. (C.A. No. 2:13-cv-07496-HB), pending in the United States District Court for the Eastern District of Pennsylvania.
	On January 28, 2014, the defendants entered into a Memorandum of Understanding (“MOU”) with Monatt, Srour, Bushansky, Naiditch and Hinnau pursuant to which defendants and the referenced plaintiffs agreed in principle to a settlement of their lawsuits (“Settled Lawsuits”), which will be memorialized in a separate settlement agreement, subject to customary conditions, including consummation of the PVR Acquisition, which occurred on March 21, 2014, completion of certain confirmatory discovery, class certification and final approval by the Court of Common Pleas for Delaware County, Pennsylvania. If the Court approves the settlement, the Settled Lawsuits will be dismissed with prejudice and all defendants will be released from any and all claims relating to the Settled Lawsuits.
	The settlement will not affect any provisions of the merger agreement or the form or amount of consideration received by PVR unitholders in the PVR Acquisition. The defendants have denied and continue to deny any wrongdoing or liability with respect to the plaintiffs’ claims in the aforementioned litigation and have entered into the settlement to eliminate the uncertainty, burden, risk, expense, and distraction of further litigation.
	Utility Line Services, Inc. vs. PVR Marcellus Gas Gathering LLC.  On May 22, 2012, Plaintiff and Counterclaim Defendant, Utility Line Services, Inc. (“ULS”) filed suit against PVR Marcellus Gas Gathering, LLC now known as Regency Marcellus Gas Gathering LLC (“Regency Marcellus”) relating to a dispute involving payment under a construction contract (the “Construction Contract”) entered into in October 2010 for Regency Marcellus’ multi-phase pipeline construction project in Lycoming County, PA (the “Project”). Under the terms of the Construction Contract, Regency Marcellus believed ULS was obligated to design, permit and build Phases I and II of Regency Marcellus’ 30-inch pipeline and to design additional phases of the project. Due to ULS’ deficiencies and delays throughout the project, as well as extensive overbilling for its services, Regency Marcellus allowed the Construction Contract to terminate in accordance with its terms in December 2011 and refused to pay ULS’ outstanding invoices for the Project. ULS then filed suit alleging: Regency Marcellus’ refusal to pay certain invoices totaling approximately $17 million; penalties pursuant to the Pennsylvania Contractor and Subcontractor Payment Act, 73 P.S. § 501, et seq. (“CASPA”), Regency Marcellus’ alleged wrongful withholding of payments owed to ULS; and breach of contract in connection with Regency Marcellus’ alleged wrongful termination of ULS in December 2011. ULS alleged damages, inclusive of CASPA penalties, are in excess of $30 million. Regency Marcellus alleged counterclaims against ULS for breach of the parties’ contract for engineering and construction services; restitution for Regency Marcellus’ overpayments to ULS because of ULS’ improper billing practices; attorneys’ fees resulting from ULS’ meritless claim under CASPA; and professional malpractice against ULS for negligent performance of various engineering services on the Project. Regency Marcellus’ alleged damages exceed $21 million.
	Trial commenced on March 24, 2014 and on April 17, 2014, the jury found in favor of ULS and assessed damages against Regency Marcellus of approximately $24 million. In addition, the jury may order interest and attorneys’ fees against Regency Marcellus of approximately $10 million. The jury found against Regency Marcellus on its counterclaims. Regency Marcellus has filed appropriate post-trial pleadings and is considering its appeal options.
	EROC Shareholder Litigation. Two putative class action lawsuits challenging the Eagle Rock Midstream Acquisition are currently pending in federal district court in Houston, Texas. Both cases name Eagle Rock and its current directors, as well as the Partnership and a subsidiary (collectively, the "Regency Defendants"), as defendants. Each of the lawsuits has been brought by a purported unitholder of Eagle Rock (collectively, the “Plaintiffs”), both individually and on behalf of a putative class consisting of public unitholders of Eagle Rock. The Plaintiffs in each case seek to enjoin the transaction, claiming, among other things, that it yields inadequate consideration, was tainted by conflict and constitutes breaches of common law fiduciary duties or contractually imposed duties to the shareholders. The Partnership and its subsidiary are named as “aiders and abettors” of the allegedly wrongful actions of Eagle Rock and its board.
	Environmental. The Partnership is responsible for environmental remediation at certain sites on its gathering and processing systems, resulting primarily from releases of hydrocarbons. The Partnership’s remediation program typically involves the management of contaminated soils and may involve remediation of groundwater. Activities vary with site conditions and locations, the extent and nature of the contamination, remedial requirements and complexity. The ultimate liability and total costs associated with these sites will depend upon many factors.
	The table below reflects the environmental liabilities recorded at March 31, 2014 and December 31, 2013. Except as described above, the Partnership does not have any material environmental remediation matters assessed as reasonably possible that would require disclosure in the financial statements.
		March 31, 2014		December 31, 2013
	Current	$	2	$	2
	Noncurrent	8		6
	Total environmental liabilities	$	10	$	8
	The Partnership recorded less than $1 million in expenditures related to environmental remediation for the three months ended March 31, 2014.
	Endangered Species Act. In March 2014 the U.S. Fish & Wildlife Service listed the lesser prairie chicken as a “threatened” species under the federal Endangered Species Act. This species is predominantly located in the Partnership’s Permian and Midcontinent regions; therefore, the Partnership may encounter additional costs and delays in infrastructure development. The Partnership is participating, along with other companies in our industry, in a conservation plan for this species, which will allow the Partnership to participate in managing the related conservation efforts.
	Air Quality Control. The Partnership is currently negotiating settlements to certain enforcement actions by the NMED and the TCEQ. The TCEQ recently initiated a state-wide emissions inventory for the sulfur dioxide emissions from sites with reported emissions of 10 tons per year or more. If this data demonstrates that any source or group of sources may cause or contribute to a violation of the National Ambient Air Quality Standards, they must be sufficiently controlled to ensure timely attainment of the standard. This may potentially affect three recovery units in Texas. It is unclear at this time how the NMED will address the sulfur dioxide standard.
	Compliance Orders from the NMED. The Partnership has been in discussions with the NMED concerning allegations of violations of New Mexico air regulations related to the Jal #3 and Jal #4 facilities. Hearings on the compliance orders were delayed until June 2014 to allow the parties to pursue substantive settlement discussions. The Partnership has meritorious defenses to the NMED claims and can offer significant mitigating factors to the claimed violations. The Partnership has recorded a liability of less than $1 million related to the claims and will continue to assess its potential exposure to the allegations as the matters progress.
	CDM Sales Tax Audit. CDM Resource Management LLC (“CDM”), a subsidiary of the Partnership, has historically claimed the manufacturing exemption from sales tax in Texas, as is common in the industry. The exemption is based on the fact that CDM’s natural gas compression equipment is used in the process of treating natural gas for ultimate use and sale. In a recent audit by the Texas Comptroller’s office, the Comptroller has challenged the applicability of the manufacturing exemption to CDM. The period being audited is from August 2006 to August 2007, and liability for that period is potentially covered by an indemnity obligation from CDM’s prior owners. CDM may also have liability for periods since 2008, and prospectively, if the Comptroller’s challenge is ultimately successful. An audit of the 2008 period has commenced. In April 2013, an independent audit review agreed with the Comptroller’s position. While CDM continues to disagree with this position and intends to seek redetermination and other relief, we are unable to predict the final outcome of this matter.
	Mine Health and Safety Laws. There are numerous mine health and safety laws and regulations applicable to the coal mining industry. However, since we do not operate any mines and do not employ any coal miners, we are not subject to such laws and regulations. Accordingly, we have not accrued any related liabilities.
	In addition to the matters discussed above, the Partnership is involved in legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business.

Related_Party_Transactions

Related Party Transactions	3 Months Ended
	Mar. 31, 2014
Related Party Transactions [Abstract]	'
Related Party Transactions	'
	Related Party Transactions
	As of March 31, 2014 and December 31, 2013, details of the Partnership’s related party receivables and related party payables were as follows:
		March 31, 2014		December 31, 2013
	Related party receivables
	ETE and its subsidiaries	$	21	$	25
	HPC	2		1
	Ranch JV	1		2
	Total related party receivables	$	24	$	28
	Related party payables
	ETE and its subsidiaries	$	55	$	68
	HPC	1		1
	Ranch JV	1		—
	Total related party payables	$	57	$	69
	Transactions with ETE and its subsidiaries. Under the service agreement with Services Co., the Partnership paid Services Co.’s direct expenses for services performed, plus an annual fee of $10 million, and received the benefit of any cost savings recognized for these services. The service agreement has a five year term ending May 26, 2015, subject to earlier termination rights in the event of a change in control, the failure to achieve certain cost savings for the Partnership or upon an event of default. On April 30, 2013, this agreement was amended to provide for a waiver of the $10 million annual fee effective as of May 1, 2013 through and including April 30, 2015 and to clarify the scope and expenses chargeable as direct expenses thereunder.
	On April 30, 2013, the Partnership entered into the second amendment (the “Operation and Service Amendment”) to the Operation and Service Agreement (the “Operation and Service Agreement”), by and among the Partnership, ETC, the General Partner and RGS. Under the Operation and Service Agreement, ETC performs certain operations, maintenance and related services reasonably required to operate and maintain certain facilities owned by the Partnership, and the Partnership reimburses ETC for actual costs and expenses incurred in connection with the provision of these services based on an annual budget agreed upon by both parties. The Operation and Service Agreement Amendment describes the services that ETC will provide in the future.
	The Partnership incurred total service fees related to the agreements described above from ETE and its subsidiaries of $1 million and $4 million for the three months ended March 31, 2014 and 2013, respectively.
	In conjunction with distributions by the Partnership to the limited and general partner interests, ETE received cash distributions of $17 million and $15 million for the three months ended March 31, 2014 and 2013, respectively.
	The Partnership’s Contract Services segment provides contract compression and treating services to subsidiaries of ETE and records revenue in gathering, transportation and other fees. The Partnership’s Contract Services segment purchased compression equipment from a subsidiary of ETE for $9 million and $14 million during the three months ended March 31, 2014 and 2013, respectively.
	Transactions with Lone Star. In 2013, a subsidiary of the Partnership entered into a nineteen month agreement to sell 4,800 Bbls/d of NGLs to Lone Star. For the three months ended March 31, 2014, the Partnership had recorded $17 million in NGL sales under this contract which is included in the related party receivable from ETE and its subsidiaries.
	Transactions with Southern Union. Prior to April 30, 2013, Southern Union provided certain administrative services for SUGS that were either based on SUGS’s pro-rata share of combined net investment, margin and certain expenses or direct costs incurred by Southern Union on the behalf of SUGS. Southern Union also charged a management and royalty fee to SUGS for certain management support services provided by Southern Union on the behalf of SUGS and for the use of certain Southern Union trademarks, trade names and service marks by SUGS. These administrative services are no longer being provided subsequent to the SUGS Acquisition.
	Transactions with HPC. Under a Master Services Agreement with HPC, the Partnership operates and provides all employees and services for the operation and management of HPC. The related party general and administrative expenses reimbursed to the Partnership were $4 million and $5 million for the three months ended March 31, 2014 and 2013, respectively, which are recorded in gathering, transportation and other fees.
	The Partnership’s Contract Services segment provides compression services to HPC and records revenues in gathering, transportation and other fees. The Partnership also receives transportation services from HPC and records it as cost of sales.

Segment_Information

Segment Information	3 Months Ended
	Mar. 31, 2014
Segment Information [Abstract]	'
Segment Information	'
	Segment Information
	The Partnership has six reportable segments: Gathering and Processing, Natural Gas Transportation, NGL Services, Contract Services, Natural Resources and Corporate. The reportable segments are as described below:
	•	Gathering and Processing. The Partnership provides “wellhead-to-market” services to producers of natural gas, which include transporting raw natural gas from the wellhead through gathering systems, processing raw natural gas to separate NGLs from the raw natural gas and selling or delivering pipeline-quality natural gas and NGLs to various markets and pipeline systems, the gathering of oil (crude and/or condensate, a lighter oil) received from producers, and the gathering and disposing of salt water. This segment also includes ELG, which operates natural gas gathering, oil pipeline, and oil stabilization facilities in south Texas, the Partnership’s 33.33% membership interest in Ranch JV, which processes natural gas delivered from NGL-rich shale formations in west Texas, and the Partnership’s 51% interest in Aqua - PVR, which transports and supplies fresh water to natural gas producers in the Marcellus shale in Pennsylvania. The Partnership completed the SUGS Acquisition on April 30, 2013 which was a reorganization of entities under common control. Therefore, the Gathering and Processing segment amounts have been retrospectively adjusted to reflect the SUGS Acquisition for the three months ended March 31, 2013.
	•	Natural Gas Transportation. The Partnership owns a 49.99% general partner interest in HPC, which owns RIGS, a 450- mile intrastate pipeline that delivers natural gas from northwest Louisiana to downstream pipelines and markets, and a 50% membership interest in MEP, which owns a 500-mile interstate natural gas pipeline stretching from southeast Oklahoma through northeast Texas, northern Louisiana and central Mississippi to an interconnect with the Transcontinental Gas Pipe Line system in Butler, Alabama. This segment also includes Gulf States, which owns a 10-mile interstate pipeline that extends from Harrison County, Texas to Caddo Parish, Louisiana.
	•	NGL Services. The Partnership owns a 30% membership interest in Lone Star, an entity owning a diverse set of midstream energy assets including pipelines, storage, fractionation and processing facilities located in Texas, Mississippi and Louisiana.
	•	Contract Services. The Partnership owns and operates a fleet of compressors used to provide turn-key natural gas compression services for customer specific systems. The Partnership also owns and operates a fleet of equipment used to provide treating services, such as carbon dioxide and hydrogen sulfide removal, natural gas cooling, dehydration and BTU management.
	•	Natural Resources. The Partnership is involved in the management of coal and natural resources properties and the related collection of royalties. The Partnership also earns revenues from other land management activities, such as selling standing timber, leasing coal-related infrastructure facilities, and collecting oil and gas royalties. This segment also includes the Partnership’s 50% interest in Coal Handling, which owns and operates end-user coal handling facilities.
	•	Corporate. The Corporate segment comprises the Partnership’s corporate assets.
	The Partnership accounts for intersegment revenues as if the revenues were to third parties, exclusive of certain cost of capital charges.
	Management evaluates the performance of each segment and makes capital allocation decisions through the separate consideration of segment margin and operation and maintenance expenses. Segment margin for the Gathering and Processing and the Natural Gas Transportation segments is defined as total revenues, including service fees, less cost of sales. In the Contract Services segment, segment margin is defined as revenues less direct costs. The Natural Resources segment margin is generally equal to total revenues as there is typically minimal cost of sales associated with the management and leasing of properties.
	Management believes segment margin is an important measure because it directly relates to volume, commodity price changes and revenue generating horsepower. Operation and maintenance expenses are a separate measure used by management to evaluate performance of field operations. Direct labor, insurance, property taxes, repair and maintenance, utilities and contract services comprise the most significant portion of operation and maintenance expenses. These expenses fluctuate depending on the activities performed during a specific period. The Partnership does not deduct operation and maintenance expenses from total revenues in calculating segment margin because management separately evaluates commodity volume and price changes in segment margin. The Partnership does not record segment margin for its investments in unconsolidated affiliates (HPC, MEP, Lone Star, Ranch JV, Aqua - PVR, and Coal Handling) because it records its ownership percentages of their net income as income from unconsolidated affiliates in accordance with the equity method of accounting.
	Results for each segment are shown below:
		Three Months Ended March 31,
		2014			2013
	External Revenues
	Gathering and Processing	$	793		$	486
	Natural Gas Transportation	—			—
	NGL Services	—			—
	Contract Services	63			49
	Natural Resources	2			—
	Corporate	5			5
	Eliminations	—			—
	Total	$	863		$	540
	Intersegment Revenues
	Gathering and Processing	$	—		$	—
	Natural Gas Transportation	—			—
	NGL Services	—			—
	Contract Services	4			3
	Natural Resources	—			—
	Corporate	—			—
	Eliminations	(4		)	(3		)
	Total	$	—		$	—
	Segment Margin
	Gathering and Processing	$	166		$	104
	Natural Gas Transportation	—			—
	NGL Services	—			—
	Contract Services	56			47
	Natural Resources	2			—
	Corporate	5			5
	Eliminations	(4		)	(3		)
	Total	$	225		$	153
	Operation and Maintenance
	Gathering and Processing	$	60		$	55
	Natural Gas Transportation	—			—
	NGL Services	—			—
	Contract Services	20			17
	Natural Resources	—			—
	Corporate	2			—
	Eliminations	(4		)	(3		)
	Total	$	78		$	69
	The table below provides a reconciliation of total segment margin to income (loss) before income taxes:
		Three Months Ended March 31,
		2014			2013
	Total segment margin	$	225		$	153
	Operation and maintenance	(78		)	(69		)
	General and administrative	(33		)	(33		)
	Gain (loss) on asset sales, net	2			(1		)
	Depreciation, depletion and amortization	(94		)	(65		)
	Income from unconsolidated affiliates	43			35
	Interest expense, net	(56		)	(37		)
	Other income and deductions, net	2			(14		)
	Income (loss) before income taxes	$	11		$	(31	)
	The tables below provide amounts reflected in the condensed consolidated balance sheets for each segment:
Total Assets	March 31, 2014			December 31, 2013
Gathering and Processing	$	10,493		$	4,748
Natural Gas Transportation	982			991
NGL Services	1,097			1,070
Contract Services	1,953			1,897
Natural Resources	560			—
Corporate	112			76
Total	$	15,197		$	8,782
Investment in Unconsolidated Affiliates	March 31, 2014			December 31, 2013
Gathering and Processing	$	89		$	36
Natural Gas Transportation	980			991
NGL Services	1,097			1,070
Natural Resources	12			—
Total	$	2,178		$	2,097

EquityBased_Compensation

Equity-Based Compensation	3 Months Ended
	Mar. 31, 2014
Equity-Based Compensation [Abstract]	'
Equity-Based Compensation	'
	Equity-Based Compensation
	The Partnership’s LTIP for its employees, directors and consultants authorizes grants up to 5,865,584 common units. LTIP compensation expense of $2 million was recorded in general and administrative expense for the three months ended March 31, 2014 and 2013.
	Phantom Units. Phantom units granted during the period were service condition grants that (1) have graded vesting over five years or (2) vest over the next five years on a cliff basis; by vesting 60% at the end of the third year of service and vesting the remaining 40% at the end of the fifth year of service. Distributions related to the unvested phantom units are paid concurrent with the Partnership’s distribution for common units.
	The following table presents phantom units activity for the three months ended March 31, 2014:
	Phantom Units	Units		Weighted Average Grant
				Date Fair Value
	Outstanding at beginning of period	982,242		$	23.16
	Service condition grants	710,791		25.97
	Vested service condition	(1,126	)	24.19
	Forfeited service condition	(42,585	)	24.64
	Outstanding at end of period	1,649,322		$	24.33
	The Partnership expects to recognize $33 million of compensation expense related to non-vested phantom units over a weighted-average period of 3.9 years.

Fair_Value_Measures

Fair Value Measures	3 Months Ended
	Mar. 31, 2014
Fair Value Measures [Abstract]	'
Fair Value Measures	'
	Fair Value Measures
	The Partnership’s financial assets and liabilities measured at fair value on a recurring basis are derivatives related to commodity swaps and embedded derivatives in the Series A preferred units. Derivatives related to commodity swaps are valued using discounted cash flow techniques. These techniques incorporate Level 1 and Level 2 inputs such as commodity prices. These market inputs are utilized in the discounted cash flow calculation considering the instrument’s term, notional amount, discount rate and credit risk and are classified as Level 2 in the hierarchy. Embedded derivatives related to Series A preferred units are valued using a binomial lattice model. The inputs utilized in the model include credit spread, probabilities of the occurrence of certain events, common unit price, dividend yield, and expected volatility, and are classified as Level 3 in the hierarchy.
	The following table presents the Partnership’s derivative assets and liabilities measured at fair value on a recurring basis:
		Fair Value Measurements at March 31, 2014							Fair Value Measurements at December 31, 2013
		Fair Value Total			Significant		Unobservable		Fair Value Total		Significant		Unobservable
					Observable		Inputs				Observable		Inputs
					Inputs		(Level 3)				Inputs		(Level 3)
					(Level 2)						(Level 2)
	Assets
	Commodity Derivatives:
	Natural Gas	$	—		$	—	$	—	$	2	$	2	$	—
	NGLs	3			3		—		2		2		—
	Total Assets	$	3		$	3	$	—	$	4	$	4	$	—
	Liabilities
	Commodity Derivatives:
	Natural Gas	$	8		$	8	$	—	$	4	$	4	$	—
	NGLs	1			1		—		4		4		—
	Condensate	2			2		—		1		1		—
	Embedded derivatives in Series A preferred units	20			—		20		19		—		19
	Total Liabilities	$	31		$	11	$	20	$	28	$	9	$	19
	The following table presents the material unobservable inputs used to estimate the fair value of the embedded derivatives in the Series A preferred units:
	Unobservable Input		March 31, 2014
	Credit Spread		4.15	%
	Volatility		22.55	%
	Changes in the Partnership’s cost of equity and U.S. Treasury yields would cause a change in the credit spread used to value the embedded derivatives. Changes in the Partnership’s historical unit price volatility would cause a change in the volatility used to value the embedded derivatives.
	The following table presents the changes in Level 3 derivatives measured on a recurring basis for the three months ended March 31, 2014. There were no transfers between the fair value hierarchy levels for the three months ended March 31, 2014.
		Embedded Derivatives in Series A Preferred Units
	Net liability balance at December 31, 2013	$	19
	Change in fair value	1
	Net liability balance at March 31, 2014	$	20
	The carrying amount of cash and cash equivalents, accounts receivable and accounts payable approximates fair value due to their short-term maturities. Long-term debt, other than the Senior Notes, is comprised of borrowings under which interest accrues under a floating interest rate structure. Accordingly, the carrying value approximates fair value.
	The aggregate fair value and carrying amount of the Senior Notes at March 31, 2014 were $5.1 billion and $4.87 billion, respectively. As of December 31, 2013, the aggregate fair value and carrying amount of the Senior Notes were $2.83 billion and $2.80 billion, respectively. The fair value of the Senior Notes is a Level 1 valuation based on third party market value quotations.

Organization_And_Summary_Of_Si1

Organization And Summary Of Significant Accounting Policies (Policy)	3 Months Ended
	Mar. 31, 2014
Organization And Summary Of Significant Accounting Policies	'
Organization And Basis Of Presentation	'
	Organization. The unaudited condensed consolidated financial statements presented herein contain the results of Regency Energy Partners LP and its subsidiaries (the “Partnership”), a Delaware limited partnership. The Partnership and its subsidiaries are engaged in the business of gathering and processing, compression, treating and transportation of natural gas; the transportation, fractionation and storage of NGLs; the gathering, transportation and terminaling of oil (crude and/or condensate, a lighter oil) received from producers; and the management of coal and natural resource properties in the United States. Regency GP LP is the Partnership’s general partner and Regency GP LLC (collectively the “General Partner”) is the managing general partner of the Partnership and the general partner of Regency GP LP.
Basis of Presentation and Significant Accounting Policies [Text Block]	'
	Basis of Presentation. The unaudited financial information included in this Form 10-Q has been prepared on the same basis as the audited consolidated financial statements included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2013. In the opinion of the Partnership’s management, such financial information reflects all adjustments necessary for a fair presentation of the financial position and the results of operations for such interim periods in accordance with GAAP. All inter-company items and transactions have been eliminated in consolidation. Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with GAAP have been omitted pursuant to the rules and regulations of the SEC.
Use Of Estimates	'
	Use of Estimates. The unaudited condensed consolidated financial statements have been prepared in conformity with GAAP, which includes the use of estimates and assumptions made by management that affect the reported amounts of assets, liabilities, revenues, expenses and disclosure of contingent assets and liabilities that exist at the date of the condensed consolidated financial statements. Although these estimates are based on management’s available knowledge of current and expected future events, actual results could be different from those estimates.
Equity Method Investments, Policy [Policy Text Block]	'
	Equity Method Investments. Even though there is a presumption of a controlling financial interest in Aqua - PVR (because of our 51% ownership), our partner in this joint venture has substantive participating rights and management authority that preclude us from controlling the joint venture. Therefore, it is accounted for as an equity method investment.
Revenue Recognition, Services, Royalty Fees [Policy Text Block]	'
	Coal Royalties Revenues and Deferred Income. The Partnership recognizes coal royalties revenues on the basis of tons of coal sold by its lessees and the corresponding revenues from those sales. The Partnership does not have access to actual production and revenues information until 30 days following the month of production. Therefore, financial results include estimated revenues and accounts receivable for the month of production. The Partnership records any differences between the actual amounts ultimately received or paid and the original estimates in the period they become finalized. Most lessees must make minimum monthly or annual payments that are generally recoverable over certain time periods. These minimum payments are recorded as deferred income. If the lessee recovers a minimum payment through production, the deferred income attributable to the minimum payment is recognized as coal royalties revenues. If a lessee fails to meet its minimum production for certain pre-determined time periods, the deferred income attributable to the minimum payment is recognized as minimum rental revenues, which is a component of other revenues on our consolidated statements of operations. Other liabilities on the balance sheet also include deferred unearned income from a coal services facility lease, which is recognized as other income as it is earned.

Organization_And_Summary_Of_Si2

Organization And Summary Of Significant Accounting Policies (Tables)	3 Months Ended
	Mar. 31, 2014
Organization And Summary Of Significant Accounting Policies	'
Revenue by Combined Entity [Table Text Block]	'
	The following table presents the revenues and net income for the previously separate entities and the combined amounts presented herein:
		Three Months Ended March 31, 2013
	Revenues:
	Partnership	$	349
	SUGS	191
	Combined	$	540
	Net loss:
	Partnership	$	(5	)
	SUGS	(24		)
	Combined	$	(29	)

Partners_Capital_and_Distribut1

Partners' Capital and Distributions (Tables)	3 Months Ended
	Mar. 31, 2014
Partners’ Capital and Distributions [Abstract]	'
Schedule of Stockholders Equity [Table Text Block]	'
	The change in common and Class F units during the three months ended March 31, 2014 was as follows:
		Common		Class F
	Balance - December 31, 2013	210,850,232		6,274,483
	Issuance of common units under LTIP, net of forfeitures and tax withholding	10,126		—
	Issuance of common units under the equity distribution agreement	1,255,572		—
	Issuance of common units in connection with Hoover Acquisition	4,040,471		—
	Issuance of common units in connection with PVR Acquisition	140,388,382		—
	Balance - March 31, 2014	356,544,783		6,274,483
Schedule of Distributions Made to Members or Limited Partners, by Distribution [Table Text Block]	'
	Following are distributions declared by the Partnership subsequent to December 31, 2013:
	Quarter Ended		Record Date	Payment Date	Cash Distributions
					(per common unit)
	December 31, 2013		February 7, 2014	February 14, 2014	$0.48
	March 31, 2014		May 8, 2014	May 15, 2014	$0.48

Income_Loss_Per_Limited_Partne1

Income (Loss) Per Limited Partner Unit (Tables)	3 Months Ended
	Mar. 31, 2014
Earnings Per Share [Abstract]	'
Basic And Diluted Income (Loss) From Continuing Operations	'
	The following tables provide a reconciliation of the numerator and denominator of the basic and diluted earnings per common unit computations for the three months ended March 31, 2014 and 2013:
		Three Months Ended March 31,
		2014					2013
		Income		Units	Per-Unit		Loss			Units	Per-Unit
		(Numerator)		(Denominator)	Amount		(Numerator)			(Denominator)	Amount
	Basic income (loss) per unit
	Amount allocated to common units	$	1	226,046,232	$	0	$	(9	)	170,952,804	$	(0.06	)
	Effect of Dilutive Securities:
	Common unit options	—		22,787			—			—
	Phantom units	—		424,332			—			—
	Series A preferred units	—		2,054,217			—			—
	Diluted income (loss) per unit	$	1	228,547,568	$	0	$	(9	)	170,952,804	$	(0.06	)
Weighted Average Outstanding Amount Of Securities	'
	The following data show securities that could potentially dilute earnings per unit in the future that were not included in the computation of diluted earnings per unit because to do so would have been antidilutive for the periods presented:
		Three Months Ended March 31, 2013
	Common unit options	12,854
	Phantom units	267,820
	Series A preferred units	4,665,683

Acquisitions_Tables

Acquisitions (Tables)	3 Months Ended
	Mar. 31, 2014
Business Acquisition, Pro Forma Information [Table Text Block]	'
	The following unaudited pro forma consolidated results of operations for the three months ended March 31, 2014 and 2013 are presented as if the PVR and Hoover acquisitions had been completed on January 1, 2013, and assumes there were no other changes in operations. This pro forma information does not necessarily reflect the actual results that would have occurred had the acquisitions occurred on January 1, 2013, nor is it indicative of future results of operations.
		Three Months Ended March 31,
		2014			2013
	Revenues	$	1,145		$	810
	Net loss attributable to the Partnership	(29		)	(60		)
	Basic net loss per Limited Partner unit	$	(0.10	)	$	(0.20	)
	Diluted net loss per Limited Partner unit	$	(0.10	)	$	(0.20	)
PVR [Member]	'
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed [Table Text Block]	'
	Management’s evaluation of the assigned fair values is ongoing. The table below represents a preliminary allocation of the total purchase price:
		At March 21, 2014
	Current assets	$	150
	Property, plant and equipment	2,687
	Investment in unconsolidated affiliates	62
	Goodwill and intangible assets	3,079
	Total assets acquired	$	5,978
	Current liabilities	166
	Long-term debt	1,887
	Asset retirement obligations	3
	Net assets acquired	$	3,922
Hoover Energy [Member]	'
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed [Table Text Block]	'
	Management’s evaluation of the assigned fair values is ongoing. The table below represents a preliminary allocation of the total purchase price:
		At February 3, 2014
	Current assets	$	5
	Property, plant and equipment	114
	Goodwill and intangible assets	181
	Total assets acquired	$	300
	Current liabilities	5
	Asset retirement obligations	2
	Net assets acquired	$	293

Investment_In_Unconsolidated_A1

Investment In Unconsolidated Affiliates (Tables)	3 Months Ended
	Mar. 31, 2014
Carrying value of limited and general partnership interest	'
	The carrying value of the Partnership’s investment in each of the unconsolidated affiliates as of March 31, 2014 and December 31, 2013 is as follows:
		March 31, 2014			December 31, 2013
	HPC	$	439		$	442
	MEP	541			548
	Lone Star	1,097			1,070
	Ranch JV	38			36
	Aqua - PVR	51			—
	Coal Handling	12			—
	Grey Ranch	—			1
	Total	$	2,178		$	2,097
Changes In The Partnership's Investment	'
	The following tables summarize the Partnership’s investment activities in each of the unconsolidated affiliates for the three months ended March 31, 2014 and 2013:
		Three Months Ended March 31, 2014
		HPC			MEP			Lone Star			Ranch JV		Grey Ranch
	Contributions to unconsolidated affiliates	$	—		$	—		$	27		$	—	$	—
	Distributions from unconsolidated affiliates	(10		)	(18		)	(25		)	—		—
	Share of earnings of unconsolidated affiliates’ net income (loss)	7			11			25			2		(1		)
	Amortization of excess fair value of investment	(1		)	—			—			—		—
		Three Months Ended March 31, 2013
		HPC			MEP			Lone Star			Ranch JV
	Contributions to unconsolidated affiliates	$	—		$	—		$	27		$	1
	Distributions from unconsolidated affiliates	(16		)	(19		)	(17		)	—
	Share of earnings of unconsolidated affiliates’ net income	10			10			16			—
	Amortization of excess fair value of investment	(1		)	—			—			—
Condensed Consolidated Income Statements	'
	The following tables present selected income statement data for each of the unconsolidated affiliates, on a 100% basis, for the three months ended March 31, 2014 and 2013:
		Three Months Ended March 31, 2014
		HPC			MEP			Lone Star			Ranch JV
	Total revenues	$	37		$	66		$	813		$	9
	Operating income	18			34			84			7
	Net income	15			21			83			6
		Three Months Ended March 31, 2013
		HPC			MEP			Lone Star			Ranch JV
	Total revenues	$	40		$	65		$	358		$	3
	Operating income	20			34			56			—
	Net income	20			21			55			—

Derivative_Instruments_Tables

Derivative Instruments (Tables)	3 Months Ended
	Mar. 31, 2014
Derivative Instruments [Abstract]	'
Schedule Of Derivative Assets And Liabilities Statement	'
	The Partnership’s derivative assets and liabilities, including credit risk adjustments, as of March 31, 2014 and December 31, 2013 are detailed below:
		Assets						Liabilities
		March 31, 2014			December 31, 2013			March 31, 2014		December 31, 2013
	Derivatives not designated as cash flow hedges
	Current amounts
	Commodity contracts	$	2		$	3		$	11	$	9
	Long-term amounts
	Commodity contracts	1			1			—		—
	Embedded derivatives in Series A preferred units	—			—			20		19
	Total derivatives	$	3		$	4		$	31	$	28
Derivative Instruments, Gain (Loss) [Table Text Block]	'
	The Partnership’s statements of operations for the three months ended March 31, 2014 and 2013 were impacted by derivative instruments activities as follows:
				Three Months Ended March 31,
				2014			2013
	Derivatives not designated in a hedging relationship		Location of Gain/(Loss)	Amount of Gain/(Loss) Recognized
			Recognized in Income	in Income on Derivatives
	Commodity derivatives		Revenues	$	(13	)	$	(3	)
	Embedded derivatives in Series A preferred units		Other income &  deductions, net	(1		)	(14		)
				$	(14	)	$	(17	)

LongTerm_Debt_Tables

Long-Term Debt (Tables)	3 Months Ended
	Mar. 31, 2014
Long-Term Debt Disclosure [Abstract]	'
Partnership's Long-Term Debt	'
	Obligations in the form of senior notes and borrowings under the revolving credit facility are as follows:
		March 31, 2014			December 31, 2013
	Senior notes	$	4,873		$	2,800
	Revolving loans	606			510
	Unamortized premium and discounts	85			—
	Long-term debt	$	5,564		$	3,310
	Availability under revolving credit facility:
	Total credit facility limit	$	1,500		$	1,200
	Revolving loans	(606		)	(510		)
	Letters of credit	(21		)	(14		)
	Total available	$	873		$	676
Long-Term Debt Maturities	'
	Long-term debt maturities as of March 31, 2014 for each of the next five years are as follows:
	Years Ending December 31,		Amount
	2014 (remainder)		$	—
	2015		—
	2016		—
	2017		—
	2018		900
	Thereafter		4,579
	Total *		$	5,479
	*	Excludes a $99 million unamortized premium on the PVR senior notes assumed by the Partnership and a $14 million unamortized discount on the 2022 Notes.

Commitments_And_Contingencies_

Commitments And Contingencies (Tables)	3 Months Ended
	Mar. 31, 2014
Commitments and Contingencies Disclosure [Abstract]	'
Schedule of Accrued Liabilities [Table Text Block]	'
	The table below reflects the environmental liabilities recorded at March 31, 2014 and December 31, 2013. Except as described above, the Partnership does not have any material environmental remediation matters assessed as reasonably possible that would require disclosure in the financial statements.
		March 31, 2014		December 31, 2013
	Current	$	2	$	2
	Noncurrent	8		6
	Total environmental liabilities	$	10	$	8

Related_Party_Transactions_Tab

Related Party Transactions (Tables)	3 Months Ended
	Mar. 31, 2014
Related Party Transactions [Abstract]	'
Schedule of Related Party Transactions [Table Text Block]	'
	As of March 31, 2014 and December 31, 2013, details of the Partnership’s related party receivables and related party payables were as follows:
		March 31, 2014		December 31, 2013
	Related party receivables
	ETE and its subsidiaries	$	21	$	25
	HPC	2		1
	Ranch JV	1		2
	Total related party receivables	$	24	$	28
	Related party payables
	ETE and its subsidiaries	$	55	$	68
	HPC	1		1
	Ranch JV	1		—
	Total related party payables	$	57	$	69

Segment_Information_Tables

Segment Information (Tables)	3 Months Ended
	Mar. 31, 2014
Segment Information [Abstract]	'
Operating Results for Each Segment	'
	Results for each segment are shown below:
		Three Months Ended March 31,
		2014			2013
	External Revenues
	Gathering and Processing	$	793		$	486
	Natural Gas Transportation	—			—
	NGL Services	—			—
	Contract Services	63			49
	Natural Resources	2			—
	Corporate	5			5
	Eliminations	—			—
	Total	$	863		$	540
	Intersegment Revenues
	Gathering and Processing	$	—		$	—
	Natural Gas Transportation	—			—
	NGL Services	—			—
	Contract Services	4			3
	Natural Resources	—			—
	Corporate	—			—
	Eliminations	(4		)	(3		)
	Total	$	—		$	—
	Segment Margin
	Gathering and Processing	$	166		$	104
	Natural Gas Transportation	—			—
	NGL Services	—			—
	Contract Services	56			47
	Natural Resources	2			—
	Corporate	5			5
	Eliminations	(4		)	(3		)
	Total	$	225		$	153
	Operation and Maintenance
	Gathering and Processing	$	60		$	55
	Natural Gas Transportation	—			—
	NGL Services	—			—
	Contract Services	20			17
	Natural Resources	—			—
	Corporate	2			—
	Eliminations	(4		)	(3		)
	Total	$	78		$	69
Reconciliation of Total Segment Margin to Income (Loss) Before Income Taxes	'
	The table below provides a reconciliation of total segment margin to income (loss) before income taxes:
		Three Months Ended March 31,
		2014			2013
	Total segment margin	$	225		$	153
	Operation and maintenance	(78		)	(69		)
	General and administrative	(33		)	(33		)
	Gain (loss) on asset sales, net	2			(1		)
	Depreciation, depletion and amortization	(94		)	(65		)
	Income from unconsolidated affiliates	43			35
	Interest expense, net	(56		)	(37		)
	Other income and deductions, net	2			(14		)
	Income (loss) before income taxes	$	11		$	(31	)
Schedule Of Assets Related To Balance Sheet	'
	The tables below provide amounts reflected in the condensed consolidated balance sheets for each segment:
	Total Assets	March 31, 2014			December 31, 2013
	Gathering and Processing	$	10,493		$	4,748
	Natural Gas Transportation	982			991
	NGL Services	1,097			1,070
	Contract Services	1,953			1,897
	Natural Resources	560			—
	Corporate	112			76
	Total	$	15,197		$	8,782
	Investment in Unconsolidated Affiliates	March 31, 2014			December 31, 2013
	Gathering and Processing	$	89		$	36
	Natural Gas Transportation	980			991
	NGL Services	1,097			1,070
	Natural Resources	12			—
	Total	$	2,178		$	2,097

EquityBased_Compensation_Table

Equity-Based Compensation (Tables) (Phantom Units)	3 Months Ended
	Mar. 31, 2014
Phantom Units	'
Phantom Units Activity	'
	The following table presents phantom units activity for the three months ended March 31, 2014:
	Phantom Units	Units		Weighted Average Grant
				Date Fair Value
	Outstanding at beginning of period	982,242		$	23.16
	Service condition grants	710,791		25.97
	Vested service condition	(1,126	)	24.19
	Forfeited service condition	(42,585	)	24.64
	Outstanding at end of period	1,649,322		$	24.33

Fair_Value_Measures_Tables

Fair Value Measures (Tables)	3 Months Ended
	Mar. 31, 2014
Fair Value Measures [Abstract]	'
FV of Partnership's Derivative Assets and Liabilities	'
	The following table presents the Partnership’s derivative assets and liabilities measured at fair value on a recurring basis:
		Fair Value Measurements at March 31, 2014							Fair Value Measurements at December 31, 2013
		Fair Value Total			Significant		Unobservable		Fair Value Total		Significant		Unobservable
					Observable		Inputs				Observable		Inputs
					Inputs		(Level 3)				Inputs		(Level 3)
					(Level 2)						(Level 2)
	Assets
	Commodity Derivatives:
	Natural Gas	$	—		$	—	$	—	$	2	$	2	$	—
	NGLs	3			3		—		2		2		—
	Total Assets	$	3		$	3	$	—	$	4	$	4	$	—
	Liabilities
	Commodity Derivatives:
	Natural Gas	$	8		$	8	$	—	$	4	$	4	$	—
	NGLs	1			1		—		4		4		—
	Condensate	2			2		—		1		1		—
	Embedded derivatives in Series A preferred units	20			—		20		19		—		19
	Total Liabilities	$	31		$	11	$	20	$	28	$	9	$	19
Significant Unobservable Inputs for FV Estimation of Embedded Derivatives	'
	The following table presents the material unobservable inputs used to estimate the fair value of the embedded derivatives in the Series A preferred units:
	Unobservable Input		March 31, 2014
	Credit Spread		4.15	%
	Volatility		22.55	%
Valuation Changes in Level 3 Derivatives	'
	The following table presents the changes in Level 3 derivatives measured on a recurring basis for the three months ended March 31, 2014. There were no transfers between the fair value hierarchy levels for the three months ended March 31, 2014.
		Embedded Derivatives in Series A Preferred Units
	Net liability balance at December 31, 2013	$	19
	Change in fair value	1
	Net liability balance at March 31, 2014	$	20

Organization_And_Summary_Of_Si3

Organization And Summary Of Significant Accounting Policies Narrative (Details) (USD $)	Apr. 30, 2013
In Millions, unless otherwise specified
Organization, Consolidation and Presentation of Financial Statements [Abstract]	'
Business Acquisition, Cost of Acquired Entity, Purchase Price	$1,500

Organization_And_Summary_Of_Si4

Organization And Summary Of Significant Accounting Policies Combined Information (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Revenues	$863	$540
Net income (loss)	12	-29
Regency [Member]	'	'
Revenues	'	349
Net income (loss)	'	-5
SUGS [Member]	'	'
Revenues	'	191
Net income (loss)	'	-24
Combined [Member]	'	'
Revenues	'	540
Net income (loss)	'	($29)

Partners_Capital_and_Distribut2

Partners' Capital and Distributions Narrative (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014
Partners’ Capital and Distributions [Abstract]	'
Equity Distribution Agreement Maximum Aggregate Value Of Common Units Sold	$200
Stock Issued During Period, Shares, Issued for Cash	34
Remaining amount available to be issued under the Equity Distribution Agreement	$0

Partners_Capital_and_Distribut3

Partners' Capital and Distributions Unit Activity (Details)	3 Months Ended						3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2014	Mar. 31, 2014
			Common Units [Member]	Common Units [Member]	Class F Units [Member]	Class F Units [Member]	Hoover Energy [Member]	PVR [Member]
							Common Units [Member]	Common Units [Member]
Capital Unit [Line Items]	'	'	'	'	'	'	'	'
Limited Partners' Capital Account, Units Outstanding	'	'	356,544,783	210,850,232	6,274,483	6,274,483	'	'
Issuance of common units under LTIP, net of forfeitures and tax withholding	'	'	10,126	'	'	'	'	'
Issuance of common units under the equity distribution agreement	'	'	1,255,572	'	'	'	'	'
Issuance of common units in connection with acquisitions	6,274,483	0	'	'	'	'	4,040,471	140,388,382

Partners_Capital_and_Distribut4

Partners' Capital and Distributions Quarterly Distributions of Available Cash (Details) (USD $)	3 Months Ended
	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2013
Quarterly Distributions of Available Cash [Abstract]	'	'	'
Dividends Payable, Date of Record	8-May-14	7-Feb-14	'
Dividends Payable, Date of Payment	15-May-14	14-Feb-14	'
Distributions per common unit	$0.48	$0.48	$0.46

Income_Loss_Per_Limited_Partne2

Income (Loss) Per Limited Partner Unit Reconciliation of Numerator and Denominator of Basic and Diluted Earnings Per Common Unit (Details) (USD $)	3 Months Ended
In Millions, except Share data, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Net income (loss) allocated to limited partners	$1	($9)
Diluted income (loss) from continuing operations amount	1	-9
Weighted average number of common units outstanding	226,046,232	170,952,804
Diluted weighted number of units outstanding	228,547,568	170,952,804
Basic income (loss) per common unit	$0	($0.06)
Diluted income (loss) per common unit	$0	($0.06)
Common unit options [Member]	'	'
Income allocated to dilutive securities	0	0
Incremental common shares attributable to options	22,787	0
Phantom Units [Member]	'	'
Income allocated to dilutive securities	0	0
Incremental common shares attributable to phantom units	424,332	0
Series A preferred units [Member]	'	'
Income allocated to dilutive securities	$0	$0
Incremental common shares attributable to assumed conversion of Series A preferred units	2,054,217	0

Income_Loss_Per_Limited_Partne3

Income (Loss) Per Limited Partner Unit Antidilutive Securities Excluded from Computations of Earnings Per Unit (Details)	3 Months Ended
	Mar. 31, 2013
Common unit options [Member]	'
Antidilutive Securities Excluded from Computation of Earnings Per Share	'
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	12,854
Phantom Units [Member]	'
Antidilutive Securities Excluded from Computation of Earnings Per Share	'
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	267,820
Series A preferred units [Member]	'
Antidilutive Securities Excluded from Computation of Earnings Per Share	'
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	4,665,683

Acquisitions_Narrative_Details

Acquisitions Narrative (Details) (USD $)	3 Months Ended			2 Months Ended		0 Months Ended			2 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Apr. 30, 2013	Mar. 31, 2014	Feb. 03, 2014	Mar. 31, 2014	Mar. 21, 2014	Dec. 23, 2013	Mar. 31, 2014
				Hoover Energy [Member]	Hoover Energy [Member]	PVR [Member]	PVR [Member]	Eagle Rock [Member]	Private Common Unit Offering [Member]
									Hoover Energy [Member]
Business Acquisition, Transaction Costs	'	'	'	'	'	'	$36,100,000	'	'
Significant Acquisitions and Disposals, Acquisition Costs or Sale Proceeds	'	'	1,500,000,000	'	293,200,000	'	5,700,000,000	1,300,000,000	'
Partners' Capital Account, Units, Sold in Private Placement	'	'	'	'	'	'	'	'	4,040,471
Business Combination, Acquisition Related Costs	'	'	'	183,600,000	'	'	'	'	'
Asset Retirement Obligation	'	'	'	'	2,000,000	'	'	'	'
Revenues	863,000,000	540,000,000	'	5,000,000	'	37,000,000	'	'	'
Net Income (Loss) Attributable to Parent	9,000,000	-29,000,000	'	2,000,000	'	2,000,000	'	'	'
Business Acquisition, Share Price	'	'	'	'	'	'	$27.82	'	'
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Financial Liabilities	'	'	'	'	'	'	$1,800,000,000	'	'
Number of Share Received in Exchange of Each Share	'	'	'	'	'	'	1.02	'	'

Acquisitions_PVR_PPA_Table_Det

Acquisitions PVR PPA Table (Details) (PVR [Member], USD $)	Mar. 21, 2014
In Millions, unless otherwise specified
PVR [Member]	'
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets	$150
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment	2,687
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Other Noncurrent Assets	62
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Goodwill and Intangible Assets	3,079
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets	5,978
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities	166
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt	1,887
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Other	3
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net	$3,922

Acquisitions_Hoover_PPA_Detail

Acquisitions Hoover PPA (Details) (Hoover Energy [Member], USD $)	Feb. 03, 2014
In Millions, unless otherwise specified
Hoover Energy [Member]	'
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets	$5
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment	114
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Goodwill and Intangible Assets	181
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets	300
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities	5
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Other	2
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net	$293

Acquisitions_Pro_Forma_Results

Acquisitions Pro Forma Results of Operations Table (Details) (USD $)	3 Months Ended
In Millions, except Per Share data, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Business Combinations [Abstract]	'	'
Revenues	$1,145	$810
Net loss attributable to the Partnership	($29)	($60)
Basic net loss per Limited Partner unit	($0.10)	($0.20)
Diluted net loss per Limited Partner unit	($0.10)	($0.20)

Investment_In_Unconsolidated_A2

Investment In Unconsolidated Affiliates Narrative (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014
HPC [Member]	'
Ownership in affiliate	49.99%
MEP {Member]	'
Ownership in affiliate	50.00%
Lone Star {Member]	'
Ownership in affiliate	30.00%
Ranch JV {Member]	'
Ownership in affiliate	33.33%
Aqua - PVR [Member]	'
Ownership in affiliate	51.00%
Coal Handling [Member]	'
Ownership in affiliate	50.00%
Grey Ranch JV [Member]	'
Ownership in affiliate	50.00%
Equity Method Investment, Cash Settlement	$4
Gain (Loss) on Sale of Equity Investment	($1)

Investment_In_Unconsolidated_A3

Investment In Unconsolidated Affiliates Carrying Value of Unconsolidated Affiliates (Details) (USD $)	Mar. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Equity Method Investments	$2,178	$2,097
HPC [Member]	'	'
Equity Method Investments	439	442
MEP {Member]	'	'
Equity Method Investments	541	548
Lone Star {Member]	'	'
Equity Method Investments	1,097	1,070
Ranch JV {Member]	'	'
Equity Method Investments	38	36
Aqua - PVR [Member]	'	'
Equity Method Investments	51	0
Coal Handling [Member]	'	'
Equity Method Investments	12	0
Grey Ranch JV [Member]	'	'
Equity Method Investments	$0	$1

Investment_In_Unconsolidated_A4

Investment In Unconsolidated Affiliates Changes In Partnership's Investment (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Distributions from unconsolidated affiliates	$43	$36
Share of earnings of unconsolidated affiliates’ net income (loss)	43	35
HPC [Member]	'	'
Contributions to unconsolidated affiliates	0	0
Distributions from unconsolidated affiliates	-10	-16
Share of earnings of unconsolidated affiliates’ net income (loss)	7	10
Amortization of excess fair value of investment	-1	-1
MEP {Member]	'	'
Contributions to unconsolidated affiliates	0	0
Distributions from unconsolidated affiliates	-18	-19
Share of earnings of unconsolidated affiliates’ net income (loss)	11	10
Amortization of excess fair value of investment	0	0
Lone Star {Member]	'	'
Contributions to unconsolidated affiliates	27	27
Distributions from unconsolidated affiliates	-25	-17
Share of earnings of unconsolidated affiliates’ net income (loss)	25	16
Amortization of excess fair value of investment	0	0
Ranch JV {Member]	'	'
Contributions to unconsolidated affiliates	0	1
Distributions from unconsolidated affiliates	0	0
Share of earnings of unconsolidated affiliates’ net income (loss)	2	0
Amortization of excess fair value of investment	0	0
Grey Ranch JV [Member]	'	'
Contributions to unconsolidated affiliates	0	'
Distributions from unconsolidated affiliates	0	'
Share of earnings of unconsolidated affiliates’ net income (loss)	-1	'
Amortization of excess fair value of investment	$0	'

Investment_In_Unconsolidated_A5

Investment In Unconsolidated Affiliates Selected I/S Data for each of the Unconsolidated Affiliates (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
HPC [Member]	'	'
Equity method investments, total revenues	$37	$40
Equity method investments, operating income	18	20
Equity method investments, net income	15	20
MEP {Member]	'	'
Equity method investments, total revenues	66	65
Equity method investments, operating income	34	34
Equity method investments, net income	21	21
Lone Star {Member]	'	'
Equity method investments, total revenues	813	358
Equity method investments, operating income	84	56
Equity method investments, net income	83	55
Ranch JV {Member]	'	'
Equity method investments, total revenues	9	3
Equity method investments, operating income	7	0
Equity method investments, net income	$6	$0

Derivative_Instruments_Narrati

Derivative Instruments Narrative (Details) (USD $)	Mar. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Outstanding borrowings in interest rate risk	$606	$510
Maximum	'	'
Credit risk of derivatives	3	'
Reduction in credit risk of derivatives due to netting feature	$2	'

Derivative_Instruments_Schedul

Derivative Instruments Schedule Of Derivative Assets And Liabilities (Details) (USD $)	Mar. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Derivative Asset, Fair Value, Gross Asset	$3	$4
Derivative Liability, Noncurrent	20	19
Derivative Liability, Fair Value, Gross Liability	31	28
Current | Derivatives Not Designated as Cash Flow Hedges [Member] | Commodity Derivatives	'	'
Derivative Asset, Fair Value, Gross Asset	2	3
Derivative Liability, Fair Value, Gross Liability	11	9
Long Term | Derivatives Not Designated as Cash Flow Hedges [Member] | Commodity Derivatives	'	'
Derivative Asset, Fair Value, Gross Asset	1	1
Derivative Liability, Fair Value, Gross Liability	0	0
Long Term | Derivatives Not Designated as Cash Flow Hedges [Member] | Embedded Derivatives in Series A Preferred Units [Member]	'	'
Derivative Asset, Fair Value, Gross Asset	$0	$0

Derivative_Instruments_IS_Impa

Derivative Instruments I/S Impact of Derivative Instruments (Details) (Derivatives Not Designated In a Hedging Relationships, USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Derivative, Gain (Loss) on Derivative, Net	($14)	($17)
Commodity Derivatives | Revenues	'	'
Derivative, Gain (Loss) on Derivative, Net	-13	-3
Embedded Derivatives in Series A Preferred Units [Member] | Other Income and Deductions, Net	'	'
Derivative, Gain (Loss) on Derivative, Net	($1)	($14)

LongTerm_Debt_Narrative_Detail

Long-Term Debt Narrative (Details) (USD $)

Mar. 31, 2014

Dec. 31, 2013

Feb. 28, 2014

Mar. 31, 2014

Feb. 28, 2014

Apr. 24, 2014

Mar. 31, 2014

Mar. 25, 2014

Mar. 31, 2014

Mar. 25, 2014

Apr. 23, 2014

Mar. 31, 2014

Apr. 30, 2014

Feb. 28, 2014

Feb. 28, 2014

Revolving Credit Facility [Member]

Revolving Credit Facility [Member]

Senior Notes Due Two Thousand And Twenty Two [Member]

8.25% PVR Senior Notes Due Two Thousand Eighteen [Member]

8.25% PVR Senior Notes Due Two Thousand Eighteen [Member]

8.375% PVR Senior Notes Due Two Thousand Twenty [Member]

8.375% PVR Senior Notes Due Two Thousand Twenty [Member]

6.5% PVR Senior Notes Due Two Thousand Twenty One [Member]

6.5% PVR Senior Notes Due Two Thousand Twenty One [Member]

6.5% PVR Senior Notes Due Two Thousand Twenty One [Member]

8.375% Senior Notes Due Two Thousand Nineteen [Member]

Redemption Before December 1, 2021 [Member]

Redemption After December 1, 2021 [Member]

Senior Notes Due Two Thousand And Twenty Two [Member]

Senior Notes Due Two Thousand And Twenty Two [Member]

Revolving credit facility maximum allowable additional borrowings

$1,500,000,000

$1,200,000,000

$1,500,000,000

'

'

'

'

'

'

'

'

'

'

'

'

Line of Credit Facility, Additional Borrowing Capacity

'

'

500,000,000

'

'

'

'

'

'

'

'

'

'

'

'

Long-term debt weighted-average interest rate

'

'

'

2.41%

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Face Amount

'

'

'

'

900,000,000

'

300,000,000

'

473,000,000

'

'

400,000,000

550,000,000

'

'

Debt Instrument, Interest Rate, Stated Percentage

'

'

'

'

5.88%

'

8.25%

'

8.38%

'

'

6.50%

8.38%

'

'

Senior Note Redeemable Portion

'

'

'

'

'

'

'

'

'

'

'

'

'

100.00%

100.00%

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Acquiree's Senior Notes Assumed

1,200,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Extinguishment of Debt, Amount

'

'

'

'

'

313,000,000

'

'

'

'

'

'

'

'

'

Debt Instrument, Redemption Price, Percentage

'

'

'

'

'

104.13%

'

101.00%

'

101.00%

'

'

'

'

'

Debt Instrument Redemption Value

'

'

'

'

'

'

'

'

'

'

$0

'

'

'

'

LongTerm_Debt_Partnerships_Lon

Long-Term Debt Partnership's Long-Term Debt Schedule (Details) (USD $)	Mar. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Long-Term Debt Disclosure [Abstract]	'	'
Senior notes	$4,873	$2,800
Line of Credit Facility, Amount Outstanding	606	510
Unamortized premium and discounts	85	0
Long-term debt	5,564	3,310
Total credit facility limit	1,500	1,200
Availability under revolving loans	-606	-510
Letters of credit	-21	-14
Total available	$873	$676

LongTerm_Debt_LongTerm_Debt_Ma

Long-Term Debt Long-Term Debt Maturities Schedule (Details) (USD $)	Mar. 31, 2014
In Millions, unless otherwise specified
Long-Term Debt Disclosure [Abstract]	'
2014 (remainder)	$0
2015	0
2016	0
2017	0
2018	900
Thereafter	4,579
Total	5,479	[1]
Debt Instrument, Unamortized Premium	99
Debt Instrument, Unamortized Discount	$14
[1]	*Excludes a $99 million unamortized premium on the PVR senior notes assumed by the Partnership and a $14 million unamortized discount on the 2022 Notes.

Commitments_And_Contingencies_1

Commitments And Contingencies Narrative (Details) (USD $)	3 Months Ended	1 Months Ended	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014	Apr. 30, 2014	Mar. 31, 2014	Mar. 31, 2014	Apr. 17, 2014
		ULS [Member]	ULS [Member]	Regency Marcellus [Member]	Regency Marcellus [Member]
Disputed Amount in Litigation	'	'	'	$17	'
Loss Contingency, Damages Awarded, Value	'	24	'	'	'
Estimated Litigation Liability	'	'	'	'	10
Loss Contingency, Damages Sought, Value	'	'	30	21	'
Environmental Remediation Expense	0	'	'	'	'
Accrual for Environmental Loss Contingencies	$0	'	'	'	'

Commitments_And_Contingencies_2

Commitments And Contingencies Environmental Remediation Schedule (Details) (USD $)	Mar. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Commitments and Contingencies Disclosure [Abstract]	'	'
Accrued Environmental Loss Contingencies, Current	$2	$2
Accrued Environmental Loss Contingencies, Noncurrent	8	6
Accrual for Environmental Loss Contingencies	$10	$8

Related_Party_Transactions_Nar

Related Party Transactions Narrative (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Related Party Transaction, NGL Sales	$50	$25
General and administrative	33	33
ETE	'	'
Related Party Transaction, Expenses from Transactions with Related Party	1	4
Distribution Made to Limited Partner, Cash Distributions Paid	17	15
ETE | May Twenty Six Service Agreement	'	'
Management Fee, Amount Paid	10	'
ETP [Member]	'	'
Purchase of compression equipment	9	14
Lone Star {Member]	'	'
Related Party Transaction, NGL Sales, Quantity	4,800	'
Related Party Transaction, NGL Sales	17	'
HPC [Member]	'	'
General and administrative	$4	$5

Related_Party_Transactions_Rel

Related Party Transactions Related Party Receivables and Payables (Details) (USD $)	Mar. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Related Party Transaction [Line Items]	'	'
Related party receivables	$24	$28
Related party payables	57	69
ETE And Its Subsidiaries [Member]	'	'
Related Party Transaction [Line Items]	'	'
Related party receivables	21	25
Related party payables	55	68
HPC [Member]	'	'
Related Party Transaction [Line Items]	'	'
Related party receivables	2	1
Related party payables	1	1
Ranch JV {Member]	'	'
Related Party Transaction [Line Items]	'	'
Related party receivables	1	2
Related party payables	$1	$0

Segment_Information_Narrative_

Segment Information Narrative (Details)	Mar. 31, 2014
HPC [Member]	'
Total general partner interest	49.99%
MEP {Member]	'
Total general partner interest	50.00%
Lone Star {Member]	'
Total general partner interest	30.00%
Ranch JV {Member]	'
Total general partner interest	33.33%
Aqua - PVR [Member]	'
Total general partner interest	51.00%
Coal Handling [Member]	'
Total general partner interest	50.00%

Segment_Information_Operating_

Segment Information Operating Results for Each Segment (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
External Revenues	$863	$540
Intersegment Revenue	0	0
Segment Margin	225	153
Operation and maintenance	78	69
Gathering and Processing	'	'
External Revenues	793	486
Intersegment Revenue	0	0
Segment Margin	166	104
Operation and maintenance	60	55
Natural Gas Transportation	'	'
External Revenues	0	0
Intersegment Revenue	0	0
Segment Margin	0	0
Operation and maintenance	0	0
NGL Services	'	'
External Revenues	0	0
Intersegment Revenue	0	0
Segment Margin	0	0
Operation and maintenance	0	0
Contract Services	'	'
External Revenues	63	49
Intersegment Revenue	4	3
Segment Margin	56	47
Operation and maintenance	20	17
Natural Resources [Member]	'	'
External Revenues	2	0
Intersegment Revenue	0	0
Segment Margin	2	0
Operation and maintenance	0	0
Corporate	'	'
External Revenues	5	5
Intersegment Revenue	0	0
Segment Margin	5	5
Operation and maintenance	2	0
Eliminations	'	'
External Revenues	0	0
Intersegment Revenue	-4	-3
Segment Margin	-4	-3
Operation and maintenance	($4)	($3)

Segment_Information_Reconcilia

Segment Information Reconciliation of Total Segment Margin to Income (Loss) Before Income Taxes (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Segment Information [Abstract]	'	'
Total segment margin	$225	$153
Operation and maintenance	-78	-69
General and administrative	-33	-33
Gain (loss) on asset sales, net	2	-1
Depreciation, depletion and amortization	-94	-65
Income from unconsolidated affiliates	43	35
Interest expense, net	-56	-37
Other income and deductions, net	2	-14
INCOME (LOSS) BEFORE INCOME TAXES	$11	($31)

Segment_Information_Total_Segm

Segment Information Total Segment Assets (Details) (USD $)	Mar. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Segment Reporting Information	'	'
Total assets	$15,197	$8,782
Gathering and Processing	'	'
Segment Reporting Information	'	'
Total assets	10,493	4,748
Natural Gas Transportation	'	'
Segment Reporting Information	'	'
Total assets	982	991
NGL Services	'	'
Segment Reporting Information	'	'
Total assets	1,097	1,070
Contract Services	'	'
Segment Reporting Information	'	'
Total assets	1,953	1,897
Natural Resources	'	'
Segment Reporting Information	'	'
Total assets	560	0
Corporate	'	'
Segment Reporting Information	'	'
Total assets	$112	$76

Segment_Information_Investment

Segment Information Investment in Unconsolidated Affiliates (Details) (USD $)	Mar. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Segment Reporting Information	'	'
Investment in unconsolidated affiliates	$2,178	$2,097
Gathering and Processing	'	'
Segment Reporting Information	'	'
Investment in unconsolidated affiliates	89	36
Natural Gas Transportation	'	'
Segment Reporting Information	'	'
Investment in unconsolidated affiliates	980	991
NGL Services	'	'
Segment Reporting Information	'	'
Investment in unconsolidated affiliates	1,097	1,070
Natural Resources	'	'
Segment Reporting Information	'	'
Investment in unconsolidated affiliates	$12	$0

EquityBased_Compensation_Narra

Equity-Based Compensation Narrative (Details) (USD $)	3 Months Ended
In Millions, except Share data, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Equity-Based Compensation [Abstract]	'	'
Partnership's LTIP units	5,865,584	'
Share-based Compensation	$2	$2
Partnership expects to recognize compensation expense	$33	'
Non-vested phantom units period, in years	'3 years 11 months	'

EquityBased_Compensation_Phant

Equity-Based Compensation Phantom Units Activity (Details) (Phantom Units, USD $)	3 Months Ended
	Mar. 31, 2014
Phantom Units	'
Outstanding at the beginning of the period, Units	982,242
Service condition grants, Units	710,791
Vested service condition, Units	-1,126
Forfeited service condition, Units	-42,585
Outstanding at the end of period, Units	1,649,322
Outstanding at the beginning of the period, Weighted Average Grant Date Fair Value	$23.16
Service condition grants, Weighted Average Grant Date Fair Value	$25.97
Vested service condition, Weighted Average Grant Date Fair Value	$24.19
Forfeited service condition, Weighted Average Grant Date Fair Value	$24.64
Outstanding at the end of the period, Weighted Average Grant Date Fair Value	$24.33

Fair_Value_Measures_Narrative_

Fair Value Measures Narrative (Details) (USD $)	Mar. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Fair Value Measures [Abstract]	'	'
Debt Instrument, Fair Value Disclosure	$5,100	$2,830
Unsecured Long-term Debt, Noncurrent	$4,873	$2,800

Fair_Value_Measures_FV_of_Part

Fair Value Measures FV of Partnership's Derivative Assets And Liabilities (Details) (USD $)	Mar. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Fair Value Measurement, Assets	$3	$4
Fair Value Measurement, Liabilities	31	28
Significant Observable Inputs (Level 2)	'	'
Fair Value Measurement, Assets	3	4
Fair Value Measurement, Liabilities	11	9
Unobservable Inputs (Level 3)	'	'
Fair Value Measurement, Assets	0	0
Fair Value Measurement, Liabilities	20	19
Natural Gas Transportation	'	'
Fair Value Measurement, Assets	0	2
Fair Value Measurement, Liabilities	8	4
Natural Gas Transportation | Significant Observable Inputs (Level 2)	'	'
Fair Value Measurement, Assets	0	2
Fair Value Measurement, Liabilities	8	4
Natural Gas Transportation | Unobservable Inputs (Level 3)	'	'
Fair Value Measurement, Assets	0	0
Fair Value Measurement, Liabilities	0	0
NGLs	'	'
Fair Value Measurement, Assets	3	2
Fair Value Measurement, Liabilities	1	4
NGLs | Significant Observable Inputs (Level 2)	'	'
Fair Value Measurement, Assets	3	2
Fair Value Measurement, Liabilities	1	4
NGLs | Unobservable Inputs (Level 3)	'	'
Fair Value Measurement, Assets	0	0
Fair Value Measurement, Liabilities	0	0
Condensate	'	'
Fair Value Measurement, Liabilities	2	1
Condensate | Significant Observable Inputs (Level 2)	'	'
Fair Value Measurement, Liabilities	2	1
Condensate | Unobservable Inputs (Level 3)	'	'
Fair Value Measurement, Liabilities	0	0
Embedded Derivatives in Series A Preferred Units [Member]	'	'
Embedded Derivatives in Series A Preferred Units	20	19
Embedded Derivatives in Series A Preferred Units [Member] | Significant Observable Inputs (Level 2)	'	'
Embedded Derivatives in Series A Preferred Units	0	0
Embedded Derivatives in Series A Preferred Units [Member] | Unobservable Inputs (Level 3)	'	'
Embedded Derivatives in Series A Preferred Units	$20	$19

Fair_Value_Measures_Significan

Fair Value Measures Significant Unobservable Inputs for FV Estimation of Embedded Derivatives (Details)	Mar. 31, 2014
Fair Value Measures [Abstract]	'
Fair Value, Embedded Derivatives Significant Unobservable Input, Credit Spread	4.15%
Fair Value, Embedded Derivatives Significant Unobservable Input, Volatility	22.55%

Fair_Value_Measures_Valuation_

Fair Value Measures Valuation Changes in Level 3 Derivatives (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014
Fair Value Measures [Abstract]	'
Beginning balance	$19
Change in fair value	1
Ending balance	$20