Midcoast Energy Partners (MEP) 10-Q 20 Dec 13 2013 Q3 Quarterly report Financial data

Document_And_Entity_Informatio

Document And Entity Information	9 Months Ended
	Sep. 30, 2013	Dec. 20, 2013
Document and Entity Information [Abstract]	'	'
Document Type	'10-Q	'
Amendment Flag	'false	'
Document Period End Date	30-Sep-13	'
Document Fiscal Year Focus	'2013	'
Document Fiscal Period Focus	'Q3	'
Trading Symbol	'mep	'
Entity Registrant Name	'MIDCOAST ENERGY PARTNERS, L.P.	'
Entity Central Index Key	'0001578685	'
Current Fiscal Year End Date	'--12-31	'
Entity Filer Category	'Non-accelerated Filer	'
Entity Common Stock, Shares Outstanding	'	22,610,056
Entity Current Reporting Status	'No	'
Entity Shell Company	'No	'
Entity Interactive Data File	'Yes	'

Consolidated_Statements_Of_Inc

Consolidated Statements Of Income (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Operating revenue	$1,331.30	$1,143.10	$3,887.90	$3,600.30
Operating revenue - affiliate	49.6	77.8	162.4	317.2
Total revenue	1,380.90	1,220.90	4,050.30	3,917.50
Operating expenses	'	'	'	'
Cost of natural gas and natural gas liquids	1,244.30	1,038	3,553.40	3,322.50
Selling, General and Administrative Expense, Total	149.5	152.9	442.5	450.6
Operating and maintenance services	88.7	96.3	263.1	271.8
General and administrative services	25	22.3	73.1	77.7
Depreciation and amortization	35.8	34.3	106.3	101.1
Operating Expenses, Total	1,393.80	1,190.90	3,995.90	3,773.10
Operating income	-12.9	30	54.4	144.4
Interest expense, total	0	0	0	0
Other income (expense)	0	0	0.2	-0.1
Income before income tax expense	-12.9	30	54.6	144.3
Income tax expense	0.6	1.3	8.9	2.1
Net income	-13.5	28.7	45.7	142.2
Third Party [Member]	'	'	'	'
Operating expenses	'	'	'	'
Cost of natural gas and natural gas liquids	1,221.30	986.1	3,457.90	3,078.90
Operating and maintenance services	61.4	69.7	181.7	190.6
General and administrative services	0	-1.7	0.1	5.9
Affiliate [Member]	'	'	'	'
Operating expenses	'	'	'	'
Cost of natural gas and natural gas liquids	23	51.9	95.5	243.6
Selling, General and Administrative Expense, Total	52.3	50.6	154.4	153
Operating and maintenance services	27.3	26.6	81.4	81.2
General and administrative services	$25	$24	$73	$71.80

Consolidated_Statements_Of_Com

Consolidated Statements Of Comprehensive Income (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Consolidated Statements Of Comprehensive Income	'	'	'	'
Net income	($13.50)	$28.70	$45.70	$142.20
Other comprehensive income (loss), net of tax expense	-17	-22.7	-5.7	43.6
Comprehensive income	($30.50)	$6	$40	$185.80

Consolidated_Statements_Of_Com1

Consolidated Statements Of Comprehensive Income (Parenthetical) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Consolidated Statements Of Comprehensive Income	'	'	'	'
Tax expense (benefit) from other comprehensive income (loss)	($0.10)	($0.10)	$0	$0.20

Consolidated_Statements_Of_Cas

Consolidated Statements Of Cash Flows (USD $)	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012
Cash provided by operating activities	'	'
Net income	$45.70	$142.20
Adjustments to reconcile net income (loss) to net cash provided by operating activities:	'	'
Depreciation and amortization	106.3	101.1
Derivative fair value net gains	13.9	-7.9
Inventory market price adjustments	3.3	9.8
Deferred income taxes	7.5	0.3
Other	0.1	6.7
Changes in operating assets and liabilities, net of acquisitions:	'	'
Receivables, trade and other	-28.8	-25.9
Due from General Partner and affiliates	10.6	7.3
Accrued receivables	463.2	119.4
Inventory	-75.1	28.4
Current and long-term other assets	-7	-8.6
Due to General Partner and affiliates	-1.9	13.2
Accounts payable and other	-23.2	28.8
Accrued purchases	-97.5	-148.1
Property and other taxes payable	8.8	4.8
Net cash provided by operating activities	425.9	271.5
Cash used in investing activities	'	'
Additions to property, plant and equipment	-206.6	-315.1
Asset acquisitions	-0.9	0
Proceeds from sale of net assets	5	9.2
Investment in joint venture	-181.8	-81.7
Other	-2.2	-2.9
Net cash used in investing activities	-386.5	-390.5
Cash provided by financing activities	'	'
Contributions from partners	166.9	361
Distribution to partners	-206.3	-242
Net cash provided by (used in) financing activities	-39.4	119
Net increase (decrease) in cash and cash equivalents	0	0
Cash and cash equivalents at beginning of year	0	0
Cash and cash equivalents at end of period	$0	$0

Consolidated_Statements_Of_Fin

Consolidated Statements Of Financial Position (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Current assets	'	'
Cash and cash equivalents	$0	$0
Receivables, trade and other, net of allowance for doubtful accounts	54.8	26.2
Due from General Partner and affiliates	132.1	263.5
Accrued receivables	88	551.2
Inventory	144.6	74.8
Other current assets	28	32.5
Assets, Current, Total	447.5	948.2
Property, plant and equipment, net	4,058.30	3,963
Goodwill	226.5	226.5
Intangibles, net	251.6	257.2
Equity Investment in Joint Venture	365.5	183.7
Other assets, net	92	88.8
Total assets	5,441.40	5,667.40
Current liabilities	'	'
Due to General Partner and affiliates	37.5	41.3
Accounts payable and other	185.1	314.5
Accrued purchases	398.9	494.3
Property and other taxes payable	25.2	16.4
Distribution payable to EEP	0	0
Liabilities, Current, Total	646.7	866.5
LiabilitiesAbstract	'	'
Other long-term liabilities	79.9	86.7
Liabilities, Total	726.6	953.2
Commitments and contingencies	'	'
Partners' capital	'	'
Limited Partner interest	4,713.40	4,707.10
General Partner	0	0
Accumulated other comprehensive income (loss)	1.4	7.1
Total partners' capital	4,714.80	4,714.20
Liabilities and Stockholders' Equity, Total	$5,441.40	$5,667.40

Consolidated_Statements_Of_Fin1

Consolidated Statements Of Financial Position (Parenthetical) (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Receivables, trade and other, allowance for doubtful accounts	$1.10	$1.90

Basis_Of_Presentation

Basis Of Presentation	9 Months Ended
	Sep. 30, 2013
Organization And Nature Of Operations	'
Organization And Nature Of Operations	'
	1. ORGANIZATION AND NATURE OF OPERATIONS
	Initial Public Offering
	On November 13, 2013, Midcoast Energy Partners, L.P., or MEP, completed its initial public offering, or the Offering, of 18,500,000 Class A common units (2,775,000 additional Class A common units were issued pursuant to the exercise of the underwriters' over-allotment option on December 9, 2013), representing limited partner interests. MEP received proceeds (net of underwriting discounts, structuring fees and offering expenses) from the Offering of approximately $354.9 million. MEP used the net proceeds to distribute approximately $304.5 million to EEP, to pay approximately $3.4 million in revolving credit facility origination and commitment fees and used approximately $47.0 million to redeem 2,775,000 Class A common units from EEP. Unless the context otherwise requires, references in this report to the Predecessor, we, our, us, or like terms, when used in a historical context (periods prior to November 13, 2013), refer to Midcoast Operating, L.P. References in this report to Midcoast Energy Partners, the Partnership, we, our, us, or like terms used in the present tense or prospectively (periods beginning on November 13, 2013) refer to Midcoast Energy Partners, L.P. and its subsidiaries. Following the completion of the Offering, EEP continues to own crude oil and liquid petroleum assets and a 61% non-controlling interest in Midcoast Operating. EEP also retained a significant interest through its ownership of our general partner, a 52% limited partner interest, after the exercise of the over-allotment option, in us and all of our incentive distribution rights. The Class A common units began trading on November 7, 2013 on the New York Stock Exchange, or NYSE, under the ticker symbol MEP. For more information on the Offering refer to Note 11. Subsequent Events.
	General
	We own and operate a portfolio of assets engaged in the business of gathering, processing and treating natural gas, as well as the transportation and marketing of natural gas, natural gas liquids, or NGLs, crude oil and condensate. Our portfolio of natural gas and NGL pipelines, plants and related facilities are geographically concentrated in the Gulf Coast and Mid-Continent regions of the United States, primarily in Texas and Oklahoma. We also own and operate natural gas and NGL logistics and marketing assets that primarily support our gathering, processing and transportation business. We hold our assets in a series of limited partnerships and limited liability companies that we wholly own either directly or indirectly.
	Our capital accounts consist of general partner interests held by Midcoast OLP GP, L.L.C (f/k/a Enbridge Midcoast Holdings, L.L.C.), or the OLP GP, a wholly owned subsidiary of EEP, and limited partner interests held directly by EEP. At September 30, 2013 and December 31, 2012, our equity interests were distributed as follows:
			30-Sep-13		31-Dec-12
		Limited partner interests	99.999	%	99.999	%
		General partner interests	0.001	%	0.001	%
	Enbridge Energy Partners, L.P.
	EEP was formed in 1991 by Enbridge Energy Company, Inc., its general partner, an indirect, wholly owned subsidiary of Enbridge Inc., which we refer to as Enbridge, a leading energy transportation and distribution company located in Calgary, Alberta, Canada. EEP was formed to acquire, own and operate the crude oil and liquid petroleum transportation assets of Enbridge Energy, Limited Partnership, which owns the United States portion of a crude oil and liquid petroleum pipeline system extending from western Canada through the upper and lower Great Lakes region of the United States to eastern Canada.
	EEP is a publicly-traded Delaware limited partnership that owns and operates crude oil and liquid petroleum transportation and storage assets and, through its ownership interests in us, natural gas gathering, treating, processing, transmission and marketing assets in the United States. EEP's Class A common units are traded on the NYSE under the symbol EEP.
	Enbridge Energy Management, L.L.C.
	Enbridge Energy Management, L.L.C., which we refer to as Enbridge Management, is a Delaware limited liability company that was formed by Enbridge Energy Company, Inc. in May 2002. EEP's general partner, through its direct ownership of the voting shares of Enbridge Management, elects all of the directors of Enbridge Management. Enbridge Management's listed shares are traded on the NYSE under the symbol EEQ. Enbridge Management owns all of a special class of EEP's limited partner interests and derives all of its earnings from its investment in EEP.
	Enbridge Management's principal activity is managing the business and affairs of EEP pursuant to a delegation of control agreement among EEP's general partner, Enbridge Management and EEP. In accordance with its limited liability company agreement, Enbridge Management's activities are restricted to being a limited partner of EEP and managing its business and affairs.
	Enbridge Inc.
	Enbridge is the indirect parent of EEP's general partner, and its common shares are publicly traded on the NYSE in the United States and on the Toronto Stock Exchange in Canada, in each case, under the symbol ENB. Enbridge is a leader in energy transportation and distribution in North America, with a focus on crude oil and liquids pipelines, natural gas pipelines, natural gas distribution and renewable energy. At September 30, 2013 and December 31, 2012, Enbridge and its consolidated subsidiaries held an effective 20.6% and 21.8% interest in MEP, respectively, through its ownership in Enbridge Management and EEP's general partner.
	Basis of Presentation
	The accompanying unaudited interim consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States, or GAAP, for interim consolidated financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. Accordingly, they do not include all the information and footnotes required by GAAP for complete consolidated financial statements. In the opinion of management, they contain all adjustments, consisting only of normal recurring adjustments, which management considers necessary to present fairly our financial position as of September 30, 2013, our results of operations for the three and nine month periods ended September 30, 2013 and 2012 and our cash flows for the nine month periods ended September 30, 2013 and 2012. We derived our consolidated statement of financial position as of December 31, 2012 from the audited financial statements included in our prospectus related to the Offering of the Partnership dated November 6, 2013, as filed with the SEC on November 8, 2013, or the Prospectus. Our results of operations for the three and nine month periods ended September 30, 2013 should not be taken as indicative of the results to be expected for the full year due to seasonal fluctuations in the supply of and demand for natural gas, NGLs and crude oil, timing and completion of our construction projects, maintenance activities, the impact of forward commodity prices and differentials on derivative financial instruments that are accounted for at fair value. These interim consolidated financial statements should be read in conjunction with the audited consolidated financial statements and accompanying footnotes in the Prospectus.

Cash_And_Cash_Equivalents

Cash And Cash Equivalents	9 Months Ended
	Sep. 30, 2013
Cash And Cash Equivalents	'
Cash And Cash Equivalents	'
	2. CASH AND CASH EQUIVALENTS
	Throughout the periods covered by the financial statements presented herein, EEP has provided cash management services to us through a centralized treasury system. As a result, all of our charges and cost allocations covered by the centralized treasury system were deemed to have been paid by us to EEP, in cash, during the period in which the cost was recorded in the financial statements. In addition, all of our cash receipts were advanced to EEP as they were received. As a result of using EEP's centralized treasury system, the excess of cash receipts advanced to EEP over the charges and cash allocation represents a net reduction in partners' capital as presented on our consolidated statements of financial position.

Inventory

Inventory	9 Months Ended
	Sep. 30, 2013
Inventory	'
Inventory	'
	3. INVENTORY
		Our inventory is comprised of the following:
			September 30,		December 31,
			2013		2012
			(in millions)
		Materials and supplies	$	0.6	$	0.4
		Crude oil inventory		11.5		10.1
		Natural gas and NGL inventory		132.5		64.3
			$	144.6	$	74.8
	The “Cost of natural gas and natural gas liquids” on our consolidated statements of income includes charges totaling $0.9 million and $0.2 million, and $3.3 million and $9.8 million for the three and nine month periods ended September 30, 2013 and 2012, respectively, that we recorded to reduce the cost basis of our inventory of natural gas and NGLs to reflect the current market value.

Property_Plant_And_Equipment

Property, Plant And Equipment	9 Months Ended
	Sep. 30, 2013
Property, Plant And Equipment	'
Property, Plant And Equipment	'
	4. PROPERTY, PLANT AND EQUIPMENT
	Our property, plant and equipment is comprised of the following:
				September 30,		December 31,
				2013		2012
				(in millions)
		Land		$	11.3	$	8.7
		Rights-of-way			374.1		340.3
		Pipelines			1,724.70		1,603.80
		Pumping equipment, buildings and tanks			88.7		65.4
		Compressors, meters and other operating equipment			1,953.40		1,755.70
		Vehicles, office furniture and equipment			146.5		133
		Processing and treating plants			511.3		489.8
		Construction in progress			184		402.2
			Total property, plant and equipment		4,994.00		4,798.90
		Accumulated depreciation			-935.7		-835.9
			Property, plant and equipment, net	$	4,058.30	$	3,963.00

Related_Party_Transactions

Related Party Transactions	9 Months Ended
	Sep. 30, 2013
Related Party Transactions [Abstract]	'
Related Party Transactions	'
	5. RELATED PARTY TRANSACTIONS
	Administrative and Workforce Related Services
	Enbridge and Enbridge Management and its affiliates provided management and administrative, operational and workforce related services to us during the periods presented in these financial statements. Employees of Enbridge and its affiliates are assigned to provide services to one or more affiliates of Enbridge, including us. Where directly attributable, the costs of all compensation, benefits expenses and employer expenses for these employees are charged directly by Enbridge to the appropriate affiliate. Enbridge does not record any profit or margin for the administrative and operational services charged to us.
	We do not directly employ any of the individuals responsible for managing or operating our business. We have historically obtained managerial, administrative and operational services from EEP's general partner, Enbridge Management and affiliates of Enbridge pursuant to service agreements among us, the Partnership, Enbridge Management and affiliates of Enbridge. Pursuant to these service agreements, we have agreed to reimburse EEP's general partner and affiliates of Enbridge for the cost of managerial, administrative, operational and director services they provide to us. In connection with the Offering, we entered into an intercorporate services agreement with EEP pursuant to which we agreed upon certain aspects of our relationship with EEP, including the provision by EEP or its affiliates to us of certain administrative services and employees, our agreement to reimburse EEP or its affiliates for the cost of such services and employees and certain other matters.
	Intercorporate Services Agreement
	EEP's general partner, Enbridge Management, Enbridge and affiliates of Enbridge provide managerial, administrative, operational and director services to us pursuant to service agreements, and we reimburse them for the costs of those services. Through a general and administrative services agreement among us, EEP's general partner, Enbridge Management and Enbridge Employee Services, Inc., a subsidiary of EEP's general partner, which we refer to as EES, we are charged for the services of employees resident in the United States. The charges related to these service agreements are included in “General and administrative - affiliate” expenses on our consolidated statements of income. Under the general and administrative services agreement, EES also provides services to us, EEP, Enbridge Management and EEP's general partner and charges each recipient, on a monthly basis, the actual costs that it incurs for those services. EEP's general partner and Enbridge Management may request that EES provide special additional general services for which each party, as appropriate, agrees to pay costs and expenses incurred by EES in connection with providing the special additional general services. The types of services provided under the general and administrative services agreement include:
	•       accounting, tax planning and compliance services, including preparation of financial statements and income tax returns;
	•       administrative, executive, legal, human resources and computer support services;
	•        insurance coverage;
	•       all administrative and operational services required to operate existing systems and any additional systems acquired by us and operated by EES; and
	•       facilitation of the business and affairs of Enbridge Management and us, including, but not limited to, public and government affairs, engineering, environmental, finance, audit, operations and operational support, safety/compliance and other services.
	EES captures all costs that it incurs for providing the services to us by cost center in its financial system. The cost centers applicable to us are “Shared Service” and “EEP only”. Shared Service cost centers are used to capture costs that are not specific to a single United States Enbridge entity but are shared among multiple United States Enbridge entities. The costs captured in the cost centers that are specific to us are charged in full to us. The costs captured in cost centers that are outside of our business unit are charged to other Enbridge entities.
	The general method used to allocate the Shared Service costs is established through the budgeting process and reimbursed as follows:
	•       each cost center establishes a budget;
	•        each cost center manager estimates the amount of time the department spends on us and entities that are not directly affiliated with us;
	•        costs are accumulated monthly for each cost center;
	•       the actual costs accumulated monthly by each cost center are allocated to us or other Enbridge entities based on the allocation model; and
	•       we reimburse EES for our share of the allocated costs.
	The total amount incurred by us, through EEP, per the EEP only cost centers, for services received pursuant to the general and administrative services agreement for the three month periods ended September 30, 2013 and 2012 was $52.3 million and $50.6 million, respectively. For the nine month periods ended September 30, 2013 and 2012, we incurred, through EEP, $154.4 million and $153.0 million, respectively, pursuant to the general and administrative services agreement. These amounts were settled through “Contributions from partners” as reflected on our consolidated statements of cash flows. The following table presents the affiliate amounts reflected in our consolidated statements of income by category as follows:
			For the three month period				For the nine month period
			ended September 30,				ended September 30,
			2013		2012		2013		2012
			(unaudited; in millions)
	Operating and maintenance - affiliate		$	27.3	$	26.6	$	81.4	$	81.2
	General and administrative - affiliate			25		24		73		71.8
		Total	$	52.3	$	50.6	$	154.4	$	153
	Enbridge and Enbridge Management and their respective affiliates allocated direct workforce costs to us for our construction projects of $4.5 million and $6.4 million as of September 30, 2013 and December 31, 2012, respectively, that we recorded as additions to “Property, plant and equipment, net” on our consolidated statements of financial position.
	Insurance Allocation Agreement
	We participate in the comprehensive insurance program that is maintained by Enbridge for its benefit and the benefit of its subsidiaries. In December 2012, EEP entered into an insurance allocation agreement with Enbridge and another Enbridge subsidiary, which was amended on November 13, 2013, as discussed in Note 11. Subsequent Events. Under this agreement, in the unlikely event that multiple insurable incidents occur which exceed coverage limits within the same insurance period, the total insurance coverage will be allocated among the Enbridge entities on an equitable basis.
	Affiliate Revenues and Purchases
	We purchase natural gas, NGLs and crude oil from third parties, which subsequently generate operating revenues from sales to Enbridge and its affiliates. The sales to Enbridge and its affiliates are presented in “Operating revenue - affiliate” on our consolidated statements of income. These transactions are entered into at the market price on the date of sale. Included in our results for the three month periods ended September 30, 2013 and 2012 are operating revenues from sales to Enbridge and its affiliates of $49.6 million and $77.8 million, respectively. Included in our results for the nine month periods ended September 30, 2013 and 2012 are operating revenues from sales to Enbridge and affiliates of $162.4 million and $317.2 million, respectively.
	We also purchase natural gas, NGLs and crude oil from Enbridge and its affiliates for sale to third parties at market prices on the date of purchase. The purchases of natural gas, NGLs and crude oil from Enbridge and its affiliates are presented in “Cost of natural gas and natural gas liquids - affiliate” on our consolidated statements of income. Included in our results for the three month periods ended September 30, 2013 and 2012 are costs for natural gas, NGLs and crude oil purchases from Enbridge and its affiliates of $23.0 million and $51.9 million, respectively. Included in our results for the nine month periods ended September 30, 2013 and 2012 are costs for natural gas, NGLs and crude oil purchases from Enbridge and its affiliates of $95.5 million and $243.6 million, respectively. Routine purchases and sales with affiliates are settled monthly through EEP's centralized treasury function at terms that are consistent with third-party transactions. Routine purchases and sales with affiliates that have not yet been settled are included in “Due from general partner and affiliates” and “Due to general partner and affiliates” on our consolidated statements of financial position.
	Related Party Transactions with Joint Venture
	We have a 35% aggregate interest in the Texas Express NGL system, which is comprised of two joint ventures with third parties that together are constructing a 580 mile NGL intrastate transportation pipeline and a related NGL gathering system that was placed into service in the fourth quarter of 2013. Our equity investment in the Texas Express NGL system at September 30, 2013 and December 31, 2012 was $365.5 million and $183.7 million, respectively, which is included on our consolidated statements of financial position in “Equity investment in joint venture.”
	Our logistics and marketing business has made commitments to transport up to 120,000 barrels per day, or bpd, of NGLs on the Texas Express NGL system from 2013 to 2023.
	Partners' Capital Transactions
	The partners' capital accounts reflected in the financial statements contained herein, as of September 30, 2013, reflect the ownership of our Predecessor and are comprised of a 99.999% limited partner interest that is owned entirely by EEP and a 0.001% general partner interest that at September 30, 2013 is owned by the OLP GP, a wholly owned subsidiary of EEP. We paid cash distributions to EEP and the OLP GP totaling $206.3 million, and $242.0 million during the nine months ended September 30, 2013 and 2012, respectively. These amounts were settled through “Distributions to partners” as reflected on our consolidated statements of cash flows.
	Conflicts of Interest
	Our Predecessor was also a direct subsidiary of EEP, which, as of September 30, 2013, owned all of the limited partner interests and controlled the general partner, the OLP GP. As a result, any conflicts of interest that exist between Enbridge Management, EEP's general partner, Enbridge and EEP may also represent conflicts with us. Enbridge Management makes substantially all decisions relating to the management of EEP's business and affairs pursuant to a delegation of control agreement with EEP's general partner and through this arrangement also makes all decisions relating to the management of our business and affairs. EEP's general partner owns the voting shares of Enbridge Management and elects all of its directors. Enbridge, through its wholly owned subsidiary, Enbridge Pipelines, Inc., owns all the common stock of EEP's general partner. Most of the directors and officers of EEP's general partner are also directors and officers of Enbridge Management and some are directors and officers of Enbridge and have fiduciary duties to manage the business of Enbridge, EEP's general partner and Enbridge Management in a manner that may not be in the best interests of MEP's unitholders. Certain conflicts of interest could arise as a result of the relationships among Enbridge Management, EEP's general partner, Enbridge, EEP and the Predecessor. EEP's partnership agreement and our partnership agreement and the delegation of control agreement contain provisions that allow Enbridge Management to take into account the interest of all parties in addition to those of our owners in resolving conflicts of interest, thereby limiting its fiduciary duties to our owners, as well as provisions that may restrict the remedies available to our owners for actions taken that might, without such limitations, constitute breaches of fiduciary duty.
	Sale of Accounts Receivable
	Certain of our subsidiaries entered into a receivables purchase agreement, dated June 28, 2013, as amended on September 20, 2013 and December 2, 2013 which we refer to as the Receivables Agreement, with an indirect wholly owned subsidiary of Enbridge. The Receivables Agreement and the transactions contemplated thereby were approved by a special committee of the board of directors of Enbridge Management. Pursuant to the Receivables Agreement, the Enbridge subsidiary will purchase on a monthly basis, for cash, current accounts receivables and accrued receivables, or the receivables, of those of ours subsidiaries and other subsidiaries of EEP that are parties thereto up to an aggregate monthly maximum of $450.0 million net of receivables that have not been collected. Following the sale and transfer of the receivables to the Enbridge subsidiary, the receivables are deposited in an account of that subsidiary, and ownership and control are vested in that subsidiary. The Enbridge subsidiary has no recourse with respect to the receivables acquired from these operating subsidiaries under the terms of and subject to the conditions stated in the Receivables Agreement. EEP and, as of December 2, 2013, MEP, each act in an administrative capacity as collection agent on behalf of the Enbridge subsidiary and can be removed at any time in the sole discretion of the Enbridge subsidiary. EEP and MEP have no other involvement with the purchase and sale of the receivables pursuant to the Receivables Agreement. The Receivables Agreement terminates on December 30, 2016.
	Consideration for the receivables sold is equivalent to the carrying value of the receivables less a discount for credit risk. The difference between the carrying value of the receivables sold and the cash proceeds received is recognized in “General and administrative – affiliate” expense in our consolidated statements of income. For the three and nine month periods ended September 30, 2013, the loss stemming from the discount on the receivables sold was not material. For the three and nine month periods ended September 30, 2013, we derecognized and sold $641.0 million and $772.5 million, respectively, of accrued receivables to the Enbridge subsidiary. For the three and nine month periods ended September 30, 2013, the cash proceeds were $640.8 million and $772.3 million, respectively, which was remitted to EEP through our centralized treasury system. As of September 30, 2013, $308.7 million of the receivables were outstanding from customers that had not been collected on behalf of the Enbridge subsidiary.
	Allocated Interest
	EEP incurs borrowing cost on our behalf, which we recognize to the extent we are able to capitalize such costs to our construction related projects. The interest cost we incur is directly offset by the amount of interest we capitalize on outstanding construction projects.
	Our interest cost of the three and nine months ended September 30, 2013 and 2012 is detailed below.
			For the three month period				For the nine month period
			ended September 30,				ended September 30,
			2013		2012		2013		2012
			(unaudited; in millions)
	Interest expense		$	5.1	$	1.6	$	16.6	$	4.6
	Interest capitalized			5.1		1.6		16.6		4.6
	Interest cost incurred		$	-	$	-	$	-	$	-
	Interest cost paid		$	5.1	$	1.6	$	16.6	$	4.6
	Derivative Transactions
	We have related party derivative transactions executed on behalf of EEP that were contracted through MEP prior to the Offering and are allocated to EEP. These transactions were contracted to hedge the forward price of EEP's crude oil length inherent to the operation of pipelines and to hedge EEP's interest payments of variable rate debt obligations that are sensitive to changes in interest rates. These hedges create a fixed sales price for crude oil that EEP will receive in the future and lock in the interest rate on EEP's anticipated future debt. Subsequent to the Offering, these transactions were re-contracted through EEP and will no longer be allocated from MEP. These transactions are included as part of Note 7. Derivative Financial Instruments and Hedging Activities.

Commitments_And_Contingencies

Commitments And Contingencies	9 Months Ended
	Sep. 30, 2013
Commitments And Contingencies	'
Commitments And Contingencies	'
	6. COMMITMENTS AND CONTINGENCIES
	Environmental Liabilities
	We are subject to federal and state laws and regulations relating to the protection of the environment. Environmental risk is inherent to the operating activities of our gathering, processing, and transportation and logistics and marketing businesses, and we are, at times, subject to environmental cleanup and enforcement actions. We manage this environmental risk through appropriate environmental policies and practices to minimize any impact our operations may have on the environment. To the extent that we are unable to recover payment for environmental liabilities from insurance or otherwise, we will be responsible for payment of liabilities arising from environmental incidents associated with the operating activities of our gathering, processing and transportation and logistics and marketing businesses. We continue to voluntarily monitor past leak sites on our systems for the purpose of assessing whether any remediation is required in light of current regulations.
	As of September 30, 2013 and December 31, 2012, we had $0.2 million and $0.3 million, respectively, included in “Accounts payable and other” and as of December 31, 2012, we had accrued $0.1 million in “Other long-term liabilities,” on our consolidated statements of financial position for costs we have incurred primarily to address remediation of contaminated sites, asbestos containing materials, management of hazardous waste material disposal, outstanding air quality measures for certain of our natural gas assets and penalties we have been or expect to be assessed related to environmental liabilities.
	Legal and Regulatory Proceedings
	We are a participant in various legal and regulatory proceedings arising in the ordinary course of business. Some of these proceedings are covered, in whole or in part, by insurance. We are also directly, or indirectly, subject to challenges by special interest groups to regulatory approvals and permits for certain of our expansion projects.

Derivative_Financial_Instrumen

Derivative Financial Instruments And Hedging Activities	9 Months Ended
	Sep. 30, 2013
Derivative Financial Instruments And Hedging Activities	'
Derivative Financial Instruments And Hedging Activities	'
	7. DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES
	Our net income and cash flows are subject to volatility stemming from fluctuations in commodity prices of natural gas, NGLs, condensate and fractionation margins. Fractionation margins represent the relative difference between the price we receive from NGL and condensate sales and the corresponding cost of natural gas we purchase for processing. Our exposure to commodity price risk exists within both of our segments. We use derivative financial instruments (i.e., futures, forwards, swaps, options and other financial instruments with similar characteristics) to manage the risks associated with market fluctuations in commodity prices, as well as to reduce the volatility in our cash flows. Based on our risk management policies, all of our derivative financial instruments are employed in connection with an underlying asset, liability and/or forecasted transaction and are not entered into with the objective of speculating on commodity prices. We have hedged a portion of our exposure to variability in future cash flows associated with commodity price risks through 2016 in accordance with our risk management policies.
	Accounting Treatment
	We record all derivative financial instruments in our consolidated financial statements at fair market value, which we adjust each period for changes in the fair market value, and refer to as marking to market, or mark-to-market. The fair market value of these derivative financial instruments reflects the estimated amounts that we would pay to transfer a liability or receive to sell an asset in an orderly transaction with market participants to terminate or close the contracts at the reporting date, taking into account the current unrealized losses or gains on open contracts. We apply a mid-market pricing convention, which we refer to as the market approach, to value substantially all of our derivative instruments. Actively traded external market quotes, data from pricing services and published indices are used to value our derivative instruments, which are fair-valued on a recurring basis. We may also use these inputs with internally developed methodologies that result in our best estimates of fair value.
	In accordance with the applicable authoritative accounting guidance, if a derivative financial instrument does not qualify as a hedge, or is not designated as a hedge, the derivative is marked-to-market each period with the increases and decreases in fair market value recorded in our consolidated statements of income as increases and decreases in “Cost of natural gas and natural gas liquids” or “Operating revenue” for our commodity-based derivatives. Cash flow is only impacted to the extent the actual derivative contract is settled by making or receiving a payment to or from the counterparty or by making or receiving a payment for entering into a contract that exactly offsets the original derivative contract. Typically, we settle our derivative contracts when the physical transaction that underlies the derivative financial instrument occurs.
	If a derivative financial instrument qualifies and is designated as a cash flow hedge, which is a hedge of a forecasted transaction or future cash flows, any unrealized mark-to-market gain or loss is deferred in “Accumulated other comprehensive income,” also referred to as AOCI, a component of “Partners' capital,” until the underlying hedged transaction occurs. To the extent that the hedge instrument is effective in offsetting the transaction being hedged, there is no impact to the income statement until the underlying transaction occurs. At inception and on a quarterly basis, we formally assess whether the hedge contract is highly effective in offsetting changes in cash flows of hedged items. Any ineffective portion of a cash flow hedge's change in fair market value is recognized each period in earnings. Realized gains and losses on derivative financial instruments that are designated as hedges and qualify for hedge accounting are included in “Cost of natural gas and natural gas liquids” for commodity hedges in the period in which the hedged transaction occurs. Gains and losses deferred in AOCI related to cash flow hedges for which hedge accounting has been discontinued remain in AOCI until the underlying physical transaction occurs unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period or within an additional two month period of time thereafter. Generally, our preference is for our derivative financial instruments to receive hedge accounting treatment whenever possible to mitigate the non-cash earnings volatility that arises from recording the changes in fair value of our derivative financial instruments through earnings. To qualify for cash flow hedge accounting treatment as set forth in the authoritative accounting guidance, very specific requirements must be met in terms of hedge structure, hedge objective and hedge documentation.
	Non-Qualified Hedges
	Many of our derivative financial instruments qualify for hedge accounting treatment as set forth in the authoritative accounting guidance. However, we have derivative financial instruments associated with our commodity activities where the hedge structure does not meet the requirements to apply hedge accounting. As a result, these derivative financial instruments do not qualify for hedge accounting and are referred to as non-qualifying. These non-qualifying derivative financial instruments are marked-to-market each period with the change in fair value, representing unrealized gains and losses, included in “Cost of natural gas and natural gas liquids” in our consolidated statements of income. These mark-to-market adjustments produce a degree of earnings volatility that can often be significant from period to period, but have no cash flow impact relative to changes in market prices. The cash flow impact occurs when the underlying physical transaction takes place in the future and the associated financial instrument contract settlement is made.
	The following transaction types do not qualify for hedge accounting and contribute to volatility in our earnings and in our cash flows upon settlement:
	Commodity Price Exposures:
	•        Transportation—In our logistics and marketing business, when we transport natural gas from one location to another, the pricing index used for natural gas sales is usually different from the pricing index used for natural gas purchases, which exposes us to market price risk relative to changes in those two indices. By entering into a basis swap, where we exchange one pricing index for another, we can effectively lock in the margin, representing the difference between the sales price and the purchase price, on the combined natural gas purchase and natural gas sale, removing any market price risk on the physical transactions. Although this represents a sound economic hedging strategy, the derivative financial instruments (i.e., the basis swaps) we use to manage the commodity price risk associated with these transportation contracts do not qualify for hedge accounting, since only the future margin has been fixed and not the future cash flow. As a result, the changes in fair value of these derivative financial instruments are recorded in earnings.
	•       Storage—In our logistics and marketing business, we use derivative financial instruments (i.e., natural gas swaps) to hedge the relative difference between the injection price paid to purchase and store natural gas and the withdrawal price at which the natural gas is sold from storage. The intent of these derivative financial instruments is to lock in the margin, representing the difference between the price paid for the natural gas injected and the price received upon withdrawal of the natural gas from storage in a future period. We do not pursue cash flow hedge accounting treatment for these storage transactions since the underlying forecasted injection or withdrawal of natural gas may not occur in the period as originally forecast. This can occur because we have the flexibility to make changes in the underlying injection or withdrawal schedule, based on changes in market conditions. In addition, since the physical natural gas or NGLs are recorded at the lower of cost or market, timing differences can result when the derivative financial instrument is settled in a period that is different from the period the physical natural gas is sold from storage. As a result, derivative financial instruments associated with our natural gas and NGL storage activities can increase volatility due to fluctuations in NGL prices until the underlying transactions are settled or offset.
	•       Optional Natural Gas Processing Volumes—In our gathering, processing and transportation business, we use derivative financial instruments to hedge the volumes of NGLs produced from our natural gas processing facilities. Some of our natural gas contracts allow us the choice of processing natural gas when it is economical and to cease doing so when processing becomes uneconomic. We have entered into derivative financial instruments to fix the sales price of a portion of the NGLs that we produce at our discretion and to fix the associated purchase price of natural gas required for processing. We typically designate derivative financial instruments associated with NGLs we produce per contractual processing requirements as cash flow hedges when the processing of natural gas is probable of occurrence. However, we are precluded from designating the derivative financial instruments as qualifying hedges of the respective commodity price risk when the discretionary processing volumes are subject to change. As a result, our operating income is subject to increased volatility due to fluctuations in NGL prices until the underlying transactions are settled or offset.
	•        NGL Forward Contracts—In our logistics and marketing business, we use forward contracts to fix the price of NGLs we purchase and store in inventory and to fix the price of NGLs that we sell from inventory to meet the demands of our customers that sell and purchase NGLs. In the second quarter of 2009, we determined that a sub-group of physical NGL sales contracts with terms allowing for economic net settlement did not qualify for the normal purchases and normal sales, or NPNS, scope exception and are being marked-to-market each period with the changes in fair value recorded in earnings. The forward contracts for which we have revoked the NPNS election do not qualify for hedge accounting and are being marked-to-market each period with the changes in fair value recorded in earnings. As a result, our operating income is subject to additional volatility associated with fluctuations in NGL prices until the forward contracts are settled.
	•        Natural Gas Forward Contracts—In our logistics and marketing business, we use forward contracts to sell natural gas to our customers. Historically, we have not considered these contracts to be derivatives under the NPNS exception allowed by authoritative accounting guidance. In the first quarter of 2010, we determined that a sub-group of physical natural gas sales contracts with terms allowing for economic net settlement did not qualify for the NPNS scope exception, and are being marked-to-market each period with the changes in fair value recorded in earnings. As a result, our operating income is subject to additional volatility associated with the changes in fair value of these contracts.
	•        Crude Forward Contracts—In our logistics and marketing business, we use forward contracts to fix the price of crude we purchase and store in inventory and to fix the price of crude that we sell from inventory. A sub-group of physical crude contracts with terms allowing for economic net settlement do not qualify for the normal purchases and normal sales, or NPNS, scope exception and are being marked-to-market each period with the changes in fair value recorded in earnings. As a result, our operating income is subject to additional volatility associated with fluctuations in crude prices until the forward contracts are settled.
	•        Natural Gas and NGL Options—In our gathering, processing and transportation business, we use options to hedge the forecasted commodity exposure of our NGLs and natural gas. Although options can qualify for hedge accounting treatment, pursuant to the authoritative accounting guidance, we have elected non-qualifying treatment. As such, our option premiums are expensed as incurred. These derivatives are being marked-to-market, with the changes in fair value recorded to earnings each period. As a result, our operating income is subject to volatility due to movements in the prices of NGLs and natural gas until the underlying long-term transactions are settled.
	In all instances related to the commodity exposures described above, the underlying physical purchase, storage and sale of the commodity is accounted for on a historical cost or net realizable value basis rather than on the mark-to-market basis we employ for the derivative financial instruments used to mitigate the commodity price risk associated with our storage and transportation assets. This difference in accounting (i.e., the derivative financial instruments are recorded at fair market value while the physical transactions are recorded at the lower of historical cost or net realizable value) can and has resulted in volatility in our reported net income, even though the economic margin is essentially unchanged from the date the transactions were consummated.
	Derivative Positions
	Our derivative financial instruments are included at their fair values in the consolidated statements of financial position as follows:
				September 30,			December 31,
				2013			2012
				(in millions)
		Other current assets		$	138.3		$	275
		Other assets, net			72.5			78.1
		Accounts payable and other			-151.2			-259.9
		Other long-term liabilities			-64			-78
				$	-4.4		$	15.2
	The changes in the net assets and liabilities associated with our derivatives are primarily attributable to the effects of new derivative transactions we have entered at prevailing market prices, settlement of maturing derivatives and the change in forward market prices of our remaining hedges. Our portfolio of derivative financial instruments is largely comprised of long-term natural gas, NGL and crude oil sales and purchase contracts.
	We record the change in fair value of our highly effective cash flow hedges in AOCI until the derivative financial instruments are settled, at which time they are reclassified to earnings. Also included in AOCI are unrecognized losses of approximately $0.6 million associated with derivative financial instruments that qualified for and were classified as cash flow hedges of forecasted transactions that were subsequently de-designated. These losses are reclassified to earnings over the periods during which the originally hedged forecasted transactions affect earnings. During the nine month period ended September 30, 2013, unrealized commodity hedge gains of $1.7 million were de-designated as a result of the hedges no longer meeting hedge accounting criteria. We estimate that approximately $4.5 million, representing unrealized net losses from our cash flow hedging activities based on pricing and positions at September 30, 2013, will be reclassified from AOCI to earnings during the next 12 months.
	The table below summarizes our derivative balances by counterparty credit quality (negative amounts represent our net obligations to pay the counterparty).
				September 30,			December 31,
				2013			2012
				(in millions)
		Counterparty Credit Quality (1)
		AAA		$	0.1		$	-
		AA			-57.8			-116.6
		A			-84.5			-150.4
		Lower than A			137.8			282.2
				$	-4.4		$	15.2
		______________________________
		(1)As determined by nationally-recognized statistical ratings organizations.
	As the net value of our derivative financial instruments has decreased in response to changes in forward commodity prices, our outstanding financial exposure to third parties has also decreased. When credit thresholds are met pursuant to the terms of our International Swaps and Derivatives Association, Inc., or ISDA®, financial contracts, we have the right to require collateral from our counterparties. We would include any cash collateral received in the balances listed above, however, as of September 30, 2013 and December 31, 2012, we were not holding any cash collateral on our asset exposures. When we are in a position of posting collateral to cover our counterparties' exposure to our non-performance, the collateral is provided through letters of credit, which are not reflected above.
	The ISDA® agreements and associated credit support, which govern our financial derivative transactions, contain no credit rating downgrade triggers that would accelerate the maturity dates of our outstanding transactions. A change in ratings is not an event of default under these instruments, and the maintenance of a specific minimum credit rating is not a condition to transacting under the ISDA® agreements. In the event of a credit downgrade, additional collateral may be required to be posted under the agreement if we are in a liability position to our counterparty, but the agreement will not automatically terminate and require immediate settlement of all future amounts due.
	The ISDA® agreements, in combination with our master netting agreements, and credit arrangements governing our commodity swaps require that collateral be posted per tiered contractual thresholds based on the credit rating of each counterparty. EEP generally provides letters of credit to satisfy such collateral requirements under our ISDA® agreements. These agreements will require additional collateral postings of up to 100% on net liability positions in the event of a credit downgrade below investment grade. Automatic termination clauses which exist are related only to non-performance activities, such as the refusal to post collateral when contractually required to do so. When we are holding an asset position, our counterparties are likewise required to post collateral on their liability (our asset) exposures, also determined by tiered contractual collateral thresholds. Counterparty collateral may consist of cash or letters of credit, both of which must be fulfilled with immediately available funds.
	At September 30, 2013 and December 31, 2012, we had credit concentrations in the following industry sectors, as presented below:
				September 30,			December 31,
				2013			2012
				(in millions)
		United States financial institutions and investment banking entities		$	-114.5		$	-204.7
		Non-United States financial institutions			-28			-87.4
		Integrated oil companies			-3.8			4.5
		General Partner and affiliates			143.1			297.2
		Other			-1.2			5.6
				$	-4.4		$	15.2
	Gross derivative balances are presented below before the effects of collateral received or posted and without the effects of master netting arrangements. Both our assets and liabilities are adjusted for non-performance risk, which is statistically derived. This credit valuation adjustment model considers existing derivative asset and liability balances in conjunction with contractual netting and collateral arrangements, current market data such as credit default swap rates and bond spreads and probability of default assumptions to quantify an adjustment to fair value. For credit modeling purposes, collateral received is included in the calculation of our assets, while any collateral posted is excluded from the calculation of the credit adjustment. Our credit exposure for these over-the-counter derivatives is directly with our counterparty and continues until the maturity or termination of the contracts. A reconciliation between the derivative balances presented at gross values rather than the net amounts we present in our other derivative disclosures, is also provided below.
	Effect of Derivative Instruments on the Consolidated Statements of Financial Position
						Asset Derivatives						Liability Derivatives
						Fair Value at						Fair Value at
				Financial Position		September 30,			December 31,			September 30,			December 31,
				Location		2013			2012(3)			2013			2012(3)
						(in millions)
	Derivatives designated as
	hedging instruments(1)
Commodity contracts			Other current assets		$	2.4		$	12.2		$	-1.8		$	-4.2
Commodity contracts			Other assets, net			4.8			2.5			-1.2			-1.1
Commodity contracts			Accounts payable and other			4.2			4.7			-8.5			-5.7
Commodity contracts			Other long-term liabilities			0.2			2			-1.2			-4.5
						11.6			21.4			-12.7			-15.5
Derivatives not designated
	as hedging instruments
Interest rate contracts			Other current assets(2)			123			246.9			-			-
Interest rate contracts			Other assets, net(2)			83.2			68.3			-27.9			-3.3
Interest rate contracts			Accounts payable and other(2)			-			-			-123			-246.9
Interest rate contracts			Other long-term liabilities(2)			2.3			3.3			-57.6			-68.3
Commodity contracts			Other current assets(2)			17.2			27.2			-2.5			-7.1
Commodity contracts			Other assets, net(2)			14.4			11.8			-0.9			-0.1
Commodity contracts			Accounts payable and other(2)			9.2			0.8			-32.9			-12.8
Commodity contracts			Other long-term liabilities(2)			0.2			1.6			-8			-12.1
						249.5			359.9			-252.8			-350.6
Total derivative instruments					$	261.1		$	381.3		$	-265.5		$	-366.1
______________________________
(1)	Includes items currently designated as hedging instruments. Excludes the portion of de-designated hedges which may have a component remaining in AOCI.
(2)	Includes both affiliate and third party transactions.
(3)	The effect of derivative instruments on the consolidated statements of financial position, as of December 31, 2012, was revised to disclose the financial position location on a gross basis. The revisions to the disclosures are not considered material to and had no impact on amounts previously reported in the consolidated statements of financial position.
Effect of Derivative Instruments on the Consolidated Statements of Income and Accumulated Other Comprehensive Income
															Amount of gain
															(loss) recognized in
												Location of gain			earnings on
												(loss) recognized in			derivative
												earnings on  derivative			(Ineffective Portion
			Amount of gain									(Ineffective Portion			and Amount
Derivatives in Cash			(loss) recognized in			Location of gain (loss)			Amount of gain (loss)			and Amount			Excluded from
Flow Hedging			AOCI on Derivative			reclassified from			reclassified from			Excluded from			Effectiveness
Relationships			(Effective Portion)			AOCI to earnings			AOCI to earnings			Effectiveness Testing)(1)			Testing)(1)
	(in millions)
For the three month period ended September 30, 2013
						Cost of natural gas and						Cost of natural gas and
Commodity contracts			$	-17.2			natural gas liquids		$	-0.6			natural gas liquids		$	-0.5
Total			$	-17.2					$	-0.6					$	-0.5
For the three month period ended September 30, 2012
						Cost of natural gas and						Cost of natural gas and
Commodity contracts			$	-22.9			natural gas liquids		$	4.6			natural gas liquids		$	-3.9
Total			$	-22.9					$	4.6					$	-3.9
For the nine month period ended September 30, 2013
						Cost of natural gas and						Cost of natural gas and
Commodity contracts			$	-8.8			natural gas liquids		$	3			natural gas liquids		$	1.8
Total			$	-8.8					$	3					$	1.8
For the nine month period ended September 30, 2012
						Cost of natural gas and						Cost of natural gas and
Commodity contracts			$	47.2			natural gas liquids		$	-3.4			natural gas liquids		$	1.2
Total			$	47.2					$	-3.4					$	1.2
______________________________
(1)	Includes only the ineffective portion of derivatives that are designated as hedging instruments and does not include net gains or losses associated with derivatives that do not qualify for hedge accounting treatment.
Components of Accumulated Other Comprehensive Income/(Loss)
				Cash Flow
				Hedges
				(in millions)
Balance at December 31, 2012				$	7.1
	Other comprehensive income (loss) before reclassifications				-2.7
	Amounts reclassified from AOCI (1)				-3
		Net other comprehensive income (loss)			-5.7
Balance at September 30, 2013				$	1.4
_______________________________________
(1)For additional details on the amounts reclassified from AOCI, reference the Reclassifications from Accumulated Other Comprehensive Income table below.
Reclassifications from Accumulated Other Comprehensive Income
				For the three month period ended September 30,						For the nine month period ended September 30,
				2013			2012			2013			2012
				(in millions)
Losses (gains) on cash flow hedges:
	Commodity Contracts (1)			$	0.6		$	-4.6		$	-3		$	3.4
		Total Reclassifications from AOCI		$	0.6		$	-4.6		$	-3		$	3.4
______________________________
(1)Loss (gain) reported within “Cost of natural gas and natural gas liquids" in the consolidated statements of income.
Effect of Derivative Instruments on Consolidated Statements of Income
						For the three month period						For the nine month period
						ended September 30,						ended September 30,
						2013			2012			2013			2012
Derivatives Not Designated			Location of Gain or (Loss)			Amount of Gain or (Loss)						Amount of Gain or  (Loss)
as Hedging Instruments			Recognized in Earnings(1)			Recognized in Earnings(2)						Recognized in Earnings(2)
						(in millions)
			Cost of natural gas and
Commodity contracts				natural gas liquids(3)		$	-28.1		$	-12.4		$	-8.9		$	21.7
Commodity contracts			Operating revenue				-6.2			-			-6.2			-
Total						$	-34.3		$	-12.4		$	-15.1		$	21.7
________________________
(1)	Does not include settlements associated with derivative instruments that settle through physical delivery.
(2)	Includes only net gains or losses associated with those derivatives that do not qualify for hedge accounting treatment and does not include the ineffective portion of derivatives that are designated as hedging instruments.
(3)	Includes settlements losses of $0.2 million for the three month period ended September 30, 2013, settlement gains of $8.3 million for the three month period ended September 30, 2012 and settlement gains of $0.5 million and $15.0 million for the nine month periods ended September 30, 2013 and September 30, 2012, respectively.
Gross to Net Presentation Reconciliation of Derivative Assets and Liabilities
		30-Sep-13									December 31, 2012
		Assets			Liabilities			Total			Assets			Liabilities			Total
		(in millions)
Fair value of derivatives—gross presentation		$	261.1		$	-265.5		$	-4.4		$	381.3		$	-366.1		$	15.2
Effects of netting agreements			-50.3			50.3			-			-28.2			28.2			-
Fair value of derivatives—net presentation		$	210.8		$	-215.2		$	-4.4		$	353.1		$	-337.9		$	15.2
We record the fair market value of our derivative financial and physical instruments in the consolidated statements of financial position as current and long-term assets or liabilities on a net basis by counterparty. The terms of the ISDA®, which governs our financial contracts and our other master netting agreements, allow the parties to elect in respect of all transactions under the agreement, in the event of a default and upon notice to the defaulting party, for the non-defaulting party to set-off all settlement payments, collateral held and any other obligations (whether or not then due), which the non-defaulting party owes to the defaulting party.
Offsetting of Financial Assets and Derivative Assets
				As of September 30, 2013
				Gross			Gross Amount			Net Amount of Assets			Gross Amount
				Amount of			Offset in the			Presented in the			Not Offset in the
				Recognized			Statement of			Statement of			Statement of			Net
				Assets			Financial Position			Financial Position			Financial Position			Amount
				(in millions)
Description:
	Derivatives			$	261.1		$	-50.3		$	210.8		$	-4.8		$	206
		Total		$	261.1		$	-50.3		$	210.8		$	-4.8		$	206
Offsetting of Financial Liabilities and Derivative Liabilities
				As of September 30, 2013
				Gross			Gross Amount			Net Amount of Liabilities			Gross Amount
				Amount of			Offset in the			Presented in the			Not Offset in the
				Recognized			Statement of			Statement of			Statement of			Net
				Liabilities			Financial Position			Financial Position			Financial Position			Amount
				(in millions)
Description:
	Derivatives			$	-265.5		$	50.3		$	-215.2		$	4.8		$	-210.4
		Total		$	-265.5		$	50.3		$	-215.2		$	4.8		$	-210.4
Inputs to Fair Value Derivative Instruments
The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2013 and December 31, 2012. We classify financial assets and liabilities in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect our valuation of the financial assets and liabilities and their placement within the fair value hierarchy.
			30-Sep-13												December 31, 2012
			Level 1			Level 2			Level 3			Total			Level 1			Level 2			Level 3			Total
			(in millions)
Commodity contracts:
	Financial		$	-		$	-7		$	0.8		$	-6.2		$	-		$	-7		$	8.4		$	1.4
	Physical			-			-			-5.1			-5.1			-			-			7.4			7.4
Commodity options				-			-			6.9			6.9			-			-			6.4			6.4
Total			$	-		$	-7		$	2.6		$	-4.4		$	-		$	-7		$	22.2		$	15.2
Qualitative Information about Level 3 Fair Value Measurements
Data from pricing services and published indices are used to value our Level 3 derivative instruments, which are fair-valued on a recurring basis. We may also use these inputs with internally developed methodologies that result in our best estimate of fair value. The inputs listed in the table below would have a direct impact on the fair values of the listed instruments. The significant unobservable inputs used in the fair value measurement of the commodity derivatives (Natural Gas, NGLs and Crude Oil) are forward commodity prices. The significant unobservable inputs used in determining the fair value measurement of options are price and volatility. Increases/(decreases) in the forward commodity price in isolation would result in significantly higher/(lower) fair values for long positions, with offsetting impacts to short positions. Increases/(decreases) in volatility would increase/(decrease) the value for the holder of the option. Generally, a change in the estimate of forward commodity prices is unrelated to a change in the estimate of volatility of prices. An increase to the credit valuation adjustment would change the fair value of the positions.
Quantitative Information About Level 3 Fair Value Measurements
			Fair Value at							Range (1)
			September 30,			Valuation		Unobservable				Weighted
Contract Type			2013 (2)			Technique		Input		Lowest	Highest	Average	Units
Commodity Contracts - Financial			(in millions)
	Natural Gas		$	2.6		Market Approach		Forward Gas Price		3.24	4.19	3.69	MMBtu
	NGLs		$	-1.8		Market Approach		Forward NGL Price		0.25	2.08	1.25	Gal
Commodity Contracts - Physical
	Natural Gas		$	0.9		Market Approach		Forward Gas Price		3.24	4.35	3.72	MMBtu
	Crude Oil		$	-1.1		Market Approach		Forward Crude Price		83.41	107.67	99.42	Bbl
	NGLs		$	-4.9		Market Approach		Forward NGL Price		0.01	2.28	0.95	Gal
Commodity Options
	Natural Gas, Crude and NGLs		$	6.9		Option Model		Option Volatility		24%	145%	41%
Total Fair Value			$	2.6
_______________________________________
(1)	Prices are in dollars per Millions of British Thermal Units, or MMBtu, for Natural Gas, dollars per Gallon, or Gal, for NGLs and dollars per barrel, or Bbl, for Crude Oil.
(2)	Fair values are presented in millions of dollars and include credit valuation adjustments of approximately $0.3 million of losses.
Quantitative Information About Level 3 Fair Value Measurements
			Fair Value at							Range(1)
			December 31,			Valuation		Unobservable				Weighted
Contract Type			2012(2)			Technique		Input		Lowest	Highest	Average	Units
Commodity Contracts - Financial			(in millions)
	Natural Gas		$	8.8		Market Approach		Forward Gas Price		3.21	4.31	3.54	MMBtu
	NGLs		$	-0.4		Market Approach		Forward NGL Price		0.25	2.21	1.4	Gal
Commodity Contracts - Physical
	Natural Gas		$	1.7		Market Approach		Forward Gas Price		3.19	4.58	3.73	MMBtu
	Crude Oil		$	2.6		Market Approach		Forward Crude Price		65.22	116.56	94.31	Bbl
	NGLs		$	3.1		Market Approach		Forward NGL Price		-	2.22	0.61	Gal
Commodity Options
	Natural Gas, Crude and NGLs		$	6.4		Option Model		Option Volatility		29%	104%	40%
Total Fair Value			$	22.2
_______________________________
(1)	Prices are in dollars per MMBtu, for Natural Gas, dollars per Gal, for NGLs and dollars per Bbl, for Crude Oil.
(2)	Fair values are presented in millions and include credit valuation adjustments of approximately $0.1 million of losses.
Level 3 Fair Value Reconciliation
The table below provides a reconciliation of changes in the fair value of our Level 3 financial assets and liabilities measured on a recurring basis from January 1, 2013 to September 30, 2013. No transfers of assets between any of the Levels occurred during the period.
				Commodity			Commodity
				Financial			Physical			Commodity
				Contracts			Contracts			Options			Total
				(in millions)
Beginning balance as of January 1, 2013				$	8.4		$	7.4		$	6.4		$	22.2
	Transfer out of Level 3 (1)				-			-			-			-
Gains or losses:
	Included in earnings (or changes in net assets)				1.7			21.7			-0.5			22.9
	Included in other comprehensive income				3.4			-			-			3.4
Purchases, issuances, sales and settlements:
	Purchases				-			-			3			3
	Settlements (2)				-12.7			-34.2			-2			-48.9
Ending balance as of September 30, 2013				$	0.8		$	-5.1		$	6.9		$	2.6
Amount of changes in net assets attributable to the change in unrealized
	gains or losses related to assets still held at the reporting date			$	0.6		$	-6.2		$	4		$	-1.6
Amounts reported in operating revenue				$	-		$	-6.2		$	-		$	-6.2
_________________
(1)	Our policy is to recognize transfers as of the last day of the reporting period.
(2)	Settlements represent the realized portion of forward contracts.
Fair Value Measurements of Commodity Derivatives
The following table provides summarized information about the fair values of expected cash flows of our outstanding commodity based swaps and physical contracts at September 30, 2013 and December 31, 2012.
				At September 30, 2013																At December 31, 2012
								Wtd. Average Price (2)						Fair Value (3)						Fair Value (3)
				Commodity		Notional (1)		Receive			Pay			Asset			Liability			Asset			Liability
Portion of contracts maturing in 2013
	Swaps
		Receive variable/pay fixed		Natural Gas		1,058,748		$	3.49		$	3.59		$	0.1		$	-0.2		$	0.2		$	-0.3
				NGL		985,200		$	46.8		$	45.4		$	1.8		$	-0.5		$	1.4		$	-
				Crude Oil		257,664		$	101.36		$	102.95		$	0.2		$	-0.7		$	0.2		$	-3.9
		Receive fixed/pay variable		Natural Gas		2,361,000		$	4.36		$	3.55		$	1.9		$	-		$	7.8		$	-
				NGL		1,854,028		$	50.19		$	52.46		$	3		$	-7.2		$	9.3		$	-9.9
				Crude Oil		591,548		$	94.24		$	101.48		$	0.6		$	-4.8		$	6.3		$	-8.8
		Receive variable/pay variable		Natural Gas		13,277,500		$	3.53		$	3.51		$	0.3		$	-0.1		$	1.2		$	-0.2
	Physical Contracts
		Receive variable/pay fixed		NGL		2,330,976		$	37.27		$	36.89		$	3.3		$	-2.4		$	0.6		$	-0.8
				Crude Oil		255,010		$	102.19		$	105.97		$	-		$	-1		$	0.4		$	-0.4
		Receive fixed/pay variable		NGL		3,844,386		$	39.72		$	41.85		$	3.3		$	-11.4		$	2.6		$	-2.2
				Crude Oil		339,200		$	105.55		$	102.04		$	1.2		$	-		$	0.2		$	-1
		Receive variable/pay variable		Natural Gas		19,866,685		$	3.53		$	3.52		$	0.3		$	-0.2		$	0.9		$	-
				NGL		6,135,041		$	47.4		$	47.2		$	3.6		$	-2.4		$	5.2		$	-2.3
				Crude Oil		1,120,690		$	98.78		$	99.06		$	1.4		$	-1.7		$	6.4		$	-3
Portion of contracts maturing in 2014
	Swaps
		Receive variable/pay fixed		Natural Gas		21,870		$	3.75		$	5.22		$	-		$	-		$	-		$	-
				NGL		286,250		$	82.33		$	83.05		$	-		$	-0.2		$	-		$	-
				Crude Oil		506,255		$	95.33		$	101.95		$	-		$	-3.3		$	-		$	-5
		Receive fixed/pay variable		Natural Gas		3,006,890		$	3.97		$	3.73		$	0.7		$	-		$	0.2		$	-
				NGL		2,208,800		$	53.93		$	53.67		$	5.6		$	-5		$	0.9		$	-2.7
				Crude Oil		1,573,205		$	94.43		$	95.41		$	3.6		$	-5.2		$	5.4		$	-2.7
		Receive variable/pay variable		Natural Gas		13,842,500		$	3.77		$	3.76		$	0.2		$	-		$	0.1		$	-0.1
	Physical Contracts
		Receive variable/pay fixed		NGL		45,000		$	43.79		$	45.45		$	-		$	-0.1		$	-		$	-
		Receive fixed/pay variable		NGL		325,617		$	53.43		$	55.69		$	0.1		$	-0.8		$	-		$	-
		Receive variable/pay variable		Natural Gas		34,169,685		$	3.77		$	3.76		$	0.9		$	-0.4		$	0.5		$	-
				NGL		7,037,705		$	33.02		$	32.9		$	1.8		$	-0.9		$	-		$	-
Portion of contracts maturing in 2015
	Swaps
		Receive variable/pay fixed		Crude Oil		515,015		$	88.53		$	100.93		$	-		$	-6.3		$	-		$	-5.6
		Receive fixed/pay variable		NGL		292,000		$	56.76		$	54.04		$	1.2		$	-0.5		$	0.7		$	-0.2
				Crude Oil		865,415		$	97.72		$	88.53		$	7.9		$	-		$	6.8		$	-0.2
		Receive variable/pay variable		Natural Gas		900,000		$	4.05		$	4.04		$	-		$	-		$	-		$	-
	Physical Contracts
		Receive variable/pay variable		Natural Gas		8,541,825		$	4.1		$	4.06		$	0.5		$	-0.1		$	0.4		$	-
Portion of contracts maturing in 2016
	Swaps
		Receive fixed/pay variable		Crude Oil		45,750		$	99.31		$	84.81		$	0.6		$	-		$	0.5		$	-
	Physical Contracts
		Receive variable/pay variable		Natural Gas		783,240		$	4.28		$	4.17		$	0.1		$	-		$	0.1		$	-
______________________________
(1)	Volumes of natural gas are measured in MMBtu, whereas volumes of NGL and crude oil are measured in Bbl.
(2)	Weighted average prices received and paid are in $/MMBtu for natural gas and $/Bbl for NGL and crude oil.
(3)	The fair value is determined based on quoted market prices at September 30, 2013 and December 31, 2012, respectively, discounted using the swap rate for the respective periods to consider the time value of money. Fair values are presented in millions of dollars and exclude credit valuation adjustments of approximately $0.2 million of losses at September 30, 2013 and $0.2 million of losses at December 31, 2012.
The following table provides summarized information about the fair values of expected cash flows of our outstanding commodity options at September 30, 2013 and December 31, 2012.
				At September 30, 2013																At December 31, 2012
								Strike			Market			Fair Value (3)						Fair Value (3)
				Commodity		Notional (1)		Price (2)			Price (2)			Asset			Liability			Asset			Liability
Portion of option contracts maturing in 2013
		Puts (purchased)		Natural Gas		414,000		$	4.18		$	3.48		$	0.3		$	-		$	1.4		$	-
				NGL		138,000		$	31.26		$	27.76		$	1.1		$	-		$	3.7		$	-
		Puts (written)		NGL		69,000		$	26.18		$	10.68		$	-		$	-1.1		$	-		$	-
Portion of option contracts maturing in 2014
		Puts (purchased)		NGL		401,500		$	52.21		$	50.44		$	3.1		$	-		$	1.3		$	-
		Calls (written)		NGL		273,750		$	57.93		$	48.65		$	-		$	-0.9		$	-		$	-
Portion of option contracts maturing in 2015
		Puts (purchased)		NGL		547,500		$	53.76		$	52.52		$	4.5		$	-		$	-		$	-
______________________________
(1)	Volumes of natural gas are measured in MMBtu, whereas volumes of NGL and crude oil are measured in Bbl.
(2)	Strike and market prices are in $/MMBtu for natural gas and in $/Bbl for NGL and crude oil.
(3)	The fair value is determined based on quoted market prices at September 30, 2013 and December 31, 2012, respectively, discounted using the swap rate for the respective periods to consider the time value of money.
Fair Value Measurements of Commodity Derivatives
The following table provides summarized information about the fair values of expected cash flows of our outstanding commodity based swaps and physical contracts at September 30, 2013 and December 31, 2012.
				At September 30, 2013																At December 31, 2012
								Wtd. Average Price (2)						Fair Value (3)						Fair Value (3)
				Commodity		Notional (1)		Receive			Pay			Asset			Liability			Asset			Liability
Portion of contracts maturing in 2013
	Swaps
		Receive variable/pay fixed		Natural Gas		1,058,748		$	3.49		$	3.59		$	0.1		$	-0.2		$	0.2		$	-0.3
				NGL		985,200		$	46.8		$	45.4		$	1.8		$	-0.5		$	1.4		$	-
				Crude Oil		257,664		$	101.36		$	102.95		$	0.2		$	-0.7		$	0.2		$	-3.9
		Receive fixed/pay variable		Natural Gas		2,361,000		$	4.36		$	3.55		$	1.9		$	-		$	7.8		$	-
				NGL		1,854,028		$	50.19		$	52.46		$	3		$	-7.2		$	9.3		$	-9.9
				Crude Oil		591,548		$	94.24		$	101.48		$	0.6		$	-4.8		$	6.3		$	-8.8
		Receive variable/pay variable		Natural Gas		13,277,500		$	3.53		$	3.51		$	0.3		$	-0.1		$	1.2		$	-0.2
	Physical Contracts
		Receive variable/pay fixed		NGL		2,330,976		$	37.27		$	36.89		$	3.3		$	-2.4		$	0.6		$	-0.8
				Crude Oil		255,010		$	102.19		$	105.97		$	-		$	-1		$	0.4		$	-0.4
		Receive fixed/pay variable		NGL		3,844,386		$	39.72		$	41.85		$	3.3		$	-11.4		$	2.6		$	-2.2
				Crude Oil		339,200		$	105.55		$	102.04		$	1.2		$	-		$	0.2		$	-1
		Receive variable/pay variable		Natural Gas		19,866,685		$	3.53		$	3.52		$	0.3		$	-0.2		$	0.9		$	-
				NGL		6,135,041		$	47.4		$	47.2		$	3.6		$	-2.4		$	5.2		$	-2.3
				Crude Oil		1,120,690		$	98.78		$	99.06		$	1.4		$	-1.7		$	6.4		$	-3
Portion of contracts maturing in 2014
	Swaps
		Receive variable/pay fixed		Natural Gas		21,870		$	3.75		$	5.22		$	-		$	-		$	-		$	-
				NGL		286,250		$	82.33		$	83.05		$	-		$	-0.2		$	-		$	-
				Crude Oil		506,255		$	95.33		$	101.95		$	-		$	-3.3		$	-		$	-5
		Receive fixed/pay variable		Natural Gas		3,006,890		$	3.97		$	3.73		$	0.7		$	-		$	0.2		$	-
				NGL		2,208,800		$	53.93		$	53.67		$	5.6		$	-5		$	0.9		$	-2.7
				Crude Oil		1,573,205		$	94.43		$	95.41		$	3.6		$	-5.2		$	5.4		$	-2.7
		Receive variable/pay variable		Natural Gas		13,842,500		$	3.77		$	3.76		$	0.2		$	-		$	0.1		$	-0.1
	Physical Contracts
		Receive variable/pay fixed		NGL		45,000		$	43.79		$	45.45		$	-		$	-0.1		$	-		$	-
		Receive fixed/pay variable		NGL		325,617		$	53.43		$	55.69		$	0.1		$	-0.8		$	-		$	-
		Receive variable/pay variable		Natural Gas		34,169,685		$	3.77		$	3.76		$	0.9		$	-0.4		$	0.5		$	-
				NGL		7,037,705		$	33.02		$	32.9		$	1.8		$	-0.9		$	-		$	-
Portion of contracts maturing in 2015
	Swaps
		Receive variable/pay fixed		Crude Oil		515,015		$	88.53		$	100.93		$	-		$	-6.3		$	-		$	-5.6
		Receive fixed/pay variable		NGL		292,000		$	56.76		$	54.04		$	1.2		$	-0.5		$	0.7		$	-0.2
				Crude Oil		865,415		$	97.72		$	88.53		$	7.9		$	-		$	6.8		$	-0.2
		Receive variable/pay variable		Natural Gas		900,000		$	4.05		$	4.04		$	-		$	-		$	-		$	-
	Physical Contracts
		Receive variable/pay variable		Natural Gas		8,541,825		$	4.1		$	4.06		$	0.5		$	-0.1		$	0.4		$	-
Portion of contracts maturing in 2016
	Swaps
		Receive fixed/pay variable		Crude Oil		45,750		$	99.31		$	84.81		$	0.6		$	-		$	0.5		$	-
	Physical Contracts
		Receive variable/pay variable		Natural Gas		783,240		$	4.28		$	4.17		$	0.1		$	-		$	0.1		$	-
______________________________
(1)	Volumes of natural gas are measured in MMBtu, whereas volumes of NGL and crude oil are measured in Bbl.
(2)	Weighted average prices received and paid are in $/MMBtu for natural gas and $/Bbl for NGL and crude oil.
(3)	The fair value is determined based on quoted market prices at September 30, 2013 and December 31, 2012, respectively, discounted using the swap rate for the respective periods to consider the time value of money. Fair values are presented in millions of dollars and exclude credit valuation adjustments of approximately $0.2 million of losses at September 30, 2013 and $0.2 million of losses at December 31, 2012.
The following table provides summarized information about the fair values of expected cash flows of our outstanding commodity options at September 30, 2013 and December 31, 2012.
				At September 30, 2013																At December 31, 2012
								Strike			Market			Fair Value (3)						Fair Value (3)
				Commodity		Notional (1)		Price (2)			Price (2)			Asset			Liability			Asset			Liability
Portion of option contracts maturing in 2013
		Puts (purchased)		Natural Gas		414,000		$	4.18		$	3.48		$	0.3		$	-		$	1.4		$	-
				NGL		138,000		$	31.26		$	27.76		$	1.1		$	-		$	3.7		$	-
		Puts (written)		NGL		69,000		$	26.18		$	10.68		$	-		$	-1.1		$	-		$	-
Portion of option contracts maturing in 2014
		Puts (purchased)		NGL		401,500		$	52.21		$	50.44		$	3.1		$	-		$	1.3		$	-
		Calls (written)		NGL		273,750		$	57.93		$	48.65		$	-		$	-0.9		$	-		$	-
Portion of option contracts maturing in 2015
		Puts (purchased)		NGL		547,500		$	53.76		$	52.52		$	4.5		$	-		$	-		$	-
______________________________
(1)	Volumes of natural gas are measured in MMBtu, whereas volumes of NGL and crude oil are measured in Bbl.
(2)	Strike and market prices are in $/MMBtu for natural gas and in $/Bbl for NGL and crude oil.
(3)	The fair value is determined based on quoted market prices at September 30, 2013 and December 31, 2012, respectively, discounted using the swap rate for the respective periods to consider the time value of money.
			September 30,			December 31,
			2013			2012
			(in millions)
	Counterparty Credit Quality (1)
	AAA		$	0.1		$	-
	AA			-57.8			-116.6
	A			-84.5			-150.4
	Lower than A			137.8			282.2
			$	-4.4		$	15.2
	______________________________
	(1)As determined by nationally-recognized statistical ratings organizations.

Income_Taxes

Income Taxes	9 Months Ended
	Sep. 30, 2013
Income Taxes	'
Income Taxes	'
	8. INCOME TAXES
	We are not a taxable entity for United States federal income tax purposes or for the majority of states that impose an income tax. Taxes on our net income generally are borne by our owners through the allocation of taxable income. The State of Texas imposes taxes on us that are based on many, but not all, items included in net income.
	We computed our income tax expense by applying a Texas state income tax rate to modified gross margin. Our Texas state income tax rate was 0.4% and 0.5% for the nine month periods ended September 30, 2013 and 2012, respectively. Our income tax expense is $0.6 million and $1.3 million and $8.9 million and $2.1 million for the three and nine month periods ended September 30, 2013 and 2012, respectively.
	At September 30, 2013 and December 31, 2012, we have included a current income tax payable of $1.7 million and $3.7 million in “Property and other taxes payable” on our consolidated statements of financial position, respectively. In addition, at September 30, 2013 and December 31, 2012, we have included a deferred income tax payable of $10.5 million and $3.0 million, respectively, in “Deferred income tax liability” on our consolidated statements of financial position to reflect the tax associated with the difference between the net basis in assets and liabilities for financial and state tax reporting. Included in the $10.5 million is $6.6 million due to a new tax bill that went into effect in June 2013, as discussed below.
	The Texas Legislature passed House Bill 500, or HB 500, and it was subsequently signed into law in June 2013. The most noteworthy item in the law for us is that HB 500 allows a pipeline company that transports oil, gas, or other petroleum products owned by others to subtract as Cost of Goods Sold, or COGS, its depreciation, operations and maintenance costs related to the services provided. Under the new law, we are allowed additional deductions against our income for Texas margin tax purposes. We have recorded an additional “Deferred income tax liability” on our consolidated statements of financial position of approximately $6.6 million for the nine month period ended September 30, 2013 as a result of this new tax law. In the future, our effective tax rate in the State of Texas will be lower as a result of this change in law.

Segment_Information

Segment Information	9 Months Ended
	Sep. 30, 2013
Segment Information	'
Segment Information	'
	9. SEGMENT INFORMATION
	Our business is divided into operating segments, defined as components of the enterprise, about which financial information is available and evaluated regularly by our Chief Operating Decision Maker, collectively comprised of our senior management, in deciding how resources are allocated and performance is assessed.
	Each of our reportable segments is a business unit that offers different services and products that is managed separately, since each business segment requires different operating strategies. We conduct our business through two distinct reporting segments:
	•        Gathering, processing and transportation; and
	•       Logistics and marketing.
	The following tables present certain financial information relating to our business segments and corporate activities:
			For the three month period ended September 30, 2013
			Gathering, Processing and Transportation		Logistics and Marketing		Corporate (1)		Total
			(in millions)
	Total revenue		$	668.2	$	1,228.80	$	-	$	1,897.00
	Less: Intersegment revenue			496.8		19.3		-		516.1
	Operating revenue			171.4		1,209.50		-		1,380.90
	Cost of natural gas and natural gas liquids			33.5		1,210.80		-		1,244.30
	Segment gross margin			137.9		-1.3		-		136.6
	Operating and maintenance			71		17.7		-		88.7
	General and administrative			22.1		2.9		-		25
	Depreciation and amortization			34.1		1.7		-		35.8
				127.2		22.3		-		149.5
	Operating income (loss)			10.7		-23.6		-		-12.9
	Income (loss) before income tax expense			10.7		-23.6		-		-12.9
	Income tax expense			-		-		0.6		0.6
	Net income (loss)		$	10.7	$	-23.6	$	-0.6	$	-13.5
	______________________________
	(1)	Corporate consists of income taxes, which are not allocated to the business segments.
			For the three month period ended September 30, 2012
			Gathering, Processing and Transportation		Logistics and Marketing		Corporate (1)		Total
			(in millions)
	Total revenue		$	683.8	$	1,026.80	$	-	$	1,710.60
	Less: Intersegment revenue			461.8		27.9		-		489.7
	Operating revenue			222		998.9		-		1,220.90
	Cost of natural gas and natural gas liquids			67.2		970.8		-		1,038.00
	Segment gross margin			154.8		28.1		-		182.9
	Operating and maintenance			74.4		20.1		1.8		96.3
	General and administrative			21.6		2.7		-2		22.3
	Depreciation and amortization			32.4		1.9		-		34.3
				128.4		24.7		-0.2		152.9
	Operating income			26.4		3.4		0.2		30
	Income before income tax expense			26.4		3.4		0.2		30
	Income tax expense			-		-		1.3		1.3
	Net income (loss)		$	26.4	$	3.4	$	-1.1	$	28.7
	______________________________
	(1)	Corporate consists of interest expense, interest income, allowance for equity during construction, noncontrolling interest and other costs such as income taxes, which are not allocated to the business segments.
			As of and for the nine month period ended September 30, 2013
			Gathering, Processing and Transportation		Logistics and Marketing		Corporate (1)		Total
			(in millions)
	Total revenue		$	2,034.00	$	3,580.00	$	-	$	5,614.00
	Less: Intersegment revenue			1,491.00		72.7		-		1,563.70
	Operating revenue			543		3,507.30		-		4,050.30
	Cost of natural gas and natural gas liquids			101.7		3,451.70		-		3,553.40
	Segment gross margin			441.3		55.6		-		496.9
	Operating and maintenance			208.2		54.9		-		263.1
	General and administrative			64.6		8.5		-		73.1
	Depreciation and amortization			101.3		5		-		106.3
				374.1		68.4		-		442.5
	Operating income (loss)			67.2		-12.8		-		54.4
	Other income			-		-		0.2		0.2
	Income (loss) before income tax expense			67.2		-12.8		0.2		54.6
	Income tax expense			-		-		8.9		8.9
	Net income (loss)		$	67.2	$	-12.8	$	-8.7	$	45.7
	Total assets (2)		$	4,829.30	$	557.4	$	54.7	$	5,441.40
	Capital expenditures (excluding acquisitions)		$	177.9	$	14	$	13.9	$	205.8
	______________________________
	(1)	Corporate consists of income taxes, which are not allocated to the business segments.
(2)	Totals assets for our Gathering, Processing and Transportation segment includes our long term equity investment in the Texas Express NGL system.
		As of and for the nine month period ended September 30, 2012
		Gathering, Processing and Transportation		Logistics and Marketing		Corporate (1)		Total
		(in millions)
Total revenue		$	2,015.10	$	3,376.80	$	-	$	5,391.90
Less: Intersegment revenue			1,398.60		75.8		-		1,474.40
Operating revenue			616.5		3,301.00		-		3,917.50
Cost of natural gas and natural gas liquids			79.6		3,242.90		-		3,322.50
Segment gross margin			536.9		58.1		-		595
Operating and maintenance			209.7		60.3		1.8		271.8
General and administrative			63.9		15.8		-2		77.7
Depreciation and amortization			95.6		5.5		-		101.1
			369.2		81.6		-0.2		450.6
Operating income (loss)			167.7		-23.5		0.2		144.4
Other income (expense)			-		-		-0.1		-0.1
Income (loss) before income tax expense			167.7		-23.5		0.1		144.3
Income tax expense			-		-		2.1		2.1
Net income (loss)		$	167.7	$	-23.5	$	-2	$	142.2
Total assets (2)		$	4,372.10	$	903.6	$	138.3	$	5,414.00
Capital expenditures (excluding acquisitions)		$	317.8	$	3.1	$	10.8	$	331.7
______________________________
(1)	Corporate consists of income taxes, which are not allocated to the business segments.
(2)	Totals assets for our Gathering, Processing and Transportation segment includes our long term equity investment in the Texas Express NGL system.

Supplemental_Cash_Flows_Inform

Supplemental Cash Flows Information	9 Months Ended
	Sep. 30, 2013
Supplemental Cash Flows Information	'
Supplemental Cash Flows Information	'
	10. SUPPLEMENTAL CASH FLOWS INFORMATION
	The following table provides supplemental information for the item labeled “Other" in the “Cash provided by operating activities" section of our consolidated statements of cash flows.
				For the nine month
				period ended September 30,
				2013			2012
				(in millions)
		Loss on sale of assets		$	1.1		$	-
		Amortization of hedging costs			0.3			2.5
		Allowance for doubtful accounts			0.2			-
		Write-down of project costs			-			4.3
		Environmental costs, net of recoveries			-0.1			-
		Texas Express long-term inventory (line fill)			-1.3			-
		Other			-0.1			-0.1
				$	0.1		$	6.7
	In the “Cash used in investing activities” section of the consolidated statements of cash flows, we exclude changes that did not affect cash. The following is a reconciliation of additions to property, plant and equipment to total capital expenditures (excluding “Investment in joint venture”):
						For the nine month
						period ended September 30,
						2013			2012
						(in millions)
		Additions to property, plant and equipment				$	206.6		$	315.1
			Increase (decrease) in construction payables				-0.8			16.6
		Total capital expenditures (excluding "Investment in joint venture")				$	205.8		$	331.7

Subsequent_Events

Subsequent Events	9 Months Ended
	Sep. 30, 2013
Subsequent Events	'
Subsequent Events	'
	11. SUBSEQUENT EVENTS
	Initial Public Offering
	On November 13, 2013, the Partnership completed the Offering, as discussed in Note 1. Organization and Nature of Operations.
	Contribution, Conveyance and Assumption Agreement
	On November 13, 2013, in connection with the closing of the Offering, the following transactions, among others, occurred pursuant to a contribution, conveyance and assumption agreement, or the Contribution Agreement, by and among EEP, the Partnership, the General Partner, Midcoast Operating and OLP GP:
	•        EEP conveyed a portion of its limited partner interest in Midcoast Operating to the General Partner as a capital contribution with a value equal to 2.0% of the equity value of the Partnership after the Offering, or the GP Contribution Interest;
	•       the General Partner conveyed the GP Contribution Interest to the Partnership in exchange for (1) 922,859 general partner units in the Partnership, representing a continuation of its 2.0% general partner interest in the Partnership and (2) the Incentive Distribution Rights in the Partnership;
	•       EEP conveyed (1) all of its limited liability company interests in the OLP GP and (2) a limited partner interest in Midcoast Operating equal to 39.0% less the percentage of the GP Contribution Interest to the Partnership in exchange for (a) 4,110,056 Class A common units representing a 9.0% limited partner interest in the Partnership, (b) 22,610,056 subordinated units representing a 49.0% limited partner interest in the Partnership and (c) the right to receive $323.4 million in cash, and (d) the right to receive $304.5 million in cash as reimbursement for certain capital expenditures made with respect to certain assets of Midcoast Operating and the OLP GP;
	•        the public, through the underwriters, contributed $333.0 million in cash (or $311.8 million net of the underwriters' discount and commissions of $20.0 million and a structuring fee of $1.2 million payable to Merrill Lynch, Pierce, Fenner & Smith Incorporated) to the Partnership in exchange for 18,500,000 Class A common units; and
	•        the Partnership redeemed the initial limited partner interests of EEP and refunded EEP's initial contribution, as well as any interest or other profit that may have resulted from the investment or other use of such initial capital contribution.
	Pursuant to the Contribution Agreement, upon the exercise of the Over-Allotment Option (as defined in the Contribution Agreement), the Partnership used the net proceeds from that exercise to redeem from EEP the number of Class A common units MEP issues to the underwriters upon such exercise.
	Omnibus Agreement
	On November 13, 2013, in connection with the closing of the Offering, the Partnership entered into an Omnibus Agreement, or the Omnibus Agreement, by and among the General Partner, the Partnership, EEP and Enbridge, pursuant to which EEP will indemnify the Partnership for certain matters, including environmental, right-of-way and permit matters, and EEP will grant the Partnership a license to use the Enbridge logo and certain other trademarks and trade names.
	Credit Agreement
	On November 13, 2013, in connection with the closing of the Offering, the Partnership, Midcoast Operating and their material domestic subsidiaries, entered into a Credit Agreement, or the Credit Agreement, by and among the Partnership, as co-borrower and a guarantor, Midcoast Operating, as co-borrower and a guarantor, Bank of America, N.A., as administrative agent, letter of credit issuer, swing line lender and lender, and each of the other lenders party thereto.
	The Credit Agreement is a committed senior revolving credit facility with related letter of credit and swing line facilities that permits aggregate borrowings of up to, at any one time outstanding, $850.0 million, including up to (1) initially $90.0 million under the letter of credit facility and (2) $75.0 million under the swing line facility. Subject to customary conditions, the Partnership may request that the lenders' aggregate commitments be increased to an amount not to exceed $1.0 billion. The facility matures in three years, subject to four one-year requests for extension.
	Loans under the Credit Agreement accrue interest at a per annum rate by reference, at our election, to the Eurodollar rate, which is equal to the LIBOR rate or a comparable or successor rate reasonably approved by the Administrative Agent, or base rate, in each case, plus an applicable margin. The applicable margin on Eurodollar (LIBOR) rate loans ranges from 1.75% to 2.75% and the applicable margin on base rate loans ranges from 0.75% to 1.75%, in each case determined based upon the Partnership's total leverage ratio (as defined below) at the applicable time. A letter of credit fee is payable by the Partnership equal to the applicable margin for Eurodollar (LIBOR) rate loans times the daily amount available to be drawn under outstanding letters of credit. A commitment fee is payable by the borrowers equal to an applicable margin times the daily unused amount of the lenders' commitment, which applicable margin ranges from 0.30% to 0.50% based upon the Partnership's total leverage ratio at the applicable time.
	Each of the Partnership's domestic material subsidiaries has unconditionally guaranteed all existing and future indebtedness and liabilities of the borrowers arising under the Credit Agreement and other loan documents, and each co-borrower has guaranteed all such indebtedness and liabilities of the other co-borrower. The credit facility is unsecured but security will be provided upon occurrence of any of the following: (1) for two consecutive quarters, the Total Leverage Ratio as described below, exceeds 4.25 to 1.00 or 4.75 to 1.00 during acquisition period, (2) uncured breach to certain terms and conditions of the credit agreement and (3) obtaining a non-investment grade initial debt rating from either S&P or Moody's.
	The Credit Agreement also contains customary representations, warranties, events of default, indemnities and remedies provisions.
	Additionally, the Credit Agreement contains various covenants and restrictive provisions which limit the ability of the Partnership, Midcoast Operating and their subsidiaries to incur certain liens or permit them to exist, merge or consolidate with another company, dispose of assets, make distributions on or redeem or repurchase their equity interests, incur or guarantee additional debt, repay subordinated debt prior to maturity, make certain investments and acquisitions, alter their lines of business, enter into certain types of transactions with affiliates and enter into agreements that restrict their ability to perform certain obligations under the Credit Agreement or to make payments to a borrower or any of their material subsidiaries.
	The Credit Agreement also requires compliance with two financial covenants. The Partnership must not permit the ratio of consolidated funded debt to pro forma Earnings Before Interest, Taxes, Depreciation and Amortization, or EBITDA, or the Total Leverage Ratio, of the Partnership and its consolidated subsidiaries, including Midcoast Operating, as of the end of any applicable four-quarter period, to exceed 5.00 to 1.00, or 5.50 to 1.00 during acquisition periods. The Partnership also must maintain, on a consolidated basis, as of the end of each applicable four-quarter period, a ratio of pro forma EBITDA to consolidated interest expense for such four-quarter period then ended of at least 2.50 to 1.00.
	These covenants are subject to exceptions and qualifications set forth in the Credit Agreement. At such time as the Partnership obtains an investment grade rating from either Moody's or S&P, certain covenants under the Credit Agreement will no longer be applicable to either the borrowers or the guarantors, or in some instances, any of them, including, but not limited to, the obligation to provide security in certain circumstances, certain restrictions on liens, investments and debt, and restrictions on dispositions.
	Intercorporate Services Agreement
	On November 13, 2013, in connection with the closing of the Offering, the Partnership entered into an Intercorporate Service Agreement, or the Intercorporate Services Agreement, with EEP, pursuant to which EEP will provide the Partnership with the following services:
	•       executive, management, business development, administrative, legal, human resources, records and information management, public affairs, investor relations, government relations and computer support services;
	•       accounting and tax planning and compliance services, including preparation of financial statements and income tax returns, unitholder tax reporting and audit and treasury services;
	•        strategic insurance advice, planning and claims management and related support services, and arrangement of insurance coverage as required;
	•        facilitation of capital markets access and financing services, cash management and related banking services, financial structuring and advisory services, as well as credit support for the Partnership's subsidiaries and affiliates on an as-needed basis for projects, transactions or other purposes;
	•        operational and technical services, including integrity, safety, environmental, project management, engineering, fundamentals analysis and regulatory, and pipeline control and field operations; and
	•        such other services as the Partnership may request.
	Under the Intercorporate Services Agreement, the Partnership will reimburse EEP and its affiliates for the costs and expenses incurred in providing such services to the Partnership. The allocation methodology under which the Partnership will reimburse EEP and its affiliates for the provision of general administrative and operational services to Midcoast Operating will not differ from what Midcoast Operating was allocated historically under its prior services agreements with Enbridge and certain of its affiliates that were in effect prior to the Intercorporate Services Agreement. However, EEP has agreed to reduce the amounts payable for general and administrative expenses that otherwise would have been allocable to Midcoast Operating by $25.0 million annually. Based on the Partnership's 39% interest in Midcoast Operating, the reduction in amounts payable for general and administrative services attributable to the Partnership will be approximately $9.8 million annually and will continue for the term of the agreement.
	Financial Support Agreement
	On November 13, 2013, in connection with the closing of the Offering, Midcoast Operating entered into a Financial Support Agreement, or the Financial Support Agreement, between Midcoast Operating and EEP, pursuant to which EEP will provide letters of credit and guarantees, not to exceed $700.0 million in the aggregate at any time outstanding, in support of Midcoast Operating's and its wholly owned subsidiaries' financial obligations under derivative agreements and natural gas and NGL purchase agreements to which Midcoast Operating, or one or more of its wholly owned subsidiaries, is a party. This agreement terminates after four years, or earlier, when EEP owns less than 20% of the limited partnership interests in Midcoast Operating.
	The annual costs that Midcoast Operating initially estimates that it will incur under the Financial Support Agreement range from approximately $4.0 million to $5.0 million and are based on the cumulative average amount of letters of credit and guarantees that EEP will provide on Midcoast Operating's and its wholly owned subsidiaries' behalf multiplied by a 2.5% annual fee. If the Credit Agreement is secured, the Financial Support Agreement will also be secured to the same extent on a second-lien basis.
	Amended and Restated Allocation Agreement
	On November 13, 2013, in connection with the closing of the Offering, the Partnership entered into an Amended and Restated Allocation Agreement, or the Insurance Allocation Agreement, by and among the Partnership, Enbridge, EEP and Enbridge Income Fund Holdings Inc., in order to participate in the comprehensive insurance program that is maintained by Enbridge for it and its subsidiaries. Under this agreement, in the unlikely event that multiple insurable incidents occur that exceed coverage limits within the same insurance period, the total insurance coverage available to Enbridge and its subsidiaries under the insurance program will be allocated among the participating Enbridge entities on an equitable basis.
	Working Capital Credit Facility
	On November 13, 2013, in connection with the closing of the Offering, Midcoast Operating entered into a $250.0 million Working Capital Loan Agreement, or the Working Capital Credit Facility, by and between Midcoast Operating, as borrower, and EEP, as lender. The facility is available exclusively to fund working capital borrowings. Borrowings under the facility are scheduled to mature on November 13, 2017 and accrue interest at a per annum rate of LIBOR plus 2.5%. Midcoast Operating has agreed to pay a commitment fee on the unused commitment at a per annum rate of 0.4250%, payable each fiscal quarter. EEP's commitment to lend pursuant to the Working Capital Credit Facility will end on the earlier of the maturity date and the date on which EEP owns less than a 20% limited partner interest in Midcoast Operating. If EEP's commitment to lend has terminated before the facility has matured (by acceleration or otherwise), then the aggregate amount of all outstanding borrowings under the facility will automatically convert to a term loan that will bear interest at LIBOR (calculated as of the conversion date) plus 2.5%. The Working Capital Credit Facility also contains certain customary representations, warranties, indemnities, events of default and remedies provisions and also provides that if the Credit Agreement is secured, the Working Capital Credit Facility also will be secured to the same extent on a second-lien basis.
	Amended and Restated Agreement of Limited Partnership of Midcoast Operating, L.P.
	On November 13, 2013, in connection with the closing of the Offering, the OLP GP, the Partnership and EEP entered into the Amended and Restated Agreement of Limited Partnership of Midcoast Operating, or as amended and restated, the Midcoast Operating LP Agreement. Based on the Partnership's sole ownership of the OLP GP, it has the sole responsibility for managing the operations of Midcoast Operating. However, the Midcoast Operating LP Agreement provides that certain actions of Midcoast Operating will require the unanimous approval of all the partners. These actions include the following:
	•       any reorganization, merger, consolidation or similar transaction;
	•        any new class of partnership interests or the issuance of any additional partnership interests;
	•        any admission or withdrawal of any person as partner other than in accordance with the Midcoast Operating LP Agreement;
	•        any modification, alteration or amendment of the amount, timing, frequency or method of calculation of distributions to the partners;
	•        any sale or lease of all or substantially all of Midcoast Operating's assets;
	•        causing or permitting Midcoast Operating to file an application for bankruptcy; and
	•        approving any distribution and determination of value by Midcoast Operating of any assets in kind or the approval of any distribution of any cash or property on a non-pro rata basis.
	Under the Midcoast Operating LP Agreement, the Partnership and EEP each have the option to contribute its proportionate share of additional capital to Midcoast Operating if any additional capital contributions are necessary to fund capital expenditures or other growth projects. To the extent that the Partnership or EEP elect not to make any such capital contributions, the contributing party will be permitted to make additional capital contributions in exchange for additional interests in Midcoast Operating.
	The Midcoast Operating LP Agreement provides that Midcoast Operating will distribute all distributable cash of Midcoast Operating to the Partnership and EEP on a pro rata basis within 45 days of the end of each quarter.
	First Amended and Restated Agreement of Limited Partnership of Midcoast Energy Partners, L.P.
	On November 13, 2013, in connection with the closing of the Offering, the Partnership amended and restated its agreement of limited partnership and entered into its First Amended and Restated Agreement of Limited Partnership, or as amended and restated, the Partnership Agreement. A description of the Partnership Agreement is contained in the Prospectus in the sections entitled Provisions of Our Partnership Agreement Relating to Cash Distributions and Our Partnership Agreement, all of which are incorporated herein by reference.
	Exercise of the Underwriters' Option
	On December 9, 2013, the Partnership closed the sale of an additional 2,775,000 Class A common units representing limited partner interests in connection with the Offering. The Partnership used the net proceeds of approximately $47.0 million from the exercise of the option to redeem 2,775,000 Class A common units from EEP. Upon redemption of the Class A common units from EEP, the public owned a 46% limited partner interest in Midcoast Partners. EEP, through certain of its subsidiaries, holds a 2% general partner interest and owns the remaining limited partner interest in Midcoast Partners.

Basis_of_Presentation_Tables

Basis of Presentation (Tables)	9 Months Ended
	Sep. 30, 2013
Limited Liability Company or Limited Partnership, Summary of Ownership Structure [Abstract]	'
Schedule Of Ownership In Partnership [Table Text Block]	'
			30-Sep-13		31-Dec-12
		Limited partner interests	99.999	%	99.999	%
		General partner interests	0.001	%	0.001	%

Inventory_Tables

Inventory (Tables)	9 Months Ended
	Sep. 30, 2013
Inventory	'
Schedule Of Inventory	'
		Our inventory is comprised of the following:
			September 30,		December 31,
			2013		2012
			(in millions)
		Materials and supplies	$	0.6	$	0.4
		Crude oil inventory		11.5		10.1
		Natural gas and NGL inventory		132.5		64.3
			$	144.6	$	74.8

Property_Plant_And_Equipment_T

Property, Plant And Equipment (Tables)	9 Months Ended
	Sep. 30, 2013
Property, Plant And Equipment	'
Schedule Of Property, Plant And Equipment	'
	Our property, plant and equipment is comprised of the following:
				September 30,		December 31,
				2013		2012
				(in millions)
		Land		$	11.3	$	8.7
		Rights-of-way			374.1		340.3
		Pipelines			1,724.70		1,603.80
		Pumping equipment, buildings and tanks			88.7		65.4
		Compressors, meters and other operating equipment			1,953.40		1,755.70
		Vehicles, office furniture and equipment			146.5		133
		Processing and treating plants			511.3		489.8
		Construction in progress			184		402.2
			Total property, plant and equipment		4,994.00		4,798.90
		Accumulated depreciation			-935.7		-835.9
			Property, plant and equipment, net	$	4,058.30	$	3,963.00

Related_Party_Transactions_Tab

Related Party Transactions (Tables)	9 Months Ended
	Sep. 30, 2013
Related Party Transactions [Abstract]	'
Schedule Of Cash Activity For A1 Credit Facility And A1 Term Note	'
			For the three month period				For the nine month period
			ended September 30,				ended September 30,
			2013		2012		2013		2012
			(unaudited; in millions)
	Operating and maintenance - affiliate		$	27.3	$	26.6	$	81.4	$	81.2
	General and administrative - affiliate			25		24		73		71.8
		Total	$	52.3	$	50.6	$	154.4	$	153
Schedule of Distributions To Series AC Interests	'
			For the three month period				For the nine month period
			ended September 30,				ended September 30,
			2013		2012		2013		2012
			(unaudited; in millions)
	Interest expense		$	5.1	$	1.6	$	16.6	$	4.6
	Interest capitalized			5.1		1.6		16.6		4.6
	Interest cost incurred		$	-	$	-	$	-	$	-
	Interest cost paid		$	5.1	$	1.6	$	16.6	$	4.6

Derivative_Financial_Instrumen1

Derivative Financial Instruments And Hedging Activities (Tables)	9 Months Ended
	Sep. 30, 2013
Derivative Financial Instruments And Hedging Activities	'
Schedule Of Derivative Instruments In Statement Of Financial Position, Fair Value	'
	Derivative Positions
	Our derivative financial instruments are included at their fair values in the consolidated statements of financial position as follows:
				September 30,			December 31,
				2013			2012
				(in millions)
		Other current assets		$	138.3		$	275
		Other assets, net			72.5			78.1
		Accounts payable and other			-151.2			-259.9
		Other long-term liabilities			-64			-78
				$	-4.4		$	15.2
Schedule Of Derivative Balances By Counter Party Credit Quality	'
	The table below summarizes our derivative balances by counterparty credit quality (negative amounts represent our net obligations to pay the counterparty).
				September 30,			December 31,
				2013			2012
				(in millions)
		Counterparty Credit Quality (1)
		AAA		$	0.1		$	-
		AA			-57.8			-116.6
		A			-84.5			-150.4
		Lower than A			137.8			282.2
				$	-4.4		$	15.2
		______________________________
		(1)As determined by nationally-recognized statistical ratings organizations.
				September 30,			December 31,
				2013			2012
				(in millions)
		Counterparty Credit Quality (1)
		AAA		$	0.1		$	-
		AA			-57.8			-116.6
		A			-84.5			-150.4
		Lower than A			137.8			282.2
				$	-4.4		$	15.2
		______________________________
		(1)As determined by nationally-recognized statistical ratings organizations.
Schedule Of Credit Concentrations In Industry Sectors	'
	At September 30, 2013 and December 31, 2012, we had credit concentrations in the following industry sectors, as presented below:
				September 30,			December 31,
				2013			2012
				(in millions)
		United States financial institutions and investment banking entities		$	-114.5		$	-204.7
		Non-United States financial institutions			-28			-87.4
		Integrated oil companies			-3.8			4.5
		General Partner and affiliates			143.1			297.2
		Other			-1.2			5.6
				$	-4.4		$	15.2
Effect Of Derivative Instruments On The Consolidated Statements Of Financial Position	'
	Effect of Derivative Instruments on the Consolidated Statements of Financial Position
						Asset Derivatives						Liability Derivatives
						Fair Value at						Fair Value at
				Financial Position		September 30,			December 31,			September 30,			December 31,
				Location		2013			2012(3)			2013			2012(3)
						(in millions)
	Derivatives designated as
		hedging instruments(1)
	Commodity contracts			Other current assets		$	2.4		$	12.2		$	-1.8		$	-4.2
	Commodity contracts			Other assets, net			4.8			2.5			-1.2			-1.1
	Commodity contracts			Accounts payable and other			4.2			4.7			-8.5			-5.7
	Commodity contracts			Other long-term liabilities			0.2			2			-1.2			-4.5
							11.6			21.4			-12.7			-15.5
	Derivatives not designated
		as hedging instruments
	Interest rate contracts			Other current assets(2)			123			246.9			-			-
	Interest rate contracts			Other assets, net(2)			83.2			68.3			-27.9			-3.3
	Interest rate contracts			Accounts payable and other(2)			-			-			-123			-246.9
	Interest rate contracts			Other long-term liabilities(2)			2.3			3.3			-57.6			-68.3
	Commodity contracts			Other current assets(2)			17.2			27.2			-2.5			-7.1
	Commodity contracts			Other assets, net(2)			14.4			11.8			-0.9			-0.1
	Commodity contracts			Accounts payable and other(2)			9.2			0.8			-32.9			-12.8
	Commodity contracts			Other long-term liabilities(2)			0.2			1.6			-8			-12.1
							249.5			359.9			-252.8			-350.6
	Total derivative instruments					$	261.1		$	381.3		$	-265.5		$	-366.1
	______________________________
	(1)	Includes items currently designated as hedging instruments. Excludes the portion of de-designated hedges which may have a component remaining in AOCI.
	(2)	Includes both affiliate and third party transactions.
	(3)	The effect of derivative instruments on the consolidated statements of financial position, as of December 31, 2012, was revised to disclose the financial position location on a gross basis. The revisions to the disclosures are not considered material to and had no impact on amounts previously reported in the consolidated statements of financial position.
Effect Of Derivative Instruments On The Consolidated Statements Of Income And Accumulated Other Comprehensive Income	'
	Effect of Derivative Instruments on the Consolidated Statements of Income and Accumulated Other Comprehensive Income
																Amount of gain
																(loss) recognized in
													Location of gain			earnings on
													(loss) recognized in			derivative
													earnings on  derivative			(Ineffective Portion
				Amount of gain									(Ineffective Portion			and Amount
	Derivatives in Cash			(loss) recognized in			Location of gain (loss)			Amount of gain (loss)			and Amount			Excluded from
	Flow Hedging			AOCI on Derivative			reclassified from			reclassified from			Excluded from			Effectiveness
	Relationships			(Effective Portion)			AOCI to earnings			AOCI to earnings			Effectiveness Testing)(1)			Testing)(1)
		(in millions)
	For the three month period ended September 30, 2013
							Cost of natural gas and						Cost of natural gas and
	Commodity contracts			$	-17.2			natural gas liquids		$	-0.6			natural gas liquids		$	-0.5
	Total			$	-17.2					$	-0.6					$	-0.5
	For the three month period ended September 30, 2012
							Cost of natural gas and						Cost of natural gas and
	Commodity contracts			$	-22.9			natural gas liquids		$	4.6			natural gas liquids		$	-3.9
	Total			$	-22.9					$	4.6					$	-3.9
	For the nine month period ended September 30, 2013
							Cost of natural gas and						Cost of natural gas and
	Commodity contracts			$	-8.8			natural gas liquids		$	3			natural gas liquids		$	1.8
	Total			$	-8.8					$	3					$	1.8
	For the nine month period ended September 30, 2012
							Cost of natural gas and						Cost of natural gas and
	Commodity contracts			$	47.2			natural gas liquids		$	-3.4			natural gas liquids		$	1.2
	Total			$	47.2					$	-3.4					$	1.2
	______________________________
	(1)	Includes only the ineffective portion of derivatives that are designated as hedging instruments and does not include net gains or losses associated with derivatives that do not qualify for hedge accounting treatment.
Components Of Accumulated Other Comprehensive Income	'
	Components of Accumulated Other Comprehensive Income/(Loss)
					Cash Flow
					Hedges
					(in millions)
	Balance at December 31, 2012				$	7.1
		Other comprehensive income (loss) before reclassifications				-2.7
		Amounts reclassified from AOCI (1)				-3
			Net other comprehensive income (loss)			-5.7
	Balance at September 30, 2013				$	1.4
	_______________________________________
	(1)For additional details on the amounts reclassified from AOCI, reference the Reclassifications from Accumulated Other Comprehensive Income table below.
Reclassifications from Accumulated Other Comprehensive Income	'
	Reclassifications from Accumulated Other Comprehensive Income
					For the three month period ended September 30,						For the nine month period ended September 30,
					2013			2012			2013			2012
					(in millions)
	Losses (gains) on cash flow hedges:
		Commodity Contracts (1)			$	0.6		$	-4.6		$	-3		$	3.4
			Total Reclassifications from AOCI		$	0.6		$	-4.6		$	-3		$	3.4
	______________________________
	(1)Loss (gain) reported within “Cost of natural gas and natural gas liquids" in the consolidated statements of income.
Effect Of Derivative Instruments On Consolidated Statements Of Income	'
	Effect of Derivative Instruments on Consolidated Statements of Income
							For the three month period						For the nine month period
							ended September 30,						ended September 30,
							2013			2012			2013			2012
	Derivatives Not Designated			Location of Gain or (Loss)			Amount of Gain or (Loss)						Amount of Gain or  (Loss)
	as Hedging Instruments			Recognized in Earnings(1)			Recognized in Earnings(2)						Recognized in Earnings(2)
							(in millions)
				Cost of natural gas and
	Commodity contracts				natural gas liquids(3)		$	-28.1		$	-12.4		$	-8.9		$	21.7
	Commodity contracts			Operating revenue				-6.2			-			-6.2			-
	Total						$	-34.3		$	-12.4		$	-15.1		$	21.7
	________________________
	(1)	Does not include settlements associated with derivative instruments that settle through physical delivery.
	(2)	Includes only net gains or losses associated with those derivatives that do not qualify for hedge accounting treatment and does not include the ineffective portion of derivatives that are designated as hedging instruments.
	(3)	Includes settlements losses of $0.2 million for the three month period ended September 30, 2013, settlement gains of $8.3 million for the three month period ended September 30, 2012 and settlement gains of $0.5 million and $15.0 million for the nine month periods ended September 30, 2013 and September 30, 2012, respectively.
Gross To Net Presentation Reconciliation Of Derivative Assets And Liabilities	'
	Gross to Net Presentation Reconciliation of Derivative Assets and Liabilities
			30-Sep-13									December 31, 2012
			Assets			Liabilities			Total			Assets			Liabilities			Total
			(in millions)
	Fair value of derivatives—gross presentation		$	261.1		$	-265.5		$	-4.4		$	381.3		$	-366.1		$	15.2
	Effects of netting agreements			-50.3			50.3			-			-28.2			28.2			-
	Fair value of derivatives—net presentation		$	210.8		$	-215.2		$	-4.4		$	353.1		$	-337.9		$	15.2
Offsetting Of Financial Assets And Derivative Assets	'
	Offsetting of Financial Assets and Derivative Assets
					As of September 30, 2013
					Gross			Gross Amount			Net Amount of Assets			Gross Amount
					Amount of			Offset in the			Presented in the			Not Offset in the
					Recognized			Statement of			Statement of			Statement of			Net
					Assets			Financial Position			Financial Position			Financial Position			Amount
					(in millions)
	Description:
		Derivatives			$	261.1		$	-50.3		$	210.8		$	-4.8		$	206
			Total		$	261.1		$	-50.3		$	210.8		$	-4.8		$	206
Offsetting Of Financial Liabilities And Derivative Liabilities	'
	Offsetting of Financial Liabilities and Derivative Liabilities
					As of September 30, 2013
					Gross			Gross Amount			Net Amount of Liabilities			Gross Amount
					Amount of			Offset in the			Presented in the			Not Offset in the
					Recognized			Statement of			Statement of			Statement of			Net
					Liabilities			Financial Position			Financial Position			Financial Position			Amount
					(in millions)
	Description:
		Derivatives			$	-265.5		$	50.3		$	-215.2		$	4.8		$	-210.4
			Total		$	-265.5		$	50.3		$	-215.2		$	4.8		$	-210.4
Table Setting Forth By Level Within The Fair Value Hierarchy Financial Assets And Liabilities	'
	Inputs to Fair Value Derivative Instruments
	The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2013 and December 31, 2012. We classify financial assets and liabilities in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect our valuation of the financial assets and liabilities and their placement within the fair value hierarchy.
				30-Sep-13												December 31, 2012
				Level 1			Level 2			Level 3			Total			Level 1			Level 2			Level 3			Total
				(in millions)
	Commodity contracts:
		Financial		$	-		$	-7		$	0.8		$	-6.2		$	-		$	-7		$	8.4		$	1.4
		Physical			-			-			-5.1			-5.1			-			-			7.4			7.4
	Commodity options				-			-			6.9			6.9			-			-			6.4			6.4
	Total			$	-		$	-7		$	2.6		$	-4.4		$	-		$	-7		$	22.2		$	15.2
Schedule Of Reconciliation Of Changes In Fair Value Of Level 3 Financial Assets And Liabilities	'
	Level 3 Fair Value Reconciliation
	The table below provides a reconciliation of changes in the fair value of our Level 3 financial assets and liabilities measured on a recurring basis from January 1, 2013 to September 30, 2013. No transfers of assets between any of the Levels occurred during the period.
					Commodity			Commodity
					Financial			Physical			Commodity
					Contracts			Contracts			Options			Total
					(in millions)
	Beginning balance as of January 1, 2013				$	8.4		$	7.4		$	6.4		$	22.2
		Transfer out of Level 3 (1)				-			-			-			-
	Gains or losses:
		Included in earnings (or changes in net assets)				1.7			21.7			-0.5			22.9
		Included in other comprehensive income				3.4			-			-			3.4
	Purchases, issuances, sales and settlements:
		Purchases				-			-			3			3
		Settlements (2)				-12.7			-34.2			-2			-48.9
	Ending balance as of September 30, 2013				$	0.8		$	-5.1		$	6.9		$	2.6
	Amount of changes in net assets attributable to the change in unrealized
		gains or losses related to assets still held at the reporting date			$	0.6		$	-6.2		$	4		$	-1.6
	Amounts reported in operating revenue				$	-		$	-6.2		$	-		$	-6.2
	_________________
	(1)	Our policy is to recognize transfers as of the last day of the reporting period.
	(2)	Settlements represent the realized portion of forward contracts.
Schedule Of Fair Values Of Expected Cash Flows Of Outstanding Commodity Based Swaps And Physical Contracts	'
	Fair Value Measurements of Commodity Derivatives
	The following table provides summarized information about the fair values of expected cash flows of our outstanding commodity based swaps and physical contracts at September 30, 2013 and December 31, 2012.
					At September 30, 2013																At December 31, 2012
									Wtd. Average Price (2)						Fair Value (3)						Fair Value (3)
					Commodity		Notional (1)		Receive			Pay			Asset			Liability			Asset			Liability
	Portion of contracts maturing in 2013
		Swaps
			Receive variable/pay fixed		Natural Gas		1,058,748		$	3.49		$	3.59		$	0.1		$	-0.2		$	0.2		$	-0.3
					NGL		985,200		$	46.8		$	45.4		$	1.8		$	-0.5		$	1.4		$	-
					Crude Oil		257,664		$	101.36		$	102.95		$	0.2		$	-0.7		$	0.2		$	-3.9
			Receive fixed/pay variable		Natural Gas		2,361,000		$	4.36		$	3.55		$	1.9		$	-		$	7.8		$	-
					NGL		1,854,028		$	50.19		$	52.46		$	3		$	-7.2		$	9.3		$	-9.9
					Crude Oil		591,548		$	94.24		$	101.48		$	0.6		$	-4.8		$	6.3		$	-8.8
			Receive variable/pay variable		Natural Gas		13,277,500		$	3.53		$	3.51		$	0.3		$	-0.1		$	1.2		$	-0.2
		Physical Contracts
			Receive variable/pay fixed		NGL		2,330,976		$	37.27		$	36.89		$	3.3		$	-2.4		$	0.6		$	-0.8
					Crude Oil		255,010		$	102.19		$	105.97		$	-		$	-1		$	0.4		$	-0.4
			Receive fixed/pay variable		NGL		3,844,386		$	39.72		$	41.85		$	3.3		$	-11.4		$	2.6		$	-2.2
					Crude Oil		339,200		$	105.55		$	102.04		$	1.2		$	-		$	0.2		$	-1
			Receive variable/pay variable		Natural Gas		19,866,685		$	3.53		$	3.52		$	0.3		$	-0.2		$	0.9		$	-
					NGL		6,135,041		$	47.4		$	47.2		$	3.6		$	-2.4		$	5.2		$	-2.3
					Crude Oil		1,120,690		$	98.78		$	99.06		$	1.4		$	-1.7		$	6.4		$	-3
	Portion of contracts maturing in 2014
		Swaps
			Receive variable/pay fixed		Natural Gas		21,870		$	3.75		$	5.22		$	-		$	-		$	-		$	-
					NGL		286,250		$	82.33		$	83.05		$	-		$	-0.2		$	-		$	-
					Crude Oil		506,255		$	95.33		$	101.95		$	-		$	-3.3		$	-		$	-5
			Receive fixed/pay variable		Natural Gas		3,006,890		$	3.97		$	3.73		$	0.7		$	-		$	0.2		$	-
					NGL		2,208,800		$	53.93		$	53.67		$	5.6		$	-5		$	0.9		$	-2.7
					Crude Oil		1,573,205		$	94.43		$	95.41		$	3.6		$	-5.2		$	5.4		$	-2.7
			Receive variable/pay variable		Natural Gas		13,842,500		$	3.77		$	3.76		$	0.2		$	-		$	0.1		$	-0.1
		Physical Contracts
			Receive variable/pay fixed		NGL		45,000		$	43.79		$	45.45		$	-		$	-0.1		$	-		$	-
			Receive fixed/pay variable		NGL		325,617		$	53.43		$	55.69		$	0.1		$	-0.8		$	-		$	-
			Receive variable/pay variable		Natural Gas		34,169,685		$	3.77		$	3.76		$	0.9		$	-0.4		$	0.5		$	-
					NGL		7,037,705		$	33.02		$	32.9		$	1.8		$	-0.9		$	-		$	-
	Portion of contracts maturing in 2015
		Swaps
			Receive variable/pay fixed		Crude Oil		515,015		$	88.53		$	100.93		$	-		$	-6.3		$	-		$	-5.6
			Receive fixed/pay variable		NGL		292,000		$	56.76		$	54.04		$	1.2		$	-0.5		$	0.7		$	-0.2
					Crude Oil		865,415		$	97.72		$	88.53		$	7.9		$	-		$	6.8		$	-0.2
			Receive variable/pay variable		Natural Gas		900,000		$	4.05		$	4.04		$	-		$	-		$	-		$	-
		Physical Contracts
			Receive variable/pay variable		Natural Gas		8,541,825		$	4.1		$	4.06		$	0.5		$	-0.1		$	0.4		$	-
	Portion of contracts maturing in 2016
		Swaps
			Receive fixed/pay variable		Crude Oil		45,750		$	99.31		$	84.81		$	0.6		$	-		$	0.5		$	-
		Physical Contracts
			Receive variable/pay variable		Natural Gas		783,240		$	4.28		$	4.17		$	0.1		$	-		$	0.1		$	-
	______________________________
	(1)	Volumes of natural gas are measured in MMBtu, whereas volumes of NGL and crude oil are measured in Bbl.
	(2)	Weighted average prices received and paid are in $/MMBtu for natural gas and $/Bbl for NGL and crude oil.
	(3)	The fair value is determined based on quoted market prices at September 30, 2013 and December 31, 2012, respectively, discounted using the swap rate for the respective periods to consider the time value of money. Fair values are presented in millions of dollars and exclude credit valuation adjustments of approximately $0.2 million of losses at September 30, 2013 and $0.2 million of losses at December 31, 2012.
	Fair Value Measurements of Commodity Derivatives
	The following table provides summarized information about the fair values of expected cash flows of our outstanding commodity based swaps and physical contracts at September 30, 2013 and December 31, 2012.
					At September 30, 2013																At December 31, 2012
									Wtd. Average Price (2)						Fair Value (3)						Fair Value (3)
					Commodity		Notional (1)		Receive			Pay			Asset			Liability			Asset			Liability
	Portion of contracts maturing in 2013
		Swaps
			Receive variable/pay fixed		Natural Gas		1,058,748		$	3.49		$	3.59		$	0.1		$	-0.2		$	0.2		$	-0.3
					NGL		985,200		$	46.8		$	45.4		$	1.8		$	-0.5		$	1.4		$	-
					Crude Oil		257,664		$	101.36		$	102.95		$	0.2		$	-0.7		$	0.2		$	-3.9
		Receive fixed/pay variable		Natural Gas		2,361,000		$	4.36		$	3.55		$	1.9		$	-		$	7.8		$	-
				NGL		1,854,028		$	50.19		$	52.46		$	3		$	-7.2		$	9.3		$	-9.9
				Crude Oil		591,548		$	94.24		$	101.48		$	0.6		$	-4.8		$	6.3		$	-8.8
		Receive variable/pay variable		Natural Gas		13,277,500		$	3.53		$	3.51		$	0.3		$	-0.1		$	1.2		$	-0.2
	Physical Contracts
		Receive variable/pay fixed		NGL		2,330,976		$	37.27		$	36.89		$	3.3		$	-2.4		$	0.6		$	-0.8
				Crude Oil		255,010		$	102.19		$	105.97		$	-		$	-1		$	0.4		$	-0.4
		Receive fixed/pay variable		NGL		3,844,386		$	39.72		$	41.85		$	3.3		$	-11.4		$	2.6		$	-2.2
				Crude Oil		339,200		$	105.55		$	102.04		$	1.2		$	-		$	0.2		$	-1
		Receive variable/pay variable		Natural Gas		19,866,685		$	3.53		$	3.52		$	0.3		$	-0.2		$	0.9		$	-
				NGL		6,135,041		$	47.4		$	47.2		$	3.6		$	-2.4		$	5.2		$	-2.3
				Crude Oil		1,120,690		$	98.78		$	99.06		$	1.4		$	-1.7		$	6.4		$	-3
Portion of contracts maturing in 2014
	Swaps
		Receive variable/pay fixed		Natural Gas		21,870		$	3.75		$	5.22		$	-		$	-		$	-		$	-
				NGL		286,250		$	82.33		$	83.05		$	-		$	-0.2		$	-		$	-
				Crude Oil		506,255		$	95.33		$	101.95		$	-		$	-3.3		$	-		$	-5
		Receive fixed/pay variable		Natural Gas		3,006,890		$	3.97		$	3.73		$	0.7		$	-		$	0.2		$	-
				NGL		2,208,800		$	53.93		$	53.67		$	5.6		$	-5		$	0.9		$	-2.7
				Crude Oil		1,573,205		$	94.43		$	95.41		$	3.6		$	-5.2		$	5.4		$	-2.7
		Receive variable/pay variable		Natural Gas		13,842,500		$	3.77		$	3.76		$	0.2		$	-		$	0.1		$	-0.1
	Physical Contracts
		Receive variable/pay fixed		NGL		45,000		$	43.79		$	45.45		$	-		$	-0.1		$	-		$	-
		Receive fixed/pay variable		NGL		325,617		$	53.43		$	55.69		$	0.1		$	-0.8		$	-		$	-
		Receive variable/pay variable		Natural Gas		34,169,685		$	3.77		$	3.76		$	0.9		$	-0.4		$	0.5		$	-
				NGL		7,037,705		$	33.02		$	32.9		$	1.8		$	-0.9		$	-		$	-
Portion of contracts maturing in 2015
	Swaps
		Receive variable/pay fixed		Crude Oil		515,015		$	88.53		$	100.93		$	-		$	-6.3		$	-		$	-5.6
		Receive fixed/pay variable		NGL		292,000		$	56.76		$	54.04		$	1.2		$	-0.5		$	0.7		$	-0.2
				Crude Oil		865,415		$	97.72		$	88.53		$	7.9		$	-		$	6.8		$	-0.2
		Receive variable/pay variable		Natural Gas		900,000		$	4.05		$	4.04		$	-		$	-		$	-		$	-
	Physical Contracts
		Receive variable/pay variable		Natural Gas		8,541,825		$	4.1		$	4.06		$	0.5		$	-0.1		$	0.4		$	-
Portion of contracts maturing in 2016
	Swaps
		Receive fixed/pay variable		Crude Oil		45,750		$	99.31		$	84.81		$	0.6		$	-		$	0.5		$	-
	Physical Contracts
		Receive variable/pay variable		Natural Gas		783,240		$	4.28		$	4.17		$	0.1		$	-		$	0.1		$	-
______________________________
(1)	Volumes of natural gas are measured in MMBtu, whereas volumes of NGL and crude oil are measured in Bbl.
(2)	Weighted average prices received and paid are in $/MMBtu for natural gas and $/Bbl for NGL and crude oil.
(3)	The fair value is determined based on quoted market prices at September 30, 2013 and December 31, 2012, respectively, discounted using the swap rate for the respective periods to consider the time value of money. Fair values are presented in millions of dollars and exclude credit valuation adjustments of approximately $0.2 million of losses at September 30, 2013 and $0.2 million of losses at December 31, 2012.
Schedule Of Fair Values Of Expected Cash Flows Of Outstanding Commodity Options	'
	The following table provides summarized information about the fair values of expected cash flows of our outstanding commodity options at September 30, 2013 and December 31, 2012.
					At September 30, 2013																At December 31, 2012
									Strike			Market			Fair Value (3)						Fair Value (3)
					Commodity		Notional (1)		Price (2)			Price (2)			Asset			Liability			Asset			Liability
	Portion of option contracts maturing in 2013
			Puts (purchased)		Natural Gas		414,000		$	4.18		$	3.48		$	0.3		$	-		$	1.4		$	-
					NGL		138,000		$	31.26		$	27.76		$	1.1		$	-		$	3.7		$	-
			Puts (written)		NGL		69,000		$	26.18		$	10.68		$	-		$	-1.1		$	-		$	-
	Portion of option contracts maturing in 2014
			Puts (purchased)		NGL		401,500		$	52.21		$	50.44		$	3.1		$	-		$	1.3		$	-
			Calls (written)		NGL		273,750		$	57.93		$	48.65		$	-		$	-0.9		$	-		$	-
	Portion of option contracts maturing in 2015
			Puts (purchased)		NGL		547,500		$	53.76		$	52.52		$	4.5		$	-		$	-		$	-
	______________________________
	(1)	Volumes of natural gas are measured in MMBtu, whereas volumes of NGL and crude oil are measured in Bbl.
	(2)	Strike and market prices are in $/MMBtu for natural gas and in $/Bbl for NGL and crude oil.
	(3)	The fair value is determined based on quoted market prices at September 30, 2013 and December 31, 2012, respectively, discounted using the swap rate for the respective periods to consider the time value of money.
	The following table provides summarized information about the fair values of expected cash flows of our outstanding commodity options at September 30, 2013 and December 31, 2012.
					At September 30, 2013																At December 31, 2012
									Strike			Market			Fair Value (3)						Fair Value (3)
					Commodity		Notional (1)		Price (2)			Price (2)			Asset			Liability			Asset			Liability
	Portion of option contracts maturing in 2013
			Puts (purchased)		Natural Gas		414,000		$	4.18		$	3.48		$	0.3		$	-		$	1.4		$	-
					NGL		138,000		$	31.26		$	27.76		$	1.1		$	-		$	3.7		$	-
			Puts (written)		NGL		69,000		$	26.18		$	10.68		$	-		$	-1.1		$	-		$	-
	Portion of option contracts maturing in 2014
			Puts (purchased)		NGL		401,500		$	52.21		$	50.44		$	3.1		$	-		$	1.3		$	-
			Calls (written)		NGL		273,750		$	57.93		$	48.65		$	-		$	-0.9		$	-		$	-
	Portion of option contracts maturing in 2015
			Puts (purchased)		NGL		547,500		$	53.76		$	52.52		$	4.5		$	-		$	-		$	-
	______________________________
	(1)	Volumes of natural gas are measured in MMBtu, whereas volumes of NGL and crude oil are measured in Bbl.
	(2)	Strike and market prices are in $/MMBtu for natural gas and in $/Bbl for NGL and crude oil.
	(3)	The fair value is determined based on quoted market prices at September 30, 2013 and December 31, 2012, respectively, discounted using the swap rate for the respective periods to consider the time value of money.
Schedule Of Quantitative Information On Level 3 Fair Value Measurements	'
	Quantitative Information About Level 3 Fair Value Measurements
				Fair Value at							Range (1)
				September 30,			Valuation		Unobservable				Weighted
	Contract Type			2013 (2)			Technique		Input		Lowest	Highest	Average	Units
	Commodity Contracts - Financial			(in millions)
		Natural Gas		$	2.6		Market Approach		Forward Gas Price		3.24	4.19	3.69	MMBtu
		NGLs		$	-1.8		Market Approach		Forward NGL Price		0.25	2.08	1.25	Gal
	Commodity Contracts - Physical
		Natural Gas		$	0.9		Market Approach		Forward Gas Price		3.24	4.35	3.72	MMBtu
		Crude Oil		$	-1.1		Market Approach		Forward Crude Price		83.41	107.67	99.42	Bbl
		NGLs		$	-4.9		Market Approach		Forward NGL Price		0.01	2.28	0.95	Gal
	Commodity Options
		Natural Gas, Crude and NGLs		$	6.9		Option Model		Option Volatility		24%	145%	41%
	Total Fair Value			$	2.6
	_______________________________________
	(1)	Prices are in dollars per Millions of British Thermal Units, or MMBtu, for Natural Gas, dollars per Gallon, or Gal, for NGLs and dollars per barrel, or Bbl, for Crude Oil.
	(2)	Fair values are presented in millions of dollars and include credit valuation adjustments of approximately $0.3 million of losses.
	Quantitative Information About Level 3 Fair Value Measurements
				Fair Value at							Range(1)
				December 31,			Valuation		Unobservable				Weighted
	Contract Type			2012(2)			Technique		Input		Lowest	Highest	Average	Units
	Commodity Contracts - Financial			(in millions)
		Natural Gas		$	8.8		Market Approach		Forward Gas Price		3.21	4.31	3.54	MMBtu
		NGLs		$	-0.4		Market Approach		Forward NGL Price		0.25	2.21	1.4	Gal
	Commodity Contracts - Physical
		Natural Gas		$	1.7		Market Approach		Forward Gas Price		3.19	4.58	3.73	MMBtu
		Crude Oil		$	2.6		Market Approach		Forward Crude Price		65.22	116.56	94.31	Bbl
		NGLs		$	3.1		Market Approach		Forward NGL Price		-	2.22	0.61	Gal
	Commodity Options
		Natural Gas, Crude and NGLs		$	6.4		Option Model		Option Volatility		29%	104%	40%
	Total Fair Value			$	22.2
	_______________________________
	(1)	Prices are in dollars per MMBtu, for Natural Gas, dollars per Gal, for NGLs and dollars per Bbl, for Crude Oil.
	(2)	Fair values are presented in millions and include credit valuation adjustments of approximately $0.1 million of losses.

Segment_Information_Tables

Segment Information (Tables)	9 Months Ended
	Sep. 30, 2013
Segment Information	'
Schedule Of Segment Reporting Information, By Segment	'
	The following tables present certain financial information relating to our business segments and corporate activities:
			For the three month period ended September 30, 2013
			Gathering, Processing and Transportation		Logistics and Marketing		Corporate (1)		Total
			(in millions)
	Total revenue		$	668.2	$	1,228.80	$	-	$	1,897.00
	Less: Intersegment revenue			496.8		19.3		-		516.1
	Operating revenue			171.4		1,209.50		-		1,380.90
	Cost of natural gas and natural gas liquids			33.5		1,210.80		-		1,244.30
	Segment gross margin			137.9		-1.3		-		136.6
	Operating and maintenance			71		17.7		-		88.7
	General and administrative			22.1		2.9		-		25
	Depreciation and amortization			34.1		1.7		-		35.8
				127.2		22.3		-		149.5
	Operating income (loss)			10.7		-23.6		-		-12.9
	Income (loss) before income tax expense			10.7		-23.6		-		-12.9
	Income tax expense			-		-		0.6		0.6
	Net income (loss)		$	10.7	$	-23.6	$	-0.6	$	-13.5
	______________________________
	(1)	Corporate consists of income taxes, which are not allocated to the business segments.
			For the three month period ended September 30, 2012
			Gathering, Processing and Transportation		Logistics and Marketing		Corporate (1)		Total
			(in millions)
	Total revenue		$	683.8	$	1,026.80	$	-	$	1,710.60
	Less: Intersegment revenue			461.8		27.9		-		489.7
	Operating revenue			222		998.9		-		1,220.90
	Cost of natural gas and natural gas liquids			67.2		970.8		-		1,038.00
	Segment gross margin			154.8		28.1		-		182.9
	Operating and maintenance			74.4		20.1		1.8		96.3
	General and administrative			21.6		2.7		-2		22.3
	Depreciation and amortization			32.4		1.9		-		34.3
				128.4		24.7		-0.2		152.9
	Operating income			26.4		3.4		0.2		30
	Income before income tax expense			26.4		3.4		0.2		30
	Income tax expense			-		-		1.3		1.3
	Net income (loss)		$	26.4	$	3.4	$	-1.1	$	28.7
	______________________________
	(1)	Corporate consists of interest expense, interest income, allowance for equity during construction, noncontrolling interest and other costs such as income taxes, which are not allocated to the business segments.
			As of and for the nine month period ended September 30, 2013
			Gathering, Processing and Transportation		Logistics and Marketing		Corporate (1)		Total
			(in millions)
	Total revenue		$	2,034.00	$	3,580.00	$	-	$	5,614.00
	Less: Intersegment revenue			1,491.00		72.7		-		1,563.70
	Operating revenue			543		3,507.30		-		4,050.30
	Cost of natural gas and natural gas liquids			101.7		3,451.70		-		3,553.40
	Segment gross margin			441.3		55.6		-		496.9
	Operating and maintenance			208.2		54.9		-		263.1
	General and administrative			64.6		8.5		-		73.1
	Depreciation and amortization			101.3		5		-		106.3
				374.1		68.4		-		442.5
	Operating income (loss)			67.2		-12.8		-		54.4
	Other income			-		-		0.2		0.2
	Income (loss) before income tax expense			67.2		-12.8		0.2		54.6
	Income tax expense			-		-		8.9		8.9
	Net income (loss)		$	67.2	$	-12.8	$	-8.7	$	45.7
	Total assets (2)		$	4,829.30	$	557.4	$	54.7	$	5,441.40
	Capital expenditures (excluding acquisitions)		$	177.9	$	14	$	13.9	$	205.8
	______________________________
	(1)	Corporate consists of income taxes, which are not allocated to the business segments.
	(2)	Totals assets for our Gathering, Processing and Transportation segment includes our long term equity investment in the Texas Express NGL system.
			As of and for the nine month period ended September 30, 2012
			Gathering, Processing and Transportation		Logistics and Marketing		Corporate (1)		Total
			(in millions)
	Total revenue		$	2,015.10	$	3,376.80	$	-	$	5,391.90
Less: Intersegment revenue			1,398.60		75.8		-		1,474.40
Operating revenue			616.5		3,301.00		-		3,917.50
Cost of natural gas and natural gas liquids			79.6		3,242.90		-		3,322.50
Segment gross margin			536.9		58.1		-		595
Operating and maintenance			209.7		60.3		1.8		271.8
General and administrative			63.9		15.8		-2		77.7
Depreciation and amortization			95.6		5.5		-		101.1
			369.2		81.6		-0.2		450.6
Operating income (loss)			167.7		-23.5		0.2		144.4
Other income (expense)			-		-		-0.1		-0.1
Income (loss) before income tax expense			167.7		-23.5		0.1		144.3
Income tax expense			-		-		2.1		2.1
Net income (loss)		$	167.7	$	-23.5	$	-2	$	142.2
Total assets (2)		$	4,372.10	$	903.6	$	138.3	$	5,414.00
Capital expenditures (excluding acquisitions)		$	317.8	$	3.1	$	10.8	$	331.7
______________________________
(1)	Corporate consists of income taxes, which are not allocated to the business segments.
(2)	Totals assets for our Gathering, Processing and Transportation segment includes our long term equity investment in the Texas Express NGL system.

Supplemental_Cash_Flows_Inform1

Supplemental Cash Flows Information (Tables)	9 Months Ended
	Sep. 30, 2013
Supplemental Cash Flows Information	'
Schedule Of Cash Flow Supplemental Disclosures Table Text Block	'
				For the nine month
				period ended September 30,
				2013			2012
				(in millions)
		Loss on sale of assets		$	1.1		$	-
		Amortization of hedging costs			0.3			2.5
		Allowance for doubtful accounts			0.2			-
		Write-down of project costs			-			4.3
		Environmental costs, net of recoveries			-0.1			-
		Texas Express long-term inventory (line fill)			-1.3			-
		Other			-0.1			-0.1
				$	0.1		$	6.7
	In the “Cash used in investing activities” section of the consolidated statements of cash flows, we exclude changes that did not affect cash. The following is a reconciliation of additions to property, plant and equipment to total capital expenditures (excluding “Investment in joint venture”):
						For the nine month
						period ended September 30,
						2013			2012
						(in millions)
		Additions to property, plant and equipment				$	206.6		$	315.1
			Increase (decrease) in construction payables				-0.8			16.6
		Total capital expenditures (excluding "Investment in joint venture")				$	205.8		$	331.7

Organization_and_Nature_of_Ops

Organization and Nature of Ops (Details) (USD $)

9 Months Ended

9 Months Ended

12 Months Ended

9 Months Ended

12 Months Ended

9 Months Ended

12 Months Ended

In Millions, except Share data, unless otherwise specified

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Dec. 31, 2012

Initial Public Offering [Member]

Pro Forma [Member]

Pro Forma [Member]

General partner interests

General partner interests

Limited partner interests (EEP)

Limited partner interests (EEP)

Limited partner interests (EEP)

Limited partner interests (EEP)

Limited partner interests (EEP)

Enbridge Inc.

Enbridge Inc.

Credit Facility and Commitment Fees [Member]

IPO

Pro Forma [Member]

Pro Forma [Member]

Pro Forma [Member]

Pro Forma [Member]

Pro Forma [Member]

IPO

Intial Public Offering Overallotment [Member]

IPO

IPO

Distribution Made to Limited Partner, Cash Distributions Paid

'

$242

'

'

'

'

'

'

'

'

'

'

'

'

Ownership Interest

'

'

'

'

'

'

'

'

'

'

'

52.00%

20.60%

21.80%

Distribution to EEP

206.3

242

'

'

'

'

'

'

'

'

304.5

'

'

'

Stock Issued, New Issues

'

'

18,500,000

'

'

'

'

'

'

'

'

'

'

'

Ownership interest after IPO

'

'

'

'

'

'

'

'

'

'

61.00%

'

'

'

Ownership interest before IPO

'

'

'

'

'

0.00%

0.00%

100.00%

100.00%

'

'

'

'

'

Payment obligation to EEP

'

'

'

3.4

'

'

'

'

'

'

'

'

'

'

Payments to Repurchase Class A Units from EEP

'

'

'

'

'

'

'

'

'

47

'

'

'

'

Common Stock, Shares, Repurchased

'

'

'

'

'

'

'

'

'

2,775,000

'

'

'

'

Proceeds from Issuance Initial Public Offering

'

'

'

'

$354.90

'

'

'

'

'

'

'

'

'

Initial Offering Period

'2013-11-13

'

'

'

'

'

'

'

'

'

'

'

'

'

Net_Income_Per_Limited_Partner

Net Income Per Limited Partner And General Partner Interest (Basic And Diluted Net Income Per Limited Partner Unit) (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Net Income Per Limited Partner And General Partner Interest	'	'	'	'
Net income	($13.50)	$28.70	$45.70	$142.20

Inventory_Narrative_Details

Inventory (Narrative) (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012
Inventory	'	'	'	'	'
Materials and supplies	$0.60	'	$0.60	'	$0.40
Crude oil inventory	11.5	'	11.5	'	10.1
Natural gas and NGL inventory	132.5	'	132.5	'	64.3
Inventory, Gross	144.6	'	144.6	'	74.8
Charges related to cost of natural gas	$0.90	$0.20	$3.30	$9.80	'

Property_Plant_And_Equipment_S

Property, Plant And Equipment (Schedule Of Property, Plant and Equipment) (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Property, Plant and Equipment [Line Items]	'	'
Land	$11.30	$8.70
Rights-of-way	374.1	340.3
Pipelines	1,724.70	1,603.80
Pumping equipment, buildings and tanks	88.7	65.4
Compressors, meters and other operating equipment	1,953.40	1,755.70
Vehicles, office furniture and equipment	146.5	133
Processing and treating plants	511.3	489.8
Construction in progress	184	402.2
Total property, plant and equipment	4,994	4,798.90
Accumulated depreciation	-935.7	-835.9
Property, plant and equipment, net	$4,058.30	$3,963

Partners_Capital_Changes_In_Pa

Partners' Capital (Changes In Partners' Capital Attributable To General And Limited Partners)(Details) (USD $)	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013		Sep. 30, 2012
Partners Capital Account [Line Items]	'		'
Beginning Balance, value	$4,714.20		'
Distribution to partners	-206.3		-242
Ending Balance, value	4,714.80		'
Accumulated Other Comprehensive Income (Loss) [Member]	'		'
Partners Capital Account [Line Items]	'		'
Net realized income on changes in fair value of derivative financial instruments reclassified to earnings	($3)	[1]	'
[1]	For additional details on the amounts reclassified from AOCI, reference the Reclassifications from Accumulated Other Comprehensive Income table below.

Partners_Capital_Distribution_

Partners' Capital (Distribution To Partners) (Details) (USD $)	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012
Distribution Made to Limited Partner, Cash Distributions Paid	'	$242

Related_Party_Transactions_Nar

Related Party Transactions (Narrative) (Details) (USD $)

3 Months Ended

9 Months Ended

3 Months Ended

9 Months Ended

12 Months Ended

In Millions, unless otherwise specified

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Dec. 31, 2012

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2012

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Affiliate [Member]

Affiliate [Member]

Affiliate [Member]

Affiliate [Member]

Construction Project Work Force Cost Transactions [Member]

Construction Project Work Force Cost Transactions [Member]

Texas Express NGL System [Member]

Texas Express NGL System [Member]

mi

Equity Method (JV) Investments [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

Ownership Percentage of JV

'

'

'

'

'

'

'

'

'

'

'

35.00%

'

Equity Investment in Joint Venture

$365.50

'

$365.50

'

$183.70

'

'

'

'

'

'

'

'

Miles Of Pipeline

'

'

'

'

'

'

'

'

'

'

'

580

'

Related Party Transaction [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

Total operating, general, and administrative services

149.5

152.9

442.5

450.6

'

52.3

50.6

154.4

153

'

'

'

'

Operating and maintenance services

88.7

96.3

263.1

271.8

'

27.3

26.6

81.4

81.2

'

'

'

'

General and administrative services

25

22.3

73.1

77.7

'

25

24

73

71.8

'

'

'

'

Expenses from Transactions with Related Party

'

'

'

'

'

'

'

'

'

4.5

6.4

'

'

Revenue From Related Parties

49.6

77.8

162.4

317.2

'

'

'

'

'

'

'

'

'

Cost of natural gas and natural gas liquids

1,244.30

1,038

3,553.40

3,322.50

'

23

51.9

95.5

243.6

'

'

'

'

Distribution to EEP and Midcoast GP

'

'

'

$242

'

'

'

'

'

'

'

'

'

Related_Party_Transactions_Joi

Related Party Transactions (Joint Funding Arrangement Discussions) (Details)	Sep. 30, 2012
Other Commitments [Line Items]	'
Transportation Commitments	120,000

Related_Party_Transactions_Int

Related Party Transactions (Interest) (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Interest Expense [Abstract]	'	'	'	'
Interest cost paid	$5.10	$1.60	$16.60	$4.60
Interest costs incurred	0	0	0	0
Interest expense	5.1	1.6	16.6	4.6
Interest capitalized	$5.10	$1.60	$16.60	$4.60

Related_Party_Sale_of_AR_Detai

Related Party (Sale of AR) (Details) (USD $)	3 Months Ended	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2013
Proceeds from Sale of Receivables	$640.80	$772.30
AR Sales, Max Amount Outstanding	450	450
Accrued Receivable [Member]	'	'
Net value of Recivables sold	641	772.5
Sold Receivables that have not been collected at the balance sheet date.	$308.70	$308.70

Commitments_And_Contingencies_

Commitments And Contingencies (Narrative) (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Accrual for environmental loss contingencies	$0.20	$0.30
Accrued Environmental Loss Contingencies, Noncurrent	'	$0.10

Derivative_Financial_Instrumen2

Derivative Financial Instruments And Hedging Activities (Narrative) (Details) (USD $)	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Derivative Financial Instruments And Hedging Activities	'	'
Unrecognized losses of derivative financial instruments that were classified as cash flow hedges	$0.60	'
De-designated unrealized commodity hedge gains and losses	1.7	'
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months	4.5	'
Net liability position	($4.40)	$15.20

Derivative_Financial_Instrumen3

Derivative Financial Instruments And Hedging Activities (Net Unrealized Gains And Losses Associated To Changes In Fair Value) (Details) (USD $)	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012
Derivative fair value net gains	($13.90)	$7.90

Derivative_Financial_Instrumen4

Derivative Financial Instruments And Hedging Activities (Derivative Instruments In Statement Of Financial Position, Fair Value) (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Derivative Financial Instruments And Hedging Activities	'	'
Other current assets	$138.30	$275
Other assets, net	72.5	78.1
Accounts payable and other	-151.2	-259.9
Other long-term liabilities	-64	-78
Net asset (liability) position	($4.40)	$15.20

Derivative_Financial_Instrumen5

Derivative Financial Instruments And Hedging Activities (Derivative Balances By Counterparty Credit Quality) (Details) (USD $)	9 Months Ended		12 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013		Dec. 31, 2012
AAA Rating [Member]	'		'
Derivative balance by counterparty credit quality	$0.10	[1]	$0	[1]
AA Rating [Member]	'		'
Derivative balance by counterparty credit quality	-57.8	[1]	-116.6	[1]
Less Than AA Rating [Member]	'		'
Derivative balance by counterparty credit quality	-84.5	[1]	-150.4	[1]
Two Lower Than AA Rating [Member]	'		'
Derivative balance by counterparty credit quality	$137.80	[1]	$282.20	[1]
[1]	As determined by nationally-recognized statistical ratings organizations.

Derivative_Financial_Instrumen6

Derivative Financial Instruments And Hedging Activities (Credit Concentrations In Industry Sectors) (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Net Total	($4.40)	$15.20
United States Financial Institutions And Investment Banking Entities [Member]	'	'
Credit concentrations	-114.5	-204.7
Non United States Financial Institutions [Member]	'	'
Credit concentrations	-28	-87.4
Integrated Oil Companies [Member]	'	'
Credit concentrations	-3.8	4.5
Midcoast OLP GP, L.L.C. [Member]	'	'
Credit concentrations	143.1	297.2
Other [Member]	'	'
Credit concentrations	($1.20)	$5.60

Derivative_Financial_Instrumen7

Derivative Financial Instruments And Hedging Activities (Effect Of Derivative Instruments On Consolidated Statements Of Financial Positions) (Details) (USD $)	Sep. 30, 2013		Dec. 31, 2012
In Millions, unless otherwise specified
Derivatives Designated As Hedging Instruments [Member]	'		'
Assets at Fair Value	$11.60	[1]	$21.40	[1]
Liability at Fair Value	-12.7	[1]	-15.5	[1]
Derivatives Designated As Hedging Instruments [Member] | Other Current Assets [Member] | Commodity Contract [Member]	'		'
Assets at Fair Value	2.4	[1]	12.2	[1],[2]
Liability at Fair Value	-1.8	[1]	-4.2	[1],[2]
Derivatives Designated As Hedging Instruments [Member] | Other assets, net | Commodity Contract [Member]	'		'
Assets at Fair Value	4.8	[1]	2.5	[1],[2]
Liability at Fair Value	-1.2	[1]	-1.1	[1],[2]
Derivatives Designated As Hedging Instruments [Member] | Accounts Payable And Other [Member] | Commodity Contract [Member]	'		'
Assets at Fair Value	4.2	[1]	4.7	[1],[2]
Liability at Fair Value	-8.5	[1]	-5.7	[1],[2]
Derivatives Designated As Hedging Instruments [Member] | Other Long-Term Liabilities [Member] | Commodity Contract [Member]	'		'
Assets at Fair Value	0.2	[1]	2	[1],[2]
Liability at Fair Value	-1.2	[1]	-4.5	[1],[2]
Derivatives Not Designated As Hedging Instruments [Member]	'		'
Assets at Fair Value	249.5		359.9
Liability at Fair Value	-252.8		-350.6
Derivatives Not Designated As Hedging Instruments [Member] | Other Current Assets [Member] | Interest Rate Contracts [Member]	'		'
Assets at Fair Value	123	[3]	246.9	[2],[3]
Liability at Fair Value	0	[3]	0	[2],[3]
Derivatives Not Designated As Hedging Instruments [Member] | Other Current Assets [Member] | Commodity Contract [Member]	'		'
Assets at Fair Value	17.2	[3]	27.2	[2],[3]
Liability at Fair Value	-2.5	[3]	-7.1	[2],[3]
Derivatives Not Designated As Hedging Instruments [Member] | Other assets, net | Interest Rate Contracts [Member]	'		'
Assets at Fair Value	83.2	[3]	68.3	[2],[3]
Liability at Fair Value	-27.9	[3]	-3.3	[2],[3]
Derivatives Not Designated As Hedging Instruments [Member] | Other assets, net | Commodity Contract [Member]	'		'
Assets at Fair Value	14.4	[3]	11.8	[2],[3]
Liability at Fair Value	-0.9	[3]	-0.1	[2],[3]
Derivatives Not Designated As Hedging Instruments [Member] | Accounts Payable And Other [Member] | Interest Rate Contracts [Member]	'		'
Assets at Fair Value	0	[3]	0	[2],[3]
Liability at Fair Value	-123	[3]	-246.9	[2],[3]
Derivatives Not Designated As Hedging Instruments [Member] | Accounts Payable And Other [Member] | Commodity Contract [Member]	'		'
Assets at Fair Value	9.2	[3]	0.8	[2],[3]
Liability at Fair Value	-32.9	[3]	-12.8	[2],[3]
Derivatives Not Designated As Hedging Instruments [Member] | Other Long-Term Liabilities [Member] | Interest Rate Contracts [Member]	'		'
Assets at Fair Value	2.3	[3]	3.3	[2],[3]
Liability at Fair Value	-57.6	[3]	-68.3	[2],[3]
Derivatives Not Designated As Hedging Instruments [Member] | Other Long-Term Liabilities [Member] | Commodity Contract [Member]	'		'
Assets at Fair Value	0.2	[3]	1.6	[2],[3]
Liability at Fair Value	($8)	[3]	($12.10)	[2],[3]
[1]	Includes items currently designated as hedging instruments. Excludes the portion of de-designated hedges which may have a component remaining in AOCI.
[2]	The effect of derivative instruments on the consolidated statements of financial position, as of December 31, 2012, was revised to disclose the financial position location on a gross basis. The revisions to the disclosures are not considered material to and had no impact on amounts previously reported in the consolidated statements of financial position.
[3]	Includes both affiliate and third party transactions.

Derivative_Financial_Instrumen8

Derivative Financial Instruments And Hedging Activities (Effect Of Derivative Instruments On Consolidated Statements Of Income And AOCI) (Details) (Derivatives in Cash Flow Hedging Relationships [Member], Commodity Contract [Member], USD $)	3 Months Ended				9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013		Sep. 30, 2012		Sep. 30, 2013		Sep. 30, 2012
Recognized In AOCI Effective Portion [Member]	'		'		'		'
Amount of gain (loss) recognized in AOCI on Derivative (Effective Portion)	($17.20)		($22.90)		($8.80)		$47.20
Reclassified From AOCI To Earnings, Effective Portion [Member] | Cost of natural gas and natural gas liquids [Member]	'		'		'		'
Amount of gain (loss) reclassified from AOCI to earnings (Effective Portion)	-0.6		4.6		3		-3.4
Recognized In Earnings On Derivative, Ineffective Portion And Amount Excluded From Effectiveness Testing [Member] | Cost of natural gas and natural gas liquids [Member]	'		'		'		'
Amount of gain (loss) recognized in earnings on derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)	($0.50)	[1]	($3.90)	[1]	$1.80	[1]	$1.20	[1]
[1]	Includes only the ineffective portion of derivatives that are designated as hedging instruments and does not include net gains or losses associated with derivatives that do not qualify for hedge accounting treatment.

Derivative_Financial_Instrumen9

Derivative Financial Instruments And Hedging Activities (Components Of Accumulated Other Comprehensive Income) (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Derivative Financial Instruments And Hedging Activities	'	'	'	'
Beginning balance	'	'	$7.10	'
Other comprehensive income (loss) before reclassifications	'	'	-2.7	'
Tax benefit (expense)	0.1	0.1	0	-0.2
Net other comprehensive income (loss)	-17	-22.7	-5.7	43.6
Ending balance	$1.40	'	$1.40	'

Recovered_Sheet1

Derivative Financial Instruments And Hedging Activities (Reclassifications From Accumulated Other Comprehensive Income) (Details) (Reclassified From AOCI To Earnings, Effective Portion [Member], Derivatives in Cash Flow Hedging Relationships [Member], Cost of natural gas and natural gas liquids [Member], Commodity Contract [Member], USD $)	3 Months Ended				9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013		Sep. 30, 2012		Sep. 30, 2013		Sep. 30, 2012
Reclassified From AOCI To Earnings, Effective Portion [Member] | Derivatives in Cash Flow Hedging Relationships [Member] | Cost of natural gas and natural gas liquids [Member] | Commodity Contract [Member]	'		'		'		'
Amounts reclassified from AOCI	$0.60	[1]	($4.60)	[1]	($3)	[1]	$3.40	[1]
[1]	Loss (gain) reported within bCost of natural gas and natural gas liquids" in the consolidated statements of income.

Recovered_Sheet2

Derivative Financial Instruments And Hedging Activities (Effect Of Derivative Instruments On Consolidated Statements Of Income) (Details) (Derivatives Not Designated As Hedging Instruments [Member], USD $)	3 Months Ended				9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013		Sep. 30, 2012		Sep. 30, 2013		Sep. 30, 2012
Amount of Gain or (Loss) Recognized in Earnings	($34.30)	[1],[2]	($12.40)	[1],[2]	($15.10)	[1],[2]	$21.70	[1],[2]
Operating revenue [Member] | Location Of Gain Or Loss Recognized In Earnings [Member] | Commodity Contract [Member]	'		'		'		'
Amount of Gain or (Loss) Recognized in Earnings	-6.2	[1],[2]	0	[1],[2]	-6.2	[1],[2]	0	[1],[2]
Cost of natural gas and natural gas liquids [Member] | Location Of Gain Or Loss Recognized In Earnings [Member] | Commodity Contract [Member]	'		'		'		'
Amount of Gain or (Loss) Recognized in Earnings	-28.1	[1],[2],[3]	-12.4	[1],[2],[3]	-8.9	[1],[2],[3]	21.7	[1],[2],[3]
Gain (Loss) on Settlement of Derivative Instruments	($0.20)		$8.30		$0.50		$15
[1]	Does not include settlements associated with derivative instruments that settle through physical delivery.
[2]	Includes only net gains or losses associated with those derivatives that do not qualify for hedge accounting treatment and does not include the ineffective portion of derivatives that are designated as hedging instruments.
[3]	Includes settlements losses of $0.2 million for the three month period ended September 30, 2013, settlement gains of $8.3 million for the three month period ended September 30, 2012 and settlement gains of $0.5 million and $15.0 million for the nine month periods ended September 30, 2013 and September 30, 2012, respectively.

Recovered_Sheet3

Derivative Financial Instruments And Hedging Activities (Gross To Net Presentation Reconciliation Of Derivative Assets And Liabilities) (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Net Total	($4.40)	$15.20
Effects Of Netting Agreements [Member]	'	'
Gross Derivative Assets	-50.3	-28.2
Liability at Fair Value	50.3	28.2
Gross Total	0	0
Fair Value Of Derivatives Gross Presentation [Member]	'	'
Gross Derivative Assets	261.1	381.3
Liability at Fair Value	-265.5	-366.1
Gross Total	-4.4	15.2
Fair Value Of Derivatives Net Presentation [Member]	'	'
Net Derivative assets	210.8	353.1
Net Derivative Liabilitites	-215.2	-337.9
Net Total	($4.40)	$15.20

Recovered_Sheet4

Derivative Financial Instruments And Hedging Activities (Offsetting Of Financial Assets And Derivative Assets) (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Effects Of Netting Agreements [Member]	'	'
Gross Derivative Assets	($50.30)	($28.20)
Derivative, Fair Value, Net	0	0
Fair Value Of Derivatives Gross Presentation [Member]	'	'
Gross Derivative Assets	261.1	381.3
Derivative, Fair Value, Net	-4.4	15.2
Fair Value Of Derivatives Net Presentation [Member]	'	'
Net Derivative assets	210.8	353.1
Fair Value of Derivative Assets Net of Non Offset Amounts [Member]	'	'
Derivative, Fair Value, Net	206	'
Other Assets	'	'
Gross Amount Not Offset in the Statement of Financial Position	($4.80)	'

Recovered_Sheet5

Derivative Financial Instruments And Hedging Activities (Offsetting Of Financial Liabilities And Derivative Liabilities) (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Effects Of Netting Agreements [Member]	'	'
Liability at Fair Value	$50.30	$28.20
Derivative, Fair Value, Net	0	0
Fair Value Of Derivatives Gross Presentation [Member]	'	'
Liability at Fair Value	-265.5	-366.1
Derivative, Fair Value, Net	-4.4	15.2
Fair Value Of Derivatives Net Presentation [Member]	'	'
Net Derivative Liabilitites	-215.2	-337.9
Other Liabilities [Member]	'	'
Gross Amount Not Offset in the Statement of Financial Position	4.8	'
Fair Value Of Derivative Liabilities Net Of Non Offset Amounts Member [Member]	'	'
Derivative, Fair Value, Net	($210.40)	'

Recovered_Sheet6

Derivative Financial Instruments And Hedging Activities (Level With In The Fair Value Hierarchy Financial Assets And Liabilities) (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Assets and liabilities accounted for at fair value on a recurring basis	($4.40)	$15.20
Commodity Contracts-Financial [Member]	'	'
Assets and liabilities accounted for at fair value on a recurring basis	-6.2	1.4
Commodity Contracts-Physical [Member]	'	'
Assets and liabilities accounted for at fair value on a recurring basis	-5.1	7.4
Commodity Options [Member]	'	'
Assets and liabilities accounted for at fair value on a recurring basis	6.9	6.4
Level 2 [Member]	'	'
Assets and liabilities accounted for at fair value on a recurring basis	-7	-7
Level 2 [Member] | Commodity Contracts-Financial [Member]	'	'
Assets and liabilities accounted for at fair value on a recurring basis	-7	-7
Level 2 [Member] | Commodity Contracts-Physical [Member]	'	'
Assets and liabilities accounted for at fair value on a recurring basis	0	0
Level 2 [Member] | Commodity Options [Member]	'	'
Assets and liabilities accounted for at fair value on a recurring basis	0	0
Level 3 [Member]	'	'
Assets and liabilities accounted for at fair value on a recurring basis	2.6	22.2
Level 3 [Member] | Commodity Contracts-Financial [Member]	'	'
Assets and liabilities accounted for at fair value on a recurring basis	0.8	8.4
Level 3 [Member] | Commodity Contracts-Physical [Member]	'	'
Assets and liabilities accounted for at fair value on a recurring basis	-5.1	7.4
Level 3 [Member] | Commodity Options [Member]	'	'
Assets and liabilities accounted for at fair value on a recurring basis	$6.90	$6.40

Recovered_Sheet7

Derivative Financial Instruments And Hedging Activities (Quantitative Information About Level 3 Fair Value Measurements) (Details) (USD $)	9 Months Ended		12 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013		Dec. 31, 2012
Assets and liabilities accounted for at fair value on a recurring basis	($4.40)		$15.20
Level 3 [Member]	'		'
Assets and liabilities accounted for at fair value on a recurring basis	2.6		22.2
Credit valuation adjustments	-0.3		-0.1
Level 3 [Member] | Commodity Contracts-Financial [Member] | Market Approach [Member] | Forward Gas Price [Member] | Natural Gas [Member]	'		'
Assets and liabilities accounted for at fair value on a recurring basis	2.6	[1]	8.8	[2]
Level 3 [Member] | Commodity Contracts-Financial [Member] | Market Approach [Member] | Forward Gas Price [Member] | Minimum [Member] | Natural Gas [Member]	'		'
Market Price	3.24	[3]	3.21	[4]
Level 3 [Member] | Commodity Contracts-Financial [Member] | Market Approach [Member] | Forward Gas Price [Member] | Maximum [Member] | Natural Gas [Member]	'		'
Market Price	4.19	[3]	4.31	[4]
Level 3 [Member] | Commodity Contracts-Financial [Member] | Market Approach [Member] | Forward Gas Price [Member] | Weighted Average [Member] | Natural Gas [Member]	'		'
Weighted Average	3.69	[3]	3.54	[4]
Level 3 [Member] | Commodity Contracts-Financial [Member] | Market Approach [Member] | Forward Ngl Price [Member] | NGL [Member]	'		'
Assets and liabilities accounted for at fair value on a recurring basis	-1.8	[1]	-0.4	[2]
Level 3 [Member] | Commodity Contracts-Financial [Member] | Market Approach [Member] | Forward Ngl Price [Member] | Minimum [Member] | NGL [Member]	'		'
Market Price	0.25	[3]	0.25	[4]
Level 3 [Member] | Commodity Contracts-Financial [Member] | Market Approach [Member] | Forward Ngl Price [Member] | Maximum [Member] | NGL [Member]	'		'
Market Price	2.08	[3]	2.21	[4]
Level 3 [Member] | Commodity Contracts-Financial [Member] | Market Approach [Member] | Forward Ngl Price [Member] | Weighted Average [Member] | NGL [Member]	'		'
Weighted Average	1.25	[3]	1.4	[4]
Level 3 [Member] | Commodity Contracts-Physical [Member] | Market Approach [Member] | Forward Gas Price [Member] | Natural Gas [Member]	'		'
Assets and liabilities accounted for at fair value on a recurring basis	0.9	[1]	1.7	[2]
Level 3 [Member] | Commodity Contracts-Physical [Member] | Market Approach [Member] | Forward Gas Price [Member] | Minimum [Member] | Natural Gas [Member]	'		'
Market Price	3.24	[3]	3.19	[4]
Level 3 [Member] | Commodity Contracts-Physical [Member] | Market Approach [Member] | Forward Gas Price [Member] | Maximum [Member] | Natural Gas [Member]	'		'
Market Price	4.35	[3]	4.58	[4]
Level 3 [Member] | Commodity Contracts-Physical [Member] | Market Approach [Member] | Forward Gas Price [Member] | Weighted Average [Member] | Natural Gas [Member]	'		'
Weighted Average	3.72	[3]	3.73	[4]
Level 3 [Member] | Commodity Contracts-Physical [Member] | Market Approach [Member] | Forward Crude Oil Price [Member] | Liquids [Member]	'		'
Assets and liabilities accounted for at fair value on a recurring basis	-1.1	[1]	2.6	[2]
Level 3 [Member] | Commodity Contracts-Physical [Member] | Market Approach [Member] | Forward Crude Oil Price [Member] | Minimum [Member] | Liquids [Member]	'		'
Market Price	83.41	[3]	65.22	[4]
Level 3 [Member] | Commodity Contracts-Physical [Member] | Market Approach [Member] | Forward Crude Oil Price [Member] | Maximum [Member] | Liquids [Member]	'		'
Market Price	107.67	[3]	116.56	[4]
Level 3 [Member] | Commodity Contracts-Physical [Member] | Market Approach [Member] | Forward Crude Oil Price [Member] | Weighted Average [Member] | Liquids [Member]	'		'
Weighted Average	99.42	[3]	94.31	[4]
Level 3 [Member] | Commodity Contracts-Physical [Member] | Market Approach [Member] | Forward Ngl Price [Member] | NGL [Member]	'		'
Assets and liabilities accounted for at fair value on a recurring basis	-4.9	[1]	3.1	[2]
Level 3 [Member] | Commodity Contracts-Physical [Member] | Market Approach [Member] | Forward Ngl Price [Member] | Minimum [Member] | NGL [Member]	'		'
Market Price	0.01	[3]	0	[4]
Level 3 [Member] | Commodity Contracts-Physical [Member] | Market Approach [Member] | Forward Ngl Price [Member] | Maximum [Member] | NGL [Member]	'		'
Market Price	2.28	[3]	2.22	[4]
Level 3 [Member] | Commodity Contracts-Physical [Member] | Market Approach [Member] | Forward Ngl Price [Member] | Weighted Average [Member] | NGL [Member]	'		'
Weighted Average	0.95	[3]	0.61	[4]
Level 3 [Member] | Commodity Options [Member] | Option Model [Member] | Option Volatility [Member] | Natural Gas Crude Oil And Ngls [Member]	'		'
Assets and liabilities accounted for at fair value on a recurring basis	$6.90	[1]	$6.40	[2]
Level 3 [Member] | Commodity Options [Member] | Option Model [Member] | Option Volatility [Member] | Minimum [Member] | Natural Gas Crude Oil And Ngls [Member]	'		'
Option Volatility	24.00%		29.00%
Level 3 [Member] | Commodity Options [Member] | Option Model [Member] | Option Volatility [Member] | Maximum [Member] | Natural Gas Crude Oil And Ngls [Member]	'		'
Option Volatility	145.00%		104.00%
Level 3 [Member] | Commodity Options [Member] | Option Model [Member] | Option Volatility [Member] | Weighted Average [Member] | Natural Gas Crude Oil And Ngls [Member]	'		'
Option Volatility	41.00%		40.00%
[1]	Fair values are presented in millions of dollars and include credit valuation adjustments of approximately $0.3 million of losses.
[2]	Fair values are presented in millions and include credit valuation adjustments of approximately $0.1 million of losses.
[3]	Prices are in dollars per Millions of British Thermal Units, or MMBtu, for Natural Gas, dollars per Gallon, or Gal, for NGLs and dollars per barrel, or Bbl, for Crude Oil.
[4]	Prices are in dollars per MMBtu, for Natural Gas, dollars per Gal, for NGLs and dollars per Bbl, for Crude Oil.

Recovered_Sheet8

Derivative Financial Instruments And Hedging Activities (Reconciliation Of Changes In Fair Value Of L3 Assets And Liabilities On Recurring Basis) (Details) (Level 3 [Member], USD $)	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013
Beginning balance	$22.20
Transfer out of Level 3	0	[1]
Gains or losses included in earnings (or changes in net assets)	22.9
Gains or losses included in other comprehensive income	3.4
Purchases	3
Settlements	-48.9	[2]
Ending balance	2.6
Amount of changes in net assets attributable to the change in unrealized gains or losses related to assets still held at the reporting date	-1.6
Amounts reported in operating revenue	-6.2
Commodity Contracts-Financial [Member]	'
Beginning balance	8.4
Transfer out of Level 3	0	[1]
Gains or losses included in earnings (or changes in net assets)	1.7
Gains or losses included in other comprehensive income	3.4
Purchases	0
Settlements	-12.7	[2]
Ending balance	0.8
Amount of changes in net assets attributable to the change in unrealized gains or losses related to assets still held at the reporting date	0.6
Amounts reported in operating revenue	0
Commodity Contracts-Physical [Member]	'
Beginning balance	7.4
Transfer out of Level 3	0	[1]
Gains or losses included in earnings (or changes in net assets)	21.7
Gains or losses included in other comprehensive income	0
Purchases	0
Settlements	-34.2	[2]
Ending balance	-5.1
Amount of changes in net assets attributable to the change in unrealized gains or losses related to assets still held at the reporting date	-6.2
Amounts reported in operating revenue	-6.2
Commodity Options [Member]	'
Beginning balance	6.4
Transfer out of Level 3	0	[1]
Gains or losses included in earnings (or changes in net assets)	-0.5
Gains or losses included in other comprehensive income	0
Purchases	3
Settlements	-2	[2]
Ending balance	6.9
Amount of changes in net assets attributable to the change in unrealized gains or losses related to assets still held at the reporting date	4
Amounts reported in operating revenue	$0
[1]	Our policy is to recognize transfers as of the last day of the reporting period.
[2]	Settlements represent the realized portion of forward contracts.

Recovered_Sheet9

Derivative Financial Instruments And Hedging Activities (Fair Values Of Expected Cash Flows, Outstanding Commodity Based Swaps And Physical Contracts) (Details) (Commodity [Member], USD $)	9 Months Ended		12 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013		Dec. 31, 2012
Credit Valuation Adjustments	$0		$0
Swaps [Member]	'		'
Credit Valuation Adjustments	-0.2		-0.2
Natural Gas [Member] | Receive Variable Pay Fixed [Member] | Portion Of Contracts Maturing In 2013 | Swaps [Member]	'		'
Notional	1,058,748	[1]	'
Assets at Fair Value	0.1	[2]	0.2	[2]
Liability at Fair Value	-0.2	[2]	-0.3	[2]
Natural Gas [Member] | Receive Variable Pay Fixed [Member] | Portion Of Contracts Maturing In 2014 | Swaps [Member]	'		'
Notional	21,870	[1]	'
Assets at Fair Value	0	[2]	0	[2]
Liability at Fair Value	0	[2]	0	[2]
Natural Gas [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2013 | Swaps [Member]	'		'
Notional	2,361,000	[1]	'
Assets at Fair Value	1.9	[2]	7.8	[2]
Liability at Fair Value	0	[2]	0	[2]
Natural Gas [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2014 | Swaps [Member]	'		'
Notional	3,006,890	[1]	'
Assets at Fair Value	0.7	[2]	0.2	[2]
Liability at Fair Value	0	[2]	0	[2]
Natural Gas [Member] | Receive Variable Pay Variable [Member] | Portion Of Contracts Maturing In 2013 | Swaps [Member]	'		'
Notional	13,277,500	[1]	'
Assets at Fair Value	0.3	[2]	1.2	[2]
Liability at Fair Value	-0.1	[2]	-0.2	[2]
Natural Gas [Member] | Receive Variable Pay Variable [Member] | Portion Of Contracts Maturing In 2013 | Physical Contracts [Member]	'		'
Notional	19,866,685	[1]	'
Assets at Fair Value	0.3	[2]	0.9	[2]
Liability at Fair Value	-0.2	[2]	0	[2]
Natural Gas [Member] | Receive Variable Pay Variable [Member] | Portion Of Contracts Maturing In 2014 | Swaps [Member]	'		'
Notional	13,842,500	[1]	'
Assets at Fair Value	0.2	[2]	0.1	[2]
Liability at Fair Value	0	[2]	-0.1	[2]
Natural Gas [Member] | Receive Variable Pay Variable [Member] | Portion Of Contracts Maturing In 2014 | Physical Contracts [Member]	'		'
Notional	34,169,685	[1]	'
Assets at Fair Value	0.9	[2]	0.5	[2]
Liability at Fair Value	-0.4	[2]	0	[2]
Natural Gas [Member] | Receive Variable Pay Variable [Member] | Portion Of Contracts Maturing In 2015 | Swaps [Member]	'		'
Notional	900,000	[1]	'
Assets at Fair Value	0	[2]	0	[2]
Liability at Fair Value	0	[2]	0	[2]
Natural Gas [Member] | Receive Variable Pay Variable [Member] | Portion Of Contracts Maturing In 2015 | Physical Contracts [Member]	'		'
Notional	8,541,825	[1]	'
Liability at Fair Value	-0.1	[2]	0	[2]
Natural Gas [Member] | Receive Variable Pay Variable [Member] | Portion Of Contracts Maturing In 2016 | Physical Contracts [Member]	'		'
Notional	783,240	[1]	'
Assets at Fair Value	0.1	[2]	0.1	[2]
Liability at Fair Value	0	[2]	0	[2]
NGL [Member] | Receive Variable Pay Fixed [Member] | Portion Of Contracts Maturing In 2013 | Swaps [Member]	'		'
Notional	985,200	[1]	'
Assets at Fair Value	1.8	[2]	1.4	[2]
Liability at Fair Value	-0.5	[2]	0	[2]
NGL [Member] | Receive Variable Pay Fixed [Member] | Portion Of Contracts Maturing In 2013 | Physical Contracts [Member]	'		'
Notional	2,330,976	[1]	'
Assets at Fair Value	3.3	[2]	0.6	[2]
Liability at Fair Value	-2.4	[2]	-0.8	[2]
NGL [Member] | Receive Variable Pay Fixed [Member] | Portion Of Contracts Maturing In 2014 | Swaps [Member]	'		'
Notional	286,250	[1]	'
Assets at Fair Value	0	[2]	0	[2]
Liability at Fair Value	-0.2	[2]	0	[2]
NGL [Member] | Receive Variable Pay Fixed [Member] | Portion Of Contracts Maturing In 2014 | Physical Contracts [Member]	'		'
Notional	45,000	[1]	'
Assets at Fair Value	0	[2]	0	[2]
Liability at Fair Value	-0.1	[2]	0	[2]
NGL [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2013 | Swaps [Member]	'		'
Notional	1,854,028	[1]	'
Assets at Fair Value	3	[2]	9.3	[2]
Liability at Fair Value	-7.2	[2]	-9.9	[2]
NGL [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2013 | Physical Contracts [Member]	'		'
Notional	3,844,386	[1]	'
Assets at Fair Value	3.3	[2]	2.6	[2]
Liability at Fair Value	-11.4	[2]	-2.2	[2]
NGL [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2014 | Swaps [Member]	'		'
Notional	2,208,800	[1]	'
Assets at Fair Value	5.6	[2]	0.9	[2]
Liability at Fair Value	-5	[2]	-2.7	[2]
NGL [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2014 | Physical Contracts [Member]	'		'
Notional	325,617	[1]	'
Assets at Fair Value	0.1	[2]	0	[2]
Liability at Fair Value	-0.8	[2]	0	[2]
NGL [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2015 | Swaps [Member]	'		'
Notional	292,000	[1]	'
Assets at Fair Value	1.2	[2]	0.7	[2]
Liability at Fair Value	-0.5	[2]	-0.2	[2]
NGL [Member] | Receive Variable Pay Variable [Member] | Portion Of Contracts Maturing In 2013 | Physical Contracts [Member]	'		'
Notional	6,135,041	[1]	'
Assets at Fair Value	3.6	[2]	5.2	[2]
Liability at Fair Value	-2.4	[2]	-2.3	[2]
NGL [Member] | Receive Variable Pay Variable [Member] | Portion Of Contracts Maturing In 2014 | Physical Contracts [Member]	'		'
Notional	7,037,705	[1]	'
Assets at Fair Value	1.8	[2]	0	[2]
Liability at Fair Value	-0.9	[2]	0	[2]
Liquids [Member] | Receive Variable Pay Fixed [Member] | Portion Of Contracts Maturing In 2013 | Swaps [Member]	'		'
Notional	257,664	[1]	'
Assets at Fair Value	0.2	[2]	0.2	[2]
Liability at Fair Value	-0.7	[2]	-3.9	[2]
Liquids [Member] | Receive Variable Pay Fixed [Member] | Portion Of Contracts Maturing In 2013 | Physical Contracts [Member]	'		'
Notional	255,010	[1]	'
Assets at Fair Value	0	[2]	0.4	[2]
Liability at Fair Value	-1	[2]	-0.4	[2]
Liquids [Member] | Receive Variable Pay Fixed [Member] | Portion Of Contracts Maturing In 2014 | Swaps [Member]	'		'
Notional	506,255	[1]	'
Assets at Fair Value	0	[2]	0	[2]
Liability at Fair Value	-3.3	[2]	-5	[2]
Liquids [Member] | Receive Variable Pay Fixed [Member] | Portion Of Contracts Maturing In 2015 | Swaps [Member]	'		'
Notional	515,015	[1]	'
Assets at Fair Value	0	[2]	0	[2]
Liability at Fair Value	-6.3	[2]	-5.6	[2]
Liquids [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2013 | Swaps [Member]	'		'
Notional	591,548	[1]	'
Assets at Fair Value	0.6	[2]	6.3	[2]
Liability at Fair Value	-4.8	[2]	-8.8	[2]
Liquids [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2013 | Physical Contracts [Member]	'		'
Notional	339,200	[1]	'
Assets at Fair Value	1.2	[2]	0.2	[2]
Liability at Fair Value	0	[2]	-1	[2]
Liquids [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2014 | Swaps [Member]	'		'
Notional	1,573,205	[1]	'
Assets at Fair Value	3.6	[2]	5.4	[2]
Liability at Fair Value	-5.2	[2]	-2.7	[2]
Liquids [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2015 | Swaps [Member]	'		'
Notional	865,415	[1]	'
Assets at Fair Value	7.9	[2]	6.8	[2]
Liability at Fair Value	0	[2]	-0.2	[2]
Liquids [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2016 | Swaps [Member]	'		'
Notional	45,750	[1]	'
Assets at Fair Value	0.6	[2]	0.5	[2]
Liability at Fair Value	0	[2]	0	[2]
Liquids [Member] | Receive Variable Pay Variable [Member] | Portion Of Contracts Maturing In 2013 | Physical Contracts [Member]	'		'
Notional	1,120,690	[1]	'
Assets at Fair Value	1.4	[2]	6.4	[2]
Liability at Fair Value	-1.7	[2]	-3	[2]
Receive | Natural Gas [Member] | Receive Variable Pay Fixed [Member] | Portion Of Contracts Maturing In 2013 | Swaps [Member]	'		'
Average variable price	3.49	[3]	'
Receive | Natural Gas [Member] | Receive Variable Pay Fixed [Member] | Portion Of Contracts Maturing In 2014 | Swaps [Member]	'		'
Average variable price	3.75	[3]	'
Receive | Natural Gas [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2013 | Swaps [Member]	'		'
Average fixed price	4.36	[3]	'
Receive | Natural Gas [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2014 | Swaps [Member]	'		'
Average fixed price	3.97	[3]	'
Receive | Natural Gas [Member] | Receive Variable Pay Variable [Member] | Portion Of Contracts Maturing In 2013 | Swaps [Member]	'		'
Average variable price	3.53	[3]	'
Receive | Natural Gas [Member] | Receive Variable Pay Variable [Member] | Portion Of Contracts Maturing In 2013 | Physical Contracts [Member]	'		'
Average variable price	3.53	[3]	'
Receive | Natural Gas [Member] | Receive Variable Pay Variable [Member] | Portion Of Contracts Maturing In 2014 | Swaps [Member]	'		'
Average variable price	3.77	[3]	'
Receive | Natural Gas [Member] | Receive Variable Pay Variable [Member] | Portion Of Contracts Maturing In 2014 | Physical Contracts [Member]	'		'
Average variable price	3.77	[3]	'
Receive | Natural Gas [Member] | Receive Variable Pay Variable [Member] | Portion Of Contracts Maturing In 2015 | Swaps [Member]	'		'
Average variable price	4.05	[3]	'
Receive | Natural Gas [Member] | Receive Variable Pay Variable [Member] | Portion Of Contracts Maturing In 2015 | Physical Contracts [Member]	'		'
Average variable price	4.1	[3]	'
Assets at Fair Value	$0.50	[2]	$0.40	[2]
Receive | Natural Gas [Member] | Receive Variable Pay Variable [Member] | Portion Of Contracts Maturing In 2016 | Physical Contracts [Member]	'		'
Average variable price	4.28	[3]	'
Receive | NGL [Member] | Receive Variable Pay Fixed [Member] | Portion Of Contracts Maturing In 2013 | Swaps [Member]	'		'
Average variable price	46.8	[3]	'
Receive | NGL [Member] | Receive Variable Pay Fixed [Member] | Portion Of Contracts Maturing In 2013 | Physical Contracts [Member]	'		'
Average variable price	37.27	[3]	'
Receive | NGL [Member] | Receive Variable Pay Fixed [Member] | Portion Of Contracts Maturing In 2014 | Swaps [Member]	'		'
Average variable price	82.33	[3]	'
Receive | NGL [Member] | Receive Variable Pay Fixed [Member] | Portion Of Contracts Maturing In 2014 | Physical Contracts [Member]	'		'
Average variable price	43.79	[3]	'
Receive | NGL [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2013 | Swaps [Member]	'		'
Average fixed price	50.19	[3]	'
Receive | NGL [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2013 | Physical Contracts [Member]	'		'
Average fixed price	39.72	[3]	'
Receive | NGL [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2014 | Swaps [Member]	'		'
Average fixed price	53.93	[3]	'
Receive | NGL [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2014 | Physical Contracts [Member]	'		'
Average fixed price	53.43	[3]	'
Receive | NGL [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2015 | Swaps [Member]	'		'
Average fixed price	56.76	[3]	'
Receive | NGL [Member] | Receive Variable Pay Variable [Member] | Portion Of Contracts Maturing In 2013 | Physical Contracts [Member]	'		'
Average variable price	47.4	[3]	'
Receive | NGL [Member] | Receive Variable Pay Variable [Member] | Portion Of Contracts Maturing In 2014 | Physical Contracts [Member]	'		'
Average variable price	33.02	[3]	'
Receive | Liquids [Member] | Receive Variable Pay Fixed [Member] | Portion Of Contracts Maturing In 2013 | Swaps [Member]	'		'
Average variable price	101.36	[3]	'
Receive | Liquids [Member] | Receive Variable Pay Fixed [Member] | Portion Of Contracts Maturing In 2013 | Physical Contracts [Member]	'		'
Average variable price	102.19	[3]	'
Receive | Liquids [Member] | Receive Variable Pay Fixed [Member] | Portion Of Contracts Maturing In 2014 | Swaps [Member]	'		'
Average variable price	95.33	[3]	'
Receive | Liquids [Member] | Receive Variable Pay Fixed [Member] | Portion Of Contracts Maturing In 2015 | Swaps [Member]	'		'
Average variable price	88.53	[3]	'
Receive | Liquids [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2013 | Swaps [Member]	'		'
Average fixed price	94.24	[3]	'
Receive | Liquids [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2013 | Physical Contracts [Member]	'		'
Average fixed price	105.55	[3]	'
Receive | Liquids [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2014 | Swaps [Member]	'		'
Average fixed price	94.43	[3]	'
Receive | Liquids [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2015 | Swaps [Member]	'		'
Average fixed price	97.72	[3]	'
Receive | Liquids [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2016 | Swaps [Member]	'		'
Average fixed price	99.31	[3]	'
Receive | Liquids [Member] | Receive Variable Pay Variable [Member] | Portion Of Contracts Maturing In 2013 | Physical Contracts [Member]	'		'
Average variable price	98.78	[3]	'
Pay | Natural Gas [Member] | Receive Variable Pay Fixed [Member] | Portion Of Contracts Maturing In 2013 | Swaps [Member]	'		'
Average fixed price	3.59	[3]	'
Pay | Natural Gas [Member] | Receive Variable Pay Fixed [Member] | Portion Of Contracts Maturing In 2014 | Swaps [Member]	'		'
Average fixed price	5.22	[3]	'
Pay | Natural Gas [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2013 | Swaps [Member]	'		'
Average variable price	3.55	[3]	'
Pay | Natural Gas [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2014 | Swaps [Member]	'		'
Average variable price	3.73	[3]	'
Pay | Natural Gas [Member] | Receive Variable Pay Variable [Member] | Portion Of Contracts Maturing In 2013 | Swaps [Member]	'		'
Average variable price	3.51	[3]	'
Pay | Natural Gas [Member] | Receive Variable Pay Variable [Member] | Portion Of Contracts Maturing In 2013 | Physical Contracts [Member]	'		'
Average variable price	3.52	[3]	'
Pay | Natural Gas [Member] | Receive Variable Pay Variable [Member] | Portion Of Contracts Maturing In 2014 | Swaps [Member]	'		'
Average variable price	3.76	[3]	'
Pay | Natural Gas [Member] | Receive Variable Pay Variable [Member] | Portion Of Contracts Maturing In 2014 | Physical Contracts [Member]	'		'
Average variable price	3.76	[3]	'
Pay | Natural Gas [Member] | Receive Variable Pay Variable [Member] | Portion Of Contracts Maturing In 2015 | Swaps [Member]	'		'
Average variable price	4.04	[3]	'
Pay | Natural Gas [Member] | Receive Variable Pay Variable [Member] | Portion Of Contracts Maturing In 2015 | Physical Contracts [Member]	'		'
Average variable price	4.06	[3]	'
Pay | Natural Gas [Member] | Receive Variable Pay Variable [Member] | Portion Of Contracts Maturing In 2016 | Physical Contracts [Member]	'		'
Average variable price	4.17	[3]	'
Pay | NGL [Member] | Receive Variable Pay Fixed [Member] | Portion Of Contracts Maturing In 2013 | Swaps [Member]	'		'
Average fixed price	45.4	[3]	'
Pay | NGL [Member] | Receive Variable Pay Fixed [Member] | Portion Of Contracts Maturing In 2013 | Physical Contracts [Member]	'		'
Average fixed price	36.89	[3]	'
Pay | NGL [Member] | Receive Variable Pay Fixed [Member] | Portion Of Contracts Maturing In 2014 | Swaps [Member]	'		'
Average fixed price	83.05	[3]	'
Pay | NGL [Member] | Receive Variable Pay Fixed [Member] | Portion Of Contracts Maturing In 2014 | Physical Contracts [Member]	'		'
Average fixed price	45.45	[3]	'
Pay | NGL [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2013 | Swaps [Member]	'		'
Average variable price	52.46	[3]	'
Pay | NGL [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2013 | Physical Contracts [Member]	'		'
Average variable price	41.85	[3]	'
Pay | NGL [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2014 | Swaps [Member]	'		'
Average variable price	53.67	[3]	'
Pay | NGL [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2014 | Physical Contracts [Member]	'		'
Average variable price	55.69	[3]	'
Pay | NGL [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2015 | Swaps [Member]	'		'
Average variable price	54.04	[3]	'
Pay | NGL [Member] | Receive Variable Pay Variable [Member] | Portion Of Contracts Maturing In 2013 | Physical Contracts [Member]	'		'
Average variable price	47.2	[3]	'
Pay | NGL [Member] | Receive Variable Pay Variable [Member] | Portion Of Contracts Maturing In 2014 | Physical Contracts [Member]	'		'
Average variable price	32.9	[3]	'
Pay | Liquids [Member] | Receive Variable Pay Fixed [Member] | Portion Of Contracts Maturing In 2013 | Swaps [Member]	'		'
Average fixed price	102.95	[3]	'
Pay | Liquids [Member] | Receive Variable Pay Fixed [Member] | Portion Of Contracts Maturing In 2013 | Physical Contracts [Member]	'		'
Average fixed price	105.97	[3]	'
Pay | Liquids [Member] | Receive Variable Pay Fixed [Member] | Portion Of Contracts Maturing In 2014 | Swaps [Member]	'		'
Average fixed price	101.95	[3]	'
Pay | Liquids [Member] | Receive Variable Pay Fixed [Member] | Portion Of Contracts Maturing In 2015 | Swaps [Member]	'		'
Average fixed price	100.93	[3]	'
Pay | Liquids [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2013 | Swaps [Member]	'		'
Average variable price	101.48	[3]	'
Pay | Liquids [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2013 | Physical Contracts [Member]	'		'
Average variable price	102.04	[3]	'
Pay | Liquids [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2014 | Swaps [Member]	'		'
Average variable price	95.41	[3]	'
Pay | Liquids [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2015 | Swaps [Member]	'		'
Average variable price	88.53	[3]	'
Pay | Liquids [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2016 | Swaps [Member]	'		'
Average variable price	84.81	[3]	'
Pay | Liquids [Member] | Receive Variable Pay Variable [Member] | Portion Of Contracts Maturing In 2013 | Physical Contracts [Member]	'		'
Average variable price	99.06	[3]	'
[1]	Volumes of natural gas are measured in MMBtu, whereas volumes of NGL and crude oil are measured in Bbl.
[2]	The fair value is determined based on quoted market prices at September 30, 2013 and DecemberB 31, 2012, respectively, discounted using the swap rate for the respective periods to consider the time value of money. Fair values are presented in millions of dollars and exclude credit valuation adjustments of approximately $0.2 million of losses at September 30, 2013 and $0.2 million of losses at DecemberB 31, 2012.
[3]	Weighted average prices received and paid are in $/MMBtu for natural gas and $/Bbl for NGL and crude oil.

Recovered_Sheet10

Derivative Financial Instruments And Hedging Activities (Fair Values Of Expected Cash Flows Of Outstanding Commodity Options) (Details) (Commodity [Member], USD $)	9 Months Ended		12 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013		Dec. 31, 2012
Credit valuation adjustments	$0		$0
Put Option [Member] | Written [Member] | Portion Of Option Contracts Maturing in 2013 | NGL [Member]	'		'
Notional	69,000	[1]	'
Strike Price	26.18	[2]	'
Market Price	10.68	[2]	'
Assets at Fair Value	0	[3]	0	[3]
Net Derivative Liabilitites	1.1	[3]	0	[3]
Put Option [Member] | Purchased [Member] | Portion Of Option Contracts Maturing in 2013 | Natural Gas [Member]	'		'
Notional	414,000	[1]	'
Strike Price	4.18	[2]	'
Market Price	3.48	[2]	'
Assets at Fair Value	0.3	[3]	1.4	[3]
Net Derivative Liabilitites	0	[3]	0	[3]
Put Option [Member] | Purchased [Member] | Portion Of Option Contracts Maturing in 2013 | NGL [Member]	'		'
Notional	138,000	[1]	'
Strike Price	31.26	[2]	'
Market Price	27.76	[2]	'
Assets at Fair Value	1.1	[3]	3.7	[3]
Net Derivative Liabilitites	0	[3]	0	[3]
Put Option [Member] | Purchased [Member] | Portion Of Option Contracts Maturing in 2014 | NGL [Member]	'		'
Notional	401,500	[1]	'
Strike Price	52.21	[2]	'
Market Price	50.44	[2]	'
Assets at Fair Value	3.1	[3]	1.3	[3]
Net Derivative Liabilitites	0	[3]	0	[3]
Put Option [Member] | Purchased [Member] | Portion Of Option Contracts Maturing in 2015 | NGL [Member]	'		'
Notional	547,500	[1]	'
Strike Price	53.76	[2]	'
Market Price	52.52	[2]	'
Assets at Fair Value	4.5	[3]	0	[3]
Net Derivative Liabilitites	0	[3]	0	[3]
Call Option [Member] | Written [Member] | Portion Of Option Contracts Maturing in 2014 | NGL [Member]	'		'
Notional	273,750	[1]	'
Strike Price	57.93	[2]	'
Market Price	48.65	[2]	'
Assets at Fair Value	0	[3]	0	[3]
Net Derivative Liabilitites	$0.90	[3]	$0	[3]
[1]	Volumes of natural gas are measured in MMBtu, whereas volumes of NGL and crude oil are measured in Bbl.
[2]	Strike and market prices are in $/MMBtu for natural gas and in $/Bbl for NGL and crude oil.
[3]	The fair value is determined based on quoted market prices at September 30, 2013 and DecemberB 31, 2012, respectively, discounted using the swap rate for the respective periods to consider the time value of money.

Income_Taxes_Narrative_Details

Income Taxes (Narrative) (Details) (USD $)	3 Months Ended		9 Months Ended		12 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012
Effective income tax rate	'	'	0.40%	0.50%	'
Income tax expense	$0.60	$1.30	$8.90	$2.10	'
Current income tax payable	'	'	1.7	'	3.7
Deferred income tax liability	10.5	'	10.5	'	3
Texas State Income Tax Rate [Member]	'	'	'	'	'
Deferred income tax liability	$6.60	'	$6.60	'	'

Segment_Information_Details

Segment Information (Details) (USD $)	3 Months Ended				9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013		Sep. 30, 2012		Sep. 30, 2013		Sep. 30, 2012		Dec. 31, 2012
Segment Reporting Information [Line Items]	'		'		'		'		'
Total revenue	$1,897		$1,710.60		$5,614		$5,391.90		'
Operating revenue	1,380.90		1,220.90		4,050.30		3,917.50		'
Cost of natural gas and natural gas liquids	1,244.30		1,038		3,553.40		3,322.50		'
Selling, General and Administrative Expense, Total	149.5		152.9		442.5		450.6		'
Operating and maintenance services	88.7		96.3		263.1		271.8		'
General and administrative services	25		22.3		73.1		77.7		'
Depreciation and amortization	35.8		34.3		106.3		101.1		'
Operating Income (Loss)	-12.9		30		54.4		144.4		'
Interest expense	0		0		0		0		'
Other income (expense)	0		0		0.2		-0.1		'
Income (loss) from continuing operations before income tax expense	-12.9		30		54.6		144.3		'
Income tax expense	0.6		1.3		8.9		2.1		'
Net income (loss)	-13.5		28.7		45.7		142.2		'
Total assets	5,441.40		'		5,441.40		'		5,667.40
Capital expenditures (excluding acquisitions)	205.8		331.7		205.8		331.7		'
Intersegment Revenue Eliminations [Member]	'		'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'		'
Total revenue	-516.1		-489.7		-1,563.70		-1,474.40		'
Processing and Transportation [Member]	'		'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'		'
Total revenue	668.2		683.8		2,034		2,015.10		'
Operating revenue	171.4		222		543		616.5		'
Segment gross margin	137.9		154.8		441.3		536.9		'
Cost of natural gas and natural gas liquids	33.5		67.2		101.7		79.6		'
Selling, General and Administrative Expense, Total	127.2		128.4		374.1		369.2		'
Operating and maintenance services	71		74.4		208.2		209.7		'
General and administrative services	22.1		21.6		64.6		63.9		'
Depreciation and amortization	34.1		32.4		101.3		95.6		'
Operating Income (Loss)	10.7		26.4		67.2		167.7		'
Other income (expense)	0		0		0		0		'
Income (loss) from continuing operations before income tax expense	10.7		26.4		67.2		167.7		'
Income tax expense	0		0		0		0		'
Net income (loss)	10.7		26.4		67.2		167.7		'
Total assets	4,829.30	[1]	4,372.10	[1]	4,829.30	[1]	4,372.10	[1]	'
Capital expenditures (excluding acquisitions)	177.9		317.8		177.9		317.8		'
Processing and Transportation [Member] | Intersegment Revenue Eliminations [Member]	'		'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'		'
Total revenue	-496.8		-461.8		-1,491		-1,398.60		'
Logistics and Marketing [Member]	'		'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'		'
Total revenue	1,228.80		1,026.80		3,580		3,376.80		'
Operating revenue	1,209.50		998.9		3,507.30		3,301		'
Segment gross margin	-1.3		28.1		55.6		58.1		'
Cost of natural gas and natural gas liquids	1,210.80		970.8		3,451.70		3,242.90		'
Selling, General and Administrative Expense, Total	22.3		24.7		68.4		81.6		'
Operating and maintenance services	17.7		20.1		54.9		60.3		'
General and administrative services	2.9		2.7		8.5		15.8		'
Depreciation and amortization	1.7		1.9		5		5.5		'
Operating Income (Loss)	-23.6		3.4		-12.8		-23.5		'
Other income (expense)	0		0		0		0		'
Income (loss) from continuing operations before income tax expense	-23.6		3.4		-12.8		-23.5		'
Income tax expense	0		0		0		0		'
Net income (loss)	-23.6		3.4		-12.8		-23.5		'
Total assets	557.4		903.6		557.4		903.6		'
Capital expenditures (excluding acquisitions)	14		3.1		14		3.1		'
Logistics and Marketing [Member] | Intersegment Revenue Eliminations [Member]	'		'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'		'
Total revenue	-19.3		-27.9		-72.7		-75.8		'
Corporate [Member]	'		'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'		'
Total revenue	0	[2]	0	[3]	0	[2]	0	[2]	'
Operating revenue	0	[2]	0	[3]	0	[2]	0	[2]	'
Segment gross margin	0	[2]	0	[3]	0	[2]	0	[2]	'
Cost of natural gas and natural gas liquids	0	[2]	0	[3]	0	[2]	0	[2]	'
Selling, General and Administrative Expense, Total	0	[2]	-0.2	[3]	0	[2]	-0.2	[2]	'
Operating and maintenance services	0	[2]	1.8	[3]	0	[2]	1.8	[2]	'
General and administrative services	0	[2]	-2	[3]	0	[2]	-2	[2]	'
Depreciation and amortization	0	[2]	0	[3]	0	[2]	0	[2]	'
Operating Income (Loss)	0	[2]	0.2	[3]	0	[2]	0.2	[2]	'
Other income (expense)	0	[2]	0	[3]	0.2	[2]	-0.1	[2]	'
Income (loss) from continuing operations before income tax expense	0	[2]	0.2	[3]	0.2	[2]	0.1	[2]	'
Income tax expense	0.6	[2]	1.3	[3]	8.9	[2]	2.1	[2]	'
Net income (loss)	-0.6	[2]	-1.1	[3]	-8.7	[2]	-2	[2]	'
Total assets	54.7	[1],[2]	138.3	[1],[2]	54.7	[1],[2]	138.3	[1],[2]	'
Capital expenditures (excluding acquisitions)	13.9	[2]	10.8	[2]	13.9	[2]	10.8	[2]	'
Corporate [Member] | Intersegment Revenue Eliminations [Member]	'		'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'		'
Total revenue	$0	[2]	$0	[3]	$0	[2]	$0	[2]	'
[1]	Totals assets for our Gathering, Processing and Transportation segment includes our long term equity investment in the Texas Express NGL system.
[2]	Corporate consists of income taxes, which are not allocated to the business segments.
[3]	Corporate consists of interest expense, interest income, allowance for equity during construction, noncontrolling interest and other costs such as income taxes, which are not allocated to the business segments.

Supplemental_Cash_Flows_Inform2

Supplemental Cash Flows Information (Details) (USD $)	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012
Discount accretion	$0	$0
Amortization of hedging costs	0.3	2.5
Texas Express long-term inventory (line fill)	-1.3	0
Allowance for doubtful accounts	0.2	0
Write-down of project costs	0	4.3
Environmental costs, net of recoveries	-0.1	0
Other elements included in 'Other' of 'Cash From Operating Activities'	-0.1	-0.1
Other	0.1	6.7
Additions to property, plant and equipment	206.6	315.1
Changes in construction payables	-0.8	16.6
Total capital expenditures (excluding joint venture)	205.8	331.7
Sale of South Haynesville Pipeline assets [Member]	'	'
Loss on sale of assets	$1.10	$0

Subsequent_Events_Narrative_De

Subsequent Events (Narrative) (Details) (USD $)	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012
Distribution Made to Limited Partner, Cash Distributions Paid	'	$242

Subsequent_Events_IPO_Agreemen

Subsequent Events - IPO Agreements (Details) (USD $)	9 Months Ended
	Sep. 30, 2013
Pro Forma [Member] | Subsequent Event [Member]	'
IPO Agreements [Line Items]	'
Payment obligation to EEP	$323,400,000
Debt Disclosure [Abstract]	'
Line of Credit Facility, Initiation Date	13-Nov-13
Pro Forma [Member] | CAPEX Reimbursement [Member] | Subsequent Event [Member]	'
IPO Agreements [Line Items]	'
Payment obligation to EEP	304,500,000
Pro Forma [Member] | Midcoast Energy Partners [Member] | Subsequent Event [Member]	'
IPO Agreements [Line Items]	'
General and Administrative Services, Reduction	9,800,000
Pro Forma [Member] | Midcoast Operating [Member] | Subsequent Event [Member]	'
IPO Agreements [Line Items]	'
General and Administrative Services, Reduction	25,000,000
Ownership Interest In Affiiate Of Partnership	39.00%
Pro Forma [Member] | Senior Revolving Credit Facility [Member] | Subsequent Event [Member]	'
Debt Disclosure [Abstract]	'
Line of Credit Facility, Current Borrowing Capacity	850,000,000
Line Of Credit Facility, Maximum Borrowing Capacity	1,000,000,000
Credit Facility term to maturity	'1 year 0 months 0 days
Number of Renewal Periods	4
Period Of Revolving Credit Agreement	'1 year 0 months 0 days
Pro Forma [Member] | Letter of Credit [Member] | Subsequent Event [Member]	'
Debt Disclosure [Abstract]	'
Line of Credit Facility, Current Borrowing Capacity	90,000,000
Pro Forma [Member] | Swing Line Facility [Member] | Subsequent Event [Member]	'
Debt Disclosure [Abstract]	'
Line of Credit Facility, Current Borrowing Capacity	75,000,000
Pro Forma [Member] | Financial Support Letter of Credit [Member] | Subsequent Event [Member]	'
Debt Disclosure [Abstract]	'
Line of Credit Facility, Current Borrowing Capacity	700,000,000
Line of Credit Facility, Commitment Fee Percentage	2.50%
Pro Forma [Member] | Working Capital Facility [Member]	'
Debt Disclosure [Abstract]	'
Credit facility maturity date	13-Nov-17
Pro Forma [Member] | Working Capital Facility [Member] | Subsequent Event [Member]	'
Debt Disclosure [Abstract]	'
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage	0.43%
Pro Forma [Member] | Working Capital Facility [Member] | London Interbank Offered Rate (LIBOR) [Member]	'
Debt Disclosure [Abstract]	'
Debt Instrument, Basis Spread on Variable Rate	2.50%
Pro Forma [Member] | Maximum [Member] | Senior Revolving Credit Facility [Member] | Subsequent Event [Member]	'
Debt Disclosure [Abstract]	'
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage	0.50%
Total Leverage Ratio	5
Interest Expense Covenant Ratio, Debt Instrument	2.5
Pro Forma [Member] | Maximum [Member] | Senior Revolving Credit Facility [Member] | Base Rate [Member] | Subsequent Event [Member]	'
Debt Disclosure [Abstract]	'
Debt Instrument, Basis Spread on Variable Rate	1.75%
Pro Forma [Member] | Maximum [Member] | Senior Revolving Credit Facility [Member] | Eurocurrency Rate [Member]	'
Debt Disclosure [Abstract]	'
Debt Instrument, Basis Spread on Variable Rate	2.75%
Pro Forma [Member] | Maximum [Member] | Secured Debt [Member] | Subsequent Event [Member]	'
Debt Disclosure [Abstract]	'
Total Leverage Ratio	4.25
Pro Forma [Member] | Maximum [Member] | Financial Support Letter of Credit [Member] | Subsequent Event [Member]	'
Debt Disclosure [Abstract]	'
Annual costs on Credit Facility	5,000,000
Pro Forma [Member] | Minimum [Member] | Senior Revolving Credit Facility [Member] | Subsequent Event [Member]	'
Debt Disclosure [Abstract]	'
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage	0.30%
Pro Forma [Member] | Minimum [Member] | Senior Revolving Credit Facility [Member] | Base Rate [Member] | Subsequent Event [Member]	'
Debt Disclosure [Abstract]	'
Debt Instrument, Basis Spread on Variable Rate	0.75%
Pro Forma [Member] | Minimum [Member] | Senior Revolving Credit Facility [Member] | Eurocurrency Rate [Member]	'
Debt Disclosure [Abstract]	'
Debt Instrument, Basis Spread on Variable Rate	1.75%
Pro Forma [Member] | Minimum [Member] | Financial Support Letter of Credit [Member] | Subsequent Event [Member]	'
Debt Disclosure [Abstract]	'
Annual costs on Credit Facility	$4,000,000
Pro Forma [Member] | Minimum [Member] | Working Capital Facility [Member] | Midcoast Operating [Member]	'
IPO Agreements [Line Items]	'
Ownership Interest In Affiiate Of Partnership	20.00%
Acquisition [Member] | Maximum [Member] | Senior Revolving Credit Facility [Member] | Subsequent Event [Member]	'
Debt Disclosure [Abstract]	'
Total Leverage Ratio	5.5
Acquisition [Member] | Maximum [Member] | Secured Debt [Member] | Subsequent Event [Member]	'
Debt Disclosure [Abstract]	'
Total Leverage Ratio	4.75

Subsequent_Events_IPO_Details

Subsequent Events - IPO (Details) (USD $)	9 Months Ended
In Millions, except Share data, unless otherwise specified	Sep. 30, 2013
Subsequent Event [Member]	'
Common Stock, Discount on Shares	$20
Pro Forma [Member] | Subsequent Event [Member]	'
Payments Of Stock Issuance Costs	1.2
Pro Forma [Member] | General Partner [Member] | Subsequent Event [Member]	'
Ownership Interest	2.00%
Number of units Issued	922,859
Pro Forma [Member] | Capital Unit, Class A [Member]	'
Proceeds from Issuance Initial Public Offering	333
Public Sale of Units, Net of Discounts and Fees	311.8
Pro Forma [Member] | Capital Unit, Class A [Member] | Subsequent Event [Member]	'
Ownership Interest	46.00%
Pro Forma [Member] | Initial Public Offering [Member] | Subsequent Event [Member]	'
Ownership interest by the public	39.00%
Pro Forma [Member] | Initial Public Offering [Member] | Enbridge Energy Partners | Subsequent Event [Member]	'
Ownership Interest	9.00%
Number of units Issued	4,110,056
Pro Forma [Member] | Intial Public Offering Overallotment [Member] | Subsequent Event [Member]	'
Ownership interest by the public	46.00%
Number of units Issued	2,775,000
Proceeds from Issuance Initial Public Offering	$47
Pro Forma [Member] | Subordinated Units [Member] | Enbridge Energy Partners | Subsequent Event [Member]	'
Ownership Interest	49.00%
Number of units Issued	22,610,056