Midcoast Energy Partners (MEP) 10-Q 1 May 15 2015 Q1 Quarterly report Financial data

Document_and_Entity_Informatio

Document and Entity Information	3 Months Ended
	Mar. 31, 2015	1-May-15
Document and Entity Information [Abstract]
Entity Registrant Name	Midcoast Energy Partners, L.P.
Entity Central Index Key	1578685
Document Type	10-Q
Document Period End Date	31-Mar-15
Amendment Flag	FALSE
Current Fiscal Year End Date	-19
Entity Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding		22,610,056
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	Q1
Trading Symbol	mep

CONSOLIDATED_STATEMENTS_OF_INC

CONSOLIDATED STATEMENTS OF INCOME (USD $)	3 Months Ended
In Millions, except Per Share data, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Operating revenues:
Operating revenue (Note 13)	$851.70	$1,589.70
Operating revenue - affiliate (Notes 11 and 13)	21.8	57.2
Total operating revenue	873.5	1,646.90
Operating expenses:
Cost of natural gas and natural gas liquids	779.1	1,488.70
Operating and maintenance	63.4	81.7
General and administrative	21	27.2
Depreciation and amortization (Note 7)	38.3	37
Costs and Expenses, Total	901.8	1,634.60
Operating income (loss)	-28.3	12.3
Interest expense, net (Notes 9 and 11)	6.7	3.3
Equity in earnings (loss) of joint ventures (Note 8)	5.7	-1.2
Other loss (Note 12)		-0.1
Income (loss) before income tax expense	-29.3	7.7
Income tax expense (Note 14)	0.8	1
Net income (loss)	-30.1	6.7
Less: Net income (loss) attributable to noncontrolling interest	-10.1	6.3
Net income (loss) attributable to general and limited partner ownership interest in Midcoast Energy Partners, L.P.	-20	0.4
Net income (loss) attributable to limited partner ownership interest	-19.6	0.4
Net income (loss) per limited partner unit (basic) (Note 2) (in dollars per share)	($0.43)	$0.01
Net income (loss) per limited partner unit (diluted) (Note 2) (in dollars per share)	($0.43)	$0.01
Weighted average limited partner units outstanding (basic) (in shares)	45.2	45.2
Weighted average limited partner units outstanding (diluted) (in shares)	45.2	45.2
Third Party [Member]
Operating expenses:
Cost of natural gas and natural gas liquids	761.2	1,458.50
Operating and maintenance	38.2	54.6
General and administrative	1.9	1.9
Affiliate [Member]
Operating expenses:
Cost of natural gas and natural gas liquids	17.9	30.2
Operating and maintenance	25.2	27.1
General and administrative	$19.10	$25.30

CONSOLIDATED_STATEMENTS_OF_COM

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME [Abstract]
Net income (loss)	($30.10)	$6.70
Other comprehensive income (loss), net of tax expense (benefit) of $0.0 million as of March 31, 2015 and 2014 (Note 13)	-2.9	0.2
Comprehensive income (loss)	-33	6.9
Less: Comprehensive income (loss) attributable to:
Noncontrolling interest (Note 11)	-10.1	6.3
Other comprehensive income (loss) attributed to noncontrolling interest (Note 11)	-1.4	0.2
Comprehensive income (loss) attributable to general and limited partner ownership interests in Midcoast Energy Partners, L.P.	($21.50)	$0.40

CONSOLIDATED_STATEMENTS_OF_COM1

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME [Abstract]
Other comprehensive income (loss), tax expense (benefit)	$0	$0

CONSOLIDATED_STATEMENTS_OF_CAS

CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Cash provided by operating activities:
Net income (loss)	($30.10)	$6.70
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization (Note 7)	38.3	37
Derivative fair value net (gains) losses (Note 13)	35.1	-4.6
Inventory market price adjustments (Note 6)	4.6	1.5
Distributions from investment in joint ventures	5.7	1.6
Equity (earnings) loss from investment in joint ventures (Note 8)	-5.7	1.3
Other	0.7	1
Changes in operating assets and liabilities, net of acquisitions:
Receivables, trade and other	-11.6	3.5
Due from General Partner and affiliates	44.4	616.3
Accrued receivables	184.9	59.2
Inventory (Note 6)	48.2	26.2
Current and long-term other assets (Note 13)	-12.1	-4.8
Due to General Partner and affiliates	4.8	-478.3
Accounts payable and other (Notes 5 and 13)	-9.3	-42.3
Accrued purchases (Note 12)	-115.9	-2.4
Interest payable	-4.1	0.5
Property and other taxes payable	-9.7	-8.6
Net cash provided by operating activities	168.2	213.8
Cash used in investing activities:
Additions to property, plant and equipment (Notes 7 and 16)	-56.1	-55.5
Changes in restricted cash (Note 11)	-2.7	47.5
Asset acquisitions (Note 3)	-44.1
Investment in joint ventures (Note 8)	-1.9	-7.3
Distributions from investment in joint ventures in excess of cumulative earnings	2.4
Other	-0.6
Net cash used in investing activities	-103	-15.3
Cash used in financing activities:
Net repayments under credit facility (Note 9)	-45	-85
Distributions to partners (Note 10)	-15.8	-7.7
Contributions from noncontrolling interest (Note 10)	20.7	39.7
Distributions to noncontrolling interest (Note 10)	-19.8	-37.4
Net cash used in financing activities	-59.9	-90.4
Net increase in cash and cash equivalents	5.3	108.1
Cash and cash equivalents at beginning of year		4.9
Cash and cash equivalents at end of period	$5.30	$113

CONSOLIDATED_STATEMENTS_OF_FIN

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Millions, unless otherwise specified
Current assets:
Cash and cash equivalents (Note 5)	$5.30
Restricted cash (Notes 11 and 13)	63.5	42.8
Receivables, trade and other, net of allowance for doubtful accounts of $1.8 million at March 31, 2015 and December 31, 2014	27.2	15.6
Due from General Partner and affiliates (Note 11)	7.6	49.7
Accrued receivables	44.7	229.6
Inventory (Note 6)	28.7	81.5
Other current assets (Note 13)	158.7	178.1
Assets, Current, Total	335.7	597.3
Property, plant and equipment, net (Note 7)	4,232.40	4,159.70
Goodwill	226.5	226.5
Intangible assets, net	277.9	247.7
Equity investment in joint ventures (Note 8)	380.1	380.6
Other assets, net (Note 13)	127	142.3
Total assets	5,579.60	5,754.10
Current liabilities:
Due to General Partner and affiliates (Note 11)	39.6	41.1
Accounts payable and other (Notes 5, 12 and 13)	114.4	113.8
Accrued purchases	253.8	375.2
Property and other taxes payable (Note 14)	11.2	20.9
Interest payable	0.9	5
Liabilities, Current, Total	419.9	556
Long-term debt (Note 9)	715	760
Other long-term liabilities (Notes 12 and 14)	48.5	41.5
Total liabilities	1,183.40	1,357.50
Commitments and contingencies (Note 12)
Partners' capital (Note 10):
General Partner units (922,859 authorized and issued at March 31, 2015 and December 31, 2014)	47	47.8
Accumulated other comprehensive income (Note 13)	10.1	11.6
Total Midcoast Energy Partners, L.P. partners' capital	1,830.30	1,867.60
Noncontrolling interest	2,565.90	2,529
Total partners' capital	4,396.20	4,396.60
Liabilities and Stockholders' Equity, Total	5,579.60	5,754.10
Class A Common Units [Member]
Partners' capital (Note 10):
Limited Partner interest	616.7	634.2
Subordinated Units [Member]
Partners' capital (Note 10):
Limited Partner interest	$1,156.50	$1,174

CONSOLIDATED_STATEMENTS_OF_FIN1

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION (Parenthetical) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Millions, except Share data, unless otherwise specified
Receivables, trade and other, allowance for doubtful accounts (in dollars)	$1.80	$1.80
General Partner, units outstanding (in shares)	922,859	922,859
Class A Common Units [Member]
Partners Capital units, outstanding (in shares)	22,610,056	22,610,056
Subordinated Units [Member]
Partners Capital units, outstanding (in shares)	22,610,056	22,610,056

ORGANIZATION_AND_NATURE_OF_OPE

ORGANIZATION AND NATURE OF OPERATIONS	3 Months Ended
	Mar. 31, 2015
ORGANIZATION AND NATURE OF OPERATIONS [Abstract]
ORGANIZATION AND NATURE OF OPERATIONS	1. ORGANIZATION AND NATURE OF OPERATIONS
	Midcoast Energy Partners, L.P. is a publicly-traded Delaware limited partnership formed by Enbridge Energy Partners, L.P., or EEP, to serve as EEP's primary vehicle for owning and growing its natural gas and natural gas liquids midstream business in the United States. Midcoast Energy Partners, L.P., together with its consolidated subsidiaries, are referred to in this report as “we,” “us,” “our,” “MEP” and the “Partnership”.  For the first six months of 2014, we owned a 39% controlling interest in Midcoast Operating, L.P., or Midcoast Operating. EEP owned the remaining 61% interest in Midcoast Operating. On July 1, 2014, we purchased an additional 12.6% interest in Midcoast Operating from EEP. We own and operate, through our current 51.6% interest in Midcoast Operating, 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. EEP owns a 48.4% noncontrolling interest in Midcoast Operating. EEP also has a significant interest in us through its ownership of our General Partner, which owns all of our General Partner units and all of our incentive distribution rights, as well as an approximate 52% limited partner interest in us. Our Class A common units trade on the New York Stock Exchange, or NYSE, under the ticker symbol MEP.
	Basis of Presentation
	We have prepared the accompanying unaudited interim consolidated financial statements in accordance with accounting principles generally accepted in the United States, or GAAP, for the interim consolidated financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. Accordingly, the unaudited interim consolidated financial statements do not include all the information and notes 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 March 31, 2015, our results of operations for the three-month periods ended March 31, 2015, and 2014, and our cash flows for the three-month periods ended March 31, 2015, and 2014. We derived our consolidated statement of financial position as of December 31, 2014, from the audited financial statements included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2014. Our results of operations for the three-month periods ended March 31, 2015 and 2014, 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 unaudited interim consolidated financial statements should be read in conjunction with the audited consolidated financial statements and accompanying notes thereto presented in our Annual Report on Form 10-K for the fiscal year ended December 31, 2014.

NET_INCOME_PER_LIMITED_PARTNER

NET INCOME PER LIMITED PARTNER AND GENERAL PARTNER INTEREST	3 Months Ended
	Mar. 31, 2015
NET INCOME PER LIMITED PARTNER AND GENERAL PARTNER INTEREST [Abstract]
NET INCOME PER LIMITED PARTNER AND GENERAL PARTNER INTEREST	2. NET INCOME PER LIMITED PARTNER AND GENERAL PARTNER INTEREST
	We allocate our net income among our General Partner and limited partners using the two-class method. Under the two-class method, we allocate our net income to our limited partners, our General Partner and the holders of our incentive distribution rights, or IDRs, in accordance with the terms of our partnership agreement. We also allocate any earnings in excess of distributions to our limited partners, our General Partner and the holders of the IDRs in accordance with the terms of our partnership agreement. We allocate any distributions in excess of earnings for the period to our General Partner and our limited partners based on their respective proportionate ownership interests in us, after taking into account distributions to be paid with respect to the IDRs, as set forth in our partnership agreement.
	Distribution Targets		Portion of Quarterly			Percentage Distributed				Percentage Distributed
			Distribution Per Unit			to Limited Partners				to General Partner
	Minimum Quarterly Distribution		Up to $0.3125				98	%			2	%
	First Target Distribution		> $0.3125 to $0.359375				98	%			2	%
	Second Target Distribution		> $0.359375 to $0.390625				85	%			15	%
	Third Target Distribution		> $0.390625 to $0.468750				75	%			25	%
	Over Third Target Distribution		In excess of $0.468750				50	%			50	%
	We determined basic and diluted net income (loss) per limited partner unit as follows:
			For the three-month period ended March 31,
			2015				2014
			(in millions, except per unit amounts)
	Net income (loss)		$	(30.1	)		$	6.7
	Less: Net income (loss) attributable to noncontrolling interest			(10.1	)			6.3
	Net income (loss) attributable to general and limited partner interests in Midcoast Energy Partners, L.P.			(20.0	)			0.4
	Less distributions:
	Total distributed earnings to our General Partner			(0.3	)			(0.3	)
	Total distributed earnings to our limited partners			(15.7	)			(14.1	)
	Total distributed earnings			(16.0	)			(14.4	)
	Overdistributed earnings		$	(36.0	)		$	(14.0	)
	Weighted average limited partner units outstanding			45.2				45.2
	Basic and diluted earnings per unit:
	Distributed earnings per limited partner unit(1)		$	0.35			$	0.31
	Overdistributed earnings per limited partner unit(2)			(0.78	)			(0.30	)
	Net income (loss) per limited partner unit (basic and diluted)		$	(0.43	)		$	0.01
	(1)	Represents the total distributed earnings to limited partners divided by the weighted average number of limited partner interests outstanding for the period.
	(2)	Represents the limited partners' share (98%) of distributions in excess of earnings divided by the weighted average number of limited partner interests outstanding for the period and underdistributed earnings allocated to the limited partners based on the distribution waterfall that is outlined in our partnership agreement.

ACQUISITIONS

ACQUISITIONS	3 Months Ended
	Mar. 31, 2015
ACQUISITIONS [Abstract]
ACQUISITIONS	3. ACQUISITIONS
	We account for acquisitions using the acquisition method and record the identifiable assets acquired and liabilities assumed at their acquisition-date fair values. We have included the results of operations from this acquisition in our operating results from the acquisition date.
	On February 27, 2015, we acquired the midstream business of New Gulf Resources, LLC, or NGR, in Leon, Madison and Grimes counties, Texas for $85.1 million in cash and a contingent future payment of up to $17.0 million. Of the $85.1 million purchase price, $20.0 million was placed into escrow, pending the resolution of a legal matter and NGR's completion of additional wells connecting to our system. During March 2015, $2.0 million was released from escrow and paid to NGR. The remaining $18.0 million in escrow has been classified as “Restricted cash” in our condensed consolidated statement of financial position as of March 31, 2015.
	If NGR is able to deliver volumes into the system at certain tiered volume levels over a five-year period, we will be obligated to make future tiered payments up to $17.0 million. This could result in a maximum total purchase price of $102.1 million. The potential payment is considered contingent consideration. The fair value of this contingent consideration, using a probability-weighted discounted cash flow model is $2.3 million. The contingent consideration is presented in “Other long-term liabilities” in our statement of financial position as of March 31, 2015 and will be remeasured on a fair value basis each quarter until the performance bonus is paid or expires.
	The acquisition consisted of a natural gas gathering system that is currently in operation moving equity and third party production. Funding was provided by us and EEP based on our proportionate ownership percentages in Midcoast Operating, which are 51.6% and 48.4%, respectively. EEP paid its portion of the funding directly to NGR. Our consolidated statement of cash flows does not reflect the amount paid directly to NGR by EEP.
	As of March 31, 2015, the consideration paid and the purchase price allocation related to the NGR acquisition, as adjusted to date, are as follows.
		March 31,
		2015
		(in millions)
	Consideration:
	Cash consideration	$	85.1
	Contingent consideration		2.3
		$	87.4
	Identifiable assets acquired in business combination:
	Property, plant and equipment	$	55.1
	Intangible assets		32.3
		$	87.4
	The weighted-average amortization period of intangible assets related to the NGR acquisition is 15 years. Our consolidated operating revenue and net income included $0.1 million and $0.1 million, respectively, from NGR for the three-month period ended March 31, 2015.
	Since the effective date of the NGR midstream business acquisition was February 27, 2015, our consolidated statements of income do not include earnings from this business prior to that date. The following table presents selected unaudited pro forma earnings information for the three-month periods ended March 31, 2015 and 2014 as if the acquisition had been completed on January 1, 2014. This pro forma information was prepared using historical financial data for the NGR midstream business and reflects certain estimates and assumptions made by our management based on currently available information. Our unaudited pro forma financial information is not necessarily indicative of what our consolidated financial results would have been for the three-month periods ended March 31, 2015 and 2014 had we acquired the NGR midstream business on January 1, 2014.
		For the three-month
		period ended March 31,
		2015			2014
		(unaudited; in millions,
		except per unit amounts)
	Pro forma earnings data:
	Operating revenue	$	873.6		$	1,647.20
	Operating expenses	$	902.2		$	1,635.50
	Operating income (loss)	$	(28.6	)	$	11.7
	Net income (loss)	$	(30.4	)	$	6.1
	Net income (loss) attributable to noncontrolling interest	$	(10.2	)	$	5.9
	Net income (loss) attributable to limited partner ownership interest	$	(20.2	)	$	0.2
	Basic and diluted earnings per unit:
	As reported net income (loss) per limited partner unit (basic and diluted)	$	(0.43	)	$	0.01
	Pro forma net income (loss) per limited partner unit (basic and diluted)	$	(0.43	)	$	—

EQUITYBASED_COMPENSATION

EQUITY-BASED COMPENSATION	3 Months Ended
	Mar. 31, 2015
EQUITY-BASED COMPENSATION [Abstract]
EQUITY-BASED COMPENSATION	4. EQUITY-BASED COMPENSATION
	In connection with our initial public offering, or the Offering, our General Partner has adopted the 2013 Midcoast Energy Partners, L.P. Long-Term Incentive Plan, or the LTIP. The LTIP provides for the grant, from time to time at the discretion of the board of directors of our General Partner or any delegate thereof, subject to applicable law, of unit awards, restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights and other unit-based awards, provided that while we are an affiliate of Enbridge, awards will only be granted following a recommendation of the board of directors or compensation committee of Enbridge. The purpose of awards under the LTIP is to provide additional incentive compensation to individuals providing services to us, and to align the economic interests of such individuals with the interests of our unitholders.
	On February 17, 2015, the Board approved the first Performance Stock Unit, or PSU grants, effective January 1, 2015, under the LTIP. These PSUs were granted to employees of affiliates of our General Partner performing services on our behalf and provide for cash awards to be paid following a three-year performance cycle, at the end of which the units will vest 100%. Awards are calculated by multiplying the number of units outstanding at the end of the performance period by our weighted average share price for the 20 days prior to the maturity of the grant and by a performance multiplier. Any cash distributions paid will be notionally reinvested during the investment cycle.
	The performance multiplier ranges from zero, if our performance fails to meet threshold performance levels, to a maximum of two if we perform within the highest range of its performance targets. The 2015 PSU grants derive the performance multiplier through a calculation of our distributable cash flow per unit relative to targets established at the time of grant and yield relative to a specified peer group of companies.
	The following table presents PSU activity for the period indicated:
					Weighted
					Average
			Performance		Remaining		Average
			Stock		Contractual		Intrinsic Value
			Units		Term (years)		(in millions)
	Outstanding at January 1, 2015			—
		Units granted		323,880
		Units matured		—
		Units forfeited		—
		Dividend reinvested		8,284
	Outstanding at March 31, 2015			332,164		2.8	$	4.6
	The PSU grants are paid in cash and therefore classified as a liability award. The liability is re-measured at fair value on each reporting date until the award is settled, with the offset for the change in fair value being recorded as compensation expense based on the percentage of the requisite service that has been rendered at the reporting date. During the vesting term, compensation expense is determined based on the number of PSUs outstanding, the current market price of our units, dividends reinvested, and performance multipliers. To calculate the compensation expense for the three-month period ended March 31, 2015, performance multipliers of one, based on estimates as of March 31, 2015, were used for the 2015 PSU grants. The LTIP agreement and the individual award agreements are between our General Partner and the participants in the LTIP agreement. The associated compensation costs and liability are recorded in our consolidated financial statements based on the approved allocation methodology as some of the recipients of our PSU awards provide shared services to us, EEP and other Enbridge entities. Similar to other employee compensation costs, Enbridge Employee Services Incorporated, or EESI, will make the PSU payments to the LTIP participants on behalf of us, EEP and other Enbridge entities who will then reimburse EESI, for their respective obligation, via affiliate payable for the disbursements made to the participants.
	As of March 31, 2015, compensation expense recorded for the PSUs was $0.4 million, of which our allocated share of the cost is currently estimated to be $0.1 million. The unrecognized compensation expense related to non-vested units granted was $5.7 million and is expected to be fully recognized over a weighted-average period of approximately three years.

CASH_AND_CASH_EQUIVALENTS

CASH AND CASH EQUIVALENTS	3 Months Ended
	Mar. 31, 2015
CASH AND CASH EQUIVALENTS [Abstract]
CASH AND CASH EQUIVALENTS	5. CASH AND CASH EQUIVALENTS
	We extinguish liabilities when a creditor has relieved us of our obligation, which occurs when our financial institution honors a check that the creditor has presented for payment. Accordingly, obligations for which we have made payments that have not yet been presented to the financial institution, totaling approximately $6.9 million at March 31, 2015, and $6.6 million at December 31, 2014, are included in “Accounts payable and other” on our consolidated statements of financial position.

INVENTORY

INVENTORY	3 Months Ended
	Mar. 31, 2015
INVENTORY [Abstract]
INVENTORY	6. INVENTORY
		Our inventory is comprised of the following:
			March 31,		December 31,
			2015		2014
			(in millions)
		Materials and supplies	$	0.7	$	0.7
		Crude oil inventory		5.5		2
		Natural gas and NGL inventory		22.5		78.8
			$	28.7	$	81.5
	The “Cost of natural gas and natural gas liquids” on our consolidated statements of income includes charges totaling $4.6 million and $1.5 million for the three-month periods ended March 31, 2015 and 2014, 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	3 Months Ended
	Mar. 31, 2015
PROPERTY, PLANT AND EQUIPMENT [Abstract]
PROPERTY, PLANT AND EQUIPMENT	7. PROPERTY, PLANT AND EQUIPMENT
	Our property, plant and equipment is comprised of the following:
			March 31,			December 31,
			2015			2014
			(in millions)
		Land	$	11.3		$	11.1
		Rights-of-way		429			405
		Pipelines		1,845.80			1,785.70
		Pumping equipment, buildings and tanks		82.6			82.1
		Compressors, meters and other operating equipment		2,096.60			2,074.80
		Vehicles, office furniture and equipment		167.6			163.8
		Processing and treating plants		533			516
		Construction in progress		199.3			218.7
		Total property, plant and equipment		5,365.20			5,257.20
		Accumulated depreciation		(1,132.8	)		(1,097.5	)
		Property, plant and equipment, net	$	4,232.40		$	4,159.70

EQUITY_INVESTMENTS_IN_JOINT_VE

EQUITY INVESTMENTS IN JOINT VENTURES	3 Months Ended
	Mar. 31, 2015
EQUITY INVESTMENTS IN JOINT VENTURES [Abstract]
EQUITY INVESTMENTS IN JOINT VENTURES	8. EQUITY INVESTMENTS IN JOINT VENTURES
	We have a 35% aggregate interest in the Texas Express NGL system, which is comprised of two joint ventures with third parties. The Texas Express NGL system consists of a 593-mile NGL intrastate transportation pipeline and a related NGL gathering system. Our investment in the Texas Express NGL system is presented in “Equity investment in joint ventures” on our consolidated statements of financial position. “Equity in earnings of joint ventures” on our consolidated statements of income represents our earnings related to these joint ventures. The following table presents unaudited income statement information for the Texas Express NGL system on a combined, 100% basis for the periods presented:
			For the three-month period
			ended March 31,
			2015		2014
			(in millions)
		Operating revenues	$	28.8	$	5.3
		Operating expenses	$	11	$	8.4
		Net income (loss)	$	17.7	$	(3.1	)

DEBT

DEBT	3 Months Ended
	Mar. 31, 2015
DEBT [Abstract]
DEBT	9. DEBT
	The following table presents the carrying amounts, net of related unamortized discounts, of our consolidated debt obligations.
			Interest Rate				March 31, 2015		December 31, 2014
							(in millions)
	Credit Agreement			2.675	%		$	315	$	360
	Series A Senior Notes due 2019			3.56	%			75		75
	Series B Senior Notes due 2021			4.04	%			175		175
	Series C Senior Notes due 2024			4.42	%			150		150
	Total						$	715	$	760
	Our interest cost for the three-month periods ended March 31, 2015, and 2014, is comprised of the following:
			For the three-month period
			ended March 31,
			2015				2014
			(in millions)
	Interest cost incurred		$	7.6			$	3.3
	Interest capitalized			0.9				—
	Interest expense, net		$	6.7			$	3.3
	Debt Arrangements
	Credit Agreement
	We, Midcoast Operating, and our material domestic subsidiaries are parties to a Credit Agreement, which permits aggregate borrowings of up to, at any one time outstanding, $850.0 million. The original term of the Credit Agreement was three years, with an initial maturity date of November 13, 2016, subject to four one-year requests for extensions. On September 30, 2014, we amended our Credit Agreement to extend the maturity date from November 13, 2016 to September 30, 2017; however, $140.0 million of commitments will expire on the original maturity date of November 13, 2016.
	At March 31, 2015, we had $315.0 million in outstanding borrowings under the Credit Agreement at a weighted average interest rate of 2.7%. Under the Credit Agreement, we had net repayments of approximately $45.0 million during the three-month period ended March 31, 2015, which includes gross borrowings of $1,150.0 million and gross repayments of $1,195.0 million. At March 31, 2015, we were in compliance with the terms of our financial covenants in the Credit Agreement.
	Senior Notes
	Our senior notes in the aggregate amount of $400.0 million were issued in a private placement on September 30, 2014 and consist of three tranches: $75.0 million of 3.56% Series A Senior Notes due in 2019; $175.0 million of 4.04% Series B Senior Notes due in 2021; and $150.0 million of 4.42% Series C Senior Notes due in 2024, collectively the Notes. All of the Notes pay interest semi-annually on March 31 and September 30, commencing on March 31, 2015. At March 31, 2015, we were in compliance with the terms of our financial covenants under the purchase agreement.
	Financial Support Agreement
	Midcoast Operating is party to a Financial Support Agreement with EEP, pursuant to which EEP provides 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.
	The annual costs that Midcoast Operating will incur under the Financial Support Agreement 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. Midcoast Operating incurred $0.2 million of these costs for the three-month period ended March 31, 2015, which is included in “Operating and maintenance-affiliate” on our consolidated statements of income.
	Available Credit
	At March 31, 2015, we have approximately $535.0 million available under the terms of our Credit Agreement, determined as follows:
					(in millions)
		Total credit limit under Credit Agreement			$	850
		Amounts outstanding under Credit Agreement				(315.0	)
		Total amount available at March 31, 2015			$	535
	Fair Value of Debt Obligations
	The carrying amounts of our outstanding borrowings under the Credit Agreement approximate the fair values at March 31, 2015, and December 31, 2014, respectively, due to the short-term nature and frequent repricing of the amounts outstanding under these obligations. The outstanding borrowings under the Credit Agreement are included with our long-term debt obligations above since we have the ability and the intent to refinance the amounts outstanding on a long-term basis.
	The approximate fair values of our fixed-rate debt obligations were $391.9 million at March 31, 2015. We determined the approximate fair values using a standard methodology that incorporates pricing points that are obtained from independent, third-party investment dealers who actively make markets in our debt securities. We use these pricing points to calculate the present value of the principal obligation to be repaid at maturity and all future interest payment obligations for any debt outstanding. The fair value of our long-term debt obligations is categorized as Level 2 within the fair value hierarchy.

PARTNERS_CAPITAL

PARTNERS' CAPITAL	3 Months Ended
	Mar. 31, 2015
PARTNERS' CAPITAL [Abstract]
PARTNERS' CAPITAL	10. PARTNERS' CAPITAL
	Distribution to Partners
	The following table sets forth our distributions, as approved by the board of directors of our General Partner, during the three-month period ended March 31, 2015.
	Distribution			Distribution			Distribution				Cash
	Declaration Date		Record Date	Payment Date			per Unit				Distributed
							(in millions, except per unit amounts)
		28-Jan-15	6-Feb-15	13-Feb-15			$	0.3425			$	15.8
	Changes in Partners' Capital
	The following table presents significant changes in partners' capital accounts attributable to our General Partner and limited partners as well as the noncontrolling interest in our consolidated subsidiary during the three-month period ended March 31, 2015 and 2014.
				For the three-month
				period ended March 31,
				2015				2014
				(in millions)
	Class A common units:
	Beginning balance			$	634.2			$	495.3
	Net income (loss)				(9.8	)			0.2
	Distributions				(7.7	)			(3.7	)
	Ending balance			$	616.7			$	491.8
	Subordinated units:
	Beginning balance			$	1,174.00			$	1,035.10
	Net income (loss)				(9.8	)			0.2
	Distributions				(7.7	)			(3.8	)
	Ending balance			$	1,156.50			$	1,031.50
	General Partner units:
	Beginning balance			$	47.8			$	42.2
	Net loss				(0.4	)			(0.2	)
	Distributions				(0.4	)			—
	Ending balance			$	47			$	42
	Accumulated other comprehensive income (loss)
	Beginning balance			$	11.6			$	(3.1	)
	Changes in fair value of derivative financial instruments reclassified to earnings				(4.3	)			6.5
	Changes in fair value of derivative financial instruments recognized in other comprehensive income (loss)				2.8				(6.3	)
	Ending balance			$	10.1			$	(2.9	)
	Noncontrolling interest
	Beginning balance			$	2,529.00			$	2,983.20
	Capital contributions				68.2				46.1
	Comprehensive income:
	Net income (loss)				(10.1	)			6.3
	Other comprehensive income (loss), net of tax				(1.4	)			0.2
	Distributions to noncontrolling interest				(19.8	)			(37.4	)
	Ending balance			$	2,565.90			$	2,998.40
	Total partners' capital at end of period			$	4,396.20			$	4,560.80
	Securities Authorized for Issuance under Equity Compensation Plans
	In connection with our LTIP, we filed a registration statement on Form S-8 with the SEC registering the issuance of 3,750,000 Class A common units that are issuable pursuant to awards granted under the LTIP. As of March 31, 2015, we have not issued any Class A common units under our LTIP.
	Shelf-Registration Statement
	From time to time, we may seek to satisfy liquidity needs through the issuance of registered debt or equity securities. To that end, in December 2014, we filed a shelf registration statement on Form S-3 with the SEC with a proposed aggregate offering price for all securities registered of $1.5 billion, which became effective on February 5, 2015.

RELATED_PARTY_TRANSACTIONS

RELATED PARTY TRANSACTIONS	3 Months Ended
	Mar. 31, 2015
RELATED PARTY TRANSACTIONS [Abstract]
RELATED PARTY TRANSACTIONS	11. RELATED PARTY TRANSACTIONS
	Intercorporate Services Agreement
	We do not directly employ any of the individuals responsible for managing or operating our business nor do we have any directors. We have an Intercorporate Services Agreement with EEP, pursuant to which EEP and its affiliates provides us with services as set forth in the agreement, which include such functions as management, accounting, operational and administrative personnel, among other such functions.
	Under the Intercorporate Services Agreement, we reimburse EEP and its affiliates for the costs and expenses incurred in providing us with such services. The affiliate amounts incurred by us through EEP for services received pursuant to the Intercorporate Services Agreement are reflected in “Operating and maintenance – affiliate” and “General and administrative – affiliate” on our consolidated statements of income. 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. As a result, for the three-month period ended March 31, 2015, we recognized $6.3 million as a reduction to “Due to General Partner and affiliates” with the offset recorded as a contribution to “Noncontrolling interest” in our consolidated statements of financial position.
	Enbridge and Enbridge Management and their respective affiliates allocated direct workforce costs to us for our construction projects of $0.5 million and $5.8 million as of March 31, 2015, and December 31, 2014, respectively, that we recorded as additions to “Property, plant and equipment, net” on our consolidated statements of financial position.
	Affiliate Revenues and Purchases
	We sell natural gas, NGLs and crude oil at market prices on the date of sale to Enbridge and its affiliates. The sales to Enbridge and its affiliates are presented in “Operating revenue - affiliate” on our consolidated statements of income. We also purchase natural gas, NGLs and crude oil at market prices on the date of purchase from Enbridge and its affiliates for sale to third parties. 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.
	Also, included in “Cost of natural gas and natural gas liquids – affiliate”, for the three-month periods ended March 31, 2015 and 2014, are $5.8 million and $5.3 million, respectively, of pipeline transportation and demand fees from Texas Express NGL system. 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 2015 to 2022.
	Routine purchases and sales with affiliates are settled monthly through MEP's centralized treasury function at terms that are consistent with third-party transactions for the three-month periods ended March 31, 2015 and 2014. 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.
	Partners' Capital Transactions
	Midcoast Operating paid cash distributions totaling $19.8 million and $37.4 million to EEP during the three-month periods ended March 31, 2015 and 2014, respectively, for its ownership interest in Midcoast Operating. In addition, we paid cash distributions totaling $8.5 million and $4.1 million to EEP for the three-month periods ended March 31, 2015 and 2014, respectively, for its ownership interest in us. These amounts are reflected in “Distributions to noncontrolling interest” and “Distributions to partners”, respectively, on our consolidated statements of cash flows.
	Sale of Accounts Receivable
	For the three-month periods ended March 31, 2015 and 2014, we sold and derecognized $705.4 million and $976.3 million, respectively, of receivables to an indirect wholly-owned subsidiary of Enbridge. For the three-month periods ended March 31, 2015 and 2014, we received cash proceeds of $705.2 million and $976.0 million, respectively. As of March 31, 2015 and December 31, 2014, $242.5 million and $272.7 million, respectively, of the receivables were outstanding and had not been collected on behalf of the Enbridge subsidiary.
	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-month periods ended March 31, 2015 and 2014, the expense stemming from the discount on the receivables sold was $0.2 million and $0.3 million, respectively.
	As of March 31, 2015 and December 31, 2014, we had $22.9 million and $17.7 million, respectively, included in “Restricted cash” on our consolidated statements of financial position, consisting of cash collections related to the receivables sold that have yet to be remitted to the Enbridge subsidiary.

COMMITMENTS_AND_CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	3 Months Ended
	Mar. 31, 2015
COMMITMENTS AND CONTINGENCIES [Abstract]
COMMITMENTS AND CONTINGENCIES	12. 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 March 31, 2015, we did not have any remaining material accrued environmental liabilities. As of December 31, 2014, we had $0.2 million of accrued environmental liabilities included in “Other long-term liabilities.”
	Legal and Regulatory Proceedings
	We are a participant in a number of legal proceedings arising in the ordinary course of business. Some of these proceedings are covered, in whole or in part, by insurance. While the ultimate outcome and impact to us cannot be predicted with certainty, we believe the outcome of all these proceedings will not, individually or in the aggregate, have a material adverse effect on our financial position, results of operations or cash flows. In addition, we are not aware of any significant legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statutes to which we are subject.

DERIVATIVE_FINANCIAL_INSTRUMEN

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES	3 Months Ended
	Mar. 31, 2015
DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES [Abstract]
DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES	13. 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 the variability in future cash flows associated with commodity price risks through 2020 in accordance with our risk management policies. Our derivative instruments that qualify for hedge accounting under authoritative guidance are classified as cash flow hedges.
	Derivative Positions
	Our derivative financial instruments are included at their fair values in the consolidated statements of financial position as follows:
			March 31,				December 31,
			2015				2014
			(in millions)
	Other current assets		$	133.5			$	164.7
	Other assets, net			76.4				91.5
	Accounts payable and other (1)			(61.7	)			(74.4	)
	Other long-term liabilities			(21.0	)			(22.5	)
	Due from General Partner and affiliates			0.1				0.3
			$	127.3			$	159.6
	-1	Includes $22.6 million and $28.4 million of cash collateral at March 31, 2015 and December 31, 2014, respectively.
	The changes in the 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 natural gas, NGL and crude oil sales and purchase contracts.
	The table below summarizes our derivative balances by counterparty credit quality (negative amounts represent our net obligations to pay the counterparty).
			March 31,				December 31,
			2015				2014
			(in millions)
	Counterparty Credit Quality (1)
	AAA		$	0.4			$	0.1
	AA  (2)			69.5				74.4
	A			47.4				67.1
	Lower than A			10				18
			$	127.3			$	159.6
	(1)	As determined by nationally-recognized statistical ratings organizations.
	(2)	Includes $22.6 million and $28.4 million of cash collateral at March 31, 2015 and December 31, 2014, respectively.
	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 include any cash collateral received in the balances listed above. As of March 31, 2015, and December 31, 2014, we were holding cash collateral of $22.6 million and $28.4 million on our asset exposures, respectively. Cash collateral is classified as “Restricted cash” in our consolidated statements of financial position. 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. We generally provide 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 March 31, 2015, and December 31, 2014, we had credit concentrations in the following industry sectors, as presented below:
			March 31,				December 31,
			2015				2014
			(in millions)
	United States financial institutions and investment banking entities (1)		$	80.3			$	88.5
	Non-United States financial institutions			19				30.7
	Integrated oil companies			0.1				1.7
	Other			27.9				38.7
			$	127.3			$	159.6
	(1)	Includes $22.6 million and $28.4 million of cash collateral at March 31, 2015 and December 31, 2014, respectively.
	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, or OTC, derivatives is directly with our counterparty and continues until the maturity or termination of the contracts.
	Effect of Derivative Instruments on the Consolidated Statements of Financial Position
					Asset Derivatives								Liability Derivatives
					Fair Value at								Fair Value at
			Financial Position		March 31,				December 31,				March 31,				December 31,
			Location		2015				2014				2015				2014
					(in millions)
	Derivatives designated as cash flow hedging instruments (1)
	Commodity contracts		Other current assets		$	20.7			$	26.1			$	—			$	—
	Commodity contracts		Other assets			—				2.1				—				—
						20.7				28.2				—				—
	Derivatives not designated as hedging instruments
	Commodity contracts		Other current assets			112.8				138.6				—				—
	Commodity contracts		Other assets			76.4				89.4				—				—
	Commodity contracts		Accounts payable and other  (2)			—				—				(39.1	)			(46.0	)
	Commodity contracts		Other long-term liabilities			—				—				(21.0	)			(22.5	)
	Commodity contracts		Due from general partner			0.1				0.3				—				—
			and affiliates
						189.3				228.3				(60.1	)			(68.5	)
	Total derivative instruments				$	210			$	256.5			$	(60.1	)		$	(68.5	)
	(1)	Includes items currently designated as hedging instruments. Excludes the portion of de-designated hedges which may have a component remaining in AOCI.
	(2)	Excludes total of $22.6 million and $28.4 million of cash collateral at March 31, 2015 and December 31, 2014, respectively.
	Accumulated Other Comprehensive Income
	Also included in AOCI, as of March 31, 2015, are unrecognized gains of approximately $0.5 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 gains are reclassified to earnings over the periods during which the originally hedged forecasted transactions affect earnings.
During the three-month periods ended March 31, 2015 and 2014, unrealized commodity hedge gains of $0.6 million and losses of $0.1 million, respectively, were de-designated as a result of the hedges no longer meeting hedge accounting criteria. We estimate that approximately $21.7 million, representing unrealized net gains from our cash flow hedging activities based on pricing and positions at March 31, 2015, will be reclassified from AOCI to earnings during the next 12 months.
Effect of Derivative Instruments on the Consolidated Statements of Income and Accumulated Other Comprehensive Income
Derivatives in Cash Flow		Amount of Gain (Loss)				Location of Gain (Loss)		Amount of Gain (Loss)				Location of Gain		Amount of Gain
Hedging Relationships		Recognized in				Reclassified from		Reclassified from				(Loss) Recognized in		(Loss) Recognized in
		AOCI on Derivative				AOCI to Earnings		AOCI to Earnings				Earnings on Derivative		Earnings on
		(Effective Portion)				(Effective Portion)		(Effective Portion)				(Ineffective Portion and		Derivative
												Amount Excluded from		(Ineffective Portion
												Effectiveness Testing) (1)		and Amount
														Excluded from
														Effectiveness
														Testing) (1)
(in millions)
For the three-month period ended March 31, 2015
Commodity contracts		$	(3.6	)		Cost of natural gas and		$	8.4			Cost of natural gas and		$	(4.0	)
						natural gas liquids						natural gas liquids
For the three-month period ended March 31, 2014
Commodity contracts		$	(0.1	)		Cost of natural gas and		$	(6.5	)		Cost of natural gas and		$	1.7
						natural gas liquids						natural gas liquids
(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
		2015				2014
		(in millions)
Balance at January 1,		$	11.6			$	(3.1	)
Other Comprehensive Income before reclassifications (1)			2.8				(2.4	)
Amounts reclassified from AOCI (2) (3)			(4.3	)			2.6
Net other comprehensive loss		$	(1.5	)		$	0.2
Balance at March 31,		$	10.1			$	(2.9	)
(1)	Excludes NCI gain of $2.7 million and loss of $3.7 million reclassified from AOCI at March 31, 2015 and 2014, respectively.
(2)	Excludes NCI loss of $4.1 million and gain of $3.9 million reclassified from AOCI at March 31, 2015 and 2014, respectively.
(3)	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 March 31,
		2015				2014
		(in millions)
Losses (gains) on cash flow hedges:
Commodity Contracts (1) (2)		$	(4.3	)		$	2.6
Total Reclassifications from AOCI		$	(4.3	)		$	2.6
(1)	Loss (gain) reported within “Cost of natural gas and natural gas liquids” in the consolidated statements of income.
(2)	Excludes NCI loss of $4.1 million and NCI gain of $3.9 million reclassified from AOCI for the three-month periods ended March 31, 2015 and 2014, respectively.
Effect of Derivative Instruments on Consolidated Statements of Income
				For the three-month
				period ended March 31,
				2015				2014
Derivatives Not Designated		Location of Gain or (Loss)		Amount of Gain or (Loss)
		Recognized in Earnings (1)		Recognized in Earnings (2)
as Hedging Instruments
				(in millions)
Commodity contracts		Operating revenue		$	(17.3	)		$	0.8
Commodity contracts		Operating revenue — affiliate			(0.2	)			—
Commodity contracts		Cost of natural gas and natural gas liquids (3)			12.1				(6.4	)
Total				$	(5.4	)		$	(5.6	)
(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 gains and (losses) of $25.7 million and ($8.5) million for the three-month periods ended March 31, 2015 and 2014, respectively.
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 gross basis. However, 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. The effect of the rights of set-off are outlined below.
Offsetting of Financial Assets and Derivative Assets
					As of March 31, 2015
					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(1)				Amount
					(in millions)
Description:
Derivatives					$	210		$		—			$	210			$	(76.5	)		$	133.5
					As of December 31, 2014
					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(1)				Amount
					(in millions)
Description:
Derivatives					$	256.5		$		—			$	256.5			$	(91.8	)		$	164.7
___________________
(1)
Includes $22.6 million and $28.4 million of cash collateral at March 31, 2015 and December 31, 2014, respectively.
Offsetting of Financial Liabilities and Derivative Liabilities
					As of March 31, 2015
					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 (1)				Financial Position				Financial Position				Financial Position (1)				Amount
			(in millions)
Description:
Derivatives					$	(82.7	)	$		—			$	(82.7	)		$	76.5			$	(6.2	)
					As of December 31, 2014
					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 (1)				Financial Position				Financial Position				Financial Position (1)				Amount
(in millions)
Description:
Derivatives					$	(96.9	)	$		—			$	(96.9	)		$	91.8			$	(5.1	)
___________________
(1)
Includes $22.6 million and $28.4 million of cash collateral at March 31, 2015 and December 31, 2014, respectively.
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 March 31, 2015, and December 31, 2014. 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.
				31-Mar-15																				31-Dec-14
			Level 1					Level 2				Level 3				Collateral				Total				Level 1				Level 2				Level 3		Collateral			Total
				(in millions)
Commodity contracts:
Financial			$		—			$	13.1			$	30.3			$	—			$	43.4		$		—			$	19.1			$	42.7	$	—		$	61.8
Physical					—				—				7				—				7				—				—				19.5		—			19.5
Commodity options					—				—				99.5				—				99.5				—				—				106.7		—			106.7
			$		—			$	13.1			$	136.8			$	—			$	149.9		$		—			$	19.1			$	168.9	$	—		$	188
Cash Collateral					—				-				—				(22.6	)			(22.6	)			—				—				—		(28.4	)		(28.4	)
Total			$		—			$	13.1			$	136.8			$	(22.6	)		$	127.3		$		—			$	19.1			$	168.9	$	(28.4	)	$	159.6
Qualitative Information about Level 2 Fair Value Measurements
We categorize, as Level 2, the fair value of assets and liabilities that we measure with either directly or indirectly observable inputs as of the measurement date, where pricing inputs are other than quoted prices in active markets for the identical instrument. This category includes both OTC transactions valued using exchange traded pricing information in addition to assets and liabilities that we value using either models or other valuation methodologies derived from observable market data. These models are primarily industry-standard models that consider various inputs including: (1) quoted prices for assets and liabilities; (2) time value; and (3) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the assets and liabilities, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace.
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. A change to the credit valuation adjustment would change the fair value of the positions in opposite directions.
Quantitative Information About Level 3 Fair Value Measurements
			Fair Value at (2)											Range (1)
			March 31,						Valuation		Unobservable											Weighted
Contract Type			2015						Technique		Input			Lowest				Highest				Average			Units
			(in millions)
Commodity Contracts - Financial
Natural Gas					$	1.6			Market Approach		Forward Gas Price				2.23				3.56				2.79		MMBtu
NGLs					$	28.7			Market Approach		Forward NGL Price				0.18				1.14				0.63		Gal
Commodity Contracts - Physical
Natural Gas					$	1.9			Market Approach		Forward Gas Price				2.23				4.24				2.69		MMBtu
Crude Oil					$	(0.7	)		Market Approach		Forward Crude Oil Price				38.21				53.7				48.97		Bbl
NGLs					$	5.8			Market Approach		Forward NGL Price				0.08				1.4				0.43		Gal
Commodity Options
Natural Gas, Crude and NGLs					$	99.5			Option Model		Option Volatility				18	%			112	%			33	%
Total Fair Value					$	136.8
_______________________________________
(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 $0.8 million of losses.
Quantitative Information About Level 3 Fair Value Measurements
			Fair Value at											Range(1)
			December 31,						Valuation		Unobservable											Weighted
Contract Type			2014(2)						Technique		Input			Lowest				Highest				Average			Units
			(in millions)
Commodity Contracts - Financial
Natural Gas					$	0.6			Market Approach		Forward Gas Price				2.55				3.72				3.04		MMBtu
NGLs					$	42.1			Market Approach		Forward NGL Price				0.48				1.14				0.64		Gal
Commodity Contracts - Physical
Natural Gas					$	1.5			Market Approach		Forward Gas Price				1.55				4.08				3.08		MMBtu
Crude Oil					$	(0.9	)		Market Approach		Forward Crude Oil Price				49.57				55.6				53.51		Bbl
NGLs					$	18.9			Market Approach		Forward NGL Price				0.06				1.21				0.54		Gal
Commodity Options
Natural Gas, Crude and NGLs					$	106.7			Option Model		Option Volatility				19	%			94	%			36	%
Total Fair Value					$	168.9
_______________________________
(1)
Prices are in dollars per MMBtu for Natural Gas, dollars per Gallon, or Gal, for NGLs, and Bbl for Crude Oil.
(2)
Fair values include credit valuation adjustments of approximately $1.0 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, 2015 to March 31, 2015. 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, 2015					$	42.7			$	19.5			$	106.7			$	168.9
Transfer out of Level 3 (1)						—				—				—				—
Gains or losses included in earnings:
Reported in Operating revenue						—				1.5				—				1.5
Reported in Cost of natural gas and natural gas liquids						0.2				4.9				4				9.1
Gains or losses included in other comprehensive income:
Reported in Other comprehensive income (loss), net of tax						(1.4	)			—				—				(1.4	)
Purchases, issuances, sales and settlements:
Purchases						—				—				—				—
Sales						—				—				—				—
Settlements (2)						(11.2	)			(18.9	)			(11.2	)			(41.3	)
Ending balance as of March 31, 2015					$	30.3			$	7			$	99.5			$	136.8
Amounts reported in Operating revenue					$	—			$	(17.5	)		$	—			$	(17.5	)
Amount of changes in net assets attributable to the change in unrealized gains or losses related to assets and liabilities still held at the reporting date:
Reported in Operating revenue					$	—			$	2.6			$	—			$	2.6
Reported in Cost of natural gas and natural gas liquids					$	2.2			$	3.1			$	7.7			$	13
_________________
(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 March 31, 2015 and December 31, 2014.
				At March 31, 2015																						At December 31, 2014
										Wtd. Average Price (2)								Fair Value (3)								Fair Value (3)
				Commodity			Notional	-1			Receive				Pay				Asset				Liability				Asset				Liability
																		(in millions)
Portion of contracts maturing in 2015
		Swaps
		Receive variable/pay fixed		Natural Gas			1,541,324			$	2.61			$	2.98			$	—			$	(0.6	)		$	—			$	(0.7	)
				NGL			504,250			$	33.12			$	40.52			$	0.1			$	(3.8	)		$	—			$	(6.8	)
				Crude Oil			739,750			$	52.35			$	83.3			$	—			$	(22.9	)		$	—			$	(27.4	)
		Receive fixed/pay variable		Natural Gas			1,728,938			$	2.91			$	2.71			$	0.4			$	—			$	3.7			$	—
				NGL			1,550,500			$	46.19			$	31			$	24			$	(0.5	)		$	39.2			$	—
				Crude Oil			915,000			$	90.93			$	52.62			$	35			$	—			$	42.4			$	—
		Receive variable/pay variable		Natural Gas			68,310,000			$	2.56			$	2.54			$	2.6			$	(1.5	)		$	1.5			$	(1.7	)
		Physical Contracts
		Receive variable/pay fixed		Natural Gas			155,150			$	2.39			$	2.19			$	—			$	—			$	—			$	—
				NGL			80,000			$	32.76			$	41.89			$	—			$	(0.7	)		$	—			$	(3.6	)
				Crude Oil			11,000			$	48.18			$	51.64			$	—			$	—			$	—			$	—
		Receive fixed/pay variable		Natural Gas			406,373			$	2.46			$	2.51			$	—			$	—			$	—			$	—
				NGL			398,525			$	26.68			$	21.93			$	1.9			$	(0.1	)		$	19.8			$	—
				Crude Oil			109,000			$	52.59			$	50.02			$	0.3			$	—			$	0.5			$	—
		Receive variable/pay variable		Natural Gas			192,448,455			$	2.61			$	2.61			$	1.6			$	(0.5	)		$	2.2			$	(1.0	)
				NGL			10,861,860			$	18.5			$	18.15			$	3.9			$	(0.1	)		$	3.7			$	(1.0	)
				Crude Oil			654,682			$	46.53			$	47.97			$	1			$	(1.9	)		$	0.3			$	(1.7	)
Portion of contracts maturing in 2016
		Swaps
		Receive variable/pay fixed		Natural Gas			363,514			$	2.75			$	3.41			$	—			$	(0.2	)		$	—			$	(0.1	)
				Crude Oil			415,950			$	58.02			$	82.69			$	—			$	(10.2	)		$	—			$	(8.1	)
		Receive fixed/pay variable		Natural Gas			465,600			$	3.32			$	3.16			$	0.1			$	—			$	—			$	—
				NGL			823,500			$	39.64			$	27.63			$	9.8			$	—			$	9.3			$	—
				Crude Oil			415,950			$	85.08			$	58.02			$	11.2			$	—			$	9.1			$	—
		Receive variable/pay variable		Natural Gas			44,959,000			$	2.93			$	2.91			$	2			$	(1.1	)		$	0.5			$	(0.3	)
		Physical Contracts
		Receive fixed/pay variable		Natural Gas			63,591			$	3.12			$	2.98			$	—			$	—			$	—			$	—
				NGL			4,398			$	29.86			$	25.91			$	—			$	—			$	—			$	—
		Receive variable/pay variable		Natural Gas			59,944,568			$	3.05			$	3.04			$	0.9			$	(0.4	)		$	0.7			$	(0.4	)
				NGL			8,944,071			$	18			$	17.89			$	0.9			$	—			$	—			$	—
Portion of contracts maturing in 2017
		Swaps
		Receive variable/pay fixed		Natural Gas			24,030			$	3.24			$	3.48			$	—			$	—			$	—			$	—
				NGL			547,500			$	23.81			$	25.86			$	—			$	(1.1	)		$	—			$	—
				Crude Oil			547,500			$	61.3			$	66.72			$	—			$	(2.9	)		$	—			$	—
		Receive fixed/pay variable		NGL			547,500			$	23.59			$	23.81			$	0.3			$	(0.5	)		$	0.7			$	—
				Crude Oil			547,500			$	66.78			$	61.3			$	2.9			$	—			$	0.8			$	—
		Receive variable/pay variable		Natural Gas			2,700,000			$	3.44			$	3.37			$	0.2			$	—			$	—			$	—
		Physical Contracts
		Receive variable/pay variable		Natural Gas			28,047,550			$	3.36			$	3.35			$	0.3			$	(0.1	)		$	0.2			$	(0.1	)
Portion of contracts maturing in 2018
		Physical Contracts
		Receive variable/pay variable		Natural Gas			5,787,810			$	3.57			$	3.56			$	0.1			$	—			$	—			$	—
Portion of contracts maturing in 2019
		Physical Contracts
		Receive variable/pay variable		Natural Gas			2,187,810			$	3.56			$	3.53			$	0.1			$	—			$	—			$	—
Portion of contracts maturing in 2020
		Physical Contracts
		Receive variable/pay variable		Natural Gas			359,640			$	3.88			$	3.85			$	—			$	—			$	—			$	—
______________________________
(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 March 31, 2015, and December 31, 2014, 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 $0.1 million of losses at March 31, 2015 and $0.4 million of losses at December 31, 2014, as well as cash collateral received.
	The following table provides summarized information about the fair value of expected cash flows of our outstanding commodity options at March 31, 2015 and December 31, 2014.
				At March 31, 2015																						At December 31, 2014
										Strike				Market				Fair Value (3)								Fair Value (3)
				Commodity		Notional (1)				Price (2)				Price (2)				Asset				Liability				Asset				Liability
																		(in millions)
Portion of option contracts maturing in 2015
		Puts (purchased)		Natural Gas			3,025,000			$	3.9			$	2.78			$	3.5			$	—			$	3.8			$	—
				NGL			1,732,500			$	43.32			$	26.68			$	29.3			$	—			$	40.2			$	—
				Crude Oil			550,000			$	81.56			$	52.55			$	16			$	—			$	18.8			$	—
		Calls (written)		Natural Gas			962,500			$	5.05			$	2.78			$	—			$	—			$	—			$	—
				NGL			1,113,750			$	45.8			$	26.06			$	—			$	(0.2	)		$	—			$	(0.6	)
				Crude Oil			550,000			$	88.39			$	52.55			$	—			$	—			$	—			$	(0.4	)
		Puts (written)		Natural Gas			3,025,000			$	3.9			$	2.79			$	—			$	(3.5	)		$	—			$	(3.8	)
		Calls (purchased)		Natural Gas			962,500			$	5.05			$	2.78			$	—			$	—			$	—			$	—
Portion of option contracts maturing in 2016
		Puts (purchased)		Natural Gas			1,647,000			$	3.75			$	3.11			$	1.3			$	—			$	1			$	—
				NGL			2,836,500			$	39.24			$	26.46			$	39.9			$	—			$	39.3			$	—
				Crude Oil			805,200			$	75.91			$	58.23			$	15.6			$	—			$	14.7			$	—
		Calls (written)		Natural Gas			1,647,000			$	4.98			$	3.11			$	—			$	(0.1	)		$	—			$	(0.1	)
				NGL			2,836,500			$	45.14			$	26.46			$	—			$	(2.4	)		$	—			$	(3.2	)
				Crude Oil			805,200			$	86.68			$	58.23			$	—			$	(0.5	)		$	—			$	(2.7	)
		Puts (written)		Natural Gas			1,647,000			$	3.75			$	3.11			$	—			$	(1.3	)		$	—			$	(1.0	)
		Calls (purchased)		Natural Gas			1,647,000			$	4.98			$	3.11			$	0.1			$	—			$	0.1			$	—
Portion of option contracts maturing in 2017
		Puts (purchased)		NGL			547,500			$	21.7			$	23.81			$	1			$	—			$	1.2			$	—
				Crude Oil			547,500			$	63			$	61.3			$	5.1			$	—			$	4.1			$	—
		Calls (written)		NGL			547,500			$	25.34			$	23.81			$	—			$	(1.2	)		$	—			$	(0.7	)
				Crude Oil			547,500			$	71.45			$	61.3			$	—			$	(2.5	)		$	—			$	(3.3	)
______________________________
(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 March 31, 2015, and December 31, 2014, 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 any credit valuation adjustments of approximately $0.6 million and $0.7 million of losses at March 31, 2015 and December 31, 2014, respectively, as well as cash collateral received.

INCOME_TAXES

INCOME TAXES	3 Months Ended
	Mar. 31, 2015
INCOME TAXES [Abstract]
INCOME TAXES	14. 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 unitholders through the allocation of taxable income. Our income tax expense results from the enactment of state income tax laws by the State of Texas that apply to entities organized as partnerships. Our income tax expense is based upon 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 0.6% and 0.5% for the three-month periods ended March 31, 2015 and 2014, respectively. Our income tax expense is $0.8 million and $1.0 million for the three-month periods ended March 31, 2015 and 2014, respectively.
	At March 31, 2015 and December 31, 2014, we included a current income tax payable of $2.1 million and $1.5 million, respectively, in “Property and other taxes payable” on our consolidated statements of financial position. In addition, at March 31, 2015 and December 31, 2014, we included a deferred income tax payable of $14.4 million and $14.2 million, respectively, in “Other long-term liabilities” 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.

SEGMENT_INFORMATION

SEGMENT INFORMATION	3 Months Ended
	Mar. 31, 2015
SEGMENT INFORMATION [Abstract]
SEGMENT INFORMATION	15. 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 are 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:
		As of and for the three-month period ended March 31, 2015
		Gathering, Processing and Transportation			Logistics and Marketing			Corporate (1)			Total
		(in millions)
	Total revenue	$	385.4		$	765.3		$	—		$	1,150.70
	Less: Intersegment revenue		267.3			9.9			—			277.2
	Operating revenue		118.1			755.4			—			873.5
	Cost of natural gas and natural gas liquids		21.9			757.2			—			779.1
	Segment gross margin		96.2			(1.8	)		—			94.4
	Operating and maintenance		50.8			12.6			—			63.4
	General and administrative		16.3			3			1.7			21
	Depreciation and amortization		36.7			1.6			—			38.3
			103.8			17.2			1.7			122.7
	Operating loss		(7.6	)		(19.0	)		(1.7	)		(28.3	)
	Interest expense, net		—			—			6.7			6.7
	Other income		5.7	-2		—			—			5.7
	Loss before income tax expense		(1.9	)		(19.0	)		(8.4	)		(29.3	)
	Income tax expense		—			—			0.8			0.8
	Net loss		(1.9	)		(19.0	)		(9.2	)		(30.1	)
	Less: Net loss attributable to:
	Noncontrolling interest		—			-			(10.1	)		(10.1	)
	Net income (loss) attributable to general and limited partner ownership interests in Midcoast Energy Partners, L.P.	$	(1.9	)	$	(19.0	)	$	0.9		$	(20.0	)
	Total assets	$	5,226.20	(3)	$	236.9		$	116.5		$	5,579.60
	Capital expenditures (excluding acquisitions)	$	54.8		$	0.7		$	0.1		$	55.6
	______________________________
	(1)
	Corporate consists of interest expense, interest income, noncontrolling interest and other costs such as income taxes, which are not allocated to the business segments.
	(2)
	Other income for our Gathering, Processing and Transportation segment includes our long-term equity investment in the Texas Express NGL system.
	(3)
	Totals assets for our Gathering, Processing and Transportation segment includes $380.1 million for our long-term equity investment in the Texas Express NGL system.
		As of and for the three-month period ended March 31, 2014
		Gathering, Processing and Transportation			Logistics and Marketing			Corporate (1)			Total
		(in millions)
	Total revenue	$	725		$	1,473.00		$	—		$	2,198.00
	Less: Intersegment revenue		521.7			29.4			—			551.1
	Operating revenue		203.3			1,443.60			—			1,646.90
	Cost of natural gas and natural gas liquids		84.8			1,403.90			—			1,488.70
	Segment gross margin		118.5			39.7			—			158.2
	Operating and maintenance		64.4			17.3			—			81.7
	General and administrative		24			3.2			—			27.2
	Depreciation and amortization		35			2			—			37
			123.4			22.5			—			145.9
	Operating income (loss)		(4.9	)		17.2			—			12.3
	Interest expense, net		—			—			3.3			3.3
	Other expense		(1.2	) (2)		—			(0.1	)		(1.3	)
	Income (loss) before income tax expense		(6.1	)		17.2			(3.4	)		7.7
	Income tax expense		—			—			1			1
	Net income (loss)		(6.1	)		17.2			(4.4	)		6.7
	Less: Net income attributable to:
	Noncontrolling interest		—			—			6.3			6.3
	Net income (loss) attributable to general and limited partner ownership interests in Midcoast Energy Partners, L.P.	$	(6.1	)	$	17.2		$	(10.7	)	$	0.4
	Total assets	$	4,901.70	(3)	$	311.1		$	216.7		$	5,429.50
	Capital expenditures (excluding acquisitions)	$	47.8		$	2.3		$	5.3		$	55.4
	______________________________
	(1)
	Corporate consists of interest expense, interest income, noncontrolling interest and other costs such as income taxes, which are not allocated to the business segments.
	(2)
	Other expense for our Gathering, Processing and Transportation segment includes our long-term equity investment in the Texas Express NGL system.
(3)
Totals assets for our Gathering, Processing and Transportation segment includes $375.7 million for our long-term equity investment in the Texas Express NGL system.

SUPPLEMENTAL_CASH_FLOW_INFORMA

SUPPLEMENTAL CASH FLOW INFORMATION	3 Months Ended
	Mar. 31, 2015
SUPPLEMENTAL CASH FLOW INFORMATION [Abstract]
SUPPLEMENTAL CASH FLOW INFORMATION	16. SUPPLEMENTAL CASH FLOW INFORMATION
	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 cash used for additions to property, plant and equipment to total capital expenditures (excluding “Investment in joint ventures”):
			For the three-month period ended March 31,
			2015			2014
			(in millions)
		Additions to property, plant and equipment	$	56.1		$	55.5
		Decrease in construction payables		(0.5	)		(0.1	)
		Total capital expenditures (excluding “Investment in joint ventures”)	$	55.6		$	55.4

RECENT_ACCOUNTING_PRONOUNCEMEN

RECENT ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED	3 Months Ended
	Mar. 31, 2015
RECENT ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED [Abstract]
RECENT ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED	17. RECENT ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED
	Revenues from Contracts with Customers
	In May 2014, the FASB issued Accounting Standards Update No. 2014-09 that outlines a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. This accounting update is effective for annual and interim periods beginning on or after December 15, 2016, and may be applied on either a full or modified retrospective basis. We are currently evaluating which transition approach we will apply and the impact that this pronouncement will have on our consolidated financial statements.
	Going Concern Uncertainties
	In August 2014, the FASB issued Accounting Standards Update No. 2014-15 which provides guidance on determining when and how to disclose going-concern uncertainties in the financial statements. The new standard requires management to perform interim and annual assessments of an entity's ability to continue as a going concern within one year of the date the financial statements are issued. An entity must provide certain disclosures if conditions or events raise substantial doubt about the entity's ability to continue as a going concern. This accounting update is effective for annual and interim periods ending after December 15, 2016, with early adoption permitted. We do not expect that the adoption of this pronouncement will have a material impact on our consolidated financial statements.
	Consolidation
	In February 2015, the FASB issued Accounting Standards Update No. 2015-02, which addresses concerns about the current accounting for consolidation of certain legal entities.  It makes targeted amendments to the current consolidations guidance and ends the deferral granted to certain entities from applying the variable interest entity, or VIE guidance.  Among other things, the amended standard eliminates the specialized consolidation model and guidance for limited partnerships, which included the presumption that the general partner should consolidate a limited partnership. This accounting update is effective for annual and interim periods beginning after December 15, 2015. Early adoption is permitted, and the new standard may be adopted either retrospectively or using a modified retrospective approach. We are currently evaluating which transition approach we will apply and the impact that this pronouncement will have on our consolidated financial statements, though we expect that this amended guidance will require us to (1) revisit our consolidation model and perform a VIE analysis for each limited partnership that we currently consolidate and (2) include additional disclosures within our consolidated financial statements.
	Debt Issuance Costs
	In April 2015, the FASB issued Accounting Standards Update No. 2015-03, which simplifies the presentation of debt issuance costs. The standard requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, and that the amortization of the debt issuance cost should be recorded as interest expense.  The amendments do not affect the current guidance on the recognition and measurement of debt issuance costs. This accounting update is effective for annual and interim periods beginning on or after December 15, 2015. Early adoption is permitted, and the new standard must be adopted retrospectively. We are currently evaluating the impact that this pronouncement will have on our consolidated financial statements.

SUBSEQUENT_EVENTS

SUBSEQUENT EVENTS	3 Months Ended
	Mar. 31, 2015
SUBSEQUENT EVENTS [Abstract]
SUBSEQUENT EVENTS	18. SUBSEQUENT EVENTS
	Distribution to Partners
	On April 29, 2015, the board of directors of Midcoast Holdings, acting in its capacity as the General Partner of MEP, declared a cash distribution payable to our partners on May 15, 2015. The distribution will be paid to unitholders of record as of May 8, 2015, of our available cash of $16.0 million at March 31, 2015, or $0.3475 per limited partner unit. We will pay $7.4 million to our public Class A common unitholders, while $8.6 million in the aggregate will be paid to EEP with respect to its Class A common units and subordinated units and Midcoast Holdings, L.L.C., with respect to its general partner interest.
	Midcoast Operating Distribution
	On April 29, 2015, the general partner of Midcoast Operating declared a cash distribution by Midcoast Operating payable to its partners of record as of May 8, 2015. Midcoast Operating will pay $27.8 million to us and $26.0 million to EEP.

NET_INCOME_PER_LIMITED_PARTNER1

NET INCOME PER LIMITED PARTNER AND GENERAL PARTNER INTEREST (Tables)	3 Months Ended
	Mar. 31, 2015
NET INCOME PER LIMITED PARTNER AND GENERAL PARTNER INTEREST [Abstract]
Schedule of Formula for Distributing Available Cash
	Distribution Targets		Portion of Quarterly			Percentage Distributed				Percentage Distributed
			Distribution Per Unit			to Limited Partners				to General Partner
	Minimum Quarterly Distribution		Up to $0.3125				98	%			2	%
	First Target Distribution		> $0.3125 to $0.359375				98	%			2	%
	Second Target Distribution		> $0.359375 to $0.390625				85	%			15	%
	Third Target Distribution		> $0.390625 to $0.468750				75	%			25	%
	Over Third Target Distribution		In excess of $0.468750				50	%			50	%
Basic and Diluted Net Income Per Limited Partner Unit
			For the three-month period ended March 31,
			2015				2014
			(in millions, except per unit amounts)
	Net income (loss)		$	(30.1	)		$	6.7
	Less: Net income (loss) attributable to noncontrolling interest			(10.1	)			6.3
	Net income (loss) attributable to general and limited partner interests in Midcoast Energy Partners, L.P.			(20.0	)			0.4
	Less distributions:
	Total distributed earnings to our General Partner			(0.3	)			(0.3	)
	Total distributed earnings to our limited partners			(15.7	)			(14.1	)
	Total distributed earnings			(16.0	)			(14.4	)
	Overdistributed earnings		$	(36.0	)		$	(14.0	)
	Weighted average limited partner units outstanding			45.2				45.2
	Basic and diluted earnings per unit:
	Distributed earnings per limited partner unit(1)		$	0.35			$	0.31
	Overdistributed earnings per limited partner unit(2)			(0.78	)			(0.30	)
	Net income (loss) per limited partner unit (basic and diluted)		$	(0.43	)		$	0.01
	(1)	Represents the total distributed earnings to limited partners divided by the weighted average number of limited partner interests outstanding for the period.
	(2)	Represents the limited partners' share (98%) of distributions in excess of earnings divided by the weighted average number of limited partner interests outstanding for the period and underdistributed earnings allocated to the limited partners based on the distribution waterfall that is outlined in our partnership agreement.

ACQUISITIONS_Tables

ACQUISITIONS (Tables)	3 Months Ended
	Mar. 31, 2015
ACQUISITIONS [Abstract]
Schedule of Consideration Paid and Purchase Price Allocation
		March 31,
		2015
		(in millions)
	Consideration:
	Cash consideration	$	85.1
	Contingent consideration		2.3
		$	87.4
	Identifiable assets acquired in business combination:
	Property, plant and equipment	$	55.1
	Intangible assets		32.3
		$	87.4
Schedule of Pro Forma Financial Information
		For the three-month
		period ended March 31,
		2015			2014
		(unaudited; in millions,
		except per unit amounts)
	Pro forma earnings data:
	Operating revenue	$	873.6		$	1,647.20
	Operating expenses	$	902.2		$	1,635.50
	Operating income (loss)	$	(28.6	)	$	11.7
	Net income (loss)	$	(30.4	)	$	6.1
	Net income (loss) attributable to noncontrolling interest	$	(10.2	)	$	5.9
	Net income (loss) attributable to limited partner ownership interest	$	(20.2	)	$	0.2
	Basic and diluted earnings per unit:
	As reported net income (loss) per limited partner unit (basic and diluted)	$	(0.43	)	$	0.01
	Pro forma net income (loss) per limited partner unit (basic and diluted)	$	(0.43	)	$	—

EQUITYBASED_COMPENSATION_Table

EQUITY-BASED COMPENSATION (Tables)	3 Months Ended
	Mar. 31, 2015
EQUITY-BASED COMPENSATION [Abstract]
Schedule of PSU Activity					Weighted
					Average
			Performance		Remaining		Average
			Stock		Contractual		Intrinsic Value
			Units		Term (years)		(in millions)
	Outstanding at January 1, 2015			—
		Units granted		323,880
		Units matured		—
		Units forfeited		—
		Dividend reinvested		8,284
	Outstanding at March 31, 2015			332,164		2.8	$	4.6

INVENTORY_Tables

INVENTORY (Tables)	3 Months Ended
	Mar. 31, 2015
INVENTORY [Abstract]
Schedule of Inventory		Our inventory is comprised of the following:
			March 31,		December 31,
			2015		2014
			(in millions)
		Materials and supplies	$	0.7	$	0.7
		Crude oil inventory		5.5		2
		Natural gas and NGL inventory		22.5		78.8
			$	28.7	$	81.5

PROPERTY_PLANT_AND_EQUIPMENT_T

PROPERTY, PLANT AND EQUIPMENT (Tables)	3 Months Ended
	Mar. 31, 2015
PROPERTY, PLANT AND EQUIPMENT [Abstract]
Schedule of Property, Plant and Equipment			March 31,			December 31,
			2015			2014
			(in millions)
		Land	$	11.3		$	11.1
		Rights-of-way		429			405
		Pipelines		1,845.80			1,785.70
		Pumping equipment, buildings and tanks		82.6			82.1
		Compressors, meters and other operating equipment		2,096.60			2,074.80
		Vehicles, office furniture and equipment		167.6			163.8
		Processing and treating plants		533			516
		Construction in progress		199.3			218.7
		Total property, plant and equipment		5,365.20			5,257.20
		Accumulated depreciation		(1,132.8	)		(1,097.5	)
		Property, plant and equipment, net	$	4,232.40		$	4,159.70

EQUITY_INVESTMENTS_IN_JOINT_VE1

EQUITY INVESTMENTS IN JOINT VENTURES (Tables)	3 Months Ended
	Mar. 31, 2015
EQUITY INVESTMENTS IN JOINT VENTURES [Abstract]
Schedule of Information of Joint Venture
			For the three-month period
			ended March 31,
			2015		2014
			(in millions)
		Operating revenues	$	28.8	$	5.3
		Operating expenses	$	11	$	8.4
		Net income (loss)	$	17.7	$	(3.1	)

DEBT_Tables

DEBT (Tables)	3 Months Ended
	Mar. 31, 2015
DEBT [Abstract]
Schedule of Debt Obligations
			Interest Rate				March 31, 2015		December 31, 2014
							(in millions)
	Credit Agreement			2.675	%		$	315	$	360
	Series A Senior Notes due 2019			3.56	%			75		75
	Series B Senior Notes due 2021			4.04	%			175		175
	Series C Senior Notes due 2024			4.42	%			150		150
	Total						$	715	$	760
Schedule of Interest Cost
			For the three-month period
			ended March 31,
			2015				2014
			(in millions)
	Interest cost incurred		$	7.6			$	3.3
	Interest capitalized			0.9				—
	Interest expense, net		$	6.7			$	3.3
Schedule of Line of Credit Facilities					(in millions)
		Total credit limit under Credit Agreement			$	850
		Amounts outstanding under Credit Agreement				(315.0	)
		Total amount available at March 31, 2015			$	535

PARTNERS_CAPITAL_Tables

PARTNERS' CAPITAL (Tables)	3 Months Ended
	Mar. 31, 2015
PARTNERS' CAPITAL [Abstract]
Schedule of Distributions	Distribution			Distribution			Distribution				Cash
	Declaration Date		Record Date	Payment Date			per Unit				Distributed
							(in millions, except per unit amounts)
		28-Jan-15	6-Feb-15	13-Feb-15			$	0.3425			$	15.8
Schedule of Changes in Partners' Capital				For the three-month
				period ended March 31,
				2015				2014
				(in millions)
	Class A common units:
	Beginning balance			$	634.2			$	495.3
	Net income (loss)				(9.8	)			0.2
	Distributions				(7.7	)			(3.7	)
	Ending balance			$	616.7			$	491.8
	Subordinated units:
	Beginning balance			$	1,174.00			$	1,035.10
	Net income (loss)				(9.8	)			0.2
	Distributions				(7.7	)			(3.8	)
	Ending balance			$	1,156.50			$	1,031.50
	General Partner units:
	Beginning balance			$	47.8			$	42.2
	Net loss				(0.4	)			(0.2	)
	Distributions				(0.4	)			—
	Ending balance			$	47			$	42
	Accumulated other comprehensive income (loss)
	Beginning balance			$	11.6			$	(3.1	)
	Changes in fair value of derivative financial instruments reclassified to earnings				(4.3	)			6.5
	Changes in fair value of derivative financial instruments recognized in other comprehensive income (loss)				2.8				(6.3	)
	Ending balance			$	10.1			$	(2.9	)
	Noncontrolling interest
	Beginning balance			$	2,529.00			$	2,983.20
	Capital contributions				68.2				46.1
	Comprehensive income:
	Net income (loss)				(10.1	)			6.3
	Other comprehensive income (loss), net of tax				(1.4	)			0.2
	Distributions to noncontrolling interest				(19.8	)			(37.4	)
	Ending balance			$	2,565.90			$	2,998.40
	Total partners' capital at end of period			$	4,396.20			$	4,560.80

DERIVATIVE_FINANCIAL_INSTRUMEN1

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Tables)	3 Months Ended
	Mar. 31, 2015
DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES [Abstract]
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value
			March 31,				December 31,
			2015				2014
			(in millions)
	Other current assets		$	133.5			$	164.7
	Other assets, net			76.4				91.5
	Accounts payable and other (1)			(61.7	)			(74.4	)
	Other long-term liabilities			(21.0	)			(22.5	)
	Due from General Partner and affiliates			0.1				0.3
			$	127.3			$	159.6
	-1	Includes $22.6 million and $28.4 million of cash collateral at March 31, 2015 and December 31, 2014, respectively.
Schedule of Derivative Balances by Counter Party Credit Quality
			March 31,				December 31,
			2015				2014
			(in millions)
	Counterparty Credit Quality (1)
	AAA		$	0.4			$	0.1
	AA  (2)			69.5				74.4
	A			47.4				67.1
	Lower than A			10				18
			$	127.3			$	159.6
	(1)	As determined by nationally-recognized statistical ratings organizations.
	(2)	Includes $22.6 million and $28.4 million of cash collateral at March 31, 2015 and December 31, 2014, respectively.
Schedule of Credit Concentrations in Industry Sectors
			March 31,				December 31,
			2015				2014
			(in millions)
	United States financial institutions and investment banking entities (1)		$	80.3			$	88.5
	Non-United States financial institutions			19				30.7
	Integrated oil companies			0.1				1.7
	Other			27.9				38.7
			$	127.3			$	159.6
	(1)	Includes $22.6 million and $28.4 million of cash collateral at March 31, 2015 and December 31, 2014, respectively.
Effect of Derivative Instruments on the Consolidated Statements of Financial Position
					Asset Derivatives								Liability Derivatives
					Fair Value at								Fair Value at
			Financial Position		March 31,				December 31,				March 31,				December 31,
			Location		2015				2014				2015				2014
					(in millions)
	Derivatives designated as cash flow hedging instruments (1)
	Commodity contracts		Other current assets		$	20.7			$	26.1			$	—			$	—
	Commodity contracts		Other assets			—				2.1				—				—
						20.7				28.2				—				—
	Derivatives not designated as hedging instruments
	Commodity contracts		Other current assets			112.8				138.6				—				—
	Commodity contracts		Other assets			76.4				89.4				—				—
	Commodity contracts		Accounts payable and other  (2)			—				—				(39.1	)			(46.0	)
	Commodity contracts		Other long-term liabilities			—				—				(21.0	)			(22.5	)
	Commodity contracts		Due from general partner			0.1				0.3				—				—
			and affiliates
						189.3				228.3				(60.1	)			(68.5	)
	Total derivative instruments				$	210			$	256.5			$	(60.1	)		$	(68.5	)
	(1)	Includes items currently designated as hedging instruments. Excludes the portion of de-designated hedges which may have a component remaining in AOCI.
	(2)	Excludes total of $22.6 million and $28.4 million of cash collateral at March 31, 2015 and December 31, 2014, respectively.
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
	Derivatives in Cash Flow		Amount of Gain (Loss)				Location of Gain (Loss)		Amount of Gain (Loss)				Location of Gain		Amount of Gain
	Hedging Relationships		Recognized in				Reclassified from		Reclassified from				(Loss) Recognized in		(Loss) Recognized in
			AOCI on Derivative				AOCI to Earnings		AOCI to Earnings				Earnings on Derivative		Earnings on
			(Effective Portion)				(Effective Portion)		(Effective Portion)				(Ineffective Portion and		Derivative
													Amount Excluded from		(Ineffective Portion
													Effectiveness Testing) (1)		and Amount
															Excluded from
															Effectiveness
															Testing) (1)
	(in millions)
	For the three-month period ended March 31, 2015
	Commodity contracts		$	(3.6	)		Cost of natural gas and		$	8.4			Cost of natural gas and		$	(4.0	)
							natural gas liquids						natural gas liquids
	For the three-month period ended March 31, 2014
	Commodity contracts		$	(0.1	)		Cost of natural gas and		$	(6.5	)		Cost of natural gas and		$	1.7
							natural gas liquids						natural gas liquids
	(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)	Components of Accumulated Other Comprehensive Income/(Loss)
			Cash Flow Hedges
			2015				2014
			(in millions)
	Balance at January 1,		$	11.6			$	(3.1	)
	Other Comprehensive Income before reclassifications (1)			2.8				(2.4	)
	Amounts reclassified from AOCI (2) (3)			(4.3	)			2.6
	Net other comprehensive loss		$	(1.5	)		$	0.2
	Balance at March 31,		$	10.1			$	(2.9	)
	(1)	Excludes NCI gain of $2.7 million and loss of $3.7 million reclassified from AOCI at March 31, 2015 and 2014, respectively.
	(2)	Excludes NCI loss of $4.1 million and gain of $3.9 million reclassified from AOCI at March 31, 2015 and 2014, respectively.
	(3)	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 March 31,
			2015				2014
			(in millions)
	Losses (gains) on cash flow hedges:
	Commodity Contracts (1) (2)		$	(4.3	)		$	2.6
	Total Reclassifications from AOCI		$	(4.3	)		$	2.6
	(1)	Loss (gain) reported within “Cost of natural gas and natural gas liquids” in the consolidated statements of income.
	(2)	Excludes NCI loss of $4.1 million and NCI gain of $3.9 million reclassified from AOCI for the three-month periods ended March 31, 2015 and 2014, respectively.
Effect of Derivative Instruments on Consolidated Statements of Income	Effect of Derivative Instruments on Consolidated Statements of Income
					For the three-month
					period ended March 31,
					2015				2014
	Derivatives Not Designated		Location of Gain or (Loss)		Amount of Gain or (Loss)
			Recognized in Earnings (1)		Recognized in Earnings (2)
	as Hedging Instruments
					(in millions)
	Commodity contracts		Operating revenue		$	(17.3	)		$	0.8
	Commodity contracts		Operating revenue — affiliate			(0.2	)			—
	Commodity contracts		Cost of natural gas and natural gas liquids (3)			12.1				(6.4	)
	Total				$	(5.4	)		$	(5.6	)
	(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 gains and (losses) of $25.7 million and ($8.5) million for the three-month periods ended March 31, 2015 and 2014, respectively.
Offsetting of Financial Assets and Derivative Assets	Offsetting of Financial Assets and Derivative Assets
						As of March 31, 2015
						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(1)				Amount
						(in millions)
	Description:
	Derivatives					$	210		$		—			$	210			$	(76.5	)		$	133.5
						As of December 31, 2014
						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(1)				Amount
						(in millions)
	Description:
	Derivatives					$	256.5		$		—			$	256.5			$	(91.8	)		$	164.7
	___________________
	(1)
	Includes $22.6 million and $28.4 million of cash collateral at March 31, 2015 and December 31, 2014, respectively.
Offsetting of Financial Liabilities and Derivative Liabilities	Offsetting of Financial Liabilities and Derivative Liabilities
						As of March 31, 2015
						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 (1)				Financial Position				Financial Position				Financial Position (1)				Amount
				(in millions)
	Description:
	Derivatives					$	(82.7	)	$		—			$	(82.7	)		$	76.5			$	(6.2	)
						As of December 31, 2014
						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 (1)				Financial Position				Financial Position				Financial Position (1)				Amount
	(in millions)
	Description:
	Derivatives					$	(96.9	)	$		—			$	(96.9	)		$	91.8			$	(5.1	)
	___________________
	(1)
	Includes $22.6 million and $28.4 million of cash collateral at March 31, 2015 and December 31, 2014, respectively.
Table Setting Forth by Level within the Fair Value Hierarchy Financial Assets and Liabilities					31-Mar-15																				31-Dec-14
				Level 1					Level 2				Level 3				Collateral				Total				Level 1				Level 2				Level 3		Collateral			Total
					(in millions)
	Commodity contracts:
	Financial			$		—			$	13.1			$	30.3			$	—			$	43.4		$		—			$	19.1			$	42.7	$	—		$	61.8
	Physical					—				—				7				—				7				—				—				19.5		—			19.5
	Commodity options					—				—				99.5				—				99.5				—				—				106.7		—			106.7
				$		—			$	13.1			$	136.8			$	—			$	149.9		$		—			$	19.1			$	168.9	$	—		$	188
	Cash Collateral					—				-				—				(22.6	)			(22.6	)			—				—				—		(28.4	)		(28.4	)
	Total			$		—			$	13.1			$	136.8			$	(22.6	)		$	127.3		$		—			$	19.1			$	168.9	$	(28.4	)	$	159.6
Schedule of Quantitative Information on Level 3 Fair Value Measurements	Quantitative Information About Level 3 Fair Value Measurements
				Fair Value at (2)											Range (1)
				March 31,						Valuation		Unobservable											Weighted
	Contract Type			2015						Technique		Input			Lowest				Highest				Average			Units
				(in millions)
	Commodity Contracts - Financial
	Natural Gas					$	1.6			Market Approach		Forward Gas Price				2.23				3.56				2.79		MMBtu
	NGLs					$	28.7			Market Approach		Forward NGL Price				0.18				1.14				0.63		Gal
	Commodity Contracts - Physical
	Natural Gas					$	1.9			Market Approach		Forward Gas Price				2.23				4.24				2.69		MMBtu
	Crude Oil					$	(0.7	)		Market Approach		Forward Crude Oil Price				38.21				53.7				48.97		Bbl
	NGLs					$	5.8			Market Approach		Forward NGL Price				0.08				1.4				0.43		Gal
	Commodity Options
	Natural Gas, Crude and NGLs					$	99.5			Option Model		Option Volatility				18	%			112	%			33	%
	Total Fair Value					$	136.8
	_______________________________________
	(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 $0.8 million of losses.
	Quantitative Information About Level 3 Fair Value Measurements
				Fair Value at											Range(1)
				December 31,						Valuation		Unobservable											Weighted
	Contract Type			2014(2)						Technique		Input			Lowest				Highest				Average			Units
				(in millions)
	Commodity Contracts - Financial
	Natural Gas					$	0.6			Market Approach		Forward Gas Price				2.55				3.72				3.04		MMBtu
	NGLs					$	42.1			Market Approach		Forward NGL Price				0.48				1.14				0.64		Gal
	Commodity Contracts - Physical
	Natural Gas					$	1.5			Market Approach		Forward Gas Price				1.55				4.08				3.08		MMBtu
	Crude Oil					$	(0.9	)		Market Approach		Forward Crude Oil Price				49.57				55.6				53.51		Bbl
	NGLs					$	18.9			Market Approach		Forward NGL Price				0.06				1.21				0.54		Gal
	Commodity Options
	Natural Gas, Crude and NGLs					$	106.7			Option Model		Option Volatility				19	%			94	%			36	%
	Total Fair Value					$	168.9
	_______________________________
	(1)
	Prices are in dollars per MMBtu for Natural Gas, dollars per Gallon, or Gal, for NGLs, and Bbl for Crude Oil.
	(2)
	Fair values include credit valuation adjustments of approximately $1.0 million of losses.
Schedule of Reconciliation of Changes in Fair Value of Level 3 Financial Assets and Liabilities						Commodity				Commodity
						Financial				Physical				Commodity
						Contracts				Contracts				Options				Total
						(in millions)
	Beginning balance as of January 1, 2015					$	42.7			$	19.5			$	106.7			$	168.9
	Transfer out of Level 3 (1)						—				—				—				—
	Gains or losses included in earnings:
	Reported in Operating revenue						—				1.5				—				1.5
	Reported in Cost of natural gas and natural gas liquids						0.2				4.9				4				9.1
	Gains or losses included in other comprehensive income:
	Reported in Other comprehensive income (loss), net of tax						(1.4	)			—				—				(1.4	)
	Purchases, issuances, sales and settlements:
	Purchases						—				—				—				—
	Sales						—				—				—				—
	Settlements (2)						(11.2	)			(18.9	)			(11.2	)			(41.3	)
	Ending balance as of March 31, 2015					$	30.3			$	7			$	99.5			$	136.8
	Amounts reported in Operating revenue					$	—			$	(17.5	)		$	—			$	(17.5	)
	Amount of changes in net assets attributable to the change in unrealized gains or losses related to assets and liabilities still held at the reporting date:
	Reported in Operating revenue					$	—			$	2.6			$	—			$	2.6
	Reported in Cost of natural gas and natural gas liquids					$	2.2			$	3.1			$	7.7			$	13
	_________________
	(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					At March 31, 2015																						At December 31, 2014
											Wtd. Average Price (2)								Fair Value (3)								Fair Value (3)
					Commodity			Notional	-1			Receive				Pay				Asset				Liability				Asset				Liability
																			(in millions)
	Portion of contracts maturing in 2015
			Swaps
			Receive variable/pay fixed		Natural Gas			1,541,324			$	2.61			$	2.98			$	—			$	(0.6	)		$	—			$	(0.7	)
					NGL			504,250			$	33.12			$	40.52			$	0.1			$	(3.8	)		$	—			$	(6.8	)
					Crude Oil			739,750			$	52.35			$	83.3			$	—			$	(22.9	)		$	—			$	(27.4	)
			Receive fixed/pay variable		Natural Gas			1,728,938			$	2.91			$	2.71			$	0.4			$	—			$	3.7			$	—
					NGL			1,550,500			$	46.19			$	31			$	24			$	(0.5	)		$	39.2			$	—
					Crude Oil			915,000			$	90.93			$	52.62			$	35			$	—			$	42.4			$	—
			Receive variable/pay variable		Natural Gas			68,310,000			$	2.56			$	2.54			$	2.6			$	(1.5	)		$	1.5			$	(1.7	)
			Physical Contracts
			Receive variable/pay fixed		Natural Gas			155,150			$	2.39			$	2.19			$	—			$	—			$	—			$	—
					NGL			80,000			$	32.76			$	41.89			$	—			$	(0.7	)		$	—			$	(3.6	)
					Crude Oil			11,000			$	48.18			$	51.64			$	—			$	—			$	—			$	—
			Receive fixed/pay variable		Natural Gas			406,373			$	2.46			$	2.51			$	—			$	—			$	—			$	—
					NGL			398,525			$	26.68			$	21.93			$	1.9			$	(0.1	)		$	19.8			$	—
					Crude Oil			109,000			$	52.59			$	50.02			$	0.3			$	—			$	0.5			$	—
			Receive variable/pay variable		Natural Gas			192,448,455			$	2.61			$	2.61			$	1.6			$	(0.5	)		$	2.2			$	(1.0	)
					NGL			10,861,860			$	18.5			$	18.15			$	3.9			$	(0.1	)		$	3.7			$	(1.0	)
					Crude Oil			654,682			$	46.53			$	47.97			$	1			$	(1.9	)		$	0.3			$	(1.7	)
	Portion of contracts maturing in 2016
			Swaps
			Receive variable/pay fixed		Natural Gas			363,514			$	2.75			$	3.41			$	—			$	(0.2	)		$	—			$	(0.1	)
					Crude Oil			415,950			$	58.02			$	82.69			$	—			$	(10.2	)		$	—			$	(8.1	)
			Receive fixed/pay variable		Natural Gas			465,600			$	3.32			$	3.16			$	0.1			$	—			$	—			$	—
					NGL			823,500			$	39.64			$	27.63			$	9.8			$	—			$	9.3			$	—
					Crude Oil			415,950			$	85.08			$	58.02			$	11.2			$	—			$	9.1			$	—
			Receive variable/pay variable		Natural Gas			44,959,000			$	2.93			$	2.91			$	2			$	(1.1	)		$	0.5			$	(0.3	)
			Physical Contracts
			Receive fixed/pay variable		Natural Gas			63,591			$	3.12			$	2.98			$	—			$	—			$	—			$	—
					NGL			4,398			$	29.86			$	25.91			$	—			$	—			$	—			$	—
			Receive variable/pay variable		Natural Gas			59,944,568			$	3.05			$	3.04			$	0.9			$	(0.4	)		$	0.7			$	(0.4	)
					NGL			8,944,071			$	18			$	17.89			$	0.9			$	—			$	—			$	—
	Portion of contracts maturing in 2017
			Swaps
			Receive variable/pay fixed		Natural Gas			24,030			$	3.24			$	3.48			$	—			$	—			$	—			$	—
					NGL			547,500			$	23.81			$	25.86			$	—			$	(1.1	)		$	—			$	—
					Crude Oil			547,500			$	61.3			$	66.72			$	—			$	(2.9	)		$	—			$	—
			Receive fixed/pay variable		NGL			547,500			$	23.59			$	23.81			$	0.3			$	(0.5	)		$	0.7			$	—
					Crude Oil			547,500			$	66.78			$	61.3			$	2.9			$	—			$	0.8			$	—
			Receive variable/pay variable		Natural Gas			2,700,000			$	3.44			$	3.37			$	0.2			$	—			$	—			$	—
			Physical Contracts
			Receive variable/pay variable		Natural Gas			28,047,550			$	3.36			$	3.35			$	0.3			$	(0.1	)		$	0.2			$	(0.1	)
	Portion of contracts maturing in 2018
			Physical Contracts
			Receive variable/pay variable		Natural Gas			5,787,810			$	3.57			$	3.56			$	0.1			$	—			$	—			$	—
	Portion of contracts maturing in 2019
			Physical Contracts
			Receive variable/pay variable		Natural Gas			2,187,810			$	3.56			$	3.53			$	0.1			$	—			$	—			$	—
	Portion of contracts maturing in 2020
			Physical Contracts
			Receive variable/pay variable		Natural Gas			359,640			$	3.88			$	3.85			$	—			$	—			$	—			$	—
	______________________________
	(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 March 31, 2015, and December 31, 2014, 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 $0.1 million of losses at March 31, 2015 and $0.4 million of losses at December 31, 2014, as well as cash collateral received.
Schedule of Fair Values of Expected Cash Flows of Outstanding Commodity Options		The following table provides summarized information about the fair value of expected cash flows of our outstanding commodity options at March 31, 2015 and December 31, 2014.
					At March 31, 2015																						At December 31, 2014
											Strike				Market				Fair Value (3)								Fair Value (3)
					Commodity		Notional (1)				Price (2)				Price (2)				Asset				Liability				Asset				Liability
																			(in millions)
	Portion of option contracts maturing in 2015
			Puts (purchased)		Natural Gas			3,025,000			$	3.9			$	2.78			$	3.5			$	—			$	3.8			$	—
					NGL			1,732,500			$	43.32			$	26.68			$	29.3			$	—			$	40.2			$	—
					Crude Oil			550,000			$	81.56			$	52.55			$	16			$	—			$	18.8			$	—
			Calls (written)		Natural Gas			962,500			$	5.05			$	2.78			$	—			$	—			$	—			$	—
					NGL			1,113,750			$	45.8			$	26.06			$	—			$	(0.2	)		$	—			$	(0.6	)
					Crude Oil			550,000			$	88.39			$	52.55			$	—			$	—			$	—			$	(0.4	)
			Puts (written)		Natural Gas			3,025,000			$	3.9			$	2.79			$	—			$	(3.5	)		$	—			$	(3.8	)
			Calls (purchased)		Natural Gas			962,500			$	5.05			$	2.78			$	—			$	—			$	—			$	—
	Portion of option contracts maturing in 2016
			Puts (purchased)		Natural Gas			1,647,000			$	3.75			$	3.11			$	1.3			$	—			$	1			$	—
					NGL			2,836,500			$	39.24			$	26.46			$	39.9			$	—			$	39.3			$	—
					Crude Oil			805,200			$	75.91			$	58.23			$	15.6			$	—			$	14.7			$	—
			Calls (written)		Natural Gas			1,647,000			$	4.98			$	3.11			$	—			$	(0.1	)		$	—			$	(0.1	)
					NGL			2,836,500			$	45.14			$	26.46			$	—			$	(2.4	)		$	—			$	(3.2	)
					Crude Oil			805,200			$	86.68			$	58.23			$	—			$	(0.5	)		$	—			$	(2.7	)
			Puts (written)		Natural Gas			1,647,000			$	3.75			$	3.11			$	—			$	(1.3	)		$	—			$	(1.0	)
			Calls (purchased)		Natural Gas			1,647,000			$	4.98			$	3.11			$	0.1			$	—			$	0.1			$	—
	Portion of option contracts maturing in 2017
			Puts (purchased)		NGL			547,500			$	21.7			$	23.81			$	1			$	—			$	1.2			$	—
					Crude Oil			547,500			$	63			$	61.3			$	5.1			$	—			$	4.1			$	—
			Calls (written)		NGL			547,500			$	25.34			$	23.81			$	—			$	(1.2	)		$	—			$	(0.7	)
					Crude Oil			547,500			$	71.45			$	61.3			$	—			$	(2.5	)		$	—			$	(3.3	)
	______________________________
	(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 March 31, 2015, and December 31, 2014, 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 any credit valuation adjustments of approximately $0.6 million and $0.7 million of losses at March 31, 2015 and December 31, 2014, respectively, as well as cash collateral received.

SEGMENT_INFORMATION_Tables

SEGMENT INFORMATION (Tables)	3 Months Ended
	Mar. 31, 2015
SEGMENT INFORMATION [Abstract]
Schedule of Segment Reporting Information, By Segment		As of and for the three-month period ended March 31, 2015
		Gathering, Processing and Transportation			Logistics and Marketing			Corporate (1)			Total
		(in millions)
	Total revenue	$	385.4		$	765.3		$	—		$	1,150.70
	Less: Intersegment revenue		267.3			9.9			—			277.2
	Operating revenue		118.1			755.4			—			873.5
	Cost of natural gas and natural gas liquids		21.9			757.2			—			779.1
	Segment gross margin		96.2			(1.8	)		—			94.4
	Operating and maintenance		50.8			12.6			—			63.4
	General and administrative		16.3			3			1.7			21
	Depreciation and amortization		36.7			1.6			—			38.3
			103.8			17.2			1.7			122.7
	Operating loss		(7.6	)		(19.0	)		(1.7	)		(28.3	)
	Interest expense, net		—			—			6.7			6.7
	Other income		5.7	-2		—			—			5.7
	Loss before income tax expense		(1.9	)		(19.0	)		(8.4	)		(29.3	)
	Income tax expense		—			—			0.8			0.8
	Net loss		(1.9	)		(19.0	)		(9.2	)		(30.1	)
	Less: Net loss attributable to:
	Noncontrolling interest		—			-			(10.1	)		(10.1	)
	Net income (loss) attributable to general and limited partner ownership interests in Midcoast Energy Partners, L.P.	$	(1.9	)	$	(19.0	)	$	0.9		$	(20.0	)
	Total assets	$	5,226.20	(3)	$	236.9		$	116.5		$	5,579.60
	Capital expenditures (excluding acquisitions)	$	54.8		$	0.7		$	0.1		$	55.6
	______________________________
	(1)
	Corporate consists of interest expense, interest income, noncontrolling interest and other costs such as income taxes, which are not allocated to the business segments.
	(2)
	Other income for our Gathering, Processing and Transportation segment includes our long-term equity investment in the Texas Express NGL system.
	(3)
	Totals assets for our Gathering, Processing and Transportation segment includes $380.1 million for our long-term equity investment in the Texas Express NGL system.
		As of and for the three-month period ended March 31, 2014
		Gathering, Processing and Transportation			Logistics and Marketing			Corporate (1)			Total
		(in millions)
	Total revenue	$	725		$	1,473.00		$	—		$	2,198.00
	Less: Intersegment revenue		521.7			29.4			—			551.1
	Operating revenue		203.3			1,443.60			—			1,646.90
	Cost of natural gas and natural gas liquids		84.8			1,403.90			—			1,488.70
	Segment gross margin		118.5			39.7			—			158.2
	Operating and maintenance		64.4			17.3			—			81.7
	General and administrative		24			3.2			—			27.2
	Depreciation and amortization		35			2			—			37
			123.4			22.5			—			145.9
	Operating income (loss)		(4.9	)		17.2			—			12.3
	Interest expense, net		—			—			3.3			3.3
	Other expense		(1.2	) (2)		—			(0.1	)		(1.3	)
	Income (loss) before income tax expense		(6.1	)		17.2			(3.4	)		7.7
	Income tax expense		—			—			1			1
	Net income (loss)		(6.1	)		17.2			(4.4	)		6.7
	Less: Net income attributable to:
	Noncontrolling interest		—			—			6.3			6.3
	Net income (loss) attributable to general and limited partner ownership interests in Midcoast Energy Partners, L.P.	$	(6.1	)	$	17.2		$	(10.7	)	$	0.4
	Total assets	$	4,901.70	(3)	$	311.1		$	216.7		$	5,429.50
	Capital expenditures (excluding acquisitions)	$	47.8		$	2.3		$	5.3		$	55.4
	______________________________
	(1)
	Corporate consists of interest expense, interest income, noncontrolling interest and other costs such as income taxes, which are not allocated to the business segments.
	(2)
	Other expense for our Gathering, Processing and Transportation segment includes our long-term equity investment in the Texas Express NGL system.
	(3)
	Totals assets for our Gathering, Processing and Transportation segment includes $375.7 million for our long-term equity investment in the Texas Express NGL system.

SUPPLEMENTAL_CASH_FLOW_INFORMA1

SUPPLEMENTAL CASH FLOW INFORMATION (Tables)	3 Months Ended
	Mar. 31, 2015
SUPPLEMENTAL CASH FLOW INFORMATION [Abstract]
Schedule of Supplemental Cash Flow Information
			For the three-month period ended March 31,
			2015			2014
			(in millions)
		Additions to property, plant and equipment	$	56.1		$	55.5
		Decrease in construction payables		(0.5	)		(0.1	)
		Total capital expenditures (excluding “Investment in joint ventures”)	$	55.6		$	55.4

ORGANIZATION_AND_NATURE_OF_OPE1

ORGANIZATION AND NATURE OF OPERATIONS (Details)	3 Months Ended	6 Months Ended	12 Months Ended
	Mar. 31, 2015	Jun. 30, 2014	Dec. 31, 2014
Midcoast Operating, L.P. [Member]
Ownership in Midcoast Operating (in percentage)	51.60%	39.00%
Ownership in Midcoast Operating held by EEP (in percentage)	48.40%	61.00%
Additional interest purchased (in percentage)			12.60%
Limited Partner Interests (EEP) [Member]
Master limited partnership ownership interest (in percentage)	52.00%

NET_INCOME_PER_LIMITED_PARTNER2

NET INCOME PER LIMITED PARTNER AND GENERAL PARTNER INTEREST (Formula for Distributing Available Cash in Partnership Agreement) (Details) (USD $)	3 Months Ended
	Mar. 31, 2015
Minimum Quarterly Distribution [Member]
Portion of Quarterly Distribution Per Unit, maximum	$0.31
Percentage Distributed To Limited Partners	98.00%
Percentage Distributed to General Partner	2.00%
First Target Distribution [Member]
Portion of Quarterly Distribution Per Unit, minimum	$0.31
Portion of Quarterly Distribution Per Unit, maximum	$0.36
Percentage Distributed To Limited Partners	98.00%
Percentage Distributed to General Partner	2.00%
Second Target Distribution [Member]
Portion of Quarterly Distribution Per Unit, minimum	$0.36
Portion of Quarterly Distribution Per Unit, maximum	$0.39
Percentage Distributed To Limited Partners	85.00%
Percentage Distributed to General Partner	15.00%
Third Target Distribution [Member]
Portion of Quarterly Distribution Per Unit, minimum	$0.39
Portion of Quarterly Distribution Per Unit, maximum	$0.47
Percentage Distributed To Limited Partners	75.00%
Percentage Distributed to General Partner	25.00%
Over Third Target Distribution [Member]
Portion of Quarterly Distribution Per Unit, minimum	$0.47
Percentage Distributed To Limited Partners	50.00%
Percentage Distributed to General Partner	50.00%

NET_INCOME_PER_LIMITED_PARTNER3

NET INCOME PER LIMITED PARTNER AND GENERAL PARTNER INTEREST (Basic and Diluted Net Income Per Limited Partner Unit) (Details) (USD $)	3 Months Ended
In Millions, except Per Share data, unless otherwise specified	Mar. 31, 2015		Mar. 31, 2014
Earnings Per Share [Line Items]
Net income (loss)	($30.10)		$6.70
Less: Net income (loss) attributable to noncontrolling interest	-10.1		6.3
Net income (loss) attributable to general and limited partner ownership interest in Midcoast Energy Partners, L.P.	-20		0.4
Total distributed earnings to our General Partner	-0.3		-0.3
Total distributed earnings to our limited partners	-15.7		-14.1
Total distributed earnings	-16		-14.4
Overdistributed earnings	($36)		($14)
Weighted average limited partner units outstanding (basic) (in shares)	45.2		45.2
Distributed earnings per limited partner unit (in dollars per share)	$0.35	[1]	$0.31	[1]
Overdistributed earnings per limited partner unit (in dollars per share)	($0.78)	[2]	($0.30)	[2]
Net income (loss) per limited partner unit (basic) (in dollars per share)	($0.43)		$0.01
Net income (loss) per limited partner unit (diluted) (in dollars per share)	($0.43)		$0.01
[1]	Represents the total distributed earnings to limited partners divided by the weighted average number of limited partner interests outstanding for the period.
[2]	Represents the limited partners' share (98%) of distributions in excess of earnings divided by the weighted average number of limited partner interests outstanding for the period and underdistributed earnings allocated to the limited partners based on the distribution waterfall that is outlined in our partnership agreement.

ACQUISITIONS_Details

ACQUISITIONS (Details) (USD $)	3 Months Ended		6 Months Ended	1 Months Ended
In Millions, except Per Share data, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014	Jun. 30, 2014	Mar. 31, 2015
Pro forma earnings data:
As reported net income (loss) per limited partner unit (basic) (in dollars per share)	($0.43)	$0.01
As reported net income (loss) per limited partner unit (diluted) (in dollars per share)	($0.43)	$0.01
Midcoast Operating, L.P. [Member]
Business Acquisition [Line Items]
Ownership in Midcoast Operating (in percentage)	51.60%		39.00%
Ownership in Midcoast Operating held by EEP (in percentage)	48.40%		61.00%	48.40%
Eaglebine Acquisition [Member]
Business Acquisition [Line Items]
Maximum contingent future payment	$17			$17
Price transferred to escrow agent	20
Restricted cash	18			18
Amount released from escrow and paid to seller				2
Earnout period	5 years
Maximum purchase price	102.1
Fair value of contingent consideration	2.3			2.3
Consideration:
Cash consideration	85.1
Contingent consideration	2.3
Total	87.4
Identifiable assets acquired in business combination:
Property, plant, and equipment	55.1			55.1
Intangible assets	32.3			32.3
Total	87.4			87.4
Weighted-average amortization period of intangible assets	15 years
Operating revenue	0.1
Net income	0.1
Pro forma earnings data:
Operating revenue	873.6	1,647.20
Operating expenses	902.2	1,635.50
Operating income (loss)	-28.6	11.7
Net income (loss)	-30.4	6.1
Net income (loss) attributable to noncontrolling interest	-10.2	5.9
Net income (loss) attributable to limited partner ownership interest	($20.20)	$0.20
As reported net income (loss) per limited partner unit (basic) (in dollars per share)	($0.43)	$0.01
As reported net income (loss) per limited partner unit (diluted) (in dollars per share)	($0.43)	$0.01
Pro forma net income (loss) per limited partner unit (basic) (in dollars per share)	($0.43)
Pro forma net income (loss) per limited partner unit (diluted) (in dollars per share)	($0.43)

EQUITYBASED_COMPENSATION_Detai

EQUITY-BASED COMPENSATION (Details) (Phantom Share Units (PSUs) [Member], USD $)	3 Months Ended
In Millions, except Share data, unless otherwise specified	Mar. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period	3 years
Vesting percentage	100.00%
Number of days used in calculating awards	20 days
Performance multiplier	1
Performance Stock Units
Outstanding
Units granted	323,880
Units matured
Units forfeited
Dividend reinvested	8,284
Outstanding	332,164
Weighted Average Remaining Contractual Term
Outstanding	2 years 9 months 18 days
Average Intrinsic Value
Outstanding	$4.60
Compensation expense	0.4
Allocated share of the cost	0.1
Unrecognized compensation expense related to non-vested units	$5.70
Unrecognized compensation expense related to non-vested units, recognition period	3 years
Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance multiplier	0
Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance multiplier	2

CASH_AND_CASH_EQUIVALENTS_Deta

CASH AND CASH EQUIVALENTS (Details) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Millions, unless otherwise specified
CASH AND CASH EQUIVALENTS [Abstract]
Obligations paid but not yet presented to financial institution	$6.90	$6.60

INVENTORY_Details

INVENTORY (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014
INVENTORY [Abstract]
Materials and supplies	$0.70		$0.70
Crude oil inventory	5.5		2
Natural gas and NGL inventory	22.5		78.8
Inventory, Net, Total	28.7		81.5
Charges related to cost of natural gas	$4.60	$1.50

PROPERTY_PLANT_AND_EQUIPMENT_D

PROPERTY, PLANT AND EQUIPMENT (Details) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Millions, unless otherwise specified
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$5,365.20	$5,257.20
Accumulated depreciation	-1,132.80	-1,097.50
Property, plant and equipment, net	4,232.40	4,159.70
Land [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	11.3	11.1
Rights-of-Way [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	429	405
Pipelines [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	1,845.80	1,785.70
Pumping Equipment, Buildings and Tanks [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	82.6	82.1
Compressors, Meters and Other Operating Equipment [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	2,096.60	2,074.80
Vehicles, Office Furniture and Equipment [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	167.6	163.8
Processing and Treating Plants [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	533	516
Construction in Progress [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$199.30	$218.70

EQUITY_INVESTMENTS_IN_JOINT_VE2

EQUITY INVESTMENTS IN JOINT VENTURES (Details) (Texas Express NGL System [Member], USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
	entities
	mi
Texas Express NGL System [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest in joint venture (in percentage)	35.00%
Number of joint ventures (in entities)	2
Length of pipeline (in miles)	593
Percentage of combined basis	100.00%
Operating revenues	$28.80	$5.30
Operating expenses	11	8.4
Net income (loss)	$17.70	($3.10)

DEBT_Schedule_of_Debt_Obligati

DEBT (Schedule of Debt Obligations) (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Carrying amount	$715	$760
Credit Agreement [Member]
Debt Instrument [Line Items]
Carrying amount	315	360
Interest rate (in percentage)	2.68%
Senior Notes [Member] | 3.560% Series A Senior Notes due 2019 [Member]
Debt Instrument [Line Items]
Carrying amount	75	75
Interest rate (in percentage)	3.56%
Maturity date	31-Dec-19
Senior Notes [Member] | 4.040% Series B Senior Notes due 2021 [Member]
Debt Instrument [Line Items]
Carrying amount	175	175
Interest rate (in percentage)	4.04%
Maturity date	31-Dec-21
Senior Notes [Member] | 4.420% Series C Senior Notes due 2024 [Member]
Debt Instrument [Line Items]
Carrying amount	$150	$150
Interest rate (in percentage)	4.42%
Maturity date	31-Dec-24

DEBT_Schedule_of_Interest_Cost

DEBT (Schedule of Interest Cost) (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Interest Costs Incurred [Abstract]
Interest cost incurred	$7.60	$3.30
Interest capitalized	0.9
Interest expense, net	$6.70	$3.30

DEBT_Narrative_Details

DEBT (Narrative) (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Debt Instruments [Abstract]
Line of credit facility remaining borrowing capacity	$535
Covenant terms
Net repayments under credit facility (Note 9)	-45	-85
Proceeds from lines of credit	1,150
Repayments of lines of credit	1,195
Fixed Rate Debt Obligations [Member]
Covenant terms
Fair values of obligations	391.9
Senior Notes [Member]
Debt Instruments [Abstract]
Debt instrument, face amount	400
Senior Notes [Member] | 3.560% Series A Senior Notes due 2019 [Member]
Debt Instruments [Abstract]
Debt instrument, face amount	75
Interest rate (in percentage)	3.56%
Maturity date	31-Dec-19
Senior Notes [Member] | 4.040% Series B Senior Notes due 2021 [Member]
Debt Instruments [Abstract]
Debt instrument, face amount	175
Interest rate (in percentage)	4.04%
Maturity date	31-Dec-21
Senior Notes [Member] | 4.420% Series C Senior Notes due 2024 [Member]
Debt Instruments [Abstract]
Debt instrument, face amount	150
Interest rate (in percentage)	4.42%
Maturity date	31-Dec-24
Senior Revolving Credit Facility [Member]
Debt Instruments [Abstract]
Total credit limit	850
Amount outstanding	315
Line of credit facility remaining borrowing capacity	535
Original term of credit agreement (in years)	3 years
Credit facility, expiration date	30-Sep-17
Covenant terms
Number of one-year requests for extensions	4
Debt, weighted average interest rate (in percentage)	2.70%
Senior Revolving Credit Facility [Member] | Portion of Facility Maturing in 2016 [Member]
Debt Instruments [Abstract]
Total credit available, maximum amount	140
Credit facility, expiration date	13-Nov-16
Financial Standby Letter of Credit [Member]
Debt Instruments [Abstract]
Total credit available, maximum amount	700
Line of credit facility, commitment fee percentage (in percentage)	2.50%
Commitment fees and issuance costs (in dollars)	$0.20

DEBT_Schedule_of_Available_Cre

DEBT (Schedule of Available Credit) (Details) (USD $)	Mar. 31, 2015
In Millions, unless otherwise specified
Line of Credit Facility [Line Items]
Total amount available	$535
Senior Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Total credit limit	850
Amounts outstanding	-315
Total amount available	$535

PARTNERS_CAPITAL_Distribution_

PARTNERS' CAPITAL (Distribution To Partners) (Details) (First Quarter Distribution [Member], USD $)	1 Months Ended	3 Months Ended
In Millions, except Per Share data, unless otherwise specified	Feb. 13, 2015	Mar. 31, 2015
First Quarter Distribution [Member]
Distribution Declaration Date		28-Jan-15
Record Date		6-Feb-15
Distribution Payment Date		13-Feb-15
Distribution per Unit (in dollars per share)	$0.34
Cash distributed (in dollars)	$15.80

PARTNERS_CAPITAL_Schedule_of_C

PARTNERS' CAPITAL (Schedule of Changes in Partners' Capital) (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014
Beginning balance	$1,867.60
Net income (loss)	-20	0.4
Distributions	-15.7	-14.1
Distributions	-0.3	-0.3
Ending balance	1,830.30
Noncontrolling interest:
Noncontrolling interest, beginning balance	2,529	2,983.20
Capital contributions	68.2	46.1
Comprehensive income:
Net income (loss)	-10.1	6.3
Other comprehensive income (loss), net of tax	-1.4	0.2
Distributions to noncontrolling interests	-19.8	-37.4
Noncontrolling interest, ending balance	2,565.90	2,998.40
Total partners' capital	4,396.20	4,560.80	4,396.60
Limited Partner [Member] | Class A Common Units [Member]
Beginning balance	634.2	495.3
Net income (loss)	-9.8	0.2
Distributions	-7.7	-3.7
Ending balance	616.7	491.8
Limited Partner [Member] | Subordinated Units [Member]
Beginning balance	1,174	1,035.10
Net income (loss)	-9.8	0.2
Distributions	-7.7	-3.8
Ending balance	1,156.50	1,031.50
General Partner [Member]
Beginning balance	47.8	42.2
Net income (loss)	-0.4	-0.2
Distributions	-0.4
Ending balance	47	42
Accumulated Other Comprehensive Income (Loss) [Member]
Beginning balance	11.6	-3.1
Changes in fair value of derivative financial instruments reclassified to earnings	-4.3	6.5
Changes in fair value of derivative financial instruments recognized in other comprehensive income (loss)	2.8	-6.3
Ending balance	$10.10	($2.90)

PARTNERS_CAPITAL_Narrative_Det

PARTNERS' CAPITAL (Narrative) (Details) (USD $)	Mar. 31, 2015
In Billions, except Share data, unless otherwise specified
PARTNERS' CAPITAL [Abstract]
Number of units authorized for issuance (in shares)	3,750,000
Value of securities covered by registration statement	$1.50

RELATED_PARTY_TRANSACTIONS_Det

RELATED PARTY TRANSACTIONS (Details) (USD $)	3 Months Ended		12 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014
Related Party Transaction [Line Items]
Distribution to partners	$15.80	$7.70
Texas Express NGL System [Member]
Equity Method (JV) Investments [Line Items]
Transportation Commitments (in Barrels per day)	120,000
Parent Company [Member]
Related Party Transaction [Line Items]
Distribution to partners	8.5	4.1
Midcoast Operating, L.P. [Member]
Related Party Transaction [Line Items]
Cash distributed (in dollars)	19.8	37.4
General and Administrative Services Transactions [Member] | Midcoast Operating, L.P. [Member]
Related Party Transaction [Line Items]
General and administrative services, reduction (in dollars)	6.3		25
Construction Project Work Force Cost Transactions [Member]
Related Party Transaction [Line Items]
Expenses from transactions with related party	0.5	5.8
Pipeline Transportation and Demand Fees from Texas Express NGL System [Member]
Related Party Transaction [Line Items]
Expenses from transactions with related party	$5.80	$5.30

RELATED_PARTY_TRANSACTIONS_Sal

RELATED PARTY TRANSACTIONS (Sale of AR) (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014
Net value of receivables sold	$705.40	$976.30
Proceeds from sale of receivables	705.2	976
Sold receivables that have not been collected at the balance sheet date	242.5		272.7
(Gain) loss on sale of accounts receivable	0.2	0.3
Restricted cash	63.5		42.8
Sale of Accounts Receivable to Affiliate [Member]
Restricted cash	$22.90		$17.70

COMMITMENTS_AND_CONTINGENCIES_

COMMITMENTS AND CONTINGENCIES (Details) (USD $)	Dec. 31, 2014
In Millions, unless otherwise specified
COMMITMENTS AND CONTINGENCIES [Abstract]
Accrued environmental liabilities	$0.20

DERIVATIVE_FINANCIAL_INSTRUMEN2

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Narrative) (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014
DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES [Abstract]
Unrealized gains (losses) related to cash flow hedges of forecasted transactions that were subsequently de-designated	$0.50
De-designated unrealized commodity hedge gains and losses	0.6	-0.1
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months	21.7
Net asset (liability) position	$127.30		$159.60

DERIVATIVE_FINANCIAL_INSTRUMEN3

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Derivative Instruments in Statement of Financial Position) (Details) (USD $)	Mar. 31, 2015		Dec. 31, 2014
In Millions, unless otherwise specified
Derivatives, Fair Value [Line Items]
Net Total	$127.30		$159.60
Cash collateral	22.6		28.4
Other Current Assets [Member]
Derivatives, Fair Value [Line Items]
Net Total	133.5		164.7
Other Noncurrent Assets [Member]
Derivatives, Fair Value [Line Items]
Net Total	76.4		91.5
Accounts Payable and Other [Member]
Derivatives, Fair Value [Line Items]
Net Total	-61.7	[1]	-74.4	[1]
Cash collateral	22.6		28.4
Other Noncurrent Liabilities [Member]
Derivatives, Fair Value [Line Items]
Net Total	-21		-22.5
Due from General Partner and Affiliates [Member]
Derivatives, Fair Value [Line Items]
Net Total	$0.10		$0.30
[1]	Includes $22.6 million and $28.4 million of cash collateral at March 31, 2015 and December 31, 2014, respectively.

DERIVATIVE_FINANCIAL_INSTRUMEN4

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Derivative Balances by Counterparty Credit Quality) (Details) (USD $)	Mar. 31, 2015		Dec. 31, 2014
In Millions, unless otherwise specified
Derivative [Line Items]
Net Total	$127.30		$159.60
Cash collateral	22.6		28.4
AAA Rating [Member]
Derivative [Line Items]
Net Total	0.4	[1]	0.1	[1]
AA Rating [Member]
Derivative [Line Items]
Net Total	69.5	[1],[2]	74.4	[1],[2]
Cash collateral	22.6		28.4
A Rating [Member]
Derivative [Line Items]
Net Total	47.4	[1]	67.1	[1]
Lower than A [Member]
Derivative [Line Items]
Net Total	$10	[1]	$18	[1]
[1]	As determined by nationally-recognized statistical ratings organizations.
[2]	Includes $22.6 million and $28.4 million of cash collateral at March 31, 2015 and December 31, 2014, respectively.

DERIVATIVE_FINANCIAL_INSTRUMEN5

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Credit Concentrations in Industry Sectors) (Details) (USD $)	Mar. 31, 2015		Dec. 31, 2014
In Millions, unless otherwise specified
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Net Total	$127.30		$159.60
Cash collateral	22.6		28.4
United States Financial Institutions and Investment Banking Entities [Member]
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Net Total	80.3	[1]	88.5	[1]
Cash collateral	22.6		28.4
Non-United States Financial Institutions [Member]
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Net Total	19		30.7
Integrated Oil Companies [Member]
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Net Total	0.1		1.7
Other [Member]
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Net Total	$27.90		$38.70
[1]	Includes $22.6 million and $28.4 million of cash collateral at March 31, 2015 and December 31, 2014, respectively.

DERIVATIVE_FINANCIAL_INSTRUMEN6

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Effect of Derivative Instruments on Consolidated Statements of Financial Position) (Details) (USD $)	Mar. 31, 2015		Dec. 31, 2014
In Millions, unless otherwise specified
Derivatives, Fair Value [Line Items]
Asset Derivatives	$210		$256.50
Liability Derivatives	-60.1		-68.5
Derivatives Designated As Hedging Instruments [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	20.7	[1]	28.2	[1]
Liability Derivatives		[1]		[1]
Derivatives Designated As Hedging Instruments [Member] | Other Current Assets [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	20.7	[1]	26.1	[1]
Liability Derivatives		[1]		[1]
Derivatives Designated As Hedging Instruments [Member] | Other Assets [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives		[1]	2.1	[1]
Liability Derivatives		[1]		[1]
Derivatives Not Designated As Hedging Instruments [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	189.3		228.3
Liability Derivatives	-60.1		-68.5
Derivatives Not Designated As Hedging Instruments [Member] | Other Current Assets [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	112.8		138.6
Liability Derivatives
Derivatives Not Designated As Hedging Instruments [Member] | Other Assets [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	76.4		89.4
Liability Derivatives
Derivatives Not Designated As Hedging Instruments [Member] | Accounts Payable and Other [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives		[2]		[2]
Liability Derivatives	-39.1	[2]	-46	[2]
Derivatives Not Designated As Hedging Instruments [Member] | Other Long-term Liabilities [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives
Liability Derivatives	-21		-22.5
Derivatives Not Designated As Hedging Instruments [Member] | Due from General Partner and Affiliates [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	0.1		0.3
Liability Derivatives
[1]	Includes items currently designated as hedging instruments. Excludes the portion of de-designated hedges which may have a component remaining in AOCI.
[2]	Excludes total of $22.6 million and $28.4 million of cash collateral at March 31, 2015 and December 31, 2014, respectively.

DERIVATIVE_FINANCIAL_INSTRUMEN7

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
In Millions, unless otherwise specified	Mar. 31, 2015		Mar. 31, 2014
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain (loss) recognized in AOCI on Derivative (Effective Portion)	($3.60)		($0.10)
Cost of Natural Gas and Natural Gas Liquids [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain (loss) reclassified from AOCI to earnings (Effective Portion)	8.4		-6.5
Amount of gain (loss) recognized in earnings on derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)	($4)	[1]	$1.70	[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_INSTRUMEN8

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Components of Accumulated Other Comprehensive Income) (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015		Mar. 31, 2014
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance	$11.60
Net other comprehensive income (loss)	-2.9		0.2
Ending balance	10.1
Less: Net income (loss) attributable to noncontrolling interest	-10.1		6.3
Cash Flow Hedge [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance	11.6		-3.1
Other Comprehensive Income before reclassifications	2.8	[1]	-2.4	[1]
Amounts reclassified from AOCI	-4.3	[2],[3]	2.6	[2],[3]
Net other comprehensive income (loss)	-1.5		0.2
Ending balance	10.1		-2.9
Noncontrolling Interest [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income before reclassifications	2.7		-3.7
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Noncontrolling Interest [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Less: Net income (loss) attributable to noncontrolling interest	($4.10)		$3.90
[1]	Excludes NCI gain of $2.7 million and loss of $3.7 million reclassified from AOCI at March 31, 2015 and 2014, respectively.
[2]	Excludes NCI loss of $4.1 million and gain of $3.9 million reclassified from AOCI at March 31, 2015 and 2014, respectively.
[3]	For additional details on the amounts reclassified from AOCI, reference the Reclassifications from Accumulated Other Comprehensive Income table below.

DERIVATIVE_FINANCIAL_INSTRUMEN9

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Reclassifications from Accumulated Other Comprehensive Income) (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015		Mar. 31, 2014
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Cost of natural gas and natural gas liquids	$779.10		$1,488.70
Total Reclassifications from AOCI	20		-0.4
Less: Net income (loss) attributable to noncontrolling interest	-10.1		6.3
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Noncontrolling Interest [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Less: Net income (loss) attributable to noncontrolling interest	-4.1		3.9
Reclassification out of AOCI [Member] | Cash Flow Hedge [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Total Reclassifications from AOCI	-4.3		2.6
Commodity Contract [Member] | Reclassification out of AOCI [Member] | Cash Flow Hedge [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Cost of natural gas and natural gas liquids	($4.30)	[1],[2]	$2.60	[1],[2]
[1]	Loss (gain) reported within bCost of natural gas and natural gas liquidsb in the consolidated statements of income.
[2]	Excludes NCI loss of $4.1 million and NCI gain of $3.9 million reclassified from AOCI for the three-month periods ended March 31, 2015 and 2014, respectively.

Recovered_Sheet1

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
In Millions, unless otherwise specified	Mar. 31, 2015		Mar. 31, 2014
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain or (Loss) Recognized in Earnings	($5.40)	[1],[2]	($5.60)	[1],[2]
Operating Revenue [Member] | Commodity Contract [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain or (Loss) Recognized in Earnings	-17.3	[1],[2]	0.8	[1],[2]
Operating Revenue - Affiliate [Member] | Commodity Contract [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain or (Loss) Recognized in Earnings	-0.2	[1],[2]		[1],[2]
Cost of Natural Gas and Natural Gas Liquids [Member] | Commodity Contract [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain or (Loss) Recognized in Earnings	12.1	[1],[2],[3]	-6.4	[1],[2],[3]
Gain (Loss) on Settlement of Derivative Instruments	$25.70		($8.50)
[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 gains and (losses) of $25.7 million and ($8.5) million for the three-month periods ended March 31, 2015 and 2014, respectively.

Recovered_Sheet2

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Offsetting of Financial Assets and Derivative Assets) (Details) (USD $)	Mar. 31, 2015		Dec. 31, 2014
In Millions, unless otherwise specified
Derivatives
Gross Amount of Recognized Assets	$210		$256.50
Gross Amount Offset in the Statement of Financial Position
Net Amount of Assets Presented in the Statement of Financial Position	210		256.5
Gross Amount Not Offset in the Statement of Financial Position	-76.5	[1]	-91.8	[1]
Net Amount	$133.50		$164.70
[1]	Includes $22.6 million and $28.4 million of cash collateral at March 31, 2015 and December 31, 2014, respectively.

Recovered_Sheet3

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Offsetting of Financial Liabilities and Derivative Liabilities) (Details) (USD $)	Mar. 31, 2015		Dec. 31, 2014
In Millions, unless otherwise specified
Derivatives
Gross Amount of Recognized Liabilities	($82.70)	[1]	($96.90)	[1]
Gross Amount Offset in the Statement of Financial Position
Net Amount of Liabilities Presented in the Statement of Financial Position	-82.7		-96.9
Gross Amount Not Offset in the Statement of Financial Position	76.5	[1]	91.8	[1]
Net Amount	($6.20)		($5.10)
[1]	Includes $22.6 million and $28.4 million of cash collateral at March 31, 2015 and December 31, 2014, respectively.

Recovered_Sheet4

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Level with in Fair Value Hierarchy, Financial Assets and Liabilities) (Details) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Millions, unless otherwise specified
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments	$149.90	$188
Cash Collateral	-22.6	-28.4
Total	127.3	159.6
Commodity Contracts - Financial [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments	43.4	61.8
Commodity Contracts - Physical [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments	7	19.5
Commodity Options [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments	99.5	106.7
Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments
Cash Collateral
Total
Level 1 [Member] | Commodity Contracts - Financial [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments
Level 1 [Member] | Commodity Contracts - Physical [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments
Level 1 [Member] | Commodity Options [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments
Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments	13.1	19.1
Cash Collateral
Total	13.1	19.1
Level 2 [Member] | Commodity Contracts - Financial [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments	13.1	19.1
Level 2 [Member] | Commodity Contracts - Physical [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments
Level 2 [Member] | Commodity Options [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments
Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments	136.8	168.9
Cash Collateral
Total	136.8	168.9
Level 3 [Member] | Commodity Contracts - Financial [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments	30.3	42.7
Level 3 [Member] | Commodity Contracts - Physical [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments	7	19.5
Level 3 [Member] | Commodity Options [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments	$99.50	$106.70

Recovered_Sheet5

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Quantitative Information about Level 3 Fair Value Measurements) (Details) (USD $)	3 Months Ended		12 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015		Dec. 31, 2014
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Assets and liabilities accounted for at fair value on a recurring basis	$127.30		$159.60
Commodity Contracts - Financial [Member] | Minimum [Member] | Natural Gas [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Forward Price	2.23	[1]	2.55	[2]
Commodity Contracts - Financial [Member] | Minimum [Member] | NGL [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Forward Price	0.18	[1]	0.48	[2]
Commodity Contracts - Financial [Member] | Maximum [Member] | Natural Gas [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Forward Price	3.56	[1]	3.72	[2]
Commodity Contracts - Financial [Member] | Maximum [Member] | NGL [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Forward Price	1.14	[1]	1.14	[2]
Commodity Contracts - Financial [Member] | Weighted Average [Member] | Natural Gas [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Forward Price	2.79	[1]	3.04	[2]
Commodity Contracts - Financial [Member] | Weighted Average [Member] | NGL [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Forward Price	0.63	[1]	0.64	[2]
Commodity Contracts - Physical [Member] | Minimum [Member] | Natural Gas [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Forward Price	2.23	[1]	1.55	[2]
Commodity Contracts - Physical [Member] | Minimum [Member] | Crude Oil [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Forward Price	38.21	[1]	49.57	[2]
Commodity Contracts - Physical [Member] | Minimum [Member] | NGL [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Forward Price	0.08	[1]	0.06	[2]
Commodity Contracts - Physical [Member] | Maximum [Member] | Natural Gas [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Forward Price	4.24	[1]	4.08	[2]
Commodity Contracts - Physical [Member] | Maximum [Member] | Crude Oil [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Forward Price	53.7	[1]	55.6	[2]
Commodity Contracts - Physical [Member] | Maximum [Member] | NGL [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Forward Price	1.4	[1]	1.21	[2]
Commodity Contracts - Physical [Member] | Weighted Average [Member] | Natural Gas [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Forward Price	2.69	[1]	3.08	[2]
Commodity Contracts - Physical [Member] | Weighted Average [Member] | Crude Oil [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Forward Price	48.97	[1]	53.51	[2]
Commodity Contracts - Physical [Member] | Weighted Average [Member] | NGL [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Forward Price	0.43	[1]	0.54	[2]
Commodity Options [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Credit Valuation Adjustments	-0.6		-0.7
Commodity Options [Member] | Minimum [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Option Volatility	18.00%	[1]	19.00%	[2]
Commodity Options [Member] | Maximum [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Option Volatility	112.00%	[1]	94.00%	[2]
Commodity Options [Member] | Weighted Average [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Option Volatility	33.00%	[1]	36.00%	[2]
Swaps [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Credit Valuation Adjustments	-0.1		-0.4
Level 3 [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Assets and liabilities accounted for at fair value on a recurring basis	136.8		168.9
Credit Valuation Adjustments	-0.8		-1
Level 3 [Member] | Commodity Contracts - Financial [Member] | Natural Gas [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Assets and liabilities accounted for at fair value on a recurring basis	1.6	[3]	0.6	[4]
Level 3 [Member] | Commodity Contracts - Financial [Member] | NGL [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Assets and liabilities accounted for at fair value on a recurring basis	28.7	[3]	42.1	[4]
Level 3 [Member] | Commodity Contracts - Physical [Member] | Natural Gas [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Assets and liabilities accounted for at fair value on a recurring basis	1.9	[3]	1.5	[4]
Level 3 [Member] | Commodity Contracts - Physical [Member] | Crude Oil [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Assets and liabilities accounted for at fair value on a recurring basis	-0.7	[3]	-0.9	[4]
Level 3 [Member] | Commodity Contracts - Physical [Member] | NGL [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Assets and liabilities accounted for at fair value on a recurring basis	5.8	[3]	18.9	[4]
Level 3 [Member] | Commodity Options [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Assets and liabilities accounted for at fair value on a recurring basis	$99.50	[3]	$106.70	[4]
[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]	Prices are in dollars per MMBtu for Natural Gas, dollars per Gallon, or Gal, for NGLs, and Bbl for Crude Oil.
[3]	Fair values are presented in millions of dollars and include credit valuation adjustments of approximately $0.8 million of losses.
[4]	Fair values include credit valuation adjustments of approximately $1.0 million of losses.

Recovered_Sheet6

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Reconciliation of Changes in Fair Value of L3 Assets and Liabilities on Recurring Basis) (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Beginning balance	$168.90
Transfer in (out) of Level 3		[1]
Gains or losses included in other comprehensive income	-1.4
Purchases, issuances, sales and settlements:
Purchases
Sales
Settlements	-41.3	[2]
Ending balance	136.8
Operating Revenue [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Gains or losses included in earnings	1.5
Purchases, issuances, sales and settlements:
Amounts reported in Operating revenue	-17.5
Amount of changes in net assets attributable to the change in unrealized gains or losses related to assets and liabilities still held at the reporting date	2.6
Cost of Natural Gas and Natural Gas Liquids [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Gains or losses included in earnings	9.1
Purchases, issuances, sales and settlements:
Amount of changes in net assets attributable to the change in unrealized gains or losses related to assets and liabilities still held at the reporting date	13
Commodity Contracts - Financial [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Beginning balance	42.7
Transfer in (out) of Level 3		[1]
Gains or losses included in other comprehensive income	-1.4
Purchases, issuances, sales and settlements:
Purchases
Sales
Settlements	-11.2	[2]
Ending balance	30.3
Commodity Contracts - Financial [Member] | Operating Revenue [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Gains or losses included in earnings
Purchases, issuances, sales and settlements:
Amounts reported in Operating revenue
Amount of changes in net assets attributable to the change in unrealized gains or losses related to assets and liabilities still held at the reporting date
Commodity Contracts - Financial [Member] | Cost of Natural Gas and Natural Gas Liquids [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Gains or losses included in earnings	0.2
Purchases, issuances, sales and settlements:
Amount of changes in net assets attributable to the change in unrealized gains or losses related to assets and liabilities still held at the reporting date	2.2
Commodity Contracts - Physical [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Beginning balance	19.5
Transfer in (out) of Level 3		[1]
Gains or losses included in other comprehensive income
Purchases, issuances, sales and settlements:
Purchases
Sales
Settlements	-18.9	[2]
Ending balance	7
Commodity Contracts - Physical [Member] | Operating Revenue [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Gains or losses included in earnings	1.5
Purchases, issuances, sales and settlements:
Amounts reported in Operating revenue	-17.5
Amount of changes in net assets attributable to the change in unrealized gains or losses related to assets and liabilities still held at the reporting date	2.6
Commodity Contracts - Physical [Member] | Cost of Natural Gas and Natural Gas Liquids [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Gains or losses included in earnings	4.9
Purchases, issuances, sales and settlements:
Amount of changes in net assets attributable to the change in unrealized gains or losses related to assets and liabilities still held at the reporting date	3.1
Commodity Options [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Beginning balance	106.7
Transfer in (out) of Level 3		[1]
Gains or losses included in other comprehensive income
Purchases, issuances, sales and settlements:
Purchases
Sales
Settlements	-11.2	[2]
Ending balance	99.5
Commodity Options [Member] | Operating Revenue [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Gains or losses included in earnings
Purchases, issuances, sales and settlements:
Amounts reported in Operating revenue
Amount of changes in net assets attributable to the change in unrealized gains or losses related to assets and liabilities still held at the reporting date
Commodity Options [Member] | Cost of Natural Gas and Natural Gas Liquids [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Gains or losses included in earnings	4
Purchases, issuances, sales and settlements:
Amount of changes in net assets attributable to the change in unrealized gains or losses related to assets and liabilities still held at the reporting date	$7.70
[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_Sheet7

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Fair Values of Expected Cash Flows of Commodity Based Swaps and Physical Contracts) (Details) (USD $)	3 Months Ended		12 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015		Dec. 31, 2014
Fair Value
Asset	$210		$256.50
Liability	-82.7	[1]	-96.9	[1]
Swaps - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Fixed - Natural Gas [Member]
Derivative [Line Items]
Notional	1,541,324	[2]
Fair Value
Asset		[3]		[3]
Liability	-0.6	[3]	-0.7	[3]
Swaps - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Fixed - NGL [Member]
Derivative [Line Items]
Notional	504,250	[2]
Fair Value
Asset	0.1	[3]		[3]
Liability	-3.8	[3]	-6.8	[3]
Swaps - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Fixed - Crude Oil [Member]
Derivative [Line Items]
Notional	739,750	[2]
Fair Value
Asset		[3]		[3]
Liability	-22.9	[3]	-27.4	[3]
Swaps - Portion of Contracts Maturing in 2015 - Receive Fixed/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Notional	1,728,938	[2]
Fair Value
Asset	0.4	[3]	3.7	[3]
Liability		[3]		[3]
Swaps - Portion of Contracts Maturing in 2015 - Receive Fixed/Pay Variable - NGL [Member]
Derivative [Line Items]
Notional	1,550,500	[2]
Fair Value
Asset	24	[3]	39.2	[3]
Liability	-0.5	[3]		[3]
Swaps - Portion of Contracts Maturing in 2015 - Receive Fixed/Pay Variable - Crude Oil [Member]
Derivative [Line Items]
Notional	915,000	[2]
Fair Value
Asset	35	[3]	42.4	[3]
Liability		[3]		[3]
Swaps - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Notional	68,310,000	[2]
Fair Value
Asset	2.6	[3]	1.5	[3]
Liability	-1.5	[3]	-1.7	[3]
Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Fixed - Natural Gas [Member]
Derivative [Line Items]
Notional	155,150	[2]
Fair Value
Asset		[3]		[3]
Liability		[3]		[3]
Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Fixed - NGL [Member]
Derivative [Line Items]
Notional	80,000	[2]
Fair Value
Asset		[3]		[3]
Liability	-0.7	[3]	-3.6	[3]
Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Fixed - Crude Oil [Member]
Derivative [Line Items]
Notional	11,000	[2]
Fair Value
Asset		[3]		[3]
Liability		[3]		[3]
Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Fixed/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Notional	406,373	[2]
Fair Value
Asset		[3]		[3]
Liability		[3]		[3]
Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Fixed/Pay Variable - NGL [Member]
Derivative [Line Items]
Notional	398,525	[2]
Fair Value
Asset	1.9	[3]	19.8	[3]
Liability	-0.1	[3]		[3]
Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Fixed/Pay Variable - Crude Oil [Member]
Derivative [Line Items]
Notional	109,000	[2]
Fair Value
Asset	0.3	[3]	0.5	[3]
Liability		[3]		[3]
Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Notional	192,448,455	[2]
Fair Value
Asset	1.6	[3]	2.2	[3]
Liability	-0.5	[3]	-1	[3]
Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Variable - NGL [Member]
Derivative [Line Items]
Notional	10,861,860	[2]
Fair Value
Asset	3.9	[3]	3.7	[3]
Liability	-0.1	[3]	-1	[3]
Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Variable - Crude Oil [Member]
Derivative [Line Items]
Notional	654,682	[2]
Fair Value
Asset	1	[3]	0.3	[3]
Liability	-1.9	[3]	-1.7	[3]
Swaps - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Fixed - Natural Gas [Member]
Derivative [Line Items]
Notional	363,514	[2]
Fair Value
Asset		[3]		[3]
Liability	-0.2	[3]	-0.1	[3]
Swaps - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Fixed - Crude Oil [Member]
Derivative [Line Items]
Notional	415,950	[2]
Fair Value
Asset		[3]		[3]
Liability	-10.2	[3]	-8.1	[3]
Swaps - Portion of Contracts Maturing in 2016 - Receive Fixed/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Notional	465,600	[2]
Fair Value
Asset	0.1	[3]		[3]
Liability		[3]		[3]
Swaps - Portion of Contracts Maturing in 2016 - Receive Fixed/Pay Variable - NGL [Member]
Derivative [Line Items]
Notional	823,500	[2]
Fair Value
Asset	9.8	[3]	9.3	[3]
Liability		[3]		[3]
Swaps - Portion of Contracts Maturing in 2016 - Receive Fixed/Pay Variable - Crude Oil [Member]
Derivative [Line Items]
Notional	415,950	[2]
Fair Value
Asset	11.2	[3]	9.1	[3]
Liability		[3]		[3]
Swaps - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Notional	44,959,000	[2]
Fair Value
Asset	2	[3]	0.5	[3]
Liability	-1.1	[3]	-0.3	[3]
Physical Contracts - Portion of Contracts Maturing in 2016 - Receive Fixed/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Notional	63,591	[2]
Fair Value
Asset		[3]		[3]
Liability		[3]		[3]
Physical Contracts - Portion of Contracts Maturing in 2016 - Receive Fixed/Pay Variable - NGL [Member]
Derivative [Line Items]
Notional	4,398	[2]
Fair Value
Asset		[3]		[3]
Liability		[3]		[3]
Physical Contracts - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Notional	59,944,568	[2]
Fair Value
Asset	0.9	[3]	0.7	[3]
Liability	-0.4	[3]	-0.4	[3]
Physical Contracts - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Variable - NGL [Member]
Derivative [Line Items]
Notional	8,944,071	[2]
Fair Value
Asset	0.9	[3]		[3]
Liability		[3]		[3]
Swaps - Portion of Contracts Maturing in 2017 - Receive Variable/Pay Fixed - Natural Gas [Member]
Derivative [Line Items]
Notional	24,030	[2]
Fair Value
Asset		[3]		[3]
Liability		[3]		[3]
Swaps - Portion of Contracts Maturing in 2017 - Receive Variable/Pay Fixed - NGL [Member]
Derivative [Line Items]
Notional	547,500	[2]
Fair Value
Asset		[3]		[3]
Liability	-1.1	[3]		[3]
Swaps - Portion of Contracts Maturing in 2017 - Receive Variable/Pay Fixed - Crude Oil [Member]
Derivative [Line Items]
Notional	547,500	[2]
Fair Value
Asset		[3]		[3]
Liability	-2.9	[3]		[3]
Swaps - Portion of Contracts Maturing in 2017 - Receive Fixed/Pay Variable - NGL [Member]
Derivative [Line Items]
Notional	547,500	[2]
Fair Value
Asset	0.3	[3]	0.7	[3]
Liability	-0.5	[3]		[3]
Swaps - Portion of Contracts Maturing in 2017 - Receive Fixed/Pay Variable - Crude Oil [Member]
Derivative [Line Items]
Notional	547,500	[2]
Fair Value
Asset	2.9	[3]	0.8	[3]
Liability		[3]		[3]
Swaps - Portion of Contracts Maturing in 2017 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Notional	2,700,000	[2]
Fair Value
Asset	0.2	[3]		[3]
Liability		[3]		[3]
Physical Contracts - Portion of Contracts Maturing in 2017 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Notional	28,047,550	[2]
Fair Value
Asset	0.3	[3]	0.2	[3]
Liability	-0.1	[3]	-0.1	[3]
Physical Contracts - Portion of Contracts Maturing in 2018 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Notional	5,787,810	[2]
Fair Value
Asset	0.1	[3]		[3]
Liability		[3]		[3]
Physical Contracts - Portion of Contracts Maturing in 2019 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Notional	2,187,810	[2]
Fair Value
Asset	0.1	[3]		[3]
Liability		[3]		[3]
Physical Contracts - Portion of Contracts Maturing in 2020 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Notional	359,640	[2]
Fair Value
Asset		[3]		[3]
Liability		[3]		[3]
Swap [Member]
Fair Value
Credit valuation adjustments	($0.10)		($0.40)
Receive [Member] | Swaps - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Fixed - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price	2.61	[4]
Receive [Member] | Swaps - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Fixed - NGL [Member]
Derivative [Line Items]
Wtd. Average Price	33.12	[4]
Receive [Member] | Swaps - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Fixed - Crude Oil [Member]
Derivative [Line Items]
Wtd. Average Price	52.35	[4]
Receive [Member] | Swaps - Portion of Contracts Maturing in 2015 - Receive Fixed/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price	2.91	[4]
Receive [Member] | Swaps - Portion of Contracts Maturing in 2015 - Receive Fixed/Pay Variable - NGL [Member]
Derivative [Line Items]
Wtd. Average Price	46.19	[4]
Receive [Member] | Swaps - Portion of Contracts Maturing in 2015 - Receive Fixed/Pay Variable - Crude Oil [Member]
Derivative [Line Items]
Wtd. Average Price	90.93	[4]
Receive [Member] | Swaps - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price	2.56	[4]
Receive [Member] | Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Fixed - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price	2.39	[4]
Receive [Member] | Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Fixed - NGL [Member]
Derivative [Line Items]
Wtd. Average Price	32.76	[4]
Receive [Member] | Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Fixed - Crude Oil [Member]
Derivative [Line Items]
Wtd. Average Price	48.18	[4]
Receive [Member] | Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Fixed/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price	2.46	[4]
Receive [Member] | Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Fixed/Pay Variable - NGL [Member]
Derivative [Line Items]
Wtd. Average Price	26.68	[4]
Receive [Member] | Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Fixed/Pay Variable - Crude Oil [Member]
Derivative [Line Items]
Wtd. Average Price	52.59	[4]
Receive [Member] | Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price	2.61	[4]
Receive [Member] | Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Variable - NGL [Member]
Derivative [Line Items]
Wtd. Average Price	18.5	[4]
Receive [Member] | Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Variable - Crude Oil [Member]
Derivative [Line Items]
Wtd. Average Price	46.53	[4]
Receive [Member] | Swaps - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Fixed - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price	2.75	[4]
Receive [Member] | Swaps - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Fixed - Crude Oil [Member]
Derivative [Line Items]
Wtd. Average Price	58.02	[4]
Receive [Member] | Swaps - Portion of Contracts Maturing in 2016 - Receive Fixed/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price	3.32	[4]
Receive [Member] | Swaps - Portion of Contracts Maturing in 2016 - Receive Fixed/Pay Variable - NGL [Member]
Derivative [Line Items]
Wtd. Average Price	39.64	[4]
Receive [Member] | Swaps - Portion of Contracts Maturing in 2016 - Receive Fixed/Pay Variable - Crude Oil [Member]
Derivative [Line Items]
Wtd. Average Price	85.08	[4]
Receive [Member] | Swaps - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price	2.93	[4]
Receive [Member] | Physical Contracts - Portion of Contracts Maturing in 2016 - Receive Fixed/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price	3.12	[4]
Receive [Member] | Physical Contracts - Portion of Contracts Maturing in 2016 - Receive Fixed/Pay Variable - NGL [Member]
Derivative [Line Items]
Wtd. Average Price	29.86	[4]
Receive [Member] | Physical Contracts - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price	3.05	[4]
Receive [Member] | Physical Contracts - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Variable - NGL [Member]
Derivative [Line Items]
Wtd. Average Price	18	[4]
Receive [Member] | Swaps - Portion of Contracts Maturing in 2017 - Receive Variable/Pay Fixed - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price	3.24	[4]
Receive [Member] | Swaps - Portion of Contracts Maturing in 2017 - Receive Variable/Pay Fixed - NGL [Member]
Derivative [Line Items]
Wtd. Average Price	23.81	[4]
Receive [Member] | Swaps - Portion of Contracts Maturing in 2017 - Receive Variable/Pay Fixed - Crude Oil [Member]
Derivative [Line Items]
Wtd. Average Price	61.3	[4]
Receive [Member] | Swaps - Portion of Contracts Maturing in 2017 - Receive Fixed/Pay Variable - NGL [Member]
Derivative [Line Items]
Wtd. Average Price	23.59	[4]
Receive [Member] | Swaps - Portion of Contracts Maturing in 2017 - Receive Fixed/Pay Variable - Crude Oil [Member]
Derivative [Line Items]
Wtd. Average Price	66.78	[4]
Receive [Member] | Swaps - Portion of Contracts Maturing in 2017 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price	3.44	[4]
Receive [Member] | Physical Contracts - Portion of Contracts Maturing in 2017 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price	3.36	[4]
Receive [Member] | Physical Contracts - Portion of Contracts Maturing in 2018 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price	3.57	[4]
Receive [Member] | Physical Contracts - Portion of Contracts Maturing in 2019 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price	3.56	[4]
Receive [Member] | Physical Contracts - Portion of Contracts Maturing in 2020 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price	3.88	[4]
Pay [Member] | Swaps - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Fixed - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price	2.98	[4]
Pay [Member] | Swaps - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Fixed - NGL [Member]
Derivative [Line Items]
Wtd. Average Price	40.52	[4]
Pay [Member] | Swaps - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Fixed - Crude Oil [Member]
Derivative [Line Items]
Wtd. Average Price	83.3	[4]
Pay [Member] | Swaps - Portion of Contracts Maturing in 2015 - Receive Fixed/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price	2.71	[4]
Pay [Member] | Swaps - Portion of Contracts Maturing in 2015 - Receive Fixed/Pay Variable - NGL [Member]
Derivative [Line Items]
Wtd. Average Price	31	[4]
Pay [Member] | Swaps - Portion of Contracts Maturing in 2015 - Receive Fixed/Pay Variable - Crude Oil [Member]
Derivative [Line Items]
Wtd. Average Price	52.62	[4]
Pay [Member] | Swaps - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price	2.54	[4]
Pay [Member] | Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Fixed - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price	2.19	[4]
Pay [Member] | Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Fixed - NGL [Member]
Derivative [Line Items]
Wtd. Average Price	41.89	[4]
Pay [Member] | Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Fixed - Crude Oil [Member]
Derivative [Line Items]
Wtd. Average Price	51.64	[4]
Pay [Member] | Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Fixed/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price	2.51	[4]
Pay [Member] | Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Fixed/Pay Variable - NGL [Member]
Derivative [Line Items]
Wtd. Average Price	21.93	[4]
Pay [Member] | Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Fixed/Pay Variable - Crude Oil [Member]
Derivative [Line Items]
Wtd. Average Price	50.02	[4]
Pay [Member] | Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price	2.61	[4]
Pay [Member] | Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Variable - NGL [Member]
Derivative [Line Items]
Wtd. Average Price	18.15	[4]
Pay [Member] | Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Variable - Crude Oil [Member]
Derivative [Line Items]
Wtd. Average Price	47.97	[4]
Pay [Member] | Swaps - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Fixed - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price	3.41	[4]
Pay [Member] | Swaps - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Fixed - Crude Oil [Member]
Derivative [Line Items]
Wtd. Average Price	82.69	[4]
Pay [Member] | Swaps - Portion of Contracts Maturing in 2016 - Receive Fixed/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price	3.16	[4]
Pay [Member] | Swaps - Portion of Contracts Maturing in 2016 - Receive Fixed/Pay Variable - NGL [Member]
Derivative [Line Items]
Wtd. Average Price	27.63	[4]
Pay [Member] | Swaps - Portion of Contracts Maturing in 2016 - Receive Fixed/Pay Variable - Crude Oil [Member]
Derivative [Line Items]
Wtd. Average Price	58.02	[4]
Pay [Member] | Swaps - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price	2.91	[4]
Pay [Member] | Physical Contracts - Portion of Contracts Maturing in 2016 - Receive Fixed/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price	2.98	[4]
Pay [Member] | Physical Contracts - Portion of Contracts Maturing in 2016 - Receive Fixed/Pay Variable - NGL [Member]
Derivative [Line Items]
Wtd. Average Price	25.91	[4]
Pay [Member] | Physical Contracts - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price	3.04	[4]
Pay [Member] | Physical Contracts - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Variable - NGL [Member]
Derivative [Line Items]
Wtd. Average Price	17.89	[4]
Pay [Member] | Swaps - Portion of Contracts Maturing in 2017 - Receive Variable/Pay Fixed - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price	3.48	[4]
Pay [Member] | Swaps - Portion of Contracts Maturing in 2017 - Receive Variable/Pay Fixed - NGL [Member]
Derivative [Line Items]
Wtd. Average Price	25.86	[4]
Pay [Member] | Swaps - Portion of Contracts Maturing in 2017 - Receive Variable/Pay Fixed - Crude Oil [Member]
Derivative [Line Items]
Wtd. Average Price	66.72	[4]
Pay [Member] | Swaps - Portion of Contracts Maturing in 2017 - Receive Fixed/Pay Variable - NGL [Member]
Derivative [Line Items]
Wtd. Average Price	23.81	[4]
Pay [Member] | Swaps - Portion of Contracts Maturing in 2017 - Receive Fixed/Pay Variable - Crude Oil [Member]
Derivative [Line Items]
Wtd. Average Price	61.3	[4]
Pay [Member] | Swaps - Portion of Contracts Maturing in 2017 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price	3.37	[4]
Pay [Member] | Physical Contracts - Portion of Contracts Maturing in 2017 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price	3.35	[4]
Pay [Member] | Physical Contracts - Portion of Contracts Maturing in 2018 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price	3.56	[4]
Pay [Member] | Physical Contracts - Portion of Contracts Maturing in 2019 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price	3.53	[4]
Pay [Member] | Physical Contracts - Portion of Contracts Maturing in 2020 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price	3.85	[4]
[1]	Includes $22.6 million and $28.4 million of cash collateral at March 31, 2015 and December 31, 2014, respectively.
[2]	Volumes of natural gas are measured in MMBtu, whereas volumes of NGL and crude oil are measured in Bbl.
[3]	The fair value is determined based on quoted market prices at March 31, 2015, and December 31, 2014, 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 $0.1 million of losses at March 31, 2015 and $0.4 million of losses at December 31, 2014, as well as cash collateral received.
[4]	Weighted average prices received and paid are in $/MMBtu for natural gas and $/Bbl for NGL and crude oil.

Recovered_Sheet8

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Fair Values of Expected Cash Flows of Commodity Options) (Details) (USD $)	3 Months Ended		12 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015		Dec. 31, 2014
Fair Value
Liability	($82.70)		($96.90)
Commodity Option [Member]
Fair Value
Credit valuation adjustments	-0.6		-0.7
Written [Member] | Portion of Put Option Contracts Maturing in 2015 - Natural Gas [Member]
Derivative [Line Items]
Notional	3,025,000	[1]
Strike Price	3.9	[2]
Market Price	2.79	[2]
Fair Value
Asset		[3]		[3]
Liability	-3.5	[3]	-3.8	[3]
Written [Member] | Portion of Call Option Contracts Maturing in 2015 - Natural Gas [Member]
Derivative [Line Items]
Notional	962,500	[1]
Strike Price	5.05	[2]
Market Price	2.78	[2]
Fair Value
Asset		[3]		[3]
Liability		[3]		[3]
Written [Member] | Portion of Call Option Contracts Maturing in 2015 - NGL [Member]
Derivative [Line Items]
Notional	1,113,750	[1]
Strike Price	45.8	[2]
Market Price	26.06	[2]
Fair Value
Asset		[3]		[3]
Liability	-0.2	[3]	-0.6	[3]
Written [Member] | Portion of Call Option Contracts Maturing in 2015 - Crude Oil [Member]
Derivative [Line Items]
Notional	550,000	[1]
Strike Price	88.39	[2]
Market Price	52.55	[2]
Fair Value
Asset		[3]		[3]
Liability		[3]	-0.4	[3]
Written [Member] | Portion of Put Option Contracts Maturing in 2016 - Natural Gas [Member]
Derivative [Line Items]
Notional	1,647,000	[1]
Strike Price	3.75	[2]
Market Price	3.11	[2]
Fair Value
Asset		[3]		[3]
Liability	-1.3	[3]	-1	[3]
Written [Member] | Portion of Call Option Contracts Maturing in 2016 - Natural Gas [Member]
Derivative [Line Items]
Notional	1,647,000	[1]
Strike Price	4.98	[2]
Market Price	3.11	[2]
Fair Value
Asset		[3]		[3]
Liability	-0.1	[3]	-0.1	[3]
Written [Member] | Portion of Call Option Contracts Maturing in 2016 - NGL [Member]
Derivative [Line Items]
Notional	2,836,500	[1]
Strike Price	45.14	[2]
Market Price	26.46	[2]
Fair Value
Asset		[3]		[3]
Liability	-2.4	[3]	-3.2	[3]
Written [Member] | Portion of Call Option Contracts Maturing in 2016 - Crude Oil [Member]
Derivative [Line Items]
Notional	805,200	[1]
Strike Price	86.68	[2]
Market Price	58.23	[2]
Fair Value
Asset		[3]		[3]
Liability	-0.5	[3]	-2.7	[3]
Written [Member] | Portion of Call Option Contracts Maturing in 2017 - NGL [Member]
Derivative [Line Items]
Notional	547,500	[1]
Strike Price	25.34	[2]
Market Price	23.81	[2]
Fair Value
Asset		[3]		[3]
Liability	-1.2	[3]	-0.7	[3]
Written [Member] | Portion of Call Option Contracts Maturing in 2017 - Crude Oil [Member]
Derivative [Line Items]
Notional	547,500	[1]
Strike Price	71.45	[2]
Market Price	61.3	[2]
Fair Value
Asset		[3]		[3]
Liability	-2.5	[3]	-3.3	[3]
Purchased [Member] | Portion of Put Option Contracts Maturing in 2015 - Natural Gas [Member]
Derivative [Line Items]
Notional	3,025,000	[1]
Strike Price	3.9	[2]
Market Price	2.78	[2]
Fair Value
Asset	3.5	[3]	3.8	[3]
Liability		[3]		[3]
Purchased [Member] | Portion of Put Option Contracts Maturing in 2015 - NGL [Member]
Derivative [Line Items]
Notional	1,732,500	[1]
Strike Price	43.32	[2]
Market Price	26.68	[2]
Fair Value
Asset	29.3	[3]	40.2	[3]
Liability		[3]		[3]
Purchased [Member] | Portion of Put Option Contracts Maturing in 2015 - Crude Oil [Member]
Derivative [Line Items]
Notional	550,000	[1]
Strike Price	81.56	[2]
Market Price	52.55	[2]
Fair Value
Asset	16	[3]	18.8	[3]
Liability		[3]		[3]
Purchased [Member] | Portion of Call Option Contracts Maturing in 2015 - Natural Gas [Member]
Derivative [Line Items]
Notional	962,500	[1]
Strike Price	5.05	[2]
Market Price	2.78	[2]
Fair Value
Asset		[3]		[3]
Liability		[3]		[3]
Purchased [Member] | Portion of Put Option Contracts Maturing in 2016 - Natural Gas [Member]
Derivative [Line Items]
Notional	1,647,000	[1]
Strike Price	3.75	[2]
Market Price	3.11	[2]
Fair Value
Asset	1.3	[3]	1	[3]
Liability		[3]		[3]
Purchased [Member] | Portion of Put Option Contracts Maturing in 2016 - NGL [Member]
Derivative [Line Items]
Notional	2,836,500	[1]
Strike Price	39.24	[2]
Market Price	26.46	[2]
Fair Value
Asset	39.9	[3]	39.3	[3]
Liability		[3]		[3]
Purchased [Member] | Portion of Put Option Contracts Maturing in 2016 - Crude Oil [Member]
Derivative [Line Items]
Notional	805,200	[1]
Strike Price	75.91	[2]
Market Price	58.23	[2]
Fair Value
Asset	15.6	[3]	14.7	[3]
Liability		[3]		[3]
Purchased [Member] | Portion of Call Option Contracts Maturing in 2016 - Natural Gas [Member]
Derivative [Line Items]
Notional	1,647,000	[1]
Strike Price	4.98	[2]
Market Price	3.11	[2]
Fair Value
Asset	0.1	[3]	0.1	[3]
Liability		[3]		[3]
Purchased [Member] | Portion of Put Option Contracts Maturing in 2017 - NGL [Member]
Derivative [Line Items]
Notional	547,500	[1]
Strike Price	21.7	[2]
Market Price	23.81	[2]
Fair Value
Asset	1	[3]	1.2	[3]
Liability		[3]		[3]
Purchased [Member] | Portion of Put Option Contracts Maturing in 2017 - Crude Oil [Member]
Derivative [Line Items]
Notional	547,500	[1]
Strike Price	63	[2]
Market Price	61.3	[2]
Fair Value
Asset	5.1	[3]	4.1	[3]
Liability		[3]		[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 March 31, 2015, and December 31, 2014, 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 any credit valuation adjustments of approximately $0.6 million and $0.7 million of losses at March 31, 2015 and December 31, 2014, respectively, as well as cash collateral received.

INCOME_TAXES_Details

INCOME TAXES (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014
Income tax expense:
Income tax expense	$0.80	$1
Current income tax payable	2.1		1.5
Deferred income tax liability	$14.40		$14.20
Texas State Income Tax Rate [Member]
Income tax expense:
Effective income tax rate (in percentage)	0.60%	0.50%

SEGMENT_INFORMATION_Details

SEGMENT INFORMATION (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015		Mar. 31, 2014		Dec. 31, 2014
	segments
Segment Reporting Information [Line Items]
Number of reporting segments (in segments)	2
Operating revenue	$873.50		$1,646.90
Cost of natural gas and natural gas liquids	779.1		1,488.70
Segment gross margin	94.4		158.2
Operating and maintenance	63.4		81.7
General and administrative	21		27.2
Depreciation and amortization	38.3		37
Operating Expenses, Total	122.7		145.9
Operating income (loss)	-28.3		12.3
Interest expense, net	6.7		3.3
Other income (expense)	5.7		-1.3
Income (loss) before income tax expense	-29.3		7.7
Income tax expense	0.8		1
Net income (loss)	-30.1		6.7
Less: Net income (loss) attributable to noncontrolling interest	-10.1		6.3
Net income (loss) attributable to general and limited partner ownership interest in Midcoast Energy Partners, L.P.	-20		0.4
Total assets	5,579.60		5,429.50		5,754.10
Capital expenditures (excluding acquisitions)	55.6		55.4
Equity investment in joint ventures	380.1				380.6
Operating Segments [Member]
Segment Reporting Information [Line Items]
Operating revenue	1,150.70		2,198
Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Operating revenue	-277.2		-551.1
Gathering, Processing and Transportation [Member]
Segment Reporting Information [Line Items]
Operating revenue	118.1		203.3
Cost of natural gas and natural gas liquids	21.9		84.8
Segment gross margin	96.2		118.5
Operating and maintenance	50.8		64.4
General and administrative	16.3		24
Depreciation and amortization	36.7		35
Operating Expenses, Total	103.8		123.4
Operating income (loss)	-7.6		-4.9
Interest expense, net
Other income (expense)	5.7	[1]	-1.2	[2]
Income (loss) before income tax expense	-1.9		-6.1
Income tax expense
Net income (loss)	-1.9		-6.1
Less: Net income (loss) attributable to noncontrolling interest
Net income (loss) attributable to general and limited partner ownership interest in Midcoast Energy Partners, L.P.	-1.9		-6.1
Total assets	5,226.20	[3]	4,901.70	[4]
Capital expenditures (excluding acquisitions)	54.8		47.8
Equity investment in joint ventures	380.1		375.7
Gathering, Processing and Transportation [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Operating revenue	385.4		725
Gathering, Processing and Transportation [Member] | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Operating revenue	-267.3		-521.7
Logistics and Marketing [Member]
Segment Reporting Information [Line Items]
Operating revenue	755.4		1,443.60
Cost of natural gas and natural gas liquids	757.2		1,403.90
Segment gross margin	-1.8		39.7
Operating and maintenance	12.6		17.3
General and administrative	3		3.2
Depreciation and amortization	1.6		2
Operating Expenses, Total	17.2		22.5
Operating income (loss)	-19		17.2
Interest expense, net
Other income (expense)
Income (loss) before income tax expense	-19		17.2
Income tax expense
Net income (loss)	-19		17.2
Less: Net income (loss) attributable to noncontrolling interest
Net income (loss) attributable to general and limited partner ownership interest in Midcoast Energy Partners, L.P.	-19		17.2
Total assets	236.9		311.1
Capital expenditures (excluding acquisitions)	0.7		2.3
Logistics and Marketing [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Operating revenue	765.3		1,473
Logistics and Marketing [Member] | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Operating revenue	-9.9		-29.4
Corporate [Member]
Segment Reporting Information [Line Items]
Operating revenue		[5]		[5]
Cost of natural gas and natural gas liquids		[5]		[5]
Segment gross margin		[5]		[5]
Operating and maintenance		[5]		[5]
General and administrative	1.7	[5]		[5]
Depreciation and amortization		[5]		[5]
Operating Expenses, Total	1.7	[5]		[5]
Operating income (loss)	-1.7	[5]		[5]
Interest expense, net	6.7	[5]	3.3	[5]
Other income (expense)		[5]	-0.1	[5]
Income (loss) before income tax expense	-8.4	[5]	-3.4	[5]
Income tax expense	0.8	[5]	1	[5]
Net income (loss)	-9.2	[5]	-4.4	[5]
Less: Net income (loss) attributable to noncontrolling interest	-10.1	[5]	6.3	[5]
Net income (loss) attributable to general and limited partner ownership interest in Midcoast Energy Partners, L.P.	0.9	[5]	-10.7	[5]
Total assets	116.5	[5]	216.7	[5]
Capital expenditures (excluding acquisitions)	0.1	[5]	5.3	[5]
Corporate [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Operating revenue		[5]		[5]
Corporate [Member] | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Operating revenue		[5]		[5]
[1]	Other income for our Gathering, Processing and Transportation segment includes our long-term equity investment in the Texas Express NGL system.
[2]	Other expense for our Gathering, Processing and Transportation segment includes our long-term equity investment in the Texas Express NGL system.
[3]	Totals assets for our Gathering, Processing and Transportation segment includes $380.1 million for our long-term equity investment in the Texas Express NGL system.
[4]	Totals assets for our Gathering, Processing and Transportation segment includes $375.7 million for our long-term equity investment in the Texas Express NGL system.
[5]	Corporate consists of interest expense, interest income, noncontrolling interest and other costs such as income taxes, which are not allocated to the business segments.

SUPPLEMENTAL_CASH_FLOW_INFORMA2

SUPPLEMENTAL CASH FLOW INFORMATION (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
SUPPLEMENTAL CASH FLOW INFORMATION [Abstract]
Additions to property, plant and equipment	$56.10	$55.50
Decrease in construction payables	-0.5	-0.1
Total capital expenditures (excluding investment in joint venture)	$55.60	$55.40

SUBSEQUENT_EVENTS_Details

SUBSEQUENT EVENTS (Details) (USD $)	3 Months Ended		1 Months Ended
In Millions, except Per Share data, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014	15-May-15
Subsequent Event [Line Items]
Distributions to General Partner	$0.30	$0.30
Subsequent Event [Member]
Subsequent Event [Line Items]
Distribution declaration date	29-Apr-15
Record date	8-May-15
Distribution payment date	15-May-15
Cash available for distribution	16
Subsequent Event [Member] | Scenario, Forecast [Member]
Subsequent Event [Line Items]
Distribution per Unit (in dollars per share)			$0.35
Amount paid to parent			8.6
Subsequent Event [Member] | Midcoast Operating, L.P. [Member] | Scenario, Forecast [Member]
Subsequent Event [Line Items]
Amount paid to parent			27.8
Distributions to General Partner			26
Subsequent Event [Member] | Public Common Unitholders [Member] | Scenario, Forecast [Member]
Subsequent Event [Line Items]
Cash distributed (in dollars)			$7.40