Midcoast Energy Partners (MEP) 10-Q 2 May 14 2014 Q1 Quarterly report Financial data

Document_And_Entity_Informatio

Document And Entity Information	3 Months Ended
	Mar. 31, 2014	1-May-14
Document and Entity Information [Abstract]	'	'
Document Type	'10-Q	'
Amendment Flag	'false	'
Document Period End Date	31-Mar-14	'
Document Fiscal Year Focus	'2014	'
Document Fiscal Period Focus	'Q1	'
Trading Symbol	'mep	'
Entity Registrant Name	'MIDCOAST ENERGY PARTNERS, L.P.	'
Entity Central Index Key	'0001578685	'
Current Fiscal Year End Date	'--12-31	'
Entity Filer Category	'Non-accelerated Filer	'
Entity Current Reporting Status	'Yes	'
Entity Shell Company	'No	'
Entity Interactive Data File	'Yes	'
Statement [Line Items]	'	'
Entity Common Stock, Shares Outstanding	'	22,610,056

Consolidated_Statements_Of_Inc

Consolidated Statements Of Income (USD $)	3 Months Ended
In Millions, except Per Share data, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Operating revenue	$1,589.70	$1,311.70
Operating revenue - affiliate	57.2	58.6
Total revenue	1,646.90	1,370.30
Operating expenses	'	'
Cost of natural gas and natural gas liquids	1,488.70	1,196.10
Selling, General and Administrative Expense, Total	145.9	143.1
Operating and maintenance	81.7	83.4
General and administrative	27.2	24.5
Depreciation and amortization	37	35.2
Operating Expenses, Total	1,634.60	1,339.20
Operating income	12.3	31.1
Interest expense, net	3.3	0
Other income (expense)	-1.3	0.1
Income (loss) before income tax expense	7.7	31.2
Income tax expense	1	0.5
Net income (loss)	6.7	30.7
Less: Net income attributable to noncontrolling interest	6.3	0
Net income attributable to general and limited partner ownership interest in Midcoast Energy Partners, L.P.	0.4	30.7
Net income (loss) attributable to limited partner ownership interests [Abstract]	'	'
Net income attributable to limited partner ownership interests	0.4	11.8
Basic and diluted earnings per limited partner unit [Abstract]	'	'
Net income (loss) per limited partner unit (basic)	$0.01	$0.44
Net income (loss) per limited partner unit (diluted)	$0.01	$0.44
Weighted average limited partner units outstanding (basic)	45.2	26.7
Weighted average limited partnership units outstanding (diluted)	45.2	26.7
Third Party [Member]	'	'
Operating expenses	'	'
Cost of natural gas and natural gas liquids	1,458.50	1,158
Operating and maintenance	54.6	57.1
General and administrative	1.9	0
Affiliate [Member]	'	'
Operating expenses	'	'
Cost of natural gas and natural gas liquids	30.2	38.1
Selling, General and Administrative Expense, Total	52.4	50.8
Operating and maintenance	27.1	26.3
General and administrative	$25.30	$24.50

Consolidated_Statements_Of_Com

Consolidated Statements Of Comprehensive Income (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Consolidated Statements Of Comprehensive Income	'	'
Net income (loss)	$6.70	$30.70
Other comprehensive income (loss), net of tax expense (benefit)	0.2	-0.7
Comprehensive income (loss)	6.9	30
Less: Comprehensive income attributable to noncontrolling interest	6.3	0
Less: Other comprehensive income allocated to noncontrolling interest	0.2	0
Comprehensive income (loss) attributable to general and limited partner ownership interests in Midcoast Energy Partners, L.P.	$0.40	$30

Consolidated_Statements_Of_Com1

Consolidated Statements Of Comprehensive Income (Parenthetical) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Consolidated Statements Of Comprehensive Income	'	'
Tax expense (benefit) from other comprehensive income (loss)	$0	$0

Consolidated_Statements_Of_Cas

Consolidated Statements Of Cash Flows (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Cash provided by operating activities	'	'
Net income	$6.70	$30.70
Adjustments to reconcile net income (loss) to net cash provided by operating activities:	'	'
Depreciation and amortization	37	35.2
Derivative fair value net (gains) losses	-4.6	1.5
Distributions from investment in joint venture	1.6	0
Inventory market price adjustments	1.5	0.8
Equity loss from investment in joint venture	1.3	0
Other	1	-2.2
Changes in operating assets and liabilities, net of acquisitions:	'	'
Receivables, trade and other	3.5	-42.8
Due from General Partner and affiliates	616.3	7.5
Accrued receivables	59.2	133.3
Inventory	26.2	-2.9
Current and long-term other assets	-4.8	-1.7
Due to General Partner and affiliates	-478.3	16.5
Accounts payable and other	-42.5	-22.6
Environmental liabilities	0.2	0
Accrued purchases	-2.4	-37.1
Interest payable	0.5	0
Property and other taxes payable	-8.6	-6.9
Net cash provided by operating activities	213.8	109.3
Cash used in investing activities	'	'
Additions to property, plant and equipment	-55.5	-78
Asset acquisitions	0	-0.9
Proceeds from sale of net assets	0	5
Changes in restricted cash	47.5	0
Investment in joint venture	-7.3	-36.8
Other	0	-1.1
Net cash used in investing activities	-15.3	-111.8
Cash provided by (used in) financing activities	'	'
Contributions from partners	39.7	63.2
Distribution to partners	-45.1	-60.7
Net borrowings (repayments) under Credit Facility	-85	0
Net cash provided by (used in) financing activities	-90.4	2.5
Net increase (decrease) in cash and cash equivalents	108.1	0
Cash and cash equivalents at beginning of year	4.9	0
Cash and cash equivalents at end of period	$113	$0

Consolidated_Statements_Of_Fin

Consolidated Statements Of Financial Position (USD $)	Mar. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Current assets	'	'
Cash and cash equivalents	$113	$4.90
Restricted Cash	14	61.5
Receivables, trade and other, net of allowance for doubtful accounts	29.8	50.3
Due from General Partner and affiliates	40.4	654.8
Accrued receivables	140	182.2
Inventory	60.3	88
Other current assets	31.2	19.1
Assets, Current, Total	428.7	1,060.80
Property, plant and equipment, net	4,102	4,082.30
Goodwill	226.5	226.5
Intangibles, net	251.7	255
Equity Investment in Joint Venture	375.7	371.3
Other assets, net	44.9	40.5
Total assets	5,429.50	6,036.40
Current liabilities	'	'
Due to General Partner and affiliates	43.2	534.3
Accounts payable and other	79.4	114.4
Accrued purchases	460.8	463.3
Interest payable	0.8	0.3
Property and other taxes payable	11.2	19.8
Liabilities, Current, Total	595.4	1,132.10
LiabilitiesAbstract	'	'
Long-term debt	250	335
Other long-term liabilities	23.3	16.6
Liabilities, Total	868.7	1,483.70
Commitments and contingencies	'	'
Partners' capital	'	'
Limited Partner interest	1,523.30	1,530.40
General Partner	42	42.2
Accumulated other comprehensive income (loss)	-2.9	-3.1
Total Midcoast Energy Partners, L.P. partners' capital	1,562.40	1,569.50
Noncontrolling interest	2,998.40	2,983.20
Total partners' capital	4,560.80	4,552.70
Liabilities and Stockholders' Equity, Total	5,429.50	6,036.40
Class A Common Units [Member]	'	'
Partners' capital	'	'
Limited Partner interest	491.8	495.3
Subordinated Units [Member]	'	'
Partners' capital	'	'
Limited Partner interest	$1,031.50	$1,035.10

Consolidated_Statements_Of_Fin1

Consolidated Statements Of Financial Position (Parenthetical) (USD $)	Mar. 31, 2014	Dec. 31, 2013
In Millions, except Share data, unless otherwise specified
Receivables, trade and other, allowance for doubtful accounts	$0.50	$0.50
Partners Capital units, outstanding	922,859	922,859
Class A Common Units [Member]	'	'
Partners Capital units, outstanding	22,610,056	22,610,056
Subordinated Units [Member]	'	'
Partners Capital units, outstanding	22,610,056	22,610,056

Basis_Of_Presentation

Basis Of Presentation	3 Months Ended
	Mar. 31, 2014
Organization And Nature Of Operations	'
Organization And Nature Of Operations	'
	1. ORGANIZATION AND NATURE OF OPERATIONS
	Initial Public Offering
	Midcoast Energy Partners, L.P., or MEP, is a 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. We own and operate a portfolio of assets engaged in the business of gathering, processing and treating natural gas, as well as the transportation and marketing of natural gas, natural gas liquids, or NGLs, crude oil and condensate. Our portfolio of natural gas and NGL pipelines, plants and related facilities are geographically concentrated in the Gulf Coast and Mid-Continent regions of the United States, primarily in Texas and Oklahoma. On November 13, 2013, MEP completed its initial public offering, or the Offering, of 18,500,000 Class A common units (2,775,000 additional Class A common units were issued pursuant to the exercise of the underwriters' over-allotment option on December 9, 2013), representing limited partner interests. Following the completion of the Offering, EEP continues to own crude oil and liquid petroleum assets and a 61% non-controlling interest in Midcoast Operating. EEP also retained a significant interest in us through its ownership of our general partner, which owns all of our General Partner units and all of our incentive distribution rights, and a 52% limited partner interest in us. The Class A common units began trading on November 7, 2013, on the New York Stock Exchange, or NYSE, under the ticker symbol MEP. We intend to pursue acquisitions of additional interests in our natural gas assets, held through Midcoast Operating, from EEP. EEP has indicated that it intends to offer us the opportunity to purchase additional interests in Midcoast Operating from time to time, although EEP is not legally obligated to do so. We do not know when, or if, any such additional interests will be offered to us to purchase.
	Basis of Presentation
	The accompanying unaudited interim consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States, or GAAP, for interim consolidated financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. Accordingly, they do not include all the information and footnotes required by GAAP for complete consolidated financial statements. In the opinion of management, they contain all adjustments, consisting only of normal recurring adjustments, which management considers necessary to present fairly our financial position as of March 31, 2014, our results of operations for the three month periods ended March 31, 2014 and 2013 and our cash flows for the three month periods ended March 31, 2014 and 2013. We derived our consolidated statement of financial position as of December 31, 2013, from the audited financial statements included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2013. Our results of operations for the three month periods ended March 31, 2014 and 2013 should not be taken as indicative of the results to be expected for the full year due to seasonal fluctuations in the supply of and demand for natural gas, NGLs and crude oil, timing and completion of our construction projects, maintenance activities, the impact of forward commodity prices and differentials on derivative financial instruments that are accounted for at fair value. These unaudited interim consolidated financial statements should be read in conjunction with the audited consolidated financial statements and accompanying footnotes thereto presented in our Annual Report on Form 10-K for the fiscal year ended December 31, 2013.
	Certain adjustments relating to the prior period and having a net adverse impact of approximately $0.9 million to net income were recorded in the current period.  We consider these adjustments to be immaterial to the unaudited interim consolidated financial statements both individually and taken as a whole.
	Our results of operations may not be comparable to our Predecessor's historical results of operations for the reasons described below:
	Our Predecessor's results of operations historically reflected 100% of the revenues and expenses relating to Midcoast Operating. We currently own a 39% controlling interest in Midcoast Operating. We currently consolidate the results of operations of Midcoast Operating and then record a 61% non-controlling interest deduction for EEP's retained interest in Midcoast Operating.
	Although the allocation methodology under which we will continue to reimburse EEP and its affiliates for the provisions of certain administrative and operational services to Midcoast Operating will not change, $25.0 million in annual amounts payable for general and administrative expenses that were paid by Midcoast Operating historically under its existing services agreements will not be payable by Midcoast Operating going forward.
	We expect to incur an additional $4.0 million of incremental annual general and administrative expenses as a result of being a separate publicly traded partnership, 100% of which will be attributable to us.
	EEP no longer provides letters of credit and parental guarantees to Midcoast Operating at no cost, and we are responsible for our proportionate share of the annual expenses attributable to a financial support agreement that Midcoast Operating entered into with EEP. During the term of the financial support agreement, when requested by Midcoast Operating, EEP will provide letters of credit and guarantees in support of Midcoast Operating's financial obligations under certain hedges and key customer natural gas and NGL purchase agreements. The annual cost that Midcoast Operating incurs under the financial support agreement, which we estimate will initially range from approximately $4.0 million to $5.0 million, is based on the cumulative average amount of letters of credit and guarantees that EEP may provide on Midcoast Operating's behalf multiplied by a 2.5% annual fee. Based on our 39% controlling interest in Midcoast Operating, the Partnership incurred $1.2 million of these annual costs for the three months ended March 31, 2014. Without such financial support from EEP, we expect that Midcoast Operating would be required to provide letters of credit, cash collateral or other financial support with respect to these agreements or similar agreements it enters into in the future.
	We incur interest expense under our revolving credit facility, Midcoast Operating's working capital credit facility and other borrowing arrangements we may enter into from time to time. Prior to our acquiring control of our Predecessor, it was a wholly owned subsidiary of EEP and, as such, did not incur any direct interest expense from third parties and only recognized intercompany interest expense to the extent such amounts were capitalized as part of its construction projects.

Summary_of_Significant_Account

Summary of Significant Accounting Policies	3 Months Ended
	Mar. 31, 2014
Accounting Policies [Abstract]	'
Summary Of Significant Accounting Policies	'
	2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
	Obligations Resulting from Joint and Several Liability Arrangements
	Effective January 1, 2014, we retrospectively adopted Financial Accounting Standards Board, or FASB, Accounting Standards Update No. 2013-04, which provides measurement and disclosure guidance for obligations with fixed amounts at a reporting date resulting from joint and several liability arrangements. There was no material impact to the consolidated financial statements for the current or prior periods presented as a result of adopting this update.

Net_Income_Per_Limited_Partner

Net Income Per Limited Partner And General Partner Interest	3 Months Ended
	Mar. 31, 2014
Net Income Per Limited Partner And General Partner Interest	'
Net Income Per Limited Partner And General Partner Interest	'
	3. 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 in accordance with applicable authoritative accounting guidance. 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 Distribution Per Unit	Percentage Distributed to Limited Partners		Percentage Distributed 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 per limited partner unit as follows:
						For the three month
						period ended March 31,
						2014		2013(3)
						(in millions, except per unit amounts)
	Net income				$	6.7		$	30.7
	Less: Net income attributable to noncontrolling interest					6.3			18.7
	Net income attributable to general and limited partner
		interests in Midcoast Energy Partners, L.P.				0.4			12
	Less distributions:
			Total distributed earnings to our General Partner			-0.3			-0.1
			Total distributed earnings to our limited partners			-14.1			-8.4
	Total distributed earnings					-14.4			-8.5
	Underdistributed (Overdistributed) earnings				$	-14		$	3.5
	Weighted average limited partner units outstanding					45.2			26.7
	Basic and diluted earnings per unit:
		Distributed earnings per limited partner unit (1)			$	0.31		$	0.31
		Underdistributed (Overdistributed) earnings per limited partner unit (2)				-0.3			0.13
	Net income per limited partner unit (basic and diluted)				$	0.01		$	0.44
	______________________________
	(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.
	(3)	Represents calculation retrospectively reflecting the affiliate capitalization of MEP consisting of 4.1 million MEP Class A common units, 22.6 million MEP subordinated units and MEP general partner interest upon the transfer of a controlling ownership, including limited partner and general partner interest, in Midcoast Operating. The noncontrolling interest reflects the 61% retained by EEP.

Cash_And_Cash_Equivalents

Cash And Cash Equivalents	3 Months Ended
	Mar. 31, 2014
Cash And Cash Equivalents	'
Cash And Cash Equivalents	'
	4. 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 $13.7 million at March 31, 2014, and $8.8 million at December 31, 2013, are included in “Accounts payable and other” on our consolidated statements of financial position. At December 31, 2013, we reclassified a book overdraft of $49.1 million to “Accounts payable and other” on our consolidated statements of financial position.

Inventory

Inventory	3 Months Ended
	Mar. 31, 2014
Inventory	'
Inventory	'
	5. INVENTORY
		Our inventory is comprised of the following:
			March 31,		December 31,
			2014		2013
			(in millions)
		Materials and supplies	$	0.5	$	0.6
		Crude oil inventory		11.2		12.6
		Natural gas and NGL inventory		48.6		74.8
			$	60.3	$	88
	The “Cost of natural gas and natural gas liquids” on our consolidated statements of income includes charges totaling $1.5 million and $0.8 million for the three month periods ended March 31, 2014 and 2013, 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, 2014
Property, Plant And Equipment	'
Property, Plant And Equipment	'
	6. PROPERTY, PLANT AND EQUIPMENT
	Our property, plant and equipment is comprised of the following:
				March 31,		December 31,
				2014		2013
				(in millions)
		Land		$	11.2	$	11.6
		Rights-of-way			385.5		380
		Pipelines			1,765.00		1,741.90
		Pumping equipment, buildings and tanks			79.5		79.2
		Compressors, meters and other operating equipment			2,024.60		1,993.20
		Vehicles, office furniture and equipment			152.1		148.5
		Processing and treating plants			514.6		514.4
		Construction in progress			172.5		181.4
			Total property, plant and equipment		5,105.00		5,050.20
		Accumulated depreciation			-1,003.00		-967.9
			Property, plant and equipment, net	$	4,102.00	$	4,082.30

Debt

Debt	3 Months Ended
	Mar. 31, 2014
Debt Disclosure [Abstract]	'
Debt	'
	7. DEBT
	Credit Agreement
	On November 13, 2013, in connection with the closing of the Offering, we, Midcoast Operating, and our material domestic subsidiaries, entered into a Credit Agreement, which we refer to as the Credit Agreement, by and among us, as co-borrower and a guarantor, Midcoast Operating, as co-borrower and a guarantor, our material subsidiaries party thereto as guarantors, Bank of America, N.A., as administrative agent, letter of credit issuer, swing line lender and lender, and each of the other lenders party thereto.
	The Credit Agreement is a committed senior revolving credit facility (with related letter of credit and swing line facilities) that permits aggregate borrowings of up to, at any one time outstanding, $850.0 million, including up to initially: (1) $90.0 million under the letter of credit facility; and (2) $75.0 million under the swing line facility. Subject to customary conditions, we may request that the lenders' aggregate commitments be increased to an amount not to exceed $1.0 billion. The facility matures in three years, subject to four one-year requests for extensions. At March 31, 2014, we were in compliance with the terms of our financial covenants.
	Loans under the Credit Agreement accrue interest at a per annum rate by reference, at our election, to the Eurodollar rate, which is equal to the LIBOR rate or a comparable or successor rate reasonably approved by the Administrative Agent, or base rate, in each case, plus an applicable margin. The applicable margin on Eurodollar (LIBOR) rate loans ranges from 1.75% to 2.75% and the applicable margin on base rate loans ranges from 0.75% to 1.75%, in each case determined based upon our total leverage ratio (as defined below) at the applicable time. At March 31, 2014, we had $250.0 million in outstanding borrowings under the Credit Agreement at a weighted average interest rate of 1.9%. Under the Credit Agreement, MEP had net repayments of approximately $85.0 million during the three month period ended March 31, 2014, which includes gross borrowings of $1,725.0 million and gross repayments of $1,810.0 million. A letter of credit fee is payable by the borrowers equal to the applicable margin for Eurodollar (LIBOR) rate loans times the daily amount available to be drawn under outstanding letters of credit. A commitment fee is payable by us equal to an applicable margin times the daily unused amount of the lenders' commitment, which applicable margin ranges from 0.30% to 0.50% based upon our total leverage ratio at the applicable time.
	Each of our domestic material subsidiaries has unconditionally guaranteed all existing and future indebtedness and liabilities of the borrowers arising under the Credit Agreement and other loan documents, and each co-borrower has guaranteed all such indebtedness and liabilities of the other co-borrower. The credit facility is unsecured but security will be provided upon occurrence of any of the following: (1) for two consecutive quarters, the Total Leverage Ratio as described below, exceeds 4.25 to 1.00, or 4.75 to 1.00 during acquisition periods, (2) uncured breach to certain terms and conditions of the Credit Agreement and (3) obtaining a non-investment grade initial debt rating from either S&P or Moody's.
	Additionally, our Credit Agreement contains various covenants and restrictive provisions which limit our ability and that of Midcoast Operating and their subsidiaries to incur certain liens or permit them to exist, merge or consolidate with another company, dispose of assets, make distributions on or redeem or repurchase their equity interests during the continuance of a default, incur or guarantee additional debt, repay subordinated debt prior to maturity, make certain investments and acquisitions, alter their lines of business, enter into certain types of transactions with affiliates and enter into agreements that restrict their ability to perform certain obligations under the Credit Agreement or to make payments to a borrower or any of their material subsidiaries.
	Our Credit Agreement also requires compliance with two financial covenants. We are not permitted to allow our ratio of consolidated funded debt to pro forma EBITDA (the total leverage ratio), as of the end of any applicable four-quarter period, to exceed 5.00 to 1.00, or 5.50 to 1.00 during acquisition periods. We must also maintain (on a consolidated basis), as of the end of each applicable four-quarter period, a ratio of pro forma EBITDA to consolidated interest expense for such four-quarter period then ended of at least 2.50 to 1.00.
	These covenants are subject to exceptions and qualifications set forth in the Credit Agreement. At such time as we obtain an investment grade rating from either Moody's or S&P, certain covenants under the Credit Agreement will no longer be applicable to either the borrowers or the guarantors, or in some instances, any of them (including, but not limited to, the obligation to provide security in certain circumstances, certain restrictions on liens, investments and debt, and restrictions on dispositions).
	Working Capital Credit Facility
	On November 13, 2013, in connection with the closing of the Offering, Midcoast Operating entered into a $250.0 million working capital credit facility with EEP as the lender. The facility is available exclusively to fund working capital borrowings. Borrowings under the facility are scheduled to mature in 2017 and accrue interest at a per annum rate of LIBOR, plus 2.5%. EEP's commitment to lend pursuant to the working capital credit facility will end on the earlier of the facility's maturity date (by acceleration or otherwise) and the date on which EEP owns less than 20% of the outstanding limited partner interests in Midcoast Operating. If EEP's commitment to lend has terminated before the facility has matured (by acceleration or otherwise), then the aggregate amount of all outstanding borrowings under the facility will automatically convert to a term loan that will bear interest at LIBOR (calculated as of the conversion date) plus 2.5%. Midcoast Operating has agreed to pay a commitment fee on the unused commitment at a per annum rate of 0.4250%, payable each fiscal quarter.
	The working capital credit facility also provides that, if the Credit Agreement is secured, the working capital credit facility also will be secured to the same extent on a second lien basis. EEP has agreed to subordinate its right to payment on obligations owed under the working capital credit facility and liens, if secured, to the rights of the lenders under the Credit Agreement, subject to the terms and conditions of a subordination agreement.
	Financial Support Agreement
	On November 13, 2013, in connection with the closing of the Offering, Midcoast Operating entered into a Financial Support Agreement, between Midcoast Operating and EEP, pursuant to which EEP will provide letters of credit and guarantees, not to exceed $700.0 million in the aggregate at any time outstanding, in support of Midcoast Operating's and its wholly owned subsidiaries' financial obligations under derivative agreements and natural gas and NGL purchase agreements to which Midcoast Operating, or one or more of its wholly owned subsidiaries, is a party. Under the Financial Support Agreement, EEP's support of Midcoast Operating's and its wholly owned subsidiaries' obligations will terminate on the earlier to occur of (1) the fourth anniversary of the closing of the Offering and (2) the date on which EEP owns, directly or indirectly (other than through its ownership interests in the Partnership), less than 20% of the total outstanding limited partner interest in Midcoast Operating.
	The annual costs that Midcoast Operating initially estimates that it will incur under the Financial Support Agreement range from approximately $4.0 million to $5.0 million and are based on the cumulative average amount of letters of credit and guarantees that EEP will provide on Midcoast Operating's and its wholly owned subsidiaries' behalf multiplied by a 2.5% annual fee. The cumulative average amount of letters of credit and guarantees will be calculated (1) with respect to letters of credit, by reference to the aggregate face value, in U.S. dollars, of letters of credit outstanding at the close of business on any business day, after taking into account any changes in such amount since the close of business on the immediately preceding business day, and (2) with respect to guarantees, by reference to the net realizable financial obligation of Midcoast Operating and its wholly owned subsidiaries under the applicable contracts, in each case after taking into account market fluctuations in commodity prices, any related EEP letters of credit and any increases or decreases underlying each guarantee. The “net realizable financial obligation” is (1) in the case of outstanding commodity derivative contracts, the amount required to terminate or discharge each such contract based upon current market prices of the relevant commodity and (2) in the case of natural gas and NGL purchase agreements, the outstanding amount owed for product received that would be recorded as a liability under U.S. GAAP, in each case, net of any amounts owed to Midcoast Operating under any agreements with counterparties that have received guarantees from EEP. Based on the Partnership's 39% controlling interest in Midcoast Operating, the Partnership incurred $1.2 million of these annual costs for the three months ending March 31, 2014, which is included in “Operating and maintenance” on our consolidated statements of income.
	The Financial Support Agreement also provides that if the Credit Agreement is secured, the Financial Support Agreement also will be secured to the same extent on a second-lien basis. EEP has agreed to subordinate its right to payment on obligations owed under the Financial Support Agreement and liens, if secured, to the rights of the lenders under the Credit Agreement, subject to the terms and conditions of a subordination agreement.
	Certain Available Credit
	At March 31, 2014, we could borrow approximately $850.0 million under the terms of our Credit Agreement and the working capital credit facility, determined as follows:
			(in millions)
		Total credit available under Credit Agreement	$	850
		Total credit available under working capital credit facility		250
		Less: Amounts outstanding under Credit Agreement		250
		Total amount we could borrow at March 31, 2014	$	850
	Fair Value of Debt Obligations
	The carrying amount of our borrowings under our Credit Agreement approximates the fair value at March 31, 2014 and December 31, 2013, respectively, due to the short-term nature and frequent repricing of this obligations. The fair value of our outstanding borrowings under our Credit Agreement is included with our long-term debt obligations since we have the ability to refinance the amounts on a long-term basis. The approximate fair value of our long-term debt obligation is determined 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 obligation is categorized as Level 2 within the fair value hierarchy.
			(in millions)
		Total credit available under Credit Agreement	$	850
		Total credit available under working capital credit facility		250
		Less: Amounts outstanding under Credit Agreement		250
		Total amount we could borrow at March 31, 2014	$	850

Partners_Capital

Partners' Capital	3 Months Ended
	Mar. 31, 2014
Partners' Capital [Abstract]	'
Partners' Capital	'
	8. PARTNERS' CAPITAL
	Distribution to Partners
	The following table sets forth our distributions, as approved by the board of directors of Midcoast Holdings, L.L.C, our General Partner, during the three month period ended March 31, 2014.
	Distribution					Distribution	Distribution		Cash
	Declaration Date			Record Date		Payment Date	per Unit		Distributed
							(in millions, except per unit amounts)
	29-Jan-14			7-Feb-14		14-Feb-14	$	0.16644	$	7.7
	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 the three month periods ended March 31, 2014 and 2013.
					For the three month
					period ended March 31,
					2014		2013
					(in millions)
	Class A common units:
		Beginning balance			$	495.3	$	-
		Net income				0.2		-
		Distributions				-3.7		-
		Ending balance			$	491.8	$	-
	Subordinated units:
		Beginning balance			$	1,035.10	$	-
		Net income				0.2		-
		Distributions				-3.8		-
		Ending balance			$	1,031.50	$	-
	General Partner units:
		Beginning balance			$	42.2	$	-
		Distributions				-0.2		-
		Ending balance			$	42	$	-
	Limited Partner: (1)
		Beginning balance			$	-	$	4,707.10
		Capital contribution				-		66.1
		Net income				-		30.7
		Distributions				-		-60.7
		Ending balance			$	-	$	4,743.20
	Accumulated other comprehensive income (loss)
		Beginning balance			$	-3.1	$	7.1
		Net realized income on changes in fair value of derivative
			financial instruments reclassified to earnings			6.5		-1.5
		Unrealized net income (loss) on derivative financial instruments				-6.3		0.8
		Ending balance			$	-2.9	$	6.4
	Noncontrolling interest
		Beginning balance			$	2,983.20	$	-
		Capital contributions				46.1		-
		Comprehensive income:
		Net income				6.3		-
		Other comprehensive income, net of tax				0.2		-
		Distributions to noncontrolling interest				-37.4		-
		Ending balance			$	2,998.40	$	-
	Total partners’ capital at end of period				$	4,560.80	$	4,749.60
	_______________________________________
	(1)	These amounts represent the changes in the capital account for the three month period ended March 31, 2013 of the former limited partner of Midcoast Operating, our predecessor for accounting purposes. These changes are not comparable to the Partnership’s limited partner interests, and thus, are shown here separately.

Related_Party_Transactions

Related Party Transactions	3 Months Ended
	Mar. 31, 2014
Related Party Transactions [Abstract]	'
Related Party Transactions	'
	9. RELATED PARTY TRANSACTIONS
	Administrative and Workforce Related Services
	We do not directly employ any of the individuals responsible for managing or operating our business. We entered into an intercorporate services agreement with EEP pursuant to which we agreed upon certain aspects of our relationship with EEP, including the provision by EEP or its affiliates to us of certain administrative services and employees, our agreement to reimburse EEP or its affiliates for the cost of such services and employees and certain other matters.
	Intercorporate Services Agreement
	On November 13, 2013, in connection with the closing of the Offering, the Partnership entered into an Intercorporate Service Agreement with EEP, pursuant to which EEP provides the Partnership with the shared services, such as management and accounting.
	Under the Intercorporate Services Agreement, the Partnership reimburses EEP and its affiliates for the costs and expenses incurred in providing such services to the Partnership. The allocation methodology under which the Partnership reimburses EEP and its affiliates for the provision of general administrative and operational services to Midcoast Operating does not differ from what Midcoast Operating was allocated historically under its prior services agreements with Enbridge and certain of its affiliates that were in effect prior to the Intercorporate Services Agreement. However, EEP has agreed to reduce the amounts payable for general and administrative expenses that otherwise would have been allocable to Midcoast Operating by $25.0 million annually. For the three month period ending March 31, 2014, we recognized $6.4 million as a reduction to “Due to general partner and affiliates” with the offset to “Noncontrolling interest” in our consolidated statements of financial position related to this reduction in amounts payable to EEP for general and administrative expenses.
	The total amount incurred by us, through EEP for services received pursuant to the general and administrative services agreement for the three month periods ended March 31, 2014 and 2013 were $52.4 million and $50.8 million, respectively. These amounts were settled through “Cash” and “Contributions from partners” as reflected on our consolidated statements of cash flows for the three month periods ended March 31, 2014 and 2013 respectively. The following table presents the affiliate amounts reflected in our consolidated statements of income by category as follows:
			For the three month period
			ended March 31,
			2014		2013
			(unaudited; in millions)
	Operating and maintenance - affiliate		$	27.1	$	26.3
	General and administrative - affiliate			25.3		24.5
		Total	$	52.4	$	50.8
	Enbridge and Enbridge Management and their respective affiliates allocated direct workforce costs to us for our construction projects of $0.9 million and $6.8 million as of March 31, 2014 and December 31, 2013, respectively, that we recorded as additions to “Property, plant and equipment, net” on our consolidated statements of financial position.
	Affiliate Revenues and Purchases
	We purchase natural gas, NGLs and crude oil from third parties, which subsequently generate operating revenues from sales to Enbridge and its affiliates. The sales to Enbridge and its affiliates are presented in “Operating revenue - affiliate” on our consolidated statements of income. These transactions are entered into at the market price on the date of sale. Included in our results for the three month periods ended March 31, 2014 and 2013 are operating revenues from sales to Enbridge and its affiliates of $57.2 million and $58.6 million, respectively.
	We also purchase natural gas, NGLs and crude oil from Enbridge and its affiliates for sale to third parties at market prices on the date of purchase. The purchases of natural gas, NGLs and crude oil from Enbridge and its affiliates are presented in “Cost of natural gas and natural gas liquids - affiliate” on our consolidated statements of income. Included in our results for the three month periods ended March 31, 2014 and 2013 are costs for natural gas, NGLs and crude oil purchases from Enbridge and its affiliates of $30.2 million and $38.1 million, respectively. 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 period ended March 31, 2014. For the three month period ended March 31, 2013, our Predecessor's routine purchases and sales with affiliates were settled monthly through EEP's centralized treasury function at terms that were consistent with third-party transactions. Routine purchases and sales with affiliates that have not yet been settled are included in “Due from general partner and affiliates” and “Due to general partner and affiliates” on our consolidated statements of financial position.
	Related Party Transactions with Joint Venture
	We have a 35% aggregate interest in the Texas Express NGL system, which is comprised of two joint ventures with third parties that together are constructing a 580 mile NGL intrastate transportation pipeline and a related NGL gathering system that was placed into service in the fourth quarter of 2013. Our equity investment in the Texas Express NGL system at March 31, 2014 and December 31, 2013 was $375.7 million and $371.3 million, respectively, which is included on our consolidated statements of financial position in “Equity investment in joint venture.” For the three month period ending March 31, 2014 we recognized a $1.3 million equity loss in “Other income (expense)” on our consolidated statement of income related to our investment in the 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 2014 to 2023.
	Partners' Capital Transactions
	Cash distributions totaling $37.4 million were paid on February 14, 2014 to EEP by Midcoast Operating as follows: (i) in the amount of $22.3 million for that portion of the three month period ending December 31, 2013 prior to the Offering, and (ii) in the amount of $15.1 million for the period from the completion of the Offering through December 31, 2013. In addition, on February 14, 2014, cash distributions totaling $4.1 million were paid to EEP and Midcoast Holdings by the Partnership for the period from the completion of the Offering through December 31, 2013. These amounts were settled through “Distributions to partners” as reflected on our consolidated statements of cash flows.
	Sale of Accounts Receivable
	Certain of our subsidiaries entered into a receivables purchase agreement, dated June 28, 2013, as amended on September 20, 2013 and December 2, 2013, which we refer to as the Receivables Agreement, with an indirect wholly owned subsidiary of Enbridge. Pursuant to the Receivables Agreement, the Enbridge subsidiary will purchase on a monthly basis, for cash, current accounts receivables and accrued receivables, or the receivables, of those of our subsidiaries and other subsidiaries of EEP that are parties thereto up to an aggregate monthly maximum of $450.0 million net of receivables that have not been collected. Following the sale and transfer of the receivables to the Enbridge subsidiary, the receivables are deposited in an account of that subsidiary, and ownership and control are vested in that subsidiary. The Enbridge subsidiary has no recourse with respect to the receivables acquired from these operating subsidiaries under the terms of and subject to the conditions stated in the Receivables Agreement. EEP and, as of December 2, 2013, MEP, each act in an administrative capacity as collection agent on behalf of the Enbridge subsidiary and can be removed at any time in the sole discretion of the Enbridge subsidiary. EEP and MEP have no other involvement with the purchase and sale of the receivables pursuant to the Receivables Agreement. The Receivables Agreement terminates on December 30, 2016.
	Consideration for the receivables sold is equivalent to the carrying value of the receivables less a discount for credit risk. The difference between the carrying value of the receivables sold and the cash proceeds received is recognized in “General and administrative – affiliate” expense in our consolidated statements of income. For the three month period ended March 31, 2014, the loss stemming from the discount on the receivables sold was $0.3 million. For the three period ended March 31, 2014, we derecognized and sold $976.3 million of accrued receivables to the Enbridge subsidiary. For the three month period ended March 31, 2014, the cash proceeds were $976.0 million which was remitted to the buyer through our centralized treasury system. As of March 31, 2014, $322.4 million of the receivables were outstanding from customers that had not been collected on behalf of the Enbridge subsidiary.
	As of March 31, 2014, we have $14.0 million 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.
	Allocated Interest
	Historically, EEP incurred borrowing cost on behalf of our Predecessor, which we recognized to the extent we were able to capitalize such costs to our construction related projects. The interest cost we incurred was directly offset by the amount of interest we capitalized on outstanding construction projects.
	Our interest cost of the three months ended March 31, 2013 is detailed below.
			For the three month period
			ended March 31,
			2013
			(unaudited; in millions)
	Interest cost incurred		$	5.6
	Interest capitalized			5.6
	Interest expense, net		$	-
	Interest cost paid		$	5.6
	Derivative Transactions
	Our Predecessor has historically had related party derivative transactions executed on behalf of EEP that were contracted through our Predecessor prior to the Offering and were allocated to EEP. These transactions were contracted to hedge the forward price of EEP's crude oil length inherent to the operation of pipelines and to hedge EEP's interest payments of variable rate debt obligations. Subsequent to the Offering, these transactions were re-contracted through EEP and are no longer allocated from our Predecessor. These historical transactions are included as part of Note 11. Derivative Financial Instruments and Hedging Activities.
	Certain of our subsidiaries entered into a receivables purchase agreement, dated June 28, 2013, as amended on September 20, 2013 and December 2, 2013, which we refer to as the Receivables Agreement, with an indirect wholly owned subsidiary of Enbridge. Pursuant to the Receivables Agreement, the Enbridge subsidiary will purchase on a monthly basis, for cash, current accounts receivables and accrued receivables, or the receivables, of those of our subsidiaries and other subsidiaries of EEP that are parties thereto up to an aggregate monthly maximum of $450.0 million net of receivables that have not been collected. Following the sale and transfer of the receivables to the Enbridge subsidiary, the receivables are deposited in an account of that subsidiary, and ownership and control are vested in that subsidiary. The Enbridge subsidiary has no recourse with respect to the receivables acquired from these operating subsidiaries under the terms of and subject to the conditions stated in the Receivables Agreement. EEP and, as of December 2, 2013, MEP, each act in an administrative capacity as collection agent on behalf of the Enbridge subsidiary and can be removed at any time in the sole discretion of the Enbridge subsidiary. EEP and MEP have no other involvement with the purchase and sale of the receivables pursuant to the Receivables Agreement. The Receivables Agreement terminates on December 30, 2016.
	Consideration for the receivables sold is equivalent to the carrying value of the receivables less a discount for credit risk. The difference between the carrying value of the receivables sold and the cash proceeds received is recognized in “General and administrative – affiliate” expense in our consolidated statements of income. For the three month period ended March 31, 2014, the loss stemming from the discount on the receivables sold was $0.3 million. For the three period ended March 31, 2014, we derecognized and sold $976.3 million of accrued receivables to the Enbridge subsidiary. For the three month period ended March 31, 2014, the cash proceeds were $976.0 million which was remitted to the buyer through our centralized treasury system. As of March 31, 2014, $322.4 million of the receivables were outstanding from customers that had not been collected on behalf of the Enbridge subsidiary.
	As of March 31, 2014, we have $14.0 million 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, 2014
Commitments And Contingencies	'
Commitments And Contingencies	'
	10. 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, 2014 and December 31, 2013, we did not record any environmental 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 not 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, 2014
Derivative Financial Instruments And Hedging Activities	'
Derivative Financial Instruments And Hedging Activities	'
	11. DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES
	Our net income and cash flows are subject to volatility stemming from fluctuations in commodity prices of natural gas, NGLs, condensate and fractionation margins. Fractionation margins represent the relative difference between the price we receive from NGL and condensate sales and the corresponding cost of natural gas we purchase for processing. Our exposure to commodity price risk exists within both of our segments. We use derivative financial instruments (i.e., futures, forwards, swaps, options and other financial instruments with similar characteristics) to manage the risks associated with market fluctuations in commodity prices, as well as to reduce the volatility in our cash flows. Based on our risk management policies, all of our derivative financial instruments are employed in connection with an underlying asset, liability and/or forecasted transaction and are not entered into with the objective of speculating on commodity prices. We have hedged a portion of our exposure to variability in future cash flows associated with commodity price risks through 2017 in accordance with our risk management policies.
	Accounting Treatment
	Effective January 1, 2014, the Partnership elected to prospectively change its presentation of derivative assets and liabilities from a net basis to a gross basis in the Consolidated Statements of Financial Position. This change was adopted to provide more granular information related to the future economic benefits available to, and obligations of, the Partnership in our Consolidated Statements of Financial Position. This change had no impact to the Consolidated Statements of Income, Net income (loss) per limited partner unit, or Partners' capital.
	We record all derivative financial instruments in our consolidated financial statements at fair market value, which we adjust each period for changes in the fair market value, and refer to as marking to market, or mark-to-market. The fair market value of these derivative financial instruments reflects the estimated amounts that we would pay to transfer a liability or receive to sell an asset in an orderly transaction with market participants to terminate or close the contracts at the reporting date, taking into account the current unrealized losses or gains on open contracts. We apply a mid-market pricing convention, which we refer to as the market approach, to value substantially all of our derivative instruments. Actively traded external market quotes, data from pricing services and published indices are used to value our derivative instruments, which are fair-valued on a recurring basis. We may also use these inputs with internally developed methodologies that result in our best estimates of fair value.
	In accordance with the applicable authoritative accounting guidance, if a derivative financial instrument does not qualify as a cash flow hedge, or is not designated as a cash flow hedge, the derivative is marked-to-market each period with the increases and decreases in fair market value recorded in our consolidated statements of income as increases and decreases in “Cost of natural gas and natural gas liquids” or “Operating revenue” for our commodity-based derivatives. Cash flow is only impacted to the extent the actual derivative contract is settled by making or receiving a payment to or from the counterparty or by making or receiving a payment for entering into a contract that exactly offsets the original derivative contract. Typically, we settle our derivative contracts when the physical transaction that underlies the derivative financial instrument occurs.
	If a derivative financial instrument qualifies and is designated as a cash flow hedge, which is a hedge of a forecasted transaction or future cash flows, any unrealized mark-to-market gain or loss is deferred in “Accumulated other comprehensive income,” also referred to as AOCI, a component of “Partners' capital,” until the underlying hedged transaction occurs. To the extent that the hedge instrument is effective in offsetting the transaction being hedged, there is no impact to the income statement until the underlying transaction occurs. At inception and on a quarterly basis, we formally assess whether the hedge contract is highly effective in offsetting changes in cash flows of hedged items. Any ineffective portion of a cash flow hedge's change in fair market value is recognized each period in earnings. Realized gains and losses on derivative financial instruments that are designated as hedges and qualify for hedge accounting are included in “cost of natural gas and natural gas liquids” for commodity hedges in the period in which the hedged transaction occurs. Gains and losses deferred in AOCI related to cash flow hedges for which hedge accounting has been discontinued remain in AOCI until the underlying physical transaction occurs unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period or within an additional two month period of time thereafter. Generally, our preference is for our derivative financial instruments to receive hedge accounting treatment whenever possible to mitigate the non-cash earnings volatility that arises from recording the changes in fair value of our derivative financial instruments through earnings. To qualify for cash flow hedge accounting treatment as set forth in the authoritative accounting guidance, very specific requirements must be met in terms of hedge structure, hedge objective and hedge documentation.
	Non-Qualified Hedges
	Many of our derivative financial instruments qualify for hedge accounting treatment as set forth in the authoritative accounting guidance. However, we have derivative financial instruments associated with our commodity activities where the hedge structure does not meet the requirements to apply hedge accounting. As a result, these derivative financial instruments do not qualify for hedge accounting and are referred to as non-qualifying. These non-qualifying derivative financial instruments are marked-to-market each period with the change in fair value included in “Cost of natural gas and natural gas liquids” or “Operating revenue” in our consolidated statements of income. These mark-to-market adjustments produce a degree of earnings volatility that can often be significant from period to period, but have no cash flow impact relative to changes in market prices. The cash flow impact occurs when the underlying physical transaction takes place in the future and the associated financial instrument contract settlement is made.
	The following transaction types do not qualify for hedge accounting and contribute to volatility in our earnings and in our cash flows upon settlement:
	Commodity Price Exposures:
	•        Transportation—In our logistics and marketing business, when we transport natural gas from one location to another, the pricing index used for natural gas sales is usually different from the pricing index used for natural gas purchases, which exposes us to market price risk relative to changes in those two indices. By entering into a basis swap, where we exchange one pricing index for another, we can effectively lock in the margin, representing the difference between the sales price and the purchase price, on the combined natural gas purchase and natural gas sale, removing any market price risk on the physical transactions. Although this represents a sound economic hedging strategy, the derivative financial instruments (i.e., the basis swaps) we use to manage the commodity price risk associated with these transportation contracts do not qualify for hedge accounting, since only the future margin has been fixed and not the future cash flow. As a result, the changes in fair value of these derivative financial instruments are recorded in earnings.
	•       Storage—In our logistics and marketing business, we use derivative financial instruments (i.e., natural gas swaps) to hedge the relative difference between the injection price paid to purchase and store natural gas and the withdrawal price at which the natural gas is sold from storage. The intent of these derivative financial instruments is to lock in the margin, representing the difference between the price paid for the natural gas injected and the price received upon withdrawal of the natural gas from storage in a future period. We do not pursue cash flow hedge accounting treatment for these storage transactions since the underlying forecasted injection or withdrawal of natural gas may not occur in the period as originally forecast. This can occur because we have the flexibility to make changes in the underlying injection or withdrawal schedule, based on changes in market conditions. In addition, since the physical natural gas or NGLs are recorded at the lower of cost or market, timing differences can result when the derivative financial instrument is settled in a period that is different from the period the physical natural gas is sold from storage. As a result, derivative financial instruments associated with our natural gas and NGL storage activities can increase volatility due to fluctuations in NGL prices until the underlying transactions are settled or offset.
	•       Optional Natural Gas Processing Volumes—In our gathering, processing and transportation business, we use derivative financial instruments to hedge the volumes of NGLs produced from our natural gas processing facilities. Some of our natural gas contracts allow us the choice of processing natural gas when it is economical and to cease doing so when processing becomes uneconomic. We have entered into derivative financial instruments to fix the sales price of a portion of the NGLs that we produce at our discretion and to fix the associated purchase price of natural gas required for processing. We typically designate derivative financial instruments associated with NGLs we produce per contractual processing requirements as cash flow hedges when the processing of natural gas is probable of occurrence. However, we are precluded from designating the derivative financial instruments as qualifying hedges of the respective commodity price risk when the discretionary processing volumes are subject to change. As a result, our operating income is subject to increased volatility due to fluctuations in NGL prices until the underlying transactions are settled or offset.
	•        NGL Forward Contracts—In our logistics and marketing business, we use forward contracts to fix the price of NGLs we purchase and store in inventory and to fix the price of NGLs that we sell from inventory to meet the demands of our customers that sell and purchase NGLs. A sub-group of physical NGL sales contracts qualify for the normal purchases and normal sales, or NPNS, scope exception. All other forward contracts are being marked-to-market each period with the changes in fair value recorded in earnings. As a result, our operating income is subject to additional volatility associated with fluctuations in NGL prices until the forward contracts are settled.
	•        Natural Gas Forward Contracts—In our logistics and marketing business, we use forward contracts to sell natural gas to our customers. Certain physical natural gas contracts with terms allowing for economic net settlement are being marked-to-market each period with the changes in fair value recorded in earnings. As a result, our operating income is subject to additional volatility associated with the changes in fair value of these contracts.
	•        Crude Forward Contracts—In our logistics and marketing business, we use forward contracts to fix the price of crude we purchase and store in inventory and to fix the price of crude that we sell from inventory. A sub-group of physical crude contracts with terms allowing for economic net settlement do not qualify for the NPNS, scope exception and are being marked-to-market each period with the changes in fair value recorded in earnings. As a result, our operating income is subject to additional volatility associated with fluctuations in crude prices until the forward contracts are settled.
	•        Condensate, Natural Gas and NGL Options—In our gathering, processing and transportation business, we use options to hedge the forecasted commodity exposure of our condensate, NGLs and natural gas. Although options can qualify for hedge accounting treatment, pursuant to the authoritative accounting guidance, we have elected non-qualifying treatment. As such, our option premiums are expensed as incurred. These derivatives are being marked-to-market, with the changes in fair value recorded to earnings each period. As a result, our operating income is subject to volatility due to movements in the prices of condensate, NGLs and natural gas until the underlying long-term transactions are settled.
	In all instances related to the commodity exposures described above, the underlying physical purchase, storage and sale of the commodity is accounted for on a historical cost or net realizable value basis rather than on the mark-to-market basis we employ for the derivative financial instruments used to mitigate the commodity price risk associated with our storage and transportation assets. This difference in accounting (i.e., the derivative financial instruments are recorded at fair market value while the physical transactions are recorded at the lower of historical cost or net realizable value) can and has resulted in volatility in our reported net income, even though the economic margin is essentially unchanged from the date the transactions were consummated.
	Derivative Positions
	Our derivative financial instruments are included at their fair values in the consolidated statements of financial position as follows:
				March 31,			December 31,
				2014			2013
				(in millions)
		Other current assets		$	24.2		$	10.3
		Other assets, net			14.8			10.3
		Accounts payable and other			-28.5			-21.1
		Other long-term liabilities			-7			-0.9
				$	3.5		$	-1.4
	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.
	We record the change in fair value of our highly effective cash flow hedges in AOCI until the derivative financial instruments are settled, at which time they are reclassified to earnings. Also included in AOCI are unrecognized losses of approximately $0.3 million associated with derivative financial instruments that qualified for and were classified as cash flow hedges of forecasted transactions that were subsequently de-designated. These losses are reclassified to earnings over the periods during which the originally hedged forecasted transactions affect earnings. During the three month period ended March 31, 2014, unrealized commodity hedge losses of $0.1 million were de-designated as a result of the hedges no longer meeting hedge accounting criteria. We estimate that approximately $8.2 million, representing unrealized net losses from our cash flow hedging activities based on pricing and positions at March 31, 2014, will be reclassified from AOCI to earnings during the next 12 months.
	The table below summarizes our derivative balances by counterparty credit quality (negative amounts represent our net obligations to pay the counterparty).
				March 31,			December 31,
				2014			2013
				(in millions)
		Counterparty Credit Quality (1)
		AAA		$	-		$	0.2
		AA			-0.5			-2.1
		A			2			-1.1
		Lower than A			2			1.6
				$	3.5		$	-1.4
		______________________________
		(1)As determined by nationally-recognized statistical ratings organizations.
	As the net value of our derivative financial instruments has increased in response to changes in forward commodity prices, our outstanding financial exposure to third parties has also increased. 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, 2014 and December 31, 2013, we were not holding any cash collateral on our asset exposures. When we are in a position of posting collateral to cover our counterparties' exposure to our non-performance, the collateral is provided through letters of credit, which are not reflected above.
	The ISDA® agreements and associated credit support, which govern our financial derivative transactions, contain no credit rating downgrade triggers that would accelerate the maturity dates of our outstanding transactions. A change in ratings is not an event of default under these instruments, and the maintenance of a specific minimum credit rating is not a condition to transacting under the ISDA® agreements. In the event of a credit downgrade, additional collateral may be required to be posted under the agreement if we are in a liability position to our counterparty, but the agreement will not automatically terminate and require immediate settlement of all future amounts due.
	The ISDA® agreements, in combination with our master netting agreements, and credit arrangements governing our commodity swaps require that collateral be posted per tiered contractual thresholds based on the credit rating of each counterparty. 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, 2014 and December 31, 2013, we had credit concentrations in the following industry sectors, as presented below:
				March 31,			December 31,
				2014			2013
				(in millions)
		United States financial institutions and investment banking entities		$	2.3		$	2.4
		Non-United States financial institutions			0.8			0.1
		Integrated oil companies			-0.5			-1.6
		Other			0.9			-2.3
				$	3.5		$	-1.4
	Gross derivative balances are presented below before the effects of collateral received or posted and without the effects of master netting arrangements. Both our assets and liabilities are adjusted for non-performance risk, which is statistically derived. This credit valuation adjustment model considers existing derivative asset and liability balances in conjunction with contractual netting and collateral arrangements, current market data such as credit default swap rates and bond spreads and probability of default assumptions to quantify an adjustment to fair value. For credit modeling purposes, collateral received is included in the calculation of our assets, while any collateral posted is excluded from the calculation of the credit adjustment. Our credit exposure for these over-the-counter derivatives is directly with our counterparty and continues until the maturity or termination of the contracts.
	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		2014			2013			2014			2013
						(in millions)
	Derivatives designated as
	hedging instruments(1)
Commodity contracts			Other current assets		$	3.2		$	2		$	-		$	-0.6
Commodity contracts			Other assets			2.8			3.5			-			-0.5
Commodity contracts			Accounts payable and other			-			1.9			-10.7			-12.7
Commodity contracts			Other long-term liabilities			-			0.6			-0.9			-1.4
						6			8			-11.6			-15.2
Derivatives not designated
	as hedging instruments
Commodity contracts			Other current assets			21			9			-			-0.1
Commodity contracts			Other assets			12			10.7			-			-3.4
Commodity contracts			Accounts payable and other			-			5.4			-17.8			-15.7
Commodity contracts			Other long-term liabilities			-			-			-6.1			-0.1
						33			25.1			-23.9			-19.3
Total derivative instruments					$	39		$	33.1		$	-35.5		$	-34.5
______________________________
(1)	Includes items currently designated as hedging instruments. Excludes the portion of de-designated hedges which may have a component remaining in AOCI.
Effect of Derivative Instruments on the Consolidated Statements of Income and Accumulated Other Comprehensive Income
															Amount of Gain
															(Loss) Recognized in
												Location of Gain			Earnings on
												(Loss) Recognized in			Derivative
												Earnings on Derivative			(Ineffective Portion
			Amount of Gain			Location of Gain (Loss)			Amount of Gain (Loss)			(Ineffective Portion			and Amount
Derivatives in Cash			(Loss) Recognized in			Reclassified from			Reclassified from			and Amount			Excluded from
Flow Hedging			AOCI on Derivative			AOCI to Earnings			AOCI to Earnings			Excluded from			Effectiveness
Relationships			(Effective Portion)			(Effective Portion)			(Effective Portion)			Effectiveness Testing)(1)			Testing)(1)
	(in millions)
For the three month period ended March 31, 2014
						Cost of natural gas and						Cost of natural gas and
Commodity contracts			$	-0.1			natural gas liquids		$	-6.5			natural gas liquids		$	1.7
Total			$	-0.1					$	-6.5					$	1.7
For the three month period ended March 31, 2013
						Cost of natural gas and						Cost of natural gas and
Commodity contracts			$	-1.6			natural gas liquids		$	1.5			natural gas liquids		$	0.5
Total			$	-1.6					$	1.5					$	0.5
______________________________
(1)	Includes only the ineffective portion of derivatives that are designated as hedging instruments and does not include net gains or losses associated with derivatives that do not qualify for hedge accounting treatment.
Components of Accumulated Other Comprehensive Income/(Loss)
				Cash Flow
				Hedges
				(in millions)
Balance at December 31, 2013				$	-3.1
	Other Comprehensive Income before reclassifications (1)				-2.4
	Amounts reclassified from AOCI (2) (3)				2.6
	Tax benefit (expense)				0
		Net other comprehensive income (loss)		$	0.2
Balance at March 31, 2014				$	-2.9
_______________________________________
(1)	Excludes NCI loss of $3.7 million reclassified from AOCI at March 31, 2014.
(2)	Excludes NCI gain of $3.9 million reclassified from AOCI at March 31, 2014.
(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,
				2014			2013
				(unaudited; in millions)
Losses (gains) on cash flow hedges:
	Commodity Contracts (1) (2)			$	2.6		$	-1.5
		Total Reclassifications from AOCI		$	2.6		$	-1.5
______________________________
(1)Loss (gain) reported within "Cost of natural gas and natural gas liquids" in the consolidated statements of income.
(2)Excludes NCI gain of $3.9 million reclassified from AOCI at March 31, 2014.
Effect of Derivative Instruments on Consolidated Statements of Income
						For the three month period
						ended March 31,
						2014			2013(4)
Derivatives Not Designated			Location of Gain or (Loss)			Amount of Gain or  (Loss)
as Hedging Instruments			Recognized in Earnings(1)			Recognized in Earnings(2)
						(unaudited; in millions)
			Cost of natural gas and
Commodity contracts				natural gas liquids(3)		$	-6.4		$	-2.4
Commodity contracts			Operating revenue				0.8			-
Total						$	-5.6		$	-2.4
________________________
(1)	Does not include settlements associated with derivative instruments that settle through physical delivery.
(2)	Includes only net gains or losses associated with those derivatives that do not qualify for hedge accounting treatment and does not include the ineffective portion of derivatives that are designated as hedging instruments.
(3)	Includes settlements losses of $8.5 million and $0.4 million for the three month periods ended March 31, 2014 and March 31, 2013, respectively.
(4)	Includes both affiliate and third party transactions.
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, 2014
				Gross Amount of Assets			Amount
				Presented in the			Not Offset in the
				Statement of			Statement of			Net
				Financial Position			Financial Position			Amount
				(unaudited; in millions)
Description:
	Derivatives			$	39		$	-18.2		$	20.8
		Total		$	39		$	-18.2		$	20.8
Offsetting of Financial Liabilities and Derivative Liabilities
				As of March 31, 2014
				Gross Amount of Liabilities			Amount
				Presented in the			Not Offset in the
				Statement of			Statement of			Net
				Financial Position			Financial Position			Amount
				(unaudited; in millions)
Description:
	Derivatives			$	-35.5		$	18.2		$	-17.3
		Total		$	-35.5		$	18.2		$	-17.3
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, 2014 and December 31, 2013. 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.
We categorize 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, as Level 2. This category includes both over-the-counter, or 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; (3) volatility factors; and (4) 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.
			31-Mar-14												December 31, 2013
			Level 1			Level 2			Level 3			Total			Level 1			Level 2			Level 3			Total
			(in millions)
Commodity contracts:
	Financial		$	-		$	-3.9		$	-3.4		$	-7.3		$	-		$	-3.4		$	-6.9		$	-10.3
	Physical			-			-			3.6			3.6			-			-			0.5			0.5
Commodity options				-			-			7.2			7.2			-			-			8.4			8.4
Total			$	-		$	-3.9		$	7.4		$	3.5		$	-		$	-3.4		$	2		$	-1.4
Qualitative Information about Level 3 Fair Value Measurements
Data from pricing services and published indices are used to value our Level 3 derivative instruments, which are fair-valued on a recurring basis. We may also use these inputs with internally developed methodologies that result in our best estimate of fair value. The inputs listed in the table below would have a direct impact on the fair values of the listed instruments. The significant unobservable inputs used in the fair value measurement of the commodity derivatives (Natural Gas, NGLs and Crude Oil) are forward commodity prices. The significant unobservable inputs used in determining the fair value measurement of options are price and volatility. Increases/(decreases) in the forward commodity price in isolation would result in significantly higher/(lower) fair values for long positions, with offsetting impacts to short positions. Increases/(decreases) in volatility would increase/(decrease) the value for the holder of the option. Generally, a change in the estimate of forward commodity prices is unrelated to a change in the estimate of volatility of prices. An increase to the credit valuation adjustment would decrease the fair value of the positions.
Quantitative Information About Level 3 Fair Value Measurements
			Fair Value at							Range (1)
			March 31,			Valuation		Unobservable				Weighted
Contract Type			2014			Technique		Input		Lowest	Highest	Average	Units
Commodity Contracts - Financial			(in millions)
	Natural Gas		$	-0.3		Market Approach		Forward Gas Price		3.88	4.68	4.42	MMBtu
	NGLs		$	-3.1		Market Approach		Forward NGL Price		1.01	2.18	1.35	Gal
Commodity Contracts - Physical
	Natural Gas		$	2.3		Market Approach		Forward Gas Price		3.34	5.17	4.25	MMBtu
	Crude Oil		$	-1.2		Market Approach		Forward Crude Price		87.93	106.27	100.05	Bbl
	NGLs		$	2.5		Market Approach		Forward NGL Price		0.01	2.31	1.11	Gal
Commodity Options
	Natural Gas, Crude and NGLs		$	7.2		Option Model		Option Volatility		15%	77%	34%
Total Fair Value			$	7.4
_______________________________________
(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.
Quantitative Information About Level 3 Fair Value Measurements
			Fair Value at							Range(1)
			December 31,			Valuation		Unobservable				Weighted
Contract Type			2013(2)			Technique		Input		Lowest	Highest	Average	Units
Commodity Contracts - Financial			(in millions)
	Natural Gas		$	0		Market Approach		Forward Gas Price		3.64	4.41	4.14	MMBtu
	NGLs		$	-6.9		Market Approach		Forward NGL Price		1	2.13	1.38	Gal
Commodity Contracts - Physical
	Natural Gas		$	1.1		Market Approach		Forward Gas Price		3.36	4.82	4.15	MMBtu
	Crude Oil		$	-0.5		Market Approach		Forward Crude Price		86.37	103.04	97.24	Bbl
	NGLs		$	-0.1		Market Approach		Forward NGL Price		0.02	2.19	0.95	Gal
Commodity Options
	Natural Gas, Crude and NGLs		$	8.4		Option Model		Option Volatility		18%	44%	28%
Total Fair Value			$	2
_______________________________
(1)	Prices are in dollars per MMBtu for Natural Gas, dollars per Gal for NGLs and dollars per Bbl for Crude Oil.
(2)	Fair values include credit valuation adjustments of approximately $0.1 million of gains.
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, 2014 to March 31, 2014. 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, 2014				$	-6.9		$	0.5		$	8.4		$	2
	Transfer out of Level 3 (1)				-			-			-			-
Gains or losses:
	Included in earnings				-5.3			1.7			-1.5			-5.1
	Included in other comprehensive income				-1.1			-			-			-1.1
Purchases, issuances, sales and settlements:
	Purchases				-			-			0.2			0.2
	Settlements (2)				9.9			1.4			0.1			11.4
Ending balance as of March 31, 2014				$	-3.4		$	3.6		$	7.2		$	7.4
Amount of changes in net assets attributable to the change in unrealized
	gains or losses related to assets still held at the reporting date			$	-1.2		$	1.9		$	-1.1		$	-0.4
Amounts reported in operating revenue				$	-		$	0.8		$	-		$	0.8
_________________
(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, 2014 and December 31, 2013.
				At March 31, 2014																At December 31, 2013
								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 2014
	Swaps
		Receive variable/pay fixed		Natural Gas		872,000		$	4.43		$	4.28		$	0.1		$	-		$	-		$	-
				NGL		653,750		$	65.16		$	65.99		$	0.9		$	-1.5		$	0.6		$	-0.4
				Crude Oil		70,000		$	100.82		$	100.1		$	0.1		$	-		$	-		$	-
		Receive fixed/pay variable		Natural Gas		2,443,800		$	4		$	4.39		$	-		$	-1		$	0.1		$	-1
				NGL		1,967,500		$	54.5		$	56		$	4.8		$	-7.7		$	4.8		$	-12.7
				Crude Oil		858,250		$	91.82		$	98.09		$	0.2		$	-5.6		$	0.3		$	-5.4
		Receive variable/pay variable		Natural Gas		38,490,000		$	4.38		$	4.38		$	0.6		$	-0.4		$	0.6		$	-0.1
	Physical Contracts
		Receive variable/pay fixed		Natural Gas		5,703,122		$	4.46		$	4.41		$	0.4		$	-0.1		$	-		$	-
				NGL		1,073,640		$	57.57		$	57.25		$	1.2		$	-0.9		$	0.9		$	-0.9
				Crude Oil		243,713		$	99.24		$	99.81		$	0.3		$	-0.4		$	-		$	-
		Receive fixed/pay variable		Natural Gas		23,485,419		$	4.33		$	4.33		$	0.1		$	-0.1		$	-		$	-
				NGL		1,197,064		$	55.26		$	56.68		$	0.1		$	-1.8		$	0.4		$	-2.6
				Crude Oil		333,526		$	99.25		$	100.28		$	0.4		$	-0.7		$	-		$	-0.4
		Receive variable/pay variable		Natural Gas		89,130,497		$	4.41		$	4.4		$	1.8		$	-0.7		$	0.9		$	-0.4
				NGL		8,029,834		$	42.91		$	42.48		$	5.2		$	-1.7		$	5.8		$	-3.7
				Crude Oil		843,189		$	97.13		$	98.03		$	3.4		$	-4.1		$	1.1		$	-1.2
Portion of contracts maturing in 2015
	Swaps
		Receive fixed/pay variable		Natural Gas		60,000		$	4.52		$	4.51		$	-		$	-		$	-		$	-
				NGL		565,750		$	51.33		$	50.71		$	1.4		$	-1.1		$	1.5		$	-1.1
				Crude Oil		350,400		$	93		$	89.89		$	1.2		$	-0.2		$	1.7		$	-
		Receive variable/pay variable		Natural Gas		10,107,500		$	4.32		$	4.33		$	0.1		$	-0.1		$	0.1		$	-
		Receive variable/pay fixed		Crude Oil		67,500		$	92.58		$	91.1		$	0.1		$	-		$	-		$	-
	Physical Contracts
		Receive fixed/pay variable		Natural Gas		3,158,951		$	4.49		$	4.5		$	-		$	-		$	-		$	-
				NGL		54,760		$	54.21		$	52.91		$	0.1		$	-		$	-		$	-
		Receive variable/pay variable		Natural Gas		46,325,708		$	4.24		$	4.22		$	1.2		$	-0.4		$	0.5		$	-0.1
				NGL		808,001		$	71.16		$	70.79		$	0.4		$	-0.1		$	-		$	-
Portion of contracts maturing in 2016
	Swaps
		Receive fixed/pay variable		Crude Oil		45,750		$	99.31		$	84.52		$	0.7		$	-		$	0.7		$	-
	Physical Contracts
		Receive variable/pay variable		Natural Gas		31,192,423		$	3.97		$	3.97		$	0.7		$	-0.5		$	0.1		$	-
Portion of contracts maturing in 2017
	Physical Contracts
		Receive variable/pay variable		Natural Gas		13,425,825		$	4.17		$	4.18		$	0.3		$	-0.4		$	-		$	-
______________________________
(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, 2014 and December 31, 2013, 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 gains at December 31, 2013.
The following table provides summarized information about the fair values of expected cash flows of our outstanding commodity options at March 31, 2014 and December 31, 2013.
				At March 31, 2014																At December 31, 2013
								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 2014
		Puts (purchased)		Natural Gas		3,300,000		$	3.9		$	4.46		$	0.4		$	-		$	0.7		$	-
				NGL		394,500		$	53.04		$	53.17		$	2.3		$	-		$	2.9		$	-
		Calls (written)		NGL		206,250		$	59.62		$	54.36		$	-		$	-0.6		$	-		$	-1
		Puts (written)		Natural Gas		1,729,000		$	3.9		$	4.49		$	-		$	-0.2		$	-		$	-0.5
		Calls (purchased)		NGL		46,000		$	50.4		$	45.73		$	0.2		$	-		$	-		$	-
Portion of option contracts maturing in 2015
		Puts (purchased)		Natural Gas		4,015,000		$	3.9		$	4.2		$	1.9		$	-		$	1.7		$	-
				NGL		1,113,250		$	50.64		$	53.31		$	6.1		$	-		$	6		$	-
				Crude Oil		456,250		$	85		$	89.5		$	2.3		$	-		$	1.8		$	-
		Calls (written)		Natural Gas		1,277,500		$	5.05		$	4.2		$	-		$	-0.4		$	-		$	-0.3
				NGL		292,000		$	62.48		$	57.59		$	-		$	-1.6		$	-		$	-1
				Crude Oil		456,250		$	90.7		$	89.5		$	-		$	-3.1		$	-		$	-1.9
Portion of option contracts maturing in 2016
		Puts (purchased)		Crude Oil		91,500		$	80		$	84.3		$	0.6		$	-		$	-		$	-
		Calls (written)		Crude Oil		91,500		$	87		$	84.3		$	-		$	-0.7		$	-		$	-
______________________________
(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, 2014 and December 31, 2013, respectively, discounted using the swap rate for the respective periods to consider the time value of money.
Fair Value Measurements of Commodity Derivatives
The following table provides summarized information about the fair values of expected cash flows of our outstanding commodity based swaps and physical contracts at March 31, 2014 and December 31, 2013.
				At March 31, 2014																At December 31, 2013
								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 2014
	Swaps
		Receive variable/pay fixed		Natural Gas		872,000		$	4.43		$	4.28		$	0.1		$	-		$	-		$	-
				NGL		653,750		$	65.16		$	65.99		$	0.9		$	-1.5		$	0.6		$	-0.4
				Crude Oil		70,000		$	100.82		$	100.1		$	0.1		$	-		$	-		$	-
		Receive fixed/pay variable		Natural Gas		2,443,800		$	4		$	4.39		$	-		$	-1		$	0.1		$	-1
				NGL		1,967,500		$	54.5		$	56		$	4.8		$	-7.7		$	4.8		$	-12.7
				Crude Oil		858,250		$	91.82		$	98.09		$	0.2		$	-5.6		$	0.3		$	-5.4
		Receive variable/pay variable		Natural Gas		38,490,000		$	4.38		$	4.38		$	0.6		$	-0.4		$	0.6		$	-0.1
	Physical Contracts
		Receive variable/pay fixed		Natural Gas		5,703,122		$	4.46		$	4.41		$	0.4		$	-0.1		$	-		$	-
				NGL		1,073,640		$	57.57		$	57.25		$	1.2		$	-0.9		$	0.9		$	-0.9
				Crude Oil		243,713		$	99.24		$	99.81		$	0.3		$	-0.4		$	-		$	-
		Receive fixed/pay variable		Natural Gas		23,485,419		$	4.33		$	4.33		$	0.1		$	-0.1		$	-		$	-
				NGL		1,197,064		$	55.26		$	56.68		$	0.1		$	-1.8		$	0.4		$	-2.6
				Crude Oil		333,526		$	99.25		$	100.28		$	0.4		$	-0.7		$	-		$	-0.4
		Receive variable/pay variable		Natural Gas		89,130,497		$	4.41		$	4.4		$	1.8		$	-0.7		$	0.9		$	-0.4
				NGL		8,029,834		$	42.91		$	42.48		$	5.2		$	-1.7		$	5.8		$	-3.7
				Crude Oil		843,189		$	97.13		$	98.03		$	3.4		$	-4.1		$	1.1		$	-1.2
Portion of contracts maturing in 2015
	Swaps
		Receive fixed/pay variable		Natural Gas		60,000		$	4.52		$	4.51		$	-		$	-		$	-		$	-
				NGL		565,750		$	51.33		$	50.71		$	1.4		$	-1.1		$	1.5		$	-1.1
				Crude Oil		350,400		$	93		$	89.89		$	1.2		$	-0.2		$	1.7		$	-
		Receive variable/pay variable		Natural Gas		10,107,500		$	4.32		$	4.33		$	0.1		$	-0.1		$	0.1		$	-
		Receive variable/pay fixed		Crude Oil		67,500		$	92.58		$	91.1		$	0.1		$	-		$	-		$	-
	Physical Contracts
		Receive fixed/pay variable		Natural Gas		3,158,951		$	4.49		$	4.5		$	-		$	-		$	-		$	-
				NGL		54,760		$	54.21		$	52.91		$	0.1		$	-		$	-		$	-
		Receive variable/pay variable		Natural Gas		46,325,708		$	4.24		$	4.22		$	1.2		$	-0.4		$	0.5		$	-0.1
				NGL		808,001		$	71.16		$	70.79		$	0.4		$	-0.1		$	-		$	-
Portion of contracts maturing in 2016
	Swaps
		Receive fixed/pay variable		Crude Oil		45,750		$	99.31		$	84.52		$	0.7		$	-		$	0.7		$	-
	Physical Contracts
		Receive variable/pay variable		Natural Gas		31,192,423		$	3.97		$	3.97		$	0.7		$	-0.5		$	0.1		$	-
Portion of contracts maturing in 2017
	Physical Contracts
		Receive variable/pay variable		Natural Gas		13,425,825		$	4.17		$	4.18		$	0.3		$	-0.4		$	-		$	-
______________________________
(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, 2014 and December 31, 2013, 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 gains at December 31, 2013.
The following table provides summarized information about the fair values of expected cash flows of our outstanding commodity options at March 31, 2014 and December 31, 2013.
				At March 31, 2014																At December 31, 2013
								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 2014
		Puts (purchased)		Natural Gas		3,300,000		$	3.9		$	4.46		$	0.4		$	-		$	0.7		$	-
				NGL		394,500		$	53.04		$	53.17		$	2.3		$	-		$	2.9		$	-
		Calls (written)		NGL		206,250		$	59.62		$	54.36		$	-		$	-0.6		$	-		$	-1
		Puts (written)		Natural Gas		1,729,000		$	3.9		$	4.49		$	-		$	-0.2		$	-		$	-0.5
		Calls (purchased)		NGL		46,000		$	50.4		$	45.73		$	0.2		$	-		$	-		$	-
Portion of option contracts maturing in 2015
		Puts (purchased)		Natural Gas		4,015,000		$	3.9		$	4.2		$	1.9		$	-		$	1.7		$	-
				NGL		1,113,250		$	50.64		$	53.31		$	6.1		$	-		$	6		$	-
				Crude Oil		456,250		$	85		$	89.5		$	2.3		$	-		$	1.8		$	-
		Calls (written)		Natural Gas		1,277,500		$	5.05		$	4.2		$	-		$	-0.4		$	-		$	-0.3
				NGL		292,000		$	62.48		$	57.59		$	-		$	-1.6		$	-		$	-1
				Crude Oil		456,250		$	90.7		$	89.5		$	-		$	-3.1		$	-		$	-1.9
Portion of option contracts maturing in 2016
		Puts (purchased)		Crude Oil		91,500		$	80		$	84.3		$	0.6		$	-		$	-		$	-
		Calls (written)		Crude Oil		91,500		$	87		$	84.3		$	-		$	-0.7		$	-		$	-
______________________________
(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, 2014 and December 31, 2013, respectively, discounted using the swap rate for the respective periods to consider the time value of money.
			March 31,			December 31,
			2014			2013
			(in millions)
	Counterparty Credit Quality (1)
	AAA		$	-		$	0.2
	AA			-0.5			-2.1
	A			2			-1.1
	Lower than A			2			1.6
			$	3.5		$	-1.4
	______________________________
	(1)As determined by nationally-recognized statistical ratings organizations.

Income_Taxes

Income Taxes	3 Months Ended
	Mar. 31, 2014
Income Taxes	'
Income Taxes	'
	12. 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 that apply to entities organized as partnerships by the state of Texas that 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 0.5% for the three month periods ended March 31, 2014 and 2013. Our income tax expense is $1.0 million and $0.5 million for the three month periods ended March 31, 2014 and 2013, respectively.
	At March 31, 2014 and December 31, 2013, we have included a current income tax payable of $1.8 million and $1.0 million, respectively, in “Property and other taxes payable” on our consolidated statements of financial position. In addition, at March 31, 2014 and December 31, 2013, we have included a deferred income tax payable of $11.6 million and $11.1 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, 2014
Segment Information	'
Segment Information	'
	13. SEGMENT INFORMATION
	Our business is divided into operating segments, defined as components of the enterprise, about which financial information is available and evaluated regularly by our Chief Operating Decision Maker, collectively comprised of our senior management, in deciding how resources are allocated and performance is assessed.
	Each of our reportable segments is a business unit that offers different services and products that is managed separately, since each business segment requires different operating strategies. We conduct our business through two distinct reporting segments:
	•        Gathering, Processing and Transportation; and
	•       Logistics and Marketing.
	The following tables present certain financial information relating to our business segments and corporate activities:
			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 (3)			-1.2		-		-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 (2)		$	4,901.70	$	311.1	$	216.7	$	5,429.50
	Capital expenditures (excluding acquisitions)		$	47.8	$	2.3	$	5.3	$	55.4
	______________________________
	(1)	Corporate consists of income taxes and interest expense, which are not allocated to the business segments.
	(2)	Totals assets for our Gathering, Processing and Transportation segment includes our long-term equity investment in the Texas Express NGL system.
	(3)	Other income (expense) for our Gathering, Processing and Transportation segment includes our equity investment in the Texas Express NGL system which began recognizing operating costs during the fourth quarter of 2013.
			As of and for the three month period ended March 31, 2013
			Gathering, Processing and Transportation		Logistics and Marketing		Corporate (1)		Total
			(in millions)
	Total revenue		$	659.2	$	1,223.00	$	-	$	1,882.20
	Less: Intersegment revenue			487		24.9		-		511.9
	Operating revenue			172.2		1,198.10		-		1,370.30
	Cost of natural gas and natural gas liquids			17.4		1,178.70		-		1,196.10
	Segment gross margin			154.8		19.4		-		174.2
	Operating and maintenance			64.2		19.2		-		83.4
	General and administrative			21.9		2.6		-		24.5
	Depreciation and amortization			33.5		1.7		-		35.2
				119.6		23.5		-		143.1
	Operating income (loss)			35.2		-4.1		-		31.1
	Other income (expense)			-		-		0.1		0.1
	Income (loss) before income tax expense			35.2		-4.1		0.1		31.2
	Income tax expense			-		-		0.5		0.5
	Net income (loss)		$	35.2	$	-4.1	$	-0.4	$	30.7
	Total assets (2)		$	4,533.10	$	843.2	$	237.6	$	5,613.90
	Capital expenditures (excluding acquisitions)		$	66.3	$	4.6	$	-	$	70.9
	______________________________
	(1)	Corporate consists of income taxes, which are not allocated to the business segments.
	(2)	Totals assets for our Gathering, Processing and Transportation segment includes our long-term equity investment in the Texas Express NGL system.

Supplemental_Cash_Flows_Inform

Supplemental Cash Flows Information	3 Months Ended
	Mar. 31, 2014
Supplemental Cash Flows Information	'
Supplemental Cash Flows Information	'
	14. SUPPLEMENTAL CASH FLOW INFORMATION
	The following table provides supplemental information for the item labeled “Other" in the “Cash provided by operating activities" section of our consolidated statements of cash flows.
				For the three month
				period ended March 31,
				2014			2013
				(in millions)
		Deferred income taxes		$	0.5		$	-
		Texas Express long-term inventory (line fill)			0.3			-
		Loss on sale of assets			-			1.1
		Allowance for interest used during construction			-			-2.8
		Amortization of hedging			-			-0.2
		Other			0.2			-0.3
				$	1		$	-2.2
	In the “Cash used in investing activities” section of the consolidated statements of cash flows, we exclude changes that did not affect cash. The following is a reconciliation of additions to property, plant and equipment to total capital expenditures (excluding “Investment in joint venture”):
						For the three month
						period ended March 31,
						2014			2013
						(in millions)
		Additions to property, plant and equipment				$	55.5		$	78
			Decrease in construction payables				-0.1			-7.1
		Total capital expenditures (excluding "Investment in joint venture")				$	55.4		$	70.9

Subsequent_Events

Subsequent Events	3 Months Ended
	Mar. 31, 2014
Subsequent Events	'
Subsequent Events	'
	16. SUBSEQUENT EVENTS
	Distribution to Partners
	On April 29, 2014, the board of directors of Midcoast Holdings, L.L.C., acting in its capacity as the general partner of MEP, declared a cash distribution payable to our partners on May 15, 2014. The distribution will be paid to unitholders of record as of May 8, 2014, of our available cash of $14.4 million at March 31, 2014, or $0.3125 per limited partner unit. We will pay $6.6 million to our public Class A common unitholders, while $7.8 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, 2014, the general partner of Midcoast Operating, acting in its capacity as the general partner of Midcoast Operating, declared a cash distribution by Midcoast Operating payable to its partners of record as of May 8, 2014. Midcoast Operating will pay $15.3 million to us and $23.9 million to EEP.
	Distribution to Partners
	On April 29, 2014, the board of directors of Midcoast Holdings, L.L.C., acting in its capacity as the general partner of MEP, declared a cash distribution payable to our partners on May 15, 2014. The distribution will be paid to unitholders of record as of May 8, 2014, of our available cash of $14.4 million at March 31, 2014, or $0.3125 per limited partner unit. We will pay $6.6 million to our public Class A common unitholders, while $7.8 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, 2014, the general partner of Midcoast Operating, acting in its capacity as the general partner of Midcoast Operating, declared a cash distribution by Midcoast Operating payable to its partners of record as of May 8, 2014. Midcoast Operating will pay $15.3 million to us and $23.9 million to EEP.

Recent_Accounting_Pronouncemen

Recent Accounting Pronouncements Not Yet Adopted	3 Months Ended
	Mar. 31, 2014
Disclosure Text Block [Abstract]	'
Description of New Accounting Pronouncements Not yet Adopted [Text Block]	'
	15. RECENT ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED
	In April of 2014, FASB issued Accounting Standards Update No. 2014-08 that changes the criteria and requires expanded disclosures for reporting discontinued operations. The adoption of the pronouncement is not anticipated to have a material impact on our consolidated financial statements. This accounting update is effective for annual and interim periods beginning after December 15, 2014 and is to be applied prospectively.

Net_Income_Per_Limited_Partner1

Net Income Per Limited Partner And General Partner Interest (Tables)	3 Months Ended
	Mar. 31, 2014
Net Income Per Limited Partner And General Partner Interest	'
Schedule Of Formula For Distributing Available Cash	'
		Distribution Targets		Portion of Quarterly Distribution Per Unit	Percentage Distributed to Limited Partners		Percentage Distributed 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	'
			We determined basic and diluted net income per limited partner unit as follows:
						For the three month
						period ended March 31,
						2014		2013(3)
						(in millions, except per unit amounts)
	Net income				$	6.7		$	30.7
	Less: Net income attributable to noncontrolling interest					6.3			18.7
	Net income attributable to general and limited partner
		interests in Midcoast Energy Partners, L.P.				0.4			12
	Less distributions:
			Total distributed earnings to our General Partner			-0.3			-0.1
			Total distributed earnings to our limited partners			-14.1			-8.4
	Total distributed earnings					-14.4			-8.5
	Underdistributed (Overdistributed) earnings				$	-14		$	3.5
	Weighted average limited partner units outstanding					45.2			26.7
	Basic and diluted earnings per unit:
		Distributed earnings per limited partner unit (1)			$	0.31		$	0.31
		Underdistributed (Overdistributed) earnings per limited partner unit (2)				-0.3			0.13
	Net income per limited partner unit (basic and diluted)				$	0.01		$	0.44
	______________________________
	(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.
	(3)	Represents calculation retrospectively reflecting the affiliate capitalization of MEP consisting of 4.1 million MEP Class A common units, 22.6 million MEP subordinated units and MEP general partner interest upon the transfer of a controlling ownership, including limited partner and general partner interest, in Midcoast Operating. The noncontrolling interest reflects the 61% retained by EEP.

Inventory_Tables

Inventory (Tables)	3 Months Ended
	Mar. 31, 2014
Inventory	'
Schedule Of Inventory	'
		Our inventory is comprised of the following:
			March 31,		December 31,
			2014		2013
			(in millions)
		Materials and supplies	$	0.5	$	0.6
		Crude oil inventory		11.2		12.6
		Natural gas and NGL inventory		48.6		74.8
			$	60.3	$	88

Property_Plant_And_Equipment_T

Property, Plant And Equipment (Tables)	3 Months Ended
	Mar. 31, 2014
Property, Plant And Equipment	'
Schedule Of Property, Plant And Equipment	'
	Our property, plant and equipment is comprised of the following:
				March 31,		December 31,
				2014		2013
				(in millions)
		Land		$	11.2	$	11.6
		Rights-of-way			385.5		380
		Pipelines			1,765.00		1,741.90
		Pumping equipment, buildings and tanks			79.5		79.2
		Compressors, meters and other operating equipment			2,024.60		1,993.20
		Vehicles, office furniture and equipment			152.1		148.5
		Processing and treating plants			514.6		514.4
		Construction in progress			172.5		181.4
			Total property, plant and equipment		5,105.00		5,050.20
		Accumulated depreciation			-1,003.00		-967.9
			Property, plant and equipment, net	$	4,102.00	$	4,082.30

Debt_Tables

Debt (Tables)	3 Months Ended
	Mar. 31, 2014
Debt Disclosure [Abstract]	'
Schedule Of Line Of Credit Facilities	'
			(in millions)
		Total credit available under Credit Agreement	$	850
		Total credit available under working capital credit facility		250
		Less: Amounts outstanding under Credit Agreement		250
		Total amount we could borrow at March 31, 2014	$	850
			(in millions)
		Total credit available under Credit Agreement	$	850
		Total credit available under working capital credit facility		250
		Less: Amounts outstanding under Credit Agreement		250
		Total amount we could borrow at March 31, 2014	$	850

Partners_Capital_Tables

Partners' Capital (Tables)	3 Months Ended
	Mar. 31, 2014
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)
	29-Jan-14			7-Feb-14		14-Feb-14	$	0.16644	$	7.7
Schedule Of Changes In Partners' Capital Attributable To General And Limited Partners	'
					For the three month
					period ended March 31,
					2014		2013
					(in millions)
	Class A common units:
		Beginning balance			$	495.3	$	-
		Net income				0.2		-
		Distributions				-3.7		-
		Ending balance			$	491.8	$	-
	Subordinated units:
		Beginning balance			$	1,035.10	$	-
		Net income				0.2		-
		Distributions				-3.8		-
		Ending balance			$	1,031.50	$	-
	General Partner units:
		Beginning balance			$	42.2	$	-
		Distributions				-0.2		-
		Ending balance			$	42	$	-
	Limited Partner: (1)
		Beginning balance			$	-	$	4,707.10
		Capital contribution				-		66.1
		Net income				-		30.7
		Distributions				-		-60.7
		Ending balance			$	-	$	4,743.20
	Accumulated other comprehensive income (loss)
		Beginning balance			$	-3.1	$	7.1
		Net realized income on changes in fair value of derivative
			financial instruments reclassified to earnings			6.5		-1.5
		Unrealized net income (loss) on derivative financial instruments				-6.3		0.8
		Ending balance			$	-2.9	$	6.4
	Noncontrolling interest
		Beginning balance			$	2,983.20	$	-
		Capital contributions				46.1		-
		Comprehensive income:
		Net income				6.3		-
		Other comprehensive income, net of tax				0.2		-
		Distributions to noncontrolling interest				-37.4		-
		Ending balance			$	2,998.40	$	-
	Total partners’ capital at end of period				$	4,560.80	$	4,749.60
	_______________________________________
	(1)	These amounts represent the changes in the capital account for the three month period ended March 31, 2013 of the former limited partner of Midcoast Operating, our predecessor for accounting purposes. These changes are not comparable to the Partnership’s limited partner interests, and thus, are shown here separately.

Related_Party_Transactions_Tab

Related Party Transactions (Tables)	3 Months Ended
	Mar. 31, 2014
Related Party Transactions [Abstract]	'
Schedule Of Cash Activity For A1 Credit Facility And A1 Term Note	'
			For the three month period
			ended March 31,
			2014		2013
			(unaudited; in millions)
	Operating and maintenance - affiliate		$	27.1	$	26.3
	General and administrative - affiliate			25.3		24.5
		Total	$	52.4	$	50.8
Interest Income and Interest Expense Disclosure [Table Text Block]	'
			For the three month period
			ended March 31,
			2013
			(unaudited; in millions)
	Interest cost incurred		$	5.6
	Interest capitalized			5.6
	Interest expense, net		$	-
	Interest cost paid		$	5.6

Derivative_Financial_Instrumen1

Derivative Financial Instruments And Hedging Activities (Tables)	3 Months Ended
	Mar. 31, 2014
Derivative Financial Instruments And Hedging Activities	'
Schedule Of Derivative Instruments In Statement Of Financial Position, Fair Value	'
	Derivative Positions
	Our derivative financial instruments are included at their fair values in the consolidated statements of financial position as follows:
				March 31,			December 31,
				2014			2013
				(in millions)
		Other current assets		$	24.2		$	10.3
		Other assets, net			14.8			10.3
		Accounts payable and other			-28.5			-21.1
		Other long-term liabilities			-7			-0.9
				$	3.5		$	-1.4
Schedule Of Derivative Balances By Counter Party Credit Quality	'
	The table below summarizes our derivative balances by counterparty credit quality (negative amounts represent our net obligations to pay the counterparty).
				March 31,			December 31,
				2014			2013
				(in millions)
		Counterparty Credit Quality (1)
		AAA		$	-		$	0.2
		AA			-0.5			-2.1
		A			2			-1.1
		Lower than A			2			1.6
				$	3.5		$	-1.4
		______________________________
		(1)As determined by nationally-recognized statistical ratings organizations.
				March 31,			December 31,
				2014			2013
				(in millions)
		Counterparty Credit Quality (1)
		AAA		$	-		$	0.2
		AA			-0.5			-2.1
		A			2			-1.1
		Lower than A			2			1.6
				$	3.5		$	-1.4
		______________________________
		(1)As determined by nationally-recognized statistical ratings organizations.
Schedule Of Credit Concentrations In Industry Sectors	'
	At March 31, 2014 and December 31, 2013, we had credit concentrations in the following industry sectors, as presented below:
				March 31,			December 31,
				2014			2013
				(in millions)
		United States financial institutions and investment banking entities		$	2.3		$	2.4
		Non-United States financial institutions			0.8			0.1
		Integrated oil companies			-0.5			-1.6
		Other			0.9			-2.3
				$	3.5		$	-1.4
Effect Of Derivative Instruments On The Consolidated Statements Of Financial Position	'
	Effect of Derivative Instruments on the Consolidated Statements of Financial Position
						Asset Derivatives						Liability Derivatives
						Fair Value at						Fair Value at
				Financial Position		March 31,			December 31,			March 31,			December 31,
				Location		2014			2013			2014			2013
						(in millions)
	Derivatives designated as
		hedging instruments(1)
	Commodity contracts			Other current assets		$	3.2		$	2		$	-		$	-0.6
	Commodity contracts			Other assets			2.8			3.5			-			-0.5
	Commodity contracts			Accounts payable and other			-			1.9			-10.7			-12.7
	Commodity contracts			Other long-term liabilities			-			0.6			-0.9			-1.4
							6			8			-11.6			-15.2
	Derivatives not designated
		as hedging instruments
	Commodity contracts			Other current assets			21			9			-			-0.1
	Commodity contracts			Other assets			12			10.7			-			-3.4
	Commodity contracts			Accounts payable and other			-			5.4			-17.8			-15.7
	Commodity contracts			Other long-term liabilities			-			-			-6.1			-0.1
							33			25.1			-23.9			-19.3
	Total derivative instruments					$	39		$	33.1		$	-35.5		$	-34.5
	______________________________
	(1)	Includes items currently designated as hedging instruments. Excludes the portion of de-designated hedges which may have a component remaining in AOCI.
Effect Of Derivative Instruments On The Consolidated Statements Of Income And Accumulated Other Comprehensive Income	'
	Effect of Derivative Instruments on the Consolidated Statements of Income and Accumulated Other Comprehensive Income
																Amount of Gain
																(Loss) Recognized in
													Location of Gain			Earnings on
													(Loss) Recognized in			Derivative
													Earnings on Derivative			(Ineffective Portion
				Amount of Gain			Location of Gain (Loss)			Amount of Gain (Loss)			(Ineffective Portion			and Amount
	Derivatives in Cash			(Loss) Recognized in			Reclassified from			Reclassified from			and Amount			Excluded from
	Flow Hedging			AOCI on Derivative			AOCI to Earnings			AOCI to Earnings			Excluded from			Effectiveness
	Relationships			(Effective Portion)			(Effective Portion)			(Effective Portion)			Effectiveness Testing)(1)			Testing)(1)
		(in millions)
	For the three month period ended March 31, 2014
							Cost of natural gas and						Cost of natural gas and
	Commodity contracts			$	-0.1			natural gas liquids		$	-6.5			natural gas liquids		$	1.7
	Total			$	-0.1					$	-6.5					$	1.7
	For the three month period ended March 31, 2013
							Cost of natural gas and						Cost of natural gas and
	Commodity contracts			$	-1.6			natural gas liquids		$	1.5			natural gas liquids		$	0.5
	Total			$	-1.6					$	1.5					$	0.5
	______________________________
	(1)	Includes only the ineffective portion of derivatives that are designated as hedging instruments and does not include net gains or losses associated with derivatives that do not qualify for hedge accounting treatment.
Components Of Accumulated Other Comprehensive Income	'
	Components of Accumulated Other Comprehensive Income/(Loss)
					Cash Flow
					Hedges
					(in millions)
	Balance at December 31, 2013				$	-3.1
		Other Comprehensive Income before reclassifications (1)				-2.4
		Amounts reclassified from AOCI (2) (3)				2.6
		Tax benefit (expense)				0
			Net other comprehensive income (loss)		$	0.2
	Balance at March 31, 2014				$	-2.9
	_______________________________________
	(1)	Excludes NCI loss of $3.7 million reclassified from AOCI at March 31, 2014.
	(2)	Excludes NCI gain of $3.9 million reclassified from AOCI at March 31, 2014.
	(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,
					2014			2013
					(unaudited; in millions)
	Losses (gains) on cash flow hedges:
		Commodity Contracts (1) (2)			$	2.6		$	-1.5
			Total Reclassifications from AOCI		$	2.6		$	-1.5
	______________________________
	(1)Loss (gain) reported within "Cost of natural gas and natural gas liquids" in the consolidated statements of income.
	(2)Excludes NCI gain of $3.9 million reclassified from AOCI at March 31, 2014.
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,
							2014			2013(4)
	Derivatives Not Designated			Location of Gain or (Loss)			Amount of Gain or  (Loss)
	as Hedging Instruments			Recognized in Earnings(1)			Recognized in Earnings(2)
							(unaudited; in millions)
				Cost of natural gas and
	Commodity contracts				natural gas liquids(3)		$	-6.4		$	-2.4
	Commodity contracts			Operating revenue				0.8			-
	Total						$	-5.6		$	-2.4
	________________________
	(1)	Does not include settlements associated with derivative instruments that settle through physical delivery.
	(2)	Includes only net gains or losses associated with those derivatives that do not qualify for hedge accounting treatment and does not include the ineffective portion of derivatives that are designated as hedging instruments.
	(3)	Includes settlements losses of $8.5 million and $0.4 million for the three month periods ended March 31, 2014 and March 31, 2013, respectively.
	(4)	Includes both affiliate and third party transactions.
Offsetting Of Financial Assets And Derivative Assets	'
	Offsetting of Financial Assets and Derivative Assets
					As of March 31, 2014
					Gross Amount of Assets			Amount
					Presented in the			Not Offset in the
					Statement of			Statement of			Net
					Financial Position			Financial Position			Amount
					(unaudited; in millions)
	Description:
		Derivatives			$	39		$	-18.2		$	20.8
			Total		$	39		$	-18.2		$	20.8
Offsetting Of Financial Liabilities And Derivative Liabilities	'
	Offsetting of Financial Liabilities and Derivative Liabilities
					As of March 31, 2014
					Gross Amount of Liabilities			Amount
					Presented in the			Not Offset in the
					Statement of			Statement of			Net
					Financial Position			Financial Position			Amount
					(unaudited; in millions)
	Description:
		Derivatives			$	-35.5		$	18.2		$	-17.3
			Total		$	-35.5		$	18.2		$	-17.3
Table Setting Forth By Level Within The Fair Value Hierarchy Financial Assets And Liabilities	'
	Inputs to Fair Value Derivative Instruments
	The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2014 and December 31, 2013. 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.
	We categorize 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, as Level 2. This category includes both over-the-counter, or 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; (3) volatility factors; and (4) 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.
				31-Mar-14												December 31, 2013
				Level 1			Level 2			Level 3			Total			Level 1			Level 2			Level 3			Total
				(in millions)
	Commodity contracts:
		Financial		$	-		$	-3.9		$	-3.4		$	-7.3		$	-		$	-3.4		$	-6.9		$	-10.3
		Physical			-			-			3.6			3.6			-			-			0.5			0.5
	Commodity options				-			-			7.2			7.2			-			-			8.4			8.4
	Total			$	-		$	-3.9		$	7.4		$	3.5		$	-		$	-3.4		$	2		$	-1.4
Schedule Of Reconciliation Of Changes In Fair Value Of Level 3 Financial Assets And Liabilities	'
	Level 3 Fair Value Reconciliation
	The table below provides a reconciliation of changes in the fair value of our Level 3 financial assets and liabilities measured on a recurring basis from January 1, 2014 to March 31, 2014. 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, 2014				$	-6.9		$	0.5		$	8.4		$	2
		Transfer out of Level 3 (1)				-			-			-			-
	Gains or losses:
		Included in earnings				-5.3			1.7			-1.5			-5.1
		Included in other comprehensive income				-1.1			-			-			-1.1
	Purchases, issuances, sales and settlements:
		Purchases				-			-			0.2			0.2
		Settlements (2)				9.9			1.4			0.1			11.4
	Ending balance as of March 31, 2014				$	-3.4		$	3.6		$	7.2		$	7.4
	Amount of changes in net assets attributable to the change in unrealized
		gains or losses related to assets still held at the reporting date			$	-1.2		$	1.9		$	-1.1		$	-0.4
	Amounts reported in operating revenue				$	-		$	0.8		$	-		$	0.8
	_________________
	(1)	Our policy is to recognize transfers as of the last day of the reporting period.
	(2)	Settlements represent the realized portion of forward contracts.
Schedule Of Fair Values Of Expected Cash Flows Of Outstanding Commodity Based Swaps And Physical Contracts	'
	Fair Value Measurements of Commodity Derivatives
	The following table provides summarized information about the fair values of expected cash flows of our outstanding commodity based swaps and physical contracts at March 31, 2014 and December 31, 2013.
					At March 31, 2014																At December 31, 2013
									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 2014
		Swaps
			Receive variable/pay fixed		Natural Gas		872,000		$	4.43		$	4.28		$	0.1		$	-		$	-		$	-
					NGL		653,750		$	65.16		$	65.99		$	0.9		$	-1.5		$	0.6		$	-0.4
					Crude Oil		70,000		$	100.82		$	100.1		$	0.1		$	-		$	-		$	-
			Receive fixed/pay variable		Natural Gas		2,443,800		$	4		$	4.39		$	-		$	-1		$	0.1		$	-1
					NGL		1,967,500		$	54.5		$	56		$	4.8		$	-7.7		$	4.8		$	-12.7
					Crude Oil		858,250		$	91.82		$	98.09		$	0.2		$	-5.6		$	0.3		$	-5.4
			Receive variable/pay variable		Natural Gas		38,490,000		$	4.38		$	4.38		$	0.6		$	-0.4		$	0.6		$	-0.1
		Physical Contracts
			Receive variable/pay fixed		Natural Gas		5,703,122		$	4.46		$	4.41		$	0.4		$	-0.1		$	-		$	-
					NGL		1,073,640		$	57.57		$	57.25		$	1.2		$	-0.9		$	0.9		$	-0.9
					Crude Oil		243,713		$	99.24		$	99.81		$	0.3		$	-0.4		$	-		$	-
			Receive fixed/pay variable		Natural Gas		23,485,419		$	4.33		$	4.33		$	0.1		$	-0.1		$	-		$	-
					NGL		1,197,064		$	55.26		$	56.68		$	0.1		$	-1.8		$	0.4		$	-2.6
					Crude Oil		333,526		$	99.25		$	100.28		$	0.4		$	-0.7		$	-		$	-0.4
			Receive variable/pay variable		Natural Gas		89,130,497		$	4.41		$	4.4		$	1.8		$	-0.7		$	0.9		$	-0.4
					NGL		8,029,834		$	42.91		$	42.48		$	5.2		$	-1.7		$	5.8		$	-3.7
					Crude Oil		843,189		$	97.13		$	98.03		$	3.4		$	-4.1		$	1.1		$	-1.2
	Portion of contracts maturing in 2015
		Swaps
			Receive fixed/pay variable		Natural Gas		60,000		$	4.52		$	4.51		$	-		$	-		$	-		$	-
					NGL		565,750		$	51.33		$	50.71		$	1.4		$	-1.1		$	1.5		$	-1.1
					Crude Oil		350,400		$	93		$	89.89		$	1.2		$	-0.2		$	1.7		$	-
			Receive variable/pay variable		Natural Gas		10,107,500		$	4.32		$	4.33		$	0.1		$	-0.1		$	0.1		$	-
			Receive variable/pay fixed		Crude Oil		67,500		$	92.58		$	91.1		$	0.1		$	-		$	-		$	-
		Physical Contracts
			Receive fixed/pay variable		Natural Gas		3,158,951		$	4.49		$	4.5		$	-		$	-		$	-		$	-
					NGL		54,760		$	54.21		$	52.91		$	0.1		$	-		$	-		$	-
			Receive variable/pay variable		Natural Gas		46,325,708		$	4.24		$	4.22		$	1.2		$	-0.4		$	0.5		$	-0.1
					NGL		808,001		$	71.16		$	70.79		$	0.4		$	-0.1		$	-		$	-
	Portion of contracts maturing in 2016
		Swaps
			Receive fixed/pay variable		Crude Oil		45,750		$	99.31		$	84.52		$	0.7		$	-		$	0.7		$	-
		Physical Contracts
			Receive variable/pay variable		Natural Gas		31,192,423		$	3.97		$	3.97		$	0.7		$	-0.5		$	0.1		$	-
	Portion of contracts maturing in 2017
		Physical Contracts
			Receive variable/pay variable		Natural Gas		13,425,825		$	4.17		$	4.18		$	0.3		$	-0.4		$	-		$	-
	______________________________
	(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, 2014 and December 31, 2013, 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 gains at December 31, 2013.
	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, 2014 and December 31, 2013.
					At March 31, 2014																At December 31, 2013
									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 2014
		Swaps
			Receive variable/pay fixed		Natural Gas		872,000		$	4.43		$	4.28		$	0.1		$	-		$	-		$	-
					NGL		653,750		$	65.16		$	65.99		$	0.9		$	-1.5		$	0.6		$	-0.4
					Crude Oil		70,000		$	100.82		$	100.1		$	0.1		$	-		$	-		$	-
			Receive fixed/pay variable		Natural Gas		2,443,800		$	4		$	4.39		$	-		$	-1		$	0.1		$	-1
					NGL		1,967,500		$	54.5		$	56		$	4.8		$	-7.7		$	4.8		$	-12.7
					Crude Oil		858,250		$	91.82		$	98.09		$	0.2		$	-5.6		$	0.3		$	-5.4
		Receive variable/pay variable		Natural Gas		38,490,000		$	4.38		$	4.38		$	0.6		$	-0.4		$	0.6		$	-0.1
	Physical Contracts
		Receive variable/pay fixed		Natural Gas		5,703,122		$	4.46		$	4.41		$	0.4		$	-0.1		$	-		$	-
				NGL		1,073,640		$	57.57		$	57.25		$	1.2		$	-0.9		$	0.9		$	-0.9
				Crude Oil		243,713		$	99.24		$	99.81		$	0.3		$	-0.4		$	-		$	-
		Receive fixed/pay variable		Natural Gas		23,485,419		$	4.33		$	4.33		$	0.1		$	-0.1		$	-		$	-
				NGL		1,197,064		$	55.26		$	56.68		$	0.1		$	-1.8		$	0.4		$	-2.6
				Crude Oil		333,526		$	99.25		$	100.28		$	0.4		$	-0.7		$	-		$	-0.4
		Receive variable/pay variable		Natural Gas		89,130,497		$	4.41		$	4.4		$	1.8		$	-0.7		$	0.9		$	-0.4
				NGL		8,029,834		$	42.91		$	42.48		$	5.2		$	-1.7		$	5.8		$	-3.7
				Crude Oil		843,189		$	97.13		$	98.03		$	3.4		$	-4.1		$	1.1		$	-1.2
Portion of contracts maturing in 2015
	Swaps
		Receive fixed/pay variable		Natural Gas		60,000		$	4.52		$	4.51		$	-		$	-		$	-		$	-
				NGL		565,750		$	51.33		$	50.71		$	1.4		$	-1.1		$	1.5		$	-1.1
				Crude Oil		350,400		$	93		$	89.89		$	1.2		$	-0.2		$	1.7		$	-
		Receive variable/pay variable		Natural Gas		10,107,500		$	4.32		$	4.33		$	0.1		$	-0.1		$	0.1		$	-
		Receive variable/pay fixed		Crude Oil		67,500		$	92.58		$	91.1		$	0.1		$	-		$	-		$	-
	Physical Contracts
		Receive fixed/pay variable		Natural Gas		3,158,951		$	4.49		$	4.5		$	-		$	-		$	-		$	-
				NGL		54,760		$	54.21		$	52.91		$	0.1		$	-		$	-		$	-
		Receive variable/pay variable		Natural Gas		46,325,708		$	4.24		$	4.22		$	1.2		$	-0.4		$	0.5		$	-0.1
				NGL		808,001		$	71.16		$	70.79		$	0.4		$	-0.1		$	-		$	-
Portion of contracts maturing in 2016
	Swaps
		Receive fixed/pay variable		Crude Oil		45,750		$	99.31		$	84.52		$	0.7		$	-		$	0.7		$	-
	Physical Contracts
		Receive variable/pay variable		Natural Gas		31,192,423		$	3.97		$	3.97		$	0.7		$	-0.5		$	0.1		$	-
Portion of contracts maturing in 2017
	Physical Contracts
		Receive variable/pay variable		Natural Gas		13,425,825		$	4.17		$	4.18		$	0.3		$	-0.4		$	-		$	-
______________________________
(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, 2014 and December 31, 2013, 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 gains at December 31, 2013.
Schedule Of Fair Values Of Expected Cash Flows Of Outstanding Commodity Options	'
	The following table provides summarized information about the fair values of expected cash flows of our outstanding commodity options at March 31, 2014 and December 31, 2013.
					At March 31, 2014																At December 31, 2013
									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 2014
			Puts (purchased)		Natural Gas		3,300,000		$	3.9		$	4.46		$	0.4		$	-		$	0.7		$	-
					NGL		394,500		$	53.04		$	53.17		$	2.3		$	-		$	2.9		$	-
			Calls (written)		NGL		206,250		$	59.62		$	54.36		$	-		$	-0.6		$	-		$	-1
			Puts (written)		Natural Gas		1,729,000		$	3.9		$	4.49		$	-		$	-0.2		$	-		$	-0.5
			Calls (purchased)		NGL		46,000		$	50.4		$	45.73		$	0.2		$	-		$	-		$	-
	Portion of option contracts maturing in 2015
			Puts (purchased)		Natural Gas		4,015,000		$	3.9		$	4.2		$	1.9		$	-		$	1.7		$	-
					NGL		1,113,250		$	50.64		$	53.31		$	6.1		$	-		$	6		$	-
					Crude Oil		456,250		$	85		$	89.5		$	2.3		$	-		$	1.8		$	-
			Calls (written)		Natural Gas		1,277,500		$	5.05		$	4.2		$	-		$	-0.4		$	-		$	-0.3
					NGL		292,000		$	62.48		$	57.59		$	-		$	-1.6		$	-		$	-1
					Crude Oil		456,250		$	90.7		$	89.5		$	-		$	-3.1		$	-		$	-1.9
	Portion of option contracts maturing in 2016
			Puts (purchased)		Crude Oil		91,500		$	80		$	84.3		$	0.6		$	-		$	-		$	-
			Calls (written)		Crude Oil		91,500		$	87		$	84.3		$	-		$	-0.7		$	-		$	-
	______________________________
	(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, 2014 and December 31, 2013, respectively, discounted using the swap rate for the respective periods to consider the time value of money.
	The following table provides summarized information about the fair values of expected cash flows of our outstanding commodity options at March 31, 2014 and December 31, 2013.
					At March 31, 2014																At December 31, 2013
									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 2014
			Puts (purchased)		Natural Gas		3,300,000		$	3.9		$	4.46		$	0.4		$	-		$	0.7		$	-
					NGL		394,500		$	53.04		$	53.17		$	2.3		$	-		$	2.9		$	-
			Calls (written)		NGL		206,250		$	59.62		$	54.36		$	-		$	-0.6		$	-		$	-1
			Puts (written)		Natural Gas		1,729,000		$	3.9		$	4.49		$	-		$	-0.2		$	-		$	-0.5
			Calls (purchased)		NGL		46,000		$	50.4		$	45.73		$	0.2		$	-		$	-		$	-
	Portion of option contracts maturing in 2015
			Puts (purchased)		Natural Gas		4,015,000		$	3.9		$	4.2		$	1.9		$	-		$	1.7		$	-
					NGL		1,113,250		$	50.64		$	53.31		$	6.1		$	-		$	6		$	-
					Crude Oil		456,250		$	85		$	89.5		$	2.3		$	-		$	1.8		$	-
			Calls (written)		Natural Gas		1,277,500		$	5.05		$	4.2		$	-		$	-0.4		$	-		$	-0.3
					NGL		292,000		$	62.48		$	57.59		$	-		$	-1.6		$	-		$	-1
					Crude Oil		456,250		$	90.7		$	89.5		$	-		$	-3.1		$	-		$	-1.9
	Portion of option contracts maturing in 2016
			Puts (purchased)		Crude Oil		91,500		$	80		$	84.3		$	0.6		$	-		$	-		$	-
			Calls (written)		Crude Oil		91,500		$	87		$	84.3		$	-		$	-0.7		$	-		$	-
	______________________________
	(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, 2014 and December 31, 2013, respectively, discounted using the swap rate for the respective periods to consider the time value of money.
Schedule Of Quantitative Information On Level 3 Fair Value Measurements	'
	Quantitative Information About Level 3 Fair Value Measurements
				Fair Value at							Range (1)
				March 31,			Valuation		Unobservable				Weighted
	Contract Type			2014			Technique		Input		Lowest	Highest	Average	Units
	Commodity Contracts - Financial			(in millions)
		Natural Gas		$	-0.3		Market Approach		Forward Gas Price		3.88	4.68	4.42	MMBtu
		NGLs		$	-3.1		Market Approach		Forward NGL Price		1.01	2.18	1.35	Gal
	Commodity Contracts - Physical
		Natural Gas		$	2.3		Market Approach		Forward Gas Price		3.34	5.17	4.25	MMBtu
		Crude Oil		$	-1.2		Market Approach		Forward Crude Price		87.93	106.27	100.05	Bbl
		NGLs		$	2.5		Market Approach		Forward NGL Price		0.01	2.31	1.11	Gal
	Commodity Options
		Natural Gas, Crude and NGLs		$	7.2		Option Model		Option Volatility		15%	77%	34%
	Total Fair Value			$	7.4
	_______________________________________
	(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.
	Quantitative Information About Level 3 Fair Value Measurements
				Fair Value at							Range(1)
				December 31,			Valuation		Unobservable				Weighted
	Contract Type			2013(2)			Technique		Input		Lowest	Highest	Average	Units
	Commodity Contracts - Financial			(in millions)
		Natural Gas		$	0		Market Approach		Forward Gas Price		3.64	4.41	4.14	MMBtu
		NGLs		$	-6.9		Market Approach		Forward NGL Price		1	2.13	1.38	Gal
	Commodity Contracts - Physical
		Natural Gas		$	1.1		Market Approach		Forward Gas Price		3.36	4.82	4.15	MMBtu
		Crude Oil		$	-0.5		Market Approach		Forward Crude Price		86.37	103.04	97.24	Bbl
		NGLs		$	-0.1		Market Approach		Forward NGL Price		0.02	2.19	0.95	Gal
	Commodity Options
		Natural Gas, Crude and NGLs		$	8.4		Option Model		Option Volatility		18%	44%	28%
	Total Fair Value			$	2
	_______________________________
	(1)	Prices are in dollars per MMBtu for Natural Gas, dollars per Gal for NGLs and dollars per Bbl for Crude Oil.
	(2)	Fair values include credit valuation adjustments of approximately $0.1 million of gains.

Segment_Information_Tables

Segment Information (Tables)	3 Months Ended
	Mar. 31, 2014
Segment Information	'
Schedule Of Segment Reporting Information, By Segment	'
	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, 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 (3)			-1.2		-		-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 (2)		$	4,901.70	$	311.1	$	216.7	$	5,429.50
	Capital expenditures (excluding acquisitions)		$	47.8	$	2.3	$	5.3	$	55.4
	______________________________
	(1)	Corporate consists of income taxes and interest expense, which are not allocated to the business segments.
	(2)	Totals assets for our Gathering, Processing and Transportation segment includes our long-term equity investment in the Texas Express NGL system.
	(3)	Other income (expense) for our Gathering, Processing and Transportation segment includes our equity investment in the Texas Express NGL system which began recognizing operating costs during the fourth quarter of 2013.
			As of and for the three month period ended March 31, 2013
			Gathering, Processing and Transportation		Logistics and Marketing		Corporate (1)		Total
			(in millions)
	Total revenue		$	659.2	$	1,223.00	$	-	$	1,882.20
	Less: Intersegment revenue			487		24.9		-		511.9
	Operating revenue			172.2		1,198.10		-		1,370.30
	Cost of natural gas and natural gas liquids			17.4		1,178.70		-		1,196.10
	Segment gross margin			154.8		19.4		-		174.2
	Operating and maintenance			64.2		19.2		-		83.4
	General and administrative			21.9		2.6		-		24.5
	Depreciation and amortization			33.5		1.7		-		35.2
				119.6		23.5		-		143.1
	Operating income (loss)			35.2		-4.1		-		31.1
	Other income (expense)			-		-		0.1		0.1
	Income (loss) before income tax expense			35.2		-4.1		0.1		31.2
	Income tax expense			-		-		0.5		0.5
	Net income (loss)		$	35.2	$	-4.1	$	-0.4	$	30.7
	Total assets (2)		$	4,533.10	$	843.2	$	237.6	$	5,613.90
	Capital expenditures (excluding acquisitions)		$	66.3	$	4.6	$	-	$	70.9
	______________________________
	(1)	Corporate consists of income taxes, which are not allocated to the business segments.
	(2)	Totals assets for our Gathering, Processing and Transportation segment includes our long-term equity investment in the Texas Express NGL system.

Supplemental_Cash_Flows_Inform1

Supplemental Cash Flows Information (Tables)	3 Months Ended
	Mar. 31, 2014
Supplemental Cash Flows Information	'
Schedule Of Cash Flow Supplemental Disclosures Table Text Block	'
	The following table provides supplemental information for the item labeled “Other" in the “Cash provided by operating activities" section of our consolidated statements of cash flows.
				For the three month
				period ended March 31,
				2014			2013
				(in millions)
		Deferred income taxes		$	0.5		$	-
		Texas Express long-term inventory (line fill)			0.3			-
		Loss on sale of assets			-			1.1
		Allowance for interest used during construction			-			-2.8
		Amortization of hedging			-			-0.2
		Other			0.2			-0.3
				$	1		$	-2.2
	In the “Cash used in investing activities” section of the consolidated statements of cash flows, we exclude changes that did not affect cash. The following is a reconciliation of additions to property, plant and equipment to total capital expenditures (excluding “Investment in joint venture”):
						For the three month
						period ended March 31,
						2014			2013
						(in millions)
		Additions to property, plant and equipment				$	55.5		$	78
			Decrease in construction payables				-0.1			-7.1
		Total capital expenditures (excluding "Investment in joint venture")				$	55.4		$	70.9

Organization_and_Nature_of_Ops

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

3 Months Ended

10 Months Ended

3 Months Ended

12 Months Ended

3 Months Ended

12 Months Ended

In Millions, except Share data, unless otherwise specified

Mar. 31, 2014

Mar. 31, 2013

Nov. 12, 2013

Mar. 31, 2014

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2014

Mar. 31, 2014

Mar. 31, 2013

Mar. 31, 2014

Mar. 31, 2014

Dec. 31, 2014

Dec. 31, 2014

Midcoast Operating, L.P.

Initial Public Offering [Member]

Intial Public Offering Overallotment [Member]

Forecast [Member]

General Partner interests

General Partner interests

Limited partner interests (EEP)

Limited partner interests (EEP)

Midcoast Operating, L.P.

Midcoast Operating, L.P.

Midcoast Operating, L.P.

Forecast [Member]

Forecast [Member]

Maximum [Member]

Minimum [Member]

Ownership in Midcoast Operating

'

'

100.00%

39.00%

'

'

'

'

'

'

61.00%

'

'

Ownership Interest

'

'

'

'

'

'

'

'

'

52.00%

'

'

'

Distributions by Midcoast Operating

$45.10

$60.70

'

'

'

'

'

$0.20

$0

'

'

'

'

Stock Issued, New Issues

'

'

'

'

18,500,000

2,775,000

'

'

'

'

'

'

'

Annual costs on Credit Facility

1.2

'

'

'

'

'

'

'

'

'

'

5

4

Line of Credit Facility, Commitment Fee Percentage

2.50%

'

'

'

'

'

2.50%

'

'

'

'

'

'

Additional G&A Expenses

'

'

'

'

'

'

4

'

'

'

'

'

'

Prior Year Misstatement Corrected In Current Year Financials

$0.90

'

'

'

'

'

'

'

'

'

'

'

'

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, 2014
Minimum Quarterly Distribution [Member]	'
Portion of Quarterly Distribution Per Unit, maximum	$0.31
Percentage Distributed to General Partner	2.00%
Percentage Distributed To Limited Partners	98.00%
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 General Partner	2.00%
Percentage Distributed To Limited Partners	98.00%
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 General Partner	15.00%
Percentage Distributed To Limited Partners	85.00%
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 General Partner	25.00%
Percentage Distributed To Limited Partners	75.00%
Over Third Target Distribution [Member]	'
Portion of Quarterly Distribution Per Unit, minimum	$0.47
Percentage Distributed to General Partner	50.00%
Percentage Distributed To Limited Partners	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, 2014		Mar. 31, 2013
Earnings Per Share [Line Items]	'		'
Net income	$6.70		$30.70
Less: Net income attributable to noncontrolling interest	6.3		0
Net income attributable to general and limited partner ownership interests in Midcoast Energy Partners, L.P.	0.4		30.7
Total distributed earnings	-14.4		'
Total distributed earnings to our limited partners	-14.1		'
Total distributed earnings to our General Partner	-0.3		'
Underdistibuted (Overdistributed) earnings	-14		'
Weighted average limited partner units outstanding (basic)	45.2		26.7
Distributed earnings per limited partner unit	$0.31	[1]	'
Underdistibuted (Overdistributed) earnings per limited partner unit	($0.30)	[2]	'
Net income (loss) per limited partner unit (basic)	$0.01		$0.44
Net income (loss) per limited partner unit (diluted)	$0.01		$0.44
Pro Forma [Member]	'		'
Earnings Per Share [Line Items]	'		'
Net income	'		30.7	[3]
Less: Net income attributable to noncontrolling interest	'		18.7	[3]
Net income attributable to general and limited partner ownership interests in Midcoast Energy Partners, L.P.	'		12	[3]
Total distributed earnings	'		-8.5	[3]
Total distributed earnings to our limited partners	'		-8.4	[3]
Total distributed earnings to our General Partner	'		-0.1	[3]
Underdistibuted (Overdistributed) earnings	'		$3.50	[3]
Weighted average limited partner units outstanding (basic)	'		26.7	[3]
Distributed earnings per limited partner unit	'		$0.31	[1],[3]
Underdistibuted (Overdistributed) earnings per limited partner unit	'		$0.13	[2],[3]
Net income (loss) per limited partner unit (basic)	'		$0.44	[3]
[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 partnersb share (98%)B 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.
[3]	Represents calculation retrospectively reflecting the affiliate capitalization of MEP consisting of 4.1 million MEP Class A common units, 22.6 million MEP subordinated units and MEP general partner interest upon the transfer of a controlling ownership, including limited partner and general partner interest, in Midcoast Operating. The noncontrolling interest reflects the 61% retained by EEP.

Cash_And_Cash_Equivalents_Narr

Cash And Cash Equivalents (Narrative) (Details) (USD $)	Mar. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Cash And Cash Equivalents	'	'
Accounts payable and other	$13.70	$8.80
Bank Overdrafts	'	$49.10

Inventory_Narrative_Details

Inventory (Narrative) (Details) (USD $)	3 Months Ended		12 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013	Dec. 31, 2013
Inventory	'	'	'
Materials and supplies	$0.50	'	$0.60
Crude oil inventory	11.2	'	12.6
Natural gas and NGL inventory	48.6	'	74.8
Inventory, Gross	60.3	'	88
Charges related to cost of natural gas	$1.50	$0.80	$0.80

Property_Plant_And_Equipment_S

Property, Plant And Equipment (Schedule Of Property, Plant and Equipment) (Details) (USD $)	Mar. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Property, Plant and Equipment [Line Items]	'	'
Land	$11.20	$11.60
Rights-of-way	385.5	380
Pipelines	1,765	1,741.90
Pumping equipment, buildings and tanks	79.5	79.2
Compressors, meters and other operating equipment	2,024.60	1,993.20
Vehicles, office furniture and equipment	152.1	148.5
Processing and treating plants	514.6	514.4
Construction in progress	172.5	181.4
Total property, plant and equipment	5,105	5,050.20
Accumulated depreciation	-1,003	-967.9
Property, plant and equipment, net	$4,102	$4,082.30

Debt_Credit_Facility_Details

Debt (Credit Facility) (Details) (USD $)

3 Months Ended

10 Months Ended

12 Months Ended

3 Months Ended

3 Months Ended

3 Months Ended

3 Months Ended

12 Months Ended

12 Months Ended

In Millions, unless otherwise specified

Mar. 31, 2014

Mar. 31, 2013

Nov. 12, 2013

Dec. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Dec. 31, 2014

Dec. 31, 2014

Mar. 31, 2014

Dec. 31, 2014

Dec. 31, 2014

Dec. 31, 2014

Forecast [Member]

Midcoast Operating, L.P.

Senior Revolving Credit Facility [Member]

Senior Revolving Credit Facility [Member]

Senior Revolving Credit Facility [Member]

Senior Revolving Credit Facility [Member]

Senior Revolving Credit Facility [Member]

Senior Revolving Credit Facility [Member]

Senior Revolving Credit Facility [Member]

Senior Revolving Credit Facility [Member]

Senior Revolving Credit Facility [Member]

Letter of Credit [Member]

Swing Line Facility [Member]

Swing Line Facility [Member]

Secured Debt [Member]

Secured Debt [Member]

Secured Debt [Member]

Unsecured Debt [Member]

Financial Standby Letter of Credit [Member]

Financial Standby Letter of Credit [Member]

Financial Standby Letter of Credit [Member]

Working Capital Facility [Member]

Working Capital Facility [Member]

Working Capital Facility [Member]

Working Capital Facility [Member]

Maximum [Member]

Maximum [Member]

Maximum [Member]

Maximum [Member]

Minimum [Member]

Minimum [Member]

Minimum [Member]

Minimum [Member]

Minimum [Member]

Maximum [Member]

Maximum [Member]

Minimum [Member]

Maximum [Member]

Minimum [Member]

Forecast [Member]

LIBOR [Member]

Minimum [Member]

Acquisition [Member]

Base Rate [Member]

Eurocurrency Rate [Member]

Acquisition [Member]

Base Rate [Member]

Eurocurrency Rate [Member]

Acquisition [Member]

Acquisition [Member]

Midcoast Operating, L.P.

Midcoast Operating, L.P.

Forecast [Member]

Midcoast Operating, L.P.

Forecast [Member]

Forecast [Member]

Forecast [Member]

Line of Credit Facility [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Annual costs on Credit Facility

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$1.20

$5

$4

'

'

'

'

Debt Instrument, Basis Spread on Variable Rate

'

'

'

'

'

'

'

'

1.75%

2.75%

'

'

0.75%

1.75%

'

'

'

'

'

'

'

'

'

'

'

'

2.50%

'

Line of Credit Facility, Commitment Fee Percentage

2.50%

'

'

2.50%

'

'

0.50%

'

'

'

0.30%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Line of Credit Facility, Unused Capacity, Fee Perentage

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0.43%

'

'

Debt Instruments [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Line of Credit Facility, Current Borrowing Capacity

'

'

'

'

'

'

'

'

'

'

'

'

'

'

90

75

'

'

'

'

850

'

'

'

'

'

'

'

Line of Credit Facility, Maximum Borrowing Capacity

'

'

'

'

'

1,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

850

700

'

'

250

'

'

'

Total credit available under working capital credit facility

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

250

'

'

'

'

'

'

'

Less: Amounts outstanding under Credit Facilities

-250

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

250

'

'

'

'

'

'

'

Line Of Credit Facility Remaining Borrowing Capacity

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

850

'

'

'

'

'

'

'

Long Term Debt, Other Disclosures [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Total Leverage Ratio

'

'

'

'

'

'

5

5.5

'

'

1

1

'

'

'

'

1

4.25

4.75

1

'

'

'

'

'

'

'

'

Interest Expense Covenant Ratio, Debt Instrument

'

'

'

'

'

'

2.5

'

'

'

1

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Ownership Interest In Affiiate Of Partnership

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

20.00%

'

'

'

20.00%

Ownership in Midcoast Operating

'

'

100.00%

'

39.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt, Weighted Average Interest Rate

'

'

'

'

'

1.90%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Repayments of Lines of Credit

1,810

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Net borrowings (repayments) under Credit Facility

-85

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Proceeds from Lines of Credit

$1,725

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt_Fair_Value_Of_Debt_Obliga

Debt (Fair Value Of Debt Obligations) (Details) (USD $)	Mar. 31, 2014
In Millions, unless otherwise specified
Carrying amount, credit facilities	$250

Partners_Capital_Changes_In_Pa

Partners' Capital (Changes In Partners' Capital Attributable To General And Limited Partners)(Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014		Mar. 31, 2013
Partners Capital Account [Line Items]	'		'
Beginning Balance, value	$4,552.70		'
Net income	0.4		30.7
Distribution to partners	45.1		60.7
Net realized income on changes in fair value of derivative financial instruments reclassified to earnings	6.5		'
Other comprehensive income, net of tax	6.3		0
Ending Balance, value	4,560.80		4,749.60
Capital Unit, Class A [Member]	'		'
Partners Capital Account [Line Items]	'		'
Beginning Balance, value	495.3		0
Net income	0.2		0
Distribution to partners	3.7		0
Ending Balance, value	491.8		0
Subordinated Units [Member]	'		'
Partners Capital Account [Line Items]	'		'
Beginning Balance, value	1,035.10		0
Net income	0.2		0
Distribution to partners	3.8		0
Ending Balance, value	1,031.50		0
General Partner [Member]	'		'
Partners Capital Account [Line Items]	'		'
Beginning Balance, value	42.2		0
Distribution to partners	0.2		0
Ending Balance, value	42		0
Limited Partner [Member]	'		'
Partners Capital Account [Line Items]	'		'
Beginning Balance, value	0		4,707.10
Capital contribution	0		66.1
Net income	0		30.7
Distribution to partners	0		60.7
Ending Balance, value	0		4,743.20
Accumulated Other Comprehensive Income (Loss) [Member]	'		'
Partners Capital Account [Line Items]	'		'
Beginning Balance, value	-3.1		7.1
Net realized income on changes in fair value of derivative financial instruments reclassified to earnings	2.6	[1],[2]	-1.5
Unrealized net income (loss) on derivative financial instruments	-6.3		0.8
Ending Balance, value	-2.9		6.4
Noncontrolling Interest [Member]	'		'
Partners Capital Account [Line Items]	'		'
Beginning Balance, value	2,983.20		0
Capital contribution	46.1		0
Net income	6.3		0
Other comprehensive income, net of tax	0.2		0
Distributions to noncontrolling interest	-37.4		0
Ending Balance, value	$2,998.40		$0
[1]	Excludes NCI gain of $3.9 million reclassified from AOCI at March 31, 2014.
[2]	For additional details on the amounts reclassified from AOCI, reference the Reclassifications from Accumulated Other Comprehensive Income table below.

Partners_Capital_Distribution_

Partners' Capital (Distribution To Partners) (Details) (USD $)	3 Months Ended
In Millions, except Per Share data, unless otherwise specified	Mar. 31, 2014
Distribution Made to Limited Partner, Distributions Paid, Per Unit	$0.17
First Quarter Distribution [Member]	'
Distribution Declaration Date	29-Jan-14
Record Date	7-Feb-14
Distribution Payment Date	14-Feb-14
Distribution Made to Limited Partner, Cash Distributions Paid	$7.70

Related_Party_Transactions_Nar

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

3 Months Ended

3 Months Ended

12 Months Ended

3 Months Ended

12 Months Ended

In Millions, unless otherwise specified

Mar. 31, 2014

Mar. 31, 2013

Dec. 31, 2013

Mar. 31, 2014

Mar. 31, 2013

Mar. 31, 2014

Mar. 31, 2013

Mar. 31, 2014

Dec. 31, 2014

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Affiliate [Member]

Affiliate [Member]

General And Administrative Services Transactions [Member]

General And Administrative Services Transactions [Member]

General And Administrative Services Transactions [Member]

General And Administrative Services Transactions [Member]

Construction Project Work Force Cost Transactions [Member]

Construction Project Work Force Cost Transactions [Member]

Texas Express NGL System [Member]

Texas Express NGL System [Member]

Midcoast Operating, L.P.

Midcoast Operating, L.P.

mi

Equity Method (JV) Investments [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

Ownership Percentage of JV

'

'

'

'

'

'

'

'

'

'

'

35.00%

'

Equity Investment in Joint Venture

$375.70

'

$371.30

'

'

'

'

'

'

'

'

'

$371.30

Miles Of Pipeline

'

'

'

'

'

'

'

'

'

'

'

580

'

Related Party Transaction [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

Total operating, general, and administrative

145.9

143.1

'

52.4

50.8

'

'

'

'

'

'

'

'

Operating and maintenance

81.7

83.4

'

27.1

26.3

'

'

'

'

'

'

'

'

General and administrative

27.2

24.5

'

25.3

24.5

52.4

50.8

'

'

'

'

'

'

Expenses from Transactions with Related Party

'

'

'

'

'

'

'

'

'

0.9

6.8

'

'

Revenue From Related Parties

57.2

58.6

'

'

'

'

'

'

'

'

'

'

'

Cost of natural gas and natural gas liquids

1,488.70

1,196.10

'

30.2

38.1

'

'

'

'

'

'

'

'

General and Administrative Services, Reduction

'

'

'

'

'

'

'

$6.40

$25

'

'

'

'

Related_Party_Transactions_Joi

Related Party Transactions (Joint Funding Arrangement Discussions) (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Less: Net income attributable to noncontrolling interest	$6.30	$0
Other Commitments [Line Items]	'	'
Transportation Commitments	120,000	'
Logistics and Marketing [Member]	'	'
Less: Net income attributable to noncontrolling interest	$0	'

Related_Party_Transactions_Int

Related Party Transactions (Interest) (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Interest Expense [Abstract]	'	'
Interest cost paid	'	$5.60
Interest expense, net	3.3	0
Interest cost incurred	'	5.6
Interest capitalized	'	$5.60

Related_Party_Sale_of_AR_Detai

Related Party (Sale of AR) (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Receivables	'	'
Gain (Loss) on Sale of Accounts Receivable	($0.30)	'
Statement [Line Items]	'	'
Proceeds from Sale of Receivables	976	'
Restricted Cash	14	61.5
AR Sales, Max Amount Outstanding	450	'
Accrued Receivable [Member]	'	'
Statement [Line Items]	'	'
Net value of Recivables sold	976.3	'
Sold Receivables that have not been collected at the balance sheet date.	$322.40	'

Related_Party_Partners_Capital

Related Party (Partners' Capital Transactions) (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Related Party Transaction [Line Items]	'	'
Distributions by Midcoast Operating	$45.10	$60.70
Midcoast Energy Partners | Enbridge Energy Partners [Member]	'	'
Related Party Transaction [Line Items]	'	'
Distribution Made to Limited Partner, Cash Distributions Paid	4.1	'
Midcoast Operating, L.P. | Enbridge Energy Partners [Member]	'	'
Related Party Transaction [Line Items]	'	'
Distributions by Midcoast Operating	37.4	'
Midcoast Operating, L.P. | Enbridge Energy Partners [Member] | Transaction Period Before IPO [Member]	'	'
Related Party Transaction [Line Items]	'	'
Distributions by Midcoast Operating	22.3	'
Midcoast Operating, L.P. | Enbridge Energy Partners [Member] | Transaction Period After IPO [Member]	'	'
Related Party Transaction [Line Items]	'	'
Distributions by Midcoast Operating	$15.10	'

Derivative_Financial_Instrumen2

Derivative Financial Instruments And Hedging Activities (Narrative) (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Derivative Financial Instruments And Hedging Activities	'	'
Unrecognized losses of derivative financial instruments that were classified as cash flow hedges	$0.30	'
De-designated unrealized commodity hedge gains and losses	0.1	'
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months	8.2	'
Net asset (liability) position	$3.50	($1.40)

Derivative_Financial_Instrumen3

Derivative Financial Instruments And Hedging Activities (Net Unrealized Gains And Losses Associated To Changes In Fair Value) (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Derivative fair value net gains (losses)	$4.60	($1.50)

Derivative_Financial_Instrumen4

Derivative Financial Instruments And Hedging Activities (Derivative Instruments In Statement Of Financial Position, Fair Value) (Details) (USD $)	Mar. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Derivative Financial Instruments And Hedging Activities	'	'
Other current assets	$24.20	$10.30
Other assets, net	14.8	10.3
Accounts payable and other	-28.5	-21.1
Other long-term liabilities	-7	-0.9
Net asset (liability) position	$3.50	($1.40)

Derivative_Financial_Instrumen5

Derivative Financial Instruments And Hedging Activities (Derivative Balances By Counterparty Credit Quality) (Details) (USD $)	3 Months Ended		12 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014		Dec. 31, 2013
AAA Rating [Member]	'		'
Derivative balance by counterparty credit quality	$0	[1]	$0.20	[1]
AA Rating [Member]	'		'
Derivative balance by counterparty credit quality	-0.5	[1]	-2.1	[1]
Less Than AA Rating [Member]	'		'
Derivative balance by counterparty credit quality	2	[1]	-1.1	[1]
Two Lower Than AA Rating [Member]	'		'
Derivative balance by counterparty credit quality	$2	[1]	$1.60	[1]
[1]	As determined by nationally-recognized statistical ratings organizations.

Derivative_Financial_Instrumen6

Derivative Financial Instruments And Hedging Activities (Credit Concentrations In Industry Sectors) (Details) (USD $)	Mar. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Net Total	$3.50	($1.40)
United States Financial Institutions And Investment Banking Entities [Member]	'	'
Credit concentrations	2.3	2.4
Non United States Financial Institutions [Member]	'	'
Credit concentrations	0.8	0.1
Integrated Oil Companies [Member]	'	'
Credit concentrations	-0.5	-1.6
Other [Member]	'	'
Credit concentrations	$0.90	($2.30)

Derivative_Financial_Instrumen7

Derivative Financial Instruments And Hedging Activities (Effect Of Derivative Instruments On Consolidated Statements Of Financial Positions) (Details) (USD $)	Mar. 31, 2014		Dec. 31, 2013
In Millions, unless otherwise specified
Total Liability at Fair Value Without Cash Collateral	($35.50)		($34.50)
Derivatives Designated As Hedging Instruments [Member]	'		'
Assets at Fair Value	6	[1]	8	[1]
Liability at Fair Value	-11.6	[1]	-15.2	[1]
Derivatives Designated As Hedging Instruments [Member] | Other Current Assets [Member] | Commodity Contract [Member]	'		'
Assets at Fair Value	3.2	[1]	2	[1]
Liability at Fair Value	0	[1]	-0.6	[1]
Derivatives Designated As Hedging Instruments [Member] | Other assets, net | Commodity Contract [Member]	'		'
Assets at Fair Value	2.8	[1]	3.5	[1]
Liability at Fair Value	0	[1]	-0.5	[1]
Derivatives Designated As Hedging Instruments [Member] | Accounts Payable And Other [Member] | Commodity Contract [Member]	'		'
Assets at Fair Value	0	[1]	1.9	[1]
Liability at Fair Value	-10.7	[1]	-12.7	[1]
Derivatives Designated As Hedging Instruments [Member] | Other Long-Term Liabilities [Member] | Commodity Contract [Member]	'		'
Assets at Fair Value	0	[1]	0.6	[1]
Liability at Fair Value	-0.9	[1]	-1.4	[1]
Derivatives Not Designated As Hedging Instruments [Member]	'		'
Assets at Fair Value	33		25.1
Liability at Fair Value	-23.9		-19.3
Derivatives Not Designated As Hedging Instruments [Member] | Other Current Assets [Member] | Commodity Contract [Member]	'		'
Assets at Fair Value	21		9
Liability at Fair Value	0		-0.1
Derivatives Not Designated As Hedging Instruments [Member] | Other assets, net | Commodity Contract [Member]	'		'
Assets at Fair Value	12		10.7
Liability at Fair Value	0		-3.4
Derivatives Not Designated As Hedging Instruments [Member] | Accounts Payable And Other [Member] | Commodity Contract [Member]	'		'
Assets at Fair Value	0		5.4
Liability at Fair Value	-17.8		-15.7
Derivatives Not Designated As Hedging Instruments [Member] | Other Long-Term Liabilities [Member] | Commodity Contract [Member]	'		'
Assets at Fair Value	0		0
Liability at Fair Value	($6.10)		($0.10)
[1]	Includes items currently designated as hedging instruments. Excludes the portion of de-designated hedges which may have a component remaining in AOCI.

Derivative_Financial_Instrumen8

Derivative Financial Instruments And Hedging Activities (Effect Of Derivative Instruments On Consolidated Statements Of Income And AOCI) (Details) (Derivatives in Cash Flow Hedging Relationships [Member], USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014		Mar. 31, 2013
Recognized In AOCI Effective Portion [Member]	'		'
Amount of gain (loss) recognized in AOCI on Derivative (Effective Portion)	($0.10)		($1.60)
Recognized In AOCI Effective Portion [Member] | Commodity Contract [Member]	'		'
Amount of gain (loss) recognized in AOCI on Derivative (Effective Portion)	-0.1		-1.6
Reclassified From AOCI To Earnings, Effective Portion [Member]	'		'
Amount of gain (loss) reclassified from AOCI to earnings (Effective Portion)	-6.5		1.5
Reclassified From AOCI To Earnings, Effective Portion [Member] | Cost of natural gas and natural gas liquids [Member] | Commodity Contract [Member]	'		'
Amount of gain (loss) reclassified from AOCI to earnings (Effective Portion)	-6.5		1.5
Recognized In Earnings On Derivative, Ineffective Portion And Amount Excluded From Effectiveness Testing [Member]	'		'
Amount of gain (loss) recognized in earnings on derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)	1.7	[1]	0.5	[1]
Recognized In Earnings On Derivative, Ineffective Portion And Amount Excluded From Effectiveness Testing [Member] | Cost of natural gas and natural gas liquids [Member] | Commodity Contract [Member]	'		'
Amount of gain (loss) recognized in earnings on derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)	$1.70	[1]	$0.50	[1]
[1]	Includes only the ineffective portion of derivatives that are designated as hedging instruments and does not include net gains or losses associated with derivatives that do not qualify for hedge accounting treatment.

Derivative_Financial_Instrumen9

Derivative Financial Instruments And Hedging Activities (Components Of Accumulated Other Comprehensive Income) (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014		Mar. 31, 2013
Derivative Financial Instruments And Hedging Activities	'		'
Beginning balance	($3.10)		'
Other comprehensive income (loss) before reclassifications	-2.4	[1]	'
Amounts reclassified from AOCI	6.5		'
Tax benefit (expense)	0		0
Net other comprehensive income (loss)	0.2		-0.7
Ending balance	($2.90)		'
[1]	Excludes NCI loss of $3.7 million reclassified from AOCI at March 31, 2014.

Recovered_Sheet1

Derivative Financial Instruments And Hedging Activities (Reclassifications From Accumulated Other Comprehensive Income) (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014		Mar. 31, 2013
Cost of natural gas and natural gas liquids	$1,488.70		$1,196.10
Interest Expense	3.3		0
Cash Flow Hedge [Member] | Commodity Contract [Member] | Reclassification out of AOCI [Member]	'		'
Cost of natural gas and natural gas liquids	$2.60	[1],[2]	($1.50)	[1]
[1]	Loss (gain) reported within "Cost of natural gas and natural gas liquids" in the consolidated statements of income.
[2]	Excludes NCI gain of $3.9 million reclassified from AOCI at March 31, 2014.

Recovered_Sheet2

Derivative Financial Instruments And Hedging Activities (Effect Of Derivative Instruments On Consolidated Statements Of Income) (Details) (Derivatives Not Designated As Hedging Instruments [Member], USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014		Mar. 31, 2013
Amount of Gain or (Loss) Recognized in Earnings	($5.60)	[1],[2]	($2.40)	[1],[2],[3]
Operating revenue [Member] | Location Of Gain Or Loss Recognized In Earnings [Member] | Commodity Contract [Member]	'		'
Amount of Gain or (Loss) Recognized in Earnings	0.8	[1],[2]	0	[1],[2],[3]
Cost of natural gas and natural gas liquids [Member] | Location Of Gain Or Loss Recognized In Earnings [Member] | Commodity Contract [Member]	'		'
Amount of Gain or (Loss) Recognized in Earnings	-6.4	[1],[2],[4]	-2.4	[1],[2],[3],[4]
Gain (Loss) on Settlement of Derivative Instruments	($8.50)		($0.40)
[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 both affiliate and third party transactions.
[4]	Includes settlements losses of $8.5 million and $0.4 million for the three month periods ended March 31, 2014 and March 31, 2013, respectively.

Recovered_Sheet3

Derivative Financial Instruments And Hedging Activities (Gross To Net Presentation Reconciliation Of Derivative Assets And Liabilities) (Details) (USD $)	Mar. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Net Total	$3.50	($1.40)
Fair Value Of Derivatives Net Presentation [Member]	'	'
Gross Derivative assets	39	'
Gross Derivative Liabilitites	($35.50)	'

Recovered_Sheet4

Derivative Financial Instruments And Hedging Activities (Offsetting Of Financial Assets And Derivative Assets) (Details) (USD $)	Mar. 31, 2014
In Millions, unless otherwise specified
Fair Value Of Derivatives Net Presentation [Member]	'
Gross Derivative assets	$39
Fair Value of Derivative Assets Net of Non Offset Amounts [Member]	'
Derivative, Fair Value, Net	20.8
Other Assets	'
Gross Amount Not Offset in the Statement of Financial Position	($18.20)

Recovered_Sheet5

Derivative Financial Instruments And Hedging Activities (Offsetting Of Financial Liabilities And Derivative Liabilities) (Details) (USD $)	Mar. 31, 2014
In Millions, unless otherwise specified
Fair Value Of Derivatives Net Presentation [Member]	'
Gross Derivative Liabilitites	($35.50)
Other Liabilities [Member]	'
Amount Not Offset in the Statement of Financial Position	18.2
Fair Value Of Derivative Liabilities Net Of Non Offset Amounts Member [Member]	'
Derivative, Fair Value, Net	($17.30)

Recovered_Sheet6

Derivative Financial Instruments And Hedging Activities (Level With In The Fair Value Hierarchy Financial Assets And Liabilities) (Details) (USD $)	Mar. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Assets and liabilities accounted for at fair value on a recurring basis	$3.50	($1.40)
Commodity Contracts-Financial [Member]	'	'
Assets and liabilities accounted for at fair value on a recurring basis	-7.3	-10.3
Commodity Contracts-Physical [Member]	'	'
Assets and liabilities accounted for at fair value on a recurring basis	3.6	0.5
Commodity Options [Member]	'	'
Assets and liabilities accounted for at fair value on a recurring basis	7.2	8.4
Level 2 [Member]	'	'
Assets and liabilities accounted for at fair value on a recurring basis	-3.9	-3.4
Level 2 [Member] | Commodity Contracts-Financial [Member]	'	'
Assets and liabilities accounted for at fair value on a recurring basis	-3.9	-3.4
Level 2 [Member] | Commodity Contracts-Physical [Member]	'	'
Assets and liabilities accounted for at fair value on a recurring basis	0	0
Level 2 [Member] | Commodity Options [Member]	'	'
Assets and liabilities accounted for at fair value on a recurring basis	0	0
Level 3 [Member]	'	'
Assets and liabilities accounted for at fair value on a recurring basis	7.4	2
Level 3 [Member] | Commodity Contracts-Financial [Member]	'	'
Assets and liabilities accounted for at fair value on a recurring basis	-3.4	-6.9
Level 3 [Member] | Commodity Contracts-Physical [Member]	'	'
Assets and liabilities accounted for at fair value on a recurring basis	3.6	0.5
Level 3 [Member] | Commodity Options [Member]	'	'
Assets and liabilities accounted for at fair value on a recurring basis	$7.20	$8.40

Recovered_Sheet7

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, 2014		Dec. 31, 2013
Assets and liabilities accounted for at fair value on a recurring basis	$3.50		($1.40)
Level 3 [Member]	'		'
Assets and liabilities accounted for at fair value on a recurring basis	7.4		2
Credit valuation adjustments	0		0.1
Level 3 [Member] | Commodity Contracts-Financial [Member] | Market Approach [Member] | Forward Gas Price [Member] | Natural Gas [Member]	'		'
Assets and liabilities accounted for at fair value on a recurring basis	-0.3		0	[1]
Level 3 [Member] | Commodity Contracts-Financial [Member] | Market Approach [Member] | Forward Gas Price [Member] | Minimum [Member] | Natural Gas [Member]	'		'
Market Price	3.88	[2]	3.64	[3]
Level 3 [Member] | Commodity Contracts-Financial [Member] | Market Approach [Member] | Forward Gas Price [Member] | Maximum [Member] | Natural Gas [Member]	'		'
Market Price	4.68	[2]	4.41	[3]
Level 3 [Member] | Commodity Contracts-Financial [Member] | Market Approach [Member] | Forward Gas Price [Member] | Weighted Average [Member] | Natural Gas [Member]	'		'
Weighted Average	4.42	[2]	4.14	[3]
Level 3 [Member] | Commodity Contracts-Financial [Member] | Market Approach [Member] | Forward Ngl Price [Member] | NGLs [Member]	'		'
Assets and liabilities accounted for at fair value on a recurring basis	-3.1		-6.9	[1]
Level 3 [Member] | Commodity Contracts-Financial [Member] | Market Approach [Member] | Forward Ngl Price [Member] | Minimum [Member] | NGLs [Member]	'		'
Market Price	1.01	[2]	1	[3]
Level 3 [Member] | Commodity Contracts-Financial [Member] | Market Approach [Member] | Forward Ngl Price [Member] | Maximum [Member] | NGLs [Member]	'		'
Market Price	2.18	[2]	2.13	[3]
Level 3 [Member] | Commodity Contracts-Financial [Member] | Market Approach [Member] | Forward Ngl Price [Member] | Weighted Average [Member] | NGLs [Member]	'		'
Weighted Average	1.35	[2]	1.38	[3]
Level 3 [Member] | Commodity Contracts-Physical [Member] | Market Approach [Member] | Forward Gas Price [Member] | Natural Gas [Member]	'		'
Assets and liabilities accounted for at fair value on a recurring basis	2.3		1.1	[1]
Level 3 [Member] | Commodity Contracts-Physical [Member] | Market Approach [Member] | Forward Gas Price [Member] | Minimum [Member] | Natural Gas [Member]	'		'
Market Price	3.34	[2]	3.36	[3]
Level 3 [Member] | Commodity Contracts-Physical [Member] | Market Approach [Member] | Forward Gas Price [Member] | Maximum [Member] | Natural Gas [Member]	'		'
Market Price	5.17	[2]	4.82	[3]
Level 3 [Member] | Commodity Contracts-Physical [Member] | Market Approach [Member] | Forward Gas Price [Member] | Weighted Average [Member] | Natural Gas [Member]	'		'
Weighted Average	4.25	[2]	4.15	[3]
Level 3 [Member] | Commodity Contracts-Physical [Member] | Market Approach [Member] | Forward Crude Oil Price [Member] | Crude Oil [Member]	'		'
Assets and liabilities accounted for at fair value on a recurring basis	-1.2		-0.5	[1]
Level 3 [Member] | Commodity Contracts-Physical [Member] | Market Approach [Member] | Forward Crude Oil Price [Member] | Minimum [Member] | Crude Oil [Member]	'		'
Market Price	87.93	[2]	86.37	[3]
Level 3 [Member] | Commodity Contracts-Physical [Member] | Market Approach [Member] | Forward Crude Oil Price [Member] | Maximum [Member] | Crude Oil [Member]	'		'
Market Price	106.27	[2]	103.04	[3]
Level 3 [Member] | Commodity Contracts-Physical [Member] | Market Approach [Member] | Forward Crude Oil Price [Member] | Weighted Average [Member] | Crude Oil [Member]	'		'
Weighted Average	100.05	[2]	97.24	[3]
Level 3 [Member] | Commodity Contracts-Physical [Member] | Market Approach [Member] | Forward Ngl Price [Member] | NGLs [Member]	'		'
Assets and liabilities accounted for at fair value on a recurring basis	2.5		-0.1	[1]
Level 3 [Member] | Commodity Contracts-Physical [Member] | Market Approach [Member] | Forward Ngl Price [Member] | Minimum [Member] | NGLs [Member]	'		'
Market Price	0.01	[2]	0.02	[3]
Level 3 [Member] | Commodity Contracts-Physical [Member] | Market Approach [Member] | Forward Ngl Price [Member] | Maximum [Member] | NGLs [Member]	'		'
Market Price	2.31	[2]	2.19	[3]
Level 3 [Member] | Commodity Contracts-Physical [Member] | Market Approach [Member] | Forward Ngl Price [Member] | Weighted Average [Member] | NGLs [Member]	'		'
Weighted Average	1.11	[2]	0.95	[3]
Level 3 [Member] | Commodity Options [Member] | Option Model [Member] | Option Volatility [Member] | Natural Gas Crude Oil And Ngls [Member]	'		'
Assets and liabilities accounted for at fair value on a recurring basis	$7.20		$8.40	[1]
Level 3 [Member] | Commodity Options [Member] | Option Model [Member] | Option Volatility [Member] | Minimum [Member] | Natural Gas Crude Oil And Ngls [Member]	'		'
Option Volatility	15.00%		18.00%
Level 3 [Member] | Commodity Options [Member] | Option Model [Member] | Option Volatility [Member] | Maximum [Member] | Natural Gas Crude Oil And Ngls [Member]	'		'
Option Volatility	77.00%		44.00%
Level 3 [Member] | Commodity Options [Member] | Option Model [Member] | Option Volatility [Member] | Weighted Average [Member] | Natural Gas Crude Oil And Ngls [Member]	'		'
Option Volatility	34.00%		28.00%
[1]	Fair values include credit valuation adjustments of approximately $0.1 million of gains.
[2]	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.
[3]	Prices are in dollars per MMBtu for Natural Gas, dollars per Gal for NGLs and dollars per Bbl for Crude Oil.

Recovered_Sheet8

Derivative Financial Instruments And Hedging Activities (Reconciliation Of Changes In Fair Value Of L3 Assets And Liabilities On Recurring Basis) (Details) (Level 3 [Member], USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014
Beginning balance	$2
Transfer out of Level 3	0	[1]
Gains or losses included in earnings	-5.1
Gains or losses included in other comprehensive income	-1.1
Purchases	0.2
Settlements	11.4	[2]
Ending balance	7.4
Amount of changes in net assets attributable to the change in unrealized gains or losses related to assets still held at the reporting date	-0.4
Amounts reported in operating revenue	0.8
Commodity Contracts-Financial [Member]	'
Beginning balance	-6.9
Transfer out of Level 3	0	[1]
Gains or losses included in earnings	-5.3
Gains or losses included in other comprehensive income	-1.1
Purchases	0
Settlements	9.9	[2]
Ending balance	-3.4
Amount of changes in net assets attributable to the change in unrealized gains or losses related to assets still held at the reporting date	-1.2
Amounts reported in operating revenue	0
Commodity Contracts-Physical [Member]	'
Beginning balance	0.5
Transfer out of Level 3	0	[1]
Gains or losses included in earnings	1.7
Gains or losses included in other comprehensive income	0
Purchases	0
Settlements	1.4	[2]
Ending balance	3.6
Amount of changes in net assets attributable to the change in unrealized gains or losses related to assets still held at the reporting date	1.9
Amounts reported in operating revenue	0.8
Commodity Options [Member]	'
Beginning balance	8.4
Transfer out of Level 3	0	[1]
Gains or losses included in earnings	-1.5
Gains or losses included in other comprehensive income	0
Purchases	0.2
Settlements	0.1	[2]
Ending balance	7.2
Amount of changes in net assets attributable to the change in unrealized gains or losses related to assets still held at the reporting date	-1.1
Amounts reported in operating revenue	$0
[1]	Our policy is to recognize transfers as of the last day of the reporting period.
[2]	Settlements represent the realized portion of forward contracts.

Recovered_Sheet9

Derivative Financial Instruments And Hedging Activities (Fair Values Of Expected Cash Flows, Outstanding Commodity Based Swaps And Physical Contracts) (Details) (Commodity [Member], USD $)	3 Months Ended		12 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014		Dec. 31, 2013
Credit Valuation Adjustments	$0		$0
Swaps [Member]	'		'
Credit Valuation Adjustments	0		0.1
Natural Gas [Member] | Receive Variable Pay Fixed [Member] | Portion Of Contracts Maturing In 2014 | Swaps [Member]	'		'
Notional	872,000	[1]	'
Assets at Fair Value	0.1	[2]	0	[2]
Liability at Fair Value	0	[2]	0	[2]
Natural Gas [Member] | Receive Variable Pay Fixed [Member] | Portion Of Contracts Maturing In 2014 | Physical Contracts [Member]	'		'
Notional	5,703,122	[1]	'
Assets at Fair Value	0.4	[2]	0	[2]
Liability at Fair Value	-0.1	[2]	0	[2]
Natural Gas [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2014 | Swaps [Member]	'		'
Notional	2,443,800	[1]	'
Assets at Fair Value	0	[2]	0.1	[2]
Liability at Fair Value	-1	[2]	-1	[2]
Natural Gas [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2014 | Physical Contracts [Member]	'		'
Notional	23,485,419	[1]	'
Assets at Fair Value	0.1	[2]	0	[2]
Liability at Fair Value	-0.1	[2]	0	[2]
Natural Gas [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2015 | Swaps [Member]	'		'
Notional	60,000	[1]	'
Assets at Fair Value	0	[2]	0	[2]
Liability at Fair Value	0	[2]	0	[2]
Natural Gas [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2015 | Physical Contracts [Member]	'		'
Notional	3,158,951	[1]	'
Assets at Fair Value	0	[2]	0	[2]
Liability at Fair Value	0	[2]	0	[2]
Natural Gas [Member] | Receive Variable Pay Variable [Member] | Portion Of Contracts Maturing In 2014 | Swaps [Member]	'		'
Notional	38,490,000	[1]	'
Assets at Fair Value	0.6	[2]	0.6	[2]
Liability at Fair Value	-0.4	[2]	-0.1	[2]
Natural Gas [Member] | Receive Variable Pay Variable [Member] | Portion Of Contracts Maturing In 2014 | Physical Contracts [Member]	'		'
Notional	89,130,497	[1]	'
Assets at Fair Value	1.8	[2]	0.9	[2]
Liability at Fair Value	-0.7	[2]	-0.4	[2]
Natural Gas [Member] | Receive Variable Pay Variable [Member] | Portion Of Contracts Maturing In 2015 | Swaps [Member]	'		'
Notional	10,107,500	[1]	'
Assets at Fair Value	0.1	[2]	0.1	[2]
Liability at Fair Value	-0.1	[2]	0	[2]
Natural Gas [Member] | Receive Variable Pay Variable [Member] | Portion Of Contracts Maturing In 2015 | Physical Contracts [Member]	'		'
Notional	46,325,708	[1]	'
Assets at Fair Value	1.2	[2]	0.5	[2]
Liability at Fair Value	-0.4	[2]	-0.1	[2]
Natural Gas [Member] | Receive Variable Pay Variable [Member] | Portion Of Contracts Maturing In 2016 | Physical Contracts [Member]	'		'
Notional	31,192,423	[1]	'
Assets at Fair Value	0.7	[2]	0.1	[2]
Liability at Fair Value	-0.5	[2]	0	[2]
Natural Gas [Member] | Receive Variable Pay Variable [Member] | Portion Of Contracts Maturing In 2017 | Physical Contracts [Member]	'		'
Notional	13,425,825	[1]	'
Assets at Fair Value	0.3	[2]	0	[2]
Liability at Fair Value	-0.4	[2]	0	[2]
NGLs [Member] | Receive Variable Pay Fixed [Member] | Portion Of Contracts Maturing In 2014 | Swaps [Member]	'		'
Notional	653,750	[1]	'
Assets at Fair Value	0.9	[2]	0.6	[2]
Liability at Fair Value	-1.5	[2]	-0.4	[2]
NGLs [Member] | Receive Variable Pay Fixed [Member] | Portion Of Contracts Maturing In 2014 | Physical Contracts [Member]	'		'
Notional	1,073,640	[1]	'
Assets at Fair Value	1.2	[2]	0.9	[2]
Liability at Fair Value	-0.9	[2]	-0.9	[2]
NGLs [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2014 | Swaps [Member]	'		'
Notional	1,967,500	[1]	'
Assets at Fair Value	4.8	[2]	4.8	[2]
Liability at Fair Value	-7.7	[2]	-12.7	[2]
NGLs [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2014 | Physical Contracts [Member]	'		'
Notional	1,197,064	[1]	'
Assets at Fair Value	0.1	[2]	0.4	[2]
Liability at Fair Value	-1.8	[2]	-2.6	[2]
NGLs [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2015 | Swaps [Member]	'		'
Notional	565,750	[1]	'
Assets at Fair Value	1.4	[2]	1.5	[2]
Liability at Fair Value	-1.1	[2]	-1.1	[2]
NGLs [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2015 | Physical Contracts [Member]	'		'
Notional	54,760	[1]	'
Assets at Fair Value	0.1	[2]	0	[2]
Liability at Fair Value	0	[2]	0	[2]
NGLs [Member] | Receive Variable Pay Variable [Member] | Portion Of Contracts Maturing In 2014 | Physical Contracts [Member]	'		'
Notional	8,029,834	[1]	'
Assets at Fair Value	5.2	[2]	5.8	[2]
Liability at Fair Value	-1.7	[2]	-3.7	[2]
NGLs [Member] | Receive Variable Pay Variable [Member] | Portion Of Contracts Maturing In 2015 | Physical Contracts [Member]	'		'
Notional	808,001	[1]	'
Assets at Fair Value	0.4	[2]	0	[2]
Liability at Fair Value	-0.1	[2]	0	[2]
Liquids [Member] | Receive Variable Pay Fixed [Member] | Portion Of Contracts Maturing In 2014 | Swaps [Member]	'		'
Notional	70,000	[1]	'
Assets at Fair Value	0.1	[2]	0	[2]
Liability at Fair Value	0	[2]	0	[2]
Liquids [Member] | Receive Variable Pay Fixed [Member] | Portion Of Contracts Maturing In 2014 | Physical Contracts [Member]	'		'
Notional	243,713	[1]	'
Assets at Fair Value	0.3	[2]	0	[2]
Liability at Fair Value	-0.4	[2]	0	[2]
Liquids [Member] | Receive Variable Pay Fixed [Member] | Portion Of Contracts Maturing In 2015 | Swaps [Member]	'		'
Notional	67,500	[1]	'
Assets at Fair Value	0.1	[2]	0	[2]
Liability at Fair Value	0	[2]	0	[2]
Liquids [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2014 | Swaps [Member]	'		'
Notional	858,250	[1]	'
Assets at Fair Value	0.2	[2]	0.3	[2]
Liability at Fair Value	-5.6	[2]	-5.4	[2]
Liquids [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2014 | Physical Contracts [Member]	'		'
Notional	333,526	[1]	'
Assets at Fair Value	0.4	[2]	0	[2]
Liability at Fair Value	-0.7	[2]	-0.4	[2]
Liquids [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2015 | Swaps [Member]	'		'
Notional	350,400	[1]	'
Assets at Fair Value	1.2	[2]	1.7	[2]
Liability at Fair Value	-0.2	[2]	0	[2]
Liquids [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2016 | Swaps [Member]	'		'
Notional	45,750	[1]	'
Assets at Fair Value	0.7	[2]	0.7	[2]
Liability at Fair Value	0	[2]	0	[2]
Liquids [Member] | Receive Variable Pay Variable [Member] | Portion Of Contracts Maturing In 2014 | Physical Contracts [Member]	'		'
Notional	843,189	[1]	'
Assets at Fair Value	3.4	[2]	1.1	[2]
Liability at Fair Value	($4.10)	[2]	($1.20)	[2]
Receive | Natural Gas [Member] | Receive Variable Pay Fixed [Member] | Portion Of Contracts Maturing In 2014 | Swaps [Member]	'		'
Average variable price	4.43	[3]	'
Receive | Natural Gas [Member] | Receive Variable Pay Fixed [Member] | Portion Of Contracts Maturing In 2014 | Physical Contracts [Member]	'		'
Average variable price	4.46	[3]	'
Receive | Natural Gas [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2014 | Swaps [Member]	'		'
Average fixed price	4	[3]	'
Receive | Natural Gas [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2014 | Physical Contracts [Member]	'		'
Average fixed price	4.33	[3]	'
Receive | Natural Gas [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2015 | Swaps [Member]	'		'
Average fixed price	4.52	[3]	'
Receive | Natural Gas [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2015 | Physical Contracts [Member]	'		'
Average fixed price	4.49	[3]	'
Receive | Natural Gas [Member] | Receive Variable Pay Variable [Member] | Portion Of Contracts Maturing In 2014 | Swaps [Member]	'		'
Average variable price	4.38	[3]	'
Receive | Natural Gas [Member] | Receive Variable Pay Variable [Member] | Portion Of Contracts Maturing In 2014 | Physical Contracts [Member]	'		'
Average variable price	4.41	[3]	'
Receive | Natural Gas [Member] | Receive Variable Pay Variable [Member] | Portion Of Contracts Maturing In 2015 | Swaps [Member]	'		'
Average variable price	4.32	[3]	'
Receive | Natural Gas [Member] | Receive Variable Pay Variable [Member] | Portion Of Contracts Maturing In 2015 | Physical Contracts [Member]	'		'
Average variable price	4.24	[3]	'
Receive | Natural Gas [Member] | Receive Variable Pay Variable [Member] | Portion Of Contracts Maturing In 2016 | Physical Contracts [Member]	'		'
Average variable price	3.97	[3]	'
Receive | Natural Gas [Member] | Receive Variable Pay Variable [Member] | Portion Of Contracts Maturing In 2017 | Physical Contracts [Member]	'		'
Average variable price	4.17	[3]	'
Receive | NGLs [Member] | Receive Variable Pay Fixed [Member] | Portion Of Contracts Maturing In 2014 | Swaps [Member]	'		'
Average variable price	65.16	[3]	'
Receive | NGLs [Member] | Receive Variable Pay Fixed [Member] | Portion Of Contracts Maturing In 2014 | Physical Contracts [Member]	'		'
Average variable price	57.57	[3]	'
Receive | NGLs [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2014 | Swaps [Member]	'		'
Average fixed price	54.5	[3]	'
Receive | NGLs [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2014 | Physical Contracts [Member]	'		'
Average fixed price	55.26	[3]	'
Receive | NGLs [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2015 | Swaps [Member]	'		'
Average fixed price	51.33	[3]	'
Receive | NGLs [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2015 | Physical Contracts [Member]	'		'
Average fixed price	54.21	[3]	'
Receive | NGLs [Member] | Receive Variable Pay Variable [Member] | Portion Of Contracts Maturing In 2014 | Physical Contracts [Member]	'		'
Average variable price	42.91	[3]	'
Receive | NGLs [Member] | Receive Variable Pay Variable [Member] | Portion Of Contracts Maturing In 2015 | Physical Contracts [Member]	'		'
Average variable price	71.16	[3]	'
Receive | Liquids [Member] | Receive Variable Pay Fixed [Member] | Portion Of Contracts Maturing In 2014 | Swaps [Member]	'		'
Average variable price	100.82	[3]	'
Receive | Liquids [Member] | Receive Variable Pay Fixed [Member] | Portion Of Contracts Maturing In 2014 | Physical Contracts [Member]	'		'
Average variable price	99.24	[3]	'
Receive | Liquids [Member] | Receive Variable Pay Fixed [Member] | Portion Of Contracts Maturing In 2015 | Swaps [Member]	'		'
Average variable price	92.58	[3]	'
Receive | Liquids [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2014 | Swaps [Member]	'		'
Average fixed price	91.82	[3]	'
Receive | Liquids [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2014 | Physical Contracts [Member]	'		'
Average fixed price	99.25	[3]	'
Receive | Liquids [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2015 | Swaps [Member]	'		'
Average fixed price	93	[3]	'
Receive | Liquids [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2016 | Swaps [Member]	'		'
Average fixed price	99.31	[3]	'
Receive | Liquids [Member] | Receive Variable Pay Variable [Member] | Portion Of Contracts Maturing In 2014 | Physical Contracts [Member]	'		'
Average variable price	97.13	[3]	'
Pay | Natural Gas [Member] | Receive Variable Pay Fixed [Member] | Portion Of Contracts Maturing In 2014 | Swaps [Member]	'		'
Average fixed price	4.28	[3]	'
Pay | Natural Gas [Member] | Receive Variable Pay Fixed [Member] | Portion Of Contracts Maturing In 2014 | Physical Contracts [Member]	'		'
Average fixed price	4.41	[3]	'
Pay | Natural Gas [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2014 | Swaps [Member]	'		'
Average variable price	4.39	[3]	'
Pay | Natural Gas [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2014 | Physical Contracts [Member]	'		'
Average variable price	4.33	[3]	'
Pay | Natural Gas [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2015 | Swaps [Member]	'		'
Average variable price	4.51	[3]	'
Pay | Natural Gas [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2015 | Physical Contracts [Member]	'		'
Average variable price	4.5	[3]	'
Pay | Natural Gas [Member] | Receive Variable Pay Variable [Member] | Portion Of Contracts Maturing In 2014 | Swaps [Member]	'		'
Average variable price	4.38	[3]	'
Pay | Natural Gas [Member] | Receive Variable Pay Variable [Member] | Portion Of Contracts Maturing In 2014 | Physical Contracts [Member]	'		'
Average variable price	4.4	[3]	'
Pay | Natural Gas [Member] | Receive Variable Pay Variable [Member] | Portion Of Contracts Maturing In 2015 | Swaps [Member]	'		'
Average variable price	4.33	[3]	'
Pay | Natural Gas [Member] | Receive Variable Pay Variable [Member] | Portion Of Contracts Maturing In 2015 | Physical Contracts [Member]	'		'
Average variable price	4.22	[3]	'
Pay | Natural Gas [Member] | Receive Variable Pay Variable [Member] | Portion Of Contracts Maturing In 2016 | Physical Contracts [Member]	'		'
Average variable price	3.97	[3]	'
Pay | Natural Gas [Member] | Receive Variable Pay Variable [Member] | Portion Of Contracts Maturing In 2017 | Physical Contracts [Member]	'		'
Average variable price	4.18	[3]	'
Pay | NGLs [Member] | Receive Variable Pay Fixed [Member] | Portion Of Contracts Maturing In 2014 | Swaps [Member]	'		'
Average fixed price	65.99	[3]	'
Pay | NGLs [Member] | Receive Variable Pay Fixed [Member] | Portion Of Contracts Maturing In 2014 | Physical Contracts [Member]	'		'
Average fixed price	57.25	[3]	'
Pay | NGLs [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2014 | Swaps [Member]	'		'
Average variable price	56	[3]	'
Pay | NGLs [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2014 | Physical Contracts [Member]	'		'
Average variable price	56.68	[3]	'
Pay | NGLs [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2015 | Swaps [Member]	'		'
Average variable price	50.71	[3]	'
Pay | NGLs [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2015 | Physical Contracts [Member]	'		'
Average variable price	52.91	[3]	'
Pay | NGLs [Member] | Receive Variable Pay Variable [Member] | Portion Of Contracts Maturing In 2014 | Physical Contracts [Member]	'		'
Average variable price	42.48	[3]	'
Pay | NGLs [Member] | Receive Variable Pay Variable [Member] | Portion Of Contracts Maturing In 2015 | Physical Contracts [Member]	'		'
Average variable price	70.79	[3]	'
Pay | Liquids [Member] | Receive Variable Pay Fixed [Member] | Portion Of Contracts Maturing In 2014 | Swaps [Member]	'		'
Average fixed price	100.1	[3]	'
Pay | Liquids [Member] | Receive Variable Pay Fixed [Member] | Portion Of Contracts Maturing In 2014 | Physical Contracts [Member]	'		'
Average fixed price	99.81	[3]	'
Pay | Liquids [Member] | Receive Variable Pay Fixed [Member] | Portion Of Contracts Maturing In 2015 | Swaps [Member]	'		'
Average fixed price	91.1	[3]	'
Pay | Liquids [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2014 | Swaps [Member]	'		'
Average variable price	98.09	[3]	'
Pay | Liquids [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2014 | Physical Contracts [Member]	'		'
Average variable price	100.28	[3]	'
Pay | Liquids [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2015 | Swaps [Member]	'		'
Average variable price	89.89	[3]	'
Pay | Liquids [Member] | Receive Fixed Pay Variable [Member] | Portion Of Contracts Maturing In 2016 | Swaps [Member]	'		'
Average variable price	84.52	[3]	'
Pay | Liquids [Member] | Receive Variable Pay Variable [Member] | Portion Of Contracts Maturing In 2014 | Physical Contracts [Member]	'		'
Average variable price	98.03	[3]	'
[1]	Volumes of natural gas are measured in MMBtu, whereas volumes of NGL and crude oil are measured in Bbl.
[2]	The fair value is determined based on quoted market prices at March 31, 2014 and DecemberB 31, 2013, 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 gains at DecemberB 31, 2013.
[3]	Weighted average prices received and paid are in $/MMBtu for natural gas and $/Bbl for NGL and crude oil.

Recovered_Sheet10

Derivative Financial Instruments And Hedging Activities (Fair Values Of Expected Cash Flows Of Outstanding Commodity Options) (Details) (Commodity [Member], USD $)	3 Months Ended		12 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014		Dec. 31, 2013
Credit valuation adjustments	$0		$0
Put Option [Member] | Written [Member] | Portion Of Option Contracts Maturing in 2014 | Natural Gas [Member]	'		'
Notional	1,729,000	[1]	'
Strike Price	3.9	[2]	'
Market Price	4.49	[2]	'
Assets at Fair Value	0	[3]	0	[3]
Gross Derivative Liabilitites	-0.2	[3]	-0.5	[3]
Put Option [Member] | Purchased [Member] | Portion Of Option Contracts Maturing in 2014 | Natural Gas [Member]	'		'
Notional	3,300,000	[1]	'
Strike Price	3.9	[2]	'
Market Price	4.46	[2]	'
Assets at Fair Value	0.4	[3]	0.7	[3]
Gross Derivative Liabilitites	0	[3]	0	[3]
Put Option [Member] | Purchased [Member] | Portion Of Option Contracts Maturing in 2014 | NGLs [Member]	'		'
Notional	394,500	[1]	'
Strike Price	53.04	[2]	'
Market Price	53.17	[2]	'
Assets at Fair Value	2.3	[3]	2.9	[3]
Gross Derivative Liabilitites	0	[3]	0	[3]
Put Option [Member] | Purchased [Member] | Portion Of Option Contracts Maturing in 2015 | Natural Gas [Member]	'		'
Notional	4,015,000	[1]	'
Strike Price	3.9	[2]	'
Market Price	4.2	[2]	'
Assets at Fair Value	1.9	[3]	1.7	[3]
Gross Derivative Liabilitites	0	[3]	0	[3]
Put Option [Member] | Purchased [Member] | Portion Of Option Contracts Maturing in 2015 | NGLs [Member]	'		'
Notional	1,113,250	[1]	'
Strike Price	50.64	[2]	'
Market Price	53.31	[2]	'
Assets at Fair Value	6.1	[3]	6	[3]
Gross Derivative Liabilitites	0	[3]	0	[3]
Put Option [Member] | Purchased [Member] | Portion Of Option Contracts Maturing in 2015 | Liquids [Member]	'		'
Notional	456,250	[1]	'
Strike Price	85	[2]	'
Market Price	89.5	[2]	'
Assets at Fair Value	2.3	[3]	1.8	[3]
Gross Derivative Liabilitites	0	[3]	0	[3]
Put Option [Member] | Purchased [Member] | Portion Of Option Contracts Maturing in 2016 | Liquids [Member]	'		'
Notional	91,500	[1]	'
Strike Price	80	[2]	'
Market Price	84.3	[2]	'
Assets at Fair Value	0.6	[3]	0	[3]
Gross Derivative Liabilitites	0	[3]	0	[3]
Call Option [Member] | Written [Member] | Portion Of Option Contracts Maturing in 2014 | NGLs [Member]	'		'
Notional	206,250	[1]	'
Strike Price	59.62	[2]	'
Market Price	54.36	[2]	'
Assets at Fair Value	0	[3]	0	[3]
Gross Derivative Liabilitites	-0.6	[3]	-1	[3]
Call Option [Member] | Written [Member] | Portion Of Option Contracts Maturing in 2015 | Natural Gas [Member]	'		'
Notional	1,277,500	[1]	'
Strike Price	5.05	[2]	'
Market Price	4.2	[2]	'
Assets at Fair Value	0	[3]	0	[3]
Gross Derivative Liabilitites	-0.4	[3]	-0.3	[3]
Call Option [Member] | Written [Member] | Portion Of Option Contracts Maturing in 2015 | NGLs [Member]	'		'
Notional	292,000	[1]	'
Strike Price	62.48	[2]	'
Market Price	57.59	[2]	'
Assets at Fair Value	0	[3]	0	[3]
Gross Derivative Liabilitites	-1.6	[3]	-1	[3]
Call Option [Member] | Written [Member] | Portion Of Option Contracts Maturing in 2015 | Liquids [Member]	'		'
Notional	456,250	[1]	'
Strike Price	90.7	[2]	'
Market Price	89.5	[2]	'
Assets at Fair Value	0	[3]	0	[3]
Gross Derivative Liabilitites	-3.1	[3]	-1.9	[3]
Call Option [Member] | Written [Member] | Portion Of Option Contracts Maturing in 2016 | Liquids [Member]	'		'
Notional	91,500	[1]	'
Strike Price	87	[2]	'
Market Price	84.3	[2]	'
Assets at Fair Value	0	[3]	0	[3]
Gross Derivative Liabilitites	-0.7	[3]	0	[3]
Call Option [Member] | Purchased [Member] | Portion Of Option Contracts Maturing in 2014 | NGLs [Member]	'		'
Notional	46,000	[1]	'
Strike Price	50.4	[2]	'
Market Price	45.73	[2]	'
Assets at Fair Value	0.2	[3]	0	[3]
Gross Derivative Liabilitites	$0	[3]	$0	[3]
[1]	Volumes of natural gas are measured in MMBtu, whereas volumes of NGL and crude oil are measured in Bbl.
[2]	Strike and market prices are in $/MMBtu for natural gas and in $/Bbl for NGL and crude oil.
[3]	The fair value is determined based on quoted market prices at March 31, 2014 and DecemberB 31, 2013, respectively, discounted using the swap rate for the respective periods to consider the time value of money.

Income_Taxes_Narrative_Details

Income Taxes (Narrative) (Details) (USD $)	3 Months Ended		12 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013	Dec. 31, 2013
Effective income tax rate	0.50%	0.50%	'
Income tax expense	$1	$0.50	'
Current income tax payable	1.8	'	1
Deferred income tax liability	$11.60	'	$11.10

Segment_Information_Details

Segment Information (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014		Mar. 31, 2013		Dec. 31, 2013
Segment Reporting Information [Line Items]	'		'		'
Total revenue	$2,198		$1,882.20		'
Operating revenue	1,646.90		1,370.30		'
Cost of natural gas and natural gas liquids	1,488.70		1,196.10		'
Selling, General and Administrative Expense, Total	145.9		143.1		'
Operating and maintenance	81.7		83.4		'
General and administrative	27.2		24.5		'
Depreciation and amortization	37		35.2		'
Operating income (loss)	12.3		31.1		'
Interest expense, net	3.3		0		'
Other income (expense)	-1.3		0.1		'
Income (loss) before income tax expense	7.7		31.2		'
Income tax expense	1		0.5		'
Net income (loss)	6.7		30.7		'
Less: Net income attributable to noncontrolling interest	6.3		0		'
Net income (loss) attributable to general and limited partner ownership interest in Midcoast Energy Partners, L.P.	0.4		30.7		'
Total assets	5,429.50		5,613.90		6,036.40
Capital expenditures (excluding investment in joint venture)	55.4		70.9		'
Intersegment Revenue Eliminations [Member]	'		'		'
Segment Reporting Information [Line Items]	'		'		'
Total revenue	-551.1		-511.9		'
Processing and Transportation [Member]	'		'		'
Segment Reporting Information [Line Items]	'		'		'
Total revenue	725		659.2		'
Operating revenue	203.3		172.2		'
Segment gross margin	118.5		154.8		'
Cost of natural gas and natural gas liquids	84.8		17.4		'
Selling, General and Administrative Expense, Total	123.4		119.6		'
Operating and maintenance	64.4		64.2		'
General and administrative	24		21.9		'
Depreciation and amortization	35		33.5		'
Operating income (loss)	-4.9		35.2		'
Interest expense, net	0		'		'
Other income (expense)	-1.2	[1]	0		'
Income (loss) before income tax expense	-6.1		35.2		'
Income tax expense	0		0		'
Net income (loss)	-6.1		35.2		'
Less: Net income attributable to noncontrolling interest	0		'		'
Net income (loss) attributable to general and limited partner ownership interest in Midcoast Energy Partners, L.P.	-6.1		'		'
Total assets	4,901.70	[2]	4,533.10	[2]	'
Capital expenditures (excluding investment in joint venture)	47.8		66.3		'
Processing and Transportation [Member] | Intersegment Revenue Eliminations [Member]	'		'		'
Segment Reporting Information [Line Items]	'		'		'
Total revenue	-521.7		-487		'
Logistics and Marketing [Member]	'		'		'
Segment Reporting Information [Line Items]	'		'		'
Total revenue	1,473		1,223		'
Operating revenue	1,443.60		1,198.10		'
Segment gross margin	39.7		19.4		'
Cost of natural gas and natural gas liquids	1,403.90		1,178.70		'
Selling, General and Administrative Expense, Total	22.5		23.5		'
Operating and maintenance	17.3		19.2		'
General and administrative	3.2		2.6		'
Depreciation and amortization	2		1.7		'
Operating income (loss)	17.2		-4.1		'
Interest expense, net	0		'		'
Other income (expense)	0		0		'
Income (loss) before income tax expense	17.2		-4.1		'
Income tax expense	0		0		'
Net income (loss)	17.2		-4.1		'
Less: Net income attributable to noncontrolling interest	0		'		'
Net income (loss) attributable to general and limited partner ownership interest in Midcoast Energy Partners, L.P.	17.2		'		'
Total assets	311.1		843.2		'
Capital expenditures (excluding investment in joint venture)	2.3		4.6		'
Logistics and Marketing [Member] | Intersegment Revenue Eliminations [Member]	'		'		'
Segment Reporting Information [Line Items]	'		'		'
Total revenue	-29.4		-24.9		'
Corporate [Member]	'		'		'
Segment Reporting Information [Line Items]	'		'		'
Total revenue	0	[3]	0	[3]	'
Operating revenue	0	[3]	0	[3]	'
Segment gross margin	0	[3]	0	[3]	'
Cost of natural gas and natural gas liquids	0	[3]	0	[3]	'
Selling, General and Administrative Expense, Total	0	[3]	0	[3]	'
Operating and maintenance	0	[3]	0	[3]	'
General and administrative	0	[3]	0	[3]	'
Depreciation and amortization	0	[3]	0	[3]	'
Operating income (loss)	0	[3]	0	[3]	'
Interest expense, net	3.3	[3]	'		'
Other income (expense)	-0.1	[3]	0.1	[3]	'
Income (loss) before income tax expense	-3.4	[3]	0.1	[3]	'
Income tax expense	1	[3]	0.5	[3]	'
Net income (loss)	-4.4	[3]	-0.4	[3]	'
Less: Net income attributable to noncontrolling interest	6.3	[3]	'		'
Net income (loss) attributable to general and limited partner ownership interest in Midcoast Energy Partners, L.P.	-10.7	[3]	'		'
Total assets	216.7	[3]	237.6	[3]	'
Capital expenditures (excluding investment in joint venture)	5.3	[3]	0	[3]	'
Corporate [Member] | Intersegment Revenue Eliminations [Member]	'		'		'
Segment Reporting Information [Line Items]	'		'		'
Total revenue	$0	[3]	$0	[3]	'
[1]	Other income (expense) for our Gathering, Processing and Transportation segment includes our equity investment in the Texas Express NGL system which began recognizing operating costs during the fourth quarter of 2013.
[2]	Totals assets for our Gathering, Processing and Transportation segment includes our long-term equity investment in the Texas Express NGL system.
[3]	Corporate consists of income taxes and interest expense, which are not allocated to the business segments.

Supplemental_Cash_Flows_Inform2

Supplemental Cash Flows Information (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Discount accretion	$0	$0
Amortization of hedging costs	0	-0.2
Deferred income taxes	0.5	0
Texas Express long-term inventory (line fill)	0.3	0
Allowance for interest used during construction	0	-2.8
Other elements included in 'Other' of 'Cash From Operating Activities'	0.2	-0.3
Other	1	-2.2
Additions to property, plant and equipment	55.5	78
Decrease in construction payables	-0.1	-7.1
Total capital expenditures (excluding investment in joint venture)	55.4	70.9
Sale of South Haynesville Pipeline assets [Member]	'	'
Loss on sale of assets	$0	$1.10

Subsequent_Events_Narrative_De

Subsequent Events (Narrative) (Details) (USD $)	3 Months Ended
In Millions, except Per Share data, unless otherwise specified	Mar. 31, 2014
Distribution Made to Limited Partner, Distributions Paid, Per Unit	$0.17
Subsequent Event [Member]	'
Distribution Declaration Date	29-Apr-14
Record Date	8-May-14
Distribution Payment Date	15-May-14
Distribution Made to Limited Partner, Distributions Paid, Per Unit	$0.31
Cash Available for Distribution	$14.40
Amount Paid To EEP	7.8
Noncontrolling Interest [Member] | Subsequent Event [Member]	'
Distribution Made to Limited Partner, Cash Distributions Paid	6.6
Midcoast Operating, L.P. | Subsequent Event [Member]	'
Distribution Declaration Date	29-Apr-14
Amount Paid To EEP	15.3
Midcoast Operating, L.P. | General Partner [Member] | Subsequent Event [Member]	'
Amount Paid To EEP	$23.90