Enbridge Energy Partners 10-Q 3 Nov 14 2014 Q3 Quarterly report Financial data

Document_and_Entity_Informatio

Document and Entity Information	9 Months Ended
	Sep. 30, 2014	Nov. 03, 2014
Document and Entity Information [Abstract]	'	'
Entity Registrant Name	'ENBRIDGE ENERGY PARTNERS LP	'
Entity Central Index Key	'0000880285	'
Document Type	'10-Q	'
Document Period End Date	30-Sep-14	'
Amendment Flag	'false	'
Current Fiscal Year End Date	'--12-31	'
Entity Filer Category	'Large Accelerated Filer	'
Entity Common Stock, Shares Outstanding	'	254,208,428
Document Fiscal Year Focus	'2014	'
Document Fiscal Period Focus	'Q3	'
Trading Symbol	'eep	'

CONSOLIDATED_STATEMENTS_OF_INC

CONSOLIDATED STATEMENTS OF INCOME (USD $)	3 Months Ended		9 Months Ended
In Millions, except Per Share data, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Operating revenue (Note 10)	$1,874	$1,724	$5,663.60	$4,950.30
Operating revenue - affiliate (Note 8)	68.3	65.4	229.4	204.8
Total operating revenue	1,942.30	1,789.40	5,893	5,155.10
Operating expenses:	'	'	'	'
Cost of natural gas	1,238.20	1,257.50	3,986.70	3,564.40
Environmental costs, net of recoveries (Note 9)	50.1	0.6	93.3	184.3
Operating and administrative	235.3	265.1	676.9	678
Power (Note 10)	59.5	43	164.1	105.8
Depreciation and amortization	118.8	99.6	336	287.6
Costs and Expenses, Total	1,701.90	1,665.80	5,257	4,820.10
Operating income	240.4	123.6	636	335
Interest expense, net (Notes 6 and 10)	137.1	70.5	294.2	226.4
Allowance for equity used during construction (Note 13)	14.5	9.3	47.8	25.2
Other income	1.8	0.4	2.2	1
Income before income tax expense	119.6	62.8	391.8	134.8
Income tax expense (Note 11)	2.1	1.5	6.1	17.5
Net income	117.5	61.3	385.7	117.3
Less: Net income attributable to:	'	'	'	'
Noncontrolling interest (Note 8)	70.7	20.3	149.4	54.3
Series 1 preferred unit distributions	22.5	22.7	67.5	35.8
Accretion of discount on Series 1 preferred units	3.8	3.4	11.1	5.7
Net income attributable to general and limited partner ownership interests in Enbridge Energy Partners, L.P.	20.5	14.9	157.7	21.5
Net income (loss) allocable to limited partner interests	-14.5	-17.6	49.5	-73.8
Net income (loss) per limited partner unit (basic) (Note 2)	($0.04)	($0.05)	$0.15	($0.23)
Weighted average limited partner units outstanding (basic)	328.8	317.4	327.6	313.2
Net income (loss) per limited partner unit (diluted) (Note 2)	($0.04)	($0.05)	$0.15	($0.23)
Weighted average limited partner units outstanding (diluted)	328.8	317.4	327.6	313.2
Third Party [Member]	'	'	'	'
Operating expenses:	'	'	'	'
Cost of natural gas	1,208.50	1,234.70	3,888.40	3,469.10
Operating and administrative	119.4	153.6	323.3	348.9
Affiliate [Member]	'	'	'	'
Operating expenses:	'	'	'	'
Cost of natural gas	29.7	22.8	98.3	95.3
Operating and administrative	$115.90	$111.50	$353.60	$329.10

CONSOLIDATED_STATEMENTS_OF_COM

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME [Abstract]	'	'	'	'
Net income	$117.50	$61.30	$385.70	$117.30
Other comprehensive income (loss), net of tax expense (benefit) of $0.0 million $(0.1) million, $0.0 million and $0.0 million, respectively (Note 10)	55.5	-14	-80.6	177.7
Comprehensive income	173	47.3	305.1	295
Less: Comprehensive income attributable to:	'	'	'	'
Noncontrolling interest (Note 8)	70.7	20.3	149.4	54.3
Series 1 preferred unit distributions	22.5	22.7	67.5	35.8
Accretion of discount on Series 1 preferred units	3.8	3.4	11.1	5.7
Other comprehensive income attributed to noncontrolling interest	2.1	'	1.8	'
Comprehensive income attributable to general and limited partner ownership interests in Enbridge Energy Partners, L.P.	$73.90	$0.90	$75.30	$199.20

CONSOLIDATED_STATEMENTS_OF_COM1

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME [Abstract]	'	'	'	'
Other comprehensive income (loss), tax expense (benefit)	$0	($0.10)	$0	$0

CONSOLIDATED_STATEMENTS_OF_CAS

CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013
Cash provided by operating activities	'	'
Net income	$385.70	$117.30
Adjustments to reconcile net income to net cash provided by operating activities:	'	'
Depreciation and amortization (Note 5)	336	287.6
Derivative fair value net losses (Note 10)	62.7	16.8
Inventory market price adjustments (Note 4)	4.8	3.3
Environmental costs, net of recoveries (Note 9)	81.5	221.1
Distributions from investments in joint ventures (Note 8)	6.1	'
Equity earnings from investments in joint ventures (Note 8)	-7.1	'
Deferred income taxes (Note 11)	1.5	13.5
State income taxes	3.2	7.9
Allowance for equity used during construction (Note 13)	-47.8	-25.2
Amortization of debt issuance and hedging costs	8	7.5
Other	5	3.2
Changes in operating assets and liabilities, net of acquisitions:	'	'
Receivables, trade and other	0.9	66.2
Due from General Partner and affiliates	15.3	-4.9
Accrued receivables	27.7	452.5
Inventory (Note 4)	-131	-87.4
Current and long-term other assets (Note 10)	-28.7	-22.3
Due to General Partner and affiliates	-23.4	3.1
Accounts payable and other (Notes 3 and 10)	-93.1	28
Environmental liabilities (Note 9)	-116.7	-79.8
Accrued purchases	-28.6	-77
Interest payable	5.9	8.3
Property and other taxes payable	23.8	8.1
Settlement of interest rate derivatives (Note 10)	'	-5.3
Net cash provided by operating activities	491.7	942.5
Cash used in investing activities	'	'
Additions to property, plant and equipment (Notes 5 and 14)	-2,055.80	-1,514.50
Changes in restricted cash (Note 8)	31.2	-2.2
Investments in joint ventures (Note 8)	-35.4	-181.8
Distributions from investments in joint ventures in excess of cumulative earnings	27	'
Other	-0.7	-5.6
Net cash used in investing activities	-2,033.70	-1,704.10
Cash provided by financing activities	'	'
Net proceeds from Series 1 preferred unit issuance	'	1,200
Net proceeds from unit issuances (Note 7)	'	519.3
Distributions to partners (Note 7)	-544.2	-530.6
Repayments to General Partner (Note 8)	-12	-12
Net proceeds from issuance of long-term debt (Note 6)	398.1	'
Repayments of long-term debt (Note 6)	'	-200
Net borrowings under credit facility (Note 6)	30	'
Net commercial paper borrowings (repayments) (Note 6)	799.8	-734.9
Contributions from noncontrolling interest (Notes 7 and 8)	1,083	355.2
Distributions to noncontrolling interest (Notes 7 and 8)	-80.9	-39.7
Net cash provided by financing activities	1,673.80	557.3
Net increase (decrease) in cash and cash equivalents	131.8	-204.3
Cash and cash equivalents at beginning of year	164.8	227.9
Cash and cash equivalents at end of period	$296.60	$23.60

CONSOLIDATED_STATEMENTS_OF_FIN

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION (USD $)	Sep. 30, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Current assets:	'	'
Cash and cash equivalents (Note 3)	$296.60	$164.80
Restricted cash (Note 8)	38.2	69.4
Receivables, trade and other, net of allowance for doubtful accounts of $0.5 million in 2014 and 2013 (Note 9)	48.5	49.4
Due from General Partner and affiliates	26.7	40.5
Accrued receivables	182.5	210.2
Inventory (Note 4)	221.1	94.9
Other current assets (Note 10)	74.5	47.6
Assets, Current, Total	888.1	676.8
Property, plant and equipment, net (Note 5)	15,038.10	13,176.80
Goodwill	246.7	246.7
Intangibles, net	255.9	263.2
Other assets, net (Note 10)	518.3	538
Total assets	16,947.10	14,901.50
Current liabilities:	'	'
Due to General Partner and affiliates (Note 8)	98	121.4
Accounts payable and other (Notes 3, 10 and 13)	632.3	822
Environmental liabilities (Note 9)	164.1	233.7
Accrued purchases	437	465.6
Interest payable	73.9	68
Property and other taxes payable (Note 11)	94.2	70.7
Note payable to General Partner (Note 8)	12	12
Current maturities of long-term debt (Note 6)	200	200
Liabilities, Current, Total	1,711.50	1,993.40
Long-term debt (Note 6)	6,007.90	4,777.40
Loans from General Partner and affiliate (Note 8)	294	306
Due to General Partner and affiliates (Note 8)	125.8	58.2
Deferred income tax liability (Note 11)	19	17.4
Other long-term liabilities (Notes 9 and 10)	396	51.7
Total liabilities	8,554.20	7,204.10
Commitments and contingencies (Note 9)	'	'
Partners' capital: (Notes 7 and 8)	'	'
Series 1 preferred units (48,000,000 at September 30, 2014 and December 31, 2013)	1,171.80	1,160.70
General Partner	199.9	301.5
Accumulated other comprehensive income (loss) (Note 10)	-159	-76.6
Total Enbridge Energy Partners, L.P. partners' capital	5,138.60	5,721.80
Noncontrolling interest (Note 8)	3,254.30	1,975.60
Total partners' capital	8,392.90	7,697.40
Liabilities and Stockholders' Equity, Total	16,947.10	14,901.50
Class D Units [Member]	'	'
Partners' capital: (Notes 7 and 8)	'	'
Common units	2,516.80	'
Class A Common Units [Member]	'	'
Partners' capital: (Notes 7 and 8)	'	'
Common units	240.1	2,979
Class B Common Units [Member]	'	'
Partners' capital: (Notes 7 and 8)	'	'
Common units	'	65.3
i-units [Member]	'	'
Partners' capital: (Notes 7 and 8)	'	'
Common units	675.9	1,291.90
Incentive Distribution Units [Member]	'	'
Partners' capital: (Notes 7 and 8)	'	'
Common units	$493.10	'

CONSOLIDATED_STATEMENTS_OF_FIN1

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION (Parenthetical) (USD $)	Sep. 30, 2014	Dec. 31, 2013
In Millions, except Share data, unless otherwise specified
Receivables, trade and other, allowance for doubtful accounts	$0.50	$0.50
Preferred Units, Issued	48,000,000	48,000,000
Class D Units [Member]	'	'
Common units, outstanding	66,100,000	'
Class A Common Units [Member]	'	'
Common units, outstanding	254,208,428	254,208,428
Class B Common Units [Member]	'	'
Common units, outstanding	7,825,500	7,825,500
i-units [Member]	'	'
Common units, outstanding	67,260,894	63,743,099
Incentive Distribution Units [Member]	'	'
Common units, outstanding	1,000	'

BASIS_OF_PRESENTATION

BASIS OF PRESENTATION	9 Months Ended
	Sep. 30, 2014
BASIS OF PRESENTATION	'
BASIS OF PRESENTATION	'
	1. BASIS OF PRESENTATION
	We have prepared the accompanying unaudited interim consolidated financial statements in accordance with accounting principles generally accepted in the United States of America, or GAAP, for interim consolidated financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. Accordingly, the unaudited interim consolidated financial statements do not include all the information and footnotes required by GAAP for complete consolidated financial statements. In the opinion of management, they contain all adjustments, consisting only of normal recurring adjustments, which management considers necessary to present fairly our financial position as of September 30, 2014, our results of operations for the three and  nine month periods ended September 30, 2014, and 2013, and our cash flows for the  nine month periods ended September 30, 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 nine month period ended September 30, 2014, should not be taken as indicative of the results to be expected for the full year due to seasonal fluctuations in the supply of and demand for crude oil, seasonality of portions of our natural gas business, 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 and the effect of environmental costs and related insurance recoveries on our Lakehead system. Our unaudited interim consolidated financial statements should be read in conjunction with our audited consolidated financial statements and notes thereto presented in our Annual Report on Form 10-K for the fiscal year ended December 31, 2013.
	Comparative Amounts
	During the first quarter of 2014, we changed our reporting segments. The Marketing segment was combined with the Natural Gas segment to form one new segment named “Natural Gas.” There was no change to the Liquids segment.
	This change was a result of our reorganization in connection with Midcoast Energy Partner, L.P.'s, or MEP's, initial public offering, or IPO, of its Class A common units representing limited partnership interests. This reorganization prompted management to reassess the presentation of EEP's reportable segments considering the financial information available and evaluated regularly by our Chief Operating Decision Maker. Our new segment reporting is consistent with how management makes resource allocation decisions, evaluates performance, and furthers the achievement of our long-term objectives. Financial information for the prior periods has been restated to reflect the change in reporting segments.
	Additionally, we have reclassified certain prior period affiliate amounts related to operating revenue, the cost of natural gas, and operating and administrative expenses to conform to the current period presentation. These reclassifications did not impact net income.

NET_INCOME_PER_LIMITED_PARTNER

NET INCOME PER LIMITED PARTNER UNIT	9 Months Ended
	Sep. 30, 2014
NET INCOME PER LIMITED PARTNER UNIT [Abstract]	'
NET INCOME PER LIMITED PARTNER UNIT	'
	2. NET INCOME PER LIMITED PARTNER UNIT
	We allocate our net income among our Series 1 Preferred Units, or Preferred Units, our General Partner interest and our limited partners units using the two-class method in accordance with applicable authoritative accounting guidance. Under the two-class method, we allocate our net income attributable to our general and limited partner interests to our General Partner and our limited partners according to the distribution formula for available cash as set forth in our partnership agreement. We also allocate any earnings in excess of distributions to our General Partner and limited partners utilizing the distribution formula for available cash specified in our partnership agreement. We allocate any distributions in excess of earnings for the period to our General Partner and limited partners based on their sharing of losses of 2% and 98%, respectively, as set forth in our partnership agreement. Until July 1, 2014, we allocated the distributions to the General Partner and limited partners as follows:
	Distribution Targets		Portion of Quarterly			Percentage Distributed to				Percentage Distributed
			Distribution Per Unit			General Partner				to Limited partners
	Minimum Quarterly Distribution		Up to $0.295				2	%					98	%
	First Target Distribution		> $0.295 to $0.35				15	%					85	%
	Second Target Distribution		> $0.35 to $0.495				25	%					75	%
	Over Second Target Distribution		In excess of $0.495				50	%					50	%
	Equity Restructuring Transaction
	On July 1, 2014, we entered into an equity restructuring transaction, or Equity Restructuring, with the General Partner in which the General Partner irrevocably waived its right to receive cash distributions and allocations of items of income, gain, deduction and loss in excess of 2% in respect of its general partner interest in the incentive distribution rights, or Previous IDRs, in exchange for the issuance to a wholly-owned subsidiary of the General Partner of (i) 66.1 million units of a new class of limited partner interests designated as Class D units, and (ii) 1,000 units of a new class of limited partner interests designated as Incentive Distribution Units, or IDUs.
	The Class D units entitle the holder thereof to receive quarterly distributions equal to the amount derived by multiplying the number of Class D units outstanding by the distribution rate per unit paid on our Class A and Class B common units, collectively referred to as common units. The Class D units are convertible on a one-for-one basis into our Class A common units any time after the fifth anniversary of issuance, or July 1, 2019, at the holder's option. We may redeem the Class D units in whole or in part after the 30-year anniversary of issuance, or July 1, 2044, at our option for either a cash amount equal to the notional value per unit, or with newly issued Class A common units with an aggregate market value at redemption equal to 105% of the aggregate notional value of the Class D units being redeemed. The Class D units have a notional value of $31.35 per unit, which was the closing price of our Class A common units on June 17, 2014, and have the same voting rights as the Class A common units. In the event of a liquidation event (or any merger or other extraordinary transaction), the Class D units entitle the holder thereof to a preference in liquidation equal to 20% of the notional value, with such preference being increased by an additional 20% on each anniversary of issuance, resulting in a liquidation preference equal to 100% of the notional value on and after July 1, 2018.
	The IDUs entitle the holder thereof to receive 23% of the incremental distributions we pay in excess of $0.5435 per common unit, i-unit, and Class D unit per quarter. In the event of any decrease in the Class A common unit distribution below the current quarterly distribution level of $0.5435 per unit in any quarter during the five years commencing with the fourth quarter of 2014, the distribution we pay on the Class D units will be adjusted to the amount that we would have paid in respect of the Previous IDRs had the Equity Restructuring not occurred. In addition, we reduced the third quarter 2014 distribution payable on the Class D units so that the aggregate distributions we pay in calendar year 2014 with respect to the Previous IDRs, the Class D units and the IDUs will not exceed the distribution that we would have paid in calendar year 2014 in respect to the Previous IDRs had the Equity Restructuring not occurred.
	Beginning July 1, 2014, as established by our amended and restated partnership agreement, we calculate distributions to the General Partner and limited partners based upon the distribution rates and percentages set forth in the following table:
	Distribution Targets		Portion of Quarterly			Percentage Distributed to				Percentage Distributed
			Distribution Per Unit			General Partner and IDUs (1)				to Limited partners
	Minimum Quarterly Distribution		Up to $0.5345				2	%					98	%
	First Target Distribution		> $0.5345				25	%					75	%
	(1)	For distributions in excess of the Minimum Quarterly Distribution, this percentage includes both the General Partner's distributions of 2% and the distribution to the Incentive Distribution Unit holder, a wholly-owned subsidiary of our General Partner.
	We recorded the Class D units and IDUs at their fair values of $2,480.0 million and $491.7 million, respectively, with the offset recorded as a reduction to the carrying amounts of the capital accounts of the Class A and Class B common units, the i-units and the general partner on a pro rata basis. We determined the fair values of the Class D units using a market approach based upon the closing price of the Class A common units as of July 1, 2014 adjusted for differences in specific rights granted to the Class D units and other economic factors that would affect the fair value of the Class D units. We determined the fair value of the IDUs using an income approach on the basis of discounted cash flows from expected quarterly distributions.
	We determined basic and diluted net income per limited partner unit as follows:
			For the three month								For the nine month
			period ended								period ended
			September 30,								September 30,
			2014				2013				2014			2013
			(in millions, except per unit amounts)
	Net income		$	117.5			$	61.3			$	385.7		$	117.3
	Less Net income attributable to:
	Noncontrolling interest			(70.7	)			(20.3	)			(149.4	)		(54.3	)
	Series 1 preferred unit distributions			(22.5	)			(22.7	)			(67.5	)		(35.8	)
	Accretion of discount on Series 1 preferred units			(3.8	)			(3.4	)			(11.1	)		(5.7	)
	Net income attributable to general and limited partner interests in Enbridge Energy Partners, L.P.			20.5				14.9				157.7			21.5
	Less distributions:
	Incentive distributions			(1.4	)			(32.9	)			(35.9	)		(96.8	)
	Distributed earnings attributed to our General Partner			(4.5	)			(3.6	)			(12.6	)		(10.6	)
	Distributed earnings attributed to Class D units			(33.1	)			—				(69.8	)		—
	Total distributed earnings to our General Partner, Class D units, and IDUs			(39.0	)			(36.5	)			(118.3	)		(107.4	)
	Total distributed earnings attributed to our common units and i-units			(182.8	)			(176.5	)			(542.7	)		(518.6	)
	Total distributed earnings			(221.8	)			(213.0	)			(661.0	)		(626.0	)
	Overdistributed earnings		$	(201.3	)		$	(198.1	)		$	(503.3	)	$	(604.5	)
	Weighted average limited partner units outstanding			328.8				317.4				327.6			313.2
	Basic and diluted earnings per unit:
	Distributed earnings per unit (1)		$	0.56			$	0.56			$	1.66		$	1.66
	Overdistributed earnings per limited partner unit (2)			(0.60	)			(0.61	)			(1.51	)		(1.89	)
	Net income (loss) per unit (basic and diluted) (3)		$	(0.04	)		$	(0.05	)		$	0.15		$	(0.23	)
	(1)	Represents the total distributed earnings to common units and i-units divided by the weighted average number of limited partner interests outstanding for the period.
	(2)	Represents the common unit's and i-unit's share (98%) of distributions in excess of earnings divided by the weighted average number of common units and i-units outstanding for the period and overdistributed earnings allocated to the common units and i-units based on the distribution waterfall that is outlined in our partnership agreement.
	(3)	For the three month period ended September 30, 2014, 43,201,310 anti-dilutive Preferred units and 66,100,000 anti-dilutive Class D units were excluded from the if-converted method of calculating diluted earnings per unit. For the nine month period ended September 30, 2014, 43,201,310 anti-dilutive Preferred units and 22,275,458 anti-dilutive Class D units were excluded from the if-converted method of calculating diluted earnings per unit.

CASH_AND_CASH_EQUIVALENTS

CASH AND CASH EQUIVALENTS	9 Months Ended
	Sep. 30, 2014
CASH AND CASH EQUIVALENTS [Abstract]	'
CASH AND CASH EQUIVALENTS	'
	3. 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 $16.2 million at September 30, 2014, and $24.0 million at December 31, 2013, are included in “Accounts payable and other” on our consolidated statements of financial position.

INVENTORY

INVENTORY	9 Months Ended
	Sep. 30, 2014
INVENTORY [Abstract]	'
INVENTORY	'
	4. INVENTORY
		Our inventory is comprised of the following:
			September 30,		December 31,
			2014		2013
			(in millions)
		Materials and supplies	$	2.2	$	2.1
		Crude oil inventory		12.3		18
		Natural gas and NGL inventory		206.6		74.8
			$	221.1	$	94.9
	The “Cost of natural gas and natural gas liquids” on our consolidated statements of income includes charges totaling $1.5 million and $0.9 million for the three month periods ended September 30, 2014 and 2013 respectively, and $4.8 million and $3.3 million for the nine month periods ended September 30, 2014 and 2013, respectively, that we recorded to reduce the cost basis of our inventory of natural gas and natural gas liquids, or NGLs, to reflect the current market value.

PROPERTY_PLANT_AND_EQUIPMENT

PROPERTY, PLANT AND EQUIPMENT	9 Months Ended
	Sep. 30, 2014
PROPERTY, PLANT AND EQUIPMENT [Abstract]	'
PROPERTY, PLANT AND EQUIPMENT	'
	5. PROPERTY, PLANT AND EQUIPMENT
	Our property, plant and equipment is comprised of the following:
		September 30,			December 31,
		2014			2013
		(in millions)
	Land	$	43.1		$	43.6
	Rights-of-way		829.4			666.2
	Pipelines		9,617.30			8,035.80
	Pumping equipment, buildings and tanks		2,831.00			2,233.00
	Compressors, meters and other operating equipment		2,124.10			1,989.80
	Vehicles, office furniture and equipment		417.4			322
	Processing and treating plants		514.2			514.4
	Construction in progress		1,329.00			2,077.70
	Total property, plant and equipment		17,705.50			15,882.50
	Accumulated depreciation		(2,667.4	)		(2,705.7	)
	Property, plant and equipment, net	$	15,038.10		$	13,176.80
	During the nine month period ended September 30, 2014, we recorded asset retirement obligations, or AROs, of $100.6 million. Of that amount, $60.0 million is related to the pre-replacement Line 6B and $40.6 million is related to the pre-replacement Line 3. These AROs are recorded in “Accounts payable and other” and “Other long-term liabilities,” respectively, with an offset to “Property, plant and equipment, net” in our consolidated statements of financial position. Both of these pipelines are part of our Lakehead system, and the AROs are related to the decommissioning of the original pipelines as we are completing Line 6B replacement work in 2014 and the Line 3 replacement with an estimated in-service date of late 2017. The associated ARO is a component of the pipelines category of “Property, plant and equipment, net.” We record AROs at fair value in the period in which they can be reasonably determined. Fair value is determined based on expected future cash flows and estimated retirement periods, as well as discount and inflation rates.
	During the three month period ended September 30, 2014, we retired components of our pre-replacement Line 6B assets, including the related asset retirement costs, in the amount of $282.5 million. Consistent with the group method of depreciation, we charged the retirement of these components to accumulated depreciation.

DEBT

DEBT	9 Months Ended
	Sep. 30, 2014
DEBT [Abstract]	'
DEBT	'
	6. DEBT
	The following table presents the carrying amounts, net of related amortized discounts, of our consolidated debt obligations.
				30-Sep-14			31-Dec-13
				(in millions)
	EEP debt obligations:
	Commercial Paper			$	1,100.00		$	300
	5.350% Senior Notes due 2014				200			200
	5.875% Senior Notes due 2016				299.9			299.9
	7.000% Senior Notes due 2018				99.9			99.9
	6.500% Senior Notes due 2018				399.3			399.1
	9.875% Senior Notes due 2019				500			500
	5.200% Senior Notes due 2020				499.9			499.9
	4.200% Senior Notes due 2021				599.2			599.1
	7.125% Senior Notes due 2028				99.8			99.8
	5.950% Senior Notes due 2033				199.8			199.8
	6.300% Senior Notes due 2034				99.8			99.8
	7.500% Senior Notes due 2038				399.1			399
	5.500% Senior Notes due 2040				546.4			546.4
	8.050% Junior subordinated notes due 2067				399.8			399.7
	MEP debt obligations:
	MEP Credit Agreement				365			335
	3.560% MEP Series A Senior Notes due 2019				75			-
	4.040% MEP Series B Senior Notes due 2021				175			-
	4.420% MEP Series C Senior Notes due 2024				150			-
	Total			$	6,207.90		$	4,977.40
	Interest Cost
	Our interest cost for the three and nine month periods ended September 30, 2014, and 2013, is comprised of the following:
				For the three month						For the nine month
				period ended September 30,						period ended September 30,
				2014			2013			2014			2013
				(in millions)
	Interest expense			$	137.1		$	70.5		$	294.2		$	226.4
	Interest capitalized				11.6			13.4			35.7			39.8
	Interest cost incurred			$	148.7		$	83.9		$	329.9		$	266.2
	Weighted average interest rate				6	%		6.3	%		6.2	%		6.1	%
	Credit Facilities and Commercial Paper
	We have a committed multi-year senior unsecured revolving credit facility, which we refer to as the Credit Facility, and a 364-day credit agreement, which we refer to as the 364-Day Credit Facility. We refer to our Credit Facility and our 364-Day Credit Facility as the Credit Facilities. The Credit Facility permits aggregate borrowings of up to, at any one time outstanding, $1.975 billion.
	On October 6, 2014, we amended our Credit Facility to extend the maturity date to September 26, 2019; however, $175.0 million of commitments will expire on the original maturity date of September 26, 2018.
	On July 3, 2014, we amended our 364-Day Credit Facility to extend the revolving credit termination date to July 3, 2015, and to decrease aggregate commitments under the facility to $650.0 million. The 364-Day Credit Facility provides aggregate lending commitments of up to $650.0 million: (1) on a revolving basis for a 364-day period, extendible annually at the lenders' discretion, and (2) for a 364-day term on a non-revolving basis following the expiration of all revolving periods. Together, the Credit Facilities provide an aggregate amount of approximately $2.625 billion of bank credit, as of September 30, 2014, which we use to fund our general activities and working capital needs.
	We have a commercial paper program that provides for the issuance of up to an aggregate principal amount of $1.5 billion of commercial paper and is supported by our Credit Facilities. We access the commercial paper market primarily to provide temporary financing for our operating activities, capital expenditures and acquisitions when the available interest rates we can obtain are lower than the rates available under our Credit Facilities. At September 30, 2014, we had approximately $1.1 billion in principal amount of commercial paper outstanding at a weighted average interest rate of 0.33%, excluding the effect of our interest rate hedging activities. Under our commercial paper program, we had net borrowings of approximately $799.8 million during the nine month period ended September 30, 2014, which includes gross borrowings of $7.4 billion and gross repayments of $6.6 billion. At December 31, 2013, we had $300.0 million in principal amount of commercial paper outstanding at a weighted average interest rate of 0.37%, excluding the effect of our interest rate hedging activities. Our policy is to limit the amount of commercial paper we can issue by the amounts available under our Credit Facility up to an aggregate principal amount of $1.5 billion.
	We have the ability and intent to refinance all of our commercial paper obligations on a long-term basis through borrowings under our Credit Facilities. Accordingly, such amounts have been classified as “Long-term debt” in our accompanying consolidated statements of financial position.
	On February 3, 2014, we entered into an uncommitted letter of credit arrangement, pursuant to which the lender may, on a discretionary basis and with no commitment, agree to issue standby letters of credit upon our request. On September 9, 2014, we amended this uncommitted letter of credit arrangement to increase the aggregate amount not to exceed $220.0 million. While the letter of credit arrangement is uncommitted and issuance of letters of credit is at the lender's sole discretion, we view this arrangement as a liquidity enhancement as it allows us to potentially reduce our reliance on utilizing our committed Credit Facilities for issuance of letters of credit to support our hedging activities.
	The amounts we may borrow under the terms of our Credit Facilities are reduced by the face amount of our letters of credit outstanding. Our policy is to maintain availability at any time under our Credit Facilities amounts that are at least equal to the amount of commercial paper that we have outstanding at any time. Taking that policy into account, at September 30, 2014, we have approximately $1.3 billion available under the terms of our Credit Facilities, determined as follows:
					(in millions)
		Total credit available under Credit Facilities			$	2,625.00
		Less: Amounts outstanding under Credit Facilities				-
			Principal amount of commercial paper outstanding			1,100.00
			Letters of credit outstanding			183.6
		Total amount available at September 30, 2014			$	1,341.40
	As of September 30, 2014, we were in compliance with the terms of all of our financial covenants under the Credit Facilities.
	MEP Credit Agreement
	On November 13, 2013, MEP, Midcoast Operating L.P., or Midcoast Operating, and their material domestic subsidiaries, entered into a senior revolving credit facility, or the MEP Credit Agreement which permits aggregate borrowings of up to, at any one time outstanding, $850.0 million. The original term of the MEP Credit Agreement is three years with an initial maturity date of November 13, 2016, subject to four one-year requests for extensions. On September 30, 2014, MEP amended the MEP Credit Agreement to extend the maturity date from November 13, 2016, to September 30, 2017; however, $140.0 million of commitments will expire on the original maturity date of November 13, 2016. In connection with the amendment to the MEP Credit Agreement, we entered into an amended and restated subordination agreement by and among MEP, Midcoast Operating, the other parties from time to time party thereto and us in favor of Bank of America N.A., as administrative agent, and for the benefit of the administrative agent and the lenders party to the MEP Credit Agreement, to accommodate the subordination agreement entered into in connection with the MEP private debt issuance on September 30, 2014, described under “MEP Private Debt Issuance.”
	At September 30, 2014, MEP had $365.0 million in outstanding borrowings under the MEP Credit Agreement at a weighted average interest rate of 1.9%. Under the MEP Credit Agreement, we had net borrowings of approximately $30.0 million during the nine month period ended September 30, 2014, which includes gross borrowings of $5,570.0 billion and gross repayments of $5,540.0 billion. As of September 30, 2014, MEP was in compliance with the terms of its financial covenants.
	MEP Private Debt Issuance
	On September 30, 2014, MEP completed a private debt issuance of $400.0 million. The debt consists of three tranches of senior notes: $75.0 million of 3.56% Series A Senior Notes due in 2019; $175.0 million of 4.04% Series B Senior Notes due in 2021; and $150.0 million of 4.42% Series C Senior Notes due in 2024, collectively the Notes. All of the Notes pay interest semi-annually on March 31 and September 30, commencing on March 31, 2015. MEP received approximately $398.1 million in net proceeds, which were used to repay outstanding indebtedness and for other general partnership purposes. Using a portion of the net proceeds, MEP settled two interest rate swaps for a net payment of $0.9 million on September 30, 2014, which will be amortized to interest expense over the original 5 year hedge term.
	The Notes were issued pursuant to a Note Purchase Agreement, or the Purchase Agreement, between MEP and the purchasers named therein. The Notes and all other obligations under the Purchase Agreement are unconditionally guaranteed by each of MEP's domestic material subsidiaries pursuant to a guaranty agreement. Until such time as MEP obtains an investment grade rating from either Moody's or S&P and upon certain trigger events, MEP and the guarantors will grant liens in their assets (subject to certain excluded assets) to secure the obligations under the Notes. There are currently no liens associated with the Notes.
	Additionally, the Purchase Agreement contains various covenants and restrictive provisions which limit the ability of MEP and its subsidiaries to incur certain liens or permit such liens to exist, merge or consolidate with another company, dispose of assets, make distributions on or redeem or repurchase their equity interests, incur or guarantee additional debt, repay subordinated debt or certain debt owed to affiliates prior to maturity, alter MEP's lines of business, and enter into certain types of transactions with affiliates or subsidiaries that MEP is permitted to designate as unrestricted subsidiaries.
	The Purchase Agreement also requires compliance with two financial covenants. MEP must not permit the ratio of consolidated funded debt to pro forma earnings before interest, taxes, depreciation and amortization (the total leverage ratio), EBITDA, 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. MEP also must maintain, on a consolidated basis, as of the end of each applicable four-quarter period, a ratio of pro forma EBITDA to consolidated interest expense for such four quarter period then ended of at least 2.50 to 1.00.
	In connection with MEP's entry into the Purchase Agreement, MEP, along with the guarantors and us, entered into a subordination agreement in which we agreed to subordinate our right to payment on obligations owed by Midcoast Operating under each of the Financial Support Agreement and the Working Capital Agreements, both entered into by and between Midcoast Operating and us on November 13, 2013, and liens, if secured, to the rights of the holders under the Purchase Agreement, subject to the terms and conditions of the subordination agreement in favor and for the benefit of the holders of the Notes.
	Fair Value of Debt Obligations
	The carrying amounts of our outstanding commercial paper, borrowings under our Credit Facilities, and MEP Credit Agreement approximate their fair values at September 30, 2014, and December 31, 2013, respectively, due to the short-term nature and frequent repricing of the amounts outstanding under these obligations. The fair value of our outstanding commercial paper and borrowings under our Credit Facilities and MEP Credit Agreement are included with our long-term debt obligations above since we have the ability and the intent to refinance the amounts outstanding on a long-term basis.
	The approximate fair values of our fixed-rate debt obligations was $5.5 billion and $4.9 billion at September 30, 2014, and December 31, 2013, respectively. We determined the approximate fair values using a standard methodology that incorporates pricing points that are obtained from independent, third-party investment dealers who actively make markets in our debt securities. We use these pricing points to calculate the present value of the principal obligation to be repaid at maturity and all future interest payment obligations for any debt outstanding. The fair value of our long-term debt obligations is categorized as Level 2 within the fair value hierarchy.

PARTNERS_CAPITAL

PARTNERS' CAPITAL	9 Months Ended
	Sep. 30, 2014
PARTNERS' CAPITAL [Abstract]	'
PARTNERS' CAPITAL	'
	7. PARTNERS' CAPITAL
	Distribution to Partners
	The following table sets forth our distributions, as approved by the board of directors of Enbridge Energy Management, or Enbridge Management, during the nine month period ended September 30, 2014.
													Amount of
											Cash		Distribution		Retained
											available		of i-units to		from
	Distribution			Distribution			Distribution				for		i-unit		General		Distribution
	Declaration Date		Record Date	Payment Date			per Unit				distribution		Holders (1)		Partner (2)		of Cash
							(in millions, except per unit amounts)
		31-Jul-14	7-Aug-14	14-Aug-14			$	0.555			$	224.7	$	36.7	$	0.8	$	187.3
		30-Apr-14	8-May-14	15-May-14			$	0.5435			$	214.5	$	35.3	$	0.7	$	178.5
		30-Jan-14	7-Feb-14	14-Feb-14			$	0.5435			$	213.7	$	34.6	$	0.7	$	178.4
	_______________________________
	(1)
	We issued 3,517,795 i-units to Enbridge Management, the sole owner of our i-units, during 2014 in lieu of cash distributions.
	(2)
	We retained an amount equal to 2% of the i-unit distribution from our General Partner to maintain its 2% general partner interest in us.
	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 interests in our consolidated subsidiaries, Enbridge Energy, Limited Partnership, or OLP, and MEP, for the nine month periods ended September 30, 2014 and 2013. The noncontrolling interest in the OLP arises from the joint funding arrangements with our General Partner and its affiliate to finance: (1) construction of the U.S. portion of the Alberta Clipper crude oil pipeline and related facilities, which we refer to as the Alberta Clipper Pipeline; (2) expansion of our Lakehead system to transport crude oil to destinations in the Midwest United States, which we refer to as the Eastern Access Projects; and (3) further expansion of our Lakehead system to transport crude oil between Neche, North Dakota and Superior, Wisconsin, which we refer to as the Mainline Expansion Projects. Noncontrolling interest in MEP arises from its public unitholders' ownership interests in MEP.
				For the nine month
				period ended
				September 30,
				2014				2013
				(in millions)
	Series 1 Preferred interests
	Beginning balance			$	1,160.70			$	-
	Proceeds from issuance of preferred units				-				1,200.00
	Net income				67.5				35.8
	Accretion of discount on preferred units				11.1				5.7
	Distribution payable				(67.5	)			(35.8	)
	Beneficial conversion feature of preferred units				-				(47.7	)
	Ending balance			$	1,171.80			$	1,158.00
	General and limited partner interests
	Beginning balance			$	4,637.70			$	4,774.90
	Proceeds from issuance of partnership interests, net of costs				-				519.3
	Net income				157.7				21.5
	Distributions				(544.2	)			(530.6	)
	Beneficial conversion feature of preferred units				-				47.7
	Transfer of interests in subsidiary to Midcoast Energy Partners, L.P.				(125.4	)			-
	Ending balance			$	4,125.80			$	4,832.80
	Accumulated other comprehensive loss
	Beginning balance			$	(76.6	)		$	(320.5	)
	Changes in fair value of derivative financial instruments reclassified to earnings				22.2				21.3
	Changes in fair value of derivative financial instruments recognized in other
	comprehensive income (loss)				(104.6	)			156.4
	Ending balance			$	(159.0	)		$	(142.8	)
	Noncontrolling interest
	Beginning balance			$	1,975.60			$	793.5
	Capital contributions				1,083.00				355.2
	Transfer of interests in subsidiary to Midcoast Energy Partners, L.P.				125.4				-
	Other comprehensive loss allocated to noncontrolling interest				1.8				-
	Net income				149.4				54.3
	Distributions to noncontrolling interest				(80.9	)			(39.7	)
	Ending balance			$	3,254.30			$	1,163.30
	Total partners' capital at end of period			$	8,392.90			$	7,011.30
	Midcoast Energy Partners, L.P.
	On November 13, 2013, MEP, one of our subsidiaries, completed its IPO of 18,500,000 Class A common units representing limited partner interests and subsequently issued an additional 2,775,000 Class A common units pursuant to the underwriter's exercise of their over allotment option. MEP received proceeds (net of underwriting discounts, structuring fees and offering expenses) of approximately $354.9 million. MEP used the net proceeds to distribute approximately $304.5 million to us, to pay approximately $3.4 million in revolving credit facility origination and commitment fees and used approximately $47.0 million to redeem 2,775,000 Class A common units from us. At September 30, 2014, we owned 5.9% of outstanding MEP Class A common units, 100% of the outstanding MEP Subordinated Units, 100% of MEP's general partner and 48.4% of the limited partner interests in Midcoast Operating.
	On July 1, 2014, we sold a 12.6% limited partner interest in Midcoast Operating to MEP, for $350.0 million in cash, which reduced our total ownership interest in Midcoast Operating from 61% to 48.4%. This transaction represents our first sale to MEP of additional interests in Midcoast Operating since MEP's IPO on November 13, 2013. We intend to sell additional interests in our natural gas assets, held through Midcoast Operating, to MEP and use the proceeds from any such sale as a source of funding for us. However, we do not know when, or if, any additional interests will be offered for sale.
	The change in our total ownership interest in Midcoast Operating was recorded as an equity transaction, and no loss on the sale was recognized in our consolidated statements of income or comprehensive income. The increase in MEP's ownership interest in Midcoast Operating resulted in a reclassification of $125.4 million from the partners' capital accounts on a pro-rata basis to “Noncontrolling interest” in our consolidated statements of financial position.

RELATED_PARTY_TRANSACTIONS

RELATED PARTY TRANSACTIONS	9 Months Ended
	Sep. 30, 2014
RELATED PARTY TRANSACTIONS [Abstract]	'
RELATED PARTY TRANSACTIONS	'
	8. RELATED PARTY TRANSACTIONS
	Administrative and Workforce Related Services
	We do not directly employ any of the individuals responsible for managing or operating our business, nor do we have any directors. Enbridge and its affiliates provide management and we obtain managerial, administrative, operational and workforce related services from our General Partner, Enbridge Management and affiliates of Enbridge pursuant to service agreements among our General Partner, Enbridge Management, affiliates of Enbridge, and us. Pursuant to these service agreements, we have agreed to reimburse our General Partner, Enbridge Management and affiliates of Enbridge for the cost of managerial, administrative, operational and director services they provide to us. Where directly attributable, the cost of all compensation, benefits expenses and employer expenses for these employees are charged directly by Enbridge to the appropriate affiliate. Enbridge does not record any profit or margin for the administrative and operational services charged to us.
	The following table presents the affiliate amounts incurred by us for services received pursuant to the services agreements. The amounts we incurred are reflected in our consolidated statements of income by category.
				For the three month period ended September 30,								For the nine month period ended September 30,
				2014				2013				2014			2013
				(in millions)
		Operating and administrative - affiliate		$	115.9			$	111.5			$	353.6		$	329.1
	Distribution from MEP
	The following table presents distributions paid by MEP to its public Class A common unitholders and us during the nine month period ended September 30, 2014, representing the noncontrolling interest in MEP.
	Distribution		Distribution		Amount Paid to				Amount Paid to the				Total MEP
	Declaration Date		Payment Date		EEP				noncontrolling interest				Distribution
					(in millions)
	31-Jul-14		14-Aug-14		$	8.1			$	6.9			$	15
	29-Apr-14		15-May-14			7.8				6.6				14.4
	29-Jan-14		14-Feb-14			4.2				3.5				7.7
					$	20.1			$	17			$	37.1
	Working Capital Credit Facility
	On November 13, 2013, we entered into a $250.0 million Working Capital Loan Agreement, or the Working Capital Credit Facility, by and between Midcoast Operating, as borrower, and the Partnership, as lender. On October 30, 2014, we received a notice from Midcoast Operating that it is exercising its right under the Working Capital Agreement to terminate the Working Capital Agreement upon 30-days' notice, and such termination is expected to occur in the fourth quarter. As of September 30, 2014, there were no outstanding borrowings under the Working Capital Agreement.
	Joint Funding Arrangement for Alberta Clipper Pipeline
	In 2009, we entered into a joint funding arrangement with several of our affiliates and affiliates of Enbridge Inc., or Enbridge, to finance the construction of the United States segment of the Alberta Clipper Pipeline, which we refer to as the Series AC. As part of that arrangement, we have a credit agreement between our General Partner and us, which we refer to as the A1 Term Note. A summary of the cash activity for the A1 Term Note for the nine month periods ended September 30, 2014 and 2013 are as follows:
					A1 Term Note
					September 30,
					2014				2013
					(in millions)
		Beginning Balance			$	318			$	330
		Borrowings				-				-
		Repayments				(12.0	)			(12.0	)
		Ending Balance			$	306			$	318
	We incurred interest expense under the A1 Term Note of $6.1 million and $18.3 million for the three and nine month periods ended September 30, 2014, respectively. We have presented the amounts in “Interest expense, net” on our consolidated statements of income.
	We allocated earnings derived from operating the Alberta Clipper Pipeline in the amount of $16.3 million and $38.0 million for the three and nine month periods ended September 30, 2014, respectively, to our General Partner for its 66.67% share of the earnings of the Alberta Clipper Pipeline. We also allocated $13.4 million and $39.6 million of such earnings to our General Partner for the three and nine month periods ended September 30, 2013, respectively. We have presented the amounts we allocated to our General Partner for its share of the earnings of the Alberta Clipper Pipeline in “Net income attributable to noncontrolling interest” on our consolidated statements of income.
	Distribution to Series AC Interests
	The following table presents distributions paid by the OLP to our General Partner and its affiliate during the nine month period ended September 30, 2014, representing the noncontrolling interest in the Series AC, and to us, as the holders of the Series AC general and limited partner interests. The distributions were declared by the board of directors of Enbridge Management, acting on behalf of Enbridge Pipelines (Lakehead) L.L.C., the managing general partner of the OLP and the Series AC interests.
	Distribution		Distribution		Amount Paid to				Amount paid to the				Total Series AC
	Declaration Date		Payment Date		Partnership				noncontrolling interest				Distribution
					(in millions)
	31-Jul-14		14-Aug-14		$	7.4			$	14.8			$	22.2
	30-Apr-14		15-May-14			6.6				13.1				19.7
	30-Jan-14		14-Feb-14			6.4				12.8				19.2
					$	20.4			$	40.7			$	61.1
	Joint Funding Arrangement for Eastern Access Projects
	The OLP has a series of partnership interests, which we refer to as the EA interests. The EA interests were created to finance projects to increase access to refineries in the U.S. Upper Midwest and in Ontario, Canada for light crude oil produced in western Canada and the United States, which we refer to as the Eastern Access Projects. Our General Partner owns 75% of the EA interests, and projects are jointly funded by our General Partner at 75% and us at 25%.
	Our General Partner made equity contributions totaling $550.5 million and $272.5 million to the OLP during the nine month periods ended September 30, 2014 and 2013, respectively, to fund its equity portion of the construction costs associated with the Eastern Access Projects.
	We allocated earnings from the Eastern Access Projects in the amount of $41.7 million and $90.5 million to our General Partner for its ownership of the EA interest for the three and nine month periods ended September 30, 2014, respectively. We allocated earnings derived from the Eastern Access Projects in the amount of $6.6 million and $14.4 million to our General Partner for the three and nine month periods ended September 30, 2013, respectively. We have presented the amount allocated to our General Partner in “Net income attributable to noncontrolling interest” on our consolidated statements of income.
	Distribution to Series EA Interests
	The following table presents distributions paid by the OLP to our General Partner and its affiliate during the nine month period ended September 30, 2014, representing the noncontrolling interest in the Series EA, and to us, as the holders of the Series EA general and limited partner interests. The distributions were declared by the board of directors of Enbridge Management, acting on behalf of Enbridge Pipelines (Lakehead), L.L.C., the managing general partner of the OLP and the Series EA interests.
	Distribution		Distribution		Amount Paid to				Amount Paid to the				Total Series EA
	Declaration Date		Payment Date		EEP				noncontrolling interest				Distribution
					(in millions)
	31-Jul-14		14-Aug-14		$	5.6			$	16.7			$	22.3
	29-Apr-14		15-May-14			2.5				6.5				9
					$	8.1			$	23.2			$	31.3
	Joint Funding Arrangement for U.S. Mainline Expansion Projects
	The OLP also has a series of partnership interests, which we refer to as the ME interests. The ME interests were created to finance projects to increase access to the markets of North Dakota and western Canada for light oil production on our Lakehead System between Neche, North Dakota and Superior, Wisconsin, which we refer to as our Mainline Expansion Projects. Our General Partner owns 75% of the ME interests, and the projects are jointly funded by our General Partner at 75% and us at 25%, under the Mainline Expansion Joint Funding Agreement, which parallels the Eastern Access Joint Funding Agreement.
	Our General Partner has made equity contributions totaling $384.0 million and $82.7 million to the OLP for the nine month periods ended September 30, 2014, and 2013, respectively, to fund its equity portion of the construction costs associated with the Mainline Expansion Projects.
	We allocated earnings from the Mainline Expansion Projects in the amount of $9.8 million and $20.0 million to our General Partner for its ownership of the ME interest for the three and nine month periods ended September 30, 2014, respectively. We allocated earnings derived from the Mainline Expansion Projects in the amount of $0.3 million to our General Partner for the three and nine month periods ended September 30, 2013, respectively. We have presented the amount we allocated to our General Partner in “Net income attributable to noncontrolling interest” on our consolidated statements of income.
	Sale of Accounts Receivable
	For the three and nine month periods ended September 30, 2014, we sold and derecognized $1,260.1 million and $3,792.8 million, respectively, of receivables to a wholly owned subsidiary of Enbridge. For the three and nine month periods ended September 30, 2014, the cash proceeds were $1,259.8 million and $3,791.8 million, respectively, which was remitted to us through our centralized treasury system. As of September 30, 2014, $411.1 million of the receivables were outstanding and had not been collected on behalf of the Enbridge subsidiary.
	Consideration for the receivables sold is equivalent to the carrying value of the receivables less a discount for credit risk. The difference between the carrying value of the receivables sold and the cash proceeds received is recognized in “Operating and administrative-affiliate” expense in our consolidated statements of income. For the three and nine month periods ended September 30, 2014, the cost stemming from the discount on the receivables sold was not material.
	As of September 30, 2014 and December 31, 2013, we had $38.2 million and $69.4 million, respectively, included in “Restricted cash” on our consolidated statements of financial position, consisting of cash collections related to the receivables sold that have yet to be remitted to the Enbridge subsidiary as of September 30, 2014.
	Affiliate Revenues and Purchases
	We record operating revenues in our Liquids segment for storage, transportation and terminaling services we provide to affiliates. The sales to affiliates are presented in “Operating revenue - affiliate” on our consolidated statements of income. Purchases of natural gas, natural gas liquids, or NGLs, and crude oil from Enbridge and its affiliates are presented in “Cost of natural gas - affiliate” on our consolidated statements of income.
	The following table presents our results for the three and nine month periods ended September 30, 2014, and September 30, 2013, for operating revenues from sales to Enbridge and its affiliates and costs of natural gas, NGLs and crude oil purchases from Enbridge and its affiliates.
			For the three month period ended September 30,								For the nine month period ended September 30,
			2014				2013				2014			2013
			(in millions)
	Operating revenue - affiliate		$	68.3			$	65.4			$	229.4		$	204.8
	Cost of natural gas - affiliate		$	29.7			$	22.8			$	98.3		$	95.3
Related Party Transactions with Joint Ventures
We have a 35% aggregate indirect interest in the Texas Express NGL system, which is comprised of two joint ventures with third parties that together include a 580-mile NGL intrastate transportation pipeline and a related NGL gathering system that was placed into service in the fourth quarter of 2013. Our equity investment in the Texas Express NGL system at September 30, 2014 and December 31, 2013, was $380.2 million and $371.3 million, respectively, which is included on our consolidated statements of financial position in “Other assets, net.” For the three and nine month periods ending September 30, 2014, we recognized $6.1 million and $7.1 million of equity earnings, respectively, in “Other income (expense)” on our consolidated statements of income related to our investment in the system.
For the three and nine month periods ended September 30, 2014, we incurred $5.4 million and $16.8 million, respectively, of pipeline transportation and demand fees from Texas Express NGL system for our Natural Gas business. We did not incur any fees from the Texas Express NGL system for the three and nine month periods ended September 30, 2013. These expenses are included in “Cost of natural gas – affiliate” on our consolidated statements of income.
Our Natural Gas 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.

COMMITMENTS_AND_CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	9 Months Ended
	Sep. 30, 2014
COMMITMENTS AND CONTINGENCIES [Abstract]	'
COMMITMENTS AND CONTINGENCIES	'
	9. 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 liquid hydrocarbon and natural gas pipeline operations, 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 environmental liabilities through insurance or other potentially responsible parties, we will be responsible for payment of liabilities arising from environmental incidents associated with the operating activities of our Liquids and Natural Gas businesses. Our General Partner has agreed to indemnify us from and against any costs relating to environmental liabilities associated with the Lakehead system assets prior to the transfer of these assets to us in 1991. This excludes any liabilities resulting from a change in laws after such transfer. We continue to voluntarily investigate past leak sites on our systems for the purpose of assessing whether any remediation is required in light of current regulations.
	As of September 30, 2014 and December 31, 2013, we had $64.0 million and $25.8 million, respectively, included in “Other long-term liabilities,” that we have accrued for costs we have recognized primarily to address remediation of contaminated sites, asbestos containing materials, management of hazardous waste material disposal, outstanding air quality measures for certain of our liquids and natural gas assets and penalties we have been or expect to be assessed.
	Griffith Terminal Crude Oil Release
	On February 25, 2014, a release of approximately 975 barrels of crude oil occurred within the Griffith Terminal in Griffith, Indiana. A repair plan has been reviewed with Pipeline and Hazardous Materials Safety Administration, or PHMSA and repair work has commenced. The released oil was fully contained within our facility and substantially all of the free product was recovered. The released oil did not affect the local community, wildlife or water supply. In connection with this crude oil release, the cost estimate is approximately $7.0 million, excluding possible fines and penalties. As of September 30, 2014, we made payments of $6.0 million, and we have a remaining estimated liability of $1.0 million.
	Lakehead Line 6B Crude Oil Release
	We continue to perform necessary remediation, restoration and monitoring of the areas affected by the Line 6B crude oil release. All the initiatives we are undertaking in the monitoring and restoration phase are intended to restore the crude oil release area to the satisfaction of the appropriate regulatory authorities.
	On March 14, 2013, we received an order from the Environmental Protection Agency, or EPA, which we refer to as the Order, that defined the scope which requires additional containment and active recovery of submerged oil relating to the Line 6B crude oil release. We submitted our initial proposed work plan required by the EPA on April 4, 2013, and we resubmitted the workplan on April 23, 2013, and again on May 1, 2013, based on EPA comments. The EPA approved the Submerged Oil Recovery and Assessment workplan, or SORA, with modifications on May 8, 2013. We incorporated the modification and submitted an approved SORA on May 13, 2013. At this time we have completed substantially all of the SORA.
	We are also working with the Michigan Department of Environmental Quality, or MDEQ, to transition submerged oil reassessment, sheen management and sediment trap monitoring and maintenance activities from the EPA to the MDEQ, through a Kalamazoo River Residual Oil Monitoring and Maintenance Work Plan or, the Plan.
	As of September 30, 2014, our total cost estimate for the Line 6B crude oil release is $1.21 billion, which is an increase of $85.9 million as compared to December 31, 2013. On May 28, 2014 the MDEQ, Water Resource Division, approved our Schedule of Work for the remainder of 2014. Of the total cost increase of $50.9 million during the three month period ended September 30, 2014, $33.0 million is primarily related to the MDEQ approved Schedule of Work, and completion of the dredge activities near Ceresco and Morrow Lake, and $17.9 million is related to an increase of estimated civil penalties under the Clean Water Act of the United States, as described below under Lines 6A & 6B Fines and Penalties.
	For purposes of estimating our expected losses associated with the Line 6B crude oil release, we have included those costs that we considered probable and that could be reasonably estimated at September 30, 2014. Our estimates exclude: (1) amounts we have capitalized, (2) any claims associated with the release that may later become evident, (3) amounts recoverable under insurance, and (4) fines and penalties from other governmental agencies except as described in the Line 6A & 6B Fines and Penalties section below. Our assumptions include, where applicable, estimates of the expected number of days the associated services will be required and rates that we have obtained from contracts negotiated for the respective service and equipment providers. As we receive invoices for the actual personnel, equipment and services, our estimates will continue to be further refined. Our estimates also consider currently available facts, existing technology and presently enacted laws and regulations. These amounts also consider our and other companies' prior experience remediating contaminated sites and data released by government organizations. Despite the efforts we have made to ensure the reasonableness of our estimates, changes to the recorded amounts associated with this release are possible as more reliable information becomes available. We continue to have the potential of incurring additional costs in connection with this crude oil release due to variations in any or all of the categories described above, including modified or revised requirements from regulatory agencies, in addition to fines and penalties as well as expenditures associated with litigation and settlement of claims.
	The material components underlying our total estimated loss for the cleanup, remediation and restoration associated with the Line 6B crude oil release include the following:
			(in millions)
		Response Personnel & Equipment	$	551.6
		Environmental Consultants		227
		Professional, regulatory and other		429.4
		Total	$	1,208.00
	For the nine month periods ended September 30, 2014 and 2013, we made payments of $117.4 million and $62.3 million, respectively, for costs associated with the Line 6B crude oil release. As of September 30, 2014 and December 31, 2013, we had a remaining estimated liability of $219.4 million and $258.9 million, respectively.
	Lines 6A & 6B Fines and Penalties
	On September 9, 2010, a crude oil release occurred on Line 6A in Romeoville, Illinois. Due to the absence of sufficient information, we cannot provide a reasonable estimate of the liability for potential fines and penalties that could be assessed in connection with the Line 6A release. At September 30, 2014, our total estimated costs for the Line 6A crude oil release do not include an estimate for fines and penalties, which may be imposed by the EPA and PHMSA, in addition to other federal, state and local governmental agencies.
	At September 30, 2014, our estimated costs related to the Line 6B crude oil release included $47.5 million in fines and penalties. Of this amount, $3.7 million related to civil penalties assessed by PHMSA that we paid during the third quarter of 2012. The total also included an amount of $40.0 million related to civil penalties under the Clean Water Act of the United States. While no final fine or penalty has been assessed or agreed to date, we believe that, based on the best information available at this time, the $40.0 million represents an estimate of the minimum amount which may be assessed, excluding costs of injunctive relief that may be agreed to with the relevant governmental agencies. Given the complexity of settlement negotiations, which we expect will continue, and the limited information available to assess the matter, we are unable to reasonably estimate the final penalty which might be incurred or to reasonably estimate a range of outcomes at this time. Injunctive relief is likely to include measures directed toward enhancing spill prevention, leak detection, and emergency response to environmental events, and the cost of compliance with such measures could be significant. Discussions with governmental agencies regarding fines, penalties, and injunctive relief are ongoing.
	Insurance Recoveries
	We are included in the comprehensive insurance program that is maintained by Enbridge for its subsidiaries and affiliates that renew throughout the year. On May 1 of each year, our insurance program is up for renewal and includes commercial liability insurance coverage that is consistent with coverage considered customary for our industry and includes coverage for environmental incidents such as those we have incurred for the crude oil releases from Lines 6A and 6B, excluding costs for fines and penalties.
	A majority of the costs incurred for the crude oil release for Line 6B are covered by the insurance policy that expired on April 30, 2011, which had an aggregate limit of $650.0 million for pollution liability. Including our remediation spending through September 30, 2014, we have exceeded the limits of coverage under this insurance policy. As of September 30, 2014, we have recorded total insurance recoveries of $547.0 million for the Line 6B crude oil release, out of the $650.0 million aggregate limit. We will record receivables for additional amounts we claim for recovery pursuant to our insurance policies during the period that we deem realization of the claim for recovery to be probable.
	In March 2013, we and Enbridge filed a lawsuit against the insurers of our remaining $145.0 million coverage, as one particular insurer is disputing our recovery eligibility for costs related to our claim on the Line 6B crude oil release and the other remaining insurers assert that their payment is predicated on the outcome of our recovery with that insurer. We received a partial recovery payment of $42.0 million from the other remaining insurers.
	Of the remaining $103.0 million coverage limit, $85.0 million is the subject matter of the lawsuit Enbridge filed in March 2013 against one particular insurer who is disputing our recovery eligibility for costs related to our claim on the Line 6B oil release. The recovery of the remaining $18.0 million is awaiting resolution of this lawsuit. While we believe those costs are eligible for recovery, there can be no assurance that we will prevail in our lawsuit.
	We are pursuing recovery of the costs associated with the Line 6A crude oil release from third parties; however, there can be no assurance that any such recovery will be obtained. Additionally, fines and penalties would not be covered under our existing insurance policy.
	Enbridge renewed its comprehensive property and liability insurance programs under which we are insured through April 30, 2015, having a liability aggregate limit of $700.0 million, including sudden and accidental pollution liability. The deductible applicable to oil pollution events was increased to $30.0 million per event, from the previous $10.0 million. In the unlikely event that multiple insurable incidents which in aggregate exceed coverage limits occur within the same insurance period, the total insurance coverage will be allocated among the Enbridge entities on an equitable basis based on an insurance allocation agreement we have entered into with Enbridge, MEP, and other Enbridge subsidiaries.
	Legal and Regulatory Proceedings
	We are a participant in various legal and regulatory proceedings arising in the ordinary course of business. Some of these proceedings are covered, in whole or in part, by insurance. We are also directly, or indirectly, subject to challenges by special interest groups to regulatory approvals and permits for certain of our expansion projects.
	A number of governmental agencies and regulators have initiated investigations into the Line 6B crude oil release. Approximately 10 actions or claims are pending against us and our affiliates in state and federal courts in connection with the Line 6B crude oil release, including direct actions and actions seeking class status. Based on the current status of these cases, we do not expect the outcome of these actions to be material.
	Governmental agencies and regulators have also initiated investigations into the Line 6A crude oil release. One claim was filed against us and our affiliates by the State of Illinois in an Illinois state court in connection with this crude oil release, and the parties are currently operating under an agreed interim order. The costs associated with this order are included in the estimated environmental costs accrued for the Line 6A crude oil release. We are also pursuing recovery of the costs associated with the Line 6A crude oil release from third parties; however, there can be no assurance that any such recovery will be obtained.
	We have accrued a provision for future legal costs and probable losses associated with the Line 6A and Line 6B crude oil releases as described above in this footnote.

DERIVATIVE_FINANCIAL_INSTRUMEN

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES	9 Months Ended
	Sep. 30, 2014
DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES [Abstract]	'
DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES	'
	10. DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES
	Our net income and cash flows are subject to volatility stemming from changes in interest rates on our variable rate debt obligations and fluctuations in commodity prices of natural gas, NGLs, condensate, crude oil, power 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 interest rate risk exposure results from changes in interest rates on our variable rate debt and exists at the corporate level where our variable rate debt obligations are issued. Our exposure to commodity price risk exists within each 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 interest rates and commodity prices, as well as to reduce volatility of 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 interest rates or commodity prices. We have hedged a portion of our exposure to variability in future cash flows associated with the risks discussed above through 2019 in accordance with our risk management policies.
	Accounting Treatment
	Effective January 1, 2014, we elected to prospectively change the presentation of derivative assets and liabilities from a net basis to a gross basis in the Consolidated Statements of Financial Position.  We adopted this change to provide more detailed information about the future economic benefits and obligations associated with our derivative activities 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.
	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 transaction types associated with our commodity derivative financial instruments where the hedge structure does not meet the requirements to apply hedge accounting. As a result, these derivative financial instruments do not qualify for hedge accounting and are referred to as non-qualifying. These non-qualifying derivative financial instruments are marked-to-market each period with the change in fair value, representing unrealized gains and losses, included in “Cost of natural gas,” “Operating revenue”, “Power” or “Interest expense” 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 the volatility of our income and cash flows:
	Commodity Price Exposures:
	•               Transportation—In our Natural Gas segment, 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 Natural Gas segment, we use derivative financial instruments (i.e., natural gas, crude oil and NGL swaps) to hedge the relative difference between the injection price paid to purchase and store natural gas, crude oil and NGLs and the withdrawal price at which these commodities are 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, crude oil and NGLs injected and the price received upon withdrawal of these commodities 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 these commodities, 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 commodities 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 commodity is sold from storage. As a result, derivative financial instruments associated with our storage activities can create volatility in our earnings.
	•               Condensate, Natural Gas and NGL Options—In our Natural Gas segment, 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.
	•               Optional Natural Gas Processing Volumes—In our Natural Gas segment, 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 and Crude Oil Forward Contracts—In our Natural Gas segment, we use forward contracts to fix the price of NGLs and crude oil we purchase and to fix the price of NGLs and crude oil that we sell to meet the demands of our customers that sell and purchase NGLs and crude oil. A subgroup of physical NGL and physical crude oil 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 change in fair value recorded in earnings.  As a result, our operating income is subject to additional volatility associated with fluctuations in NGL and crude oil prices until the forward contracts are settled.
	•              Natural Gas Forward Contracts—In our Natural Gas segment, we use forward contracts to sell natural gas to our customers. A subgroup of physical natural gas contracts qualify for the NPNS scope exception.  All other forward contracts are being marked-to-market each period with the change 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 Oil Contracts—In our Liquids segment, we use forward contracts to hedge a portion of the crude oil length inherent in the operation of our pipelines, which we subsequently sell at market rates. These hedges create a fixed sales price for the crude oil that we will receive in the future. We elected not to designate these derivative financial instruments as cash flow hedges, and as a result, will experience some additional volatility associated with fluctuations in crude oil prices until the underlying transactions are settled or offset.
	•               Power Purchase Agreements—In our Liquids segment, we use forward physical power agreements to fix the price of a portion of the power consumed by our pumping stations in the transportation of crude oil in our owned pipelines. We designate these derivative agreements as non-qualifying hedges because they fail to meet the criteria for cash flow hedging or the NPNS exception. As various states in which our pipelines operate have legislated either partially or fully deregulated power markets, we have the opportunity to create economic hedges on power exposure. As a result, our operating income is subject to additional volatility associated with changes in the fair value of these agreements due to fluctuations in forward power prices.
	Except for physical power, 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 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. Relating to the power purchase agreements, commodity power purchases are immediately consumed as part of pipeline operations and are subsequently recorded as actual power expenses each period.
	Derivative Positions
	Our derivative financial instruments are included at their fair values in the consolidated statements of financial position as follows:
					September 30,				December 31,
					2014				2013
					(in millions)
		Other current assets			$	37.8			$	21.2
		Other assets, net				36.2				74.4
		Accounts payable and other (1)				(25.6	)			(172.0	)
		Other long-term liabilities				(267.9	)			(12.3	)
		Due from general partner and affiliates				0.4				-
					$	(219.1	)		$	(88.7	)
		______________________________
	(1)
	Includes $16.7 million of cash collateral at December 31, 2013.
	The changes in the assets and liabilities associated with our derivatives are primarily attributable to the effects of new derivative transactions we have entered at prevailing market prices, settlement of maturing derivatives and the change in forward market prices of our remaining hedges. Our portfolio of derivative financial instruments is largely comprised of natural gas, NGL and crude oil sales and purchase contracts.
	The table below summarizes our derivative balances by counterparty credit quality (negative amounts represent our net obligations to pay the counterparty).
					September 30,				December 31,
					2014				2013
					(in millions)
		Counterparty Credit Quality (1)
		AAA			$	0.3			$	0.3
		AA				(91.0	)			(49.7	)
		A (2)				(134.0	)			(40.1	)
		Lower than A				5.6				0.8
					$	(219.1	)		$	(88.7	)
		______________________________
		-1
		As determined by nationally-recognized statistical ratings organizations.
	(2)
	Includes $16.7 million of cash collateral at December 31, 2013.
	As the net value of our derivative financial instruments has decreased in response to changes in forward commodity prices, our outstanding financial exposure to third parties has also decreased. When credit thresholds are met pursuant to the terms of our International Swaps and Derivatives Association, Inc., or ISDA®, financial contracts, we have the right to require collateral from our counterparties. We include any cash collateral received in the balances listed above. 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.
	At September 30, 2014, we had no cash collateral on our asset exposures, and at December 31, 2013, we held $16.7 million of cash collateral on our asset exposures, and we have provided letters of credit totaling $183.0 million and $76.1 million relating to our liability exposures pursuant to the margin thresholds in effect, respectively, under our ISDA® agreements.
	In the event that our credit ratings were to decline to the lowest level of investment grade, as determined by Standard & Poor's and Moody's, we would be required to provide additional amounts under our existing letters of credit to meet the requirements of our ISDA® agreements. For example, if our credit ratings had been at the lowest level of investment grade at September 30, 2014, we would have been required to provide additional letters of credit in the amount of $48.8 million.
	At September 30, 2014 and December 31, 2013, we had credit concentrations in the following industry sectors, as presented below:
					September 30,				December 31,
					2014				2013
					(in millions)
		United States financial institutions and investment banking entities			$	(176.3	)		$	(85.0	)
		Non-United States financial institutions (1)				(49.3	)			0.8
		Other				6.5				(4.5	)
					$	(219.1	)		$	(88.7	)
	______________________________
	(1)
	Includes $16.7 million of cash collateral at December 31, 2013.
	Gross derivative balances are presented below before the effects of collateral received or posted and without the effects of master netting arrangements. Both our assets and liabilities are adjusted for non-performance risk, which is statistically derived. This credit valuation adjustment model considers existing derivative asset and liability balances in conjunction with contractual netting and collateral arrangements, current market data such as credit default swap rates and bond spreads and probability of default assumptions to quantify an adjustment to fair value. For credit modeling purposes, collateral received is included in the calculation of our assets, while any collateral posted is excluded from the calculation of the credit adjustment. Our credit exposure for these over-the-counter, or OTC, derivatives is directly with our counterparty and continues until the maturity or termination of the contracts.
	Effect of Derivative Instruments on the Consolidated Statements of Financial Position
						Asset Derivatives								Liability Derivatives
						Fair Value at								Fair Value at
			Financial Position			September 30,				December 31,				September 30,				December 31,
			Location			2014				2013				2014				2013
						(in millions)
Derivatives designated as hedging instruments (1)
	Interest rate contracts		Other current assets			$	-			$	8.1			$	-			$	-
	Interest rate contracts		Other assets				16.9				57.1				-				-
	Interest rate contracts		Accounts payable and other(2)				-				11.9				(7.8	)			(145.5	)
	Interest rate contracts		Other long-term liabilities				-				-				(255.0	)			(11.3	)
	Commodity contracts		Other current assets				3.3				2				-				(0.6	)
	Commodity contracts		Other assets				1.3				3.5				-				(0.5	)
	Commodity contracts		Accounts payable and other				-				1.9				(2.2	)			(12.7	)
	Commodity contracts		Other long-term liabilities				-				0.6				(0.3	)			(1.4	)
							21.5				85.1				(265.3	)			(172.0	)
	Derivatives not designated as hedging instruments
	Commodity contracts		Other current assets				34.5				11.8				-				(0.1	)
	Commodity contracts		Other assets				18				17.6				-				(3.3	)
	Commodity contracts		Accounts payable and other				-				5.4				(15.6	)			(16.3	)
	Commodity contracts		Other long-term liabilities				-				-				(12.6	)			(0.2	)
	Commodity contracts		Due from general partner and affiliates				0.4				-				-				-
							52.9				34.8				(28.2	)			(19.9	)
	Total derivative instruments					$	74.4			$	119.9			$	(293.5	)		$	(191.9	)
	______________________________
-1
Includes items currently designated as hedging instruments. Excludes the portion of de-designated hedges which may have a component remaining in AOCI.
-2
Liability derivatives exclude $16.7 million of cash collateral at December 31, 2013.
Accumulated Other Comprehensive Income
We record the change in fair value of our derivative financial instruments that qualify for and are designated as a cash flow hedge, which is a hedge of a forecasted transaction or future cash flows, in “Accumulated other comprehensive income”, also referred to as AOCI, a component of “Partners' capital,” until the underlying hedged transaction occurs.  Upon settlement of the designated cash flow hedges, gains (losses) are reclassified to earnings.  Also included in AOCI, as of September 30, 2014, are unrecognized losses of approximately $29.6 million associated with derivative financial instruments that qualified for and were classified as cash flow hedges of forecasted transactions that were subsequently de-designated, settled, or terminated. These losses are reclassified to earnings over the periods during which the originally hedged forecasted transactions affect earnings. During the nine month period ended September 30, 2014, unrealized commodity hedge losses of $0.2 million were de-designated as a result of the hedges no longer meeting hedge accounting criteria. We estimate that approximately $11.7 million, representing unrealized net losses from our cash flow hedging activities based on pricing and positions at September 30, 2014, will be reclassified from AOCI to earnings during the next 12 months.
During the first quarter of 2014 it was determined that a portion of forecasted short term debt transactions were not expected to occur, due to changing funding requirements. Since we will require less short-term debt than previously forecasted, we terminated several of our existing interest rate hedges used to lock-in interest rates on our short-term debt issuances as these hedges no longer meet the cash flow hedging requirements. These terminations resulted in realized losses of $0.8 million for the nine month period ended September 30, 2014.
Our earnings and cash flows are exposed to the variability in longer term interest rates ahead of the anticipated fixed rate debt issuances. Forward starting interest rate swaps are used as cash flow hedges against the effect of future interest rate movements on earnings and cash flow. In order to mitigate the negative effect that increasing interest rates can have on our cash flows, we have purchased 10 year interest rate swaps with a total notional value of $ 2.35 billion as of September 30, 2014.
In September 2014, we amended the maturity date on certain interest rate hedges of future debt issuances that were originally set to mature in 2014 and 2016 to better reflect the expected timing of future debt issuances. The ineffective portion of the hedges fair value in relation to the hedged future debt issuances is recognized in income at the amendment date and each quarter end. For the three and nine months ended September 30, 2014, interest expense increased due to recognition of unrealized losses for hedge ineffectiveness of approximately $62.2 million associated with interest rate hedges that were originally set to mature in 2014 and 2016.
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 September 30, 2014
Interest rate contracts			$	44.1			Interest expense		$	(4.0	)		Interest expense		$	(62.2	)
Commodity contracts				11.2			Cost of natural gas			(2.1	)		Cost of natural gas			0.9
Total			$	55.3					$	(6.1	)				$	(61.3	)
For the three month period ended September 30, 2013
Interest rate contracts			$	1.7			Interest expense		$	(4.2	)		Interest expense		$	(1.1	)
Commodity contracts				(17.2	)		Cost of natural gas			(0.6	)		Cost of natural gas			(0.5	)
Total			$	(15.5	)				$	(4.8	)				$	(1.6	)
For the nine month period ended September 30, 2014
Interest rate contracts			$	(93.0	)		Interest expense		$	(12.1	)		Interest expense		$	(73.2	)
Commodity contracts				7.9			Cost of natural gas			(12.4	)		Cost of natural gas			1.5
Total			$	(85.1	)				$	(24.5	)				$	(71.7	)
For the nine month period ended September 30, 2013
Interest rate contracts			$	179.3			Interest expense		$	(24.3	)		Interest expense		$	(0.5	)
Commodity contracts				(8.8	)		Cost of natural gas			3			Cost of natural gas			1.8
Total			$	170.5					$	(21.3	)				$	1.3
______________________________
-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				$	(76.6	)
	Other Comprehensive Income before reclassifications (1)				(104.6	)
	Amounts reclassified from AOCI (2) (3)				22.2
	Tax benefit (expense)				-
		Net other comprehensive income		$	(82.4	)
Balance at September 30, 2014				$	(159.0	)
_______________________________________
-1
Excludes NCI loss of $0.5 million reclassified from AOCI at September 30, 2014.
-2
Excludes NCI gain of $2.3 million reclassified from AOCI at September 30, 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 September 30,															For the nine month period ended September 30,
							2014							2013								2014									2013
							(in millions)
Losses (gains) on cash flow hedges:
Interest Rate Contracts (1)										$	4							$	4.2							$		12.1						$	24.3
Commodity Contracts (2) (3)											1.6								0.6									10.1							(3.0	)
Total Reclassifications from AOCI										$	5.6							$	4.8							$		22.2						$	21.3
______________________________
-1
Loss reported within "Interest expense" in the consolidated statements of income.
-2
Loss (gain) reported within "Cost of natural gas" in the consolidated statements of income.
-3
Excludes NCI gain of $0.5 million and $2.3 million reclassified from AOCI for the three and nine month periods ending September 30, 2014.
Effect of Derivative Instruments on Consolidated Statements of Income
				For the three month								For the nine month
				period ended								period ended
				September 30,								September 30,
				2014				2013  (2)				2014				2013  (2)
Derivatives Not Designated		Location of Gain or (Loss)		Amount of Gain or (Loss)								Amount of Gain or (Loss)
as Hedging Instruments		Recognized in Earnings (1)		Recognized in Earnings (3)								Recognized in Earnings (3)
				(in millions)
Interest rate contracts		Interest expense (4)		$	—			$	0.1			$	—			$	—
Commodity contracts		Operating revenue (5)			14.6				(16.7	)			10.1				(14.0	)
Commodity contracts		Operating revenue—Affiliate			—				—				0.5				—
Commodity contracts		Power			—				0.1				0.5				0.3
Commodity contracts		Cost of natural gas (6)			9.5				(21.8	)			(9.9	)			(2.6	)
Total				$	24.1			$	(38.3	)		$	1.2			$	(16.3	)
(1)	Does not include settlements associated with derivative instruments that settle through physical delivery.
(2)	The effects of derivative instruments on consolidated statements of income for the three and nine month periods ended September 30, 2013 have been revised to include settlement gains (losses) on derivatives not designated as hedge instruments of $(0.8) million and $1.8 million, respectively. The revisions to the disclosure had no impact on previously reported net income or earnings per unit.
(3)	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.
(4)	Includes settlement gains of $0.1 million and $0.3 million for the three and nine month periods ended September 30, 2013, respectively.
(5)	Includes settlement gains (losses) of $0.6 million and $(0.7) million for the three month periods ended September 30, 2014 and September 30, 2013, respectively, and $0.9 million and $1.0 million for the nine month periods ended September 30, 2014 and September 30, 2013, respectively.
(6)	Includes settlement gains (losses) of $0.2 million and $(0.2) million for the three month periods ended September 30, 2014 and September 30, 2013, respectively, and $(8.6) million and $0.5 million for the nine month periods ended September 30, 2014 and September 30, 2013, respectively.
We record the fair market value of our derivative financial and physical instruments in the consolidated statements of financial position as current and long-term assets or liabilities on a gross basis. However, the terms of the ISDA, which governs our financial contracts and our other master netting agreements, allow the parties to elect in respect of all transactions under the agreement, in the event of a default and upon notice to the defaulting party, for the non-defaulting party to set-off all settlement payments, collateral held and any other obligations (whether or not then due), which the non-defaulting party owes to the defaulting party. The effect of the rights of set-off are outlined below.
Offsetting of Financial Assets and Derivative Assets
		As of September 30, 2014
		Gross				Gross Amount				Net Amount of Assets				Gross Amount				Net
		Amount of				Offset in the				Presented in the				Not Offset in the				Amount
		Recognized				Statement of				Statement of				Statement of
		Assets				Financial Position				Financial Position				Financial Position
		(in millions)
Description:
Derivatives		$	74.4			$	—			$	74.4			$	(33.6	)		$	40.8
Total		$	74.4			$	—			$	74.4			$	(33.6	)		$	40.8
		As of December 31, 2013
		Gross				Gross Amount				Net Amount of Assets				Gross Amount				Net
		Amount of				Offset in the				Presented in the				Not Offset in the				Amount
		Recognized				Statement of				Statement of				Statement of
		Assets				Financial Position				Financial Position				Financial Position
		(in millions)
Description:
Derivatives		$	119.9			$	(24.3	)		$	95.6			$	(18.6	)		$	77
Total		$	119.9			$	(24.3	)		$	95.6			$	(18.6	)		$	77
Offsetting of Financial Liabilities and Derivative Liabilities
		As of September 30, 2014
		Gross				Gross Amount				Net Amount of Liabilities				Gross Amount				Net
		Amount of				Offset in the				Presented in the				Not Offset in the				Amount
		Recognized				Statement of				Statement of				Statement of
		Liabilities				Financial Position				Financial Position				Financial Position
		(in millions)
Description:
Derivatives		$	(293.5	)		$	—			$	(293.5	)		$	33.6			$	(259.9	)
Total		$	(293.5	)		$	—			$	(293.5	)		$	33.6			$	(259.9	)
		As of December 31, 2013
		Gross				Gross Amount				Net Amount  of Liabilities				Gross Amount				Net
		Amount of				Offset in the				Presented in the				Not Offset in the				Amount
		Recognized				Statement of				Statement of				Statement of
		Liabilities				Financial Position				Financial Position				Financial Position
		(in millions)
Description:
Derivatives (1)		$	(208.6	)		$	24.3			$	(184.3	)		$	18.6			$	(165.7	)
Total		$	(208.6	)		$	24.3			$	(184.3	)		$	18.6			$	(165.7	)
(1)	Includes $16.7 million of cash collateral at December 31, 2013.
Inputs to Fair Value Derivative Instruments
The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 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.
				30-Sep-14																December 31, 2013
				Level 1				Level 2				Level 3				Total				Level 1				Level 2				Level 3				Total
				(in millions)
	Interest rate contracts (1)			$	-			$	(245.9	)		$	-			$	(245.9	)		$	-			$	(96.4	)		$	-			$	(96.4	)
	Commodity contracts:
	Financial				-				12.1				1.8				13.9				-				6.4				(6.9	)			(0.5	)
	Physical				-				-				7.6				7.6				-				-				(0.2	)			(0.2	)
	Commodity options				-				-				5.3				5.3				-				-				8.4				8.4
	Total			$	-			$	(233.8	)		$	14.7			$	(219.1	)		$	-			$	(90.0	)		$	1.3			$	(88.7	)
_______________________________________
(1)
During the period, there were no significant transfers in or out of any of any of the Levels or between Levels.
Qualitative Information about Level 2 Fair Value Measurements
We categorize, as Level 2, the fair value of assets and liabilities that we measure with either directly or indirectly observable inputs as of the measurement date, where pricing inputs are other than quoted prices in active markets for the identical instrument. This category includes both OTC transactions valued using exchange traded pricing information in addition to assets and liabilities that we value using either models or other valuation methodologies derived from observable market data. These models are primarily industry-standard models that consider various inputs including: (1) quoted prices for assets and liabilities; (2) time value; and (3) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the assets and liabilities, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace.
Qualitative Information about Level 3 Fair Value Measurements
Data from pricing services and published indices are used to value our Level 3 derivative instruments, which are fair-valued on a recurring basis. We may also use these inputs with internally developed methodologies that result in our best estimate of fair value. The inputs listed in the table below would have a direct impact on the fair values of the listed instruments. The significant unobservable inputs used in the fair value measurement of the commodity derivatives (Natural Gas, NGLs, Crude and Power) are forward commodity prices. The significant unobservable inputs used in determining the fair value measurement of options are price and volatility. Increases/(decreases) in the forward commodity price in isolation would result in significantly higher/(lower) fair values for long positions, with offsetting impacts to short positions. Increases/(decreases) in volatility would increase/(decrease) the value for the holder of the option. Generally, a change in the estimate of forward commodity prices is unrelated to a change in the estimate of volatility of prices. An increase to the credit valuation adjustment would change the fair value of the positions.
Quantitative Information About Level 3 Fair Value Measurements
			Fair Value at											Range (1)
			September 30,						Valuation		Unobservable											Weighted
Contract Type			2014  (2)						Technique		Input			Lowest				Highest				Average			Units
Commodity Contracts - Financial			(in millions)
Natural Gas					$	(0.6	)		Market Approach		Forward Gas Price				3.49				4.74				4.01		MMBtu
NGLs					$	2.4			Market Approach		Forward NGL Price				0.24				1.98				1.18		Gal
Commodity Contracts - Physical
Natural Gas					$	1.8			Market Approach		Forward Gas Price				2.03				4.83				4.04		MMBtu
Crude Oil					$	(1.5	)		Market Approach		Forward Crude Price				83.03				94.98				90.86		Bbl
NGLs					$	7.4			Market Approach		Forward NGL Price				0.23				2.05				1.08		Gal
Power					$	(0.1	)		Market Approach		Forward Power Price				36.21				39.49				37.84		MWh
Commodity Options
Natural Gas, Crude and NGLs					$	5.3			Option Model		Option Volatility				14	%			40	%			28	%
Total Fair Value					$	14.7
(1)	Prices are in dollars per Millions of British Thermal Units, or MMBtu, for Natural Gas; dollars per Gallon, or Gal, for NGLs; dollars per barrel, or Bbl, for Crude Oil; and dollars per Megawatt hour, or MWh, for Power.
(2)	Fair values include credit valuation adjustments of approximately $0.1 million of losses.
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					$	-			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 Oil Price				86.37				103.04				97.24	Bbl
NGLs					$	(0.1	)		Market Approach		Forward NGL Price				0.02				2.19				0.95	Gal
Power					$	(0.7	)		Market Approach		Forward Power Price				32.4				38.98				35.07	MWh
Commodity Options
Natural Gas, Crude and NGLs					$	8.4			Option Model		Option Volatility				18	%			44	%			28	%
Total Fair Value					$	1.3
-1
Prices are in dollars per Millions of British Thermal Units, or MMBtu, for Natural Gas; dollars per Gallon, or Gal, for NGLs; dollars per barrel, or Bbl, for Crude Oil; and dollars per Megawatt hour, or MWh, for Power.
-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 September 30, 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	)		$	(0.2	)		$	8.4			$	1.3
Transfer in (out) of Level 3 (1)						-				-				-				-
Gains or losses:
Included in earnings						(3.9	)			11.1				(1.1	)			6.1
Included in other comprehensive income						(0.2	)			-				-				(0.2	)
Purchases, issuances, sales and settlements:
Purchases						-				-				0.4				0.4
Sales						-				-				(1.6	)			(1.6	)
Settlements (2)						12.8				(3.3	)			(0.8	)			8.7
Ending balance as September 30, 2014					$	1.8			$	7.6			$	5.3			$	14.7
Amount of changes in net assets attributable to the change in derivative
gains or losses related to assets still held at the reporting date					$	2.4			$	7.2			$	(1.8	)		$	7.8
Amounts reported in operating revenue					$	-			$	11.2			$	-			$	11.2
-1
Our policy is to recognize transfers as of the last day of the reporting period.
-2
Settlements represent the realized portion of forward contracts.
Fair Value Measurements of Commodity Derivatives
The following table provides summarized information about the fair values of expected cash flows of our outstanding commodity based swaps and physical contracts at September 30, 2014 and December 31, 2013.
				At September 30, 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			668,692			$	4			$	3.91			$	0.1			$	-			$	-			$	-
				NGL			623,000			$	56.02			$	56.64			$	0.3			$	(0.7	)		$	0.6			$	(0.4	)
				Crude Oil			95,000			$	89.87			$	92.56			$	-			$	(0.3	)		$	-			$	-
		Receive fixed/pay variable		Natural Gas			2,380,100			$	4.26			$	4.09			$	0.5			$	(0.1	)		$	0.1			$	(1.0	)
				NGL			2,021,140			$	51.91			$	50.97			$	3.7			$	(1.8	)		$	4.8			$	(12.7	)
				Crude Oil			457,764			$	95.26			$	90.14			$	2.7			$	(0.4	)		$	3.4			$	(5.4	)
		Receive variable/pay variable		Natural Gas			19,562,500			$	4.03			$	4.02			$	0.6			$	(0.5	)		$	0.6			$	(0.1	)
		Physical Contracts
		Receive variable/pay fixed		Natural Gas			313,224			$	3.89			$	1.23			$	0.8			$	-			$	-			$	-
				NGL			550,000			$	42.4			$	43.88			$	-			$	(0.8	)		$	0.9			$	(0.9	)
				Crude Oil			45,000			$	90.85			$	93.9			$	-			$	(0.1	)		$	-			$	-
		Receive fixed/pay variable		Natural Gas			185,506			$	4.03			$	3.97			$	-			$	-			$	-			$	-
				NGL			3,504,872			$	39.2			$	37.85			$	5.1			$	(0.4	)		$	0.4			$	(2.6	)
				Crude Oil			75,000			$	93.08			$	90.62			$	0.2			$	-			$	-			$	(0.4	)
		Pay fixed		Power (4)			14,716			$	37.84			$	46.59			$	-			$	(0.1	)		$	-			$	(0.7	)
		Receive variable/pay variable		Natural Gas			72,613,470			$	4.02			$	4.02			$	0.9			$	(1.1	)		$	0.9			$	(0.4	)
				NGL			10,947,422			$	42.8			$	42.61			$	2.7			$	(0.6	)		$	5.8			$	(3.7	)
				Crude Oil			758,914			$	88.26			$	90.52			$	0.8			$	(2.5	)		$	1.1			$	(1.2	)
Portion of contracts maturing in 2015
		Swaps
		Receive variable/pay fixed		Natural Gas			316,837			$	3.91			$	3.93			$	-			$	-			$	-			$	-
				NGL			145,850			$	72.56			$	78.2			$	-			$	(0.8	)		$	-			$	-
				Crude Oil			456,000			$	87.81			$	92.94			$	-			$	(2.3	)		$	-			$	-
		Receive fixed/pay variable		Natural Gas			809,761			$	4.56			$	4.21			$	0.3			$	-			$	-			$	-
				NGL			1,024,750			$	54.42			$	52.36			$	3.1			$	(1.0	)		$	1.5			$	(1.1	)
				Crude Oil			1,303,165			$	96.75			$	87.78			$	11.7			$	-			$	8.3			$	-
		Receive variable/pay variable		Natural Gas			42,725,000			$	3.92			$	3.94			$	0.8			$	(1.7	)		$	0.1			$	-
		Physical Contracts
		Receive variable/pay fixed		NGL			95,000			$	46.73			$	48.37			$	-			$	(0.2	)		$	-			$	-
		Receive fixed/pay variable		NGL			586,394			$	49.38			$	47.79			$	1			$	-			$	-			$	-
		Receive variable/pay variable		Natural Gas			108,991,322			$	4.05			$	4.05			$	1.4			$	(0.7	)		$	0.5			$	(0.1	)
				NGL			3,094,719			$	61.4			$	61.19			$	1.2			$	(0.5	)		$	-			$	-
				Crude Oil			151,000			$	90.3			$	88.89			$	0.2			$	-			$	-			$	-
Portion of contracts maturing in 2016
		Swaps
		Receive variable/pay fixed		Natural Gas			181,435			$	3.78			$	3.85			$	-			$	-			$	-			$	-
				Crude Oil			68,250			$	86.36			$	90			$	-			$	(0.2	)		$	-			$	-
		Receive fixed/pay variable		Crude Oil			68,250			$	90.89			$	86.36			$	0.3			$	-			$	0.7			$	-
		Receive variable/pay variable		Natural Gas			12,027,000			$	3.96			$	3.98			$	0.1			$	(0.3	)		$	-			$	-
		Physical Contracts
		Receive variable/pay variable		Natural Gas			34,560,879			$	4.06			$	4.05			$	0.7			$	(0.4	)		$	0.1			$	-
Portion of contracts maturing in 2017
		Physical Contracts
		Receive variable/pay variable		Natural Gas			14,299,743			$	4.27			$	4.26			$	0.2			$	(0.1	)		$	-			$	-
		______________________________
-1
Volumes of natural gas are measured in MMBtu, whereas volumes of NGL and crude oil are measured in Bbl. Our power purchase agreements are measured in MWh.
-2
Weighted average prices received and paid are in $/MMBtu for natural gas, $/Bbl for NGL and crude oil and $/MWh for power.
-3
The fair value is determined based on quoted market prices at September 30, 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 $0.2 million of losses and $0.1 million of gains at September 30, 2014 and December 31, 2013, respectively.
-4
For physical power, the receive price shown represents the index price used for valuation purposes.
The following table provides summarized information about the fair values of expected cash flows of our outstanding commodity options at September 30, 2014 and December 31, 2013.
				At September 30, 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			1,104,000			$	3.9			$	4.1			$	0.1			$	-			$	0.7			$	-
				NGL			193,200			$	54.79			$	52.43			$	0.9			$	-			$	2.9			$	-
		Calls (written)		NGL			115,000			$	60.92			$	54.59			$	-			$	(0.1	)		$	-			$	(1.0	)
		Puts (written)		Natural Gas			1,104,000			$	3.9			$	4.1			$	-			$	(0.1	)		$	-			$	(0.5	)
				NGL			32,200			$	66.36			$	51.7			$	-			$	(0.5	)		$	-			$	-
		Calls (purchased)		NGL			46,000			$	50.4			$	43.84			$	-			$	-			$	-			$	-
				Portion of option contracts maturing in 2015
		Puts (purchased)		Natural Gas			4,015,000			$	3.9			$	4			$	1.4			$	-			$	1.7			$	-
				NGL			1,350,500			$	48.75			$	50.62			$	5.5			$	-			$	6			$	-
				Crude Oil			547,500			$	85.42			$	87.76			$	2.3			$	-			$	1.8			$	-
		Calls (written)		Natural Gas			1,277,500			$	5.05			$	4			$	-			$	(0.1	)		$	-			$	(0.3	)
				NGL			529,250			$	55.18			$	50.29			$	-			$	(1.7	)		$	-			$	(1.0	)
				Crude Oil			547,500			$	91.75			$	87.76			$	-			$	(2.1	)		$	-			$	(1.9	)
		Puts (written)		Natural Gas			4,015,000			$	3.9			$	4			$	-			$	(1.4	)		$	-			$	-
		Calls (purchased)		Natural Gas			1,277,500			$	5.05			$	4			$	0.1			$	-			$	-			$	-
				Portion of option contracts maturing in 2016
		Puts (purchased)		Natural Gas			1,647,000			$	3.75			$	4.08			$	0.5			$	-			$	-			$	-
				NGL			1,281,000			$	41.82			$	44.06			$	6.5			$	-				-				-
				Crude Oil			439,200			$	80			$	85.93			$	2			$	-				-				-
		Calls (written)		Natural Gas			1,647,000			$	4.98			$	4.08			$	-			$	(0.3	)		$	-			$	-
				NGL			1,281,000			$	48.59			$	44.06			$	-			$	(5.6	)			-				-
				Crude Oil			439,200			$	92.25			$	85.93			$	-			$	(2.2	)			-				-
______________________________
-1
Volumes of natural gas are measured in MMBtu, whereas volumes of NGL and crude oil are measured in Bbl.
-2
Strike and market prices are in $/MMBtu for natural gas and in $/Bbl for NGL and crude oil.
-3
The fair value is determined based on quoted market prices at September 30, 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.
Fair Value Measurements of Interest Rate Derivatives
We enter into interest rate swaps, caps and derivative financial instruments with similar characteristics to manage the cash flow associated with future interest rate movements on our indebtedness. The following table provides information about our current interest rate derivatives for the specified periods.
									Average				Fair Value (2)  at
Date of Maturity & Contract Type			Accounting Treatment			Notional			Fixed Rate (1)				30-Sep-14				December 31, 2013
						(dollars in millions)
Contracts maturing in 2015
	Interest Rate Swaps—Pay Fixed		Cash Flow Hedge			$	510			1.53	%		$	(1.9	)		$	(6.8	)
	Contracts maturing in 2016
	Interest Rate Swaps—Pay Fixed		Cash Flow Hedge			$	90			0.55	%		$	-				-
	Contracts maturing in 2017
	Interest Rate Swaps—Pay Fixed		Cash Flow Hedge			$	450			2.21	%		$	(12.2	)		$	(13.8	)
	Contracts maturing in 2018
	Interest Rate Swaps—Pay Fixed		Cash Flow Hedge			$	810			2.24	%		$	1.4			$	3.3
	Contracts maturing in 2019
	Interest Rate Swaps—Pay Fixed		Cash Flow Hedge			$	620			2.96	%		$	(1.0	)		$	-
	Contracts settling prior to maturity
	2014—Pre-issuance Hedges (3)		Cash Flow Hedge			$	-			0	%		$	-			$	(132.7	)
	2015—Pre-issuance Hedges		Cash Flow Hedge			$	1,000			5.48	%		$	(208.5	)			-
	2016—Pre-issuance Hedges		Cash Flow Hedge			$	500			4.21	%		$	(38.0	)		$	60.8
	2017—Pre-issuance Hedges		Cash Flow Hedge			$	500			3.69	%		$	(10.8	)			-
	2018—Pre-issuance Hedges		Cash Flow Hedge			$	350			3.08	%		$	12.4				-
	__________________________
(1)
Interest rate derivative contracts are based on the one-month or three-month London Interbank Offered Rate, or LIBOR.
(2)
The fair value is determined from quoted market prices at September 30, 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 $12.7 million of gains at September 30, 2014 and $7.1 million of losses at December 31, 2013.
(3)
Includes $16.7 million of cash collateral at December 31, 2013.

INCOME_TAXES

INCOME TAXES	9 Months Ended
	Sep. 30, 2014
INCOME TAXES [Abstract]	'
INCOME TAXES	'
	11. INCOME TAXES
	We are not a taxable entity for United States federal income tax purposes, or for the majority of states that impose an income tax. Taxes on our net income generally are borne by our unitholders through the allocation of taxable income. Our income tax expense results from the enactment of state income tax laws by the State of Texas that apply to entities organized as partnerships.  Our income tax expense is based upon many but not all items included in net income.
	We computed our income tax expense by applying a Texas state income tax rate to modified gross margin. The Texas state income tax rate was 0.4% for the nine month periods ended September 30, 2014 and 2013. Our income tax expense is $2.1 million and $1.5 million, for the three month periods ended September 2014 and 2013, respectively, and $6.1 million and $17.5 million for the nine month periods ended September 30, 2014 and 2013, respectively.
	At September 30, 2014 and December 31, 2013, we have included a current income tax payable of $1.1 million and $0.9 million, respectively, in “Property and other taxes payable” on our consolidated statements of financial position. In addition, at September 30, 2014 and December 31, 2013, we have included a deferred income tax payable of $19.0 million and $17.4 million, respectively, in “Deferred income tax liability,” on our consolidated statements of financial position to reflect the tax associated with the difference between the net basis in assets and liabilities for financial and state tax reporting.

SEGMENT_INFORMATION

SEGMENT INFORMATION	9 Months Ended
	Sep. 30, 2014
SEGMENT INFORMATION [Abstract]	'
SEGMENT INFORMATION	'
	12. 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, because each business segment requires different operating strategies. We have segregated our business activities into two distinct operating segments:
	•               Liquids; and
	•               Natural Gas.
	During the first quarter of 2014, we changed our reporting segments. The Marketing segment was combined with the Natural Gas segment to form one new segment called “Natural Gas”. There was no change to the Liquids segment.
	This change was a result of the reorganization of EEP resulting from MEP's IPO, which prompted Management to reassess the presentation of EEP's reportable segments considering the financial information available and evaluated regularly by EEP's Chief Operating Decision Maker. The new segment is consistent with how management makes resource allocation decisions, evaluates performance, and furthers the achievement of the Partnership's long-term objectives. Financial information for the prior periods has been restated to reflect the change in reporting segments.
	The following tables present certain financial information relating to our business segments and corporate activities:
			For the three month period ended September 30, 2014
			Liquids			Natural Gas				Corporate (1)				Total
			(in millions)
	Operating revenue		$	542.9		$	1,399.40			$	-			$	1,942.30
	Cost of natural gas			-			1,238.20				-				1,238.20
	Environmental costs, net of recoveries			50.1			-				-				50.1
	Operating and administrative			126.5			105				3.8				235.3
	Power			59.5			-				-				59.5
	Depreciation and amortization			79.3			39.5				-				118.8
				315.4			1,382.70				3.8				1,701.90
	Operating income (loss)			227.5			16.7				(3.8	)			240.4
	Interest expense, net			-			-				137.1				137.1
	Allowance for equity used during construction			-			-				14.5				14.5
	Other income (expense) (2)			-			6.1				(4.3	)			1.8
	Income (loss) before income tax expense			227.5			22.8				(130.7	)			119.6
	Income tax expense			-			-				2.1				2.1
	Net income (loss)			227.5			22.8				(132.8	)			117.5
	Less: Net income attributable to:
	Noncontrolling interest			-			-				70.7				70.7
	Series 1 preferred unit distributions			-			-				22.5				22.5
	Accretion of discount on Series 1 preferred units			-			-				3.8				3.8
	Net income (loss) attributable to general and limited partner ownership interests in Enbridge Energy Partners, L.P.		$	227.5		$	22.8			$	(229.8	)		$	20.5
	______________________________
	(1)
	Corporate consists of interest expense, interest income, allowance for equity used during construction, noncontrolling interest and other costs such as income taxes, which are not allocated to the business segments.
	2)
	Other income (expense) for our Natural Gas segment includes our equity investment in the Texas Express NGL system which we began recognizing operating costs during the fourth quarter of 2013.
				For the three month period ended September 30, 2013
				Liquids			Natural Gas				Corporate (1)				Total
				(in millions)
	Operating revenue			$	401.5		$	1,387.90			$	-			$	1,789.40
	Cost of natural gas				-			1,257.50				-				1,257.50
	Environmental costs, net of recoveries				0.6			-				-				0.6
	Operating and administrative				149.7			113.6				1.8				265.1
	Power				43			-				-				43
	Depreciation and amortization				63.8			35.8				-				99.6
					257.1			1,406.90				1.8				1,665.80
	Operating income (loss)				144.4			(19.0	)			(1.8	)			123.6
	Interest expense, net				-			-				70.5				70.5
	Allowance for equity used during construction				-			-				9.3				9.3
	Other income				-			-				0.4				0.4
	Income (loss) before income tax expense				144.4			(19.0	)			(62.6	)			62.8
	Income tax expense				-			-				1.5				1.5
	Net income (loss)				144.4			(19.0	)			(64.1	)			61.3
	Less: Net income attributable to the noncontrolling interest				-			-				20.3				20.3
	Series 1 preferred unit distributions				-			-				22.7				22.7
	Accretion of discount on Series 1 preferred units				-			-				3.4				3.4
	Net income (loss) attributable to general and limited partner ownership interests in Enbridge Energy Partners, L.P.			$	144.4		$	(19.0	)		$	(110.5	)		$	14.9
	______________________________
	-1
	Corporate consists of interest expense, interest income, allowance for equity used during construction, noncontrolling interest and other costs such as income taxes, which are not allocated to the business segments.
					As of and for the nine month period ended September 30, 2014
					Liquids						Natural Gas								Corporate (1)						Total
					(in millions)
	Operating revenue					$		1,449.90						$		4,443.10					$	-					$	5,893.00
Cost of natural gas							-								3,986.70						-						3,986.70
Environmental costs, net of recoveries							93.3								-						-						93.3
Operating and administrative							352.5								317.5						6.9						676.9
Power							164.1								-						-						164.1
Depreciation and amortization							222.7								113.3						-						336
							832.6								4,417.50						6.9						5,257.00
Operating income (loss)							617.3								25.6						(6.9		)				636
Interest expense, net							-								-						294.2						294.2
Allowance for equity used during construction							-								-						47.8						47.8
Other income (expense)							-								7.1		-2				(4.9		)				2.2
Income (loss) before income tax expense							617.3								32.7						(258.2		)				391.8
Income tax expense							-								-						6.1						6.1
Net income (loss)							617.3								32.7						(264.3		)				385.7
Less: Net income attributable to:
Noncontrolling interest							-								-						149.4						149.4
Series 1 preferred unit distributions							-								-						67.5						67.5
Accretion of discount on Series 1 preferred units							-								-						11.1						11.1
Net income (loss) attributable to general and limited partner ownership interests in Enbridge Energy Partners, L.P.					$		617.3						$		32.7					$	(492.3		)			$	157.7
Total assets					$		11,252.80						$		5,461.90		-3			$	232.4					$	16,947.10
Capital expenditures (excluding acquisitions)					$		1,861.30						$		158.4					$	3.2					$	2,022.90
______________________________
-1
	Corporate consists of interest expense, interest income, allowance for equity used during construction, noncontrolling interest and other costs such as income taxes, which are not allocated to the business segments.
-2
	Other income (expense) for our Natural Gas segment includes our equity investment in the Texas Express NGL system which began recognizing operating costs during the fourth quarter of 2013.
-3
	Total assets for our Natural Gas segment includes our long term equity investment in the Texas Express NGL system.
					As of and for the nine month period ended September 30, 2013
					Liquids						Natural Gas								Corporate (1)						Total
					(in millions)
Operating revenue							$	1,100.70							$	4,054.40					$	-					$	5,155.10
Cost of natural gas								-								3,564.40						-						3,564.40
Environmental costs, net of recoveries								184.3								-						-						184.3
Operating and administrative								334.8								337.8						5.4						678
Power								105.8								-						-						105.8
Depreciation and amortization								181								106.6						-						287.6
								805.9								4,008.80						5.4						4,820.10
Operating income (loss)								294.8								45.6						(5.4	)					335
Interest expense, net								-								-						226.4						226.4
Allowance for equity used during construction								-								-						25.2						25.2
Other income								-								-						1						1
Income (loss) before income tax expense								294.8								45.6						(205.6	)					134.8
Income tax expense								-								-						17.5						17.5
Net income (loss)								294.8								45.6						(223.1	)					117.3
Less: Net income attributable to the noncontrolling interest								-								-						54.3						54.3
Series 1 preferred unit distributions								-								-						35.8						35.8
Accretion of discount on Series 1 preferred units								-								-						5.7						5.7
Net income (loss) attributable to general and limited partner ownership interests in Enbridge Energy Partners, L.P.							$	294.8							$	45.6					$	(318.9	)				$	21.5
Total assets							$	8,497.90							$	5,224.60		-2			$	161.5					$	13,884.00
Capital expenditures (excluding acquisitions)							$	1,527.20							$	191.9					$	13.9					$	1,733.00
______________________________
-1
Corporate consists of interest expense, interest income, allowance for equity used during construction, noncontrolling interest and other costs such as income taxes, which are not allocated to the business segments.
-2
Total assets for our Natural Gas segment includes our long term equity investment in the Texas Express NGL system.

REGULATORY_MATTERS

REGULATORY MATTERS	9 Months Ended
	Sep. 30, 2014
REGULATORY MATTERS [Abstract]	'
REGULATORY MATTERS	'
	13. REGULATORY MATTERS
	Regulatory Accounting
	We apply the authoritative regulatory accounting provisions to a number of our pipeline projects that meet the criteria outlined for regulated operations. The rates for Southern Access, Alberta Clipper, the Mainline Expansion Project, Eastern Access, the Line 6B 75-mile Replacement Project, Line 6B Integrity Project, and the Line 14 Project, which are currently the primary applicable projects, are based on a cost-of-service recovery model that follows the FERC's authoritative guidance and is subject to annual filing requirements with the FERC. Under our cost-of-service tolling methodology, we calculate tolls annually based on forecast volumes and costs. A difference between forecast and actual results causes an over or under recovery of rates in any given year. These over or under recoveries of rates are returned to shippers or recovered by us through future rate adjustments in the following year. Under the authoritative accounting provisions applicable to our regulated operations, over or under recoveries are recognized in the financial statements in the current period. This accounting model matches earnings to the period with which they relate and conforms to how we recover our costs associated with these expansions through the annual cost-of-service filings with the FERC and through toll rate adjustments with our customers.
	Due to over or under recovery revenue adjustments made in accordance with the FERC's authoritative guidance and our cost-of-service tariff methodology, we recognize assets and liabilities for regulatory purposes. The assets and liabilities that we recognize for regulatory purposes are recorded on a net basis in “Other current assets” or “Accounts payable and other,” respectively, on our consolidated statements of financial position. As of September 30, 2014 and December 31, 2013, we had a net regulatory liability balance of $5.6 million and a net regulatory asset balance of $7.7 million, respectively.
	The net regulatory asset or liability balance is comprised of the cumulative over and under recovery revenue adjustments made during the prior calendar year, less any amortizations, and the cumulative over and under recovery revenue adjustments made during current calendar year to date. We track regulatory assets and liabilities by vintage, and our regulatory assets and liabilities are amortized on a straight-line basis over a one-year recovery period. Accordingly, amortization for a net regulatory asset or liability arising from over and under recovery adjustments related to any given calendar year does not begin until January of the following year. Our over and under recovery revenue adjustments and net regulatory asset amortization for the three and nine months ended September 30, 2014 and 2013 are as follows:
			For the three month					For the nine month
			period ended September 30,					period ended September 30,
			2014			2013		2014			2013
			(in millions)					(in millions)
	Current Year (Over)/Under Recovery Revenue Adjustments		$	(4.5	)	$	3.2	$	(5.6	)	$	7.7
	Amortization of Prior Year Regulatory (Asset)/Liability			—			3.8		(7.7	)(1)		11.5
	-1	The amortization of the prior year regulatory asset for the nine month period ended September 30, 2014, includes a $7.6 million adjustment of the regulatory asset for the difference between estimates as of December 31, 2013, and actual data received during the nine month period ended September 30, 2014.
	Other Contractual Obligations
	Southern Access Pipeline
	We have entered into certain contractual obligations with our customers on the Southern Access Pipeline in which a portion of the revenue earned on volumes above certain predetermined shipment levels, or qualifying volumes, are returned to the shippers through future rate adjustments. We record the liabilities associated with this contractual obligation in “Accounts payable and other,” on our consolidated statements of financial position. The amortization for this contractual obligation reflects the related transportation rate adjustment in the subsequent year. At September 30, 2014, we had no qualifying volume liabilities related to the Southern Access Pipeline on our statements of financial position. At December 31, 2013, we had $6.1 million in qualifying volume liabilities related to the Southern Access Pipeline on our statements of financial position. For the nine month periods ended September 30, 2014 and 2013, we increased our revenues by $6.1 million and $4.2 million, respectively, on our consolidated statements of income with a corresponding amount reducing the contractual obligation on our consolidated statements of financial position to account for amortization of the liability.
	Alberta Clipper Pipeline
	A portion of the rates we charge our customers includes an estimate for annual property taxes. If the estimated property tax we collect from our customers is significantly higher than the actual property tax imposed, we are contractually obligated to refund 50% of the property tax over recovery. At September 30, 2014 and December 31, 2013, we had $6.3 million and $6.9 million, respectively, in property tax over recovery liabilities related to our Alberta Clipper Pipeline on our statements of financial position.
	For 2013, we also incurred liabilities related to this contractual obligation on the Alberta Clipper Pipeline. As a result, in 2013, we reduced revenues for the amounts due back to our shippers and recorded a liability for the contractual obligation. We amortize the liability on a straight line basis in the following year. For the nine month periods ended September 30, 2014 and 2013, we increased our revenues by $5.2 million and $4.5 million, respectively, on our consolidated statements of income with a corresponding amount reducing the contractual obligation on our consolidated statements of financial position.
	Allowance for Equity Used During Construction
	We are permitted to capitalize and recover costs for rate-making purposes that include an allowance for equity costs during construction, referred to as AEDC. In connection with construction of the Eastern Access Projects, Line 6B 75-mile Replacement and Mainline Expansion Projects, we recorded $14.5 and $47.8 million of “Allowance for equity used during construction” in our consolidated statement of income for the three and nine month period ended September 30, 2014, respectively, and a corresponding amount of $47.8 million of AEDC in “Property, plant and equipment” on our consolidated statement of financial position at September 30, 2014. We recorded $9.3 million and $25.2 million of “Allowance for equity used during construction” in our consolidated statements of income for the three and nine month period ended September 30, 2013, respectively, and a corresponding amount of $25.2 million of AEDC in “Property, plant and equipment” on our consolidated statement of financial position at September 30, 2013.

SUPPLEMENTAL_CASH_FLOWS_INFORM

SUPPLEMENTAL CASH FLOWS INFORMATION	9 Months Ended
	Sep. 30, 2014
SUPPLEMENTAL CASH FLOWS INFORMATION [Abstract]	'
SUPPLEMENTAL CASH FLOWS INFORMATION	'
	14. SUPPLEMENTAL CASH FLOWS INFORMATION
	In the “Cash used in investing activities” section of the consolidated statements of cash flows, we exclude changes that did not affect cash. The following is a reconciliation of cash used for additions to property, plant and equipment to total capital expenditures (excluding “Investment in joint venture”):
			For the nine month
			period ended September 30,
			2014			2013
			(in millions)
		Additions to property, plant and equipment	$	2,055.80		$	1,514.50
		Increase (decrease) in construction payables		(32.9	)		218.5
		Total capital expenditures (excluding "Investment in joint venture")	$	2,022.90		$	1,733.00

RECENT_ACCOUNTING_PRONOUNCEMEN

RECENT ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED	9 Months Ended
	Sep. 30, 2014
RECENT ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED [Abstract]	'
RECENT ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED	'
	15. RECENT ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED
	In April 2014, the Financial Accounting Standards Board, or FASB, issued Accounting Standards Update No. 2014-08 that changes the criteria and requires expanded disclosures for reporting discontinued operations. This accounting update is effective for annual and interim periods beginning after December 15, 2014 and is to be applied prospectively. We do not expect that the adoption of this pronouncement will have a material impact on our consolidated financial statements.
	In May 2014, the FASB issued Accounting Standards Update No. 2014-09 that outlines a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. This accounting update is effective for annual and interim periods beginning on or after December 15, 2016 and may be applied on either a full or modified retrospective basis. We are currently evaluating which transition approach we will apply and the impact that this pronouncement will have on our consolidated financial statements.
	In August 2014, the FASB issued Accounting Standards Update No. 2014-15 which provides guidance on determining when and how to disclose going-concern uncertainties in the financial statements. The new standard requires management to perform interim and annual assessments of an entity's ability to continue as a going concern within one year of the date the financial statements are issued. An entity must provide certain disclosures if conditions or events raise substantial doubt about the entity's ability to continue as a going concern. This accounting update is effective for annual and interim periods beginning on or after December 15, 2016, with early adoption permitted. We do not expect that the adoption of this pronouncement will have a material impact on our consolidated financial statements.

SUBSEQUENT_EVENTS

SUBSEQUENT EVENTS	9 Months Ended
	Sep. 30, 2014
SUBSEQUENT EVENTS [Abstract]	'
SUBSEQUENT EVENTS	'
	16. SUBSEQUENT EVENTS
	Credit Facility Agreement Amendments
	On October 6, 2014, we amended the Credit Facility to extend the maturity date from September 26, 2018 to September 26, 2019; however, $175.0 million of commitments will expire on the original maturity date of September 26, 2018.
	Distribution to Partners
	On October 31, 2014, the board of directors of Enbridge Management declared a distribution payable to our partners on November 14, 2014. The distribution will be paid to unitholders of record as of November 7, 2014 of our available cash of $221.8 million at September 30, 2014, or $0.5550 per limited partner unit. Of this distribution, $183.7 million will be paid in cash, $37.3 million will be distributed in i-units to our i-unitholder, Enbridge Management, and due to the i-unit distribution, $0.8 million will be retained from our General Partner from amounts otherwise distributable to it in respect of its general partner interest and limited partner interest to maintain its 2% general partner interest.
	Distribution to Series AC Interests
	On October 31, 2014, the board of directors of Enbridge Management, acting on behalf of Enbridge Pipelines (Lakehead) L.L.C., the managing general partner of the OLP and a holder of the Series AC interests, declared a distribution payable to the holders of the Series AC general and limited partner interests. The OLP will pay $20.3 million to the noncontrolling interest in the Series AC, while $10.1 million will be paid to us.
	Distribution to Series EA Interests
	On October 31, 2014, the board of directors of Enbridge Management, acting on behalf of Enbridge Pipelines (Lakehead) L.L.C., the managing general partner of the OLP and a holder of the Series EA interests, declared a distribution payable to the holders of the Series EA general and limited partner interests. The OLP will pay $43.7 million to the noncontrolling interest in the Series EA, while $14.6 million will be paid to us.
	Distribution to Series ME Interests
	On October 31, 2014, the board of directors of Enbridge Management, acting on behalf of Enbridge Pipelines (Lakehead) L.L.C., the managing general partner of the OLP and a holder of the Series ME interests, declared a distribution payable to the holders of the Series ME general and limited partner interests. The OLP will pay $1.9 million to the noncontrolling interest in the Series ME, while $0.6 million will be paid to us.
	Distribution from MEP
	On October 30, 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 their partners on November 14, 2014. The distribution will be paid to unitholders of record as of November 7, 2014, of MEP's available cash of $15.6 million at September 30, 2014, or $0.3375 per limited partner unit. MEP will pay $7.2  million to their public Class A common unitholders, while $8.4 million in the aggregate will be paid to us with respect to our Class A common units, our subordinated units, and to Midcoast Holdings, L.L.C. with respect to its general partner interest.
	Midcoast Operating Distribution
	On October 30, 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 November 7, 2014. Midcoast Operating will pay $12.6 million to us and $13.5 million to MEP.

NET_INCOME_PER_LIMITED_PARTNER1

NET INCOME PER LIMITED PARTNER UNIT (Tables)	9 Months Ended
	Sep. 30, 2014
NET INCOME PER LIMITED PARTNER UNIT [Abstract]	'
Schedule Of Formula For Distributing Available Cash	'
	Beginning July 1, 2014, as established by our amended and restated partnership agreement, we calculate distributions to the General Partner and limited partners based upon the distribution rates and percentages set forth in the following table:
	Distribution Targets		Portion of Quarterly			Percentage Distributed to				Percentage Distributed
			Distribution Per Unit			General Partner and IDUs (1)				to Limited partners
	Minimum Quarterly Distribution		Up to $0.5345				2	%					98	%
	First Target Distribution		> $0.5345				25	%					75	%
	(1)	For distributions in excess of the Minimum Quarterly Distribution, this percentage includes both the General Partner's distributions of 2% and the distribution to the Incentive Distribution Unit holder, a wholly-owned subsidiary of our General Partner.
	Until July 1, 2014, we allocated the distributions to the General Partner and limited partners as follows:
	Distribution Targets		Portion of Quarterly			Percentage Distributed to				Percentage Distributed
			Distribution Per Unit			General Partner				to Limited partners
	Minimum Quarterly Distribution		Up to $0.295				2	%					98	%
	First Target Distribution		> $0.295 to $0.35				15	%					85	%
	Second Target Distribution		> $0.35 to $0.495				25	%					75	%
	Over Second Target Distribution		In excess of $0.495				50	%					50	%
Basic and Diluted Net Income Per Limited Partner Unit	'
			For the three month								For the nine month
			period ended								period ended
			September 30,								September 30,
			2014				2013				2014			2013
			(in millions, except per unit amounts)
	Net income		$	117.5			$	61.3			$	385.7		$	117.3
	Less Net income attributable to:
	Noncontrolling interest			(70.7	)			(20.3	)			(149.4	)		(54.3	)
	Series 1 preferred unit distributions			(22.5	)			(22.7	)			(67.5	)		(35.8	)
	Accretion of discount on Series 1 preferred units			(3.8	)			(3.4	)			(11.1	)		(5.7	)
	Net income attributable to general and limited partner interests in Enbridge Energy Partners, L.P.			20.5				14.9				157.7			21.5
	Less distributions:
	Incentive distributions			(1.4	)			(32.9	)			(35.9	)		(96.8	)
	Distributed earnings attributed to our General Partner			(4.5	)			(3.6	)			(12.6	)		(10.6	)
	Distributed earnings attributed to Class D units			(33.1	)			—				(69.8	)		—
	Total distributed earnings to our General Partner, Class D units, and IDUs			(39.0	)			(36.5	)			(118.3	)		(107.4	)
	Total distributed earnings attributed to our common units and i-units			(182.8	)			(176.5	)			(542.7	)		(518.6	)
	Total distributed earnings			(221.8	)			(213.0	)			(661.0	)		(626.0	)
	Overdistributed earnings		$	(201.3	)		$	(198.1	)		$	(503.3	)	$	(604.5	)
	Weighted average limited partner units outstanding			328.8				317.4				327.6			313.2
	Basic and diluted earnings per unit:
	Distributed earnings per unit (1)		$	0.56			$	0.56			$	1.66		$	1.66
	Overdistributed earnings per limited partner unit (2)			(0.60	)			(0.61	)			(1.51	)		(1.89	)
	Net income (loss) per unit (basic and diluted) (3)		$	(0.04	)		$	(0.05	)		$	0.15		$	(0.23	)
	(1)	Represents the total distributed earnings to common units and i-units divided by the weighted average number of limited partner interests outstanding for the period.
	(2)	Represents the common unit's and i-unit's share (98%) of distributions in excess of earnings divided by the weighted average number of common units and i-units outstanding for the period and overdistributed earnings allocated to the common units and i-units based on the distribution waterfall that is outlined in our partnership agreement.
	(3)	For the three month period ended September 30, 2014, 43,201,310 anti-dilutive Preferred units and 66,100,000 anti-dilutive Class D units were excluded from the if-converted method of calculating diluted earnings per unit. For the nine month period ended September 30, 2014, 43,201,310 anti-dilutive Preferred units and 22,275,458 anti-dilutive Class D units were excluded from the if-converted method of calculating diluted earnings per unit.

INVENTORY_Tables

INVENTORY (Tables)	9 Months Ended
	Sep. 30, 2014
INVENTORY [Abstract]	'
Schedule of Inventory	'
		Our inventory is comprised of the following:
			September 30,		December 31,
			2014		2013
			(in millions)
		Materials and supplies	$	2.2	$	2.1
		Crude oil inventory		12.3		18
		Natural gas and NGL inventory		206.6		74.8
			$	221.1	$	94.9

PROPERTY_PLANT_AND_EQUIPMENT_T

PROPERTY, PLANT AND EQUIPMENT (Tables)	9 Months Ended
	Sep. 30, 2014
PROPERTY, PLANT AND EQUIPMENT [Abstract]	'
Schedule of Property, Plant and Equipment	'
		September 30,			December 31,
		2014			2013
		(in millions)
	Land	$	43.1		$	43.6
	Rights-of-way		829.4			666.2
	Pipelines		9,617.30			8,035.80
	Pumping equipment, buildings and tanks		2,831.00			2,233.00
	Compressors, meters and other operating equipment		2,124.10			1,989.80
	Vehicles, office furniture and equipment		417.4			322
	Processing and treating plants		514.2			514.4
	Construction in progress		1,329.00			2,077.70
	Total property, plant and equipment		17,705.50			15,882.50
	Accumulated depreciation		(2,667.4	)		(2,705.7	)
	Property, plant and equipment, net	$	15,038.10		$	13,176.80

DEBT_Tables

DEBT (Tables)	9 Months Ended
	Sep. 30, 2014
DEBT [Abstract]	'
Schedule of Debt Obligations	'
				30-Sep-14			31-Dec-13
				(in millions)
	EEP debt obligations:
	Commercial Paper			$	1,100.00		$	300
	5.350% Senior Notes due 2014				200			200
	5.875% Senior Notes due 2016				299.9			299.9
	7.000% Senior Notes due 2018				99.9			99.9
	6.500% Senior Notes due 2018				399.3			399.1
	9.875% Senior Notes due 2019				500			500
	5.200% Senior Notes due 2020				499.9			499.9
	4.200% Senior Notes due 2021				599.2			599.1
	7.125% Senior Notes due 2028				99.8			99.8
	5.950% Senior Notes due 2033				199.8			199.8
	6.300% Senior Notes due 2034				99.8			99.8
	7.500% Senior Notes due 2038				399.1			399
	5.500% Senior Notes due 2040				546.4			546.4
	8.050% Junior subordinated notes due 2067				399.8			399.7
	MEP debt obligations:
	MEP Credit Agreement				365			335
	3.560% MEP Series A Senior Notes due 2019				75			-
	4.040% MEP Series B Senior Notes due 2021				175			-
	4.420% MEP Series C Senior Notes due 2024				150			-
	Total			$	6,207.90		$	4,977.40
Schedule of Interest Costs	'
				For the three month						For the nine month
				period ended September 30,						period ended September 30,
				2014			2013			2014			2013
				(in millions)
	Interest expense			$	137.1		$	70.5		$	294.2		$	226.4
	Interest capitalized				11.6			13.4			35.7			39.8
	Interest cost incurred			$	148.7		$	83.9		$	329.9		$	266.2
	Weighted average interest rate				6	%		6.3	%		6.2	%		6.1	%
Schedule of Line of Credit Facilities	'
					(in millions)
		Total credit available under Credit Facilities			$	2,625.00
		Less: Amounts outstanding under Credit Facilities				-
			Principal amount of commercial paper outstanding			1,100.00
			Letters of credit outstanding			183.6
		Total amount available at September 30, 2014			$	1,341.40

PARTNERS_CAPITAL_Tables

PARTNERS' CAPITAL (Tables)	9 Months Ended
	Sep. 30, 2014
PARTNERS' CAPITAL [Abstract]	'
Schedule of Distributions	'
													Amount of
											Cash		Distribution		Retained
											available		of i-units to		from
	Distribution			Distribution			Distribution				for		i-unit		General		Distribution
	Declaration Date		Record Date	Payment Date			per Unit				distribution		Holders (1)		Partner (2)		of Cash
							(in millions, except per unit amounts)
		31-Jul-14	7-Aug-14	14-Aug-14			$	0.555			$	224.7	$	36.7	$	0.8	$	187.3
		30-Apr-14	8-May-14	15-May-14			$	0.5435			$	214.5	$	35.3	$	0.7	$	178.5
		30-Jan-14	7-Feb-14	14-Feb-14			$	0.5435			$	213.7	$	34.6	$	0.7	$	178.4
	_______________________________
	(1)
	We issued 3,517,795 i-units to Enbridge Management, the sole owner of our i-units, during 2014 in lieu of cash distributions.
	(2)
	We retained an amount equal to 2% of the i-unit distribution from our General Partner to maintain its 2% general partner interest in us.
Schedule of Changes in Partners' Capital Attributable to General And Limited Partners	'
				For the nine month
				period ended
				September 30,
				2014				2013
				(in millions)
	Series 1 Preferred interests
	Beginning balance			$	1,160.70			$	-
	Proceeds from issuance of preferred units				-				1,200.00
	Net income				67.5				35.8
	Accretion of discount on preferred units				11.1				5.7
	Distribution payable				(67.5	)			(35.8	)
	Beneficial conversion feature of preferred units				-				(47.7	)
	Ending balance			$	1,171.80			$	1,158.00
	General and limited partner interests
	Beginning balance			$	4,637.70			$	4,774.90
	Proceeds from issuance of partnership interests, net of costs				-				519.3
	Net income				157.7				21.5
	Distributions				(544.2	)			(530.6	)
	Beneficial conversion feature of preferred units				-				47.7
	Transfer of interests in subsidiary to Midcoast Energy Partners, L.P.				(125.4	)			-
	Ending balance			$	4,125.80			$	4,832.80
	Accumulated other comprehensive loss
	Beginning balance			$	(76.6	)		$	(320.5	)
	Changes in fair value of derivative financial instruments reclassified to earnings				22.2				21.3
	Changes in fair value of derivative financial instruments recognized in other
	comprehensive income (loss)				(104.6	)			156.4
	Ending balance			$	(159.0	)		$	(142.8	)
	Noncontrolling interest
	Beginning balance			$	1,975.60			$	793.5
	Capital contributions				1,083.00				355.2
	Transfer of interests in subsidiary to Midcoast Energy Partners, L.P.				125.4				-
	Other comprehensive loss allocated to noncontrolling interest				1.8				-
	Net income				149.4				54.3
	Distributions to noncontrolling interest				(80.9	)			(39.7	)
	Ending balance			$	3,254.30			$	1,163.30
	Total partners' capital at end of period			$	8,392.90			$	7,011.30

RELATED_PARTY_TRANSACTIONS_Tab

RELATED PARTY TRANSACTIONS (Tables)	9 Months Ended
	Sep. 30, 2014
RELATED PARTY TRANSACTIONS [Abstract]	'
Schedule of Transactions with Affiliates	'
				For the three month period ended September 30,								For the nine month period ended September 30,
				2014				2013				2014			2013
				(in millions)
		Operating and administrative - affiliate		$	115.9			$	111.5			$	353.6		$	329.1
				For the three month period ended September 30,								For the nine month period ended September 30,
				2014				2013				2014			2013
				(in millions)
		Operating revenue - affiliate		$	68.3			$	65.4			$	229.4		$	204.8
		Cost of natural gas - affiliate		$	29.7			$	22.8			$	98.3		$	95.3
Schedule of Distributions	'
	Distribution		Distribution		Amount Paid to				Amount Paid to the				Total MEP
	Declaration Date		Payment Date		EEP				noncontrolling interest				Distribution
					(in millions)
	31-Jul-14		14-Aug-14		$	8.1			$	6.9			$	15
	29-Apr-14		15-May-14			7.8				6.6				14.4
	29-Jan-14		14-Feb-14			4.2				3.5				7.7
					$	20.1			$	17			$	37.1
	Distribution		Distribution		Amount Paid to				Amount paid to the				Total Series AC
	Declaration Date		Payment Date		Partnership				noncontrolling interest				Distribution
					(in millions)
	31-Jul-14		14-Aug-14		$	7.4			$	14.8			$	22.2
	30-Apr-14		15-May-14			6.6				13.1				19.7
	30-Jan-14		14-Feb-14			6.4				12.8				19.2
					$	20.4			$	40.7			$	61.1
	Distribution		Distribution		Amount Paid to				Amount Paid to the				Total Series EA
	Declaration Date		Payment Date		EEP				noncontrolling interest				Distribution
					(in millions)
	31-Jul-14		14-Aug-14		$	5.6			$	16.7			$	22.3
	29-Apr-14		15-May-14			2.5				6.5				9
					$	8.1			$	23.2			$	31.3
Schedule of Cash Activity for A1 Credit Facility and A1 Term Note	'
					A1 Term Note
					September 30,
					2014				2013
					(in millions)
		Beginning Balance			$	318			$	330
		Borrowings				-				-
		Repayments				(12.0	)			(12.0	)
		Ending Balance			$	306			$	318

COMMITMENTS_AND_CONTINGENCIES_

COMMITMENTS AND CONTINGENCIES (Tables)	9 Months Ended
	Sep. 30, 2014
COMMITMENTS AND CONTINGENCIES [Abstract]	'
Material Components Underlying Estimated Loss For Cleanup, Remediation And Restoration	'
			(in millions)
		Response Personnel & Equipment	$	551.6
		Environmental Consultants		227
		Professional, regulatory and other		429.4
		Total	$	1,208.00

DERIVATIVE_FINANCIAL_INSTRUMEN1

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Tables)	9 Months Ended
	Sep. 30, 2014
DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES [Abstract]	'
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value	'
					September 30,				December 31,
					2014				2013
					(in millions)
		Other current assets			$	37.8			$	21.2
		Other assets, net				36.2				74.4
		Accounts payable and other (1)				(25.6	)			(172.0	)
		Other long-term liabilities				(267.9	)			(12.3	)
		Due from general partner and affiliates				0.4				-
					$	(219.1	)		$	(88.7	)
		______________________________
	(1)
	Includes $16.7 million of cash collateral at December 31, 2013.
Schedule of Derivative Balances by Counter Party Credit Quality	'
					September 30,				December 31,
					2014				2013
					(in millions)
		Counterparty Credit Quality (1)
		AAA			$	0.3			$	0.3
		AA				(91.0	)			(49.7	)
		A (2)				(134.0	)			(40.1	)
		Lower than A				5.6				0.8
					$	(219.1	)		$	(88.7	)
		______________________________
		-1
		As determined by nationally-recognized statistical ratings organizations.
	(2)
	Includes $16.7 million of cash collateral at December 31, 2013.
Schedule of Credit Concentrations in Industry Sectors	'
					September 30,				December 31,
					2014				2013
					(in millions)
		United States financial institutions and investment banking entities			$	(176.3	)		$	(85.0	)
		Non-United States financial institutions (1)				(49.3	)			0.8
		Other				6.5				(4.5	)
					$	(219.1	)		$	(88.7	)
	______________________________
	(1)
	Includes $16.7 million of cash collateral at December 31, 2013.
Effect of Derivative Instruments on the Consolidated Statements of Financial Position	'
	Effect of Derivative Instruments on the Consolidated Statements of Financial Position
							Asset Derivatives								Liability Derivatives
							Fair Value at								Fair Value at
				Financial Position			September 30,				December 31,				September 30,				December 31,
				Location			2014				2013				2014				2013
							(in millions)
	Derivatives designated as hedging instruments (1)
		Interest rate contracts		Other current assets			$	-			$	8.1			$	-			$	-
		Interest rate contracts		Other assets				16.9				57.1				-				-
		Interest rate contracts		Accounts payable and other(2)				-				11.9				(7.8	)			(145.5	)
		Interest rate contracts		Other long-term liabilities				-				-				(255.0	)			(11.3	)
		Commodity contracts		Other current assets				3.3				2				-				(0.6	)
		Commodity contracts		Other assets				1.3				3.5				-				(0.5	)
		Commodity contracts		Accounts payable and other				-				1.9				(2.2	)			(12.7	)
		Commodity contracts		Other long-term liabilities				-				0.6				(0.3	)			(1.4	)
								21.5				85.1				(265.3	)			(172.0	)
		Derivatives not designated as hedging instruments
		Commodity contracts		Other current assets				34.5				11.8				-				(0.1	)
		Commodity contracts		Other assets				18				17.6				-				(3.3	)
		Commodity contracts		Accounts payable and other				-				5.4				(15.6	)			(16.3	)
		Commodity contracts		Other long-term liabilities				-				-				(12.6	)			(0.2	)
		Commodity contracts		Due from general partner and affiliates				0.4				-				-				-
								52.9				34.8				(28.2	)			(19.9	)
		Total derivative instruments					$	74.4			$	119.9			$	(293.5	)		$	(191.9	)
		______________________________
	-1
	Includes items currently designated as hedging instruments. Excludes the portion of de-designated hedges which may have a component remaining in AOCI.
	-2
	Liability derivatives exclude $16.7 million of cash collateral at December 31, 2013.
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 September 30, 2014
	Interest rate contracts			$	44.1			Interest expense		$	(4.0	)		Interest expense		$	(62.2	)
	Commodity contracts				11.2			Cost of natural gas			(2.1	)		Cost of natural gas			0.9
	Total			$	55.3					$	(6.1	)				$	(61.3	)
	For the three month period ended September 30, 2013
	Interest rate contracts			$	1.7			Interest expense		$	(4.2	)		Interest expense		$	(1.1	)
	Commodity contracts				(17.2	)		Cost of natural gas			(0.6	)		Cost of natural gas			(0.5	)
	Total			$	(15.5	)				$	(4.8	)				$	(1.6	)
	For the nine month period ended September 30, 2014
	Interest rate contracts			$	(93.0	)		Interest expense		$	(12.1	)		Interest expense		$	(73.2	)
	Commodity contracts				7.9			Cost of natural gas			(12.4	)		Cost of natural gas			1.5
	Total			$	(85.1	)				$	(24.5	)				$	(71.7	)
	For the nine month period ended September 30, 2013
	Interest rate contracts			$	179.3			Interest expense		$	(24.3	)		Interest expense		$	(0.5	)
	Commodity contracts				(8.8	)		Cost of natural gas			3			Cost of natural gas			1.8
	Total			$	170.5					$	(21.3	)				$	1.3
	______________________________
	-1
	Includes only the ineffective portion of derivatives that are designated as hedging instruments and does not include net gains or losses associated with derivatives that do not qualify for hedge accounting treatment.
Components of Accumulated Other Comprehensive Income/(Loss)	'
	Components of Accumulated Other Comprehensive Income/(Loss)
					Cash Flow
					Hedges
					(in millions)
	Balance at December 31, 2013				$	(76.6	)
		Other Comprehensive Income before reclassifications (1)				(104.6	)
		Amounts reclassified from AOCI (2) (3)				22.2
		Tax benefit (expense)				-
			Net other comprehensive income		$	(82.4	)
	Balance at September 30, 2014				$	(159.0	)
	_______________________________________
	-1
	Excludes NCI loss of $0.5 million reclassified from AOCI at September 30, 2014.
	-2
	Excludes NCI gain of $2.3 million reclassified from AOCI at September 30, 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 September 30,															For the nine month period ended September 30,
								2014							2013								2014									2013
								(in millions)
	Losses (gains) on cash flow hedges:
	Interest Rate Contracts (1)										$	4							$	4.2							$		12.1						$	24.3
	Commodity Contracts (2) (3)											1.6								0.6									10.1							(3.0	)
	Total Reclassifications from AOCI										$	5.6							$	4.8							$		22.2						$	21.3
	______________________________
	-1
	Loss reported within "Interest expense" in the consolidated statements of income.
	-2
	Loss (gain) reported within "Cost of natural gas" in the consolidated statements of income.
	-3
	Excludes NCI gain of $0.5 million and $2.3 million reclassified from AOCI for the three and nine month periods ending September 30, 2014.
Effect of Derivative Instruments on Consolidated Statements of Income	'
	Effect of Derivative Instruments on Consolidated Statements of Income
					For the three month								For the nine month
					period ended								period ended
					September 30,								September 30,
					2014				2013  (2)				2014				2013  (2)
	Derivatives Not Designated		Location of Gain or (Loss)		Amount of Gain or (Loss)								Amount of Gain or (Loss)
	as Hedging Instruments		Recognized in Earnings (1)		Recognized in Earnings (3)								Recognized in Earnings (3)
					(in millions)
	Interest rate contracts		Interest expense (4)		$	—			$	0.1			$	—			$	—
	Commodity contracts		Operating revenue (5)			14.6				(16.7	)			10.1				(14.0	)
	Commodity contracts		Operating revenue—Affiliate			—				—				0.5				—
	Commodity contracts		Power			—				0.1				0.5				0.3
	Commodity contracts		Cost of natural gas (6)			9.5				(21.8	)			(9.9	)			(2.6	)
	Total				$	24.1			$	(38.3	)		$	1.2			$	(16.3	)
	(1)	Does not include settlements associated with derivative instruments that settle through physical delivery.
	(2)	The effects of derivative instruments on consolidated statements of income for the three and nine month periods ended September 30, 2013 have been revised to include settlement gains (losses) on derivatives not designated as hedge instruments of $(0.8) million and $1.8 million, respectively. The revisions to the disclosure had no impact on previously reported net income or earnings per unit.
	(3)	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.
	(4)	Includes settlement gains of $0.1 million and $0.3 million for the three and nine month periods ended September 30, 2013, respectively.
	(5)	Includes settlement gains (losses) of $0.6 million and $(0.7) million for the three month periods ended September 30, 2014 and September 30, 2013, respectively, and $0.9 million and $1.0 million for the nine month periods ended September 30, 2014 and September 30, 2013, respectively.
	(6)	Includes settlement gains (losses) of $0.2 million and $(0.2) million for the three month periods ended September 30, 2014 and September 30, 2013, respectively, and $(8.6) million and $0.5 million for the nine month periods ended September 30, 2014 and September 30, 2013, respectively.
Offsetting of Financial Assets and Derivative Assets	'
	Offsetting of Financial Assets and Derivative Assets
			As of September 30, 2014
			Gross				Gross Amount				Net Amount of Assets				Gross Amount				Net
			Amount of				Offset in the				Presented in the				Not Offset in the				Amount
			Recognized				Statement of				Statement of				Statement of
			Assets				Financial Position				Financial Position				Financial Position
			(in millions)
	Description:
	Derivatives		$	74.4			$	—			$	74.4			$	(33.6	)		$	40.8
	Total		$	74.4			$	—			$	74.4			$	(33.6	)		$	40.8
			As of December 31, 2013
			Gross				Gross Amount				Net Amount of Assets				Gross Amount				Net
			Amount of				Offset in the				Presented in the				Not Offset in the				Amount
			Recognized				Statement of				Statement of				Statement of
			Assets				Financial Position				Financial Position				Financial Position
			(in millions)
	Description:
	Derivatives		$	119.9			$	(24.3	)		$	95.6			$	(18.6	)		$	77
	Total		$	119.9			$	(24.3	)		$	95.6			$	(18.6	)		$	77
Offsetting of Financial Liabilities and Derivative Liabilities	'
	Offsetting of Financial Liabilities and Derivative Liabilities
			As of September 30, 2014
			Gross				Gross Amount				Net Amount of Liabilities				Gross Amount				Net
			Amount of				Offset in the				Presented in the				Not Offset in the				Amount
			Recognized				Statement of				Statement of				Statement of
			Liabilities				Financial Position				Financial Position				Financial Position
			(in millions)
	Description:
	Derivatives		$	(293.5	)		$	—			$	(293.5	)		$	33.6			$	(259.9	)
	Total		$	(293.5	)		$	—			$	(293.5	)		$	33.6			$	(259.9	)
			As of December 31, 2013
			Gross				Gross Amount				Net Amount  of Liabilities				Gross Amount				Net
			Amount of				Offset in the				Presented in the				Not Offset in the				Amount
			Recognized				Statement of				Statement of				Statement of
			Liabilities				Financial Position				Financial Position				Financial Position
			(in millions)
	Description:
	Derivatives (1)		$	(208.6	)		$	24.3			$	(184.3	)		$	18.6			$	(165.7	)
	Total		$	(208.6	)		$	24.3			$	(184.3	)		$	18.6			$	(165.7	)
	(1)	Includes $16.7 million of cash collateral at December 31, 2013.
Table Setting Forth By Level Within The Fair Value Hierarchy Financial Assets And Liabilities	'
					30-Sep-14																December 31, 2013
					Level 1				Level 2				Level 3				Total				Level 1				Level 2				Level 3				Total
					(in millions)
		Interest rate contracts (1)			$	-			$	(245.9	)		$	-			$	(245.9	)		$	-			$	(96.4	)		$	-			$	(96.4	)
		Commodity contracts:
		Financial				-				12.1				1.8				13.9				-				6.4				(6.9	)			(0.5	)
		Physical				-				-				7.6				7.6				-				-				(0.2	)			(0.2	)
		Commodity options				-				-				5.3				5.3				-				-				8.4				8.4
		Total			$	-			$	(233.8	)		$	14.7			$	(219.1	)		$	-			$	(90.0	)		$	1.3			$	(88.7	)
	_______________________________________
	(1)
	During the period, there were no significant transfers in or out of any of any of the Levels or between Levels.
Schedule of Quantitative Information on Level 3 Fair Value Measurements	'
	Quantitative Information About Level 3 Fair Value Measurements
				Fair Value at											Range (1)
				September 30,						Valuation		Unobservable											Weighted
	Contract Type			2014  (2)						Technique		Input			Lowest				Highest				Average			Units
	Commodity Contracts - Financial			(in millions)
	Natural Gas					$	(0.6	)		Market Approach		Forward Gas Price				3.49				4.74				4.01		MMBtu
	NGLs					$	2.4			Market Approach		Forward NGL Price				0.24				1.98				1.18		Gal
	Commodity Contracts - Physical
	Natural Gas					$	1.8			Market Approach		Forward Gas Price				2.03				4.83				4.04		MMBtu
	Crude Oil					$	(1.5	)		Market Approach		Forward Crude Price				83.03				94.98				90.86		Bbl
	NGLs					$	7.4			Market Approach		Forward NGL Price				0.23				2.05				1.08		Gal
	Power					$	(0.1	)		Market Approach		Forward Power Price				36.21				39.49				37.84		MWh
	Commodity Options
	Natural Gas, Crude and NGLs					$	5.3			Option Model		Option Volatility				14	%			40	%			28	%
	Total Fair Value					$	14.7
	(1)	Prices are in dollars per Millions of British Thermal Units, or MMBtu, for Natural Gas; dollars per Gallon, or Gal, for NGLs; dollars per barrel, or Bbl, for Crude Oil; and dollars per Megawatt hour, or MWh, for Power.
	(2)	Fair values include credit valuation adjustments of approximately $0.1 million of losses.
	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					$	-			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 Oil Price				86.37				103.04				97.24	Bbl
	NGLs					$	(0.1	)		Market Approach		Forward NGL Price				0.02				2.19				0.95	Gal
	Power					$	(0.7	)		Market Approach		Forward Power Price				32.4				38.98				35.07	MWh
	Commodity Options
	Natural Gas, Crude and NGLs					$	8.4			Option Model		Option Volatility				18	%			44	%			28	%
	Total Fair Value					$	1.3
	-1
	Prices are in dollars per Millions of British Thermal Units, or MMBtu, for Natural Gas; dollars per Gallon, or Gal, for NGLs; dollars per barrel, or Bbl, for Crude Oil; and dollars per Megawatt hour, or MWh, for Power.
	-2
	Fair values include credit valuation adjustments of approximately $0.1 million of gains.
Schedule of Reconciliation of Changes in Fair Value of Level 3 Financial Assets and Liabilities	'
						Commodity				Commodity
						Financial				Physical				Commodity
						Contracts				Contracts				Options				Total
						(in millions)
	Beginning balance as of January 1, 2014					$	(6.9	)		$	(0.2	)		$	8.4			$	1.3
	Transfer in (out) of Level 3 (1)						-				-				-				-
	Gains or losses:
	Included in earnings						(3.9	)			11.1				(1.1	)			6.1
	Included in other comprehensive income						(0.2	)			-				-				(0.2	)
	Purchases, issuances, sales and settlements:
	Purchases						-				-				0.4				0.4
	Sales						-				-				(1.6	)			(1.6	)
	Settlements (2)						12.8				(3.3	)			(0.8	)			8.7
	Ending balance as September 30, 2014					$	1.8			$	7.6			$	5.3			$	14.7
	Amount of changes in net assets attributable to the change in derivative
	gains or losses related to assets still held at the reporting date					$	2.4			$	7.2			$	(1.8	)		$	7.8
	Amounts reported in operating revenue					$	-			$	11.2			$	-			$	11.2
	-1
	Our policy is to recognize transfers as of the last day of the reporting period.
	-2
	Settlements represent the realized portion of forward contracts.
Schedule of Fair Values of Expected Cash Flows of Outstanding Commodity Based Swaps and Physical Contracts	'
					At September 30, 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			668,692			$	4			$	3.91			$	0.1			$	-			$	-			$	-
					NGL			623,000			$	56.02			$	56.64			$	0.3			$	(0.7	)		$	0.6			$	(0.4	)
					Crude Oil			95,000			$	89.87			$	92.56			$	-			$	(0.3	)		$	-			$	-
			Receive fixed/pay variable		Natural Gas			2,380,100			$	4.26			$	4.09			$	0.5			$	(0.1	)		$	0.1			$	(1.0	)
					NGL			2,021,140			$	51.91			$	50.97			$	3.7			$	(1.8	)		$	4.8			$	(12.7	)
					Crude Oil			457,764			$	95.26			$	90.14			$	2.7			$	(0.4	)		$	3.4			$	(5.4	)
			Receive variable/pay variable		Natural Gas			19,562,500			$	4.03			$	4.02			$	0.6			$	(0.5	)		$	0.6			$	(0.1	)
			Physical Contracts
			Receive variable/pay fixed		Natural Gas			313,224			$	3.89			$	1.23			$	0.8			$	-			$	-			$	-
					NGL			550,000			$	42.4			$	43.88			$	-			$	(0.8	)		$	0.9			$	(0.9	)
					Crude Oil			45,000			$	90.85			$	93.9			$	-			$	(0.1	)		$	-			$	-
			Receive fixed/pay variable		Natural Gas			185,506			$	4.03			$	3.97			$	-			$	-			$	-			$	-
					NGL			3,504,872			$	39.2			$	37.85			$	5.1			$	(0.4	)		$	0.4			$	(2.6	)
					Crude Oil			75,000			$	93.08			$	90.62			$	0.2			$	-			$	-			$	(0.4	)
			Pay fixed		Power (4)			14,716			$	37.84			$	46.59			$	-			$	(0.1	)		$	-			$	(0.7	)
			Receive variable/pay variable		Natural Gas			72,613,470			$	4.02			$	4.02			$	0.9			$	(1.1	)		$	0.9			$	(0.4	)
					NGL			10,947,422			$	42.8			$	42.61			$	2.7			$	(0.6	)		$	5.8			$	(3.7	)
					Crude Oil			758,914			$	88.26			$	90.52			$	0.8			$	(2.5	)		$	1.1			$	(1.2	)
	Portion of contracts maturing in 2015
			Swaps
			Receive variable/pay fixed		Natural Gas			316,837			$	3.91			$	3.93			$	-			$	-			$	-			$	-
					NGL			145,850			$	72.56			$	78.2			$	-			$	(0.8	)		$	-			$	-
					Crude Oil			456,000			$	87.81			$	92.94			$	-			$	(2.3	)		$	-			$	-
			Receive fixed/pay variable		Natural Gas			809,761			$	4.56			$	4.21			$	0.3			$	-			$	-			$	-
					NGL			1,024,750			$	54.42			$	52.36			$	3.1			$	(1.0	)		$	1.5			$	(1.1	)
					Crude Oil			1,303,165			$	96.75			$	87.78			$	11.7			$	-			$	8.3			$	-
			Receive variable/pay variable		Natural Gas			42,725,000			$	3.92			$	3.94			$	0.8			$	(1.7	)		$	0.1			$	-
			Physical Contracts
			Receive variable/pay fixed		NGL			95,000			$	46.73			$	48.37			$	-			$	(0.2	)		$	-			$	-
			Receive fixed/pay variable		NGL			586,394			$	49.38			$	47.79			$	1			$	-			$	-			$	-
			Receive variable/pay variable		Natural Gas			108,991,322			$	4.05			$	4.05			$	1.4			$	(0.7	)		$	0.5			$	(0.1	)
					NGL			3,094,719			$	61.4			$	61.19			$	1.2			$	(0.5	)		$	-			$	-
					Crude Oil			151,000			$	90.3			$	88.89			$	0.2			$	-			$	-			$	-
	Portion of contracts maturing in 2016
			Swaps
			Receive variable/pay fixed		Natural Gas			181,435			$	3.78			$	3.85			$	-			$	-			$	-			$	-
					Crude Oil			68,250			$	86.36			$	90			$	-			$	(0.2	)		$	-			$	-
			Receive fixed/pay variable		Crude Oil			68,250			$	90.89			$	86.36			$	0.3			$	-			$	0.7			$	-
			Receive variable/pay variable		Natural Gas			12,027,000			$	3.96			$	3.98			$	0.1			$	(0.3	)		$	-			$	-
			Physical Contracts
			Receive variable/pay variable		Natural Gas			34,560,879			$	4.06			$	4.05			$	0.7			$	(0.4	)		$	0.1			$	-
	Portion of contracts maturing in 2017
			Physical Contracts
			Receive variable/pay variable		Natural Gas			14,299,743			$	4.27			$	4.26			$	0.2			$	(0.1	)		$	-			$	-
			______________________________
	-1
	Volumes of natural gas are measured in MMBtu, whereas volumes of NGL and crude oil are measured in Bbl. Our power purchase agreements are measured in MWh.
	-2
	Weighted average prices received and paid are in $/MMBtu for natural gas, $/Bbl for NGL and crude oil and $/MWh for power.
	-3
	The fair value is determined based on quoted market prices at September 30, 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 $0.2 million of losses and $0.1 million of gains at September 30, 2014 and December 31, 2013, respectively.
	-4
	For physical power, the receive price shown represents the index price used for valuation purposes.
Schedule of Fair Values of Expected Cash Flows of Outstanding Commodity Options	'
					At September 30, 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			1,104,000			$	3.9			$	4.1			$	0.1			$	-			$	0.7			$	-
					NGL			193,200			$	54.79			$	52.43			$	0.9			$	-			$	2.9			$	-
			Calls (written)		NGL			115,000			$	60.92			$	54.59			$	-			$	(0.1	)		$	-			$	(1.0	)
			Puts (written)		Natural Gas			1,104,000			$	3.9			$	4.1			$	-			$	(0.1	)		$	-			$	(0.5	)
					NGL			32,200			$	66.36			$	51.7			$	-			$	(0.5	)		$	-			$	-
			Calls (purchased)		NGL			46,000			$	50.4			$	43.84			$	-			$	-			$	-			$	-
					Portion of option contracts maturing in 2015
			Puts (purchased)		Natural Gas			4,015,000			$	3.9			$	4			$	1.4			$	-			$	1.7			$	-
					NGL			1,350,500			$	48.75			$	50.62			$	5.5			$	-			$	6			$	-
					Crude Oil			547,500			$	85.42			$	87.76			$	2.3			$	-			$	1.8			$	-
			Calls (written)		Natural Gas			1,277,500			$	5.05			$	4			$	-			$	(0.1	)		$	-			$	(0.3	)
					NGL			529,250			$	55.18			$	50.29			$	-			$	(1.7	)		$	-			$	(1.0	)
					Crude Oil			547,500			$	91.75			$	87.76			$	-			$	(2.1	)		$	-			$	(1.9	)
			Puts (written)		Natural Gas			4,015,000			$	3.9			$	4			$	-			$	(1.4	)		$	-			$	-
			Calls (purchased)		Natural Gas			1,277,500			$	5.05			$	4			$	0.1			$	-			$	-			$	-
					Portion of option contracts maturing in 2016
			Puts (purchased)		Natural Gas			1,647,000			$	3.75			$	4.08			$	0.5			$	-			$	-			$	-
					NGL			1,281,000			$	41.82			$	44.06			$	6.5			$	-				-				-
					Crude Oil			439,200			$	80			$	85.93			$	2			$	-				-				-
			Calls (written)		Natural Gas			1,647,000			$	4.98			$	4.08			$	-			$	(0.3	)		$	-			$	-
					NGL			1,281,000			$	48.59			$	44.06			$	-			$	(5.6	)			-				-
					Crude Oil			439,200			$	92.25			$	85.93			$	-			$	(2.2	)			-				-
	______________________________
	-1
	Volumes of natural gas are measured in MMBtu, whereas volumes of NGL and crude oil are measured in Bbl.
	-2
	Strike and market prices are in $/MMBtu for natural gas and in $/Bbl for NGL and crude oil.
	-3
	The fair value is determined based on quoted market prices at September 30, 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.
Schedule of Current Interest Rate Derivatives	'
										Average				Fair Value (2)  at
	Date of Maturity & Contract Type			Accounting Treatment			Notional			Fixed Rate (1)				30-Sep-14				December 31, 2013
							(dollars in millions)
	Contracts maturing in 2015
		Interest Rate Swaps—Pay Fixed		Cash Flow Hedge			$	510			1.53	%		$	(1.9	)		$	(6.8	)
		Contracts maturing in 2016
		Interest Rate Swaps—Pay Fixed		Cash Flow Hedge			$	90			0.55	%		$	-				-
		Contracts maturing in 2017
		Interest Rate Swaps—Pay Fixed		Cash Flow Hedge			$	450			2.21	%		$	(12.2	)		$	(13.8	)
		Contracts maturing in 2018
		Interest Rate Swaps—Pay Fixed		Cash Flow Hedge			$	810			2.24	%		$	1.4			$	3.3
		Contracts maturing in 2019
		Interest Rate Swaps—Pay Fixed		Cash Flow Hedge			$	620			2.96	%		$	(1.0	)		$	-
		Contracts settling prior to maturity
		2014—Pre-issuance Hedges (3)		Cash Flow Hedge			$	-			0	%		$	-			$	(132.7	)
		2015—Pre-issuance Hedges		Cash Flow Hedge			$	1,000			5.48	%		$	(208.5	)			-
		2016—Pre-issuance Hedges		Cash Flow Hedge			$	500			4.21	%		$	(38.0	)		$	60.8
		2017—Pre-issuance Hedges		Cash Flow Hedge			$	500			3.69	%		$	(10.8	)			-
		2018—Pre-issuance Hedges		Cash Flow Hedge			$	350			3.08	%		$	12.4				-
		__________________________
	(1)
	Interest rate derivative contracts are based on the one-month or three-month London Interbank Offered Rate, or LIBOR.
	(2)
	The fair value is determined from quoted market prices at September 30, 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 $12.7 million of gains at September 30, 2014 and $7.1 million of losses at December 31, 2013.
	(3)
	Includes $16.7 million of cash collateral at December 31, 2013.

SEGMENT_INFORMATION_Tables

SEGMENT INFORMATION (Tables)	9 Months Ended
	Sep. 30, 2014
SEGMENT INFORMATION [Abstract]	'
Schedule of Segment Reporting Information, By Segment	'
			For the three month period ended September 30, 2014
			Liquids			Natural Gas				Corporate (1)				Total
			(in millions)
	Operating revenue		$	542.9		$	1,399.40			$	-			$	1,942.30
	Cost of natural gas			-			1,238.20				-				1,238.20
	Environmental costs, net of recoveries			50.1			-				-				50.1
	Operating and administrative			126.5			105				3.8				235.3
	Power			59.5			-				-				59.5
	Depreciation and amortization			79.3			39.5				-				118.8
				315.4			1,382.70				3.8				1,701.90
	Operating income (loss)			227.5			16.7				(3.8	)			240.4
	Interest expense, net			-			-				137.1				137.1
	Allowance for equity used during construction			-			-				14.5				14.5
	Other income (expense) (2)			-			6.1				(4.3	)			1.8
	Income (loss) before income tax expense			227.5			22.8				(130.7	)			119.6
	Income tax expense			-			-				2.1				2.1
	Net income (loss)			227.5			22.8				(132.8	)			117.5
	Less: Net income attributable to:
	Noncontrolling interest			-			-				70.7				70.7
	Series 1 preferred unit distributions			-			-				22.5				22.5
	Accretion of discount on Series 1 preferred units			-			-				3.8				3.8
	Net income (loss) attributable to general and limited partner ownership interests in Enbridge Energy Partners, L.P.		$	227.5		$	22.8			$	(229.8	)		$	20.5
	______________________________
	(1)
	Corporate consists of interest expense, interest income, allowance for equity used during construction, noncontrolling interest and other costs such as income taxes, which are not allocated to the business segments.
	2)
	Other income (expense) for our Natural Gas segment includes our equity investment in the Texas Express NGL system which we began recognizing operating costs during the fourth quarter of 2013.
				For the three month period ended September 30, 2013
				Liquids			Natural Gas				Corporate (1)				Total
				(in millions)
	Operating revenue			$	401.5		$	1,387.90			$	-			$	1,789.40
	Cost of natural gas				-			1,257.50				-				1,257.50
	Environmental costs, net of recoveries				0.6			-				-				0.6
	Operating and administrative				149.7			113.6				1.8				265.1
	Power				43			-				-				43
	Depreciation and amortization				63.8			35.8				-				99.6
					257.1			1,406.90				1.8				1,665.80
	Operating income (loss)				144.4			(19.0	)			(1.8	)			123.6
	Interest expense, net				-			-				70.5				70.5
	Allowance for equity used during construction				-			-				9.3				9.3
	Other income				-			-				0.4				0.4
	Income (loss) before income tax expense				144.4			(19.0	)			(62.6	)			62.8
	Income tax expense				-			-				1.5				1.5
	Net income (loss)				144.4			(19.0	)			(64.1	)			61.3
	Less: Net income attributable to the noncontrolling interest				-			-				20.3				20.3
	Series 1 preferred unit distributions				-			-				22.7				22.7
	Accretion of discount on Series 1 preferred units				-			-				3.4				3.4
	Net income (loss) attributable to general and limited partner ownership interests in Enbridge Energy Partners, L.P.			$	144.4		$	(19.0	)		$	(110.5	)		$	14.9
	______________________________
	-1
	Corporate consists of interest expense, interest income, allowance for equity used during construction, noncontrolling interest and other costs such as income taxes, which are not allocated to the business segments.
					As of and for the nine month period ended September 30, 2014
					Liquids						Natural Gas								Corporate (1)						Total
					(in millions)
	Operating revenue					$		1,449.90						$		4,443.10					$	-					$	5,893.00
	Cost of natural gas							-								3,986.70						-						3,986.70
	Environmental costs, net of recoveries							93.3								-						-						93.3
	Operating and administrative							352.5								317.5						6.9						676.9
	Power							164.1								-						-						164.1
	Depreciation and amortization							222.7								113.3						-						336
								832.6								4,417.50						6.9						5,257.00
	Operating income (loss)							617.3								25.6						(6.9		)				636
	Interest expense, net							-								-						294.2						294.2
Allowance for equity used during construction							-								-						47.8						47.8
Other income (expense)							-								7.1		-2				(4.9		)				2.2
Income (loss) before income tax expense							617.3								32.7						(258.2		)				391.8
Income tax expense							-								-						6.1						6.1
Net income (loss)							617.3								32.7						(264.3		)				385.7
Less: Net income attributable to:
Noncontrolling interest							-								-						149.4						149.4
Series 1 preferred unit distributions							-								-						67.5						67.5
Accretion of discount on Series 1 preferred units							-								-						11.1						11.1
Net income (loss) attributable to general and limited partner ownership interests in Enbridge Energy Partners, L.P.					$		617.3						$		32.7					$	(492.3		)			$	157.7
Total assets					$		11,252.80						$		5,461.90		-3			$	232.4					$	16,947.10
Capital expenditures (excluding acquisitions)					$		1,861.30						$		158.4					$	3.2					$	2,022.90
______________________________
-1
	Corporate consists of interest expense, interest income, allowance for equity used during construction, noncontrolling interest and other costs such as income taxes, which are not allocated to the business segments.
-2
	Other income (expense) for our Natural Gas segment includes our equity investment in the Texas Express NGL system which began recognizing operating costs during the fourth quarter of 2013.
-3
	Total assets for our Natural Gas segment includes our long term equity investment in the Texas Express NGL system.
					As of and for the nine month period ended September 30, 2013
					Liquids						Natural Gas								Corporate (1)						Total
					(in millions)
Operating revenue							$	1,100.70							$	4,054.40					$	-					$	5,155.10
Cost of natural gas								-								3,564.40						-						3,564.40
Environmental costs, net of recoveries								184.3								-						-						184.3
Operating and administrative								334.8								337.8						5.4						678
Power								105.8								-						-						105.8
Depreciation and amortization								181								106.6						-						287.6
								805.9								4,008.80						5.4						4,820.10
Operating income (loss)								294.8								45.6						(5.4	)					335
Interest expense, net								-								-						226.4						226.4
Allowance for equity used during construction								-								-						25.2						25.2
Other income								-								-						1						1
Income (loss) before income tax expense								294.8								45.6						(205.6	)					134.8
Income tax expense								-								-						17.5						17.5
Net income (loss)								294.8								45.6						(223.1	)					117.3
Less: Net income attributable to the noncontrolling interest								-								-						54.3						54.3
Series 1 preferred unit distributions								-								-						35.8						35.8
Accretion of discount on Series 1 preferred units								-								-						5.7						5.7
Net income (loss) attributable to general and limited partner ownership interests in Enbridge Energy Partners, L.P.							$	294.8							$	45.6					$	(318.9	)				$	21.5
Total assets							$	8,497.90							$	5,224.60		-2			$	161.5					$	13,884.00
Capital expenditures (excluding acquisitions)							$	1,527.20							$	191.9					$	13.9					$	1,733.00
______________________________
-1
Corporate consists of interest expense, interest income, allowance for equity used during construction, noncontrolling interest and other costs such as income taxes, which are not allocated to the business segments.
-2
Total assets for our Natural Gas segment includes our long term equity investment in the Texas Express NGL system.

REGULATORY_MATTERS_Tables

REGULATORY MATTERS (Tables)	9 Months Ended
	Sep. 30, 2014
REGULATORY MATTERS [Abstract]	'
Over and Under Recovery Revenue Adjustments and Net Regulatory Asset Amortization	'
			For the three month					For the nine month
			period ended September 30,					period ended September 30,
			2014			2013		2014			2013
			(in millions)					(in millions)
	Current Year (Over)/Under Recovery Revenue Adjustments		$	(4.5	)	$	3.2	$	(5.6	)	$	7.7
	Amortization of Prior Year Regulatory (Asset)/Liability			—			3.8		(7.7	)(1)		11.5
	-1	The amortization of the prior year regulatory asset for the nine month period ended September 30, 2014, includes a $7.6 million adjustment of the regulatory asset for the difference between estimates as of December 31, 2013, and actual data received during the nine month period ended September 30, 2014.

SUPPLEMENTAL_CASH_FLOWS_INFORM1

SUPPLEMENTAL CASH FLOWS INFORMATION (Tables)	9 Months Ended
	Sep. 30, 2014
SUPPLEMENTAL CASH FLOWS INFORMATION [Abstract]	'
Schedule of Supplemental Cash Flow Information	'
			For the nine month
			period ended September 30,
			2014			2013
			(in millions)
		Additions to property, plant and equipment	$	2,055.80		$	1,514.50
		Increase (decrease) in construction payables		(32.9	)		218.5
		Total capital expenditures (excluding "Investment in joint venture")	$	2,022.90		$	1,733.00

NET_INCOME_PER_LIMITED_PARTNER2

NET INCOME PER LIMITED PARTNER UNIT (Narrative) (Details) (USD $)	3 Months Ended	9 Months Ended
In Millions, except Share data, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2014
Class D Units [Member]	'	'
Number of units issued in transaction	66,100,000	'
Conversion ratio	'	100.00%
Redemption term	'	'30 years
Redemption rate	'	105.00%
Notional value	'	$31.35
Preference in liquidation	20.00%	20.00%
Preference in liquidation, annual increase	'	20.00%
Maximum preference in liquidation	'	100.00%
Fair value of capital distribution	$2,480	'
Incentive Distribution Units [Member]	'	'
Number of units issued in transaction	1,000	'
Percentage Distributed to General Partner	'	23.00%
Portion of Quarterly Distribution Per Unit Minimum	'	$0.54
Distribution period	'	'5 years
Fair value of capital distribution	$491.70	'

NET_INCOME_PER_LIMITED_PARTNER3

NET INCOME PER LIMITED PARTNER UNIT (Formula for Distributing Available Cash in Partnership Agreement) (Details) (USD $)	3 Months Ended		6 Months Ended
	Sep. 30, 2014		Jun. 30, 2014
Minimum Quarterly Distribution [Member]	'		'
Portion of Quarterly Distribution Per Unit, maximum	$0.53		$0.30
Percentage Distributed to General Partner amd IDUs	2.00%	[1]	2.00%
Percentage Distributed To Limited Partners	98.00%		98.00%
First Target Distribution [Member]	'		'
Portion of Quarterly Distribution Per Unit, minimum	$0.53		$0.30
Portion of Quarterly Distribution Per Unit, maximum	'		$0.35
Percentage Distributed to General Partner amd IDUs	25.00%	[1]	15.00%
Percentage Distributed To Limited Partners	75.00%		85.00%
Second Target Distribution [Member]	'		'
Portion of Quarterly Distribution Per Unit, minimum	'		$0.35
Portion of Quarterly Distribution Per Unit, maximum	'		$0.50
Percentage Distributed to General Partner amd IDUs	'		25.00%
Percentage Distributed To Limited Partners	'		75.00%
Over Second Target Distribution [Member]	'		'
Portion of Quarterly Distribution Per Unit, minimum	'		$0.50
Percentage Distributed to General Partner amd IDUs	'		50.00%
Percentage Distributed To Limited Partners	'		50.00%
[1]	For distributions in excess of the Minimum Quarterly Distribution, this percentage includes both the General Partner's distributions of 2% and the distribution to the Incentive Distribution Unit holder, a wholly-owned subsidiary of our General Partner.

NET_INCOME_PER_LIMITED_PARTNER4

NET INCOME PER LIMITED PARTNER UNIT (Basic and Diluted Net Income Per Limited Partner Unit) (Details) (USD $)	3 Months Ended				9 Months Ended
In Millions, except Share data, unless otherwise specified	Sep. 30, 2014		Sep. 30, 2013		Sep. 30, 2014		Sep. 30, 2013
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]	'		'		'		'
Net income	$117.50		$61.30		$385.70		$117.30
Less: Net income attributable to noncontrolling interest	-70.7		-20.3		-149.4		-54.3
Less: Net income attributable to Series 1 preferred unit distributions	-22.5		-22.7		-67.5		-35.8
Less: Net income attributable to Accretion of discount on Series 1 preferred units	-3.8		-3.4		-11.1		-5.7
Net income attributable to general and limited partner ownership interests in Enbridge Energy Partners, L.P.	20.5		14.9		157.7		21.5
Incentive distributions	-1.4		-32.9		-35.9		-96.8
Total distributed earnings to our General Partner, Class D units, and IDUs	-39		-36.5		-118.3		-107.4
Total distributed earnings attributed to our common units and i-units	-182.8		-176.5		-542.7		-518.6
Total distributed earnings	-221.8		-213		-661		-626
Overdistributed earnings	-201.3		-198.1		-503.3		-604.5
Weighted average limited partner units outstanding	328,800,000		317,400,000		327,600,000		313,200,000
Basic and diluted earnings per unit:	'		'		'		'
Distributed earnings per unit	$0.56	[1]	$0.56	[1]	$1.66	[1]	$1.66	[1]
Overdistributed earnings per limited partner unit	($0.60)	[2]	($0.61)	[2]	($1.51)	[2]	($1.89)	[2]
Net income (loss) per unit (basic)	($0.04)		($0.05)		$0.15		($0.23)
Net income (loss) per unit (diluted)	($0.04)		($0.05)		$0.15		($0.23)
Preferred Stock [Member]	'		'		'		'
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]	'		'		'		'
Anti-dilutive Preferred Units excluded	43,201,310		'		43,201,310		'
Class D Units [Member]	'		'		'		'
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]	'		'		'		'
Anti-dilutive Preferred Units excluded	66,100,000		'		22,275,458		'
General Partner [Member]	'		'		'		'
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]	'		'		'		'
Distributed earnings attributed to our General Partner and Class D Units	-4.5		-3.6		-12.6		-10.6
Class D Units [Member]	'		'		'		'
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]	'		'		'		'
Distributed earnings attributed to our General Partner and Class D Units	($33.10)		'		($69.80)		'
[1]	Represents the total distributed earnings to common units and i-units divided by the weighted average number of limited partner interests outstanding for the period.
[2]	Represents the common unit's and i-unit's share (98%) of distributions in excess of earnings divided by the weighted average number of common units and i-units outstanding for the period and overdistributed earnings allocated to the common units and i-units based on the distribution waterfall that is outlined in our partnership agreement.

CASH_AND_CASH_EQUIVALENTS_Deta

CASH AND CASH EQUIVALENTS (Details) (USD $)	Sep. 30, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
CASH AND CASH EQUIVALENTS [Abstract]	'	'
Accounts payable and other	$16.20	$24

INVENTORY_Details

INVENTORY (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013
INVENTORY [Abstract]	'	'	'	'	'
Materials and supplies	$2.20	'	$2.20	'	$2.10
Crude oil inventory	12.3	'	12.3	'	18
Natural gas and NGL inventory	206.6	'	206.6	'	74.8
Inventory, Net, Total	221.1	'	221.1	'	94.9
Charges related to cost of natural gas	$1.50	$0.90	$4.80	$3.30	'

PROPERTY_PLANT_AND_EQUIPMENT_S

PROPERTY, PLANT AND EQUIPMENT (Schedule of Property, Plant and Equipment) (Details) (USD $)	Sep. 30, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Property, Plant and Equipment [Line Items]	'	'
Property, plant and equipment	$17,705.50	$15,882.50
Accumulated depreciation	-2,667.40	-2,705.70
Property, plant and equipment, net	15,038.10	13,176.80
Land [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Property, plant and equipment	43.1	43.6
Rights-of-Way [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Property, plant and equipment	829.4	666.2
Pipelines [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Property, plant and equipment	9,617.30	8,035.80
Pumping Equipment, Buildings and Tanks [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Property, plant and equipment	2,831	2,233
Compressors, Meters and Other Operating Equipment [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Property, plant and equipment	2,124.10	1,989.80
Vehicles, Office Furniture and Equipment [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Property, plant and equipment	417.4	322
Processing and Treating Plants [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Property, plant and equipment	514.2	514.4
Construction in Progress [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Property, plant and equipment	$1,329	$2,077.70

PROPERTY_PLANT_AND_EQUIPMENT_A

PROPERTY, PLANT AND EQUIPMENT (ARO) (Details) (USD $)	9 Months Ended	3 Months Ended	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2014	Sep. 30, 2014	Sep. 30, 2014
		Line 6B Pre-Replacement Assets [Member]	Line 6B Pipeline [Member]	Line 3 Pipeline [Member]
Regulatory Liabilities [Line Items]	'	'	'	'
Asset retirement obligation	$100.60	'	$60	$40.60
Charge to accumulated depreciation	'	$282.50	'	'

DEBT_Debt_Obligations_Details

DEBT (Debt Obligations) (Details) (USD $)	9 Months Ended
	Sep. 30, 2014	Dec. 31, 2013
Debt Instrument [Line Items]	'	'
Carrying amount	$6,207,900,000	$4,977,400,000
Fixed Rate Debt Obligations [Member]	'	'
Debt Instrument [Line Items]	'	'
Approximate fair values of debt obligations	5,500,000,000	4,900,000,000
Commercial Paper [Member]	'	'
Debt Instrument [Line Items]	'	'
Carrying amount	1,100,000,000	300,000,000
Senior Notes [Member] | 5.350% Senior Notes due 2014 [Member]	'	'
Debt Instrument [Line Items]	'	'
Carrying amount	200,000,000	200,000,000
Interest rate	5.35%	'
Maturity date	31-Dec-14	'
Senior Notes [Member] | 5.875% Senior Notes due 2016 [Member]	'	'
Debt Instrument [Line Items]	'	'
Carrying amount	299,900,000	299,900,000
Interest rate	5.88%	'
Maturity date	31-Dec-16	'
Senior Notes [Member] | 7.000% Senior Notes due 2018 [Member]	'	'
Debt Instrument [Line Items]	'	'
Carrying amount	99,900,000	99,900,000
Interest rate	7.00%	'
Maturity date	31-Dec-18	'
Senior Notes [Member] | 6.500% Senior Notes due 2018 [Member]	'	'
Debt Instrument [Line Items]	'	'
Carrying amount	399,300,000	399,100,000
Interest rate	6.50%	'
Maturity date	31-Dec-18	'
Senior Notes [Member] | 9.875% Senior Notes due 2019 [Member]	'	'
Debt Instrument [Line Items]	'	'
Carrying amount	500,000,000	500,000,000
Interest rate	9.88%	'
Maturity date	31-Dec-19	'
Senior Notes [Member] | 5.200% Senior Notes due 2020 [Member]	'	'
Debt Instrument [Line Items]	'	'
Carrying amount	499,900,000	499,900,000
Interest rate	5.20%	'
Maturity date	31-Dec-20	'
Senior Notes [Member] | 4.200% Senior Notes due 2021 [Member]	'	'
Debt Instrument [Line Items]	'	'
Carrying amount	599,200,000	599,100,000
Interest rate	4.20%	'
Maturity date	31-Dec-21	'
Senior Notes [Member] | 7.125% Senior Notes due 2028 [Member]	'	'
Debt Instrument [Line Items]	'	'
Carrying amount	99,800,000	99,800,000
Interest rate	7.13%	'
Maturity date	31-Dec-28	'
Senior Notes [Member] | 5.950% Senior Notes due 2033 [Member]	'	'
Debt Instrument [Line Items]	'	'
Carrying amount	199,800,000	199,800,000
Interest rate	5.95%	'
Maturity date	31-Dec-33	'
Senior Notes [Member] | 6.300% Senior Notes due 2034 [Member]	'	'
Debt Instrument [Line Items]	'	'
Carrying amount	99,800,000	99,800,000
Interest rate	6.30%	'
Maturity date	31-Dec-34	'
Senior Notes [Member] | 7.500% Senior Notes due 2038 [Member]	'	'
Debt Instrument [Line Items]	'	'
Carrying amount	399,100,000	399,000,000
Interest rate	7.50%	'
Maturity date	31-Dec-38	'
Senior Notes [Member] | 5.500% Senior Notes due 2040 [Member]	'	'
Debt Instrument [Line Items]	'	'
Carrying amount	546,400,000	546,400,000
Interest rate	5.50%	'
Maturity date	31-Dec-40	'
Senior Notes [Member] | 3.560% Series A Senior Notes due 2019 [Member] | Midcoast Energy Partners [Member]	'	'
Debt Instrument [Line Items]	'	'
Carrying amount	75,000,000	'
Interest rate	3.56%	'
Maturity date	31-Dec-19	'
Senior Notes [Member] | 4.040% Series B Senior Notes due 2021 [Member] | Midcoast Energy Partners [Member]	'	'
Debt Instrument [Line Items]	'	'
Carrying amount	175,000,000	'
Interest rate	4.04%	'
Maturity date	31-Dec-21	'
Senior Notes [Member] | 4.420% Series C Senior Notes due 2024 [Member] | Midcoast Energy Partners [Member]	'	'
Debt Instrument [Line Items]	'	'
Carrying amount	150,000,000	'
Interest rate	4.42%	'
Maturity date	31-Dec-24	'
Credit Facilities [Member] | Midcoast Energy Partners [Member]	'	'
Debt Instrument [Line Items]	'	'
Carrying amount	365,000,000	335,000,000
8.050% Junior subordinated notes due 2067 [Member]	'	'
Debt Instrument [Line Items]	'	'
Carrying amount	$399,800,000	$399,700,000
Interest rate	8.05%	'
Maturity date	31-Dec-67	'

DEBT_Interest_Cost_Details

DEBT (Interest Cost) (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Interest Cost	'	'	'	'
Interest expense	$137.10	$70.50	$294.20	$226.40
Interest capitalized	11.6	13.4	35.7	39.8
Interest cost incurred	$148.70	$83.90	$329.90	$266.20
Weighted average interest rate	6.00%	6.30%	6.20%	6.10%

DEBT_Credit_Facility_Details

DEBT (Credit Facility) (Details) (USD $)	Sep. 30, 2014	Dec. 31, 2013	Sep. 30, 2014	Sep. 30, 2014	Sep. 30, 2014	Sep. 30, 2014
In Millions, unless otherwise specified			Credit Facility [Member]	Credit Facility [Member]	364-Day Credit Facility [Member]	Standby Letters of Credit [Member]
				Portion of Credit Facility Due in 2018 [Member]
Line of Credit Facility [Line Items]	'	'	'	'	'	'
Line of Credit Facility, Maximum Borrowing Capacity	'	'	$1,975	$175	$650	$220
Facility term	'	'	'	'	'364 days	'
Total Credit available under Credit Facilities	2,625	'	'	'	'	'
Less: Amounts outstanding under Credit Facilities	'	'	'	'	'	'
Principal amount of commercial paper outstanding	1,100	300	'	'	'	'
Letters of credit outstanding	183.6	'	'	'	'	'
Total amount we could borrow at balance sheet date	$1,341.40	'	'	'	'	'
Credit facility maturity date	'	'	26-Sep-19	26-Sep-18	3-Jul-15	'

DEBT_Commercial_Paper_Details

DEBT (Commercial Paper) (Details) (USD $)	9 Months Ended			9 Months Ended	12 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013	Sep. 30, 2014	Dec. 31, 2013
				Commercial Paper [Member]	Commercial Paper [Member]
Commercial paper aggregate principal amount supported by Credit Facilities	'	'	'	$1,500,000,000	'
Principal amount of commercial paper issuances	1,100,000,000	'	300,000,000	'	'
Weighted average interest rate of Commercial paper excluding the effect of interest rate hedging activities	'	'	'	0.33%	0.37%
Borrowings of Commercial Paper	7,400,000,000	'	'	'	'
Repayments of Commercial Paper	6,600,000,000	'	'	'	'
Net commercial paper borrowings (repayments) (Note 6)	$799,800,000	($734,900,000)	'	'	'

DEBT_MEP_Credit_Agreement_Deta

DEBT (MEP Credit Agreement) (Details) (USD $)	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013
Line of Credit Facility [Line Items]	'	'
Carrying amount, credit facilities	'	'
Net borrowings under credit facility (Note 6)	30	'
Senior Revolving Credit Facility [Member] | Midcoast Energy Partners [Member]	'	'
Line of Credit Facility [Line Items]	'	'
Line of Credit Facility, Maximum Borrowing Capacity	850	'
Debt, Weighted Average Interest Rate	1.90%	'
Carrying amount, credit facilities	365	'
Repayments of lines of credit	5,540	'
Proceeds from lines of credit	5,570	'
Net borrowings under credit facility (Note 6)	30	'
Facility term	'3 years	'
Credit facility maturity date	30-Sep-17	'
Senior Revolving Credit Facility [Member] | Midcoast Energy Partners [Member] | Portion of Credit Facility Maturing in 2016 [Member]	'	'
Line of Credit Facility [Line Items]	'	'
Line of Credit Facility, Maximum Borrowing Capacity	$140	'
Credit facility maturity date	13-Nov-16	'

DEBT_MEP_Private_Debt_Issuance

DEBT (MEP Private Debt Issuance) (Details) (Senior Notes [Member], Midcoast Energy Partners [Member], USD $)	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014
	contracts
Debt Instrument [Line Items]	'
Debt instrument, face amount	$400
Net proceeds	398.1
Net payments to unwind hedge	0.9
Number of swaps unwound	2
Total leverage ratio	5
Interest expense covenant ratio, debt instrument	2.5
Amortization period of payments made related to debt issuance to settle treasury locks	'5 years
Scenario, Acquisition [Member]	'
Debt Instrument [Line Items]	'
Total leverage ratio	5.5
3.560% Series A Senior Notes due 2019 [Member]	'
Debt Instrument [Line Items]	'
Debt instrument, face amount	75
Maturity date	31-Dec-19
Interest rate	3.56%
4.040% Series B Senior Notes due 2021 [Member]	'
Debt Instrument [Line Items]	'
Debt instrument, face amount	175
Maturity date	31-Dec-21
Interest rate	4.04%
4.420% Series C Senior Notes due 2024 [Member]	'
Debt Instrument [Line Items]	'
Debt instrument, face amount	$150
Maturity date	31-Dec-24
Interest rate	4.42%

PARTNERS_CAPITAL_Distribution_

PARTNERS' CAPITAL (Distribution to Partners) (Details) (USD $)

3 Months Ended

9 Months Ended

0 Months Ended

9 Months Ended

0 Months Ended

9 Months Ended

0 Months Ended

9 Months Ended

0 Months Ended

In Millions, except Share data, unless otherwise specified

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Feb. 14, 2014

Sep. 30, 2014

Feb. 14, 2014

Feb. 14, 2014

15-May-14

Sep. 30, 2014

15-May-14

15-May-14

Aug. 14, 2014

Sep. 30, 2014

Aug. 14, 2014

Aug. 14, 2014

i-units [Member]

First Quarter Distribution [Member]

First Quarter Distribution [Member]

First Quarter Distribution [Member]

First Quarter Distribution [Member]

Second Quarter Distribution [Member]

Second Quarter Distribution [Member]

Second Quarter Distribution [Member]

Second Quarter Distribution [Member]

Third Quarter Distribution [Member]

Third Quarter Distribution [Member]

Third Quarter Distribution [Member]

Third Quarter Distribution [Member]

i-units [Member]

General Partner [Member]

i-units [Member]

General Partner [Member]

i-units [Member]

General Partner [Member]

Distribution Declaration Date

'

'

'

'

'

'

30-Jan-14

'

'

'

30-Apr-14

'

'

'

31-Jul-14

'

'

Record Date

'

'

'

'

'

'

7-Feb-14

'

'

'

8-May-14

'

'

'

7-Aug-14

'

'

Distribution Payment Date

'

'

'

'

'

'

14-Feb-14

'

'

'

15-May-14

'

'

'

14-Aug-14

'

'

Distribution Made to Member or Limited Partner, Distributions Paid, Per Unit

'

'

'

'

'

$0.54

'

'

'

$0.54

'

'

'

$0.56

'

'

'

Cash available for distribution

'

'

'

'

'

$213.70

'

'

'

$214.50

'

'

'

$224.70

'

'

'

Distribution Made to Member or Limited Partner, Cash Distributions Paid

'

'

'

'

'

178.4

'

'

0.7

[1]

178.5

'

'

0.7

[1]

187.3

'

'

0.8

[1]

Amount of Distribution

$182.80

$176.50

$542.70

$518.60

'

'

'

$34.60

[2]

'

'

'

$35.30

[2]

'

'

'

$36.70

[2]

'

Units issued in lieu of cash distributions

'

'

'

'

3,517,795

'

'

'

'

'

'

'

'

'

'

'

'

[1]

We retained an amount equal to 2% of the i-unit distribution from our General Partner to maintain its 2% general partner interest in us.

[2]

We issued 3,517,795 i-units to Enbridge Management, the sole owner of our i-units, during 2014 in lieu of cash distributions.

PARTNERS_CAPITAL_Changes_in_Pa

PARTNERS' CAPITAL (Changes in Partners' Capital) (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Beginning Balance, value	'	'	$7,697.40	'
Net income	20.5	14.9	157.7	21.5
Net Income (preferred stock)	22.5	22.7	67.5	35.8
Accretion of discount on preferred units	3.8	3.4	11.1	5.7
Ending Balance, value	8,392.90	7,011.30	8,392.90	7,011.30
Noncontrolling interest	'	'	'	'
Beginning balance	'	'	1,975.60	793.5
Capital contributions	'	'	1,083	355.2
Transfer of interests in subsidiary to Midcoast Energy Partners, L.P.	125.4	'	125.4	'
Other comprehensive loss allocated to noncontrolling interest	2.1	'	1.8	'
Noncontrolling interest (Note 8)	70.7	20.3	149.4	54.3
Distributions to noncontrolling interest	'	'	-80.9	-39.7
Ending balance	3,254.30	1,163.30	3,254.30	1,163.30
Series 1 Preferred Interests [Member]	'	'	'	'
Beginning Balance, value	'	'	1,160.70	'
Proceeds from issuance of partnership interests, net of costs	'	'	'	1,200
Net Income (preferred stock)	'	'	67.5	35.8
Accretion of discount on preferred units	'	'	11.1	5.7
Distributions	'	'	-67.5	-35.8
Beneficial conversion feature of preferred units	'	'	'	-47.7
Ending Balance, value	1,171.80	1,158	1,171.80	1,158
General and Limited Partner Interests [Member]	'	'	'	'
Beginning Balance, value	'	'	4,637.70	4,774.90
Proceeds from issuance of partnership interests, net of costs	'	'	'	519.3
Net income	'	'	157.7	21.5
Distributions	'	'	-544.2	-530.6
Beneficial conversion feature of preferred units	'	'	'	47.7
Transfer of interests in subsidiary to Midcoast Energy Partners, L.P.	'	'	-125.4	'
Ending Balance, value	4,125.80	4,832.80	4,125.80	4,832.80
Accumulated Other Comprehensive Income (Loss) [Member]	'	'	'	'
Beginning Balance, value	'	'	-76.6	-320.5
Changes in fair value of derivative financial instruments reclassified to earnings	'	'	22.2	21.3
Changes in fair value of derivative financial instruments recognized in other comprehensive income (loss)	'	'	-104.6	156.4
Ending Balance, value	($159)	($142.80)	($159)	($142.80)

PARTNERS_CAPITAL_Midcoast_IPO_

PARTNERS' CAPITAL (Midcoast IPO) (Details) (USD $)

3 Months Ended

9 Months Ended

12 Months Ended

3 Months Ended

6 Months Ended

9 Months Ended

12 Months Ended

9 Months Ended

In Millions, except Share data, unless otherwise specified

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2013

Dec. 31, 2013

Sep. 30, 2014

Jun. 30, 2014

Sep. 30, 2014

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Midcoast Operating [Member]

Midcoast Operating [Member]

Midcoast Operating [Member]

IPO [Member]

IPO [Member]

Initial Public Offering [Member]

Initial Public Offering Overallotment [Member]

General Partner [Member]

Capital Unit, Class A [Member]

Subordinated Units [Member]

Midcoast Energy Partners [Member]

Number of common units issued

'

'

'

'

'

'

'

'

'

18,500,000

2,775,000

'

'

'

Aggregate gross proceeds

'

'

$519.30

'

'

'

'

$304.50

$354.90

'

'

'

'

'

Commitment fees and Issuance Costs

'

'

'

3.4

'

'

'

'

'

'

'

'

'

'

Payments to redeem common units

'

'

'

47

'

'

'

'

'

'

'

'

'

'

Common units redeemed

'

'

'

2,775,000

'

'

'

'

'

'

'

'

'

'

Ownership Interest

'

'

'

'

48.40%

61.00%

48.40%

'

'

'

'

100.00%

5.90%

100.00%

Ownership interest sold

'

'

'

'

12.60%

'

'

'

'

'

'

'

'

'

Cash received

'

'

'

'

350

'

'

'

'

'

'

'

'

'

Transfer of interests in subsidiary to Midcoast Energy Partners, L.P.

$125.40

$125.40

'

'

'

'

'

'

'

'

'

'

'

'

RELATED_PARTY_TRANSACTIONS_Joi

RELATED PARTY TRANSACTIONS (Joint Funding Arrangement Discussions) (Details) (USD $)

3 Months Ended

9 Months Ended

3 Months Ended

9 Months Ended

3 Months Ended

9 Months Ended

3 Months Ended

9 Months Ended

3 Months Ended

9 Months Ended

3 Months Ended

9 Months Ended

3 Months Ended

9 Months Ended

0 Months Ended

9 Months Ended

In Millions, unless otherwise specified

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Nov. 13, 2013

Sep. 30, 2014

Texas Express NGL System [Member]

Texas Express NGL System [Member]

Texas Express NGL System [Member]

Affiliated Entity [Member]

Affiliated Entity [Member]

Affiliated Entity [Member]

Affiliated Entity [Member]

Pipeline Transportation and Demand Fees from Texas Express NGL System [Member]

Pipeline Transportation and Demand Fees from Texas Express NGL System [Member]

Alberta Clipper Pipeline [Member]

Alberta Clipper Pipeline [Member]

Alberta Clipper Pipeline [Member]

Alberta Clipper Pipeline [Member]

Eastern Access Pipeline [Member]

Eastern Access Pipeline [Member]

Eastern Access Pipeline [Member]

Eastern Access Pipeline [Member]

US Mainline Expansion [Member]

US Mainline Expansion [Member]

US Mainline Expansion [Member]

US Mainline Expansion [Member]

Midcoast Energy Partners [Member]

Midcoast Energy Partners [Member]

bbl

bbl

mi

mi

entities

entities

Operating and administrative

$235.30

$265.10

$676.90

$678

'

'

'

$115.90

$111.50

$353.60

$329.10

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Interest expense, net (Notes 6 and 10)

137.1

70.5

294.2

226.4

'

'

'

'

'

'

'

'

'

6.1

'

18.3

'

'

'

'

'

'

'

'

'

'

'

General Partners' equity contributions

'

'

1,083

355.2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

550.5

272.5

'

'

384

82.7

'

'

Less: Net income attributable to noncontrolling interest

70.7

20.3

149.4

54.3

'

'

'

'

'

'

'

'

'

16.3

13.4

38

39.6

41.7

6.6

90.5

14.4

9.8

0.3

20

0.3

'

'

Ownership interest in affiliate of Partnership

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

66.67%

'

'

'

25.00%

'

'

'

25.00%

'

'

'

Noncontrolling Interest, Ownership Percentage by Parent

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

75.00%

'

75.00%

'

75.00%

'

75.00%

'

'

'

Related party expenses

'

'

'

'

'

'

'

'

'

'

'

5.4

16.8

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Affiliate revenues

68.3

65.4

229.4

204.8

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Cost of natural gas

1,238.20

1,257.50

3,986.70

3,564.40

'

'

'

29.7

22.8

98.3

95.3

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Amount of credit agreement

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

250

'

Number of days of notice to terminate Working Capital Agreement

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'30 days

Schedule of Equity Method Investments [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Ownership Percentage of JV

'

'

'

'

35.00%

35.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of joint ventures

'

'

'

'

2

2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Equity Investment in Joint Venture

'

'

'

'

380.2

380.2

371.3

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Equity loss from investment in joint venture

'

'

$7.10

'

$6.10

$7.10

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Miles of pipeline

'

'

'

'

580

580

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Transportation commitments

'

'

'

'

120,000

120,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

RELATED_PARTY_TRANSACTIONS_Cas

RELATED PARTY TRANSACTIONS (Cash Activity for A1 Credit Agreement and A1 Term Note) (Details) (USD $)	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013
Repayments	($12)	($12)
Notes Payable, Other Payables [Member]	'	'
Beginning Balance	318	330
Borrowings	'	'
Repayments	-12	-12
Ending Balance	$306	$318

RELATED_PARTY_TRANSACTIONS_Dis

RELATED PARTY TRANSACTIONS (Distributions by Affiliates) (Details) (USD $)

0 Months Ended

9 Months Ended

0 Months Ended

9 Months Ended

0 Months Ended

9 Months Ended

0 Months Ended

9 Months Ended

0 Months Ended

9 Months Ended

0 Months Ended

9 Months Ended

0 Months Ended

9 Months Ended

0 Months Ended

9 Months Ended

0 Months Ended

9 Months Ended

0 Months Ended

9 Months Ended

0 Months Ended

9 Months Ended

In Millions, unless otherwise specified

Feb. 14, 2014

Sep. 30, 2014

15-May-14

Sep. 30, 2014

Aug. 14, 2014

Sep. 30, 2014

Sep. 30, 2014

Feb. 14, 2014

Sep. 30, 2014

15-May-14

Sep. 30, 2014

Aug. 14, 2014

Sep. 30, 2014

Sep. 30, 2014

Feb. 14, 2014

Sep. 30, 2014

15-May-14

Sep. 30, 2014

Aug. 14, 2014

Sep. 30, 2014

Sep. 30, 2014

15-May-14

Sep. 30, 2014

Aug. 14, 2014

Sep. 30, 2014

First Quarter Distribution [Member]

First Quarter Distribution [Member]

Second Quarter Distribution [Member]

Second Quarter Distribution [Member]

Third Quarter Distribution [Member]

Third Quarter Distribution [Member]

Midcoast Energy Partners [Member]

Midcoast Energy Partners [Member]

Midcoast Energy Partners [Member]

Midcoast Energy Partners [Member]

Midcoast Energy Partners [Member]

Midcoast Energy Partners [Member]

Midcoast Energy Partners [Member]

Alberta Clipper Pipeline [Member]

Alberta Clipper Pipeline [Member]

Alberta Clipper Pipeline [Member]

Alberta Clipper Pipeline [Member]

Alberta Clipper Pipeline [Member]

Alberta Clipper Pipeline [Member]

Alberta Clipper Pipeline [Member]

Series EA [Member]

Series EA [Member]

Series EA [Member]

Series EA [Member]

Series EA [Member]

First Quarter Distribution [Member]

First Quarter Distribution [Member]

Second Quarter Distribution [Member]

Second Quarter Distribution [Member]

Third Quarter Distribution [Member]

Third Quarter Distribution [Member]

First Quarter Distribution [Member]

First Quarter Distribution [Member]

Second Quarter Distribution [Member]

Second Quarter Distribution [Member]

Third Quarter Distribution [Member]

Third Quarter Distribution [Member]

Second Quarter Distribution [Member]

Second Quarter Distribution [Member]

Third Quarter Distribution [Member]

Third Quarter Distribution [Member]

Distribution Declaration Date

'

30-Jan-14

'

30-Apr-14

'

31-Jul-14

'

'

29-Jan-14

'

29-Apr-14

'

31-Jul-14

'

'

30-Jan-14

'

30-Apr-14

'

31-Jul-14

'

'

29-Apr-14

'

31-Jul-14

Distribution Payment Date

'

14-Feb-14

'

15-May-14

'

14-Aug-14

'

'

14-Feb-14

'

15-May-14

'

14-Aug-14

'

'

14-Feb-14

'

15-May-14

'

14-Aug-14

'

'

15-May-14

'

14-Aug-14

Amount Paid To Parent

'

'

'

'

'

'

$20.10

$4.20

'

$7.80

'

$8.10

'

$20.40

$6.40

'

$6.60

'

$7.40

'

$8.10

$2.50

'

$5.60

'

Amount paid to the noncontrolling interest

'

'

'

'

'

'

17

3.5

'

6.6

'

6.9

'

40.7

12.8

'

13.1

'

14.8

'

23.2

6.5

'

16.7

'

Total amount of distribution paid

$178.40

'

$178.50

'

$187.30

'

$37.10

$7.70

'

$14.40

'

$15

'

$61.10

$19.20

'

$19.70

'

$22.20

'

$31.30

$9

'

$22.30

'

RELATED_PARTY_TRANSACTIONS_Sal

RELATED PARTY TRANSACTIONS (Sale of AR) (Details) (USD $)	3 Months Ended	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2014	Dec. 31, 2013
Net value of receivables sold	$1,260.10	$3,792.80	'
Proceeds from Sale of Receivables	1,259.80	3,791.80	'
Restricted cash (Note 8)	38.2	38.2	69.4
Sold Receivables that have not been collected at the balance sheet date.	$411.10	$411.10	'

COMMITMENTS_AND_CONTINGENCIES_1

COMMITMENTS AND CONTINGENCIES (Narrative) (Details) (USD $)

3 Months Ended

9 Months Ended

3 Months Ended

9 Months Ended

3 Months Ended

9 Months Ended

3 Months Ended

9 Months Ended

In Millions, unless otherwise specified

Mar. 31, 2013

Jun. 30, 2011

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2013

Dec. 31, 2013

Mar. 31, 2013

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Line Six Romeoville Leak [Member]

Line Six Marshall Leak [Member]

Line Six Marshall Leak [Member]

Line Six Marshall Leak [Member]

Line Six Marshall Leak [Member]

Line Six Marshall Leak [Member]

Line Six Marshall Leak [Member]

Line Six Marshall Leak [Member]

Line Six Marshall Leak [Member]

Line Six Marshall Leak [Member]

Griffith Terminal Leak [Member]

claims

claims

claims

Approved Schedule of Work and Other Costs [Member]

Fines Assessed by PHMSA [Member]

Fines Related to Clean Water Act [Member]

Fines Related to Clean Water Act [Member]

bbl

Accrual for environmental loss contingencies

'

'

$64

$25.80

'

$1,210

$1,210

'

'

'

'

'

'

'

'

Estimated total loss of crude oil release

'

'

'

'

'

1,208

1,208

'

'

'

'

'

'

'

7

Accrual for additional environmental loss contingencies

'

'

'

'

'

50.9

85.9

'

'

'

33

'

17.9

'

'

Costs paid associated with crude oil release

'

'

'

'

'

'

117.4

62.3

'

'

'

'

'

'

6

Remaining liabilities

'

'

164.1

233.7

'

219.4

219.4

'

258.9

'

'

'

'

'

1

Aggregate insurance coverage limit

'

650

700

'

'

'

'

'

'

'

'

'

'

'

'

Insurance recoveries

'

'

'

'

'

'

'

42

'

'

'

'

'

'

'

Government fines and penalties

'

'

'

'

'

'

47.5

'

'

'

'

3.7

'

40

'

Insurance recoveries, since inception

'

'

'

'

'

547

547

'

'

'

'

'

'

'

'

Number of claims filed against

'

'

'

'

1

10

10

'

'

'

'

'

'

'

'

Remaining insurance recoveries in litigation

103

'

'

'

'

18

18

'

'

85

'

'

'

'

'

Crude oil released in barrels

'

'

'

'

'

'

'

'

'

'

'

'

'

'

975

Increase (decrease) in other insurance liability

10

'

30

'

'

'

'

'

'

'

'

'

'

'

'

Remaining aggregate insurance coverage

'

'

$145

'

'

'

'

'

'

'

'

'

'

'

'

COMMITMENTS_AND_CONTINGENCIES_2

COMMITMENTS AND CONTINGENCIES (Material Components Underlying Estimated Loss for Cleanup, Remediation and Restoration) (Details) (Line Six Marshall Leak [Member], USD $)	Sep. 30, 2014
In Millions, unless otherwise specified
Estimated total loss of crude oil release	$1,208
Response Personnel and Equipment [Member]	'
Estimated total loss of crude oil release	551.6
Environmental Consultants [Member]	'
Estimated total loss of crude oil release	227
Professional, Regulatory and Other [Member]	'
Estimated total loss of crude oil release	$429.40

DERIVATIVE_FINANCIAL_INSTRUMEN2

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Narrative) (Details) (USD $)	9 Months Ended		9 Months Ended		3 Months Ended	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013	Sep. 30, 2014	Sep. 30, 2014	Sep. 30, 2014	Sep. 30, 2014
			Short Term Debt Hedging Instruments [Member]	Forward Starting Interest Rate Swaps Entered Into [Member]	Amended Interest Rate Hedges [Member]	Amended Interest Rate Hedges [Member]
DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES [Abstract]	'	'	'	'	'	'
Unrecognized losses of derivative financial instruments that were classified as cash flow hedges	$29.60	'	'	'	'	'
De-designated unrealized commodity hedge losses	-0.2	'	'	'	'	'
Cash flow hedge gain (loss) to be reclassified within twelve months	11.7	'	'	'	'	'
Net liability position	-219.1	-88.7	'	'	'	'
Expected value of cash collateral or letters of credit if credit rating is downgraded	48.8	'	'	'	'	'
Letters of credit outstanding, derivatives	183	76.1	'	'	'	'
Derivative [Line Items]	'	'	'	'	'	'
Term of derivatives	'	'	'	'10 years	'	'
Notional amount	'	'	'	2,350	'	'
Losses for interest rate hedge ineffectiveness	'	'	($0.80)	'	($62.20)	($62.20)

DERIVATIVE_FINANCIAL_INSTRUMEN3

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Derivative Instruments in Statement of Financial Position) (Details) (USD $)	Sep. 30, 2014		Dec. 31, 2013
In Millions, unless otherwise specified
Derivatives, Fair Value [Line Items]	'		'
Net Total	($219.10)		($88.70)
Cash collateral held	'		16.7
Other Current Assets [Member]	'		'
Derivatives, Fair Value [Line Items]	'		'
Net Total	37.8		21.2
Other Noncurrent Assets [Member]	'		'
Derivatives, Fair Value [Line Items]	'		'
Net Total	36.2		74.4
Accounts Payable and Other [Member]	'		'
Derivatives, Fair Value [Line Items]	'		'
Net Total	-25.6	[1]	-172	[1]
Other Noncurrent Liabilities [Member]	'		'
Derivatives, Fair Value [Line Items]	'		'
Net Total	-267.9		-12.3
Due from General Partner and Affiliates [Member]	'		'
Derivatives, Fair Value [Line Items]	'		'
Net Total	$0.40		'
[1]	Includes $16.7 million of cash collateral at December 31, 2013.

DERIVATIVE_FINANCIAL_INSTRUMEN4

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Derivative Balances by Counterparty Credit Quality) (Details) (USD $)	Sep. 30, 2014		Dec. 31, 2013
In Millions, unless otherwise specified
Derivative [Line Items]	'		'
Net Total	($219.10)		($88.70)
Cash collateral held	'		16.7
AAA Rating [Member]	'		'
Derivative [Line Items]	'		'
Net Total	0.3	[1]	0.3	[1]
AA Rating [Member]	'		'
Derivative [Line Items]	'		'
Net Total	-91	[1]	-49.7	[1]
A Rating [Member]	'		'
Derivative [Line Items]	'		'
Net Total	-134	[1],[2]	-40.1	[1],[2]
Cash collateral held	'		16.7
Lower than A [Member]	'		'
Derivative [Line Items]	'		'
Net Total	$5.60	[1]	$0.80	[1]
[1]	As determined by nationally-recognized statistical ratings organizations.
[2]	Includes $16.7 million of cash collateral at December 31, 2013.

DERIVATIVE_FINANCIAL_INSTRUMEN5

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Credit Concentrations in Industry Sectors) (Details) (USD $)	Sep. 30, 2014		Dec. 31, 2013
In Millions, unless otherwise specified
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]	'		'
Net Total	($219.10)		($88.70)
Cash collateral held	'		16.7
United States Financial Institutions And Investment Banking Entities [Member]	'		'
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]	'		'
Credit concentrations	-176.3		-85
Non United States Financial Institutions [Member]	'		'
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]	'		'
Credit concentrations	-49.3	[1]	0.8	[1]
Cash collateral held	'		16.7
Other [Member]	'		'
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]	'		'
Credit concentrations	$6.50		($4.50)
[1]	Includes $16.7 million of cash collateral at December 31, 2013.

DERIVATIVE_FINANCIAL_INSTRUMEN6

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Effect of Derivative Instruments on Consolidated Statements of Financial Position) (Details) (USD $)	Sep. 30, 2014		Dec. 31, 2013
In Millions, unless otherwise specified
Derivatives, Fair Value [Line Items]	'		'
Asset Derivatives	$74.40		$119.90
Liability Derivatives	-293.5		-191.9
Cash collateral held	'		16.7
Derivatives Designated As Hedging Instruments [Member]	'		'
Derivatives, Fair Value [Line Items]	'		'
Asset Derivatives	21.5	[1]	85.1	[1]
Liability Derivatives	-265.3	[1]	-172	[1]
Derivatives Designated As Hedging Instruments [Member] | Other Current Assets [Member] | Interest Rate Contracts [Member]	'		'
Derivatives, Fair Value [Line Items]	'		'
Asset Derivatives	'	[1]	8.1	[1]
Liability Derivatives	'	[1]	'	[1]
Derivatives Designated As Hedging Instruments [Member] | Other Current Assets [Member] | Commodity Contract [Member]	'		'
Derivatives, Fair Value [Line Items]	'		'
Asset Derivatives	3.3	[1]	2	[1]
Liability Derivatives	'	[1]	-0.6	[1]
Derivatives Designated As Hedging Instruments [Member] | Other Assets [Member] | Interest Rate Contracts [Member]	'		'
Derivatives, Fair Value [Line Items]	'		'
Asset Derivatives	16.9	[1]	57.1	[1]
Liability Derivatives	'	[1]	'	[1]
Derivatives Designated As Hedging Instruments [Member] | Other Assets [Member] | Commodity Contract [Member]	'		'
Derivatives, Fair Value [Line Items]	'		'
Asset Derivatives	1.3	[1]	3.5	[1]
Liability Derivatives	'	[1]	-0.5	[1]
Derivatives Designated As Hedging Instruments [Member] | Accounts Payable and Other [Member] | Interest Rate Contracts [Member]	'		'
Derivatives, Fair Value [Line Items]	'		'
Asset Derivatives	'	[1],[2]	11.9	[1],[2]
Liability Derivatives	-7.8	[1],[2]	-145.5	[1],[2]
Derivatives Designated As Hedging Instruments [Member] | Accounts Payable and Other [Member] | Commodity Contract [Member]	'		'
Derivatives, Fair Value [Line Items]	'		'
Asset Derivatives	'	[1]	1.9	[1]
Liability Derivatives	-2.2	[1]	-12.7	[1]
Derivatives Designated As Hedging Instruments [Member] | Other Long-term Liabilities [Member] | Interest Rate Contracts [Member]	'		'
Derivatives, Fair Value [Line Items]	'		'
Asset Derivatives	'	[1]	'	[1]
Liability Derivatives	-255	[1]	-11.3	[1]
Derivatives Designated As Hedging Instruments [Member] | Other Long-term Liabilities [Member] | Commodity Contract [Member]	'		'
Derivatives, Fair Value [Line Items]	'		'
Asset Derivatives	'	[1]	0.6	[1]
Liability Derivatives	-0.3	[1]	-1.4	[1]
Derivatives Not Designated As Hedging Instruments [Member]	'		'
Derivatives, Fair Value [Line Items]	'		'
Asset Derivatives	52.9		34.8
Liability Derivatives	-28.2		-19.9
Derivatives Not Designated As Hedging Instruments [Member] | Other Current Assets [Member] | Commodity Contract [Member]	'		'
Derivatives, Fair Value [Line Items]	'		'
Asset Derivatives	34.5		11.8
Liability Derivatives	'		-0.1
Derivatives Not Designated As Hedging Instruments [Member] | Other Assets [Member] | Commodity Contract [Member]	'		'
Derivatives, Fair Value [Line Items]	'		'
Asset Derivatives	18		17.6
Liability Derivatives	'		-3.3
Derivatives Not Designated As Hedging Instruments [Member] | Accounts Payable and Other [Member] | Commodity Contract [Member]	'		'
Derivatives, Fair Value [Line Items]	'		'
Asset Derivatives	'		5.4
Liability Derivatives	-15.6		-16.3
Derivatives Not Designated As Hedging Instruments [Member] | Other Long-term Liabilities [Member] | Commodity Contract [Member]	'		'
Derivatives, Fair Value [Line Items]	'		'
Asset Derivatives	'		'
Liability Derivatives	-12.6		-0.2
Derivatives Not Designated As Hedging Instruments [Member] | Due from General Partner and Affiliates [Member] | Commodity Contract [Member]	'		'
Derivatives, Fair Value [Line Items]	'		'
Asset Derivatives	0.4		'
Liability Derivatives	'		'
[1]	Includes items currently designated as hedging instruments. Excludes the portion of de-designated hedges which may have a component remaining in AOCI.
[2]	Liability derivatives exclude $16.7 million of cash collateral at December 31, 2013.

DERIVATIVE_FINANCIAL_INSTRUMEN7

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Effect of Derivative Instruments on Consolidated Statements of Income and AOCI) (Details) (Derivatives in Cash Flow Hedging Relationships [Member], USD $)	3 Months Ended				9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014		Sep. 30, 2013		Sep. 30, 2014		Sep. 30, 2013
Derivative Instruments, Gain (Loss) [Line Items]	'		'		'		'
Amount of Gain (Loss) Recognized in AOCI on Derivative (Effective Portion)	$55.30		($15.50)		($85.10)		$170.50
Amount of Gain (Loss) Reclassified from AOCI to Earnings (Effective Portion)	-6.1		-4.8		-24.5		-21.3
Amount of Gain (Loss) Recognized in Earnings on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)	-61.3	[1]	-1.6	[1]	-71.7	[1]	1.3	[1]
Interest Rate Contracts [Member]	'		'		'		'
Derivative Instruments, Gain (Loss) [Line Items]	'		'		'		'
Amount of Gain (Loss) Recognized in AOCI on Derivative (Effective Portion)	44.1		1.7		-93		179.3
Commodity Contract [Member]	'		'		'		'
Derivative Instruments, Gain (Loss) [Line Items]	'		'		'		'
Amount of Gain (Loss) Recognized in AOCI on Derivative (Effective Portion)	11.2		-17.2		7.9		-8.8
Interest Expense [Member] | Interest Rate Contracts [Member]	'		'		'		'
Derivative Instruments, Gain (Loss) [Line Items]	'		'		'		'
Amount of Gain (Loss) Reclassified from AOCI to Earnings (Effective Portion)	-4		-4.2		-12.1		-24.3
Amount of Gain (Loss) Recognized in Earnings on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)	-62.2	[1]	-1.1	[1]	-73.2	[1]	-0.5	[1]
Cost of Natural Gas [Member] | Commodity Contract [Member]	'		'		'		'
Derivative Instruments, Gain (Loss) [Line Items]	'		'		'		'
Amount of Gain (Loss) Reclassified from AOCI to Earnings (Effective Portion)	-2.1		-0.6		-12.4		3
Amount of Gain (Loss) Recognized in Earnings on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)	$0.90	[1]	($0.50)	[1]	$1.50	[1]	$1.80	[1]
[1]	Includes only the ineffective portion of derivatives that are designated as hedging instruments and does not include net gains or losses associated with derivatives that do not qualify for hedge accounting treatment.

DERIVATIVE_FINANCIAL_INSTRUMEN8

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Components of Accumulated Other Comprehensive Income) (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014		Sep. 30, 2013
Accumulated Other Comprehensive Income (Loss) [Line Items]	'	'	'		'
Beginning balance	'	'	($76.60)		'
Tax benefit (expense)	0	-0.1	0		0
Net other comprehensive income	55.5	-14	-80.6		177.7
Ending balance	-159	'	-159		'
Cash Flow Hedges [Member]	'	'	'		'
Accumulated Other Comprehensive Income (Loss) [Line Items]	'	'	'		'
Beginning balance	'	'	-76.6		'
Other Comprehensive Income before reclassifications	'	'	-104.6	[1]	'
Amounts reclassified from AOCI	'	'	22.2	[2],[3]	'
Tax benefit (expense)	'	'	'		'
Net other comprehensive income	'	'	-82.4		'
Ending balance	-159	'	-159		'
Noncontrolling Interest [Member]	'	'	'		'
Accumulated Other Comprehensive Income (Loss) [Line Items]	'	'	'		'
Other Comprehensive Income before reclassifications	'	'	-0.5		'
Amounts reclassified from AOCI	'	'	$2.30		'
[1]	Excludes NCI loss of $0.5 million reclassified from AOCI at September 30, 2014.
[2]	Excludes NCI gain of $2.3 million reclassified from AOCI at September 30, 2014.
[3]	For additional details on the amounts reclassified from AOCI, reference the Reclassifications from Accumulated Other Comprehensive Income table below.

DERIVATIVE_FINANCIAL_INSTRUMEN9

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Reclassifications from Accumulated Other Comprehensive Income) (Details) (USD $)	3 Months Ended				9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014		Sep. 30, 2013		Sep. 30, 2014		Sep. 30, 2013
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]	'		'		'		'
Cost of natural gas	$1,238.20		$1,257.50		$3,986.70		$3,564.40
Interest expense, net	137.1		70.5		294.2		226.4
Total Reclassifications from AOCI	-20.5		-14.9		-157.7		-21.5
NCI gain	70.7		20.3		149.4		54.3
Reclassification out of AOCI [Member] | Cash Flow Hedges [Member]	'		'		'		'
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]	'		'		'		'
Total Reclassifications from AOCI	5.6		4.8		22.2		21.3
Interest Rate Contracts [Member] | Reclassification out of AOCI [Member] | Cash Flow Hedges [Member]	'		'		'		'
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]	'		'		'		'
Interest expense, net	4	[1]	4.2	[1]	12.1	[1]	24.3	[1]
Commodity Contract [Member] | Reclassification out of AOCI [Member] | Cash Flow Hedges [Member]	'		'		'		'
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]	'		'		'		'
Cost of natural gas	1.6	[2],[3]	0.6	[2],[3]	10.1	[2],[3]	-3	[2],[3]
NCI gain	$0.50		'		$2.30		'
[1]	Loss reported within "Interest expense" in the consolidated statements of income.
[2]	Excludes NCI gain of $0.5 million and $2.3 million reclassified from AOCI for the three and nine month periods ending September 30, 2014.
[3]	Loss (gain) reported within "Cost of natural gas" in the consolidated statements of income.

Recovered_Sheet1

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Effect of Derivative Instruments on Consolidated Statements of Income) (Details) (Derivatives Not Designated As Hedging Instruments [Member], USD $)	3 Months Ended				9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014		Sep. 30, 2013		Sep. 30, 2014		Sep. 30, 2013
Derivative Instruments, Gain (Loss) [Line Items]	'		'		'		'
Amount of Gain or (Loss) Recognized in Earnings	$24.10	[1],[2]	($38.30)	[1],[2],[3]	$1.20	[1],[2]	($16.30)	[1],[2],[3]
Gain (Loss) on Settlement of Derivative Instruments	'		-0.8		'		1.8
Interest Expense [Member] | Interest Rate Contracts [Member]	'		'		'		'
Derivative Instruments, Gain (Loss) [Line Items]	'		'		'		'
Amount of Gain or (Loss) Recognized in Earnings	'	[1],[2],[4]	0.1	[1],[2],[3],[4]	'	[1],[2],[4]	'	[1],[2],[3],[4]
Gain (Loss) on Settlement of Derivative Instruments	'		0.1		'		0.3
Operating Revenue [Member] | Commodity Contract [Member]	'		'		'		'
Derivative Instruments, Gain (Loss) [Line Items]	'		'		'		'
Amount of Gain or (Loss) Recognized in Earnings	14.6	[1],[2],[5]	-16.7	[1],[2],[3],[5]	10.1	[1],[2],[5]	-14	[1],[2],[3],[5]
Gain (Loss) on Settlement of Derivative Instruments	0.6		-0.7		0.9		1
Operating Revenue - Affiliate [Member] | Commodity Contract [Member]	'		'		'		'
Derivative Instruments, Gain (Loss) [Line Items]	'		'		'		'
Amount of Gain or (Loss) Recognized in Earnings	'	[1],[2]	'	[1],[2],[3]	0.5	[1],[2]	'	[1],[2],[3]
Power [Member] | Commodity Contract [Member]	'		'		'		'
Derivative Instruments, Gain (Loss) [Line Items]	'		'		'		'
Amount of Gain or (Loss) Recognized in Earnings	'	[1],[2]	0.1	[1],[2],[3]	0.5	[1],[2]	0.3	[1],[2],[3]
Cost of Natural Gas [Member] | Commodity Contract [Member]	'		'		'		'
Derivative Instruments, Gain (Loss) [Line Items]	'		'		'		'
Amount of Gain or (Loss) Recognized in Earnings	9.5	[1],[2],[6]	-21.8	[1],[2],[3],[6]	-9.9	[1],[2],[6]	-2.6	[1],[2],[3],[6]
Gain (Loss) on Settlement of Derivative Instruments	$0.20		($0.20)		($8.60)		$0.50
[1]	Does not include settlements associated with derivative instruments that settle through physical delivery.
[2]	Includes only net gains or losses associated with those derivatives that do not qualify for hedge accounting treatment and does not include the ineffective portion of derivatives that are designated as hedging instruments.
[3]	The effects of derivative instruments on consolidated statements of income for the three and nine month periods ended September 30, 2013 have been revised to include settlement gains (losses) on derivatives not designated as hedge instruments of $(0.8) million and $1.8 million, respectively. The revisions to the disclosure had no impact on previously reported net income or earnings per unit.
[4]	Includes settlement gains of $0.1 million and $0.3 million for the three and nine month periods ended September 30, 2013, respectively.
[5]	Includes settlement gains (losses) of $0.6 million and $(0.7) million for the three month periods ended September 30, 2014 and September 30, 2013, respectively, and $0.9 million and $1.0 million for the nine month periods ended September 30, 2014 and September 30, 2013, respectively.
[6]	Includes settlement gains (losses) of $0.2 million and $(0.2) million for the three month periods ended September 30, 2014 and September 30, 2013, respectively, and $(8.6) million and $0.5 million for the nine month periods ended September 30, 2014 and September 30, 2013, respectively.

Recovered_Sheet2

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Offsetting of Financial Assets and Derivative Assets) (Details) (USD $)	Sep. 30, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Derivatives	'	'
Gross Amount of Recognized Assets	$74.40	$119.90
Gross Amount Offset in the Statement of Financial Position	'	-24.3
Net Amount of Assets Presented in the Statement of Financial Position	74.4	95.6
Gross Amount Not Offset in the Statement of Financial Position	-33.6	-18.6
Net Amount	40.8	77
Total	'	'
Gross Amount of Recognized Assets	74.4	119.9
Gross Amount Offset in the Statement of Financial Position	'	-24.3
Net Amount of Assets Presented in the Statement of Financial Position	74.4	95.6
Gross Amount Not Offset in the Statement of Financial Position	-33.6	-18.6
Net Amount	$40.80	$77

Recovered_Sheet3

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Offsetting of Financial Liabilities and Derivative Liabilities) (Details) (USD $)	Sep. 30, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Derivatives	'	'
Gross Amount of Recognized Liabilities	($293.50)	($208.60)	[1]
Gross Amount Offset in the Statement of Financial Position	'	24.3	[1]
Net Amount of Liabilities Presented in the Statement of Financial Position	-293.5	-184.3	[1]
Gross Amount Not Offset in the Statement of Financial Position	33.6	18.6	[1]
Net Amount	-259.9	-165.7	[1]
Total	'	'
Gross Amount of Recognized Liabilities	-293.5	-208.6
Gross Amount Offset in the Statement of Financial Position	'	24.3
Net Amount of Liabilities Presented in the Statement of Financial Position	-293.5	-184.3
Gross Amount Not Offset in the Statement of Financial Position	33.6	18.6
Net Amount	-259.9	-165.7
Cash collateral	'	$16.70
[1]	Includes $16.7 million of cash collateral at December 31, 2013.

Recovered_Sheet4

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Level with in Fair Value Hierarchy, Financial Assets and Liabilities) (Details) (USD $)	Sep. 30, 2014		Dec. 31, 2013
In Millions, unless otherwise specified
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
Assets and liabilities accounted for at fair value on a recurring basis	($219.10)		($88.70)
Interest Rate Contracts [Member]	'		'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
Assets and liabilities accounted for at fair value on a recurring basis	-245.9	[1]	-96.4	[1]
Commodity Contracts-Financial [Member]	'		'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
Assets and liabilities accounted for at fair value on a recurring basis	13.9		-0.5
Commodity Contracts-Physical [Member]	'		'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
Assets and liabilities accounted for at fair value on a recurring basis	7.6		-0.2
Commodity Options [Member]	'		'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
Assets and liabilities accounted for at fair value on a recurring basis	5.3		8.4
Level 1 [Member]	'		'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
Assets and liabilities accounted for at fair value on a recurring basis	'		'
Level 1 [Member] | Interest Rate Contracts [Member]	'		'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
Assets and liabilities accounted for at fair value on a recurring basis	'	[1]	'	[1]
Level 1 [Member] | Commodity Contracts-Financial [Member]	'		'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
Assets and liabilities accounted for at fair value on a recurring basis	'		'
Level 1 [Member] | Commodity Contracts-Physical [Member]	'		'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
Assets and liabilities accounted for at fair value on a recurring basis	'		'
Level 1 [Member] | Commodity Options [Member]	'		'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
Assets and liabilities accounted for at fair value on a recurring basis	'		'
Level 2 [Member]	'		'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
Assets and liabilities accounted for at fair value on a recurring basis	-233.8		-90
Level 2 [Member] | Interest Rate Contracts [Member]	'		'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
Assets and liabilities accounted for at fair value on a recurring basis	-245.9	[1]	-96.4	[1]
Level 2 [Member] | Commodity Contracts-Financial [Member]	'		'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
Assets and liabilities accounted for at fair value on a recurring basis	12.1		6.4
Level 2 [Member] | Commodity Contracts-Physical [Member]	'		'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
Assets and liabilities accounted for at fair value on a recurring basis	'		'
Level 2 [Member] | Commodity Options [Member]	'		'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
Assets and liabilities accounted for at fair value on a recurring basis	'		'
Level 3 [Member]	'		'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
Assets and liabilities accounted for at fair value on a recurring basis	14.7		1.3
Level 3 [Member] | Interest Rate Contracts [Member]	'		'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
Assets and liabilities accounted for at fair value on a recurring basis	'	[1]	'	[1]
Level 3 [Member] | Commodity Contracts-Financial [Member]	'		'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
Assets and liabilities accounted for at fair value on a recurring basis	1.8		-6.9
Level 3 [Member] | Commodity Contracts-Physical [Member]	'		'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
Assets and liabilities accounted for at fair value on a recurring basis	7.6		-0.2
Level 3 [Member] | Commodity Options [Member]	'		'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
Assets and liabilities accounted for at fair value on a recurring basis	$5.30		$8.40
[1]	During the period, there were no significant transfers in or out of any of any of the Levels or between Levels.

Recovered_Sheet5

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Quantitative Information about Level 3 Fair Value Measurements) (Details) (USD $)	9 Months Ended		12 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014		Dec. 31, 2013
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]	'		'
Assets and liabilities accounted for at fair value on a recurring basis	-219.1		-88.7
Commodity Contracts-Financial [Member] | Minimum [Member] | Natural Gas [Member]	'		'
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]	'		'
Forward Price	3.49	[1]	3.64	[1]
Commodity Contracts-Financial [Member] | Minimum [Member] | NGL [Member]	'		'
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]	'		'
Forward Price	0.24	[1]	1	[1]
Commodity Contracts-Financial [Member] | Maximum [Member] | Natural Gas [Member]	'		'
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]	'		'
Forward Price	4.74	[1]	4.41	[1]
Commodity Contracts-Financial [Member] | Maximum [Member] | NGL [Member]	'		'
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]	'		'
Forward Price	1.98	[1]	2.13	[1]
Commodity Contracts-Financial [Member] | Weighted Average [Member] | Natural Gas [Member]	'		'
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]	'		'
Forward Price	4.01	[1]	4.14	[1]
Commodity Contracts-Financial [Member] | Weighted Average [Member] | NGL [Member]	'		'
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]	'		'
Forward Price	1.18	[1]	1.38	[1]
Commodity Contracts-Physical [Member] | Minimum [Member] | Natural Gas [Member]	'		'
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]	'		'
Forward Price	2.03	[1]	3.36	[1]
Commodity Contracts-Physical [Member] | Minimum [Member] | Crude Oil [Member]	'		'
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]	'		'
Forward Price	83.03	[1]	86.37	[1]
Commodity Contracts-Physical [Member] | Minimum [Member] | NGL [Member]	'		'
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]	'		'
Forward Price	0.23	[1]	0.02	[1]
Commodity Contracts-Physical [Member] | Minimum [Member] | Power [Member]	'		'
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]	'		'
Forward Price	36.21	[1]	32.4	[1]
Commodity Contracts-Physical [Member] | Maximum [Member] | Natural Gas [Member]	'		'
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]	'		'
Forward Price	4.83	[1]	4.82	[1]
Commodity Contracts-Physical [Member] | Maximum [Member] | Crude Oil [Member]	'		'
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]	'		'
Forward Price	94.98	[1]	103.04	[1]
Commodity Contracts-Physical [Member] | Maximum [Member] | NGL [Member]	'		'
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]	'		'
Forward Price	2.05	[1]	2.19	[1]
Commodity Contracts-Physical [Member] | Maximum [Member] | Power [Member]	'		'
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]	'		'
Forward Price	39.49	[1]	38.98	[1]
Commodity Contracts-Physical [Member] | Weighted Average [Member] | Natural Gas [Member]	'		'
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]	'		'
Forward Price	4.04	[1]	4.15	[1]
Commodity Contracts-Physical [Member] | Weighted Average [Member] | Crude Oil [Member]	'		'
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]	'		'
Forward Price	90.86	[1]	97.24	[1]
Commodity Contracts-Physical [Member] | Weighted Average [Member] | NGL [Member]	'		'
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]	'		'
Forward Price	1.08	[1]	0.95	[1]
Commodity Contracts-Physical [Member] | Weighted Average [Member] | Power [Member]	'		'
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]	'		'
Forward Price	37.84	[1]	35.07	[1]
Commodity Options [Member] | Minimum [Member]	'		'
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]	'		'
Option Volatility	14.00%	[1]	18.00%	[1]
Commodity Options [Member] | Maximum [Member]	'		'
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]	'		'
Option Volatility	40.00%	[1]	44.00%	[1]
Commodity Options [Member] | Weighted Average [Member]	'		'
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]	'		'
Option Volatility	28.00%	[1]	28.00%	[1]
Level 3 [Member]	'		'
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]	'		'
Assets and liabilities accounted for at fair value on a recurring basis	14.7		1.3
Credit valuation adjustments	0.1		-0.1
Level 3 [Member] | Commodity Contracts-Financial [Member] | Natural Gas [Member]	'		'
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]	'		'
Assets and liabilities accounted for at fair value on a recurring basis	-0.6	[2]	'	[3]
Level 3 [Member] | Commodity Contracts-Financial [Member] | NGL [Member]	'		'
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]	'		'
Assets and liabilities accounted for at fair value on a recurring basis	2.4	[2]	-6.9	[3]
Level 3 [Member] | Commodity Contracts-Physical [Member] | Natural Gas [Member]	'		'
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]	'		'
Assets and liabilities accounted for at fair value on a recurring basis	1.8	[2]	1.1	[3]
Level 3 [Member] | Commodity Contracts-Physical [Member] | Crude Oil [Member]	'		'
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]	'		'
Assets and liabilities accounted for at fair value on a recurring basis	-1.5	[2]	-0.5	[3]
Level 3 [Member] | Commodity Contracts-Physical [Member] | NGL [Member]	'		'
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]	'		'
Assets and liabilities accounted for at fair value on a recurring basis	7.4	[2]	-0.1	[3]
Level 3 [Member] | Commodity Contracts-Physical [Member] | Power [Member]	'		'
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]	'		'
Assets and liabilities accounted for at fair value on a recurring basis	-0.1	[2]	-0.7	[3]
Level 3 [Member] | Commodity Options [Member]	'		'
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]	'		'
Assets and liabilities accounted for at fair value on a recurring basis	5.3	[2]	8.4	[3]
[1]	Prices are in dollars per Millions of British Thermal Units, or MMBtu, for Natural Gas; dollars per Gallon, or Gal, for NGLs; dollars per barrel, or Bbl, for Crude Oil; and dollars per Megawatt hour, or MWh, for Power.
[2]	Fair values include credit valuation adjustments of approximately $0.1 million of losses.
[3]	Fair values include credit valuation adjustments of approximately $0.1 million of gains.

Recovered_Sheet6

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Reconciliation of Changes in Fair Value of L3 Assets and Liabilities on Recurring Basis) (Details) (USD $)	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]	'
Beginning balance	$1.30
Transfer in (out) of Level 3	'	[1]
Gains or losses included in earnings	6.1
Gains or losses included in other comprehensive income	-0.2
Purchases, issuances, sales and settlements:	'
Purchases	0.4
Sales	-1.6
Settlements	8.7	[2]
Ending balance	14.7
Amount of changes in net assets attributable to the change in unrealized gains or losses related to assets still held at the reporting date	7.8
Operating Revenue [Member]	'
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]	'
Gains or losses included in earnings	11.2
Commodity Contracts-Financial [Member]	'
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]	'
Beginning balance	-6.9
Transfer in (out) of Level 3	'	[1]
Gains or losses included in earnings	-3.9
Gains or losses included in other comprehensive income	-0.2
Purchases, issuances, sales and settlements:	'
Purchases	'
Sales	'
Settlements	12.8	[2]
Ending balance	1.8
Amount of changes in net assets attributable to the change in unrealized gains or losses related to assets still held at the reporting date	2.4
Commodity Contracts-Financial [Member] | Operating Revenue [Member]	'
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]	'
Gains or losses included in earnings	'
Commodity Contracts-Physical [Member]	'
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]	'
Beginning balance	-0.2
Transfer in (out) of Level 3	'	[1]
Gains or losses included in earnings	11.1
Gains or losses included in other comprehensive income	'
Purchases, issuances, sales and settlements:	'
Purchases	'
Sales	'
Settlements	-3.3	[2]
Ending balance	7.6
Amount of changes in net assets attributable to the change in unrealized gains or losses related to assets still held at the reporting date	7.2
Commodity Contracts-Physical [Member] | Operating Revenue [Member]	'
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]	'
Gains or losses included in earnings	11.2
Commodity Options [Member]	'
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]	'
Beginning balance	8.4
Transfer in (out) of Level 3	'	[1]
Gains or losses included in earnings	-1.1
Gains or losses included in other comprehensive income	'
Purchases, issuances, sales and settlements:	'
Purchases	0.4
Sales	-1.6
Settlements	-0.8	[2]
Ending balance	5.3
Amount of changes in net assets attributable to the change in unrealized gains or losses related to assets still held at the reporting date	-1.8
Commodity Options [Member] | Operating Revenue [Member]	'
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]	'
Gains or losses included in earnings	'
[1]	Our policy is to recognize transfers as of the last day of the reporting period.
[2]	Settlements represent the realized portion of forward contracts.

Recovered_Sheet7

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Fair Values of Expected Cash Flows of Commodity Based Swaps and Physical Contracts) (Details) (USD $)	9 Months Ended		12 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014		Dec. 31, 2013
Fair Value	'		'
Asset	$74.40		$119.90
Liability Derivatives	-293.5		-208.6	[1]
Swaps - Portion of Contracts Maturing in 2014 - Receive Variable/Pay Fixed - Natural Gas [Member]	'		'
Derivative [Line Items]	'		'
Notional	668,692	[2]	'
Fair Value	'		'
Asset	0.1	[3]	'	[3]
Liability Derivatives	'	[3]	'	[3]
Swaps - Portion of Contracts Maturing in 2014 - Receive Variable/Pay Fixed - NGL [Member]	'		'
Derivative [Line Items]	'		'
Notional	623,000	[2]	'
Fair Value	'		'
Asset	0.3	[3]	0.6	[3]
Liability Derivatives	-0.7	[3]	-0.4	[3]
Swaps - Portion of Contracts Maturing in 2014 - Receive Variable/Pay Fixed - Crude Oil [Member]	'		'
Derivative [Line Items]	'		'
Notional	95,000	[2]	'
Fair Value	'		'
Asset	'	[3]	'	[3]
Liability Derivatives	-0.3	[3]	'	[3]
Swaps - Portion of Contracts Maturing in 2014 - Receive Fixed/Pay Variable - Natural Gas [Member]	'		'
Derivative [Line Items]	'		'
Notional	2,380,100	[2]	'
Fair Value	'		'
Asset	0.5	[3]	0.1	[3]
Liability Derivatives	-0.1	[3]	-1	[3]
Swaps - Portion of Contracts Maturing in 2014 - Receive Fixed/Pay Variable - NGL [Member]	'		'
Derivative [Line Items]	'		'
Notional	2,021,140	[2]	'
Fair Value	'		'
Asset	3.7	[3]	4.8	[3]
Liability Derivatives	-1.8	[3]	-12.7	[3]
Swaps - Portion of Contracts Maturing in 2014 - Receive Fixed/Pay Variable - Crude Oil [Member]	'		'
Derivative [Line Items]	'		'
Notional	457,764	[2]	'
Fair Value	'		'
Asset	2.7	[3]	3.4	[3]
Liability Derivatives	-0.4	[3]	-5.4	[3]
Swaps - Portion of Contracts Maturing in 2014 - Receive Variable/Pay Variable - Natural Gas [Member]	'		'
Derivative [Line Items]	'		'
Notional	19,562,500	[2]	'
Fair Value	'		'
Asset	0.6	[3]	0.6	[3]
Liability Derivatives	-0.5	[3]	-0.1	[3]
Physical Contracts - Portion of Contracts Maturing in 2014 - Receive Variable/Pay Fixed - Natural Gas [Member]	'		'
Derivative [Line Items]	'		'
Notional	313,224	[2]	'
Fair Value	'		'
Asset	0.8	[3]	'	[3]
Liability Derivatives	'	[3]	'	[3]
Physical Contracts - Portion of Contracts Maturing in 2014 - Receive Variable/Pay Fixed - NGL [Member]	'		'
Derivative [Line Items]	'		'
Notional	550,000	[2]	'
Fair Value	'		'
Asset	'	[3]	0.9	[3]
Liability Derivatives	-0.8	[3]	-0.9	[3]
Physical Contracts - Portion of Contracts Maturing in 2014 - Receive Variable/Pay Fixed - Crude Oil [Member]	'		'
Derivative [Line Items]	'		'
Notional	45,000	[2]	'
Fair Value	'		'
Asset	'	[3]	'	[3]
Liability Derivatives	-0.1	[3]	'	[3]
Physical Contracts - Portion of Contracts Maturing in 2014 - Receive Fixed/Pay Variable - Natural Gas [Member]	'		'
Derivative [Line Items]	'		'
Notional	185,506	[2]	'
Fair Value	'		'
Asset	'	[3]	'	[3]
Liability Derivatives	'	[3]	'	[3]
Physical Contracts - Portion of Contracts Maturing in 2014 - Receive Fixed/Pay Variable - NGL [Member]	'		'
Derivative [Line Items]	'		'
Notional	3,504,872	[2]	'
Fair Value	'		'
Asset	5.1	[3]	0.4	[3]
Liability Derivatives	-0.4	[3]	-2.6	[3]
Physical Contracts - Portion of Contracts Maturing in 2014 - Receive Fixed/Pay Variable - Crude Oil [Member]	'		'
Derivative [Line Items]	'		'
Notional	75,000	[2]	'
Fair Value	'		'
Asset	0.2	[3]	'	[3]
Liability Derivatives	'	[3]	-0.4	[3]
Physical Contracts - Portion of Contracts Maturing in 2014 - Pay Fixed - Power [Member]	'		'
Derivative [Line Items]	'		'
Notional	14,716	[2],[4]	'
Fair Value	'		'
Asset	'	[3],[4]	'	[3],[4]
Liability Derivatives	-0.1	[3],[4]	-0.7	[3],[4]
Physical Contracts - Portion of Contracts Maturing in 2014 - Receive Variable/Pay Variable - Natural Gas [Member]	'		'
Derivative [Line Items]	'		'
Notional	72,613,470	[2]	'
Fair Value	'		'
Asset	0.9	[3]	0.9	[3]
Liability Derivatives	-1.1	[3]	-0.4	[3]
Physical Contracts - Portion of Contracts Maturing in 2014 - Receive Variable/Pay Variable - NGL [Member]	'		'
Derivative [Line Items]	'		'
Notional	10,947,422	[2]	'
Fair Value	'		'
Asset	2.7	[3]	5.8	[3]
Liability Derivatives	-0.6	[3]	-3.7	[3]
Physical Contracts - Portion of Contracts Maturing in 2014 - Receive Variable/Pay Variable - Crude Oil [Member]	'		'
Derivative [Line Items]	'		'
Notional	758,914	[2]	'
Fair Value	'		'
Asset	0.8	[3]	1.1	[3]
Liability Derivatives	-2.5	[3]	-1.2	[3]
Swaps - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Fixed - Natural Gas [Member]	'		'
Derivative [Line Items]	'		'
Notional	316,837	[2]	'
Fair Value	'		'
Asset	'	[3]	'	[3]
Liability Derivatives	'	[3]	'	[3]
Swaps - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Fixed - NGL [Member]	'		'
Derivative [Line Items]	'		'
Notional	145,850	[2]	'
Fair Value	'		'
Asset	'	[3]	'	[3]
Liability Derivatives	-0.8	[3]	'	[3]
Swaps - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Fixed - Crude Oil [Member]	'		'
Derivative [Line Items]	'		'
Notional	456,000	[2]	'
Fair Value	'		'
Asset	'	[3]	'	[3]
Liability Derivatives	-2.3	[3]	'	[3]
Swaps - Portion of Contracts Maturing in 2015 - Receive Fixed/Pay Variable - Natural Gas [Member]	'		'
Derivative [Line Items]	'		'
Notional	809,761	[2]	'
Fair Value	'		'
Asset	0.3	[3]	'	[3]
Liability Derivatives	'	[3]	'	[3]
Swaps - Portion of Contracts Maturing in 2015 - Receive Fixed/Pay Variable - NGL [Member]	'		'
Derivative [Line Items]	'		'
Notional	1,024,750	[2]	'
Fair Value	'		'
Asset	3.1	[3]	1.5	[3]
Liability Derivatives	-1	[3]	-1.1	[3]
Swaps - Portion of Contracts Maturing in 2015 - Receive Fixed/Pay Variable - Crude Oil [Member]	'		'
Derivative [Line Items]	'		'
Notional	1,303,165	[2]	'
Fair Value	'		'
Asset	11.7	[3]	8.3	[3]
Liability Derivatives	'	[3]	'	[3]
Swaps - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Variable - Natural Gas [Member]	'		'
Derivative [Line Items]	'		'
Notional	42,725,000	[2]	'
Fair Value	'		'
Asset	0.8	[3]	0.1	[3]
Liability Derivatives	-1.7	[3]	'	[3]
Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Fixed - NGL [Member]	'		'
Derivative [Line Items]	'		'
Notional	95,000	[2]	'
Fair Value	'		'
Asset	'	[3]	'	[3]
Liability Derivatives	-0.2	[3]	'	[3]
Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Fixed/Pay Variable - NGL [Member]	'		'
Derivative [Line Items]	'		'
Notional	586,394	[2]	'
Fair Value	'		'
Asset	1	[3]	'	[3]
Liability Derivatives	'	[3]	'	[3]
Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Variable - Natural Gas [Member]	'		'
Derivative [Line Items]	'		'
Notional	108,991,322	[2]	'
Fair Value	'		'
Asset	1.4	[3]	0.5	[3]
Liability Derivatives	-0.7	[3]	-0.1	[3]
Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Variable - NGL [Member]	'		'
Derivative [Line Items]	'		'
Notional	3,094,719	[2]	'
Fair Value	'		'
Asset	1.2	[3]	'	[3]
Liability Derivatives	-0.5	[3]	'	[3]
Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Variable - Crude Oil [Member]	'		'
Derivative [Line Items]	'		'
Notional	151,000	[2]	'
Fair Value	'		'
Asset	0.2	[3]	'	[3]
Liability Derivatives	'	[3]	'	[3]
Swaps - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Fixed - Natural Gas [Member]	'		'
Derivative [Line Items]	'		'
Notional	181,435	[2]	'
Fair Value	'		'
Asset	'	[3]	'	[3]
Liability Derivatives	'	[3]	'	[3]
Swaps - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Fixed - Crude Oil [Member]	'		'
Derivative [Line Items]	'		'
Notional	68,250	[2]	'
Fair Value	'		'
Asset	'	[3]	'	[3]
Liability Derivatives	-0.2	[3]	'	[3]
Swaps - Portion of Contracts Maturing in 2016 - Receive Fixed/Pay Variable - Crude Oil [Member]	'		'
Derivative [Line Items]	'		'
Notional	68,250	[2]	'
Fair Value	'		'
Asset	0.3	[3]	0.7	[3]
Liability Derivatives	'	[3]	'	[3]
Swaps - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Variable - Natural Gas [Member]	'		'
Derivative [Line Items]	'		'
Notional	12,027,000	[2]	'
Fair Value	'		'
Asset	0.1	[3]	'	[3]
Liability Derivatives	-0.3	[3]	'	[3]
Physical Contracts - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Variable - Natural Gas [Member]	'		'
Derivative [Line Items]	'		'
Notional	34,560,879	[2]	'
Fair Value	'		'
Asset	0.7	[3]	0.1	[3]
Liability Derivatives	-0.4	[3]	'	[3]
Physical Contracts - Portion of Contracts Maturing in 2017 - Receive Variable/Pay Variable - Natural Gas [Member]	'		'
Derivative [Line Items]	'		'
Notional	14,299,743	[2]	'
Fair Value	'		'
Asset	0.2	[3]	'	[3]
Liability Derivatives	-0.1	[3]	'	[3]
Swap [Member]	'		'
Fair Value	'		'
Credit valuation adjustments	($0.20)		$0.10
Receive [Member] | Swaps - Portion of Contracts Maturing in 2014 - Receive Variable/Pay Fixed - Natural Gas [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	4	[5]	'
Receive [Member] | Swaps - Portion of Contracts Maturing in 2014 - Receive Variable/Pay Fixed - NGL [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	56.02	[5]	'
Receive [Member] | Swaps - Portion of Contracts Maturing in 2014 - Receive Variable/Pay Fixed - Crude Oil [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	89.87	[5]	'
Receive [Member] | Swaps - Portion of Contracts Maturing in 2014 - Receive Fixed/Pay Variable - Natural Gas [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	4.26	[5]	'
Receive [Member] | Swaps - Portion of Contracts Maturing in 2014 - Receive Fixed/Pay Variable - NGL [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	51.91	[5]	'
Receive [Member] | Swaps - Portion of Contracts Maturing in 2014 - Receive Fixed/Pay Variable - Crude Oil [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	95.26	[5]	'
Receive [Member] | Swaps - Portion of Contracts Maturing in 2014 - Receive Variable/Pay Variable - Natural Gas [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	4.03	[5]	'
Receive [Member] | Physical Contracts - Portion of Contracts Maturing in 2014 - Receive Variable/Pay Fixed - Natural Gas [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	3.89	[5]	'
Receive [Member] | Physical Contracts - Portion of Contracts Maturing in 2014 - Receive Variable/Pay Fixed - NGL [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	42.4	[5]	'
Receive [Member] | Physical Contracts - Portion of Contracts Maturing in 2014 - Receive Variable/Pay Fixed - Crude Oil [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	90.85	[5]	'
Receive [Member] | Physical Contracts - Portion of Contracts Maturing in 2014 - Receive Fixed/Pay Variable - Natural Gas [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	4.03	[5]	'
Receive [Member] | Physical Contracts - Portion of Contracts Maturing in 2014 - Receive Fixed/Pay Variable - NGL [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	39.2	[5]	'
Receive [Member] | Physical Contracts - Portion of Contracts Maturing in 2014 - Receive Fixed/Pay Variable - Crude Oil [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	93.08	[5]	'
Receive [Member] | Physical Contracts - Portion of Contracts Maturing in 2014 - Pay Fixed - Power [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	37.84	[4],[5]	'
Receive [Member] | Physical Contracts - Portion of Contracts Maturing in 2014 - Receive Variable/Pay Variable - Natural Gas [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	4.02	[5]	'
Receive [Member] | Physical Contracts - Portion of Contracts Maturing in 2014 - Receive Variable/Pay Variable - NGL [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	42.8	[5]	'
Receive [Member] | Physical Contracts - Portion of Contracts Maturing in 2014 - Receive Variable/Pay Variable - Crude Oil [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	88.26	[5]	'
Receive [Member] | Swaps - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Fixed - Natural Gas [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	3.91	[5]	'
Receive [Member] | Swaps - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Fixed - NGL [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	72.56	[5]	'
Receive [Member] | Swaps - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Fixed - Crude Oil [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	87.81	[5]	'
Receive [Member] | Swaps - Portion of Contracts Maturing in 2015 - Receive Fixed/Pay Variable - Natural Gas [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	4.56	[5]	'
Receive [Member] | Swaps - Portion of Contracts Maturing in 2015 - Receive Fixed/Pay Variable - NGL [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	54.42	[5]	'
Receive [Member] | Swaps - Portion of Contracts Maturing in 2015 - Receive Fixed/Pay Variable - Crude Oil [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	96.75	[5]	'
Receive [Member] | Swaps - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Variable - Natural Gas [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	3.92	[5]	'
Receive [Member] | Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Fixed - NGL [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	46.73	[5]	'
Receive [Member] | Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Fixed/Pay Variable - NGL [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	49.38	[5]	'
Receive [Member] | Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Variable - Natural Gas [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	4.05	[5]	'
Receive [Member] | Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Variable - NGL [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	61.4	[5]	'
Receive [Member] | Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Variable - Crude Oil [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	90.3	[5]	'
Receive [Member] | Swaps - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Fixed - Natural Gas [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	3.78	[5]	'
Receive [Member] | Swaps - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Fixed - Crude Oil [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	86.36	[5]	'
Receive [Member] | Swaps - Portion of Contracts Maturing in 2016 - Receive Fixed/Pay Variable - Crude Oil [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	90.89	[5]	'
Receive [Member] | Swaps - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Variable - Natural Gas [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	3.96	[5]	'
Receive [Member] | Physical Contracts - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Variable - Natural Gas [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	4.06	[5]	'
Receive [Member] | Physical Contracts - Portion of Contracts Maturing in 2017 - Receive Variable/Pay Variable - Natural Gas [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	4.27	[5]	'
Pay [Member] | Swaps - Portion of Contracts Maturing in 2014 - Receive Variable/Pay Fixed - Natural Gas [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	3.91	[5]	'
Pay [Member] | Swaps - Portion of Contracts Maturing in 2014 - Receive Variable/Pay Fixed - NGL [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	56.64	[5]	'
Pay [Member] | Swaps - Portion of Contracts Maturing in 2014 - Receive Variable/Pay Fixed - Crude Oil [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	92.56	[5]	'
Pay [Member] | Swaps - Portion of Contracts Maturing in 2014 - Receive Fixed/Pay Variable - Natural Gas [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	4.09	[5]	'
Pay [Member] | Swaps - Portion of Contracts Maturing in 2014 - Receive Fixed/Pay Variable - NGL [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	50.97	[5]	'
Pay [Member] | Swaps - Portion of Contracts Maturing in 2014 - Receive Fixed/Pay Variable - Crude Oil [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	90.14	[5]	'
Pay [Member] | Swaps - Portion of Contracts Maturing in 2014 - Receive Variable/Pay Variable - Natural Gas [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	4.02	[5]	'
Pay [Member] | Physical Contracts - Portion of Contracts Maturing in 2014 - Receive Variable/Pay Fixed - Natural Gas [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	1.23	[5]	'
Pay [Member] | Physical Contracts - Portion of Contracts Maturing in 2014 - Receive Variable/Pay Fixed - NGL [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	43.88	[5]	'
Pay [Member] | Physical Contracts - Portion of Contracts Maturing in 2014 - Receive Variable/Pay Fixed - Crude Oil [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	93.9	[5]	'
Pay [Member] | Physical Contracts - Portion of Contracts Maturing in 2014 - Receive Fixed/Pay Variable - Natural Gas [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	3.97	[5]	'
Pay [Member] | Physical Contracts - Portion of Contracts Maturing in 2014 - Receive Fixed/Pay Variable - NGL [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	37.85	[5]	'
Pay [Member] | Physical Contracts - Portion of Contracts Maturing in 2014 - Receive Fixed/Pay Variable - Crude Oil [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	90.62	[5]	'
Pay [Member] | Physical Contracts - Portion of Contracts Maturing in 2014 - Pay Fixed - Power [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	46.59	[4],[5]	'
Pay [Member] | Physical Contracts - Portion of Contracts Maturing in 2014 - Receive Variable/Pay Variable - Natural Gas [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	4.02	[5]	'
Pay [Member] | Physical Contracts - Portion of Contracts Maturing in 2014 - Receive Variable/Pay Variable - NGL [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	42.61	[5]	'
Pay [Member] | Physical Contracts - Portion of Contracts Maturing in 2014 - Receive Variable/Pay Variable - Crude Oil [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	90.52	[5]	'
Pay [Member] | Swaps - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Fixed - Natural Gas [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	3.93	[5]	'
Pay [Member] | Swaps - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Fixed - NGL [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	78.2	[5]	'
Pay [Member] | Swaps - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Fixed - Crude Oil [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	92.94	[5]	'
Pay [Member] | Swaps - Portion of Contracts Maturing in 2015 - Receive Fixed/Pay Variable - Natural Gas [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	4.21	[5]	'
Pay [Member] | Swaps - Portion of Contracts Maturing in 2015 - Receive Fixed/Pay Variable - NGL [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	52.36	[5]	'
Pay [Member] | Swaps - Portion of Contracts Maturing in 2015 - Receive Fixed/Pay Variable - Crude Oil [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	87.78	[5]	'
Pay [Member] | Swaps - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Variable - Natural Gas [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	3.94	[5]	'
Pay [Member] | Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Fixed - NGL [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	48.37	[5]	'
Pay [Member] | Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Fixed/Pay Variable - NGL [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	47.79	[5]	'
Pay [Member] | Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Variable - Natural Gas [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	4.05	[5]	'
Pay [Member] | Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Variable - NGL [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	61.19	[5]	'
Pay [Member] | Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Variable - Crude Oil [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	88.89	[5]	'
Pay [Member] | Swaps - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Fixed - Natural Gas [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	3.85	[5]	'
Pay [Member] | Swaps - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Fixed - Crude Oil [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	90	[5]	'
Pay [Member] | Swaps - Portion of Contracts Maturing in 2016 - Receive Fixed/Pay Variable - Crude Oil [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	86.36	[5]	'
Pay [Member] | Swaps - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Variable - Natural Gas [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	3.98	[5]	'
Pay [Member] | Physical Contracts - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Variable - Natural Gas [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	4.05	[5]	'
Pay [Member] | Physical Contracts - Portion of Contracts Maturing in 2017 - Receive Variable/Pay Variable - Natural Gas [Member]	'		'
Derivative [Line Items]	'		'
Wtd. Average Price	4.26	[5]	'
[1]	Includes $16.7 million of cash collateral at December 31, 2013.
[2]	Volumes of natural gas are measured in MMBtu, whereas volumes of NGL and crude oil are measured in Bbl. Our power purchase agreements are measured in MWh.
[3]	The fair value is determined based on quoted market prices at September 30, 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 $0.2 million of losses and $0.1 million of gains at September 30, 2014 and December 31, 2013, respectively.
[4]	For physical power, the receive price shown represents the index price used for valuation purposes.
[5]	Weighted average prices received and paid are in $/MMBtu for natural gas, $/Bbl for NGL and crude oil and $/MWh for power.

Recovered_Sheet8

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Fair Values of Expected Cash Flows of Commodity Options) (Details) (USD $)	Sep. 30, 2014		Dec. 31, 2013
In Millions, unless otherwise specified
Fair Value	'		'
Liability	($293.50)		($184.30)	[1]
Written [Member] | Portion of Put Option Contracts Maturing in 2014 - Natural Gas [Member]	'		'
Derivative [Line Items]	'		'
Notional	1,104,000	[2]	'
Strike Price	3.9	[3]	'
Market Price	4.1	[3]	'
Fair Value	'		'
Asset	'	[4]	'
Liability	-0.1	[4]	-0.5	[4]
Written [Member] | Portion of Put Option Contracts Maturing in 2014 - NGL [Member]	'		'
Derivative [Line Items]	'		'
Notional	32,200	[2]	'
Strike Price	66.36	[3]	'
Market Price	51.7	[3]	'
Fair Value	'		'
Asset	'	[4]	'	[4]
Liability	-0.5	[4]	'	[4]
Written [Member] | Portion of Call Option Contracts Maturing in 2014 - NGL [Member]	'		'
Derivative [Line Items]	'		'
Notional	115,000	[2]	'
Strike Price	60.92	[3]	'
Market Price	54.59	[3]	'
Fair Value	'		'
Asset	'	[4]	'
Liability	-0.1	[4]	-1	[4]
Written [Member] | Portion of Put Option Contracts Maturing in 2015 - Natural Gas [Member]	'		'
Derivative [Line Items]	'		'
Notional	4,015,000	[2]	'
Strike Price	3.9	[3]	'
Market Price	4	[3]	'
Fair Value	'		'
Asset	'	[4]	'	[4]
Liability	-1.4	[4]	'	[4]
Written [Member] | Portion of Call Option Contracts Maturing in 2015 - Natural Gas [Member]	'		'
Derivative [Line Items]	'		'
Notional	1,277,500	[2]	'
Strike Price	5.05	[3]	'
Market Price	4	[3]	'
Fair Value	'		'
Asset	'	[4]	'	[4]
Liability	-0.1	[4]	-0.3	[4]
Written [Member] | Portion of Call Option Contracts Maturing in 2015 - NGL [Member]	'		'
Derivative [Line Items]	'		'
Notional	529,250	[2]	'
Strike Price	55.18	[3]	'
Market Price	50.29	[3]	'
Fair Value	'		'
Asset	'	[4]	'	[4]
Liability	-1.7	[4]	-1	[4]
Written [Member] | Portion of Call Option Contracts Maturing in 2015 - Crude Oil [Member]	'		'
Derivative [Line Items]	'		'
Notional	547,500	[2]	'
Strike Price	91.75	[3]	'
Market Price	87.76	[3]	'
Fair Value	'		'
Asset	'	[4]	'	[4]
Liability	-2.1	[4]	-1.9	[4]
Written [Member] | Portion of Call Option Contracts Maturing in 2016 - Natural Gas [Member]	'		'
Derivative [Line Items]	'		'
Notional	1,647,000	[2]	'
Strike Price	4.98	[3]	'
Market Price	4.08	[3]	'
Fair Value	'		'
Asset	'	[4]	'	[4]
Liability	-0.3	[4]	'	[4]
Written [Member] | Portion of Call Option Contracts Maturing in 2016 - NGL [Member]	'		'
Derivative [Line Items]	'		'
Notional	1,281,000	[2]	'
Strike Price	48.59	[3]	'
Market Price	44.06	[3]	'
Fair Value	'		'
Asset	'	[4]	'	[4]
Liability	-5.6	[4]	'	[4]
Written [Member] | Portion of Call Option Contracts Maturing in 2016 - Crude Oil [Member]	'		'
Derivative [Line Items]	'		'
Notional	439,200	[2]	'
Strike Price	92.25	[3]	'
Market Price	85.93	[3]	'
Fair Value	'		'
Asset	'	[4]	'	[4]
Liability	-2.2	[4]	'	[4]
Purchased [Member] | Portion of Put Option Contracts Maturing in 2014 - Natural Gas [Member]	'		'
Derivative [Line Items]	'		'
Notional	1,104,000	[2]	'
Strike Price	3.9	[3]	'
Market Price	4.1	[3]	'
Fair Value	'		'
Asset	0.1	[4]	0.7	[4]
Liability	'	[4]	'	[4]
Purchased [Member] | Portion of Put Option Contracts Maturing in 2014 - NGL [Member]	'		'
Derivative [Line Items]	'		'
Notional	193,200	[2]	'
Strike Price	54.79	[3]	'
Market Price	52.43	[3]	'
Fair Value	'		'
Asset	0.9	[4]	2.9	[4]
Liability	'	[4]	'	[4]
Purchased [Member] | Portion of Call Option Contracts Maturing in 2014 - NGL [Member]	'		'
Derivative [Line Items]	'		'
Notional	46,000	[2]	'
Strike Price	50.4	[3]	'
Market Price	43.84	[3]	'
Fair Value	'		'
Asset	'	[4]	'	[4]
Liability	'	[4]	'	[4]
Purchased [Member] | Portion of Put Option Contracts Maturing in 2015 - Natural Gas [Member]	'		'
Derivative [Line Items]	'		'
Notional	4,015,000	[2]	'
Strike Price	3.9	[3]	'
Market Price	4	[3]	'
Fair Value	'		'
Asset	1.4	[4]	1.7	[4]
Liability	'	[4]	'	[4]
Purchased [Member] | Portion of Put Option Contracts Maturing in 2015 - NGL [Member]	'		'
Derivative [Line Items]	'		'
Notional	1,350,500	[2]	'
Strike Price	48.75	[3]	'
Market Price	50.62	[3]	'
Fair Value	'		'
Asset	5.5	[4]	6	[4]
Liability	'	[4]	'	[4]
Purchased [Member] | Portion of Put Option Contracts Maturing in 2015 - Crude Oil [Member]	'		'
Derivative [Line Items]	'		'
Notional	547,500	[2]	'
Strike Price	85.42	[3]	'
Market Price	87.76	[3]	'
Fair Value	'		'
Asset	2.3	[4]	1.8	[4]
Liability	'	[4]	'	[4]
Purchased [Member] | Portion of Call Option Contracts Maturing in 2015 - Natural Gas [Member]	'		'
Derivative [Line Items]	'		'
Notional	1,277,500	[2]	'
Strike Price	5.05	[3]	'
Market Price	4	[3]	'
Fair Value	'		'
Asset	0.1	[4]	'	[4]
Liability	'	[4]	'	[4]
Purchased [Member] | Portion of Put Option Contracts Maturing in 2016 - Natural Gas [Member]	'		'
Derivative [Line Items]	'		'
Notional	1,647,000	[2]	'
Strike Price	3.75	[3]	'
Market Price	4.08	[3]	'
Fair Value	'		'
Asset	0.5	[4]	'	[4]
Liability	'	[4]	'	[4]
Purchased [Member] | Portion of Put Option Contracts Maturing in 2016 - NGL [Member]	'		'
Derivative [Line Items]	'		'
Notional	1,281,000	[2]	'
Strike Price	41.82	[3]	'
Market Price	44.06	[3]	'
Fair Value	'		'
Asset	6.5	[4]	'	[4]
Liability	'	[4]	'	[4]
Purchased [Member] | Portion of Put Option Contracts Maturing in 2016 - Crude Oil [Member]	'		'
Derivative [Line Items]	'		'
Notional	439,200	[2]	'
Strike Price	80	[3]	'
Market Price	85.93	[3]	'
Fair Value	'		'
Asset	2	[4]	'	[4]
Liability	'	[4]	'	[4]
[1]	Includes $16.7 million of cash collateral at December 31, 2013.
[2]	Volumes of natural gas are measured in MMBtu, whereas volumes of NGL and crude oil are measured in Bbl.
[3]	Strike and market prices are in $/MMBtu for natural gas and in $/Bbl for NGL and crude oil.
[4]	The fair value is determined based on quoted market prices at September 30, 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.

Recovered_Sheet9

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Interest Rate Derivatives) (Details) (Interest Rate Swaps [Member], Derivatives in Cash Flow Hedging Relationships [Member], USD $)	9 Months Ended		12 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014		Dec. 31, 2013
Derivative [Line Items]	'		'
Credit valuation adjustments	$12.70		($7.10)
Contracts Maturing In 2015 [Member]	'		'
Derivative [Line Items]	'		'
Notional	510		'
Average Fixed Rate	1.53%	[1]	'
Interest Rate Derivatives, at Fair Value, Net	-1.9	[2]	-6.8	[2]
Contracts Maturing In 2016 [Member]	'		'
Derivative [Line Items]	'		'
Notional	90		'
Average Fixed Rate	0.55%	[1]	'
Interest Rate Derivatives, at Fair Value, Net	'	[2]	'	[2]
Contracts Maturing In 2017 [Member]	'		'
Derivative [Line Items]	'		'
Notional	450		'
Average Fixed Rate	2.21%	[1]	'
Interest Rate Derivatives, at Fair Value, Net	-12.2	[2]	-13.8	[2]
Contracts Maturing In 2018 [Member]	'		'
Derivative [Line Items]	'		'
Notional	810		'
Average Fixed Rate	2.24%	[1]	'
Interest Rate Derivatives, at Fair Value, Net	1.4	[2]	3.3	[2]
Contracts Maturing In 2019 [Member]	'		'
Derivative [Line Items]	'		'
Notional	620		'
Average Fixed Rate	2.96%	[1]	'
Interest Rate Derivatives, at Fair Value, Net	-1	[2]	'	[2]
Contracts Settling Prior to Maturity - 2014 Pre Issuance Hedges [Member]	'		'
Derivative [Line Items]	'		'
Notional	'		'
Average Fixed Rate	0.00%	[1],[3]	'
Interest Rate Derivatives, at Fair Value, Net	'	[2],[3]	-132.7	[2],[3]
Contracts Settling Prior to Maturity - 2015 Pre Issuance Hedges [Member]	'		'
Derivative [Line Items]	'		'
Notional	1,000		'
Average Fixed Rate	5.48%	[1]	'
Interest Rate Derivatives, at Fair Value, Net	-208.5	[2]	'	[2]
Contracts Settling Prior to Maturity - 2016 Pre Issuance Hedges [Member]	'		'
Derivative [Line Items]	'		'
Notional	500		'
Average Fixed Rate	4.21%	[1]	'
Interest Rate Derivatives, at Fair Value, Net	-38	[2]	60.8	[2]
Contracts Settling Prior to Maturity - 2017 Pre Issuance Hedges [Member]	'		'
Derivative [Line Items]	'		'
Notional	500		'
Average Fixed Rate	3.69%	[1]	'
Interest Rate Derivatives, at Fair Value, Net	-10.8	[2]	'	[2]
Contracts Settling Prior to Maturity - 2018 Pre Issuance Hedges [Member]	'		'
Derivative [Line Items]	'		'
Notional	350		'
Average Fixed Rate	3.08%	[1]	'
Interest Rate Derivatives, at Fair Value, Net	$12.40	[2]	'	[2]
[1]	Interest rate derivative contracts are based on the one-month or three-month London Interbank Offered Rate, or LIBOR.
[2]	The fair value is determined from quoted market prices at September 30, 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 $12.7 million of gains at September 30, 2014 and $7.1 million of losses at December 31, 2013.
[3]	Includes $16.7 million of cash collateral at December 31, 2013.

INCOME_TAXES_Details

INCOME TAXES (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013
Effective income tax rate	'	'	0.40%	0.40%	'
Income tax expense	$2.10	$1.50	$6.10	$17.50	'
Current income tax payable	1.1	'	1.1	'	0.9
Deferred income tax liability (Note 11)	$19	'	$19	'	$17.40

SEGMENT_INFORMATION_Details

SEGMENT INFORMATION (Details) (USD $)	3 Months Ended				9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014		Sep. 30, 2013		Sep. 30, 2014		Sep. 30, 2013		Dec. 31, 2013
					segments
Segment Reporting Information [Line Items]	'		'		'		'		'
Number of segments	'		'		2		'		'
Operating revenue	$1,942.30		$1,789.40		$5,893		$5,155.10		'
Cost of natural gas	1,238.20		1,257.50		3,986.70		3,564.40		'
Environmental costs, net of recoveries	50.1		0.6		93.3		184.3		'
Operating and administrative	235.3		265.1		676.9		678		'
Power	59.5		43		164.1		105.8		'
Depreciation and amortization	118.8		99.6		336		287.6		'
Costs and Expenses, Total	1,701.90		1,665.80		5,257		4,820.10		'
Operating income	240.4		123.6		636		335		'
Interest expense, net	137.1		70.5		294.2		226.4		'
Allowance for equity used during construction	14.5		9.3		47.8		25.2		'
Other income	1.8		0.4		2.2		1		'
Income before income tax expense	119.6		62.8		391.8		134.8		'
Income tax expense	2.1		1.5		6.1		17.5		'
Net income	117.5		61.3		385.7		117.3		'
Less: Net income attributable to noncontrolling interest	70.7		20.3		149.4		54.3		'
Series 1 preferred unit distributions (Note 7)	22.5		22.7		67.5		35.8		'
Accretion of discount on Series 1 preferred units (Note 7)	3.8		3.4		11.1		5.7		'
Net income attributable to general and limited partner ownership interests in Enbridge Energy Partners, L.P.	20.5		14.9		157.7		21.5		'
Total assets	16,947.10		13,884		16,947.10		13,884		14,901.50
Capital expenditures (excluding acquisitions)	'		'		2,022.90		1,733		'
Liquids [Member]	'		'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'		'
Operating revenue	542.9		401.5		1,449.90		1,100.70		'
Cost of natural gas	'		'		'		'		'
Environmental costs, net of recoveries	50.1		0.6		93.3		184.3		'
Operating and administrative	126.5		149.7		352.5		334.8		'
Power	59.5		43		164.1		105.8		'
Depreciation and amortization	79.3		63.8		222.7		181		'
Costs and Expenses, Total	315.4		257.1		832.6		805.9		'
Operating income	227.5		144.4		617.3		294.8		'
Interest expense, net	'		'		'		'		'
Allowance for equity used during construction	'		'		'		'		'
Other income	'	[1]	'		'		'		'
Income before income tax expense	227.5		144.4		617.3		294.8		'
Income tax expense	'		'		'		'		'
Net income	227.5		144.4		617.3		294.8		'
Less: Net income attributable to noncontrolling interest	'		'		'		'		'
Series 1 preferred unit distributions (Note 7)	'		'		'		'		'
Accretion of discount on Series 1 preferred units (Note 7)	'		'		'		'		'
Net income attributable to general and limited partner ownership interests in Enbridge Energy Partners, L.P.	227.5		144.4		617.3		294.8		'
Total assets	11,252.80		8,497.90		11,252.80		8,497.90		'
Capital expenditures (excluding acquisitions)	'		'		1,861.30		1,527.20		'
Natural Gas [Member]	'		'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'		'
Operating revenue	1,399.40		1,387.90		4,443.10		4,054.40		'
Cost of natural gas	1,238.20		1,257.50		3,986.70		3,564.40		'
Environmental costs, net of recoveries	'		'		'		'		'
Operating and administrative	105		113.6		317.5		337.8		'
Power	'		'		'		'		'
Depreciation and amortization	39.5		35.8		113.3		106.6		'
Costs and Expenses, Total	1,382.70		1,406.90		4,417.50		4,008.80		'
Operating income	16.7		-19		25.6		45.6		'
Interest expense, net	'		'		'		'		'
Allowance for equity used during construction	'		'		'		'		'
Other income	6.1	[1]	'		7.1	[2]	'		'
Income before income tax expense	22.8		-19		32.7		45.6		'
Income tax expense	'		'		'		'		'
Net income	22.8		-19		32.7		45.6		'
Less: Net income attributable to noncontrolling interest	'		'		'		'		'
Series 1 preferred unit distributions (Note 7)	'		'		'		'		'
Accretion of discount on Series 1 preferred units (Note 7)	'		'		'		'		'
Net income attributable to general and limited partner ownership interests in Enbridge Energy Partners, L.P.	22.8		-19		32.7		45.6		'
Total assets	5,461.90	[3]	5,224.60	[3]	5,461.90	[3]	5,224.60	[3]	'
Capital expenditures (excluding acquisitions)	'		'		158.4		191.9		'
Corporate [Member]	'		'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'		'
Operating revenue	'	[4]	'	[4]	'	[4]	'	[4]	'
Cost of natural gas	'	[4]	'	[4]	'	[4]	'	[4]	'
Environmental costs, net of recoveries	'	[4]	'	[4]	'	[4]	'	[4]	'
Operating and administrative	3.8	[4]	1.8	[4]	6.9	[4]	5.4	[4]	'
Power	'	[4]	'	[4]	'	[4]	'	[4]	'
Depreciation and amortization	'	[4]	'	[4]	'	[4]	'	[4]	'
Costs and Expenses, Total	3.8	[4]	1.8	[4]	6.9	[4]	5.4	[4]	'
Operating income	-3.8	[4]	-1.8	[4]	-6.9	[4]	-5.4	[4]	'
Interest expense, net	137.1	[4]	70.5	[4]	294.2	[4]	226.4	[4]	'
Allowance for equity used during construction	14.5	[4]	9.3	[4]	47.8	[4]	25.2	[4]	'
Other income	-4.3	[1],[4]	0.4	[4]	-4.9	[4]	1	[4]	'
Income before income tax expense	-130.7	[4]	-62.6	[4]	-258.2	[4]	-205.6	[4]	'
Income tax expense	2.1	[4]	1.5	[4]	6.1	[4]	17.5	[4]	'
Net income	-132.8	[4]	-64.1	[4]	-264.3	[4]	-223.1	[4]	'
Less: Net income attributable to noncontrolling interest	70.7	[4]	20.3	[4]	149.4	[4]	54.3	[4]	'
Series 1 preferred unit distributions (Note 7)	22.5	[4]	22.7	[4]	67.5	[4]	35.8	[4]	'
Accretion of discount on Series 1 preferred units (Note 7)	3.8	[4]	3.4	[4]	11.1	[4]	5.7	[4]	'
Net income attributable to general and limited partner ownership interests in Enbridge Energy Partners, L.P.	-229.8	[4]	-110.5	[4]	-492.3	[4]	-318.9	[4]	'
Total assets	232.4	[4]	161.5	[4]	232.4	[4]	161.5	[4]	'
Capital expenditures (excluding acquisitions)	'		'		$3.20	[4]	$13.90	[4]	'
[1]	Other income (expense) for our Natural Gas segment includes our equity investment in the Texas Express NGL system which we began recognizing operating costs during the fourth quarter of 2013.
[2]	Other income (expense) for our Natural Gas segment includes our equity investment in the Texas Express NGL system which began recognizing operating costs during the fourth quarter of 2013.
[3]	Total assets for our Natural Gas segment includes our long term equity investment in the Texas Express NGL system.
[4]	Corporate consists of interest expense, interest income, allowance for equity used during construction, noncontrolling interest and other costs such as income taxes, which are not allocated to the business segments.

REGULATORY_MATTERS_Details

REGULATORY MATTERS (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014		Sep. 30, 2013	Dec. 31, 2013
Regulatory liabilities	$5.60	'	$5.60		'	'
Regulatory assets	'	'	'		'	7.7
Current Year (Over)/Under Recovery Revenue Adjustments	-4.5	3.2	-5.6		7.7	'
Amortization of Prior Year Regulatory (Asset)/Liability	'	3.8	-7.7	[1]	11.5	'
Allowance for equity used during construction	14.5	9.3	47.8		25.2	'
Southern Access Pipeline [Member]	'	'	'		'	'
Regulatory liabilities	'	'	'		'	6.1
Increase (decrease) in revenues	'	'	6.1		4.2	'
Alberta Clipper Pipeline [Member]	'	'	'		'	'
Regulatory liabilities	6.3	'	6.3		'	6.9
Increase (decrease) in revenues	'	'	5.2		4.5	'
Obligation to refund overcollection to customers	'	'	50.00%		'	'
Adjustment for Data Received Since Beginning of Fiscal Year [Member]	'	'	'		'	'
Amortization of Prior Year Regulatory (Asset)/Liability	'	'	$7.60		'	'
[1]	The amortization of the prior year regulatory asset for the nine month period ended September 30, 2014, includes a $7.6 million adjustment of the regulatory asset for the difference between estimates as of December 31, 2013, and actual data received during the nine month period ended September 30, 2014.

SUPPLEMENTAL_CASH_FLOWS_INFORM2

SUPPLEMENTAL CASH FLOWS INFORMATION (Details) (USD $)	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013
SUPPLEMENTAL CASH FLOWS INFORMATION [Abstract]	'	'
Additions to property, plant and equipment	$2,055.80	$1,514.50
Increase (decrease) in construction payables	-32.9	218.5
Total capital expenditures (excluding "Investment in joint venture")	$2,022.90	$1,733

SUBSEQUENT_EVENTS_Details

SUBSEQUENT EVENTS (Details) (USD $)

3 Months Ended

9 Months Ended

1 Months Ended

9 Months Ended

1 Months Ended

9 Months Ended

1 Months Ended

9 Months Ended

1 Months Ended

In Millions, except Per Share data, unless otherwise specified

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Nov. 14, 2014

Sep. 30, 2014

Oct. 31, 2014

Sep. 30, 2014

Oct. 31, 2014

Oct. 31, 2014

Sep. 30, 2014

Sep. 30, 2014

Nov. 14, 2014

Oct. 30, 2014

Nov. 14, 2014

Nov. 14, 2014

Credit Facility [Member]

Credit Facility [Member]

Subsequent Event [Member]

Subsequent Event [Member]

Alberta Clipper Pipeline [Member]

Alberta Clipper Pipeline [Member]

Series EA [Member]

Series EA [Member]

Series ME Interests [Member]

Midcoast Energy Partners [Member]

Midcoast Energy Partners [Member]

Midcoast Energy Partners [Member]

Midcoast Operating [Member]

i-units [Member]

General Partner [Member]

Portion of Credit Facility Due in 2018 [Member]

Scenario, Forecast [Member]

Subsequent Event [Member]

Subsequent Event [Member]

Subsequent Event [Member]

Subsequent Event [Member]

Subsequent Event [Member]

Subsequent Event [Member]

Subsequent Event [Member]

Subsequent Event [Member]

Scenario, Forecast [Member]

Scenario, Forecast [Member]

Scenario, Forecast [Member]

Scenario, Forecast [Member]

Scenario, Forecast [Member]

Scenario, Forecast [Member]

Scenario, Forecast [Member]

Subsequent Event [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Distribution declaration date

'

'

'

'

'

'

31-Oct-14

'

'

'

'

'

'

'

30-Oct-14

'

'

'

'

Record Date

'

'

'

'

'

'

7-Nov-14

'

'

'

'

'

'

'

7-Nov-14

'

'

'

'

Distribution payment date

'

'

'

'

'

'

14-Nov-14

'

'

'

'

'

'

'

14-Nov-14

'

'

'

'

Cash available for distribution

'

'

'

'

'

'

$221.80

'

'

'

'

'

'

'

$15.60

'

'

'

'

Distribution Made to Member or Limited Partner, Distributions Paid, Per Unit

'

'

'

'

'

'

'

$0.56

'

'

'

'

'

'

'

$0.34

'

'

'

Total amount of distribution paid

'

'

'

'

'

'

'

183.7

61.1

'

31.3

'

'

37.1

'

'

'

'

'

Amount of Distribution

182.8

176.5

542.7

518.6

'

'

'

'

'

'

'

'

'

'

'

7.2

'

37.3

'

Amount Paid To Parent

'

'

'

'

'

'

'

'

20.4

10.1

8.1

14.6

0.6

20.1

'

8.4

13.5

'

0.8

Amount paid to the noncontrolling interest

'

'

'

'

'

'

'

'

40.7

20.3

23.2

43.7

1.9

17

'

'

12.6

'

'

Credit facility maturity date

'

'

'

'

26-Sep-19

26-Sep-18

'

'

'

'

'

'

'

'

'

'

'

'

'

Line of credit facility, maximum borrowing capacity

'

'

'

'

$1,975

$175

'

'

'

'

'

'

'

'

'

'

'

'

'