Enbridge Energy Partners 10-K18 Feb 152014 FY Annual reportFinancial data

Company Profile

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
Document and Entity Information (USD $)	Dec. 31, 2014	Feb. 13, 2015	Jun. 30, 2014
Document and Entity Information [Abstract]
Entity Registrant Name	ENBRIDGE ENERGY PARTNERS LP
Entity Central Index Key	880285
Document Type	10-K
Document Period End Date	31-Dec-14
Amendment Flag	FALSE
Current Fiscal Year End Date	-19
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		254,208,428
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY
Trading Symbol	eep
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$7,667,339,293

CONSOLIDATED_STATEMENTS_OF_INC

CONSOLIDATED STATEMENTS OF INCOME (USD $)	12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Commodity sales	$5,693.90	[1]	$5,368.50	[2]
Transportation and other services	2,270.80	[1]	1,748.60	[2]
Total operating revenue	7,964.70		7,117.10		6,706.10
Operating expenses:
Commodity costs	5,145.90		4,948.90		4,570.10
Environmental costs, net of recoveries (Note 13)	97.3		273.7
Environmental costs, net of recoveries (Note 13)					-91.3
Operating and administrative	950		918.4		840.5
Power (Note 14)	226.6		147.7		148.8
Depreciation and amortization (Note 7)	458.2		388		344.8
Costs and Expenses, Total	6,878		6,676.70		5,812.90
Operating income	1,086.70		440.4		893.2
Interest expense, net (Notes 10 and 14)	403.2		320.4		345
Allowance for equity used during construction (Note 17)	57.2		43.1		11.2
Other income (expense) (Notes 13 and 17)	8.9		16		-1.2
Income before income tax expense	749.6		179.1		558.2
Income tax expense (Note 15)	9.6		18.7		8.1
Net income	740		160.4		550.1
Less: Net income attributable to:
Noncontrolling interest (Note 12)	263.3		88.3		57
Series 1 preferred unit distributions	90		58.2
Accretion of discount on Series 1 preferred units	14.9		9.2
Net income attributable to general and limited partner ownership interests in Enbridge Energy Partners, L.P.	371.8		4.7		493.1
Net income (loss) allocable to common units and i-units	218.4		-122.7		369.2
Net income (loss) per common unit and i-unit (basic) (Note 4) (in dollars per share)	$0.67	[3]	($0.39)	[3]	$1.27	[3]
Weighted average limited partner units outstanding (basic) (in shares)	328.2		316.2		290.6
Net income (loss) per common unit and i-unit (diluted) (Note 4) (in dollars per share)	$0.67	[3]	($0.39)	[3]	$1.27	[3]
Weighted average common units and i-units outstanding (diluted) (in shares)	328.2		316.2		290.6
Cash distributions paid per limited partner unit outstanding (in dollars per share)	$2.20		$2.17		$2.15
Third Party [Member]
Commodity sales	5,487.80		5,155.40		4,724.30
Transportation and other services	2,191.80		1,690		1,552
Operating expenses:
Commodity costs	5,026.70		4,829.40		4,282.20
Operating and administrative	478		480.8		418.8
Affiliate [Member]
Commodity sales	206.1		213.1		396.2
Transportation and other services	79		58.6		33.6
Operating expenses:
Commodity costs	119.2		119.5		287.9
Operating and administrative	$472		$437.60		$421.70

[1]	There were no intersegment revenues for the year ended December 31, 2014.
[2]	There were no intersegment revenues for the year ended December 31, 2013.
[3]	For the year ended December 31, 2014 and 2013, 43,201,310 anti-dilutive Preferred Units were excluded from the if-converted method of calculating diluted earnings per unit. For the year ended December 31, 2014, 66,100,000 anti-dilutive Class D units were excluded from the if-converted method of calculating diluted earnings per unit.

CONSOLIDATED_STATEMENTS_OF_COM

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME [Abstract]
Net income	$740	$160.40	$550.10
Other comprehensive income (loss), net of tax expense of $0.2, $0.0, and $0.2, respectively (Note 14)	-127.7	243.9	-4
Comprehensive income	612.3	404.3	546.1
Less: Comprehensive income attributable to:
Noncontrolling interest (Note 12)	263.3	88.3	57
Series 1 preferred unit distributions	90	58.2
Accretion of discount on Series 1 preferred units	14.9	9.2
Other comprehensive income (loss) allocated to noncontrolling interest	7.1	-0.9
Comprehensive income attributable to general and limited partner ownership interests in Enbridge Energy Partners, L.P.	$237	$247.70	$489.10

CONSOLIDATED_STATEMENTS_OF_COM1

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME [Abstract]
Other comprehensive income (loss), tax expense (benefit)	$0.20	$0	$0.20

CONSOLIDATED_STATEMENTS_OF_CAS

CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Cash provided by operating activities
Net income	$740	$160.40	$550.10
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization (Note 7)	458.2	388	344.8
Derivative fair value net (gains) losses (Note 14)	-72	28.6	18.5
Inventory market price adjustments (Note 6)	11.4	3.4	9.8
Asset impairment charges (Note 7)	15.6
Environmental costs, net of recoveries (Note 13)	82.2	308.1	72.6
Distributions from investments in joint ventures (Note 12)	12.2
Equity earnings from investments in joint ventures (Note 12)	-13.2
Deferred income taxes (Note 15)	4.1	14.5	0.1
State income taxes	3.7	8.4
Allowance for equity used during construction (Note 17)	-57.2	-43.1	-11.2
Amortization of debt issuance and hedging costs	9.4	10.5	12.7
Gain on sale of assets		-17.1
Other	7.3	-3.9	1.4
Changes in operating assets and liabilities, net of acquisitions:
Receivables, trade and other	1.7	125	42.7
Due from General Partner and affiliates	0.7	-12.6	-3.1
Accrued receivables	-50.1	286.1	-61.8
Inventory (Note 6)	-10.7	-21.2	11.1
Current and long-term other assets (Note 14)	-47.1	-24.1	-7.3
Due to General Partner and affiliates (Note 12)	22.4	79.1	-12.5
Accounts payable and other (Notes 5 and 14)	-101.1	85.1	-8.6
Environmental liabilities (Note 13)	-143.1	-174.9	-100.3
Accrued purchases	-89.9	13.8	-19.1
Interest payable	6.6	4.3	-0.9
Property and other taxes payable	26.1	-0.7	12
Settlement of interest rate derivatives (Note 14)	-0.4	-5.3
Net cash provided by operating activities	816.8	1,212.40	851
Cash used in investing activities
Additions to property, plant and equipment (Notes 7 and 18)	-2,933.60	-2,409.90	-1,739.90
Changes in restricted cash (Note 12)	-27.6	-69.4
Asset acquisitions	-0.2	-0.9
Proceeds from the sale of net assets		44.7	9.5
Investment in joint venture (Note 12)	-36.7	-188.6	-168.5
Distributions from investments in joint ventures in excess of cumulative earnings	27.8
Other	-6.3	-18.8	-7.7
Net cash used in investing activities	-2,976.60	-2,642.90	-1,906.60
Cash provided by financing activities
Net proceeds from Series 1 preferred unit issuance (Note 11)		1,199.20
Net proceeds from unit issuances (Note 11)		519.3	457
Distributions to partners (Note 11)	-727.9	-708.9	-660.3
Repayments to General Partner (Note 12)	-12	-12	-12
Proceeds from long-term debt, net of discounts (Note 10)	398.1
Repayments on long-term debt (Note 10)	-200	-200	-100
Net proceeds under credit facilities (Note 10)	1,185	335
Net commercial paper borrowings (repayments) (Note 10)	312.1	-859.9	884.9
Contribution from noncontrolling interest (Notes 11 and 12)	1,391.60	1,148.50	350.9
Distributions to noncontrolling interest (Notes 11 and 12)	-154	-53.8	-59.9
Net cash provided by financing activities	2,192.90	1,367.40	860.6
Net increase (decrease) in cash and cash equivalents	33.1	-63.1	-195
Cash and cash equivalents at beginning of year	164.8	227.9	422.9
Cash and cash equivalents at end of period	$197.90	$164.80	$227.90

CONSOLIDATED_STATEMENTS_OF_FIN

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Current assets:
Cash and cash equivalents (Note 5)	$197.90	$164.80
Restricted cash (Notes 12 and 14)	97	69.4
Receivables, trade and other, net of allowance for doubtful accounts of $1.8 and $0.5 in 2014 and 2013, respectively (Notes 2 and 12)	46.2	49.4
Due from General Partner and affiliates	41.4	40.5
Accrued receivables	260.3	210.2
Inventory (Note 6)	94.2	94.9
Other current assets (Note 14)	218.4	47.6
Assets, Current, Total	955.4	676.8
Property, plant and equipment, net (Notes 7, 12 and 17)	15,692.70	13,176.80
Goodwill (Note 8)	246.7	246.7
Intangible assets, net (Note 9)	254.8	263.2
Other assets, net (Note 14)	597.3	538
Total assets	17,746.90	14,901.50
Current liabilities:
Due to General Partner and affiliates (Note 12)	143.7	121.4
Accounts payable and other (Notes 5, 14 and 17)	777.7	822
Environmental liabilities (Note 13)	141.7	233.7
Accrued purchases	375.7	465.6
Property and other taxes payable (Note 15)	96.5	70.7
Interest payable	74.6	68
Note payable to General Partner (Note 12)	306	12
Current maturities of long-term debt (Note 10)		200
Liabilities, Current, Total	1,915.90	1,993.40
Long-term debt (Note 10)	6,675.20	4,777.40
Loans from General Partner and affiliate (Note 12)		306
Due to General Partner and affiliates (Note 12)	148.3	58.2
Other long-term liabilities (Notes 13, 14, and 15)	278.1	69.1
Total Liabilities	9,017.50	7,204.10
Commitments and contingencies (Note 13)
Partners' capital (Notes 11 and 12):
Series 1 preferred units (48,000,000 at December 31, 2014 and 2013)	1,175.60	1,160.70
General Partner	198.3	301.5
Accumulated other comprehensive loss (Note 14)	-211.4	-76.6
Total Enbridge Energy Partners, L.P. partners' capital	5,120.40	5,721.80
Noncontrolling interest (Note 12)	3,609	1,975.60
Total partners' capital	8,729.40	7,697.40
Liabilities and Stockholders' Equity, Total	17,746.90	14,901.50
Class D Units [Member]
Partners' capital (Notes 11 and 12):
Common units	2,516.80
Class A Common Units [Member]
Partners' capital (Notes 11 and 12):
Common units	235.5	2,979
Class B Common Units [Member]
Partners' capital (Notes 11 and 12):
Common units		65.3
i-Units [Member]
Partners' capital (Notes 11 and 12):
Common units	712.6	1,291.90
Incentive Distribution Units [Member]
Partners' capital (Notes 11 and 12):
Common units	$493

CONSOLIDATED_STATEMENTS_OF_FIN1

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION (Parenthetical) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Receivables, trade and other, allowance for doubtful accounts (in dollars)	$1.80	$0.50
Preferred units, authorized (in shares)	48,000,000	48,000,000
Preferred units, issued (in shares)	48,000,000	48,000,000
Class D Units [Member]
Common units, authorized (in shares)	66,100,000
Common units, issued (in shares)	66,100,000
Class A Common Units [Member]
Common units, authorized (in shares)	254,208,428	254,208,428
Common units, issued (in shares)	254,208,428	254,208,428
Class B Common Units [Member]
Common units, authorized (in shares)	7,825,500	7,825,500
Common units, issued (in shares)	7,825,500	7,825,500
i-Units [Member]
Common units, authorized (in shares)	68,305,187	63,743,099
Common units, issued (in shares)	68,305,187	63,743,099
Incentive Distribution Units [Member]
Common units, authorized (in shares)	1,000
Common units, issued (in shares)	1,000

CONSOLIDATED_STATEMENTS_OF_PAR

CONSOLIDATED STATEMENTS OF PARTNERS CAPITAL (USD $)	Total	Class A Common Units [Member]	Incentive Distribution Units [Member]	Series 1 Preferred Interests [Member]	Limited Partner [Member]	Limited Partner [Member]	Limited Partner [Member]	Limited Partner [Member]	Limited Partner [Member]	General Partner [Member]	Accumulated Other Comprehensive Income (Loss) [Member]
In Millions, except Share data, unless otherwise specified	USD ($)			USD ($)	Class D Units [Member]	Class A Common Units [Member]	Class B Common Units [Member]	i-Units [Member]	Incentive Distribution Units [Member]	USD ($)	USD ($)
					USD ($)	USD ($)	USD ($)	USD ($)	USD ($)
Noncontrolling interest, beginning balance at Dec. 31, 2011	$445.50
Beginning balance at Dec. 31, 2011						3,386.70	82.2	728.6		285.6	-316.5
Beginning balance (in shares) at Dec. 31, 2011						238,043,964	7,825,500	38,566,334
Allocation of proceeds and issuance costs from unit issuances						418.5	8.4	22.7
Allocation of proceeds and issuance costs from unit issuances (in shares)						16,164,464
Equity restructuring fair value allocation
Equity restructuring fair value allocation (in shares)
Net income (loss) allocation	493.1					306.2	10.1	50.5		126.3
General Partner contribution										9.4
Transfer of interests in subsidiary to Midcoast Energy Partners, L.P.
Distributions						-521.2	-16.8			-122.3
Distributions (in shares)								2,632,090
Accretion of discount on preferred units
Beneficial conversion feature of preferred units
Changes in fair value of derivative financial instruments reclassified to earnings											28.8
Changes in fair value of derivative financial instruments recognized in other comprehensive income (loss)											-32.8
Noncontrolling interest:
Capital contributions	350.9
Issuance of MEP units
Comprehensive income:
Noncontrolling interest (Note 12)	57
Other comprehensive income, net of tax
Distributions	-59.9
Total partners' capital	5,247.90
Noncontrolling interest, ending balance at Dec. 31, 2012	793.5
Ending balance at Dec. 31, 2012	4,454.40					3,590.20	83.9	801.8		299	-320.5
Ending balance (in shares) at Dec. 31, 2012						254,208,428	7,825,500	41,198,424
Allocation of proceeds and issuance costs from unit issuances				1,199.20				508.5
Allocation of proceeds and issuance costs from unit issuances (in shares)				48,000,000				18,774,686
Equity restructuring fair value allocation
Equity restructuring fair value allocation (in shares)
Net income (loss) allocation	4.7			58.2		-96.3	-2.8	-26.3		130.1
General Partner contribution										10.8
Transfer of interests in subsidiary to Midcoast Energy Partners, L.P.
Distributions				-58.2		-552.6	-17			-139.3
Distributions (in shares)								3,769,989
Accretion of discount on preferred units	9.2			9.2
Beneficial conversion feature of preferred units				-47.7		37.7	1.2	7.9		0.9
Changes in fair value of derivative financial instruments reclassified to earnings											27.1
Changes in fair value of derivative financial instruments recognized in other comprehensive income (loss)											216.8
Noncontrolling interest:
Capital contributions	793.6
Issuance of MEP units	354.9
Comprehensive income:
Noncontrolling interest (Note 12)	88.3
Transfer of interests in subsidiary to Midcoast Energy Partners, L.P.
Other comprehensive income, net of tax	-0.9
Distributions	-53.8
Total partners' capital	7,697.40
Noncontrolling interest, ending balance at Dec. 31, 2013	1,975.60
Ending balance at Dec. 31, 2013	5,721.80			1,160.70		2,979	65.3	1,291.90		301.5	-76.6
Ending balance (in shares) at Dec. 31, 2013				48,000,000		254,208,428	7,825,500	63,743,099
Allocation of proceeds and issuance costs from unit issuances
Allocation of proceeds and issuance costs from unit issuances (in shares)
Equity restructuring fair value allocation					2,480.10	-2,255.60	-58.5	-598.1	491.7	59.6
Equity restructuring fair value allocation (in shares)					66,100,000				1,000
Net income (loss) allocation	371.8			90	106.5	165.8	13.4	43.6	4.1	38.4
General Partner contribution
Transfer of interests in subsidiary to Midcoast Energy Partners, L.P.						-95.2	-2.9	-24.8		-2.5
Distributions				-90	-69.8	-558.5	-17.3		-2.8	-79.5
Distributions (in shares)								4,562,088
Accretion of discount on preferred units	14.9			14.9
Beneficial conversion feature of preferred units
Changes in fair value of derivative financial instruments reclassified to earnings											22
Changes in fair value of derivative financial instruments recognized in other comprehensive income (loss)											-156.8
Noncontrolling interest:
Capital contributions	1,391.60
Issuance of MEP units
Comprehensive income:
Noncontrolling interest (Note 12)	263.3
Transfer of interests in subsidiary to Midcoast Energy Partners, L.P.	125.4
Other comprehensive income, net of tax	7.1
Distributions	-154
Total partners' capital	8,729.40
Noncontrolling interest, ending balance at Dec. 31, 2014	3,609
Ending balance at Dec. 31, 2014	$5,120.40			$1,175.60	$2,516.80	$235.50	$0	$712.60	$493	$198.30	($211.40)
Ending balance (in shares) at Dec. 31, 2014				48,000,000	66,100,000	254,208,428	7,825,500	68,305,187	1,000

ORGANIZATION_AND_NATURE_OF_OPE

ORGANIZATION AND NATURE OF OPERATIONS	12 Months Ended
ORGANIZATION AND NATURE OF OPERATIONS	Dec. 31, 2014
ORGANIZATION AND NATURE OF OPERATIONS [Abstract]
ORGANIZATION AND NATURE OF OPERATIONS	1. ORGANIZATION AND NATURE OF OPERATIONS

	General

	Enbridge Energy Partners, L.P., together with its consolidated subsidiaries is a publicly-traded Delaware limited partnership that owns and operates crude oil and liquid petroleum transportation and storage assets, natural gas gathering, treating, processing, and transmission assets and marketing assets in the United States of America. Our Class A common units are traded on the NYSE, under the symbol EEP.

	We were formed in 1991 by our General Partner, which is an indirect, wholly-owned subsidiary of Enbridge. We were formed to acquire, own and operate the crude oil and liquid petroleum transportation assets of the OLP, which owns the United States portion of a crude oil and liquid petroleum pipeline system extending from western Canada through the upper and lower Great Lakes region of the United States to eastern Canada.

	We are a geographically and operationally diversified organization, providing crude oil gathering, transportation and storage services, and natural gas gathering, treating, processing, marketing and transportation services in the Gulf Coast and Mid-Continent regions of the United States. We hold our assets in a series of limited liability companies and limited partnerships that we own either directly or indirectly.

	Midcoast Energy Partners, L.P.

	On November 13, 2013, MEP 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.

	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%. 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.

	Under the Midcoast Operating Agreement, we and MEP each have the option to contribute its proportionate share of additional capital to Midcoast Operating if any additional capital contributions are necessary to fund capital expenditures or other growth projects. To the extent that we or MEP elect not to make any such capital contributions, the contributing party will be permitted to make additional capital contributions in exchange for additional interests in Midcoast Operating. We can elect not to participate in certain growth projects. We expect to participate proportionately in these natural gas capital projects, although there is no guarantee that we will do so.

	At December 31, 2014, we owned approximately 53.8% of MEP's outstanding common units, 100% of MEP's outstanding subordinated units, 100% of MEP's general partner, and 48.4% of the limited partner interests in Midcoast Operating.

	Enbridge Energy Management, L.L.C.

	Enbridge Management, is a Delaware limited liability company that was formed in May 2002. Our General Partner, through its direct ownership of the voting shares of Enbridge Management, elects all of its directors. Enbridge Management's listed shares are traded on the NYSE under the symbol “EEQ.” Enbridge Management owns all of a special class of our limited partner interests that we refer to as i-units and derives all of its earnings from its investment in us.

	Enbridge Management's principal activity is managing our business and affairs pursuant to a delegation of control agreement among our General Partner, Enbridge Management and us. The delegation of control agreement provides that Enbridge Management will not amend or propose to amend our partnership agreement, allow a merger or consolidation involving us, allow a sale or exchange of all or substantially all of our assets or dissolve or liquidate us without the approval of our General Partner. In accordance with its limited liability company agreement, Enbridge Management's activities are restricted to being our limited partner and managing our business and affairs.

	Enbridge Inc.

	Enbridge is the indirect parent of our General Partner, and its common shares are publicly traded on the NYSE in the United States and the Toronto Stock Exchange, or TSX, in Canada under the symbol “ENB.” Enbridge is a leader in energy transportation and distribution in North America, with a focus on crude oil and liquids pipelines, natural gas pipelines and natural gas distribution. At December 31, 2014 and 2013, Enbridge and its consolidated subsidiaries held an effective 40.3% and 29.9% voting interest in us, respectively, through its ownership in Enbridge Management and our General Partner.

	Business Segments

	We conduct our business through two operating segments: Liquids and Natural Gas.

	Liquids

	Our Liquids segment includes the Lakehead, North Dakota and the Mid-Continent crude oil systems. Our Lakehead system consists of a series of interstate common carrier crude oil and liquid petroleum pipelines that are regulated by the FERC, and storage assets, all of which are located in the Great Lakes and Midwest regions of the United States. Our Lakehead system, together with the Enbridge system in Canada owned by Enbridge, forms the longest liquid petroleum pipeline in the world. The Lakehead system, which spans approximately 2,211 miles and includes approximately 5,300 miles of pipe, has been in operation for more than 60 years and is the primary transporter of crude oil and liquid petroleum from western Canada to the United States. The Lakehead system serves all the major refining centers in the Great Lakes and Midwest regions of the United States and the province of Ontario, Canada. Our North Dakota crude oil system is approximately 847 miles long, has 23 pump stations, multiple delivery points and storage facilities with an aggregate working storage capacity of approximately 1.8 million barrels. The North Dakota system connects directly into the Lakehead system in the state of Minnesota. Our Mid-Continent system consists of over 1,666 miles of crude oil pipelines, including the FERC-regulated Ozark pipeline and approximately 21.4 million barrels of storage capacity, which serve refineries in the United States Mid-Continent region from Cushing, Oklahoma.

	Natural Gas

	During the first quarter of 2014, we combined our Marketing segment with the Natural Gas segment to form a new segment named “Natural Gas.” Our Natural Gas segment consists of natural gas and NGL, rail and liquid marketing, gathering and transportation pipeline systems, natural gas processing and treating facilities and NGL fractionation facilities, predominantly located in active producing basins in east and north Texas, as well as the Texas Panhandle and western Oklahoma. At December 31, 2014, our Natural Gas segment is comprised of eight active and three standby natural gas treating plants and 18 active and six standby natural gas processing plants, excluding plants that are inactive based on current volumes. In addition, our Natural Gas segment includes approximately 11,100 miles of natural gas and NGL gathering and transmission pipelines, as well as trucks, trailers and rail cars used for transporting NGLs, crude oil and carbon dioxide.

	Our Natural Gas segment provides natural gas supply, transportation, balancing, storage and sales services for producers and wholesale customers on our natural gas pipelines as well as other interconnected natural gas pipeline systems. We primarily undertake marketing activities to increase the utilization of our natural gas pipelines, realize incremental income on gas purchased at the wellhead and provide value-added services to customers.

	Our Natural Gas business purchases third-party pipeline transportation capacity, which provides us and our customers with access to natural gas markets that might not be directly accessible from our existing natural gas pipelines. Our Natural Gas business also purchases third-party storage capacity, which permits us to inject and store natural gas over various periods of time for withdrawal as these products become needed by end users of natural gas. These contracts may be denoted as firm transportation, interruptible transportation, firm storage, interruptible storage or parking and lending services. These various contract structures are used to mitigate risk associated with our natural gas purchase and sale contracts and to provide us with opportunities to competitively market natural gas products.

SUMMARY_OF_SIGNIFICANT_ACCOUNT

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	Dec. 31, 2014
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

	Basis of Presentation and Use of Estimates

	We prepare our consolidated financial statements in accordance with United States generally accepted accounting principles, or U.S. GAAP. Our preparation of these consolidated financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and the disclosure of contingent assets and liabilities. We regularly evaluate these estimates utilizing historical experience, consultation with experts and other methods we consider reasonable in the circumstances. Nevertheless, actual results may differ significantly from these estimates. We record the effect of any revisions to these estimates in our consolidated financial statements in the period in which the facts that give rise to the revision become known.



	Principles of Consolidation

	The consolidated financial statements include our accounts and all accounts on a consolidated basis of: (1) our wholly and majority-owned subsidiaries; and (2) our subsidiaries over which we have control, even if we do not have a majority ownership. We consolidate the accounts of entities over which we have a controlling financial interest through our ownership of the general partner or the majority voting interests in the entity. All significant intercompany accounts and transactions have been eliminated in consolidation. Ownership interests in our subsidiaries represented by other parties that do not control the entity are presented in our consolidated financial statements as activities and balances attributable to the noncontrolling interest.


	Equity Investment in Joint Venture

	Our natural gas and NGLs business includes our 35% aggregate interest in the Texas Express NGL system, which is comprised of two joint ventures with third parties, representing a 593-mile NGL intrastate transportation pipeline and a related NGL gathering system. We use the equity method of accounting for our 35% joint venture interest in the Texas Express NGL system as a result of our ability to significantly influence the operating activities, but insufficient ability to control these activities without the participation of a majority of the other members.



	Accounting for Regulated Operations

	Our interstate liquids pipelines are subject to regulation by the FERC and various state authorities. Regulatory bodies exercise statutory authority over matters such as construction, rates, underlying accounting practices and ratemaking agreements with customers.

	The recovery of construction, operating and other costs associated with portions of our Lakehead system are subject to the authoritative accounting provisions applicable to regulated operations. Accordingly, we record costs that are allowed in the ratemaking process in a period different from the period in which the costs would be charged to expense by a non-regulated entity. Also, we record assets and liabilities that result from the regulated ratemaking process that would not be recorded under U.S. GAAP for non-regulated entities.

	Allowance for Funds Used During Construction

	During the construction of our pipelines that qualify for regulated accounting, we are allowed to capitalize costs that represent the estimated debt and equity costs of capital necessary to finance the construction of our pipelines. The debt and equity costs, referred to collectively as allowance for funds used during construction, or AFUDC, are capitalized as part of the costs of pipeline construction in “Property, plant and equipment, net” in our consolidated statements of financial position. The equity return component and interest costs related to the AFUDC are credited to “Other income” and “Interest expense,” respectively, on our consolidated statements of income. Entities that do not qualify for regulated accounting are only allowed to capitalize interest costs related to its construction activities, while a component for equity is prohibited.

	Cost-of-Service Recovery Model

	The rates for a number of our projects are based on a cost-of-service recovery model that follows the FERC's authoritative guidance and are subject to annual filing requirements with the FERC. Under our cost-of-service tolling methodology, we calculate tolls based on forecast volumes and costs. A difference between forecast and actual results causes an over or under recovery in any given 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 projects through the annual cost-of-service filings with the FERC and through toll rate adjustments with our customers.


	Revenue Recognition and the Estimation of Revenues and Commodity Costs

	Liquids

	In our Liquids segment, we generally do not own the crude oil and liquid petroleum that we transport or store, and therefore, we do not assume significant direct commodity price risk. Revenues of our Liquids segment are primarily derived from three sources: interstate transportation of crude oil and liquid petroleum under tariffs regulated by the FERC, ship-or-pay agreements and contract storage revenues related to our crude oil storage assets.

	The tariffs established for our interstate pipelines specify the amounts to be paid by shippers for transportation services we provide between receipt and delivery locations and the general terms and conditions of transportation services on the respective pipeline systems. We recognize revenue upon delivery of products to our customers, when pricing is determinable and collectability is reasonably assured.

	We generally recognize revenue from minimum volume commitments on ship-or-pay agreements when those volume commitments are not utilized during the period. Some long-term ship-or-pay contracts also contain make-up-rights. Make-up-rights are earned by shippers when minimum volume commitments are not utilized during the period but under certain circumstances can be used to offset overages in future periods, subject to expiration periods. We recognize revenue associated with make-up rights at the earlier of when the make-up volume is shipped, the make-up right expires, or when it is determined that the likelihood that the shipper will utilize the make-up right is remote.

	We recognize contract storage revenues based on contractual terms under which customers pay for the option to use available storage capacity and/or a fee based on storage volumes. We recognize revenues as storage services are rendered, when pricing is determinable and collectability is reasonably assured.

	Revenues for our Liquids segment are all recorded in “Transportation and other services” and “Transportation and other services – affiliate” on our Consolidated Statements of Income.

	Natural Gas

	We recognize revenue upon delivery of natural gas and NGLs to customers, when services are rendered, pricing is determinable and collectability is reasonably assured. We generate revenues and segment gross margin principally under the following types of contractual arrangements:

	Fee-Based Arrangements

	In a fee-based arrangement, we receive a fee per Mcf of natural gas processed or per gallon of NGLs produced. Under this arrangement, we have no direct commodity price exposure. We receive fee-based revenue for services, such as compression fees, gathering fees and treating fees that are recognized when the services are performed. Additionally, revenues that are derived from transmission services consist of reservation fees charged for transportation of natural gas on some of our intrastate pipeline systems. Customers paying these fees typically pay a reservation fee each month to reserve capacity plus a nominal commodity charge based on actual transportation volumes. Reservation fees are required to be paid whether or not the shipper delivers the volumes, thus referred to as a ship-or-pay arrangement. Consequently, we recognize revenue for reservation fees ratably over the period in which capacity is reserved. Additional revenues from our intrastate pipelines are derived from the combined sales of natural gas and transportation services. Revenues from fee-based arrangements for our Natural Gas segment are recorded in “Transportation and other services” and “Transportation and other services – affiliate” on our Consolidated Statements of Income.

	Commodity-Based Arrangements

	We also generate revenue and segment gross margin under other types of service arrangements with customers. These arrangements expose us to commodity price risk, which we mitigate to a substantial degree with the use of derivative financial instruments to hedge open positions in these commodities. We hedge a significant amount of our exposure to commodity price risk to support the stability of our cash flows.

	The commodity-based service contracts we have with customers are categorized as follows:

	• Percentage-of-Proceeds Contracts - Under these contracts, we receive a negotiated percentage of the sales proceeds related to natural gas and NGLs we process. The processed products include residue natural gas, NGLs, condensate and sulfur, which we can sell at market prices and retain a percentage of the proceeds as our compensation. This type of arrangement exposes us to commodity price risk, as the revenues from percentage-of-proceeds contracts directly correlate with the market prices of the applicable commodities that we receive.

• Percentage-of-Liquids Contracts - Under these contracts, we receive a negotiated percentage of the NGLs extracted from natural gas that require processing, which we can then sell at market prices and retain the proceeds as our compensation. This contract structure is similar to percentage-of-proceeds arrangements except that we only receive a percentage of the NGLs produced. Ownership of the residue natural gas remaining after the extraction of NGLs resides with the customer. This type of contract may also require us to provide the customer with a guaranteed NGL recovery percentage regardless of actual NGL production. Since revenues from percentage-of-liquids contracts directly correlate with the market price of NGLs, this type of arrangement also exposes us to commodity price risk.

• Percentage-of-Index Contracts - Under these contracts, we purchase raw natural gas at a negotiated percentage of an agreed upon index price. We then resell the natural gas, generally for the index price, and keep the difference as our compensation.

• Keep-Whole Contracts - Under these contracts, we gather or purchase raw natural gas from the customer. We extract and retain the NGLs produced during processing for our own account, which we then sell at market prices. In instances where we purchase raw natural gas at the wellhead, we may also sell the resulting residue natural gas for our own account at market prices. In those instances where we gather and process raw natural gas for the customer's account, we generally must return to the customer residue natural gas with an energy content equivalent to the original raw natural gas we received, as measured in British thermal units, or Btu. This type of arrangement has the highest commodity price exposure because our costs are dependent on the price of natural gas purchased and our revenues are dependent on the price of NGLs sold. As a result, we benefit from these types of contracts when the value of the NGLs is high relative to the cost of the natural gas and are disadvantaged when the cost of the natural gas is high relative to the value of the NGLs.

Under the terms of each of our commodity-based service contracts, we retain natural gas and NGLs as our compensation for providing these customers with our services. As of December 31, 2014, we are exposed to fluctuations in commodity prices in the near term on approximately 10% to 15% of the physical natural gas, NGLs and condensate we expect to receive as compensation for our services. Due to this unhedged commodity price exposure, our gross margin, representing commodity sales less commodity costs, generally increases when the prices of these commodities are rising and generally decreases when the prices are declining. As a result of entering into these derivative instruments, we have largely fixed the amount of cash that we will pay and receive in the future when we sell the residue gas, NGLs and condensate, even though the market price of these commodities will continue to fluctuate.

Marketing

Marketing revenues are derived from providing supply, transportation, balancing, storage and sales services for producers and wholesale customers on our natural gas pipelines, as well as other interconnected pipeline systems. Natural gas marketing activities are primarily undertaken to realize incremental revenues on natural gas purchased at the wellhead, and to provide other services valued by our customers. In general, natural gas we purchase and sell is priced at a published daily or monthly index price. Sales to wholesale customers typically incorporate a premium for managing their transmission and balancing requirements. Higher premiums and associated revenues result from transactions that involve smaller volumes or that offer greater service flexibility for wholesale customers. At the request of some customers, we will enter into long-term fixed price purchase or sales contracts with our customers and usually will enter into offsetting positions under the same or similar terms. We recognize revenues upon delivery of natural gas to our customers, when services are rendered, pricing is determinable and collectability is reasonably assured. Marketing revenues for our Natural Gas segment are recorded in “Commodity sales” and “Commodity sales – affiliate” on our Consolidated Statements of Income. The related cost of natural gas and natural gas liquids sold is recorded in “Commodity costs” and “Commodity costs – affiliate.”

Estimation of Revenue and Commodity Costs

In order to permit the timely preparation of our consolidated financial statements, for our natural gas segment, we estimate our current month revenue and commodity costs. We generally cannot compile actual billing information nor obtain actual vendor invoices within a timeframe that would permit the recording of this actual data before our preparation of the consolidated financial statements. As a result, we record an estimate each month for our operating revenues and commodity costs based on the best available volume and price data for natural gas delivered and received, along with an adjustment of the prior month's estimate to equal the prior month's actual data. As a result, there is one month of estimated data recorded in our operating revenues and commodity costs for each of the years ended December 31, 2014, 2013 and 2012. We believe that the assumptions underlying these estimates are not significantly different from the actual amounts due to the routine nature of these estimates and the stability of our processes.

In addition, we estimate current month revenues in our liquids segment. We record an estimate each month for our operating revenues based on the best available volume and rate data for crude oil delivered, along with an adjustment of the prior month's estimate to equal the prior month's actual data. As a result, there is one month of estimated data recorded in our operating revenues for the years ended December 31, 2014, 2013, and 2012. We believe that the assumptions underlying these estimates are not significantly different from the actual amounts due to the routine nature of these estimates and the stability of our processes.

Cash and Cash Equivalents

Cash equivalents are defined as all highly marketable securities with original maturities of three months or less when purchased. The carrying value of cash and cash equivalents approximates fair value because of the short term to maturity of these investments.

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 issued check payments that have not been presented to the financial institution are included in “Accounts payable and other” on our consolidated statements of financial position.

Allowance for Doubtful Accounts

We establish provisions for losses on accounts receivable when we determine that we will not collect all or part of an outstanding balance. Collectability is reviewed regularly and an allowance is established or adjusted, as necessary, using the specific identification method.


Inventory

Inventory includes product inventory and materials and supplies inventory. We record all product inventories at the lower of our cost, as determined on a weighted average basis, or market value. Our product inventory consists of liquid hydrocarbons and natural gas. Upon disposition, product inventory is recorded to “Commodity costs” at the weighted average cost of inventory, including any adjustments recorded to reduce inventory to market value.

Materials and supplies inventory is used either during operations and charged to “Operating and administrative” as incurred, or for capital projects and new construction and capitalized to “Property, plant and equipment, net.”


Oil Measurement Adjustments

Oil measurement adjustments occur as part of the normal operations associated with our liquid petroleum operations. The three types of oil measurement adjustments that routinely occur on our systems include:

• Physical, which result from evaporation, shrinkage, differences in measurement (including sediment and water measurement) between receipt and delivery locations and other operational conditions;

• Degradation, resulting from mixing at the interface within our pipeline systems or terminal and storage facilities between higher quality light crude oil and lower quality heavy crude oil in pipelines; and

• Revaluation, which are a function of crude oil prices, the level of our carriers' inventory and the inventory positions of customers.

Quantifying oil measurement adjustments are difficult because: (1) physical measurements of volumes are not practical, as products continuously move through our pipelines, which are primarily located underground; (2) the extensive length of our pipeline systems; and (3) the numerous grades and types of crude oil products we carry. We utilize engineering-based models and operational assumptions to estimate product volumes in our systems and associated oil measurement adjustments. Material changes in our assumptions may result in revisions to our oil measurement estimates in the period determined. Oil measurement adjustments are included within the “Operating and administrative” line item of our Consolidated Statements of Income.


Operational Balancing Agreements and Natural Gas Imbalances

To facilitate deliveries of natural gas and provide for operational flexibility, we have operational balancing agreements in place with other interconnecting pipelines. These agreements ensure that the volume of natural gas a shipper schedules for transportation between two interconnecting pipelines equals the volume actually delivered. If natural gas moves between pipelines in volumes that are more or less than the volumes the shipper previously scheduled, a natural gas imbalance is created. The imbalances are settled through periodic cash payments or repaid in-kind through the receipt or delivery of natural gas in the future. Natural gas imbalances are recorded as “Accrued receivables” and “Accrued purchases” on our consolidated statements of financial position using the posted index prices, which approximate market rates, or our weighted average commodity costs.



Capitalization Policies, Depreciation Methods and Impairment of Property, Plant and Equipment


We capitalize expenditures related to property, plant and equipment, subject to a minimum rule, that have a useful life greater than one year for: (1) assets purchased or constructed; (2) existing assets that are replaced, improved or the useful lives have been extended; or (3) all land, regardless of cost. Acquisitions of new assets, additions, replacements and improvements (other than land) costing less than the minimum rule in addition to maintenance and repair costs, including any planned major maintenance activities, are expensed as incurred.

During construction, we capitalize direct costs, such as labor and materials, and other costs, such as direct overhead and interest at our weighted average cost of debt, and, in our regulated businesses that apply the authoritative accounting provisions applicable to regulated operations, an equity return component.

We record property, plant and equipment at its original cost, which we depreciate on a straight-line basis over the lesser of its estimated useful life or the estimated remaining lives of the crude oil or natural gas production in the basins the assets serve. Our determination of the useful lives of property, plant and equipment requires us to make various assumptions, including the supply of and demand for hydrocarbons in the markets served by our assets, normal wear and tear of the facilities, and the extent and frequency of maintenance programs. We routinely utilize consultants and other experts to assist us in assessing the remaining lives of the crude oil or natural gas production in the basins we serve.

We record depreciation using the group method of depreciation which is commonly used by pipelines, utilities and similar entities. Under the group method, for all segments, upon the disposition of property, plant and equipment, the net book value less net proceeds is typically charged to accumulated depreciation and no gain or loss on disposal is recognized. However, when a separately identifiable group of assets, such as a stand-alone pipeline system is sold, we recognize a gain or loss in our consolidated statements of income for the difference between the cash received and the net book value of the assets sold. Changes in any of our assumptions may alter the rate at which we recognize depreciation in our consolidated financial statements. At regular intervals, we retain the services of independent consultants to assist us with assessing the reasonableness of the useful lives we have established for the property, plant and equipment of our major systems. Based on the results of these assessments we may make modifications to the assumptions we use to determine our depreciation rates.

We evaluate the recoverability of our property, plant and equipment when events or circumstances such as economic obsolescence, the business climate, legal and other factors indicate we may not recover the carrying amount of the assets. We continually monitor our businesses, the market and business environments to identify indicators that could suggest an asset may not be recoverable. We evaluate the asset for recoverability by estimating the undiscounted future cash flows expected to be derived from operating the asset as a going concern. These cash flow estimates require us to make projections and assumptions for many years into the future for pricing, demand, competition, operating cost, contract renewals and other factors. We recognize an impairment loss when the carrying amount of the asset exceeds its fair value as determined by quoted market prices in active markets or present value techniques. The determination of the fair value using present value techniques requires us to make projections and assumptions regarding future cash flows and weighted average cost of capital. Any changes we make to these projections and assumptions could result in significant revisions to our evaluation of the recoverability of our property, plant and equipment and the recognition of an impairment loss in our consolidated statements of income.

Assessment of Recoverability of Goodwill

Goodwill represents the future economic benefits arising from other assets acquired in a business combination that are not individually identified and separately recognized.

We test goodwill for impairment annually based on carrying values of our reporting units as of the end of the second quarter, or more frequently if impairment indicators arise that suggest the carrying value of goodwill may be impaired. In testing goodwill for impairment, we make critical assumptions that include but are not limited to: (1) projections of future financial performance, which include commodity price and volume assumptions, (2) the expected growth rate of our Natural Gas assets, (3) residual values of the assets; and (4) market weighted average cost of capital. Impairment occurs when the carrying amount of a reporting unit's goodwill exceeds its implied fair value. We reduce the carrying value of goodwill to its fair value at the time we determine that an impairment has occurred.


Assessment of Recoverability of Intangible Assets

Our intangible assets primarily consist of customer contracts for the purchase and sale of natural gas, natural gas supply opportunities and contributions we have made in aid of construction activities that will benefit our operations, as well as workforce contracts and customer relationships. We amortize these assets on a straight-line basis over the weighted average useful lives of the underlying assets, representing the period over which the assets are expected to contribute directly or indirectly to our future cash flows.

We evaluate the carrying value of our intangible assets whenever events or changes in circumstances indicate that the carrying amount of these assets may not be recoverable. In assessing the recoverability of intangible assets, we compare the carrying value to the undiscounted future cash flows we expect the intangible assets or the underlying assets to generate. If the total of the undiscounted future cash flows is less than the carrying amount of the intangible assets, we write the intangible assets down to their fair value.

Derivative Financial Instruments

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 and fractionation margins. Fractionation margins represent the relative difference between the price we receive from NGL and condensate sales and the corresponding commodity costs of natural gas and natural gas liquids we purchase for processing. We use a variety of derivative financial instruments including futures, forwards, swaps, options and other financial instruments with similar characteristics to create offsetting positions to specific commodity or interest rate exposures.

We record all derivative financial instruments at fair market value in our Consolidated Statements of Financial Position. Price assumptions we use to value our non-qualifying derivative financial instruments can affect net income for each period. We use published market price information where available, or quotations from OTC market makers to find executable bids and offers. We may also use these inputs with internally developed methodologies that result in our best estimate of fair value. The valuations also reflect the potential impact of liquidating our position in an orderly manner over a reasonable period of time under present market conditions, including credit risk of our counterparties. The amounts reported in our consolidated financial statements change quarterly as these valuations are revised to reflect actual results, changes in market conditions or other factors, many of which are beyond our control.

For those instruments that qualify for hedge accounting, the accounting treatment is dependent on the intended use and designation of each instrument. We record changes in the fair value of our derivative financial instruments that do not qualify for hedge accounting in our consolidated statements of income as follows:

• Natural Gas segment commodity-based derivatives—“Commodity Costs” and “Commodity sales”

• Liquids segment commodity-based derivatives—“Transportation and other services” and “Power”

• Corporate interest rate derivatives—“Interest expense”

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.

Qualified Hedges

If a derivative financial instrument qualifies and is designated as a cash flow hedge, which is a hedge of a forecasted transaction or future cash flows, any unrealized mark-to-market gain or loss is deferred in AOCI, a component of “Partners' capital” in our consolidated statements of financial position, until the underlying hedged transaction occurs. To the extent that the hedge instrument is effective in offsetting the transaction being hedged, there is no impact to the income statement until the underlying transaction occurs. At inception and on a quarterly basis, we formally assess whether the hedge contract is highly effective in offsetting changes in cash flows of hedged items. Any ineffective portion of a cash flow hedge's change in fair market value is recognized each period in earnings. Realized gains and losses on derivative financial instruments that are designated as hedges and qualify for hedge accounting are included in “Commodity costs” for commodity hedges and “Interest expense” for interest rate hedges in our consolidated statements of income in the period in which the hedged transaction occurs. Gains and losses deferred in AOCI related to cash flow hedges for which hedge accounting has been discontinued remain in AOCI until the underlying physical transaction occurs unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period or within an additional two-month period of time thereafter.

Generally, our preference is for our derivative financial instruments to receive hedge accounting treatment whenever possible to mitigate the non-cash earnings volatility that arises from recording the changes in fair value of our derivative financial instruments through earnings. To qualify for cash flow hedge accounting treatment as set forth in the authoritative accounting guidance, very specific requirements must be met in terms of hedge structure, hedge objective and hedge documentation.

Our formal hedging program provides a control structure and governance for our hedging activities specific to identified risks and time periods, which are subject to the approval and monitoring by the board of directors of Enbridge Management or a committee of senior management appointed by our General Partner. We employ derivative financial instruments in connection with an underlying asset, liability or anticipated transaction and we do not use derivative financial instruments for speculative purposes.

At inception, we formally document the relationship between the hedging instrument and the hedged item, the risk management objective, and the method used for assessing and testing correlation and hedge effectiveness. We also assess, both at the inception of the hedge and on an on-going basis, whether the derivatives that are used in our hedging transactions are highly effective in offsetting changes in cash flows of the hedged item. Furthermore, we regularly assess the creditworthiness of our counterparties to manage against the risk of default. If we determine that a derivative is no longer highly effective as a hedge, we discontinue hedge accounting prospectively by including changes in the fair value of the derivative in current earnings.

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 “Commodity costs,” “Commodity sales,” “Transportation and other services,” “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.



Fair Value Measurements

We apply the authoritative accounting provisions for measuring fair value to our derivative instruments and disclosures associated with our outstanding commodity activities. We define fair value as the expected price we would receive to sell an asset or pay to transfer a liability in an orderly transaction with market participants at the measurement date.

We employ a hierarchy which prioritizes the inputs we use to measure recurring fair value into three distinct categories based upon whether such inputs are observable in active markets or unobservable. We classify assets and liabilities in their entirety based on the lowest level of input that is significant to the fair value measurement. Our methodology for categorizing assets and liabilities that are measured at fair value pursuant to this hierarchy gives the highest priority to unadjusted quoted prices in active markets and the lowest level to unobservable inputs as outlined below:

• Level 1—We include in this category the fair value of assets and liabilities that we measure based on unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. We consider active markets as those in which transactions for the assets or liabilities occur with sufficient frequency and volume to provide pricing information on an ongoing basis. The fair value of our assets and liabilities included in this category consists primarily of exchange-traded derivative instruments.

• Level 2— We include in this category 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: (a) quoted prices for assets and liabilities; (b) time value; (c) volatility factors; and (d) 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.

• Level 3—We include in this category the fair value of assets and liabilities that we measure based on prices or valuation techniques that require inputs which are both significant to the fair value measurement and less observable from objective sources (i.e., values supported by lesser volumes of market activity). We may also use these inputs with internally developed methodologies that result in our best estimate of the fair value. Level 3 assets and liabilities primarily include derivative instruments for which we do not have sufficient corroborating market evidence, such as binding broker quotes, to support classifying the asset or liability as Level 2. Additionally, Level 3 valuations may utilize modeled pricing inputs to derive forward valuations, which may include some or all of the following inputs: non-binding broker quotes, time value, volatility, correlation and extrapolation methods.

We record all derivative financial instruments in our consolidated financial statements at fair market value, which we adjust on a recurring basis each period for changes in the fair market value, and refer to as marking to market, or mark-to-market. The fair market value of these derivative financial instruments reflects the estimated amounts that we would pay to transfer a liability or receive to sell an asset in an orderly transaction with market participants to terminate or close the contracts at the reporting date, taking into account the current unrealized losses or gains on open contracts. We apply a mid-market pricing convention, or the “market approach,” to value substantially all of our derivative instruments.

Our assets are adjusted for the non-performance risk of our counterparties using their current credit default swap spread rates. Likewise, in the case of our liabilities, our nonperformance risk is considered in the valuation and is also adjusted using a credit adjustment model incorporating inputs such as credit default swap rates, bond spreads, and default probabilities.

Our credit exposure for over-the-counter derivatives is directly with our counterparty and continues until the maturity or termination of the contracts. As appropriate, valuations are adjusted for various factors such as credit and liquidity considerations. Actively traded external market quotes, data from pricing services and published indices are also used to value our derivative instruments. We may use these inputs along with internally developed methodologies that result in our best estimates of fair value.


Income Taxes

We are not a taxable entity for United States federal income tax purposes or for the majority of states that impose an income tax. Taxes on our net income generally are borne by our unitholders through the allocation of taxable income. Our income tax expense results from the enactment of state income tax laws that apply to entities organized as partnerships by the State of Texas. This tax is computed on our modified gross margin and we have determined the tax to be an income tax as set forth in authoritative accounting literature.

We recognize deferred income tax assets and liabilities for temporary differences between the relevant basis of our assets and liabilities for financial reporting and tax purposes. We record the impact of changes in tax legislation on deferred income tax liabilities and assets in the period the legislation is enacted.

We recognize the tax effects of any uncertain tax positions as the largest amount that will more likely than not be realized upon ultimate settlement with a taxing authority having full knowledge of the position and all relevant facts. We recognize accrued interest income related to unrecognized tax benefits in interest income when the related unrecognized tax benefits are recognized.

Net income for financial statement purposes may differ significantly from taxable income of unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirements under our partnership agreement. The aggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined because information regarding each partner's tax attributes in us is not available.

Commitments, Contingencies and Environmental Liabilities

We expense or capitalize, as appropriate, expenditures for ongoing compliance with environmental regulations that relate to past or current operations. We expense amounts we incur for remediation of existing environmental contamination caused by past operations that do not benefit future periods by preventing or eliminating future contamination. We record liabilities for environmental matters when assessments indicate that remediation efforts are probable, and the costs can be reasonably estimated. Estimates of environmental liabilities are based on currently available facts, existing technology and presently enacted laws and regulations taking into consideration the likely effects of inflation and other factors. These amounts also consider prior experience in remediating contaminated sites, other companies' clean-up experience and data released by government organizations. Our estimates are subject to revision in future periods based on actual costs or new information and are included in “Environmental liabilities” and “Other long-term liabilities” in our consolidated statements of financial position at their undiscounted amounts. We always have the potential of incurring additional costs in connection with environmental liabilities 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. We evaluate recoveries from insurance coverage separately from the liability and, when recovery is probable, we record and report an asset separately from the associated liability in our consolidated financial statements.

We recognize liabilities for other commitments and contingencies when, after fully analyzing the available information, we determine it is either probable that an asset has been impaired, or that a liability has been incurred and the amount of impairment or loss can be reasonably estimated. When a range of probable loss can be estimated, we accrue the most likely amount, or if no amount is more likely than another, we accrue the minimum of the range of probable loss. We expense legal costs associated with loss contingencies as such costs are incurred.

Asset Retirement Obligations

Legal obligations exist for a minority of our right-of-way agreements due to requirements or landowner options that compel us to remove the pipe at final abandonment. Sufficient data exists with certain pipeline systems to reasonably estimate the cost of abandoning or retiring a pipeline system. However, in some cases, there is insufficient information to reasonably determine the timing and/or method of settlement for estimating the fair value of the asset retirement obligation. In these cases, the asset retirement obligation cost is considered indeterminate because there is no data or information that can be derived from past practice, industry practice, our intentions, or the estimated economic life of the asset. Useful lives of most pipeline systems are primarily derived from available supply resources and ultimate consumption of those resources by end users. Variables can affect the remaining lives of the assets which preclude us from making a reasonable estimate of the asset retirement obligation. Indeterminate asset retirement obligation costs will be recognized in the period in which sufficient information exists to allow us to reasonably estimate potential settlement dates and methods.

We record a liability for the fair value of asset retirement obligations and conditional asset retirement obligations that we can reasonably estimate, on a discounted basis. We collectively refer to asset retirement obligations and conditional asset retirement obligations as ARO. Typically, we record an ARO at the time the assets are installed or acquired, if a reasonable estimate of fair value can be made. In connection with establishing an ARO, we capitalize the costs as part of the carrying value of the related assets. We recognize an ongoing expense for the interest component of the liability as part of depreciation expense resulting from changes in the value of the ARO due to the passage of time. We depreciate the initial capitalized costs over the useful lives of the related assets. We extinguish the liabilities for an ARO when assets are taken out of service or otherwise abandoned.

DISPOSITIONS

DISPOSITIONS	12 Months Ended
DISPOSITIONS	Dec. 31, 2014
DISPOSITIONS [Abstract]
DISPOSITIONS	3. DISPOSITIONS

	2013 Dispositions

	In November 2013, we sold one of our non-core liquids assets, the El Dorado storage facility located in Butler County, Kansas to a third party for $40.0 million. We recognized a $17.1 million gain on the El Dorado storage facility sale in “other income” on our consolidated statement of income. The El Dorado storage terminal consists of 11 tanks with a capacity of 1.15 million barrels in addition to two 16” pipelines. The El Dorado storage terminal is not strategic to Enbridge's future growth in the U.S. Midwest.

NET_INCOME_PER_LIMITED_PARTNER

NET INCOME PER LIMITED PARTNER UNIT	12 Months Ended
NET INCOME PER LIMITED PARTNER UNIT	Dec. 31, 2014
NET INCOME PER LIMITED PARTNER UNIT [Abstract]
NET INCOME PER LIMITED PARTNER UNIT	4. 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 partner 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 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 distributions to the General Partner and limited partners as follows:


	Distribution Targets		Portion of Quarterly		Percentage Distributed to	Percentage Distributed to
	Distribution Targets		Distribution Per Unit		General Partner	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. For more information, please refer to Note 11. Partners' Capital of our consolidated financial statements in Item 8.

	Beginning July 1, 2014, pursuant to our 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 Targets		Distribution Per Unit		General Partner and IDUs⁽¹⁾	to Limited partners
	Minimum Quarterly Distribution		Up to $0.5435		2%	98%
	Target Distribution		> $0.5435		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 determined basic and diluted net income (loss) per common unit and i-unit as follows:


			For the year ended December 31,
			2014			2013			2012
			(in millions, except per unit amounts)
	Net income		$	740		$	160.4		$	550.1
	Less Net income attributable to:
	Noncontrolling interest			(263.3	)		(88.3	)		(57.0	)
	Series 1 preferred unit distributions			(90.0	)		(58.2	)		—
	Accretion of discount on Series 1 preferred units			(14.9	)		(9.2	)		—

	Net income attributable to general and limited partner interests in Enbridge Energy Partners, L.P.			371.8			4.7			493.1
	Less distributions:
	Incentive distributions			(39.1	)		(129.9	)		(116.3	)
	Distributed earnings attributed to our General Partner			(17.3	)		(14.2	)		(13.0	)
	Distributed earnings attributed to Class D units			(107.5	)		—			—

	Total distributed earnings to our General Partner, Class D units and IDUs			(163.9	)		(144.1	)		(129.3	)
	Total distributed earnings attributed to our common units and i-units			(731.0	)		(695.6	)		(636.3	)

	Total distributed earnings			(894.9	)		(839.7	)		(765.6	)

	Overdistributed earnings		$	(523.1	)	$	(835.0	)	$	(272.5	)

	Weighted average common units and i-units outstanding			328.2			316.2			290.6


	Basic and diluted earnings per unit:
	Distributed earnings per common unit and i-unit⁽¹⁾		$	2.23		$	2.2		$	2.19
	Overdistributed earnings per common unit and i-unit⁽²⁾			(1.56	)		(2.59	)		(0.92	)

	Net income (loss) per common unit and i-unit (basic and diluted)⁽³⁾		$	0.67		$	(0.39	)	$	1.27


	(1)	Represents the total distributed earnings to common units and i-units divided by the weighted average number of common units and i-units outstanding for the period.

	(2)	Represents the common units' 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 year ended December 31, 2014 and 2013, 43,201,310 anti-dilutive Preferred Units were excluded from the if-converted method of calculating diluted earnings per unit. For the year ended December 31, 2014, 66,100,000 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	12 Months Ended
CASH AND CASH EQUIVALENTS	Dec. 31, 2014
CASH AND CASH EQUIVALENTS [Abstract]
CASH AND CASH EQUIVALENTS	5. CASH AND CASH EQUIVALENTS

	We extinguish liabilities when a creditor has relieved us of our obligation, which occurs when our financial institution honors a check that the creditor has presented for payment. Accordingly, obligations for which we have made payments that have not yet been presented to the financial institution totaling approximately $17.9 million and $24.0 million at December 31, 2014 and 2013, respectively, are included in “Accounts payable and other” on our consolidated statements of financial position. At December 31, 2014 and 2013, we reclassified a book overdraft of $40.0 million and $49.1 million, respectively, to “Accounts payable and other” on our consolidated statements of financial position.

INVENTORY

INVENTORY	12 Months Ended
INVENTORY	Dec. 31, 2014
INVENTORY [Abstract]
INVENTORY	6. INVENTORY

		Our inventory is comprised of the following:
			December 31,
			2014		2013

			(in millions)
		Materials and supplies	$	2.2	$	2.1
		Crude oil inventory		13.2		18
		Natural gas and NGL inventory		78.8		74.8
			$	94.2	$	94.9

	The “Commodity costs” on our consolidated statements of income includes charges totaling $11.4 million, $3.4 million and $9.8 million for the years ended December 31, 2014, 2013 and 2012, 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	12 Months Ended
PROPERTY, PLANT AND EQUIPMENT	Dec. 31, 2014
PROPERTY, PLANT AND EQUIPMENT [Abstract]
PROPERTY, PLANT AND EQUIPMENT	7. PROPERTY, PLANT AND EQUIPMENT

	Our property, plant and equipment is comprised of the following:

					Depreciation			December 31,
					Rates			2014			2013

								(in millions)
		Land				-		$	44.2		$	43.6
		Rights-of-way				1.80%-7.14%			851.8			666.2
		Pipelines				1.79%-6.70%			9,585.40			8,035.80
		Pumping equipment, buildings and tanks				1.48%-6.67%			3,126.80			2,233.00
		Compressors, meters and other operating equipment				1.80%-20.00%			2,072.70			1,989.80
		Vehicles, office furniture and equipment				1.33%-33.33%			413.9			322
		Processing and treating plants				2.21%-2.73%			516			514.4
		Construction in progress							1,857.10			2,077.70
		Total property, plant and equipment							18,467.90			15,882.50
		Accumulated depreciation							(2,775.2	)		(2,705.7	)
		Property, plant and equipment, net						$	15,692.70		$	13,176.80

	Based on our own internal study, with consideration of a third-party consultant's report, we revised depreciation rates for our North Dakota, Ozark, and Cushing liquids systems effective October 1, 2013. The asset life was extended from 22 years to 30 years due to additional reserve growth and pipeline connectivity needs. The new remaining service lives resulted in an approximately $16.8 million annual reduction in depreciation expense for future periods with a reduction of $4.2 million for the year ended December 31, 2013.

	During the year ended December 31, 2014, we evaluated our Louisiana propylene pipeline for impairment in connection with the renegotiation of a contract. As a result of our analysis, we reduced the carrying value of $15.6 million to zero and recognized a corresponding non-cash impairment charge. This pipeline is part of our Natural Gas segment.

	During the year ended December 31, 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.

	We recorded an additional ARO for the year ended December 31, 2014 of $113.9 related to the pre-replacement of Lines 3 and 6B. Of that amount, $67.2 million is related to Line 6B and was recorded in “Accounts payable and other” with an offset to “Property, plant and equipment, net” in our statement of financial position and $46.7 million is related to Line 3 and was recorded in “Other long-term liabilities” with an offset to “Property, plant and equipment, net” in our consolidated statements of financial position. We did not record an additional ARO for the year ended December 31, 2013. We recorded an ARO of $0.4 million for the year ended December 31, 2012, when we recognized abandonment costs associated with assets we acquired through the September 2010 acquisition of the Elk City natural gas gathering and processing system.

	We do not have any assets that are legally restricted for purposes of settling our ARO at December 31, 2014 and 2013. The following is a reconciliation of the beginning and ending aggregate carrying amount of our ARO liabilities for each of the years ended December 31, 2014 and 2013:

			2014				2013
			(in millions)
	Balance at beginning of period			$	3.4			$	3.4
	Additions				113.9				-
	Accretion expense				1.1				-
	Liabilities settled				(21.6	)			-
	Balance at end of period			$	96.8			$	3.4

GOODWILL

GOODWILL	12 Months Ended
GOODWILL	Dec. 31, 2014
GOODWILL [Abstract]
GOODWILL	8. GOODWILL

	For each of the years ended December 31, 2014 and 2013, the carrying amount of goodwill was $246.7 million related to our natural gas business.

	We test our goodwill for impairment annually primarily by using a discounted cash flow analysis. In addition, we also consider overall market capitalization of our business, cash flow measurement data and other factors. We completed our annual goodwill impairment test using amounts as of June 30, 2014, which did not indicate the existence of impairment to goodwill associated with any of our reporting units. The critical assumptions used in our analysis included the following:

	1) A weighted average cost of capital of approximately 6.6%;

	2) An annual growth rate for our natural gas business of approximately 5.0%;

	3) A capital structure consisting of approximately 50% debt and 50% equity; and

	4) A long-term commodity price forecast using recent pricing information.

	We did not record any goodwill impairment during the years ended December 31, 2014, 2013 and 2012. We have not observed any further events or circumstances subsequent to our analysis that would, more likely than not, reduce the fair value of our reporting units below the carrying amounts as of December 31, 2014.

INTANGIBLE_ASSETS

INTANGIBLE ASSETS	12 Months Ended
INTANGIBLE ASSETS	Dec. 31, 2014
INTANGIBLE ASSETS [Abstract]
INTANGIBLE ASSETS	9. INTANGIBLE ASSETS

	The following table provides the gross carrying value, accumulated amortization and activity affecting amounts comprising each of our major classes of intangible assets.


				31-Dec-14
			Gross Intangible Assets at December 31, 2013		Additions		Dispositions			Intangible Assets, Gross		Gross Accumulated Amortization at December 31, 2013			Amortization Expenses			Accumulated Amortization, Gross			Intangible Assets, Net

		Natural Gas Opportunities	$	291	$	-	$	-		$	291	$	(59.4	)	$	(10.3	)	$	(69.7	)	$	221.3
		Customer Contracts		4.4		-		-			4.4		(1.7	)		(0.4	)		(2.1	)		2.3
		Other		37.7		8.1		(1.0	)		44.8		(8.8	)		(4.8	)		(13.6	)		31.2
		Total intangible assets	$	333.1	$	8.1	$	(1.0	)	$	340.2	$	(69.9	)	$	(15.5	)	$	(85.4	)	$	254.8

			31-Dec-13
			Gross Intangible Assets at December 31, 2012		Additions		Dispositions			Intangible Assets, Gross		Gross Accumulated Amortization at December 31, 2012			Amortization Expenses			Accumulated Amortization, Gross			Intangible Assets, Net

		Natural Gas Opportunities	$	291	$	-	$	-		$	291	$	(49.0	)	$	(10.4	)	$	(59.4	)	$	231.6
		Customer Contracts		4.4		-		-			4.4		(1.2	)		(0.5	)		(1.7	)		2.7
		Other		15.4		22.3		-			37.7		(3.4	)		(5.4	)		(8.8	)		28.9
		Total intangible assets	$	310.8	$	22.3	$	-		$	333.1	$	(53.6	)	$	(16.3	)	$	(69.9	)	$	263.2


	Intangible assets include customer contracts and natural gas supply opportunities, both of which relate entirely to our Natural Gas segment. Our customer contracts are comprised of natural gas purchase and sale agreements. We amortize our customer contracts on a straight-line basis over the weighted average useful life of the underlying reserves at the time of acquisition, which is approximately 25 year.

	We obtained a portion of the natural gas supply opportunities in conjunction with the 2003 North Texas system acquisition. We obtained an additional portion of natural gas supply opportunities in connection with our September 2010 acquisition of the Elk City system. The value of these intangible assets is derived from growth opportunities present in the Barnett Shale producing zone of North Texas and the Granite Wash reservoir of the Anadarko basin in western Oklahoma and the Texas Panhandle. The natural gas supply opportunities relate entirely to our gathering, processing and transportation business. We are amortizing the natural gas supply opportunities on a straight line basis over the weighted average estimated useful life of the underlying reserves at the time of the acquisition, which is approximate 25 to 30 years.

	Our other intangible assets are comprised of contributions we made in aid of construction for our gathering, processing and transportation business. Contributions in aid of construction have an estimated useful life of 25 years, and software has an estimated useful life of 3 years. In connection with our October 2010 acquisition of a common carrier trucking company, we recognized additional intangibles assets related to workforce contracts and customer relationships.

	The following table presents our forecast of amortization expense associated with existing intangible assets for the years indicated:




			2015		2016		2017			2018		2019
			$	15.7	$	13.5	$	12.2		$	12	$	12

DEBT

DEBT	12 Months Ended
DEBT	Dec. 31, 2014
DEBT [Abstract}
DEBT	10. DEBT

	The following table presents the primary components of our outstanding indebtedness with third parties and the weighted average interest rates associated with each component as of December 31, 2014, before the effect of our interest rate hedging activities. Our indebtedness with related parties is discussed in Note 12. Related Party Transactions.

				Interest			December 31,
				Rate			2014			2013

							(in millions)
	EEP debt obligations:
	Commercial Paper(1)				0.503	%	$	612.3		$	300
	Credit Facilities due 2016-2018				1.293	%		1,160.00			-
	Senior Notes due 2014				5.35	%		-			200
	Senior Notes due 2016				5.875	%		300			300
	Senior Notes due 2018				7	%		100			100
	Senior Notes due 2018				6.5	%		400			400
	Senior Notes due 2019				9.875	%		500			500
	Senior Notes due 2020				5.2	%		500			500
	Senior Notes due 2021				4.2	%		600			600
	Senior Notes due 2028				7.125	%		100			100
	Senior Notes due 2033				5.95	%		200			200
	Senior Notes due 2034				6.3	%		100			100
	Senior Notes due 2038				7.5	%		400			400
	Senior Notes due 2040				5.5	%		550			550
	Junior subordinated notes due 2067				8.05	%		400			400
	MEP debt obligations:
	MEP Credit Agreement				3.2	%		360			335
	MEP Series A Senior Notes due 2019				3.56	%		75			-
	MEP Series B Senior Notes due 2021				4.04	%		175			-
	MEP Series C Senior Notes due 2024				4.42	%		150			-
	Total Principal of Debt Obligations							6,682.30			4,985.00
	Other:
	Unamortized Discount							(7.1	)		(7.6	)
	Current Maturities and short term debt							-			(200.0	)
	Total Long Term Debt						$	6,675.20		$	4,777.40
	______________________________
	(1)

	Individual issuances of commercial paper generally mature in 90 days or less, but are supported by our Credit Facilities



	Interest Cost

	For the years ended December 31, 2014, 2013 and 2012 our interest cost is comprised of the following:

				For the year ended December 31,

				2014			2013			2012

				(in millions)

		Interest expense		$	403.2		$	320.4		$	345
		Interest capitalized			45.3			51.7			36.3
		Interest cost incurred		$	448.5		$	372.1		$	381.3

		Interest paid		$	332.4		$	342.3		$	352.1

		Weighted average interest rate			6.1	%		6.2	%		6.4	%

	Maturities of Third Party Debt

	The scheduled maturities of outstanding third-party debt, excluding any discounts at December 31, 2014, are summarized as follows in millions:


	2015		$	-
	2016			950
	2017			360
	2018			1,622.30
	2019			575
	Thereafter			3,175.00
	Total		$	6,682.30



Credit Facilities

In September 2011, we entered into a multi-year senior unsecured revolving credit facility, as amended through October 6, 2014, which we refer to as the Credit Facility. The Credit Facility permits aggregate borrowings of up to, at any one time outstanding, $1.975 billion, a letter of credit subfacility and a swing line subfacility. The Credit Facility matures September 26, 2019; however, $175.0 million of commitments will expire on the original maturity date of September 26, 2018.

On July 6, 2012, we entered into a 364-day credit agreement, as amended through July 3, 2014, which we refer to as the 364-Day Credit Facility. 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. Our 364-day Credit Facility terminates July 3, 2015.

Together, the Credit Facilities provide an aggregate amount of approximately $2,625 million of bank credit, as of December 31, 2014, which we use to fund our general activities and working capital needs.

Under our Credit Facilities, we had net borrowings of approximately $1,160.0 million during the twelve month period ended December 31, 2014, which includes gross borrowings of $2,120.0 million and gross repayments of $960.0 million.

LIBOR rate borrowings under the terms of our Credit Facilities may be renewed as LIBOR rate borrowings or as base rate borrowings at the end of each LIBOR rate interest period, which is typically a period of three months or less. These renewals do not constitute new borrowings under the Credit Facilities and do not require any cash repayments or prepayments. For the twelve month period ended December 31, 2014, we had LIBOR rate borrowings of $1.160 billion on an outstanding balance under our Credit Facilities and no base rate borrowings. For the twelve month period ended December 31, 2013, we did not have any LIBOR rate borrowings or base rate borrowings.

The Credit Facilities contain, among other affirmative and negative covenants, certain financial covenants. A failure to comply with that covenant could result in an event of default under the Credit Facilities, which would prohibit us from declaring or making distributions to our unitholders and would permit acceleration of, and termination of our access to, our indebtedness under the Credit Facilities, and may cause acceleration of our outstanding senior notes. Although we expect to be able to comply with this covenant under each of our Credit Facilities, there can be no assurance that in the future we will be able to do so or that our lenders will be willing to waive such non-compliance or further amend such covenants. As of December 31, 2014, we were in compliance with the terms of all of our financial covenants under the Credit Facilities.

Our Credit Facilities previously were amended to (1) exclude up to $650.0 million of the costs associated with the remediation of the area affected by the crude oil releases on Lines 6A and 6B from the EBITDA component of the consolidated leverage ratio covenant in each of our Credit Facilities and (2) with respect to the quarterly covenant compliance testing, from the definition of consolidated net income component of the consolidated leverage ratio covenant, accrued but unpaid costs, expenses, fines, and penalties occurring after September 30, 2013, related to the remediation of the area affected by the crude oil releases on Lines 6A and 6B.

On February 3, 2014, EEP entered into an uncommitted letter of credit arrangement, pursuant to which the bank may, on a discretionary basis and with no commitment, agree to issue standby letters of credit upon our request in an aggregate amount not to exceed $200.0 million. On September 9, 2014, the amount was increased to $220.0 million. While the letter of credit arrangement is uncommitted and issuance of letters of credit is at the bank's sole discretion, we view this arrangement as liquidity enhancement as it allows EEP to potentially reduce its reliance on utilizing the committed Credit Facilities for issuance of letters of credit to support its hedging activities.

Commercial Paper

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 December 31, 2014, we had approximately $612.3 million in principal amount of commercial paper outstanding at a weighted average interest rate of 0.50%, excluding the effect of our interest rate hedging activities. Under our commercial paper program, we had net borrowings of approximately $312.1 million during the twelve month period ended December 31, 2014, which includes gross borrowings of $11.2 billion and gross repayments of $10.9 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 that the commercial paper we can issue is limited 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.

The amounts we may borrow under the terms of our Credit Facilities are reduced by the face amount of our letters of credit outstanding. It is our policy 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 such time. Taking that policy into account, at December 31, 2014, we had approximately $522.5 million available to us under the terms of our Credit Facilities, determined as follows:

			(in millions)
Total credit limit under Credit Facilities			$	2,625.00
Less: Amounts outstanding under Credit Facilities				-
	Principal amount of commercial paper outstanding			612.3
	Credit Facilities			1,160.00
	Letters of credit outstanding			330.2
Total amount available at December 31, 2014			$	522.5

Senior Notes

All of our senior notes represent our unsecured obligations that rank equally in right of payment with all of our existing and future unsecured and unsubordinated indebtedness. Our senior notes are structurally subordinated to all existing and future indebtedness and other liabilities, including trade payables of our subsidiaries and the $200.0 million of senior notes issued by the OLP. The borrowings under our senior notes are non-recourse to our General Partner and Enbridge Management. All of our senior notes either pay or accrue interest semi-annually and have varying maturities and terms.

The OLP, our operating subsidiary that owns the Lakehead system, has $200.0 million of senior notes outstanding representing unsecured obligations that are structurally senior to our senior notes. The OLP Notes consist of $100.0 million of 7.000% senior notes due 2018 and $100.0 million of 7.125% senior notes due 2028. All of the OLP Notes pay interest semi-annually.

Junior Subordinated Notes

The $400.0 million in principal amount of our fixed/floating rate, junior subordinated notes due 2067, which we refer to as the Junior Notes, represent our unsecured obligations that are subordinate in right of payment to all of our existing and future senior indebtedness. The Junior Notes bear interest at a fixed annual rate of 8.05%, exclusive of any discounts or interest rate hedging activities, payable semi-annually in arrears on April 1 and October 1 of each year until October 1, 2017. After October 1, 2017, the Junior Notes will bear interest at a variable rate equal to the three-month LIBOR for the related interest period increased by 3.7975%, payable quarterly in arrears on January 1, April 1, July 1 and October 1 of each year beginning January 1, 2018. We may elect to defer interest payments on the Junior Notes for up to ten consecutive years on one or more occasions, but not beyond the final repayment date. Until paid, any interest we elect to defer will bear interest at the prevailing interest rate, compounded semi-annually during the period the Junior Notes bear interest at the fixed annual rate and quarterly during the period that the Junior Notes bear interest at a variable annual rate.

The Junior Notes do not restrict our ability to incur additional indebtedness. However, with limited exceptions, during any period we elect to defer interest payments on the Junior Notes, we cannot make cash distribution payments or liquidate any of our equity securities, nor can we or our subsidiaries make any principal and interest payments for any debt that ranks equally with or junior to the Junior Notes.

The scheduled maturity date for the Junior Notes is initially October 1, 2037, but we may extend the maturity date up to two times, on October 1, 2017, and October 1, 2027, in each case for an additional ten-year period. As a result, the scheduled maturity date may be extended to October 1, 2047, or October 1, 2057. Our obligation to repay the Junior Notes on the scheduled maturity date is limited by an agreement we refer to as the Replacement Capital Covenant, which we entered into in connection with our offering of the Junior Notes, but not as part of the Junior Notes. The Replacement Capital Covenant limits the types of financing sources we can use to repay the Junior Notes. We are required to repay the Junior Notes on the scheduled maturity date only to the extent the principal amount repaid does not exceed proceeds we have received from the issuance and sale of securities, that, among other attributes defined in the Replacement Capital Covenant, have characteristics that are the same or more equity-like than the Junior Notes. We refer to the securities that meet this characterization as qualifying capital securities. If we do not receive sufficient proceeds from the sale of qualifying capital securities to repay the Junior Notes by the scheduled maturity date, we must use our commercially reasonable efforts to raise sufficient proceeds from the sale of qualifying capital securities to permit repayment of the Junior Notes on the following quarterly interest payment date, and on each subsequent quarterly interest payment date until the Junior Notes are paid in full. Regardless of the amount of qualifying capital securities that we have issued and sold, the final repayment date is initially October 1, 2067. We may extend the final repayment date for an additional ten-year period on October 1, 2017, and as a result the final repayment date may be extended to October 1, 2077. We may extend the scheduled maturity date whether or not we also extend the final repayment date, and we may extend the final repayment date whether or not we extend the scheduled maturity date.

We may redeem the Junior Notes in whole at any time, or in part, prior to October 1, 2017, for a “make-whole” redemption price, and thereafter at a redemption price equal to the principal amount plus accrued and unpaid interest on the Junior Notes. We may also redeem the Junior Notes prior to October 1, 2017, in whole, but not in part, upon the occurrence of certain tax or rating agency events at specified redemption prices. Our right to optionally redeem the Junior Notes is also limited by the Replacement Capital Covenant, which limits the types of financing sources we can use to redeem the Junior Notes in the same manner as to repay the Junior Notes, as discussed in the above paragraph.

MEP Credit Agreement

On November 13, 2013, in connection with the closing of the Offering, MEP, Midcoast Operating, and their material domestic subsidiaries, entered into a Credit Agreement, which we refer to as the MEP Credit Agreement, by and among MEP, as co-borrower and a guarantor, Midcoast Operating, as co-borrower and a guarantor, MEP's material subsidiaries party thereto as guarantors, Bank of America, N.A., as administrative agent, letter of credit issuer, swing line lender and lender, and each of the other lenders party thereto.

The MEP Credit Agreement is a committed senior revolving credit facility (with related letter of credit and swing line facilities) that permits aggregate borrowings of up to, at any one time outstanding, $850.0 million, including up to initially: (1) $90.0 million under the letter of credit facility; and (2) $75.0 million under the swing line facility. Subject to customary conditions, MEP may request that the lenders' aggregate commitments be increased to an amount not to exceed $1.0 billion. The facility matures in two years, subject to four one-year requests for extensions. At December 31, 2014, MEP was in compliance with the terms of their financial covenants.

On September 30, 2014, MEP amended the MEP Credit Agreement to, among other things 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, MEP entered into an amended and restated subordination agreement by and among MEP, Midcoast Operating, the other parties from time to time party thereto and EEP 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 Credit Agreement, to accommodate the subordination agreement entered into in connection with the Purchase Agreement, described below under “MEP Private Debt Issuance.”

Loans under the MEP Credit Agreement accrue interest at a per annum rate by reference, at MEP's election, to the Eurodollar rate, which is equal to the LIBOR rate or a comparable or successor rate reasonably approved by the administrative agent, or base rate, in each case, plus an applicable margin. The applicable margin on Eurodollar (LIBOR) rate loans ranges from 1.75% to 2.75% and the applicable margin on base rate loans ranges from 0.75% to 1.75%, in each case determined based upon our total leverage ratio (as defined below) at the applicable time. At December 31, 2014, MEP had $360.0 million in outstanding borrowings under the MEP Credit Agreement at a weighted average interest rate of 3.2%. Under the Credit Agreement, MEP had net repayments of approximately $25.0 million during the twelve month period ended December 31, 2014, which includes gross borrowings of $6,920.0 million and gross repayments of $6,895.0 million.

A letter of credit fee is payable by the borrowers equal to the applicable margin for Eurodollar (LIBOR) rate loans times the daily amount available to be drawn under outstanding letters of credit. A commitment fee is payable by us equal to an applicable margin times the daily unused amount of the lenders' commitment, which applicable margin ranges from 0.30% to 0.50% based upon our total leverage ratio at the applicable time.

Each of MEP's domestic material subsidiaries has unconditionally guaranteed all existing and future indebtedness and liabilities of the borrowers arising under the MEP Credit Agreement and other loan documents, and each co-borrower has guaranteed all such indebtedness and liabilities of the other co-borrower. The MEP Credit Agreement is unsecured but security will be provided upon occurrence of any of the following: (1) for two consecutive quarters, the total leverage ratio as described below, exceeds 4.25 to 1.00, or 4.75 to 1.00 during acquisition periods, (2) uncured breach to certain terms and conditions of the MEP Credit Agreement and (3) obtaining a non-investment grade initial debt rating from either S&P or Moody's.

The MEP Credit Agreement also requires compliance with two financial covenants. MEP must not permit the ratio of consolidated funded debt to pro forma EBITDA (the total leverage ratio) of MEP and its consolidated subsidiaries (including Midcoast Operating), as of the end of any applicable four-quarter period, to exceed 5.00 to 1.00, or 5.50 to 1.00 during acquisition periods. 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. These covenants are subject to exceptions and qualifications set forth in the Credit Agreement.

MEP Private Debt Issuance

On September 30, 2014, MEP completed a private debt offering of $400.0 million of notes consisting 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 five 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 contains events of default, indemnities, and covenants customary for transactions of this nature. These covenants and restrictive provisions are subject to exceptions and qualifications set forth in the Purchase Agreement. At such time as we obtain an investment grade rating from either Moody's or S&P, the obligation to provide security in certain circumstances will no longer be applicable to the Partnership or the guarantors and certain restrictions on prepayments of certain subordinated and affiliate will become less restricted.

The Purchase Agreement also requires compliance with two financial covenants. MEP must not permit the ratio of consolidated funded debt to pro forma EBITDA (the total leverage ratio) as of the end of any applicable four-quarter period, to exceed 5.00 to 1.00, or 5.50 to 1.00 during acquisition periods. 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. AT December 31, 2014, MEP was in compliance with the terms of its financial covenants under the Purchase Agreement.

The Notes are prepayable at our option, in whole or in part, provided that any such prepayment may incur a “make-whole” premium as specified in the Purchase Agreement. We must offer to prepay the notes upon the occurrence of any change of control. Under the Purchase Agreement, a change of control occurs if EEP or Enbridge ceases to control, directly or indirectly, our general partner. In addition, we must offer to prepay the Notes upon the occurrence of certain asset dispositions if the proceeds therefrom are not timely reinvested in productive assets.

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 the MEP Credit Agreement approximate their fair values at December 31, 2014 and December 31, 2013, respectively, due to the short-term nature and frequent repricing of 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 since we have the ability to refinance the amounts on a long-term basis.

The approximate fair values of our fixed-rate debt obligations was $5.1 billion and $4.9 billion at December 31, 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	12 Months Ended
PARTNERS' CAPITAL	Dec. 31, 2014
PARTNERS' CAPITAL [Abstract]
PARTNERS' CAPITAL	11. PARTNERS' CAPITAL

	Our capital accounts are comprised of a 2% general partner interest and 98% limited partner interests. Our limited partner interests at December 31, 2014, include Class A and Class B common units, Class D units, i-units, IDUs and Series 1 preferred units. We refer to our Class A and Class B common units collectively as common units. Our limited partners have limited rights of ownership as provided for under our partnership agreement and, as discussed below, the right to participate in our distributions. Our General Partner manages our operations, subject to a delegation of control agreement with Enbridge Management, and participates in our distributions. At December 31, 2014 and 2013, our voting interests were as follows:

			2014			2013

	Series 1 preferred units			9.6	%		11.5	%
	Class A common units owned by the public			46.4	%		55.2	%
	Class A common units owned by our General Partner			10.4	%		12.3	%
	Class B common units owned by our General Partner			1.7	%		2.1	%
	Class D units owned by our General Partner			14.7	%		-	%
	i-units owned by Enbridge Management ⁽¹⁾			15.2	%		16.9	%
	General Partner interest			2.0	%		2.0	%
				100.0	%		100.0	%

	-1

	For the years ended December 31, 2014 and 2013, our General Partner 11.7% of Enbridge Management, which owns all of our i-units.



	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 paid on our 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 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 on the Class D units so that the aggregate distributions paid in calendar year 2014 with respect to the previous IDRs, the Class D units, and the IDUs did 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.

	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 being 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.



	Series 1 Preferred Unit Purchase Agreement

	On May 8, 2013, we issued and sold 48,000,000 of our preferred units, representing limited partner interests in us, or Preferred Units, for aggregate proceeds of approximately $1.2 billion. We used proceeds from the Preferred Unit issuance to repay commercial paper, to finance a portion of its capital expansion program relating to its core liquids and natural gas systems and for general partnership purposes.

	The Preferred Units are entitled to annual cash distributions of 7.50% of the issue price, payable quarterly, which are subject to reset every five years. However, these quarterly cash distributions, during the first full eight quarters ending June 30, 2015, will accrue and accumulate, which we refer to as the Payment Deferral. Thus we will accrue, but not pay these amounts until the earlier of the fifth anniversary of the issuance of such Preferred Units or the redemption of such Preferred Units by us. The quarterly cash distribution for the three month period ended June 30, 2013, was prorated from May 8, 2013.

	On or after June 1, 2016, at the sole option of the holder of the Preferred Units, the Preferred Units may be converted into Class A Common Units, in whole or in part, at a conversion price of $27.78 per unit plus any accrued, accumulated and unpaid distributions, excluding the Payment Deferral, as adjusted for splits, combinations and unit distributions. At all other times, redemption of the Preferred Units, in whole or in part, is permitted only if: (1) the Partnership uses the net proceeds from incurring debt and issuing equity, which includes asset sales, in equal amounts to redeem such Preferred Units; (2) a material change in the current tax treatment of the Preferred Units occurs; or (3) the rating agencies' treatment of the equity credit for the Preferred Units is reduced by 50% or more, all at a redemption price of $25.00 per unit plus any accrued, accumulated and unpaid distributions, including the Payment Deferral.

	The Preferred Units were issued at a discount to the market price of the common units into which they are convertible. This discount totaling $47.7 million represents a beneficial conversion feature and is reflected as an increase in common and i-unit unitholders' and General Partner's capital and a decrease in Preferred Unitholders' capital to reflect the fair value of the Preferred Units at issuance on the Partnership's consolidated statement of partners' capital for the twelve month period ended December 31, 2013. The beneficial conversion feature is considered a dividend and is distributed ratably from the issuance date of May 8, 2013 through the first conversion date, which is June 1, 2016, resulting in an increase in preferred capital and a decrease in common and subordinated unitholders' capital.

	Issuance of Class A Common Units

	The following table presents the net proceeds from our Class A common unit issuances for the year ended December 31, 2012. There were no issuances of Class A common units for the years ended December 31, 2014 and 2013.

	Issuance Date			Number of Class A common units Issued			Offering Price per Class A common unit		Net Proceeds		General		Net Proceeds Including General Partner Contribution

									to the		Partner

									Partnership (1)		Contribution (2)

				(in millions, except units and per unit amounts)
	2012
	September (3)				16,100,000		$	28.64	$	446.8	$	9.4	$	456.2


	(1)

	Net of underwriters' fees and discounts, commissions and issuance expenses if any.
	(2)

	Contributions made by the General Partner to maintain its 2% general partner interest.
(3)

The proceeds from the September 2012 equity issuance were used to fund a portion of our capital expansion projects and for general partnership purposes.

Class B common units

All of our outstanding Class B common units are held by our General Partner and have rights similar to our Class A common units except that they are not currently eligible for trading on the NYSE.

i-units

The i-units are a separate class of our limited partner interests, all of which are owned by Enbridge Management and are not publicly traded.

Enbridge Management, as the owner of our i-units, votes together with the holders of the common units as a single class. However, the i-units vote separately as a class on the following matters:

• Any proposed action that would cause us to be treated as a corporation for United States federal income tax purposes;

• Amendments to our partnership agreement that would have a material adverse effect on the holder of our i-units, unless, under our partnership agreement, the amendment could be made by our General Partner without a vote of holders of any class of units;

• The removal of our General Partner and the election of a successor general partner; and

• The transfer by our General Partner of its general partner interest to a non-affiliated person that requires a vote of holders of units under our partnership agreement and the admission of that person as a general partner.

In all cases, Enbridge Management will vote or refrain from voting its i-units in the same manner that owners of Enbridge Management's shares vote or refrain from voting their shares. Furthermore, under the terms of our partnership agreement, we agree that we will not, except in liquidation, make a distribution on an i-unit other than in additional i-units or a security that has in all material respects the same rights and privileges as the i-units.

Investments

In September 2013, Enbridge Management completed a public offering of 8,424,686 Listed Shares, representing limited liability company interests with limited voting rights, at a price to the underwriters of $28.02 per Listed Share. Enbridge Management received net proceeds of $235.6 million, which were subsequently invested in a number of our i-units equal to the number of Listed Shares sold in the offering. We used the proceeds from our issuance of i-units to Enbridge Management to repay commercial paper, finance a portion of our capital expansion program relating to our core liquids and natural gas systems and for general corporate purposes.

In March 2013, Enbridge Management completed a public offering of 10,350,000 Listed Shares, representing limited liability company interests with limited voting rights, at a price to the underwriters of $26.44 per Listed Share. Enbridge Management received net proceeds of $272.9 million, which were subsequently invested in a number of our i-units equal to the number of Listed Shares sold in the offering. We used the proceeds from our issuance of i-units to Enbridge Management to finance a portion of our capital expansion program relating to the expansion of our core liquids and natural gas systems and for general corporate purposes.

Distributions

Our partnership agreement requires us to distribute 100% of our “available cash”, which is generally defined in our partnership agreement as the sum of all cash receipts plus reductions in cash reserves established in prior quarters less cash disbursements and additions to cash reserves in that calendar quarter. Enbridge Management, as delegate of our General Partner under the delegation of control agreement, computes the amount of our “available cash.” Typically, our General Partner and owners of our common units will receive distributions in cash. We also retain reserves to provide for the proper conduct of our business, to stabilize distributions to our unitholders and our General Partner and, as necessary, to comply with the terms of our agreements or obligations (including any reserves required under debt instruments for future principal and interest payments and for future capital expenditures). We make distributions to our partners approximately 45 days following the end of each calendar quarter in accordance with their respective percentage interests.

Our General Partner is granted discretion by our partnership agreement, which discretion has been delegated to Enbridge Management, subject to the approval of our General Partner in certain cases, to establish, maintain and adjust reserves for future operating expenses, debt service, maintenance capital expenditures, and distributions for the next four quarters. These reserves are not restricted by magnitude, but only by type of future cash requirements with which they can be associated. When Enbridge Management determines our quarterly distributions, it considers current and expected reserve needs along with current and expected cash flows to identify the appropriate sustainable distribution level.

Distributions of our available cash are generally made 98% to holders of our limited partner units and 2% to our General Partner. However, distributions are subject to the payment of incentive distributions to our General Partner to the extent that certain target levels of distributions to the unitholders are achieved. Before July 1, 2014 the incentive distributions payable to our General Partner were 15%, 25% and 50% of all quarterly distributions of available cash that exceed target levels of $0.295, $0.35 and $0.495 per limited partner units, respectively. After July 1, 2014, the incentive distributions payable to the IDUs are 25% of all quarterly distributions of available cash that exceed the target level of $0.5435 per limited partner unit. As set forth in our partnership agreement, we will not make cash distributions on our i-units, but instead, will distribute additional i-units such that the cash is retained and used in our operations and to finance a portion of our capital expansion projects.

Enbridge Management, as owner of the i-units, does not receive distributions in cash. Instead, each time that we make a cash distribution to our General Partner, holders of the Class D units, and holders of our Class A and Class B common units, the number of i-units owned by Enbridge Management and the percentage of our total units owned by Enbridge Management will increase automatically under the provisions of our partnership agreement with the result that the number of i-units owned by Enbridge Management will equal the number of Enbridge Management's listed and voting shares that are then outstanding. The amount of this increase in i-units is determined by dividing the cash amount distributed per common unit by the average price of one of Enbridge Management's listed shares on the NYSE for the 10 trading day period immediately preceding the ex-dividend date for Enbridge Management's shares multiplied by the number of shares outstanding on the record date. The cash equivalent amount of the additional i-units is treated as if it had actually been distributed for purposes of determining the distributions to be made to our General Partner.




Distribution to Partners

The following table sets forth our distributions, as approved by the board of directors of Enbridge Management, during the years ended December 31, 2014, 2013 and 2012.

											Amount of
									Cash		Distribution		Retained
					Distribution				available		of i-units to		from
Distribution					Payment		Distribution		for		i-unit		General		Distribution
Declaration Date			Record Date		Date		per Unit		distribution		Holders (1)		Partner (2)		of Cash
									(in millions, except per unit amounts)
2014
		31-Oct	7-Nov		14-Nov		$	0.555	$	221.8	$	37.3	$	0.8	$	183.7
		31-Jul	7-Aug		14-Aug		$	0.555		224.7		36.7		0.8		187.2
		30-Apr	8-May		15-May		$	0.5435		214.5		35.3		0.7		178.5
		30-Jan	7-Feb		14-Feb		$	0.5435		213.7		34.6		0.7		178.4
									$	874.7	$	143.9	$	3	$	727.8
2013
		31-Oct	7-Nov		14-Nov		$	0.5435	$	213.1	$	34.1	$	0.7	$	178.3
		29-Jul	7-Aug		14-Aug		$	0.5435		206.8		28.9		0.6		177.3
		30-Apr	8-May		15-May		$	0.5435		206.2		28.4		0.6		177.2
		30-Jan	7-Feb		14-Feb		$	0.5435		198.9		22.4		0.4		176.1
									$	825	$	113.8	$	2.3	$	708.9
2012
		31-Oct	7-Nov		14-Nov		$	0.5435	$	198.5	$	22	$	0.4	$	176.1
		30-Jul	7-Aug		14-Aug		$	0.5435		187.5		21.6		0.5		165.4
		30-Apr	7-May		15-May		$	0.5325		180.7		20.9		0.4		159.4
		30-Jan	7-Feb		14-Feb		$	0.5325		180.3		20.5		0.4		159.4
									$	747	$	85	$	1.7	$	660.3

(1)

We issued 4,562,088, 3,769,989 and 2,632,090 i-units to Enbridge Management, L.L.C., the sole owner of our i-units, during 2014, 2013 and 2012, respectively, in lieu of cash.
(2)

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

RELATED_PARTY_TRANSACTIONS

RELATED PARTY TRANSACTIONS

12 Months Ended

Dec. 31, 2014

RELATED PARTY TRANSACTIONS [Abstract]

RELATED PARTY TRANSACTIONS

12. 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 affiliate amounts incurred by us for services received pursuant to the services agreements are reflected in “Operating and administrative – affiliate” on our consolidated statements of income.

Service Agreements

Our General Partner, Enbridge Management, Enbridge and affiliates of Enbridge provide managerial, administrative, operational and director services to us pursuant to service agreements, and we reimburse them for the costs of those services. Through an operational services agreement among Enbridge, Enbridge Operational Services, Inc., or EOSI, and Enbridge Pipelines, both subsidiaries of Enbridge, all of whom we refer to as the Canadian service providers, and us, we are charged for the services of Enbridge employees resident in Canada. Through a general and administrative services agreement among us, our General Partner, Enbridge Management and Enbridge Employee Services, Inc., or EES, we are charged for the services of employees resident in the United States. The charges related to these service agreements are included in “Operating and administrative – affiliate” expenses on our consolidated statements of income.

Operational Services Agreement

We are charged an amount by the Canadian service providers for services we are provided under the operational services agreement. The amount we are charged is established as part of the annual budget and agreed upon by us and the Canadian service providers. The amount we are charged is computed based on an estimate of the pro-rata reimbursement of each Canadian service provider's estimated annual departmental costs, net of amounts charged to other affiliates and amounts identifiable as costs of that Canadian service provider. The Canadian service providers charge us a monthly fixed fee that is computed as one-twelfth of the annual budgeted amount. Under the operational services agreement, our General Partner and Enbridge Management pay the Canadian service providers a monthly fee determined in the manner described above. At the request of Enbridge Management, the fee for these operational services provided to it in its capacity as the delegate of our General Partner are billed directly to us.

Enbridge Management and our General Partner may request that the Canadian service providers provide special additional operational services for which each, as appropriate, agrees to pay costs and expenses incurred by the Canadian service provider in connection with providing the special additional operational services. The types of services provided under the operational services agreement include:

• Executive, administrative and other services on an “as required” basis;

• Monitoring transportation capacity, scheduling shipments, standardizing integrity, maintenance and other operational requirements;

• Addressing regulatory matters associated with the liquids pipeline operations;

• Providing monthly measurement information, forecasts, oil accounting, invoicing and related services;

• Computer application development and support services, including liquid pipelines' control center operations;

• Electrical power requirements and costs for system operations;

• Patrol and aircraft services; and

• Any other operational services required to operate existing systems and any additional systems acquired by us.

Each year, the Canadian service providers prepare annual budgets by departmental cost center for their respective operations. After establishing a budget for the following year, the costs associated with each department are allocated to us, our General Partner, Enbridge Management and other Enbridge affiliates using one of the following three methods:

• Capital assets employed as a percentage of Enbridge-wide capital assets;

• Time-based estimates; or

• Full-time-equivalent (FTE)/headcount as a percentage of Enbridge-wide FTEs.

The total amount we reimbursed the Canadian service providers pursuant to the operational services agreement for the years ended December 31, 2014, 2013 and 2012, was $150.9 million, $154.9 million and $133.0 million, respectively.

General and Administrative Services Agreement

We, Enbridge Management and our General Partner receive services from EES under the general and administrative services agreement. Under this agreement, EES provides services to us, Enbridge Management and our General Partner and charges each recipient for services, on a monthly basis, the actual costs that it incurs for those services. Our General Partner and Enbridge Management may request that EES provide special additional general services for which each, as appropriate, agrees to pay costs and expenses incurred by EES in connection with providing the special additional general services. The types of services provided under the general and administrative services agreement include:

• Accounting, tax planning and compliance services, including preparation of financial statements and income tax returns;

• Administrative, executive, legal, human resources and computer support services;

• Insurance coverage;

• All administrative and operational services required to operate existing systems and any additional systems acquired by us and operated by EES; and

• Facilitate the business and affairs of Enbridge Management and us, including, but not limited to, public and government affairs, engineering, environmental, finance, audit, operations and operational support, safety/compliance and other services.

EES captures all costs that it incurs for providing the services by cost center in its financial system. The cost centers are determined to be “Shared Service”, “Enbridge Energy Partners, L.P. only” or “Non-Enbridge Energy Partners, L.P.” Shared Service cost centers are used to capture costs that are not specific to a single United States Enbridge entity but are shared among multiple United States Enbridge entities. The costs captured in the cost centers that are specific to us are charged in full to us. The costs captured in cost centers that are outside of our business unit are charged to other Enbridge entities.

The general method used to allocate the Shared Service costs is established through the budgeting process and reimbursed as follows:

• Each cost center establishes a budget.

• Each cost center manager estimates the amount of time the department spends on us and entities that are not directly affiliated with us.

• Costs are accumulated monthly for each cost center.

• The actual costs accumulated monthly by each cost center are allocated to us or entities that are not directly affiliated with us based on the allocation model.

• We reimburse EES for its share of the allocated costs.

The total amount reimbursed by us for services received pursuant to the general and administrative services agreement for the years ended December 31, 2014, 2013 and 2012, was $179.0 million, $284.1 million and $291.1 million, respectively.

Enbridge and its affiliates allocated direct workforce costs to us for our construction projects of $44.3 million, $51.7 million and $33.1 million during 2014, 2013 and 2012, respectively, that we recorded as additions to “Property, plant and equipment, net” on our consolidated statements of financial position.

Insurance Allocation Agreement

We participate in the comprehensive insurance program that is maintained by Enbridge for it and its subsidiaries. In December 2012, the Partnership entered into an insurance allocation agreement with Enbridge and another Enbridge subsidiary, which was amended and restated on November 13, 2013, to add MEP as a party. Under this agreement, in the unlikely event multiple insurable incidents occur which exceed coverage limits within the same insurance period, the total insurance coverage will be allocated among the Enbridge entities on an equitable basis.

Sale of Accounts Receivable

Certain of our subsidiaries entered into a receivables purchase agreement, dated June 28, 2013, and amended on September 20, 2013 and December 2, 2013, which we refer to as the Receivables Agreement, with an indirect wholly-owned subsidiary of Enbridge. The Receivables Agreement and the transactions contemplated thereby were approved by the special committee of the board of directors of Enbridge Management. Pursuant to the Receivables Agreement, the Enbridge subsidiary will purchase on a monthly basis, for cash, current accounts receivable and accrued receivables, or the receivables, of the respective subsidiaries initially up to a monthly maximum of $450.0 million. Following the sale and transfer of the receivables to the Enbridge subsidiary, the receivables are deposited in an account of that subsidiary, and ownership and control are vested in that subsidiary. The Enbridge subsidiary has no recourse with respect to the receivables acquired from these operating subsidiaries under the terms of and subject to the conditions stated in the Receivables Agreement.

We and MEP act in an administrative capacity as collection agents on behalf of the Enbridge subsidiary and can be removed at any time in the sole discretion of the Enbridge subsidiary. We have no other involvement with the purchase and sale of the receivables pursuant to the Receivables Agreement. The Receivables Agreement terminates on December 30, 2016.

Consideration for the receivables sold is equivalent to the carrying value of the receivables less a discount for credit risk. The difference between the carrying value of the receivables sold and the cash proceeds received is recognized in “Operating and administrative-affiliate” expense in our consolidated statements of income. For the years ended December 31, 2014 and 2013, the cost stemming from the discount on the receivables sold was not material.

For the years ended December 31, 2014 and 2013, we sold and derecognized receivables of $4,987.0 million and $2,241.5 million, respectively. For the years ended December 31, 2014 and 2013, the cash proceeds were $4,985.7 million and $2,235.7 million, respectively, which was remitted to us through our centralized treasury system. As of December 31, 2014 and 2013, $378.0 million and $380.1 million, respectively, of the receivables were outstanding and had not been collected on behalf of the Enbridge subsidiary.

As of December 31, 2014, and December 31, 2013, we had $71.9 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 December 31, 2014.

Line 6A and 6B Expense Reimbursement

For the years ended December 31, 2014, 2013 and 2012, we have reimbursed Enbridge $0.4 million, $0.5 million and $4.1 million, respectively, for its assistance with the administration and clean-up efforts for our Line 6A and 6B crude oil releases. For further details related to our Line 6A and 6B crude oil releases, refer to Note 13. Commitments and Contingencies—Lakehead Lines 6A and 6B Crude Oil Releases.

Affiliate Revenues and Purchases

We purchase natural gas from third-parties, which subsequently generates operating revenues from sales to Enbridge and its affiliates. These transactions are entered into at the market price on the date of sale and are presented in “Commodity sales - affiliate” on our Consolidated Statements of Income. We also record operating revenues in our Liquids segment for storage, transportation and terminaling services we provide to affiliates, which are presented in “Transportation and other services – affiliate” on our Consolidated Statements of Income.

We also purchase natural gas from Enbridge and its affiliates for sale to third-parties at market prices on the date of purchase. Included in our results for the years ended December 31, 2014, 2013 and 2012, are costs for natural gas purchases of $119.2 million, $119.5 million and $287.9 million, respectively, related to these purchases. Purchases of natural gas, NGLs, and crude oil from Enbridge and its affiliates are presented in “Commodity costs - affiliate” on our consolidated statements of income.

Facilities Cost Reimbursement Agreement

In 2007, we entered into an agreement with Enbridge Pipelines to install and operate certain sampling and related facilities for the purpose of improving the quality of crude oil and the transportation services on our Lakehead system, which directly increases the transportation services revenue of Enbridge Pipelines. As compensation for installing and operating these transportation facilities, Enbridge Pipelines makes annual payments to us on a cost of service basis. The income we recorded for providing these transportation services in 2014, 2013 and 2012 was approximately $0.8 million, $0.8 million and $0.8 million, respectively.

General Partner Equity Transactions

Our General Partner owns an effective 2% general partner interest in us. Pursuant to our partnership agreement we paid cash distributions to our General Partner of $79.5 million, $139.3 million and $122.3 million for the years ended December 31, 2014, 2013 and 2012, respectively. The cash distributions we make to our General Partner exclude an amount equal to 2% of the i-units, which we retain from the General Partner to maintain its 2% general partner interest in us.

As of December 31, 2014, and 2013, our General Partner owned 46,518,336 Class A common units, representing a 10.4% and 12.3% limited partner voting interest in us for the respective years. We paid the General Partner cash distributions of $102.2 million, $101.1 million and $100.1 million for the years ended December 31, 2014, 2013 and 2012, respectively, with respect to its ownership of Class A common units.

As of December 31, 2014, and 2013, our General Partner also owned 7,825,500 Class B common units, representing a 1.7% and 2.1% limited partner voting interest in us for the respective years. We paid the General Partner cash distributions of $17.2 million, $17.0 million and $16.8 million for the years ended December 31, 2014, 2013 and 2012, respectively, with respect to its ownership of Class B common units.

As of December 2014, our General Partner also owned 48,000,000 Series 1 Preferred Units, representing 9.6% and 11.5% of limited partner voting interests in the partnership for December 31, 2014, and 2013, respectively.

The following table presents our issuances of limited partner interests where our General Partner made a contribution to retain its 2% general partner interest:

Issuance Dates

Number of Class A common

Offering Price

Net Proceeds

General

Net Proceeds Including General Partner Contribution

units Issued

per Class A

to the

Partner

common unit (1)

Partnership (2)

Contribution

(in millions, except units and per unit amount)

2012

September

16,100,000

28.64

446.8

9.4

456.2

(1) The offering price per unit listed for the Equity Distribution Agreement, or EDA, issuances is a calculated average unit price for the periods indicated.

(2)Net of underwriters' fees and discounts, commissions and issuance expenses.

Conflicts of Interest

Enbridge Management makes all decisions relating to the management of our business and affairs through a delegation of control agreement with our General Partner and us. Our General Partner owns the voting shares of Enbridge Management and elects all of its directors. Enbridge, through its wholly-owned subsidiary, Enbridge Pipelines, owns all the common stock of our General Partner. Some of our General Partner's directors and officers are also directors and officers of Enbridge and Enbridge Management and have fiduciary duties to manage the business of Enbridge and Enbridge Management in a manner that may not be in the best interests of our unitholders. Certain conflicts of interest could arise as a result of the relationships among Enbridge Management, our General Partner, Enbridge and us. Our partnership agreement and the delegation of control agreement contain provisions that allow Enbridge Management to take into account the interest of all parties in addition to those of our unitholders in resolving conflicts of interest, thereby limiting its fiduciary duties to our unitholders, as well as provisions that may restrict the remedies available to our unitholders for actions taken that might, without such limitations, constitute breaches of fiduciary duty.

Enbridge Management

Pursuant to the delegation of control agreement between Enbridge Management, our General Partner and us, and our partnership agreement, we pay all expenses relating to Enbridge Management. This includes Texas franchise taxes and other capital-based foreign, state and local taxes not otherwise paid or reimbursed pursuant to a tax indemnification agreement between Enbridge and Enbridge Management on behalf of Enbridge Management.

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 593-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 December 31, 2014 and 2013, was $380.6 million and $371.3 million, respectively, which is included on our consolidated statements of financial position in “Other assets, net.” For the year ended December 31, 2014 and 2013, we recognized $13.2 million and $(1.0) million of equity earnings (losses), respectively, in “Other income (expense)” on our consolidated statements of income related to our investment in the system.

For the year ended December 31, 2014 and 2013, we incurred $21.9 million and $3.2 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 year ended December 31, 2012. These expenses are recorded in “Commodity costs – affiliate” on our consolidated statements of income.

Our Natural Gas business has made commitments to transport up to 120,000 bpd of NGLs on the Texas Express NGL system from 2014 to 2022.

Financing Transactions with Affiliates

Distribution from MEP

The following table presents distributions paid by MEP to its public Class A common unitholders and us during the year ended December 31, 2014, representing the noncontrolling interest in MEP.

Distribution

Amount Paid to

Amount Paid to the

Total MEP

Declaration Date

Payment Date

EEP

noncontrolling interest

Distribution

(in millions)

30-Oct-14

14-Nov-14

8.4

7.2

15.6

31-Jul-14

14-Aug-14

8.1

6.9

29-Apr-14

15-May-14

7.8

6.6

14.4

29-Jan-14

14-Feb-14

4.2

3.5

7.7

28.5

24.2

52.7

Joint Funding Arrangement for Alberta Clipper Pipeline

In July 2009, we entered into a joint funding arrangement to finance the construction of the United States segment of the Alberta Clipper Pipeline with several of our affiliates and affiliates of Enbridge, which we refer to as the Series AC. As part of the joint funding arrangement, we have borrowings outstanding and payable to our General Partner under a promissory note, which we refer to as the A1 Term Note. The A1 Term Note bears interest at a fixed rate of 5.20% and has a maximum loan amount of $400.0 million. Pursuant to the terms of the A1 Term Note, we are required to make semi-annual payments of principal and accrued interest. The semi-annual principal payments are based upon a straight-line amortization of the principal balance over a 30 year period as set forth in the approved terms of the cost of service recovery model associated with the Alberta Clipper Pipeline, with the unpaid balance due in 2020. The A1 Term Note has recourse only to the assets of the United States portion of the Alberta Clipper Pipeline and is subordinate to all of our senior indebtedness.

A summary of the cash activity for the A1 Term Note for the years ended December 31, 2014, 2013 and 2012, are as follows:

A1 Term

Note

(in millions)

Balance at December 31, 2012

330

Repayments

(12.0

)

Balance at December 31, 2013

318

Repayments

(12.0

)

Balance at December 31, 2014

306

We incurred interest expense under the A1 Term Note of $24.3 million, $25.2, and $26.2 million for the years ended December 31, 2014, 2013 and 2012, respectively. We have presented the amounts in “Interest expense, net” on our consolidated statements of income.

On January 2, 2015, we completed a transaction pursuant to which the General Partner and its affiliates contributed to us the remaining 66.7% interest in the U.S. segment of the Alberta Clipper Pipeline in exchange for approximately 18,114,975 units of a new class of limited partner interests designated as Class E units with an aggregate value of $694.0 million. As part of this transaction, we repaid the borrowings outstanding of $306.0 million on the A1 Term Note. See Note 21. Subsequent Events for more information about this transaction.

Distribution to Series AC Interests

The following table presents distributions paid by the OLP to our General Partner and its affiliate during the years ended December 31, 2014, 2013 and 2012, 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

Amount Paid to

Amount Paid to the

Total Series AC

Declaration Date

Payment Date

Partnership

noncontrolling interest

Distribution

(in millions)

2014

31-Oct

14-Nov

10.1

20.3

30.4

31-Jul

14-Aug

7.4

14.8

22.2

30-Apr

15-May

6.6

13.1

19.7

30-Jan

14-Feb

6.4

12.8

19.2

30.5

91.5

2013

31-Oct

14-Nov

14.1

21.1

29-Jul

14-Aug

5.5

16.5

30-Apr

15-May

7.5

14.9

22.4

30-Jan

14-Feb

6.9

13.8

20.7

26.9

53.8

80.7

2012

31-Oct

14-Nov

6.5

12.9

19.4

30-Jul

14-Aug

7.2

14.4

21.6

30-Apr

15-May

8.4

16.8

25.2

30-Jan

14-Feb

7.9

15.8

23.7

59.9

89.9

Joint Funding Arrangement for Eastern Access Projects

In May 2012, we amended and restated partnership agreement of the OLP to establish an additional 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 United States 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. From May 2012 through June 27, 2013, our General Partner indirectly owned 60% all assets, liabilities and operations related to the Eastern Access Projects.

On June 28, 2013, we and our affiliates entered into an agreement with our General Partner pursuant to which we exercised our option to decrease our economic interest and funding of the Eastern Access Projects from 40% to 25%. Additionally, within one year of the in-service date, scheduled for early 2016, we have the option to increase our economic interest by up to 15 percentage points. We received $90.2 million from our General Partner in consideration for our assignment to it of this portion of our interest, determined based on the capital we had funded prior to June 28, 2013 pursuant to Eastern Access Projects. Our General Partner now owns 75% of the EA interests, and the Eastern Access Projects are jointly funded by our General Partner at 75% and us at 25%.

Our General Partner made equity contributions totaling $622.5 million and $609.2 million to the OLP for the years ended December 31, 2014 and 2013, respectively to fund its equity portion of the construction costs associated with the Eastern Access Projects.

Distribution to Series EA Interests

The following table presents distributions paid by the OLP to our General Partner and its affiliate during the year ended December 31, 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

Amount Paid to

Amount Paid to the

Total Series EA

Declaration Date

Payment Date

EEP

noncontrolling interest

Distribution

(in millions)

31-Oct-14

14-Nov-14

14.6

43.7

58.3

31-Jul-14

14-Aug-14

5.6

16.7

22.3

29-Apr-14

15-May-14

2.5

6.5

22.7

66.9

89.6

Joint Funding Arrangement for U.S. Mainline Expansion Projects

In December 2012, the OLP further amended and restated its limited partnership agreement to establish another 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. From December 2012 through June 27, 2013, the projects were jointly funded by our General Partner at 60% and the Partnership at 40%, under the Mainline Expansion Joint Funding Agreement, which parallels the Eastern Access Joint Funding Agreement.

On June 28, 2013, we and our affiliates entered into an agreement with our General Partner pursuant to which we exercised our option to decrease our economic interest and funding in the projects from 40% to 25%. Additionally, within one year of the in-service date, currently scheduled for 2016, we have the option to increase our economic interest held at that time by up to 15 percentage points. All other operations are captured by the Lakehead interests. We received $12.0 million from our General Partner in consideration for our economic interest. Our General Partner now owns 75% of the ME interests, and the U.S. Mainline Expansion Projects are jointly funded by our General Partner at 75% and us at 25%.

Our General Partner has made equity contributions totaling $577.5 million and $159.9 million to the OLP for the years ended December 31, 2014 and 2013, respectively to fund its equity portion of the construction costs associated with the U.S. Mainline Expansion Projects.

Distribution to Series ME Interests

The following table presents distributions paid by the OLP to our General Partner and its affiliate during the year ended December 31, 2014, representing the noncontrolling interest in the Series ME, and to us, as the holders of the Series ME 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 ME interests.

Distribution

Amount Paid to

Amount Paid to the

Total Series EA

Declaration Date

Payment Date

EEP

noncontrolling interest

Distribution

(in millions)

31-Oct-14

14-Nov-14

0.6

1.9

2.5

Noncontrolling Interests

The following table presents the components of net income attributable to noncontrolling interests as presented on our Consolidated Statements of Income:

For the year ended December 31

2014

2013

2012

(in millions)

Alberta Clipper Interests

54.6

52.6

53.9

Eastern Access Interests

145.3

32.1

3.4

U.S. Mainline Expansion Interests

33.8

4.3

(0.3

)

Midcoast Energy Partners, L.P.

29.6

(0.7

)

Total

263.3

88.3

Midcoast Energy Partners, L.P.

On November 13, 2013, MEP completed its initial public offering of Class A common units, representing limited partner interests in MEP. On the same date, in connection with the closing of that offering, certain transactions, among others, occurred pursuant to which we effectively conveyed to MEP all of our limited liability company interests in the general partner of the operating subsidiary of MEP, or Midcoast Operating and a 39% limited partner interest in Midcoast Operating, in exchange for certain MEP Class A common units and MEP Subordinated Units, approximately $304.5 million in cash as reimbursement for certain capital expenditures with respect to the contributed businesses, and a right to receive $323.4 million in cash. Also in connection with the closing of that offering, on November 13, 2013, we entered into the following agreements:

Omnibus Agreement

We, Midcoast Holdings, L.L.C., or the MEP General Partner, MEP, and Enbridge, entered in the Omnibus Agreement to which we agreed to indemnify MEP for certain matters, including environmental, right-of-way and permit matters, and we granted MEP a license to use the Enbridge logo and certain other trademarks and tradenames. The Omnibus Agreement may be terminated by the mutual agreement of the parties, or by either Enbridge or MEP in the event that we cease to control the MEP General Partner, provided that our indemnification obligations will remain in full force and effect until they expire in accordance with their respective terms.

Under the Omnibus Agreement, we also agreed to indemnify MEP for all known and certain unknown environmental liabilities that are associated with the ownership or operation of MEP's assets arising prior to the closing of that offering, in each case that are identified prior to the third anniversary of the closing of that offering. Our obligation to indemnify MEP for any environmental liabilities is subject to a $500,000 aggregate deductible before MEP is entitled to indemnification. We will also indemnify MEP for failure to have certain rights-of-way, consents, licenses and permits necessary to own and operate its assets in substantially the same manner in which they were owned and operated prior to the closing of the Offering, including the cost of curing certain such failures that do not allow its assets to be operated in accordance with prudent industry practice, in each case that are identified prior to the third anniversary of the closing of the Offering. Our obligation to indemnify MEP for any right-of-way, consent, license or permit matters will be subject to a $500,000 aggregate deductible before MEP is entitled to indemnification. There will be a $15 million aggregate cap on the amounts for which we will indemnify MEP for environmental, right-of-way, consents, licenses and permit matters under the Omnibus Agreement.

Intercorporate Services Agreement

We entered into an Intercorporate Service Agreement, or the Intercorporate Services Agreement, with MEP, pursuant to which we will provide MEP with the following services:

• executive, management, business development, administrative, legal, human resources, records and information management, public affairs, investor relations, government relations and computer support services;

• accounting and tax planning and compliance services, including preparation of financial statements and income tax returns, unitholder tax reporting and audit and treasury services;

• strategic insurance advice, planning and claims management and related support services, and arrangement of insurance coverage as required;

• facilitation of capital markets access and financing services, cash management and related banking services, financial structuring and advisory services, as well as credit support for MEP's subsidiaries and affiliates on an as-needed basis for projects, transactions or other purposes;

• operational and technical services, including integrity, safety, environmental, project management, engineering, fundamentals analysis and regulatory, and pipeline control and field operations; and

• such other services as MEP may request.

Under the Intercorporate Services Agreement, MEP will reimburse the Partnership and its affiliates for the costs and expenses incurred in providing such services to MEP; however, we have agreed to reduce the amounts payable for general and administrative expenses that otherwise would have been allocable to Midcoast Operating by $25.0 million annually.

Financial Support Agreement

We entered into a Financial Support Agreement with Midcoast Operating, or the Financial Support Agreement, pursuant to which we will provide letters of credit and guarantees, not to exceed $700.0 million in the aggregate at any time outstanding, in support of Midcoast Operating's and its wholly owned subsidiaries' financial obligations under derivative agreements and natural gas and NGL purchase agreements to which Midcoast Operating, or one or more of its wholly owned subsidiaries, is a party. Under the Financial Support Agreement, our support of Midcoast Operating's and its wholly owned subsidiaries' obligations will terminate on the earlier to occur of (1) November 13, 2017, and (2) the date on which EEP owns, directly or indirectly (other than through its ownership interests in MEP), less than 20% of the total outstanding limited partner interests in Midcoast Operating.

The Financial Support Agreement also provides that if MEPs bank credit agreement is secured, the Financial Support Agreement also will be secured to the same extent on a second-lien basis. We also have agreed to subordinate our right to payment on obligations owed under the Financial Support Agreement and Working Capital Credit Facility (defined below) and liens, if secured, to the rights of the lenders under the MEP credit agreement.

Amended and Restated Allocation Agreement

MEP entered into an Amended and Restated Allocation Agreement, or the Insurance Allocation Agreement, by and among MEP, Enbridge, EEP and Enbridge Income Fund Holdings Inc., in order to participate in the comprehensive insurance program that is maintained by Enbridge for it and its subsidiaries. Under the Insurance Allocation Agreement, in the unlikely event that multiple insurable incidents occur that exceed coverage limits within the same insurance period, the total insurance coverage available to Enbridge and its subsidiaries under the insurance program will be allocated among the participating Enbridge entities on an equitable basis.

Working Capital Credit Facility

On November 13, 2013, 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 us, as lender. On October 30, 2014, Midcoast Operating notified us that it was exercising its right to terminate the Working Capital Agreement upon 30-days' notice, and such termination occurred in the fourth quarter of 2014. As of December 31, 2014, there were no outstanding borrowings under the Working Capital Agreement.

COMMITMENTS_AND_CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	12 Months Ended
COMMITMENTS AND CONTINGENCIES	Dec. 31, 2014
COMMITMENTS AND CONTINGENCIES [Abstract]
COMMITMENTS AND CONTINGENCIES	13. 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 December 31, 2014 and 2013, we had $60.1 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 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 December 31, 2014, we made payments of $6.3 million, and we have a remaining estimated liability of $0.7 million.

	Lakehead Lines 6A & 6B Crude Oil Releases

	Line 6B Crude Oil Release

	On July 26, 2010, a release of crude oil on Line 6B of our Lakehead system was reported near Marshall, Michigan. We estimate that approximately 20,000 barrels of crude oil were leaked at the site, a portion of which reached the Talmadge Creek, a waterway that feeds the Kalamazoo River. The released crude oil affected approximately 38 miles of shoreline along the Talmadge Creek and Kalamazoo River waterways, including residential areas, businesses, farmland and marshland between Marshall and downstream of Battle Creek, Michigan. In response to the release, a unified command structure was established under the jurisdiction of the EPA, the Michigan Department of Natural Resources and Environment, or MDNRE, and other federal, state and local agencies.

	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 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.

	As of December 31, 2014, regulatory authority has transferred from the EPA to the Michigan Department of Environmental Quality, or MDEQ. We are now working with the MDEQ who has oversight over 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 December 31, 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. The total cost increase of $85.9 million during the year ended December 31, 2014, is primarily related to the MDEQ approved Schedule of Work, completion of the dredge activities near Ceresco and Morrow Lake, and 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 December 31, 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 years ended December 31, 2014, 2013 and 2012, we made payments of $141.4 million, $156.3 million and $134.0 million, for costs associated with the Line 6B crude oil release. For the years ended December 31, 2014 and 2013, we had a remaining estimated liability of $195.2 million and $258.9 million, respectively. Additionally, we recognized $42.0 million and $170.0 million, respectively, of insurance recoveries in our consolidated statements of income for the years ended, 2013 and 2012, respectively. We did not recognize any insurance recoveries for the year ended December 31, 2014.

	Line 6A Crude Oil Release

	A release of crude oil from Line 6A of our Lakehead system was reported in an industrial area of Romeoville, Illinois on September 9, 2010. We estimate that approximately 9,000 barrels of crude oil were released, of which approximately 1,400 barrels were removed from the pipeline as part of the repair. Some of the released crude oil went onto a roadway, into a storm sewer, a waste water treatment facility and then into a nearby retention pond. All but a small amount of the crude oil was recovered. We completed excavation and replacement of the pipeline segment and returned it to service on September 17, 2010.

	We are continuing to monitor the areas affected by the crude oil release from Line 6A of our Lakehead system for any additional requirements. We have completed the cleanup, remediation and restoration of the areas affected by the release. On October 21, 2013, the National Transportation Safety Board, or NTSB, publicly posted their final report related to the Line 6A crude oil release that occurred in Romeoville, Illinois on September 9, 2010, which states that the probable cause of the crude oil release was erosion caused by a leaking water pipe resulting from an improperly installed third-party water service line below our oil pipeline.

	In connection with this crude oil release, the total cost estimate as of December 31, 2014 is approximately $51.0 million, before insurance recoveries and excluding fines and penalties, which is an increase of $3.0 million as compared to December 31, 2013. These costs included the emergency response, environmental remediation and cleanup activities associated with the crude oil release. For the years ended 2013 and 2012, we paid $1.5 million and $1.2 million, respectively, related to the costs on the Line 6A release, with no such costs paid in 2014. For the year ended December 31, 2014 our remaining estimated liability was $3.0 million, we adjusted our liability primarily due to additional legal expenses. At December 31, 2013, we had no estimated liability.

	We continue to monitor this estimate based upon actual invoices received and paid, to determine if our estimate should be updated. We have the potential of incurring additional costs in connection with this crude oil release, including fines and penalties as well as expenditures associated with litigation.

	We included those costs we considered probable and that we could reasonably estimate for purposes of determining our expected losses associated with the Line 6A release. Our estimates do not include consideration for any unasserted claims associated with the release that may later become evident, nor have we considered any potential recoveries from third-parties that may later be determined to have contributed to the release.

	Lines 6A & 6B Fines and Penalties

	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 December 31, 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 December 31, 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 further measures directed toward enhancing spill prevention, leak detection, and emergency response to environmental events. 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 for Enbridge and its affiliates. Including our remediation spending through December 31, 2014, costs related to Line 6B have exceeded the limits of the coverage available under this insurance policy. As of December 31, 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 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, 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.

Lakehead Line 14 Crude Oil Release

On July 27, 2012, a release of crude oil was detected on Line 14 of our Lakehead system near Grand Marsh, Wisconsin. The estimate of volume of the oil released was approximately 1,700 barrels. We received a CAO, from PHMSA, on July 30, 2012 followed by an amended CAO, which we refer to as the PHMSA Corrective Action Orders, on August 1, 2012. Upon restart of Line 14 on August 7, 2012, PHMSA restricted the operating pressure to 80% of the pressure in place at the time immediately prior to the incident. During the fourth quarter of 2013 we received approval from the PHMSA to remove the pressure restrictions and to return to normal operating pressures for a period of twelve months. In December 2014, PHMSA again considered the status of the pipeline in light of information they acquired throughout 2014. On December 9, 2014, we received a letter from PHMSA approving our request to continue the normal operation of Line 14 without pressure restrictions.

The total estimated costs for repair and remediation associated with this crude oil release were approximately $10.5 million, inclusive of approximately $1.6 million of lost revenue and excluding any fines and penalties. There was no remaining liability as of December 31, 2014. Despite the efforts we have made to ensure the reasonableness of our estimate, changes to the estimated amounts associated with this release are possible as more reliable information becomes available. We will be pursuing claims under our insurance policy, although we do not expect any recoveries to be significant.

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 7 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 the 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.

On July 25, 2013, the United States Department of Justice, or DOJ, and the EPA filed a complaint against us related to permit violations for the discharge of hydrotest water in 2010 related to the Alberta Clipper Pipeline and one of our affiliates. We have agreed to settle with the DOJ and EPA for $254 thousand related to the Alberta Clipper Pipeline portion of the permit violation.

Oil and Gas in Custody

Our Liquids assets transport crude oil and NGLs owned by our customers for a fee. The volume of liquid hydrocarbons in our pipeline systems at any one time varies from approximately 29.0 million to 61.0 million barrels, virtually all of which is owned by our customers. Under the terms of our tariffs, losses of crude oil from identifiable incidents not resulting from our direct negligence may be apportioned among our customers. In addition, we maintain adequate property insurance coverage with respect to crude oil and NGLs in our custody.

Approximately 40% of the natural gas volumes on our Natural Gas assets are transported for customers on a contractual basis. We purchase the remaining volumes and sell to third parties downstream of the purchase point. At any point in time, the value of our customers' natural gas in the custody of our Natural Gas systems is not significant to our operating results, cash flows, or financial position.

Rights-of-Way

As part of our pipeline construction process, we must obtain certain rights-of-way from landowners whose property the pipeline will cross. Rights-of-way that we buy are capitalized as part of “Property, plant and equipment, net” in our consolidated statements of financial position. Rights-of-way that we lease are expensed. We have recorded expenses of $3.6 million, $2.3 million and $2.7 million for the leased right-of-way agreements for the years ended December 31, 2014, 2013 and 2012, respectively.



Future Minimum Commitments


As of December 31, 2014, our future minimum commitments that have remaining non-cancelable terms in excess of one year are as follows:




		2015			2016		2017		2018		2019		Thereafter		Total
		(in millions)
Purchase commitments⁽¹⁾		$	1,012.70		$	—	$	—	$	—	$	—	$	—	$	1,012.70
Power commitments⁽²⁾			14.8			9.2		6.3		3.8		1.5		—		35.6
Other operating leases			25.6			23.5		21.9		15.2		14.8		342.3		443.3
Right-of-way			2.3			2.1		1.7		1.6		1.5		33.7		42.9
Product purchase obligations⁽³⁾			23.1			8.3		14.7		24.5		25.5		112.5		208.6
Transportation/Service contract obligations⁽⁴⁾			63.3			58.3		99.5		109.1		113.8		403.5		847.5
Fractionation agreement obligations⁽⁵⁾			70.1			70.1		70.1		70.1		70.1		235		585.5

Total		$	1,211.90		$	171.5	$	214.2	$	224.3	$	227.2	$	1,127.00	$	3,176.10


(1)	Represents commitments to purchase materials, primarily pipe from third-party suppliers in connection with our growth projects.

(2)	Represents commitments to purchase power in connection with our Liquids segment.

-3	We have long-term product purchase obligations with several third-party suppliers to acquire natural gas and NGLs at the approximate market value at the time of delivery.

-4	The service contract obligations represent the minimum payment amounts for firm transportation and storage capacity we have reserved on third-party pipelines and storage facilities.

-5	The fractionation agreement obligations represent the minimum payment amounts for firm fractionation of our NGL supply that we reserve at third party fractionation facilities.

The purchases made under our non-cancelable commitments for the years ended December 31, 2014, 2013 and 2012 were $1.9 billion, $590.7 million and $276.7 million, respectively.

The consolidated operating expenses include lease and rental expense amounts of $18.2 million, $25.0 million and $27.7 million during the years ended December 31, 2014, 2013 and 2012, respectively.

DERIVATIVE_FINANCIAL_INSTRUMEN

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES	12 Months Ended
DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES	Dec. 31, 2014
DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES [Abstract]
DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES	14. 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 and fractionation margins. Fractionation margins represent the relative difference between the price we receive from NGL and condensate sales and the corresponding commodity costs of natural gas and natural gas liquids 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 the variability in future cash flows associated with the risks discussed above through 2019 in accordance with our risk management policies.

	Derivative Positions
	Our derivative financial instruments are included at their fair values in the consolidated statements of financial position as follows:


			December 31,
			2014				2013
			(in millions)
	Other current assets		$	185.5			$	21.2
	Other assets, net			93.3				74.4
	Accounts payable and other⁽¹⁾			(315.4	)			(172.0	)
	Other long-term liabilities			(124.6	)			(12.3	)
	Due from general partner and affiliates			0.3				—

			$	(160.9	)		$	(88.7	)


	(1)	Includes $28.4 million of cash collateral at December 31, 2014, and $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.
	Also included in AOCI are unrecognized losses of approximately $28.4 million associated with derivative financial instruments that qualified for and were classified as cash flow hedges of forecasted transactions that were subsequently de-designated. These losses are reclassified to earnings over the periods during which the originally hedged forecasted transactions affect earnings. During the years ended December 31, 2014 and 2013, unrealized commodity hedge losses of $0.2 million and gains of $1.7 million, respectively, were de-designated as a result of the hedges no longer meeting hedge accounting criteria. We estimate that approximately $219.9 million, representing unrealized net losses from our cash flow hedging activities based on pricing and positions at December 31, 2014, will be reclassified from AOCI to earnings during the next 12 months.
	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 year ended December 31, 2014, we recognized in interest expense unrealized losses for hedge ineffectiveness of approximately $100.6 million associated with interest rate hedges that were originally set to mature in 2014 and 2016.
	During the first quarter 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 met the cash flow hedging requirements. These terminations resulted in realized losses of $0.8 million for the year ended December 31, 2013.
	During the year ended December 31, 2013 it was determined that a portion of forecasted short term debt transactions were not expected to occur, due to changing funding requirements. Since we required 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 met the cash flow hedging requirements. These terminations resulted in realized losses of $5.3 million of additional interest expense for the year ended December 31, 2013.

	The year ended December 31, 2013 also includes unrealized losses from reductions to AOCI for hedge ineffectiveness of approximately $29.6 million associated with interest rate hedges that were originally set to mature in December 2013. However, in November 2013, these hedges were amended to extend the maturity date to December 2014 to better reflect the expected timing of future debt issuances.
	The year ended December 31, 2012 also includes unrealized losses from reductions to AOCI for hedge ineffectiveness of approximately $20.8 million associated with interest rate hedges that were originally set to mature in December 2012. However, in December 2012, these hedges were amended to extend the maturity date to December 2013 to better reflect the expected timing of future debt issuances.
	The table below summarizes our derivative balances by counterparty credit quality (negative amounts represent our net obligations to pay the counterparty).


			December 31,
			2014				2013
			(in millions)
	Counterparty Credit Quality⁽¹⁾
	AAA		$	0.1			$	0.3
	AA⁽²⁾			(49.8	)			(49.7	)
	A⁽³⁾			(129.1	)			(40.1	)
	Lower than A			17.9				0.8

			$	(160.9)			$	(88.7)


	(1)	As determined by nationally-recognized statistical ratings organizations.

	(2)	Includes $28.4 million of cash collateral at December 31, 2014.

	(3)	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 interest rates, our outstanding financial exposure to third parties has also decreased. When credit thresholds are met pursuant to the terms of our ISDA^®, financial contracts, we have the right to require collateral from our counterparties. We include any cash collateral received in the balances listed above. As of December 31, 2014 we are holding $28.4 million in cash collateral on our asset exposures. As of December 31, 2013, we held $16.7 million in cash collateral on our asset exposures. Cash collateral is classified as “Restricted cash” in our consolidated statements of financial position. When we are in a position of posting collateral to cover our counterparties' exposure to our non-performance, the collateral is provided through letters of credit, which are not reflected above.
	The ISDA^® agreements and associated credit support, which govern our financial derivative transactions, contain no credit rating downgrade triggers that would accelerate the maturity dates of our outstanding transactions. A change in ratings is not an event of default under these instruments, and the maintenance of a specific minimum credit rating is not a condition to transacting under the ISDA^® agreements. In the event of a credit downgrade, additional collateral may be required to be posted under the agreement if we are in a liability position to our counterparty, but the agreement will not automatically terminate and require immediate settlement of all future amounts due.
	The ISDA^® agreements, in combination with our master netting agreements, and credit arrangements governing our interest rate and commodity swaps require that collateral be posted per tiered contractual thresholds based on the credit rating of each counterparty. We generally provide letters of credit to satisfy such collateral requirements under our ISDA^® agreements. These agreements will require additional collateral postings of up to 100% on net liability positions in the event of a credit downgrade below investment grade. Automatic termination clauses which exist are related only to non-performance activities, such as the refusal to post collateral when contractually required to do so. When we are holding an asset position, our counterparties are likewise required to post collateral on their liability (our asset) exposures, also determined by tiered contractual collateral thresholds. Counterparty collateral may consist of cash or letters of credit, both of which must be fulfilled with immediately available funds.
	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 December 31, 2014 we would have been required to provide additional letters of credit in the amount of $50.6 million.
	At December 31, 2014 and 2013, we had credit concentrations in the following industry sectors, as presented below:


			December 31,
			2014				2013
			(in millions)
	United States financial institutions and investment banking entities⁽¹⁾		$	(147.1	)		$	(85.0	)
	Non-United States financial institutions⁽²⁾			(54.2	)			0.8
	Other			40.4				(4.5	)

			$	(160.9)			$	(88.7)


-1	Includes $28.4 million of cash collateral at December 31, 2014.

-2	Includes $16.7 million of cash collateral at December 31, 2013.

As of December 31, 2014, we have provided letters of credit totaling $329.6 million and $76.1 million relating to our liability exposures pursuant to the margin thresholds in effect at December 31, 2014 and 2013, respectively, under our ISDA^® agreements
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 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
		Financial Position		Fair Value at								Fair Value at
		Location		December 31,								December 31,
				2014				2013⁽³⁾				2014				2013⁽³⁾
				(in millions)
Derivatives designated as hedging instruments⁽¹⁾
Interest rate contracts		Other current assets		$	—			$	8.1			$	—			$	—
Interest rate contracts		Other assets			—				57.1				—				—
Interest rate contracts		Accounts payable and other⁽²⁾			—				11.9				(241.0	)			(145.5	)
Interest rate contracts		Other long-term liabilities			—				—				(102.0	)			(11.3	)
Commodity contracts		Other current assets			26.1				2				—				(0.6	)
Commodity contracts		Other assets			2.1				3.5				—				(0.5	)
Commodity contracts		Accounts payable and other			—				1.9				—				(12.7	)
Commodity contracts		Other long-term liabilities			—				0.6				—				(1.4	)

					28.2				85.1				(343.0	)			(172.0	)

Derivatives not designated as hedging instruments
Commodity contracts		Other current assets			159.4				11.8				—				(0.1	)
Commodity contracts		Other assets			91.2				17.6				—				(3.3	)
Commodity contracts		Accounts payable and other⁽²⁾			—				5.4				(46.0	)			(16.3	)
Commodity contracts		Other long-term liabilities			—				—				(22.6	)			(0.2	)
Commodity contracts		Due from general partner and affiliates			0.3				—				—				—

					250.9				34.8				(68.6	)			(19.9	)

Total derivative instruments				$	279.1			$	119.9			$	(411.6	)		$	(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 $28.4 and $16.7 million of cash collateral at December 31, 2014 and 2013, respectively.

(3)	The effect of derivative instruments on the consolidated statements of financial position, as of December 31, 2013, was revised to disclose the financial position location on a gross basis. The revisions to the disclosures are not considered material to and had no impact on amounts previously reported in the consolidated statements of financial position.


Effect of Derivative Instruments on the Consolidated Statements of Income and Accumulated Other Comprehensive Income



Derivatives in Cash Flow		Amount of Gain				Location of Gain		Amount of Gain (Loss)				Location of Gain		Amount of Gain
Hedging Relationships		(Loss) Recognized in				(Loss) Reclassified		Reclassified from				(Loss) Recognized in		(Loss) Recognized in
		AOCI on Derivative				from AOCI to		AOCI to Earnings				Earnings on Derivative		Earnings on
		(Effective Portion)				Earnings		(Effective Portion)				(Ineffective Portion and		Derivative
						(Effective Portion)						Amount Excluded from		(Ineffective Portion
												Effectiveness Testing)⁽¹⁾		and Amount
														Excluded from
														Effectiveness
														Testing)⁽¹⁾
(in millions)
For the year ended December 31, 2014
Interest rate contracts		$	(163.4	)		Interest expense		$	(16.2	)		Interest expense		$	(100.1	)
Commodity contracts			29.9			Commodity costs			(5.8	)		Commodity costs			5.6

Total		$	(133.5	)				$	(22.0	)				$	(94.5	)

For the year ended December 31, 2013
Interest rate contracts		$	251			Interest expense		$	(29.8	)		Interest expense		$	(21.5	)
Commodity contracts			(16.5	)		Commodity costs			2.7			Commodity costs			3.3

Total		$	234.5					$	(27.1	)				$	(18.2	)

For the year ended December 31, 2012
Interest rate contracts		$	(45.4	)		Interest expense		$	(28.9	)		Interest expense		$	(20.5	)
Commodity contracts			41.8			Commodity costs			0.1			Commodity costs			3.1

Total		$	(3.6	)				$	(28.8	)				$	(17.4	)


(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⁾			(155.9	)
Amounts reclassified from AOCI⁽²⁾⁽³⁾			21.2
Tax benefit (expense)			(0.1	)

Net other comprehensive income		$	(134.8	)

Balance at December 31, 2014		$	(211.4	)


-1	Excludes NCI gain of $6.3 million reclassified from AOCI at December 31, 2014.

-2	Excludes NCI gain of $0.8 million reclassified from AOCI at December 31, 2014.

-3	For additional details on the amounts reclassified from AOCI, reference the Reclassifications from Accumulated Other Comprehensive Income table below.


Reclassifications from Accumulated Other Comprehensive Income


		For the year ended December 31,
		2014				2013				2012
		(in millions)
Losses (gains) on cash flow hedges:
Interest Rate Contracts⁽¹⁾		$	16.2			$	29.8			$	28.9
Commodity Contracts⁽²⁾⁽³⁾			5				(2.7	)			(0.1	)

Total Reclassifications from AOCI		$	21.2			$	27.1			$	28.8


(1)	Loss (gain) reported within “Interest expense” in the Consolidated Statements of Income.

(2)	Loss (gain) reported within “Commodity costs” in the Consolidated Statements of Income.

(3)	Excludes NCI gain of $0.8 million year ending December 31, 2014.
Effect of Derivative Instruments on Consolidated Statements of Income



				December 31,
				2014				2013				2012⁽⁶⁾
Derivatives Not Designated as Hedging Instruments		Location of Gain (Loss)		Amount of Gain (Loss)
Derivatives Not Designated as Hedging Instruments		Recognized in Earnings⁽¹⁾		Recognized in Earnings⁽²⁾
				(in millions)
Interest rate contracts		Interest expense⁽³⁾		$	—			$	—			$	—
Commodity contracts		Transportation and other services			17.4				(3.0	)			—
Commodity contracts		Commodity sales⁽⁴⁾			23.7				(3.0	)			7.4
Commodity contracts		Commodity sales—affiliate			0.3				—				—
Commodity contracts		Power			0.7				0.6				0.1
Commodity contracts		Commodity costs⁽⁵⁾			136.8				(8.0	)			19.5

Total				$	178.9			$	(13.4	)		$	27.0


(1)	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.

(2)	Does not include settlements associated with derivative instruments that settle through physical delivery.

(3)	Includes settlement gains of $0 million, $0.2 million, and $0.5 million for the years ended December 31, 2014, 2013 and 2012, respectively.

(4)	Includes settlement gains of $4.5 million, $1.4 million, and $6.2 million for the years ended December 31, 2014, 2013 and 2012, respectively.

(5)	Includes settlement gains (losses) of $8.0 million and ($4.6) million and $21.4 million for the years ended December 31, 2014, December 31, 2013, and December 31, 2012, respectively.

(6)	The effects of derivatives instruments on consolidated statements of income have been revised to include settlement gains on derivatives not designated as hedge instruments of $28.1 million for the year ended December 31, 2012.

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 December 31, 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⁽¹⁾
		(in millions)
Description:
Derivatives		$	279.1			$	—			$	279.1			$	(91.8	)		$	187.3

Total		$	279.1			$	—			$	279.1			$	(91.8	)		$	187.3



		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⁽¹⁾
		(in millions)
Description:
Derivatives		$	119.9			$	(24.3	)		$	95.6			$	(18.6)			$	77.0

Total		$	119.9			$	(24.3	)		$	95.6			$	-18.6			$	77


-1	Includes $28.4 million and $16.7 million of cash collateral at December 31, 2014 and December 31, 2013, respectively.
Offsetting of Financial Liabilities and Derivative Liabilities


		As of December 31, 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⁽¹⁾
		(in millions)
Description:
Derivatives		$	(440.0	)		$	—			$	(440.0	)		$	91.8			$	(348.2	)

Total		$	(440.0	)		$	—			$	(440.0	)		$	91.8			$	(348.2	)



		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⁽¹⁾
		(in millions)
Description:
Derivatives		$	(208.6	)		$	24.3			$	(184.3	)		$	18.6			$	(165.7	)

Total		$	(208.6	)		$	24.3			$	(184.3	)		$	18.6			$	(165.7	)


(1)	Includes $28.4 million and $16.7 million of cash collateral at December 31, 2014 and December 31, 2013, respectively.


Inputs to Fair Value Derivative Instruments



The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2014 and 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.


		31-Dec-14																				31-Dec-13
		Level 1				Level 2				Level 3				Collateral				Total				Level 1				Level 2				Level 3			Collateral			Total
		(in millions)
Interest rate contracts⁽¹⁾		$	—			$	(343.0	)		$	—			$	—			$	(343.0	)		$	—			$	(79.7	)		$	—		$	—		$	(79.7	)
Commodity contracts:
Financial			—				41.6				42.7				—				84.3				—				6.4				(6.9	)		—			(0.5	)
Physical			—				—				19.5				—				19.5				—				—				(0.2	)		—			(0.2	)
Commodity options			—				—				106.7				—				106.7				—				—				8.4			—			8.4

			—				(301.4	)			168.9				—				(132.5	)			—				(73.3	)			1.3			—			(72.0	)

Cash Collateral			—				—				—				(28.4	)			(28.4	)			—				—				—			(16.7	)		(16.7	)

Total		$	—			$	(301.4	)		$	168.9			$	(28.4	)		$	(160.9	)		$	—			$	(73.3	)		$	1.3		$	(16.7	)	$	(88.7	)


(1)	Amounts have been revised to exclude $16.7 million of cash collateral at December 31, 2013.

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



Contract Type		Fair Value at				Valuation		Unobservable		Range⁽¹⁾
		December 31,				Technique		Input		Range⁽¹⁾
		2014⁽²⁾								Lowest				Highest				Weighted				Units
										Lowest				Highest				Average				Units
		(in millions)
Commodity Contracts—
Financial
Natural Gas		$	0.6			Market Approach		Forward Gas Price			2.55				3.72				3.04			MMBtu
NGLs			42.1			Market Approach		Forward NGL Price			0.48				1.14				0.64			Gal
Commodity Contracts—
Physical
Natural Gas			1.5			Market Approach		Forward Gas Price			1.55				4.08				3.08			MMBtu
Crude Oil			(0.9	)		Market Approach		Forward Crude Price			49.57				55.6				53.51			Bbl
NGLs			18.9			Market Approach		Forward NGL Price			0.06				1.21				0.54			Gal
Commodity Options
Natural Gas, Crude and NGLs			106.7			Option Model		Option Volatility			19%				94%				36%

Total Fair Value		$	168.9


-1	Prices are in dollars per MMBtu for Natural Gas, Gal for NGLs, Bbl for Crude Oil and MWh for Power.

-2	Fair values are presented in millions of dollars and include credit valuation adjustments of approximately $1.0 million of losses.


Quantitative Information About Level 3 Fair Value Measurements



Contract Type		Fair Value at				Valuation		Unobservable		Range⁽¹⁾
		December 31,				Technique		Input		Range⁽¹⁾
		2013⁽²⁾								Lowest				Highest				Weighted				Units
										Lowest				Highest				Average				Units
		(in millions)
Commodity Contracts—
Financial
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 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 MMBtu for Natural Gas, Gal for NGLs, Bbl for Crude Oil and MWh for Power.
(2)	Fair values are presented in millions and 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 December 31, 2014. No transfers of assets between any of the Levels occurred during the period.



		Commodity				Commodity				Commodity				Total
		Financial				Physical				Options
		Contracts				Contracts
		(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			30.2				48.6				101.7				180.5
Included in other comprehensive income			16.9				—				—				16.9
Purchases, issuances, sales and settlements
Purchases			—				—				0.7				0.7
Sales			—				—				(2.1	)			(2.1	)
Settlements⁽²⁾			2.5				(28.9	)			(2.0	)			(28.4	)

Ending balance as of December 31, 2014		$	42.7			$	19.5			$	106.7			$	168.9

Amount of changes in net assets attributable to the change in derivative gains or losses related to assets still held at the reporting date		$	42.2			$	19			$	100.4			$	161.6

Amounts reported in commodity sales		$	—			$	24			$	—			$	24


(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 December 31, 2014 and 2013.


		At December 31, 2014																						At December 31, 2013
		Commodity		Notional⁽¹⁾				Wtd. Average Price⁽²⁾								Fair Value⁽³⁾								Fair Value⁽³⁾
		Commodity		Notional⁽¹⁾				Receive				Pay				Asset				Liability				Asset				Liability
Portion of contracts maturing in 2015
Swaps
Receive variable/pay fixed		Natural Gas			896,915			$	2.94			$	3.67			$	—			$	(0.7	)		$	—			$	—
		NGL			225,850			$	35.24			$	65.37			$	—			$	(6.8	)		$	—			$	—
		Crude Oil			912,250			$	56.73			$	86.82			$	—			$	(27.4	)		$	—			$	—
Receive fixed/pay variable		Natural Gas			3,645,440			$	3.95			$	2.93			$	3.7			$	—			$	—			$	—
		NGL			1,980,850			$	46.91			$	27.11			$	39.2			$	—			$	1.5			$	(1.1	)
		Crude Oil			1,759,415			$	93.79			$	56.75			$	65.0			$	—			$	8.3			$	—
Receive variable/pay variable		Natural Gas			59,606,800			$	2.89			$	2.89			$	1.5			$	(1.7	)		$	0.1			$	—
Physical Contracts
Receive variable/pay fixed		Natural Gas			232,400			$	3.09			$	2.99			$	—			$	—			$	—			$	—
		NGL			206,300			$	22.54			$	39.95			$	—			$	(3.6	)		$	—			$	—
		Crude Oil			11,300			$	53.44			$	56.27			$	—			$	—			$	—			$	—
Receive fixed/pay variable		Natural Gas			290,114			$	3.02			$	3.18			$	—			$	—			$	—			$	—
		NGL			1,042,921			$	44.6			$	25.58			$	19.8			$	—			$	—			$	—
		Crude Oil			65,000			$	62.46			$	54			$	0.5			$	—			$	—			$	—
Receive variable/pay variable		Natural Gas			148,689,068			$	2.95			$	2.95			$	2.2			$	(1.0	)		$	0.5			$	(0.1	)
		NGL			7,221,805			$	22.68			$	22.3			$	3.7			$	(1.0	)		$	—			$	—
		Crude Oil			558,553			$	50.57			$	53.07			$	0.3			$	(1.7	)		$	—			$	—
Portion of contracts maturing in 2016
Swaps
Receive variable/pay fixed		Natural Gas			181,435			$	3.15			$	3.85			$	—			$	(0.1	)		$	—			$	—
		Crude Oil			415,950			$	62.96			$	82.69			$	—			$	(8.1	)		$	—			$	—
Receive fixed/pay variable		Natural Gas			75,000			$	3.48			$	3.52			$	—			$	—			$	—			$	—
		NGL			823,500			$	39.64			$	28.18			$	9.3			$	—			$	—			$	—
		Crude Oil			415,950			$	85.08			$	62.96			$	9.1			$	—			$	0.7			$	—
Receive variable/pay variable		Natural Gas			20,587,000			$	3.3			$	3.29			$	0.5			$	(0.3	)		$	—			$	—
Physical Contracts
Receive fixed/pay variable		NGL			1,788			$	28.67			$	25.71			$	—			$	—			$	—			$	—
Receive variable/pay variable		Natural Gas			34,834,479			$	3.4			$	3.39			$	0.7			$	(0.4	)		$	0.1			$	—
Portion of contracts maturing in 2017
Swaps
Receive fixed/pay variable		NGL			365,000			$	24.78			$	22.79			$	0.7			$	—			$	—			$	—
		Crude Oil			365,000			$	69.35			$	66.97			$	0.8			$	—			$	—			$	—
Physical Contracts
Receive variable/pay variable		Natural Gas			14,909,743			$	3.77			$	3.76			$	0.2			$	(0.1	)		$	—			$	—
Portion of contracts maturing in 2018
Swaps
Receive variable/pay variable		Natural Gas			900,000			$	4.03			$	4.03			$	—			$	—			$	—			$	—

(1)	Volumes of natural gas are measured in MMBtu, whereas volumes of NGL and crude oil are measured in Bbl.

(2)	Weighted average prices received and paid are in $/MMBtu for natural gas and $/Bbl for NGL and crude oil.

(3)	The fair value is determined based on quoted market prices at December 31, 2014 and 2013 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 $0.5 million of losses and $0.1 million of gains at December 31, 2014 and 2013, respectively, and cash collateral received.




The following table provides summarized information about the fair values of expected cash flows of our outstanding commodity options at December 31, 2014 and 2013.


		At December 31, 2014																						At December 31, 2013
								Strike				Market				Fair Value⁽³⁾								Fair Value
		Commodity		Notional⁽¹⁾				Price⁽²⁾				Price⁽²⁾				Asset				Liability				Asset				Liability
Portion of option contracts maturing in 2015
Puts (purchased)		Natural Gas			4,015,000			$	3.9			$	3.03			$	3.8			$	—			$	1.7			$	—
		NGL			2,254,500			$	43.41			$	26.09			$	40.2			$	—			$	6			$	—
		Crude Oil			730,000			$	81.56			$	56.78			$	18.8			$	—			$	1.8			$	—
Calls (written)		Natural Gas			1,277,500			$	5.05			$	3.03			$	—			$	—			$	—			$	(0.3	)
		NGL			1,433,250			$	45.74			$	25.97			$	—			$	(0.6	)		$	—			$	(1.0	)
		Crude Oil			730,000			$	88.39			$	56.78			$	—			$	(0.4	)		$	—			$	(1.9	)
Puts (written)		Natural Gas			4,015,000			$	3.9			$	3.02			$	—			$	(3.8	)		$	—			$	—
Calls (purchased)		Natural Gas			1,277,500			$	5.05			$	3.03			$	—			$	—			$	—			$	—
Portion of option contracts maturing in 2016
Puts (purchased)		Natural Gas			1,647,000			$	3.75			$	3.46			$	1			$	—			$	—			$	—
		NGL			2,836,500			$	39.24			$	27.03			$	39.3			$	—			$	—			$	—
		Crude Oil			805,200			$	75.91			$	63.21			$	14.7			$	—			$	—			$	—
Calls (written)		Natural Gas			1,647,000			$	4.98			$	3.46			$	—			$	(0.1	)		$	—			$	—
		NGL			2,836,500			$	45.14			$	27.03			$	—			$	(3.2	)		$	—			$	—
		Crude Oil			805,200			$	86.68			$	63.34			$	—			$	(2.7	)		$	—			$	—
Puts (written)		Natural Gas			1,647,000			$	3.75			$	3.46			$	—			$	(1.0	)		$	—			$	—
Calls (purchased)		Natural Gas			1,647,000			$	4.98			$	3.46			$	0.1			$	—			$	—			$	—
Portion of option contracts maturing in 2017
Puts (purchased)		NGL			365,000			$	23.1			$	22.79			$	1.2			$	—			$	—			$	—
		Crude Oil			365,000			$	66			$	66.97			$	4.1			$	—			$	—			$	—
Calls (written)		NGL			365,000			$	26.15			$	22.79			$	—			$	(0.7	)		$	—			$	—
		Crude Oil			365,000			$	74			$	66.97			$	—			$	(3.3	)		$	—			$	—

-1	Volumes of natural gas are measured in MMBtu, whereas volumes of NGL and crude oil are measured in Bbl.

-2	Strike and market prices are in $/MMBtu for natural gas and in $/Bbl for NGL and crude oil.

-3	The fair value is determined based on quoted market prices at December 31, 2014 and 2013, 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 $0.7 million of losses at December 31, 2014 and cash collateral received.


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.


		Accounting		Notional				Average				Fair Value⁽²⁾
		Treatment						Fixed Rate⁽¹⁾				December 31,
Date of Maturity & Contract Type												2014				2013⁽³⁾
				(dollars in millions)
Contracts maturing in 2015
Interest Rate Swaps—Pay Fixed		Cash Flow Hedge		$	510				1.53	%		$	(0.2	)		$	(6.8	)
Contracts maturing in 2016
Interest Rate Swaps—Pay Fixed		Cash Flow Hedge		$	90				0.55	%		$	(0.1	)		$	—
Contracts maturing in 2017
Interest Rate Swaps—Pay Fixed		Cash Flow Hedge		$	450				2.21	%		$	(12.9	)		$	(13.8	)
Contracts maturing in 2018
Interest Rate Swaps—Pay Fixed		Cash Flow Hedge		$	810				2.24	%		$	(1.3	)		$	3.3
Contracts maturing in 2019
Interest Rate Swaps—Pay Fixed		Cash Flow Hedge		$	620				2.96	%		$	(3.3	)		$	—
Contracts settling prior to maturity
2015—Pre-issuance Hedges		Cash Flow Hedge		$	1,000				5.48	%		$	(258.3	)		$	—
2016—Pre-issuance Hedges		Cash Flow Hedge		$	500				4.21	%		$	(63.4	)		$	60.8
2017—Pre-issuance Hedges		Cash Flow Hedge		$	500				3.69	%		$	(36.0	)			—
2018—Pre-issuance Hedges		Cash Flow Hedge		$	350				3.08	%		$	(4.9	)			—

-1	Interest rate derivative contracts are based on the one-month or three-month LIBOR.

-2	The fair value is determined from quoted market prices at December 31, 2014 and 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 $37.4 million of gains at December 31, 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	12 Months Ended
INCOME TAXES	Dec. 31, 2014
INCOME TAXES [Abstract]
INCOME TAXES	15. INCOME TAXES

	We are not a taxable entity for United States federal income tax purposes, or for the majority of states that impose an income tax. Taxes on our net income generally are borne by our unitholders through the allocation of taxable income. Our income tax expense results from the enactment of state income tax laws by the State of Texas that apply to entities organized as partnerships. Our income tax expense is based upon many but not all items included in net income.

	We computed our income tax expense by applying a Texas state income tax rate to modified gross margin. Our Texas state income tax rate was 0.4% for the year ended December 31, 2014 and 0.5% for the years ended December 31, 2013 and 2012. Our income tax expense is summarized below:


			2014			2013			2012
			(in millions)
	Current state		$	5.5		$	4.3		$	8.1
	Deferred state			4.1			14.4			—
	Total income tax expense		$	9.6		$	18.7		$	8.1

	Our effective tax rate is calculated by dividing the income tax expense by the pretax net book income or loss. The income base for calculating our state income tax expense is modified gross margin for Texas rather than pretax net book income or loss. As a result, this difference is the only reconciling item between the statutory and effective income tax rate. Our effective tax rate for the years ended December 31, 2014, 2013, and 2012, is as follows:


			2014			2013			2012
			(in millions)
	Income before income tax expense		$	749.6		$	179.1		$	558.2
	State income tax expense		$	9.6		$	18.7		$	8.1
	Effective income tax rate			1.3	%		10.4	%		1.6	%

	At December 31, 2014 and 2013, we included a current income tax payable of $1.5 million and $0.9 million, respectively, in “Property and other taxes payable” on our consolidated statements of financial position. In addition, at December 31, 2014 and 2013, we included a deferred income tax payable of $21.7 million and $17.4 million, respectively, in “Other long-term liabilities,” on our consolidated statements of financial position to reflect the tax associated with the difference between the net basis in assets and liabilities for financial and state tax reporting. We recognize deferred income tax assets and liabilities for temporary differences between the relevant basis of our assets and liabilities for financial reporting and tax purposes. The impact of changes in tax legislation on deferred income tax liabilities and assets is recorded in the period of enactment.

	In June 2013, the Texas Legislature passed HB 500, which was subsequently signed into law. The most significant change in the law for us is that HB 500 allows a pipeline company that transports oil, gas, or other petroleum products owned by others to subtract as cost of goods sold, or COGS, its depreciation, operations, and maintenance costs related to the services provided. Under the new law, we are allowed additional deductions against its income for Texas Margin Tax purposes. At December 31, 2013, we included approximately $12.4 million in our deferred income tax liability as a result of the revised tax law. Our effective tax rate in the State of Texas is lower as a result of this law change.

	The tax effects of significant temporary differences representing deferred tax assets and liabilities are as follows:


			December 31,

			2014			2013
			(in millions)
	Net book basis of assets in excess of tax basis		$	(21.5	)	$	(17.4	)
	Net book losses on derivatives not recognized for tax purposes			(0.2	)		-
	Net deferred tax liability		$	(21.7	)	$	(17.4	)

	Accounting for Uncertainty in Income Taxes

	The following is a reconciliation of our beginning and ending balance of unrecognized tax benefits in millions:


		(in millions)
	Unrecognized tax benefits at December 31, 2013	$	29.8
	Additions for tax positions taken in current period		3.4
	Unrecognized tax benefits at December 31, 2014	$	33.2

	As of December 31, 2014 and 2013, the entire balance of unrecognized tax benefits would favorably affect our effective tax rate in future periods if recognized. It is reasonably possible that our liability for unrecognized tax benefits will increase by $3.4 million during the next twelve months. We also recognized interest accrued related to unrecognized tax benefits and penalties as income tax expense. As of December 31, 2014, the Company has accrued penalties of $0.5 million and interest of $0.4 million. Furthermore, we recognize accrued interest income related to unrecognized tax benefits in interest income when the related unrecognized tax benefits are recognized. As such, at December 31, 2014 and 2013, $0.7 million and $0.6 million of accrued interest income, respectively, has not been included in the balance of unrecognized tax benefits.

	Our tax years are generally open to examination by the Internal Revenue Service and state revenue authorities for calendar years ended December 2013, 2012, and 2011.

SEGMENT_INFORMATION

SEGMENT INFORMATION	12 Months Ended
SEGMENT INFORMATION	Dec. 31, 2014
SEGMENT INFORMATION [Abstract]
SEGMENT INFORMATION	16. SEGMENT INFORMATION

	Our business is divided into operating segments, defined as components of the enterprise, about which financial information is available and evaluated regularly by our Chief Operating Decision Maker, collectively comprised of our senior management, in deciding how resources are allocated and performance is assessed.
	Each of our reportable segments is a business unit that offers different services and products that is managed separately, since each business segment requires different operating strategies. We 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 our reorganization resulting from the Offering, which prompted management to reassess the presentation of our reportable segments considering the financial information available and evaluated regularly by our Chief Operating Decision Maker. The new segment is consistent with how management makes resource allocation decisions and 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.

	The following tables present certain financial information relating to our business segments and corporate activities:


			As of and for the year ended December 31, 2014
			Liquids			Natural Gas				Corporate⁽¹⁾				Total
			(in millions)
	Operating revenues:⁽²⁾
	Commodity sales		$	—		$	5,693.9			$	—			$	5,693.9
	Transportation and other services			2,070.40			200.4				—				2,270.80

				2,070.40			5,894.30				—				7,964.70

	Commodity costs			—			5,145.90				—				5,145.90
	Environmental costs, net of recoveries			97.3			—				—				97.3
	Operating and administrative			500.8			438.6				10.6				950
	Power			226.6			—				—				226.6
	Depreciation and amortization			306.8			151.4				—				458.2

				1,131.50			5,735.90				10.6				6,878.00

	Operating income (loss)			938.9			158.4				(10.6	)			1,086.70
	Interest expense, net			—			—				403.2				403.2
	Allowance for equity used during construction			—			—				57.2				57.2
	Other income (expense)			—			13.2	⁽³⁾			(4.3	)			8.9

	Income (loss) before income tax expense			938.9			171.6				(360.9	)			749.6
	Income tax expense			—			—				9.6				9.6

	Net income (loss)			938.9			171.6				(370.5	)			740
	Less: Net income attributable to
	Noncontrolling interest			—			—				263.3				263.3
	Series 1 preferred unit distributions			—			—				90				90
	Accretion of discount on Series 1 preferred units			—			—				14.9				14.9

	Net income (loss) attributable to general and limited partner ownership interests in Enbridge Energy Partners, L.P.		$	938.9		$	171.6			$	(738.7	)		$	371.8

	Total Assets		$	11,871.20		$	5,633.5	⁽⁴⁾		$	242.2			$	17,746.90

	Capital expenditures (excluding acquisitions)		$	2,563.40		$	230			$	6			$	2,799.40


	(1)	Corporate consists of interest expense, interest income, allowance for equity during construction, noncontrolling interest and other costs such as income taxes, which are not allocated to the business segments.

	(2)	There were no intersegment revenues for the year ended December 31, 2014.

	(3)	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.

	(4)	Totals assets for our Natural Gas Segment includes $380.6 million for our long term equity investment in the Texas Express NGL system.



			As of and for the year ended December 31, 2013
			Liquids			Natural Gas				Corporate⁽¹⁾				Total
		(in millions)
Operating revenues:⁽²⁾
Commodity sales		$	—		$	5,368.5			$	—			$	5,368.50
Transportation and other services			1,519.90			228.7				—				1,748.60

			1,519.90			5,597.20				—				7,117.10

Commodity costs			—			4,948.90				—				4,948.90
Environmental costs, net of recoveries			273.7			—				—				273.7
Operating and administrative			461			449.8				7.6				918.4
Power			147.7			—				—				147.7
Depreciation and amortization			244.9			143.1				—				388

			1,127.30			5,541.80				7.6				6,676.70

Operating income (loss)			392.6			55.4				(7.6	)			440.4
Interest expense, net			—			—				320.4				320.4
Allowance for equity used during construction			—			—				43.1				43.1
Other income (expense)			—			(1.5	)⁽³⁾			17.5	⁽⁴⁾			16

Income (loss) before income tax expense			392.6			53.9				(267.4	)			179.1
Income tax expense			—			—				18.7				18.7

Net income (loss)			392.6			53.9				(286.1	)			160.4
Less: Net income attributable to
Noncontrolling interest			—			—				88.3				88.3
Series 1 preferred unit distributions			—			—				58.2				58.2
Accretion of discount on Series 1 preferred units			—			—				9.2				9.2

Net income (loss) attributable to general and limited partner ownership interests in Enbridge Energy Partners, L.P.		$	392.6		$	53.9			$	(441.8	)		$	4.7

Total assets		$	9,268.9		$	4,635.1	⁽⁵⁾		$	997.5			$	14,901.5

Capital expenditures (excluding acquisitions)		$	2,330.70		$	251.3			$	18.8			$	2,600.80


(1)	Corporate consists of interest expense, interest income, allowance for equity during construction, noncontrolling interest and other costs such as income taxes, which are not allocated to the business segments.

(2)	There were no intersegment revenues for the year ended December 31, 2013.

(3)	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.

(4)	Other income (expense) for our Corporate segment includes a gain of $17.1 million from the El Dorado storage facility sale in November of 2013.

(5)	Totals assets for our Natural Gas Segment includes $ 371.3 million for our long term equity investment in the Texas Express NGL system.



		As of and for the year ended December 31, 2012
		Liquids			Natural Gas				Corporate⁽¹⁾				Total
		(in millions)
Operating Revenues:
Commodity sales		$	—		$	5,120.50			$	—			$	5,120.50
Transportation and other services			1,347.30			239.8				—				1,587.10
Less: Intersegment Revenue			1.5			—				—				1.5

			1,345.80			5,360.30				—				6,706.10
Commodity costs			—			4,570.10				—				4,570.10
Environmental costs, net of recoveries			(91.3	)		—				—				(91.3	)
Operating and administrative			371.5			466.7				2.3				840.5
Power			148.8			—				—				148.8
Depreciation and amortization			210			134.8				—				344.8

			639			5,171.60				2.3				5,812.90

Operating income (loss)			706.8			188.7				(2.3	)			893.2
Interest expense, net			—			—				345				345
Allowance for equity used during construction			—			—				11.2				11.2
Other expense			—			—				(1.2	)			(1.2	)

Income (loss) before income tax expense			706.8			188.7				(337.3	)			558.2
Income tax expense			—			—				8.1				8.1

Net income (loss)			706.8			188.7				(345.4	)			550.1
Less: Net income attributable to
Noncontrolling interest			—			—				57				57

Net income (loss) attributable to general and limited
partner ownership interests in Enbridge Energy Partners, L.P.		$	706.8		$	188.7			$	(402.4	)		$	493.1

Total assets		$	7,361.1		$	5,334.8	⁽²⁾		$	100.9			$	12,796.8

Capital expenditures (excluding acquisitions)		$	1,373.40		$	439.7			$	13.1			$	1,826.20


(1)	Corporate consists of interest expense, interest income, allowance for equity during construction, noncontrolling interest and other costs such as income taxes, which are not allocated to the business segments.

(2)	Total assets for our Natural Gas Segment includes $183.7 million for our long-term equity investment in the Texas Express NGL system.
Our revenue is derived from a wide customer base. No revenues from transactions with a single external customer amounted to 10% or more of our total consolidated revenues for the years ended December 31, 2014, 2013, and 2012.

REGULATORY_MATTERS

REGULATORY MATTERS

12 Months Ended

Dec. 31, 2014

REGULATORY MATTERS [Abstract]

REGULATORY MATTERS

17. 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 in any given year. These over or under recoveries are deferred through a revenue adjustment and are returned to or recovered from shippers 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 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 December 31, 2014 and 2013, we had a net regulatory asset balance of 6.0 million and $7.7 million, respectively.

The net regulatory asset or liability balance is comprised of the cumulative over and under recovery adjustments made during the prior calendar year, less any amortizations, and the cumulative over and under recovery 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 twelve month periods ended December 31, 2014, 2013, and 2012 are as follows:

For the twelve month

period ended December 31,

2014

2013

2012

(in millions)

Current Year (Over)/Under Recovery Adjustments

7.7

(15.3

)

Amortization of Prior Year Regulatory (Asset)/Liability

(7.7

)

15.3

43.6

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 December 31, 2014 we had no qualifying volume liabilities, and at December 31, 2013 we had $6.1 million in qualifying volume liabilities related to the Southern Access Pipeline on our Consolidated Statements of Financial Position.

For the years ended December 31, 2013 and 2012, we incurred liabilities related to contractual obligations with our customers on the Southern Access Pipeline related to qualifying volumes. As a result, in 2013 and 2012, we recorded a liability for the contractual amounts due back to our shippers with the corresponding amount as a reduction to revenue. We amortized the liability on a straight line basis as an adjustment to revenue in the following year. For the twelve month periods ended December 31, 2014 and 2013, we amortized through revenue $6.1 million and $6.3 million of qualifying volume liabilities, respectively, on our Consolidated Statements of Income with a corresponding amount reducing the contractual obligation on our Consolidated Statements of Financial Position.

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 to our customers. At December 31, 2014 and 2013, we had $5.9 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 the years ended December 31, 2013 and 2012, we also incurred liabilities related to contractual obligations with our customers on the Alberta Clipper Pipeline related to property taxes. As a result, in 2013 and 2012, we recorded a liability for the contractual amounts due back to our shippers with the corresponding amount as a reduction to revenue. We amortized the liability on a straight line basis as an adjustment to revenue in the following year. For the twelve month periods ended December 31, 2014 and 2013, we amortized through revenue $6.9 million and $6.0 million of property tax over recovery liabilities, 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 AEDC. In connection with construction of the Eastern Access Projects, Line 6B 75-mile Replacement and Mainline Expansion projects, we recorded $57.2 million, $43.1 million, and $11.2 million of “Allowance for equity used during construction” on our Consolidated Statements of Income at December 31, 2014, 2013 and 2012, respectively. We also recorded a corresponding $57.2 million, $43.1 million, and $11.2 million of AEDC in “Property, plant and equipment, net” on our Consolidated Statements of Financial Position at December 31, 2014, 2013 and 2012, respectively.

SUPPLEMENTAL_CASH_FLOWS_INFORM

SUPPLEMENTAL CASH FLOWS INFORMATION	12 Months Ended
SUPPLEMENTAL CASH FLOWS INFORMATION	Dec. 31, 2014
SUPPLEMENTAL CASH FLOW INFORMATION [Abstract]
SUPPLEMENTAL CASH FLOWS INFORMATION	18. SUPPLEMENTAL CASH FLOWS INFORMATION



		For the year ended December 31,
		2014			2013		2012
		(in millions)
	Cash Paid during the year for:
	Interest (net of capitalization)	$	332.4		$	342.3	$	352.1

	Income taxes	$	1.5		$	2.5	$	7.6

	In the “Cash used in investing activities” section of the consolidated statements of cash flows, we exclude changes that did not affect cash. The following is a reconciliation of additions to property, plant and equipment to total capital expenditures (excluding “Investment in joint venture”):


		For the year ended
		December 31,
		2014			2013		2012
		(in millions)
	Additions to property, plant and equipment	$	2,933.6		$	2,409.9	$	1,739.9
	Increase (decrease) in construction payables		(141.0	)		190.9		86.3
	Capital leases		6.8			—		—

	Total capital expenditures (excluding “Investment in joint venture”)	$	2,799.40		$	2,600.80	$	1,826.20

RECENT_ACCOUNTING_PRONOUNCEMEN

RECENT ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED	12 Months Ended
RECENT ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED	Dec. 31, 2014
RECENT ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED [Abstract]
RECENT ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED	19. RECENT ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED

	Discontinued Operations

	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.

	Revenues from Contracts with Customers

	In May 2014, the FASB issued Accounting Standards Update No. 2014-09 that outlines a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. This accounting update is effective for annual and interim periods beginning on or after December 15, 2016 and may be applied on either a full or modified retrospective basis. We are currently evaluating which transition approach we will apply and the impact that this pronouncement will have on our consolidated financial statements.

	Going Concern Uncertainties

	In August 2014, the FASB issued Accounting Standards Update No. 2014-15 which provides guidance on determining when and how to disclose going-concern uncertainties in the financial statements. The new standard requires management to perform interim and annual assessments of an entity's ability to continue as a going concern within one year of the date the financial statements are issued. An entity must provide certain disclosures if conditions or events raise substantial doubt about the entity's ability to continue as a going concern. This accounting update is effective for annual and interim periods 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.


	Hybrid Financial Instruments Issued in the Form of a Share

	In November 2014, The FASB issued Accounting Standards Update No. 2014-16 with the intent to eliminate the use of different methods in practice in the accounting for hybrid financial instruments issued in the form of a share. The new standard clarifies the evaluation of the economic characteristics and risks of a host contract in these hybrid financial instruments. We do not expect that the adoption of this pronouncement will have a material impact on our consolidated financial statements. This accounting update is effective for annual and interim periods beginning after December 15, 2015 and is to be applied on a modified retrospective basis.

QUARTERLY_FINANCIAL_DATA_Unaud

QUARTERLY FINANCIAL DATA (Unaudited)	12 Months Ended
QUARTERLY FINANCIAL DATA (Unaudited)	Dec. 31, 2014
QUARTERLY FINANCIAL DATA (Unaudited) [Abstract]
QUARTERLY FINANCIAL DATA (Unaudited)	20. QUARTERLY FINANCIAL DATA (Unaudited)

		First			Second		Third			Fourth			Total
		(in millions, except per unit amounts)
	2014 Quarters
	Operating revenue	$	2,079.60		$	1,871.10	$	1,942.30		$	2,071.70		$	7,964.7
	Operating expense	$	1,864.90		$	1,690.20	$	1,701.90		$	1,621.00		$	6,878.0
	Operating income	$	214.7		$	180.9	$	240.4		$	450.7		$	1,086.7
	Net income	$	155.7		$	112.5	$	117.5		$	354.3		$	740.0
	Net income attributable to noncontrolling interest	$	36.3		$	42.4	$	70.7		$	113.9		$	263.3
	Net income attributable to general and limited partner ownership interests in	$	93.3		$	43.9	$	20.5		$	214.1		$	371.8

	Enbridge Energy Partners, L.P.
	Net income (loss) per common unit and i-unit	$	0.18		$	0.02	$	(0.04	)	$	0.51		$	0.67

	2013 Quarters
	Operating revenue	$	1,693.00		$	1,672.70	$	1,789.40		$	1,962.00		$	7,117.10
	Operating expense	$	1,690.60		$	1,463.70	$	1,665.80		$	1,856.60		$	6,676.70
	Operating income	$	2.4		$	209	$	123.6		$	105.4		$	440.4
	Net income (loss)	$	(67.7	)	$	123.7	$	61.3		$	43.1		$	160.4
	Net income attributable to noncontrolling interest	$	15.6		$	18.4	$	20.3		$	34		$	88.3
	Net income (loss) attributable to general and limited	$	(83.3	)	$	89.9	$	14.9		$	(16.8	)	$	4.7

	partner ownership interests in Enbridge Energy Partners, L.P.
	Net income (loss) per common unit and i-unit	$	(0.36	)	$	0.18	$	(0.05	)	$	(0.15	)	$	(0.39	)

SUBSEQUENT_EVENTS

SUBSEQUENT EVENTS	12 Months Ended
SUBSEQUENT EVENTS	Dec. 31, 2014
SUBSEQUENT EVENTS [Abstract]
SUBSEQUENT EVENTS	21. SUBSEQUENT EVENTS

	Eaglebine Acquisition

	On February 9, 2015, we announced an agreement with New Gulf Resources, LLC, or NGR, to purchase NGR's midstream business in Leon, Madison and Grimes Counties, Texas for $85.0 million. The acquisition consists of a natural gas gathering system that is currently in operation moving equity and third party production.

	Alberta Clipper Drop Down


	On January 2, 2015, we closed a transaction, or the Drop Down, pursuant to which we acquired the remaining 66.7% interest in the U.S. segment of the Alberta Clipper Pipeline from our General Partner. The consideration consisted of approximately 18,114,975 units of a new class of limited partner interests designated as Class E units with an aggregate value of $694.0 million issued to the General Partner. In addition, we repaid the borrowings outstanding of $306.0 million on the A1 Term Note owed to the General Partner.

	In connection with the closing of the Drop Down, we amended and restated the partnership agreement of the OLP, to, among other things, reflect the transfer by the General Partner to us of the Series AC units of the OLP, which represent limited partner interest in the OLP that relate to the U.S. Alberta Clipper assets of the OLP. In addition, we amended and restated our partnership agreement which among other things, provides for the issuance of and sets forth the rights, preferences and obligations of the Class E units.

	The Class E units are entitled to the same distributions as the Partnership's Class A common units held by the public and are convertible into Class A common units on a one-for-one basis at the General Partner's option. The Class E units are not entitled to distributions with respect to the quarter ended December 31, 2014. The Class E units are redeemable at our option after 30 years, if not earlier converted by the General Partner. The Class E units have a liquidation preference equal to their notional value at December 23, 2014 of $38.31 per unit, which was determined based on the trailing five-day volume-weighted average price of our Class A common units as of that date, which was the date on which we and the General Partner entered into a contribution agreement setting forth the terms of the Drop Down.

	If the aggregate EBITDA, attributable to the Series AC interest in the OLP for calendar years 2015 and 2016 is less than $265.9 million, then 1,305,142 of the Class E units will be cancelled by us effective as of June 15, 2017 for no consideration and will no longer be deemed outstanding for any purposes under our partnership agreement.

	In addition, during each taxable year during the period from January 1, 2015 through December 31, 2037 in which a majority of the Class E units issued on the closing date of the Drop Down remain outstanding, holders of Class A common units, Class B common units and Class D units of the Partnership (including those held by the General Partner) will be specially allocated items of gross income that would otherwise be allocated to holders of Class E units, to the extent that such an amount of gross income exists, in an annual amount equal to $40 million. The annual amount of such allocation will be reduced to $20 million for each taxable year beginning after December 31, 2037.


	Distribution to Partners

	On January 29, 2015, the board of directors of Enbridge Management declared a distribution payable to our partners on February 13, 2015. The distribution was paid to unitholders of record as of February 6, 2015, of our available cash of $233.9 million at December 31, 2014, or $0.57 per limited partner unit. Of this distribution, $194.2 million was paid in cash, $38.9 million was distributed in i-units to our i-unitholder and $0.8 million was retained from our General Partner in respect of the i-unit distribution to maintain its 2% general partner interest.

	Distribution to Series AC Interests

	On January 29, 2015, the board of directors of Enbridge Management, acting on behalf of Enbridge Pipelines (Lakehead) L.L.C., the managing general partner of the OLP declared a final distribution payable to the holders of the Series AC general and limited partner interests. The OLP paid $27.5 million to the noncontrolling interest in the Series AC, while $13.7 million was paid to us.

	Distribution to Series EA Interests

	On January 29, 2015, 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 paid $67.0 million to the noncontrolling interest in the Series EA, while $22.3 million was paid to us.

	Distribution to Series ME Interests

	On January 29, 2015, 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 paid $5.2 million to the noncontrolling interest in the Series ME, while $1.8 million was paid to us.

	Distribution from MEP

	On January 28, 2015, 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 February 13, 2015. The distribution was paid to unitholders of record as of February 6, 2015, of MEP's available cash of $15.8 million at December 31, 2014, or $0.3425 per limited partner unit. MEP paid $7.3 million to their public Class A common unitholders, while $8.5 million in the aggregate was paid to us with respect to our Class A common units, subordinated units and to Midcoast Holdings, L.L.C. with respect to its general partner interest.

	Midcoast Operating Distribution

	On January 28, 2015, 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 February 6, 2015. Midcoast Operating paid $19.8 million to us and $21.1 million to MEP.

SUMMARY_OF_SIGNIFICANT_ACCOUNT1

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	Dec. 31, 2014
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation and Use of Estimates	Basis of Presentation and Use of Estimates

	We prepare our consolidated financial statements in accordance with United States generally accepted accounting principles, or U.S. GAAP. Our preparation of these consolidated financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and the disclosure of contingent assets and liabilities. We regularly evaluate these estimates utilizing historical experience, consultation with experts and other methods we consider reasonable in the circumstances. Nevertheless, actual results may differ significantly from these estimates. We record the effect of any revisions to these estimates in our consolidated financial statements in the period in which the facts that give rise to the revision become known.



Principles of Consolidation	Principles of Consolidation

	The consolidated financial statements include our accounts and all accounts on a consolidated basis of: (1) our wholly and majority-owned subsidiaries; and (2) our subsidiaries over which we have control, even if we do not have a majority ownership. We consolidate the accounts of entities over which we have a controlling financial interest through our ownership of the general partner or the majority voting interests in the entity. All significant intercompany accounts and transactions have been eliminated in consolidation. Ownership interests in our subsidiaries represented by other parties that do not control the entity are presented in our consolidated financial statements as activities and balances attributable to the noncontrolling interest.

Equity Investment in Joint Venture	Equity Investment in Joint Venture

	Our natural gas and NGLs business includes our 35% aggregate interest in the Texas Express NGL system, which is comprised of two joint ventures with third parties, representing a 593-mile NGL intrastate transportation pipeline and a related NGL gathering system. We use the equity method of accounting for our 35% joint venture interest in the Texas Express NGL system as a result of our ability to significantly influence the operating activities, but insufficient ability to control these activities without the participation of a majority of the other members.

Accounting for Regulated Operations	Accounting for Regulated Operations

	Our interstate liquids pipelines are subject to regulation by the FERC and various state authorities. Regulatory bodies exercise statutory authority over matters such as construction, rates, underlying accounting practices and ratemaking agreements with customers.

	The recovery of construction, operating and other costs associated with portions of our Lakehead system are subject to the authoritative accounting provisions applicable to regulated operations. Accordingly, we record costs that are allowed in the ratemaking process in a period different from the period in which the costs would be charged to expense by a non-regulated entity. Also, we record assets and liabilities that result from the regulated ratemaking process that would not be recorded under U.S. GAAP for non-regulated entities.

	Allowance for Funds Used During Construction

	During the construction of our pipelines that qualify for regulated accounting, we are allowed to capitalize costs that represent the estimated debt and equity costs of capital necessary to finance the construction of our pipelines. The debt and equity costs, referred to collectively as allowance for funds used during construction, or AFUDC, are capitalized as part of the costs of pipeline construction in “Property, plant and equipment, net” in our consolidated statements of financial position. The equity return component and interest costs related to the AFUDC are credited to “Other income” and “Interest expense,” respectively, on our consolidated statements of income. Entities that do not qualify for regulated accounting are only allowed to capitalize interest costs related to its construction activities, while a component for equity is prohibited.

	Cost-of-Service Recovery Model

	The rates for a number of our projects are based on a cost-of-service recovery model that follows the FERC's authoritative guidance and are subject to annual filing requirements with the FERC. Under our cost-of-service tolling methodology, we calculate tolls based on forecast volumes and costs. A difference between forecast and actual results causes an over or under recovery in any given 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 projects through the annual cost-of-service filings with the FERC and through toll rate adjustments with our customers.

Revenue Recognition and the Estimation of Revenues and Commodity Costs	Revenue Recognition and the Estimation of Revenues and Commodity Costs

	Liquids

	In our Liquids segment, we generally do not own the crude oil and liquid petroleum that we transport or store, and therefore, we do not assume significant direct commodity price risk. Revenues of our Liquids segment are primarily derived from three sources: interstate transportation of crude oil and liquid petroleum under tariffs regulated by the FERC, ship-or-pay agreements and contract storage revenues related to our crude oil storage assets.

	The tariffs established for our interstate pipelines specify the amounts to be paid by shippers for transportation services we provide between receipt and delivery locations and the general terms and conditions of transportation services on the respective pipeline systems. We recognize revenue upon delivery of products to our customers, when pricing is determinable and collectability is reasonably assured.

	We generally recognize revenue from minimum volume commitments on ship-or-pay agreements when those volume commitments are not utilized during the period. Some long-term ship-or-pay contracts also contain make-up-rights. Make-up-rights are earned by shippers when minimum volume commitments are not utilized during the period but under certain circumstances can be used to offset overages in future periods, subject to expiration periods. We recognize revenue associated with make-up rights at the earlier of when the make-up volume is shipped, the make-up right expires, or when it is determined that the likelihood that the shipper will utilize the make-up right is remote.

	We recognize contract storage revenues based on contractual terms under which customers pay for the option to use available storage capacity and/or a fee based on storage volumes. We recognize revenues as storage services are rendered, when pricing is determinable and collectability is reasonably assured.

	Revenues for our Liquids segment are all recorded in “Transportation and other services” and “Transportation and other services – affiliate” on our Consolidated Statements of Income.

	Natural Gas

	We recognize revenue upon delivery of natural gas and NGLs to customers, when services are rendered, pricing is determinable and collectability is reasonably assured. We generate revenues and segment gross margin principally under the following types of contractual arrangements:

	Fee-Based Arrangements

	In a fee-based arrangement, we receive a fee per Mcf of natural gas processed or per gallon of NGLs produced. Under this arrangement, we have no direct commodity price exposure. We receive fee-based revenue for services, such as compression fees, gathering fees and treating fees that are recognized when the services are performed. Additionally, revenues that are derived from transmission services consist of reservation fees charged for transportation of natural gas on some of our intrastate pipeline systems. Customers paying these fees typically pay a reservation fee each month to reserve capacity plus a nominal commodity charge based on actual transportation volumes. Reservation fees are required to be paid whether or not the shipper delivers the volumes, thus referred to as a ship-or-pay arrangement. Consequently, we recognize revenue for reservation fees ratably over the period in which capacity is reserved. Additional revenues from our intrastate pipelines are derived from the combined sales of natural gas and transportation services. Revenues from fee-based arrangements for our Natural Gas segment are recorded in “Transportation and other services” and “Transportation and other services – affiliate” on our Consolidated Statements of Income.

	Commodity-Based Arrangements

	We also generate revenue and segment gross margin under other types of service arrangements with customers. These arrangements expose us to commodity price risk, which we mitigate to a substantial degree with the use of derivative financial instruments to hedge open positions in these commodities. We hedge a significant amount of our exposure to commodity price risk to support the stability of our cash flows.

	The commodity-based service contracts we have with customers are categorized as follows:

	• Percentage-of-Proceeds Contracts - Under these contracts, we receive a negotiated percentage of the sales proceeds related to natural gas and NGLs we process. The processed products include residue natural gas, NGLs, condensate and sulfur, which we can sell at market prices and retain a percentage of the proceeds as our compensation. This type of arrangement exposes us to commodity price risk, as the revenues from percentage-of-proceeds contracts directly correlate with the market prices of the applicable commodities that we receive.

	• Percentage-of-Liquids Contracts - Under these contracts, we receive a negotiated percentage of the NGLs extracted from natural gas that require processing, which we can then sell at market prices and retain the proceeds as our compensation. This contract structure is similar to percentage-of-proceeds arrangements except that we only receive a percentage of the NGLs produced. Ownership of the residue natural gas remaining after the extraction of NGLs resides with the customer. This type of contract may also require us to provide the customer with a guaranteed NGL recovery percentage regardless of actual NGL production. Since revenues from percentage-of-liquids contracts directly correlate with the market price of NGLs, this type of arrangement also exposes us to commodity price risk.

	• Percentage-of-Index Contracts - Under these contracts, we purchase raw natural gas at a negotiated percentage of an agreed upon index price. We then resell the natural gas, generally for the index price, and keep the difference as our compensation.

	• Keep-Whole Contracts - Under these contracts, we gather or purchase raw natural gas from the customer. We extract and retain the NGLs produced during processing for our own account, which we then sell at market prices. In instances where we purchase raw natural gas at the wellhead, we may also sell the resulting residue natural gas for our own account at market prices. In those instances where we gather and process raw natural gas for the customer's account, we generally must return to the customer residue natural gas with an energy content equivalent to the original raw natural gas we received, as measured in British thermal units, or Btu. This type of arrangement has the highest commodity price exposure because our costs are dependent on the price of natural gas purchased and our revenues are dependent on the price of NGLs sold. As a result, we benefit from these types of contracts when the value of the NGLs is high relative to the cost of the natural gas and are disadvantaged when the cost of the natural gas is high relative to the value of the NGLs.

	Under the terms of each of our commodity-based service contracts, we retain natural gas and NGLs as our compensation for providing these customers with our services. As of December 31, 2014, we are exposed to fluctuations in commodity prices in the near term on approximately 10% to 15% of the physical natural gas, NGLs and condensate we expect to receive as compensation for our services. Due to this unhedged commodity price exposure, our gross margin, representing commodity sales less commodity costs, generally increases when the prices of these commodities are rising and generally decreases when the prices are declining. As a result of entering into these derivative instruments, we have largely fixed the amount of cash that we will pay and receive in the future when we sell the residue gas, NGLs and condensate, even though the market price of these commodities will continue to fluctuate.

	Marketing

	Marketing revenues are derived from providing supply, transportation, balancing, storage and sales services for producers and wholesale customers on our natural gas pipelines, as well as other interconnected pipeline systems. Natural gas marketing activities are primarily undertaken to realize incremental revenues on natural gas purchased at the wellhead, and to provide other services valued by our customers. In general, natural gas we purchase and sell is priced at a published daily or monthly index price. Sales to wholesale customers typically incorporate a premium for managing their transmission and balancing requirements. Higher premiums and associated revenues result from transactions that involve smaller volumes or that offer greater service flexibility for wholesale customers. At the request of some customers, we will enter into long-term fixed price purchase or sales contracts with our customers and usually will enter into offsetting positions under the same or similar terms. We recognize revenues upon delivery of natural gas to our customers, when services are rendered, pricing is determinable and collectability is reasonably assured. Marketing revenues for our Natural Gas segment are recorded in “Commodity sales” and “Commodity sales – affiliate” on our Consolidated Statements of Income. The related cost of natural gas and natural gas liquids sold is recorded in “Commodity costs” and “Commodity costs – affiliate.”

	Estimation of Revenue and Commodity Costs

	In order to permit the timely preparation of our consolidated financial statements, for our natural gas segment, we estimate our current month revenue and commodity costs. We generally cannot compile actual billing information nor obtain actual vendor invoices within a timeframe that would permit the recording of this actual data before our preparation of the consolidated financial statements. As a result, we record an estimate each month for our operating revenues and commodity costs based on the best available volume and price data for natural gas delivered and received, along with an adjustment of the prior month's estimate to equal the prior month's actual data. As a result, there is one month of estimated data recorded in our operating revenues and commodity costs for each of the years ended December 31, 2014, 2013 and 2012. We believe that the assumptions underlying these estimates are not significantly different from the actual amounts due to the routine nature of these estimates and the stability of our processes.

	In addition, we estimate current month revenues in our liquids segment. We record an estimate each month for our operating revenues based on the best available volume and rate data for crude oil delivered, along with an adjustment of the prior month's estimate to equal the prior month's actual data. As a result, there is one month of estimated data recorded in our operating revenues for the years ended December 31, 2014, 2013, and 2012. We believe that the assumptions underlying these estimates are not significantly different from the actual amounts due to the routine nature of these estimates and the stability of our processes.

Cash and Cash Equivalents	Cash and Cash Equivalents

	Cash equivalents are defined as all highly marketable securities with original maturities of three months or less when purchased. The carrying value of cash and cash equivalents approximates fair value because of the short term to maturity of these investments.

	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 issued check payments that have not been presented to the financial institution are included in “Accounts payable and other” on our consolidated statements of financial position.

Allowance for Doubtful Accounts	Allowance for Doubtful Accounts

	We establish provisions for losses on accounts receivable when we determine that we will not collect all or part of an outstanding balance. Collectability is reviewed regularly and an allowance is established or adjusted, as necessary, using the specific identification method.

Inventory	Inventory

	Inventory includes product inventory and materials and supplies inventory. We record all product inventories at the lower of our cost, as determined on a weighted average basis, or market value. Our product inventory consists of liquid hydrocarbons and natural gas. Upon disposition, product inventory is recorded to “Commodity costs” at the weighted average cost of inventory, including any adjustments recorded to reduce inventory to market value.

	Materials and supplies inventory is used either during operations and charged to “Operating and administrative” as incurred, or for capital projects and new construction and capitalized to “Property, plant and equipment, net.”

Oil Measurement Adjustments	Oil Measurement Adjustments

	Oil measurement adjustments occur as part of the normal operations associated with our liquid petroleum operations. The three types of oil measurement adjustments that routinely occur on our systems include:

	• Physical, which result from evaporation, shrinkage, differences in measurement (including sediment and water measurement) between receipt and delivery locations and other operational conditions;

	• Degradation, resulting from mixing at the interface within our pipeline systems or terminal and storage facilities between higher quality light crude oil and lower quality heavy crude oil in pipelines; and

	• Revaluation, which are a function of crude oil prices, the level of our carriers' inventory and the inventory positions of customers.

	Quantifying oil measurement adjustments are difficult because: (1) physical measurements of volumes are not practical, as products continuously move through our pipelines, which are primarily located underground; (2) the extensive length of our pipeline systems; and (3) the numerous grades and types of crude oil products we carry. We utilize engineering-based models and operational assumptions to estimate product volumes in our systems and associated oil measurement adjustments. Material changes in our assumptions may result in revisions to our oil measurement estimates in the period determined. Oil measurement adjustments are included within the “Operating and administrative” line item of our Consolidated Statements of Income.

Operational Balancing Agreements and Natural Gas Imbalances	Operational Balancing Agreements and Natural Gas Imbalances

	To facilitate deliveries of natural gas and provide for operational flexibility, we have operational balancing agreements in place with other interconnecting pipelines. These agreements ensure that the volume of natural gas a shipper schedules for transportation between two interconnecting pipelines equals the volume actually delivered. If natural gas moves between pipelines in volumes that are more or less than the volumes the shipper previously scheduled, a natural gas imbalance is created. The imbalances are settled through periodic cash payments or repaid in-kind through the receipt or delivery of natural gas in the future. Natural gas imbalances are recorded as “Accrued receivables” and “Accrued purchases” on our consolidated statements of financial position using the posted index prices, which approximate market rates, or our weighted average commodity costs.



Capitalization Policies, Depreciation Methods and Impairment of Property, Plant and Equipment	Capitalization Policies, Depreciation Methods and Impairment of Property, Plant and Equipment


	We capitalize expenditures related to property, plant and equipment, subject to a minimum rule, that have a useful life greater than one year for: (1) assets purchased or constructed; (2) existing assets that are replaced, improved or the useful lives have been extended; or (3) all land, regardless of cost. Acquisitions of new assets, additions, replacements and improvements (other than land) costing less than the minimum rule in addition to maintenance and repair costs, including any planned major maintenance activities, are expensed as incurred.

	During construction, we capitalize direct costs, such as labor and materials, and other costs, such as direct overhead and interest at our weighted average cost of debt, and, in our regulated businesses that apply the authoritative accounting provisions applicable to regulated operations, an equity return component.

	We record property, plant and equipment at its original cost, which we depreciate on a straight-line basis over the lesser of its estimated useful life or the estimated remaining lives of the crude oil or natural gas production in the basins the assets serve. Our determination of the useful lives of property, plant and equipment requires us to make various assumptions, including the supply of and demand for hydrocarbons in the markets served by our assets, normal wear and tear of the facilities, and the extent and frequency of maintenance programs. We routinely utilize consultants and other experts to assist us in assessing the remaining lives of the crude oil or natural gas production in the basins we serve.

	We record depreciation using the group method of depreciation which is commonly used by pipelines, utilities and similar entities. Under the group method, for all segments, upon the disposition of property, plant and equipment, the net book value less net proceeds is typically charged to accumulated depreciation and no gain or loss on disposal is recognized. However, when a separately identifiable group of assets, such as a stand-alone pipeline system is sold, we recognize a gain or loss in our consolidated statements of income for the difference between the cash received and the net book value of the assets sold. Changes in any of our assumptions may alter the rate at which we recognize depreciation in our consolidated financial statements. At regular intervals, we retain the services of independent consultants to assist us with assessing the reasonableness of the useful lives we have established for the property, plant and equipment of our major systems. Based on the results of these assessments we may make modifications to the assumptions we use to determine our depreciation rates.

	We evaluate the recoverability of our property, plant and equipment when events or circumstances such as economic obsolescence, the business climate, legal and other factors indicate we may not recover the carrying amount of the assets. We continually monitor our businesses, the market and business environments to identify indicators that could suggest an asset may not be recoverable. We evaluate the asset for recoverability by estimating the undiscounted future cash flows expected to be derived from operating the asset as a going concern. These cash flow estimates require us to make projections and assumptions for many years into the future for pricing, demand, competition, operating cost, contract renewals and other factors. We recognize an impairment loss when the carrying amount of the asset exceeds its fair value as determined by quoted market prices in active markets or present value techniques. The determination of the fair value using present value techniques requires us to make projections and assumptions regarding future cash flows and weighted average cost of capital. Any changes we make to these projections and assumptions could result in significant revisions to our evaluation of the recoverability of our property, plant and equipment and the recognition of an impairment loss in our consolidated statements of income.

Assessment of Recoverability of Goodwill	Assessment of Recoverability of Goodwill

	Goodwill represents the future economic benefits arising from other assets acquired in a business combination that are not individually identified and separately recognized.

	We test goodwill for impairment annually based on carrying values of our reporting units as of the end of the second quarter, or more frequently if impairment indicators arise that suggest the carrying value of goodwill may be impaired. In testing goodwill for impairment, we make critical assumptions that include but are not limited to: (1) projections of future financial performance, which include commodity price and volume assumptions, (2) the expected growth rate of our Natural Gas assets, (3) residual values of the assets; and (4) market weighted average cost of capital. Impairment occurs when the carrying amount of a reporting unit's goodwill exceeds its implied fair value. We reduce the carrying value of goodwill to its fair value at the time we determine that an impairment has occurred.

Assessment of Recoverability of Intangible Assets	Assessment of Recoverability of Intangible Assets

	Our intangible assets primarily consist of customer contracts for the purchase and sale of natural gas, natural gas supply opportunities and contributions we have made in aid of construction activities that will benefit our operations, as well as workforce contracts and customer relationships. We amortize these assets on a straight-line basis over the weighted average useful lives of the underlying assets, representing the period over which the assets are expected to contribute directly or indirectly to our future cash flows.

	We evaluate the carrying value of our intangible assets whenever events or changes in circumstances indicate that the carrying amount of these assets may not be recoverable. In assessing the recoverability of intangible assets, we compare the carrying value to the undiscounted future cash flows we expect the intangible assets or the underlying assets to generate. If the total of the undiscounted future cash flows is less than the carrying amount of the intangible assets, we write the intangible assets down to their fair value.

Derivative Financial Instruments	Derivative Financial Instruments

	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 and fractionation margins. Fractionation margins represent the relative difference between the price we receive from NGL and condensate sales and the corresponding commodity costs of natural gas and natural gas liquids we purchase for processing. We use a variety of derivative financial instruments including futures, forwards, swaps, options and other financial instruments with similar characteristics to create offsetting positions to specific commodity or interest rate exposures.

	We record all derivative financial instruments at fair market value in our Consolidated Statements of Financial Position. Price assumptions we use to value our non-qualifying derivative financial instruments can affect net income for each period. We use published market price information where available, or quotations from OTC market makers to find executable bids and offers. We may also use these inputs with internally developed methodologies that result in our best estimate of fair value. The valuations also reflect the potential impact of liquidating our position in an orderly manner over a reasonable period of time under present market conditions, including credit risk of our counterparties. The amounts reported in our consolidated financial statements change quarterly as these valuations are revised to reflect actual results, changes in market conditions or other factors, many of which are beyond our control.

	For those instruments that qualify for hedge accounting, the accounting treatment is dependent on the intended use and designation of each instrument. We record changes in the fair value of our derivative financial instruments that do not qualify for hedge accounting in our consolidated statements of income as follows:

	• Natural Gas segment commodity-based derivatives—“Commodity Costs” and “Commodity sales”

	• Liquids segment commodity-based derivatives—“Transportation and other services” and “Power”

	• Corporate interest rate derivatives—“Interest expense”

	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.

	Qualified Hedges

	If a derivative financial instrument qualifies and is designated as a cash flow hedge, which is a hedge of a forecasted transaction or future cash flows, any unrealized mark-to-market gain or loss is deferred in AOCI, a component of “Partners' capital” in our consolidated statements of financial position, until the underlying hedged transaction occurs. To the extent that the hedge instrument is effective in offsetting the transaction being hedged, there is no impact to the income statement until the underlying transaction occurs. At inception and on a quarterly basis, we formally assess whether the hedge contract is highly effective in offsetting changes in cash flows of hedged items. Any ineffective portion of a cash flow hedge's change in fair market value is recognized each period in earnings. Realized gains and losses on derivative financial instruments that are designated as hedges and qualify for hedge accounting are included in “Commodity costs” for commodity hedges and “Interest expense” for interest rate hedges in our consolidated statements of income in the period in which the hedged transaction occurs. Gains and losses deferred in AOCI related to cash flow hedges for which hedge accounting has been discontinued remain in AOCI until the underlying physical transaction occurs unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period or within an additional two-month period of time thereafter.

	Generally, our preference is for our derivative financial instruments to receive hedge accounting treatment whenever possible to mitigate the non-cash earnings volatility that arises from recording the changes in fair value of our derivative financial instruments through earnings. To qualify for cash flow hedge accounting treatment as set forth in the authoritative accounting guidance, very specific requirements must be met in terms of hedge structure, hedge objective and hedge documentation.

	Our formal hedging program provides a control structure and governance for our hedging activities specific to identified risks and time periods, which are subject to the approval and monitoring by the board of directors of Enbridge Management or a committee of senior management appointed by our General Partner. We employ derivative financial instruments in connection with an underlying asset, liability or anticipated transaction and we do not use derivative financial instruments for speculative purposes.

	At inception, we formally document the relationship between the hedging instrument and the hedged item, the risk management objective, and the method used for assessing and testing correlation and hedge effectiveness. We also assess, both at the inception of the hedge and on an on-going basis, whether the derivatives that are used in our hedging transactions are highly effective in offsetting changes in cash flows of the hedged item. Furthermore, we regularly assess the creditworthiness of our counterparties to manage against the risk of default. If we determine that a derivative is no longer highly effective as a hedge, we discontinue hedge accounting prospectively by including changes in the fair value of the derivative in current earnings.

	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 “Commodity costs,” “Commodity sales,” “Transportation and other services,” “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.



Fair Value Measurements	Fair Value Measurements

	We apply the authoritative accounting provisions for measuring fair value to our derivative instruments and disclosures associated with our outstanding commodity activities. We define fair value as the expected price we would receive to sell an asset or pay to transfer a liability in an orderly transaction with market participants at the measurement date.

	We employ a hierarchy which prioritizes the inputs we use to measure recurring fair value into three distinct categories based upon whether such inputs are observable in active markets or unobservable. We classify assets and liabilities in their entirety based on the lowest level of input that is significant to the fair value measurement. Our methodology for categorizing assets and liabilities that are measured at fair value pursuant to this hierarchy gives the highest priority to unadjusted quoted prices in active markets and the lowest level to unobservable inputs as outlined below:

	• Level 1—We include in this category the fair value of assets and liabilities that we measure based on unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. We consider active markets as those in which transactions for the assets or liabilities occur with sufficient frequency and volume to provide pricing information on an ongoing basis. The fair value of our assets and liabilities included in this category consists primarily of exchange-traded derivative instruments.

	• Level 2— We include in this category 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: (a) quoted prices for assets and liabilities; (b) time value; (c) volatility factors; and (d) 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.

	• Level 3—We include in this category the fair value of assets and liabilities that we measure based on prices or valuation techniques that require inputs which are both significant to the fair value measurement and less observable from objective sources (i.e., values supported by lesser volumes of market activity). We may also use these inputs with internally developed methodologies that result in our best estimate of the fair value. Level 3 assets and liabilities primarily include derivative instruments for which we do not have sufficient corroborating market evidence, such as binding broker quotes, to support classifying the asset or liability as Level 2. Additionally, Level 3 valuations may utilize modeled pricing inputs to derive forward valuations, which may include some or all of the following inputs: non-binding broker quotes, time value, volatility, correlation and extrapolation methods.

	We record all derivative financial instruments in our consolidated financial statements at fair market value, which we adjust on a recurring basis each period for changes in the fair market value, and refer to as marking to market, or mark-to-market. The fair market value of these derivative financial instruments reflects the estimated amounts that we would pay to transfer a liability or receive to sell an asset in an orderly transaction with market participants to terminate or close the contracts at the reporting date, taking into account the current unrealized losses or gains on open contracts. We apply a mid-market pricing convention, or the “market approach,” to value substantially all of our derivative instruments.

	Our assets are adjusted for the non-performance risk of our counterparties using their current credit default swap spread rates. Likewise, in the case of our liabilities, our nonperformance risk is considered in the valuation and is also adjusted using a credit adjustment model incorporating inputs such as credit default swap rates, bond spreads, and default probabilities.

	Our credit exposure for over-the-counter derivatives is directly with our counterparty and continues until the maturity or termination of the contracts. As appropriate, valuations are adjusted for various factors such as credit and liquidity considerations. Actively traded external market quotes, data from pricing services and published indices are also used to value our derivative instruments. We may use these inputs along with internally developed methodologies that result in our best estimates of fair value.

Income Taxes	Income Taxes

	We are not a taxable entity for United States federal income tax purposes or for the majority of states that impose an income tax. Taxes on our net income generally are borne by our unitholders through the allocation of taxable income. Our income tax expense results from the enactment of state income tax laws that apply to entities organized as partnerships by the State of Texas. This tax is computed on our modified gross margin and we have determined the tax to be an income tax as set forth in authoritative accounting literature.

	We recognize deferred income tax assets and liabilities for temporary differences between the relevant basis of our assets and liabilities for financial reporting and tax purposes. We record the impact of changes in tax legislation on deferred income tax liabilities and assets in the period the legislation is enacted.

	We recognize the tax effects of any uncertain tax positions as the largest amount that will more likely than not be realized upon ultimate settlement with a taxing authority having full knowledge of the position and all relevant facts. We recognize accrued interest income related to unrecognized tax benefits in interest income when the related unrecognized tax benefits are recognized.

	Net income for financial statement purposes may differ significantly from taxable income of unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirements under our partnership agreement. The aggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined because information regarding each partner's tax attributes in us is not available.

Commitments, Contingencies and Environmental Liabilities	Commitments, Contingencies and Environmental Liabilities

	We expense or capitalize, as appropriate, expenditures for ongoing compliance with environmental regulations that relate to past or current operations. We expense amounts we incur for remediation of existing environmental contamination caused by past operations that do not benefit future periods by preventing or eliminating future contamination. We record liabilities for environmental matters when assessments indicate that remediation efforts are probable, and the costs can be reasonably estimated. Estimates of environmental liabilities are based on currently available facts, existing technology and presently enacted laws and regulations taking into consideration the likely effects of inflation and other factors. These amounts also consider prior experience in remediating contaminated sites, other companies' clean-up experience and data released by government organizations. Our estimates are subject to revision in future periods based on actual costs or new information and are included in “Environmental liabilities” and “Other long-term liabilities” in our consolidated statements of financial position at their undiscounted amounts. We always have the potential of incurring additional costs in connection with environmental liabilities 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. We evaluate recoveries from insurance coverage separately from the liability and, when recovery is probable, we record and report an asset separately from the associated liability in our consolidated financial statements.

	We recognize liabilities for other commitments and contingencies when, after fully analyzing the available information, we determine it is either probable that an asset has been impaired, or that a liability has been incurred and the amount of impairment or loss can be reasonably estimated. When a range of probable loss can be estimated, we accrue the most likely amount, or if no amount is more likely than another, we accrue the minimum of the range of probable loss. We expense legal costs associated with loss contingencies as such costs are incurred.

Asset Retirement Obligations	Asset Retirement Obligations

	Legal obligations exist for a minority of our right-of-way agreements due to requirements or landowner options that compel us to remove the pipe at final abandonment. Sufficient data exists with certain pipeline systems to reasonably estimate the cost of abandoning or retiring a pipeline system. However, in some cases, there is insufficient information to reasonably determine the timing and/or method of settlement for estimating the fair value of the asset retirement obligation. In these cases, the asset retirement obligation cost is considered indeterminate because there is no data or information that can be derived from past practice, industry practice, our intentions, or the estimated economic life of the asset. Useful lives of most pipeline systems are primarily derived from available supply resources and ultimate consumption of those resources by end users. Variables can affect the remaining lives of the assets which preclude us from making a reasonable estimate of the asset retirement obligation. Indeterminate asset retirement obligation costs will be recognized in the period in which sufficient information exists to allow us to reasonably estimate potential settlement dates and methods.

	We record a liability for the fair value of asset retirement obligations and conditional asset retirement obligations that we can reasonably estimate, on a discounted basis. We collectively refer to asset retirement obligations and conditional asset retirement obligations as ARO. Typically, we record an ARO at the time the assets are installed or acquired, if a reasonable estimate of fair value can be made. In connection with establishing an ARO, we capitalize the costs as part of the carrying value of the related assets. We recognize an ongoing expense for the interest component of the liability as part of depreciation expense resulting from changes in the value of the ARO due to the passage of time. We depreciate the initial capitalized costs over the useful lives of the related assets. We extinguish the liabilities for an ARO when assets are taken out of service or otherwise abandoned.

NET_INCOME_PER_LIMITED_PARTNER1

NET INCOME PER LIMITED PARTNER UNIT (Tables)	12 Months Ended
NET INCOME PER LIMITED PARTNER UNIT (Tables)	Dec. 31, 2014
NET INCOME PER LIMITED PARTNER UNIT [Abstract]
Schedule of Formula for Distributing Available Cash	Beginning July 1, 2014, pursuant to our 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 Targets		Distribution Per Unit		General Partner and IDUs⁽¹⁾	to Limited partners
	Minimum Quarterly Distribution		Up to $0.5435		2%	98%
	Target Distribution		> $0.5435		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 distributions to the General Partner and limited partners as follows:

	Distribution Targets		Portion of Quarterly		Percentage Distributed to	Percentage Distributed to
	Distribution Targets		Distribution Per Unit		General Partner	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 year ended December 31,
			2014			2013			2012
			(in millions, except per unit amounts)
	Net income		$	740		$	160.4		$	550.1
	Less Net income attributable to:
	Noncontrolling interest			(263.3	)		(88.3	)		(57.0	)
	Series 1 preferred unit distributions			(90.0	)		(58.2	)		—
	Accretion of discount on Series 1 preferred units			(14.9	)		(9.2	)		—

	Net income attributable to general and limited partner interests in Enbridge Energy Partners, L.P.			371.8			4.7			493.1
	Less distributions:
	Incentive distributions			(39.1	)		(129.9	)		(116.3	)
	Distributed earnings attributed to our General Partner			(17.3	)		(14.2	)		(13.0	)
	Distributed earnings attributed to Class D units			(107.5	)		—			—

	Total distributed earnings to our General Partner, Class D units and IDUs			(163.9	)		(144.1	)		(129.3	)
	Total distributed earnings attributed to our common units and i-units			(731.0	)		(695.6	)		(636.3	)

	Total distributed earnings			(894.9	)		(839.7	)		(765.6	)

	Overdistributed earnings		$	(523.1	)	$	(835.0	)	$	(272.5	)

	Weighted average common units and i-units outstanding			328.2			316.2			290.6


	Basic and diluted earnings per unit:
	Distributed earnings per common unit and i-unit⁽¹⁾		$	2.23		$	2.2		$	2.19
	Overdistributed earnings per common unit and i-unit⁽²⁾			(1.56	)		(2.59	)		(0.92	)

	Net income (loss) per common unit and i-unit (basic and diluted)⁽³⁾		$	0.67		$	(0.39	)	$	1.27


	(1)	Represents the total distributed earnings to common units and i-units divided by the weighted average number of common units and i-units outstanding for the period.

	(2)	Represents the common units' 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 year ended December 31, 2014 and 2013, 43,201,310 anti-dilutive Preferred Units were excluded from the if-converted method of calculating diluted earnings per unit. For the year ended December 31, 2014, 66,100,000 anti-dilutive Class D units were excluded from the if-converted method of calculating diluted earnings per unit.

INVENTORY_Tables

INVENTORY (Tables)	12 Months Ended
INVENTORY (Tables)	Dec. 31, 2014
INVENTORY [Abstract]
Schedule of Inventory		Our inventory is comprised of the following:
			December 31,
			2014		2013

			(in millions)
		Materials and supplies	$	2.2	$	2.1
		Crude oil inventory		13.2		18
		Natural gas and NGL inventory		78.8		74.8
			$	94.2	$	94.9

PROPERTY_PLANT_AND_EQUIPMENT_T

PROPERTY, PLANT AND EQUIPMENT (Tables)	12 Months Ended
PROPERTY, PLANT AND EQUIPMENT (Tables)	Dec. 31, 2014
PROPERTY, PLANT AND EQUIPMENT [Abstract]
Schedule of Property, Plant and Equipment					Depreciation			December 31,
					Rates			2014			2013

								(in millions)
		Land				-		$	44.2		$	43.6
		Rights-of-way				1.80%-7.14%			851.8			666.2
		Pipelines				1.79%-6.70%			9,585.40			8,035.80
		Pumping equipment, buildings and tanks				1.48%-6.67%			3,126.80			2,233.00
		Compressors, meters and other operating equipment				1.80%-20.00%			2,072.70			1,989.80
		Vehicles, office furniture and equipment				1.33%-33.33%			413.9			322
		Processing and treating plants				2.21%-2.73%			516			514.4
		Construction in progress							1,857.10			2,077.70
		Total property, plant and equipment							18,467.90			15,882.50
		Accumulated depreciation							(2,775.2	)		(2,705.7	)
		Property, plant and equipment, net						$	15,692.70		$	13,176.80
Schedule of Asset Retirement Obligations			2014				2013
			(in millions)
	Balance at beginning of period			$	3.4			$	3.4
	Additions				113.9				-
	Accretion expense				1.1				-
	Liabilities settled				(21.6	)			-
	Balance at end of period			$	96.8			$	3.4

INTANGIBLE_ASSETS_Tables

INTANGIBLE ASSETS (Tables)	12 Months Ended
INTANGIBLE ASSETS (Tables)	Dec. 31, 2014
INTANGIBLE ASSETS [Abstract]
Schedule of Intangible Assets by Major Class				31-Dec-14
			Gross Intangible Assets at December 31, 2013		Additions		Dispositions			Intangible Assets, Gross		Gross Accumulated Amortization at December 31, 2013			Amortization Expenses			Accumulated Amortization, Gross			Intangible Assets, Net

		Natural Gas Opportunities	$	291	$	-	$	-		$	291	$	(59.4	)	$	(10.3	)	$	(69.7	)	$	221.3
		Customer Contracts		4.4		-		-			4.4		(1.7	)		(0.4	)		(2.1	)		2.3
		Other		37.7		8.1		(1.0	)		44.8		(8.8	)		(4.8	)		(13.6	)		31.2
		Total intangible assets	$	333.1	$	8.1	$	(1.0	)	$	340.2	$	(69.9	)	$	(15.5	)	$	(85.4	)	$	254.8

			31-Dec-13
			Gross Intangible Assets at December 31, 2012		Additions		Dispositions			Intangible Assets, Gross		Gross Accumulated Amortization at December 31, 2012			Amortization Expenses			Accumulated Amortization, Gross			Intangible Assets, Net

		Natural Gas Opportunities	$	291	$	-	$	-		$	291	$	(49.0	)	$	(10.4	)	$	(59.4	)	$	231.6
		Customer Contracts		4.4		-		-			4.4		(1.2	)		(0.5	)		(1.7	)		2.7
		Other		15.4		22.3		-			37.7		(3.4	)		(5.4	)		(8.8	)		28.9
		Total intangible assets	$	310.8	$	22.3	$	-		$	333.1	$	(53.6	)	$	(16.3	)	$	(69.9	)	$	263.2

Schedule of Project Amortization Expense			2015		2016		2017			2018		2019
			$	15.7	$	13.5	$	12.2		$	12	$	12

DEBT_Tables

DEBT (Tables)	12 Months Ended
DEBT (Tables)	Dec. 31, 2014
DEBT [Abstract}
Schedule of Debt Obligations			Interest			December 31,
			Rate			2014			2013

						(in millions)
	EEP debt obligations:
	Commercial Paper(1)			0.503	%	$	612.3		$	300
	Credit Facilities due 2016-2018			1.293	%		1,160.00			-
	Senior Notes due 2014			5.35	%		-			200
	Senior Notes due 2016			5.875	%		300			300
	Senior Notes due 2018			7	%		100			100
	Senior Notes due 2018			6.5	%		400			400
	Senior Notes due 2019			9.875	%		500			500
	Senior Notes due 2020			5.2	%		500			500
	Senior Notes due 2021			4.2	%		600			600
	Senior Notes due 2028			7.125	%		100			100
	Senior Notes due 2033			5.95	%		200			200
	Senior Notes due 2034			6.3	%		100			100
	Senior Notes due 2038			7.5	%		400			400
	Senior Notes due 2040			5.5	%		550			550
	Junior subordinated notes due 2067			8.05	%		400			400
	MEP debt obligations:
	MEP Credit Agreement			3.2	%		360			335
	MEP Series A Senior Notes due 2019			3.56	%		75			-
	MEP Series B Senior Notes due 2021			4.04	%		175			-
	MEP Series C Senior Notes due 2024			4.42	%		150			-
	Total Principal of Debt Obligations						6,682.30			4,985.00
	Other:
	Unamortized Discount						(7.1	)		(7.6	)
	Current Maturities and short term debt						-			(200.0	)
	Total Long Term Debt					$	6,675.20		$	4,777.40
	______________________________
	(1)

	Individual issuances of commercial paper generally mature in 90 days or less, but are supported by our Credit Facilities
Schedule of Interest Costs			For the year ended December 31,

			2014			2013			2012

			(in millions)

		Interest expense	$	403.2		$	320.4		$	345
		Interest capitalized		45.3			51.7			36.3
		Interest cost incurred	$	448.5		$	372.1		$	381.3

		Interest paid	$	332.4		$	342.3		$	352.1

		Weighted average interest rate		6.1	%		6.2	%		6.4	%
Schedule of Maturities of Third Party Debt
		2015	$	-
		2016		950
		2017		360
		2018		1,622.30
		2019		575
		Thereafter		3,175.00
		Total	$	6,682.30
Schedule of Line of Credit Facilities			(in millions)
	Total credit limit under Credit Facilities		$	2,625.00
	Less: Amounts outstanding under Credit Facilities			-
		Principal amount of commercial paper outstanding		612.3
		Credit Facilities		1,160.00
		Letters of credit outstanding		330.2
	Total amount available at December 31, 2014		$	522.5

PARTNERS_CAPITAL_Tables

PARTNERS' CAPITAL (Tables)	12 Months Ended
PARTNERS' CAPITAL (Tables)	Dec. 31, 2014
PARTNERS' CAPITAL [Abstract]
Schedule of Equity Interests			2014				2013

	Series 1 preferred units			9.6	%			11.5	%
	Class A common units owned by the public			46.4	%			55.2	%
	Class A common units owned by our General Partner			10.4	%			12.3	%
	Class B common units owned by our General Partner			1.7	%			2.1	%
	Class D units owned by our General Partner			14.7	%			-	%
	i-units owned by Enbridge Management ⁽¹⁾			15.2	%			16.9	%
	General Partner interest			2.0	%			2.0	%
				100.0	%			100.0	%

	-1

	For the years ended December 31, 2014 and 2013, our General Partner 11.7% of Enbridge Management, which owns all of our i-units.
Schedule of Net Proceeds from Class A Common Units through Equity Offerings	Issuance Date			Number of Class A common units Issued				Offering Price per Class A common unit			Net Proceeds			General			Net Proceeds Including General Partner Contribution

											to the			Partner

											Partnership (1)			Contribution (2)

				(in millions, except units and per unit amounts)
	2012
	September (3)				16,100,000			$	28.64		$	446.8		$	9.4		$	456.2


	(1)

	Net of underwriters' fees and discounts, commissions and issuance expenses if any.
	(2)

	Contributions made by the General Partner to maintain its 2% general partner interest.
	(3)

	The proceeds from the September 2012 equity issuance were used to fund a portion of our capital expansion projects and for general partnership purposes.
Schedule of Distributions															Amount of
												Cash			Distribution			Retained
						Distribution						available			of i-units to			from
	Distribution					Payment			Distribution			for			i-unit			General		Distribution
	Declaration Date			Record Date		Date			per Unit			distribution			Holders (1)			Partner (2)		of Cash
												(in millions, except per unit amounts)
	2014
		31-Oct		7-Nov		14-Nov			$	0.555		$	221.8		$	37.3		$	0.8	$	183.7
		31-Jul		7-Aug		14-Aug			$	0.555			224.7			36.7			0.8		187.2
		30-Apr		8-May		15-May			$	0.5435			214.5			35.3			0.7		178.5
		30-Jan		7-Feb		14-Feb			$	0.5435			213.7			34.6			0.7		178.4
												$	874.7		$	143.9		$	3	$	727.8
	2013
		31-Oct		7-Nov		14-Nov			$	0.5435		$	213.1		$	34.1		$	0.7	$	178.3
		29-Jul		7-Aug		14-Aug			$	0.5435			206.8			28.9			0.6		177.3
		30-Apr		8-May		15-May			$	0.5435			206.2			28.4			0.6		177.2
		30-Jan		7-Feb		14-Feb			$	0.5435			198.9			22.4			0.4		176.1
												$	825		$	113.8		$	2.3	$	708.9
	2012
		31-Oct		7-Nov		14-Nov			$	0.5435		$	198.5		$	22		$	0.4	$	176.1
		30-Jul		7-Aug		14-Aug			$	0.5435			187.5			21.6			0.5		165.4
		30-Apr		7-May		15-May			$	0.5325			180.7			20.9			0.4		159.4
		30-Jan		7-Feb		14-Feb			$	0.5325			180.3			20.5			0.4		159.4
												$	747		$	85		$	1.7	$	660.3

	(1)

	We issued 4,562,088, 3,769,989 and 2,632,090 i-units to Enbridge Management, L.L.C., the sole owner of our i-units, during 2014, 2013 and 2012, respectively, in lieu of cash.
	(2)

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

RELATED_PARTY_TRANSACTIONS_Tab

RELATED PARTY TRANSACTIONS (Tables)	12 Months Ended
RELATED PARTY TRANSACTIONS (Tables)	Dec. 31, 2014
RELATED PARTY TRANSACTIONS [Abstract]
Schedule of Limited Partner Interests Issued, General Partner Contribution to Retain General Partner Interest	Issuance Dates		Number of Class A common				Offering Price				Net Proceeds				General		Net Proceeds Including General Partner Contribution
			units Issued
							per Class A				to the				Partner

							common unit (1)				Partnership (2)				Contribution
				(in millions, except units and per unit amount)
	2012
	September			16,100,000			$	28.64			$	446.8			$	9.4	$	456.2

	(1) The offering price per unit listed for the Equity Distribution Agreement, or EDA, issuances is a calculated average unit price for the periods indicated.
	(2)Net of underwriters' fees and discounts, commissions and issuance expenses.
Schedule of Distributions
	Distribution	Distribution			Amount Paid to				Amount Paid to the				Total MEP
	Declaration Date	Payment Date			EEP				noncontrolling interest				Distribution

					(in millions)
	30-Oct-14	14-Nov-14			$	8.4			$	7.2			$	15.6
	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
					$	28.5			$	24.2			$	52.7
	Distribution	Distribution			Amount Paid to				Amount Paid to the				Total Series AC
	Declaration Date	Payment Date
					Partnership				noncontrolling interest				Distribution
					(in millions)
	2014
	31-Oct	14-Nov			$	10.1			$	20.3			$	30.4
	31-Jul	14-Aug				7.4				14.8				22.2
	30-Apr	15-May				6.6				13.1				19.7
	30-Jan	14-Feb				6.4				12.8				19.2
					$	30.5			$	61			$	91.5
	2013
	31-Oct	14-Nov			$	7			$	14.1			$	21.1
	29-Jul	14-Aug				5.5				11				16.5
	30-Apr	15-May				7.5				14.9				22.4
	30-Jan	14-Feb				6.9				13.8				20.7
					$	26.9			$	53.8			$	80.7
	2012
	31-Oct	14-Nov			$	6.5			$	12.9			$	19.4
	30-Jul	14-Aug				7.2				14.4				21.6
	30-Apr	15-May				8.4				16.8				25.2
	30-Jan	14-Feb				7.9				15.8				23.7
					$	30			$	59.9			$	89.9
	Distribution	Distribution			Amount Paid to				Amount Paid to the				Total Series EA
	Distribution	Distribution			Amount Paid to				Amount Paid to the				Total Series EA
	Declaration Date	Payment Date			EEP				noncontrolling interest				Distribution

					(in millions)
	31-Oct-14	14-Nov-14			$	14.6			$	43.7			$	58.3
	31-Jul-14	14-Aug-14				5.6				16.7				22.3
	29-Apr-14	15-May-14				2.5				6.5				9
					$	22.7			$	66.9			$	89.6
	Distribution	Distribution			Amount Paid to				Amount Paid to the				Total Series EA
	Distribution	Distribution			Amount Paid to				Amount Paid to the				Total Series EA
	Declaration Date	Payment Date			EEP				noncontrolling interest				Distribution

					(in millions)
	31-Oct-14	14-Nov-14			$	0.6			$	1.9			$	2.5
Schedule of Cash Activity for A1 Credit Facility and A1 Term Note		A1 Term
		Note

		(in millions)

	Balance at December 31, 2012	$	330
	Repayments		(12.0	)
	Balance at December 31, 2013		318
	Repayments		(12.0	)
	Balance at December 31, 2014	$	306
Schedule of Transactions with Affiliates			For the year ended December 31
			2014				2013				2012
				(in millions)
	Alberta Clipper Interests		$	54.6			$	52.6			$	53.9
	Eastern Access Interests			145.3				32.1				3.4
	U.S. Mainline Expansion Interests			33.8				4.3				(0.3	)
	Midcoast Energy Partners, L.P.			29.6				(0.7	)			-
	Total		$	263.3			$	88.3			$	57

COMMITMENTS_AND_CONTINGENCIES_

COMMITMENTS AND CONTINGENCIES (Tables)	12 Months Ended
COMMITMENTS AND CONTINGENCIES (Tables)	Dec. 31, 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
Schedule of Future Minimum Commitments	As of December 31, 2014, our future minimum commitments that have remaining non-cancelable terms in excess of one year are as follows:




			2015		2016		2017		2018		2019		Thereafter		Total
			(in millions)
	Purchase commitments⁽¹⁾		$	1,012.70	$	—	$	—	$	—	$	—	$	—	$	1,012.70
	Power commitments⁽²⁾			14.8		9.2		6.3		3.8		1.5		—		35.6
	Other operating leases			25.6		23.5		21.9		15.2		14.8		342.3		443.3
	Right-of-way			2.3		2.1		1.7		1.6		1.5		33.7		42.9
	Product purchase obligations⁽³⁾			23.1		8.3		14.7		24.5		25.5		112.5		208.6
	Transportation/Service contract obligations⁽⁴⁾			63.3		58.3		99.5		109.1		113.8		403.5		847.5
	Fractionation agreement obligations⁽⁵⁾			70.1		70.1		70.1		70.1		70.1		235		585.5

	Total		$	1,211.90	$	171.5	$	214.2	$	224.3	$	227.2	$	1,127.00	$	3,176.10


	(1)	Represents commitments to purchase materials, primarily pipe from third-party suppliers in connection with our growth projects.

	(2)	Represents commitments to purchase power in connection with our Liquids segment.

	-3	We have long-term product purchase obligations with several third-party suppliers to acquire natural gas and NGLs at the approximate market value at the time of delivery.

	-4	The service contract obligations represent the minimum payment amounts for firm transportation and storage capacity we have reserved on third-party pipelines and storage facilities.

	-5	The fractionation agreement obligations represent the minimum payment amounts for firm fractionation of our NGL supply that we reserve at third party fractionation facilities.

DERIVATIVE_FINANCIAL_INSTRUMEN1

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Tables)	12 Months Ended
	Dec. 31, 2014
DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES [Abstract]
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value

			December 31,
			2014				2013
			(in millions)
	Other current assets		$	185.5			$	21.2
	Other assets, net			93.3				74.4
	Accounts payable and other⁽¹⁾			(315.4	)			(172.0	)
	Other long-term liabilities			(124.6	)			(12.3	)
	Due from general partner and affiliates			0.3				—

			$	(160.9	)		$	(88.7	)


	(1)	Includes $28.4 million of cash collateral at December 31, 2014, and $16.7 million of cash collateral at December 31, 2013.
Schedule of Derivative Balances by Counter Party Credit Quality
			December 31,
			2014				2013
			(in millions)
	Counterparty Credit Quality⁽¹⁾
	AAA		$	0.1			$	0.3
	AA⁽²⁾			(49.8	)			(49.7	)
	A⁽³⁾			(129.1	)			(40.1	)
	Lower than A			17.9				0.8

			$	(160.9)			$	(88.7)


	(1)	As determined by nationally-recognized statistical ratings organizations.

	(2)	Includes $28.4 million of cash collateral at December 31, 2014.

	(3)	Includes $16.7 million of cash collateral at December 31, 2013.
Schedule of Credit Concentrations in Industry Sectors

			December 31,
			2014				2013
			(in millions)
	United States financial institutions and investment banking entities⁽¹⁾		$	(147.1	)		$	(85.0	)
	Non-United States financial institutions⁽²⁾			(54.2	)			0.8
	Other			40.4				(4.5	)

			$	(160.9)			$	(88.7)


	-1	Includes $28.4 million of cash collateral at December 31, 2014.

	-2	Includes $16.7 million of cash collateral at December 31, 2013.
Effect of Derivative Instruments on the Consolidated Statements of Financial Position

					Asset Derivatives								Liability Derivatives
			Financial Position		Fair Value at								Fair Value at
			Location		December 31,								December 31,
					2014				2013⁽³⁾				2014				2013⁽³⁾
					(in millions)
	Derivatives designated as hedging instruments⁽¹⁾
	Interest rate contracts		Other current assets		$	—			$	8.1			$	—			$	—
	Interest rate contracts		Other assets			—				57.1				—				—
	Interest rate contracts		Accounts payable and other⁽²⁾			—				11.9				(241.0	)			(145.5	)
	Interest rate contracts		Other long-term liabilities			—				—				(102.0	)			(11.3	)
	Commodity contracts		Other current assets			26.1				2				—				(0.6	)
	Commodity contracts		Other assets			2.1				3.5				—				(0.5	)
	Commodity contracts		Accounts payable and other			—				1.9				—				(12.7	)
	Commodity contracts		Other long-term liabilities			—				0.6				—				(1.4	)

						28.2				85.1				(343.0	)			(172.0	)

	Derivatives not designated as hedging instruments
	Commodity contracts		Other current assets			159.4				11.8				—				(0.1	)
	Commodity contracts		Other assets			91.2				17.6				—				(3.3	)
	Commodity contracts		Accounts payable and other⁽²⁾			—				5.4				(46.0	)			(16.3	)
	Commodity contracts		Other long-term liabilities			—				—				(22.6	)			(0.2	)
	Commodity contracts		Due from general partner and affiliates			0.3				—				—				—

						250.9				34.8				(68.6	)			(19.9	)

	Total derivative instruments				$	279.1			$	119.9			$	(411.6	)		$	(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 $28.4 and $16.7 million of cash collateral at December 31, 2014 and 2013, respectively.

	(3)	The effect of derivative instruments on the consolidated statements of financial position, as of December 31, 2013, was revised to disclose the financial position location on a gross basis. The revisions to the disclosures are not considered material to and had no impact on amounts previously reported in the consolidated statements of financial position.
Effect of Derivative Instruments on the Consolidated Statements of Income and Accumulated Other Comprehensive Income
	Derivatives in Cash Flow		Amount of Gain				Location of Gain		Amount of Gain (Loss)				Location of Gain		Amount of Gain
	Hedging Relationships		(Loss) Recognized in				(Loss) Reclassified		Reclassified from				(Loss) Recognized in		(Loss) Recognized in
			AOCI on Derivative				from AOCI to		AOCI to Earnings				Earnings on Derivative		Earnings on
			(Effective Portion)				Earnings		(Effective Portion)				(Ineffective Portion and		Derivative
							(Effective Portion)						Amount Excluded from		(Ineffective Portion
													Effectiveness Testing)⁽¹⁾		and Amount
															Excluded from
															Effectiveness
															Testing)⁽¹⁾
	(in millions)
	For the year ended December 31, 2014
	Interest rate contracts		$	(163.4	)		Interest expense		$	(16.2	)		Interest expense		$	(100.1	)
	Commodity contracts			29.9			Commodity costs			(5.8	)		Commodity costs			5.6

	Total		$	(133.5	)				$	(22.0	)				$	(94.5	)

	For the year ended December 31, 2013
	Interest rate contracts		$	251			Interest expense		$	(29.8	)		Interest expense		$	(21.5	)
	Commodity contracts			(16.5	)		Commodity costs			2.7			Commodity costs			3.3

	Total		$	234.5					$	(27.1	)				$	(18.2	)

	For the year ended December 31, 2012
	Interest rate contracts		$	(45.4	)		Interest expense		$	(28.9	)		Interest expense		$	(20.5	)
	Commodity contracts			41.8			Commodity costs			0.1			Commodity costs			3.1

	Total		$	(3.6	)				$	(28.8	)				$	(17.4	)


	(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⁾			(155.9	)
	Amounts reclassified from AOCI⁽²⁾⁽³⁾			21.2
	Tax benefit (expense)			(0.1	)

	Net other comprehensive income		$	(134.8	)

	Balance at December 31, 2014		$	(211.4	)


	-1	Excludes NCI gain of $6.3 million reclassified from AOCI at December 31, 2014.

	-2	Excludes NCI gain of $0.8 million reclassified from AOCI at December 31, 2014.

	-3	For additional details on the amounts reclassified from AOCI, reference the Reclassifications from Accumulated Other Comprehensive Income table below.

Reclassifications from Accumulated Other Comprehensive Income

			For the year ended December 31,
			2014				2013				2012
			(in millions)
	Losses (gains) on cash flow hedges:
	Interest Rate Contracts⁽¹⁾		$	16.2			$	29.8			$	28.9
	Commodity Contracts⁽²⁾⁽³⁾			5				(2.7	)			(0.1	)

	Total Reclassifications from AOCI		$	21.2			$	27.1			$	28.8


	(1)	Loss (gain) reported within “Interest expense” in the Consolidated Statements of Income.

	(2)	Loss (gain) reported within “Commodity costs” in the Consolidated Statements of Income.

	(3)	Excludes NCI gain of $0.8 million year ending December 31, 2014.
Effect of Derivative Instruments on Consolidated Statements of Income
					December 31,
					2014				2013				2012⁽⁶⁾
	Derivatives Not Designated as Hedging Instruments		Location of Gain (Loss)		Amount of Gain (Loss)
	Derivatives Not Designated as Hedging Instruments		Recognized in Earnings⁽¹⁾		Recognized in Earnings⁽²⁾
					(in millions)
	Interest rate contracts		Interest expense⁽³⁾		$	—			$	—			$	—
	Commodity contracts		Transportation and other services			17.4				(3.0	)			—
	Commodity contracts		Commodity sales⁽⁴⁾			23.7				(3.0	)			7.4
	Commodity contracts		Commodity sales—affiliate			0.3				—				—
	Commodity contracts		Power			0.7				0.6				0.1
	Commodity contracts		Commodity costs⁽⁵⁾			136.8				(8.0	)			19.5

	Total				$	178.9			$	(13.4	)		$	27.0


	(1)	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.

	(2)	Does not include settlements associated with derivative instruments that settle through physical delivery.

	(3)	Includes settlement gains of $0 million, $0.2 million, and $0.5 million for the years ended December 31, 2014, 2013 and 2012, respectively.

	(4)	Includes settlement gains of $4.5 million, $1.4 million, and $6.2 million for the years ended December 31, 2014, 2013 and 2012, respectively.

	(5)	Includes settlement gains (losses) of $8.0 million and ($4.6) million and $21.4 million for the years ended December 31, 2014, December 31, 2013, and December 31, 2012, respectively.

	(6)	The effects of derivatives instruments on consolidated statements of income have been revised to include settlement gains on derivatives not designated as hedge instruments of $28.1 million for the year ended December 31, 2012.

Offsetting of Financial Assets and Derivative Assets

			As of December 31, 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⁽¹⁾
			(in millions)
	Description:
	Derivatives		$	279.1			$	—			$	279.1			$	(91.8	)		$	187.3

	Total		$	279.1			$	—			$	279.1			$	(91.8	)		$	187.3



			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⁽¹⁾
			(in millions)
	Description:
	Derivatives		$	119.9			$	(24.3	)		$	95.6			$	(18.6)			$	77.0

	Total		$	119.9			$	(24.3	)		$	95.6			$	-18.6			$	77


	-1	Includes $28.4 million and $16.7 million of cash collateral at December 31, 2014 and December 31, 2013, respectively.
Offsetting of Financial Liabilities and Derivative Liabilities

			As of December 31, 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⁽¹⁾
			(in millions)
	Description:
	Derivatives		$	(440.0	)		$	—			$	(440.0	)		$	91.8			$	(348.2	)

	Total		$	(440.0	)		$	—			$	(440.0	)		$	91.8			$	(348.2	)



			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⁽¹⁾
			(in millions)
	Description:
	Derivatives		$	(208.6	)		$	24.3			$	(184.3	)		$	18.6			$	(165.7	)

	Total		$	(208.6	)		$	24.3			$	(184.3	)		$	18.6			$	(165.7	)


	(1)	Includes $28.4 million and $16.7 million of cash collateral at December 31, 2014 and December 31, 2013, respectively.
Table Setting Forth By Level Within The Fair Value Hierarchy Financial Assets And Liabilities

			31-Dec-14																				31-Dec-13
			Level 1				Level 2				Level 3				Collateral				Total				Level 1				Level 2				Level 3			Collateral			Total
			(in millions)
	Interest rate contracts⁽¹⁾		$	—			$	(343.0	)		$	—			$	—			$	(343.0	)		$	—			$	(79.7	)		$	—		$	—		$	(79.7	)
	Commodity contracts:
	Financial			—				41.6				42.7				—				84.3				—				6.4				(6.9	)		—			(0.5	)
	Physical			—				—				19.5				—				19.5				—				—				(0.2	)		—			(0.2	)
	Commodity options			—				—				106.7				—				106.7				—				—				8.4			—			8.4

				—				(301.4	)			168.9				—				(132.5	)			—				(73.3	)			1.3			—			(72.0	)

	Cash Collateral			—				—				—				(28.4	)			(28.4	)			—				—				—			(16.7	)		(16.7	)

	Total		$	—			$	(301.4	)		$	168.9			$	(28.4	)		$	(160.9	)		$	—			$	(73.3	)		$	1.3		$	(16.7	)	$	(88.7	)


	(1)	Amounts have been revised to exclude $16.7 million of cash collateral at December 31, 2013.
Schedule of Quantitative Information on Level 3 Fair Value Measurements
	Contract Type		Fair Value at				Valuation		Unobservable		Range⁽¹⁾
			December 31,				Technique		Input		Range⁽¹⁾
			2013⁽²⁾								Lowest				Highest				Weighted				Units
											Lowest				Highest				Average				Units
			(in millions)
	Commodity Contracts—
	Financial
	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 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 MMBtu for Natural Gas, Gal for NGLs, Bbl for Crude Oil and MWh for Power.
	(2)	Fair values are presented in millions and include credit valuation adjustments of approximately $0.1 million of gains.


	Contract Type		Fair Value at				Valuation		Unobservable		Range⁽¹⁾
			December 31,				Technique		Input		Range⁽¹⁾
			2014⁽²⁾								Lowest				Highest				Weighted				Units
											Lowest				Highest				Average				Units
			(in millions)
	Commodity Contracts—
	Financial
	Natural Gas		$	0.6			Market Approach		Forward Gas Price			2.55				3.72				3.04			MMBtu
	NGLs			42.1			Market Approach		Forward NGL Price			0.48				1.14				0.64			Gal
	Commodity Contracts—
	Physical
	Natural Gas			1.5			Market Approach		Forward Gas Price			1.55				4.08				3.08			MMBtu
	Crude Oil			(0.9	)		Market Approach		Forward Crude Price			49.57				55.6				53.51			Bbl
	NGLs			18.9			Market Approach		Forward NGL Price			0.06				1.21				0.54			Gal
	Commodity Options
	Natural Gas, Crude and NGLs			106.7			Option Model		Option Volatility			19%				94%				36%

	Total Fair Value		$	168.9


	-1	Prices are in dollars per MMBtu for Natural Gas, Gal for NGLs, Bbl for Crude Oil and MWh for Power.

	-2	Fair values are presented in millions of dollars and include credit valuation adjustments of approximately $1.0 million of losses.
Schedule of Reconciliation of Changes in Fair Value of Level 3 Financial Assets and Liabilities
			Commodity				Commodity				Commodity				Total
			Financial				Physical				Options
			Contracts				Contracts
			(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			30.2				48.6				101.7				180.5
	Included in other comprehensive income			16.9				—				—				16.9
	Purchases, issuances, sales and settlements
	Purchases			—				—				0.7				0.7
	Sales			—				—				(2.1	)			(2.1	)
	Settlements⁽²⁾			2.5				(28.9	)			(2.0	)			(28.4	)

	Ending balance as of December 31, 2014		$	42.7			$	19.5			$	106.7			$	168.9

	Amount of changes in net assets attributable to the change in derivative gains or losses related to assets still held at the reporting date		$	42.2			$	19			$	100.4			$	161.6

	Amounts reported in commodity sales		$	—			$	24			$	—			$	24


	(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 December 31, 2014																						At December 31, 2013
			Commodity		Notional⁽¹⁾				Wtd. Average Price⁽²⁾								Fair Value⁽³⁾								Fair Value⁽³⁾
			Commodity		Notional⁽¹⁾				Receive				Pay				Asset				Liability				Asset				Liability
	Portion of contracts maturing in 2015
	Swaps
	Receive variable/pay fixed		Natural Gas			896,915			$	2.94			$	3.67			$	—			$	(0.7	)		$	—			$	—
			NGL			225,850			$	35.24			$	65.37			$	—			$	(6.8	)		$	—			$	—
			Crude Oil			912,250			$	56.73			$	86.82			$	—			$	(27.4	)		$	—			$	—
	Receive fixed/pay variable		Natural Gas			3,645,440			$	3.95			$	2.93			$	3.7			$	—			$	—			$	—
			NGL			1,980,850			$	46.91			$	27.11			$	39.2			$	—			$	1.5			$	(1.1	)
			Crude Oil			1,759,415			$	93.79			$	56.75			$	65.0			$	—			$	8.3			$	—
	Receive variable/pay variable		Natural Gas			59,606,800			$	2.89			$	2.89			$	1.5			$	(1.7	)		$	0.1			$	—
	Physical Contracts
	Receive variable/pay fixed		Natural Gas			232,400			$	3.09			$	2.99			$	—			$	—			$	—			$	—
			NGL			206,300			$	22.54			$	39.95			$	—			$	(3.6	)		$	—			$	—
			Crude Oil			11,300			$	53.44			$	56.27			$	—			$	—			$	—			$	—
	Receive fixed/pay variable		Natural Gas			290,114			$	3.02			$	3.18			$	—			$	—			$	—			$	—
			NGL			1,042,921			$	44.6			$	25.58			$	19.8			$	—			$	—			$	—
			Crude Oil			65,000			$	62.46			$	54			$	0.5			$	—			$	—			$	—
	Receive variable/pay variable		Natural Gas			148,689,068			$	2.95			$	2.95			$	2.2			$	(1.0	)		$	0.5			$	(0.1	)
			NGL			7,221,805			$	22.68			$	22.3			$	3.7			$	(1.0	)		$	—			$	—
			Crude Oil			558,553			$	50.57			$	53.07			$	0.3			$	(1.7	)		$	—			$	—
	Portion of contracts maturing in 2016
	Swaps
	Receive variable/pay fixed		Natural Gas			181,435			$	3.15			$	3.85			$	—			$	(0.1	)		$	—			$	—
			Crude Oil			415,950			$	62.96			$	82.69			$	—			$	(8.1	)		$	—			$	—
	Receive fixed/pay variable		Natural Gas			75,000			$	3.48			$	3.52			$	—			$	—			$	—			$	—
			NGL			823,500			$	39.64			$	28.18			$	9.3			$	—			$	—			$	—
			Crude Oil			415,950			$	85.08			$	62.96			$	9.1			$	—			$	0.7			$	—
	Receive variable/pay variable		Natural Gas			20,587,000			$	3.3			$	3.29			$	0.5			$	(0.3	)		$	—			$	—
	Physical Contracts
	Receive fixed/pay variable		NGL			1,788			$	28.67			$	25.71			$	—			$	—			$	—			$	—
	Receive variable/pay variable		Natural Gas			34,834,479			$	3.4			$	3.39			$	0.7			$	(0.4	)		$	0.1			$	—
	Portion of contracts maturing in 2017
	Swaps
	Receive fixed/pay variable		NGL			365,000			$	24.78			$	22.79			$	0.7			$	—			$	—			$	—
			Crude Oil			365,000			$	69.35			$	66.97			$	0.8			$	—			$	—			$	—
	Physical Contracts
	Receive variable/pay variable		Natural Gas			14,909,743			$	3.77			$	3.76			$	0.2			$	(0.1	)		$	—			$	—
	Portion of contracts maturing in 2018
	Swaps
	Receive variable/pay variable		Natural Gas			900,000			$	4.03			$	4.03			$	—			$	—			$	—			$	—

	(1)	Volumes of natural gas are measured in MMBtu, whereas volumes of NGL and crude oil are measured in Bbl.

	(2)	Weighted average prices received and paid are in $/MMBtu for natural gas and $/Bbl for NGL and crude oil.

	(3)	The fair value is determined based on quoted market prices at December 31, 2014 and 2013 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 $0.5 million of losses and $0.1 million of gains at December 31, 2014 and 2013, respectively, and cash collateral received.
Schedule of Fair Values of Expected Cash Flows of Outstanding Commodity Options

			At December 31, 2014																						At December 31, 2013
									Strike				Market				Fair Value⁽³⁾								Fair Value
			Commodity		Notional⁽¹⁾				Price⁽²⁾				Price⁽²⁾				Asset				Liability				Asset				Liability
	Portion of option contracts maturing in 2015
	Puts (purchased)		Natural Gas			4,015,000			$	3.9			$	3.03			$	3.8			$	—			$	1.7			$	—
			NGL			2,254,500			$	43.41			$	26.09			$	40.2			$	—			$	6			$	—
			Crude Oil			730,000			$	81.56			$	56.78			$	18.8			$	—			$	1.8			$	—
	Calls (written)		Natural Gas			1,277,500			$	5.05			$	3.03			$	—			$	—			$	—			$	(0.3	)
			NGL			1,433,250			$	45.74			$	25.97			$	—			$	(0.6	)		$	—			$	(1.0	)
			Crude Oil			730,000			$	88.39			$	56.78			$	—			$	(0.4	)		$	—			$	(1.9	)
	Puts (written)		Natural Gas			4,015,000			$	3.9			$	3.02			$	—			$	(3.8	)		$	—			$	—
	Calls (purchased)		Natural Gas			1,277,500			$	5.05			$	3.03			$	—			$	—			$	—			$	—
	Portion of option contracts maturing in 2016
	Puts (purchased)		Natural Gas			1,647,000			$	3.75			$	3.46			$	1			$	—			$	—			$	—
			NGL			2,836,500			$	39.24			$	27.03			$	39.3			$	—			$	—			$	—
			Crude Oil			805,200			$	75.91			$	63.21			$	14.7			$	—			$	—			$	—
	Calls (written)		Natural Gas			1,647,000			$	4.98			$	3.46			$	—			$	(0.1	)		$	—			$	—
			NGL			2,836,500			$	45.14			$	27.03			$	—			$	(3.2	)		$	—			$	—
			Crude Oil			805,200			$	86.68			$	63.34			$	—			$	(2.7	)		$	—			$	—
	Puts (written)		Natural Gas			1,647,000			$	3.75			$	3.46			$	—			$	(1.0	)		$	—			$	—
	Calls (purchased)		Natural Gas			1,647,000			$	4.98			$	3.46			$	0.1			$	—			$	—			$	—
	Portion of option contracts maturing in 2017
	Puts (purchased)		NGL			365,000			$	23.1			$	22.79			$	1.2			$	—			$	—			$	—
			Crude Oil			365,000			$	66			$	66.97			$	4.1			$	—			$	—			$	—
	Calls (written)		NGL			365,000			$	26.15			$	22.79			$	—			$	(0.7	)		$	—			$	—
			Crude Oil			365,000			$	74			$	66.97			$	—			$	(3.3	)		$	—			$	—

	-1	Volumes of natural gas are measured in MMBtu, whereas volumes of NGL and crude oil are measured in Bbl.

	-2	Strike and market prices are in $/MMBtu for natural gas and in $/Bbl for NGL and crude oil.

	-3	The fair value is determined based on quoted market prices at December 31, 2014 and 2013, 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 $0.7 million of losses at December 31, 2014 and cash collateral received.

Schedule of Current Interest Rate Derivatives

			Accounting		Notional				Average				Fair Value⁽²⁾
			Treatment						Fixed Rate⁽¹⁾				December 31,
	Date of Maturity & Contract Type												2014				2013⁽³⁾
					(dollars in millions)
	Contracts maturing in 2015
	Interest Rate Swaps—Pay Fixed		Cash Flow Hedge		$	510				1.53	%		$	(0.2	)		$	(6.8	)
	Contracts maturing in 2016
	Interest Rate Swaps—Pay Fixed		Cash Flow Hedge		$	90				0.55	%		$	(0.1	)		$	—
	Contracts maturing in 2017
	Interest Rate Swaps—Pay Fixed		Cash Flow Hedge		$	450				2.21	%		$	(12.9	)		$	(13.8	)
	Contracts maturing in 2018
	Interest Rate Swaps—Pay Fixed		Cash Flow Hedge		$	810				2.24	%		$	(1.3	)		$	3.3
	Contracts maturing in 2019
	Interest Rate Swaps—Pay Fixed		Cash Flow Hedge		$	620				2.96	%		$	(3.3	)		$	—
	Contracts settling prior to maturity
	2015—Pre-issuance Hedges		Cash Flow Hedge		$	1,000				5.48	%		$	(258.3	)		$	—
	2016—Pre-issuance Hedges		Cash Flow Hedge		$	500				4.21	%		$	(63.4	)		$	60.8
	2017—Pre-issuance Hedges		Cash Flow Hedge		$	500				3.69	%		$	(36.0	)			—
	2018—Pre-issuance Hedges		Cash Flow Hedge		$	350				3.08	%		$	(4.9	)			—

	-1	Interest rate derivative contracts are based on the one-month or three-month LIBOR.

	-2	The fair value is determined from quoted market prices at December 31, 2014 and 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 $37.4 million of gains at December 31, 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_Tables

INCOME TAXES (Tables)	12 Months Ended
INCOME TAXES (Tables)	Dec. 31, 2014
INCOME TAXES [Abstract]
Schedule of Income Tax Expense			2014			2013			2012
			(in millions)
	Current state		$	5.5		$	4.3		$	8.1
	Deferred state			4.1			14.4			—
	Total income tax expense		$	9.6		$	18.7		$	8.1

Effective Income Tax Rate Reconciliation			2014			2013			2012
			(in millions)
	Income before income tax expense		$	749.6		$	179.1		$	558.2
	State income tax expense		$	9.6		$	18.7		$	8.1
	Effective income tax rate			1.3	%		10.4	%		1.6	%

Schedule of Deferred Tax Assets and Liabilities			December 31,

			2014			2013
			(in millions)
	Net book basis of assets in excess of tax basis		$	(21.5	)	$	(17.4	)
	Net book losses on derivatives not recognized for tax purposes			(0.2	)		-
	Net deferred tax liability		$	(21.7	)	$	(17.4	)

Unrecognized Tax Schedule		(in millions)
	Unrecognized tax benefits at December 31, 2013	$	29.8
	Additions for tax positions taken in current period		3.4
	Unrecognized tax benefits at December 31, 2014	$	33.2

SEGMENT_INFORMATION_Tables

SEGMENT INFORMATION (Tables)	12 Months Ended
SEGMENT INFORMATION (Tables)	Dec. 31, 2014
SEGMENT INFORMATION [Abstract]
Schedule of Segment Reporting Information, By Segment

			As of and for the year ended December 31, 2014
			Liquids			Natural Gas				Corporate⁽¹⁾				Total
			(in millions)
	Operating revenues:⁽²⁾
	Commodity sales		$	—		$	5,693.9			$	—			$	5,693.9
	Transportation and other services			2,070.40			200.4				—				2,270.80

				2,070.40			5,894.30				—				7,964.70

	Commodity costs			—			5,145.90				—				5,145.90
	Environmental costs, net of recoveries			97.3			—				—				97.3
	Operating and administrative			500.8			438.6				10.6				950
	Power			226.6			—				—				226.6
	Depreciation and amortization			306.8			151.4				—				458.2

				1,131.50			5,735.90				10.6				6,878.00

	Operating income (loss)			938.9			158.4				(10.6	)			1,086.70
	Interest expense, net			—			—				403.2				403.2
	Allowance for equity used during construction			—			—				57.2				57.2
	Other income (expense)			—			13.2	⁽³⁾			(4.3	)			8.9

	Income (loss) before income tax expense			938.9			171.6				(360.9	)			749.6
	Income tax expense			—			—				9.6				9.6

	Net income (loss)			938.9			171.6				(370.5	)			740
	Less: Net income attributable to
	Noncontrolling interest			—			—				263.3				263.3
	Series 1 preferred unit distributions			—			—				90				90
	Accretion of discount on Series 1 preferred units			—			—				14.9				14.9

	Net income (loss) attributable to general and limited partner ownership interests in Enbridge Energy Partners, L.P.		$	938.9		$	171.6			$	(738.7	)		$	371.8

	Total Assets		$	11,871.20		$	5,633.5	⁽⁴⁾		$	242.2			$	17,746.90

	Capital expenditures (excluding acquisitions)		$	2,563.40		$	230			$	6			$	2,799.40


	(1)	Corporate consists of interest expense, interest income, allowance for equity during construction, noncontrolling interest and other costs such as income taxes, which are not allocated to the business segments.

	(2)	There were no intersegment revenues for the year ended December 31, 2014.

	(3)	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.

	(4)	Totals assets for our Natural Gas Segment includes $380.6 million for our long term equity investment in the Texas Express NGL system.



			As of and for the year ended December 31, 2013
			Liquids			Natural Gas				Corporate⁽¹⁾				Total
			(in millions)
	Operating revenues:⁽²⁾
	Commodity sales		$	—		$	5,368.5			$	—			$	5,368.50
	Transportation and other services			1,519.90			228.7				—				1,748.60

				1,519.90			5,597.20				—				7,117.10

	Commodity costs			—			4,948.90				—				4,948.90
	Environmental costs, net of recoveries			273.7			—				—				273.7
	Operating and administrative			461			449.8				7.6				918.4
	Power			147.7			—				—				147.7
	Depreciation and amortization			244.9			143.1				—				388

			1,127.30			5,541.80				7.6				6,676.70

Operating income (loss)			392.6			55.4				(7.6	)			440.4
Interest expense, net			—			—				320.4				320.4
Allowance for equity used during construction			—			—				43.1				43.1
Other income (expense)			—			(1.5	)⁽³⁾			17.5	⁽⁴⁾			16

Income (loss) before income tax expense			392.6			53.9				(267.4	)			179.1
Income tax expense			—			—				18.7				18.7

Net income (loss)			392.6			53.9				(286.1	)			160.4
Less: Net income attributable to
Noncontrolling interest			—			—				88.3				88.3
Series 1 preferred unit distributions			—			—				58.2				58.2
Accretion of discount on Series 1 preferred units			—			—				9.2				9.2

Net income (loss) attributable to general and limited partner ownership interests in Enbridge Energy Partners, L.P.		$	392.6		$	53.9			$	(441.8	)		$	4.7

Total assets		$	9,268.9		$	4,635.1	⁽⁵⁾		$	997.5			$	14,901.5

Capital expenditures (excluding acquisitions)		$	2,330.70		$	251.3			$	18.8			$	2,600.80


(1)	Corporate consists of interest expense, interest income, allowance for equity during construction, noncontrolling interest and other costs such as income taxes, which are not allocated to the business segments.

(2)	There were no intersegment revenues for the year ended December 31, 2013.

(3)	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.

(4)	Other income (expense) for our Corporate segment includes a gain of $17.1 million from the El Dorado storage facility sale in November of 2013.

(5)	Totals assets for our Natural Gas Segment includes $ 371.3 million for our long term equity investment in the Texas Express NGL system.



		As of and for the year ended December 31, 2012
		Liquids			Natural Gas				Corporate⁽¹⁾				Total
		(in millions)
Operating Revenues:
Commodity sales		$	—		$	5,120.50			$	—			$	5,120.50
Transportation and other services			1,347.30			239.8				—				1,587.10
Less: Intersegment Revenue			1.5			—				—				1.5

			1,345.80			5,360.30				—				6,706.10
Commodity costs			—			4,570.10				—				4,570.10
Environmental costs, net of recoveries			(91.3	)		—				—				(91.3	)
Operating and administrative			371.5			466.7				2.3				840.5
Power			148.8			—				—				148.8
Depreciation and amortization			210			134.8				—				344.8

			639			5,171.60				2.3				5,812.90

Operating income (loss)			706.8			188.7				(2.3	)			893.2
Interest expense, net			—			—				345				345
Allowance for equity used during construction			—			—				11.2				11.2
Other expense			—			—				(1.2	)			(1.2	)

Income (loss) before income tax expense			706.8			188.7				(337.3	)			558.2
Income tax expense			—			—				8.1				8.1

Net income (loss)			706.8			188.7				(345.4	)			550.1
Less: Net income attributable to
Noncontrolling interest			—			—				57				57

Net income (loss) attributable to general and limited
partner ownership interests in Enbridge Energy Partners, L.P.		$	706.8		$	188.7			$	(402.4	)		$	493.1

Total assets		$	7,361.1		$	5,334.8	⁽²⁾		$	100.9			$	12,796.8

Capital expenditures (excluding acquisitions)		$	1,373.40		$	439.7			$	13.1			$	1,826.20


(1)	Corporate consists of interest expense, interest income, allowance for equity during construction, noncontrolling interest and other costs such as income taxes, which are not allocated to the business segments.

(2)	Total assets for our Natural Gas Segment includes $183.7 million for our long-term equity investment in the Texas Express NGL system.

REGULATORY_MATTERS_Tables

REGULATORY MATTERS (Tables)	12 Months Ended
REGULATORY MATTERS (Tables)	Dec. 31, 2014
REGULATORY MATTERS [Abstract]
Over and Under Recovery Revenue Adjustments and Net Regulatory Asset Amortization			For the twelve month
			period ended December 31,
			2014			2013		2012
			(in millions)

		Current Year (Over)/Under Recovery Adjustments	$	6		$	7.7	$	(15.3	)
		Amortization of Prior Year Regulatory (Asset)/Liability		(7.7	)		15.3		43.6

SUPPLEMENTAL_CASH_FLOWS_INFORM1

SUPPLEMENTAL CASH FLOWS INFORMATION (Tables)	12 Months Ended
SUPPLEMENTAL CASH FLOWS INFORMATION (Tables)	Dec. 31, 2014
SUPPLEMENTAL CASH FLOW INFORMATION [Abstract]
Schedule of Supplemental Cash Flow Information
		For the year ended December 31,
		2014			2013		2012
		(in millions)
	Cash Paid during the year for:
	Interest (net of capitalization)	$	332.4		$	342.3	$	352.1

	Income taxes	$	1.5		$	2.5	$	7.6


		For the year ended
		December 31,
		2014			2013		2012
		(in millions)
	Additions to property, plant and equipment	$	2,933.6		$	2,409.9	$	1,739.9
	Increase (decrease) in construction payables		(141.0	)		190.9		86.3
	Capital leases		6.8			—		—

	Total capital expenditures (excluding “Investment in joint venture”)	$	2,799.40		$	2,600.80	$	1,826.20

QUARTERLY_FINANCIAL_DATA_Unaud1

QUARTERLY FINANCIAL DATA (Unaudited) (Tables)	12 Months Ended
QUARTERLY FINANCIAL DATA (Unaudited) (Tables)	Dec. 31, 2014
QUARTERLY FINANCIAL DATA (Unaudited) [Abstract]
Schedule of Quarterly Financial Data		First			Second		Third			Fourth			Total
		(in millions, except per unit amounts)
	2014 Quarters
	Operating revenue	$	2,079.60		$	1,871.10	$	1,942.30		$	2,071.70		$	7,964.7
	Operating expense	$	1,864.90		$	1,690.20	$	1,701.90		$	1,621.00		$	6,878.0
	Operating income	$	214.7		$	180.9	$	240.4		$	450.7		$	1,086.7
	Net income	$	155.7		$	112.5	$	117.5		$	354.3		$	740.0
	Net income attributable to noncontrolling interest	$	36.3		$	42.4	$	70.7		$	113.9		$	263.3
	Net income attributable to general and limited partner ownership interests in	$	93.3		$	43.9	$	20.5		$	214.1		$	371.8

	Enbridge Energy Partners, L.P.
	Net income (loss) per common unit and i-unit	$	0.18		$	0.02	$	(0.04	)	$	0.51		$	0.67

	2013 Quarters
	Operating revenue	$	1,693.00		$	1,672.70	$	1,789.40		$	1,962.00		$	7,117.10
	Operating expense	$	1,690.60		$	1,463.70	$	1,665.80		$	1,856.60		$	6,676.70
	Operating income	$	2.4		$	209	$	123.6		$	105.4		$	440.4
	Net income (loss)	$	(67.7	)	$	123.7	$	61.3		$	43.1		$	160.4
	Net income attributable to noncontrolling interest	$	15.6		$	18.4	$	20.3		$	34		$	88.3
	Net income (loss) attributable to general and limited	$	(83.3	)	$	89.9	$	14.9		$	(16.8	)	$	4.7

	partner ownership interests in Enbridge Energy Partners, L.P.
	Net income (loss) per common unit and i-unit	$	(0.36	)	$	0.18	$	(0.05	)	$	(0.15	)	$	(0.39	)

ORGANIZATION_AND_NATURE_OF_OPE1

ORGANIZATION AND NATURE OF OPERATIONS (Details) (USD $)	1 Months Ended		12 Months Ended			6 Months Ended
In Millions, except Share data, unless otherwise specified	Sep. 30, 2012		Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2014	Jun. 30, 2014
			segments
			plants
Aggregate gross proceeds	$456.20	[1]		$519.30	$457
Master Limited Partnership Ownership Interest (in percentage)			100.00%	100.00%
Transfer of interests in subsidiary to Midcoast Energy Partners, L.P.			125.4
Number of reporting segments (in segments)			2
Natural gas treating plants (in plants)			8			8
Natural gas treating plants, standby (in plants)			3			3
Natural gas processing plants (in plants)			18			18
Natural gas processing plants, standby (in plants)			6			6
Natural Gas Reserves [Member]
Length of pipeline (in miles)			11,100			11,100
Lakehead System [Member]
Covered area of pipeline (in miles)			2,211			2,211
Length of pipeline (in miles)			5,300			5,300
Mid Continent System [Member]
Length of pipeline (in miles)			1,666			1,666
Crude oil capacity (in barrels)			21,400,000			21,400,000
North Dakota System [Member]
Length of pipeline (in miles)			847			847
Number of pump stations (in stations)			23			23
Crude oil capacity (in barrels)			1,800,000			1,800,000
Enbridge Inc. [Member]
Ownership interest in affiliate of Partnership (in percentage)			40.30%	29.90%
Midcoast Energy Partners [Member]
Commitment fees and issuance costs (in dollars)				3.4
Payments to redeem common units				47
Common units redeemed				2,775,000
Midcoast Operating [Member]
Master Limited Partnership Ownership Interest (in percentage)						48.40%	61.00%
Ownership interest sold (in percentage)			12.60%
Cash received			350
IPO [Member] \| Midcoast Energy Partners [Member]
Number of common units issued (in shares)				18,500,000
Aggregate gross proceeds				$354.90
Over-Allotment Option [Member] \| Midcoast Energy Partners [Member]
Number of common units issued (in shares)				2,775,000
General Partner [Member]
Master Limited Partnership Ownership Interest (in percentage)			2.00%	2.00%
General Partner [Member] \| Midcoast Energy Partners [Member]
Master Limited Partnership Ownership Interest (in percentage)			100.00%
Subordinated Units [Member] \| Midcoast Energy Partners [Member]
Master Limited Partnership Ownership Interest (in percentage)			100.00%
Partnership Common Units [Member] \| Midcoast Energy Partners [Member]
Master Limited Partnership Ownership Interest (in percentage)			53.80%

[1]	The proceeds from the September 2012 equity issuance were used to fund a portion of our capital expansion projects and for general partnership purposes.

SUMMARY_OF_SIGNIFICANT_ACCOUNT2

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details)	12 Months Ended
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details)	Dec. 31, 2014
Additional period thereafter related to gains and losses deferred in AOCI	2 months
Minimum [Member] \| Commodity [Member]
Fluctuation in commodity price risk (in percentage)	10.00%
Maximum [Member] \| Commodity [Member]
Fluctuation in commodity price risk (in percentage)	15.00%
Texas Express NGL System [Member]
Ownership interest in joint venture (in percentage)	35.00%
Number of joint ventures (in entities)	2
Length of pipeline (in miles)	593

DISPOSITIONS_Details

DISPOSITIONS (Details) (USD $)	1 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Nov. 30, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
	tanks
	bbl
DISPOSITIONS [Abstract]
Proceeds from the sale of net assets	$40
Gain on sale of assets	$17.10		$17.10
Number of storage tanks sold (in tanks)	11
Capacity of storage units sold (in barrels)	1,150,000

NET_INCOME_PER_LIMITED_PARTNER2

NET INCOME PER LIMITED PARTNER UNIT (Narrative) (Details)	12 Months Ended
NET INCOME PER LIMITED PARTNER UNIT (Narrative) (Details)	Dec. 31, 2014
Class D Units [Member]
Number of units issued in transaction (in shares)	66,100,000
Incentive Distribution Units [Member]
Number of units issued in transaction (in shares)	1,000

NET_INCOME_PER_LIMITED_PARTNER3

NET INCOME PER LIMITED PARTNER UNIT (Formula for Distributing Available Cash in Partnership Agreement) (Details) (USD $)	6 Months Ended
	Dec. 31, 2014		Jun. 30, 2014
Minimum Quarterly Distribution [Member]
Portion of Quarterly Distribution Per Unit, maximum (in dollars per share)	$0.54		$0.30
Percentage Distributed to General Partner (in percentage)	2.00%	[1]	2.00%
Percentage Distributed to Limited partners (in percentage)	98.00%		98.00%
First Target Distribution [Member]
Portion of Quarterly Distribution Per Unit, minimum (in dollars per share)	$0.54		$0.30
Portion of Quarterly Distribution Per Unit, maximum (in dollars per share)			$0.35
Percentage Distributed to General Partner (in percentage)	25.00%	[1]	15.00%
Percentage Distributed to Limited partners (in percentage)	75.00%		85.00%
Second Target Distribution [Member]
Portion of Quarterly Distribution Per Unit, minimum (in dollars per share)			$0.35
Portion of Quarterly Distribution Per Unit, maximum (in dollars per share)			$0.50
Percentage Distributed to General Partner (in percentage)			25.00%
Percentage Distributed to Limited partners (in percentage)			75.00%
Over Second Target Distribution [Member]
Portion of Quarterly Distribution Per Unit, minimum (in dollars per share)			$0.50
Percentage Distributed to General Partner (in percentage)			50.00%
Percentage Distributed to Limited partners (in percentage)			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								12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net income (loss)	$354.30	$117.50	$112.50	$155.70	$43.10	$61.30	$123.70	($67.70)	$740		$160.40		$550.10
Less: Net income attributable to noncontrolling interest	-113.9	-70.7	-42.4	-36.3	-34	-20.3	-18.4	-15.6	-263.3		-88.3		-57
Less: Net income attributable to Series 1 preferred unit distributions									-90		-58.2
Less: Net income attributable to Accretion of discount on Series 1 preferred units									-14.9		-9.2
Net income attributable to general and limited partner ownership interests in Enbridge Energy Partners, L.P.	214.1	20.5	43.9	93.3	-16.8	14.9	89.9	-83.3	371.8		4.7		493.1
Incentive distributions									-39.1		-129.9		-116.3
Total distributed earnings to our General Partner, Class D units, and IDUs									-163.9		-144.1		-129.3
Total distributed earnings attributed to our common units and i-units									-731		-695.6		-636.3
Total distributed earnings									-894.9		-839.7		-765.6
Overdistributed earnings									-523.1		-835		-272.5
Weighted average limited partner units outstanding (basic) (in shares)									328,200,000		316,200,000		290,600,000
Basic and diluted earnings per unit:
Distributed earnings per unit (in dollars per share)									$2.23	[1]	$2.20	[1]	$2.19	[1]
Overdistributed earnings per limited partner unit (in dollars per share)									($1.56)	[2]	($2.59)	[2]	($0.92)	[2]
Net income (loss) per common unit and i-unit (basic) (in dollars per share)	$0.51	($0.04)	$0.02	$0.18	($0.15)	($0.05)	$0.18	($0.36)	$0.67	[3]	($0.39)	[3]	$1.27	[3]
Net income (loss) per common unit and i-unit (diluted) (in dollars per share)	$0.51	($0.04)	$0.02	$0.18	($0.15)	($0.05)	$0.18	($0.36)	$0.67	[3]	($0.39)	[3]	$1.27	[3]
Preferred Stock [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Anti-dilutive Preferred Units excluded (in shares)									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 (in shares)									66,100,000
General Partner [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net income attributable to general and limited partner ownership interests in Enbridge Energy Partners, L.P.									38.4		130.1		126.3
Distributed earnings attributed to our General Partner									-17.3		-14.2		-13
Class D Units [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Total distributed earnings to our General Partner, Class D units, and IDUs									($107.50)

[1]	Represents the total distributed earnings to common units and i-units divided by the weighted average number of common units and i-units outstanding for the period.
[2]	Represents the common units' 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 year ended December 31, 2014 and 2013, 43,201,310 anti-dilutive Preferred Units were excluded from the if-converted method of calculating diluted earnings per unit. For the year ended December 31, 2014, 66,100,000 anti-dilutive Class D units were excluded from the if-converted method of calculating diluted earnings per unit.

CASH_AND_CASH_EQUIVALENTS_Deta

CASH AND CASH EQUIVALENTS (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
CASH AND CASH EQUIVALENTS [Abstract]
Obligations paid but not yet presented to financial institution	$17.90	$24
Book overdrafts	$40	$49.10

INVENTORY_Details

INVENTORY (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
INVENTORY [Abstract]
Materials and supplies	$2.20	$2.10
Crude oil inventory	13.2	18
Natural gas and NGL inventory	78.8	74.8
Inventory, Net, Total	94.2	94.9
Charges related to cost of natural gas	$11.40	$3.40	$9.80

PROPERTY_PLANT_AND_EQUIPMENT_S

PROPERTY, PLANT AND EQUIPMENT (Schedule of Property, Plant and Equipment) (Details) (USD $)	12 Months Ended			9 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Sep. 30, 2013
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$18,467.90	$15,882.50
Accumulated depreciation	-2,775.20	-2,705.70
Property, plant and equipment, net	15,692.70	13,176.80
Asset impairment charges	15.6
Retirement of assets charged to accumulated depreciation	282.5
Louisiana Propylene Pipeline [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, net	0
Asset impairment charges	15.6
Land [Member]
Property, Plant and Equipment [Line Items]
Depreciation Rates
Property, plant and equipment	44.2	43.6
Rights-of-Way [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	851.8	666.2
Rights-of-Way [Member] \| Minimum [Member]
Property, Plant and Equipment [Line Items]
Depreciation Rates	1.80%
Rights-of-Way [Member] \| Maximum [Member]
Property, Plant and Equipment [Line Items]
Depreciation Rates	7.14%
Pipelines [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	9,585.40	8,035.80
Pipelines [Member] \| Minimum [Member]
Property, Plant and Equipment [Line Items]
Depreciation Rates	1.79%
Pipelines [Member] \| Maximum [Member]
Property, Plant and Equipment [Line Items]
Depreciation Rates	6.70%
Pumping Equipment, Buildings and Tanks [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	3,126.80	2,233
Useful life		30 years		22 years
Pumping Equipment, Buildings and Tanks [Member] \| Service Life [Member]
Property, Plant and Equipment [Line Items]
Reduction in depreciation expense	16.8	4.2
Pumping Equipment, Buildings and Tanks [Member] \| Minimum [Member]
Property, Plant and Equipment [Line Items]
Depreciation Rates	1.48%
Pumping Equipment, Buildings and Tanks [Member] \| Maximum [Member]
Property, Plant and Equipment [Line Items]
Depreciation Rates	6.67%
Compressors, Meters and Other Operating Equipment [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	2,072.70	1,989.80
Compressors, Meters and Other Operating Equipment [Member] \| Minimum [Member]
Property, Plant and Equipment [Line Items]
Depreciation Rates	1.80%
Compressors, Meters and Other Operating Equipment [Member] \| Maximum [Member]
Property, Plant and Equipment [Line Items]
Depreciation Rates	20.00%
Vehicles, Office Furniture and Equipment [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	413.9	322
Vehicles, Office Furniture and Equipment [Member] \| Minimum [Member]
Property, Plant and Equipment [Line Items]
Depreciation Rates	1.33%
Vehicles, Office Furniture and Equipment [Member] \| Maximum [Member]
Property, Plant and Equipment [Line Items]
Depreciation Rates	33.33%
Processing and Treating Plants [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	516	514.4
Processing and Treating Plants [Member] \| Minimum [Member]
Property, Plant and Equipment [Line Items]
Depreciation Rates	2.21%
Processing and Treating Plants [Member] \| Maximum [Member]
Property, Plant and Equipment [Line Items]
Depreciation Rates	2.73%
Construction in Progress [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$1,857.10	$2,077.70

PROPERTY_PLANT_AND_EQUIPMENT_A

PROPERTY, PLANT AND EQUIPMENT (Asset Retirement Obligation) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Regulatory Liabilities [Line Items]
Balance at beginning of period	$3.40	$3.40
Additions	113.9		0.4
Accretion expense	1.1
Liabilities settled	-21.6
Balance at end of period	96.8	3.4	3.4
Line 6B Pipeline [Member]
Regulatory Liabilities [Line Items]
Additions	67.2
Line 3 Pipeline [Member]
Regulatory Liabilities [Line Items]
Additions	$46.70

GOODWILL_Details

GOODWILL (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Goodwill [Line Items]
Goodwill	246.7	$246.70
Goodwill [Member]
Goodwill [Line Items]
Capital structure, debt	50.00%
Capital structure, equity	50.00%
Weighted Average [Member] \| Goodwill [Member]
Goodwill [Line Items]
Cost of capital	6.60%
Natural Gas [Member]
Goodwill [Line Items]
Goodwill	246.7	$246.70
Natural Gas [Member] \| Goodwill [Member]
Goodwill [Line Items]
Annual growth rate	5.00%

INTANGIBLE_ASSETS_Schedule_of_

INTANGIBLE ASSETS (Schedule of Intangible Assets) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Finite-Lived Intangible Assets [Line Items]
Gross Intangible Assets, beginning balance	$333.10	$310.80
Additions	8.1	22.3
Dispositions	-1
Intangible Assets, Gross, ending balance	340.2	333.1
Gross Accumulated Amortization, beginning balance	-69.9	-53.6
Amortization Expenses	-15.5	-16.3
Accumulated Amortization, Gross, ending balance	-85.4	-69.9
Intangible Assets, Net	254.8	263.2
Natural Gas Opportunities [Member]
Finite-Lived Intangible Assets [Line Items]
Gross Intangible Assets, beginning balance	291	291
Additions
Dispositions
Intangible Assets, Gross, ending balance	291	291
Gross Accumulated Amortization, beginning balance	-59.4	-49
Amortization Expenses	-10.3	-10.4
Accumulated Amortization, Gross, ending balance	-69.7	-59.4
Intangible Assets, Net	221.3	231.6
Customer Contracts [Member]
Finite-Lived Intangible Assets [Line Items]
Gross Intangible Assets, beginning balance	4.4	4.4
Additions
Dispositions
Intangible Assets, Gross, ending balance	4.4	4.4
Gross Accumulated Amortization, beginning balance	-1.7	-1.2
Amortization Expenses	-0.4	-0.5
Accumulated Amortization, Gross, ending balance	-2.1	-1.7
Intangible Assets, Net	2.3	2.7
Other Intangible Assets [Member]
Finite-Lived Intangible Assets [Line Items]
Gross Intangible Assets, beginning balance	37.7	15.4
Additions	8.1	22.3
Dispositions	-1
Intangible Assets, Gross, ending balance	44.8	37.7
Gross Accumulated Amortization, beginning balance	-8.8	-3.4
Amortization Expenses	-4.8	-5.4
Accumulated Amortization, Gross, ending balance	-13.6	-8.8
Intangible Assets, Net	$31.20	$28.90

INTANGIBLE_ASSETS_Narrative_De

INTANGIBLE ASSETS (Narrative) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014
Forecast of amortization expense associated with existing intangible assets for the years indicated:
2015	15.7
2016	13.5
2017	12.2
2018	12
2019	12
Natural Gas Opportunities [Member] \| Minimum [Member]
Finite-Lived Intangible Assets [Line Items]
Intangible assets, useful life (in years)	25 years
Natural Gas Opportunities [Member] \| Maximum [Member]
Finite-Lived Intangible Assets [Line Items]
Intangible assets, useful life (in years)	30 years
Underlying Reserve [Member]
Finite-Lived Intangible Assets [Line Items]
Intangible assets, useful life (in years)	25 years
Contributions in Aid of Construction [Member]
Finite-Lived Intangible Assets [Line Items]
Intangible assets, useful life (in years)	25 years
Computer Software, Intangible Asset [Member]
Finite-Lived Intangible Assets [Line Items]
Intangible assets, useful life (in years)	3 years

DEBT_Debt_Obligations_Details

DEBT (Debt Obligations) (Details) (USD $)	12 Months Ended
DEBT (Debt Obligations) (Details) (USD $)	Dec. 31, 2014		Dec. 31, 2013
Debt Instrument [Line Items]
Total Principal of Debt Obligations	$6,682,300,000		$4,985,000,000
Unamortized Discount	-7,100,000		-7,600,000
Current Maturities and short term debt			-200,000,000
Total Long Term Debt	6,675,200,000		4,777,400,000
Fixed Rate Debt Obligations [Member]
Debt Instrument [Line Items]
Approximate fair values of debt obligations	5,100,000,000		4,900,000,000
Commercial Paper [Member]
Debt Instrument [Line Items]
Interest Rate (in percentage)	0.50%	[1]	0.37%
Total Principal of Debt Obligations	612,300,000	[1]	300,000,000	[1]
Senior Notes [Member] \| 5.350% Senior Notes due 2014 [Member]
Debt Instrument [Line Items]
Maturity date	31-Dec-14
Interest Rate (in percentage)	5.35%
Total Principal of Debt Obligations			200,000,000
Senior Notes [Member] \| 5.875% Senior Notes due 2016 [Member]
Debt Instrument [Line Items]
Maturity date	31-Dec-16
Interest Rate (in percentage)	5.88%
Total Principal of Debt Obligations	300,000,000		300,000,000
Senior Notes [Member] \| 7.000% Senior Notes due 2018 [Member]
Debt Instrument [Line Items]
Maturity date	31-Dec-18
Interest Rate (in percentage)	7.00%
Total Principal of Debt Obligations	100,000,000		100,000,000
Senior Notes [Member] \| 6.500% Senior Notes due 2018 [Member]
Debt Instrument [Line Items]
Maturity date	31-Dec-18
Interest Rate (in percentage)	6.50%
Total Principal of Debt Obligations	400,000,000		400,000,000
Senior Notes [Member] \| 9.875% Senior Notes due 2019 [Member]
Debt Instrument [Line Items]
Maturity date	31-Dec-19
Interest Rate (in percentage)	9.88%
Total Principal of Debt Obligations	500,000,000		500,000,000
Senior Notes [Member] \| 5.200% Senior Notes due 2020 [Member]
Debt Instrument [Line Items]
Maturity date	31-Dec-20
Interest Rate (in percentage)	5.20%
Total Principal of Debt Obligations	500,000,000		500,000,000
Senior Notes [Member] \| 4.200% Senior Notes due 2021 [Member]
Debt Instrument [Line Items]
Maturity date	31-Dec-21
Interest Rate (in percentage)	4.20%
Total Principal of Debt Obligations	600,000,000		600,000,000
Senior Notes [Member] \| 7.125% Senior Notes due 2028 [Member]
Debt Instrument [Line Items]
Maturity date	31-Dec-28
Interest Rate (in percentage)	7.13%
Total Principal of Debt Obligations	100,000,000		100,000,000
Senior Notes [Member] \| 5.950% Senior Notes due 2033 [Member]
Debt Instrument [Line Items]
Maturity date	31-Dec-33
Interest Rate (in percentage)	5.95%
Total Principal of Debt Obligations	200,000,000		200,000,000
Senior Notes [Member] \| 6.300% Senior Notes due 2034 [Member]
Debt Instrument [Line Items]
Maturity date	31-Dec-34
Interest Rate (in percentage)	6.30%
Total Principal of Debt Obligations	100,000,000		100,000,000
Senior Notes [Member] \| 7.500% Senior Notes due 2038 [Member]
Debt Instrument [Line Items]
Maturity date	31-Dec-38
Interest Rate (in percentage)	7.50%
Total Principal of Debt Obligations	400,000,000		400,000,000
Senior Notes [Member] \| 5.500% Senior Notes due 2040 [Member]
Debt Instrument [Line Items]
Maturity date	31-Dec-40
Interest Rate (in percentage)	5.50%
Total Principal of Debt Obligations	550,000,000		550,000,000
Senior Notes [Member] \| 3.560% Series A Senior Notes due 2019 [Member] \| Midcoast Energy Partners [Member]
Debt Instrument [Line Items]
Maturity date	31-Dec-19
Interest Rate (in percentage)	3.56%
Total Principal of Debt Obligations	75,000,000
Senior Notes [Member] \| 4.040% Series B Senior Notes due 2021 [Member] \| Midcoast Energy Partners [Member]
Debt Instrument [Line Items]
Maturity date	31-Dec-21
Interest Rate (in percentage)	4.04%
Total Principal of Debt Obligations	175,000,000
Senior Notes [Member] \| 4.420% Series C Senior Notes due 2024 [Member] \| Midcoast Energy Partners [Member]
Debt Instrument [Line Items]
Maturity date	31-Dec-24
Interest Rate (in percentage)	4.42%
Total Principal of Debt Obligations	150,000,000
Credit Facilities [Member]
Debt Instrument [Line Items]
Maturity date, start	31-Dec-16
Maturity date, end	31-Dec-18
Interest Rate (in percentage)	1.29%
Total Principal of Debt Obligations	1,160,000,000
Credit Facilities [Member] \| Midcoast Energy Partners [Member]
Debt Instrument [Line Items]
Interest Rate (in percentage)	3.20%
Total Principal of Debt Obligations	360,000,000		335,000,000
Junior Subordinated Notes [Member]
Debt Instrument [Line Items]
Maturity date	31-Dec-67
Interest Rate (in percentage)	8.05%
Total Principal of Debt Obligations	$400,000,000		$400,000,000

[1]	Individual issuances of commercial paper generally mature in 90 days or less, but are supported by our Credit Facilities

DEBT_Interest_Cost_Details

DEBT (Interest Cost) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Interest Cost
Interest expense	$403.20	$320.40	$345
Interest capitalized	45.3	51.7	36.3
Interest cost incurred	448.5	372.1	381.3
Interest paid	$332.40	$342.30	$352.10
Weighted average interest rate (in percentage)	6.10%	6.20%	6.40%

DEBT_Maturities_of_Third_Party

DEBT (Maturities of Third Party Debt) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Scheduled maturities of outstanding third-party debt:
2015
2016	950
2017	360
2018	1,622.30
2019	575
Thereafter	3,175
Total	$6,682.30	$4,985

DEBT_Credit_Facility_Details

DEBT (Credit Facility) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Feb. 03, 2014
Line of Credit Facility [Line Items]
Total credit limit under Credit Facilities	$2,625
Principal amount of commercial paper outstanding	612.3	300
Amounts outstanding under Credit Facilities	1,160
Letters of credit outstanding	330.2
Total amount available	522.5
Net borrowings under facilities	1,185	335
Credit Facilities, Excluding Commercial Paper [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	2,625
Credit Facility [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	1,975
Credit facility maturity date	26-Sep-19
Net borrowings under facilities	1,160
Proceeds from lines of credit	2,120
Repayments of lines of credit	960
Credit Facility [Member] \| LIBOR [Member]
Line of Credit Facility [Line Items]
Amounts outstanding under Credit Facilities	1,160
Credit Facility [Member] \| Portion of Credit Facility Due in 2018 [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	175
Credit facility maturity date	26-Sep-18
364-Day Credit Facility [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	650
Facility term	364 days
Credit facility maturity date	3-Jul-15
Standby Letters of Credit [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$220			$200

DEBT_Commercial_Paper_Details

DEBT (Commercial Paper) (Details) (USD $)	12 Months Ended
DEBT (Commercial Paper) (Details) (USD $)	Dec. 31, 2014		Dec. 31, 2013	Dec. 31, 2012
Principal amount of commercial paper issuances	$612,300,000		$300,000,000
Borrowings of Commercial Paper	11,200,000,000
Repayments of Commercial Paper	10,900,000,000
Net commercial paper borrowings (repayments) (Note 10)	312,100,000		-859,900,000	884,900,000
Commercial Paper [Member]
Commercial paper aggregate principal amount supported by Credit Facilities	$1,500,000,000
Weighted average interest rate of Commercial paper excluding the effect of interest rate hedging activities	0.50%	[1]	0.37%

[1]	Individual issuances of commercial paper generally mature in 90 days or less, but are supported by our Credit Facilities

DEBT_Senior_Notes_and_Junior_S

DEBT (Senior Notes and Junior Subordinated Notes) (Details) (USD $)	12 Months Ended	3 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2017	Dec. 31, 2013
Debt Instrument [Line Items]
Principal amount of debt	$6,682.30		$4,985
8.050% Junior Subordinated Notes due 2067 [Member]
Debt Instrument [Line Items]
Interest Rate (in percentage)	8.05%
Maturity date	31-Dec-67
Principal amount of debt	400		400
8.050% Junior Subordinated Notes due 2067 [Member] \| Scenario, Forecast [Member]
Debt Instrument [Line Items]
Spread on variable rate (in percentage)		3.80%
Senior Notes [Member] \| 7.000% Senior Notes due 2018 [Member]
Debt Instrument [Line Items]
Interest Rate (in percentage)	7.00%
Maturity date	31-Dec-18
Principal amount of debt	100		100
Senior Notes [Member] \| 7.125% Senior Notes due 2028 [Member]
Debt Instrument [Line Items]
Interest Rate (in percentage)	7.13%
Maturity date	31-Dec-28
Principal amount of debt	100		100
Senior Notes [Member] \| Enbridge Energy, Limited Partnership [Member]
Debt Instrument [Line Items]
Principal amount of debt	200
Senior Notes [Member] \| Enbridge Energy, Limited Partnership [Member] \| 7.000% Senior Notes due 2018 [Member]
Debt Instrument [Line Items]
Interest Rate (in percentage)	7.00%
Principal amount of debt	100
Senior Notes [Member] \| Enbridge Energy, Limited Partnership [Member] \| 7.125% Senior Notes due 2028 [Member]
Debt Instrument [Line Items]
Interest Rate (in percentage)	7.13%
Principal amount of debt	$100

DEBT_MEP_Credit_Agreement_Deta

DEBT (MEP Credit Agreement) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Line of Credit Facility [Line Items]
Total credit available	$2,625
Carrying amount, credit facilities	1,160
Net proceeds under credit facilities (Note 10)	1,185	335
Midcoast Energy Partners [Member]
Line of Credit Facility [Line Items]
Repayments of lines of credit	6,895
Proceeds from lines of credit	6,920
Net proceeds under credit facilities (Note 10)	25
Senior Revolving Credit Facility [Member] \| Midcoast Energy Partners [Member]
Line of Credit Facility [Line Items]
Total Credit available under Credit Facilities	1,000
Total credit available	850
Debt, weighted average interest rate (in percentage)	3.20%
Carrying amount, credit facilities	360
Total leverage ratio	5
Interest expense covenant ratio, debt instrument	2.5
Facility term	2 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]
Total Credit available under Credit Facilities	140
Credit facility maturity date	13-Nov-16
Senior Revolving Credit Facility [Member] \| Scenario, Acquisition [Member] \| Midcoast Energy Partners [Member]
Line of Credit Facility [Line Items]
Total leverage ratio	5.5
Senior Revolving Credit Facility [Member] \| Minimum [Member] \| Midcoast Energy Partners [Member]
Line of Credit Facility [Line Items]
Line of credit facility, commitment fee percentage (in percentage)	0.30%
Senior Revolving Credit Facility [Member] \| Minimum [Member] \| Base Rate [Member] \| Midcoast Energy Partners [Member]
Line of Credit Facility [Line Items]
Spread on variable rate (in percentage)	0.75%
Senior Revolving Credit Facility [Member] \| Minimum [Member] \| Eurocurrency Rate [Member] \| Midcoast Energy Partners [Member]
Line of Credit Facility [Line Items]
Spread on variable rate (in percentage)	1.75%
Senior Revolving Credit Facility [Member] \| Maximum [Member] \| Midcoast Energy Partners [Member]
Line of Credit Facility [Line Items]
Line of credit facility, commitment fee percentage (in percentage)	0.50%
Senior Revolving Credit Facility [Member] \| Maximum [Member] \| Base Rate [Member] \| Midcoast Energy Partners [Member]
Line of Credit Facility [Line Items]
Spread on variable rate (in percentage)	1.75%
Senior Revolving Credit Facility [Member] \| Maximum [Member] \| Eurocurrency Rate [Member] \| Midcoast Energy Partners [Member]
Line of Credit Facility [Line Items]
Spread on variable rate (in percentage)	2.75%
Letter of Credit [Member] \| Midcoast Energy Partners [Member]
Line of Credit Facility [Line Items]
Total credit available	90
Swing Line Facility [Member] \| Midcoast Energy Partners [Member]
Line of Credit Facility [Line Items]
Total credit available	$75
Secured Debt [Member] \| Midcoast Energy Partners [Member]
Line of Credit Facility [Line Items]
Total leverage ratio	4.25
Secured Debt [Member] \| Scenario, Acquisition [Member] \| Midcoast Energy Partners [Member]
Line of Credit Facility [Line Items]
Total leverage ratio	4.75

DEBT_MEP_Private_Debt_Issuance

DEBT (MEP Private Debt Issuance) (Details) (Senior Notes [Member], Midcoast Energy Partners [Member], USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014
	contracts
Debt Instrument [Line Items]
Debt, 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, face amount	75
Maturity date	31-Dec-19
Interest Rate (in percentage)	3.56%
4.040% Series B Senior Notes due 2021 [Member]
Debt Instrument [Line Items]
Debt, face amount	175
Maturity date	31-Dec-21
Interest Rate (in percentage)	4.04%
4.420% Series C Senior Notes due 2024 [Member]
Debt Instrument [Line Items]
Debt, face amount	$150
Maturity date	31-Dec-24
Interest Rate (in percentage)	4.42%

PARTNERS_CAPITAL_Narrative_Det

PARTNERS' CAPITAL (Narrative) (Details) (USD $)	6 Months Ended			1 Months Ended		12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014		Jun. 30, 2014	Sep. 30, 2013	Mar. 31, 2013	Dec. 31, 2014
Percentage of available cash required to be distributed (in percentage)	100.00%					100.00%
Minimum Quarterly Distribution [Member]
Portion of Quarterly Distribution Per Unit, Maximum (in dollars per share)	$0.54		$0.30
Percentage Distributed to General Partner and IDUs (in percentage)	2.00%	[1]	2.00%
First Target Distribution [Member]
Portion of Quarterly Distribution Per Unit, Minimum (in dollars per share)	$0.54		$0.30
Portion of Quarterly Distribution Per Unit, Maximum (in dollars per share)			$0.35
Percentage Distributed to General Partner and IDUs (in percentage)	25.00%	[1]	15.00%
Second Target Distribution [Member]
Portion of Quarterly Distribution Per Unit, Minimum (in dollars per share)			$0.35
Portion of Quarterly Distribution Per Unit, Maximum (in dollars per share)			$0.50
Percentage Distributed to General Partner and IDUs (in percentage)			25.00%
Over Second Target Distribution [Member]
Portion of Quarterly Distribution Per Unit, Minimum (in dollars per share)			$0.50
Percentage Distributed to General Partner and IDUs (in percentage)			50.00%
Enbridge Energy Management, LLC [Member]
Stock issued, new issues (in shares)				8,424,686	10,350,000
Proceeds from issuance of shares (in dollars)				$235.60	$272.90
Offering price per share (in dollars per share)				$28.02	$26.44
Number of trading days						10 days
Class D Units [Member]
Number of units issued in transaction (in shares)						66,100,000
Conversion ratio (in percentage)						100.00%
Redemption term						30 years
Redemption rate (in percentage)						105.00%
Notional value (in dollars per share)						31.35
Preference in liquidation (in percentage)	20.00%					20.00%
Preference in liquidation, annual increase (in percentage)						20.00%
Maximum preference in liquidation (in percentage)						100.00%
Fair value of capital distribution (in dollars)						2,480
Incentive Distribution Units [Member]
Number of units issued in transaction (in shares)						1,000
Portion of Quarterly Distribution Per Unit, Minimum (in dollars per share)						0.5435
Percentage Distributed to General Partner and IDUs (in percentage)						23.00%
Distribution period						5 years
Fair value of capital distribution (in dollars)						491.7

[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.

PARTNERS_CAPITAL_Schedule_of_E

PARTNERS' CAPITAL (Schedule of Equity Interests) (Details)	12 Months Ended
PARTNERS' CAPITAL (Schedule of Equity Interests) (Details)	Dec. 31, 2014		Dec. 31, 2013
Master Limited Partnership Ownership Interest (in percentage)	100.00%		100.00%
Enbridge Energy Company, Inc [Member] \| Enbridge Energy Management, LLC [Member]
Master Limited Partnership Ownership Interest (in percentage)	11.70%		11.70%
Preferred Partner [Member]
Master Limited Partnership Ownership Interest (in percentage)	9.60%		11.50%
Limited Partner [Member]
Master Limited Partnership Ownership Interest (in percentage)	98.00%
Limited Partner [Member] \| Public Common Unitholders [Member] \| Class A Common Units [Member]
Master Limited Partnership Ownership Interest (in percentage)	46.40%		55.20%
Limited Partner [Member] \| Public Common Unitholders [Member] \| Class D Units [Member]
Master Limited Partnership Ownership Interest (in percentage)	14.70%
Limited Partner [Member] \| Enbridge Energy Company, Inc [Member] \| Class A Common Units [Member]
Master Limited Partnership Ownership Interest (in percentage)	10.40%		12.30%
Limited Partner [Member] \| Enbridge Energy Company, Inc [Member] \| Class B Common Units [Member]
Master Limited Partnership Ownership Interest (in percentage)	1.70%		2.10%
Limited Partner [Member] \| Enbridge Energy Management, LLC [Member] \| I Units [Member]
Master Limited Partnership Ownership Interest (in percentage)	15.20%	[1]	16.90%	[1]
General Partner [Member]
Master Limited Partnership Ownership Interest (in percentage)	2.00%		2.00%

[1]	For the years ended December 31, 2014 and 2013, our General Partner 11.7% of Enbridge Management, which owns all of our i-units.

PARTNERS_CAPITAL_Series_1_Pref

PARTNERS' CAPITAL (Series 1 Preferred Unit Purchase Agreement) (Details) (USD $)	0 Months Ended	12 Months Ended
In Millions, except Share data, unless otherwise specified	7-May-13	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Proceeds from sale of units (in dollars)	$1,200		$1,199.20
Dividend rate (in percentage)		7.50%
Period of reset related to quarterly cash contributions		5 years
Conversion price per unit (in dollars per share)		$27.78
Early conversion price per unit (in dollars per share)		$25
Distribution deferral date		30-Jun-15
Optional conversion date		1-Jun-16
Rating threshold at which securities are redeemable (in percentage)		50.00%
Series 1 Preferred Interests [Member]
Number of units issued (in shares)	48,000,000		48,000,000
Beneficial conversion feature of preferred units			($47.70)

PARTNERS_CAPITAL_Schedule_of_C

PARTNERS' CAPITAL (Schedule of Class A Common Unit Equity Issuances) (Details) (USD $)	1 Months Ended		12 Months Ended
In Millions, except Share data, unless otherwise specified	Sep. 30, 2012		Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Net Proceeds Including General Partner Contribution	$456.20	[1]		$519.30	$457
General Partner [Member]
General Partner Contribution	9.4	[1],[2]		10.8	9.4
Class A Common Units [Member]
Number of Class A common units Issued (in shares)	16,100,000	[1]
Offering Price per Class A common unit (in dollars per share)	$28.64	[1],[3]
Net Proceeds to the Partnership (in dollars)	$446.80	[1],[4]

[1]	The proceeds from the September 2012 equity issuance were used to fund a portion of our capital expansion projects and for general partnership purposes.
[2]	Contributions made by the General Partner to maintain its 2% general partner interest.
[3]	The offering price per unit listed for the Equity Distribution Agreement, or EDA, issuances is a calculated average unit price for the periods indicated.
[4]	Net of underwriters' fees and discounts, commissions and issuance expenses if any.

PARTNERS_CAPITAL_Distribution_

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

12 Months Ended

0 Months Ended

1 Months Ended

0 Months Ended

In Millions, except Share data, unless otherwise specified

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Feb. 14, 2014

Feb. 14, 2013

Feb. 14, 2012

15-May-14

15-May-13

15-May-12

Aug. 14, 2014

Aug. 14, 2013

Aug. 14, 2012

Nov. 14, 2014

Nov. 14, 2013

Nov. 14, 2012

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

$2.20

$2.17

$2.15

Cash available for distribution

$874.70

$825

$747

Distribution Made to Member or Limited Partner, Cash Distributions Paid

727.8

708.9

660.3

Amount of Distribution

731

695.6

636.3

i-Units [Member]

Amount of Distribution

143.9

[1]

113.8

[1]

Units issued in lieu of cash distributions

4,562,088

3,769,989

2,632,090

General Partner [Member]

Distribution Made to Member or Limited Partner, Cash Distributions Paid

[2]

2.3

[2]

1.7

[2]

First Quarter Distribution [Member]

Distribution Declaration Date

30-Jan-14

30-Jan-13

30-Jan-12

Record Date

7-Feb-14

7-Feb-13

7-Feb-12

Distribution Payment Date

14-Feb-14

14-Feb-13

14-Feb-12

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

$0.54

$0.53

Cash available for distribution

213.7

198.9

180.3

Distribution Made to Member or Limited Partner, Cash Distributions Paid

178.4

176.1

159.4

First Quarter Distribution [Member] | i-Units [Member]

Amount of Distribution

34.6

[1]

22.4

[1]

20.5

[1]

First Quarter Distribution [Member] | General Partner [Member]

Distribution Made to Member or Limited Partner, Cash Distributions Paid

0.7

[2]

0.4

[2]

0.4

[2]

Second Quarter Distribution [Member]

Distribution Declaration Date

30-Apr-14

30-Apr-13

30-Apr-12

Record Date

8-May-14

8-May-13

7-May-12

Distribution Payment Date

15-May-14

15-May-13

15-May-12

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

$0.54

$0.53

Cash available for distribution

214.5

206.2

180.7

Distribution Made to Member or Limited Partner, Cash Distributions Paid

178.5

177.2

159.4

Second Quarter Distribution [Member] | i-Units [Member]

Amount of Distribution

35.3

[1]

28.4

[1]

20.9

[1]

Second Quarter Distribution [Member] | General Partner [Member]

Distribution Made to Member or Limited Partner, Cash Distributions Paid

0.7

[2]

0.6

[2]

0.4

[2]

Third Quarter Distribution [Member]

Distribution Declaration Date

31-Jul-14

29-Jul-13

30-Jul-12

Record Date

7-Aug-14

7-Aug-13

7-Aug-12

Distribution Payment Date

14-Aug-14

14-Aug-13

14-Aug-12

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

$0.56

$0.54

Cash available for distribution

224.7

206.8

187.5

Distribution Made to Member or Limited Partner, Cash Distributions Paid

187.2

177.3

165.4

Third Quarter Distribution [Member] | i-Units [Member]

Amount of Distribution

36.7

[1]

28.9

[1]

21.6

[1]

Third Quarter Distribution [Member] | General Partner [Member]

Distribution Made to Member or Limited Partner, Cash Distributions Paid

0.8

[2]

0.6

[2]

0.5

[2]

Fourth Quarter Distribution [Member]

Distribution Declaration Date

31-Oct-14

31-Oct-13

31-Oct-12

Record Date

7-Nov-14

7-Nov-13

7-Nov-12

Distribution Payment Date

14-Nov-14

14-Nov-13

14-Nov-12

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

$0.56

$0.54

Cash available for distribution

221.8

213.1

198.5

Distribution Made to Member or Limited Partner, Cash Distributions Paid

183.7

178.3

176.1

Fourth Quarter Distribution [Member] | i-Units [Member]

Amount of Distribution

37.3

[1]

34.1

[1]

Fourth Quarter Distribution [Member] | General Partner [Member]

Distribution Made to Member or Limited Partner, Cash Distributions Paid

$0.80

[2]

$0.70

[2]

$0.40

[2]

[1]

We issued 4,562,088, 3,769,989 and 2,632,090 i-units to Enbridge Management, L.L.C., the sole owner of our i-units, during 2014, 2013 and 2012, respectively, in lieu of cash.

[2]

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

RELATED_PARTY_TRANSACTIONS_Joi

RELATED PARTY TRANSACTIONS (Joint Funding Arrangement Discussions) (Details) (USD $)	12 Months Ended			0 Months Ended	6 Months Ended	0 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Jan. 02, 2015	Jun. 27, 2013	Nov. 13, 2013
Operating and administrative	$950	$918.40	$840.50
Interest expense, net (Notes 10 and 14)	403.2	320.4	345
General Partners' equity contributions	1,391.60	1,148.50	350.9
Cost of natural gas	5,145.90	4,948.90	4,570.10
Other revenues from transactions with related party	0.8	0.8	0.8
Repayment of debt	12	12	12
Schedule of Equity Method Investments [Line Items]
Equity loss from investment in joint venture	13.2
Texas Express NGL System [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest in joint venture (in percentage)	35.00%
Number of joint ventures (in entities)	2
Equity Investment in Joint Venture	380.6	371.3
Equity loss from investment in joint venture	13.2	-1
Length of pipeline (in miles)	593
Transportation commitments (in Bpd)	120,000
Subsequent Event [Member]
Repayment of debt				306
Alberta Clipper Pipeline [Member] \| Subsequent Event [Member]
Percentage of interest acquired (in percentage)				66.70%
Alberta Clipper Pipeline [Member] \| Class E Units [Member] \| Subsequent Event [Member]
Number of units issued (in shares)				18,114,975
Value of equity transferred				694
Affiliated Entity [Member]
Operating and administrative	472	437.6	421.7
Cost of natural gas	119.2	119.5	287.9
Pipeline Transportation and Demand Fees from Texas Express NGL System [Member]
Related party expenses	21.9	3.2
Operation Services Transactions [Member]
Rate charged for monthly fixed fee	8.33%
Related party expenses	150.9	154.9	133
General and Administrative Services Transactions [Member]
Related party expenses	179	284.1	291.1
Construction Project Work Force Cost Transactions [Member]
Related party expenses	44.3	51.7	33.1
Administration and Cleanup Efforts for Crude Oil Releases [Member]
Related party expenses	0.4	0.5	4.1
Alberta Clipper Pipeline [Member]
Maximum loan amount of related party note payable	400
Interest rate of related party note payable (in percentage)	5.20%
Amortization period of Term Note	30 years
Interest expense, net (Notes 10 and 14)	24.3	25.2	26.2
Eastern Access Pipeline [Member]
General Partners' equity contributions	622.5	609.2
Ownership interest in affiliate of Partnership (in percentage)	25.00%				40.00%
Proceeds from (repurchase of) equity					90.2
Noncontrolling interest, ownership by parent (in percentage)	75.00%				60.00%
Option period to increase economic interest	1 year
Option to purchase additional interest (in percentage)	15.00%
US Mainline Expansion [Member]
General Partners' equity contributions	577.5	159.9
Ownership interest in affiliate of Partnership (in percentage)	25.00%				40.00%
Proceeds from (repurchase of) equity					12
Noncontrolling interest, ownership by parent (in percentage)	75.00%				60.00%
Option period to increase economic interest	1 year
Option to purchase additional interest (in percentage)	15.00%
Midcoast Energy Partners [Member]
Ownership interest in affiliate of Partnership (in percentage)						39.00%
Amount of credit agreement						$250
Number of days of notice to terminate Working Capital Agreement	30 days

RELATED_PARTY_TRANSACTIONS_Sal

RELATED PARTY TRANSACTIONS (Sale of AR) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Net value of receivables sold	$4,987	$2,241.50
Proceeds from Sale of Receivables	4,985.70	2,235.70
AR Sales, Max Amount Outstanding	450
Restricted cash (Notes 12 and 14)	97	69.4
Sold Receivables that have not been collected at the balance sheet date.	378	380.1
Sale of Accounts Receivable to Affiliate [Member]
Restricted cash (Notes 12 and 14)	$71.90	$69.40

RELATED_PARTY_TRANSACTIONS_Gen

RELATED PARTY TRANSACTIONS (General Partner Equity Transactions) (Details) (USD $)	1 Months Ended		12 Months Ended			0 Months Ended
In Millions, except Share data, unless otherwise specified	Sep. 30, 2012		Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	7-May-13
Related Party Transaction [Line Items]
Master Limited Partnership Ownership Interest (in percentage)			100.00%	100.00%
Net Proceeds Including General Partner Contribution	$456.20	[1]		$519.30	$457
Class A Common Units [Member]
Related Party Transaction [Line Items]
Number of Class A common units Issued (in shares)	16,100,000	[1]
Offering Price per Class A common unit (in dollars per share)	$28.64	[1],[2]
Net Proceeds to the Partnership (in dollars)	446.8	[1],[3]
Limited Partner [Member]
Related Party Transaction [Line Items]
Master Limited Partnership Ownership Interest (in percentage)			98.00%
Limited Partner [Member] \| Class A Common Units [Member]
Related Party Transaction [Line Items]
Distributions to partners			558.5	552.6	521.2
Number of Class A common units Issued (in shares)					16,164,464
Net Proceeds to the Partnership (in dollars)					418.5
Limited Partner [Member] \| Class B Common Units [Member]
Related Party Transaction [Line Items]
Distributions to partners			17.3	17	16.8
Number of Class A common units Issued (in shares)
Net Proceeds to the Partnership (in dollars)					8.4
Limited Partner [Member] \| Class D Units [Member]
Related Party Transaction [Line Items]
Distributions to partners			69.8
Limited Partner [Member] \| I Units [Member]
Related Party Transaction [Line Items]
Distributions to partners
Number of Class A common units Issued (in shares)				18,774,686
Net Proceeds to the Partnership (in dollars)				508.5	22.7
Limited Partner [Member] \| Enbridge Energy Company, Inc [Member] \| Class A Common Units [Member]
Related Party Transaction [Line Items]
Units outstanding (in shares)			46,518,336
Master Limited Partnership Ownership Interest (in percentage)			10.40%	12.30%
Limited Partner [Member] \| Enbridge Energy Company, Inc [Member] \| Class B Common Units [Member]
Related Party Transaction [Line Items]
Units outstanding (in shares)			7,825,500
Master Limited Partnership Ownership Interest (in percentage)			1.70%	2.10%
General Partner [Member]
Related Party Transaction [Line Items]
Master Limited Partnership Ownership Interest (in percentage)			2.00%	2.00%
Distributions to partners			79.5	139.3	122.3
General Partner Contribution	9.4	[1],[4]		10.8	9.4
Preferred Partner [Member]
Related Party Transaction [Line Items]
Master Limited Partnership Ownership Interest (in percentage)			9.60%	11.50%
Distributions to partners			90	58.2
Number of Class A common units Issued (in shares)				48,000,000		48,000,000
Net Proceeds to the Partnership (in dollars)				1,199.20
Preferred Partner [Member] \| Enbridge Energy Company, Inc [Member]
Related Party Transaction [Line Items]
Units outstanding (in shares)			48,000,000
General Partner [Member] \| Limited Partner [Member] \| Class A Common Units [Member]
Related Party Transaction [Line Items]
Distributions to partners			102.2	101.1	100.1
General Partner [Member] \| Limited Partner [Member] \| Class B Common Units [Member]
Related Party Transaction [Line Items]
Distributions to partners			$17.20	$17	$16.80

[1]	The proceeds from the September 2012 equity issuance were used to fund a portion of our capital expansion projects and for general partnership purposes.
[2]	The offering price per unit listed for the Equity Distribution Agreement, or EDA, issuances is a calculated average unit price for the periods indicated.
[3]	Net of underwriters' fees and discounts, commissions and issuance expenses if any.
[4]	Contributions made by the General Partner to maintain its 2% general partner interest.

RELATED_PARTY_TRANSACTIONS_Dis

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

12 Months Ended

0 Months Ended

1 Months Ended

0 Months Ended

1 Months Ended

0 Months Ended

In Millions, unless otherwise specified

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Feb. 14, 2014

Feb. 14, 2013

Feb. 14, 2012

15-May-14

15-May-13

15-May-12

Aug. 14, 2014

Aug. 14, 2013

Aug. 14, 2012

Nov. 14, 2014

Nov. 14, 2013

Nov. 14, 2012

Feb. 14, 2014

15-May-14

Nov. 14, 2014

Total amount of distribution paid

$727.80

$708.90

$660.30

First Quarter Distribution [Member]

Distribution Declaration Date

30-Jan-14

30-Jan-13

30-Jan-12

Distribution Payment Date

14-Feb-14

14-Feb-13

14-Feb-12

Total amount of distribution paid

178.4

176.1

159.4

Second Quarter Distribution [Member]

Distribution Declaration Date

30-Apr-14

30-Apr-13

30-Apr-12

Distribution Payment Date

15-May-14

15-May-13

15-May-12

Total amount of distribution paid

178.5

177.2

159.4

Third Quarter Distribution [Member]

Distribution Declaration Date

31-Jul-14

29-Jul-13

30-Jul-12

Distribution Payment Date

14-Aug-14

14-Aug-13

14-Aug-12

Total amount of distribution paid

187.2

177.3

165.4

Fourth Quarter Distribution [Member]

Distribution Declaration Date

31-Oct-14

31-Oct-13

31-Oct-12

Distribution Payment Date

14-Nov-14

14-Nov-13

14-Nov-12

Total amount of distribution paid

183.7

178.3

176.1

Midcoast Energy Partners [Member]

Amount Paid To Parent

28.5

Amount paid to the noncontrolling interest

24.2

Total amount of distribution paid

52.7

Midcoast Energy Partners [Member] | First Quarter Distribution [Member]

Distribution Declaration Date

29-Jan-14

Distribution Payment Date

14-Feb-14

Amount Paid To Parent

4.2

Amount paid to the noncontrolling interest

3.5

Total amount of distribution paid

7.7

Midcoast Energy Partners [Member] | Second Quarter Distribution [Member]

Distribution Declaration Date

29-Apr-14

Distribution Payment Date

15-May-14

Amount Paid To Parent

7.8

Amount paid to the noncontrolling interest

6.6

Total amount of distribution paid

14.4

Midcoast Energy Partners [Member] | Third Quarter Distribution [Member]

Distribution Declaration Date

31-Jul-14

Distribution Payment Date

14-Aug-14

Amount Paid To Parent

8.1

Amount paid to the noncontrolling interest

6.9

Total amount of distribution paid

Midcoast Energy Partners [Member] | Fourth Quarter Distribution [Member]

Distribution Declaration Date

30-Oct-14

Distribution Payment Date

14-Nov-14

Amount Paid To Parent

8.4

Amount paid to the noncontrolling interest

7.2

Total amount of distribution paid

15.6

Alberta Clipper Pipeline [Member]

Amount Paid To Parent

30.5

26.9

Amount paid to the noncontrolling interest

53.8

59.9

Total amount of distribution paid

91.5

80.7

89.9

Alberta Clipper Pipeline [Member] | First Quarter Distribution [Member]

Distribution Declaration Date

30-Jan-14

30-Jan-13

30-Jan-12

Distribution Payment Date

14-Feb-14

14-Feb-13

14-Feb-12

Amount Paid To Parent

6.4

6.9

7.9

Amount paid to the noncontrolling interest

12.8

13.8

15.8

Total amount of distribution paid

19.2

20.7

23.7

Alberta Clipper Pipeline [Member] | Second Quarter Distribution [Member]

Distribution Declaration Date

30-Apr-14

30-Apr-13

30-Apr-12

Distribution Payment Date

15-May-14

15-May-13

15-May-12

Amount Paid To Parent

6.6

7.5

8.4

Amount paid to the noncontrolling interest

13.1

14.9

16.8

Total amount of distribution paid

19.7

22.4

25.2

Alberta Clipper Pipeline [Member] | Third Quarter Distribution [Member]

Distribution Declaration Date

31-Jul-14

29-Jul-13

30-Jul-12

Distribution Payment Date

14-Aug-14

14-Aug-13

14-Aug-12

Amount Paid To Parent

7.4

5.5

7.2

Amount paid to the noncontrolling interest

14.8

14.4

Total amount of distribution paid

22.2

16.5

21.6

Alberta Clipper Pipeline [Member] | Fourth Quarter Distribution [Member]

Distribution Declaration Date

31-Oct-14

31-Oct-13

31-Oct-12

Distribution Payment Date

14-Nov-14

14-Nov-13

14-Nov-12

Amount Paid To Parent

10.1

6.5

Amount paid to the noncontrolling interest

20.3

14.1

12.9

Total amount of distribution paid

30.4

21.1

19.4

Series EA [Member]

Amount Paid To Parent

22.7

Amount paid to the noncontrolling interest

66.9

Total amount of distribution paid

89.6

Series EA [Member] | Second Quarter Distribution [Member]

Distribution Declaration Date

29-Apr-14

Distribution Payment Date

15-May-14

Amount Paid To Parent

2.5

Amount paid to the noncontrolling interest

6.5

Total amount of distribution paid

Series EA [Member] | Third Quarter Distribution [Member]

Distribution Declaration Date

31-Jul-14

Distribution Payment Date

14-Aug-14

Amount Paid To Parent

5.6

Amount paid to the noncontrolling interest

16.7

Total amount of distribution paid

22.3

Series EA [Member] | Fourth Quarter Distribution [Member]

Distribution Declaration Date

31-Oct-14

Distribution Payment Date

14-Nov-14

Amount Paid To Parent

14.6

Amount paid to the noncontrolling interest

43.7

Total amount of distribution paid

58.3

Series ME Interests [Member] | Fourth Quarter Distribution [Member]

Distribution Declaration Date

31-Oct-14

Distribution Payment Date

14-Nov-14

Amount Paid To Parent

0.6

Amount paid to the noncontrolling interest

1.9

Total amount of distribution paid

$2.50

RELATED_PARTY_TRANSACTIONS_Cas

RELATED PARTY TRANSACTIONS (Cash Activity for A1 Credit Agreement and A1 Term Note) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Repayments	($12)	($12)	($12)
Notes Payable, Other Payables [Member]
Beginning Balance	318	330
Repayments	-12	-12
Ending Balance	$306	$318

RELATED_PARTY_TRANSACTIONS_Sch

RELATED PARTY TRANSACTIONS (Schedule of Net Income Attributable to Noncontrolling Interests) (Details) (USD $)	3 Months Ended								12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Related Party Transaction [Line Items]
Noncontrolling interest (Note 12)	$113.90	$70.70	$42.40	$36.30	$34	$20.30	$18.40	$15.60	$263.30	$88.30	$57
Alberta Clipper Interests [Member]
Related Party Transaction [Line Items]
Noncontrolling interest (Note 12)									54.6	52.6	53.9
Eastern Access Interests [Member]
Related Party Transaction [Line Items]
Noncontrolling interest (Note 12)									145.3	32.1	3.4
U.S. Mainline Expansion Interests [Member]
Related Party Transaction [Line Items]
Noncontrolling interest (Note 12)									33.8	4.3	-0.3
Midcoast Energy Partners, L.P. [Member]
Related Party Transaction [Line Items]
Noncontrolling interest (Note 12)									$29.60	($0.70)

RELATED_PARTY_TRANSACTIONS_Mid

RELATED PARTY TRANSACTIONS (Midcoast Agreements) (Details) (Midcoast Energy Partners [Member], USD $)	0 Months Ended	12 Months Ended
	Nov. 13, 2013	Dec. 31, 2014
Related Party Transaction [Line Items]
Ownership interest in affiliate of Partnership (in percentage)	39.00%
Reimbursement from Affiliate	$304,500,000
Proceeds from Contributions from Affiliates	323,400,000
General and Administrative Services Transactions [Member]
Related Party Transaction [Line Items]
General and administrative services, reduction		25,000,000
Minimum [Member]
Related Party Transaction [Line Items]
Ownership interest in affiliate of Partnership (in percentage)		20.00%
Minimum [Member] \| Omnibus Agreement [Member]
Related Party Transaction [Line Items]
Other commitment		500,000
Maximum [Member] \| Omnibus Agreement [Member]
Related Party Transaction [Line Items]
Other commitment		15,000,000
Maximum [Member] \| Financial Support Agreement [Member]
Related Party Transaction [Line Items]
Other commitment		$700,000,000

COMMITMENTS_AND_CONTINGENCIES_1

COMMITMENTS AND CONTINGENCIES (Environmental Liabilities) (Details) (USD $)	3 Months Ended		12 Months Ended
	Sep. 30, 2013	Jun. 30, 2011	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Mar. 31, 2013	Sep. 09, 2010	Jul. 26, 2010	Feb. 25, 2014	Aug. 07, 2012	Jul. 27, 2012
							bbl	bbl	bbl		bbl
								mi
Accrual for environmental loss contingencies			$60,100,000	$25,800,000
Remaining liabilities			141,700,000	233,700,000
Aggregate insurance coverage limit		650,000,000	700,000,000
Insurance recoveries					91,300,000
Government fines and penalties	254,000
Insurance recoveries, since inception			547,000,000
Remaining expected insurance recoveries			103,000,000
Increase (decrease) in other insurance liability			30,000,000	10,000,000
Remaining aggregate insurance coverage						145,000,000
Disputes with Insurers for Which Partial Payment Was Received [Member]
Insurance recoveries				42,000,000
Dispute with One Particular Insurer [Member]
Remaining expected insurance recoveries			85,000,000
Disputes with Remaining Insurers [Member]
Remaining expected insurance recoveries			18,000,000
Line Six Romeoville Leak [Member]
Crude oil released (in barrels)							9,000
Crude oil recovered (in barrels)							1,400
Estimated total loss of crude oil release			51,000,000
Accrual for environmental loss contingencies, increase (decrease) for revision in estimates			3,000,000
Costs paid associated with crude oil release				1,500,000	1,200,000
Remaining liabilities			3,000,000
Loss contingency, pending claims (in claims)			1
Line Six Marshall Leak [Member]
Crude oil released (in barrels)								20,000
Area impacted by crude oil release (in miles)								38
Accrual for environmental loss contingencies			40,000,000
Estimated total loss of crude oil release			1,208,000,000
Accrual for environmental loss contingencies, increase (decrease) for revision in estimates			85,900,000
Costs paid associated with crude oil release			141,400,000	156,300,000	134,000,000
Remaining liabilities			195,200,000	258,900,000
Insurance recoveries				42,000,000	170,000,000
Government fines and penalties			47,500,000
Loss contingency, pending claims (in claims)			7
Line Six Marshall Leak [Member] \| Fines Assessed by PHMSA [Member]
Government fines and penalties			3,700,000
Line Six Marshall Leak [Member] \| Fines Related to Clean Water Act [Member]
Government fines and penalties			40,000,000
Griffith Terminal Leak [Member]
Crude oil released (in barrels)									975
Estimated total loss of crude oil release			7,000,000
Costs paid associated with crude oil release			6,300,000
Remaining liabilities			700,000
Line Fourteen Grand Marsh Leak [Member]
Crude oil released (in barrels)											1,700
Operating pressure restriction (in percentage)										80.00%
Estimated total loss of crude oil release				10,500,000
Estimate of lost revenues				$1,600,000

COMMITMENTS_AND_CONTINGENCIES_2

COMMITMENTS AND CONTINGENCIES (Material Components Underlying Estimated Loss for Cleanup, Remediation and Restoration) (Details) (Line Six Marshall Leak [Member], USD $)	Dec. 31, 2014
In Millions, unless otherwise specified	Dec. 31, 2014
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

COMMITMENTS_AND_CONTINGENCIES_3

COMMITMENTS AND CONTINGENCIES (Commitments and Other Disclosures) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013	Dec. 31, 2012
Long-term Purchase Commitment [Line Items]
Natural gas volumes purchased on contractual basis (in percentage)	40.00%
Rent expense	$18.20		$25	$27.70
Total Future Minimum Commitments
2015	1,211.90
2016	171.5
2017	214.2
2018	224.3
2019	227.2
Thereafter	1,127
Total	3,176.10
Purchases made under our non-cancelable commitments	1,900		590.7	276.7
Other Operating Leases [Member]
Lease Commitments:
2015	25.6
2016	23.5
2017	21.9
2018	15.2
2019	14.8
Thereafter	342.3
Total	443.3
Right-of-Way [Member]
Long-term Purchase Commitment [Line Items]
Rent expense	3.6		2.3	2.7
Lease Commitments:
2015	2.3
2016	2.1
2017	1.7
2018	1.6
2019	1.5
Thereafter	33.7
Total	42.9
Minimum [Member]
Long-term Purchase Commitment [Line Items]
Natural gas volumes in custody (in barrels)	29,000,000
Maximum [Member]
Long-term Purchase Commitment [Line Items]
Natural gas volumes in custody (in barrels)	61,000,000
Purchase Commitments [Member]
Purchase Commitments and Obligations:
2015	1,012.70	[1]
2016		[1]
2017		[1]
2018		[1]
2019		[1]
Thereafter		[1]
Total	1,012.70	[1]
Power Commitments [Member]
Purchase Commitments and Obligations:
2015	14.8	[2]
2016	9.2	[2]
2017	6.3	[2]
2018	3.8	[2]
2019	1.5	[2]
Thereafter		[2]
Total	35.6	[2]
Product Purchase Obligations [Member]
Purchase Commitments and Obligations:
2015	23.1	[3]
2016	8.3	[3]
2017	14.7	[3]
2018	24.5	[3]
2019	25.5	[3]
Thereafter	112.5	[3]
Total	208.6	[3]
Transportation/Service Contract Obligations [Member]
Purchase Commitments and Obligations:
2015	63.3	[4]
2016	58.3	[4]
2017	99.5	[4]
2018	109.1	[4]
2019	113.8	[4]
Thereafter	403.5	[4]
Total	847.5	[4]
Fractionation Agreement Obligations [Member]
Purchase Commitments and Obligations:
2015	70.1	[5]
2016	70.1	[5]
2017	70.1	[5]
2018	70.1	[5]
2019	70.1	[5]
Thereafter	235	[5]
Total	$585.50	[5]

[1]	Represents commitments to purchase materials, primarily pipe from third-party suppliers in connection with our growth projects.
[2]	Represents commitments to purchase power in connection with our Liquids segment.
[3]	We have long-term product purchase obligations with several third-party suppliers to acquire natural gas and NGLs at the approximate market value at the time of delivery.
[4]	The service contract obligations represent the minimum payment amounts for firm transportation and storage capacity we have reserved on third-party pipelines and storage facilities.
[5]	The fractionation agreement obligations represent the minimum payment amounts for firm fractionation of our NGL supply that we reserve at third party fractionation facilities.

DERIVATIVE_FINANCIAL_INSTRUMEN2

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Narrative) (Details) (USD $)	12 Months Ended		3 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Mar. 31, 2014	Dec. 31, 2012
DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES [Abstract]
Unrecognized losses of derivative financial instruments that were classified as cash flow hedges	$28.40
De-designated unrealized commodity hedge losses	-0.2	1.7
Cash flow hedge gain (loss) to be reclassified within twelve months	219.9
Net asset (liability) position	-160.9	-88.7
Expected value of cash collateral or letters of credit if credit rating is downgraded	50.6
Letters of credit outstanding, derivatives	329.6	76.1
Short Term Debt Hedging Instruments [Member]
Derivative [Line Items]
Losses for interest rate hedge ineffectiveness		-5.3	-0.8
Amended Interest Rate Hedges [Member]
Derivative [Line Items]
Losses for interest rate hedge ineffectiveness	($100.60)	($29.60)		($20.80)

DERIVATIVE_FINANCIAL_INSTRUMEN3

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Derivative Instruments in Statement of Financial Position) (Details) (USD $)	Dec. 31, 2014		Dec. 31, 2013
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013
Derivatives, Fair Value [Line Items]
Net Total	($160.90)		($88.70)
Cash collateral held	28.4		16.7
Other Current Assets [Member]
Derivatives, Fair Value [Line Items]
Net Total	185.5		21.2
Other Noncurrent Assets [Member]
Derivatives, Fair Value [Line Items]
Net Total	93.3		74.4
Accounts Payable and Other [Member]
Derivatives, Fair Value [Line Items]
Net Total	-315.4	[1]	-172	[1]
Other Noncurrent Liabilities [Member]
Derivatives, Fair Value [Line Items]
Net Total	-124.6		-12.3
Due from General Partner and Affiliates [Member]
Derivatives, Fair Value [Line Items]
Net Total	$0.30

[1]	Includes $28.4 million of cash collateral at December 31, 2014, and $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 $)	Dec. 31, 2014		Dec. 31, 2013
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013
Derivative [Line Items]
Net Total	($160.90)		($88.70)
Cash collateral held	28.4		16.7
AAA Rating [Member]
Derivative [Line Items]
Net Total	0.1	[1]	0.3	[1]
AA Rating [Member]
Derivative [Line Items]
Net Total	-49.8	[1],[2]	-49.7	[1],[2]
Cash collateral held	28.4
A Rating [Member]
Derivative [Line Items]
Net Total	-129.1	[1],[3]	-40.1	[1],[3]
Cash collateral held			16.7
Lower than A [Member]
Derivative [Line Items]
Net Total	$17.90	[1]	$0.80	[1]

[1]	As determined by nationally-recognized statistical ratings organizations.
[2]	Includes $28.4 million of cash collateral at December 31, 2014.
[3]	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 $)	Dec. 31, 2014		Dec. 31, 2013
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Net Total	($160.90)		($88.70)
Cash collateral held	28.4		16.7
United States Financial Institutions And Investment Banking Entities [Member]
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Credit concentrations	-147.1	[1]	-85	[1]
Cash collateral held	28.4
Non United States Financial Institutions [Member]
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Credit concentrations	-54.2	[2]	0.8	[2]
Cash collateral held			16.7
Other [Member]
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Credit concentrations	$40.40		($4.50)

[1]	Includes $28.4 million of cash collateral at December 31, 2014.
[2]	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 $)	Dec. 31, 2014		Dec. 31, 2013
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013
Derivatives, Fair Value [Line Items]
Asset Derivatives	$279.10		$119.90	[1]
Liability Derivatives	-411.6		-191.9	[1]
Cash collateral held	28.4		16.7
Derivatives Designated As Hedging Instruments [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	28.2	[2]	85.1	[1],[2]
Liability Derivatives	-343	[2]	-172	[1],[2]
Derivatives Designated As Hedging Instruments [Member] \| Other Current Assets [Member] \| Interest Rate Contracts [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives		[2]	8.1	[1],[2]
Liability Derivatives		[2]		[1],[2]
Derivatives Designated As Hedging Instruments [Member] \| Other Current Assets [Member] \| Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	26.1	[2]	2	[1],[2]
Liability Derivatives		[2]	-0.6	[1],[2]
Derivatives Designated As Hedging Instruments [Member] \| Other Assets [Member] \| Interest Rate Contracts [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives		[2]	57.1	[1],[2]
Liability Derivatives		[2]		[1],[2]
Derivatives Designated As Hedging Instruments [Member] \| Other Assets [Member] \| Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	2.1	[2]	3.5	[1],[2]
Liability Derivatives		[2]	-0.5	[1],[2]
Derivatives Designated As Hedging Instruments [Member] \| Accounts Payable and Other [Member] \| Interest Rate Contracts [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives		[2],[3]	11.9	[1],[2],[3]
Liability Derivatives	-241	[2],[3]	-145.5	[1],[2],[3]
Derivatives Designated As Hedging Instruments [Member] \| Accounts Payable and Other [Member] \| Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives		[2]	1.9	[1],[2]
Liability Derivatives		[2]	-12.7	[1],[2]
Derivatives Designated As Hedging Instruments [Member] \| Other Long-term Liabilities [Member] \| Interest Rate Contracts [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives		[2]		[1],[2]
Liability Derivatives	-102	[2]	-11.3	[1],[2]
Derivatives Designated As Hedging Instruments [Member] \| Other Long-term Liabilities [Member] \| Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives		[2]	0.6	[1],[2]
Liability Derivatives		[2]	-1.4	[1],[2]
Derivatives Not Designated As Hedging Instruments [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	250.9		34.8	[1]
Liability Derivatives	-68.6		-19.9	[1]
Derivatives Not Designated As Hedging Instruments [Member] \| Other Current Assets [Member] \| Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	159.4		11.8	[1]
Liability Derivatives			-0.1	[1]
Derivatives Not Designated As Hedging Instruments [Member] \| Other Assets [Member] \| Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	91.2		17.6	[1]
Liability Derivatives			-3.3	[1]
Derivatives Not Designated As Hedging Instruments [Member] \| Accounts Payable and Other [Member] \| Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives		[3]	5.4	[1],[3]
Liability Derivatives	-46	[3]	-16.3	[1],[3]
Derivatives Not Designated As Hedging Instruments [Member] \| Other Long-term Liabilities [Member] \| Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives				[1]
Liability Derivatives	-22.6		-0.2	[1]
Derivatives Not Designated As Hedging Instruments [Member] \| Due from General Partner and Affiliates [Member] \| Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	0.3			[1]
Liability Derivatives				[1]

[1]	The effect of derivative instruments on the consolidated statements of financial position, as of December 31, 2013, was revised to disclose the financial position location on a gross basis. The revisions to the disclosures are not considered material to and had no impact on amounts previously reported in the consolidated statements of financial position.
[2]	Includes items currently designated as hedging instruments. Excludes the portion of de-designated hedges which may have a component remaining in AOCI.
[3]	Liability derivatives exclude $28.4 and $16.7 million of cash collateral at December 31, 2014 and 2013, respectively.

DERIVATIVE_FINANCIAL_INSTRUMEN7

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Effect of Derivative Instruments on Consolidated Statements of Income and AOCI) (Details) (Derivatives in Cash Flow Hedging Relationships [Member], USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in AOCI on Derivative (Effective Portion)	($133.50)		$234.50		($3.60)
Amount of Gain (Loss) Reclassified from AOCI to Earnings (Effective Portion)	-22		-27.1		-28.8
Amount of Gain (Loss) Recognized in Earnings on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)	-94.5	[1]	-18.2	[1]	-17.4	[1]
Interest Rate Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in AOCI on Derivative (Effective Portion)	-163.4		251		-45.4
Commodity Contract [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in AOCI on Derivative (Effective Portion)	29.9		-16.5		41.8
Interest Expense [Member] \| Interest Rate Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Reclassified from AOCI to Earnings (Effective Portion)	-16.2		-29.8		-28.9
Amount of Gain (Loss) Recognized in Earnings on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)	-100.1	[1]	-21.5	[1]	-20.5	[1]
Commodity Costs [Member] \| Commodity Contract [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Reclassified from AOCI to Earnings (Effective Portion)	-5.8		2.7		0.1
Amount of Gain (Loss) Recognized in Earnings on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)	$5.60	[1]	$3.30	[1]	$3.10	[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 $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013	Dec. 31, 2012
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance	($76.60)
Tax benefit (expense)	-0.2		0	-0.2
Net other comprehensive income	-127.7		243.9	-4
Ending balance	-211.4		-76.6
Reclassification out of AOCI [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance	-76.6
Other Comprehensive Income before reclassifications	-155.9	[1]
Amounts reclassified from AOCI	21.2	[2],[3]
Tax benefit (expense)	-0.1
Net other comprehensive income	-134.8
Ending balance	-211.4
Noncontrolling Interest [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income before reclassifications	6.3
Amounts reclassified from AOCI	$0.80

[1]	Excludes NCI gain of $6.3 million reclassified from AOCI at December 31, 2014.
[2]	Excludes NCI gain of $0.8 million reclassified from AOCI at December 31, 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								12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Commodity costs									$5,145.90		$4,948.90		$4,570.10
Interest expense, net									403.2		320.4		345
Total Reclassifications from AOCI	-214.1	-20.5	-43.9	-93.3	16.8	-14.9	-89.9	83.3	-371.8		-4.7		-493.1
NCI gain	113.9	70.7	42.4	36.3	34	20.3	18.4	15.6	263.3		88.3		57
Reclassification out of AOCI [Member] \| Reclassification out of AOCI [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Total Reclassifications from AOCI									21.2		27.1		28.8
Interest Rate Contracts [Member] \| Reclassification out of AOCI [Member] \| Reclassification out of AOCI [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Interest expense, net									16.2	[1]	29.8	[1]	28.9	[1]
Commodity Contract [Member] \| Reclassification out of AOCI [Member] \| Reclassification out of AOCI [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Commodity costs									5	[2],[3]	-2.7	[2],[3]	-0.1	[2],[3]
NCI gain									($0.80)

[1]	Loss (gain) reported within bInterest expenseb in the Consolidated Statements of Income.
[2]	Loss (gain) reported within bCommodity costsb in the Consolidated Statements of Income.
[3]	Excludes NCI gain of $0.8 million year ending December 31, 2014.

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 $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain or (Loss) Recognized in Earnings	$178.90	[1],[2]	($13.40)	[1],[2]	$27	[1],[2],[3]
Gain (Loss) on Settlement of Derivative Instruments					28.1
Interest Expense [Member] \| Interest Rate Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain or (Loss) Recognized in Earnings		[1],[2],[4]		[1],[2],[4]		[1],[2],[3],[4]
Gain (Loss) on Settlement of Derivative Instruments	0		0.2		0.5
Transportation and Other Services [Member] \| Interest Rate Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain or (Loss) Recognized in Earnings	17.4	[1],[2]	-3	[1],[2]		[1],[2],[3]
Commodity Sales [Member] \| Commodity Contract [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain or (Loss) Recognized in Earnings	23.7	[1],[2],[5]	-3	[1],[2],[5]	7.4	[1],[2],[3],[5]
Gain (Loss) on Settlement of Derivative Instruments	4.5		1.4		6.2
Commodity Sales - Affiliate [Member] \| Commodity Contract [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain or (Loss) Recognized in Earnings	0.3	[1],[2]		[1],[2]		[1],[2],[3]
Power [Member] \| Commodity Contract [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain or (Loss) Recognized in Earnings	0.7	[1],[2]	0.6	[1],[2]	0.1	[1],[2],[3]
Commodity Costs [Member] \| Commodity Contract [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain or (Loss) Recognized in Earnings	136.8	[1],[2],[6]	-8	[1],[2],[6]	19.5	[1],[2],[3],[6]
Gain (Loss) on Settlement of Derivative Instruments	$8		($4.60)		$21.40

[1]	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.
[2]	Does not include settlements associated with derivative instruments that settle through physical delivery.
[3]	The effects of derivatives instruments on consolidated statements of income have been revised to include settlement gains on derivatives not designated as hedge instruments of $28.1 million for the year ended December 31, 2012.
[4]	Includes settlement gains of $0 million, $0.2 million, and $0.5 million for the years ended December 31, 2014, 2013 and 2012, respectively.
[5]	Includes settlement gains of $4.5 million, $1.4 million, and $6.2 million for the years ended December 31, 2014, 2013 and 2012, respectively.
[6]	Includes settlement gains (losses) of $8.0 million and ($4.6) million and $21.4 million for the years ended December 31, 2014, December 31, 2013, and December 31, 2012, respectively.

Recovered_Sheet2

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Offsetting of Financial Assets and Derivative Assets) (Details) (USD $)	Dec. 31, 2014		Dec. 31, 2013
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013
Derivatives
Gross Amount of Recognized Assets	$279.10		$119.90	[1]
Gross Amount Offset in the Statement of Financial Position			-24.3
Net Amount of Assets Presented in the Statement of Financial Position	279.1		95.6
Gross Amount Not Offset in the Statement of Financial Position	-91.8	[2]	-18.6	[2]
Net Amount	187.3		77
Total
Gross Amount of Recognized Assets	279.1		119.9
Gross Amount Offset in the Statement of Financial Position			-24.3
Net Amount of Assets Presented in the Statement of Financial Position	279.1		95.6
Gross Amount Not Offset in the Statement of Financial Position	-91.8	[2]	-18.6	[2]
Net Amount	$187.30		$77

[1]	The effect of derivative instruments on the consolidated statements of financial position, as of December 31, 2013, was revised to disclose the financial position location on a gross basis. The revisions to the disclosures are not considered material to and had no impact on amounts previously reported in the consolidated statements of financial position.
[2]	Includes $28.4 million and $16.7 million of cash collateral at December 31, 2014 and December 31, 2013, respectively.

Recovered_Sheet3

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Offsetting of Financial Liabilities and Derivative Liabilities) (Details) (USD $)	Dec. 31, 2014		Dec. 31, 2013
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013
Derivatives
Gross Amount of Recognized Liabilities	($440)		($208.60)
Gross Amount Offset in the Statement of Financial Position			24.3
Net Amount of Liabilities Presented in the Statement of Financial Position	-440		-184.3
Gross Amount Not Offset in the Statement of Financial Position	91.8	[1]	18.6	[1]
Net Amount	-348.2		-165.7
Total
Gross Amount of Recognized Liabilities	-440		-208.6
Gross Amount Offset in the Statement of Financial Position			24.3
Net Amount of Liabilities Presented in the Statement of Financial Position	-440		-184.3
Gross Amount Not Offset in the Statement of Financial Position	91.8	[1]	18.6	[1]
Net Amount	($348.20)		($165.70)

[1]	Includes $28.4 million and $16.7 million of cash collateral at December 31, 2014 and December 31, 2013, respectively.

Recovered_Sheet4

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Level with in Fair Value Hierarchy, Financial Assets and Liabilities) (Details) (USD $)	Dec. 31, 2014		Dec. 31, 2013
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments	($132.50)		($72)
Cash Collateral	-28.4		-16.7
Total	-160.9		-88.7
Interest Rate Contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments	-343	[1]	-79.7	[1]
Commodity Contracts - Financial [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments	84.3		-0.5
Commodity Contracts - Physical [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments	19.5		-0.2
Commodity Options [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments	106.7		8.4
Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments
Cash Collateral
Total
Level 1 [Member] \| Interest Rate Contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments		[1]		[1]
Level 1 [Member] \| Commodity Contracts - Financial [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments
Level 1 [Member] \| Commodity Contracts - Physical [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments
Level 1 [Member] \| Commodity Options [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments
Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments	-301.4		-73.3
Cash Collateral
Total	-301.4		-73.3
Level 2 [Member] \| Interest Rate Contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments	-343	[1]	-79.7	[1]
Level 2 [Member] \| Commodity Contracts - Financial [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments	41.6		6.4
Level 2 [Member] \| Commodity Contracts - Physical [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments
Level 2 [Member] \| Commodity Options [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments
Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments	168.9		1.3
Cash Collateral
Total	168.9		1.3
Level 3 [Member] \| Interest Rate Contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments		[1]		[1]
Level 3 [Member] \| Commodity Contracts - Financial [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments	42.7		-6.9
Level 3 [Member] \| Commodity Contracts - Physical [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments	19.5		-0.2
Level 3 [Member] \| Commodity Options [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments	$106.70		$8.40

[1]	Amounts have been revised to exclude $16.7 million of cash collateral at December 31, 2013.

Recovered_Sheet5

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Quantitative Information about Level 3 Fair Value Measurements) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 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	-160.9		-88.7
Commodity Contracts - Financial [Member] \| Minimum [Member] \| Natural Gas [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Forward Price	2.55	[1]	3.64	[1]
Commodity Contracts - Financial [Member] \| Minimum [Member] \| NGL [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Forward Price	0.48	[1]	1	[1]
Commodity Contracts - Financial [Member] \| Maximum [Member] \| Natural Gas [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Forward Price	3.72	[1]	4.41	[1]
Commodity Contracts - Financial [Member] \| Maximum [Member] \| NGL [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Forward Price	1.14	[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	3.04	[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	0.64	[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	1.55	[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	49.57	[1]	86.37	[1]
Commodity Contracts - Physical [Member] \| Minimum [Member] \| NGL [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Forward Price	0.06	[1]	0.02	[1]
Commodity Contracts - Physical [Member] \| Minimum [Member] \| Power [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Forward Price			32.4	[1]
Commodity Contracts - Physical [Member] \| Maximum [Member] \| Natural Gas [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Forward Price	4.08	[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	55.6	[1]	103.04	[1]
Commodity Contracts - Physical [Member] \| Maximum [Member] \| NGL [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Forward Price	1.21	[1]	2.19	[1]
Commodity Contracts - Physical [Member] \| Maximum [Member] \| Power [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Forward Price			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	3.08	[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	53.51	[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	0.54	[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			35.07	[1]
Commodity Options [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Credit valuation adjustments	-0.7
Commodity Options [Member] \| Minimum [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Option Volatility	19.00%	[1]	18.00%	[1]
Commodity Options [Member] \| Maximum [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Option Volatility	94.00%	[1]	44.00%	[1]
Commodity Options [Member] \| Weighted Average [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Option Volatility	36.00%	[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	168.9		1.3
Credit valuation adjustments	-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	42.1	[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	1.5	[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	-0.9	[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	18.9	[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			-0.7	[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	106.7	[2]	8.4	[3]

[1]	Prices are in dollars per MMBtu for Natural Gas, Gal for NGLs, Bbl for Crude Oil and MWh for Power.
[2]	Fair values are presented in millions of dollars and include credit valuation adjustments of approximately $1.0 million of losses.
[3]	Fair values are presented in millions and 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 $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 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	180.5
Gains or losses included in other comprehensive income	16.9
Purchases, issuances, sales and settlements:
Purchases	0.7
Sales	-2.1
Settlements	-28.4	[2]
Ending balance	168.9
Amount of changes in net assets attributable to the change in unrealized gains or losses related to assets still held at the reporting date	161.6
Commodity Sales [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Gains or losses included in earnings	24
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	30.2
Gains or losses included in other comprehensive income	16.9
Purchases, issuances, sales and settlements:
Purchases
Sales
Settlements	2.5	[2]
Ending balance	42.7
Amount of changes in net assets attributable to the change in unrealized gains or losses related to assets still held at the reporting date	42.2
Commodity Contracts - Financial [Member] \| Commodity Sales [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	48.6
Gains or losses included in other comprehensive income
Purchases, issuances, sales and settlements:
Purchases
Sales
Settlements	-28.9	[2]
Ending balance	19.5
Amount of changes in net assets attributable to the change in unrealized gains or losses related to assets still held at the reporting date	19
Commodity Contracts - Physical [Member] \| Commodity Sales [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Gains or losses included in earnings	24
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	101.7
Gains or losses included in other comprehensive income
Purchases, issuances, sales and settlements:
Purchases	0.7
Sales	-2.1
Settlements	-2	[2]
Ending balance	106.7
Amount of changes in net assets attributable to the change in unrealized gains or losses related to assets still held at the reporting date	100.4
Commodity Options [Member] \| Commodity Sales [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 $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013
Fair Value
Asset	$279.10		$119.90	[1]
Liability	-440		-208.6
Swaps - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Fixed - Natural Gas [Member]
Derivative [Line Items]
Notional	896,915	[2]
Fair Value
Asset		[3]		[3]
Liability	-0.7	[3]		[3]
Swaps - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Fixed - NGL [Member]
Derivative [Line Items]
Notional	225,850	[2]
Fair Value
Asset		[3]		[3]
Liability	-6.8	[3]		[3]
Swaps - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Fixed - Crude Oil [Member]
Derivative [Line Items]
Notional	912,250	[2]
Fair Value
Asset		[3]		[3]
Liability	-27.4	[3]		[3]
Swaps - Portion of Contracts Maturing in 2015 - Receive Fixed/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Notional	3,645,440	[2]
Fair Value
Asset	3.7	[3]		[3]
Liability		[3]		[3]
Swaps - Portion of Contracts Maturing in 2015 - Receive Fixed/Pay Variable - NGL [Member]
Derivative [Line Items]
Notional	1,980,850	[2]
Fair Value
Asset	39.2	[3]	1.5	[3]
Liability		[3]	-1.1	[3]
Swaps - Portion of Contracts Maturing in 2015 - Receive Fixed/Pay Variable - Crude Oil [Member]
Derivative [Line Items]
Notional	1,759,415	[2]
Fair Value
Asset	65	[3]	8.3	[3]
Liability		[3]		[3]
Swaps - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Notional	59,606,800	[2]
Fair Value
Asset	1.5	[3]	0.1	[3]
Liability	-1.7	[3]		[3]
Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Fixed - Natural Gas [Member]
Derivative [Line Items]
Notional	232,400	[2]
Fair Value
Asset		[3]		[3]
Liability		[3]		[3]
Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Fixed - NGL [Member]
Derivative [Line Items]
Notional	206,300	[2]
Fair Value
Asset		[3]		[3]
Liability	-3.6	[3]		[3]
Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Fixed - Crude Oil [Member]
Derivative [Line Items]
Notional	11,300	[2]
Fair Value
Asset		[3]		[3]
Liability		[3]		[3]
Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Fixed/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Notional	290,114	[2]
Fair Value
Asset		[3]		[3]
Liability		[3]		[3]
Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Fixed/Pay Variable - NGL [Member]
Derivative [Line Items]
Notional	1,042,921	[2]
Fair Value
Asset	19.8	[3]		[3]
Liability		[3]		[3]
Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Fixed/Pay Variable - Crude Oil [Member]
Derivative [Line Items]
Notional	65,000	[2]
Fair Value
Asset	0.5	[3]		[3]
Liability		[3]		[3]
Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Notional	148,689,068	[2]
Fair Value
Asset	2.2	[3]	0.5	[3]
Liability	-1	[3]	-0.1	[3]
Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Variable - NGL [Member]
Derivative [Line Items]
Notional	7,221,805	[2]
Fair Value
Asset	3.7	[3]		[3]
Liability	-1	[3]		[3]
Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Variable - Crude Oil [Member]
Derivative [Line Items]
Notional	558,553	[2]
Fair Value
Asset	0.3	[3]		[3]
Liability	-1.7	[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	-0.1	[3]		[3]
Swaps - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Fixed - Crude Oil [Member]
Derivative [Line Items]
Notional	415,950	[2]
Fair Value
Asset		[3]		[3]
Liability	-8.1	[3]		[3]
Swaps - Portion of Contracts Maturing in 2016 - Receive Fixed/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Notional	75,000	[2]
Fair Value
Asset		[3]		[3]
Liability		[3]		[3]
Swaps - Portion of Contracts Maturing in 2016 - Receive Fixed/Pay Variable - NGL [Member]
Derivative [Line Items]
Notional	823,500	[2]
Fair Value
Asset	9.3	[3]		[3]
Liability		[3]		[3]
Swaps - Portion of Contracts Maturing in 2016 - Receive Fixed/Pay Variable - Crude Oil [Member]
Derivative [Line Items]
Notional	415,950	[2]
Fair Value
Asset	9.1	[3]	0.7	[3]
Liability		[3]		[3]
Swaps - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Notional	20,587,000	[2]
Fair Value
Asset	0.5	[3]		[3]
Liability	-0.3	[3]		[3]
Physical Contracts - Portion of Contracts Maturing in 2016 - Receive Fixed/Pay Variable - NGL [Member]
Derivative [Line Items]
Notional	1,788	[2]
Fair Value
Asset		[3]		[3]
Liability		[3]		[3]
Physical Contracts - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Notional	34,834,479	[2]
Fair Value
Asset	0.7	[3]	0.1	[3]
Liability	-0.4	[3]		[3]
Swaps - Portion of Contracts Maturing in 2017 - Receive Fixed/Pay Variable - NGL [Member]
Derivative [Line Items]
Notional	365,000	[2]
Fair Value
Asset	0.7	[3]		[3]
Liability		[3]		[3]
Swaps - Portion of Contracts Maturing in 2017 - Receive Fixed/Pay Variable - Crude Oil [Member]
Derivative [Line Items]
Notional	365,000	[2]
Fair Value
Asset	0.8	[3]		[3]
Liability		[3]		[3]
Physical Contracts - Portion of Contracts Maturing in 2017 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Notional	14,909,743	[2]
Fair Value
Asset	0.2	[3]		[3]
Liability	-0.1	[3]		[3]
Physical Contracts - Portion of Contracts Maturing in 2018 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Notional	900,000	[2]
Fair Value
Asset		[3]		[3]
Liability		[3]		[3]
Swap [Member]
Fair Value
Credit valuation adjustments	($0.50)		$0.10
Receive [Member] \| Swaps - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Fixed - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price	2.94	[4]
Receive [Member] \| Swaps - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Fixed - NGL [Member]
Derivative [Line Items]
Wtd. Average Price	35.24	[4]
Receive [Member] \| Swaps - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Fixed - Crude Oil [Member]
Derivative [Line Items]
Wtd. Average Price	56.73	[4]
Receive [Member] \| Swaps - Portion of Contracts Maturing in 2015 - Receive Fixed/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price	3.95	[4]
Receive [Member] \| Swaps - Portion of Contracts Maturing in 2015 - Receive Fixed/Pay Variable - NGL [Member]
Derivative [Line Items]
Wtd. Average Price	46.91	[4]
Receive [Member] \| Swaps - Portion of Contracts Maturing in 2015 - Receive Fixed/Pay Variable - Crude Oil [Member]
Derivative [Line Items]
Wtd. Average Price	93.79	[4]
Receive [Member] \| Swaps - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price	2.89	[4]
Receive [Member] \| Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Fixed - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price	3.09	[4]
Receive [Member] \| Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Fixed - NGL [Member]
Derivative [Line Items]
Wtd. Average Price	22.54	[4]
Receive [Member] \| Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Fixed - Crude Oil [Member]
Derivative [Line Items]
Wtd. Average Price	53.44	[4]
Receive [Member] \| Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Fixed/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price	3.02	[4]
Receive [Member] \| Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Fixed/Pay Variable - NGL [Member]
Derivative [Line Items]
Wtd. Average Price	44.6	[4]
Receive [Member] \| Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Fixed/Pay Variable - Crude Oil [Member]
Derivative [Line Items]
Wtd. Average Price	62.46	[4]
Receive [Member] \| Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price	2.95	[4]
Receive [Member] \| Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Variable - NGL [Member]
Derivative [Line Items]
Wtd. Average Price	22.68	[4]
Receive [Member] \| Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Variable - Crude Oil [Member]
Derivative [Line Items]
Wtd. Average Price	50.57	[4]
Receive [Member] \| Swaps - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Fixed - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price	3.15	[4]
Receive [Member] \| Swaps - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Fixed - Crude Oil [Member]
Derivative [Line Items]
Wtd. Average Price	62.96	[4]
Receive [Member] \| Swaps - Portion of Contracts Maturing in 2016 - Receive Fixed/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price	3.48	[4]
Receive [Member] \| Swaps - Portion of Contracts Maturing in 2016 - Receive Fixed/Pay Variable - NGL [Member]
Derivative [Line Items]
Wtd. Average Price	39.64	[4]
Receive [Member] \| Swaps - Portion of Contracts Maturing in 2016 - Receive Fixed/Pay Variable - Crude Oil [Member]
Derivative [Line Items]
Wtd. Average Price	85.08	[4]
Receive [Member] \| Swaps - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price	3.3	[4]
Receive [Member] \| Physical Contracts - Portion of Contracts Maturing in 2016 - Receive Fixed/Pay Variable - NGL [Member]
Derivative [Line Items]
Wtd. Average Price	28.67	[4]
Receive [Member] \| Physical Contracts - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price	3.4	[4]
Receive [Member] \| Swaps - Portion of Contracts Maturing in 2017 - Receive Fixed/Pay Variable - NGL [Member]
Derivative [Line Items]
Wtd. Average Price	24.78	[4]
Receive [Member] \| Swaps - Portion of Contracts Maturing in 2017 - Receive Fixed/Pay Variable - Crude Oil [Member]
Derivative [Line Items]
Wtd. Average Price	69.35	[4]
Receive [Member] \| Physical Contracts - Portion of Contracts Maturing in 2017 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price	3.77	[4]
Receive [Member] \| Physical Contracts - Portion of Contracts Maturing in 2018 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price	4.03	[4]
Pay [Member] \| Swaps - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Fixed - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price	3.67	[4]
Pay [Member] \| Swaps - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Fixed - NGL [Member]
Derivative [Line Items]
Wtd. Average Price	65.37	[4]
Pay [Member] \| Swaps - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Fixed - Crude Oil [Member]
Derivative [Line Items]
Wtd. Average Price	86.82	[4]
Pay [Member] \| Swaps - Portion of Contracts Maturing in 2015 - Receive Fixed/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price	2.93	[4]
Pay [Member] \| Swaps - Portion of Contracts Maturing in 2015 - Receive Fixed/Pay Variable - NGL [Member]
Derivative [Line Items]
Wtd. Average Price	27.11	[4]
Pay [Member] \| Swaps - Portion of Contracts Maturing in 2015 - Receive Fixed/Pay Variable - Crude Oil [Member]
Derivative [Line Items]
Wtd. Average Price	56.75	[4]
Pay [Member] \| Swaps - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price	2.89	[4]
Pay [Member] \| Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Fixed - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price	2.99	[4]
Pay [Member] \| Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Fixed - NGL [Member]
Derivative [Line Items]
Wtd. Average Price	39.95	[4]
Pay [Member] \| Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Fixed - Crude Oil [Member]
Derivative [Line Items]
Wtd. Average Price	56.27	[4]
Pay [Member] \| Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Fixed/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price	3.18	[4]
Pay [Member] \| Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Fixed/Pay Variable - NGL [Member]
Derivative [Line Items]
Wtd. Average Price	25.58	[4]
Pay [Member] \| Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Fixed/Pay Variable - Crude Oil [Member]
Derivative [Line Items]
Wtd. Average Price	54	[4]
Pay [Member] \| Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price	2.95	[4]
Pay [Member] \| Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Variable - NGL [Member]
Derivative [Line Items]
Wtd. Average Price	22.3	[4]
Pay [Member] \| Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Variable - Crude Oil [Member]
Derivative [Line Items]
Wtd. Average Price	53.07	[4]
Pay [Member] \| Swaps - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Fixed - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price	3.85	[4]
Pay [Member] \| Swaps - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Fixed - Crude Oil [Member]
Derivative [Line Items]
Wtd. Average Price	82.69	[4]
Pay [Member] \| Swaps - Portion of Contracts Maturing in 2016 - Receive Fixed/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price	3.52	[4]
Pay [Member] \| Swaps - Portion of Contracts Maturing in 2016 - Receive Fixed/Pay Variable - NGL [Member]
Derivative [Line Items]
Wtd. Average Price	28.18	[4]
Pay [Member] \| Swaps - Portion of Contracts Maturing in 2016 - Receive Fixed/Pay Variable - Crude Oil [Member]
Derivative [Line Items]
Wtd. Average Price	62.96	[4]
Pay [Member] \| Swaps - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price	3.29	[4]
Pay [Member] \| Physical Contracts - Portion of Contracts Maturing in 2016 - Receive Fixed/Pay Variable - NGL [Member]
Derivative [Line Items]
Wtd. Average Price	25.71	[4]
Pay [Member] \| Physical Contracts - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price	3.39	[4]
Pay [Member] \| Swaps - Portion of Contracts Maturing in 2017 - Receive Fixed/Pay Variable - NGL [Member]
Derivative [Line Items]
Wtd. Average Price	22.79	[4]
Pay [Member] \| Swaps - Portion of Contracts Maturing in 2017 - Receive Fixed/Pay Variable - Crude Oil [Member]
Derivative [Line Items]
Wtd. Average Price	66.97	[4]
Pay [Member] \| Physical Contracts - Portion of Contracts Maturing in 2017 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price	3.76	[4]
Pay [Member] \| Physical Contracts - Portion of Contracts Maturing in 2018 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price	4.03	[4]

[1]	The effect of derivative instruments on the consolidated statements of financial position, as of December 31, 2013, was revised to disclose the financial position location on a gross basis. The revisions to the disclosures are not considered material to and had no impact on amounts previously reported in the consolidated statements of financial position.
[2]	Volumes of natural gas are measured in MMBtu, whereas volumes of NGL and crude oil are measured in Bbl.
[3]	The fair value is determined based on quoted market prices at December 31, 2014 and 2013 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 $0.5 million of losses and $0.1 million of gains at December 31, 2014 and 2013, respectively, and cash collateral received.
[4]	Weighted average prices received and paid are in $/MMBtu for natural gas and $/Bbl for NGL and crude oil.

Recovered_Sheet8

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Fair Values of Expected Cash Flows of Commodity Options) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013
Fair Value
Liability	($440)		($184.30)
Commodity Option [Member]
Fair Value
Credit valuation adjustments	-0.7
Written [Member] \| Portion of Put Option Contracts Maturing in 2015 - Natural Gas [Member]
Derivative [Line Items]
Notional	4,015,000	[1]
Strike Price	3.9	[2]
Market Price	3.02	[2]
Fair Value
Asset		[3]		[3]
Liability	-3.8	[3]		[3]
Written [Member] \| Portion of Call Option Contracts Maturing in 2015 - Natural Gas [Member]
Derivative [Line Items]
Notional	1,277,500	[1]
Strike Price	5.05	[2]
Market Price	3.03	[2]
Fair Value
Asset		[3]		[3]
Liability		[3]	-0.3	[3]
Written [Member] \| Portion of Call Option Contracts Maturing in 2015 - NGL [Member]
Derivative [Line Items]
Notional	1,433,250	[1]
Strike Price	45.74	[2]
Market Price	25.97	[2]
Fair Value
Asset		[3]		[3]
Liability	-0.6	[3]	-1	[3]
Written [Member] \| Portion of Call Option Contracts Maturing in 2015 - Crude Oil [Member]
Derivative [Line Items]
Notional	730,000	[1]
Strike Price	88.39	[2]
Market Price	56.78	[2]
Fair Value
Asset		[3]		[3]
Liability	-0.4	[3]	-1.9	[3]
Written [Member] \| Portion of Put Option Contracts Maturing in 2016 - Natural Gas [Member]
Derivative [Line Items]
Notional	1,647,000	[1]
Strike Price	3.75	[2]
Market Price	3.46	[2]
Fair Value
Asset		[3]		[3]
Liability	-1	[3]		[3]
Written [Member] \| Portion of Call Option Contracts Maturing in 2016 - Natural Gas [Member]
Derivative [Line Items]
Notional	1,647,000	[1]
Strike Price	4.98	[2]
Market Price	3.46	[2]
Fair Value
Asset		[3]		[3]
Liability	-0.1	[3]		[3]
Written [Member] \| Portion of Call Option Contracts Maturing in 2016 - NGL [Member]
Derivative [Line Items]
Notional	2,836,500	[1]
Strike Price	45.14	[2]
Market Price	27.03	[2]
Fair Value
Asset		[3]		[3]
Liability	-3.2	[3]		[3]
Written [Member] \| Portion of Call Option Contracts Maturing in 2016 - Crude Oil [Member]
Derivative [Line Items]
Notional	805,200	[1]
Strike Price	86.68	[2]
Market Price	63.34	[2]
Fair Value
Asset		[3]		[3]
Liability	-2.7	[3]		[3]
Written [Member] \| Portion of Call Option Contracts Maturing in 2017 - NGL [Member]
Derivative [Line Items]
Notional	365,000	[1]
Strike Price	26.15	[2]
Market Price	22.79	[2]
Fair Value
Asset		[3]		[3]
Liability	-0.7	[3]		[3]
Written [Member] \| Portion of Call Option Contracts Maturing in 2017 - Crude Oil [Member]
Derivative [Line Items]
Notional	365,000	[1]
Strike Price	74	[2]
Market Price	66.97	[2]
Fair Value
Asset		[3]		[3]
Liability	-3.3	[3]		[3]
Purchased [Member] \| Portion of Put Option Contracts Maturing in 2015 - Natural Gas [Member]
Derivative [Line Items]
Notional	4,015,000	[1]
Strike Price	3.9	[2]
Market Price	3.03	[2]
Fair Value
Asset	3.8	[3]	1.7	[3]
Liability		[3]		[3]
Purchased [Member] \| Portion of Put Option Contracts Maturing in 2015 - NGL [Member]
Derivative [Line Items]
Notional	2,254,500	[1]
Strike Price	43.41	[2]
Market Price	26.09	[2]
Fair Value
Asset	40.2	[3]	6	[3]
Liability		[3]		[3]
Purchased [Member] \| Portion of Put Option Contracts Maturing in 2015 - Crude Oil [Member]
Derivative [Line Items]
Notional	730,000	[1]
Strike Price	81.56	[2]
Market Price	56.78	[2]
Fair Value
Asset	18.8	[3]	1.8	[3]
Liability		[3]		[3]
Purchased [Member] \| Portion of Call Option Contracts Maturing in 2015 - Natural Gas [Member]
Derivative [Line Items]
Notional	1,277,500	[1]
Strike Price	5.05	[2]
Market Price	3.03	[2]
Fair Value
Asset		[3]		[3]
Liability		[3]		[3]
Purchased [Member] \| Portion of Put Option Contracts Maturing in 2016 - Natural Gas [Member]
Derivative [Line Items]
Notional	1,647,000	[1]
Strike Price	3.75	[2]
Market Price	3.46	[2]
Fair Value
Asset	1	[3]		[3]
Liability		[3]		[3]
Purchased [Member] \| Portion of Put Option Contracts Maturing in 2016 - NGL [Member]
Derivative [Line Items]
Notional	2,836,500	[1]
Strike Price	39.24	[2]
Market Price	27.03	[2]
Fair Value
Asset	39.3	[3]		[3]
Liability		[3]		[3]
Purchased [Member] \| Portion of Put Option Contracts Maturing in 2016 - Crude Oil [Member]
Derivative [Line Items]
Notional	805,200	[1]
Strike Price	75.91	[2]
Market Price	63.21	[2]
Fair Value
Asset	14.7	[3]		[3]
Liability		[3]		[3]
Purchased [Member] \| Portion of Call Option Contracts Maturing in 2016 - Natural Gas [Member]
Derivative [Line Items]
Notional	1,647,000	[1]
Strike Price	4.98	[2]
Market Price	3.46	[2]
Fair Value
Asset	0.1	[3]		[3]
Liability		[3]		[3]
Purchased [Member] \| Portion of Put Option Contracts Maturing in 2017 - NGL [Member]
Derivative [Line Items]
Notional	365,000	[1]
Strike Price	23.1	[2]
Market Price	22.79	[2]
Fair Value
Asset	1.2	[3]		[3]
Liability		[3]		[3]
Purchased [Member] \| Portion of Put Option Contracts Maturing in 2017 - Crude Oil [Member]
Derivative [Line Items]
Notional	365,000	[1]
Strike Price	66	[2]
Market Price	66.97	[2]
Fair Value
Asset	4.1	[3]		[3]
Liability		[3]		[3]

[1]	Volumes of natural gas are measured in MMBtu, whereas volumes of NGL and crude oil are measured in Bbl.
[2]	Strike and market prices are in $/MMBtu for natural gas and in $/Bbl for NGL and crude oil.
[3]	The fair value is determined based on quoted market prices at December 31, 2014 and 2013, 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 $0.7 million of losses at December 31, 2014 and cash collateral received.

Recovered_Sheet9

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Interest Rate Derivatives) (Details) (Interest Rate Swaps [Member], Derivatives in Cash Flow Hedging Relationships [Member], USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013
Derivative [Line Items]
Credit valuation adjustments	$37.40		($7.10)
Contracts Maturing In 2015 [Member]
Derivative [Line Items]
Notional	510
Average Fixed Rate (in percentage)	1.53%	[1]
Interest Rate Derivatives, at Fair Value, Net	-0.2	[2]	-6.8	[2],[3]
Contracts Maturing In 2016 [Member]
Derivative [Line Items]
Notional	90
Average Fixed Rate (in percentage)	0.55%	[1]
Interest Rate Derivatives, at Fair Value, Net	-0.1	[2]		[2],[3]
Contracts Maturing In 2017 [Member]
Derivative [Line Items]
Notional	450
Average Fixed Rate (in percentage)	2.21%	[1]
Interest Rate Derivatives, at Fair Value, Net	-12.9	[2]	-13.8	[2],[3]
Contracts Maturing In 2018 [Member]
Derivative [Line Items]
Notional	810
Average Fixed Rate (in percentage)	2.24%	[1]
Interest Rate Derivatives, at Fair Value, Net	-1.3	[2]	3.3	[2],[3]
Contracts Maturing In 2019 [Member]
Derivative [Line Items]
Notional	620
Average Fixed Rate (in percentage)	2.96%	[1]
Interest Rate Derivatives, at Fair Value, Net	-3.3	[2]		[2],[3]
Contracts Settling Prior to Maturity - 2015 Pre Issuance Hedges [Member]
Derivative [Line Items]
Notional	1,000
Average Fixed Rate (in percentage)	5.48%	[1]
Interest Rate Derivatives, at Fair Value, Net	-258.3	[2]		[2],[3]
Contracts Settling Prior to Maturity - 2016 Pre Issuance Hedges [Member]
Derivative [Line Items]
Notional	500
Average Fixed Rate (in percentage)	4.21%	[1]
Interest Rate Derivatives, at Fair Value, Net	-63.4	[2]	60.8	[2],[3]
Contracts Settling Prior to Maturity - 2017 Pre Issuance Hedges [Member]
Derivative [Line Items]
Notional	500
Average Fixed Rate (in percentage)	3.69%	[1]
Interest Rate Derivatives, at Fair Value, Net	-36	[2]		[2],[3]
Contracts Settling Prior to Maturity - 2018 Pre Issuance Hedges [Member]
Derivative [Line Items]
Notional	350
Average Fixed Rate (in percentage)	3.08%	[1]
Interest Rate Derivatives, at Fair Value, Net	($4.90)	[2]		[2],[3]

[1]	Interest rate derivative contracts are based on the one-month or three-month LIBOR.
[2]	The fair value is determined from quoted market prices at December 31, 2014 and 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 $37.4 million of gains at December 31, 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 $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income tax expense:
Current state	$5.50	$4.30	$8.10
Deferred state	4.1	14.4
Total income tax expense	9.6	18.7	8.1
A reconciliation of the income tax expense with amounts determined by applying the statutory U.S. federal income tax rate to income before income tax expense:
Income before income tax expense	749.6	179.1	558.2
State income tax expense	9.6	18.7	8.1
Effective income tax rate (in percentage)	1.30%	10.40%	1.60%
Current income tax payable	1.5	0.9
Deferred income tax liability (Note 15)	21.7	17.4
Deferred tax assets and liabilities:
Net book basis of assets in excess of tax basis	-21.5	-17.4
Net book losses on derivatives not recognized for tax purposes	-0.2
Net deferred tax liability	-21.7	-17.4
Accounting for Uncertainty in Income Taxes:
Unrecognized tax benefits at December 31, 2013	29.8
Additions for tax positions taken in current period	3.4
Unrecognized tax benefits at December 31, 2014	33.2	29.8
Unrecognized tax benefits, possible estimate change	3.4
Penalties accrued	0.5
Interest accrued	0.4
Accrued interest income not included in balance of unrecognized tax benefits	0.7	0.6
Tax Year 2011 [Member]
Accounting for Uncertainty in Income Taxes:
Open tax year	2011
Tax Year 2012 [Member]
Accounting for Uncertainty in Income Taxes:
Open tax year	2012
Tax Year 2013 [Member]
Accounting for Uncertainty in Income Taxes:
Open tax year	2013
Texas State Income Tax Rate [Member]
A reconciliation of the income tax expense with amounts determined by applying the statutory U.S. federal income tax rate to income before income tax expense:
Effective income tax rate (in percentage)	0.40%	0.50%	0.50%
Deferred income tax liability (Note 15)		$12.40

SEGMENT_INFORMATION_Details

SEGMENT INFORMATION (Details) (USD $)	1 Months Ended	3 Months Ended										12 Months Ended
In Millions, unless otherwise specified	Nov. 30, 2013	Dec. 31, 2014		Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013		Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
	Nov. 30, 2013	Dec. 31, 2014		Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013		Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	segments		Dec. 31, 2013		Dec. 31, 2012
Segment Reporting Information [Line Items]
Number of reporting segments (in segments)												2
Commodity sales												$5,693.90	[1]	$5,368.50	[2]
Transportation and other services												2,270.80	[1]	1,748.60	[2]
Total operating revenue		2,071.70		1,942.30	1,871.10	2,079.60	1,962		1,789.40	1,672.70	1,693	7,964.70		7,117.10		6,706.10
Commodity costs												5,145.90		4,948.90		4,570.10
Environmental costs, net of recoveries												97.3		273.7
Environmental costs, net of recoveries																-91.3
Operating and administrative												950		918.4		840.5
Power												226.6		147.7		148.8
Depreciation and amortization												458.2		388		344.8
Costs and Expenses, Total		1,621		1,701.90	1,690.20	1,864.90	1,856.60		1,665.80	1,463.70	1,690.60	6,878		6,676.70		5,812.90
Operating income		450.7		240.4	180.9	214.7	105.4		123.6	209	2.4	1,086.70		440.4		893.2
Interest expense, net												403.2		320.4		345
Allowance for equity used during construction												57.2		43.1		11.2
Other income (expense)												8.9		16		-1.2
Income before income tax expense												749.6		179.1		558.2
Income tax expense												9.6		18.7		8.1
Net income		354.3		117.5	112.5	155.7	43.1		61.3	123.7	-67.7	740		160.4		550.1
Noncontrolling interest (Note 12)		113.9		70.7	42.4	36.3	34		20.3	18.4	15.6	263.3		88.3		57
Series 1 preferred unit distributions (Note 7)												90		58.2
Accretion of discount on Series 1 preferred units (Note 7)												14.9		9.2
Net income attributable to general and limited partner ownership interests in Enbridge Energy Partners, L.P.		214.1		20.5	43.9	93.3	-16.8		14.9	89.9	-83.3	371.8		4.7		493.1
Total assets		17,746.90					14,901.50					17,746.90		14,901.50		12,796.80
Capital expenditures (excluding acquisitions)												2,799.40		2,600.80		1,826.20
Gain on sale of assets	17.1													17.1
Operating Segments [Member]
Segment Reporting Information [Line Items]
Commodity sales																5,120.50
Transportation and other services																1,587.10
Intersegment Revenue Eliminations [Member]
Segment Reporting Information [Line Items]
Total operating revenue																-1.5
Liquids [Member]
Segment Reporting Information [Line Items]
Commodity sales													[1]		[2]
Transportation and other services												2,070.40	[1]	1,519.90	[2]
Total operating revenue												2,070.40	[1]	1,519.90	[2]	1,345.80
Commodity costs
Environmental costs, net of recoveries												97.3		273.7
Environmental costs, net of recoveries																-91.3
Operating and administrative												500.8		461		371.5
Power												226.6		147.7		148.8
Depreciation and amortization												306.8		244.9		210
Costs and Expenses, Total												1,131.50		1,127.30		639
Operating income												938.9		392.6		706.8
Interest expense, net
Allowance for equity used during construction
Other income (expense)
Income before income tax expense												938.9		392.6		706.8
Income tax expense
Net income												938.9		392.6		706.8
Noncontrolling interest (Note 12)
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.												938.9		392.6		706.8
Total assets		11,871.20					9,268.90					11,871.20		9,268.90		7,361.10
Capital expenditures (excluding acquisitions)												2,563.40		2,330.70		1,373.40
Liquids [Member] \| Operating Segments [Member]
Segment Reporting Information [Line Items]
Transportation and other services																1,347.30
Liquids [Member] \| Intersegment Revenue Eliminations [Member]
Segment Reporting Information [Line Items]
Total operating revenue																-1.5
Natural Gas [Member]
Segment Reporting Information [Line Items]
Commodity sales												5,693.90	[1]	5,368.50	[2]
Transportation and other services												200.4	[1]	228.7	[2]
Total operating revenue												5,894.30	[1]	5,597.20	[2]	5,360.30
Commodity costs												5,145.90		4,948.90		4,570.10
Environmental costs, net of recoveries
Environmental costs, net of recoveries
Operating and administrative												438.6		449.8		466.7
Power
Depreciation and amortization												151.4		143.1		134.8
Costs and Expenses, Total												5,735.90		5,541.80		5,171.60
Operating income												158.4		55.4		188.7
Interest expense, net
Allowance for equity used during construction
Other income (expense)												13.2	[3]	-1.5	[4]
Income before income tax expense												171.6		53.9		188.7
Income tax expense
Net income												171.6		53.9		188.7
Noncontrolling interest (Note 12)
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.												171.6		53.9		188.7
Total assets		5,633.50	[5]				4,635.10	[6]				5,633.50	[5]	4,635.10	[6]	5,334.80	[7]
Capital expenditures (excluding acquisitions)												230		251.3		439.7
Equity Method Investments		380.6					371.3					380.6		371.3		183.7
Natural Gas [Member] \| Operating Segments [Member]
Segment Reporting Information [Line Items]
Commodity sales																5,120.50
Transportation and other services																239.8
Corporate [Member]
Segment Reporting Information [Line Items]
Commodity sales													[1],[8]		[2],[8]
Transportation and other services													[1],[8]		[2],[8]
Total operating revenue													[1],[8]		[2],[8]		[8]
Commodity costs													[8]		[8]		[8]
Environmental costs, net of recoveries													[8]		[8]
Environmental costs, net of recoveries																	[8]
Operating and administrative												10.6	[8]	7.6	[8]	2.3	[8]
Power													[8]		[8]		[8]
Depreciation and amortization													[8]		[8]		[8]
Costs and Expenses, Total												10.6	[8]	7.6	[8]	2.3	[8]
Operating income												-10.6	[8]	-7.6	[8]	-2.3	[8]
Interest expense, net												403.2	[8]	320.4	[8]	345	[8]
Allowance for equity used during construction												57.2	[8]	43.1	[8]	11.2	[8]
Other income (expense)												-4.3	[8]	17.5	[8],[9]	-1.2	[8]
Income before income tax expense												-360.9	[8]	-267.4	[8]	-337.3	[8]
Income tax expense												9.6	[8]	18.7	[8]	8.1	[8]
Net income												-370.5	[8]	-286.1	[8]	-345.4	[8]
Noncontrolling interest (Note 12)												263.3	[8]	88.3	[8]	57	[8]
Series 1 preferred unit distributions (Note 7)												90	[8]	58.2	[8]
Accretion of discount on Series 1 preferred units (Note 7)												14.9	[8]	9.2	[8]
Net income attributable to general and limited partner ownership interests in Enbridge Energy Partners, L.P.												-738.7	[8]	-441.8	[8]	-402.4	[8]
Total assets		242.2	[8]				997.5	[8]				242.2	[8]	997.5	[8]	100.9	[8]
Capital expenditures (excluding acquisitions)												6	[8]	18.8	[8]	13.1	[8]
Gain on sale of assets														17.1
Corporate [Member] \| Operating Segments [Member]
Segment Reporting Information [Line Items]
Commodity sales																	[8]
Transportation and other services																	[8]
Corporate [Member] \| Intersegment Revenue Eliminations [Member]
Segment Reporting Information [Line Items]
Total operating revenue																	[8]

[1]	There were no intersegment revenues for the year ended December 31, 2014.
[2]	There were no intersegment revenues for the year ended December 31, 2013.
[3]	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.
[4]	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.
[5]	Totals assets for our Natural Gas Segment includes $380.6 million for our long term equity investment in the Texas Express NGL system.
[6]	Totals assets for our Natural Gas Segment includes $ 371.3 million for our long term equity investment in the Texas Express NGL system.
[7]	Total assets for our Natural Gas Segment includes $183.7 million for our long-term equity investment in the Texas Express NGL system.
[8]	Corporate consists of interest expense, interest income, allowance for equity during construction, noncontrolling interest and other costs such as income taxes, which are not allocated to the business segments.
[9]	Other income (expense) for our Corporate segment includes a gain of $17.1 million from the El Dorado storage facility sale in November of 2013.

REGULATORY_MATTERS_Details

REGULATORY MATTERS (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Regulatory assets	$6	$7.70
Current Year (Over)/Under Recovery Revenue Adjustments	6	7.7	-15.3
Amortization of Prior Year Regulatory (Asset)/Liability	-7.7	15.3	43.6
Allowance for equity used during construction	57.2	43.1	11.2
Southern Access Pipeline [Member]
Qualifying volume liabilities		6.1
Amortization through revenue	6.1	6.3
Alberta Clipper Pipeline [Member]
Qualifying volume liabilities	5.9	6.9
Amortization through revenue	$6.90	$6
Obligation to refund overcollection to customers	50.00%

SUPPLEMENTAL_CASH_FLOW_INFORMA

SUPPLEMENTAL CASH FLOW INFORMATION (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
SUPPLEMENTAL CASH FLOW INFORMATION [Abstract]
Interest (net of capitalization)	$332.40	$342.30	$352.10
Income taxes	1.5	2.5	7.6
Additions to property, plant and equipment	2,933.60	2,409.90	1,739.90
Increase (decrease) in construction payables	-141	190.9	86.3
Capital leases	6.8
Total capital expenditures (excluding investment in joint venture)	$2,799.40	$2,600.80	$1,826.20

QUARTERLY_FINANCIAL_DATA_Unaud2

QUARTERLY FINANCIAL DATA (Unaudited) (Details) (USD $)	3 Months Ended								12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
QUARTERLY FINANCIAL DATA (Unaudited) [Abstract]
Operating revenue	$2,071.70	$1,942.30	$1,871.10	$2,079.60	$1,962	$1,789.40	$1,672.70	$1,693	$7,964.70		$7,117.10		$6,706.10
Operating expense	1,621	1,701.90	1,690.20	1,864.90	1,856.60	1,665.80	1,463.70	1,690.60	6,878		6,676.70		5,812.90
Operating income	450.7	240.4	180.9	214.7	105.4	123.6	209	2.4	1,086.70		440.4		893.2
Net income (loss)	354.3	117.5	112.5	155.7	43.1	61.3	123.7	-67.7	740		160.4		550.1
Less: Net income attributable to noncontrolling interest	113.9	70.7	42.4	36.3	34	20.3	18.4	15.6	263.3		88.3		57
Net income (loss) attributable to general and limited partner ownership interest in Enbridge Energy Partners, L.P.	$214.10	$20.50	$43.90	$93.30	($16.80)	$14.90	$89.90	($83.30)	$371.80		$4.70		$493.10
Net income (loss) per limited partner unit (basic) (in dollars per share)	$0.51	($0.04)	$0.02	$0.18	($0.15)	($0.05)	$0.18	($0.36)	$0.67	[1]	($0.39)	[1]	$1.27	[1]
Net income (loss) per common unit and i-unit (diluted) (in dollars per share)	$0.51	($0.04)	$0.02	$0.18	($0.15)	($0.05)	$0.18	($0.36)	$0.67	[1]	($0.39)	[1]	$1.27	[1]

[1]	For the year ended December 31, 2014 and 2013, 43,201,310 anti-dilutive Preferred Units were excluded from the if-converted method of calculating diluted earnings per unit. For the year ended December 31, 2014, 66,100,000 anti-dilutive Class D units were excluded from the if-converted method of calculating diluted earnings per unit.

SUBSEQUENT_EVENTS_Details

SUBSEQUENT EVENTS (Details) (USD $)	12 Months Ended						0 Months Ended		1 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012		Feb. 13, 2015	Jan. 02, 2015	Feb. 09, 2015	Jan. 30, 2015	Feb. 14, 2015
Subsequent Event [Line Items]
Cash available for distribution	$874.70		$825		$747
Distribution Made to Member or Limited Partner, Distributions Paid, Per Unit	$2.20		$2.17		$2.15
Total amount of distribution paid	727.8		708.9		660.3
Amount of Distribution	731		695.6		636.3
Repayment of debt	12		12		12
Subsequent Event [Member]
Subsequent Event [Line Items]
Distribution declaration date	29-Jan-15
Record Date	6-Feb-15
Distribution payment date	13-Feb-15
Cash available for distribution	233.9
Distribution Made to Member or Limited Partner, Distributions Paid, Per Unit							$0.57
Total amount of distribution paid							194.2
Repayment of debt								306
Subsequent Event [Member] \| Class E Units [Member]
Subsequent Event [Line Items]
Conversion ratio (in percentage)								100.00%
Notional value (in dollars per share)								$38.31
Redemption term								30 years
Trading window used in determining the notional value								5 days
Earnings threshold determining cancellation of units								265.9
Number of partnership units potentially cancellable (in shares)								1,305,142
Amount of gross income threshold resulting in special allocations								40
Amount of gross income threshold resulting in special allocations, secondary period								20
Subsequent Event [Member] \| Eaglebine Acquisition [Member]
Subsequent Event [Line Items]
Payments to acquire interest in business									85
Subsequent Event [Member] \| Alberta Clipper Pipeline [Member]
Subsequent Event [Line Items]
Percentage of interest acquired (in percentage)								66.70%
Subsequent Event [Member] \| Alberta Clipper Pipeline [Member] \| Class E Units [Member]
Subsequent Event [Line Items]
Number of units issued (in shares)								18,114,975
Value of equity transferred								694
Alberta Clipper Pipeline [Member]
Subsequent Event [Line Items]
Total amount of distribution paid	91.5		80.7		89.9
Amount Paid To Parent	30.5		26.9		30
Amount paid to the noncontrolling interest	61		53.8		59.9
Alberta Clipper Pipeline [Member] \| Subsequent Event [Member]
Subsequent Event [Line Items]
Amount Paid To Parent										13.7
Amount paid to the noncontrolling interest										27.5
Series EA [Member]
Subsequent Event [Line Items]
Total amount of distribution paid	89.6
Amount Paid To Parent	22.7
Amount paid to the noncontrolling interest	66.9
Series EA [Member] \| Subsequent Event [Member]
Subsequent Event [Line Items]
Amount Paid To Parent										22.3
Amount paid to the noncontrolling interest										67
Series ME Interests [Member] \| Subsequent Event [Member]
Subsequent Event [Line Items]
Amount Paid To Parent										1.8
Amount paid to the noncontrolling interest										5.2
Midcoast Energy Partners [Member]
Subsequent Event [Line Items]
Total amount of distribution paid	52.7
Amount Paid To Parent	28.5
Amount paid to the noncontrolling interest	24.2
Midcoast Energy Partners [Member] \| Subsequent Event [Member]
Subsequent Event [Line Items]
Distribution declaration date	28-Jan-15
Record Date	6-Feb-15
Distribution payment date	13-Feb-15
Cash available for distribution	15.8
Distribution Made to Member or Limited Partner, Distributions Paid, Per Unit											$0.34
Amount of Distribution											7.3
Amount Paid To Parent											8.5
Midcoast Operating [Member] \| Subsequent Event [Member]
Subsequent Event [Line Items]
Amount Paid To Parent											21.1
Amount paid to the noncontrolling interest											19.8
i-Units [Member]
Subsequent Event [Line Items]
Amount of Distribution	143.9	[1]	113.8	[1]	85	[1]
i-Units [Member] \| Subsequent Event [Member]
Subsequent Event [Line Items]
Amount of Distribution							38.9
General Partner [Member]
Subsequent Event [Line Items]
Total amount of distribution paid	3	[2]	2.3	[2]	1.7	[2]
General Partner [Member] \| Subsequent Event [Member]
Subsequent Event [Line Items]
Amount Paid To Parent							$0.80

[1]	We issued 4,562,088, 3,769,989 and 2,632,090 i-units to Enbridge Management, L.L.C., the sole owner of our i-units, during 2014, 2013 and 2012, respectively, in lieu of cash.
[2]	We retained an amount equal to 2% of the i-unit distribution from our General Partner to maintain its 2% general parner interest in us.