Midcoast Energy Partners (MEP) 10-Q 30 Oct 15 2015 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2015	Oct. 30, 2015
Document and Entity Information [Abstract]
Entity Registrant Name	Midcoast Energy Partners, L.P.
Entity Central Index Key	1,578,685
Document Type	10-Q
Document Period End Date	Sep. 30, 2015
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding		22,610,056
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	Q3
Trading Symbol	mep

CONSOLIDATED STATEMENTS OF INCO

CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Operating revenues:
Operating revenue (Note 14)	$ 649	$ 1,348.8	$ 2,252.3	$ 4,268.4
Operating revenue - affiliate (Notes 12 and 14)	12	50.6	62.3	174.7
Total operating revenue	661	1,399.4	2,314.6	4,443.1
Operating expenses:
Cost of natural gas and natural gas liquids	522.7	1,238.2	1,972.4	3,986.7
Operating and maintenance	74	80.6	206.9	246.5
General and administrative	$ 21.2	$ 25.9	61.1	$ 74.7
Goodwill impairment (Note 8)			226.5
Asset impairment (Note 7)			12.3
Depreciation and amortization (Note 7)	$ 39.2	$ 39.5	118.3	$ 113.3
Costs and Expenses, Total	657.1	1,384.2	2,597.5	4,421.2
Operating income (loss)	3.9	15.2	(282.9)	21.9
Interest expense, net (Notes 10 and 12)	(7.6)	(3.6)	(21.5)	(9.7)
Equity in earnings of joint ventures (Note 9)	8.9	6.1	20.5	7.1
Other loss	(0.4)	(0.8)	(0.2)	(0.7)
Income (loss) before income tax expense	4.8	16.9	(284.1)	18.6
Income tax expense (Note 15)	(3.7)	(0.9)	(1.4)	(2.7)
Net income (loss)	1.1	16	(285.5)	15.9
Less: Net income (loss) attributable to noncontrolling interest	4.7	9.7	(125.4)	13.8
Net income (loss) attributable to general and limited partner ownership interest in Midcoast Energy Partners, L.P.	(3.6)	6.3	(160.1)	2.1
Net income (loss) attributable to limited partner ownership interest	$ (3.5)	$ 6.2	$ (156.8)	$ 2.1
Net income (loss) per limited partner unit (basic) (Note 2) (in dollars per share)	$ (0.08)	$ 0.14	$ (3.47)	$ 0.05
Net income (loss) per limited partner unit (diluted) (Note 2) (in dollars per share)	$ (0.08)	$ 0.14	$ (3.47)	$ 0.05
Weighted-average limited partner units outstanding (basic) (in shares)	45.2	45.2	45.2	45.2
Weighted-average limited partner units outstanding (diluted) (in shares)	45.2	45.2	45.2	45.2
Third Party [Member]
Operating expenses:
Cost of natural gas and natural gas liquids	$ 503.3	$ 1,208.5	$ 1,912	$ 3,888.4
Operating and maintenance	48.8	54.3	131.7	165.5
General and administrative	1.6	2.5	4.6	6
Affiliate [Member]
Operating expenses:
Cost of natural gas and natural gas liquids	19.4	29.7	60.4	98.3
Operating and maintenance	25.2	26.3	75.2	81
General and administrative	$ 19.6	$ 23.4	$ 56.5	$ 68.7

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME [Abstract]
Net income (loss)	$ 1.1	$ 16	$ (285.5)	$ 15.9
Other comprehensive income (loss), net of tax (Note 14)	(5.2)	10.2	(16.1)	8.6
Comprehensive income (loss)	(4.1)	26.2	(301.6)	24.5
Less:
Net income (loss) attributable to noncontrolling interest	4.7	9.7	(125.4)	13.8
Other comprehensive income (loss) attributed to noncontrolling interest (Note 12)	(2.5)	6.3	(7.8)	5.3
Comprehensive income (loss) attributable to general and limited partner (Note 12) ownership interests in Midcoast Energy Partners, L.P.	$ (6.3)	$ 10.2	$ (168.4)	$ 5.4

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
Cash provided by operating activities:
Net income (loss)	$ (285.5)	$ 15.9
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization (Note 7)	118.3	$ 113.3
Goodwill impairment (Note 8)	226.5
Derivative fair value net (gains) losses (Note 14)	53.5	$ (11.5)
Inventory market price adjustments (Note 6)	5.4	$ 4.8
Asset impairment (Note 7)	12.3
Distributions from investment in joint ventures	20.5	$ 6.1
Equity earnings from investment in joint ventures (Note 9)	(20.5)	(7.1)
Deferred income taxes (Note 15)	0.2	$ 1.4
Loss on sales of assets	3.2
Other	2.4	$ 0.6
Changes in operating assets and liabilities, net of acquisitions:
Receivables, trade and other	13.9	11.5
Due from General Partner and affiliates	38.7	641.7
Accrued receivables	200.6	28
Inventory (Note 6)	(9.8)	(129.1)
Current and long-term other assets (Note 14)	1.8	(11.5)
Due to General Partner and affiliates	13.3	(487.4)
Accounts payable and other (Notes 5 and 14)	$ (20.6)	(50.6)
Environmental liabilities (Note 13)		0.2
Accrued purchases	$ (177.2)	(21.3)
Interest payable	(3.8)	0.4
Property and other taxes payable	5.4	6.6
Net cash provided by operating activities	198.6	112
Cash used in investing activities:
Additions to property, plant and equipment (Notes 7 and 17)	(155.4)	(166.6)
Changes in restricted cash (Note 12)	32.1	$ 55.6
Acquisitions (Note 3)	(43.9)
Proceeds from sales of assets	2.1
Investment in joint ventures (Note 9)	(3)	$ (35.4)
Distributions from investment in joint ventures in excess of cumulative earnings	9.5	27
Other	(1.6)	(0.8)
Net cash used in investing activities	$ (160.2)	(120.2)
Cash (used in) provided by financing activities:
Proceeds from long-term debt, net of discounts (Note 10)		398.1
Net borrowings under credit facility (Note 10)	$ 60	30
Distributions to partners (Note 11)	$ (48.1)	(37.1)
Acquisition of noncontrolling interest in subsidiary (Note 11)		(350)
Contributions from noncontrolling interest (Note 11)	$ 37.3	111.8
Distributions to noncontrolling interest (Note 11)	(72)	(83.3)
Net cash (used in) provided by financing activities	(22.8)	69.5
Net increase in cash and cash equivalents	$ 15.6	61.3
Cash and cash equivalents at beginning of year		4.9
Cash and cash equivalents at end of period	$ 15.6	$ 66.2

CONSOLIDATED STATEMENTS OF FINA

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents (Note 5)	$ 15.6
Restricted cash (Notes 3, 12 and 14)	25.7	$ 42.8
Receivables, trade and other, net of allowance for doubtful accounts of $1.6 million and $1.8 million, respectively, at September 30, 2015 and December 31, 2014	1.5	15.6
Due from General Partner and affiliates (Note 12)	17.9	49.7
Accrued receivables	29	229.6
Inventory (Note 6)	85.9	81.5
Other current assets (Notes 7 and 14)	136.9	178.1
Assets, Current, Total	312.5	597.3
Property, plant and equipment, net (Note 7)	$ 4,222.7	4,159.7
Goodwill (Note 8)		226.5
Intangible assets, net	$ 277.2	247.7
Equity investment in joint ventures (Note 9)	373.7	380.6
Other assets, net (Note 14)	106.7	142.3
Total assets	5,292.8	5,754.1
Current liabilities:
Due to General Partner and affiliates (Note 12)	35.6	41.1
Accounts payable and other (Notes 5, 13 and 14)	89.8	113.8
Accrued purchases	198	375.2
Property and other taxes payable (Note 15)	26.3	20.9
Interest payable	1.2	5
Liabilities, Current, Total	350.9	556
Long-term debt (Note 10)	820	760
Other long-term liabilities (Notes 13 and 15)	49.8	41.5
Total liabilities	$ 1,220.7	$ 1,357.5
Commitments and contingencies (Note 13)
Partners' capital (Note 11):
General Partner units (922,859 authorized and issued at September 30, 2015 and December 31, 2014)	$ 43.6	$ 47.8
Accumulated other comprehensive income (Note 14)	3.3	11.6
Total Midcoast Energy Partners, L.P. partners' capital	1,651.1	1,867.6
Noncontrolling interest	2,421	2,529
Total partners' capital	4,072.1	4,396.6
Liabilities and Stockholders' Equity, Total	5,292.8	5,754.1
Class A Common Units [Member]
Partners' capital (Note 11):
Limited Partner interest	532.2	634.2
Subordinated Units [Member]
Partners' capital (Note 11):
Limited Partner interest	$ 1,072	$ 1,174

CONSOLIDATED STATEMENTS OF FIN6

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION (Parenthetical) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Receivables, trade and other, allowance for doubtful accounts (in dollars)	$ 1.6	$ 1.8
General Partner, units outstanding (in shares)	922,859	922,859
Class A Common Units [Member]
Partners Capital units, outstanding (in shares)	22,610,056	22,610,056
Subordinated Units [Member]
Partners Capital units, outstanding (in shares)	22,610,056	22,610,056

ORGANIZATION AND NATURE OF OPER

ORGANIZATION AND NATURE OF OPERATIONS	9 Months Ended
	Sep. 30, 2015
ORGANIZATION AND NATURE OF OPERATIONS [Abstract]
ORGANIZATION AND NATURE OF OPERATIONS	1. ORGANIZATION AND NATURE OF OPERATIONS Midcoast Energy Partners, L.P. is a publicly-traded Delaware limited partnership formed by Enbridge Energy Partners, L.P., or EEP, to serve as EEP's primary vehicle for owning and growing its natural gas and natural gas liquids midstream business in the United States. Midcoast Energy Partners, L.P., together with its consolidated subsidiaries, are referred to in this report as “we,” “us,” “our,” “MEP” and the “Partnership.” For the first six months of 2014, we owned a 39 61 12.6 51.6 48.4 52 Basis of Presentation We have prepared the accompanying unaudited interim consolidated financial statements in accordance with generally accepted accounting principles in the United States of America, or GAAP, for interim consolidated financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. Accordingly, the unaudited interim consolidated financial statements do not include all the information and footnotes required by GAAP for complete consolidated financial statements. In the opinion of management, they contain all adjustments, consisting only of normal recurring adjustments, which management considers necessary to present fairly our financial position as of September 30, 2015, our results of operations for the three and nine months ended September 30, 2015 and 2014, and our cash flows for the nine months ended September 30, 2015 and 2014. We derived our consolidated statement of financial position as of December 31, 2014, from the audited financial statements included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2014. Our results of operations for the three and nine months ended September 30, 2015 and 2014, should not be taken as indicative of the results to be expected for the full year due to seasonal fluctuations in the supply of and demand for natural gas, NGLs and crude oil, timing and completion of our construction projects, maintenance activities, the impact of forward commodity prices and differentials on derivative financial instruments that are accounted for at fair value. Our unaudited interim consolidated financial statements should be read in conjunction with our audited consolidated financial statements and notes thereto presented in our Annual Report on Form 10-K for the fiscal year ended December 31, 2014.

NET INCOME PER LIMITED PARTNER

NET INCOME PER LIMITED PARTNER AND GENERAL PARTNER INTEREST	9 Months Ended
	Sep. 30, 2015
NET INCOME PER LIMITED PARTNER AND GENERAL PARTNER INTEREST [Abstract]
NET INCOME PER LIMITED PARTNER AND GENERAL PARTNER INTEREST	2. NET INCOME PER LIMITED PARTNER AND GENERAL PARTNER INTEREST We allocate our net income among our General Partner and limited partners using the two-class method. Under the two-class method, we allocate our net income to our limited partners, our General Partner and the holders of our IDRs in accordance with the terms of our partnership agreement. We also allocate any earnings in excess of distributions to our limited partners, our General Partner and the holders of the IDRs in accordance with the terms of our partnership agreement. We allocate any distributions in excess of earnings for the period to our General Partner and our limited partners based on their respective proportionate ownership interests in us, after taking into account distributions to be paid with respect to the IDRs, as set forth in our partnership agreement. Distribution Targets Portion of Quarterly Percentage Distributed to Percentage Distributed Minimum Quarterly Distribution Up to $ 0.3125 98 % 2 % First Target Distribution > $ 0.3125 0.359375 98 % 2 % Second Target Distribution > $ 0.359375 0.390625 85 % 15 % Third Target Distribution > $ 0.390625 0.468750 75 % 25 % Over Third Target Distribution In excess of $ 0.468750 50 % 50 % We determined basic and diluted net income (loss) per limited partner unit as follows: For the three months For the nine months ended September 30, ended September 30, 2015 2014 2015 2014 (in millions, except per unit amounts) Net income (loss) $ 1.1 $ 16.0 $ (285.5 ) $ 15.9 Less: Net income (loss) attributable to noncontrolling interest 4.7 9.7 (125.4 ) 13.8 Net income (loss) attributable to general and limited partner interests in Midcoast Energy Partners, L.P. (3.6 ) 6.3 (160.1 ) 2.1 Less distributions: Total distributed earnings to our General Partner (0.3 ) (0.3 ) (0.9 ) (0.9 ) Total distributed earnings to our limited partners (16.2 ) (15.3 ) (47.9 ) (44.1 ) Total distributed earnings (16.5 ) (15.6 ) (48.8 ) (45.0 ) Overdistributed earnings $ (20.1 ) $ (9.3 ) $ (208.9 ) $ (42.9 ) Weighted-average limited partner units outstanding 45.2 45.2 45.2 45.2 Basic and diluted earnings per unit: Distributed earnings per limited partner unit (1) $ 0.36 $ 0.34 $ 1.06 $ 0.98 Overdistributed earnings per limited partner unit (2) (0.44 ) (0.20 ) (4.53 ) (0.93 ) Net income (loss) per limited partner unit (basic and diluted) $ (0.08 ) $ 0.14 $ (3.47 ) $ 0.05 (1) Represents the total distributed earnings to limited partners divided by the weighted-average number of limited partner interests outstanding for the period. (2) Represents the limited partners' share (98

ACQUISITIONS AND DISPOSITIONS

ACQUISITIONS AND DISPOSITIONS	9 Months Ended
	Sep. 30, 2015
ACQUISITIONS AND DISPOSITIONS [Abstract]
ACQUISITIONS AND DISPOSITIONS	3. ACQUISITIONS AND DISPOSITIONS Acquisitions We account for acquisitions using the acquisition method and record the identifiable assets acquired and liabilities assumed at their acquisition-date fair values. We have included the results of operations in our operating results from the acquisition date. On February 27, 2015, we acquired the midstream business of New Gulf Resources, LLC, or NGR, in Leon, Madison and Grimes counties, Texas. The acquisition consisted of a natural gas gathering system that is in operation. This acquisition strengthened our position into the Eaglebine play, and will continue to allow us to offer gathering and processing services while leveraging assets on our existing footprint. We acquired the midstream business of NGR for $ 85.0 17.0 85.0 20.0 5.0 15.0 If NGR is able to deliver volumes into the system at certain tiered volume levels over a five 17.0 102.0 2.3 2.5 0.2 Funding was provided by us and EEP, based on our proportionate ownership percentages in Midcoast Operating, at the time of acquisition, which was 51.6 48.4 As of September 30, 2015, the consideration paid and the purchase price allocation related to the NGR acquisition, as adjusted to date, are as follows: September 30, 2015 (in millions) Consideration: Cash consideration $ 85.0 Contingent consideration 2.3 $ 87.3 Identifiable assets acquired in business combination: Property, plant and equipment $ 55.1 Intangible assets 32.2 $ 87.3 The weighted-average amortization period of intangible assets related to the NGR acquisition is 15 0.6 0.1 1.2 0.2 Since the effective date of the NGR midstream business acquisition was February 27, 2015, our consolidated statements of income do not include earnings from this business prior to that date. The following table presents selected unaudited pro forma earnings information for the three and nine months ended September 30, 2015 and 2014, as if the acquisition had been completed on January 1, 2014. This pro forma information was prepared using historical financial data for the NGR midstream business and reflects certain estimates and assumptions made by our management based on currently available information. Our unaudited pro forma financial information is not necessarily indicative of what our consolidated financial results would have been for the three and nine months ended September 30, 2015 and 2014, had we acquired the NGR midstream business on January 1, 2014. For the three months For the nine months ended September 30, ended September 30, 2015 2014 2015 2014 (unaudited; in millions, except per unit amounts) Pro forma earnings data: Operating revenue $ 661.0 $ 1,399.6 $ 2,314.7 $ 4,443.8 Operating expenses $ 657.1 $ 1,384.4 $ 2,597.9 $ 4,422.5 Operating income (loss) $ 3.9 $ 15.2 $ (283.2 ) $ 21.3 Net income (loss) $ 1.1 $ 16.0 $ (285.8 ) $ 15.3 Net income (loss) attributable to noncontrolling interest $ 4.7 $ 9.7 $ (125.5 ) $ 13.5 Net income (loss) attributable to limited partner ownership interest $ (3.6 ) $ 6.3 $ (160.3 ) $ 1.8 Basic and diluted earnings per unit: As reported net income (loss) per limited partner unit (basic and diluted) $ (0.08 ) $ 0.14 $ (3.47 ) $ 0.05 Pro forma net income (loss) per limited partner unit (basic and diluted) $ (0.08 ) $ 0.14 $ (3.46 ) $ 0.04 Dispositions On September 1, 2015, two We received net proceeds of $ 4.3 9.3 4.2 14 1.3

EQUITY-BASED COMPENSATION

EQUITY-BASED COMPENSATION	9 Months Ended
	Sep. 30, 2015
EQUITY-BASED COMPENSATION [Abstract]
EQUITY-BASED COMPENSATION	4. EQUITY-BASED COMPENSATION In November 2013, our General Partner adopted the 2013 Midcoast Energy Partners, L.P. Long-Term Incentive Plan, or the LTIP. The LTIP provides for the grant of, from time to time at the discretion of the board of directors of our General Partner or any delegate thereof, subject to applicable law, unit awards, restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights and other unit-based awards, provided that while we are an affiliate of Enbridge, awards will only be granted following a recommendation of the board of directors or compensation committee of Enbridge to the board of our General Partner. The purpose of awards under the LTIP is to provide additional incentive compensation to individuals providing services to us, and to align the economic interests of such individuals with the interests of our unitholders. On February 17, 2015, the board of our General Partner approved the first grant of Performance Stock Units, or PSUs, effective January 1, 2015, under the LTIP. These PSUs were granted to employees of affiliates of our General Partner performing services on our behalf and provide for cash awards to be paid at the end of the three 100 20 The performance multiplier ranges from zero two The following table presents PSU activity for the period indicated: Weighted Average Average Intrinsic Performance Remaining Value Stock Units Term (years) (in millions) January 1, 2015 — Units granted 323,880 Units matured — Units forfeited (1,948 ) Distribution reinvested 27,384 September 30, 2015 349,316 2.3 $ 3.6 The PSUs are paid in cash and therefore classified as a liability award. The liability is re-measured at fair value on each reporting date until the award is settled, with the offset for the change in fair value being recorded as compensation expense based on the percentage of the requisite service that has been rendered at the reporting date. During the vesting term, compensation expense is determined based on the number of PSUs outstanding, the current market price of our Class A common units, dividends reinvested, and performance multipliers. The LTIP agreement and the individual award agreements are between our General Partner and the participants in the LTIP agreement. The associated compensation costs and liability are recorded in our consolidated financial statements based on the approved allocation methodology as some of the recipients of our PSUs provide shared services to us, EEP and other Enbridge entities. Similar to other employee compensation costs, Enbridge Employee Services Incorporated, or EESI, will make the PSU payments to the LTIP participants on behalf of us, EEP and other Enbridge entities who will then reimburse EESI, for their respective obligation, via an affiliate payable for the disbursements made to the participants. To calculate the compensation expense for the three and nine months ended September 30, 2015, a performance multiplier of one 0.3 0.9 0.1 0.3 3.8 two

CASH AND CASH EQUIVALENTS

CASH AND CASH EQUIVALENTS	9 Months Ended
	Sep. 30, 2015
CASH AND CASH EQUIVALENTS [Abstract]
CASH AND CASH EQUIVALENTS	5. CASH AND CASH EQUIVALENTS We extinguish liabilities when a creditor has relieved us of our obligation, which occurs when our financial institution honors a check that the creditor has presented for payment. Accordingly, obligations for which we have made payments that have not yet been presented to the financial institution, totaling approximately $ 4.7 6.6

INVENTORY

INVENTORY	9 Months Ended
	Sep. 30, 2015
INVENTORY [Abstract]
INVENTORY	6. INVENTORY Our inventory is comprised of the following: September 30, December 31, 2015 2014 (in millions) Materials and supplies $ 0.6 $ 0.7 Crude oil inventory — 2.0 Natural gas and NGL inventory 85.3 78.8 $ 85.9 $ 81.5 The “Cost of natural gas and natural gas liquids” on our consolidated statements of income includes charges totaling $ 0.1 1.5 5.4 4.8

PROPERTY, PLANT AND EQUIPMENT

PROPERTY, PLANT AND EQUIPMENT	9 Months Ended
	Sep. 30, 2015
PROPERTY, PLANT AND EQUIPMENT [Abstract]
PROPERTY, PLANT AND EQUIPMENT	7. PROPERTY, PLANT AND EQUIPMENT Our property, plant and equipment is comprised of the following: September 30, December 31, 2015 2014 (in millions) Land $ 14.2 $ 11.1 Rights-of-way 436.2 405.0 Pipelines 1,848.3 1,785.7 Pumping equipment, buildings and tanks 88.4 82.1 Compressors, meters and other operating equipment 2,145.6 2,074.8 Vehicles, office furniture and equipment 137.5 163.8 Processing and treating plants 632.8 516.0 Construction in progress 74.4 218.7 Total property, plant and equipment 5,377.4 5,257.2 Accumulated depreciation (1,154.7 ) (1,097.5 ) Property, plant and equipment, net $ 4,222.7 $ 4,159.7 On July 31, 2015, we sold our non-core Tinsley crude oil pipeline, storage facilities, and docks in our Logistics and Marketing segment and our non-core Louisiana propylene pipeline in our Gathering, Processing and Transportation segment. The sale price was $ 1.3 4.5 3.2 12.3

GOODWILL

GOODWILL	9 Months Ended
	Sep. 30, 2015
GOODWILL [Abstract]
GOODWILL	8. GOODWILL Goodwill represents the excess of the purchase price of an entity over the estimated fair value of the assets acquired and liabilities assumed. Our goodwill originated from acquisitions by EEP that are fully associated with our gathering, processing and transportation and logistics and marketing businesses. As of December 31, 2014, the carrying amount of goodwill was $ 226.5 206.1 20.4 We test goodwill for impairment annually or more frequently if events or changes in circumstances indicate that it is more likely than not that the fair value of a reporting unit is less than its carrying value. During May 2015, due to adverse market conditions facing our business, we learned from producers that reductions in drilling will be sustained and prolonged due to continued low prices for natural gas and NGLs. As a result, we determined that the impact on our forecasted operating profits and cash flows for both the gathering, processing and transportation and marketing reporting units for the next five years would be significantly reduced from our prior forecasts. During the second quarter of 2015, we performed the first step of our goodwill impairment analysis and determined that the carrying value of the gathering, processing and transportation and marketing reporting units exceeded fair value. We completed the second step of the goodwill impairment analysis comparing the implied fair value of the reporting units to the carrying amounts of that goodwill and determined that goodwill was completely impaired, including $ 206.1 20.4 226.5 We measure the fair value of our reporting units 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. Our estimate of fair value required us to use significant unobservable inputs representative of a Level 3 fair value measurement, including assumptions related to the future performance of our gathering, processing and transportation and marketing reporting units.

EQUITY INVESTMENTS IN JOINT VEN

EQUITY INVESTMENTS IN JOINT VENTURES	9 Months Ended
	Sep. 30, 2015
EQUITY INVESTMENTS IN JOINT VENTURES [Abstract]
EQUITY INVESTMENTS IN JOINT VENTURES	9. EQUITY INVESTMENTS IN JOINT VENTURES We have a 35 two 593 100 For the three months For the nine months ended September 30, ended September 30, 2015 2014 2015 2014 (in millions) Operating revenues $ 36.5 $ 27.3 $ 93.9 $ 51.7 Operating expenses $ 11.1 $ 9.7 $ 33.8 $ 30.0 Net income $ 25.4 $ 17.5 $ 59.9 $ 21.6

DEBT

DEBT	9 Months Ended
	Sep. 30, 2015
DEBT [Abstract]
DEBT	10. DEBT The following table presents the carrying amounts, net of related unamortized discounts, of our consolidated debt obligations. September 30, December 31, Interest Rate 2015 2014 (in millions) Credit Agreement due 2016-2018 2.672 % $ 420.0 $ 360.0 Series A Senior Notes due September 2019 3.560 % 75.0 75.0 Series B Senior Notes due September 2021 4.040 % 175.0 175.0 Series C Senior Notes due September 2024 4.420 % 150.0 150.0 Total $ 820.0 $ 760.0 Our interest cost for the three and nine months ended September 30, 2015, and 2014, is comprised of the following: For the three months For the nine months ended September 30, ended September 30, 2015 2014 2015 2014 (in millions) Interest cost incurred $ 7.8 $ 4.0 $ 23.0 $ 10.3 Less: Interest capitalized 0.2 0.4 1.5 0.6 Interest expense, net $ 7.6 $ 3.6 $ 21.5 $ 9.7 Debt Arrangements Credit Agreement We, Midcoast Operating, and our material domestic subsidiaries are parties to the Credit Agreement, which previously permitted aggregate borrowings of up to, at any one time outstanding, $ 850.0 810.0 three four September 30, 2018 140.0 November 13, 2016 25.0 September 30, 2017 At September 30, 2015, we had $ 420.0 2.67 $ 60.0 $ 4,160.0 $ 4,100.0 Senior Notes Our senior notes in the aggregate amount of $ 400.0 75.0 3.56 175.0 4.04 150.0 4.42 Financial Support Agreement Midcoast Operating is party to a Financial Support Agreement with EEP, pursuant to which EEP provides letters of credit and guarantees, not to exceed $ 700.0 The annual costs that Midcoast Operating incurs under the Financial Support Agreement are based on the cumulative average amount of letters of credit and guarantees that EEP provides on behalf of Midcoast Operating and its wholly-owned subsidiaries, multiplied by a 2.5 0.1 $ 0.4 Available Credit At September 30, 2015, we had approximately$ 390.0 (in millions) Total credit limit under Credit Agreement $ 810.0 Amounts outstanding under Credit Agreement (420.0 ) Total amount available at September 30, 2015 $ 390.0 Fair Value of Debt Obligations The carrying amount of our outstanding borrowings under the Credit Agreement approximates the fair value at September 30, 2015 and December 31, 2014, respectively, due to the short-term nature and frequent repricing of the amounts outstanding under these obligations. The outstanding borrowings under the Credit Agreement are included with our long-term debt obligations since we have the ability and the intent to refinance the amounts outstanding on a long-term basis. The approximate fair values of our fixed-rate debt obligations were $ 393.0

PARTNERS' CAPITAL

PARTNERS' CAPITAL	9 Months Ended
	Sep. 30, 2015
PARTNERS' CAPITAL [Abstract]
PARTNERS' CAPITAL	11. PARTNERS' CAPITAL Distribution to Partners The following table sets forth our distributions, as approved by the board of directors of our General Partner, during the nine months ended September 30, 2015. Distribution Distribution Distribution Cash Declaration Date Record Date Payment Date per Unit Distributed (in millions, except per unit amounts) July 29, 2015 August 7, 2015 August 14, 2015 $ 0.35250 $ 16.3 April 29, 2015 May 8, 2015 May 15, 2015 $ 0.34750 $ 16.0 January 28, 2015 February 6, 2015 February 13, 2015 $ 0.34250 $ 15.8 We paid cash distributions to EEP for its ownership interest in us totaling $ 8.8 8.1 25.9 20.0 Distributions to Noncontrolling Interests Midcoast Operating paid cash distributions to EEP for its ownership interest in Midcoast Operating totaling $ 26.2 22.1 72.0 83.3 On July 29, 2015, the partners of Midcoast Operating approved an amendment to Midcoast Operating's limited partnership agreement that would potentially enhance our distributable cash flow, demonstrating EEP's further support of our ongoing cash distribution strategy and growth outlook. The amendment will provide a mechanism for us to receive increased quarterly distributions from Midcoast Operating and for EEP to receive reduced quarterly distributions if our declared distribution exceeds our distributable cash, as that term is defined in Midcoast Operating's limited partnership agreement. Midcoast Operating's adjustment of EEP's distribution will be limited by EEP's pro rata share of the Midcoast Operating quarterly cash distribution and a maximum of $ 0.005 Changes in Partners' Capital The following table presents significant changes in partners' capital accounts attributable to our General Partner and limited partners as well as the noncontrolling interest in our consolidated subsidiary during the nine months ended September 30, 2015 For the nine month ended September 30, 2015 2014 (in millions) Class A common units: Beginning balance $ 634.2 $ 495.3 Net income (loss) (78.4 ) 1.0 Acquisition of noncontrolling interest in subsidiary — 133.3 Distributions (23.6 ) (18.2 ) Ending balance $ 532.2 $ 611.4 Subordinated units: Beginning balance $ 1,174.0 $ 1,035.1 Net income (loss) (78.4 ) 1.1 Acquisition of noncontrolling interest in subsidiary — 133.3 Distributions (23.6 ) (18.2 ) Ending balance $ 1,072.0 $ 1,151.3 General Partner units: Beginning balance $ 47.8 $ 42.2 Net loss (3.3 ) — Acquisition of noncontrolling interest in subsidiary — 5.4 Distributions (0.9 ) (0.7 ) Ending balance $ 43.6 $ 46.9 Accumulated other comprehensive income (loss) Beginning balance $ 11.6 $ (3.1 ) Changes in fair value of derivative financial instruments reclassified to earnings (12.5 ) 5.1 Changes in fair value of derivative financial instruments recognized in other comprehensive income (loss) 4.2 (1.8 ) Ending balance $ 3.3 $ 0.2 Noncontrolling interest Beginning balance $ 2,529.0 $ 2,983.2 Capital contributions 97.2 130.5 Acquisition of noncontrolling interest in subsidiary — (622.0 ) Comprehensive income: Net income (loss) (125.4 ) 13.8 Other comprehensive income (loss), net of tax (7.8 ) 5.3 Distributions to noncontrolling interest (72.0 ) (83.3 ) Ending balance $ 2,421.0 $ 2,427.5 Total partners' capital at end of period $ 4,072.1 $ 4,237.3 Securities Authorized for Issuance under LTIP In connection with our LTIP, we filed a registration statement on Form S-8 with the SEC registering the issuance of 3,750,000 Shelf-Registration Statement From time to time, we may seek to satisfy liquidity needs through the offer and sale of debt or equity securities in public offerings. In December 2014, we filed a shelf-registration statement on Form S-3 with the SEC, which became effective on February 5, 2015, with a proposed aggregate offering price for all securities registered of $ 1.5

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS	9 Months Ended
	Sep. 30, 2015
RELATED PARTY TRANSACTIONS [Abstract]
RELATED PARTY TRANSACTIONS	12. RELATED PARTY TRANSACTIONS Intercorporate Services Agreement We do not directly employ any of the individuals responsible for managing or operating our business nor do we have any directors. We have an Intercorporate Services Agreement with EEP, pursuant to which EEP and its affiliates provides us with services as set forth in the agreement, which include such functions as management, accounting, operational and administrative personnel, among other such functions. Under the Intercorporate Services Agreement, we reimburse EEP and its affiliates for the costs and expenses incurred in providing us with such services. The amounts incurred by us through EEP for services received pursuant to the Intercorporate Services Agreement are reflected in “Operating and maintenance — affiliate” and “General and administrative — affiliate” on our consolidated statements of income. EEP has agreed to reduce the amounts payable for general and administrative expenses that otherwise would have been allocable to Midcoast Operating by $ 25.0 6.3 18.8 Enbridge and Enbridge Management and their respective affiliates allocated direct workforce costs to us for our construction projects of $ 2.2 5.8 Affiliate Revenues and Purchases We sell natural gas, NGLs and crude oil at market prices on the date of sale to Enbridge and its affiliates. The sales to Enbridge and its affiliates are presented in “Operating revenue — affiliate” on our consolidated statements of income. We also purchase natural gas, NGLs and crude oil at market prices on the date of purchase from Enbridge and its affiliates for sale to third parties. The purchases of natural gas, NGLs and crude oil from Enbridge and its affiliates are presented in “Cost of natural gas and natural gas liquids — affiliate” on our consolidated statements of income. Also, included in “Cost of natural gas and natural gas liquids — affiliate,” are $ 5.1 5.4 13.4 16.8 120,000 29,000 Routine purchases and sales with affiliates are settled monthly through MEP's centralized treasury function at terms that are consistent with third-party transactions for the three and nine months ended September 30, 2015 and 2014. Routine purchases and sales with affiliates that have not yet been settled are included in “Due from General Partner and affiliates” and “Due to General Partner and affiliates” on our consolidated statements of financial position. Sale of Accounts Receivable We sold and derecognized receivables to an indirect wholly-owned subsidiary of Enbridge for $ 509.8 845.7 1,752.4 2,702.2 509.7 845.5 1,751.9 2,701.5 221.0 272.7 Consideration for the receivables sold is equivalent to the carrying value of the receivables less a discount for credit risk. The difference between the carrying value of the receivables sold and the cash proceeds received is recognized in “General and administrative — affiliate” expense in our consolidated statements of income. The expense stemming from the discount on the receivables sold was $ 0.1 0.2 0.5 0.7 As of September 30, 2015 and December 31, 2014, we had $ 6.7 17.7

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	9 Months Ended
	Sep. 30, 2015
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 the operating activities of our gathering, processing and transportation and logistics and marketing businesses, and we are, at times, subject to environmental cleanup and enforcement actions. We manage this environmental risk through appropriate environmental policies and practices to minimize any impact our operations may have on the environment. To the extent that we are unable to recover payment for environmental liabilities from insurance or otherwise, we will be responsible for payment of liabilities arising from environmental incidents associated with the operating activities of our gathering, processing and transportation and logistics and marketing businesses. We continue to voluntarily monitor past leak sites on our systems for the purpose of assessing whether any remediation is required in light of current regulations. As of September 30, 2015, we did not have any remaining material accrued environmental liabilities. As of December 31, 2014, we had $ 0.2 Legal and Regulatory Proceedings We are a participant in a number of legal proceedings arising in the ordinary course of business. Some of these proceedings are covered, in whole or in part, by insurance. While the ultimate outcome and impact to us cannot be predicted with certainty, we believe the outcome of all these proceedings will not, individually or in the aggregate, have a material adverse effect on our financial position, results of operations or cash flows. In addition, we are not aware of any significant legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statutes to which we are subject.

DERIVATIVE FINANCIAL INSTRUMENT

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES	9 Months Ended
	Sep. 30, 2015
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 fluctuations in commodity prices of natural gas, NGLs, condensate and fractionation margins. Fractionation margins represent the relative difference between the price we receive from NGL and condensate sales and the corresponding cost of natural gas we purchase for processing. Our exposure to commodity price risk exists within both of our segments. We use derivative financial instruments (i.e., futures, forwards, swaps, options, and other financial instruments with similar characteristics) to manage the risks associated with market fluctuations in commodity prices, as well as to reduce the volatility in our cash flows. Based on our risk management policies, all of our derivative financial instruments are employed in connection with an underlying asset, liability and/or forecasted transaction and are not entered into with the objective of speculating on commodity prices. We have hedged a portion of our exposure to the variability in future cash flows associated with commodity price risks in future periods in accordance with our risk management policies. Our derivative instruments that are designated for hedge accounting under authoritative guidance are classified as cash flow hedges. Derivative Positions Our derivative financial instruments are included at their fair values in the consolidated statements of financial position as follows: September 30, December 31, 2014 (in millions) Other current assets $ 127.6 $ 164.7 Other assets, net 54.3 91.5 Accounts payable and other (1) (58.2 ) (74.4 ) Other long-term liabilities (21.8 ) (22.5 ) Due from General Partner and affiliates — 0.3 $ 101.9 $ 159.6 (1) Includes $ 16.2 28.4 The changes in the assets and liabilities associated with our derivatives are primarily attributable to the effects of new derivative transactions we have entered at prevailing market prices, settlement of maturing derivatives and the change in forward market prices of our remaining hedges. Our portfolio of derivative financial instruments is largely comprised of natural gas, NGL and crude oil sales and purchase contracts. The table below summarizes our derivative balances by counterparty credit quality (negative amounts represent our net obligations to pay the counterparty). September 30, December 31, 2014 (in millions) Counterparty Credit Quality (1) AAA $ 0.2 $ 0.1 AA (2) 67.7 74.4 A 29.6 67.1 Lower than A 4.4 18.0 $ 101.9 $ 159.6 (1) As determined by nationally-recognized statistical ratings organizations. (2) Includes $ 16.2 28.4 As the net value of our derivative financial instruments has decreased in response to changes in forward commodity prices, our outstanding financial exposure to third parties has also decreased. When credit thresholds are met pursuant to the terms of our International Swaps and Derivatives Association, Inc., or ISDA®, financial contracts, we have the right to require collateral from our counterparties. We include any cash collateral received in the balances listed above. As of September 30, 2015, and December 31, 2014, our short-term liabilities included $ 16.2 28.4 4.0 16.2 12.2 The ISDA® agreements and associated credit support, which govern our financial derivative transactions, contain no credit rating downgrade triggers that would accelerate the maturity dates of our outstanding transactions. A change in ratings is not an event of default under these instruments, and the maintenance of a specific minimum credit rating is not a condition to transacting under the ISDA® agreements. In the event of a credit downgrade, additional collateral may be required to be posted under the agreement if we are in a liability position to our counterparty, but the agreement will not automatically terminate and require immediate settlement of all future amounts due. The ISDA® agreements, in combination with our master netting agreements, and credit arrangements governing our commodity swaps require that collateral be posted per tiered contractual thresholds based on the credit rating of each counterparty. We generally provide letters of credit to satisfy such collateral requirements under our ISDA® agreements. These agreements will require additional collateral postings of up to 100 In the event that our credit ratings were to decline below 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 below the lowest level of investment grade at September 30, 2015, we would have been required to provide additional letters of credit in the amount of $ 12.2 At September 30, 2015, and December 31, 2014, we had credit concentrations in the following industry sectors, as presented below: September 30, December 31, 2014 (in millions) United States financial institutions and investment banking entities (1) $ 81.4 $ 88.5 Non-United States financial institutions (6.5 ) 30.7 Integrated oil companies 2.0 1.7 Other 25.0 38.7 $ 101.9 $ 159.6 (1) Includes $ 16.2 28.4 Gross derivative balances are presented below before the effects of collateral received or posted and without the effects of master netting arrangements. Both our assets and liabilities are adjusted for non-performance risk, which is statistically derived. This credit valuation adjustment model considers existing derivative asset and liability balances in conjunction with contractual netting and collateral arrangements, current market data such as credit default swap rates and bond spreads and probability of default assumptions to quantify an adjustment to fair value. For credit modeling purposes, collateral received is included in the calculation of our assets, while any collateral posted is excluded from the calculation of the credit adjustment. Our credit exposure for these over-the-counter, or OTC, derivatives is directly with our counterparty and continues until the maturity or termination of the contracts. Effect of Derivative Instruments on the Consolidated Statements of Financial Position Asset Derivatives Liability Derivatives Fair Value at Fair Value at Financial Position September 30, December 31, September 30, December 31, Location 2015 2014 2015 2014 (in millions) Derivatives designated as cash flow hedging instruments: (1) Commodity contracts Other current assets $ 7.4 $ 26.1 $ — $ — Commodity contracts Other assets — 2.1 — — 7.4 28.2 — — Derivatives not designated as hedging instruments: Commodity contracts Other current assets 120.2 138.6 — — Commodity contracts Other assets 54.3 89.4 — — Commodity contracts Accounts payable and other (2) — — (42.0 ) (46.0 ) Commodity contracts Other long-term liabilities — — (21.8 ) (22.5 ) Commodity contracts Due from general partner and affiliates — 0.3 — — 174.5 228.3 (63.8 ) (68.5 ) Total derivative instruments $ 181.9 $ 256.5 $ (63.8 ) $ (68.5 ) (1) Includes items currently designated as hedging instruments. Excludes the portion of de-designated hedges which may have a component remaining in AOCI. (2) Excludes total of $ 16.2 28.4 Accumulated Other Comprehensive Income We record the change in fair value of our highly effective cash flow hedges in AOCI until the derivative financial instruments are settled, at which time they are reclassified to earnings. As of September 30, 2015 and December 31, 2014, we included in AOCI unrecognized gains of approximately $ 0.4 0.1 During the nine months ended September 30, 2015 and 2014, unrealized commodity hedge gains of $ 1.5 0.2 8.3 Effect of Derivative Instruments on the Consolidated Statements of Income and Accumulated Other Comprehensive Income Amount of Gain (Loss) Recognized in Location of Gain Earnings on (Loss) Recognized in Derivative Earnings on Derivative (Ineffective Portion Amount of Gain Location of Gain (Loss) Amount of Gain (Loss) (Ineffective Portion and Amount Derivatives in Cash (Loss) Recognized in Reclassified from Reclassified from and Amount Excluded from Flow Hedging AOCI on Derivative AOCI to Earnings AOCI to Earnings Excluded from Effectiveness Relationships (Effective Portion) (Effective Portion) (Effective Portion) Effectiveness Testing) (1) Testing) (1) (in millions) For the three months ended September 30, 2015 Commodity contracts $ (5.5 ) Cost of natural gas and natural gas liquids $ 8.5 Cost of natural gas and natural gas liquids $ (0.1 ) For the three months ended September 30, 2014 Commodity contracts $ 11.2 Cost of natural gas and natural gas liquids $ (2.1 ) Cost of natural gas and natural gas liquids $ 0.9 For the nine months ended September 30, 2015 Commodity contracts $ (16.8 ) Cost of natural gas and natural gas liquids $ 24.0 Cost of natural gas and natural gas liquids $ (4.1 ) For the nine months ended September 30, 2014 Commodity contracts $ 7.9 Cost of natural gas and natural gas liquids $ (12.4 ) Cost of natural gas and natural gas liquids $ 1.5 (1) Includes only the ineffective portion of derivatives that are designated as hedging instruments and does not include net gains or losses associated with derivatives that do not qualify for hedge accounting treatment. Components of Accumulated Other Comprehensive Income/(Loss) Cash Flow Hedges 2015 2014 (in millions) Balance at January 1 $ 11.6 $ (3.1 ) Other comprehensive income (loss) before reclassifications (1) (2) 4.1 (1.8 ) Amounts reclassified from AOCI (3) (4) (12.5 ) 5.1 Tax benefit 0.1 — Net other comprehensive income (loss) $ (8.3 ) $ 3.3 Balance at September 30 $ 3.3 $ 0.2 (1) Excludes NCI gain of $ 3.7 2.9 (2) Excludes NCI gain of $ 0.9 (3) Excludes NCI loss of $ 11.5 7.3 (4) For additional details on the amounts reclassified from AOCI, reference the Reclassifications from Accumulated Other Comprehensive Income Reclassifications from Accumulated Other Comprehensive Income For the three months ended For the nine months ended 2015 2014 2015 2014 (in millions) Losses (gains) on cash flow hedges: Commodity Contracts (1)(2)(3) $ (4.5 ) $ 1.1 $ (12.5 ) $ 5.1 Total Reclassifications from AOCI $ (4.5 ) $ 1.1 $ (12.5 ) $ 5.1 (1) Loss (gain) reported within “Cost of natural gas and natural gas liquids” in the consolidated statements of income. (2) Excludes NCI loss of $ 4.0 1.0 (3) Excludes NCI loss of $ 11.5 7.3 Effect of Derivative Instruments on Consolidated Statements of Income For the three months For the nine months ended September 30, ended September 30, Derivatives Not 2015 2014 2015 2014 Designated Location of Gain or (Loss) Amount of Gain or (Loss) Amount of Gain or (Loss) as Hedging Instruments Recognized in Earnings Recognized in Earnings (1)(2) Recognized in Earnings (1)(2) (in millions) Commodity contracts Operating revenue $ (7.2 ) $ 7.7 $ (22.4 ) $ 10.8 Commodity contracts Operating revenue – affiliate — (0.1 ) (0.3 ) 0.4 Commodity contracts Cost of natural gas and natural gas liquids (3) 40.7 9.5 44.3 (9.9 ) Total $ 33.5 $ 17.1 $ 21.6 $ 1.3 (1) Does not include settlements associated with derivative instruments that settle through physical delivery. (2) Includes only net gains or losses associated with those derivatives that do not qualify for hedge accounting treatment and does not include the ineffective portion of derivatives that are designated as hedging instruments. (3) Includes settlements gains (losses) of $ 27.3 0.1 71.0 8.6) 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 ® Offsetting of Financial Assets and Derivative Assets As of September 30, 2015 Gross Gross Amount Net Amount of Assets Gross Amount Amount of Offset in the Presented in the Not Offset in the Recognized Statement of Statement of Statement of Net Assets Financial Position Financial Position Financial Position (1) Amount (in millions) Description: Derivatives $ 181.9 $ — $ 181.9 $ (59.9 ) $ 122.0 As of December 31, 2014 Gross Gross Amount Net Amount of Assets Gross Amount Amount of Offset in the Presented in the Not Offset in the Recognized Statement of Statement of Statement of Net Assets Financial Position Financial Position Financial Position (1) Amount (in millions) Description: Derivatives $ 256.5 $ — $ 256.5 $ (91.8 ) $ 164.7 (1) Includes $ 16.2 28.4 Offsetting of Financial Liabilities and Derivative Liabilities As of September 30, 2015 Gross Gross Amount Net Amount of Liabilities Gross Amount Amount of Offset in the Presented in the Not Offset in the Recognized Statement of Statement of Statement of Net Liabilities (1) Financial Position Financial Position Financial Position (1) Amount (in millions) Description: Derivatives $ (80.0 ) $ — $ (80.0 ) $ 59.9 $ (20.1 ) As of December 31, 2014 Gross Gross Amount Net Amount of Liabilities Gross Amount Amount of Offset in the Presented in the Not Offset in the Recognized Statement of Statement of Statement of Net Liabilities Financial Position Financial Position Financial Position Amount (in millions) Description: Derivatives $ (96.9 ) $ — $ (96.9 ) $ 91.8 $ (5.1 ) (1) Includes $ 16.2 28.4 Inputs to Fair Value Derivative Instruments The following table sets forth by level within the fair value hierarchy our net financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2015, and December 31, 2014. We classify financial assets and liabilities in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect our valuation of the financial assets and liabilities and their placement within the fair value hierarchy. September 30, 2015 December 31, 2014 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total (in millions) Commodity contracts: Financial $ — $ 6.1 $ 14.3 $ 20.4 $ — $ 19.1 $ 42.7 $ 61.8 Physical — — 4.6 4.6 — — 19.5 19.5 Commodity options — — 93.1 93.1 — — 106.7 106.7 $ — $ 6.1 $ 112.0 $ 118.1 $ — $ 19.1 $ 168.9 $ 188.0 Cash Collateral (16.2 ) (28.4 ) Total $ 101.9 $ 159.6 Qualitative Information about Level 2 Fair Value Measurements We categorize, as Level 2, the fair value of assets and liabilities that we measure with either directly or indirectly observable inputs as of the measurement date, where pricing inputs are other than quoted prices in active markets for the identical instrument. This category includes both OTC transactions valued using exchange traded pricing information in addition to assets and liabilities that we value using either models or other valuation methodologies derived from observable market data. These models are primarily industry-standard models that consider various inputs including: (1) quoted prices for assets and liabilities; (2) time value; and (3) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the assets and liabilities, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace. Qualitative Information about Level 3 Fair Value Measurements Data from pricing services and published indices are used to value our Level 3 derivative instruments, which are fair-valued on a recurring basis. We may also use these inputs with internally developed methodologies that result in our best estimate of fair value. The inputs listed in the table below would have a direct impact on the fair values of the listed instruments. The significant unobservable inputs used in the fair value measurement of the commodity derivatives (natural gas, NGLs, and crude oil) are forward commodity prices. The significant unobservable inputs used in determining the fair value measurement of options are price and volatility. Increases/(decreases) in the forward commodity price in isolation would result in higher/(lower) fair values for long positions, with offsetting impacts to short positions. Increases/(decreases) in volatility would increase/(decrease) the value for the holder of the option. Generally, a change in the estimate of forward commodity prices is unrelated to a change in the estimate of volatility of prices. A change to the credit valuation adjustment would change the fair value of the positions in opposite directions. Quantitative Information About Level 3 Fair Value Measurements Fair Value at Range (1) September 30, Valuation Unobservable Weighted Contract Type 2015 (2) Technique Input Lowest Highest Average Units (in millions) Commodity Contracts - Financial Natural Gas $ 0.3 Market Approach Forward Gas Price 2.41 3.16 2.84 MMBtu NGLs 14.0 Market Approach Forward NGL Price 0.20 0.99 0.51 Gal Commodity Contracts - Physical Natural Gas (3.9 ) Market Approach Forward Gas Price 2.33 3.53 2.61 MMBtu Crude Oil (0.4 ) Market Approach Forward Crude Oil Price 31.17 47.93 44.35 Bbl NGLs 8.9 Market Approach Forward NGL Price 0.20 1.39 0.43 Gal Commodity Options Natural Gas, Crude and NGLs 93.1 Option Model Option Volatility 10 % 62 % 35 % Total Fair Value $ 112.0 (1) Prices are in dollars per Millions of British Thermal Units, or MMBtu, for natural gas, dollars per Gallon, or Gal, for NGLs and dollars per barrel, or Bbl, for crude oil. (2) Fair values include credit valuation adjustment losses of approximately $ 0.3 Fair Value at Range (1) December 31, Valuation Unobservable Weighted Contract Type 2014 (2) Technique Input Lowest Highest Average Units (in millions) Commodity Contracts - Financial Natural Gas $ 0.6 Market Approach Forward Gas Price 2.55 3.72 3.04 MMBtu NGLs 42.1 Market Approach Forward NGL Price 0.48 1.14 0.64 Gal Commodity Contracts - Physical Natural Gas 1.5 Market Approach Forward Gas Price 1.55 4.08 3.08 MMBtu Crude Oil (0.9 ) Market Approach Forward Crude Oil Price 49.57 55.60 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, and Bbl for crude oil. (2) Fair values include credit valuation adjustment losses of approximately $ 1.0 Level 3 Fair Value Reconciliation The table below provides a reconciliation of changes in the fair value of our Level 3 financial assets and liabilities measured on a recurring basis from January 1, 2015 to September 30, 2015. No transfers of assets between any of the Levels occurred during the period. Commodity Commodity Financial Physical Commodity Contracts Contracts Options Total (in millions) Beginning balance as of January 1, 2015 $ 42.7 $ 19.5 $ 106.7 $ 168.9 Transfer out of Level 3 (1) — — — — Gains or losses included in earnings: Reported in Operating revenue — (3.2 ) — (3.2 ) Reported in Cost of natural gas and natural gas liquids (1.1 ) 18.8 30.2 47.9 Gains or losses included in other comprehensive income: Reported in Other comprehensive income (loss), net of tax 0.4 — — 0.4 Purchases, issuances, sales and settlements: Purchases — — — — Sales — — 2.0 2.0 Settlements (2) (27.7 ) (30.5 ) (45.8 ) (104.0 ) Ending balance as of September 30, 2015 $ 14.3 $ 4.6 $ 93.1 $ 112.0 Amounts reported in Operating revenue $ — $ (22.7 ) $ — $ (22.7 ) Amount of changes in net assets attributable to the change in unrealized gains or losses related to assets and liabilities still held at the reporting date: Reported in Operating revenue $ — $ (1.4 ) $ — $ (1.4 ) Reported in Cost of natural gas and natural gas liquids $ (2.0 ) $ 5.3 $ 30.6 $ 33.9 (1) Our policy is to recognize transfers as of the last day of the reporting period. (2) Settlements represent the realized portion of forward contracts. Fair Value Measurements of Commodity Derivatives The following table provides summarized information about the fair values of expected cash flows of our outstanding commodity based swaps and physical contracts at September 30, 2015 and December 31, 2014. At September 30, 2015 At December 31, 2014 Wtd. Average Price (2) Fair Value (3) Fair Value (3) Commodity Notional (1) Receive Pay Asset Liability Asset Liability (in millions) Portion of contracts maturing in 2015 Swaps Receive variable/pay fixed NGL 964,000 $ 22.66 $ 25.42 $ 0.7 $ (3.3 ) $ — $ (6.8 ) Crude Oil 350,000 $ 45.54 $ 72.70 $ — $ (9.5 ) $ — $ (27.4 ) Receive fixed/pay variable NGL 1,913,800 $ 29.66 $ 24.25 $ 11.3 $ (1.0 ) $ 39.2 $ — Crude Oil 398,720 $ 81.28 $ 45.63 $ 14.2 $ — $ 42.4 $ — Receive variable/pay variable Natural Gas 828,000 $ 2.45 $ 2.52 $ — $ (0.1 ) $ 1.5 $ (1.7 ) Physical Contracts Receive variable/pay fixed NGL 50,000 $ 31.63 $ 33.02 $ — $ (0.1 ) $ — $ (3.6 ) Crude Oil 8,600 $ 45.26 $ 45.12 $ — $ — $ — $ — Receive fixed/pay variable NGL 3,048,988 $ 18.83 $ 17.16 $ 6.4 $ (1.3 ) $ 19.8 $ — Crude Oil 54,500 $ 42.69 $ 45.80 $ — $ (0.2 ) $ 0.5 $ — Receive variable/pay variable Natural Gas 54,524,000 $ 2.48 $ 2.49 $ — $ (0.8 ) $ 2.2 $ (1.0 ) NGL 5,150,479 $ 20.54 $ 20.07 $ 5.3 $ (2.9 ) $ 3.7 $ (1.0 ) Crude Oil 742,342 $ 43.59 $ 43.90 $ 1.3 $ (1.5 ) $ 0.3 $ (1.7 ) Portion of contracts maturing in 2016 Swaps Receive variable/pay fixed Natural Gas 16,287 $ 2.72 $ 3.48 $ — $ — $ — $ (0.1 ) NGL 833,500 $ 23.81 $ 30.54 $ — $ (5.6 ) $ — $ — Crude Oil 415,950 $ 49.02 $ 82.69 $ — $ (14.0 ) $ — $ (8.1 ) Receive fixed/pay variable NGL 1,428,500 $ 31.34 $ 22.26 $ 13.3 $ (0.3 ) $ 9.3 $ — Crude Oil 425,950 $ 84.17 $ 48.95 $ 14.9 $ — $ 9.1 $ — Receive variable/pay variable Natural Gas 5,124,000 $ 2.79 $ 2.76 $ 0.2 $ — $ 0.5 $ (0.3 ) Physical Contracts Receive fixed/pay variable NGL 233,952 $ 20.02 $ 19.25 $ 0.2 $ (0.1 ) $ — $ — Receive variable/pay variable Natural Gas 177,875,634 $ 2.62 $ 2.64 $ — $ (3.4 ) $ 0.7 $ (0.4 ) NGL 9,640,509 $ 17.02 $ 16.88 $ 1.6 $ (0.2 ) $ — $ — Portion of contracts maturing in 2017 Swaps Receive variable/pay fixed Natural Gas 76,530 $ 2.62 $ 2.97 $ — $ — $ — $ — NGL 547,500 $ 19.97 $ 25.86 $ — $ (3.2 ) $ — $ — Crude Oil 547,500 $ 52.74 $ 66.72 $ — $ (7.6 ) $ — $ — Receive fixed/pay variable NGL 547,500 $ 23.59 $ 19.97 $ 2.0 $ — $ 0.7 $ — Crude Oil 547,500 $ 66.78 $ 52.74 $ 7.6 $ — $ 0.8 $ — Receive variable/pay variable Natural Gas 8,050,000 $ 2.82 $ 2.77 $ 0.4 $ — $ — $ — Physical Contracts Receive variable/pay variable Natural Gas 2,187,810 $ 3.03 $ 3.01 $ 0.1 $ — $ 0.2 $ (0.1 ) Portion of contracts maturing in 2018 Physical Contracts Receive variable/pay variable Natural Gas 2,187,810 $ 3.16 $ 3.14 $ 0.1 $ — $ — $ — Portion of contracts maturing in 2019 Physical Contracts Receive variable/pay variable Natural Gas 2,187,810 $ 3.25 $ 3.22 $ 0.1 $ — $ — $ — Portion of contracts maturing in 2020 Physical Contracts Receive variable/pay variable Natural Gas 359,640 $ 3.55 $ 3.52 $ — $ — $ — $ — (1) Volumes of natural gas are measured in MMBtu, whereas volumes of NGL and crude oil are measured in Bbl. (2) Weighted-average prices received and paid are in $/MMBtu for natural gas and $/Bbl for NGL and crude oil. (3) The fair value is determined based on quoted market prices at September 30, 2015, and December 31, 2014, respectively, discounted using the swap rate for the respective periods to consider the time value of money. Fair values exclude credit valuation adjustment gains (losses) of approximately $ 0.4 0.4) The following table provides summarized information about the fair value of expected cash flows of our outstanding commodity options at September 30, 2015 and December 31, 2014. At September 30, 2015 At December 31, 2014 Strike Market Fair Value (3) Fair Value (3) Commodity Notional (1) Price (2) Price (2) Asset Liability Asset Liability (in millions) Portion of option contracts maturing in 2015 Puts (purchased) Natural Gas 1,012,000 $ 3.90 $ 2.60 $ 1.3 $ — $ 3.8 $ — NGL 579,600 $ 43.32 $ 23.75 $ 11.4 $ — $ 40.2 $ — Crude Oil 184,000 $ 81.56 $ 45.77 $ 6.6 $ — $ 18.8 $ — Calls (written) Natural Gas 322,000 $ 5.05 $ 2.60 $ — $ — $ — $ — NGL 372,600 $ 45.80 $ 23.58 $ — $ — $ — $ (0.6 ) Crude Oil 184,000 $ 88.39 $ 45.77 $ — $ — $ — $ (0.4 ) Puts (written) Natural Gas 1,012,000 $ 3.90 $ 2.60 $ — $ (1.3 ) $ — $ (3.8 ) NGL 23,000 $ 77.28 $ 39.81 $ — $ (0.9 ) $ — $ — Calls (purchased) Natural Gas 322,000 $ 5.05 $ 2.60 $ — $ — $ — $ — Portion of option contracts maturing in 2016 Puts (purchased) Natural Gas 1,647,000 $ 3.75 $ 2.80 $ 1.7 $ — $ 1.0 $ — NGL 2,836,500 $ 39.24 $ 22.88 $ 48.4 $ — $ 39.3 $ — Crude Oil 805,200 $ 75.91 $ 49.23 $ 21.8 $ — $ 14.7 $ — Calls (written) Natural Gas 1,647,000 $ 4.98 $ 2.80 $ — $ — $ — $ (0.1 ) NGL 2,836,500 $ 45.14 $ 22.88 $ — $ (1.2 ) $ — $ (3.2 ) Crude Oil 805,200 $ 86.68 $ 49.23 $ — $ (0.2 ) $ — $ (2.7 ) Puts (written) Natural Gas 1,647,000 $ 3.75 $ 2.80 $ — $ (1.7 ) $ — $ (1.0 ) NGL 91,500 $ 39.06 $ 25.26 $ — $ (1.3 ) $ — $ — Calls (purchased) Natural Gas 1,647,000 $ 4.98 $ 2.80 $ — $ — $ 0.1 $ — NGL 91,500 $ 46.41 $ 25.26 $ — $ — $ — $ — Portion of option contracts maturing in 2017 Puts (purchased) NGL 1,277,500 $ 25.26 $ 24.76 $ 5.5 $ — $ 1.2 $ — Crude Oil 547,500 $ 63.00 $ 52.74 $ 7.5 $ — $ 4.1 $ — Calls (written) NGL 1,277,500 $ 29.46 $ 24.76 $ — $ (3.0 ) $ — $ (0.7 ) Crude Oil 547,500 $ 71.45 $ 52.74 $ — $ (1.1 ) $ — $ (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 September 30, 2015, and December 31, 2014, respectively, discounted using the swap rate for the respective periods to consider the time value of money. Fair values exclude any credit valuation adjustment losses of approximately $ 0.4 0.7

INCOME TAXES

INCOME TAXES	9 Months Ended
	Sep. 30, 2015
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 franchise tax laws by the State of Texas that apply to entities organized as partnerships, and which is based upon many but not all items included in net income. We computed our income tax expense by applying a Texas state franchise tax rate to modified gross margin. Our Texas state franchise tax rate was 0.4 0.5 3.7 1.4 0.9 2.7 In the third quarter of 2015, we assigned certain contracts in our Logistics and Marketing segment to a third party. Refer to Note 3. Acquisitions and Dispositions 2.4 At September 30, 2015 and December 31, 2014, we included a current income tax payable of $ 1.0 1.5 14.4 14.2 The Texas Franchise Tax Reduction Act of 2015 was signed into law on June 15, 2015. The law applies to original reports filed on or after January 1, 2016, and permanently reduces Texas franchise tax rates. Specifically, the general 1.0 0.75 3.5

SEGMENT INFORMATION

SEGMENT INFORMATION	9 Months Ended
	Sep. 30, 2015
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 are managed separately, since each business segment requires different operating strategies. We conduct our business through two • Gathering, Processing and Transportation; and • Logistics and Marketing. The following tables present certain financial information relating to our business segments and corporate activities: For the three months ended September 30, 2015 Gathering, Logistics and Corporate (1) Total (in millions) Total revenue $ 357.7 $ 520.8 $ — $ 878.5 Less: Intersegment revenue 214.3 3.2 — 217.5 Operating revenue 143.4 517.6 — 661.0 Cost of natural gas and natural gas liquids 16.7 506.0 — 522.7 Segment gross margin 126.7 11.6 — 138.3 Operating and maintenance 55.7 18.2 0.1 74.0 General and administrative 17.2 3.0 1.0 21.2 Depreciation and amortization 37.1 2.1 — 39.2 110.0 23.3 1.1 134.4 Operating income (loss) 16.7 (11.7 ) (1.1 ) 3.9 Interest expense, net — — (7.6 ) (7.6 ) Other income (loss) 8.9 (2) — (0.4 ) 8.5 Income (loss) before income tax expense 25.6 (11.7 ) (9.1 ) 4.8 Income tax expense — — (3.7 ) (3.7 ) Net income (loss) $ 25.6 $ (11.7 ) $ (12.8 ) $ 1.1 Less: Net income attributable to noncontrolling interest — — 4.7 4.7 Net income (loss) attributable to general and limited partner ownership interests in Midcoast Energy Partners, L.P. $ 25.6 $ (11.7 ) $ (17.5 ) $ (3.6 ) ______________ (1) Corporate consists of interest expense, interest income, noncontrolling interest and other costs such as income taxes, which are not allocated to the business segments. (2) Other income for our Gathering, Processing and Transportation segment includes our equity investment in the Texas Express NGL system. For the three months ended September 30, 2014 Gathering, Logistics and Corporate (1) Total (in millions) Total revenue $ 646.3 $ 1,252.4 $ — $ 1,898.7 Less: Intersegment revenue 484.9 14.4 — 499.3 Operating revenue 161.4 1,238.0 — 1,399.4 Cost of natural gas and natural gas liquids 20.7 1,217.5 — 1,238.2 Segment gross margin 140.7 20.5 — 161.2 Operating and maintenance 64.9 15.7 — 80.6 General and administrative 21.3 3.1 1.5 25.9 Depreciation and amortization 35.5 4.0 — 39.5 121.7 22.8 1.5 146.0 Operating income (loss) 19.0 (2.3 ) (1.5 ) 15.2 Interest expense, net — — (3.6 ) (3.6 ) Other income 5.3 (2) — — 5.3 Income (loss) before income tax expense 24.3 (2.3 ) (5.1 ) 16.9 Income tax expense — — (0.9 ) (0.9 ) Net income (loss) $ 24.3 $ (2.3 ) $ (6.0 ) $ 16.0 Less: Net income attributable to noncontrolling interest — — 9.7 9.7 Net income (loss) attributable to general and limited partner ownership interests in Midcoast Energy Partners, L.P. $ 24.3 $ (2.3 ) $ (15.7 ) $ 6.3 ______________________________ (1) Corporate consists of interest expense, interest income, noncontrolling interest and other costs such as income taxes, which are not allocated to the business segments. (2) Other income for our Gathering, Processing and Transportation segment includes our equity investment in the Texas Express NGL system. As of and for the nine months ended September 30, 2015 Gathering, Logistics and Corporate (1) Total (in millions) Total revenue $ 1,144.5 $ 1,975.3 $ — $ 3,119.8 Less: Intersegment revenue 776.9 28.3 — 805.2 Operating revenue 367.6 1,947.0 — 2,314.6 Cost of natural gas and natural gas liquids 58.5 1,913.9 — 1,972.4 Segment gross margin 309.1 33.1 — 342.2 Operating and maintenance 161.5 45.1 0.3 206.9 General and administrative 48.5 9.0 3.6 61.1 Goodwill impairment 206.1 20.4 — 226.5 Asset impairment — 12.3 — 12.3 Depreciation and amortization 112.0 6.3 — 118.3 528.1 93.1 3.9 625.1 Operating loss (219.0 ) (60.0 ) (3.9 ) (282.9 ) Interest expense, net — — (21.5 ) (21.5 ) Other income (loss) 20.5 (2) — (0.2 ) 20.3 Loss before income tax expense (198.5 ) (60.0 ) (25.6 ) (284.1 ) Income tax expense — — (1.4 ) (1.4 ) Net loss (198.5 ) (60.0 ) (27.0 ) (285.5 ) Less: Net loss attributable to noncontrolling interest — — (125.4 ) (125.4 ) Net income (loss) attributable to general and limited partner ownership interests in Midcoast Energy Partners, L.P. $ (198.5 ) $ (60.0 ) $ 98.4 $ (160.1 ) Total assets $ 4,983.0 (3) $ 210.2 $ 99.6 $ 5,292.8 Capital expenditures (excluding acquisitions) $ 132.8 $ 11.0 $ 3.6 $ 147.4 ______________________________ (1) Corporate consists of interest expense, interest income, noncontrolling interest and other costs such as income taxes, which are not allocated to the business segments. (2) Other income for our Gathering, Processing and Transportation segment includes our equity investment in the Texas Express NGL system. (3) Totals assets for our Gathering, Processing and Transportation segment includes $ 373.7 As of and for the nine months ended September 30, 2014 Gathering, Logistics and Corporate (1) Total (in millions) Total revenue $ 2,065.3 $ 3,981.2 $ — $ 6,046.5 Less: Intersegment revenue 1,531.2 72.2 — 1,603.4 Operating revenue 534.1 3,909.0 — 4,443.1 Cost of natural gas and natural gas liquids 155.6 3,831.1 — 3,986.7 Segment gross margin 378.5 77.9 — 456.4 Operating and maintenance 196.5 49.8 0.2 246.5 General and administrative 62.4 8.8 3.5 74.7 Depreciation and amortization 105.4 7.9 — 113.3 364.3 66.5 3.7 434.5 Operating income (loss) 14.2 11.4 (3.7 ) 21.9 Interest expense, net — — (9.7 ) (9.7 ) Other income 6.4 (2) — — 6.4 Income (loss) before income tax expense 20.6 11.4 (13.4 ) 18.6 Income tax expense — — (2.7 ) (2.7 ) Net income (loss) 20.6 11.4 (16.1 ) 15.9 Less: Net income attributable to noncontrolling interest — — 13.8 13.8 Net income (loss) attributable to general and limited partner ownership interests in Midcoast Energy Partners, L.P. $ 20.6 $ 11.4 $ (29.9 ) $ 2.1 Total assets $ 4,955.8 (3) $ 499.2 $ 130.2 $ 5,585.2 Capital expenditures (excluding acquisitions) $ 149.8 $ 8.6 $ 3.2 $ 161.6 ______________________________ (1) Corporate consists of interest expense, interest income, noncontrolling interest and other costs such as income taxes, which are not allocated to the business segments. (2) Other income for our Gathering, Processing and Transportation segment includes our equity investment in the Texas Express NGL system. (3) Totals assets for our Gathering, Processing and Transportation segment includes $ 380.2

SUPPLEMENTAL CASH FLOW INFORMAT

SUPPLEMENTAL CASH FLOW INFORMATION	9 Months Ended
	Sep. 30, 2015
SUPPLEMENTAL CASH FLOW INFORMATION [Abstract]
SUPPLEMENTAL CASH FLOW INFORMATION	17. SUPPLEMENTAL CASH FLOW INFORMATION In the “Cash used in investing activities” section of the consolidated statements of cash flows, we exclude changes that did not affect cash. The following is a reconciliation of cash used for additions to property, plant and equipment to total capital expenditures (excluding “Acquisitions” and “Investment in joint ventures”): For the nine months ended September 30, 2015 2014 (in millions) Additions to property, plant and equipment $ 155.4 $ 166.6 Decrease in construction payables (8.0 ) (5.0 ) Total capital expenditures $ 147.4 $ 161.6

RECENT ACCOUNTING PRONOUNCEMENT

RECENT ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED	9 Months Ended
	Sep. 30, 2015
RECENT ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED [Abstract]
RECENT ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED	18. RECENT ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED Revenues from Contracts with Customers In May 2014, the FASB issued Accounting Standards Update No. 2014-09, which 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. In July 2015, the FASB delayed the effective date of the new revenue standard by one year. This accounting update is effective for annual and interim periods beginning after December 15, 2017 and may be applied on either a full or modified retrospective basis. We are currently evaluating which transition approach we will apply and the impact that this pronouncement will have on our consolidated financial statements. Going Concern Uncertainties In August 2014, the FASB issued Accounting Standards Update No. 2014-15 which provides guidance on determining when and how to disclose going-concern uncertainties in the financial statements. The new standard requires management to perform interim and annual assessments of an entity's ability to continue as a going concern within one year of the date the financial statements are issued. An entity must provide certain disclosures if conditions or events raise substantial doubt about the entity's ability to continue as a going concern. This accounting update is effective for annual and interim periods ending after December 15, 2016, with early adoption permitted. We do not expect that the adoption of this pronouncement will have a material impact on our consolidated financial statements. Consolidation In February 2015, the FASB issued Accounting Standards Update No. 2015-02, which addresses concerns about the current accounting for consolidation of certain legal entities. It makes targeted amendments to the current consolidation guidance and ends the deferral granted to certain entities from applying the variable interest entity, or VIE guidance. Among other things, the amended standard eliminates the specialized consolidation model and guidance for limited partnerships, which included the presumption that the general partner should consolidate a limited partnership. This accounting update is effective for annual and interim periods beginning after December 15, 2015. Early adoption is permitted, and the new standard may be adopted either retrospectively or using a modified retrospective approach. We are currently evaluating which transition approach we will apply and the impact that this pronouncement will have on our consolidated financial statements, although we expect that this amended guidance will require us to (1) revisit our consolidation model and perform a VIE analysis for each limited partnership that we currently consolidate and (2) include additional disclosures within our consolidated financial statements. Debt Issuance Costs In April 2015, the FASB issued Accounting Standards Update No. 2015-03, which simplifies the presentation of debt issuance costs. The standard requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, and that the amortization of the debt issuance cost should be recorded as interest expense. The amendments do not affect the current guidance on the recognition and measurement of debt issuance costs. This accounting update is effective for annual and interim periods beginning on or after December 15, 2015. Early adoption is permitted, and the new standard must be adopted retrospectively. We do not expect that the adoption of this pronouncement will have a material impact on our consolidated financial statements. Inventory Measurement In July 2015, the FASB issued Accounting Standards Update No. 2015-11, which simplifies the subsequent measurement of inventories. For inventory within the scope of the new guidance, entities will be required to compare the cost of inventory to only one measure, its net realizable value, and not the three measures required by current guidance. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. No other changes were made to the current guidance on inventory measurement. This accounting update is effective for annual and interim periods beginning on or after December 15, 2016. We are currently evaluating the impact that this pronouncement will have on our consolidated financial statements.

SUBSEQUENT EVENTS

SUBSEQUENT EVENTS	9 Months Ended
	Sep. 30, 2015
SUBSEQUENT EVENTS [Abstract]
SUBSEQUENT EVENTS	19. SUBSEQUENT EVENTS Distribution to Partners On October 29, 2015 November 13, 2015 November 6, 2015 $ 16.5 $ 0.3575 $ 7.6 $ 8.9 Midcoast Operating Distribution On October 29, 2015, the general partner of Midcoast Operating declared a cash distribution by Midcoast Operating payable on November 13, 2015 to its partners of record as of November 6, 2015. Midcoast Operating will pay $ 27.4 $ 25.7

NET INCOME PER LIMITED PARTNE26

NET INCOME PER LIMITED PARTNER AND GENERAL PARTNER INTEREST (Tables)	9 Months Ended
	Sep. 30, 2015
NET INCOME PER LIMITED PARTNER AND GENERAL PARTNER INTEREST [Abstract]
Schedule of Formula for Distributing Available Cash	Distribution Targets Portion of Quarterly Percentage Distributed to Percentage Distributed Minimum Quarterly Distribution Up to $ 0.3125 98 % 2 % First Target Distribution > $ 0.3125 0.359375 98 % 2 % Second Target Distribution > $ 0.359375 0.390625 85 % 15 % Third Target Distribution > $ 0.390625 0.468750 75 % 25 % Over Third Target Distribution In excess of $ 0.468750 50 % 50 %
Basic and Diluted Net Income Per Limited Partner Unit	For the three months For the nine months ended September 30, ended September 30, 2015 2014 2015 2014 (in millions, except per unit amounts) Net income (loss) $ 1.1 $ 16.0 $ (285.5 ) $ 15.9 Less: Net income (loss) attributable to noncontrolling interest 4.7 9.7 (125.4 ) 13.8 Net income (loss) attributable to general and limited partner interests in Midcoast Energy Partners, L.P. (3.6 ) 6.3 (160.1 ) 2.1 Less distributions: Total distributed earnings to our General Partner (0.3 ) (0.3 ) (0.9 ) (0.9 ) Total distributed earnings to our limited partners (16.2 ) (15.3 ) (47.9 ) (44.1 ) Total distributed earnings (16.5 ) (15.6 ) (48.8 ) (45.0 ) Overdistributed earnings $ (20.1 ) $ (9.3 ) $ (208.9 ) $ (42.9 ) Weighted-average limited partner units outstanding 45.2 45.2 45.2 45.2 Basic and diluted earnings per unit: Distributed earnings per limited partner unit (1) $ 0.36 $ 0.34 $ 1.06 $ 0.98 Overdistributed earnings per limited partner unit (2) (0.44 ) (0.20 ) (4.53 ) (0.93 ) Net income (loss) per limited partner unit (basic and diluted) $ (0.08 ) $ 0.14 $ (3.47 ) $ 0.05 (1) Represents the total distributed earnings to limited partners divided by the weighted-average number of limited partner interests outstanding for the period. (2) Represents the limited partners' share (98

ACQUISITIONS AND DISPOSITIONS (

ACQUISITIONS AND DISPOSITIONS (Tables)	9 Months Ended
	Sep. 30, 2015
ACQUISITIONS AND DISPOSITIONS [Abstract]
Schedule of Consideration Paid and Purchase Price Allocation	September 30, 2015 (in millions) Consideration: Cash consideration $ 85.0 Contingent consideration 2.3 $ 87.3 Identifiable assets acquired in business combination: Property, plant and equipment $ 55.1 Intangible assets 32.2 $ 87.3
Schedule of Pro Forma Financial Information	For the three months For the nine months ended September 30, ended September 30, 2015 2014 2015 2014 (unaudited; in millions, except per unit amounts) Pro forma earnings data: Operating revenue $ 661.0 $ 1,399.6 $ 2,314.7 $ 4,443.8 Operating expenses $ 657.1 $ 1,384.4 $ 2,597.9 $ 4,422.5 Operating income (loss) $ 3.9 $ 15.2 $ (283.2 ) $ 21.3 Net income (loss) $ 1.1 $ 16.0 $ (285.8 ) $ 15.3 Net income (loss) attributable to noncontrolling interest $ 4.7 $ 9.7 $ (125.5 ) $ 13.5 Net income (loss) attributable to limited partner ownership interest $ (3.6 ) $ 6.3 $ (160.3 ) $ 1.8 Basic and diluted earnings per unit: As reported net income (loss) per limited partner unit (basic and diluted) $ (0.08 ) $ 0.14 $ (3.47 ) $ 0.05 Pro forma net income (loss) per limited partner unit (basic and diluted) $ (0.08 ) $ 0.14 $ (3.46 ) $ 0.04

EQUITY-BASED COMPENSATION (Tabl

EQUITY-BASED COMPENSATION (Tables)	9 Months Ended
	Sep. 30, 2015
EQUITY-BASED COMPENSATION [Abstract]
Schedule of PSU Activity	Weighted Average Average Intrinsic Performance Remaining Value Stock Units Term (years) (in millions) January 1, 2015 — Units granted 323,880 Units matured — Units forfeited (1,948 ) Distribution reinvested 27,384 September 30, 2015 349,316 2.3 $ 3.6

INVENTORY (Tables)

INVENTORY (Tables)	9 Months Ended
	Sep. 30, 2015
INVENTORY [Abstract]
Schedule of Inventory	September 30, December 31, 2015 2014 (in millions) Materials and supplies $ 0.6 $ 0.7 Crude oil inventory — 2.0 Natural gas and NGL inventory 85.3 78.8 $ 85.9 $ 81.5

PROPERTY, PLANT AND EQUIPMENT (

PROPERTY, PLANT AND EQUIPMENT (Tables)	9 Months Ended
	Sep. 30, 2015
PROPERTY, PLANT AND EQUIPMENT [Abstract]
Schedule of Property, Plant and Equipment	September 30, December 31, 2015 2014 (in millions) Land $ 14.2 $ 11.1 Rights-of-way 436.2 405.0 Pipelines 1,848.3 1,785.7 Pumping equipment, buildings and tanks 88.4 82.1 Compressors, meters and other operating equipment 2,145.6 2,074.8 Vehicles, office furniture and equipment 137.5 163.8 Processing and treating plants 632.8 516.0 Construction in progress 74.4 218.7 Total property, plant and equipment 5,377.4 5,257.2 Accumulated depreciation (1,154.7 ) (1,097.5 ) Property, plant and equipment, net $ 4,222.7 $ 4,159.7

EQUITY INVESTMENTS IN JOINT V31

EQUITY INVESTMENTS IN JOINT VENTURES (Tables)	9 Months Ended
	Sep. 30, 2015
EQUITY INVESTMENTS IN JOINT VENTURES [Abstract]
Schedule of Information of Joint Venture	For the three months For the nine months ended September 30, ended September 30, 2015 2014 2015 2014 (in millions) Operating revenues $ 36.5 $ 27.3 $ 93.9 $ 51.7 Operating expenses $ 11.1 $ 9.7 $ 33.8 $ 30.0 Net income $ 25.4 $ 17.5 $ 59.9 $ 21.6

DEBT (Tables)

DEBT (Tables)	9 Months Ended
	Sep. 30, 2015
DEBT [Abstract]
Schedule of Debt Obligations	September 30, December 31, Interest Rate 2015 2014 (in millions) Credit Agreement due 2016-2018 2.672 % $ 420.0 $ 360.0 Series A Senior Notes due September 2019 3.560 % 75.0 75.0 Series B Senior Notes due September 2021 4.040 % 175.0 175.0 Series C Senior Notes due September 2024 4.420 % 150.0 150.0 Total $ 820.0 $ 760.0
Schedule of Interest Cost	For the three months For the nine months ended September 30, ended September 30, 2015 2014 2015 2014 (in millions) Interest cost incurred $ 7.8 $ 4.0 $ 23.0 $ 10.3 Less: Interest capitalized 0.2 0.4 1.5 0.6 Interest expense, net $ 7.6 $ 3.6 $ 21.5 $ 9.7
Schedule of Line of Credit Facilities	(in millions) Total credit limit under Credit Agreement $ 810.0 Amounts outstanding under Credit Agreement (420.0 ) Total amount available at September 30, 2015 $ 390.0

PARTNERS' CAPITAL (Tables)

PARTNERS' CAPITAL (Tables)	9 Months Ended
	Sep. 30, 2015
PARTNERS' CAPITAL [Abstract]
Schedule of Distributions	Distribution Distribution Distribution Cash Declaration Date Record Date Payment Date per Unit Distributed (in millions, except per unit amounts) July 29, 2015 August 7, 2015 August 14, 2015 $ 0.35250 $ 16.3 April 29, 2015 May 8, 2015 May 15, 2015 $ 0.34750 $ 16.0 January 28, 2015 February 6, 2015 February 13, 2015 $ 0.34250 $ 15.8
Schedule of Changes in Partners' Capital	For the nine month ended September 30, 2015 2014 (in millions) Class A common units: Beginning balance $ 634.2 $ 495.3 Net income (loss) (78.4 ) 1.0 Acquisition of noncontrolling interest in subsidiary — 133.3 Distributions (23.6 ) (18.2 ) Ending balance $ 532.2 $ 611.4 Subordinated units: Beginning balance $ 1,174.0 $ 1,035.1 Net income (loss) (78.4 ) 1.1 Acquisition of noncontrolling interest in subsidiary — 133.3 Distributions (23.6 ) (18.2 ) Ending balance $ 1,072.0 $ 1,151.3 General Partner units: Beginning balance $ 47.8 $ 42.2 Net loss (3.3 ) — Acquisition of noncontrolling interest in subsidiary — 5.4 Distributions (0.9 ) (0.7 ) Ending balance $ 43.6 $ 46.9 Accumulated other comprehensive income (loss) Beginning balance $ 11.6 $ (3.1 ) Changes in fair value of derivative financial instruments reclassified to earnings (12.5 ) 5.1 Changes in fair value of derivative financial instruments recognized in other comprehensive income (loss) 4.2 (1.8 ) Ending balance $ 3.3 $ 0.2 Noncontrolling interest Beginning balance $ 2,529.0 $ 2,983.2 Capital contributions 97.2 130.5 Acquisition of noncontrolling interest in subsidiary — (622.0 ) Comprehensive income: Net income (loss) (125.4 ) 13.8 Other comprehensive income (loss), net of tax (7.8 ) 5.3 Distributions to noncontrolling interest (72.0 ) (83.3 ) Ending balance $ 2,421.0 $ 2,427.5 Total partners' capital at end of period $ 4,072.1 $ 4,237.3

DERIVATIVE FINANCIAL INSTRUME34

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Tables)	9 Months Ended
	Sep. 30, 2015
DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES [Abstract]
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value	September 30, December 31, 2014 (in millions) Other current assets $ 127.6 $ 164.7 Other assets, net 54.3 91.5 Accounts payable and other (1) (58.2 ) (74.4 ) Other long-term liabilities (21.8 ) (22.5 ) Due from General Partner and affiliates — 0.3 $ 101.9 $ 159.6 (1) Includes $ 16.2 28.4
Schedule of Derivative Balances by Counter Party Credit Quality	September 30, December 31, 2014 (in millions) Counterparty Credit Quality (1) AAA $ 0.2 $ 0.1 AA (2) 67.7 74.4 A 29.6 67.1 Lower than A 4.4 18.0 $ 101.9 $ 159.6 (1) As determined by nationally-recognized statistical ratings organizations. (2) Includes $ 16.2 28.4
Schedule of Credit Concentrations in Industry Sectors	September 30, December 31, 2014 (in millions) United States financial institutions and investment banking entities (1) $ 81.4 $ 88.5 Non-United States financial institutions (6.5 ) 30.7 Integrated oil companies 2.0 1.7 Other 25.0 38.7 $ 101.9 $ 159.6 (1) Includes $ 16.2 28.4
Effect of Derivative Instruments on the Consolidated Statements of Financial Position	Asset Derivatives Liability Derivatives Fair Value at Fair Value at Financial Position September 30, December 31, September 30, December 31, Location 2015 2014 2015 2014 (in millions) Derivatives designated as cash flow hedging instruments: (1) Commodity contracts Other current assets $ 7.4 $ 26.1 $ — $ — Commodity contracts Other assets — 2.1 — — 7.4 28.2 — — Derivatives not designated as hedging instruments: Commodity contracts Other current assets 120.2 138.6 — — Commodity contracts Other assets 54.3 89.4 — — Commodity contracts Accounts payable and other (2) — — (42.0 ) (46.0 ) Commodity contracts Other long-term liabilities — — (21.8 ) (22.5 ) Commodity contracts Due from general partner and affiliates — 0.3 — — 174.5 228.3 (63.8 ) (68.5 ) Total derivative instruments $ 181.9 $ 256.5 $ (63.8 ) $ (68.5 ) (1) Includes items currently designated as hedging instruments. Excludes the portion of de-designated hedges which may have a component remaining in AOCI. (2) Excludes total of $ 16.2 28.4
Effect of Derivative Instruments on the Consolidated Statements of Income and Accumulated Other Comprehensive Income	Amount of Gain (Loss) Recognized in Location of Gain Earnings on (Loss) Recognized in Derivative Earnings on Derivative (Ineffective Portion Amount of Gain Location of Gain (Loss) Amount of Gain (Loss) (Ineffective Portion and Amount Derivatives in Cash (Loss) Recognized in Reclassified from Reclassified from and Amount Excluded from Flow Hedging AOCI on Derivative AOCI to Earnings AOCI to Earnings Excluded from Effectiveness Relationships (Effective Portion) (Effective Portion) (Effective Portion) Effectiveness Testing) (1) Testing) (1) (in millions) For the three months ended September 30, 2015 Commodity contracts $ (5.5 ) Cost of natural gas and natural gas liquids $ 8.5 Cost of natural gas and natural gas liquids $ (0.1 ) For the three months ended September 30, 2014 Commodity contracts $ 11.2 Cost of natural gas and natural gas liquids $ (2.1 ) Cost of natural gas and natural gas liquids $ 0.9 For the nine months ended September 30, 2015 Commodity contracts $ (16.8 ) Cost of natural gas and natural gas liquids $ 24.0 Cost of natural gas and natural gas liquids $ (4.1 ) For the nine months ended September 30, 2014 Commodity contracts $ 7.9 Cost of natural gas and natural gas liquids $ (12.4 ) Cost of natural gas and natural gas liquids $ 1.5 (1) Includes only the ineffective portion of derivatives that are designated as hedging instruments and does not include net gains or losses associated with derivatives that do not qualify for hedge accounting treatment.
Components of Accumulated Other Comprehensive Income/(Loss)	Cash Flow Hedges 2015 2014 (in millions) Balance at January 1 $ 11.6 $ (3.1 ) Other comprehensive income (loss) before reclassifications (1) (2) 4.1 (1.8 ) Amounts reclassified from AOCI (3) (4) (12.5 ) 5.1 Tax benefit 0.1 — Net other comprehensive income (loss) $ (8.3 ) $ 3.3 Balance at September 30 $ 3.3 $ 0.2 (1) Excludes NCI gain of $ 3.7 2.9 (2) Excludes NCI gain of $ 0.9 (3) Excludes NCI loss of $ 11.5 7.3 (4) For additional details on the amounts reclassified from AOCI, reference the Reclassifications from Accumulated Other Comprehensive Income
Reclassifications from Accumulated Other Comprehensive Income	For the three months ended For the nine months ended 2015 2014 2015 2014 (in millions) Losses (gains) on cash flow hedges: Commodity Contracts (1)(2)(3) $ (4.5 ) $ 1.1 $ (12.5 ) $ 5.1 Total Reclassifications from AOCI $ (4.5 ) $ 1.1 $ (12.5 ) $ 5.1 (1) Loss (gain) reported within “Cost of natural gas and natural gas liquids” in the consolidated statements of income. (2) Excludes NCI loss of $ 4.0 1.0 (3) Excludes NCI loss of $ 11.5 7.3
Effect of Derivative Instruments on Consolidated Statements of Income	For the three months For the nine months ended September 30, ended September 30, Derivatives Not 2015 2014 2015 2014 Designated Location of Gain or (Loss) Amount of Gain or (Loss) Amount of Gain or (Loss) as Hedging Instruments Recognized in Earnings Recognized in Earnings (1)(2) Recognized in Earnings (1)(2) (in millions) Commodity contracts Operating revenue $ (7.2 ) $ 7.7 $ (22.4 ) $ 10.8 Commodity contracts Operating revenue – affiliate — (0.1 ) (0.3 ) 0.4 Commodity contracts Cost of natural gas and natural gas liquids (3) 40.7 9.5 44.3 (9.9 ) Total $ 33.5 $ 17.1 $ 21.6 $ 1.3 (1) Does not include settlements associated with derivative instruments that settle through physical delivery. (2) Includes only net gains or losses associated with those derivatives that do not qualify for hedge accounting treatment and does not include the ineffective portion of derivatives that are designated as hedging instruments. (3) Includes settlements gains (losses) of $ 27.3 0.1 71.0 8.6)
Offsetting of Financial Assets and Derivative Assets	As of September 30, 2015 Gross Gross Amount Net Amount of Assets Gross Amount Amount of Offset in the Presented in the Not Offset in the Recognized Statement of Statement of Statement of Net Assets Financial Position Financial Position Financial Position (1) Amount (in millions) Description: Derivatives $ 181.9 $ — $ 181.9 $ (59.9 ) $ 122.0 As of December 31, 2014 Gross Gross Amount Net Amount of Assets Gross Amount Amount of Offset in the Presented in the Not Offset in the Recognized Statement of Statement of Statement of Net Assets Financial Position Financial Position Financial Position (1) Amount (in millions) Description: Derivatives $ 256.5 $ — $ 256.5 $ (91.8 ) $ 164.7 (1) Includes $ 16.2 28.4
Offsetting of Financial Liabilities and Derivative Liabilities	As of September 30, 2015 Gross Gross Amount Net Amount of Liabilities Gross Amount Amount of Offset in the Presented in the Not Offset in the Recognized Statement of Statement of Statement of Net Liabilities (1) Financial Position Financial Position Financial Position (1) Amount (in millions) Description: Derivatives $ (80.0 ) $ — $ (80.0 ) $ 59.9 $ (20.1 ) As of December 31, 2014 Gross Gross Amount Net Amount of Liabilities Gross Amount Amount of Offset in the Presented in the Not Offset in the Recognized Statement of Statement of Statement of Net Liabilities Financial Position Financial Position Financial Position Amount (in millions) Description: Derivatives $ (96.9 ) $ — $ (96.9 ) $ 91.8 $ (5.1 ) (1) Includes $ 16.2 28.4
Table Setting Forth by Level within the Fair Value Hierarchy Financial Assets and Liabilities	September 30, 2015 December 31, 2014 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total (in millions) Commodity contracts: Financial $ — $ 6.1 $ 14.3 $ 20.4 $ — $ 19.1 $ 42.7 $ 61.8 Physical — — 4.6 4.6 — — 19.5 19.5 Commodity options — — 93.1 93.1 — — 106.7 106.7 $ — $ 6.1 $ 112.0 $ 118.1 $ — $ 19.1 $ 168.9 $ 188.0 Cash Collateral (16.2 ) (28.4 ) Total $ 101.9 $ 159.6
Schedule of Quantitative Information on Level 3 Fair Value Measurements	Fair Value at Range (1) September 30, Valuation Unobservable Weighted Contract Type 2015 (2) Technique Input Lowest Highest Average Units (in millions) Commodity Contracts - Financial Natural Gas $ 0.3 Market Approach Forward Gas Price 2.41 3.16 2.84 MMBtu NGLs 14.0 Market Approach Forward NGL Price 0.20 0.99 0.51 Gal Commodity Contracts - Physical Natural Gas (3.9 ) Market Approach Forward Gas Price 2.33 3.53 2.61 MMBtu Crude Oil (0.4 ) Market Approach Forward Crude Oil Price 31.17 47.93 44.35 Bbl NGLs 8.9 Market Approach Forward NGL Price 0.20 1.39 0.43 Gal Commodity Options Natural Gas, Crude and NGLs 93.1 Option Model Option Volatility 10 % 62 % 35 % Total Fair Value $ 112.0 (1) Prices are in dollars per Millions of British Thermal Units, or MMBtu, for natural gas, dollars per Gallon, or Gal, for NGLs and dollars per barrel, or Bbl, for crude oil. (2) Fair values include credit valuation adjustment losses of approximately $ 0.3 Fair Value at Range (1) December 31, Valuation Unobservable Weighted Contract Type 2014 (2) Technique Input Lowest Highest Average Units (in millions) Commodity Contracts - Financial Natural Gas $ 0.6 Market Approach Forward Gas Price 2.55 3.72 3.04 MMBtu NGLs 42.1 Market Approach Forward NGL Price 0.48 1.14 0.64 Gal Commodity Contracts - Physical Natural Gas 1.5 Market Approach Forward Gas Price 1.55 4.08 3.08 MMBtu Crude Oil (0.9 ) Market Approach Forward Crude Oil Price 49.57 55.60 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, and Bbl for crude oil. (2) Fair values include credit valuation adjustment losses of approximately $ 1.0
Schedule of Reconciliation of Changes in Fair Value of Level 3 Financial Assets and Liabilities	Commodity Commodity Financial Physical Commodity Contracts Contracts Options Total (in millions) Beginning balance as of January 1, 2015 $ 42.7 $ 19.5 $ 106.7 $ 168.9 Transfer out of Level 3 (1) — — — — Gains or losses included in earnings: Reported in Operating revenue — (3.2 ) — (3.2 ) Reported in Cost of natural gas and natural gas liquids (1.1 ) 18.8 30.2 47.9 Gains or losses included in other comprehensive income: Reported in Other comprehensive income (loss), net of tax 0.4 — — 0.4 Purchases, issuances, sales and settlements: Purchases — — — — Sales — — 2.0 2.0 Settlements (2) (27.7 ) (30.5 ) (45.8 ) (104.0 ) Ending balance as of September 30, 2015 $ 14.3 $ 4.6 $ 93.1 $ 112.0 Amounts reported in Operating revenue $ — $ (22.7 ) $ — $ (22.7 ) Amount of changes in net assets attributable to the change in unrealized gains or losses related to assets and liabilities still held at the reporting date: Reported in Operating revenue $ — $ (1.4 ) $ — $ (1.4 ) Reported in Cost of natural gas and natural gas liquids $ (2.0 ) $ 5.3 $ 30.6 $ 33.9 (1) Our policy is to recognize transfers as of the last day of the reporting period. (2) Settlements represent the realized portion of forward contracts.
Schedule of Fair Values of Expected Cash Flows of Outstanding Commodity Based Swaps and Physical Contracts	At September 30, 2015 At December 31, 2014 Wtd. Average Price (2) Fair Value (3) Fair Value (3) Commodity Notional (1) Receive Pay Asset Liability Asset Liability (in millions) Portion of contracts maturing in 2015 Swaps Receive variable/pay fixed NGL 964,000 $ 22.66 $ 25.42 $ 0.7 $ (3.3 ) $ — $ (6.8 ) Crude Oil 350,000 $ 45.54 $ 72.70 $ — $ (9.5 ) $ — $ (27.4 ) Receive fixed/pay variable NGL 1,913,800 $ 29.66 $ 24.25 $ 11.3 $ (1.0 ) $ 39.2 $ — Crude Oil 398,720 $ 81.28 $ 45.63 $ 14.2 $ — $ 42.4 $ — Receive variable/pay variable Natural Gas 828,000 $ 2.45 $ 2.52 $ — $ (0.1 ) $ 1.5 $ (1.7 ) Physical Contracts Receive variable/pay fixed NGL 50,000 $ 31.63 $ 33.02 $ — $ (0.1 ) $ — $ (3.6 ) Crude Oil 8,600 $ 45.26 $ 45.12 $ — $ — $ — $ — Receive fixed/pay variable NGL 3,048,988 $ 18.83 $ 17.16 $ 6.4 $ (1.3 ) $ 19.8 $ — Crude Oil 54,500 $ 42.69 $ 45.80 $ — $ (0.2 ) $ 0.5 $ — Receive variable/pay variable Natural Gas 54,524,000 $ 2.48 $ 2.49 $ — $ (0.8 ) $ 2.2 $ (1.0 ) NGL 5,150,479 $ 20.54 $ 20.07 $ 5.3 $ (2.9 ) $ 3.7 $ (1.0 ) Crude Oil 742,342 $ 43.59 $ 43.90 $ 1.3 $ (1.5 ) $ 0.3 $ (1.7 ) Portion of contracts maturing in 2016 Swaps Receive variable/pay fixed Natural Gas 16,287 $ 2.72 $ 3.48 $ — $ — $ — $ (0.1 ) NGL 833,500 $ 23.81 $ 30.54 $ — $ (5.6 ) $ — $ — Crude Oil 415,950 $ 49.02 $ 82.69 $ — $ (14.0 ) $ — $ (8.1 ) Receive fixed/pay variable NGL 1,428,500 $ 31.34 $ 22.26 $ 13.3 $ (0.3 ) $ 9.3 $ — Crude Oil 425,950 $ 84.17 $ 48.95 $ 14.9 $ — $ 9.1 $ — Receive variable/pay variable Natural Gas 5,124,000 $ 2.79 $ 2.76 $ 0.2 $ — $ 0.5 $ (0.3 ) Physical Contracts Receive fixed/pay variable NGL 233,952 $ 20.02 $ 19.25 $ 0.2 $ (0.1 ) $ — $ — Receive variable/pay variable Natural Gas 177,875,634 $ 2.62 $ 2.64 $ — $ (3.4 ) $ 0.7 $ (0.4 ) NGL 9,640,509 $ 17.02 $ 16.88 $ 1.6 $ (0.2 ) $ — $ — Portion of contracts maturing in 2017 Swaps Receive variable/pay fixed Natural Gas 76,530 $ 2.62 $ 2.97 $ — $ — $ — $ — NGL 547,500 $ 19.97 $ 25.86 $ — $ (3.2 ) $ — $ — Crude Oil 547,500 $ 52.74 $ 66.72 $ — $ (7.6 ) $ — $ — Receive fixed/pay variable NGL 547,500 $ 23.59 $ 19.97 $ 2.0 $ — $ 0.7 $ — Crude Oil 547,500 $ 66.78 $ 52.74 $ 7.6 $ — $ 0.8 $ — Receive variable/pay variable Natural Gas 8,050,000 $ 2.82 $ 2.77 $ 0.4 $ — $ — $ — Physical Contracts Receive variable/pay variable Natural Gas 2,187,810 $ 3.03 $ 3.01 $ 0.1 $ — $ 0.2 $ (0.1 ) Portion of contracts maturing in 2018 Physical Contracts Receive variable/pay variable Natural Gas 2,187,810 $ 3.16 $ 3.14 $ 0.1 $ — $ — $ — Portion of contracts maturing in 2019 Physical Contracts Receive variable/pay variable Natural Gas 2,187,810 $ 3.25 $ 3.22 $ 0.1 $ — $ — $ — Portion of contracts maturing in 2020 Physical Contracts Receive variable/pay variable Natural Gas 359,640 $ 3.55 $ 3.52 $ — $ — $ — $ — (1) Volumes of natural gas are measured in MMBtu, whereas volumes of NGL and crude oil are measured in Bbl. (2) Weighted-average prices received and paid are in $/MMBtu for natural gas and $/Bbl for NGL and crude oil. (3) The fair value is determined based on quoted market prices at September 30, 2015, and December 31, 2014, respectively, discounted using the swap rate for the respective periods to consider the time value of money. Fair values exclude credit valuation adjustment gains (losses) of approximately $ 0.4 0.4)
Schedule of Fair Values of Expected Cash Flows of Outstanding Commodity Options	At September 30, 2015 At December 31, 2014 Strike Market Fair Value (3) Fair Value (3) Commodity Notional (1) Price (2) Price (2) Asset Liability Asset Liability (in millions) Portion of option contracts maturing in 2015 Puts (purchased) Natural Gas 1,012,000 $ 3.90 $ 2.60 $ 1.3 $ — $ 3.8 $ — NGL 579,600 $ 43.32 $ 23.75 $ 11.4 $ — $ 40.2 $ — Crude Oil 184,000 $ 81.56 $ 45.77 $ 6.6 $ — $ 18.8 $ — Calls (written) Natural Gas 322,000 $ 5.05 $ 2.60 $ — $ — $ — $ — NGL 372,600 $ 45.80 $ 23.58 $ — $ — $ — $ (0.6 ) Crude Oil 184,000 $ 88.39 $ 45.77 $ — $ — $ — $ (0.4 ) Puts (written) Natural Gas 1,012,000 $ 3.90 $ 2.60 $ — $ (1.3 ) $ — $ (3.8 ) NGL 23,000 $ 77.28 $ 39.81 $ — $ (0.9 ) $ — $ — Calls (purchased) Natural Gas 322,000 $ 5.05 $ 2.60 $ — $ — $ — $ — Portion of option contracts maturing in 2016 Puts (purchased) Natural Gas 1,647,000 $ 3.75 $ 2.80 $ 1.7 $ — $ 1.0 $ — NGL 2,836,500 $ 39.24 $ 22.88 $ 48.4 $ — $ 39.3 $ — Crude Oil 805,200 $ 75.91 $ 49.23 $ 21.8 $ — $ 14.7 $ — Calls (written) Natural Gas 1,647,000 $ 4.98 $ 2.80 $ — $ — $ — $ (0.1 ) NGL 2,836,500 $ 45.14 $ 22.88 $ — $ (1.2 ) $ — $ (3.2 ) Crude Oil 805,200 $ 86.68 $ 49.23 $ — $ (0.2 ) $ — $ (2.7 ) Puts (written) Natural Gas 1,647,000 $ 3.75 $ 2.80 $ — $ (1.7 ) $ — $ (1.0 ) NGL 91,500 $ 39.06 $ 25.26 $ — $ (1.3 ) $ — $ — Calls (purchased) Natural Gas 1,647,000 $ 4.98 $ 2.80 $ — $ — $ 0.1 $ — NGL 91,500 $ 46.41 $ 25.26 $ — $ — $ — $ — Portion of option contracts maturing in 2017 Puts (purchased) NGL 1,277,500 $ 25.26 $ 24.76 $ 5.5 $ — $ 1.2 $ — Crude Oil 547,500 $ 63.00 $ 52.74 $ 7.5 $ — $ 4.1 $ — Calls (written) NGL 1,277,500 $ 29.46 $ 24.76 $ — $ (3.0 ) $ — $ (0.7 ) Crude Oil 547,500 $ 71.45 $ 52.74 $ — $ (1.1 ) $ — $ (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 September 30, 2015, and December 31, 2014, respectively, discounted using the swap rate for the respective periods to consider the time value of money. Fair values exclude any credit valuation adjustment losses of approximately $ 0.4 0.7

SEGMENT INFORMATION (Tables)

SEGMENT INFORMATION (Tables)	9 Months Ended
	Sep. 30, 2015
SEGMENT INFORMATION [Abstract]
Schedule of Segment Reporting Information, By Segment	For the three months ended September 30, 2015 Gathering, Logistics and Corporate (1) Total (in millions) Total revenue $ 357.7 $ 520.8 $ — $ 878.5 Less: Intersegment revenue 214.3 3.2 — 217.5 Operating revenue 143.4 517.6 — 661.0 Cost of natural gas and natural gas liquids 16.7 506.0 — 522.7 Segment gross margin 126.7 11.6 — 138.3 Operating and maintenance 55.7 18.2 0.1 74.0 General and administrative 17.2 3.0 1.0 21.2 Depreciation and amortization 37.1 2.1 — 39.2 110.0 23.3 1.1 134.4 Operating income (loss) 16.7 (11.7 ) (1.1 ) 3.9 Interest expense, net — — (7.6 ) (7.6 ) Other income (loss) 8.9 (2) — (0.4 ) 8.5 Income (loss) before income tax expense 25.6 (11.7 ) (9.1 ) 4.8 Income tax expense — — (3.7 ) (3.7 ) Net income (loss) $ 25.6 $ (11.7 ) $ (12.8 ) $ 1.1 Less: Net income attributable to noncontrolling interest — — 4.7 4.7 Net income (loss) attributable to general and limited partner ownership interests in Midcoast Energy Partners, L.P. $ 25.6 $ (11.7 ) $ (17.5 ) $ (3.6 ) ______________ (1) Corporate consists of interest expense, interest income, noncontrolling interest and other costs such as income taxes, which are not allocated to the business segments. (2) Other income for our Gathering, Processing and Transportation segment includes our equity investment in the Texas Express NGL system. For the three months ended September 30, 2014 Gathering, Logistics and Corporate (1) Total (in millions) Total revenue $ 646.3 $ 1,252.4 $ — $ 1,898.7 Less: Intersegment revenue 484.9 14.4 — 499.3 Operating revenue 161.4 1,238.0 — 1,399.4 Cost of natural gas and natural gas liquids 20.7 1,217.5 — 1,238.2 Segment gross margin 140.7 20.5 — 161.2 Operating and maintenance 64.9 15.7 — 80.6 General and administrative 21.3 3.1 1.5 25.9 Depreciation and amortization 35.5 4.0 — 39.5 121.7 22.8 1.5 146.0 Operating income (loss) 19.0 (2.3 ) (1.5 ) 15.2 Interest expense, net — — (3.6 ) (3.6 ) Other income 5.3 (2) — — 5.3 Income (loss) before income tax expense 24.3 (2.3 ) (5.1 ) 16.9 Income tax expense — — (0.9 ) (0.9 ) Net income (loss) $ 24.3 $ (2.3 ) $ (6.0 ) $ 16.0 Less: Net income attributable to noncontrolling interest — — 9.7 9.7 Net income (loss) attributable to general and limited partner ownership interests in Midcoast Energy Partners, L.P. $ 24.3 $ (2.3 ) $ (15.7 ) $ 6.3 ______________________________ (1) Corporate consists of interest expense, interest income, noncontrolling interest and other costs such as income taxes, which are not allocated to the business segments. (2) Other income for our Gathering, Processing and Transportation segment includes our equity investment in the Texas Express NGL system. As of and for the nine months ended September 30, 2015 Gathering, Logistics and Corporate (1) Total (in millions) Total revenue $ 1,144.5 $ 1,975.3 $ — $ 3,119.8 Less: Intersegment revenue 776.9 28.3 — 805.2 Operating revenue 367.6 1,947.0 — 2,314.6 Cost of natural gas and natural gas liquids 58.5 1,913.9 — 1,972.4 Segment gross margin 309.1 33.1 — 342.2 Operating and maintenance 161.5 45.1 0.3 206.9 General and administrative 48.5 9.0 3.6 61.1 Goodwill impairment 206.1 20.4 — 226.5 Asset impairment — 12.3 — 12.3 Depreciation and amortization 112.0 6.3 — 118.3 528.1 93.1 3.9 625.1 Operating loss (219.0 ) (60.0 ) (3.9 ) (282.9 ) Interest expense, net — — (21.5 ) (21.5 ) Other income (loss) 20.5 (2) — (0.2 ) 20.3 Loss before income tax expense (198.5 ) (60.0 ) (25.6 ) (284.1 ) Income tax expense — — (1.4 ) (1.4 ) Net loss (198.5 ) (60.0 ) (27.0 ) (285.5 ) Less: Net loss attributable to noncontrolling interest — — (125.4 ) (125.4 ) Net income (loss) attributable to general and limited partner ownership interests in Midcoast Energy Partners, L.P. $ (198.5 ) $ (60.0 ) $ 98.4 $ (160.1 ) Total assets $ 4,983.0 (3) $ 210.2 $ 99.6 $ 5,292.8 Capital expenditures (excluding acquisitions) $ 132.8 $ 11.0 $ 3.6 $ 147.4 ______________________________ (1) Corporate consists of interest expense, interest income, noncontrolling interest and other costs such as income taxes, which are not allocated to the business segments. (2) Other income for our Gathering, Processing and Transportation segment includes our equity investment in the Texas Express NGL system. (3) Totals assets for our Gathering, Processing and Transportation segment includes $ 373.7 As of and for the nine months ended September 30, 2014 Gathering, Logistics and Corporate (1) Total (in millions) Total revenue $ 2,065.3 $ 3,981.2 $ — $ 6,046.5 Less: Intersegment revenue 1,531.2 72.2 — 1,603.4 Operating revenue 534.1 3,909.0 — 4,443.1 Cost of natural gas and natural gas liquids 155.6 3,831.1 — 3,986.7 Segment gross margin 378.5 77.9 — 456.4 Operating and maintenance 196.5 49.8 0.2 246.5 General and administrative 62.4 8.8 3.5 74.7 Depreciation and amortization 105.4 7.9 — 113.3 364.3 66.5 3.7 434.5 Operating income (loss) 14.2 11.4 (3.7 ) 21.9 Interest expense, net — — (9.7 ) (9.7 ) Other income 6.4 (2) — — 6.4 Income (loss) before income tax expense 20.6 11.4 (13.4 ) 18.6 Income tax expense — — (2.7 ) (2.7 ) Net income (loss) 20.6 11.4 (16.1 ) 15.9 Less: Net income attributable to noncontrolling interest — — 13.8 13.8 Net income (loss) attributable to general and limited partner ownership interests in Midcoast Energy Partners, L.P. $ 20.6 $ 11.4 $ (29.9 ) $ 2.1 Total assets $ 4,955.8 (3) $ 499.2 $ 130.2 $ 5,585.2 Capital expenditures (excluding acquisitions) $ 149.8 $ 8.6 $ 3.2 $ 161.6 ______________________________ (1) Corporate consists of interest expense, interest income, noncontrolling interest and other costs such as income taxes, which are not allocated to the business segments. (2) Other income for our Gathering, Processing and Transportation segment includes our equity investment in the Texas Express NGL system. (3) Totals assets for our Gathering, Processing and Transportation segment includes $ 380.2

SUPPLEMENTAL CASH FLOW INFORM36

SUPPLEMENTAL CASH FLOW INFORMATION (Tables)	9 Months Ended
	Sep. 30, 2015
SUPPLEMENTAL CASH FLOW INFORMATION [Abstract]
Schedule of Supplemental Cash Flow Information	For the nine months ended September 30, 2015 2014 (in millions) Additions to property, plant and equipment $ 155.4 $ 166.6 Decrease in construction payables (8.0 ) (5.0 ) Total capital expenditures $ 147.4 $ 161.6

ORGANIZATION AND NATURE OF OP37

ORGANIZATION AND NATURE OF OPERATIONS (Details)	9 Months Ended		12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Midcoast Operating, L.P. [Member]
Ownership in Midcoast Operating (in percentage)	51.60%	39.00%
Ownership in Midcoast Operating held by EEP (in percentage)	48.40%	61.00%
Additional interest purchased (in percentage)			12.60%
Limited Partner Interests (EEP) [Member]
Master limited partnership ownership interest (in percentage)	52.00%

NET INCOME PER LIMITED PARTNE38

NET INCOME PER LIMITED PARTNER AND GENERAL PARTNER INTEREST (Formula for Distributing Available Cash in Partnership Agreement) (Details)	9 Months Ended
	Sep. 30, 2015$ / shares
Minimum Quarterly Distribution [Member]
Portion of Quarterly Distribution Per Unit, maximum	$ 0.3125
Percentage Distributed To Limited Partners	98.00%
Percentage Distributed to General Partner	2.00%
First Target Distribution [Member]
Portion of Quarterly Distribution Per Unit, minimum	$ 0.3125
Portion of Quarterly Distribution Per Unit, maximum	$ 0.359375
Percentage Distributed To Limited Partners	98.00%
Percentage Distributed to General Partner	2.00%
Second Target Distribution [Member]
Portion of Quarterly Distribution Per Unit, minimum	$ 0.359375
Portion of Quarterly Distribution Per Unit, maximum	$ 0.390625
Percentage Distributed To Limited Partners	85.00%
Percentage Distributed to General Partner	15.00%
Third Target Distribution [Member]
Portion of Quarterly Distribution Per Unit, minimum	$ 0.390625
Portion of Quarterly Distribution Per Unit, maximum	$ 0.468750
Percentage Distributed To Limited Partners	75.00%
Percentage Distributed to General Partner	25.00%
Over Third Target Distribution [Member]
Portion of Quarterly Distribution Per Unit, minimum	$ 0.468750
Percentage Distributed To Limited Partners	50.00%
Percentage Distributed to General Partner	50.00%

NET INCOME PER LIMITED PARTNE39

NET INCOME PER LIMITED PARTNER AND GENERAL PARTNER INTEREST (Basic and Diluted Net Income Per Limited Partner Unit) (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Earnings Per Share [Line Items]
Net income (loss)		$ 1.1	$ 16	$ (285.5)	$ 15.9
Less: Net income (loss) attributable to noncontrolling interest		4.7	9.7	(125.4)	13.8
Net income (loss) attributable to general and limited partner ownership interest in Midcoast Energy Partners, L.P.		(3.6)	6.3	(160.1)	2.1
Total distributed earnings to our General Partner		(0.3)	(0.3)	(0.9)	(0.9)
Total distributed earnings to our limited partners		(16.2)	(15.3)	(47.9)	(44.1)
Total distributed earnings		(16.5)	(15.6)	(48.8)	(45)
Overdistributed earnings		$ (20.1)	$ (9.3)	$ (208.9)	$ (42.9)
Weighted average limited partner units outstanding (basic) (in shares)		45.2	45.2	45.2	45.2
Distributed earnings per limited partner unit (in dollars per share)	[1]	$ 0.36	$ 0.34	$ 1.06	$ 0.98
Overdistributed earnings per limited partner unit (in dollars per share)	[2]	(0.44)	(0.20)	(4.53)	(0.93)
Net income (loss) per limited partner unit (basic and diluted) (in dollars per share)		(0.08)	0.14	(3.47)	0.05
Net income (loss) per limited partner unit (diluted) (in dollars per share)		$ (0.08)	$ 0.14	$ (3.47)	$ 0.05
[1]	Represents the total distributed earnings to limited partners divided by the weighted-average number of limited partner interests outstanding for the period.
[2]	Represents the limited partners' share (98%) of distributions in excess of earnings divided by the weighted-average number of limited partner interests outstanding for the period and underdistributed earnings allocated to the limited partners based on the distribution waterfall that is outlined in our partnership agreement.

ACQUISITIONS AND DISPOSITIONS40

ACQUISITIONS AND DISPOSITIONS (Acquisitions) (Details) - USD ($) $ / shares in Units, $ in Millions	Feb. 27, 2015	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Pro forma earnings data:
As reported net income (loss) per limited partner unit (basic) (in dollars per share)		$ (0.08)	$ 0.14	$ (3.47)	$ 0.05
As reported net income (loss) per limited partner unit (diluted) (in dollars per share)		$ (0.08)	$ 0.14	$ (3.47)	$ 0.05
Midcoast Operating, L.P. [Member]
Business Acquisition [Line Items]
Ownership in Midcoast Operating (in percentage)				51.60%	39.00%
Ownership in Midcoast Operating held by EEP (in percentage)		48.40%	61.00%	48.40%	61.00%
NGR Acquisition [Member]
Business Acquisition [Line Items]
Maximum contingent future payment	$ 17	$ 17		$ 17
Price transferred to escrow agent	20
Restricted cash		15		15
Amount released from escrow and paid to seller				$ 5
Earnout period				5 years
Maximum purchase price				$ 102
Fair value of contingent consideration	2.3	2.5		2.5
Accretion of contingent consideration				0.2
Consideration:
Cash consideration	$ 85			85
Contingent consideration				2.3
Total				87.3
Identifiable assets acquired in business combination:
Property, plant, and equipment		55.1		55.1
Intangible assets		32.2		32.2
Total		87.3		$ 87.3
Weighted-average amortization period of intangible assets				15 years
Operating revenue		0.6		$ 1.2
Net income		0.1		0.2
Pro forma earnings data:
Operating revenue		661	$ 1,399.6	2,314.7	$ 4,443.8
Operating expenses		657.1	1,384.4	2,597.9	4,422.5
Operating income (loss)		3.9	15.2	(283.2)	21.3
Net income (loss)		1.1	16	(285.8)	15.3
Net income (loss) attributable to noncontrolling interest		4.7	9.7	(125.5)	13.5
Net income (loss) attributable to limited partner ownership interest		$ (3.6)	$ 6.3	$ (160.3)	$ 1.8
As reported net income (loss) per limited partner unit (basic) (in dollars per share)		$ (0.08)	$ 0.14	$ (3.47)	$ 0.05
As reported net income (loss) per limited partner unit (diluted) (in dollars per share)		(0.08)	0.14	(3.47)	0.05
Pro forma net income (loss) per limited partner unit (basic) (in dollars per share)		(0.08)	0.14	(3.46)	0.04
Pro forma net income (loss) per limited partner unit (diluted) (in dollars per share)		$ (0.08)	$ 0.14	$ (3.46)	$ 0.04

ACQUISITIONS AND DISPOSITIONS41

ACQUISITIONS AND DISPOSITIONS (Dispositions) (Details) - Disposal Group, Disposed of by Sale, Not Discontinued Operations [Member] - Logistics and Marketing [Member] $ in Millions	Sep. 01, 2015USD ($)item
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Number of subsidiaries sold | item	2
Proceeds from sale of assets	$ 4.3
Loss on sale of assets	(9.3)
Amount of prepayment	$ 4.2
Term of commitment	14 months
Severance costs	$ 1.3

EQUITY-BASED COMPENSATION (Deta

EQUITY-BASED COMPENSATION (Details) - Phantom Share Units (PSUs) [Member] $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2015USD ($)shares	Sep. 30, 2015USD ($)shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period		3 years
Vesting percentage		100.00%
Number of days used in calculating awards		20 days
Performance multiplier		1
Performance Stock Units
Outstanding
Units granted		323,880
Units matured
Units forfeited		(1,948)
Distribution reinvested		27,384
Outstanding	349,316	349,316
Weighted Average Remaining Contractual Term
Outstanding		2 years 3 months 18 days
Average Intrinsic Value
Outstanding | $	$ 3.6	$ 3.6
Compensation expense | $	0.3	0.9
Allocated share of the cost | $	0.1	0.3
Unrecognized compensation expense related to non-vested units | $	$ 3.8	$ 3.8
Unrecognized compensation expense related to non-vested units, recognition period		2 years
Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance multiplier		0
Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance multiplier		2

CASH AND CASH EQUIVALENTS (Deta

CASH AND CASH EQUIVALENTS (Details) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
CASH AND CASH EQUIVALENTS [Abstract]
Obligations paid but not yet presented to financial institution	$ 4.7	$ 6.6

INVENTORY (Details)

INVENTORY (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
INVENTORY [Abstract]
Materials and supplies	$ 0.6		$ 0.6		$ 0.7
Crude oil inventory					2
Natural gas and NGL inventory	$ 85.3		$ 85.3		78.8
Inventory, Net, Total	85.9		85.9		$ 81.5
Charges related to cost of natural gas	$ 0.1	$ 1.5	$ 5.4	$ 4.8

PROPERTY, PLANT AND EQUIPMENT45

PROPERTY, PLANT AND EQUIPMENT (Details) - USD ($) $ in Millions	Jul. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Property, Plant and Equipment [Line Items]
Property, plant and equipment		$ 5,377.4			$ 5,377.4		$ 5,257.2
Accumulated depreciation		(1,154.7)			(1,154.7)		(1,097.5)
Property, plant and equipment, net		$ 4,222.7			4,222.7		4,159.7
Loss on sale of assets					(3.2)
Asset impairment charges					12.3
Tinsley Crude Oil Pipeline, Storage Facilities and Docks [Member]
Property, Plant and Equipment [Line Items]
Proceeds from sale of assets	$ 1.3
Carrying amount of assets sold	$ 4.5
Loss on sale of assets		$ (3.2)			(3.2)
Asset impairment charges			$ 12.3
Land [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment		14.2			14.2		11.1
Rights-of-Way [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment		436.2			436.2		405
Pipelines [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment		1,848.3			1,848.3		1,785.7
Pumping Equipment, Buildings and Tanks [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment		88.4			88.4		82.1
Compressors, Meters and Other Operating Equipment [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment		2,145.6			2,145.6		2,074.8
Vehicles, Office Furniture and Equipment [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment		137.5			137.5		163.8
Processing and Treating Plants [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment		632.8			632.8		516
Construction in Progress [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment		$ 74.4			$ 74.4		$ 218.7

GOODWILL (Details)

GOODWILL (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Goodwill [Line Items]
Goodwill					$ 226.5
Goodwill impairment			$ 226.5
Processing and Transportation [Member]
Goodwill [Line Items]
Goodwill					206.1
Goodwill impairment			206.1
Logistics and Marketing [Member]
Goodwill [Line Items]
Goodwill					$ 20.4
Goodwill impairment			$ 20.4

EQUITY INVESTMENTS IN JOINT V47

EQUITY INVESTMENTS IN JOINT VENTURES (Details) - Texas Express NGL System [Member] $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015USD ($)entitiesmi	Sep. 30, 2014USD ($)	Sep. 30, 2015USD ($)entitiesmi	Sep. 30, 2014USD ($)
Schedule of Equity Method Investments [Line Items]
Ownership interest in joint venture (in percentage)	35.00%		35.00%
Number of joint ventures (in entities) | entities	2		2
Length of pipeline (in miles) | mi	593		593
Percentage of combined basis	100.00%		100.00%
Operating revenues	$ 36.5	$ 27.3	$ 93.9	$ 51.7
Operating expenses	11.1	9.7	33.8	30
Net income	$ 25.4	$ 17.5	$ 59.9	$ 21.6

DEBT (Schedule of Debt Obligati

DEBT (Schedule of Debt Obligations) (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Carrying amount	$ 820	$ 760
Credit Agreement [Member]
Debt Instrument [Line Items]
Carrying amount	$ 420	360
Interest rate (in percentage)	2.672%
Maturity date, start	Dec. 31, 2016
Maturity date, end	Dec. 31, 2018
Senior Notes [Member] | 3.560% Series A Senior Notes due September 2019 [Member]
Debt Instrument [Line Items]
Carrying amount	$ 75	75
Interest rate (in percentage)	3.56%
Maturity date	Sep. 30, 2019
Senior Notes [Member] | 4.040% Series B Senior Notes due September 2021 [Member]
Debt Instrument [Line Items]
Carrying amount	$ 175	175
Interest rate (in percentage)	4.04%
Maturity date	Sep. 30, 2021
Senior Notes [Member] | 4.420% Series C Senior Notes due September 2024 [Member]
Debt Instrument [Line Items]
Carrying amount	$ 150	$ 150
Interest rate (in percentage)	4.42%
Maturity date	Sep. 30, 2024

DEBT (Schedule of Interest Cost

DEBT (Schedule of Interest Cost) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Interest Costs Incurred [Abstract]
Interest cost incurred	$ 7.8	$ 4	$ 23	$ 10.3
Less: Interest capitalized	0.2	0.4	1.5	0.6
Interest expense, net	$ 7.6	$ 3.6	$ 21.5	$ 9.7

DEBT (Narrative) (Details)

DEBT (Narrative) (Details) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2015USD ($)requests	Sep. 30, 2015USD ($)requests	Sep. 30, 2014USD ($)	Sep. 02, 2015USD ($)
Debt Instruments [Abstract]
Line of credit facility remaining borrowing capacity	$ 390	$ 390
Covenant terms
Net borrowings under credit facility (Note 10)		60	$ 30
Proceeds from lines of credit		4,160
Repayments of lines of credit		4,100
Fixed Rate Debt Obligations [Member]
Covenant terms
Fair values of obligations	393	393
Senior Notes [Member]
Debt Instruments [Abstract]
Debt instrument, face amount	400	400
Senior Notes [Member] | 3.560% Series A Senior Notes due September 2019 [Member]
Debt Instruments [Abstract]
Debt instrument, face amount	$ 75	$ 75
Interest rate (in percentage)	3.56%	3.56%
Maturity date		Sep. 30, 2019
Senior Notes [Member] | 4.040% Series B Senior Notes due September 2021 [Member]
Debt Instruments [Abstract]
Debt instrument, face amount	$ 175	$ 175
Interest rate (in percentage)	4.04%	4.04%
Maturity date		Sep. 30, 2021
Senior Notes [Member] | 4.420% Series C Senior Notes due September 2024 [Member]
Debt Instruments [Abstract]
Debt instrument, face amount	$ 150	$ 150
Interest rate (in percentage)	4.42%	4.42%
Maturity date		Sep. 30, 2024
Senior Revolving Credit Facility [Member]
Debt Instruments [Abstract]
Total credit limit	$ 810	$ 810		$ 850
Amount outstanding	420	420
Line of credit facility remaining borrowing capacity	$ 390	$ 390
Original term of credit agreement (in years)		3 years
Credit facility, expiration date		Sep. 30, 2018
Covenant terms
Number of one-year requests for extensions | requests	4	4
Debt, weighted average interest rate (in percentage)	2.67%	2.67%
Senior Revolving Credit Facility [Member] | Portion of Facility Maturing in 2016 [Member]
Debt Instruments [Abstract]
Total credit available, maximum amount	$ 140	$ 140
Credit facility, expiration date		Nov. 13, 2016
Senior Revolving Credit Facility [Member] | Portion of Facility Maturing in 2017 [Member]
Debt Instruments [Abstract]
Total credit available, maximum amount	25	$ 25
Maturity date		Sep. 30, 2017
Financial Standby Letter of Credit [Member]
Debt Instruments [Abstract]
Total credit available, maximum amount	700	$ 700
Line of credit facility, commitment fee percentage (in percentage)		2.50%
Commitment fees and issuance costs (in dollars)	$ 0.1	$ 0.4

DEBT (Schedule of Available Cre

DEBT (Schedule of Available Credit) (Details) - USD ($) $ in Millions	Sep. 30, 2015	Sep. 02, 2015
Line of Credit Facility [Line Items]
Total amount available	$ 390
Senior Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Total credit limit	810	$ 850
Amounts outstanding	(420)
Total amount available	$ 390

PARTNERS' CAPITAL (Distribution

PARTNERS' CAPITAL (Distribution To Partners) (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended			9 Months Ended
	Aug. 14, 2015	May. 15, 2015	Feb. 13, 2015	Sep. 30, 2015
First Quarter Distribution [Member]
Distribution Declaration Date				Jan. 28, 2015
Record Date				Feb. 6, 2015
Distribution Payment Date				Feb. 13, 2015
Distribution per Unit (in dollars per share)			$ 0.34250
Cash distributed (in dollars)			$ 15.8
Second Quarter Distribution [Member]
Distribution Declaration Date				Apr. 29, 2015
Record Date				May 8, 2015
Distribution Payment Date				May 15, 2015
Distribution per Unit (in dollars per share)		$ 0.34750
Cash distributed (in dollars)		$ 16
Third Quarter Distribution [Member]
Distribution Declaration Date				Jul. 29, 2015
Record Date				Aug. 7, 2015
Distribution Payment Date				Aug. 14, 2015
Distribution per Unit (in dollars per share)	$ 0.35250
Cash distributed (in dollars)	$ 16.3

PARTNERS' CAPITAL (Schedule of

PARTNERS' CAPITAL (Schedule of Changes in Partners' Capital) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Beginning balance			$ 1,867.6
Net income (loss)	$ (3.6)	$ 6.3	(160.1)	$ 2.1
Distributions	(16.2)	(15.3)	(47.9)	(44.1)
Distributions	(0.3)	(0.3)	(0.9)	(0.9)
Ending balance	1,651.1		1,651.1
Noncontrolling interest:
Noncontrolling interest, beginning balance			2,529	2,983.2
Capital contributions			$ 97.2	130.5
Acquisition of noncontrolling interest in subsidiary				(622)
Comprehensive income:
Net income (loss)	4.7	9.7	$ (125.4)	13.8
Other comprehensive income (loss), net of tax	(2.5)	6.3	(7.8)	5.3
Distributions to noncontrolling interests			(72)	(83.3)
Noncontrolling interest, ending balance	2,421	2,427.5	2,421	2,427.5
Total partners' capital	4,072.1	4,237.3	4,072.1	4,237.3	$ 4,396.6
Limited Partner [Member] | Class A Common Units [Member]
Beginning balance			634.2	495.3
Net income (loss)			$ (78.4)	1
Acquisition of noncontrolling interest in subsidiary				133.3
Distributions			$ (23.6)	(18.2)
Ending balance	532.2	611.4	532.2	611.4
Limited Partner [Member] | Subordinated Units [Member]
Beginning balance			1,174	1,035.1
Net income (loss)			$ (78.4)	1.1
Acquisition of noncontrolling interest in subsidiary				133.3
Distributions			$ (23.6)	(18.2)
Ending balance	1,072	1,151.3	1,072	1,151.3
General Partner [Member]
Beginning balance			47.8	$ 42.2
Net income (loss)			$ (3.3)
Acquisition of noncontrolling interest in subsidiary				$ 5.4
Distributions			$ (0.9)	(0.7)
Ending balance	43.6	46.9	43.6	46.9
Accumulated Other Comprehensive Income (Loss) [Member]
Beginning balance			11.6	(3.1)
Changes in fair value of derivative financial instruments reclassified to earnings			(12.5)	5.1
Changes in fair value of derivative financial instruments recognized in other comprehensive income (loss)			4.2	(1.8)
Ending balance	$ 3.3	$ 0.2	$ 3.3	$ 0.2

PARTNERS' CAPITAL (Narrative) (

PARTNERS' CAPITAL (Narrative) (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Distribution to EEP			$ 48.1	$ 37.1
Distributions to noncontrolling interest	$ 26.2	$ 22.1	$ 72	83.3
Number of units authorized for issuance (in shares)	3,750,000		3,750,000
Value of securities covered by registration statement	$ 1,500		$ 1,500
Parent Company [Member]
Distribution to EEP	$ 8.8	$ 8.1	$ 25.9	$ 20
Midcoast Operating, L.P. [Member]
Maximum quarterly distribution (dollars per share)			$ 0.005

RELATED PARTY TRANSACTIONS (Det

RELATED PARTY TRANSACTIONS (Details) $ in Millions	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2015USD ($)bbl	Sep. 30, 2014USD ($)	Sep. 30, 2015USD ($)bbl	Sep. 30, 2014USD ($)	Dec. 31, 2014USD ($)
General and Administrative Services Transactions [Member] | Midcoast Operating, L.P. [Member]
Related Party Transaction [Line Items]
General and administrative services, reduction (in dollars)	$ 6.3		$ 18.8		$ 25
Construction Project Work Force Cost Transactions [Member]
Related Party Transaction [Line Items]
Expenses from transactions with related party			2.2		$ 5.8
Pipeline Transportation and Demand Fees from Texas Express NGL System [Member]
Related Party Transaction [Line Items]
Expenses from transactions with related party	$ 5.1	$ 5.4	$ 13.4	$ 16.8
Texas Express NGL System [Member]
Equity Method (JV) Investments [Line Items]
Transportation Commitments (in Barrels per day) | bbl	29,000		29,000
Texas Express NGL System [Member] | Maximum [Member]
Equity Method (JV) Investments [Line Items]
Transportation Commitments (in Barrels per day) | bbl	120,000		120,000

RELATED PARTY TRANSACTIONS (Sal

RELATED PARTY TRANSACTIONS (Sale of AR) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Net value of receivables sold	$ 509.8	$ 845.7	$ 1,752.4	$ 2,702.2
Proceeds from sale of receivables	509.7	845.5	1,751.9	2,701.5
Sold receivables that have not been collected at the balance sheet date	221		221		$ 272.7
(Gain) loss on sale of accounts receivable	0.1	$ 0.2	0.5	$ 0.7
Restricted cash	25.7		25.7		42.8
Sale of Accounts Receivable to Affiliate [Member]
Restricted cash	$ 6.7		$ 6.7		$ 17.7

COMMITMENTS AND CONTINGENCIES (

COMMITMENTS AND CONTINGENCIES (Details) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
COMMITMENTS AND CONTINGENCIES [Abstract]
Accrued environmental liabilities	$ 0	$ 0.2

DERIVATIVE FINANCIAL INSTRUME58

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Narrative) (Details) - USD ($) $ in Millions	9 Months Ended		12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Unrealized gains (losses) related to cash flow hedges of forecasted transactions that were subsequently de-designated	$ 0.4		$ (0.1)
De-designated unrealized commodity hedge gains (losses)	1.5	$ (0.2)
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months	8.3
Expected value of cash collateral or letters of credit if credit rating is downgraded	12.2
Cash collateral	16.2		$ 28.4
Midcoast Energy Partners LP [Member]
Cash collateral	4
Enbridge Energy Partners LP [Member]
Cash collateral	$ 12.2

DERIVATIVE FINANCIAL INSTRUME59

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Derivative Instruments in Statement of Financial Position) (Details) - USD ($) $ in Millions		Sep. 30, 2015	Dec. 31, 2014
Derivatives, Fair Value [Line Items]
Net Total		$ 101.9	$ 159.6
Cash collateral		16.2	28.4
Other Current Assets [Member]
Derivatives, Fair Value [Line Items]
Net Total		127.6	164.7
Other Assets, Net [Member]
Derivatives, Fair Value [Line Items]
Net Total		54.3	91.5
Accounts Payable and Other [Member]
Derivatives, Fair Value [Line Items]
Net Total	[1]	(58.2)	(74.4)
Cash collateral		16.2	28.4
Other Long-term Liabilities [Member]
Derivatives, Fair Value [Line Items]
Net Total		$ (21.8)	(22.5)
Due from General Partner and Affiliates [Member]
Derivatives, Fair Value [Line Items]
Net Total			$ 0.3
[1]	Includes $16.2 million and $28.4 million of cash collateral at September 30, 2015 and December 31, 2014, respectively.

DERIVATIVE FINANCIAL INSTRUME60

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Derivative Balances by Counterparty Credit Quality) (Details) - USD ($) $ in Millions		Sep. 30, 2015	Dec. 31, 2014
Derivative [Line Items]
Net Total		$ 101.9	$ 159.6
Cash collateral		16.2	28.4
AAA Rating [Member]
Derivative [Line Items]
Net Total	[1]	0.2	0.1
AA Rating [Member]
Derivative [Line Items]
Net Total	[1],[2]	67.7	74.4
Cash collateral		16.2	28.4
A Rating [Member]
Derivative [Line Items]
Net Total	[1]	29.6	67.1
Lower than A [Member]
Derivative [Line Items]
Net Total	[1]	$ 4.4	$ 18
[1]	As determined by nationally-recognized statistical ratings organizations.
[2]	Includes $16.2 million and $28.4 million of cash collateral at September 30, 2015 and December 31, 2014, respectively.

DERIVATIVE FINANCIAL INSTRUME61

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Credit Concentrations in Industry Sectors) (Details) - USD ($) $ in Millions		Sep. 30, 2015	Dec. 31, 2014
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Net Total		$ 101.9	$ 159.6
Cash collateral		16.2	28.4
United States Financial Institutions and Investment Banking Entities [Member]
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Net Total	[1]	81.4	88.5
Cash collateral		16.2	28.4
Non-United States Financial Institutions [Member]
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Net Total		(6.5)	30.7
Integrated Oil Companies [Member]
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Net Total		2	1.7
Other [Member]
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Net Total		$ 25	$ 38.7
[1]	Includes $16.2 million and $28.4 million of cash collateral at September 30, 2015 and December 31, 2014, respectively.

DERIVATIVE FINANCIAL INSTRUME62

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Effect of Derivative Instruments on Consolidated Statements of Financial Position) (Details) - USD ($) $ in Millions		Sep. 30, 2015	Dec. 31, 2014
Derivatives, Fair Value [Line Items]
Asset Derivatives		$ 181.9	$ 256.5
Liability Derivatives		(63.8)	(68.5)
Derivatives Designated As Hedging Instruments [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	[1]	$ 7.4	$ 28.2
Liability Derivatives	[1]
Derivatives Designated As Hedging Instruments [Member] | Other Current Assets [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	[1]	$ 7.4	$ 26.1
Liability Derivatives	[1]
Derivatives Designated As Hedging Instruments [Member] | Other Assets [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	[1]		$ 2.1
Liability Derivatives	[1]
Derivatives Not Designated As Hedging Instruments [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives		$ 174.5	$ 228.3
Liability Derivatives		(63.8)	(68.5)
Derivatives Not Designated As Hedging Instruments [Member] | Other Current Assets [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives		$ 120.2	$ 138.6
Liability Derivatives
Derivatives Not Designated As Hedging Instruments [Member] | Other Assets [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives		$ 54.3	$ 89.4
Liability Derivatives
Derivatives Not Designated As Hedging Instruments [Member] | Accounts Payable and Other [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	[2]
Liability Derivatives	[2]	$ (42)	$ (46)
Derivatives Not Designated As Hedging Instruments [Member] | Other Long-term Liabilities [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives
Liability Derivatives		$ (21.8)	$ (22.5)
Derivatives Not Designated As Hedging Instruments [Member] | Due from General Partner and Affiliates [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives			$ 0.3
Liability Derivatives
[1]	Includes items currently designated as hedging instruments. Excludes the portion of de-designated hedges which may have a component remaining in AOCI.
[2]	Excludes total of $16.2 million and $28.4 million of cash collateral at September 30, 2015 and December 31, 2014, respectively.

DERIVATIVE FINANCIAL INSTRUME63

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Effect of Derivative Instruments on Consolidated Statements of Income and AOCI) (Details) - Derivatives in Cash Flow Hedging Relationships [Member] - Commodity Contract [Member] - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain (loss) recognized in AOCI on Derivative (Effective Portion)		$ (5.5)	$ 11.2	$ (16.8)	$ 7.9
Cost of Natural Gas and Natural Gas Liquids [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain (loss) reclassified from AOCI to earnings (Effective Portion)		8.5	(2.1)	24	(12.4)
Amount of gain (loss) recognized in earnings on derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)	[1]	$ (0.1)	$ 0.9	$ (4.1)	$ 1.5
[1]	Includes only the ineffective portion of derivatives that are designated as hedging instruments and does not include net gains or losses associated with derivatives that do not qualify for hedge accounting treatment.

DERIVATIVE FINANCIAL INSTRUME64

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Components of Accumulated Other Comprehensive Income) (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance				$ 11.6
Net other comprehensive income (loss)		$ (5.2)	$ 10.2	(16.1)	$ 8.6
Ending balance		3.3		3.3
Cash Flow Hedge [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance				11.6	(3.1)
Other comprehensive income (loss) before reclassifications	[1],[2]			4.1	(1.8)
Amounts reclassified from AOCI	[3],[4]			(12.5)	$ 5.1
Tax benefit				0.1
Net other comprehensive income (loss)				(8.3)	$ 3.3
Ending balance		$ 3.3	$ 0.2	3.3	0.2
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Noncontrolling Interest [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other comprehensive income (loss) before reclassifications				3.7	(2.9)
Amounts reclassified from AOCI				$ (11.5)	7.3
Reclassification of AOCI relating to acquisition of interests in subsidiaries					$ 0.9
[1]	Excludes NCI gain of $0.9 million reclassified from AOCI related to the acquisition of additional interests in Midcoast Operating as of September 30, 2014.
[2]	Excludes NCI gain of $3.7 million and NCI loss of $2.9 million reclassified from AOCI at September 30, 2015 and 2014, respectively.
[3]	Excludes NCI loss of $11.5 million and NCI gain of $7.3 million reclassified from AOCI at September 30, 2015 and 2014, respectively.
[4]	For additional details on the amounts reclassified from AOCI, reference the Reclassifications from Accumulated Other Comprehensive Income table below.

DERIVATIVE FINANCIAL INSTRUME65

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Reclassifications from Accumulated Other Comprehensive Income) (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Cost of natural gas and natural gas liquids		$ 522.7	$ 1,238.2	$ 1,972.4	$ 3,986.7
Total Reclassifications from AOCI		(1.1)	(16)	285.5	(15.9)
Reclassification out of AOCI [Member] | Cash Flow Hedge [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Total Reclassifications from AOCI		(4.5)	1.1	(12.5)	5.1
Reclassification out of AOCI [Member] | Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Noncontrolling Interest [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Total Reclassifications from AOCI		(4)	1	(11.5)	7.3
Commodity Contract [Member] | Reclassification out of AOCI [Member] | Cash Flow Hedge [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Cost of natural gas and natural gas liquids	[1],[2],[3]	$ (4.5)	$ 1.1	$ (12.5)	$ 5.1
[1]	Excludes NCI loss of $11.5 million and NCI gain of $7.3 million reclassified from AOCI for the nine months ended September 30, 2015 and 2014, respectively.
[2]	Excludes NCI loss of $4.0 million and NCI gain of $1.0 million reclassified from AOCI for the three months ended September 30, 2015 and 2014, respectively.
[3]	Loss (gain) reported within “Cost of natural gas and natural gas liquids” in the consolidated statements of income.

DERIVATIVE FINANCIAL INSTRUME66

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Effect of Derivative Instruments on Consolidated Statements of Income) (Details) - Derivatives Not Designated As Hedging Instruments [Member] - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain or (Loss) Recognized in Earnings	[1],[2]	$ 33.5	$ 17.1	$ 21.6	$ 1.3
Operating Revenue [Member] | Commodity Contract [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain or (Loss) Recognized in Earnings	[1],[2]	$ (7.2)	7.7	(22.4)	10.8
Operating Revenue - Affiliate [Member] | Commodity Contract [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain or (Loss) Recognized in Earnings	[1],[2]		(0.1)	(0.3)	0.4
Cost of Natural Gas and Natural Gas Liquids [Member] | Commodity Contract [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain or (Loss) Recognized in Earnings	[1],[2],[3]	$ 40.7	9.5	44.3	(9.9)
Gain (Loss) on Settlement of Derivative Instruments		$ 27.3	$ 0.1	$ 71	$ (8.6)
[1]	Does not include settlements associated with derivative instruments that settle through physical delivery.
[2]	Includes only net gains or losses associated with those derivatives that do not qualify for hedge accounting treatment and does not include the ineffective portion of derivatives that are designated as hedging instruments.
[3]	Includes settlements gains (losses) of $27.3 million and $0.1 million for the three months ended September 30, 2015 and 2014, respectively, and settlement gains (losses) of $71.0 million and $(8.6) million for the nine months ended September 30, 2015 and 2014, respectively.

DERIVATIVE FINANCIAL INSTRUME67

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Offsetting of Financial Assets and Derivative Assets) (Details) - USD ($) $ in Millions		Sep. 30, 2015	Dec. 31, 2014
Derivatives
Gross Amount of Recognized Assets		$ 181.9	$ 256.5
Gross Amount Offset in the Statement of Financial Position
Net Amount of Assets Presented in the Statement of Financial Position		$ 181.9	$ 256.5
Gross Amount Not Offset in the Statement of Financial Position	[1]	(59.9)	(91.8)
Net Amount		$ 122	$ 164.7
[1]	Includes $16.2 million and $28.4 million of cash collateral at September 30, 2015 and December 31, 2014, respectively.

DERIVATIVE FINANCIAL INSTRUME68

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Offsetting of Financial Liabilities and Derivative Liabilities) (Details) - USD ($) $ in Millions		Sep. 30, 2015	Dec. 31, 2014
Derivatives
Gross Amount of Recognized Liabilities	[1]	$ (80)	$ (96.9)
Gross Amount Offset in the Statement of Financial Position
Net Amount of Liabilities Presented in the Statement of Financial Position		$ (80)	$ (96.9)
Gross Amount Not Offset in the Statement of Financial Position	[1]	59.9	91.8
Net Amount		$ (20.1)	$ (5.1)
[1]	Includes $16.2 million and $28.4 million of cash collateral at September 30, 2015 and December 31, 2014, respectively.

DERIVATIVE FINANCIAL INSTRUME69

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Level with in Fair Value Hierarchy, Financial Assets and Liabilities) (Details) - USD ($) $ in Millions	Sep. 30, 2015		Dec. 31, 2014
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments	$ 118.1		$ 188
Cash Collateral	(16.2)		(28.4)
Total	101.9		159.6
Commodity Contracts - Financial [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments	20.4		61.8
Commodity Contracts - Physical [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments	4.6		19.5
Commodity Options [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments	$ 93.1		$ 106.7
Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments
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	$ 6.1		$ 19.1
Level 2 [Member] | Commodity Contracts - Financial [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments	$ 6.1		$ 19.1
Level 2 [Member] | Commodity Contracts - Physical [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments
Level 2 [Member] | Commodity Options [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments
Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments	$ 112		$ 168.9
Total	112	[1]	168.9	[2]
Level 3 [Member] | Commodity Contracts - Financial [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments	14.3		42.7
Level 3 [Member] | Commodity Contracts - Physical [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments	4.6		19.5
Level 3 [Member] | Commodity Options [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments	$ 93.1		$ 106.7
[1]	Fair values include credit valuation adjustment losses of approximately $0.3 million.
[2]	Fair values include credit valuation adjustment losses of approximately $1.0 million.

DERIVATIVE FINANCIAL INSTRUME70

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Quantitative Information about Level 3 Fair Value Measurements) (Details) $ in Millions	9 Months Ended		12 Months Ended
	Sep. 30, 2015USD ($)$ / MMBTU$ / gal$ / bbl		Dec. 31, 2014USD ($)$ / MMBTU$ / gal$ / bbl
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Assets and liabilities accounted for at fair value on a recurring basis	$ 101.9		$ 159.6
Commodity Contracts - Financial [Member] | Minimum [Member] | Natural Gas [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Forward Price | $ / MMBTU	2.41	[1]	2.55	[2]
Commodity Contracts - Financial [Member] | Minimum [Member] | NGL [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Forward Price | $ / gal	0.20	[1]	0.48	[2]
Commodity Contracts - Financial [Member] | Maximum [Member] | Natural Gas [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Forward Price | $ / MMBTU	3.16	[1]	3.72	[2]
Commodity Contracts - Financial [Member] | Maximum [Member] | NGL [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Forward Price | $ / gal	0.99	[1]	1.14	[2]
Commodity Contracts - Financial [Member] | Weighted Average [Member] | Natural Gas [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Forward Price | $ / MMBTU	2.84	[1]	3.04	[2]
Commodity Contracts - Financial [Member] | Weighted Average [Member] | NGL [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Forward Price | $ / gal	0.51	[1]	0.64	[2]
Commodity Contracts - Physical [Member] | Minimum [Member] | Natural Gas [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Forward Price | $ / MMBTU	2.33	[1]	1.55	[2]
Commodity Contracts - Physical [Member] | Minimum [Member] | Crude Oil [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Forward Price | $ / bbl	31.17	[1]	49.57	[2]
Commodity Contracts - Physical [Member] | Minimum [Member] | NGL [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Forward Price | $ / gal	0.20	[1]	0.06	[2]
Commodity Contracts - Physical [Member] | Maximum [Member] | Natural Gas [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Forward Price | $ / MMBTU	3.53	[1]	4.08	[2]
Commodity Contracts - Physical [Member] | Maximum [Member] | Crude Oil [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Forward Price | $ / bbl	47.93	[1]	55.60	[2]
Commodity Contracts - Physical [Member] | Maximum [Member] | NGL [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Forward Price | $ / gal	1.39	[1]	1.21	[2]
Commodity Contracts - Physical [Member] | Weighted Average [Member] | Natural Gas [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Forward Price | $ / MMBTU	2.61	[1]	3.08	[2]
Commodity Contracts - Physical [Member] | Weighted Average [Member] | Crude Oil [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Forward Price | $ / bbl	44.35	[1]	53.51	[2]
Commodity Contracts - Physical [Member] | Weighted Average [Member] | NGL [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Forward Price | $ / gal	0.43	[1]	0.54	[2]
Commodity Options [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Credit Valuation Adjustments	$ (0.4)		$ (0.7)
Commodity Options [Member] | Minimum [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Option Volatility	10.00%	[1]	19.00%	[2]
Commodity Options [Member] | Maximum [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Option Volatility	62.00%	[1]	94.00%	[2]
Commodity Options [Member] | Weighted Average [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Option Volatility	35.00%	[1]	36.00%	[2]
Swaps [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Credit Valuation Adjustments	$ 0.4		$ (0.4)
Level 3 [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Assets and liabilities accounted for at fair value on a recurring basis	112	[3]	168.9	[4]
Credit Valuation Adjustments	(0.3)		(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	0.3	[3]	0.6	[4]
Level 3 [Member] | Commodity Contracts - Financial [Member] | NGL [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Assets and liabilities accounted for at fair value on a recurring basis	14	[3]	42.1	[4]
Level 3 [Member] | Commodity Contracts - Physical [Member] | Natural Gas [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Assets and liabilities accounted for at fair value on a recurring basis	(3.9)	[3]	1.5	[4]
Level 3 [Member] | Commodity Contracts - Physical [Member] | Crude Oil [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Assets and liabilities accounted for at fair value on a recurring basis	(0.4)	[3]	(0.9)	[4]
Level 3 [Member] | Commodity Contracts - Physical [Member] | NGL [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Assets and liabilities accounted for at fair value on a recurring basis	8.9	[3]	18.9	[4]
Level 3 [Member] | Commodity Options [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Assets and liabilities accounted for at fair value on a recurring basis	$ 93.1	[3]	$ 106.7	[4]
[1]	Prices are in dollars per Millions of British Thermal Units, or MMBtu, for natural gas, dollars per Gallon, or Gal, for NGLs and dollars per barrel, or Bbl, for crude oil.
[2]	Prices are in dollars per MMBtu for natural gas, Gal for NGLs, and Bbl for crude oil.
[3]	Fair values include credit valuation adjustment losses of approximately $0.3 million.
[4]	Fair values include credit valuation adjustment losses of approximately $1.0 million.

DERIVATIVE FINANCIAL INSTRUME71

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Reconciliation of Changes in Fair Value of L3 Assets and Liabilities on Recurring Basis) (Details) $ in Millions	9 Months Ended
	Sep. 30, 2015USD ($)
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Beginning balance	$ 168.9
Transfer in (out) of Level 3		[1]
Gains or losses included in other comprehensive income	$ 0.4
Purchases, issuances, sales and settlements:
Purchases
Sales	$ 2
Settlements	(104)	[2]
Ending balance	112
Operating Revenue [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Gains or losses included in earnings	(3.2)
Purchases, issuances, sales and settlements:
Amounts reported in Operating revenue	(22.7)
Amount of changes in net assets attributable to the change in unrealized gains or losses related to assets and liabilities still held at the reporting date	(1.4)
Cost of Natural Gas and Natural Gas Liquids [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Gains or losses included in earnings	47.9
Purchases, issuances, sales and settlements:
Amount of changes in net assets attributable to the change in unrealized gains or losses related to assets and liabilities still held at the reporting date	33.9
Commodity Contracts - Financial [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Beginning balance	$ 42.7
Transfer in (out) of Level 3		[1]
Gains or losses included in other comprehensive income	$ 0.4
Purchases, issuances, sales and settlements:
Purchases
Sales
Settlements	$ (27.7)	[2]
Ending balance	$ 14.3
Commodity Contracts - Financial [Member] | Operating Revenue [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Gains or losses included in earnings
Purchases, issuances, sales and settlements:
Amounts reported in Operating revenue
Amount of changes in net assets attributable to the change in unrealized gains or losses related to assets and liabilities still held at the reporting date
Commodity Contracts - Financial [Member] | Cost of Natural Gas and Natural Gas Liquids [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Gains or losses included in earnings	$ (1.1)
Purchases, issuances, sales and settlements:
Amount of changes in net assets attributable to the change in unrealized gains or losses related to assets and liabilities still held at the reporting date	(2)
Commodity Contracts - Physical [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Beginning balance	$ 19.5
Transfer in (out) of Level 3		[1]
Gains or losses included in other comprehensive income
Purchases, issuances, sales and settlements:
Purchases
Sales
Settlements	$ (30.5)	[2]
Ending balance	4.6
Commodity Contracts - Physical [Member] | Operating Revenue [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Gains or losses included in earnings	(3.2)
Purchases, issuances, sales and settlements:
Amounts reported in Operating revenue	(22.7)
Amount of changes in net assets attributable to the change in unrealized gains or losses related to assets and liabilities still held at the reporting date	(1.4)
Commodity Contracts - Physical [Member] | Cost of Natural Gas and Natural Gas Liquids [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Gains or losses included in earnings	18.8
Purchases, issuances, sales and settlements:
Amount of changes in net assets attributable to the change in unrealized gains or losses related to assets and liabilities still held at the reporting date	5.3
Commodity Options [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Beginning balance	$ 106.7
Transfer in (out) of Level 3		[1]
Gains or losses included in other comprehensive income
Purchases, issuances, sales and settlements:
Purchases
Sales	$ 2
Settlements	(45.8)	[2]
Ending balance	$ 93.1
Commodity Options [Member] | Operating Revenue [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Gains or losses included in earnings
Purchases, issuances, sales and settlements:
Amounts reported in Operating revenue
Amount of changes in net assets attributable to the change in unrealized gains or losses related to assets and liabilities still held at the reporting date
Commodity Options [Member] | Cost of Natural Gas and Natural Gas Liquids [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Gains or losses included in earnings	$ 30.2
Purchases, issuances, sales and settlements:
Amount of changes in net assets attributable to the change in unrealized gains or losses related to assets and liabilities still held at the reporting date	$ 30.6
[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.

DERIVATIVE FINANCIAL INSTRUME72

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Fair Values of Expected Cash Flows of Commodity Based Swaps and Physical Contracts) (Details) $ in Millions		9 Months Ended	12 Months Ended
		Sep. 30, 2015USD ($)MMBTU$ / MMBTU$ / bblbbl	Dec. 31, 2014USD ($)
Fair Value
Asset		$ 181.9	$ 256.5
Liability	[1]	$ (80)	$ (96.9)
Swaps - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Fixed - NGL [Member]
Derivative [Line Items]
Notional (Bbl) | bbl	[2]	964,000
Fair Value
Asset	[3]	$ 0.7
Liability	[3]	$ (3.3)	$ (6.8)
Swaps - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Fixed - Crude Oil [Member]
Derivative [Line Items]
Notional (Bbl) | bbl	[2]	350,000
Fair Value
Asset	[3]
Liability	[3]	$ (9.5)	$ (27.4)
Swaps - Portion of Contracts Maturing in 2015 - Receive Fixed/Pay Variable - NGL [Member]
Derivative [Line Items]
Notional (Bbl) | bbl	[2]	1,913,800
Fair Value
Asset	[3]	$ 11.3	$ 39.2
Liability	[3]	$ (1)
Swaps - Portion of Contracts Maturing in 2015 - Receive Fixed/Pay Variable - Crude Oil [Member]
Derivative [Line Items]
Notional (Bbl) | bbl	[2]	398,720
Fair Value
Asset	[3]	$ 14.2	$ 42.4
Liability	[3]
Swaps - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Notional (MMBtu) | MMBTU	[2]	828,000
Fair Value
Asset	[3]		$ 1.5
Liability	[3]	$ (0.1)	$ (1.7)
Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Fixed - NGL [Member]
Derivative [Line Items]
Notional (Bbl) | bbl	[2]	50,000
Fair Value
Asset	[3]
Liability	[3]	$ (0.1)	$ (3.6)
Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Fixed - Crude Oil [Member]
Derivative [Line Items]
Notional (Bbl) | bbl	[2]	8,600
Fair Value
Asset	[3]
Liability	[3]
Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Fixed/Pay Variable - NGL [Member]
Derivative [Line Items]
Notional (Bbl) | bbl	[2]	3,048,988
Fair Value
Asset	[3]	$ 6.4	$ 19.8
Liability	[3]	$ (1.3)
Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Fixed/Pay Variable - Crude Oil [Member]
Derivative [Line Items]
Notional (Bbl) | bbl	[2]	54,500
Fair Value
Asset	[3]		$ 0.5
Liability	[3]	$ (0.2)
Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Notional (MMBtu) | MMBTU	[2]	54,524,000
Fair Value
Asset	[3]		$ 2.2
Liability	[3]	$ (0.8)	(1)
Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Variable - NGL [Member]
Derivative [Line Items]
Notional (Bbl) | bbl	[2]	5,150,479
Fair Value
Asset	[3]	$ 5.3	3.7
Liability	[3]	$ (2.9)	(1)
Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Variable - Crude Oil [Member]
Derivative [Line Items]
Notional (Bbl) | bbl	[2]	742,342
Fair Value
Asset	[3]	$ 1.3	0.3
Liability	[3]	$ (1.5)	$ (1.7)
Swaps - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Fixed - Natural Gas [Member]
Derivative [Line Items]
Notional (MMBtu) | MMBTU	[2]	16,287
Fair Value
Asset	[3]
Liability	[3]		$ (0.1)
Swaps - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Fixed - NGL [Member]
Derivative [Line Items]
Notional (Bbl) | bbl	[2]	833,500
Fair Value
Asset	[3]
Liability	[3]	$ (5.6)
Swaps - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Fixed - Crude Oil [Member]
Derivative [Line Items]
Notional (Bbl) | bbl	[2]	415,950
Fair Value
Asset	[3]
Liability	[3]	$ (14)	$ (8.1)
Swaps - Portion of Contracts Maturing in 2016 - Receive Fixed/Pay Variable - NGL [Member]
Derivative [Line Items]
Notional (Bbl) | bbl	[2]	1,428,500
Fair Value
Asset	[3]	$ 13.3	$ 9.3
Liability	[3]	$ (0.3)
Swaps - Portion of Contracts Maturing in 2016 - Receive Fixed/Pay Variable - Crude Oil [Member]
Derivative [Line Items]
Notional (Bbl) | bbl	[2]	425,950
Fair Value
Asset	[3]	$ 14.9	$ 9.1
Liability	[3]
Swaps - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Notional (MMBtu) | MMBTU	[2]	5,124,000
Fair Value
Asset	[3]	$ 0.2	$ 0.5
Liability	[3]		$ (0.3)
Physical Contracts - Portion of Contracts Maturing in 2016 - Receive Fixed/Pay Variable - NGL [Member]
Derivative [Line Items]
Notional (Bbl) | bbl	[2]	233,952
Fair Value
Asset	[3]	$ 0.2
Liability	[3]	$ (0.1)
Physical Contracts - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Notional (MMBtu) | MMBTU	[2]	177,875,634
Fair Value
Asset	[3]		$ 0.7
Liability	[3]	$ (3.4)	$ (0.4)
Physical Contracts - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Variable - NGL [Member]
Derivative [Line Items]
Notional (Bbl) | bbl	[2]	9,640,509
Fair Value
Asset	[3]	$ 1.6
Liability	[3]	$ (0.2)
Swaps - Portion of Contracts Maturing in 2017 - Receive Variable/Pay Fixed - Natural Gas [Member]
Derivative [Line Items]
Notional (MMBtu) | MMBTU	[2]	76,530
Fair Value
Asset	[3]
Liability	[3]
Swaps - Portion of Contracts Maturing in 2017 - Receive Variable/Pay Fixed - NGL [Member]
Derivative [Line Items]
Notional (Bbl) | bbl	[2]	547,500
Fair Value
Asset	[3]
Liability	[3]	$ (3.2)
Swaps - Portion of Contracts Maturing in 2017 - Receive Variable/Pay Fixed - Crude Oil [Member]
Derivative [Line Items]
Notional (Bbl) | bbl	[2]	547,500
Fair Value
Asset	[3]
Liability	[3]	$ (7.6)
Swaps - Portion of Contracts Maturing in 2017 - Receive Fixed/Pay Variable - NGL [Member]
Derivative [Line Items]
Notional (Bbl) | bbl	[2]	547,500
Fair Value
Asset	[3]	$ 2	$ 0.7
Liability	[3]
Swaps - Portion of Contracts Maturing in 2017 - Receive Fixed/Pay Variable - Crude Oil [Member]
Derivative [Line Items]
Notional (Bbl) | bbl	[2]	547,500
Fair Value
Asset	[3]	$ 7.6	$ 0.8
Liability	[3]
Swaps - Portion of Contracts Maturing in 2017 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Notional (MMBtu) | MMBTU	[2]	8,050,000
Fair Value
Asset	[3]	$ 0.4
Liability	[3]
Physical Contracts - Portion of Contracts Maturing in 2017 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Notional (MMBtu) | MMBTU	[2]	2,187,810
Fair Value
Asset	[3]	$ 0.1	$ 0.2
Liability	[3]		$ (0.1)
Physical Contracts - Portion of Contracts Maturing in 2018 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Notional (MMBtu) | MMBTU	[2]	2,187,810
Fair Value
Asset	[3]	$ 0.1
Liability	[3]
Physical Contracts - Portion of Contracts Maturing in 2019 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Notional (MMBtu) | MMBTU	[2]	2,187,810
Fair Value
Asset	[3]	$ 0.1
Liability	[3]
Physical Contracts - Portion of Contracts Maturing in 2020 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Notional (MMBtu) | MMBTU	[2]	359,640
Fair Value
Asset	[3]
Liability	[3]
Swap [Member]
Fair Value
Credit valuation adjustments		$ 0.4	$ (0.4)
Receive [Member] | Swaps - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Fixed - NGL [Member]
Derivative [Line Items]
Wtd. Average Price | $ / bbl	[4]	22.66
Receive [Member] | Swaps - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Fixed - Crude Oil [Member]
Derivative [Line Items]
Wtd. Average Price | $ / bbl	[4]	45.54
Receive [Member] | Swaps - Portion of Contracts Maturing in 2015 - Receive Fixed/Pay Variable - NGL [Member]
Derivative [Line Items]
Wtd. Average Price | $ / bbl	[4]	29.66
Receive [Member] | Swaps - Portion of Contracts Maturing in 2015 - Receive Fixed/Pay Variable - Crude Oil [Member]
Derivative [Line Items]
Wtd. Average Price | $ / bbl	[4]	81.28
Receive [Member] | Swaps - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price | $ / MMBTU	[4]	2.45
Receive [Member] | Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Fixed - NGL [Member]
Derivative [Line Items]
Wtd. Average Price | $ / bbl	[4]	31.63
Receive [Member] | Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Fixed - Crude Oil [Member]
Derivative [Line Items]
Wtd. Average Price | $ / bbl	[4]	45.26
Receive [Member] | Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Fixed/Pay Variable - NGL [Member]
Derivative [Line Items]
Wtd. Average Price | $ / bbl	[4]	18.83
Receive [Member] | Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Fixed/Pay Variable - Crude Oil [Member]
Derivative [Line Items]
Wtd. Average Price | $ / bbl	[4]	42.69
Receive [Member] | Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price | $ / MMBTU	[4]	2.48
Receive [Member] | Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Variable - NGL [Member]
Derivative [Line Items]
Wtd. Average Price | $ / bbl	[4]	20.54
Receive [Member] | Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Variable - Crude Oil [Member]
Derivative [Line Items]
Wtd. Average Price | $ / bbl	[4]	43.59
Receive [Member] | Swaps - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Fixed - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price | $ / MMBTU	[4]	2.72
Receive [Member] | Swaps - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Fixed - NGL [Member]
Derivative [Line Items]
Wtd. Average Price | $ / bbl	[4]	23.81
Receive [Member] | Swaps - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Fixed - Crude Oil [Member]
Derivative [Line Items]
Wtd. Average Price | $ / bbl	[4]	49.02
Receive [Member] | Swaps - Portion of Contracts Maturing in 2016 - Receive Fixed/Pay Variable - NGL [Member]
Derivative [Line Items]
Wtd. Average Price | $ / bbl	[4]	31.34
Receive [Member] | Swaps - Portion of Contracts Maturing in 2016 - Receive Fixed/Pay Variable - Crude Oil [Member]
Derivative [Line Items]
Wtd. Average Price | $ / bbl	[4]	84.17
Receive [Member] | Swaps - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price | $ / MMBTU	[4]	2.79
Receive [Member] | Physical Contracts - Portion of Contracts Maturing in 2016 - Receive Fixed/Pay Variable - NGL [Member]
Derivative [Line Items]
Wtd. Average Price | $ / bbl	[4]	20.02
Receive [Member] | Physical Contracts - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price | $ / MMBTU	[4]	2.62
Receive [Member] | Physical Contracts - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Variable - NGL [Member]
Derivative [Line Items]
Wtd. Average Price | $ / bbl	[4]	17.02
Receive [Member] | Swaps - Portion of Contracts Maturing in 2017 - Receive Variable/Pay Fixed - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price | $ / MMBTU	[4]	2.62
Receive [Member] | Swaps - Portion of Contracts Maturing in 2017 - Receive Variable/Pay Fixed - NGL [Member]
Derivative [Line Items]
Wtd. Average Price | $ / bbl	[4]	19.97
Receive [Member] | Swaps - Portion of Contracts Maturing in 2017 - Receive Variable/Pay Fixed - Crude Oil [Member]
Derivative [Line Items]
Wtd. Average Price | $ / bbl	[4]	52.74
Receive [Member] | Swaps - Portion of Contracts Maturing in 2017 - Receive Fixed/Pay Variable - NGL [Member]
Derivative [Line Items]
Wtd. Average Price | $ / bbl	[4]	23.59
Receive [Member] | Swaps - Portion of Contracts Maturing in 2017 - Receive Fixed/Pay Variable - Crude Oil [Member]
Derivative [Line Items]
Wtd. Average Price | $ / bbl	[4]	66.78
Receive [Member] | Swaps - Portion of Contracts Maturing in 2017 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price | $ / MMBTU	[4]	2.82
Receive [Member] | Physical Contracts - Portion of Contracts Maturing in 2017 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price | $ / MMBTU	[4]	3.03
Receive [Member] | Physical Contracts - Portion of Contracts Maturing in 2018 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price | $ / MMBTU	[4]	3.16
Receive [Member] | Physical Contracts - Portion of Contracts Maturing in 2019 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price | $ / MMBTU	[4]	3.25
Receive [Member] | Physical Contracts - Portion of Contracts Maturing in 2020 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price | $ / MMBTU	[4]	3.55
Pay [Member] | Swaps - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Fixed - NGL [Member]
Derivative [Line Items]
Wtd. Average Price | $ / bbl	[4]	25.42
Pay [Member] | Swaps - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Fixed - Crude Oil [Member]
Derivative [Line Items]
Wtd. Average Price | $ / bbl	[4]	72.70
Pay [Member] | Swaps - Portion of Contracts Maturing in 2015 - Receive Fixed/Pay Variable - NGL [Member]
Derivative [Line Items]
Wtd. Average Price | $ / bbl	[4]	24.25
Pay [Member] | Swaps - Portion of Contracts Maturing in 2015 - Receive Fixed/Pay Variable - Crude Oil [Member]
Derivative [Line Items]
Wtd. Average Price | $ / bbl	[4]	45.63
Pay [Member] | Swaps - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price | $ / MMBTU	[4]	2.52
Pay [Member] | Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Fixed - NGL [Member]
Derivative [Line Items]
Wtd. Average Price | $ / bbl	[4]	33.02
Pay [Member] | Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Fixed - Crude Oil [Member]
Derivative [Line Items]
Wtd. Average Price | $ / bbl	[4]	45.12
Pay [Member] | Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Fixed/Pay Variable - NGL [Member]
Derivative [Line Items]
Wtd. Average Price | $ / bbl	[4]	17.16
Pay [Member] | Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Fixed/Pay Variable - Crude Oil [Member]
Derivative [Line Items]
Wtd. Average Price | $ / bbl	[4]	45.80
Pay [Member] | Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price | $ / MMBTU	[4]	2.49
Pay [Member] | Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Variable - NGL [Member]
Derivative [Line Items]
Wtd. Average Price | $ / bbl	[4]	20.07
Pay [Member] | Physical Contracts - Portion of Contracts Maturing in 2015 - Receive Variable/Pay Variable - Crude Oil [Member]
Derivative [Line Items]
Wtd. Average Price | $ / bbl	[4]	43.90
Pay [Member] | Swaps - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Fixed - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price | $ / MMBTU	[4]	3.48
Pay [Member] | Swaps - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Fixed - NGL [Member]
Derivative [Line Items]
Wtd. Average Price | $ / bbl	[4]	30.54
Pay [Member] | Swaps - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Fixed - Crude Oil [Member]
Derivative [Line Items]
Wtd. Average Price | $ / bbl	[4]	82.69
Pay [Member] | Swaps - Portion of Contracts Maturing in 2016 - Receive Fixed/Pay Variable - NGL [Member]
Derivative [Line Items]
Wtd. Average Price | $ / bbl	[4]	22.26
Pay [Member] | Swaps - Portion of Contracts Maturing in 2016 - Receive Fixed/Pay Variable - Crude Oil [Member]
Derivative [Line Items]
Wtd. Average Price | $ / bbl	[4]	48.95
Pay [Member] | Swaps - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price | $ / MMBTU	[4]	2.76
Pay [Member] | Physical Contracts - Portion of Contracts Maturing in 2016 - Receive Fixed/Pay Variable - NGL [Member]
Derivative [Line Items]
Wtd. Average Price | $ / bbl	[4]	19.25
Pay [Member] | Physical Contracts - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price | $ / MMBTU	[4]	2.64
Pay [Member] | Physical Contracts - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Variable - NGL [Member]
Derivative [Line Items]
Wtd. Average Price | $ / bbl	[4]	16.88
Pay [Member] | Swaps - Portion of Contracts Maturing in 2017 - Receive Variable/Pay Fixed - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price | $ / MMBTU	[4]	2.97
Pay [Member] | Swaps - Portion of Contracts Maturing in 2017 - Receive Variable/Pay Fixed - NGL [Member]
Derivative [Line Items]
Wtd. Average Price | $ / bbl	[4]	25.86
Pay [Member] | Swaps - Portion of Contracts Maturing in 2017 - Receive Variable/Pay Fixed - Crude Oil [Member]
Derivative [Line Items]
Wtd. Average Price | $ / bbl	[4]	66.72
Pay [Member] | Swaps - Portion of Contracts Maturing in 2017 - Receive Fixed/Pay Variable - NGL [Member]
Derivative [Line Items]
Wtd. Average Price | $ / bbl	[4]	19.97
Pay [Member] | Swaps - Portion of Contracts Maturing in 2017 - Receive Fixed/Pay Variable - Crude Oil [Member]
Derivative [Line Items]
Wtd. Average Price | $ / bbl	[4]	52.74
Pay [Member] | Swaps - Portion of Contracts Maturing in 2017 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price | $ / MMBTU	[4]	2.77
Pay [Member] | Physical Contracts - Portion of Contracts Maturing in 2017 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price | $ / MMBTU	[4]	3.01
Pay [Member] | Physical Contracts - Portion of Contracts Maturing in 2018 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price | $ / MMBTU	[4]	3.14
Pay [Member] | Physical Contracts - Portion of Contracts Maturing in 2019 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price | $ / MMBTU	[4]	3.22
Pay [Member] | Physical Contracts - Portion of Contracts Maturing in 2020 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Wtd. Average Price | $ / MMBTU	[4]	3.52
[1]	Includes $16.2 million and $28.4 million of cash collateral at September 30, 2015 and December 31, 2014, respectively.
[2]	Volumes of natural gas are measured in MMBtu, whereas volumes of NGL and crude oil are measured in Bbl.
[3]	The fair value is determined based on quoted market prices at September 30, 2015, and December 31, 2014, respectively, discounted using the swap rate for the respective periods to consider the time value of money. Fair values exclude credit valuation adjustment gains (losses) of approximately $0.4 million and ($0.4) million at September 30, 2015 and December 31, 2014, respectively, as well as cash collateral received.
[4]	Weighted-average prices received and paid are in $/MMBtu for natural gas and $/Bbl for NGL and crude oil.

DERIVATIVE FINANCIAL INSTRUME73

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Fair Values of Expected Cash Flows of Commodity Options) (Details) $ in Millions		9 Months Ended	12 Months Ended
		Sep. 30, 2015USD ($)MMBTU$ / MMBTU$ / bblbbl	Dec. 31, 2014USD ($)
Fair Value
Asset		$ 181.9	$ 256.5
Liability	[1]	(80)	(96.9)
Commodity Option [Member]
Fair Value
Credit valuation adjustments		$ (0.4)	$ (0.7)
Written [Member] | Portion of Put Option Contracts Maturing in 2015 - Natural Gas [Member]
Derivative [Line Items]
Notional (MMBtu) | MMBTU	[2]	1,012,000
Strike Price | $ / MMBTU	[3]	3.90
Market Price | $ / MMBTU	[3]	2.60
Fair Value
Asset	[4]
Liability	[4]	$ (1.3)	$ (3.8)
Written [Member] | Portion of Put Option Contracts Maturing in 2015 - NGL [Member]
Derivative [Line Items]
Notional (Bbl) | bbl	[2]	23,000
Strike Price | $ / bbl	[3]	77.28
Market Price | $ / bbl	[3]	39.81
Fair Value
Asset	[4]
Liability	[4]	$ (0.9)
Written [Member] | Portion of Call Option Contracts Maturing in 2015 - Natural Gas [Member]
Derivative [Line Items]
Notional (MMBtu) | MMBTU	[2]	322,000
Strike Price | $ / MMBTU	[3]	5.05
Market Price | $ / MMBTU	[3]	2.60
Fair Value
Asset	[4]
Liability	[4]
Written [Member] | Portion of Call Option Contracts Maturing in 2015 - NGL [Member]
Derivative [Line Items]
Notional (Bbl) | bbl	[2]	372,600
Strike Price | $ / bbl	[3]	45.80
Market Price | $ / bbl	[3]	23.58
Fair Value
Asset	[4]
Liability	[4]		$ (0.6)
Written [Member] | Portion of Call Option Contracts Maturing in 2015 - Crude Oil [Member]
Derivative [Line Items]
Notional (Bbl) | bbl	[2]	184,000
Strike Price | $ / bbl	[3]	88.39
Market Price | $ / bbl	[3]	45.77
Fair Value
Asset	[4]
Liability	[4]		$ (0.4)
Written [Member] | Portion of Put Option Contracts Maturing in 2016 - Natural Gas [Member]
Derivative [Line Items]
Notional (MMBtu) | MMBTU	[2]	1,647,000
Strike Price | $ / MMBTU	[3]	3.75
Market Price | $ / MMBTU	[3]	2.80
Fair Value
Asset	[4]
Liability	[4]	$ (1.7)	$ (1)
Written [Member] | Portion of Put Option Contracts Maturing in 2016 - NGL [Member]
Derivative [Line Items]
Notional (Bbl) | bbl	[2]	91,500
Strike Price | $ / bbl	[3]	39.06
Market Price | $ / bbl	[3]	25.26
Fair Value
Asset	[4]
Liability	[4]	$ (1.3)
Written [Member] | Portion of Call Option Contracts Maturing in 2016 - Natural Gas [Member]
Derivative [Line Items]
Notional (MMBtu) | MMBTU	[2]	1,647,000
Strike Price | $ / MMBTU	[3]	4.98
Market Price | $ / MMBTU	[3]	2.80
Fair Value
Asset	[4]
Liability	[4]		$ (0.1)
Written [Member] | Portion of Call Option Contracts Maturing in 2016 - NGL [Member]
Derivative [Line Items]
Notional (Bbl) | bbl	[2]	2,836,500
Strike Price | $ / bbl	[3]	45.14
Market Price | $ / bbl	[3]	22.88
Fair Value
Asset	[4]
Liability	[4]	$ (1.2)	$ (3.2)
Written [Member] | Portion of Call Option Contracts Maturing in 2016 - Crude Oil [Member]
Derivative [Line Items]
Notional (Bbl) | bbl	[2]	805,200
Strike Price | $ / bbl	[3]	86.68
Market Price | $ / bbl	[3]	49.23
Fair Value
Asset	[4]
Liability	[4]	$ (0.2)	$ (2.7)
Written [Member] | Portion of Call Option Contracts Maturing in 2017 - NGL [Member]
Derivative [Line Items]
Notional (Bbl) | bbl	[2]	1,277,500
Strike Price | $ / bbl	[3]	29.46
Market Price | $ / bbl	[3]	24.76
Fair Value
Asset	[4]
Liability	[4]	$ (3)	$ (0.7)
Written [Member] | Portion of Call Option Contracts Maturing in 2017 - Crude Oil [Member]
Derivative [Line Items]
Notional (Bbl) | bbl	[2]	547,500
Strike Price | $ / bbl	[3]	71.45
Market Price | $ / bbl	[3]	52.74
Fair Value
Asset	[4]
Liability	[4]	$ (1.1)	$ (3.3)
Purchased [Member] | Portion of Put Option Contracts Maturing in 2015 - Natural Gas [Member]
Derivative [Line Items]
Notional (MMBtu) | MMBTU	[2]	1,012,000
Strike Price | $ / MMBTU	[3]	3.90
Market Price | $ / MMBTU	[3]	2.60
Fair Value
Asset	[4]	$ 1.3	$ 3.8
Liability	[4]
Purchased [Member] | Portion of Put Option Contracts Maturing in 2015 - NGL [Member]
Derivative [Line Items]
Notional (Bbl) | bbl	[2]	579,600
Strike Price | $ / bbl	[3]	43.32
Market Price | $ / bbl	[3]	23.75
Fair Value
Asset	[4]	$ 11.4	$ 40.2
Liability	[4]
Purchased [Member] | Portion of Put Option Contracts Maturing in 2015 - Crude Oil [Member]
Derivative [Line Items]
Notional (Bbl) | bbl	[2]	184,000
Strike Price | $ / bbl	[3]	81.56
Market Price | $ / bbl	[3]	45.77
Fair Value
Asset	[4]	$ 6.6	$ 18.8
Liability	[4]
Purchased [Member] | Portion of Call Option Contracts Maturing in 2015 - Natural Gas [Member]
Derivative [Line Items]
Notional (MMBtu) | MMBTU	[2]	322,000
Strike Price | $ / MMBTU	[3]	5.05
Market Price | $ / MMBTU	[3]	2.60
Fair Value
Asset	[4]
Liability	[4]
Purchased [Member] | Portion of Put Option Contracts Maturing in 2016 - Natural Gas [Member]
Derivative [Line Items]
Notional (MMBtu) | MMBTU	[2]	1,647,000
Strike Price | $ / MMBTU	[3]	3.75
Market Price | $ / MMBTU	[3]	2.80
Fair Value
Asset	[4]	$ 1.7	$ 1
Liability	[4]
Purchased [Member] | Portion of Put Option Contracts Maturing in 2016 - NGL [Member]
Derivative [Line Items]
Notional (Bbl) | bbl	[2]	2,836,500
Strike Price | $ / bbl	[3]	39.24
Market Price | $ / bbl	[3]	22.88
Fair Value
Asset	[4]	$ 48.4	$ 39.3
Liability	[4]
Purchased [Member] | Portion of Put Option Contracts Maturing in 2016 - Crude Oil [Member]
Derivative [Line Items]
Notional (Bbl) | bbl	[2]	805,200
Strike Price | $ / bbl	[3]	75.91
Market Price | $ / bbl	[3]	49.23
Fair Value
Asset	[4]	$ 21.8	$ 14.7
Liability	[4]
Purchased [Member] | Portion of Call Option Contracts Maturing in 2016 - Natural Gas [Member]
Derivative [Line Items]
Notional (MMBtu) | MMBTU	[2]	1,647,000
Strike Price | $ / MMBTU	[3]	4.98
Market Price | $ / MMBTU	[3]	2.80
Fair Value
Asset	[4]		$ 0.1
Liability	[4]
Purchased [Member] | Portion of Call Option Contracts Maturing in 2016 - NGL [Member]
Derivative [Line Items]
Notional (Bbl) | bbl	[2]	91,500
Strike Price | $ / bbl	[3]	46.41
Market Price | $ / bbl	[3]	25.26
Fair Value
Asset	[4]
Liability	[4]
Purchased [Member] | Portion of Put Option Contracts Maturing in 2017 - NGL [Member]
Derivative [Line Items]
Notional (Bbl) | bbl	[2]	1,277,500
Strike Price | $ / bbl	[3]	25.26
Market Price | $ / bbl	[3]	24.76
Fair Value
Asset	[4]	$ 5.5	$ 1.2
Liability	[4]
Purchased [Member] | Portion of Put Option Contracts Maturing in 2017 - Crude Oil [Member]
Derivative [Line Items]
Notional (Bbl) | bbl	[2]	547,500
Strike Price | $ / bbl	[3]	63
Market Price | $ / bbl	[3]	52.74
Fair Value
Asset	[4]	$ 7.5	$ 4.1
Liability	[4]
[1]	Includes $16.2 million and $28.4 million of cash collateral at September 30, 2015 and December 31, 2014, respectively.
[2]	Volumes of natural gas are measured in MMBtu, whereas volumes of NGL and crude oil are measured in Bbl.
[3]	Strike and market prices are in $/MMBtu for natural gas and in $/Bbl for NGL and crude oil.
[4]	The fair value is determined based on quoted market prices at September 30, 2015, and December 31, 2014, respectively, discounted using the swap rate for the respective periods to consider the time value of money. Fair values exclude any credit valuation adjustment losses of approximately $0.4 million and $0.7 million at September 30, 2015 and December 31, 2014, respectively, as well as cash collateral received.

INCOME TAXES (Details)

INCOME TAXES (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Income tax expense:
Income tax expense (benefit)	$ 3.7	$ 0.9	$ 1.4	$ 2.7
Tax effect of disposition	2.4		2.4
Current income tax payable	1		1		$ 1.5
Deferred income tax liability	$ 14.4		$ 14.4		$ 14.2
Texas State Income Tax Rate [Member]
Income tax expense:
Effective income tax rate (in percentage)			0.40%	0.50%
State franchise tax rate	0.75%		0.75%		1.00%
Reduction in deferred income tax payable			$ (3.5)

SEGMENT INFORMATION (Details)

SEGMENT INFORMATION (Details) $ in Millions		3 Months Ended				9 Months Ended
		Sep. 30, 2015USD ($)		Sep. 30, 2014USD ($)		Sep. 30, 2015USD ($)segments		Sep. 30, 2014USD ($)		Dec. 31, 2014USD ($)
Segment Reporting Information [Line Items]
Number of reporting segments (in segments) | segments						2
Operating revenue		$ 661		$ 1,399.4		$ 2,314.6		$ 4,443.1
Cost of natural gas and natural gas liquids		522.7		1,238.2		1,972.4		3,986.7
Segment gross margin		138.3		161.2		342.2		456.4
Operating and maintenance		74		80.6		206.9		246.5
General and administrative		$ 21.2		$ 25.9		61.1		$ 74.7
Goodwill impairment						226.5
Asset impairment						12.3
Depreciation and amortization		$ 39.2		$ 39.5		118.3		$ 113.3
Operating Expenses, Total		134.4		146		625.1		434.5
Operating income (loss)		3.9		15.2		(282.9)		21.9
Interest expense, net		(7.6)		(3.6)		(21.5)		(9.7)
Other income (loss)		8.5		5.3		20.3		6.4
Income (loss) before income tax expense		4.8		16.9		(284.1)		18.6
Income tax expense		(3.7)		(0.9)		(1.4)		(2.7)
Net income (loss)		1.1		16		(285.5)		15.9
Less: Net income (loss) attributable to noncontrolling interest		4.7		9.7		(125.4)		13.8
Net income (loss) attributable to general and limited partner ownership interest in Midcoast Energy Partners, L.P.		(3.6)		6.3		(160.1)		2.1
Total assets		5,292.8		5,585.2		5,292.8		5,585.2		$ 5,754.1
Capital expenditures (excluding acquisitions)						147.4		161.6
Equity investment in joint ventures		373.7				373.7				$ 380.6
Operating Segments [Member]
Segment Reporting Information [Line Items]
Operating revenue		878.5		1,898.7		3,119.8		6,046.5
Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Operating revenue		(217.5)		(499.3)		(805.2)		(1,603.4)
Gathering, Processing and Transportation [Member]
Segment Reporting Information [Line Items]
Operating revenue		143.4		161.4		367.6		534.1
Cost of natural gas and natural gas liquids		16.7		20.7		58.5		155.6
Segment gross margin		126.7		140.7		309.1		378.5
Operating and maintenance		55.7		64.9		161.5		196.5
General and administrative		17.2		21.3		48.5		62.4
Goodwill impairment						$ 206.1
Asset impairment
Depreciation and amortization		37.1		35.5		$ 112		105.4
Operating Expenses, Total		110		121.7		528.1		364.3
Operating income (loss)		$ 16.7		$ 19		$ (219)		$ 14.2
Interest expense, net
Other income (loss)		$ 8.9	[1]	$ 5.3	[2]	$ 20.5	[3]	$ 6.4	[4]
Income (loss) before income tax expense		$ 25.6		$ 24.3		$ (198.5)		$ 20.6
Income tax expense
Net income (loss)		$ 25.6		$ 24.3		$ (198.5)		$ 20.6
Less: Net income (loss) attributable to noncontrolling interest
Net income (loss) attributable to general and limited partner ownership interest in Midcoast Energy Partners, L.P.		$ 25.6		$ 24.3		$ (198.5)		$ 20.6
Total assets		4,983	[5]	4,955.8	[6]	4,983	[5]	4,955.8	[6]
Capital expenditures (excluding acquisitions)						132.8		149.8
Equity investment in joint ventures		373.7		380.2		373.7		380.2
Gathering, Processing and Transportation [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Operating revenue		357.7		646.3		1,144.5		2,065.3
Gathering, Processing and Transportation [Member] | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Operating revenue		(214.3)		(484.9)		(776.9)		(1,531.2)
Logistics and Marketing [Member]
Segment Reporting Information [Line Items]
Operating revenue		517.6		1,238		1,947		3,909
Cost of natural gas and natural gas liquids		506		1,217.5		1,913.9		3,831.1
Segment gross margin		11.6		20.5		33.1		77.9
Operating and maintenance		18.2		15.7		45.1		49.8
General and administrative		3		3.1		9		8.8
Goodwill impairment						20.4
Asset impairment						12.3
Depreciation and amortization		2.1		4		6.3		7.9
Operating Expenses, Total		23.3		22.8		93.1		66.5
Operating income (loss)		$ (11.7)		$ (2.3)		$ (60)		$ 11.4
Interest expense, net
Other income (loss)
Income (loss) before income tax expense		$ (11.7)		$ (2.3)		$ (60)		$ 11.4
Income tax expense
Net income (loss)		$ (11.7)		$ (2.3)		$ (60)		$ 11.4
Less: Net income (loss) attributable to noncontrolling interest
Net income (loss) attributable to general and limited partner ownership interest in Midcoast Energy Partners, L.P.		$ (11.7)		$ (2.3)		$ (60)		$ 11.4
Total assets		210.2		499.2		210.2		499.2
Capital expenditures (excluding acquisitions)						11		8.6
Logistics and Marketing [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Operating revenue		520.8		1,252.4		1,975.3		3,981.2
Logistics and Marketing [Member] | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Operating revenue		$ (3.2)		$ (14.4)		$ (28.3)		$ (72.2)
Corporate [Member]
Segment Reporting Information [Line Items]
Operating revenue			[7]		[8]		[9]		[10]
Cost of natural gas and natural gas liquids			[7]		[8]		[9]		[10]
Segment gross margin			[7]		[8]		[9]		[10]
Operating and maintenance		$ 0.1	[7]			$ 0.3	[9]	$ 0.2	[10]
General and administrative		$ 1	[7]	$ 1.5	[8]	$ 3.6	[9]	$ 3.5	[10]
Goodwill impairment	[9]
Asset impairment	[9]
Depreciation and amortization			[7]		[8]		[9]		[10]
Operating Expenses, Total		$ 1.1	[7]	$ 1.5	[8]	$ 3.9	[9]	$ 3.7	[10]
Operating income (loss)		(1.1)	[7]	(1.5)	[8]	(3.9)	[9]	(3.7)	[10]
Interest expense, net		(7.6)	[7]	(3.6)	[8]	(21.5)	[9]	$ (9.7)	[10]
Other income (loss)		(0.4)	[7]			(0.2)	[9]		[10]
Income (loss) before income tax expense		(9.1)	[7]	(5.1)	[8]	(25.6)	[9]	$ (13.4)	[10]
Income tax expense		(3.7)	[7]	(0.9)	[8]	(1.4)	[9]	(2.7)	[10]
Net income (loss)		(12.8)	[7]	(6)	[8]	(27)	[9]	(16.1)	[10]
Less: Net income (loss) attributable to noncontrolling interest		4.7	[7]	9.7	[8]	(125.4)	[9]	13.8	[10]
Net income (loss) attributable to general and limited partner ownership interest in Midcoast Energy Partners, L.P.		(17.5)	[7]	(15.7)	[8]	98.4	[9]	(29.9)	[10]
Total assets		$ 99.6	[9]	$ 130.2	[10]	99.6	[9]	130.2	[10]
Capital expenditures (excluding acquisitions)						$ 3.6	[9]	$ 3.2	[10]
Corporate [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Operating revenue			[7]		[8]		[9]		[10]
Corporate [Member] | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Operating revenue			[7]		[8]		[9]		[10]
[1]	Other income for our Gathering, Processing and Transportation segment includes our equity investment in the Texas Express NGL system.
[2]	Other income for our Gathering, Processing and Transportation segment includes our equity investment in the Texas Express NGL system.
[3]	Other income for our Gathering, Processing and Transportation segment includes our equity investment in the Texas Express NGL system.
[4]	Other income for our Gathering, Processing and Transportation segment includes our equity investment in the Texas Express NGL system.
[5]	Totals assets for our Gathering, Processing and Transportation segment includes $373.7 million for our equity investment in the Texas Express NGL system.
[6]	Totals assets for our Gathering, Processing and Transportation segment includes $380.2 million for our equity investment in the Texas Express NGL system.
[7]	Corporate consists of interest expense, interest income, noncontrolling interest and other costs such as income taxes, which are not allocated to the business segments.
[8]	Corporate consists of interest expense, interest income, noncontrolling interest and other costs such as income taxes, which are not allocated to the business segments.
[9]	Corporate consists of interest expense, interest income, noncontrolling interest and other costs such as income taxes, which are not allocated to the business segments.
[10]	Corporate consists of interest expense, interest income, noncontrolling interest and other costs such as income taxes, which are not allocated to the business segments.

SUPPLEMENTAL CASH FLOW INFORM76

SUPPLEMENTAL CASH FLOW INFORMATION (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
SUPPLEMENTAL CASH FLOW INFORMATION [Abstract]
Additions to property, plant and equipment	$ 155.4	$ 166.6
Decrease in construction payables	(8)	(5)
Total capital expenditures	$ 147.4	$ 161.6

SUBSEQUENT EVENTS (Details)

SUBSEQUENT EVENTS (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended	3 Months Ended		9 Months Ended
	Nov. 13, 2015	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Subsequent Event [Line Items]
Distributions to General Partner		$ 0.3	$ 0.3	$ 0.9	$ 0.9
Subsequent Event [Member]
Subsequent Event [Line Items]
Distribution declaration date				Oct. 29, 2015
Record date				Nov. 6, 2015
Distribution payment date				Nov. 13, 2015
Cash available for distribution		$ 16.5		$ 16.5
Subsequent Event [Member] | Scenario, Forecast [Member]
Subsequent Event [Line Items]
Distribution per Unit (in dollars per share)	$ 0.3575
Amount paid to parent	$ 8.9
Subsequent Event [Member] | Midcoast Operating, L.P. [Member] | Scenario, Forecast [Member]
Subsequent Event [Line Items]
Amount paid to parent	27.4
Distributions to General Partner	25.7
Subsequent Event [Member] | Public Common Unitholders [Member] | Scenario, Forecast [Member]
Subsequent Event [Line Items]
Cash distributed (in dollars)	$ 7.6