Midcoast Energy Partners (MEP) 10-Q 2 May 16 2016 Q1 Quarterly report Financial data

Document And Entity Information

Document And Entity Information - shares	3 Months Ended
	Mar. 31, 2016	May. 02, 2016
Document Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2016
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	Q1
Entity Registrant Name	Midcoast Energy Partners, L.P.
Entity Central Index Key	1,578,685
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Trading Symbol	MEP
Entity Common Stock, Shares Outstanding		22,610,056

CONSOLIDATED STATEMENTS OF INCO

CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Operating revenues:
Commodity sales (Note 13)	$ 377.8	$ 800.9
Commodity sales - affiliate (Notes 11 and 13)	5.2	21.8
Transportation and other services	48.9	50.8
Revenues, Total	431.9	873.5
Operating expenses:
Cost of natural gas and natural gas liquids	348	779.1
Operating and maintenance	57.2	63.4
General and administrative	15.6	21
Depreciation and amortization	39.5	38.3
Costs and Expenses, Total	460.3	901.8
Operating loss	(28.4)	(28.3)
Interest expense, net (Note 9)	(8.3)	(6.7)
Equity in earnings of joint ventures (Note 8)	7.1	5.7
Other income	0.2	0
Loss before income tax expense	(29.4)	(29.3)
Income tax expense (Note 14)	(0.9)	(0.8)
Net loss	(30.3)	(30.1)
Less: Net loss attributable to noncontrolling interest	(10.1)	(10.1)
Net loss attributable to general and limited partner ownership interest in Midcoast Energy Partners, L.P.	(20.2)	(20)
Net loss attributable to limited partner ownership interest	$ (19.8)	$ (19.6)
Net loss per limited partner unit (basic and diluted) (Note 2) (in dollars per share)	$ (0.44)	$ (0.43)
Weighted-average limited partner units outstanding (in shares)	45.2	45.2
Third Party [Member]
Operating expenses:
Cost of natural gas and natural gas liquids	$ 335.4	$ 761.2
Operating and maintenance	32.3	38.2
General and administrative	2.5	1.9
Affiliated Entity [Member]
Operating expenses:
Cost of natural gas and natural gas liquids	12.6	17.9
Operating and maintenance	24.9	25.2
General and administrative	$ 13.1	$ 19.1

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Net loss	$ (30.3)	$ (30.1)
Other comprehensive loss, net of tax	0	(2.9)
Comprehensive loss	(30.3)	(33)
Less:
Net loss attributable to noncontrolling interest	(10.1)	(10.1)
Other comprehensive loss attributed to noncontrolling interest	0	(1.4)
Comprehensive loss attributable to general and limited partner ownership interests in Midcoast Energy Partners, L.P.	$ (20.2)	$ (21.5)

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Cash provided by operating activities:
Net loss	$ (30.3)	$ (30.1)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation and amortization	39.5	38.3
Derivative fair value net losses (Note 13)	27.1	35.1
Inventory market price adjustments (Note 5)	0	4.6
Distributions from investment in joint ventures	7.1	5.7
Equity earnings from investment in joint ventures	(7.1)	(5.7)
Other	(3.1)	0.7
Changes in operating assets and liabilities, net of acquisitions:
Receivables, trade and other	4.8	(11.6)
Due from General Partner and affiliates	45.4	44.4
Accrued receivables	32.1	184.9
Inventory	18.2	48.2
Current and long-term other assets	(1.7)	(12.1)
Due to General Partner and affiliates	68.8	4.8
Accounts payable and other	(31.1)	(9.3)
Accrued purchases	(34.7)	(115.9)
Interest payable	(4.1)	(4.1)
Property and other taxes payable	(7.6)	(9.7)
Net cash provided by operating activities	123.3	168.2
Cash used in investing activities:
Additions to property, plant and equipment (Notes 16)	(16.3)	(56.1)
Changes in restricted cash (Note 3)	3	(2.7)
Acquisitions	0	(44.1)
Investment in joint ventures	0	(1.9)
Distributions from investment in joint ventures in excess of cumulative earnings	4.2	2.4
Other	(0.8)	(0.6)
Net cash used in investing activities	(9.9)	(103)
Cash used in financing activities:
Net repayments under credit facility (Note 9)	(50)	(45)
Distributions to partners (Note 10)	(16.5)	(15.8)
Contributions from General Partner (Note 11)	9.5	0
Contributions from noncontrolling interest	2.9	20.7
Distributions to noncontrolling interest (Note 10)	(25.9)	(19.8)
Net cash used in financing activities	(80)	(59.9)
Net increase in cash and cash equivalents	33.4	5.3
Cash and cash equivalents at beginning of year	18	0
Cash and cash equivalents at end of period	$ 51.4	$ 5.3

CONSOLIDATED STATEMENTS OF FINA

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents (Note 4)	$ 51.4	$ 18
Restricted cash (Note 4)	14.6	20.6
Receivables, trade and other, net of allowance for doubtful accounts of $2.6 million and $2.5 million, respectively, at March 31, 2016 and December 31, 2015	10.3	13.3
Due from General Partner and affiliates (Note 11)	4.3	47
Accrued receivables	24	56.1
Inventory (Note 5)	13.7	31.9
Other current assets (Note 13)	100.2	118.5
Assets, Current, Total	218.5	305.4
Property, plant and equipment, net (Note 6)	4,207.5	4,226.3
Intangible assets, net	267.5	272.9
Equity investment in joint ventures (Note 8)	368	372.3
Other assets, net (Note 13)	81.1	95.2
Total assets	5,142.6	5,272.1
Current liabilities:
Due to General Partner and affiliates (Note 11)	108.2	45.7
Accounts payable and other (Notes 4 and 13)	57.2	92.6
Accrued purchases	109.1	143.8
Property and other taxes payable (Note 14)	10.8	18.4
Interest payable	1.1	5.2
Liabilities, Current, Total	286.4	305.7
Long-term debt (Note 9)	838.3	888.2
Other long-term liabilities (Notes 13 and 14)	39.6	45.9
Total liabilities	$ 1,164.3	$ 1,239.8
Commitments and contingencies (Note 12)
Partners’ capital (Note 10):
General Partner units (922,859 authorized and issued at March 31, 2016 and December 31, 2015)	$ 52.1	$ 43.3
Accumulated other comprehensive income (Note 13)	(0.9)	(0.9)
Total Midcoast Energy Partners, L.P. partners’ capital	1,599.4	1,626.6
Noncontrolling interest	2,378.9	2,405.7
Total partners’ capital	3,978.3	4,032.3
Liabilities and Stockholders' Equity, Total	5,142.6	5,272.1
Class A Common Units [Member]
Partners’ capital (Note 10):
Limited Partner interest	504.2	522.2
Subordinated Units [Member]
Partners’ capital (Note 10):
Limited Partner interest	$ 1,044	$ 1,062

CONSOLIDATED STATEMENTS OF FIN6

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION (Parenthetical) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Receivables, trade and other, allowance for doubtful accounts (in dollars)	$ 2.6	$ 2.5
General Partner, units authorized (in shares)	922,859	922,859
General Partner, units issued (in shares)	922,859	922,859
Class A Common Units [Member]
Partners Capital units, authorized (in shares)	22,610,056	22,610,056
Partners Capital units, issued (in shares)	22,610,056	22,610,056
Subordinated Units [Member]
Partners Capital units, authorized (in shares)	22,610,056	22,610,056
Partners Capital units, issued (in shares)	22,610,056	22,610,056

ORGANIZATION AND NATURE OF OPER

ORGANIZATION AND NATURE OF OPERATIONS	3 Months Ended
	Mar. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [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.” We own and operate, through our 51.6% controlling interest in Midcoast Operating, L.P., or Midcoast Operating, a portfolio of assets engaged in the business of gathering, processing and treating natural gas, as well as the transportation of natural gas, natural gas liquids, or NGLs, crude oil and condensate. In addition, we also provide marketing services of natural gas and NGLs to wholesale customers. Our portfolio of natural gas and NGL pipelines, plants and related facilities are geographically concentrated in the Gulf Coast and Mid-Continent regions of the United States, primarily in Texas and Oklahoma. EEP owns a 48.4% noncontrolling interest in Midcoast Operating. EEP also has a significant interest in us through its ownership of our General Partner, which owns all of our General Partner units and all of our incentive distribution rights, or IDRs, as well as an approximate 52% limited partner interest in us. Our Class A common units trade on the New York Stock Exchange, or NYSE, under the ticker symbol “MEP.” Basis of Presentation We have prepared the accompanying unaudited interim consolidated financial statements in accordance with 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 March 31, 2016, our results of operations for the three months ended March 31, 2016 and 2015, and our cash flows for the three months ended March 31, 2016 and 2015. We derived our consolidated statement of financial position as of December 31, 2015 from the audited financial statements included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2015. Our results of operations for the three months ended March 31, 2016 and 2015, 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, 2015.

NET INCOME PER LIMITED PARTNER

NET INCOME PER LIMITED PARTNER AND GENERAL PARTNER INTEREST	3 Months Ended
	Mar. 31, 2016
Earnings Per Share [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, including any earnings in excess of distributions, to our limited partners, our General Partner and the holders of our IDRs in accordance with the terms of our partnership agreement. We allocate any distributions in excess of earnings for the period to our General Partner and our limited partners based on their respective proportionate ownership interests in us, after taking into account distributions to be paid with respect to the IDRs, as set forth in our partnership agreement. Distribution Targets Portion of Quarterly Percentage Distributed Percentage Distributed Minimum Quarterly Distribution Up to $0.3125 98% 2% First Target Distribution > $0.3125 to $0.359375 98% 2% Second Target Distribution > $0.359375 to $0.390625 85% 15% Third Target Distribution > $0.390625 to $0.468750 75% 25% Over Third Target Distribution In excess of $0.468750 50% 50% For the three months 2016 2015 (in millions, except per unit amounts) Net loss $ (30.3 ) $ (30.1 ) Less: Net loss attributable to noncontrolling interest (10.1 ) (10.1 ) Net loss attributable to general and limited partner interests in Midcoast Energy Partners, L.P. (20.2 ) (20.0 ) Less distributions: Total distributed earnings to our General Partner (0.3 ) (0.3 ) Total distributed earnings to our limited partners (16.2 ) (15.7 ) Total distributed earnings (16.5 ) (16.0 ) Overdistributed earnings $ (36.7 ) $ (36.0 ) Weighted-average limited partner units outstanding 45.2 45.2 Basic and diluted earnings per unit: Distributed earnings per limited partner unit (1) $ 0.36 $ 0.35 Overdistributed earnings per limited partner unit (2) (0.80 ) (0.78 ) Net loss per limited partner unit (basic and diluted) $ (0.44 ) $ (0.43 ) (1) Represents the total distributed earnings to limited partners divided by the weighted-average number of limited partner interests outstanding for the period. (2) Represents the limited partners’ share (98%) of distributions in excess of earnings divided by the weighted-average number of limited partner interests outstanding for the period and underdistributed earnings allocated to the limited partners based on the distribution waterfall that is outlined in our partnership agreement.

ACQUISITIONS

ACQUISITIONS	3 Months Ended
	Mar. 31, 2016
Business Combinations [Abstract]
ACQUISITIONS	3. ACQUISITIONS Acquisitions On February 27, 2015, we acquired a midstream business in Leon, Madison and Grimes counties, Texas. The acquisition consisted of a natural gas gathering system. We acquired the midstream business for $85.0 million in cash and a contingent future payment of up to $17.0 million. Of the $85.0 million purchase price, $20.0 million was placed into escrow, pending the resolution of a legal matter and completion of additional wells connecting to our system within one year of the acquisition date. We have classified $6.0 million of these escrow funds as “Other assets, net” in our consolidated statements of financial position as of March 31, 2016, pending the resolution of a legal matter. Since the acquisition date, we have released $11.0 million from escrow for additional wells connected to our system. During the first quarter of 2016, the remaining $3.0 million in escrow was returned to us as some of the additional wells were not connected to our system within one year of the acquisition date. For the three months ended March 31, 2016, we recognized a $3.0 million gain as a reduction to “Operating and maintenance” expense in our consolidated statements of income related to the return of these escrow funds. The purchase and sale agreement contained a provision whereby we would have been obligated to make future tiered payments of up to $17.0 million if volumes were delivered into the system at certain tiered volume levels over a five-year period. We determined at the time of the acquisition that the potential payment was contingent consideration. At the acquisition date, the fair value of this contingent consideration, using a probability-weighted discounted cash flow model was $2.3 million. The contingent consideration was re-measured on a fair value basis each quarter until December 31, 2015, which resulted in an addition to the liability of $0.3 million for accretion. During the three months ended March 31, 2016, we determined, based on current and forecasted volumes, that it is remote that we will be obligated to make any payments at the expiration of the five-year period. Consequently, we reversed the liability and recognized a $2.6 million gain as a reduction to “Operating and maintenance” expense in our consolidated statements of income for the three months ended March 31, 2016.

CASH AND CASH EQUIVALENTS

CASH AND CASH EQUIVALENTS	3 Months Ended
	Mar. 31, 2016
Cash and Cash Equivalents [Abstract]
CASH AND CASH EQUIVALENTS	4. CASH AND CASH EQUIVALENTS We extinguish liabilities when a creditor has relieved us of our obligation, which occurs when our financial institution honors a check that the creditor has presented for payment. Accordingly, obligations for which we have made payments that have not yet been presented to the financial institution, totaling approximately $3.0 million at March 31, 2016, and $4.2 million at December 31, 2015, are included in “Accounts payable and other” on our consolidated statements of financial position. Restricted Cash March 31, 2016 December 31, 2015 (in millions) Cash collateral on behalf of Enbridge subsidiary for accounts receivable sales and not remitted (see Note 11) $ 14.6 $ 14.6 Cash held in escrow for acquisitions (see Note 3) — 6.0 $ 14.6 $ 20.6

INVENTORY

INVENTORY	3 Months Ended
	Mar. 31, 2016
Inventory Disclosure [Abstract]
INVENTORY	5. INVENTORY March 31, 2016 December 31, 2015 (in millions) Materials and supplies $ 0.6 $ 0.6 Natural gas and NGL inventory 13.1 31.3 $ 13.7 $ 31.9 The “Cost of natural gas and natural gas liquids” on our consolidated statements of income includes charges totaling $4.6 million for the three months ended March 31, 2015, that we recorded to reduce the cost basis of our inventory of natural gas and NGLs, to reflect the current market value. For the three months ended March 31, 2016, we did not have any similar material charges related to our inventory of natural gas and NGLs.

PROPERTY, PLANT AND EQUIPMENT

PROPERTY, PLANT AND EQUIPMENT	3 Months Ended
	Mar. 31, 2016
Property, Plant and Equipment [Abstract]
PROPERTY, PLANT AND EQUIPMENT	6. PROPERTY, PLANT AND EQUIPMENT Depreciation Rates March 31, 2016 December 31, 2015 (in millions) Land — $ 14.5 $ 14.2 Rights-of-way 2.08% – 7.14% 465.5 460.3 Pipelines 1.89% – 6.7% 1,869.1 1,864.4 Pumping equipment, buildings and tanks 1.48% – 6.67% 88.4 88.4 Compressors, meters and other operating equipment 1.8% – 20.0% 2,160.2 2,147.6 Vehicles, office furniture and equipment 2.19% – 33.33% 136.2 137.1 Processing and treating plants 2.21% – 4.0% 629.2 627.8 Construction in progress 47.3 57.1 Total property, plant and equipment 5,410.4 5,396.9 Accumulated depreciation (1,202.9 ) (1,170.6 ) Property, plant and equipment, net $ 4,207.5 $ 4,226.3

VARIABLE INTEREST ENTITIES

VARIABLE INTEREST ENTITIES	3 Months Ended
	Mar. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
VARIABLE INTEREST ENTITIES	7. VARIABLE INTEREST ENTITIES Principles of Consolidation On January 1, 2016, we adopted Accounting Standards Update No. 2015-02, which amended consolidation guidance to, among other things, eliminate the specialized consolidation model and guidance for limited partnerships, including the presumption that the general partner should consolidate a limited partnership. As a result, we have determined that certain entities that we historically consolidated under this presumption are variable interest entities, or VIEs. Further, we determined that we are the primary beneficiary for these VIEs and will continue to consolidate these entities under the amended guidance. While the amended guidance did not impact our conclusion that such entities should be consolidated, because such entities are now considered VIEs, additional disclosures are necessary. We have applied this amended guidance retrospectively to our disclosures. The consolidated financial statements include our accounts, and accounts of our subsidiaries and VIEs for which we are the primary beneficiary. Upon inception of a contractual agreement, we perform an assessment to determine whether the arrangement contains a variable interest in a legal entity and whether that legal entity is a VIE. Where we conclude we are the primary beneficiary of a VIE, we consolidate the accounts of that entity. We assess all aspects of our interests in an entity and use judgment when determining if we are the primary beneficiary. The primary beneficiary has both the power to direct the activities of the VIE that most significantly impact the entity’s economic performance and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. Other qualitative factors that are considered include decision-making responsibilities, the VIE capital structure, risk and rewards sharing, contractual agreements with the VIE, voting rights and level of involvement of other parties. A reassessment of the primary beneficiary conclusion is conducted when there are changes in the facts and circumstances related to a VIE. All significant intercompany accounts and transactions are eliminated upon consolidation. Ownership interests in subsidiaries represented by other parties that do not control the entity are presented in the consolidated financial statements as activities and balances attributable to noncontrolling interests. Investments and entities over which we exercise significant influence are accounted for using the equity method. Midcoast Operating Midcoast Operating is a Texas limited partnership. As of March 31, 2016, we owned a 51.6% direct limited partner interest in Midcoast Operating. In addition, we own Midcoast Operating’s general partner, Midcoast OLP GP, L.L.C. EEP owns the remaining limited partner interests in Midcoast Operating. We are the primary beneficiary of Midcoast Operating because (1) through our ownership in Midcoast Operating’s general partner and our majority limited partner interest, we have the power to direct the activities that most significantly impact Midcoast Operating’s economic performance; and (2) we have the obligation to absorb losses and the right to receive residual returns that potentially could be significant to Midcoast Operating. In addition, we are the entity within the related party group that is most closely associated with Midcoast Operating. As of March 31, 2016 and December 31, 2015, our consolidated statements of financial position include total assets of $5,079.0 million and $5,241.5 million, respectively, and total liabilities of $251.4 million and $323.7 million, respectively, related to Midcoast Operating. The assets of Midcoast Operating can only be used to settle their obligations, which include a cross-guarantee under MEP’s Credit Agreement and a guarantee of MEP’s Senior Notes. We do not have an obligation to provide financial support to Midcoast Operating other than by virtue of certain contractual obligations prescribed by the terms of certain indemnities and guarantees to pay certain liabilities of Midcoast Operating in the event of a default. March 31, 2016 December 31, 2015 (unaudited; in millions) ASSETS Cash and cash equivalents $ 3.6 $ 3.4 Restricted cash $ — $ 6.0 Receivables, trade and other, net $ 10.4 $ 13.3 Due from General Partner and affiliates $ 4.1 $ 46.9 Accrued receivables $ 24.0 $ 56.1 Inventory $ 13.7 $ 31.9 Other current assets $ 100.2 $ 118.5 Property, plant and equipment, net $ 4,207.5 $ 4,226.3 Intangible assets, net $ 267.5 $ 272.9 Equity investment in joint ventures $ 368.0 $ 372.3 Other assets, net $ 80.0 $ 93.9 LIABILITIES Due to General Partner and affiliates $ 38.4 $ 28.5 Accounts payable and other $ 53.5 $ 87.1 Accrued purchases $ 109.1 $ 143.8 Property and other taxes payable $ 10.8 $ 18.4 Other long-term liabilities $ 39.6 $ 45.9

EQUITY INVESTMENTS IN JOINT VEN

EQUITY INVESTMENTS IN JOINT VENTURES	3 Months Ended
	Mar. 31, 2016
Equity Method Investments and Joint Ventures [Abstract]
EQUITY INVESTMENTS IN JOINT VENTURES	8. EQUITY INVESTMENTS IN JOINT VENTURES We have a 35% aggregate interest in the Texas Express NGL system, which is comprised of two joint ventures with third parties. The Texas Express NGL system consists of a 593-mile NGL intrastate transportation pipeline and a related NGL gathering system. Our investment in and earnings from the Texas Express NGL system are presented in “Equity investment in joint ventures” on our consolidated statements of financial position and “Equity in earnings of joint ventures” on our consolidated statements of income, respectively. For the three months 2016 2015 (in millions) Operating revenues $ 32.2 $ 28.8 Operating expenses $ 12.0 $ 11.0 Net income $ 20.1 $ 17.7

DEBT

DEBT	3 Months Ended
	Mar. 31, 2016
Debt Disclosure [Abstract]
DEBT	9. DEBT Interest Rate March 31, December 31, (in millions) Credit Agreement due 2018 2.691% $ 440.0 $ 490.0 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 principal amount of debt obligations 840.0 890.0 Unamortized debt issuance costs (1.7 ) (1.8 ) Total $ 838.3 $ 888.2 On January 1, 2016, we adopted Accounting Standards Update No. 2015-03, which requires us to present debt issuance costs in the balance sheet as a reduction to the carrying amount of the debt liability, rather than as an asset. We have retrospectively adopted this guidance for all periods presented. The adoption of this guidance did not have a material impact on our consolidated financial statements. For the three months 2016 2015 (in millions) Interest cost incurred $ 8.4 $ 7.6 Less: Interest capitalized 0.1 0.9 Interest expense, net $ 8.3 $ 6.7 Debt Arrangements Credit Agreement We, Midcoast Operating, and our material domestic subsidiaries are parties to the Credit Agreement, which permits aggregate borrowings of up to $810.0 million at any one time outstanding. The original term of the Credit Agreement was three years, with an initial maturity date of November 13, 2016, subject to four one-year requests for extension. Our Credit Agreement’s current maturity date is September 30, 2018; however, $140.0 million of commitments expire on the initial maturity date of November 13, 2016 and an additional $25.0 million of commitments expire on September 30, 2017. During the three months ended March 31, 2016, we had net repayments of approximately $50.0 million, which includes gross borrowings of $1,585.0 million and gross repayments of $1,635.0 million. Debt Covenants At March 31, 2016, we were in compliance with the terms of our financial covenants under our debt agreements. Available Credit (in millions) Total credit limit under Credit Agreement $ 810.0 Amounts outstanding under Credit Agreement (440.0 ) Total amount available at March 31, 2016 $ 370.0 Fair Value of Debt Obligations The carrying amount of our outstanding borrowings under the Credit Agreement approximates the fair value at March 31, 2016 and December 31, 2015, 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 $372.5 million at March 31, 2016. We determined the approximate fair values using a standard methodology that incorporates pricing points that are obtained from independent, third-party investment dealers who actively make markets in our debt securities. We use these pricing points to calculate the present value of the principal obligation to be repaid at maturity and all future interest payment obligations for any debt outstanding. The fair value of our long-term debt obligations is categorized as Level 2 within the fair value hierarchy.

PARTNERS' CAPITAL

PARTNERS' CAPITAL	3 Months Ended
	Mar. 31, 2016
Partners' Capital Notes [Abstract]
PARTNERS’ CAPITAL	10. PARTNERS’ CAPITAL Distribution to Partners Distribution Record Date Distribution Distribution Cash Distributed (in millions, except per unit amounts) January 28, 2016 February 5, 2016 February 12, 2016 $0.35750 $16.5 Cash distributed to partners is reflected in “Distributions to partners,” on our consolidated statements of cash flows. We paid cash distributions to EEP for its ownership interest in us totaling $8.9 million and $8.5 million for the three months ended March 31, 2016 and 2015, respectively. Distributions to Noncontrolling Interests Midcoast Operating paid cash distributions to EEP for its ownership interest in Midcoast Operating totaling $25.9 million and $19.8 million for the three months ended March 31, 2016 and 2015, respectively. These amounts are reflected in “Distributions to noncontrolling interest” in our consolidated statements of cash flows. During any quarter until the quarter ending December 31, 2017, if our quarterly declared distribution exceeds our distributable cash, as that term is defined in Midcoast Operating’s limited partnership agreement, we receive an increased quarterly distribution from Midcoast Operating, and EEP receives a corresponding reduction to its quarterly distribution in the amount that our declared distribution exceeds our distributable cash. 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 per unit quarterly distribution increase by us. There is no requirement for us to compensate EEP for these adjusted distributions, except for settling our capital accounts with Midcoast Operating in a liquidation scenario. For the three months ended March 31, 2016, EEP’s quarterly distribution from Midcoast Operating was reduced by $0.8 million. Changes in Partners’ Capital 2016 2015 (in millions) Class A common units: Beginning balance $ 522.2 $ 634.2 Net loss (9.9 ) (9.8 ) Distributions (8.1 ) (7.7 ) Ending balance $ 504.2 $ 616.7 Subordinated units: Beginning balance $ 1,062.0 $ 1,174.0 Net loss (9.9 ) (9.8 ) Distributions (8.1 ) (7.7 ) Ending balance $ 1,044.0 $ 1,156.5 General Partner units: Beginning balance $ 43.3 $ 47.8 Net loss (0.4 ) (0.4 ) Contributions 9.5 — Distributions (0.3 ) (0.4 ) Ending balance $ 52.1 $ 47.0 Accumulated other comprehensive income (loss) Beginning balance $ (0.9 ) $ 11.6 Changes in fair value of derivative financial instruments reclassified to earnings — (4.3 ) Changes in fair value of derivative financial instruments recognized in other — 2.8 Ending balance $ (0.9 ) $ 10.1 Noncontrolling interest Beginning balance $ 2,405.7 $ 2,529.0 Capital contributions 9.2 68.2 Comprehensive income: Net loss (10.1 ) (10.1 ) Other comprehensive loss, net of tax — (1.4 ) Distributions to noncontrolling interest (25.9 ) (19.8 ) Ending balance $ 2,378.9 $ 2,565.9 Total partners’ capital at end of period $ 3,978.3 $ 4,396.2 Securities Authorized for Issuance under LTIP In August 2014, we filed a registration statement on Form S-8 with the SEC registering the issuance of 3,750,000 Class A common units that are issuable pursuant to awards that may be granted under the LTIP. As of March 31, 2016, we had not granted any awards for, or that are convertible into, Class A common units under our LTIP.

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS	3 Months Ended
	Mar. 31, 2016
Related Party Transactions [Abstract]
RELATED PARTY TRANSACTIONS	11. RELATED PARTY TRANSACTIONS We do not directly employ any of the individuals responsible for managing or operating our business nor do we have any directors. Enbridge and its affiliates provide management, administrative, operational and workforce related services to us. Employees of Enbridge and its affiliates are assigned to work for one or more affiliates of Enbridge, including us. Where directly attributable, the costs of all compensation, benefits expenses and employer expenses for these employees are charged directly by Enbridge to the appropriate affiliate. Enbridge does not record any profit or margin for the administrative and operational services charged to us. The affiliate amounts incurred by us 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. Under the Intercorporate Services Agreement, we reimburse EEP and its affiliates for the costs and expenses incurred in providing us with such services. However, EEP has agreed to reduce the amounts payable for general and administrative expenses that otherwise would have been allocable to Midcoast Operating by $25.0 million annually. As a result, for each of the three months ended March 31, 2016 and 2015, we recognized $6.3 million as a reduction to “Due to general partner and affiliates” with the offset recorded as a contribution to “Noncontrolling interest” in our consolidated statements of financial position. Omnibus Agreement We, Midcoast Holdings, EEP, and Enbridge are parties to the Omnibus Agreement under which EEP agreed to, among other things, indemnify us for certain matters, including environmental, right-of-way and permit matters. EEP’s obligation to indemnify us for these matters is subject to a $500,000 aggregate deductible before we are entitled to indemnification. Additionally, there is a $15.0 million aggregate cap on the amounts for which EEP will indemnify us for under the Omnibus Agreement. For the three months ended March 31, 2016, we received indemnification proceeds from EEP under the Omnibus Agreement of $12.2 million for the acquisition of title to right-of-way assets that were pending at the time of our initial public offering and associated legal fees. Of this amount, $9.5 million was classified as a contribution from our General Partner in our consolidated statements of cash flows, and $2.7 million was classified as a reduction of legal expenses reflected in “General and administrative — affiliate” expense in our consolidated statements of income. 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 pipeline transportation and demand fees from the Texas Express NGL system of $5.4 million and $5.8 million for the three months ended March 31, 2016 and 2015, respectively. Our logistics and marketing business has made commitments to transport up to 120,000 barrels per day, or Bpd, of NGLs on the Texas Express NGL system through 2022. The current commitment level is 29,000 Bpd. Routine purchases and sales with affiliates are settled monthly through our centralized treasury function at terms that are consistent with third-party transactions for the three months ended March 31, 2016 and 2015. 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 For the three months ended March 31, 2016 and 2015, we sold and derecognized receivables of $435.3 million and $705.4 million, respectively, to an indirect, wholly-owned subsidiary of Enbridge. As a result, for the three months ended March 31, 2016 and 2015, we received cash proceeds of $435.1 million and $705.2 million, respectively. Consideration for the receivables sold is equivalent to the carrying value of the receivables less a discount for credit risk. The difference between the carrying value of the receivables sold and the cash proceeds received is recognized in “General and administrative — affiliate” expense in our consolidated statements of income. For each of the three months ended March 31, 2016 and 2015, the expense stemming from the discount on the receivables sold was $0.2 million. As of March 31, 2016 and December 31, 2015, we had $14.6 million and $14.6 million, respectively, in “Restricted cash” on our consolidated statements of financial position for cash collections related to sold and derecognized receivables that have yet to be remitted to the Enbridge subsidiary. As of March 31, 2016 and December 31, 2015, outstanding receivables of $107.1 million and $147.1 million, respectively, which had been sold and derecognized, had not been collected on behalf of the Enbridge subsidiary. Financial Support Agreement At March 31, 2016, EEP provided $4.9 million of letters of credit outstanding and $23.3 million of guarantees to Midcoast Operating under a Financial Support Agreement with Midcoast Operating. At December 31, 2015, EEP provided $7.5 million of letters of credit outstanding and $21.7 million in guarantees to Midcoast Operating under this agreement. 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% annual fee. Midcoast Operating incurred $0.1 million and $0.2 million of these costs for the three months ended March 31, 2016 and 2015, respectively, which are included in “Operating and maintenance — affiliate” on our consolidated statements of income.

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	3 Months Ended
	Mar. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENCIES	12. COMMITMENTS AND CONTINGENCIES Environmental Liabilities We are subject to federal and state laws and regulations relating to the protection of the environment. Environmental risk is inherent to our operating activities, 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 our operating activities. We continue to voluntarily monitor past leak sites on our systems for the purpose of assessing whether any remediation is required in light of current regulations. As of March 31, 2016 and December 31, 2015, we did not have any material accrued environmental liabilities. Legal and Regulatory Proceedings We are a participant in a number of legal proceedings arising in the ordinary course of business. Some of these proceedings are 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	3 Months Ended
	Mar. 31, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES	13. DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES Our net income and cash flows are subject to volatility stemming from fluctuations in commodity prices of natural gas, NGLs, condensate, crude oil 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 March 31, 2016 December 31, 2015 (in millions) Other current assets $ 96.5 $ 117.3 Other assets, net 26.2 39.2 Accounts payable and other (1) (30.4 ) (45.7 ) Other long-term liabilities (14.3 ) (18.3 ) $ 78.0 $ 92.5 (1) Includes $12.6 million of cash collateral at December 31, 2015. 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. March 31, 2016 December 31, 2015 (in millions) Counterparty Credit Quality (1) AAA $ 0.1 $ — AA (2) 61.6 67.6 A 15.1 24.1 Lower than A 1.2 0.8 $ 78.0 $ 92.5 (1) As determined by nationally-recognized statistical ratings organizations. (2) Includes $12.6 million of cash collateral at December 31, 2015. As the net value of our derivative financial instruments has decreased as a result of the settlement of maturing derivatives, 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. At March 31, 2016, we did not have any cash collateral on our asset exposures. At December 31, 2015, our short-term liabilities included $12.6 million relating to cash collateral on our asset exposures. Cash collateral is classified as “Restricted cash” in our consolidated statements of financial position. As of December 31, 2015, all of our cash collateral was held directly by EEP. We provided letters of credit totaling $4.9 million and $7.5 million relating to our liability exposures pursuant to the margin thresholds in effect at March 31, 2016 and December 31, 2015, respectively, under our ISDA® agreements. 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 ® 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 March 31, 2016, we would have been required to provide letters of credit in the amount of $10.5 million related to our open positions. March 31, 2016 December 31, 2015 (in millions) United States financial institutions and investment banking entities (1) $ 68.2 $ 80.8 Non-United States financial institutions (12.5 ) (12.3 ) Integrated oil companies (0.3 ) 0.6 Other 22.6 23.4 $ 78.0 $ 92.5 (1) Includes $12.6 million of cash collateral at December 31, 2015. 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. Asset Derivatives Liability Derivatives Fair Value at Fair Value at Financial Position Location March 31, 2016 December 31, 2015 March 31, 2016 December 31, 2015 (in millions) Derivatives not designated as hedging instruments: Commodity contracts Other current assets 96.5 117.3 — — Commodity contracts Other assets 26.2 39.2 — — Commodity contracts Accounts payable and other (1) — — (30.4 ) (33.1 ) Commodity contracts Other long-term liabilities — — (14.3 ) (18.3 ) 122.7 156.5 (44.7 ) (51.4 ) Total derivative instruments $ 122.7 $ 156.5 $ (44.7 ) $ (51.4 ) (1) Excludes $12.6 million of cash collateral at December 31, 2015. 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 March 31, 2016 and December 31, 2015, we included in AOCI unrecognized losses of approximately $0.4 million associated with derivative financial instruments that qualified for and were classified as cash flow hedges of forecasted transactions that were subsequently de-designated, settled, or terminated. These losses are reclassified to earnings over the periods during which the originally hedged forecasted transactions affect earnings. During the three months ended March 31, 2015, unrealized commodity hedge gains of $0.6 million were de-designated as a result of the hedges no longer meeting hedge accounting criteria. At March 31, 2016, we had no designated commodity hedges. We estimate that approximately $0.1 million, representing unrealized net gains from our cash flow hedging activities based on pricing and positions at March 31, 2016, will be reclassified from AOCI to earnings during the next 12 months. Derivatives in Cash Flow Amount of Gain Location of Gain Amount of Gain Location of Gain (Loss) (1) Amount of Gain (1) (in millions) For the three months ended March 31, 2016 Interest Rate contracts $ — Interest expense $ (0.1 ) Interest expense $ — Commodity contracts — Cost of natural gas and 0.1 Cost of natural gas and — $ — $ — $ — For the three months ended March 31, 2015 Commodity contracts $ (3.6 ) Cost of natural gas and natural gas liquids $ 8.4 Cost of natural gas and natural gas liquids $ (4.0 ) (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. Cash Flow Hedges 2016 2015 (in millions) Balance at January 1 $ (0.9 ) $ 11.6 Other comprehensive income (loss) before reclassifications (1) — 2.8 Amounts reclassified from AOCI (2) (3) — (4.3 ) Net other comprehensive income (loss) $ — $ (1.5 ) Balance at March 31 $ (0.9 ) $ 10.1 (1) Excludes NCI gain of $2.7 million reclassified from AOCI at March 31, 2015. (2) Excludes NCI loss of $4.1 million reclassified from AOCI at March 31, 2015. (3) For additional details on the amounts reclassified from AOCI, reference the Reclassifications from Accumulated Other Comprehensive Income For the three months 2016 2015 (in millions) Losses (gains) on cash flow hedges: Commodity Contracts (1) (2) $ — $ (4.3 ) Total Reclassifications from AOCI $ — $ (4.3 ) (1) Loss (gain) reported within “Cost of natural gas and natural gas liquids” in the consolidated statements of income. (2) Excludes NCI loss $4.1 million reclassified from AOCI for the three months ended March 31, 2015. For the three months 2016 2015 Derivatives Not Location of Gain or (Loss) Amount of Gain or (Loss) (1) (2) (in millions) Commodity contracts Operating revenue $ (2.4 ) $ (17.3 ) Commodity contracts Operating revenue – affiliate — (0.2 ) Commodity contracts Cost of natural gas and natural gas liquids (3) 1.8 12.1 Total $ (0.6 ) $ (5.4 ) (1) Does not include settlements associated with derivative instruments that settle through physical delivery. (2) Includes only net gains or losses associated with those derivatives that do not receive hedge accounting treatment and does not include the ineffective portion of derivatives that are designated as hedging instruments. (3) Includes settlement gains of $26.5 million and $25.7 million for the three months ended March 31, 2016 and 2015, respectively. We record the fair market value of our derivative financial and physical instruments in the consolidated statements of financial position as current and long-term assets or liabilities on a gross basis. However, the terms of the ISDA®, which govern our financial contracts and our other master netting agreements, allow the parties to elect in respect of all transactions under the agreement, in the event of a default and upon notice to the defaulting party, for the non-defaulting party to set-off all settlement payments, collateral held and any other obligations (whether or not then due), which the non-defaulting party owes to the defaulting party. The effect of the rights of set-off are outlined below. As of March 31, 2016 Gross Gross Amount Offset in the Statement of Financial Position Net Amount Gross Amount Net Amount (in millions) Description: Derivatives $ 122.7 $ — $ 122.7 $ (23.2 ) $ 99.5 As of December 31, 2015 Gross Gross Amount Offset in the Statement of Financial Position Net Amount Gross Amount (1) Net Amount (in millions) Description: Derivatives $ 156.5 $ — $ 156.5 $ (41.5 ) $ 115.0 (1) Includes $12.6 million of cash collateral at December 31, 2015. Gross Gross Amount Offset in the Statement of Financial Position Net Amount Gross Amount Net Amount (in millions) Description: Derivatives $ (44.7 ) $ — $ (44.7 ) $ 23.2 $ (21.5 ) As of December 31, 2015 Gross (1) Gross Amount Offset in the Statement of Financial Position Net Amount Gross Amount (1) Net Amount (in millions) Description: Derivatives $ (64.0 ) $ — $ (64.0 ) $ 41.5 $ (22.5 ) (1) Includes $12.6 million of cash collateral at December 31, 2015. Inputs to Fair Value Derivative Instruments December 31, 2015 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total (in millions) Commodity contracts: Financial $ — $ 0.6 $ 5.5 $ 6.1 $ — $ 1.3 $ 8.9 $ 10.2 Physical — — 0.9 0.9 — — 0.6 0.6 Commodity options — — 71.0 71.0 — — 94.3 94.3 $ — $ 0.6 $ 77.4 $ 78.0 $ — $ 1.3 $ 103.8 $ 105.1 Cash collateral — (12.6 ) Total $ 78.0 $ 92.5 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 measure the fair value of our Level 3 derivative instruments on a recurring basis. We may also use these inputs with internally developed methodologies that result in our best estimate of fair value. The inputs listed in the table below would have a direct impact on the fair values of the listed instruments. The significant unobservable inputs used in the fair value measurement of the commodity derivatives (natural gas, NGLs, crude and power) are forward commodity prices. The significant unobservable inputs used in determining the fair value measurement of options are price and volatility. Forward commodity price in isolation has a direct relationship to the fair value of a commodity contract in a long position and an inverse relationship to a commodity contract in a short position. Volatility has a direct relationship to the fair value of an option contract. 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 has an inverse relationship to the fair value of our derivative contracts. Contract Type Fair Value at March 31, 2016 (2) Valuation Unobservable Range (1) Units Lowest Highest Weighted (in millions) Commodity Contracts – Financial Natural Gas $ 0.6 Market Approach Forward Gas Price 1.80 3.27 2.69 MMBtu NGLs 4.9 Market Approach Forward NGL Price 0.17 0.92 0.42 Gal Commodity Contracts – Physical Natural Gas (1.8 ) Market Approach Forward Gas Price 1.53 3.27 2.01 MMBtu Crude Oil 0.3 Market Approach Forward Crude Price 28.29 40.90 38.91 Bbl NGLs 2.4 Market Approach Forward NGL Price 0.17 0.92 0.41 Gal Commodity Options Natural Gas, Crude and NGLs 71.0 Option Model Option Volatility 8 % 100 % 37 % Total Fair Value $ 77.4 (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) Fair values include credit valuation adjustment losses of approximately $0.2 million. Quantitative Information About Level 3 Fair Value Measurements Contract Type Fair Value at December 31, (2) Valuation Unobservable Range (1) Units Lowest Highest Weighted Average (in millions) Commodity Contracts – Financial Natural Gas $ 0.3 Market Approach Forward Natural Gas 2.27 3.07 2.64 MMBtu NGLs 8.6 Market Approach Forward NGL Price 0.16 0.93 0.41 Gal Commodity Contracts – Physical Natural Gas (2.5 ) Market Approach Forward Natural Gas 2.08 3.44 2.33 MMBtu Crude Oil — Market Approach Forward Crude Oil Price 26.50 38.41 37.29 Bbl NGLs 3.1 Market Approach Forward NGL Price 0.16 1.20 0.40 Gal Commodity Options Natural Gas, Crude and NGLs 94.3 Option Model Option Volatility 13 % 74 % 36 % Total Fair Value $ 103.8 (1) Prices are in dollars per MMBtu for natural gas, dollars per gallon, or Gal, for NGLs, and Bbl for crude oil. (2) Fair values include credit valuation adjustment losses of approximately $0.3 million. Level 3 Fair Value Reconciliation Commodity Financial Contracts Commodity Physical Contracts Commodity Options Total (in millions) Beginning balance as of January 1, 2016 $ 8.9 $ 0.6 $ 94.3 $ 103.8 Transfer out of Level 3 (1) — — — — Gains or losses included in earnings: Reported in Operating revenue — (6.7 ) — (6.7 ) Reported in Cost of natural gas and natural gas liquids 0.4 8.5 (1.5 ) 7.4 Gains or losses included in other comprehensive income: Purchases, issuances, sales and settlements: Purchases — — — — Sales — — — — Settlements (2) (3.8 ) (1.5 ) (21.8 ) (27.1 ) Ending balance as of March 31, 2016 $ 5.5 $ 0.9 $ 71.0 $ 77.4 Amounts reported in Operating revenue $ — $ (2.4 ) $ — $ (2.4 ) Amount of changes in net assets attributable to the change in unrealized gains or losses related to assets and liabilities still held at the reporting date: Reported in Operating revenue $ — $ (2.7 ) $ — $ (2.7 ) Reported in Cost of natural gas and natural gas $ 0.4 $ 4.8 $ (2.5 ) $ 2.7 (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 At March 31, 2016 At December 31, 2015 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 2016 Swaps Receive variable/pay fixed Natural Gas 16,287 $ 2.43 $ 3.48 $ — $ — $ — $ — NGL 1,570,750 $ 23.30 $ 25.39 $ 1.8 $ (5.1 ) $ 0.2 $ (8.4 ) Crude Oil 464,000 $ 40.65 $ 65.19 $ 0.1 $ (11.5 ) $ — $ (17.5 ) Receive fixed/pay variable NGL 1,894,000 $ 27.74 $ 22.68 $ 11.0 $ (1.4 ) $ 18.3 $ (0.2 ) Crude Oil 494,000 $ 64.02 $ 40.51 $ 12.2 $ (0.6 ) $ 18.2 $ — Receive variable/pay variable Natural Gas 7,355,000 $ 2.47 $ 2.47 $ 0.2 $ (0.2 ) $ 0.1 $ (0.1 ) Physical Contracts Receive variable/pay fixed NGL 890,000 $ 17.94 $ 16.02 $ 1.8 $ (0.1 ) $ — $ (0.2 ) Crude Oil — $ — $ — $ — $ — $ — $ (0.2 ) Receive fixed/pay variable NGL 869,166 $ 22.46 $ 24.95 $ 0.1 $ (2.3 ) $ 1.9 $ (0.2 ) Receive variable/pay variable Natural Gas 118,233,634 $ 1.94 $ 1.96 $ — $ (2.1 ) $ — $ (2.8 ) NGL 8,400,616 $ 16.85 $ 16.51 $ 3.7 $ (0.8 ) $ 4.0 $ (2.4 ) Crude Oil 681,040 $ 38.84 $ 38.38 $ 0.7 $ (0.4 ) $ 0.7 $ (0.5 ) Portion of contracts maturing in 2017 Swaps Receive variable/pay fixed Natural Gas 76,530 $ 2.49 $ 2.97 $ — $ — $ — $ — NGL 757,500 $ 16.63 $ 21.05 $ 0.1 $ (3.5 ) $ — $ (4.5 ) Crude Oil 547,500 $ 44.92 $ 66.72 $ — $ (11.8 ) $ — $ (10.9 ) Receive fixed/pay variable NGL 757,500 $ 19.19 $ 16.63 $ 2.2 $ (0.3 ) $ 3.3 $ (0.1 ) Crude Oil 638,750 $ 63.63 $ 44.92 $ 11.9 $ — $ 10.9 $ — Receive variable/pay variable Natural Gas 12,550,000 $ 2.75 $ 2.70 $ 0.8 $ (0.2 ) $ 0.5 $ (0.2 ) Physical Contracts Receive fixed/pay variable NGL 595 $ 22.37 $ 21.17 $ — $ — $ — $ — Receive variable/pay variable Natural Gas 3,987,810 $ 2.78 $ 2.75 $ 0.1 $ — $ 0.1 $ — NGL 186,500 $ 23.33 $ 23.40 $ — $ — $ — $ — Portion of contracts maturing in 2018 Physical Contracts Receive variable/pay variable Natural Gas 2,187,810 $ 2.92 $ 2.89 $ 0.1 $ — $ 0.1 $ — Portion of contracts maturing in 2019 Physical Contracts Receive variable/pay variable Natural Gas 2,187,810 $ 3.00 $ 2.97 $ 0.1 $ — $ 0.1 $ — Portion of contracts maturing in 2020 Physical Contracts Receive variable/pay variable Natural Gas 359,640 $ 3.29 $ 3.26 $ — $ — $ — $ — (1) Volumes of natural gas are measured in MMBtu, whereas volumes of NGL and crude oil are measured in Bbl. (2) Weighted-average prices received and paid are in $/MMBtu for natural gas and $/Bbl for NGL and crude oil. (3) The fair value is determined based on quoted market prices at March 31, 2016, and December 31, 2015, respectively, discounted using the swap rate for the respective periods to consider the time value of money. Fair values exclude credit valuation adjustment gains of approximately $0.4 million and $0.6 million at March 31, 2016 and December 31, 2015, respectively, as well as cash collateral received. At March 31, 2016 At December 31, 2015 Commodity Notional (1) Strike Price (2) Market Price (2) Fair Value (3) Fair Value (3) Asset Liability Asset Liability (in millions) Portion of option contracts maturing in 2016 Puts (purchased) Natural Gas 1,237,500 $ 3.75 $ 2.22 $ 1.9 $ — $ 2.1 $ — NGL 2,227,500 $ 39.29 $ 22.66 $ 37.6 $ — $ 54.4 $ — Crude Oil 605,000 $ 75.91 $ 41.68 $ 20.7 $ — $ 27.7 $ — Calls (written) Natural Gas 1,237,500 $ 4.98 $ 2.22 $ — $ — $ — $ — NGL 2,227,500 $ 45.09 $ 22.66 $ — $ (0.4 ) $ — $ (0.3 ) Crude Oil 605,000 $ 86.68 $ 41.68 $ — $ — $ — $ — Puts (written) Natural Gas 1,237,500 $ 3.75 $ 2.22 $ — $ (1.9 ) $ — $ (2.1 ) NGL 68,750 $ 39.06 $ 23.25 $ — $ (1.1 ) $ — $ (1.5 ) Calls (purchased) Natural Gas 1,237,500 $ 4.98 $ 2.22 $ — $ — $ — $ — NGL 68,750 $ 46.41 $ 23.25 $ — $ — $ — $ — Portion of option contracts maturing in 2017 Puts (purchased) NGL 1,277,500 $ 25.26 $ 23.44 $ 5.1 $ — $ 5.8 $ — Crude Oil 638,750 $ 59.86 $ 44.92 $ 11.1 $ — $ 10.0 $ — Calls (written) NGL 1,277,500 $ 29.46 $ 23.44 $ — $ (0.8 ) $ — $ (0.8 ) Crude Oil 638,750 $ 68.19 $ 44.92 $ — $ (0.9 ) $ — $ (0.6 ) Portion of option contracts maturing in 2018 Puts (purchased) Crude Oil 91,250 $ 42.00 $ 47.03 $ 0.5 $ — $ — $ — Calls (written) Crude Oil 91,250 $ 51.75 $ 47.03 $ — $ (0.5 ) $ — $ — (1) Volumes of natural gas are measured in MMBtu, whereas volumes of NGL and crude oil are measured in Bbl. (2) Strike and market prices are in $/MMBtu for natural gas and in $/Bbl for NGL and crude oil. (3) The fair value is determined based on quoted market prices at March 31, 2016, and December 31, 2015, respectively, discounted using the swap rate for the respective periods to consider the time value of money. Fair values exclude credit valuation adjustment losses of approximately $0.3 million and $0.4 million at March 31, 2016 and December 31, 2015, respectively, as well as cash collateral received.

INCOME TAXES

INCOME TAXES	3 Months Ended
	Mar. 31, 2016
Income Tax Disclosure [Abstract]
INCOME TAXES	14. INCOME TAXES We are not a taxable entity for United States federal income tax purposes or for the majority of states that impose an income tax. Taxes on our net income generally are borne by our unitholders through the allocation of taxable income. Our income tax expense results from the enactment of 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 0.5% and 0.6% for the three months ended March 31, 2016 and 2015, respectively. At March 31, 2016 and December 31, 2015, we included a current income tax payable of $2.7 million and $1.1 million, respectively, in “Property and other taxes payable” on our consolidated statements of financial position. In addition, at March 31, 2016 and December 31, 2015, we included a deferred income tax payable of $14.5 million and $14.3 million, respectively, in “Other long-term liabilities” on our consolidated statements of financial position to reflect the tax associated with the difference between the net basis in assets and liabilities for financial and state tax reporting.

SEGMENT INFORMATION

SEGMENT INFORMATION	3 Months Ended
	Mar. 31, 2016
Segment Reporting [Abstract]
SEGMENT INFORMATION	15. SEGMENT INFORMATION Our business is divided into operating segments, defined as components of the enterprise, about which financial information is available and evaluated regularly by our Chief Operating Decision Maker, collectively comprised of our senior management, in deciding how resources are allocated and performance is assessed. Each of our reportable segments is a business unit that offers different services and products that are managed separately, since each business segment requires different operating strategies. We conduct our business through two distinct reporting segments: • Gathering, Processing and Transportation; and • Logistics and Marketing. The following tables present certain financial information relating to our business segments and corporate activities: Gathering, Processing and Transportation Logistics and Marketing Corporate (1) Total (in millions) Total revenue $ 243.1 $ 248.8 $ — $ 491.9 Less: Intersegment revenue 54.5 5.5 — 60.0 Operating revenue 188.6 243.3 — 431.9 Cost of natural gas and natural gas liquids 118.5 229.5 — 348.0 Segment gross margin 70.1 13.8 — 83.9 Operating and maintenance 46.7 10.4 0.1 57.2 General and administrative 13.0 1.5 1.1 15.6 Depreciation and amortization 37.7 1.8 — 39.5 97.4 13.7 1.2 112.3 Operating income (loss) (27.3 ) 0.1 (1.2 ) (28.4 ) Other income 7.1 (2) — 0.2 7.3 Interest expense, net — — (8.3 ) (8.3 ) Income (loss) before income tax expense (20.2 ) 0.1 (9.3 ) (29.4 ) Income tax expense — — (0.9 ) (0.9 ) Net income (loss) (20.2 ) 0.1 (10.2 ) (30.3 ) Less: Net loss attributable to noncontrolling interest — — (10.1 ) (10.1 ) Net income (loss) attributable to general and $ (20.2 ) $ 0.1 $ (0.1 ) $ (20.2 ) Total assets $ 4,897.8 (3) $ 130.9 $ 113.9 $ 5,142.6 Capital expenditures (excluding acquisitions) $ 15.9 $ 2.7 $ (0.9 ) $ 17.7 (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 $368.0 million for our equity investment in the Texas Express NGL system. As of and for the three months ended March 31, 2015 Gathering, Processing and Transportation Logistics and Marketing Corporate (1) Total (in millions) Total revenue $ 385.4 $ 765.3 $ — $ 1,150.7 Less: Intersegment revenue 267.3 9.9 — 277.2 Operating revenue 118.1 755.4 — 873.5 Cost of natural gas and natural gas liquids 21.9 757.2 — 779.1 Segment gross margin 96.2 (1.8 ) — 94.4 Operating and maintenance 50.8 12.6 — 63.4 General and administrative 16.3 3.0 1.7 21.0 Depreciation and amortization 36.7 1.6 — 38.3 103.8 17.2 1.7 122.7 Operating loss (7.6 ) (19.0 ) (1.7 ) (28.3 ) Other income 5.7 (2) — — 5.7 Interest expense, net — — (6.7 ) (6.7 ) Loss before income tax expense (1.9 ) (19.0 ) (8.4 ) (29.3 ) Income tax expense — — (0.8 ) (0.8 ) Net loss (1.9 ) (19.0 ) (9.2 ) (30.1 ) Less: Net loss attributable to noncontrolling interest — — (10.1 ) (10.1 ) Net income (loss) attributable to general and limited partner ownership interests in Midcoast Energy Partners, L.P. $ (1.9 ) $ (19.0 ) $ 0.9 $ (20.0 ) Total assets $ 5,226.2 (3) $ 236.9 $ 116.5 $ 5,579.6 Capital expenditures (excluding acquisitions) $ 54.8 $ 0.7 $ 0.1 $ 55.6 (1) Corporate consists of interest expense, interest income, noncontrolling interest and other costs such as income taxes, which are not allocated to the business segments. (2) Other income for our Gathering, Processing and Transportation segment includes our equity investment in the Texas Express NGL system. (3) Totals assets for our Gathering, Processing and Transportation segment includes $380.1 million for our equity investment in the Texas Express NGL system.

SUPPLEMENTAL CASH FLOW INFORMAT

SUPPLEMENTAL CASH FLOW INFORMATION	3 Months Ended
	Mar. 31, 2016
Supplemental Cash Flow Information [Abstract]
SUPPLEMENTAL CASH FLOWS INFORMATION	16. SUPPLEMENTAL CASH FLOW INFORMATION In the “Cash used in investing activities” section of the consolidated statements of cash flows, we exclude changes that did not affect cash. For the three months 2016 2015 (in millions) Additions to property, plant and equipment $ 16.3 $ 56.1 Increase (decrease) in construction payables 1.4 (0.5 ) Total capital expenditures $ 17.7 $ 55.6

RECENT ACCOUNTING PRONOUNCEMENT

RECENT ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED	3 Months Ended
	Mar. 31, 2016
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
RECENT ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED	17. RECENT ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED Revenues from Contracts with Customers In May 2014, the FASB issued Accounting Standards Update No. 2014-09, 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 on or after December 15, 2017, and may be applied on either a full or modified retrospective basis. We are in the early stages of reviewing our revenue contracts and are unable to estimate the impacts that this pronouncement will have on our consolidated financial statements at this time. We are also currently evaluating which transition approach we will apply. Leases In February 2016, the FASB issued Accounting Standards Update No. 2016-02, which requires lessees to recognize a right-of-use asset and a lease liability on the balance sheet for practically all leases (other than leases that are less than 12 months). The pronouncement continues to require lessees to distinguish between operating and financing, formerly known as capital leases, and lessors to distinguish between sales-type, direct financing, and operating leases for income statement purposes. This accounting update is effective for annual periods, and for interim periods within those annual periods, beginning after December 15, 2018. Early adoption is permitted, and entities are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach with certain optional practical expedients. We are currently evaluating the impact that this pronouncement will have on our consolidated financial statements.

SUBSEQUENT EVENTS

SUBSEQUENT EVENTS	3 Months Ended
	Mar. 31, 2016
Subsequent Events [Abstract]
SUBSEQUENT EVENTS	18. SUBSEQUENT EVENTS Distribution to Partners On April 28, 2016, the board of directors of Midcoast Holdings, our General Partner, declared a cash distribution payable to our unitholders on May 13, 2016. The distribution will be paid to unitholders of record as of May 6, 2016, of our available cash of $16.5 million at March 31, 2016, or $0.3575 per limited partner unit. We will pay $7.6 million to our public Class A common unitholders, while $8.9 million in the aggregate will be paid to EEP with respect to its Class A common units and subordinated units and Midcoast Holdings, L.L.C., with respect to its general partner interest. Midcoast Operating Distribution On April 28, 2016, the general partner of Midcoast Operating declared a cash distribution by Midcoast Operating payable on May 13, 2016 to its partners of record as of May 6, 2016. Midcoast Operating will pay $26.0 million to us and $22.9 million to EEP.

NET INCOME PER LIMITED PARTNE25

NET INCOME PER LIMITED PARTNER AND GENERAL PARTNER INTEREST (Tables)	3 Months Ended
	Mar. 31, 2016
Earnings Per Share [Abstract]
Schedule of Formula for Distributing Available Cash	Distribution Targets Portion of Quarterly Percentage Distributed Percentage Distributed Minimum Quarterly Distribution Up to $0.3125 98% 2% First Target Distribution > $0.3125 to $0.359375 98% 2% Second Target Distribution > $0.359375 to $0.390625 85% 15% Third Target Distribution > $0.390625 to $0.468750 75% 25% Over Third Target Distribution In excess of $0.468750 50% 50%
Basic and Diluted Net Income Per Limited Partner Unit	We determined basic and diluted net loss per limited partner unit as follows: For the three months 2016 2015 (in millions, except per unit amounts) Net loss $ (30.3 ) $ (30.1 ) Less: Net loss attributable to noncontrolling interest (10.1 ) (10.1 ) Net loss attributable to general and limited partner interests in Midcoast Energy Partners, L.P. (20.2 ) (20.0 ) Less distributions: Total distributed earnings to our General Partner (0.3 ) (0.3 ) Total distributed earnings to our limited partners (16.2 ) (15.7 ) Total distributed earnings (16.5 ) (16.0 ) Overdistributed earnings $ (36.7 ) $ (36.0 ) Weighted-average limited partner units outstanding 45.2 45.2 Basic and diluted earnings per unit: Distributed earnings per limited partner unit (1) $ 0.36 $ 0.35 Overdistributed earnings per limited partner unit (2) (0.80 ) (0.78 ) Net loss per limited partner unit (basic and diluted) $ (0.44 ) $ (0.43 ) (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.

CASH AND CASH EQUIVALENTS (Tabl

CASH AND CASH EQUIVALENTS (Tables)	3 Months Ended
	Mar. 31, 2016
Cash and Cash Equivalents [Abstract]
Schedule of Restricted Cash	Restricted cash is comprised of the following: March 31, 2016 December 31, 2015 (in millions) Cash collateral on behalf of Enbridge subsidiary for accounts receivable sales and not remitted (see Note 11) $ 14.6 $ 14.6 Cash held in escrow for acquisitions (see Note 3) — 6.0 $ 14.6 $ 20.6

INVENTORY (Tables)

INVENTORY (Tables)	3 Months Ended
	Mar. 31, 2016
Inventory Disclosure [Abstract]
Schedule of Inventory	Our inventory is comprised of the following: March 31, 2016 December 31, 2015 (in millions) Materials and supplies $ 0.6 $ 0.6 Natural gas and NGL inventory 13.1 31.3 $ 13.7 $ 31.9

PROPERTY, PLANT AND EQUIPMENT (

PROPERTY, PLANT AND EQUIPMENT (Tables)	3 Months Ended
	Mar. 31, 2016
Property, Plant and Equipment [Abstract]
Schedule of Property, Plant and Equipment	Our property, plant and equipment is comprised of the following: Depreciation Rates March 31, 2016 December 31, 2015 (in millions) Land — $ 14.5 $ 14.2 Rights-of-way 2.08% – 7.14% 465.5 460.3 Pipelines 1.89% – 6.7% 1,869.1 1,864.4 Pumping equipment, buildings and tanks 1.48% – 6.67% 88.4 88.4 Compressors, meters and other operating equipment 1.8% – 20.0% 2,160.2 2,147.6 Vehicles, office furniture and equipment 2.19% – 33.33% 136.2 137.1 Processing and treating plants 2.21% – 4.0% 629.2 627.8 Construction in progress 47.3 57.1 Total property, plant and equipment 5,410.4 5,396.9 Accumulated depreciation (1,202.9 ) (1,170.6 ) Property, plant and equipment, net $ 4,207.5 $ 4,226.3

VARIABLE INTEREST ENTITIES (Tab

VARIABLE INTEREST ENTITIES (Tables)	3 Months Ended
	Mar. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Schedule of Variable Interest Entities	March 31, 2016 December 31, 2015 (unaudited; in millions) ASSETS Cash and cash equivalents $ 3.6 $ 3.4 Restricted cash $ — $ 6.0 Receivables, trade and other, net $ 10.4 $ 13.3 Due from General Partner and affiliates $ 4.1 $ 46.9 Accrued receivables $ 24.0 $ 56.1 Inventory $ 13.7 $ 31.9 Other current assets $ 100.2 $ 118.5 Property, plant and equipment, net $ 4,207.5 $ 4,226.3 Intangible assets, net $ 267.5 $ 272.9 Equity investment in joint ventures $ 368.0 $ 372.3 Other assets, net $ 80.0 $ 93.9 LIABILITIES Due to General Partner and affiliates $ 38.4 $ 28.5 Accounts payable and other $ 53.5 $ 87.1 Accrued purchases $ 109.1 $ 143.8 Property and other taxes payable $ 10.8 $ 18.4 Other long-term liabilities $ 39.6 $ 45.9

EQUITY INVESTMENTS IN JOINT V30

EQUITY INVESTMENTS IN JOINT VENTURES (Tables)	3 Months Ended
	Mar. 31, 2016
Equity Method Investments and Joint Ventures [Abstract]
Schedule of Information of Joint Venture	The following table presents unaudited income statement information for the Texas Express NGL system on a combined, 100% basis for the periods presented: For the three months 2016 2015 (in millions) Operating revenues $ 32.2 $ 28.8 Operating expenses $ 12.0 $ 11.0 Net income $ 20.1 $ 17.7

DEBT (Tables)

DEBT (Tables)	3 Months Ended
	Mar. 31, 2016
Debt Disclosure [Abstract]
Schedule of Debt Obligations	Interest Rate March 31, December 31, (in millions) Credit Agreement due 2018 2.691% $ 440.0 $ 490.0 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 principal amount of debt obligations 840.0 890.0 Unamortized debt issuance costs (1.7 ) (1.8 ) Total $ 838.3 $ 888.2
Schedule of Interest Cost	For the three months 2016 2015 (in millions) Interest cost incurred $ 8.4 $ 7.6 Less: Interest capitalized 0.1 0.9 Interest expense, net $ 8.3 $ 6.7
Schedule of Line of Credit Facilities	(in millions) Total credit limit under Credit Agreement $ 810.0 Amounts outstanding under Credit Agreement (440.0 ) Total amount available at March 31, 2016 $ 370.0

PARTNERS' CAPITAL (Tables)

PARTNERS' CAPITAL (Tables)	3 Months Ended
	Mar. 31, 2016
Partners' Capital Notes [Abstract]
Schedule of Distributions	The following table sets forth our distributions, as approved by the board of directors of our General Partner, during the three months ended March 31, 2016. Distribution Record Date Distribution Distribution Cash Distributed (in millions, except per unit amounts) January 28, 2016 February 5, 2016 February 12, 2016 $0.35750 $16.5
Schedule of Changes in Partners' Capital	The following table presents significant changes in partners’ capital accounts attributable to our General Partner and limited partners as well as the noncontrolling interest in our consolidated subsidiary during the three months ended March 31, 2016 and 2015. 2016 2015 (in millions) Class A common units: Beginning balance $ 522.2 $ 634.2 Net loss (9.9 ) (9.8 ) Distributions (8.1 ) (7.7 ) Ending balance $ 504.2 $ 616.7 Subordinated units: Beginning balance $ 1,062.0 $ 1,174.0 Net loss (9.9 ) (9.8 ) Distributions (8.1 ) (7.7 ) Ending balance $ 1,044.0 $ 1,156.5 General Partner units: Beginning balance $ 43.3 $ 47.8 Net loss (0.4 ) (0.4 ) Contributions 9.5 — Distributions (0.3 ) (0.4 ) Ending balance $ 52.1 $ 47.0 Accumulated other comprehensive income (loss) Beginning balance $ (0.9 ) $ 11.6 Changes in fair value of derivative financial instruments reclassified to earnings — (4.3 ) Changes in fair value of derivative financial instruments recognized in other — 2.8 Ending balance $ (0.9 ) $ 10.1 Noncontrolling interest Beginning balance $ 2,405.7 $ 2,529.0 Capital contributions 9.2 68.2 Comprehensive income: Net loss (10.1 ) (10.1 ) Other comprehensive loss, net of tax — (1.4 ) Distributions to noncontrolling interest (25.9 ) (19.8 ) Ending balance $ 2,378.9 $ 2,565.9 Total partners’ capital at end of period $ 3,978.3 $ 4,396.2

DERIVATIVE FINANCIAL INSTRUME33

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Tables)	3 Months Ended
	Mar. 31, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value	Our derivative financial instruments are included at their fair values in the consolidated statements of financial position as follows: March 31, 2016 December 31, 2015 (in millions) Other current assets $ 96.5 $ 117.3 Other assets, net 26.2 39.2 Accounts payable and other (1) (30.4 ) (45.7 ) Other long-term liabilities (14.3 ) (18.3 ) $ 78.0 $ 92.5 (1) Includes $12.6 million of cash collateral at December 31, 2015.
Schedule of Derivative Balances by Counter Party Credit Quality	The table below summarizes our derivative balances by counterparty credit quality (any negative amounts represent our net obligations to pay the counterparty). March 31, 2016 December 31, 2015 (in millions) Counterparty Credit Quality (1) AAA $ 0.1 $ — AA (2) 61.6 67.6 A 15.1 24.1 Lower than A 1.2 0.8 $ 78.0 $ 92.5 (1) As determined by nationally-recognized statistical ratings organizations. (2) Includes $12.6 million of cash collateral at December 31, 2015.
Schedule of Credit Concentrations in Industry Sectors	At March 31, 2016, and December 31, 2015, we had credit concentrations in the following industry sectors, as presented below: March 31, 2016 December 31, 2015 (in millions) United States financial institutions and investment banking entities (1) $ 68.2 $ 80.8 Non-United States financial institutions (12.5 ) (12.3 ) Integrated oil companies (0.3 ) 0.6 Other 22.6 23.4 $ 78.0 $ 92.5 (1) Includes $12.6 million of cash collateral at December 31, 2015.
Effect of Derivative Instruments on the Consolidated Statements of Financial Position	Asset Derivatives Liability Derivatives Fair Value at Fair Value at Financial Position Location March 31, 2016 December 31, 2015 March 31, 2016 December 31, 2015 (in millions) Derivatives not designated as hedging instruments: Commodity contracts Other current assets 96.5 117.3 — — Commodity contracts Other assets 26.2 39.2 — — Commodity contracts Accounts payable and other (1) — — (30.4 ) (33.1 ) Commodity contracts Other long-term liabilities — — (14.3 ) (18.3 ) 122.7 156.5 (44.7 ) (51.4 ) Total derivative instruments $ 122.7 $ 156.5 $ (44.7 ) $ (51.4 ) (1) Excludes $12.6 million of cash collateral at December 31, 2015.
Effect of Derivative Instruments on the Consolidated Statements of Income and Accumulated Other Comprehensive Income	Effect of Derivative Instruments on the Consolidated Statements of Income and Accumulated Other Comprehensive Income Derivatives in Cash Flow Amount of Gain Location of Gain Amount of Gain Location of Gain (Loss) (1) Amount of Gain (1) (in millions) For the three months ended March 31, 2016 Interest Rate contracts $ — Interest expense $ (0.1 ) Interest expense $ — Commodity contracts — Cost of natural gas and 0.1 Cost of natural gas and — $ — $ — $ — For the three months ended March 31, 2015 Commodity contracts $ (3.6 ) Cost of natural gas and natural gas liquids $ 8.4 Cost of natural gas and natural gas liquids $ (4.0 ) (1) Includes only the ineffective portion of derivatives that are designated as hedging instruments and does not include net gains or losses associated with derivatives that do not qualify for hedge accounting treatment.
Components of Accumulated Other Comprehensive Income/(Loss)	Components of Accumulated Other Comprehensive Income/(Loss) Cash Flow Hedges 2016 2015 (in millions) Balance at January 1 $ (0.9 ) $ 11.6 Other comprehensive income (loss) before reclassifications (1) — 2.8 Amounts reclassified from AOCI (2) (3) — (4.3 ) Net other comprehensive income (loss) $ — $ (1.5 ) Balance at March 31 $ (0.9 ) $ 10.1 (1) Excludes NCI gain of $2.7 million reclassified from AOCI at March 31, 2015. (2) Excludes NCI loss of $4.1 million reclassified from AOCI at March 31, 2015. (3) For additional details on the amounts reclassified from AOCI, reference the Reclassifications from Accumulated Other Comprehensive Income
Reclassifications from Accumulated Other Comprehensive Income	Reclassifications from Accumulated Other Comprehensive Income For the three months 2016 2015 (in millions) Losses (gains) on cash flow hedges: Commodity Contracts (1) (2) $ — $ (4.3 ) Total Reclassifications from AOCI $ — $ (4.3 ) (1) Loss (gain) reported within “Cost of natural gas and natural gas liquids” in the consolidated statements of income. (2) Excludes NCI loss $4.1 million reclassified from AOCI for the three months ended March 31, 2015.
Effect of Derivative Instruments on Consolidated Statements of Income	Effect of Derivative Instruments on Consolidated Statements of Income For the three months 2016 2015 Derivatives Not Location of Gain or (Loss) Amount of Gain or (Loss) (1) (2) (in millions) Commodity contracts Operating revenue $ (2.4 ) $ (17.3 ) Commodity contracts Operating revenue – affiliate — (0.2 ) Commodity contracts Cost of natural gas and natural gas liquids (3) 1.8 12.1 Total $ (0.6 ) $ (5.4 ) (1) Does not include settlements associated with derivative instruments that settle through physical delivery. (2) Includes only net gains or losses associated with those derivatives that do not receive hedge accounting treatment and does not include the ineffective portion of derivatives that are designated as hedging instruments. (3) Includes settlement gains of $26.5 million and $25.7 million for the three months ended March 31, 2016 and 2015, respectively.
Offsetting of Financial Assets and Derivative Assets	Offsetting of Financial Assets and Derivative Assets As of March 31, 2016 Gross Gross Amount Offset in the Statement of Financial Position Net Amount Gross Amount Net Amount (in millions) Description: Derivatives $ 122.7 $ — $ 122.7 $ (23.2 ) $ 99.5 As of December 31, 2015 Gross Gross Amount Offset in the Statement of Financial Position Net Amount Gross Amount (1) Net Amount (in millions) Description: Derivatives $ 156.5 $ — $ 156.5 $ (41.5 ) $ 115.0 (1) Includes $12.6 million of cash collateral at December 31, 2015.
Offsetting of Financial Liabilities and Derivative Liabilities	Offsetting of Financial Liabilities and Derivative Liabilities Gross Gross Amount Offset in the Statement of Financial Position Net Amount Gross Amount Net Amount (in millions) Description: Derivatives $ (44.7 ) $ — $ (44.7 ) $ 23.2 $ (21.5 ) As of December 31, 2015 Gross (1) Gross Amount Offset in the Statement of Financial Position Net Amount Gross Amount (1) Net Amount (in millions) Description: Derivatives $ (64.0 ) $ — $ (64.0 ) $ 41.5 $ (22.5 ) (1) Includes $12.6 million of cash collateral at December 31, 2015.
Table Setting Forth by Level within the Fair Value Hierarchy Financial Assets and Liabilities	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 March 31, 2016, and December 31, 2015. 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. December 31, 2015 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total (in millions) Commodity contracts: Financial $ — $ 0.6 $ 5.5 $ 6.1 $ — $ 1.3 $ 8.9 $ 10.2 Physical — — 0.9 0.9 — — 0.6 0.6 Commodity options — — 71.0 71.0 — — 94.3 94.3 $ — $ 0.6 $ 77.4 $ 78.0 $ — $ 1.3 $ 103.8 $ 105.1 Cash collateral — (12.6 ) Total $ 78.0 $ 92.5
Schedule of Quantitative Information on Level 3 Fair Value Measurements	Quantitative Information About Level 3 Fair Value Measurements Contract Type Fair Value at March 31, 2016 (2) Valuation Unobservable Range (1) Units Lowest Highest Weighted (in millions) Commodity Contracts – Financial Natural Gas $ 0.6 Market Approach Forward Gas Price 1.80 3.27 2.69 MMBtu NGLs 4.9 Market Approach Forward NGL Price 0.17 0.92 0.42 Gal Commodity Contracts – Physical Natural Gas (1.8 ) Market Approach Forward Gas Price 1.53 3.27 2.01 MMBtu Crude Oil 0.3 Market Approach Forward Crude Price 28.29 40.90 38.91 Bbl NGLs 2.4 Market Approach Forward NGL Price 0.17 0.92 0.41 Gal Commodity Options Natural Gas, Crude and NGLs 71.0 Option Model Option Volatility 8 % 100 % 37 % Total Fair Value $ 77.4 (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) Fair values include credit valuation adjustment losses of approximately $0.2 million. Quantitative Information About Level 3 Fair Value Measurements Contract Type Fair Value at December 31, (2) Valuation Unobservable Range (1) Units Lowest Highest Weighted Average (in millions) Commodity Contracts – Financial Natural Gas $ 0.3 Market Approach Forward Natural Gas 2.27 3.07 2.64 MMBtu NGLs 8.6 Market Approach Forward NGL Price 0.16 0.93 0.41 Gal Commodity Contracts – Physical Natural Gas (2.5 ) Market Approach Forward Natural Gas 2.08 3.44 2.33 MMBtu Crude Oil — Market Approach Forward Crude Oil Price 26.50 38.41 37.29 Bbl NGLs 3.1 Market Approach Forward NGL Price 0.16 1.20 0.40 Gal Commodity Options Natural Gas, Crude and NGLs 94.3 Option Model Option Volatility 13 % 74 % 36 % Total Fair Value $ 103.8 (1) Prices are in dollars per MMBtu for natural gas, dollars per gallon, or Gal, for NGLs, and Bbl for crude oil. (2) Fair values include credit valuation adjustment losses of approximately $0.3 million.
Schedule of Reconciliation of Changes in Fair Value of Level 3 Financial Assets and Liabilities	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, 2016 to March 31, 2016. No transfers of assets between any of the Levels occurred during the period. Commodity Financial Contracts Commodity Physical Contracts Commodity Options Total (in millions) Beginning balance as of January 1, 2016 $ 8.9 $ 0.6 $ 94.3 $ 103.8 Transfer out of Level 3 (1) — — — — Gains or losses included in earnings: Reported in Operating revenue — (6.7 ) — (6.7 ) Reported in Cost of natural gas and natural gas liquids 0.4 8.5 (1.5 ) 7.4 Gains or losses included in other comprehensive income: Purchases, issuances, sales and settlements: Purchases — — — — Sales — — — — Settlements (2) (3.8 ) (1.5 ) (21.8 ) (27.1 ) Ending balance as of March 31, 2016 $ 5.5 $ 0.9 $ 71.0 $ 77.4 Amounts reported in Operating revenue $ — $ (2.4 ) $ — $ (2.4 ) Amount of changes in net assets attributable to the change in unrealized gains or losses related to assets and liabilities still held at the reporting date: Reported in Operating revenue $ — $ (2.7 ) $ — $ (2.7 ) Reported in Cost of natural gas and natural gas $ 0.4 $ 4.8 $ (2.5 ) $ 2.7 (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	The following table provides summarized information about the fair values of expected cash flows of our outstanding commodity based swaps and physical contracts at March 31, 2016 and December 31, 2015. At March 31, 2016 At December 31, 2015 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 2016 Swaps Receive variable/pay fixed Natural Gas 16,287 $ 2.43 $ 3.48 $ — $ — $ — $ — NGL 1,570,750 $ 23.30 $ 25.39 $ 1.8 $ (5.1 ) $ 0.2 $ (8.4 ) Crude Oil 464,000 $ 40.65 $ 65.19 $ 0.1 $ (11.5 ) $ — $ (17.5 ) Receive fixed/pay variable NGL 1,894,000 $ 27.74 $ 22.68 $ 11.0 $ (1.4 ) $ 18.3 $ (0.2 ) Crude Oil 494,000 $ 64.02 $ 40.51 $ 12.2 $ (0.6 ) $ 18.2 $ — Receive variable/pay variable Natural Gas 7,355,000 $ 2.47 $ 2.47 $ 0.2 $ (0.2 ) $ 0.1 $ (0.1 ) Physical Contracts Receive variable/pay fixed NGL 890,000 $ 17.94 $ 16.02 $ 1.8 $ (0.1 ) $ — $ (0.2 ) Crude Oil — $ — $ — $ — $ — $ — $ (0.2 ) Receive fixed/pay variable NGL 869,166 $ 22.46 $ 24.95 $ 0.1 $ (2.3 ) $ 1.9 $ (0.2 ) Receive variable/pay variable Natural Gas 118,233,634 $ 1.94 $ 1.96 $ — $ (2.1 ) $ — $ (2.8 ) NGL 8,400,616 $ 16.85 $ 16.51 $ 3.7 $ (0.8 ) $ 4.0 $ (2.4 ) Crude Oil 681,040 $ 38.84 $ 38.38 $ 0.7 $ (0.4 ) $ 0.7 $ (0.5 ) Portion of contracts maturing in 2017 Swaps Receive variable/pay fixed Natural Gas 76,530 $ 2.49 $ 2.97 $ — $ — $ — $ — NGL 757,500 $ 16.63 $ 21.05 $ 0.1 $ (3.5 ) $ — $ (4.5 ) Crude Oil 547,500 $ 44.92 $ 66.72 $ — $ (11.8 ) $ — $ (10.9 ) Receive fixed/pay variable NGL 757,500 $ 19.19 $ 16.63 $ 2.2 $ (0.3 ) $ 3.3 $ (0.1 ) Crude Oil 638,750 $ 63.63 $ 44.92 $ 11.9 $ — $ 10.9 $ — Receive variable/pay variable Natural Gas 12,550,000 $ 2.75 $ 2.70 $ 0.8 $ (0.2 ) $ 0.5 $ (0.2 ) Physical Contracts Receive fixed/pay variable NGL 595 $ 22.37 $ 21.17 $ — $ — $ — $ — Receive variable/pay variable Natural Gas 3,987,810 $ 2.78 $ 2.75 $ 0.1 $ — $ 0.1 $ — NGL 186,500 $ 23.33 $ 23.40 $ — $ — $ — $ — Portion of contracts maturing in 2018 Physical Contracts Receive variable/pay variable Natural Gas 2,187,810 $ 2.92 $ 2.89 $ 0.1 $ — $ 0.1 $ — Portion of contracts maturing in 2019 Physical Contracts Receive variable/pay variable Natural Gas 2,187,810 $ 3.00 $ 2.97 $ 0.1 $ — $ 0.1 $ — Portion of contracts maturing in 2020 Physical Contracts Receive variable/pay variable Natural Gas 359,640 $ 3.29 $ 3.26 $ — $ — $ — $ — (1) Volumes of natural gas are measured in MMBtu, whereas volumes of NGL and crude oil are measured in Bbl. (2) Weighted-average prices received and paid are in $/MMBtu for natural gas and $/Bbl for NGL and crude oil. (3) The fair value is determined based on quoted market prices at March 31, 2016, and December 31, 2015, respectively, discounted using the swap rate for the respective periods to consider the time value of money. Fair values exclude credit valuation adjustment gains of approximately $0.4 million and $0.6 million at March 31, 2016 and December 31, 2015, respectively, as well as cash collateral received.
Schedule of Fair Values of Expected Cash Flows of Outstanding Commodity Options	The following table provides summarized information about the fair value of expected cash flows of our outstanding commodity options at March 31, 2016 and December 31, 2015. At March 31, 2016 At December 31, 2015 Commodity Notional (1) Strike Price (2) Market Price (2) Fair Value (3) Fair Value (3) Asset Liability Asset Liability (in millions) Portion of option contracts maturing in 2016 Puts (purchased) Natural Gas 1,237,500 $ 3.75 $ 2.22 $ 1.9 $ — $ 2.1 $ — NGL 2,227,500 $ 39.29 $ 22.66 $ 37.6 $ — $ 54.4 $ — Crude Oil 605,000 $ 75.91 $ 41.68 $ 20.7 $ — $ 27.7 $ — Calls (written) Natural Gas 1,237,500 $ 4.98 $ 2.22 $ — $ — $ — $ — NGL 2,227,500 $ 45.09 $ 22.66 $ — $ (0.4 ) $ — $ (0.3 ) Crude Oil 605,000 $ 86.68 $ 41.68 $ — $ — $ — $ — Puts (written) Natural Gas 1,237,500 $ 3.75 $ 2.22 $ — $ (1.9 ) $ — $ (2.1 ) NGL 68,750 $ 39.06 $ 23.25 $ — $ (1.1 ) $ — $ (1.5 ) Calls (purchased) Natural Gas 1,237,500 $ 4.98 $ 2.22 $ — $ — $ — $ — NGL 68,750 $ 46.41 $ 23.25 $ — $ — $ — $ — Portion of option contracts maturing in 2017 Puts (purchased) NGL 1,277,500 $ 25.26 $ 23.44 $ 5.1 $ — $ 5.8 $ — Crude Oil 638,750 $ 59.86 $ 44.92 $ 11.1 $ — $ 10.0 $ — Calls (written) NGL 1,277,500 $ 29.46 $ 23.44 $ — $ (0.8 ) $ — $ (0.8 ) Crude Oil 638,750 $ 68.19 $ 44.92 $ — $ (0.9 ) $ — $ (0.6 ) Portion of option contracts maturing in 2018 Puts (purchased) Crude Oil 91,250 $ 42.00 $ 47.03 $ 0.5 $ — $ — $ — Calls (written) Crude Oil 91,250 $ 51.75 $ 47.03 $ — $ (0.5 ) $ — $ — (1) Volumes of natural gas are measured in MMBtu, whereas volumes of NGL and crude oil are measured in Bbl. (2) Strike and market prices are in $/MMBtu for natural gas and in $/Bbl for NGL and crude oil. (3) The fair value is determined based on quoted market prices at March 31, 2016, and December 31, 2015, respectively, discounted using the swap rate for the respective periods to consider the time value of money. Fair values exclude credit valuation adjustment losses of approximately $0.3 million and $0.4 million at March 31, 2016 and December 31, 2015, respectively, as well as cash collateral received.

SEGMENT INFORMATION (Tables)

SEGMENT INFORMATION (Tables)	3 Months Ended
	Mar. 31, 2016
Segment Reporting [Abstract]
Schedule of Segment Reporting Information, By Segment	The following tables present certain financial information relating to our business segments and corporate activities: Gathering, Processing and Transportation Logistics and Marketing Corporate (1) Total (in millions) Total revenue $ 243.1 $ 248.8 $ — $ 491.9 Less: Intersegment revenue 54.5 5.5 — 60.0 Operating revenue 188.6 243.3 — 431.9 Cost of natural gas and natural gas liquids 118.5 229.5 — 348.0 Segment gross margin 70.1 13.8 — 83.9 Operating and maintenance 46.7 10.4 0.1 57.2 General and administrative 13.0 1.5 1.1 15.6 Depreciation and amortization 37.7 1.8 — 39.5 97.4 13.7 1.2 112.3 Operating income (loss) (27.3 ) 0.1 (1.2 ) (28.4 ) Other income 7.1 (2) — 0.2 7.3 Interest expense, net — — (8.3 ) (8.3 ) Income (loss) before income tax expense (20.2 ) 0.1 (9.3 ) (29.4 ) Income tax expense — — (0.9 ) (0.9 ) Net income (loss) (20.2 ) 0.1 (10.2 ) (30.3 ) Less: Net loss attributable to noncontrolling interest — — (10.1 ) (10.1 ) Net income (loss) attributable to general and $ (20.2 ) $ 0.1 $ (0.1 ) $ (20.2 ) Total assets $ 4,897.8 (3) $ 130.9 $ 113.9 $ 5,142.6 Capital expenditures (excluding acquisitions) $ 15.9 $ 2.7 $ (0.9 ) $ 17.7 (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 $368.0 million for our equity investment in the Texas Express NGL system. As of and for the three months ended March 31, 2015 Gathering, Processing and Transportation Logistics and Marketing Corporate (1) Total (in millions) Total revenue $ 385.4 $ 765.3 $ — $ 1,150.7 Less: Intersegment revenue 267.3 9.9 — 277.2 Operating revenue 118.1 755.4 — 873.5 Cost of natural gas and natural gas liquids 21.9 757.2 — 779.1 Segment gross margin 96.2 (1.8 ) — 94.4 Operating and maintenance 50.8 12.6 — 63.4 General and administrative 16.3 3.0 1.7 21.0 Depreciation and amortization 36.7 1.6 — 38.3 103.8 17.2 1.7 122.7 Operating loss (7.6 ) (19.0 ) (1.7 ) (28.3 ) Other income 5.7 (2) — — 5.7 Interest expense, net — — (6.7 ) (6.7 ) Loss before income tax expense (1.9 ) (19.0 ) (8.4 ) (29.3 ) Income tax expense — — (0.8 ) (0.8 ) Net loss (1.9 ) (19.0 ) (9.2 ) (30.1 ) Less: Net loss attributable to noncontrolling interest — — (10.1 ) (10.1 ) Net income (loss) attributable to general and limited partner ownership interests in Midcoast Energy Partners, L.P. $ (1.9 ) $ (19.0 ) $ 0.9 $ (20.0 ) Total assets $ 5,226.2 (3) $ 236.9 $ 116.5 $ 5,579.6 Capital expenditures (excluding acquisitions) $ 54.8 $ 0.7 $ 0.1 $ 55.6 (1) Corporate consists of interest expense, interest income, noncontrolling interest and other costs such as income taxes, which are not allocated to the business segments. (2) Other income for our Gathering, Processing and Transportation segment includes our equity investment in the Texas Express NGL system. (3) Totals assets for our Gathering, Processing and Transportation segment includes $380.1 million for our equity investment in the Texas Express NGL system.

SUPPLEMENTAL CASH FLOW INFORM35

SUPPLEMENTAL CASH FLOW INFORMATION (Tables)	3 Months Ended
	Mar. 31, 2016
Supplemental Cash Flow Information [Abstract]
Schedule of Supplemental Cash Flow Information	For the three months 2016 2015 (in millions) Additions to property, plant and equipment $ 16.3 $ 56.1 Increase (decrease) in construction payables 1.4 (0.5 ) Total capital expenditures $ 17.7 $ 55.6

ORGANIZATION AND NATURE OF OP36

ORGANIZATION AND NATURE OF OPERATIONS (Details) - Limited Partner Interests (EEP) [Member]	3 Months Ended
	Mar. 31, 2016
Ownership in Midcoast Operating (in percentage)	51.60%
Master limited partnership ownership interest (in percentage)	52.00%
Ownership interest after IPO (in percentage)	48.40%

NET INCOME PER LIMITED PARTNE37

NET INCOME PER LIMITED PARTNER AND GENERAL PARTNER INTEREST (Formula for Distributing Available Cash in Partnership Agreement) (Details)	3 Months Ended
	Mar. 31, 2016$ / 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 PARTNE38

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
		Mar. 31, 2016	Mar. 31, 2015
Earnings Per Share [Line Items]
Net loss		$ (30.3)	$ (30.1)
Less: Net loss attributable to noncontrolling interest		(10.1)	(10.1)
Net loss attributable to general and limited partner interests in Midcoast Energy Partners, L.P.		(20.2)	(20)
Total distributed earnings to our General Partner		(0.3)	(0.3)
Total distributed earnings to our limited partners		(16.2)	(15.7)
Total distributed earnings		(16.5)	(16)
Overdistributed earnings		$ (36.7)	$ (36)
Weighted-average limited partner units outstanding (basic) (in shares)		45.2	45.2
Distributed earnings per limited partner unit (in dollars per share)	[1]	$ 0.36	$ 0.35
Overdistributed earnings per limited partner unit (in dollars per share)	[2]	(0.80)	(0.78)
Net loss per limited partner unit (basic and diluted) (in dollars per share)		$ (0.44)	$ (0.43)
Minimum Quarterly Distribution [Member]
Earnings Per Share [Line Items]
Limited partners' share of distributions interest		98.00%
[1]	Represents the total distributed earnings to limited partners divided by the weighted-average number of limited partner interests outstanding for the period.
[2]	Represents the limited partners' share (98%) of distributions in excess of earnings divided by the weighted-average number of limited partner interests outstanding for the period and underdistributed earnings allocated to the limited partners based on the distribution waterfall that is outlined in our partnership agreement.

ACQUISITIONS (Details)

ACQUISITIONS (Details) - NGR Acquisition [Member] - USD ($) $ in Millions	1 Months Ended	3 Months Ended	12 Months Ended
	Feb. 27, 2015	Mar. 31, 2016	Dec. 31, 2015
Business Acquisition [Line Items]
Maximum contingent future payment	$ 17	$ 17
Price transferred to escrow agent	20
Amount released from escrow and paid to seller		11
Other Assets		6
Business Combination, Gain Recognized, Escrow Funds		$ 3
Fair value of contingent consideration	2.3
Accretion of contingent consideration			$ 0.3
Consideration:
Cash consideration	$ 85
Pro forma earnings data:
Business Combination Contingent Consideration Earnout Period		5 years
Returned escrow deposit released		$ 3
Contingent liability reversed		$ 2.6

CASH AND CASH EQUIVALENTS (Deta

CASH AND CASH EQUIVALENTS (Details) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Cash collateral on behalf of Enbridge subsidiary for accounts receivable sales and not remitted (see Note 11)	$ 14.6	$ 14.6
Cash held in escrow for acquisitions (see Note 3)	0	6
Restricted Cash and Cash Equivalents	14.6	20.6
Obligations Paid Not Yet Presented To Financial Institution	$ 3	$ 4.2

INVENTORY (Details)

INVENTORY (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
INVENTORY [Abstract]
Materials and supplies	$ 0.6		$ 0.6
Natural gas and NGL inventory	13.1		31.3
Inventory, Net, Total	13.7		$ 31.9
Charges related to cost of natural gas	$ 0	$ 4.6

PROPERTY, PLANT AND EQUIPMENT42

PROPERTY, PLANT AND EQUIPMENT (Schedule of Property, Plant and Equipment) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Dec. 31, 2015
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 5,410.4	$ 5,396.9
Accumulated depreciation	(1,202.9)	(1,170.6)
Property, plant and equipment, net	4,207.5	4,226.3
Land [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	14.5	14.2
Rights Of Way [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 465.5	460.3
Rights Of Way [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Depreciation Rates	2.08%
Rights Of Way [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Depreciation Rates	7.14%
Pipelines [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 1,869.1	1,864.4
Pipelines [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Depreciation Rates	1.89%
Pipelines [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Depreciation Rates	6.70%
Pumping Equipment, Buildings and Tanks [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 88.4	88.4
Pumping Equipment, Buildings and Tanks [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Depreciation Rates	1.48%
Pumping Equipment, Buildings and Tanks [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Depreciation Rates	6.67%
Compressors, Meters and Other Operating Equipment [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 2,160.2	2,147.6
Compressors, Meters and Other Operating Equipment [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Depreciation Rates	1.80%
Compressors, Meters and Other Operating Equipment [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Depreciation Rates	20.00%
Vehicles, Office Furniture and Equipment [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 136.2	137.1
Vehicles, Office Furniture and Equipment [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Depreciation Rates	2.19%
Vehicles, Office Furniture and Equipment [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Depreciation Rates	33.33%
Processing and Treating Plants [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 629.2	627.8
Processing and Treating Plants [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Depreciation Rates	2.21%
Processing and Treating Plants [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Depreciation Rates	4.00%
Construction in Progress [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 47.3	$ 57.1

VARIABLE INTEREST ENTITIES (VIE

VARIABLE INTEREST ENTITIES (VIE Assets and Liabilities) (Details) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015	Mar. 31, 2015	Dec. 31, 2014
ASSETS
Cash and cash equivalents	$ 51.4	$ 18	$ 5.3	$ 0
Restricted cash	14.6	20.6
Receivables, trade and other, net	10.3	13.3
Due from General Partner and affiliates	4.3	47
Accrued receivables	24	56.1
Inventory	13.7	31.9
Other current assets	100.2	118.5
Property, plant and equipment, net	4,207.5	4,226.3
Intangible assets, net	267.5	272.9
Equity investment in joint ventures	368	372.3	$ 380.1
Other assets, net	81.1	95.2
LIABILITIES
Due to General Partner and affiliates	108.2	45.7
Accounts payable and other	57.2	92.6
Accrued purchases	109.1	143.8
Property and other taxes payable	10.8	18.4
Other long-term liabilities	39.6	45.9
Variable Interest Entity, Primary Beneficiary [Member]
ASSETS
Cash and cash equivalents	3.6	3.4
Restricted cash	0	6
Receivables, trade and other, net	10.4	13.3
Due from General Partner and affiliates	4.1	46.9
Accrued receivables	24	56.1
Inventory	13.7	31.9
Other current assets	100.2	118.5
Property, plant and equipment, net	4,207.5	4,226.3
Intangible assets, net	267.5	272.9
Equity investment in joint ventures	368	372.3
Other assets, net	80	93.9
LIABILITIES
Due to General Partner and affiliates	38.4	28.5
Accounts payable and other	53.5	87.1
Accrued purchases	109.1	143.8
Property and other taxes payable	10.8	18.4
Other long-term liabilities	$ 39.6	$ 45.9

VARIABLE INTEREST ENTITIES (Nar

VARIABLE INTEREST ENTITIES (Narrative) (Details) - Midcoast Operating [Member] - Variable Interest Entity, Primary Beneficiary [Member] - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Dec. 31, 2015
Variable Interest Entity [Line Items]
Ownership in Midcoast Operating (in percentage)	51.60%
VIE assets	$ 5,079	$ 5,241.5
VIE liabilities	$ 251.4	$ 323.7

EQUITY INVESTMENTS IN JOINT V45

EQUITY INVESTMENTS IN JOINT VENTURES (Details) - Texas Express NGL System [Member] $ in Millions	3 Months Ended
	Mar. 31, 2016USD ($)Entities	Mar. 31, 2015USD ($)
Schedule of Equity Method Investments [Line Items]
Ownership interest in joint venture (in percentage)	35.00%
Length of pipeline (in miles)	593
Number of joint ventures (in entities) | Entities	2
Percentage of combined basis	100.00%
Operating revenues	$ 32.2	$ 28.8
Operating expenses	12	11
Net income (loss)	$ 20.1	$ 17.7

DEBT (Schedule of Debt Obligati

DEBT (Schedule of Debt Obligations) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Total principal amount of debt obligations	$ 840	$ 890
Unamortized debt issuance costs	(1.7)	(1.8)
Total	$ 838.3	888.2
Credit Agreement [Member]
Debt Instrument [Line Items]
Interest rate (in percentage)	2.691%
Maturity date	Dec. 31, 2018
Total principal amount of debt obligations	$ 440	490
Senior Notes [Member] | 3.560% Series A Senior Notes due September 2019 [Member]
Debt Instrument [Line Items]
Interest rate (in percentage)	3.56%
Maturity date	Sep. 30, 2019
Total principal amount of debt obligations	$ 75	75
Senior Notes [Member] | 4.040% Series B Senior Notes due September 2021 [Member]
Debt Instrument [Line Items]
Interest rate (in percentage)	4.04%
Maturity date	Sep. 30, 2021
Total principal amount of debt obligations	$ 175	175
Senior Notes [Member] | 4.420% Series C Senior Notes due September 2024 [Member]
Debt Instrument [Line Items]
Interest rate (in percentage)	4.42%
Maturity date	Sep. 30, 2024
Total principal amount of debt obligations	$ 150	$ 150

DEBT (Schedule of Interest Cost

DEBT (Schedule of Interest Cost) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Interest Costs Incurred [Abstract]
Interest cost incurred	$ 8.4	$ 7.6
Less: Interest capitalized	0.1	0.9
Interest expense, net	$ 8.3	$ 6.7

DEBT (Schedule of Available Cre

DEBT (Schedule of Available Credit) (Details) $ in Millions	Mar. 31, 2016USD ($)
Line of Credit Facility [Line Items]
Total amount available at March 31, 2016	$ 370
Senior Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Total credit limit under Credit Agreement	810
Amounts outstanding under Credit Agreement	(440)
Total amount available at March 31, 2016	$ 370

DEBT (Narrative) (Details)

DEBT (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Debt Instruments [Abstract]
Line of credit facility remaining borrowing capacity	$ 370
Covenant terms
Proceeds from (repayments of) lines of credit	(50)	$ (45)
Proceeds from lines of credit	1,585
Repayments of lines of credit	1,635
Senior Revolving Credit Facility [Member]
Debt Instruments [Abstract]
Total credit available, maximum amount	810
Line of credit facility remaining borrowing capacity	$ 370
Maturity date	Sep. 30, 2018
Portion of Facility Maturing in 2016 [Member] | Senior Revolving Credit Facility [Member]
Debt Instruments [Abstract]
Total credit available, maximum amount	$ 140
Credit facility, expiration date	Nov. 13, 2016
Portion of Facility Maturing in 2017 [Member] | Senior Revolving Credit Facility [Member]
Debt Instruments [Abstract]
Total credit available, maximum amount	$ 25
Maturity date	Sep. 30, 2017
Fixed Rate Debt Obligations [Member]
Covenant terms
Fair values of obligations	$ 372.5

PARTNERS' CAPITAL (Narrative) (

PARTNERS' CAPITAL (Narrative) (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Subsidiary or Equity Method Investee [Line Items]
Distribution to partners	$ 16.5	$ 15.8
Maximum Quarterly Distribution Per Share	$ 0.005
Number of units authorized for issuance (in shares)	3,750,000
Enbridge Energy Partners [Member]
Subsidiary or Equity Method Investee [Line Items]
Distribution to partners	$ 25.9	19.8
Midcoast Operating, LP [Member]
Subsidiary or Equity Method Investee [Line Items]
Distribution Made to Limited Partner, Cash Distributions Paid	8.9	$ 8.5
Reduction of distribution	$ 0.8

PARTNERS' CAPITAL (Distribution

PARTNERS' CAPITAL (Distribution To Partners) (Details) - First Quarter Distribution [Member] $ / shares in Units, $ in Millions	3 Months Ended
	Mar. 31, 2016USD ($)$ / shares
Distribution Made to Limited Partner [Line Items]
Distribution Declaration Date	Jan. 28, 2016
Record Date	Feb. 5, 2016
Distribution Payment Date	Feb. 12, 2016
Distribution per Unit (in dollars per share) | $ / shares	$ 0.35750
Cash distributed (in dollars) | $	$ 16.5

PARTNERS' CAPITAL (Schedule of

PARTNERS' CAPITAL (Schedule of Changes in Partners' Capital) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
Beginning balance	$ 1,626.6
Net loss	(20.2)	$ (20)
Distributions	(16.2)	(15.7)
Ending balance	1,599.4
Noncontrolling interest
Beginning balance	2,405.7	2,529
Capital contributions	9.2	68.2
Comprehensive income:
Net loss	(10.1)	(10.1)
Other comprehensive loss, net of tax	0	(1.4)
Distributions to noncontrolling interest	(25.9)	(19.8)
Ending balance	2,378.9	2,565.9
Total partners’ capital at end of period	3,978.3	4,396.2	$ 4,032.3
Accumulated other comprehensive income (loss) [Member]
Beginning balance	(0.9)	11.6
Changes in fair value of derivative financial instruments reclassified to earnings	0	(4.3)
Changes in fair value of derivative financial instruments recognized in other comprehensive income	0	2.8
Ending balance	(0.9)	10.1
General Partner units [Member]
Beginning balance	43.3	47.8
Net loss	(0.4)	(0.4)
Contributions	9.5	0
Distributions	(0.3)	(0.4)
Ending balance	52.1	47
Limited Partner [Member] | Class A common units [Member]
Beginning balance	522.2	634.2
Net loss	(9.9)	(9.8)
Distributions	(8.1)	(7.7)
Ending balance	504.2	616.7
Limited Partner [Member] | Subordinated Units [Member]
Beginning balance	1,062	1,174
Net loss	(9.9)	(9.8)
Distributions	(8.1)	(7.7)
Ending balance	$ 1,044	$ 1,156.5

RELATED PARTY TRANSACTIONS (Det

RELATED PARTY TRANSACTIONS (Details) $ in Millions	3 Months Ended
	Mar. 31, 2016USD ($)bbl	Mar. 31, 2015USD ($)	Dec. 31, 2015USD ($)
Related Party Transaction [Line Items]
General and administrative services, reduction (in dollars)	$ 25
Omnibus Agreement [Member]
Related Party Transaction [Line Items]
Indemnification proceeds from affiliate	12.2
Maximum indemnification proceeds	15
Indemnification deductible	500,000
General Partner [Member]
Related Party Transaction [Line Items]
Indemnification proceeds from affiliate	9.5
Affiliated Entity [Member]
Related Party Transaction [Line Items]
Increase Decrease in Operating Maintenance Cost	$ 2.7
Texas Express Ngl System [Member] | Maximum [Member]
Related Party Transaction [Line Items]
Oil and gas delivery commitments and contracts daily contractual transportation volume | bbl	120,000
Texas Express Ngl System [Member] | Minimum [Member]
Related Party Transaction [Line Items]
Oil and gas delivery commitments and contracts daily contractual transportation volume | bbl	29,000
General and Administrative Services Transactions [Member]
Related Party Transaction [Line Items]
General and administrative services, reduction (in dollars)	$ 6.3
Pipeline Transportation and Demand Fees from Texas Express NGL System [Member]
Related Party Transaction [Line Items]
Expenses from transactions with related party	5.4	$ 5.8
Financial Support Agreement [Member]
Related Party Transaction [Line Items]
Letters of credit provided	4.9		$ 7.5
Guarantees provided	$ 23.3		$ 21.7
Letters of credit, commitment fee percentage	2.50%
Commitment fees	$ 0.1	$ 0.2

RELATED PARTY TRANSACTIONS (Sal

RELATED PARTY TRANSACTIONS (Sale of AR) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
Related Party Transaction [Line Items]
Net value of receivables sold	$ 435.3	$ 705.4
Proceeds from sale of receivables	435.1	705.2
Sold receivables that have not been collected at the balance sheet date	107.1		$ 147.1
(Gain) loss on sale of accounts receivable	0.2	$ 0.2
Restricted cash	14.6		20.6
Sale of accounts receivable to affiliate [Member]
Related Party Transaction [Line Items]
Restricted cash	$ 14.6		$ 14.6

DERIVATIVE FINANCIAL INSTRUME55

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gains (losses) related to cash flow hedges of forecasted transactions that were subsequently de-designated		$ 0.4
De-designated unrealized commodity hedge gains (losses)		$ 0.6
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months	$ 0.1
Expected value of cash collateral or letters of credit if credit rating is downgraded	10.5
Letters of credit provided on derivatives	$ 4.9		$ 7.5

DERIVATIVE FINANCIAL INSTRUME56

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Derivative Instruments in Statement of Financial Position) (Details) - USD ($) $ in Millions		Mar. 31, 2016	Dec. 31, 2015
Derivatives, Fair Value [Line Items]
Net Total		$ 78	$ 92.5
Cash collateral			12.6
Other Current Assets [Member]
Derivatives, Fair Value [Line Items]
Net Total		96.5	117.3
Other Assets, Net [Member]
Derivatives, Fair Value [Line Items]
Net Total		26.2	39.2
Accounts Payable and Other [Member]
Derivatives, Fair Value [Line Items]
Net Total	[1]	(30.4)	(45.7)
Other Long-term Liabilities [Member]
Derivatives, Fair Value [Line Items]
Net Total		$ (14.3)	$ (18.3)
[1]	Includes $12.6 million of cash collateral at December 31, 2015.

DERIVATIVE FINANCIAL INSTRUME57

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Derivative Balances by Counterparty Credit Quality) (Details) - USD ($) $ in Millions		Mar. 31, 2016	Dec. 31, 2015
Derivative [Line Items]
Net Total		$ 78	$ 92.5
Aaa Rating [Member]
Derivative [Line Items]
Net Total	[1]	0.1	0
Aa Rating [Member]
Derivative [Line Items]
Net Total	[1],[2]	61.6	67.6
A Rating [Member]
Derivative [Line Items]
Net Total	[1]	15.1	24.1
Lower Than A Rating [Member]
Derivative [Line Items]
Net Total	[1]	$ 1.2	$ 0.8
[1]	As determined by nationally-recognized statistical ratings organizations.
[2]	Includes $12.6 million of cash collateral at December 31, 2015.

DERIVATIVE FINANCIAL INSTRUME58

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Credit Concentrations in Industry Sectors) (Details) - USD ($) $ in Millions		Mar. 31, 2016	Dec. 31, 2015
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Net Total		$ 78	$ 92.5
United States Financial Institutions And Investment Banking Entities [Member]
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Credit concentrations	[1]	68.2	80.8
Non United States Financial Institutions [Member]
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Credit concentrations		(12.5)	(12.3)
Integrated Oil Companies [Member]
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Credit concentrations		(0.3)	0.6
Other [Member]
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Credit concentrations		$ 22.6	$ 23.4
[1]	Includes $12.6 million of cash collateral at December 31, 2015.

DERIVATIVE FINANCIAL INSTRUME59

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Effect of Derivative Instruments on Consolidated Statements of Financial Position) (Details) - USD ($) $ in Millions		Mar. 31, 2016	Dec. 31, 2015
Derivatives, Fair Value [Line Items]
Asset Derivatives		$ 122.7	$ 156.5
Liability Derivatives		(44.7)	(51.4)
Derivatives Not Designated As Hedging Instruments [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives		122.7	156.5
Liability Derivatives		(44.7)	(51.4)
Derivatives Not Designated As Hedging Instruments [Member] | Other Current Assets [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives		96.5	117.3
Liability Derivatives		0	0
Derivatives Not Designated As Hedging Instruments [Member] | Other Assets [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives		26.2	39.2
Liability Derivatives		0	0
Derivatives Not Designated As Hedging Instruments [Member] | Accounts Payable and Other [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	[1]	0	0
Liability Derivatives	[1]	(30.4)	(33.1)
Derivatives Not Designated As Hedging Instruments [Member] | Other Long-term Liabilities [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives		0	0
Liability Derivatives		$ (14.3)	$ (18.3)
[1]	Excludes $12.6 million of cash collateral at December 31, 2015.

DERIVATIVE FINANCIAL INSTRUME60

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Effect of Derivative Instruments on Consolidated Statements of Income and AOCI) (Details) - Derivatives in Cash Flow Hedging Relationships [Member] - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain (loss) recognized in AOCI on Derivative (Effective Portion)	$ 0
Amount of gain (loss) reclassified from AOCI to earnings (Effective Portion)	0
Amount of gain (loss) recognized in earnings on derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)	0
Interest Rate Contract [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain (loss) recognized in AOCI on Derivative (Effective Portion)	0
Amount of gain (loss) reclassified from AOCI to earnings (Effective Portion)	(0.1)
Amount of gain (loss) recognized in earnings on derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)	0
Commodity Contract [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain (loss) recognized in AOCI on Derivative (Effective Portion)	0	$ (3.6)
Amount of gain (loss) reclassified from AOCI to earnings (Effective Portion)	0.1	8.4
Amount of gain (loss) recognized in earnings on derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)	$ 0	$ (4)	[1]
[1]	Includes only the ineffective portion of derivatives that are designated as hedging instruments and does not include net gains or losses associated with derivatives that do not qualify for hedge accounting treatment.

DERIVATIVE FINANCIAL INSTRUME61

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Components of Accumulated Other Comprehensive Income) (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2016	Mar. 31, 2015
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance		$ (0.9)
Net other comprehensive income (loss)		0	$ (2.9)
Ending balance		(0.9)
Cash Flow Hedge [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance		(0.9)	11.6
Other comprehensive income before reclassifications	[1]	0	2.8
Amounts reclassified from AOCI	[2],[3]	0	(4.3)
Net other comprehensive income (loss)		0	(1.5)
Ending balance		$ (0.9)	10.1
Noncontrolling Interest [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other comprehensive income before reclassifications			2.7
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Noncontrolling Interest [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Amounts reclassified from AOCI			$ 4.1
[1]	Excludes NCI gain of $2.7 million reclassified from AOCI at March 31, 2015.
[2]	Excludes NCI loss of $4.1 million reclassified from AOCI at March 31, 2015.
[3]	For additional details on the amounts reclassified from AOCI, reference the Reclassifications from Accumulated Other Comprehensive Income table below.

DERIVATIVE FINANCIAL INSTRUME62

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Reclassifications from Accumulated Other Comprehensive Income) (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2016	Mar. 31, 2015
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Total Reclassifications from AOCI		$ (30.3)	$ (30.1)
Cost of natural gas and natural gas liquids		348	779.1
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
Cash Flow Hedge [Member] | Reclassification out of AOCI [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Total Reclassifications from AOCI		0	(4.3)
Commodity Contract [Member] | Cash Flow Hedge [Member] | Reclassification out of AOCI [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Cost of natural gas and natural gas liquids	[1],[2]	$ 0	$ (4.3)
[1]	Excludes NCI loss $4.1 million reclassified from AOCI for the three months ended March 31, 2015.
[2]	Loss (gain) reported within "Cost of natural gas and natural gas liquids" in the consolidated statements of income.

DERIVATIVE FINANCIAL INSTRUME63

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Effect of Derivative Instruments on Consolidated Statements of Income) (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2016	Mar. 31, 2015
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on Settlement of Derivative Instruments		$ 26.5	$ 25.7
Derivatives Not Designated As Hedging Instruments [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain or (Loss) Recognized in Earnings	[1],[2]	(0.6)	(5.4)
Derivatives Not Designated As Hedging Instruments [Member] | Operating Revenue [Member] | Commodity Contract [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain or (Loss) Recognized in Earnings	[1],[2]	(2.4)	(17.3)
Derivatives Not Designated As Hedging Instruments [Member] | Operating Revenue Affiliate [Member] | Commodity Contract [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain or (Loss) Recognized in Earnings	[1],[2]	0	(0.2)
Derivatives Not Designated As Hedging Instruments [Member] | 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]	$ 1.8	$ 12.1
[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 receive hedge accounting treatment and does not include the ineffective portion of derivatives that are designated as hedging instruments
[3]	Includes settlement gains of $26.5 million and $25.7 million for the three months ended March 31, 2016 and 2015, respectively.

DERIVATIVE FINANCIAL INSTRUME64

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Offsetting of Financial Assets and Derivative Assets) (Details) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Gross Amount of Recognized Assets	$ 122.7	$ 156.5
Gross Amount Offset in the Statement of Financial Position	0	0
Net Amount of Assets Presented in the Statement of Financial Position	122.7	156.5
Gross Amount Not Offset in the Statement of Financial Position	(23.2)	(41.5)	[1]
Net Amount	$ 99.5	115
Cash collateral		$ 12.6
[1]	Includes $12.6 million of cash collateral at December 31, 2015.

DERIVATIVE FINANCIAL INSTRUME65

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Offsetting of Financial Liabilities and Derivative Liabilities) (Details) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Gross Amount of Recognized Liabilities	$ (44.7)	$ (64)	[1]
Gross Amount Offset in the Statement of Financial Position	0	0
Net Amount of Liabilities Presented in the Statement of Financial Position	(44.7)	(64)
Gross Amount Not Offset in the Statement of Financial Position	23.2	41.5	[1]
Net Amount	$ (21.5)	(22.5)
Cash collateral		$ 12.6
[1]	Includes $12.6 million of cash collateral at December 31, 2015.

DERIVATIVE FINANCIAL INSTRUME66

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Level with in Fair Value Hierarchy, Financial Assets and Liabilities) (Details) - USD ($) $ in Millions	Mar. 31, 2016		Dec. 31, 2015
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments	$ 78		$ 105.1
Cash collateral	0		(12.6)
Total	78		92.5
Commodity Contracts - Financial [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments	6.1		10.2
Commodity Contracts - Physical [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments	0.9		0.6
Commodity Options [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments	71		94.3
Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments	0		0
Level 1 [Member] | Commodity Contracts - Financial [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments	0		0
Level 1 [Member] | Commodity Contracts - Physical [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments	0		0
Level 1 [Member] | Commodity Options [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments	0		0
Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments	0.6		1.3
Level 2 [Member] | Commodity Contracts - Financial [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments	0.6		1.3
Level 2 [Member] | Commodity Contracts - Physical [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments	0		0
Level 2 [Member] | Commodity Options [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments	0		0
Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments	77.4		103.8
Total	77.4	[1]	103.8	[2]
Level 3 [Member] | Commodity Contracts - Financial [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments	5.5		8.9
Level 3 [Member] | Commodity Contracts - Physical [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments	0.9		0.6
Level 3 [Member] | Commodity Options [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments	$ 71		$ 94.3
[1]	Fair values include credit valuation adjustment losses of approximately $0.2 million.
[2]	Fair values include credit valuation adjustment losses of approximately $0.3 million.

DERIVATIVE FINANCIAL INSTRUME67

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Quantitative Information about Level 3 Fair Value Measurements) (Details) $ in Millions	3 Months Ended		12 Months Ended
	Mar. 31, 2016USD ($)$ / MillionsofBTU-MMBTU$ / Gallon-gal$ / Barrel-bbl		Dec. 31, 2015USD ($)$ / MillionsofBTU-MMBTU$ / Gallon-gal$ / Barrel-bbl
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Assets and liabilities accounted for at fair value on a recurring basis	$ 78		$ 92.5
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	77.4	[1]	103.8	[2]
Credit Valuation Adjustments	$ 0.2		$ 0.3
Commodity Contracts Financial [Member] | Natural Gas [Member] | Minimum [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Forward Price | $ / MillionsofBTU-MMBTU	1.80	[3]	2.27	[4]
Commodity Contracts Financial [Member] | Natural Gas [Member] | Maximum [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Forward Price | $ / MillionsofBTU-MMBTU	3.27	[3]	3.07	[4]
Commodity Contracts Financial [Member] | Natural Gas [Member] | Weighted Average [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Forward Price | $ / MillionsofBTU-MMBTU	2.69	[3]	2.64	[4]
Commodity Contracts Financial [Member] | NGL [Member] | Minimum [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Forward Price | $ / Gallon-gal	0.17	[3]	0.16	[4]
Commodity Contracts Financial [Member] | NGL [Member] | Maximum [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Forward Price | $ / Gallon-gal	0.92	[3]	0.93	[4]
Commodity Contracts Financial [Member] | NGL [Member] | Weighted Average [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Forward Price | $ / Gallon-gal	0.42	[3]	0.41	[4]
Commodity Contracts Financial [Member] | Level 3 [Member] | Natural Gas [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Assets and liabilities accounted for at fair value on a recurring basis	$ 0.6	[1]	$ 0.3	[2]
Commodity Contracts Financial [Member] | Level 3 [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	$ 4.9	[1]	$ 8.6	[2]
Commodity Contracts Physical [Member] | Crude Oil [Member] | Minimum [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Forward Price | $ / Barrel-bbl	28.29	[3]	26.50	[4]
Commodity Contracts Physical [Member] | Crude Oil [Member] | Maximum [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Forward Price | $ / Barrel-bbl	40.90	[3]	38.41	[4]
Commodity Contracts Physical [Member] | Crude Oil [Member] | Weighted Average [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Forward Price | $ / Barrel-bbl	38.91	[3]	37.29	[4]
Commodity Contracts Physical [Member] | Natural Gas [Member] | Minimum [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Forward Price | $ / MillionsofBTU-MMBTU	1.53	[3]	2.08	[4]
Commodity Contracts Physical [Member] | Natural Gas [Member] | Maximum [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Forward Price | $ / MillionsofBTU-MMBTU	3.27	[3]	3.44	[4]
Commodity Contracts Physical [Member] | Natural Gas [Member] | Weighted Average [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Forward Price | $ / MillionsofBTU-MMBTU	2.01	[3]	2.33	[4]
Commodity Contracts Physical [Member] | NGL [Member] | Minimum [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Forward Price | $ / Gallon-gal	0.17	[3]	0.16	[4]
Commodity Contracts Physical [Member] | NGL [Member] | Maximum [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Forward Price | $ / Gallon-gal	0.92	[3]	1.20	[4]
Commodity Contracts Physical [Member] | NGL [Member] | Weighted Average [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Forward Price | $ / Gallon-gal	0.41	[3]	0.40	[4]
Commodity Contracts Physical [Member] | Level 3 [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	$ 0.3	[1]	$ 0	[2]
Commodity Contracts Physical [Member] | Level 3 [Member] | Natural Gas [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Assets and liabilities accounted for at fair value on a recurring basis	(1.8)	[1]	(2.5)	[2]
Commodity Contracts Physical [Member] | Level 3 [Member] | NGL [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Assets and liabilities accounted for at fair value on a recurring basis	2.4	[1]	3.1	[2]
Commodity Option [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Credit Valuation Adjustments	$ 0.3		$ 0.4
Commodity Option [Member] | Minimum [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Option Volatility	8.00%	[3]	13.00%	[4]
Commodity Option [Member] | Maximum [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Option Volatility	100.00%	[3]	74.00%	[4]
Commodity Option [Member] | Weighted Average [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Option Volatility	37.00%	[3]	36.00%	[4]
Commodity Option [Member] | Level 3 [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	$ 71	[1]	$ 94.3	[2]
[1]	Fair values include credit valuation adjustment losses of approximately $0.2 million.
[2]	Fair values include credit valuation adjustment losses of approximately $0.3 million.
[3]	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.
[4]	Prices are in dollars per MMBtu for natural gas, dollars per gallon, or Gal, for NGLs, and Bbl for crude oil.

DERIVATIVE FINANCIAL INSTRUME68

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Reconciliation of Changes in Fair Value of L3 Assets and Liabilities on Recurring Basis) (Details) $ in Millions	3 Months Ended
	Mar. 31, 2016USD ($)
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Beginning balance	$ 103.8
Transfer out of Level 3	0	[1]
Purchases, issuances, sales and settlements:
Purchases	0
Sales	0
Settlements	(27.1)	[2]
Ending balance	77.4
Amounts reported in Operating revenue	(2.4)
Operating Revenue [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Gains or losses included in earnings	(6.7)
Purchases, issuances, sales and settlements:
Amount of changes in net assets attributable to the change in unrealized gains or losses related to assets or liabilities still held at the reporting date	(2.7)
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	7.4
Purchases, issuances, sales and settlements:
Amount of changes in net assets attributable to the change in unrealized gains or losses related to assets or liabilities still held at the reporting date	2.7
Commodity Contracts - Financial [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Beginning balance	8.9
Transfer out of Level 3	0	[1]
Purchases, issuances, sales and settlements:
Purchases	0
Sales	0
Settlements	(3.8)	[2]
Ending balance	5.5
Amounts reported in Operating revenue	0
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	0
Purchases, issuances, sales and settlements:
Amount of changes in net assets attributable to the change in unrealized gains or losses related to assets or liabilities still held at the reporting date	0
Commodity Contracts - Financial [Member] | Cost of Natural Gas and Natural Gas Liquids [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Gains or losses included in earnings	0.4
Purchases, issuances, sales and settlements:
Amount of changes in net assets attributable to the change in unrealized gains or losses related to assets or liabilities still held at the reporting date	0.4
Commodity Contracts - Physical [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Beginning balance	0.6
Transfer out of Level 3	0	[1]
Purchases, issuances, sales and settlements:
Purchases	0
Sales	0
Settlements	(1.5)	[2]
Ending balance	0.9
Amounts reported in Operating revenue	(2.4)
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	(6.7)
Purchases, issuances, sales and settlements:
Amount of changes in net assets attributable to the change in unrealized gains or losses related to assets or liabilities still held at the reporting date	(2.7)
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	8.5
Purchases, issuances, sales and settlements:
Amount of changes in net assets attributable to the change in unrealized gains or losses related to assets or liabilities still held at the reporting date	4.8
Commodity Options [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Beginning balance	94.3
Transfer out of Level 3	0	[1]
Purchases, issuances, sales and settlements:
Purchases	0
Sales	0
Settlements	(21.8)	[2]
Ending balance	71
Amounts reported in Operating revenue	0
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	0
Purchases, issuances, sales and settlements:
Amount of changes in net assets attributable to the change in unrealized gains or losses related to assets or liabilities still held at the reporting date	0
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	(1.5)
Purchases, issuances, sales and settlements:
Amount of changes in net assets attributable to the change in unrealized gains or losses related to assets or liabilities still held at the reporting date	$ (2.5)
[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 INSTRUME69

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Fair Values of Expected Cash Flows of Commodity Based Swaps and Physical Contracts) (Details) $ in Millions		3 Months Ended	12 Months Ended
		Mar. 31, 2016USD ($)MMBTU$ / MillionsofBTU-MMBTUbbl	Dec. 31, 2015USD ($)
Fair Value
Asset		$ 122.7	$ 156.5
Liability		$ (44.7)	(64)	[1]
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]	$ 0	0
Liability	[3]	$ 0	0
Swaps - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Fixed - Natural Gas [Member] | Pay [Member]
Derivative [Line Items]
Wtd. Average Price | $ / MillionsofBTU-MMBTU	[4]	3.48
Swaps - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Fixed - Natural Gas [Member] | Receive [Member]
Derivative [Line Items]
Wtd. Average Price | $ / MillionsofBTU-MMBTU	[4]	2.43
Swaps - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Fixed - NGL [Member]
Derivative [Line Items]
Notional (Bbl) | bbl	[2]	1,570,750
Fair Value
Asset	[3]	$ 1.8	0.2
Liability	[3]	$ (5.1)	(8.4)
Swaps - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Fixed - NGL [Member] | Pay [Member]
Derivative [Line Items]
Wtd. Average Price | $ / MillionsofBTU-MMBTU	[4]	25.39
Swaps - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Fixed - NGL [Member] | Receive [Member]
Derivative [Line Items]
Wtd. Average Price | $ / MillionsofBTU-MMBTU	[4]	23.30
Swaps - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Fixed - Crude Oil [Member]
Derivative [Line Items]
Notional (Bbl) | bbl	[2]	464,000
Fair Value
Asset	[3]	$ 0.1	0
Liability	[3]	$ (11.5)	(17.5)
Swaps - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Fixed - Crude Oil [Member] | Pay [Member]
Derivative [Line Items]
Wtd. Average Price | $ / MillionsofBTU-MMBTU	[4]	65.19
Swaps - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Fixed - Crude Oil [Member] | Receive [Member]
Derivative [Line Items]
Wtd. Average Price | $ / MillionsofBTU-MMBTU	[4]	40.65
Swaps - Portion of Contracts Maturing in 2016 - Receive Fixed/Pay Variable - NGL [Member]
Derivative [Line Items]
Notional (Bbl) | bbl	[2]	1,894,000
Fair Value
Asset	[3]	$ 11	18.3
Liability	[3]	$ (1.4)	(0.2)
Swaps - Portion of Contracts Maturing in 2016 - Receive Fixed/Pay Variable - NGL [Member] | Pay [Member]
Derivative [Line Items]
Wtd. Average Price | $ / MillionsofBTU-MMBTU	[4]	22.68
Swaps - Portion of Contracts Maturing in 2016 - Receive Fixed/Pay Variable - NGL [Member] | Receive [Member]
Derivative [Line Items]
Wtd. Average Price | $ / MillionsofBTU-MMBTU	[4]	27.74
Swaps - Portion of Contracts Maturing in 2016 - Receive Fixed/Pay Variable - Crude Oil [Member]
Derivative [Line Items]
Notional (Bbl) | bbl	[2]	494,000
Fair Value
Asset	[3]	$ 12.2	18.2
Liability	[3]	$ (0.6)	0
Swaps - Portion of Contracts Maturing in 2016 - Receive Fixed/Pay Variable - Crude Oil [Member] | Pay [Member]
Derivative [Line Items]
Wtd. Average Price | $ / MillionsofBTU-MMBTU	[4]	40.51
Swaps - Portion of Contracts Maturing in 2016 - Receive Fixed/Pay Variable - Crude Oil [Member] | Receive [Member]
Derivative [Line Items]
Wtd. Average Price | $ / MillionsofBTU-MMBTU	[4]	64.02
Swaps - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Notional (MMBtu) | MMBTU	[2]	7,355,000
Fair Value
Asset	[3]	$ 0.2	0.1
Liability	[3]	$ (0.2)	(0.1)
Swaps - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Variable - Natural Gas [Member] | Pay [Member]
Derivative [Line Items]
Wtd. Average Price | $ / MillionsofBTU-MMBTU	[4]	2.47
Swaps - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Variable - Natural Gas [Member] | Receive [Member]
Derivative [Line Items]
Wtd. Average Price | $ / MillionsofBTU-MMBTU	[4]	2.47
Physical Contracts - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Fixed - NGL [Member]
Derivative [Line Items]
Notional (Bbl) | bbl	[2]	890,000
Fair Value
Asset	[3]	$ 1.8	0
Liability	[3]	$ (0.1)	(0.2)
Physical Contracts - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Fixed - NGL [Member] | Pay [Member]
Derivative [Line Items]
Wtd. Average Price | $ / MillionsofBTU-MMBTU	[4]	16.02
Physical Contracts - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Fixed - NGL [Member] | Receive [Member]
Derivative [Line Items]
Wtd. Average Price | $ / MillionsofBTU-MMBTU	[4]	17.94
Physical Contracts - Portion of Contracts Maturing in 2016 - Receive Variable /Pay Fixed - Crude Oil [Member]
Derivative [Line Items]
Notional (Bbl) | bbl	[2]	0
Fair Value
Asset	[3]	$ 0	0
Liability	[3]	$ 0	(0.2)
Physical Contracts - Portion of Contracts Maturing in 2016 - Receive Variable /Pay Fixed - Crude Oil [Member] | Pay [Member]
Derivative [Line Items]
Wtd. Average Price | $ / MillionsofBTU-MMBTU	[4]	0
Physical Contracts - Portion of Contracts Maturing in 2016 - Receive Variable /Pay Fixed - Crude Oil [Member] | Receive [Member]
Derivative [Line Items]
Wtd. Average Price | $ / MillionsofBTU-MMBTU	[4]	0
Physical Contracts - Portion of Contracts Maturing in 2016 - Receive Fixed/Pay Variable - NGL [Member]
Derivative [Line Items]
Notional (Bbl) | bbl	[2]	869,166
Fair Value
Asset	[3]	$ 0.1	1.9
Liability	[3]	$ (2.3)	(0.2)
Physical Contracts - Portion of Contracts Maturing in 2016 - Receive Fixed/Pay Variable - NGL [Member] | Pay [Member]
Derivative [Line Items]
Wtd. Average Price | $ / MillionsofBTU-MMBTU	[4]	24.95
Physical Contracts - Portion of Contracts Maturing in 2016 - Receive Fixed/Pay Variable - NGL [Member] | Receive [Member]
Derivative [Line Items]
Wtd. Average Price | $ / MillionsofBTU-MMBTU	[4]	22.46
Physical Contracts - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Notional (MMBtu) | MMBTU	[2]	118,233,634
Fair Value
Asset	[3]	$ 0	0
Liability	[3]	$ (2.1)	(2.8)
Physical Contracts - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Variable - Natural Gas [Member] | Pay [Member]
Derivative [Line Items]
Wtd. Average Price | $ / MillionsofBTU-MMBTU	[4]	1.96
Physical Contracts - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Variable - Natural Gas [Member] | Receive [Member]
Derivative [Line Items]
Wtd. Average Price | $ / MillionsofBTU-MMBTU	[4]	1.94
Physical Contracts - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Variable - NGL [Member]
Derivative [Line Items]
Notional (Bbl) | bbl	[2]	8,400,616
Fair Value
Asset	[3]	$ 3.7	4
Liability	[3]	$ (0.8)	(2.4)
Physical Contracts - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Variable - NGL [Member] | Pay [Member]
Derivative [Line Items]
Wtd. Average Price | $ / MillionsofBTU-MMBTU	[4]	16.51
Physical Contracts - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Variable - NGL [Member] | Receive [Member]
Derivative [Line Items]
Wtd. Average Price | $ / MillionsofBTU-MMBTU	[4]	16.85
Physical Contracts - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Variable - Crude Oil [Member]
Derivative [Line Items]
Notional (Bbl) | bbl	[2]	681,040
Fair Value
Asset	[3]	$ 0.7	0.7
Liability	[3]	$ (0.4)	(0.5)
Physical Contracts - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Variable - Crude Oil [Member] | Pay [Member]
Derivative [Line Items]
Wtd. Average Price | $ / MillionsofBTU-MMBTU	[4]	38.38
Physical Contracts - Portion of Contracts Maturing in 2016 - Receive Variable/Pay Variable - Crude Oil [Member] | Receive [Member]
Derivative [Line Items]
Wtd. Average Price | $ / MillionsofBTU-MMBTU	[4]	38.84
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]	$ 0	0
Liability	[3]	$ 0	0
Swaps - Portion of Contracts Maturing in 2017 - Receive Variable/Pay Fixed - Natural Gas [Member] | Pay [Member]
Derivative [Line Items]
Wtd. Average Price | $ / MillionsofBTU-MMBTU	[4]	2.97
Swaps - Portion of Contracts Maturing in 2017 - Receive Variable/Pay Fixed - Natural Gas [Member] | Receive [Member]
Derivative [Line Items]
Wtd. Average Price | $ / MillionsofBTU-MMBTU	[4]	2.49
Swaps - Portion of Contracts Maturing in 2017 - Receive Variable/Pay Fixed - NGL [Member]
Derivative [Line Items]
Notional (Bbl) | bbl	[2]	757,500
Fair Value
Asset	[3]	$ 0.1	0
Liability	[3]	$ (3.5)	(4.5)
Swaps - Portion of Contracts Maturing in 2017 - Receive Variable/Pay Fixed - NGL [Member] | Pay [Member]
Derivative [Line Items]
Wtd. Average Price | $ / MillionsofBTU-MMBTU	[4]	21.05
Swaps - Portion of Contracts Maturing in 2017 - Receive Variable/Pay Fixed - NGL [Member] | Receive [Member]
Derivative [Line Items]
Wtd. Average Price | $ / MillionsofBTU-MMBTU	[4]	16.63
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]	$ 0	0
Liability	[3]	$ (11.8)	(10.9)
Swaps - Portion of Contracts Maturing in 2017 - Receive Variable/Pay Fixed - Crude Oil [Member] | Pay [Member]
Derivative [Line Items]
Wtd. Average Price | $ / MillionsofBTU-MMBTU	[4]	66.72
Swaps - Portion of Contracts Maturing in 2017 - Receive Variable/Pay Fixed - Crude Oil [Member] | Receive [Member]
Derivative [Line Items]
Wtd. Average Price | $ / MillionsofBTU-MMBTU	[4]	44.92
Swaps - Portion of Contracts Maturing in 2017 - Receive Fixed/Pay Variable - NGL [Member]
Derivative [Line Items]
Notional (Bbl) | bbl	[2]	757,500
Fair Value
Asset	[3]	$ 2.2	3.3
Liability	[3]	$ (0.3)	(0.1)
Swaps - Portion of Contracts Maturing in 2017 - Receive Fixed/Pay Variable - NGL [Member] | Pay [Member]
Derivative [Line Items]
Wtd. Average Price | $ / MillionsofBTU-MMBTU	[4]	16.63
Swaps - Portion of Contracts Maturing in 2017 - Receive Fixed/Pay Variable - NGL [Member] | Receive [Member]
Derivative [Line Items]
Wtd. Average Price | $ / MillionsofBTU-MMBTU	[4]	19.19
Swaps - Portion of Contracts Maturing in 2017 - Receive Fixed/Pay Variable - Crude Oil [Member]
Derivative [Line Items]
Notional (Bbl) | bbl	[2]	638,750
Fair Value
Asset	[3]	$ 11.9	10.9
Liability	[3]	$ 0	0
Swaps - Portion of Contracts Maturing in 2017 - Receive Fixed/Pay Variable - Crude Oil [Member] | Pay [Member]
Derivative [Line Items]
Wtd. Average Price | $ / MillionsofBTU-MMBTU	[4]	44.92
Swaps - Portion of Contracts Maturing in 2017 - Receive Fixed/Pay Variable - Crude Oil [Member] | Receive [Member]
Derivative [Line Items]
Wtd. Average Price | $ / MillionsofBTU-MMBTU	[4]	63.63
Swaps - Portion of Contracts Maturing in 2017 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Notional (MMBtu) | MMBTU	[2]	12,550,000
Fair Value
Asset	[3]	$ 0.8	0.5
Liability	[3]	$ (0.2)	(0.2)
Swaps - Portion of Contracts Maturing in 2017 - Receive Variable/Pay Variable - Natural Gas [Member] | Pay [Member]
Derivative [Line Items]
Wtd. Average Price | $ / MillionsofBTU-MMBTU	[4]	2.70
Swaps - Portion of Contracts Maturing in 2017 - Receive Variable/Pay Variable - Natural Gas [Member] | Receive [Member]
Derivative [Line Items]
Wtd. Average Price | $ / MillionsofBTU-MMBTU	[4]	2.75
Physical Contracts - Portion of Contracts Maturing in 2017 - Receive Variable/Pay Variable - Natural Gas [Member]
Derivative [Line Items]
Notional (Bbl) | bbl	[3]	3,987,810
Fair Value
Asset	[3]	$ 0.1	0.1
Liability	[3]	$ 0	0
Physical Contracts - Portion of Contracts Maturing in 2017 - Receive Variable/Pay Variable - Natural Gas [Member] | Receive [Member]
Derivative [Line Items]
Wtd. Average Price | $ / MillionsofBTU-MMBTU	[3]	2.78
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	0.1
Liability	[3]	$ 0	0
Physical Contracts - Portion of Contracts Maturing in 2018 - Receive Variable/Pay Variable - Natural Gas [Member] | Pay [Member]
Derivative [Line Items]
Wtd. Average Price | $ / MillionsofBTU-MMBTU	[4]	2.89
Physical Contracts - Portion of Contracts Maturing in 2018 - Receive Variable/Pay Variable - Natural Gas [Member] | Receive [Member]
Derivative [Line Items]
Wtd. Average Price | $ / MillionsofBTU-MMBTU	[4]	2.92
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	0.1
Liability	[3]	$ 0	0
Physical Contracts - Portion of Contracts Maturing in 2019 - Receive Variable/Pay Variable - Natural Gas [Member] | Pay [Member]
Derivative [Line Items]
Wtd. Average Price | $ / MillionsofBTU-MMBTU	[4]	2.97
Physical Contracts - Portion of Contracts Maturing in 2019 - Receive Variable/Pay Variable - Natural Gas [Member] | Receive [Member]
Derivative [Line Items]
Wtd. Average Price | $ / MillionsofBTU-MMBTU	[4]	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]	$ 0	0
Liability	[3]	$ 0	0
Physical Contracts - Portion of Contracts Maturing in 2020 - Receive Variable/Pay Variable - Natural Gas [Member] | Pay [Member]
Derivative [Line Items]
Wtd. Average Price | $ / MillionsofBTU-MMBTU	[4]	3.26
Physical Contracts - Portion of Contracts Maturing in 2020 - Receive Variable/Pay Variable - Natural Gas [Member] | Receive [Member]
Derivative [Line Items]
Wtd. Average Price | $ / MillionsofBTU-MMBTU	[4]	3.29
Swap [Member]
Fair Value
Credit Valuation Adjustments		$ 0.4	0.6
Physical Contracts - Portion of Contracts Maturing in 2017 - Receive Fixed/Pay Variable - NGL [Member] | Pay [Member]
Derivative [Line Items]
Notional (Bbl) | bbl	[2]	595
Wtd. Average Price | $ / MillionsofBTU-MMBTU	[4]	21.17
Fair Value
Asset	[3]	$ 0	0
Liability	[3]	$ 0	0
Physical Contracts - Portion of Contracts Maturing in 2017 - Receive Fixed/Pay Variable - NGL [Member] | Receive [Member]
Derivative [Line Items]
Wtd. Average Price | $ / MillionsofBTU-MMBTU	[4]	22.37
Portion of Contracts Maturing in 2017 - Receive Fixed/Pay Variable - NGL [Member]
Derivative [Line Items]
Notional (Bbl) | bbl	[2]	186,500
Fair Value
Asset	[3]	$ 0	0
Liability	[3]	$ 0	$ 0
Portion of Contracts Maturing in 2017 - Receive Fixed/Pay Variable - NGL [Member] | Pay [Member]
Derivative [Line Items]
Wtd. Average Price | $ / MillionsofBTU-MMBTU	[4]	23.40
Portion of Contracts Maturing in 2017 - Receive Fixed/Pay Variable - NGL [Member] | Receive [Member]
Derivative [Line Items]
Wtd. Average Price | $ / MillionsofBTU-MMBTU	[4]	23.33
[1]	Includes $12.6 million of cash collateral at December 31, 2015.
[2]	Volumes of natural gas are measured in MMBtu, whereas volumes of NGL and crude oil are measured in Bbl.
[3]	The fair value is determined based on quoted market prices at March 31, 2016, and December 31, 2015, respectively, discounted using the swap rate for the respective periods to consider the time value of money. Fair values exclude credit valuation adjustment gains of approximately $0.4 million and $0.6 million at March 31, 2016 and December 31, 2015, 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 INSTRUME70

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Fair Values of Expected Cash Flows of Commodity Options) (Details) $ in Millions		3 Months Ended	12 Months Ended
		Mar. 31, 2016USD ($)MMBTU$ / Barrel-bblbbl	Dec. 31, 2015USD ($)
Fair Value
Asset		$ 122.7	$ 156.5
Liability		(44.7)	(64)	[1]
Commodity Option [Member]
Fair Value
Credit Valuation Adjustments		$ 0.3	0.4
Purchased [Member] | Portion Of Put Option Contracts Maturing In 2016 - Natural Gas [Member]
Derivative [Line Items]
Notional (MMBtu) | MMBTU	[2]	1,237,500
Strike Price | $ / Barrel-bbl	[3]	3.75
Market Price | $ / Barrel-bbl	[3]	2.22
Fair Value
Asset	[4]	$ 1.9	2.1
Liability	[4]	$ 0	0
Purchased [Member] | Portion Of Put Option Contracts Maturing In 2016 - NGL [Member]
Derivative [Line Items]
Notional (Bbl) | bbl	[2]	2,227,500
Strike Price | $ / Barrel-bbl	[3]	39.29
Market Price | $ / Barrel-bbl	[3]	22.66
Fair Value
Asset	[4]	$ 37.6	54.4
Liability	[4]	$ 0	0
Purchased [Member] | Portion Of Put Option Contracts Maturing In 2016 - Crude Oil [Member]
Derivative [Line Items]
Notional (Bbl) | bbl	[2]	605,000
Strike Price | $ / Barrel-bbl	[3]	75.91
Market Price | $ / Barrel-bbl	[3]	41.68
Fair Value
Asset	[4]	$ 20.7	27.7
Liability	[4]	$ 0	0
Purchased [Member] | Portion Of Call Option Contracts Maturing In 2016 - Natural Gas [Member]
Derivative [Line Items]
Notional (MMBtu) | MMBTU	[2]	1,237,500
Strike Price | $ / Barrel-bbl	[3]	4.98
Market Price | $ / Barrel-bbl	[3]	2.22
Fair Value
Asset	[4]	$ 0	0
Liability	[4]	$ 0	0
Purchased [Member] | Portion Of Call Option Contracts Maturing In 2016 - NGL [Member]
Derivative [Line Items]
Notional (Bbl) | bbl	[2]	68,750
Strike Price | $ / Barrel-bbl	[3]	46.41
Market Price | $ / Barrel-bbl	[3]	23.25
Fair Value
Asset	[4]	$ 0	0
Liability	[4]	$ 0	0
Purchased [Member] | Portion Of Put Option Contracts Maturing In 2017 - NGL [Member]
Derivative [Line Items]
Notional (Bbl) | bbl	[2]	1,277,500
Strike Price | $ / Barrel-bbl	[3]	25.26
Market Price | $ / Barrel-bbl	[3]	23.44
Fair Value
Asset	[4]	$ 5.1	5.8
Liability	[4]	$ 0	0
Purchased [Member] | Portion Of Put Option Contracts Maturing In 2017 - Crude Oil [Member]
Derivative [Line Items]
Notional (Bbl) | bbl	[2]	638,750
Strike Price | $ / Barrel-bbl	[3]	59.86
Market Price | $ / Barrel-bbl	[3]	44.92
Fair Value
Asset	[4]	$ 11.1	10
Liability	[4]	$ 0	0
Purchased [Member] | Portion Of Put Option Contracts Maturing In 2018 Crude Oil [Member]
Derivative [Line Items]
Notional (Bbl) | bbl	[2]	91,250
Strike Price | $ / Barrel-bbl	[3]	42
Market Price | $ / Barrel-bbl	[3]	47.03
Fair Value
Asset	[4]	$ 0.5	0
Liability	[4]	$ 0	0
Written [Member] | Portion Of Put Option Contracts Maturing In 2016 - Natural Gas [Member]
Derivative [Line Items]
Notional (MMBtu) | MMBTU	[2]	1,237,500
Strike Price | $ / Barrel-bbl	[3]	3.75
Market Price | $ / Barrel-bbl	[3]	2.22
Fair Value
Asset	[4]	$ 0	0
Liability	[4]	$ (1.9)	(2.1)
Written [Member] | Portion Of Put Option Contracts Maturing In 2016 - NGL [Member]
Derivative [Line Items]
Notional (Bbl) | bbl	[2]	68,750
Strike Price | $ / Barrel-bbl	[3]	39.06
Market Price | $ / Barrel-bbl	[3]	23.25
Fair Value
Asset	[4]	$ 0	0
Liability	[4]	$ (1.1)	(1.5)
Written [Member] | Portion Of Call Option Contracts Maturing In 2016 - Natural Gas [Member]
Derivative [Line Items]
Notional (MMBtu) | MMBTU	[2]	1,237,500
Strike Price | $ / Barrel-bbl	[3]	4.98
Market Price | $ / Barrel-bbl	[3]	2.22
Fair Value
Asset	[4]	$ 0	0
Liability	[4]	$ 0	0
Written [Member] | Portion Of Call Option Contracts Maturing In 2016 - NGL [Member]
Derivative [Line Items]
Notional (Bbl) | bbl	[2]	2,227,500
Strike Price | $ / Barrel-bbl	[3]	45.09
Market Price | $ / Barrel-bbl	[3]	22.66
Fair Value
Asset	[4]	$ 0	0
Liability	[4]	$ (0.4)	(0.3)
Written [Member] | Portion Of Call Option Contracts Maturing In 2016 - Crude Oil [Member]
Derivative [Line Items]
Notional (Bbl) | bbl	[2]	605,000
Strike Price | $ / Barrel-bbl	[3]	86.68
Market Price | $ / Barrel-bbl	[3]	41.68
Fair Value
Asset	[4]	$ 0	0
Liability	[4]	$ 0	0
Written [Member] | Portion Of Call Option Contracts Maturing In 2017 - NGL [Member]
Derivative [Line Items]
Notional (Bbl) | bbl	[2]	1,277,500
Strike Price | $ / Barrel-bbl	[3]	29.46
Market Price | $ / Barrel-bbl	[3]	23.44
Fair Value
Asset	[4]	$ 0	0
Liability	[4]	$ (0.8)	(0.8)
Written [Member] | Portion Of Call Option Contracts Maturing In 2017 - Crude Oil [Member]
Derivative [Line Items]
Notional (Bbl) | bbl		638,750
Strike Price | $ / Barrel-bbl	[3]	68.19
Market Price | $ / Barrel-bbl	[3]	44.92
Fair Value
Asset	[4]	$ 0	0
Liability	[4]	$ (0.9)	(0.6)
Written [Member] | Portion Of Call Option Contracts Maturing In 2018 Crude Oil [Member]
Derivative [Line Items]
Notional (Bbl) | bbl	[2]	91,250
Strike Price | $ / Barrel-bbl	[3]	51.75
Market Price | $ / Barrel-bbl	[3]	47.03
Fair Value
Asset	[4]	$ 0	0
Liability	[4]	$ (0.5)	$ 0
[1]	Includes $12.6 million of cash collateral at December 31, 2015.
[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 March 31, 2016, and December 31, 2015, respectively, discounted using the swap rate for the respective periods to consider the time value of money. Fair values exclude credit valuation adjustment losses of approximately $0.3 million and $0.4 million at March 31, 2016 and December 31, 2015, respectively, as well as cash collateral received.

INCOME TAXES (Details)

INCOME TAXES (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
A reconciliation of the income tax expense with amounts determined by applying the statutory U.S. federal income tax rate to income before income tax expense:
Current income tax payable	$ 2.7		$ 1.1
Deferred income tax liability	$ 14.5		$ 14.3
Texas State Income Tax Rate [Member]
A reconciliation of the income tax expense with amounts determined by applying the statutory U.S. federal income tax rate to income before income tax expense:
Effective income tax rate (in percentage)	0.50%	0.60%

SEGMENT INFORMATION (Details)

SEGMENT INFORMATION (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2016		Mar. 31, 2015		Dec. 31, 2015
Segment Reporting Information [Line Items]
Operating revenue		$ 431.9		$ 873.5
Cost of natural gas and natural gas liquids		348		779.1
Segment gross margin		83.9		94.4
Operating and maintenance		57.2		63.4
General and administrative		15.6		21
Depreciation and amortization		39.5		38.3
Total expenses		112.3		122.7
Operating loss		(28.4)		(28.3)
Other income		7.3		5.7
Interest expense, net		(8.3)		(6.7)
Income (loss) before income tax expense		(29.4)		(29.3)
Income tax expense		(0.9)		(0.8)
Net loss		(30.3)		(30.1)
Less: Net loss attributable to noncontrolling interest		(10.1)		(10.1)
Net income (loss)		(20.2)		(20)
Total assets		5,142.6		5,579.6		$ 5,272.1
Capital expenditures (excluding acquisitions)		17.7		55.6
Equity investment in joint ventures		368		380.1		$ 372.3
Operating Segments [Member]
Segment Reporting Information [Line Items]
Operating revenue		491.9		1,150.7
Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Operating revenue		(60)		(277.2)
Gathering, Processing and Transportation [Member]
Segment Reporting Information [Line Items]
Operating revenue		188.6		118.1
Cost of natural gas and natural gas liquids		118.5		21.9
Segment gross margin		70.1		96.2
Operating and maintenance		46.7		50.8
General and administrative		13		16.3
Depreciation and amortization		37.7		36.7
Total expenses		97.4		103.8
Operating loss		(27.3)		(7.6)
Other income	[1]	7.1		5.7
Interest expense, net		0		0
Income (loss) before income tax expense		(20.2)		(1.9)
Income tax expense		0		0
Net loss		(20.2)		(1.9)
Less: Net loss attributable to noncontrolling interest		0		0
Net income (loss)		(20.2)		(1.9)
Total assets		4,897.8	[2]	5,226.2	[3]
Capital expenditures (excluding acquisitions)		15.9		54.8
Gathering, Processing and Transportation [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Operating revenue		243.1		385.4
Gathering, Processing and Transportation [Member] | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Operating revenue		(54.5)		(267.3)
Logistics And Marketing [Member]
Segment Reporting Information [Line Items]
Operating revenue		243.3		755.4
Cost of natural gas and natural gas liquids		229.5		757.2
Segment gross margin		13.8		(1.8)
Operating and maintenance		10.4		12.6
General and administrative		1.5		3
Depreciation and amortization		1.8		1.6
Total expenses		13.7		17.2
Operating loss		0.1		(19)
Other income		0		0
Interest expense, net		0		0
Income (loss) before income tax expense		0.1		(19)
Income tax expense		0		0
Net loss		0.1		(19)
Less: Net loss attributable to noncontrolling interest		0		0
Net income (loss)		0.1		(19)
Total assets		130.9		236.9
Capital expenditures (excluding acquisitions)		2.7		0.7
Logistics And Marketing [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Operating revenue		248.8		765.3
Logistics And Marketing [Member] | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Operating revenue		(5.5)		(9.9)
Corporate [Member]
Segment Reporting Information [Line Items]
Operating revenue	[4]	0		0
Cost of natural gas and natural gas liquids	[4]	0		0
Segment gross margin	[4]	0		0
Operating and maintenance	[4]	0.1		0
General and administrative	[4]	1.1		1.7
Depreciation and amortization	[4]	0		0
Total expenses	[4]	1.2		1.7
Operating loss	[4]	(1.2)		(1.7)
Other income	[4]	0.2		0
Interest expense, net	[4]	(8.3)		(6.7)
Income (loss) before income tax expense	[4]	(9.3)		(8.4)
Income tax expense	[4]	(0.9)		(0.8)
Net loss	[4]	(10.2)		(9.2)
Less: Net loss attributable to noncontrolling interest	[4]	(10.1)		(10.1)
Net income (loss)	[4]	(0.1)		0.9
Total assets	[4]	113.9		116.5
Capital expenditures (excluding acquisitions)	[4]			0.1
Return of Capital expenditures	[4]	(0.9)
Corporate [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Operating revenue	[4]	0		0
Corporate [Member] | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Operating revenue		$ 0		$ 0	[4]
[1]	Other income for our Gathering, Processing and Transportation segment includes our equity investment in the Texas Express NGL system.
[2]	Totals assets for our Gathering, Processing and Transportation segment includes $368.0 million for our equity investment in the Texas Express NGL system.
[3]	Totals assets for our Gathering, Processing and Transportation segment includes $380.1 million for our equity investment in the Texas Express NGL system.
[4]	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 INFORM73

SUPPLEMENTAL CASH FLOW INFORMATION (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Additions to property, plant and equipment	$ 16.3	$ 56.1
Increase (decrease) in construction payables	1.4	(0.5)
Total capital expenditures	$ 17.7	$ 55.6

SUBSEQUENT EVENTS (Details)

SUBSEQUENT EVENTS (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended	3 Months Ended
	Apr. 28, 2016	Mar. 31, 2016	Mar. 31, 2015
Distributions to general partner		$ 0.3	$ 0.3
Midcoast Operating Lp [Member]
Cash distributed (in dollars)		$ 8.9	$ 8.5
Subsequent Event [Member]
Distribution declaration date	Apr. 28, 2016
Record date	May 6, 2016
Distribution payment date	May 13, 2016
Cash available for distribution	$ 16.5
Subsequent Event [Member] | Scenario, Forecast [Member]
Cash distributions paid per limited partner unit outstanding (in dollars per share)	$ 0.3575
Amount paid to parent	$ 8.9
Subsequent Event [Member] | Midcoast Operating Lp [Member] | Scenario, Forecast [Member]
Distributions to general partner	22.9
Amount paid to parent	26
Subsequent Event [Member] | Public Common Unitholders [Member] | Scenario, Forecast [Member]
Cash distributed (in dollars)	$ 7.6