Midcoast Energy Partners 10Q 2013 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2013

¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number 1-36175

MIDCOAST ENERGY PARTNERS, L.P.

(Exact Name of Registrant as Specified in Its Charter)

Delaware

61-1714064

(State or Other Jurisdiction of

Incorporation or Organization)

(I.R.S. Employer

Identification No.)

1100 Louisiana

Suite 3300

Houston, Texas 77002

(Address of Principal Executive Offices) (Zip Code)

(713) 821-2000

(Registrant’s Telephone Number, Including Area Code)

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ¨ No x*

* The registrant became subject to such requirements on November 6, 2013

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):


Large Accelerated Filer	¨	Accelerated Filer	¨
Non-Accelerated Filer	x (Do not check if a smaller reporting company)	Smaller reporting company	¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x

The registrant had 22,610,056 Class A common units outstanding as of December 20, 2013.

MIDCOAST ENERGY PARTNERS, L.P.

TABLE OF CONTENTS


	PART I—FINANCIAL INFORMATION
Item 1.	Financial Statements
	Consolidated Statements of Income for the three and nine month periods ended September 30, 2013 and 2012	1
	Consolidated Statements of Comprehensive Income for the three and nine month periods ended September 30, 2013 and 2012	2
	Consolidated Statements of Cash Flows for the nine month periods ended September 30, 2013 and 2012	3
	Consolidated Statements of Financial Position as of September 30, 2013 and December 31, 2012	4
	Notes to the Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	33
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	49
Item 4.	Controls and Procedures	51

	PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	52
Item 1A.	Risk Factors	52
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	52
Item 6.	Exhibits	52
Signatures		53
Exhibits		54

The information in this report relates to periods that ended prior to the completion of Midcoast Energy Partners, L.P.’s initial public offering and prior to the effective dates of the agreements discussed herein. Consequently, the unaudited consolidated statements and related discussion of financial condition and results of operations contained in this report pertain to Midcoast Operating, L.P. (formerly known as Enbridge Midcoast Energy, L.P.), our predecessor, for accounting purposes.

Unless the context otherwise requires, references in this report to “the Predecessor,” “we,” “our,” “us,” or like terms, when used in a historical context (periods prior to November 13, 2013), refer to Midcoast Operating, L.P. References in this report to “Midcoast Energy Partners,” “the Partnership,” “we,” “our,” “us,” or like terms used in the present tense or prospectively (starting November 13, 2013) refer to Midcoast Energy Partners, L.P. and its subsidiaries. We refer to our general partner, Midcoast Holdings, L.L.C., as our “General Partner” and refer to Enbridge Energy Partners, L.P. and its subsidiaries, other than us, as “Enbridge Energy Partners,” or “EEP.” References to “Enbridge” refer collectively to Enbridge, Inc. and its subsidiaries other than us, our subsidiaries, our General Partner and EEP, its subsidiaries and its general partner. References to “Midcoast Operating” refer to Midcoast Operating, L.P. and its subsidiaries. After the initial public offering, we own a 39% controlling interest in Midcoast Operating, and EEP owns a 61% non-controlling interest in Midcoast Operating. Unless otherwise specifically noted, financial results and operating data are shown on a 100% basis and are not adjusted to reflect EEP’s 61% non-controlling interest in Midcoast Operating.

This Quarterly Report on Form 10-Q includes forward-looking statements, which are statements that frequently use words such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecast,” “intend,” “may,” “plan,” “position,” “projection,” “should,” “strategy,” “target,” “will” and similar words. Although we believe that such forward-looking statements are reasonable based on currently available information, such statements involve risks, uncertainties and assumptions and are not guarantees of performance. Future actions, conditions or events and future results of operations may differ materially from

those expressed in these forward-looking statements. Many of the factors that will determine these results are beyond our ability to control or predict. Specific factors that could cause actual results to differ from those in the forward-looking statements include: (1) changes in the demand for or the supply of, forecast data for, and price trends related to natural gas, natural gas liquids, or NGLs, and crude oil; (2) our ability to successfully complete and finance expansion projects; (3) the effects of competition, in particular, by other pipeline and gathering systems, as well as other processing and treating plants; (4) shut-downs or cutbacks at our facilities or refineries, petrochemical plants, utilities or other businesses for which we transport products or to whom we sell products; (5) hazards and operating risks that may not be covered fully by insurance; (6) changes in or challenges to our rates; and (7) changes in laws or regulations to which we are subject, including compliance with environmental and operational safety regulations that may increase costs of system integrity testing and maintenance.

For additional factors that may affect results, see “Risk Factors” included in our prospectus related to our initial public offering, which we refer to as “the Offering,” dated November 6, 2013 and filed with the United States Securities and Exchange Commission, or SEC, on November 8, 2013, which is available to the public over the Internet at the SEC’s website (www.sec.gov).

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

MIDCOAST OPERATING, L.P.—Predecessor

CONSOLIDATED STATEMENTS OF INCOME


	For the three month period ended September 30,						For the nine month period ended September 30,
	2013			2012			2013		2012
	(unaudited; in millions)
Operating revenues:
Operating revenue (Note 7)	$	1,331.3		$	1,143.1		$	3,887.9	$	3,600.3
Operating revenue—affiliate (Notes 5 and 7)		49.6			77.8			162.4		317.2

		1,380.9			1,220.9			4,050.3		3,917.5
Operating expenses:
Cost of natural gas and natural gas liquids (Notes 3 and 7)		1,221.3			986.1			3,457.9		3,078.9
Cost of natural gas and natural gas liquids—affiliate (Notes 5 and 7)		23.0			51.9			95.5		243.6
Operating and maintenance		61.4			69.7			181.7		190.6
Operating and maintenance—affiliate (Note 5)		27.3			26.6			81.4		81.2
General and administrative		—			(1.7	)		0.1		5.9
General and administrative—affiliate (Note 5)		25.0			24.0			73.0		71.8
Depreciation and amortization (Note 4)		35.8			34.3			106.3		101.1

		1,393.8			1,190.9			3,995.9		3,773.1

Operating income (expense)		(12.9	)		30.0			54.4		144.4
Other income (expense)		—			—			0.2		(0.1	)

Income (loss) before income tax expense		(12.9	)		30.0			54.6		144.3
Income tax expense (Note 8)		0.6			1.3			8.9		2.1

Net income (loss)	$	(13.5	)	$	28.7		$	45.7	$	142.2

The accompanying notes are an integral part of these consolidated financial statements.

MIDCOAST OPERATING, L.P.—Predecessor

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME


	For the three month period ended September 30,						For the nine month period ended September 30,
	2013			2012			2013			2012
	(unaudited; in millions)
Net income (loss)	$	(13.5	)	$	28.7		$	45.7		$	142.2
Other comprehensive income (loss), net of tax expense (benefit) of $(0.1) million, $(0.1) million, $0.0 million and $0.2 million, respectively (Note 7)		(17.0	)		(22.7	)		(5.7	)		43.6

Comprehensive income (loss)	$	(30.5	)	$	6.0		$	40.0		$	185.8

The accompanying notes are an integral part of these consolidated financial statements.

MIDCOAST OPERATING, L.P.—Predecessor

CONSOLIDATED STATEMENTS OF CASH FLOWS


	For the nine month period ended September 30,
	2013			2012
	(unaudited; in millions)
Cash provided by operating activities:
Net income	$	45.7		$	142.2
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization (Note 4)		106.3			101.1
Derivative fair value net losses (gains) (Note 7)		13.9			(7.9	)
Inventory market price adjustments (Note 3)		3.3			9.8
Deferred income taxes (Note 8)		7.5			0.3
Other (Note 10)		0.1			6.7
Changes in operating assets and liabilities, net of acquisitions:
Receivables, trade and other		(28.8	)		(25.9	)
Due from general partner and affiliates		10.6			7.3
Accrued receivables		463.2			119.4
Inventory (Note 3)		(75.1	)		28.4
Current and long-term other assets (Note 7)		(7.0	)		(8.6	)
Due to general partner and affiliates		(1.9	)		13.2
Accounts payable and other (Notes 2 and 7)		(23.2	)		28.8
Accrued purchases		(97.5	)		(148.1	)
Property and other taxes payable		8.8			4.8

Net cash provided by operating activities		425.9			271.5


Cash used in investing activities:
Additions to property, plant and equipment (Notes 4 and 10)		(206.6	)		(315.1	)
Asset acquisitions		(0.9	)		—
Proceeds from the sale of net assets		5.0			9.2
Investment in joint venture		(181.8	)		(81.7	)
Other		(2.2	)		(2.9	)

Net cash used in investing activities		(386.5	)		(390.5	)


Cash provided by (used in) financing activities:
Contributions from partners		166.9			361.0
Distributions to partners (Note 5)		(206.3	)		(242.0	)

Net cash provided by (used in) financing activities		(39.4	)		119.0


Net increase (decrease) in cash and cash equivalents		—			—
Cash and cash equivalents at beginning of year		—			—

Cash and cash equivalents at end of period	$	—		$	—

The accompanying notes are an integral part of these consolidated financial statements.

MIDCOAST OPERATING, L.P.—Predecessor

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION


	September 30, 2013		December 31, 2012
	(unaudited; in millions)
ASSETS
Current assets:
Receivables, trade and other, net of allowance for doubtful accounts of $1.1 million and $1.9 million	$	54.8	$	26.2
Due from general partner and affiliates (Note 5)		132.1		263.5
Accrued receivables		88.0		551.2
Inventory (Note 3)		144.6		74.8
Other current assets (Note 7)		28.0		32.5

		447.5		948.2
Property, plant and equipment, net (Note 4)		4,058.3		3,963.0
Goodwill		226.5		226.5
Intangibles, net		251.6		257.2
Equity investment in joint venture (Note 5)		365.5		183.7
Other assets, net (Note 7)		92.0		88.8

	$	5,441.4	$	5,667.4

LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Due to general partner and affiliates (Note 5)	$	37.5	$	41.3
Accounts payable and other (Notes 2, 6 and 7)		185.1		314.5
Accrued purchases		398.9		494.3
Property and other taxes payable (Note 8)		25.2		16.4

		646.7		866.5
Other long-term liabilities (Note 7)		79.9		86.7

Total liabilities		726.6		953.2

Commitments and contingencies
Partners’ capital: (Note 5)
Limited partner interest		4,713.4		4,707.1
General partner		—		—
Accumulated other comprehensive income (Note 7)		1.4		7.1

Total partners’ capital		4,714.8		4,714.2

	$	5,441.4	$	5,667.4

The accompanying notes are an integral part of these consolidated financial statements.

MIDCOAST OPERATING, L.P.—Predecessor

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

1. ORGANIZATION AND NATURE OF OPERATIONS

Initial Public Offering

On November 13, 2013, Midcoast Energy Partners, L.P., or MEP, completed its initial public offering, or the Offering, of 18,500,000 Class A common units (2,775,000 additional Class A common units were issued pursuant to the exercise of the underwriters’ over-allotment option on December 9, 2013), representing limited partner interests. MEP received proceeds (net of underwriting discounts, structuring fees and offering expenses) from the Offering of approximately $354.9 million. MEP used the net proceeds to distribute approximately $304.5 million to EEP, to pay approximately $3.4 million in revolving credit facility origination and commitment fees and used approximately $47.0 million to redeem 2,775,000 Class A common units from EEP. Unless the context otherwise requires, references in this report to the Predecessor, we, our, us, or like terms, when used in a historical context (periods prior to November 13, 2013), refer to Midcoast Operating, L.P. References in this report to Midcoast Energy Partners, the Partnership, we, our, us, or like terms used in the present tense or prospectively (periods beginning on November 13, 2013) refer to Midcoast Energy Partners, L.P. and its subsidiaries. Following the completion of the Offering, EEP continues to own crude oil and liquid petroleum assets and a 61% non-controlling interest in Midcoast Operating. EEP also retained a significant interest through its ownership of our general partner, a 52% limited partner interest, after the exercise of the over-allotment option, in us and all of our incentive distribution rights. The Class A common units began trading on November 7, 2013 on the New York Stock Exchange, or NYSE, under the ticker symbol MEP. For more information on the Offering refer to Note 11.Subsequent Events.

General

We own and operate a portfolio of assets engaged in the business of gathering, processing and treating natural gas, as well as the transportation and marketing of natural gas, natural gas liquids, or NGLs, crude oil and condensate. Our portfolio of natural gas and NGL pipelines, plants and related facilities are geographically concentrated in the Gulf Coast and Mid-Continent regions of the United States, primarily in Texas and Oklahoma. We also own and operate natural gas and NGL logistics and marketing assets that primarily support our gathering, processing and transportation business. We hold our assets in a series of limited partnerships and limited liability companies that we wholly own either directly or indirectly.

Our capital accounts consist of general partner interests held by Midcoast OLP GP, L.L.C (f/k/a Enbridge Midcoast Holdings, L.L.C.), or the OLP GP, a wholly owned subsidiary of EEP, and limited partner interests held directly by EEP. At September 30, 2013 and December 31, 2012, our equity interests were distributed as follows:


	September 30, 2013			December 31, 2012
Limited partner interests		99.999	%		99.999	%
General partner interests		0.001	%		0.001	%

Enbridge Energy Partners, L.P.

EEP was formed in 1991 by Enbridge Energy Company, Inc., its general partner, an indirect, wholly owned subsidiary of Enbridge Inc., which we refer to as Enbridge, a leading energy transportation and distribution company located in Calgary, Alberta, Canada. EEP was formed to acquire, own and operate the crude oil and liquid petroleum transportation assets of Enbridge Energy, Limited Partnership, which owns the United States portion of a crude oil and liquid petroleum pipeline system extending from western Canada through the upper and lower Great Lakes region of the United States to eastern Canada.

EEP is a publicly-traded Delaware limited partnership that owns and operates crude oil and liquid petroleum transportation and storage assets and, through its ownership interests in us, natural gas gathering, treating, processing, transmission and marketing assets in the United States. EEP’s Class A common units are traded on the NYSE under the symbol EEP.

Enbridge Energy Management, L.L.C.

Enbridge Energy Management, L.L.C., which we refer to as Enbridge Management, is a Delaware limited liability company that was formed by Enbridge Energy Company, Inc. in May 2002. EEP’s general partner, through its direct ownership of the voting shares of Enbridge Management, elects all of the directors of Enbridge Management. Enbridge Management’s listed shares are traded on the NYSE under the symbol EEQ. Enbridge Management owns all of a special class of EEP’s limited partner interests and derives all of its earnings from its investment in EEP.

Enbridge Management’s principal activity is managing the business and affairs of EEP pursuant to a delegation of control agreement among EEP’s general partner, Enbridge Management and EEP. In accordance with its limited liability company agreement, Enbridge Management’s activities are restricted to being a limited partner of EEP and managing its business and affairs.

Enbridge Inc.

Enbridge is the indirect parent of EEP’s general partner, and its common shares are publicly traded on the NYSE in the United States and on the Toronto Stock Exchange in Canada, in each case, under the symbol ENB. Enbridge is a leader in energy transportation and distribution in North America, with a focus on crude oil and liquids pipelines, natural gas pipelines, natural gas distribution and renewable energy. At September 30, 2013 and December 31, 2012, Enbridge and its consolidated subsidiaries held an effective 20.6% and 21.8% interest in MEP, respectively, through its ownership in Enbridge Management and EEP’s general partner.

Basis of Presentation

The accompanying unaudited interim consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States, or GAAP, for interim consolidated financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. Accordingly, they do not include all the information and footnotes required by GAAP for complete consolidated financial statements. In the opinion of management, they contain all adjustments, consisting only of normal recurring adjustments, which management considers necessary to present fairly our financial position as of September 30, 2013, our results of operations for the three and nine month periods ended September 30, 2013 and 2012 and our cash flows for the nine month periods ended September 30, 2013 and 2012. We derived our consolidated statement of financial position as of December 31, 2012 from the audited financial statements included in our prospectus related to the Offering of the Partnership dated November 6, 2013, as filed with the SEC on November 8, 2013, or the Prospectus. Our results of operations for the three and nine month periods ended September 30, 2013 should not be taken as indicative of the results to be expected for the full year due to seasonal fluctuations in the supply of and demand for natural gas, NGLs and crude oil, timing and completion of our construction projects, maintenance activities, the impact of forward commodity prices and differentials on derivative financial instruments that are accounted for at fair value. These interim consolidated financial statements should be read in conjunction with the audited consolidated financial statements and accompanying footnotes in the Prospectus.

2. CASH AND CASH EQUIVALENTS

Throughout the periods covered by the financial statements presented herein, EEP has provided cash management services to us through a centralized treasury system. As a result, all of our charges and cost allocations covered by the centralized treasury system were deemed to have been paid by us to EEP, in cash,

during the period in which the cost was recorded in the financial statements. In addition, all of our cash receipts were advanced to EEP as they were received. As a result of using EEP’s centralized treasury system, the excess of cash receipts advanced to EEP over the charges and cash allocation represents a net reduction in partners’ capital as presented on our consolidated statements of financial position.

3. INVENTORY

Our inventory is comprised of the following:


	September 30, 2013		December 31, 2012
	(in millions)
Materials and supplies	$	0.6	$	0.4
Crude oil inventory		11.5		10.1
Natural gas and NGL inventory		132.5		64.3

	$	144.6	$	74.8

The “Cost of natural gas and natural gas liquids” on our consolidated statements of income includes charges totaling $0.9 million and $0.2 million, and $3.3 million and $9.8 million for the three and nine month periods ended September 30, 2013 and 2012, respectively, that we recorded to reduce the cost basis of our inventory of natural gas and NGLs to reflect the current market value.

4. PROPERTY, PLANT AND EQUIPMENT

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


	September 30, 2013			December 31, 2012
	(in millions)
Land	$	11.3		$	8.7
Rights-of-way		374.1			340.3
Pipelines		1,724.7			1,603.8
Pumping equipment, buildings and tanks		88.7			65.4
Compressors, meters and other operating equipment		1,953.4			1,755.7
Vehicles, office furniture and equipment		146.5			133.0
Processing and treating plants		511.3			489.8
Construction in progress		184.0			402.2

Total property, plant and equipment		4,994.0			4,798.9
Accumulated depreciation		(935.7	)		(835.9	)

Property, plant and equipment, net	$	4,058.3		$	3,963.0

5. RELATED PARTY TRANSACTIONS

Administrative and Workforce Related Services

Enbridge and Enbridge Management and its affiliates provided management and administrative, operational and workforce related services to us during the periods presented in these financial statements. Employees of Enbridge and its affiliates are assigned to provide services to 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.

We do not directly employ any of the individuals responsible for managing or operating our business. We have historically obtained managerial, administrative and operational services from EEP’s general partner, Enbridge Management and affiliates of Enbridge pursuant to service agreements among us, the Partnership, Enbridge Management and affiliates of Enbridge. Pursuant to these service agreements, we have agreed to reimburse EEP’s general partner and affiliates of Enbridge for the cost of managerial, administrative, operational and director services they provide to us. In connection with the Offering, we entered into an intercorporate services agreement with EEP pursuant to which we agreed upon certain aspects of our relationship with EEP, including the provision by EEP or its affiliates to us of certain administrative services and employees, our agreement to reimburse EEP or its affiliates for the cost of such services and employees and certain other matters.

Intercorporate Services Agreement

EEP’s general partner, Enbridge Management, Enbridge and affiliates of Enbridge provide managerial, administrative, operational and director services to us pursuant to service agreements, and we reimburse them for the costs of those services. Through a general and administrative services agreement among us, EEP’s general partner, Enbridge Management and Enbridge Employee Services, Inc., a subsidiary of EEP’s general partner, which we refer to as EES, we are charged for the services of employees resident in the United States. The charges related to these service agreements are included in “General and administrative—affiliate” expenses on our consolidated statements of income. Under the general and administrative services agreement, EES also provides services to us, EEP, Enbridge Management and EEP’s general partner and charges each recipient, on a monthly basis, the actual costs that it incurs for those services. EEP’s general partner and Enbridge Management may request that EES provide special additional general services for which each party, as appropriate, agrees to pay costs and expenses incurred by EES in connection with providing the special additional general services. The types of services provided under the general and administrative services agreement include:

•

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

•

administrative, executive, legal, human resources and computer support services;

•

insurance coverage;

•

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

•

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

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

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

•

each cost center establishes a budget;

•

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

•

costs are accumulated monthly for each cost center;

•

the actual costs accumulated monthly by each cost center are allocated to us or other Enbridge entities based on the allocation model; and

•

we reimburse EES for our share of the allocated costs.

The total amount incurred by us, through EEP, per the EEP only cost centers, for services received pursuant to the general and administrative services agreement for the three month periods ended September 30, 2013 and 2012 was $52.3 million and $50.6 million, respectively. For the nine month periods ended September 30, 2013 and 2012, we incurred, through EEP, $154.4 million and $153.0 million, respectively, pursuant to the general and administrative services agreement. These amounts were settled through “Contributions from partners” as reflected on our consolidated statements of cash flows. The following table presents the affiliate amounts reflected in our consolidated statements of income by category as follows:


	For the three month period ended September 30,				For the nine month period ended September 30,
	2013		2012		2013		2012
	(unaudited; in millions)
Operating and maintenance—affiliate	$	27.3	$	26.6	$	81.4	$	81.2
General and administrative—affiliate		25.0		24.0		73.0		71.8

Total	$	52.3	$	50.6	$	154.4	$	153.0

Enbridge and Enbridge Management and their respective affiliates allocated direct workforce costs to us for our construction projects of $4.5 million and $6.4 million as of September 30, 2013 and December 31, 2012, respectively, that we recorded as additions to “Property, plant and equipment, net” on our consolidated statements of financial position.

Insurance Allocation Agreement

We participate in the comprehensive insurance program that is maintained by Enbridge for its benefit and the benefit of its subsidiaries. In December 2012, EEP entered into an insurance allocation agreement with Enbridge and another Enbridge subsidiary, which was amended on November 13, 2013, as discussed in Note 11.Subsequent Events. Under this agreement, in the unlikely event that multiple insurable incidents occur which exceed coverage limits within the same insurance period, the total insurance coverage will be allocated among the Enbridge entities on an equitable basis.

Affiliate Revenues and Purchases

We purchase natural gas, NGLs and crude oil from third parties, which subsequently generate operating revenues from sales to Enbridge and its affiliates. The sales to Enbridge and its affiliates are presented in “Operating revenue—affiliate” on our consolidated statements of income. These transactions are entered into at the market price on the date of sale. Included in our results for the three month periods ended September 30, 2013 and 2012 are operating revenues from sales to Enbridge and its affiliates of $49.6 million and $77.8 million, respectively. Included in our results for the nine month periods ended September 30, 2013 and 2012 are operating revenues from sales to Enbridge and affiliates of $162.4 million and $317.2 million, respectively.

We also purchase natural gas, NGLs and crude oil from Enbridge and its affiliates for sale to third parties at market prices on the date of purchase. The purchases of natural gas, NGLs and crude oil from Enbridge and its affiliates are presented in “Cost of natural gas and natural gas liquids—affiliate” on our consolidated statements of income. Included in our results for the three month periods ended September 30, 2013 and 2012 are costs for natural gas, NGLs and crude oil purchases from Enbridge and its affiliates of $23.0 million and $51.9 million, respectively. Included in our results for the nine month periods ended September 30, 2013 and 2012 are costs for

natural gas, NGLs and crude oil purchases from Enbridge and its affiliates of $95.5 million and $243.6 million, respectively. Routine purchases and sales with affiliates are settled monthly through EEP’s centralized treasury function at terms that are consistent with third-party transactions. Routine purchases and sales with affiliates that have not yet been settled are included in “Due from general partner and affiliates” and “Due to general partner and affiliates” on our consolidated statements of financial position.

Related Party Transactions with Joint Venture

We have a 35% aggregate interest in the Texas Express NGL system, which is comprised of two joint ventures with third parties that together are constructing a 580 mile NGL intrastate transportation pipeline and a related NGL gathering system that was placed into service in the fourth quarter of 2013. Our equity investment in the Texas Express NGL system at September 30, 2013 and December 31, 2012 was $365.5 million and $183.7 million, respectively, which is included on our consolidated statements of financial position in “Equity investment in joint venture.”

Our logistics and marketing business has made commitments to transport up to 120,000 barrels per day, or bpd, of NGLs on the Texas Express NGL system from 2013 to 2023.

Partners’ Capital Transactions

The partners’ capital accounts reflected in the financial statements contained herein, as of September 30, 2013, reflect the ownership of our Predecessor and are comprised of a 99.999% limited partner interest that is owned entirely by EEP and a 0.001% general partner interest that at September 30, 2013 is owned by the OLP GP, a wholly owned subsidiary of EEP. We paid cash distributions to EEP and the OLP GP totaling $206.3 million, and $242.0 million during the nine months ended September 30, 2013 and 2012, respectively. These amounts were settled through “Distributions to partners” as reflected on our consolidated statements of cash flows.

Conflicts of Interest

Our Predecessor was also a direct subsidiary of EEP, which, as of September 30, 2013, owned all of the limited partner interests and controlled the general partner, the OLP GP. As a result, any conflicts of interest that exist between Enbridge Management, EEP’s general partner, Enbridge and EEP may also represent conflicts with us. Enbridge Management makes substantially all decisions relating to the management of EEP’s business and affairs pursuant to a delegation of control agreement with EEP’s general partner and through this arrangement also makes all decisions relating to the management of our business and affairs. EEP’s general partner owns the voting shares of Enbridge Management and elects all of its directors. Enbridge, through its wholly owned subsidiary, Enbridge Pipelines, Inc., owns all the common stock of EEP’s general partner. Most of the directors and officers of EEP’s general partner are also directors and officers of Enbridge Management and some are directors and officers of Enbridge and have fiduciary duties to manage the business of Enbridge, EEP’s general partner and Enbridge Management in a manner that may not be in the best interests of MEP’s unitholders. Certain conflicts of interest could arise as a result of the relationships among Enbridge Management, EEP’s general partner, Enbridge, EEP and the Predecessor. EEP’s partnership agreement and our partnership agreement and the delegation of control agreement contain provisions that allow Enbridge Management to take into account the interest of all parties in addition to those of our owners in resolving conflicts of interest, thereby limiting its fiduciary duties to our owners, as well as provisions that may restrict the remedies available to our owners for actions taken that might, without such limitations, constitute breaches of fiduciary duty.

Sale of Accounts Receivable

wholly owned subsidiary of Enbridge. The Receivables Agreement and the transactions contemplated thereby were approved by a special committee of the board of directors of Enbridge Management. Pursuant to the Receivables Agreement, the Enbridge subsidiary will purchase on a monthly basis, for cash, current accounts receivables and accrued receivables, or the receivables, of those of ours subsidiaries and other subsidiaries of EEP that are parties thereto up to an aggregate monthly maximum of $450.0 million net of receivables that have not been collected. Following the sale and transfer of the receivables to the Enbridge subsidiary, the receivables are deposited in an account of that subsidiary, and ownership and control are vested in that subsidiary. The Enbridge subsidiary has no recourse with respect to the receivables acquired from these operating subsidiaries under the terms of and subject to the conditions stated in the Receivables Agreement. EEP and, as of December 2, 2013, MEP, each act in an administrative capacity as collection agent on behalf of the Enbridge subsidiary and can be removed at any time in the sole discretion of the Enbridge subsidiary. EEP and MEP have no other involvement with the purchase and sale of the receivables pursuant to the Receivables Agreement. The Receivables Agreement terminates on December 30, 2016.

Consideration for the receivables sold is equivalent to the carrying value of the receivables less a discount for credit risk. The difference between the carrying value of the receivables sold and the cash proceeds received is recognized in “General and administrative—affiliate” expense in our consolidated statements of income. For the three and nine month periods ended September 30, 2013, the loss stemming from the discount on the receivables sold was not material. For the three and nine month periods ended September 30, 2013, we derecognized and sold $641.0 million and $772.5 million, respectively, of accrued receivables to the Enbridge subsidiary. For the three and nine month periods ended September 30, 2013, the cash proceeds were $640.8 million and $772.3 million, respectively, which was remitted to EEP through our centralized treasury system. As of September 30, 2013, $308.7 million of the receivables were outstanding from customers that had not been collected on behalf of the Enbridge subsidiary.

Allocated Interest

EEP incurs borrowing cost on our behalf, which we recognize to the extent we are able to capitalize such costs to our construction related projects. The interest cost we incur is directly offset by the amount of interest we capitalize on outstanding construction projects.

Our interest cost of the three and nine months ended September 30, 2013 and 2012 is detailed below.


	For the three month period ended September 30,				For the nine month period ended September 30,
	2013		2012		2013		2012
	(unaudited; in millions)
Interest expense	$	5.1	$	1.6	$	16.6	$	4.6
Interest capitalized		5.1		1.6		16.6		4.6

Interest cost incurred	$	—	$	—	$	—	$	—

Interest cost paid	$	5.1	$	1.6	$	16.6	$	4.6

Derivative Transactions

We have related party derivative transactions executed on behalf of EEP that were contracted through MEP prior to the Offering and are allocated to EEP. These transactions were contracted to hedge the forward price of EEP’s crude oil length inherent to the operation of pipelines and to hedge EEP’s interest payments of variable rate debt obligations that are sensitive to changes in interest rates. These hedges create a fixed sales price for crude oil that EEP will receive in the future and lock in the interest rate on EEP’s anticipated future debt. Subsequent to the Offering, these transactions were re-contracted through EEP and will no longer be allocated from MEP. These transactions are included as part of Note 7.Derivative Financial Instruments and Hedging Activities.

6. COMMITMENTS AND CONTINGENCIES

Environmental Liabilities

We are subject to federal and state laws and regulations relating to the protection of the environment. Environmental risk is inherent to the operating activities of our gathering, processing, and transportation and logistics and marketing businesses, and we are, at times, subject to environmental cleanup and enforcement actions. We manage this environmental risk through appropriate environmental policies and practices to minimize any impact our operations may have on the environment. To the extent that we are unable to recover payment for environmental liabilities from insurance or otherwise, we will be responsible for payment of liabilities arising from environmental incidents associated with the operating activities of our gathering, processing and transportation and logistics and marketing businesses. We continue to voluntarily monitor past leak sites on our systems for the purpose of assessing whether any remediation is required in light of current regulations.

As of September 30, 2013 and December 31, 2012, we had $0.2 million and $0.3 million, respectively, included in “Accounts payable and other” and as of December 31, 2012, we had accrued $0.1 million in “Other long-term liabilities,” on our consolidated statements of financial position for costs we have incurred primarily to address remediation of contaminated sites, asbestos containing materials, management of hazardous waste material disposal, outstanding air quality measures for certain of our natural gas assets and penalties we have been or expect to be assessed related to environmental liabilities.

Legal and Regulatory Proceedings

We are a participant in various legal and regulatory proceedings arising in the ordinary course of business. Some of these proceedings are covered, in whole or in part, by insurance. We are also directly, or indirectly, subject to challenges by special interest groups to regulatory approvals and permits for certain of our expansion projects.

7. DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES

Our net income and cash flows are subject to volatility stemming from fluctuations in commodity prices of natural gas, NGLs, condensate and fractionation margins. Fractionation margins represent the relative difference between the price we receive from NGL and condensate sales and the corresponding cost of natural gas we purchase for processing. Our exposure to commodity price risk exists within both of our segments. We use derivative financial instruments (i.e., futures, forwards, swaps, options and other financial instruments with similar characteristics) to manage the risks associated with market fluctuations in commodity prices, as well as to reduce the volatility in our cash flows. Based on our risk management policies, all of our derivative financial instruments are employed in connection with an underlying asset, liability and/or forecasted transaction and are not entered into with the objective of speculating on commodity prices. We have hedged a portion of our exposure to variability in future cash flows associated with commodity price risks through 2016 in accordance with our risk management policies.

Accounting Treatment

We record all derivative financial instruments in our consolidated financial statements at fair market value, which we adjust each period for changes in the fair market value, and refer to as marking to market, or mark-to-market. The fair market value of these derivative financial instruments reflects the estimated amounts that we would pay to transfer a liability or receive to sell an asset in an orderly transaction with market participants to terminate or close the contracts at the reporting date, taking into account the current unrealized losses or gains on open contracts. We apply a mid-market pricing convention, which we refer to as the market approach, to value substantially all of our derivative instruments. Actively traded external market quotes, data from pricing services and published indices are used to value our derivative instruments, which are fair-valued on a recurring basis. We may also use these inputs with internally developed methodologies that result in our best estimates of fair value.

In accordance with the applicable authoritative accounting guidance, if a derivative financial instrument does not qualify as a hedge, or is not designated as a hedge, the derivative is marked-to-market each period with the increases and decreases in fair market value recorded in our consolidated statements of income as increases and decreases in “Cost of natural gas and natural gas liquids” or “Operating revenue” for our commodity-based derivatives. Cash flow is only impacted to the extent the actual derivative contract is settled by making or receiving a payment to or from the counterparty or by making or receiving a payment for entering into a contract that exactly offsets the original derivative contract. Typically, we settle our derivative contracts when the physical transaction that underlies the derivative financial instrument occurs.

If a derivative financial instrument qualifies and is designated as a cash flow hedge, which is a hedge of a forecasted transaction or future cash flows, any unrealized mark-to-market gain or loss is deferred in “Accumulated other comprehensive income,” also referred to as AOCI, a component of “Partners’ capital,” until the underlying hedged transaction occurs. To the extent that the hedge instrument is effective in offsetting the transaction being hedged, there is no impact to the income statement until the underlying transaction occurs. At inception and on a quarterly basis, we formally assess whether the hedge contract is highly effective in offsetting changes in cash flows of hedged items. Any ineffective portion of a cash flow hedge’s change in fair market value is recognized each period in earnings. Realized gains and losses on derivative financial instruments that are designated as hedges and qualify for hedge accounting are included in “Cost of natural gas and natural gas liquids” for commodity hedges in the period in which the hedged transaction occurs. Gains and losses deferred in AOCI related to cash flow hedges for which hedge accounting has been discontinued remain in AOCI until the underlying physical transaction occurs unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period or within an additional two month period of time thereafter. Generally, our preference is for our derivative financial instruments to receive hedge accounting treatment whenever possible to mitigate the non-cash earnings volatility that arises from recording the changes in fair value of our derivative financial instruments through earnings. To qualify for cash flow hedge accounting treatment as set forth in the authoritative accounting guidance, very specific requirements must be met in terms of hedge structure, hedge objective and hedge documentation.

Non-Qualified Hedges

Many of our derivative financial instruments qualify for hedge accounting treatment as set forth in the authoritative accounting guidance. However, we have derivative financial instruments associated with our commodity activities where the hedge structure does not meet the requirements to apply hedge accounting. As a result, these derivative financial instruments do not qualify for hedge accounting and are referred to as non-qualifying. These non-qualifying derivative financial instruments are marked-to-market each period with the change in fair value, representing unrealized gains and losses, included in “Cost of natural gas and natural gas liquids” in our consolidated statements of income. These mark-to-market adjustments produce a degree of earnings volatility that can often be significant from period to period, but have no cash flow impact relative to changes in market prices. The cash flow impact occurs when the underlying physical transaction takes place in the future and the associated financial instrument contract settlement is made.

The following transaction types do not qualify for hedge accounting and contribute to volatility in our earnings and in our cash flows upon settlement:

Commodity Price Exposures:

•

Transportation—In our logistics and marketing business, when we transport natural gas from one location to another, the pricing index used for natural gas sales is usually different from the pricing index used for natural gas purchases, which exposes us to market price risk relative to changes in those two indices. By entering into a basis swap, where we exchange one pricing index for another, we can effectively lock in the margin, representing the difference between the sales price and the purchase price, on the combined natural gas purchase and natural gas sale, removing any market price risk on the

physical transactions. Although this represents a sound economic hedging strategy, the derivative financial instruments (i.e., the basis swaps) we use to manage the commodity price risk associated with these transportation contracts do not qualify for hedge accounting, since only the future margin has been fixed and not the future cash flow. As a result, the changes in fair value of these derivative financial instruments are recorded in earnings.

•

Storage—In our logistics and marketing business, we use derivative financial instruments (i.e., natural gas swaps) to hedge the relative difference between the injection price paid to purchase and store natural gas and the withdrawal price at which the natural gas is sold from storage. The intent of these derivative financial instruments is to lock in the margin, representing the difference between the price paid for the natural gas injected and the price received upon withdrawal of the natural gas from storage in a future period. We do not pursue cash flow hedge accounting treatment for these storage transactions since the underlying forecasted injection or withdrawal of natural gas may not occur in the period as originally forecast. This can occur because we have the flexibility to make changes in the underlying injection or withdrawal schedule, based on changes in market conditions. In addition, since the physical natural gas or NGLs are recorded at the lower of cost or market, timing differences can result when the derivative financial instrument is settled in a period that is different from the period the physical natural gas is sold from storage. As a result, derivative financial instruments associated with our natural gas and NGL storage activities can increase volatility due to fluctuations in NGL prices until the underlying transactions are settled or offset.

•

Optional Natural Gas Processing Volumes—In our gathering, processing and transportation business, we use derivative financial instruments to hedge the volumes of NGLs produced from our natural gas processing facilities. Some of our natural gas contracts allow us the choice of processing natural gas when it is economical and to cease doing so when processing becomes uneconomic. We have entered into derivative financial instruments to fix the sales price of a portion of the NGLs that we produce at our discretion and to fix the associated purchase price of natural gas required for processing. We typically designate derivative financial instruments associated with NGLs we produce per contractual processing requirements as cash flow hedges when the processing of natural gas is probable of occurrence. However, we are precluded from designating the derivative financial instruments as qualifying hedges of the respective commodity price risk when the discretionary processing volumes are subject to change. As a result, our operating income is subject to increased volatility due to fluctuations in NGL prices until the underlying transactions are settled or offset.

•

NGL Forward Contracts—In our logistics and marketing business, we use forward contracts to fix the price of NGLs we purchase and store in inventory and to fix the price of NGLs that we sell from inventory to meet the demands of our customers that sell and purchase NGLs. In the second quarter of 2009, we determined that a sub-group of physical NGL sales contracts with terms allowing for economic net settlement did not qualify for the normal purchases and normal sales, or NPNS, scope exception and are being marked-to-market each period with the changes in fair value recorded in earnings. The forward contracts for which we have revoked the NPNS election do not qualify for hedge accounting and are being marked-to-market each period with the changes in fair value recorded in earnings. As a result, our operating income is subject to additional volatility associated with fluctuations in NGL prices until the forward contracts are settled.

•

Natural Gas Forward Contracts—In our logistics and marketing business, we use forward contracts to sell natural gas to our customers. Historically, we have not considered these contracts to be derivatives under the NPNS exception allowed by authoritative accounting guidance. In the first quarter of 2010, we determined that a sub-group of physical natural gas sales contracts with terms allowing for economic net settlement did not qualify for the NPNS scope exception, and are being marked-to-market each period with the changes in fair value recorded in earnings. As a result, our operating income is subject to additional volatility associated with the changes in fair value of these contracts.

•

Crude Forward Contracts—In our logistics and marketing business, we use forward contracts to fix the price of crude we purchase and store in inventory and to fix the price of crude that we sell from inventory. A sub-group of physical crude contracts with terms allowing for economic net settlement do not qualify for the normal purchases and normal sales, or NPNS, scope exception and are being marked-to-market each period with the changes in fair value recorded in earnings. As a result, our operating income is subject to additional volatility associated with fluctuations in crude prices until the forward contracts are settled.

•

Natural Gas and NGL Options—In our gathering, processing and transportation business, we use options to hedge the forecasted commodity exposure of our NGLs and natural gas. Although options can qualify for hedge accounting treatment, pursuant to the authoritative accounting guidance, we have elected non-qualifying treatment. As such, our option premiums are expensed as incurred. These derivatives are being marked-to-market, with the changes in fair value recorded to earnings each period. As a result, our operating income is subject to volatility due to movements in the prices of NGLs and natural gas until the underlying long-term transactions are settled.

In all instances related to the commodity exposures described above, the underlying physical purchase, storage and sale of the commodity is accounted for on a historical cost or net realizable value basis rather than on the mark-to-market basis we employ for the derivative financial instruments used to mitigate the commodity price risk associated with our storage and transportation assets. This difference in accounting (i.e., the derivative financial instruments are recorded at fair market value while the physical transactions are recorded at the lower of historical cost or net realizable value) can and has resulted in volatility in our reported net income, even though the economic margin is essentially unchanged from the date the transactions were consummated.

Derivative Positions

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


	September 30, 2013			December 31, 2012
	(in millions)
Other current assets	$	138.3		$	275.0
Other assets, net		72.5			78.1
Accounts payable and other		(151.2	)		(259.9	)
Other long-term liabilities		(64.0	)		(78.0	)

	$	(4.4	)	$	15.2

The changes in the net 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 long-term natural gas, NGL and crude oil sales and purchase contracts.

We record the change in fair value of our highly effective cash flow hedges in AOCI until the derivative financial instruments are settled, at which time they are reclassified to earnings. Also included in AOCI are unrecognized losses of approximately $0.6 million associated with derivative financial instruments that qualified for and were classified as cash flow hedges of forecasted transactions that were subsequently de-designated. These losses are reclassified to earnings over the periods during which the originally hedged forecasted transactions affect earnings. During the nine month period ended September 30, 2013, unrealized commodity hedge gains of $1.7 million were de-designated as a result of the hedges no longer meeting hedge accounting criteria. We estimate that approximately $4.5 million, representing unrealized net losses from our cash flow hedging activities based on pricing and positions at September 30, 2013, will be reclassified from AOCI to earnings during the next 12 months.

The table below summarizes our derivative balances by counterparty credit quality (negative amounts represent our net obligations to pay the counterparty).


	September 30, 2013			December 31, 2012
	(in millions)
Counterparty Credit Quality⁽¹⁾
AAA	$	0.1		$	—
AA		(57.8	)		(116.6	)
A		(84.5	)		(150.4	)
Lower than A		137.8			282.2

	$	(4.4	)	$	15.2

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

As the net value of our derivative financial instruments has decreased in response to changes in forward commodity prices, our outstanding financial exposure to third parties has also decreased. When credit thresholds are met pursuant to the terms of our International Swaps and Derivatives Association, Inc., or ISDA^®, financial contracts, we have the right to require collateral from our counterparties. We would include any cash collateral received in the balances listed above, however, as of September 30, 2013 and December 31, 2012, we were not holding any cash collateral on our asset exposures. When we are in a position of posting collateral to cover our counterparties’ exposure to our non-performance, the collateral is provided through letters of credit, which are not reflected above.

The ISDA^® agreements and associated credit support, which govern our financial derivative transactions, contain no credit rating downgrade triggers that would accelerate the maturity dates of our outstanding transactions. A change in ratings is not an event of default under these instruments, and the maintenance of a specific minimum credit rating is not a condition to transacting under the ISDA^® agreements. In the event of a credit downgrade, additional collateral may be required to be posted under the agreement if we are in a liability position to our counterparty, but the agreement will not automatically terminate and require immediate settlement of all future amounts due.

The ISDA^® agreements, in combination with our master netting agreements, and credit arrangements governing our commodity swaps require that collateral be posted per tiered contractual thresholds based on the credit rating of each counterparty. EEP generally provides letters of credit to satisfy such collateral requirements under our ISDA^® agreements. These agreements will require additional collateral postings of up to 100% on net liability positions in the event of a credit downgrade below investment grade. Automatic termination clauses which exist are related only to non-performance activities, such as the refusal to post collateral when contractually required to do so. When we are holding an asset position, our counterparties are likewise required to post collateral on their liability (our asset) exposures, also determined by tiered contractual collateral thresholds. Counterparty collateral may consist of cash or letters of credit, both of which must be fulfilled with immediately available funds.

At September 30, 2013 and December 31, 2012, we had credit concentrations in the following industry sectors, as presented below:


	September 30, 2013			December 31, 2012
	(in millions)
United States financial institutions and investment banking entities	$	(114.5	)	$	(204.7	)
Non-United States financial institutions		(28.0	)		(87.4	)
Integrated oil companies		(3.8	)		4.5
General Partner and affiliates		143.1			297.2
Other		(1.2	)		5.6

	$	(4.4	)	$	15.2

Gross derivative balances are presented below before the effects of collateral received or posted and without the effects of master netting arrangements. Both our assets and liabilities are adjusted for non-performance risk, which is statistically derived. This credit valuation adjustment model considers existing derivative asset and liability balances in conjunction with contractual netting and collateral arrangements, current market data such as credit default swap rates and bond spreads and probability of default assumptions to quantify an adjustment to fair value. For credit modeling purposes, collateral received is included in the calculation of our assets, while any collateral posted is excluded from the calculation of the credit adjustment. Our credit exposure for these over-the-counter derivatives is directly with our counterparty and continues until the maturity or termination of the contracts. A reconciliation between the derivative balances presented at gross values rather than the net amounts we present in our other derivative disclosures, is also provided below.

Effect of Derivative Instruments on the Consolidated Statements of Financial Position


	Financial Position Location	Asset Derivatives				Liability Derivatives
		Fair Value at				Fair Value at
		September 30, 2013		December 31, 2012 ⁽³⁾		September 30, 2013			December 31, 2012 ⁽³⁾
		(in millions)
Derivatives designated ashedging instruments⁽¹⁾
Commodity contracts	Other current assets	$	2.4	$	12.2	$	(1.8	)	$	(4.2	)
Commodity contracts	Other assets, net		4.8		2.5		(1.2	)		(1.1	)
Commodity contracts	Accounts payable and other		4.2		4.7		(8.5	)		(5.7	)
Commodity contracts	Other long-term liabilities		0.2		2.0		(1.2	)		(4.5	)

			11.6		21.4		(12.7	)		(15.5	)


Derivatives not designatedas hedging instruments
Interest rate contracts	Other current assets⁽²⁾		123.0		246.9		—			—
Interest rate contracts	Other assets, net⁽²⁾		83.2		68.3		(27.9	)		(3.3	)
Interest rate contracts	Accounts payable and other⁽²⁾		—		—		(123.0	)		(246.9	)
Interest rate contracts	Other long-term liabilities⁽²⁾		2.3		3.3		(57.6	)		(68.3	)
Commodity contracts	Other current assets⁽²⁾		17.2		27.2		(2.5	)		(7.1	)
Commodity contracts	Other assets, net⁽²⁾		14.4		11.8		(0.9	)		(0.1	)
Commodity contracts	Accounts payable and other⁽²⁾		9.2		0.8		(32.9	)		(12.8	)
Commodity contracts	Other long-term liabilities⁽²⁾		0.2		1.6		(8.0	)		(12.1	)

			249.5		359.9		(252.8	)		(350.6	)

Total derivative instruments		$	261.1	$	381.3	$	(265.5	)	$	(366.1	)

⁽¹⁾	Includes items currently designated as hedging instruments. Excludes the portion of de-designated hedges which may have a component remaining in AOCI.

⁽²⁾	Includes both affiliate and third party transactions.

⁽³⁾

The effect of derivative instruments on the consolidated statements of financial position, as of December 31, 2012, was revised to disclose the financial position location on a gross basis. The revisions to the disclosures are not considered material to and had no impact on amounts previously reported in the consolidated statements of financial position.

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


Derivatives in Cash Flow Hedging Relationships	Amount of gain (loss) recognized in AOCI on Derivative (Effective Portion)			Location of gain (loss) reclassified from AOCI to earnings	Amount of gain (loss) reclassified from AOCI to earnings			Location of gain (loss) recognized in earnings on derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)⁽¹⁾	Amount of gain (loss) recognized in earnings on derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)⁽¹⁾
(in millions)
For the three month period ended September 30, 2013
Commodity contracts	$	(17.2	)	Cost of natural gas and natural gas liquids	$	(0.6	)	Cost of natural gas and natural gas liquids	$	(0.5	)

Total	$	(17.2	)		$	(0.6	)		$	(0.5	)

For the three month period ended September 30, 2012
Commodity contracts	$	(22.9	)	Cost of natural gas and natural gas liquids	$	4.6		Cost of natural gas and natural gas liquids	$	(3.9	)

Total	$	(22.9	)		$	4.6			$	(3.9	)

For the nine month period ended September 30, 2013
Commodity contracts	$	(8.8	)	Cost of natural gas and natural gas liquids	$	3.0		Cost of natural gas and natural gas liquids	$	1.8

Total	$	(8.8	)		$	3.0			$	1.8

For the nine month period ended September 30, 2012
Commodity contracts	$	47.2		Cost of natural gas and natural gas liquids	$	(3.4	)	Cost of natural gas and natural gas liquids	$	1.2

Total	$	47.2			$	(3.4	)		$	1.2

⁽¹⁾	Includes only the ineffective portion of derivatives that are designated as hedging instruments and does not include net gains or losses associated with derivatives that do not qualify for hedge accounting treatment.

Components of Accumulated Other Comprehensive Income/(Loss)


	Cash Flow Hedges
	(in millions)

Balance at December 31, 2012	$	7.1
Other comprehensive income (loss) before reclassifications		(2.7	)
Amounts reclassified from AOCI⁽¹⁾		(3.0	)

Net other comprehensive income (loss)		(5.7	)

Balance at September 30, 2013	$	1.4

⁽¹⁾	For additional details on the amounts reclassified from AOCI, reference theReclassifications from Accumulated Other Comprehensive Income table below.

Reclassifications from Accumulated Other Comprehensive Income


	For the three month period ended September 30,					For the nine month period ended September 30,
	2013		2012			2013			2012
	(in millions)
Losses (gains) on cash flow hedges:
Commodity Contracts⁽¹⁾	$	0.6	$	(4.6	)	$	(3.0	)	$	3.4

Total Reclassifications from AOCI	$	0.6	$	(4.6	)	$	(3.0	)	$	3.4

⁽¹⁾	Loss (gain) reported within “Cost of natural gas and natural gas liquids” in the consolidated statements of income.

Effect of Derivative Instruments on Consolidated Statements of Income


	Location of Gain or (Loss) Recognized in Earnings⁽¹⁾	For the three month period ended September 30,						For the nine month period ended September 30,
		2013			2012			2013			2012
Derivatives Not Designated as Hedging Instruments		Amount of Gain or (Loss) Recognized in Earnings⁽²⁾						Amount of Gain or (Loss) Recognized in Earnings⁽²⁾
		(in millions)
Commodity contracts	Cost of natural gas and natural gas liquids⁽³⁾	$	(28.1	)	$	(12.4	)	$	(8.9	)	$	21.7
Commodity contracts	Operating revenue		(6.2	)		—			(6.2	)		—

Total		$	(34.3	)	$	(12.4	)	$	(15.1	)	$	21.7

⁽¹⁾	Does not include settlements associated with derivative instruments that settle through physical delivery.

⁽²⁾	Includes only net gains or losses associated with those derivatives that do not qualify for hedge accounting treatment and does not include the ineffective portion of derivatives that are designated as hedging instruments.

⁽³⁾

Includes settlements losses of $0.2 million for the three month period ended September 30, 2013, settlement gains of $8.3 million for the three month period ended September 30, 2012 and settlement gains of $0.5 million and $15.0 million for the nine month periods ended September 30, 2013 and September 30, 2012, respectively.

Gross to Net Presentation Reconciliation of Derivative Assets and Liabilities


	September 30, 2013									December 31, 2012
	Assets			Liabilities			Total			Assets			Liabilities			Total
	(in millions)
Fair value of derivatives—gross presentation	$	261.1		$	(265.5	)	$	(4.4	)	$	381.3		$	(366.1	)	$	15.2
Effects of netting agreements		(50.3	)		50.3			—			(28.2	)		28.2			—

Fair value of derivatives—net presentation	$	210.8		$	(215.2	)	$	(4.4	)	$	353.1		$	(337.9	)	$	15.2

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 net basis by counterparty. The terms of the ISDA^®, which governs our financial contracts and our other master netting agreements, allow the parties to elect in respect of all transactions under the agreement, in the event of a default and upon notice to the defaulting party, for the non-defaulting party to set-off all settlement payments, collateral held and any other obligations (whether or not then due), which the non-defaulting party owes to the defaulting party.

Offsetting of Financial Assets and Derivative Assets


	As of September 30, 2013
	Gross Amount of Recognized Assets		Gross Amount Offset in the Statement of Financial Position			Net Amount of Assets Presented in the Statement of Financial Position		Gross Amount Not Offset in the Statement of Financial Position			Net Amount
	(in millions)
Description:
Derivatives	$	261.1	$	(50.3	)	$	210.8	$	(4.8	)	$	206.0

Total	$	261.1	$	(50.3	)	$	210.8	$	(4.8	)	$	206.0

Offsetting of Financial Liabilities and Derivative Liabilities


	As of September 30, 2013
	Gross Amount of Recognized Liabilities			Gross Amount Offset in the Statement of Financial Position		Net Amount of Liabilities Presented in the Statement of Financial Position			Gross Amount Not Offset in the Statement of Financial Position		Net Amount
	(in millions)
Description:
Derivatives	$	(265.5	)	$	50.3	$	(215.2	)	$	4.8	$	(210.4	)

Total	$	(265.5	)	$	50.3	$	(215.2	)	$	4.8	$	(210.4	)

Inputs to Fair Value Derivative Instruments

The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2013 and December 31, 2012. We classify financial assets and liabilities in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect our valuation of the financial assets and liabilities and their placement within the fair value hierarchy.


	September 30, 2013											December 31, 2012
	Level 1		Level 2			Level 3			Total			Level 1		Level 2			Level 3		Total
	(in millions)
Commodity contracts:
Financial	$	—	$	(7.0	)	$	0.8		$	(6.2	)	$	—	$	(7.0	)	$	8.4	$	1.4
Physical		—		—			(5.1	)		(5.1	)		—		—			7.4		7.4
Commodity options		—		—			6.9			6.9			—		—			6.4		6.4

Total	$	—	$	(7.0	)	$	2.6		$	(4.4	)	$	—	$	(7.0	)	$	22.2	$	15.2

Qualitative Information about Level 3 Fair Value Measurements

Data from pricing services and published indices are used to value our Level 3 derivative instruments, which are fair-valued on a recurring basis. We may also use these inputs with internally developed methodologies that result in our best estimate of fair value. The inputs listed in the table below would have a direct impact on the fair values of the listed instruments. The significant unobservable inputs used in the fair value measurement of the commodity derivatives (Natural Gas, NGLs and Crude Oil) are forward commodity prices. The significant unobservable inputs used in determining the fair value measurement of options are price and volatility. Increases/(decreases) in the forward commodity price in isolation would result in significantly higher/(lower) fair values for long positions, with offsetting impacts to short positions. Increases/(decreases) in volatility would increase/(decrease) the value for the holder of the option. Generally, a change in the estimate of forward commodity prices is unrelated to a change in the estimate of volatility of prices. An increase to the credit valuation adjustment would change the fair value of the positions.

Quantitative Information About Level 3 Fair Value Measurements


	Fair Value at September 30, 2013 ⁽²⁾					Range⁽¹⁾
Contract Type	Fair Value at September 30, 2013 ⁽²⁾			Valuation Technique	Unobservable Input	Lowest			Highest			Weighted Average			Units
	(in millions)
*Commodity Contracts—Financial*
Natural Gas	$	2.6		Market Approach	Forward Gas Price		3.24			4.19			3.69		MMBtu
NGLs	$	(1.8	)	Market Approach	Forward NGL Price		0.25			2.08			1.25		Gal
*Commodity Contracts—Physical*
Natural Gas	$	0.9		Market Approach	Forward Gas Price		3.24			4.35			3.72		MMBtu
Crude Oil	$	(1.1	)	Market Approach	Forward Crude Price		83.41			107.67			99.42		Bbl
NGLs	$	(4.9	)	Market Approach	Forward NGL Price		0.01			2.28			0.95		Gal
*Commodity Options*
Natural Gas, Crude and NGLs	$	6.9		Option Model	Option Volatility		24	%		145	%		41	%

*Total Fair Value*	$	2.6

⁽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 are presented in millions of dollars and include credit valuation adjustments of approximately $0.3 million of losses.

Quantitative Information About Level 3 Fair Value Measurements


	Fair Value at December 31, 2012 ⁽²⁾					Range⁽¹⁾
Contract Type	Fair Value at December 31, 2012 ⁽²⁾			Valuation Technique	Unobservable Input	Lowest			Highest			Weighted Average			Units
	(in millions)
*Commodity Contracts—Financial*
Natural Gas	$	8.8		Market Approach	Forward Gas Price		3.21			4.31			3.54		MMBtu
NGLs	$	(0.4	)	Market Approach	Forward NGL Price		0.25			2.21			1.40		Gal
*Commodity Contracts—Physical*
Natural Gas	$	1.7		Market Approach	Forward Gas Price		3.19			4.58			3.73		MMBtu
Crude Oil	$	2.6		Market Approach	Forward Crude Price		65.22			116.56			94.31		Bbl
NGLs	$	3.1		Market Approach	Forward NGL Price		—			2.22			0.61		Gal
*Commodity Options*
Natural Gas, Crude and NGLs	$	6.4		Option Model	Option Volatility		29	%		104	%		40	%

*Total Fair Value*	$	22.2

⁽¹⁾	Prices are in dollars per MMBtu, for Natural Gas, dollars per Gal, for NGLs and dollars per Bbl, for Crude Oil.

⁽²⁾	Fair values are presented in millions and include credit valuation adjustments of approximately $0.1 million of losses.

Level 3 Fair Value Reconciliation

The table below provides a reconciliation of changes in the fair value of our Level 3 financial assets and liabilities measured on a recurring basis from January 1, 2013 to September 30, 2013. 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, 2013	$	8.4		$	7.4		$	6.4		$	22.2
Transfer out of Level 3⁽¹⁾		—			—			—			—
Gains or losses:
Included in earnings (or changes in net assets)		1.7			21.7			(0.5	)		22.9
Included in other comprehensive income		3.4			—			—			3.4
Purchases, issuances, sales and settlements:
Purchases		—			—			3.0			3.0
Settlements⁽²⁾		(12.7	)		(34.2	)		(2.0	)		(48.9	)

Ending balance as of September 30, 2013	$	0.8		$	(5.1	)	$	6.9		$	2.6

Amount of changes in net assets attributable to the change in unrealizedgains or losses related to assets still held at the reporting date	$	0.6		$	(6.2	)	$	4.0		$	(1.6	)

Amounts reported in operating revenue	$	—		$	(6.2	)	$	—		$	(6.2	)

⁽¹⁾	Our policy is to recognize transfers as of the last day of the reporting period.

⁽²⁾	Settlements represent the realized portion of forward contracts.

Fair Value Measurements of Commodity Derivatives

The following table provides summarized information about the fair values of expected cash flows of our outstanding commodity based swaps and physical contracts at September 30, 2013 and December 31, 2012.


	At September 30, 2013												At December 31, 2012
				Wtd. Average Price⁽²⁾				Fair Value⁽³⁾					Fair Value⁽³⁾
	Commodity	Notional⁽¹⁾		Receive		Pay		Asset		Liability			Asset		Liability
*Portion of contracts maturing in 2013*
Swaps
Receive variable/pay fixed	Natural Gas		1,058,748	$	3.49	$	3.59	$	0.1	$	(0.2	)	$	0.2	$	(0.3	)
	NGL		985,200	$	46.80	$	45.40	$	1.8	$	(0.5	)	$	1.4	$	—
	Crude Oil		257,664	$	101.36	$	102.95	$	0.2	$	(0.7	)	$	0.2	$	(3.9	)
Receive fixed/pay variable	Natural Gas		2,361,000	$	4.36	$	3.55	$	1.9	$	—		$	7.8	$	—
	NGL		1,854,028	$	50.19	$	52.46	$	3.0	$	(7.2	)	$	9.3	$	(9.9	)
	Crude Oil		591,548	$	94.24	$	101.48	$	0.6	$	(4.8	)	$	6.3	$	(8.8	)
Receive variable/pay variable	Natural Gas		13,277,500	$	3.53	$	3.51	$	0.3	$	(0.1	)	$	1.2	$	(0.2	)
Physical Contracts
Receive variable/pay fixed	NGL		2,330,976	$	37.27	$	36.89	$	3.3	$	(2.4	)	$	0.6	$	(0.8	)
	Crude Oil		255,010	$	102.19	$	105.97	$	—	$	(1.0	)	$	0.4	$	(0.4	)
Receive fixed/pay variable	NGL		3,844,386	$	39.72	$	41.85	$	3.3	$	(11.4	)	$	2.6	$	(2.2	)
	Crude Oil		339,200	$	105.55	$	102.04	$	1.2	$	—		$	0.2	$	(1.0	)
Receive variable/pay variable	Natural Gas		19,866,685	$	3.53	$	3.52	$	0.3	$	(0.2	)	$	0.9	$	—
	NGL		6,135,041	$	47.40	$	47.20	$	3.6	$	(2.4	)	$	5.2	$	(2.3	)
	Crude Oil		1,120,690	$	98.78	$	99.06	$	1.4	$	(1.7	)	$	6.4	$	(3.0	)
*Portion of contracts maturing in 2014*
Swaps
Receive variable/pay fixed	Natural Gas		21,870	$	3.75	$	5.22	$	—	$	—		$	—	$	—
	NGL		286,250	$	82.33	$	83.05	$	—	$	(0.2	)	$	—	$	—
	Crude Oil		506,255	$	95.33	$	101.95	$	—	$	(3.3	)	$	—	$	(5.0	)
Receive fixed/pay variable	Natural Gas		3,006,890	$	3.97	$	3.73	$	0.7	$	—		$	0.2	$	—
	NGL		2,208,800	$	53.93	$	53.67	$	5.6	$	(5.0	)	$	0.9	$	(2.7	)
	Crude Oil		1,573,205	$	94.43	$	95.41	$	3.6	$	(5.2	)	$	5.4	$	(2.7	)
Receive variable/pay variable	Natural Gas		13,842,500	$	3.77	$	3.76	$	0.2	$	—		$	0.1	$	(0.1	)
Physical Contracts
Receive variable/pay fixed	NGL		45,000	$	43.79	$	45.45	$	—	$	(0.1	)	$	—	$	—
Receive fixed/pay variable	NGL		325,617	$	53.43	$	55.69	$	0.1	$	(0.8	)	$	—	$	—
Receive variable/pay variable	Natural Gas		34,169,685	$	3.77	$	3.76	$	0.9	$	(0.4	)	$	0.5	$	—
	NGL		7,037,705	$	33.02	$	32.90	$	1.8	$	(0.9	)	$	—	$	—
*Portion of contracts maturing in 2015*
Swaps
Receive variable/pay fixed	Crude Oil		515,015	$	88.53	$	100.93	$	—	$	(6.3	)	$	—	$	(5.6	)
Receive fixed/pay variable	NGL		292,000	$	56.76	$	54.04	$	1.2	$	(0.5	)	$	0.7	$	(0.2	)
	Crude Oil		865,415	$	97.72	$	88.53	$	7.9	$	—		$	6.8	$	(0.2	)
Receive variable/pay variable	Natural Gas		900,000	$	4.05	$	4.04	$	—	$	—		$	—	$	—
Physical Contracts
Receive variable/pay variable	Natural Gas		8,541,825	$	4.10	$	4.06	$	0.5	$	(0.1	)	$	0.4	$	—
*Portion of contracts maturing in 2016*
Swaps
Receive fixed/pay variable	Crude Oil		45,750	$	99.31	$	84.81	$	0.6	$	—		$	0.5	$	—
Physical Contracts
Receive variable/pay variable	Natural Gas		783,240	$	4.28	$	4.17	$	0.1	$	—		$	0.1	$	—

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

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

⁽³⁾

The fair value is determined based on quoted market prices at September 30, 2013 and December 31, 2012, respectively, discounted using the swap rate for the respective periods to consider the time value of money. Fair values are presented in millions of dollars and exclude credit valuation adjustments of approximately $0.2 million of losses at September 30, 2013 and $0.2 million of losses at December 31, 2012.

The following table provides summarized information about the fair values of expected cash flows of our outstanding commodity options at September 30, 2013 and December 31, 2012.


	At September 30, 2013												At December 31, 2012
				Strike Price⁽²⁾		Market Price⁽²⁾		Fair Value⁽³⁾					Fair Value⁽³⁾
	Commodity	Notional⁽¹⁾		Strike Price⁽²⁾		Market Price⁽²⁾		Asset		Liability			Asset		Liability
*Portion of option contracts maturing in 2013*
Puts (purchased)	Natural Gas		414,000	$	4.18	$	3.48	$	0.3	$	—		$	1.4	$	—
	NGL		138,000	$	31.26	$	27.76	$	1.1	$	—		$	3.7	$	—
Puts (written)	NGL		69,000	$	26.18	$	10.68	$	—	$	(1.1	)	$	—	$	—
*Portion of option contracts maturing in 2014*
Puts (purchased)	NGL		401,500	$	52.21	$	50.44	$	3.1	$	—		$	1.3	$	—
Calls (written)	NGL		273,750	$	57.93	$	48.65	$	—	$	(0.9	)	$	—	$	—
*Portion of option contracts maturing in 2015*
Puts (purchased)	NGL		547,500	$	53.76	$	52.52	$	4.5	$	—		$	—	$	—

⁽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 September 30, 2013 and December 31, 2012, respectively, discounted using the swap rate for the respective periods to consider the time value of money.

8. 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 owners through the allocation of taxable income. The State of Texas imposes taxes on us that are based on many, but not all, items included in net income.

We computed our income tax expense by applying a Texas state income tax rate to modified gross margin. Our Texas state income tax rate was 0.4% and 0.5% for the nine month periods ended September 30, 2013 and 2012, respectively. Our income tax expense is $0.6 million and $1.3 million and $8.9 million and $2.1 million for the three and nine month periods ended September 30, 2013 and 2012, respectively.

At September 30, 2013 and December 31, 2012, we have included a current income tax payable of $1.7 million and $3.7 million in “Property and other taxes payable” on our consolidated statements of financial position, respectively. In addition, at September 30, 2013 and December 31, 2012, we have included a deferred income tax payable of $10.5 million and $3.0 million, respectively, in “Deferred income tax liability” on our consolidated statements of financial position to reflect the tax associated with the difference between the net basis in assets and liabilities for financial and state tax reporting. Included in the $10.5 million is $6.6 million due to a new tax bill that went into effect in June 2013, as discussed below.

The Texas Legislature passed House Bill 500, or HB 500, and it was subsequently signed into law in June 2013. The most noteworthy item in the law for us is that HB 500 allows a pipeline company that transports oil, gas, or other petroleum products owned by others to subtract as Cost of Goods Sold, or COGS, its depreciation, operations and maintenance costs related to the services provided. Under the new law, we are allowed additional deductions against our income for Texas margin tax purposes. We have recorded an additional “Deferred income tax liability” on our consolidated statements of financial position of approximately $6.6 million for the nine month period ended September 30, 2013 as a result of this new tax law. In the future, our effective tax rate in the State of Texas will be lower as a result of this change in law.

9. SEGMENT INFORMATION

Our business is divided into operating segments, defined as components of the enterprise, about which financial information is available and evaluated regularly by our Chief Operating Decision Maker, collectively comprised of our senior management, in deciding how resources are allocated and performance is assessed.

Each of our reportable segments is a business unit that offers different services and products that is managed separately, since each business segment requires different operating strategies. We conduct our business through two distinct reporting segments:

•

Gathering, processing and transportation; and

•

Logistics and marketing.

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


	For the three month period ended September 30, 2013
	Gathering, Processing and Transportation		Logistics and Marketing			Corporate⁽¹⁾			Total
	(in millions)
Total revenue	$	668.2	$	1,228.8		$	—		$	1,897.0
Less: Intersegment revenue		496.8		19.3			—			516.1

Operating revenue		171.4		1,209.5			—			1,380.9
Cost of natural gas and natural gas liquids		33.5		1,210.8			—			1,244.3

Segment gross margin		137.9		(1.3	)		—			136.6

Operating and maintenance		71.0		17.7			—			88.7
General and administrative		22.1		2.9			—			25.0
Depreciation and amortization		34.1		1.7			—			35.8

		127.2		22.3			—			149.5

Operating income (loss)		10.7		(23.6	)		—			(12.9	)

Income (loss) before income tax expense		10.7		(23.6	)		—			(12.9	)
Income tax expense		—		—			0.6			0.6

Net income (loss)	$	10.7	$	(23.6	)	$	(0.6	)	$	(13.5	)

⁽¹⁾	Corporate consists of income taxes, which are not allocated to the business segments.


	For the three month period ended September 30, 2012
	Gathering, Processing and Transportation		Logistics and Marketing		Corporate⁽¹⁾			Total
	(in millions)
Total revenue	$	683.8	$	1,026.8	$	—		$	1,710.6
Less: Intersegment revenue		461.8		27.9		—			489.7

Operating revenue		222.0		998.9		—			1,220.9
Cost of natural gas and natural gas liquids		67.2		970.8		—			1,038.0

Segment gross margin		154.8		28.1		—			182.9

Operating and maintenance		74.4		20.1		1.8			96.3
General and administrative		21.6		2.7		(2.0	)		22.3
Depreciation and amortization		32.4		1.9		—			34.3

		128.4		24.7		(0.2	)		152.9

Operating income		26.4		3.4		0.2			30.0

Income before income tax expense		26.4		3.4		0.2			30.0
Income tax expense		—		—		1.3			1.3

Net income (loss)	$	26.4	$	3.4	$	(1.1	)	$	28.7

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


	As of and for the nine month period ended September 30, 2013
	Gathering, Processing and Transportation		Logistics and Marketing			Corporate⁽¹⁾			Total
	(in millions)
Total revenue	$	2,034.0	$	3,580.0		$	—		$	5,614.0
Less: Intersegment revenue		1,491.0		72.7			—			1,563.7

Operating revenue		543.0		3,507.3			—			4,050.3
Cost of natural gas and natural gas liquids		101.7		3,451.7			—			3,553.4

Segment gross margin		441.3		55.6			—			496.9

Operating and maintenance		208.2		54.9			—			263.1
General and administrative		64.6		8.5			—			73.1
Depreciation and amortization		101.3		5.0			—			106.3

		374.1		68.4			—			442.5

Operating income (loss)		67.2		(12.8	)		—			54.4
Other income		—		—			0.2			0.2

Income (loss) before income tax expense		67.2		(12.8	)		0.2			54.6
Income tax expense		—		—			8.9			8.9

Net income (loss)	$	67.2	$	(12.8	)	$	(8.7	)	$	45.7

Total assets⁽²⁾	$	4,829.3	$	557.4		$	54.7		$	5,441.4

Capital expenditures (excluding acquisitions)	$	177.9	$	14.0		$	13.9		$	205.8

⁽¹⁾	Corporate consists of income taxes, which are not allocated to the business segments.

⁽²⁾	Totals assets for our Gathering, Processing and Transportation segment includes our long term equity investment in the Texas Express NGL system.


	As of and for the nine month period ended September 30, 2012
	Gathering, Processing and Transportation		Logistics and Marketing			Corporate⁽¹⁾			Total
	(in millions)
Total revenue	$	2,015.1	$	3,376.8		$	—		$	5,391.9
Less: Intersegment revenue		1,398.6		75.8			—			1,474.4

Operating revenue		616.5		3,301.0			—			3,917.5
Cost of natural gas and natural gas liquids		79.6		3,242.9			—			3,322.5

Segment gross margin		536.9		58.1			—			595.0

Operating and maintenance		209.7		60.3			1.8			271.8
General and administrative		63.9		15.8			(2.0	)		77.7
Depreciation and amortization		95.6		5.5			—			101.1

		369.2		81.6			(0.2	)		450.6

Operating income (loss)		167.7		(23.5	)		0.2			144.4
Other income (expense)		—		—			(0.1	)		(0.1	)

Income (loss) before income tax expense		167.7		(23.5	)		0.1			144.3
Income tax expense		—		—			2.1			2.1

Net income (loss)	$	167.7	$	(23.5	)	$	(2.0	)	$	142.2

Total assets⁽²⁾	$	4,372.1	$	903.6		$	138.3		$	5,414.0

Capital expenditures (excluding acquisitions)	$	317.8	$	3.1		$	10.8		$	331.7

⁽¹⁾	Corporate consists of income taxes, which are not allocated to the business segments.

⁽²⁾	Totals assets for our Gathering, Processing and Transportation segment includes our long term equity investment in the Texas Express NGL system.

10. SUPPLEMENTAL CASH FLOWS INFORMATION

The following table provides supplemental information for the item labeled “Other” in the “Cash provided by operating activities” section of our consolidated statements of cash flows.


	For the nine month period ended September 30,
	2013			2012
	(in millions)
Loss on sale of assets	$	1.1		$	—
Amortization of hedging costs		0.3			2.5
Allowance for doubtful accounts		0.2			—
Write-down of project costs		—			4.3
Environmental costs, net of recoveries		(0.1	)		—
Texas Express long-term inventory (line fill)		(1.3	)		—
Other		(0.1	)		(0.1	)

	$	0.1		$	6.7

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


	For the nine month period ended September 30,
	2013			2012
	(in millions)
Additions to property, plant and equipment	$	206.6		$	315.1
Increase (decrease) in construction payables		(0.8	)		16.6

Total capital expenditures (excluding “Investment in joint venture”)	$	205.8		$	331.7

11. SUBSEQUENT EVENTS

Initial Public Offering

On November 13, 2013, the Partnership completed the Offering, as discussed in Note 1.Organization and Nature of Operations.

Contribution, Conveyance and Assumption Agreement

On November 13, 2013, in connection with the closing of the Offering, the following transactions, among others, occurred pursuant to a contribution, conveyance and assumption agreement, or the Contribution Agreement, by and among EEP, the Partnership, the General Partner, Midcoast Operating and OLP GP:

•

EEP conveyed a portion of its limited partner interest in Midcoast Operating to the General Partner as a capital contribution with a value equal to 2.0% of the equity value of the Partnership after the Offering, or the GP Contribution Interest;

•

the General Partner conveyed the GP Contribution Interest to the Partnership in exchange for (1) 922,859 general partner units in the Partnership, representing a continuation of its 2.0% general partner interest in the Partnership and (2) the Incentive Distribution Rights in the Partnership;

•

EEP conveyed (1) all of its limited liability company interests in the OLP GP and (2) a limited partner interest in Midcoast Operating equal to 39.0% less the percentage of the GP Contribution Interest to the Partnership in exchange for (a) 4,110,056 Class A common units representing a 9.0% limited partner interest in the Partnership, (b) 22,610,056 subordinated units representing a 49.0% limited partner interest in the Partnership and (c) the right to receive $323.4 million in cash, and (d) the right to receive $304.5 million in cash as reimbursement for certain capital expenditures made with respect to certain assets of Midcoast Operating and the OLP GP;

•

the public, through the underwriters, contributed $333.0 million in cash (or $311.8 million net of the underwriters’ discount and commissions of $20.0 million and a structuring fee of $1.2 million payable to Merrill Lynch, Pierce, Fenner & Smith Incorporated) to the Partnership in exchange for 18,500,000 Class A common units; and

•

the Partnership redeemed the initial limited partner interests of EEP and refunded EEP’s initial contribution, as well as any interest or other profit that may have resulted from the investment or other use of such initial capital contribution.

Pursuant to the Contribution Agreement, upon the exercise of the Over-Allotment Option (as defined in the Contribution Agreement), the Partnership used the net proceeds from that exercise to redeem from EEP the number of Class A common units MEP issues to the underwriters upon such exercise.

Omnibus Agreement

On November 13, 2013, in connection with the closing of the Offering, the Partnership entered into an Omnibus Agreement, or the Omnibus Agreement, by and among the General Partner, the Partnership, EEP and Enbridge, pursuant to which EEP will indemnify the Partnership for certain matters, including environmental, right-of-way and permit matters, and EEP will grant the Partnership a license to use the Enbridge logo and certain other trademarks and trade names.

Credit Agreement

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

The Credit Agreement is a committed senior revolving credit facility with related letter of credit and swing line facilities that permits aggregate borrowings of up to, at any one time outstanding, $850.0 million, including up to (1) initially $90.0 million under the letter of credit facility and (2) $75.0 million under the swing line facility. Subject to customary conditions, the Partnership may request that the lenders’ aggregate commitments be increased to an amount not to exceed $1.0 billion. The facility matures in three years, subject to four one-year requests for extension.

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

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

The Credit Agreement also contains customary representations, warranties, events of default, indemnities and remedies provisions.

Additionally, the Credit Agreement contains various covenants and restrictive provisions which limit the ability of the Partnership, Midcoast Operating and their subsidiaries to incur certain liens or permit them to exist, merge or consolidate with another company, dispose of assets, make distributions on or redeem or repurchase their equity interests, incur or guarantee additional debt, repay subordinated debt prior to maturity, make certain investments and acquisitions, alter their lines of business, enter into certain types of transactions with affiliates and enter into agreements that restrict their ability to perform certain obligations under the Credit Agreement or to make payments to a borrower or any of their material subsidiaries.

The Credit Agreement also requires compliance with two financial covenants. The Partnership must not permit the ratio of consolidated funded debt to pro forma Earnings Before Interest, Taxes, Depreciation and Amortization, or EBITDA, or the Total Leverage Ratio, of the Partnership and its consolidated subsidiaries, including Midcoast Operating, as of the end of any applicable four-quarter period, to exceed 5.00 to 1.00, or 5.50 to 1.00 during acquisition periods. The Partnership also must maintain, on a consolidated basis, as of the end of each applicable four-quarter period, a ratio of pro forma EBITDA to consolidated interest expense for such four-quarter period then ended of at least 2.50 to 1.00.

These covenants are subject to exceptions and qualifications set forth in the Credit Agreement. At such time as the Partnership obtains an investment grade rating from either Moody’s or S&P, certain covenants under the Credit Agreement will no longer be applicable to either the borrowers or the guarantors, or in some instances, any of them, including, but not limited to, the obligation to provide security in certain circumstances, certain restrictions on liens, investments and debt, and restrictions on dispositions.

Intercorporate Services Agreement

On November 13, 2013, in connection with the closing of the Offering, the Partnership entered into an Intercorporate Service Agreement, or the Intercorporate Services Agreement, with EEP, pursuant to which EEP will provide the Partnership with the following services:

•

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

•

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

•

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

•

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

•

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

•

such other services as the Partnership may request.

Under the Intercorporate Services Agreement, the Partnership will reimburse EEP and its affiliates for the costs and expenses incurred in providing such services to the Partnership. The allocation methodology under which the Partnership will reimburse EEP and its affiliates for the provision of general administrative and operational services to Midcoast Operating will not differ from what Midcoast Operating was allocated historically under its prior services agreements with Enbridge and certain of its affiliates that were in effect prior to the Intercorporate Services Agreement. However, EEP has agreed to reduce the amounts payable for general and administrative expenses that otherwise would have been allocable to Midcoast Operating by $25.0 million annually. Based on the Partnership’s 39% interest in Midcoast Operating, the reduction in amounts payable for general and administrative services attributable to the Partnership will be approximately $9.8 million annually and will continue for the term of the agreement.

Financial Support Agreement

On November 13, 2013, in connection with the closing of the Offering, Midcoast Operating entered into a Financial Support Agreement, or the Financial Support Agreement, between Midcoast Operating and EEP, pursuant to which EEP will provide letters of credit and guarantees, not to exceed $700.0 million in the aggregate at any time outstanding, in support of Midcoast Operating’s and its wholly owned subsidiaries’ financial obligations under derivative agreements and natural gas and NGL purchase agreements to which Midcoast Operating, or one or more of its wholly owned subsidiaries, is a party. This agreement terminates after four years, or earlier, when EEP owns less than 20% of the limited partnership interests in Midcoast Operating.

The annual costs that Midcoast Operating initially estimates that it will incur under the Financial Support Agreement range from approximately $4.0 million to $5.0 million and are based on the cumulative average amount of letters of credit and guarantees that EEP will provide on Midcoast Operating’s and its wholly owned subsidiaries’ behalf multiplied by a 2.5% annual fee. If the Credit Agreement is secured, the Financial Support Agreement will also be secured to the same extent on a second-lien basis.

Amended and Restated Allocation Agreement

On November 13, 2013, in connection with the closing of the Offering, the Partnership entered into an Amended and Restated Allocation Agreement, or the Insurance Allocation Agreement, by and among the Partnership, Enbridge, EEP and Enbridge Income Fund Holdings Inc., in order to participate in the comprehensive insurance program that is maintained by Enbridge for it and its subsidiaries. Under this agreement, in the unlikely event that multiple insurable incidents occur that exceed coverage limits within the same insurance period, the total insurance coverage available to Enbridge and its subsidiaries under the insurance program will be allocated among the participating Enbridge entities on an equitable basis.

Working Capital Credit Facility

On November 13, 2013, in connection with the closing of the Offering, Midcoast Operating entered into a $250.0 million Working Capital Loan Agreement, or the Working Capital Credit Facility, by and between Midcoast Operating, as borrower, and EEP, as lender. The facility is available exclusively to fund working capital borrowings. Borrowings under the facility are scheduled to mature on November 13, 2017 and accrue interest at a per annum rate of LIBOR plus 2.5%. Midcoast Operating has agreed to pay a commitment fee on the

unused commitment at a per annum rate of 0.4250%, payable each fiscal quarter. EEP’s commitment to lend pursuant to the Working Capital Credit Facility will end on the earlier of the maturity date and the date on which EEP owns less than a 20% limited partner interest in Midcoast Operating. If EEP’s commitment to lend has terminated before the facility has matured (by acceleration or otherwise), then the aggregate amount of all outstanding borrowings under the facility will automatically convert to a term loan that will bear interest at LIBOR (calculated as of the conversion date) plus 2.5%. The Working Capital Credit Facility also contains certain customary representations, warranties, indemnities, events of default and remedies provisions and also provides that if the Credit Agreement is secured, the Working Capital Credit Facility also will be secured to the same extent on a second-lien basis.

Amended and Restated Agreement of Limited Partnership of Midcoast Operating, L.P.

On November 13, 2013, in connection with the closing of the Offering, the OLP GP, the Partnership and EEP entered into the Amended and Restated Agreement of Limited Partnership of Midcoast Operating, or as amended and restated, the Midcoast Operating LP Agreement. Based on the Partnership’s sole ownership of the OLP GP, it has the sole responsibility for managing the operations of Midcoast Operating. However, the Midcoast Operating LP Agreement provides that certain actions of Midcoast Operating will require the unanimous approval of all the partners. These actions include the following:

•

any reorganization, merger, consolidation or similar transaction;

•

any new class of partnership interests or the issuance of any additional partnership interests;

•

any admission or withdrawal of any person as partner other than in accordance with the Midcoast Operating LP Agreement;

•

any modification, alteration or amendment of the amount, timing, frequency or method of calculation of distributions to the partners;

•

any sale or lease of all or substantially all of Midcoast Operating’s assets;

•

causing or permitting Midcoast Operating to file an application for bankruptcy; and

•

approving any distribution and determination of value by Midcoast Operating of any assets in kind or the approval of any distribution of any cash or property on a non-pro rata basis.

Under the Midcoast Operating LP Agreement, the Partnership and EEP each have the option to contribute its proportionate share of additional capital to Midcoast Operating if any additional capital contributions are necessary to fund capital expenditures or other growth projects. To the extent that the Partnership or EEP elect not to make any such capital contributions, the contributing party will be permitted to make additional capital contributions in exchange for additional interests in Midcoast Operating.

The Midcoast Operating LP Agreement provides that Midcoast Operating will distribute all distributable cash of Midcoast Operating to the Partnership and EEP on a pro rata basis within 45 days of the end of each quarter.

First Amended and Restated Agreement of Limited Partnership of Midcoast Energy Partners, L.P.

On November 13, 2013, in connection with the closing of the Offering, the Partnership amended and restated its agreement of limited partnership and entered into its First Amended and Restated Agreement of Limited Partnership, or as amended and restated, the Partnership Agreement. A description of the Partnership Agreement is contained in the Prospectus in the sections entitledProvisions of Our Partnership Agreement Relating to Cash Distributions andOur Partnership Agreement, all of which are incorporated herein by reference.

Exercise of the Underwriters’ Option

On December 9, 2013, the Partnership closed the sale of an additional 2,775,000 Class A common units representing limited partner interests in connection with the Offering. The Partnership used the net proceeds of approximately $47.0 million from the exercise of the option to redeem 2,775,000 Class A common units from EEP. Upon redemption of the Class A common units from EEP, the public owned a 46% limited partner interest in Midcoast Partners. EEP, through certain of its subsidiaries, holds a 2% general partner interest and owns the remaining limited partner interest in Midcoast Partners.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and results of operations is based on and should be read in conjunction with our consolidated financial statements and the accompanying notes included in Item 1.Financial Statements and in conjunction with the audited consolidated financial statements and accompanying footnotes in our prospectus related to the initial public offering of Midcoast Energy Partners, L.P. dated November 6, 2013, as filed with the SEC on November 8, 2013, or the Prospectus. On November 13, 2013, we completed our initial public offering, or the Offering, of 18,500,000 Class A common units representing limited partner interests in the Partnership at $18.00 per Common Unit pursuant to a Registration Statement on Form S-1, as amended, initially filed by the Partnership with the SEC on June 14, 2013, including the Prospectus.

RESULTS OF OPERATIONS OF MIDCOAST OPERATING, L.P.—Predecessor—OVERVIEW

We provide services to our customers and returns for our unitholders primarily through the following activities:

•

Gathering, treating, processing and transportation of natural gas and natural gas liquids, or NGLs, through pipelines and related facilities; and

•

Supply, transportation and sales services, including purchasing and selling natural gas and NGLs.

We conduct our business through two business segments: Gathering, Processing and Transportation; and Logistics and Marketing. These segments are strategic business units established by senior management to facilitate the achievement of our long-term objectives, to aid in resource allocation decisions and to assess operational performance.

The following table reflects our operating income by business segment and corporate charges for each of the three and nine month periods ended September 30, 2013 and 2012.


	For the three month period ended September 30,					For the nine month period ended September 30,
	2013			2012		2013			2012
	(unaudited; in millions)
Operating income (loss)
Gathering, Processing and Transmission	$	10.7		$	26.4	$	67.2		$	167.7
Logistics and Marketing		(23.6	)		3.4		(12.8	)		(23.5	)
Corporate, operating and administrative		—			0.2		—			0.2

Total operating income (loss)		(12.9	)		30.0		54.4			144.4
Other income (expense)		—			—		0.2			(0.1	)

Income (loss) before income tax expense		(12.9	)		30.0		54.6			144.3
Income tax expense		0.6			1.3		8.9			2.1

Net income (loss)	$	(13.5	)	$	28.7	$	45.7		$	142.2

Contractual arrangements in our Gathering, Processing and Transportation segment and our Logistics and Marketing segment expose us to market risks associated with changes in commodity prices where we receive NGLs in return for the services we provide or where we purchase natural gas or NGLs. Our unhedged commodity position is fully exposed to fluctuations in commodity prices, which can be significant during periods of price volatility. We employ derivative financial instruments to hedge a portion of our commodity position and to reduce our exposure to fluctuations in natural gas and NGL prices. Some of these derivative financial instruments do not qualify for hedge accounting under the provisions of authoritative accounting guidance, which can create volatility in our earnings that can be significant. However, these fluctuations in earnings do not affect our cash flow. Cash flow is only affected when we settle the derivative instrument.

Summary Analysis of Operating Results

Gathering, Processing and Transportation

The operating income of our Gathering, Processing and Transportation segment for the three and nine month periods ended September 30, 2013 decreased $15.7 million and $100.5 million, respectively, when compared to the same periods in 2012, primarily due to the following:

•

Decreased operating income of $14.4 million and $46.9 million for the three and nine month periods ended September 30, 2013, respectively, due to reduced pricing spreads between our Conway and Mont Belvieu market hubs;

•

Decreased operating income of $4.6 million and $17.8 million for the three and nine month periods ended September 30, 2013, respectively, primarily due to reduced average daily volumes on our major systems when compared to the same periods of 2012;

•

Decreased operating income from keep-whole processing earnings of $3.3 million and $25.5 million, respectively, when compared to the same periods in 2012, due to a decline in total NGL production, when compared to the same periods in 2012;

•

Decreased operating income of $7.9 million for the nine month period ended September 30, 2013, for non-cash, mark-to-market net losses from derivative instruments that do not qualify for hedge accounting treatment, when compared to the same period in 2012; and

•

Increased depreciation and amortization expense of $1.7 million and $5.7 million, for the three and nine month periods ended September 30, 2013, respectively, as compared with the same periods in 2012, due to additional assets that were put in service.

The above factors were partially offset for the three and nine month periods ended September 30, 2013, as compared with the same periods in 2012 primarily due to:

•

Increased operating income of $10.7 million for the three month period ended September 30, 2013, for non-cash, mark-to-market net gains from derivative instruments that do not qualify for hedge accounting treatment, when compared to the same period in 2012; and

•

Decreased current year operating and administrative costs of $4.3 million for the three and nine month periods ended September 30, 2013 for the write down of surplus materials associated with the previously deferred portions of the Haynesville expansion within our East Texas system recorded in 2012, with no similar costs recorded during 2013.

Logistics and Marketing

The operating income of our Logistics and Marketing segment for the three month period ended September 30, 2013 decreased $27.0 million when compared to the same period in 2012, primarily due to net losses associated with our derivative instruments and a less favorable NGL pricing environment.

The operating income of our Logistics and Marketing segment for the nine month period ended September 30, 2013 increased $10.7 million when compared to the same period in 2012 due to reduced non-cash charges to inventory for the nine month period ended September 30, 2013, when compared to the same period in September 30, 2012, which we recorded to reduce the cost basis of our natural gas inventory to net realizable value. Also contributing to the increase was the expiration of certain transportation fees for natural gas being transported on a third party pipeline. General and administrative costs also decreased for the nine month period ended September 30, 2013, compared to the nine month period ended September 30, 2012, primarily due to costs we incurred in 2012 for the investigation of accounting irregularities at our trucking and NGL marketing subsidiary.

Derivative Transactions and Hedging Activities

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 variability 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 record all derivative instruments in our consolidated financial statements at fair market value pursuant to the requirements of applicable authoritative accounting guidance. We record changes in the fair value of our derivative financial instruments that do not qualify for hedge accounting in our consolidated statements of income as “Operating revenue” and “Cost of natural gas and natural gas liquids”.

The changes in fair value of our derivatives are also presented as a reconciling item on our consolidated statements of cash flows. The following table presents the net changes in fair value associated with our derivative financial instruments:


	For the three month period ended September 30,						For the nine month period ended September 30,
	2013			2012			2013			2012
	(unaudited; in millions)
Gathering, Processing and Transportation segment
Hedge ineffectiveness	$	(0.5	)	$	(3.9	)	$	1.8		$	1.2
Non-qualified hedges		(5.1	)		(12.4	)		1.4			9.9
Logistics and Marketing segment
Non-qualified hedges		(29.1	)		(8.3	)		(17.1	)		(3.2	)

Derivative fair value net gains (losses)	$	(34.7	)	$	(24.6	)	$	(13.9	)	$	7.9

Gathering, Processing and Transportation

The following tables set forth the operating results of our Gathering, Processing and Transportation segment and approximate average daily volumes of natural gas throughput and NGLs produced on our major systems for the periods presented:


	For the three month period ended September 30,				For the nine month period ended September 30,
	2013		2012		2013		2012
	(unaudited; in millions)
Operating revenues	$	171.4	$	222.0	$	543.0	$	616.5
Cost of natural gas and natural gas liquids		33.5		67.2		101.7		79.6

Segment gross margin		137.9		154.8		441.3		536.9

Operating and maintenance		71.0		74.4		208.2		209.7
General and administrative		22.1		21.6		64.6		63.9
Depreciation and amortization		34.1		32.4		101.3		95.6

Operating expenses		127.2		128.4		374.1		369.2

Operating income	$	10.7	$	26.4	$	67.2	$	167.7


Operating Statistics Throughput (MMBtu/d)
East Texas		1,120,000		1,219,000		1,201,000		1,276,000
Anadarko		957,000		1,065,000		963,000		1,023,000
North Texas		314,000		343,000		326,000		330,000

Total		2,391,000		2,627,000		2,490,000		2,629,000

NGL Production (Bpd)		88,907		98,528		89,620		92,364

Three month period ended September 30, 2013 compared with three month period ended September 30, 2012

The operating income of our Gathering, Processing and Transportation segment for the three month period ended September 30, 2013 decreased $15.7 million, as compared with the same period in 2012. The most significant area affected was segment gross margin, which decreased $16.9 million for the three month period ended September 30, 2013, as compared with the same period in 2012.

The gross margin for our Gathering, Processing and Transportation segment was affected by the reduction in gross margin derived from purchasing some of our NGLs at the Conway market hub and selling them at the Mont Belvieu market hub. On our Anadarko system, we purchase certain NGL components at Conway hub prices and then have the option to resell those same NGL components at Mont Belvieu hub prices. For the three months ended September 30, 2013, the prevailing price for NGLs increased approximately 1% per composite barrel at the Mont Belvieu pricing hub, while increasing approximately 18% per composite barrel at the Conway pricing hub, in each case as compared with the prevailing composite barrel prices for the same period in 2012. The gross margin of our Gathering, Processing and Transportation segment decreased by approximately $14.4 million for the three months ended September 30, 2013 compared with the same period in 2012 due to the changes in NGL prices between these pricing hubs.

Another factor in the decrease in gross margin for the three month period ended September 30, 2013 were losses of $4.6 million primarily due to reduced production volumes. The average daily volumes of our major systems, for the three month period ended September 30, 2013, decreased by approximately 236,000 MMBtu/d, or 9%, when compared to the same period in 2012.

A variable element of the operating results of our Gathering, Processing and Transportation segment is derived from processing natural gas on our systems. Under percentage of liquids, or POL, contracts, we are required to pay producers a contractually fixed recovery of NGLs regardless of the NGLs we physically produce or our ability to process the NGLs from the natural gas stream. NGLs that are produced in excess of this contractual obligation in addition to the barrels that we produce under traditional keep-whole gas processing arrangements we refer to collectively as keep-whole earnings. Operating revenue less the cost of natural gas derived from keep-whole earnings for the three month period ended September 30, 2013 decreased $3.3 million from the same period in 2012. The decline in keep-whole earnings is the result of a decline in total NGL production.

Partially offsetting the overall decrease in gross margin, for the three month period ended September 30, 2013, were reductions in non-cash, mark-to-market net losses of $10.7 million from non-qualifying commodity derivatives we use to economically hedge a portion of the natural gas resulting from the operating activities of our Gathering, Processing and Transportation segment. Decreases in the average forward prices of natural gas from June 30, 2013 to September 30, 2013 produced the decrease in non-cash, mark-to-market net losses, when compared to the same period in 2012. We use forward contracts to fix the price of natural gas we purchase and store in inventory and to fix the price of natural gas that we sell from inventory to meet the demands of our customers that sell and purchase natural gas.

The operating and maintenance costs of our Gathering, Processing and Transportation segment decreased approximately $3.4 million for the three month period ended September 30, 2013 compared to the same period in 2012, primarily due to a $4.3 million adjustment recorded in the third quarter of 2012 to write down project line pipe to net realizable value, as well as, expense development, engineering and other costs associated with a project in East Texas. Due to lower levels of producer activity in the East Texas region, this project was deferred to a later date and it was determined that these costs and line pipe have no future benefit. As such, these costs were expensed and the line pipe written down for the period ended September 30, 2012. There were no similar adjustments for the same period in 2013.

The general and administrative costs of our Gathering, Processing and Transportation segment for the three month period ended September 30, 2013 slightly increased compared with the same period in 2012.

The depreciation and amortization expense of our Gathering, Processing and Transportation segment increased approximately $1.7 million for the three month period ended September 30, 2013 compared with the same period of 2012, primarily due to depreciation associated with the Ajax plant, which began commissioning the operations during the three months ended September 30, 2013, in addition to depreciation associated with other assets we placed into service and began depreciating after September 30, 2012.

Nine month period ended September 30, 2013 compared with nine month period ended September 30, 2012

The primary factors affecting the operating income of our Gathering, Processing and Transportation segment for the nine month period ended September 30, 2013, as compared with the same period of 2012, are the same as noted in our three month analysis in addition to the factors discussed below.

Non-cash, mark-to-market net gains decreased $7.9 million for the nine month period ended September 30, 2013, when compared to the same period in 2012, due to fractionation margins, representing the relative difference between the price we receive from the sale of NGLs and condensate and the corresponding cost of natural gas we purchase for processing, widened during the nine month period ended September 30, 2013, when compared to the same period in 2012, as a result of lower natural gas forward prices.

Future Prospects for Gathering, Processing and Transportation

We are currently pursuing several expansion projects that are designed to increase natural gas processing, NGL production and natural gas and NGL transportation capacity. The following table and discussion summarizes our projects, which we have recently placed into service or expect to place into service in future periods:

Project

Estimated
Capital Costs

In-service Date

Funding

(in millions)

Ajax Cryogenic Processing Plant

230

Q3 2013

EEP

Texas Express NGL system

400

Q4 2013

Joint

⁽¹⁾

Beckville Cryogenic Processing Plant

145

Early 2015

EEP

⁽¹⁾	We own a 35% joint venture interest in the Texas Express NGL system. Estimated capital costs represent 35% of the total projected costs associated with constructing both the mainline and the gathering system.

Subsequent to the Offering, the above projects will be funded by the Partnership and EEP based on their proportionate ownership percentages in Midcoast Operating going forward.

Ajax Cryogenic Processing Plant

We expect development of the Granite Wash play in the Texas Panhandle and western Oklahoma to continue due to the prolific nature of the wells, current market prices for NGLs and crude oil and the application of horizontal drilling and fracturing technology to the formation. In order to accommodate the expected growth of the Granite Wash play, we began commissioning the operations of a cryogenic processing plant in the third quarter of 2013, which we refer to as our Ajax processing plant. The Ajax processing plant, condensate stabilizer, field and plant compression, gathering infrastructure and NGL pipelines assist in meeting the anticipated volume growth within our Anadarko system. The total cost of constructing the Ajax processing plant and related facilities was approximately $230 million. The Ajax processing plant increases the total processing capacity of our Anadarko system by approximately 150 million cubic feet per day, or MMcf/d, to approximately 1,150 MMcf/d and also increases the system’s condensate stabilization capacity by approximately 2,000 barrels per day, or Bpd. The Ajax processing plant is capable of producing approximately 15,000 Bpd of NGLs now that the Texas Express NGL pipeline, which we refer to as the mainline, was completed and put into operation during the fourth quarter of 2013 discussed below.

Texas Express NGL System

On October 31, 2013, we, Enterprise Product Partners L.P., or Enterprise, Anadarko Petroleum Corporation, or Anadarko, and DCP Midstream Partners, LP, or DCP Midstream, announced the start of service on the Texas Express NGL system, which consists of two separate joint ventures with third parties to design and construct a new NGL pipeline, or mainline, and NGL gathering system. The joint venture ownership of the mainline portion of the Texas Express NGL system is owned 35% by Enterprise, 35% by us, 20% by Anadarko and 10% by DCP Midstream. The joint venture ownership of the new NGL gathering system is owned 45% by Enterprise, 35% by us and 20% by Anadarko. Enterprise constructed and serves as the operator of the mainline, while we constructed and operate the new gathering system.

The Texas Express NGL pipeline originates near Skellytown, Texas in the Texas Panhandle and extends approximately 580 miles to NGL fractionation and storage facilities in the Mont Belvieu area on the Texas Gulf Coast. The mainline has an initial capacity of approximately 280,000 Bpd and is expandable to approximately 400,000 Bpd with additional pump stations on the system. There are currently capacity reservations on the mainline that, when fully phased in, will total approximately 250,000 Bpd. The new NGL gathering system initially consists of approximately 116 miles of gathering lines that connect the mainline to natural gas processing plants in the Anadarko/Granite Wash production area located in the Texas Panhandle and western Oklahoma and to Barnett Shale processing plants in North Texas. The gathering system is currently expected to include 270 miles of gathering lines by 2019. Volumes from the Rockies, Permian Basin and Mid-Continent regions will be delivered to the Texas Express NGL system utilizing Enterprise’s existing Mid-America Pipeline assets between the Conway hub and Enterprise’s Hobbs NGL fractionation facility in Gaines County, Texas. In addition, volumes from and to the Denver-Julesburg Basin in Weld County, Colorado are able to access the Texas Express NGL system through the connecting Front Range Pipeline which is being constructed by Enterprise, DCP Midstream and Anadarko.

We expect that the Texas Express NGL system will serve as a link between growing supply sources of NGLs in the Anadarko and Permian basins and the Mid-Continent and Rockies regions of the United States and the primary demand markets on the U.S. Gulf Coast. We expect our total contributions to be approximately $400 million for the construction of the Texas Express NGL system.

Beckville Cryogenic Processing Plant

In April 2013, we announced plans to construct a cryogenic natural gas processing plant near Beckville in Panola County, Texas, which we refer to as the Beckville processing plant. This plant is expected to serve existing and prospective customers pursuing production in the Cotton Valley formation, which is comprised of approximately ten counties in East Texas and has been a steady producer of natural gas for decades. Production from this play typically contains two to three gallons of NGLs per Mcf. The region currently produces approximately 1.8 billion cubic feet per day, or Bcf/d, of natural gas with 72,000 Bpd of associated NGLs. Until recently, the primary exploitation method in the Cotton Valley formation has been vertical wells. Lower horizontal drilling costs, coupled with the latest fracturing technology, has brought significant interest back to this area. Economics associated with horizontal wells in the Cotton Valley formation compare favorably to other rich natural gas plays, which has encouraged producers to increase drilling activity in the region. We expect our Beckville processing plant to be capable of processing approximately 150 MMcf/d of natural gas and producing approximately 8,500 Bpd of NGLs to accommodate the additional liquids-rich natural gas being developed within this geographical area in which our East Texas system operates. In the third quarter of 2013, we initiated construction activities at our Beckville processing plant and the related facilities on our East Texas system. We estimate the cost of constructing the plant to be approximately $145 million and expect it to commence service in early 2015.

Logistics and Marketing

The following table sets forth the operating results of our Logistics and Marketing segment for the periods presented:


	For the three month period ended September 30,					For the nine month period ended September 30,
	2013			2012		2013			2012
	(unaudited; in millions)
Operating revenues	$	1,209.5		$	998.9	$	3,507.3		$	3,301.0
Cost of natural gas and natural gas liquids		1,210.8			970.8		3,451.7			3,242.9

Segment gross margin		(1.3	)		28.1		55.6			58.1

Operating and maintenance		17.7			20.1		54.9			60.3
General and administrative		2.9			2.7		8.5			15.8
Depreciation and amortization		1.7			1.9		5.0			5.5

Operating expenses		22.3			24.7		68.4			81.6

Operating income (loss)	$	(23.6	)	$	3.4	$	(12.8	)	$	(23.5	)

Our Logistics and Marketing segment derives a majority of its operating income from selling natural gas received from producers on our Gathering, Processing and Transportation segment pipeline assets to customers utilizing the natural gas. A majority of the natural gas we purchase is produced in Texas markets where we have expanded access to several interstate natural gas pipelines over the past several years, which we can use to transport natural gas to primary markets where it can be sold to major natural gas customers.

Three month period ended September 30, 2013 compared with three month period ended September 30, 2012

The operating income of our Logistics and Marketing segment for the three month period ended September 30, 2013 decreased $27.0 million, as compared with the same period in 2012. The most significant area affected was segment gross margin, representing revenue less cost of natural gas and natural gas liquids, which decreased $29.4 million for the three month period ended September 30, 2013, as compared with the same period in 2012.

Our segment gross margin was negatively impacted by increases in the average forward prices of NGLs from June 30, 2013 to September 30, 2013, which produced non-cash, mark-to-market net losses of $20.8 million, when compared to the same period in 2012, from the non-qualifying commodity derivatives we use to economically hedge a portion of the NGLs resulting from the operating activities of our Logistics and Marketing segment. We use forward contracts to fix the price of NGLs we purchase and store in inventory and to fix the price of NGLs that we sell from inventory to meet the demands of our customers that sell and purchase NGLs.

Additionally, the gross margin was negatively impacted by fewer opportunities to benefit from price differentials between market centers for the three month period ended September 30, 2013, when compared to the same period of 2012, as a result of downward pressure on current NGL prices, particularly ethane and propane.

Operating and maintenance costs of our Logistics and Marketing segment were $2.4 million lower for the three month period ended September 30, 2013 compared with the three month period ended September 30, 2012, due to reduced outside contract labor costs and lower maintenance activities on existing trucks and trailers resulting from a more updated fleet.

General and administrative costs of our Logistics and Marketing segment were relatively flat for the three month period ended September 30, 2013 when compared with the three month period ended September 30, 2012.

Depreciation and amortization expense for the three month period ended September 30, 2013 was slightly lower than depreciation and amortization expense for the three month period ended September 30, 2012 due to the retirement of older equipment and greater use of third-party contract truck owner-operators.

Nine month period ended September 30, 2013 compared with nine month period ended September 30, 2012

The components comprising our operating results changed during the nine month period ended September 30, 2013, compared to the same period in 2012, for primarily the same reasons as in the three month analysis, in addition to the factors discussed below.

Operating results for the current year were positively affected by only $3.3 million of non-cash charges to inventory for the nine month period ended September 30, 2013, compared to $9.8 million for the same period in September 30, 2012, which we recorded to reduce the cost basis of our natural gas inventory to net realizable value. Since we hedge our storage positions financially, these charges are recovered when the physical natural gas inventory is sold or the financial hedges are realized.

Also contributing to the increase in operating results for the nine month period ended September 30, 2013, was the expiration of certain transportation fees for natural gas being transported on a third party pipeline. These transportation fees expired, effective June 30, 2012, and reduced natural gas expense by approximately $2.0 million for the nine month period ended September 30, 2013, as compared to the same period in 2012.

General and administrative costs of our Logistics and Marketing segment decreased $7.3 million for the nine month period ended September 30, 2013, compared to the nine month period ended September 30, 2012, primarily due to costs we incurred in 2012 for the investigation of accounting irregularities at our trucking and NGL marketing subsidiary.

Corporate

Our corporate activities consist of interest expense, interest income, allowance for equity during construction, referred to as AEDC, and other costs such as income taxes, which are not allocated to the business segments.


	For the three month period ended September 30,						For the nine month period ended September 30,
	2013			2012			2013			2012
	(unaudited; in millions)
Operating and maintenance	$	—		$	1.8		$	—		$	1.8
General and administrative		—			(2.0	)		—			(2.0	)

Operating expenses		—			(0.2	)		—			(0.2	)

Operating income		—			0.2			—			0.2
Other income (expense)		—			—			0.2			(0.1	)
Income tax expense		0.6			1.3			8.9			2.1

Net loss	$	(0.6	)	$	(1.1	)	$	(8.7	)	$	(2.0	)

The interest cost we recognize is an allocation of Enbridge Energy Partners, L.P., or EEP’s, cost and is directly offset by the amount of interest cost we capitalize on outstanding construction projects. Historically, EEP incurred third-party interest costs, which we recognized to the extent we were able to capitalize such costs to our construction projects.

Our interest cost for the three and nine month periods ended September 30, 2013 and 2012 is comprised of the following:


	For the three month period ended September 30,				For the nine month period ended September 30,
	2013		2012		2013		2012
	(unaudited; in millions)
Interest expense	$	5.1	$	1.6	$	16.6	$	4.6
Interest capitalized		5.1		1.6		16.6		4.6

Interest cost incurred	$	—	$	—	$	—	$	—

Interest cost paid	$	5.1	$	1.6	$	16.6	$	4.6

Three month period ended September 30, 2013 compared with three month period ended September 30, 2012

We are not a taxable entity for U.S. federal income tax purposes or for the majority of states that impose an income tax. Taxes on our net income are typically borne by our partners through the allocation of taxable income. Texas imposes taxes that are based upon many, but not all, items included in net income. Our income tax expense was $0.6 million for the three month period ended September 30, 2013 compared to $1.3 million for the three month period ended September 30, 2012. The decrease in income tax expense was primarily due to an increase in expenses allowed under Texas Margin Tax law due to the passage by the Texas Legislature of House Bill 500, which resulted in a decrease in taxable income, as discussed in Note 8.Income Taxes.

Nine month period ended September 30, 2013 compared with nine month period ended September 30, 2012

For the nine month period ended September 30, 2013 our income tax expense was $8.9 million compared to $2.1 million for the nine month period ended September 30, 2012. The increase in income tax expense was primarily due to $6.6 million of income tax expense recognized for the nine month period ended September 30, 2013 related to a new law enacted by the State of Texas in June 2013 that modifies the computation of income tax we will pay.

LIQUIDITY AND CAPITAL RESOURCES

Historically, our sources of liquidity included cash generated from operations and funding from EEP. We were dependent upon EEP and its affiliates for our treasury services. Going forward, we will have separate bank accounts, but EEP will provide treasury services on our General Partner’s behalf under an intercorporate services agreement that we entered into with EEP at the closing of the Offering. Under the intercorporate services agreement, EEP has agreed to reduce the amounts payable for general and administrative expenses that otherwise would be fully allocable to Midcoast Operating by $25.0 million annually following the closing of the Offering. In addition, at the close of the offering, Midcoast Operating entered into a Financial Support Agreement (the “Financial Support Agreement”), between Midcoast Operating and EEP, pursuant to which EEP will provide letters of credit and guarantees, not to exceed $700.0 million in the aggregate at any time outstanding, in support of Midcoast Operating’s and its wholly owned subsidiaries’ financial obligations under derivative agreements and natural gas and NGL purchase agreements to which Midcoast Operating, or one or more of its wholly owned subsidiaries, is a party.

We expect our ongoing sources of liquidity to include cash generated from operations of Midcoast Operating, borrowings under Midcoast Operating’s working capital credit facility, borrowings under our revolving credit facility and issuances of additional debt and equity securities. We believe that cash generated from these sources will be sufficient to meet our short-term working capital requirements and long-term capital expenditure requirements and to make quarterly cash distributions to our unitholders.

Revolving Credit Facility

At the closing of the Offering, we and Midcoast Operating, as co-borrowers, and our material subsidiaries, as guarantors, entered into a credit agreement with Bank of America, N.A., as administrative agent, letter of credit issuer, swing line lender and lender, and each of the other lenders party thereto. The credit agreement is a committed senior revolving credit facility (with related letter of credit and swing line facilities) that permits aggregate borrowings of up to, at any one time outstanding, $850.0 million, including up to (i) $90.0 million under the letter of credit facility and (ii) $75.0 million under the swing line facility. Subject to customary conditions, we may request that the lenders’ aggregate commitments be increased to an amount not to exceed $1.0 billion. The facility matures in three years, subject to four requests for one-year extensions.

Loans under the Credit Agreement accrue interest at a per annum rate by reference, at our election, to the Eurodollar rate, which is equal to the LIBOR rate or a comparable or successor rate reasonably approved by the Administrative Agent, or base rate, in each case, plus an applicable margin. The applicable margin on Eurodollar (LIBOR) rate loans ranges from 1.75% to 2.75% and the applicable margin on base rate loans ranges from 0.75% to 1.75%, in each case determined based upon our total leverage ratio (as defined below) at the applicable time. A letter of credit fee is payable by us equal to the applicable margin for Eurodollar (LIBOR) rate loans times the daily amount available to be drawn under outstanding letters of credit. A commitment fee is payable by us equal to an applicable margin times the daily unused amount of the lenders’ commitment, which applicable margin ranges from 0.30% to 0.50% based upon our total leverage ratio at the applicable time.

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

The revolving credit facility contains various affirmative and negative covenants and restrictive provisions that limit the borrowers’ ability (as well as the ability of our subsidiaries) to, among other things:

•

incur certain liens or permit them to exist;

•

merge or consolidate with another company;

•

dispose of assets;

•

make distributions on or redeem or repurchase equity interests;

•

incur or guarantee additional debt;

•

repay subordinated debt prior to maturity;

•

make certain investments and acquisitions;

•

alter lines of business;

•

enter into certain types of transactions with affiliates; and

•

enter into agreements that restrict the ability of us or our subsidiaries to perform certain obligations under the credit agreement or to make payments to a borrower or our material subsidiaries.

Our credit agreement also requires compliance with two financial covenants. We must not permit the ratio of consolidated funded debt to pro forma EBITDA (the “Total Leverage Ratio”) of us and our consolidated subsidiaries (including Midcoast Operating), as of the end of any applicable four-quarter period, to exceed 5.00 to 1.00, or 5.50 to 1.00 during acquisition periods. We also must maintain (on a consolidated basis), as of the end of each applicable four-quarter period, a ratio of pro forma EBITDA to consolidated interest expense for such four-quarter period then ended of at least 2.50 to 1.00.

These covenants are subject to exceptions and qualifications set forth in the credit agreement. At such time as we obtain an investment grade rating from either Moody’s or S&P, certain covenants under the credit agreement will no longer be applicable to either the borrowers or the guarantors, or in some instances, any of them (including, but not limited to, the obligation to provide security in certain circumstances, certain restrictions on liens, investments and debt, and restrictions on dispositions).

Our credit agreement also contains customary representations, warranties, indemnities and remedies provisions. In addition, the credit agreement contains events of default customary for transactions of this nature, including (1) the failure of either borrower to make payments required under the credit agreement, (2) the failure to comply with covenants and financial ratios in the credit agreement, (3) the occurrence of a change of control, (4) the institution of insolvency or similar proceedings against either borrower, a guarantor or a material subsidiary and (5) the occurrence of payment default, or the acceleration of payments, based on a non-payment default, under any other material indebtedness of either borrower or any of their subsidiaries. During the existence of an event of default, subject to the terms and conditions of the credit agreement, the lenders may terminate all outstanding commitments under the credit agreement and may declare any outstanding principal, together with accrued and unpaid interest, to be immediately due and payable and may require that all outstanding letters of credit be collateralized by cash.

Under our credit agreement, a change of control will be triggered if EEP or Enbridge ceases to control, directly or indirectly, our General Partner or if the general partner of Midcoast Operating ceases to be wholly owned, directly or indirectly by the Partnership.

Working Capital Credit Facility

At the closing of the Offering, Midcoast Operating entered into a $250.0 million working capital credit facility with EEP as the lender. The facility is available exclusively to fund working capital borrowings. Borrowings under the facility are scheduled to mature in 2017 and accrue interest at the London Interbank Offered Rate, or LIBOR, plus 2.5%. EEP’s commitment to lend pursuant to the working capital credit facility will end on the earlier of the facility’s maturity date and the date on which EEP owns less than 20% of the

outstanding limited partner interests in Midcoast Operating. If EEP’s commitment to lend has terminated before the facility has matured (by acceleration or otherwise), then the aggregate amount of all outstanding borrowings under the facility will automatically convert to a term loan that will bear interest at LIBOR (calculated as of the conversion date) plus 2.5%. Midcoast Operating has agreed to pay a commitment fee on the unused commitment at a per annum rate of 0.4250%, payable each fiscal quarter.

The working capital credit facility will contain customary events of default, including (1) the failure of Midcoast Operating to make payments required under the working capital credit facility or comply with the conditions of such working capital credit facility, (2) the failure of any of the representations or warranties of Midcoast Operating to be true in all material respects when made, (3) the occurrence of a change of control, (4) the institution of insolvency or similar proceedings against Midcoast Operating or us and (5) the occurrence of a default under any other material indebtedness of Midcoast Operating or us. During the existence of an event of default, subject to the terms and conditions of the working capital credit facility, EEP may terminate its commitment and may declare any outstanding principal, together with accrued and unpaid interest, to be immediately due and payable. The working capital credit facility also contains certain customary representations, warranties, indemnities and remedies provisions and also provides that, if our credit agreement is secured, the working capital credit facility also will be secured to the same extent on a second priority basis. EEP has agreed to subordinate its right to payment on obligations owed under the working capital credit facility and liens, if secured, to the rights of the lenders under our credit agreement, subject to the terms and conditions of a subordination agreement.

Financial Support Agreement

Accounts Receivable Sale Arrangements

Certain of our subsidiaries entered into a receivables purchase agreement, dated June 28, 2013, as amended on September 20, 2013 and December 2, 2013 which we refer to as the Receivables Agreement, with an indirect wholly owned subsidiary of Enbridge. The Receivables Agreement and the transactions contemplated thereby were approved by a special committee of the board of directors of Enbridge Management. Pursuant to the Receivables Agreement, the Enbridge subsidiary will purchase on a monthly basis, for cash, current accounts receivables and accrued receivables, or the receivables, of those of ours subsidiaries and other subsidiaries of EEP that are parties thereto up to an aggregate monthly maximum of $450.0 million net of receivables that have not been collected. Following the sale and transfer of the receivables to the Enbridge subsidiary, the receivables are deposited in an account of that subsidiary, and ownership and control are vested in that subsidiary. The Enbridge subsidiary has no recourse with respect to the receivables acquired from these operating subsidiaries under the terms of and subject to the conditions stated in the Receivables Agreement. EEP and, as of December 2, 2013, MEP, each act in an administrative capacity as collection agent on behalf of the Enbridge

subsidiary and can be removed at any time in the sole discretion of the Enbridge subsidiary. EEP and MEP have no other involvement with the purchase and sale of the receivables pursuant to the Receivables Agreement. The Receivables Agreement terminates on December 30, 2016.

Consideration for the receivables sold is equivalent to the carrying value of the receivables less a discount for credit risk. The difference between the carrying value of the receivables sold and the cash proceeds received is recognized in “General and administrative – affiliate” expense in our consolidated statements of income. For the three and nine month periods ended September 30, 2013, the loss stemming from the discount on the receivables sold was not material. For the three and nine month periods ended September 30, 2013, we derecognized and sold $641.0 million and $772.5 million, respectively, of accrued receivables to the Enbridge subsidiary. For the three and nine month periods ended September 30, 2013, the cash proceeds were $640.8 million and $772.3 million, respectively, which was remitted to EEP through our centralized treasury system. As of September 30, 2013, $308.7 million of the receivables were outstanding from customers that had not been collected on behalf of the Enbridge subsidiary.

Cash Requirements

Capital Spending

We categorize our capital expenditures as either maintenance or expansion capital expenditures. Maintenance capital expenditures are cash expenditures that are made to maintain our asset base, operating capacity or operating income or to maintain the existing useful life of any of our capital assets, in each case over the long term. Examples of maintenance capital expenditures include expenditures to replace pipelines or processing facilities, to maintain equipment reliability, integrity and safety or to comply with existing governmental regulations and industry standards. We also include a portion of our expenditures for connecting natural gas wells, or well-connects, to our natural gas gathering systems as maintenance capital expenditures. We expect to incur continuing annual maintenance capital expenditures primarily for well-connects and for pipeline integrity measures to ensure both regulatory compliance and to maintain the overall integrity of our pipeline systems. Expenditure levels will increase as pipelines age and require higher levels of inspection, maintenance and capital replacement. We also anticipate that maintenance capital expenditures will increase due to the growth of our pipeline systems. We expect to fund maintenance capital expenditures through operating cash flows.

Expansion capital expenditures are cash expenditures incurred for acquisitions or capital improvements that we expect will increase our asset base, operating capacity or operating income over the long term or meaningfully extend the useful life of any of our capital assets. Examples of expansion capital expenditures include the acquisition of additional assets or businesses, as well as capital projects that improve the service capability of our existing assets, increase operating capacities or revenues, reduce operating costs from existing levels or enable us to comply with new governmental regulations or industry standards. We anticipate funding expansion capital expenditures temporarily through borrowings under our revolving credit facility, with long-term debt and equity funding being obtained when needed and as market conditions allow.

Going forward, if EEP elects not to fund any capital expenditures at Midcoast Operating, we will have the option to fund all or a portion of EEP’s proportionate share of such capital expenditures in exchange for additional interests in Midcoast Operating. As a result, if our interests in Midcoast Operating increase, our proportionate share of the capital expenditures incurred by Midcoast Operating will also increase proportionate to our interest in Midcoast Operating. To the extent that EEP elects not to fund all or a portion of its proportionate share of Midcoast Operating’s capital expenditures, and we elect not to fund any capital expenditures not funded by EEP, we expect that Midcoast Operating will not pursue the applicable capital projects associated with such unfunded capital expenditures.

At September 30, 2013, we had approximately $57.5 million in outstanding purchase commitments attributable to capital projects for the construction of assets that will be recorded as property, plant and equipment during 2013. The following table sets forth our estimated maintenance and expansion capital

expenditures of $541.9 million for the year ending December 31, 2013. Although we anticipate making these expenditures in 2013, these estimates may change due to factors beyond our control, including weather-related issues, construction timing, changes in supplier prices or poor economic conditions, which may adversely affect our ability to access the capital markets. Additionally, our estimates may also change as a result of decisions made at a later date to revise the scope of a project or undertake a particular capital program or an acquisition of assets. As of September 30, 2013, we have spent approximately $387.6 million including $169.4 million in contributions to the Texas Express NGL system. For the year ending December 31, 2013, we anticipate our capital expenditures to approximate the following:


	Total Forecasted Expenditures
	(in millions)
Capital Projects
Beckville Cryogenic Processing Plant	$	25
Ajax Cryogenic Processing Plant		55
System Enhancements		200
Maintenance Capital Expenditure Activities		70
Joint Venture Projects
Texas Express NGL system		190

	$	540

Derivative Activities

The following table provides summarized information about the timing and expected settlement amounts of our outstanding commodity derivative financial instruments based upon the market values at September 30, 2013 for each of the indicated calendar years:


	Notional		2013			2014			2015		2016		2017		Total⁽³⁾
	(in millions)
Swaps
Natural gas⁽¹⁾		34,468,508	$	2.0		$	0.9		$	—	$	—	$	—	$	2.9
NGL⁽²⁾		5,626,278		(2.9	)		0.4			0.7		—		—		(1.8	)
Crude Oil⁽²⁾		4,354,852		(4.7	)		(4.9	)		1.6		0.6		—		(7.4	)
Options
Natural gas—puts purchased⁽¹⁾		414,000		0.3			—			—		—		—		0.3
NGL—puts purchased⁽²⁾		1,087,000		1.1			3.1			4.5		—		—		8.7
NGL—puts written⁽²⁾		69,000		(1.1	)		—			—		—		—		(1.1	)
NGL—call written⁽²⁾		273,750		—			(0.9	)		—		—		—		(0.9	)
Forward contracts
Natural gas⁽¹⁾		63,361,435		0.1			0.5			0.4		0.1		—		1.1
NGL⁽²⁾		19,718,725		(6.0	)		0.1			—		—		—		(5.9	)
Crude Oil⁽²⁾		1,714,900		(0.1	)		—			—		—		—		(0.1	)

Totals			$	(11.3	)	$	(0.8	)	$	7.2	$	0.7	$	—	$	(4.2	)

⁽¹⁾	Notional amounts for natural gas are recorded in Millions of British Thermal Units, or MMBtu.

⁽²⁾	Notional amounts for NGLs and crude oil are recorded in Barrels, or Bbl.

⁽³⁾	Fair values exclude credit adjustments of approximately $0.2 million of losses at September 30, 2013.

Cash Flow Analysis

The following table summarizes the changes in cash flows by operating, investing and financing for each of the periods indicated:


	For the nine month period ended September 30,						Variance 2013 vs. 2012 Increase (Decrease)
	2013			2012			Variance 2013 vs. 2012 Increase (Decrease)
	(unaudited; in millions)
Total cash provided by (used in):
Operating activities	$	425.9		$	271.5		$	154.4
Investing activities		(386.5	)		(390.5	)		4.0
Financing activities		(39.4	)		119.0			(158.4	)

Net increase (decrease) in cash and cash equivalents		—			—			—
Cash and cash equivalents at beginning of year		—			—			—

Cash and cash equivalents at end of period	$	—		$	—		$	—

Operating Activities

Net cash provided by our operating activities increased $154.4 million for the nine month period ended September 30, 2013 compared to the same period in 2012, primarily due to an increase in our working capital accounts of $229.8 million. This increase due to our working capital accounts was partially offset by a $96.5 million decrease in net income, offset by other non-cash items. The $21.1 million increase in our non-cash items primarily consisted of a $21.8 million increase in derivative net losses, compared to net gains in 2012, as a result of fluctuations in commodity prices and volumes.

Changes in our working capital accounts are shown in the following table and discussed below:


	For the nine month period ended September 30,						Variance 2013 vs. 2012
	2013			2012			Variance 2013 vs. 2012
	(unaudited; in millions)
Changes in operating assets and liabilities, net of acquisitions:
Receivables, trade and other	$	(28.8	)	$	(25.9	)	$	(2.9	)
Due from General Partner and affiliates		10.6			7.3			3.3
Accrued receivables		463.2			119.4			343.8
Inventory		(75.1	)		28.4			(103.5	)
Current and long-term other assets		(7.0	)		(8.6	)		1.6
Due to General Partner and affiliates		(1.9	)		13.2			(15.1	)
Accounts payable and other		(23.2	)		28.8			(52.0	)
Accrued purchases		(97.5	)		(148.1	)		50.6
Property and other taxes payable		8.8			4.8			4.0

Net change in working capital accounts	$	249.1		$	19.3		$	229.8

The changes in our operating assets and liabilities, net of acquisitions as presented in our consolidated statements of cash flow for the nine month period ended September 30, 2013, compared to the same period in 2012, is primarily the result of general timing differences for cash receipts and payments associated with current accounts. Other items affecting our cash flows from operating assets and liabilities include the following:

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Accrued receivables increased due to the sale of $308.7 million of our net accrued receivables to a subsidiary of Enbridge during the period commencing on June 28, 2013 through September 30, 2013 pursuant to the Receivables Agreement. For more information, refer to Note 5.Related Party Transactions-Sale of Accounts Receivable.

•

Inventory balances at September 30, 2013 were higher than at December 31, 2012, resulting in a decrease to cash flow from operating activities. The higher balance of inventory is mainly attributable to seasonal build in inventory levels at higher prices during the summer months relative to the fall and winter months when demand for these products is typically higher due to colder weather conditions. In contrast, inventory balances were lower at September 30, 2012 compared to December 31, 2011, resulting in an increase to cash flow from operating activities. The lower inventory balances at September 30, 2012 from December 31, 2011 were the result of lower NGL prices at September 30, 2012 combined with a modest increase in volumes while we transitioned critical control functions of our trucking and NGL marketing business from Petal, Mississippi to Houston, Texas and the related management changes.

Investing Activities

Net cash used in our investing activities during the nine month period ended September 30, 2013 decreased by $4.0 million, compared to the same period of 2012, primarily due to an increase in contributions to fund the construction activities associated with the Texas Express NGL system of approximately $100.1 million, including $12.4 million of capitalized interest. Offsetting the increase in investing activities discussed above was $108.5 million fewer additions to property, plant and equipment, net of construction payables, for the nine months ended September 30, 2013 when compared with the nine months ended September 30, 2012.

Financing Activities

Net cash provided by our financing activities decreased $158.4 million for the nine month period ended September 30, 2013, compared to the same period in 2012, primarily due to lower capital contributions from partners during 2013 which we used to finance our construction activities, which in turn were partially offset by lower distributions paid to partners during 2013.

SUBSEQUENT EVENTS

Initial Public Offering

On November 13, 2013, the Partnership completed the Offering, as discussed in Note 1.Organization and Nature of Operations.

Contribution, Conveyance and Assumption Agreement

•

Omnibus Agreement

Exercise of the Underwriters’ Option

Item 3. Quantitative and Qualitative Disclosures About Market Risk

The following should be read in conjunction with the information presented in the Prospectus, in addition to information presented in Items 1 and 2 of this Quarterly Report on Form 10-Q. There have been no material changes to that information other than as presented below.

Our net income and cash flows are subject to volatility stemming from changes in interest rates on our variable rate debt obligations and fluctuations in commodity prices of natural gas, NGLs, condensate and fractionation margins, which is the relative difference between the price we receive from NGL sales and the corresponding cost of natural gas purchases. Our interest rate risk exposure does not exist within any of our segments, but exists at the corporate level where our fixed and variable rate debt obligations are issued. Our exposure to commodity price risk exists within each of our segments. We use derivative financial instruments (i.e., futures, forwards, swaps, options and other financial instruments with similar characteristics) to manage the risks associated with market fluctuations in commodity prices and interest rates, as well as to reduce volatility to 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 forecasted transaction and are not entered into with the objective of speculating on interest rates or commodity prices.

Fair Value Measurements of Commodity Derivatives


	At September 30, 2013												At December 31, 2012
				Wtd. Average Price⁽²⁾				Fair Value⁽³⁾					Fair Value⁽³⁾
	Commodity	Notional⁽¹⁾		Receive		Pay		Asset		Liability			Asset		Liability
*Portion of contracts maturing in 2013*
Swaps
Receive variable/pay fixed	Natural Gas		1,058,748	$	3.49	$	3.59	$	0.1	$	(0.2	)	$	0.2	$	(0.3	)
	NGL		985,200	$	46.80	$	45.40	$	1.8	$	(0.5	)	$	1.4	$	—
	Crude Oil		257,664	$	101.36	$	102.95	$	0.2	$	(0.7	)	$	0.2	$	(3.9	)
Receive fixed/pay variable	Natural Gas		2,361,000	$	4.36	$	3.55	$	1.9	$	—		$	7.8	$	—
	NGL		1,854,028	$	50.19	$	52.46	$	3.0	$	(7.2	)	$	9.3	$	(9.9	)
	Crude Oil		591,548	$	94.24	$	101.48	$	0.6	$	(4.8	)	$	6.3	$	(8.8	)
Receive variable/pay variable	Natural Gas		13,277,500	$	3.53	$	3.51	$	0.3	$	(0.1	)	$	1.2	$	(0.2	)
Physical Contracts
Receive variable/pay fixed	NGL		2,330,976	$	37.27	$	36.89	$	3.3	$	(2.4	)	$	0.6	$	(0.8	)
	Crude Oil		255,010	$	102.19	$	105.97	$	—	$	(1.0	)	$	0.4	$	(0.4	)
Receive fixed/pay variable	NGL		3,844,386	$	39.72	$	41.85	$	3.3	$	(11.4	)	$	2.6	$	(2.2	)
	Crude Oil		339,200	$	105.55	$	102.04	$	1.2	$	—		$	0.2	$	(1.0	)
Receive variable/pay variable	Natural Gas		19,866,685	$	3.53	$	3.52	$	0.3	$	(0.2	)	$	0.9	$	—
	NGL		6,135,041	$	47.40	$	47.20	$	3.6	$	(2.4	)	$	5.2	$	(2.3	)
	Crude Oil		1,120,690	$	98.78	$	99.06	$	1.4	$	(1.7	)	$	6.4	$	(3.0	)
*Portion of contracts maturing in 2014*
Swaps
Receive variable/pay fixed	Natural Gas		21,870	$	3.75	$	5.22	$	—	$	—		$	—	$	—
	NGL		286,250	$	82.33	$	83.05	$	—	$	(0.2	)	$	—	$	—
	Crude Oil		506,255	$	95.33	$	101.95	$	—	$	(3.3	)	$	—	$	(5.0	)
Receive fixed/pay variable	Natural Gas		3,006,890	$	3.97	$	3.73	$	0.7	$	—		$	0.2	$	—
	NGL		2,208,800	$	53.93	$	53.67	$	5.6	$	(5.0	)	$	0.9	$	(2.7	)
	Crude Oil		1,573,205	$	94.43	$	95.41	$	3.6	$	(5.2	)	$	5.4	$	(2.7	)
Receive variable/pay variable	Natural Gas		13,842,500	$	3.77	$	3.76	$	0.2	$	—		$	0.1	$	(0.1	)
Physical Contracts
Receive variable/pay fixed	NGL		45,000	$	43.79	$	45.45	$	—	$	(0.1	)	$	—	$	—
Receive fixed/pay variable	NGL		325,617	$	53.43	$	55.69	$	0.1	$	(0.8	)	$	—	$	—
Receive variable/pay variable	Natural Gas		34,169,685	$	3.77	$	3.76	$	0.9	$	(0.4	)	$	0.5	$	—
	NGL		7,037,705	$	33.02	$	32.90	$	1.8	$	(0.9	)	$	—	$	—
*Portion of contracts maturing in 2015*
Swaps
Receive variable/pay fixed	Crude Oil		515,015	$	88.53	$	100.93	$	—	$	(6.3	)	$	—	$	(5.6	)
Receive fixed/pay variable	NGL		292,000	$	56.76	$	54.04	$	1.2	$	(0.5	)	$	0.7	$	(0.2	)
	Crude Oil		865,415	$	97.72	$	88.53	$	7.9	$	—		$	6.8	$	(0.2	)
Receive variable/pay variable	Natural Gas		900,000	$	4.05	$	4.04	$	—	$	—		$	—	$	—
Physical Contracts
Receive variable/pay variable	Natural Gas		8,541,825	$	4.10	$	4.06	$	0.5	$	(0.1	)	$	0.4	$	—
*Portion of contracts maturing in 2016*
Swaps
Receive fixed/pay variable	Crude Oil		45,750	$	99.31	$	84.81	$	0.6	$	—		$	0.5	$	—
Physical Contracts
Receive variable/pay variable	Natural Gas		783,240	$	4.28	$	4.17	$	0.1	$	—		$	0.1	$	—

⁽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 following table provides summarized information about the fair values of expected cash flows of our outstanding commodity options at September 30, 2013 and December 31, 2012.


	At September 30, 2013												At December 31, 2012
	Commodity	Notional⁽¹⁾		Strike Price⁽²⁾		Market Price⁽²⁾		Fair Value⁽³⁾					Fair Value⁽³⁾
	Commodity	Notional⁽¹⁾		Strike Price⁽²⁾		Market Price⁽²⁾		Asset		Liability			Asset		Liability
*Portion of option contracts maturing in 2013*
Puts (purchased)	Natural Gas		414,000	$	4.18	$	3.48	$	0.3	$	—		$	1.4	$	—
	NGL		138,000	$	31.26	$	27.76	$	1.1	$	—		$	3.7	$	—
Puts (written)	NGL		69,000	$	26.18	$	10.68	$	—	$	(1.1	)	$	—	$	—
*Portion of option contracts maturing in 2014*
Puts (purchased)	NGL		401,500	$	52.21	$	50.44	$	3.1	$	—		$	1.3	$	—
Calls (written)	NGL		273,750	$	57.93	$	48.65	$	—	$	(0.9	)	$	—	$	—
*Portion of option contracts maturing in 2015*
Puts (purchased)	NGL		547,500	$	53.76	$	52.52	$	4.5	$	—		$	—	$	—

⁽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 September 30, 2013 and December 31, 2012, respectively, discounted using the swap rate for the respective periods to consider the time value of money.

Our credit exposure for over-the-counter derivatives is directly with our counterparty and continues until the maturity or termination of the contract. When appropriate, valuations are adjusted for various factors such as credit and liquidity considerations.


	September 30, 2013			December 31, 2012
	(in millions)
Counterparty Credit Quality⁽¹⁾
AAA	$	0.1		$	—
AA		(57.8	)		(116.6	)
A		(84.5	)		(150.4	)
Lower than A		137.8			282.2

	$	(4.4	)	$	15.2

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

Item 4. Controls and Procedures

We, EEP and Enbridge maintain systems of disclosure controls and procedures designed to provide reasonable assurance that we are able to record, process, summarize and report the information required to be disclosed in the reports that we file or submit under the Securities Exchange Act of 1934, as amended, or the Exchange Act, within the time periods specified in the rules and forms of the SEC, and that such information is accumulated and communicated to our management, including our principal executive and principal financial officers, as appropriate, to allow timely decisions regarding required disclosure. Our management, with the participation of our principal executive and principal financial officers, has evaluated the effectiveness of our disclosure controls and procedures as of September 30, 2013. Based upon that evaluation, our principal executive and principal financial officers concluded that our disclosure controls and procedures are effective at the reasonable assurance level. In conducting this assessment, our management relied on similar evaluations conducted by employees of Enbridge affiliates who provide certain treasury, accounting and other services on our behalf.

There have been no changes in internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting during the three month period ended September 30, 2013.

PART II—OTHER INFORMATION

Item 1. Legal Proceedings

Refer to Part I, Item 1.Financial Statements, “Note 6.Commitments and Contingencies,” which is incorporated herein by reference.

Item 1A. Risk Factors

There have been no material changes to the risk factors previously disclosed in the Prospectus.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

On November 6, 2013, our registration statement on Form S-1 (File No. 333-189341), as amended, that we filed with the SEC relating to our initial public offering, or the Offering, was declared effective. Our registration statement registered 21,275,000 Class A common units (including 2,775,000 Class A common units issuable pursuant to the underwriters’ option to purchase additional Class A common units). Merrill Lynch, Pierce, Fenner, & Smith Incorporated, Barclays Capital Inc., Citigroup Global Markets Inc., Credit Suisse Securities (USA) LLC, Deutsche Bank Securities Inc., Goldman, Sachs & Co., J.P. Morgan Securities LLC, Morgan Stanley & Co. LLC, UBS Securities LLC and Wells Fargo Securities, LLC served as joint book-running managers for the Offering. RBS Securities Inc., SMBC Nikko Securities America, Inc. and Ladenburg Thalmann & Co. Inc. served as co-managers for the Offering. Upon the closing of the Offering on November 13, 2013, we sold 18,500,000 Class A common units and, on December 9, 2013, we sold an additional 2,775,000 Class A common units in connection with the exercise in full by the underwriters of their option to purchase additional Class A common units. These Class A common units were sold at a price to the public of $18.00 per Class A common unit, resulting in total gross proceeds from the Offering of approximately $383.0 million. Net proceeds from the Offering were approximately $354.9 million, after deducting underwriting discounts, structuring fees and estimated offering expenses. We used the net proceeds to fund a distribution of approximately $304.5 million to EEP, to pay revolving credit facility origination and commitment fees of approximately $3.4 million and to redeem additional Class A common units from EEP for approximately $47.0 million . None of the expenses associated with the Offering were paid to our directors. There has been no material change in the planned use of proceeds from the Offering as described in our final prospectus filed with the SEC on November 8, 2013.

Item 6. Exhibits

Reference is made to the “Index of Exhibits” following the signature page, which we hereby incorporate into this Item.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


MIDCOAST ENERGY PARTNERS, L.P. (Registrant)

By:		Midcoast Holdings, L.L.C.
		as General Partner

Date: December 20, 2013

By:

/s/ Mark A. Maki

Mark A. Maki

President

(Principal Executive Officer)

Date: December 20, 2013

By:

/s/ Stephen J. Neyland

Stephen J. Neyland

Vice President, Finance

(Principal Financial Officer)

Index of Exhibits

Each exhibit identified below is filed as a part of this Quarterly Report on Form 10-Q. Exhibits included in this filing are designated by an asterisk; all exhibits not so designated are incorporated by reference to a prior filing as indicated.


Exhibit Number		Description
3.1		Certificate of Limited Partnership of Midcoast Energy Partners, L.P., dated May 30, 2013 (incorporated by reference to Exhibit 3.1 of our Registration Statement on Form S-1 (Registration No. 333-189341), filed on June 14, 2013, as amended).
3.2		First Amended and Restated Agreement of Limited Partnership of Midcoast Energy Partners, L.P. dated November 13, 2013 (incorporated by reference to Exhibit 3.1 of our Current Report onForm 8-K, filed on November 18, 2013).
4.1		Specimen Unit Certificate for the Class A Common Units (included as Exhibit A to the Form of First Amended and Restated Agreement of Limited Partnership of the Registrant) (incorporated herein by reference to Appendix A to the prospectus included in the Registrant’s Registration Statement on Form S-1 (Registration No. 333-189341), initially filed with the Securities and Exchange Commission on June 14, 2013, as amended).
10.1		Contribution, Conveyance and Assumption Agreement of Midcoast Energy Partners, L.P. dated as of November 13, 2013, (incorporated by reference to Exhibit 10.2 of our of our Current Report on Form 8-K, filed on November 18, 2013).
10.2		Omnibus Agreement, dated as of November 13, 2013, by and among Midcoast Energy Partners, L.P., Midcoast Holdings, L.L.C., EEP and Enbridge Inc. (incorporated by reference to Exhibit 10.2 of our of our Current Report on Form 8-K, filed on November 18, 2013).
10.3		Credit Agreement, dated as of November 13, 2013, by and among Midcoast Energy Partners, L.P., as Co-Borrower, Midcoast Operating L.P., as Co-Borrower, Bank of America, N.A., as Administrative Agent, Letter of Credit Issuer, Swing Line Lender and lender, and each of the other lenders party thereto (incorporated by reference to Exhibit 10.3 of our Current Report on Form 8-K, filed on November 18, 2013).
10.4		Intercorporate Services Agreement, dated as of November 13, 2013, by and between EEP and Midcoast Energy Partners, L.P. (incorporated by reference to Exhibit 10.4 of our Current Report on Form 8-K, filed on November 18, 2013).
10.5		Financial Support Agreement, dated as of November 13, 2013, by and between Midcoast Operating, L.P. and EEP (incorporated by reference to Exhibit 10.5 of our Current Report on Form 8-K, filed on November 18, 2013).
10.6		Amended and Restated Allocation Agreement, dated as of November 13, 2013, by and among Midcoast Energy Partners, L.P., Enbridge Inc., EEP and Enbridge Income Fund Holdings Inc., (incorporated by reference to Exhibit 10.6 of our Current Report on Form 8-K, filed on November 18, 2013).
10.7		Working Capital Loan Agreement, dated November 13, 2013, by and between Midcoast Operating, L.P. and EEP (incorporated by reference to Exhibit 10.7 of our Current Report on Form 8-K, filed on November 18, 2013).
10.8		Amended and Restated Agreement of Limited Partnership of Midcoast Operating, L.P., dated as of November 13, 2013 (incorporated by reference to Exhibit 10.8 of our Current Report on Form 8-K, filed on November 18, 2013).
10.9*		Subordination Agreement dated November 13, 2013 by and among Midcoast Energy Partners, L.P., Midcoast Operating, L.P., other credit parties from time to time party there to, Enbridge Energy Partners, L.P., and Bank of America, N.A.
31.1^*		Certification of Principal Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2^*		Certification of Principal Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1^*		Certification of Principal Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2^*		Certification of Principal Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


101.INS^*		XBRL Instance Document.
101.SCH^*		XBRL Taxonomy Extension Schema Document.
101.CAL^*		XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF^*		XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB^*		XBRL Taxonomy Extension Label Linkbase Document.
101.PRE^*		XBRL Taxonomy Extension Presentation Linkbase Document.

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Midcoast Energy Partners (MEP) Inactive 10-Q2013 Q3 Quarterly report

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