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10-Q 1 d620925d10q.htm 10-Q 10-Q

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 1-10934

ENBRIDGE ENERGY PARTNERS, L.P.

(Exact Name of Registrant as Specified in Its Charter)

Delaware

39-1715850

(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 x No ¨

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):

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 254,208,428 Class A common units outstanding as of October 31, 2013.

ENBRIDGE 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	40
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	73
Item 4.	Controls and Procedures	76

	PART II - OTHER INFORMATION
Item 1.	Legal Proceedings	77
Item 1A.	Risk Factors	77
Item 5.	Other Information	77
Item 6.	Exhibits	77
Signatures		78
Exhibits		79

In this report, unless the context requires otherwise, references to “we,” “us,” “our” or the “Partnership” are intended to mean Enbridge Energy Partners, L.P. and its consolidated subsidiaries. We refer to our general partner, Enbridge Energy Company, Inc., as our “General Partner.”

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 the Partnership’s 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 crude oil, liquid petroleum, natural gas and NGLs, including the rate of development of the Alberta Oil Sands; (2) our ability to successfully complete and finance expansion projects; (3) the effects of competition, in particular, by other pipeline systems; (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, including those related to Line 6B and any additional fines and penalties assessed in connection with the crude oil release on that line; (6) changes in or challenges to our tariff 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 “Item 1A. Risk Factors” included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2012 and our subsequently filed Quarterly Reports on Form 10-Q, which are available to the public over the Internet at the U.S. Securities and Exchange Commission’s, or SEC’s, website (www.sec.gov) and at our website (www.enbridgepartners.com).

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

ENBRIDGE ENERGY PARTNERS, L.P.

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, except per unit amounts)
Operating revenue (Note 10)	$	1,729.8		$	1,481.7		$	4,969.1		$	4,604.3
Operating revenue—affiliate		59.6			82.6			186.0			330.6

		1,789.4			1,564.3			5,155.1			4,934.9

Operating expenses:
Cost of natural gas (Notes 4 and 10)		1,234.7			997.3			3,469.1			3,078.9
Cost of natural gas—affiliate		22.8			51.3			95.3			241.8
Environmental costs, net of recoveries (Note 9)		0.6			(134.9	)		184.3			(109.0	)
Operating and administrative		153.6			99.2			348.9			266.0
Operating and administrative—affiliate		111.5			116.1			329.1			352.4
Power (Note 10)		43.0			38.0			105.8			116.6
Depreciation and amortization (Note 5)		99.6			86.8			287.6			256.5

		1,665.8			1,253.8			4,820.1			4,203.2

Operating income		123.6			310.5			335.0			731.7
Interest expense (Notes 6 and 10)		70.5			83.4			226.4			248.8
Allowance for equity used during construction (Note 13)		9.3			5.6			25.2			5.6
Other income (expense)		0.4			(0.9	)		1.0			(1.2	)

Income before income tax expense		62.8			231.8			134.8			487.3
Income tax expense (Note 11)		1.5			2.6			17.5			6.4

Net income		61.3			229.2			117.3			480.9
Less: Net income attributable to:
Noncontrolling interest (Note 8)		20.3			14.0			54.3			42.1
Series 1 preferred unit distributions (Note 7)		22.7			—			35.8			—
Accretion of discount on Series 1 preferred units (Note 7)		3.4			—			5.7			—

Net income attributable to general and limited partner ownership interest in Enbridge Energy Partners, L.P.	$	14.9		$	215.2		$	21.5		$	438.8

Net income (loss) allocable to limited partner interests	$	(17.6	)	$	172.7		$	(73.8	)	$	346.2

Net income (loss) per limited partner unit (basic) (Note 2)	$	(0.05	)	$	0.60		$	(0.23	)	$	1.21

Weighted average limited partner units outstanding (basic)		317.4			289.3			313.2			286.5

Net income (loss) per limited partner unit (diluted) (Note 2)	$	(0.05	)	$	0.60		$	(0.23	)	$	1.21

Weighted average limited partner units outstanding (diluted)		317.4			289.3			313.2			286.5

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

ENBRIDGE ENERGY PARTNERS, L.P.

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	$	61.3		$	229.2		$	117.3	$	480.9
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 10)		(14.0	)		(44.7	)		177.7		(42.6	)

Comprehensive income		47.3			184.5			295.0		438.3
Less: Comprehensive income attributable to:
Noncontrolling interest (Note 8)		20.3			14.0			54.3		42.1
Series 1 preferred unit distributions (Note 7)		22.7			—			35.8		—
Accretion of discount on Series 1 preferred units (Note 7)		3.4			—			5.7		—

Comprehensive income attributable to general and limited partner ownership interests in Enbridge Energy Partners, L.P.	$	0.9		$	170.5		$	199.2	$	396.2

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

ENBRIDGE ENERGY PARTNERS, L.P.

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	$	117.3		$	480.9
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization (Note 5)		287.6			256.5
Derivative fair value net losses (gains) (Note 10)		16.8			(10.4	)
Inventory market price adjustments (Note 4)		3.3			9.8
Environmental costs, net of recoveries (Note 9)		221.1			32.2
Deferred income taxes (Note 11)		13.5			0.2
State income taxes		7.9			—
Allowance for equity used during construction		(25.2	)		(5.6	)
Other (Note 14)		10.7			15.0
Changes in operating assets and liabilities, net of acquisitions:
Receivables, trade and other		66.2			(16.8	)
Due from General Partner and affiliates		(4.9	)		2.8
Accrued receivables		452.5			125.9
Inventory (Note 4)		(87.4	)		21.0
Current and long-term other assets (Note 10)		(22.3	)		(12.6	)
Due to General Partner and affiliates		3.1			(1.1	)
Accounts payable and other (Notes 3 and 10)		28.0			6.1
Environmental liabilities (Note 9)		(79.8	)		(78.6	)
Accrued purchases		(77.0	)		(138.2	)
Interest payable		8.3			8.8
Property and other taxes payable		8.1			12.4
Settlement of interest rate derivatives		(5.3	)		—

Net cash provided by operating activities		942.5			708.3

Cash used in investing activities:
Additions to property, plant and equipment (Note 5)		(1,733.0	)		(1,211.9	)
Changes in construction payables		218.5			72.8
Changes in restricted cash (Note 8)		(2.2	)		—
Investment in joint venture		(181.8	)		(81.7	)
Other		(5.6	)		2.8

Net cash used in investing activities		(1,704.1	)		(1,218.0	)

Cash provided by financing activities:
Net proceeds from Series 1 preferred unit issuance (Note 7)		1,200.0			—
Net proceeds from unit issuances (Note 7)		519.3			456.2
Distributions to partners (Note 7)		(530.6	)		(484.2	)
Repayments to General Partner (Note 8)		(12.0	)		(12.0	)
Repayments of long-term debt (Note 6)		(200.0	)		—
Net commercial paper (repayments) borrowings (Note 6)		(734.9	)		285.0
Contributions from noncontrolling interest (Note 8)		355.2			122.3
Distributions to noncontrolling interest (Note 8)		(39.7	)		(47.0	)

Net cash provided by financing activities		557.3			320.3

Net decrease in cash and cash equivalents		(204.3	)		(189.4	)
Cash and cash equivalents at beginning of year		227.9			422.9

Cash and cash equivalents at end of period	$	23.6		$	233.5

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

ENBRIDGE ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION


	September 30, 2013			December 31, 2012
	(unaudited; in millions)
ASSETS
Current assets:
Cash and cash equivalents (Note 3)	$	23.6		$	227.9
Restricted cash (Note 8)		2.2			—
Receivables, trade and other, net of allowance for doubtful accounts of $1.1 million in 2013 and $1.9 million in 2012 (Note 9)		76.0			142.4
Due from General Partner and affiliates		32.7			27.2
Accrued receivables		117.2			569.7
Inventory (Note 4)		154.8			72.7
Other current assets (Note 10)		48.8			48.0

		455.3			1,087.9
Property, plant and equipment, net (Note 5)		12,413.8			10,937.6
Goodwill		246.7			246.7
Intangibles, net		253.7			257.2
Other assets, net (Note 10)		514.5			267.4

	$	13,884.0		$	12,796.8

LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Due to General Partner and affiliates	$	50.3		$	43.5
Accounts payable and other (Notes 3, 10 and 13)		786.5			646.0
Environmental liabilities (Note 9)		231.4			108.0
Accrued purchases		410.2			484.1
Interest payable		72.0			69.0
Property and other taxes payable (Note 11)		79.5			71.4
Note payable to General Partner (Note 8)		12.0			12.0
Current maturities of long-term debt (Note 6)		—			200.0

		1,641.9			1,634.0
Long-term debt (Note 6)		4,767.3			5,501.7
Loans from General Partner and affiliate (Note 8)		306.0			318.0
Due to General Partner and affiliates		35.8			—
Deferred income tax liability (Note 11)		16.5			3.0
Other long-term liabilities (Notes 9 and 10)		105.2			92.2

Total liabilities		6,872.7			7,548.9

Commitments and contingencies (Note 9)
Partners’ capital: (Notes 7 and 8)
Series 1 preferred units (48,000,000 at September 30, 2013)		1,158.0			—
Class A common units (254,208,428 at September 30, 2013 and December 31, 2012)		3,155.7			3,590.2
Class B common units (7,825,500 at September 30, 2013 and December 31, 2012)		70.7			83.9
i-units (62,580,110 and 41,198,424 at September 30, 2013 and December 31, 2012, respectively)		1,301.6			801.8
General Partner		304.8			299.0
Accumulated other comprehensive income (loss) (Note 10)		(142.8	)		(320.5	)

Total Enbridge Energy Partners, L.P. partners’ capital		5,848.0			4,454.4
Noncontrolling interest (Note 8)		1,163.3			793.5

Total partners’ capital		7,011.3			5,247.9

	$	13,884.0		$	12,796.8

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

ENBRIDGE ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

1. BASIS OF PRESENTATION

The accompanying unaudited interim consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP, for interim consolidated financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. Accordingly, 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 Annual Report on Form 10-K for the fiscal year ended December 31, 2012. 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 crude oil, seasonality of portions of our Natural Gas business, timing and completion of our construction projects, maintenance activities, the impact of forward commodity prices and differentials on derivative financial instruments that are accounted for at fair value and the effect of environmental costs and related insurance recoveries on our Lakehead system. Our interim consolidated financial statements should be read in conjunction with our consolidated financial statements and notes thereto presented in our Annual Report on Form 10-K for the fiscal year ended December 31, 2012.

Comparative Amounts

We made reclassifications of $2.0 million and $9.1 million for oil measurement gains from “Oil measurement adjustments” to “Operating and administrative” in our consolidated statements of income for the three and nine month periods ended September 30, 2012, respectively.

In addition, certain prior period affiliate amounts related to operating revenue, the cost of natural gas, and operating and administrative expenses have been reclassified to conform to current period presentation. These reclassifications did not impact net income.

2. NET INCOME PER LIMITED PARTNER UNIT

We allocate our net income among our Series 1 Preferred Units, or Preferred Units, Enbridge Energy Company, Inc., our General Partner, and our limited partners using first preferred unit distributions and then the two-class method in accordance with applicable authoritative accounting guidance. Under the two-class method, we allocate our net income, after noncontrolling interest and preferred unit distributions, including any incentive distribution rights embedded in the general partner interest, to our General Partner and our limited partners according to the distribution formula for available cash as set forth in our partnership agreement. We also allocate any earnings in excess of distributions to our General Partner and limited partners utilizing the distribution formula for available cash specified in our partnership agreement. We allocate any distributions in excess of earnings for the period to our General Partner and limited partners, after Preferred Unit allocations, based on their sharing of losses of 2% and 98%, respectively, as set forth in our partnership agreement as follows:


Distribution Targets	Portion of Quarterly Distribution Per Unit	Percentage Distributed to General Partner	Percentage Distributed to Limited partners
Minimum Quarterly Distribution	Up to $0.295	2 %		98	%
First Target Distribution	> $0.295 to $0.35	15 %		85	%
Second Target Distribution	> $0.35 to $0.495	25 %		75	%
Over Second Target Distribution	In excess of $0.495	50 %		50	%

We determined basic and diluted net income per limited partner unit as follows:


	For the three month period ended September 30,						For the nine month period ended September 30,
	2013			2012			2013			2012
	(in millions, except per unit amounts)
Net income	$	61.3		$	229.2		$	117.3		$	480.9
Less Net income attributable to:
Noncontrolling interest		(20.3	)		(14.0	)		(54.3	)		(42.1	)
Series 1 preferred unit distributions		(22.7	)		—			(35.8	)		—
Accretion of discount on Series 1 preferred units		(3.4	)		—			(5.7	)		—

Net income attributable to general and limited partner interests in Enbridge Energy Partners, L.P.		14.9			215.2			21.5			438.8
Less distributions paid:
Incentive distributions to our General Partner		(32.9	)		(30.7	)		(96.8	)		(85.5	)
Distributed earnings allocated to our General Partner		(3.6	)		(3.4	)		(10.6	)		(9.7	)

Total distributed earnings to our General Partner		(36.5	)		(34.1	)		(107.4	)		(95.2	)
Total distributed earnings to our limited partners		(176.5	)		(164.4	)		(518.6	)		(471.5	)

Total distributed earnings		(213.0	)		(198.5	)		(626.0	)		(566.7	)

Overdistributed earnings	$	(198.1	)	$	16.7		$	(604.5	)	$	(127.9	)

Weighted average limited partner units outstanding		317.4			289.3			313.2			286.5

Basic and diluted earnings per unit:
Distributed earnings per limited partner unit⁽¹⁾	$	0.56		$	0.57		$	1.66		$	1.65
(Overdistributed) earnings per limited partner unit⁽²⁾		(0.61	)		0.03			(1.89	)		(0.44	)

Net income (loss) per limited partner unit (basic and diluted)⁽³⁾	$	(0.05	)	$	0.60		$	(0.23	)	$	1.21

⁽¹⁾	Represents the total distributed earnings to limited partners divided by the weighted average number of limited partner interests outstanding for the period.

⁽²⁾

Represents the limited partners’ share (98%) of distributions in excess of earnings divided by the weighted average number of limited partner interests outstanding for the period and underdistributed earnings allocated to the limited partners based on the distribution waterfall that is outlined in our partnership agreement.

⁽³⁾	For the three and nine month periods ended September 30, 2013, 43,201,310 anti-dilutive Preferred Units were excluded from the if-converted method of calculating diluted earnings per unit.

3. CASH AND CASH EQUIVALENTS

We extinguish liabilities when a creditor has relieved us of our obligation, which occurs when our financial institution honors a check that the creditor has presented for payment. Accordingly, obligations for which we have made payments that have not yet been presented to the financial institution totaling approximately $34.2 million at September 30, 2013 and $22.8 million at December 31, 2012 are included in “Accounts payable and other” on our consolidated statements of financial position.

4. INVENTORY

Our inventory is comprised of the following:


	September 30, 2013		December 31, 2012
	(in millions)
Materials and supplies	$	2.2	$	1.9
Crude oil inventory		20.1		12.7
Natural gas and NGL inventory		132.5		58.1

	$	154.8	$	72.7

The “Cost of natural gas” 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 natural gas liquids, or NGLs, to reflect the current market value.

5. PROPERTY, PLANT AND EQUIPMENT

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


	September 30, 2013			December 31, 2012
	(in millions)
Land	$	43.0		$	40.4
Rights-of-way		682.7			604.5
Pipelines		7,598.6			6,662.3
Pumping equipment, buildings and tanks		2,103.0			1,646.4
Compressors, meters and other operating equipment		1,953.3			1,755.7
Vehicles, office furniture and equipment		317.1			222.7
Processing and treating plants		511.3			489.8
Construction in progress		1,826.1			1,867.2

Total property, plant and equipment		15,035.1			13,289.0
Accumulated depreciation		(2,621.3	)		(2,351.4	)

Property, plant and equipment, net	$	12,413.8		$	10,937.6

6. DEBT

Credit Facilities

In September 2011, we entered into a credit agreement with Bank of America as administrative agent, and the lenders party thereto, which we refer to as the Credit Facility. The agreement is a committed senior unsecured revolving credit facility that permits aggregate borrowings of up to, at any one time outstanding, $2.0 billion, a letter of credit subfacility and a swing line subfacility. Effective September 26, 2012, we extended the maturity date to September 26, 2017 and amended it to adjust the base interest rates. On October 28, 2013, we amended our Credit Facility to, among other things extend the maturity date from September 26, 2017 to September 26, 2018 and to reduce the aggregate permitted borrowings under the Credit Facility to up to, at any one time outstanding, $1.975 billion, as discussed in Note 15. Subsequent Events.

On July 6, 2012, we entered into a credit agreement with JPMorgan Chase Bank, as administrative agent, and a syndicate of 12 lenders, which we refer to as the 364-Day Credit Facility. The agreement is a committed senior unsecured revolving credit facility pursuant to which the lenders have committed to lend us up to

$675.0 million: (1) on a revolving basis for a 364-day period, extendible annually at the lenders’ discretion; and (2) for a 364-day term on a non-revolving basis following the expiration of all revolving periods. On February 8, 2013, we amended the 364-Day Credit Facility to reflect an increase in the lending commitments to $1.1 billion. The amended credit agreement has terms consistent with the original 364-Day Credit Facility.

On July 3, 2013, we amended our 364-Day Credit Facility, to extend the revolving credit termination date to July 4, 2014 and to increase aggregate commitments under the facility by $50.0 million. Furthermore, on July 24, 2013, we added a new lender and increased our aggregate commitments by another $50.0 million. After these changes, our 364-day Credit Facility now provides aggregate lending commitments of $1.2 billion. On October 28, 2013, we further amended our 364-Day Credit Facility as discussed in Note 15. Subsequent Events.

Our Credit Facility has been amended, and our 364-Day Credit Facility, which is discussed above, is written, to exclude up to $650 million of the costs associated with the remediation of the area affected by the Line 6B crude oil release from the Earnings Before Interest, Taxes, Depreciation and Amortization, or EBITDA, component of the consolidated leverage ratio covenant in each of those facilities, which we refer to, collectively, as our Credit Facilities. At September 30, 2013, we were in compliance with the terms of our financial covenants under our Credit Facilities.

As of September 30, 2013, our Credit Facilities provided an aggregate amount of $3.2 billion of bank credit, which we use to fund our general activities and working capital needs.

The amounts we may borrow under the terms of our Credit Facilities are reduced by the face amount of our letters of credit outstanding. It is our policy to maintain availability at any time under our Credit Facilities amounts that are at least equal to the amount of commercial paper that we have outstanding at such time. Taking that policy into account, at September 30, 2013, we could borrow approximately $2.7 billion under the terms of our Credit Facilities, determined as follows:


	(in millions)
Total credit available under Credit Facilities	$	3,200.0
Less: Amounts outstanding under Credit Facilities		—
Principal amount of commercial paper outstanding		425.0
Letters of credit outstanding		89.2


Total amount we could borrow at September 30, 2013	$	2,685.8

Individual London Inter-Bank Offered Rate, or LIBOR rate, borrowings under the terms of our Credit Facilities may be renewed as LIBOR rate borrowings or as base rate borrowings at the end of each LIBOR rate interest period, which is typically a period of three months or less. These renewals do not constitute new borrowings under the Credit Facilities and do not require any cash repayments or prepayments. For the three and nine month periods ended September 30, 2013 and 2012, we have not renewed any LIBOR rate borrowings or base rate borrowings on a non-cash basis.

Commercial Paper

We have a commercial paper program that provides for the issuance of up to an aggregate principal amount of $1.5 billion of commercial paper and is supported by our Credit Facilities. We access the commercial paper market primarily to provide temporary financing for our operating activities, capital expenditures and acquisitions when the available interest rates we can obtain are lower than the rates available under our Credit Facilities. At September 30, 2013, we had $425.0 million in principal amount of commercial paper outstanding at a weighted average interest rate of 0.34%, excluding the effect of our interest rate hedging activities. At December 31, 2012, we had $1.2 billion in principal amount of commercial paper outstanding at a weighted average interest rate of 0.46%, excluding the effect of our interest rate hedging activities. Our policy is to limit the commercial paper we issue by the amounts available for us to borrow under our Credit Facilities.

We have the ability and intent to refinance all of our commercial paper obligations on a long-term basis through borrowings under our Credit Facilities. Accordingly, such amounts have been classified as “Long-term debt” in our accompanying consolidated statements of financial position.

Senior Notes

During the second quarter of 2013, $200.0 million of our notes reached full maturity, which we repaid in full on June 3, 2013.

Fair Value of Debt Obligations

The table below presents the carrying amounts and approximate fair values of our debt obligations. The carrying amounts of our outstanding commercial paper and borrowings under our Credit Facilities and prior credit facilities approximate their fair values at September 30, 2013 and December 31, 2012, respectively, due to the short-term nature and frequent repricing of these obligations. The fair value of our outstanding commercial paper and borrowings under our Credit Facilities are included with our long-term debt obligations below since we have the ability to refinance the amounts on a long-term basis. The approximate fair values of our long-term debt obligations are determined using a standard methodology that incorporates pricing points that are obtained from independent, third-party investment dealers who actively make markets in our debt securities. We use these pricing points to calculate the present value of the principal obligation to be repaid at maturity and all future interest payment obligations for any debt outstanding. The fair value of our long-term debt obligations is categorized as Level 2 within the fair value hierarchy.


	September 30, 2013				December 31, 2012
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in millions)
Commercial Paper	$	425.0	$	425.0	$	1,160.0	$	1,160.0
4.750% Senior Notes due 2013		—		—		200.0		203.9
5.350% Senior Notes due 2014		200.0		212.5		200.0		215.6
5.875% Senior Notes due 2016		299.9		338.3		299.9		345.1
7.000% Senior Notes due 2018		99.9		119.7		99.9		124.6
6.500% Senior Notes due 2018		399.0		468.9		398.8		484.1
9.875% Senior Notes due 2019		500.0		675.1		500.0		710.5
5.200% Senior Notes due 2020		499.9		551.9		499.9		575.4
4.200% Senior Notes due 2021		599.0		611.6		598.9		644.2
7.125% Senior Notes due 2028		99.8		125.6		99.8		137.5
5.950% Senior Notes due 2033		199.8		221.0		199.8		244.2
6.300% Senior Notes due 2034		99.8		114.3		99.8		126.5
7.500% Senior Notes due 2038		399.1		517.9		399.0		573.8
5.500% Senior Notes due 2040		546.4		545.2		546.3		605.5
8.050% Junior subordinated notes due 2067		399.7		458.6		399.6		453.6

Total	$	4,767.3	$	5,385.6	$	5,701.7	$	6,604.5

7. PARTNERS’ CAPITAL

Distribution to Partners

The following table sets forth our distributions, as approved by the board of directors of Enbridge Energy Management, or Enbridge Management, during the nine month period ended September 30, 2013.


Distribution Declaration Date	Record Date	Distribution Payment Date	Distribution per Unit		Cash available for distribution		Amount of Distribution of i-units to i-unit Holders⁽¹⁾		Retained from General Partner⁽²⁾		Distribution of Cash
			(in millions, except per unit amounts)

July 29, 2013	August 7, 2013	August 14, 2013	$	0.5435	$	206.8	$	28.9	$	0.6	$	177.3

April 30, 2013	May 8, 2013	May 15, 2013	$	0.5435	$	206.2	$	28.4	$	0.6	$	177.2

January 30, 2013	February 7, 2013	February 14, 2013	$	0.5435	$	198.9	$	22.4	$	0.4	$	176.1

⁽¹⁾	We issued 2,607,000 i-units to Enbridge Management, the sole owner of our i-units, during 2013 in lieu of cash distributions.

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

Changes in Partners’ Capital

The following table presents significant changes in partners’ capital accounts attributable to our General Partner and limited partners as well as the noncontrolling interest in our consolidated subsidiary, Enbridge Energy, Limited Partnership, or the OLP, for the three and nine month periods ended September 30, 2013 and 2012. The noncontrolling interest in the OLP arises from the joint funding arrangements with our General Partner and its affiliate to finance: (1) construction of the United States portion of the Alberta Clipper crude oil pipeline and related facilities, which we refer to as the Alberta Clipper Pipeline; (2) expansion of our Lakehead system to

transport crude oil to destinations in the Midwest United States, which we refer to as the Eastern Access Projects; and (3) further expansion of our Lakehead system to transport crude oil between Neche, North Dakota and Superior, Wisconsin, which we refer to as the Mainline Expansion Projects.


	For the three month period ended September 30,						For the nine month period ended September 30,
	2013			2012			2013			2012
	(in millions)
Series 1 Preferred interests
Beginning balance	$	1,154.6		$	—		$	—		$	—
Proceeds from issuance of preferred units		—			—			1,200.0			—
Net income		22.7			—			35.8			—
Accretion of discount on preferred units		3.4			—			5.7			—
Distribution payable		(22.7	)		—			(35.8	)		—
Beneficial conversion feature of preferred units		—			—			(47.7	)		—

Ending balance	$	1,158.0		$	—		$	1,158.0		$	—

General and limited partner interests
Beginning balance	$	4,754.6		$	4,389.9		$	4,774.9		$	4,483.1
Proceeds from issuance of partnership interests, net of costs		240.6			456.2			519.3			458.2
Net income		14.9			215.2			21.5			438.8
Distributions		(177.3	)		(165.4	)		(530.6	)		(484.2	)
Beneficial conversion feature of preferred units		—			—			47.7			—

Ending balance	$	4,832.8		$	4,895.9		$	4,832.8		$	4,895.9

Accumulated other comprehensive loss
Beginning balance	$	(128.8	)	$	(314.4	)	$	(320.5	)	$	(316.5	)
Net realized income on changes in fair value of derivative financial instruments reclassified to earnings		4.8			2.8			21.3			25.1
Unrealized net income (loss) on derivative financial instruments		(18.8	)		(47.5	)		156.4			(67.7	)

Ending balance	$	(142.8	)	$	(359.1	)	$	(142.8	)	$	(359.1	)

Noncontrolling interest
Beginning balance	$	948.5		$	472.1		$	793.5		$	445.5
Capital contributions		205.5			91.2			355.2			122.3
Comprehensive income:
Net income		20.3			14.0			54.3			42.1
Distributions to noncontrolling interest		(11.0	)		(14.4	)		(39.7	)		(47.0	)

Ending balance	$	1,163.3		$	562.9		$	1,163.3		$	562.9

Total partners’ capital at end of period	$	7,011.3		$	5,099.7		$	7,011.3		$	5,099.7

Investments

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

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

The following table presents the net proceeds from the i-unit issuance for the nine month period ended September 30, 2013.


2013 Issuance Date	Number of i-units Issued		Price per i-unit		Net Proceeds to the Partnership⁽¹⁾		General Partner Contribution⁽²⁾		Net Proceeds Including General Partner Contribution
	(in millions, except units and per unit amount)
September		8,424,686	$	27.97	$	235.6	$	5.0	$	240.6
March		10,350,000	$	26.37	$	272.9	$	5.8	$	278.7

(1)	Net of underwriters’ fees, discounts, commissions, and estimated costs paid by Enbridge Management.

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

Series 1 Preferred Unit Purchase Agreement

On May 7, 2013, the Partnership entered into the Series 1 Preferred Unit Purchase Agreement, or Purchase Agreement, with our General Partner pursuant to which we issued and sold 48,000,000 of our Preferred Units, representing limited partner interests in the Partnership, for aggregate proceeds of approximately $1.2 billion. The closing of the transactions contemplated by the Purchase Agreement occurred on May 8, 2013.

The Preferred Units are entitled to annual cash distributions of 7.50% of the issue price, which are subject to reset every five years. In addition, quarterly cash distributions will not be payable on the Preferred Units during the first full eight quarters ending June 30, 2015, and instead will accrue and accumulate, which we refer to as the Payment Deferral, and will be payable upon the earlier of the fifth anniversary of the issuance of such Preferred Units or the redemption of such Preferred Units by the Partnership. The quarterly cash distribution for the three month period ended June 30, 2013 was prorated from May 8, 2013. On or after June 1, 2016, at the sole option of the holder of the Preferred Units, the Preferred Units may be converted into Class A Common Units, in whole or in part, at a conversion price of $27.78 per unit plus any accrued, accumulated and unpaid distributions, excluding the Payment Deferral, as adjusted for splits, combinations and unit distributions. At all other times, redemption of the Preferred Units, in whole or in part, is permitted only if: (1) the Partnership uses the net proceeds from incurring debt and issuing equity, which includes asset sales, in equal amounts to redeem such Preferred Units; (2) a material change in the current tax treatment of the Preferred Units occurs; or (3) the rating agencies’ treatment of the equity credit for the Preferred Units is reduced by 50% or more, all at a redemption price of $25.00 per unit plus any accrued, accumulated and unpaid distributions, including the Payment Deferral.

The Preferred Units were issued at a discount to the market price of the common units into which they are convertible. This discount totaling $47.7 million represents a beneficial conversion feature and is reflected as an increase in common and i-unit unitholders’ and General Partner’s capital and a decrease in Preferred Unitholders’ capital to reflect the fair value of the Preferred Units at issuance on the Partnership’s consolidated statement of changes in partners’ capital for the nine month period ended September 30, 2013. The beneficial conversion feature is considered a dividend and is distributed ratably from the issuance date of May 8, 2013 through the first conversion date, which is June 1, 2016, resulting in an increase in preferred capital and a decrease in common and subordinated unitholders’ capital. The impact of the beneficial conversion feature is also included in earnings per unit for the three and nine month periods ended September 30, 2013.

Proceeds from the Preferred Unit issuance were used by the Partnership to repay commercial paper, to finance a portion of its capital expansion program relating to its core liquids and natural gas systems and for general partnership purposes.

8. RELATED PARTY TRANSACTIONS

Joint Funding Arrangement for Alberta Clipper Pipeline

In July 2009, we entered into a joint funding arrangement to finance the construction of the United States segment of the Alberta Clipper Pipeline with several of our affiliates and affiliates of Enbridge Inc., or Enbridge, which we refer to as the Series AC. In March 2010, we refinanced $324.6 million of amounts we had outstanding and payable to our General Partner under the A1 Credit Agreement, a credit agreement between our General Partner and us to finance the Alberta Clipper Pipeline, by issuing a promissory note payable to our General Partner, which we refer to as the A1 Term Note. At such time we also terminated the A1 Credit Agreement. The A1 Term Note matures on March 15, 2020, bears interest at a fixed rate of 5.20% and has a maximum loan amount of $400.0 million. The terms of the A1 Term Note are similar to the terms of our 5.20% senior notes due 2020, except that the A1 Term Note has recourse only to the assets of the United States portion of the Alberta Clipper Pipeline and is subordinate to all of our senior indebtedness. Under the terms of the A1 Term Note, we have the ability to increase the principal amount outstanding to finance the debt portion of the Alberta Clipper Pipeline that our General Partner is obligated to make pursuant to the Alberta Clipper Joint Funding Arrangement for any additional costs associated with our construction of the Alberta Clipper Pipeline that we incur after the date the original A1 Term Note was issued. The increases we make to the principal balance of the A1 Term Note will also mature on March 15, 2020. Pursuant to the terms of the A1 Term Note, we are required to make semi-annual payments of principal and accrued interest. The semi-annual principal payments are based upon a straight-line amortization of the principal balance over a 30 year period as set forth in the approved terms of the cost of service recovery model associated with the Alberta Clipper Pipeline, with the unpaid balance due in 2020. The approved terms for the Alberta Clipper Pipeline are described in the “Alberta Clipper United States Term Sheet,” which is included as Exhibit I to the June 27, 2008 Offer of Settlement filed with the Federal Energy Regulatory Commission, or FERC, by the OLP and approved on August 28, 2008 (Docket No. OR08-12-000).

A summary of the cash activity for the A1 Term Note for the nine month periods ended September 30, 2013 and 2012 are as follows:


	A1 Term Note September 30,
	2013			2012
	(in millions)
Beginning Balance	$	330.0		$	342.0
Repayments		(12.0	)		(12.0	)

Ending Balance	$	318.0		$	330.0

We allocated earnings derived from operating the Alberta Clipper Pipeline in the amount of $13.4 million and $39.6 million to our General Partner for its 66.67% share of the earnings of the Alberta Clipper Pipeline for the three and nine month periods ended September 30, 2013, respectively. We also allocated $12.7 million and $40.8 million of such earnings to our General Partner for the three and nine month periods ended September 30, 2012, respectively. We have presented the amounts we allocated to our General Partner for its share of the earnings of the Alberta Clipper Pipeline in “Net income attributable to noncontrolling interest” on our consolidated statements of income.

Distribution to Series AC Interests

The following table presents distributions paid by the OLP to our General Partner and its affiliate during the nine month period ended September 30, 2013, representing the noncontrolling interest in the Series AC, and to

us, as the holders of the Series AC general and limited partner interests. The distributions were declared by the board of directors of Enbridge Management, acting on behalf of Enbridge Pipelines (Lakehead) L.L.C., the managing general partner of the OLP and the Series AC interests.


Distribution Declaration Date	Distribution Payment Date	Amount Paid to Partnership		Amount paid to the noncontrolling interest		Total Series AC Distribution
		(in millions)
July 29, 2013	August 14, 2013	$	5.5	$	11.0	$	16.5
April 30, 2013	May 15, 2013	$	7.5	$	14.9	$	22.4
January 30, 2013	February 14, 2013	$	6.9	$	13.8	$	20.7

		$	19.9	$	39.7	$	59.6

Joint Funding Arrangement for Eastern Access Projects

In May 2012, we amended and restated the partnership agreement of the OLP to establish an additional series of partnership interests, which we refer to as the EA interests. The EA interests were created to finance projects to increase access to refineries in the United States Upper Midwest and in Ontario, Canada for light crude oil produced in western Canada and the United States, which we refer to as the Eastern Access Projects. From May 2012 through June 27, 2013, our General Partner indirectly owned 60% of all assets, liabilities and operations related to the Eastern Access Projects. On June 28, 2013, we and our affiliates entered into an agreement with our General Partner pursuant to which we exercised our option to decrease our economic interest and funding of the Eastern Access Projects from 40% to 25%. Additionally, within one year of the in-service date, currently scheduled for early 2016, we have the option to increase our economic interest by up to 15 percentage points back to 40%. We received $90.2 million from our General Partner in consideration for our assignment to it of this portion of our interest, determined based on the capital we had funded prior to June 28, 2013 pursuant to Eastern Access Projects.

Our General Partner has made equity contributions totaling $272.5 million and $122.3 million to the OLP during the nine month periods ended September 30, 2013 and 2012, respectively to fund its equity portion of the construction costs associated with the Eastern Access Projects.

We allocated earnings from the Eastern Access Projects in the amount of $6.6 million and $14.4 million to our General Partner for its ownership of the EA interest for the three and nine month periods ended September 30, 2013, respectively. We allocated earnings derived from the Eastern Access Projects in the amount of $1.3 million to our General Partner for the three and nine month periods ended September 30, 2012 .We have presented this amount we allocated to our General Partner in “Net income attributable to noncontrolling interest” on our consolidated statements of income.

Joint Funding Arrangement for U.S. Mainline Expansion Projects

In December 2012, the OLP further amended and restated its limited partnership agreement to establish another series of partnership interests, which we refer to as the ME interests. The ME interests were created to finance projects to increase access to the markets of North Dakota and western Canada for light oil production on our Lakehead System between Neche, North Dakota and Superior, Wisconsin, which we refer to as our Mainline Expansion Projects. From December 2012 through June 27, 2013, the projects were jointly funded by our General Partner at 60% and the Partnership at 40%, under the Mainline Expansion Joint Funding Agreement, which parallels the Eastern Access Joint Funding Agreement. On June 28, 2013, we and our affiliates entered into an agreement with our General Partner pursuant to which we exercised our option to decrease our economic interest and funding in the projects from 40% to 25%. Additionally, within one year of the in-service date, currently scheduled for 2016, we have the option to increase our economic interest by up to 15 percentage points back to 40%. All other operations are captured by the Lakehead interests. We received $12.0 million from our

General Partner in consideration for our assignment to it of this portion of our interest, determined based on the capital we had funded prior to June 28, 2013 pursuant to the Mainline Expansion Projects.

Our General Partner has made equity contributions totaling $82.7 million to the OLP for the nine month period ended September 30, 2013 to fund its equity portion of the construction costs associated with the Mainline Expansion Projects. No such contributions were made during the nine month period ended September 30, 2012.

We allocated earnings from the Mainline Expansion Projects in the amount of $0.3 million to our General Partner for its ownership of the ME interest for the three and nine month periods ended September 30, 2013.We have presented this amount we allocated to our General Partner in “Net income attributable to noncontrolling interest” on our consolidated statements of income.

Sale of Accounts Receivable

Certain of our subsidiaries entered into a receivables purchase agreement, dated June 28, 2013, which we refer to as the Receivables Agreement, with an indirect wholly-owned subsidiary of Enbridge which was amended on September 20, 2013. The Receivables Agreement and the transactions contemplated thereby were approved by the special committee of the board of directors of Enbridge Management. Pursuant to the Receivables Agreement, the Enbridge subsidiary will purchase on a monthly basis, for cash, current accounts receivable and accrued receivables, or the receivables, of the respective subsidiaries initially up to a monthly maximum of $450.0 million. Following the sale and transfer of the receivables to the Enbridge subsidiary, the receivables are deposited in an account of that subsidiary, and ownership and control are vested in that subsidiary. The Enbridge subsidiary has no recourse with respect to the receivables acquired from these operating subsidiaries under the terms of and subject to the conditions stated in the Receivables Agreement. The Partnership acts 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. The Partnership has no other involvement with the purchase and sale of the receivables pursuant to the Receivables Agreement. The Receivables Agreement terminates on December 30, 2016.

Consideration for the receivables sold is equivalent to the carrying value of the receivables less a discount for credit risk. The difference between the carrying value of the receivables sold and the cash proceeds received is recognized in “Operating and administrative-affiliate” expense in our consolidated statements of income. For the three and nine month periods ended September 30, 2013, the cost stemming from the discount on the receivables sold was not material. For the three and nine month periods ended September 30, 2013, we sold and derecognized $822.6 million and $1,037.9 million, respectively, of receivables to the Enbridge subsidiary. For the three and nine month periods ended September 30, 2013, the cash proceeds were $822.4 million and $1,037.6 million, respectively, which was remitted to the Partnership through our centralized treasury system. As of September 30, 2013, $402.2 million of the receivables were outstanding from customers that had not been collected on behalf of the Enbridge subsidiary, $79.8 million were trade receivables and $322.4 million were accrued receivables.

As of September 30, 2013, we have $2.2 million included in “Restricted cash” on our consolidated statements of financial position, consisting of cash collections related to the Receivables sold that have yet to be remitted to the Enbridge subsidiary as of September 30, 2013. The Enbridge subsidiary retains the right to select a new collection agent at any time.

9. COMMITMENTS AND CONTINGENCIES

Environmental Liabilities

We are subject to federal and state laws and regulations relating to the protection of the environment. Environmental risk is inherent to liquid hydrocarbon and natural gas pipeline operations, and we are, at times,

subject to environmental cleanup and enforcement actions. We manage this environmental risk through appropriate environmental policies and practices to minimize any impact our operations may have on the environment. To the extent that we are unable to recover environmental liabilities through insurance or other potentially responsible parties, we will be responsible for payment of liabilities arising from environmental incidents associated with the operating activities of our Liquids and Natural Gas businesses. Our General Partner has agreed to indemnify us from and against any costs relating to environmental liabilities associated with the Lakehead system assets prior to the transfer of these assets to us in 1991. This excludes any liabilities resulting from a change in laws after such transfer. We continue to voluntarily investigate past leak sites on our systems for the purpose of assessing whether any remediation is required in light of current regulations.

As of September 30, 2013 and December 31, 2012, we had $35.7 million and $18.3 million, respectively, included in “Other long-term liabilities,” that we have accrued for costs we have recognized primarily to address remediation of contaminated sites, asbestos containing materials, management of hazardous waste material disposal, outstanding air quality measures for certain of our liquids and natural gas assets and penalties we have been or expect to be assessed.

Lakehead Line 6B Crude Oil Release

We continue to perform necessary remediation, restoration and monitoring of the areas affected by the Line 6B crude oil release. All the initiatives we are undertaking in the monitoring and restoration phase are intended to restore the crude oil release area to the satisfaction of the appropriate regulatory authorities.

As of September 30, 2013, our total cost estimate for the Line 6B crude oil release is $1,035.0 million, which is an increase of $215.0 million as compared to December 31, 2012. This total estimate is before insurance recoveries and excluding additional fines and penalties which may be imposed by federal, state and local governmental agencies, other than the Pipeline and Hazardous Materials Safety Administration, or PHMSA, civil penalty of $3.7 million, we paid during the third quarter of 2012. On March 14, 2013, we received an order from the EPA, or the Environmental Protection Agency, which we refer to as the Order, that defined the scope which requires additional containment and active recovery of submerged oil relating to the Line 6B crude oil release. We submitted our initial proposed work plan required by the EPA on April 4, 2013, and we resubmitted the workplan on April 23, 2013. The EPA approved the Submerged Oil Recovery and Assessment workplan, or SORA, with modifications on May 8, 2013. We incorporated the modification and submitted an approved SORA on May 13, 2013. The Order states that the work must be completed by December 31, 2013.

The $175.0 million increase in the total cost estimate during the three month period ending March 31, 2013, was attributable to additional work required by the Order. The $40.0 million increase during the three month period ending June 30, 2013 was attributable to further refinement and definition of the additional dredging scope per the Order and associated environmental, permitting, waste removal and other related costs. The actual costs incurred may differ from the foregoing estimate as we complete the work plan with the EPA related to the Order and work with other regulatory agencies to assure that our work plan complies with their requirements. Any such incremental costs will not be recovered under our insurance policies as our costs for the incident at September 30, 2013 exceeded the limits of our insurance coverage.

For purposes of estimating our expected losses associated with the Line 6B crude oil release, we have included those costs that we considered probable and that could be reasonably estimated at September 30, 2013. Our estimates do not include amounts we have capitalized or any claims associated with the release that may later become evident and is before any insurance recoveries and excludes fines and penalties from other governmental agencies other than the PHMSA civil penalty described above. Our assumptions include, where applicable, estimates of the expected number of days the associated services will be required and rates that we have obtained from contracts negotiated for the respective service and equipment providers. As we receive invoices for the actual personnel, equipment and services, our estimates will continue to be further refined. Our estimates also consider currently available facts, existing technology and presently enacted laws and regulations.

These amounts also consider our and other companies’ prior experience remediating contaminated sites and data released by government organizations. Despite the efforts we have made to ensure the reasonableness of our estimates, changes to the recorded amounts associated with this release are possible as more reliable information becomes available. We continue to have the potential of incurring additional costs in connection with this crude oil release due to variations in any or all of the categories described above, including modified or revised requirements from regulatory agencies in addition to fines and penalties as well as expenditures associated with litigation and settlement of claims.

The material components underlying our total estimated loss for the cleanup, remediation and restoration associated with the Line 6B crude oil release include the following:


	(in millions)
Response Personnel & Equipment	$	454
Environmental Consultants		193
Professional, regulatory and other		388

Total	$	1,035

For the nine month periods ended September 30, 2013 and 2012, we made payments of $62.3 million and $120.9 million, respectively, for costs associated with the Line 6B crude oil release. For the nine month period ended September 30, 2013, we recognized a $2.6 million impairment for homes purchased due to the Line 6B crude oil release which is included in the “Environmental costs, net of recoveries” on our consolidated statements of income. As of September 30, 2013 and December 31, 2012, we had a remaining estimated liability of $265.9 million and $115.8 million, respectively.

Lakehead Line 6A Crude Oil Release

On October 21, 2013, the National Transportation Safety Board, or NTSB, publicly posted their final report related to the Line 6A crude oil release that occurred in Romeoville, Illinois on September 9, 2010, which states that the probable cause of the crude oil release was erosion caused by a leaking water pipe resulting from an improperly installed third-party water service line below our oil pipeline.

Our total estimated costs for the Line 6A crude oil release remains at $48.0 million, of which $0.3 million is the remaining liability at September 30, 2013.

Lines 6A & 6B Fines and Penalties

At September 30, 2013, our total estimated costs for the Line 6A crude oil release do not include an estimate for fines and penalties, which may be imposed by the EPA and PHMSA, in addition to other federal, state and local governmental agencies. At September 30, 2013, our estimated costs to the Line 6B crude oil release include $3.7 million in civil penalties assessed by PHMSA that we paid during the third quarter of 2012, but do not include any other fines or penalties which may be imposed by other governmental agencies. Several factors remain outstanding at the end of the period that we consider critical in estimating the amount of additional fines and penalties that we may be assessed.

Due to the absence of sufficient information, we cannot provide a reasonable estimate of our liability for potential additional fines and penalties that we could be assessed in connection with each of the releases. As a result, except for the PHMSA civil penalty, we have not recorded any liability for expected fines and penalties.

Insurance Recoveries

We are included in the comprehensive insurance program that is maintained by Enbridge for its subsidiaries and affiliates that renew throughout the year. On May 1 of each year, our insurance program is up for renewal

and includes commercial liability insurance coverage that is consistent with coverage considered customary for our industry and includes coverage for environmental incidents such as those we have incurred for the crude oil releases from Lines 6A and 6B, excluding costs for fines and penalties.

The claims for the crude oil release for Line 6B are covered by the insurance policy that expired on April 30, 2011, which had an aggregate limit of $650.0 million for pollution liability. Based on our remediation spending through September 30, 2013, we have exceeded the limits of coverage under this insurance policy. During the third quarter 2013, we received $42.0 million of insurance recoveries for a claim we filed in connection with the Line 6B crude oil release and recognized as a reduction to environmental cost in the second quarter of 2013. We recognized $170.0 million of insurance recoveries as reductions to “Environmental costs, net of recoveries” in our consolidated statements of income for the three and nine month periods ended September 30, 2012 for the Line 6B crude oil release. As of September 30, 2013, we have recorded total insurance recoveries of $547.0 million for the Line 6B crude oil release, out of the $650.0 million aggregate limit. We expect to record receivables for additional amounts we claim for recovery pursuant to our insurance policies during the period that we deem realization of the claim for recovery to be probable.

In March 2013, we and Enbridge filed a lawsuit against the insurers of our remaining $145.0 million coverage, as one particular insurer is disputing our recovery eligibility for costs related to our claim on the Line 6B crude oil release and the other remaining insurers assert that their payment is predicated on the outcome of our recovery with that insurer. We received a partial recovery payment of $42.0 million from the other remaining insurers and have since amended our lawsuit, such that it now includes only one insurer. While we believe that our claims for the remaining $103.0 million are covered under the policy, there can be no assurance that we will prevail in this lawsuit.

We are pursuing recovery of the costs associated with the Line 6A crude oil release from third parties; however, there can be no assurance that any such recovery will be obtained. Additionally, fines and penalties would not be covered under our existing insurance policy.

Effective May 1, 2013, Enbridge renewed its comprehensive property and liability insurance programs, under which we are insured through April 30, 2014, with a current liability aggregate limit of $685.0 million, including sudden and accidental pollution liability. In the unlikely event multiple insurable incidents occur which exceed coverage limits within the same insurance period, the total insurance coverage will be allocated among the Enbridge entities on an equitable basis based on an insurance allocation agreement the Partnership has entered into with Enbridge and another Enbridge subsidiary.

Legal and Regulatory Proceedings

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

A number of governmental agencies and regulators have initiated investigations into the Line 6B crude oil release. Approximately 30 actions or claims are pending against us and our affiliates, in state and federal courts in connection with the Line 6B crude oil release, including direct actions and actions seeking class status. Based on the current status of these cases, we do not expect the outcome of these actions to be material. On July 2, 2012, PHMSA announced a Notice of Probable Violation, or NOPV, related to the Line 6B crude oil release, including a civil penalty of $3.7 million that we paid during the third quarter of 2012.

Governmental agencies and regulators have also initiated investigations into the Line 6A crude oil release. One claim has been filed against us and our affiliates by the State of Illinois in an Illinois state court in connection with this crude oil release, and the parties are currently operating under an agreed interim order. The costs associated with this order are included in the estimated environmental costs accrued for the Line 6A crude oil release. We are also pursuing recovery of the costs associated with the Line 6A crude oil release from third parties; however, there can be no assurance that any such recovery will be obtained.

We have accrued a provision for future legal costs and probable losses associated with the Line 6A and Line 6B crude oil releases as described above in this footnote.

On July 25, 2013, the U.S. Department of Justice, or DOJ, and the EPA filed a complaint against us related to permit violations for the discharge of hydrotest water in 2010 related to the Alberta Clipper Pipeline and one of our affiliates. We have agreed to settle with the DOJ and EPA for $254.0 thousand related to the Alberta Clipper Pipeline portion of the permit violation.

10. DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES

Our net income and cash flows are subject to volatility stemming from changes in interest rates on our variable rate debt obligations and fluctuations in commodity prices of natural gas, NGLs, condensate, crude oil and fractionation margins. Fractionation margins represent the relative difference between the price we receive from NGL and condensate sales and the corresponding cost of natural gas we purchase for processing. Our interest rate risk exposure results from changes in interest rates on our variable rate debt and exists at the corporate level where our variable rate debt obligations are issued. Our exposure to commodity price risk exists within each of our segments. We use derivative financial instruments (i.e., futures, forwards, swaps, options and other financial instruments with similar characteristics) to manage the risks associated with market fluctuations in interest rates and commodity prices, as well as to reduce volatility of our cash flows. Based on our risk management policies, all of our derivative financial instruments are employed in connection with an underlying asset, liability and/or forecasted transaction and are not entered into with the objective of speculating on interest rates or commodity prices. We have hedged a portion of our exposure to variability in future cash flows associated with the risks discussed above through 2018 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, or 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 estimate 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 “Operating revenue,” “Cost of natural gas” and “Power” for our commodity-based derivatives and “Interest expense” for our interest rate 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” in our consolidated statements of financial position, until the underlying hedged transaction occurs. To the extent that the hedge instrument is effective in offsetting the transaction being hedged, there is no impact to the income statement until the underlying transaction occurs. At inception and on a quarterly basis, we formally assess whether the hedge contract is highly effective in offsetting changes in cash flows of hedged items. Any

ineffective portion of a cash flow hedge’s change in fair market value is recognized each period in earnings. Realized gains and losses on derivative financial instruments that are designated as hedges and qualify for hedge accounting are included in “Cost of natural gas” for commodity hedges and “Interest expense” for interest rate hedges in our consolidated statements of income in the period in which the hedged transaction occurs. Gains and losses deferred in AOCI related to cash flow hedges for which hedge accounting has been discontinued remain in AOCI until the underlying physical transaction occurs unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period or within an additional two-month period of time thereafter. Generally, our preference is for our derivative financial instruments to receive hedge accounting treatment whenever possible to mitigate the non-cash earnings volatility that arises from recording the changes in fair value of our derivative financial instruments through earnings. To qualify for cash flow hedge accounting treatment as set forth in the authoritative accounting guidance, very specific requirements must be met in terms of hedge structure, hedge objective and hedge documentation.

Non-Qualified Hedges

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

The following transaction types do not qualify for hedge accounting and contribute to the volatility of our income and cash flows:

Commodity Price Exposures:

•

Transportation—In our Marketing segment, when we transport natural gas from one location to another, the pricing index used for natural gas sales is usually different from the pricing index used for natural gas purchases, which exposes us to market price risk relative to changes in those two indices. By entering into a basis swap, where we exchange one pricing index for another, we can effectively lock in the margin, representing the difference between the sales price and the purchase price, on the combined natural gas purchase and natural gas sale, removing any market price risk on the physical transactions. Although this represents a sound economic hedging strategy, the derivative financial instruments (i.e., the basis swaps) we use to manage the commodity price risk associated with these transportation contracts do not qualify for hedge accounting, since only the future margin has been fixed and not the future cash flow. As a result, the changes in fair value of these derivative financial instruments are recorded in earnings.

•

Storage—In our Marketing segment, 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

is 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 storage activities can create volatility in our earnings.

•

Natural Gas and NGL Options—In our Natural Gas segment, 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.

•

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

•

NGL Forward Contracts—In our Natural Gas 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. A sub-group of physical NGL sales 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 NGL prices until the forward contracts are settled.

•

Natural Gas Forward Contracts—In our Marketing segment, we use forward contracts to sell natural gas to our customers. A sub-group of physical natural gas sales contracts with terms allowing for economic net settlement do 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 Oil Contracts—In our Liquids segment, we use forward contracts to hedge a portion of the crude oil length inherent in the operation of our pipelines, which we subsequently sell at market rates. These hedges create a fixed sales price for the crude oil that we will receive in the future. We elected not to designate these derivative financial instruments as cash flow hedges, and as a result, will experience some additional volatility associated with fluctuations in crude oil prices until the underlying transactions are settled or offset.

•

Power Purchase Agreements—In our Liquids segment, we use forward physical power agreements to fix the price of a portion of the power consumed by our pumping stations in the transportation of crude oil in our owned pipelines. We designate these derivative agreements as non-qualifying hedges because they fail to meet the criteria for cash flow hedging or the NPNS exception. As various states in which our pipelines operate have legislated either partially or fully deregulated power markets, we have the opportunity to create economic hedges on power exposure. As a result, our operating income is subject to additional volatility associated with changes in the fair value of these agreements due to fluctuations in forward power prices.

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

Derivative Positions

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


	September 30, 2013			December 31, 2012
	(in millions)
Other current assets	$	16.9		$	28.3
Other assets, net		65.0			15.8
Accounts payable and other ⁽¹⁾		(161.2	)		(256.7	)
Other long-term liabilities		(56.5	)		(68.3	)

	$	(135.8	)	$	(280.9	)

⁽¹⁾	Includes $11.6 million of cash collateral at September 30, 2013.

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 $35.5 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 $132.9 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.

During the second quarter of 2013 it was determined that a portion of forecasted short term debt transactions are not expected to occur, due to changing funding requirements. Since we will require less short-term debt than previously forecasted, we terminated several of our existing interest rate hedges used to lock-in interest rates on our short-term debt issuances as these hedges no longer meet the cash flow hedging requirements. These terminations resulted in realized losses of $5.3 million for the nine month period ended September 30, 2013.

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		(57.7	)		(116.5	)
A⁽²⁾		(74.0	)		(147.7	)
Lower than A		(4.2	)		(16.7	)

	$	(135.8	)	$	(280.9	)

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

⁽²⁾	Includes $11.6 million of cash collateral at September 30, 2013.

As the net value of our derivative financial instruments has increased in response to changes in forward commodity prices, our outstanding financial exposure to third parties has also increased. When credit thresholds are met pursuant to the terms of our International Swaps and Derivatives Association, Inc., or ISDA^®, financial contracts, we have the right to require collateral from our counterparties. We include any cash collateral received in the balances listed above. As of September 30, 2013 we are holding $11.6 million in cash collateral on our asset exposures, however, as of 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 interest rate and commodity swaps require that collateral be posted per tiered contractual thresholds based on the credit rating of each counterparty. We generally provide letters of credit to satisfy such collateral requirements under our ISDA^® agreements. These agreements will require additional collateral postings of up to 100% on net liability positions in the event of a credit downgrade below investment grade. Automatic termination clauses which exist are related only to non-performance activities, such as the refusal to post collateral when contractually required to do so. When we are holding an asset position, our counterparties are likewise required to post collateral on their liability (our asset) exposures, also determined by tiered contractual collateral thresholds. Counterparty collateral may consist of cash or letters of credit, both of which must be fulfilled with immediately available funds.

In the event that our credit ratings were to decline to the lowest level of investment grade, as determined by Standard & Poor’s and Moody’s, we would be required to provide additional amounts under our existing letters of credit to meet the requirements of our ISDA^® agreements. For example, if our credit ratings had been at the lowest level of investment grade at September 30, 2013, we would have been required to provide additional letters of credit in the amount of $33.0 million.

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	)	$	(204.5	)
Non-United States financial institutions ⁽¹⁾		(17.5	)		(84.6	)
Other		(3.8	)		8.2

	$	(135.8	)	$	(280.9	)

⁽¹⁾	Includes $11.6 million of cash collateral at September 30, 2013.

As of September 30, 2013, we are holding $11.6 million of cash collateral on our asset exposures, and we have provided letters of credit totaling $88.6 million and $231.2 million relating to our liability exposures pursuant to the margin thresholds in effect at September 30, 2013 and December 31, 2012, respectively, under our ISDA^® agreements.

Gross derivative balances are presented below before the effects of collateral received or posted and without the effects of master netting arrangements. Both our assets and liabilities are adjusted for non-performance risk, which is statistically derived. This credit valuation adjustment model considers existing derivative asset and liability balances in conjunction with contractual netting and collateral arrangements, current market data such as credit default swap rates and bond spreads and probability of default assumptions to quantify an adjustment to fair value. For credit modeling purposes, collateral received is included in the calculation of our assets, while any collateral posted is excluded from the calculation of the credit adjustment. Our credit exposure for these 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 as hedging instruments⁽¹⁾
Interest rate contracts	Other assets	$	47.8	$	2.7	$	—		$	—
Interest rate contracts	Accounts payable and other⁽²⁾		—		—		(123.0	)		(246.9	)
Interest rate contracts	Other long-term liabilities		2.3		3.3		(57.6	)		(68.3	)
Commodity contracts	Other current assets		2.4		12.1		(1.8	)		(4.2	)
Commodity contracts	Other assets		4.8		2.5		(1.2	)		(1.0	)
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	)

			61.7		27.3		(193.3	)		(330.6	)


Derivatives not designated as hedging instruments
Interest rate contracts	Other current assets		—		2.4		—			(2.2	)
Commodity contracts	Other current assets		18.8		27.2		(2.5	)		(7.1	)
Commodity contracts	Other assets		14.5		11.8		(0.9	)		(0.1	)
Commodity contracts	Accounts payable and other		8.9		1.6		(31.1	)		(10.4	)
Commodity contracts	Other long-term liabilities		0.2		1.5		(0.5	)		(2.3	)

			42.4		44.5		(35.0	)		(22.1	)

Total derivative instruments		$	104.1	$	71.8	$	(228.3	)	$	(352.7	)

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

⁽²⁾	Liability derivatives exclude $11.6 million of cash collateral at September 30, 2013.

⁽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
Interest rate contracts	$	1.7		Interest expense	$	(4.2	)	Interest expense	$	(1.1	)
Commodity contracts		(17.2	)	Cost of natural gas		(0.6	)	Cost of natural gas		(0.5	)

Total	$	(15.5	)		$	(4.8	)		$	(1.6	)

For the three month period ended September 30, 2012
Interest rate contracts	$	(23.5	)	Interest expense	$	(7.4	)	Interest expense	$	(0.1	)
Commodity contracts		(22.9	)	Cost of natural gas		4.6		Cost of natural gas		(3.9	)

Total	$	(46.4	)		$	(2.8	)		$	(4.0	)

For the nine month period ended September 30, 2013
Interest rate contracts	$	179.3		Interest expense	$	(24.3	)	Interest expense	$	(0.5	)
Commodity contracts		(8.8	)	Cost of natural gas		3.0		Cost of natural gas		1.8

Total	$	170.5			$	(21.3	)		$	1.3

For the nine month period ended September 30, 2012
Interest rate contracts	$	(90.4	)	Interest expense	$	(21.7	)	Interest expense	$	0.2
Commodity contracts		47.2		Cost of natural gas		(3.4	)	Cost of natural gas		1.2

Total	$	(43.2	)		$	(25.1	)		$	1.4

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

Components of Accumulated Other Comprehensive Income/(Loss)


	Cash Flow Hedges
	(in millions)
Balance at December 31, 2012	$	(320.5	)
Other Comprehensive Income before reclassifications		156.4
Amounts reclassified from AOCI⁽¹⁾		21.3

Net Other Comprehensive Income	$	177.7

Balance at September 30, 2013	$	(142.8	)

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

Reclassifications from Accumulated Other Comprehensive Income


	For the three month period ended September 30,					For the nine month period ended September 30,
	2013		2012			2013			2012
	(in millions)
Losses (gains) on cash flow hedges:
Interest Rate Contracts⁽¹⁾	$	4.2	$	7.4		$	24.3		$	21.7
Commodity Contracts⁽²⁾		0.6		(4.6	)		(3.0	)		3.4

Total Reclassifications from AOCI	$	4.8	$	2.8		$	21.3		$	25.1

⁽¹⁾	Loss (gain) reported within “Interest expense” in the consolidated statements of income.

⁽²⁾	Loss (gain) reported within “Cost of natural gas” in the consolidated statements of income.

Effect of Derivative Instruments on Consolidated Statements of Income


		For the three month period ended September 30,						For the nine month period ended September 30,
		2013			2012 ⁽⁶⁾			2013			2012 ⁽⁶⁾
Derivatives Not Designated as Hedging Instruments	Location of Gain or (Loss) Recognized in Earnings⁽¹⁾	Amount of Gain or (Loss) Recognized in Earnings⁽²⁾						Amount of Gain or (Loss) Recognized in Earnings⁽²⁾
		(in millions)
Interest rate contracts	Interest expense⁽³⁾	$	0.1		$	—		$	—		$	—
Commodity contracts	Operating revenue⁽⁴⁾		(16.7	)		(8.0	)		(14.0	)		6.8
Commodity contracts	Power		0.1			0.2			0.3			—
Commodity contracts	Cost of natural gas⁽⁵⁾		(21.8	)		(12.4	)		(2.6	)		21.7

Total		$	(38.3	)	$	(20.2	)	$	(16.3	)	$	28.5

⁽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 settlement gains of $0.1 million, $0.2 million, $0.3 million and $0.4 million for the three and nine month periods ended September 30, 2013 and September 30, 2012, respectively.

⁽⁴⁾

Includes settlement losses of $0.7 million for the three month period ended September 30, 2013, settlement gains of $1.8 million for the three month period ended September 30, 2012 and settlement gains of $1.0 million and $4.1 million for the nine month periods ended September 30, 2013 and September 30, 2012, respectively.

⁽⁵⁾

Includes settlement 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.

⁽⁶⁾

The effects of derivative instruments on consolidated statements of income for the three and nine month periods ended September 30, 2012 have been revised to include settlement gains on derivatives not designated as hedge instruments of $10.3 million and $19.5 million, respectively. The revisions to the disclosure had no impact on previously reported net income or earnings per unit.

Gross to Net Presentation Reconciliation of Derivative Assets and Liabilities


	September 30, 2013									December 31, 2012
	Assets			Liabilities⁽¹⁾			Total			Assets			Liabilities			Total
	(in millions)
Fair value of derivatives—gross presentation	$	104.1		$	(239.9	)	$	(135.8	)	$	71.8		$	(352.7	)	$	(280.9	)
Effects of netting agreements		(22.2	)		22.2			—			(27.7	)		27.7			—

Fair value of derivatives—net presentation	$	81.9		$	(217.7	)	$	(135.8	)	$	44.1		$	(325.0	)	$	(280.9	)

⁽¹⁾	Includes $11.6 million of cash collateral at September 30, 2013.

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	$	104.1	$	(22.2	)	$	81.9	$	(16.3	)	$	65.6

Total	$	104.1	$	(22.2	)	$	81.9	$	(16.3	)	$	65.6

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⁽¹⁾	$	(239.9	)	$	22.2	$	(217.7	)	$	16.3	$	(201.4	)

Total	$	(239.9	)	$	22.2	$	(217.7	)	$	16.3	$	(201.4	)

⁽¹⁾	Includes $11.6 million of cash collateral at September 30, 2013.

Inputs to Fair Value Derivative Instruments

The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 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)
Interest rate contracts ⁽¹⁾	$	—	$	(142.1	)	$	—		$	(142.1	)	$	—	$	(309.0	)	$	—	$	(309.0	)
Commodity contracts:
Financial		—		2.4			0.9			3.3			—		7.2			8.4		15.6
Physical		—		—			(3.9	)		(3.9	)		—		—			6.1		6.1
Commodity options		—		—			6.9			6.9			—		—			6.4		6.4

Total	$	—	$	(139.7	)	$	3.9		$	(135.8	)	$	—	$	(301.8	)	$	20.9	$	(280.9	)

⁽¹⁾	Includes $11.6 million of cash collateral at September 30, 2013.

Qualitative Information about Level 3 Fair Value Measurements

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

Quantitative Information About Level 3 Fair Value Measurements


	Fair Value at September 30, 2013 ⁽²⁾			Valuation Technique	Unobservable Input	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	$	(1.7	)	Market Approach	Forward NGL Price		0.25			2.08			1.25		Gal
Commodity Contracts - Physical
Natural Gas	$	1.0		Market Approach	Forward Gas Price		3.24			4.35			3.72		MMBtu
Crude Oil	$	0.6		Market Approach	Forward Crude Price		86.59			107.94			100.97		Bbl
NGLs	$	(4.6	)	Market Approach	Forward NGL Price		0.01			2.28			0.95		Gal
Power	$	(0.9	)	Market Approach	Forward Power Price		30.98			36.75			33.17		MWh
Commodity Options
Natural Gas, Crude and NGLs	$	6.9		Option Model	Option Volatility		24	%		145	%		41	%

Total Fair Value	$	3.9

⁽¹⁾	Prices are in dollars per Millions of British Thermal Units, or MMBtu, for Natural Gas, dollars per Gallon, or Gal, for NGLs, dollars per barrel, or Bbl, for Crude Oil and dollars per Megawatt hour, or MWh, for Power.

⁽²⁾	Fair values are presented in millions of dollars and include credit valuation adjustments of approximately $0.2 million of losses.

Quantitative Information About Level 3 Fair Value Measurements


	Fair Value at December 31, 2012 ⁽²⁾			Valuation Technique	Unobservable Input	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	$	1.6		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
Power	$	(1.2	)	Market Approach	Forward Power Price		30.09			36.35			32.74		MWh
Commodity Options
Natural Gas, Crude and NGLs	$	6.4		Option Model	Option Volatility		29	%		104	%		40	%

Total Fair Value	$	20.9

⁽¹⁾	Prices are in dollars per Millions of British Thermal Units, or MMBtu, for Natural Gas, dollars per Gallon, or Gal, for NGLs, dollars per barrel, or Bbl, for Crude Oil and dollars per Megawatt hour, or MWh, for Power.

⁽²⁾	Fair values are presented in millions of dollars and include credit valuation adjustments of approximately $0.2 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		$	6.1		$	6.4		$	20.9
Transfer out of Level 3⁽¹⁾		—			—			—			—
Gains or losses:
Included in earnings (or changes in net assets)		1.8			23.8			(0.5	)		25.1
Included in other comprehensive income		3.4			—			—			3.4
Purchases, issuances, sales and settlements:
Purchases		—			—			3.0			3.0
Settlements⁽²⁾		(12.7	)		(33.8	)		(2.0	)		(48.5	)

Ending balance as September 30, 2013	$	0.9		$	(3.9	)	$	6.9		$	3.9

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

Amounts reported in operating revenue	$	—		$	(5.9	)	$	—		$	(5.9	)

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

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

Fair Value Measurements of Commodity Derivatives

The following table provides summarized information about the fair values of expected cash flows of our outstanding commodity based swaps and physical contracts at September 30, 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		125,000	$	101.15	$	105.40	$	—	$	(0.5	)	$	0.2	$	—
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		6,127,784	$	47.49	$	47.21	$	3.8	$	(2.2	)	$	5.2	$	(2.3	)
	Crude Oil		1,069,704	$	101.34	$	100.04	$	2.7	$	(1.3	)	$	6.4	$	(3.0	)
Pay fixed	Power⁽⁴⁾		10,824	$	33.10	$	42.82	$	—	$	(0.1	)	$	—	$	(0.5	)
*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	)	$	—	$	—
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	$	—	$	—		$	—	$	—
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	$	0.8	$	(0.4	)	$	0.5	$	—
	NGL		7,037,705	$	33.02	$	32.90	$	1.8	$	(0.9	)	$	—	$	—
Pay fixed	Power⁽⁴⁾		58,608	$	33.19	$	46.58	$	—	$	(0.8	)	$	—	$	(0.8	)
*Portion of contracts maturing in 2015*
Swaps
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. Our power purchase agreements are measured in MWh.

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

⁽³⁾

The fair value is determined based on quoted market prices at September 30, 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 $0.3 million of losses at September 30, 2013 and $0.4 million of losses at December 31, 2012.

⁽⁴⁾	For physical power, the receive price shown represents the index price used for valuation purposes.

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

Fair Value Measurements of Interest Rate Derivatives

We enter into interest rate swaps, caps and derivative financial instruments with similar characteristics to manage the cash flow associated with future interest rate movements on our indebtedness. The following table provides information about our current interest rate derivatives for the specified periods.


							Fair Value⁽²⁾ at
Date of Maturity & Contract Type	Accounting Treatment	Notional		Average Fixed Rate⁽¹⁾			September 30, 2013			December 31, 2012
				(dollars in millions)
*Contracts maturing in 2013*
Interest Rate Swaps—Pay Fixed	Cash Flow Hedge	$	500		4.16	%	$	(4.0	)	$	(22.6	)
Interest Rate Swaps—Pay Fixed	Non-qualifying	$	—		—		$	—		$	(2.2	)
Interest Rate Swaps—Pay Float	Non-qualifying	$	—		—		$	—		$	2.4
*Contracts maturing in 2014*
Interest Rate Swaps—Pay Fixed	Cash Flow Hedge	$	—		—		$	—		$	(0.6	)
*Contracts maturing in 2015*
Interest Rate Swaps—Pay Fixed	Cash Flow Hedge	$	300		2.43	%	$	(6.9	)	$	(6.7	)
*Contracts maturing in 2017*
Interest Rate Swaps—Pay Fixed	Cash Flow Hedge	$	400		2.21	%	$	(13.0	)	$	(16.0	)
*Contracts maturing in 2018*
Interest Rate Swaps—Pay Fixed	Cash Flow Hedge	$	325		1.26	%	$	1.7		$	(1.8	)
*Contracts settling prior to maturity*
2013—Pre-issuance Hedges ⁽³⁾	Cash Flow Hedge	$	800		4.47	%	$	(126.7	)	$	(238.4	)⁽⁴⁾
2014—Pre-issuance Hedges	Cash Flow Hedge	$	1,050		3.71	%	$	(37.1	)	$	(45.3	)
2016—Pre-issuance Hedges	Cash Flow Hedge	$	500		2.87	%	$	47.4		$	8.4

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

⁽²⁾

The fair value is determined from quoted market prices at 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 $3.5 million of losses at September 30, 2013 and $13.7 million of gains at December 31, 2012.

⁽³⁾	Includes $11.6 million of cash collateral at September 30, 2013.

⁽⁴⁾

The December 31, 2012 fair value of pre-issuance hedges due in 2013 has been revised to include a fair value credit of $154.0 million for interest rate hedges originally due in December 2012. These interest rate hedges were amended to extend the maturity date to December 2013 to better reflect the expected timing of future debt issuances.

11. INCOME TAXES

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

We computed our income tax expense by applying a Texas state income tax rate to modified gross margin. The Texas state income tax rate was 0.4% and 0.5% for the nine month periods ended September 30, 2013 and 2012, respectively. Our income tax expense is $1.5 million and $2.6 million, and $17.5 million and $6.4 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 $1.1 million and $7.7 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 $16.5 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 $16.5 million is $12.1 million due to a new tax bill that went into effect in June 2013, as discussed below.

The Texas Legislature passed House Bill 500 and the tax bill was subsequently signed into law in June 2013. The most significant change in the law for the Partnership is that House Bill 500, or 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, the Partnership is allowed additional deductions against its income for Texas Margin Tax purposes. We have recorded an additional “Deferred income tax liability” on our consolidated statements of financial position of approximately $12.1 million for the nine month period ended September 30, 2013 as a result of this new tax law. On a go forward basis, the Partnership’s future effective tax rate in the State of Texas will be lower as a result of this law change.

12. SEGMENT INFORMATION

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

Each of our reportable segments is a business unit that offers different services and products that is managed separately, because each business segment requires different operating strategies. We have segregated our business activities into three distinct operating segments:

•

Liquids;

•

Natural Gas; 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
	Liquids		Natural Gas			Marketing			Corporate⁽¹⁾			Total
	(in millions)
Total revenue	$	401.5	$	1,209.8		$	447.1		$	—		$	2,058.4
Less: Intersegment revenue		—		257.8			11.2			—			269.0

Operating revenue		401.5		952.0			435.9			—			1,789.4
Cost of natural gas		—		822.5			435.0			—			1,257.5
Environmental costs, net of recoveries		0.6		—			—			—			0.6
Operating and administrative		149.7		112.0			1.6			1.8			265.1
Power		43.0		—			—			—			43.0
Depreciation and amortization		63.8		35.8			—			—			99.6

		257.1		970.3			436.6			1.8			1,665.8
Operating income (loss)		144.4		(18.3	)		(0.7	)		(1.8	)		123.6
Interest expense		—		—			—			70.5			70.5
Allowance for equity used during construction		—		—			—			9.3			9.3
Other income		—		—			—			0.4			0.4

Income (loss) from continuing operations before income tax expense		144.4		(18.3	)		(0.7	)		(62.6	)		62.8
Income tax expense		—		—			—			1.5			1.5

Net income (loss)		144.4		(18.3	)		(0.7	)		(64.1	)		61.3
Less: Net income attributable to:
Noncontrolling interest		—		—			—			20.3			20.3
Series 1 preferred unit distributions		—		—			—			22.7			22.7
Accretion of discount on Series 1 preferred units		—		—			—			3.4			3.4

Net income (loss) attributable to general and limited partner ownership interests in Enbridge Energy Partners, L.P.	$	144.4	$	(18.3	)	$	(0.7	)	$	(110.5	)	$	14.9

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


	For the three month period ended September 30, 2012
	Liquids			Natural Gas		Marketing			Corporate⁽¹⁾			Total
	(in millions)
Total revenue	$	329.5		$	1,109.2	$	375.0		$	—		$	1,813.7
Less: Intersegment revenue		0.5			244.9		4.0			—			249.4

Operating revenue		329.0			864.3		371.0			—			1,564.3
Cost of natural gas		—			677.5		371.1			—			1,048.6
Environmental costs, net of recoveries		(134.9	)		—		—			—			(134.9	)
Operating and administrative		96.6			116.4		1.8			0.5			215.3
Power		38.0			—		—			—			38.0
Depreciation and amortization		52.5			34.3		—			—			86.8

		52.2			828.2		372.9			0.5			1,253.8
Operating income (loss)		276.8			36.1		(1.9	)		(0.5	)		310.5
Interest expense		—			—		—			83.4			83.4
Allowance for equity used during construction		—			—		—			5.6			5.6
Other expense		—			—		—			(0.9	)		(0.9	)

Income (loss) from continuing operations before income tax expense		276.8			36.1		(1.9	)		(79.2	)		231.8
Income tax expense		—			—		—			2.6			2.6

Net income (loss)		276.8			36.1		(1.9	)		(81.8	)		229.2
Less: Net income attributable to the noncontrolling interest		—			—		—			14.0			14.0

Net income (loss) attributable to general and limited partner ownership interests in Enbridge Energy Partners, L.P.	$	276.8		$	36.1	$	(1.9	)	$	(95.8	)	$	215.2

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


	As of and for the nine month period ended September 30, 2013
	Liquids		Natural Gas		Marketing			Corporate⁽¹⁾			Total
	(in millions)
Total revenue	$	1,100.7	$	3,563.1	$	1,340.6		$	—		$	6,004.4
Less: Intersegment revenue		—		816.2		33.1			—			849.3

Operating revenue		1,100.7		2,746.9		1,307.5			—			5,155.1
Cost of natural gas		—		2,259.3		1,305.1			—			3,564.4
Environmental costs, net of recoveries		184.3		—		—			—			184.3
Operating and administrative		334.8		333.6		4.2			5.4			678.0
Power		105.8		—		—			—			105.8
Depreciation and amortization		181.0		106.6		—			—			287.6

		805.9		2,699.5		1,309.3			5.4			4,820.1
Operating income (loss)		294.8		47.4		(1.8	)		(5.4	)		335.0
Interest expense		—		—		—			226.4			226.4
Allowance for equity used during construction		—		—		—			25.2			25.2
Other income		—		—		—			1.0			1.0

Income (loss) from continuing operations before income tax expense		294.8		47.4		(1.8	)		(205.6	)		134.8
Income tax expense		—		—		—			17.5			17.5

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company