September 11, 2017

VIA EDGAR

H. Roger Schwall

Assistant Director

United States Securities and Exchange Commission

Division of Corporation Finance

100 F Street, N.E.

Washington, D.C. 20549

Re: Enbridge Energy Partners, L.P.

Form 10-K for Fiscal Year Ended December 31, 2016

Filed February 17, 2017

Form 8-K

Filed July 6, 2017

Form 8-K

Filed August 3, 2017

File No. 1-10934

Dear Mr. Schwall:

Set forth below are the responses of Enbridge Energy Partners, L.P., (the “Partnership”), to comments received from the staff of the Division of Corporation Finance (the “Staff”) of the Securities and Exchange Commission (the “Commission”) by letter dated August 25, 2017, with respect to the above referenced Form 10-K and Forms 8-K.

For your convenience, each response is prefaced by the exact text of the Staff’s corresponding comment in bolded text.

Form 10-K for Fiscal Year Ended December 31, 2016

Management’s Discussion and Anal ysis of Fin anc ial Condition and Results of Oper ations, pa ge 53

Future Prospects Update for Liquids, page 59

Expansion Projects, page 61

1.           We note that your Sandpiper Project was delayed due to updated projections which indicated that this project’s pipeline capacity would not likely be needed until beyond your current five-year planning horizon. We also note your disclosure that a long-term decline in crude oil prices could have a significant impact on future production and your rate of growth. To the extent there are any known trends or uncertainties related to your expansion projects which are reasonably likely to have a material favorable or unfavorable financial impact, disclose those trends or uncertainties. In addition, revise your disclosure to provide the amounts incurred to date for each expansion project. Refer to Item 303(a)(2) of Regulation S-K.

Response:

As noted by the Staff, the Sandpiper Project has been deferred indefinitely. For the Partnership’s remaining material expansion projects, which consist of the remaining expansion of Line 61 from 950,000 barrels per day (“Bpd”) to 1,200,000 Bpd and the U.S. Line 3 Replacement Program, the Partnership has disclosed in the future prospects update for liquids and natural gas, regulatory permitting, impact of commodity price declines, and expansion project sections of its annual and quarterly filings and will continue to disclose in future filings the impacts of current regulatory, market and other material trends and uncertainties on the Partnership’s material expansion projects.

In consideration of Item 303(a)(2) of Regulation S-K, the Partnership will continue to include amounts incurred to date for our expansion projects. We included this expanded disclosure within our Form 10-Q for the period ended June 30, 2017, filed on August 3, 2017. Below is the table that was included in the previously mentioned 10-Q and will be provided in future filings:

Expansion Projects – Commercially Secured Projects

The following table summarizes the status of our commercially secured projects for the Liquids segment. Expenditures to date reflect total cumulative expenditures incurred from inception of the project to June 30, 2017.

	Estimated Capital Costs(1)	Expenditures to Date(2)	Expected In-Service Date	Status
Lakehead System Mainline Expansion:
Line 61(3),(4)	$0.4 billion	$0.4 billion	2019	Substantially complete
U.S. Line 3 Replacement Program(5),(6)	$2.9 billion	$0.5 billion	2019	Pre-construction

⁽¹⁾ These amounts are estimates and are subject to upward or downward adjustment based on various factors.

⁽²⁾ Expenditures to date reflect total cumulative expenditures incurred from inception of the project up to June 30, 2017.

⁽³⁾ Jointly funded 25% by us and 75% by our General Partner under the Mainline Expansion Joint Funding Arrangement. Estimated capital costs are presented at 100% before our General Partner’s contributions.

⁽⁴⁾ Estimated in-service date will be adjusted to coincide with the in-service date of the U.S. L3R Program and the impact of cost to be reviewed. In 2015, we completed the expansion of pipeline capacity to 950,000 Bpd.

⁽⁵⁾ As discussed under U.S. Line 3 Replacement Program below, the expected cost and in-service date of this project are under review by us in light of the schedule for regulatory review and approval communicated by the Minnesota Public Utilities Commission (MNPUC), on October 28, 2016.

⁽⁶⁾ As discussed under U.S. Line 3 Replacement Program below, the Conflicts Committee and Board of Directors approved a joint funding arrangement with the General Partner for the U.S. L3R Program. The General Partner will fund 99% and we will fund 1% of the capital cost of the U.S. L3R Program.

Critical Accounting Policies and Estimates, page 85

Asset Impairment, page 86

2.           We note your disclosure that the assumptions used in evaluating asset recoverability are subject to uncertainty and may result in the recognition of impairment charges, which could be significant. Expand your disclosure to discuss the degree of uncertainty associated with these key assumptions and identify potential events and/or changes in circumstances which would reasonably be expected to negatively affect these key assumptions. In addition, revise to include a discussion of the judgments and estimates inherent in assessing your expansion projects for impairment under FASB ASC 360-10- 35-17, including the circumstances that resulted in the impairment of the assets related to your Sandpiper Project. Refer to section V of SEC Release No. 33-8350.

Response:

In future filings, we will expand our disclosure to include discussion related to the uncertainty associated with the key assumptions. We will also expand to include potential events and/or changes in circumstances which would be expected to negatively affect the key assumptions. Below is an example of language that we will provide in future filings:

Asset Impairment

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

We periodically review our expansion projects for impairment by evaluating their costs incurred to date, the progress made against schedule, and our expectations of future economic, regulatory and political conditions that would impact the overall recoverability of our projects’ costs. During the year ended December 31, 2016, we decided to discontinue the Sandpiper Project due to difficulties in obtaining all the necessary permits and regulatory approvals, the delayed progress of the project to date, and our expectations of near term demand for the pipeline as well as the future political and regulatory environment in the United States and, thus, withdrew our regulatory applications pending with the Minnesota Public Utilities Company. As a result, we evaluated the capital costs spent to date related to the Sandpiper Project for impairment and recognized an impairment of $756.7 million. The Sandpiper Project had not been placed into service, and the estimated remaining fair value of $54.5 million was based on the estimated price that would be received to sell unused pipe, land and other related equipment in its current condition, considering current market conditions for sale of these assets. The valuation considered a range of potential selling prices from various alternatives that could be used to dispose of these assets. We utilized market data from comparable transactions in determining the fair value and considered current market conditions and the length of time it would take to sell the unused pipe and related equipment. These assumptions, and in particular the estimated length of time to sell the unused pipe and related equipment, are subject to uncertainty and could be negatively impacted by changes in demand for pipe, the degree of customization in pipe and related equipment needed for other pipeline projects, saturation in the market for pipe due to other cancelled or delayed projects or other factors.

We believe the assumptions used in evaluating recoverability of our assets are appropriate and result in reasonable estimates of the fair values of our assets. However, the assumptions used are subject to uncertainty, and declines in the future performance or cash flows of our assets, changes in business conditions, such as commodity prices and drilling, or increases to our weighted average cost of capital assumptions due to changes in credit or equity markets may result in the recognition of impairment charges, which could be significant.

Notes to the Consolidated Financial Statements

Note 11 – Property, Plant and Equipment, page 123

3.           We note that you recorded an impairment charge of $756.7 million during the three months ended September 30, 2016 related to your Sandpiper Project. Please tell us the changes to events and circumstances that resulted in the withdrawal of your regulatory applications for the Sandpiper Project on September 1, 2016. Tell us how these facts and circumstances were different from the ones that existed when you filed on July 29, 2016 your 10-Q for the period ending June 30, 2016.

Response:

In early August 2016, negotiations involving our co-venturer in the Sandpiper Project, who was also the major secured anchor shipper on the project, regarding an investment in a separate competing project progressed to a point where the Partnership expected termination of the transportation services agreement from the anchor shipper. In a press release, the Partnership announced it had entered into agreements on August 2, 2016 to invest in a competing Bakken pipeline system and that it expected its transportation services and joint venture agreements for the Sandpiper Project to be terminated upon closing of that investment. In that press release the Partnership also announced that it continued to believe the Bakken region was a highly productive and attractive basin, which had significant crude oil supply growth potential that would require additional pipeline capacity in the future. The Partnership also announced that the scope and timing of the Sandpiper Project would be evaluated during the remainder of the quarter. As disclosed in the Partnership’s Quarterly Report on Form 10-Q for the quarterly period ending June 30, 2016, the Sandpiper Project environmental assessment process in Minnesota had been intertwined with another of the Partnership’s projects, the Line 3 Replacement Program. Thus, as long as the decision regarding the pursuit of the Sandpiper Project remained open, there was the potential for a delaying impact to the Partnership’s L3R Program. This provided additional motivation to the Partnership to expeditiously complete its evaluation of the Sandpiper Project.

By September 1, the Partnership had completed its review of the Sandpiper Project and concluded that the project should be deferred until such time as crude oil production in North Dakota recovers sufficiently to support development of the additional pipeline capacity. Based on updated projections, the Partnership believes that new pipeline capacity would not likely be needed until beyond the Partnership’s five-year planning horizon.

These factors led to the application for withdrawal of the Sandpiper Project regulatory application on September 1, 2016. The results of the Partnership’s review and the withdrawal were announced in a press release at that time.

In light of the facts and circumstances noted above and our decision to defer the project for the foreseeable future, the Partnership tested the capitalized costs incurred to date for the Sandpiper Project for impairment.

Form 8-K filed July 6, 2017

4.           Tell us your consideration of filing pro forma financial information for the sale of your ownership interests in the Midcoast Energy Partners, L.P. within four business days of the disposition. See Item 2.01 of Form 8-K, Rule 11-01(b)(2) of Regulation S-X and Question 129.01 of our Compliance and Disclosure Interpretations related to Exchange Act Form 8-K. As part of your response, provide us with the results of the significance tests in accordance with Rule 1-02(w) of Regulation S-X.

Response:

We have reviewed Item 9.01(b)(1) of Form 8-K and the related requirements of Article 11 of Regulation S-X.

The results of the significance tests under Article 11 as of December 31, 2016 indicated that Midcoast Energy Partners, L.P.’s total assets and income from continuing operations before income taxes were both greater than 10% of Enbridge Energy Partners, L.P.’s total.

Based on this analysis, we intend to file an amendment to the Partnership’s Current Report on Form 8-K that was originally filed on July 6, 2017 (the “Initial 8-K”) to add pro forma financial information as specified by Section 11-02 of Regulation S-X (the “Amended Form 8-K”).

In the Amended Form 8-K, we propose to include the following information:

·           A pro forma statement of income for the Partnership’s fiscal year ended December 31, 2016, substantially in the form attached as Exhibit A to this letter. While we acknowledge the Staff’s position set forth in Section 3230.2.b of the Division’s Financial Reporting Manual, we do not believe pro forma statements of income for 2015 or 2014 are required by Article 11 of Regulation S-X or would be material to investors in this situation. In this regard, we note that the disposed Midcoast Energy Partners, L.P. (“MEP”) business was itself a reporting public company, and its 2016 Form 10-K, filed February 16, 2017, included financial statements for each of these years. The disposed MEP business was also reported as a separate segment by the Partnership. As such, investors already have ample information with which to evaluate the significance and effects of the MEP disposition on the Partnership’s historical results prior to 2016.

·           With respect to an interim pro forma statement of income and balance sheet for the Partnership, the Amended Form 8-K would explain that the Partnership’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2017 (the “Form 10-Q”), reflected the MEP business as discontinued operations in the Partnership’s unaudited consolidated statements of income for the three and six months ended June 30, 2017 and in the Partnership’s unaudited consolidated statements of financial position as of December 31, 2016. The Amended Form 8-K would also explain that the results of operations for the disposed MEP business for such periods, and the major classes of assets and liabilities of the MEP Business as of such date, are included in Note 6 to the Partnership’s unaudited consolidated financial statements included in the Form 10-Q. Finally, the Amended 8-K would note that the disposition had been completed prior to the June 30, 2017 balance sheet included in the Form 10-Q, and was therefore already reflected therein. The Amended Form 8-K would incorporate such information from the Form 10-Q.

We believe the aforementioned information would fully satisfy the objectives set forth in Section 11-02(a) of Regulation S-X. While we acknowledge that the interim pro forma statement of income and balance sheet information is not in typical pro forma format, we believe that the information included in the Form 10-Q that would be described and incorporated by reference in the Amended Form 8-K would provide substantially the same information as would be included in a traditional pro forma presentation. We also note that Section 11-02(b) of the Regulation S-X does not mandate a traditional columnar presentation in all cases. Rather, it permits a narrative description of pro forma effects in certain circumstances when there are limited adjustments that would be easily understood. We believe the proposed information to be included and incorporated by reference into the Amended Form 8-K satisfies those requirements.

Form 8-K filed August 3, 2017

Exhibit 99.1

5.           We note that you present adjusted net income per common unit and i-unit on a per share basis. Revise your presentation to provide a reconciliation of this non-GAAP earnings per share measure to GAAP earnings per share. Refer to Question 102.05 of the Non-GAAP Financial Measures Compliance & Disclosure Interpretations.

Response:

In future filings we will revise our presentation to provide a reconciliation of adjusted net income per common unit and i-unit to net income per common unit and i-unit. The following table presents the reconciliation for the three and six months ended June 30, 2017:

Adjusted Net Income per unit (basic and diluted)	Three months ended June 30,					Six months ended June 30,
(unaudited)	2017			2016		2017			2016
Net income per common unit and i-unit (basic and diluted)	$	0.21		$	0.08		0.36			0.15
Noncash derivative fair value (gains) losses:
- Liquids		-			0.02		(0.01	)		0.02
- Natural Gas - included in Discontinued Operations		(0.02	)		0.10		(0.03	)		0.16
- Other		-			-		0.01			0.01
Accretion of discount on Series 1 preferred units		0.02			-		0.02			0.01
Make-up rights adjustment		-			-		-			-
Line 2 hydrotest expenses, net of recoveries		-			-		-			(0.02	)
Line 6A and 6B incident expenses, net of recoveries		-			-		-			0.05
Option premium amortization		-			-		-			-
Sandpiper Project wind down costs		-			-		0.01			-
Gain on sale of assets		(0.08	)		-		(0.09	)		-
Severance costs		0.01			-		0.02			-
Asset impairment		-			0.02		-			0.01
Integration		-			-		0.00			-
Adjusted net income per common unit and i-unit (basic and diluted)	$	0.14		$	0.22		0.30			0.39

Should the Staff have any questions or comments, please contact the undersigned at 403-231-3900.

Sincerely,
Enbridge Energy Partners, L.P.
By:	Enbridge Energy Management, L.L.C.,
	as delegate of Enbridge Energy Company, Inc., its general partner
By:	/s/ Chris Johnston
	Name: Chris Johnston
	Title: Vice President, Finance

cc:

Commission

Diane Fritz, Staff Accountant

Kimberly L. Calder, Assistant Chief Accountant

Enbridge Energy Partners, L.P.

Mark A. Maki

Valorie Wanner

Exhibit A

Enbridge Energy Partners, L.P.
Consolidated Pro Forma Statement of Income

	Year ended December 31,
	2016 As Filed			Sale of MEP Adjustments			2016 Pro Forma
	(in millions)
Operating revenues:
Commodity sales	$	1,776		$	1,776		$	-
Commodity sales - affiliate		10			10			-
Transportation and other services		2,589			180			2,409
Transportation and other services - affiliate		107			-			107
		4,482			1,966			2,516
Operating expenses:
Commodity costs		1,622			1,622			-
Commodity costs - affiliate		38			38			-
Environmental costs, net of recoveries		2			-			2
Operating and administrative		429			148			281
Operating and administrative - affiliate		437			146			291
Power		277			-			277
Depreciation and amortization		581			154			427
Asset impairment		768			11			757
		4,154			2,119			2,035
Operating income (loss)		328			(153	)		481
Interest expense, net		(446	)		(33	)		(413	)
Allowance for equity used during construction		46			30			16
Other income		32			1			31
Income (loss) before income tax expense		(40	)		(155	)		115
Income tax expense		(1	)		(2	)		1
Net income from continuing operations	$	(41	)	$	(157	)	$	116