Enbridge Energy Partners, L.P. Reports Fourth Quarter 2017 Results

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Feb 15, 2018, 04:15 ET

HOUSTON, Feb. 15, 2018 /PRNewswire/ - Enbridge Energy Partners, L.P. (NYSE:EEP) (EEP or the Partnership) today reported fourth quarter 2017 financial results and provided a quarterly business update.

FOURTH QUARTER AND FULL YEAR HIGHLIGHTS

Fourth quarter loss of $6 million and full year net income of $245 million; Fourth quarter and full year cash provided by operating activities of $112 million and $500 million, respectively
Fourth quarter and full year adjusted earnings before interest, taxes, depreciation and amortization (EBITDA) of $430 million and $1,667 million; Fourth quarter and full year distributable cash flow (DCF) of $211 million and $784 million, respectively
Advanced Line 3 Replacement Project with construction underway in Canada; Minnesota regulatory process reaffirmed with the Minnesota Public Utilities Commission (MPUC), permit decisions expected in the second quarter of 2018
Announced quarterly distribution of $0.35 per unit, or $1.40 on an annualized basis, for the quarter ended December 31, 2017

PRESIDENT'S COMMENT

"2017 was an important transitional year for EEP," commented Mark Maki, President of the Partnership. "EEP is now well positioned with one of the lowest business risk profiles in the sector. Following the restructuring announced earlier in 2017, our stable financial results have reflected this enhanced value proposition and we have finished the year in-line with our guidance expectations. We now look forward to 2018 to continue to provide investors with reliable financial results and stable distributions from one of North America's most strategically positioned liquids pipeline infrastructure assets."

FINANCIAL RESULTS SUMMARY

EEP reported financial results for the three and twelve months ended December 31, 2017, compared to the same periods in 2016, as summarized in the table below:

	Three months ended December 31,				Twelve months ended December 31,
(unaudited; in millions, except per unit amounts)	2017		2016		2017		2016
Net income (loss)⁽¹⁾	$	(6)	$	81	$	245	$	(162)
Net income (loss) per unit (basic and diluted)	$	(0.05)	$	0.08	$	0.50	$	(1.08)
Operating Cash Flow	$	112	$	455	$	500	$	1,416
Adjusted EBITDA⁽²⁾	$	430	$	469	$	1,667	$	1,881
Distributable Cash Flow	$	211	$	221	$	784	$	943
Coverage Ratio (as declared)	1.30		0.83		1.22		0.90
Adjusted net income⁽¹⁾	$	122	$	104	$	365	$	442
Adjusted net income per unit (basic and diluted)	$	0.26	$	0.14	$	0.80	$	0.62

(1) Net income and adjusted net income attributable to general and limited partner ownership interests in Enbridge Energy Partners, L.P.

(2) Includes noncontrolling interests

Net income for the fourth quarter of 2017 decreased $87 million over the same period from the prior year primarily driven by a non-recurring earnings charge of $168 million related to the termination of interest rate swaps due to updated funding plan assumptions.

Net income for the full year increased by $407 million over the prior year primarily due to the absence of an asset impairment loss of $490 million, net of noncontrolling interest, related to the Sandpiper project in 2016. Results also include losses from the Midcoast assets which were sold to an affiliate of Enbridge Inc. in the second quarter of 2017.

Adjusted net income and adjusted EBITDA for the three and twelve months ended December 31, 2017, eliminate the effect of: (a) non-cash, mark-to-market net gains and losses; and (b) other adjustments, including the derivative settlement noted above. Refer to the Non-GAAP Reconciliations Appendices below for additional details.

Fourth quarter and full year 2017 adjusted EBITDA were down $39 million and $214 million respectively. The biggest driver of the period over period variances was the sale of the Midcoast assets in the second quarter of 2017.

Fourth quarter and full year 2017 operating cash flow decreased $343 million and $916 million, respectively, primarily due to the termination of interest rate swaps described above and from the absence of operating cash flows from the Midcoast assets. Full year 2017 cash flows also decreased period over period due to the termination of a receivables arrangement with a subsidiary of the general partner as part of the EEP restructuring in the second quarter of 2017 which affected the timing of the collection of receivables.

DCF for the fourth quarter was $211 million, a decrease of $10 million over the comparable prior period in 2016. Full year 2017 DCF was $784 million compared to $943 million in the prior year period. The year-over-year change in DCF was largely driven by a $214 million reduction in Adjusted EBITDA as discussed in the Segment Results below, as well as a higher allowance for equity used during construction in 2017 related to ongoing construction for the Line 3 Replacement Program, offset by lower maintenance capital in 2017 and a reduction in noncontrolling interests as a result of EEP acquiring an additional 15% interest in Eastern Access.

PROJECT EXECUTION

The U.S. Line 3 Replacement Program, along with the Canadian Program, will support the safety and operational reliability of the mainline system, enhance system flexibility, and allow EEP to optimize throughput on the mainline.

Following the receipt of all required regulatory permitting for the Line 3 Replacement in Canada, construction began in August 2017 on certain Canadian segments of the pipeline and construction will continue through the winter. Regulatory permitting is also in place in North Dakota as well as in Wisconsin where construction is substantially complete.

In Minnesota, the MPUC is expected to vote on the Certificate of Need and Route Permit at the end of the second quarter of 2018. In parallel with this process, additional clarification and analysis will be provided to support the adequacy of the Final Environmental Impact Statement, as requested by the MPUC in December. Management continues to anticipate an in-service date for the project in the second half of 2019.

U.S. TAX REFORM

On December 22, 2017, the United States implemented U.S. Tax Reform. The "Tax Cuts and Jobs Act" (TCJA) was signed into law and became enacted for tax purposes. Substantially all of the provisions of the TCJA are effective for taxation years beginning after December 31, 2017. The most significant change included in the TCJA was a reduction in the corporate federal income tax rate from 35% to 21%.

This tax rate change is expected to cause Enbridge Energy Partners, L.P. to reduce the income tax allowance component of the tolls in its FERC regulated cost-of-service based Facility Surcharge Mechanism (FSM) projects. Impacts of tax reform will be realized in the first quarter of 2018 and will be reflected in Lakehead's FSM toll filing for rates effective April 1, 2018. The total annual impact to EEP is expected to be roughly $55 million per year, net of noncontrolling interests.

As a result of the U.S. Tax Reform, EEP is adjusting its 2018 DCF guidance range to $720 million - $770 million from $775 million - $825 million and total distribution coverage in 2018 to approximately 1.15x from approximately 1.2x. Target consolidated Debt to EBITDA guidance remains unchanged.

SEGMENT RESULTS

For purposes of evaluating performance of the Partnership, we make adjustments for unusual, non-recurring or non-operating factors to our reported earnings, segment EBITDA, and cash flow provided by operating activities, as it allows Management and our investors to more accurately compare the Partnership's performance across periods and the factors being adjusted for are not indicative of the underlying performance and cash flows of the business. Schedules reconciling adjusted EBITDA, adjusted EBITDA by segment, adjusted earnings, adjusted earnings per common share and distributable cash flow to their closest GAAP equivalent are available at www.enbridgepartners.com and as an Appendix to this news release.

		Three months ended December 31,				Twelve months ended December 31,
		Three months ended December 31,				Twelve months ended December 31,
(unaudited; in millions)		2017		2016		2017		2016
	Lakehead	$	351	$	379	$	1,388	$	1,470
	Mid-Continent	18		22		59		93
	Bakken Assets	59		32		227		(599)
Total Liquids EBITDA		$	428	$	433	$	1,674	$	964
Other		(3)		(1)		(7)		(9)
Net income (loss)		$	(6)	$	81	$	245	$	(162)

		Three months ended December 31,				Twelve months ended December 31,
		Three months ended December 31,				Twelve months ended December 31,
(unaudited; in millions)		2017		2016		2017		2016
	Lakehead	$	360	$	374	$	1,415	$	1,466
	Mid-Continent	17		23		60		94
	Bakken Assets	56		37		177		171
Total Liquids Adjusted EBITDA		$	433	$	434	$	1,652	$	1,731
Other⁽¹⁾		(3)		35		15		150
Total Adjusted EBITDA		$	430	$	469	$	1,667	$	1,881

(1) Includes the adjusted results of our disposed Natural Gas segment for the comparative periods.

Liquids

Fourth quarter adjusted EBITDA for the total Liquids segment remained essentially unchanged at $433 million over the comparable period in 2016.

Adjusted EBITDA decreased on the Lakehead System, for both the fourth quarter and full year 2017, as a result of a lower Lakehead System Local Toll and higher operating costs which will be partially recoverable in 2018.
Adjusted EBITDA decreased from the Mid-Continent System as a result of the sale of Ozark Pipeline on March 1, 2017.
Adjusted EBITDA from the Bakken assets increased as a result of the Bakken Pipeline System, which was placed into service in June 2017, and continued steady results from the legacy pipeline system.

		Three months ended December 31,		Twelve months ended December 31,
Liquids Systems Volumes		Three months ended December 31,		Twelve months ended December 31,
(thousand barrels per day)		2017	2016	2017	2016
Lakehead System:
	United States	2,085	2,001	2,027	1,968
	Canada	639	623	646	606
Total Lakehead System delivery volumes		2,724	2,624	2,673	2,574
Mid-Continent System delivery volumes		—	153	24	188
Bakken Assets:
	North Dakota System to Clearbrook	216	213	214	216
	Bakken System to Cromer⁽¹⁾	108	123	115	136
Total Bakken Assets delivery volumes		324	336	329	352
Total Liquids segment delivery volumes		3,048	3,113	3,026	3,114

(1) Lower spot volumes on the Bakken Pipeline a component of the Bakken assets that delivers volumes into Cromer, Manitoba.

Other

Other primarily reflects the results of the Midcoast gas gathering and processing assets. This business was sold in the second quarter of 2017. Remaining amounts in Other in 2017 represent unallocated corporate costs.

Conference Call Details

The Partnership will host a joint conference call and webcast at 9:00 a.m. Eastern Time (7 a.m. Mountain Time) on February 16, 2018, with Enbridge Inc. (TSX: ENB) (NYSE: ENB), Enbridge Income Fund Holdings Inc. (TSX: ENF), and Spectra Energy Partners, LP (NYSE: SEP) to provide an enterprise wide business update and review 2017 fourth quarter and year-end financial results. Analysts, members of the media and other interested parties can access the call toll free at (877) 930-8043 or outside North America at (253) 336-7522 using the access code of 4939158#. The call will be audio webcast live at https://edge.media-server.com/m6/p/rudushbf. A webcast replay and podcast will be available approximately two hours after the conclusion of the event and a transcript will be posted to the website within approximately 24 hours. An audio replay will be available for seven days after the call toll free at (855) 859-2056 or outside North America at (404) 537-3406 using the replay passcode 4939158#.

The conference call format will include prepared remarks from the executive team followed by a question and answer session for the analyst and investor community only. Enbridge's media and investor relations teams will be available after the call for any additional questions.

Forward-Looking Statements

This news release includes forward-looking statements, which are statements that frequently use words such as "anticipate," "believe," "consider," "continue," "could," "estimate," "evaluate," "expect," "explore," "forecast," "intend," "may," "opportunity," "plan," "position," "projection," "should," "strategy," "target," "will" and similar words. Although the Partnership believes 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. Any forward-looking statement made by the Partnership in this release speaks only as of the date on which it is made, and the Partnership undertakes no obligation to publicly update any forward-looking statement. 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) the effectiveness of the various actions the Partnership has announced resulting from its strategic review process; (2) changes in the demand for the supply of, forecast data for, and price trends related to crude oil, liquid petroleum, including the rate of development of the Alberta Oil Sands; (3) the Partnership's ability to successfully complete and finance expansion projects; (4) the effects of competition, in particular, by other pipeline systems; (5) shut-downs or cutbacks at the Partnership's facilities or refineries, petrochemical plants, utilities or other businesses for which the Partnership transports products or to whom it sell products; (6) hazards and operating risks that may not be covered fully by insurance, including those related to Line 6B, (7) any fines, penalties and injunctive relief assessed in connection with any crude oil release; (8) changes in or challenges to the Partnership's tariff rates; (9) changes in laws or regulations to which the Partnership is subject, including compliance with environmental and operational safety regulations that may increase costs of system integrity testing and maintenance; and (10) permitting at federal, state and local level or renewals of rights of way. Any statements regarding sponsor expectations or intentions are based on information communicated to the Partnership by Enbridge Inc., but there can be no assurance that these expectations or intentions will not change in the future.

Except to the extent required by law, we assume no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. Reference should also be made to the Partnership's filings with the U.S. Securities and Exchange Commission (the "SEC"), including its most recently filed 2017 Annual Report on Form 10-K dated February 15, 2018 and any subsequently filed Quarterly Reports on Form 10-Q or current reports on Form 8-K for additional factors that may affect results. These filings are available to the public over the Internet at the SEC's website (www.sec.gov) and at the Partnership's website.

About Enbridge Energy Partners, L.P.

Enbridge Energy Partners, L.P. owns and operates a diversified portfolio of crude oil transportation systems in the United States. Its principal crude oil system is the largest pipeline transporter of growing oil production from western Canada and the North Dakota Bakken formation. The system's deliveries to refining centers and connected carriers in the United States account for approximately 23 percent of total U.S. oil imports. Enbridge Energy Partners, L.P. is traded on the New York Stock Exchange under the symbol EEP; information about the company is available on its website at www.enbridgepartners.com.

About Enbridge Energy Management, L.L.C.

Enbridge Energy Management, L.L.C. manages the business and affairs of the Partnership, and its sole asset is an approximate 19.9 percent limited partner interest in the Partnership. Enbridge Energy Company, Inc., an indirect wholly owned subsidiary of Enbridge Inc. of Calgary, Alberta, Canada (NYSE: ENB) (TSX: ENB) is the General Partner of the Partnership and holds an approximate 35 percent interest in the Partnership. Enbridge Management is the delegate of the General Partner of the Partnership.

NON-GAAP RECONCILIATIONS APPENDICES

Reconciliations of forward looking non-GAAP financial measures to comparable GAAP measures are not available due to the challenges with estimating some of the items, particularly with estimating non-cash unrealized derivative fair value losses and gains, which are subject to market variability and therefore a reconciliation is not available without unreasonable effort.

Adjusted Net Income and Segment Adjusted EBITDA

Adjusted net income for the Partnership and adjusted EBITDA for the principal business segment are provided to illustrate trends in income excluding non-cash unrealized derivative fair value losses and gains and other items that Management believes are not indicative of the Partnership's core operating results. The derivative non-cash losses and gains result from marking to market certain financial derivatives used by the Partnership for hedging purposes that do not qualify for hedge accounting treatment in accordance with the authoritative accounting guidance as prescribed under generally accepted accounting principles in the United States. Non-GAAP measures no longer include make-up rights and option premium amortization adjustments. These changes were made on a prospective basis beginning with the second quarter of 2016 and are not material for historical periods presented.

Adjusted EBITDA and Distributable Cash Flow

Adjusted EBITDA (adjusted earnings before interest, taxes, depreciation and amortization) is used as a supplemental financial measurement to manage the performance of the entity. Distributable cash flow is used as a supplemental financial measurement to assess liquidity and the ability to generate cash sufficient to pay interest costs and make cash distributions to unitholders. The following reconciliations of net income to adjusted EBITDA and net cash provided by operating activities to distributable cash flow are provided because adjusted EBITDA and distributable cash flow are not financial measures recognized under generally accepted accounting principles.

APPENDIX A
NON-GAAP RECONCILATION EARNINGS TO DISTRIBUTABLE CASH FLOW

	Three months ended December 31,				Twelve months ended December 31,

(unaudited; in millions, except per unit amounts)	2017		2016		2017		2016
Net income (loss) attributable to general and limited partner ownership interests in Enbridge Energy Partners, L.P.	$	(6)	$	81	$	245	$	(162)
Noncash derivative fair value (gains) losses:
-Liquids	4		2		3		9
-Natural Gas (included in Discontinued Operations)	—		19		(12)		85
-Other	(52)		3		(50)		7
Accretion of discount on Series 1 preferred units	—		1		8		5
Make-up rights adjustment	—		—		—		1
Line 2 hydrotest expenses, net of recoveries	—		(1)		—		(11)
Line 6A and 6B incident expenses, net of recoveries	—		(8)		—		(2)
Option premium amortization	—		—		—		1
Sandpiper Project wind down costs	1		2		6		5
Gain on sale of assets	(4)		—		(40)		1
Severance costs	—		5		8		6
Asset impairment	—		—		—		497
Integration costs	11		—		29		—
Pre-issuance hedge termination	168		—		168		—
Adjusted net income	$	122	$	104	$	365	$	442
Series 1 preferred unit distributions	—		23		29		90
Net income attributable to noncontrolling interest	106		86		345		329
Depreciation and amortization	107		111		436		427
Interest expense, net	103		109		407		406
Income tax expense (benefit)	(8)		(6)		(8)		(1)
Interest expense, income tax expense, and depreciation and amortization - discontinued operations	—		42		93		188
Adjusted EBITDA	$	430	$	469	$	1,667	$	1,881
Net income attributable to noncontrolling interest	(110)		(122)		(418)		(467)
Interest expense, net^(1)(2)(3)	(97)		(109)		(398)		(413)
Income tax expense (benefit)	8		6		8		(1)
Distributions in excess of equity earnings	5		—		8		6
Maintenance capital expenditures	(10)		(20)		(36)		(55)
Allowance for equity used during construction⁽⁴⁾	(14)		—		(47)		—
Other	(1)		(3)		—		(8)
DCF	$	211	$	221	$	784	$	943

(1)	Excludes unrealized mark-to-market net gains of $52 million and $50 million for the three and twelve months ended December 31, 2017, respectively. Excludes unrealized mark-to-market net losses of $3 million and $7 million for the three and twelve months ended December 31, 2016, respectively.
(2)	Excludes $7 million and $27 million of amortization related to pre-issuance interest swaps for the three and twelve months ended December 31, 2017 and for the three and twelve months ended December 31, 2016.
(3)	Excludes $168 million loss related to the termination of long-term interest rate swaps as not highly probable to issue long-term debt.
(4)	Distributable cash flow excludes allowance for equity used during construction beginning Q1 2017.

APPENDIX B
NON-GAAP RECONCILIATION REPORTED TO ADJUSTED NET INCOME PER COMMON UNIT AND I-UNIT

	Three months ended December 31,				Twelve months ended December 31,

(unaudited)	2017		2016		2017		2016
Net income (loss) per common unit and i-unit (basic and diluted) interests in Enbridge Energy Partners, L.P.	$	(0.05)	$	0.08	$	0.50	$	(1.08)
Noncash derivative fair value (gains) losses:
-Liquids	0.01		—		0.01		0.02
-Natural Gas (included in Discontinued Operations)	—		0.07		(0.03)		0.24
-Other	(0.13)		0.01		(0.12)		0.02
Accretion of discount on Series 1 preferred units	—		—		0.02		0.01
Line 2 hydrotest expenses, net of recoveries	—		—		—		(0.03)
Line 6A and 6B incident expenses, net of recoveries	—		(0.03)		—		(0.01)
Sandpiper Project wind down costs	—		—		0.01		0.01
Gain on sale of assets	(0.01)		—		(0.10)		—
Severance costs	—		0.01		0.02		0.01
Asset impairment	—		—		—		1.43
Integration costs	0.02		—		0.07		—
Pre-issuance hedge termination	0.42		—		0.42		—
Adjusted net income per common unit and i-unit (basic and diluted)	$	0.26	$	0.14	$	0.80	$	0.62
Weighted average common units and i-units outstanding	423		351		400		348

APPENDIX C
NON-GAAP RECONCILIATION LIQUIDS REPORTED EBITDA TO ADJUSTED EBITDA

	Three months ended December 31,				Twelve months ended December 31,

(unaudited; in millions)	2017		2016		2017		2016
EBITDA	$	428	$	433	$	1,674	$	964
Noncash derivative fair value (gains) losses:	4		2		3		9
Make-up rights adjustment	—		—		—		1
Line 2 hydrotest expenses, net of recoveries	—		(1)		—		(11)
Line 6A and 6B incident expenses, net of recoveries	—		(8)		—		(2)
Gain on sale of assets	(6)		—		(63)		—
Sandpiper Project wind down costs	2		3		9		9
Severance costs	—		5		6		4
Integration costs	5		—		23		—
Asset impairment	—		—		—		757
Adjusted EBITDA	$	433	$	434	$	1,652	$	1,731

APPENDIX D
NON-GAAP RECONCILIATION - OPERATING CASH FLOW TO DISTRIBUTABE CASH FLOW

	Three months ended December 31,				Twelve months ended December 31,

(unaudited; in millions)	2017		2016		2017		2016
Total net cash provided by operating activities	$	112	$	455	$	500	$	1,416
Changes in operating assets and liabilities, net of cash acquired	39		(108)		551		13
Allowance for equity used during construction⁽¹⁾	—		10		—		46
Option premium amortization	—		—		—		1
Line 2 hydrotest expense, net of recoveries	—		(1)		—		(11)
Distributions in excess of equity earnings	5		—		8		5
Maintenance capital expenditures	(10)		(20)		(36)		(55)
Noncontrolling interests	(111)		(122)		(418)		(467)
Gain on sale of assets	—		—		11		—
Distribution support agreement⁽²⁾	—		(3)		—		(7)
Pre-issuance hedge termination	168		—		168		—
Other	8		10		—		2
Distributable cash flow	$	211	$	221	$	784	$	943

(1)	Distributable cash flow excludes allowance for equity used during construction beginning Q1 2017.
(2)	Distribution agreement in place with MEP to support 1.0x coverage of the then declared distribution with a term through 2017, and no requirement for MEP to reimburse EEP for adjusted distributions.