Enbridge Energy Partners, L.P. Reports Second Quarter 2018 Results
HOUSTON, Aug. 2, 2018 /PRNewswire/ - Enbridge Energy Partners, L.P. (NYSE: EEP) (EEP or the Partnership) today reported second quarter 2018 financial results and provided a quarterly business update. EEP reported net income of $187 million, of which $95 million is attributable to EEP's controlling interests, for the second quarter ended June 30, 2018, with net income per unit of $0.19. The second quarter results included net non-recurring special items of $17 million, which increased net income per unit by $0.04.
SECOND QUARTER HIGHLIGHTS:
- Solid quarter supported by strong Lakehead volumes
- Received non-binding offer from Enbridge Inc. (Enbridge), the indirect parent of EEP's General Partner (GP), together with a wholly-owned subsidiary of Enbridge, to acquire all of the outstanding EEP units not beneficially owned by Enbridge and its affiliates; a special committee of independent directors has been established to review and consider the offer
- Minnesota Public Utilities Commission (MPUC) voted in favor of the issuance of the Certificate of Need and Route Permit for the Line 3 Replacement Project; construction is well underway in Canada and is now complete in Wisconsin
- Announced quarterly distribution of $0.35 per unit, or $1.40 on an annualized basis, for the quarter ended June 30, 2018
Second quarter 2018 cash provided by operating activities was $294 million, compared with cash used in operating activities of $190 million in the second quarter 2017. Distributable cash flow (DCF) was $166 million, compared with $182 million in the prior year quarter. EEP's coverage ratio was 1.01x as declared in the second quarter 2018 and 1.14x as declared in the second quarter 2017.
For the quarter, adjusted earnings before interest, taxes, depreciation and amortization (EBITDA) were $380 million, compared with $397 million in the prior year quarter. Adjusted net income was $78 million for the quarter, or $0.15 adjusted net income per unit, compared with $65 million, or $0.14 adjusted net income per unit in the prior year quarter. Net income was $95 million for the quarter, or $0.19 net income per unit, compared with $93 million, or $0.21 net income per unit in the prior year quarter.
RESTRUCTURING PROPOSAL
On May 17, 2018, EEP received a non-binding offer from both Enbridge and one of its wholly-owned subsidiaries, to acquire all of EEP's outstanding Class A common units not beneficially owned by Enbridge and its affiliates. Under the terms of the offer, EEP Class A unitholders would receive 0.3083 common shares of Enbridge per EEP Class A common unit.
The board of directors of Enbridge Energy Management L.L.C. (EEQ), as the delegate of the GP, has established a special committee of independent directors to review and consider the proposal. Any definitive agreement is subject to applicable board and unitholder approvals by 66 2/3 percent of our outstanding units and is expected to contain customary closing conditions, including standard regulatory notifications and approvals.
LINE 3 REPLACEMENT (L3R) PROGRAM UPDATE
The U.S. Line 3 Replacement Program (U.S. L3R Program), along with the Canadian Line 3 Replacement Program, will support the safety and operational reliability of the mainline system, enhance system flexibility and allow EEP to optimize throughput on the mainline.
The project continues to progress well on several fronts. In Canada, the first phase of pipeline construction is complete, with approximately 40 percent of the pipe now laid, and the remainder to be advanced later this year. In the U.S., the pipeline replacement work in Wisconsin is now complete and has been placed into service.
In Minnesota, on June 28, the MPUC voted in favor of issuing a Certificate of Need and a Route Permit for the project. A written order documenting the MPUC's rulings in these dockets is expected to be issued by September 2018. In addition to the MPUC's approval, permits are also required from the U.S. Army Corps of Engineers, state agencies (including the Minnesota Department of Natural Resources and the Minnesota Pollution Control Agency) and local governments in Minnesota. The Partnership anticipates the receipt of such permits in time to begin construction activities during the first quarter of 2019, and continues to anticipate an in-service date for the project in the second half of 2019.
EEP has a joint funding arrangement with its General Partner for the U.S. L3R Program. Under the terms of the arrangement, the GP funds 99 percent and EEP funds 1 percent of the capital cost of the U.S. L3R Program. EEP has an option to increase its interest in the U.S. L3R Program assets up to 40 percent at the book value at any time up to four years after the project goes into service.
REVISED FERC POLICY ON TREATMENT OF INCOME TAXES
On July 18, 2018, the Federal Energy Regulatory Commission (FERC) issued an Order that: (1) dismissed all requests for rehearing of its March 15, 2018 Revised Policy Statement and explained that its revised policy does not establish a binding rule, but is instead an expression of general policy that the Commission intends to follow in the future; and (2) provides guidance that if a Master Limited Partnership (MLP) or other tax pass-through pipeline eliminates its income tax allowance from its cost of service pursuant to FERC's Revised Policy Statement, then Accumulated Deferred Income Taxes (ADIT) will similarly be removed from its cost of service and MLP pipelines may also eliminate previously-accumulated sums in ADIT instead of flowing ADIT balances back to ratepayers. As a statement of general policy, FERC will consider alternative application of its tax allowance and ADIT policy on a case-by-case basis.
EEP continues to assess the financial impact of the July 18, 2018, announcement. Pending greater clarification from FERC on the application of its new policy, assessing the near- and long-term implications of the policy is challenging. The Partnership has provided its best estimate of the implications to 2018 DCF, which includes a $30 million positive impact from the proposed ADIT change, assuming FERC's revised policy is retroactive to March 2018. This benefit to DCF partially offsets the previously estimated $120 million negative impact of U.S. Tax Reform and the MLP tax disallowance.
SEGMENT RESULTS
For purposes of evaluating performance of the Partnership, the Partnership makes adjustments for unusual, non-recurring or non-operating factors to reported earnings, segment EBITDA, and cash flow provided by operating activities, as it allows Management and its 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 as Appendices to this news release.
Liquids
Second quarter adjusted EBITDA decreased by $9 million over the comparable period in 2017 primarily due to the following items:
- Lower Lakehead System EBITDA driven by the regulatory impact of the United States legislation, referred to as the "Tax Cuts and Jobs Act," which reduced the corporate federal income tax rate from 35 percent to 21 percent (U.S. Tax Reform) and FERC's income tax policy to no longer permit recovery of an income tax allowance in cost of service rates as announced in March 2018, partially offset by the timing of operating expenses.
- Higher EBITDA attributable to a full quarter of equity earnings from the Partnership's interest in the Bakken Pipeline System, which was placed into service on June 1, 2017.
Second quarter adjusted EBITDA excludes certain special items which are further described in Appendix E below.
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 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 August 3, 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 2018 second quarter 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 5369238#. The call will be audio webcast live at https://edge.media-server.com/m6/p/ijz44wew. 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 5369238#.
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 negotiation and execution, and the terms and conditions, of definitive agreements relating to Enbridge's offer to acquire all of the Partnership's outstanding Class A common units not currently beneficially owned by Enbridge (the Proposed Transaction) and the timing and ability of Enbridge or the Partnership to enter into or consummate such agreements; (2) the effectiveness of the various actions the Partnership has taken resulting from the Partnership's strategic review process; (3) changes in the demand for, the supply of, forecast data for, and price trends related to crude oil and liquid petroleum, including the rate of development of the Alberta Oil Sands; (4) The Partnership's ability to successfully complete and finance expansion projects; (5) the effects of competition, in particular, by other pipeline systems; (6) 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 the Partnership sell products; (7) hazards and operating risks that may not be covered fully by insurance; (8) any fines, penalties and injunctive relief assessed in connection with any crude oil release; (9) state or federal legislative and regulatory initiatives or actions that affect cost and investment recovery or that have an effect on rate structure, or other changes in or challenges to the Partnership's tariff rates; (10) 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 (11) permitting at federal, state and local levels 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, the Partnership assumes 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 (SEC), including its most recently filed 2017 Annual Report on Form 10-K dated February 16, 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 25 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 Partnership 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 21 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.
FOR FURTHER INFORMATION PLEASE CONTACT:
Enbridge Energy Partners, L.P.
Media
Michael Barnes
Toll Free: (888) 992-0997
Email: [email protected]
Investment Community
Roni Cappadonna
Toll Free: (800) 481-2804
Email: [email protected]
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.
Adjusted EBITDA and Distributable Cash Flow
Adjusted EBITDA 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 in the United States.
APPENDIX A
FINANCIAL RESULTS
EEP reported financial results for the three and six months ended June 30, 2018, compared to the same period in 2017, as summarized in the tables below:
| Three months ended |
Six months ended |
||||||||||
| 2018 |
2017 |
2018 |
2017 |
||||||||
| (unaudited; in millions, except per unit amounts) |
|||||||||||
| Net income(1) |
$ |
95 |
$ |
93 |
$ |
169 |
$ |
158 |
|||
| Net income per unit (basic and diluted) |
$ |
0.19 |
$ |
0.21 |
$ |
0.34 |
$ |
0.36 |
|||
| Operating Cash Flow |
$ |
294 |
$ |
(190) |
$ |
616 |
$ |
44 |
|||
| Adjusted EBITDA(2) |
$ |
380 |
$ |
397 |
$ |
810 |
$ |
811 |
|||
| Distributable Cash Flow |
$ |
166 |
$ |
182 |
$ |
378 |
$ |
380 |
|||
| Distribution Coverage Ratio (as declared) |
1.01 |
1.14 |
1.16 |
1.19 |
|||||||
| Adjusted net income(1) |
$ |
78 |
$ |
65 |
$ |
196 |
$ |
134 |
|||
| Adjusted net income per unit (basic and diluted) |
$ |
0.15 |
$ |
0.14 |
$ |
0.40 |
$ |
0.30 |
|||
| (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 |
| Three months ended |
Six months ended |
|||||||||||
| 2018 |
2017 |
2018 |
2017 |
|||||||||
| (unaudited; in millions, except per unit amounts) |
||||||||||||
| Operating revenues |
$ |
537 |
$ |
596 |
$ |
1,129 |
$ |
1,201 |
||||
| Operating expenses: |
||||||||||||
| Environmental costs, net of recoveries |
(23) |
4 |
(22) |
14 |
||||||||
| Operating and administrative |
135 |
158 |
267 |
312 |
||||||||
| Power |
75 |
66 |
152 |
140 |
||||||||
| Depreciation and amortization |
109 |
108 |
219 |
217 |
||||||||
| Impairment of long-lived asset |
1 |
— |
36 |
— |
||||||||
| Gain on sale of assets |
— |
(51) |
— |
(62) |
||||||||
| Operating income |
240 |
311 |
477 |
580 |
||||||||
| Interest expense, net |
101 |
103 |
205 |
202 |
||||||||
| Allowance for equity used during construction |
16 |
11 |
32 |
21 |
||||||||
| Income from equity investment in joint venture |
33 |
6 |
56 |
6 |
||||||||
| Other income (expense) |
(1) |
5 |
(1) |
5 |
||||||||
| Income from continuing operations before income taxes |
187 |
230 |
359 |
410 |
||||||||
| Income tax benefit |
— |
2 |
— |
1 |
||||||||
| Income from continuing operations |
187 |
232 |
359 |
411 |
||||||||
| Loss from discontinued operations, net of taxes |
— |
(35) |
— |
(57) |
||||||||
| Net income |
187 |
197 |
359 |
354 |
||||||||
| Noncontrolling interests |
(92) |
(91) |
(190) |
(159) |
||||||||
| Series 1 preferred unit distributions |
— |
(6) |
— |
(29) |
||||||||
| Accretion of discount on Series 1 preferred units |
— |
(7) |
— |
(8) |
||||||||
| Net income - controlling interests |
$ |
95 |
$ |
93 |
$ |
169 |
$ |
158 |
||||
| Net income allocable to common units and i-units: |
||||||||||||
| Income from continuing operations |
$ |
83 |
$ |
105 |
$ |
145 |
$ |
172 |
||||
| Loss from discontinued operations |
— |
(24) |
— |
(38) |
||||||||
| Net income allocable to common units and i-units |
$ |
83 |
$ |
81 |
$ |
145 |
$ |
134 |
||||
| Net income per common unit and i-unit (basic and diluted): |
||||||||||||
| Income from continuing operations |
$ |
0.19 |
$ |
0.27 |
$ |
0.34 |
$ |
0.46 |
||||
| Loss from discontinued operations |
— |
(0.06) |
— |
(0.10) |
||||||||
| Net income per common unit and i-unit |
$ |
0.19 |
$ |
0.21 |
$ |
0.34 |
$ |
0.36 |
||||
| Weighted average common units and i-units (basic and diluted) |
428 |
400 |
427 |
377 |
||||||||
APPENDIX B
SEGMENT RESULTS
EEP reported segment results for the three and six months ended June 30, 2018, compared to the same period in 2017, as summarized in the tables below:
| Three months ended |
Six months ended |
|||||||||||||
| 2018 |
2017 |
2018 |
2017 |
|||||||||||
| (unaudited; in millions) |
||||||||||||||
| Lakehead |
$ |
331 |
$ |
335 |
$ |
652 |
$ |
687 |
||||||
| Mid-Continent |
13 |
15 |
29 |
29 |
||||||||||
| Bakken Assets |
60 |
90 |
112 |
116 |
||||||||||
| Total Liquids EBITDA |
$ |
404 |
$ |
440 |
$ |
793 |
$ |
832 |
||||||
| Other |
(6) |
(13) |
(9) |
(16) |
||||||||||
| Three months ended |
Six months ended |
|||||||||||||
| 2018 |
2017 |
2018 |
2017 |
|||||||||||
| (unaudited; in millions) |
||||||||||||||
| Lakehead |
$ |
309 |
$ |
337 |
$ |
672 |
$ |
689 |
||||||
| Mid-Continent |
13 |
16 |
29 |
30 |
||||||||||
| Bakken Assets |
62 |
40 |
115 |
71 |
||||||||||
| Total Liquids Adjusted EBITDA |
$ |
384 |
$ |
393 |
$ |
816 |
$ |
790 |
||||||
| Other(1) |
(4) |
4 |
(6) |
21 |
||||||||||
| Total Adjusted EBITDA |
$ |
380 |
$ |
397 |
$ |
810 |
$ |
811 |
||||||
| (1) |
Includes the adjusted results of our disposed Natural Gas segment for the comparative period. |
| Three months ended |
Six months ended |
||||||||||
| Liquids Systems Volumes |
2018 |
2017 |
2018 |
2017 |
|||||||
| (average barrels per day in thousands) |
|||||||||||
| Lakehead System: |
|||||||||||
| United States |
2,178 |
1,986 |
2,128 |
2,021 |
|||||||
| Canada |
599 |
618 |
643 |
654 |
|||||||
| Total Lakehead System delivery volumes |
2,777 |
2,604 |
2,771 |
2,675 |
|||||||
| Mid-Continent System delivery volumes |
— |
— |
— |
47 |
|||||||
| Bakken Assets: |
|||||||||||
| North Dakota System to Clearbrook |
217 |
219 |
216 |
211 |
|||||||
| Bakken System to Cromer(1) |
64 |
136 |
54 |
134 |
|||||||
| Total Bakken Assets delivery volumes |
281 |
355 |
270 |
345 |
|||||||
| Total Liquids segment delivery volumes |
3,058 |
2,959 |
3,041 |
3,067 |
|||||||
| (1) |
Lower spot volumes on the Bakken Pipeline a component of the Bakken Assets that delivers volumes into Cromer, Manitoba. |
APPENDIX C
NON-GAAP RECONCILATION EARNINGS TO DISTRIBUTABLE CASH FLOW
| Three months ended |
Six months ended |
|||||||||||||
| 2018 |
2017 |
2018 |
2017 |
|||||||||||
| (unaudited; in millions) |
||||||||||||||
| Net income - controlling interests |
$ |
95 |
$ |
93 |
$ |
169 |
$ |
158 |
||||||
| Noncash derivative fair value (gains) losses: |
||||||||||||||
| -Liquids |
5 |
(1) |
7 |
(3) |
||||||||||
| -Natural Gas (included in Discontinued Operations) |
— |
(8) |
— |
(12) |
||||||||||
| -Other |
— |
1 |
— |
2 |
||||||||||
| Accretion of discount on Series 1 preferred units |
— |
7 |
— |
8 |
||||||||||
| Leak remediation costs, net of recoveries |
(23) |
— |
(23) |
— |
||||||||||
| Sandpiper Project wind down costs |
— |
1 |
— |
4 |
||||||||||
| Gain on sale of assets |
— |
(32) |
— |
(32) |
||||||||||
| Severance costs |
— |
3 |
1 |
8 |
||||||||||
| Impairment of long-lived asset |
1 |
— |
36 |
— |
||||||||||
| Integration costs |
(3) |
1 |
3 |
1 |
||||||||||
| Legal costs |
3 |
— |
3 |
— |
||||||||||
| Adjusted net income |
$ |
78 |
$ |
65 |
$ |
196 |
$ |
134 |
||||||
| Series 1 preferred unit distributions |
— |
6 |
— |
29 |
||||||||||
| Net income attributable to noncontrolling interests |
92 |
70 |
190 |
138 |
||||||||||
| Depreciation and amortization |
109 |
108 |
219 |
217 |
||||||||||
| Interest expense, net |
101 |
103 |
205 |
202 |
||||||||||
| Income tax expense (benefit) |
— |
(2) |
— |
(1) |
||||||||||
| Interest expense, income tax expense, and depreciation and |
— |
47 |
— |
92 |
||||||||||
| Adjusted EBITDA |
$ |
380 |
$ |
397 |
$ |
810 |
$ |
811 |
||||||
| Net income attributable to noncontrolling interests |
(102) |
(94) |
(211) |
(191) |
||||||||||
| Interest expense, net(1)(2)(3) |
(93) |
(104) |
(189) |
(204) |
||||||||||
| Income tax expense (benefit) |
— |
2 |
— |
— |
||||||||||
| Distributions in excess of equity earnings, net of NCI |
3 |
(1) |
10 |
— |
||||||||||
| Maintenance capital expenditures |
(6) |
(7) |
(11) |
(16) |
||||||||||
| Allowance for equity used during construction(4) |
(16) |
(11) |
(32) |
(21) |
||||||||||
| Other |
— |
— |
1 |
1 |
||||||||||
| DCF |
$ |
166 |
$ |
182 |
$ |
378 |
$ |
380 |
||||||
| (1) |
Excludes $6 million and $7 million of amortization related to pre-issuance interest swaps for the three months ended June 30, 2018 and 2017, respectively. Excludes $13 million and $13 million of amortization related to pre-issuance interest swaps for the six months ended June 30, 2018 and 2017. |
| (2) |
Excludes $2 million and $3 million of amortization related debt issuance costs for the three and six months ended June 30, 2018, respectively, beginning Q1 2018. |
| (3) |
Excludes $2 million and $2 million of unrealized mark-to-market net losses for the three and six months ended June 30, 2017, respectively. |
| (4) |
Distributable cash flow excludes allowance for equity used during construction beginning Q1 2017. |
APPENDIX D
NON-GAAP RECONCILIATION REPORTED TO ADJUSTED NET INCOME PER COMMON UNIT AND I-UNIT
| Three months ended |
Six months ended |
||||||||||||||
| 2018 |
2017 |
2018 |
2017 |
||||||||||||
| (unaudited) |
|||||||||||||||
| Net income per common unit and i-unit (basic and diluted) |
$ |
0.19 |
$ |
0.21 |
$ |
0.34 |
$ |
0.36 |
|||||||
| Noncash derivative fair value (gains) losses: |
|||||||||||||||
| -Liquids |
0.01 |
— |
0.02 |
(0.01) |
|||||||||||
| -Natural Gas (included in Discontinued Operations) |
— |
(0.02) |
— |
(0.03) |
|||||||||||
| Accretion of discount on Series 1 preferred units |
— |
0.02 |
— |
0.02 |
|||||||||||
| Leak remediation costs, net of recoveries |
(0.05) |
— |
(0.05) |
— |
|||||||||||
| Sandpiper Project wind down costs |
— |
— |
— |
0.01 |
|||||||||||
| Gain on sale of assets |
— |
(0.08) |
— |
(0.08) |
|||||||||||
| Severance costs |
— |
0.01 |
0.01 |
0.03 |
|||||||||||
| Impairment of long-lived asset |
— |
— |
0.06 |
— |
|||||||||||
| Integration costs |
(0.01) |
— |
0.01 |
— |
|||||||||||
| Legal costs |
0.01 |
— |
0.01 |
— |
|||||||||||
| Adjusted net income per common unit and i-unit (basic and |
$ |
0.15 |
$ |
0.14 |
$ |
0.40 |
$ |
0.30 |
|||||||
| Weighted average common units and i-units outstanding |
428 |
400 |
427 |
377 |
|||||||||||
APPENDIX E
NON-GAAP RECONCILIATION LIQUIDS REPORTED EBITDA TO ADJUSTED EBITDA
| Three months ended |
Six months ended |
|||||||||||||
| 2018 |
2017 |
2018 |
2017 |
|||||||||||
| (unaudited; in millions) |
||||||||||||||
| EBITDA |
$ |
404 |
$ |
440 |
$ |
793 |
$ |
832 |
||||||
| Noncash derivative fair value (gains) losses |
5 |
(1) |
7 |
(3) |
||||||||||
| Leak remediation costs, net of recoveries |
(23) |
— |
(23) |
— |
||||||||||
| Gain on sale of assets |
— |
(52) |
— |
(52) |
||||||||||
| Sandpiper Project wind down costs |
— |
3 |
— |
6 |
||||||||||
| Severance costs |
— |
2 |
— |
6 |
||||||||||
| Integration costs |
(3) |
1 |
3 |
1 |
||||||||||
| Impairment of long-lived asset |
1 |
— |
36 |
— |
||||||||||
| Adjusted EBITDA |
$ |
384 |
$ |
393 |
$ |
816 |
$ |
790 |
||||||
APPENDIX F
NON-GAAP RECONCILIATION - OPERATING CASH FLOW TO DISTRIBUTABE CASH FLOW
| Three months ended |
Six months ended |
|||||||||||||
| 2018 |
2017 |
2018 |
2017 |
|||||||||||
| (unaudited; in millions) |
||||||||||||||
| Total net cash provided by (used in) operating activities |
$ |
294 |
$ |
(190) |
$ |
616 |
$ |
44 |
||||||
| Changes in operating assets and liabilities, net of cash acquired |
(3) |
494 |
(31) |
547 |
||||||||||
| Equity earnings from investment in joint venture |
(23) |
— |
— |
— |
||||||||||
| Distributions in excess of equity earnings, net of NCI |
3 |
— |
10 |
1 |
||||||||||
| Maintenance capital expenditures |
(6) |
(7) |
(11) |
(16) |
||||||||||
| Noncontrolling interests |
(102) |
(94) |
(211) |
(191) |
||||||||||
| Gain on sale of assets |
— |
— |
— |
11 |
||||||||||
| Severance costs |
— |
3 |
1 |
8 |
||||||||||
| Integration costs |
(3) |
1 |
3 |
1 |
||||||||||
| Legal costs |
3 |
— |
3 |
— |
||||||||||
| Other |
3 |
(25) |
(2) |
(25) |
||||||||||
| Distributable cash flow(1) |
$ |
166 |
$ |
182 |
$ |
378 |
$ |
380 |
||||||
| (1) Distributable cash flow excludes allowance for equity used during construction beginning Q1 2017. |
SOURCE Enbridge Energy Partners, L.P.
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