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: michael.barnes@enbridge.com
Investment Community
Roni Cappadonna
Toll Free: (800) 481-2804
Email: investor.relations@enbridge.com
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
June 30,
|
Six months ended
June 30,
|
|
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
June 30,
|
Six months ended
June 30,
|
|
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
June 30,
|
|
Six months ended
June 30,
|
|
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
June 30,
|
|
Six months ended
June 30,
|
|
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
June 30,
|
|
Six months ended
June 30,
|
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
June 30,
|
|
Six months ended
June 30,
|
|
|
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
amortization - discontinued operations
|
—
|
|
|
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
June 30,
|
|
Six months ended
June 30,
|
|
|
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
diluted)
|
$
|
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
June 30,
|
|
Six months ended
June 30,
|
|
|
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
June 30,
|
|
Six months ended
June 30,
|
|
|
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.
|
View original
content:http://www.prnewswire.com/news-releases/enbridge-energy-partners-lp-reports-second-quarter-2018-results-300691230.html
SOURCE Enbridge Energy Partners, L.P.