DEDHAM, Mass., Aug. 3, 2017 /CNW/ -- Atlantic Power
Corporation (NYSE: AT) (TSX: ATP) ("Atlantic Power" or the
"Company") today reported its financial results for the three and
six months ended June 30, 2017.
Net loss attributable to Atlantic Power Corporation of
$(21.9) million for the three months
ended June 30, 2017 increased
slightly from $(18.5) million in the
year-ago period primarily because of non-cash impairment expense
recorded at the Company's equity-owned Chambers and Selkirk projects. Project Adjusted
EBITDA, which does not include impairment expense, increased to
$85.4 million from $46.2 million in the year-ago period, reflecting
revenues received under the Global Adjustment settlement and the
positive impact of the enhanced dispatch agreements and the
expiration of an unfavorable fuel contract at North Bay and Kapuskasing (as discussed on page
2).
Second Quarter 2017 Financial Highlights
- Results included Cdn$32.8 million
(US$24.7 million) of revenues from
Global Adjustment settlement in Ontario
- Net loss of $(21.9) million in Q2
2017 vs. $(18.5) million in Q2
2016
- Project loss of $(12.1) million
in Q2 2017 vs. project income of $25.2
million in Q2 2016
- Net loss and Project loss included $57.7
million of non-cash impairments for Chambers and
Selkirk (equity-owned projects) in
Q2 2017
- Project Adjusted EBITDA of $85.4
million in Q2 2017 vs. $46.2
million in Q2 2016
- Cash provided by operating activities of $50.9 million in Q2 2017 vs. $24.3 million in Q2 2016
- Repaid $29.5 million of term loan
and project debt during Q2 2017; for full year 2017, expect to
repay a total of $150 million or
more, including $40 million of
discretionary debt repayment
- Liquidity at June 30 of
$227.2 million, including
$104.4 million of unrestricted
cash
Recent Developments
- Announced new seven-year tolling agreements with San Diego Gas
& Electric for two projects in San
Diego, Naval Station and North Island, subject to regulatory
approval and retaining control of the two sites
"This quarter's results keep us on track to meet our 2017
guidance for Project Adjusted EBITDA and our expectation for
Operating Cash Flow," said James J. Moore,
Jr., President and CEO of Atlantic Power. "The
restructuring we began two and a half years ago has resulted in
debt reduction of approximately one billion
dollars and reduced corporate overhead and interest expense
of $91 million annually. Our
efforts to strengthen the balance sheet have resulted in
significantly lower leverage and an improved debt maturity
profile. We also have greater liquidity, which at
June 30 totaled $227 million, including $104 million of unrestricted cash, of which
$69 million is available for capital
allocation, as compared to an enterprise value of approximately
$1.3 billion and a market
capitalization of approximately $270
million. We will continue to allocate available
capital to debt reduction, common and preferred share repurchases
and internal and external growth investments, based on
price-to-value estimates both on an absolute and a relative
basis."
Mr. Moore continued, "We recently announced new offtake
agreements for our Naval Station and North Island projects in San
Diego. Although these contracts are subject to a couple of
significant conditions, including approval of the California Public
Utilities Commission and site control with the U.S. Navy, we were
pleased to achieve this important milestone. We continue to
work on arranging new contracts for other projects for which Power
Purchase Agreements are expiring in 2018, and we hope to have more
to report in the coming quarters."
Atlantic Power
Corporation
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Table 1 – Summary
of Financial Results
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(in millions of
U.S. dollars, except as otherwise stated)
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Unaudited
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Three months
ended
June
30,
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Six months
ended
June
30,
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2017
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2016
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2017
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2016
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Financial
Highlights
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Project
revenue
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$124.0
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$98.2
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$222.4
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$204.6
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Project
income
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(12.1)
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25.2
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13.2
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53.9
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Net loss attributable
to Atlantic Power Corporation
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(21.9)
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(18.5)
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(24.6)
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(33.5)
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Cash provided by
operating activities
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50.9
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24.3
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85.0
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53.7
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Project Adjusted
EBITDA
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85.4
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46.2
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149.3
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108.7
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All amounts are in
U.S. dollars and are approximate unless otherwise indicated.
Project Adjusted EBITDA is not a recognized measure under
generally accepted accounting principles in the United States
("GAAP") and does not have a standardized meaning prescribed by
GAAP; therefore, this measure may not be comparable to similar
measures presented by other companies. Please refer to
"Non-GAAP Disclosures" on page 13 of this news release for an
explanation and a reconciliation of "Project Adjusted EBITDA" as
used in this news release to project income (loss), the most
directly comparable measure on a GAAP basis, and Net
loss.
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Financial Results
Results for the second quarter of 2017 were significantly
affected by changes to the operational and contractual status of
the Kapuskasing, North Bay and Nipigon plants in Ontario, which commenced in January 2017, and the settlement of the Global
Adjustment dispute with the Ontario Electricity Financial
Corporation in April 2017 (the "OEFC
Settlement"). In addition, the Company recorded significant
impairments on two of its equity-owned projects in the second
quarter, which affected project income and net income, although not
cash flow or Project Adjusted EBITDA. These developments are
discussed below.
Enhanced Dispatch Contracts
As previously reported, since the beginning of 2017, the
Kapuskasing, North Bay and Nipigon plants have been under enhanced
dispatch contracts that provide fixed monthly payments but do not
require the plants to generate power. As a result, they have
been in a non-operational state, which has resulted in operating
and fuel cost savings relative to 2016, when the plants were
operating and Kapuskasing and
North Bay were purchasing gas
under an above-market contract that expired at year-end 2016.
The revenues received under these contracts were $6.5 million and $12.4
million lower in the three and six months ended June 30, 2017, respectively, than in the
comparable year-ago periods, but this was more than offset by lower
maintenance and fuel expenses.
The Company has accelerated depreciation at Kapuskasing and North Bay through year-end 2017, when it will
have fully depreciated both plants consistent with the expiration
date of the enhanced dispatch contracts. The increased
depreciation associated with these plants was $3.9 million and $8.0
million for the three and six months ended June 30, 2017, respectively.
OEFC Settlement
As discussed in the Company's May 4,
2017 press release, in April
2017 the OEFC agreed to pay the Company a total of
approximately Cdn$36 million in
settlement of the Global Adjustment dispute, which was related to
power sold to the OEFC under the Power Purchase Agreements ("PPAs")
for the Kapuskasing, North Bay and Tunis projects. The Company received
Cdn$11.0 million of this amount in
the first quarter of 2017, consisting of Cdn$8.7 million for power sold by Kapuskasing and North Bay in 2016 and Cdn$2.3 million for Kapuskasing and North Bay under the enhanced dispatch
contracts for the first quarter of 2017. During the second
quarter of 2017, the Company received another Cdn$21.8 million, consisting of Cdn$20.3 million for power sold by the three
plants in April 2013 through year-end
2015 and another Cdn$1.4 million
under the enhanced dispatch contracts for Kapuskasing and North Bay for the second quarter of
2017. The remaining Cdn$3.6
million will be received as earned under the enhanced
dispatch contracts for the Kapuskasing and North Bay projects over the balance of
2017.
The Cdn$11.0 million received in
the first quarter of 2017 was recorded as deferred revenue and
therefore did not benefit net income or Project Adjusted EBITDA for
the quarter. In the second quarter of 2017, the Company
reversed this deferral and included the amount in revenues.
Thus, the total amount associated with the OEFC settlement included
in revenues in the second quarter was Cdn$32.8 million, which resulted in a
US$24.7 million benefit to Project
Adjusted EBITDA for the second quarter of 2017.
Impairment of Selkirk and
Chambers
The Company owns a 17.7% limited partner interest in
Selkirk, which has been operating
as a merchant facility since its PPA expired in August 2014.
During that time the Company has not received any distributions
from the project. Based on the project's history of making no
cash distributions while operating as a merchant facility, the
short-term and long-term operational forecast, as well as the
likelihood that further investment will be required to operate the
facility, the Company determined that its investment in
Selkirk is impaired and the
decline in value is other than temporary. Accordingly, during
the second quarter of 2017, the Company recorded a $10.6 million full impairment of its
investment.
The Company owns a 40% limited partner interest in Chambers,
which is a coal-fired project operating under a PPA that expires in
March 2024. During the second quarter of 2017, the Company
performed an analysis of the value of the project on the assumption
that it operated as a merchant facility after the PPA
expires. Although declining power prices have been observed
for several years, in the Company's most recent long-term forecast,
it identified a significant decrease in the long-term outlook for
power, gas and coal prices for the region in which the project
operates, which had a significant negative impact on the estimated
discounted cash flows of Chambers post-PPA. These discounted
cash flows represent a significant component of the overall value
of the project compared to its carrying value. Accordingly,
during the second quarter of 2017, the Company recorded a
$47.1 million impairment of its
$124.3 million investment in
Chambers, reducing the carrying value to $77.2 million.
Total impairment expense of $57.7
million for the three and six months ended June 30, 2017 was recorded in earnings from
unconsolidated affiliates and reduced both Project income and Net
income, but did not affect cash from operating activities or
Project Adjusted EBITDA.
Three Months Ended June 30,
2017
Net loss attributable to Atlantic Power
Corporation for the second quarter of 2017 was $(21.9) million as compared to $(18.5) million in the second quarter of
2016. Results benefited from increased revenues of
$25.8 million (primarily the result
of the OEFC settlement and improved hydrology at Curtis Palmer),
lower fuel and operations and maintenance expenses totaling
$17.8 million (primarily the result
of the enhanced dispatch contracts and the expiration of an
above-market gas supply contract in Ontario), and lower interest expense of
$33.0 million (due to a $31.4 million write-off of deferred financing
costs in the second quarter of 2016 and lower debt levels).
These positive factors were more than offset by the impairment
expense of $57.7 million, increased
depreciation expense of $4.0 million
and a $14.9 million negative change
in the fair value of derivative instruments (non-cash).
Project loss for the second quarter of 2017 was
$(12.1) million as compared to
project income in the year-ago period of $25.2 million. The $37.3 million reduction was primarily
attributable to the $57.7 million
impairment expense, $(14.9) million
change in fair value of derivative instruments and increased
depreciation expense, partially offset by increased revenues and
lower fuel and operations and maintenance expense as discussed
previously.
Project Adjusted EBITDA for the second quarter of
2017 was $85.4 million, an increase
of $39.2 million from $46.2 million in the year-ago period.
Primary drivers were the OEFC settlement discussed previously
($24.7 million), the favorable impact
on margins of the enhanced dispatch contracts and the expiration of
an above-market gas contract in Ontario (totaling $10.8
million), improved hydrology at Curtis Palmer ($6.5 million), and more modest increases at
Williams Lake and Piedmont (each $1.3
million). These positive factors were partially offset by
decreases at Frederickson (-$2.7
million), due to expenses associated with a major
maintenance outage, Mamquam (-$1.7
million), due to a forced outage and lower water flows, and
Calstock (-$1.2 million), due to lower waste heat and higher
fuel costs. During the quarter, the Canadian dollar declined
modestly relative to year-ago period, which had a non-cash
translation impact on Project Adjusted EBITDA of approximately
$(2.0) million.
Cash provided by operating activities for the
second quarter of 2017 of $50.9
million increased $26.6
million from the $24.3 million
a year ago. The 2017 period included approximately
$16.4 million of cash collected under
the OEFC settlement (the other $8
million was received in the first quarter). Other
factors that positively affected cash flow included the benefit to
gross margin from the revised contractual, operating and fuel
supply arrangements for Kapuskasing, North
Bay and Nipigon, as
previously discussed, improved hydrology at Curtis Palmer and a
$4.2 million reduction in cash
interest payments due to lower debt balances and a reduced spread
on the term loan (effective April 2017). These positive
factors were partially offset by decreases at Frederickson and
Mamquam, for reasons previously discussed.
Significant uses of cash provided by operating activities during
the second quarter of 2017 included $27.1
million of term loan amortization, $2.4 million of project debt amortization and
$2.2 million of preferred dividend
payments. The Company also used $2.2
million of cash for capital expenditures.
Six Months Ended June 30,
2017
Net loss attributable to Atlantic Power
Corporation for the six months ended June 30, 2017 was $(24.6)
million as compared to $(33.5)
million in the six months ended June
30, 2016. The $8.9
million reduction in loss was the result of several positive
factors, including increased revenues of $17.8 million (primarily the result of the OEFC
settlement and improved hydrology at Curtis Palmer, partially
offset by lower revenues under the enhanced dispatch contracts),
lower fuel and operations and maintenance expenses totaling
$28.7 million (primarily the result
of the enhanced dispatch contracts and expiration of an
above-market gas supply contract in Ontario), and lower interest expense of
$32.2 million (due to a $31.4 million write-off of deferred financing
costs in the second quarter of 2016 and lower debt levels).
These positive factors were more than offset by the $57.7 million impairment expense, increased
depreciation of $8.7 million, a
$14.9 million negative change in the
fair value of derivative instruments (non-cash) and a $14.2 million reduction in foreign exchange
loss. The reduction in foreign exchange loss was primarily
due to a $14.7 million decrease in
unrealized loss in the revaluation of instruments denominated in
Canadian dollars, stemming from the repurchase and cancellation of
Cdn$152.1 million Canadian
dollar-denominated convertible debentures in the second quarter of
2016.
Project income for the six months ended
June 30, 2017 declined to
$13.2 million from $53.9 million in the year-ago period. The
$40.7 million reduction was primarily
attributable to the $57.7 million
impairment expense, $(7.1) million
change in fair value of derivative instruments and increased
depreciation expense, partially offset by increased revenues and
lower fuel and operations and maintenance expense as discussed
previously.
Project Adjusted EBITDA for the six months ended
June 30, 2017 was $149.3 million, an increase of $40.6 million from $108.7
million in the year-ago period. Primary drivers were
the OEFC settlement ($24.7 million),
the favorable impact on margins of the enhanced dispatch contracts
and the expiration of an above-market gas contract in Ontario (totaling $17.6
million), improved hydrology at Curtis Palmer ($6.5 million), and more modest increases at
Piedmont ($1.9 million) and Orlando ($1.7
million). These positive factors were partially offset by
decreases at Morris (-$5.0 million),
primarily due to higher fuel prices, lower energy and capacity
prices and the non-recurrence of a return on a construction project
in the first quarter of 2016; Mamquam (-$3.6
million), due to a forced outage in the second quarter of
2017 and lower water flows as compared to a record year in 2016;
Calstock (-$2.5 million), due to lower waste heat and higher
fuel prices; and Frederickson (-$2.3
million), due to a major maintenance outage in the second
quarter of 2017. During the first six months of 2017, the
Canadian dollar appreciated slightly relative to the year-ago
period but the impact on Project Adjusted EBITDA was
immaterial.
Cash provided by operating activities for the six
months ended June 30, 2017 of
$85.0 million increased $31.3 million from the $53.7 million a year ago. The 2017 period
included approximately $24.7 million
of cash collected under the OEFC settlement. Other factors
that positively affected cash flow included the benefit to gross
margin from the revised contractual, operating and fuel supply
arrangements for Kapuskasing,
North Bay and Nipigon, as previously discussed, improved
hydrology at Curtis Palmer and a $1.3
million reduction in cash interest payments due to lower
debt balances and a reduced spread on the term loan (effective
April 2017). These positive factors were partially offset by
decreases at Morris, Frederickson, Mamquam and Calstock, for reasons previously
discussed.
Significant uses of cash provided by operating activities during
the six months ended June 30, 2017
included $52.1 million of term loan
amortization, $4.7 million of project
debt amortization and $4.3 million of
preferred dividend payments. The Company also used
$4.2 million of cash for capital
expenditures, primarily for the upgrade of the third and final
combustion turbine at Morris.
Liquidity and Balance Sheet
Liquidity
As shown in Table 2, the Company's liquidity at June 30, 2017 was $227.2
million, an increase of approximately $13 million from the March
31, 2017 level. The increase was attributable to an
increase in unrestricted cash, to $104.4
million from $91.5 million in
the previous period. The unrestricted cash of $104.4 million includes $78.6 million at the parent, of which the Company
considers approximately $69 million
to be discretionary cash available for general corporate purposes.
Atlantic Power
Corporation
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Table 2 –
Liquidity (in millions of U.S. dollars)
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Unaudited
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June
30,
2017
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March
31,
2017
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Cash and cash
equivalents, parent
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$78.6
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$65.6
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Cash and cash
equivalents, projects
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25.8
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25.9
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Total cash
and cash equivalents
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104.4
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91.5
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Revolving credit
facility
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200.0
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91.5
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Letters of credit
outstanding
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(77.2)
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(77.5)
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Availability under revolving credit facility
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122.8
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122.5
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Total
liquidity
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$227.2
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$214.0
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Note: Liquidity
numbers presented do not include restricted cash of $14.1 million
at June 30, 2017 and $10.0 million at March 31, 2017.
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Balance Sheet
Debt Repayment
During the second quarter of 2017, the Company repaid
$27.1 million of the APLP Holdings
term loan and amortized $2.4 million
of project-level debt. For the first six months of 2017, the
Company repaid a total of $52.1
million of the term loan and amortized $4.7 million of project-level debt. At
June 30, 2017, the Company's
consolidated debt was $947 million,
excluding unamortized discounts and deferred financing costs.
The Company's consolidated leverage ratio (consolidated gross debt
to trailing 12-month consolidated Adjusted EBITDA) was 4.4 times at
June 30, 2017. The improvement
in the leverage ratio from 5.4 times at March 31, 2017 was primarily attributable to the
positive impacts on EBITDA of the OEFC settlement payments
(recorded in the second quarter) and the enhanced dispatch
contracts (for the past two quarters) combined with the continued
reduction in debt.
For the full year 2017, the Company expects to repay
$100 million of its APLP Holdings
term loan (including the $52.1
million repaid in the first half of the year) and
$11.8 million of project-level debt
(including the $4.7 million amortized
in the first half). In addition, the Company plans to
allocate $40 million or more of its
discretionary cash to additional debt reduction (which could
include convertible debentures, further repayment of term loan and
repayment of Piedmont project
debt). This would put total debt repayment for the year at
$150 million or more.
Debt Maturity Profile
The Company has no bullet maturities in 2017. In 2018, the
Company has a project debt maturity at Piedmont totaling $54.2
million at its August 2018
maturity date. The remaining $42.5
million of Series C convertible debentures mature in
June 2019 and became callable at par
in June 2017. The $62.4 million
(U.S. dollar equivalent) of Series D convertible debentures mature
in December 2019 and are callable at
par in December 2017. The Company's revolving credit facility
has a 2021 maturity and the APLP Holdings term loan has a 2023
maturity (though is expected to be more than 80% repaid by the
maturity date).
Repricing of Term Loan and Revolver
As reported in the Company's April 17,
2017 press release, the Company executed a repricing of the
APLP Holdings term loan and revolving credit facility, reducing the
interest rate margin on the term loan and revolver by 75 basis
points, to LIBOR plus 425 basis points. Transaction costs
associated with the repricing of $1.1
million were included in interest expense in the second
quarter of 2017.
Normal Course Issuer Bid (NCIB) Update
The Company put in place a new normal course issuer bid ("NCIB")
on December 29, 2016. Details
of this program can be found in the Company's December 20, 2016 press release. The
Company has repurchased less than $100,000 of convertible debentures (in
January 2017) and no common shares
under this NCIB. In July 2017,
the Company repurchased and cancelled 171,612 shares of the 4.85%
Cumulative Redeemable Preferred (Series I issue) at Cdn$15.5 per share for a total payment of
Cdn$2.7 million.
Reaffirming 2017 Guidance
The Company has not provided guidance for Project income or Net
income because of the difficulty of making accurate forecasts and
projections without unreasonable efforts with respect to certain
highly variable components of these comparable GAAP metrics,
including changes in the fair value of derivative instruments and
foreign exchange gains or losses. These factors, which
generally do not affect cash flow, are not included in Project
Adjusted EBITDA.
The Company has not changed its 2017 guidance for Project
Adjusted EBITDA of $250 to $265
million. Table 3 provides a bridge of the Company's
2017 Project Adjusted EBITDA guidance to Cash provided by operating
activities. For purposes of providing this bridge to a cash
flow measure, the impact of changes in working capital is assumed
to be nil.
Atlantic Power
Corporation Table 3 – Bridge of 2017 Project Adjusted
EBITDA Guidance to Cash Provided by Operating
Activities (in millions of U.S.
dollars) Unaudited
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2017 Project
Adjusted EBITDA Guidance(1)
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$250 -
$265
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Adjustment for equity
method projects(2)
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(1)
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Corporate G&A
expense
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(22)
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Cash interest
payments
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(67)
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Cash taxes
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(4)
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Other
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-
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Cash provided by
operating activities
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$155
-$170
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Note: For the
purpose of providing a bridge of Project Adjusted EBITDA guidance
to a cash flow measure, the impact of changes in working capital on
Cash provided by operating activities is assumed to be
nil.
(1)
Initially provided on May 4, 2017.
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(2) For
equity method projects, represents difference between Project
Adjusted EBITDA and cash distribution from equity method
projects.
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Other Financial Updates
Update on San Diego PPAs
As previously disclosed, the Company has three projects in
San Diego that sell power to San
Diego Gas & Electric ("SDG&E") under PPAs that are
scheduled to expire in December 2019. The Company also
supplies steam from these projects to the U.S. Navy under
agreements that provide the Company with the right to use the
property at the respective sites on which each project is
located. Those agreements are scheduled to expire in February
2018.
As discussed in the Company's August 1,
2017 press release, the Company has executed new seven-year
Power Purchase Tolling Agreements ("PPTAs") with SDG&E for its
Naval Station and North Island projects. The PPTAs are
subject to significant conditions precedent, including the approval
of the California Public Utilities Commission ("CPUC"), which could
take approximately four months or longer, and the Company's ability
to continue using the property at the respective sites. The
Company has submitted a detailed proposal in a solicitation by the
U.S. Navy for energy security and resiliency at these two sites,
but the timeframe for resolution of this process is
uncertain. If successful in the solicitation, the Company
would retain the right to use the property. Subject to
meeting the conditions precedent, deliveries under the PPTAs would
commence as early as February 2018. The Project Adjusted
EBITDA of the two projects under the PPTAs is estimated to be
approximately $6 million annually on
a combined basis as compared to approximately $16 million under the existing PPAs in
2017.
The Company continues to pursue contractual arrangements for its
Naval Training Center ("NTC") project in San Diego, which also would be subject to
retaining control of the respective site and regulatory
approval. NTC is expected to generate approximately
$4 million of Project Adjusted EBITDA
in 2017.
Maintenance and Capex
For 2017, including its share of equity-owned projects, the
Company expects to incur maintenance expenses of approximately
$41 million (modestly lower than the
2016 level), which includes an estimate of the cost to prepare
Tunis for a return to service in
2018 under its PPA. Approximately $17.8 million of maintenance expense was incurred
in the first six months of 2017. The Company's estimate of
capital expenditures for 2017 is approximately $5.5 million (slightly lower than the 2016
level). Approximately $4.8
million was incurred in the first six months of 2017, most
of it related to the recently completed upgrade of the third and
final combustion turbine at Morris.
Supplementary Information Regarding Non-GAAP
Disclosures
A discussion of non-GAAP disclosures and schedules reconciling
Project Adjusted EBITDA, a non-GAAP measure, to the comparable GAAP
measure, can be found on page 13 of this release.
Investor Conference Call and Webcast
Atlantic Power's management team will host a telephone
conference call on Friday, August 4,
2017 at 8:30 AM ET.
Management's prepared remarks and an accompanying presentation will
be available on the Conference Calls page of the Company's website
prior to the call.
Conference Call / Webcast Information:
Date: Friday, August
4, 2017
Start Time: 8:30 AM
ET
Phone Number: U.S. (Toll Free) 1-855-239-3193;
Canada (Toll Free) 1-855-669-9657;
International (Toll) 1-412-542-4129.
Conference Access: Please request access to the
Atlantic Power conference call.
Webcast: The call will be broadcast over Atlantic
Power's website at www.atlanticpower.com.
Replay/Archive Information:
Replay: Access conference call number
10110155 at the following telephone numbers: U.S.
(Toll Free) 1-877-344-7529; Canada
(Toll Free) 1-855-669-9658; International (Toll)
1-412-317-0088. The replay will be available one hour after
the end of the conference call through September 4, 2017 at 11:59
PM ET.
Webcast archive: The conference call will be archived
on Atlantic Power's website at www.atlanticpower.com for a period
of 12 months.
About Atlantic Power
Atlantic Power owns and operates a diverse fleet of twenty-three
power generation assets across nine states in the United States and two provinces in
Canada. The Company's power generation projects sell
electricity to utilities and other large commercial customers
largely under long-term PPAs, which seek to minimize exposure to
changes in commodity prices. The aggregate gross electric
generation capacity of this portfolio is approximately 2,138
megawatts ("MW"), and the Company's aggregate net ownership
interest is approximately 1,500 MW. Nineteen of the projects
are currently operational, totaling 1,975 MW on a gross capacity
basis and 1,337 MW on a net ownership basis. The remaining
four projects, all in Ontario, are
not operational, three due to revised contractual arrangements with
the offtaker and the other, Tunis,
has a forward-starting 15-year contractual agreement that will
commence between November 2017 and
June 2019.
Atlantic Power's shares trade on the New York Stock Exchange
under the symbol AT and on the Toronto Stock Exchange under the
symbol ATP. For more information, please visit the Company's
website at www.atlanticpower.com or contact:
Atlantic Power Corporation
Investor Relations
(617) 977-2700
info@atlanticpower.com
Copies of the Company's financial data and other publicly filed
documents are available on SEDAR at www.sedar.com or on EDGAR at
www.sec.gov/edgar.shtml under "Atlantic Power Corporation" or on
the Company's website.
************************************************************************************************************************Cautionary
Note Regarding Forward-Looking Statements
To the extent any statements made in this news release contain
information that is not historical, these statements are
forward-looking statements within the meaning of Section 27A of the
U.S. Securities Act of 1933, as amended, and Section 21E of the
U.S. Securities Exchange Act of 1934, as amended, and under
Canadian securities law (collectively, "forward-looking
statements").
Certain statements in this news release may constitute
"forward-looking statements", which reflect the expectations of
management regarding the future growth, results of operations,
performance and business prospects and opportunities of the Company
and its projects. These statements, which are based on
certain assumptions and describe the Company's future plans,
strategies and expectations, can generally be identified by the use
of the words "may," "will," "project," "continue," "believe,"
"intend," "anticipate," "expect" or similar expressions that are
predictions of or indicate future events or trends and which do not
relate solely to present or historical matters. Examples of
such statements in this press release include, but are not limited,
to statements with respect to the following:
- the Company's expectation with respect to progress on PPAs
expiring in 2018;
- the Company's expectation that it will receive another
Cdn$3.6 million of Global Adjustment
revenues under the OEFC settlement over the remainder of 2017;
- the Company's estimate of discretionary cash ($69 million) and its plans to allocate
approximately $40 million or more to
discretionary debt repayment in 2017;
- the Company's estimate of an enterprise value ($1.3 billion);
- the Company's expectation to allocate available capital to debt
reduction, common and preferred share repurchases (and internal and
external growth investments), based on price-to-value estimates
both on an absolute and relative basis;
- the Company's expectation that it will repay $100 million of its APLP Holdings term loan and
$11.8 million of project-level debt
for the full year 2017;
- the Company's expectation that it will repay $150 million or more of debt in 2017;
- the Company's expectation that it will repay more than 80% of
its term loan by the maturity date in 2023;
- the Company's estimation that 2017 Project Adjusted EBITDA will
be in the range of $250 to $265
million;
- the Company's estimation that 2017 cash flows provided by
operating activities will be in the range of $155 to $170 million, assuming for this purpose
that working capital changes are nil;
- the Company's ability to satisfy certain conditions relating to
the PPTAs, including obtaining the approval of the CPUC and
retaining site control at Naval Station and North Island;
- the expected timeline for obtaining CPUC approval;
- the Company's expectations with respect to the level of Project
Adjusted EBITDA that Naval Station, North Island and NTC will
generate in 2017;
- the Company's expectations with respect to the level of Project
Adjusted EBITDA that Naval Station and North Island may generate
under the PPTAs;
- the Company's expectation that in 2017, including its share of
equity-owned projects, capital expenditures will total
approximately $5.5 million and
maintenance expense will total approximately $41 million; and
- the results of operations and performance of the Company's
projects, business prospects, opportunities and future growth of
the Company will be as described herein.
Forward-looking statements involve significant risks and
uncertainties, should not be read as guarantees of future
performance or results, and will not necessarily be accurate
indications of whether or not or the times at or by which such
performance or results will be achieved. Please refer to the
factors discussed under "Risk Factors" and "Forward-Looking
Information" in the Company's periodic reports as filed with the
Securities and Exchange Commission from time to time for a detailed
discussion of the risks and uncertainties affecting the Company,
including, without limitation, the outcome or impact of the
Company's business strategy to increase the intrinsic value of the
Company on a per-share basis through disciplined management of its
balance sheet and cost structure and investment of its
discretionary cash in a combination of organic and external growth
projects, acquisitions, and repurchases of debt and equity
securities; the Company's ability to enter into new PPAs on
favorable terms or at all after the expiration of existing
agreements, and the outcome or impact on the Company's business of
any such actions. Although the forward-looking statements
contained in this news release are based upon what are believed to
be reasonable assumptions, investors cannot be assured that actual
results will be consistent with these forward-looking statements,
and the differences may be material. These forward-looking
statements are made as of the date of this news release and, except
as expressly required by applicable law, the Company assumes no
obligation to update or revise them to reflect new events or
circumstances. The Company's ability to achieve its
longer-term goals, including those described in this news release,
is based on significant assumptions relating to and including,
among other things, the general conditions of the markets in which
it operates, revenues, internal and external growth opportunities,
its ability to sell assets at favorable prices or at all and
general financial market and interest rate conditions. The
Company's actual results may differ, possibly materially and
adversely, from these goals.
Atlantic Power
Corporation
Table 4 –
Consolidated Balance Sheet (in millions of U.S.
dollars)
|
|
|
Unaudited
|
|
|
|
June
30,
|
December
31,
|
|
2017
|
2016
|
Assets
|
|
|
Current
assets:
|
|
|
Cash and cash
equivalents
|
$104.4
|
$85.6
|
Restricted
cash
|
14.1
|
13.3
|
Accounts
receivable
|
42.3
|
37.3
|
Current
portion of derivative instruments asset
|
2.8
|
4.0
|
Inventory
|
19.5
|
16.0
|
Prepayments
|
7.2
|
5.9
|
Income taxes
receivable
|
0.5
|
-
|
Other current
assets
|
2.9
|
2.8
|
Total current
assets
|
193.7
|
164.9
|
|
|
|
Property, plant and
equipment, net
|
705.8
|
733.2
|
Equity investments in
unconsolidated affiliates
|
204.2
|
266.8
|
Power purchase
agreements and intangible assets, net
|
227.4
|
246.2
|
Goodwill
|
36.0
|
36.0
|
Derivative
instruments asset
|
2.8
|
4.6
|
Other
assets
|
4.2
|
5.1
|
Total
assets
|
$1,374.1
|
$1,456.8
|
|
|
|
Liabilities
|
|
|
Current
liabilities:
|
|
|
Accounts
payable
|
$3.3
|
$4.5
|
Accrued
interest
|
2.0
|
0.7
|
Other accrued
liabilities
|
23.9
|
24.4
|
Current
portion of long-term debt
|
106.9
|
111.9
|
Current
portion of derivative instruments liability
|
6.3
|
7.6
|
Other current
liabilities
|
3.0
|
1.8
|
Total current
liabilities
|
145.4
|
150.9
|
|
|
|
Long-term debt
(1)
|
707.6
|
749.2
|
Convertible
debentures (2)
|
102.8
|
100.4
|
Derivative
instruments liability
|
24.4
|
21.3
|
Deferred income
taxes
|
43.6
|
68.3
|
Power purchase and
fuel supply agreement liabilities, net
|
24.7
|
25.3
|
Other long-term
liabilities
|
56.3
|
55.5
|
Total
liabilities
|
$1,104.8
|
$1,170.9
|
|
|
|
Equity
|
|
|
Common shares, no par
value, unlimited authorized shares; 115,280,908 and 114,649,888
issued and outstanding at June 30, 2017 and December 31, 2016,
respectively
|
1,274.0
|
1,272.9
|
Accumulated other
comprehensive loss
|
(141.6)
|
(148.5)
|
Retained
deficit
|
(1,084.4)
|
(1,059.8)
|
Total Atlantic Power
Corporation shareholders' equity
|
48.0
|
64.6
|
Preferred shares
issued by a subsidiary company
|
221.3
|
221.3
|
Total
equity
|
269.3
|
285.9
|
Total liabilities and
equity
|
$1,374.1
|
$1,456.8
|
(1) Net of
unamortized discount and deferred financing costs
(2) Net of
unamortized deferred financing costs
|
|
|
Atlantic Power
Corporation
|
|
|
|
|
|
|
|
Table 5 –
Consolidated Statements of Operations
|
|
|
|
|
|
|
|
(in millions of
U.S. dollars, except per share amounts)
|
|
|
|
|
|
|
|
Unaudited
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months
ended June
30,
|
|
Six months
ended
June
30,
|
|
|
2017
|
2016
|
|
2017
|
2016
|
Project
revenue:
|
|
|
|
|
|
|
Energy
sales
|
|
$40.0
|
$45.1
|
|
$77.1
|
$97.6
|
Energy
capacity revenue
|
|
28.3
|
37.3
|
|
47.8
|
69.2
|
Other
|
|
55.7
|
15.8
|
|
97.5
|
22.0
|
|
|
124.0
|
98.2
|
|
222.4
|
204.6
|
Project
expenses:
|
|
|
|
|
|
|
Fuel
|
|
24.0
|
35.1
|
|
52.9
|
74.0
|
Operations and
maintenance
|
|
23.3
|
30.0
|
|
43.6
|
51.2
|
Depreciation
and amortization
|
|
29.5
|
25.5
|
|
59.0
|
50.3
|
|
|
76.8
|
90.6
|
|
155.5
|
175.5
|
Project other
income:
|
|
|
|
|
|
|
Change in fair
value of derivative instruments
|
|
(2.7)
|
12.2
|
|
(3.9)
|
11.0
|
Equity in
(loss) earnings of unconsolidated affiliates
|
|
(54.4)
|
7.6
|
|
(45.4)
|
18.3
|
Interest
expense, net
|
|
(2.2)
|
(2.4)
|
|
(4.4)
|
(4.5)
|
Other income,
net
|
|
-
|
0.2
|
|
-
|
-
|
|
|
(59.3)
|
17.6
|
|
(53.7)
|
24.8
|
Project (loss)
income
|
|
(12.1)
|
25.2
|
|
13.2
|
53.9
|
Administrative and
other expenses:
|
|
|
|
|
|
|
Administration
|
|
5.7
|
5.8
|
|
12.1
|
11.9
|
Interest
expense, net
|
|
18.4
|
51.2
|
|
35.7
|
67.8
|
Foreign
exchange loss
|
|
5.9
|
2.6
|
|
8.3
|
22.5
|
Other income
(expense), net
|
|
-
|
0.3
|
|
-
|
(2.2)
|
|
|
30.0
|
59.9
|
|
56.1
|
100.0
|
Loss from operations
before income taxes
|
|
(42.1)
|
(34.7)
|
|
(42.9)
|
(46.1)
|
Income tax
benefit
|
|
(22.3)
|
(18.4)
|
|
(22.6)
|
16.8
|
Net loss
|
|
(19.8)
|
(16.3)
|
|
(20.3)
|
(29.3)
|
Net income
attributable to preferred share dividends of a subsidiary
company
|
|
2.1
|
2.2
|
|
4.3
|
4.2
|
Net loss attributable
to Atlantic Power Corporation
|
|
($21.9)
|
($18.5)
|
|
($24.6)
|
($33.5)
|
Net loss per share
attributable to Atlantic Power Corporation shareholders:
|
|
|
|
|
|
|
Basic
|
|
($0.19)
|
($0.15)
|
|
($0.21)
|
($0.28)
|
Diluted
|
|
(0.19)
|
(0.15)
|
|
(0.21)
|
(0.28)
|
|
|
|
|
|
|
|
Weighted average
number of common shares outstanding:
|
|
|
|
|
|
|
Basic
|
|
115.2
|
121.6
|
|
115.0
|
121.8
|
Diluted
|
|
115.2
|
121.6
|
|
115.0
|
121.8
|
|
|
|
|
|
|
|
|
|
|
|
Atlantic Power
Corporation
|
Table 6 –
Consolidated Statements of Cash Flows (in millions of U.S.
dollars)
|
Unaudited
|
|
|
|
|
|
|
|
Six months ended
June 30,
|
|
|
|
2017
|
2016
|
Cash provided by
operating activities:
|
|
|
|
|
Net loss
|
|
|
($20.3)
|
($29.3)
|
Adjustments to
reconcile net loss to net cash provided by operating
activities:
|
|
|
|
|
Depreciation and
amortization
|
|
|
59.0
|
50.3
|
Gain on purchase and
cancellation of convertible debentures
|
|
|
-
|
(2.5)
|
Loss on sale of
assets
|
|
|
-
|
0.2
|
Stock-based
compensation expense
|
|
|
1.1
|
0.8
|
Equity in loss
(earnings) from unconsolidated affiliates
|
|
|
45.4
|
(18.3)
|
Distributions from
unconsolidated affiliates
|
|
|
17.2
|
23.5
|
Unrealized foreign
exchange loss
|
|
|
8.3
|
22.5
|
Change in fair value
of derivative instruments
|
|
|
3.9
|
(11.0)
|
Amortization of debt
discount and deferred financing costs
|
|
|
5.2
|
37.5
|
Change in deferred
income taxes
|
|
|
(24.9)
|
(18.6)
|
Change in other
operating balances
|
|
|
|
|
Accounts
receivable
|
|
|
(5.0)
|
(3.3)
|
Inventory
|
|
|
(3.4)
|
(0.4)
|
Prepayments and other
assets
|
|
|
(0.3)
|
1.7
|
Accounts
payable
|
|
|
(1.4)
|
3.5
|
Accruals and other
liabilities
|
|
|
0.2
|
(2.9)
|
Cash provided by
operating activities
|
|
|
85.0
|
53.7
|
|
|
|
|
|
Cash (used in)
provided by investing activities:
|
|
|
|
|
Change in restricted
cash
|
|
|
(0.8)
|
0.9
|
Reimbursement of costs
for third-party construction project
|
|
|
-
|
4.7
|
Purchase of property,
plant and equipment
|
|
|
(4.2)
|
(2.0)
|
Cash (used in)
provided by investing activities
|
|
|
(5.0)
|
3.6
|
|
|
|
|
|
Cash (used in)
provided by financing activities:
|
|
|
|
|
Proceeds from term loan facility, net of discount
|
|
|
-
|
679.0
|
Common share
repurchases
|
|
|
-
|
(4.7)
|
Repayment of corporate
and project-level debt
|
|
|
(56.9)
|
(502.7)
|
Repayment of
convertible debentures
|
|
|
-
|
(127.0)
|
Deferred financing
costs
|
|
|
-
|
(15.9)
|
Dividends paid to
preferred shareholders
|
|
|
(4.3)
|
(4.2)
|
Cash (used in)
provided by financing activities
|
|
|
(61.2)
|
24.5
|
|
|
|
|
|
Net increase in cash
and cash equivalents
|
|
|
18.8
|
81.8
|
Cash and cash
equivalents at beginning of period
|
|
|
85.6
|
72.4
|
Cash and cash
equivalents at end of period
|
|
|
$104.4
|
$154.2
|
|
|
|
|
|
Supplemental cash
flow information
|
|
|
|
|
Interest
paid
|
|
|
$33.4
|
$34.7
|
Income taxes paid,
net
|
|
|
$2.2
|
$1.9
|
Accruals for
construction in progress
|
|
|
$1.3
|
$1.0
|
Non-GAAP Disclosures
Project Adjusted EBITDA is not a measure recognized under
GAAP and does not have a standardized meaning prescribed by GAAP,
and is therefore unlikely to be comparable to similar measures
presented by other companies. Investors are cautioned that
the Company may calculate this non-GAAP measure in a manner that is
different from other companies. The most directly comparable
GAAP measure is Project income (loss). Project Adjusted
EBITDA is defined as project income (loss) plus interest, taxes,
depreciation and amortization (including non-cash impairment
charges), and changes in the fair value of derivative
instruments. Management uses Project Adjusted EBITDA at the
project level to provide comparative information about project
performance and believes such information is helpful to
investors. A reconciliation of Project Adjusted EBITDA to
Project income (loss) and to Net loss on a consolidated basis is
provided in Table 7 below.
Cash Distributions from Projects is the amount of cash
distributed by the projects to the Company out of available project
cash flow after all project-level operating costs, interest
payments, principal repayment, capital expenditures and working
capital requirements. A bridge of Project Adjusted EBITDA to
Cash Distributions from Projects can be found in the second quarter
2017 presentation on the Company's website.
Project income (loss) and Project Adjusted EBITDA by project
also can be found in the second quarter 2017 presentation on the
Company's website.
Atlantic Power
Corporation
|
|
Table 7 –
Reconciliation of Net loss to Project Adjusted
EBITDA
|
|
(in millions of
U.S. dollars, except as otherwise stated)
|
|
Unaudited
|
|
|
|
|
|
|
|
|
|
Three months ended
June 30,
|
|
Six months ended
June 30,
|
|
2017
|
2016
|
|
2017
|
2016
|
Net loss
attributable to Atlantic Power Corporation
|
($21.9)
|
($18.5)
|
|
($24.6)
|
($33.5)
|
Net income
attributable to preferred share dividends of a subsidiary
company
|
2.1
|
2.2
|
|
4.3
|
4.2
|
Net loss from
operations
|
($19.8)
|
($16.3)
|
|
($20.3)
|
($29.3)
|
Income tax
benefit
|
(22.3)
|
(18.4)
|
|
(22.6)
|
(16.8)
|
Loss from operations
before income taxes
|
(42.1)
|
(34.7)
|
|
(42.9)
|
(46.1)
|
Administration
|
5.7
|
5.8
|
|
12.1
|
11.9
|
Interest expense,
net
|
18.4
|
51.2
|
|
35.7
|
67.8
|
Foreign exchange
loss
|
5.9
|
2.6
|
|
8.3
|
22.5
|
Other expense
(income), net
|
-
|
0.3
|
|
-
|
(2.2)
|
Project (loss)
income
|
($12.1)
|
$25.2
|
|
$13.2
|
$53.9
|
|
|
|
|
|
|
Reconciliation to
Project Adjusted EBITDA
|
|
|
|
|
|
Depreciation and
amortization
|
$34.7
|
$30.4
|
|
$69.3
|
$60.3
|
Interest expense,
net
|
2.5
|
2.9
|
|
5.3
|
5.4
|
Change in the fair
value of derivative instruments
|
2.6
|
(12.2)
|
|
3.8
|
(11.0)
|
Other (income)
expense
|
-
|
(0.1)
|
|
-
|
0.1
|
Impairment
|
57.7
|
-
|
|
57.7
|
-
|
Project Adjusted
EBITDA
|
$85.4
|
$46.2
|
|
$149.3
|
$108.7
|
|
|
|
|
|
|
|
|
|
|
|
View original
content:http://www.prnewswire.com/news-releases/atlantic-power-corporation-releases-second-quarter-2017-results-300499563.html
SOURCE Atlantic Power Corporation