DEDHAM, Mass., Nov. 9, 2017 /PRNewswire/ --
Third Quarter and YTD 2017 Highlights
- Cash provided by operating activities of $52.9 million in Q3 2017 vs. $38.2 million in Q3 2016
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- $137.9 million for the first nine
months of 2017 vs. $91.9 million in
the year-ago period
- Net loss of $(32.9) million in Q3
2017 vs. $(82.4) million in Q3
2016
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- $(57.5) million for the first
nine months of 2017 vs. $(116.2)
million in the year-ago period
- Project Adjusted EBITDA of $77.4
million in Q3 2017 vs. $51.3
million in Q3 2016
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- $226.6 million for the first nine
months of 2017 vs. $159.9 million in
the year-ago period
- Repaid $29.4 million of term loan
and project debt during Q3 2017 and $86.2
million year to date
- Liquidity at September 30, 2017
of $249.8 million
Recent Developments
- In October, repaid $54.6 million
remaining project debt at Piedmont, yielding estimated interest cost
savings of $4.5 million annually
-
- Pro forma for Piedmont debt
repayment, liquidity was $178.5
million and leverage ratio was 3.6 times
- In October, executed second repricing of term loan and
revolver, reducing spread 75 bp to L+3.50%
-
- Estimated interest cost savings of $4
million in 2018 and $15
million over terms of facilities
- In October, executed a one-year extension of the maturity date
of the revolver to April 2022
- In October, Moody's upgraded the Company's corporate family
credit rating to Ba3 from B1
Guidance
- Increased 2017 Project Adjusted EBITDA guidance range by
$10 million (see page 7)
Atlantic Power Corporation (NYSE: AT) (TSX: ATP) ("Atlantic
Power" or the "Company") today reported its financial results for
the three and nine months ended September
30, 2017. Net loss attributable to Atlantic Power
Corporation of $(32.9) million for
the three months ended September 30,
2017 decreased from $(82.4)
million in the year-ago period, primarily because of higher
margins at Kapuskasing and
North Bay (as discussed on page
2), an extended planned outage at Morris in the third quarter of
2016 that did not recur in 2017, lower non-cash impairment expense
and lower interest expense, partially offset by other
factors. Project Adjusted EBITDA, which does not include
impairment expense, increased to $77.4
million from $51.3 million in
the third quarter of 2016, primarily due to increases at
Kapuskasing, North Bay, Morris and
Curtis Palmer, which experienced higher water flows.
Cash provided by operating activities increased to $52.9 million from $38.2
million in the third quarter of 2016.
"We have increased our 2017 guidance for Project Adjusted EBITDA
and our expectation for Operating Cash Flow as a result of our
strong year-to-date results and our outlook for the remainder of
the year," said James J. Moore, Jr.,
President and CEO of Atlantic Power. "We finished the third
quarter with liquidity of $250
million, and in October we used $60
million of discretionary cash to pay off the Piedmont debt ten months ahead of its
maturity, reducing annual interest costs by approximately
$4.5 million. For the full
year, we expect to reduce debt by approximately $166 million. We also executed another
successful repricing of our term loan and revolving credit
facility, reducing the spread an additional 75 basis points, which
will save $4 million of interest
costs in 2018. Lastly, we recently executed an agreement to
extend the maturity date of our corporate revolver by one year, to
April 2022, further extending our
stable liquidity profile."
Mr. Moore continued, "The steps that we have taken over the past
few years to reduce our cost structure by nearly $100 million annually from 2013 levels, pay down
approximately $1 billion of debt, and
improve our maturity profile, position us well to continue
delevering and to allocate available cash to growth initiatives,
security repurchases and discretionary debt repayment."
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
September 30,
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Nine months
ended
September 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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$108.6
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$101.2
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$331.0
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$305.8
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Project
loss
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(20.9)
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(57.1)
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(7.7)
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(3.3)
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Net loss attributable
to Atlantic Power Corporation
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(32.9)
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(82.4)
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(57.5)
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(116.2)
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Cash provided by
operating activities
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52.9
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38.2
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137.9
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91.9
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Project Adjusted
EBITDA
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77.4
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51.3
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226.6
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159.9
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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 14 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 third 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 its three San Diego
plants in the third 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 $4.2 million and $16.6
million lower in the three and nine months ended
September 30, 2017, respectively,
than in the comparable year-ago periods, but this decrease 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 $4.5 million and $12.6
million for the three and nine months ended September 30, 2017, respectively.
OEFC Settlement
In April 2017, the OEFC agreed to
pay the Company a total of approximately Cdn$36.4 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. A subsequent adjustment increased this amount to
approximately Cdn$37.8 million.
The Company received and recorded a total of Cdn$34.0 million of revenue related to the OEFC
Settlement in the first nine months of 2017, including Cdn$1.2 million in the third quarter of
2017. The remaining amount will be received as earned under
the enhanced dispatch contracts for the Kapuskasing and North Bay projects in the fourth quarter of
2017.
The benefit to Project Adjusted EBITDA from the OEFC Settlement
was US$25.6 million for the nine
months ended September 30, 2017,
including $1.0 million in the third
quarter of 2017.
Impairment of San Diego Plants
As discussed in the Company's previous filings on Form 10-K and
Form 10-Q, the Company owns three plants in San Diego – Naval Station, Naval Training
Center ("NTC") and North Island. These plants sell power to
San Diego Gas & Electric ("SDG&E") under PPAs that are
scheduled to expire in December 2019. In addition, the three
plants supply steam 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 (the "Navy
agreements"). The Navy agreements are scheduled to expire in
February 2018. In August 2017,
the Company learned that proposals involving the Naval Station and
North Island plants were not selected in the final round of the
Navy's solicitation for energy security and resiliency at the
respective bases on which these two plants are located. A
successful outcome in this solicitation was the clearest path to
obtaining the right to remain on the sites beyond February 2018 ("site control").
Based on the outcome of the Navy solicitation, the Company
determined that it is unlikely that the three plants will operate
beyond the expiration of the Navy agreements. The Company
undertook an evaluation of the carrying values of the long-lived
assets, including intangible assets (associated with the PPAs) and
property, plant and equipment (PP&E). This evaluation
assumed that the PPAs will terminate in February 2018. During
the third quarter, the Company recorded a $57.3 million impairment of the long-lived assets
at these three plants, including $18.2
million for a full impairment of the remaining intangible
assets. At September 30, 2017,
there was $7.7 million of remaining
PP&E, which will be depreciated through February 2018.
As of September 30, 2017, the
Company had recorded $4.6 million of
net removal obligations for the San
Diego plants. The Company is in the process of
evaluating the estimated removal costs and may make adjustments to
this amount in the fourth quarter of 2017. The timing and
final arrangements for decommissioning the sites have not yet been
determined.
The $57.3 million impairment
associated with the San Diego Plants reduced both Project income
and Net income for the three and nine months ended September 30, 2017. Impairment expense does
not affect cash from operating activities or Project Adjusted
EBITDA.
Three Months Ended September 30,
2017
Net loss attributable to Atlantic Power
Corporation for the third quarter of 2017 was $(32.9) million as compared to $(82.4) million in the third quarter of
2016. The $49.5 million
reduction in net loss was the result of increased revenues of
$7.4 million (primarily driven by
higher water flows at Curtis Palmer and the non-recurrence of an
extended planned outage at Morris in the prior-year period,
partially offset by lower revenues under the enhanced dispatch
contracts), a reduction in fuel and operations and maintenance
expenses of $19.0 million (primarily
at Kapuskasing, North Bay and Morris, as discussed
previously), a $27.4 million
reduction in impairment expense (the year-ago period included
$84.7 million of impairment expense
associated with the Company's Mamquam, Curtis Palmer, North Bay and Kapuskasing plants), and a $6.4 million reduction in corporate and project
interest expense. These positive factors were partially
offset by an increase in foreign exchange loss (loss of
$9.4 million versus a gain of
$3.4 million in the year-ago period),
a $10.9 million negative change in
the fair value of derivative instruments (non-cash), and increased
depreciation expense of $6.1 million
(mostly for Kapuskasing and
North Bay).
Project loss for the third quarter of 2017 was
$(20.9) million as compared to
$(57.1) million in the year-ago
period. The $36.2 million
reduction in loss was primarily attributable to the reduction in
impairment expense, increased revenues, and lower fuel and
operations and maintenance expense, as discussed previously,
partially offset by increased foreign exchange loss, a negative
change in the fair value of derivative instruments and increased
depreciation expense, as discussed previously.
Project Adjusted EBITDA for the third quarter of
2017 was $77.4 million, an increase
of $26.1 million from $51.3 million in the year-ago period.
Primary drivers were the favorable impact on margins of the
enhanced dispatch contracts and the expiration of an above-market
gas contract in Ontario (totaling
$11.1 million, including $1.0 million related to the OEFC Settlement), the
non-recurrence of an extended planned outage at Morris
($7.5 million), higher water flows at
Curtis Palmer ($3.5 million), higher
water flows and lower maintenance expense at Mamquam ($1.1 million), and modest increases at
Orlando and Williams Lake. These positive factors
were partially offset by modest decreases at several plants, none
of which exceeded $0.5 million.
During the quarter, the Canadian dollar appreciated modestly
relative to the year-ago period. This had a non-cash
translation benefit to Project Adjusted EBITDA of approximately
$1.0 million.
Cash provided by operating activities for the
third quarter of 2017 of $52.9
million increased $14.7
million from $38.2 million a
year ago. 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; higher revenues and lower maintenance expense
at Morris, which underwent an extended scheduled outage in the
third quarter of 2016; and higher water flows at Curtis
Palmer. These positive factors were partially offset by a
$2.2 million increase in cash
interest payments that was timing-related.
Significant uses of the $52.9
million of cash provided by operating activities included
$25.0 million of term loan
amortization, $4.4 million of project
debt amortization and $2.2 million of
preferred dividend payments. The Company also used
$1.5 million of cash for capital
expenditures and $3.1 million for the
repurchase of preferred shares.
Nine Months Ended September 30,
2017
Net loss attributable to Atlantic Power
Corporation for the nine months ended September 30, 2017 was $(57.5) million as compared to $(116.2) million in the nine months ended
September 30, 2016. The
$58.7 million reduction in loss was
the result of several positive factors, including increased
revenues of $25.2 million (primarily
the result of the OEFC Settlement, increased water flows at Curtis
Palmer, and higher steam revenues at the San Diego plants, partially offset by lower
revenues under the enhanced dispatch contracts), lower fuel and
operations and maintenance expenses totaling $47.7 million (primarily the result of the
enhanced dispatch contracts and expiration of an above-market gas
supply contract in Ontario, and
the non-recurrence of the extended planned outage at Morris in
August 2016), a $27.4 million reduction in impairment expense for
the Company's consolidated projects (the year-ago period included
$84.7 million of impairment expense
associated with the Company's Mamquam, Curtis Palmer, North Bay and Kapuskasing plants), and a $38.7 million reduction in corporate and project
interest expense (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 partially offset by a $64.0
million reduction in earnings from unconsolidated affiliates
(primarily because of a $57.7 million
impairment recorded at Chambers and Selkirk in the second quarter of 2017), a
$25.8 million negative change in the
fair value of derivative instruments (non-cash), and $14.9 million of increased depreciation expense,
primarily at Kapuskasing and North
Bay.
Project loss for the nine months ended
September 30, 2017 increased to
$(7.7) million from $(3.3) million in the year-ago period. The
$4.4 million increase in loss was
primarily attributable to the reduction in earnings from
unconsolidated affiliates, the negative change in fair value of
derivative instruments, and increased depreciation expense,
partially offset by increased revenues, lower fuel and operations
and maintenance expense, and lower impairment expense for
consolidated projects, as discussed previously.
Project Adjusted EBITDA for the nine months ended
September 30, 2017 was $226.6 million, an increase of $66.7 million from $159.9
million in the year-ago period. Primary drivers were
the OEFC Settlement ($25.6 million),
the favorable impact on margins of the enhanced dispatch contracts
and the expiration of an above-market gas contract in Ontario (totaling $27.3
million), increased water flows at Curtis Palmer
($10.0 million), and more modest
increases at Orlando ($2.8 million, due to the settlement of favorable
fuel swaps), Morris ($2.4 million,
mostly due to the outage in the year-ago period), and Piedmont ($2.1
million, partly due to maintenance in the year-ago period).
These positive factors were partially offset by decreases at
Mamquam (-$2.5 million, due to lower
water flows in the first six months of 2017 compared to a record
year in 2016, and a forced outage in the second quarter of 2017),
Frederickson (-$2.2 million, due to
higher planned maintenance expense in the second quarter of 2017),
and Calstock (-$2.1 million, due to lower waste heat and higher
fuel prices).
During the first nine months of 2017, the Canadian dollar
appreciated slightly relative to the year-ago period. This
had a non-cash translation benefit to Project Adjusted EBITDA of
approximately $1.7
million.
Cash provided by operating activities for the nine
months ended September 30, 2017 of
$137.9 million increased $46.0 million from $91.9
million a year ago. The 2017 period included
approximately $25.6 million of cash
collected under the OEFC settlement, most of which occurred in the
second 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, lower
operation and maintenance expense, and improved hydrology at Curtis
Palmer. These positive factors were partially offset by
decreases at Mamquam, Frederickson and Calstock, for reasons previously
discussed. In addition, cash provided by operating activities
was reduced $25.0 million from the
year-ago period due to changes in working capital, primarily due to
the timing of revenue receipts at Oxnard and Morris ($11.7 million) and inventory buildup for 2018 and
2019 planned outages ($3.3
million).
Significant uses of the $137.9
million of cash provided by operating activities during the
nine months ended September 30, 2017
included $77.1 million of term loan
amortization, $9.1 million of project
debt amortization and $6.5 million of
preferred dividend payments. The Company also used
$5.7 million of cash for capital
expenditures, primarily for the upgrade of the third and final
combustion turbine at Morris in the second quarter of 2017, and
$3.1 million of cash for the
repurchase of preferred shares in the third quarter of 2017.
Liquidity and Balance Sheet
Liquidity
As shown in Table 2, the Company's liquidity at September 30, 2017 was $249.8 million, an increase of $22.6 million from the June 30, 2017 level. The increase was
attributable to an $18.0 million
increase in unrestricted cash, which resulted from increased cash
provided by operating activities, and a $4.6
million increase in revolver availability, due to a
reduction in letters of credit outstanding.
On October 12, 2017, the Company
used $59.6 million of cash at the
parent and $4.5 million of previously
restricted cash at the project to repay the remaining project debt
at Piedmont, totaling $54.6 million, and to pay $0.1 million of accrued interest and $9.4 million of interest rate swap termination
costs. The Company also posted a corporate letter of credit
at the project in the amount of $11.7
million. Pro forma for this development, liquidity at
September 30, 2017, would be
$178.5 million, as shown in Table
2.
The pro forma unrestricted cash of $62.8
million includes $40.5 million
at the parent, of which the Company considers slightly more than
$30 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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Pro Forma
Sep 30, 2017
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Piedmont (Oct 2017) (1)
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Sep 30,
2017
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June 30,
2017
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Cash and cash
equivalents, parent
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$40.5
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($59.6)
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$100.1
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$78.6
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Cash and cash
equivalents, projects
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22.3
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22.3
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25.8
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Total cash
and cash equivalents
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62.8
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122.4
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104.4
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Revolving credit
facility
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200.0
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200.0
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200.0
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Letters of credit
outstanding
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(84.3)
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(11.7)
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(72.6)
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(77.2)
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Availability under revolving credit facility
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115.7
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127.4
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122.8
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Total
liquidity
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$178.5
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$249.8
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$227.2
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Excludes restricted
cash of:
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8.0
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(4.5)
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12.5
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14.1
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(1) Uses
of liquidity were $54.6 million to repay Piedmont debt, $9.5
million for accrued interest and swap termination costs and $11.7
million for a project-level letter of credit.
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Balance Sheet
Debt Repayment
During the third quarter of 2017, the Company repaid
$25.0 million of the APLP Holdings
term loan and amortized $4.4 million
of project-level debt. For the first nine months of 2017, the
Company repaid a total of $77.1
million of the term loan and amortized $9.1 million of project-level debt. At
September 30, 2017, the Company's
consolidated debt was $927 million,
excluding unamortized discounts and deferred financing costs, and
the Company's consolidated leverage ratio (consolidated gross debt
to trailing 12-month consolidated Adjusted EBITDA) was 3.8
times. The improvement in the leverage ratio from 4.4 times
at June 30, 2017 was primarily
attributable to the positive impacts on EBITDA of the OEFC
Settlement payments (most of which were recorded in the second
quarter) and the enhanced dispatch contracts (for the past three
quarters) combined with the continued reduction in debt.
In October 2017, as previously
discussed, the Company repaid $54.6
million of remaining project debt at Piedmont, which had been scheduled to mature
in August 2018. Pro forma for this repayment, consolidated
debt at September 30, 2017 would be
$872 million and the consolidated
leverage ratio would be 3.6 times. Annual interest savings
associated with repayment of the 8.2% Piedmont project debt are approximately
$4.5 million.
For the full year 2017, the Company expects debt repayment to
total $166 million, including
approximately $100 million of the
APLP Holdings term loan, $11.4
million of project-level debt and $54.6 million of Piedmont debt.
Debt Maturity Profile
The Company has no bullet maturities in 2017 or 2018. The
remaining $42.5 million of Series C
convertible debentures mature in June
2019 and became callable at par in June 2017. The
$64.9 million (U.S. dollar
equivalent) of Series D convertible debentures mature in
December 2019 and are callable at par
in December 2017. In October
2017, the Company extended the maturity date of its
$200 million revolving credit
facility by one year, to April 2022. The $563 million APLP Holdings term loan has an
April 2023 maturity, although it is
expected to be more than 80% repaid by the maturity date.
Repricing of Term Loan and Revolver
As reported in the Company's October 19,
2017 press release, the Company executed a repricing of the
$563 million APLP Holdings term loan
and $200 million revolving credit
facility, reducing the interest rate margin on the term loan and
revolver by 75 basis points, to LIBOR plus 350 basis points.
This repricing is the second for these facilities; since the
original financing in April 2016, the
spread has been reduced a total of 150 basis points, from LIBOR
plus 500 basis points to LIBOR plus 350. As a result of the
October 2017 repricing, the Company
expects to realize interest cost savings in 2018 of approximately
$4 million compared to the cost based
on the previous spread. Cumulative savings through the
maturity dates of the term loan (April
2023) and revolver (April
2022) are estimated to be approximately $15 million. The combined savings of both
repricing transactions is expected to be approximately $33 million over the terms of the
facilities. Transaction costs associated with the repricing
will be included in interest expense in the fourth 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. In the
third quarter of 2017, the Company repurchased and canceled 93,391
common shares at an average price of $2.36 per share. The Company also
repurchased and canceled a total of 250,000 shares of the 4.85%
Cumulative Redeemable Preferred (Series I issue) at Cdn$15.5 per share for a total payment of
Cdn$3.9 million. The Company
also repurchased a nominal amount of convertible debentures in the
third quarter of 2017.
Credit Rating Upgrade
In early October, Moody's upgraded the Company's corporate
family credit rating to Ba3 from B1 and upgraded the credit rating
for the term loan and revolving credit facility to Ba2 from
Ba3. Moody's cited the Company's continuing efforts to
improve its credit profile through cost cutting and debt
reduction.
Increasing 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 increased its previous 2017 guidance for Project
Adjusted EBITDA of $250 to
$265 million by $10 million to a range of $260 to $275 million. The primary reasons
for the increase are higher water flows at Curtis Palmer and lower
costs at the non-operational plants in Ontario in the year to date, and the
expectation that certain repowering expenditures previously planned
for the fourth quarter of 2017 will not occur or will be deferred
into 2018.
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
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Table 3 – Bridge
of 2017 Project Adjusted EBITDA Guidance to Cash Provided by
Operating Activities
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(in millions of
U.S. dollars)
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Unaudited
|
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Current 11/9/17
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Previous 5/4/17
|
2017 Project
Adjusted EBITDA Guidance
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$260 -
$275
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$250 -
$265
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Adjustment for equity
method projects(1)
|
1
|
(1)
|
Corporate G&A
expense
|
(22)
|
(22)
|
Cash interest
payments(2)
|
(73)
|
(67)
|
Cash taxes
|
(4)
|
(4)
|
Other
|
-
|
-
|
Cash provided by
operating activities
|
$160 -
$175
|
$155 -
$170
|
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.
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(1) For
equity method projects, represents difference between Project
Adjusted EBITDA and cash distribution from equity method
projects.
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(2)
Increase relative to 5/4/17 guidance reflects interest rate swap
termination cost ($9) related to Piedmont debt repayment, partially
offset by term loan repricing savings.
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Other Financial Updates
Update on Near-Term PPA Expirations
As previously disclosed, the Company has seven plants with PPAs
(or lease agreements, in the case of the San Diego plants) that are scheduled to expire
within the next 12 months.
Kapuskasing and North Bay (Ontario). The Company does not
expect to extend or renew the enhanced dispatch contracts for these
two plants, which will expire on December
31, 2017.
Naval Station, NTC and North Island (San Diego). The three plants sell
power to SDG&E under PPAs that are scheduled to expire on
December 1, 2019. The plants
are located on Naval bases in San
Diego, and the agreements with the Navy that provide the
Company the right to use the sites are scheduled to expire on
February 8, 2018. The Company
executed new seven-year contracts with SDG&E for Naval Station
and North Island in August 2017. However, the contracts are
conditioned on the Company's ability to remain on the sites beyond
February 2018. The contracts are also subject to the approval
of the California Public Utilities Commission. In late August
the Company learned that it was not selected in the Navy's
solicitation for energy security and resiliency proposals at these
bases, which had been the clearest path to obtaining site
control. Although the Company is pursuing alternative paths
to site control, if it is not successful, the plants may cease
operations as early as February 2018.
Williams Lake (British Columbia). The PPA with BC
Hydro is scheduled to expire on April
1, 2018. The Company is negotiating a short-term
extension of the PPA with the utility customer, with a goal of
bridging the period to the outcome of the utility's integrated
resource plan (IRP) in 2019. Additional capital investment in
the plant would be deferred during the short-term extension.
Kenilworth (New Jersey). The PPA with Merck is
scheduled to expire on September 30,
2018. The Company is exploring both short- and long-term
extensions with Merck.
2017 Maintenance and Capex
For 2017, including its share of equity-owned projects, the
Company expects to incur maintenance expenses of approximately
$34.3 million, of which $23.6 million was incurred in the first nine
months of 2017. This is lower than the $41.2 million previously forecast because certain
repowering expenditures originally planned for the fourth quarter
of 2017 will not occur or will be deferred into 2018. The
Company's estimate of capital expenditures for 2017 is
approximately $5.4 million, unchanged
from the previous forecast. The majority ($4.9 million) was incurred in the first nine
months of 2017, most of it related to the upgrade of the third and
final combustion turbine at Morris, which was completed in the
second quarter of 2017.
Tunis Planned Restart
The Company has received the required environmental permit and
expects to begin work on returning Tunis to service as a simple-cycle plant with
a targeted commercial operation date of mid-2018. Most of the
estimated $6.5 million cost will be
incurred in 2018 and will be expensed. The plant has a
15-year PPA that will commence with commercial
operation.
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 14 of this release.
Investor Conference Call and Webcast
Atlantic Power's management team will host a telephone
conference call on Friday, November 10,
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, November
10, 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
10112968 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 December 10, 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 PPA that will commence with the
commercial operation of the plant before 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 estimates of annual interest cost savings
associated with the repayment of Piedmont debt and the repricing of its term
loan and revolver;
- the Company's expectation that it will repay approximately
$166 million of debt in 2017;
- the Company's expectation to allocate available cash to growth
initiatives, security repurchases and discretionary debt
repayment;
- the Company's expectation that it will have fully depreciated
the Kapuskasing and North Bay plants by year-end 2017;
- the Company's expectation that it will receive another
approximately Cdn$3.8 million of
revenues under the OEFC settlement in the fourth quarter of
2017;
- the Company's estimate of discretionary cash, pro forma for the
repayment of Piedmont debt in
October 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 $260 to $275
million;
- the Company's estimation that 2017 cash flows provided by
operating activities will be in the range of $160 to $175 million, assuming for this purpose
that working capital changes are nil;
- the Company's expectation with respect to progress on PPAs
expiring in 2018;
- the Company's expectation that the Naval Station, NTC, and
North Island plants may cease operations as early as February 2018 if the Company is unsuccessful in
obtaining site control;
- the Company's expectation that capital investment in the
Williams Lake plant would be
deferred should the Company agree to a short-term PPA extension
with BC Hydro;
- the Company's expectation that in 2017, including its share of
equity-owned projects, maintenance expense will total approximately
$34.3 million and capital
expenditures will total approximately $5.4
million;
- the Company's expectations with respect to the estimated cost
and timing of a planned restart of its Tunis plant; 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.
Atlantic Power
Corporation
Table 4 –
Consolidated Balance Sheet (in millions of U.S.
dollars)
|
|
Unaudited
|
|
|
|
September
30,
|
December
31,
|
|
2017
|
2016
|
Assets
|
|
|
Current
assets:
|
|
|
Cash and
cash equivalents
|
$122.4
|
$85.6
|
Restricted cash
|
12.5
|
13.3
|
Accounts
receivable
|
48.8
|
37.3
|
Current
portion of derivative instruments asset
|
2.5
|
4.0
|
Inventory
|
20.3
|
16.0
|
Prepayments
|
6.7
|
5.9
|
Income
taxes receivable
|
0.5
|
-
|
Other
current assets
|
3.9
|
2.8
|
Total current
assets
|
217.6
|
164.9
|
|
|
|
Property, plant and
equipment, net
|
652.6
|
733.2
|
Equity investments in
unconsolidated affiliates
|
199.8
|
266.8
|
Power purchase
agreements and intangible assets, net
|
201.6
|
246.2
|
Goodwill
|
36.0
|
36.0
|
Derivative
instruments asset
|
2.6
|
4.6
|
Other
assets
|
3.7
|
5.1
|
Total
assets
|
$1,313.9
|
$1,456.8
|
|
|
|
Liabilities
|
|
|
Current
liabilities:
|
|
|
Accounts
payable
|
$3.2
|
$4.5
|
Accrued
interest
|
4.5
|
0.7
|
Other
accrued liabilities
|
23.0
|
24.4
|
Current
portion of long-term debt
|
156.5
|
111.9
|
Current
portion of derivative instruments liability
|
13.5
|
7.6
|
Other
current liabilities
|
2.6
|
1.8
|
Total current
liabilities
|
203.3
|
150.9
|
|
|
|
Long-term debt, net
of unamortized discount and deferred financing costs
|
637.3
|
749.2
|
Convertible
debentures, net of unamortized deferred financing costs
|
105.5
|
100.4
|
Derivative
instruments liability
|
19.5
|
21.3
|
Deferred income
taxes
|
26.5
|
68.3
|
Power purchase and
fuel supply agreement liabilities, net
|
24.7
|
25.3
|
Asset retirement
obligations
|
52.7
|
50.2
|
Other long-term
liabilities
|
4.5
|
5.3
|
Total
liabilities
|
$1,074.0
|
$1,170.9
|
|
|
|
Equity
|
|
|
Common shares, no par
value, unlimited authorized shares; 115,211,976 and 114,649,888
issued and outstanding at September 30, 2017 and December 31, 2016,
respectively
|
1,274.3
|
1,272.9
|
Accumulated other
comprehensive loss
|
(132.3)
|
(148.5)
|
Retained
deficit
|
(1,117.3)
|
(1,059.8)
|
Total Atlantic Power
Corporation shareholders' equity
|
24.7
|
64.6
|
Preferred shares
issued by a subsidiary company
|
215.2
|
221.3
|
Total
equity
|
239.9
|
285.9
|
Total liabilities and
equity
|
$1,313.9
|
$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
September 30,
|
Nine months
ended September
30,
|
|
|
2017
|
2016
|
|
2017
|
2016
|
Project
revenue:
|
|
|
|
|
|
|
Energy
sales
|
|
$36.5
|
$40.7
|
|
$113.6
|
$138.4
|
Energy
capacity revenue
|
|
37.9
|
44.0
|
|
85.7
|
113.2
|
Other
|
|
34.2
|
16.5
|
|
131.7
|
54.2
|
|
|
108.6
|
101.2
|
|
331.0
|
305.8
|
Project
expenses:
|
|
|
|
|
|
|
Fuel
|
|
26.2
|
36.8
|
|
79.1
|
110.8
|
Operations and maintenance
|
|
19.8
|
28.2
|
|
63.4
|
79.4
|
Depreciation and amortization
|
|
31.4
|
25.3
|
|
90.5
|
75.6
|
|
|
77.4
|
90.3
|
|
233.0
|
265.8
|
Project other
income:
|
|
|
|
|
|
|
Change
in fair value of derivative instruments
|
|
(1.9)
|
9.0
|
|
(5.8)
|
20.0
|
Equity
in earnings (loss) of unconsolidated affiliates
|
|
9.2
|
9.6
|
|
(36.1)
|
27.9
|
Interest
expense, net
|
|
(2.2)
|
(2.4)
|
|
(6.6)
|
(6.9)
|
Impairment
|
|
(57.3)
|
(84.7)
|
|
(57.3)
|
(84.7)
|
Other
income, net
|
|
0.1
|
0.5
|
|
0.1
|
0.4
|
|
|
(52.1)
|
(68.0)
|
|
(105.7)
|
(43.3)
|
Project
loss
|
|
(20.9)
|
(57.1)
|
|
(7.7)
|
(3.3)
|
|
|
|
|
|
|
|
Administrative and
other expenses:
|
|
|
|
|
|
|
Administration
|
|
5.5
|
5.7
|
|
17.6
|
17.6
|
Interest
expense, net
|
|
13.8
|
20.0
|
|
49.5
|
87.9
|
Foreign
exchange loss (gain)
|
|
9.4
|
(3.4)
|
|
17.7
|
19.1
|
Other
income, net
|
|
-
|
(1.7)
|
|
-
|
(3.9)
|
|
|
28.7
|
20.6
|
|
84.8
|
120.7
|
Loss from operations
before income taxes
|
|
(49.6)
|
(77.7)
|
|
(92.5)
|
(124.0)
|
Income tax (benefit)
expense
|
|
(15.9)
|
2.6
|
|
(38.5)
|
(14.2)
|
Net loss
|
|
(33.7)
|
(80.3)
|
|
(54.0)
|
(109.8)
|
Net (loss) income
attributable to preferred share dividends of a subsidiary
company
|
|
(0.8)
|
2.1
|
|
3.5
|
6.4
|
Net loss attributable
to Atlantic Power Corporation
|
|
($32.9)
|
($82.4)
|
|
($57.5)
|
($116.2)
|
Net loss per share
attributable to Atlantic Power Corporation shareholders:
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
($0.29)
|
($0.69)
|
|
($0.50)
|
($0.96)
|
Diluted
|
|
(0.29)
|
(0.69)
|
|
($0.50)
|
($0.96)
|
Weighted average
number of common shares outstanding:
|
|
|
|
|
|
|
Basic
|
|
115.3
|
119.3
|
|
115.1
|
120.9
|
Diluted
|
|
115.3
|
119.3
|
|
115.1
|
120.9
|
Atlantic Power
Corporation
|
Table 6 –
Consolidated Statements of Cash Flows (in millions of U.S.
dollars)
|
Unaudited
|
|
|
|
|
Nine months ended
September 30,
|
|
|
|
2017
|
2016
|
Cash provided by
operating activities:
|
|
|
|
|
Net loss
|
|
|
($54.0)
|
($109.8)
|
Adjustments to
reconcile net loss to net cash provided by operating
activities:
|
|
|
|
|
Depreciation and
amortization
|
|
|
90.5
|
75.6
|
Gain on purchase and
cancellation of convertible debentures
|
|
|
-
|
(4.7)
|
Loss on disposal of
fixed assets
|
|
|
0.1
|
0.2
|
Stock-based
compensation
|
|
|
1.6
|
1.4
|
Long-lived asset and
goodwill impairment
|
|
|
57.3
|
84.7
|
Equity in loss
(earnings) from unconsolidated affiliates
|
|
|
36.1
|
(27.9)
|
Distributions from
unconsolidated affiliates
|
|
|
30.9
|
36.5
|
Unrealized foreign
exchange loss
|
|
|
17.0
|
19.1
|
Change in fair value
of derivative instruments
|
|
|
5.8
|
(20.0)
|
Amortization of debt
discount and deferred financing costs
|
|
|
7.8
|
41.7
|
Change in deferred
income taxes
|
|
|
(42.1)
|
(16.8)
|
Change in other
operating balances
|
|
|
|
|
Accounts
receivable
|
|
|
(11.5)
|
-
|
Inventory
|
|
|
(4.2)
|
1.1
|
Prepayments and other
assets
|
|
|
0.6
|
0.3
|
Accounts
payable
|
|
|
0.3
|
0.4
|
Accruals and other
liabilities
|
|
|
1.7
|
10.1
|
Cash provided by
operating activities
|
|
|
137.9
|
91.9
|
|
|
|
|
|
Cash (used in)
provided by investing activities:
|
|
|
|
|
Change in restricted
cash
|
|
|
0.8
|
2.6
|
Reimbursement of costs
for third-party construction project
|
|
|
-
|
4.7
|
Purchase of property,
plant and equipment
|
|
|
(5.7)
|
(6.5)
|
Cash (used in)
provided by investing activities
|
|
|
(4.9)
|
0.8
|
|
|
|
|
|
Cash (used in)
provided by financing activities:
|
|
|
|
|
Proceeds from term loan facility, net of discount
|
|
|
-
|
679.0
|
Common share
repurchases
|
|
|
(0.2)
|
(13.9)
|
Preferred share
repurchases
|
|
|
(3.1)
|
-
|
Repayment of corporate
and project-level debt
|
|
|
(86.3)
|
(526.4)
|
Repayment of
convertible debentures
|
|
|
(0.1)
|
(187.4)
|
Deferred financing
costs
|
|
|
-
|
(16.2)
|
Dividends paid to
preferred shareholders
|
|
|
(6.5)
|
(6.4)
|
Cash (used in)
provided by financing activities
|
|
|
(96.2)
|
(71.3)
|
|
|
|
|
|
Net increase in cash
and cash equivalents
|
|
|
36.8
|
21.4
|
Cash and cash
equivalents at beginning of period
|
|
|
85.6
|
72.4
|
Cash and cash
equivalents at end of period
|
|
|
$122.4
|
$93.8
|
|
|
|
|
|
Supplemental cash
flow information
|
|
|
|
|
Interest
paid
|
|
|
$44.2
|
$43.3
|
Income taxes paid,
net
|
|
|
$3.4
|
$2.8
|
Accruals for
construction in progress
|
|
|
$-
|
0.4
|
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 third quarter
2017 presentation on the Company's website.
Project income (loss) and Project Adjusted EBITDA by project
also can be found in the third 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)
|
|
Unaudited
|
|
|
|
|
|
|
|
Three months
ended
September 30,
|
|
Nine months
ended
September 30,
|
|
2017
|
2016
|
|
2017
|
2016
|
Net loss
attributable to Atlantic Power Corporation
|
($32.9)
|
($82.4)
|
|
($57.5)
|
($116.2)
|
Net income
attributable to preferred share dividends of a subsidiary
company
|
(0.8)
|
2.1
|
|
3.5
|
6.4
|
Net loss from
operations
|
($33.7)
|
($80.3)
|
|
($54.0)
|
($109.8)
|
Income tax (benefit)
expense
|
(15.9)
|
2.6
|
|
(38.5)
|
(14.2)
|
Loss from operations
before income taxes
|
(49.6)
|
(77.7)
|
|
(92.5)
|
(124.0)
|
Administration
|
5.5
|
5.7
|
|
17.6
|
17.6
|
Interest expense,
net
|
13.8
|
20.0
|
|
49.5
|
87.9
|
Foreign exchange loss
(gain)
|
9.4
|
(3.4)
|
|
17.7
|
19.1
|
Other income,
net
|
-
|
(1.7)
|
|
-
|
(3.9)
|
Project
loss
|
($20.9)
|
($57.1)
|
|
($7.7)
|
($3.3)
|
|
|
|
|
|
|
Reconciliation to
Project Adjusted EBITDA
|
|
|
|
|
|
Depreciation and
amortization
|
$36.6
|
$30.4
|
|
$105.6
|
$90.8
|
Interest expense,
net
|
2.5
|
$2.8
|
|
8.0
|
$8.2
|
Change in the fair
value of derivative instruments
|
2.0
|
($9.0)
|
|
5.8
|
($20.1)
|
Other (income)
expense
|
(0.1)
|
($0.5)
|
|
57.6
|
($0.4)
|
Impairment
|
57.3
|
84.7
|
|
57.3
|
84.7
|
Project Adjusted
EBITDA
|
$77.4
|
$51.3
|
|
$226.6
|
$159.9
|
View original
content:http://www.prnewswire.com/news-releases/atlantic-power-corporation-releases-third-quarter-2017-results-300553433.html
SOURCE Atlantic Power Corporation