DEDHAM, Mass., March 1, 2018 /PRNewswire/ --
Fourth Quarter and Full Year 2017 Highlights
- Cash provided by operating activities of $31.3 million in Q4 2017 vs. $20.4 million in Q4 2016
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- $169.2 million for the full year
2017 vs. $112.3 million in 2016, up
$56.9 million
- Net loss attributable to Atlantic Power of $(41.1) million in Q4 2017 vs. $(6.6) million in Q4 2016
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- $(98.6) million for the full year
2017 vs. $(122.4) million in 2016, a
$23.8 million improvement
- Project Adjusted EBITDA of $62.2
million in Q4 2017 vs. $42.3
million in Q4 2016
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- $288.8 million for the full year
2017 vs. $202.2 million in 2016, an
increase of $86.6 million; Company's
2017 guidance was a range of $260 to
$275 million
- Repaid $79.6 million of term loan
and project debt in Q4 2017 and $165.9
million for the full year
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- Leverage ratio at year end 2017 was 3.3 times, down from 5.6
times at year end 2016
- Liquidity at December 31, 2017 of
$198.2 million, including
approximately $40 million of
discretionary cash
- In October, executed second repricing of term loan and revolver
and a one-year extension of the maturity date of the revolver to
April 2022
- Also in October, Moody's upgraded the Company's corporate
family credit rating to Ba3 from B1
Recent Developments
- In December, executed amendment and short-term extension of
Williams Lake energy purchase
agreement, subject to regulatory approval
- In December, executed long-term enhanced dispatch contract for
Nipigon for November 2018 through December 2022; replaces Power Purchase Agreement
(PPA)
- In January, issued Cdn$115.0
million Series E convertible unsecured subordinated
debenture with a 6.00% interest rate and a January 2025 maturity; using net proceeds of
Cdn$109.1 million to:
-
- Redeem US$42.5 million Series C
convertible debenture, effective March 5,
2018
- Redeem Cdn$56.2 million of Series
D convertible debenture, effective March 7,
2018; Cdn$24.7 million will
remain outstanding
- Operations at the Company's three San
Diego projects ceased on February 7,
2018; continuing to pursue site control with the U.S. Navy
while also beginning decommissioning preparations
2018 Guidance and Outlook
- Initiated 2018 Project Adjusted EBITDA guidance (see pages 7-8
of this release)
- Expect to repay another $100
million of debt in 2018
Atlantic Power Corporation (NYSE: AT) (TSX: ATP) ("Atlantic
Power" or the "Company") today reported its financial results for
the three months and year ended December 31,
2017. Net loss attributable to Atlantic Power
Corporation of $(41.1) million for
the fourth quarter of 2017 increased from $(6.6) million in the year-ago period, primarily
because of increased non-cash impairment expense and interest rate
swap termination costs, partially offset by higher gross margins at
Kapuskasing and North Bay (as discussed on page 2), higher
water flows at Curtis Palmer, and revenues related to the OEFC
Settlement (as discussed on page 3). Project Adjusted EBITDA,
which does not include impairment expense or interest expense,
increased to $62.2 million from
$42.3 million in the fourth quarter
of 2016, primarily due to increases at Kapuskasing, North
Bay, Curtis Palmer and several other projects. Cash
provided by operating activities increased to $31.3 million from $20.4
million in the fourth quarter of 2016.
"Our 2017 results for Project Adjusted EBITDA and Operating Cash
Flow exceeded our guidance and expectations, mostly due to
continued strong water flows at Curtis Palmer and the cost savings
we have been able to achieve in Ontario," said James
J. Moore, Jr., President and CEO of Atlantic Power.
"We ended the fourth quarter with liquidity of $198 million, including approximately
$40 million of discretionary cash,
after paying off $54.6 million of
Piedmont debt in October, ten
months ahead of its maturity. For the full year, we reduced
debt by approximately $166 million
and ended the year with substantially lower leverage than a few
years ago. During the fourth quarter, as we previously
reported, we executed a second successful repricing of our term
loan and revolving credit facility, and we executed an agreement to
extend the maturity date of our corporate revolver by one year to
April 2022. In January, we issued a new seven-year
convertible debenture that allows us to redeem the majority of our
existing 2019 convertible debt maturities."
Mr. Moore continued, "Heading into 2018, we have lower debt
levels, an improved debt maturity profile, a higher credit rating
and stable liquidity. We intend to pay down another
$100 million of debt this year.
We will continue to take a rational approach to capital allocation,
remaining committed to our delevering goals while allocating
available cash to growth, security repurchases when they are at a
compelling price to value, 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
December 31,
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Twelve months
ended
December 31,
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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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$100.0
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$93.4
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$431.0
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$399.2
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Project (loss)
income
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(39.7)
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13.3
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(47.4)
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10.1
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Net loss attributable
to Atlantic Power Corporation
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(41.1)
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(6.6)
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(98.6)
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(122.4)
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Cash provided by
operating activities
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31.3
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20.4
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169.2
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112.3
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Project Adjusted
EBITDA
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62.2
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42.3
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288.8
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202.2
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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 15 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 fourth quarter and full year 2017 were
significantly affected by changes to the operational and
contractual status of the Kapuskasing, North
Bay and Nipigon projects 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 several of its projects in the second,
third and fourth quarters of the year, 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 projects have been under enhanced
dispatch contracts that provide fixed monthly payments but do not
require the projects 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 projects
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 $2.8 million and $19.4
million lower in the three months and year ended
December 31, 2017, respectively, than
in the comparable year-ago periods, but this decrease was more than
offset by lower fuel and operations and maintenance expenses.
In 2017, the Company accelerated depreciation at Kapuskasing and North Bay property, plant and equipment in
order to fully depreciate both projects by year end 2017, the
expiration date of the enhanced dispatch contracts. The
increased depreciation was $5.2
million and $27.4 million for
the three months and year ended December 31,
2017, respectively. However, this increased
depreciation expense was mostly offset by lower amortization
expense of $26.3 million, primarily
because the Company had accelerated amortization of the intangible
assets (PPAs) for both projects in the fourth quarter of
2016.
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 PPAs for the Kapuskasing, North
Bay and Tunis
projects. A subsequent adjustment increased this amount to
approximately Cdn$37.8 million.
In the fourth quarter of 2017, the Company recorded Cdn$3.8 million of revenue related to the OEFC
settlement. The benefit to Project Adjusted EBITDA from the
OEFC Settlement was US$28.6 million
for the full year 2017, including $3.0
million recorded in the fourth quarter.
Impairment of Goodwill, Long-Lived Assets and Equity
Investments
In the fourth quarter of 2017, the Company recorded event-driven
impairments of its equity investment in Frederickson and its
Williams Lake project
(consolidated). Also in the fourth quarter of 2017, the
Company conducted its annual impairment test of goodwill and
long-lived assets. As a result of that test, it recorded an
impairment of goodwill at its Curtis Palmer project.
The Company owns a 50.15% interest in Frederickson, which is a
gas-fired project that operates under three PPAs that expire in
August 2022. As an equity-owned project, it is not reviewed
as part of the Company's annual assessment but only in response to
a triggering event. Although declining power prices have been
observed for several years, in the Company's most recent long-term
forecast completed in December 2017,
it identified a significant decrease in the long-term outlook for
power prices for the region. The Company performed an
analysis of the value of the project on the assumption that it
operates as a merchant facility after the PPAs expire. The
decline in the long-term price forecast had a significant negative
impact on the estimated discounted cash flows of Frederickson
post-PPA, which the Company views as other than temporary.
Accordingly, in the fourth quarter of 2017, the Company recorded a
$28.3 million impairment of the
$108.3 million carrying value of its
investment. The impairment was included in earnings from
unconsolidated affiliates. The Company continues to see value
for the project post-PPA because of planned large coal plant
retirements and strong population growth in the region.
Also in the fourth quarter of 2017, the Company recorded a
$29.1 million impairment of the
$40.0 million carrying value of
long-lived assets at its Williams
Lake project. This was based on an assessment of the
cash flows under the short-term contract extension recently
executed for Williams Lake as well
as a probability-weighted evaluation of expected cash flows under a
long-term extension.
In conducting the annual impairment assessment for its
consolidated projects, the Company determined that there had been a
decline in the long-term power price forecast for its Curtis Palmer
project for the period beyond the expiration of the project's
existing PPA. Accordingly, in the fourth quarter of 2017, the
Company recorded a $14.7 million
impairment of goodwill at Curtis Palmer, which reduced the carrying
value of the project's goodwill to $14.4
million.
As previously reported, in the third quarter of 2017, the
Company recorded a $57.3 million
impairment of long-lived assets at its three San Diego projects, based on the expectation
that they would not continue to operate beyond the expiration of
the agreements with the U.S. Navy that provided the Company with
the right to use the property. On February 7, 2018, the Company ceased operations
at all three projects.
Also as previously reported, in the second quarter of 2017, the
Company recorded a $47.1 million
impairment of its equity investment in Chambers and a $10.6 million full impairment of its equity
investment in Selkirk. In November
2017, the Company sold its 17.7% interest in Selkirk to the majority partner for
$1.0 million. The Company
recorded a $1.0 million gain on sale
in the fourth quarter of 2017, which was included in earnings from
unconsolidated affiliates.
Total impairment expense for 2017 was $187.1 million, including $86.0 million included in earnings from
unconsolidated affiliates. This expense reduced both Project
income and Net income, but did not affect cash provided by
operating activities or Project Adjusted EBITDA.
Three Months Ended December 31,
2017
Net loss attributable to Atlantic Power
Corporation for the fourth quarter of 2017 was $(41.1) million as compared to $(6.6) million in the fourth quarter of
2016. The $34.5 million
increase in net loss was the result of a $70.9 million increase in impairment expense, as
discussed previously, a $9.9 million
adverse change in the fair value of derivative instruments
(non-cash), and $5.1 million of
higher interest expense, primarily attributable to the $9.4 million cost of terminating the interest
rate swap at Piedmont when that
project's debt was redeemed in October 2017. These negative
factors were partially offset by increased gross margin and lower
operation and maintenance expense at Kapuskasing and North Bay, due to the revised contractual and
operational arrangements discussed previously, higher gross margin
at Curtis Palmer due to higher water flows, OEFC Settlement
revenues, lower depreciation and amortization expense, and an
increased tax benefit.
Project loss for the fourth quarter of 2017 was
$(39.7) million as compared to
project income of $13.3 million in
the year-ago period. The $53.0
million reduction from income to loss was primarily
attributable to increased impairment expense, an adverse change in
the fair value of derivatives, and the interest rate swap
termination cost at Piedmont. These negative factors were
partially offset by higher gross margins and lower operating
expenses at Kapuskasing and
North Bay, the final OEFC
Settlement revenues, higher revenues at Curtis Palmer due to higher
water flows, and lower depreciation and amortization
expense.
Project Adjusted EBITDA for the fourth quarter of
2017 was $62.2 million, an increase
of $19.9 million from $42.3 million in the year-ago period. The
primary drivers were the favorable impact on gross margins of the
enhanced dispatch contracts and the expiration of an above-market
gas contract in Ontario (totaling
$13.5 million), OEFC Settlement
revenues ($3.0 million), higher water
flows at Curtis Palmer ($2.6
million), and modest increases at Oxnard, Orlando and other projects. These
positive factors were partially offset by a $2.0 million decrease at Kenilworth, which benefited from a gas
settlement in the prior period, and more modest decreases at
several other projects. During the quarter, the Canadian
dollar depreciated modestly relative to the year-ago period.
This had a non-cash translation benefit to Project Adjusted EBITDA
of approximately $1.3 million.
Cash provided by operating activities for the
fourth quarter of 2017 of $31.3
million increased $10.9
million from $20.4 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, receipt of OEFC Settlement revenues, and
higher water flows at Curtis Palmer.
Significant uses of the $31.3
million of cash provided by operating activities included
$22.7 million of term loan
amortization, $2.4 million of project
debt amortization and $2.2 million of
preferred dividend payments.
Year Ended December 31,
2017
Net loss attributable to Atlantic Power
Corporation for the year ended December 31, 2017 was $(98.6) million as compared to $(122.4) million for the year ended December 31, 2016. The $23.8 million reduction in loss was the result of
several positive factors, including increased revenues of
$31.8 million (primarily the result
of the OEFC Settlement, increased water flows at Curtis Palmer,
higher steam revenues at the San
Diego projects, and higher revenues at Morris, which had an
extended planned outage in 2016, partially offset by lower revenues
under the enhanced dispatch contracts), lower fuel and operations
and maintenance expenses totaling $60.5
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 2016), and a $33.5 million reduction in corporate and project
interest expense (due to a $31.4
million write-off of deferred financing costs in 2016 and
lower debt levels). The Company also had an increased tax
benefit. These positive factors were partially offset by a
$101.2 million increase in impairment
expense, as previously discussed, and a $35.8 million negative change in the fair value
of derivative instruments (non-cash),
Project loss for the year ended December 31, 2017 was $(47.4) million as compared to project income of
$10.1 million in 2016. The
$57.5 million reduction from income
to loss was primarily attributable to the impairment charges
recorded for the Company's consolidated and equity owned projects
and the negative change in the fair value of derivative
instruments, partially offset by increased revenues and lower fuel
and operations and maintenance expense, as discussed
previously.
Project Adjusted EBITDA for the year ended
December 31, 2017 was $288.8 million, an increase of $86.6 million from $202.2
million in the year-ago period. The primary drivers of
the increase were the favorable impact on gross margins of the
enhanced dispatch contracts and the expiration of an above-market
gas contract in Ontario (totaling
$41.6 million), the OEFC Settlement
($28.6 million), increased water
flows at Curtis Palmer ($12.6
million), and more modest increases at Orlando ($4.6
million, due to the settlement of favorable fuel swaps),
Morris ($4.0 million, mostly due to
the extended planned outage in 2016), and several other
projects. These positive factors were partially offset by
decreases at Mamquam (-$3.2 million,
due to lower water flows in the first, second and fourth quarters
of 2017 compared to a record year in 2016, and a forced outage in
the second quarter of 2017), Frederickson (-$2.1 million, due to higher planned maintenance
expense in the second quarter of 2017), and Calstock (-$1.8
million, due to lower waste heat and higher fuel
prices). During 2017, the Canadian dollar depreciated
slightly relative to 2016. This had a non-cash translation
benefit to Project Adjusted EBITDA of approximately $3.0 million.
Cash provided by operating activities for the year
ended December 31, 2017 of
$169.2 million increased $56.9 million from $112.3
million a year ago. The 2017 period included
approximately $26.6 million of cash
collected under the OEFC Settlement, most of which occurred in the
second quarter. (Another $2.0
million recorded in 2017 revenue was collected in early
2018.) 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
higher water flows at Curtis Palmer. These positive factors
were partially offset by decreases at Mamquam, Frederickson and
Kenilworth, for reasons previously
discussed. In addition, cash provided by operating activities
was reduced $24.3 million from the
year-ago period due to changes in working capital, primarily due to
the timing of revenue receipts at Kapuskasing, Nipigon and North
Bay ($10.5 million) and a
decrease in prepaids, supplies and other assets ($3.4 million).
Significant uses of the $169.2
million of cash provided by operating activities during the
year ended December 31, 2017 included
$165.9 million of debt repayment and
$8.7 million of preferred dividend
payments. The Company also used $5.3
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 December 31, 2017 was $198.2 million, a decrease of $51.6 million from the September 30, 2017 level. The decrease
consisted of a $43.7 million decrease
in unrestricted cash and a $7.9
million decrease in revolver availability. The
reduction in liquidity was primarily attributable to the redemption
of Piedmont project debt in full
in October 2017, including accrued
interest and swap termination costs, and the need to post a
project-level letter of credit. Total use of liquidity for
this purpose was $75.8
million.
The Company's unrestricted cash of $78.7
million includes $49.7 million
at the parent, of which the Company considers slightly more than
$40 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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Dec 31,
2017
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Sep 30,
2017
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Cash and cash
equivalents, parent
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$49.7
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$100.1
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Cash and cash
equivalents, projects
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29.0
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22.3
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Total cash
and cash equivalents
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78.7
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122.4
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Revolving credit
facility
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200.0
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200.0
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Letters of credit
outstanding
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(80.5)
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(72.6)
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Availability under revolving credit facility
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119.5
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127.4
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Total
liquidity
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$198.2
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$249.8
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Excludes restricted
cash of:
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6.2
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12.5
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Balance Sheet
Debt Repayment
During the fourth quarter of 2017, the Company repaid
$22.7 million of the APLP Holdings
term loan, repaid $54.6 million of
remaining project debt at Piedmont, and amortized $2.4 million of project-level debt. For the
full year, the Company repaid $100
million of the term loan and repaid or amortized
$66 million of project-level debt,
including Piedmont. At December 31,
2017, the Company's consolidated debt was $846 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 3.3 times. The improvement in the
leverage ratio from 3.8 times at September
30, 2017 was primarily attributable to the positive impacts
on EBITDA of the OEFC Settlement payments and the enhanced dispatch
contracts combined with the continued reduction in debt, including
at Piedmont.
Convertible Debentures
On January 29, 2018, the Company
closed the offering of Cdn$100.0
million of Series E convertible unsecured subordinated
debentures (the "Series E debentures"). On February 2, 2018, the underwriters exercised
their over-allotment option, which resulted in the Company issuing
another Cdn$15.0 million of Series E
debentures. The Series E debentures, which carry a 6.00%
interest rate, have a maturity date of January 31, 2025. The conversion rate on
the Series E debentures is approximately 238.0952 common shares per
Cdn$1,000 principal amount,
representing a conversion price of Cdn$4.20 per common share. Net proceeds
from the offering after expenses totaled Cdn$109.1 million.
The Company used the net proceeds from the Series E offering to
redeem, in full, the outstanding principal amount of US$42.5 million of Series C debentures (which
have a maturity date of June 2019)
and to redeem Cdn$56.2 million, on a
pro rata basis, of the outstanding principal amount of the Series D
debentures (which have a maturity date of December 2019). The
redemptions will occur on March 5 and
March 7, 2018, respectively.
Following the redemptions, the Company will have Cdn$24.7 million of Series D debentures
outstanding.
Debt Maturity Profile
Following the issuance of the Series E debentures, the
redemption of the Series C debentures in full and the partial
redemption of the Series D debentures, the Company will have
no bullet maturities until December
2019, the maturity date of the remaining Cdn$24.7 million of Series D debentures.
The Series D debentures are callable at par at any time prior to
maturity. There are no bullet maturities in 2020 or
2021. In October 2017, the
Company extended the maturity date of its $200 million revolving credit facility by one
year, to April 2022. The $540
million APLP Holdings term loan has an April 2023 maturity, although it is expected to
be more than 80% repaid by the maturity date. As previously
noted, the Company has Cdn$115.0
million of Series E debentures maturing in January
2025.
Repricing of Term Loan and Revolver
As previously reported, in October
2017 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 350 basis points. This represented the second repricing
for these facilities in 2017, resulting in a cumulative reduction
in the spread of 150 basis points. 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
were included in interest expense in the fourth quarter of
2017.
Normal Course Issuer Bid (NCIB) Update
The normal course issuer bid ("NCIB") that the Company had put
in place in December 2016 expired on
December 28, 2017. Amounts
repurchased under this NCIB totaled 93,391 common shares at an
average price of $2.36 per share,
250,000 shares of the 4.85% Cumulative Redeemable Preferred (Series
I issue) at Cdn$15.50 per share for a
total payment of Cdn$3.9 million, and
a nominal amount of convertible debentures (less than Cdn$100,000). There were no purchases under
this NCIB in the fourth quarter of 2017.
On December 29, 2017, the Company
put in place a new NCIB for common shares, preferred shares and
convertible unsecured subordinated debentures. Details of
this program can be found in the Company's December 20, 2017 press release.
2018 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 initiated guidance for 2018 Project Adjusted
EBITDA in the range of $170 to
$185 million. The expected
decrease from the 2017 level of $288.8
million is primarily attributable to the impact of PPA
expirations in 2017 and 2018 and the non-recurrence of revenues
received under the OEFC settlement in 2017. These factors
account for approximately $105
million of the expected decrease, consistent with
disclosures made in the Company's third quarter 2017 financial
results presentation. Other factors contributing to lower
Project Adjusted EBITDA include maintenance expense associated with
a planned gas turbine overhaul at Manchief in the second quarter of
2018 and restart costs for Tunis. The majority of the
Tunis costs are being incurred in
2018 and a substantial majority will be expensed. The
Company's 2018 guidance assumes average water conditions as
compared to favorable conditions in 2017. These negative
factors are expected to be partially offset by increases at several
other projects, including Morris (higher PJM capacity prices) and
Frederickson (maintenance outage in 2017).
Table 3 provides a bridge of the Company's 2018 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.
The impact of lower Project Adjusted EBITDA on cash provided
by operating activities is expected to be mitigated by lower cash
interest payments in 2018 relative to 2017. The expected
$25 million reduction in cash
interest payments is attributable to a full year benefit from the
$166 million of debt repaid in 2017,
a partial year benefit from the expected debt repayment of
$100 million in 2018, the lower
interest rate on the term loan and revolver, and the non-recurrence
of the Piedmont interest rate swap
termination cost.
Atlantic Power
Corporation
Table 3 – Bridge
of 2018 Project Adjusted EBITDA Guidance to Cash Provided by
Operating Activities
(in millions of
U.S. dollars)
Unaudited
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2018
Guidance
(as of
3/1/18)
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2017
Actual
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Project Adjusted
EBITDA
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$170 -
$185
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$288.8
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Adjustment for equity
method projects(1)
|
(2)
|
(6.4)
|
|
Corporate G&A
expense
|
(22)
|
(23.6)
|
|
Cash interest
payments
|
(47)
|
(72.0)
|
|
Cash taxes
|
(4)
|
(4.4)
|
|
Other (including
changes in working capital)
|
-
|
(13.2)
|
|
Cash provided by
operating activities
|
$95 -
$110
|
$169.2
|
|
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) For
equity method projects, represents difference between Project
Adjusted EBITDA and cash distribution from equity method
projects.
|
|
|
|
|
|
|
|
Other Financial Updates
Update on 2017-2018 PPA Expirations
As previously disclosed, the Company has seven projects with
PPAs (or lease agreements, in the case of the San Diego projects) that are scheduled to
expire (or have expired) between year end 2017 and September
2018.
Kapuskasing and North Bay (Ontario). The enhanced dispatch
contracts for both projects expired on December 31, 2017 and were not extended or
renewed. Both projects are in a non-operational status,
though the Company does not plan to decommission either at this
time.
Naval Station, NTC and North Island (San Diego). The projects ceased
operations on February 7, 2018 when
the agreements with the U.S. Navy that provided the Company the
right to use the sites expired. As a result, the projects are
no longer selling power to San Diego Gas & Electric
("SDG&E") under their respective PPAs. Although the
Company remains in communication with the Navy regarding alternate
paths to site control for one or more of the projects, the paths
are challenging and the outcome is uncertain. The Company is
also preparing estimates for the scope and timing of
decommissioning the three sites. On March 1, 2018, the California Public Utilities
Commission ("CPUC") approved the seven-year Power Purchase Tolling
Agreements with SDG&E for Naval Station and North Island
(initially disclosed in the Company's August
1, 2017 press release), Resource Adequacy agreements for all
three projects, and early termination of the existing PPAs.
The CPUC decision is subject to a 30-day appeal period.
However, operation of the projects continues to be subject to the
Company obtaining site control.
Williams Lake (British Columbia). In December 2017, the Company executed an amendment
to and extension of the existing energy purchase agreement with BC
Hydro, which was scheduled to expire on April 1, 2018. The amended contract is
subject to approval of the BC Utilities Commission. The
extension covers the period from April 2,
2018 to June 30, 2019, or
September 30, 2019 at the option of
BC Hydro. The Company will not upgrade the facility or burn
rail ties during the extension period. The purpose of the
extension is to bridge to the outcome of BC Hydro's integrated
resource plan (IRP) in the second or third quarter of 2019, which
will determine the role of biomass in the utility's long-term
energy needs. The outcome of the IRP is expected to have a
major impact on the Company's ability to operate Williams Lake over the longer term.
Kenilworth (New Jersey). The PPA with Merck is
scheduled to expire on September 30,
2018, though there are provisions for a series of short-term
extensions at Merck's option. The Company is exploring short-
and long-term alternatives with Merck.
Nipigon (Ontario). Since January 2017, Nipigon has been under an enhanced dispatch
contract with the Ontario Independent Electricity System Operator
("IESO"). During this time, the PPA for the project, which
has an expiration date of December
2022, has been suspended. In December 2017, the Company entered into a
long-term enhanced dispatch contract with the IESO for Nipigon for the period November 1, 2018 through December 31, 2022. As a result, the PPA
will be terminated effective October
31, 2018. The long-term enhanced dispatch contract
provides for Nipigon to receive
monthly capacity-type payments based on the original PPA, with
adjustment for operational savings that will be shared with the
IESO. In addition, the project will function as a market
participant and earn energy revenues for those periods during which
it operates. In 2018, the Company will accelerate
amortization of the remaining $18.3
million of intangible PPA asset through October 31, 2018.
Tunis Planned Restart
In the fourth quarter of 2017, the Company commenced work on
returning Tunis to service as a
simple-cycle plant with a targeted commercial operation date of the
third quarter of 2018. Most of the estimated $5 to $6 million
cost will be incurred in 2018 and a substantial majority is
expected to be expensed. The project has a 15-year PPA that
will commence with commercial operation. Under the PPA,
Tunis will receive monthly
capacity payments and will earn energy revenues for those periods
during which it operates.
Maintenance and Capex
Including its share of equity-owned projects, the Company
incurred maintenance expenses of $32.6
million and capital expenditures of $5.5 million in 2017. The majority of the
capital expenditures ($4.9 million)
was incurred in the first nine months of 2017 and was related to
the upgrade of the third and final combustion turbine at Morris,
which was completed in the second quarter of 2017.
For 2018, the Company expects to incur maintenance expenses of
approximately $34.8 million and
capital expenditures of approximately $1.4
million. The modest increase in maintenance expense
relative to 2017 is associated with the Tunis restart work and the Manchief gas
turbine outage, partially offset by lower maintenance expense at
Frederickson and other projects.
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 15 of this release.
Investor Conference Call and Webcast
Atlantic Power's management team will host a telephone
conference call on Friday, March 2,
2018 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, March
2, 2018
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
10117040 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 April
2, 2018 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 is an independent power producer that owns power
generation assets in nine states in the
United States and two provinces in Canada. The
generation projects sell electricity and steam to investment-grade
utilities and other creditworthy large customers predominantly
under long‑term PPAs that have expiration dates ranging from 2018
to 2037. The Company seeks to minimize its exposure to
commodity prices through provisions in the contracts, fuel supply
agreements and hedging arrangements. The projects are
diversified by geography, fuel type, technology, dispatch profile
and offtaker (customer). The majority of the projects in
operation are 100% owned and directly operated and maintained by
the Company. The Company has expertise in operating most fuel
types, including gas, hydro, and biomass, and it owns a 40%
interest in one coal project.
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 that it will repay approximately
$100 million of debt in 2018;
- the Company's expectation to allocate available cash to growth
initiatives, security repurchases and discretionary debt
repayment;
- the Company's expectation that it will repay more than 80% of
its term loan by the maturity date in 2023;
- the Company's estimates of annual interest cost savings
associated with the repricing of its term loan and revolver;
- the Company's estimation that 2018 Project Adjusted EBITDA will
be in the range of $170 to
$185 million;
- the Company's estimation that PPA expirations and the
non-recurrence of the OEFC Settlement will reduce 2018 Project
Adjusted EBITDA by approximately $105
million relative to 2017;
- the Company's estimation that decreases to 2018 Project
Adjusted EBITDA will be partially offset by increases at several
projects, including Morris and Frederickson;
- the Company's estimation that 2018 cash flows provided by
operating activities will be in the range of $95 to $110
million, assuming for this purpose that working capital
changes are nil;
- the Company's expectations with respect to progress on PPAs
expiring in 2018;
- the Company's expectation that capital investment in the
Williams Lake project will be
deferred during the extension period;
- the Company's expectations with respect to the estimated cost
and timing of a planned restart of its Tunis project;
- the Company's estimation that in 2018, including its share of
equity-owned projects, maintenance expense will total approximately
$34.8 million and capital
expenditures will total approximately $1.4
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.
Atlantic Power
Corporation
Table 4 –
Consolidated Balance Sheet (in millions of U.S.
dollars)
|
|
|
|
|
|
|
December
31,
|
December
31,
|
|
2017
|
2016
|
Assets
|
|
|
Current
assets:
|
|
|
Cash and
cash equivalents
|
$78.7
|
$85.6
|
Restricted cash
|
6.2
|
13.3
|
Accounts
receivable
|
52.7
|
37.3
|
Current
portion of derivative instruments asset
|
2.7
|
4.0
|
Inventory
|
17.7
|
16.0
|
Prepayments
|
6.9
|
5.9
|
Income
taxes receivable
|
1.0
|
-
|
Other
current assets
|
3.1
|
2.8
|
Total current
assets
|
169.0
|
164.9
|
Property, plant and
equipment, net
|
602.3
|
733.2
|
Equity investments in
unconsolidated affiliates
|
163.7
|
266.8
|
Power purchase
agreements and intangible assets, net
|
191.2
|
246.2
|
Goodwill
|
21.3
|
36.0
|
Derivative
instruments asset
|
2.8
|
4.6
|
Other
assets
|
8.5
|
5.1
|
Total
assets
|
$1,158.8
|
$1,456.8
|
|
|
|
Liabilities
|
|
|
Current
liabilities:
|
|
|
Accounts
payable
|
$2.2
|
$4.5
|
Accrued
interest
|
0.3
|
0.7
|
Other
accrued liabilities
|
25.5
|
24.4
|
Current
portion of long-term debt
|
99.5
|
111.9
|
Current
portion of derivative instruments liability
|
4.4
|
7.6
|
Other
current liabilities
|
1.0
|
1.8
|
Total current
liabilities
|
132.9
|
150.9
|
Long-term debt, net
of unamortized discount and deferred financing costs
|
616.3
|
749.2
|
Convertible
debentures, net of unamortized deferred financing costs
|
105.4
|
100.4
|
Derivative
instruments liability
|
19.9
|
21.3
|
Deferred income
taxes
|
11.7
|
68.3
|
Power purchase and
fuel supply agreement liabilities, net
|
24.1
|
25.3
|
Other long-term
liabilities
|
51.7
|
55.5
|
Total
liabilities
|
$962.0
|
$1,170.9
|
|
|
|
Equity
|
|
|
Common shares, no par
value, unlimited authorized shares; 115,211,976 and 114,649,888
issued and outstanding at December 31, 2017 and December 31, 2016,
respectively
|
1,274.8
|
1,272.9
|
Accumulated other
comprehensive loss
|
(134.8)
|
(148.5)
|
Retained
deficit
|
(1,158.4)
|
(1,059.8)
|
Total Atlantic Power
Corporation shareholders' equity
|
(18.4)
|
64.6
|
Preferred shares
issued by a subsidiary company
|
215.2
|
221.3
|
Total
equity
|
196.8
|
285.9
|
Total liabilities and
equity
|
$1,158.8
|
$1,456.8
|
Atlantic Power
Corporation
|
Table 5 –
Consolidated Statements of Operations
|
(in millions of
U.S. dollars, except per share amounts)
|
Quarterly Results
Unaudited
|
|
|
Three months
ended
December 31,
|
Twelve months
ended
December
31,
|
|
|
2017
|
2016
|
|
2017
|
2016
|
Project
revenue:
|
|
|
|
|
|
|
Energy
sales
|
|
$35.3
|
$45.8
|
|
$148.9
|
$184.2
|
Energy
capacity revenue
|
|
20.1
|
28.7
|
|
105.8
|
141.9
|
Other
|
|
44.6
|
18.9
|
|
176.3
|
73.1
|
|
|
100.0
|
93.4
|
|
431.0
|
399.2
|
Project
expenses:
|
|
|
|
|
|
|
Fuel
|
|
27.2
|
38.7
|
|
106.3
|
149.5
|
Operations and maintenance
|
|
24.4
|
25.8
|
|
87.8
|
105.2
|
Depreciation and amortization
|
|
22.7
|
37.9
|
|
113.1
|
113.5
|
|
|
74.2
|
102.4
|
|
307.2
|
368.2
|
Project other
income:
|
|
|
|
|
|
|
Change
in fair value of derivative instruments
|
|
7.9
|
17.8
|
|
2.1
|
37.9
|
Equity
in (loss) earnings of unconsolidated affiliates
|
|
(18.7)
|
8.0
|
|
(54.8)
|
35.9
|
Interest
expense, net
|
|
(10.8)
|
(2.3)
|
|
(17.5)
|
(9.2)
|
Impairment
|
|
(43.9)
|
(1.2)
|
|
(101.1)
|
(85.9)
|
Other
income, net
|
|
0.1
|
-
|
|
0.1
|
0.4
|
|
|
(65.4)
|
22.3
|
|
(171.2)
|
(20.9)
|
Project (loss)
income
|
|
(39.7)
|
13.3
|
|
(47.4)
|
10.1
|
|
|
|
|
|
|
|
Administrative and
other expenses:
|
|
|
|
|
|
|
Administration
|
|
6.0
|
5.0
|
|
23.6
|
22.6
|
Interest
expense, net
|
|
14.7
|
18.1
|
|
64.2
|
106.0
|
Foreign
exchange (gain) loss
|
|
(1.4)
|
(5.1)
|
|
16.3
|
13.9
|
Other
expense, net
|
|
(0.4)
|
-
|
|
(0.4)
|
(3.9)
|
|
|
18.9
|
18.1
|
|
103.7
|
138.6
|
Loss from operations
before income taxes
|
|
(58.6)
|
(4.8)
|
|
(151.1)
|
(128.5)
|
Income tax
benefit
|
|
(19.7)
|
(0.4)
|
|
(58.1)
|
(14.6)
|
Net loss
|
|
(38.9)
|
(4.4)
|
|
(93.0)
|
(113.9)
|
Net income
attributable to preferred share dividends of a subsidiary
company
|
|
2.2
|
2.2
|
|
5.6
|
8.5
|
Net loss attributable
to Atlantic Power Corporation
|
|
($41.1)
|
($6.6)
|
|
($98.6)
|
($122.4)
|
Net loss per share
attributable to Atlantic Power Corporation:
|
Basic
|
|
($0.36)
|
($0.06)
|
|
($0.86)
|
($1.02)
|
Diluted
|
|
(0.36)
|
(0.06)
|
|
(0.86)
|
(1.02)
|
Weighted average
number of common shares outstanding:
|
|
|
|
|
|
|
Basic
|
|
115.2
|
115.5
|
|
115.1
|
119.5
|
Diluted
|
|
115.2
|
115.5
|
|
115.1
|
119.5
|
Atlantic Power
Corporation
|
Table 6 –
Consolidated Statements of Cash Flows (in millions of U.S.
dollars)
|
|
|
|
|
|
Twelve months
ended December 31,
|
|
|
|
2017
|
2016
|
Cash provided by
operating activities:
|
|
|
|
|
Net loss
|
|
|
($93.0)
|
($113.9)
|
Adjustments to
reconcile net loss to net cash provided by operating
activities:
|
|
|
|
|
Depreciation and
amortization
|
|
|
113.1
|
113.5
|
Loss (gain) on sale of
assets
|
|
|
0.1
|
-
|
Gain on purchase and
cancellation of convertible debentures
|
|
|
-
|
(3.7)
|
Stock-based
compensation
|
|
|
2.1
|
1.8
|
Long-lived asset and
goodwill impairment
|
|
|
101.1
|
85.9
|
Equity in loss
(earnings) from unconsolidated affiliates
|
|
|
54.8
|
(35.9)
|
Distributions from
unconsolidated affiliates
|
|
|
47.3
|
55.3
|
Unrealized foreign
exchange loss
|
|
|
15.2
|
13.8
|
Change in fair value
of derivative instruments
|
|
|
(2.1)
|
(37.9)
|
Amortization of debt
discount and deferred financing costs
|
|
|
10.8
|
44.6
|
Change in deferred
income taxes
|
|
|
(62.2)
|
(17.5)
|
Change in other
operating balances
|
|
|
|
|
Accounts
receivable
|
|
|
(15.4)
|
2.3
|
Inventory
|
|
|
(1.6)
|
0.9
|
Prepayments and other
assets
|
|
|
0.4
|
5.4
|
Accounts
payable
|
|
|
(0.9)
|
(0.2)
|
Accruals and other
liabilities
|
|
|
(0.5)
|
(2.1)
|
Cash provided by
operating activities
|
|
|
169.2
|
112.3
|
|
|
|
|
|
Cash provided by
(used in) investing activities:
|
|
|
|
|
Change in restricted
cash
|
|
|
7.1
|
1.9
|
Proceeds from sale of
assets and equity investments, net
|
|
|
1.0
|
-
|
Reimbursement of costs
for third-party construction project
|
|
|
-
|
4.8
|
Purchase of property,
plant and equipment
|
|
|
(5.3)
|
(7.2)
|
Cash provided by
(used in) investing activities
|
|
|
2.8
|
(0.5)
|
|
|
|
|
|
Cash used in
financing activities:
|
|
|
|
|
Proceeds from term loan facility, net of discount
|
|
|
-
|
679.0
|
Common share
repurchases
|
|
|
(0.2)
|
(19.5)
|
Preferred share
repurchases
|
|
|
(3.1)
|
-
|
Repayment of corporate
and project-level debt
|
|
|
(165.9)
|
(544.4)
|
Repayment of
convertible debentures
|
|
|
-
|
(188.5)
|
Deferred financing
costs
|
|
|
(0.3)
|
(16.2)
|
Cash payments for
vested LTIP units withheld for taxes
|
|
|
(0.7)
|
(0.5)
|
Dividends paid to
preferred shareholders
|
|
|
(8.7)
|
(8.5)
|
Cash used in
financing activities
|
|
|
(178.9)
|
(98.6)
|
|
|
|
|
|
Net (decrease)
increase in cash and cash equivalents
|
|
|
(6.9)
|
13.2
|
Cash and cash
equivalents at beginning of period
|
|
|
85.6
|
72.4
|
Cash and cash
equivalents at end of period
|
|
|
$78.7
|
$85.6
|
|
|
|
|
|
Supplemental cash
flow information
|
|
|
|
|
Interest
paid
|
|
|
$72.0
|
$70.7
|
Income taxes paid,
net
|
|
|
$4.4
|
$3.5
|
Accruals for
construction in progress
|
|
|
$1.2
|
$1.2
|
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 fourth quarter
and year end 2017 presentation on the Company's website.
Project income (loss) and Project Adjusted EBITDA by project
also can be found in the fourth quarter and year end 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
December 31,
|
|
Twelve months
ended
December 31,
|
|
2017
|
2016
|
|
2017
|
2016
|
Net loss
attributable to Atlantic Power Corporation
|
($41.1)
|
($6.6)
|
|
($98.6)
|
($122.4)
|
Net income
attributable to preferred share dividends of a subsidiary
company
|
2.2
|
2.2
|
|
5.6
|
8.5
|
Net
loss
|
($38.9)
|
($4.4)
|
|
($93.0)
|
($113.9)
|
Income tax
benefit
|
(19.7)
|
(0.4)
|
|
(58.1)
|
(14.6)
|
Loss from operations
before income taxes
|
(58.6)
|
(4.8)
|
|
(151.1)
|
(128.5)
|
Administration
|
6.0
|
5.0
|
|
23.6
|
22.6
|
Interest expense,
net
|
14.7
|
18.1
|
|
64.2
|
106.0
|
Foreign exchange
(gain) loss
|
(1.4)
|
(5.1)
|
|
16.3
|
13.9
|
Other income,
net
|
(0.4)
|
-
|
|
(0.4)
|
(3.9)
|
Project (loss)
income
|
($39.7)
|
$13.3
|
|
($47.4)
|
$10.1
|
|
|
|
|
|
|
Reconciliation to
Project Adjusted EBITDA
|
|
|
|
|
|
Depreciation and
amortization
|
$27.6
|
$42.7
|
|
$133.2
|
$133.5
|
Interest expense,
net
|
11.2
|
2.7
|
|
19.2
|
10.9
|
Change in the fair
value of derivative instruments
|
(7.9)
|
(17.8)
|
|
(2.1)
|
(37.9)
|
Other income,
net
|
(58.8)
|
0.1
|
|
(1.2)
|
(0.3)
|
Impairment
|
129.8
|
1.2
|
|
187.1
|
85.9
|
Project Adjusted
EBITDA
|
$62.2
|
$42.3
|
|
$288.8
|
$202.2
|
|
|
|
|
|
|
|
|
|
|
|
View original
content:http://www.prnewswire.com/news-releases/atlantic-power-corporation-releases-fourth-quarter-and-year-end-2017-results-300607160.html
SOURCE Atlantic Power Corporation