DEDHAM, Mass., Nov. 1, 2018 /CNW/ --
Third Quarter 2018 Financial Highlights
- Net loss attributable to Atlantic Power of $(3.2) million in Q3 2018 vs. $(32.9) million in Q3 2017
- Project income of $26.2 million
in Q3 2018 vs. project loss of $(20.9)
million in Q3 2017
- Cash from operating activities of $19.5
million in Q3 2018 decreased from $52.9 million in Q3 2017
- Project Adjusted EBITDA of $45.4
million in Q3 2018 decreased from $77.4 million in Q3 2017
- Repaid $20.8 million of term loan
and project debt in Q3 2018 and $79.5
million year to date; leverage ratio of 4.5 times at
September 30, 2018
- Repurchased and canceled approximately 1.4 million common
shares and approximately 284 thousand preferred shares in the third
quarter of 2018, at a total cost of approximately $6.5 million
- Liquidity at September 30, 2018
was $180.6 million, including
approximately $32 million of
discretionary cash
- Announced an agreement to acquire two contracted biomass plants
in South Carolina with a total
capacity of 40 megawatts (MW) for $13
million; expected closing in late Q3 or Q4 2019
Recent Developments
- Repurchased and canceled approximately 288 thousand common
shares in October 2018
- Executed fourth re-pricing of term loan and revolver, reducing
spread by another 25 basis points
- Returned Tunis to commercial
operation under 15-year contract on October
4, 2018
- Nipigon's Long-Term Enhanced
Dispatch Contract went into effect on November 1, 2018
2018 Guidance
- Reaffirmed 2018 Project Adjusted EBITDA guidance (see page 6 of
this news release)
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, 2018. Net loss was reduced and project income
increased in the third quarter of 2018, primarily because the 2017
period included $57.3 million of
impairment expense, which did not recur in 2018. Cash from
operating activities and Project Adjusted EBITDA declined in the
third quarter of 2018 primarily because of Power Purchase Agreement
(PPA) expirations in late 2017 and early 2018 and the
non-recurrence of OEFC Settlement revenue recorded in 2017, as
expected. Continued below-average water flows at Curtis
Palmer also contributed to the decline. In addition, cash
from operating activities was affected by the timing of the
September distribution from Orlando, which was received on October
1. Impairment expense is not included in Project Adjusted
EBITDA or cash flow.
"Third quarter results were in line with our expectations and
keep us on plan to achieve our 2018 guidance. We repaid
$20.8 million of debt during the
quarter and just this week we announced another successful
re-pricing of our term loan. We also invested $6.5 million in common and preferred share
repurchases this quarter. In September we announced an
agreement to acquire two biomass projects in South Carolina for $13
million, which represents our second external growth
investment this year," said James J. Moore,
Jr., President and CEO of Atlantic Power.
Mr. Moore continued, "Over the next few years we expect to
continue reducing our debt levels meaningfully using the
significant recurring cash flow from our existing businesses.
At the same time, our strong liquidity enables us to buy back
common and preferred shares and make additional growth investments,
when these are accretive to intrinsic value per share."
Atlantic Power
Corporation
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Table 1 – Summary
of Financial Results
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(in millions of
U.S. dollars)
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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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2018
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2017
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2018
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2017
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Project
revenue
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$65.4
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$108.6
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$211.6
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$331.0
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Project income
(loss)
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26.2
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(20.9)
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68.0
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(7.7)
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Net (loss) income
attributable to Atlantic Power Corporation
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(3.2)
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(32.9)
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12.1
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(57.5)
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Cash provided by
operating activities
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19.5
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52.9
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97.8
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138.7
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Project Adjusted
EBITDA
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45.4
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77.4
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138.5
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226.6
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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 Income
(loss).
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Financial Results for the Three Months Ended September 30, 2018
Consolidation of Koma Kulshan
On July 27, 2018, the Company
closed the acquisition of the remaining 50% partnership interest in
Koma Kulshan held by Covanta. As a result, the Company owns
100% of the project and consolidated the project in its financial
statements from that date. For periods prior to that date,
Koma is included as an equity method investment. The impact
on revenues for the third quarter of 2018 was immaterial. The
purchase price allocation (discussed in the Company's report on
Form 10-Q) resulted in a $6.7 million
gain included in other income for the step-up of the carrying value
of the Company's investment in its original 50% partnership
interest in the project. This is a non-cash gain and is not
included in Project Adjusted EBITDA.
Key Business Drivers
The most significant business drivers in the third quarter of
2018 were the expirations of the PPAs at Kapuskasing and North Bay in Ontario at year-end 2017, the early
terminations of the PPAs for the three San Diego projects effective March 1, 2018, and the short-term contract
extension at Williams Lake (less
favorable economics) effective April
2, 2018. The impact of these was as expected. In
addition, results were affected by continued below-average water
flows at Curtis Palmer.
Net Loss, Project Income and Project Adjusted EBITDA
Net loss attributable to Atlantic Power Corporation for
the third quarter of 2018 was $(3.2)
million compared to $(32.9)
million in the third quarter of 2017. The $29.7 million reduction in loss was primarily
attributable to a $47.1 million
increase in Project income (discussed below), a $4.9 million reduction in unrealized foreign
exchange loss, which was related to the revaluation of debt
denominated in Canadian dollars (the Canadian dollar appreciated
during the quarter, but to a smaller degree than in the comparable
2017 period), and a $3.5 million gain
on the repurchase of the Company's preferred shares. These
positive factors were partially offset by a $19.5 million increase in income tax expense,
which was attributable to changes in the U.S. tax
law.
Project income for the third quarter of 2018 was
$26.2 million as compared to a
project loss of $(20.9) million in
the year-ago period. The most significant driver of the
$47.1 million improvement was the
non-recurrence of $57.3 million of
impairment expense recorded at the San
Diego projects in the 2017 period. Project income also
benefited from the $6.7 million
purchase accounting gain recorded at Koma. Piedmont benefited from lower interest expense
as a result of the repayment of its project debt in October
2017. These positive variances were partially offset by lower
project income at Curtis Palmer, due to lower water flows than the
comparable 2017 period (-$3.2
million); at Williams Lake,
due to a PPA extension on less favorable terms (-$3.2 million); at Kapuskasing and North Bay, due to PPA expirations, partially
offset by lower depreciation expense (-$2.6
million) and to smaller decreases at Nipigon, Cadillac and Kenilworth.
Project Adjusted EBITDA for the third quarter of 2018
declined to $45.4 million from
$77.4 million in the third quarter of
2017. The $32.0 million
decrease was primarily attributable to the expiration of contracts
at Kapuskasing and North Bay at year end 2017 (-$11.3 million); the early termination of the PPAs
for the three San Diego projects
effective March 1, 2018
(-$11.3 million); a less favorable
short-term PPA at Williams Lake
(-$5.0 million), and lower water
flows at Curtis Palmer (-$3.3
million). These decreases were partially offset by
modest increases at other projects.
Cash Flow
Cash provided by operating activities for the third
quarter of 2018 declined to $19.5
million from $52.9 million in
the third quarter of 2017. Most of the $33.4 million reduction in operating cash flow
was attributable to the $32.0 million
reduction in Project Adjusted EBITDA. Distributions from
unconsolidated affiliates declined $3.6
million, but this was a timing issue as the September
distribution from Orlando was not
received until October 1
($3.6 million). On the positive
side, cash interest payments were $0.7
million lower in the 2018 period (resulting from debt
repayment and a lower spread on the Company's credit
facilities).
Cash used in investing activities for the third quarter
of 2018 was $(14.5) million compared
to $(1.5) million in the third
quarter of 2017. In the 2018 period the Company used
$(11.7) million of cash (net of cash
received) to acquire Covanta's 50% partnership interest in Koma
Kulshan and buy out the operation and maintenance contract from
Covanta and $(2.6) million for the
deposit required under the agreement to acquire the two
South Carolina biomass plants.
Cash used in financing activities for the third quarter
of 2018 was $(29.7) million as
compared to $(35.0) million in the
year-ago period. The Company repaid $(20.8) million of term loan and project debt,
repurchased $(3.1) million of common
shares and $(3.4) million (US$
equivalent) of preferred shares, and paid $(2.1) million of preferred dividends. In
the comparable 2017 period, the Company repaid $(29.4) million of term loan and project debt,
repurchased $(3.3) million (US$
equivalent) of preferred shares and paid $(2.3) million of preferred dividends.
During the third quarter, the Company had a $24.7 million net decrease in cash, restricted
cash and cash
equivalents.
Financial Results for the Nine Months Ended September 30, 2018
Key Business Drivers
As with the second quarter, the most significant business
drivers in the first nine months of 2018 were the expirations,
early terminations and short-term extensions of the PPAs at
Kapuskasing, North Bay, the San
Diego projects and Williams
Lake, as previously described, maintenance costs associated
with the Tunis re-start in the
first six months of 2018 and the Manchief gas turbine overhaul in
the second quarter of 2018, and lower water flows at Curtis Palmer
than in 2017. These declines were partially offset by
increases at Morris, Frederickson, Nipigon, Orlando and Mamquam. Overall, results
for the year to date were in line with the Company's
expectations.
Net Income, Project Income and Project Adjusted
EBITDA
Net income attributable to Atlantic Power Corporation for
the first nine months of 2018 was $12.1
million compared to a net loss of $(57.5) million in the first nine months of
2017. The $69.6 million
improvement was primarily attributable to a $75.7 million increase in Project income
(discussed below); a $26.8 million
increase in unrealized foreign exchange gain ($9.1 million gain versus a $17.7 million loss), which was related to the
revaluation of debt denominated in Canadian dollars (due to the
depreciation of the Canadian dollar during the first nine months of
2018, compared to an appreciation in the comparable 2017 period);
an $8.8 million reduction in
corporate interest expense as a result of debt repayment and
re-pricing of the Company's credit facilities; and a $7.9 million gain on the repurchase of the
Company's preferred shares. These positive factors were
partially offset by a $46.2 million
increase in income tax expense, which was attributable to an
increase in pretax income and changes in the U.S. tax
law.
Project income for the first nine months of 2018
increased to $68.0 million from a
project loss of $(7.7) million in the
year-ago period. The $75.7
million improvement was primarily attributable to the
non-recurrence of $57.7 million of
impairment expense recorded at Chambers and Selkirk and $57.3
million of impairment expense recorded at the three
San Diego projects in 2017
($115 million in total). Other
positive variances included Piedmont ($5.9
million), due to lower interest expense resulting from
repayment of the project's debt in October
2017; Frederickson ($5.8
million), due to lower maintenance expense than in 2017;
Orlando ($5.6 million), due to a change in the fair value
of derivatives and higher availability and contractual capacity
rates than in 2017; and Morris ($4.6
million), due to higher energy and capacity revenues.
These positive variances were partially offset by the impact of PPA
expirations and early terminations at Kapuskasing and North Bay (-$29.3
million) and the three San
Diego projects (-$13 million,
excluding the benefit associated with non-recurrence of the
impairment); project loss at Tunis
(-$10.8 million), due to maintenance
expense associated with the planned re-start of the facility in
2018 and the non-recurrence of the OEFC Settlement revenues
recorded in 2017; at Curtis Palmer (-$6.4
million), due to lower water flows than the comparable 2017
period; and at Manchief (-$6.1
million), due to the gas turbine overhaul in the second
quarter of 2018.
Project Adjusted EBITDA for the first nine months of 2018
declined to $138.5 million from
$226.6 million in the first nine
months of 2017. The $88.1
million decrease was primarily attributable to the
expiration of contracts at Kapuskasing and North Bay at year end 2017 (-$54.2 million); the early termination of the PPAs
for the three San Diego projects
effective March 1, 2018
(-$21.7 million); maintenance
expenses incurred at Tunis in
preparation for re-start incurred in 2018 and the non-recurrence of
OEFC Settlement revenues recorded in 2017 (-$10.8 million); a less favorable short-term PPA
at Williams Lake, partially offset
by cost reductions (-$6.8 million);
lower water flows at Curtis Palmer (-$6.4
million), and maintenance expenses associated with the
Manchief gas turbine overhaul in the second quarter of 2018
(-$6.1 million). Partially
offsetting these decreases were increases at Morris ($6.2 million), due to a higher capacity price
realized in the PJM capacity auction for this year, higher steam
and ancillary services revenues, higher merchant dispatch and lower
expenses; Frederickson ($3.0
million), due to maintenance expense in 2017; Nipigon ($2.9
million), due to a contractual rate increase, lower fuel
costs and other factors; Orlando
($2.6 million), due to higher
availability and higher contractual capacity rates; Mamquam
($2.6 million), due to higher water
flows and lower maintenance expense; and modest increases at other
projects.
Cash Flow
Cash provided by operating activities for the first nine
months of 2018 declined $40.9 million
to $97.8 million from $138.7 million in the first nine months of
2017. Operating cash flow was negatively affected by the
$88.1 million reduction in Project
Adjusted EBITDA. However, this impact was partially offset by
$34.6 million of net favorable
changes in working capital, particularly a $29.2 million decrease in working capital at
Kapuskasing, North Bay and the three San Diego projects, as they were not in
operation at September 30,
2018. In addition, cash interest payments were $13.9 million lower in the first nine months of
2018 than in the comparable 2017 period, as a result of debt
repayment and a lower spread on the Company's credit facilities,
and distributions from unconsolidated affiliates increased
$6.5 million (mostly at Frederickson
and Orlando).
Cash used in investing activities for the first nine
months of 2018 was $(16.9) million
compared to $(5.7) million in the
first nine months of 2017. In the 2018 period the Company
used $(12.8) million of cash (net of
cash received) to acquire additional ownership interests in Koma
Kulshan and buy out the operation and maintenance contract and
$(2.6) million for the deposit
required under the agreement to acquire the two South Carolina biomass plants. Capital
expenditures in the 2018 period were $4.2
million lower than in the 2017 period.
Cash used in financing activities for the first nine
months of 2018 was $(107.9) million
as compared to $(97.0) million in the
year-ago period. In the 2018 period, the Company issued
$92.2 million (US$ equivalent) of new
convertible debentures and used the proceeds to redeem ($88.1) million of existing convertible
debentures. It also repaid $(79.5)
million of term loan and project debt, repurchased
$(12.3) million of common shares and
$(8.0) million (US$ equivalent) of
preferred shares, paid $(6.3) million
of preferred dividends and incurred $(5.1)
million of deferred financing costs. In the comparable
2017 period, the Company repaid $(86.3)
million of term loan and project debt, repurchased
$(3.1) million (US$ equivalent) of
preferred shares and paid $(6.5)
million of preferred dividends.
During the first nine months of 2018, the Company had a
$27.0 million net decrease in cash,
restricted cash and cash
equivalents.
Liquidity and Balance Sheet
Liquidity
As shown in Table 2, the Company's liquidity at September 30, 2018 was $180.6 million, down from $203.4 million at June
30, 2018. Revolver availability was largely unchanged
at $123 million, but the Company's
unrestricted cash of $57.6 million
declined $23.2 million. During
the quarter the Company used $12.5
million of cash for the acquisition of Covanta's 50%
partnership interest in Koma Kulshan, $6.5
million for repurchases of the Company's common and
preferred shares, and $2.6 million
for the deposit associated with the South
Carolina biomass acquisition.
The mix of cash between the parent and projects, as shown in
Table 2, reflects the release during the quarter of cash from the
projects (to the parent) as working capital needs were reduced at
those projects not in operation due to PPA expirations. This
occurred in the second quarter as well. At September 30, 2018, there was $39.1 million of cash at the parent, of which the
Company considers approximately $32
million to be discretionary cash available for general
corporate purposes.
Atlantic Power
Corporation
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Table 2 –
Liquidity
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(in millions of
U.S. dollars)
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Unaudited
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Sept. 30,
2018
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June 30,
2018
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Cash and cash
equivalents, parent
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$39.1
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$49.2
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Cash and cash
equivalents, projects
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18.5
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31.6
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Total cash
and cash equivalents
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57.6
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80.8
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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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(77.0)
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(77.4)
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Availability under revolving credit facility
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123.0
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122.6
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Total
liquidity
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$180.6
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$203.4
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Excludes restricted
cash of:
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$0.3
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$1.9
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Balance Sheet
Debt Repayment
During the third quarter of 2018, the Company repaid
$20 million of the APLP Holdings term
loan and amortized $750 thousand of
project-level debt. Year to date through September 30, 2018, the Company has repaid
$70 million of the term loan and
$9.5 million of project debt.
This is consistent with the Company's plan to repay $90 million of the term loan and amortize
$10 million of project debt in
2018.
At September 30, 2018, the
Company's consolidated debt was $762
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 4.5 times.
Debt Maturity Profile
The substantial majority of the Company's debt is amortizing in
nature. The next bullet maturity is in December 2019, when the remaining Cdn$24.7 million of 6.00% Series D Debentures
mature; these are callable at par at any time prior to
maturity. The Company has no bullet maturities in 2020 or
2021. The Company's $200
million revolving credit facility matures in April
2022. The $470 million APLP
Holdings term loan has an April 2023
maturity, although it is expected to be more than 80% repaid
(through amortization and the sweep) by the maturity date.
The Cdn$115.0 million of 6.00% Series
E Debentures issued in January 2018
have a January 2025 maturity
date.
Re-pricing of Term Loan and Revolver
As previously reported in its October 31, 2018 press
release, the Company executed a re-pricing of the APLP Holdings
term loan and revolving credit facility, reducing the interest rate
margin on the term loan and revolver by 25 basis points, to LIBOR
plus 275 basis points. This represented the fourth re-pricing
for these facilities since April
2017, resulting in a cumulative reduction in the spread of
225 basis points. The Company expects to realize, before
related transaction costs, $1.2
million of interest cost savings in 2019 and $3.25 million over the remaining terms of the
facilities, as a result of the 25 basis point reduction. The
combined savings of the four re-pricing transactions are expected
to be approximately $44.4 million
over the remaining terms of the facilities. Transaction costs
associated with the re-pricing will be included in interest expense
in the fourth quarter of 2018.
Normal Course Issuer Bid (NCIB) Update
The Company has in place an NCIB for its common and preferred
shares and convertible debentures. In the third quarter of
2018, the Company repurchased and canceled approximately 1.4
million common shares at a total cost of $3.1 million, or an average price of $2.15 per share. Also in the third quarter
of 2018, the Company repurchased and canceled 237,500 shares of the
4.85% Cumulative Redeemable Preferred, Series 1 at Cdn$15.30 per share; 5,000 shares of the
Cumulative Rate Reset Preferred, Series 2 at Cdn$17.99 per share; and 41,695 shares of the
Cumulative Floating Rate Preferred, Series 3 at Cdn$17.95 per share, for a total cost of
Cdn$4.5 million (US$3.4 million equivalent). With these
repurchases, the Company has reached the 10% limit on repurchases
of Series 1 and Series 3 preferred shares under this NCIB.
In October 2018, the Company
repurchased and canceled another 288 thousand common shares at a
total cost of $619 thousand, or an
average price of $2.15 per
share.
For the year to date October 31,
2018, the Company has repurchased and canceled a total of
approximately 6.1 million common shares at a total cost of
$12.9 million, or an average price of
$2.12 per share, and has repurchased
and canceled 475,000 shares of the 4.85% Cumulative Redeemable
Preferred, Series 1; 5,000 shares of the Cumulative Rate Reset
Preferred, Series 2; and 164,790 shares of the Cumulative Floating
Rate Preferred, Series 3, at a total cost of Cdn$10.3 million (US$8.0
million equivalent).
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 is reaffirming its guidance for 2018 Project
Adjusted EBITDA in the range of $170
to $185 million. Although
continued below-average water flows at Curtis Palmer and a delayed
re-start at Tunis hurt results
modestly relative to the Company's original expectations, this has
been offset by better results elsewhere in the portfolio.
Table 3 provides a bridge of the Company's 2018 Project Adjusted
EBITDA guidance to Cash provided by operating activities.
This bridge is unchanged from that presented in the Company's
second quarter 2018 financial results release. For purposes
of providing this bridge to a cash flow measure, the impact of
changes in working capital is assumed to be nil. It should be
noted that for the nine months ended September 30, 2018, changes in working capital
have had a positive impact on operating cash flow as a result of
decreases in working capital at those projects not in operation due
to PPA expirations and early terminations (Kapuskasing, North
Bay and the three San Diego
projects).
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Atlantic Power
Corporation
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Table 3 – Bridge
of 2018 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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2018
Guidance
(initiated
3/1/18)
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Project Adjusted
EBITDA
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$170 -
$185
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Adjustment for equity
method projects(1)
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(2)
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Corporate G&A
expense
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(22)
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Cash interest
payments
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(45)
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Cash taxes
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(4)
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Other (including
changes in working capital)
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-
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Cash provided by
operating activities
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$95 -
$110
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Note: For the
purpose of providing 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.
See comment in preceding paragraph
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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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Commercial and Operational Updates
Agreement to Acquire Two Contracted Biomass Plants in
South Carolina
In September 2018, the Company
announced an agreement to acquire the Allendale and Dorchester biomass plants in South Carolina from EDF Renewables for
$13 million. The plants have
been in commercial operation since 2013. Each has a capacity
of 20 MW, and all of the output is sold to Santee Cooper under PPAs
that run to 2043. Closing of the acquisition is expected to
occur late in the third quarter or the fourth quarter of 2019
following a restructuring of the plants' ownership structure by EDF
Renewables. The purchase is expected to be funded from the
Company's discretionary cash. Upon execution of the
agreement, the Company paid $2.6
million of the purchase price, which is being held in escrow
and is included in the Company's other assets at September 30, 2018.
2018-2019 PPA Expirations
The Company has five projects with PPAs that expired in 2018 or
are scheduled to expire in 2019:
Naval Station, North Island and NTC (San Diego). As previously reported,
these plants have not been in operation since February 7, 2018, when the land use agreements
with the U.S. Navy that provided the Company the right to use the
sites expired. The PPAs with San Diego Gas & Electric
(SDG&E) were terminated effective March
1, 2018. The Company executed new power contracts for
all three plants, which were conditioned on the Company obtaining
the right to remain on the Navy sites for the contract term ("site
control"). Although the Company had been in discussions with
the Navy regarding site control for two of the three sites, these
discussions were terminated in August. The Company is
required by its land use agreements with the Navy to decommission
the sites and has begun preparations to do so. The cost and
timing of the decommissioning are dependent on the scope of work,
which is still to be determined together with the Navy. The
Company expects that the substantial majority of the cash outlays
will be incurred in 2019.
Williams Lake (British Columbia). Since
April 2, 2018, the project has been
operating under an amended energy purchase agreement with BC Hydro,
which provides for a short-term extension to June 30, 2019, or September 30, 2019 at the option of BC
Hydro. The amended contract is subject to the approval of the
BC Utilities Commission (BCUC). The BCUC recently extended
the schedule for review of the contract and a decision is not
expected until near year-end 2018 or in early 2019. BC Hydro
and the Company recently extended the date on which either party
will have the right to provide notice of intended contract
termination if the contract has not received BCUC approval to
February 28, 2019.
Kenilworth. The
Energy Services Agreement with Merck expires in September 2019, although the customer has two
remaining one-year renewal options under the agreement.
Tunis Commercial Operation
On October 4, 2018, the Company
returned the Tunis plant to
commercial operation under a 15-year PPA with the Ontario
Independent Electricity System Operator (IESO). Tunis will operate in dispatchable mode and
receive monthly capacity payments based on an average contracted
capacity of 36.5 MW. It also will earn energy revenues for
those periods during which it operates.
Tunis had not been in operation
since December 2014. The re-start required overhauls of the
gas turbine and the project's generator and upgrades of the gas
turbine control system and other systems, at a total cost of
approximately $5 million (US$
equivalent). Most of the costs were incurred in the first six
months of 2018 and all of the costs were expensed.
Nipigon Contract Update
On November 1, 2018, Nipigon's Long-Term Enhanced Dispatch Contract
(LTEDC) went into effect, replacing the original PPA for the
project while retaining the same expiration date (December
2022). Nipigon will receive
monthly capacity-type payments, with adjustment for operational
savings that will be shared with the IESO. It will operate on
a flexible basis (when needed or economic), earning energy revenues
for those periods during which it operates. The Company plans
to install upgrades to some of the project's components and systems
in 2019, although Nipigon did not
require an overhaul such as the one for Tunis prior to the LTEDC becoming
effective.
Maintenance and Capex
In the third quarter of 2018, the Company incurred $5.8 million of maintenance expense.
Through September 30 of this year,
the Company incurred maintenance expense of $27.8 million and made capital expenditures of
$1.4 million. The most
significant maintenance expenses this year have been associated
with the Tunis re-start (in the
first six months) and the Manchief gas turbine outage (in the
second quarter). For the full year, the Company estimates
that maintenance expense will total approximately $33.4 million (down from the previous expectation
of $34.8 million) and capital
expenditures approximately $1.8
million. (All of these figures include the Company's
proportional share of maintenance expenses and capital expenditures
at equity method investments.)
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.
Information by Project
A schedule of Project income (loss), Project Adjusted EBITDA and
Cash Distributions by project can be found in the third quarter
2018 presentation on the Company's website. 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.
Investor Conference Call and Webcast
Atlantic Power's management team will host a telephone
conference call and webcast on Friday,
November 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, November
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
10125391 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 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
Company's 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 2019 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 view that its third quarter and year-to-date
September 2018 results were in line
with its expectations;
- the Company's expectation that it will continue to reduce its
debt levels meaningfully over the next few years;
- the Company's assessment of its cash flow and liquidity and its
ability to continue delevering, repurchasing shares and making
growth investments;
- the Company's view that approximately $32 million of cash at the parent is available
for discretionary purposes;
- the Company's assessment of its working capital needs at its
projects;
- the Company's expectation that it will repay $100 million of debt in 2018;
- the Company's estimate that it will have repaid more than 80%
of its term loan by the April 2023
maturity date;
- the Company's estimates of interest cost savings resulting from
the re-pricing of its term loan and revolver;
- the Company's guidance for 2018 Project Adjusted EBITDA in the
range of $170 to $185 million;
- the Company's estimate that with respect to its 2018 guidance,
the impact of below-average water flows at Curtis Palmer and the
delayed re-start at Tunis will be
offset elsewhere in the portfolio;
- the Company's estimate for 2018 Cash provided by operating
activities in the range of $95 to
$110 million, assuming for this
purpose that changes in working capital are nil;
- the Company's estimation that cash outlays associated with the
decommissioning of the three San
Diego projects will be mostly incurred in 2019;
- the Company's estimation that, in 2018, including its share of
equity-owned projects, maintenance expense will total approximately
$33.4 million and capital
expenditures will total approximately $1.8
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
U.S. Securities and Exchange Commission (the "SEC") from time to
time for a detailed discussion of the risks and uncertainties
affecting the Company. 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
|
|
|
|
|
|
|
|
|
Sept.
30,
|
Dec.
31,
|
|
|
2018
|
2017
|
|
Assets
|
|
|
|
Current
assets:
|
|
|
|
Cash and cash
equivalents
|
$57.6
|
$78.7
|
|
Restricted
cash
|
0.3
|
6.2
|
|
Accounts
receivable
|
33.2
|
52.7
|
|
Current portion of
derivative instruments asset
|
6.4
|
2.7
|
|
Inventory
|
16.9
|
17.7
|
|
Prepayments
|
5.4
|
6.9
|
|
Income taxes
receivable
|
0.7
|
1.0
|
|
Other current
assets
|
3.4
|
3.1
|
|
Total current
assets
|
123.9
|
169.0
|
|
Property, plant and
equipment, net
|
567.9
|
602.3
|
|
Equity investments in
unconsolidated affiliates
|
155.7
|
163.7
|
|
Power purchase
agreements and intangible assets, net
|
179.2
|
191.2
|
|
Goodwill
|
21.4
|
21.3
|
|
Derivative
instruments asset
|
1.2
|
2.8
|
|
Other
assets
|
9.4
|
8.5
|
|
Total
assets
|
$1,058.6
|
$1,158.8
|
|
|
|
|
|
Liabilities
|
|
|
|
Current
liabilities:
|
|
|
|
Accounts
payable
|
$2.1
|
$2.2
|
|
Accrued
interest
|
4.0
|
0.3
|
|
Other accrued
liabilities
|
20.3
|
25.5
|
|
Current portion of
long-term debt
|
78.1
|
99.5
|
|
Current portion of
derivative instruments liability
|
9.1
|
4.4
|
|
Other current
liabilities
|
0.5
|
1.0
|
|
Total current
liabilities
|
114.1
|
132.9
|
|
Long-term debt, net
of unamortized discount and deferred financing costs
|
557.9
|
616.3
|
|
Convertible
debentures, net of discount and unamortized deferred financing
costs
|
99.1
|
105.4
|
|
Derivative
instruments liability
|
16.9
|
19.9
|
|
Deferred income
taxes
|
17.7
|
11.7
|
|
Power purchase and
fuel supply agreement liabilities, net
|
22.3
|
24.1
|
|
Asset retirement
obligations, net
|
47.1
|
45.3
|
|
Other long-term
liabilities
|
5.7
|
6.4
|
|
Total
liabilities
|
$880.8
|
$962.0
|
|
|
|
|
|
Equity
|
|
|
|
Common shares, no par
value, unlimited authorized shares; 110,281,935 and 115,211,976
issued and outstanding at Sept. 30, 2018 and Dec. 31, 2017,
respectively
|
1,264.5
|
1,274.8
|
|
Accumulated other
comprehensive loss
|
(139.5)
|
(134.8)
|
|
Retained
deficit
|
(1,146.5)
|
(1,158.4)
|
|
Total Atlantic Power
Corporation shareholders' equity
|
(21.5)
|
(18.4)
|
|
Preferred shares
issued by a subsidiary company
|
199.3
|
215.2
|
|
Total
equity
|
177.8
|
196.8
|
|
Total liabilities and
equity
|
$1,058.6
|
$1,158.8
|
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,
|
|
|
2018
|
2017
|
|
2018
|
2017
|
Project
revenue:
|
|
|
|
|
|
|
|
Energy
sales
|
|
$25.0
|
$36.5
|
|
$94.8
|
$113.6
|
Energy
capacity revenue
|
|
29.5
|
37.9
|
|
72.9
|
85.7
|
Other
|
|
10.9
|
34.2
|
|
43.9
|
131.7
|
|
|
65.4
|
108.6
|
|
211.6
|
331.0
|
Project
expenses:
|
|
|
|
|
|
|
Fuel
|
|
16.7
|
26.2
|
|
54.0
|
79.1
|
Operations and
maintenance
|
|
18.0
|
19.8
|
|
66.5
|
63.4
|
Depreciation
and amortization
|
|
21.0
|
31.4
|
|
65.7
|
90.5
|
|
|
55.7
|
77.4
|
|
186.2
|
233.0
|
Project other income
(loss):
|
|
|
|
|
|
|
Change in fair
value of derivative instruments
|
|
-
|
(1.9)
|
|
3.6
|
(5.8)
|
Equity in
earnings (loss) of unconsolidated affiliates
|
|
10.2
|
9.2
|
|
33.7
|
(36.1)
|
Interest,
net
|
|
(0.4)
|
(2.2)
|
|
(1.4)
|
(6.6)
|
Impairment
|
|
-
|
(57.3)
|
|
-
|
(57.3)
|
Other
Income
|
|
6.7
|
0.1
|
|
6.7
|
0.1
|
|
|
16.5
|
(52.1)
|
|
42.6
|
(105.7)
|
Project income
(loss)
|
|
26.2
|
(20.9)
|
|
68.0
|
(7.7)
|
Administrative and
other expenses:
|
|
|
|
|
|
|
Administration
|
|
5.7
|
5.5
|
|
17.9
|
17.6
|
Interest
expense, net
|
|
14.6
|
13.8
|
|
40.7
|
49.5
|
Foreign
exchange loss (gain)
|
|
4.5
|
9.4
|
|
(9.1)
|
17.7
|
Other expense,
net
|
|
2.5
|
-
|
|
0.3
|
-
|
|
|
27.3
|
28.7
|
|
49.8
|
84.8
|
(Loss) income from
operations before income taxes
|
|
(1.1)
|
(49.6)
|
|
18.2
|
(92.5)
|
Income tax expense
(benefit)
|
|
3.6
|
(15.9)
|
|
7.7
|
(38.5)
|
Net (loss)
income
|
|
(4.7)
|
(33.7)
|
|
10.5
|
(54.0)
|
Net (loss) income
attributable to preferred share dividends of a subsidiary
company
|
|
(1.5)
|
(0.8)
|
|
(1.6)
|
3.5
|
Net (loss) income
attributable to Atlantic Power Corporation
|
|
($3.2)
|
($32.9)
|
|
$12.1
|
($57.5)
|
Net (loss) income per
share attributable to Atlantic Power Corporation
shareholders:
|
|
|
|
|
|
|
Basic
|
|
($0.03)
|
($0.29)
|
|
$0.11
|
($0.50)
|
Diluted
|
|
(0.03)
|
(0.29)
|
|
0.11
|
(0.50)
|
Weighted average
number of common shares outstanding:
|
|
|
|
|
|
|
Basic
|
|
111.1
|
115.3
|
|
112.8
|
115.1
|
Diluted
|
|
111.1
|
115.3
|
|
140.1
|
115.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Atlantic Power
Corporation
|
Table 6 –
Consolidated Statements of Cash Flow
|
(in millions of
U.S. dollars)
|
Unaudited
|
|
|
Nine months ended
Sept. 30,
|
|
2018
|
2017
|
Cash provided by
operating activities:
|
|
|
Net income
(loss)
|
$10.5
|
($54.0)
|
Adjustments to
reconcile net income (loss) to net cash provided by operating
activities:
|
|
|
Depreciation and
amortization
|
65.7
|
90.5
|
Loss on disposal of
fixed assets
|
-
|
0.1
|
Gain on fair value
adjustment to equity investment resulting from
step
|
(6.7)
|
-
|
acquisition
|
|
|
Stock-based
compensation
|
1.8
|
1.6
|
Long-lived asset and
goodwill impairment
|
-
|
57.3
|
Equity in (earnings)
loss from unconsolidated affiliates
|
(33.7)
|
36.1
|
Distributions from
unconsolidated affiliates
|
37.4
|
30.9
|
Unrealized foreign
exchange (gain) loss
|
(8.6)
|
17.0
|
Change in fair value
of derivative instruments
|
(3.5)
|
5.8
|
Change in fair value
of convertible debenture conversion option derivative
|
0.2
|
-
|
Amortization of debt
discount and deferred financing costs
|
7.4
|
7.8
|
Change in deferred
income taxes
|
5.0
|
(42.1)
|
Change in other
operating balances
|
|
|
Accounts
receivable
|
19.7
|
(11.5)
|
Inventory
|
0.8
|
(4.2)
|
Prepayments and other
assets
|
3.2
|
0.6
|
Accounts
payable
|
(1.0)
|
0.3
|
Accruals and other
liabilities
|
(0.4)
|
2.5
|
Cash provided by
operating activities
|
97.8
|
138.7
|
|
|
|
Cash used in
investing activities:
|
|
|
Cash paid for
acquisition, net of cash received
|
(12.8)
|
-
|
Deposit for
acquisition
|
(2.6)
|
-
|
Purchase of property,
plant and equipment
|
(1.5)
|
(5.7)
|
Cash used in
investing activities
|
(16.9)
|
(5.7)
|
|
|
|
Cash used in
financing activities:
|
|
|
Proceeds from
convertible debenture issuance
|
92.2
|
-
|
Repayment of
convertible debentures
|
(88.1)
|
(0.1)
|
Common share
repurchases
|
(12.3)
|
(0.2)
|
Preferred share
repurchases
|
(8.0)
|
(3.1)
|
Repayment of corporate
and project-level debt
|
(79.5)
|
(86.3)
|
Cash payments for
vested LTIP units withheld for taxes
|
(0.8)
|
(0.8)
|
Deferred financing
costs
|
(5.1)
|
-
|
Dividends paid to
preferred shareholders
|
(6.3)
|
(6.5)
|
Cash used in
financing activities:
|
(107.9)
|
(97.0)
|
|
|
|
Net (decrease)
increase in cash, restricted cash and cash equivalents
|
(27.0)
|
36.0
|
Cash, restricted cash
and cash equivalents at beginning of period
|
84.9
|
98.9
|
Cash, restricted cash
and cash equivalents at end of period
|
$57.9
|
$134.9
|
|
|
|
Supplemental cash
flow information
|
|
|
Interest
paid
|
$30.2
|
$44.2
|
Income taxes paid,
net
|
$2.5
|
$3.4
|
Accruals for
construction in progress
|
$-
|
$-
|
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 income (loss) on a consolidated
basis is provided in Table 7 below.
Atlantic Power
Corporation
|
Table 7 –
Reconciliation of Net (Loss) income to Project Adjusted
EBITDA
|
(in millions of
U.S. dollars)
|
Unaudited
|
|
Three months
ended
September 30,
|
|
Nine months
ended
September 30,
|
|
2018
|
2017
|
|
2018
|
2017
|
Net (loss) income
attributable to Atlantic Power Corporation
|
($3.2)
|
($32.9)
|
|
$12.1
|
($57.5)
|
Net (loss) income
attributable to preferred share dividends of a subsidiary
company
|
(1.5)
|
(0.8)
|
|
(1.6)
|
3.5
|
Net (loss)
income
|
($4.7)
|
($33.7)
|
|
$10.5
|
($54.0)
|
Income tax expense
(benefit)
|
3.6
|
(15.9)
|
|
7.7
|
(38.5)
|
(Loss) income from
operations before income taxes
|
(1.1)
|
(49.6)
|
|
18.2
|
(92.5)
|
Administration
|
5.7
|
5.5
|
|
17.9
|
17.6
|
Interest expense,
net
|
14.6
|
13.8
|
|
40.7
|
49.5
|
Foreign exchange loss
(gain)
|
4.5
|
9.4
|
|
(9.1)
|
17.7
|
Other expense,
net
|
2.5
|
-
|
|
0.3
|
-
|
Project income
(loss)
|
$26.2
|
($20.9)
|
|
$68.0
|
($7.7)
|
|
|
|
|
|
|
Reconciliation to
Project Adjusted EBITDA
|
|
|
|
|
|
Depreciation and
amortization
|
$25.0
|
$36.6
|
|
$78.0
|
$105.6
|
Interest,
net
|
(0.6)
|
2.5
|
|
2.7
|
8.0
|
Change in the fair
value of derivative instruments
|
-
|
2.0
|
|
(3.5)
|
5.8
|
Impairment
|
-
|
57.3
|
|
-
|
57.3
|
Other project
(income) expense
|
(5.2)
|
(0.1)
|
|
(6.7)
|
57.6
|
Project Adjusted
EBITDA
|
$45.4
|
$77.4
|
|
$138.5
|
$226.6
|
View original
content:http://www.prnewswire.com/news-releases/atlantic-power-corporation-releases-third-quarter-2018-results-300742760.html
SOURCE Atlantic Power Corporation