DEDHAM, Mass., Nov. 5, 2015 /PRNewswire/ -- Atlantic Power
Corporation (NYSE: AT) (TSX: ATP) ("Atlantic Power" or the
"Company") today released its results for the three and nine months
ended September 30, 2015.
Third Quarter 2015 Financial Highlights
- Completed the redemption of $310.9
million outstanding principal amount of 9.0% Senior
Unsecured Notes due 2018 (the 9.0% Notes) in July
- Amortized $14 million of term
loan and project debt in third quarter; for the year to date, debt
amortization, repurchases and redemptions total approximately
$409 million
- Q3 2015 Project income of $24
million vs. project loss of $(65)
million in Q3 2014 (results exclude the wind businesses,
which are included in discontinued operations); increase was mostly
due to $92 million of asset and
goodwill impairment expense in 2014 that did not recur in 2015
- Q3 2015 Project Adjusted EBITDA of $56
million vs. $58 million in Q3
2014 (results exclude $0 million and
$14 million, respectively, from the
wind businesses)
- Q3 2015 Cash flows from operating activities of $14.5 million vs. $40
million in Q3 2014 (including $0
million and $11 million,
respectively, from the wind businesses); decrease was primarily
attributable to the sale of the wind businesses and $19.5 million of costs associated with the
redemption of the 9.0% Notes, both in 2015
- Q3 2015 Adjusted Cash Flows from Operating Activities, which
excludes discontinued operations, changes in working capital,
severance and other restructuring charges, and debt prepayment or
redemption costs, decreased to $39
million from $44 million in Q3
2014
- Q3 2015 Adjusted Free Cash Flow of $18
million was after $14 million
of term loan and project debt repayment and $4 million of capital expenditures and declined
slightly from $20 million in Q3
2014
2015 Guidance
- No change to Project Adjusted EBITDA guidance of $200 to $215 million
- Raised lower end of Adjusted Cash Flows from Operating
Activities guidance to a range of $95 to
$105 million (had been $90 to $105
million), mostly due to lower expected G&A and cash
interest payments
- No change to Adjusted Free Cash Flow guidance of $0 to $10 million
- Expect 2015 corporate G&A expense of approximately
$32 million vs. $35 million previously; on track for $28 million or lower in 2016 (48% reduction from
2013)
- Optimization initiatives expected to produce approximately
$6 million of cash flow benefit in
2015 (in line with previous estimate of $4
to $8 million) and approximately $10
million in 2016
Recent Developments
- Lead plaintiff in U.S. securities class action suit dropped
appeal in late October; both sides jointly stipulated to dismissal
of the appeal with prejudice; awaiting court approval
- Moody's upgraded the Company's corporate family credit rating
in mid-October to B1 from B2
- CEO and directors purchased 185,000 common shares of the
Company during the third quarter at an average price of
$2.23, following purchases in the
second quarter of more than 380,000 shares at an average price of
$3.09
"We have made significant progress in strengthening the
Company's financial position, including reducing our debt by more
than $800 million in the past seven
quarters through the sale of our wind businesses at an attractive
valuation, the redemption of our highest-cost debt, ongoing
amortization of our term loan and project debt as well as
discretionary debt repurchases. As a result, we have reduced
our cash interest payments by approximately half. These
actions have improved our credit profile, which was recognized in a
recent upgrade of our corporate credit rating," said James J. Moore, President and Chief Executive
Officer of Atlantic Power. "We continue to evaluate
opportunities to reshape our remaining US$292 million of corporate debt maturities in
2017 and 2019. In addition, we have streamlined our
organizational structure, reducing our overhead costs by nearly
half from 2013 through the expected level for 2016."
"We have been investing in our own fleet at returns superior to
those available in the external market and with much lower risk,
and already are realizing incremental cash flow from these
projects. Going forward, we see the potential for larger
investments in conjunction with possible extensions of existing
Power Purchase Agreements (PPAs)," continued Mr. Moore. "The
progress we have made in improving our financial risk profile
allows us to move from a primarily defensive strategy to one that
is more balanced, including continuing to make attractive
investments in our projects while also pursuing capital-efficient,
disciplined external growth. We also see investment
opportunities in our own capital structure, although our primary
focus will be on additional delevering in order to further improve
our credit profile."
Atlantic Power
Corporation
Table 1 – Selected
Results
(in millions of
U.S. dollars, except as otherwise stated)
Unaudited
|
|
Three months ended
September 30,
|
Nine months ended
September 30,
|
|
2015
|
2014
|
2015
|
2014
|
Excluding results
from discontinued operations(1)
|
|
|
|
|
Project
revenue
|
$107.5
|
$121.6
|
$321.8
|
$370.0
|
Project income
(loss)
|
24.2
|
(65.1)
|
63.0
|
(41.0)
|
Project Adjusted
EBITDA
|
56.0
|
58.1
|
158.5
|
172.6
|
Cash Distributions
from Projects
|
51.5
|
40.8
|
146.3
|
152.4
|
Adjusted Cash Flows
from Operating Activities
|
38.7
|
44.2
|
77.7
|
74.6
|
Adjusted Free Cash
Flow
|
18.1
|
20.1
|
(5.7)
|
1.1
|
Aggregate power
generation (thousands of Net MWh)
|
1,659.0
|
1,649.6
|
4,673.8
|
4,806.8
|
Weighted average
availability
|
94.3%
|
94.3%
|
93.5%
|
91.6%
|
Including results
from discontinued operations (1)
|
|
|
|
|
Cash flows from
operating activities
|
$14.5
|
$40.4
|
$67.7
|
$45.9
|
Free Cash
Flow
|
(6.1)
|
12.6
|
(19.5)
|
(48.4)
|
Results of
discontinued operations
|
|
|
|
|
Project Adjusted
EBITDA
|
$-
|
$14.1
|
$28.3
|
$49.0
|
Cash Distributions
from Projects
|
-
|
10.5
|
7.3
|
35.3
|
Cash flows from
operating activities
|
-
|
10.8
|
21.9
|
36.9
|
(1)
Canadian Hills, Meadow Creek, Goshen North, Idaho Wind and Rockland
(the "Wind Projects") were sold in June 2015 and are designated as
discontinued operations for the nine months ended September 30,
2015 and 2014. Greeley was sold in March 2014 and is included
as a component of discontinued operations for the nine months ended
September 30, 2014. The results of discontinued operations
are excluded from Project revenue, Project income, Project Adjusted
EBITDA, Cash Distributions from Projects, Adjusted Cash Flows from
Operating Activities and Adjusted Free Cash Flow as presented in
Table 1. The results for discontinued operations have also
been excluded from the aggregate power generation and weighted
average availability statistics shown in Table 1. Under GAAP,
the cash flows attributable to the Wind Projects and Greeley are
included in cash flows from operating activities as shown on the
Company's Consolidated Statement of Cash Flows; therefore, the
Company's calculation of Free Cash Flow shown on Table 1 also
includes cash flows from the Wind Projects and Greeley.
However, the inclusion of Greeley in 2014 had no impact on cash
flows from operating activities or Free Cash Flow. Results of
discontinued operations shown above are for the Wind Projects, as
Greeley had no impact on Project Adjusted EBITDA, Cash
Distributions from Projects or cash flows from operating activities
for the 2014 period in which it was included in discontinued
operations.
Note: Project
Adjusted EBITDA, Cash Distributions from Projects, Adjusted Cash
Flows from Operating Activities, Adjusted Free Cash Flow and Free
Cash Flow are not recognized measures under GAAP and do not have
any standardized meaning prescribed by GAAP; therefore, these
measures may not be comparable to similar measures presented by
other companies. Please refer to Tables 9 through 12 for
reconciliations of these non-GAAP measures to GAAP
measures.
|
|
|
|
|
|
|
|
All amounts are in U.S. dollars and are approximate unless
otherwise indicated. Adjusted Cash Flows from Operating Activities,
Free Cash Flow, Adjusted Free Cash Flow, Cash Distributions from
Projects, Project Adjusted EBITDA and APLP Project Adjusted EBITDA
are not recognized measures under generally accepted accounting
principles in the United States
("GAAP") and do not have standardized meanings prescribed by GAAP;
therefore, these measures may not be comparable to similar measures
presented by other companies. Please see "Regulation G Disclosures"
attached to this news release for an explanation and the GAAP
reconciliation of "Adjusted Cash Flows from Operating Activities",
"Free Cash Flow", "Adjusted Free Cash Flow", "Cash Distributions
from Projects" and "Project Adjusted EBITDA" as used in this news
release. The Company has not reconciled non-GAAP financial
measures relating to individual projects or the projects in
discontinued operations or the APLP projects to the directly
comparable GAAP measures due to the difficulty in making the
relevant adjustments on an individual project basis. The
Company has not provided a reconciliation of forward-looking
non-GAAP measures, due primarily to variability and difficulty in
making accurate forecasts and projections, as not all of the
information necessary for a quantitative reconciliation is
available to the Company without unreasonable efforts.
Operating Results
The discussion of operating results excludes the Wind
Projects, which were sold in June
2015 and are included in discontinued operations.
Three Months Ended September 30,
2015
Project availability was 94.3% in the third quarter of
2015, unchanged from the year-ago period. Increased
availability at Nipigon, which had a maintenance outage in the
comparable 2014 period, was offset by lower availability at
Mamquam, which had a scheduled maintenance outage in the third
quarter of 2015. (The 2015 availability figure excludes
Tunis, which has been mothballed
since February 2015 following the
expiration of its PPA in December
2014.)
Generation increased 0.6% in the third quarter of 2015
from the year-ago period, primarily due to Frederickson, which had
increased dispatch as a result of warmer weather and reduced hydro
availability in the region as compared to 2014, and Nipigon, which
had a maintenance outage in the third quarter of 2014. These
increases were partially offset by decreases at Tunis, due to the expiration of its PPA, and
at Mamquam, which had a scheduled maintenance outage in the third
quarter of 2015.
Nine Months Ended September 30,
2015
Project availability increased to 93.5% in the nine
months ended Sept. 30, 2015 from
91.6% in the comparable period in 2014. Increased
availability at Chambers, Orlando,
Nipigon and North Island, all of which had maintenance outages in
2014, more than offset decreased availability at Manchief and
Mamquam, which had scheduled maintenance outages in 2015.
(The 2015 availability figure excludes Tunis.)
Generation decreased 2.8% in the nine months ended
Sept. 30, 2015 from the comparable
year-ago period, primarily due to PPA expirations at Selkirk
(August 2014) and Tunis (December
2014); lower dispatch at Chambers due to unfavorable
pricing; lower water flows at Curtis Palmer and a scheduled
maintenance outage at Mamquam. These decreases were partially
offset by an increase at Frederickson due to higher dispatch and
increases at Nipigon and Morris, which had outages in
2014.
Financial Results
In the second quarter of 2015, the Company revised its
reportable business segments as a result of recent significant
asset sales and in order to align with changes in management's
structure, resource allocation and performance assessment in making
decisions regarding the Company's operations. Results of the
Company's businesses are now reported in four segments: East
U.S., West U.S., Canada and
Un-allocated Corporate.
Atlantic Power
Corporation
Table 2 – Segment
Results
(in millions of
U.S. dollars, except as otherwise stated)
Unaudited
|
|
Three months ended
September 30,
|
Nine months ended
September 30,
|
|
2015
|
2014
|
2015
|
2014
|
Project income
(loss)
|
|
|
|
|
East U.S.
|
$12.4
|
$(8.2)
|
$40.0
|
$4.8
|
West U.S.
|
11.5
|
(29.9)
|
7.3
|
(27.1)
|
Canada
|
1.9
|
(24.5)
|
17.9
|
(11.8)
|
Un-allocated
Corporate
|
(1.6)
|
(2.5)
|
(2.2)
|
(6.9)
|
Total
|
24.2
|
(65.1)
|
63.0
|
(41.0)
|
Project Adjusted
EBITDA
|
|
|
|
|
East U.S.
|
$27.4
|
$27.3
|
$81.0
|
$82.4
|
West U.S.
|
21.4
|
21.3
|
37.1
|
44.8
|
Canada
|
7.6
|
12.3
|
43.0
|
51.6
|
Un-allocated
Corporate
|
(0.4)
|
(2.8)
|
(2.6)
|
(6.2)
|
Total
|
56.0
|
58.1
|
158.5
|
172.6
|
The results of the
Wind Projects and Greeley, which are components of discontinued
operations, are excluded from Project income and Project Adjusted
EBITDA as presented in Table 2.
Note: Project
Adjusted EBITDA is not a recognized measure under GAAP and does not
have any standardized meaning prescribed by GAAP; therefore, this
measure may not be comparable to similar measures presented by
other companies. Please refer to Tables 8 through 12 for a
reconciliation of this non-GAAP measure to a GAAP measure.
The Company has not reconciled this non-GAAP financial measure
relating to individual project segments to the directly comparable
GAAP measure due to the difficulty in making the relevant
adjustments on a segment basis.
|
Table 2 provides a breakdown of project income and Project
Adjusted EBITDA by segment for the three and nine months ended
Sept. 30, 2015 as compared to the
same periods in 2014. The Company's Wind Projects were sold
in June 2015 and are included in
results of discontinued operations for the three and nine-month
periods ended Sept. 30, 2015 and
2014. Greeley was sold in March
2014 and is included as a component of discontinued
operations for the nine months ended Sept.
30, 2014. Results for project income and Project
Adjusted EBITDA exclude discontinued operations.
Accordingly, results of the Wind Projects and Greeley are not
included in Project income or Project Adjusted EBITDA for either
the 2015 or 2014 periods shown in Table 2.
Three Months Ended September 30,
2015
Project income can fluctuate significantly due to
non-cash adjustments to "mark-to-market" the fair value of
derivatives. Non-cash goodwill impairment charges and gains
or losses on the sale of assets are included in project income and
can also affect year-over-year comparisons. None of these
items are included in Project Adjusted EBITDA.
Project income increased $89.3
million to $24.2 million in
the third quarter of 2015 from a project loss of $(65.1) million for the third quarter of
2014. The 2014 result included a $91.8
million non-cash impairment of goodwill at Kenilworth,
Manchief and Williams Lake and an
$8.6 million gain from the sale of
Delta-Person.
Project Adjusted EBITDA includes the proportional share
of Project Adjusted EBITDA from the Company's equity method
projects. Project Adjusted EBITDA is a non-GAAP
measure. Table 8 of this press release provides a
reconciliation of Project Adjusted EBITDA to Project
income.
Project Adjusted EBITDA decreased modestly to $56.0 million in the third quarter of 2015 from
$58.1 million in the third quarter of
2014. The most significant drivers of lower EBITDA were the
Selkirk PPA expiration, lower water flows at Curtis Palmer and
Mamquam and the scheduled maintenance outage at Mamquam, and higher
maintenance expense for a turbine repair at North Bay. These
factors were partially offset by higher Project Adjusted EBITDA at
Piedmont, which benefited from higher revenue, lower fuel expense
and lower maintenance expense, and Nipigon, which had a scheduled
maintenance outage in 2014. In addition, the Un-allocated
Corporate segment experienced a reduced loss of $(0.4) million versus $(2.8) million in the year-ago period, primarily
due to $1.1 million of lower
project-level compensation expense and $1.0
million of reduced development and administrative
costs. Currency had an approximate $(1.4) million impact on Project Adjusted EBITDA,
with an average U.S. dollar to Canadian dollar exchange rate for
the third quarter of 2015 of 1.31 versus 1.10 for the year-ago
period. However, from an overall cash standpoint, that impact
was mostly offset by the benefit of the stronger U.S. dollar on the
Company's Canadian-denominated interest and dividend payments.
Corporate-level G&A expense (shown as
"Administration" on the Consolidated Statements of Operations)
decreased $2.3 million to
$6.9 million in the third quarter of
2015 from $9.2 million a year
ago. The improvement was due primarily to a $2.7 million decrease in employee compensation
expense. The 2014 figure included $4.2
million of severance charges.
Cash Flow Metrics
Cash flows from operating activities (GAAP) and Free Cash
Flow include the cash flows from projects classified as
discontinued operations. Free Cash Flow is a non-GAAP
measure. Table 10 of this press release provides a
reconciliation of Free Cash Flow to cash flows from operating
activities.
Cash flows from operating activities of $14.5 million in the third quarter of 2015
declined $25.9 million from
$40.4 million in the third quarter of
2014. The reduction was primarily attributable to the
$14.0 million premium and
$5.5 million of accrued interest paid
at redemption of the 9.0% Notes in June
2015 (both of which are included in interest expense) as
well as the $10.8 million reduction
in operating cash flows from the wind businesses, which were sold
in June 2015 (see "Results of
Discontinued Operations").
Free Cash Flow, which is after debt repayment,
capital expenditures and preferred dividends, decreased
$18.7 million to $(6.1) million for the third quarter of 2015 from
$12.6 million for the third quarter
of 2014. The reduction is primarily due to the $25.9 million reduction in operating cash flows,
partially offset by a $3.1 million
decrease in capital expenditures and a $4.4
million reduction in distributions to noncontrolling
interests, including preferred dividends.
Cash Distributions from Projects and the adjusted cash flow
metrics discussed below, all of which are non-GAAP measures,
exclude cash flows from projects classified as discontinued
operations. Adjusted Cash Flows from Operating Activities,
which excludes discontinued operations, changes in working capital,
severance, restructuring charges, acquisition and disposition
expenses and debt prepayment and redemption costs, is a measure of
the cash flow available to the Company to make principal repayments
on its debt (primarily through amortization and the cash sweep
under the APLP term loan), invest in its fleet through required or
discretionary capital expenditures, and make dividend payments to
preferred and common shareholders, if and when declared by the
board of directors. Adjusted Free Cash Flow is after debt
repayment or amortization, capital expenditures and preferred
dividends, but is before common dividend payments. It is thus
a key measure in evaluating the amount of cash flow available to
the Company to make common dividend payments. Tables 10 and
11 of this press release provide a reconciliation of the Company's
non-GAAP cash flow metrics to cash flows from operating
activities.
Cash Distributions from Projects increased $10.7 million to $51.5
million for the third quarter of 2015 from $40.8 million for the same period in 2014.
Significant increases occurred at the following projects:
Nipigon, which benefited from higher availability than in the third
quarter of 2014, when it underwent a major outage to upgrade and
replace its steam generator, and from higher waste heat and
capacity revenue due to rate escalation under the PPA; Chambers,
which benefited from lower debt service and lower capital
expenditures, and which did not make a distribution in the year-ago
quarter (the timing of distributions changed under the project's
new debt agreement in June 2014);
Calstock, which had a maintenance outage in the third quarter of
2014, and which benefited from additional waste heat this quarter,
and Orlando, which benefited from
lower gas costs and increased capacity payments. These
increases were partially offset by reductions at Manchief, which
had a major gas turbine outage in the second quarter of 2015 and
which has also experienced reduced dispatch, and Selkirk, which has
been operating on a merchant basis in unfavorable market conditions
since its PPA expired in August
2014.
Adjusted Cash Flows from Operating Activities decreased
$5.5 million to $38.7 million in the third quarter of 2015 from
$44.2 million in the year-ago period,
primarily because of lower Project Adjusted EBITDA and several
other less significant factors. The 2015 result excludes the
$14.0 million premium and
$5.5 million of accrued interest paid
at redemption of the 9.0% Notes in June 2015.
Adjusted Free Cash Flow decreased modestly to
$18.1 million in the third quarter of
2015 from $20.1 million in the third
quarter of 2014. The decrease was primarily attributable to
lower Adjusted Cash Flows from Operating Activities, partially
offset by lower capital expenditures and the favorable impact of
the appreciation of the U.S. dollar against the Canadian dollar on
the level of preferred dividend payments.
Nine Months Ended September 30,
2015
Project income increased $104.0
million to $63.0 million in
the third quarter of 2015 from a project loss of ($41.0) million in the third quarter of
2014. The 2014 result included $106.6
million of non-cash impairments of long-lived assets and
goodwill at Tunis and of goodwill
at Kenilworth, Manchief and Williams
Lake. Results also benefited from increases in project
income at Orlando, Morris,
Piedmont, Curtis Palmer (lower interest expense, partially offset
by lower water flows), North Island and Calstock. These
increases were partially offset by increased maintenance expense at
Manchief related to a gas turbine overhaul in the second quarter of
2015, the expiration of the PPA at Tunis in December
2014, higher fuel expense and higher maintenance expense
associated with a turbine repair at North Bay and the $8.6 million gain on the sale of Delta-Person in
2014. In addition, there was a $14.6
million negative year-over-year change in the fair value of
derivatives.
Project Adjusted EBITDA decreased $14.1 million to $158.5
million for the first nine months of 2015 from $172.6 million for the comparable period in
2014. The most significant drivers of the decline were lower
results from Selkirk due to the expiration of its PPA and reduced
dispatch in an unfavorable market environment, the gas turbine
maintenance outage at Manchief, the mothballed status of
Tunis, lower water flows at Curtis
Palmer and Mamquam and higher fuel and maintenance expense at North
Bay and Kapuskasing, partially offset by higher waste heat
generation. Currency had an approximate $(6.0) million impact on Project Adjusted EBITDA,
with an average U.S. dollar to Canadian dollar exchange rate for
the first nine months of 2015 of 1.27 versus 1.10 for the year-ago
period. These negative factors were partially offset by
increases at Orlando, which
benefited from higher generation and lower fuel expenses due to
lower gas prices; Morris, which had lower fuel expense and lower
maintenance expense than the comparable year-ago period; Piedmont,
which had higher revenue, lower fuel expense and lower maintenance
expense than a year ago; Calstock, which had higher waste heat
generation and lower maintenance expense, and Nipigon, which had a
maintenance outage in the comparable year-ago period and also
benefited from high levels of waste heat. In addition, the
Un-allocated Corporate segment had a reduced loss of $(2.6) million versus $(6.2) million in the year-ago period, due
primarily to a $1.9 million reduction
in project-level compensation expense and $1.6 million of decreased development and
administrative
costs.
Corporate-level G&A expense decreased
$3.7 million to $23.0 million in the
first nine months of 2015 from $26.7
million in the comparable year-ago period. The
improvement was primarily attributable to a $2.5 million reduction in legal expenses
associated with the U.S. and Canadian shareholder actions, a
$1.4 million decrease in business
development costs related to divestitures and a $0.6 million reduction in employee compensation
expense.
Cash Flow Metrics
Cash flows from operating activities of $67.7 million for the first nine months of 2015
increased $21.8 million from
$45.9 million for the comparable
period in 2014. The increase is primarily due to $46.8 million of interest expense related to the
debt repayment and repurchase transactions in the first quarter of
2014, partially offset by $19.5
million of premiums and accrued interest paid related to the
redemption of the 9.0% Notes in July
2015, as well as $1.1 million
of tax payments and $15.0 million of
reduced cash flows from the wind businesses, which were sold in
June 2015.
Free Cash Flow of $(19.5)
million for the first nine months of 2015 increased
$28.9 million from $(48.4) million for the comparable period in
2014. The increase is primarily due to the $21.8 million increase in operating cash flows
described previously, a $5.0 million
decrease in distributions to noncontrolling interests related to
Canadian Hills and Rockland and a
$2.1 million decrease in preferred
dividends (driven primarily by the exchange rate). Repayment
of the APLP term loan and amortization of project debt totaled
$67.3 million in the first nine
months of 2015 versus $66.7 million
in 2014, including an $8.1 million
repayment of Piedmont principal at term loan conversion in February
2014.
Cash Distributions from Projects decreased $(6.1) million to $146.3
million for the first nine months of 2015 from $152.4 million for the comparable year-ago
period. Significant increases were experienced at the
following projects: Chambers, due to a change in the timing
of distributions; Morris, which benefited from lower gas prices,
reduced property taxes and a higher PJM capacity rate; Orlando, which benefited from lower gas
prices, higher capacity payments and increased generation;
Calstock, which benefited from additional waste heat and lower
maintenance expense relative to the year-ago period when it had an
outage, and Nipigon, which benefited from improved availability
following two outages in 2014, additional waste heat and higher
capacity payments due to contract escalation. These increases
were more than offset by decreases at Selkirk and Tunis, due to their PPA expirations; Manchief,
due to the gas turbine outage and reduced dispatch, and the Navy
projects, which benefited from the timing of gas payments in the
2014 period.
Adjusted Cash Flows from Operating Activities of
$77.7 million for the first nine
months of 2015 increased $3.1 million
from $74.6 million in the comparable
year-ago period. The 2015 result excludes the $14.0 million premium and $5.5 million of accrued interest paid at
redemption of the 9.0% Notes in June 2015. The 2014 result
excludes $49.4 million of interest
expense associated with the debt refinancing and repurchase
transactions in the first quarter of 2014. The increase in
Adjusted Cash Flows from Operating Activities was primarily
attributable to a $10.0 million
reduction in cash interest payments and to slightly lower G&A
expense, partially offset by lower Project Adjusted
EBITDA.
Adjusted Free Cash Flow of $(5.7)
million decreased $6.8 million
for the first nine months of 2015 from $1.1
million in the comparable year-ago period. Results for
both years exclude interest expense associated with debt
refinancing or redemption as described above. The 2014 result
also excludes an $8.1 million
Piedmont principal repayment at term loan conversion. The
decrease in Adjusted Free Cash Flow was primarily attributable to
the $3.1 million increase in Adjusted
Cash Flows from Operating Activities described above and a
$2.1 million reduction in preferred
dividend payments (driven by a more favorable exchange rate), which
were more than offset by a $12.2
million increase in term loan and project debt
amortization.
Results of Discontinued Operations
The Wind Projects were sold in June
2015 and are a component of discontinued operations for the
three and nine months ended Sept. 30,
2015 and 2014. Greeley was sold in March 2014 and is included as a component of
discontinued operations for the first nine months of 2014.
The results for Greeley were immaterial during that
period.
Project Adjusted EBITDA of the Wind Projects was
$0.0 million for the third quarter of
2015 versus $14.1 million for the
comparable year-ago period. Results for the first nine months
of 2015 were $28.3 million versus
$49.0 million for the comparable
year-ago period.
Cash flows from operating activities of the Wind Projects
were $0.0 million and $21.9 million for the third quarter and first
nine months of 2015, respectively, versus $10.8 million and $36.9
million, respectively, for the comparable 2014
periods.
Liquidity
As shown in Table 3, the Company's liquidity at Sept. 30, 2015 was $177.2
million, including $76.4
million of unrestricted cash. Liquidity at
June 30, 2015 of $492.2 million included approximately
$335 million of net cash proceeds
received from the sale of the Company's Wind Projects in
June. In July, the Company used $330.4
million of cash to redeem the $310.9
million of 9.0% Notes, including redemption premiums and
accrued interest. On a pro forma basis for that transaction,
liquidity at June 30, 2015 was
$161.8 million.
Atlantic Power
Corporation
Table 3 –
Liquidity (in millions of U.S. dollars)
|
|
|
Unaudited
|
|
June 30,
2015
|
Redemption of 9.0%
Notes
July
2015
|
September 30,
2015
|
Revolver
capacity
|
|
$210.0
|
|
$210.0
|
Letters of credit
outstanding
|
|
(111.6)
|
|
(109.2)
|
Unused borrowing
capacity
|
|
98.4
|
|
100.8
|
Unrestricted cash
(1)
|
|
393.8
|
(330.4)
|
76.4
|
Total
Liquidity
|
|
$492.2
|
|
$177.2
|
(1)
Includes project-level cash for working capital needs of $11.4
million at June 30, 2015 and $13.0 million at September 30,
2015.
Note: Does not
include restricted cash of $17.6 million at June 30, 2015 and $14.5
million at September 30, 2015.
|
Progress on Debt Reduction
Redemption of Senior Unsecured Notes
The Company completed the redemption of its outstanding
$310.9 million principal amount of
9.0% Notes in July, and used the cash proceeds from the sale of its
Wind Projects to fund the redemption. The 9.0% Notes were
redeemed at a price equal to 104.5% of the principal amount, plus
accrued interest to the redemption date, for a total amount of
$330.4 million. The redemption
premium of $14.0 million and accrued
interest of $5.5 million as well as a
non-cash write-off of deferred financing costs of $9.0 million were recorded in interest expense in
the third quarter of 2015. Annual interest expense savings
associated with the redemption are approximately $28.0 million.
Discretionary Debt Repurchases
In the third quarter of 2015, the Company repurchased
$0.7 million of convertible
debentures under the Normal Course Issuer Bid (NCIB). In the
first nine months of 2015, the Company repurchased $21.6 million of convertible debentures under the
NCIB and $9.0 million of 9.0% Notes,
for total discretionary debt repurchases of $30.6 million year to date. The Company
also had repurchased $3.0 million of
convertible debentures under the NCIB in December 2014. The
NCIB is scheduled to expire on November
10, 2015.
Amortization of APLP Term Loan and Project Debt
In the third quarter of 2015, the Company made repayments on the
APLP term loan totaling $9.7 million
and amortized $4.4 million of
project-level debt. On a year to date basis, repayments
totaled $56.6 million and
$10.7 million, respectively.
For the full year, the Company expects to repay approximately
$65 million of the APLP term loan
through the 50% cash sweep and 1% mandatory annual
amortization. For the full year, amortization of
project-level debt is expected to total approximately $14 million.
Cumulative Debt Reduction since Year End 2013
The Company had consolidated debt at Sept. 30, 2015 of approximately $1.0 billion. This represents a net
reduction of approximately $741
million since year end 2013, including $249 million of project debt associated with the
Wind Projects that was transferred to the buyer of the assets at
closing. The Company has also reduced its share of debt at
equity-owned projects by approximately $76
million, most of which was associated with the two
equity-owned Wind Projects. Thus, total debt has been reduced
approximately $817 million over the
past seven quarters. Cash interest savings associated with
this reduction in debt are more than $65
million on an annualized basis.
Further debt reduction is expected to be achieved through
continued amortization of project-level debt and the APLP term
loan, which together are expected to average approximately
$70 to $80 million annually over the
next two years.
The Company also has an improved corporate maturity
profile. The remaining corporate debt consists of
$292 million (U.S. dollar equivalent)
of convertible debentures maturing in 2017 and 2019. The
Company continues to explore opportunities to address these
maturities.
2015 Guidance
The Company's 2015 guidance is as follows:
- Total Company Project Adjusted EBITDA of $200 to $215 million
- APLP Project Adjusted EBITDA of $148 to
$160 million
- Adjusted Cash Flows from Operating Activities of $95 to $105 million, revised from the previous
range provided August 10, 2015 of
$90 to $105 million
- Adjusted Free Cash Flow of $0 to $10
million
Adjusted Cash Flows from Operating Activities has benefited from
modestly lower G&A expense and slightly lower cash interest
payments relative to previous expectations. Although this
benefits Adjusted Free Cash Flow as well, that benefit is expected
to be offset by higher than expected amortization of the APLP term
loan. Table 4 shows the Company's full-year 2015 guidance and
actual results for the first nine months of 2015.
Atlantic Power
Corporation
Table 4 – Updated
2015 Guidance vs. YTD 2015 Actual Results
(in millions of
U.S. dollars, except as otherwise stated)
|
|
|
Unaudited
|
|
|
2015
Guidance
(Updated
11/5/15)
|
YTD
2015
Actual
|
Project Adjusted
EBITDA
|
|
|
$200 -
$215
|
$158.5
|
Adjusted Cash Flows
from Operating Activities (1)
|
|
|
$95 - $105
|
$77.7
|
Adjusted Free Cash
Flow (2)
|
|
|
$0 - $10
|
$(5.7)
|
APLP Project Adjusted
EBITDA (3)
|
|
|
$148 -
$160
|
$116.0
|
(1)
Adjusted Cash Flows from Operating Activities is used to evaluate
cash flows from operating activities without the effects of changes
in working capital balances, acquisition and disposition expenses,
litigation expenses, severance and restructuring charges, debt
prepayment and redemption costs and cash provided by or used in
discontinued operations. The intent is to reflect normal
operations and remove items that are not reflective of the
long-term operations of the business.
(2)
Adjusted Free Cash Flow is defined as Free Cash Flow excluding
changes in working capital balances, acquisition and disposition
expenses, litigation expense, severance and restructuring charges,
debt prepayment and redemption costs and cash provided by or used
in discontinued operations. Free Cash Flow is defined as cash
flows from operating activities less capex; project-level debt
repayments, including amortization of the APLP term loan; and
distributions to noncontrolling interests, including preferred
share dividends. Adjusted Free Cash Flow is a key measure in
evaluating the amount of cash flow available to the Company to make
common dividend payments.
(3) APLP
is a wholly owned subsidiary of the Company. APLP Project
Adjusted EBITDA is a summation of Project Adjusted EBITDA at each
APLP project, and is calculated in a manner which is consistent
with the Company's Project Adjusted EBITDA
calculation.
Note: Project
Adjusted EBITDA, Adjusted Cash Flows from Operating Activities,
Adjusted Free Cash Flow and APLP Project Adjusted EBITDA are not
recognized measures under GAAP and do not have any standardized
meaning prescribed by GAAP; therefore, these measures may not be
comparable to similar measures presented by other
companies.
|
|
|
|
|
|
|
|
Other Financial Updates
G&A Expense Targets
The Company now expects 2015 corporate G&A of approximately
$32 million versus previous guidance
of $35 million, and is on track to
achieve its corporate G&A cost target of $28 million or lower by 2016, representing a 48%
cumulative reduction from 2013. The 2015 G&A of
$32 million includes approximately
$4 million of severance expense and
approximately $1 million of
restructuring and other charges.
Optimization Investments
The majority of the Company's capital expenditures are
discretionary investments in existing projects designed to increase
their output or improve their efficiency in order to enhance the
margins of these facilities. The Company considers these
investments to be an attractive use of its cash considering the
relatively modest capital requirements and potential for strong
risk-adjusted returns.
The most significant of these investments have been the turbine
upgrades at Curtis Palmer completed in 2013 and 2014, the Nipigon
Once-Through Steam Generator upgrade and feedwater booster pump
installation, completed in 2014 and 2015, respectively, and several
projects at Morris. In total, these represent an investment
of $29 million over the three-year
period 2013 through 2015. The Company expects to realize a
cash flow benefit from completed projects of approximately
$6 million in 2015, at the midpoint
of previous expectations of $4 to $8
million due to lower water flows at Curtis Palmer and high
levels of waste heat at Nipigon. The Company expects this to
increase to approximately $10 million
in 2016, including an initial cash flow contribution from projects
expected to be completed in late 2015 and the first quarter of
2016. This outlook assumes lower waste heat levels in 2016
than in 2015, though still above typical levels, and average water
flows at Curtis Palmer.
The Company expects that optimization-related investments will
total approximately $5 million in
2016.
Maintenance and Capex
The Company projects 2015 capital expenditures of approximately
$14 million, of which approximately
$12 million relates to discretionary
optimization projects described above. The Company has
incurred approximately $10.5 million
of capital expenditures year to date. In the fourth quarter,
the Company expects to receive a customer reimbursement of
approximately $6 million related to
one of the optimization projects. Net of that reimbursement,
2015 capital expenditures are expected to be approximately
$8 million.
In addition to amounts capitalized, the Company incurs
maintenance expense to maintain its projects. Total
maintenance expense is expected to be approximately $46 million for 2015, of which $36.7 million was incurred in the first nine
months of 2015.
Share Purchases by Insiders
In the third quarter, CEO James J.
Moore, Jr. and two directors of the Company purchased a
total of 185,000 common shares of the Company at an average price
of $2.23 per share. Including
those made in the second quarter, purchases by management and
directors this year total approximately 565,000 shares. The
average purchase price in the second quarter of 2015 was
$3.09 per share. There have
been no sales by officers or directors this
year.
U.S. Shareholder Litigation
In late October, the plaintiffs in the U.S. securities class
action suit informed the Company that they would not further pursue
the appeal of the district court ruling in March of this year that
had granted the Company's motion to dismiss the suit. On
Oct. 29, the plaintiffs and the
Company filed a joint stipulation with the United States Court of Appeals for the
First Circuit agreeing to voluntarily dismiss the appeal with
prejudice, with each party bearing its own costs and fees.
The stipulation is pending approval by the appeals court.
Supplementary Financial Information
For further information, attached to this news release is a
summary of Project Adjusted EBITDA by segment for the three and
nine months ended September 30, 2015
and 2014 (Table 8) with a reconciliation to project income (loss);
a bridge from Project Adjusted EBITDA to Cash Distributions from
Projects by segment for the nine months ended September 30, 2015 (Table 9A) and the nine months
ended September 30, 2014 (Table 9B);
a reconciliation of Cash Distributions from Projects and Project
Adjusted EBITDA to net income (loss) and of various non-GAAP cash
flow metrics to cash flows from operating activities for the three
and nine months ended September 30,
2015 and 2014 (Table 10); reconciliations of Adjusted Cash
Flows from Operating Activities and Adjusted Free Cash Flow to cash
flows from operating activities for the three and nine months ended
September 30, 2015 and 2014 (Tables
11A and 11B); and a summary of Project Adjusted EBITDA for selected
projects (top contributors based on the Company's 2015 budget,
representing approximately 90% of total Project Adjusted EBITDA)
for the three and nine months ended September 30, 2015 and 2014 (Table 12).
Investor Conference Call and Webcast
A telephone conference call hosted by Atlantic Power's
management team will be held on Friday, November 6, 2015 at
8:30 AM ET. An accompanying
slide presentation will be available on the Company's website prior
to the call. The telephone numbers for the conference call
are: U.S. Toll Free:
1-888-317-6003; Canada Toll Free: 1-866-284-3684; International
Toll: +1-412-317-6061. Participants will need to provide
access code 2718429 to enter the conference call. The
conference call will also be broadcast over Atlantic Power's
website, with an accompanying slide presentation. Please call
or log in 10 minutes prior to the call. The telephone numbers
to listen to the conference call after it is completed (Instant
Replay) are U.S. Toll Free: 1-877-344-7529; Canada Toll Free
1-855-669-9658; International Toll: +1-412-317-0088. Please
enter conference call number 10073982. The replay will be
available 1 hour after the end of the conference call through
February 11, 2016 at 9:00 AM ET. The conference call will also
be archived on Atlantic Power's website.
About Atlantic Power
Atlantic Power owns and operates a diverse fleet of power
generation assets in the United
States and Canada. The Company's power generation
projects sell electricity to utilities and other large commercial
customers largely under long-term power purchase agreements, which
seek to minimize exposure to changes in commodity prices.
Atlantic Power's power generation projects in operation have an
aggregate gross electric generation capacity of approximately 2,141
megawatts ("MW") in which its aggregate ownership interest is
approximately 1,504 MW. The Company's current portfolio
consists of interests in twenty-three operational power generation
projects across nine states in the United
States and two provinces in Canada.
Atlantic Power trades 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
Amanda Wagemaker, Investor
Relations
(617) 977-2700
info@atlanticpower.com
Copies of certain financial data and other publicly filed
documents are filed 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:
- 2015 Project Adjusted EBITDA will be in the range of
$200 to $215 million;
- 2015 APLP Project Adjusted EBITDA will be in the range of
$148 to $160 million;
- 2015 Adjusted Cash Flows from Operating Activities will be in
the range of $95 to $105
million;
- 2015 Adjusted Free Cash Flow will be in the range of
$0 to $10 million;
- the benefit of lower corporate G&A expense and lower cash
interest payments to guidance for Adjusted Free Cash Flow is
expected to be offset by higher than expected amortization of the
APLP term loan;
- the Company's dividend level;
- the Company expects to have G&A costs of approximately
$32 million in 2015, and expects to
achieve its corporate G&A cost target of $28 million or lower in 2016;
- the Company expects to incur approximately $4 million of severance expense and approximately
$1 million of restructuring charges
in 2015;
- for 2015, the Company projects that capital expenditures will
total approximately $14 million,
before an expected $6 million
customer reimbursement, and total maintenance expense will be
approximately $46 million;
- the Company expects to realize a cash flow benefit from
discretionary investments in its existing projects of approximately
$6 million in 2015;
- the Company expects to realize a cash flow benefit from
discretionary investments in its existing projects of approximately
$10 million in 2016;
- the Company expects that discretionary investments in its fleet
will be approximately $5 million in
2016;
- for the full year 2015, the Company expects to repay
approximately $65 million of the APLP
term loan through the 50% cash sweep and 1% mandatory annual
amortization, and expects amortization of project-level debt to
total approximately $14 million;
- the Company expects to further reduce debt through continued
amortization of project-level debt and the APLP term loan, which
together are expected to average approximately $70 to $80 million annually over the next two
years;
- the Company's expectations regarding the exploration of
opportunities to reshape its remaining corporate debt and address
the maturities of its convertible debentures;
- the nature of any further proceedings in the U.S. and Canadian
securities litigation; 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 plan, including the objective of enhancing the
value of its existing assets through optimization investments and
commercial activities, delevering its balance sheet to improve its
cost of capital and ability to compete for new investments, and
utilizing its core competencies to create proprietary investment
opportunities, and the Company's ability to raise additional
capital for growth and/or debt reduction, and the outcome or impact
on the Company's business of any such actions. Although the
forward-looking statements contained in this news release are based
upon what are believed to be reasonable assumptions, investors
cannot be assured that actual results will be consistent with these
forward-looking statements, and the differences may be material.
These forward-looking statements are made as of the date of this
news release and, except as expressly required by applicable law,
the Company assumes no obligation to update or revise them to
reflect new events or circumstances. The Company's ability to
achieve its longer-term goals, including those described in this
news release, is based on significant assumptions relating to and
including, among other things, the general conditions of the
markets in which it operates, revenues, internal and external
growth opportunities, its ability to sell assets at favorable
prices or at all and general financial market and interest rate
conditions. The Company's actual results may differ, possibly
materially and adversely, from these goals.
Atlantic Power
Corporation
Table 5 –
Consolidated Balance Sheet (in millions of U.S.
dollars)
|
September
30,
|
December
31,
|
2015
|
2014
|
Assets
|
(Unaudited)
|
Current
assets:
|
Cash and cash
equivalents
|
$76.4
|
$106.0
|
Restricted
cash
|
14.5
|
22.5
|
Accounts
receivable
|
41.6
|
46.2
|
Inventory
|
17.6
|
19.3
|
Prepayments and other
current assets
|
12.8
|
13.9
|
Assets held for
sale
|
-
|
792.1
|
Refundable income
taxes
|
-
|
0.2
|
Total current
assets
|
162.9
|
1,000.2
|
|
Property, plant and
equipment, net
|
875.7
|
962.9
|
Equity investments in
unconsolidated affiliates
|
296.5
|
305.2
|
Other intangible
assets, net
|
324.4
|
377.1
|
Goodwill
|
197.2
|
197.2
|
Derivative
instruments asset
|
-
|
1.1
|
Deferred financing
costs
|
44.8
|
62.8
|
Other
assets
|
8.7
|
10.1
|
Total
assets
|
$1,910.2
|
$2,916.6
|
|
Liabilities
|
Current
liabilities:
|
Accounts
payable
|
$7.1
|
$9.4
|
Income taxes
payable
|
0.6
|
-
|
Accrued
interest
|
6.6
|
5.3
|
Other accrued
liabilities
|
35.5
|
30.7
|
Current portion of
long-term debt
|
16.8
|
20.0
|
Current portion of
derivative instruments liability
|
35.1
|
36.1
|
Liabilities held for
sale
|
-
|
271.8
|
Other current
liabilities
|
5.5
|
6.8
|
Total current
liabilities
|
107.2
|
380.1
|
|
Long-term
debt
|
738.3
|
1,145.9
|
Convertible
debentures
|
291.9
|
340.6
|
Derivative
instruments liability
|
30.9
|
47.5
|
Deferred income
taxes
|
112.8
|
92.4
|
Power purchase and
fuel supply agreement liabilities, net
|
28.4
|
33.4
|
Other non-current
liabilities
|
56.4
|
60.2
|
Commitments and
contingencies
|
-
|
-
|
Total
liabilities
|
1,365.9
|
2,100.1
|
|
|
Common shares, no par
value, unlimited authorized shares; 122,118,147 and
121,323,614
issued and
outstanding at September 30, 2015 and December 31, 2014,
respectively
|
1,290.4
|
1,288.4
|
Accumulated other
comprehensive loss
|
(121.1)
|
(68.3)
|
Retained
deficit
|
(846.3)
|
(863.9)
|
Total Atlantic Power
Corporation shareholders' equity
|
323.0
|
356.2
|
Preferred shares
issued by a subsidiary company
|
221.3
|
221.3
|
Noncontrolling
interests held for sale
|
-
|
239.0
|
Total
equity
|
544.3
|
816.5
|
Total liabilities and
equity
|
$1,910.2
|
$2,916.6
|
Atlantic Power
Corporation
Table 6 –
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,
|
|
|
2015
|
2014
|
|
2015
|
2014
|
|
Project
revenue:
|
|
|
|
|
|
Energy
sales
|
$43.4
|
$53.0
|
|
$144.9
|
$177.6
|
|
Energy capacity
revenue
|
45.9
|
49.1
|
|
117.4
|
124.0
|
|
Other
|
18.2
|
19.5
|
|
59.5
|
68.4
|
|
|
107.5
|
121.6
|
|
321.8
|
370.0
|
|
|
|
|
|
|
|
|
Project
expenses:
|
|
|
|
|
|
|
Fuel
|
41.1
|
49.3
|
|
125.3
|
159.5
|
|
Operations and
maintenance
|
24.8
|
28.9
|
|
81.6
|
85.5
|
|
Development
|
-
|
1.0
|
|
1.1
|
2.7
|
|
Depreciation and
amortization
|
27.8
|
30.7
|
|
83.8
|
92.1
|
|
|
93.7
|
109.9
|
|
291.8
|
339.8
|
|
Project other income
(expense):
|
|
|
|
|
|
|
Change in fair value
of derivative instruments
|
3.6
|
1.7
|
|
8.7
|
23.3
|
|
Equity in earnings of
unconsolidated affiliates
|
8.9
|
15.6
|
|
28.3
|
27.8
|
|
Interest expense,
net
|
(2.1)
|
(2.3)
|
|
(6.2)
|
(15.7)
|
|
Impairment
|
-
|
(91.8)
|
|
-
|
(106.6)
|
|
Other income
(expense), net
|
-
|
-
|
|
2.2
|
-
|
|
|
10.4
|
(76.8)
|
|
33.0
|
(71.2)
|
|
Project (loss)
income
|
24.2
|
(65.1)
|
|
63.0
|
(41.0)
|
|
|
|
|
|
|
|
|
Administrative and
other expenses (income):
|
|
|
|
|
|
|
Administration
|
6.9
|
9.2
|
|
23.0
|
26.7
|
|
Interest,
net
|
41.0
|
26.7
|
|
91.3
|
120.8
|
|
Foreign exchange
gain
|
(21.7)
|
(19.0)
|
|
(49.1)
|
(20.4)
|
|
Other income,
net
|
-
|
-
|
|
(3.1)
|
-
|
|
|
26.2
|
16.9
|
|
62.1
|
127.1
|
|
(Loss) income from
continuing operations before income taxes
|
(2.0)
|
(82.0)
|
|
0.9
|
(168.1)
|
|
Income tax expense
(benefit)
|
1.4
|
1.4
|
|
(0.3)
|
(20.0)
|
|
(Loss) income from
continuing operations
|
(3.4)
|
(83.4)
|
|
1.2
|
(148.1)
|
|
Net income (loss)
from discontinued operations, net of tax (1)
|
(0.5)
|
(7.7)
|
|
20.6
|
(21.8)
|
|
Net income
(loss)
|
(3.9)
|
(91.1)
|
|
21.8
|
(169.9)
|
|
Net loss attributable
to noncontrolling interests of discontinued operations
|
-
|
(5.1)
|
|
(11.0)
|
(11.8)
|
|
Net income
attributable to preferred share dividends of a subsidiary
company
|
2.1
|
2.9
|
|
6.7
|
8.8
|
|
Net income (loss)
attributable to Atlantic Power Corporation
|
$(6.0)
|
$(88.9)
|
|
$26.1
|
$(166.9)
|
|
|
|
|
|
|
|
|
Basic and diluted
earnings per share:
|
|
|
|
|
|
|
Loss from continuing
operations attributable to Atlantic Power Corporation
|
$(0.05)
|
$(0.72)
|
|
$(0.05)
|
$(1.30)
|
|
Income (loss) from
discontinued operations, net of tax
|
-
|
(0.02)
|
|
0.26
|
(0.08)
|
|
Net income (loss)
attributable to Atlantic Power Corporation
|
$(0.05)
|
$(0.74)
|
|
$0.21
|
$(1.38)
|
|
Weighted average
number of common shares outstanding:
|
|
|
|
|
|
|
Basic
|
122.1
|
120.7
|
|
121.8
|
120.6
|
|
Diluted
|
122.2
|
120.7
|
|
121.9
|
120.6
|
|
|
|
|
|
|
|
|
Dividends paid per
common share:
|
$0.02
|
$0.06
|
|
$0.07
|
$0.23
|
|
(1) Includes
contributions from the Wind Projects and Greeley, which are
components of discontinued operations.
|
|
|
|
|
|
|
|
|
|
|
|
Atlantic Power
Corporation
Table 7 –
Consolidated Statements of Cash Flows (in millions of U.S.
dollars)
|
|
|
|
Unaudited
|
|
|
|
|
|
|
Nine months ended
September 30,
|
|
|
|
|
|
2015
|
2014
|
|
Cash flows from
operating activities:
|
|
|
|
|
|
|
Net (loss)
income
|
|
|
|
$21.8
|
$(169.9)
|
|
Adjustments to
reconcile to net cash provided by operating activities
|
|
|
|
|
|
|
Depreciation and
amortization
|
|
|
|
94.1
|
122.3
|
|
Gain on sale of
discontinued operations
|
|
|
|
(47.2)
|
(2.1)
|
|
Gain on sale of
development project and other assets
|
|
|
|
(2.3)
|
-
|
|
Gain on sale of equity
investment
|
|
|
|
-
|
(8.6)
|
|
Gain on purchase and
cancellation of convertible debentures
|
|
|
|
(3.1)
|
-
|
|
Long-term incentive
plan expense
|
|
|
|
2.0
|
1.8
|
|
Impairment
charges
|
|
|
|
-
|
106.6
|
|
Equity in earnings
from unconsolidated affiliates
|
|
|
|
(28.3)
|
(18.8)
|
|
Distributions from
unconsolidated affiliates
|
|
|
|
40.0
|
52.8
|
|
Unrealized foreign
exchange gain
|
|
|
|
(49.3)
|
(21.0)
|
|
Change in fair value
of derivative instruments
|
|
|
|
(8.0)
|
(12.3)
|
|
Change in deferred
income taxes
|
|
|
|
23.6
|
(11.1)
|
|
Change in other
operating balances
|
|
|
|
|
|
|
Accounts
receivable
|
|
|
|
4.3
|
(0.3)
|
|
Inventory
|
|
|
|
1.7
|
(4.3)
|
|
Prepayments,
refundable income taxes and other assets
|
|
|
|
20.2
|
18.2
|
|
Accounts
payable
|
|
|
|
(6.0)
|
(4.8)
|
|
Accruals and other
liabilities
|
|
|
|
4.2
|
(2.6)
|
|
Cash provided by
operating activities
|
|
|
|
67.7
|
45.9
|
|
|
|
|
|
|
|
|
Cash flows provided
by investing activities
|
|
|
|
|
|
|
Change in restricted
cash
|
|
|
|
8.0
|
78.2
|
|
Proceeds from sale of
assets, net of cash sold
|
|
|
|
326.3
|
0.9
|
|
Contribution to
unconsolidated affiliate
|
|
|
|
(0.5)
|
8.6
|
|
Capitalized
development costs
|
|
|
|
(0.8)
|
-
|
|
Purchase of property,
plant and equipment
|
|
|
|
(9.4)
|
(11.3)
|
|
Cash provided by
investing activities
|
|
|
|
323.6
|
76.4
|
|
|
|
|
|
|
|
|
Cash flows used in
financing activities
|
|
|
|
|
|
|
Proceeds from senior
secured term loan facility
|
|
|
|
-
|
600.0
|
|
Repayment of corporate
and project-level debt
|
|
|
|
(387.1)
|
(621.9)
|
|
Repayment of
convertible debentures
|
|
|
|
(18.7)
|
-
|
|
Deferred financing
costs
|
|
|
|
-
|
(39.0)
|
|
Dividends paid to
common shareholders
|
|
|
|
(8.5)
|
(32.0)
|
|
Dividends paid to
noncontrolling interests
|
|
|
|
(10.5)
|
(20.4)
|
|
Cash used in
financing activities
|
|
|
|
(424.8)
|
(113.3)
|
|
|
|
|
|
|
|
|
Net increase
(decrease) in cash and cash equivalents
|
|
|
|
(33.5)
|
9.0
|
|
Cash and cash
equivalents at beginning of period at discontinued
operations
|
|
|
|
3.9
|
-
|
|
Cash and cash
equivalents at beginning of period
|
|
|
|
106.0
|
158.6
|
|
Cash and cash
equivalents at end of period
|
|
|
|
$76.4
|
$167.6
|
|
|
|
|
|
|
|
|
Supplemental cash
flow information
|
|
|
|
|
|
|
Interest
paid
|
|
|
|
$75.5
|
$124.4
|
|
Income taxes paid,
net
|
|
|
|
$4.1
|
$1.0
|
|
Accruals for
construction in progress
|
|
|
|
$1.2
|
$8.2
|
|
|
|
|
|
|
|
|
|
|
|
Regulation G 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. 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)
is provided in Table 8 below. Investors are cautioned that
the Company may calculate this measure in a manner that is
different from other companies.
Cash Distributions from Projects, Adjusted Cash Flows from
Operating Activities, Free Cash Flow and Adjusted Free Cash
Flow are not measures recognized under GAAP and do not have
standardized meanings prescribed by GAAP, and are therefore
unlikely to be comparable to similar measures presented by other
companies. Adjusted Cash Flows from Operating Activities is
used to evaluate cash flows from operating activities without the
effects of changes in working capital balances, acquisition and
disposition expenses, litigation expenses, severance and
restructuring charges, and cash provided by or used in discontinued
operations. The intent is to reflect normal operations and
remove items that are not reflective of the long-term operations of
the business. Free Cash Flow is defined as cash flows from
operating activities less capex; project-level debt repayments,
including amortization of the new term loan; and distributions to
noncontrolling interests, including preferred share dividends.
Adjusted Free Cash Flow is defined as Free Cash Flow excluding
changes in working capital balances, acquisition and disposition
expenses, litigation expense, severance and restructuring charges,
and cash provided by or used in discontinued operations.
Management believes that these non-GAAP cash flow measures
are relevant supplemental measures of the Company's ability to earn
and distribute cash returns to investors. A bridge of Project
Adjusted EBITDA to Cash Distributions from Projects is provided in
Tables 9A and 9B on page 16. A reconciliation of Free Cash
Flow to cash flows from operating activities is provided in Table
10 on page 17 of this release. Reconciliations of Adjusted
Free Cash Flow and Adjusted Cash Flows from Operating Activities to
cash flows from operating activities are provided in Tables 11A and
11B on pages 18 and 19 of this release. Investors are
cautioned that the Company may calculate these measures in a manner
that is different from other companies.
Atlantic Power
Corporation
Table 8 – Project
Adjusted EBITDA by Segment (in millions of U.S.
dollars)
Unaudited
|
|
|
|
|
|
|
Three months ended
September 30,
|
Nine months ended
September 30,
|
|
2015
|
2014
|
2015
|
2014
|
Project Adjusted
EBITDA by segment
|
|
|
|
|
East U.S.
|
$27.4
|
$27.3
|
$81.0
|
$82.4
|
West U.S.
(1)
|
21.4
|
21.3
|
37.1
|
44.8
|
Canada
|
7.6
|
12.3
|
43.0
|
51.6
|
Un-allocated
Corporate
|
(0.4)
|
(2.8)
|
(2.6)
|
(6.2)
|
Total
|
$56.0
|
$58.1
|
$158.5
|
$172.6
|
|
|
|
|
|
Reconciliation to
project income
|
|
|
|
|
Depreciation and
amortization
|
32.8
|
38.9
|
98.9
|
120.6
|
Interest expense,
net
|
2.5
|
3.0
|
7.7
|
18.1
|
Change in the fair
value of derivative instruments
|
(3.6)
|
(1.8)
|
(8.7)
|
(23.1)
|
Other (income)
expense
|
0.1
|
83.1
|
(2.4)
|
98.0
|
Project income
(loss)
|
$24.2
|
$(65.1)
|
$63.0
|
$(41.0)
|
(1)
Excludes Greeley, which is a component of discontinued
operations.
Notes: Table 8
excludes the Wind Projects, which comprise the entirety of the
former Wind segment. The Wind Projects are designated as
discontinued operations for the three and nine months ended
September 30, 2015 and 2014.
Table 8 presents
Project Adjusted EBITDA, which is not a recognized measure under
GAAP and does not have any standardized meaning prescribed by GAAP;
therefore, this measure may not be comparable to a similar measure
presented by other companies.
|
|
|
|
|
|
Atlantic Power
Corporation
Table 9A – Cash
Distributions from Projects (by Segment, in millions of U.S.
dollars)
Nine months ended
September 30, 2015 (Unaudited)
|
Unaudited
|
Project
Adjusted
EBITDA
|
Repayment of
long-term debt
|
Interest
expense,
net
|
Capital
expenditures
|
Other,
including
changes in working
capital
|
Cash
Distributions
from Projects
|
|
Segment
|
|
|
|
|
|
|
|
East
U.S.
|
|
|
|
|
|
|
|
Consolidated
|
$50.4
|
$(6.1)
|
$(5.5)
|
$(7.2)
|
$1.7
|
$33.3
|
|
Equity
method
|
30.6
|
(4.5)
|
(2.0)
|
(0.2)
|
5.2
|
29.1
|
|
Total
|
81.0
|
(10.6)
|
(7.5)
|
(7.4)
|
6.9
|
62.4
|
|
West
U.S.
|
|
|
|
|
|
|
|
Consolidated
|
27.3
|
-
|
-
|
(0.6)
|
(2.3)
|
24.4
|
|
Equity
method
|
9.8
|
-
|
-
|
-
|
0.8
|
10.6
|
|
Total
|
37.1
|
-
|
-
|
(0.6)
|
(1.5)
|
35.0
|
|
Canada
|
|
|
|
|
|
|
|
Consolidated
|
43.0
|
(0.2)
|
-
|
(2.5)
|
8.6
|
48.9
|
|
Equity
method
|
-
|
-
|
-
|
-
|
-
|
-
|
|
Total
|
43.0
|
(0.2)
|
-
|
(2.5)
|
8.6
|
48.9
|
|
Total
consolidated
|
120.7
|
(6.3)
|
(5.5)
|
(10.3)
|
8.0
|
106.6
|
|
Total equity
method
|
40.4
|
(4.5)
|
(2.0)
|
(0.2)
|
6.0
|
39.7
|
|
Un-allocated
corporate
|
(2.6)
|
-
|
-
|
0.2
|
2.4
|
-
|
|
Total
|
$158.5
|
$(10.8)
|
$(7.5)
|
$(10.3)
|
$16.4
|
$146.3
|
|
Note: Table 9A
presents Cash Distributions from Projects and Project Adjusted
EBITDA, which are not recognized measures under GAAP and do not
have any standardized meanings prescribed by GAAP; therefore, these
measures may not be comparable to similar measures presented by
other companies.
|
|
|
|
Atlantic Power
Corporation
Table 9B – Cash
Distributions from Projects (by Segment, in millions of U.S.
dollars)
Nine months ended
September 30, 2014 (Unaudited)
|
|
Project
Adjusted
EBITDA
|
Repayment of
long-term debt
|
Interest
expense,
net
|
Capital
expenditures
|
Other,
including
changes in working
capital
|
Cash
Distributions from
Projects
|
|
Segment
|
|
|
|
|
|
|
|
East
U.S.
|
|
|
|
|
|
|
|
Consolidated
|
$46.6
|
$(12.2)
|
$(5.7)
|
$(1.2)
|
$3.8
|
$31.3
|
|
Equity
method
|
35.8
|
(3.8)
|
(6.2)
|
(0.6)
|
1.2
|
26.4
|
|
Total
|
82.4
|
(16.0)
|
(11.9)
|
(1.8)
|
5.0
|
57.7
|
|
West
U.S.
|
|
|
|
|
|
|
|
Consolidated
|
34.0
|
-
|
-
|
(0.5)
|
3.1
|
36.6
|
|
Equity
method
|
10.8
|
(1.0)
|
(0.1)
|
-
|
1.1
|
10.8
|
|
Total
|
44.8
|
(1.0)
|
(0.1)
|
(0.5)
|
4.2
|
47.4
|
|
Canada
|
|
|
|
|
|
|
|
Consolidated
|
51.6
|
(0.1)
|
-
|
(6.9)
|
2.7
|
47.3
|
|
Equity
method
|
-
|
-
|
-
|
-
|
-
|
-
|
|
Total
|
51.6
|
(0.1)
|
-
|
(6.9)
|
2.7
|
47.3
|
|
Total
consolidated
|
132.2
|
(12.3)
|
(5.7)
|
(8.6)
|
9.6
|
115.2
|
|
Total equity
method
|
46.6
|
(4.8)
|
(6.3)
|
(0.6)
|
2.3
|
37.2
|
|
Un-allocated
corporate
|
(6.2)
|
-
|
-
|
(1.0)
|
7.2
|
-
|
|
Total
|
$172.6
|
$(17.1)
|
$(12.0)
|
$(10.2)
|
$19.1
|
$152.4
|
|
Note: Table 9B
presents Cash Distributions from Projects and Project Adjusted
EBITDA, which are not recognized measures under GAAP and do not
have any standardized meanings prescribed by GAAP; therefore, these
measures may not be comparable to similar measures presented by
other companies.
|
|
Atlantic Power
Corporation
Table 10 – Free
Cash Flow (in millions of U.S. dollars)
Unaudited
|
|
|
|
|
|
Three months
ended
September
30,
|
|
Nine months
ended
September
30,
|
|
|
2015
|
2014
|
|
2015
|
2014
|
|
Cash Distributions
from Projects
|
$51.5
|
$40.8
|
|
$146.3
|
$152.4
|
|
Repayment of long-term
debt
|
(4.4)
|
(4.2)
|
|
(10.8)
|
(17.1)
|
|
Interest expense,
net
|
(2.5)
|
(2.7)
|
|
(7.5)
|
(12.0)
|
|
Capital
expenditures
|
(5.2)
|
(7.3)
|
|
(10.3)
|
(10.2)
|
|
Other, including
changes in working capital
|
7.6
|
(3.1)
|
|
16.4
|
19.1
|
|
Project Adjusted
EBITDA
|
$56.0
|
$58.1
|
|
$158.5
|
$172.6
|
|
Depreciation and
amortization
|
32.8
|
38.9
|
|
98.9
|
120.6
|
|
Interest expense,
net
|
2.5
|
3.0
|
|
7.7
|
18.1
|
|
Change in the fair
value of derivative instruments
|
(3.6)
|
(1.8)
|
|
(8.7)
|
(23.1)
|
|
Other (income)
expense
|
0.1
|
83.1
|
|
(2.4)
|
98.0
|
|
Project income
(loss)
|
$24.2
|
$(65.1)
|
|
$63.0
|
$(41.0)
|
|
Administrative and
other expenses (income)
|
26.2
|
16.9
|
|
62.1
|
127.1
|
|
Income tax expense
(benefit)
|
1.4
|
1.4
|
|
(0.3)
|
(20.0)
|
|
Net income (loss) from
discontinued operations, net of tax
|
(0.5)
|
(7.7)
|
|
20.6
|
(21.8)
|
|
Net income
(loss)
|
$(3.9)
|
$(91.1)
|
|
$21.8
|
$(169.9)
|
|
Adjustments to
reconcile to net cash provided by operating activities
|
10.7
|
117.4
|
|
21.5
|
209.6
|
|
Change in other
operating balances
|
7.7
|
14.1
|
|
24.4
|
6.2
|
|
Cash flows from
operating activities
|
$14.5
|
$40.4
|
|
$67.7
|
$45.9
|
|
Term loan facility
repayments (1)
|
(9.7)
|
(9.6)
|
|
(56.6)
|
(47.1)
|
|
Project-level debt
repayments
|
(4.4)
|
(4.2)
|
|
(10.7)
|
(19.6)
|
|
Purchases of property,
plant and equipment (2)
|
(4.4)
|
(7.5)
|
|
(9.4)
|
(10.0)
|
|
Distributions to
noncontrolling interests (3)
|
-
|
(2.9)
|
|
(3.8)
|
(8.8)
|
|
Dividends on preferred
shares of a subsidiary company
|
(2.1)
|
(3.6)
|
|
(6.7)
|
(8.8)
|
|
Free Cash
Flow
|
$(6.1)
|
$12.6
|
|
$(19.5)
|
$(48.4)
|
|
Additional GAAP cash
flow measures:
|
|
|
|
|
|
|
Cash flows from
investing activities
|
$(1.3)
|
$0.9
|
|
$323.6
|
$76.4
|
|
Cash flows from
financing activities
|
(330.5)
|
(31.4)
|
|
(424.8)
|
(113.3)
|
|
(1)
Includes mandatory 1% annual amortization and 50% excess cash flow
repayments by the Partnership.
(2)
Excludes construction costs related to the Company's Canadian Hills
project in 2014.
(3)
Distributions to noncontrolling interests include distributions to
the tax equity investors at Canadian Hills and to the other 50%
owner of Rockland. These projects were sold in June
2015.
Note: Table 10
presents Cash Distributions from Projects, Project Adjusted EBITDA
and Free Cash Flow, which are not recognized measures under GAAP
and do not have any standardized meanings prescribed by GAAP;
therefore, these measures may not be comparable to similar measures
presented by other companies.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Atlantic Power
Corporation
Table 11A –
Adjusted Cash Flows from Operating Activities and Adjusted Free
Cash Flow (in millions of U.S. dollars)
Three months ended
September 30, 2015 and 2014 (Unaudited)
|
|
Three months
ended
September 30,
2015
|
Three months
ended
September 30,
2014
|
|
|
Continuing
Operations
|
Discontinued
Operations
|
Total
|
Continuing
Operations
|
Discontinued
Operations
|
Total
|
|
Project Adjusted
EBITDA
|
$56.0
|
$-
|
$56.0
|
$58.1
|
$14.1
|
$72.2
|
|
Adjustment for equity
method projects (1)
|
0.1
|
-
|
0.1
|
(1.5)
|
(0.5)
|
(2.0)
|
|
Corporate G&A
expense
|
(6.9)
|
-
|
(6.9)
|
(9.2)
|
-
|
(9.2)
|
|
Cash interest
payments
|
(29.2)
|
-
|
(29.2)
|
(7.8)
|
(1.9)
|
(9.7)
|
|
Cash taxes
|
(1.2)
|
(1.2)
|
(2.4)
|
-
|
-
|
-
|
|
Other, including
changes in working capital
|
(3.1)
|
-
|
(3.1)
|
(9.9)
|
(0.9)
|
(10.9)
|
|
Cash flows from
operating activities
|
$15.7
|
$(1.2)
|
$14.5
|
$29.7
|
$10.8
|
$40.4
|
|
Changes in other
operating balances
|
3.1
|
-
|
3.1
|
9.9
|
0.9
|
10.9
|
|
Severance
charges
|
0.4
|
-
|
0.4
|
4.4
|
-
|
4.4
|
|
Restructuring and
other charges
|
-
|
-
|
-
|
0.9
|
-
|
0.9
|
|
Shareholder litigation
expenses
|
-
|
-
|
-
|
(0.7)
|
-
|
(0.7)
|
|
Refinancing
transaction costs (Q1 2014)
|
-
|
-
|
-
|
-
|
-
|
-
|
|
Debt redemption costs
(9.0% Notes) (Q3 2015)
|
19.5
|
-
|
19.5
|
-
|
-
|
-
|
|
Adjusted Cash
Flows from Operating Activities
|
$38.7
|
$(1.2)
|
$37.5
|
$44.2
|
$11.7
|
$55.9
|
|
Term loan facility
repayments (2)
|
(9.7)
|
-
|
(9.7)
|
(9.6)
|
-
|
(9.6)
|
|
Project-level debt
repayments
|
(4.4)
|
-
|
(4.4)
|
(4.2)
|
-
|
(4.2)
|
|
Purchases of property,
plant and equipment (3)
|
(4.4)
|
-
|
(4.4)
|
(7.4)
|
(0.1)
|
(7.5)
|
|
Distributions to
noncontrolling interests (4)
|
-
|
-
|
-
|
-
|
(3.6)
|
(3.6)
|
|
Dividends on preferred
shares of a subsidiary company
|
(2.1)
|
-
|
(2.1)
|
(2.9)
|
-
|
(2.9)
|
|
Adjusted Free Cash
Flow
|
$18.1
|
$(1.2)
|
$16.9
|
$20.1
|
$8.0
|
$28.1
|
|
Additional GAAP cash
flow measures:
|
|
|
|
|
|
|
|
Cash flows from
investing activities
|
$(1.3)
|
$-
|
$(1.3)
|
$0.5
|
$0.4
|
$0.9
|
|
Cash flows from
financing activities
|
(330.5)
|
-
|
(330.5)
|
(18.9)
|
(12.5)
|
(31.4)
|
|
(1)
Represents difference between Project Adjusted EBITDA and cash
distributions from equity method projects.
(2)
Includes mandatory 1% annual amortization and 50% excess cash flow
repayments by the Partnership.
(3)
Excludes construction costs related to the Company's Canadian Hills
project in 2014.
(4)
Distributions to noncontrolling interests primarily include
distributions, if any, to the tax equity investors at Canadian
Hills and to the other 50% owner of Rockland.
Note: Table 11A
presents Project Adjusted EBITDA, Adjusted Cash Flows from
Operating Activities and Adjusted Free Cash Flow, which are not
recognized measures under GAAP and do not have any standardized
meanings prescribed by GAAP; therefore, these measures may not be
comparable to similar measures presented by other
companies.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Atlantic Power
Corporation
Table 11B –
Adjusted Cash Flows from Operating Activities and Adjusted Free
Cash Flow (in millions of U.S. dollars)
Nine months ended
September 30, 2015 and 2014 (Unaudited)
|
|
|
Nine months
ended
September 30,
2015
|
Nine months
ended
September 30,
2014
|
|
|
Continuing
Operations
|
Discontinued
Operations
|
Total
|
Continuing
Operations
|
Discontinued
Operations
|
Total
|
|
Project Adjusted
EBITDA
|
$158.5
|
$28.3
|
$186.8
|
$172.6
|
$49.0
|
$221.6
|
|
Adjustment for equity
method projects (1)
|
(3.8)
|
(2.7)
|
(6.5)
|
(11.3)
|
(3.2)
|
(14.5)
|
|
Corporate G&A
expense
|
(23.0)
|
-
|
(23.0)
|
(26.7)
|
-
|
(26.7)
|
|
Cash interest
payments
|
(75.5)
|
-
|
(75.5)
|
(115.4)
|
(9.0)
|
(124.4)
|
|
Cash taxes
|
(2.9)
|
(1.2)
|
(4.1)
|
(1.0)
|
-
|
(1.0)
|
|
Other, including
changes in working capital
|
(6.3)
|
(3.7)
|
(10.0)
|
(9.3)
|
0.1
|
(9.1)
|
|
Cash flows from
operating activities
|
$47.0
|
$20.7
|
$67.7
|
$8.9
|
$36.9
|
$45.9
|
|
Changes in other
operating balances
|
6.3
|
3.7
|
10.0
|
9.3
|
(0.1)
|
9.1
|
|
Severance
charges
|
3.8
|
-
|
3.8
|
5.2
|
-
|
5.2
|
|
Restructuring and
other charges
|
0.5
|
-
|
0.5
|
1.0
|
-
|
1.0
|
|
Shareholder litigation
expenses
|
0.6
|
-
|
0.6
|
0.8
|
-
|
0.8
|
|
Refinancing
transaction costs (Q1 2014)
|
-
|
-
|
-
|
49.4
|
-
|
49.4
|
|
Debt redemption costs
(9.0% Notes) (Q3 2015)
|
19.5
|
-
|
19.5
|
-
|
-
|
-
|
|
Adjusted Cash
Flows from Operating Activities
|
$77.7
|
$24.4
|
$102.1
|
$74.6
|
$36.8
|
$111.4
|
|
Term loan facility
repayments (2)
|
(56.6)
|
-
|
(56.6)
|
(47.1)
|
-
|
(47.1)
|
|
Project-level debt
repayments (3)
|
(10.7)
|
-
|
(10.7)
|
(8.0)
|
(3.5)
|
(11.5)
|
|
Purchases of property,
plant and equipment (4)
|
(9.4)
|
0.1
|
(9.3)
|
(9.6)
|
(0.4)
|
(10.0)
|
|
Distributions to
noncontrolling interests (5)
|
-
|
(3.8)
|
(3.8)
|
-
|
(8.8)
|
(8.8)
|
|
Dividends on preferred
shares of a subsidiary company
|
(6.7)
|
-
|
(6.7)
|
(8.8)
|
-
|
(8.8)
|
|
Adjusted Free Cash
Flow
|
$(5.7)
|
$20.7
|
$15.0
|
$1.1
|
$24.1
|
$25.2
|
|
Additional GAAP cash
flow measures:
|
|
|
|
|
|
|
|
Cash flows from
investing activities
|
$336.4
|
$(12.8)
|
$323.6
|
$69.5
|
$6.9
|
$76.4
|
|
Cash flows from
financing activities
|
(411.8)
|
(13.0)
|
(424.8)
|
(71.9)
|
(41.4)
|
(113.3)
|
|
(1)
Represents difference between Project Adjusted EBITDA and cash
distributions from equity method projects.
(2)
Includes mandatory 1% annual amortization and 50% excess cash flow
repayments by the Partnership.
(3) 2014
continuing operations and total columns exclude $8.1 million
repayment of Piedmont principal at term loan conversion in February
2014.
(4)
Excludes construction costs related to the Company's Canadian Hills
project in 2014.
(5)
Distributions to noncontrolling interests primarily include
distributions, if any, to the tax equity investors at Canadian
Hills and to the other 50% owner of Rockland.
Note: Table 11B
presents Project Adjusted EBITDA, Adjusted Cash Flows from
Operating Activities and Adjusted Free Cash Flow, which are not
recognized measures under GAAP and do not have any standardized
meanings prescribed by GAAP; therefore, these measures may not be
comparable to similar measures presented by other
companies.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Atlantic Power
Corporation
Table 12 – Project
Adjusted EBITDA by Project (for Selected
Projects)
(in millions of
U.S. dollars)
Unaudited
|
|
|
|
|
Three months
ended
September
30,
|
Nine months
ended
September
30,
|
|
|
|
|
2015
|
2014
|
2015
|
2014
|
|
East
U.S.
|
|
Accounting
|
|
|
|
|
|
Cadillac
|
|
Consolidated
|
$1.6
|
$2.2
|
$6.1
|
$5.4
|
|
Curtis
Palmer
|
|
Consolidated
|
5.4
|
5.5
|
20.9
|
24.2
|
|
Morris
|
|
Consolidated
|
4.5
|
3.0
|
13.3
|
9.6
|
|
Piedmont
|
|
Consolidated
|
5.6
|
3.4
|
7.7
|
4.2
|
|
Other
(1)
|
|
Consolidated
|
0.7
|
1.0
|
2.4
|
3.2
|
|
Chambers
|
|
Equity
method
|
4.0
|
4.3
|
13.7
|
14.1
|
|
Orlando
|
|
Equity
method
|
5.4
|
5.3
|
16.6
|
10.0
|
|
Other
(2)
|
|
Equity
method
|
0.2
|
2.6
|
0.3
|
11.7
|
|
Total
|
|
|
27.4
|
27.3
|
81.0
|
82.4
|
|
West
U.S.
|
|
|
|
|
|
|
|
Manchief
|
|
Consolidated
|
3.8
|
3.7
|
2.4
|
10.9
|
|
Naval
Station
|
|
Consolidated
|
4.3
|
4.4
|
8.9
|
9.1
|
|
North
Island
|
|
Consolidated
|
3.3
|
3.1
|
7.0
|
4.3
|
|
Other
(3)
|
|
Consolidated
|
6.7
|
6.9
|
9.0
|
9.7
|
|
Frederickson
|
|
Equity
method
|
3.2
|
3.0
|
9.2
|
8.9
|
|
Other
(4)
|
|
Equity
method
|
0.1
|
0.2
|
0.6
|
1.9
|
|
Total
|
|
|
21.4
|
21.3
|
37.1
|
44.8
|
|
Canada
|
|
|
|
|
|
|
|
Calstock
|
|
Consolidated
|
2.3
|
0.6
|
7.0
|
3.9
|
|
Kapuskasing
|
|
Consolidated
|
(0.3)
|
1.2
|
4.1
|
6.1
|
|
Nipigon
|
|
Consolidated
|
3.3
|
1.4
|
13.1
|
10.1
|
|
North Bay
|
|
Consolidated
|
(1.2)
|
0.9
|
3.6
|
6.9
|
|
Williams
Lake
|
|
Consolidated
|
4.9
|
5.8
|
12.5
|
12.6
|
|
Other
(5)
|
|
Consolidated
|
(1.4)
|
2.4
|
2.7
|
12.0
|
|
Total
|
|
|
7.6
|
12.3
|
43.0
|
51.6
|
|
Totals
|
|
|
|
|
|
|
|
Consolidated
projects
|
|
|
43.5
|
45.5
|
120.7
|
132.2
|
|
Equity method
projects
|
|
|
12.9
|
15.4
|
40.4
|
46.6
|
|
Un-allocated
corporate
|
|
|
(0.4)
|
(2.8)
|
(2.6)
|
(6.2)
|
|
Total Project
Adjusted EBITDA
|
|
|
$56.0
|
$58.1
|
$158.5
|
$172.6
|
|
|
|
|
|
|
|
|
|
Reconciliation to
project income (loss)
|
|
|
|
|
|
|
|
Depreciation and
amortization
|
|
|
$32.8
|
$38.9
|
$98.9
|
$120.6
|
|
Interest expense,
net
|
|
|
2.5
|
3.0
|
7.7
|
18.1
|
|
Change in the fair
value of derivative instruments
|
|
|
(3.6)
|
(1.8)
|
(8.7)
|
(23.1)
|
|
Other (income)
expense
|
|
|
0.1
|
83.1
|
(2.4)
|
98.0
|
|
Project income
(loss)
|
|
|
$24.2
|
$(65.1)
|
$63.0
|
$(41.0)
|
|
(1)
Kenilworth
(2)
Selkirk
(3) Naval Training
Station and Oxnard
(4) Q3 2014: Koma
Kulshan; YTD September 2014: Koma Kulshan and Delta-Person;
Q3 and YTD June 2015: Koma Kulshan
(5) Tunis, Moresby
Lake and Mamquam,
Notes: Table 12
presents Project Adjusted EBITDA, which is not a recognized measure
under GAAP and does not have any standardized meaning prescribed by
GAAP; therefore, this measure may not be comparable to a similar
measure presented by other companies. The Company has not
reconciled non-GAAP financial measures relating to individual
projects to the directly comparable GAAP measures due to the
difficulty in making the relevant adjustments on an individual
project basis.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
To view the original version on PR Newswire,
visit:http://www.prnewswire.com/news-releases/atlantic-power-corporation-releases-third-quarter-2015-results-300173680.html
SOURCE Atlantic Power Corporation