BOSTON, Nov. 6, 2014 /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, 2014.
"Our results year to date have been driven by strong wind
generation, increased waste heat at our Ontario projects, and lower maintenance and
administrative expenses. We are encouraged by the progress we
have made in improving the performance of our projects and reducing
our costs, which we expect will benefit future periods. We
also maintained a strong liquidity position of $272 million, including $168 million of unrestricted cash," said
Kenneth Hartwick, interim President
and CEO of Atlantic Power. "Although our availability
improved this quarter, we had lower dispatch at a few projects
primarily due to a mild summer. Notwithstanding that, we
still expect 2014 Project Adjusted EBITDA to be in the middle of
our initial guidance range. During the quarter, we incurred
severance costs associated with recent management changes and steps
to reduce our cost structure. These costs will reduce Free
Cash Flow, and thus we now expect our Free Cash Flow to be in the
lower end of our initial guidance range."
"Following our review of strategic options, our Board determined
that it was in the best interest of the Company and its
stakeholders for the Company to remain independent. Since
then, we have taken further steps to ensure an efficient cost
structure and narrowed our capital allocation priorities in the
near term to debt reduction and attractive investments in existing
projects," Mr. Hartwick continued. "We expect to fund these
investments with existing Free Cash Flow but are also evaluating
potential asset sales and partnerships with the intended use of
proceeds to reduce high-cost debt. Deleveraging, reducing our
financial risk and lowering our cost of capital should improve our
ability to regain effective access to the capital markets, which
would allow us to grow as well as address debt maturities in 2017
and beyond. We believe that achieving these goals will result
in meaningful value creation for shareholders over time."
All amounts are in U.S. dollars and are approximate unless
otherwise indicated. 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 "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 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.
Strategic Priorities
- Focus on improvement in credit metrics to achieve competitive
cost of capital and ready access to capital markets
- Target significant reduction in leverage using proceeds from
selective asset sales under consideration
- Repurchase outstanding debt securities where economically
attractive; implementing normal course issuer bid (NCIB) for at
least $15 million and up to 10% of
outstanding convertible debentures ($35
million)
- Deploy capital in high return projects and aggressively reduce
corporate expenses
- Continue to make optimization investments in existing fleet
with attractive expected returns (five-year payback or 20% current
yield); targeting approximately $5 to $10
million of such investments in 2015
- Achieve at least $7 million
reduction in general and administrative (G&A) expense in
addition to $8 million already
achieved, for total expected annual savings of at least
$15 million in 2015 relative to 2013;
further potential cost reductions under evaluation
- Longer-term goal of successfully pursuing value-enhancing
acquisition, development or joint venture opportunities
Recent Financial and Operational Accomplishments
- Completed major optimization projects planned for this year and
expect to realize annual run-rate cash flow benefit of at least
$8 million in 2015, at least half of
which has been realized this year
- Implemented personnel reductions and took other steps
consistent with G&A savings target for 2015
- Reduced outstanding amount of APLP term loan through mandatory
amortization and cash sweep and amortized project debt by
$73 million year to date; on track to
achieve approximate $85 million
reduction by year-end 2014
- September 30th liquidity of
$272 million, including $168 million of unrestricted cash, of which
$41 million was used to repay the
Cdn$44.8 million convertible
debenture at maturity on October 31;
expected annual interest savings in 2015 of $2.7 million; no other non-amortizing corporate
debt maturities until March 2017
- Settled dispute with Zachry for $5
million, previously accrued and to be paid from Piedmont restricted cash
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,
|
|
2014
|
2013
|
2014
|
2013
|
Excluding results
from discontinued operations(1)
|
|
|
|
|
Project
revenue
|
$138.3
|
$140.0
|
$426.8
|
$413.4
|
Project (loss)
income
|
(68.6)
|
4.4
|
(52.2)
|
56.4
|
Project Adjusted
EBITDA
|
72.2
|
75.0
|
221.6
|
211.4
|
Cash Distributions
from Projects
|
51.2
|
65.7
|
187.0
|
169.7
|
Aggregate power
generation (thousands of Net MWh)
|
2,023.0
|
2,211.0
|
6,138.7
|
6,129.8
|
Weighted average
availability
|
95.0%
|
94.8%
|
93.0%
|
94.2%
|
Including results
from discontinued operations (1)
|
|
|
|
|
Cash flows from
operating activities
|
$40.4
|
$46.4
|
$45.9
|
$143.3
|
Free Cash
Flow
|
12.6
|
38.6
|
(48.4)
|
113.0
|
(1) The
Path 15 transmission line ("Path 15"), Auburndale Power Partners,
L.P. ("Auburndale"), Lake CoGen, Ltd. ("Lake") and Pasco Cogen,
Ltd. ("Pasco") (collectively, the "Sold Projects") were sold in
April 2013, the Company's interest in Rollcast Energy ("Rollcast")
was sold in November 2013, and Thermo Power & Electric, LLC
("Greeley") was sold in March 2014. Accordingly, the
revenues, project income (loss), Project Adjusted EBITDA and Cash
Distributions from these assets are included in discontinued
operations for the three and nine month periods ended September 30,
2013 and September 30, 2014. The results of discontinued
operations are excluded from Project revenue, Project income,
Project Adjusted EBITDA and Cash Distributions from Projects 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 Sold Projects,
Rollcast 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 Sold Projects,
Rollcast, and Greeley. The Gregory project ("Gregory"), which
was sold in August 2013, and the Delta-Person generating station
("Delta-Person"), which was sold in July 2014, are both accounted
for under the equity method of accounting and therefore are
included in the Company's financial results from continuing
operations.
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|
|
|
|
|
|
|
Third Quarter 2014 Financial Highlights
- Project Adjusted EBITDA of $72.2
million decreased $2.8 million
from Q3 2013, in line with expectations
- As previously disclosed, following an impairment charge at
Tunis recorded in second quarter
results, the Company initiated an analysis of its remaining
goodwill during the third quarter. As a result of that analysis,
non-cash goodwill impairments at three projects totaling
$91.8 million were recorded in the
third quarter, primarily driven by lower forward power curves as
compared to levels at the time the projects were acquired in
2011
- GAAP results included the $91.8
million impairment, an $8.6
million asset sale gain, and a $0.4
million non-cash gain on changes in the fair value of
derivatives, for a project loss of $(68.6)
million; project income excluding these items was
$14.2 million. Q3 2013 results of
$4.4 million included a $34.7 million non-cash impairment, a $3.5 million non-cash loss on changes in the fair
value of derivatives and a $31.0
million asset sale gain; project income excluding these
items was $11.6 million; thus,
year-over-year increase was $2.6
million
- Cash flows from operating activities of $40.4 million decreased $6.0 million from Q3 2013
- Free Cash Flow of $12.6 million
decreased $26.0 million from Q3 2013,
due primarily to debt repayment, higher capex (primarily for
Nipigon and other optimization
investments) and lower cash flows from operating activities
YTD September 2014 Financial
Highlights
- Project Adjusted EBITDA of $221.6
million increased $10.2
million from YTD Sept. 2013,
due to strong wind generation, increased waste heat in Ontario, lower maintenance expense at several
projects, increased margins at Orlando, and lower unallocated expenses,
partially offset by lower dispatch due to a mild summer
- GAAP results included $106.6
million non-cash impairments, a $12.3
million non-cash gain on changes in the fair value of
derivatives and an $8.6 million asset
sale gain, for a project loss of $(52.2)
million; excluding these items, project income was
$33.5 million. YTD Sept. 2013 project income of $56.4 million included a $34.7 million non-cash impairment, a $33.4 million non-cash gain on changes in the
fair value of derivatives and a $31.0
million asset sale gain; project income excluding these
items was $26.7 million; thus,
year-over-year increase was $6.8
million
- Cash flows from operating activities of $45.9 million decreased $97.4 million from YTD Sept. 2013, primarily due to interest expense
related to the debt repayment and repurchase transactions in the
first quarter of 2014, changes in working capital and the loss of
cash flows from businesses that were divested in 2013
- Free Cash Flow of $(48.4) million
decreased $161.4 million from YTD
Sept. 2013 due primarily to the
reduction in cash flows from operating activities, increased debt
repayment of $54.5 million and higher
capex of $5.8 million
2014 Guidance Ranges Narrowed
- Project Adjusted EBITDA of $285 to $300
million; previous guidance range was $280 to $305 million
- APLP Project Adjusted EBITDA of $165 to
$175 million, unchanged from previous guidance
- Free Cash Flow of $0 to $10
million, down from $0 to $25
million previously, reflecting severance costs incurred in
the second half of 2014 (guidance excludes $57.5 million of debt refinancing costs and
Piedmont debt repayment)
Strategic Update and Longer-Term Goals
A major factor in the Company's ability to meet its longer-term
goal of successfully pursuing value-enhancing acquisition and
development opportunities is a competitive cost of capital and
ready access to the capital markets. The Company is committed
to deleveraging its balance sheet to achieve this longer-term goal,
and has targeted a general credit profile with the following
attributes to facilitate access to the capital markets:
- Consolidated Debt to Adjusted EBITDA ratio in the range of
5.0-5.75x
- Consolidated Debt to Total Capitalization ratio of
approximately 60%
- Adjusted EBITDA to Interest Coverage multiple of 2.5x or
better
Consolidated Debt includes long-term debt and convertible
debentures, including the current portion of such debt, as
presented on the Company's consolidated balance sheet. Total
Capitalization includes Consolidated Debt plus total shareholders'
equity as presented on the Company's consolidated balance
sheet. Adjusted EBITDA is a non-GAAP measure that is defined
on page 15 of this press release. Adjusted EBITDA to Interest
Coverage multiple is defined on page 15 of this press
release.
The Company expects to achieve a net reduction in total debt of
approximately $85 million by year-end
2014 as follows:
- Amortization of the APLP term loan in the amount of an
estimated $53 million, including
$47.1 million through the third
quarter of 2014
- Amortization of consolidated project-level debt of
approximately $26 million, including
$8.1 million of Piedmont debt repaid at term loan
conversion
- Reduction in the Company's proportional share of project-level
debt at equity-method projects of approximately $7 million, including $6
million associated with the Delta-Person project that was
sold in the third quarter of 2014
Together with continued amortization of its project debt and
APLP term loan in the amount of $80 to $85
million annually (average for 2015 through 2017), the
Company plans to take additional steps to improve its ability to
achieve these credit metrics by the end of 2016, including:
- Significant reduction in leverage using proceeds from selective
asset sales currently under consideration
- Repurchase outstanding debt securities where economically
attractive; implementing an NCIB program for at least $15 million and up to 10% of outstanding
convertible debentures ($35
million)
In addition to reducing debt, the Company also intends to deploy
capital in high return projects and aggressively reduce corporate
expenses in order to achieve these goals:
- Continue to make optimization investments in existing fleet
with expected attractive returns (five-year payback or 20% current
yield); expect to make approximately $5 to
$10 million of such investments in 2015
- Achieve at least $7 million
reduction in G&A expense on an annual basis in addition to
$8 million previously achieved
($15 million annual run rate savings
in 2015 versus 2013), with further potential cost reductions under
evaluation
Business Update
Piedmont
In October 2014, Piedmont settled a dispute in arbitration with
Zachry, the project's contractor, related to amounts owed by the
project for work performed by Zachry under the project's
engineering, procurement and construction ("EPC") contract. Under
the terms of the settlement, the project agreed to pay Zachry
$5.0 million within seven days
following execution of the settlement agreement. The
settlement results in a mutual release of all arbitration claims by
both parties, other than certain excluded warranty claims retained
by Piedmont against Zachry. The
payment will be made from restricted cash at the project reserved
for retainage and arbitration claims. At September 30, 2014, Piedmont had accrued $8.2 million for the final retainage payment
under the EPC. After payment of the settlement agreement, the
remaining $3.2 million of reversed
accrual will be credited to operations and maintenance expense.
As previously disclosed, during the first quarter of 2014,
Piedmont underwent several forced
maintenance outages that resulted in the project not meeting its
debt service coverage ratio covenant as of September 30, 2014. The Company does not
expect Piedmont to meet its debt
service coverage ratio covenant for at least the next 18
months. As a result, the project is not expected to make
distributions for at least the next 18 months, which is nine months
beyond the Company's previous expectation.
Selkirk PPA expiration
The Company has an 18.5% ownership interest in the Selkirk project. The project's Power
Purchase Agreement (PPA) covering approximately three-quarters of
the capacity expired on August 31,
2014. Since the expiration of the PPA, Selkirk has been operating on a 100% merchant
basis, with the project selling power into the spot market to the
extent that spot prices support profitable operation of the
project.
Tunis
The PPA with the Ontario Power Authority (OPA) for the Company's
Tunis project is scheduled to
expire on December 31, 2014.
Although the Company is continuing negotiations with the OPA, it
has taken steps to minimize plant costs following the PPA
expiration, including giving notice to the affected
employees.
Operating Results
Project Availability and Generation
Three Months Ended September 30,
2014
Availability increased slightly to 95.0% from 94.8%, which
represented an improvement over the levels experienced in the first
and second quarters of this year and was consistent with the
Company's historical levels. Increased availability at
Mamquam, Moresby Lake and Koma Kulshan in the West segment and
Morris in the East segment occurred primarily because of scheduled
maintenance outages during the comparable 2013 quarter.
Improvements for these projects were partially offset by decreased
availability in the East segment at Nipigon, which underwent a scheduled
maintenance outage in the current period. Most of the
Company's projects earned their expected level of capacity payments
during the quarter. The impact of reduced availability on
capacity payments at the Ontario
projects and Piedmont was
$1.8 million. In July,
Piedmont experienced an unplanned
outage related to a failure in the generator lead line that has
been repaired. The project achieved 99.5% availability in
August and 98% in September.
Generation decreased 8.5% due primarily to lower dispatch at
Manchief and Williams Lake in the
West Segment, lower dispatch at Selkirk in the East segment due to mild summer
weather and scheduled maintenance at Chambers (East segment).
These decreases were partially offset by increased generation
in the Wind segment, primarily due to favorable winds at Canadian
Hills.
Nine Months Ended September 30,
2014
Availability declined to 93.0% from 94.2%, with all of the
decrease occurring in the first and second quarters of the
year. The decrease was attributable to a combination of
forced outages (some weather-related) and extensions of scheduled
outages. Year to date, reduced availability resulted in
capacity payments being $8.4 million
lower than their expected level. The majority of this impact
was at the Ontario projects, which
had unplanned outages due to weather and other factors in the first
quarter of this year, and Piedmont, which had several forced outages
earlier this year, the most recent in July, as discussed
previously.
Generation increased 0.1% in the first nine months of 2014 due
primarily to the addition of Piedmont in the East segment in April 2013 (additional quarter in 2014), higher
dispatch at Frederickson in the West segment and favorable wind
conditions for Meadow Creek (in
the Wind segment). These positive comparisons were mostly
offset by reduced dispatch at Manchief and Williams Lake in the West segment and reduced
generation at Selkirk and
Tunis in the East
segment.
Financial Results
Table 2 provides a breakdown of project income and Project
Adjusted EBITDA by segment for the three and nine month periods
ended September 30, 2014 as compared
to the same periods in 2013.
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,
|
|
2014
|
2013
|
2014
|
2013
|
Project income
(loss)
|
|
|
|
|
East
|
$(9.7)
|
$(29.4)
|
$17.7
|
$13.9
|
West
|
(53.1)
|
41.8
|
(51.7)
|
42.5
|
Wind
|
(3.5)
|
(3.5)
|
(11.1)
|
11.9
|
Un-allocated
Corporate
|
(2.3)
|
(4.5)
|
(7.1)
|
(11.9)
|
Total
|
(68.6)
|
4.4
|
(52.2)
|
56.4
|
Project Adjusted
EBITDA
|
|
|
|
|
East
|
$32.7
|
$33.5
|
$116.5
|
$112.1
|
West
|
28.3
|
32.7
|
62.3
|
67.3
|
Wind
|
14.1
|
12.9
|
49.0
|
43.4
|
Un-allocated
Corporate
|
(2.9)
|
(4.1)
|
(6.2)
|
(11.4)
|
Total
|
72.2
|
75.0
|
221.6
|
211.4
|
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 11 for a
reconciliation of this non-GAAP measure to a GAAP
measure.
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Project Income
Reported 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.
Three Months Ended September 30,
2014
Project income decreased by $73.0
million to a loss of $(68.6)
million compared to project income of $4.4 million for the same period in 2013.
The reduction in project income was primarily due to non-cash
goodwill impairment charges of $91.8
million, an increase of $57.0
million from Q3 2013; decreased asset sale gains at equity
method projects of $22.4 million
($8.6 million at Delta-Person in Q3
2014 and $31.0 million at Gregory in
Q3 2013); decreased project income of $5.3
million at Selkirk due to
lower dispatch and accelerated depreciation resulting from the PPA
expiration on August 31, 2014;
partially offset by increases in the fair value of gas purchase
agreements and interest rate swap agreements accounted for as
derivatives totaling $3.9 million;
improvements at other projects including Nipigon, Orlando, Curtis Palmer and Canadian Hills; and
a $2.2 million reduction in loss from
the Un-allocated Corporate segment due to reductions in development
expense at Ridgeline and lower compensation
expense.
Nine Months Ended September 30,
2014
Project income decreased by $108.6
million to a loss of $(52.2)
million compared to project income of $56.4 million for the same period in 2013.
The reduction in project income was primarily due to non-cash
goodwill impairment charges in 2014 of $106.6 million, an increase of $71.9 million from the 2013 period; decreased
asset sale gains of $22.4 million, as
described previously; net negative non-cash changes in fair value
of gas purchase agreements and interest rate swap agreements
accounted for as derivatives totaling $21.1
million; decreased project income of $12.6 million at Selkirk, as described previously; decreases at
Chambers and Calstock totaling
$4.7 million, primarily due to
scheduled turbine maintenance in 2014; legal expenses incurred at
Piedmont of $2.6 million related to Zachry arbitration and
land owner disputes; partially offset by improvements at several
projects in the East and West segments due to favorable outage
comparisons; an additional quarter of Piedmont operation; increased margins at
Morris and Orlando; lower interest
expense at Curtis Palmer; improved generation at Meadow Creek; and a $4.8 million reduction in the Un-allocated
Corporate segment loss primarily attributable to $2.2 million in development and administrative
expense reductions at Ridgeline and a $1.2
million reduction in compensation expense.
Project Adjusted EBITDA
Project Adjusted EBITDA includes proportional EBITDA from the
Company's equity method projects and 100% of EBITDA from
Rockland, which is 50% owned by
the Company, but is consolidated. Projects classified as
discontinued operations are excluded from Project Adjusted
EBITDA.
Three Months Ended September 30,
2014
Project Adjusted EBITDA decreased $2.8
million to $72.2 million from
$75.0 million for the comparable
period in 2013. Notwithstanding lower generation levels
during the quarter, results for Project Adjusted EBITDA were in
line with the Company's expectations. Projects with the most
significant year-over-year decreases in Project Adjusted EBITDA
included Selkirk, as described
previously; Naval Station, North Island and Naval Training Center,
due to lower energy revenues; Calstock and Chambers, due to increased
maintenance expense and lower dispatch at Chambers; Curtis Palmer,
due to lower water flows relative to 2013; smaller decreases at a
number of other projects; partially offset by increases at
Orlando, primarily due to higher
capacity payments under a new PPA and lower fuel expenses following
the expiration of an above-market gas supply contract at the end of
2013; Canadian Hills, due to increased wind generation;
Nipigon and Kapuskasing, primarily due to favorable outage
comparisons and increased waste heat generation; and a $1.2 million reduction in the loss of the
Un-allocated Corporate segment, primarily due to lower development
expenses at Ridgeline.
Nine Months Ended September 30,
2014
Project Adjusted EBITDA increased by $10.2 million to $221.6
million from $211.4 million
for the same period in 2013. Year-to-date results are in line
with the Company's expectations. For the nine-month period,
the most significant contributors to the improvement in Project
Adjusted EBITDA were the Ontario
projects other than Calstock, due
to the timing of maintenance expense and increased waste heat
generation; the wind projects, primarily Meadow Creek and Canadian Hills, due to
increased generation; Morris, due primarily to lower maintenance
costs relative to 2013 and higher merchant capacity and ancillary
services revenues; Naval Training Center, due primarily to
favorable maintenance comparisons; Orlando, as described previously; a
$5.2 million reduction in loss from
the Un-allocated Corporate segment, primarily due to a reduction in
development costs at Ridgeline and a reduction in administrative
costs; partially offset by decreases at Selkirk, as described previously; Williams Lake, primarily due to lower energy
prices under the PPA beginning in April
2013, partially offset by lower maintenance expense;
Calstock due to a scheduled
turbine overhaul in 2014; the sale of Gregory in August 2013 and Delta-Person in July 2014; and smaller decreases at several other
projects in the East and West segments.
Corporate G&A Expense
Administrative expenses, which include administration expense
(corporate-level G&A expense), interest expense, foreign
exchange gains and losses and other income, are not included in
Project Adjusted EBITDA.
In the third quarter, administration expense increased
$0.8 million from the comparable
year-ago period. During the quarter, the Company incurred
$4.2 million of severance charges
associated with management changes and personnel reductions that
occurred during the quarter. This represented an increase of
$2.9 million in accrued severance
expense from the year-ago period, which was mostly offset by (i) a
reduction in legal expenses of $1.5
million, as during the quarter the Company exceeded the
$1.5 million deductible under its
directors and officers insurance policy with regard to legal costs
incurred for the purported class action shareholder litigation, and
expects additional costs incurred to be paid by its insurance
carrier to the extent set forth under the terms of its coverage;
and (ii) a $0.7 million reduction in
professional fees from the third quarter of 2013, when the Company
incurred costs related to the amendment of the prior Senior Credit
Facility.
For the nine months year to date, administration expense
decreased $1.8 million, primarily due
to a $4.7 million reduction in
transactional fees incurred for the 2013 asset divestitures and
$0.7 million for lower professional
costs related to the 2013 credit facility amendment. These
reductions were partially offset by $4.2
million of severance costs, which increased $3.9 million from the year-ago period.
Cash Flow Metrics
Cash Distributions from Projects
Cash Distributions from Projects, which excludes projects
classified as discontinued operations, increased by $17.3 million to $187.0
million for the nine months ended September 30, 2014, compared to $169.7 million for the same period in 2013.
This result includes a decline in the third quarter of 2014 of
$14.5 million from the year-ago
period.
Significant increases for the YTD Sept.
2014 occurred at (i) the Navy projects in California,
attributable to lower operation and maintenance expenses than in
2013, during which the projects experienced planned outages, and to
lower working capital requirements associated with a new gas supply
agreement in 2014; (ii) Meadow
Creek, Canadian Hills, Rockland and Idaho Wind, due to the release of
construction-related blade and credit reserves and increased wind
generation; (iii) Orlando, due to
lower gas costs following the termination of swaps that were above
market as well as favorable changes to the project's PPA; and (iv)
Mamquam, due to lower maintenance expense.
These increases were partially offset by decreases at (i)
Chambers, which benefited from the release of the DuPont settlement
in the 2013 period and for which there was a change in the
distribution date under the project's new debt agreement in 2014,
with distributions next expected to occur in December; (ii)
Selkirk, due to the expiration of
the PPA at the end of August; (iii) the Ontario projects, due to the timing of revenue
receipts and higher maintenance expenses; and (iv) smaller
decreases at several other projects.
For the third quarter, significant decreases, in order of
importance, occurred at the Ontario projects, for the reasons mentioned
above; and Morris, due to gas storage purchases; with smaller
decreases at Oxnard and
Manchief. These decreases were partially offset by increases
at Williams Lake, due to lower
maintenance expense; and Orlando,
the Navy projects in California,
and Rockland, each for the reasons
described above.
Cash Flows from Operating Activities
Three Months Ended September 30,
2014
Cash flows from operating activities decreased by $6.0 million to $40.4
million compared to $46.4
million for the same period in 2013. The decrease is
primarily due to the $2.8 million
decrease in Project Adjusted EBITDA for the quarter and an
approximate $16 million increase in
cash outflows for working capital, partially offset by other
factors.
Nine Months Ended September 30,
2014
Cash flows from operating activities decreased by $97.4 million to $45.9
million compared to $143.3
million for the same period in 2013. The decrease is
primarily due to $46.8 million of
interest expense related to the debt repayment and repurchase
transactions in the first quarter (as described in more detail in
the first quarter 2014 press release dated May 12, 2014), a $45.2
million increase in cash outflows for working capital due to
a $36.0 million decrease in prepaid
and other assets due to the collection of security deposits in the
first quarter of 2013, and a decrease in cash flows from
discontinued operations (projects sold in 2013).
Free Cash Flow
Three Months Ended September 30,
2014
Free Cash Flow decreased by $26.0
million to $12.6 million
compared to $38.6 million for the
same period in 2013. The decrease is due primarily to
$9.6 million of term loan facility
repayments at APLP pursuant to mandatory amortization and the cash
sweep; $6.0 million of decreased cash
flows from operations; $6.0 million
of increased project capex, most of which was related to
$6.1 million at Nipigon for the replacement and upgrade of the
project's steam generator; and $2.5
million of increased repayments of project-level debt.
Nine Months Ended September 30,
2014
Free Cash Flow decreased by $161.4
million to $(48.4) million
compared to $113.0 million for the
same period in 2013. The decrease is primarily due to a
$97.4 million decrease in operating
cash flows as described previously, $47.1
million of term loan facility repayments by APLP and a
$7.4 million increase in
project-level debt repayment. The $47.1 million of term loan repayments through the
third quarter, which includes $2.9
million of 1% mandatory amortization and $44.3 million of debt repaid pursuant to the 50%
sweep of APLP's cash flow after debt service and capex, represents
approximately 89% of the amount estimated for the full year of
approximately $53 million.
The Company's full year 2014 Free Cash Flow guidance excludes
(i) $49.4 million of interest expense
related to the refinancing and debt repurchase transactions and
(ii) the $8.1 million Piedmont construction debt repayment. On
that basis, Free Cash Flow for the first nine months of 2014 is
approximately $9 million compared to
$113 million for the same period in
2013.
Liquidity
As can be seen from Table 3, the Company's liquidity increased
from approximately $261 million at
June 30, 2014 to approximately
$272 million as of September 30, 2014, including $168 million of unrestricted cash. On
October 31, Cdn$44.8 million of the Company's convertible
debentures (ATP.DB) matured, and the Company used $41 million of cash to repay the debentures at
maturity. Pro forma for this use of cash, liquidity at the
end of the quarter would have been approximately $231 million (see Table 3).
Atlantic Power
Corporation
Table 3 –
Liquidity (in millions of U.S. dollars)
|
|
|
Unaudited
|
|
June 30,
2014
|
September
30, 2014
|
Pro
Forma
|
Revolver
capacity
|
|
$210.0
|
$210.0
|
$210
|
Letters of credit
outstanding
|
|
(107.0)
|
(106.0)
|
(106)
|
Unused borrowing
capacity
|
|
103.0
|
104.0
|
104
|
Unrestricted cash
(1)
|
|
157.6
|
167.6
|
127
|
Total
Liquidity
|
|
$260.6
|
$271.6
|
$231
|
(1)
Includes project-level cash for working capital needs of $16.3
million at September 30, 2014 and $16.4 million at June 30,
2014. Pro forma unrestricted cash reflects repayment of $41
million (Cdn$44.8 million) of convertible debentures (ATP.DB) on
October 31, 2014 at maturity.
|
|
|
|
|
|
|
2014 Guidance Ranges Narrowed
- Project Adjusted EBITDA of $285 to $300
million, narrowed from $280 to $305
million previously
- Free Cash Flow of $0 to $10
million, down from $0 to $25
million previously
Project Adjusted EBITDA
The Company is narrowing its guidance for 2014 Project Adjusted
EBITDA to a range of $285 million to $300
million from a range of $280 to $305
million previously. The narrower range is based on
results for the year to date as well as the Company's expectation
for the balance of the year. The Company is reaffirming its
expectation for 2014 APLP Project Adjusted EBITDA in the range of
$165 to $175 million.
Free Cash Flow
The Company is lowering its guidance for 2014 Free Cash Flow to
a range of $0 to $10 million from a
range of $0 to $25 million
previously. This guidance is net of planned capital
expenditures totaling $16 million and
debt repayments under the APLP term loan of an estimated
$53 million in 2014 pursuant to
mandatory amortization and the cash sweep. Relative to
previous expectations, severance expenses accrued in the third
quarter and additional amounts to be accrued in the fourth quarter
associated with recent management changes and personnel reductions
are expected to have an adverse impact on cash flows from operating
activities and Free Cash Flow in the fourth quarter of 2014.
They are not expected to affect Project Adjusted EBITDA as the
majority of these costs have been or will be recorded in corporate
G&A expense, which is not included in Project Adjusted
EBITDA.
The Company's Free Cash Flow guidance excludes (i) approximately
$49.4 million in expenses associated
with the first quarter refinancing and debt repurchase transactions
and (ii) the $8.1 million repayment
of Piedmont construction debt made
to facilitate the term loan conversion in February, together
totaling $57.5 million.
See Table 4 for full-year 2014 guidance and year-to date 2014
actual results.
Atlantic Power
Corporation
Table 4 – 2014
Annual Guidance and YTD 2014 Actual
(in millions of
U.S. dollars, except as otherwise stated)
|
|
|
Unaudited
|
|
2014 Initial
Guidance
Provided
2/27/14
|
2014 Revised
Guidance
Provided
11/6/14
|
YTD 2014
Actual
|
Project Adjusted
EBITDA
|
|
$280 -
$305
|
$285 -
$300
|
$221.6
|
Free Cash Flow
(1)
|
|
$0 - $25
|
$0 - $10
|
$(48.4)
|
APLP Project Adjusted
EBITDA (2)
|
|
$165 -
$175
|
$165 -
$175
|
$131.6
|
(1) Free
Cash Flow is defined as cash flows from operating activities less
capex; project-level debt repayments, including amortization of the
Senior Secured Term Loan Facility; and distributions to
noncontrolling interests, including preferred share
dividends. Note that 2014 guidance excludes $49 million of
refinancing and debt repurchase transaction costs in first quarter
2014 and $8 million of Piedmont debt repayment in February
2014.
(2) 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, APLP Project Adjusted EBITDA 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.
|
|
|
|
|
|
|
|
Other Financial Updates
Goodwill Impairment
Based on the continued deficit of the Company's market
capitalization as compared to its book carrying value, the Company
determined in the second quarter of 2014 that it was appropriate to
initiate a test of the remaining goodwill at its reporting units
prior to its annual goodwill impairment test that would have
occurred in the fourth quarter of 2014. The test was
performed as of August 31, 2014 and
concluded during the quarter ended September
30, 2014. As a result of the event-driven goodwill
assessment, it was determined that goodwill was impaired at the
Kenilworth (East segment),
Manchief (East Segment) and Williams
Lake (West segment) reporting units. Accordingly, the
Company recorded a full impairment of the remaining goodwill at
Kenilworth ($17.9 million) and Manchief ($50.2 million) and a partial impairment of the
remaining goodwill at Williams
Lake ($23.7 million).
The total goodwill impairment recorded in the three months ended
September 30, 2014 was $91.8 million.
As previously disclosed, during the second quarter of 2014, the
Company recorded a $14.8 million
non-cash impairment charge for the Tunis project, including $5.2 million for all of the project's goodwill
and $9.6 million associated with the
carrying value of the project's long-lived assets. The
Company updated its impairment analysis for the Tunis project as of September 30, 2014 and determined that no further
impairment of the project's long-lived assets was required as of
that date.
G&A Expense Reduction
In the third quarter and year to date, the Company accrued
severance costs of $4.2 million
associated with recent management changes and personnel
reductions. Additional severance costs are expected to be
accrued in the fourth quarter. These costs were not assumed
in the Company's 2014 guidance initially provided on February 27, 2014. The Company expects to
realize cost savings from these initiatives in 2015, which are
included in its expectation of at least a $7
million annual reduction in G&A expense in addition to
cost reductions previously achieved. Including the
$8 million of administrative and
development cost reductions implemented in 2013, the Company
expects that its 2015 G&A expense will be at least $15 million lower than the 2013 level. In
addition to personnel cost savings, the Company expects to have
lower project and business development expenses, including a
$3 million annual benefit from the
scheduled expiration of a contractual obligation related to the
Ridgeline acquisition beginning in the first quarter of 2015.
Also, going forward the Company expects to have lower legal
expenses associated with the purported class action shareholder
litigation now that it has met its $1.5
million deductible under its directors and officers
insurance policy and expects additional costs incurred to be paid
by its insurance carrier to the extent set forth under the terms of
its coverage.
The Company's project-level G&A expense and expenses for
Ridgeline are included in the Un-allocated Corporate segment and
therefore included in Project Adjusted EBITDA.
Corporate-level G&A expense is included in Administration
expense on the consolidated statement of operations. The
G&A expense discussion in the preceding paragraph refers to
total G&A expense.
Capex and Optimization Update
The Company expects to have major maintenance and capital
expenditures in 2014 of approximately $35
million. In the first nine months of 2014, the Company
invested $23 million, or about
two-thirds of the total expected for the year.
Included in this forecast are certain expenditures designed to
improve the operating performance and enhance the efficiency or
lower the costs of the Company's existing portfolio. The
Company views these investments as an attractive use of its
available cash as it believes that the risk-adjusted returns are
compelling and the capital requirements are relatively
modest. The level of planned spending associated with these
optimization initiatives is approximately $18 million in 2014, for a 2013-2014 total of
approximately $27 million. The
largest of these projects is the steam generator replacement and
upgrade at Nipigon, which occurred
during an outage in the third quarter. Total estimated cost
of the Nipigon project is
approximately $12 million, including
$8 million invested in 2014 and
approximately $1 million to be spent
in 2015. Other projects completed this year include the
repowering of two turbines at Curtis Palmer, capacity uprates at
North Island, Mamquam and Calstock, and an investment designed to boost
output at Morris during peak periods.
The Company expects that optimization-related spending for 2013
and 2014 totaling $27 million will
produce incremental cash flow of at least $8
million annually on a run-rate basis in 2015, a significant
portion of which has already been realized in the current
year. Going forward, the Company expects that major
maintenance and routine capex will average approximately
$25 million annually (versus
approximately $20 million in
2014). For 2015, the Company expects to invest approximately
$5 to $10 million in discretionary
optimization projects. Including these investments, major
maintenance and capex are estimated to be in the range of
$30 to $35 million.
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, 2014
and 2013 (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, 2014 (Table 9A) and the nine months
ended September 30, 2013 (Table 9B);
a reconciliation of Cash Distributions from Projects and Project
Adjusted EBITDA to Net income (loss) and of Free Cash Flow to cash
flows from operating activities for the three and nine months ended
September 30, 2014 and 2013 (Table
10); and a summary of Project Adjusted EBITDA for selected projects
(top contributors based on the Company's 2014 budget, representing
approximately 80% of total Project Adjusted EBITDA) for the three
and nine months ended September 30,
2014 and 2013 (Table 11).
Investor Conference Call and Webcast
A telephone conference call hosted by Atlantic Power's
management team will be held on Friday, November 7, 2014 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 8939283
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
10053515. The replay will be available 1 hour after
the end of the conference call through February 9, 2015 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. Atlantic Power'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. Its
power generation projects in operation have an aggregate gross
electric generation capacity of approximately 2,945 MW in which its
aggregate ownership interest is approximately 2,024 MW. Its current
portfolio consists of interests in twenty-eight operational power
generation projects across eleven 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 our Company
and our projects. These statements, which are based on
certain assumptions and describe our 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 progress made by the Company in improving the performance
of its projects and reducing its costs should benefit future
periods;
- the Company's expectation that it will fund attractive
investments in existing projects with existing Free Cash Flow, and
will evaluate potential asset sales and partnerships with the
intended use of proceeds to reduce high-cost debt;
- deleveraging, reducing the Company's financial risk and
lowering its cost of capital should improve the Company's ability
to regain effective access to the capital markets, which would
allow the Company to grow as well as address debt maturities in
2017 and beyond;
- the Company's focus on improving its credit metrics to achieve
competitive cost of capital and ready access to capital markets
through targeted reductions in leverage using proceeds from
selective asset sales under consideration, the repurchase of
outstanding debt securities where economically attractive,
including the planned implementation of a normal course issuer bid
for at least $15 million and up to
10% of outstanding convertible debt securities ($35 million);
- the Company's ability to achieve its targeted credit metrics by
the end of 2016;
- the Company's intention to deploy capital in high return
projects, including by continuing to make optimization investments
in its existing fleet with attractive returns and targeting
approximately $5 to $10 million of
such investments in 2015, and to aggressively reduce corporate
expenses;
- the Company's longer-term goal of successfully pursuing
value-enhancing acquisition, development or joint venture
opportunities;
- the Company will achieve expected annual interest rating
savings of $2.7 million in 2015 in
connection with the repayment at maturity of the Company's
Cdn$44.8 million convertible
debenture on October 31;
- the Company's targeted general credit profile with (i)
Consolidated Debt to Adjusted EBITDA ratio in the range of
5.0-5.75x, (ii) Consolidated Debt to Total Capitalization ratio of
approximately 60% and (iii) Adjusted EBITDA to Interest Coverage
multiple of 2.5x or better;
- 2014 Project Adjusted EBITDA will be in the range of
$285 to $300 million;
- 2014 APLP Project Adjusted EBITDA will be in the range of
$165 to $175 million;
- 2014 Free Cash Flow will be in the range of $0 to $10 million, excluding refinancing and debt
repurchase transaction costs and principal repayment of
Piedmont construction debt;
- the Company will reduce total debt on a net basis by
approximately $85 million this
year;
- Piedmont will be unable to
pass its debt service coverage ratio covenant for at least the next
18 months and as a result, will not make distributions for at least
the next 18 months;
- the Company's steps to minimize plant costs following the
expiration of the Tunis PPA;
- APLP term loan repayments for the full year will total
approximately $53 million;
- the Company expects to realize additional G&A cost savings
of at least $7 million in 2015, for a
total run-rate reduction of at least $15
million relative to 2013;
- the Company expects to have lower project and business
development expenses, including a $3
million annual benefit from the scheduled expiration of a
contractual obligation related to the Ridgeline acquisition
beginning in the first quarter of 2015;
- the Company expects to have lower legal expenses associated
with the purported class action shareholder litigation, and expects
that additional costs incurred in connection with such purported
class action shareholder litigation will be paid by the Company's
directors and officers insurance carrier to the extent set forth
under the terms of its coverage;
- the Company will have project capital expenditures and major
maintenance expenses of approximately $35
million in 2014, including optimization initiatives of
approximately $18 million;
- major maintenance expense and maintenance capex will average
approximately $25 million annually,
versus approximately $20 million in
2014;
- the level of optimization investments will be approximately
$18 million in 2014, for a two-year
(2013 and 2014) total of approximately $27
million, and that these investments will produce a cash flow
run-rate contribution of at least $8
million annually on a run-rate basis in 2015, with at least
half of that already realized in 2014 from investments completed to
date;
- the Company will have annual optimization capex on average of
approximately $5 to $10 million;
- major maintenance and capex for 2015 will be in the range of
$30 to $35 million, including
approximately $5 to $10 million in
discretionary optimization projects; 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 Company's ability to evaluate
and/or implement a broad range of potential options, including
further selected asset sales or joint ventures to raise additional
capital for growth or potential debt reduction. 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 financial outlook
information contained in this news release is presented to provide
readers with guidance on the cash distributions expected to be
received by the Company and to give readers a better understanding
of the Company's ability to pay its current level of distributions
into the future. 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. Readers are cautioned that such
information may not be appropriate for other purposes.
Atlantic Power
Corporation
Table 5 –
Consolidated Balance Sheets (in millions of U.S.
dollars)
|
|
|
|
|
|
|
|
|
September
30,
|
December
31,
|
|
|
|
|
2014
|
2013
|
Assets
|
|
|
|
Unaudited
|
|
Current
assets:
|
|
|
|
|
Cash and cash
equivalents
|
|
|
|
$167.6
|
$158.6
|
Restricted
cash
|
|
|
|
18.5
|
96.2
|
Accounts
receivable
|
|
|
|
64.6
|
64.3
|
Current portion of
derivative instruments asset
|
|
|
|
-
|
0.2
|
Inventory
|
|
|
|
20.3
|
16.0
|
Prepayments and other
current assets
|
|
|
|
14.6
|
16.1
|
Refundable income
taxes
|
|
|
|
2.6
|
4.0
|
Total current
assets
|
|
|
|
288.2
|
355.4
|
|
|
|
|
|
|
Property, plant and
equipment, net
|
|
|
|
1,710.4
|
1,813.4
|
Equity investments in
unconsolidated affiliates
|
|
|
|
360.2
|
394.3
|
Other intangible
assets, net
|
|
|
|
399.8
|
451.5
|
Goodwill
|
|
|
|
197.2
|
296.3
|
Derivative
instruments asset
|
|
|
|
5.8
|
13.0
|
Restricted
cash
|
|
|
|
17.5
|
18.0
|
Deferred financing
costs
|
|
|
|
67.3
|
41.7
|
Other
assets
|
|
|
|
10.1
|
11.4
|
Total
assets
|
|
|
|
$3,056.5
|
$3,395.0
|
|
|
|
|
|
|
Liabilities and
Shareholder's Equity
|
|
|
|
|
|
Current
liabilities:
|
|
|
|
|
|
Accounts
payable
|
|
|
|
$10.4
|
$14.0
|
Accrued
interest
|
|
|
|
21.5
|
17.7
|
Other accrued
liabilities
|
|
|
|
51.3
|
58.8
|
Current portion of
long-term debt
|
|
|
|
26.1
|
216.2
|
Current portion of
convertible debentures
|
|
|
|
40.0
|
42.1
|
Current portion of
derivative instruments liability
|
|
|
|
29.6
|
28.5
|
Dividends
payable
|
|
|
|
-
|
6.8
|
Other current
liabilities
|
|
|
|
8.4
|
5.3
|
Total current
liabilities
|
|
|
|
187.3
|
389.4
|
|
|
|
|
|
|
Long-term
debt
|
|
|
|
1,413.1
|
1,254.8
|
Convertible
debentures
|
|
|
|
351.4
|
363.1
|
Derivative
instruments liability
|
|
|
|
52.4
|
76.1
|
Deferred income
taxes
|
|
|
|
98.8
|
111.5
|
Power purchase and
fuel supply agreement liabilities, net
|
|
|
|
34.9
|
38.7
|
Other non-current
liabilities
|
|
|
|
61.8
|
65.4
|
Commitments and
contingencies
|
|
|
|
-
|
-
|
Total
liabilities
|
|
|
|
2,199.7
|
2,299.0
|
|
|
|
|
|
|
Equity
|
|
|
|
|
|
Common shares, no par
value, unlimited authorized shares; 120,806,572 and 120,205,813
issued and outstanding at September 30, 2014 and December 31, 2013,
respectively
|
|
|
|
1,287.0
|
1,286.1
|
Preferred shares
issued by a subsidiary company
|
|
|
|
221.3
|
221.3
|
Accumulated other
comprehensive loss
|
|
|
|
(46.9)
|
(22.4)
|
Retained
deficit
|
|
|
|
(850.4)
|
(655.4)
|
Total Atlantic Power
Corporation shareholders' equity
|
|
|
|
611.0
|
829.6
|
Noncontrolling
interests
|
|
|
|
245.8
|
266.4
|
Total
equity
|
|
|
|
856.8
|
1,096.0
|
Total liabilities and
equity
|
|
|
|
$3,056.5
|
$3,395.0
|
|
|
|
|
|
|
|
|
|
|
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,
|
|
2014
|
2013
|
|
2014
|
2013
|
Project
revenue:
|
|
|
|
|
Energy
sales
|
$69.6
|
$72.9
|
|
$234.2
|
$226.6
|
Energy capacity
revenue
|
49.1
|
49.9
|
|
124.0
|
127.1
|
Other
|
19.6
|
17.2
|
|
68.6
|
59.7
|
|
138.3
|
140.0
|
|
426.8
|
413.4
|
|
|
|
|
|
|
Project
expenses:
|
|
|
|
|
|
Fuel
|
49.3
|
46.7
|
|
159.5
|
144.4
|
Operations and
maintenance
|
34.0
|
37.3
|
|
101.2
|
111.0
|
Development
|
1.0
|
1.4
|
|
2.7
|
4.9
|
Depreciation and
amortization
|
40.8
|
42.0
|
|
122.3
|
124.7
|
|
125.1
|
127.4
|
|
385.7
|
385.0
|
Project other income
(expense):
|
|
|
|
|
|
Change in fair value
of derivative instruments
|
0.4
|
(3.5)
|
|
12.3
|
33.4
|
Equity in earnings of
unconsolidated affiliates
|
15.4
|
39.1
|
|
27.3
|
55.0
|
Interest expense,
net
|
(5.8)
|
(9.0)
|
|
(26.3)
|
(25.7)
|
Impairment
|
(91.8)
|
(34.8)
|
|
(106.6)
|
(34.7)
|
|
(81.8)
|
(8.2)
|
|
(93.3)
|
28.0
|
Project (loss)
income
|
(68.6)
|
4.4
|
|
(52.2)
|
56.4
|
|
|
|
|
|
|
Administrative and
other expenses (income):
|
|
|
|
|
|
Administration
|
9.2
|
8.4
|
|
26.7
|
28.5
|
Interest,
net
|
26.7
|
27.5
|
|
120.8
|
78.7
|
Foreign exchange
(gain) loss
|
(19.0)
|
9.1
|
|
(20.4)
|
(12.9)
|
Other income,
net
|
-
|
-
|
|
(2.1)
|
(9.5)
|
|
16.9
|
45.0
|
|
125.0
|
84.8
|
Loss from continuing
operations before income taxes
|
(85.5)
|
(40.6)
|
|
(177.2)
|
(28.4)
|
Income tax expense
(benefit)
|
5.6
|
-
|
|
(7.4)
|
(1.9)
|
Loss from continuing
operations
|
(91.1)
|
(40.6)
|
|
(169.8)
|
(26.5)
|
Net loss from
discontinued operations, net of tax (1)
|
-
|
-
|
|
(0.1)
|
(5.2)
|
Net loss
|
(91.1)
|
(40.6)
|
|
(169.9)
|
(31.7)
|
Net loss attributable
to noncontrolling interest
|
(5.1)
|
(2.5)
|
|
(11.8)
|
(3.3)
|
Net income
attributable to preferred share dividends of a subsidiary
company
|
2.9
|
3.2
|
|
8.8
|
9.5
|
Net loss attributable
to Atlantic Power Corporation
|
$(88.9)
|
$(41.3)
|
|
$(166.9)
|
$(37.9)
|
|
|
|
|
|
|
Basic earnings per
share:
|
|
|
|
|
|
Loss from continuing
operations attributable to Atlantic Power Corporation
|
$(0.74)
|
$(0.34)
|
|
$(1.38)
|
$(0.28)
|
Loss from discontinued
operations, net of tax
|
-
|
-
|
|
-
|
(0.04)
|
Net loss attributable
to Atlantic Power Corporation
|
$(0.74)
|
$(0.34)
|
|
$(1.38)
|
$(0.32)
|
Diluted earnings per
share:
|
|
|
|
|
|
Loss from continuing
operations attributable to Atlantic Power Corporation
|
$(0.74)
|
$(0.34)
|
|
$(1.38)
|
$(0.28)
|
Loss from discontinued
operations, net of tax
|
-
|
-
|
|
-
|
(0.04)
|
Net loss attributable
to Atlantic Power Corporation
|
$(0.74)
|
$(0.34)
|
|
$(1.38)
|
$(0.32)
|
(1) Includes
contributions from the Sold Projects and Path 15, which are a
component 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,
|
|
|
|
|
2014
|
2013
|
Cash flows from
operating activities:
|
|
|
|
|
|
Net loss
|
|
|
|
$(169.9)
|
$(31.7)
|
Adjustments to
reconcile to net cash provided by operating activities
|
|
|
|
|
|
Depreciation and
amortization
|
|
|
|
122.3
|
135.0
|
Loss of discontinued
operations
|
|
|
|
-
|
32.8
|
Gain on sale of
asset
|
|
|
|
(2.1)
|
(4.6)
|
Gain on sale of equity
investment
|
|
|
|
(8.6)
|
(30.4)
|
Long-term incentive
plan expense
|
|
|
|
1.8
|
1.7
|
Impairment
charges
|
|
|
|
106.6
|
39.8
|
Equity in earnings
from unconsolidated affiliates
|
|
|
|
(18.8)
|
(24.6)
|
Distributions from
unconsolidated affiliates
|
|
|
|
52.8
|
28.5
|
Unrealized foreign
exchange gain
|
|
|
|
(21.0)
|
1.5
|
Change in fair value
of derivative instruments
|
|
|
|
(12.3)
|
(44.1)
|
Change in deferred
income taxes
|
|
|
|
(11.1)
|
(11.9)
|
Change in other
operating balances
|
|
|
|
|
|
Accounts
receivable
|
|
|
|
(0.3)
|
4.5
|
Inventory
|
|
|
|
(4.3)
|
(1.5)
|
Prepayments,
refundable income taxes and other assets
|
|
|
|
18.2
|
54.2
|
Accounts
payable
|
|
|
|
(4.8)
|
(11.9)
|
Accruals and other
liabilities
|
|
|
|
(2.6)
|
6.0
|
Cash provided by
operating activities
|
|
|
|
45.9
|
143.3
|
|
|
|
|
|
|
Cash flows provided
by investing activities
|
|
|
|
|
|
Change in restricted
cash
|
|
|
|
78.2
|
(99.1)
|
Proceeds from sale of
asset, net
|
|
|
|
0.9
|
183.0
|
Proceeds from sale of
equity investment asset, net
|
|
|
|
8.6
|
-
|
Proceeds from treasury
grant
|
|
|
|
-
|
103.2
|
Biomass development
costs
|
|
|
|
-
|
(0.1)
|
Construction in
progress
|
|
|
|
(1.3)
|
(35.2)
|
Purchase of property,
plant and equipment
|
|
|
|
(10.0)
|
(4.2)
|
Cash provided by
investing activities
|
|
|
|
76.4
|
147.6
|
|
|
|
|
|
|
Cash flows used in
financing activities
|
|
|
|
|
|
Proceeds from senior
secured term loan facility
|
|
|
|
600.0
|
-
|
Proceeds from
project-level debt
|
|
|
|
-
|
20.8
|
Repayment of corporate
and project-level debt
|
|
|
|
(621.9)
|
(115.4)
|
Payments for revolving
credit facility borrowings
|
|
|
|
-
|
(67.0)
|
Deferred financing
costs
|
|
|
|
(39.0)
|
(0.5)
|
Equity contribution
from noncontrolling interest
|
|
|
|
-
|
44.6
|
Offering costs related
to tax equity
|
|
|
|
-
|
(1.0)
|
Dividends paid to
common shareholders
|
|
|
|
(32.0)
|
(54.2)
|
Dividends paid to
noncontrolling interests
|
|
|
|
(20.4)
|
(13.9)
|
Cash used in
financing activities
|
|
|
|
(113.3)
|
(186.6)
|
|
|
|
|
|
|
Net (decrease)
increase in cash and cash equivalents
|
|
|
|
9.0
|
104.3
|
Less cash at
discontinued operations
|
|
|
|
-
|
(0.3)
|
Cash and cash
equivalents at beginning of period at discontinued
operations
|
|
|
|
-
|
6.5
|
Cash and cash
equivalents at beginning of period
|
|
|
|
158.6
|
60.2
|
Cash and cash
equivalents at end of period
|
|
|
|
$167.6
|
$170.7
|
|
|
|
|
|
|
Supplemental cash
flow information
|
|
|
|
|
|
Interest
paid
|
|
|
|
$124.4
|
$87.0
|
Income taxes paid,
net
|
|
|
|
$1.0
|
$4.6
|
Accruals for
construction in progress
|
|
|
|
$8.2
|
$8.3
|
|
|
|
|
|
|
|
|
|
|
|
Regulation G Disclosures
Project Adjusted EBITDA, Cash Distributions from
Projects and Free Cash Flow are not measures recognized
under GAAP and do not have standardized meanings prescribed by
GAAP. Management believes that Free Cash Flow and Cash
Distributions from Projects are relevant supplemental measures of
the Company's ability to earn and distribute cash returns to
investors. Reconciliations of Free Cash Flow to cash flows
from operating activities and of Cash Distributions from Projects
to Project income (loss) are provided in Table 10 on page 17 of
this release. Investors are cautioned that the Company may
calculate these measures in a manner that is different from other
companies.
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.
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. Project Adjusted EBITDA is
not a measure recognized under GAAP and is therefore unlikely to be
comparable to similar measures presented by other companies and
does not have a standardized meaning prescribed by GAAP.
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 a bridge to Cash Distributions from Projects are provided in
Table 8 below and Tables 9A and 9B on page 16, respectively.
Investors are cautioned that the Company may calculate this
measure 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,
|
|
|
2014
|
2013
|
2014
|
2013
|
Project Adjusted
EBITDA by segment
|
|
|
|
|
|
East
(1)
|
|
$32.7
|
$33.5
|
$116.5
|
$112.1
|
West
(2)
|
|
28.3
|
32.7
|
62.3
|
67.3
|
Wind
|
|
14.1
|
12.9
|
49.0
|
43.4
|
Un-allocated corporate
(3)
|
|
(2.9)
|
(4.1)
|
(6.2)
|
(11.4)
|
Total
|
|
$72.2
|
$75.0
|
$221.6
|
$211.4
|
|
|
|
|
|
|
Reconciliation to
project income
|
|
|
|
|
|
Depreciation and
amortization
|
|
50.4
|
51.1
|
154.8
|
153.5
|
Interest expense,
net
|
|
7.6
|
10.7
|
32.4
|
30.5
|
Change in the fair
value of derivative instruments
|
|
(0.4)
|
3.6
|
(11.5)
|
(34.8)
|
Other
expense
|
|
83.2
|
5.2
|
98.1
|
5.8
|
Project (loss)
income
|
|
$(68.6)
|
$4.4
|
$(52.2)
|
$56.4
|
(1) Excludes
Auburndale, Lake and Pasco, which are components of discontinued
operations.
(2) Excludes Greeley
and Path 15, which are components of discontinued
operations.
(3) Excludes
Rollcast, which is a component of discontinued
operations.
Note: 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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA is defined as (i) for the Company's
consolidated projects: project income (loss) plus interest,
taxes, depreciation and amortization (including non-cash impairment
charges) and changes in the fair value of derivative instruments,
plus (ii) for the Company's equity-method projects: cash
distributions to the Company from these projects; less (iii)
corporate administration expense as shown on the Company's
consolidated statement of operations. Adjusted EBITDA
is not a measure recognized under GAAP and is therefore unlikely to
be comparable to similar measures presented by other companies and
does not have a standardized meaning prescribed by GAAP.
Adjusted EBITDA to Interest Coverage ratio is defined as
Adjusted EBITDA divided by the sum of (ii) project-level interest
expense, net, as shown on the Company's consolidated statement of
operations, and (ii) corporate interest expense, net, as shown on
the Company's consolidated statement of operations.
Atlantic Power
Corporation
Table 9A – Cash
Distributions from Projects (by Segment, in millions of U.S.
dollars)
Nine months ended
September 30, 2014 (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
|
|
|
|
|
|
|
Consolidated
|
$80.7
|
$(12.2)
|
$(5.7)
|
$(7.8)
|
$8.9
|
$63.9
|
Equity
method
|
35.8
|
(3.8)
|
(6.2)
|
(0.6)
|
1.2
|
26.4
|
Total
|
116.5
|
(16.0)
|
(11.9)
|
(8.4)
|
10.1
|
90.3
|
West
|
|
|
|
|
|
|
Consolidated
|
51.6
|
(0.1)
|
-
|
(0.7)
|
0.5
|
51.3
|
Equity
method
|
10.7
|
(1.0)
|
(0.1)
|
-
|
1.2
|
10.8
|
Total
|
62.3
|
(1.1)
|
(0.1)
|
(0.7)
|
1.7
|
62.1
|
Wind
|
|
|
|
|
|
|
Consolidated
|
41.2
|
(3.5)
|
(10.6)
|
(0.4)
|
3.3
|
30.0
|
Equity
method
|
7.8
|
(1.9)
|
(3.6)
|
0.2
|
2.1
|
4.6
|
Total
|
49.0
|
(5.4)
|
(14.2)
|
(0.2)
|
5.4
|
34.6
|
Total
consolidated
|
173.5
|
(15.8)
|
(16.3)
|
(8.9)
|
12.7
|
145.2
|
Total equity
method
|
54.3
|
(6.7)
|
(9.9)
|
(0.4)
|
4.5
|
41.8
|
Un-allocated
corporate
|
(6.2)
|
-
|
-
|
(1.1)
|
7.3
|
-
|
Total
|
$221.6
|
$(22.5)
|
$(26.2)
|
$(10.4)
|
$24.5
|
$187.0
|
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, 2013 (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
|
|
|
|
|
|
|
Consolidated
|
$74.2
|
$(3.3)
|
$(12.8)
|
$(2.6)
|
$17.6
|
$73.1
|
Equity
method
|
37.9
|
(10.4)
|
(0.9)
|
(0.6)
|
0.6
|
26.6
|
Total
|
112.1
|
(13.7)
|
(13.7)
|
(3.2)
|
18.2
|
99.7
|
West
|
|
|
|
|
|
|
Consolidated
|
54.0
|
-
|
-
|
(1.1)
|
(13.2)
|
39.7
|
Equity
method
|
13.3
|
(1.9)
|
(0.3)
|
(1.2)
|
0.6
|
10.5
|
Total
|
67.3
|
(1.9)
|
(0.3)
|
(2.3)
|
(12.6)
|
50.2
|
Wind
|
|
|
|
|
|
|
Consolidated
|
36.1
|
(4.9)
|
(11.0)
|
(2.9)
|
0.1
|
17.4
|
Equity
method
|
7.3
|
(1.7)
|
(3.6)
|
(0.2)
|
0.6
|
2.4
|
Total
|
43.4
|
(6.6)
|
(14.6)
|
(3.1)
|
0.7
|
19.8
|
Total
consolidated
|
164.3
|
(8.2)
|
(23.8)
|
(6.6)
|
4.5
|
130.2
|
Total equity
method
|
58.5
|
(14.0)
|
(4.8)
|
(2.0)
|
1.8
|
39.5
|
Un-allocated
corporate
|
(11.4)
|
(0.3)
|
(1.8)
|
-
|
13.5
|
-
|
Total
|
$211.4
|
$(22.5)
|
$(30.4)
|
$(8.6)
|
$19.8
|
$169.7
|
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,
|
|
2014
|
2013
|
|
2014
|
2013
|
Cash Distributions
from Projects
|
$51.2
|
$65.7
|
|
$187.0
|
$169.7
|
Repayment of long-term
debt
|
(4.5)
|
(5.6)
|
|
(22.5)
|
(22.5)
|
Interest expense,
net
|
(7.5)
|
(10.6)
|
|
(26.2)
|
(30.4)
|
Capital
expenditures
|
(7.4)
|
(2.1)
|
|
(10.4)
|
(8.6)
|
Other, including
changes in working capital
|
(1.6)
|
9.0
|
|
24.5
|
19.8
|
Project Adjusted
EBITDA
|
$72.2
|
$75.0
|
|
$221.6
|
$211.4
|
Depreciation and
amortization
|
50.4
|
51.1
|
|
154.8
|
153.5
|
Interest expense,
net
|
7.6
|
10.7
|
|
32.4
|
30.5
|
Change in the fair
value of derivative instruments
|
(0.4)
|
3.6
|
|
(11.5)
|
(34.8)
|
Other (income)
expense
|
83.2
|
5.2
|
|
98.1
|
5.8
|
Project (loss)
income
|
$(68.6)
|
$4.4
|
|
$(52.2)
|
$56.4
|
Administrative and
other expenses (income)
|
16.9
|
45.0
|
|
125.0
|
84.8
|
Income tax (benefit)
expense
|
5.6
|
-
|
|
(7.4)
|
(1.9)
|
Net loss from
discontinued operations, net of tax
|
-
|
-
|
|
(0.1)
|
(5.2)
|
Net
loss
|
$(91.1)
|
$(40.6)
|
|
$(169.9)
|
$(31.7)
|
Adjustments to
reconcile to net cash provided by operating activities
|
117.4
|
57.2
|
|
209.6
|
123.7
|
Change in other
operating balances
|
14.1
|
29.8
|
|
6.2
|
51.3
|
Cash flows from
operating activities
|
$40.4
|
$46.4
|
|
$45.9
|
$143.3
|
Term loan facility
repayments (1)
|
(9.6)
|
-
|
|
(47.1)
|
-
|
Project-level debt
repayments
|
(4.2)
|
(1.7)
|
|
(19.6)
|
(12.2)
|
Purchases of property,
plant and equipment (2)
|
(7.5)
|
(1.5)
|
|
(10.0)
|
(4.2)
|
Distributions to
noncontrolling interests (3)
|
(3.6)
|
(1.4)
|
|
(8.8)
|
(4.4)
|
Dividends on preferred
shares of a subsidiary company
|
(2.9)
|
(3.2)
|
|
(8.8)
|
(9.5)
|
Free Cash
Flow
|
$12.6
|
$38.6
|
|
$(48.4)
|
$113.0
|
(1)
Includes mandatory 1% annual amortization and 50% excess cash flow
repayments by the Partnership.
(2)
Excludes construction costs related to our Canadian Hills project
in 2014 and 2013 and our Piedmont and Meadow Creek projects in
2013.
(3)
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 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 11 – 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,
|
|
|
|
2014
|
2013
|
|
2014
|
2013
|
East
|
|
Accounting
|
|
|
|
|
|
Cadillac
|
|
Consolidated
|
$2.2
|
$2.5
|
|
$5.4
|
$7.1
|
Curtis
Palmer
|
|
Consolidated
|
5.5
|
6.5
|
|
24.2
|
25.2
|
Morris
|
|
Consolidated
|
3.0
|
2.8
|
|
9.6
|
4.9
|
Nipigon
|
|
Consolidated
|
1.4
|
(0.5)
|
|
10.1
|
8.2
|
North Bay
|
|
Consolidated
|
0.9
|
0.6
|
|
6.9
|
5.0
|
Piedmont
|
|
Consolidated
|
3.4
|
3.5
|
|
4.2
|
3.7
|
Tunis
|
|
Consolidated
|
1.3
|
2.0
|
|
7.1
|
6.1
|
Other
(1)
|
|
Consolidated
|
2.8
|
3.0
|
|
13.2
|
14.0
|
Chambers
|
|
Equity
method
|
4.3
|
5.3
|
|
14.1
|
15.5
|
Selkirk
|
|
Equity
method
|
2.6
|
5.5
|
|
11.7
|
15.7
|
Orlando
|
|
Equity
method
|
5.3
|
2.3
|
|
10.0
|
6.7
|
Total
|
|
|
32.7
|
33.5
|
|
116.5
|
112.1
|
West
|
|
|
|
|
|
|
|
Manchief
|
|
Consolidated
|
3.7
|
4.5
|
|
10.9
|
12.3
|
Naval
Station
|
|
Consolidated
|
4.4
|
5.0
|
|
9.1
|
9.4
|
Williams
Lake
|
|
Consolidated
|
5.8
|
7.0
|
|
12.6
|
15.4
|
Other
(2)
|
|
Consolidated
|
11.2
|
11.5
|
|
19.0
|
16.9
|
Frederickson
|
|
Equity
method
|
3.0
|
3.0
|
|
8.9
|
8.9
|
Other
(3)
|
|
Equity
method
|
0.2
|
1.7
|
|
1.8
|
4.4
|
Total
|
|
|
28.3
|
32.7
|
|
62.3
|
67.3
|
Wind
|
|
|
|
|
|
|
|
Canadian
Hills
|
|
Consolidated
|
5.7
|
3.7
|
|
19.4
|
18.4
|
Meadow
Creek
|
|
Consolidated
|
3.7
|
3.9
|
|
13.8
|
10.4
|
Rockland
|
|
Consolidated
|
2.3
|
2.8
|
|
8.0
|
7.3
|
Other
(4)
|
|
Equity
method
|
2.4
|
2.5
|
|
7.8
|
7.3
|
Total
|
|
|
14.1
|
12.9
|
|
49.0
|
43.4
|
Totals
|
|
|
|
|
|
|
|
Consolidated
projects
|
|
|
57.3
|
58.8
|
|
173.5
|
164.3
|
Equity method
projects
|
|
|
17.8
|
20.3
|
|
54.3
|
58.5
|
Un-allocated
corporate
|
|
|
(2.9)
|
(4.1)
|
|
(6.2)
|
(11.4)
|
Total Project
Adjusted EBITDA
|
|
|
$72.2
|
$75.0
|
|
$221.6
|
$211.4
|
|
|
|
|
|
|
|
|
Reconciliation to
project income (loss)
|
|
|
|
|
|
|
|
Depreciation and
amortization
|
|
|
$50.4
|
$51.1
|
|
$154.8
|
$153.5
|
Interest expense,
net
|
|
|
7.6
|
10.7
|
|
32.4
|
30.5
|
Change in the fair
value of derivative instruments
|
|
|
(0.4)
|
3.6
|
|
(11.5)
|
(34.8)
|
Other
expense
|
|
|
83.2
|
5.2
|
|
98.1
|
5.8
|
Project (loss)
income
|
|
|
$(68.6)
|
$4.4
|
|
$(52.2)
|
$56.4
|
(1) Kenilworth,
Calstock, and Kapuskasing
(2) Moresby Lake,
Mamquam, North Island, Naval Training Station, and
Oxnard
(3) Q3 and YTD
September 2013: Koma Kulshan, Gregory, and Delta-Person; Q3 and YTD
September 2014: Koma Kulshan and Delta-Person
(4) Idaho Wind and
Goshen North
Notes: Table 11
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.
|
|
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SOURCE Atlantic Power Corporation