BOSTON, Feb. 26, 2015 /PRNewswire/ -- Atlantic Power
Corporation (NYSE: AT) (TSX: ATP) ("Atlantic Power" or the
"Company") today released its results for the three months and year
ended December 31, 2014.
"Since our third quarter earnings call, Atlantic Power has made
significant progress on its strategy by meaningfully reducing
overhead costs, delivering attractive cash returns from
discretionary investments in its fleet, and moving ahead on a
potential asset divestiture process," said Mr. James J. Moore, Jr., President and Chief
Executive Officer of Atlantic Power. "Our plans for 2015
include further significant reductions in our overhead run rates
from 2015 to 2016 and additional investments in our fleet at cash
returns and risk levels that are much more favorable than those
available in the external markets, both of which should result in
improved internal cash flow. In addition, we are evaluating
potential asset divestitures as well as refinancing to achieve our
goal of reshaping our debt. We expect that our successful
execution of this plan will provide a stable platform for Atlantic
Power to begin growing its business again in 2016 on an absolute
basis, in addition to the organic growth in cash flows provided by
returns on discretionary investments in our fleet and cost
reductions."
Mr. Moore continued, "Project Adjusted EBITDA for 2014 came in
at the high end of our guidance range. We also generated an
increase in Adjusted Cash Flows from Operating Activities, which we
used to reinvest in our projects, pay down debt and pay dividends
to shareholders. Our results benefited from strong wind
generation, increased waste heat at our Ontario generation projects, and steps we took
to reduce administrative expenses. We also received a modest
contribution from the $18 million of
discretionary optimization investments made in our existing fleet
in 2013 and 2014."
"We continue to make significant progress in rationalizing our
corporate overhead, including development expense, reducing it from
$54 million in 2013 to an expected
level of $38 million or lower in
2015, with further significant improvement expected in 2016.
We also expect to make another $11
million of discretionary optimization investments in 2015,
for a three-year total of approximately $29
million. By 2016, we expect these investments to be
producing a cash flow benefit of at least $10 million annually," said Mr. Moore. "In
addition, we remain focused on reducing our leverage through
amortization, opportunistic repurchases of our debt and the use of
proceeds from potential asset divestitures, if market valuations
are compelling, or by reshaping our debt through refinancing and
extended amortization. We expect to be able to provide
greater detail on these efforts by our next quarterly earnings
report."
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 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.
Atlantic Power
Corporation
Table 1 – Selected
Results
(in millions of
U.S. dollars, except as otherwise stated)
|
|
Years ended
December 31,
|
Unaudited
|
2014
|
2013
|
Excluding results
from discontinued operations (1)
|
|
|
Project
revenue
|
$569.2
|
$544.1
|
Project (loss)
income
|
(50.5)
|
63.7
|
Project Adjusted
EBITDA
|
299.3
|
268.9
|
Cash Distributions
from Projects
|
248.9
|
223.0
|
Adjusted Cash Flows
from Operating Activities
|
142.4
|
75.7
|
Adjusted Free Cash
Flow
|
29.9
|
37.6
|
Aggregate power
generation (thousands of Net MWh)
|
8,199.3
|
8,094.5
|
Weighted average
availability
|
93%
|
95%
|
Including results
from discontinued operations (1)
|
|
|
Cash flows from
operating activities
|
$65.0
|
$152.4
|
Free Cash
Flow
|
(55.6)
|
108.8
|
(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, Cash
Distributions from Projects, and Adjusted Cash Flows from Operating
Activities from these assets are included in discontinued
operations for the years ended December 31, 2013 and December 31,
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 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.
|
Year End 2014 Financial Highlights
- Project Adjusted EBITDA of $299.3
million increased $30.4
million from 2013 and came in at the high end of the
Company's revised guidance range of $285 to
$300 million
- GAAP results included $106.6
million of non-cash impairments and an $8.7 million non-cash loss on changes in the fair
value of derivatives, partially offset by an $8.6 million asset sale gain, for a project loss
of $(50.5) million; excluding these
items, project income was $56.2
million. For 2013, project income of $63.7 million included a $34.9 million non-cash impairment, which was more
than offset by a $49.5 million
non-cash gain on changes in the fair value of derivatives and a
$30.4 million asset sale gain;
project income excluding these items was $18.7 million. Thus, the year-over-year increase
in project income excluding these items was $37.5 million
- Cash flows from operating activities of $65.0 million decreased $87.4 million from 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 $(55.6) million
decreased $164.4 million from 2013
due primarily to the decrease in cash flows from operating
activities described above, increased debt repayment and higher
capex
- Adjusted Cash Flows from Operating Activities, which excludes
the items affecting cash flows from operating activities described
above, was approximately $142 million
in 2014, and was primarily used to reduce debt, fund capital
expenditures, and pay dividends to shareholders; the increase of
$66.7 million from 2013 was
attributable to increased Project Adjusted EBITDA, higher cash
distributions from projects and modestly lower cash interest
expense
- Adjusted Free Cash Flow of $29.9
million decreased $7.7 million
from 2013, as the increase in Adjusted Cash Flows from Operating
Activities was more than offset by a higher level of debt
amortization
- Completed $18 million of major
optimization projects in 2013-2014 and expect to realize cash flow
benefit of $4 to $8 million in
2015
Progress on Debt Reduction Goals
- Reduced outstanding amount of APLP term loan through mandatory
amortization and cash sweep by $58
million, approximately $5
million more than expected
- Repaid approximately $29 million
of project-level debt, including at equity-owned projects
- Repaid Cdn$44.8 million
convertible debenture at maturity on October
31, 2014 using cash on hand; expect interest savings in 2015
of $2.7 million
- Repurchased $3.1 million of
convertible debentures in December under Normal Course Issuer Bid
(NCIB) and another $6.1 million in
2015 to date
- Repurchased $9 million of senior
unsecured notes in January 2015;
amount outstanding now $310.9
million
2015 Guidance and Capital Deployment Plans
- Total Company Project Adjusted EBITDA of $265 to $285 million
- APLP Project Adjusted EBITDA of $148 to
$160 million
- Adjusted Cash Flows from Operating Activities of $120 to $140 million
- Adjusted Free Cash Flow of $10 to $30
million
- Expect to achieve at least a $16
million reduction in general and administrative (G&A)
and development expenses in 2015 relative to 2013
- Planning $11 million of
optimization investments in 2015
- Expect major maintenance and capex of approximately
$35 million in 2015
- Expect to amortize approximately $48 to
$54 million of APLP term loan and $24
million of project-level debt (total of approximately
$75 million); will continue to
evaluate opportunistic debt repurchases using cash on hand and
proceeds from potential asset sales, if market valuations are
compelling
Strategy
The Company continues to focus on executing its business plan,
including the objectives of enhancing the value of its existing
assets through discretionary capital investments and commercial
activities, delevering its balance sheet to reduce its interest
expense and improve its cost of capital to better compete for new
investments, improving its cost structure and reducing
overhead. In addition, the Company continues to assess other
potential options, including selected asset sales or the
contribution of assets to a joint venture, if the valuation of a
particular asset or assets is compelling, in order to raise
additional capital for growth and/or debt reduction. Going forward,
as the Company executes its business strategy, and consistent with
its objectives, the Board of Directors, together with management
will regularly evaluate the optimal dividend policy for the
Company.
Operating Results
Project availability declined to 93.4% in 2014 from 94.8%
in 2013. The decrease was attributable to a combination of
forced outages (some weather-related, particularly in the first
quarter) and extensions of scheduled maintenance outages,
particularly at Nipigon, Chambers,
Orlando and Canadian Hills.
For the year, reduced availability resulted in capacity payments
being $10.3 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 2014, and Piedmont,
which had several forced outages during the
year.
Generation increased 1.3% year over year due primarily to
the addition of Piedmont in
April 2013 (additional quarter in
2014), increased generation at Orlando due to the expiration of an
unfavorable natural gas contract in the comparable 2013 period,
higher dispatch at Frederickson and favorable wind conditions for
Meadow Creek. These positive comparisons were partially
offset by reduced dispatch at Manchief and Williams Lake, reduced generation at
Selkirk due to mild summer
weather, and reduced generation at Canadian Hills due to
weather-related outages.
Financial Results
Table 2 provides a breakdown of project income and Project
Adjusted EBITDA by segment for the year ended December 31, 2014 as compared to the same period
in 2013.
Atlantic Power
Corporation
Table 2 – Segment
Results
(in millions of
U.S. dollars, except as otherwise stated)
Unaudited
|
|
Years ended
December 31,
|
|
2014
|
2013
|
Project income
(loss)
|
|
|
East
|
$21.8
|
$25.8
|
West
|
(51.3)
|
35.8
|
Wind
|
(11.5)
|
18.6
|
Un-allocated
Corporate
|
(9.5)
|
(16.5)
|
Total
|
(50.5)
|
63.7
|
Project Adjusted
EBITDA
|
|
|
East
|
$158.5
|
$150.7
|
West
|
78.5
|
77.2
|
Wind
|
69.8
|
59.6
|
Un-allocated
Corporate
|
(7.5)
|
(18.6)
|
Total
|
299.3
|
268.9
|
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.
|
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.
Project income decreased by $114.2
million to a loss of $(50.5)
million for the year ended December
31, 2014 compared to project income of $63.7 million for the same period in 2013.
The reduction in project income was primarily due to non-cash
impairment charges in 2014 of $106.6
million, an increase of $71.7
million from the 2013 period; decreased asset sale gains of
$21.8 million; net year-over-year
non-cash changes in the fair value of gas purchase agreements and
interest rate swap agreements accounted for as derivatives totaling
$(58.2) million; and decreased
project income of $11.9 million at
Selkirk, due to lower energy
revenues and accelerated depreciation. These negative factors
were partially offset by improvements at several projects in the
East and West segments due to favorable outage comparisons;
increased margins at Morris and Orlando; lower interest expense at Curtis
Palmer; improved generation at Meadow
Creek; an additional quarter of Piedmont operation; and a $7.1 million reduction in loss in the
Un-allocated Corporate segment, primarily attributable to
$3.5 million in development and
administrative expense reductions at Ridgeline as well as
administrative reduction initiatives undertaken during the
year.
Excluding the non-cash impairment charges, asset sale gains or
losses and non-cash changes in the fair value of derivatives
described above, the comparisons would be as follows:
- 2014: Reported project loss of $(50.5) million included $106.6 million of non-cash impairments, an
$8.7 million non-cash loss on changes
in the fair value of derivatives, and an $8.6 million asset sale gain. Excluding
these items, results were project income of $56.2 million.
- 2013: Reported project income of $63.7 million included a $34.9 million non-cash impairment, which was more
than offset by a $49.5 million
non-cash gain on changes in the fair value of derivatives and a
$30.4 million asset sale gain.
Excluding these items, project income was $18.7 million.
- Thus, the year-over-year increase in project income excluding
these items was $37.5 million.
The increase was attributable to the factors described previously
(improved results at several projects, lower interest expense at
Curtis Palmer and a reduction in loss in the Un-allocated Corporate
segment).
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.
Project Adjusted EBITDA increased by $30.4 million to $299.3
million for the year ended December
31, 2014 from $268.9 million
for the same period in 2013, at the high end of the Company's
guidance range of $285 to $300
million. For the year, the most significant
contributors to the improvement in Project Adjusted EBITDA were the
wind projects, primarily Meadow
Creek, due to increased generation; the Ontario projects other than Calstock, due to the timing of maintenance
expense and increased waste heat generation; Morris, due primarily
to an increase in energy revenues, partially offset by higher fuel
expenses; Orlando, due to higher
gross margins under an amended PPA and following the expiration of
above-market gas swaps; Piedmont,
due to a full year of operation and lower maintenance expense;
Naval Training Center, due primarily to favorable maintenance
comparisons; Mamquam, due to favorable maintenance comparisons and
improved water flows; and an $11.1
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. These
positive factors were partially offset by decreases at Selkirk, due to the expiration of the
project's PPA in August 2014 and
lower dispatch due to mild summer weather; Manchief, due to higher
than normal dispatch in 2013; Chambers, due to higher major
maintenance costs in 2014; the sales 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 corporate-level G&A
expense, interest expense, foreign exchange gains and losses and
other income, are not included in Project Adjusted EBITDA.
For the year, administration expense increased $2.7 million from the comparable year-ago
period. In the second half of the year, the Company incurred
$6.0 million of severance charges
associated with management changes and personnel reductions, which
are expected to result in lower administrative costs going
forward. These charges were partially offset by lower
transaction costs related to the asset divestitures in 2013 and a
reduction in legal expenses, as in the third quarter of 2014 the
Company exceeded its deductible under its directors and officers
insurance policy with regard to legal costs incurred for the
purported class action shareholder litigation, and expects
additional incurred costs to be paid by its insurance carrier to
the extent set forth under its terms of coverage.
Cash Flow Metrics
Cash Distributions from Projects
Cash Distributions from Projects, which excludes projects
classified as discontinued operations, increased by $25.9 million to $248.9
million for the year ended December
31, 2014, compared to $223.0
million for the same period in 2013. This result
includes an increase of $8.5 million
in the fourth quarter of 2014 from the year-ago period.
Significant increases for 2014 occurred at: (i) Meadow Creek, Canadian Hills, Rockland and Idaho Wind, due to the release of
construction-related blade and credit reserves and increased wind
generation; (ii) 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; (iii) 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;
(iv) the Ontario projects, due to
higher waste heat availability; and (v) Mamquam, due to lower
maintenance expense.
These increases were partially offset by decreases at (i)
Selkirk, due to the expiration of
the PPA at the end of August; (ii) Morris, due to gas storage
purchases; and (iii) 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. The project made a distribution in
December, which was released to the Company in January
2015.
Cash Flows from Operating Activities
Cash flows from operating activities decreased by $87.4 million to $65.0
million for the year ended December
31, 2014 compared to $152.4
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 $65.7
million increase in cash outflows for working capital due to
a $39.4 million decrease in prepaid
and other assets due to the collection of security deposits related
to completed construction projects in the first quarter of 2013,
and a decrease in cash flows from discontinued operations (projects
sold in 2013).
Free Cash Flow
Free Cash Flow decreased by $164.4
million to $(55.6) million for
the year ended December 31, 2014
compared to $108.8 million for the
same period in 2013. The decrease is primarily due to an
$87.4 million decrease in operating
cash flows as described previously, $58.4
million of term loan facility repayments by APLP and a
$10.6 million increase in
project-level debt repayment.
The Company's full year 2014 Free Cash Flow guidance of
$0 to $10 million excluded (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 full year 2014 was approximately
$2 million compared to $109 million for the same period in 2013.
Relative to the Company's guidance, Free Cash Flow was reduced by
approximately $5 million due to a
higher level of term loan repayments than previously expected.
Adjusted Cash Flows from Operating Activities
Adjusted Cash Flows from Operating Activities increased by
$66.7 million to $142.4 million for the year ended December 31, 2014 compared to $75.7 million for the same period in 2013.
Unlike cash flows from operating activities, which decreased on a
year-over-year basis, Adjusted Cash Flows from Operating Activities
excludes the impact of certain non-recurring items, such as the
refinancing and repurchase transactions in the first quarter of
2014, as well as changes in working capital (both of which reduced
operating cash flow in 2014 relative to 2013). The increase
in Adjusted Cash Flows from Operating Activities for the year was
primarily attributable to higher levels of Project Adjusted EBITDA,
higher cash distributions from projects and modestly lower cash
interest expense.
Adjusted Free Cash Flow
Adjusted Free Cash Flow decreased by $7.7
million to $29.9 million for
the year ended December 31, 2014
compared to $37.6 million for the
same period in 2013, as the increase in Adjusted Cash Flows from
Operating Activities was more than offset by higher levels of debt
repayment, particularly amortization of the APLP term loan.
Unlike Free Cash Flow, Adjusted Free Cash Flow does not include
changes in working capital or cash outlays for transaction expenses
(such as the refinancing transaction expenses incurred in the first
quarter of 2014) or the repayment of Piedmont debt at term loan conversion, both of
which reduced Free Cash Flow.
Tables 11 and 12 of this press release provide a reconciliation
of the Company's non-GAAP cash flow metrics to cash flows from
operating activities.
Financial Results for the Three Months Ended December 31, 2014
Project income decreased by $4.5
million to $2.8 million for
the three months ended December 31,
2014 from $7.3 million for the
year-ago period. The decrease in project income relates
primarily to a $37.5 million
mark-to-market decrease in the fair value of derivatives, partially
offset by higher levels of Project Adjusted EBITDA and a reduction
in project expenses including depreciation and interest
expense.
Project Adjusted EBITDA increased by $19.8 million to $77.9
million for the three months ended December 31, 2014 from $58.1 million for the year-ago period.
Significant increases occurred at Piedmont (lower maintenance expense due to a
maintenance outage in the fourth quarter of 2013 and a partial
reversal of a 2013 accrual), Orlando (more favorable PPA and gas supply
costs), North Island (major gas turbine overhaul in 2013
period), Williams Lake
(higher availability and other factors), and the wind projects in
Idaho (favorable winds). In
addition, the Company benefited from a reduction in Un-allocated
Corporate expenses of $4.8 million
due to steps taken earlier in the year to reduce administrative and
development expense. These positive factors were partially
offset by a reduction at Selkirk,
for which the PPA expired on August
31, and which was also affected by mild weather and reduced
dispatch in the fourth quarter.
Liquidity
As can be seen from Table 3, the Company's liquidity decreased
from approximately $272 million as of
September 30, 2014, to $214 million at December
31, 2014, including $110
million of unrestricted cash. During the fourth
quarter, the Company used approximately $43
million of cash on hand to repay Cdn$44.8 million of convertible debentures
(ATP.DB) at their October 31st
maturity date. It also repurchased $3.1 million of convertible debentures under the
NCIB and paid $3.1 million of
dividends on its common shares.
Atlantic Power
Corporation
Table 3 –
Liquidity (in millions of U.S. dollars)
|
Unaudited
|
September
30, 2014
|
December 31,
2014
|
Revolver
capacity
|
$210.0
|
$210.0
|
Letters of credit
outstanding
|
(106.0)
|
(105.7)
|
Unused borrowing
capacity
|
104.0
|
104.3
|
Unrestricted cash
(1)
|
167.6
|
109.9
|
Total
Liquidity
|
$271.6
|
$214.2
|
(1)
Includes project-level cash for working capital needs of $16.3
million at September 30, 2014 and $18.2 million at December 31,
2014.
|
Other Financial Updates
Goodwill Impairment Assessment
At December 31, 2014, the Company
had $197.2 million of goodwill.
As previously reported, the Company performed an event-driven
test of its goodwill and long-lived assets at all of its projects
as of August 31, 2014 and during the
third quarter of 2014 recorded goodwill impairments at its
Kenilworth, Manchief and
Williams Lake projects.
During the fourth quarter, the Company performed its annual
goodwill impairment test as of November 30,
2014 and determined that no further impairments were
required at that time. The Company also updated its asset
impairment analysis for Tunis and
determined that no further impairment of long-lived assets was
required (the Company had previously written off all of the
goodwill at Tunis).
Senior Unsecured Notes – Fixed Charge Coverage Ratio
As previously reported, the Company can no longer satisfy the
Fixed Charge Coverage Ratio test under the restricted payments
covenant of its senior unsecured note indenture. The test is
based on rolling four quarter results. In the second quarter
of 2015, the charges recorded in the first quarter of 2014 for the
refinancing and repurchase transaction costs will no longer be
included in the calculation and the Company expects to be back in
compliance at that time. Until then, the Company is limited
to the payment of common dividends not exceeding the Restricted
Payments basket, which is the greater of $50
million or 2% of consolidated net assets ($55.8 million as of December 31, 2014). Through year-end 2014,
the Company had paid dividends totaling $32.5 million that count against the basket
provision; another $3 million of
dividends declared in February 2015
to be paid in March 2015 are also
subject to the basket provision. In addition, any similar
debt prepayment charges incurred in connection with further debt
reduction would also be reflected in the calculation of the fixed
charge coverage ratio on a rolling four quarter basis, beginning
with the quarter in which such charges are incurred, as would any
associated reduction in interest expense.
2015 Guidance and Outlook
G&A Expense Targets
Project-level G&A expense and Ridgeline expenses, including
development expense, 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, which is not included in Project Adjusted EBITDA.
Together these comprise total G&A expense.
As previously disclosed, during 2013 and 2014 the Company
undertook a number of steps to reduce its G&A and development
costs, including recent management changes and personnel
reductions. These actions are expected to result in cost
savings going forward, including in 2015. In addition to
personnel cost savings, the Company expects to have lower project
and business development expense, including a $3 million annual benefit from the scheduled
expiration of a contractual obligation related to the Ridgeline
acquisition in the first quarter of 2015. In addition, as
discussed above, the Company expects to have lower legal expenses
going forward.
Total G&A expense in 2014 was $45
million, including $6 million
of severance expense. The Company expects G&A expense in
2015 of no more than $38 million,
including approximately $3 million of
severance expense. The Company is targeting further
significant improvement in G&A expense in 2016.
Optimization Investments
In 2013 and 2014, the Company made approximately $18 million of discretionary investments in its
existing projects designed to increase the output, improve the
efficiency or improve the margins of these facilities. In
2015, the Company expects to realize a cash flow benefit of
$4 to $8 million from these
investments. The most significant of these projects were the
repowering of two turbines at Curtis Palmer, the steam generator
replacement and upgrade at Nipigon, an investment designed to boost
output at Morris during peak periods and an interconnection upgrade
at North Island. The Company expects to revisit this
expectation as it gains operating experience with these upgrades
over the course of this year.
The Company expects to invest another $11
million in 2015 across a number of projects, with the most
significant at Curtis Palmer, Mamquam, Nipigon, and several at Morris. Together
with optimization investments completed in 2013 and 2014, the
Company expects a cash flow benefit from these investments of at
least $10 million in 2016.
In addition to these production-based investments, the Company
continues to pursue commercial and asset management opportunities
around its existing projects, some of which require only a modest
level of capital expenditures or expense. Examples of these
include bringing outsourced project management contracts in-house;
improving commercial terms around fuel supply or other consumables;
reducing letter of credit requirements; identifying ways to improve
the terms of existing PPAs for both the Company and its customers;
and positioning the projects to be able to take advantage of
opportunities in the power markets. Any cash contribution
from these efforts is incremental to those realized from
production-based optimization projects.
The Company views both the optimization projects as well as its
commercial and asset management activities to be an attractive use
of its cash considering the relatively modest capital requirements
and potential for strong risk-adjusted returns.
Major Maintenance and Capex
In 2014, the Company had capex of $13
million and major maintenance expense of $20 million, for a total of $33 million, in line with the Company's
expectation of $35 million. The
capex figure is net of approximately $2.4
million of insurance proceeds and other recoveries for
Piedmont. Most of the capex (approximately $12 million) were for the discretionary
optimization investments discussed above at Curtis Palmer,
Nipigon, Morris and North
Island.
For 2015, the Company expects capex of approximately
$12 million, of which approximately
$10 million relates to discretionary
optimization investments at Morris, Nipigon and Curtis Palmer.
(Approximately $11 million of the
$12 million total capex budget is for
projects at APLP.) Major maintenance expense is expected to
be approximately $23 million, with
the increase from 2014 primarily attributable to the scheduled gas
turbine outage at Manchief.
Debt Reduction
The Company expects to amortize approximately $24 million of project-level debt in 2015,
including its share of debt at equity method projects. It
also expects to repay $48 to $54
million of APLP term loan through the 50% cash sweep and 1%
mandatory amortization, for a total debt reduction through
amortization of approximately $75
million. Amortization of project-level debt and the
APLP term loan is expected to average approximately $75 million annually over the next five years
($80 million on a three-year average
basis). In addition, the Company will continue to evaluate
discretionary repurchases of debt using cash on hand or the
proceeds from potential asset sales, if the valuation of a
particular asset or assets is compelling. In January 2015, the Company repurchased
$9 million of senior unsecured
notes. Year to date through February
21, 2015, it had repurchased $6.1
million of convertible debentures under the
NCIB.
Guidance
The Company is initiating 2015 guidance as follows:
- Project Adjusted EBITDA of $265 to $285 million. The decline from 2014
($299.3 million) is primarily
attributable to the expiration of PPAs for Selkirk and Tunis in 2014 and a gas turbine overhaul at
Manchief, partially offset by higher results from Orlando, Nipigon and several other projects.
- Project Adjusted EBITDA for APLP of
$148 to $160 million
- Adjusted Cash Flows from Operating
Activities of $120 to $140
million. The decline from 2014 ($142 million) is primarily attributable to lower
Project Adjusted EBITDA, partially offset by lower G&A expense
and lower interest expense.
- Adjusted Free Cash Flow of $10 to $30 million. This is net of planned
capital expenditures totaling $12
million and consolidated project-level debt and term loan
amortization totaling approximately $72
million. The decrease in Adjusted Free Cash Flow from the
2014 level of $30 million is
primarily attributable to lower levels of G&A expense, interest
expense, and debt amortization, which are expected to be more than
offset by lower Project Adjusted EBITDA.
See Table 4 for full-year 2015 guidance and 2014 actual
results.
Atlantic Power
Corporation
Table 4 – 2015
Annual Guidance vs. 2014 Actual Results
(in millions of
U.S. dollars, except as otherwise stated)
|
Unaudited
|
2015 Annual
Guidance
|
2014
Actual
|
Project Adjusted
EBITDA
|
$265 -
$285
|
$299.3
|
Adjusted Cash Flows
from Operating Activities (1)
|
$120 -
$140
|
$142.4
|
Adjusted Free Cash
Flow (2)
|
$10 - $30
|
$29.9
|
APLP Project Adjusted
EBITDA (3)
|
$148 -
$160
|
$176.1
|
(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 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.
(2)
Adjusted Free Cash Flow is defined as Free Cash Flow excluding
changes in working capital balances, acquisition expenses,
litigation expense, severance and restructuring charges, 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 new
term loan; and distributions to noncontrolling interests, including
preferred share dividends.
(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.
|
Business Update
Piedmont
Currently the Company does not expect its Piedmont project to meet its debt service
coverage ratio covenants, restricting its ability to make
distributions before 2017 at the earliest, due to continued
operational issues that have resulted in higher forecasted
maintenance and fuel expenses than initially expected.
Tunis
The PPA with the Ontario Power Authority (OPA) for the Company's
Tunis project expired on
December 31, 2014; however, the
Company has entered into an agreement with the OPA and its
successor, the Independent Electricity System Operator (IESO), for
the future operations of the Tunis
facility. Subject to meeting certain technical modifications
to the plant, gas delivery and other requirements, Tunis will operate under a 15-year agreement
with the IESO commencing between November
2017 and June 2019.
The new contract will require the plant to become fully
dispatchable as opposed to its current baseload
configuration. As such, Tunis will provide electricity to the
Ontario grid only when required,
thereby assisting to reduce the incidents of surplus baseload
generation in the market. The new agreement provides
Tunis with a fixed monthly payment
which escalates annually according to a pre-defined formula while
allowing Tunis to earn additional
energy revenues for those periods during which it is called upon to
operate.
Supplementary Financial Information
For further information, attached to this news release is a
summary of Project Adjusted EBITDA by segment for the three months
and years ended December 31, 2014 and
2013 (Table 9) with a reconciliation to Project income (loss); a
bridge from Project Adjusted EBITDA to Cash Distributions from
Projects by segment for the year ended December 31, 2014 (Table 10A) and the year ended
December 31, 2013 (Table 10B); 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 years
ended December 31, 2014 and 2013
(Table 11); a reconciliation of Adjusted Cash Flows from Operating
Activities and Adjusted Free Cash Flow to cash flows from operating
activities (Table 12); 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 years ended December 31,
2014 and 2013 (Table 13).
Investor Conference Call and Webcast
A telephone conference call hosted by Atlantic Power's
management team will be held on Friday, February 27, 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 4977312
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
10058795. The replay will be available 1 hour after
the end of the conference call through May
28, 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 the
Company and its projects. These statements, which are
based on certain assumptions and describe the Company's future
plans, strategies and expectations, can generally be identified by
the use of the words "may," "will," "project," "continue,"
"believe," "intend," "anticipate," "expect" or similar expressions
that are predictions of or indicate future events or trends and
which do not relate solely to present or historical matters.
Examples of such statements in this press release include,
but are not limited, to statements with respect to the
following:
- the Company's plans for 2015, including further significant
reductions in overhead run rates from 2015 to 2016 and additional
investments in its fleet at cash returns that the company believes
are more favorable than those available in external markets, both
of which the company expects to result in improved cash flow;
- the Company's expectation that successful execution of its
business plan will provide a stable platform for it to begin
growing its business again in 2016 on an absolute basis, in
addition to the organic growth in cash flows provided by returns on
discretionary investments in its fleet and cost reductions;
- the outcome or impact of the Company's business plan, including
the objective of enhancing the value of its existing assets through
optimization investment and commercial activities, delevering its
balance sheet to improve its cost of capital and ability to compete
for new investments, utilizing its core competencies to create
proprietary investment opportunities, improving its cost structure
and reducing overhead;
- the Company's ability to evaluate and/or implement potential
options, including asset sales or the contribution of assets to a
joint venture, if the valuation of a particular asset or assets is
compelling, in order to raise additional capital for growth and/or
debt reduction, and the outcome or impact on the Company's business
plan of any such potential options;
- the Company's expectations regarding the pursuit of commercial
and asset management opportunities around its existing projects and
any cash contributions from such opportunities;
- the Company will achieve expected annual interest rate 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, 2014;
- 2015 Project Adjusted EBITDA will be in the range of
$265 to $285 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 $120 to $140
million;
- 2015 Adjusted Free Cash Flow will be in the range of
$10 to $30 million;
- the Company expects to amortize $48 to
$54 million of the APLP term loan and $24 million of project-level debt in 2015, for a
total debt reduction through amortization of approximately
$75 million; and the expectation that
amortization of project-level debt and the APLP term loan will
average approximately $75 million
annual over the next five years ($80
million on a three-year average basis);
- the Company's expectations regarding compliance with the fixed
charge coverage ratio test included in the restricted payments
covenant in its senior unsecured note indenture;
- the expectation that recent management changes and personnel
reduction will result in cost savings going forward;
- the Company expects to have G&A costs of no more than
$38 million in 2015, for a total
reduction of at least $16 million
relative to 2013, with further significant improvement expected in
2016;
- the Company expects to incur approximately $3 million of severance expense in 2015;
- 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 optimization investments in 2013 and 2014 of approximately
$18 million will produce
approximately $4 to $8 million of
annual cash flow benefit;
- the level of optimization investments will be approximately
$11 million in 2015, and cumulative
investments for 2013 through 2015 will produce a cash flow
contribution of at least $10 million
annually in 2016;
- the Company will have project capital expenditures and major
maintenance expenses of approximately $35
million in 2015, including optimization initiatives of
approximately $11 million;
- Piedmont will be unable to
pass its debt service coverage ratio covenant or make distributions
before 2017; 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 potential options, including asset sales or joint
ventures, if the valuation of a particular asset or assets is
compelling, to raise additional capital for growth and/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 6 –
Consolidated Balance Sheet (in millions of U.S.
dollars)
|
|
December
31,
|
December
31,
|
|
2014
|
2013
|
Assets
|
(Unaudited)
|
|
Current
assets:
|
Cash and cash
equivalents
|
$109.9
|
$158.6
|
Restricted
cash
|
22.5
|
96.2
|
Accounts
receivable
|
57.4
|
64.3
|
Current portion of
derivative instruments asset
|
-
|
0.2
|
Inventory
|
19.3
|
16.0
|
Prepayments and other
current assets
|
16.3
|
16.1
|
Refundable income
taxes
|
0.2
|
4.0
|
Total current
assets
|
225.6
|
355.4
|
|
Property, plant and
equipment, net
|
1,673.4
|
1,813.4
|
Equity investments in
unconsolidated affiliates
|
343.9
|
394.3
|
Power purchase
agreements and intangible assets, net
|
381.4
|
451.5
|
Goodwill
|
197.2
|
296.3
|
Derivative
instruments asset
|
1.1
|
13.0
|
Restricted
cash
|
19.1
|
18.0
|
Deferred financing
costs
|
64.2
|
41.7
|
Other
assets
|
10.7
|
11.4
|
Total
assets
|
$2,916.6
|
$3,395.0
|
|
Liabilities
|
Current
liabilities:
|
Accounts
payable
|
$11.0
|
$14.0
|
Accrued
interest
|
5.4
|
17.7
|
Other accrued
liabilities
|
34.9
|
58.8
|
Current portion of
long-term debt
|
26.4
|
216.2
|
Current portion of
convertible debentures
|
-
|
42.1
|
Current portion of
derivative instruments liability
|
39.2
|
28.5
|
Dividends
payable
|
-
|
6.8
|
Other current
liabilities
|
6.8
|
5.3
|
Total current
liabilities
|
123.7
|
389.4
|
|
Long-term
debt
|
1,388.3
|
1,254.8
|
Convertible
debentures
|
340.6
|
363.1
|
Derivative
instruments liability
|
57.5
|
76.1
|
Deferred income
taxes
|
92.3
|
111.5
|
Power purchase and
fuel supply agreement liabilities, net
|
33.4
|
38.7
|
Other long-term
liabilities
|
64.2
|
65.4
|
Commitments and
contingencies
|
-
|
-
|
Total
liabilities
|
2,100.1
|
2,299.0
|
|
Equity
|
Common shares, no par
value, unlimited authorized shares; 121,323,614 and 120,205,813
issued and outstanding at December 31, 2014 and December 31, 2013,
respectively
|
1,288.4
|
1,286.1
|
Preferred shares
issued by a subsidiary company
|
221.3
|
221.3
|
Accumulated other
comprehensive income (loss)
|
(68.3)
|
(22.4)
|
Retained
deficit
|
(863.9)
|
(655.4)
|
Total Atlantic Power
Corporation shareholders' equity
|
577.5
|
829.6
|
Noncontrolling
interest
|
239.0
|
266.4
|
Total
equity
|
816.6
|
1,096.0
|
Total liabilities and
equity
|
$2,916.6
|
$3,395.0
|
Atlantic Power
Corporation
Table 7 –
Consolidated Statements of Operations
(in millions of
U.S. dollars, except per share amounts)
Unaudited
|
|
Years
Ended December
31,
|
Three months
ended December
31,
|
|
2014
|
2013
|
2012
|
2014
|
2013
|
Project
revenue
|
Energy
sales
|
$315.9
|
$302.2
|
$214.5
|
$81.7
|
$75.6
|
Energy capacity
revenue
|
161.3
|
163.7
|
147.2
|
37.3
|
36.6
|
Other
|
92.0
|
78.2
|
68.1
|
23.4
|
18.5
|
|
569.2
|
544.1
|
429.8
|
142.4
|
130.7
|
|
|
|
|
|
|
Project
expenses:
|
|
|
|
|
|
Fuel
|
210.4
|
194.3
|
164.9
|
50.9
|
48.5
|
Operations and
maintenance
|
130.2
|
150.8
|
119.6
|
29.4
|
41.2
|
Development
|
3.7
|
7.2
|
-
|
1.0
|
2.3
|
Depreciation and
amortization
|
162.6
|
166.1
|
116.6
|
40.3
|
41.4
|
|
506.9
|
518.4
|
401.1
|
121.6
|
133.4
|
Project other income
(expense):
|
|
|
|
|
|
Change in fair value
of derivative instruments
|
(8.7)
|
49.5
|
(59.3)
|
(21.0)
|
16.1
|
Equity in earnings of
unconsolidated affiliates
|
25.8
|
26.9
|
15.2
|
7.1
|
2.3
|
Gain on sale of equity
investments
|
8.6
|
30.4
|
0.6
|
-
|
-
|
Interest expense,
net
|
(31.9)
|
(34.4)
|
(16.4)
|
(5.6)
|
(8.7)
|
Impairment of
goodwill
|
(106.6)
|
(34.9)
|
-
|
-
|
-
|
Other income,
net
|
-
|
0.5
|
-
|
1.5
|
0.3
|
|
(112.8)
|
38.0
|
(59.9)
|
(18.0)
|
10.0
|
Project (loss)
income
|
(50.5)
|
63.7
|
(31.2)
|
2.8
|
7.3
|
|
|
|
|
|
|
Administrative and
other expenses (income):
|
|
|
|
|
|
Administration
|
37.9
|
35.2
|
28.3
|
12.0
|
6.7
|
Interest,
net
|
146.7
|
104.1
|
89.8
|
25.9
|
25.4
|
Foreign exchange
(gain) loss
|
(38.3)
|
(27.4)
|
0.5
|
(17.9)
|
(14.5)
|
Other income,
net
|
(2.8)
|
(10.5)
|
(5.7)
|
(0.7)
|
(1.0)
|
|
143.5
|
101.4
|
112.9
|
19.3
|
16.6
|
Loss from continuing
operations before income taxes
|
(194.0)
|
(37.7)
|
(144.1)
|
(16.5)
|
(9.3)
|
Income tax
benefit
|
(11.9)
|
(19.5)
|
(28.1)
|
(4.5)
|
(17.6)
|
(Loss) income from
continuing operations
|
(182.1)
|
(18.2)
|
(116.0)
|
(12.0)
|
8.3
|
Net (loss) income
from discontinued operations, net of tax (1)
|
(0.1)
|
(5.6)
|
15.7
|
-
|
(0.4)
|
Net (loss)
income
|
(182.2)
|
(23.8)
|
(100.3)
|
(12.0)
|
7.9
|
Net loss attributable
to noncontrolling interest
|
(16.4)
|
(3.4)
|
(0.6)
|
(4.6)
|
(0.1)
|
Net income
attributable to preferred share dividends of a subsidiary
company
|
11.6
|
12.6
|
13.1
|
2.8
|
3.0
|
Net (loss) income
attributable to Atlantic Power Corporation
|
$(177.4)
|
$(33.0)
|
$(112.8)
|
$(10.2)
|
$4.9
|
|
|
|
|
|
|
Basic and diluted
earnings (loss) earnings per share:
|
|
|
|
|
|
(Loss) income from
continuing operations attributable to Atlantic Power
Corporation
|
$(1.47)
|
$(0.23)
|
$(1.10)
|
$(0.09)
|
$0.04
|
(Loss) income from
discontinued operations, net of tax
|
-
|
(0.05)
|
0.13
|
-
|
-
|
Net (loss) income
attributable to Atlantic Power Corporation
|
$(1.47)
|
$(0.28)
|
(0.97)
|
$(0.09)
|
$0.04
|
(1) Includes
contributions from the Sold Projects and Rollcast which are a
component of discontinued operations.
|
Atlantic Power
Corporation
Table 8 –
Consolidated Statements of Cash Flows (in millions of U.S.
dollars)
|
|
Years ended
December 31,
|
Unaudited
|
2014
|
2013
|
2012
|
Cash flows from
operating activities:
|
|
|
|
Net loss
|
$(182.2)
|
$(23.8)
|
$(100.3)
|
Adjustments to
reconcile to net cash provided by operating activities
|
|
|
|
Depreciation and
amortization
|
162.6
|
176.4
|
157.2
|
Loss from discontinued
operations
|
-
|
32.8
|
-
|
(Gain) loss on sale of
assets & other charges
|
(2.9)
|
(5.1)
|
0.8
|
Long-term incentive
plan expense
|
3.5
|
2.2
|
2.5
|
Long-lived asset and
goodwill impairment charges
|
106.6
|
39.7
|
60.5
|
Gain on sale of equity
investments
|
(8.6)
|
(30.4)
|
(0.6)
|
Equity in earnings
from unconsolidated affiliates
|
(25.8)
|
(26.9)
|
(25.7)
|
Distributions from
unconsolidated affiliates
|
76.2
|
40.9
|
38.4
|
Unrealized foreign
exchange (gain) loss
|
(38.8)
|
(13.0)
|
19.0
|
Change in fair value
of derivative instruments
|
8.7
|
(60.2)
|
46.7
|
Change in deferred
income taxes
|
(15.7)
|
(27.3)
|
(34.1)
|
Change in other
operating balances
|
|
|
|
Accounts
receivable
|
6.9
|
3.4
|
2.3
|
Inventory
|
(3.3)
|
0.8
|
(6.2)
|
Prepayments,
refundable income taxes and other assets
|
21.1
|
51.5
|
(13.3)
|
Accounts
payable
|
(4.1)
|
(8.4)
|
21.1
|
Accruals and other
liabilities
|
(39.2)
|
(0.2)
|
(1.2)
|
Cash provided by
operating activities
|
65.0
|
152.4
|
167.1
|
|
|
Cash flows provided
by (used in) investing activities
|
|
|
|
Change in restricted
cash
|
72.6
|
(93.7)
|
(11.6)
|
Proceeds from sale of
assets and equity investments, net
|
9.5
|
182.6
|
27.9
|
Cash paid for
acquisitions and investments, net of cash acquired
|
-
|
-
|
(80.5)
|
Proceeds from treasury
grant
|
-
|
103.2
|
-
|
Biomass development
costs
|
-
|
(0.2)
|
(0.5)
|
Construction in
progress
|
-
|
(39.3)
|
(456.2)
|
Purchase of property,
plant and equipment
|
(13.4)
|
(5.5)
|
(2.9)
|
Cash provided by
(used in) investing activities
|
68.7
|
147.1
|
(523.8)
|
|
|
Cash flows (used in)
provided by financing activities
|
|
|
|
Proceeds from senior
secured term loan facility
|
600.0
|
-
|
-
|
Proceeds from issuance
of convertible debentures
|
-
|
-
|
230.6
|
Proceeds from issuance
of equity, net of offering costs
|
-
|
(1.0)
|
66.3
|
Proceeds from
project-level debt
|
-
|
20.8
|
291.9
|
Repayment of corporate
and project-level debt
|
(639.8)
|
(118.8)
|
(284.8)
|
Repayment of
convertible debentures
|
(43.0)
|
-
|
-
|
Payments for revolving
credit facility borrowings
|
-
|
(67.0)
|
(60.8)
|
Proceeds from
revolving credit facility borrowings
|
-
|
-
|
69.8
|
Deferred financing
costs
|
(39.0)
|
(2.8)
|
(31.2)
|
Equity contribution
from noncontrolling interest
|
-
|
44.6
|
225.0
|
Dividends paid to
common shareholders
|
(34.9)
|
(65.1)
|
(131.0)
|
Dividends paid to
noncontrolling interests
|
(25.7)
|
(18.3)
|
(13.1)
|
Cash (used in)
provided by financing activities
|
(182.4)
|
(207.6)
|
362.7
|
|
|
Net (decrease)
increase in cash and cash equivalents
|
(48.7)
|
91.9
|
6.0
|
Less cash at
discontinued operations
|
-
|
-
|
(6.5)
|
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
|
60.7
|
Cash and cash
equivalents at end of period
|
$109.9
|
$158.6
|
$60.2
|
Supplemental cash
flow information
|
|
|
|
Interest
paid
|
$168.8
|
$130.4
|
$40.2
|
Income taxes paid,
net
|
$3.8
|
$5.9
|
$1.1
|
Accruals for
construction in progress
|
$-
|
$8.9
|
$4.1
|
|
|
|
|
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 9 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
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 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 10A and 10B
on page 17. A reconciliation of Free Cash Flow to cash flows
from operating activities is provided in Table 11 on page 18 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 Table 12 on page 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 9 – Project
Adjusted EBITDA by segment
Unaudited
|
|
Years
ended December
31,
|
Three months
ended
December 31,
|
|
2014
|
2013
|
2012
|
2014
|
2013
|
Project Adjusted
EBITDA by segment
|
|
|
|
|
|
East
(1)
|
$158.5
|
$150.7
|
$145.7
|
$42.2
|
$38.2
|
West
(2)
|
78.5
|
77.2
|
78.9
|
16.0
|
9.5
|
Wind
|
69.8
|
59.6
|
10.9
|
20.8
|
16.3
|
Un-allocated corporate
(3)
|
(7.5)
|
(18.6)
|
(11.1)
|
(1.1)
|
(5.9)
|
Total
|
299.3
|
268.9
|
224.4
|
77.9
|
58.1
|
|
|
|
|
|
|
Reconciliation to
project income
|
|
|
|
|
|
Depreciation and
amortization
|
201.7
|
208.8
|
163.5
|
46.8
|
55.2
|
Interest expense,
net
|
39.5
|
38.5
|
24.0
|
7.4
|
10.7
|
Change in the fair
value of derivative instruments
|
10.4
|
(50.3)
|
56.6
|
22.0
|
(15.4)
|
Other
expense
|
98.2
|
8.2
|
11.5
|
-
|
0.4
|
Project (loss)
income
|
$(50.5)
|
$63.7
|
$(31.2)
|
$1.7
|
$7.2
|
(1) Excludes
Auburndale, Lake and Pasco, which are components of discontinued
operations.
(2) Excludes Path 15,
which is a component of discontinued operations.
(3) Excludes
Rollcast, which is a component of discontinued
operations.
Notes: Table 9
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 10A – Cash
Distributions from Projects (by Segment, in millions of U.S.
dollars)
Year ended
December 31, 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
|
|
|
|
|
|
|
Consolidated
|
$114.2
|
$(14.6)
|
$(7.6)
|
$(10.1)
|
$10.7
|
$92.6
|
Equity
method
|
44.3
|
(5.0)
|
(6.8)
|
(0.6)
|
1.0
|
32.9
|
Total
|
158.5
|
(19.6)
|
(14.4)
|
(10.7)
|
11.7
|
125.5
|
West
|
|
|
|
|
|
|
Consolidated
|
64.1
|
-
|
-
|
(0.8)
|
6.4
|
69.7
|
Equity
method
|
14.4
|
(1.0)
|
(0.1)
|
-
|
1.0
|
14.3
|
Total
|
78.5
|
(1.0)
|
(0.1)
|
(0.8)
|
7.4
|
84.0
|
Wind
|
|
|
|
|
|
|
Consolidated
|
58.2
|
(6.4)
|
(14.2)
|
(1.4)
|
(2.2)
|
34.0
|
Equity
method
|
11.6
|
(2.8)
|
(4.8)
|
0.1
|
1.3
|
5.4
|
Total
|
69.8
|
(9.2)
|
(19.0)
|
(1.3)
|
(0.9)
|
39.4
|
Total
consolidated
|
236.5
|
(21.0)
|
(21.8)
|
(12.3)
|
14.9
|
196.3
|
Total equity
method
|
70.3
|
(8.8)
|
(11.7)
|
(0.5)
|
3.3
|
52.6
|
Un-allocated
corporate
|
(7.5)
|
-
|
-
|
(1.2)
|
8.7
|
-
|
Total
|
$299.3
|
$(29.8)
|
$(33.5)
|
$(14.0)
|
$26.9
|
$248.9
|
Notes: Table 10A
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 10B – Cash
Distributions from Projects (by Segment, in millions of U.S.
dollars)
Year ended
December 31, 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
|
$100.3
|
$(3.9)
|
$(17.3)
|
$(6.7)
|
$18.8
|
$91.2
|
Equity
method
|
50.4
|
(14.0)
|
(3.6)
|
(0.9)
|
4.3
|
36.2
|
Total
|
150.7
|
(17.9)
|
(20.9)
|
(7.6)
|
23.1
|
127.4
|
West
|
|
|
|
|
|
|
Consolidated
|
60.0
|
-
|
-
|
(1.1)
|
(3.3)
|
55.6
|
Equity
method
|
17.2
|
1.2
|
(0.3)
|
(1.1)
|
(2.9)
|
14.1
|
Total
|
77.2
|
1.2
|
(0.3)
|
(2.2)
|
(6.2)
|
69.7
|
Wind
|
|
|
|
|
|
|
Consolidated
|
50.0
|
(7.0)
|
(14.6)
|
(5.5)
|
0.5
|
23.4
|
Equity
method
|
9.6
|
(2.6)
|
(4.9)
|
-
|
0.4
|
2.5
|
Total
|
59.6
|
(9.6)
|
(19.5)
|
(5.5)
|
0.9
|
25.9
|
Total
consolidated
|
210.3
|
(10.9)
|
(31.9)
|
(13.3)
|
16.0
|
170.2
|
Total equity
method
|
77.2
|
(15.4)
|
(8.8)
|
(2.0)
|
1.8
|
52.8
|
Un-allocated
corporate
|
(18.6)
|
(0.2)
|
3.1
|
0.2
|
15.5
|
-
|
Total
|
$268.9
|
$(26.5)
|
$(37.6)
|
$(15.1)
|
$33.3
|
$223.0
|
Notes: Table 10B
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 11 – Free
Cash Flow (in millions of U.S. dollars)
Unaudited
|
Years ended
December 31,
|
|
2014
|
2013
|
2012
|
Cash Distributions
from Projects
|
$248.9
|
$223.0
|
$196.6
|
Repayment of long-term
debt
|
(29.8)
|
(26.5)
|
(27.4)
|
Interest expense,
net
|
(33.5)
|
(37.6)
|
(24.0)
|
Capital
expenditures
|
(14.0)
|
(15.1)
|
(1.8)
|
Other, including
changes in working capital
|
26.9
|
33.3
|
25.4
|
Project Adjusted
EBITDA
|
$299.3
|
$268.9
|
$224.4
|
Depreciation and
amortization
|
201.7
|
208.8
|
163.5
|
Interest expense,
net
|
39.5
|
38.5
|
24.0
|
Change in the fair
value of derivative instruments
|
10.4
|
(50.3)
|
56.6
|
Other (income)
expense
|
98.2
|
8.2
|
11.5
|
Project (loss)
income
|
$(50.5)
|
$63.7
|
$(31.2)
|
Administrative and
other expenses
|
143.5
|
101.4
|
112.9
|
Income tax expense
(benefit)
|
(11.9)
|
(19.5)
|
(28.1)
|
Income (loss) from
discontinued operations, net of tax
|
(0.1)
|
(5.6)
|
15.7
|
Net
loss
|
$(182.2)
|
$(23.8)
|
$(100.3)
|
Adjustments to
reconcile to net cash provided by operating activities
|
265.8
|
129.1
|
264.7
|
Change in other
operating balances
|
(18.6)
|
47.1
|
2.7
|
Cash flows from
operating activities
|
$65.0
|
$152.4
|
$167.1
|
Term loan facility
repayments (1)
|
(58.4)
|
-
|
-
|
Project-level debt
repayments
|
(26.2)
|
(15.6)
|
(19.6)
|
Purchases of property,
plant and equipment (2)
|
(13.4)
|
(6.5)
|
(2.9)
|
Distributions to
noncontrolling interests (3)
|
(11.0)
|
(8.9)
|
-
|
Dividends on preferred
shares of a subsidiary company
|
(11.6)
|
(12.6)
|
(13.0)
|
Free Cash
Flow
|
$(55.6)
|
$108.8
|
$131.6
|
Additional GAAP
cash flow measures:
|
|
|
|
Cash flows from
investing activities
|
$68.7
|
$147.1
|
$(523.8)
|
Cash flows from
financing activities
|
$(182.4)
|
$(207.6)
|
$362.7
|
(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 and 2013 and its 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 11
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 12 –
Adjusted Cash Flows from Operating Activities and Adjusted Free
Cash Flow (in millions of U.S. dollars)
Unaudited
|
Years ended
December 31,
|
|
2014
|
2013
|
2012
|
Cash flows from
operating activities
|
$65.0
|
$152.4
|
$167.1
|
Changes in other
operating balances
|
18.6
|
(47.1)
|
(2.7)
|
Cash flows from
discontinued operations
|
-
|
(31.6)
|
(89.0)
|
Severance
charges
|
6.0
|
1.0
|
-
|
Restructuring
charges
|
2.0
|
-
|
-
|
Shareholder litigation
expenses
|
1.4
|
1.0
|
-
|
Refinancing
transaction costs
|
49.4
|
-
|
-
|
Adjusted Cash
Flows from Operating Activities
|
$142.4
|
$75.7
|
$75.4
|
Term loan facility
repayments (1)
|
(58.4)
|
-
|
-
|
Project-level debt
repayments
|
(26.2)
|
(15.6)
|
(19.6)
|
Amount
associated with discontinued operations (included in line
above)
|
-
|
5.2
|
15.6
|
Principal repayment of Piedmont debt at term conversion (included
above)
|
8.1
|
-
|
-
|
Purchases of property,
plant and equipment (2)
|
(13.4)
|
(6.5)
|
(2.9)
|
Amount
associated with discontinued operations (included in line
above)
|
-
|
0.3
|
1.6
|
Distributions to
noncontrolling interests (3)
|
(11.0)
|
(8.9)
|
-
|
Dividends on preferred
shares of a subsidiary company
|
(11.6)
|
(12.6)
|
(13.0)
|
Adjusted Free Cash
Flow
|
$29.9
|
$37.6
|
$57.1
|
Additional GAAP
cash flow measures:
|
|
|
|
Cash flows from
investing activities
|
$68.7
|
$147.1
|
$(523.8)
|
Cash flows from
financing activities
|
$(182.4)
|
$(207.6)
|
$362.7
|
(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 and 2013 and its
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 12
presents 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 13 – Project
Adjusted EBITDA by Project (for Selected
Projects)
(in millions of
U.S. dollars)
Unaudited
|
|
Years ended
December 31,
|
|
|
2014
|
2013
|
2012
|
East
|
Accounting
|
|
|
|
Cadillac
|
Consolidated
|
$7.5
|
$9.1
|
$9.2
|
Curtis
Palmer
|
Consolidated
|
31.5
|
32.1
|
28.0
|
Morris
|
Consolidated
|
12.7
|
6.3
|
8.2
|
Nipigon
|
Consolidated
|
15.3
|
13.4
|
14.6
|
North Bay
|
Consolidated
|
10.6
|
8.5
|
8.1
|
Piedmont
|
Consolidated
|
6.5
|
2.3
|
(0.1)
|
Tunis
|
Consolidated
|
10.3
|
9.5
|
13.5
|
Other
(1)
|
Consolidated
|
19.8
|
19.1
|
9.6
|
Chambers
|
Equity
method
|
18.6
|
20.6
|
27.8
|
Selkirk
|
Equity
method
|
10.3
|
20.8
|
17.8
|
Orlando
|
Equity
method
|
15.4
|
9.0
|
9.0
|
Total
|
|
158.5
|
150.7
|
145.7
|
West
|
|
|
|
|
Manchief
|
Consolidated
|
15.0
|
16.9
|
15.1
|
Naval
Station
|
Consolidated
|
10.3
|
10.5
|
7.3
|
Williams
Lake
|
Consolidated
|
15.8
|
16.5
|
18.5
|
Other
(2)
|
Consolidated
|
23.0
|
16.1
|
23.0
|
Frederickson
|
Equity
Method
|
12.2
|
12.1
|
10.8
|
Other
(3)
|
Equity
method
|
2.2
|
5.1
|
4.2
|
Total
|
|
78.5
|
77.2
|
78.9
|
Wind
|
|
|
|
|
Canadian
Hills
|
Consolidated
|
26.6
|
25.6
|
0.8
|
Meadow
Creek
|
Consolidated
|
19.3
|
14.0
|
-
|
Rockland
|
Consolidated
|
12.3
|
10.4
|
3.5
|
Other
(4)
|
Equity
method
|
11.6
|
9.6
|
6.6
|
Total
|
|
69.8
|
59.6
|
10.9
|
Totals
|
|
|
|
|
Consolidated
projects
|
|
236.5
|
210.3
|
159.3
|
Equity method
projects
|
|
70.3
|
77.2
|
76.2
|
Un-allocated
corporate
|
|
(7.5)
|
(18.6)
|
(11.1)
|
Total Project
Adjusted EBITDA
|
|
$299.3
|
$268.9
|
$224.4
|
|
|
|
|
|
Depreciation and
amortization
|
|
$201.7
|
$208.8
|
$163.5
|
Interest expense,
net
|
|
39.5
|
38.5
|
24.0
|
Change in the fair
value of derivative instruments
|
|
10.4
|
(50.3)
|
56.6
|
Other (income)
expense
|
|
98.2
|
8.2
|
11.5
|
Project income
(loss)
|
|
$(50.5)
|
$63.7
|
$(31.2)
|
(1) 2012
and 2013: Kenilworth, Calstock, Kapuskasing, and Onondaga; 2014:
Kenilworth, Calstock, and Kapuskasing
(2)
Moresby Lake, Mamquam, North Island, Naval Training Station, and
Oxnard
(3) 2012:
Badger Creek, Delta-Person, Gregory, PERH, and Koma Kulshan; 2013:
Koma Kulshan, Gregory, and Delta-Person; 2014: Koma Kulshan
and Delta-Person
(4) 2012:
Idaho Wind; 2013 and 2014: Idaho Wind and Goshen North
Notes: Table 13
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-fourth-quarter-and-year-end-2014-results-300042516.html
SOURCE Atlantic Power Corporation