BOSTON, Aug. 7, 2014 /CNW/ -- Atlantic Power
Corporation (NYSE: AT) (TSX: ATP) ("Atlantic Power" or the
"Company") today released its results for the three and six months
ended June 30, 2014.
"Our results this quarter benefited from continued strong wind
generation, increased waste heat at our Ontario projects, improved water flows at
Curtis Palmer and lower maintenance and administrative expenses
versus a year ago. The improvement in our operating results
this quarter largely offset the impact of outages that we
experienced earlier in the year," said Barry Welch, President and CEO of Atlantic
Power.
"During the quarter, we repaid $37.5
million of our new term loan, which puts us on track to
reduce total debt on a net basis by approximately $80 million this year. The significant
amount of term loan repayment resulted in negative Free Cash Flow
this quarter, but we expect positive Free Cash Flow generation in
the second half of the year," Mr. Welch continued. "Based on
our results year to date and our expectations for the balance of
the year, we are reaffirming our 2014 guidance metrics for Project
Adjusted EBITDA and Free Cash Flow."
All amounts are in U.S. dollars and are approximate unless
otherwise indicated. Free Cash Flow, Cash Distributions from
Projects, and 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.
Second Quarter 2014 Financial Highlights
- Project loss of $(3.8) million
decreased $24.1 million from Q2
2013, driven by a $14.8 million
non-cash impairment charge at Tunis in 2014 and $27.1
million of negative non-cash changes in fair value of
derivatives
- Project Adjusted EBITDA of $75.0
million increased $19.1
million from Q2 2013, due to fewer outages, stronger wind
and waste heat, higher water flows at Curtis Palmer and a full
quarter of Piedmont
- Cash flows from operating activities of $34.0 million increased $26.8 million from Q2 2013
- Free Cash Flow of $(15.1) million
decreased $7.6 million from Q2 2013,
as increased cash flows from operating activities were offset by
the initial repayment on Atlantic Power Limited Partnership (APLP)
term loan of $37.5 million
(approximately 70% of amount expected for full year)
YTD June 2014 Financial
Highlights
- Project income of $16.4 million
decreased $35.4 million from YTD
June 2013, driven by the $14.8 million Tunis impairment charge in 2014 and
$25.0 million of negative non-cash
changes in fair value of derivatives
- Project Adjusted EBITDA of $149.6
million increased $13.5
million from YTD June
2013
- Cash flows from operating activities of $5.5 million decreased $91.4 million from YTD June 2013, primarily due to $54 million of debt refinancing and repurchase
costs, a $33 million reduction from
businesses divested in 2013 and a $29
million reduction in working capital from 2013
- Free Cash Flow of $(61.0) million
decreased $135.5 million from YTD
June 2013 due to the reduction in
cash flows from operating activities and $37.5 million of term loan repayment
Other Highlights
- On track to invest $17 million in
2014 (2013-2014 total $27 million) in
existing projects to boost output, improve efficiency and reduce
costs, with expected cash return of at least $8 million annually beginning in 2015
- Closed sale of Delta-Person for $7.2
million in proceeds, plus another $1.4 million held in escrow, expected to be
released 12 months after close of the transaction
- Liquidity at quarter-end totaled $261
million, including $158
million of unrestricted cash
2014 Guidance Reaffirmed
- Project Adjusted EBITDA of $280 to $305
million
- Project Adjusted EBITDA for APLP alone of $165 to $175 million
- Free Cash Flow of $0 to $25
million, which excludes approximately $49 million of debt refinancing transaction costs
and $8 million of Piedmont debt payment (total $57.5 million)
Atlantic Power
Corporation
Table 1 – Selected
Results
(in millions of
U.S. dollars, except as otherwise stated)
Unaudited
|
|
Three months ended
June 30,
|
Six months ended
June 30,
|
|
2014
|
2013
|
2014
|
2013
|
Excluding results
from discontinued operations(1)
|
|
|
|
|
Project
revenue
|
$143.2
|
$136.1
|
$288.5
|
$273.6
|
Project (loss)
income
|
(3.8)
|
20.3
|
16.4
|
51.8
|
Project Adjusted
EBITDA
|
75.0
|
55.9
|
149.6
|
136.1
|
Cash Distributions
from Projects
|
85.3
|
50.1
|
135.7
|
104.0
|
Aggregate power
generation (thousands of Net MWh)
|
2,022.8
|
2,008.6
|
4,110.7
|
3,890.7
|
Weighted average
availability
|
91.2%
|
92.9%
|
91.9%
|
93.9%
|
Including results
from discontinued operations (1)
|
|
|
|
|
Cash flows from
operating activities
|
$34.0
|
$7.2
|
$5.5
|
$96.9
|
Free Cash
Flow
|
(15.1)
|
(7.5)
|
(61.0)
|
74.5
|
(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 six month periods ended June 30, 2013 and June 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.
Note: Project
Adjusted EBITDA, Free Cash Flow and Cash Distributions from
Projects are not recognized measures under GAAP and do not have any
standardized meaning prescribed by GAAP;
therefore, these measures may not be comparable to similar measures
presented by other companies. Please refer to Tables 9 through 12
for reconciliations of these non-GAAP measures to GAAP
measures.
|
|
|
|
|
|
|
|
Financial Results
Table 2 provides a breakdown of project income and Project
Adjusted EBITDA by segment for the three and six month periods
ended June 30, 2014 as compared to
the same period in 2013.
Project Income
Reported project income can fluctuate significantly due to
impacts from non-cash mark-to-market fair value of derivatives
adjustments.
Three Months Ended June 30,
2014
Project income decreased by $24.1
million to $(3.8) million
compared to $20.3 million for the
same period in 2013. The reduction in project income was
primarily due to:
- Negative non-cash changes in the fair value of gas purchase
agreements and interest rate swap agreements accounted for as
derivatives in the East and Wind segments totaling $27.1 million
- Decreased project income of $12.6
million at Tunis (East),
primarily due to a long-lived asset and goodwill impairment of
$14.8 million, partially offset by
favorable outage comparisons
- Decreased project income of $4.9
million at Selkirk (East),
primarily due to accelerated depreciation resulting from the
scheduled expiration of the project's Power Purchase Agreement
(PPA) in August 2014
These decreases were partially offset by the following positive
factors:
- Increased project income of $11.5
million at Kapuskasing
(East) and Naval Training Center, Williams Lake and Mamquam (West) mostly due to
lower maintenance expense versus 2013, when the projects underwent
scheduled maintenance outages
- Increased project income of $3.4
million at Curtis Palmer (East), primarily due to a decrease
in interest expense of $2.8 million
due to redemption of project's senior notes in February 2014
- Increased project income of $3.3
million at Orlando (East),
which benefited from lower gas costs following the termination of
above-market swaps in February 2014
and higher capacity payments under a new PPA
- Increased project income of $2.3
million at Piedmont (East),
excluding the impact of derivatives included above, attributable to
a full quarter of operation versus a partial quarter in 2013
Atlantic Power
Corporation
Table 2 – Segment
Results
(in millions of
U.S. dollars, except as otherwise stated)
Unaudited
|
|
|
Three months ended
June 30,
|
Six months ended
June 30,
|
|
2014
|
2013
|
2014
|
2013
|
Project income
(loss)
|
|
|
|
|
East
|
$(3.6)
|
$12.2
|
$27.7
|
$43.4
|
West
|
6.7
|
(3.1)
|
1.5
|
0.4
|
Wind
|
(1.9)
|
14.5
|
(7.5)
|
15.3
|
Un-allocated
Corporate
|
(5.0)
|
(3.3)
|
(5.3)
|
(7.3)
|
Total
|
(3.8)
|
20.3
|
16.4
|
51.8
|
Project Adjusted
EBITDA
|
|
|
|
|
East
|
$38.5
|
$29.4
|
$84.0
|
$78.5
|
West
|
22.9
|
14.1
|
34.1
|
34.7
|
Wind
|
17.2
|
15.5
|
35.1
|
30.5
|
Un-allocated
Corporate
|
(3.6)
|
(3.1)
|
(3.6)
|
(7.6)
|
Total
|
75.0
|
55.9
|
149.6
|
136.1
|
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 9
through 12 for a reconciliation of this non-GAAP measure to a GAAP
measure.
The Company has not
reconciled non-GAAP financial measures relating to individual
projects to the directly comparable GAAP measure due to the
difficulty in making the relevant adjustments on an
individual project basis.
|
|
Six Months Ended June 30,
2014
Project income decreased by $35.4
million to $16.4 million
compared to $51.8 million for the
same period in 2013. The reduction in project income was primarily
due to:
- Net negative non-cash changes in fair value of gas purchase
agreements and interest rate swap agreements accounted for as
derivatives in the East and Wind segments totaling $25.0 million
- Decreased project income of $12.8
million at Tunis (East),
primarily due to the $14.8 million
impairment recorded in the second quarter of 2014, partially offset
by favorable outage comparisons
- Decreased project income of $7.2
million at Selkirk (East),
primarily due to accelerated depreciation as described above
- Decreased project income of $2.8
million at Piedmont (East),
excluding the impact of derivatives included above, primarily due
to higher fuel and maintenance costs, partially offset by increased
capacity payments (the project had two quarters of operation in
2014 versus a partial quarter in 2013)
- Net decreases in project income for other projects totaling
approximately $7 million
These decreases were partially offset by the following positive
factors:
- Increased project income of $10.5
million at Morris and North
Bay (East) and Naval Training Center (West) primarily due to
lower maintenance expense relative to 2013, when the projects
underwent scheduled maintenance outages
- Increased project income from Wind segment of $3.8 million, excluding the impact of derivatives
included above, primarily due to increased wind generation from
Meadow Creek
- Increased project income of $3.1
million at Orlando (East),
excluding the impact of derivatives included above, primarily due
to lower gas costs and higher capacity payments as described
above
- Reduction in Un-allocated Corporate segment of $2.0 million, including $1.7 million in development costs and
$0.6 million in administrative
expenses related to cost reduction initiatives undertaken in
2013
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 June 30,
2014
Project Adjusted EBITDA increased $19.1
million to $75.0 million from
$55.9 million for the comparable
period in 2013. The most significant contributors to the increase
in Project Adjusted EBITDA were the following:
- Naval Training Center, Williams
Lake and Mamquam (West), totaling approximately $9.1 million, primarily due to lower maintenance
costs in 2014 relative to 2013, when the projects had scheduled
maintenance outages
- Ontario projects (East),
totaling approximately $6.5
million. Tunis,
Kapuskasing and North Bay experienced lower maintenance costs
in 2014 relative to 2013, when the projects had scheduled
maintenance outages. In addition, the Ontario projects benefited from higher waste
heat generation resulting in additional energy margin
- Piedmont (East), approximately
$2.1 million, due to a full quarter
of operation versus a partial quarter of operation in 2013
- Other projects in the East totaling approximately $2.0 million, primarily Orlando, due to lower gas costs and higher
capacity payments, and Curtis Palmer, due to increased water flows
due to a late snowmelt and above-average rainfall
- Wind projects $1.7 million,
primarily due to stronger wind generation, particularly at
Meadow Creek
These increases were partially offset by the following
decreases:
- Cadillac (East), $1.3 million due to lower capacity revenue and
energy margin and higher maintenance expenses due to a scheduled
outage
Six Months Ended June 30,
2014
Project Adjusted EBITDA increased by $13.5 million to $149.6
million from $136.1 million
for the same period in 2013, as the $19.1
million increase in the second quarter of 2014 described
previously more than offset the reduction in the first quarter of
2014. Results for the first quarter were adversely affected
by extreme weather and several plant outages, difficulties sourcing
fuel at the Company's biomass projects, a gas swap termination at
Orlando and several
project-specific factors. For the six-month period, the most
significant contributors to the increase in Project Adjusted EBITDA
were the following:
- Wind projects, $4.6 million due
to stronger wind generation, particularly at Meadow Creek and Rockland, partly offset by impact of Canadian
Hills weather-related outage in January
- Tunis, North Bay and Kapuskasing (East), totaling $4.5 million, due primarily to increased waste
heat, decreased maintenance expenses and other factors
- Morris (East) $4.4 million, due primarily to lower maintenance
costs, lower fuel expenses and higher revenues (higher PJM power
prices)
- Naval Training Center (West), $3.9
million due to lower maintenance expense compared to 2013,
when the project underwent scheduled turbine maintenance
- Reduction in Un-allocated Corporate loss of $4.0 million, primarily due to a reduction in
development costs at Ridgeline of $1.7
million and a reduction in administrative costs of
$2.2 million resulting from cost
reduction initiatives undertaken in 2013
These increases were partially offset by the following
decreases:
- Cadillac (East), $1.4 million due to lower capacity revenue and
increased maintenance expenses resulting from a scheduled
maintenance outage in March and April of 2014 that was
extended
- Net decreases totaling approximately $6.5 million at other projects, including
Williams Lake and North Island
(West) and Calstock (East), as
well as smaller decreases at other projects
Cash Distributions from Projects
Cash Distributions from Projects, which excludes projects
classified as discontinued operations, increased by $32 million to approximately $136 million for the six months ended
June 30, 2014, compared to
$104 million for the same period in
2013. This result included a $35
million increase in the second quarter of 2014, which more
than offset the decline in the first quarter of 2014.
Significant increases in the six months ended June 30, 2014 relative to the year-ago period
occurred at (i) the Navy projects in California and were 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) Nipigon and Tunis, due to the timing of revenue
receipts.
These increases were partly 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) Williams Lake, due to costs associated with a
January 2014 forced outage; and (iii)
Selkirk, due to use of working
capital to support credit requirements, although a distribution
from the project is expected in August.
Cash Flow from Operating Activities
As previously reported, during the first quarter of 2014 the
Company incurred significant costs in conjunction with its
refinancing and debt repurchase transactions, which included entry
into the new credit facilities, debt redemptions and repurchases,
and the Piedmont term loan
conversion. These costs, which totaled approximately
$100 million and included prepayment
premiums and make-wholes, accrued interest expense, swap
termination costs and financing expenses and fees, are detailed in
Table 4 to the first quarter 2014 earnings release dated
May 12, 2014. Approximately
$49.4 million of these costs were
recorded in interest expense and another $4
million to terminate gas swaps at the Orlando project were included in fuel
expense. Together these reduced cash flows from operating
activities and Free Cash Flow by approximately $54 million in the first quarter of 2014,
$0 million in the second quarter of
2014 and $54 million in the first six
months of 2014. With the exception of the Orlando gas swap termination cost, these
transaction costs did not affect Project income or Project Adjusted
EBITDA.
Three Months Ended June 30,
2014
Cash flows from operating activities increased by $26.8 million to $34
million compared to $7.2
million for the same period in 2013. The increase is
primarily due to the $19.1 million
increase in Project Adjusted EBITDA for the quarter and a
$7.0 million benefit from changes in
working capital.
Six Months Ended June 30,
2014
Cash flows from operating activities decreased by $91.4 million to $5.5
million compared to $96.9
million for the same period in 2013. The decrease is
primarily due to the $54 million of
refinancing transaction costs incurred in the first quarter and
described previously, a $32.8 million
decrease in loss from discontinued operations (projects sold in
2013) and a $29.3 million decrease in
working capital from the comparable 2013 period. The decrease
in working capital is due to a $31.6
million decrease in prepaid and other assets due to the
collection of security deposits related to recently completed
construction projects, such as Piedmont, Canadian Hills and Meadow Creek, in the first quarter of
2013.
Free Cash Flow
Three Months Ended June 30,
2014
Free Cash Flow decreased by $7.6
million to $(15.1) million
compared to $(7.5) million for the
same period in 2013. The decrease is primarily due to
$37.5 million of term loan facility
repayments by APLP, partially offset by $28.6 million of higher operating cash
flows. The $37.5 million of
term loan repayments in the second quarter included $1.5 million of 1% mandatory amortization
($6.0 million annually) and
$36.0 million of debt repaid pursuant
to the 50% sweep of APLP's cash flow after debt service and
capex. The Company expects term loan repayments for the full
year to total approximately $52 to $55
million.
Six Months Ended June 30,
2014
Free Cash Flow decreased by $135.5
million to $(61.0) million
compared to $74.5 million for the
same period in 2013. The decrease is primarily due to
$37.5 million of term loan facility
repayments by APLP and a $91.4
million decrease in operating cash flows as described
previously.
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 six months of 2014 is
approximately $(3.5) million compared
to $74.5 million for the same period
in 2013.
Results of Discontinued Operations
Results of discontinued operations are discussed beginning on
page 9 of this press release.
Reaffirming 2014 Guidance
- Annual Project Adjusted EBITDA guidance of $280 to $305 million
- Annual Free Cash Flow guidance of $0 to
$25 million
Project Adjusted EBITDA
The Company is reaffirming its previous guidance for 2014
Project Adjusted EBITDA in the range of $280
to $305 million. Results for the first six months of
2014 totaled $149.6 million, or
approximately 51% of the full-year guidance. In the second
quarter, favorable maintenance cost comparisons due to fewer
planned outages, increased waste heat, higher levels of wind
generation, and increased water levels at Curtis Palmer mostly
offset the impact on first-quarter results of plant outages, lower
water levels at Curtis Palmer and a $4
million termination cost for certain gas swaps at
Orlando.
The Company is also reaffirming its expectation for APLP's 2014
Project Adjusted EBITDA in the range of $165
to $175 million.
The Company has not reconciled non-GAAP financial measures
relating to the APLP projects to the directly comparable GAAP
measures due to the difficulty in making the relevant adjustments
on an individual project basis.
Free Cash Flow
The Company is reaffirming its previous guidance for 2014 Free
Cash Flow in the range of $0 to $25
million. This 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. The
Company's Free Cash Flow guidance is net of planned capital
expenditures totaling $16 million and
debt repayments under the APLP term loan of approximately
$52 to $55 million in 2014.
In the first six months of 2014, Free Cash Flow excluding the
$57.5 million of transaction-related
costs and Piedmont debt repayment
(consistent with full-year guidance) was $(3.5) million. However, this was after
$37.5 million of term loan
repayment. The amount of term loan repayment in the second
half of this year is expected to be lower than in the first half
because of the timing of APLP cash flows, which are typically
stronger in the winter and spring months at the Ontario projects (waste heat) and Curtis
Palmer (hydro generation), and the timing of APLP capital
expenditures, which are expected to be higher in the second
half. The Company expects that Free Cash Flow will benefit in
the second half from distributions from minority-owned projects,
some of which were deferred from the first half, and lower parent
interest expense.
See Table 3 for full-year 2014 guidance and year-to date 2014
actual results.
Atlantic Power
Corporation
Table 3 – 2014
Annual Guidance and YTD 2014 Actual
(in millions of
U.S. dollars, except as otherwise stated)
|
Unaudited
|
|
2014 Annual
Guidance
|
YTD 2014
Actual
|
Project Adjusted
EBITDA
|
|
$280 -
$305
|
$149.6
|
Free Cash Flow
(1)
|
|
$0 - $25
|
$(61.0)
|
APLP Project Adjusted
EBITDA (2)
|
|
$165 -
$175
|
$88.8
|
(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 $54 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.
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.
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. 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.
|
|
Financial Update
Liquidity
As can be seen from Table 4, the Company's liquidity increased
from approximately $246 million at
March 31, 2014 to approximately
$261 million as of June 30, 2014, including $158 million of unrestricted cash. The
Company plans to use $41 million of
this cash to repay its Cdn$45 million
convertible debentures due in October
2014.
The increase in liquidity in the quarter resulted from a
reduction in letters of credit outstanding to $107 million from $144
million, which increased revolver availability by
$37 million. This was partly
offset by a $22 million reduction in
unrestricted cash, which was attributable to debt repayment and
other uses of cash during the quarter.
Atlantic Power
Corporation
Table 4 –
Liquidity (in millions of U.S. dollars)
|
|
Unaudited
|
|
March 31,
2014
|
June 30,
2014
|
Revolver
capacity
|
|
$210.0
|
$210.0
|
Letters of credit
outstanding
|
|
(144.1)
|
(107.0)
|
Unused borrowing
capacity
|
|
65.9
|
103.0
|
Unrestricted cash
(1)
|
|
180.0
|
157.6
|
Total
Liquidity
|
|
$245.9
|
$260.6
|
(1)
Includes project-level cash for working capital needs of $16.4
million at June 30, 2014 and $17.6 million at March 31,
2014.
|
|
Covenant Update
Due to the aggregate impact of the up-front costs resulting from
the prepayments and repurchases of the Company's indebtedness
incurred in the first quarter of 2014 and as previously disclosed
in the first quarter earnings release dated May 12, 2014, the Company is not in compliance
with the fixed charge coverage ratio test included in the
restricted payments covenant of the indenture governing its 9.0%
senior unsecured notes. The fixed charge coverage ratio must
be at least 1.75 to 1.00 and is measured on a rolling four quarter
basis, so the costs associated with debt prepayments and
repurchases incurred in the first quarter of 2014 would no longer
be included in the calculation beginning in the second quarter of
2015.
As a consequence of the non-compliance, common dividend
payments, which are declared and paid at the discretion of the
Company's board of directors, in the aggregate cannot exceed the
restricted payments "basket" provision of the greater of
$50 million and 2% of consolidated
net assets (approximately $61 million
at June 30, 2014), until such time
that the Company satisfies the fixed charge coverage ratio
test. The Company has declared seven monthly dividends in
January through July totaling approximately $25.6 million that are subject to the basket
provision.
The Company expects to be in compliance with the financial
maintenance covenants governing (i) the Company's 9.0% senior
unsecured notes; (ii) APLP's senior secured credit facilities,
including the term loan; and (iii) APLP's 5.95% Medium-Term Notes,
for at least the next twelve months.
Piedmont
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 June
30, 2014. The Company does not expect Piedmont to pass its debt service coverage
ratio covenant for at least the next twelve months. As a
result, the project is not expected to make distributions for at
least the next twelve months, which is at least six months beyond
the Company's previous expectation.
Tunis Impairment
The Company's Tunis project in
Ontario has a PPA with the Ontario
Power Authority (OPA) that is scheduled to expire on December 31, 2014. Consistent with its
accounting policy of reviewing its projects for potential
impairment six months prior to the expiration of an existing PPA,
the Company conducted an impairment analysis of Tunis in the second quarter of 2014.
Based on the results of this analysis, the Company recorded a
$14.8 million non-cash impairment
charge for Tunis, including
$9.6 million associated with the
carrying value of the project's property, plant and equipment and
$5.2 million for all of the project's
goodwill.
Business Update
Project Operating Performance
Three Months Ended June 30,
2014
Availability declined to 91.2% from 92.9% in the second quarter
of 2013 due to extended scheduled maintenance outages at Cadillac,
Orlando, and Naval Station, partly offset by fewer forced outage
hours at Williams Lake and Naval Station than in the year-ago
period. Generation increased 0.7% due to higher generation at
Curtis Palmer, Williams Lake,
Meadow Creek and Rockland, partially offset by the outages at
Cadillac, Orlando and Naval Station and reduced dispatch at
Manchief and Selkirk.
Six Months Ended June 30,
2014
Availability declined to 91.9% from 93.9% in the first six
months of 2013 due to both scheduled and forced outages in the
first quarter of 2014, some of which were related to extreme
weather, and extended scheduled maintenance outages at Cadillac,
Orlando and Naval Station in the second quarter. Generation
increased 5.7% in the first six months of 2014 due to the addition
of Piedmont in April 2013, increased dispatch at Chambers,
higher generation at Frederickson, and higher wind generation at
Meadow Creek and Rockland, partially offset by reduced dispatch
at Manchief.
Capex and Optimization Update
The Company now expects to have major maintenance and capital
expenditures in 2014 of approximately $35 to
$40 million. This estimate is down slightly from the
previous expectation of $38 to $43
million, because of an insurance recovery at Piedmont, timing of expenditures and cost
savings on certain purchases, partly offset by increases at other
projects. In the first six months of 2014, the Company
invested $12.5 million, or about
one-third 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 $17 million in 2014. The largest of these
projects is the steam generator replacement and upgrade at
Nipigon, which will occur during
an outage scheduled to begin later this month and be completed this
fall. Total estimated cost of the Nipigon project is approximately $11 million, including $8
million to be spent in 2014. Other projects already
completed this year include the repowering of two turbines at
Curtis Palmer and capacity uprates at North Island, Mamquam and
Calstock. A project designed to boost output at Morris during
peak periods is under way, with the major equipment installed and
performance testing scheduled for this month.
Together with investments made in 2013 totaling $10 million, the Company expects that
optimization-related spending over the two-year period totaling
$27 million will produce incremental
cash flow of at least $8 million
annually on a run-rate basis beginning in 2015. The Company
is already realizing a portion of this benefit this year from
investments completed to date.
Going forward, the Company expects that major maintenance and
routine capex will average approximately $25
million annually (versus approximately $19 million in 2014). Although the level of
optimization investments will vary from year to year, the Company
has a target of identifying approximately $5
to $10 million of such investments annually.
Supplementary Financial Information
For further information, attached to this news release is a
summary of Project Adjusted EBITDA by segment for the three and six
months ended June 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 six months ended June 30,
2014 (Table 9A) and the six months ended June 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 six months ended June 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 six months
ended June 30, 2014 and 2013 (Table
11).
Financial Results of Discontinued Operations
Financial results for the three and six month periods ended
June 30, 2014 and June 30, 2013 are affected by the classification
of the Company's interests in its divested assets as discontinued
operations; accordingly, the revenues, project income, Project
Adjusted EBITDA and Cash Distributions from Projects classified as
discontinued operations are excluded from results from continuing
operations. The results of discontinued operations have been
separately stated in the Consolidated Statements of Operations as
"Net income (loss) from discontinued operations, net of tax".
The divested assets included in discontinued operations for these
periods are the Auburndale,
Lake, Pasco and Greeley projects and the Company's
interests in Rollcast and Path 15.
The cash flow attributable to discontinued operations is
included in cash flows from operating activities as shown on the
Consolidated Statement of Cash Flows; therefore, the Company's
calculation of Free Cash Flow as shown herein also includes cash
flow from discontinued operations.
- Project income (loss) from discontinued operations was
$0.0 million and $(0.1) million, respectively, for the three and
six months ended June 30, 2014,
compared to $(5.0) million and
$(4.1) million, respectively, for the
same periods in 2013.
- Project Adjusted EBITDA from discontinued operations was
$0.0 million and $(0.1) million, respectively, for the three and
six months ended June 30, 2014,
compared to $6.6 million and
$38.3 million, respectively, for the
same periods in 2013.
- Cash Distributions from Projects from discontinued
operations was $0.0 million and
$0.0 million, respectively, for the
three and six months ended June 30,
2014, compared to $22.5
million and $22.6 million,
respectively, for the same periods in 2013.
Delta-Person was sold in July
2014, resulting in a gain on sale of approximately
$8.6 million, of which the Company
received net cash proceeds of $7.2
million for its 40% interest in the project, with an
additional $1.4 million currently
held in escrow, which the Company expects will be released 12
months after the close of the transaction. The Gregory
project was sold in August 2013. Gregory and Delta-Person are
both accounted for under the equity method of accounting and
therefore are included in the Company's financial results from
continuing operations for the relevant reporting periods rather
than being included in discontinued operations.
The Company has not reconciled non-GAAP financial measures
relating to discontinued operations to the directly comparable GAAP
measures due to the difficulty in making the relevant adjustments
on an individual project basis.
Investor Conference Call and Webcast
A telephone conference call hosted by Atlantic Power's
management team will be held on Friday, August 8, 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 3658548
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
10049145. The replay will be available 1 hour after
the end of the conference call through November 7, 2014 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:
- 2014 Project Adjusted EBITDA will be in the range of
$280 to $305 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 $25 million, excluding refinancing and debt
repurchase transaction costs and principal repayment of
Piedmont construction debt;
- the Company's Free Cash Flow will improve in the remainder of
the year;
- the Company will have positive Free Cash Flow generation in the
second half of the year;
- the Company will reduce total debt on a net basis by
approximately $80 million this
year;
- the Company will repay the Cdn$44.8
million aggregate principal amount of convertible debentures
due October 2014 at maturity using
cash;
- the Company will be in compliance with the financial
maintenance covenants governing its 9.0% senior unsecured notes,
APLP's senior secured credit facilities and APLP's 5.95%
Medium-Term notes, for at least the next twelve months;
- the impact of the fixed charge coverage ratio included in the
restricted payments "basket" provision of the indenture governing
the Company's 9.0% senior unsecured notes;
- Piedmont will be unable to
pass its debt service coverage ratio covenant for at least the next
twelve months and as a result, will not make distributions for at
least the next twelve months;
- APLP term loan repayments for the full year will total
approximately $52 to $55 million,
including repayments in the second half that are less than first
half repayments of $37.5 million,
because of the timing of cash flows from APLP projects, which are
typically stronger in the winter and spring months at certain
projects, and the timing of APLP capital expenditures, which are
expected to be higher in the second half of the year;
- an additional $1.4 million of net
cash proceeds from the sale of Delta-Person will be released to the
Company 12 months after the close of the transaction;
- the Company will have project capital expenditures and major
maintenance expenses of approximately $35 to
$40 million in 2014, including optimization initiatives of
approximately $16 million;
- major maintenance expense and maintenance capex will average
approximately $25 million annually,
versus approximately $19 million in
2014;
- the level of optimization investments will be approximately
$17 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 approximately $8
million beginning in 2015, with a portion of that realized
in 2014 from investments completed to date;
- the Company will have annual optimization capex on average of
approximately $5 to $10 million;
and
- the results of operations and performance of the Company's
projects, business prospects, opportunities and future growth of
the Company will be as described herein.
Forward-looking statements involve significant risks and
uncertainties, should not be read as guarantees of future
performance or results, and will not necessarily be accurate
indications of whether or not or the times at or by which such
performance or results will be achieved. Please refer to the
factors discussed under "Risk Factors" and "Forward-Looking
Information" in the Company's periodic reports as filed with the
Securities and Exchange Commission from time to time for a detailed
discussion of the risks and uncertainties affecting our 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, the acquisition of
assets, the dividend level, as well as broader strategic options,
including a sale or merger of the Company, and the impact any such
potential options may have on the Company or the Company's stock
price. 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.
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)
|
|
|
|
|
June
30,
|
December
31,
|
|
|
|
|
2014
|
2013
|
Assets
|
|
|
|
Unaudited
|
Current
assets:
|
|
|
|
|
Cash and cash
equivalents
|
|
|
|
$157.6
|
$158.6
|
Restricted
cash
|
|
|
|
17.8
|
96.2
|
Accounts
receivable
|
|
|
|
61.5
|
64.3
|
Current portion of
derivative instruments asset
|
|
|
|
1.7
|
0.2
|
Inventory
|
|
|
|
18.6
|
16.0
|
Prepayments and other
current assets
|
|
|
|
15.4
|
16.1
|
Refundable income
taxes
|
|
|
|
2.1
|
4.0
|
Total current
assets
|
|
|
|
274.7
|
355.4
|
|
|
|
|
|
|
Property, plant and
equipment, net
|
|
|
|
1,751.2
|
1,813.4
|
Equity investments in
unconsolidated affiliates
|
|
|
|
368.5
|
394.3
|
Other intangible
assets, net
|
|
|
|
420.6
|
451.5
|
Goodwill
|
|
|
|
291.1
|
296.3
|
Derivative
instruments asset
|
|
|
|
6.3
|
13.0
|
Other
assets
|
|
|
|
98.3
|
71.1
|
Total
assets
|
|
|
|
$3,210.7
|
$3,395.0
|
|
|
|
|
|
|
Liabilities and
Shareholder's Equity
|
|
|
|
|
|
Current
liabilities:
|
|
|
|
|
|
Accounts
payable
|
|
|
|
$10.5
|
$14.0
|
Accrued
interest
|
|
|
|
6.3
|
17.7
|
Other accrued
liabilities
|
|
|
|
48.9
|
58.8
|
Current portion of
long-term debt
|
|
|
|
26.4
|
216.2
|
Current portion of
convertible debentures
|
|
|
|
42.0
|
42.1
|
Current portion of
derivative instruments liability
|
|
|
|
28.4
|
28.5
|
Dividends
payable
|
|
|
|
3.8
|
6.8
|
Other current
liabilities
|
|
|
|
8.1
|
5.3
|
Total current
liabilities
|
|
|
|
174.4
|
389.4
|
|
|
|
|
|
|
Long-term
debt
|
|
|
|
1,436.0
|
1,254.8
|
Convertible
debentures
|
|
|
|
362.4
|
363.1
|
Derivative
instruments liability
|
|
|
|
58.2
|
76.1
|
Deferred income
taxes
|
|
|
|
95.7
|
111.5
|
Power purchase and
fuel supply agreement liabilities, net
|
|
|
|
36.9
|
38.7
|
Other non-current
liabilities
|
|
|
|
63.2
|
65.4
|
Commitments and
contingencies
|
|
|
|
-
|
-
|
Total
liabilities
|
|
|
|
2,226.8
|
2,299.0
|
|
|
|
|
|
|
Equity
|
|
|
|
|
|
Common shares, no par
value, unlimited authorized shares; 120,712,916
and 120,205,813 issued and outstanding at June 30, 2014 and
December
31, 2013, respectively
|
|
|
|
1,286.5
|
1,286.1
|
Preferred shares
issued by a subsidiary company
|
|
|
|
221.3
|
221.3
|
Accumulated other
comprehensive loss
|
|
|
|
(24.1)
|
(22.4)
|
Retained
deficit
|
|
|
|
(754.3)
|
(655.4)
|
Total Atlantic Power
Corporation shareholders' equity
|
|
|
|
729.4
|
829.6
|
Noncontrolling
interests
|
|
|
|
254.5
|
266.4
|
Total
equity
|
|
|
|
983.9
|
1,096.0
|
Total liabilities and
equity
|
|
|
|
$3,210.7
|
$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
June
30,
|
|
Six months
ended
June
30,
|
|
2014
|
2013
|
|
2014
|
2013
|
Project
revenue:
|
|
|
|
|
Energy
sales
|
$82.4
|
$76.9
|
|
$164.7
|
$153.8
|
Energy capacity
revenue
|
41.3
|
42.9
|
|
74.8
|
77.2
|
Other
|
19.5
|
16.3
|
|
49.0
|
42.6
|
|
143.2
|
136.1
|
|
288.5
|
273.6
|
|
|
|
|
|
|
Project
expenses:
|
|
|
|
|
|
Fuel
|
50.4
|
50.0
|
|
110.2
|
97.7
|
Operations and
maintenance
|
34.5
|
46.4
|
|
67.2
|
73.9
|
Development
|
1.1
|
1.8
|
|
1.8
|
3.5
|
Depreciation and
amortization
|
40.9
|
41.8
|
|
81.5
|
82.7
|
|
126.9
|
140.0
|
|
260.7
|
257.8
|
Project other income
(expense):
|
|
|
|
|
|
Change in fair value
of derivative instruments
|
(2.8)
|
24.3
|
|
11.9
|
36.9
|
Equity in earnings of
unconsolidated affiliates
|
3.3
|
8.7
|
|
11.9
|
15.9
|
Interest expense,
net
|
(5.8)
|
(8.8)
|
|
(20.4)
|
(16.8)
|
Impairment
|
(14.8)
|
-
|
|
(14.8)
|
-
|
|
(20.1)
|
24.2
|
|
(11.4)
|
36.0
|
Project (loss)
income
|
(3.8)
|
20.3
|
|
16.4
|
51.8
|
|
|
|
|
|
|
Administrative and
other expenses (income):
|
|
|
|
|
|
Administration
|
10.2
|
11.8
|
|
17.5
|
20.1
|
Interest,
net
|
27.7
|
25.3
|
|
94.1
|
51.2
|
Foreign exchange loss
(gain)
|
15.3
|
(14.5)
|
|
(1.5)
|
(22.0)
|
Other income,
net
|
-
|
(9.5)
|
|
(2.1)
|
(9.5)
|
|
53.2
|
13.1
|
|
108.0
|
39.8
|
(Loss) income from
continuing operations before income taxes
|
(57.0)
|
7.2
|
|
(91.6)
|
12.0
|
Income tax (benefit)
expense
|
(0.6)
|
0.6
|
|
(12.9)
|
(1.9)
|
(Loss) income from
continuing operations
|
(56.4)
|
6.6
|
|
(78.7)
|
13.9
|
Net loss from
discontinued operations, net of tax (1)
|
-
|
(5.4)
|
|
(0.1)
|
(4.9)
|
Net (loss)
income
|
(56.4)
|
1.2
|
|
(78.8)
|
9.0
|
Net (loss) income
attributable to noncontrolling interest
|
(0.3)
|
1.1
|
|
(6.7)
|
(0.8)
|
Net income
attributable to preferred share dividends of a subsidiary
company
|
3.1
|
3.1
|
|
5.9
|
6.3
|
Net (loss) income
attributable to Atlantic Power Corporation
|
$(59.2)
|
$(3.0)
|
|
$(78.0)
|
$3.5
|
|
|
|
|
|
|
Basic earnings per
share:
|
|
|
|
|
|
(Loss) income from
continuing operations attributable to Atlantic Power
Corporation
|
$(0.49)
|
$0.02
|
|
$(0.65)
|
$0.07
|
Loss from discontinued
operations, net of tax
|
-
|
(0.05)
|
|
-
|
(0.04)
|
Net (loss) income
attributable to Atlantic Power Corporation
|
$(0.49)
|
$(0.03)
|
|
$(0.65)
|
$0.03
|
Diluted earnings per
share:
|
|
|
|
|
|
(Loss) income from
continuing operations attributable to Atlantic Power
Corporation
|
$(0.49)
|
$0.02
|
|
$(0.65)
|
$0.07
|
Loss from discontinued
operations, net of tax
|
-
|
(0.05)
|
|
-
|
(0.04)
|
Net (loss) income
attributable to Atlantic Power Corporation
|
$(0.49)
|
$(0.03)
|
|
$(0.65)
|
$0.03
|
(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
|
|
|
|
|
Six months ended
June 30,
|
|
|
2014
|
2013
|
Cash flows from
operating activities:
|
|
|
|
Net (loss)
income
|
|
$(78.8)
|
$9.0
|
Adjustments to
reconcile to net cash provided by operating activities
|
|
|
|
Depreciation and
amortization
|
|
81.5
|
92.8
|
Loss of discontinued
operations
|
|
-
|
32.8
|
Gain on sale of
asset
|
|
(2.1)
|
(4.4)
|
Long-term incentive
plan expense
|
|
0.9
|
1.2
|
Impairment
charges
|
|
14.8
|
4.9
|
Equity in earnings
from unconsolidated affiliates
|
|
(11.9)
|
(15.9)
|
Distributions from
unconsolidated affiliates
|
|
37.8
|
18.0
|
Unrealized foreign
exchange gain
|
|
(1.4)
|
(8.7)
|
Change in fair value
of derivative instruments
|
|
(11.9)
|
(47.7)
|
Change in deferred
income taxes
|
|
(15.5)
|
(6.5)
|
Change in other
operating balances
|
|
|
|
Accounts
receivable
|
|
2.8
|
(3.6)
|
Inventory
|
|
(2.6)
|
(1.3)
|
Prepayments,
refundable income taxes and other assets
|
|
14.7
|
46.3
|
Accounts
payable
|
|
(4.6)
|
(9.4)
|
Accruals and other
liabilities
|
|
(18.2)
|
(10.6)
|
Cash provided by
operating activities
|
|
5.5
|
96.9
|
|
|
|
|
Cash flows provided
by investing activities
|
|
|
|
Change in restricted
cash
|
|
78.4
|
(19.4)
|
Proceeds from sale of
asset, net
|
|
1.0
|
148.3
|
Proceeds from treasury
grant
|
|
-
|
53.7
|
Biomass development
costs
|
|
-
|
(0.1)
|
Construction in
progress
|
|
(1.5)
|
(28.5)
|
Purchase of property,
plant and equipment
|
|
(2.5)
|
(2.7)
|
Cash provided by
investing activities
|
|
75.4
|
151.3
|
|
|
|
|
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
|
|
(608.0)
|
(64.2)
|
Payments for revolving
credit facility borrowings
|
|
-
|
(67.0)
|
Deferred financing
costs
|
|
(38.8)
|
-
|
Equity contribution
from noncontrolling interest
|
|
-
|
44.6
|
Offering costs related
to tax equity
|
|
-
|
(1.0)
|
Dividends paid to
common shareholders
|
|
(20.9)
|
(43.2)
|
Dividends paid to
noncontrolling interests
|
|
(14.2)
|
(9.3)
|
Cash used in
financing activities
|
|
(81.9)
|
(119.3)
|
|
|
|
|
Net (decrease)
increase in cash and cash equivalents
|
|
(1.0)
|
128.9
|
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
|
|
$157.6
|
$195.6
|
|
|
|
|
Supplemental cash
flow information
|
|
|
|
Interest
paid
|
|
$114.7
|
$65.3
|
Income taxes paid,
net
|
|
$1.0
|
$1.4
|
Accruals for
construction in progress
|
|
$8.2
|
$8.6
|
|
|
|
|
|
|
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 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
June 30,
|
Six months ended
June 30,
|
|
2014
|
2013
|
2014
|
2013
|
Project Adjusted
EBITDA by segment
|
|
|
|
|
East
(1)
|
$38.5
|
$29.4
|
$84.0
|
$78.5
|
West
(2)
|
22.9
|
14.1
|
34.1
|
34.7
|
Wind
|
17.2
|
15.5
|
35.1
|
30.5
|
Un-allocated corporate
(3)
|
(3.6)
|
(3.1)
|
(3.6)
|
(7.6)
|
Total
|
$75.0
|
$55.9
|
$149.6
|
$136.1
|
|
|
|
|
|
Reconciliation to
project income
|
|
|
|
|
Depreciation and
amortization
|
52.3
|
50.5
|
104.7
|
102.3
|
Interest expense,
net
|
8.6
|
9.5
|
24.7
|
19.7
|
Change in the fair
value of derivative instruments
|
3.1
|
(26.8)
|
(11.0)
|
(38.3)
|
Other (income)
expense
|
14.8
|
2.4
|
14.8
|
0.6
|
Project income
(loss)
|
$(3.8)
|
$20.3
|
$16.4
|
$51.8
|
(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.
|
|
Atlantic Power
Corporation
Table 9A – Cash
Distributions from Projects (by Segment, in millions of U.S.
dollars)
Six months ended
June 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
|
$60.3
|
$(9.4)
|
$(9.9)
|
$(0.6)
|
$24.2
|
$64.6
|
Equity
method
|
23.7
|
(3.3)
|
(5.4)
|
(0.6)
|
1.7
|
16.1
|
Total
|
84.0
|
(12.7)
|
(15.3)
|
(1.2)
|
25.9
|
80.7
|
West
|
|
|
|
|
|
|
Consolidated
|
26.6
|
-
|
-
|
(0.8)
|
(1.7)
|
24.1
|
Equity
method
|
7.5
|
(1.0)
|
-
|
-
|
0.3
|
6.8
|
Total
|
34.1
|
(1.0)
|
-
|
(0.8)
|
(1.4)
|
30.9
|
Wind
|
|
|
|
|
|
|
Consolidated
|
29.7
|
(3.5)
|
(7.1)
|
(0.3)
|
2.5
|
21.3
|
Equity
method
|
5.4
|
(2.9)
|
(2.3)
|
0.2
|
2.4
|
2.8
|
Total
|
35.1
|
(6.4)
|
(9.4)
|
(0.1)
|
4.9
|
24.1
|
Total
consolidated
|
116.6
|
(12.9)
|
(17.0)
|
(1.7)
|
25.0
|
110.0
|
Total equity
method
|
36.6
|
(7.2)
|
(7.7)
|
(0.4)
|
4.4
|
25.7
|
Un-allocated
corporate
|
(3.6)
|
-
|
-
|
(0.9)
|
4.5
|
-
|
Total
|
$149.6
|
$(20.1)
|
$(24.7)
|
$(3.0)
|
$33.9
|
$135.7
|
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)
Six months ended
June 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
|
$53.8
|
$(2.7)
|
$(8.1)
|
$(1.3)
|
$14.9
|
$56.6
|
Equity
method
|
24.7
|
(7.0)
|
(1.2)
|
-
|
2.6
|
19.1
|
Total
|
78.5
|
(9.7)
|
(9.3)
|
(1.3)
|
17.5
|
75.7
|
West
|
|
|
|
|
|
|
Consolidated
|
26.2
|
-
|
-
|
(0.8)
|
(12.0)
|
13.4
|
Equity
method
|
8.5
|
(1.6)
|
(0.1)
|
(0.4)
|
0.1
|
6.5
|
Total
|
34.7
|
(1.6)
|
(0.1)
|
(1.2)
|
(11.9)
|
19.9
|
Wind
|
|
|
|
|
|
|
Consolidated
|
25.5
|
(4.9)
|
(7.4)
|
(2.3)
|
(4.2)
|
6.7
|
Equity
method
|
5.0
|
(1.1)
|
(2.4)
|
(0.1)
|
0.3
|
1.7
|
Total
|
30.5
|
(6.0)
|
(9.8)
|
(2.4)
|
(3.9)
|
8.4
|
Total
consolidated
|
105.5
|
(7.6)
|
(15.5)
|
(4.4)
|
(1.3)
|
76.7
|
Total equity
method
|
38.2
|
(9.7)
|
(3.7)
|
(0.5)
|
3.0
|
27.3
|
Un-allocated
corporate
|
(7.6)
|
-
|
(1.3)
|
-
|
8.9
|
-
|
Total
|
$136.1
|
$(17.3)
|
$(20.5)
|
$(4.9)
|
$10.6
|
$104.0
|
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
June
30,
|
|
Six months
ended
June
30,
|
|
2014
|
2013
|
|
2014
|
2013
|
Cash Distributions
from Projects
|
$85.3
|
$50.1
|
|
$135.7
|
$104.0
|
Repayment of long-term
debt
|
(8.4)
|
(11.7)
|
|
(20.1)
|
(17.3)
|
Interest expense,
net
|
(8.5)
|
(11.1)
|
|
(24.7)
|
(20.5)
|
Capital
expenditures
|
(1.3)
|
(2.7)
|
|
(3.0)
|
(4.9)
|
Other, including
changes in working capital
|
28.5
|
19.7
|
|
33.9
|
10.6
|
Project Adjusted
EBITDA
|
$75.0
|
$55.9
|
|
$149.6
|
$136.1
|
Depreciation and
amortization
|
52.3
|
50.5
|
|
104.7
|
102.3
|
Interest expense,
net
|
8.6
|
9.5
|
|
24.7
|
19.7
|
Change in the fair
value of derivative instruments
|
3.1
|
(26.8)
|
|
(11.0)
|
(38.3)
|
Other (income)
expense
|
14.8
|
2.4
|
|
14.8
|
0.6
|
Project (loss)
income
|
$(3.8)
|
$20.3
|
|
$16.4
|
$51.8
|
Administrative and
other expenses (income)
|
53.2
|
13.1
|
|
108.0
|
39.8
|
Income tax (benefit)
expense
|
(0.6)
|
0.6
|
|
(12.9)
|
(1.9)
|
Net loss from
discontinued operations, net of tax
|
-
|
(5.4)
|
|
(0.1)
|
(4.9)
|
Net (loss)
income
|
$(56.4)
|
$1.2
|
|
$(78.8)
|
$9.0
|
Adjustments to
reconcile to net cash provided by operating
activities
|
95.6
|
18.1
|
|
92.2
|
66.5
|
Change in other
operating balances
|
(5.2)
|
(12.1)
|
|
(7.9)
|
21.4
|
Cash flows from
operating activities
|
$34.0
|
$7.2
|
|
$5.5
|
$96.9
|
Term loan facility
repayments (1)
|
(37.5)
|
-
|
|
(37.5)
|
-
|
Project-level debt
repayments
|
(5.5)
|
(7.9)
|
|
(15.4)
|
(10.5)
|
Purchases of property,
plant and equipment (2)
|
0.1
|
(1.7)
|
|
(2.5)
|
(2.7)
|
Distributions to
noncontrolling interests (3)
|
(3.1)
|
(2.0)
|
|
(5.2)
|
(2.9)
|
Dividends on preferred
shares of a subsidiary company
|
(3.1)
|
(3.1)
|
|
(5.9)
|
(6.3)
|
Free Cash
Flow
|
$(15.1)
|
$(7.5)
|
|
$(61.0)
|
$74.5
|
(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
June
30,
|
Six months
ended
June
30,
|
|
|
|
2014
|
2013
|
2014
|
2013
|
East
|
|
Accounting
|
|
|
|
|
Cadillac
|
|
Consolidated
|
$1.2
|
$2.4
|
$3.2
|
$4.6
|
Curtis
Palmer
|
|
Consolidated
|
12.1
|
11.4
|
18.7
|
18.7
|
Morris
|
|
Consolidated
|
2.8
|
1.0
|
6.6
|
2.1
|
Nipigon
|
|
Consolidated
|
2.8
|
2.3
|
8.7
|
8.6
|
North Bay
|
|
Consolidated
|
1.2
|
(0.8)
|
6.1
|
4.5
|
Piedmont
|
|
Consolidated
|
2.2
|
0.1
|
0.8
|
0.1
|
Tunis
|
|
Consolidated
|
1.0
|
(0.8)
|
5.8
|
4.1
|
Other
(1)
|
|
Consolidated
|
3.4
|
2.8
|
10.4
|
11.1
|
Chambers
|
|
Equity
method
|
4.0
|
4.3
|
9.8
|
10.2
|
Selkirk
|
|
Equity
method
|
4.2
|
4.4
|
9.1
|
10.1
|
Orlando
|
|
Equity
method
|
3.6
|
2.3
|
4.8
|
4.4
|
Total
|
|
|
38.5
|
29.4
|
84.0
|
78.5
|
West
|
|
|
|
|
|
|
Manchief
|
|
Consolidated
|
3.5
|
3.9
|
7.2
|
7.9
|
Naval
Station
|
|
Consolidated
|
3.5
|
3.1
|
4.8
|
4.5
|
Williams
Lake
|
|
Consolidated
|
2.8
|
(0.3)
|
6.8
|
8.4
|
Other
(2)
|
|
Consolidated
|
9.5
|
3.0
|
7.8
|
5.4
|
Frederickson
|
|
Equity
method
|
2.6
|
2.8
|
5.9
|
5.9
|
Other
(3)
|
|
Equity
method
|
1.0
|
1.6
|
1.6
|
2.6
|
Total
|
|
|
22.9
|
14.1
|
34.1
|
34.7
|
Wind
|
|
|
|
|
|
|
Canadian
Hills
|
|
Consolidated
|
8.1
|
7.8
|
13.8
|
14.5
|
Meadow
Creek
|
|
Consolidated
|
4.2
|
3.5
|
10.2
|
6.5
|
Rockland
|
|
Consolidated
|
2.3
|
2.0
|
5.7
|
4.5
|
Other
(4)
|
|
Equity
method
|
2.6
|
2.2
|
5.4
|
5.0
|
Total
|
|
|
17.2
|
15.5
|
35.1
|
30.5
|
Totals
|
|
|
|
|
|
|
Consolidated
projects
|
|
|
60.6
|
41.4
|
116.6
|
105.5
|
Equity method
projects
|
|
|
18.0
|
17.6
|
36.6
|
38.2
|
Un-allocated
corporate
|
|
|
(3.6)
|
(3.1)
|
(3.6)
|
(7.6)
|
Total Project
Adjusted EBITDA
|
|
|
$75.0
|
$55.9
|
$149.6
|
$136.1
|
|
|
|
|
|
|
|
Reconciliation to
project income (loss)
|
|
|
|
|
|
|
Depreciation and
amortization
|
|
|
$52.3
|
$50.5
|
$104.7
|
$102.3
|
Interest expense,
net
|
|
|
8.6
|
9.5
|
24.7
|
19.7
|
Change in the fair
value of derivative instruments
|
|
|
3.1
|
(26.8)
|
(11.0)
|
(38.3)
|
Other (income)
expense
|
|
|
14.8
|
2.4
|
14.8
|
0.6
|
Project income
(loss)
|
|
|
$(3.8)
|
$20.3
|
$16.4
|
$51.8
|
|
(1) Kenilworth,
Calstock, and Kapuskasing
(2) Moresby Lake,
Mamquam, North Island, Naval Training Station, and
Oxnard
(3) Q2 and YTD June
2013: Koma Kulshan, Gregory, and Delta-Person; Q2 and YTD June
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