Atlantic Power Corporation Releases Second Quarter 2014 Results

       Atlantic Power Corporation Releases Second Quarter 2014 Results

PR Newswire

BOSTON, Aug. 7, 2014

BOSTON, Aug. 7, 2014 /PRNewswire/ --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.

Atlantic Power Corporation Logo

"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

  oProject 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
  oProject 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
  oCash flows from operating activities of $34.0 million increased $26.8
    million from Q2 2013
  oFree 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

  oProject 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
  oProject Adjusted EBITDA of $149.6 million increased $13.5 million from YTD
    June 2013
  oCash 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
  oFree 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

  oOn 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
  oClosed 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
  oLiquidity at quarter-end totaled $261 million, including $158 million of
    unrestricted cash

2014 Guidance Reaffirmed

  oProject Adjusted EBITDA of $280 to $305 million
  oProject Adjusted EBITDA for APLP alone of $165 to $175 million
  oFree 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 85.3        50.1                135.7       104.0
Projects
Aggregate power
generation (thousands   2,022.8     2,008.6             4,110.7     3,890.7
of Net MWh)
Weighted average        91.2%       92.9%               91.9%       93.9%
availability
Including results from
discontinued operations
^(1)
Cash flows from         $34.0       $7.2                $5.5        $96.9
operating activities
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:

  oNegative 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
  oDecreased 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
  oDecreased 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:

  oIncreased 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
  oIncreased 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
  oIncreased 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
  oIncreased 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:

  oNet 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
  oDecreased 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
  oDecreased project income of $7.2 million at Selkirk (East), primarily due
    to accelerated depreciation as described above
  oDecreased 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)
  oNet decreases in project income for other projects totaling approximately
    $7 million

These decreases were partially offset by the following positive factors:

  oIncreased 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
  oIncreased 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
  oIncreased 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
  oReduction 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:

  oNaval 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
  oOntario 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
  oPiedmont (East), approximately $2.1 million, due to a full quarter of
    operation versus a partial quarter of operation in 2013
  oOther 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
  oWind projects $1.7 million, primarily due to stronger wind generation,
    particularly at Meadow Creek

These increases were partially offset by the following decreases:

  oCadillac (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:

  oWind 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
  oTunis, North Bay and Kapuskasing (East), totaling $4.5 million, due
    primarily to increased waste heat, decreased maintenance expenses and
    other factors
  oMorris (East) $4.4 million, due primarily to lower maintenance costs,
    lower fuel expenses and higher revenues (higher PJM power prices)
  oNaval Training Center (West), $3.9 million due to lower maintenance
    expense compared to 2013, when the project underwent scheduled turbine
    maintenance
  oReduction 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:

  oCadillac (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
  oNet 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

  oAnnual Project Adjusted EBITDA guidance of $280 to $305 million
  oAnnual 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           $165 - $175                $88.8
EBITDA ^(2)
^(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                                                      June 30, 2014
                                         March 31, 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.

  oProject 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.
  oProject 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.
  oCash 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:

  o2014 Project Adjusted EBITDA will be in the range of $280 to $305 million;
  o2014 APLP Project Adjusted EBITDA will be in the range of $165 to $175
    million;
  o2014 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;
  othe Company's Free Cash Flow will improve in the remainder of the year;
  othe Company will have positive Free Cash Flow generation in the second
    half of the year;
  othe Company will reduce total debt on a net basis by approximately $80
    million this year;
  othe Company will repay the Cdn$44.8 million aggregate principal amount of
    convertible debentures due October 2014 at maturity using cash;
  othe 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;
  othe 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;
  oPiedmont 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;
  oAPLP 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;
  oan 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;
  othe 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;
  omajor maintenance expense and maintenance capex will average approximately
    $25 million annually, versus approximately $19 million in 2014;
  othe 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;
  othe Company will have annual optimization capex on average of
    approximately $5 to $10 million; and
  othe 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                 36.9     38.7
liabilities, net
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,       1,286.5  1,286.1
2014 and December
31, 2013, respectively
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'           729.4    829.6
equity
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  Six months ended

                                          June 30,           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        (2.8)      24.3     11.9      36.9
instruments
Equity in earnings of unconsolidated      3.3        8.7      11.9      15.9
affiliates
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  (57.0)     7.2      (91.6)    12.0
before income taxes
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,    -          (5.4)    (0.1)     (4.9)
net of tax ^(1)
Net (loss) income                         (56.4)     1.2      (78.8)    9.0
Net (loss) income attributable to         (0.3)      1.1      (6.7)     (0.8)
noncontrolling interest
Net income attributable to preferred      3.1        3.1      5.9       6.3
share dividends of a subsidiary company
Net (loss) income attributable to         $(59.2)    $(3.0)   $(78.0)   $3.5
Atlantic Power Corporation
Basic earnings per share:
(Loss) income from continuing operations
attributable to Atlantic Power            $(0.49)    $0.02    $(0.65)   $0.07
Corporation
Loss from discontinued operations, net of -          (0.05)   -         (0.04)
tax
Net (loss) income attributable to         $(0.49)    $(0.03)  $(0.65)   $0.03
Atlantic Power Corporation


Diluted earnings per share:
(Loss) income from continuing operations
attributable to Atlantic Power            $(0.49)    $0.02    $(0.65)   $0.07
Corporation
Loss from discontinued operations, net of -          (0.05)   -         (0.04)
tax
Net (loss) income attributable to         $(0.49)    $(0.03)  $(0.65)   $0.03
Atlantic Power Corporation
(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          (11.9)        (15.9)
affiliates
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  14.7          46.3
assets
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          600.0         -
facility
Proceeds from project-level debt                -             20.8
Repayment of corporate and project-level debt   (608.0)       (64.2)
Payments for revolving credit facility          -             (67.0)
borrowings
Deferred financing costs                        (38.8)        -
Equity contribution from noncontrolling         -             44.6
interest
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        (1.0)         128.9
equivalents
Cash and cash equivalents at beginning of       -             6.5
period at discontinued operations
Cash and cash equivalents at beginning of       158.6         60.2
period
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   Six months ended
                                June 30,             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     3.1        (26.8)    (11.0)    (38.3)
derivative instruments
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)
                                                      Other,
             Project  Repayment Interest              including Cash
Unaudited    Adjusted of        expense, Capital      changes   Distributions
             EBITDA   long-term net      expenditures in        from Projects
                      debt                            working
                                                      capital
Segment
East
            $60.3    $(9.4)    $(9.9)   $(0.6)       $24.2     $64.6
Consolidated
 Equity     23.7     (3.3)     (5.4)    (0.6)        1.7       16.1
method
 Total      84.0     (12.7)    (15.3)   (1.2)        25.9      80.7
West
            26.6     -         -        (0.8)        (1.7)     24.1
Consolidated
 Equity     7.5      (1.0)     -        -            0.3       6.8
method
 Total      34.1     (1.0)     -        (0.8)        (1.4)     30.9
Wind
            29.7     (3.5)     (7.1)    (0.3)        2.5       21.3
Consolidated
 Equity     5.4      (2.9)     (2.3)    0.2          2.4       2.8
method
 Total      35.1     (6.4)     (9.4)    (0.1)        4.9       24.1
 Total      116.6    (12.9)    (17.0)   (1.7)        25.0      110.0
consolidated
 Total
equity       36.6     (7.2)     (7.7)    (0.4)        4.4       25.7
method
Un-allocated (3.6)    -         -        (0.9)        4.5       -
corporate
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)
                                                      Other,
             Project  Repayment Interest              including Cash
             Adjusted of        expense, Capital      changes   Distributions
             EBITDA   long-term net      expenditures in        from Projects
                      debt                            working
                                                      capital
Segment
East
            $53.8    $(2.7)    $(8.1)   $(1.3)       $14.9     $56.6
Consolidated
 Equity     24.7     (7.0)     (1.2)    -            2.6       19.1
method
 Total      78.5     (9.7)     (9.3)    (1.3)        17.5      75.7
West
            26.2     -         -        (0.8)        (12.0)    13.4
Consolidated
 Equity     8.5      (1.6)     (0.1)    (0.4)        0.1       6.5
method
 Total      34.7     (1.6)     (0.1)    (1.2)        (11.9)    19.9
Wind
            25.5     (4.9)     (7.4)    (2.3)        (4.2)     6.7
Consolidated
 Equity     5.0      (1.1)     (2.4)    (0.1)        0.3       1.7
method
 Total      30.5     (6.0)     (9.8)    (2.4)        (3.9)     8.4
 Total      105.5    (7.6)     (15.5)   (4.4)        (1.3)     76.7
consolidated
 Total
equity       38.2     (9.7)     (3.7)    (0.5)        3.0       27.3
method
Un-allocated (7.6)    -         (1.3)    -            8.9       -
corporate
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           Six months ended

                            June 30,                    June 30,
                            2014         2013            2014        2013
Cash Distributions from     $85.3        $50.1           $135.7      $104.0
Projects
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 28.5         19.7            33.9        10.6
working capital
Project Adjusted EBITDA     $75.0        $55.9           $149.6      $136.1
Depreciation and            52.3         50.5            104.7       102.3
amortization
Interest expense, net       8.6          9.5             24.7        19.7
Change in the fair value of 3.1          (26.8)          (11.0)      (38.3)
derivative instruments
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    53.2         13.1            108.0       39.8
expenses (income)
Income tax (benefit)        (0.6)        0.6             (12.9)      (1.9)
expense
Net loss from discontinued  -            (5.4)           (0.1)       (4.9)
operations, net of tax
Net (loss) income           $(56.4)      $1.2            $(78.8)     $9.0
Adjustments to reconcile to
net cash provided by        95.6         18.1            92.2        66.5
operating
activities
Change in other operating   (5.2)        (12.1)          (7.9)       21.4
balances
Cash flows from operating   $34.0        $7.2            $5.5        $96.9
activities
Term loan facility          (37.5)       -               (37.5)      -
repayments ^(1)
Project-level debt          (5.5)        (7.9)           (15.4)      (10.5)
repayments
Purchases of property,      0.1          (1.7)           (2.5)       (2.7)
plant and equipment ^(2)
Distributions to
noncontrolling interests    (3.1)        (2.0)           (5.2)       (2.9)
^(3)
Dividends on preferred
shares of a subsidiary      (3.1)        (3.1)           (5.9)       (6.3)
company
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 EBITDAby Project (for Selected Projects)

(in millions of U.S. dollars)

Unaudited

                                  Three months ended         Six months ended

                                  June 30,                   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                   3.1     (26.8) (11.0)   (38.3)
derivative instruments
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

Website: www.atlanticpower.com
 
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