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.  Logo - http://photos.prnewswire.com/prnh/20110809/NE49346LOGO  SOURCE Atlantic Power Corporation  Website: www.atlanticpower.com  
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