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                                 POWER


                                    AtlAntic Power
                                    corPorAtion
                                                AtlAntic 2007
                              AnnuAlAnnuAl REPORtpoweR coRpoRAtion
                                    RepoRt 2007                        A




Atlantic Power AR-jp.indd 1                                          4/22/08 8:04:09 AM
                 2007
                 COntEnts
             3 Report to Shareholders
             7 Projects At a Glance
             10 Management’s Discussion and Analysis
             43 Consolidated Financial Statements and Notes
             64 Corporate Information




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Atlantic Power AR-jp.indd 2                                                             4/22/08 8:04:11 AM
                              CORPORAtE PROfIlE
                              Atlantic Power Corporation owns interests in
                              a diversified and growing portfolio of power
                              generating and transmission projects located in
                              major markets in the United States. The Com-
                              pany’s objectives are to generate stable cash flows to
                              support distributions and grow the Company’s value
                              over the long term by enhancing the performance of
                              its existing assets and by making accretive acquisi-
                              tions. The Company’s income participating
                              securities (IPSs) are listed on the Toronto Stock
                              Exchange under the symbol ATP.UN.




                              fInAnCIAl hIGhlIGhts
                              (us$000 except where noted)
                              Years ended December 31                                          2007                     2006                    2005

                              Cash flows from operating activities                     $     85,901            $      57,521            $     38,370


                              Cash available for distribution                                73,996                   57,893                  48,680
                              Total IPS distributions                                        61,388                   43,449                  32,448
                              Payout Ratio                                                     83%                      75%                     67%


                              Total assets                                                 1,081,847               1,232,696                 926,630




                              MEEtInG OuR GOAls
                              In 2007 we made considerable progress on all of our key objectives:

                              1. sustain and grow cash flows:                                  3. Enhance financial flexibility:
                                 · Cash available for distribution increased 28%                  · Increased revolving credit facility from
                                 · Extended or entered into new power                               $75 to $100 million, extended its term
                                   purchase agreements at four projects                             and improved pricing
                                 · Installed upgraded gas turbines at the                         · Raised $48.5 million in private placement
                                   Lake Project, improving fuel efficiency by                       of 20-year non-recourse debt at holding
                                   4% and output by 10%                                             company for the Path 15 Project

                              2. Make accretive acquisitions:                                  4. Generate strong returns for investors:
                                 · Purchased remaining 50% interest in the Pasco                  · 44% total return for investors from our IPO in
                                   Project using $25 million cash on hand                           November 2004 through December 31, 2007




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Atlantic Power AR-jp.indd 1                                                                                                                          4/22/08 8:04:11 AM
             2                AtlAntic poweR coRpoRAtion   AnnuAl RepoRt 2007




Atlantic Power AR-jp.indd 2                                                     4/22/08 8:04:14 AM
                 REPORt tO shAREhOldERs


                              2007 was another year in which we generated substan-
                              tial growth in distributable cash by successfully execut-
                              ing our focused value-enhancing strategies. A number of
                              key achievements completed during the year also bode
                              well for continued growth going forward.

                              strong Performance                                           help alleviate what had been a chronic north-south trans-
                              In 2007 we continued our track record of demonstrat-         mission congestion problem in the west coast power grid.
                              ing solid progress in all of our growth initiatives.         It went into service in December 2004.
                                   Cash available for distribution, the most important          The acquisition provided a number of benefits to
                              metric for our investors, rose 28% for the year ended        Atlantic Power. It is a strategic and critical transmis-
                              December 31, 2007 to US $74.0 million compared to            sion asset with strong federal and state support produc-
                              $57.9 million in 2006. Distributions declared during         ing substantial benefits for ratepayers. It will provide
                              the year were US $61.4 million, resulting in a conser-       highly stable cash flows for more than 30 years, with
                              vative payout ratio of 83%. Our growth and increased         a federally regulated revenue stream that is indepen-
                              cash flow in 2007 also strengthened our financial            dent of power prices or line utilization. In addition,
                              position and provided us with substantial resources          it has very low operating risk, will require minimal
                              to help fund anticipated future investments as well          ongoing capital expenditures and reduces our overall
                              as the flexibility to act on acquisition opportunities as    portfolio risk.
                              they arise – a significant competitive strength.                  Most important, the Path 15 Project was immedi-
                                   Adjusted EBITDA (as defined in our MD&A) at the         ately accretive to our cash flow available for distribu-
                              Project level increased 11% during the year, the result      tion. We acquired Path 15 for an equity investment of
                              of enhanced performance at a significant number of           approximately $30.4 million net of non-recourse acqui-
                              Projects and a full year contribution from the Path 15       sition leverage, and through the end of 2007 we had
                              acquisition completed in September 2006. Aggregate           already received total cash distributions of more than
                              power generation increased by 3%, while plant availabil-     $21 million. We will continue to evaluate similar
                              ity rose by approximately 1% when compared to 2006.          accretive acquisitions that build value for our inves-
                                                                                           tors and contribute to increased cash flow available for
                              significant Accomplishments                                  distribution.
                              We continued to make significant progress on all three of         We also continue to examine all of our existing
                              our long-term strategic growth objectives during 2007.       investments to ensure each is making an appropriate
                                  Since our initial public offering we have grown our      return, fits with and enhances our overall portfolio,
                              business by prudently acquiring interests in power-produc-   and that its risk profile is at an appropriate level. Based
                              ing and related assets that meet our strict operating and    on this ongoing review, in 2007 we sold our equity in-
                              financial criteria. An excellent example is our September    vestment in the Jamaica Project for $6.2 million. We
                              2006 purchase of Path 15, an 84-mile, 500-kilovolt trans-    believed we had maximized the potential we could
                              mission line built along an existing transmission corridor   derive from the investment and wanted to eliminate
                              in California. The transmission line was constructed to      any risk associated with our exposure to the Project.



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Atlantic Power AR-jp.indd 3                                                                                                                       4/22/08 8:04:17 AM
                              In addition, the Project was not consistent with our pri-      completed the installation of upgraded gas turbines at
                              mary focus on the North American power industry.               the Lake Project. This investment will increase the proj-
                                  Our second strategy for building value is to evalu-        ect’s efficiency by 4% and its output by 10%. Factoring
                              ate opportunities to consolidate and increase our              in the improved heat rate and output, projected gas and
                              ownership in projects where we already have partial            electricity prices, plus changes to the turbine service
                              interests. We have a thorough understanding of these           agreement and major maintenance timing, we expect
                              projects and can accurately identify the risk-adjusted         a net increase in distributions from the Lake Project of
                              return and potential upside of such investments.               approximately $3 million in 2008, $1.7 million in 2009,
                                  An excellent example of this strategy is our pur-          between $0.3 million and $0.8 million per year through
                              chase of substantially all of the remaining 50.1% of           2014, and more than $5 million in 2015.
                              the Pasco Project for approximately $25 million in                  At our Onondaga Project, we anticipated that it would
                              December 2007. This investment was immediately                 cease contributing to our results once its swap and hedge
                              accretive to our cash flow, contributing $2.7 million          agreements finished in mid-2008. While we took the
                              of distributions in December. Based on our current             facility offline at the end of April, we have determined
                              expectation of operating cash flow and debt service            that the project could provide further value. The gas tur-
                              reserve releases, the additional interest in Pasco is ex-      bines will likely be sold for $5 million or more, and we
                              pected to increase cash distributions by approximately         are working with a developer to explore re-powering the
                              $6 million in both 2008 and 2009. Looking further              project into a 30 to 50 MW biomass facility. If the concept
                              ahead, from 2010 through 2018, based on our expecta-           proves to be technically and economically feasible, the
                              tions of operating performance and the terms of a new          new project could continue to provide some further cash
                              ten-year tolling agreement at Pasco that commences             distributions should we contribute the Onondaga Project
                              in 2009, the additional ownership is expected to pro-          site, its electrical interconnection and some remaining
                              vide increased distributions of approximately $2 mil-          equipment to a new joint venture.
                              lion per year. Under this new tolling agreement, we                 We also continually review the power purchase and
                              also do not incur the risks of either fuel price changes       fuel supply agreements at our Projects for opportunities
                              or potential new costs for environmental compliance.           to grow and enhance the long-term stability of our cash
                              We will continue to pursue similar opportunities to            flow. For example, in September 2007 the Chambers
                              grow our interests in certain of our current projects          Project executed a three-year renewal of its power
                              where these investments will contribute to higher re-          sales agreement with Atlantic City Electric. While
                              turns for our investors.                                       the Project’s base power sales agreement runs through
                                  Our third growth strategy is to enhance the operat-        2024, this separate agreement is an ongoing profit-
                              ing and financial performance of our existing facilities.      sharing arrangement with the utility for a portion of the
                              For example, during the fourth quarter of 2007 we              plant’s output sold on the open market, depending on



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Atlantic Power AR-jp.indd 4                                                                                                                            4/22/08 8:04:20 AM
                                                                                                                              Directors from
                                                                                                                              left to right:
                                                                                                                              Bill W hitman,
                                                                                                                              Ken Hartwick,
                                                                                                                              John McNeil,
                                                                                                                              Irving Gerstein,
                                                                                                                              and Barry Welch




                              market prices and the utility’s own power needs. The          Importantly, these initiatives serve to strengthen the long-
                              new agreement should generate additional cash distri-         term stability and sustainability of our distributable cash.
                              butions from the Project of approximately $1 million              Finally, we will continue to look for opportunities
                              per year. Additional new or extended agreements at            to consolidate and increase our ownership in projects
                              Pasco, Gregory, Rumford and Stockton executed dur-            where we have partial interests. We know these proj-
                              ing 2007 should also generate less volatile and higher        ects, are comfortable with their operations, and can
                              levels of cash flow over the long term, while lengthen-       accurately assess their future potential and risk pro-
                              ing our portfolio’s average contract term.                    file. Such investments can also be highly accretive to
                                                                                            our distributable cash flow.
                              A Positive Outlook                                                In addition, while the passing of Bill C-52 by the
                              2007 was clearly an active and successful year for            Canadian federal government may result in the tax-
                              Atlantic Power. Looking ahead, we remain confident in         ability of many publicly traded income trusts in 2011,
                              our ability to continue building value for our investors by   we remain confident that, as a corporation, we will
                              executing the core value-enhancing strategies that have       be unaffected in terms of taxes or constraints on our
                              generated such solid growth and performance since our         ability to continue growing.
                              initial public offering more than three years ago.                  Looking ahead, our ultimate objective remains
                                  We continue to evaluate additional acquisition op-        to deliver predictable, stable cash distributions and to
                              portunities within the North American power industry          enhance the Company’s value for our investors. Over
                              that meet our investment guidelines and can provide           the past three years we have clearly demonstrated that
                              an increase in cash available for our investors. Demand       we can grow distributable cash through the successful
                              for electricity continues to grow across North America,       implementation of our value-enhancing strategies,
                              resulting in a need for new power plants in many re-          and we believe we have the facilities, the industry re-
                              gions. In addition, there is increased liquidity in the       lationships and the management expertise to build on
                              secondary market for ownership interests in power-re-         this strong track record of performance.
                              lated assets. Through our numerous relationships with             In closing, we thank our customers, partners and
                              our investors, our sponsor, our existing project partners     sponsor for their significant contributions, and our
                              and the broader industry network, we have excellent           shareholders for their continued support.
                              access to these growth opportunities.
                                  We will also work with our project operators to en-
                              hance the operating and financial performance of our
                              facilities through ongoing operational improvements and
                              the optimization of our power purchase agreements, fuel       Barry Welch
                              supply contracts and other commercial arrangements.           President and Chief Executive Officer



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Atlantic Power AR-jp.indd 5                                                                                                                         4/22/08 8:04:24 AM
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Atlantic Power AR-jp.indd 6                                                     4/22/08 8:04:27 AM
                                                                                          PROJECts At A GlAnCE




                                  n

                                                                                                                                M
                                                                                                                I
                                                                                                                        h   O


                              l                                                                                     K

                                  J
                                                         B
                                      A
                                                                                                    d
                                                                                                        E
                                                                           C                                f
                                                                                                        G




                              GAs                                              COAl / BIOMAss
                              A Badger Creek Bakersfield CA                    K Chambers Carney’s Point NJ
                              B delta-Person Albuquerque NM                    l stockton Stockton CA
                              C Gregory Corpus Christi TX                      M Rumford Rumford ME
                              d Mid-Georgia Kathleen GA
                              E lake Umatilla FL                               hydRO
                              f Orlando Orlando FL                             n Koma Kulshan Whatcom County WA
                              G Pasco Tampa FL                                 O topsham Topsham ME
                              h selkirk Bethlehem NY
                              I Onondaga Geddes NY

                              tRAnsMIssIOn lInE
                              J  Path 15 California




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Atlantic Power AR-jp.indd 7                                                                                                     4/22/08 8:04:29 AM
             8                AtlAntic poweR coRpoRAtion   AnnuAl RepoRt 2007




Atlantic Power AR-jp.indd 8                                                     4/22/08 8:04:30 AM
                                                                                                      PROJECt PORtfOlIO


                                                                                            total              Ownership      net
                 Project name                         location       fuel type               MW                  Interest     MW

                 Badger Creek                         California     Natural gas              46                     50.0%     23

                 Chambers                             New Jersey     Coal                    262                     40.0%    105

                 Delta-Person                         New Mexico     Natural gas             132                     40.0%     53

                 Gregory                              Texas          Natural gas             400                     17.1%     68

                 Koma Kulshan                         Washington     Hydro                    13                     49.8%      6

                 Lake                                 Florida        Natural gas             110                     100.0%   110

                 Mid-Georgia                          Georgia        Natural gas             308                     50.0%    154

                 Onondaga                             New York       Natural gas              91                     100.0%    91

                 Orlando                              Florida        Natural gas             126                     50.0%     63

                 Pasco                                Florida        Natural gas             121                     99.8%    121

                 Path 15                              California     Transmission            n/A                     100.0%   n/A

                 Rumford                              Maine          Coal/Biomass             85                     23.5%     20

                 Selkirk                              New York       Natural gas             345                     18.5%     64

                 Stockton                             California     Coal                     55                     50.0%     27

                 Topsham                              Maine          Hydro                    14                     50.0%      7

                 For more information, see page 31.




                                                                   AnnuAl RepoRt 2007   AtlAntic poweR coRpoRAtion              9




Atlantic Power AR-jp.indd 9                                                                                                   4/22/08 8:04:30 AM
             MAnAGEMEnt’s dIsCussIOn And AnAlysIs
             of Financial condition and Results of operations



             The following management’s discussion and analysis (“MD&A”) of financial condition and results of operations should be read in conjunc-
             tion with the audited annual financial statements of Atlantic Power Corporation (“Atlantic Power” or the “Company”) for the year ended
             December 31, 2007. All dollar amounts in this MD&A are in thousands of U.S. dollars, unless otherwise stated. The financial statements have
             been prepared in accordance with Canadian generally accepted accounting principles (“GAAP”).

             forward-looking statements
             Certain statements in this MD&A may constitute “forward-looking statements”, which reflect the expectations of Atlantic Power Man-
             agement, LLC (the “Manager”) regarding future growth, results of operations, performance and business prospects and opportunities
             of Atlantic Power Corporation (the “Company”), Atlantic Power Holdings, LLC (“Atlantic Holdings”) and the Projects (as defined
             below). Such forward-looking statements reflect current expectations regarding future events and operating performance and speak
             only as of the date of this MD&A. Forward-looking statements involve significant risks and uncertainties, should not be read as guar-
             antees 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. A number of factors could cause actual results to differ materially from the results dis-
             cussed in the forward-looking statements, including, but not limited to, the factors discussed under “Risk Factors” section in this
             MD&A and under “Risk Factors” in the Company’s annual information form dated March 26, 2008. Although the forward-looking
             statements contained in this MD&A 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 MD&A and, except as expressly required by applicable law, the Company assumes no obliga-
             tion to update or revise them to reflect new events or circumstances.

             Information contained in this MD&A is based on information available to management as of March 26, 2008.

             Copies of financial data and other publicly filed documents, including the Company’s annual information form, are available through
             the Internet on SEDAR at www.sedar.com under “Atlantic Power Corporation” or on the Company’s website at www.atlanticpower-
             corporation.com.

             Overview
             The Company currently has 61,470,500 income participating securities (“IPSs”) and Cdn$60 million principal amount of 6.25%
             convertible secured debentures due October 31, 2011 (the “Debentures”) outstanding, and owns 100% of the membership interests in
             Atlantic Power Holdings, LLC (“Holdings”). Holdings was formed in 2004 to acquire indirect interests in a diversified portfolio of
             power generating facilities located primarily in major markets in the United States from ArcLight Energy Partners Funds I, L.P.
             (“Fund I”) and ArcLight Energy Partners Funds II, L.P. (“Fund II”, and, together with Fund I, the “ArcLight Funds”) and Caithness
             Energy, LLC (“Caithness”) (together with the ArcLight Funds, the “Former Investors”). As of February 2007, Holdings is a wholly
             owned subsidiary of the Company.
                 Each IPS is comprised of: (1) one common share of the Company (“Common Share”); and (2) Cdn$5.767 aggregate principal
             amount of 11.0% subordinated notes of the Company (“Subordinated Notes”). IPS investors receive a monthly distribution comprised
             of a dividend payment on the Common Share and an interest payment on the Subordinated Notes. The current annual rate of the
             total distribution is Cdn$1.06 per IPS. The Debentures were issued on October 11, 2006 and bear interest at an annual rate of 6.25%,
             payable semi-annually in arrears on April 30 and October 31 of each year commencing on April 30, 2007.




             10                          AtlAntic poweR coRpoRAtion        AnnuAl RepoRt 2007




Atlantic Power AR-jp.indd 10                                                                                                                           4/22/08 8:04:30 AM
                     As of December 31, 2007, the Company owned interests in 14 power generating facilities in the United States and a transmission
                 line in central California (collectively, the “Projects” and individually, a “Project”). The generating Projects have a combined total
                 power generating capacity of approximately 2,120 megawatts (“MW”). The Company’s interests in the Projects represented approxi-
                 mately 925 MW of power generating capacity as of December 31, 2007. Most of the generating Projects sell their power under long-
                 term power purchase agreements (“PPAs”) to investment-grade utilities or other purchasers. These agreements are typically structured
                 to stabilize cash flows by: (1) providing a significant portion of revenues via steady capacity or tolling payments generally designed to
                 provide a return of and on capital and to cover fixed costs regardless of how much electricity the plant is called upon to produce,
                 provided that the plant meets an availability requirement; and (2) passing most of the generating Projects’ fuel costs on to the purchas-
                 ers. As a result, variations in the portfolio’s cash flow based on changes in the amount of power generated, spot market electricity
                 prices and fuel price changes are significantly mitigated.
                     The Path 15 transmission line is a United States Federal Energy Regulatory Commission (“FERC”) regulated asset with a 30-year
                 regulatory life through 2034. Its annual revenue requirement is established by FERC and is collected by the California Independent
                 System Operator (“CAISO”) from utilities in California without variation for changes in power prices or line usage and with virtually
                 no technical or operating risks.
                     The Company’s objectives are to maintain the stability and sustainability of cash distributions to holders of IPSs in the form of
                 interest payments on Subordinated Notes and dividends on Common Shares, and to increase the long-term value of the Company.
                 To achieve these objectives, Company management, working directly with project managers, focuses on cash flows of the existing
                 Projects by improving facility performance, increasing output and efficiency, optimizing contracts and managing other project risks.
                 In addition, the Company has a focused growth strategy that includes consolidating interests in Projects in which it currently owns an
                 interest and making accretive acquisitions, with a primary focus on the electric power industry in the United States and Canada.
                     Management believes that opportunities for accretive acquisitions will be available based on a number of factors, including con-
                 tinued electricity demand growth and the corresponding need for new power plants, increased liquidity in the secondary market for
                 ownership interests in power-related assets, and superior access to potential growth transactions through ArcLight, certain of the
                 Company’s institutional investors and the Manager’s industry contacts. Competitors for these opportunities include private equity
                 funds, power income funds and other sources of capital.
                     The most significant economic factors affecting the Company’s performance are changes in interest rates, credit spreads and the
                 currency exchange rates between the U.S. dollar and the Canadian dollar. Most Project-related debt bears interest at a fixed rate, but
                 a small amount does have exposure to variability in interest rates. Credit spreads could affect valuations of assets the Company may
                 be attempting to buy or sell. Substantially all of the Company’s operating cash flow is earned in U.S. dollars and a large portion of the
                 Company’s cash obligations, primarily distributions on IPSs and interest payments on the Debentures, are denominated in Canadian
                 dollars. See “Financial and Other Instruments” in this MD&A for more information about currency exchange rate impacts and the
                 Company’s strategy for managing this risk.

                 non-GAAP financial Measures
                 Cash Flow Available for Distribution is not a measure recognized under GAAP and does not have a standardized meaning prescribed
                 by GAAP and is therefore unlikely to be comparable to similar measures presented by other issuers. Management believes Cash Flow
                 Available for Distribution is a relevant supplemental measure of the Company’s ability to earn and distribute cash returns to investors.
                 A reconciliation of net cash provided by operating activities from the Company’s financial statements to Cash Flow Available for
                 Distribution is set out in the “Cash Flow Available for Distribution” section of this MD&A. Investors are cautioned that the Company
                 may calculate this measure in a manner that is different from other companies.
                     Earnings before interest, taxes, depreciation and amortization (including non-cash impairment charges) and changes in fair value
                 of derivative instruments (“Adjusted EBITDA”) is not a measure recognized under GAAP and does not have a standardized meaning
                 prescribed by GAAP and is therefore unlikely to be comparable to similar measures presented by other issuers. Management uses
                 unaudited Adjusted EBITDA at the Projects to provide comparative information about Project performance. Investors are cautioned
                 that the Company may calculate this measure in a manner that is different from other companies.




                                                                          AnnuAl RepoRt 2007       AtlAntic poweR coRpoRAtion                           11




Atlantic Power AR-jp.indd 11                                                                                                                          4/22/08 8:04:30 AM
             Recent transactions/developments
             In the fourth quarter of 2007, the Company completed an upgrade of the gas turbines at the Lake Project that is expected to increase
             both the efficiency and output of the Lake Project by approximately 4% and 10%, respectively. The net cost of the upgrade was ap-
             proximately $9.3 million, of which $7.8 million was funded in the third quarter of 2007 with $2.6 million of cash on hand at the
             Project and a $5.2 million capital contribution from the Company. The completion of the upgrade in the fourth quarter was paid by
             the Lake Project with a $1.5 million capital contribution from the Company. In addition, the turbines that were replaced were sold
             in December 2007 for cash proceeds of $3.1 million and the Project recorded a loss of approximately $8.6 million on the sale. Factor-
             ing in improved heat rate and output, projected gas prices plus changes to the turbine service agreement and major maintenance
             timing, the Company expects this investment to provide an internal rate of return in excess of 15%.
                 In December 2007, the Company acquired substantially all of the remaining 50.1% of the Pasco Project from its partners for ap-
             proximately $25 million. Based on management’s current expectations of operating cash flow and debt service reserve releases, the
             acquisition of the remaining interest in Pasco is expected to increase distributions to Atlantic Power from Pasco by $7.0 million in both
             2008 and 2009. In 2010 through 2018, based on management’s expectations of operating performance and the terms of the new tolling
             agreement that commences in 2009, the additional ownership in Pasco is expected to provide increased distributions to the Company
             of approximately $2 million per year. The Company financed the equity purchase price of approximately $25 million with cash on
             hand. The Company also assumed an additional $7.5 million of existing debt at Pasco which is non-recourse to Atlantic Power and
             matures on December 31, 2008.
                 In October 2007, the Stockton Project extended its existing PPA with Pacific Gas & Electric by one year. The extended PPA expires
             in March 2009.
                 In September 2007, a subsidiary of the Company entered into a permanent financing arrangement related to its acquisition of the
             Path 15 Project. The financing is a fully amortizing term loan with final maturity in 2027 and bears interest at a fixed rate of 7.9%.
             Principal and interest payments are due in June and December of each year during the term of the loan. The term loan is secured by
             the Company’s investment in the Path 15 Project and is non-recourse to the Company.
                 In August 2007, the Chambers Project executed a three-year renewal of its power sales agreement (“PSA”) with Atlantic City Elec-
             tric (“ACE”) for the period August 2007 through July 2010. The PSA has historically been renewed on an annual basis. Under the terms
             of the PSA, ACE markets all energy and capacity from the Project that is not otherwise purchased by ACE under the Project’s base PPA.
             The volume of electricity that will be sold under the PSA varies based on market prices and the requirements of ACE under the base
             PPA. The Project and ACE share the profits on electricity and capacity sold under the PSA. As a result of the developing capacity mar-
             ket in the region, the new PSA is expected to result in improved financial performance at the Chambers Project and the Company
             projects that it could receive additional distributions from the Project of approximately $1 million per year.
                 In August 2007, the Company amended its revolving credit facility. Under the terms of the amendment, the total amount available
             under the credit facility has been increased from $75 million to $100 million, of which $50 million may be utilized for letters of credit.
             The November 2008 maturity date of the credit facility has been extended to August 2012 with an option for the Company to extend the
             maturity date by one additional year. In addition the interest rate margin on balances and letters of credit outstanding under the credit
             facility has been reduced. See “Liquidity and Capital Resources – Credit Facility” in this MD&A for additional information.
                 In August 2007, the Pasco Project signed a new ten-year tolling agreement with Tampa Electric Company (“TECO”). Under the
             terms of the tolling agreement, which is effective from 2009 to 2018, all of the capacity and energy of the Project is dedicated to TECO
             and the Project does not retain any fuel or electricity price risk. The agreement is subject to customary approval by the Florida Public
             Service Commission. After considering the acquisition of substantially all of the remaining 50.1% of Pasco as described above, the Com-
             pany expects to receive annual distributions from the Pasco Project of approximately $7 million during the term of the agreement.
                 In July 2007, the Gregory Project executed a PPA with Fortis Energy Marketing and Trading GP (“Fortis”). The new PPA begins
             following the expiry of the current PPA at the Project in 2008 and extends for five years, through 2013. The PPA is structured as a tolling
             agreement whereby the Project receives capacity payments for making the plant available and is not exposed to fuel or electricity price
             risk. As a result of executing the new PPA and the terms of the project-level financing arrangements, the Company received distribu-
             tions from Gregory in the amount of $8.1 million in January 2008. This distribution was attributable to the release of project-level debt
             service reserves.




             12                          AtlAntic poweR coRpoRAtion        AnnuAl RepoRt 2007




Atlantic Power AR-jp.indd 12                                                                                                                           4/22/08 8:04:30 AM
                     In July 2007, a subsidiary of the Company entered into an agreement to sell its equity investment in the Jamaica Project for
                 $6.2 million. The carrying value of the Jamaica Project at June 30, 2007 exceeded the sales price and, accordingly, an impairment
                 charge in the amount of $5.1 million was recorded in the second quarter of 2007. The sale transaction closed on October 30, 2007.
                     In June 2007, the Onondaga Project paid $9.75 million to an unrelated third party in exchange for the assumption by the third
                 party of long-term gas transportation contractual obligations that are not required for the operation of the Project. The carrying value
                 of the gas transportation liability at the date of the transaction exceeded the amount paid by the Onondaga Project to extinguish the
                 liability, resulting in a gain of approximately $10 million in the second quarter of 2007. The Onondaga Project funded the transaction
                 with a $9.75 million contribution from the Company, which was partially funded by a $9.4 million release of restricted cash at the
                 Path 15 Project. The Company had previously intended to extinguish this liability in 2008, but management determined that it was
                 more economical to execute the transaction in the second quarter of 2007. See “Liquidity and Capital Resources – Restricted Cash”
                 in this MD&A for additional information.
                     In February 2007, the Rumford Project executed an Interim Financial Consolidation Agreement (“IFCA”) with its steam host, the
                 Rumford Paper Company (“Rumford Paper”). The IFCA consolidates the payment obligations of the various agreements between the
                 Rumford Project and Rumford Paper into fixed payment obligations commencing January 1, 2007. The effect of the IFCA is similar to
                 a lease wherein Rumford Paper assumes the risk of fuel and power price volatility as well as most operating costs. Payments under the
                 IFCA will be made quarterly to the partnership over a three-year term ending December 31, 2009. The Company expects to receive
                 annual project distributions of approximately $2.7 million during the term of the IFCA compared to project distributions in the
                 amount of $2.3 million received in 2006 from Rumford.
                     On December 20, 2006, the Company announced that it had agreed to sell, on a private placement basis, a total of 8,600,000 IPSs
                 to three institutional investors, including Caisse de dépôt et placement du Québec (“CDP”), as well as Cdn$3.0 million principal
                 amount of Subordinated Notes issued and sold separately from the IPSs of the Company (the “Separate Subordinated Notes”). This
                 transaction increased CDP’s ownership in the Company to 19% of IPSs outstanding. Net proceeds were used by the Company in
                 February 2007 to acquire all of the remaining interest of the Former Investors in Holdings.

                 Changes in Accounting Policies
                 FinAnciAl inStRuMentS
                 On January 1, 2007, the Company adopted the new recommendations of Section 3855, “Financial Instruments – Recognition and Mea-
                 surement,” Section 3865, “Hedges,” Section 1530, “Comprehensive Income” and Section 3251, “Equity,” from The Canadian Institute
                 of Chartered Accountants (CICA) Handbook. The retroactive application of the new standards does not require restatement of prior peri-
                 ods. This change in accounting policy will result in significantly increased variability in net income but will not impact cash flows.
                     Section 3855, “Financial Instruments – Recognition and Measurement,” establishes standards for recognizing and measuring fi-
                 nancial assets, financial liabilities and non-financial derivatives. The standard requires that financial assets, financial liabilities and
                 non-financial derivatives be recognized on the consolidated balance sheets.
                     Under this standard, all financial instruments are required to be initially measured at fair value on initial recognition. Measure-
                 ment in subsequent periods is based on the classification of the financial instrument. Financial assets and financial liabilities held for
                 trading are measured at fair value with changes in fair value reported in earnings. Financial assets held to maturity, loans and receiv-
                 ables and financial liabilities other than those held for trading are measured at amortized cost using the effective interest method.
                 Available-for-sale financial assets and liabilities are measured at fair value with changes in fair value reported in other comprehensive
                 income until the financial instrument is de-recognized, at which time cumulative gain or loss previously recognized in accumulated
                 other comprehensive income is recognized in net income for the period.
                     Transaction costs are expensed as incurred for financial instruments classified or designated as held-for-trading. For other financial
                 instruments, transaction costs are capitalized on initial recognition.




                                                                           AnnuAl RepoRt 2007       AtlAntic poweR coRpoRAtion                            13




Atlantic Power AR-jp.indd 13                                                                                                                            4/22/08 8:04:31 AM
                 Derivative instruments are recorded on the consolidated balance sheets at fair value unless the derivative instrument is a contract
             to buy or sell a non-financial item in accordance with the Company’s expected purchase, sale or usage requirements, referred to as a
             “normal purchase” or “normal sale.” Changes in the fair values of derivative instruments are recognized in earnings unless the de-
             rivative instrument qualifies and is designated as an effective cash flow hedge or a normal purchase or normal sale. Normal purchases
             and normal sales are exempt from the application of the standard and are accounted for as executory contracts. Changes in the fair
             value of a derivative instrument designated as an effective cash flow hedge are recorded in accumulated other comprehensive income,
             a component of equity.
                 The Company has classified accounts payable, long-term debt (including current portion), subordinated notes and convertible
             debentures as other financial liabilities and measures these liabilities at amortized cost.
                 Other significant accounting implications of Section 3855 include the use of the effective interest method of amortization for any
             transaction costs or fees, premiums or discounts earned or incurred for financial instruments measured at amortized cost.

             Chambers Power Purchase Agreement
             As a result of adopting the requirements of Section 3855, the Company determined that the power purchase agreement, inclusive of
             the inter-related power sales agreement (collectively, the “PPA”) at the proportionately consolidated Chambers Project is a derivative
             instrument. The PPA does not qualify for exclusion from Section 3855 and has not been designated as a hedge. Accordingly, the PPA
             has been recorded at its fair value in the consolidated balance sheets and changes in the fair value are recognized in change in fair
             value of derivative instruments in the consolidated statements of loss, comprehensive loss and deficit.
                 The fair value of the PPA is measured by comparing the net present value of the cash flows expected to be received under the terms
             of the PPA to the net present value of the cash flows that would be received if the same volumes were sold at projected market power
             prices over the term of the contract expiring in 2024. Accordingly, periodic changes to the fair value of the PPA reflect changes in
             projected market conditions and do not directly impact the amount of cash flow the Chambers Project will receive under the terms
             of the PPA. For example, an increase in projected future prices of natural gas would result in increased projected future prices for
             power in the region generated from all sources, including plants such as Chambers that burn coal and are not directly impacted by
             changes in natural gas prices. When cash flows computed using projected future market power prices are compared to the contracted
             cash flows under the PPA, and future market prices increase, the fair value of the PPA declines and the Company records a loss. This
             accounting result is not related to the economics of the Chambers Project in any way and does not impact the cash distributions paid
             to the Company by the Chambers Project.
                 The initial impact of the accounting change was to decrease the opening deficit by $212,183 as of January 1, 2007 to reflect the fair
             value of the PPA in the amount of $155,762 and the removal from the consolidated balance sheet of the unamortized cost of the PPA
             in the amount of $56,421 (previously presented as a credit in other long-term liabilities) on that date. In addition a future tax liability
             and corresponding increase in deficit of $87,938 was recorded as a result of the adjustments to opening deficit as of January 1, 2007
             described above.
                 As of December 31, 2007, the fair value of the PPA in the amount of $49,652 was reflected in the consolidated balance sheets as $5,607
             included in the current portion of derivative instruments asset and $44,045 included in derivative instruments asset. The change in fair
             value of the PPA for the three and twelve months ended December 31, 2007 is recorded as a loss in the amount of $31,181 and $106,110,
             respectively, in the consolidated statements of loss, comprehensive loss and deficit. The change in fair value of the PPA also resulted in
             reductions in the future tax liability during the three and twelve-months ended December 31, 2007 of $12,472 and $42,445, respectively,
             which were recorded as a credit to income taxes in the consolidated statements of operations and deficit.




             14                          AtlAntic poweR coRpoRAtion        AnnuAl RepoRt 2007




Atlantic Power AR-jp.indd 14                                                                                                                           4/22/08 8:04:31 AM
                 Deferred Financing Costs
                 Deferred financing costs in the amount of $10,990 as of January 1, 2007 have been reclassified and presented together with the respec-
                 tive debt instrument to which the costs relate and are now being amortized using the effective interest method.
                     See Note 2(a) to the Company’s Consolidated Financial Statements for the year ended December 31, 2007 for additional informa-
                 tion about the adoption of the CICA Handbook Sections described above.

                 long-term Incentive Plan
                 The officers and other employees of the Manager are eligible to participate in the Company’s Long-Term Incentive Plan (“LTIP”), as
                 determined by the independent members of the Board of Directors of the Company. On an annual basis, the Board of Directors es-
                 tablishes awards that are based on the cash flow performance of the Company in the most recently completed year, each participant’s
                 base salary and the market price of the IPSs at the award date. Awards are granted in the form of notional units that have economic
                 characteristics similar to the Company’s IPSs. Notional units vest over a three-year period and are redeemed in a combination of cash
                 and IPSs upon vesting. Unvested notional units are entitled to receive distributions equal to the monthly distributions made on public
                 IPS during the vesting period in the form of additional notional units. Unvested notional units are subject to forfeiture if the participant
                 is not an employee of the Manager for any reason other than death, retirement, disability or change of control at the vesting date or if
                 the Company does not meet certain ongoing cash flow performance targets.
                     Compensation expense related to awards granted to participants in the LTIP is recorded over the vesting period based on the esti-
                 mated fair value of the award at each balance sheet date. Forfeitures are recorded as they occur and are not included in the estimated
                 fair value of the awards. The aggregate number of IPSs which may be issued from treasury under the LTIP is limited to one million.
                     On March 28, 2007, the Board of Directors approved grants of notional units to acquire a maximum of 172,071 IPSs under the
                 terms of the LTIP. The measurement date for the awards for accounting purposes occurred when participants were informed of the
                 details of their awards in April 2007. As a result, compensation expense related to the LTIP in the amount of $0.3 million and
                 $1.0 million was recorded in the three and twelve-month periods ended December 31, 2007, respectively. No compensation expense
                 related to the LTIP was recorded in the three and twelve-month periods ended December 31, 2006.

                 long-term Investments
                 During the first quarter of 2007, management reviewed its accounting for its investments in the Gregory and the Selkirk Projects that
                 have historically been accounted for using the equity method. Based on a current assessment, management determined that as of
                 January 1, 2007, the cost method of accounting is appropriate for these investments. Beginning January 1, 2007, the Company has
                 prospectively changed its accounting for its investments in the Gregory and Selkirk Projects from the equity method to the cost
                 method of accounting. Under the cost method, investment income is recorded to the extent of distributions received from the Proj-
                 ects. This change in accounting does not impact cash flow.
                     The Company’s investments in the Delta-Person and Rumford Projects continue to be recorded under the equity method of
                 accounting and are also included in long-term investments in the consolidated balance sheets.

                 Recently iSSued Accounting StAndARdS
                 A. Financial instruments – presentation
                 The CICA issued Handbook Section 3863, “Financial Instruments – Presentation,” which replaces CICA Handbook Section 3861,
                 to enhance financial statement users’ understanding of the significance of financial instruments to an entity’s financial position,
                 performance and cash flows. This section establishes the standards for presentation of financial instruments and non-financial deriva-
                 tives. It deals with the classification of financial instruments, from the perspective of the issuer, between liabilities and equity, the
                 classification of related interest, dividends, gains and losses, and the circumstances in which financial assets and financial liabilities are
                 offset. This standard harmonizes disclosure with International Financial Reporting Standards and applies to interim and annual
                 financial statements relating to fiscal years beginning on or after October 1, 2007. The Company is currently evaluating the impact of
                 this standard.




                                                                            AnnuAl RepoRt 2007        AtlAntic poweR coRpoRAtion                            15




Atlantic Power AR-jp.indd 15                                                                                                                               4/22/08 8:04:31 AM
             B. Financial instruments – disclosure
             The CICA issued Handbook Section 3862, “Financial Instruments – Disclosure,” which requires an entity to have sufficient disclosures
             so as to ensure that users of the financial statements can evaluate the significance of financial instruments on the entity’s financial posi-
             tion and performance. In order to satisfy this principle, Section 3862 lists specific disclosure requirements. The new standard applies
             to interim and annual financial statements relating to fiscal years beginning on or after October 1, 2007. The Company is currently
             evaluating the impact of this standard.

             selected financial data (in thousands of u.s. dollars, except as otherwise stated)

                                                                           three months ended december 31                      years ended december 31
             (unaudited)                                                    2007         2006       2005               2007           2006       2005

             Project income
             Project revenue                                               76,030       69,506         58,023      306,192        261,091        184,700
             Project expenses                                              51,219       47,454         46,312      204,805        181,753        144,193
             Project other income (expense)                              (120,241)      (7,447)        (4,052)    (214,782)       (22,091)         7,749

             Total project income (loss)                                  (95,430)      14,605          7,659     (113,395)         57,247        48,256

             Administrative and other expenses
             Management fees and administration                            2,574          1,894         1,693        8,185           6,367         5,095
             Interest, net                                                10,607          9,858         7,178       44,282          31,589        23,698
             Distribution, non-controlling interest                            –          2,029         4,340            –          15,107        20,578
             Income (loss) from change in non-controlling
                 interest liability                                             –         1,647       (10,588)           –           3,691       (10,588)
             Foreign exchange loss (gain)                                   2,030        (5,297)        1,872       30,142           1,295         6,453
             Other expenses                                                   399           287           247          975           1,029           990

             Total administrative and other expenses                      15,610        10,418          4,742       83,584          59,078        46,226

             Income (loss) before income taxes                           (111,040)        4,187         2,917     (196,979)         (1,831)        2,030

             Income tax expense (benefit)                                 (36,797)        1,253           179       (47,774)           577         2,539

             Net income (loss)                                            (74,243)        2,934         2,738     (149,205)         (2,408)          (509)

             Basic earnings (loss) per share, US$                          $(1.21)       $(0.06)        $0.06        $(2.43)        $(0.05)        $(0.01)
             Basic earnings (loss) per share, Cdn$                         $(1.19)       $(0.06)        $0.07        $(2.61)        $(0.06)        $(0.02)

             Diluted earnings (loss) per share, US$                        $(1.21)       $(0.05)        $0.06        $(2.43)        $(0.05)        $(0.01)
             Diluted earnings (loss) per share, Cdn$                       $(1.19)       $(0.06)        $0.07        $(2.61)        $(0.06)        $(0.02)

             Total assets at December 31                                1,081,847    1,176,275       926,630     1,081,847      1,232,696        926,630

             Total long-term liabilities at December 31                  881,403     1,012,876       812,448       881,403        847,052        812,448

             Cash flows from operating activities                         47,184        23,883         19,473       85,901          57,521        38,370
             Cash distributions declared per IPS, Cdn$                     $0.27         $0.27          $0.26        $1.06           $1.04         $1.01




             16                            AtlAntic poweR coRpoRAtion        AnnuAl RepoRt 2007




Atlantic Power AR-jp.indd 16                                                                                                                               4/22/08 8:04:31 AM
                 Results of Operations for the three and twelve-Month Periods Ended december 31, 2007
                 oVeRView
                 Project income is the primary GAAP measure of the Company’s operating results and is discussed in “Project Operations Performance
                 – Three and Twelve-Month Periods Ended December 31, 2007” below. In addition, an analysis of non-project expenses impacting the
                 results of the Company is set out in “Administrative and Other Expenses” below.
                     Significant non-cash items, which are subject to potentially significant fluctuations, include: (1) the change in fair value of certain
                 financial instruments and non-financial derivatives that are required by GAAP to be revalued at each balance sheet date (see “Finan-
                 cial and Other Instruments” in this MD&A for additional information); (2) the non-cash portion of the foreign exchange gain or loss,
                 reflecting the impact of foreign exchange fluctuations from period to period on the U.S. dollar equivalent of the Company’s Canadian
                 dollar-denominated debt and the mark-to-market value of currency forward contracts; (3) the impairment of goodwill at the Chambers
                 Project in the fourth quarter of 2007; and (4) for periods prior to January 1, 2007, the change in fair value of the non-controlling inter-
                 est previously held in Holdings by the Former Investors.
                     Cash Flow Available for Distribution was $20,667 and $73,996 for the three and twelve months ended December 31, 2007, respec-
                 tively, compared to $11,626 and $57,893, respectively, for the same periods in 2006, representing an increase of 78% in the fourth
                 quarter and an increase of 28% for the year-to-date period. See “Cash Flow Available for Distribution” in this MD&A for additional
                 information.
                     Net loss and comprehensive loss for the three and twelve months ended December 31, 2007 was $74,243 and $149,205, respec-
                 tively, compared to net income of $2,934 and a net loss of $2,408, respectively, for the comparable periods in 2006. The change
                 reflects project income (loss) of $(95,430) and $(113,395), respectively, during the three and twelve-month periods ended
                 December 31, 2007, attributable to the non-cash change in fair value of derivative instruments of $(38,730) for the fourth quarter of
                 2007 and $(128,377) for the twelve months ended December 31, 2007, as well as the non-cash impairment of goodwill at Chambers
                 of $71,726 in the fourth quarter of 2007. Excluding these non-cash charges and related future income taxes, the net loss for the three
                 months and twelve months ended December 31, 2007 would have been $7,969 and $29,143, respectively. See “Project Income” in
                 this MD&A for additional information.
                     Administrative and other expenses increased by $5,192 to $15,610 for the three months ended December 31, 2007 and increased by
                 $24,506 to $83,584 for the twelve months ended December 31, 2007, compared to the same periods in 2006. A significant portion of
                 this increase in both the quarter and year-to-date periods is attributable to foreign exchange losses in 2007 resulting from the strengthen-
                 ing of the Canadian dollar. In addition, interest expense was higher in the full year 2007 compared to 2006 as a result of higher levels
                 of outstanding debt. Partially offsetting these increases is the absence of the net impact of the non-controlling interest liability during
                 the three and twelve months ended December 31, 2007. The non-controlling interest liability was extinguished as a result of the re-
                 demption of the Former Investors’ interests in the fourth quarter of 2006 and has no impact on 2007 results. See “Administrative and
                 Other Expenses” in this MD&A for additional information.
                     The Company is organized as a Canadian-resident corporation but pays income taxes primarily in the United States and in the in-
                 dividual states in which it operates. The Company’s taxable income has historically not been significant and therefore net cash taxes
                 have also not been significant. The adoption of the new accounting standards related to financial instruments as of January 1, 2007 re-
                 sulted in the PPA at the Chambers Project being recorded at fair value at each balance sheet date. Accounting for this contract at fair
                 value has resulted in significant volatility in its recorded value. The future tax liability related to these changes in fair value has also
                 changed significantly from period to period and is expected to continue to be subject to significant variations in future periods. Accord-
                 ingly, a significant portion of the amounts recorded as income taxes in the consolidated statement of operations and deficit relates to
                 fluctuations in the future tax liability that result from changes in the market value of the Chambers PPA. Management does not expect
                 these fluctuations in income taxes for book purposes to result in material cash payments of taxes in the foreseeable future.




                                                                           AnnuAl RepoRt 2007        AtlAntic poweR coRpoRAtion                           17




Atlantic Power AR-jp.indd 17                                                                                                                             4/22/08 8:04:31 AM
             Project Income
             Project revenue totalled $76,030 and $306,192 during the three and twelve months ended December 31, 2007, respectively, an in-
             crease of $6,524 (9%) and $45,101 (17%), respectively, from the same periods in the prior year. The increase in project revenues
             during the three months ended December 31, 2007 was primarily attributable to the following factors:

             ·    Higher revenues at Pasco attributable to higher volumes sold compared to the prior year due to an outage in October 2006,
                  as well as higher revenues associated with the increased ownership of the Project by the Company for the final seven days of 2007
             ·    Increased revenues at the Chambers Project as a result of increased generation and higher spot market prices
             ·    Higher dispatch at Mid-Georgia due to warmer than average weather in the region.

             For the twelve-month period ended December 31, 2007, the increase in revenues is attributable to the fourth quarter factors described
             above, as well as higher variable energy payments at Badger Creek under the Project’s power purchase agreement, primarily in the
             first and second quarters, due to higher natural gas prices, and the operations of the Path 15 Project acquired September 15, 2006.
                  Project expenses increased by $3,765 or 8% to $51,219 during the three months ended December 31, 2007 compared to the prior
             year primarily as a result of:

             ·    Increased fuel costs at Chambers as a result of higher volumes of electricity generated
             ·    Increased fuel expense at Onondaga
             ·    Higher fuel expense at Pasco attributable to higher volumes sold compared to the prior year due to an outage in October
                  2006, as well as higher operating costs associated with the increased ownership of the Project by the Company for the final
                  seven days of 2007.

             For the twelve months ended December 31, 2007, project expenses increased by $23,052 or 13% over the same period in 2006 to
             $204,805. In addition to the factors described above for the fourth quarter of 2007, the higher expenses in the year-to-date period in-
             clude:

             ·    Increased fuel expenses at Badger Creek as a result of higher natural gas prices earlier in the year
             ·    Higher fuel expense at Mid-Georgia resulting from higher dispatch from the Project’s PPA counterparty
             ·    Higher fuel prices at Orlando due to adjustments in the variable price component of the Project’s gas supply agreement
             ·    Additional depreciation and operating expense attributable to the acquisition of the Path 15 Project on September 15, 2006
             ·    Higher amortization expense at Chambers resulting from a one-time non-cash benefit recorded in the third quarter of 2006 due
                  to a purchase accounting adjustment.

                 Project other income (expense) of ($120,241) and ($214,782) during the three and twelve months ended December 31, 2007, re-
             spectively, includes a non-cash charge attributable to the change in fair value of derivative instruments of $38,730 and $128,377, re-
             spectively. The change in fair value of derivative instruments is comprised of (1) a decrease in the fair value of the Chambers PPA of
             $31,181 and $106,110, respectively, for the three and twelve-month periods in 2007, driven by changes in forecasted long-term com-
             modity prices; and (2) the net change in fair value of the indexed swap derivative instruments at the Onondaga Project in the amount
             of $5,574 and $20,289, respectively, for the fourth quarter and year-to-date periods in 2007. The change in fair value of derivative in-
             struments in the three and twelve-month periods ended December 31, 2006 of $5,306 and $18,233, respectively, relates to the indexed
             swap derivative instruments at the Onondaga Project.
                 The increase in project interest expense during the three and twelve months ended December 31, 2007 compared to the same periods
             in 2006 is primarily attributable to non-recourse project-level debt associated with Path 15, which was acquired in September 2006.




             18                          AtlAntic poweR coRpoRAtion       AnnuAl RepoRt 2007




Atlantic Power AR-jp.indd 18                                                                                                                           4/22/08 8:04:31 AM
                     Other income (loss) of ($77,937) and ($67,896) for the three and twelve-month periods ended December 31, 2007 is primarily
                 attributable to:
                 · Fourth quarter impairment of goodwill at Chambers in the amount of $71,726 resulting from the significant increase in the book
                     value of the reporting unit due to the Project’s PPA being recorded as a financial instrument at fair value. The fair value accounting
                     for the PPA and the impairment of goodwill do not reflect any change in the underlying economic value of or anticipated future
                     cash distributions from the Chambers Project.
                 · Fourth quarter loss on the sale of replaced gas turbines at Lake in the amount of $8,554
                 · Fourth quarter income of $2,430 at Chambers related to a cash payment received from the Project’s other owner as compensation
                     for a technical tax termination of the Project partnership resulting from the other owner transferring its interest in the Project to
                     another party
                 · Gain of approximately $10,040 in the second quarter on the settlement of a gas transportation contract liability at the Onondaga
                     Project.

                 Administrative and Other Expenses
                 Management fees and administration includes the costs of operating a public company, as well as the fees and costs associated with
                 the Manager. The Manager is indirectly owned by the ArcLight Funds and receives compensation in the form of an annual base fee
                 that is indexed to inflation and an incentive fee that is equal to 25% of the cash distributions to IPS holders and Former Investors in
                 excess of Cdn$1.00 per year per IPS. The Company also reimburses the Manager for reasonable costs incurred to manage the Com-
                 pany. The increase in management fees and administration during the three and twelve-month periods ended December 31, 2007 is
                 primarily attributable to personnel additions in the offices of the Manager of the Company, the expense recognized related to awards
                 under the Company’s LTIP that did not exist in prior periods, and increased business development costs associated with the review of
                 potential acquisitions.
                     Interest expense primarily relates to required interest payments to holders of the Subordinated Notes and the Debentures. The
                 increase in net interest expense during the three and twelve-month periods ended December 31, 2007 is attributable to the issuance
                 of the Debentures and additional Subordinated Notes in the fourth quarter of 2006. Earnings on higher levels of cash and cash
                 equivalents invested in the three and twelve-month periods ended December 31, 2007, as well as higher short-term interest rates on
                 these investments, partially offset this increase in interest expense.
                     Prior to December 31, 2006, distributions to non-controlling interest represented distributions paid by Holdings on membership
                 interests owned by the Former Investors. As described in “Recent Transactions” in this MD&A, the Company acquired all of the re-
                 maining Former Investors’ interest in Holdings in February 2007 and, accordingly, no further distributions will be paid to the Former
                 Investors. Also related to the Former Investors interests in Holdings prior to 2007, the loss (income) from change in non-controlling
                 interest represented: (1) the change in the fair value of the liability during each period based on the market value of the IPSs at each
                 balance sheet date; and (2) the reduction in the liability resulting from the redemptions of the Former Investors’ interest in Holdings
                 that occurred in the fourth quarter of 2006.
                     Prior to December 31, 2006, the non-controlling interest liability was estimated at each balance sheet date based on the market
                 value of the Company’s IPSs at the balance sheet date multiplied by the number of membership interests in Holdings owned by the
                 Former Investors at that date. In December 2006, the final amount to be paid to the Former Investors for its remaining interest in
                 Holdings was determined based on the net price received per IPS for the Company’s sale, on a private placement basis, of 8,600,000
                 IPSs (see “Recent Transactions” in this MD&A for additional information). As a result, the liability was recorded at $76.9 million at
                 December 31, 2006 and this amount was paid to the Former Investors in February 2007 to redeem their remaining interest in Holdings,
                 extinguishing the liability. Beginning in 2007, the financial statements no longer reflect income variations that are attributable to
                 changes in the non-controlling interest liability.
                     Foreign exchange loss primarily reflects the unrealized impact of changes in foreign exchange rates on the U.S. dollar equivalent
                 of the Company’s Canadian dollar-denominated obligations to holders of Subordinated Notes and Debentures and, prior to 2007,
                 obligations to non-controlling interest. In addition, unrealized and realized gains and losses on the Company’s forward contracts for
                 the purchase of Canadian dollars to satisfy these obligations are included in foreign exchange loss.




                                                                          AnnuAl RepoRt 2007        AtlAntic poweR coRpoRAtion                           19




Atlantic Power AR-jp.indd 19                                                                                                                           4/22/08 8:04:31 AM
                 The value of the U.S. dollar relative to the Canadian dollar did not significantly change in the fourth quarter of 2007, but declined
             by approximately 4% in the fourth quarter of 2006. For the full year 2007, the value of the U.S. dollar relative to the Canadian dollar
             declined by approximately 17% compared to no significant change the prior year. The Company’s Canadian dollar obligations out-
             standing during the three and twelve months ended December 31, 2007 primarily consist of the outstanding subordinated notes and
             convertible debentures. In the comparable 2006 periods, the Company’s Canadian dollar obligations consisted of the subordinated
             notes and the non-controlling interest liability. In the fourth quarter of 2006, the convertible debentures and additional subordinated
             notes were issued. In the first quarter of 2007, the non-controlling interest liability was extinguished.

             The following table summarizes the components of the foreign exchange gains (losses):

                                                                                                      three months ended                 years ended
                                                                                                            december 31                 december 31
                                                                                                       2007         2006           2007         2006

             Subordinated notes and convertible debentures                                        $ (1,612)     $ 13,448       $ (68,419)    $    3,265
             Non-controlling interest                                                                    –          4,325              –         (2,196)
             Forward contracts                                                                      (4,191)       (13,521)        30,703         (6,289)

             Unrealized foreign exchange gains (losses)                                              (5,803)         4,252      (37,716)         (5,220)
             Realized foreign exchange gains
                on forward contract settlements                                                       3,773          1,046         7,574          3,925

                                                                                                  $ (2,030)     $    5,298     $ (30,142)    $   (1,295)


             supplementary financial Information
             The key measure used by management to evaluate the results of the Company’s investments is Cash Flow Available for Distribution.
             See “Cash Flow Available for Distribution” in this MD&A for additional details and for a reconciliation of Cash Flow Available for
             Distribution to its nearest GAAP measure, cash flows from operating activities.
                 The primary factor influencing Cash Flow Available for Distribution is cash distributions received from the Projects. These distribu-
             tions received are generally funded from Adjusted EBITDA generated by the Projects, reduced by Project-level debt service and capital
             expenditures, and adjusted for changes in Project-level working capital and cash reserves. Please read “Non-GAAP Financial Measures”
             in this MD&A for important disclosures with respect to Cash Flow Available for Distribution and Project Adjusted EBITDA.
                 Because Project Adjusted EBITDA and Project distributions are key measures of both the performance of the Company’s invest-
             ments and Cash Flow Available for Distribution, this MD&A contains supplementary unaudited non-GAAP information that sum-
             marizes Adjusted EBITDA by Project and a reconciliation of Adjusted EBITDA by Project-to-Project distributions actually received by
             the Company.
                 Many of the Company’s investments are either proportionately consolidated or accounted for under the cost or equity method of
             accounting in the consolidated financial statements presented in accordance with GAAP. The proportionate consolidation method
             of accounting is applied by recording in the Company’s consolidated financial statements its proportionate share of each financial
             statement account at the proportionately consolidated Project. As a result, some components of the Company’s balance sheet con-
             tain assets that are not directly available to the Company in the normal course of business, or liabilities that are not direct obligations
             of the Company.
                 For example, the Company’s proportionate share of cash at a proportionately consolidated Project is reflected in the consolidated
             balance sheet even though this cash may not be directly controlled by the Company because it is subject to: (1) the provisions of the
             partnership agreement that governs the underlying investment; or (2) in the case of Restricted Cash, the non-recourse debt covenants
             at the Projects. Conversely, the Company’s proportionate share of debt at a proportionately consolidated Project is also reflected in the
             consolidated balance sheet notwithstanding that all of the Project-level debt at the Projects is secured by assets at the Projects and is
             non-recourse to the Company.




             20                          AtlAntic poweR coRpoRAtion        AnnuAl RepoRt 2007




Atlantic Power AR-jp.indd 20                                                                                                                              4/22/08 8:04:32 AM
                 Project Operations Performance – three and twelve-Month Periods Ended december 31, 2007
                 Aggregate Adjusted EBITDA for the Projects, including earnings from Projects accounted for under the cost and equity methods,
                 decreased 5% to $40,654 for the three-month period ended December 31, 2007 compared to the fourth quarter of 2006. For the twelve
                 months ended December 31, 2007, Adjusted EBITDA increased 11% to $166,942 compared to the comparable period in 2006.
                    The decrease in Project Adjusted EBITDA in the fourth quarter of 2007 was primarily attributable to the following factors:

                 ·   Lower Adjusted EBITDA at Selkirk and no Adjusted EBITDA contribution from Gregory in 2007 due to these Projects being recorded
                     under the cost method of accounting beginning January 1, 2007. Under the cost method of accounting, Adjusted EBITDA is equal to
                     distributions received. The Selkirk Project pays distributions in the second and fourth quarter of each year and distributable cash at
                     Gregory is currently restricted under the terms of its project-level debt agreement. See “Recent Transactions” in this MD&A for ad-
                     ditional information about the new PPA at Gregory and distributions that are expected from that Project beginning in 2008.
                 ·   The absence of Adjusted EBITDA for the Jamaica Project, which was sold in October 2007
                 ·   Lower Adjusted EBITDA at Onondaga due to increased fuel expense, including the absence in the fourth quarter of 2007 of the
                     amortization of the liability associated with the gas transportation contracts that were extinguished in the second quarter of 2007.

                 Factors that partially offset the decrease described above include:

                 ·   Increased revenues at the Chambers Project as a result of increased generation and higher spot market prices
                 ·   Increased generation and efficiency and lower maintenance expense at Pasco resulting from turbine upgrades in 2006.

                    In addition to the factors described above for the fourth quarter, Adjusted EBITDA for the year-to-date period in 2007 compared to
                 2006 increased primarily as a result of:

                 ·   The contribution from the Path 15 Project, which was acquired on September 15, 2006
                 ·   The absence of a non-cash charge recorded at Stockton in the third quarter of 2006 related to future asset retirement obligations
                 ·   Higher dispatch at Mid-Georgia due to warmer than average weather in the region.

                 Factors that partially offset the increase described above include:

                 ·   Lower Adjusted EBITDA at Onondaga due to increased fuel expense as described above.

                 The generation and availability of the Project portfolio for the year ended December 31, 2007 did not change significantly from the
                 same period in 2006. Aggregate power generation increased 2.9% and plant availability rose 0.6% from the same period in 2006. Gen-
                 eration during the period was primarily impacted by increased generation at Mid-Georgia, due to increased dispatch, and at Gregory
                 and Pasco due to planned outages in 2006. The improved generation in 2007 was offset slightly by a reduction in production at Selkirk,
                 largely due to an unplanned outage in January 2007.
                     The Project portfolio achieved a weighted average availability of 97.6% for the year ended December 31, 2007, versus 97.0% for the year
                 ended December 31, 2006. The favorable change in the portfolio availability was due primarily to increased availability at Gregory.
                     For the fourth quarter of 2007, the aggregate generation of the portfolio increased 12% versus the same period last year, largely due
                 to the increased generation at Mid-Georgia associated with the plant’s increased dispatch by its host utility, slightly offset by lower
                 output at Delta-Person (compared to the same period in 2006 when generation was increased by higher dispatch). Availability for the
                 fourth quarter of 2007 of 96.2% was largely unchanged from the same period in 2006 – an increase of 1.3%.




                                                                           AnnuAl RepoRt 2007       AtlAntic poweR coRpoRAtion                            21




Atlantic Power AR-jp.indd 21                                                                                                                            4/22/08 8:04:32 AM
             Cash flow from Operating Activities
             The Company’s cash flow from the Projects varies from year to year based on, among other things, changes in rates under the PPAs, fuel
             supply and transportation agreements, steam sales agreements and other Project contracts, compliance with the terms of non-recourse
             project-level financing including debt repayment schedules, the transition to market pricing following the expiry of PPAs, fuel supply and
             transportation contracts, working capital requirements and the operating performance of the Projects. Project cash flows may have some
             seasonality and the pattern and frequency of distributions from the Projects to the Company during the year can also vary.
                 The Company’s cash flow from operating activities increased by $28,380 or 49% for the year ended December 31, 2007 compared
             to the same period in the prior year. The increase is primarily attributable to significantly higher Adjusted EBITDA at the Company’s
             consolidated and proportionately consolidated Projects and routine changes in working capital balances during the 2007 period. See
             “Project Operations Performance–Three And Twelve-Month Periods Ended December 31, 2007” for additional information about
             Adjusted Project EBITDA.

             Cash flow Available for distribution
             Holders of IPSs receive cash distributions in the form of interest payments on Subordinated Notes and dividends on Common Shares.
             The Company increased the distribution from an annual rate of Cdn$1.03 per IPS to an annual rate of Cdn$1.06 per IPS, effective
             with the September 2006 distribution.
                 Cash flow available for distribution increased by $9,041 and $16,103 in the three and twelve months ended December 31, 2007,
             respectively, when compared to the prior year periods.
                 The increase in both the fourth quarter and the full year is primarily attributable to substantially higher operating cash flows
             driven by increased Adjusted EBITDA at the Projects. See “Project Operations Performance – Three and twelve-month periods ended
             December 31, 2007” in this MD&A for additional details. This increase is partially offset by adjustments related to income tax install-
             ments recoverable, which reduce cash flow available for distribution in both the fourth quarter and the full year 2007 when compared
             to the prior year periods. In addition, for the twelve months ended December 31, 2007, Project-level debt repayments were higher than
             in the prior year due to the acquisition of the Path 15 Project on September 15, 2006.
                The table below presents the Company’s calculation of Cash Flow Available for Distribution for the three and twelve months
             ended December 31, 2007 and 2006.




             22                          AtlAntic poweR coRpoRAtion        AnnuAl RepoRt 2007




Atlantic Power AR-jp.indd 22                                                                                                                          4/22/08 8:04:32 AM
                 (In thousands of u.s. dollars, except as otherwise stated)                                                      three months ended                         years ended
                                                                                                                                       december 31                         december 31
                 (unaudited)                                                                                                      2007         2006                   2007         2006

                 Cash flows from operating activities                                                                          47,184             23,883           85,901             57,521

                 Project-level debt repayment                                                                                 (13,156)           (11,441)         (37,581)           (27,185)
                 Interest on IPS portion of Subordinated Notes                                                                  9,968              7,723           36,726             26,464
                 Income tax installments recoverable (net)1, 2                                                                (21,638)            (8,124)          (6,120)             4,734

                 Purchase of property, plant and equipment3                                                                     (1,691)              (415)          (4,930)            (3,641)

                 Cash Flow Available for Distribution, US$4                                                                    20,667             11,626           73,996             57,893

                 Cash Flow Available for Distribution, Cdn$4                                                                   20,295             13,272           79,435             67,399

                 Interest on IPS Subordinated Notes                                                                              9,968              7,723          36,726             26,464
                 Dividends on IPS Common Shares                                                                                  6,693              5,187          24,662             16,985

                 Total IPS distributions, US$                                                                                  16,661             12,910           61,388             43,449
                 Total IPS distributions, Cdn$                                                                                 16,296             14,776           65,181             49,151

                 Cash Flow Available for Distribution per basic IPS, Cdn$4                                                       $0.33              $0.25            $1.29              $1.45
                 Cash Flow Available for Distribution per diluted IPS, Cdn$4                                                     $0.32              $0.23            $1.25              $1.42

                 Total distribution declared per IPS, US$                                                                        $0.27              $0.25            $1.00              $0.94
                 Total distribution declared per IPS, Cdn$                                                                       $0.27              $0.27            $1.06              $1.04
                 1    income tax installments recoverable represents management’s estimate of u.S. federal income tax installment payments that will be recovered in future periods.
                      the amount presented is comprised of installment payments made during the period, offset by the current tax provision recorded in the consolidated statement of
                      operations and deficit and any income tax refunds received. these adjustments have the effect of removing changes in working capital resulting from the timing
                      of quarterly tax payments and annual refund from the calculation of cash flow available for distribution. in addition, during the third quarters of both 2007 and 2006,
                      the respective prior year tax returns were finalized. As a result, the previously recorded tax provisions were adjusted to reflect the actual tax liability on the final tax
                      returns. these amounts are included in this table as additions to income tax installments recoverable in the amounts of $1,544 and $2,195 for the three and twelve
                      months ended december 31, 2007 and 2006, respectively.
                 2    during the second quarter of 2007, the company settled a long-term gas transportation contract liability for a $9.75 million cash payment. the cash payment was
                      previously expected to create a taxable loss in 2007 that would be carried back to prior years and result in a refund of approximately $3.2 million. this expected refund
                      was previously included in income tax installments recoverable for the second quarter of 2007. during the fourth quarter of 2007, management revised
                      its estimates of taxable income for 2007 and determined that the company is likely to have taxable income during the year rather than the taxable loss that resulted
                      from the analysis in the second quarter. Accordingly, the company does not expect to realize the $3.2 million cash tax benefit that was added to cash available for
                      distribution in the second quarter and this amount has been subtracted from cash available for distribution in the fourth quarter.
                 3    capital expenditures exclude growth capital expenditures at the lake project to purchase and install upgraded gas turbines in the amount of $4,546 and $12,341
                      for the three and twelve-months ended december 31, 2007. proceeds from the sale of the replaced turbines in the amount of $3,061 are also excluded from cash
                      available for distribution for the three and twelve-month periods ended december 31, 2007.
                 4    cash Flow Available for distribution 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 issuers. See “non-gAAp Financial Measures” in this Md&A.




                                                                                         AnnuAl RepoRt 2007               AtlAntic poweR coRpoRAtion                                         23




Atlantic Power AR-jp.indd 23                                                                                                                                                               4/22/08 8:04:32 AM
             discussion of distributable Cash
                                                                                        three months ended
                                                                                              december 31                  years ended december 31
                                                                                                      2007          2007          2006          2005

             Cash flows from operating activities (A)                                            $ 47,184      $ 85,901      $ 57,521 $       38,370
             Net loss (B)                                                                          (74,243)    (149,205)       (2,408)          (509)
             Actual cash distributions paid – Interest on subordinated notes                         9,956       36,235        26,464         20,346
             Dividends (C)                                                                           6,686       24,342        16,985         12,102

             Excess of cash flows from operating activities over dividends paid (A-C)               40,498       61,559         40,536         26,268
             Excess (shortfall) of net income over dividends paid (B-C)                            (80,829)    (173,547)       (19,393)       (12,611)



             As illustrated in the table above, the Company has historically generated substantially more cash flows from operating activities than
             it has paid in dividends. The Company has monthly interest payment obligations on its subordinated notes, including subordinated
             notes comprising a portion of each IPS, and its convertible debentures. The interest and dividend payments in the table above are
             expressed in U.S. dollars but paid in Canadian dollars. The payments in the table do not reflect the benefit of the Company’s contracts
             for forward purchases of Canadian dollars at exchange rates that are significantly more favorable than current levels of currency ex-
             change rates at December 31, 2007. See “Financial and Other Instruments” in this MD&A for additional details about the Company’s
             forward currency contracts.
                 The Company periodically evaluates its level of cash dividends with its Board of Directors by analyzing long-term cash flow projec-
             tions, as well as the accretion to cash flow provided by acquisitions, and maintains the dividend at a level that is sustainable on a
             long-term basis. In addition, the Company maintains cash on hand to be deployed for acquisitions and other growth opportunities at
             existing projects.
                 Net income includes large fluctuations in the fair value of derivative instruments and, prior to January 1, 2007, changes in the fair
             value of the non-controlling interest liability. These items do not affect cash flows that may be distributed to shareholders. Accord-
             ingly, management does not view the comparison of net income to cash dividends to be a meaningful measure of the Company’s
             historical or future ability to pay cash dividends to its shareholders.
                 Management believes that its calculation of Cash Flow Available for Distribution on the previous page provides meaningful infor-
             mation about the Company’s ability to pay dividends from cash generated by the operations of its operating assets.

             summary of Quarterly Results
             Variations in quarterly results are driven by the following factors:
             · Seasonality of Project revenues created by seasonal variances in demand for electric power, in some cases varied seasonal pricing
                for electricity under the PPAs and the typical scheduling of major facility maintenance in the spring and fall
             · Variations in cash flow may also be driven by the timing of quarterly and semi-annual Project-level debt payments, as distributions
                from the Projects to the Company must occur in conjunction with passing certain cash flow coverage tests related to those pay-
                ment dates
             · Non-cash charges, principally: (1) the change in fair value of certain financial instruments and non-financial derivatives that are
                required by GAAP to be revalued at each balance sheet date (see “Financial and Other Instruments” in this MD&A for additional
                information); (2) the non-cash portion of the foreign exchange gain or loss, reflecting the impact of foreign exchange fluctuations
                from period to period on the U.S. dollar equivalent of the Company’s Canadian dollar-denominated debt and the mark-to-market
                value of currency forward contracts; (3) the impairment of goodwill at the Chambers Project in the fourth quarter of 2007; and
                (4) for periods prior to January 1, 2007, the change in fair value of the non-controlling interest previously held in Holdings by
                the Former Investors.




             24                          AtlAntic poweR coRpoRAtion        AnnuAl RepoRt 2007




Atlantic Power AR-jp.indd 24                                                                                                                           4/22/08 8:04:32 AM
                 selected Quarterly Consolidated financial data (in thousands of u.s. dollars, except as otherwise stated)

                                                                                                 20061                                                     2007
                                                                            Q1             Q2             Q3             Q4              Q1         Q2            Q3       Q4

                 Project revenues                                     59,910          61,650         70,024         69,507        72,933         75,841      81,388     76,030
                 Net income (loss)                                     3,321           4,656        (13,319)         2,934       (32,047)       (24,188)    (18,728)   (74,243)
                 Cash flow from operating activities                   8,027          15,978          9,633         23,883        18,782         11,927       8,007     47,184
                 Cash distributions                                    9,951          10,273         10,314         12,910        13,964         15,069      15,695     16,661
                 Cash available for distribution                      10,243          21,309         14,715         11,626        20,819         17,413      15,097     20,667
                 Payout ratio                                           97%             49%            70%           111%           67%            87%        104%        81%

                 Per IPS statistics
                 Net income (loss) – basic                                0.07           0.11          (0.30)          0.06            (0.52)     (0.39)      (0.30)     (1.21)
                 Net income (loss) – diluted                              0.07           0.11          (0.30)          0.05            (0.52)     (0.39)      (0.30)     (1.21)
                 Cash flow from operating activities                      0.18           0.36           0.25           0.45             0.31       0.19        0.13       0.77
                 Cash available for distribution
                     US$                                                  0.23           0.48           0.33           0.22            0.34        0.28        0.25       0.34
                    Cdn$                                                  0.27           0.54           0.38           0.25            0.39        0.31        0.25       0.33
                 Distributions
                     US$                                                  0.23           0.23           0.23           0.25            0.23        0.25        0.26       0.27
                     Cdn$                                                 0.26           0.26           0.26           0.27            0.27        0.27        0.27       0.27
                 1   certain 2006 figures have been reclassified to conform to the financial statement presentation adopted in 2007.




                 liquidity and Capital Resources
                 The Company’s primary source of cash and cash equivalents is distributions from the Projects. A significant portion of the cash re-
                 ceived from Project distributions is distributed in the form of interest and dividends to holders of the IPSs, the Separate Subordinated
                 Notes and the Debentures. The Company plans to maintain the stability and sustainability of cash distributions to holders of IPSs.
                 The Company may fund future acquisitions with a combination of cash on hand, the issuance of additional debt or equity securities
                 and the incurrence of bank debt.
                     The Onondaga Project receives substantially all of its cash flows through settlements on a swap agreement and a related commod-
                 ity derivative instrument that have effectively fixed cash distributions to the Company from the Onondaga Project since the IPO. As
                 previously disclosed since the IPO, the financial agreements at the Onondaga Project expire in June 2008 and management does not
                 expect to receive material cash distributions from that Project after that date and is currently planning to cease operations in the Plant’s
                 current form. The Company is currently pursuing the sale of the Project’s turbines and estimates that the net proceeds from selling
                 the turbines could be approximately $5 million.
                     Management believes that the Company will be able to generate sufficient amounts of cash and cash equivalents to maintain the
                 Company’s operations and meet obligations as they become due. The following additional sources of liquidity, beyond cash flow from
                 operations, are available to the Company.




                                                                                       AnnuAl RepoRt 2007             AtlAntic poweR coRpoRAtion                            25




Atlantic Power AR-jp.indd 25                                                                                                                                               4/22/08 8:04:32 AM
             Credit facility
             In August 2007, the Company amended its credit facility. Under the terms of the amendment, the total amount available under the
             credit facility has been increased from $75 million to $100 million, of which $50 million may be utilized for letters of credit. The
             November 2008 maturity date of the credit facility has been extended to August 2012 with an option of an additional one-year exten-
             sion. In addition, the amended credit facility does not contain a requirement to reduce outstanding borrowings to zero on an annual
             basis, which gives the Company more flexibility in utilizing the credit facility for periods longer than one year.
                Outstanding amounts under the amended credit facility bear interest at the London Interbank Offered Rate (“LIBOR”) plus an
             applicable margin that varies based on certain credit statistics of Holdings. The range of applicable margin is 0.875% to 1.625%. Based
             on Holdings’ credit ratios at December 31, 2007, the applicable margin is currently 0.875%. Prior to the amendment, the applicable
             margin was fixed at 1.50%.
                As of December 31, 2007, $23,307 was allocated, but not drawn, to support letters of credit for contractual credit support at several
             Projects. In the first quarter of 2007, $31,000 was borrowed under the credit facility and used to repay the outstanding balance on the
             Path 15 Acquisition Credit Facility. See “Path 15 Acquisition Credit Facility” in this MD&A for additional information. As of Decem-
             ber 31, 2007, no advances were outstanding under the credit facility and the amount available for advances and letters of credit was
             $76,693 and $26,693, respectively.

             Restricted Cash
             The Projects generally have reserve requirements to support payments for major maintenance costs and project-level debt service. For
             Projects that are consolidated or proportionately consolidated with Atlantic Power, these amounts, or Atlantic Power’s portion of these
             amounts, are reflected as Restricted Cash on the Company’s consolidated balance sheet.
                 At December 31, 2007, Restricted Cash at consolidated and proportionately consolidated Projects totaled approximately
             $38.3 million. All Project-level debt is non-recourse to the Company and is fully amortized over the life of the Projects’ PPAs.
                 In June 2007, the Company issued a letter of credit in the amount of $9.4 million to provide credit support related to debt service
             reserve requirements at the Path 15 Project. As a result, $9.4 million in restricted cash was released to the Company. The released cash
             was used to partially fund a $9.75 million investment in the Onondaga Project, which was used by the Onondaga Project for the ex-
             tinguishment of a gas transportation contract liability. See “Results of Operations for the Three and Twelve-Month Periods Ended
             December 31, 2007” in this MD&A for additional information.
                 In December 2006, the Company sold 8,600,000 IPSs in a private placement transaction. See “Recent Transactions” in this MD&A
             for additional details. The proceeds from the private placement transaction were used in February 2007 to acquire all of the remaining
             interests of the Former Investors in Holdings. The net proceeds from the private placement transaction were deposited into an escrow
             account until regulatory approval was received in February 2007 for the transaction, in which the Company acquired all of the remain-
             ing interests of the Former Investors in Holdings. The balance in the escrow account was $74,433 at December 31, 2006 and was in-
             cluded in Restricted Cash in the consolidated balance sheet. The entire balance in the escrow account was paid to the Former Investors
             in February 2007.

             short-term Investments
             As of December 31, 2007, approximately $26 million of the Company’s cash and cash equivalents were invested in auction-rate secu-
             rities (“ARSs”). All of these ARSs are AAA rated by one or more of the major credit rating agencies and are comprised of guaranteed
             student loans or municipal securities. ARSs typically have an underlying maturity of up to 40 years but have historically traded in
             seven or 28 day intervals in a highly liquid market. The ARSs that were held at December 31, 2007 were redeemed at auctions held in
             January 2008 and the proceeds were re-invested in ARSs.
                 In February 2008, the overall market for ARSs suffered a significant decline in liquidity. In February and March 2008, several auc-
             tions of ARSs in which the Company had an investment were unsuccessful, resulting in the Company continuing to hold these secu-
             rities and the issuers paying interest at the maximum contractual rate. As of March 25, 2008, the Company had approximately
             $36 million invested in ARSs that are collateralized by portfolios of student loans that are guaranteed by the U.S. government under
             the Federal Family Education Loan Program.




             26                          AtlAntic poweR coRpoRAtion       AnnuAl RepoRt 2007




Atlantic Power AR-jp.indd 26                                                                                                                        4/22/08 8:04:32 AM
                     Based on the current market conditions, it is likely that auctions related to these securities will be unsuccessful in the near term.
                 Unsuccessful auctions will result in the Company continuing to hold these ARSs beyond their next scheduled auction reset dates and
                 limiting the short-term liquidity of these investments. While this affects the Company’s ability to access these funds in the near term,
                 management does not believe that the underlying securities or collateral have been affected. The Company intends to hold these ARSs
                 and does not anticipate a need to sell the ARSs in order to run the business. Management further believes that the issuers of these ARSs
                 are undertaking efforts to refinance the securities.
                     Management will continue to monitor the market for ARSs and consider its impact, if any, on the fair market value of the Com-
                 pany’s investments. If the current market conditions deteriorate further, the Company will be required to reclassify its investments
                 in ARSs from cash and cash equivalents to short-term investments and may also be required to record book losses on the ARSs but
                 does not anticipate any realized loss in these investments.

                 Path 15 Acquisition Credit facility and term loan
                 The acquisition of the Path 15 Project on September 15, 2006 was initially financed with an acquisition credit facility in the amount
                 of $88 million (the “Acquisition Credit Facility”) at Holdings. In October 2006, approximately $37 million of the net proceeds of the
                 Company’s public offering of IPSs and Debentures were applied to repay a portion of the principal amount outstanding on the Acqui-
                 sition Credit Facility. In the first quarter of 2007, the remaining balance due on the Acquisition Credit Facility was repaid using cash
                 on hand and funds drawn from the revolving credit facility.
                     In September 2007, a subsidiary of the Company entered into a permanent financing arrangement for the Path 15 Project. The
                 financing is a $48 million, fully amortizing term loan with final maturity in 2027 and bears interest at a fixed rate of 7.9%. Principal
                 and interest payments are due in June and December of each year during the term of the loan. The term loan is secured by the
                 Company’s investment in the Path 15 Project and is non-recourse to the Company.

                 Information Regarding Guarantors
                 The Subordinated Notes and the Debentures are secured by a pledge of the Company’s membership interests in Holdings and are
                 guaranteed by Holdings and Teton Power Funding, LLC, Epsilon Power Funding, LLC, MP Power LLC, Teton East Coast Generation
                 LLC, Teton Fuels Mid-Georgia LLC, Teton Selkirk LLC, Badger Power Generation I LLC, Badger Power Generation II LLC, Baker
                 Lake Hydro LLC, Dade Investment, L.P., Geddes II Company LLC, Geddes Cogeneration Company LLC, MEP Rumford, LLC, NCP
                 Dade Power LLC, NCP Houston Power LLC, NCP Pasco LLC, NCP Perry LLC, Olympia Hydro LLC, Onondaga Cogeneration Lim-
                 ited Partnership, Orlando Power Generation I LLC, Orlando Power Generation II LLC, Stockton Cogen (II) LLC, Teton Operating
                 Services, LLC and Teton New Lake, LLC (the ‘‘Guarantors’’). The guarantee of Holdings is secured by a pledge of its membership
                 interests in Teton Power Funding, LLC and Epsilon Power Funding, LLC and the guarantees of certain of the Guarantors are secured
                 by pledges of the membership interests or other securities they hold in subsidiary entities subject to the provisions of agreements
                 governing or affecting interests in such subsidiaries which may restrict or prevent pledges in certain cases.
                     The consolidated financial statements of the Company include the consolidated financial results of the Company and its guaran-
                 tor and non-guarantor subsidiaries. Summary unaudited consolidated financial information of the Company, the Guarantors and the
                 non-guarantor subsidiaries of the Company as at and for the twelve-month period ended December 31, 2007 is presented in the table
                 below. The selected financial information for the Company and for the Guarantors includes certain investments in subsidiaries
                 accounted for on a cost basis and is therefore not presented in accordance with GAAP.




                                                                          AnnuAl RepoRt 2007       AtlAntic poweR coRpoRAtion                           27




Atlantic Power AR-jp.indd 27                                                                                                                          4/22/08 8:04:32 AM
                                                                              Atlantic power    guarantor non-guarantor      consolidation
                                                                                corporation    subsidiaries   subsidiaries    adjustments    consolidated

             Income Statement
             Project revenue                                                              –       25,523        280,669                 –      306,192
             Project expenses                                                             –        3,144        201,661                 –      204,805
             Project other income (expense)                                               –       60,173       (274,955)                –     (214,782)

             Project income (loss)                                                      –         82,552       (195,947)              –       (113,395)
             Dividends received                                                    67,251         99,325              –        (166,576)             –
             Administrative and other expenses                                    113,991        (30,860)           453               –         83,584

             Income (loss) before income taxes                                     (46,740)      212,737       (196,400)       (166,576)      (196,979)
             Income taxes                                                          (47,774)            –              –               –        (47,774)

             Income (loss)                                                           1,034       212,737       (196,400)       (166,576)      (149,205)

             Balance sheet
             Current assets                                                         10,870        63,938        108,125           (6,471)      176,462

             Investments in guarantor subsidiaries                                492,407              –              –        (492,407)             –
             Investment in non-guarantor subsidiaries                                   –        400,687              –        (400,687)             –
             Other non-current assets                                                   –         34,834        746,491         124,060        905,385

             Total non-current assets                                             492,407        435,521        746,491        (769,034)       905,385

             Total assets                                                         503,277        499,459        854,616        (775,505)     1,081,847

             Current liabilities                                                   36,191          4,221         63,572         (17,315)        86,669
             Non-current liabilities                                              488,215          2,831        390,357               –        881,403
             Shareholders’ equity                                                 (21,129)       492,407        400,687        (758,190)       113,775

             Total liabilities and shareholders’ equity                           503,277        499,459        854,616        (775,505)     1,081,847



             Contractual Obligations
             Contractual obligations of the Company as at the period ended December 31, 2007 are presented in the table below.

             Payments due by period                                                   total          2008     2009-2011       2012-2013      thereafter

             Long-term debt (A)                                                 $ 381,097      $ 36,925       $ 69,358        $ 53,635 $ 221,179
             Subordinated notes (B)                                               397,459             –              –               –   397,459
             Convertible debentures (C)                                            60,527             –         60,527               –         –

             Total contractual obligations                                      $ 839,083      $ 36,925       $ 129,885       $ 53,635 $ 618,638

             A. long-teRM debt
             Long-term debt represents the Company’s consolidated and proportionately consolidated share of Project long-term debt. The amount
             presented excludes the net unamortized purchase price adjustment of $13,482 related to the fair value of debt assumed in the Path 15
             acquisition. Project debt is non-recourse to the Company and is amortized during the term of the respective revenue generating con-
             tracts of the Projects. The range of interest rates on long-term Project debt at December 31, 2007 was 3.5% to 9.5%.

             b. SuboRdinAted noteS
             As of December 31, 2007, the Company had $397,459 outstanding principal amount of Subordinated Notes due 2016. The notes pay
             only interest at a rate of 11% until their maturity.




             28                           AtlAntic poweR coRpoRAtion    AnnuAl RepoRt 2007




Atlantic Power AR-jp.indd 28                                                                                                                              4/22/08 8:04:33 AM
                 c. conVeRtible debentuReS
                 The Debentures pay interest semi-annually on April 30 and October 31 each year, commencing on April 30, 2007. The Debentures
                 mature on October 31, 2011 and are convertible into approximately 80.6452 IPSs per Cdn$1,000 principal amount of Debentures, at
                 any time, at the option of the holder, representing a conversion price of Cdn$12.40 per IPS.

                 Project Contracts
                 Each Project typically has a set of contracts that includes the following obligations of the Project partnerships, all of which are non-
                 recourse to the Company. Therefore, specific contracts for individual Projects are not discussed in detail in the MD&A or included in
                 the Contractual Obligations table above. The following are general characteristics of the typical contracts at the Projects:

                 ·   PPAs generally allow Projects to pass through their fuel costs. See the table in “Project Portfolio” in this MD&A with respect to
                     off-takers and durations.
                 ·   Fuel supply agreements
                 ·   Fuel transportation agreements may incorporate capacity reservation/demand payments for natural gas, or shipping cost per ton
                     of coal
                 ·   Steam sales agreements typically have a tenor that matches that of the related PPA and are designed to meet regulatory requirements
                     for thermal load/efficiency at fossil fuel plants
                 ·   Operating and maintenance agreements provide for services provided by third parties or owners
                 ·   Long-term service agreements may be in place for gas or steam turbine inspections and overhauls
                 ·   Site lease agreements grant use of project land where Projects do not own the site.

                 Further information about the Projects’ agreements is contained in the Company’s annual information form dated March 26, 2008,
                 which is available on the SEDAR website at www.sedar.com.

                 financial Instrument Contracts
                 Please see the discussion in “Financial and Other Instruments” in this MD&A.

                 Credit facility
                 Please see the discussion in “Liquidity and Capital Resources” in this MD&A.

                 Management and Incentive fees
                 The Company pays a management fee under the management agreement executed in November 2004 among the Company, Hold-
                 ings and the Manager (the “Management Agreement”) that is subject to adjustment for acquisitions as agreed to by the manager,
                 Holdings and the Company as approved by the directors of the Company who are independent of the Manager and its affiliates and
                 associates, plus incentive fees, inflation adjustment and expenses. See “Related Party Transactions” in this MD&A for additional de-
                 tails. The Company paid the Manager $344 and $869 in aggregate base management and incentive fees, respectively, during the
                 twelve months ended December 31, 2007 and paid $340 and $554 in base management and incentive fees, respectively, in the com-
                 parable period in 2006.




                                                                         AnnuAl RepoRt 2007       AtlAntic poweR coRpoRAtion                           29




Atlantic Power AR-jp.indd 29                                                                                                                         4/22/08 8:04:33 AM
             Project-level debt
             Long-term debt, including the current portion, which is included on the Company’s consolidated balance sheet, is primarily comprised
             of debt at Projects and Project holding companies that are consolidated or proportionately consolidated in the Company’s financial
             statements. This project-level debt is serviced by the Projects before any cash distributions are made to the Company and is also non-
             recourse to the Company. The following table summarizes the maturities of project-level debt. The amounts presented represent the
             Company’s proportionate share of the non-recourse project-level debt balances at December 31, 2007 and exclude any purchase ac-
             counting adjustments recorded to adjust the debt to its fair value at the time the Project was acquired by the Company. Certain of the
             projects have more than one tranche of debt outstanding with different maturities, different interest rates and/or debt containing vari-
             able interest rates. The range of interest rates presented represents the rates in effect at December 31, 2007.

                                                                         total
                                                                   Remaining
                                                        Range of     principal
                                                   interest Rates Repayments            2008          2009          2010         2011      thereafter

             Consolidated and proportionately
                 consolidated Projects:
             Chambers                                3.5%-8.4%        143,725          9,635        10,531       12,051        12,794        98,774
             Orlando                                      6.7%          3,468          3,468             –            –             –             –
             Pasco                                   6.3%-9.1%         12,038         12,038             –            –             –             –
             Path 15                                 7.9%-9.0%        177,054          8,086         7,508        7,480         7,987       145,992
             Mid-Georgia                             7.6%-9.0%         42,307          2,646         2,891        3,161         3,562        30,048
             Topsham                                      9.5%          2,445          1,052         1,393            –             –             –

             Total consolidated and
                 proportionately
                 consolidated Projects                                381,097         39,626        22,323       22,692        24,343       274,814

             Equity and cost method Projects:
             Delta-Person                                 6.6%          14,722         1,028         1,098         1,147        1,220        10,229
             Selkirk                                 8.7%-9.0%          39,952         7,955         8,122         8,247       10,188         5,440
             Gregory                                6.0%-6.75%          20,748         1,542         1,668         1,757        1,901        13,881
             Total equity and cost
                 method Projects                                        75,422        10,524        10,888       11,151        13,309        29,550
             Total all Projects                                       456,519         47,450        33,211       33,843        37,652       304,422




             30                          AtlAntic poweR coRpoRAtion       AnnuAl RepoRt 2007




Atlantic Power AR-jp.indd 30                                                                                                                            4/22/08 8:04:33 AM
                 Project Portfolio
                 The following table outlines the Company’s portfolio of power generating assets as of March 26, 2008, including its interest in each
                 facility. Management believes the portfolio is well diversified based on electricity and steam buyers, regulatory jurisdictions and
                 regional power pools, thereby mitigating exposure to market, regulatory or environmental conditions specific to any single region.

                                                                                                                                                                                 Off-taker
                                                                                total      Ownership Acct’g              net        Electricity                      PPA        s&P Credit
                 Project name           location            fuel type            MW          Interest 1 tmt 2            MW     3   Off-taker                      Expiry          Rating
                 Badger Creek           California          Natural gas            46           50.0%             p       23        Pacific Gas & Electric          2011              bbb+
                 Chambers               New Jersey          Coal                 262            40.0%             p       89 4      Atlantic City Electric          2024                bbb
                                                                                                                          16        DuPont                          2024                  A
                 Delta-Person           New Mexico          Natural gas          132            40.0% 5           e       53        Public Service of               2020                bbb
                                                                                                                                    New Mexico
                 Gregory                Texas               Natural gas          400            17.1%         cost        59        Constellation Energy            2008              bbb+
                                                                                                                          59        Fortis 12                       2013                A-
                                                                                                                           9        Sherwin Alumina                 2020               n/R
                 Koma Kulshan           Washington          Hydro                  13           49.8%             p         6       Puget Sound Energy              2037               bbb-
                 Lake                   Florida             Natural gas          121          100.0%              c      121        Progress Energy Florida         2013              bbb+
                 Mid-Georgia            Georgia             Natural gas          308            50.0%             p      154        Georgia Power                   2028                    A
                 Onondaga               New York            Natural gas            91         100.0%              c       91        Niagara Mohawk 6                2008                   A-
                 Orlando                Florida             Natural gas          126            50.0%             p       44        Progress Energy Florida         2023              bbb+
                                                                                                                          19        Reedy Creek                     2013               AAA
                                                                                                                                    Improvement District
                 Pasco                  Florida             Natural gas          121            99.8%             p      121        TECO                            2018              bbb+
                                                                                                                                    Progress Energy Florida         2008              bbb+
                 Path 15                California          Transmission         n/A 10       100.0%              c      n/A 9      California Utilities via          n/A               bbb
                                                                                                                                    CAISO 9                                             to A 11
                 Rumford                Maine               Coal/biomass           85           23.5% 5           e       20        Rumford Paper Co. 7             2009                 n/R
                 Selkirk                New York            Natural gas                                  5
                                                                                 345            18.5%         cost        15        Niagara Mohawk                  2008                    A
                                                                                                                          49        Consolidated Edison             2014                    A
                 Stockton               California          Coal                   55           50.0%             p       24        Pacific Gas & Electric          2009              bbb+
                                                                                                                           3        Corn Products Int’l             2009              bbb-
                 Topsham 8              Maine               Hydro                  14           50.0%             p         7       Central Maine Power             2011              bbb+
                 1  except as otherwise noted, economic interest represents the percentage ownership interest in each project held indirectly by the company.
                 2  Accounting treatment: c – consolidated; p – proportionate consolidation; e – equity method; cost – cost method.
                 3  Represents the interest of the company in each project’s electricity generation capacity based on the company’s economic interest.
                 4  includes separate power sales agreement in which the project and Atlantic city electric (“Ace”) share profits on merchant sales of electricity not purchased by Ace
                    under the base ppA.
                 5 Represents the company’s estimate of its share of the cash flow from the project.
                 6 A swap agreement with niagara Mohawk power corporation has replaced the onondaga ppA.
                 7 For further information, see the discussion of the interim financial consolidation agreement with the former Mead/westvaco paper mill (now owned by newpage)
                    under “Recent transactions” in this Md&A.
                 8 the company owns its interest in this project as a lessor.
                 9 path 15 is an 84-mile, 500-kilovolt transmission line in california. the project is a FeRc-regulated asset with a FeRc-approved regulatory life of 30 years, through 2034.
                 10 california utilities pay transmission Access charges (“tAcs”) to california independent System operator (“cAiSo”), which allocates the payments among owners of
                    transmission and transmission System Rights, such as path 15, in accordance with the project’s FeRc-approved annual revenue requirement.
                 11 the largest payers of tAcs supporting path 15’s annual revenue requirement and their S&p credit ratings are pg&e (bbb+), Socal ed (bbb+) and Sdg&e (A).
                    cAiSo imposes minimum credit quality requirements of A or better for all participants unless collateral is posted per cAiSo imposed schedule.
                 12 ppA with Fortis energy Marketing and trading gp commences in 2009 at the expiry of the ppA with constellation energy.




                                                                                          AnnuAl RepoRt 2007             AtlAntic poweR coRpoRAtion                                         31




Atlantic Power AR-jp.indd 31                                                                                                                                                              4/22/08 8:04:33 AM
             Capital Expenditures
             Capital expenditures for the Projects are generally made at the Project level using Project cash flows and Project reserves. Therefore,
             the distributions that the Company receives from the Projects are made net of capital expenditures required at the Projects and the
             Company generally does not need to inject funds into the Projects for ongoing capital expenditure, except in the case of occasional
             opportunities for the Company to invest in discretionary expansions or upgrades that are accretive to cash flow. The Projects in which
             the Company has investments generally consist of large capital assets that have established commercial operations. Ongoing capital
             expenditures for assets of this nature are generally not significant because most major expenditures relate to planned repairs and
             maintenance and are expensed when incurred.
                In the fourth quarter of 2007, the Company completed an upgrade of the gas turbines at the Lake Project that is expected to
             increase both its efficiency and output by approximately 4% and 10%, respectively. The net cost of the upgrade was approximately
             $9.3 million, of which $7.8 million was funded in the third quarter of 2007 with $2.6 million of cash on hand at the Project and a
             $5.2 million capital contribution from the Company. The completion of the upgrade in the fourth quarter was paid by the Lake Project
             with a $1.5 million capital contribution from the Company. In addition, the turbines that were replaced were sold in December 2007 for
             cash proceeds of $3.1 million. A loss in the amount of approximately $8.6 million was recorded on the sale of the replaced turbines.

             Related Party transactions
             The Manager has been engaged under the Management Agreement to provide certain management and administrative services to
             the Company, for which it is paid: (1) a base management fee ($344 for 2007), which is adjusted annually for inflation and when ac-
             quisitions increase the scope of the Manager’s responsibilities under the agreement; (2) a reimbursement of costs; and (3) an incentive
             fee equal to 25% of the excess in distributions paid during the year to IPS holders and Former Investors above Cdn$1.00 per IPS. The
             Management Agreement has an initial term of 20 years expiring in 2024. In addition, the Path 15 Project directly pays the Manager an
             annual fee of $266,000, which is subject to adjustment for inflation.
                 The Manager receives administrative and office support services from ArcLight under a management support agreement executed
             in November 2004 among the Manager, ArcLight and the Company. This agreement also requires the ArcLight Funds and their
             affiliates to give the Manager the opportunity to pursue, on behalf of the Company, investment opportunities that do not fit within the
             investment guidelines for the ArcLight Funds or other investment funds managed by ArcLight or its affiliates.
                 The Manager is owned indirectly by subsidiaries of the ArcLight Funds which, in conjunction with a subsidiary of Caithness,
             owned 41.9% of Holdings’ common membership interest immediately after the IPO, but reduced their interest to 29.9% in October
             2005 and further reduced their interest to approximately 14% in October 2006. In February 2007, the Company acquired all of the
             remaining interest of the Former Investors in Holdings.

             financial and Other Instruments
             The Company uses forward foreign currency contracts to manage its exposure to changes in foreign exchange rates, as the Company
             earns its income principally in the United States but has the obligation to make distributions predominantly in Canadian dollars.
             Since its inception, the Company has established a hedging strategy for the purpose of reinforcing the long-term sustainability of its
             distributions. The Company has executed this strategy by entering into forward contracts to purchase Canadian dollars at fixed rates
             of exchange sufficient to make monthly distributions through December 2011 at the current annual distribution level of Cdn$1.06 per
             IPS to IPS holders, as well as interest payments on the Subordinated Notes and Convertible Debentures. It is the Company’s intention
             to periodically consider whether to extend the length of these forward contracts. Changes in the fair market value of the Company’s
             forward contracts partially offset exchange gains or losses on the U.S. dollar equivalent of the Company’s Canadian dollar obligations.




             32                         AtlAntic poweR coRpoRAtion       AnnuAl RepoRt 2007




Atlantic Power AR-jp.indd 32                                                                                                                       4/22/08 8:04:33 AM
                    The following table summarizes the Company’s forward foreign currency contracts with monthly settlement terms as of Decem-
                 ber 31, 2007:

                 notional Monthly Amounts
                                                                                                                      Sell u.S.    buy cdn.        Average
                 Period                                                                                                 dollars      dollars           rate

                 Current–2009                                                                                           4,811         5,800        1.2055
                 2010                                                                                                   5,167         5,800        1.1225
                 2011                                                                                                   5,494         5,800        1.0557


                 In addition to the forward contracts in the table above that settle on a monthly basis, the Company has executed forward contracts to pur-
                 chase Canadian dollars at fixed rates of exchange sufficient to make semi-annual payments on the Debentures. The contracts provide for
                 the purchase of Cdn$1.9 million in April and in October of 2008 through 2011 at a rate of 1.1075 Canadian dollars per U.S. dollar.
                     The foreign exchange forward contracts are carried at estimated fair value based on quoted market value. Mark-to-market adjust-
                 ments of the foreign currency forward contracts are reflected in foreign exchange gains and losses. At December 31, 2007, the fair
                 value of the foreign exchange forward contracts was included in current portion of derivative instruments liability and derivative in-
                 struments asset in the amount of $977 and $35,566 respectively.
                     Certain of the Projects also use interest rate swaps to manage fluctuations in interest rates and natural gas forwards or swaps to
                 minimize the effects on cash flow of changing natural gas prices, which are a significant component of Project expenses. In addition,
                 other Projects have entered into natural gas contracts with pricing terms designed to minimize the impact of gas price volatility on
                 operating margins.
                     The Company has a swap agreement (the “Indexed Swap”) at the Onondaga Project under which it receives monthly payments based
                 upon the differential between an indexed contract price and a market reference price for electricity through June 2008. In order to lock
                 in favorable gas, power, and capacity pricing under the Indexed Swap, the Company has entered into an Indexed Swap Hedge.
                     The values of all the financial instruments described above are subject to changes in market prices and none has been designated
                 as a cash flow hedge for accounting purposes. Management monitors these risks and the market values of these financial instruments
                 and periodically reviews its risk management strategies as market conditions change.

                 Accounting Estimates
                 The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of
                 assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements and the reported
                 amounts of revenues and expenses during the period. Actual results could differ from those estimates. During the periods presented,
                 management has made a number of estimates and valuation assumptions, including the fair values of acquired assets, the useful lives
                 and recoverability of property, plant and equipment and PPAs, the recoverability of equity investments, the recoverability of future tax
                 assets and the fair value of financial instruments and derivatives.
                     The Company has acquired the majority of its long-term assets through acquisitions. In applying the purchase method of account-
                 ing, the Company is required to estimate the fair value of the assets acquired including the property, plant and equipment and intan-
                 gible assets. The determination of these fair values is complex and involves making significant judgments.
                     Revenue recognition is based on contractual capacity, energy and firm transmission sales by the Projects to electricity and steam
                 buyers and, for one Project which has fluctuating rates over time, the average rate over the term of the PPA is used for revenue with
                 the difference between cash received and revenue recognized as deferred revenue. The revenue at Path 15 is based on a regulatory
                 revenue requirement, with any timing differences between receipt of cash and the regulatory revenue requirement recorded as
                 deferred revenue.




                                                                          AnnuAl RepoRt 2007        AtlAntic poweR coRpoRAtion                           33




Atlantic Power AR-jp.indd 33                                                                                                                           4/22/08 8:04:33 AM
                 Fixed asset valuations of power plants are based on depreciated replacement cost. Valuations of PPAs and fuel supply agreements
             are based on the incremental net present value of cash flows provided by the agreement as compared to the merchant value of the
             plant. The Company typically uses outside consultants to determine the merchant value of a facility. On an ongoing basis, the Com-
             pany monitors the performance of the facilities to determine if any recoverability issues exist or if any change in the useful life of the
             facility is required.
                 The future tax asset valuation allowance has been determined pursuant to the provisions of CICA Handbook Section 3465, “In-
             come Taxes,” including the Company’s estimation of future taxable income, where necessary, and is adequate to reduce the total fu-
             ture tax asset to an amount that will more likely than not be realized. The Company has provided a valuation allowance to reduce net
             future tax assets to an amount expected to be recovered in the foreseeable future.
                 The fair values of financial instruments and derivatives such as the forward foreign currency contracts, interest rate swaps and
             natural gas swaps are typically based on market quotes. The Company also has an Indexed Swap and related hedge agreement and,
             pursuant to the adoption of Section 3855, has adopted fair value accounting for the Chambers PPA as of January 1, 2007. See changes
             in “Accounting Policies” in this MD&A for additional information. The fair values of these agreements are based on estimated future
             cash flows and take into account certain assumptions, including forecasts of future energy prices, inflation rates, discount rates and
             credit risk. Energy prices can be volatile and other assumptions can change from period to period. These factors can create significant
             fluctuations in the estimated fair values of these agreements.
                 For additional information regarding accounting policies and estimates, please see Note 1 to the Company’s audited consolidated
             financial statements for the twelve months ended December 31, 2007.

             Commitments and Contingencies
             From time to time, the Company and its subsidiaries and Projects are parties to disputes and litigation that arise in the normal course
             of business. The Company assesses its exposure to these matters and records estimated loss contingencies when a loss is likely and can
             be reasonably estimated. There were no matters pending as of December 31, 2007 that are expected to have a material impact on the
             Company’s financial position or results of operations.

             Outstanding share data
             The Company had 61,470,500 IPSs outstanding at December 31, 2007 compared to 44,339,500 IPSs outstanding at December 31,
             2006. The Debentures are convertible to approximately 80.6452 IPSs per Cdn$1,000 principal amount of Debentures, at any time, at
             the option of the holder, representing a conversion price of Cdn$12.40 per IPS. As of December 31, 2007, 4,838,712 IPSs would be
             required to be issued if all of the outstanding Debentures were converted to IPSs. Unvested notional units outstanding under the LTIP
             would represent approximately 180,000 IPSs if vested at December 31, 2007.

             Outlook
             In order to maintain stable distributions and provide long-term growth, the Company will continue to focus on enhancing the operat-
             ing and financial performance of existing Projects and pursuing accretive acquisitions in the North American market.
                 The existing portfolio has many attributes that allow it to support the stability of cash flows desired: diversity of fuel types, geogra-
             phy, state and federal regulatory bodies, off takers and equipment manufacturers. The combination of long-term energy sales and fuel
             purchase agreements are designed to both provide a solid credit foundation to the business model and to mitigate impacts to operating
             margins of changes in commodity costs. The Company continually analyzes and implements organic opportunities to improve oper-
             ating performance both with accretive capital expenditures and through revisions and/or extensions to key contracts.
                 Acquisition opportunities are being reviewed to locate appropriate risk-adjusted returns with cash flow and diversification charac-
             teristics that further strengthen the existing portfolio. These opportunities may range from portions of individual projects to companies
             with an attractive mix of existing assets and late-stage development projects. Availability of debt and equity capital currently appears
             to be generally available at leverage levels that we find appropriate for the Company, despite recent volatility in capital markets. The
             secondary market for these acquisition opportunities remains very active and the Company continues to see opportunities from many
             sources in our extensive industry network.




             34                           AtlAntic poweR coRpoRAtion        AnnuAl RepoRt 2007




Atlantic Power AR-jp.indd 34                                                                                                                             4/22/08 8:04:33 AM
                     While the portfolio’s structure significantly mitigates commodity price movements, we still carefully review potential impacts from
                 regional price projections and subscribe to a highly respected third party for its commodity price updates and trend analysis. Recently,
                 significant short- and longer-term upward pressure on coal prices has been analyzed for operating margin impacts. Generally, our
                 Florida gas projects benefit from increasing coal prices, as the coal-indexed PPA energy payments see greater upward movement than
                 the coal-indexed component in gas purchase agreements. The Chambers Project has a very effective pass-through of coal price move-
                 ments between the fuel cost and electricity revenue sides of its margin. Stockton sees a negative impact from increased coal and pe-
                 troleum coke prices, but also is testing the potential use of biomass fuel in the plant’s overall fuel mix in order to somewhat mitigate
                 that effect. Overall, the portfolio has a net positive impact from increased coal price projections.
                     Natural gas price movements also have varied effects on different projects. For example, higher projected prices have a negative
                 impact on a project such as Lake, whose current PPA with more coal-indexed pricing expires in 2009. This possible impact is some-
                 what mitigated by higher projected coal prices discussed above. On the other hand, Chambers benefits from higher natural gas prices
                 because of the opportunity to sell increasing portions of its output to the spot market under the profit-sharing structure of its PSA with
                 its PPA off-taker. Overall, management believes that increasing gas prices have a roughly neutral net impact on the portfolio’s mar-
                 gins.

                 Risk factors
                 Atlantic Power’s future performance and its ability to generate sufficient cash flow to meet its monthly cash distributions to holders of
                 IPSs, and the Common Shares and Subordinated Notes represented thereby, and to holders of Debentures, is subject to a number of
                 risks and uncertainties. Any of these risks and uncertainties could have a material adverse effect on the Company’s results of operations,
                 business prospects, financial condition, the cash available to the Company for distribution to holders of IPSs, Common Shares, Subor-
                 dinated Notes or Debentures or on the market price or value of IPSs, Common Shares or Subordinated Notes. In addition to the sum-
                 mary of certain risk factors below and other information contained or incorporated by reference in this MD&A, “Risk Factors” in the
                 Company’s annual information form dated March 26, 2008 should be given careful consideration and is incorporated by reference
                 herein. Additional risks and uncertainties not currently known to the Company or management of the Manager, or that the Company
                 or management of the Manager currently consider immaterial, may also impair operations of the Company. If any such risks actually
                 occur, the business, financial condition, or liquidity and results of operations of the Company, and the ability of the Company to make
                 distributions on the IPSs, the Common Shares and Subordinated Notes represented thereby, and the Debentures, could be materially
                 adversely affected. The Company’s annual information form is available on the SEDAR website at www.sedar.com.

                 The following is a summary of the primary risks facing the Company, with further discussion of risk factors found in the Company’s
                 Annual Information Form dated March 26, 2008.

                 ReVenue MAy be Reduced upon expiRAtion oR teRMinAtion oF ppAS
                 Power generated by the Projects, in most cases, is sold under PPAs that expire at various times. In addition, these PPAs may be subject
                 to termination in certain circumstances, including default by the Project owner or operator. When a PPA expires or is terminated, it
                 is possible that the price received by the relevant Project for power under subsequent arrangements may be reduced significantly. It is
                 possible that subsequent power purchase arrangements may not be available at prices that permit the operation of the Project on a
                 profitable basis. If this occurs, the affected Project may temporarily or permanently cease operations.

                 the pRojectS depend on theiR electRicity And theRMAl eneRgy cuStoMeRS
                 Each Project relies on one or more PPAs, steam sales agreements or other agreements with one or more utilities or other customers for
                 a substantial portion of its revenue. The amount of cash available for distribution to holders of IPSs, Common Shares and Subordi-
                 nated Notes is highly dependent upon customers under such agreements fulfilling their contractual obligations. There is no assurance
                 that these customers will perform their obligations or make required payments to the Project Operating Entities.




                                                                          AnnuAl RepoRt 2007        AtlAntic poweR coRpoRAtion                           35




Atlantic Power AR-jp.indd 35                                                                                                                           4/22/08 8:04:33 AM
             ceRtAin pRojectS ARe expoSed to FluctuAtionS in the pRice oF electRicity And FuelS
             While a majority of the off-takers of the Projects are contractually obligated to purchase electricity output under long-term PPAs, and
             a portion of the revenues under the contracts is typically a relatively fixed capacity payment, variable payments made for energy pro-
             duced will depend on escalators based on fluctuations in electricity and/or fuel prices and possibly inflation, which may not effec-
             tively hedge the Project’s operating margins relative to changes in variable inputs. In addition, should any of the long-term PPAs expire
             or terminate, the Manager or the relevant Project operator will be required to either negotiate new PPAs or sell into the electricity
             wholesale market, in which case the changed price relationships between electricity revenues and variable inputs may result in oper-
             ating margin reduction or elimination.

             pRedicting pRoject cASh FlowS oVeR the long teRM iS diFFicult
             Due to the many uncertainties described in this risk factors section that could materially affect future revenues or expenses, it can be
             difficult to make long-term projections of the Company’s operating margins.

             opeRAtionS ARe Subject to the pRoViSionS oF VARiouS eneRgy lAwS And RegulAtionS
             Generally, in the United States, the Company’s projects are subject to regulation by the FERC regarding the terms and conditions of
             wholesale service and rates, as well as by state agencies regarding PPAs entered into by Qualifying Facility (“QF”) projects and the sit-
             ing of the generation facilities. The majority of the Company’s generation is sold by QF projects under PPAs that required approval by
             state authorities.
                 On August 8, 2005, the Energy Policy Act of 2005 (“EPAct 2005”) was enacted, which removed certain regulatory constraints on in-
             vestment in utility power producers by repealing the Public Utility Holding Company Act of 1935 (“PUHCA 1935”) and enacting the
             Public Utility Holding Company Act of 2005 (“PUHCA 2005”). EPAct 2005 also limited the requirement that electric utilities buy elec-
             tricity from QFs to certain markets that lack competitive characteristics. Finally, EPAct 2005 amended and expanded the reach of
             FERC’s corporate merger approval authority under section 203 of the Federal Power Act (“FPA”). Over the past several months, FERC
             has issued final rulemakings implementing the provisions of EPAct 2005.
                 If any Project that is a QF were to lose its status as a QF, then such Project may no longer be entitled to exemption from provisions
             of PUHCA 2005 or from provisions of the FPA and state law and regulations. Such Project might be able to obtain exempt wholesale
             generator status to maintain its exemption from the provisions of PUHCA 2005; however, there can be no assurance provided that the
             Company’s Projects will be able to obtain such exemptions. Loss of QF status could trigger defaults under covenants to maintain QF
             status in the PPAs, steam sales agreements and Project-level debt agreements and could result, if not cured within allowed cure peri-
             ods; in termination of agreements, penalties or acceleration of indebtedness under such agreements, plus interest.
                 The Projects would also have to file with FERC for market-based rates or file for acceptance for filing of the rates set forth in the
             applicable PPA. Such rates would then be subject to initial and potentially subsequent reviews by FERC under the FPA, which could
             result in reductions in the rates.
                 In connection with its first transmission investment, Path 15, the Company will be required to have its Path 15 operating subsidiary
             make a triennial filing with the FERC for review of certain aspects of its rate recovery, such as the allowed return on equity. The first
             such filing was made in December 2007 for the 2008-2010 rate recovery period. While the Company believes that Path 15’s current
             rate recovery assumptions are supported both by other recent analogous FERC precedents and recent FERC policy statements, it is
             possible that such rate reviews would result in a lower allowed return on equity or other changes that could have a material effect on
             the project’s revenues.
                 EPAct 2005 provides incentives for various forms of electric generation technologies, which may subsidize our competitors. In ad-
             dition, EPAct 2005 requires the FERC to select an industry self-regulatory organization that will impose mandatory reliability rules and
             standards. Among other things, FERC’s rules implementing these provisions allow such reliability organizations to impose sanctions
             on generators that violate their new reliability rules.
                 The Company’s projects require licenses, permits and approvals that can be in addition to any required environmental permits.
             No assurance can be provided that we will be able to obtain, comply with and renew as required all necessary licenses, permits and
             approvals for these facilities. If we cannot comply with and renew as required all applicable regulations, our business, results of
             operations and financial condition could be adversely affected.



             36                          AtlAntic poweR coRpoRAtion       AnnuAl RepoRt 2007




Atlantic Power AR-jp.indd 36                                                                                                                            4/22/08 8:04:34 AM
                    We cannot provide assurance that the introductions of new laws, or other future regulatory developments, will not have a material
                 adverse impact on our business, operations or financial condition.

                 pRojectS ARe Subject to SigniFicAnt enViRonMentAl And otheR RegulAtionS
                 The Projects are subject to numerous and significant federal, state and local laws, including statutes, regulations, by-laws, guidelines,
                 policies, directives and other requirements governing or relating to, among other things: air emissions; discharges into water; the stor-
                 age, handling, use, transportation and distribution of dangerous goods and hazardous and residual materials, such as chemicals; the
                 prevention of releases of hazardous materials into the environment; the prevention, presence and remediation of hazardous materials
                 in soil and groundwater, both on and off site; land use and zoning matters; and workers’ health and safety matters. As such, the opera-
                 tion of the Projects carries an inherent risk of environmental, health and safety liabilities (including potential civil actions, compli-
                 ance or remediation orders, fines and other penalties), and may result in the Projects being involved from time to time in administra-
                 tive and judicial proceedings relating to such matters.
                     Environmental laws and regulations have generally become more stringent over time, and this trend may continue. In particular,
                 the U.S. Environmental Protection Agency, or EPA, has recently promulgated regulations under the Clean Air Interstate Rule (“CAIR”)
                 requiring additional reductions in nitrogen oxides, or NOX, and sulfur dioxide, or SO2, emissions, commencing in 2009 and 2010,
                 respectively, and has also promulgated regulations requiring reductions in mercury emissions from coal-fired electric generating units,
                 commencing in 2010 with more substantial reductions in 2018. Moreover, certain of the states in which we operate have promulgated
                 air pollution control regulations which are more stringent than existing and proposed federal regulations.
                     Ongoing public concerns about emissions of carbon dioxide and other greenhouse gases (“GHG”) from power plants have resulted
                 in proposed laws and regulations at the federal, state and regional levels that, if they were to take effect substantially as proposed,
                 would likely apply to Project operations. Specifically, there is a proposed multi-state carbon cap-and-trade program known as the Re-
                 gional Greenhouse Gas Initiative, or RGGI, which would apply to the Company’s fossil-fueled facilities in the Northeast, primarily
                 Chambers and Rumford, which utilize coal. Model rules for implementation of RGGI have already been proposed by several North-
                 eastern states and currently are in the public comment stage. The State of Florida is conducting stakeholder meetings as part of the
                 process of developing greenhouse gas contract regulations.
                     Under the CAIR program, regulations are under consideration that would modify the existing program of distribution of NOX al-
                 locations at no cost to generators, to an auction-based program for all allocations.
                     In 2006, the State of California passed legislation initiating two programs to control/reduce the creation of GHG. These two laws,
                 more commonly known as Assembly Bill (“AB”) 32 and Senate Bill (“SB”) 1368, are currently in the regulatory rulemaking phase that
                 will involve public comment and negotiations over specific provisions.
                     Under AB 32 (the California Global Warming Act of 2006) the California Air Resources Board (“CARB”) is required to adopt a
                 GHG emissions cap on all major sources (not limited to the electric sector). In order to do so, regulations will be adopted for the
                 mandatory reporting and verification of GHG emissions and to reduce statewide emissions of GHG to 1990 levels by 2020. This will
                 most likely require that electric generating facilities reduce their emissions of GHG or pay for the right to emit by the implementation
                 date of January 1, 2012. The program has yet to be finalized and the decision as to whether allocations will be distributed or auctioned
                 will be determined in the rulemaking process that is currently underway. This could affect the Company’s coal-fired Stockton Project
                 and to a much lesser extent, if at all, its Badger Creek Project.
                     SB 1368 added the requirement that the California Energy Commission (“CEC”), in consultation with the California Public
                 Utilities Commission (“CPUC”) and the CARB, establish a GHG emission performance standard and implement regulations for
                 power purchase agreements that exceed five years entered into prospectively by publicly owned electric utilities. The legislation di-
                 rects the CEC to establish the performance standard as one not exceeding the rate of GHG emitted per megawatt-hour associated with
                 combined-cycle, gas turbine baseload generation. Provisions are under consideration in the rulemaking to allow facilities that have
                 higher CO2 emissions to be able to negotiate PPAs for up to a five-year period or sell power to entities not subject to SB 1368. This
                 statute may limit Stockton’s ability to extend its PPA with Pacific Gas & Electric (which currently expires in early 2009) beyond the
                 five-year limit.
                     In addition to the regional initiatives, legislation for the regulation of GHG has been introduced at the federal level and if passed,
                 may eventually override the regional efforts with a national cap-and-trade program.



                                                                          AnnuAl RepoRt 2007        AtlAntic poweR coRpoRAtion                           37




Atlantic Power AR-jp.indd 37                                                                                                                           4/22/08 8:04:34 AM
                 Significant expenditures may be required for either capital expenditures or the purchase of allowances under any or all of these
             programs to keep the Projects’ facilities compliant with environmental laws and regulations. The Projects’ PPAs do not allow for the
             pass through of emissions allowance or emission reduction capex costs. If it is not economical to make those expenditures, it may be
             necessary to retire or mothball facilities, or restrict or modify our operations to comply with more stringent standards.
                 The Projects have obtained environmental permits and other approvals that are required for their operations. Compliance with
             applicable laws and future changes to them is material to the Company’s businesses. Although the Manager believes the operations
             of the Projects are currently in material compliance with applicable environmental laws, licences, permits and other authorizations
             required for the operation of the Projects and although there are environmental monitoring and reporting systems in place with re-
             spect to all the Projects, there is no guarantee that more stringent laws will not be imposed, that there will not be more stringent en-
             forcement of applicable laws or that such systems may not fail, which may result in material expenditures. Failure by the Projects to
             comply with any environmental, health or safety requirements, or increases in the cost of such compliance, including as a result of
             unanticipated liabilities or expenditures for investigation, assessment, remediation or prevention, could result in additional expense,
             capital expenditures, restrictions and delays in the Projects’ activities, the extent of which cannot be predicted.

             the pRojectS depend on SupplieRS undeR Fuel Supply AgReeMentS And incReASeS in Fuel coStS
             MAy AdVeRSely AFFect the pRoFitAbility oF the pRojectS
             Revenues in respect of the Projects may be affected by the availability, or lack therof, of a stable supply of fuel at reasonable prices. To
             the extent possible, the Projects attempt to match fuel costs to PPA energy payments. To the extent that fuel costs are not matched
             directly to PPA energy payments, increases in fuel costs may adversely affect the profitability of the Projects.
                 The amount of energy generated at the Projects is highly dependent on suppliers under certain fuel supply and transportation
             agreements fulfilling their contractual obligations. The loss of significant fuel supply agreements or an inability or failure by any sup-
             plier to meet its contractual commitments may adversely affect cash distributions by the Company. The amount of energy generated
             at the Projects is also dependent upon the availability of natural gas, coal, oil or biomass. There can be no assurance that the long-term
             availability of such resources will remain unchanged.
                 Upon the expiry or termination of existing fuel supply or transportation agreements, the Manager or Project operators will have to
             renegotiate these agreements or may need to source fuel from other suppliers. There can be no assurance that the Manager or Project
             operators will be able to renegotiate these agreements or enter into new agreements on similar terms. Furthermore, there can be no
             assurance as to availability of the supply or pricing of fuel under new arrangements. The gas supply contract expiration in 2009 at the
             Company’s Lake Project is discussed in “Outlook” in this MD&A.

             u.S. FedeRAl incoMe tAx RiSkS
             There can be no assurance that U.S. federal income tax laws and IRS administrative policies respecting the U.S. federal income tax
             consequences generally applicable to a holder of Common Shares and Subordinated Notes, as represented by IPSs, will not be changed
             in a manner which adversely affects Non-U.S. Holders.
                 There is no authority that directly addresses the tax treatment of securities similar to the Subordinated Notes as part of a unit that
             includes common shares of the Company. In light of this absence of direct authority, it cannot be concluded with certainty that the
             Subordinated Notes will be treated as debt for U.S. federal income tax purposes, and, although the Company intends to take the posi-
             tion that the Subordinated Notes are debt for U.S. federal income tax purposes, there can be no assurance that this position will not be
             challenged by the IRS. If such a challenge were sustained, interest payments on the Subordinated Notes would be re-characterized as
             non-deductible distributions with respect to the Company’s equity, and the Company’s net taxable income and thus its U.S. federal
             income tax liability would be materially increased. As a result, the Company’s after-tax cash flow would be reduced and the Company’s
             ability to make interest payments on Subordinated Notes and distributions with respect to Common Shares could be materially and
             adversely impacted.




             38                          AtlAntic poweR coRpoRAtion         AnnuAl RepoRt 2007




Atlantic Power AR-jp.indd 38                                                                                                                            4/22/08 8:04:34 AM
                 Recent cAnAdiAn FedeRAl incoMe tAx pRopoSAlS
                 On December 21, 2006, the Department of Finance (Canada) released for public comment draft legislation significantly modifying the
                 income tax rules applicable to certain publicly listed trusts and partnerships. An investment in IPSs does not involve a publicly listed
                 trust or partnership but an investment in IPSs shares certain characteristics with investments in publicly listed trust or partnership enti-
                 ties that are the subject of the draft legislation and the proposals first announced on October 31, 2006. The proposals of October 31, 2006
                 indicated that although the details outlined therein reflected the then present intentions of the government, any aspect of these mea-
                 sures may be changed accordingly and possibly with retroactive effect if there should emerge structures or transactions that are clearly
                 devised to frustrate the policy objectives underlying the proposals. Management believes that the proposed rules do not apply to the
                 Company and do not alter the tax consequences of an investment in Common Shares and Subordinated Notes represented by IPSs.
                 However, there is no assurance that the December 21, 2006 draft legislation and, more generally, Canadian federal income tax laws and
                 administrative policies will not be changed in a manner that adversely affects the holders of Common Shares and Subordinated Notes
                 represented by IPSs.
                     On June 22, 2007, Bill C-52, which significantly modifies the Canadian federal income tax rules applicable to certain publicly listed
                 trusts and partnerships, received Royal Assent. An investment in IPSs does not involve a publicly listed trust or partnership, but an in-
                 vestment in IPSs shares certain characteristics with investments in publicly listed trust or partnership entities that are the subject of the
                 new legislation. The proposals of October 31, 2006 first announcing the proposed rules indicated that although the details outlined
                 therein reflected the then present intentions of the government, any aspect of these measures may be changed accordingly and possibly
                 with retroactive effect if there should emerge structures or transactions that are clearly devised to frustrate the policy objectives underly-
                 ing the proposals. Management believes that the proposed rules do not apply to the Company and do not alter the tax consequences of
                 an investment in Common Shares and Subordinated Notes represented by IPSs. However, there is no assurance that Canadian federal
                 income tax laws and administrative policies will not be changed in a manner that adversely affects the holders of Common shares and
                 Subordinated Notes represented by IPSs.

                 disclosure Controls and Procedures
                 Based on the requirements of Multilateral Instrument 52-109, “Certification of Disclosure in Issuers’ Annual and Interim Filings,” the
                 Chief Executive Officer and Chief Financial Officer of the Manager have evaluated the effectiveness of the Company’s disclosure
                 controls and procedures (as defined in Multilateral Instrument 52-109) as of December 31, 2007. Based on that evaluation, the Chief
                 Executive Officer and Chief Financial Officer of the Manager have concluded that the Company’s disclosure controls and procedures
                 were effective as of December 31, 2007 to provide reasonable assurance that material information relating to the Company would be
                 made known to them by others within the Company.
                    During the fourth quarter of 2007, the Company began a conversion to an improved general ledger accounting system. As of
                 December 31, 2007, the accounting system conversion was partially complete and, as a result, internal controls over financial report-
                 ing were changed to reflect the portions of the conversion that were complete and the impact that those completed portions of the
                 conversion had on our 2007 year-end financial close and reporting process. Management expects to complete the accounting system
                 conversion for use in the first quarter of 2008 financial reporting process. As this conversion is completed, additional changes will be
                 made to internal controls over financial reporting. Management believes that the accounting system conversion represents an im-
                 provement in internal control over financial reporting.

                 Additional Information
                 Additional information is available on the Company’s website at www.atlanticpowercorporation.com, or under the Company’s profile
                 on the SEDAR website at www.sedar.com.
                    The following tables present unaudited non-GAAP supplementary financial information provided for informational purposes.
                 Please see “Non-GAAP Financial Measures” and “Results of Operations for the Three and Twelve-Month Periods Ended Decem-
                 ber 31, 2007 – Supplementary Financial Information” in this MD&A for additional details about the supplementary information.




                                                                            AnnuAl RepoRt 2007        AtlAntic poweR coRpoRAtion                            39




Atlantic Power AR-jp.indd 39                                                                                                                               4/22/08 8:04:34 AM
             Project Adjusted EBItdA1 (in thousands of u.s. dollars)                                three months ended     twelve months ended
                                                                                                          december 31             december 31
             (unaudited)                                                                            2007          2006      2007          2006
             Adjusted EBITDA1 from consolidated and proportionately consolidated Projects
             Badger Creek                                                                           1,314       1,290      4,109        4,188
             Chambers                                                                               4,962       3,684     28,028       23,984
             Koma Kulshan                                                                             323         107      1,196          758
             Lake                                                                                   6,633       6,612     28,042       28,970
             Mid-Georgia                                                                              982         688      5,587        4,461
             Onondaga                                                                               4,681       6,244     21,966       23,500
             Orlando                                                                                2,214       2,361      8,336       10,040
             Pasco                                                                                  3,633       3,226     14,225        9,761
             Stockton                                                                                 968       1,014      3,505        1,915
             Topsham                                                                                  470         812      2,031        2,523
             Path 15                                                                                8,175       7,815     31,564        9,270
             Other                                                                                    248         164        987          645

             Total adjusted EBITDA1 from consolidated and proportionately
                 consolidated Projects                                                             34,603      34,017     149,576     120,015
             Amortization                                                                           9,792      11,965      48,188      40,676
             Interest expense, net                                                                  8,868       6,298      26,975      16,795
             Change in the fair value of derivative instruments                                    38,730       5,306     128,377      18,233
             Other expense                                                                         77,934           –      67,897      (2,499)
             Earnings (loss) from consolidated and proportionately consolidated Projects         (100,721)     10,448    (121,861)     46,810

             Adjusted EBITDA1 from equity and cost method Projects
             Delta-Person                                                                             558         529      2,255        2,457
             Gregory2                                                                                   –       2,176          –        6,066
             Jamaica                                                                                    –         741      2,381        3,432
             Rumford                                                                                  655         237      2,585        1,479
             Selkirk2                                                                               4,821       5,443     10,350       16,838
             Other                                                                                     16        (136)      (205)        (229)

             Total adjusted EBITDA1 from equity and cost method Projects                            6,051       8,990     17,366       30,043
             Amortization                                                                             463       3,369      1,948       13,061
             Interest expense, net                                                                    223       1,488      1,172        5,892
             Other Expense 3                                                                            –         (72)    (5,115)         170
             Income tax                                                                                73          48        665          482

             Equity income from equity and cost investments                                         5,292       4,157       8,466      10,438

             Project income
             Total adjusted EBITDA1 from all Projects                                             40,654       43,007    166,942      150,058
             Amortization                                                                         10,255       15,334     50,136       53,737
             Interest expense, net                                                                 9,091        7,786     28,148       22,687
             Other (income) expense                                                               77,936          (72)    73,011       (2,329)
             Change in the fair value of derivative instruments                                   38,728        5,306    128,376       18,233
             Income taxes                                                                             73           48        665          482

             Project income (loss) as reported in the statement of income                         (95,430)     14,605    (113,395)     57,248

             Earnings (loss) from consolidated and proportionately consolidated Projects         100,722       10,448    (121,861)     46,810
             Income from equity and cost method Projects                                           5,292        4,157       8,466      10,438

             Project income (loss) as reported in the statement of income                         95,430       14,605    (113,395)     57,248


             40                          AtlAntic poweR coRpoRAtion         AnnuAl RepoRt 2007




Atlantic Power AR-jp.indd 40                                                                                                                    4/22/08 8:04:34 AM
                 1    Adjusted ebitdA is not a measure recognized under gAAp and does not have a standardized meaning prescribed by gAAp. Adjusted ebitdA is defined as earnings
                      before interest, taxes, depreciation, amortization (including non-cash impairment charges) and changes in fair value of derivative instruments. Management uses
                      adjusted ebitdA at the projects to provide comparative information about project performance. See “non-gAAp Financial Measures” in this Md&A.
                 2    effective january 1, 2007, the gregory and Selkirk projects are accounted for under the cost method of accounting. See “changes in Accounting policies” in this
                      Md&A for additional information.
                 3    Sale of the company’s equity investment in the jamaica project for $6.2 million closed on october 30, 2007. other expense includes an impairment in the amount of
                      $5.1 million recorded in the second quarter of 2007.



                 Reconciliation of Project distributions (in thousands of u.s. dollars)

                                                                                                                                                         change in
                                                                                                    Repayment            interest           capital        working            project
                 For the twelve months ended                                          Adjusted          of long-        expense,            expen-      capital and      distribution
                 December 31, 2007 (unaudited)                                        ebitdAA        term debt                net           ditures     other items         received

                 Consolidated and proportionately
                     consolidated Projects
                 Badger Creek                                                            4,109                 –               43             (192)            (310)           3,650
                 Chambers                                                               28,028            (9,331)         (11,549)            (316)            (264)           6,568
                 Koma Kulshan                                                            1,196              (925)             (24)            (271)              24                –
                 Lake                                                                   28,042              (574)             106          (13,879)          11,755           25,450
                 Mid-Georgia                                                             5,587            (2,411)          (3,589)               –              413                –
                 Onondaga                                                               21,966                 –               54                –           (3,070)          18,950
                 Orlando                                                                 8,336            (3,980)            (122)            (132)            (853)           3,249
                 Pasco                                                                  14,225            (7,226)            (395)            (836)           6,267           12,035
                 Stockton                                                                3,505                 –               60             (391)             327            3,501
                 Topsham                                                                 2,031            (1,625)            (338)               –              (68)               –
                 Path 15                                                                31,564           (11,842)         (11,217)               –           (3,213)           5,292
                 Other                                                                     987                 –               (5)               –             (982)               –

                 Total consolidated and proportionately
                     consolidated Projects                                             149,576           (37,914)         (26,976)         (16,016)          10,026           78,695

                 Equity and cost method Projects
                 Delta-Person                                                            2,255              (935)             (991)               –             762            1,091
                 Jamaica                                                                 2,381              (813)             (239)            (149)          5,015            6,195
                 Rumford                                                                 2,585                 –                32             (291)            475            2,801
                 Selkirk                                                                10,350                 –                 –                –               –           10,350
                 Other                                                                    (204)                –                26                –             371              193

                 Total equity and cost method Projects                                  17,366            (1,748)          (1,172)             (440)          6,623           20,630

                 Total all Projects                                                    166,942           (39,662)         (28,148)         (16,456)          16,649           99,325

                 A    Adjusted ebitdA is not a measure recognized under gAAp and does not have a standardized meaning prescribed by gAAp. Adjusted ebitdA is defined as earnings
                      before interest, taxes, depreciation, amortization (including non-cash impairment charges) and changes in fair value of derivative instruments. Management uses
                      adjusted ebitdA at the projects to provide comparative information about project performance. See non-gAAp Financial Measures in this Md&A.




                                                                                      AnnuAl RepoRt 2007            AtlAntic poweR coRpoRAtion                                      41




Atlantic Power AR-jp.indd 41                                                                                                                                                      4/22/08 8:04:34 AM
             MAnAGEMEnt’s REsPOnsIBIlIty fOR fInAnCIAl stAtEMEnts
             to the Shareholders of Atlantic power corporation



             The accompanying consolidated financial statements of Atlantic Power Corporation, the management discussion and analysis and
             the information included in this annual report have been prepared by Atlantic Power Management, LLC, the Corporation’s manage-
             ment, which is responsible for their consistency, integrity and objectivity. Management is also responsible for ensuring that the con-
             solidated financial statements are prepared and presented in accordance with Canadian generally accepted accounting principles,
             which include amounts that are based on estimates and judgments. To fulfill these responsibilities, management maintains appro-
             priate internal control systems and policies and procedures to provide reasonable assurance that assets are safeguarded and financial
             records are reliable and form a proper basis for the preparation of financial statements.
                 KPMG LLP, the Corporation’s independent auditors, are responsible for auditing the consolidated financial statements in accor-
             dance with Canadian generally accepted accounting principles, and have expressed their opinion on the consolidated financial state-
             ments in this report. Their report, as auditors, is set forth below.
                 The Corporation’s Board of Directors is responsible for ensuring that management fulfills its responsibilities for financial report-
             ing and internal controls. The Board of Directors carries out this responsibility through its Audit Committee, which meets regu-
             larly with management and the independent auditors. The members of the Audit Committee are independent of management.
             The consolidated financial statements have been reviewed and approved by the Board of Directors and its Audit Committee.
             The independent auditors have direct and full access to the Audit Committee and the Board of Directors.




             Barry Welch                 Patrick Welch
             president and ceo           chief financial officer




             AudItORs’ REPORt tO thE shAREhOldERs
             We have audited the consolidated balance sheets of Atlantic Power Corporation as at December 31, 2007 and 2006 and the con-
             solidated statements of loss and comprehensive loss and deficit and cash flows for the years then ended. These financial statements
             are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements
             based on our audits.
                 We conducted our audits in accordance with Canadian generally accepted auditing standards.Those standards require that we
             plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement.
             An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit
             also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the
             overall financial statement presentation.
                 In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the Com-
             pany as at December 31, 2007 and 2006 and the results of its operations and its cash flows for the years then ended in accordance
             with Canadian generally accepted accounting principles.




             Chartered Accountants, licensed Public Accountants
             toronto, canada march 26, 2008




             42                          AtlAntic poweR coRpoRAtion       AnnuAl RepoRt 2007




Atlantic Power AR-jp.indd 42                                                                                                                        4/22/08 8:04:37 AM
                 Consolidated Balance sheets (in thousands of u.s. dollars)

                 December 31, 2007 and 2006                                                                              2007             2006

                 Assets
                 Current assets:
                 Cash and cash equivalents                                                                     $       55,990     $     68,627
                 Restricted cash                                                                                       38,304          111,866
                 Current portion of derivative instruments asset                                                       23,753           33,016
                 Accounts receivable                                                                                   38,134           36,055
                 Prepayments, supplies and other                                                                       10,020            9,179
                 Income tax recoverable                                                                                10,261           12,415

                                                                                                                     176,462           271,158

                 Property, plant and equipment (Note 5)                                                              413,040           411,180
                 Transmission system rights (Note 6)                                                                 210,972           218,846
                 Long-term investments (Note 7)                                                                       64,815            76,973
                 Other intangible assets                                                                             125,976           141,695
                 Goodwill (Note 8)                                                                                     8,918            79,158
                 Long-term portion of derivative instruments asset                                                    79,611            17,108
                 Deferred financing costs                                                                                  –            10,990
                 Other assets                                                                                          2,053             5,588

                                                                                                               $   1,081,847      $   1,232,696

                 Liabilities and Shareholders’ Equity
                 Current liabilities:
                 Accounts payable and accrued liabilities                                                      $       32,886     $     30,833
                 Current portion of long-term and short-term debt                                                      36,926           86,168
                 Current portion of derivative instruments liability                                                    7,822           11,612
                 Interest payable on Subordinated Notes                                                                 4,271            3,873
                 Distribution payable, non-controlling interest (Note 19)                                                   –              669
                 Non-controlling interest liability                                                                         –           76,888
                 Dividends payable                                                                                      2,127            1,872
                 Other                                                                                                  2,637           10,329

                                                                                                                       86,669          222,244

                 Long-term debt (Note 11)                                                                            356,188           342,412
                 Subordinated Notes (Note 12)                                                                        386,092           336,840
                 Convertible Debentures (Note 13)                                                                     59,912            51,484
                 Derivative instruments liability                                                                      8,044             7,377
                 Future tax liability                                                                                 46,914            17,101
                 Other liabilities                                                                                    24,253            91,838

                 Shareholders’ equity:
                 Common stock (Note 14)                                                                               216,636          216,636
                 Deficit                                                                                             (102,861)         (53,236)

                                                                                                                     113,775           163,400
                 Commitments and contingencies (Note 20)
                 Subsequent events (Note 21)
                                                                                                               $   1,081,847      $   1,232,696
                 See accompanying notes to consolidated financial statements.

                 On behalf of the Board:




                 Ken hartwick                     Irving Gerstein
                 Director                         Director
                                                                                AnnuAl RepoRt 2007   AtlAntic poweR coRpoRAtion              43




Atlantic Power AR-jp.indd 43                                                                                                               4/22/08 8:04:37 AM
             Consolidated statements of loss, Comprehensive loss and deficit (in thousands of u.s. dollars, except per share amounts)

             Years ended December 31, 2007 and 2006                                                        2007                         2006

             Project revenue:
                Energy sales                                                                      $     268,605             $     247,368
                Transmission services                                                                    34,524                    10,090
                Other                                                                                     3,063                     3,633

                                                                                                        306,192                   261,091

             Project expenses:
                Fuel                                                                                    109,217                    92,150
                Operations and maintenance                                                               38,467                    42,176
                Project operator fees and expenses                                                        8,933                     6,751
                Depreciation and amortization                                                            48,188                    40,676

                                                                                                        204,805                   181,753

             Project other income (expense):
                Change in fair value of derivative instruments (Note 16)                               (128,377)                   (18,233)
                Income from long-term investments                                                         8,466                     10,438
                Goodwill impairment (Note 8)                                                            (71,726)                         –
                Interest, net                                                                           (26,975)                   (16,795)

                  Other project income                                                                    3,830                         2,499

                                                                                                       (214,782)                   (22,091)

             Project income (loss)                                                                     (113,395)                   57,247

             Administrative and other expenses:
               Management fees and administration                                                         8,185                     6,367
               Interest, net                                                                             44,282                    31,589
               Distribution, non-controlling interest (Note 19)                                               –                    15,107
               Loss from change in non-controlling interest liability (Note 19)                               –                     3,691
               Foreign exchange loss                                                                     30,142                     1,295
               Other expenses                                                                               975                     1,029

                                                                                                         83,584                    59,078


             Loss before income taxes                                                                  (196,979)                    (1,831)

             Income tax expense (benefit) (Note 15)                                                     (47,774)                         577


             Net loss and comprehensive loss                                                           (149,205)                    (2,408)
             Deficit, beginning of year                                                                 (53,236)                   (33,843)
             Cumulative effect of adopting new accounting policies (Note 2)                             124,245                          –

             Dividends                                                                                  (24,665)                   (16,985)

             Deficit, end of year                                                                 $    (102,861)            $      (53,236)


             Loss per share (Note 18):
                Basic and diluted                                                                 $        (2.43)           $           (0.05)
             See accompanying notes to consolidated financial statements.




             44                                AtlAntic poweR coRpoRAtion   AnnuAl RepoRt 2007




Atlantic Power AR-jp.indd 44                                                                                                                   4/22/08 8:04:37 AM
                 Consolidated statements of Cash flows (in thousands of u.s. dollars)

                 Years ended December 31, 2007 and 2006                                                                  2007           2006

                 Cash flows from (used in) operating activities:
                    Net loss                                                                                   $     (149,205)    $    (2,408)
                    Items not involving cash:
                         Depreciation and amortization                                                                47,602           41,705
                         Earnings from equity investments                                                              1,898          (10,438)
                         Goodwill impairment                                                                          71,726                –
                         Loss on disposal of assets                                                                    8,923              550
                         Change in fair value of non-controlling interest                                                  –            3,691
                         Change in gas transportation contract commitment (Note 9)                                   (23,573)          (6,594)
                         Unrealized foreign exchange loss                                                             37,716            5,220
                         Change in deferred revenue                                                                     (838)             389
                         Change in fair value of derivative instruments                                              131,089           16,463
                         Future income taxes                                                                         (51,747)               –
                    Change in non-cash operating working capital                                                       8,225           (2,857)
                    Distributions from equity investments                                                              4,085           11,800

                                                                                                                       85,901         57,521

                 Cash flows from (used in) financing activities:
                    Proceeds from issuance of common stock                                                                  –          69,150
                    Proceeds from issuance of subordinated notes                                                            –          87,050
                    Proceeds from issuance of project-level debt                                                       48,056          88,000
                    Proceeds from convertible debentures                                                                    –          52,780
                    Proceeds from revolving credit facility borrowings                                                 31,000               –
                    Common stock issuance costs                                                                             –          (3,383)
                    Deferred financing costs                                                                                –          (4,690)
                    Dividends paid                                                                                    (24,342)        (16,371)
                    Repayment of revolving credit facility borrowings                                                 (31,000)        (10,000)
                    Repayment of long-term debt                                                                       (88,581)        (64,185)
                    Repayment of obligations to non-controlling interest                                              (76,888)        (87,287)
                    Cash proceeds from escrow used for redemption                                                      74,433         (74,433)

                                                                                                                      (67,322)        36,631

                 Cash flows used in investing activities:
                    Proceeds from sale of equity investment                                                             6,195               –
                    Acquisition, net of cash acquired (Note 3)                                                        (23,213)        (65,743)
                    Purchase of property, plant and equipment                                                         (17,271)         (3,640)
                    Proceeds from sale of property, plant and equipment                                                 3,073               –

                                                                                                                      (31,216)        (69,383)


                 Increase (decrease) in cash and cash equivalents                                                     (12,637)        24,769
                 Cash and cash equivalents, beginning of period                                                        68,627         43,858
                 Cash and cash equivalents, end of period                                                      $       55,990     $   68,627

                 Supplemental cash flow information:
                    Interest paid                                                                              $       72,248     $   47,381
                 See accompanying notes to consolidated financial statements.




                                                                                AnnuAl RepoRt 2007   AtlAntic poweR coRpoRAtion            45




Atlantic Power AR-jp.indd 45                                                                                                              4/22/08 8:04:37 AM
             nOtEs tO COnsOlIdAtEd fInAnCIAl stAtEMEnts
             years ended december 31, 2007 and 2006 (in thousands of u.S. dollars, unless otherwise noted, and except per share amounts)



             Atlantic Power Corporation (the “Company”) is a corporation established under the laws of the Province of Ontario on June 18, 2004
             and continued to the Province of British Columbia on July 8, 2005. The Company issued income participating securities (“IPSs”) for
             cash pursuant to an initial public offering on November 18, 2004. Prior to November 18, 2004, the Company was inactive.
                 The Company currently owns, through its wholly owned subsidiary Atlantic Power Holdings, LLC (“Holdings”) indirect inter-
             ests in 14 power generation projects and one transmission line located in the United States of America (collectively, the “Proj-
             ects”). Four of the Projects are wholly owned subsidiaries of the Company: Onondaga Cogeneration Limited Partnership (“Onon-
             daga”), Lake Cogen Ltd., Pasco Cogen, Ltd. and Atlantic Holdings Path 15, LLC (“Path 15”).



             1. significant accounting policies
             A. bASiS oF conSolidAtion
             The consolidated financial statements of the Company are prepared in accordance with Canadian generally accepted accounting
             principles and include the consolidated accounts of all of its subsidiaries. The Company applies the equity method of accounting
             for investments in which it has significant influence but does not control and applies the cost method of accounting for invest-
             ments in which it does not have significant influence. The Company proportionately consolidates investments in which it has
             joint control. The Company eliminates intercompany accounts and transactions.

             b. cASh And cASh eQuiVAlentS
             Cash and cash equivalents include cash deposited at banks and highly liquid investments with original maturities of three months
             or less.

             c. ReStRicted cASh
             Restricted cash represents cash and cash equivalents that are maintained by the Projects to support payments for major mainte-
             nance costs and meet project-level contractual debt obligations. In addition, at December 31, 2006, $74,433 of restricted cash was
             held in escrow for the February 2007 transaction in which the Company acquired all of the remaining interests in Atlantic Hold-
             ings from the Former Investors.

             d. pRopeRty, plAnt And eQuipMent
             Property, plant and equipment are stated at cost, net of accumulated depreciation. Depreciation is provided on a straight-line basis
             over the estimated useful life of the related asset. The useful lives of facilities range from three to 60 years. The weighted average
             useful life is 23 years.

             e. tRAnSMiSSion SySteM RightS
             Transmission system rights are an intangible asset that represents the long-term right to approximately 72% of the capacity of the
             Path 15 transmission line in California. Transmission system rights are amortized on a straight-line basis over 30 years, the regula-
             tory life of the project.

             F. goodwill
             Goodwill is the residual amount that results when the purchase price of an acquired business exceeds the sum of the amounts
             allocated to the assets acquired, less liabilities assumed, based on their fair values. Goodwill is allocated, as of the date of the busi-
             ness combination, to the Company’s reporting units that are expected to benefit from the synergies of the business combination.
                 Goodwill is not amortized and is tested for impairment annually, or more frequently if events or changes in circumstances
             indicate that the asset might be impaired. The impairment test is carried out in two steps. In the first step, the carrying amount of
             the reporting unit is compared with its fair value. When the fair value of a reporting unit exceeds its carrying amount, goodwill of
             the reporting unit is considered not to be impaired and the second step of the impairment test is unnecessary.
             The second step is carried out when the carrying amount of a reporting unit exceeds its fair value, in which case, the implied fair
             value of the reporting unit’s goodwill is compared with its carrying amount to measure the amount of the impairment loss, if any.



             46                          AtlAntic poweR coRpoRAtion        AnnuAl RepoRt 2007




Atlantic Power AR-jp.indd 46                                                                                                                          4/22/08 8:04:37 AM
                 The implied fair value of goodwill is determined in the same manner as the value of goodwill in a business combination described
                 in the preceding paragraph, using the fair value of the reporting unit as if it were the purchase price. When the carrying amount
                 of reporting unit goodwill exceeds the implied fair value of the goodwill, an impairment loss is recognized in an amount equal to
                 the excess and is presented as a separate line item in the consolidated statement of loss, comprehensive loss and deficit.

                 g. otheR intAngible ASSetS
                 Other intangible assets include power purchase contracts and fuel supply agreements.
                     Power purchase contracts are valued at the time of acquisition based on the rates received under the power purchase contracts
                 relative to projected market rates. The balances are presented net of accumulated amortization. Amortization is recorded on a
                 straight-line basis over the remaining term of the contract. The amortization period ranges from one to 16 years. The weighted
                 average period of amortization is 13 years.
                     Fuel supply agreements are valued at the time of acquisition based on the rates projected to be paid under the fuel supply
                 agreement relative to projected market rates. The amortization period ranges from one to 16 years. The weighted average period
                 of amortization is nine years.

                 h. ReVenue Recognition
                 The Company recognizes energy sales revenue when electricity and steam are delivered under the terms of the related contracts.
                 If the power purchase contract contains capacity payments that fluctuate over the term of the contract, the Company recognizes
                 revenue based on the estimated average rate for the duration of the contract with the difference between cash received and reve-
                 nue recognized reflected as deferred revenue.
                     Transmission services revenue is recognized as transmission services are provided. The annual revenue requirement for trans-
                 mission services is regulated by the Federal Energy Regulatory Commission (“FERC”) and is established through a rate-making
                 process that occurs every three years. When actual cash receipts from transmission services revenue are different than the regu-
                 lated revenue requirement because of timing differences, the over or under collections are deferred until the timing differences
                 reverse in future periods.
                     Onondaga recognizes revenue as the swap agreements it has entered settle monthly, net of any change in fair value on these
                 swap agreements (Note 16).

                 i. incoMe tAxeS
                 Income taxes are accounted for using the asset and liability method. Future tax assets and liabilities are recognized for the future
                 tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and
                 their respective tax bases. Future tax assets and liabilities are measured using enacted or substantively enacted tax rates expected
                 to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on
                 future tax assets and liabilities of a change in tax rates is recognized in income in the year that includes the date of enactment or
                 substantive enactment.
                     A valuation allowance is recorded against future tax assets to the extent that it is more likely than not that the future tax asset
                 will not be realized.

                 j. gAS tRAnSpoRtAtion contRAct liAbility
                 All of the Company’s gas transportation costs are expensed as incurred.

                 k. Accounting FoR deRiVAtiVeS
                 The following policy was effective through December 31, 2006. On January 1, 2007, the Company adopted new accounting policies
                 for derivatives and other financial instruments (see Note 2(a) for additional detail). The Company uses financial derivative agree-
                 ments in the form of interest rate swaps and foreign exchange forward contracts to manage its current and anticipated exposure to
                 fluctuations in interest rates and foreign currency exchange rates. On occasion, the Company has also entered into natural gas
                 supply contracts and natural gas forwards or swaps to minimize the effects of the price volatility of natural gas which is a major



                                                                         AnnuAl RepoRt 2007       AtlAntic poweR coRpoRAtion                          47




Atlantic Power AR-jp.indd 47                                                                                                                        4/22/08 8:04:37 AM
             production cost. The Company does not enter into financial derivative agreements for trading or speculative purposes; however,
             not all derivatives qualify for hedge accounting.
                 Derivative financial instruments not designated as a hedge are measured at fair value with changes in fair value recorded in the
             consolidated statements of operations and deficit. Derivative financial instruments not designated as hedges are the foreign cur-
             rency forward contracts, the Indexed Swap and the Indexed Swap Hedge agreements and certain interest rate swaps. Mark-to-
             market adjustments of the foreign currency forward contracts are reflected in foreign exchange loss, Indexed Swap and Indexed
             Swap Hedge agreements are netted and reflected as indexed swaps under project revenue and adjustments of interest rate swaps
             are reflected in project interest expense in the consolidated statements of operations and deficit.
                 Effectiveness tests are performed to evaluate hedge effectiveness at inception and on an ongoing basis, both retroactively and
             prospectively. Unrealized gains or losses on the interest rate swaps designated within a designated hedging relationship are not
             recognized.
                 Gains and losses on natural gas forward contracts and swaps that are designated as a hedge of fuel costs are recognized in in-
             come as actual fuel costs are recognized.
                 Natural gas supply contracts in the normal course of business, in which the Company takes possession of natural gas, are
             treated as executory contracts.

             l. ASSet RetiReMent obligAtionS
             The fair value of estimated asset retirement obligations is recognized in the consolidated balance sheets when identified and a
             reasonable estimate of fair value can be made. The asset retirement cost, equal to the estimated fair value of the asset retirement
             obligation, is capitalized as part of the cost of the related long-lived asset. The asset retirement costs are depreciated over the asset’s
             estimated useful life and included in depreciation expense on the consolidated statements of loss, comprehensive loss and deficit.
             Increases in the asset retirement obligation resulting from the passage of time are recorded as accretion of asset retirement obliga-
             tion in the consolidated statements of loss, comprehensive loss and deficit. Actual expenditures incurred are charged against the
             accumulated obligation.

             M. iMpAiRMent oF long-liVed ASSetS
             Long-lived assets, such as property, plant and equipment, transmission system rights and other intangible assets subject to depre-
             ciation and amortization, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying
             amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carry-
             ing amount of an asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount
             of an asset exceeds its estimated future cash flows, an impairment charge is recognized in the amount by which the carrying
             amount of the asset exceeds its fair value.

             n. FoReign cuRRency tRAnSlAtion
             The Company’s functional currency and reporting currency is the United States dollar. The functional currency of the Compa-
             ny’s subsidiaries and other investments is the United States dollar. Monetary assets and liabilities denominated in Canadian dollars
             are translated into United States dollars using the rate of exchange in effect at the end of the year. All transactions denominated
             in Canadian dollars are translated into United States dollars at the exchange rates in effect at the transaction date. Foreign cur-
             rency translation gains and losses are reflected in the consolidated statements of loss, comprehensive loss and deficit.

             o. uSe oF eStiMAteS
             The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts
             of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported
             amounts of revenue and expenses during the year. Actual results could differ from those estimates. During the periods presented,
             management has made a number of estimates and valuation assumptions, including the fair values of acquired assets, the useful
             lives and recoverability of property, plant and equipment and power purchase contracts, the recoverability of long-term invest-
             ments, the recoverability of future tax assets, and the fair value of financial instruments and derivatives. These estimates and



             48                          AtlAntic poweR coRpoRAtion        AnnuAl RepoRt 2007




Atlantic Power AR-jp.indd 48                                                                                                                           4/22/08 8:04:37 AM
                 valuation assumptions are based on present conditions and management’s planned course of action, as well as assumptions about
                 future business and economic conditions. Should the underlying valuation assumptions and estimates change, the recorded
                 amounts could change by a material amount.

                 2. Changes in accounting policies
                 A. FinAnciAl inStRuMentS
                 On January 1, 2007, the Company adopted the new recommendations of Section 3855, “Financial Instruments – Recognition and
                 Measurement,” Section 3865, “Hedges,” Section 1530, “Comprehensive Income” and Section 3251, “Equity,” from the CICA
                 Handbook. The retroactive application of the new standards does not require restatement of prior periods. This change in ac-
                 counting policy will result in significantly increased variability in net income but will not impact cash flows.
                     Section 3855, Financial Instruments – Recognition and Measurement, establishes standards for recognizing and measuring
                 financial assets, financial liabilities and non-financial derivatives. The standard requires that financial assets, financial liabilities
                 and non-financial derivatives be recognized on the consolidated balance sheets.
                     Under this standard, all financial instruments are required to be measured at fair value on initial recognition. Measurement in
                 subsequent periods is based on the classification of the financial instrument. Financial assets and financial liabilities held for trad-
                 ing are measured at fair value with changes in fair value reported in earnings. Financial assets held to maturity, loans and receiv-
                 ables and financial liabilities other than those held for trading are measured at amortized cost using the effective interest method.
                 Available-for-sale financial assets and liabilities are measured at fair value with changes in fair value reported in other comprehen-
                 sive income until the financial instrument is de-recognized, at which time cumulative gain or loss previously recognized in ac-
                 cumulated other comprehensive income is recognized in net income for the period.
                     Transaction costs are expensed as incurred for financial instruments classified or designated as held-for-trading. For other finan-
                 cial instruments, transaction costs are capitalized on initial recognition.
                     Derivative instruments are recorded on the consolidated balance sheets at fair value unless the derivative instrument is a con-
                 tract to buy or sell a non-financial item in accordance with the Company’s expected purchase, sale or usage requirements, referred
                 to as a “normal purchase or normal sale.” Changes in the fair values of derivative instruments are recognized in earnings unless
                 the derivative instrument qualifies and is designated as an effective cash flow hedge or a normal purchase or normal sale. Normal
                 purchases and normal sales are exempt from the application of the standard and are accounted for as executory contracts. Chang-
                 es in the fair value of a derivative instrument designated as an effective cash flow hedge are recorded in accumulated other com-
                 prehensive income, a component of equity.
                     The Company has classified accounts payable, long-term debt (including current portion), Subordinated Notes and Convert-
                 ible Debentures as other financial liabilities and measures these liabilities at amortized cost.
                     Other significant accounting implications of Section 3855 include the use of the effective interest method of amortization for
                 any transaction costs or fees, premiums or discounts earned or incurred for financial instruments measured at amortized cost.

                 Chambers power purchase agreement
                 As a result of adopting the requirements of Section 3855, the Company determined that the power purchase agreement (“PPA”) at
                 the proportionately consolidated Chambers Project is a derivative instrument. The PPA does not qualify for exclusion from Section
                 3855 and has not been designated as a hedge. Accordingly, the PPA has been recorded at its fair value in the consolidated balance
                 sheets and changes in the fair value are recognized in change in fair value of derivative instruments in the consolidated statements
                 of loss, comprehensive loss and deficit.
                     The fair value of the PPA is measured by comparing the net present value of the cash flows expected to be received under the
                 terms of the PPA to the net present value of the cash flows that would be received if the same volumes were sold at projected mar-
                 ket power prices over the term of the contract expiring in 2024. Accordingly, periodic changes to the fair value of the PPA reflect
                 changes in market conditions and do not directly impact the amount of cash flow the Chambers Project will receive under the
                 terms of the PPA.
                     The impact of this change was to decrease the opening deficit as of January 1, 2007 by $212,183 to reflect the fair value of the
                 PPA in the amount of $155,762 and the removal from the consolidated balance sheet of the unamortized cost of the PPA in the



                                                                          AnnuAl RepoRt 2007       AtlAntic poweR coRpoRAtion                           49




Atlantic Power AR-jp.indd 49                                                                                                                          4/22/08 8:04:38 AM
             amount of $56,421 (previously presented in other liabilities) on that date. In addition, a future tax liability and corresponding in-
             crease in deficit of $87,938 was recorded as a result of the adjustment to opening deficit as of January 1, 2007 described above.
                As of December 31, 2007, the fair value of the PPA in the amount of $49,652 was reflected in the consolidated balance sheets as
             $5,607 included in current portion of derivative instruments asset and $44,045 included in derivative instruments asset. The
             change in fair value of the PPA for the period ended December 31, 2007 is recorded as a loss in the amount of $106,110 in the
             consolidated statements of loss, comprehensive loss and deficit. The change in fair value of the PPA also resulted in reductions in
             the future tax liability during the period ended December 31, 2007 of $42,445, which was recorded as a credit to income taxes in
             the consolidated statements of loss, comprehensive loss and deficit.

             Other financial instruments
             Deferred financing costs in the amount of $10,990 as of January 1, 2007 have been reclassified and presented together with the
             respective debt instrument to which the costs relate and are now being amortized using the effective interest method.
                 In addition, the Company determined that the Subordinated Notes contained an embedded derivative, namely the early re-
             demption option, which is recorded at fair value. The value at December 31, 2007 was nil.
                 See Note 16 for information about other financial instruments that were not impacted by the adoption of Section 3855.
                 Section 3865, “Hedges,” specifies the criteria that must be satisfied in order for hedge accounting to be applied and the ac-
             counting for fair value hedges and cash flow hedges. Hedge accounting is discontinued prospectively when the derivative no
             longer qualifies as an effective hedge, or the derivative is terminated or sold, or upon the sale of the hedged item. As of December
             31, 2007, the Company has not designated any derivative instruments as a cash flow hedge or a fair value hedge.
                 Section 1530, “Comprehensive Income,” establishes standards for the reporting and display of comprehensive income, which
             consists of net income and other comprehensive income (“OCI”). OCI is presented as a component of equity and is comprised of
             certain changes in shareholders’ equity that are not recognized in net income. Examples of items included in OCI include the
             effective portion of the changes in fair value of derivative instruments designated as a cash flow hedge and changes in the cur-
             rency translation adjustment relating to self-sustaining foreign operations. As of December 31, 2007, the Company does not have
             any items recorded in OCI.
                 Section 3251, “Equity,” establishes standards for the presentation of equity and changes in equity during the reporting period,
             in addition to the requirement in Section 1530. The adoption of Section 3251 had no impact on the Company’s consolidated fi-
             nancial statements.

             b. long-teRM incentiVe plAn
             The officers and other employees of Atlantic Power Management, LLC (the “Manager”) are eligible to participate in the Com-
             pany’s Long-Term Incentive Plan (“LTIP”) that was implemented in 2007, as determined by the independent members of the Board
             of Directors of the Company. On an annual basis, the Board of Directors establishes awards that are based on the cash flow per-
             formance of the Company in the most recently completed year, each participant’s base salary and the market price of the IPSs at
             the award date. Awards are granted in the form of notional units that have economic characteristics similar to the Company’s IPSs.
             Notional units vest over a three-year period and are redeemed in a combination of cash and IPSs upon vesting.
                 Unvested notional awards are entitled to receive distributions equal to the distributions per public IPS during the vesting period
             in the form of additional notional units. Unvested awards are subject to forfeiture if the participant is not an employee of the Man-
             ager at the vesting date or if the Company does not meet certain ongoing cash flow performance targets.
                 Compensation expense related to awards granted to participants in the LTIP is recorded over the vesting period based on the
             estimated fair value of the award at each balance sheet date. Fair value of the awards is determined by projecting the total number
             of notional units that will vest in future periods, including distributions received on notional units during the vesting period, and
             applying the current market price per IPS to the projected number of notional units that will vest. Forfeitures are recorded as they
             occur and are not included in the estimated fair value of the awards. The aggregate number of IPSs which may be issued from
             treasury under the LTIP is limited to one million.




             50                         AtlAntic poweR coRpoRAtion       AnnuAl RepoRt 2007




Atlantic Power AR-jp.indd 50                                                                                                                      4/22/08 8:04:38 AM
                 c. long-teRM inVeStMentS
                 During the first quarter of 2007, management reviewed its accounting for its investments in the Gregory and the Selkirk Projects
                 that have historically been accounted for using the equity method. Based on a current assessment, management has determined
                 that as of January 1, 2007, the cost method of accounting is appropriate for these investments. Beginning January 1, 2007, the Com-
                 pany has prospectively changed its accounting for its investments in the Gregory and Selkirk Projects from the equity method to
                 the cost method of accounting. Under the cost method, investment income is recorded to the extent of distributions received from
                 the Projects. This change in accounting policy does not impact cash flow.
                    The Company’s investments in the Delta-Person and Rumford Projects continue to be recorded under the equity method of
                 accounting and are also included in long-term investments in the consolidated balance sheets.

                 Recently issued accounting standards
                 a. Financial instruments – presentation
                 The CICA issued Handbook Section 3863, “Financial Instruments – Presentation,” which replaces CICA Handbook Section 3861,
                 to enhance financial statement users’ understanding of the significance of financial instruments to an entity’s financial position,
                 performance and cash flows. This section establishes the standards for presentation of financial instruments and non-financial
                 derivatives. It deals with the classification of financial instruments, from the perspective of the issuer, between liabilities and eq-
                 uity, the classification of related interest, dividends, gains and losses, and the circumstances in which financial assets and financial
                 liabilities are offset. This standard harmonizes disclosure with International Financial Reporting Standards and applies to interim
                 and annual financial statements relating to fiscal years beginning on or after October 1, 2007. The Company is currently evaluating
                 the impact of this standard.

                 b. Financial instruments – disclosure
                 The CICA issued Handbook Section 3862, “Financial Instruments – Disclosure,” which requires an entity to have sufficient
                 disclosure so as to ensure that users of the financial statements can evaluate the significance of financial instruments for the
                 entity’s financial position and performance. In order to satisfy this principle, Section 3862 lists specific disclosure requirements.
                 The new standard applies to interim and annual financial statements relating to fiscal years beginning on or after October 1, 2007.
                 The Company is currently evaluating the impact of this standard.

                 3. Acquisitions and divestments
                 A. pASco cogeneRAtion, l.p. AcQuiSition
                 In December 2007, the Company acquired substantially all of the remaining 50.1% of the Pasco Project from its existing partners.
                 The cash payment for the acquisition in the amount of approximately $25,000, including acquisition costs, has been allocated to
                 the net assets acquired based on management’s preliminary estimate of the fair value at December 24, 2007 as follows:

                                                                                                                                            preliminary
                                                                                                                                      purchase equation

                 Working capital                                                                                                             $    4,466
                 Other long-term assets                                                                                                          20,518
                 Long-term debt (excluding current portion)                                                                                           –

                 Total purchase price adjustments                                                                                                24,984
                 Less cash acquired                                                                                                               1,771

                 Cash paid, net of cash acquired                                                                                             $   23,213




                                                                         AnnuAl RepoRt 2007       AtlAntic poweR coRpoRAtion                           51




Atlantic Power AR-jp.indd 51                                                                                                                         4/22/08 8:04:38 AM
             b. jAMAicA pRiVAte poweR coMpAny ltd. diVeStMent
             In July 2007, a subsidiary of the Company entered into an agreement to sell its equity investment in the Jamaica Project for
             $6.2 million. The carrying value of the equity investment at June 30, 2007 exceeded the sales price and, accordingly, an impair-
             ment charge in the amount of $5.1 million was recorded in the second quarter of 2007 and is included in income from long-term
             investments in the consolidated statement of loss, comprehensive loss and deficit for the year ended December 31, 2007.

             c. pAth 15 AcQuiSition
             On June 29, 2006, The Company agreed to indirectly acquire 100% of Trans-Elect NTD Holdings Path 15, LLC, which owns ap-
             proximately 72% of the transmission system rights in the Path 15 transmission project (the “Path 15 Project”) located in California.
             Subsequent to the acquisition, management changed the name of Trans-Elect NTD Holdings Path 15, LLC to Atlantic Holdings
             Path 15, LLC.
                 The acquisition of Path 15 closed on September 15, 2006 and was financed with an acquisition credit facility in the amount of
             $88,000 (the “Acquisition Credit Facility”). Loans under the Acquisition Credit Facility bear interest at a rate equal to a eurodollar
             rate or a U.S. base rate, plus an applicable margin to those rates. The Acquisition Credit Facility was secured by pledges of assets
             in certain wholly owned and other investment companies of the Company. As of December 31, 2006, the applicable rate, includ-
             ing margin, was 7.33% on the loan outstanding on the Acquisition Credit Facility. The Acquisition Credit Facility was included
             in the current portion of long-term debt and short-term debt in the consolidated balance sheet and had an outstanding balance of
             $31 million at December 31, 2006. The remaining outstanding balance was paid in March 2007 using funds drawn from the Com-
             pany’s revolving credit facility.
                 In September 2007, a subsidiary of the Company entered into a permanent financing arrangement for the Path 15 Project. The
             financing is a $48 million term loan with final maturity in 2027 and bears interest at a fixed rate of 7.9%. Principal and interest
             payments are due in June and December of each year during the term of the loan. The term loan is secured by the Company’s
             investment in the Path 15 Project and is non-recourse to the Company.
                 During the year ended December 31, 2007, management revised its initial estimate of acquired liabilities recorded at the time
             of the Path 15 acquisition. The revised estimate resulted in an increase to goodwill in the amount of $1,486 in the consolidated
             balance sheet as of December 31, 2007.

             4. Joint venture investments
             The Company accounts for eight entities under proportionate consolidation:

             entity name                                                                                                    proportion consolidated

             Badger Creek Limited                                                                                                           50.0%
             Chambers                                                                                                                       40.0%
             Koma Kulshan Associates                                                                                                        49.8%
             Mid-Georgia Cogen LP                                                                                                           50.0%
             Orlando Cogen Limited LP                                                                                                       50.0%
             Pasco Cogen Ltd.1                                                                                                              99.8%
             Stockton Cogen Company                                                                                                         50.0%
             Topsham Hydro Assets                                                                                                           50.0%
             1    An additional 49.9% of pasco cogen ltd. was acquired on december 24, 2007 (see note 3(a)).




             52                                AtlAntic poweR coRpoRAtion             AnnuAl RepoRt 2007




Atlantic Power AR-jp.indd 52                                                                                                                          4/22/08 8:04:38 AM
                 The following summarizes the balance sheets at December 31, 2007 and 2006, and operating results and distributions paid to the
                 Company for the years ended December 31, 2007 and 2006 for the Company’s proportionate share of the eight entities:


                                                                                                                               company’s share

                                                                                                                2007                      2006

                 Assets
                 Current assets                                                                       $      57,045               $     56,318
                 Non-current assets                                                                         397,951                    430,999

                                                                                                      $     454,996               $    487,317

                 Liabilities
                 Current liabilities                                                                  $      40,498               $     33,945
                 Non-current liabilities                                                                    184,173                    177,209

                                                                                                      $     224,671               $    211,154


                 Operating results:
                   Revenue                                                                            $      192,935              $    173,484
                   Net income (loss)                                                                        (153,926)                   19,848

                 Distributions paid to the Company                                                    $       29,003              $     31,056




                 5. Property, plant and equipment
                                                                                                                               company’s share

                                                                                                                2007                      2006

                 Cost                                                                                 $     477,042               $    450,923
                 Less accumulated depreciation                                                               64,002                     39,743

                                                                                                      $     413,040               $    411,180



                 Depreciation of $24,259 and $20,627 was expensed for the years ended December 31, 2007 and 2006, respectively.




                                                                     AnnuAl RepoRt 2007     AtlAntic poweR coRpoRAtion                       53




Atlantic Power AR-jp.indd 53                                                                                                               4/22/08 8:04:38 AM
             6. Other intangible assets and transmission system rights
             Other intangible assets include power purchase contracts that are not separately recorded as financial instruments and fuel supply
             agreements. Transmission system rights represent the long-term right to approximately 72% of the capacity of the Path 15 transmis-
             sion line.
                                                                                                              2007                        2006

             Transmission system rights                                                              $     218,846              $     221,227
             Power purchase agreements                                                                      70,232                     70,993
             Fuel supply agreements                                                                         77,885                     93,939

             Less amortization                                                                              (30,015)                   (25,618)

                                                                                                     $     336,948              $     360,541


             Amortization of $30,015 and $25,618 was expensed for the periods ended December 31, 2007 and 2006, respectively.



             7. long-term investments
             The Company has investments accounted for under the equity method and the cost method. The equity accounted for entities
             are Delta-Person Limited Partnership and Rumford Cogeneration Company LP (“Rumford”). The cost accounted for entities are
             Gregory Power Partners LP and Selkirk Cogen Partners LP. The Company owns a portion of its interest in Rumford through
             Javelin Energy LLC. An analysis of the investments is presented below:
                                                                                                              2007                        2006

             Long-term investments, beginning of year                                                $      76,973              $       78,335
             Proceeds from disposal of equity investment (Note 3)                                           (6,175)                          –
             Equity earnings, net of impairment charges                                                     (1,898)                     10,438
             Distributions received                                                                         (4,085)                    (11,800)

             Long-term investments, end of year                                                      $      64,815              $       76,973



             8. Goodwill
                                                                                  path 15                 chambers                        total

             Goodwill, beginning of year 2006                              $        7,432            $       71,726             $       79,158
             Adjustment to purchase price allocations                                   –                         –                          –
             Impairment loss                                                            –                         –                          –

             Goodwill, end of year 2006                                    $        7,432            $       71,726             $       79,158


             Adjustment to purchase price allocations                               1,486                                                1,486
             Impairment loss                                                                                 71,726                     71,726

             Goodwill, end of year 2007                                    $        8,918            $             –            $        8,918




             54                        AtlAntic poweR coRpoRAtion      AnnuAl RepoRt 2007




Atlantic Power AR-jp.indd 54                                                                                                                      4/22/08 8:04:38 AM
                 The impairment of goodwill at Chambers in the amount of $71,726 resulted from the significant increase in the book value of the
                 reporting unit due to the Project’s PPA being recorded as a financial instrument at fair value. The fair value accounting for the PPA
                 and the impairment of goodwill do not have any impact on the underlying economic value of or anticipated future cash distribu-
                 tions from the Chambers Project.



                 9. Gas transportation contract liability
                 Prior to June 2007, Onondaga had certain long-term commitments for the provision of natural gas transportation service to the
                 Onondaga Project through the year 2013. The contracts provided for fixed monthly demand charges, in addition to variable com-
                 modity charges based on the quantity of gas transported. Obligations related to the long-term gas transportation agreements were
                 recognized as liabilities in purchase accounting upon the acquisition of Onondaga by the Company. These obligations were
                 previously being amortized over the remaining lives of the contracts. In June 2007, Onondaga paid $9.75 million to an unrelated
                 third party in exchange for the assumption by the third party of the obligations under the long-term gas transportation agreements.
                 The carrying value of the transportation contract liability at the date of the transaction exceeded the amount paid by Onondaga
                 to extinguish the liability, resulting in a gain of approximately $10 million in the second quarter of 2007. The gain was recorded
                 in other project income in the consolidated statement of loss, comprehensive loss and deficit. The Onondaga Project funded the
                 transaction with a $9.75 million contribution from the Company, which was partially funded by a $9.4 million release of
                 restricted cash at the Path 15 Project.



                 10. Credit facility
                 In August 2007, the Company amended its credit facility. Under the terms of the amendment, the total amount available under
                 the credit facility has been increased from $75 million to $100 million, of which $50 million may be utilized for letters of credit.
                 The November 2008 maturity date of the credit facility has been extended to August 2012 with an option of an additional one-year
                 extension.
                    Outstanding amounts under the amended credit facility bear interest at the London Interbank Offered Rate (“LIBOR”) plus an
                 applicable margin that varies based on certain credit ratios of Holdings. The range of applicable margin is 0.875% to 1.625%.
                 Based on Holdings’ credit statistics at December 31, 2007, the applicable margin is currently 0.875%. Prior to the amendment, the
                 applicable margin was fixed at 1.50%.
                    As of December 31, 2007 and 2006, $23,307 and $13,465 was allocated, but not drawn, to support letters of credit for contrac-
                 tual credit support at several projects. In March 2007, the Company borrowed $31,000 under the credit facility and used the pro-
                 ceeds to repay the Acquisition Credit Facility related to the acquisition of Path 15. In September 2007, the outstanding amount on
                 the credit facility was repaid with proceeds from the permanent financing arrangement for the Path 15 Project (see Note 3).
                    The Company must meet certain financial covenants. The facility is secured by pledges of assets and interests in certain
                 subsidiaries.




                                                                        AnnuAl RepoRt 2007       AtlAntic poweR coRpoRAtion                         55




Atlantic Power AR-jp.indd 55                                                                                                                      4/22/08 8:04:38 AM
             11. long-term debt
             Long-term debt represents the Company’s consolidated and proportionately consolidated share of Project long-term debt and the
             unamortized balance of purchase accounting adjustments that were recorded in connection with the Path 15 acquisition in order
             to adjust the debt to its fair value on the acquisition date. Project debt is non-recourse to the Company and amortizes during the
             term of the respective revenue generating contracts of the Projects.
                                                                                                              2007                        2006

             Project debt, interest rates ranging from 3.5% to 9.5%,
                maturing between 2007 and 2028                                                       $     381,097              $     414,374
             Plus purchase accounting fair value adjustments                                                19,758                     14,206
             Less deferred financing costs                                                                   7,741                          –
             Less current portion of Project debt                                                           36,926                     86,168

                                                                                                     $     356,188              $     342,412



             Principal payments due under the terms of short-term and long-term debt in the next five years and thereafter are as follows:

             2008                                                                                                               $      36,926
             2009                                                                                                                      22,323
             2010                                                                                                                      22,692
             2011                                                                                                                      24,343
             2012                                                                                                                      26,306
             Thereafter                                                                                                               248,507

                                                                                                                                $     381,097



             The Project debt of joint ventures is secured by the respective facility and its contracts with no other recourse to the Company.
             The loans have certain financial covenants that must be met. At December 31, 2007, all of the Company’s Projects were in compli-
             ance with the covenants contained in Project-level debt. All of the debt in the table above is represented by non-recourse debt of
             joint ventures, except for the $31,000 outstanding balance on the Acquisition Credit Facility (Note 3(c)).



             12. subordinated notes

                                                                                                              2007                        2006

             Subordinated Notes (Cdn$392,696; 2006 – Cdn$392,553)                                    $     396,343              $     336,840
             Less deferred financing costs                                                                  10,251                          –

                                                                                                     $     386,092              $     336,840




             56                         AtlAntic poweR coRpoRAtion     AnnuAl RepoRt 2007




Atlantic Power AR-jp.indd 56                                                                                                                     4/22/08 8:04:38 AM
                 The Company issued $176,560 of 11% Subordinated Notes in conjunction with its initial public offering of IPSs and $30,367 of
                 11% Subordinated Notes separately.
                   Since the initial public offering, the Company has completed the following additional issuances of 11% Subordinated Notes:

                 Date                                                                  Amount issued           premium (discount)        net proceeds

                 October 2005 1                                                       $        37,125             $           605    $        37,730
                 October 2006 1                                                                43,278                        (878)            42,400
                 December 2006 1                                                               42,926                        (871)            42,055
                 December 2006 2                                                                2,597                         (53)             2,544

                 1    issuance made in connection with ipS offering.
                 2    issuance of 11% Subordinated notes separate from ipSs.




                 The Subordinated Notes will mature in 2016 subject to redemption under specified conditions at the option of the Company,
                 commencing on or after November 18, 2009. Interest is payable monthly in arrears and the principal repayment will occur at
                 maturity. The Subordinated Notes are denominated in Canadian dollars and are secured by a subordinated pledge of the Com-
                 pany’s interest in Holdings and certain subsidiaries, and contain certain restrictive covenants.
                    Interest expense was $40,818 and $30,042 for the years ended December 31, 2007 and 2006, respectively.



                 13. Convertible debentures
                 On October 11, 2006, the Company closed the sale of Cdn$60,000 aggregate principal amount of 6.25% Convertible Secured De-
                 bentures (“Debentures”) for gross proceeds of $52,780. The Debentures pay interest semi-annually on April 30 and October 31 of
                 each year. The Debentures mature on October 31, 2011 and are convertible into approximately 80.6452 IPSs per Cdn$1,000 principal
                 amount of Debentures, at any time, at the option of the holder, representing a conversion price of Cdn$12.40 per IPS.
                   Interest expense was $3,532 and $709 for the years ended December 31, 2007 and 2006, respectively.



                 14. Common stock

                                                                                                         number of shares (000s)             Amount

                 Balance, December 31, 2005                                                                                44,339    $       148,025
                 Issuance of common stock                                                                                   8,531             36,232
                 Private placement of common stock                                                                          8,600             32,379

                 Balance, December 31, 2006 and 2007                                                                       61,470    $       216,636



                 On October 6, 2006, the Company issued 8,531,000 IPSs at a rate of Cdn$10.55 per IPS. Proceeds of $36,232, net of offering costs,
                 were allocated to common stock.
                    On December 21, 2006, the Company issued 8,600,000 IPSs at a rate of Cdn$10.00 per IPS to Caisse de dépôt et placement du
                 Québec and two other institutional investors. Proceeds of $32,378, net of estimated offering costs, were allocated to common stock.




                                                                               AnnuAl RepoRt 2007       AtlAntic poweR coRpoRAtion                 57




Atlantic Power AR-jp.indd 57                                                                                                                     4/22/08 8:04:38 AM
             15. Income taxes

                                                                                                              2007                       2006

             Current income tax expense                                                             $        3,974             $          577
             Future income tax benefit                                                                     (51,748)                         –

                                                                                                    $      (47,774)            $          577



             The following is a reconciliation of income taxes calculated at the Canadian enacted statutory rate of 36.12% and 36.12% at
             December 31, 2007 and 2006, respectively, to the provision for income taxes in the consolidated statements of loss, comprehensive
             loss and deficit:
                                                                                                              2007                       2006

             Computed income tax recovery at Canadian statutory rate                                $      (71,149)            $         (662)
             Decrease resulting from:
               Operating in countries with different income tax rates                                       (7,643)                       (65)

                                                                                                           (78,792)                      (727)
             Valuation allowance                                                                            52,710                     10,103

                                                                                                           (26,082)                     9,376


             Non-taxable foreign-source income                                                                (475)                      (466)
             Permanent differences                                                                          (8,682)                     5,287
             Canadian loss carryforwards                                                                   (12,051)                   (10,735)
             Branch profits tax                                                                                993                        546
             Prior year true-up                                                                             (1,544)                    (3,588)
             Other                                                                                              67                        157

                                                                                                           (21,692)                    (8,799)

             Income tax expense                                                                     $      (47,774)            $          577




             58                        AtlAntic poweR coRpoRAtion      AnnuAl RepoRt 2007




Atlantic Power AR-jp.indd 58                                                                                                                     4/22/08 8:04:38 AM
                 The tax effect of temporary differences that give rise to significant portions of the future tax assets and future tax liabilities at
                 December 31, 2007 and 2006 are presented below:


                                                                                                                     2007                       2006

                 Future tax assets:
                    Intangible assets                                                                      $       26,725              $       57,697
                    Loss carryforwards                                                                             38,152                      23,594
                    Gas transportation contract and other accrued liabilities                                       9,889                      16,090
                    Unrealized foreign exchange loss on Subordinated Notes                                         28,387                         570
                    IPS issuance costs                                                                              3,199                       4,372
                    Other                                                                                               –                         744

                     Total future tax assets                                                                     106,352                     103,067
                     Valuation allowance                                                                         (89,364)                    (61,602)

                                                                                                                   16,988                      41,465


                 Future tax liabilities:
                    Property plant and equipment                                                                  (48,614)                     57,012
                    IPS issuance costs                                                                                  –                           –
                    Unrealized foreign exchange gain                                                              (13,835)                      1,554
                    Other                                                                                          (1,453)                          –

                     Total future tax liabilities                                                                 (63,902)                     58,566

                 Net future tax liability                                                                  $      (46,914)             $      (17,101)



                 As of December 31, 2007 and 2006, the Company had the following net operating loss carryforwards that are scheduled to expire
                 in the following years:


                                                                                                                     2007                       2006

                 2014                                                                                      $        6,460              $        5,504
                 2015                                                                                              35,328                      30,476
                 2026                                                                                              36,598                      28,144
                 2027                                                                                              46,993                           –

                                                                                                           $     125,379               $       64,124



                 These losses relate to the Canadian entity and may only be used to offset the future income of the Canadian entity for Canadian
                 income tax purposes. At December 31, 2006, a full valuation allowance was taken against the future tax assets set up in respect of
                 the Canadian entity’s loss carryforwards as the Company believes that it is not more likely than not that the Canadian entity would
                 be able to use any of these loss carryforwards.




                                                                        AnnuAl RepoRt 2007       AtlAntic poweR coRpoRAtion                         59




Atlantic Power AR-jp.indd 59                                                                                                                      4/22/08 8:04:39 AM
             16. financial instruments
             A. indexed SwAp And indexed SwAp hedge
             A swap agreement (“Indexed Swap”) exists between a power utility company and Onondaga, which replaced Onondaga’s original
             power purchase contract. The Indexed Swap expires on June 30, 2008. The Indexed Swap is a financial instrument under which
             the utility company makes monthly payments to Onondaga based upon the differential between an indexed “contract price” and
             a market reference price for electricity. The indexed contract price fluctuates in relation to the market cost of natural gas and a
             prescribed index of inflation. The notional quantity of electricity for the purpose of these calculations is fixed for the full term of
             the Indexed Swap.
                 In May 2004, a subsidiary of Onondaga entered into commodity derivative instruments (“Indexed Swap Hedge”), in order to
             lock in favorable gas, power and capacity pricing under the Indexed Swap. The Indexed Swap Hedge extends through June 30,
             2008 and removes almost all commodity price risk from the Indexed Swap through its term.
                 At December 31, 2007, the fair value of the Indexed Swap was included in the current portion of derivative instruments asset in
             the amount of $17,689 and the fair value of the Indexed Swap Hedge was included in the current portion of derivative instruments
             liability in the amount of $6,844. At December 31, 2006, the fair value of the Indexed Swap was included in the current portion of
             derivative instruments assets and the long-term portion of derivative instruments asset in the amount of $33,016 and $17,108, re-
             spectively. At December 31, 2006, the fair value of the Indexed Swap Hedge was included in the current portion of derivative in-
             struments liability and the long-term portion of derivative instruments liability in the amount of $11,612 and $7,377, respectively.
             Changes in the fair values of derivative instruments are recorded in change in fair value of derivative instruments in the consoli-
             dated statements of loss, comprehensive loss and deficit.

             b. FoReign cuRRency contRActS
             The Company uses forward foreign currency contracts to manage its exposure to changes in foreign exchange rates, as the Company
             earns its income principally in the United States but has the obligation to make distributions to shareholders predominantly in
             Canadian dollars. Since its inception, the Company has established a hedging strategy for the purpose of reinforcing the long-term
             sustainability of its distributions. The Company has executed this strategy by entering into forward contracts to purchase Canadian
             dollars at fixed rates of exchange sufficient to make monthly distributions through December 2011 at the current annual distribution
             level of Cdn$1.06 per IPS to IPS holders, as well as interest payments on the Subordinated Notes. It is the Company’s intention to
             periodically consider extending the length of these forward contracts. Changes in the fair market value of the Company’s forward
             contracts partially offset exchange gains or losses on the U.S. dollar equivalent of the Company’s Canadian dollar obligations.
             The following table summarizes the Company’s forward foreign currency contracts with monthly settlement terms as of Decem-
             ber 31, 2007:
                                                                                                                          notional Monthly Amounts

             Period                                                          Sell u.S. dollars     buy canadian dollars                Average rate

             2008–2009                                                                 4,811                      5,800                     1.2055
             2010                                                                      5,167                      5,800                     1.1225
             2011                                                                      5,494                      5,800                     1.0557


             In addition to the forward contracts in the table above that settle on a monthly basis, the Company has executed forward contracts
             to purchase Canadian dollars at fixed rates of exchange sufficient to make semi-annual payments on the Debentures. The con-
             tracts provide for the purchase of Cdn$1.9 million in April and in October of 2008 through 2011 at a rate of 1.1075 Canadian dol-
             lars per U.S. dollar.




             60                         AtlAntic poweR coRpoRAtion       AnnuAl RepoRt 2007




Atlantic Power AR-jp.indd 60                                                                                                                       4/22/08 8:04:39 AM
                     The foreign exchange forward contracts are carried at estimated fair value based on quoted market value. Mark-to-market ad-
                 justments in the foreign currency forward contracts are reflected in foreign exchange gains and losses. At December 31, 2007, the
                 fair value of the foreign exchange forward contracts was included in current portion of derivative instruments liability and long-
                 term portion of derivative instruments asset in the amount of $977 and $35,566, respectively. At December 31, 2006, the fair value
                 of the foreign exchange forward contracts was included in current portion of derivative instruments asset and long-term portion of
                 derivative instruments asset in the amount of $2,010 and $1,876, respectively.
                     The foreign exchange loss during the periods ended December 31, 2007 and 2006 primarily reflects unrealized foreign ex-
                 change losses on the U.S. dollar equivalent of the Company’s Canadian dollar-denominated obligation related to Convertible
                 Debentures and Subordinated Notes, unrealized foreign exchange gains on the changes in the fair market value of the Company’s
                 forward contracts and realized foreign exchange gains on forward contract settlements during the period. Foreign exchange gains
                 (losses) are as follows:
                                                                                                                   2007                        2006

                 Subordinated notes and convertible debentures                                            $     (68,419)             $        3,265
                 Non-controlling interest                                                                             –                      (2,196)
                 Forward contracts                                                                               30,703                      (6,289)

                 Unrealized foreign exchange gains (losses)                                                     (37,716)                     (5,220)
                 Realized foreign exchange gains on forward contract settlements                                  7,574                       3,925

                                                                                                          $     (30,142)             $       (1,295)


                 c. otheR FinAnciAl inStRuMentS
                 Certain of the Projects also use interest rate swaps to manage fluctuations in interest rates and natural gas forwards or swaps to
                 minimize the effects on cash flow of changing natural gas prices, which are a significant component of certain Project expenses.
                 In addition, other Projects have entered into natural gas contracts with pricing terms designed to minimize the impact of gas price
                 volatility on operating margins.



                 17. long-term Incentive Plan
                 On March 28, 2007, the Board of Directors approved grants of notional units to acquire a maximum of 172,071 IPSs under the
                 terms of the LTIP. The weighted average fair value per notional unit granted was $9.43. The measurement date for the awards for
                 accounting purposes occurred when participants were informed of the details of their awards in April 2007. As a result, compensa-
                 tion expense related to the LTIP in the amount of approximately $1 million was recorded in the year ended December 31, 2007.
                 No compensation expense related to the LTIP was recorded in the year ended December 31, 2006.




                                                                       AnnuAl RepoRt 2007      AtlAntic poweR coRpoRAtion                         61




Atlantic Power AR-jp.indd 61                                                                                                                    4/22/08 8:04:39 AM
             18. Basic and diluted loss per share
             Basic loss per share has been calculated using the weighted average number of units outstanding during periods ended
             December 31, 2007 and 2006 of 61,470,500 and 46,398,368, respectively.
                Diluted loss per share is computed including dilutive potential IPSs as if they were outstanding IPSs during the period. Dilutive
             potential IPSs include 4,838,712 IPSs that would be issued if all of the convertible debentures were converted into IPSs at
             January 1, 2007. Dilutive potential IPSs also include the weighted average number of IPSs, as of the date such notional units were
             granted, that would be issued if the unvested notional units outstanding under the Company’s LTIP were vested and redeemed for
             IPSs under the terms of the LTIP. Weighted average dilutive potential IPSs related to the LTIP were 156,067 for the period ended
             December 31, 2007.
                Because the Company reported a loss during the period ended December 31, 2007, the effect of including these shares in the
             calculation is anti-dilutive.



             19. Related party transactions
             In connection with the Company’s initial public offering, ArcLight Energy Partners Funds I, L.P. (“Fund I”) and ArcLight Energy
             Partners Funds II, L.P. (“Fund II”, and, together with Fund I, the “ArcLight Funds”) and Caithness Energy, LLC (“Caithness”)
             (together with the ArcLight Funds, the “Former Investors”) acquired the right to request, at any time, that Holdings purchase for
             cancellation all or any portion of the Former Investors’ interests in Holdings, subject to a minimum remaining 10% interest for a
             two-year period from November 18, 2004. This liquidity right was treated as a liability of the Company and recorded at fair value
             on the consolidated balance sheets. Any change in the non-controlling interest liability was recognized in the consolidated state-
             ments of loss, comprehensive loss and deficit as a change in non-controlling interest liability.
                The Former Investors have exercised the liquidity right in a series of transactions since the initial public offering through
             February 2007 as follows:

                                                                                           Amount paid to                        incremental     Former investors’
             Date                                                                         Former investors                    share acquired 1    remaining share

             October 2005                                                                   $         64,374                          12.0%                29.9%
             October 2006                                                                             87,287                          15.5%                14.4%
             February 2007                                                                            76,888                          14.4%                   0%
             1    Represents incremental portion of holdings purchased by the company from the Former investors in the transaction.



             The amounts paid to the Former Investors in the transactions above were financed by the Company through the sale of IPSs and
             Convertible Debentures.
                 At December 31, 2006, $74,433 in restricted cash included in the consolidated balance sheet was held in escrow pending regu-
             latory approval of a transaction whereby the remaining interests of the Former Investors were acquired by Holdings. In February
             2007, the required regulatory approval was obtained and the transaction was completed. Holdings is now a wholly owned subsid-
             iary of the Company and the liquidity right of the Former Investors has been extinguished.
                 During the period ended December 31, 2007, in accordance with the management agreement between the Company and
             Atlantic Power Management, LLC (that is owned by the ArcLight Funds), the Company incurred management and incentive fees,
             and cost reimbursements of $344 and $869, respectively. During the period ended December 31, 2006, the Company incurred
             management and incentive fees, and cost reimbursements of $340 and $554, respectively.




             62                                AtlAntic poweR coRpoRAtion               AnnuAl RepoRt 2007




Atlantic Power AR-jp.indd 62                                                                                                                                      4/22/08 8:04:39 AM
                 20. Commitments and contingencies
                 From time to time, the Company, its subsidiaries and the Projects are parties to disputes and litigation that arise in the normal
                 course of business. The Company assesses its exposure to these matters and records estimated loss contingencies when a loss is
                 likely and can be reasonably estimated. There are no matters pending as of December 31, 2007 which are expected to have a mate-
                 rial impact on the Company’s financial position or results of operations.



                 21. subsequent events
                 Auction-RAte SecuRitieS
                 As of December 31, 2007, approximately $26 million of the Company’s cash and cash equivalents were invested in auction-rate
                 securities (“ARSs”). All of these ARSs are AAA rated by one or more of the major credit rating agencies and are comprised of guaran-
                 teed student loans or municipal securities. ARSs typically have an underlying maturity of up to 40 years but have historically traded
                 in seven or 28 day intervals in a highly liquid market. The ARSs that were held at December 31, 2007 were redeemed at auctions
                 held in January 2008 and the proceeds were re-invested in ARSs.
                     In February 2008, the overall market for ARSs suffered a significant decline in liquidity. In February and March 2008, several
                 auctions of ARSs in which the Company had an investment were unsuccessful, resulting in the Company continuing to hold these
                 securities and the issuers paying interest at the maximum contractual rate. As of March 26, 2008, the Company had approximate-
                 ly $36 million invested in ARSs that are collateralized by portfolios of student loans that are guaranteed by the U.S. government
                 under the Federal Family Education Loan Program.
                     Based on the current market conditions, it is likely that auctions related to these securities will be unsuccessful in the near
                 term. Unsuccessful auctions will result in the Company continuing to hold these ARSs beyond their next scheduled auction reset
                 dates and limiting the short-term liquidity of these investments. While this affects the Company’s ability to access these funds in
                 the near term, management does not believe that the underlying securities or collateral have been affected. The Company intends
                 to hold these ARSs and does not anticipate a need to sell the ARSs in order to run the business. Management further believes that
                 the issuers of these ARSs are undertaking efforts to refinance the securities.
                     Management will continue to monitor the market for ARSs and consider its impact, if any, on the fair market value of the Com-
                 pany’s investments. If liquidity does not return to the market for ARSs, the Company will be required to reclassify its investments in
                 ARSs from cash and cash equivalents to short-term investments. If the current market conditions deteriorate further, the Company
                 may also be required to record book losses on the ARSs but does not anticipate any long-term realized loss in these investments.



                 22. Comparative figures
                 Certain 2006 figures have been reclassified to conform to the financial statement presentation adopted in 2007.




                                                                         AnnuAl RepoRt 2007      AtlAntic poweR coRpoRAtion                          63




Atlantic Power AR-jp.indd 63                                                                                                                       4/22/08 8:04:39 AM
             Atlantic Power Corporation                             Atlantic Power Corporation directors

             Exchange listing                                       Irving Gerstein
             IPSs Issued and Outstanding: 61,470,500                chairman of the board
             Ticker Symbol: ATP.UN                                  Toronto, Ontario
                                                                    Mr. Gerstein is a retired executive and
             Cdn$60 million 6.25% Convertible Debentures            is currently a Director of Medical Facilities
             due October 31, 2011                                   Corporation, Economic Investment Trust
             Ticker Symbol: ATP.DB                                  Limited and Student Transportation
                                                                    of America.
             Exchange: TSX
                                                                    Ken hartwick
             Investor Relations                                     chairman of the audit committee
             Contact: Barry Welch                                   Toronto, Ontario
             t 617.977.2700                                         Mr. Hartwick is President and Co-CEO of
                                                                    Ontario Energy Savings Corp., which is a wholly
             Corporate headquarters                                 owned subsidiary of, and provides administrative
             355 Burrard Street, Suite 1900                         services to, Energy Savings Income Fund, an
             Vancouver, BC V6C 2G8                                  income trust traded on the TSX.

             Website                                                John Mcneil
             www.atlanticpowercorporation.com                       Toronto, Ontario
                                                                    Mr. McNeil is President of BDR NorthAmerica
             Annual Meeting                                         Inc., an energy consulting firm based in
             Wednesday, June 4, 2008, 10:00 a.m. EDT                Toronto, Ontario.
             Albany Club — 91 King Street East
             4th Floor, John A. McDonald Room                       Barry Welch
             Toronto, ON M5C 1G3                                    Boston, Massachusetts
                                                                    Mr. Welch is President and CEO of
             transfer Agent                                         Atlantic Power Management, LLC.
             Computershare Investor Services, Inc.
             100 University Avenue                                  Bill Whitman
             Toronto, ON M5J 2Y1                                    Ridgewood, New Jersey
                                                                    Mr. Whitman is Senior Vice President of
             Independent Auditors                                   NW Financial Group, LLC, Jersey City, NJ,
             KPMG LLP                                               an investment bank specializing in
             Commerce Court West                                    municipal finance.
             199 Bay Street
             Toronto, ON M5L 1B2

             legal Counsel
             Goodmans LLP
             250 Yonge Street
             Toronto, ON M5B 2M6




             64                        AtlAntic poweR coRpoRAtion       AnnuAl RepoRt 2007




Atlantic Power AR-jp.indd 64                                                                                           4/22/08 8:04:39 AM
                 CORPORAtE InfORMAtIOn


                 Atlantic Power Management     Paul Rapisarda                                    Directors from left to right:
                                               managing director, asset                          Barry Welch,
                 Barry Welch                   management & acquisitions                         John McNeil,
                 president and chief                                                             Irving Gerstein,
                 executive officer             200 Clarendon Street, Floor 25                    Bill W hitman,
                                               Boston, MA 02116                                  and Ken Hartwick
                 Patrick Welch                 t 617.977.2400
                 chief financial officer and   f 617.977.2410
                 corporate secretary           info@atlanticpowercorporation.com



                                               AnnuAl RepoRt 2007   AtlAntic poweR coRpoRAtion                          65




Atlantic Power AR-jp.indd 65                                                                                          4/22/08 8:04:42 AM
                         Atlantic power Management, llc
                         200 clarendon Street, Floor 25
                         boston, Massachusetts 02116
                         telephone: 617.977.2400
                         Fax: 617.977.2410

                         www.atlanticpowercorporation.com




Atlantic Power AR-jp.indd 66                                4/22/08 8:04:42 AM

				
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