Atlantic Power Corporation Releases Third Quarter 2014 Results -- BOSTON, Nov. 6, 2014 /PRNewswire/ -- BOSTON, Nov. 6, 2014 /PRNewswire/ -- Atlantic Power Corporation (NYSE: AT) (TSX: ATP) ("Atlantic Power" or the "Company") today released its results for the three and nine months ended September 30, 2014. Our results year to date have been driven by strong wind generation, increased waste heat at our Ontario projects, and lower maintenance and administrative expenses. We are encouraged by the progress we have made in improving the performance of our projects and reducing our costs, which we expect will benefit future periods. We also maintained a strong liquidity position of $272 million, including $168 million of unrestricted cash," said Kenneth Hartwick, interim President and CEO of Atlantic Power. Although our availability improved this quarter, we had lower dispatch at a few projects primarily due to a mild summer. Notwithstanding that, we still expect 2014 Project Adjusted EBITDA to be in the middle of our initial guidance range. During the quarter, we incurred severance costs associated with recent management changes and steps to reduce our cost structure. These costs will reduce Free Cash Flow, and thus we now expect our Free Cash Flow to be in the lower end of our initial guidance range. Following our review of strategic options, our Board determined that it was in the best interest of the Company and its stakeholders for the Company to remain independent. Since then, we have taken further steps to ensure an efficient cost structure and narrowed our capital allocation priorities in the near term to debt reduction and attractive investments in existing projects," Mr. Hartwick continued. We expect to fund these investments with existing Free Cash Flow but are also evaluating potential asset sales and partnerships with the intended use of proceeds to reduce high-cost debt. Deleveraging, reducing our financial risk and lowering our cost of capital should improve our ability to regain effective access to the capital markets, which would allow us to grow as well as address debt maturities in 2017 and beyond. We believe that achieving these goals will result in meaningful value creation for shareholders over time. All amounts are in U.S. dollars and are approximate unless otherwise indicated. Free Cash Flow, Cash Distributions from Projects, Project Adjusted EBITDA and APLP Project Adjusted EBITDA are not recognized measures under generally accepted accounting principles in the United States ("GAAP") and do not have standardized meanings prescribed by GAAP; therefore, these measures may not be comparable to similar measures presented by other companies. Please see "Regulation G Disclosures" attached to this news release for an explanation and the GAAP reconciliation of "Free Cash Flow," "Cash Distributions from Projects" and "Project Adjusted EBITDA" as used in this news release. The Company has not reconciled non-GAAP financial measures relating to individual projects or the APLP projects to the directly comparable GAAP measures due to the difficulty in making the relevant adjustments on an individual project basis. The Company has not provided a reconciliation of forward-looking non-GAAP measures, due primarily to variability and difficulty in making accurate forecasts and projections, as not all of the information necessary for a quantitative reconciliation is available to the Company without unreasonable efforts. Strategic Priorities Focus on improvement in credit metrics to achieve competitive cost of capital and ready access to capital markets Target significant reduction in leverage using proceeds from selective asset sales under consideration Repurchase outstanding debt securities where economically attractive; implementing normal course issuer bid (NCIB) for at least $15 million and up to 10% of outstanding convertible debentures ($35 million) Deploy capital in high return projects and aggressively reduce corporate expenses Continue to make optimization investments in existing fleet with attractive expected returns (five-year payback or 20% current yield); targeting approximately $5 to $10 million of such investments in 2015 Achieve at least $7 million reduction in general and administrative (G&A) expense in addition to $8 million already achieved, for total expected annual savings of at least $15 million in 2015 relative to 2013; further potential cost reductions under evaluation Longer-term goal of successfully pursuing value-enhancing acquisition, development or joint venture opportunities Recent Financial and Operational Accomplishments Completed major optimization projects planned for this year and expect to realize annual run-rate cash flow benefit of at least $8 million in 2015, at least half of which has been realized this year Implemented personnel reductions and took other steps consistent with G&A savings target for 2015 Reduced outstanding amount of APLP term loan through mandatory amortization and cash sweep and amortized project debt by $73 million year to date; on track to achieve approximate $85 million reduction by year-end 2014 September 30th liquidity of $272 million, including $168 million of unrestricted cash, of which $41 million was used to repay the Cdn$44.8 million convertible debenture at maturity on October 31; expected annual interest savings in 2015 of $2.7 million; no other non-amortizing corporate debt maturities until March 2017 Settled dispute with Zachry for $5 million, previously accrued and to be paid from Piedmont restricted cash Atlantic Power Corporation Table 1 - Selected Results in millions of U.S. dollars, except as otherwise stated Three months ended September 30, Nine months ended September 30, Excluding results from discontinued operations (1) Project revenue Project (loss) income Project Adjusted EBITDA Cash Distributions from Projects Aggregate power generation (thousands of Net MWh) Weighted average availability Including results from discontinued operations (1) Cash flows from operating activities Free Cash Flow (1) The Path 15 transmission line ("Path 15"), Auburndale Power Partners, L.P. ("Auburndale"), Lake CoGen, Ltd. ("Lake") and Pasco Cogen, Ltd. ("Pasco") (collectively, the "Sold Projects") were sold in April 2013, the Company's interest in Rollcast Energy ("Rollcast") was sold in November 2013, and Thermo Power & Electric, LLC ("Greeley") was sold in March 2014. Accordingly, the revenues, project income (loss), Project Adjusted EBITDA and Cash Distributions from these assets are included in discontinued operations for the three and nine month periods ended September 30, 2013 and September 30, 2014. The results of discontinued operations are excluded from Project revenue, Project income, Project Adjusted EBITDA and Cash Distributions from Projects as presented in Table 1. The results for discontinued operations have also been excluded from the aggregate power generation and weighted average availability statistics shown in Table 1. Under GAAP, the cash flows attributable to the Sold Projects, Rollcast and Greeley are included in cash flows from operating activities as shown on the Company's Consolidated Statement of Cash Flows; therefore, the Company's calculation of Free Cash Flow shown on Table 1 also includes cash flows from the Sold Projects, Rollcast, and Greeley. The Gregory project ("Gregory"), which was sold in August 2013, and the Delta-Person generating station ("Delta-Person"), which was sold in July 2014, are both accounted for under the equity method of accounting and therefore are included in the Company's financial results from continuing operations. Project Adjusted EBITDA of $72.2 million decreased $2.8 million from Q3 2013, in line with expectations As previously disclosed, following an impairment charge at Tunis recorded in second quarter results, the Company initiated an analysis of its remaining goodwill during the third quarter. As a result of that analysis, non-cash goodwill impairments at three projects totaling $91.8 million were recorded in the third quarter, primarily driven by lower forward power curves as compared to levels at the time the projects were acquired in 2011 GAAP results included the $91.8 million impairment, an $8.6 million asset sale gain, and a $0.4 million non-cash gain on changes in the fair value of derivatives, for a project loss of $ (68.6) million; project income excluding these items was $14.2 million. Q3 2013 results of $4.4 million included a $34.7 million non-cash impairment, a $3.5 million non-cash loss on changes in the fair value of derivatives and a $31.0 million asset sale gain; project income excluding these items was $11.6 million; thus, year-over-year increase was $2.6 million Cash flows from operating activities of $40.4 million decreased $6.0 million from Q3 2013 Free Cash Flow of $12.6 million decreased $26.0 million from Q3 2013, due primarily to debt repayment, higher capex (primarily for Nipigon and other optimization investments) and lower cash flows from operating activities YTD September 2014 Financial Highlights Project Adjusted EBITDA of $221.6 million increased $10.2 million from YTD Sept. 2013, due to strong wind generation, increased waste heat in Ontario, lower maintenance expense at several projects, increased margins at Orlando, and lower unallocated expenses, partially offset by lower dispatch due to a mild summer GAAP results included $106.6 million non-cash impairments, a $12.3 million non-cash gain on changes in the fair value of derivatives and an $8.6 million asset sale gain, for a project loss of $ (52.2) million; excluding these items, project income was $33.5 million. 2013 project income of $56.4 million included a $34.7 million non-cash impairment, a $33.4 million non-cash gain on changes in the fair value of derivatives and a $31.0 million asset sale gain; project income excluding these items was $26.7 million; thus, year-over-year increase was $6.8 million Cash flows from operating activities of $45.9 million decreased $97.4 million from YTD Sept. 2013, primarily due to interest expense related to the debt repayment and repurchase transactions in the first quarter of 2014, changes in working capital and the loss of cash flows from businesses that were divested in 2013 Free Cash Flow of $ (48.4) million decreased $161.4 million from YTD Sept. 2013 due primarily to the reduction in cash flows from operating activities, increased debt repayment of $54.5 million and higher capex of $5.8 million 2014 Guidance Ranges Narrowed Project Adjusted EBITDA of $285 to $300 million; previous guidance range was $280 to $305 million APLP Project Adjusted EBITDA of $165 to $175 million, unchanged from previous guidance Free Cash Flow of $0 to $10 million, down from $0 to $25 million previously, reflecting severance costs incurred in the second half of 2014 (guidance excludes $57.5 million of debt refinancing costs and Piedmont debt repayment) Strategic Update and Longer-Term Goals A major factor in the Company's ability to meet its longer-term goal of successfully pursuing value-enhancing acquisition and development opportunities is a competitive cost of capital and ready access to the capital markets. The Company is committed to deleveraging its balance sheet to achieve this longer-term goal, and has targeted a general credit profile with the following attributes to facilitate access to the capital markets: Consolidated Debt to Adjusted EBITDA ratio in the range of 5.0-5.75x Consolidated Debt to Total Capitalization ratio of approximately 60% Adjusted EBITDA to Interest Coverage multiple of 2.5x or better Consolidated Debt includes long-term debt and convertible debentures, including the current portion of such debt, as presented on the Company's consolidated balance sheet. Total Capitalization includes Consolidated Debt plus total shareholders' equity as presented on the Company's consolidated balance sheet. Adjusted EBITDA is a non-GAAP measure that is defined on page 15 of this press release. Adjusted EBITDA to Interest Coverage multiple is defined on page 15 of this press release. The Company expects to achieve a net reduction in total debt of approximately $85 million by year-end 2014 as follows: Amortization of the APLP term loan in the amount of an estimated $53 million, including $47.1 million through the third quarter of 2014 Amortization of consolidated project-level debt of approximately $26 million, including $8.1 million of Piedmont debt repaid at term loan conversion Reduction in the Company's proportional share of project-level debt at equity-method projects of approximately $7 million, including $6 million associated with the Delta-Person project that was sold in the third quarter of 2014 Together with continued amortization of its project debt and APLP term loan in the amount of $80 to $85 million annually (average for 2015 through 2017), the Company plans to take additional steps to improve its ability to achieve these credit metrics by the end of 2016, including: Significant reduction in leverage using proceeds from selective asset sales currently under consideration Repurchase outstanding debt securities where economically attractive; implementing an NCIB program for at least $15 million and up to 10% of outstanding convertible debentures ($35 million) In addition to reducing debt, the Company also intends to deploy capital in high return projects and aggressively reduce corporate expenses in order to achieve these goals: Continue to make optimization investments in existing fleet with expected attractive returns (five-year payback or 20% current yield); expect to make approximately $5 to $10 million of such investments in 2015 Achieve at least $7 million reduction in G&A expense on an annual basis in addition to $8 million previously achieved ($15 million annual run rate savings in 2015 versus 2013), with further potential cost reductions under evaluation Business Update Piedmont In October 2014, Piedmont settled a dispute in arbitration with Zachry, the project's contractor, related to amounts owed by the project for work performed by Zachry under the project's engineering, procurement and construction ("EPC") contract. Under the terms of the settlement, the project agreed to pay Zachry $5.0 million within seven days following execution of the settlement agreement. The settlement results in a mutual release of all arbitration claims by both parties, other than certain excluded warranty claims retained by Piedmont against Zachry. The payment will be made from restricted cash at the project reserved for retainage and arbitration claims. At September 30, 2014, Piedmont had accrued $8.2 million for the final retainage payment under the EPC. After payment of the settlement agreement, the remaining $3.2 million of reversed accrual will be credited to operations and maintenance expense. As previously disclosed, during the first quarter of 2014, Piedmont underwent several forced maintenance outages that resulted in the project not meeting its debt service coverage ratio covenant as of September 30, 2014. The Company does not expect Piedmont to meet its debt service coverage ratio covenant for at least the next 18 months. As a result, the project is not expected to make distributions for at least the next 18 months, which is nine months beyond the Company's previous expectation. Selkirk PPA expiration The Company has an 18.5% ownership interest in the Selkirk project. The project's Power Purchase Agreement (PPA) covering approximately three-quarters of the capacity expired on August 31, 2014. Since the expiration of the PPA, Selkirk has been operating on a 100% merchant basis, with the project selling power into the spot market to the extent that spot prices support profitable operation of the project. Tunis The PPA with the Ontario Power Authority (OPA) for the Company's Tunis project is scheduled to expire on December 31, 2014. Although the Company is continuing negotiations with the OPA, it has taken steps to minimize plant costs following the PPA expiration, including giving notice to the affected employees. Operating Results Project Availability and Generation Availability increased slightly to 95.0% from 94.8%, which represented an improvement over the levels experienced in the first and second quarters of this year and was consistent with the Company's historical levels. Increased availability at Mamquam, Moresby Lake and Koma Kulshan in the West segment and Morris in the East segment occurred primarily because of scheduled maintenance outages during the comparable 2013 quarter. Improvements for these projects were partially offset by decreased availability in the East segment at Nipigon, which underwent a scheduled maintenance outage in the current period. Most of the Company's projects earned their expected level of capacity payments during the quarter. The impact of reduced availability on capacity payments at the Ontario projects and Piedmont was $1.8 million. In July, Piedmont experienced an unplanned outage related to a failure in the generator lead line that has been repaired. The project achieved 99.5% availability in August and 98% in September. Generation decreased 8.5% due primarily to lower dispatch at Manchief and Williams Lake in the West Segment, lower dispatch at Selkirk in the East segment due to mild summer weather and scheduled maintenance at Chambers (East segment). These decreases were partially offset by increased generation in the Wind segment, primarily due to favorable winds at Canadian Hills. Availability declined to 93.0% from 94.2%, with all of the decrease occurring in the first and second quarters of the year. The decrease was attributable to a combination of forced outages (some weather-related) and extensions of scheduled outages. Year to date, reduced availability resulted in capacity payments being $8.4 million lower than their expected level. The majority of this impact was at the Ontario projects, which had unplanned outages due to weather and other factors in the first quarter of this year, and Piedmont, which had several forced outages earlier this year, the most recent in July, as discussed previously. Generation increased 0.1% in the first nine months of 2014 due primarily to the addition of Piedmont in the East segment in April 2013 (additional quarter in 2014), higher dispatch at Frederickson in the West segment and favorable wind conditions for Meadow Creek (in the Wind segment). These positive comparisons were mostly offset by reduced dispatch at Manchief and Williams Lake in the West segment and reduced generation at Selkirk and Tunis in the East segment. Financial Results Table 2 provides a breakdown of project income and Project Adjusted EBITDA by segment for the three and nine month periods ended September 30, 2014 as compared to the same periods in 2013. Table 2 - Segment Results Project income (loss) East West Wind Un-allocated Corporate Note: Project Adjusted EBITDA is not a recognized measure under GAAP and does not have any standardized meaning prescribed by GAAP; therefore, this measure may not be comparable to similar measures presented by other companies. Please refer to Tables 8 through 11 for a reconciliation of this non-GAAP measure to a GAAP measure. Project Income Reported project income can fluctuate significantly due to non-cash adjustments to "mark-to-market" the fair value of derivatives. Non-cash goodwill impairment charges and gains or losses on the sale of assets are included in project income and can also affect year-over-year comparisons. None of these items are included in Project Adjusted EBITDA. Project income decreased by $73.0 million to a loss of $ (68.6) million compared to project income of $4.4 million for the same period in 2013. The reduction in project income was primarily due to non-cash goodwill impairment charges of $91.8 million, an increase of $57.0 million from Q3 2013; decreased asset sale gains at equity method projects of $22.4 million ($8.6 million at Delta-Person in Q3 2014 and $31.0 million at Gregory in Q3 2013); decreased project income of $5.3 million at Selkirk due to lower dispatch and accelerated depreciation resulting from the PPA expiration on August 31, 2014; partially offset by increases in the fair value of gas purchase agreements and interest rate swap agreements accounted for as derivatives totaling $3.9 million; improvements at other projects including Nipigon, Orlando, Curtis Palmer and Canadian Hills; and a $2.2 million reduction in loss from the Un-allocated Corporate segment due to reductions in development expense at Ridgeline and lower compensation expense. Project income decreased by $108.6 million to a loss of $ (52.2) million compared to project income of $56.4 million for the same period in 2013. The reduction in project income was primarily due to non-cash goodwill impairment charges in 2014 of $106.6 million, an increase of $71.9 million from the 2013 period; decreased asset sale gains of $22.4 million, as described previously; net negative non-cash changes in fair value of gas purchase agreements and interest rate swap agreements accounted for as derivatives totaling $21.1 million; decreased project income of $12.6 million at Selkirk, as described previously; decreases at Chambers and Calstock totaling $4.7 million, primarily due to scheduled turbine maintenance in 2014; legal expenses incurred at Piedmont of $2.6 million related to Zachry arbitration and land owner disputes; partially offset by improvements at several projects in the East and West segments due to favorable outage comparisons; an additional quarter of Piedmont operation; increased margins at Morris and Orlando; lower interest expense at Curtis Palmer; improved generation at Meadow Creek; and a $4.8 million reduction in the Un-allocated Corporate segment loss primarily attributable to $2.2 million in development and administrative expense reductions at Ridgeline and a $1.2 million reduction in compensation expense. Project Adjusted EBITDA includes proportional EBITDA from the Company's equity method projects and 100% of EBITDA from Rockland, which is 50% owned by the Company, but is consolidated. Projects classified as discontinued operations are excluded from Project Adjusted EBITDA. Project Adjusted EBITDA decreased $2.8 million to $72.2 million from $75.0 million for the comparable period in 2013. Notwithstanding lower generation levels during the quarter, results for Project Adjusted EBITDA were in line with the Company's expectations. Projects with the most significant year-over-year decreases in Project Adjusted EBITDA included Selkirk, as described previously; Naval Station, North Island and Naval Training Center, due to lower energy revenues; Calstock and Chambers, due to increased maintenance expense and lower dispatch at Chambers; Curtis Palmer, due to lower water flows relative to 2013; smaller decreases at a number of other projects; partially offset by increases at Orlando, primarily due to higher capacity payments under a new PPA and lower fuel expenses following the expiration of an above-market gas supply contract at the end of 2013; Canadian Hills, due to increased wind generation; Nipigon and Kapuskasing, primarily due to favorable outage comparisons and increased waste heat generation; and a $1.2 million reduction in the loss of the Un-allocated Corporate segment, primarily due to lower development expenses at Ridgeline. Project Adjusted EBITDA increased by $10.2 million to $221.6 million from $211.4 million for the same period in 2013. Year-to-date results are in line with the Company's expectations. For the nine-month period, the most significant contributors to the improvement in Project Adjusted EBITDA were the Ontario projects other than Calstock, due to the timing of maintenance expense and increased waste heat generation; the wind projects, primarily Meadow Creek and Canadian Hills, due to increased generation; Morris, due primarily to lower maintenance costs relative to 2013 and higher merchant capacity and ancillary services revenues; Naval Training Center, due primarily to favorable maintenance comparisons; Orlando, as described previously; a $5.2 million reduction in loss from the Un-allocated Corporate segment, primarily due to a reduction in development costs at Ridgeline and a reduction in administrative costs; partially offset by decreases at Selkirk, as described previously; Williams Lake, primarily due to lower energy prices under the PPA beginning in April 2013, partially offset by lower maintenance expense; Calstock due to a scheduled turbine overhaul in 2014; the sale of Gregory in August 2013 and Delta-Person in July 2014; and smaller decreases at several other projects in the East and West segments. Corporate G&A Expense Administrative expenses, which include administration expense (corporate-level G&A expense), interest expense, foreign exchange gains and losses and other income, are not included in Project Adjusted EBITDA. In the third quarter, administration expense increased $0.8 million from the comparable year-ago period. During the quarter, the Company incurred $4.2 million of severance charges associated with management changes and personnel reductions that occurred during the quarter. This represented an increase of $2.9 million in accrued severance expense from the year-ago period, which was mostly offset by (i) a reduction in legal expenses of $1.5 million, as during the quarter the Company exceeded the $1.5 million deductible under its directors and officers insurance policy with regard to legal costs incurred for the purported class action shareholder litigation, and expects additional costs incurred to be paid by its insurance carrier to the extent set forth under the terms of its coverage; and (ii) a $0.7 million reduction in professional fees from the third quarter of 2013, when the Company incurred costs related to the amendment of the prior Senior Credit Facility. For the nine months year to date, administration expense decreased $1.8 million, primarily due to a $4.7 million reduction in transactional fees incurred for the 2013 asset divestitures and $0.7 million for lower professional costs related to the 2013 credit facility amendment. These reductions were partially offset by $4.2 million of severance costs, which increased $3.9 million from the year-ago period. Cash Flow Metrics Cash Distributions from Projects, which excludes projects classified as discontinued operations, increased by $17.3 million to $187.0 million for the nine months ended September 30, 2014, compared to $169.7 million for the same period in 2013. This result includes a decline in the third quarter of 2014 of $14.5 million from the year-ago period. Significant increases for the YTD Sept. 2014 occurred at (i) the Navy projects in California, attributable to lower operation and maintenance expenses than in 2013, during which the projects experienced planned outages, and to lower working capital requirements associated with a new gas supply agreement in 2014; (ii) Meadow Creek, Canadian Hills, Rockland and Idaho Wind, due to the release of construction-related blade and credit reserves and increased wind generation; (iii) Orlando, due to lower gas costs following the termination of swaps that were above market as well as favorable changes to the project's PPA; and (iv) Mamquam, due to lower maintenance expense. These increases were partially offset by decreases at (i) Chambers, which benefited from the release of the DuPont settlement in the 2013 period and for which there was a change in the distribution date under the project's new debt agreement in 2014, with distributions next expected to occur in December; (ii) Selkirk, due to the expiration of the PPA at the end of August; (iii) the Ontario projects, due to the timing of revenue receipts and higher maintenance expenses; and (iv) smaller decreases at several other projects. For the third quarter, significant decreases, in order of importance, occurred at the Ontario projects, for the reasons mentioned above; and Morris, due to gas storage purchases; with smaller decreases at Oxnard and Manchief. These decreases were partially offset by increases at Williams Lake, due to lower maintenance expense; and Orlando, the Navy projects in California, and Rockland, each for the reasons described above. Cash Flows from Operating Activities Cash flows from operating activities decreased by $6.0 million to $40.4 million compared to $46.4 million for the same period in 2013. The decrease is primarily due to the $2.8 million decrease in Project Adjusted EBITDA for the quarter and an approximate $16 million increase in cash outflows for working capital, partially offset by other factors. Cash flows from operating activities decreased by $97.4 million to $45.9 million compared to $143.3 million for the same period in 2013. The decrease is primarily due to $46.8 million of interest expense related to the debt repayment and repurchase transactions in the first quarter (as described in more detail in the first quarter 2014 press release dated May 12, 2014), a $45.2 million increase in cash outflows for working capital due to a $36.0 million decrease in prepaid and other assets due to the collection of security deposits in the first quarter of 2013, and a decrease in cash flows from discontinued operations (projects sold in 2013). Free Cash Flow decreased by $26.0 million to $12.6 million compared to $38.6 million for the same period in 2013. The decrease is due primarily to $9.6 million of term loan facility repayments at APLP pursuant to mandatory amortization and the cash sweep; $6.0 million of decreased cash flows from operations; $6.0 million of increased project capex, most of which was related to $6.1 million at Nipigon for the replacement and upgrade of the project's steam generator; and $2.5 million of increased repayments of project-level debt. Free Cash Flow decreased by $161.4 million to $ (48.4) million compared to $113.0 million for the same period in 2013. The decrease is primarily due to a $97.4 million decrease in operating cash flows as described previously, $47.1 million of term loan facility repayments by APLP and a $7.4 million increase in project-level debt repayment. The $47.1 million of term loan repayments through the third quarter, which includes $2.9 million of 1% mandatory amortization and $44.3 million of debt repaid pursuant to the 50% sweep of APLP's cash flow after debt service and capex, represents approximately 89% of the amount estimated for the full year of approximately $53 million. The Company's full year 2014 Free Cash Flow guidance excludes (i) $49.4 million of interest expense related to the refinancing and debt repurchase transactions and (ii) the $8.1 million Piedmont construction debt repayment. On that basis, Free Cash Flow for the first nine months of 2014 is approximately $9 million compared to $113 million for the same period in 2013. Liquidity As can be seen from Table 3, the Company's liquidity increased from approximately $261 million at June 30, 2014 to approximately $272 million as of September 30, 2014, including $168 million of unrestricted cash. On October 31, Cdn$44.8 million of the Company's convertible debentures (ATP.DB) matured, and the Company used $41 million of cash to repay the debentures at maturity. Pro forma for this use of cash, liquidity at the end of the quarter would have been approximately $231 million (see Table 3). Table 3 - Liquidity (in millions of U.S. dollars) Pro Forma Revolver capacity Letters of credit outstanding Unused borrowing capacity Unrestricted cash (1) Total Liquidity (1) Includes project-level cash for working capital needs of $16.3 million at September 30, 2014 and $16.4 million at June 30, 2014. Pro forma unrestricted cash reflects repayment of $41 million (Cdn$44.8 million) of convertible debentures (ATP.DB) on October 31, 2014 at maturity. Project Adjusted EBITDA of $285 to $300 million, narrowed from $280 to $305 million previously Free Cash Flow of $0 to $10 million, down from $0 to $25 million previously The Company is narrowing its guidance for 2014 Project Adjusted EBITDA to a range of $285 million to $300 million from a range of $280 to $305 million previously. The narrower range is based on results for the year to date as well as the Company's expectation for the balance of the year. The Company is reaffirming its expectation for 2014 APLP Project Adjusted EBITDA in the range of $165 to $175 million. The Company is lowering its guidance for 2014 Free Cash Flow to a range of $0 to $10 million from a range of $0 to $25 million previously. This guidance is net of planned capital expenditures totaling $16 million and debt repayments under the APLP term loan of an estimated $53 million in 2014 pursuant to mandatory amortization and the cash sweep. Relative to previous expectations, severance expenses accrued in the third quarter and additional amounts to be accrued in the fourth quarter associated with recent management changes and personnel reductions are expected to have an adverse impact on cash flows from operating activities and Free Cash Flow in the fourth quarter of 2014. They are not expected to affect Project Adjusted EBITDA as the majority of these costs have been or will be recorded in corporate G&A expense, which is not included in Project Adjusted EBITDA. The Company's Free Cash Flow guidance excludes (i) approximately $49.4 million in expenses associated with the first quarter refinancing and debt repurchase transactions and (ii) the $8.1 million repayment of Piedmont construction debt made to facilitate the term loan conversion in February, together totaling $57.5 million. See Table 4 for full-year 2014 guidance and year-to date 2014 actual results. Table 4 - 2014 Annual Guidance and YTD 2014 Actual 2014 Initial Guidance Provided 2/27/14 2014 Revised Guidance Provided 11/6/14 YTD 2014 Actual Free Cash Flow (1) APLP Project Adjusted EBITDA (2) (1) Free Cash Flow is defined as cash flows from operating activities less capex; project-level debt repayments, including amortization of the Senior Secured Term Loan Facility; and distributions to noncontrolling interests, including preferred share dividends. Note that 2014 guidance excludes $49 million of refinancing and debt repurchase transaction costs in first quarter 2014 and $8 million of Piedmont debt repayment in February 2014. (2) APLP is a wholly owned subsidiary of the Company. APLP Project Adjusted EBITDA is a summation of Project Adjusted EBITDA at each APLP project, and is calculated in a manner which is consistent with the Company's Project Adjusted EBITDA calculation. Note: Project Adjusted EBITDA, APLP Project Adjusted EBITDA and Free Cash Flow are not recognized measures under GAAP and do not have any standardized meaning prescribed by GAAP; therefore, these measures may not be comparable to similar measures presented by other companies. Other Financial Updates Goodwill Impairment Based on the continued deficit of the Company's market capitalization as compared to its book carrying value, the Company determined in the second quarter of 2014 that it was appropriate to initiate a test of the remaining goodwill at its reporting units prior to its annual goodwill impairment test that would have occurred in the fourth quarter of 2014. The test was performed as of August 31, 2014 and concluded during the quarter ended September 30, 2014. As a result of the event-driven goodwill assessment, it was determined that goodwill was impaired at the Kenilworth (East segment), Manchief (East Segment) and Williams Lake (West segment) reporting units. Accordingly, the Company recorded a full impairment of the remaining goodwill at Kenilworth ($17.9 million) and Manchief ($50.2 million) and a partial impairment of the remaining goodwill at Williams Lake ($23.7 million). The total goodwill impairment recorded in the three months ended September 30, 2014 was $91.8 million. As previously disclosed, during the second quarter of 2014, the Company recorded a $14.8 million non-cash impairment charge for the Tunis project, including $5.2 million for all of the project's goodwill and $9.6 million associated with the carrying value of the project's long-lived assets. The Company updated its impairment analysis for the Tunis project as of September 30, 2014 and determined that no further impairment of the project's long-lived assets was required as of that date. G&A Expense Reduction In the third quarter and year to date, the Company accrued severance costs of $4.2 million associated with recent management changes and personnel reductions. Additional severance costs are expected to be accrued in the fourth quarter. These costs were not assumed in the Company's 2014 guidance initially provided on February 27, 2014. The Company expects to realize cost savings from these initiatives in 2015, which are included in its expectation of at least a $7 million annual reduction in G&A expense in addition to cost reductions previously achieved. Including the $8 million of administrative and development cost reductions implemented in 2013, the Company expects that its 2015 G&A expense will be at least $15 million lower than the 2013 level. In addition to personnel cost savings, the Company expects to have lower project and business development expenses, including a $3 million annual benefit from the scheduled expiration of a contractual obligation related to the Ridgeline acquisition beginning in the first quarter of 2015. Also, going forward the Company expects to have lower legal expenses associated with the purported class action shareholder litigation now that it has met its $1.5 million deductible under its directors and officers insurance policy and expects additional costs incurred to be paid by its insurance carrier to the extent set forth under the terms of its coverage. The Company's project-level G&A expense and expenses for Ridgeline are included in the Un-allocated Corporate segment and therefore included in Project Adjusted EBITDA. Corporate-level G&A expense is included in Administration expense on the consolidated statement of operations. The G&A expense discussion in the preceding paragraph refers to total G&A expense. Capex and Optimization Update The Company expects to have major maintenance and capital expenditures in 2014 of approximately $35 million. In the first nine months of 2014, the Company invested $23 million, or about two-thirds of the total expected for the year. Included in this forecast are certain expenditures designed to improve the operating performance and enhance the efficiency or lower the costs of the Company's existing portfolio. The Company views these investments as an attractive use of its available cash as it believes that the risk-adjusted returns are compelling and the capital requirements are relatively modest. The level of planned spending associated with these optimization initiatives is approximately $18 million in 2014, for a 2013-2014 total of approximately $27 million. The largest of these projects is the steam generator replacement and upgrade at Nipigon, which occurred during an outage in the third quarter. Total estimated cost of the Nipigon project is approximately $12 million, including $8 million invested in 2014 and approximately $1 million to be spent in 2015. Other projects completed this year include the repowering of two turbines at Curtis Palmer, capacity uprates at North Island, Mamquam and Calstock, and an investment designed to boost output at Morris during peak periods. The Company expects that optimization-related spending for 2013 and 2014 totaling $27 million will produce incremental cash flow of at least $8 million annually on a run-rate basis in 2015, a significant portion of which has already been realized in the current year. Going forward, the Company expects that major maintenance and routine capex will average approximately $25 million annually (versus approximately $20 million in 2014). For 2015, the Company expects to invest approximately $5 to $10 million in discretionary optimization projects. Including these investments, major maintenance and capex are estimated to be in the range of $30 to $35 million. Supplementary Financial Information For further information, attached to this news release is a summary of Project Adjusted EBITDA by segment for the three and nine months ended September 30, 2014 and 2013 (Table 8) with a reconciliation to Project income (loss); a bridge from Project Adjusted EBITDA to Cash Distributions from Projects by segment for the nine months ended September 30, 2014 (Table 9A) and the nine months ended September 30, 2013 (Table 9B); a reconciliation of Cash Distributions from Projects and Project Adjusted EBITDA to Net income (loss) and of Free Cash Flow to cash flows from operating activities for the three and nine months ended September 30, 2014 and 2013 (Table 10); and a summary of Project Adjusted EBITDA for selected projects (top contributors based on the Company's 2014 budget, representing approximately 80% of total Project Adjusted EBITDA) for the three and nine months ended September 30, 2014 and 2013 (Table 11). Investor Conference Call and Webcast A telephone conference call hosted by Atlantic Power's management team will be held on Friday, November 7, 2014 at 8:30 AM ET. An accompanying slide presentation will be available on the Company's website prior to the call. The telephone numbers for the conference call are: U.S. Toll Free: 1-888-317-6003; Canada Toll Free: 1-866-284-3684; International Toll: +1 412-317-6061. Participants will need to provide access code 8939283 to enter the conference call. The conference call will also be broadcast over Atlantic Power's website, with an accompanying slide presentation. Please call or log in 10 minutes prior to the call. The telephone numbers to listen to the conference call after it is completed (Instant Replay) are U.S. Toll Free: 1-877-344-7529; Canada Toll Free 1-855-669-9658; International Toll: +1-412-317-0088. Please enter conference call number 10053515. The replay will be available 1 hour after the end of the conference call through February 9, 2015 at 9:00 AM ET. The conference call will also be archived on Atlantic Power's website. Copies of certain financial data and other publicly filed documents are filed on SEDAR at www.sedar.com or on EDGAR at www.sec.gov/edgar.shtml under "Atlantic Power Corporation" or on the Company's website. Cautionary Note Regarding Forward-looking Statements Certain statements in this news release may constitute "forward-looking statements," which reflect the expectations of management regarding the future growth, results of operations, performance and business prospects and opportunities of our Company and our projects. These statements, which are based on certain assumptions and describe our future plans, strategies and expectations, can generally be identified by the use of the words "may," "will," "project," "continue," "believe," "intend," "anticipate," "expect" or similar expressions that are predictions of or indicate future events or trends and which do not relate solely to present or historical matters. the progress made by the Company in improving the performance of its projects and reducing its costs should benefit future periods; the Company's expectation that it will fund attractive investments in existing projects with existing Free Cash Flow, and will evaluate potential asset sales and partnerships with the intended use of proceeds to reduce high-cost debt; deleveraging, reducing the Company's financial risk and lowering its cost of capital should improve the Company's ability to regain effective access to the capital markets, which would allow the Company to grow as well as address debt maturities in 2017 and beyond; the Company's focus on improving its credit metrics to achieve competitive cost of capital and ready access to capital markets through targeted reductions in leverage using proceeds from selective asset sales under consideration, the repurchase of outstanding debt securities where economically attractive, including the planned implementation of a normal course issuer bid for at least $15 million and up to 10% of outstanding convertible debt securities ($35 million); the Company's ability to achieve its targeted credit metrics by the end of 2016; the Company's intention to deploy capital in high return projects, including by continuing to make optimization investments in its existing fleet with attractive returns and targeting approximately $5 to $10 million of such investments in 2015, and to aggressively reduce corporate expenses; the Company's longer-term goal of successfully pursuing value-enhancing acquisition, development or joint venture opportunities; the Company will achieve expected annual interest rating savings of $2.7 million in 2015 in connection with the repayment at maturity of the Company's Cdn$44.8 million convertible debenture on October 31; the Company's targeted general credit profile with (i) Consolidated Debt to Adjusted EBITDA ratio in the range of 5.0-5.75x, (ii) Consolidated Debt to Total Capitalization ratio of approximately 60% and (iii) Adjusted EBITDA to Interest Coverage multiple of 2.5x or better; 2014 Project Adjusted EBITDA will be in the range of $285 to $300 million; 2014 APLP Project Adjusted EBITDA will be in the range of $165 to $175 million; 2014 Free Cash Flow will be in the range of $0 to $10 million, excluding refinancing and debt repurchase transaction costs and principal repayment of Piedmont construction debt; the Company will reduce total debt on a net basis by approximately $85 million this year; Piedmont will be unable to pass its debt service coverage ratio covenant for at least the next 18 months and as a result, will not make distributions for at least the next 18 months; the Company's steps to minimize plant costs following the expiration of the Tunis PPA; APLP term loan repayments for the full year will total approximately $53 million; the Company expects to realize additional G&A cost savings of at least $7 million in 2015, for a total run-rate reduction of at least $15 million relative to 2013; the Company expects to have lower project and business development expenses, including a $3 million annual benefit from the scheduled expiration of a contractual obligation related to the Ridgeline acquisition beginning in the first quarter of 2015; the Company expects to have lower legal expenses associated with the purported class action shareholder litigation, and expects that additional costs incurred in connection with such purported class action shareholder litigation will be paid by the Company's directors and officers insurance carrier to the extent set forth under the terms of its coverage; the Company will have project capital expenditures and major maintenance expenses of approximately $35 million in 2014, including optimization initiatives of approximately $18 million; major maintenance expense and maintenance capex will average approximately $25 million annually, versus approximately $20 million in 2014; the level of optimization investments will be approximately $18 million in 2014, for a two-year (2013 and 2014) total of approximately $27 million, and that these investments will produce a cash flow run-rate contribution of at least $8 million annually on a run-rate basis in 2015, with at least half of that already realized in 2014 from investments completed to date; the Company will have annual optimization capex on average of approximately $5 to $10 million; major maintenance and capex for 2015 will be in the range of $30 to $35 million, including approximately $5 to $10 million in discretionary optimization projects; and the results of operations and performance of the Company's projects, business prospects, opportunities and future growth of the Company will be as described herein. Please refer to the factors discussed under "Risk Factors" and "Forward-Looking Information" in the Company's periodic reports as filed with the Securities and Exchange Commission from time to time for a detailed discussion of the risks and uncertainties affecting the Company, including, without limitation, the Company's ability to evaluate and/or implement a broad range of potential options, including further selected asset sales or joint ventures to raise additional capital for growth or potential debt reduction. The Company's ability to achieve its longer-term goals, including those described in this news release, is based on significant assumptions relating to and including, among other things, the general conditions of the markets in which it operates, revenues, internal and external growth opportunities, its ability to sell assets at favorable prices or at all and general financial market and interest rate conditions. The Company's actual results may differ, possibly materially and adversely, from these goals. Table 5 - Consolidated Balance Sheets (in millions of U.S. dollars) December 31, Assets Current assets: Current portion of derivative instruments asset Prepayments and other current assets Refundable income taxes Total current assets Property, plant and equipment, net Equity investments in unconsolidated affiliates Other intangible assets, net Derivative instruments asset Deferred financing costs Other assets Total assets Liabilities and Shareholder's Equity Current liabilities: Accrued interest Other accrued liabilities Current portion of long-term debt Current portion of convertible debentures Current portion of derivative instruments liability Dividends payable Other current liabilities Total current liabilities Long-term debt Convertible debentures Derivative instruments liability Deferred income taxes Power purchase and fuel supply agreement liabilities, net Other non-current liabilities Commitments and contingencies Total liabilities Equity Common shares, no par value, unlimited authorized shares; 120,806,572 and 120,205,813 issued and outstanding at September 30, 2014 and December 31, 2013, respectively Preferred shares issued by a subsidiary company Accumulated other comprehensive loss Retained deficit Total Atlantic Power Corporation shareholders' equity Noncontrolling interests Total equity Total liabilities and equity Table 6 - Consolidated Statements of Operations in millions of U.S. dollars, except per share amounts Three months ended Nine months ended Project revenue: Energy sales Energy capacity revenue Project expenses: Fuel Operations and maintenance Development Depreciation and amortization Project other income (expense): Change in fair value of derivative instruments Equity in earnings of unconsolidated affiliates Interest expense, net Impairment Administrative and other expenses (income): Administration Interest, net Other income, net Loss from continuing operations before income taxes Income tax expense (benefit) Loss from continuing operations Net loss from discontinued operations, net of tax (1) Net loss Net loss attributable to noncontrolling interest Net income attributable to preferred share dividends of a subsidiary company Net loss attributable to Atlantic Power Corporation Basic earnings per share: Loss from continuing operations attributable to Atlantic Power Corporation Loss from discontinued operations, net of tax Diluted earnings per share: (1) Includes contributions from the Sold Projects and Path 15, which are a component of discontinued operations. Table 7 - Consolidated Statements of Cash Flows (in millions of U.S. dollars) Cash flows from operating activities: Adjustments to reconcile to net cash provided by operating activities Loss of discontinued operations Gain on sale of asset Gain on sale of equity investment Long-term incentive plan expense Impairment charges Equity in earnings from unconsolidated affiliates Distributions from unconsolidated affiliates Unrealized foreign exchange gain Change in deferred income taxes Change in other operating balances Prepayments, refundable income taxes and other assets Accruals and other liabilities Cash provided by operating activities Cash flows provided by investing activities Change in restricted cash Proceeds from sale of asset, net Proceeds from sale of equity investment asset, net Proceeds from treasury grant Biomass development costs Construction in progress Purchase of property, plant and equipment Cash provided by investing activities Cash flows used in financing activities Proceeds from senior secured term loan facility Proceeds from project-level debt Repayment of corporate and project-level debt Payments for revolving credit facility borrowings Equity contribution from noncontrolling interest Offering costs related to tax equity Dividends paid to common shareholders Dividends paid to noncontrolling interests Cash used in financing activities Net (decrease) increase in cash and cash equivalents Less cash at discontinued operations Cash and cash equivalents at beginning of period at discontinued operations Cash and cash equivalents at beginning of period Cash and cash equivalents at end of period Supplemental cash flow information Interest paid Income taxes paid, net Accruals for construction in progress Regulation G Disclosures Project Adjusted EBITDA, Cash Distributions from Projects and Free Cash Flow are not measures recognized under GAAP and do not have standardized meanings prescribed by GAAP. Management believes that Free Cash Flow and Cash Distributions from Projects are relevant supplemental measures of the Company's ability to earn and distribute cash returns to investors. Reconciliations of Free Cash Flow to cash flows from operating activities and of Cash Distributions from Projects to Project income (loss) are provided in Table 10 on page 17 of this release. Investors are cautioned that the Company may calculate these measures in a manner that is different from other companies. Free Cash Flow is defined as cash flows from operating activities less capex; project-level debt repayments, including amortization of the new term loan; and distributions to noncontrolling interests, including preferred share dividends. Project Adjusted EBITDA is defined as project income (loss) plus interest, taxes, depreciation and amortization (including non-cash impairment charges) and changes in the fair value of derivative instruments. Project Adjusted EBITDA is not a measure recognized under GAAP and is therefore unlikely to be comparable to similar measures presented by other companies and does not have a standardized meaning prescribed by GAAP. Management uses Project Adjusted EBITDA at the project level to provide comparative information about project performance and believes such information is helpful to investors. A reconciliation of Project Adjusted EBITDA to project income (loss) and a bridge to Cash Distributions from Projects are provided in Table 8 below and Tables 9A and 9B on page 16, respectively. Investors are cautioned that the Company may calculate this measure in a manner that is different from other companies. Table 8 - Project Adjusted EBITDA by Segment (in millions of U.S. dollars) Project Adjusted EBITDA by segment East (1) West (2) Un-allocated corporate (3) Reconciliation to project income Change in the fair value of derivative instruments Other expense (1) Excludes Auburndale, Lake and Pasco, which are components of discontinued operations. (2) Excludes Greeley and Path 15, which are components of discontinued operations. (3) Excludes Rollcast, which is a component of discontinued operations. Note: Table 8 presents Project Adjusted EBITDA, which is not a recognized measure under GAAP and does not have any standardized meaning prescribed by GAAP; therefore, this measure may not be comparable to a similar measure presented by other companies. Adjusted EBITDA is defined as (i) for the Company's consolidated projects: project income (loss) plus interest, taxes, depreciation and amortization (including non-cash impairment charges) and changes in the fair value of derivative instruments, plus (ii) for the Company's equity-method projects: cash distributions to the Company from these projects; less (iii) corporate administration expense as shown on the Company's consolidated statement of operations. Adjusted EBITDA is not a measure recognized under GAAP and is therefore unlikely to be comparable to similar measures presented by other companies and does not have a standardized meaning prescribed by GAAP. Adjusted EBITDA to Interest Coverage ratio is defined as Adjusted EBITDA divided by the sum of (ii) project-level interest expense, net, as shown on the Company's consolidated statement of operations, and (ii) corporate interest expense, net, as shown on the Company's consolidated statement of operations. Table 9A - Cash Distributions from Projects (by Segment, in millions of U.S. dollars) Nine months ended September 30, 2014 (Unaudited) Repayment of long-term debt Capital expenditures Other, including changes in working capital Segment Consolidated Equity method Total consolidated Total equity method Un-allocated corporate Note: Table 9A presents Cash Distributions from Projects and Project Adjusted EBITDA, which are not recognized measures under GAAP and do not have any standardized meanings prescribed by GAAP; therefore, these measures may not be comparable to similar measures presented by other companies. Table 9B - Cash Distributions from Projects (by Segment, in millions of U.S. dollars) Nine months ended September 30, 2013 (Unaudited) Note: Table 9B presents Cash Distributions from Projects and Project Adjusted EBITDA, which are not recognized measures under GAAP and do not have any standardized meanings prescribed by GAAP; therefore, these measures may not be comparable to similar measures presented by other companies. Table 10 - Free Cash Flow (in millions of U.S. dollars) Other (income) expense Administrative and other expenses (income) Income tax (benefit) expense Net loss from discontinued operations, net of tax Term loan facility repayments (1) Project-level debt repayments Purchases of property, plant and equipment (2) Distributions to noncontrolling interests (3) Dividends on preferred shares of a subsidiary company (1) Includes mandatory 1% annual amortization and 50% excess cash flow repayments by the Partnership. (2) Excludes construction costs related to our Canadian Hills project in 2014 and 2013 and our Piedmont and Meadow Creek projects in 2013. (3) Distributions to noncontrolling interests primarily include distributions, if any, to the tax equity investors at Canadian Hills and to the other 50% owner of Rockland. Note: Table 10 presents Cash Distributions from Projects, Project Adjusted EBITDA and Free Cash Flow, which are not recognized measures under GAAP and do not have any standardized meanings prescribed by GAAP; therefore, these measures may not be comparable to similar measures presented by other companies. Table 11 - Project Adjusted EBITDA by Project (for Selected Projects) in millions of U.S. dollars Accounting Cadillac Curtis Palmer Morris Nipigon North Bay Other (1) Chambers Selkirk Orlando Manchief Naval Station Williams Lake Other (2) Frederickson Other (3) Canadian Hills Meadow Creek Rockland Other (4) Totals Consolidated projects Equity method projects Total Project Adjusted EBITDA Reconciliation to project income (loss) (1) Kenilworth, Calstock, and Kapuskasing (2) Moresby Lake, Mamquam, North Island, Naval Training Station, and Oxnard (3) Q3 and YTD September 2013: Koma Kulshan, Gregory, and Delta-Person; Q3 and YTD September 2014: Koma Kulshan and Delta-Person (4) Idaho Wind and Goshen North Notes: Table 11 presents Project Adjusted EBITDA, which is not a recognized measure under GAAP and does not have any standardized meaning prescribed by GAAP; therefore, this measure may not be comparable to a similar measure presented by other companies. The Company has not reconciled non-GAAP financial measures relating to individual projects to the directly comparable GAAP measures due to the difficulty in making the relevant adjustments on an individual project basis.