DEDHAM, Mass., Nov. 1, 2018 /PRNewswire/ --

Third Quarter 2018 Financial Highlights

• Net loss attributable to Atlantic Power of $(3.2) million in Q3 2018 vs. $(32.9) million in Q3 2017
• Project income of $26.2 million in Q3 2018 vs. project loss of $(20.9) million in Q3 2017
• Cash from operating activities of $19.5 million in Q3 2018 decreased from $52.9 million in Q3 2017
• Project Adjusted EBITDA of $45.4 million in Q3 2018 decreased from $77.4 million in Q3 2017
• Repaid $20.8 million of term loan and project debt in Q3 2018 and $79.5 million year to date; leverage ratio of 4.5 times at September 30, 2018
• Repurchased and canceled approximately 1.4 million common shares and approximately 284 thousand preferred shares in the third quarter of 2018, at a total cost of approximately $6.5 million
• Liquidity at September 30, 2018 was $180.6 million, including approximately $32 million of discretionary cash
• Announced an agreement to acquire two contracted biomass plants in South Carolina with a total capacity of 40 megawatts (MW) for $13 million; expected closing in late Q3 or Q4 2019

Recent Developments

• Repurchased and canceled approximately 288 thousand common shares in October 2018
• Executed fourth re-pricing of term loan and revolver, reducing spread by another 25 basis points
• Returned Tunis to commercial operation under 15-year contract on October 4, 2018
• Nipigon's Long-Term Enhanced Dispatch Contract went into effect on November 1, 2018

2018 Guidance

• Reaffirmed 2018 Project Adjusted EBITDA guidance (see page 6 of this news release)

Atlantic Power Corporation (NYSE: AT) (TSX: ATP) ("Atlantic Power" or the "Company") today reported its financial results for the three and nine months ended September 30, 2018.  Net loss was reduced and project income increased in the third quarter of 2018, primarily because the 2017 period included $57.3 million of impairment expense, which did not recur in 2018.  Cash from operating activities and Project Adjusted EBITDA declined in the third quarter of 2018 primarily because of Power Purchase Agreement (PPA) expirations in late 2017 and early 2018 and the non-recurrence of OEFC Settlement revenue recorded in 2017, as expected.  Continued below-average water flows at Curtis Palmer also contributed to the decline.  In addition, cash from operating activities was affected by the timing of the September distribution from Orlando, which was received on October 1.  Impairment expense is not included in Project Adjusted EBITDA or cash flow.

"Third quarter results were in line with our expectations and keep us on plan to achieve our 2018 guidance.  We repaid $20.8 million of debt during the quarter and just this week we announced another successful re-pricing of our term loan.  We also invested $6.5 million in common and preferred share repurchases this quarter.  In September we announced an agreement to acquire two biomass projects in South Carolina for $13 million, which represents our second external growth investment this year," said James J. Moore, Jr., President and CEO of Atlantic Power. 

Mr. Moore continued, "Over the next few years we expect to continue reducing our debt levels meaningfully using the significant recurring cash flow from our existing businesses.  At the same time, our strong liquidity enables us to buy back common and preferred shares and make additional growth investments, when these are accretive to intrinsic value per share."

Financial Results for the Three Months Ended September 30, 2018

Consolidation of Koma Kulshan

On July 27, 2018, the Company closed the acquisition of the remaining 50% partnership interest in Koma Kulshan held by Covanta.  As a result, the Company owns 100% of the project and consolidated the project in its financial statements from that date.  For periods prior to that date, Koma is included as an equity method investment.  The impact on revenues for the third quarter of 2018 was immaterial.  The purchase price allocation (discussed in the Company's report on Form 10-Q) resulted in a $6.7 million gain included in other income for the step-up of the carrying value of the Company's investment in its original 50% partnership interest in the project.  This is a non-cash gain and is not included in Project Adjusted EBITDA.      

Key Business Drivers

The most significant business drivers in the third quarter of 2018 were the expirations of the PPAs at Kapuskasing and North Bay in Ontario at year-end 2017, the early terminations of the PPAs for the three San Diego projects effective March 1, 2018, and the short-term contract extension at Williams Lake (less favorable economics) effective April 2, 2018.  The impact of these was as expected.  In addition, results were affected by continued below-average water flows at Curtis Palmer.

Net Loss, Project Income and Project Adjusted EBITDA

Net loss attributable to Atlantic Power Corporation for the third quarter of 2018 was $(3.2) million compared to $(32.9) million in the third quarter of 2017.  The $29.7 million reduction in loss was primarily attributable to a $47.1 million increase in Project income (discussed below), a $4.9 million reduction in unrealized foreign exchange loss, which was related to the revaluation of debt denominated in Canadian dollars (the Canadian dollar appreciated during the quarter, but to a smaller degree than in the comparable 2017 period), and a $3.5 million gain on the repurchase of the Company's preferred shares.  These positive factors were partially offset by a $19.5 million increase in income tax expense, which was attributable to changes in the U.S. tax law.    

Project income for the third quarter of 2018 was $26.2 million as compared to a project loss of $(20.9) million in the year-ago period.  The most significant driver of the $47.1 million improvement was the non-recurrence of $57.3 million of impairment expense recorded at the San Diego projects in the 2017 period.  Project income also benefited from the $6.7 million purchase accounting gain recorded at Koma.  Piedmont benefited from lower interest expense as a result of the repayment of its project debt in October 2017.  These positive variances were partially offset by lower project income at Curtis Palmer, due to lower water flows than the comparable 2017 period (-$3.2 million); at Williams Lake, due to a PPA extension on less favorable terms (-$3.2 million); at Kapuskasing and North Bay, due to PPA expirations, partially offset by lower depreciation expense (-$2.6 million) and to smaller decreases at Nipigon, Cadillac and Kenilworth.    

Project Adjusted EBITDA for the third quarter of 2018 declined to $45.4 million from $77.4 million in the third quarter of 2017.  The $32.0 million decrease was primarily attributable to the expiration of contracts at Kapuskasing and North Bay at year end 2017 (-$11.3 million); the early termination of the PPAs for the three San Diego projects effective March 1, 2018 (-$11.3 million); a less favorable short-term PPA at Williams Lake (-$5.0 million), and lower water flows at Curtis Palmer (-$3.3 million).  These decreases were partially offset by modest increases at other projects. 

Cash Flow

Cash provided by operating activities for the third quarter of 2018 declined to $19.5 million from $52.9 million in the third quarter of 2017.  Most of the $33.4 million reduction in operating cash flow was attributable to the $32.0 million reduction in Project Adjusted EBITDA.  Distributions from unconsolidated affiliates declined $3.6 million, but this was a timing issue as the September distribution from Orlando was not received until October 1 ($3.6 million).  On the positive side, cash interest payments were $0.7 million lower in the 2018 period (resulting from debt repayment and a lower spread on the Company's credit facilities).

Cash used in investing activities for the third quarter of 2018 was $(14.5) million compared to $(1.5) million in the third quarter of 2017.  In the 2018 period the Company used $(11.7) million of cash (net of cash received) to acquire Covanta's 50% partnership interest in Koma Kulshan and buy out the operation and maintenance contract from Covanta and $(2.6) million for the deposit required under the agreement to acquire the two South Carolina biomass plants.

Cash used in financing activities for the third quarter of 2018 was $(29.7) million as compared to $(35.0) million in the year-ago period.  The Company repaid $(20.8) million of term loan and project debt, repurchased $(3.1) million of common shares and $(3.4) million (US$ equivalent) of preferred shares, and paid $(2.1) million of preferred dividends.  In the comparable 2017 period, the Company repaid $(29.4) million of term loan and project debt, repurchased $(3.3) million (US$ equivalent) of preferred shares and paid $(2.3) million of preferred dividends.

During the third quarter, the Company had a $24.7 million net decrease in cash, restricted cash and cash equivalents.         

Financial Results for the Nine Months Ended September 30, 2018

Key Business Drivers

As with the second quarter, the most significant business drivers in the first nine months of 2018 were the expirations, early terminations and short-term extensions of the PPAs at Kapuskasing, North Bay, the San Diego projects and Williams Lake, as previously described, maintenance costs associated with the Tunis re-start in the first six months of 2018 and the Manchief gas turbine overhaul in the second quarter of 2018, and lower water flows at Curtis Palmer than in 2017.  These declines were partially offset by increases at Morris, Frederickson, Nipigon, Orlando and Mamquam.  Overall, results for the year to date were in line with the Company's expectations. 

Net Income, Project Income and Project Adjusted EBITDA

Net income attributable to Atlantic Power Corporation for the first nine months of 2018 was $12.1 million compared to a net loss of $(57.5) million in the first nine months of 2017.  The $69.6 million improvement was primarily attributable to a $75.7 million increase in Project income (discussed below); a $26.8 million increase in unrealized foreign exchange gain ($9.1 million gain versus a $17.7 million loss), which was related to the revaluation of debt denominated in Canadian dollars (due to the depreciation of the Canadian dollar during the first nine months of 2018, compared to an appreciation in the comparable 2017 period); an $8.8 million reduction in corporate interest expense as a result of debt repayment and re-pricing of the Company's credit facilities; and a $7.9 million gain on the repurchase of the Company's preferred shares.  These positive factors were partially offset by a $46.2 million increase in income tax expense, which was attributable to an increase in pretax income and changes in the U.S. tax law.    

Project income for the first nine months of 2018 increased to $68.0 million from a project loss of $(7.7) million in the year-ago period.  The $75.7 million improvement was primarily attributable to the non-recurrence of $57.7 million of impairment expense recorded at Chambers and Selkirk and $57.3 million of impairment expense recorded at the three San Diego projects in 2017 ($115 million in total).  Other positive variances included Piedmont ($5.9 million), due to lower interest expense resulting from repayment of the project's debt in October 2017; Frederickson ($5.8 million), due to lower maintenance expense than in 2017; Orlando ($5.6 million), due to a change in the fair value of derivatives and higher availability and contractual capacity rates than in 2017; and Morris ($4.6 million), due to higher energy and capacity revenues.  These positive variances were partially offset by the impact of PPA expirations and early terminations at Kapuskasing and North Bay (-$29.3 million) and the three San Diego projects (-$13 million, excluding the benefit associated with non-recurrence of the impairment); project loss at Tunis (-$10.8 million), due to maintenance expense associated with the planned re-start of the facility in 2018 and the non-recurrence of the OEFC Settlement revenues recorded in 2017; at Curtis Palmer (-$6.4 million), due to lower water flows than the comparable 2017 period; and at Manchief (-$6.1 million), due to the gas turbine overhaul in the second quarter of 2018. 

Project Adjusted EBITDA for the first nine months of 2018 declined to $138.5 million from $226.6 million in the first nine months of 2017.  The $88.1 million decrease was primarily attributable to the expiration of contracts at Kapuskasing and North Bay at year end 2017 (-$54.2 million); the early termination of the PPAs for the three San Diego projects effective March 1, 2018 (-$21.7 million); maintenance expenses incurred at Tunis in preparation for re-start incurred in 2018 and the non-recurrence of OEFC Settlement revenues recorded in 2017 (-$10.8 million); a less favorable short-term PPA at Williams Lake, partially offset by cost reductions (-$6.8 million); lower water flows at Curtis Palmer (-$6.4 million), and maintenance expenses associated with the Manchief gas turbine overhaul in the second quarter of 2018 (-$6.1 million).  Partially offsetting these decreases were increases at Morris ($6.2 million), due to a higher capacity price realized in the PJM capacity auction for this year, higher steam and ancillary services revenues, higher merchant dispatch and lower expenses; Frederickson ($3.0 million), due to maintenance expense in 2017; Nipigon ($2.9 million), due to a contractual rate increase, lower fuel costs and other factors; Orlando ($2.6 million), due to higher availability and higher contractual capacity rates; Mamquam ($2.6 million), due to higher water flows and lower maintenance expense; and modest increases at other projects. 

Cash Flow

Cash provided by operating activities for the first nine months of 2018 declined $40.9 million to $97.8 million from $138.7 million in the first nine months of 2017.  Operating cash flow was negatively affected by the $88.1 million reduction in Project Adjusted EBITDA.  However, this impact was partially offset by $34.6 million of net favorable changes in working capital, particularly a $29.2 million decrease in working capital at Kapuskasing, North Bay and the three San Diego projects, as they were not in operation at September 30, 2018.  In addition, cash interest payments were $13.9 million lower in the first nine months of 2018 than in the comparable 2017 period, as a result of debt repayment and a lower spread on the Company's credit facilities, and distributions from unconsolidated affiliates increased $6.5 million (mostly at Frederickson and Orlando).

Cash used in investing activities for the first nine months of 2018 was $(16.9) million compared to $(5.7) million in the first nine months of 2017.  In the 2018 period the Company used $(12.8) million of cash (net of cash received) to acquire additional ownership interests in Koma Kulshan and buy out the operation and maintenance contract and $(2.6) million for the deposit required under the agreement to acquire the two South Carolina biomass plants.  Capital expenditures in the 2018 period were $4.2 million lower than in the 2017 period.

Cash used in financing activities for the first nine months of 2018 was $(107.9) million as compared to $(97.0) million in the year-ago period.  In the 2018 period, the Company issued $92.2 million (US$ equivalent) of new convertible debentures and used the proceeds to redeem ($88.1) million of existing convertible debentures.  It also repaid $(79.5) million of term loan and project debt, repurchased $(12.3) million of common shares and $(8.0) million (US$ equivalent) of preferred shares, paid $(6.3) million of preferred dividends and incurred $(5.1) million of deferred financing costs.  In the comparable 2017 period, the Company repaid $(86.3) million of term loan and project debt, repurchased $(3.1) million (US$ equivalent) of preferred shares and paid $(6.5) million of preferred dividends.

During the first nine months of 2018, the Company had a $27.0 million net decrease in cash, restricted cash and cash equivalents.         

Liquidity and Balance Sheet 

Liquidity

As shown in Table 2, the Company's liquidity at September 30, 2018 was $180.6 million, down from $203.4 million at June 30, 2018.  Revolver availability was largely unchanged at $123 million, but the Company's unrestricted cash of $57.6 million declined $23.2 million.  During the quarter the Company used $12.5 million of cash for the acquisition of Covanta's 50% partnership interest in Koma Kulshan, $6.5 million for repurchases of the Company's common and preferred shares, and $2.6 million for the deposit associated with the South Carolina biomass acquisition. 

The mix of cash between the parent and projects, as shown in Table 2, reflects the release during the quarter of cash from the projects (to the parent) as working capital needs were reduced at those projects not in operation due to PPA expirations.  This occurred in the second quarter as well.  At September 30, 2018, there was $39.1 million of cash at the parent, of which the Company considers approximately $32 million to be discretionary cash available for general corporate purposes. 

Balance Sheet

Debt Repayment

During the third quarter of 2018, the Company repaid $20 million of the APLP Holdings term loan and amortized $750 thousand of project-level debt.  Year to date through September 30, 2018, the Company has repaid $70 million of the term loan and $9.5 million of project debt.  This is consistent with the Company's plan to repay $90 million of the term loan and amortize $10 million of project debt in 2018. 

At September 30, 2018, the Company's consolidated debt was $762 million, excluding unamortized discounts and deferred financing costs, and the Company's consolidated leverage ratio (consolidated gross debt to trailing 12-month consolidated Adjusted EBITDA) was 4.5 times. 

Debt Maturity Profile

The substantial majority of the Company's debt is amortizing in nature.  The next bullet maturity is in December 2019, when the remaining Cdn$24.7 million of 6.00% Series D Debentures mature; these are callable at par at any time prior to maturity.  The Company has no bullet maturities in 2020 or 2021.  The Company's $200 million revolving credit facility matures in April 2022.  The $470 million APLP Holdings term loan has an April 2023 maturity, although it is expected to be more than 80% repaid (through amortization and the sweep) by the maturity date.  The Cdn$115.0 million of 6.00% Series E Debentures issued in January 2018 have a January 2025 maturity date. 

Re-pricing of Term Loan and Revolver

As previously reported in its October 31, 2018 press release, the Company executed a re-pricing of the APLP Holdings term loan and revolving credit facility, reducing the interest rate margin on the term loan and revolver by 25 basis points, to LIBOR plus 275 basis points.  This represented the fourth re-pricing for these facilities since April 2017, resulting in a cumulative reduction in the spread of 225 basis points.  The Company expects to realize, before related transaction costs, $1.2 million of interest cost savings in 2019 and $3.25 million over the remaining terms of the facilities, as a result of the 25 basis point reduction.  The combined savings of the four re-pricing transactions are expected to be approximately $44.4 million over the remaining terms of the facilities.  Transaction costs associated with the re-pricing will be included in interest expense in the fourth quarter of 2018.

Normal Course Issuer Bid (NCIB) Update

The Company has in place an NCIB for its common and preferred shares and convertible debentures.  In the third quarter of 2018, the Company repurchased and canceled approximately 1.4 million common shares at a total cost of $3.1 million, or an average price of $2.15 per share.  Also in the third quarter of 2018, the Company repurchased and canceled 237,500 shares of the 4.85% Cumulative Redeemable Preferred, Series 1 at Cdn$15.30 per share; 5,000 shares of the Cumulative Rate Reset Preferred, Series 2 at Cdn$17.99 per share; and 41,695 shares of the Cumulative Floating Rate Preferred, Series 3 at Cdn$17.95 per share, for a total cost of Cdn$4.5 million (US$3.4 million equivalent).  With these repurchases, the Company has reached the 10% limit on repurchases of Series 1 and Series 3 preferred shares under this NCIB.

In October 2018, the Company repurchased and canceled another 288 thousand common shares at a total cost of $619 thousand, or an average price of $2.15 per share. 

For the year to date October 31, 2018, the Company has repurchased and canceled a total of approximately 6.1 million common shares at a total cost of $12.9 million, or an average price of $2.12 per share, and has repurchased and canceled 475,000 shares of the 4.85% Cumulative Redeemable Preferred, Series 1; 5,000 shares of the Cumulative Rate Reset Preferred, Series 2; and 164,790 shares of the Cumulative Floating Rate Preferred, Series 3, at a total cost of Cdn$10.3 million (US$8.0 million equivalent). 

2018 Guidance

The Company has not provided guidance for Project income or Net income because of the difficulty of making accurate forecasts and projections without unreasonable efforts with respect to certain highly variable components of these comparable GAAP metrics, including changes in the fair value of derivative instruments and foreign exchange gains or losses.  These factors, which generally do not affect cash flow, are not included in Project Adjusted EBITDA.    

The Company is reaffirming its guidance for 2018 Project Adjusted EBITDA in the range of $170 to $185 million.  Although continued below-average water flows at Curtis Palmer and a delayed re-start at Tunis hurt results modestly relative to the Company's original expectations, this has been offset by better results elsewhere in the portfolio.      

Table 3 provides a bridge of the Company's 2018 Project Adjusted EBITDA guidance to Cash provided by operating activities.  This bridge is unchanged from that presented in the Company's second quarter 2018 financial results release.  For purposes of providing this bridge to a cash flow measure, the impact of changes in working capital is assumed to be nil.  It should be noted that for the nine months ended September 30, 2018, changes in working capital have had a positive impact on operating cash flow as a result of decreases in working capital at those projects not in operation due to PPA expirations and early terminations (Kapuskasing, North Bay and the three San Diego projects).

Commercial and Operational Updates

Agreement to Acquire Two Contracted Biomass Plants in South Carolina

In September 2018, the Company announced an agreement to acquire the Allendale and Dorchester biomass plants in South Carolina from EDF Renewables for $13 million.  The plants have been in commercial operation since 2013.  Each has a capacity of 20 MW, and all of the output is sold to Santee Cooper under PPAs that run to 2043.  Closing of the acquisition is expected to occur late in the third quarter or the fourth quarter of 2019 following a restructuring of the plants' ownership structure by EDF Renewables.  The purchase is expected to be funded from the Company's discretionary cash.  Upon execution of the agreement, the Company paid $2.6 million of the purchase price, which is being held in escrow and is included in the Company's other assets at September 30, 2018. 

2018-2019 PPA Expirations

The Company has five projects with PPAs that expired in 2018 or are scheduled to expire in 2019:

Naval Station, North Island and NTC (San Diego).  As previously reported, these plants have not been in operation since February 7, 2018, when the land use agreements with the U.S. Navy that provided the Company the right to use the sites expired.  The PPAs with San Diego Gas & Electric (SDG&E) were terminated effective March 1, 2018.  The Company executed new power contracts for all three plants, which were conditioned on the Company obtaining the right to remain on the Navy sites for the contract term ("site control").  Although the Company had been in discussions with the Navy regarding site control for two of the three sites, these discussions were terminated in August.  The Company is required by its land use agreements with the Navy to decommission the sites and has begun preparations to do so.  The cost and timing of the decommissioning are dependent on the scope of work, which is still to be determined together with the Navy.  The Company expects that the substantial majority of the cash outlays will be incurred in 2019.   

Williams Lake (British Columbia).  Since April 2, 2018, the project has been operating under an amended energy purchase agreement with BC Hydro, which provides for a short-term extension to June 30, 2019, or September 30, 2019 at the option of BC Hydro.  The amended contract is subject to the approval of the BC Utilities Commission (BCUC).  The BCUC recently extended the schedule for review of the contract and a decision is not expected until near year-end 2018 or in early 2019.  BC Hydro and the Company recently extended the date on which either party will have the right to provide notice of intended contract termination if the contract has not received BCUC approval to February 28, 2019.       

Kenilworth.  The Energy Services Agreement with Merck expires in September 2019, although the customer has two remaining one-year renewal options under the agreement.

Tunis Commercial Operation

On October 4, 2018, the Company returned the Tunis plant to commercial operation under a 15-year PPA with the Ontario Independent Electricity System Operator (IESO).  Tunis will operate in dispatchable mode and receive monthly capacity payments based on an average contracted capacity of 36.5 MW.  It also will earn energy revenues for those periods during which it operates. 

Tunis had not been in operation since December 2014.  The re-start required overhauls of the gas turbine and the project's generator and upgrades of the gas turbine control system and other systems, at a total cost of approximately $5 million (US$ equivalent).  Most of the costs were incurred in the first six months of 2018 and all of the costs were expensed. 

Nipigon Contract Update

On November 1, 2018, Nipigon's Long-Term Enhanced Dispatch Contract (LTEDC) went into effect, replacing the original PPA for the project while retaining the same expiration date (December 2022).  Nipigon will receive monthly capacity-type payments, with adjustment for operational savings that will be shared with the IESO.  It will operate on a flexible basis (when needed or economic), earning energy revenues for those periods during which it operates.  The Company plans to install upgrades to some of the project's components and systems in 2019, although Nipigon did not require an overhaul such as the one for Tunis prior to the LTEDC becoming effective.

Maintenance and Capex

In the third quarter of 2018, the Company incurred $5.8 million of maintenance expense.  Through September 30 of this year, the Company incurred maintenance expense of $27.8 million and made capital expenditures of $1.4 million.  The most significant maintenance expenses this year have been associated with the Tunis re-start (in the first six months) and the Manchief gas turbine outage (in the second quarter).  For the full year, the Company estimates that maintenance expense will total approximately $33.4 million (down from the previous expectation of $34.8 million) and capital expenditures approximately $1.8 million.  (All of these figures include the Company's proportional share of maintenance expenses and capital expenditures at equity method investments.)       

Supplementary Information Regarding Non-GAAP Disclosures

A discussion of non-GAAP disclosures and schedules reconciling Project Adjusted EBITDA, a non-GAAP measure, to the comparable GAAP measure, can be found on page 14 of this release.

Information by Project

A schedule of Project income (loss), Project Adjusted EBITDA and Cash Distributions by project can be found in the third quarter 2018 presentation on the Company's website.  Cash Distributions from Projects is the amount of cash distributed by the projects to the Company out of available project cash flow after all project-level operating costs, interest payments, principal repayment, capital expenditures and working capital requirements. 

Investor Conference Call and Webcast

Atlantic Power's management team will host a telephone conference call and webcast on Friday, November 2, 2018 at 8:30 AM ET.  Management's prepared remarks and an accompanying presentation will be available on the Conference Calls page of the Company's website prior to the call.  

Conference Call / Webcast Information:

Date:  Friday, November 2, 2018 
Start Time:  8:30 AM ET
Phone Number:  U.S. (Toll Free) 1-855-239-3193; Canada (Toll Free) 1-855-669-9657; International (Toll) 1-412-542-4129.
Conference Access:  Please request access to the Atlantic Power conference call.
Webcast:  The call will be broadcast over Atlantic Power's website at www.atlanticpower.com.

Replay/Archive Information:

Replay:  Access conference call number 10125391 at the following telephone numbers:  U.S. (Toll Free) 1-877-344-7529; Canada (Toll Free) 1-855-669-9658; International (Toll) 1-412-317-0088.  The replay will be available one hour after the end of the conference call through December 2, 2018 at 11:59 PM ET.     

Webcast archive:  The conference call will be archived on Atlantic Power's website at www.atlanticpower.com for a period of 12 months. 

About Atlantic Power

Atlantic Power is an independent power producer that owns power generation assets in nine states in the United States and two provinces in Canada.  The Company's generation projects sell electricity and steam to investment-grade utilities and other creditworthy large customers predominantly under long‑term PPAs that have expiration dates ranging from 2019 to 2037.  The Company seeks to minimize its exposure to commodity prices through provisions in the contracts, fuel supply agreements and hedging arrangements.  The projects are diversified by geography, fuel type, technology, dispatch profile and offtaker (customer).  The majority of the projects in operation are 100% owned and directly operated and maintained by the Company.  The Company has expertise in operating most fuel types, including gas, hydro, and biomass, and it owns a 40% interest in one coal project. 

Atlantic Power's shares trade on the New York Stock Exchange under the symbol AT and on the Toronto Stock Exchange under the symbol ATP.  For more information, please visit the Company's website at www.atlanticpower.com or contact:

Atlantic Power Corporation 
Investor Relations
(617) 977-2700 
[email protected]

Copies of the Company's financial data and other publicly filed documents are available 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.

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Cautionary Note Regarding Forward-Looking Statements

To the extent any statements made in this news release contain information that is not historical, these statements are forward-looking statements within the meaning of Section 27A of the U.S. Securities Act of 1933, as amended, and Section 21E of the U.S. Securities Exchange Act of 1934, as amended, and under Canadian securities law (collectively, "forward-looking statements").

Certain statements in this news release may constitute "forward-looking statements", which reflect the expectations of management regarding the future growth, results of operations, performance and business prospects and opportunities of the Company and its projects.  These statements, which are based on certain assumptions and describe the Company's future plans, strategies and expectations, can generally be identified by the use of the words "may," "will," "project," "continue," "believe," "intend," "anticipate," "expect" or similar expressions that are predictions of or indicate future events or trends and which do not relate solely to present or historical matters.  Examples of such statements in this press release include, but are not limited, to statements with respect to the following: 

• the Company's view that its third quarter and year-to-date September 2018 results were in line with its expectations;
• the Company's expectation that it will continue to reduce its debt levels meaningfully over the next few years;
• the Company's assessment of its cash flow and liquidity and its ability to continue delevering, repurchasing shares and making growth investments;
• the Company's view that approximately $32 million of cash at the parent is available for discretionary purposes;
• the Company's assessment of its working capital needs at its projects;
• the Company's expectation that it will repay $100 million of debt in 2018;
• the Company's estimate that it will have repaid more than 80% of its term loan by the April 2023 maturity date;
• the Company's estimates of interest cost savings resulting from the re-pricing of its term loan and revolver;
• the Company's guidance for 2018 Project Adjusted EBITDA in the range of $170 to $185 million;
• the Company's estimate that with respect to its 2018 guidance, the impact of below-average water flows at Curtis Palmer and the delayed re-start at Tunis will be offset elsewhere in the portfolio;
• the Company's estimate for 2018 Cash provided by operating activities in the range of $95 to $110 million, assuming for this purpose that changes in working capital are nil;
• the Company's estimation that cash outlays associated with the decommissioning of the three San Diego projects will be mostly incurred in 2019;
• the Company's estimation that, in 2018, including its share of equity-owned projects, maintenance expense will total approximately $33.4 million and capital expenditures will total approximately $1.8 million; and
• the results of operations and performance of the Company's projects, business prospects, opportunities and future growth of the Company will be as described herein.

Forward-looking statements involve significant risks and uncertainties, should not be read as guarantees of future performance or results, and will not necessarily be accurate indications of whether or not or the times at or by which such performance or results will be achieved.  Please refer to the factors discussed under "Risk Factors" and "Forward-Looking Information" in the Company's periodic reports as filed with the U.S. Securities and Exchange Commission (the "SEC") from time to time for a detailed discussion of the risks and uncertainties affecting the Company.  Although the forward-looking statements contained in this news release are based upon what are believed to be reasonable assumptions, investors cannot be assured that actual results will be consistent with these forward-looking statements, and the differences may be material.  These forward-looking statements are made as of the date of this news release and, except as expressly required by applicable law, the Company assumes no obligation to update or revise them to reflect new events or circumstances.  

Non-GAAP Disclosures

Project 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 companies.  Investors are cautioned that the Company may calculate this non-GAAP measure in a manner that is different from other companies.  The most directly comparable GAAP measure is Project income (loss).  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.  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 to Net income (loss) on a consolidated basis is provided in Table 7 below. 

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SOURCE Atlantic Power Corporation