DEDHAM, Mass., Aug. 2, 2018 /PRNewswire/ --

Second Quarter 2018 Financial Highlights

• Net loss attributable to Atlantic Power of $(0.6) million in Q2 2018 vs. $(21.9) million in Q2 2017
• Project income of $13.6 million in Q2 2018 vs. project loss of $(12.1) million in Q2 2017
• Both Net loss and Project income (loss) improved from Q2 2017 due primarily to the non-recurrence of $57.7 million impairment expense at Chambers and Selkirk recorded in 2017
• Cash from operating activities of $28.1 million in Q2 2018 decreased from $51.6 million in Q2 2017
• Project Adjusted EBITDA of $39.8 million in Q2 2018 decreased from $85.4 million in Q2 2017
• Lower operating cash flow and Project Adjusted EBITDA resulted from Power Purchase Agreement (PPA) expirations in 2018, non-recurrence of OEFC Settlement revenue recorded in 2017, Manchief gas turbine overhaul in 2018 and Tunis re-start expenses in 2018, as expected
• Repaid $26.4 million of term loan and project debt in Q2 2018 and $58.8 million year to date; leverage ratio of 3.8 times at June 30, 2018
• Repurchased and canceled approximately 1.3 million common shares and 40,000 preferred shares in the second quarter of 2018, at a total cost of approximately $3.4 million
• Liquidity at June 30, 2018 was $203.4 million, including approximately $42 million of discretionary cash

Recent Developments (July 2018)

• Repurchased and canceled approximately 0.3 million common shares and 46,695 preferred shares in July 2018, at a total cost of approximately $1.2 million
• On July 27, 2018, closed the acquisition of Covanta's 50.00% interest in Koma Kulshan and now own 100% of the project

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 six months ended June 30, 2018.  Net loss attributable to Atlantic Power was $(0.6) million for the three months ended June 30, 2018 compared to $(21.9) million in the year-ago period.  Project income was $13.6 million for the three months ended June 30, 2018 compared to project loss of $(12.1) million in the year-ago period.  Cash provided by operating activities declined to $28.1 million for the three months ended June 30, 2018 from $51.6 million in the year-ago period.  Project Adjusted EBITDA for the three months ended June 30, 2018 declined to $39.8 million from $85.4 million in the year-ago period.

"Second quarter results declined primarily due to PPA expirations, but exceeded our expectations and keep us on plan to achieve our 2018 guidance," said James J. Moore, Jr., President and CEO of Atlantic Power.  "During the quarter we repaid $26.4 million of debt, and remain on track to repay $100 million of debt this year.  In addition, we repurchased and canceled $3.4 million of common and preferred shares during the quarter, taking us to a total of $13.7 million for the year to date through June."

Mr. Moore continued, "In early July we announced the acquisition of our partners' interests in the Koma Kulshan hydro facility for a total of $13.2 million.  This was our first external growth investment after three years of focusing on operations and balance sheet improvement.  The significant recurring cash flow from our existing businesses and our strong liquidity enable us to continue delevering and buying back shares when prices are below our estimates of intrinsic value, as well as making additional growth investments when they are accretive to intrinsic value per share."

Financial Results for the Three Months Ended June 30, 2018

Key Business Drivers

The most significant business drivers in the second 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, the short-term contract extension at Williams Lake (less favorable economics) effective April 2, 2018, and maintenance costs associated with the Tunis re-start and the Manchief gas turbine overhaul.  The impact of these drivers on results was as expected.  Overall, though, results were modestly better than anticipated due to positive variances (relative to expectations) at Morris, which benefited from higher steam and ancillary services revenues and lower gas prices;  Mamquam, which experienced significantly better than average water flows; Kenilworth, which benefited from higher merchant energy and steam sales, and other projects.  These positive variances were partially offset by below-average water flows at Curtis Palmer. 

Net Loss, Project Income and Project Adjusted EBITDA

Net loss attributable to Atlantic Power Corporation for the second quarter of 2018 was $(0.6) million compared to $(21.9) million in the second quarter of 2017.  The $21.3 million improvement was primarily attributable to a $25.7 million increase in Project income (discussed below); an $11.3 million increase in unrealized foreign exchange gain ($5.4 million gain versus a $5.9 million loss), most of which was related to the revaluation of debt denominated in Canadian dollars (due to the appreciation of the Canadian dollar during the quarter, compared to a depreciation in the comparable 2017 period), and a $7.3 million reduction in corporate interest expense as a result of debt repayment and re-pricing of the Company's credit facilities.  These positive factors were partially offset by an increase in income tax expense.    

Project income for the second quarter of 2018 was $13.6 million as compared to a project loss of $(12.1) million in the year-ago period.  The most significant driver of the $25.7 million improvement was the non-recurrence of $57.7 million of impairment expense recorded at Chambers and Selkirk in the 2017 period.  In addition, Frederickson and Orlando benefited from lower maintenance expense in 2018, and several other projects recorded modest increases in project income for various reasons.  These positive variances were partially offset by lower project income at Kapuskasing, North Bay, the three San Diego projects and Williams Lake, resulting from PPA expirations and terminations and (for Williams Lake) a PPA extension on less favorable terms; at Tunis, from 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 Manchief, due to the gas turbine overhaul in 2018; and at Curtis Palmer, due to lower water flows than the comparable 2017 period. 

Project Adjusted EBITDA for the second quarter of 2018 declined to $39.8 million from $85.4 million in the second quarter of 2017.  The $45.6 million decrease was primarily attributable to the expiration of contracts at Kapuskasing and North Bay at year-end 2017 (-$28.1 million); maintenance expenses incurred at Tunis in preparation for re-start incurred in 2018 and the absence of OEFC Settlement revenues recorded in 2017 (-$8.1 million); the early termination of the PPAs for the three San Diego projects effective March 1, 2018 (-$7.7 million); maintenance expenses associated with the Manchief gas turbine overhaul in 2018 (-$7.2 million); lower water flows at Curtis Palmer (-$3.5 million), and a less favorable short-term PPA at Williams Lake (-$2.8 million).  Partially offsetting these decreases were increases at Frederickson ($3.0 million), due to maintenance expense in 2017; Orlando ($2.0 million), due to higher availability and higher contractual capacity rates; Morris ($1.7 million), due to a higher capacity price realized in the PJM capacity auction for this year; Mamquam ($1.6 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 second quarter of 2018 declined $23.5 million to $28.1 million from $51.6 million in the second quarter of 2017.  Operating cash flow was negatively affected by the $45.6 million reduction in Project Adjusted EBITDA, but this was partially offset by $13.8 million of net favorable changes in working capital, including decreases in working capital attributable to PPA expirations and the cessation of operations at several projects compared to the year-ago period, and an $8.7 million reduction in cash interest payments (resulting from debt repayment and a lower spread on the Company's credit facilities).

Cash used in investing activities for the second quarter of 2018 was $(1.3) million compared to $(2.2) million in the second quarter of 2017.  The Company used $(1.1) million of cash in the 2018 period to acquire an additional ownership interest in Koma Kulshan; however, the Company had lower capital expenditures than in the 2017 period.

Cash used in financing activities for the second quarter of 2018 was $(32.5) million as compared to $(32.4) million in the year-ago period.  The Company repaid $(26.4) million of term loan and project debt, repurchased $(2.8) million of common shares and $(0.6) million (US$ equivalent) of preferred shares.  It also paid $(2.1) million of preferred dividends.  In the comparable 2017 period, the Company repaid $(29.5) million of term loan and project debt and paid $(2.2) million of preferred dividends.

During the second quarter, the Company had a $5.7 million net decrease in cash, restricted cash and cash equivalents.         

Financial Results for the Six Months Ended June 30, 2018

Key Business Drivers

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

Net Income, Project Income and Project Adjusted EBITDA

Net income attributable to Atlantic Power Corporation for the first six months of 2018 was $15.2 million compared to a net loss of $(24.6) million in the first six months of 2017.  The $39.8 million improvement was primarily attributable to a $28.6 million increase in Project income (discussed below); a $21.9 million increase in unrealized foreign exchange gain ($13.6 million gain versus an $8.3 million loss), most of which was related to the revaluation of debt denominated in Canadian dollars (due to the appreciation of the Canadian dollar during the first six months of 2018, compared to a depreciation in the comparable 2017 period); a $9.6 million reduction in corporate interest expense as a result of debt repayment and re-pricing of the Company's credit facilities; a $4.4 million gain on the repurchase of the Company's preferred shares; and a $2.3 million change in fair value of the conversion option derivative related to the Company's Series E convertible debentures.  These positive factors were partially offset by higher income tax expense.    

Project income for the first six months of 2018 increased to $41.8 million from $13.2 million in the year-ago period.  The $28.6 million increase was primarily attributable to the non-recurrence of $57.7 million of impairment expense recorded at Chambers and Selkirk in 2017, lower maintenance expense at Frederickson and Orlando, and modest increases at several other projects.  These positive variances were partially offset by lower project income at Kapuskasing, North Bay, and the three San Diego projects resulting from PPA expirations and terminations; at Tunis, from maintenance expense associated with the planned re-start of the facility and the non-recurrence of the OEFC Settlement revenues recorded in 2017; at Manchief, due to the gas turbine overhaul in 2018; and at Curtis Palmer, due to lower water flows than the comparable 2017 period. 

Project Adjusted EBITDA for the first six months of 2018 declined to $93.2 million from $149.3 million in the first six months of 2017.  The $56.1 million decrease was primarily attributable to the expiration of contracts at Kapuskasing and North Bay at year-end 2017 (-$42.9 million); maintenance expenses incurred at Tunis in preparation for re-start incurred in 2018 and the absence of OEFC Settlement revenues recorded in 2017 (-$10.7 million); the termination of the PPAs for the three San Diego projects effective March 1, 2018 (-$10.4 million); maintenance expenses associated with the Manchief gas turbine overhaul in 2018 (-$6.8 million); lower water flows at Curtis Palmer (-$3.2 million), and a less favorable short-term PPA at Williams Lake (-$1.8 million).  Partially offsetting these decreases were increases at Morris ($5.4 million), due to a higher capacity price realized in the PJM capacity auction for this year, higher merchant dispatch and higher steam and ancillary services revenues; Frederickson ($3.1 million), due to maintenance expense in 2017; Orlando ($2.4 million), due to higher availability and higher contractual capacity rates; Mamquam ($2.5 million), due to higher water flows and lower maintenance expense; Nipigon ($2.3 million), due to a contractual rate increase and other factors, and modest increases at other projects. 

Cash Flow

Cash provided by operating activities for the first six months of 2018 declined $7.3 million to $78.4 million from $85.7 million in the first six months of 2017.  Operating cash flow was negatively affected by the $56.1 million reduction in Project Adjusted EBITDA.  However, this impact was mostly offset by $34.7 million of net favorable changes in working capital, particularly a $17.7 million decrease in working capital at Kapuskasing, North Bay and the three San Diego projects, as they were not in operation at June 30, 2018.  In addition, cash interest payments were $13.2 million lower in the first six 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.

Cash used in investing activities for the first six months of 2018 was $(2.4) million compared to $(4.2) million in the first six months of 2017.  The Company used $(1.1) million of cash in the 2018 period to acquire an additional ownership interest in Koma Kulshan.  Capital expenditures in the 2018 period were $2.9 million lower than in the 2017 period.

Cash used in financing activities for the first six months of 2018 was $(78.2) million as compared to $(61.9) 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 ($88.0) million of existing convertible debentures.  It also repaid $(58.8) million of term loan and project debt, repurchased $(9.2) million of common shares and $(4.5) million (US$ equivalent) of preferred shares, and paid $(4.3) million of preferred dividends.  In the comparable 2017 period, the Company repaid $(56.9) million of term loan and project debt and paid $(4.3) million of preferred dividends.

During the first six months of 2018, the Company had a $2.2 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 June 30, 2018 was $203.4 million, a decrease of $1.7 million from the March 31, 2018 level.  The Company's unrestricted cash of $80.8 million includes $49.2 million at the parent, of which the Company considers approximately $42 million to be discretionary cash available for general corporate purposes.  The $10 million net increase in cash at the parent as compared to the March 31, 2018 level was primarily due to a release of cash from the projects.  Following the expiration of several PPAs and the shutdown of the three San Diego projects, the Company's need for working capital at certain projects has been reduced.  During the quarter, the Company used discretionary cash to repurchase $3.4 million of common and preferred shares and to fund the $1.1 million acquisition of an additional 0.25% interest in Koma Kulshan.  

Balance Sheet

Debt Repayment

During the second quarter of 2018, the Company repaid $20 million of the APLP Holdings term loan and amortized $6.4 million of project-level debt, including the $5.6 million of remaining debt at Epsilon Power Partners (EPP).  The EPP debt was repaid ahead of schedule. 

Year to date through June 30, 2018, the Company has repaid $50 million of the term loan and $8.8 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 June 30, 2018, the Company's consolidated debt was $778 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 3.8 times. 

Debt Maturity Profile

As a result of the first quarter 2018 convertible debenture issuance and redemption transactions, the Company has no bullet maturities until December 2019, when the remaining Cdn$24.7 million of Series D Debentures mature.  The Series D Debentures 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 $490 million APLP Holdings term loan has an April 2023 maturity, although it is expected to be more than 80% repaid by the maturity date.  The Cdn$115.0 million of Series E Debentures issued in January 2018 have a January 2025 maturity date. 

Normal Course Issuer Bid (NCIB) Update

The Company has in place an NCIB for its common and preferred shares and convertible debentures.  In June 2018, it amended the NCIB to increase the amount of preferred shares that it could repurchase to 10% of the public float from the previous amount of 5% of the public float. 

In the second quarter of 2018, the Company repurchased and canceled approximately 1.3 million common shares at a total cost of $2.8 million, or an average price of $2.14 per share.  In June 2018, the Company repurchased and canceled 40,000 shares of the Cumulative Floating Rate Preferred, Series 3 at Cdn$18.00 per share, for a total cost of Cdn$0.7 million.

In July 2018, the Company repurchased and canceled another 0.3 million common shares at a total cost of $0.6 million, or an average price of $2.14 per share.  The Company also repurchased and canceled 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$0.8 million. 

Year to date through July 31, 2018, the Company has repurchased and canceled a total of approximately 4.6 million common shares at a total cost of $9.8 million, or an average price of $2.11 per share.  It also has repurchased and canceled 237,500 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$6.7 million.  

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.  The expected decline from 2017 Project Adjusted EBITDA of $288.8 million is primarily attributable to the impact of PPA expirations in 2017 and 2018 and the non-recurrence of revenues received under the OEFC Settlement in 2017.  Other factors contributing to lower Project Adjusted EBITDA include maintenance expense associated with the gas turbine overhaul at Manchief in the second quarter of 2018 and re-start costs for Tunis, most of which were incurred and expensed in the first six months of 2018.  The Company's 2018 guidance assumes average water conditions as compared to favorable conditions in 2017.  These negative factors are expected to be partially offset by increases at several other projects, including Morris (a higher PJM capacity price) and Frederickson (maintenance outage in 2017).   

Table 3 provides a bridge of the Company's 2018 Project Adjusted EBITDA guidance to Cash provided by operating activities.  For purposes of providing this bridge to a cash flow measure, the impact of changes in working capital is assumed to be nil.  The impact of lower Project Adjusted EBITDA on cash provided by operating activities is expected to be partially mitigated by a $27 million reduction in cash interest payments in 2018 relative to 2017.   The reduction in cash interest payments is attributable to a full year benefit from the $166 million of debt repaid in 2017, a partial year benefit from the expected debt repayment of $100 million in 2018, the lower interest rate on the term loan and revolver resulting from re-pricings in 2017 and 2018, and the non-recurrence of the Piedmont interest rate swap termination cost incurred in 2017.    

Commercial and Operational Updates

Acquisition of Partners' Interests in Koma Kulshan

In June 2018, the Company acquired an additional 0.25% ownership interest in the Koma Kulshan hydro facility for $1.1 million.  On July 27, 2018, it acquired the remaining 50.00% ownership interest from Covanta and bought out the operation and maintenance contract held by Covanta for a total of $12.1 million.  The purchase was funded from discretionary cash.  As a result, the Company now owns 100% of the project and will consolidate it beginning in the third quarter of 2018.  The Company will also become the project operator.

Koma Kulshan is a 13 megawatt run-of-river hydro facility in Washington State.  The PPA with Puget Sound Energy runs through March 2037.  The project has no debt.  The total purchase price of $13.2 million represents a multiple of approximately 10 times the Company's estimate of pro forma Project Adjusted EBITDA and approximately 11 times the Company's estimate of pro forma cash distributions, both based on average water conditions.

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, the projects ceased operations on 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 projects that were conditioned on California Public Utilities Commission (CPUC) approval and the Company obtaining the right to remain on the Navy sites for the contract term ("site control").  Although the CPUC approved the Naval Station and North Island PPAs earlier this year, in late July it rejected the SCE contract for NTC.  The Company remains engaged in discussions with the Navy regarding site control for Naval Station and North Island, but the probability of success at either site remains low.  The Company is required by its land use agreements with the Navy to decommission the sites.  It intends to proceed with the decommissioning of NTC and it is making preparations to decommission both Naval Station and North Island as well.  The cost and timing of decommissioning are dependent on the scope of work, which will be determined together with the Navy.

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 beyond the original expiration date of April 1, 2018.  The amended contract will expire on 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 schedule for BCUC review was recently extended.  If the BCUC has not approved the amended contract by September 17, 2018, either party will have the right to terminate the contract, although this date may be extended at the option of BC Hydro.       

Kenilworth.  As previously reported, with the April 2018 exercise by Merck of a one-year extension option, the Energy Services Agreement will expire on September 30, 2019.  Merck has two additional successive one-year extension options under the contract. 

Tunis Planned Re-start

The Company has completed the commissioning of the Tunis plant, including installing an upgrade to the control system.  Most of the estimated $5 million cost (US$ equivalent) of the re-start was incurred in the first six months of 2018 and all of it was expensed.  Re-start of operations under the 15-year PPA has been delayed about three months pending review and acceptance by the Ontario Independent Electricity System Operator (IESO) of the commissioning report that was submitted by the independent engineer at the end of July.  Approval by the IESO will allow the project to operate in dispatchable mode.  The targeted re-start for Tunis is now in the October timeframe.   Under the PPA, Tunis will receive monthly capacity payments and will earn energy revenues for those periods during which it operates.   

Manchief Outage

The Company undertook a major gas turbine outage at its Manchief project in mid-April through late May.  This is similar to the one undertaken in 2015 for the project's other gas turbine.  The costs were expensed and reduced Project Adjusted EBITDA for Manchief by approximately $7.4 million in the second quarter of 2018. 

Maintenance and Capex

There has been no change to the Company's planned maintenance expenses of approximately $34.8 million and capital expenditures of approximately $1.4 million for 2018.  In the second quarter of 2018, the Company incurred $15.1 million of maintenance expense, a significant portion of which was for the Tunis re-start and the Manchief outage.  Through June 30 of this year, the Company has incurred maintenance expense of $22.0 million and made capital expenditures of $0.3 million.  (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 second 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, August 3, 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, August 3, 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 10122183 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 September 3, 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 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 
info@atlanticpower.com

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 expectation that it will repay $100 million of debt in 2018;
• 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 its second quarter and year-to-date June 2018 results were modestly better than anticipated;
• the Company's view that approximately $42 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 estimate that it will have repaid more than 80% of its term loan by the April 2023 maturity date;
• the Company's guidance for 2018 Project Adjusted EBITDA in the range of $170 to $185 million;
• the Company's estimate that the majority of the expected decline in 2018 Project Adjusted EBITDA is attributable to the impact of PPA expirations in 2017 and 2018 and the non-recurrence of revenues received under the OEFC Settlement;
• the Company's estimate that decreases to 2018 Project Adjusted EBITDA, including the impact of PPA expirations and lower expected results at Tunis and Manchief, will be partially offset by increases at several other projects, including Morris and Frederickson;
• 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 estimate that cash interest payments in 2018 will be approximately $45 million, or $27 million lower than the 2017 level, with the decline attributable to debt repayment in 2017 and 2018, the re-pricings of the Company's credit facilities, and the non-recurrence of the Piedmont interest rate swap termination cost incurred in October 2017;
• the Company's estimates of pro forma Project Adjusted EBITDA and pro forma cash distributions for the acquired interests in the Koma Kulshan project;
• the Company's view that it is unlikely to obtain site control at any of its three San Diego projects;
• the Company's expectations with respect to the estimated cost and timing of a planned re-start of its Tunis project;
• the Company's estimation that, in 2018, including its share of equity-owned projects, maintenance expense will total approximately $34.8 million and capital expenditures will total approximately $1.4 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. 

 

 

SOURCE Atlantic Power Corporation