DEDHAM, Mass., Nov. 9, 2017 /PRNewswire/ --  

Third Quarter and YTD 2017 Highlights

• Cash provided by operating activities of $52.9 million in Q3 2017 vs. $38.2 million in Q3 2016
• $137.9 million for the first nine months of 2017 vs. $91.9 million in the year-ago period
• Net loss of $(32.9) million in Q3 2017 vs. $(82.4) million in Q3 2016
• $(57.5) million for the first nine months of 2017 vs. $(116.2) million in the year-ago period
• Project Adjusted EBITDA of $77.4 million in Q3 2017 vs. $51.3 million in Q3 2016
• $226.6 million for the first nine months of 2017 vs. $159.9 million in the year-ago period
• Repaid $29.4 million of term loan and project debt during Q3 2017 and $86.2 million year to date
• Liquidity at September 30, 2017 of $249.8 million

Recent Developments

• In October, repaid $54.6 million remaining project debt at Piedmont, yielding estimated interest cost savings of $4.5 million annually
• Pro forma for Piedmont debt repayment, liquidity was $178.5 million and leverage ratio was 3.6 times
• In October, executed second repricing of term loan and revolver, reducing spread 75 bp to L+3.50%
• Estimated interest cost savings of $4 million in 2018 and $15 million over terms of facilities
• In October, executed a one-year extension of the maturity date of the revolver to April 2022
• In October, Moody's upgraded the Company's corporate family credit rating to Ba3 from B1

Guidance

• Increased 2017 Project Adjusted EBITDA guidance range by $10 million (see page 7)

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, 2017.  Net loss attributable to Atlantic Power Corporation of $(32.9) million for the three months ended September 30, 2017 decreased from $(82.4) million in the year-ago period, primarily because of higher margins at Kapuskasing and North Bay (as discussed on page 2), an extended planned outage at Morris in the third quarter of 2016 that did not recur in 2017, lower non-cash impairment expense and lower interest expense, partially offset by other factors.  Project Adjusted EBITDA, which does not include impairment expense, increased to $77.4 million from $51.3 million in the third quarter of 2016, primarily due to increases at Kapuskasing, North Bay, Morris and Curtis Palmer, which experienced higher water flows.  Cash provided by operating activities increased to $52.9 million from $38.2 million in the third quarter of 2016.    

"We have increased our 2017 guidance for Project Adjusted EBITDA and our expectation for Operating Cash Flow as a result of our strong year-to-date results and our outlook for the remainder of the year," said James J. Moore, Jr., President and CEO of Atlantic Power.  "We finished the third quarter with liquidity of $250 million, and in October we used $60 million of discretionary cash to pay off the Piedmont debt ten months ahead of its maturity, reducing annual interest costs by approximately $4.5 million.  For the full year, we expect to reduce debt by approximately $166 million.  We also executed another successful repricing of our term loan and revolving credit facility, reducing the spread an additional 75 basis points, which will save $4 million of interest costs in 2018.  Lastly, we recently executed an agreement to extend the maturity date of our corporate revolver by one year, to April 2022, further extending our stable liquidity profile."

Mr. Moore continued, "The steps that we have taken over the past few years to reduce our cost structure by nearly $100 million annually from 2013 levels, pay down approximately $1 billion of debt, and improve our maturity profile, position us well to continue delevering and to allocate available cash to growth initiatives, security repurchases and discretionary debt repayment." 

Financial Results

Results for the third quarter of 2017 were significantly affected by changes to the operational and contractual status of the Kapuskasing, North Bay and Nipigon plants in Ontario, which commenced in January 2017, and the settlement of the Global Adjustment dispute with the Ontario Electricity Financial Corporation in April 2017 (the "OEFC Settlement").  In addition, the Company recorded significant impairments on its three San Diego plants in the third quarter, which affected project income and net income, although not cash flow or Project Adjusted EBITDA.  These developments are discussed below. 

Enhanced Dispatch Contracts

As previously reported, since the beginning of 2017, the Kapuskasing, North Bay and Nipigon plants have been under enhanced dispatch contracts that provide fixed monthly payments but do not require the plants to generate power.  As a result, they have been in a non-operational state, which has resulted in operating and fuel cost savings relative to 2016, when the plants were operating and Kapuskasing and North Bay were purchasing gas under an above-market contract that expired at year-end 2016.  The revenues received under these contracts were $4.2 million and $16.6 million lower in the three and nine months ended September 30, 2017, respectively, than in the comparable year-ago periods, but this decrease was more than offset by lower maintenance and fuel expenses.

The Company has accelerated depreciation at Kapuskasing and North Bay through year-end 2017, when it will have fully depreciated both plants consistent with the expiration date of the enhanced dispatch contracts.  The increased depreciation associated with these plants was $4.5 million and $12.6 million for the three and nine months ended September 30, 2017, respectively. 

OEFC Settlement

In April 2017, the OEFC agreed to pay the Company a total of approximately Cdn$36.4 million in settlement of the Global Adjustment dispute, which was related to power sold to the OEFC under the Power Purchase Agreements ("PPAs") for the Kapuskasing, North Bay and Tunis projects.  A subsequent adjustment increased this amount to approximately Cdn$37.8 million.  The Company received and recorded a total of Cdn$34.0 million of revenue related to the OEFC Settlement in the first nine months of 2017, including Cdn$1.2 million in the third quarter of 2017.  The remaining amount will be received as earned under the enhanced dispatch contracts for the Kapuskasing and North Bay projects in the fourth quarter of 2017.

The benefit to Project Adjusted EBITDA from the OEFC Settlement was US$25.6 million for the nine months ended September 30, 2017, including $1.0 million in the third quarter of 2017.

Impairment of San Diego Plants

As discussed in the Company's previous filings on Form 10-K and Form 10-Q, the Company owns three plants in San Diego – Naval Station, Naval Training Center ("NTC") and North Island.  These plants sell power to San Diego Gas & Electric ("SDG&E") under PPAs that are scheduled to expire in December 2019.  In addition, the three plants supply steam to the U.S. Navy under agreements that provide the Company with the right to use the property at the respective sites on which each project is located (the "Navy agreements").  The Navy agreements are scheduled to expire in February 2018.  In August 2017, the Company learned that proposals involving the Naval Station and North Island plants were not selected in the final round of the Navy's solicitation for energy security and resiliency at the respective bases on which these two plants are located.  A successful outcome in this solicitation was the clearest path to obtaining the right to remain on the sites beyond February 2018 ("site control"). 

Based on the outcome of the Navy solicitation, the Company determined that it is unlikely that the three plants will operate beyond the expiration of the Navy agreements.  The Company undertook an evaluation of the carrying values of the long-lived assets, including intangible assets (associated with the PPAs) and property, plant and equipment (PP&E).  This evaluation assumed that the PPAs will terminate in February 2018.  During the third quarter, the Company recorded a $57.3 million impairment of the long-lived assets at these three plants, including $18.2 million for a full impairment of the remaining intangible assets.  At September 30, 2017, there was $7.7 million of remaining PP&E, which will be depreciated through February 2018.    

As of September 30, 2017, the Company had recorded $4.6 million of net removal obligations for the San Diego plants.  The Company is in the process of evaluating the estimated removal costs and may make adjustments to this amount in the fourth quarter of 2017.  The timing and final arrangements for decommissioning the sites have not yet been determined. 

The $57.3 million impairment associated with the San Diego Plants reduced both Project income and Net income for the three and nine months ended September 30, 2017.  Impairment expense does not affect cash from operating activities or Project Adjusted EBITDA.               

Three Months Ended September 30, 2017

Net loss attributable to Atlantic Power Corporation for the third quarter of 2017 was $(32.9) million as compared to $(82.4) million in the third quarter of 2016.  The $49.5 million reduction in net loss was the result of increased revenues of $7.4 million (primarily driven by higher water flows at Curtis Palmer and the non-recurrence of an extended planned outage at Morris in the prior-year period, partially offset by lower revenues under the enhanced dispatch contracts), a reduction in fuel and operations and maintenance expenses of $19.0 million (primarily at Kapuskasing, North Bay and Morris, as discussed previously), a $27.4 million reduction in impairment expense (the year-ago period included $84.7 million of impairment expense associated with the Company's Mamquam, Curtis Palmer, North Bay and Kapuskasing plants), and a $6.4 million reduction in corporate and project interest expense.  These positive factors were partially offset by an increase in foreign exchange loss (loss of $9.4 million versus a gain of $3.4 million in the year-ago period), a $10.9 million negative change in the fair value of derivative instruments (non-cash), and increased depreciation expense of $6.1 million (mostly for Kapuskasing and North Bay).

Project loss for the third quarter of 2017 was $(20.9) million as compared to $(57.1) million in the year-ago period.  The $36.2 million reduction in loss was primarily attributable to the reduction in impairment expense, increased revenues, and lower fuel and operations and maintenance expense, as discussed previously, partially offset by increased foreign exchange loss, a negative change in the fair value of derivative instruments and increased depreciation expense, as discussed previously.

Project Adjusted EBITDA for the third quarter of 2017 was $77.4 million, an increase of $26.1 million from $51.3 million in the year-ago period.  Primary drivers were the favorable impact on margins of the enhanced dispatch contracts and the expiration of an above-market gas contract in Ontario (totaling $11.1 million, including $1.0 million related to the OEFC Settlement), the non-recurrence of an extended planned outage at Morris ($7.5 million), higher water flows at Curtis Palmer ($3.5 million), higher water flows and lower maintenance expense at Mamquam ($1.1 million), and modest increases at Orlando and Williams Lake.  These positive factors were partially offset by modest decreases at several plants, none of which exceeded $0.5 million.  During the quarter, the Canadian dollar appreciated modestly relative to the year-ago period.  This had a non-cash translation benefit to Project Adjusted EBITDA of approximately $1.0 million.

Cash provided by operating activities for the third quarter of 2017 of $52.9 million increased $14.7 million from $38.2 million a year ago.  Factors that positively affected cash flow included the benefit to gross margin from the revised contractual, operating and fuel supply arrangements for Kapuskasing, North Bay and Nipigon, as previously discussed; higher revenues and lower maintenance expense at Morris, which underwent an extended scheduled outage in the third quarter of 2016; and higher water flows at Curtis Palmer.  These positive factors were partially offset by a $2.2 million increase in cash interest payments that was timing-related.

Significant uses of the $52.9 million of cash provided by operating activities included $25.0 million of term loan amortization, $4.4 million of project debt amortization and $2.2 million of preferred dividend payments.  The Company also used $1.5 million of cash for capital expenditures and $3.1 million for the repurchase of preferred shares.   

Nine Months Ended September 30, 2017

Net loss attributable to Atlantic Power Corporation for the nine months ended September 30, 2017 was $(57.5) million as compared to $(116.2) million in the nine months ended September 30, 2016.  The $58.7 million reduction in loss was the result of several positive factors, including increased revenues of $25.2 million (primarily the result of the OEFC Settlement, increased water flows at Curtis Palmer, and higher steam revenues at the San Diego plants, partially offset by lower revenues under the enhanced dispatch contracts), lower fuel and operations and maintenance expenses totaling $47.7 million (primarily the result of the enhanced dispatch contracts and expiration of an above-market gas supply contract in Ontario, and the non-recurrence of the extended planned outage at Morris in August 2016), a $27.4 million reduction in impairment expense for the Company's consolidated projects (the year-ago period included $84.7 million of impairment expense associated with the Company's Mamquam, Curtis Palmer, North Bay and Kapuskasing plants), and a $38.7 million reduction in corporate and project interest expense (due to a $31.4 million write-off of deferred financing costs in the second quarter of 2016 and lower debt levels).  These positive factors were partially offset by a $64.0 million reduction in earnings from unconsolidated affiliates (primarily because of a $57.7 million impairment recorded at Chambers and Selkirk in the second quarter of 2017), a $25.8 million negative change in the fair value of derivative instruments (non-cash), and $14.9 million of increased depreciation expense, primarily at Kapuskasing and North Bay. 

Project loss for the nine months ended September 30, 2017 increased to $(7.7) million from $(3.3) million in the year-ago period.  The $4.4 million increase in loss was primarily attributable to the reduction in earnings from unconsolidated affiliates, the negative change in fair value of derivative instruments, and increased depreciation expense, partially offset by increased revenues, lower fuel and operations and maintenance expense, and lower impairment expense for consolidated projects, as discussed previously.

Project Adjusted EBITDA for the nine months ended September 30, 2017 was $226.6 million, an increase of $66.7 million from $159.9 million in the year-ago period.  Primary drivers were the OEFC Settlement ($25.6 million), the favorable impact on margins of the enhanced dispatch contracts and the expiration of an above-market gas contract in Ontario (totaling $27.3 million), increased water flows at Curtis Palmer ($10.0 million), and more modest increases at Orlando ($2.8 million, due to the settlement of favorable fuel swaps), Morris ($2.4 million, mostly due to the outage in the year-ago period), and Piedmont ($2.1 million, partly due to maintenance in the year-ago period).  These positive factors were partially offset by decreases at Mamquam (-$2.5 million, due to lower water flows in the first six months of 2017 compared to a record year in 2016, and a forced outage in the second quarter of 2017), Frederickson (-$2.2 million, due to higher planned maintenance expense in the second quarter of 2017), and Calstock (-$2.1 million, due to lower waste heat and higher fuel prices). 

During the first nine months of 2017, the Canadian dollar appreciated slightly relative to the year-ago period.  This had a non-cash translation benefit to Project Adjusted EBITDA of approximately $1.7 million.   

Cash provided by operating activities for the nine months ended September 30, 2017 of $137.9 million increased $46.0 million from $91.9 million a year ago.  The 2017 period included approximately $25.6 million of cash collected under the OEFC settlement, most of which occurred in the second quarter.  Other factors that positively affected cash flow included the benefit to gross margin from the revised contractual, operating and fuel supply arrangements for Kapuskasing, North Bay and Nipigon, as previously discussed, lower operation and maintenance expense, and improved hydrology at Curtis Palmer.  These positive factors were partially offset by decreases at Mamquam, Frederickson and Calstock, for reasons previously discussed.  In addition, cash provided by operating activities was reduced $25.0 million from the year-ago period due to changes in working capital, primarily due to the timing of revenue receipts at Oxnard and Morris ($11.7 million) and inventory buildup for 2018 and 2019 planned outages ($3.3 million). 

Significant uses of the $137.9 million of cash provided by operating activities during the nine months ended September 30, 2017 included $77.1 million of term loan amortization, $9.1 million of project debt amortization and $6.5 million of preferred dividend payments.  The Company also used $5.7 million of cash for capital expenditures, primarily for the upgrade of the third and final combustion turbine at Morris in the second quarter of 2017, and $3.1 million of cash for the repurchase of preferred shares in the third quarter of 2017.   

Liquidity and Balance Sheet

Liquidity

As shown in Table 2, the Company's liquidity at September 30, 2017 was $249.8 million, an increase of $22.6 million from the June 30, 2017 level.  The increase was attributable to an $18.0 million increase in unrestricted cash, which resulted from increased cash provided by operating activities, and a $4.6 million increase in revolver availability, due to a reduction in letters of credit outstanding.

On October 12, 2017, the Company used $59.6 million of cash at the parent and $4.5 million of previously restricted cash at the project to repay the remaining project debt at Piedmont, totaling $54.6 million, and to pay $0.1 million of accrued interest and $9.4 million of interest rate swap termination costs.  The Company also posted a corporate letter of credit at the project in the amount of $11.7 million.  Pro forma for this development, liquidity at September 30, 2017, would be $178.5 million, as shown in Table 2.

The pro forma unrestricted cash of $62.8 million includes $40.5 million at the parent, of which the Company considers slightly more than $30 million to be discretionary cash available for general corporate purposes.   

Balance Sheet

Debt Repayment

During the third quarter of 2017, the Company repaid $25.0 million of the APLP Holdings term loan and amortized $4.4 million of project-level debt.  For the first nine months of 2017, the Company repaid a total of $77.1 million of the term loan and amortized $9.1 million of project-level debt.  At September 30, 2017, the Company's consolidated debt was $927 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.  The improvement in the leverage ratio from 4.4 times at June 30, 2017 was primarily attributable to the positive impacts on EBITDA of the OEFC Settlement payments (most of which were recorded in the second quarter) and the enhanced dispatch contracts (for the past three quarters) combined with the continued reduction in debt.     

In October 2017, as previously discussed, the Company repaid $54.6 million of remaining project debt at Piedmont, which had been scheduled to mature in August 2018.  Pro forma for this repayment, consolidated debt at September 30, 2017 would be $872 million and the consolidated leverage ratio would be 3.6 times.  Annual interest savings associated with repayment of the 8.2% Piedmont project debt are approximately $4.5 million.       

For the full year 2017, the Company expects debt repayment to total $166 million, including approximately $100 million of the APLP Holdings term loan, $11.4 million of project-level debt and $54.6 million of Piedmont debt.   

Debt Maturity Profile

The Company has no bullet maturities in 2017 or 2018.  The remaining $42.5 million of Series C convertible debentures mature in June 2019 and became callable at par in June 2017.  The $64.9 million (U.S. dollar equivalent) of Series D convertible debentures mature in December 2019 and are callable at par in December 2017.  In October 2017, the Company extended the maturity date of its $200 million revolving credit facility by one year, to April 2022.  The $563 million APLP Holdings term loan has an April 2023 maturity, although it is expected to be more than 80% repaid by the maturity date. 

Repricing of Term Loan and Revolver

As reported in the Company's October 19, 2017 press release, the Company executed a repricing of the $563 million APLP Holdings term loan and $200 million revolving credit facility, reducing the interest rate margin on the term loan and revolver by 75 basis points, to LIBOR plus 350 basis points.  This repricing is the second for these facilities; since the original financing in April 2016, the spread has been reduced a total of 150 basis points, from LIBOR plus 500 basis points to LIBOR plus 350.  As a result of the October 2017 repricing, the Company expects to realize interest cost savings in 2018 of approximately $4 million compared to the cost based on the previous spread.  Cumulative savings through the maturity dates of the term loan (April 2023) and revolver (April 2022) are estimated to be approximately $15 million.  The combined savings of both repricing transactions is expected to be approximately $33 million over the terms of the facilities.  Transaction costs associated with the repricing will be included in interest expense in the fourth quarter of 2017.   

Normal Course Issuer Bid (NCIB) Update

The Company put in place a new normal course issuer bid ("NCIB") on December 29, 2016.  Details of this program can be found in the Company's December 20, 2016 press release.  In the third quarter of 2017, the Company repurchased and canceled 93,391 common shares at an average price of $2.36 per share.  The Company also repurchased and canceled a total of 250,000 shares of the 4.85% Cumulative Redeemable Preferred (Series I issue) at Cdn$15.5 per share for a total payment of Cdn$3.9 million.  The Company also repurchased a nominal amount of convertible debentures in the third quarter of 2017.  

Credit Rating Upgrade

In early October, Moody's upgraded the Company's corporate family credit rating to Ba3 from B1 and upgraded the credit rating for the term loan and revolving credit facility to Ba2 from Ba3.  Moody's cited the Company's continuing efforts to improve its credit profile through cost cutting and debt reduction. 

Increasing 2017 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 has increased its previous 2017 guidance for Project Adjusted EBITDA of $250 to $265 million by $10 million to a range of $260 to $275 million.  The primary reasons for the increase are higher water flows at Curtis Palmer and lower costs at the non-operational plants in Ontario in the year to date, and the expectation that certain repowering expenditures previously planned for the fourth quarter of 2017 will not occur or will be deferred into 2018.

Table 3 provides a bridge of the Company's 2017 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.

Other Financial Updates

Update on Near-Term PPA Expirations

As previously disclosed, the Company has seven plants with PPAs (or lease agreements, in the case of the San Diego plants) that are scheduled to expire within the next 12 months. 

Kapuskasing and North Bay (Ontario).  The Company does not expect to extend or renew the enhanced dispatch contracts for these two plants, which will expire on December 31, 2017.

Naval Station, NTC and North Island (San Diego).  The three plants sell power to SDG&E under PPAs that are scheduled to expire on December 1, 2019.  The plants are located on Naval bases in San Diego, and the agreements with the Navy that provide the Company the right to use the sites are scheduled to expire on February 8, 2018.  The Company executed new seven-year contracts with SDG&E for Naval Station and North Island in August 2017.  However, the contracts are conditioned on the Company's ability to remain on the sites beyond February 2018.  The contracts are also subject to the approval of the California Public Utilities Commission.  In late August the Company learned that it was not selected in the Navy's solicitation for energy security and resiliency proposals at these bases, which had been the clearest path to obtaining site control.  Although the Company is pursuing alternative paths to site control, if it is not successful, the plants may cease operations as early as February 2018. 

Williams Lake (British Columbia).  The PPA with BC Hydro is scheduled to expire on April 1, 2018.  The Company is negotiating a short-term extension of the PPA with the utility customer, with a goal of bridging the period to the outcome of the utility's integrated resource plan (IRP) in 2019.  Additional capital investment in the plant would be deferred during the short-term extension.

Kenilworth (New Jersey).  The PPA with Merck is scheduled to expire on September 30, 2018.  The Company is exploring both short- and long-term extensions with Merck.                

2017 Maintenance and Capex

For 2017, including its share of equity-owned projects, the Company expects to incur maintenance expenses of approximately $34.3 million, of which $23.6 million was incurred in the first nine months of 2017.  This is lower than the $41.2 million previously forecast because certain repowering expenditures originally planned for the fourth quarter of 2017 will not occur or will be deferred into 2018.  The Company's estimate of capital expenditures for 2017 is approximately $5.4 million, unchanged from the previous forecast.  The majority ($4.9 million) was incurred in the first nine months of 2017, most of it related to the upgrade of the third and final combustion turbine at Morris, which was completed in the second quarter of 2017. 

Tunis Planned Restart

The Company has received the required environmental permit and expects to begin work on returning Tunis to service as a simple-cycle plant with a targeted commercial operation date of mid-2018.  Most of the estimated $6.5 million cost will be incurred in 2018 and will be expensed.  The plant has a 15-year PPA that will commence with commercial operation.   

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.

Investor Conference Call and Webcast

Atlantic Power's management team will host a telephone conference call on Friday, November 10, 2017 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 10, 2017 

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 10112968 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 10, 2017 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 owns and operates a diverse fleet of twenty-three power generation assets across nine states in the United States and two provinces in Canada.  The Company's power generation projects sell electricity to utilities and other large commercial customers largely under long-term PPAs, which seek to minimize exposure to changes in commodity prices.  The aggregate gross electric generation capacity of this portfolio is approximately 2,138 megawatts ("MW"), and the Company's aggregate net ownership interest is approximately 1,500 MW.  Nineteen of the projects are currently operational, totaling 1,975 MW on a gross capacity basis and 1,337 MW on a net ownership basis.  The remaining four projects, all in Ontario, are not operational, three due to revised contractual arrangements with the offtaker and the other, Tunis, has a forward-starting 15-year PPA that will commence with the commercial operation of the plant before June 2019. 

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 estimates of annual interest cost savings associated with the repayment of Piedmont debt and the repricing of its term loan and revolver;
• the Company's expectation that it will repay approximately $166 million of debt in 2017;
• the Company's expectation to allocate available cash to growth initiatives, security repurchases and discretionary debt repayment;
• the Company's expectation that it will have fully depreciated the Kapuskasing and North Bay plants by year-end 2017;
• the Company's expectation that it will receive another approximately Cdn$3.8 million of revenues under the OEFC settlement in the fourth quarter of 2017;
• the Company's estimate of discretionary cash, pro forma for the repayment of Piedmont debt in October 2017;
• the Company's expectation that it will repay more than 80% of its term loan by the maturity date in 2023;
• the Company's estimation that 2017 Project Adjusted EBITDA will be in the range of $260 to $275 million;
• the Company's estimation that 2017 cash flows provided by operating activities will be in the range of $160 to $175 million, assuming for this purpose that working capital changes are nil;
• the Company's expectation with respect to progress on PPAs expiring in 2018;
• the Company's expectation that the Naval Station, NTC, and North Island plants may cease operations as early as February 2018 if the Company is unsuccessful in obtaining site control;
• the Company's expectation that capital investment in the Williams Lake plant would be deferred should the Company agree to a short-term PPA extension with BC Hydro;
• the Company's expectation that in 2017, including its share of equity-owned projects, maintenance expense will total approximately $34.3 million and capital expenditures will total approximately $5.4 million;
• the Company's expectations with respect to the estimated cost and timing of a planned restart of its Tunis plant; 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 Securities and Exchange Commission from time to time for a detailed discussion of the risks and uncertainties affecting the Company, including, without limitation, the outcome or impact of the Company's business strategy to increase the intrinsic value of the Company on a per-share basis through disciplined management of its balance sheet and cost structure and investment of its discretionary cash in a combination of organic and external growth projects, acquisitions, and repurchases of debt and equity securities; the Company's ability to enter into new PPAs on favorable terms or at all after the expiration of existing agreements, and the outcome or impact on the Company's business of any such actions.  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 loss on a consolidated basis is provided in Table 7 below. 

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.  A bridge of Project Adjusted EBITDA to Cash Distributions from Projects can be found in the third quarter 2017 presentation on the Company's website.

Project income (loss) and Project Adjusted EBITDA by project also can be found in the third quarter 2017 presentation on the Company's website.

 

 

 

SOURCE Atlantic Power Corporation