DEDHAM, Mass., Feb. 28, 2019 /PRNewswire/ --

Full Year 2018 Highlights

• Net income attributable to Atlantic Power of $36.8 million vs. net loss of $(98.6) million in 2017
• Cash from operating activities of $137.5 million decreased from $169.2 million in 2017, but was modestly above Company's expectation
• Project Adjusted EBITDA of $185.1 million in 2018 decreased from $288.8 million in 2017, but was at the high end of Company's guidance range of $170 million to $185 million
• Repaid $100.3 million of term loan and project debt; achieved leverage ratio of 4.5 times at December 31, 2018
• Executed two re-pricings of credit facilities, resulting in additional interest cost savings
• Repurchased and canceled approximately 7.8 million common shares and approximately 645 thousand preferred shares, at a total cost of approximately $24.6 million
• Liquidity at December 31, 2018 of $191.4 million, including approximately $39 million of discretionary cash
• Returned Tunis to commercial operation under 15-year contract
• Announced two acquisitions that will add to capacity, average contract life and Project Adjusted EBITDA

Fourth Quarter 2018 Financial Results

• Net income attributable to Atlantic Power of $24.7 million vs. net loss of $(41.1) million in Q4 2017
• Cash from operating activities of $39.7 million vs. $30.5 million in Q4 2017
• Project Adjusted EBITDA of $46.6 million vs. $62.1 million in Q4 2017

Atlantic Power Corporation (NYSE: AT) (TSX: ATP) ("Atlantic Power" or the "Company") today reported its financial results for the three months and year ended December 31, 2018.  Net income in 2018 compared favorably with a net loss in 2017 primarily because the Company recorded $187.1 million of impairment expense in 2017 but none in 2018.  Cash from operating activities and Project Adjusted EBITDA declined in 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.  (Impairment expense is not included in Project Adjusted EBITDA or cash flow.)

"Project Adjusted EBITDA of $185.1 million was at the high end of our 2018 guidance range, and Operating Cash Flow of $137.5 million modestly exceeded our expectations," said James J. Moore, Jr., President and CEO of Atlantic Power.  "We used the majority of that cash flow to repay $100 million of debt, further strengthening our balance sheet and reducing our interest costs.  During the year we executed two re-pricings of our term loan for additional cost savings.  We also invested more than $24 million in common and preferred share repurchases in 2018 at attractive price-to-value levels, and announced two acquisitions, representing our first external growth investments after three years of intense focus on our costs and balance sheet."        

Mr. Moore continued, "In 2019, we expect to repay another $86 million of debt, continuing the ongoing reduction in our debt levels and leverage ratio.  In addition, we have liquidity of $191 million, including approximately $39 million of discretionary cash, that we will allocate to growth investments and common and preferred share repurchases, when these are accretive to intrinsic value per share."

 

 

Financial Results for the Three Months Ended December 31, 2018

Key Drivers

The most significant drivers of fourth quarter results 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 higher maintenance expense at Oxnard due to gas turbine repairs.  The impact of PPA expirations was expected.  On the positive side, Curtis Palmer benefited from stronger water flows and Tunis returned to service under a new PPA in October 2018.

Net Income (Loss), Project Income (Loss) and Project Adjusted EBITDA

Net income attributable to Atlantic Power Corporation for the fourth quarter of 2018 was $24.7 million compared to a net loss of $(41.1) million in the fourth quarter of 2017.  The $65.8 million swing from loss to income was primarily attributable to $72.2 million of impairment expense recorded in 2017 that did not recur, $10.4 million lower project interest expense due to the repayment of Piedmont project debt in October 2017 (the 2017 period included a $9.4 million swap termination cost), and a $12.3 million increase in unrealized foreign exchange gain, which was related to the revaluation of debt denominated in Canadian dollars (the Canadian dollar depreciated during the quarter).  These positive factors were partially offset by lower gross margins resulting from the PPA expirations previously discussed, the non-recurrence of the OEFC settlement revenues, a $9.2 million unfavorable change in the fair value of derivative instruments and a $12.2 million reduction in income tax benefit.       

Project income for the fourth quarter of 2018 was $20.1 million as compared to a project loss of $(39.7) million in the year-ago period.  The most significant drivers of the $59.8 million improvement were the non-recurrence of impairment expense recorded at Curtis Palmer, Williams Lake and Frederickson in the 2017 period, and lower project interest expense due primarily to the repayment of Piedmont project debt in full in the fourth quarter of 2017 and the non-recurrence of a related swap termination cost.  These positive factors were partially offset by lower gross margins resulting from the PPA expirations previously discussed, the non-recurrence of the OEFC settlement revenues and an unfavorable change in the fair value of derivative instruments.      

Project Adjusted EBITDA for the fourth quarter of 2018 declined to $46.6 million from $62.1 million in the fourth quarter of 2017.  The $15.5 million decrease was primarily attributable to the expiration of contracts at Kapuskasing and North Bay at year end 2017 (-$17.1 million); the early termination of the PPAs for the three San Diego projects effective March 1, 2018 (-$2.3 million); a less favorable short-term PPA at Williams Lake (-$1.6 million), and gas turbine repairs at Oxnard (-$1.2 million).  These decreases were partially offset by higher water flows at Curtis Palmer ($3.6 million) and the return of Tunis to commercial operation under the new PPA and the absence of start-up expenses incurred in 2017 ($1.8 million). 

Cash Flow

Cash provided by operating activities for the fourth quarter of 2018 increased to $39.7 million from $30.5 million in the fourth quarter of 2017.  Results were positively affected by a $16.8 million reduction in cash interest payments, due primarily to the Piedmont swap termination expense in the 2017 period, the timing of payments on the new Series E convertible debentures (one in July 2018 and two annually going forward in January and July), the reduction in debt levels and the reduced spread on the Company's credit facilities.  Distributions from unconsolidated affiliates increased $7.9 million, but this was partly a timing issue as the September distribution from Orlando was not received until October 1 ($3.6 million); Chambers had an increase of $4.2 million due to lower operation and maintenance expenditures and a release of working capital.  These factors, which positively affected cash flow, were partially offset by lower Project Adjusted EBITDA for the quarter, as previously discussed.

Cash used in investing activities for the fourth quarter of 2018 was $0.1 million compared to a $1.4 million source of funds in the fourth quarter of 2017. 

Cash used in financing activities for the fourth quarter of 2018 was $27.1 million as compared to $82.1 million in the year-ago period.  The Company repaid $20.8 million of term loan and project debt, repurchased $4.3 million of common shares and paid $2.0 million of preferred dividends.  In the comparable 2017 period, the Company repaid $79.6 million of term loan and project debt (including Piedmont, in full) and paid $2.2 million of preferred dividends.

During the fourth quarter, the Company had a $12.5 million net increase in cash, restricted cash and cash equivalents.         

Financial Results for the Year Ended December 31, 2018

Key Drivers

The most significant drivers of full year results were the expirations, early terminations and short-term extensions of the PPAs at Kapuskasing and North Bay; the San Diego projects and Williams Lake and, 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 (though they were very close to average).  These declines were partially offset by increases at Morris, Mamquam, Frederickson, Orlando and Nipigon.    

Net Income (Loss), Project Income (Loss) and Project Adjusted EBITDA

Net income attributable to Atlantic Power Corporation for 2018 was $36.8 million compared to a net loss of $(98.6) million in 2017.  The $135.4 million improvement was primarily attributable to a $135.6 million increase in Project income (discussed below); a $39.1 million increase in unrealized foreign exchange gain ($22.8 million gain versus a $16.3 million loss), which was related to the revaluation of debt denominated in Canadian dollars (due to the depreciation of the Canadian dollar during the year, compared to an appreciation in 2017, and to higher Canadian debt instruments due to the issuance of the Series E convertible debenture in January 2018); an $11.5 million reduction in corporate interest expense as a result of debt repayment and re-pricing of the Company's credit facilities, and a $3.2 million unrealized gain on the fair value of the conversion option of the Series E debentures.  These positive factors were partially offset by a $58.3 million reduction in income tax benefit.    

Project income for 2018 increased to $88.2 million from a project loss of $(47.4) million in 2017.  The $135.6 million improvement was primarily attributable to the non-recurrence of $187.1 million of impairment expense recorded in 2017, a $15.7 million reduction in interest expense due to lower debt balances and the reduced spread on the Company's credit facilities.  In addition, the Company recorded a purchase accounting gain of $7.2 million on the acquisition of the remaining ownership interests in Koma Kulshan.  Also, Morris, Orlando and other projects had increases in project income.  These positive variances were partially offset by lower gross margins resulting from the PPA expirations previously discussed, the non-recurrence of the OEFC settlement revenues and maintenance expense associated with the Tunis re-start, and the Manchief gas turbine overhaul.

Project Adjusted EBITDA for 2018 declined to $185.1 million from $288.8 million in 2017.  The $103.7 million decrease was primarily attributable to the expiration of contracts at Kapuskasing and North Bay at year end 2017 (-$71.3 million); the early termination of the PPAs for the three San Diego projects effective March 1, 2018 (-$24.0 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 (-$9.0 million); a less favorable short-term PPA at Williams Lake, partially offset by cost reductions (-$8.4 million); maintenance expenses associated with the Manchief gas turbine overhaul in the second quarter of 2018 (-$5.5 million), and lower water flows at Curtis Palmer (-$2.8 million).  Partially offsetting these decreases were increases at Morris ($7.4 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; Mamquam ($3.3 million), due to higher water flows and lower maintenance expense; Frederickson ($3.0 million), due to maintenance expense in 2017; and Orlando ($2.9 million), due to higher availability and higher contractual capacity rates.

Cash Flow

Cash provided by operating activities declined $31.7 million to $137.5 million in 2018 from $169.2 million in 2017.  Results were negatively affected by the $103.7 million reduction in Project Adjusted EBITDA.  However, this impact was partially offset by $39.3 million of net favorable changes in working capital, particularly a $20.6 million decrease in working capital at Kapuskasing, North Bay and the three San Diego projects, as they were not in operation at year end 2018.  In addition, cash interest payments were $30.7 million lower in 2018 than in 2017, as a result of debt repayment and a lower spread on the Company's credit facilities, and distributions from unconsolidated affiliates increased $14.3 million (mostly at Chambers and Orlando).

Cash used in investing activities in 2018 was $17.0 million compared to $4.3 million in 2017.  In 2018, 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 $1.8 million as compared to $5.3 million in 2017.

Cash used in financing activities in 2018 was $135.0 million as compared to $178.9 million in 2017.  In 2018, 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 $100.3 million of term loan and project debt, repurchased $16.6 million of common shares and $8.0 million (US$ equivalent) of preferred shares, paid $8.3 million of preferred dividends and incurred $5.1 million of deferred financing costs.  In 2017, the Company repaid $165.9 million of term loan and project debt, repurchased $3.3 million (US$ equivalent) of preferred shares and paid $8.7 million of preferred dividends.

For the full year 2018, the Company had a $14.5 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 December 31, 2018 was $191.4 million, up $10.8 million from $180.6 million at September 30, 2018.  Cash increased $10.7 million while revolver availability was nearly unchanged.  The increase in cash was attributable to discretionary cash flow generated during the quarter after debt repayment, capital expenditures and preferred dividends.  During the quarter the Company used $4.3 million of cash for repurchases of common shares.  At December 31, 2018, there was $45.9 million of cash at the parent, of which the Company considers approximately $39 million to be discretionary cash available for general corporate purposes.   

 

 

Balance Sheet

Debt Repayment

During the fourth quarter of 2018, the Company repaid $20 million of the APLP Holdings term loan and amortized $750 thousand of project-level debt.  For the full year 2018, the Company repaid $90 million of the term loan and $10.3 million of project debt.   

At December 31, 2018, the Company's consolidated debt was $727.4 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 Company plans to use liquidity to redeem the remaining Cdn$24.7 million of 6.00% Series D Debentures (US$18.1 million equivalent) at or before their December 2019 maturity date.

The Company's $200 million revolving credit facility matures in April 2022.  Although approximately $77 million is being used for letters of credit, there are no borrowings outstanding under the revolver.

The $450 million APLP Holdings term loan is being repaid through amortization and the sweep, with approximately $125 million of the principal expected to be remaining at the April 2023 maturity date.  

Re-pricing of Term Loan and Revolver

As previously reported, the Company executed two re-pricings of the APLP Holdings term loan and revolving credit facility in 2018, reducing the interest rate margin on the term loan and revolver by a combined 75 basis points, to LIBOR plus 275 basis points.  Interest cost savings attributable to these two re-pricings are estimated to be approximately $3.6 million in 2019.  There have been a total of four re-pricings since April 2017, resulting in a cumulative reduction in the spread of 225 basis points.  The interest cost savings associated with the cumulative reduction are expected to be approximately $44.4 million from the time of re-pricing through the remaining terms of the facilities.      

Normal Course Issuer Bid (NCIB) Update

The NCIB that the Company had put in place on December 29, 2017 expired on December 28, 2018.  Under this program, the Company repurchased and canceled approximately 7.8 million common shares at a total cost of $16.6 million, or an average price of $2.13 per share.  The Company also repurchased and canceled 475,000 shares of the 4.85% Cumulative Redeemable Preferred, Series 1 at Cdn$15.27 per share; 5,000 shares of the Cumulative Rate Reset Preferred, Series 2 at Cdn$17.99 per share; and 164,790 shares of the Cumulative Floating Rate Preferred, Series 3 at Cdn$17.89 per share, for a total cost of Cdn$10.3 million (US$8.0 million equivalent).  The Company reached the 10% limit on Series 1 and Series 3 repurchases under this NCIB.    

In the fourth quarter of 2018, the Company repurchased and canceled nearly 2.0 million common shares at a total cost of $4.3 million, or an average price of $2.15 per share.  There were no repurchases of preferred shares during the fourth quarter.   

On December 31, 2018, the Company put in place a new NCIB for common shares, preferred shares and convertible unsecured subordinated debentures.  Details of this program can be found in the Company's December 20, 2018 press release.   

In January 2019, under the new NCIB, the Company repurchased 427,500 shares of the 4.85% Cumulative Redeemable Preferred, Series 1 at Cdn$14.26 per share; 27,777 shares of the Cumulative Rate Reset Preferred, Series 2 at Cdn$18.00 per share; and 148,311 shares of the Cumulative Floating Rate Preferred, Series 3 at Cdn$17.69 per share, for a total cost of Cdn$9.2 million.  With these repurchases, the Company has reached the 10% limit on Series 1 and Series 3 repurchases under this NCIB.   

2019 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 initiated guidance for 2019 Project Adjusted EBITDA in the range of $175 million to $190 million.  The midpoint of this guidance range is in line with the 2018 actual result of $185.1 million.  The most significant factor negatively affecting 2019 results is the short-term contract extension at Williams Lake, which became effective in April 2018 and is scheduled to expire in June or possibly as late as September of this year.  In 2018, Williams Lake had Project Adjusted EBITDA of $8.0 million, but this included three months under the previous contract.  Results in 2019 are expected to be significantly lower.  Project Adjusted EBITDA for Tunis and Manchief is expected to be significantly higher this year due to start-up and overhaul-related expenses, respectively, incurred in 2018.  The Company's guidance assumes average water conditions for its hydro projects.  In 2018, water flows at Curtis Palmer were very close to average while those for Mamquam were better than average.    

Table 3 provides a bridge of the Company's 2019 Project Adjusted EBITDA guidance to an estimate of 2019 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 decline in 2019 estimated Cash provided by operating activities from the 2018 level of $137.5 million is largely attributable to the working capital assumption, Chambers project debt amortization of $5.2 million (captured in the adjustment for equity method projects), and expected decommissioning outlays.

 

 

Commercial and Operational Updates

2019-2021 PPA Expirations

The Company has four projects with PPAs that are scheduled to expire in 2019 and 2020.  There are no PPAs expiring in 2021.

Williams Lake (British Columbia).  Since April 2, 2018, the project has been operating under an amended energy purchase agreement with BC Hydro, which provided 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.  A recent report prepared for the Ministry of Energy on contracted power purchases by BC Hydro includes commentary that is supportive of biomass re-contracting in the province and provides some guidance to BC Hydro on this topic.  The Company regards this as a positive development and expects that it may begin discussions with BC Hydro on a potential longer-term contract in the next couple of months.        

Kenilworth (New Jersey).  Merck recently executed the second of its three successive one-year renewal options under the Energy Services Agreement, which extended the expiration date to September 2020.  The Company is in discussions with Merck regarding potential execution of the third extension as well as longer-term options.  In 2018, Kenilworth generated $2.0 million of Project Adjusted EBITDA. 

Oxnard (California).  The PPA with Southern California Edison will expire in May 2020 unless extended prior to that date.  The Company has pursued re-contracting opportunities but has not been successful to date.  In 2018, Oxnard generated $2.1 million of Project Adjusted EBITDA.  

Calstock (Ontario).  The PPA with the Ontario Electricity Financial Corporation will expire in June 2020 unless extended prior to that date.  Ontario remains a challenging market from a re-contracting perspective, as wholesale power prices are low.  The Company will continue to focus its efforts on advocating with the government in support of biomass and pursuing creative approaches that may benefit all parties.  In 2018, Calstock generated $5.5 million of Project Adjusted EBITDA.

Decommissioning of San Diego Projects

Naval Station, North Island and NTC (San Diego).  As previously reported, the Company is required by its land use agreements with the Navy to decommission its three project sites in San Diego.  The Company has made significant progress with the Navy in defining the scope of work for each of the three sites.  Based on current cost estimates, which could increase upon finalization of scope and receipt of final bids for the work, the Company recorded an additional $3.5 million of decommissioning expense in the fourth quarter of 2018 (decommissioning expense is not included in Project Adjusted EBITDA).  Based on these estimates, the Company anticipates cash outlays for decommissioning of approximately $5 million, nearly all of which will be incurred in 2019, with expected completion of the work in the third quarter of this year.  To date, the Company has realized approximately $1.7 million of salvage proceeds, most of which was received in January 2019.  

Update on Tunis and Nipigon Operations

Tunis (Ontario).  The project was returned to commercial operation under a 15-year PPA with the Ontario Independent Electricity System Operator (IESO) in October 2018; prior to that, it had not been in operation since December 2014.  Costs associated with preparing the project for re-start totaled approximately Cdn$5.1 million (US$4 million equivalent), most of which were incurred in the first six months of 2018 and all of which were expensed.  Under the PPA, Tunis operates as a dispatchable facility and receives 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, although it has not operated since returning to service. 

Nipigon (Ontario).  Nipigon is now under a Long-Term Enhanced Dispatch Contract (LTEDC) that went into effect in November 2018, replacing the original PPA while retaining the same contract expiration date (December 2022).  Nipigon receives 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, although it has not operated since the LTEDC went into effect.  The Company plans to install upgrades to some of the project's components and systems in 2019.

Maintenance and Capex

In the fourth quarter of 2018, the Company incurred $6.0 million of maintenance expense.  For the full year, maintenance expense totaled approximately $33.7 million and capital expenditures approximately $1.5 million.  The most significant of these expenses this year were for the Tunis start-up (in the first six months of 2018) and the Manchief gas turbine overhaul (in the second quarter).  For 2019, the Company is projecting maintenance expense of approximately $23.1 million (no major outages planned) and capital expenditures of approximately $1.2 million.  (All of these figures include the Company's proportional share of maintenance expenses and capital expenditures at equity method investments.)   

Financial Results by Segment and by Project

A schedule of Project income (loss) and Project Adjusted EBITDA by segment for the fourth quarter and full year 2018 and the comparable 2017 periods can be found on page 14 of this release.

A schedule of Project income (loss), Project Adjusted EBITDA and Cash Distributions by project for the fourth quarter and full year 2018 and the comparable 2017 periods can be found in the fourth 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. 

Supplementary Information Regarding Non-GAAP Disclosures

A discussion of non-GAAP disclosures and a schedule reconciling Project Adjusted EBITDA, a non-GAAP measure, to the comparable GAAP measure, can be found on page 15 of this release.

Investor Conference Call and Webcast

Atlantic Power's management team will host a telephone conference call and webcast on Friday, March 1, 2019 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, March 1, 2019 
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 10128680 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 March 31, 2019 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 
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 view that the two acquisitions announced in 2018 will add to capacity, average contract life and Project Adjusted EBITDA;
• the Company's view that its 2018 Project Adjusted EBITDA was at the high end of its guidance range and that Operating Cash Flow modestly exceeded its expectations;
• the Company's expectation that it will repay $86 million of consolidated debt and $5 million of Chambers debt in 2019;
• the Company's view that approximately $39 million of cash at the parent is available for discretionary purposes;
• 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 plan to redeem the Series D convertible debentures at or before their December 2019 maturity;
• the Company's estimate that approximately  $125 million of its term loan will be outstanding at the April 2023 maturity date, with the balance having been repaid previously through amortization and the sweep;
• the Company's estimates of interest cost savings resulting from the re-pricing of its term loan and revolver;
• the Company's guidance for 2019 Project Adjusted EBITDA in the range of $175 million to $190 million;
• the Company's estimate for 2019 Cash provided by operating activities in the range of $100 million to $115 million, assuming for this purpose that changes in working capital are nil;
• the Company's estimation that 2019 Project Adjusted EBITDA for Williams Lake will be significantly lower than in 2018, and its expectations for re-contracting for that project;
• the Company's estimation that 2019 Project Adjusted EBITDA for Tunis and Manchief will be significantly higher than in 2018;
• the Company's assumption in its 2019 guidance of average water conditions for its hydro projects;
• the Company's estimation that cash outlays associated with the decommissioning of the three San Diego projects will total approximately $5 million and will be mostly incurred in 2019;
• the Company's estimation that, in 2019, including its share of equity-owned projects, maintenance expense will total approximately $23.1 million and capital expenditures will total approximately $1.2 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 8 below.

 

 

SOURCE Atlantic Power Corporation