Atlantic Power Corporation Releases Fourth Quarter and Year End 2017 Results

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

Fourth Quarter and Full Year 2017 Highlights

• Cash provided by operating activities of $31.3 million in Q4 2017 vs. $20.4 million in Q4 2016
• $169.2 million for the full year 2017 vs. $112.3 million in 2016, up $56.9 million
• Net loss attributable to Atlantic Power of $(41.1) million in Q4 2017 vs. $(6.6) million in Q4 2016
• $(98.6) million for the full year 2017 vs. $(122.4) million in 2016, a $23.8 million improvement
• Project Adjusted EBITDA of $62.2 million in Q4 2017 vs. $42.3 million in Q4 2016
• $288.8 million for the full year 2017 vs. $202.2 million in 2016, an increase of $86.6 million; Company's 2017 guidance was a range of $260 to $275 million
• Repaid $79.6 million of term loan and project debt in Q4 2017 and $165.9 million for the full year
• Leverage ratio at year end 2017 was 3.3 times, down from 5.6 times at year end 2016
• Liquidity at December 31, 2017 of $198.2 million, including approximately $40 million of discretionary cash
• In October, executed second repricing of term loan and revolver and a one-year extension of the maturity date of the revolver to April 2022
• Also in October, Moody's upgraded the Company's corporate family credit rating to Ba3 from B1

Recent Developments

• In December, executed amendment and short-term extension of Williams Lake energy purchase agreement, subject to regulatory approval
• In December, executed long-term enhanced dispatch contract for Nipigon for November 2018 through December 2022; replaces Power Purchase Agreement (PPA)
• In January, issued Cdn$115.0 million Series E convertible unsecured subordinated debenture with a 6.00% interest rate and a January 2025 maturity; using net proceeds of Cdn$109.1 million to:
• Redeem US$42.5 million Series C convertible debenture, effective March 5, 2018
• Redeem Cdn$56.2 million of Series D convertible debenture, effective March 7, 2018; Cdn$24.7 million will remain outstanding
• Operations at the Company's three San Diego projects ceased on February 7, 2018; continuing to pursue site control with the U.S. Navy while also beginning decommissioning preparations

2018 Guidance and Outlook

• Initiated 2018 Project Adjusted EBITDA guidance (see pages 7-8 of this release)
• Expect to repay another $100 million of debt in 2018

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, 2017.  Net loss attributable to Atlantic Power Corporation of $(41.1) million for the fourth quarter of 2017 increased from $(6.6) million in the year-ago period, primarily because of increased non-cash impairment expense and interest rate swap termination costs, partially offset by higher gross margins at Kapuskasing and North Bay (as discussed on page 2), higher water flows at Curtis Palmer, and revenues related to the OEFC Settlement (as discussed on page 3).  Project Adjusted EBITDA, which does not include impairment expense or interest expense, increased to $62.2 million from $42.3 million in the fourth quarter of 2016, primarily due to increases at Kapuskasing, North Bay, Curtis Palmer and several other projects.  Cash provided by operating activities increased to $31.3 million from $20.4 million in the fourth quarter of 2016.    

"Our 2017 results for Project Adjusted EBITDA and Operating Cash Flow exceeded our guidance and expectations, mostly due to continued strong water flows at Curtis Palmer and the cost savings we have been able to achieve in Ontario," said James J. Moore, Jr., President and CEO of Atlantic Power.  "We ended the fourth quarter with liquidity of $198 million, including approximately $40 million of discretionary cash, after paying off $54.6 million of Piedmont debt in October, ten months ahead of its maturity.  For the full year, we reduced debt by approximately $166 million and ended the year with substantially lower leverage than a few years ago.  During the fourth quarter, as we previously reported, we executed a second successful repricing of our term loan and revolving credit facility, and we executed an agreement to extend the maturity date of our corporate revolver by one year to April 2022.  In January, we issued a new seven-year convertible debenture that allows us to redeem the majority of our existing 2019 convertible debt maturities."

Mr. Moore continued, "Heading into 2018, we have lower debt levels, an improved debt maturity profile, a higher credit rating and stable liquidity.  We intend to pay down another $100 million of debt this year.  We will continue to take a rational approach to capital allocation, remaining committed to our delevering goals while allocating available cash to growth, security repurchases when they are at a compelling price to value, and discretionary debt repayment." 

Financial Results

Results for the fourth quarter and full year 2017 were significantly affected by changes to the operational and contractual status of the Kapuskasing, North Bay and Nipigon projects 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 several of its projects in the second, third and fourth quarters of the year, 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 projects have been under enhanced dispatch contracts that provide fixed monthly payments but do not require the projects 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 projects 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 $2.8 million and $19.4 million lower in the three months and  year ended December 31, 2017, respectively, than in the comparable year-ago periods, but this decrease was more than offset by lower fuel and operations and maintenance expenses.

In 2017, the Company accelerated depreciation at Kapuskasing and North Bay property, plant and equipment in order to fully depreciate both projects by year end 2017, the expiration date of the enhanced dispatch contracts.  The increased depreciation was $5.2 million and $27.4 million for the three months and year ended December 31, 2017, respectively.  However, this increased depreciation expense was mostly offset by lower amortization expense of $26.3 million, primarily because the Company had accelerated amortization of the intangible assets (PPAs) for both projects in the fourth quarter of 2016.   

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 PPAs for the Kapuskasing, North Bay and Tunis projects.  A subsequent adjustment increased this amount to approximately Cdn$37.8 million.  In the fourth quarter of 2017, the Company recorded Cdn$3.8 million of revenue related to the OEFC settlement.  The benefit to Project Adjusted EBITDA from the OEFC Settlement was US$28.6 million for the full year 2017, including $3.0 million recorded in the fourth quarter.

Impairment of Goodwill, Long-Lived Assets and Equity Investments

In the fourth quarter of 2017, the Company recorded event-driven impairments of its equity investment in Frederickson and its Williams Lake project (consolidated).  Also in the fourth quarter of 2017, the Company conducted its annual impairment test of goodwill and long-lived assets.  As a result of that test, it recorded an impairment of goodwill at its Curtis Palmer project.

The Company owns a 50.15% interest in Frederickson, which is a gas-fired project that operates under three PPAs that expire in August 2022.  As an equity-owned project, it is not reviewed as part of the Company's annual assessment but only in response to a triggering event.  Although declining power prices have been observed for several years, in the Company's most recent long-term forecast completed in December 2017, it identified a significant decrease in the long-term outlook for power prices for the region.  The Company performed an analysis of the value of the project on the assumption that it operates as a merchant facility after the PPAs expire.  The decline in the long-term price forecast had a significant negative impact on the estimated discounted cash flows of Frederickson post-PPA, which the Company views as other than temporary.  Accordingly, in the fourth quarter of 2017, the Company recorded a $28.3 million impairment of the $108.3 million carrying value of its investment.  The impairment was included in earnings from unconsolidated affiliates.  The Company continues to see value for the project post-PPA because of planned large coal plant retirements and strong population growth in the region. 

Also in the fourth quarter of 2017, the Company recorded a $29.1 million impairment of the $40.0 million carrying value of long-lived assets at its Williams Lake project.  This was based on an assessment of the cash flows under the short-term contract extension recently executed for Williams Lake as well as a probability-weighted evaluation of expected cash flows under a long-term extension.   

In conducting the annual impairment assessment for its consolidated projects, the Company determined that there had been a decline in the long-term power price forecast for its Curtis Palmer project for the period beyond the expiration of the project's existing PPA.  Accordingly, in the fourth quarter of 2017, the Company recorded a $14.7 million impairment of goodwill at Curtis Palmer, which reduced the carrying value of the project's goodwill to $14.4 million.

As previously reported, in the third quarter of 2017, the Company recorded a $57.3 million impairment of long-lived assets at its three San Diego projects, based on the expectation that they would not continue to operate beyond the expiration of the agreements with the U.S. Navy that provided the Company with the right to use the property.  On February 7, 2018, the Company ceased operations at all three projects. 

Also as previously reported, in the second quarter of 2017, the Company recorded a $47.1 million impairment of its equity investment in Chambers and a $10.6 million full impairment of its equity investment in Selkirk.  In November 2017, the Company sold its 17.7% interest in Selkirk to the majority partner for $1.0 million.  The Company recorded a $1.0 million gain on sale in the fourth quarter of 2017, which was included in earnings from unconsolidated affiliates.    

Total impairment expense for 2017 was $187.1 million, including $86.0 million included in earnings from unconsolidated affiliates.  This expense reduced both Project income and Net income, but did not affect cash provided by operating activities or Project Adjusted EBITDA. 

Three Months Ended December 31, 2017

Net loss attributable to Atlantic Power Corporation for the fourth quarter of 2017 was $(41.1) million as compared to $(6.6) million in the fourth quarter of 2016.  The $34.5 million increase in net loss was the result of a $70.9 million increase in impairment expense, as discussed previously, a $9.9 million adverse change in the fair value of derivative instruments (non-cash), and $5.1 million of higher interest expense, primarily attributable to the $9.4 million cost of terminating the interest rate swap at Piedmont when that project's debt was redeemed in October 2017.  These negative factors were partially offset by increased gross margin and lower operation and maintenance expense at Kapuskasing and North Bay, due to the revised contractual and operational arrangements discussed previously, higher gross margin at Curtis Palmer due to higher water flows, OEFC Settlement revenues, lower depreciation and amortization expense, and an increased tax benefit.   

Project loss for the fourth quarter of 2017 was $(39.7) million as compared to project income of $13.3 million in the year-ago period.  The $53.0 million reduction from income to loss was primarily attributable to increased impairment expense, an adverse change in the fair value of derivatives, and the interest rate swap termination cost at Piedmont.  These negative factors were partially offset by higher gross margins and lower operating expenses at Kapuskasing and North Bay, the final OEFC Settlement revenues, higher revenues at Curtis Palmer due to higher water flows, and lower depreciation and amortization expense. 

Project Adjusted EBITDA for the fourth quarter of 2017 was $62.2 million, an increase of $19.9 million from $42.3 million in the year-ago period.  The primary drivers were the favorable impact on gross margins of the enhanced dispatch contracts and the expiration of an above-market gas contract in Ontario (totaling $13.5 million), OEFC Settlement revenues ($3.0 million), higher water flows at Curtis Palmer ($2.6 million), and modest increases at Oxnard, Orlando and other projects.  These positive factors were partially offset by a $2.0 million decrease at Kenilworth, which benefited from a gas settlement in the prior period, and more modest decreases at several other projects.  During the quarter, the Canadian dollar depreciated modestly relative to the year-ago period.  This had a non-cash translation benefit to Project Adjusted EBITDA of approximately $1.3 million.

Cash provided by operating activities for the fourth quarter of 2017 of $31.3 million increased $10.9 million from $20.4 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, receipt of OEFC Settlement revenues, and higher water flows at Curtis Palmer. 

Significant uses of the $31.3 million of cash provided by operating activities included $22.7 million of term loan amortization, $2.4 million of project debt amortization and $2.2 million of preferred dividend payments.    

Year Ended December 31, 2017

Net loss attributable to Atlantic Power Corporation for the year ended December 31, 2017 was $(98.6) million as compared to $(122.4) million for the year ended December 31, 2016.  The $23.8 million reduction in loss was the result of several positive factors, including increased revenues of $31.8 million (primarily the result of the OEFC Settlement, increased water flows at Curtis Palmer, higher steam revenues at the San Diego projects, and higher revenues at Morris, which had an extended planned outage in 2016, partially offset by lower revenues under the enhanced dispatch contracts), lower fuel and operations and maintenance expenses totaling $60.5 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 2016), and a $33.5 million reduction in corporate and project interest expense (due to a $31.4 million write-off of deferred financing costs in 2016 and lower debt levels).  The Company also had an increased tax benefit.  These positive factors were partially offset by a $101.2 million increase in impairment expense, as previously discussed, and a $35.8 million negative change in the fair value of derivative instruments (non-cash),

Project loss for the year ended December 31, 2017 was $(47.4) million as compared to project income of $10.1 million in 2016.  The $57.5 million reduction from income to loss was primarily attributable to the impairment charges recorded for the Company's consolidated and equity owned projects and the negative change in the fair value of derivative instruments, partially offset by increased revenues and lower fuel and operations and maintenance expense, as discussed previously.

Project Adjusted EBITDA for the year ended December 31, 2017 was $288.8 million, an increase of $86.6 million from $202.2 million in the year-ago period.  The primary drivers of the increase were the favorable impact on gross margins of the enhanced dispatch contracts and the expiration of an above-market gas contract in Ontario (totaling $41.6 million), the OEFC Settlement ($28.6 million), increased water flows at Curtis Palmer ($12.6 million), and more modest increases at Orlando ($4.6 million, due to the settlement of favorable fuel swaps), Morris ($4.0 million, mostly due to the extended planned outage in 2016), and several other projects.  These positive factors were partially offset by decreases at Mamquam (-$3.2 million, due to lower water flows in the first, second and fourth quarters of 2017 compared to a record year in 2016, and a forced outage in the second quarter of 2017), Frederickson (-$2.1 million, due to higher planned maintenance expense in the second quarter of 2017), and Calstock (-$1.8 million, due to lower waste heat and higher fuel prices).  During 2017, the Canadian dollar depreciated slightly relative to 2016.  This had a non-cash translation benefit to Project Adjusted EBITDA of approximately $3.0 million.   

Cash provided by operating activities for the year ended December 31, 2017 of $169.2 million increased $56.9 million from $112.3 million a year ago.  The 2017 period included approximately $26.6 million of cash collected under the OEFC Settlement, most of which occurred in the second quarter.  (Another $2.0 million recorded in 2017 revenue was collected in early 2018.)  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 higher water flows at Curtis Palmer.  These positive factors were partially offset by decreases at Mamquam, Frederickson and Kenilworth, for reasons previously discussed.  In addition, cash provided by operating activities was reduced $24.3 million from the year-ago period due to changes in working capital, primarily due to the timing of revenue receipts at Kapuskasing, Nipigon and North Bay ($10.5 million) and a decrease in prepaids, supplies and other assets ($3.4 million). 

Significant uses of the $169.2 million of cash provided by operating activities during the year ended December 31, 2017 included $165.9 million of debt repayment and $8.7 million of preferred dividend payments.  The Company also used $5.3 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 December 31, 2017 was $198.2 million, a decrease of $51.6 million from the September 30, 2017 level.  The decrease consisted of a $43.7 million decrease in unrestricted cash and a $7.9 million decrease in revolver availability.  The reduction in liquidity was primarily attributable to the redemption of Piedmont project debt in full in October 2017, including accrued interest and swap termination costs, and the need to post a project-level letter of credit.  Total use of liquidity for this purpose was $75.8 million. 

The Company's unrestricted cash of $78.7 million includes $49.7 million at the parent, of which the Company considers slightly more than $40 million to be discretionary cash available for general corporate purposes.   

Balance Sheet

Debt Repayment

During the fourth quarter of 2017, the Company repaid $22.7 million of the APLP Holdings term loan, repaid $54.6 million of remaining project debt at Piedmont, and amortized $2.4 million of project-level debt.  For the full year, the Company repaid $100 million of the term loan and repaid or amortized $66 million of project-level debt, including Piedmont.  At December 31, 2017, the Company's consolidated debt was $846 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 3.3 times.  The improvement in the leverage ratio from 3.8 times at September 30, 2017 was primarily attributable to the positive impacts on EBITDA of the OEFC Settlement payments and the enhanced dispatch contracts combined with the continued reduction in debt, including at Piedmont.

Convertible Debentures

On January 29, 2018, the Company closed the offering of Cdn$100.0 million of Series E convertible unsecured subordinated debentures (the "Series E debentures").  On February 2, 2018, the underwriters exercised their over-allotment option, which resulted in the Company issuing another Cdn$15.0 million of Series E debentures.  The Series E debentures, which carry a 6.00% interest rate, have a maturity date of January 31, 2025.  The conversion rate on the Series E debentures is approximately 238.0952 common shares per Cdn$1,000 principal amount, representing a conversion price of Cdn$4.20 per common share.  Net proceeds from the offering after expenses totaled Cdn$109.1 million.

The Company used the net proceeds from the Series E offering to redeem, in full, the outstanding principal amount of US$42.5 million of Series C debentures (which have a maturity date of June 2019) and to redeem Cdn$56.2 million, on a pro rata basis, of the outstanding principal amount of the Series D debentures (which have a maturity date of December 2019).  The redemptions will occur on March 5 and March 7, 2018, respectively.  Following the redemptions, the Company will have Cdn$24.7 million of Series D debentures outstanding.   

Debt Maturity Profile

Following the issuance of the Series E debentures, the redemption of the Series C debentures in full and the partial redemption of the Series D debentures, the Company   will have no bullet maturities until December 2019, the maturity date of the remaining Cdn$24.7 million of Series D debentures.  The Series D debentures are callable at par at any time prior to maturity.  There are no bullet maturities in 2020 or 2021.  In October 2017, the Company extended the maturity date of its $200 million revolving credit facility by one year, to April 2022.  The $540 million APLP Holdings term loan has an April 2023 maturity, although it is expected to be more than 80% repaid by the maturity date.  As previously noted, the Company has Cdn$115.0 million of Series E debentures maturing in January 2025. 

Repricing of Term Loan and Revolver

As previously reported, in October 2017 the Company executed a repricing of the APLP Holdings term loan and 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 represented the second repricing for these facilities in 2017, resulting in a cumulative reduction in the spread of 150 basis points.  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 were included in interest expense in the fourth quarter of 2017.   

Normal Course Issuer Bid (NCIB) Update

The normal course issuer bid ("NCIB") that the Company had put in place in December 2016 expired on December 28, 2017.  Amounts repurchased under this NCIB totaled 93,391 common shares at an average price of $2.36 per share, 250,000 shares of the 4.85% Cumulative Redeemable Preferred (Series I issue) at Cdn$15.50 per share for a total payment of Cdn$3.9 million, and a nominal amount of convertible debentures (less than Cdn$100,000).  There were no purchases under this NCIB in the fourth quarter of 2017.  

On December 29, 2017, 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, 2017 press release. 

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 has initiated guidance for 2018 Project Adjusted EBITDA in the range of $170 to $185 million.  The expected decrease from the 2017 level 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.  These factors account for approximately $105 million of the expected decrease, consistent with disclosures made in the Company's third quarter 2017 financial results presentation.  Other factors contributing to lower Project Adjusted EBITDA include maintenance expense associated with a planned gas turbine overhaul at Manchief in the second quarter of 2018 and restart costs for Tunis.  The majority of the Tunis costs are being incurred in 2018 and a substantial majority will be expensed.  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 (higher PJM capacity prices) 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 mitigated by lower cash interest payments in 2018 relative to 2017.  The expected $25 million 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, and the non-recurrence of the Piedmont interest rate swap termination cost.  

Other Financial Updates

Update on 2017-2018 PPA Expirations

As previously disclosed, the Company has seven projects with PPAs (or lease agreements, in the case of the San Diego projects) that are scheduled to expire (or have expired) between year end 2017 and September 2018. 

Kapuskasing and North Bay (Ontario).  The enhanced dispatch contracts for both projects expired on December 31, 2017 and were not extended or renewed.  Both projects are in a non-operational status, though the Company does not plan to decommission either at this time.

Naval Station, NTC and North Island (San Diego).  The projects ceased operations on February 7, 2018 when the agreements with the U.S. Navy that provided the Company the right to use the sites expired.  As a result, the projects are no longer selling power to San Diego Gas & Electric ("SDG&E") under their respective PPAs.  Although the Company remains in communication with the Navy regarding alternate paths to site control for one or more of the projects, the paths are challenging and the outcome is uncertain.  The Company is also preparing estimates for the scope and timing of decommissioning the three sites.  On March 1, 2018, the California Public Utilities Commission ("CPUC") approved the seven-year Power Purchase Tolling Agreements with SDG&E for Naval Station and North Island (initially disclosed in the Company's August 1, 2017 press release), Resource Adequacy agreements for all three projects, and early termination of the existing PPAs.  The CPUC decision is subject to a 30-day appeal period.  However, operation of the projects continues to be subject to the Company obtaining site control. 

Williams Lake (British Columbia).  In December 2017, the Company executed an amendment to and extension of the existing energy purchase agreement with BC Hydro, which was scheduled to expire on April 1, 2018.  The amended contract is subject to approval of the BC Utilities Commission.  The extension covers the period from April 2, 2018 to June 30, 2019, or September 30, 2019 at the option of BC Hydro.  The Company will not upgrade the facility or burn rail ties during the extension period.  The purpose of the extension is to bridge to the outcome of BC Hydro's integrated resource plan (IRP) in the second or third quarter of 2019, which will determine the role of biomass in the utility's long-term energy needs.  The outcome of the IRP is expected to have a major impact on the Company's ability to operate Williams Lake over the longer term.

Kenilworth (New Jersey).  The PPA with Merck is scheduled to expire on September 30, 2018, though there are provisions for a series of short-term extensions at Merck's option.  The Company is exploring short- and long-term alternatives with Merck.   

Nipigon (Ontario).  Since January 2017, Nipigon has been under an enhanced dispatch contract with the Ontario Independent Electricity System Operator ("IESO").  During this time, the PPA for the project, which has an expiration date of December 2022, has been suspended.  In December 2017, the Company entered into a long-term enhanced dispatch contract with the IESO for Nipigon for the period November 1, 2018 through December 31, 2022.  As a result, the PPA will be terminated effective October 31, 2018.  The long-term enhanced dispatch contract provides for Nipigon to receive monthly capacity-type payments based on the original PPA, with adjustment for operational savings that will be shared with the IESO.  In addition, the project will function as a market participant and earn energy revenues for those periods during which it operates.  In 2018, the Company will accelerate amortization of the remaining $18.3 million of intangible PPA asset through October 31, 2018.              

Tunis Planned Restart

In the fourth quarter of 2017, the Company commenced work on returning Tunis to service as a simple-cycle plant with a targeted commercial operation date of the third quarter of 2018.  Most of the estimated $5 to $6 million cost will be incurred in 2018 and a substantial majority is expected to be expensed.  The project has a 15-year PPA that will commence with commercial operation.  Under the PPA, Tunis will receive monthly capacity payments and will earn energy revenues for those periods during which it operates.   

Maintenance and Capex

Including its share of equity-owned projects, the Company incurred maintenance expenses of $32.6 million and capital expenditures of $5.5 million in 2017.  The majority of the capital expenditures ($4.9 million) was incurred in the first nine months of 2017 and was related to the upgrade of the third and final combustion turbine at Morris, which was completed in the second quarter of 2017.

For 2018, the Company expects to incur maintenance expenses of approximately $34.8 million and capital expenditures of approximately $1.4 million.  The modest increase in maintenance expense relative to 2017 is associated with the Tunis restart work and the Manchief gas turbine outage, partially offset by lower maintenance expense at Frederickson and other projects. 

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 15 of this release.

Investor Conference Call and Webcast

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

Conference Call / Webcast Information:

Date:  Friday, March 2, 2018 

Start Time:  8:30 AM ET

Phone Number:  U.S. (Toll Free) 1-855-239-3193; Canada (Toll Free) 1-855-669-9657; International (Toll) 1-412-542-4129.

Conference Access:  Please request access to the Atlantic Power conference call.

Webcast:  The call will be broadcast over Atlantic Power's website at www.atlanticpower.com.

Replay/Archive Information:

Replay:  Access conference call number 10117040 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 April 2, 2018 at 11:59 PM ET.     

Webcast archive:  The c