Exhibit 99.1
PREPARED REMARKS
Q3 2019
NOVEMBER 1, 2019
Ron Bialobrzeski — Atlantic Power Corporation — Director, Finance
Page 2: Cautionary Note Regarding Forward-Looking Statements
Financial figures that are presented in this document and the presentation are stated in U.S. dollars and are approximate unless otherwise noted.
Management’s prepared remarks presented in this document include forward-looking statements. As discussed on page 2 of the accompanying presentation, these statements are not guarantees of future performance and involve certain risks and uncertainties that are more fully described in our various securities filings. Actual results may differ materially from such forward-looking statements. Please see Atlantic Power Corporation’s Safe Harbor statement, presented on page 2 of the accompanying presentation, which can be found in the Investor Relations section of our website.
In addition, the financial results in the Company’s press release and the presentation include both GAAP and non-GAAP measures, including Project Adjusted EBITDA. For reconciliations of this measure to the most directly comparable GAAP financial measure to the extent that they are available without unreasonable effort, please refer to the press release, the Appendix of the presentation or our quarterly report on Form 10-Q, all of which are available on our website.
For additional information, please refer to our most recent SEC filings, which can be accessed free of charge on our website, www.atlanticpower.com, and on EDGAR and SEDAR.
James J. Moore, Jr. — Atlantic Power Corporation — President & CEO
Pages 4-5: Q3 2019 Highlights and Cadillac
Let me begin with the fire at Cadillac, which occurred on September 22nd while the plant was being brought down for its annual fall outage. The most important fact is that no one was injured. We tell our people that safety is more important than money. We are still investigating the cause along with our insurers. At this time we believe that the fire probably resulted from a malfunction in the steam turbine, but we have more work to do before reaching any firm
conclusions. We do know that the fire did not involve the fuel areas of the plant and was not related to anything specific to biomass plants.
Our assessment is that there was extensive damage to the steam turbine, generator and other components in that area of the plant. The turbine, generator and at least one transformer must be replaced. The boiler, cooling tower, fuel pile and fuel handling areas were not affected.
We are working hard to bring the plant back online. Our estimates of damages and schedules are not well defined as of yet, although we believe the repair and replacement costs will be substantially covered by insurance. Our preliminary estimate is an exposure of approximately $2.5 million to $3.0 million, representing our deductibles. Terry will address this in more detail. We expect the plant to be offline for an extended period, probably at least another nine months.
Although this incident does not appear to be the fault of any of our people or practices, we nevertheless want to use it as a rallying cry for our teams to put safety first and to shoot for perfection in our operations, recognizing — as Vince Lombardi used to say — we won’t achieve perfection but we will catch excellence in that effort. Our plant managers are our most important employees, heading our most critical teams. They need to be outstanding servant leaders. Our commitment to servant leadership has always been strong and after the event at Cadillac we saw it in action, as our people rallied to do the right things before being asked. I want to thank all of our employees throughout the Company for the outstanding performance on September 22nd and in the weeks following.
Turning to the financial results, we had a good third quarter — exceeding our expectations — following a strong first half. As Terry will address, we are raising our 2019 guidance.
During the quarter, we also continued to meet our deleveraging objectives. We have paid the term loan down to $400 million (from $700 million at issuance in April 2016) and our leverage ratio is below four times. We expect our leverage ratio to show further improvement over the next few years, as we pay down debt more quickly than EBITDA may decline (due to the impact of Power Purchase Agreement, or PPA, expirations in 2022 and beyond). We do not have a
2
specific leverage ratio target. We need to see how EBITDA settles out following the near-term PPA expirations, which will be a function of re-contracting outcomes.
We had a significant re-contracting success this quarter, executing a new ten-year contract for Williams Lake. The structure of the contract makes EBITDA and cash flow estimates more volatile, but after we have gotten further down the path in our fuel procurement strategy, we will provide guidance on our longer-term expectations. Based on our internal forecasts, which incorporate the materially higher fuel costs we are seeing in British Columbia, we believe that the new contract is significantly better from an intrinsic value per share standpoint than our earlier estimates, which were based on different re-contracting assumptions. This was a good result delivered by our commercial team.
This quarter also marked a return to growth for our Company. We acquired four contracted biomass plants for a total of $31.3 million. We are integrating the two we own outright into our fleet and already have identified some investments for next year that we expect will further improve returns. Our base case EBITDA for the plants is approximately $7 million to $9 million annually on average through 2027 and approximately $3 million annually on average from 2028 through 2043. The expected investment returns are attractive, particularly in a world of low returns. The acquisitions are accretive to our estimates of intrinsic value per share.
Looking ahead to the next five years, we expect strong operating cash flow with relatively modest exposure to PPA expirations prior to 2023. The majority of this cash flow will be applied to debt repayment, which will allow us to reduce our debt balance by approximately 50% by the end of 2023. We will have significant discretionary cash flow after debt repayment that we will look to allocate rationally, focused on price to value and intrinsic value per share. In 2020 we expect to continue pursuing additional external growth, but if we find little opportunity on that front, we can shift our focus to share buybacks. We have the liquidity and the temperament to move with speed and scale if the markets throw us any fat pitches. Our liquidity is strong at $181 million, relative to an enterprise value of $1.05 billion and an equity market capitalization of only $257 million.
3
As we firm up the EBITDA outlook for the next several years and as we continue to deliver on our deleveraging commitment, we expect the markets may begin to recognize the value in our shares that we believe exists today. In the meantime, we are well protected from a deflationary bust scenario in our sector (or more broadly across the economy) via the PPA cover on our assets. If, on the other hand, markets begin to gravitate toward hard assets because of inflation concerns, we have significant leverage to the upside as our valuation seems to embed poor re-contracting outcomes. This also may begin to be recognized.
Until then, we will continue to work to build value with a focus on frugality and intrinsic value per share. With strong liquidity, a strengthening balance sheet and excess capital to allocate, we can be patient and rational in buying or selling either our own securities or external assets. We have developed a good opportunity set and for patient and disciplined value investors, we like our position. We expect the markets to get more interesting sooner or later but we have good things to do while we are waiting.
Dan Rorabaugh — Atlantic Power Corporation — SVP Operations
Page 6: Q3 2019 Operational Performance
Safety
We had two recordable injuries in the third quarter, and seven in the first nine months of the year. As a result, our total recordable incident rate (TRIR) of 2.85 for the first nine months of 2019 was higher than the prior periods shown in the chart on page 6 of the presentation. Three of the incidents were lost time events. We take all injuries very seriously. As we discussed last quarter, we continue to take a more proactive approach on this critically important issue. We have monthly safety calls with plant management and safety specialists led by our VP of Safety. We have also increased the frequency of safety meetings and expanded safety-related communications throughout the company. Prior to the start of the fall outage season, we rolled out pre-outage safety training. We continue to make the safety of our employees our number one priority.
Generation
Turning to our operating results, generation increased 2.7% in the third quarter of 2019 compared to the 2018 period, primarily because of the acquisitions of Allendale and Dorchester and equity interests in Craven and Grayling, higher power prices in PJM (Morris), higher water flows at Curtis Palmer, and
4
higher dispatch at Frederickson. Generation at Curtis Palmer increased 30% from the year-ago period, although it was 9% below the historical average. These increases were partially offset by lower generation at Williams Lake, due to voluntary curtailment resulting from lower wood fuel inventory, and at Manchief, due to lower dispatch.
Availability
Our availability factor in the third quarter of 2019 increased slightly to 95.1% from 94.3% in the third quarter of 2018. Cadillac, Morris and Piedmont improved as they had maintenance outages in the comparable 2018 period. These increases to availability were partially offset by decreases at Moresby Lake, due to a transformer failure (which we expect to replace later this fall), and Mamquam, due to a maintenance outage for a runner replacement.
Operations Update
Nipigon
In the third quarter, we upgraded Nipigon’s gas turbine control system to improve reliability and also completed other work required by IESO market rules. Expenditures were modest and consistent with our plan. The operating performance of the plant under the long-term enhanced dispatch contract also has been consistent with our expectations.
Decommissioning of San Diego Sites
We have made progress addressing critical path issues with San Diego Gas & Electric and are now in the process of soliciting final bids from contractors for the demolition work at the three sites. We expect the majority of the work will be completed in the first half of 2020. Our current estimate is a total cost of $6.6 million, of which $852 thousand was spent in the third quarter and $1.5 million has been spent to date. We have realized a total of $1.8 million of salvage proceeds to date, most of it in January 2019. The net cash outlay is thus expected to be approximately $5 million, most of which will be spent in 2020. These estimates are subject to adjustment pending receipt of the final bids for the demolition work.
Cost Focus
During the quarter we continued to advance our program to improve our operation and maintenance performance. We rolled out Mainsaver (maintenance management system) to Allendale and Dorchester, which we acquired in July, and to Koma Kulshan, in which we acquired the remaining ownership interests in the third quarter of 2018. We will be rolling it out to Piedmont this quarter. We have an
5
ongoing focus on optimizing the preventive maintenance programs for all sites. During the quarter, we reviewed and updated the maintenance plans for six sites.
Another area of focus is avoiding equipment issues that result in unplanned outages. To that end, we have installed predictive analytic software (PRiSM) at six plants over the past two years. To date, the system has had 21 good “catches” (potential equipment problems that were avoided). We plan to roll out PRiSM to Allendale and Dorchester in 2020.
Next year we will undertake a benchmarking of our hydro and biomass plants, with a goal of driving further improvements to our cost structure as we add and integrate new assets into our fleet.
Joseph E. Cofelice — Atlantic Power Corporation — EVP Commercial Development
We are pleased with the progress we made this quarter on both our external growth and re-contracting efforts. My remarks today will focus primarily on our Williams Lake biomass plant in British Columbia. I will also review our re-contracting efforts at Oxnard and Calstock and provide an update on our recent biomass plant acquisitions. I’ll close with a brief update on our Manchief transaction.
Page 7: Williams Lake (British Columbia)
The Company executed a new ten-year Energy Purchase Agreement (EPA) with BC Hydro for Williams Lake effective October 1, 2019, which replaces the short-term EPA that had been in place since April 2018 and which expired on September 30, 2019.
The EPA provides for a fixed price (escalating annually at British Columbia CPI) per megawatt-hour of energy produced, up to an annual limit of 388.4 gigawatt-hours (GWh) of generation (an implied average annual capacity factor of approximately 67%). The plant will not operate during the months of May, June, and July (“freshet”, or the annual spring thaw that results in additional water flows for hydroelectric generating facilities), but will perform its annual maintenance during this period. The plant is required to operate in the November through February winter period, and is subject to performance penalties if it fails to meet minimum generation requirements in any one of those months (although in the 2019-2020 winter season, the plant will be required to operate only for the month of February).
The contract does not provide for a capacity payment and there is no fuel cost passthrough under the contract.
6
Conditions in the British Columbia timber market over the past couple of years have led to mill closings and production curtailments, which have adversely affected both the availability and cost of conventional fuel supplies. During the period that the plant was operating under the short-term EPA and prior to reaching agreement on a new long-term contract, we had been procuring fuel on a short-term basis only. In conjunction with negotiating a new contract for the plant, we updated our fuel supply forecasts to reflect costs that are materially higher than those experienced over the past few years.
Our focus now with the new ten-year EPA in place is on procuring fuel and rebuilding our fuel inventory through a variety of sources, including local mills and First Nations. In addition, to expedite and facilitate this effort, we are deploying a mobile shredder (chipper) that should provide access to new supplies of economic forest-based biomass and residue.
With minimal levels of fuel currently on site, our current expectation is that the plant will not operate in the fourth quarter. The EPA allows for lower generation levels in the 2019-2020 winter season so that we have time to rebuild inventory. We do not expect to incur any winter performance penalties if the plant returns to service and achieves the minimum required level of generation in February 2020.
As we have discussed on previous conference calls, we are permitted to burn rail ties up to an annual limit of 35% of the plant’s fuel requirements. This would require installation of a new fuel shredder. With the execution of the new EPA, the economic evaluation of a shredder investment continues, taking into consideration the terms and conditions of the new EPA (including contract term), the significant capital investment required, and the availability and cost of conventional forest-based biomass fuel as compared to the cost of burning rail ties. Investment in a fuel shredder would need to meet our risk/return requirements. We expect to provide a further update on fuel supply and potential options for Williams Lake over the course of the next few quarters.
We plan to make significant maintenance investments in the plant consistent with our new ten-year EPA, including a cooling tower rebuild and generator rewind. We may undertake some maintenance this winter but we expect that most of the expenditures will be incurred in 2020 and 2021 during the May through July period when the plant is scheduled to be off-line. We plan to provide more color on the amount and timing of these expenditures on our fourth quarter conference call. We have also identified some potential optimization investments, but will not undertake these unless it is economic to do so. Based on our planned maintenance, which will be expensed, and our need to rebuild fuel inventories, we estimate that the plant will generate a breakeven or minimal level of EBITDA in 2020.
7
We intend to provide longer-term EBITDA guidance for the plant at a later date. We would note that, due to the absence of a fuel cost passthrough in the contract and considering conditions in the British Columbia timber market, Williams Lake is likely to experience greater variability to EBITDA and cash flow as compared to our other biomass plants.
Page 8: Re-contracting Updates
Oxnard (California)
The Oxnard PPA expires in May 2020. As we discussed last quarter, in June, the California Public Utilities Commission (CPUC) issued an order seeking comments on near-term reliability challenges and options for potential solutions, including the procurement of capacity from existing resources that are uncontracted after 2021. We believe the CPUC order highlights the need for reliable and firm capacity to enable the continued deployment of renewable generation in California.
In September, Southern California Edison (SCE), Oxnard’s customer under its PPA, issued a 2019 System Reliability Request for Offers (RFO). The RFO is a dual-track solicitation that seeks to procure 1,745 MW of incremental system resource adequacy capacity to come online by August 1, 2021 (“Fast” Track) and in 2022 and beyond (“Standard” Track). SCE is seeking proposals for a variety of product offerings, including gas-fired generation capacity. Contract length would vary by type of product; for gas generation, the term would be three to five years. Bids are due in November with decisions by SCE expected in the first quarter of 2020. We plan to submit one or more bids for Oxnard in this RFO. We would note the process is a confidential one and thus we will be unable to comment on the status of our bids until a decision has been made public by SCE.
We are also pursuing in parallel with the RFO other potential paths to a new contract for Oxnard. Although we view these recent actions by the CPUC and SCE favorably, it is too early to know whether these developments will materially improve our re-contracting probability, which is currently low.
Calstock (Ontario)
The Calstock PPA, which expires in June 2020, is our most challenging re-contracting situation in the near term. As we have discussed on previous conference calls, under the current market structure in Ontario, there is no re-contracting mechanism or policy in place to compensate biomass plants for the non-power benefits provided. These benefits include providing an environmentally attractive alternative to landfilling wood waste, economic support for the local timber industry through the purchase of mill
8
residuals, and material economic support to the local community of Hearst, Ontario. We have strong support from the local government, unions, various forestry organizations and Hearst area mills. We continue to remain engaged with the provincial government and are working hard to develop a re-contracting path for Calstock, but have no significant news to report at this time.
Page 9: Biomass Acquisitions - Allendale and Dorchester (South Carolina)
Since closing the acquisition of the Allendale and Dorchester biomass plants at the end of July, we have been focused on integrating them into our fleet. Our integration efforts are on schedule and both plants have been performing in line with our expectations. Prior to closing the acquisition some small improvements were made that are already helping to reduce fuel burn modestly, and some others of a similar size are planned. We also have been evaluating a few optimization initiatives for both plants, primarily to improve boiler efficiency and optimize the fuel handling system. These modest investments, which we plan to make in 2020, are expected to improve plant efficiency (reducing fuel consumption and maintenance expense) and provide us access to additional supplies of lower-cost fuel (reducing unit fuel costs).
As we have noted previously, our base case forecast before any optimization initiatives is for the two plants to produce combined Project Adjusted EBITDA of approximately $3 million annually on average over the remaining term of their PPAs.
Page 10: Biomass Acquisitions - Craven and Grayling
In August, we closed the acquisition of a 50% interest in the 48 megawatt Craven County plant in North Carolina and a 30% interest in the 37 megawatt Grayling plant in Michigan. These plants are well managed and will continue to be operated by CMS Energy, a 50% owner in both plants. Results overall for the third quarter were in line with our expectations. We expect Craven and Grayling to generate a combined Project Adjusted EBITDA of approximately $4 million to $5 million annually on average over the remaining term of their PPAs. Craven and Grayling are accounted for under the equity method.
The acquisitions of the Allendale, Dorchester, Craven and Grayling plants increase our biomass presence to eight plants, including six plants that we operate. These acquisitions, funded from discretionary cash, are expected to meet our return target for external investments and be accretive to our estimates of intrinsic value per share.
9
Manchief Transaction
In May 2019, we announced an agreement to sell our Manchief plant to Public Service Co. of Colorado, the customer under the PPA, in May 2022 following the expiration of the PPA. The agreement is subject to regulatory approvals. In October, the Federal Energy Regulatory Commission approved the transaction. Also in October, the Colorado Public Utilities Commission established a schedule in Public Service Co. of Colorado’s application for a Certificate of Public Convenience and Necessity for the acquisition of Manchief and related cost recovery. The schedule calls for testimony and responses in December followed by an evidentiary hearing in January. The statutory deadline for a Commission decision is in May 2020. We will provide an update on our fourth quarter conference call.
Terry Ronan — Atlantic Power Corporation — EVP & CFO
Slide 11: Accounting and Financial Impacts of Cadillac Event
Before reviewing the results of the third quarter, capital allocation and an update to our 2019 guidance, I will begin by addressing the financial impact of the Cadillac equipment malfunction and fire. We expect the impact to be relatively modest due to our insurance coverage.
We carry both property and business interruption insurance on all of our plants. The property insurance covers the cost of replacing the existing equipment, and carries a $1.0 million deductible. In the third quarter, we recorded a $25.0 million writedown of Cadillac property, plant and equipment and a $0.2 million writedown of capital spares inventory. We also recorded a corresponding insurance receivable of $24.2 million, which reflects the estimated replacement cost less the deductible. This estimate may change, as our assessment of the cost to repair or replace damaged equipment is still in progress. The deductible was recorded as an insurance loss, which reduced Project income (and therefore Net income), but did not affect Project Adjusted EBITDA. Going forward, the cost of repairs or replacement of equipment will be capitalized to property, plant and equipment (included in Investing Cash Flow) with no impact on Operating Cash Flow.
The business interruption insurance effectively (although not precisely) replaces the Project Adjusted EBITDA that Cadillac would generate if it were in operation. The insurance carries a 45-day deductible, which we estimate represents a reduction to Project Adjusted EBITDA of approximately $1.5 million to $2.0 million. The impact on operating cash flow is the same. As the incident that took the plant out of service occurred on Sept. 22, most of this impact will be in the fourth quarter. During this extended outage, we expect Cadillac will continue to meet its debt service obligations using the business
10
interruption insurance. Cash that ordinarily would be distributed from the project will instead remain at the project until it returns to service, although this has no impact on operating cash flow as the results of the project are consolidated.
Page 12: Q3 2019 Financial Highlights
Financial results. In a continuation of the first half performance, both Project Adjusted EBITDA and cash provided by operating activities for the third quarter of 2019 exceeded our expectations, primarily due to the acquisitions and also to the avoidance of shutdown-related expenses at Williams Lake that we had previously budgeted. Water flows at Curtis Palmer were 9% below the historical average this quarter, so results for Curtis Palmer were slightly below our expectations, though still well above the dry level of 2018.
2019 guidance. Last quarter I indicated that we were trending toward the upper end of our guidance range. With three quarters of the year ahead of plan, we have increased our 2019 guidance for Project Adjusted EBITDA and narrowed the range, to $185 million - $195 million from $175 million - $190 million previously.
In addition to posting strong financial results this quarter, we also made progress on our balance sheet and our growth initiatives:
Balance sheet and maturity profile. We repaid $18.3 million of term loan and project debt during the third quarter. Our consolidated leverage ratio at September 30th was 3.7 times, which improved from last quarter as a result of debt repayment and increased EBITDA. We expect to repay approximately $15.8 million of consolidated debt during the fourth quarter, for a total of $86.6 million this year, and anticipate leverage at year end 2019 that is substantially in line with the September 30th ratio.
Capital allocation. During the third quarter of 2019, we used $28.5 million of our discretionary cash to close the acquisition of the Allendale and Dorchester biomass plants in South Carolina and minority interests in the Craven and Grayling biomass plants. Including the deposit on the South Carolina plants made in 2018 and transaction costs, the total investment in these four plants was $31.3 million. We also repurchased a modest amount of Series 2 preferred shares and a small amount of common shares at levels that we considered attractive.
I’ll review each of these highlights in more detail on the following pages.
11
Page 13: Q3 2019 Project Adjusted EBITDA bridge
Project Adjusted EBITDA for the third quarter of 2019 increased $3.5 million to $48.9 million from $45.4 million in the third quarter of 2018. Results exceeded our expectation for two primary reasons:
· We had a $1.7 million contribution by the four biomass plants we acquired in July and August (which were not included in our 2019 forecast); and
· We signed a new long-term contract for Williams Lake, which avoided $3.1 million of shutdown-related expenses that we had budgeted for the third quarter. Although Williams Lake EBITDA declined in the quarter (by $1.7 million), mostly because of voluntary curtailment due to low fuel inventory, the decline was smaller than expected.
Curtis Palmer EBITDA increased $1.5 million versus the third quarter of 2018, due to higher generation resulting from higher water flows (though generation was below the historical average for the quarter). Cadillac, Tunis and Frederickson also posted modest increases compared to the third quarter of 2018, mostly due to maintenance outages in the 2018 period; Frederickson also benefited from increased dispatch and Tunis from the new PPA that commenced in October 2018.
These positive comparisons were partially offset by Williams Lake, as previously noted, Oxnard ($1.6 million), due to gas turbine repairs, and Nipigon ($1.2 million), due to the control system upgrade.
Page 14: YTD 2019 Project Adjusted EBITDA bridge
For the first nine months of 2019, Project Adjusted EBITDA increased $14.7 million to $153.2 million from $138.5 million. Curtis Palmer accounted for $10.1 million of the increase, as higher water flows resulted in strong increases in generation (+25% vs. the historical average and +34% vs. the first nine months of 2018). Manchief and Tunis EBITDA increased $7.5 million and $6.6 million, respectively. Although most of the Manchief increase is attributable to the gas turbine overhaul in 2018, results were also driven by higher dispatch. Orlando and the acquired biomass plants also contributed to the EBITDA increases ($1.8 million and $1.7 million, respectively).
On the negative side, Williams Lake had a $6.6 million decrease in EBITDA due to the lower economics of the short-term contract extension that became effective in April 2019. Oxnard had a $2.9 million decrease in EBITDA due to gas turbine repairs and Chambers EBITDA decreased $2.8 million due to lower energy and steam demand as well as lower prices for excess energy.
12
Page 15: Operating Cash Flow and Uses of Cash
Third Quarter 2019
Cash provided by operating activities was $36.4 million in the third quarter of 2019, an increase of $16.9 million from $19.5 million in the third quarter of 2018. The increase was primarily attributable to the $3.5 million increase in Project Adjusted EBITDA, a $5.9 million increase in project distributions from unconsolidated affiliates, a $1.2 million reduction in cash interest payments and a $7.2 million favorable year-over-year change related to working capital. The increase in distributions from unconsolidated affiliates included a $3.8 million distribution from Orlando in September, which in 2018 was not received until early October.
During the third quarter, we used operating cash flow to repay $17.5 million of our term loan and to amortize $0.8 million of project debt. We also paid $1.8 million of dividends on our preferred shares and made $0.5 million of capital expenditures.
Nine Months Ended September 2019
Cash provided by operating activities for the first nine months of 2019 was $104.5 million, an increase of $6.7 million from $97.8 million in the comparable 2018 period. The increase was primarily due to the $14.7 million increase in Project Adjusted EBITDA as compared to the 2018 period, a $4.0 million increase in distributions from unconsolidated affiliates and a $3.3 million reduction in cash interest payments due to lower debt balances and a lower spread on our credit facilities. These positive variances were partially offset by a $17.3 million adverse change in cash flows attributable to changes in working capital, as the 2018 period included a $29.2 million release of working capital by Kapuskasing, North Bay and the three San Diego projects when they ceased operation.
In the first nine months of 2019, we used operating cash flow to repay $50.0 million of our term loan and to amortize $2.3 million of project debt. We also paid $5.5 million of preferred dividends and made $0.8 million of capital expenditures.
Page 16: Liquidity
During the quarter we generated discretionary cash flow (after debt repayment, preferred dividends and capital expenditures) of $15.8 million. We used this cash flow and a portion of cash on hand to fund the biomass acquisitions ($18.5 million for the Craven and Grayling interests and $10.0 million for Allendale and Dorchester) and modest repurchases of common and preferred shares. After this use of cash, we had
13
$31.2 million of unrestricted cash at the parent at September 30, 2019. After holding aside $7 million of this cash for working capital purposes, we had approximately $24 million of discretionary cash available for general corporate purposes.
Total liquidity at September 30, 2019 was $181.2 million, which included $58.1 million of unrestricted cash ($31.2 million at the parent and $26.9 million at the projects) and $123.1 million of availability under our revolver.
Page 17: Debt Repayment Profile and Projected Debt Balances
The charts on page 17 of the presentation show our expected debt repayment in 2019 through 2023 and the significant reduction in our debt levels during that period. Note that these charts include our $43 million share of project debt at Chambers, which is accounted for using the equity method. Repayment of that debt occurs at the project level before we receive cash distributions.
During the first nine months of this year, we repaid $50.0 million of term loan and $2.3 million of project debt and ended the third quarter with a consolidated leverage ratio of 3.7 times, which was slightly improved from the second quarter. In the fourth quarter, we expect to repay another $15.8 million of consolidated debt using our operating cash flow and $5.2 million of Chambers debt from project-level cash flow. We expect our year end 2019 ratio to be substantially in line with the September 30th level. However, we expect continuing repayment of debt and relatively stable levels of EBITDA to result in the leverage ratio continuing to move lower in 2020 and beyond.
Debt repayment during this period consists of term loan and project debt, which is typically amortized from operating cash flow. There are two bullet maturities during this period — our corporate revolver has an April 2022 maturity, but has no borrowings outstanding; and our term loan has an April 2023 maturity, with an expected remaining principal at that time of $111 million. Options that we will consider with respect to the $111 million include repayment at maturity using cash, an extension of the maturity date or a refinancing prior to maturity. Given the debt levels we foresee at that time, we believe that a refinancing is a feasible option. For purposes of the charts on this page, we have assumed a refinancing of the $111 million prior to maturity.
The bottom chart on page 17 of the presentation shows the impact of continued debt repayment on our debt balances, projected through year end 2023. Our debt level at September 30th, including our share of Chambers debt, was approximately $707 million. Assuming refinancing of the $111 million remaining
14
principal prior to its April 2023 maturity, our projected debt level at year end 2023 would be reduced by approximately half to $362 million. Most of this reduction would occur by year end 2022.
We expect this substantial debt repayment over the next several years to generate significant interest cost savings that would mitigate a portion of the impact of lower Project Adjusted EBITDA (from PPA expirations, or extensions on less favorable terms) on our operating cash flow.
Interest Costs
We continue to manage our exposure to increases in market interest rates. At September 30, 2019, approximately 94% of our debt carried either a fixed rate or a variable rate that has been fixed through interest rate swaps. Through December 2019, approximately 94.5% of our debt is either fixed rate or swapped, and through December 2021, approximately 97% on average. Our exposure to a 100 basis point change in LIBOR is $353 thousand over the next 12 months.
Page 18: 2019 Project Adjusted EBITDA Guidance
We have 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.
We have increased our 2019 Project Adjusted EBITDA guidance and narrowed the range, to $185 million to $195 million, from $175 million to $190 million previously. As indicated on page 18 of the presentation, the primary drivers of the increased guidance are:
· Curtis Palmer, which has benefited from higher water flows and generation levels relative to historical averages;
· The biomass plant acquisitions (for a partial year);
· Williams Lake (avoided expenses due to new contract); and
· Higher dispatch at Manchief.
These positive variances were partially offset by lower than expected results at Oxnard (gas turbine repairs), Cadillac (impact of business interruption insurance deductible related to the extended outage, approximately $1.5 million to $2.0 million), and more modest shortfalls at a couple of other projects.
15
Although we are not providing quarterly guidance, we would note that our revised full year guidance implies a decline in Project Adjusted EBITDA for the fourth quarter of 2019 from the $46.3 million recorded in the comparable 2018 period. The significant drivers of this expected decrease are Curtis Palmer, which had a strong fourth quarter in 2018 (generation 12% above the historical average), Williams Lake (no generation expected in the fourth quarter of 2019) and Cadillac (impact of business interruption insurance deductible). We expect these decreases to be partially offset by increases from the biomass acquisitions, Nipigon and Oxnard.
Page 19: 2019 Cash provided by operating activities and planned capital allocation
Our estimate of 2019 cash provided by operating activities is now a range of $115 million to $125 million, as shown on page 19 of the presentation. This is up from $100 million to $115 million previously. The increase to our estimate is attributable to our higher Project Adjusted EBITDA guidance and the delay in a majority of the San Diego decommissioning outlays to 2020.
As is our practice, for purposes of this estimate we have assumed that the impact of changes in working capital on cash flow is nil. Year to date, changes in working capital have had a $5 million benefit to operating cash flow.
Our principal planned uses of operating cash flow in 2019 include $65 million amortization of our term loan, $3.1 million of project debt amortization, approximately $8 million of dividends on our preferred shares, and $1.1 million of capital expenditures. This year, our expected term loan and project debt repayments are approximately $32 million lower than in 2018 while EBITDA is expected to be generally in line with or slightly higher than the 2018 level. Thus, we have had a higher level of discretionary cash flow this year.
Capital Allocation
As shown on page 19 of the presentation, through September, we have allocated $8.8 million to the repurchase of preferred and common shares under the NCIB and $18.5 million (US$ equivalent) to the redemption of the Series D convertible debentures ($18.9 million including accrued interest). As previously noted, we also used $28.5 million to fund the closing of the acquisitions of the Allendale and Dorchester biomass plants and equity interests in the Craven and Grayling biomass plants.
16
NCIB Update
The NCIB repurchases during the third quarter were modest. In July, we repurchased and canceled 12,000 shares of the Cumulative Rate Reset Preferred, Series 2, at Cdn$18.30 per share, for a total cost of Cdn$220 thousand (US$168 thousand equivalent). Earlier this year, we reached the 10% limit on repurchases of Series 1 and Series 3 preferred shares under our NCIB. To date, we have repurchased approximately 43% of the 10% limit on the Series 2. During the quarter, we also repurchased and canceled 2,067 common shares at an average price of $2.27 per share. In addition, in October (fourth quarter), we repurchased another 50,829 common shares at an average price of $2.27 per share.
17
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, impairment charges, insurance loss (gain), other (income) expenses 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 and to Net income (loss) on a consolidated basis is provided in Table 1 below.
Atlantic Power Corporation
Table 1 - Reconciliation of Net Income (Loss) to Project Adjusted EBITDA
(in millions of U.S. dollars)
Unaudited
| | Three months ended | | Nine months ended | |
| | September 30, | | September 30, | |
| | 2019 | | 2018 | | 2019 | | 2018 | |
Net income (loss) attributable to Atlantic Power Corporation | | $ | 12.6 | | $ | (3.2 | ) | $ | 22.7 | | $ | 12.1 | |
Net income (loss) attributable to preferred share dividends of a subsidiary company | | 1.7 | | (1.5 | ) | (3.1 | ) | (1.6 | ) |
Net income (loss) | | $ | 14.3 | | $ | (4.7 | ) | $ | 19.6 | | $ | 10.5 | |
Income tax expense | | 0.2 | | 3.6 | | 2.4 | | 7.7 | |
Income (loss) from operations before income taxes | | 14.5 | | (1.1 | ) | 22.0 | | 18.2 | |
Administration | | 5.5 | | 5.7 | | 17.3 | | 17.9 | |
Interest expense, net | | 10.9 | | 14.6 | | 33.0 | | 40.7 | |
Foreign exchange (gain) loss | | (2.8 | ) | 4.5 | | 7.1 | | (9.1 | ) |
Other (income) expense, net | | (0.2 | ) | 2.5 | | 0.7 | | 0.3 | |
Project income | | $ | 27.9 | | $ | 26.2 | | $ | 80.1 | | $ | 68.0 | |
| | | | | | | | | |
Reconciliation to Project Adjusted EBITDA | | | | | | | | | |
Depreciation and amortization | | $ | 20.2 | | $ | 25.0 | | $ | 60.6 | | $ | 78.0 | |
Interest expense, net | | 0.8 | | (0.6 | ) | 2.0 | | 2.7 | |
Change in the fair value of derivative instruments | | (1.0 | ) | — | | 8.3 | | (3.5 | ) |
Insurance loss | | 1.0 | | — | | 1.0 | | — | |
Other (income) expense, net | | — | | (5.2 | ) | 1.2 | | (6.7 | ) |
Project Adjusted EBITDA | | $ | 48.9 | | $ | 45.4 | | $ | 153.2 | | $ | 138.5 | |
18
