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.
As summarized on page 4 of the presentation, the highlights of the second quarter were as follows:
1. As addressed by Terry in his remarks, we had strong financial results that exceeded our expectations;
2. We continued to deleverage and strengthen our balance sheet with nearly $37 million of debt reduction, and improved our leverage ratio to 3.8 times;
3. We continued to allocate capital to repurchasing common and preferred shares at levels we consider attractive, although repurchases were modest this quarter;
4. We made significant progress on our growth initiatives, announcing an agreement to acquire minority interests in two contracted biomass plants for $20 million and completing the acquisition of two others for $13 million; and
5. We executed an agreement for the sale of our Manchief plant for $45 million following expiration of its PPA in May 2022, which preserves our cash flow from the project for the next three years, further reduces debt and eliminates re-contracting uncertainty.
Market fundamentals in the power sector remain weak. Demand growth is low, capacity additions continue to outpace retirements and public policy and tax subsidies continue to support additions of intermittent sources, primarily wind and solar. These additions drive up grid costs, impacting demand and devaluing more reliable power sources. All of this has made for a challenging environment in which to re-contract our gas plants. That said, we are seeing initial concerns in a few markets that are becoming heavily reliant on intermittent power, that there may be insufficient dependable resources available at peak times. Meanwhile, if the phase-out of tax subsidies for wind and solar projects occurs as scheduled, that should be beneficial to our re-contracting efforts over time.
The market-clearing returns on highly popular wind and solar investments are generally unattractive for us, and are mostly tax-driven while we currently have a low tax appetite. Our investment search process is focused on out-of-favor and unglamorous assets, what we think of as “cigar butts.” As we disclosed in June, the acquisitions we have announced — of four operating biomass plants and an additional ownership interest in Koma Kulshan — are expected to contribute $8 million to $10 million of Project Adjusted EBITDA annually on average through 2027 and at a lower level thereafter. This represents an attractive potential return on a total investment of approximately $46 million.
Measured against expected 2019 Project Adjusted EBITDA of $175 million to $190 million, the addition of $8 million to $10 million is modest. However, as existing PPAs expire, particularly in 2022 and beyond, the addition is more meaningful. We have increased and extended our expected PPA-generated revenues and cash flow as a result of these acquisitions.
Following the completion of the acquisition of Allendale and Dorchester earlier this week, we have estimated liquidity of approximately $190 million. Meanwhile, our market capitalization is approximately US$260 million based on recent share prices. Our deleveraging continues to be supported by cash flow
from existing assets that remain under PPAs. Our liquidity can be used to further reduce debt, repurchase shares or make acquisitions. Our capital allocation decisions are driven by our assessment of the most rational use of capital measured on an intrinsic value per share basis.
We are encouraged by the deal flow we are reviewing but we will be disciplined about comparing the returns on external investments to those available from investing in our own securities.
We had three recordable injuries in the second quarter, and five in the first six months of the year. As a result, our total recordable incident rate (TRIR) of 2.14 for the first six months of 2019 was higher than the prior periods shown in the chart on page 5. As noted last quarter, although only two of these were lost time events, we take all injuries very seriously and are committed to safety as job one. Since March, we have undertaken a number of additional steps, including holding a companywide Safety Stand Down to review the importance of taking a proactive approach to safety and to reiterate our commitment to ongoing safety education and training. We also formed a Corporate Safety Committee, which includes each of our plant managers and is headed by our corporate VP of Safety. The Committee meets every month and reports quarterly to the executive leadership. We have increased the frequency of safety meetings and expanded safety-related communications throughout the company. We have always made safety our number one priority and will continue to do so.
Turning to our operating results, generation increased 8.1% in the second quarter of 2019, primarily because of higher dispatch at Frederickson and well above-average water flows at Curtis Palmer. Generation at Curtis Palmer increased 50% from the year-ago period and 40% relative to the long-term average. These increases were partially offset by a 15% reduction in generation from Mamquam as compared to the year-ago period, due to lower water flows. Hydrology is volatile, though, and I would note that in July, generation at Curtis Palmer was approximately 17% below our budget for the month.
Our availability factor in the second quarter of 2019 increased slightly to 94.6% from 93.4% in the second quarter of 2018. Manchief and Kenilworth improved from the 2018 period, when they underwent turbine
overhauls. Chambers improved due to a maintenance outage in the 2018 period. These increases to availability were partially offset by decreases at Moresby Lake due to a transformer failure (which we will be replacing this fall) and Oxnard because of unplanned gas turbine repairs (in a continuation from the first quarter). Although not a factor in the year-over-year comparison, Nipigon and Tunis had availability factors in the high 90% range under the terms of their contracts, which slightly increased the weighted average availability of the fleet for the year.
Decommissioning of San Diego Sites
We are continuing to work with San Diego Gas & Electric on a critical path issue affecting the schedule and cost of decommissioning. Once that is resolved, we expect to solicit final bids from contractors for the demolition work. In the meantime, we have moved ahead with some of the work to prepare the sites. Based on our latest assessment, we now expect decommissioning to be completed in the first half of 2020. During the second quarter, we recorded a $1.4 million increase to the asset retirement obligation and now expect the cash outlay to total approximately $6.6 million. To date, we have realized $1.7 million of salvage proceeds, most of which was received in January 2019. The net outlay is thus expected to be approximately $5 million. Outlays to date total approximately $632 thousand, including approximately $112 thousand in the first six months of 2019 and the remainder in 2018.
As we’ve discussed on previous quarterly calls, we returned Nipigon to service in November 2018 under a long-term enhanced dispatch contract with the Ontario Independent Electricity System Operator (IESO). We plan to upgrade the plant’s gas turbine control system, which will improve reliability, as well as its protection system, this quarter. Preapprovals have been received and the anticipated expense is modest and already reflected in our outlook.
Next I’ll provide an update on our program to improve our operation and maintenance performance. We have been using a standard maintenance management software (Mainsaver) at most of our plants and will be rolling it out to the remainder, including the two recently acquired biomass plants in South Carolina. We have an ongoing focus on optimizing the preventive maintenance programs for all sites and are in the process of reviewing the long-term maintenance plans for each site. On balance, we have identified a modest reduction in planned expenses to date.
One of our areas 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 the two acquired biomass plants in South Carolina.
Late this year we expect to begin a benchmarking of our hydro projects and the biomass projects we’ll be acquiring, with a goal of driving further improvements to our cost structure as we add and integrate new projects into our fleet.
My remarks this quarter will focus on our biomass acquisitions and our agreement to sell our Manchief plant. I’ll also provide an update on Williams Lake and our other PPA re-contracting efforts.
South Carolina Biomass Acquisition
As reported in our earnings release, on July 31, 2019, we closed the acquisition of two 20 megawatt (MW) biomass plants in South Carolina from EDF Renewables for $13 million. We will be operating both plants, increasing the number of biomass plants that we own and operate to six. We are now focused on ensuring a smooth integration of the plants into our fleet. We intend to implement initiatives similar to those we have undertaken at our other biomass projects over the past few years with a goal of reducing the cost of production and increasing plant efficiency. One area that we have identified is the fuel handling process at both plants, which should provide us access to additional supplies of lower-cost fuel. We also plan to look at some other aspects of operations. These could require modest amounts of investment by us. In a base case scenario, before any optimization initiatives, we expect the two plants to produce combined Project Adjusted EBITDA of approximately $3 million.
Agreement to Acquire AltaGas Ownership Interests in Two Contracted Biomass Plants
In May 2019, we announced an agreement to acquire, for $20 million, the equity interests held by AltaGas Holdings (U.S.) in two biomass plants located in North Carolina and Michigan. Both plants have PPAs that run through 2027. These plants are well managed and will continue to be operated by CMS Energy, a 50% owner in both plants. Closing is subject to FERC approval and other customary approvals and conditions. We expect closing to occur in the third quarter of this year. When completed, the acquisition of AltaGas interests in these two plants (approximately 35 MW net ownership interest) will
increase the size of our biomass fleet to eight plants. Projected economics are consistent with our previously disclosed return targets.
Agreement for the Sale of Manchief Plant
Also in May, we executed an agreement to sell the Manchief power plant to Public Service of Colorado, the existing customer under the PPA, for $45.2 million, subject to working capital and other customary adjustments, and receipt of regulatory approvals. We expect closing to occur following the expiration of the PPA in May 2022. We are pleased with this outcome, which meets our following objectives for Manchief: (i) maintaining project cash flows for the reminder of the existing PPA term, and (ii) locking in value following expiration of the project’s PPA, thereby mitigating re-contracting risk in a market with limited power off-take options.
Williams Lake (British Columbia)
On our previous call in early May, we reported several positive developments involving our Williams Lake project, including that:
1. We had commenced discussions with BC Hydro on a new PPA;
2. A directive had been issued by the provincial government to the BC Utilities Commission (BCUC) to approve the recovery of rates of costs incurred by BC Hydro as a result of implementing a new PPA extension for Williams Lake, should that occur;
3. Our existing short-term PPA with BC Hydro was extended through September 30, 2019 (and subsequently approved by the BCUC on May 15), and
4. We had received a favorable ruling from the Environmental Appeal Board on the amended air permit for Williams Lake, which provides for the burning of rail ties up to an annual limit of 35% of the project’s fuel requirements.
Discussions with BC Hydro on a new long-term PPA for Williams Lake are continuing. The current focus of these discussions and our due diligence work is on the availability of an economic supply of fuel in the currently depressed BC timber market. We consider the availability and cost of fuel as the most significant risk to extending operations at Williams Lake. The objective of our discussions and due diligence is to reduce this risk to a level that allows for the execution of a new PPA and continued operations of the plant. We expect to be in a position to provide greater clarity on our third quarter conference call.
In addition to Williams Lake, we have three other projects with near-term PPA expirations (through 2021):
The Oxnard PPA expires in May 2020. To date, public policy and market conditions have not supported an extension of the PPA. However, in June, the California Public Utilities Commission (CPUC) issued an order seeking comments on near-term reliability challenges and options for potential solutions. One of the proposals would require Southern California Edison (SCE, the power customer under the Oxnard PPA) to solicit 500 MW of capacity from existing resources that are uncontracted after 2021. We plan to respond as appropriate to any solicitations issued by SCE. We also continue to pursue other potential paths to a new contract. While we view this action by the CPUC favorably, it is too early to know whether these developments will materially improve our re-contracting probability, which is currently low.
The Calstock PPA expires in June 2020. We continue to pursue re-contracting options for Calstock but have nothing positive to report at this time. 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. We continue to pursue potential solutions but view our probability of success as low.
Kenilworth (New Jersey)
In late July, Merck, our customer at the Kenilworth plant, exercised the third of three one-year contract extension options, thus extending the contract expiration date to September 2021. We also remain engaged with Merck on a potential further contract extension beyond 2021.
We have another group of projects with PPAs expiring in 2022. This is three years away and so it’s still quite early to be engaging in re-contracting discussions. That said, we’d make the following points regarding each of those projects:
Moresby Lake (British Columbia). As a small hydro facility on a diesel-dependent island, Moresby Lake is an important source of clean energy for the area. We believe prospects for a new contract with BC Hydro are good, and have been working closely with First Nations.
Frederickson (Washington State). Plans now call for all coal plants in the state to be retired by 2025. As a load-following gas plant in a hydro-sensitive market, we expect that Frederickson should have value post-PPA.
Nipigon (Ontario). The outlook for Nipigon after 2022 will be a function of the supply/demand outlook for Ontario (non-competitive, single-buyer market). The market is difficult to forecast. A recent decision by the government to suspend work on a capacity market for the province, which had been contemplated by the previous government, should be positive for incumbent generators.
Lastly, in early March I discussed recent policy developments in New York that could be positive for the longer-term outlook for Curtis Palmer, where we currently have considerable PPA term remaining. Previously (in 2016), the state had announced a goal of 50% of electricity generation from renewable resources by 2030. In July, Governor Cuomo signed an aggressive climate bill, requiring that 70% of the state’s electricity come from renewable sources by 2030 and that 100% be “carbon-free” by 2040. In this environment we believe that a hydro facility with a long remaining economic life will have significant value. Although there is much interest in expanding offshore wind to meet the state’s requirements, we are already seeing opposition develop in some areas.
Separately, as noted in early March, the New York Independent System Operator (NYISO) has issued a carbon pricing proposal and is continuing to work through details of the proposal with various stakeholders. It is a complex issue and proposal and will take time, but we believe that an explicit price on carbon, if enacted, would have a positive impact on the value of Curtis Palmer. We will continue to monitor developments closely.
Financial results. Project Adjusted EBITDA and cash provided by operating activities for the second quarter of 2019 exceeded our expectations, in a continuation of the first quarter performance. Results this year have benefited from water flows at Curtis Palmer that are well above the historical average. Although we are maintaining our guidance for the full year, the six-month results have us trending toward the upper end of the range. Hydrology is very variable, however, and we could give part of this back if it becomes dry. We will revisit guidance on our third quarter call, when we should have a clearer picture on both Curtis Palmer and Williams Lake.
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 second quarter and redeemed Cdn$24.7 million ($18.5 million US$ equivalent) of the remaining Series D convertible debentures. Our consolidated leverage ratio at June 30 was 3.8 times, which improved from last quarter as a result of debt repayment and increased EBITDA.
Capital allocation. During the second quarter of 2019, we repurchased a modest amount of common and Series 2 preferred shares at levels that we considered attractive. Also during the quarter, we committed $20 million to the acquisition of minority interests in two contracted biomass plants from AltaGas; we expect closing during the third quarter and we plan to use discretionary cash. Earlier this week, we used $10.4 million of our discretionary cash to fund the acquisition from EDF Renewables of two contracted biomass plants in South Carolina; the total cost of the acquisition, including a $2.6 million deposit made last September, was $13 million.
I’ll review each of these highlights in more detail on the following pages.
Page 8: Q2 2019 Project Adjusted EBITDA bridge
Project Adjusted EBITDA for the second quarter of 2019 increased $11.0 million to $50.8 million from $39.8 million in the second quarter of 2018. This result was better than our expectation primarily because Curtis Palmer benefited from water flows that were well above average, driving increased generation (+40% vs. the long-term average and +50% vs. the second quarter of 2018). As a result, Curtis Palmer EBITDA increased $5.9 million from the year-ago period.
The other significant drivers of the EBITDA result were generally in line with our expectations. On the positive side, Manchief increased $7.4 million due to a major gas turbine overhaul in the prior period and increased dispatch during the 2019 period, and Tunis increased $2.2 million as a result of starting up in October 2018 under a new 15-year PPA, in contrast to the second quarter of 2018 in which we incurred significant maintenance expense to prepare for start-up.
On the negative side, Chambers EBITDA declined $1.7 million due to lower energy and steam demand and lower prices for excess energy. Cadillac and Oxnard also experienced modest decreases.
Page 9: YTD 2019 Project Adjusted EBITDA bridge
For the first six months of 2019, Project Adjusted EBITDA increased $11.3 million to $104.5 million from $93.2 million. Curtis Palmer accounted for $8.6 million of the increase, as higher water flows resulted in strong increases in generation (+36% vs. the long-term average and +34% vs. the first six months of 2018). Manchief and Tunis EBITDA increased $7.9 million and $5.7 million, respectively, in line with expectations.
On the negative side, Williams Lake had a $4.9 million decrease in EBITDA due to the lower economics of the short-term contract extension that became effective in April 2019. Chambers EBITDA decreased $2.3 million due to lower energy and steam demand and lower prices for excess energy, and Cadillac and Oxnard experienced modest decreases in EBITDA.
Page 10: Operating Cash Flow and Uses of Cash
Second Quarter 2019
Cash provided by operating activities was $38.9 million in the second quarter of 2019, an increase of $10.8 million from $28.1 million in the second quarter of 2018. The increase was primarily attributable to the $11.0 million increase in Project Adjusted EBITDA, partially offset by a $1.8 million unfavorable year-over-year change in working capital and a $1.1 million reduction in distributions from unconsolidated affiliates (predominantly at Chambers, due to lower EBITDA).
During the second 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.
Six Months Ended June 2019
Cash provided by operating activities for the first six months of 2019 was $68.1 million, a decrease of $10.3 million from $78.4 million in the comparable 2018 period. Most of the decrease was the result of a $24.5 million adverse change in cash flows attributable to changes in working capital, as the 2018 period included a $17.7 million release of working capital by Kapuskasing, North Bay and the three San Diego projects when they ceased operation. This negative impact on cash flow was partially offset by the $11.3 million increase in Project Adjusted EBITDA in 2019 as compared to the 2018 period.
In the first six months of 2019, we used operating cash flow to repay $32.5 million of our term loan and to amortize $1.5 million of project debt. We also paid $3.7 million of preferred dividends.
Page 11: Liquidity
During the quarter we generated discretionary cash flow (after debt repayment, preferred dividends and capital expenditures) of $18.7 million. In April, we used $18.9 million (US$ equivalent) to redeem the remaining Series D convertible debentures at par plus accrued interest, and another $0.9 million for repurchases under our normal course issuer bid, or NCIB. Combined with a couple of other modest uses, this resulted in an approximate $3.4 million reduction in unrestricted cash during the quarter. At June 30, 2019, we had liquidity of $194.4 million, including $71.4 million of unrestricted cash and $123.0 million of availability under our revolver. After holding aside $7 million of cash for working capital purposes, we had about $39 million of discretionary cash at the parent at June 30.
Page 12: Debt Repayment Profile and Projected Debt Balances
The charts on page 12 show our expected debt repayment in 2019 through 2023 and the significant reduction in our debt levels during that period. These charts are a simpler version of the ones we have been presenting in the past; those are now included in the Appendix of the presentation. 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 six months of this year, we repaid $32.5 million of term loan and $1.5 million of project debt and ended June with a consolidated leverage ratio of 3.8 times, which was improved from 4.5 times at the end of March. In the second half of 2019, we expect to repay another $34.1 million of consolidated debt using our operating cash flow and $5.2 million of Chambers debt from project-level cash flow. We expect a slight increase in our leverage ratio to about 4 times at year end 2019. However, we expect continuing repayment of debt and relatively stable levels of EBITDA to result in the leverage ratio moving below 4 times in 2020 and continuing to decline thereafter.
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 $125 million. Options available to us with respect to the $125 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 $125 million prior to maturity.
The bottom chart on page 12 shows the impact of continued debt repayment on our debt balances, projected through year end 2023. Our debt level at June 30, including our share of Chambers debt, was approximately $728 million. Assuming refinancing of the $125 million remaining principal prior to its April 2023 maturity, our projected debt level at year end 2023 would be reduced by approximately half to $379 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.
We continue to manage our exposure to increases in market interest rates. At June 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 92% 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 $373 thousand over the next 12 months.
Page 13: 2019 Guidance
Project Adjusted EBITDA
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 are reaffirming our 2019 Project Adjusted EBITDA guidance of $175 million to $190 million. Results to date have been better than our expectation at the beginning of this year, primarily due to higher water flows and generation levels at Curtis Palmer. Based on these results, we are trending toward the upper end of this range. However, hydrology is variable, and if we were to have a dry spell at Curtis Palmer, we would effectively give back part of the strong results to date. As Dan noted, water flows at Curtis Palmer were approximately 17% below budget in July. This reduced EBITDA relative to budget by approximately $0.6 million.
Our guidance also assumes a shutdown of Williams Lake at the end of September, when the existing short-term contract extension is scheduled to expire. Consistent with that assumption we have reflected some shutdown expenses in our guidance (though not decommissioning costs, as we are not required to decommission the project on any set timeframe). As noted, however, we are in discussions with BC Hydro regarding a potential longer-term PPA for Williams Lake. If we enter into a new contract, we would not shut the plant nor would we incur the associated expenses.
We expect to know more regarding Williams Lake re-contracting and the hydrology impact on Curtis Palmer by next quarter, and would expect to revisit guidance at that time, if appropriate.
With that in mind, we have not changed our initial Project Adjusted EBITDA guidance bridge shown on page 13. Year to date results for Williams Lake, Tunis and the San Diego projects are in line with the expectations shown on that bridge, while Curtis Palmer is higher (guidance is based on a normal water year) and Manchief is slightly higher (increased dispatch). We also now expect an initial contribution from acquisitions — the two biomass plants that we closed on earlier this week and the two that we expect to close on in the third quarter. Partially offsetting those positives are results for Oxnard, Kenilworth and Moresby Lake, which are lower than our initial expectations, primarily because of maintenance expense.
Although we are not providing quarterly guidance, we would note that we expect second half 2019 results to be lower than the $92 million recorded in the comparable 2018 period. One of the more significant drivers of the expected decline is the assumed shutdown of Williams Lake.
Page 14: 2019 Cash provided by operating activities and planned capital allocation
We continue to estimate 2019 cash provided by operating activities in the range of $100 million to $115 million, as shown on page 14. As is our practice, we have assumed that the impact of changes in working capital on cash flow is nil. Year to date, changes in working capital have not had a significant impact on operating cash flow.
Operating cash flow for the first six months has exceeded our expectations primarily due to stronger results from Curtis Palmer, the timing of maintenance and capex projects at several other projects and the delay in decommissioning outlays for the San Diego projects. We expect that some of this could reverse over the course of the year.
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 the 2018 level. Thus, we have had a higher level of discretionary cash flow this year.
As shown on page 14, through July, we have allocated $8.7 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). Earlier this week we funded the remaining $10.4 million to close the acquisition of the Allendale and Dorchester biomass plants in South Carolina. Because of our strong cash flow, we have been able to make these investments without a significant reduction to our liquidity, which has been relatively stable and which we estimate was approximately $190 million on July 31 after funding the acquisition.
We also have committed $20 million for the purchase of minority interests in another two contracted biomass plants from AltaGas. We expect that acquisition to close in the third quarter of this year.
The NCIB repurchases during the second quarter were modest. We repurchased and canceled 313,307 common shares at an average price of $2.27 per share, for a total investment of approximately $712 thousand. We also repurchased and canceled 9,800 shares of the Cumulative Rate Reset Preferred, Series 2 at Cdn$18.40 per share, for a total cost of Cdn$180 thousand (US$138 thousand equivalent). In July, we repurchased and canceled another 12,000 shares of the Series 2 preferred. 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.
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, 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 and to Net income (loss) on a consolidated basis is provided in Table 1 below.