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Good day, and thank you for standing by. Welcome to the Algonquin Power & Utilities Corporation 2021 Third Quarter Earnings Webcast and Conference Call. [Operator Instructions] Please be advise that today's call is being recorded. [Operator Instructions] I would like to hand the conference over to your speaker today, Mr. Amelia Tsang, Vice President, Investor Relations. Please go ahead.
Thank you. Good morning, everyone. Thanks for joining us this morning for our third quarter earnings conference call. Presenting on the call today are Arun Banskota, our President and Chief Executive Officer; and Arthur Kacprzak, our Chief Financial Officer. Also joining us this morning for the Q&A part of the call will be Jeff Norman, our Chief Development Officer; and Johnny Johnston, our Chief Operating Officer. To accompany our earnings call today, we have a supplemental webcast presentation available on our website, algonquinpowerandutilities.com. Our financial statements and management discussion and analysis are also available on the website as well as on SEDAR and EDGAR. Before continuing the call, we would like to remind you that our discussion during the call will include certain forward-looking information, including, but not limited to, our expectations regarding future earnings, capital expenditures and pending acquisitions. At the end of the call, I will read a notice regarding both forward-looking information and non-GAAP financial measures. Please refer to our most recent MD&A filed on SEDAR and EDGAR and available on our website for additional important information on these items. On our call this morning, Arun will provide an overview of our Q3 performance, Arthur will follow with the financial results, and then Arun will conclude with an update on our strategic plan for the business. We will then open the lines for questions. [Operator Instructions] And with that, I'll turn it over to Arun.
Thank you, Amelia, and a very good morning to those who've been able to join us on the call and online. I'm pleased to report solid key financial metrics for the third quarter of the year. Q3 adjusted EBITDA was $252 million, a 27% increase year-over-year. And our Q3 adjusted net earnings per share was $0.15, in line with last year. On our regulated side of the business, operating profit was positively impacted by the addition of our new Empire wind facilities as well as the first full year of operations from our Bermuda Electric utility and ESSAL water utility in Chile, which both closed late last year, and have both performed in line with our expectations. On the renewable side of the business, operating profit from our new facilities, such as Sugar Creek, and Maverick Creek contributed to increased earnings on a year-over-year basis. Excluding new facilities, production was 7.3% below the same period last year due to lower wind resource, but this was partially offset from other income, including increased renewable energy credit or REC revenues. I'm pleased to report that the company's operating results were not materially impacted by the pandemic this quarter. Recall that in the third quarter last year, the pandemic did have a $0.01 impact on earnings per share. Generally speaking, we are not seeing negative impacts from COVID on our loads as business conditions in the regions we operate in return to normal. Our team continues to focus our efforts on Algonquin's 3 strategic pillars: growth, operational excellence and sustainability. We operate through 2 primary businesses, regulated and renewables, and we'll spend some time on each for an update. On the regulated side, one important lever of growth is acquisitions. On that topic, I'm pleased to discuss our recently announced agreement to acquire Kentucky Power Company, a vertically integrated regulated-electric utility that services approximately 228,000 customer connections in 20 Eastern Kentucky counties. As part of the transaction, we will also be acquiring AEP Kentucky Transmission Company, Inc., a regulated-electric transmission utility operating in the PJM-integrated market. We look forward to welcoming the Kentucky Power employees into the Liberty family and to working with AEP during the closing and transition process. The total enterprise value of the acquisition is approximately $2.8 billion, comprised of assumed debt of approximately $1.2 billion and a cash purchase price of approximately $1.6 billion. From our perspective, this represents an attractive valuation multiple of 1.3x rate base based on an estimated midyear 2022 rate base of approximately $2.2 billion. This transaction will have the benefit of increasing our pro forma regulatory business mix to nearly 80% of our portfolio from nearly 70% currently and further increasing our service territory and regulatory jurisdiction diversification with a supportive regulatory framework. Upon closing of the transaction, we expect to have approximately $9 billion of rate base, increasing our pro forma electric rate base from 63% to 72% of our total pro forma rate base. We expect to close the transaction in mid-2022 subject to customary closing conditions, including the receipt of various states and federal regulatory and governmental approvals. We expect the transaction to be accretive to adjusted net earnings per share in the first full year of ownership, which would be calendar year 2023 and generate mid-single-digit accretion to our adjusted net EPS thereafter while being supportive of our long-term growth trajectory. Now I thought I'd spend a few minutes on the rationale behind the acquisition and why we feel strongly that it represents a strategic fit for us. This acquisition fits squarely into our 2 playbooks of Greening the Fleet and improving return on equity from non-optimized assets. As I've mentioned in the past, Greening the Fleet is an important lever of growth and an area where we have a strong track record through the transition of our Empire and CalPeco utilities. Just between 2017 and 2020, we successfully reduced absolute carbon emissions at the acquired Empire District Electric utility by 33%. And at the acquired CalPeco Electric Utility by 38% by including renewables in the rate base, use of tax equity and shutting down a 200-megawatt coal plant in the case of Empire District. We plan on leveraging this experience at Kentucky Power. In particular, the Kentucky Power business offers significant opportunities for us to transition the existing fossil fuel generation to renewables, which will reinforce our leading role in the transition to a low-carbon economy. We see a pathway to decarbonize as it is our expectation that the low-cost resource to replace retiring or transferred coal will be a combination of renewables with support from energy [ stores ]. Wind and solar represent the lowest levelized cost of energy today and are expected to provide benefits for our customers. The existing unit power agreement with the Rockport coal-fired plant will expire in 2022, and Kentucky Power's 50% interest in the Mitchell coal-fired plant is expected to be retired or transferred by 2028. To replace the lost electricity supply from Rockport and Mitchell, we see an opportunity to utilize the integrated resource planning process to explore the potential to replace over 1,100 megawatts of fossil generation capacity with renewables. This would represent our largest Greening the Fleet opportunity to date and is aligned with our target to achieve net zero Scope 1 and 2 emissions by 2050. We look forward to partnering with the Kentucky Public Service Commission, or KPSC through the integrated resource planning process and leveraging our greenfield development expertise to deliver low-cost, clean energy solutions to Kentucky Power's customers as part of our demonstrated Greening the Fleet capabilities. Secondly, Algonquin has had a successful track record of identifying, securing regulatory approvals and closing acquisitions. We have extensive experience in managing the integration of multi-modality utilities such as Kentucky Power and Kentucky Transco. As with our previously acquired utilities, we strive to share learnings and best practices among our utilities with the aim of driving consistent improvement in our key performance metrics that provide value for our customers. A number of these acquisitions have been utility acquisitions from large entities. And our stewardship of those utilities as part of our Liberty family has helped us to create value for our shareholders and our customers. Similar with previous utilities, we will utilize our local responsive approach as our local model has been able to reduce disallowances from having transparency of our costs as well as the local model allows us to manage our costs within our regulatory allowances. In addition, we have generally been able to utilize our geographic diversity to deploy capital in a manner that reduces regulatory lag and increases returns as we have done with many of our utilities. Also contributing to our ability to earn returns is a focus on added regulatory mechanisms. Under our ownership, we have been able to secure decoupling mechanisms, capital trackers, property tax adjustments and similar mechanisms, which all help the utilities increase their returns while providing build stability and adding the necessary capital to allow us to better serve our customers. For example, after the acquisition of Granite State Electric in New Hampshire, since our first test year, our returns have averaged nearly 9% ROE, whereas under prior ownership, the returns were frequently under 3%. Similarly and perhaps more pertinently, at Empire District Electric prior to our acquisition, ROEs achieved were commonly in the 7% to 8% range, whereas under our ownership, we have been able to average nearly 9.5%. Kentucky Power is primarily regulated by the KPSC, which we view as a constructive regulatory jurisdiction and is highly rated by S&P from a regulatory perspective. Kentucky Power is a utility that has historically realized ROE below the authorized levels when compared to peers in Kentucky. We see a compelling path forward to improving the earnings profile to achieve an ROE that is closer to the off-price amount of 9.3% for the distribution rate base through the availability of certain key regulatory features. For instance, forward test years are not currently being employed by Kentucky Power despite its approved use by other regulated peers in the state and could provide for more timely recovery of costs and expenditures. We look forward to working with the commission on implementing certain improvements to help us deploy the necessary investments to deliver reliable electric service to Kentucky Power's customers, and we plan to maintain Kentucky Power's headquarters in Ashland, along with developing constructive relationships in the local community. Arthur will discuss the financing plan of the acquisition shortly. Lastly, on the acquisition front, I wanted to provide you with an update on our pending acquisition of New York American Water. We filed our joint proposal, signed off by PSC staff and the majority of intervenors in early November with a hearing scheduled for November 16. While this has been a longer process than originally anticipated, we remain confident that the transaction will close, and we are on track to do that within the timeline set out in the stock purchase agreement, which calls for closing to occur on or prior to January 3, 2022. Moving on now to operational excellence. In a mission-critical industry, safety and reliability are always the most important areas of focus. I'm very pleased to share that we have passed the impressive milestone of over 650 days that is over 9 million work hours without a single lost time injury across our North American business while keeping our customers and communities safe and maintaining our system reliability and resiliency. I want to thank our employees during the wildfire season, which was really operational excellence in action. During the quarter, The Caldor Fire impacted our South Lake Tahoe area at CalPeco, and our local teams worked with incident command and infrastructure protection teams where power lines were shut down for safety. I'm glad to say that operations have returned to normal, and our teams were proactive during the evolving event. Pruning trees on poles, deploying fire retardant on poles and clearing vegetation. Longer term, we intend to continue to make investments for system resiliency, system hardening, and wildfire prevention. On the regulatory front, our Missouri rate case continues to progress, and we expect the outcome in the middle of next year. In our regulated businesses, we are closely tracking rising gas prices as we head into this winter. We have different regulatory approved hedging policies in place. But overall, we expect the energy cost to increase and for this to flow through to customer bills through our various recovery mechanisms. Affordability is always a concern for us, and so we continue to work with our various partners on our energy efficiency programs and low-income programs to help mitigate these costs where we can. And finally, we remain firmly committed to sustainability through the inclusion of environmental, social and governance values in our broader corporate strategy and day-to-day operations. I'm pleased to report that last month, we announced our target for net zero for Scope 1 and Scope 2 emissions by 2050. The achievement of our net zero target is supported by our strong decarbonizes and track record, extensive experience in regulated utility management and deep expertise in renewables development. I spoke earlier of our Greening the Fleet capabilities and wanted to highlight our track record of environmental stewardship. Since acquiring the Empire District Utility company in 2017, Algonquin's total Scope 1 greenhouse gas emissions have been reduced by over 1 million metric tons. And Scope 1 and 2 emissions intensity per dollar of revenue have decreased by 26%. Similarly, at CalPeco, we have already reduced the carbon intensity of CalPeco by 46% since 2017. At $0.0013 per dollar of revenue, Algonquin has among the lowest carbon intensities among its peers in the industry. Concurrent with the release of our net zero target, we also released our 2021 sustainability report, which not only outline our progress on our ESG initiatives, but also provided a higher level of detail around 9 priority ESG targets for 2023, some of which we have already achieved ahead of schedule and others that we are confident in meeting. With that, I'll pass it over to Arthur, who will speak to our third quarter 2021 financial results. Arthur?
Thank you, Arun, and good morning, everyone. I'm pleased to report solid third quarter results, reflecting the benefits of Algonquin's diversified and resilient business model and proven track record of disciplined growth. Our third quarter 2021 consolidated adjusted EBITDA was $252 million, which is up approximately 27% from $197.9 million we reported for the same period last year, but slightly below our expectations. The Regulated Services Group delivered $195.8 million in operating profit in the current quarter, which compares to $146.1 million in the same quarter last year. This improvement primarily reflects contributions from BELCO, our Bermuda Electric Utility and ESSAL, our Chilean water utility as both acquisitions closed in Q4 of last year. as well as contributions from our wind facilities that were placed in service earlier this year as part of the Midwest Greening the Fleet initiative. Results also benefited from new rates implemented at Energy North and Peach State Gas systems as well as the Park Water and Apple Valley systems in California. This was offset by the impact of a onetime retroactive rate increase in Q3 of last year at the CalPeco Electric System. I should also note that the Regulated services Group did not experience any material negative impacts from COVID-19 this quarter. However, the comparative results from Q3 2020 were negatively impacted by the pandemic by approximately $4.2 million. Moving on, the Renewable Energy Group reported a Q3 divisional operating profit of $72.5 million, which compares to $67.1 million in the same quarter last year, an increase of about 8%, but below our expectations for this business unit. The addition of Sugar Creek and Maverick Creek wind generation facilities as well as the Great Bay II and Altavista solar generation facilities all contributed to the quarter-over-quarter increase in operating profit. Our investment in Atlantica also continued to provide benefits with dividends received increasing by $2.8 million over the prior year. However, this increase was partially offset by several factors. We experienced lower overall production at our wind generation facilities, primarily due to resource shortfalls. Excluding the impact of the newly added facilities' production in our existing power generation facilities, was 7.3% lower than the same quarter last year or approximately 15.4% below the long-term average. Production shortfalls along with lower-than-expected realized pricing also negatively impacted the results from our investment in the Texas coastal wind facilities. Lastly, performance at our Sanger facility was negatively impacted this quarter by higher carbon compliance costs and lower capacity payments. Some of these impacts were partially offset by higher realized renewable energy credit pricing on our U.S. wind facilities as well as operating cost savings. I should note that during the quarter, the company self-monetized approximately $8.7 million renewable tax credit benefits, which would have been otherwise included as part of the Renewable Energy Group's operating profit and in adjusted EBITDA but are reflected in our overall adjusted net earnings. In total, our Q3 adjusted net earnings per share came in at $0.15, which is in line with the $0.15 reported last year. I now want to spend a few minutes on the financing plan for Kentucky Power and for the Kentucky Power acquisition, which was designed to maintain our mid-BBB investment-grade credit ratings and maintain a strong and resilient balance sheet. Concurrent with the announcement of the transaction, we announced a CAD 800 million bought deal offering of common shares to fund a portion of the equity purchase price. This offering is expected to satisfy all of our common equity needs through the expected closing of the transaction in mid-2022. To fund the remainder of the cash purchase price, we plan to utilize some or all of the following sources: First, hybrid debt, which has seen some very attractive rates in the market recently and provides for an attractive funding source, receiving 50% equity credit from S&P and Fitch. We continue to maintain a significant room in our capital structure for this low-cost capital; second, potential monetization of nonregulated assets or investments. The current low-cost capital environment continues to precipitate a strong valuation for quality renewable generation assets. Although our core competency continues to be as a developer, operator and owner of regulated and renewable assets, we believe augmenting these competencies with the introduction of low-cost capital through monetization of some of our renewable assets or investments has the potential to drive greater shareholder value. Lastly, mandatory convertible units. As you heard me say before, we believe that mandatory convertible units are a great fit in our capital structure, having the potential to be lower cost capital compared to common equity and more effectively match investments -- the investment cash generation profile with its financing. However, recognizing the ultimate conversion to common equity, if used as a financing source, we intend to be prudent in the magnitude of their use. While we expect to have the majority of our permanent financing in place out or near the transaction close, we also secured an approximately $2.7 billion acquisition financing commitment to support the acquisition. Finally, I wanted to say just a few words on the acquisition itself. We view this acquisition to be of compelling value and expect it to be accretive to adjusted net EPS in the first full year of ownership, which would occur in calendar year 2023 based on our anticipated mid-2022 closing. Thereafter, we would expect it to generate mid-single-digit accretion to adjusted net EPS and support growth in our adjusted net EPS over the long term. Now moving on to provide some updates on our other financing activities and progress on our 2021 capital plan. Since August of 2020, we have placed into operation approximately 1,400 megawatts of renewable energy projects from our construction pipeline. During the first 9 months of the year, Algonquin has developed -- deployed capital on initiatives relating to the safety and reliability of our electric, water and gas systems, as well as delivering new renewable generation from our projects, including Maverick Creek Wind, Altavista Solar and our Midwest Greening, bringing the total capital deployed so far this year to approximately $3.4 billion and on track for our expected capital deployment in 2021 of over $4 billion. During the third quarter, the company utilized its ATM program, raising proceeds slightly north of $100 million. We view the ATM program as allowing for cost-effective and opportunistic issuance of common stock, but plan to be disciplined in its use. As a result, we do not expect further issuance under the ATM until after the expected closing date of the Kentucky Power acquisition at the earliest. Lastly, I want to say that our balance sheet remains strong and resilient. At the end of the third quarter, the company had approximately $1.9 billion of liquidity and capital reserves available. We continue to have strong support from our key banking partners and expect to maintain resilient liquidity profile as our business continues to expand. Before turning things over to Arun, I'd like to provide a brief update on our 2021 adjusted net EPS guidance. Excluding the impact of the market disruption on the Senate Wind Facility related to Winter Storm Uri in Q1, we continue to expect our 2021 adjusted net earnings per share to be in or around the lower end of the company's range of $0.71 to $0.76 that was communicated previously. We continue to assume our earning -- in our earnings guidance, normalized weather patterns in the fourth quarter as well as resource availability and production on our renewable generating facilities that is within long-term averages. We also assume that the company is able to obtain constructive regulatory outcomes as well as absence of any supply chain delays that would impact our estimated placement service dates based on the current equipment delivery and construction schedules. With that, I will hand it back to Arun to outline our strategic plans.
Thank you, Arthur. Before we close out our prepared comments this morning, I want to give an update on our strategic initiatives. With society and economies working hard and preparing for the energy transition, I'm excited about how Algonquin's regulated and renewables businesses are both well positioned to contribute to and benefit from this decarbonization transition. We remain committed to our strong track record of disciplined growth with many different levers at our disposal. Having deployed nearly $3.4 billion of capital this year, we remain on track for our 2021 planned capital expenditures. The addition of Kentucky Power will be additive to the company's long-term investment pipeline. Another growth lever on our renewable side that I'd like to touch on is our significant focus on new greenfield development. As a reminder, this prospective greenfield pipeline is over and above our long-term capital investment plan. Our greenfield investments are focused on securing new opportunities and continue to advance the projects that will eventually form part of our base long-term capital plan in future years. We look forward to discussing this in more detail at our upcoming Analyst and Investor Day, which is scheduled for the morning of Tuesday, December 14, where we will be providing the investment community the opportunity to hear from key members of the leadership team for an update on our operations, strategic direction and future growth plans for Algonquin. In summary, our 3 strategic pillars of operational excellence, growth and sustainability will be a key foundation as we continue to build the business and strive to bring long-term value to our shareholders. We remain well positioned to continue to execute on our growth strategies while forcing our sustainability goals, guided by maximizing operational excellence on behalf of our investors and customers. With that, I will turn the call over to the operator for any questions from those on the line.
[Operator Instructions] Your first question comes from the line of Rupert Merer from National Bank.
So I'd like to start by asking about plans to finance the Kentucky acquisition and the potential for asset sales. Have you had discussions in the past on selling assets? And can we get some thoughts on which assets you might select for sale? Do you think you have some orphans in the portfolio? Or would you maybe look at selling a share of the whole portfolio?
Well, first of all, Rupert, anything we do, we're going to be guided by making sure we maintain a very strong balance sheet, right? That's an absolute must for us. And so from a business risk and credit profile perspective, whatever we do in terms of asset recycling probably will be more on the renewable side of the business where we believe it could be a combination of some of the things you talked about, it could be orphan assets that we perhaps developed or acquired many years ago that may not be a good strategic fit anymore or it may be opportunities to bring in low-cost capital while maintaining our strong development and operational levers. So we probably will not be obviously announcing which exact assets before we are prepared to do so.
Okay. That's fair enough. And then secondly, if we can talk about supply chain, logistics issues and any inflationary pressures you might see on your operations. I know [indiscernible] your not baking in any potential logistics issues related to your -- or in any -- what sort of risks should we be baking in there?
Sure. So first of all, I do want to give a little bit of context. So back in 2020, we had 1,600 megawatts of renewables under construction, right? And that was right in the midst of COVID. And I'm very pleased to report that by and large, we were able to bring in that 1,600 megawatts of construction projects into operation earlier last year in 2020 and in 2021. And so we have actually really done a lot in terms of ensuring we are able to effectively manage our supply chain efforts. Now having said that, yes, we are seeing issues around shipping, issues around delivery from the various ports, but I believe we have a pretty effective supply chain management team, and we do not see any huge movements or significant movements in terms of our project milestones.
Are you seeing any inflationary pressures either on your construction costs or on your operations or you anticipating any impact?
So 2 items, right? So first of all, many of the EPC contracts and large equipment supply agreements we have, they are under -- by and large, under fixed supply -- fixed price contracts, right? Now for the ones that are coming up, what we tend to do is try to align our equipment supply and EPC agreement contracts as close as possible to the offtake agreements. So yes, we have seen some pressures and inflationary pressures anywhere from -- depending on specific components, 5% to 10%. But we have also seen an increase and uplift in the offtake pricing. So we have been able to preserve the kinds of returns that we look for.
The next question comes from the line of David Quezada from Raymond James.
Wondering if you can just provide any color on the path you see to improving ROEs, be it timing? And what you see is a low-hanging fruit just in terms of whether that's the future test year or anything like that?
So look, this is something we're very focused on. And David, as I talked about earlier, we do have a playbook that we have utilized in places like Empire State, in CalPeco and other -- Granite State and some of our other utilities as well, all right? So we are well aware that the ROE is not optimized right now in Kentucky Power. There are a number of different mechanisms. We obviously will be working closely with the commission to make sure we work this effectively, and we do something that's in the best interest of the customers as well. So there are things like, for example, the unit power agreement with Rockport, which is a coal plant that is based in Indiana. There are a certain number of costs that have been deferred and disallowed for future inclusion in the revenues. So that's one lever. Another one is utilizing forward test years, which, as I said in my prepared remarks, are utilized by our other investor-owned utility peers in Kentucky. There are also items such as the 43% equity that we see right now. We believe we have room to increase that as well. And other capital and operating cost tracking mechanisms that are available. I mean Kentucky is a very constructive regulatory state and we definitely look forward to working with the commission closely to doing what's, again, best for our customers over the long term.
That's great color. And then maybe just one more for me. As you look to green the fleet at Kentucky Power, I'm curious if you had any initial thoughts on what the mix of renewables might be and if you could potentially even include storage there?
So look, I mean we look at stores whenever we look at any renewable project these days, and it is becoming more and more compelling. We will talk about this a lot more at the Investor Day. By and large, we believe that between solar and wind that in the state of Kentucky solar has probably better resource availability and better economics. There are pockets in the state of Kentucky, where wind is a strong resource. So we'll have to work through, obviously, citing interconnection capacity, all of those things and obviously, make sure that we work with the commission through the integrate -- the IRP process as we firm up our plans.
The next question comes from the line of Nelson Ng from RBC.
First question is just to follow up on David's question on greening Kentucky. So just in terms of the Rockport facility rolling off the UPA at the end of 2022. What is Kentucky Power's requirement to backfill that capacity? Do you have enough spare capacity for now for that facility to roll off? Or can you just provide a bit more details on like if you have to get new capacity by the end of -- at the end of 2022?
Sure. So at present in Kentucky Power has several sources for its load, right? You've got Rockport coal facility. You've got Mitchell coal, you've got Big Sandy gas, and then you have purchases from the grid, right? And interestingly enough, over the last several years, what we've seen is purchases from the grid are, in fact, a lower cost than purchases from the coal plants. So when Rockport UPA expires, that should actually be positive in terms of us being able to procure lower-cost energy from the grid as compared to Rockport.
Okay. But there's no requirement to have available capacity as backup or anything, right?
There are some utility capacity requirements, and we will be working with AET to replace the Rockport contract on a short-term basis to make sure we stay in compliance with those.
Okay. Got it. And then my next question just relates to BELCO. I believe there is a $35 million rate increase request. I didn't get a chance to pull the rate case following. But can you just talk about the key drivers of the increase? And is it mainly just due to higher oil prices that you've been seeing?
Yes. So -- and I think the 2 main drivers, Nelson, you've hit on one of them, which is the increased fuel prices. And then in the last rate agreement, there was some deferred costs being in the middle of the COVID pandemic. And maybe as a reminder and context for everyone. Traditionally, we've been filing an annual rate case with the RA in Bermuda. This is us now going into our first sort of multiyear filing. This will be a 2-year rate case with them.
Next question comes from the line of Julien Dumoulin-Smith from Bank of America.
So maybe just following up, let me just first focus on Kentucky here. Just as you think about the first off, Mitchell, could that be transferred sooner here just as you think about the timeline to exit coal here, if you can elaborate on that? And then also, can you quantify a little bit, I know you alluded to it earlier, the earned ROE, just what the timeline is there? And again, I know this is ahead of your Analyst Day. But as you're thinking about that coal transition, how much coal is in rate base today, as you think about that outlook that you're going to provide as well as the timeline to get to your earned ROE given the sort of the cadence, the rate cases around this?
Sure. So first on Mitchell, Julien, right? So as I'm sure you're aware, the Kentucky Commission basically approved the investment for CCR, which takes the project capable of delivering -- continuing to operate through 2028. And the commission did not approve the investments in ELG, which should have actually enabled the plant to continue to operate through 2040. So given that order, we are -- our view is that we will be able to transfer that ownership from Kentucky Power to the West Virginia subsidiary of AEP in 2028. Are there compelling reasons for us to be and economics for us to be able to transfer that earlier? That's something we'll obviously look at. But again, we'll have to work with the Commission on that account. On your earned ROE question, the allowable ROE in Kentucky is 9.3%. And I believe some of the earlier comments I made, Julien, around the disallowance of cost under the Rockport UPA, the potential to increase the equity thickness from 43% to something higher through utilization of 4 test years and some of the other mechanisms that are already available in Kentucky that we will -- we hope to be able to come closer, much closer to the allowable ROE. However, we have continued to be fairly conservative in our modeling as to our forward-looking views on that. So we remain pretty confident to be able to get much closer to the allowable ROE.
Got it. But so just to clarify that, when you say you're conserving your model, you're saying you're not necessarily fully assuming that as you look at your outlook over the 5-year period?
That's right. We assume that we will get closer to it over time. And we believe that our first rate filing will be in 2023.
Got it. Excellent. And then can you clarify the coal and rate base here, just as you said today, if you think about like that pivot over time. What's the starting point that we're at today, if you think about sort of the degradation from coal rate base to transition to renewables over time?
So clearly, the transition will start happening at the end of 2022, right? And obviously, another big point in time is 2028 when we will no longer have ownership of Mitchell. The third part, obviously, is how quickly can we bring renewables into the rate base working through the IRP process. And given the state of the economy in Eastern Kentucky, given the much lower LCOE of our renewables, we believe that we should be able to start layering in renewables as perhaps even as early as towards the end of 2024.
Got it. Excellent. Sorry, if I can -- I know we're also fixed myopically on Kentucky here, but I've got to ask you the question around BBB here, reconciliation. How are you thinking about your prospects under this legislation, especially given how you guys talk about renewables at times. And specifically also, I'd be curious if you could comment on how you think about HLBV given this legislation, too. I mean, obviously, an expanding opportunity set and some nuances I imagine for tax and how you guys recognize them too?
Well, let me first answer on the Build Back Better, right? Look, what I usually say to folks is that renewables has gone beyond policy. It's becoming -- it's already become an economic value proposition, right? But all of the tailwinds that are out there based on things like Build Back Better, can only help us, right? I will also go beyond that. One of the fairly easy things, I think that the Biden administration could do through an executive order, in fact, is direct purchases through the federal government of renewables. We already have the grade-based solar project where the General Services Administration of the federal government is the off-taker. So we have all of the accounting, regulatory policies and processes in place to, in fact, directly contract with the federal government as well. So with all the tailwinds and what the Biden administration is trying to do to accelerate the pace of renewables, we believe that all of these tailwinds can only benefit us. Arthur, why don't you respond to the HLBV question.
Look, from the plan, basically, I mean, a lot of tailwinds and increased flexibility, obviously, with the proposals around the extension of the tax credits just makes tax equity financing continue to be viable for us also with the direct pay proposals that, that obviously provides another dimension of financing. And as well as I said before, we continue to have tax appetite internally so that we can continue -- we can look at monetizing some of our own tax credits as well. So from an overall perspective, it provides flexibility. And look, we'll use it to basically enhance project economics as it best fit.
Next question comes from the line of Sean Steuart from TD Securities.
Just a couple of questions. New York American Water, just so I understand it ahead of the hearing next week. If there are still dissenting parties on this transaction, how does that play out post this hearing? And how does that inform your thinking around the closing date of early January, worst-case scenario?
Sean, this is Johnny. So I think in the joint proposal that we filed with the commission, we had all parties [ via ] one signing on. And so I think we feel very confident in terms of the process that we've gone through, the large degree of alignment in -- with all the parties down in Long Island. And so we really feel pretty confident coming through the hearing that we should be seeing an order in the not-too-distant future.
Okay. Second question is on Aegis. And so you've got the new partnership in place. Can you give us some context on what ARES brings to the table for you guys and thoughts on advancing that vehicle using it as a growth lever going forward?
So with Aegis, as you know, we have had Abengoa as a partner. And based on everything that is out in the public, it was a challenging partnership given the financial challenges that they have been going through. So with ARES, what we have is a very solid financial partner for us to work through our development and construction financing. And rather than also bringing a bespoke partner every time we do a project, we now have the contractual terms and conditions and everything pretty much with one partner. And also there's no conflict of interest given that they are our financial partner and they're not looking to enhance their own EPC capability or anything of that sort. But we do intend to require the Aegis name and basically do everything now under Liberty development, all of our development activities globally. So you'll probably be -- not be hearing about Aegis going forward from us.
The next question comes from the line of Rob Hope from Scotiabank.
I want to circle back on Arun's comments that you're seeing a little bit of cost inflation on new or novel projects, but PPA pricing is coming up as well. How are discussions going for the next phase of contracted renewable projects. Could we see a little bit of an air pocket here if the PPA offtakers want a little bit more certainty on whether or not the inflation is transitory or if it's your for a while. Just want to get a sense of how discussions are going?
And just to make sure I understand, Rob. So basically, what I was trying to say in my comments is that we are seeing inflationary pressures depending upon certain commodities, but also it could include things like shipping and other transportation costs, things of those sort. But what I was saying is that on the flip side, by and large, we have seen higher offtake prices as well. So we have been able to preserve the economics of our projects. And one of the things we do is really try to make sure we sign off on the EPC and major equipment supply contracts as close to the offtake agreements as possible. So there's really little if any daylight between the 2 where we are exposed. That's really what I was trying to see in my remarks. I don't know if I missed anything from -- particular from your question or feel free to ask again, Rob.
Yes. Maybe just to clarify. So the next phase of renewables are the ones that you still need to secure PPAs. How are the pace of conversations going on those to get those secured? Have they -- has the inflationary environment slowed it down? Or are they still making good progress?
No. We're still making good progress, Rob. We continue to advance those discussions. We'll be sharing more at Investor Day on some of those discussions. But we also -- we'll anticipate as we move forward. The counterparties are willing to transact at higher prices, but we have to have the difficult discussion of if there's uncertainty and things that are unknown, how do we take and manage that risk because we typically do not take that on, and we remain disciplined. So if we have to push a project out, we'll push a project out, but the discussions, directly to your question have been going well.
Okay. Good to hear. And then a second question, just in terms of how you're looking at the Atlantica stake. We haven't seen a ton of drop-downs, but you do have this capital requirement coming at us with Kentucky. Do you view drop-down to Atlantica as a -- as an attractive source of capital? And I guess, secondarily, how are you viewing Atlantica from a strategic point of view?
Sure. So look, Atlantica remains a very attractive investment, especially given the price at which we are able to enter Atlantica, right? It's also very aligned with our overall ESG posture. I mean they have been rated the most #1 renewable energy company globally. And so we are very aligned on that front as well. We continue to work with them fairly well. We, in fact, have dropped down last quarter, one of our assets in Colombia that was under construction. That is now fully operational. So we have done dropdowns. As we think about doing possibly monetizing our -- some of our renewable energy assets, we will do what's best from a balance sheet perspective, first and foremost, but also what is best in the context of -- for our shareholders. And if it is found that these drop downs into Atlantica is the best outcome, we will give that serious consideration as well.
The next question comes from the line of Ben Pham from BMO Capital Markets.
So there's some commentary or a sentence in the MD&A mentioning your targeted utility exposure, 70% to 80%. And I think that's maybe the first time that I've seen maybe some more specific numbers being put there, correct me if I'm wrong. And really, my question is that really -- maybe to frame us, how you're thinking about that? I mean Kentucky brings you to 80%. So you basically saying you don't want to accelerate the utility expansion or M&A as much anymore post Kentucky? Does it impact how you sell renewable assets because that's going to change the mix around, or is this maybe credit rating driven?
First and foremost, balance sheet, right? Again, we were laser focused on making sure that we do not degrade our BBB credit rating. Business mix, obviously, is a part of that. There is no very, very clear red line on what exactly that business mix should be, which gives us optionality, frankly, on how we grow regulated versus renewables. The higher regulated mix pro forma with Kentucky Power, obviously takes us closer to 80%, which obviously has a positive impact on business risk, credit profile and so on and so forth. It also gives us optionality on accelerating our growth on the renewable side because let's say if we were to come back to 70%, which is still within the right mix for our credit rating, that opens up room just on the renewable side of the business for over 2,700 megawatts. Now that's over and on top of whatever we could do in terms of Greening the Fleet in Kentucky. So it really does accelerate significantly our potential growth of renewables, both in rate base in Kentucky as well as on the renewable side of the business. Does that answer your question, Ben?
Yes, it does. That's helpful. And maybe to follow up on some of Arthur's comments around the remaining funding for Kentucky. It sounds like -- I just maybe want a confirmation, as I guess, if you were to clear the funding near term, it sounds like your biased right now as hybrid securities, maybe a little bit of nonregulated asset sales but less of a desire to add a lot of mandatory converts given that future equity dilution. Is that correct?
Look, Ben, I think, I mean, one thing I can say about the remaining funding plan, it gives us a lot of flexibility, right? I mean these 5-seconds hybrids are very attractive. We've got flexibility with mandatories we talked about potential asset recycling opportunities that could be there. But right now, we really have -- this provides us flexibility.
Okay. And is there -- I know you feel quite good about not needing external equity ATM through mid-2022. But is there any sort of scenario like a dark sky scenario that could happen or maybe even more robust growth opportunity that you expect that could drive an equity issuance in that time frame?
Look, I mean, one of the things that that's non-negotiable for us is our strong balance sheet. We need to maintain a strong balance sheet. So there's -- we can speculate, I guess, a lot here, and I won't speculate. I mean there could be a lot of the dark cloud scenarios. But I mean, right now, as we're looking forward, I think what we stated in my remarks as -- it continues to hold.
Okay. And maybe a cleanup question on the tax credits. You mentioned that your booking this year, year-to-date. It looks like it's probably around $0.05 or so like do you expect that $0.05 to be more of maybe a structural impact to EPS going forward? Do you expect it to increase, decrease?
That's a great question. And I would say, yes. I mean as we kind of look through and I spoke to the flexibility that now we'll have actually under the Build Better Back plan as well. The ability to self-monetize is going to be there for us and is one of the ways that we'll look to potentially fund projects, again, whichever way best optimizes the particular projects economics. So yes, I would say that is a tool that we'll have to continue to manage our overall effective tax rate.
Next question comes from the line of Andrew Kuske from Crédit Suisse.
I guess the question is for Arun. And it's really around the whole notion of the organization getting bigger, which you've been on a great growth trajectory for a while, and then you've got another acquisition in the fold. How do you maintain the entrepreneurial culture and status of the organization that has historically been known for, as you expand the entire enterprise?
It's a great question, Andrew. And look, one of the things time I'm really, really pleased about at Algonquin is that very entrepreneurial culture. It's one of our guiding principles. And that and the strategic thinking is both on the renewable side of the business and on our regulated side of the business. So as you see, things like Greening the Fleet on the regulatory side of the business as well. We have been successful in putting in significant amount of renewables into rate base, putting in tax equity, perhaps as pioneers and doing that into the rate base. So we're doing things like the renewable natural gas. We've got a lot of storage pipeline. We're doing community solar projects. So this is a lot of different levers we have. But really, everything is really around the whole decarbonizes and transformation, right? What I'm extremely excited about is that, that opens up huge amount of opportunities. And we are -- we absolutely stand to benefit hugely from that transformation over the next 10, 20 years. And that's where we're really trying to align the entire company and all of our entrepreneurial event is really towards that.
That's helpful. And then maybe just a follow-up and related. If you think about your overall portfolio now, 10 years ago some of the acquisitions that were done were meaningful to the company and those assets aren't that meaningful now, but maybe they have positional value and there's things that could be done around those assets. So how do you think about just rationalizing parts of the portfolio to maybe help us the financial structure versus the entrepreneurial efforts that can be driven off of sort of the assets that are across North America?
And again, we do want to look at that very strategically, right? I mean so frankly, each of our assets and jurisdictions, we should be looking at it from a perspective of do we grow, do we hold? Or do you divest, right? And at the end of the day, what is best for our shareholders. And so we do look at it from that perspective, and like I said earlier, at the edge, there may be certain assets that we may have acquired 10, 15 years ago that may not be a good strategic fit for us. So when we think about things like asset recycling, those will obviously be at the top of the heap for us. But other than that, we also have -- believe we have lots of opportunities, given our scale on the renewable side to really continue to use the flywheel in terms of basically bringing in lower cost capital, utilizing some of that for continued development, continue to provide the kind of growth and returns that we want to provide to our shareholders. So there's a lot of good that could come from that process as well.
Last question comes from the line of Naji Baydoun from IA.
Just wanted to start off with some questions on Kentucky and some of the comments you made on strategic fit of certain assets. I guess to be clear, there's no currently any preference to sell either a stake in Atlantica or in existing assets to help finance the Kentucky acquisition?
Look, Naji, what we've talked about is that the various financing sources, and one of them could be asset recycling. But I think what Arthur has also said repeatedly is that we, in fact, have -- especially given our recent bought deal that we have a lot of flexibility on how we are going to fund the remainder of the balance. Again, hybrid debt looks very attractive right now, but we could be looking at other sources as well, such as asset recycling.
Okay. Got it. I just wanted to get, I guess, a bit more of your thought process behind the Kentucky acquisition. It seems like there's a lot of value you can unlock maybe AEP couldn't or wasn't interested in doing. How do you view these assets in terms of risk return profile maybe relative to some other M&A opportunities you're seeing in the market, especially when you take into consideration the size of the transaction.
Right. Look, what we're excited about is several things, right? First of all, it's a very compelling valuation. When you think about 1.3x rate base, and you just look at the other transactions that have been done out there, right? This is a very compelling valuation, right? Second of all, you look at the fact that Kentucky is in fact, a highly rated constructive-regulatory jurisdiction. That's another plus as well; third, you look at the Greening the Fleet of potential that I talked about earlier, especially given the fact that from the perspective of Kentucky, one of the coal plants from where we're purchasing power is in the state of Indiana. And the other coal plant from which we're purchasing power and own 50% is in West Virginia. And so from the perspective of Kentucky, being able to add significant amount of lower-cost renewable energy in the state of Kentucky, to replace the energy that is being brought in from either Indiana or West Virginia, and that is coal and has a higher cost that has to be extremely compelling as well, right? And on top of that, what I talked about is the other playbook that we have, where examples like Granite State, examples like Empire, which were underperforming when we acquired them. And the fact that we have been able to bring them back to -- at or close to allowable ROE, I think that playbook also speaks for itself. So for all of those reasons, we're actually very excited about this opportunity.
Okay. Got it. Very clear. Just one final quick question, if I can, on the entire Missouri rate case. Just any preliminary thoughts on the staff recommendation in that rate case? I know it's still ongoing, but just any thoughts.
I think at this point in time, as we're in the middle of the process, it's probably not the right time to comment. We're looking forward to engaging with -- through the process and look forward to getting a fair outcome.
There are no further questions at this time. I would now like to turn the conference back to Arun Banskota.
Thank you, operator, and thank you very much for those who are able to join us today for taking the time on our call today. With that, please stay on the line for our disclaimer.
Our discussion during this call contains certain forward-looking information, including, but not limited to, our expectations regarding earnings, capital expenditures, pending acquisitions, potential future Greening the Fleet initiatives and potential future funding sources and transactions. This forward-looking information is based on certain assumptions, including those described in our most recent MD&A filed on SEDAR and EDGAR and available on our website and is subject to risks and uncertainties that could cause actual results to differ materially from historical results or results anticipated by the forward-looking information. Forward-looking information provided during this call speaks only as of the date of this call and is based on the plans, beliefs, estimates, projections, expectations, opinions and assumptions of management as of today's date. There can be no assurance that forward-looking information will prove to be accurate, and you should not place undue reliance on forward-looking information. We disclaim any obligation to update any forward-looking information or to explain any material difference between subsequent actual events and such forward-looking information, except as required by applicable law. In addition, during the course of this call, we may have referred to certain non-GAAP financial measures, including, but not limited to, adjusted net earnings, adjusted net earnings per share or adjusted net EPS, adjusted EBITDA, adjusted funds from operations and divisional operating profit. There is no standardized measure of such non-GAAP financial measures, and consequently, AQN's method of calculating these measures may differ from methods used by other companies and therefore, they may not be comparable to similar measures presented by other companies. For more information about both forward-looking information and non-GAAP financial measures, including a reconciliation of non-GAAP measures to the corresponding GAAP measures, please refer to our most recent MD&A filed on SEDAR in Canada or EDGAR in the United States and available on our website. And that concludes our call. Thank you for joining.
This concludes today's conference call. Thank you for participating. You may now disconnect.