© 2024 Alpha Spread Limited. All Rights Reserved.
www.alphaspread.com is not operated by a broker, a dealer, or a registered investment adviser. Under no circumstances does any information posted on www.alphaspread.com represent a recommendation to buy or sell a security. The information on this site, and in its related newsletters, is not intended to be, nor does it constitute, investment advice or recommendations. The information on this site is in no way guaranteed for completeness, accuracy or in any other way. In no event shall Alpha Spread Limited be liable to any member, guest or third party for any damages of any kind arising out of the use of any content or other material published or available on www.alphaspread.com, or relating to the use of, or inability to use, www.alphaspread.com or any content, including, without limitation, any investment losses, lost profits, lost opportunity, special, incidental, indirect, consequential or punitive damages. Past performance is a poor indicator of future performance.
You don't have any saved screeners yet
Intrinsic Value is all-important and is the only logical way to evaluate the relative attractiveness of investments and businesses.
Ladies and gentlemen, thank you for standing by, and welcome to the Algonquin Power & Utilities Corporation 2020 Fourth Quarter and Full Year Earnings Webcast and Conference Call. [Operator Instructions] Please be advised that today's conference is being recorded. [Operator Instructions] I would now like to hand the conference over to your speaker today, Amelia Tsang, Vice President, Investor Relations. Thank you. Please go ahead.
Good morning, everyone. Thanks for joining us this morning for our 2020 fourth quarter and year-end earnings conference call. My name is Amelia Tsang, and I'm the Vice President of Investor Relations at Algonquin Power & Utilities. Presenting on the call today are Arun Banskota, our President and CEO; and Arthur Kacprzak, our Chief Financial Officer. Also joining us this morning for the question-and-answer 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 and capital expenditures and the expected impact of outcomes of the recent severe winter storms in Texas and the Central U.S. At the end of the call, I will read a notice regarding both forward-looking information and non-GAAP financial measures. Please also 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 Q4 and full year 2020 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 line 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 this call and online. Given that this is our year-end earnings call, I want to provide some highlights and speak to performance, both financial and operational for 2020.Firstly, on financials. I'm pleased to report steady year-over-year growth in our key financial metrics. 2020 adjusted EBITDA of $869.5 million increased 4% year-over-year, and our 2020 adjusted net earnings per share of $0.64 compares to $0.63 reported last year. There were 3 particular events: COVID, weather in the central region and delayed closing of BELCO that impacted our results.Despite these, management was able to pull a number of levers, including cost savings, to continue our growth trajectory. We exited the year with $13.2 billion in assets, a 21% increase over last year.Secondly, in terms of shareholder value creation, we continue to generate consistent outstanding returns as proven by our record on delivering total shareholder returns. In 2020, the company delivered total shareholder returns of 21.5% on the New York Stock Exchange compared to the 22.7% for the utility index and 15.3% for the S&P/TSX Capped Utilities index. Last year, we reported annual dividends per share of $0.61, which represents a 10% annual increase for the tenth consecutive year in a row.Thirdly, on operations. The company undertook many successful growth initiatives and achieved numerous milestones in 2020. We continue to focus our efforts on Algonquin's 3 strategic pillars: growth, operational excellence and sustainability. For those of you who may have participated at our Virtual Investor Day in December, we discussed this at length. We operate through 2 businesses, regulated and renewables. What is unique about us are our multiple levers of growth that support our 2 businesses and which gives us high confidence in delivering outstanding returns.One lever of growth is acquisitions, and we completed 2 utility acquisitions in 2020, ESSAL and Ascendant. With the addition of these 2 utilities, Algonquin now has over 1 million customer connections within our regulated footprint. Additionally, both acquisitions are expected to provide opportunities for future growth.With New York American Water, we submitted our regulatory application to the New York PSC last year. We are currently going through the settlement process and the year-end date is scheduled for mid-May. We continue to expect this transaction to close in 2021.On the renewable energy business, the company made its largest renewable energy acquisition, acquiring a 51% ownership interest in a portfolio of 3 operating coastal wind facilities with a combined generating capacity of 621 megawatts in South Coastal Texas. These 3 wind facilities have already achieved commercial operations. The acquisition of a 51% interest in a fourth 240-megawatt South Texas coastal facility is expected to occur in the first half of 2021 once the facility reaches commercial operations.We continue to prove out our C&I growth lever as Algonquin remains very well positioned in the C&I space where imported long-term customers are supporting renewables growth as they are looking to achieve their own sustainability goals. As further proof of concept, we signed a framework agreement with Chevron last year for the potential development of over 500 megawatts of renewable energy facilities. This has been an area of focus for us, and we are working hard to progress that portfolio and expand our customer base.2020 also marked the company's largest construction program in our history with approximately 1,600 megawatts of renewable energy projects under construction. To put that in context, these new projects approximately doubled the amount of our overall renewables portfolio. Within our renewables business, 2 of our projects, the Great Bay II Solar Facility located in Southern Maryland and the Sugar Creek Wind Facility located in Illinois both achieved full commercial operations last year.Furthermore, 2 more projects are nearing completion with more than half of Altavista Solar's 80 megawatts successfully placed in service with a power purchase agreement with Facebook. And the remaining megawatts are expected to be completed by the second quarter of this year.Our 492-megawatt Maverick Creek Wind facility in Texas completed commissioning on 111 of the 127 turbines and has long-term power purchase agreements with General Mills and Kimberly-Clark. Maverick was recently recognized by the American Clean Power Association as the fourth largest single phase wind project in the U.S. history.An important lever of growth on the regulated side, as we transition to lower carbon energy, is our Greening the Fleet initiatives. We continue to progress well on our Midwest greening initiative with the development and construction of 3 wind farms for a total 600-megawatt capacity as we work to generate and deliver more cost-effective, diverse and sustainable energy options to our customers and communities. The 150-megawatt North Fork Ridge wind facility has achieved full commercial operation, while the 300-megawatt Neosho Ridge and 150-megawatt Kings Point facilities are anticipated to be placed in service prior to the end of this month.Moving on now to operational excellence. In a mission-critical industry like ours, safety is always an area of focus. And so I'm pleased that we have just passed the impressive milestone of an entire year without a single lost time injury. I'm very proud of our employees and management for continuing to stay focused on safety first, even while we had to transition into a very different work environment given COVID-19 and the priority of keeping our employees and communities safe from the pandemic.The importance of reliably providing the essential services of electricity, water and natural gas to our customers has become even more apparent during the COVID-19 pandemic. Our diversified asset base and our emergency preparedness highlighted our resilient business model, which has meant that our essential services to customers have not been impacted. And financially, as a proof point of how resilient our business model is, the pandemic had a relatively low impact of $0.02 in adjusted net EPS for 2020.With the onset of the pandemic, we focused on cost containment strategies without sacrificing safety and reliability. In the first half of 2020, we announced we are targeting $15 million of savings for the full year, and I'm pleased that we were able to significantly beat that, delivering $24 million in savings for the year.2020 marked the first full year of contribution from New Brunswick Gas and St. Lawrence Gas. The integration of these 2 utilities into the Algonquin Liberty family has gone well as growing the business organically in these 2 facilities is a key initiative.As with all our previously acquired utilities, we strive to share learnings among our utilities with the aim of driving consistent improvement in our key performance metrics that drive value for our customers and investors. 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 want to provide a few highlights from 2020. In March, the closure of our Asbury coal generation facility in Missouri will allow us to reduce annual carbon dioxide emissions by 955,000 metric tons. In the latter part of 2020, we increased our disclosures around sustainability by releasing our first ever climate change assessment report in response to guidelines established by the Financial Stability Board's Task Force on Climate-Related Financial Disclosures, TCFD.We also released our 2020 sustainability report, which not only outlined our progress on our ESG goals but provided higher level of disclosure details around our 9 priority issues. And in 2021, you'll see us adding additional ESG-linked goals to our compensation program metrics. Overall, I'm pleased with the progress we've made in 2020 given COVID-19 and all its challenges, and I'm confident we will continue to benefit from our strong, resilient and diversified business model in 2021.Before turning to Arthur, I want to comment on storm Uri and the Midwest extreme weather event, which occurred last month. First and foremost, our thoughts are with the many people whose lives have been disrupted by the extreme weather event. Since the event began, our teams have worked tirelessly under very challenging conditions to keep our customers and communities safe and to maintain our system reliability and resiliency. I would like to thank our dedicated employees for their teamwork and [ continuous ] commitment to our customers.In our renewables business, we currently have a total of approximately 2,550 megawatts of wind, solar and hydro projects in operation, including our 51% interest in 3 South Texas coastal wind facilities. In accordance with our strategy, our portfolio of asset is very diversified across 46 facilities, 15 states and provinces and 7 ISOs. We believe this diversified portfolio will continue to be a major advantage in the face of climate change.In Texas, we have a diversified operating portfolio of approximately 965 megawatts across 5 locations: 2 inland and 3 coastal. This provides the wind resource diversification outlined during our 2020 Investor Day. The Texas portfolio also benefits from offtake diversification. Maverick Creek's 492 megawatts and our 51% interest in the East Raymond 200-megawatt facility both operate under long-term unit contingent power purchase agreements.On the remaining Texas assets in operation, we are hedged using long-term fixed financial swaps with a total combined hedge position of approximately 120 megawatts. We saw no material impact at the coastal wind assets, while storm Uri did have a major impact on our [ standard ] assets. In total, our estimated exposure remains, what we announced earlier in our press release, of $45 million to $55 million before potential mitigating impact.We have asserted force majeure at our standard facility given the large-scale market failures and extreme weather events. Storm Uri was very unusual in the level of impact across a very large geography and temperatures fell to 6 degrees Fahrenheit near our standard facility, lower by 9 degrees compared to the lowest ever recorded temperature in the last 100 years.Since there may be a dispute and possibly litigation, we do not intend to speculate today on our legal position. There are also ongoing discussions regarding potential Texas government or regulatory intervention, including questions on $9,000 a megawatt hour pricing, and this could be another mitigation to our estimated $45 million to $55 million exposure.In our regulated business, which comprises approximately 70% of our portfolio, we are diversified by modality and operating 16 jurisdictions. Despite the extreme weather conditions, the regulated service group's electric and gas operations performed well during a sustained period of increased consumption. We did encounter some weather issues in our central region. And in accordance with instructions from the SPP, we did some limited load shedding.The utilities did incur incremental commodity cost during a period of record pricing and elevated consumption. The incremental commodity costs incurred by the company are expected to be substantially recovered from customers over an extended period. We do not expect any material financial impact to our regulated business.With that, I'll pass it over to Arthur, who will speak to our Q4 and full year 2020 financial results as well as the financial impact of the rigorous extreme weather event. Arthur?
Thank you, Arun, and good morning, everyone. As Arun mentioned earlier, in 2020, Algonquin has again shown its ability to accretively grow earnings through its stable regulated services and long-term contracted renewable power businesses.Our fourth quarter 2020 consolidated adjusted EBITDA was $253.1 million, which is up approximately 10% from the $230.4 million we reported in the previous year. The regulated services group delivered $161.8 million in operating profit in the current quarter, which compares to $159.4 million in the same quarter last year.The increases primarily reflect the implementation of new rates and the contribution from ESSAL and BELCO, which both closed in the quarter. This was partially offset by decreased customer consumption, primarily at our central utilities due to warmer than usual weather. The renewable energy group reported fourth quarter divisional operating profit of $102.9 million, which compares to $85.9 million in the same quarter last year. The increase represents generally higher production across our renewables fleet during the quarter.Our Q4 adjusted net earnings per share came in at $0.21, which compares to $0.20 reported last year. Our results were positively impacted by cost savings implemented during the quarter, a solid performance from our generation facilities and the contribution of ESSAL and the BELCO acquisitions but were partially offset by the unfavorable weather in the central region, as mentioned earlier.For the full year, adjusted net EPS came in at $0.64 and compares to $0.53 recorded in the prior year. The 2020 results included a full year contribution from New Brunswick Gas and the St. Lawrence Gas systems, which were acquired late last year as well as the implementation of new rates on our CalPeco and Granite State Electric distribution systems.The results were negatively impacted by decreased consumption resulting from the COVID-19 pandemic as well as significantly unfavorable weather experienced by the central region in early 2020. The delay in the closing of BELCO also weighed negatively on our results as compared to our expectations for the year. Despite these challenges, the year-over-year growth in adjusted net EPS demonstrates the stability and resilience of our business model.Now I would like to provide a few more financial updates from the quarter. First, on the COVID-19 pandemic and its financial impacts. We have seen the impacts of the pandemic and consumption patterns continued to ease as the economy reopens. The impacts of the regulated services group's divisional operating profit was less than $1 million in Q4 with full year COVID-19 impact coming in at $14.7 million or $0.02 in adjusted net EPS.As reported previously, in the second quarter, we began implementing cost containment strategies in response to the demand decreases caused by the pandemic. I'm pleased to report that in the fourth quarter, we're able to achieve expense reductions of approximately $6 million, which brings the full year cost savings to $24 million.I'm also pleased to report that all of the reductions were made without compromising on safety, security and reliability of the services we provide to our customers. About 1/3 of these reductions occurred naturally through reduced travel and another similar expenses, 1/3 was related to timing and the final third is related to ongoing savings we're able to drive in our business and has been factored into our 2021 earnings expectations.Before turning things over back to Arun, I'd like to provide a brief update on our 2021 guidance. In 2021, our results are expected to benefit from the addition of approximately 1,400 megawatts of new renewable generation capacity completed late last year or early in the first half of this year. In addition, we expect to benefit from the first full year of operations of BELCO, ESSAL and the Texas Coastal wind portfolio. Factoring in these benefits, in total, we expect our 2021 adjusted net earnings per share to be in the range of $0.71 to $0.76, which is consistent with what we communicated at our Investor Day last December.As Arun mentioned earlier, last month, our operations were impacted by extreme winter storm conditions experienced in Texas and parts of the central U.S. The most significantly impacted facility was the Senate wind facility, which has a financial hedge in place that it poses an obligation to deliver energy. Because of the unusual market disruption related to the extreme weather events, that facility was required to purchase power for an extended period of time at exceptionally inflated pricing to cover the production shortfalls under its hedge.This is expected to result in a $0.06 negative impact to 2021 basic net earnings per share, which is calculated before any potential recoveries. We view this market disruption on the Senate facilities as unusual and not representative of the ongoing operating performance of this company and thus, have excluded its impacts from the 2021 adjusted net earnings per share expectations discussed earlier.With that, I'll now hand it back over to Arun to outline our growth plans.
Thank you, Arthur. Before we close out our prepared comments this morning, I want to give an update on our growth initiatives and capital plan. At our December Investor Day, we updated our 5-year capital investment program, which projects $9.4 billion from '21 through the end of 2025 to be spent across our 2 business groups with the emphasis on regulated services.We have identified projects that make up the entire $9.4 billion, with most of them under construction or in advanced development. This core $9.4 billion does not include any further M&A beyond previously announced transactions or any success from our 3.4-gigawatt pipeline of greenfield opportunities.Over the last year, we have bolstered our internal resources and [ software ] tooling to focus even more on greenfield development opportunities that are originated by us. For many of these opportunities, we already have site control and are in the interconnection queue, and we will work to bring this into construction in 2023 and beyond.Before we open the lines for the question-and-answer period, we remain very excited about Algonquin's businesses and prospects. With society and economies working hard to minimize carbon emissions and many countries coalescing around a net-zero carbon by 2050 goal, Algonquin's regulated and renewables businesses are well positioned to contribute to and benefit from this decarbonization transition.Our 3 strategic pillars of operational excellence, growth and sustainability will be a key foundation as we continue to build the business and bring long-term value to our shareholders. We remain well positioned to continue to execute on our growth strategies while pursuing our sustainability goals guided by maximizing operational excellence on behalf of our stakeholders, including investors, employees 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 if I could start with the Texas weather event. You discussed the incremental commodity cost of the regulated utility business in the Midwest. What's the scale of that incremental cost? And can you talk us through how this will manifest itself in the financial results? Do you book higher costs in revenues here? Are we going to see an accrual on receivables? Can you just tell us how we should be looking at that, please?
Sure. Sure. So the total cost is expected to be in the neighborhood of around just over $200 million. And that's -- primarily all of those costs are expected to be pass-through to our customers, although the timing over the pass-through is obviously subject to discussions with our regulators. We do expect to set up regulatory assets with respect to those commodity costs.
Okay. All right, very good. And then looking at the Texas event and as well as all of the growth you have on tap right now, can you give us some thoughts on the balance sheet strength today, your liquidity position and capital needs for the remainder of the year to fund your construction?
Sure, Rupert. So we have a very strong liquidity position. As you know, we've got regular -- about $1.5 billion of committed credit facilities, and we've also, call it, beefed up our liquidity position with another $1.6 billion of term facility. So right now, we're sitting at about $2.8 billion of available liquidity to us, which certainly is sufficient to fund our ongoing capital plans. But obviously, we plan to also be in the capital markets this year, raising some funding.
Your next question comes from the line of Sean Steuart from TD Securities.
A couple of questions. I see that subsequent to year-end, you sold a 32% stake of ESSAL down pretty shortly after acquiring it. Can you give us some of the rationale, especially as it looks like you sold it at a little bit of a discount to the initial purchase price?
Sure, Sean. So look, while we are very, very comfortable with Chile as a country risk and a business risk, this was our first major investment in Chile. And if you look at the structure of ESSAL, it had a strong local partner initially. And through the tendering process, they tendered their shifts.We always believed that as a first transaction, strategically, it was very important for us to have a good, strong local partner who could help us with all kinds of things locally. And so Toesca was a very natural choice. We have known them for a while. And they not only know the local energy and water sector very well. They, in fact, also own 50% of another water utility in Chile. So they were a very, very natural partner for us. So it was really a strategy that we had in place long before the final acquisition of ESSAL took place. And no, it was not at a discount.
Okay. Look, just like a modest one in our math, but maybe I'll follow up on that. Second question, Page 22 of the MD&A goes through some of the variances in the quarterly results for the regulated segment. There was an other bucket of $9.9 million that goes through several items. I'm wondering, Arthur or Arun, if you can go through some of those elements specifically and help us clarify that figure and the impact on the results.
Sure, Sean. I'll try to take a stab about it, and it really is a bunch of items in there. One of the things is we, obviously, as you're aware of, contracted services at some of our utilities. That revenue tends to be a little bit more chunky. So it's just a matter of, I guess, timing compared to last year of that revenue. I'm referring to our [indiscernible] facility as an example. We also have our ESSAL utility that we actually ended up recognizing some interest in last year -- that's going to reoccur this year. So that's just a matter of a comparative. We also had this lower AFUDC capitalization this year compared to last year. So it's a bunch of things altogether.
Your next question comes from the line of Julien Dumoulin-Smith with Bank of America.
Listen, a couple of different questions for you guys. Maybe to start higher level, can you elaborate a little bit more on ITC, PTC extension here? Just how are you thinking about the impact to your business? I mean, obviously, you guys have this accelerating opportunity, a number of different counterparties, Chevron, for instance. Just can you elaborate a little bit on how you think about the cadence of the opportunity here?
Julien, it's Jeff. And I just want to -- if you could reiterate the very beginning of that question on the ITC, PTC opportunity, just to make sure that I...
Just with the extensions here. I mean does this provide a greater sort of 5-year view on what you think you can do? I know this is out of cycle. We had the typical December update. But I'm just curious with -- given that we've got these extensions of late.
Yes. I think -- well, there is a couple of things. We are very keen about the Biden administration and where they're going to take things and what extensions will go above and beyond with what we've already seen. And obviously, the ability to improve some of the economics within our $9.4 billion pipeline to the extent that they're able to qualify for that incremental PTC, ITC.The most significant is the ITC extension, allowing projects to come online a little bit later on the solar side. And so we do see upside in the $9.4 billion pipeline on the timing of some of those projects and the ability to bring more projects, which aren't yet secured. But obviously, we're always looking the ability to bring more projects in that will take advantage of that full ITC.
Also, to add to that, Julien, where it should really help us is on our 3,400-megawatt greenfield pipeline. With the extension of the ITCs and the PTCs, obviously, the economics on those projects will be even better than what we had projected before. And again, as a reminder, that 3,400-megawatt greenfield pipeline is above and beyond our $9.4 billion 5-year capital plan.
Yes, understood. And then if I can go back into some of the details here. I just want to understand the New York American Water piece of this. Just can you talk about the confidence in getting that closed here? I mean I know there is lots of talk in the state, difficult to discern exactly what's going to transpire there.And on the Texas front, just force majeure, anything specifically we should be watching there and what you're assuming in that $0.06? I just want to make sure I understand what the $0.06 assumes on outcomes there.
Sure. Julien, let me start with the New York American Water, right? So as you know, there is a lot that has been very in the public realm, and I'm not going to repeat that. But our conversations and discussions with the commission has continued, and the hearings are set for mid-May.As you know, Governor Cuomo has come out of this bill, and one of the elements of that bill is to look at potential municipalization. We've obviously welcomed that opportunity to have a public dialogue around benefits and not of municipalization versus in a private participation. And we are still confident that, that acquisition will close in 2021.Just as context, though, I should point out, we closed St. Lawrence Gas in New York state, and that was an approximately 18-month process. So because of our presence in 16 different jurisdictions, we have a pretty good view of how long different regulatory processes take. And so we believe that we'll be in that [ kind of ] a time frame.Your second question, what I believe around Texas and force majeure. Our announcement was a full $45 million to $55 million impact before any potential mitigation, right? And so we have already issued a force majeure notice. I believe we obviously remain confident in our -- in the provisions under which we issued that.Obviously, there is a -- because it could get into a dispute or a litigation situation, I don't want to comment more on that. The other potential mitigation is, as you're well aware, Julien, I mean, there is a lot of discussion going on at the Texas legislature, at the PUC there around the merits and not about the $9,000 a megawatt hour pricing.And whether there is a possibility of part or all of that being rescinded, we see that as another potential mitigation because by and large, from every commentary out there, there was a large-scale market failure. So there are some -- those are some of those mitigations we're thinking about, but that is not included in the $45 million to $55 million number we gave in our release.
Your next question comes from the line of David Quezada from Raymond James.
Just my first question here. Just as it relates to your wind build-out in the Midwest, as that customer savings plan, I guess, completes over the next year or so here, I'm wondering what your thoughts are on the potential for future renewables and the rate base there in the Midwest and I guess, maybe even how storage could play a role there as well.
David, so let me answer the first part of the question, and I may turn that over. So in terms of the 600-megawatt wind project, in fact, one of them is already online, North Fork. And the 2 others, Neosho and Kings Point, they're scheduled to come online, in fact, by the end of this month. So they're clearly very, very advanced in terms of being in operations. We do believe that there is more opportunities out there in terms of substituting wind or solar for other forms of thermal generation, but I'll turn it over for more context.
Yes. It's Johnny Johnston. So as part of our ongoing review of our IRP brands as part of our central organization, we're always looking ahead of what opportunities we have to make sure that we've got the right generation to meet our load within our plans. At the moment, we have another 50 megawatts of solar to be put into place and then 20 megawatts of more sort of solar and storage on a sort of more of a community-type basis. And then we'll continue to review that analysis each year as we go forward. Clearly, we've still got a number of other aging facilities that are part of our generation fleet there. And as those opportunities present themselves, we'll be putting the [indiscernible].
And David, as you know, I mean, Greening the Fleet is a very key lever that we have where we believe we have a unique expertise, especially with our experience around tax equity. As you know, in CalPeco as well, we've added a number of solar generation into that rate base. We are excited about potential opportunities in Bermuda as well because that certainly is all thermal generation. So this is something that we are continuously evaluating, and you obviously continue to hear more from us on our Greening the Fleet initiative.
That's great color. Maybe just one more for me. I guess, in Europe, you've started to -- looks like unearth some opportunities in Spain. And then, I guess, a few renewable opportunities in Colombia as well. Just curious how you see the outlook and the development of projects progressing through Aegis. Just any comments that you could provide there on the momentum you're seeing in those markets.
Sure. So I do want to give context for it, right? So we are, by and large, a North American energy and water company, right? And some years ago, when we acquired our business in Atlantica, we also felt the need for a development entity that will go after nonregulated international businesses. So the scope of Aegis is just that, nonregulated and international. And the 2 markets that we have been targeting are Spain and Colombia because we believe that from a contributive business risk, potential opportunities and our own position in those markets, we believe that we have advantages in those markets.As you saw, I mean, we have, in fact, dropped down a couple of those assets in Colombia already into Atlantica. We are progressing well on a number of those solar opportunities in Spain as well, and we'll update you as we make more progress. The other thing I do want to remind you is that none of those projects are part of our $9.4 billion capital plan, so they would be above and beyond.
Your next question comes from the line of Rob Hope from Scotiabank.
Two follow-up questions for me. The first is just on the 2021 capital outlook. The renewable energy at [ 1.4 to 1.75 ] is pretty robust there and over half of -- or around half of the 5-year total spend. Is that just kind of timing of all the investments? Or are you baking in some of your, we'll call it, lower probability or earlier life stage investments there? Or is that really just kind of cleaning up the rest of Maverick, Sugar Creek and Blue Hills?
Rob, so let me try and answer your question, right? So when we were at Investor Day and we showed you that $9.4 billion capital plan, we also showed that really a large portion of that is what we [indiscernible] have already locked and loaded because, as you know, in 2020, that was our largest construction year in our history. We have around 1,600 megawatts of wind and solar projects that was coming into operation.So basically, when you look at it that way, right, I mean, Sugar Creek, for example, that has now recently come online. Our -- acquisition of our Texas coastal wind facility, which is a fairly -- which is, in fact, the largest acquisition on our renewable side, that happened earlier this year.North Fork Ridge came online, and we have some large projects that are also coming online fairly shortly, including -- on the regulator side, you've got Kings Point and Neosho. And then on the renewable side, you've got Maverick and Altavista also coming online.So it's just that a large portion of that 1,600-megawatt construction is really coming online in the first quarter and in the second quarter. And so that's what accounts for the -- a large portion of that capital investment plan happening early in 2021.
All right. That's great color. Appreciate that. And then just as a follow-up. At the Investor Day, you did say that 2021, you could be looking at mandatory equity instruments to fund the capital plan. Is that still the case? And does the -- Texas will weigh on your credit metrics a little bit here. But should we assume that the equity in the plan that you outlined in December is pretty front end loaded here?
Rob, it's Arthur. Yes, I mean, I think you can assume what we laid out at Investor Day holds with respect to our funding plans. And to your question about mandatory, yes, it's a product that we still are looking at. And I mean, as we think about -- we're probably the -- predominance over financing would be, it will probably be through mandatories, but again, we're still evaluating.
Our next question comes from the line of Mark Jarvi from CIBC Capital Markets.
I have follow-up on the last question, Arthur, for you. And just in terms of some of that pressure from the higher commodity costs and the Texas losses potentially, have you guys spoken to the rating agencies in terms of how they would look through this or deal with this in terms of any hit to FFO to debt? And does that push you to maybe reengage on the ATM earlier now?
Mark, yes. No, we obviously have spoken to the rating agencies, and it's still early days. As you know, we're not the only company that's obviously going through this. I think the rating agencies are still evaluating. Obviously, this is transitionary, but it does weigh down on the credit metrics from the top line. So I mean we view our capital plan more on a long-term basis anyway. So I wouldn't look at this as necessarily impacting our capital [ environment ] significantly.
Okay. And then in the fourth quarter, the O&M and cost on utilities had a real material step-up year-over-year and also from the prior quarter. I appreciate that ESSAL and BELCO come into the fold now. Can you maybe break it down in terms of how much of the higher O&M comes from the new assets that have been added in this quarter and then other factors that might have played into the higher OpEx from the utility segment?
Yes. I don't have the exact breakdown for you, but I would say, majority of it is due to the new acquisitions. And I mean, I can just give maybe anecdotally, when you think about seasonality, a utility like BELCO will earn about 70% of the -- earnings will come in the late spring to, call it, early fall months, right? So it is really seasonally shaped here and from that perspective, you may see a bit of an impact from margins.
Sorry, since -- you're saying that maybe top line revenues for BELCO are a little lower, but the fixed operating costs are fairly still flat across the quarters.
That's right.
Your next question comes from the line of Nelson Ng from RBC.
The first question relates to all the development projects you have on the go. So like big picture, how much do you spend or expense on development costs? I know some of your Canadian peers spend anywhere from like $20 million to $100 million. But I'm just wondering where you guys kind of fall within the range.And then secondly, how does that cost get embedded? Is it within your -- is it at the corporate level? Or is it in the renewable energy level? Or -- I know some of it's in Aegis, but can you just give a bit more color on that?
Sure. Maybe I'll -- it's Jeff, Nelson, and I'll take the first question and maybe Arthur can take the second question. But generally speaking, at Investor Day, we did indicate that we would be ramping up our spend on new renewables and [ unveil ] the 3,400-megawatt early stage greenfield pipeline. I believe, at that time, we indicated that there'd be about a $0.02 drag on EPS as a result of those activities. And so that accounts for the majority of that spend.
Okay. So $0.02 per year in general is what we should expect?
That's the incremental cost with respect to all the greenfield development that we're looking at [indiscernible]. And with respect to your question around how development costs get booked through, I mean, obviously, we would want this project to reach a certain feasibility where we start becoming capitalized on our books. But the early-stage projects are undertaken through Aegis, through that development platform. And again, once they reach a specific threshold, those costs are then reimbursed back to development [ to pull through the books ].
So Aegis does the U.S. developments as well as international, like it's all done within Aegis?
It's all done within one combined development shop. That's [indiscernible]. We call them Aegis. Maybe Aegis is not the right word for it, but it's really our one combined development shop. That does it. And those costs just get reimbursed through our results once they actually do achieve a certain [indiscernible].
Okay. Got it. And then my second question relates to weather. So Q4 weather was warmer than usual, and that was a negative impact. Q1, I guess, if you exclude the extreme weather, was probably colder than usual. Like so would that help your utility earnings in Q1?I guess, aside from the fact that you had to pay a lot for commodities, but can you just give some color as to -- like Q4 was warmer and those negative? So Q1 was colder, but obviously, commodity prices are also a lot higher. So what would be the net impact, excluding the -- obviously, excluding the Senate Wind facility?
Yes. Nelson, this is Johnny. I think it's fair to say that so far, 2021 has been a bit of a funny old year so far on the weather front. And actually, if you look at the start of the year, January is actually a much warmer winter than we were expecting. I think it's fair to say that February has been a bit colder.We're interested to see where March plays out. So in some ways, I would say, probably all things considered, it's almost a [ watch ] at the moment. And so not a huge, I think, movement either up or down as you look at the various moves that we've seen in the first couple of months of the quarter.
Your next question comes from the line of Ben Pham from BMO.
I wanted to follow up on some of the questions on the impact on your credit ratings from the Midwest water events. And I understand you're normalizing earnings per share like you shared. But clearly, there's going to be some sort of a cash flow impact.So I'm wondering, really, with your conversations with the credit rating agencies, that $50 million, do you get the sense that they're going to capitalize them in your balance sheet? Or is it going to flow through your FFO? Or they're just going to completely ignore it and normalize it out of their credit metric methodology?
Ben, it's Arthur. It's early days. Like I said, we're probably only one of the few players that are working through this. But I mean, I would just leave it at that to say, I mean, we target -- have a cushion in our metrics for especially things like this. So we're not concerned about being able to absorb it.
Okay. So it just sounds like S&P hasn't decided what they're going to do yet.
They have not decided. We had early discussions with them. I mean they went back and just say, well, how is this going to impact your credit metrics? Full transparency in terms of -- obviously, this will have a full impact, but that full impact is absolutely transitionary. So I guess I'll leave it at that, and I'm sure we'll be watching it closely over the next few weeks here. I'm sure they'll take a position.
Okay. That makes sense. I mean they can be somewhat more [ pressed ], backward-looking in anything. Maybe I can slightly turn to your 2020 guidance. And I just want to make sure I unpack -- or I mean you guys can unpack some of the drivers. On the headwinds, you mentioned the COVID-19 impact, $0.02. There is average resource conditions and then some of the acquisitions were delayed.But then on the other side, you've been able to surface cost savings and the tax benefit, which I think you said, it's about $0.05 or so. So it sounds like it's a wash on both sides. So when you look at your [ missed ] versus beginning of the year, $0.05, I mean, what else am I missing there in the conversation?
I think you've got -- I just don't think it was a full-on wash. I mean, the big impact here was COVID, was weather, but also obviously, the delay in the acquisition. As I mentioned earlier, there's a pretty significant seasonality that transpires with our BELCO utility. So we've closed it, call it, probably the worst time you can close it during the year, but -- so that's certainly weighing on our results.
Your next question comes from the line of Richard Sunderland from JPMorgan.
I just wanted to circle back to the incremental commodity costs you outlined at the start of the Q&A. But $200 million, are you able to break that down by jurisdiction and utility?
Yes. So pretty much the majority of that is through our Empire utility in Central. Most of our other utilities are on the coast and really didn't get hit so far. It's up -- because utility by some way. So it's a mixture of increased natural gas costs for running our gas generation fleet and then some incremental costs on the electricity side to serve our load.
Okay. Got it. And then thinking around recovery at a higher level, could you run through maybe some offsets to the cost here? And are you simply thinking about amortization period? Or are there other considerations in terms of the recovery dynamics?I'm thinking in 2 parts, kind of the Asbury plant recovery could potentially impact as well and the sort of the PISA dynamics at large. So I know I thrown out some kind of different levers there, but just curious how you see the path forward to recovering.
Yes. So certainly, in terms of these gas and electricity prices, we have an approved and well-established process through our fuel and purchase power adjustment tools or FAT. We file that twice a year on a 6-monthly basis. And in the normal course of business, as you file that, you then have a 6-month recovery period that follows that.Because of the material nature of these incremental costs, we filed with the commission an AAO, an accounting order, that will allow us to put those costs onto the balance sheet and then have a conversation with the commission around actually what's the right period of time for us to recover those costs in a way that makes sense for us the business, but importantly, makes sense for our customers.You could imagine, this would have a material rate drop, really not the best time for them. And so we still have those conversations with the commission. But in terms of sort of the process of prudent recovery though, it's well established and approved and documented already.
Got it. And just one last one, if I could. Just any dates or timing to watch in terms of those conversations with the commission?
So it should be between now and April. So our fuel adjustment filing is due on the 3rd of April. So we'll be having those conversations early in the next month to agree on the best way to handle the AAO.
Your final question today comes from the line of Naji Baydoun from IA Capital Markets.
Just wanted to go back to M&A for a second. I guess, in a worst-case scenario where the New York Water acquisition doesn't go through, just wondering if you can talk about your pipeline of acquisitions today and how quickly you can take that capital and reinvest it somewhere else?
Sure. So Naji, as you know, historically, we've been a fairly transaction-oriented company. So we have done something in the range of 20 transactions over the last 20 years or so. We -- because of that experience and because of our track record of being able to close our transactions, we're always in a mix in terms of discussions around these transactions, whether it be in the public realm or not.So that's something that we cannot actually pinpoint as to exactly when those transactions might happen or if. And that's why, as a matter of course, we only include on our 5-year capital plan the M&A transactions that we've already announced, that may not have closed. So that's why New York American Water is the only one on a 5-year trajectory.To your point, worst case, New York American Water doesn't close. We will be able to do another transaction. I mean, over -- we just started our 5-year plan. And obviously, we've got 4 years, 10 months more to go. So I would be highly confident in our ability to do more M&A transactions.
I appreciate that timing is difficult, but it sounds like you're confident that you can find other opportunities fairly quickly. I guess, another question is, are there any updates to the Empire rate case, either the appeal process or just any updates we should be aware of on the new rate case that you expect to file?
I don't think any material update. The appeal process is ongoing, could take up to a year for that to come through. And we're preparing to file on a case in Missouri later on this year.
Okay. And just one last question on the Chevron framework agreement. Just any updates or I guess, next steps that you're looking to achieve this year with Chevron?
Sure. So Naji, as a reminder, I mean, we announced that some time in the middle of 2020. And so what we have done since that time is, we have, in fact, done some joint procurement work to make sure we have a safe harbor equipment with us. We have also filed 4 interconnection [ key ] applications. So those are well underway.And we are working through in terms of contractual structures and starting a detailed engineering design on those projects. So we are making good progress. We're happy with the pace of progress we're making. And so the question is, when will we actually be able to announce something that starts construction. We're hopeful sometime this year.
That concludes our Q&A today. I'll now turn back to management for closing remarks.
Thank you very much, and thank you 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 future earnings and capital expenditures, future commercial dates and the impacts and outcomes of the recent severe winter storms in Texas and the Central U.S.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 earnings per share or adjusted net EPS, adjusted EBITDA, adjusted funds from operations and divisionaäl operating profit. There is no standardized measure of such non-GAAP financial metrics. And consequently, AQS method of calculating these measures may differ from methods used by other companies, and therefore, they may not be comparable with 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 the conference call.
Thank you, everybody, for joining today. That concludes your conference call. You may now disconnect.