Fortis Inc. (FTS) Q3 2021 Earnings Report, Transcript and Summary

Ladies and gentlemen, thank you for standing by. My name is Phyllis, and I will be your conference operator today. Welcome to the Fortis Q3 2021 Results and New Year Five Year Capital Outlook Conference Call and Webcast. [Operator Instructions] At this time, I would like to turn the conference over to Stephanie Amaimo. Please go ahead, Ms. Amaimo.

Thanks Phyllis, and good morning, everyone, and welcome to Fortis' Third Quarter 2021 Results and New Five Year Capital Outlook Conference Call. I'm joined by David Hutchens, President and CEO; Jocelyn Perry, Executive VP and CFO; other members of the senior management team as well as CEOs from certain subsidiaries. Before we begin today's call, I want to remind you that the discussion will include forward-looking information, which is subject to the cautionary statement contained in the supporting slide show. Actual results can differ materially from the forecast projections included in the forward-looking information presented today. All non-GAAP financial measures referenced in our prepared remarks are reconciled to the related U.S. GAAP financial measures in our third quarter 2021 MD&A. Also, unless otherwise specified, all financial information reference is in Canadian dollars. With that, I will turn the call over to David.

Thank you and good morning, everyone. Today we are pleased to report our third quarter results as we continue to deliver safe and reliable service while navigating through the pandemic. Financially, our third quarter results reflect strong core operations moderated by a lower foreign exchange rate and cooler than normal weather in Arizona. On a year-to-date basis, we have delivered strong earnings growth absent Foreign exchange. We are on track to deliver our $3.8 billion capital plan for 2021 with $2.6 billion invested through September. Additionally, we recently announced a dividend increase of approximately 6% marking 48 consecutive years of dividend increases, a record we are very proud of. Before getting into our new five year plan, I'd like to discuss the recent executive leadership developments here at Fortis. Last month, we announced the Jim Laurito will retire at the end of the year from his role as Executive Vice President of Business Development, and Chief Technology Officer. Many of you know Jim as he has been working in our industry for many years. Jim, we appreciate your immense contributions to Fortis, and wish you and Vinita all the best in retirement. And on a personal note, Jim, I'd like to express my sincere gratitude for the guidance, advice and friendship that you have given me over these last seven years. Also, we announced the appointment of Stuart Lochray, Senior Vice President of Capital Markets and Business Development. We welcome Stuart to the Fortis' family in the third quarter, and look forward to his support and building on the momentum across our businesses to execute on our growth strategy. Turning now to Slide 5, our new five year plan calls for the investment of approximately $20 billion from 2022 through 2026, showing our ability once again to extend our strong underlying organic growth. This balanced low risk plan is expected to translate into average annual rate base growth of approximately 6%. Our plan shows we've come a long way since October of 2016, when Fortis' acquired ITC and was first listed on the New York Stock Exchange. After that transaction closed, we rolled out a five year capital plan of $13 billion for 2017 through 2021. Well, that seemed ambitious at the time; we're now on track to invest approximately $18 billion in additional $5 billion over that same period, translated into rate base growth of $8 billion or 6% on average annually. The new capital plan invests in our energy infrastructure and supports a cleaner energy future and includes $1 billion of incremental investments at our regulated utilities. Drivers of the increase include customer growth, enhancements to transmission reliability and capacity, and investments in cleaner energy. This growth and capital is reduced by a lower assumed exchange rate, which decreases the plan by approximately $600 million. The new plan is highly executable with approximately 85% consisting of relatively small projects. The remainder consists of what we define as major capital projects, those exceeding $200 million, or just 1% of the five year capital plan. Our plan includes 11 such projects, including the $200 million Okanagan Capacity Upgrade project at FortisBC that will address customer growth in the region through expansion of the existing natural gas transmission system. As the pie chart on the left hand side of slide 8 highlights nearly all of our new capital plan supports energy delivery, and the transition to a cleaner energy future. Our utilities are planning for cleaner energy investments of $3.8 billion through 2026, a $500 million increase compared to our prior plan. This increase is driven mainly by additional renewables and energy storage in Arizona, and renewable interconnections at ITC. In Arizona Tucson Electric Power expects to invest in 275 megawatts of energy storage and another 90 megawatts of solar projects to support its integrated resource plan and exit coal by 2032. ITC plans to invest in transmission to interconnect renewables, including 2,800 megawatts of generator interconnections in the US Midwest, and in multi value projects. At our Western Canadian Electric and Gas utilities, clean energy initiatives include renewable and liquefied natural gas investments in British Columbia, and distributed energy resource integration investments in Alberta. Investments in the Wataynikaneyap Transmission Power Project in Ontario, and alternative energy technologies and battery investments in the Caribbean also support our sustainability strategy. Our carbon emissions reduction target is on track as we reduce emissions by nearly 2 million tonnes in 2020. With our continued investment in cleaner energy infrastructure, the planned closure of the San Juan Generating Station next year and the beginning of seasonal operations at Springville Generating Station, we are well on the path to meet our 75% carbon emissions reduction target by 2035. Our target is balanced and ensures reliable and affordable service while providing time and support for impacted communities. By 2035 we expect 99% of our assets will be related to energy delivery and renewable carbon free generation. Beyond reducing Scope 1 emissions all of our utilities are focused on improving their environmental footprint, including their scope two and three missions to investments in RNG and LNG, renewable interconnections, electric vehicles, energy efficiency initiatives, and other efforts, we are working to reduce economy wide greenhouse gas emissions. In addition to improving our already low carbon footprint, the capital plan also supports steady rate base growth across our portfolio of utilities. Central Hudson continues to lead the way with average annual rate base growth of over 7% driven by investments in infrastructure upgrades, and information technology. Our consolidated rate base growth will be mainly driven by our three largest utilities, ITC, Fortis BC, and UNS Energy. The plan is expected to increase rate base by $10 billion from approximately $31 billion in 2021, to nearly $42 billion in 2026, supporting an average annual rate base growth of approximately 6% through 2026. We have many other opportunities that could expand and extend growth at our regulated utilities which are not reflected in our capital plan today. As we have previously discussed, ITC is strategically positioned in the Midwest to invest in incremental transmission required to support a renewable energy transition in the United States. The Lake Erie Connector transmission project and the MISO long range transmission plan could be large additions to our plan, and we expect to have additional clarity on these opportunities early next year. In Arizona, Tucson Electric Power's integrated resource plan will require investments in renewables and battery storage beyond 2026 in order to exit its coal generation in 2032. At FortisBC, reducing customer greenhouse gas emissions continues to be a priority. Whether it's LNG, renewable natural gas or hydrogen, the infrastructure needed to support a decarbonized economy will complement our organic growth strategy and support clean BCs roadmap to reduce customer greenhouse gas emissions. In light of these opportunities, as well as the potential acceleration of a clean energy transition in North America, we remain optimistic that we will be able to secure investments that will be additive to our current plan. Next, I'll spend a moment discussing recent increases in commodity prices and supply chain considerations given the impacts of the pandemic are having on the economy. First, we are seeing increases in natural gas prices, which are impacting our utilities in British Columbia, Arizona and New York. While hedging policies and recovery mechanisms for these costs vary by regulatory jurisdiction, they're ultimately recovered from customers. This is expected to increase our customers' rates while these higher costs persist. As prices moderate the same mechanisms will allow those rates to decrease. We remain focused on mitigating customer bill impacts through energy efficiency and conservation programs wherever possible. We will also continue our efforts to manage costs across our enterprise through innovation and process improvements to maintain affordable service to the communities we serve. As it relates to the supply chain, our Fortis operating group is focused on proactively managing our supply requirements, with coordinated buying, and utilizing supplier alliances to maintain reliable service and ensure the execution of our capital plan. Notably to date, we have had only minor supply chain concerns. However, we are currently doubling down on our supply chain efforts to be ready for 2022 and beyond. Due to the length of our planning cycle and the long-term nature of our capital plan, the recent price increases for commodities such as steel and copper are not fully reflected in our five year plan. We will be evaluating these impacts going forward. As I mentioned last month, our Board of Directors declared a fourth quarter dividend of $0.535, representing an increase of approximately 6%. Again, this marks 48 consecutive years of dividend increases. The strength of our local energy delivery businesses coupled with our diverse, geographic and regulatory footprint positions as well to extend this record. And to that end today, we are reaffirming our 6% average annual dividend growth through 2025. Now we will turn the call over to Jocelyn for an update on our third quarter financial results.

Thank you, David and good morning everyone. Turning to Slide 15 reported earnings per common share for the quarter was $0.63 consistent with the third quarter of 2020. Adjusted earnings per common share were $0.64, $0.01 lower than the third quarter of 2020. During the quarter, cooler weather in Arizona tampered earnings by $0.05, while a lower foreign exchange rate lowered EPS by $0.03. Excluding these impacts our regulated utilities delivered strong results driven by rate base growth, new customer rates at TEP and higher earnings at ITC, FortisAlberta and in the Caribbean. For the nine months ended September 2021, adjusted EPS was $1.96 per common share, $0.08 higher than the same period in 2020. And this growth was despite the FX impact of $0.10 year-to-date. Before getting into the specific drivers of the quarterly and year-to-date earnings results, I want to touch on the recent sales trends across our utilities. And similar to the previous trends we discussed last quarter, we continue to see an increase in the commercial and industrial sales and lower residential sales. Notably commercial and industrial sales increased 6% for the quarter. Lower residential sales were associated with decrease in work from home practices and cooler weather in Arizona. And this was partially offset by warmer than normal weather in Alberta. Taking a further look at Arizona, retail sales were down in the quarter by approximately 8% compared to the same period in 2020 due to cooler temperatures, which reduced air conditioning load in the region, equating to a $0.05 EPS impact. As you can see on the slide during the third quarter of 2022 Tucson recorded the hottest month on record. Absent weather impacts retail sales in Tucson were down 1% driven by lower residential sales, reflecting changes in work from home practices, partially offset by higher commercial and industrial sales. Slide 18 highlights EPS drivers for the quarter by segment. At ITC rate base growth and an adjustment related to interest rate swaps contributed to a $0.05 increase in EPS. Our Western Canadian regulated utilities contributed a $0.03 EPS increase for the quarter driven by weight based growth, as well as higher sales due to favorable weather and the timing of expenditures in Alberta. At our other electric segment, EPS increased by $0.01 driven by higher sales in the Caribbean due to the continued recovery of the tourism industry. And at our US Electric and Gas utilities EPS decreased $0.03 in the quarter. $0.01 was driven by lower earnings in Arizona due to the cooler weather I discussed earlier. And this decrease was partially offset by the impact of new customer rates at TEP effective January 1, 2021. In New York, Central Hudson decreased EPS by $0.02 mainly driven by the timing of its pending rate decision, a decision is expected to be concluded in the fourth quarter, and once the outcome is finalized earnings associated with the delay is expected to be recognized. At our Energy Infrastructure segment, EPS decreased $0.3, mainly due to realize losses on natural gas contracts at a contract were settled during the quarter of 2021 in consideration of market conditions and favorable forward curves. Higher weighted average shares outstanding issued through the dividend reinvestment plan decreased EPS by $0.01 and the US dollar to Canadian dollar exchange rate of $1.26 for the quarter compared to $1.33 for the third quarter of 2020. And this unfavorably impacts the quarterly results by $0.03. Turning to Slide 19, this waterfall breaks down the EPS drivers year-to-date through September. And to not repeat myself, the EPS drivers for year-to-date largely reflect the same factors discussed for the quarter by segment, except that on a year-to-date bases earnings were higher in Arizona, due to new customer rates at TEP partially offset by lower sales due to cooler weather and higher operating costs. All-in-all, our utilities have delivered strong underlying earnings growth year-to-date at some foreign exchange. Turning now to our funding plan. The new five year capital plan is expected to be funded with cash from operations, debt issued at our regulated utilities and our dividend reinvestment plan. With no discrete equity required to fund the capital plan through 2026. The funding plan is largely consistent with last year's plan and our capital structure is expected to remain steady over the planning period. Overall, we continue to take conservative approach to running our business and our funding plan positions us comfortably within our existing credit ratings through 2026. In particular, Moody's CFO to debt metric is expected to average 12% through 2026. And S&P's FFO to debt is expected to average above 11%. Both Moody's and S&P metrics are above their respective thresholds and provide ample cushion to maintain our current ratings. Turning to recent regulatory developments, first ITC awaits a final rule from FERC in relation to the supplemental notice of proposed rulemaking on transmission incentives, which proposes to eliminate the 50 basis points RTO early incentives. Although any potential impact remains uncertain every 10 basis points change in ROE at ITC impacts Fortis' annual EPS by approximately $0.01 and would be applied prospectively. Next month FERC will hold a technical conference in connection with the advanced notice of proposed rulemaking issued in July 2021, focusing on regional transmission planning, cost allocation and generator interconnection processes. This progress is positive and underscores the important role transmission plays in achieving the Biden administration's climate goals. At Tucson Electric Power, you may recall that in 2019, FERC issued an order accepting formula transmission rates as filed, including an ROE of 10.4% and equity thickness of 54%, subject to refund and Settlement Procedures. A settlement in principle was reached in August 2021. And the procedural schedule was suspended to allow the settlement to be finalized. The timeline and outcome of this proceeding remains unknown. In New York, Central Hudson filed a joint proposal in August, seeking a three year rate plan effective July 1, 2021. The proposal includes an ROE of 9%, and an equity layer of 50%, declining by 1% annually to 48% in this third rate year. The proposal also reflects the use of existing regulatory balances and other measures to reduce bill impacts as well as initiatives to support the state's climate goals. An order from the New York Public Service Commission is expected in the fourth quarter of this year. And that concludes my remarks. I'll now turn the call back to David.

Thank you, Jocelyn. So why invest in Fortis? It's simple. With the strength of our utilities and local business model, we offer long term low risk diversified growth, as demonstrated by our new five year capital plan, a plan that supports our dividend growth guidance through 2025. We remain optimistic about the path ahead as we pursue incremental growth opportunities that will allow us to deliver a cleaner energy future for all our stakeholders. I will now turn the call back over to Stephanie.

Thank you, David. This concludes the presentation. At this time, we'd like to open the call to address questions from the investment community.

[Operator Instructions] Your first question comes from the line of Maurice Choy with RBC Capital Markets.

Thanks and Good morning. My first question is to just pick up on the 6% rate base growth you've announced, any thoughts on what this rate base growth may translate to in terms of EPS growth and taking this a step further, have you seen a change in your ability to achieve a similar 6% in translation versus say in the past and has it really change? What has changed?

Yes, thanks, Maurice and good morning. Good to hear from you again. As you know, we don't give earnings guidance and we obviously give rate based guidance as a proxy to somewhat and of course on a longer term basis we would expect rate based growth and earnings guidance to converge obviously in a business like ours where we have different regulatory cycles and ups and downs, et cetera and investment. It's not linear, but on a longer term basis. I mean that's what we would all expect.

Thank you. And my second question is on the dividend growth guidance, you reaffirm your growth guidance, which takes you to 2025. Traditionally, we've seen you extend this guidance in lockstep with the length of your capital plan. Is it a case of maintaining flexibility in out year? Or is that something else that motivated this decision?

Thanks, Maurice, you answered the question yourself. But four years is still a long time to be given dividend guidance. And we wanted to make sure that we were reaffirming the guidance that we had put out there. And keeping that and obviously showing a plan that supports that which is key. And that, of course, paired with our track record of hitting that, I think is the right spot to be in. But as we see in essence, a $0.5 trillion of additional investment opportunity and government support in the US related to the budget reconciliation bill, we think that there's going to be a lot of opportunities in the tail end of our five year plan, as we mentioned, I mentioned some of them, but there's this big bucket of what is all these additional investments means, does it drive for a faster clean energy transition in the US translate into additional investments for us? And we think that answer is yes. But we have to see how that trickles down over time. So we'd like to maintain some flexibility in the tail end of our five year forecast to be able to address that.

Thanks. And maybe just a quick follow up and just a tied at first and second question together then if you expect over the long term for EPS and rate based growth to converge, and in this case, you're hoping to have flexibility on the dividend out a year. Is there a target dividend payout ratio that in your mind you're looking at to balance all these positions?

Not really, Maurice. I mean these are conversations we have every year with our board of directors to base on the situation in that year and how we see things on a going forward basis. So yes, we don't have a target in mind as we sit here today.

Our next question comes from the line of Ben Pham with BMO.

Hi, thanks, good morning. First question on the quarter specifically, do you expect any of your segment results in Q3 versus to Q4, whether positive or negative, or do you expect that's mostly flowing to realize ROE?

Yes, the question I'll kick over to Jocelyn, it is breaking up a little bit there. But whether or not we see any earnings timing between Q3 and Q4, do we expect any of those to reverse?

Hi, Ben, thanks for the question. Yes, we do have some timing. We reference Central Hudson's rate case. Clearly, that's a deferral of earnings that we expect that we would have originally expected in Q3 because new rates were to be effective July 1, but now that's moved to Q4. We did have some timing of some costs also, in Alberta, that we did move earnings to Q3 versus Q4. But outside of that, no major other timing variances that we see between the quarters.

Okay, great. And site, the -- your comments were on the commodity price situation not being reflected in your base plan. Should we read that as more there's a flow through upside here, your CapEx if you start to bake that in or is it more reflected that it could tamper your growth outlook with the rising prices on the commodity side?

Well, Ben, we have a base capital plan. That's real projects. So if those projects have higher costs, then those costs would be built into that capital and would end up getting passed through as higher costs and capital costs, et cetera on a going forward basis to customers through rates. So we do have to pay attention very closely to control those costs because we want to make sure we're getting the most bangs for the invested buck for our customers. But at the end of the day, it wouldn't drop out capital projects it would just increase the cost of them, which makes us really focus on across our entire footprint and every one of our subsidiaries, to focus on other cost reductions that we can do for our customers to help them manage the bill impact. Now a lot of these things that you have to remember from a capital perspective, a lot of these projects don't necessarily add to customer rates just for an example, in Arizona, when we are shutting down our coal plants and replacing them with solar and battery storage, that actually saves our customers money. So there's some of that in there as well.

Okay, great. And maybe last, if I may, acquisitions, would love your updated comments on that, as you rolled over to CapEx program, whether large scale or smaller scale.

Updated on what? I missed the questions and updated on them --

Yes, love to hear your thoughts on appetite for M&A as you've gone through your budgeting process and look that upside to the plan down side to the plan. And I know you've communicated [Indiscernible] in the past, but would want to hear if you've maintained your past views or a slight change in appetite?

Yes, it'll probably sound really familiar. I mean, this is a big capital plan, is a big deal to get the $20 billion capital plan put together, it'll be a big deal to execute it. But we're not resting on our laurels and saying $20 billion capital plan is enough. So we're going to be out shaking the bushes looking for additional investment opportunities that are right for our customers and our stakeholders and our shareholders. So we will continue to keep that as our number one focus. That doesn't mean we're sitting here asleep at the switch, and not paying attention to things that are going on in the market and looking for opportunities that can add value for our shareholders as well. So we will continue to be good fiduciaries looking for opportunities to define value, even outside the capital plan for our company, like we always have been.

Our next question comes from the line of Linda Ezergailis with TD Securities.

Thank you. I'm wondering as you look at those opportunities as there, what sort of guardrails are you imposing on your world of possibilities as it relates to geography, technologies, commercial attributes, and specifically interested to hear whether you see any initiatives around hydrogen of whatever color or attributes or carbon capture, as within the range of possibilities and how they might manifest itself in leveraging your competencies in your existing footprint?

Yes, Linda, we don't really have any guardrails around the looking at some of these investment opportunities, because we are going to probably cast a pretty wide net, but they have to fit within our risk return profile, right. So if we're going to do an investment, it has to look like a lot like a regulated investment always looked for to us. So whether it's looking at things like hydrogen or carbon capture, utilization, storage, and each one of our jurisdictions has different pieces that they're looking at, for some of these new technologies out in British Columbia, renewable natural gas, hydrogen opportunities, that's where we're going to probably be looking at that and testing the water. But if the investments don't meet our risk return appetite, then we won't do them. But we don't have any really guardrails on those types of investments that we don't start with any guardrails on that. We want to -- we have got a great sustainability picture as we sit here today with 93% of our assets being T&D. And we will always be having the back of our mind the fit on investments and how that impacts or affects our ESG profile as well.

Okay, thank you. And maybe just some thoughts around when you are considering new projects or opportunities, how you might approach the financing part of the equation. In the past you have looked at partners for various reasons. Those tended to not have come to the top of the list. Now you might have some like sustainability, financing linked opportunities as well. Can you just talk about how you think you might approach financing any additional opportunities?

Thanks, Linda. This is Jocelyn. Yes, I think with additional capital, above and beyond the base plan, I've said this before. And this may also sound like an old story, but everything goes on the table, we have used partners, we typically like to do it ourselves. But we have used partners depends on the size of the project, you're absolutely correct that you're going to see more sustainability, linked financings associated with our investments, because the investments are unlikely to be in the space of the green energy investments with what's happening, particularly in the US. But at a very high level, everything goes back on the table, because it depends on the amount of growth and the timing of growth. We will look at everything from asset sales to equity to partners, and everything in between. So I think everything goes back on the table.

Okay, thank you. And just as a follow up, given the expectation that interest rates might be going up. How might you think about potentially pre funding, taking a more conservative approach to kind of lock in any sort of financing costs associated with the capital spend that you're certain will come?

Yes, Linda, thank you. You've hit it. We did the same thing in 2020, as well, when COVID hit we advanced a lot of financing. So I know what across the organization, now we are looking at all of our financing where it's appropriate to do interest rate locked or whether it's appropriate to advance so all of our subs are looking at this. Most of our financings are within the regulated utilities, as you would know. And then some of those utilities, we do have mechanisms whereby the interest cost or rising interest costs are actually included in regulatory deferral mechanisms or a part of the PBR structure were shared with customers. But yes, it is something that we'll always looking at and advancing financings and certainly one of the options.

Our next question comes from the line of Rob Hope with Scotiabank.

Good morning, everyone, just want to first focus on kind of some of the potential additions to the capital plan. Lake Erie Connector the government is kind of looking at that plan, can you maybe comment on kind of your discussions with offtakers there as well as kind of what next steps and when that could be put in the capital plan?

Yes, there's only one offtaker, and that is the MISO. So that that's the contract negotiations that we are currently in the midst of, there's not really much to tell you in the middle of the contract negotiations, obviously, turn in term sheets back and forth and trying to come to the agreement of the deal structure. We do expect, in the end, the Minister of Energy in Ontario is requesting that report back it by the end of this year. So we are going as fast as we can to make sure we get that done by the end of the year and get that report back to the Minister.

Alright, that's helpful. And then just taking a look at FortisBC we saw some CapEx move in this plan, can you kind of give us an update on some of the larger opportunities there including additional LNG as well as kind of the Woodfibre project connection and where these all stand?

Yes, certainly, I'm actually going to turn that one over to Roger Dall'Antonia, who's the CEO of VC and he's on the line. Roger, do you want to address that?

Yes, good morning, everyone. Thanks for the question, Rob. So Woodfibre, continuing to work closely with Woodfibre, they are looking to make FID here potentially as early as late as the end of the year. So progressing that project and nothing materially new on the expectation that we later I think last quarter, as far as other opportunity, focus for us is LNG bunkering right now working closely with proponents and the government on the EA process on the Tilbury marine jetty, and once that is in hand, we would look to an expansion of the opportunity for LNG bunkering.

Our next question comes from the line of Michael Sullivan with Wolfe Research.

Hey, everyone. Good morning. My first question was just can we get a little more of an update on the latest expectations for timing around the MISO long range transmission plan? And any additional color on expectations there?

Yes, the timing is slipped as I think we were kind of radio earlier this year that it was going to be quite a feat to get those projects in front of the board before the end of the year. And indeed, now MISO is publicly saying that that study, basically the first mover project should be out in February of 2022, with the hope of getting those before the MISO Board for approval in March of 2022. So it has slid, which is we want to hear the outcome of that probably more than anyone else. And as soon as we hear it, we'll make sure that we get that out to you all as well.

Okay, great. Thanks. And my second question was just can you quantify the earnings pickup that we should expect from the New York rate order in Q4, if it's settlements approved as is and as a follow on to that just remind us how that addressed COVID in New York, and any potential recovery there?

Michael, this is Jocelyn. I would say a couple of pennies, $0.02 that you'll see a pick up from what should have probably been recorded earlier rather than later. So you'll see that pick up in Q4.

And then on the details around the pieces that are included in the settlement from COVID perspective, the other half of your question, Charlie, you want to provide any color on that.

So in relation to COVID, a couple of things were addressed for Central Hudson, even though the generic proceeding in New York continues. So for Central Hudson, part of our revenue requirement comes through finance charges. And obviously, finance charges have been put on hold throughout COVID. So we did get treatment related to the loss revenue associated with finance charges. And we also, were able to get deferral treatment for bad debts as well. So both of those are elements that are part of the generic proceeding, but were addressed directly in our settlement discussions.

Our next question comes from the line of Mark Jarvi with CIBC Capital Markets.

Thanks. Good morning, everyone. I want to come back to investments like the Lake Erie Connector project or something -- that you do down the road like that, that might not be rate base. How would you think to frame that in terms of growth and impacts? If it's not any rate base and your hesitation to provide EPS growth?

Yes, I think, well, the way that you should think of that is it should look like a kind of a rate based asset. I mean, it's basically what we're trying to do is make this look like a contracted asset that mimics rate base. So obviously, the levels of return on equity, all of that stuff are part of the negotiation. So we can't give you that level of detail now. But that's how we're viewing it. And that's how you should view it as well.

So if you were to sign document on that agreement, you would kind of quote unquote, put it in as sort rate base spending in your go forecast.

Would we put it in as rate base in our capital forecast? No, it wouldn't, it would be in the capital, but not in the rate base, the number.

Got it, okay. And then obviously, there are a lot of headlines around Arizona, around another utility in the state, maybe you can take this opportunity kind of give us your updated view on contracts, compare how you guys see yourself position versus APS, obviously you've already done your rate case, but sort of updated view given all the headlines going on there.

Mark, I'm glad you asked. I'm amazed that this question fell so far down the queue. I thought it was on everybody's mind, given some of the analysis around the case. That APS' case recently. And I'll start out by saying this is definitely a utility specific situation. This isn't a systemic issue or problem from a regulatory perspective in the state of Arizona. And I think if you listened and you probably did it, as I did, listen to some of the hearing, I think you'll see that's how these issues are being addressed and the rhetoric around them from the Commission is a utility specific situation. Now, you and us and the utilities that we have in Arizona, have a very good working relationship with the Commission. We do every thing that we possibly can to make sure that we build the trust with our regulators and we do that through making sure that we're transparent. And we have integrity with when we with everything and every interaction that we have with that commission. That's been RMO. I've been testifying in front of that commission for almost 20 years, I can tell you that we make sure that we had, we always do the things because we know that we got to do the things that maintain that trust, because we know as hard as it is to build that it can go away pretty quickly. And I think the most important part of our business structure from a Florida's perspective is the fact that we have a business model that has the people on the ground in our jurisdictions, managing these relationships, that's absolutely critical to make sure that we maintain them and know exactly where those regulatory outcomes are going to come. And speaking of regulatory outcomes, you mentioned that this was just, I can't believe it was less than a year ago. So less than a year ago, in December of 2020, we actually got a very constructive rate outcome from the corporation commission 40P. And that I think is indication, nothing, it was in the middle of COVID, we're still in the middle of COVID. There are not a lot of things that are different. But we obviously got quite a bit different treatment and quite a bit different outcome than what you're seeing. So I guess that's a long way of saying that the situation there shouldn't be projected through to other utilities in the state, including ours.

Got it. Thanks for those comments. And then just coming back to supply chain question and rising CapEx costs. Can you just remind us again like on the PBR base utilities like West Canada, I assume that there's capital trackers and things to manage that, is it just a utility to the historical test year, whether it be regulatory lag, where you might feel a bit of a temporary pressure from higher CapEx costs, and can you kind comment on some of the things sort of the transient impacts on that.

Yes, that would be -- yes, you hit the nail on the head there, the Western Canadian utilities at PBR. They actually have inflation built into their rates as well, capital trackers, et cetera. ITC has a full retest here. So that gets that all gets trued up. So, yes, it's really probably only Arizona that would see a little bit of a drag on increased costs from an O&M and capital perspective.

And Central Hudson?

Central Hudson, Charlie, I have to say that's the rate structure, I don't know quite as well as the rest, Charlie; you want to opine on that.

So we have a proof capital budgets and net plan targets within our rate structure. So if we experience higher costs, what it would typically do is not go, it would not increase our capital budget in a particular year. But it would really kind of extend out a project over longer periods of times, because it may displace another project in order to cover those costs.

Our next question comes from the line of Andrew Kuske with Credit Suisse.

Thank you. Good morning. Probably a question to start off with David. And it's really about your, I guess, your last home state in the US in Arizona, and there UNSU as a standalone and really under the Fortis umbrella, not really impacted by a lot of the regulatory noise. And I guess it's a bigger, broader question, just from a regulatory philosophy. What's your thought on jurisdictional concentration, where you're the only utility in a region versus having we could call it a foil a competitor or comparable, within a certain jurisdiction that you can effectively play off as you've done in Arizona over the years?

Yes, Andrew, that's an interesting question. I think really, we don't really look necessarily to have a foil or hide behind other utilities; we just want to be the best utility that we can be and let our record and the transparency that we give to our regulator stand on its own and create that relationship. So we're not necessarily looking for a foil as it were. We just -- we are focused on doing regulation right. We're focused on having that relationship, again, with the regulators and making sure that we stay on site and everything that we do, there's a lot of competing interests that show up in a regulatory proceeding. And we want to make sure that we have those relationships, not just built around the -- or with a commission, but around all of those stakeholders. And I think a great example of that is the process that we went through down in Arizona to get the integrated resource plan done, and it was that broad state holder process that brought everyone together that's the kind of atmosphere that regulators are looking for these days. They have, obviously agendas, they have plans and policies they want to implement. And we got to show up and help them implement those policies.

Good. That's helpful color and context. And I guess the next question. It's along the lines of regulation. But it's probably also more directed towards Roger, and it's really just on RNG. And obviously, it's been, it's important. It's a small part of the overall business. But if you could just give us some color and context on the just your R&D activities in BC and really beyond.

Yes, Roger, you want to take that?

Yes, thanks, Andrew. So the RNG story is developing quite nicely in BC. Back in this summer, the BC government amended the greenhouse gas regulation around R&D, so we had previously a 5% renewable portfolio allowance, if you will. And that got moved to 15% and included additional renewable gases such as green hydrogen, lignin based fuels from the forestry industry. So we started, we announced our three by three, which included 15% of our natural gas portfolio coming from renewable gases by 2030, we're probably a third of the way there with signed contracts, I think we're just under just over eight petajoules, approved by the BCUC, we have a couple more contracts that we still have to file. So we're approaching 10 petajoules, in about first two years of announcing our plans to increase RNG. So we're well on track to get to the target we set for ourselves in 2030. BC government just announced clean BC, which is a very ambitious plan on carbon reduction. So we expect further opportunities on the R&D front to come.

And if I can maybe just one follow up on that. And Roger, how broad based are your procurement activities? Because we talked to a number of utilities that increasingly have RNG goals and aspirations, but there's only so much of it out there. So how broad based are your acquisition activities at the stage?

Right now we're signing for current deals across North America. So we've got I think, now, two contracts approved from US projects; we have a handful of contracts approved outside of BC, Alberta and Ontario. So we're really looking at R&D from a North American grid perspective, anything that we can tie into the grid that can be delivered to BC is what we're pursuing. So we have a pretty big footprint. Your comment on more utilities, chasing RNG I think is a fair one. It's why hydrogen over time will become an increasingly important part of the next; it won't simply just be the landfill. Waste water treatment plants or agricultural, that'll still be important, but I think hydrogen, blue, green or otherwise will be an increasing part of the real gas mix.

Our next question comes from the line of David Quezada with Raymond James.

Thanks, good morning, everyone. So my first question here just on the topic of inter regional transmission planning, as it relates, I guess, to IPC, I understand FERC has had some discussion with the industry on the right, for right of first refusal for incumbent utilities. There's been some discussion around that as well as potential requirements for more in depth, I guess, inter regional transmission planning, just curious how those concepts, how you see them developing and how that could affect things that ITC maybe in the longer term?

Yes. Thanks for that, David, for that question, David. I'll turn that over to Linda to address.

Great. Thank you. And good morning. Thanks David, for the question. Yes look, I think it's hard to specifically know or understand how FERC will specifically address the ROFR issue. I can tell you that it's definitely on their radar screen. I think there was significant amount of comments that were made around the ROFR as it should say competitive, the competitive provisions border 1,000. In the a no for comments that were filed, I mean, there have been some comments made by various [Indiscernible] over various points in time they have indicated that they also believe that those competitive provisions of order 1000 have stood in the way of realizing sort of these regional transmission projects. So, from our perspective at ITC we have actively been pursuing ROFR legislation in our various states. We have brokers in Iowa, we have a ROFR in Minnesota, and we are in the process of pursuing along with other utilities, a ROFR in Michigan. So to the extent that we can reinstate the right of first refusal in our footprints, it certainly would protect us in terms of any future regional transmission projects. But I do think FERC needs to address the issue more holistically. Because I think right now, approximately half of the states in the US are covered under kind of ROFRs are the competitive provisions don't apply, because their members are not in an RTO. So it's not a holistic proposal, the way at least it's currently structured. And we're hopeful that FERC understands that these competitive provisions have really stood in the way of realizing the needed investment and transmission to facilitate sort of the new green economy.

That's great color. Thank you for that, Linda. And then maybe just one other one for me. I thought comment, I guess in the presentation about IPP interconnections in Western Canada. I'm just curious, if what nature of projects those are, would that be your share of transmission investments in Alberta or something different?

Yes, those are just connections to Alberta's distribution system that we own out there. So there is a lot of activity in Alberta related to distributed resources. And of course, that needs us to interconnect them. And that's what that references.

Our next question comes from the line of Matthew Weekes with IA Capital Markets.

Good morning. Thanks for taking my question. I think that was the kind of downside the earnings on Central Hudson was quantified a little bit. I was wondering if you'd be able to provide some color or quantify how much maybe a positive tax one time events might have had at ITC in terms of the interest rate swap adjustments, and the timing of expenditures in Alberta and maybe some one time adjustments there as well.

Matthew, with respect to the swap adjustment that we made at ITC, this related to a swap that had been executed previously. And this was just truing up some amortization related to a swap that they had. And that was pushing $0.02 in the quarter; you won't see that again, that's just more like a one time thing. With respect to Alberta, I would say from the timing from Q3 to Q4, potentially with respect to expenses, probably about $0.01, I mean, that's all we're talking about is not material in terms of what we're seeing between one quarter and the other. But that's about the extent of the changes between the quarters.

Our next question comes from the line of Dariusz Lozny with Bank of America.

Hi, good morning, and thank you for taking my question. Most of them have been answered already. But just to come back to COVID as it relates to the Central Hudson settlement. Just wanted to clarify, there's some language in there about I believe it's Central Hudson potentially convening some discussions to specifically discuss the resolution of arrears that are related to COVID. I'm just curious, absent much updates in the generic New York docket. Have those discussions taking place? And if so, can you give any update there?

Yes, I'll turn that one right over to Charlie.

Thank you, Dave. So the New York Public Service Commission staff had put out a white paper associated with a arrears management programs and related to COVID specifically, and then there's -- so that is essentially been rolled into the generic proceeding. So in our settlement discussions, there was a lot of conversation around an arrears management programs. And we felt that it was best not to try to address that as an individual utility, recognizing it is within the generic proceeding. So rather than come to a conclusion on how we're going to handle in arrears management we agreed that we following the agreement being approved, that we would participate in conversations about the different options associated with it. Now, as I mentioned earlier, within our settlement, we did come to agreement related to finance charges, we did come to agreement related to bad debt. And we did come to an agreement related to some of our COVID costs. But the concept of arrears management is a little bit more complicated. And a number of different ideas have been thrown around, which is why we agreed to not tie up our individual settlement when it was also being handled through a generic proceeding. I hope that answers your question.

Yes, that's very helpful. Thank you very much. If I could ask one more quickly. On Alberta, it looks like I realized it's a smaller piece of the overall pie. But it looks like on a percentage basis from last year's plan to this one, the planned CapEx over five years, increased substantially. Can you just talk a little bit as far as is that a relative determination for that jurisdiction versus others? Or just maybe specific opportunities that you're seeing there? That perhaps you didn't one year ago, when you put out the other plan? Just curious about the puts and takes there?

Yes, Dariusz. Thanks for that question. And it's really a bit all over the map in FortisAlberta because it's not like one big project or anything, its customer growth and sustainment investments and new technology, et cetera. So there's a little bit of everything in that pot. I think probably what happened on a year-over-year basis from a plan perspective, is last year when we are sitting here at this time, we were set -- we were basically had oil at $40 a barrel. Now it's at $80 a barrel, we're probably in the doldrums of the economy in Alberta, as well as in the throes, the deep throes of COVID, although we're still there. And so probably from a forecast perspective, we weren't seeing a lot of that growth opportunity going forward. And now we do, we see some of that growth coming back; we see oil and gas coming back. And frankly, we have looked at the capital budget with quite a more a closer eye and looking for opportunities and investing in resiliency is also a big add there that the team has done since last year. So it's all of those things combined. So it's not one specific like project to point to.

Thank you. As there are no further questions, I would like to turn the call back to Ms. Amaimo.

Thank you, Phyllis. We have nothing further at this time. Thank you everyone for participating in our third quarter 2021 results and new five year capital outlook conference call. Please contact Investor Relations should you need anything further. Thank you for your time and have a great day.

Thank you for participating, ladies and gentlemen. This concludes today's conference. You may disconnect.