Fortis Inc
TSX:FTS
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Fortis Inc
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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 5-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 5-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 is referenced 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 5-year plan, I'd like to discuss the recent executive leadership developments here at Fortis. Last month, we announced that 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 VaNita 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 7 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 5-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 5-year capital plan of $13 billion for 2017 through 2021. While that seemed ambitious at the time, we're now on track to invest approximately $18 billion, an additional $5 billion over that same period, translating 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 in our regulated utilities. Drivers of the increase include customer growth, enhancements to transmission reliability and capacity and investments in cleaner energy. This growth in 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 5-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 to exit coal by 2032. ITC plans to invest in transmission to interconnect renewables, including 2,800 megawatts of generator interconnections in the U.S. 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 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 reduced 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 Springerville 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 2 and 3 emissions. Through 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 3 largest utilities: ITC, FortisBC 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 to date. As we have previously discussed, ITC is strategically positioned in the Midwest to invest an 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 CleanBC's 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 the pandemic is 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 that are 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 5-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 us well to extend this record. And to that end, today, we are reaffirming our 6% average annual dividend growth through 2025. Now I 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 was $0.64, $0.01 lower than the third quarter of 2020. During the quarter, cooler weather in Arizona tempered 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 9 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 continued 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 2020, 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 rate base 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 U.S. 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 are expected to be recognized. At our Energy Infrastructure segment, EPS decreased $0.03 mainly due to realized losses on natural gas contracts at Aitken Creek. Contracts 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 U.S. 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 impacted 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 basis 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 absent foreign exchange. Turning now to our funding plan. The new 5-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 a 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 rating. Turning to recent regulatory developments. First, ITC awaits the final rule from FERC in relation to the supplemental Notice of Proposed Rulemaking on transmission incentives, which proposes to eliminate the 50 basis point RTO early incentive. 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 time line and outcome of this proceeding remains unknown. In New York, Central Hudson filed a joint proposal in August, seeking a 3-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 the third rate year. The proposal also reflects the use of existing regulatory balances and other measures to reduce impact -- 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 5-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.
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% translation versus in the past? And has this ability changed? What has changed?
Yes. Thanks, Maurice. As you know, we don't give earnings guidance and we obviously give rate base guidance as a proxy to -- somewhat. And of course, on a longer-term basis, we would expect rate base 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.
And my second question is on the dividend growth guidance. You've reaffirmed 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 the out year? Or is there something else that motivated this decision?
Thanks, Maurice. You answered the question yourself. But 4 years is still a long time to be giving 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, it's 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, $0.5 trillion of additional investment opportunity and government support in the U.S. related to the budget reconciliation bill, we think that there's going to be a lot of opportunities in the tail end of our 5-year plan, as we mentioned. We mentioned some of them, but there's this big bucket of what do all these additional investments mean? Does it drive for a faster clean energy transition in the U.S. 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 5-year forecast to be able to address that.
And maybe just a quick follow-up and just to tie the first and second question together then. If you expect over the long term for EPS and rate base growth to converge, and in this case, you're hoping to have flexibility on the dividend outer year, is there a target dividend payout ratio that in your mind you're looking at as you balance all these decisions?
Not really, Maurice. I mean this is -- these are conversations we have every year with our Board of Directors to -- based 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.
First question on the quarter specifically, do you expect any of your segment results in Q3 to reverse into Q4, whether positive or negative? Or do you expect that the most will flow into your realized ROE?
Yes. The question I'll kick it over to Jocelyn, breaking up a little bit there. But whether or not we see any earnings timing between Q3 and say, Q4, do we expect any of those to reverse?
Ben, thanks for the question. Yes, we do have some timing. We referenced 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, all major other timing variances that we see between the quarters.
Okay. Great. Your comments around the commodity price situation not being reflected in your base plan, should we read that as more there's a flow-through upside to your CapEx if you start to bake that in? Or is it more reflected that it could temper 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 bang for the invested buck for our customers. But at the end of the day, it would -- 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 in every one of our subsidiaries to focus on other cost reductions that we can do for our customers to help them manage the bill impacts. 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. So 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 to hear your updated comments on that as you rolled over the CapEx program, whether large scale or smaller scale?
Update it on what? I missed the question, Ben. Updated on M&A you said?
Yes. What's your thoughts and appetite for M&A as you've gone through your budgeting process and looked at upside to the planned -- downside to the plan? And I know you've communicated thoughts on that in the past, but would want to hear if you're more maintaining your past view? Or is there a slight change in appetite.
Yes. It will probably sound really familiar. I mean this is a big capital plan. It's a big deal to get the $20 billion capital plan put together. It will be a big deal to execute it, but we are 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 #1 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 find 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.
I'm wondering as you look at those opportunities out there, what sort of guardrails are you imposing on your world of possibilities as it relates to geographies, technologies, commercial attributes? And specifically interested to hear whether you see any initiatives around hydrogen of whatever color or attribute or carbon capture as within the range of possibilities and how they might manifest themselves in leveraging your competencies in your existing footprint?
Yes, Linda, we don't really have any guardrails around 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 has looked to us. So whether it's looking at things like hydrogen or carbon capture utilization storage, I mean, 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, and we don't start with any guardrails on that. Now 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 in the back of our mind the fit on investments and how that impacts or affects our ESG profile as well.
Okay. 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 in the 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. It 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 likely to be in the space of the green energy investment with what's happening, particularly in the U.S. 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. And just as a follow-up. Given the expectation that interest rates might be going up, how might you think about potentially prefunding, 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, I think 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 right across our organization now, we are looking at all of our financing where it's appropriate to do interest rate locks 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 in some of those facilities, we do have mechanisms whereby the interest costs -- or rising interest costs are actually included in regulatory deferral mechanisms or a part of the PBR structure where it's shared with customers. But yes, it is something that we're always looking at and advancing financing is certainly one of the options.
Our next question comes from the line of Rob Hope with Scotiabank.
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 off-takers there as well as kind of what next steps and when that could be put in the capital plan?
Yes. There's only 1 off-taker and that is the ISO. So 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 contract negotiations. Obviously, turning term sheets back and forth and trying to come to the agreement of the deal structure. We do expect -- and the Minister of Energy in Ontario is requesting that report back 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.
All right. 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 BC and he's on the line. Roger, would you want to address that?
Thanks for the question, Rob. So on Woodfibre, continuing to work closely with Woodfibre. They are looking to make FID here potentially as early -- or as late as the end of the year. So progressing that project and nothing materially new on the expectation that we laid out, I think, last quarter. As far as other opportunity, the 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.
First question is 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 has slipped as I think we were kind of radioing 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. 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 the settlement's 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 pickup from what should have probably been recorded earlier rather than later. So you'll see that pickup in Q4.
And then on the details around the pieces that are included in the settlement from a COVID perspective, the other half of your question. Charlie, do you want to provide any color on that?
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 lost 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.
I want to come back to investments like the Lake Erie Connector project or for somewhere that you've done a little like that, that might not be in rate base. How would you think to frame that in terms of growth and impacts if it's not in 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 base asset. I mean it's basically what we're trying to do is make this look like a contracted asset that mimics a 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 basically if you were to design a document on that agreement, you would kind of "put it" in as sort of rate base and in your growth forecast?
Would we put it in as rate base in our capital forecast? It would be in the capital, but not in a rate base number.
Got it. Okay. And then obviously, there are a lot of headlines around Arizona around some other utility in the state. Maybe you can take this opportunity to kind of give us your updated view and then contrast and compare how you guys see your sales position versus ASP. Obviously, you've already done your rate case, but sort of updated views given all the headlines going on there?
Mark, I'm glad you asked and I'm amazed at this question fell so far down in the queue. I thought it was on everybody's mind given some of the analysis around the case -- the APS' case recently. And I'll start out by saying that 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 as I did listen to some of the hearing, I think you'll see that, 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 everything that we possibly can to make sure that we build the trust with our regulators, and we do that through making sure that we are transparent and we have integrity when we -- with everything and every interaction that we have with that commission. That's been our MO. I've been testifying in front of that commission for almost 20 years and can tell you that we make sure that we have -- we always do the things because we know that -- we've 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 Fortis 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, this was just -- I can't believe it was less than a year ago, but less than a year ago, in December of 2020, we actually got a very constructive rate outcome from the Corporation Commission for TEP. And that, I think, is indication. Nothing -- it was in the middle of COVID, we're still in the middle of COVID, there's not a lot of things that are different. But we obviously got quite a bit of different treatment and quite a 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 the supply chain question and rising CapEx costs, can you just remind us again like on the PBR-based utilities, like at West Canada, I assume that there's capital trackers and things to manage that. Is it just the utilities with a historical test year, would there be regulatory lag where you might feel a bit, I guess, temporary pressure from higher CapEx costs? If you can kind of comment in terms sort of transient impacts around that.
Yes. That would be -- yes, you hit the nail on the head there. The Western Canadian utilities have PBR. They actually have inflation built into their rates as well, capital trackers, et cetera. ITC has a forward test year. So that all gets trued up. So yes, it's really probably only Arizona that would see a little bit of a drag on the increased costs from an O&M and capital perspective.
In Central Hudson?
Central Hudson, Charlie, I have to say that, 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 improved capital budgets and net plan targets with -- in 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 our projects 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.
Probably a question to start off with David and it's really about your -- I guess, your last home state in the U.S. and Arizona. And there, UNS as a stand-alone and really under the Fortis umbrella, not really impacted by a lot of the regulatory noise. And I guess just 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 a comparable within a certain jurisdiction that you can effectively play off as you've done in Arizona over the years?
Yes, Andrew. Yes, 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 regulators 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 in 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 -- with the 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 stakeholder 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.
Okay. That's helpful color and context. And then 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 just your RNG 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 the summer, the BC government amended the greenhouse gas regulation around RNG. 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 30 by 30, which included 15% of our natural gas portfolio coming from renewable gases by 2030. We're probably 1/3 of the way there with signed contracts. I think we're just under -- just over 8 petajoules approved by the BCUC. We have a couple more contracts that we still have to file so we're approaching 10 petajoules in the first 2 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 CleanBC, which is a very ambitious plan on carbon reduction. So we expect further opportunities on the RNG front to come.
And if I can, maybe just 1 follow-up on that. And Roger, how broad based are your procurement activities because we talk 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 this stage?
Right now, we're signing for current deals across North America. So we've got, I think, now 2 contracts approved from the U.S. projects. We have a handful of contracts approved outside of BC, Alberta and Ontario. So we're really looking at RNG 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 mix. It won't simply just be the landfill wastewater treatment plants for agriculture. That will still be important, but I think hydrogen, blue, green or otherwise, will be an increasing part of the renewal gas mix.
Our next question comes from the line of David Quezada with Raymond James.
So my first question here is just on the topic of interregional transmission planning as it relates, I guess, to ITC. I understand FERC has had some discussion with the industry on the 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, interregional transmission planning. Just curious how those concepts, how you see them developing and how that could affect things at 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. 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 are a significant amount of comments that were made around the ROFR as -- or I should say, the competitive provisions of Order 1000 in the ANOPR comments that were filed. I mean there have been some comments made by various -- kind of over various points in time that 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 ROFRs 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 U.S. are covered under kind of ROFRs or 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 in 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 saw a comment, I guess, in the presentation about IPP interconnections in Western Canada. I'm just curious 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 reference is.
[Operator Instructions] Our next question comes from the line of Matthew Weekes with iA Capital Markets.
I think some of the kind of downside to 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 of a positive impact onetime event might have had at ITC in terms of the interest rate swap adjustment and the timing of expenditures in Alberta and maybe some onetime adjustments there as well?
Matthew, with respect to the swap adjustment that we made at ITC, this related to a spot that had been executed previously and this was just truing up some amortization relating 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 onetime thing. With respect to Alberta, I would say from a timing from Q3 to Q4, potentially with respect to expenses, probably about $0.01. I mean that's all we're talking about. It's 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.
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 socket, have those discussions taken 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 arrears management programs related to COVID specifically. And then -- and so that has essentially been rolled into the generic proceeding. So in our settlement discussions, there was a lot of conversation around 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 an arrears management program, 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. If I could ask one more quickly. On Alberta, it looks like -- I realize 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 5 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 1 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, it's 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 were sitting here at this time, we basically had oil at $40 a barrel, now it's at $80 a barrel. We're probably at 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 had looked at the capital budget with quite 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 5-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.