Fortis Inc. (NYSE:FTS) Q1 2023 Earnings Call Transcript

Fortis Inc. (NYSE:FTS) Q1 2023 Earnings Call Transcript May 3, 2023

Operator: Good morning everyone. Thank you for standing by. My name is Brian and I will be your conference Operator today. Welcome to the Fortis Q1 2023 earnings conference call and webcast. During the call, all participants will be in a listen-only mode. There will be a question and answer session following the presentation. At that time, those with questions should press star followed by one on their telephone. If at any time during the conference you need to reach an Operator, please press star, zero. At this time, I would now like to turn the conference over to Stephanie Amaimo. Please go ahead, Ms. Amaimo.

Stephanie Amaimo: Thanks Brian and good morning everyone, and welcome to Fortis’ first quarter 2023 results conference call. I am 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 could 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 first quarter 2023 MD&A. Also, unless otherwise specified, all financial information referenced is in Canadian dollars. With that, I will turn the call over to David.

David Hutchens: Thank you and good morning everyone. Before getting started, I’d like to introduce Chris Capone to his first earnings call since being appointed President and CEO of Central Hudson in February following the retirement of Charlie Freni. For those of you who don’t know Chris, he has been with Central Hudson for over 20 years, serving for many years as Chief Financial Officer. Welcome, Chris. We look forward to working with you in this new capacity as you lead the team in New York. Today we are pleased to report strong first quarter results which reflect the diversified nature of our business, favorable market conditions, and the continued delivery of our low risk capital plan. As we have talked about in the past, we remain keenly focused on meeting our clean energy goals while investing in the resiliency of our energy systems, all in a manner that ensures continued customer affordability.

For example, Fortis BC received a milestone approval in April from the British Columbia Utilities Commission for a $155 million investment supporting their energy efficiency programs. This is just one of the many ways our utilities are taking the lead on climate action while offering practical options to customers to reduce emissions and their bills. From a financial perspective, we invested $1 billion of capital in our energy systems and adjusted earnings per share in the quarter increased $0.13 compared to the first quarter last year, driven by strong regulated growth which Jocelyn will speak to shortly. On the regulatory front, our applications in Arizona and British Columbia continue to progress with decisions in both expected midyear. On Monday, we announced that we entered into a definitive agreement with Enbridge to sell our unregulated investment in Aitken Creek for approximately $400 million.

Once the sale is closed, we expect to use the proceeds to pay down our corporate borrowings, which strengthens our balance sheet and provides additional funding flexibility to support our regulated utilities growth strategy. The transaction is subject to approval by the BCUC as well certain closing conditions and adjustments. The sale is expected to close in the second half of 2023. With approximately $1 billion invested in our systems in the first quarter, our $4.3 billion annual capital plan remains on track. Our major capital projects progressed during the quarter. In March, Fortis BC filed amended transportation rate schedules with the BCUC in relation to the Eagle Mountain would fiber gas line project. Approval is expected in May and, once approved, the project will one step closer to construction.

The first tranche of projects associated with the MISO long range transmission plan are advancing with stakeholder outreach, routing studies and design engineering all underway at ITC. In total, ITC estimates transmission investments of US $1.4 billion to $1.8 billion through 2030 with six of the 18 projects in Tranche 1. As you may recall, the $22.3 billion five-year capital plan consists of virtually all regulated investments and a diverse mix of highly executable, low risk projects supporting rate-based growth across our portfolio of utilities. The plan also includes $5.9 billion for investments to directly support cleaner energy. Over the next five years, we expect rate base to increase by $12 billion from approximately $34 billion in 2022 to over $46 billion in 2027, supporting average annual rate base growth of 6.2%.

With a strong track record of increasing dividends for the past 49 consecutive years, coupled with our low risk growth strategy, we remain confident in our 4% to 6% annual dividend growth guidance through 2027. Now I will turn the call over to Jocelyn for an update on our first quarter financial results.

Jocelyn Perry: Thank you David, and good morning everyone. Slide 9 provides a summary of our first quarter results. Reported earnings were $437 million or $0.90 per common share. Adjusted earnings were $439 million or $0.91 per common share, $0.13 higher than the first quarter of 2022. Rate base growth and higher earnings in Arizona were the key drivers of growth for the quarter, which I’ll discuss shortly. Foreign exchange also favorably impacted the translation of our U.S.-denominated earnings, while earnings growth was tempered by higher holding company finance costs and higher weighted average shares outstanding. The waterfall chart on Slide 10 highlights the EPS drivers for the quarter by segment. At our U.S. electric and gas utilities, EPS increased by $0.08 for the quarter with UNS contributing $0.09 and Central Hudson down $0.01.

A number of items impacted UNS’ results for the quarter, most notably higher wholesale sales and FERC transmission revenues were mainly driven by favorable market conditions. Additionally, UNS benefited from gains on investments that support retirement benefits. Higher retail sales, including the favorable impact of weather, also increased earnings, and lastly lower depreciation expense associated with the retirement of the San Juan facility last June more than offset higher operating costs. About half of the increase in EPS contribution from UNS is expected to moderate given timing of wholesale and transmission revenues compared to 2022. The $0.01 EPS decrease at Central Hudson was mainly due to higher operating costs and finance costs, partially offset by rate base growth.

ITC in our Western Canadian utilities each contributed a $0.02 EPS increase driven mainly by rate base growth. At ITC, earnings growth was tempered by higher holding company finance costs. Our energy infrastructure segment contributed a $0.02 EPS increase for the quarter driven by higher margins and volumes at Aitken Creek, and higher hydroelectric production in Belize. The higher U.S. dollar to Canadian dollar foreign exchange rate favorably impacted the translation of our U.S.-denominated earnings, which increased EPS by approximately $0.03. The $0.03 decrease in EPS contribution from our corporate segment was mainly driven by higher finance costs, and lastly EPS decreased by $0.01 due to higher weighted average shares outstanding related to our dividend reinvestment program.

All in all, a very strong quarter even after excluding the timing of earnings at UNS and foreign exchange impacts. During the quarter, our regulated utilities raised over $600 million in long term debt, largely in support of their capital programs. We also recently entered into interest rate hedges to mitigate holding company refinancing risk. Despite broader market volatility during the quarter associated with the banking crisis, there remains a strong appetite for low risk, strong credit quality issuers like Fortis. With our recent debt issuances coupled with $3.6 billion available on our credit facilities, we continue to maintain a strong liquidity position supporting our $22.3 billion five-year capital plan. We remain comfortably positioned within our investment grade credit ratings as we execute our capital plan and pursue incremental organic growth opportunities.

Turning to an update on some of our ongoing regulatory proceedings since we last updated the market, first, ITC has rights of first refusal, or ROFRs for regional transmission projects in Iowa, Michigan and Minnesota. In March, the Iowa Supreme Court granted certain parties standing to challenge the Iowa ROFR, issuing a temporary injunction staying enforcement of the ROFR statute and remanding the issue to the district court. Although the timing of this proceeding and impact on future projects is unknown, the decision is not expected to impact projects already approved and awarded by MISO, including Tranche 1 of MISO’s long range transmission plan located in Iowa. In Arizona, TEP’s case continues to progress. TEP’s requested rate base of US $3.6 billion and equity layer of 54% are consistent with Arizona Corporation Commission’s staff recommendations.

Staff have also recommended and allowed ROE of 9.5% compared to TEP’s current ROE of 9.15%. Hearing concluded in April and a recommended order and opinion from the administrative law judge is expected midyear. We expect new rates later this year. In New York, there are no updates on the show cause order regarding the deployment of Central Hudson’s new customer information system. Central Hudson did file a response to the show cause order in January, and the timing and outcome of this proceeding remains unknown. Turning to Western Canada, Fortis BC filed its final reply arguments on its generic cost of capital proceeding and a decision is expected by midyear. At Fortis Alberta, proceedings related to the generic cost of capital and the third PBR term effective in 2024 are progressing with evidence filed.

A decision is expected from the Alberta Utilities Commission later this year on both proceedings. With that, I’ll now turn the call back to David.

David Hutchens: Thank you Jocelyn. 2023 is off to a great start both operationally and financially, highlighting the balance and strength of our regulated utility businesses. Looking ahead, we expect to continue to provide long term value to our shareholders through the execution of our growth strategy, supporting our 4% to 6% annual dividend growth guidance through 2027 while concurrently delivering a cleaner energy future and safe, reliable and affordable service to our customers. That concludes my remarks. I will now turn the call back over to Stephanie.

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

Q&A Session

Operator: Thank you. We will now conduct the question and answer period. The first question comes from the line of Maurice Choy. You may proceed.

Maurice Choy: I just wanted to dive a little deeper into Q1 results at UNS. Could you elaborate a little more on the nature of the timing of these wholesale electricity sales and transmission revenue? What happened during the quarter for these items to emerge, and when you say half of the year-over-year increase in EPS contribution will moderate, does that mean you need to somewhat give it back, about $0.04 to $0.05 over the remainder of the year?

Jocelyn Perry: Maurice, yes – we indicate that we think it’s going to moderate, just really based on looking at how we transacted last year for wholesale sales in particular. We had done some wholesale sales in third quarter and I believe some in the fourth, so it’s just early in the year to make predictions of how and when these transactions are actually going to unfold. When we look at the timing, most of them were in Q2 last year, so with that, we just advanced it forward in Q1, so we are expecting some of the wholesale sales to moderate.

Maurice Choy: Got it. That makes sense, and thanks for the color on that. I want to finish off with the sale of the Aitken Creek gas storage facilities. Can you take us back to when you first thought about selling the asset? Why do you feel selling an asset was the right thing to do? What was this the right asset to sell, and also, why now?

David Hutchens: Yes, that’s a great question, Maurice. It’s our job as fiduciaries to look for value within our company, and that value changes based on a lot of different inputs, one of them being market conditions and interest rates, etc. Given that we are always looking for finding that additional shareholder value, some of these things are just kind of on our list to be looking at. When things align, when you can find a good opportunity, good value and a good counterparty to look at these assets and find even more value than we can find in them, that’s what triggers a deal. It wasn’t anything like we’re sitting here, trying to figure out how to sell this for years and years and years. This was just something that we were being very opportunistic with, and now given the market conditions, provides us–particularly in a volatile market period, provides us that additional funding flexibility, balance sheet strength, etc., so just all of the right things aligned here.

Maurice Choy: Thanks, and maybe as a follow-up, you mentioned it’s one of the things that’s on your list to look at. What else is on that list, and obviously there’s some other large unregulated assets in there, like the hydro assets in Belize. Would the same logic for selling the gas storage at Aitken Creek apply to this set of hydro assets, or is it more complicated because ?

David Hutchens: Yes Maurice, you did not disappoint. I figured that–I would have given odds that would have been your follow-up question. The only other appreciable regulatory assets we have, period, is Belize. We don’t have some sort of schedule to be looking at these assets. It, again, is just us being opportunistic across our portfolio and finding that value, so we don’t have an agenda here.

Maurice Choy: Appreciate that, thank you very much.

Operator: Our next question, we have Rob Hope with Scotiabank. Please go ahead.

Robert Hope: Good morning everyone. First question is Arizona. Going into the hearing, you were a little confident that you could get a stipulation agreement, which didn’t come to bear, but can you give us some color on how the hearings went and kind of where you see yourselves more aligned or less aligned with the stakeholder?

David Hutchens: Yes, I’ll turn that over to Susan Gray, who is the CEO of UNS Energy and just spent some time on that stand in those hearings. Definitely it has been a very, I think–speaking from someone who was sitting in that chair, it seems like it was a very straightforward batch of hearings and, frankly, places of standard disagreement or argument across things like ROE and some other odds and ends. Susan, do you want to provide a little color on that?

Susan Gray: Sure, yes. Thank you for the question, Rob. Yes, I think the hearings were as expected. Prior to the hearings, we were able to narrow some of the contested issues with the other stakeholders and intervenors, and so I feel like we had a pretty straightforward hearing in terms of issues that we covered. I would say a lot of discussion around the system reliability benefit, which is an adjuster mechanism that we’re proposing to reduce regulatory lag for our new clean energy investments. There was also some conversation about the coal community transition and potential customer funding, which hasn’t really been set as a policy by the Arizona Corporation Commission, and then–yes, kind of the typical ROE, fair value increment, things like that, but I think that we’re pretty close, I think closer than we’ve been in years past in terms of what staff has put forward and what we’re recommending, and so looking forward to the judge’s recommended opinion and order this summer and then an open meeting to decide the rate case, probably early fall.

Robert Hope: Thanks for that. Then sticking with Arizona, a little bit more of a local question. Proposition 412, do you view this as kind of normal course or is there potentially some concessions to be made there?

Susan Gray: Sure, thanks for the follow-up, Rob. Proposition 412 is our proposition to approve a new franchise agreement with the City of Tucson, and I would say what’s new in this franchise is that we have added a 0.75% increase to the rate, which was previously 2.25%, in order to cover the undergrounding costs for a new transmission line that we’re building through the City of Tucson, and that would provide recovery over about a 10-year period. We’ve also designated 10% of those new funds to fund the city’s climate action and adaptation plan, so that’s the agreement that we came to with the City and that’s what’s being proposed in Prop 412. I think this is fairly new for the City, so I’m not sure I would call it normal course of action. I mean, franchise fees are normal, this is just a little bit of a twist on it. The election’s coming up just in a couple weeks here, and hope to get started on building that new transmission line underground.

Robert Hope: Thank you.

Operator: Next question comes from the line of Linda Ezergailis with TD Securities. Please go ahead.

Linda Ezergailis: Thank you. Just wanted to step back to a very high level and get your updated views on the likelihood and the relative attractiveness of potential unregulated but contracted energy infrastructure investments. I recall in recent history delegating a search for these types of opportunities to some of your regional heads, and just wondering if the overabundance of utility investments now has put those opportunities to the backburner or if they’re less attractive, or maybe you can comment on over time how much of your overall company might be unregulated, if any. Then maybe you can also specifically comment geographically on the opportunities you also see in BC with the divestiture of Aitken Creek, but you’ve got your wood fiber gas line likely proceeding and also some RNG opportunities.

David Hutchens: Yes, that’s a great question, or questions, Linda. Appreciate you asking them, because I think provides an opportunity to provide some very–some clarity. One is, are we interested in doing unregulated renewables? The answer is no. We have a lot to do in our regulated utilities, and frankly that’s where we see the additional growth going forward on top of our current existing capital plan. That’s where we’re focusing. The others are backburner, off the stove, however you want to think about it. That’s clearly not in our sights. When we think about longer term, what we want to look like from a company perspective, regulated versus unregulated, we’re practically 100% regulated other than that investment in the Belize hydro generation that we have.

We like that, we think that’s what our investors like too. We think that’s the right opportunity to look, and frankly that’s where our core competency lies. That’s where I think we’re going to see plenty of growth opportunities as we go through the clean energy transition on a going forward basis. Can you remind what the last part of your question was?

Linda Ezergailis: Just BC specifically, because you’ve got some RNG related opportunities.

David Hutchens: Oh, BC – yes. The things that we’re looking at in BC from the wood fiber pipeline, regulated utility infrastructure, from Tilbury 1B regulated utility infrastructure. Don’t try to read anything into us getting out of an unregulated storage facility as a view on our BC company. We love that BC company, we think that they have huge growth opportunities, and we see them playing a big role in Clean BC and the strategy for decarbonising that province. It’s just as simple as trading unreg for reg, and so I think that provides a lot of clarity on where we’re going on a going forward.

Linda Ezergailis: Thank you. Just a follow-up question on your capital, five-year capital expenditure plan as it continues to evolve and as you layer on new opportunities, especially potentially facilitated by the IRA in the U.S. Might you look for alternative–not alternative financing, but might you augment your current financing plan and add to it, or might you defer some more discretionary capital to kind of stay within the current financing plans?

David Hutchens: As we build out that capital plan, I don’t want to get ahead of our next release as we’re drawing up our current plans, and so the look at what our next capital plan, which will be coming in that September, call it fall time frame, that will be the time that we’ll update anything related to obviously the capital plan, timing, and how we’ll fund it. Obviously Aitken Creek gives us an extra $400 million sitting in there from a funding flexibility perspective as well.

Linda Ezergailis: Thank you.

Operator: Thank you, and the next question comes from the line of Mark Jarvi with CIBC. Please proceed with your question.

Mark Jarvi: Thanks, good morning everyone. I just wanted to come back to the strong results at UNS, and Jocelyn, you talked about timing and how much of that year-over-year comparable will moderate a little bit, but kind of implying also that results are up. Are you implying there’s some sort of structural tailwind the wholesale market in transmission revenues, and what’s driving that, if there is?

David Hutchens: Yes, for the most part it’s volume and price differences. It’s not–it’s market driven, it’s very specific to shorter term–I’ll say shorter term market perturbations, if you want to think of it in that respect. It isn’t necessarily on the wholesale side a view that there’s this long term additional wholesale sales that can–that will continue on, on a going forward basis. Now, on the transmission side, there is just a lot more use of our transmission system than we’ve had in the past – that’s probably, likely to continue. I think one of the things that folks forget is that UNS and TEP – Tucson Electric Power in particular has a large portion of their rate base that is FERC jurisdictional transmission, and we also have a forward formula rate that looks just like ITCs and we have, I think, about a billion dollars of transmission capital and about $900 million or so in the current five-year capital plan at UNS, so some of those things will continue to grow over time.

Mark Jarvi: Okay, excellent David. Then Jocelyn, coming back to you in terms of you mentioned putting some hedges around interest rates going forward. Aitken Creek allows you to take out some short term debt here. Is there anything else you’d like to do in terms of managing any holding company debt or bringing down interest expense costs?

Jocelyn Perry: Mark, I would say that the two you mentioned are two big ones for us. Obviously Aitken frees up $400 million of our borrowings to give us that flexibility, but we did enter into both here–and at ITC at the holding company level, into interest rate hedges for the upcoming holding company financings that we have to do this year, so we’re always watching the market to determine a good time to go in. But it’s good to take that risk off the table, right – the markets are still volatile, and so we’re laser-focused on taking that risk off, but Aitken and interest rate lock certainly do improve our position with respect to the volatility we expect to see on our business. But we’re always watching. I don’t see–you know, I think we’re going to be looking for our regulated utilities, potentially looking at timing of their debt offerings, so we’re watching the market very closely.

Mark Jarvi: We’ve seen a few more convertible note offerings from the U.S. utilities. Is that something you’d contemplate, or is that not a fit right now for Fortis?

Jocelyn Perry: We’re definitely always looking at things, but convertibles are not really in our space right now with our current five-year plan because we don’t require any further equity beyond the DRIP that we’ve already outlined within the plan. But certainly as David mentioned, as we now look to our next five-year capital plan and as we look at the investment profile over the next five years, we’ll look at all funding options but convertibles definitely is something that’s out there these days.

Mark Jarvi: Okay, thanks a lot.

Jocelyn Perry: Thank you.

Operator: Thank you. The next question comes from the line of Ben Pham with BMO. Please ask your question.

Ben Pham: Thanks. I wanted to ask on the Iowa situation with ITC and what are your thoughts on next milestones to look for, or your overall thoughts on the process a little bit. In terms of materiality, are you thinking this is more the capex that you have in there is not going to change, or you might see some changes and it’s not overly impactful to your potential capex plan?

David Hutchens: Thanks for that question, Ben. I’m going to punt that one right over to Linda. She has all the details that you’re looking for.

Linda Apsey: Yes, good morning. Thank you Ben. I think in terms of next steps, obviously the Supreme Court has remanded the case back to the district court, and so obviously there now will be a proceeding involving all the parties to litigate through the constitutionality of the ROFR. Unfortunately we don’t really have a good sense as to what the timing of that will be or the decision. As we stated, obviously it doesn’t have an impact on the Tranche 1 projects that have already been issued and awarded, but certainly as we go forward, there is various places that this issue is playing out – once clearly is at FERC. This was clearly an issued that was teed up in the transmission planning NOPR in terms of questions around the continuation of competitive bidding, the ROFRs, and so we would be hopeful that FERC obviously would make some decision around the ROFR issue, but it is obviously playing out.

It’s playing out in Texas, we now have it in Iowa, and so for us sitting here today, we’re going to continue to stay focused on planning the transmission system with MISO and obviously advancing sort of both the LRPT 1, the LRPT 1 projects. But I would mention that there are a lot of carve-outs for certain types of projects that are precluded from competitive bidding, certainly projects that utilize existing right-of-way, projects that are rebuilds, projects that are clearly just reliability projects. There’s a lot of different categories of projects that are not subject to competitive bidding, and so much of our five-year plan obviously is our base capital, and we would continue to have the right, the responsibility to execute on those projects that are ours.

I would say it’s premature to know exactly or understand how all of this plays itself out or what the impact is, but you can assure yourself that we will be positioned and are positioned, I would say to both be defensive and offensive on this front, so we’re taking every step that we can to prevail on the ability to have ROFRs. It is something that FERC explicitly allowed in their original–well, it was their subsequent ruling on competitive bidding, and it is something that FERC recognized, that states have the right and the ability to have state ROFRs, and so we will be actively pursuing defending the ability for states to maintain the decision around who builds in the respective states. I would just say–I mean, we have been pretty vocal through all of our comments on the FERC front in terms of we fundamentally don’t believe competitive bidding is a success story – it’s the opposite.

It takes more time, there’s no evidence to suggest that it’s cheaper, and I will give you an example right now – even in the LRTP Tranche 1, we are off and running in terms of siting, engineering, preparing our regulatory applications, meanwhile the couple of projects that are subject to competitive bidding probably won’t even have a decision on who builds those for at least another year, so how this is compatible with the overall national federal goals for carbon reduction and the need for investment in transmission is really a serious question that I think all the parties need to seriously consider. I just don’t think this is–I think this is a failed experiment, quite frankly, and we will be continuing to defend vigorously as well as be proactive on this front.

Ben Pham: That’s really good color, Linda. Maybe just sticking with ITC and the remaining 20% minority interest, can you clarify–you know, hypothetically if GIC were to sell that portion through–whether it’s a fund life ending or some other reason, does Fortis have a ROFR on that, and also just any thoughts on ITC more strategically?

David Hutchens: I’m checking around the room, and yes, apparently we do have those rights if GIC was to sell, for us to–I don’t know if it’s a right for first offer, rights of first refusal, but I totally wouldn’t expect GIC to be interested in selling that part of ITC. I can’t speak for them, of course, but they do like that investment.

Ben Pham: Perfect, and maybe just to close off on asset sales, Aitken in particular, I’m not sure – in your prepared remarks, did you comment on how the value compared to your hold value or your current trading multiple, and impact on future EPS?

David Hutchens: No, we didn’t, but Jocelyn can opine on it.

Jocelyn Perry: Yes Ben, so we paid around US $266, I believe, CAD $350, so it’s a little bit of a higher value than what we had paid a couple of years ago. With respect to multiples, I would say, as you can recall, we talk about Aitken quite frequently on the calls because the earnings somewhat are more variable, given pricing and volumes. But over the last five years, the average for Aitken has been about $0.04 a year, so if you do the math on 400, you’re going to get the mid-20 multiple for this transaction. As David talked about earlier, yes, it was a good time to do this transaction for us.

Ben Pham: Okay, that’s great. Thank you.

Operator: Thank you. The next question comes from the line of David Quezada with Raymond James. Please proceed with your question.

David Quezada: Thanks, good morning everyone. Maybe just starting with the billing system at Central Hudson, any news or updates you can share there, like how far away you are from correcting those issues and any expectations around higher O&M costs related to that?

David Hutchens: Yes, so the system is sending out bills correctly now, and as far as additional costs, we are spending some additional money to hire customer service folks, additional billing people, etc. to make sure that we’re fully recovered, and on a going forward basis, we see those bills going out correctly. It’s still a little bit of mop-up here and there from the blip that we had when we put it in service, but those are getting towards the very tail end here and then we’re just going through the process of making sure that we’re getting out there with our customers, our regulators, our government officials and telling that story and getting everything back on track.

David Quezada: Excellent, thanks for that. Maybe just one more from me. I understand there have been news reports suggesting pretty big renewable energy plans in the Mexican state of Sonora, with some plan to export that to the U.S., including into Arizona. Just curious if that’s something that could ultimately be factored into IRP for UNS or if that affects your business there in any way.

David Hutchens: Given that neither Susan nor I are familiar with that, I would probably say no. But when we look at our integrated resource plan that TEP and our smaller UNS Electric Company are both doing here later this year, we do look across a broad swath of different projects. It would just be whether or not projects like that, if they showed up, they would likely show up in one of our all-source RFP. There is very limited transmission capacity from Sonora up to Arizona, and believe me – to build transmission from Mexico to the U.S., particularly to connect into our system, we tried that about 25 years ago and gave up after about 15 years, I think, of trying to get that built. But that could actually be an opportunity for us to extend transmission, it could be an opportunity for us to look for cheaper renewables, but there’s plenty of sunshine in Arizona in our neck of the woods that connects to our existing transmission system, where we’d need much less infrastructure to attach to our grid.

David Quezada: Thanks for those comments, David. Appreciate it.

David Hutchens: You bet.

Operator: Thank you. The next question comes from the line of Andrew Kuske with Credit Suisse. Please proceed with your question.

Andrew Kuske: Thanks, good morning. Maybe continuing with the transmission theme, obviously you have a lot of skin in the game, given ITC and just the other assets you’ve got. Transmission has always been difficult to build, but there’s obviously increased emphasis given the energy transition, and there’s a lot of talk on transmission queues and the interconnection problems. How do you think is the best way to resolve it? I know that’s a big question, but what steps can you take or should the industry take overall, just to sort of tackle the problems that exist ahead?

David Hutchens: Yes, there is multiple fronts that you have to address this on, and FERC is addressing several of them. One primarily that you mentioned is the interconnection queue, and that NOPR as of last week, we hear it should be pretty soon where they get to a final ruling on how to, in essence, untangle the interconnection queue. I think they’re definitely doing it in the right manner, which is first ready, first served, and if that goes through and we can get that queue cleaned up and start getting more of those interconnections done, obviously that’s a big uptick for ITC and their business. I should note that that NOPR doesn’t address cost allocation on those interconnections, but that would be the next thing that we would look at.

There’s a lot of conversations at FERC, there’s a lot of conversations in the federal government in the U.S. that’s really focused on trying to reduce the amount of time, red tape, etc. associated with permitting and siting. We’re very hopeful that something gets done there. It feels to me like that’s a very bipartisan topic – everybody sees the need for transmission for the clean energy transition. It’s obviously going to be needed for building the additional capacity that we’d like to build, not just to support the Inflation Reduction Act and the amount of renewables, but also the manufacturing that is trying to be brought back into the United States, that can actually help provide some of those batteries and renewables, etc.

I think it’s on everybody’s to-do list, which is a good spot to be, but we definitely need to be pushing through all of the industry groups that we, and particular ITC, works with to try to find a better way to do this. The federal government, one of the main things that they’re focused on is trying to figure out how to create a little bit of an easier path through all the different agencies that have to approve siting, and of course FERC has a role there too with their backstop authority and whether or not–or how they choose to use that or redefine it.

Andrew Kuske: Okay, appreciate that color. Then I guess let’s just assume we land this in a positive spot and some of the industries do get untangled, to use your language. How much upside do you think exists to the growth that you’ve already got?

David Hutchens: Stay tuned for September. We still have to–you know, there’s no number I can put there, obviously. It’s really about the ability to execute and to get it done faster. At this point, it would probably be more of a conversation around timing versus dollars.

Andrew Kuske: Okay, so more bringing forward things versus a much larger number?

David Hutchens: Yes, like specifically Tranche 2, which we expect to be looked at over the next year or so in MISO. The timing on that could change, hopefully significantly – not the timing on when the projects get awarded but the timing on when the projects can actually get built, if we can figure out how to tighten up some of these permitting and siting requirements.

Andrew Kuske: Okay, appreciate the time. Thank you.

David Hutchens: Thank you Andrew.

Operator: Thank you. The next question comes from the line of Matthew Weekes with IA Capital. Please proceed with your question.

Matthew Weekes : Good morning. Thanks for taking my questions. Just wanted to get your high level thoughts directionally on the Canadian federal budget. Just wondering if anything specifically stands out too there, how you’re looking at different opportunities right now, and just general comments on that. Thanks.

David Hutchens: Yes, thanks Matthew. It’s a bit of a mini inflation reduction act, a lot of the same pieces are in that. There’s two in particular- one is related to tax credits for new clean energy projects, the other is tax credits related to manufacturing, and those two things are very good from an economic and clean energy–or economy and clean energy transmission standpoint. They don’t necessarily have a direct impact for us and our businesses, which are mostly energy delivery in Canada; however, the indirect impact is this is all going to mean that we need additional transmission and distribution, which is our business, to deliver the clean energy and to supply new manufacturing opportunities across Canada. It’s more of an indirect view from a Canadian perspective on that, and plus there’s still a lot TBD, particularly around hydrogen and what that credit might look like.

That might be the one opportunity where we have more of a direct benefit, say, in Fortis BC for us to look at different hydrogen development opportunities within the regulated construct there.

Matthew Weekes: Okay, that makes sense. Thank you. Just one more from me, maybe, and I think I know the answer to this. Obviously plenty of opportunities to grow in your regulated portfolio that you’ve highlighted. Organically, just wondering if there is any kind of place for M&A opportunistically, whether it’s anything larger or small scale, or just any kind of room for that in the growth plan. Thanks.

David Hutchens: Yes, as you mention, we’ve got a pretty healthy capital budget that we’re really focused on, and we’re going to spend most of our energy focused on finding out how to take that to the next level and then execute at that next level, so that’s where our main focus is here. Obviously as fiduciaries, we keep our eyes and ears open, but that’s not a priority for us.

Matthew Weekes: Okay, thank you. I’ll turn the call back. Thanks.

Operator: Thank you. The next question comes from the line of Michael Sullivan with Wolfe Research. Please ask your question.

Michael Sullivan: Hey, good morning.

David Hutchens: Morning Michael.

Michael Sullivan: Hey Dave. This got asked earlier, but I just want to be really direct on it. Can you just explain why you think you were unable to reach a settlement in Arizona, and what kind of change from when you were indicating that that may be the case on the last call?

David Hutchens: Yes, it’s just getting a bunch of people in a room to agree, and frankly you’ve got a short time frame to do that. It just didn’t happen. It’s one of those things that you try to get done, but you can’t control the different counterparties. I’ll say I was extremely pleased with Susan and the team at TEP and their ability to get it down to just those couple issues to be really discussed in earnest in the hearings. When you’re sitting here at 975 from an ROE perspective on staff’s versus ours, and the rest of the pieces that have come in and the conversations have all been constructive, it didn’t–at the end of the day, it didn’t really bother us that we had to go through a couple weeks of hearings.

It didn’t bother me, because I didn’t have to testify! But you know, it’s always better if you can get as settlement just from an expeditious standpoint, but this was the next best thing because in the end, there wasn’t a lot of topics here that we were–that were thorny.

Michael Sullivan: Okay, appreciate the color there. Also just related to–sticking with Arizona, specifically the renewables rider request and then discussion around the system improvement benefit mechanism, maybe just where does that stand, where do you see that going, and can that be resolved within the rate case or outside and it becomes longer dated? Just where are we at on that?

David Hutchens: I’ll turn that over to Susan for color on that new tracker that we’re talking about.

Susan Gray: Sure, so the tracker is the system reliability benefit, and that was a change from what we had originally proposed. It was actually suggested by the staff that we look at something that was more similar to an existing adjustor that’s used for water companies, and so we did submit a plan of administration through the testimony process. In the hearing, staff offered to work with us to come to an agreement on what that plan of administration should look like, so at this point we’re waiting for the judge to put it in her recommended opinion and order and then for the commissioners to say, yes, we do want you to work on that plan of administration. We wouldn’t actually have one in place until after the rate case is actually decided.

Michael Sullivan: Okay, very clear. Thank you very much.

David Hutchens: Thanks Michael.

Operator: As a reminder, everyone, if you wish to ask a question, please press star followed by the number one on your touchtone phone. The next question we have is from Dariusz Lozny with Bank of America. Please proceed with your question.

Dariusz Lozny: Hey, good morning. Thank you for taking my question. Just to maybe follow up on the Q1 EPS drivers that you guys reported, you call out that at both UNS and ITC an increase in the market value of some–it looks like it’s assets and some of your retirement plans as an upside driver for both UNS and ITC. Is there any way to maybe just quantify that, like what proportion of the $0.12 upside that you guys realized in Q1 was related to that mark-to-market impact?

Jocelyn Perry: Yes Dariusz, it is in UNS and ITC. It’s about a penny each in each of those utilities.

Dariusz Lozny: Okay, thank you. Just coming back to the discussion on wholesale sales in both Q1, but also prospectively, it sounded, I think from Jocelyn’s comments earlier, that it might be a negative driver in Q2. I think you mentioned that last year, the majority of those sales were in Q2, so can you maybe just comment on that as far as the shaping of that for the balance of the year? Would you expect that to maybe be a modest negative in Q2?

David Hutchens: Yes, that’s probably too much in the weeds, because the timing quarter to quarter and year over year is different, so I think we did in a couple different quarters last year, and so the two quarters this year, I don’t know if I can pick out of a hat. But overall, we expect it to obviously moderate year-over-year, so we can’t really put that kind of quarter-over-quarter clarity there.

Dariusz Lozny: Okay, fair enough. Thank you very much. I’ll pass it along here.

David Hutchens: Okay, thank you.

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

Stephanie Amaimo: Thank you Brian. We have nothing further at this time. Thank you for participating in our first quarter 2023 results conference call. Please contact Investor Relations should you need anything further. Thank you for your time, and have a great day.

Operator: Thank you for participating. This concludes today’s conference call. You may now disconnect.