Southwest Gas Holdings, Inc. Aktie

Welcome to Southwest Gas Holdings' Third Quarter 2026 Earnings Conference Call. Today's call is being recorded and our webcast is live. A replay will be available later today and for the next 12 months on the Southwest Gas Holdings' website. [Operator Instructions].

I will now turn the call over to [ Mr. Will Batista ], Director of Investor Relations, Sustainability and Stakeholder Engagement. Please go ahead.

Thanks, Kelsey, and good morning, everyone. We appreciate you joining the call this morning. This morning, we issued and posted to Southwest Gas Holdings' website, our third quarter 2026 Earnings release and filed the associated Form 10-Q. The slides accompanying today's call are also available on Southwest Gas Holdings website. We'll refer to those slides by number throughout the call today.

Please note that on today's call, we will address certain factors that may impact 2026 earnings and discuss longer-term guidance. Information that will be discussed today contains forward-looking statements. These statements are based on management's assumptions on what the future holds but are subject to several risks and uncertainties, including uncertainties surrounding the impact of future economic conditions, regulatory approvals and capital projects. This cautionary note and a note regarding non-GAAP measures are included on Slides 2 and 3 of this presentation, in today's press release and in our filings with the Securities and Exchange Commission.

We encourage you to review each of these disclosures. These risks and uncertainties may cause actual results to differ materially from statements made today. We caution against placing undue reliance on any forward-looking statements, and we assume no obligation to update any such statements. As shown on Slide 4, on today's call, we have Justin Brown, President and CEO; and Justin Forsberg, Chief Financial Officer and Treasurer. Other members of the management team are also available to answer your questions during the Q&A portion of the call today, if necessary.

I will now turn the call over to Justin Brown.

Thanks, Will. Good morning, everyone, and thank you for joining us today. Beginning on Slide 5, we delivered strong third quarter and year-to-date results while continuing to execute on our regulatory and growth priorities. Reported adjusted earnings per share from continuing operations of $0.20 compared with $0.06 in the third quarter of 2025, and year-to-date adjusted earnings per share from continuing operations of $2.69, which is up 18% from the same period last year. The improvement was primarily driven by constructive regulatory outcomes and disciplined cost management as we remain focused on delivering on our 2026 strategic priorities and key initiatives. Based on our current expectations, we are reaffirming our 2026 adjusted EPS guidance of $4.17 to $4.32 per share and our 12% to 14% long-term adjusted EPS growth target.

In Arizona and Nevada, we are working to better align cost recovery with the pace of our investments, which benefits customers and investors alike. Importantly, our plan does not depend on any single outcome as we have multiple credible paths to our objectives regardless of how individual cases may unfold. We remain focused on delivering near-term performance and long-term value that starts with safe, reliable and affordable natural gas service for our customers and extends to supporting economic development across the communities we serve, all backed by disciplined capital investment and cost management.

Turning to Slide 6. We continue to execute on our 2026 strategic priorities and remain on track to deliver on each of our key initiatives. We received final orders in both our California and Nevada rate cases, which together authorized approximately $80 million of incremental annual revenue. In Arizona, staff testimony was constructive, and I will cover it in more detail shortly. At Great Basin, we submitted our FAST 41 draft application for the 2028 expansion project, and we remain on track for the FERC certificate application by year-end and a targeted fourth quarter 2028 in-service date.

On Slide 7, at the utility, we delivered a 12-month ended return on equity of 8% and third quarter O&M expense remained relatively flat on a per customer basis, consistent with our disciplined cost management efforts across the company. We ended the quarter with nearly $700 million of available liquidity after having invested more than $800 million of capital at Southwest Gas at Great Basin so far this year. We delivered these results before realizing the full benefits of our recent regulatory outcomes in Nevada and while Arizona remains pending, underscoring the strength of our underlying business.

With new California and Nevada rates now in effect, and as we work with the parties in the Arizona Commission to bring our case to a close, we expect the associated rate relief to further improve our results as we move into 2027. We continue to see constructive outcomes as we move through our general rate case cycle in California, the final decision on cost of capital was received in August, and this completed our general rate case. The final decision authorized just over $32 million of incremental revenue, a 10% return on equity and a 50% equity ratio with rates effective back to January 1, 2026. A summary of the outcome is shown in the appendix on Slide 26.

Turning to Slide 9. In Nevada, we received a final order on October 14, authorizing nearly $48 million of incremental annual revenue, maintaining our authorized return on equity of 9.5% and an actual equity ratio of 51.35%, up from the 50% in our prior case with rates effective October of 2026. This outcome exceeds the roughly $40 million and 9.3% proposed by the other parties. While we were pleased with several elements of the outcome, we filed for reconsideration of certain post-test year plan that we believe should have been included in rate base and not deferred to a future rate proceeding. If successful, this request could further improve the overall revenue outcome in Nevada.

We also expect the commission to finalize its rules around surrounding alternative ratemaking by the end of 2026 and anticipate making a filing to implement alternative rates by early second quarter 2027. In Arizona, we received intervener testimony and notably, the commission staff recommends $53 million to $58 million of incremental annual revenue, depending on the treatment of the fair value increment, and a 9.75% return on equity. Staff also supports post test-year plant subject to in-service verification and most notably, our proposal to transition to formula rates with some modifications.

Our rebuttal testimony was filed November 2, and we updated our request to $91.3 million in annual revenue to reflect updated post-test year plant estimates and cash working capital assumptions as well as other minor adjustments and corrections to our original filing of $101 million. Additional testimony is due by the end of November, and the hearing is scheduled to begin December 7, with anticipated rates becoming effective April 1, 2027. Our formula rate proposal would provide an annual rate adjustment beginning 1 year after new base rates take effect with a 20 basis point dead band above and below the authorized return on equity and would replace several existing mechanisms. Staff supports the mechanism with some modifications to the dead band, proposing a 50 basis point dead band, and proposing some adjustments to our proposed timeline for the first filing, as well as recommending the lower end of their ROE range, while RUCO just opposes it in its entirety. And we address each of these positions in our rebuttal testimony.

Collectively, these proceedings strengthen earnings visibility, support timely recovery of prudent investment and advances our focus on reducing regulatory lag while providing rate stability for our customers. Across all 3 states, the strategy is the same: Pursue timely, constructive outcomes that align cost recovery with the pace of our investment.

Turning to Slide 11. We continue to advance our Great Basin 2028 expansion project and preparation of our FERC certificate application remains on track for filing by year-end. Recent progress includes filing key draft resource reports submitting our draft FAST 41 application, conducting field surveys and public outreach and advancing engineering and design work. Shippers have executed binding precedent agreements and posted surety supporting 1 Bcf per day of contracted demand and upon FERC approval of the certificate, they are required to execute transportation service agreements with a minimum term of 20 years.

Based on that contracted demand, we expect the project's estimated $2.3 billion investment to generate approximately $270 million to $300 million of incremental annual margin beginning at the expected fourth quarter 2028 in-service date. Because this is a cost of service project, the 1 Bcf per day already under contract is expected to fully support that margin estimate. As a reminder, $600 million of the $2.3 billion estimate along with the associated incremental margin is not reflected in our long-term guidance. We don't expect the updated estimate to materially affect our 2026 capital expenditure guidance, and we will update long-term guidance with our annual 5-year plan in February.

Importantly, the current 48-inch pipe design will serve the contracted 1 Bcf per day and can accommodate greater throughput with relatively modest additional investment depending on shipper specifications. As such, additional demand served within that current design capacity is expected to lower the rate for all shippers subscribed to the 2028 expansion project. Capital spending is expected to be approximately 15% in 2026, 25% in 2027 and 60% in 2028, as shown on the slide. We anticipate a decision on our CPCN filing in late 2027 and AFUDC is expected to be capitalized into project costs and contribute to future invested capital upon placement into service. We remain focused on executing the project safely, efficiently and in a manner that supports long-term value creation.

I will now turn the call over to Jay Fors to discuss our financial performance, expected financing plans and our guidance outlook in greater detail.

Thank you, Justin. Turning to the EPS walk on Slide 13. The quarter-over-quarter improvement at Southwest Gas was operationally driven by improved rates as well as customer growth. Lower interest expense at the holding company also contributed to the increase. While the third quarter tends to be our lowest earnings period, the earnings growth continues to support the benefits of our simplified fully regulated natural gas business model as well as our disciplined focus on cost management, regulatory improvement and purposeful capital allocation.

On Slide 14, you'll see the key drivers of the quarter-over-quarter change in Southwest Gas's adjusted net income, comparing the third quarter of 2026 to the same period in 2025. Operating margin increased $3.8 million, driven primarily by updated rates in California as well as customer growth, which remains steady across our service territories despite a prolonged higher interest rate environment. We also saw the margin benefits from the Arizona System Integrity mechanism capital tracker. These and the other increases in recovery, return on regulatory account balances were partially offset by lower billed margin across Arizona and Nevada attributable to non-decoupled customers, as well as lower margin related to the Nevada VIER mechanism, the impact of which is offset in net interest deductions.

Our team continues to deliver disciplined cost management. Year-to-date, O&M is relatively flat, and we expect our continued focus on operational efficiency to help us achieve our goal of maintaining flat O&M expense per customer at the utility over our 5-year plan. Depreciation and amortization increased by a net $1.8 million. The increase mostly reflects a 7% increase in gas plant and service compared to the third quarter of 2025. Partially offsetting the higher depreciation expense was an adjustment related to certain regulatory assets to more closely align the return on those assets with the time period over which those costs have been deferred. The increase in plant and service is consistent with our disciplined infrastructure investment strategy focused on safety, reliability and customer growth.

Lower net interest deductions primarily related to lower amounts incurred on over collected PGA balances for Nevada, as well as recoveries associated with the Nevada VIER mechanism I mentioned earlier, offset in margin, also benefited results by $4.9 million. Although other income was flat, lower non-service pension-related income and lower interest income were nearly fully offset by higher COLI gains and an increase in AFUDC equity, driven mostly by capital investment in Great Basin's 2028 expansion project. Finally, even though adjusted earnings were higher, we had a net income tax benefit driven mostly by the lower deferred state income taxes. Overall, we remain confident that we are on track to achieve our full year outlook.

Turning to Slide 15. I'll discuss our financing plans. We are in a strong financial position utilizing strategically sourced liquidity to support future growth. We have yet to issue any equity outside of our Dividend Reinvestment Plan so far in 2026, and we continue to anticipate no equity issuances for the remainder of this year. We currently plan issuing debt at the utility this year, which we anticipate sizing as needed to support liquidity and capital allocation priorities. Our strong liquidity across the company provides us with flexibility to optimize external financing sources across the enterprise as we navigate a relatively volatile interest rate market.

Additionally, we have wide flexibility in terms of tenure as we monitor borrowing costs across the yield curve and evaluate laddering maturities against our current debt maturity profile. Recall that our 5-year plan includes a mix of leverage capacity at the holding company, utility bond issuances and modest ATM usage to finance our growing $6.3 billion capital plan, and we intend to optimize the lowest cost source of funds when prudent. Later this month, when we extend the shelf registration, you'll see us update and extend our existing at-the-market equity program while retaining its capacity at $340 million.

Maintaining ATM capacity remains a prudent financing tool and should not be interpreted as a change in our current financing expectations. We continue to only expect modest external equity needs to fund our capital plan, and we do not anticipate needing to draw meaningfully on the ATM through the end of our current planning horizon. Our highly flexible and well-capitalized balance sheet positions us well to fund future growth. Over the long term, we continue to believe we have sufficient leverage capacity at the holding company to absorb much of the anticipated equity needs of the utility that are driven by our capital plan. Supported by a meaningful cushion above our current downgrade thresholds, we retain considerable flexibility in how we finance investment while preserving our financial strength.

Briefly on Slide 16, at the end of the third quarter, consolidated net debt was approximately $3.7 billion when considering the purchase gas adjustment balances that are payable to customers. We maintained investment-grade ratings with stable outlooks across the enterprise. We continue to target consolidated S&P FFO to debt above 17% over time, as the significant margin growth from the investments we are making are expected to support even further strengthening of the balance sheet as well as potential capital reinvestment opportunities.

Finally, on Slide 17, based on current visibility, we are reaffirming our 2026 adjusted EPS guidance expectations to center around the midpoint of the range of $4.17 to $4.32. In addition, we are reaffirming 2026 capital expenditures and our long-term guidance metrics and drivers. As noted, those long-term metrics reflect $1.7 billion of Great Basin capital through 2030 and do not yet incorporate the updated $2.3 billion project estimate. We intend to include the full estimate when we roll forward our 5-year capital financing, rate base and earnings assumptions this coming February.

The successful execution of our current 5-year capital program would nearly double our system-wide rate base from today by the end of 2030. Taken together, we believe our year-to-date results, on track plan execution and the continued commercial interest in Great Basin's expansion opportunities reinforce the durability of our plan. We remain confident in our ability to deliver on our long-term financial objectives of receiving timely recovery of investments, improving earned returns and preserving balance sheet strength. The progress we have made this year reinforces our confidence in achieving our long-term objectives regardless of the timing of individual regulatory outcomes. We remain committed to prudent capital allocation and to supporting long-term value creation for stockholders.

With that, let's open the line for your questions.

[Operator Instructions] Your first question comes from Constantine from Wells Fargo.

Maybe just starting off on the Arizona ACC turnover. Do you see any impacts to the current litigated process? And would it be feasible still to get at least a partial settlement on the more straightforward elements, specifically as we look at the formula rates backdrop?

Yes, Constantine, it's Justin. I think it's a good question. Obviously, the election was yesterday. I don't think they've called it, but things directionally appear to be the turnover, like you mentioned. I don't see how that would have any impact on the litigation itself that you referenced. And then I think the commission turnover, again, I think the consistent thing there is the staff and our working relationship with the staff. And so I think our prospects around settlement or working with the staff and the parties is the same regardless of elections and different things.

I mean that's the one consistent that we do know about Arizona is, they do have elections every 2 years, and we manage our business accordingly in a very measured way, and focus on our working relationship with the underlying parties like the staff and the consumer advocate.

Excellent. Understood. And maybe shifting to the overall progress on the regulatory matters year-to-date. How are you thinking about the kind of gross margin drivers in the context of '27? California and Nevada are kind of known. Arizona is progressing? And any way to frame kind of the net ROE lag with the new rates? Anything structural kind of that you would call out that still remains?

This is Justin Forsberg, Constantine. Thanks for the question. I think when we think about margin, obviously, we have California, Nevada behind us, and so we kind of have -- we have line of sight or clarity for the impact on 2027 in those states. Especially when you think about Nevada, just as a reminder, we plan on filing for formula rates, which will not necessarily impact 2027. It's more of a further out impact on that potential adjustment. And then I think the risk that's left is really Arizona, as we talked about just a second ago, right, we were expecting if we have a hearing in December, we're expecting a final decision sometime early next year with rates effective in our plan by April. So I think from that perspective, that's kind of how we think about margin improvements on the regulatory side for next year.

Okay. And then just to clarify with the timing between Nevada and Arizona, those would kind of roll in '27, '28, kind of towards the full kind of margin contribution from the improvement, right?

Yes. As far as the margin contribution, full run rate, yes, you're exactly right. Like Nevada run rate would be '27. Arizona would be a partial year, '28, and full or '27, full run rate '28, with formula rate or alternative ratemaking adjustments currently expected mid-28.

And your next question comes from Elias Jossen from JPMorgan.

Maybe sticking with Nevada, obviously we saw the governor seat flip, so just wanted to get a sense of where you guys are in the rulemaking process and how to think about, if there are any implications to consider in the state there more broadly?

Eli, it's Justin Brown. We are still working through the regulations at the PUCN, and so they had issued draft regulations in May. They received feedback and comments on those. We anticipate them issuing a new draft and hopefully voting on it by year end. We don't see the governor’s race really impacting that process. We would anticipate -- that's the timeline we’re still thinking about in terms of moving forward with respect to those regulations. And as J-Ford just mentioned, the timing around how we’re thinking about a formula rate or an alternative rate-making proposal in Nevada and when that would show up in rates. We’re still targeting middle of 2028.

I know you said the ACC race isn't called, but I guess if outcomes were to hold, and the commission is clearly moving towards Democratic base, and if we think about the timeline into next April for rate finalization, what are the kind of key items for us to monitor in next year? If there’s any historical precedent for this kind of timeline with the commission. I know, again, you still have a majority of Republicans, but just at a high level, thinking about the timeline into next year?

That's a good question, Eli. I think given kind of recent voting record among the existing 5, and really the 3 commissioners that are staying, I would just look for kind of continued consistency in terms of their approach on these different filings. I think you've seen that they've kind of coalesced around approach this year, and it seems like those three have been fairly consistent, and I would look for that consistency to continue into the year. I mean, obviously, when you have 2 new commissioners, we'll see kind of where they end up voting on different matters that come before them. So time will tell on that as cases come up, and we start to see kind of their votes and the rationale for their votes.

But I think the key is looking for the consistency with the 3 that are currently seated, and then just as we move into 2027, we'll be evaluating kind of directionally where the 2 new commissioners, kind of what their perspectives are, what their rationale is, and kind of where they start to place their votes.

Your next question comes from James Ward from Jefferies.

The D&A true-up and the state tax benefit added about $0.12 this quarter. Were those in your plan when you set guidance, and if not, what's offsetting them?

Yeah, it's a good question. I think when we sort of rewind, we do have in our plans, included in our plans, potential items when we think about it, as we do our sort of prompt year numbers. I think I'd have to really think through the magnitude of some of these opportunities that showed up. While that might be a little bit different than what we had in our plan, we do tend to, when we put our plans, we have opportunities that are in front of us that we could look at.

In terms of sort of your question on offsetting, I think we don't necessarily think that there's anything significant going the other direction. I guess other than the PGA is probably returning back to customers a little slower than what we would have anticipated, just simply given weather conditions and volumetric rates. And, so the reduction of our PGA has been a little bit slower, especially in Nevada. So that's probably something that would have been offsetting it the other direction.

In Arizona, if the commission adopts the formula rate at the low end of staff's range, how much would you still expect to see an improvement versus authorized, pardon me, versus the actual earned returns in recent years and -- separate, but related to that, could you live with a 50 basis point dead band like [Indiscernible]?

Yeah, James. I mean, I think we've talked about the dead band in the past. I mean, the policy statement provides for, I think, 20. I think the commissions and the staff's been pretty consistent on their votes around a 50. I think that's still, from our perspective, an improvement over kind of the current historical model, historical test year model, and regulatory lag that exists. So we definitely still think there's improvement there, and regarding that possible outcome, and we'll see how it goes on a go-forward basis.

Obviously, we're proposing the 20 basis point band, and then obviously, that there's circles around whatever ROE you end up getting. Whether you're authorized to, our current 984 and you have the dead band, or if they adjust the ROE to something else, that's just part of the process. No different than any rate case where they set an ROE and authorized ROE, and you're trying to manage your business to get as close to that authorized level as you can.

And your next question comes from Gabriel Moreen from Mizuho.

Maybe if I can ask a couple of Great Basin questions. Can you talk about the FAST 41 application and what that may or may not do for the process in terms of either accelerating it, smoothing it out. And then in terms of that 1.8 Bcf of additional customer interest, can you just talk about where you are, you think, in terms of getting some of that interest across the finish line? And I'm curious also of that 1.8 Bcf a day to what extent that's data centers or other interests like industrial or power gen, not data center related?

Yes, Gabe, it's Justin. On the FAST 41 application, I would think of that as more of like a kind of a transparency and a coordination opportunity. It's a voluntary program where we'll make an application filing. We've submitted a draft application, we'll get feedback. But really, what it does is it doesn't necessarily guarantee things to be faster or it's the same review requirement. It's just more of a coordination among the different permitting agencies. And so it provides greater transparency regarding how that process will go and so greater predictability in terms of the schedule.

And so that's how we're thinking about it. Granted, there could be some efficiency improvements as a result of the coordination, but that's not a guarantee. And then with respect to the additional demand, again, that's something right now, we're really focused on the 2028 expansion and the shippers that have signed up there, and we're continuing to work with those that are looking at capacity beyond that. And we'll continue to that. We continue to receive inbound calls to this day where we get additional inquiries.

I think over time, that will settle in where once we start the process in terms of the FERC filing, maybe even construction around '28, we'll probably get greater clarity around those shippers and kind of what their anticipated time lines are, and then we'll try to call less around a date and look for an announcement sometime in the future regarding kind of what that looks like, what shippers are willing to commit to buy any precedent agreements with surety similar to what we did this last 1.5 years.

And I know you responded earlier to you asked questions on the Nevada governor election as it pertains to, I think, forward rates. Can you talk about it within the context of Great Basin? I don't know to what extent it matters for land acquisition rights away or stuff like that. But maybe can you just -- I know it's early days, but can you speak to that, too?

Yes. I think it's early. It's something we'll obviously keep an eye on. I think when we think about the 2028 expansion, I think a lot of those things are already in motion. And I think given the local of where the shippers primarily are located. I think some of them have already received some of their permits from different state agencies. So I don't really anticipate any change in trajectory around the '28. Obviously, time will tell around the '29 to '35. And those shippers and kind of their appetite for continuing with their projects and things like that. So that's something we'll keep a close eye on as we work with them to firm up their interest.

Your next question comes from Chris Ellinghaus from Siebert Williams Shank.

J-Ford, I heard what you said about the ATM, but could you just repeat sort of what you were saying about equity following that?

Yes. So I was just talking about this housekeeping that will renew the ATM when we renew extend the shelf here in a few weeks. And just wanted to help people understand keeping the size of it the same as expected at $340 million, and our expectations for equity need for equity externally haven't changed. Just trying to help people understand that it's just a housekeeping item. So essentially still when you go back to what we've said previously, still expect relatively modest equity issuances externally of the ATM during the construction timeframe of a Great Basin primarily.

Okay. Great. As far as the Great Basin margin range goes, can you give us some sense of what you're thinking the variables are within the range?

Yes. I think there's a couple of things the way we think about it. Remember that it is a cost of service project, and so the margin really depending on assuming that you don't have significant change in the construction cost. Margins should be relatively similar supported by everyone who signed up today is what we're thinking about the range, we do in our construction. Estimates, we do assume some contingencies in the CapEx numbers. And so that is something that could bring the range, say, a little bit lower if costs end up coming in a little bit lower than what we've estimated in our estimates.

I think when you think about what could raise it much higher, I think it kind of depends on the timing and spending of capital, which would impact your AFUDC numbers, which would then obviously change the total cost of the project as far as rate base goes once you ultimately capitalize that interest and equity from AFUDC could have an impact on the margin. So those are kind of how we think about the range...

Like bottom and top.

So actual spending timing would be an important factor as well.

Yes.

The elections, I guess people have been trying to ask questions around this in various ways. But rather than thinking about the individual personnel or governors or whatever, but just the general swing how -- what happened last night. Do you think that leads to any kind of policy direction that might have any implications at all?

Chris, it's Justin Brown. It's a really good question. I think when we look at our 3 states and based on the changes. I mean, obviously, time will tell, but I don't think there's anything that jumps out to us as a big risk in terms of big swings and policy changes that would affect our day-to-day business.

Your next question comes from Paul Fremont from Ladenburg.

I guess my first question is on the depreciation adjustments to the regulatory assets. Has that spread over a number of states? Is it all in one state? Where would that be?

You can assume it's across our jurisdictions, just really working to line it up with the timing of -- when that -- the intent of those regulatory accounts are deferred -- the costs are deferred over.

And then I guess I would assume that in your next rate filings in, I guess, it would be all 3 jurisdictions that, that would sort of be a pass-through back to customers? Or was there an immediate sort of adjustment to revenue when you adopted the depreciation change?

Yes. I would say it's -- you should probably think of it more as nonrecurring because we're -- essentially, as we align that with the timing of that -- of our allowed deferral. We're essentially -- it's something that you might have waited until you had a rate case outcome in the past to make a true-up adjustment on your finalization. But a higher level way to think about it, Paul, is when you have to make an assessment in the accounting world as to how -- do you believe that you're going to be able to recover the return on those assets that you were allowed to book by the regulators, right?

So from our perspective, the regulators, as we went through and assessed all of our regulatory assets in this case, we believe that we're going to get recovery from the regulators on the returns that they've already allowed us to book on certain regulatory accounts. And so that's just the true up.

And since you've already had 2 rate outcomes in Nevada and California, we would assume that it may be some period of time before you file again in those jurisdictions?

Yes, Paul, it's Justin Brown. Yes, I think a lot of it will probably hinge. Like on California, we have a 5-year rate cycle. And so we are on a 5-year rate cycle absent something unique happening. And so I think you can look at it from that perspective on California. On Nevada, I think largely, it will depend on the timing of the commission issuing the regulations on the alternative rate making. If that happens, we anticipate it happening within sufficient time, but I think we have up to 6 months after our rate case decision to make a filing under those regulations per the legislation. So as long as the regulations are done and we meet that window, we would look to move to more of an alternative rate making model. And as we mentioned, looking make a filing in '27 for rates effective in '28.

If for some reason, that timing doesn't work, then we would look at probably filing another rate case at some point and around that same time line just to kind of stay current with our rates and then at that point in time, transition to an alternative rate. So a lot of it will just depend on the timing of the regulations in Nevada. And I think it's probably fair to look at Arizona the same way. Obviously, we'll get a final decision in the first -- around April of next year, and then we'll evaluate, one, whether we get approval of a formula rate proposal, but then kind of the transition timing and how we think about our rate case. Historically, in Nevada, we've been anywhere from 18 to 24 months from rate case to rate case.

In Arizona, we're kind of on a similar time line of depending on -- if you're looking at from when you file to file, it's been about 2 to 3 years, and then in Nevada, it's been like 1.5 years to 2 years. And so we usually try to keep rates as fresh as possible by making frequent filings.

And then -- given the fact that the 2 commissioners are going to be seated very late in your rate case process, I mean, is there a possibility of a delay in the schedule so that they are able to get sort of up to speed on the issues? Or would you expect the schedule to hold exactly as it is?

Yes, it's a good question. I think if our schedule provided for a draft decision in January for a vote, I think there might be a greater risk. I think looking back over history, sometimes you would see things get moved from January to February to your point. Interestingly enough, in our last rate case, a couple of years ago or maybe 2 rate cases ago, during an election, we had a vote on our rate case in January. Since our schedule is really not January schedule, it's more of a March, April time line. I think that, that probably lessens any likelihood that there would be a delay because the new commissioners would be in their seats for a couple of months.

I think generally speaking, they're kind of expected to be ready to take on their roles and responsibilities when they're seated in January. I think if there is a minor delay, it would be anything that would come up for vote in January that might get pushed to February, but I really don't expect a trickle-down effect beyond that. At least we've never seen it historically.

Last question for me, since the 2 commissioners on the Republican side who lost played a major role in the establishment of the formula rate filings that were approved by the commission. Do you see any potential changes that might come about given the fact that they're no longer -- that they won't be any longer on the commission?

Yes, Paul, I think that's a fair question. I mean, Nick and Kevin were both strong advocates. I would say, though, that they've been very effective just culturally. I mean, you can see where the commission staff has been supportive. I think the other 3 commissioners that are still there have been supportive. We touched on that earlier in terms of them coalescing around kind of different outcomes. And we'll see where whoever ends up getting seated, we'll see kind of where their perspective is on these issues.

I think in Arizona, you always have that kind of situation where -- when you have elections, you have changes. And I think you see things kind of evolve back and forth on different policy objectives. And over time, we'll see how that goes. Clearly, the -- on the formula rate issue, there's 3 commissioners that will still be there, that will have a majority next year around kind of these proposals, and they seem to have been supportive at least most recently. So time will tell. But I think from our perspective, again, we don't anticipate major swings in policy just given the current makeup and where people have been voting more recently.

Your last question comes from Ryan Levine from Citi.

Wanted to touch on Great Basin. It looks like some of the CapEx was moved slightly to be more back-end weighted from your guidance last quarter. Any color as to what drove the change and any impact to timeline?

This is Justin Forsberg, Ryan. Yes, I think there's probably not a lot to read in there. I think when we -- as we go along and continue to refine some of the estimates, as you think about -- at this point in time, we have really mitigated the risk that might have been out there from a supply chain perspective in terms of pipe as well as the compression side of things. And so we have a lot more clarity around the timing of when we might roll pipe and take delivery on those kind of things. And then I think when we think about the construction timeline and try to align expected construction spending with what we're expecting to an EPC contractor to do. It's just some modest refinement, not anything major changing there.

And then Justin, just a follow-up on that in terms of the -- that answer, you suggested that you have more confidence around the supply chain contracts. Is there anything to note around agreements that were assigned or what portion of that cost that's now been secured over the last few months?

No. I think we really secured or signed POs, if you will, a little bit earlier this year or over the summer, et cetera. And I think we are -- there's not a lot has changed there. We feel pretty confident on where we stand with suppliers. As you probably know, it's just important to add that we don't yet have an EPC contractor for the construction phase. We have had early meetings, like an early contractor meeting as far as education Q&A sessions with them, but we have not finished or completed an RFP there for the EPC side.

There are no further questions at this time. Mr. Batista, you may proceed your conference.

Thanks again, Kelsey, and thank you all for joining us today and for your questions. This concludes our conference call. We appreciate your interest in Southwest Gas Holdings and look forward to speaking with many of you soon.

Ladies and gentlemen, this does conclude your conference call for today. We thank you very much for your participation, and you may now disconnect. Have a great day, everyone.

Welcome to Southwest Gas Holdings' Second Quarter 2026 Earnings Conference Call. Today's call is being recorded, and our webcast is live. A replay will be available later today and for the next 12 months on the Southwest Gas Holdings' website. [Operator Instructions]

I will now turn the call over to Tyler Franek, Manager of Investor Relations of Southwest Gas Holdings.

Thank you, Joanna, and hello, everyone. We appreciate you joining the call today. This morning, we issued and posted to Southwest Gas Holdings' website our second quarter 2026 earnings release and filed the associated Form 10-Q. The slides accompanying today's call are also available on Southwest Gas Holdings' website. We'll refer to those slides by number throughout the call today.

Please note that on today's call, we will address certain factors that may impact 2026 earnings and discuss longer term guidance. Information that will be discussed today contains forward-looking statements. These statements are based on management's assumptions on what the future holds, but are subject to several risks and uncertainties, including uncertainties surrounding the impacts of future economic conditions, regulatory approvals and capital projects.

This cautionary note and a note regarding non-GAAP measures are included on Slides 2 and 3 of this presentation in today's press release and in our filings with the Securities and Exchange Commission. We encourage you to review each of these disclosures. These risks and uncertainties may cause actual results to differ materially from statements made today. We caution against placing undue reliance on any forward-looking statements, and we are -- assume no obligation to update any such statement.

As shown on Slide 4, on today's call, we have Justin Brown, President and CEO; and Justin Forsberg, Chief Financial Officer and Treasurer. Other members of the management team are also available to answer your questions during the Q&A portion of the call today, if necessary.

I'll now turn the call over to Justin Brown.

Good morning, everyone, and thank you for joining us today. Beginning on Slide 5, we continued our strong momentum in the second quarter, reporting adjusted earnings per share from continuing operations of $0.45, which is adjusted for the amount of California revenues that had been deferred in a memorandum account since the first quarter. This performance reflects ongoing execution of our regulatory strategy to support the timely recovery of prudent investments as well as materially lower interest expense following the payoff of all outstanding HoldCo debt last summer.

We remain confident in our outlook and are reaffirming our 2026 and long-term guidance ranges. With active proceedings across each of our jurisdictions, our regulatory strategy doesn't depend on any single outcome, giving us multiple credible paths to achieve our objectives regardless of how individual cases unfold or how the political and regulatory environments might evolve. We are focused on both near-term performance and long-term value creation, anchored by our commitment to delivering safe, reliable and affordable natural gas service to our customers, strong stakeholder partnerships and disciplined capital investment and cost management supporting the economic development of the communities we serve.

Turning to Slide 6. We continue to execute on our 2026 strategic priorities and remain on track to deliver on each of our key initiatives. We advanced our regulatory strategy during the quarter, continuing to progress rate case proceedings across all three jurisdictions. I will discuss these proceedings in greater detail in just a moment when we get to Slide 9.

Additionally, during the quarter, we received commission approval on our Nevada Triennial Resource Plan, including prudency predeterminations for $186 million of capital investment, supporting long-term natural gas infrastructure planning and providing greater visibility into future capital investment opportunities to meet customer growth and reliability needs.

We also implemented a surcharge from our first system integrity mechanism filing in Arizona for $50 million of capital that supports the timely recovery of qualifying investments. At Great Basin, we further strengthened the commercial foundation of the 2028 Expansion Project, bringing contracted demand to approximately 1 Bcf per day and revising the project design to reflect the 48-inch pipeline, resulting in both increased capital investment and annual margin estimates for the project. With those milestones achieved, our focus remains on completing the FERC CPCN filing later this year to progress the project toward regulatory approval and execution. I will discuss the project in greater detail later in our presentation.

On Slide 7, at the Utility, we delivered a 12-month ended return on equity of 8.1% or 8% on an adjusted basis, reflecting the continued progress as we work to close the gap to our weighted average authorized return of 9.89%. We delivered these results even while key rate cases remain pending across our service territories, underscoring the strength of our underlying business. As we work with our Commissions to bring each of those cases to a close, we expect the associated rate relief to further improve our results.

Our regulatory strategy around enhancing recovery mechanisms and pursuing constructive rate outcomes across all three jurisdictions is designed to improve our earned returns over time and helps ensure we continue delivering safe, reliable and affordable natural gas service to our customers.

We also continue to benefit from a strong balance sheet and substantial liquidity, ending the quarter with approximately $270 million of cash and nearly $1 billion of available liquidity. Combined with no outstanding HoldCo debt and lower associated financing costs, we believe we are well positioned to fund our long-term capital investment program, while maintaining financial flexibility and delivering value to our stockholders.

Turning to Slide 9 and an update on the progress of executing our regulatory strategy. In California, the Commission's recent decision addressed all items other than cost of capital, providing approximately $40 million of incremental annual revenue and reinforcing constructive regulatory support for our infrastructure investment programs. As part of that decision, we recognized approximately $9.7 million of incremental net income in the second quarter tied to margin that had been deferred in a memorandum account since the first quarter. A final decision on the remaining cost of capital component is currently expected later this month.

In Nevada, we filed certification materials for our general rate case during the quarter, incorporating post-test year plan adjustments through May. That update brought our requested annual revenue increase to approximately $74 million. We recently received intervenor testimony, and we are currently reviewing and preparing our rebuttal position, which will be filed with the Commission next week. The party's testimony converges on a 9.3% return on equity with proposed equity layers in the 50% to 51.35% range, and the average revenue increase recommended by the parties is just under $40 million or about 52% of our request. While a hearing is currently scheduled for later this month, on a parallel path, we have also engaged in constructive settlement discussions. Either way, we are pleased with the progress and the case is progressing toward an effective date of October 2026.

In Arizona, our general rate case is progressing as expected and remains on track for an effective date of April 2027. We anticipate starting to receive intervenor testimony in late September. Across all three states, the strategy is the same: pursue timely, constructive outcomes that align cost recovery with the pace of our investment.

Turning to Slide 10. Great Basin made significant progress on its 2028 Expansion Project during the quarter, further strengthening the project's commercial outlook. Following our most recent open season, we executed additional binding precedent agreements for the 2028 project, bringing total contracted demand to approximately 1 Bcf per day. As we look beyond the 2028 expansion, we continue to see interest in additional capacity totaling at 1.8 Bcf across the region for the 2029 through 2035 time frame, and we continue to work on converting these expressions of interest into binding precedent agreements.

As a result of this strong market demand, we have decided to proceed with a 48-inch pipeline design capable of supporting up to 1 Bcf per day of incremental transportation capacity beyond the currently contracted demand, and we will be able to accommodate additional future demand through compression additions. This design enhancement results in an upward pressure on our capital investment need for the 2028 expansion, which we now estimate at approximately $2.3 billion, resulting in approximately $270 million to $300 million of incremental annual margin upon completion. We plan to incorporate these updates into our long-term capital expenditures, rate base and earnings guidance expectations as part of our annual 5-year planning refresh, which typically concludes in February.

We are focused on a timely filing for FERC approval to ensure we meet the expected in-service date and our preparations remain on track, including environmental work, field surveys, public outreach and engineering development. We continue to target a filing before the end of the year, CPCN approval in late 2027 and a fourth quarter 2028 in-service date with the recent increase in contracted demand not expected to impact the project's regulatory schedule. Overall, we are encouraged by the strong commercial momentum behind the project and believe it represents a compelling long-term growth opportunity for Great Basin and our stockholders.

And with that, I will now turn the call over to Jay Foer to discuss financial performance, expected financing plans and our guidance outlook in greater detail.

Thank you, Justin. Turning to Slide 12. Adjusted earnings per share from continuing operations increased to $0.45 in the second quarter of 2026 compared to $0.37 in the second quarter of 2025. The increase was driven by strong performance at HoldCo, partially offset by slightly lower utility earnings, which were mostly driven by lower other income that was expected in our plan.

Reported earnings per share from continuing operations were $0.58, reflecting revenue recognized from the California rate case approved during the quarter. For comparability, adjusted earnings excluded the portion of revenue recognized retroactively for the first quarter due to the delayed rate case approval.

At HoldCo, earnings improved significantly as a result of the repayment of all outstanding parent level debt, which reduced interest expense by approximately $8.6 million compared to the prior year period. Results also benefited from higher interest income earned on elevated cash balances, reflecting the strength of our balance sheet and overall liquidity position.

Turning to Slide 13, you'll see the key drivers of the quarter-over-quarter change in Southwest Gas's adjusted net income compared to the second quarter of 2026 -- comparing the second quarter of 2026 to the same period in 2025. Operating margin increased by $12.7 million, driven primarily by $6.7 million of incremental margin from rate relief, while continuing customer growth contributed an additional $1.4 million. Customer growth remains resilient across our service territories despite a prolonged higher interest rate environment. Also contributing to the increase in operating margin was $4.9 million of net recovery-related items that are offset by a comparable increase in depreciation and amortization, highlighting the strength of our regulated recovery model.

Our team continues to deliver disciplined cost management, demonstrated by lower operations and maintenance expense, which declined by $3.7 million or nearly 3%. We saw lower outside services, bad debt expense and lease and rental costs. We expect our continued focus on operational efficiency to deliver our goal of maintaining flat O&M expense per customer at the utility over our 5-year plan.

Depreciation and amortization increased $8.7 million, primarily reflecting a 7% increase in gas plant in service compared to the second quarter of 2025, combined with modestly higher regulatory amortization expenses that are offset by equivalent increases in margin, as I mentioned earlier. The increase in plant in-service is consistent with our disciplined infrastructure investment strategy focused on safety, reliability and customer growth.

As was largely expected, other income declined by $9.4 million, driven primarily by lower interest income at the utility associated with lower cash balances relative to the prior year, lower gains from nonservice pension components, weaker COLI investment performance, the absence of a prior year gain on sale and higher charitable contributions as the 2025 contributions to the Southwest Gas Foundation were made in 2024. These planned decreases were partially offset by an increase in AFUDC equity, driven mostly by capital investment in Great Basin's 2028 Expansion Project.

Finally, even though adjusted earnings were modestly lower, income taxes were modestly higher, driven mostly by the impact of excess accumulated deferred income taxes and the impact of nondeductible executive compensation. Overall, we are pleased with our performance in the first half of the year and remain confident we are on track to achieve our full year outlook.

Turning to Slide 14, we outline our expected financing plan for the remainder of the year. We remain in a strong financial position with intentional liquidity being utilized to support anticipated future growth. We have yet to issue any equity outside of our dividend reinvestment plan so far in 2026, and we continue to anticipate no equity issuances this year with the remainder of our financing plan consisting of a utility level debt issuance.

In addition to this anticipated bond issuance of $400 million, over the remainder of the year we have some financing housekeeping items that we plan to execute. When we extend the shelf registration later this year, you'll see us update and extend our existing at-the-market equity program while rounding out its capacity in line with the shelf extension. This is a routine renewal tied to the shelf time line and is not a signal of near-term issuance.

We continue to expect only modest equity needs to fund the now expanded Great Basin 2028 Project, and we do not anticipate needing to draw meaningfully on the ATM through 2030. Looking ahead, our strong balance sheet positions us well to fund future growth. Over the long-term, we continue to believe we have sufficient leverage capacity at the holding company to absorb much of the anticipated equity needs at the utility that are driven by our $2.3 billion Expansion Project. Supported by meaningful cushion above our current downgrade thresholds, we retain considerable flexibility in how we finance that investment while preserving our financial strength.

Turning briefly to Slide 16, this slide highlights that balance sheet strength and credit profile. At the consolidated level, we ended the quarter with approximately $3.4 billion of net debt after considering the purchased gas adjustment balances that are payable to customers. Both Holdings and the Utility continue to maintain strong investment-grade ratings across all three agencies with stable outlooks, most recently reaffirmed by Fitch in July, following last fall's upgrades by S&P and Moody's affirmations last April.

Turning to Slide 17. We are reaffirming our 2026 guidance metrics. We also remain confident in our long-term guidance shown on the slide. As Justin outlined, with respect to Great Basin, we do not expect our capital expenditures and rate base forecast to likely increase -- we do expect our capital expenditures and rate base forecast to likely increase once we roll out our 5-year plan next February, given the continued economic development opportunities in northern Nevada. We expect to fold in our updated margin assumptions into our long-term guidance at that time as well.

The updated scope of Great Basin's 2028 Expansion Project is not expected to have a material impact on our 2026 guidance metrics. And for now, the additional $600 million of expected CapEx related to that 2028 expansion as well as the impact of any future expansion phases has not yet been incorporated into our current long-term outlook.

With respect to CapEx, we are on track to invest approximately $1.25 billion in 2026 and to make significant investments over the next 5 years focused on safety, reliability and system growth. With year-end 2025 rate base of $6.7 billion, this plan currently supports an expected rate base CAGR of 9.5% to 11.5% through 2030. The successful execution of our current 5-year capital program would nearly double our system-wide rate base from today by the end of 2030.

Taken together, we believe today's results and the continued momentum at Great Basin reinforce the durability of our plan. We remain confident in our ability to deliver on our priorities, supporting timely recovery of prudent investments, improve earned returns and protect the strength of our balance sheet. And we remain confident in our ability to deliver our long-term financial objectives of receiving timely recovery of investments, improving earnings -- earned returns and preserving that strength. We believe we have multiple pathways to achieve our goals across a range of regulatory outcomes and political environments. We remain committed to prudent capital allocation and to supporting long-term value creation for stockholders.

With that, let's open the line for your questions.

[Operator Instructions] We take our first question from Constantine Lednev with Wells Fargo.

Maybe starting on the Great Basin update, great news there, obviously. In terms of compression and incremental demand, do you still see the incremental capacity bids post-2030? And would you aim to handle kind of that 1.5 Bcf that you highlighted before through compression? Or should we be thinking about any other changes in demand?

Yes, Constantine, it's Justin Brown. Yes. So as we mentioned, we've had expressions of interest up to 1.8 additional Bcf through that time period 2029 through 2035. And so we'll continue to work with those expressions of interest. And as those become binding agreements, that will help us get greater clarity around kind of what potential cost there might be, what compression needs there are. But we feel comfortable given the underlying design of the pipe that we can accommodate that future demand through compression.

Okay. That makes sense. And you kind of mentioned it a little bit there, just to clean up. In terms of the capital intensity kind of beyond 2030 on that, how would that scale versus the current 2 Bcf design?

Yes. It really will just depend on what binding precedent agreements are -- get associated with that incremental interest that we've been receiving. So it's really kind of a to-be-determined.

Okay. Understood. And then one quick follow-up just on the Arizona side, just recognizing that it's still early innings in the rate case, but is there any pressure points you kind of anticipate in the process? Do you see focus shifting kind of to the new formula constructs? Or would it be feasible to have at least a partial settlement or on the more straightforward elements?

Yes. I think it's a really good question. I think we always -- every time in each of our cases, we really focus on working collaboratively with the staff and the stakeholders to try to find opportunities to streamline the case where we can reach agreement. And so while it's still a little bit early in Arizona, I mean, that's the same approach we're going to take as we start to see and as the parties start to refine their positions. As we get close to getting their testimony at the end of the month, we will then look to work with the parties on areas of common ground and try to streamline the case, and we'll see how it goes. So more to come definitely over the next 30 to 60 days.

Next question from Eli Jossen with JPMorgan.

Maybe just thinking about some of the associated CapEx for Great Basin. I know you obviously hiked a bit here. How should we think about equity needs? I mean, is it kind of a basic $600 million, 12% ROE, 50% equity layer? Or like what was the kind of implied math? And how does that translate into future equity needs?

Yes. So I think as we kind of outlined, from an equity perspective, we're really feeling pretty confident in spite of the additional CapEx pressure that we have pretty significant capacity at the holding company, given just where we're at above our downgrade cushions, et cetera. And as you think about even the time line, right, we're spending that money really over the next couple of years. And then we're planning to get pretty significant margin out of the project that you could use to reduce that leverage that you might have taken out of the holding company. So from that perspective, we feel like there's a very clear path to leaning into some of that capacity, reducing the equity needs that are from external shareholders and -- while at the same time, just not necessarily stressing our balance sheet too significantly.

Got it. And you touched on it a bit, but just thinking about the incremental expressions of interest, I know we were at 1.5 or so before. Now we're up to 1.8. Can you just talk about kind of the demand environment and what you're seeing from some of the potential customers on this pipe? Where is that coming from? And do you think there's even more in the hopper as you move through the decade?

Yes, Eli, it's Justin. I would say it's very similar to the demand that we've been describing along the way in terms of a variety of different industries, primarily driven by data center development, power gen, but there's also different industries in the area, mining, manufacturing. And so we feel good about it. Every time we've posted an open season, we continue to be surprised with how much additional demand continues to show up. So we feel really good about the regional economics and the attractive area of this part of the state for this type of development and it's continuing to provide robust opportunities for us to either secure this interest through binding precedent agreements or to remarket capacity down the road. And so it's something we feel good about in terms of looking at the demand and the interest that's there.

Your next question comes from Ryan Levine with Citi.

How is the 48-inch pipe decision impacted supply chain decision-making and more broadly, is your cost structure around the pipe really set in stone with the exception of the compression? Or any color you could share on that?

Yes, Ryan, it's Justin. I think when we think about the pipe, it's something we've talked about previously where we were working very closely with the supplier early on, on the ability to pivot from the 42 to 48. And so we don't anticipate any supply chain issues there. It's something we always felt comfortable early on with the ability to kind of flex on that depending on the market demand that shows up.

And when we think about cost, yes, it's still -- I mean, we feel pretty good about where our cost estimates are. It's something that we exercise a lot of discipline around. We work very closely with our suppliers, our contractors to where we feel pretty good about that being in the range. And then as you mentioned, as we think about future demand, obviously, the scalability of that will depend on what compression needs we have to meet future binding precedent agreements.

Okay. And then second question, any color you could share around the SB 417 rulemaking conversations and where we are in the process?

Yes. So the Commission back in May had issued a draft. Parties have filed comments in response to that, and the Commission has not yet taken any further action on it. So it's still kind of on a wait-and-see mode in terms of where we are on the rulemaking and any updates to kind of the draft regulations and ultimately Commission approval.

This concludes the Q&A portion of today's conference. I would now like to turn the call back over to Tyler Franek for closing remarks.

Thanks again, Joanna, and thank you all for joining us today and for your questions. This concludes our conference call. We appreciate your interest in Southwest Gas Holdings and look forward to seeing many of you soon.

This concludes today's Southwest Gas Holdings' Second Quarter 2026 Earnings Call and Webcast. You may disconnect your lines at this time. Have a wonderful day.

Welcome to the Southwest Gas Holdings First Quarter 2026 Earnings Conference Call.

Today's call is being recorded, and our webcast is live. A replay will be available later today and for the next 12 months on the Southwest Gas Holdings website. [Operator Instructions]

I will now turn the call over to Tyler Franek, Manager of Investor Relations of Southwest Gas Holdings. Please go ahead.

Thank you, Sheen, and hello, everyone. We appreciate you joining the call today. This morning, we issued and posted to Southwest Gas Holdings website our first quarter 2026 earnings release and filed the associated Form 10-Q. The slides accompanying today's call are also available on Southwest Gas Holdings' website. We'll refer to those slides by number throughout the call today.

Please note that on today's call, we will address certain factors that may impact 2026 earnings and discuss longer-term guidance. Information that will be discussed today contains forward-looking statements. These statements are based on management's assumptions on what the future holds, but are subject to several risks and uncertainties, including uncertainties surrounding the impacts of future economic conditions, regulatory approvals and significant capital projects. This cautionary note and the note regarding non-GAAP measures are included on Slides 2 and 3 of this presentation in today's press release and in our filings with the Securities and Exchange Commission. We encourage you to review each of these disclosures. These risks and uncertainties may cause actual results to differ materially from statements made today. We caution against placing undue reliance on any forward-looking statements, and we assume no obligation to update any such statement.

As shown on Slide 4, on today's call, we have Karen Haller, President and CEO of Southwest Gas Holdings; Justin Brown, President of Southwest Gas Corporation and incoming President and CEO of Southwest Gas Holdings; and Justin Forsberg, Chief Financial Officer and Treasurer of Southwest Gas Holdings. Other members of the management team are also available to answer your questions during the Q&A portion of the call today, if necessary.

I'll now turn the call over to Karen.

Good morning, everyone, and thank you for joining us today.

Beginning on Slide 5, we had a solid start to the year, reporting first quarter earnings per share from continuing operations of $1.91, driven by continued growth, the positive impacts of certain regulatory outcomes and significantly lower interest expense following last summer's payoff of all of the debt that had been outstanding at Holdco. As we await the final decision on our California general rate case, we remain optimistic about the company's outlook and are affirming our 2026 and long-term guidance ranges. While the pending California decision impacted the first quarter, a CPUC decision is expected sometime this year and is not expected to affect our full year 2026 guidance.

We expect our approved recovery tracking mechanism will allow us to recognize the final amount of revenue determined in the case dating back to January 1 of this year. We remain focused on near-term performance and longer-term outlook, anchored by our commitment to delivering safe, reliable, and affordable natural gas service to our customers and guided by our partnership-driven approach with regulators and other stakeholders as well as our approach to disciplined capital investment and cost management supporting the growth of the communities we serve.

Turning to Slide 6. We made meaningful progress across our strategic priorities during the quarter. We advanced our regulatory strategy with rate case filings in our 2 largest jurisdictions, requesting a combined revenue increase of approximately $172 million. In Arizona, we filed a general rate case that included a request for a formula rate mechanism designed to help mitigate regulatory lag. We also filed in Arizona, our first system integrity mechanism capital tracker, which allows for more timely collection of a portion of the safety and reliability-related capital we spent in the state last year.

In Nevada, we filed a general rate case and look forward to the PUCN final order in the rule-making proceeding that will establish the state's alternative ratemaking framework. Nevada regulators approved our triennial resource plan, reducing regulatory risk for the preapproved list of projects. The plan included prudency, predeterminations for approximately $225 million of capital investment. Additional detail on the Nevada resource plan is included in the appendix on Slide 29.

At Great Basin, we completed an open season for the 2028 expansion project. where we received bids totaling 2.5 billion cubic feet per day of incremental capacity with requests for service ranging between 2028 and 2035. We're encouraged by the continued interest for natural gas in the area and are now working with shippers to convert interest into binding precedent agreements. Justin Brown will discuss the expected impact of the open season and the status of the 2028 expansion project in more detail later in the call.

Turning to Slide 7. We believe the company is moving into the future in a strong position with significant liquidity and a fortress balance sheet, allowing an increased dividend payout balanced with financial flexibility to execute a $6.3 billion capital plan over the next 5 years. Customer growth at Southwest Gas remains strong, supported by S&P's projected population growth in Arizona and Nevada of nearly 5% from 2026 through 2031. While the constructive direction toward formula rate mechanisms in both Arizona and Nevada are expected to improve our ability to deliver returns much closer to those allowed in those jurisdictions for years to come.

Before I pass the call over to Justin Brown to further discuss our regulatory jurisdictions and demand dynamics, which we are experiencing in the Northern Nevada region served by Great Basin, I want to share how excited I am to turn the company's leadership over to him. He is a strong values-driven leader well positioned to guide the company forward.

Over to you, Justin.

Thank you, Karen, and congratulations again on your retirement and a successful career.

Let me begin with an update on our pending California rate case that Karen mentioned. While the final decision has been delayed, we have an approved memorandum account that preserves the full year benefit to earnings as if new rates were effective January 1 of this year. While the delay of the final decision has created a timing shift in first quarter results, we expect this timing shift to self-correct with the previously approved memorandum account, and we do not expect any impact to full year 2026 results due to the delayed final decision. We are also seeing progress on the case as we've received a draft decision yesterday that approves the proposed settlement, but defers the final decision on the cost of capital issues, which was the unsettled portion of the case to a separate decision that has not yet been issued.

As a reminder, we reached a settlement with the Public Advocates Office on all issues with the exception of cost of capital, representing approximately $39 million or nearly 90% of our requested revenue increase before any adjustments to our proposed cost of capital. The draft decision approving the settlement agreement is currently on the commission's May 14 agenda.

Turning to Slide 9. We recently filed a general rate case in Arizona requesting a $101 million revenue increase, supported by a proposed rate base of approximately $3.9 billion. This reflects the roughly $900 million of incremental investments we've made for the benefit of our customers since our last rate case. We also requested an annual rate adjustment mechanism that will transition us to a more constructive cost recovery model, which is consistent with the commission's policy statement on formula rates and better aligns rates with the cost of service we provide. If approved, we expect implementation of the rate adjustment mechanism approximately 12 months following the effective date of new rates from our rate case. Overall, we believe the requests are designed to ensure customers continue to receive safe and reliable service while enabling ongoing investment in infrastructure that supports growth, resiliency and long-term value for the Arizona communities we serve.

On Slide 10, we recently filed a general rate case in Nevada requesting a $71 million revenue increase anchored by our proposed rate base of approximately $2.4 billion, which includes roughly $600 million of incremental investments since our last rate case that is representative of our commitment to meeting the needs of our customers and the communities we serve by ensuring our system is operating safely and reliably. Under Nevada's statutory 210-day time line, we expect intervenor testimony in the third quarter, followed by hearings and a final decision in October with new rates effective in the fourth quarter, subject to the commission's final approval.

In parallel, the rule-making process for alternative ratemaking under SB 417 continues to advance with constructive stakeholder engagement. The expected outcome has the potential to enhance regulatory mechanisms and reduce lag over time for the benefit of our customers and the company. We anticipate the rule-making will be completed in time for us to begin the regulatory process later this year for making a proposal with the commission to utilize alternative ratemaking. We are optimistic about obtaining constructive outcomes in each of these proceedings that will position us to improve earnings visibility, support continued investment and deliver long-term value for both customers and shareholders.

Turning to Slide 11. We continue to advance the 2028 Great Basin expansion project and remain on schedule across engineering, regulatory and commercial milestones. Importantly, our recent open season for available capacity was significantly oversubscribed. We offered just over 0.3 billion cubic feet per day of capacity and received bids totaling approximately 2.5 billion cubic feet per day or nearly 8x the available design capacity. This strong level of interest included not only requests for 2028 and 2029 service dates, but also meaningful demand for phased-in capacity extending through 2035. We are now focused on converting the strong open season interest into binding precedent agreements for the various in-service periods ranging from 2028 to 2035.

As a reminder, following our open season last year, we executed precedent agreements totaling nearly 0.8 billion cubic feet per day, following a shipper's withdrawal from the project, about 0.6 billion cubic feet per day remained under signed and secured contracts. Following the completion of our design work, we determined that the project can efficiently deliver nearly 1 billion cubic feet per day at an estimated cost of $1.7 billion, leaving the 0.3 billion cubic feet per day of available capacity we recently marketed.

We will continue to evaluate system requirements as commercial milestones are achieved, but we do not expect changes to our current capital assumptions for the project if total 2028 and 2029 contracted demand settles at or below the current 1 billion cubic feet per day design. However, if contracted demand materially exceeds that amount, we will need to reconsider current design assumptions, including pipe sizes and/or compression needs, which would likely result in changes to previously disclosed capital investment and margin estimates.

From a regulatory standpoint, we continue to expect to file our formal certificate application before year-end with FERC and NEPA review during 2027, with construction to commence following FERC approval, and we still plan to meet our expected in-service date in late 2028. Overall, we believe the strong level of demand and scalability of this project positions our Great Basin assets as a significant long-term growth platform for the company.

With that, I'll turn the call over to Justin Forsberg, who will review our financial performance for the quarter.

Thank you, Justin. Slide 13 shows our progression from earnings per share from continuing operations of $1.86 in the first quarter of 2025 to $1.91 in the first quarter of 2026. At the utility, we delivered solid underlying performance, driven primarily by rate increases in Arizona and continued customer growth. While our first quarter results do not yet reflect the expected revenue benefit from the pending California rate case, our overall utility performance was strong. We recorded the impacts of higher depreciation associated with ongoing capital investment despite not yet having the corresponding California rate recovery we expect later this year.

Our guidance assumes full retroactive recovery, and we continue to expect a decision during 2026. At the holding company level, results improved meaningfully, driven by lower interest expense following the payoff of all parent level debt as well as higher interest income on elevated cash balances. This improvement was partially offset by higher income taxes resulting from higher pretax earnings and the impact of state net operating loss utilization assumptions that is not expected to recur.

Turning to Slide 14. I'll highlight the key drivers of the quarter-over-quarter change in Southwest Gas' net income comparing the first quarter of 2026 to the same period in 2025, unless otherwise noted. Operating margin improved by $15.1 million, driven primarily by rate relief, particularly in Arizona and continued customer growth, which contributed $3.1 million. Net customer growth of 1% over the past 12 months reflects strong underlying demand across our service territory and compares with our 5-year historical average of approximately 1.5% and the 1.4% growth embedded in our long-term plan.

Historically, we have used first-time meter sets that were installed over the trailing 12 months as a leading indicator of growth, particularly during COVID-related moratorium periods. As those distortions have since normalized, we believe net customer growth has become the most relevant and comparable metric across the sector. While growth remains healthy, we have seen a modest slowdown over the past year, particularly in Southern Nevada, which we view as somewhat localized and timing related rather than indicative of a change in long-term demand trends, which, as Karen noted, project population growth rates in both Arizona and Nevada to trend near 5% from 2026 to 2031 according to S&P.

Additional operating margin contributions from non-decoupled and recovery-related items were partially offset by the absence of Vintage Steel Pipeline Program recovery in the current period as this program was concluded during last year's first quarter. These recovery-related items are offset later in the income statement, highlighting the strength of our regulated recovery model. Operations and maintenance expense increased by $2.1 million or approximately 1.6%, driven largely by higher insurance costs and related claims, but remaining below inflation and reflecting net reductions in bad debt, internal gas usage and leak survey and line locating expenses.

Depreciation and amortization increased $5.9 million, primarily reflecting a 6% increase in gas plant in service compared to the first quarter of 2025, combined with modestly higher regulatory amortization expenses that are offset by equivalent increases in margin. The increase in plant and service is consistent with our disciplined infrastructure investment strategy focused on safety, reliability and customer growth.

Other income declined by $3.6 million, driven by lower interest income at the utility level associated with reduced cash balances relative to the prior year. COLI investment performance was comparable over the 2 periods. Interest expense at Southwest Gas increased modestly due to higher variable rate interest associated with Nevada regulatory mechanisms, which is offset by a corresponding increase in margin.

Income taxes increased by $6.4 million due to higher pretax earnings and increased amortization of excess deferred income taxes. Corporate income taxes also increased because of higher nondeductible executive compensation tied to performance-driven incentive outcomes aligned with stockholder value creation.

Overall, had we received the California rate case decision during the first quarter, we would have realized additional margin benefits. Consistent with industry standard accounting practices in California, a final decision in the second quarter would allow us to recognize the full retroactive year-to-date revenue and margin impact in that period. We are pleased with our start to the year and remain confident in our full year outlook based on our California rate case assumptions.

Turning to Slide 15. This slide outlines our expected sources and uses of cash for 2026. Our significant beginning cash balance reflects intentional liquidity preservation following separation. The majority of projected 2026 activity is expected at the utility, and we do not anticipate the need for equity issuances during the year. At Southwest Gas Corp., we expect operating cash flow, cash from holdings and a planned bond issuance to fund our approximately $1.3 billion capital program and a modest bond maturity. The timing of this bond issuance will be opportunistic and aligned with market conditions, reflecting our strong liquidity profile and disciplined capital structure management. Looking ahead, we believe our financing plans are designed to align incremental investment and rate base growth with credit supportive funding decisions.

Turning briefly to Slide 16. This slide highlights our balance sheet strength and credit profile. At the consolidated level, we ended the quarter with approximately $3.2 billion of net debt. Both Holdings and the utility continue to maintain strong investment-grade ratings across all 3 agencies with stable outlooks, most recently reaffirmed by Moody's in April following last year's upgrades by S&P. Our balance sheet actions reflect a deliberate and proactive approach to credit stewardship. We operate comfortably within our targeted credit parameters with a capital structure designed to support regulatory execution, fund long-term growth and preserve access to low-cost capital across market cycles.

Turning to Slide 18. We are affirming each of our 2026 and long-term financial guidance metrics, which are, as always, are subject to the risks and uncertainties Tyler mentioned at the top of the call. Based on our strong start to the year and the anticipated resolution of the California rate case, we continue to expect 2026 adjusted EPS of $4.17 to $4.32 and long-term growth of 12% to 14%. This outlook reflects continued customer growth, constructive rate recovery and disciplined system investment.

As previously discussed, earnings growth is not expected to be linear over the 5-year period and is anticipated to be front-end loaded through 2028 and 2029 as the 2028 Great Basin expansion project comes into service and formula rates reduce regulatory lag. Annual results will also likely vary based on the capital deployment timing and assumed AFUDC levels. Overall, we remain confident in our 5-year growth outlook and plan to continue to provide transparency as key milestones are achieved. Increased demand from the most recent Great Basin open season represents incremental upside optionality outside our base growth outlook, which remains driven by regulated investment and recovery. We expect this strategy to deliver durable, long-lived rate base expansion.

Our capital plan remains firmly on track. We expect to invest approximately $1.25 billion in 2026 and $6.3 billion over the next 5 years focused on safety, reliability and system growth, including the 2028 Great Basin expansion project. With year-end 2025 rate base of $6.7 billion, this plan supports an expected rate base CAGR of 9.5% to 11.5% through 2030. Notably, our 5-year capital program is nearly equal to our entire current rate base, underscoring the scale of growth embedded in our investment plan. Overall, we believe our guidance reflects a balanced plan to deliver consistent earnings growth while investing in infrastructure and supporting long-term value creation for stockholders.

Back to you, Karen.

Thank you, Justin. You can also see we have had a strong start to 2026, and we are excited about the momentum across the business. Our results and our affirmed guidance reflect the strength of our fully regulated model, constructive regulatory environments in which we operate and the disciplined focus of our team. Southwest Gas continues to be defined by its commitment to delivering safe, reliable and affordable service, supported by a long-term focus on operational excellence and value creation. That foundation positions the company well as we continue to invest in our system, advance key regulatory initiatives and pursue growth opportunities.

As I step away from my role as CEO and look ahead to retirement after nearly 3 decades with Southwest Gas, I'm proud of the progress we've made, particularly our transformation into a focused fully regulated natural gas business. I have great confidence in the future of Southwest Gas and in Justin Brown's leadership, knows this business well, and I'm confident he and the team will continue to build on the strong platform that's in place today. I also want to take a moment to thank our employees for their unwavering dedication to our customers and communities, the Southwest Gas Board for partnering with me during a transformational period and to thank our stockholders for their continued trust and support. It has truly been an honor to serve as CEO of this company.

With that, let's open the line for your questions.

[Operator Instructions] We'll take our first question from Julien Dumoulin-Smith from Jefferies.

Nicely done. I got a hand to you guys. Really nice to see it coming together here. Maybe if I could just chime in real quickly here as it pertains to the Great Basin, can you talk a little bit about the potential to ramp beyond that 0.6 bcf a day that you've obviously received surety on already? Obviously, you guys did this April supplemental open season, but what's the process on converting it? And how do you think about margin versus CapEx here? I heard the comments about not being incremental to the 1 bcf a day for CapEx. But how do you think about margin? You provided a range there, for instance, in your guidance. Just how would that accrue to the financial results? And then also, how do you think about the time line for translating it?

Julien, it's Justin. Yes. So in terms of process, the way I would describe it is, I think to your point in terms of when you think of potential, I think the potential is really reflected in that oversubscription of what the current design capacity is. We have posted and marketed about 0.3 bcf of capacity and received almost 8x that. So I think that's reflective of kind of the potential and demand in that region. Obviously, the next step similar to last year is we will work with each of those shippers that expressed interest in the project. And we're going to start the negotiation process on precedent agreements similar to what we did last fall.

And as part of that process, we're going to require surety for the pro rata share of their investment. And so we'll kind of -- as those come in, that will help us gauge kind of what the potential sizing will be if there's going to be any changes. If ultimately that settled demand comes in at the 1 bcf level, well, then I think the guidance that we've given around margin and CapEx are going to hold. If for some reason, that additional capacity comes in materially more than that, we're going to need to think about our design, think about pipe sizes, think about compressor assumptions that we've made, and that's ultimately going to have an impact on the capital investment and ultimately the margin. And so I think it's kind of more to come. It's super I think it's a little premature right now. This just completed the end of last week. And so we're really in the early stages of beginning that negotiation process. And we're going to do our best to make sure we continue to update you guys as we hit different commercial milestones along the way.

Yes. And just to clarify, obviously, there's a longer data piece here, 2030 to 2035. The time line for when you would see that translate and transpose itself. Sorry to press too much on this, but obviously, it's such a big deal.

Yes. I think that's going to -- we're going to get clarity around that as we go through the negotiation process because, again, when we posted the open season, we indicated that we would be open to kind of step up capacity or phased-in capacity. Clearly, there's demand there. And so as we go through the precedent agreement negotiation process, we'll be able to get some clarity around that as part of the next step in this process. And so I would think that once we complete kind of that contracting phase, we'll be able to give better guidance around kind of the timing of both the '28, '29 kind of in-service period, but then also those expressions of interest that go from 2030 through 2035.

Okay. Next question is from Gabriel Moreen from Mizuho.

It's Dan Dolev on for Gabe. Nicely done on the quarter. Just kind of going more on to the Great Basin here. If you guys could provide more detail on like the types of customers driving the strong open season interest, specifically how much demand is coming from power gen, data centers or industrial users and how that mix kind of informs the durability in contract of expected commitments.

Yes, Gabe. So I think it's one of those things where similar to the contracting process, these shippers are -- it's really a confidential process as we go through it. And so there's not a lot we can really share. I think what we've disclosed in the past is when you read different information around kind of the Tahoe-Reno Industrial Center, where a lot of this is driven kind of just that region. I think you see a lot of different customers from data center hyperscalers to mining to power gen. So I think you see a variety. And I think the best we can do is kind of right now kind of point to some of those publicly available articles and things about kind of the growth in that region until we get further in the process and we're able to disclose who the shippers are and things that actually sign contracts.

Next question is from Ryan Levine from Citi.

Given the potential for Great Basin to scale up to up to 2.5 Bs, how is your strategy around long lead time items evolving? Or how are you thinking about that in the context of some upside potential to the pipeline?

Ryan, good question. It's Justin. Yes, we've started that process of working with suppliers around pipe and compression. And so once this most recent open season closed, we immediately reached out to them to kind of think about, hey, depending on what contracts ultimately gets signed, we may need to pivot around some of the design elements of the project. And so we're working very closely with our supply chain folks and with our potential suppliers to make sure that we manage those in terms of those longer lead time items.

But if you've already procured some of that and some of the equipment may not be needed, would you be able to remarket that? Or do you -- how is it with your supply chain?

Yes. And what I would say is I think when you think about procurement, it's more about kind of reserving a position in the queue, which then gives you the ability to kind of transition to maybe more powerful compressors or different compressors or upsizing the pipe diameter. And so I think it's early enough in the process that we feel good about being able to pivot in the queue on those things as opposed to actually having procured something that then is not going to be relevant for the project.

Okay. And then related to California, given the settlement with the [ ALJ ] or with the key parties yesterday and the cost of capital remaining outstanding, how does the recent Sempra decision impact your thinking or your outlook for your California gas business?

Which decision are you referring to?

The SoCalGas recent decision.

Rate case or there's different cases. Okay. Yes. I mean I would say, Ryan, historically, we're always very much aware of kind of what the commission decisions are with respect to kind of the larger investor-owned utilities. Being a small multi-jurisdictional utility, there's not necessarily a pattern of the decisions, the outcomes that the large investors have versus what we have. And so typically, we're very focused kind of on our proceedings and how we manage them and our outcomes. And I think historically, there hasn't necessarily been a strong connection to some of the larger investor-owned utility outcomes. But we always are very much aware of kind of what's going on there and monitor them just so that it helps us manage our proceedings as well. But typically, the commission has done a good job of kind of addressing each one on their own merits.

Next question is from Vedula Murti from Hudson Capital.

When you talk about the ability to scale up to from 1.0 to 2.5 bcf per day, right now, we're at 1.7 for 1.0, can you give a sense as to what the upside capital requirements would be if you were to go, say, hypothetically 2.5. I know it's not asymmetric type of thing where you multiply current 1.7x 2.5. It wouldn't work like that. But can you give me a sense of how that would work?

Yes. I really don't -- it's Justin. Good to hear from you. We don't have anything in terms of being able to kind of share around kind of proportionately what that is. We're -- like I said, this really came in at the end of last week. We're really focused on working with the different shippers on finding out what is actually going to be contracted and secured with surety. And so that's really the focus. On a parallel path, we're going to be looking at kind of what the options might be depending on what ultimately gets put under contract. But it's just too hard to speculate right now in terms of what that could do based on different sizing needs, based on different potential demand.

Well, I guess given the interest and where it's obviously very early, can you give a sense as to -- I'm kind of confused about the time line at which we would know for the 2028 to 2035 period that has been discussed here when you'd be able to communicate that to us?

Yes. I mean using last year as kind of a proxy, if you will, in terms of the process, I would say normally over the next 60 to 90 days is the process by which we would be finalizing contracts and requesting surety. And so I think our hope is over that time period, most likely by the time we get to the second quarter call, if not earlier. And if we have that information earlier, it's something we would look at issuing a press release around just to make sure we keep everybody updated. Otherwise, we'd look to probably provide an update at our next call in -- after the second quarter.

So by the next call, you'll be able to tell us what beyond maybe 1 bcf per day and 1.7, what the new scope of the project would be and its time line in terms of capital?

Yes, that would be our hope.

There are no further questions at this time. This concludes the Q&A portion of today's conference. I would now like to turn the call back over to Tyler Franek for closing remarks. Go ahead.

Thanks again, Sheen, and thank you all for joining us today and for your questions. This concludes our conference call. We appreciate your interest in Southwest Gas Holdings and look forward to seeing many of you at the AGA Financial Forum in Scottsdale soon.

This concludes today's Southwest Gas Holdings First Quarter 2026 Call and Webcast. You may now disconnect your line at this time. Have a wonderful day.

Welcome to the Southwest Gas Holdings Fourth Quarter and Full Year 2025 Earnings Conference Call. Today's call is being recorded, and our webcast is live. A replay will be available later today and for the next 12 months on the Southwest Gas Holdings website. [Operator Instructions] I will now turn the call over to Tyler Franik Manager of Investor Relations of Southwest Gas Holdings.

Thank you, John, and hello, everyone. We appreciate you joining the call today. This morning, we issued and posted to Southwest Gas Holdings website our Fourth Quarter and Full Year 2025 earnings release and filed the associated Form 10-K. The slides accompanying today's call are also available on Southwest Gas Holdings website.

We'll refer to those slides by number throughout the call today. Please note that on today's call, we will address certain factors that may impact 2026 earnings and discuss longer-term guidance. Information that will be discussed today contains forward-looking statements. These statements are based on management's assumptions on what the future holds but are subject to several risks and uncertainties, including uncertainties surrounding the impacts of future economic conditions, regulatory approvals and a significant capital project at Great Basin Gas Transmission Company.

This cautionary note as well as a note regarding non-GAAP measures is included on Slides 2 and 3 of this presentation, in today's press release and in our filings with the Securities and Exchange Commission, all of which we encourage you to review. These risks and uncertainties may cause actual results to differ materially from statements made today. We caution against placing undue reliance on any forward-looking statements, and we assume no obligation to update any such statement.

As shown on Slide 4, on today's call, we have Karen Haller, President and CEO of Southwest Gas Holdings; Justin Forsberg, Chief Financial Officer and Treasurer of Southwest Gas Holdings; and Justin Brown, President of Southwest Gas Corporation as well as other members of the management team available to answer your questions during the Q&A portion of the call today. I will now turn the call over to Karen.

Thanks, Tyler. Good morning, everyone, and thank you for joining us today. Last year, we turned the page on our transformational strategy with the successful disposition of Centuri in September. The important milestone that completed our transition to a fully regulated natural gas business. This strategic step enabled us to fully pay down the remaining holding company debt strengthened our balance sheet and unlocked meaningful capital to reinvest in our core operations.

With our focus now fully centered on our regulated natural gas business, we are approaching 2026 with a stronger foundation and greater flexibility to execute on our strategic priorities and the opportunities ahead. As a result of our full separation of Centuri, termination of the [ Icahn ] Cooperation agreement and strong strategic position, I determined that after nearly 3 decades with the company, it is the right time for me to retire.

One of the most significant responsibilities of the CEO and Board of Directors is to plan for the CEO succession. The Board was prepared for this milestone and appointed Justin Brown, a Southwest Gas' next CEO effective May 8. As President of our Utility Operations over the last few years, Justin has played a critical role in executing on our strategy and positioning the company for future success. He has a proven track record leading our utility operations, and the Board has full confidence in him as Southwest Gas' next Chief Executive Officer.

Justin and I have worked closely together for many years, and I'm confident that he is the right leader to guide the company in its next phase. I will remain involved as an adviser to the company through the end of this year to ensure a smooth transition.

With that, let's turn to Slide 5. In 2025, we delivered strong financial performance with Southwest Gas adjusted net income finishing above the top end of our previously stated guidance range. This performance drove Southwest Gas adjusted return on equity to 8.3% for the year and was supported by our ongoing utility optimization efforts, effective cost management and constructive regulatory outcomes.

Together, these results demonstrate the strength of our regulated business and our commitment to driving consistent, sustainable value for our customers and shareholders. We also remain optimistic about the future as we introduce 2026 and long-term guidance ranges, which we will cover in more detail later. We are initiating a $4.17 to $4.32 per share, 2026 adjusted earnings per share guidance range from continuing operations.

We expect to see significant earnings per share growth of 12% to 14% from 2025 to 2030, driven by anticipated improvements in our regulatory environment with the inclusion of Arizona's formula rates and alternative ratemaking in Nevada, along with the opportunity we project to materialize at Great basin in Northern Nevada.

Because of these opportunities, this growth is expected to be front-end loaded over the first 3 years. So we expect the earnings growth rate to be even higher through 2028 to 2029. And Jay Forsberg will walk you through the guidance in a few minutes. As we move to 2026, our strategy is anchored in operational excellence, financial discipline and regulatory progress.

The work we accomplished in 2025 positioned us to focus on the priorities that we believe matter most in the year ahead, continuing to improve returns, advancing customer-focused investments, strengthening our regulatory frameworks and capturing growth opportunities across the service territories. Of note, we were pleased to announce earlier today that the Board of Directors approved a 4% increase in our annual dividend, beginning with the second quarter 2026 payout.

We intend to maintain a disciplined strategy focused on investing in the company's capital plans, while sustaining responsible annual dividend growth. On the next slide, I will outline the key priorities that will guide our efforts throughout 2026. As you can see on Slide 6, we achieved a lot in 2025 with an active regulatory calendar, the introduction of and progress made on the 2028 great Basin expansion project, the completion of our financing plan and of course, the simplification of our business model through the full separation of Centuri.

We are initiating our 2026 strategic priorities for the first time in decades as a fully regulated natural gas business. We are excited to direct our attention entirely to executing our regulatory strategy, achieving the next steps of the Great Basin project and preserving our balance sheet strength by implementing our 2026 financing plan.

On Slide 7, I'd like to highlight that following the completion of our Centuri disposition, S&P upgraded Southwest Gas Holdings issuer and Southwest Gas Corporation's senior unsecured long-term debt credit ratings each to BBB+ with stable outlooks. This enhanced corporate risk profile further demonstrates the positive impact of our simplification strategy.

As of the end of 2025, our cash balance was nearly $600 million, which we expect to utilize to fully fund current year dividend payments and to redeploy during 2026 into the utility business, and we have more than $1.3 billion of liquidity across the business, which enabled us to make strategic investments that are expected to generate stable, long-term returns.

I'd also like to highlight the utility's substantial net income growth, which was primarily driven by positive regulatory outcomes and strong economic activity in our service area and further enhanced by cost optimization efforts. We are enthusiastic about the company's future, and we are confident in the promising opportunities ahead.

With that, I'll turn the call over to Justin for a regulatory and economic update.

Thank you, Karen, for your generous words. And more importantly, thank you for your leadership and contributions to Southwest Gas over the past 29 years. I'm grateful for both our friendship and your continued partnership during this transition. It is both an honor and a responsibility to step into this role. I'm energized by the opportunity ahead and I look forward to continuing to work alongside our extraordinary team as we strive each day to exceed the expectations of our customers and our regulators and delivering safe, reliable and affordable natural gas service. .

We have a strong foundation, a clear strategy and the right team to deliver. I'm confident in our ability to execute our plan with discipline and create long-term value for our stockholders. While simultaneously driving meaningful outcomes for all our stakeholders. Let me begin my portion of the presentation by turning your attention to Slide 9, where I'd like to begin with key regulatory developments in both Nevada and Arizona, as we prepare to file rate cases and what we anticipate will be catalysts for better aligning capital recovery with our investments, thereby improving long-term earnings visibility.

In Arizona, we anticipate filing our rate case this week with new rates next year, and we plan to file our Nevada rate case next month and under the statutory 210-day process, new rates would become effective in the fourth quarter of this year. Importantly, both states now allow for potential alternative ratemaking adjustments following approval of a general rate case. While any mechanism remains subject to regulatory approval, we view these frameworks as constructive steps toward reducing regulatory lag and better aligning capital recovery.

This slide provides a potential time line for how our alternative ratemaking opportunities in Nevada and Arizona could develop over the next few years, and we remain confident in our ability to work collaboratively with all stakeholders on meeting these milestones. While any mechanism remains subject to regulatory approval, we view these developments as constructive steps toward reducing regulatory lag and enhancing capital recovery alignment.

In Nevada, Senate Bill 417 signed into law in June of 2025 by Governor Joe Lombardo authorizes alternative rate-making plants. The Public Utilities Commission of Nevada has continued its rule-making workshops to implement the legislation with recent sessions focused on draft policy language and stakeholder consensus. We are encouraged by the progress, and we continue to work collaboratively with all stakeholders. We currently expect the rulemaking to conclude in the coming months, which could allow alternative ratemaking adjustments to begin as early as 2028.

In Arizona, the Arizona Corporation Commission adopted a policy statement in December of 2024, signaling their openness to having regulated utilities, proposed formula rate plans as part of future rate cases and the commission recently approved its first formula rate plan last week. We have developed a formula rate plan that will be included in our rate case filing, which I will discuss in more detail on the next slide.

Overall, we believe these regulatory developments represent meaningful progress toward a modernized regulatory construct in both jurisdictions. Turning to Slide 10. As mentioned, we expect to file our Arizona rate case this week with rates anticipated to become effective in April of next year. Key elements of our filing include a revenue increase of over $100 million with a proposed rate base of $3.9 billion and a requested ROE of 10.25% plus a fair value return on rate base of 20 basis points relative to our equity ratio of approximately 50%. This case is primarily driven by the need to start recovering on the nearly $900 million in capital investments we've made for the benefit of our Arizona customers to ensure safe and reliable natural gas service.

These investments result in a proposed increase in rate base of roughly $700 million, including post test year adjustments of approximately $360 million through November of 2026. As I mentioned previously, we will also be including a formula rate adjustment proposal. The proposal resembles the guidelines established in the commission's policy statement as well as some of the other recent utility proposals currently pending in front of the commission, including the mechanism the commission approved last week.

We are looking forward to working with all stakeholders to effectuate a constructive outcome that minimizes bill impacts to customers and allows us to more timely recover our capital investments. On average, the proposed revenue increase in our case, translates to an expected bill impact of approximately $5 per month for our residential customers.

We believe our proposal reflects a balanced approach that enhances safety and infrastructure reliability while maintaining customer affordability and as always, the outcome remains subject to commission review and approval.

Moving to Slide 11. We are initiating 2026 as long-term capital guidance, which now incorporates the 2028 Great Basin expansion project. This marks the first time we have included the Great Basin project in our forward outlook, and this represents an important evolution in our capital plan.

While our capital plan remains anchored in utility distribution investments, underpinned by our commitment to safety, reliability, system modernization and meeting the needs of our growing customer base, in 2026, we anticipate early stage spending related to -- Great Basin expansion, including engineering, environmental reviews, permitting and other preconstruction activities necessary to support an efficient project time line.

Over the next 5 years, we expect to invest approximately $6.3 billion with roughly 73% directed towards Southwest Gas and 27% toward Great Basin. This capital mix positions Great Basin as a growing contributor to the company's growth story and long-term earnings platform. These investments support an expected 5-year rate base CAGR of approximately 9.5% to 11.5%. The inclusion of Great Basin provides incremental upside and diversification beyond our distribution system investments that we believe will maintain a sustainable growth trajectory of nearly 7% over the same period.

We believe the combination of our distribution investments, coupled with new opportunities emerging through Great Basin provide a compelling long-term capital framework for the company and offer meaningful earnings and cash flow growth for our investors.

Turning to Slide 12. We continue to advance the 2028 Great Basin expansion project and remain on schedule across engineering, regulatory preparation and commercial milestones. In December, we executed binding precedent agreements following a successful open season, resulting in nearly 800 million cubic feet per day of incremental capacity commitments. This supports an estimated $1.7 billion capital investment opportunity and reflects strong market demand for expanded transmission capacity.

Upon placing the project in service we estimate incremental annual margin of approximately $215 million to $245 million, representing a significant step-up in our Great Basin earnings profile. We expect to file our formal CPCN application before the end of this year following the completion of our engineering design, environmental and cultural field work. The FERC and NEPA review processes are expected to occur during 2027 with construction to begin following FERC approval and with anticipated in-service date near the end of 2028.

We recently achieved an important milestone with prefiling approval from the FERC. The FERC also encouraged evaluation of potential eligibility under Title 41 of the FAST Act, which is designed to streamline federal permitting through enhanced interagency coordination. We are currently assessing that pathway and its potential implications for project timing. As with any large scale infrastructure project, timing remains subject to regulatory approvals,

permitting outcomes and supply chain dynamics.

That said, we are proactively managing contractor engagement and procurement planning to mitigate execution risk and preserve schedule integrity. Capital deployment will ramp up as we move from engineering and permitting into construction in late 2027 and early 2028. We expect to accrue AFUDC on pre-service capital moderating near-term earnings impacts. From a financing standpoint, we are targeting a balanced 50-50 debt-to-equity structure. Debt is expected to be funded through Southwest Gas bond issuances, while equity requirements will be supported through a combination of holding company leverage capacity and modest equity issuances, including use of our existing ATM program.

This approach supports project execution while preserving credit quality and long-term financial flexibility, preserving the strength of our balance sheet. We will continue to provide updates as we achieve key milestones throughout the course of this year. And with that, I'll turn the call over to Jay For who will review our financial performance for the year.

Thanks, Justin. Turning to Slide 14. While consolidated GAAP earnings per diluted share for 2025 were $6.08, this included discontinued operations. During the year, the company completed the sale of its remaining shares of Centuri on September 5, 2025, representing a full exit and qualifying Centuri for discontinued operations reporting. The transaction generated a net gain of approximately $260 million, which when combined with the Centuri performance throughout our period of ownership during the year contributed $2.83 per diluted share to consolidated GAAP earnings. .

You can refer to Slide 32 in the appendix for a detailed breakdown of consolidated earnings for the year. Here, we present adjusted earnings per share from continuing operations, so you can clearly see the underlying business performance. As shown on the slide, adjusted earnings per diluted share from continuing operations increased nearly 19% from $3.07 in 2024 to $3.65 in 2025 and representing a $0.58 improvement year-over-year.

This increase was driven by focused execution in our natural gas distribution business as well as significantly lower financing costs at Holdings. Southwest Gas earnings benefited from rate relief and continued customer growth, contributing approximately $0.30 per share to EPS. These margin benefits were partially offset by increased depreciation and amortization tied to ongoing capital investment, higher interest expense primarily related to regulatory account balances from overcollected purchased gas costs and modestly higher operations and maintenance expense.

Lower overall expenses in the holding company were driven by a significant reduction in interest expense following the full repayment of prior holdco debt using proceeds from the Centuri transactions. This payoff was the primary driver of the improvement in earnings shown on the table.

Turning to Slide 15. You'll see the year-over-year walk from 2024 to 2025 adjusted net income for Southwest Gas. Adjusted net income increased by 8.7% from $261.2 million in 2024 to $283.9 million in 2025, representing an improvement of nearly $23 million year-over-year. These results were nearly $9 million above the high end of our net income guidance driven largely by higher than forecasted COLI results, higher interest income from elevated cash balances and some delayed in-service dates, which resulted in D&A coming in modestly lower than anticipated.

The primary driver of the year-over-year increase was a nearly $120 million improvement in operating margin. This reflects approximately $95.2 million of combined rate relief, primarily from the outcome of our Arizona rate case, $11.5 million of margin from continued customer growth as well as approximately $8 million related to recovery and return mechanisms and $5.9 million from the variable interest expense adjustment mechanism in Nevada associated with the IDRBs. These last 2 margin improvements are each wholly offset within operating income through D&A and interest expense, respectively.

O&M increased $16.8 million compared with the prior year. Excluding incentive compensation expense that came in above target, the increase was approximately 1.9% over the prior year. Other drivers included higher employee-related labor costs, higher cloud computing expenses and higher outside services costs. These cost increases were partially offset by reductions in leak survey and line locating expenses.

Overall, O&M finished the year close to budget, reflecting our efforts to manage costs while safely and reliably delivering natural gas service to our customers. Depreciation and amortization increased $27.6 million, driven by a 7% increase in average gas plant in service as we continue to invest in pipeline replacement, system reinforcement and new infrastructure for the benefit of customers, along with an approximately $8 million higher amortization related to regulatory account balances that I mentioned being offset in margin a moment ago.

Other income declined by a net $1.9 million. Several offsetting items contributed to this decrease with an expected $12.6 million decline in interest income related to carrying charges on deferred PGA balances being the largest. This decline was partially offset by an increase in company-owned life insurance asset values gains on the sale of miscellaneous assets and the timing differences and contributions to the Southwest Gas Foundation compared with 2024.

Net interest deductions increased $19.4 million, driven largely by the anticipated interest incurred on overcollected PGA balances and higher variable interest expense adjustment mechanism amount in Nevada associated with IDRBs. As I mentioned a moment ago, the impact of operating margin -- operating income of variable interest associated with the Nevada IDRBs is wholly offset in margin.

Taxes other than income taxes made up largely of property taxes increased $5.1 million, while income tax expense was also higher year-over-year due to increased pretax income. You'll note that partially offsetting GAAP net income was a $16.4 million state income tax apportionment benefit associated with certain onetime events, and we have adjusted that income tax benefit for non-GAAP presentation to reflect the true run rate net income at Southwest Gas.

In summary, the year-over-year improvement in adjusted net income is a clean, regulated utility story driven by strong operating margin growth from rate relief and customer additions, partially offset by modestly higher O&M and by higher D&A, interest expense and the impact of taxes.

Moving on to Slide 16. We outline our expected near-term financing plan, which reflects disciplined funding supported by a strong liquidity position. We entered 2026 with a significant beginning consolidated cash balance of nearly $600 million, largely representing the remaining proceeds from the Centuri separation completed in September 2025 after having utilized a portion of those excess proceeds to pay dividends to stockholders during the second half of 2025.

The liquidity at the holdco provides meaningful financial flexibility as we execute our capital program and we plan to fully fund stockholder dividends in 2026 using that holding company cash while also planning to infuse nearly the same amount of equity into Southwest Gas to fund our 2026 capital plan. The execution of this plan is projected to result in a nominal amount of cash on hand at Southwest Gas Holdings at year-end 2026.

During 2026, we expect approximately $325 million of net Southwest Gas bond issuances, along with modest revolver usage to the operating company. Importantly, we do not anticipate any equity issuance needs during the year under the existing ATM program. Across the company, our $1.25 billion capital plan is the primary use of funds. This investment includes approximately $925 million of natural gas distribution system infrastructure expenditures with the balance of the plan supporting our planned 2028 Great Basin expansion project.

Overall, our 2026 plan reflects balanced funding, strong internal cash generation, disciplined capital investment and a clear path to executing our growth strategy without the need for incremental external equity. Looking further out and turning to Slide 17, we highlight how our credit strategy is intentionally aligned with our long-term capital plan and why we believe maintaining a solid BBB+ profile is the optimal position for Southwest Gas Holdings during this investment cycle.

For 2025, we calculate S&P adjusted FFO to debt of approximately 19.7% at Southwest Gas Holdings and 18.6% at Southwest Gas Corporation. These levels sit well above S&P's 13% downgrade threshold for each entity and above our targeted long-term operating range of greater than 17%. This long-term credit metric strategy is targeted to provide more than 300 basis points of cushion above the downgrade trigger at any point in our forecast period, which we believe is an appropriate level of planned headroom to absorb potential exogenous events such as volatility in weather, commodity prices, interest rates and the timing of regulatory outcomes.

This disciplined credit positioning supports a balanced 50-50 capital structure at Southwest Gas and preserves efficient access to debt markets as we execute the more than $6 billion of planned investment through 2030. Due to our strengthened balance sheet and credit cushion, we believe we can forgo high-volume equity issuances, while utilizing the ATM for modest equity needs as well as the reestablish holdco leverage capacity as financing levers.

Just as importantly, this approach directly supports our stockholder value framework. By maintaining visible headroom above downgrade thresholds, we believe this discipline will preserve lower cost capital access and create the foundation for consistent annual dividend growth while retaining important flexibility during peak investment year. In short, our objective is not to maximize a single credit metric but to intentionally manage the balance sheet to sustain BBB+ through the capital cycle.

That discipline allows us to fund growth efficiently, protect our investment-grade profile and deliver durable long-term value to stockholders. As we highlighted on the prior slide, maintaining strong credit metrics is a core priority for both Southwest Gas Holdings and Southwest Gas Corporation.

Slide 18 reinforces how our current capital structure, liquidity position and ratings profile support that commitment and provide flexibility as we execute our plan. On a consolidated basis, total net debt at year-end 2025 was approximately $3.2 billion after adjusting for the nearly $600 million of cash on hand, and the roughly $300 million of purchased gas costs or PGA balances.

Notably, all of our outstanding debt is held by the utility. You'll see all of our current credit ratings on the right-hand side of the slide, both entities maintain solid investment-grade profiles with stable outlooks from all 3 major agencies.

Turning to Slide 19, returning value to stockholders through consistent dividend growth remains a core component of our long-term strategy. The company has paid a dividend every year since 1956, reflecting the durability of our regulated utility model. Today, we announced that our Board approved a 4% increase in the annual dividend, bringing it to an annualized $2.58 per share for 2026, up from $2.48 previously.

We intend to recommend future annual dividend increases to the Board, while maintaining a disciplined strategy focused on investing more than $6 billion in the company's capital plans and sustaining responsible annual dividend growth. Looking further ahead, as earnings and cash flows strengthen, particularly as the planned 2028 rate basin project comes into service and as projected regulatory outcomes improve, this disciplined framework creates meaningful upside potential for larger dividend increases over time as cash earnings grow.

Moving now to Slide 21, I'll walk through our newly initiated 2026 and forward-looking financial guidance. We are initiating both 2026 guidance and long-term targets that reflect our current expectations for improvement in the regulatory construct in both Arizona and Nevada as well as the projected contribution from the potential 2028 Great Basin expansion project.

Building on strong 2025 performance as a base year, we are initiating 2026 EPS guidance to land in the range of $4.17 to $4.32 per share. We expect the primary drivers of our projected performance to be continued operating margin expansion at Southwest Gas, supported by ongoing customer growth and rate relief across all our jurisdictions. In addition, we expect meaningfully lower interest expense related to holdco debt following the elimination of all debt outstanding at that level.

I'll further outline the underlying assumptions supporting our plans on the next slide. Overall, the combination of strong core utility fundamentals and a more solid capital structure supports our confidence in the 2026 earnings outlook. Looking further out, we are targeting a 5-year adjusted EPS compound annual growth rate of 12% to 14% through 2030.

This growth trajectory using an adjusted 2025 base year reflects continued customer additions, expected improvement in rate relief mechanisms and disciplined cost management along with incremental earnings from the expansion project at Great Basin as we currently expect it to come into service in late 2028. As Karen mentioned earlier, we currently expect our growth rate to be front-end loaded through 2028 and 2029 with about a 15% to 17% EPS growth rate over those periods, depending on how you model the timing of construction spending and associated AFUDC earnings as well as the anticipated improvement in earned ROEs from 2026 to 2028.

As Justin Brown mentioned a moment ago, large projects are always subject to regulatory approvals, permitting outcomes and supply chain dynamics and our robust plan is also contingent on regulatory outcomes. We expect robust rate base growth supported by capital expenditures of approximately $1.25 billion in 2026, with a total of approximately $6.3 billion for the 5 years ending in 2030. This capital plan is focused on safety, system integrity, reliability and new business distribution system growth in the utility, along with the incremental investment required to support the growing transmission business.

We are also initiating a 5-year rate base CAGR of 9.5% to 11.5%, also starting from a 2025 base, which is approximately $6.7 billion. Notably, when excluding the 2028 Great Basin expansion project, our run rate utility rate base growth is expected to be about 7% annually over the same period.

Now turning to Slide 22. We show additional detail on the fundamental drivers and financing assumptions that underpin our guidance outlook through 2030. Beginning with margin, our plan reflects a clear regulatory cadence across our jurisdictions. As Justin previously outlined, the potential implementation of formula and alternative-based rate mechanisms in both Arizona and Nevada are expected to meaningfully impact margin as we refresh rates and implement the expected regulatory improvements.

Further out, we expect incremental contributions from our other jurisdictions. Supporting this regulatory roadmap, we expect steady customer growth of approximately 1.4% annually across our service territories. For O&M, we remain focused on operational discipline with our target to keep O&M flat on a per customer basis, excluding the nonservice component of pension costs. We assume approximately $6 million to $7 million annually from company-owned life insurance, and we plan for normal natural gas price fluctuations based on current forward pricing curves over the planning horizon.

With respect to income taxes, we expect that utilizing existing net operating losses should minimize cash tax payments and result in an effective tax rate in the high teens, barring any future corporate income tax policy changes. We utilize currently anticipated forward corporate debt curves as we model interest expense when incorporating future bond issuances. The timing of bond issuances is consistent with the capital plan we outlined earlier. As I mentioned, our strategy is designed to preserve balance sheet strength and flexibility while funding our elevated capital plan. Back to you, Karen.

Thank you, Jay Fors. Before we move into the Q&A portion of the call, I'd like to draw your attention to Slide 23, where we highlight our commitment to delivering exceptional customer service, disciplined financial management maintaining a constructive regulatory engagement and preserving strategic flexibility while advancing our strategic priorities and achieving strong financial performance. I am confident in our trajectory as a leading pure play fully regulated natural gas business. .

The team is focused on ensuring we safely, reliably and affordably meet the needs of our customers every day in order to deliver value to our stockholders. With that, let's open the call for questions.

[Operator Instructions] We will take our first question from Julien Dumoulin-Smith from Jefferies.

Just really nicely done. I got to say at the outset, this is an incredible update, lots. To ask here, but really got acknowledged at the outset. And obviously, Karen, Justin congrats to each of you, respectively here. Really great high note here.

If I can pivot into the questions real quickly, though, just to kind of start at the top, I'm sure others will have a bunch. Just talk about the equity, right? I mean big plan, big chunk that you guys are biting off here. How do you think about the timing of equity? Have you engaged with the rating agencies? To what extent are you going to get some latitude or give yourselves latitude in the [indiscernible] metrics through the construction cycle here. Just trying to gauge, obviously, you've disclosed '26 equity or lack thereof, but how are you thinking about the ramp '27, '28. And that's the first question. I've got a follow-up.

Thank you, first of all. I appreciate it. And I'll let Jay Fors answer that question.

I appreciate the question, Julien. I think it's a good question. When you think about the -- I'll start with kind of the credit metrics, things like obviously, we have more than 500 basis points above our downgrade threshold at this point. And and we are committing to targeting that up greater than 300 basis points in the plan. So when you think about our anticipated equity needs for our capital plan at the utility, we think we can utilize some pretty significant leverage capacity in the holding company first to sort of offset those with really minimal equity needs.

I think a way to think about it. Obviously, as you mentioned, we don't anticipate anything -- needing anything in this year. But when you -- on a go-forward basis, I think the way I would put it is when you think about we have a shelf that expires at the end of 2026. We'll be renewing and extending that shelf. We don't anticipate upsizing our existing $340 million ATM.

Yes, I suppose that's a signaling in and of itself as to how you think about the total equity needs you'll need through the plan, right?

Yes, we think so.

Excellent. And then -- yes, indeed. And then look, let's talk about the project itself, right? I mean you talked about this capacity subscribed of nearly 800 MCF. Can you elaborate a little bit about the total scope of the project here? I mean Obviously, you got some incremental interest above that. Just talk a little bit about what the customer interest was and to the extent that the [ 1.7 ] could have ever go larger. I just want to try to tackle that here at the outset as well, just in terms of like the total eventual opportunity here and/or any other interests that does emerge [indiscernible]. You talked about data centers in Nevada, and ultimately serve that kind of customer load. What are you seeing on that front just to hit that as well.

Julien, it's Justin. And Yes, to your point, we went through kind of elongated multi open season process last year, and a lot of that was driven by just different inbound inquiries we received. And I think as we've described in the past, at some point in time, we had to kind of coalesce around an in-service date that the majority we're focused on.

And so we picked the 2028 number. And that's really kind of what we locked in on those customers that were interested in service by kind of end of calendar year '28, we had to kind of draw the line. And so I think to your point, when we think about kind of future demand, future interest, I think there's definitely some there because we had received much more inbound requests than what actually signed up. But again, I think you have to look at it in terms of kind of the timing of the different interests and people's projects and kind of what they anticipate timing.

So I think a couple of things as we move forward that I would encourage you to think about is, one, we continue to work on the design aspects. Obviously, when we have signed up capacity at a certain dekatherm a day, when you design the system, it doesn't come in at that exact number, it's virtually impossible. So we're going to -- when we complete the design, we'll compare that design, kind of efficient design to what capacity it actually hold.

If there's an opportunity to do a supplemental open season to fill up any remaining capacity based on the design, we'll do that. I think we feel confident that there is demand there and interest that people would take that. And then I think when we think about dates beyond 2028, we'll continue to work with prospective shippers on kind of what their interest is, what their timing is and we can always look to evaluate, again, kind of maybe another open season for a different date down the road.

Right. Last nuance here, if I can squeeze it in. Just the cadence of earnings uplift. I mean obviously, it's back-end weighted here. But can you speak to that as well as the -- what you're thinking on closing the gap on lag here in Arizona and Nevada as well as part of this updated plan.

Yes. I'll start with kind of the regulatory construct and kind of how we're looking about our continued effort and focus on reducing regulatory lag in our jurisdiction. So obviously, as I mentioned in my prepared remarks, this next couple of years is going to be very big for us in terms of we've got 2 sizable rate bases. We're getting ready to file. We think they're really going to be a catalyst moving forward in terms of being able to request formula rate adjustments as part of the rate case or in Nevada's case, using this rate case as kind of the springboard for that. .

And so I think when we think about kind of those mechanisms and how they're going to be designed, obviously, each state is going to be a little bit different. But I think you can look at the [ UNS Gas ] decision from last week. And I think that's a pretty good proxy when you think about the facts and circumstances of UNS Gas kind of triangulating that with the policy statement and then some of the other proposals that are pending.

I think we've always said we kind of look at hopefully being able to reduce kind of what has been kind of our historical gap of 160 basis points pertaining on any time. I think in combination with Nevada and Arizona, we're hoping to cut off about 100 basis points is what our goal is.

Julien, I can hit -- talk a little bit more about cadence like Karen and I both mentioned, right, the guidance,

yes, it's really more front-end loaded, which I think is not what you're getting at, right? We have the run rate rate base growth [indiscernible] underlying [ LPC ] of about 7%, which really supports something that you kind of sort of model, if you will, through the whole 5-year plan is that earnings trajectory because as we tighten up that lag, it should be aligned pretty well with rate base growth. The earnings, the EPS growth should be, especially with the minimal equity issuances expectations.

But I think when you think about these other things that Justin just mentioned plus the in-service anticipated at Great Basin that's where I pointed to that we see about 15% to 17% EPS growth rate over sort of that '28 to '29 from now.

Your next question comes from the line of Elias Jossen from JPMorgan Chase.

Maybe just thinking about the kind of post Great Basin and service earnings contribution. I know you've talked quite a bit about the back half versus the front half of the earnings CAGR. But can you just talk about maybe in 2030 when we start to see the full benefit of Great Basin what that earnings contribution could look like on a run rate basis? And because I think about some real inflection sort of in that 2030 time period based on those earnings contributions.

Yes, Elias. I think that's where we can point to the margin that we -- Justin mentioned, right, the $215 million to $245 million expected margin that we will get out of Great Basin. And with the sort of end of the year, toward the end of the year in service date in 2028. That margin contribution expected fully in '29 and in '30 because I'll just remind you and everybody on the call that we are expecting once we -- prior to in service that we would execute a minimum 20-year transportation service agreements that we would be bringing in that margin. And so that's kind of the Great Basin Contribution, if you will, for those outer 2 years to margin. And then you've got, as I mentioned a moment ago, the 7% kind of rate base growth of the underlying utility.

Got it. And then I think you touched on a bit in the previous response, but just -- if we think about sort of the language in the slides that discuss rate case outcomes in line with historical experience, can we just bifurcate that between sort of percentage of ask in the rate case outcomes themselves, but then if the formula rate adjustments would be incremental to that and just think about the earnings contributions from those in that language specifically?

Elias, it's Justin. Yes, I think that's a fair way to look at it in terms of kind of just our historical success, if you will, in terms of the spread between our ask and what we receive. And I think that's a reasonable way to look at it.

Your next question comes from the line of Chris Ellinghaus from Siebert Williams Shank.

Congratulations, Karen and Justin. Have a great retirement, Karen. I really appreciate the new disclosures, by the way. Justin, can you talk about the progress in the Nevada workshops thus far? And any thoughts you have?

Chris, yes, you bet. So the legislation was passed last summer. They held their first workshop in September, held another one in January and February. And again, it's just kind of working through, putting together kind of draft language draft regulations. I think the -- the good thing about the commission is they really kind of put an emphasis on trying to get consensus among the stakeholders. So there's a lot of work around kind of just evaluating kind of the competing interest different language people want, what's required by the legislation. So there's just a lot of back and forth on working on that consensus. We had -- our last workshop was just last week, last Friday, I believe. And I think we feel pretty good about we're getting there at the end. And so we anticipate probably getting some kind of draft consensus regulations out from the commission here over the next month or two

Okay. That helps. vis-a-vis the UNS Gas outcome, have you got any thoughts about ROE and relative to your discussion about the 100 basis point improvement target, does that incorporate your thoughts about where their head is on ROE?

Yes, Chris, this is Justin again. I think, generally speaking, I mean, that decision obviously just came out last week, but I think we've always kind of looked at that. And I think one of the things that we're going to see is that was, I think, one, the very first decision the commission came out with, and I thought that it was very much kind of directionally positive, generally constructive.

And I think we're going to -- and I think they've said this all along that they want to kind of get cases in and kind of evaluate what they look like for each utility for larger gas, smaller gas electrics. So I think we're going to learn a lot more as APS and TEP kind of go through their process. And then as we continue to work with stakeholders on ours. But I think the good thing is, I think the parameters are kind of there when you look at the different proposals, when you look at the policy statement, when you look at the recent UNS Gas case that I think the fairway is kind of defined for everybody. And so we'll be able to kind of all work and see where we end up with the different utilities.

Okay. And I guess this is somewhat of a difficult question, but the 7% sort of longer-term base Southwest Gas rate base growth that you talked about. I assume that's not necessarily consolidated in maybe the 2030 sort of endpoint is part of it. But that doesn't include any kinds of upsides that you see for Great Basin longer term. Is that right?

Yes, Chris, Justin again. Yes, you're spot on. That's just kind of when we think about the historical and kind of the current investment in the utility. That's really what that was designed as to kind of -- we expect kind of consistent strong growth at the utility, and that's what that reflects. So it doesn't include anything that would be kind of a one-off or any additional Great Basin opportunities that may come down the road and may materialize over time.

Okay. Lastly, when you're talking about utilizing parent leverage for the Great Basin funding. Do you expect that to be permanent? Do you ever expect to push down any of the financing costs into Great Basin?

Yes, I think it's a great question, Chris. From our perspective, I think one way to look at that is we don't expect it to be permanent, I'll say that because we do expect -- I think what I'll where I'll go with this is we sold Centuri, which is an asset that was not contributing to the dividend, and we have these dollars to deploy, redeploy into an asset, which is expected to really throw off a lot of cash. earnings at the back end once it goes into service. And so Great Basin we'll have the capacity to give a pretty sizable dividend to the parent, which will help us eat into whatever leverage we put on the parent at that point in time.

Okay. Let me ask you one more thing. Can we -- you talked about maybe having some larger upside to the dividend growth later. Can we presume that once Great basins in service?

Yes, I think that's fair. Kind of along the same lines, what I just mentioned.

[Operator Instructions] Your next question comes from the line of Gabe Moreen from Mizuho.

Just congrats again to Karen and Justin. I just had one question around Great Basin, although it's a little bit multipart. I wanted to dig down a little bit deeper in terms of locking down or squaring away some of the variables here around cost, whether it's E&C compressors, pipe, just kind of where you really stand in that process and how you might be thinking about derisking some of that at this moment. So maybe if I could -- if you can address that, that would be great.

Yes, Gabe, it's Justin. Yes, as I indicated in my remarks, I mean, I think we're working -- we're trying to be very proactive from a supply chain standpoint, working -- going through the prefiling process with FERC to just really kind of mitigate any of those kind of typical project risk, if you will.

Obviously, shipper risk is another one in terms of -- and that's why we went through kind of an elongated process to kind of make sure that we have firm precedent agreements signed up in order to kind of, again, try to mitigate risk associated with the project. We'll continue to kind of work through those processes. I think to your point on kind of where we sit right now, we feel like that's a pretty good estimate of what the cost is.

Obviously, working through with our EPC contractor and different things. I think one of the things that I would say is when we make the anticipated filing with FERC at the end of this year for the formal application, we'll have an updated cost at that point in time. So I think that's a good marker for kind of -- we're going with what we believe is kind of our best estimate right now.

When we go through this process, we're going to know more in 9 months. And when we make that filing with FERC, we'll be able to dial that in even a little bit more. And so that's kind of a good mile marker, if you will, to kind of to keep a look out on in terms of kind of what we anticipate the final project cost to be.

Gabe, I can just add something. I think you're getting at as well. It is a balance, which I think it's what you're kind of pointing to between trying to minimize the spending prior to getting a certificate from the FERC with making sure that we're mitigating some of these supply chain issues that Justin talked about. And so from that perspective, the precedent agreement is just as a reminder, I think you guys know this, but it does require a certain amount of surety that the shippers have to put up as we spend as we carefully spend dollars in this early time period.

I know I had 1 question, but 1 minor follow-up. To the extent you're going through the open season and you've got 800 million a day of capacity. To what extent were not further upstream constraints on procuring gas or capacity constraint on some of your customers here signing up for capacity?

Yes, Gabe, this is Justin again. I think that's really -- our understanding is our customers haven't expressed any restrictions in that regard. Obviously, that's something that they're responsible for, where we provide the pipeline for them to flow the gas supply that they purchase through. But yes, we're not aware of that. I think our understanding is there's sufficient capacity on the upstream suppliers as well to meet those needs.

Your next question comes from the line of Ryan Levine from Citigroup.

I had a couple of questions around just your guidance. In your -- by 2030, are you assuming that you're going to be at that 300 basis point distance from the [ 13% ] downgrade threshold? Is that embedded in plans? Or any color you could share around what's actually in your 2030 estimate?

Yes, I think that's a good question. I think the way you should look about -- folks should look at the greater than 300 basis points sort of target that we have out there really is kind of in the trough as we hit the maximum leverage at the holdco as we're -- whatever we have in our plan, right, as far as offsetting the equity needs using some holdco leverage.

So it's not necessarily by 2030. I think based on kind of what I mentioned earlier in one of the Q&As around what Great Basin be able to -- is that permanent debt at the holdco, which I said it's not, right? So you'd actually see some -- I think some improvement in our -- in the current plan we have out there, we've seen some improvement in the FFO to debt metrics above that trough year, which is likely that 2028 year.

Okay. And then similarly, around the regulatory lag improvement in your plan. Is the 100 basis points embedded in the 13% EPS growth rate? Or is that if you exceed that, would you be above that or kind of conversely, if you underperform? Is that -- are those the key drivers of the outlook?

Ryan, it's Justin. Yes, I think the guidance that we provided, we've made some reasonable assumptions around kind of the timing of formula rates and kind of what that might look like. So that's embedded in that range.

Okay. Well, congratulations to Karen and Justin and appreciate the comprehensive update. .

Your next question comes from the line of Paul Fremont from Liebenberg.

Congratulations on the update and best wishes to Karen and also to Justin. Really 2 questions. One, if I go back to Justin's earlier comment of 15% to 17% through sort of Great Basin which, I guess, the first full year would be 2029. If I use that, I would come up with 2029, somewhere between [ 640 and 680 ]. Am I thinking about that correctly? Or am I missing something there?

Yes. Paul, I appreciate the question. Obviously, we can't give you a sort of guidance on that precision when you get out that far. But I think you are thinking about the run rate in terms of how I mentioned it. And meaning that -- and also the 2029 is that first full year of in-service? So obviously, it depends on how you think about the timing of modeling construction spending and associated EDC earnings as far as the ramp-up when you look at that.

But I think the -- in terms of that full in-service year, that would be expected in the plan in 2029.

Great. And then my other question relates to the RUCO challenge to the policy statement, which had initially been turned down by the courts. But I understand that at a higher level, there's now a hearing that's been scheduled on their complaint. Any comments on that update and what you're expecting to come out of that?

Paul, it's Justin. Yes, I think our thoughts are kind of consistent. I don't think anything has changed from how we viewed the challenge from [ RUCO ] from the beginning through the process where the court kind of denied it and then decided the Superior Court decided to give them kind of their day in court. So we -- this is kind of part of the normal process. They have an opportunity to make their argument.

I think we we feel pretty strongly that there's a long precedent of the commission being able to have exclusive jurisdiction over ratemaking and doing things as part of a rate case. And I think you look at all the different regulatory mechanisms and that have withstood judgment over time. So I think from our perspective, we're not overly concerned, I haven't seen anything that causes us to be overly concerned about that challenge or kind of the procedural posture that it's currently in.

And I guess if I look at the initial court ruling, I mean, I thought it was more sort of a technical issue in terms of having a certain amount of time to file and they missed that deadline. When the Superior Court opened that up, I mean, did they just sort of disregard that time limit?

Yes. My recollection, Paul, was there was kind of a couple of different aspects, but you're right. It was kind of initially denied on a technicality, which is why they appealed it. And then the court ultimately said, no, they need to have their opportunity to be heard, and that's kind of my understanding of the posture of the case right now is that they have an opportunity to make their arguments with the appellate court.

This concludes the Q&A portion of today's conference. I would now like to turn the call back over to Tyler Franik for closing remarks.

Thanks again, John, and thank you all for joining us today and for your questions. This concludes our conference call. We appreciate your interest in Southwest Gas Holdings and look forward to speaking with many of you soon.

This concludes the Southwest Gas Holdings Fourth Quarter and Full Year 2025 Earnings Call and Webcast. You may now disconnect your line at this time. Have a wonderful day.

Welcome to Southwest Gas Holdings Third Quarter 2025 Earnings Conference Call. Today's call is being recorded, and our webcast is live. A replay will be available later today and for the next 12 months on the Southwest Gas Holdings website. [Operator Instructions]

I will now turn the call over to Justin Forsberg, Vice President of Investor Relations and Treasurer of Southwest Gas Holdings. Please go ahead.

Thank you, Joanna, and hello, everyone. We appreciate you joining the call today. This morning, we issued and posted the Southwest Gas Holdings website our third quarter 2022 (sic) [ 2025 ] earnings release and filed the associated Form 10-Q. The slides accompanying today's call are also available on Southwest Gas Holdings website. We'll refer to those slides by number throughout the call today.

Please note that on today's call, we will address certain factors that may impact 2025 earnings and discuss longer-term guidance. Information that will be discussed today contains forward-looking statements. These statements are based on management's assumptions on what the future holds but are subject to several risks and uncertainties, including uncertainties surrounding the impacts of future economic conditions, regulatory approvals and a capital project at Great Basin Gas Transmission Company that is potentially incremental to current estimates.

This cautionary note as well as a note regarding non-GAAP measures is included on Slides 2 and 3 of this presentation, in today's press release and in our filings with the Securities and Exchange Commission, all of which we encourage you to review. These risks and uncertainties may cause actual results to differ materially from statements made today. We caution against placing undue reliance on any forward-looking statements, and we assume no obligation to update any such statement.

As shown on Slide 4, on today's call, we have Karen Haller, President and CEO of Southwest Gas Holdings; Rob Stefani, Chief Financial Officer of Southwest Gas Holdings; and Justin Brown, President of Southwest Gas Corporation, as well as other members of the management team available to answer your questions during the Q&A portion of the call today.

I'll now turn the call over to Karen.

Thanks, Justin. Thank you for joining us today to discuss our results and outlook. Starting with Slide 5. During the quarter, we successfully completed our disposition of Centuri through 2 final sales transactions. This allowed us to fully pay down the remaining debt at the holding company, provided significant capital to reinvest in the core business and left us with a strong balance sheet. With our focus now fully on our natural gas regulated business, we are better positioned to address the increasing energy needs of our growing service territories.

As we enter this next chapter, operational and financial performance remain a top priority. At quarter end, Southwest Gas' trailing 12-month return on equity or ROE further improved to 8.3%, demonstrating our commitment to consistent ROE improvement over the last several years. We are optimistic for the future regulatory environments in all our jurisdictions. Later in this call, Justin Brown will discuss our anticipated rate case road map heading into the next few years as we expect new rates in effect in California in 2026 and seek approval for new rates with requests for alternative forms of ratemaking in Arizona and Nevada. We believe the future is bright for improved rate-making opportunities as we work to further improve delivered returns for our shareholders.

Significant regional energy demand is driving potential incremental growth at our Northern Nevada interstate pipeline asset, Great Basin, which could drive our already strong capital growth profile higher. We are reaffirming each of our previously communicated guidance ranges with full year net income now expected towards the top end of the $265 million to $275 million range. We continue to expect robust capital spending driven by safety, reliability and economic activity in our service territories. All our forward-looking guidance ranges exclude the potential impacts of the 2028 Great Basin expansion opportunity and the impacts of alternative forms of ratemaking opportunities in Arizona and Nevada. I'll provide more detail on guidance later in this presentation.

Moving to Slide 6. We're thrilled to have achieved the full deconsolidation and separation of Centuri. During 2025, we completed 4 follow-on offerings and 3 concurrent private placements to generate nearly $1.4 billion of net sale proceeds. A large portion of the total net sales proceeds were used to repay all debt previously outstanding at the holding company. Past August, the remaining $225 million on the term loan was paid in full, along with the remaining balance that had been outstanding on the revolving credit facility. All residual proceeds from that transaction as well as the final trade in September are expected to support Southwest Gas' capital expenditures, including the potential Great Basin expansion project, the dividend payments to shareholders and other general corporate purposes. We are excited for the future as the strategic transformation enhances transparency and aligns us squarely with long-term value creation as a fully regulated natural gas business.

As you can see on Slide 7, we are heading into the final months of 2025 on track to achieve our 2025 strategic priorities. Our utility and regulatory strategy have primarily been completed as we await final approval in our California rate case. Additionally, we continue to see the impacts of our company-wide optimization initiatives as we have observed year-to-date operations and maintenance growth that continues to be below the rate of inflation. We have begun executing Precedent Agreements from the potential shippers on the 2028 Great Basin expansion project and are working to have the rest of them finalized soon. Other activities such as work on the environmental assessment and FERC prefiling efforts are on track. Finally, with the full repayment of HoldCo debt during the third quarter, we have now completed all expected financing activities for the remainder of 2025 without having to issue new equity financing for the second consecutive year.

On Slide 8, I'd like to highlight that S&P upgraded Southwest Gas Holdings issuer and Southwest Gas Corporation's senior unsecured long-term debt credit ratings each to BBB+ with stable outlooks. Our enhanced corporate risk profile further demonstrates the positive impact of the complete separation of Centuri. As of the third quarter of 2025, our cash balance increased to nearly $780 million, and we had more than $1.5 billion of liquidity across the business, which enables us to make strategic investments that are expected to generate stable long-term returns. I'd also like to highlight the utilities net income growth, which was primarily driven by positive regulatory outcomes and strong economic activity in our service area, enhanced by cost optimization efforts. We are enthusiastic about the company's future and are confident in the promising opportunities ahead.

Before we discuss our results in more detail, as you may have seen in our press release earlier this morning, Rob will be leaving Southwest Gas Holdings December 1. The Board of Directors has initiated an internal and external search process to identify Rob's successor. On behalf of the entire management team, I want to thank Rob for the contributions he's made to the company over the past 3 years. He's been an important part of our team as we transition to become a fully regulated natural gas utility business. We wish him well in his next chapter. You can find further information on this announcement in the press release and an 8-K that will be filed later today.

Now I'll turn the call over to Justin for a regulatory and economic update.

Thanks, Karen. On Slide 10, we highlight our proposed Great Basin expansion project as we continue to make progress on finalizing Precedent Agreements with counterparties. Within the next week, we anticipate receiving final decisions from all shippers who were set Precedent Agreements.

Since we continue to receive inbound interest about expansion opportunities on Great Basin, we may consider holding a brief supplemental open season before determining the final scale of the proposed 2028 expansion. This will help clarify the magnitude and timing of this inbound interest so we can determine the appropriate course of action, including whether any interest for capacity can fit within the 2028 expansion time frame or whether there is sufficient interest to justify an expansion in subsequent years.

As is generally the case with all development projects involving multiple parties, especially projects of this size and scope, we are ultimately subject to the time lines and needs of each of the potential shippers. We are diligently working with them and remain steadfast in our commitment to help ensure their energy needs are met. While this process has taken a little longer than we initially expected, in order for us to meet the proposed in-service date of November 2028, we have started working on a parallel path to ensure that date remains viable. For example, we recently engaged in engineering procurement and construction management firm to partner with us as we work toward a prefiling application with the FERC. This firm will assist us in finalizing engineering and design work, completing the environmental assessment as well as other items necessary to file for this FERC's Certificate of Public Convenience and Necessity in the fourth quarter of 2026. We will plan to provide periodic updates as we achieve key milestones.

Moving to Slide 11. I wanted to highlight a significant filing we made in Nevada during the quarter. In September, we successfully filed our first triennial resource plan as required by a statute that was put in place during the 2023 Nevada legislative session, referred to as Senate Bill 281. Similar to integrated resource plan requirements for electric utilities, the newly required process in Nevada requires gas utilities in the state to file a plan every 3 years outlining, among other things, anticipated demand for natural gas, the sources of planned acquisitions of natural gas, the identification of the mix of supply and demand-side management programs.

The bill aimed to modernize the state's gas utility regulations, bringing them under a similar statutory framework as electric utilities to better prepare for a changing energy system and to optimize investment for the benefit of customers. This process of filing and receiving approval of a resource plan is expected to enhance certainty for investors in the state. Our current plan includes nearly $225 million of expected investments for the benefit of our customers for expansions, system integrity, including distribution and transmission integrity management programs, customer-owned yard line replacement programs and a long-term gas supply arrangement. We believe this new process allows for increased transparency and predictability for customers, investors and other stakeholders. We expect a final decision in the second quarter of 2026.

Turning to Slide 12. Here, we lay out for you a potential time line for how opportunities for alternative ratemaking in both Nevada and Arizona could play out in the near term and over the next several years. In Nevada, SB 417 is the law that was passed this past legislative session that allows for alternative ratemaking opportunities such as multiyear plans and formula rates. We currently expect to file a rate case as early as March 2026, which is 6 months following our gas planning filing. We expect new rates to be effective as early as October of 2026.

The Public Utilities Commission of Nevada has begun rule-making workshops to implement SB 417, and we're excited about the potential for this approach to streamline regulatory processes, reduce cost for customers and improve the timeliness of cost recovery. We're in the early stages of the rulemaking process, which we anticipate finishing up early next year. At the conclusion of the rule-making process, we should have greater clarity on the mechanics and time lines that will be allowed for implementing an alternative ratemaking plan. However, given the general structure set forth in SB 417 and the fact we will look to this next rate case is the basis for alternative ratemaking plan, we reasonably believe potential alternative rate-making adjustments could begin as early as 2028.

Similarly, in Arizona, following the Commission's December 2024 policy statement that supports utilities proposing formula rate plans, we expect to file a formula rate plan in Arizona as part of our next general rate case. We are currently targeting a filing for our next Arizona rate case in the first quarter of 2026. If we assume a fully litigated rate case time line, we expect new rates to be in effect during the first half of 2027 with the potential for the first annual formula rate true-up process to begin in 2028.

While the Commission has expressed support for formula rate adjustments through its published policy statement, the approval of utility plans is still forthcoming. We are encouraged by the fact that several peer utilities in Arizona have active rate cases requesting the application of formula rates. We are proactively monitoring the progress and anticipated outcomes of each of these cases as they will provide valuable insights to refine our current expectations regarding formula rate mechanics and implementation time lines. We remain optimistic about the prospects of formula rates in Arizona as this new approach could streamline the regulatory process, reduce costs for customers and improve the timeliness of cost recovery. We're excited about both of these opportunities, and we believe that alternative ratemaking enhances our ability to attract investment into both Arizona and Nevada as we continue to play our role in supporting the state's economic growth.

Turning to Slide 13. In California, we successfully reached an agreement in principle to resolve all issues in our pending rate case with the exception of cost of capital and capital structure. The agreement results in a recovery of over 90% of our adjusted ask of $43 million before any adjustments for cost of capital and capital structure. The settlement also provides for continuation of our annual attrition adjustment of 2.75% as well as continuation of several existing and new regulatory mechanisms that we propose to ensure the safety and reliability of our distribution system and to mitigate regulatory lag. Of note, the California Commission recently granted our motion seeking authority to establish a general rate case memorandum account. This essentially protects us from any potential delays in the issuance of a final decision by allowing us to recover differences between our authorized and actual revenues between January 1, 2026, and the actual effective date of the Commission's final decision.

And with that, I'll turn the call over to Rob, who will review our financial performance for the third quarter.

Thanks, Justin, and thank you, Karen, for your words earlier. It has been rewarding to work alongside the talented team at Southwest Gas as we navigated such an important time at the company. I am confident the company is well positioned for continued growth and success under Karen's leadership.

With that, I'll turn to our financial results for the third quarter. On Slide 15, we provide a walk from last year's third quarter earnings from continuing operations to the current quarter. Beginning with the utility, Southwest Gas reported higher margins supported by rate relief to better align with Southwest Gas' cost of service and capital investment as well as continued customer growth. These benefits were partially offset by higher operating and maintenance expense related in part to incentive compensation accruals, depreciation and amortization tied to ongoing capital investment and higher net interest related to the PGA liability balances. Southwest Gas Holdings corporate and administrative results reflected lower overall operating expenses and reduced interest expense due to the full repayment of the holdings term loan and revolver bank debt using proceeds from the Centuri offerings.

Overall, earnings per share related to continuing operations improved by $13.4 million or $0.19 per diluted share when compared with last year's third quarter. Consolidated EPS for the quarter was $3.74 per diluted share. The company's sale of its remaining stake in Centuri in September represented a full disposition of Centuri and qualifies for reporting as discontinued operations. Earnings related to discontinued operations, which includes the net gain on the sale of Centuri contributed $3.68 per diluted share to consolidated earnings. Slide 34 in the appendix breaks down consolidated earnings for the 3 and 9 months ended September 2025.

Moving on to Slide 16. We provide a bridge of quarter-over-quarter performance drivers for Southwest Gas. In the third quarter, utility operating margin increased by $26.8 million. This improvement was primarily driven by $22.3 million of combined rate relief across all jurisdictions, while an additional $1.6 million came from customer growth. O&M expense increased by $4.1 million compared to the prior year quarter. This increase was mainly attributable to variable labor and benefit costs, including a $4 million increase in incentive compensation. This increase was partially offset by reductions in bad debt expense and leak survey and line locating expenses. Of note, year-to-date O&M expense is up approximately 2.5% overall, less than inflation and reflective of our continued focus on cost discipline at the utility.

Depreciation and amortization increased $4.9 million, reflecting a 6% increase in average gas plant in service as compared to the third quarter of 2024. This growth demonstrates ongoing investment to enhance safety, reliability and a response to customer expansion. Other income declined by $3.4 million, driven primarily by a $3 million decrease in interest income, which is largely tied to lower carrying charges on the PGA balances. Notably, deferred purchased gas cost balances moved from a $213 million liability as of September 30, 2024, to a $356 million liability as of September 30, 2025. As a reminder, last quarter, Nevada approved our application to return these overcollected purchased gas costs to customers more quickly. We have already seen Nevada's elevated balance begin to decline compared to this year's second quarter. PGA balances are shown in the appendix on Slide 28 as well as in our Form 10-Q.

Lower comparative gains on the values associated with company-owned life insurance drove a $0.5 million decrease quarter-over-quarter. Interest expense rose $3.8 million, primarily due to interest incurred on the overcollected PGA balance compared to interest income recorded in the same quarter of last year. So the net impact of about $7 million between other income, as previously discussed, and net interest expense can be attributed to the change in the average PGA balance over the comparative periods. Finally, income taxes increased by $4.6 million, reflecting the impact of higher pretax net income during the quarter.

As shown on Slide 17, as Karen mentioned, we successfully executed 4 follow-on offerings of the company's Centuri stock between May and September of this year. In September, we completed the full separation of Centuri. These transactions, inclusive of 3 private placements collectively generated $1.35 billion of net sales proceeds and estimated after-tax cash proceeds is about $1.3 billion. The $50 million estimated cash tax on the transaction represents a low effective tax rate of approximately 3.7% due to the utilization of net operating losses and capital loss carryovers while estimated cash taxes is shown in isolation and after the utilization of net operating losses and capital loss carryovers and ultimately could adjust up or down as we consider any consolidated or combined federal or state income tax return impacts that will ultimately determine the actual NOL and capital loss carryover utilization. The sale of Centuri by means of a series of taxable sell-downs is expected to be tax efficient for shareholders.

Moving to Slide 18. We show our 2025 financing plan for both Southwest Gas Holdings and Southwest Gas Corporation. We do not currently expect any significant financing activities in the remaining months of 2025 at Southwest Gas Holdings or Southwest Gas Corporation. The 2026 financing plan is expected to be released with our fourth quarter 2025 results. Using the net proceeds from the Centuri sell-down transactions, we fully repaid all of the term loan and bank debt previously outstanding at the holding company. Remaining proceeds are expected to be deployed in the near term to partially fund the dividend as well as support future capital investments at Southwest Gas, including the potential 2028 Great Basin expansion projects.

Southwest Gas Holdings remains committed to paying a competitive dividend to our stockholders. Our planned dividend payouts in 2025 are expected to result in a payout ratio competitive to natural gas peer companies. We plan to continue to balance factors such as projected capital requirements, impacts to credit ratings, the competitiveness of the dividend yield, economic conditions and other factors and expected dividend policy sizing of earnings from continuing operations going forward. The Board generally updates dividend policy in February each year, and we expect to evaluate our recommendation of that policy between now and the reporting of our year-end results.

I will conclude by discussing our balance sheet on Slide 19. Throughout the year, we've outlined the strength of our balance sheet and commitment to maintaining an investment-grade profile at Southwest Gas and at the holding company. We were pleased to learn that on September 22, S&P upgraded Southwest Gas Holdings issuer and Southwest Gas Corporation senior unsecured long-term debt credit ratings each to BBB+ with stable outlooks, driven mostly by the exit from our position in Centuri, debt reduction at the holding company level and improving the general risk profile of the business. We expect this upgrade should lower borrowing costs, enhance access to capital and signal an improving company profile to the investment community.

On the slide, we show debt by entity. On a consolidated basis, our net debt sits at just over $3 billion across the enterprise. We are in nearly a $600 million cash position at the holdings level, reflected in the slide as the corporate and administrative line and we have about $3.7 billion of net debt at the utility. The balance sheet and liquidity position is strong with nearly $800 million of consolidated cash and another $700 million of liquidity available under our holdings level and utility level revolvers.

Back to you, Karen.

Thanks, Rob. We are pleased with our results over the first 9 months of this year and aim to carry this momentum through the last few months of this year and beyond.

On Slide 21, we reaffirm our 2025 utility net income guidance range of $265 million to $275 million but are now guiding toward the top end of the range given progress we've made throughout the year so far. For 2025 and beyond, we reaffirm each guidance metric and continue to expect the impact of the regulatory cycle to result in nonlinear net income growth over the forecast period. As a reminder, each of our forward-looking compound annual growth rates are calculated off a 2025 base year and they do not currently include any impacts related to the potential 2028 expansion opportunity at Great Basin or any outcomes related to the potential for alternative ratemaking in Arizona and Nevada in our next rate case proceedings. We expect to refresh our guidance ranges for 2026 in our year-end call this winter and will make decisions on the assumptions included in the plan at that time.

Before we move into the Q&A portion of the call, I'd like to draw your attention to Slide 22. This highlights our commitment to delivering exceptional customer service while advancing our strategic priorities and achieving strong financial performance. At Southwest Gas Holdings, we remain confident in our trajectory as a leading pure-play natural gas business. Our focus is on sustaining robust organic rate base growth driven by strong regional demand while enhancing earnings through disciplined financial management, operational excellence and constructive regulatory engagement.

With that, let's open the call for questions.

[Operator Instructions] We'll take our first question from Julien Dumoulin-Smith from Jefferies.

I appreciate it, as always. And Rob, all the best. Look, I wanted to just follow back up on Great Basin. Obviously, a good amount of time spent in the remarks here, but I do want to press a little bit to the extent possible. You talked about trying to finalize the Precedent Agreements in the near term. Can you walk through a little bit more of the specific time lines, any issues? And then more importantly, perhaps, speak to a little bit of the time line of when it would actually be included in the outlook, maybe tightening up the CapEx range as you zero on exactly the scope of what's contemplated here, if you will. And then maybe I'll throw on also if you can speak to assumptions one should be using as best you can for heuristics on ultimate capital cost and capital structure.

Julien, it's Justin. Yes, I'll try to unpack that and just follow up if there's anything I missed. So as we've talked about previously, we had conducted the open season. We had significant demand interest of capacity up to the 1.76 BCF, and we circulated Precedent Agreements and kind of draft Precedent Agreements to potential shippers. We received those back, incorporated the comments that we could and then we sent out final versions of those Precedent Agreements, which incorporated kind of the assigned capacity as well as kind of the surety requirements that we would expect of the shippers for us to proceed with the project. And we're just in the process of getting that feedback from them now on kind of a final decision of who's willing to commit and who's not. And so we'll complete that process hopefully within the next week. And then once we have that, we'll be able to assess kind of the ultimate scale of the project.

And then as I mentioned, we continue to receive inbound inquiries. So we may look at even hosting a supplemental open season that's relatively brief to just kind of firm up what is the capacity and kind of the final estimates around the 2028 expansion. I think when we think about kind of guidance and different things, we would probably look to kind of our regularly scheduled fourth quarter call in February to kind of update as we should know at that time what is in and what is out and what that project looks like and kind of more of the assumptions on the financing and different things that you alluded to. Hopefully, that addresses what you're getting at.

Yes. Justin, I appreciate it. Actually, if I can ask you to elaborate a little bit. I mean, there's a $1.2 billion to $1.6 billion range here. You talked about up to 1.76 BCF a day. Is there a scenario here where that's upsized to address what you just alluded to with that additional open season? Or is that kind of contemplated in that range as far as you're concerned for CapEx?

Yes. Based on that range we provided, that's reflective of kind of the feedback we were getting and kind of what our estimated cost was in order to upsize the system to meet that potential capacity.

Okay. Excellent. I appreciate that. And ultimately, let me -- if I can press it this way. If it is, as you suggest that you'll be able to put this together into some form of guidance by 4Q, should we expect an integrated CAGR in tandem with that, that would correspond with the '28 in service?

Yes. We'll assess it at that time as we get information on the project, and we're able to kind of factor that in with our overall capital expenditure plan and kind of the guidance we -- we've been giving. I think as last year, we gave a 5-year guidance on CapEx, so it would be incorporated in that.

Excellent. All right. I'll leave it there. All the best. Speak to you soon.

The next question comes from Chris Ellinghaus at Siebert Williams Shank.

Rob, on Slide 16, the margin increase for the quarter, there's a delta for a third item beyond rate relief and customer growth. What's included in that last little sliver?

Yes. I mean, there's the rate relief, there's customer growth and then there's just recovery mechanics on like interest recovery mechanisms and whatnot.

Okay. That helps. As far as Great Basin goes, so you get the agreements here next week and you might do an open season. Does that suggest that the FERC filing is sort of late in the quarter and what's your anticipation of the FERC review schedule?

Chris, it's Justin. Yes, we're still targeting based on the initial inquiries that November 2028 in-service date, which is why we've started on a parallel path as we're firming up kind of commitments on the shippers to ultimately determine who's in and who's out. We've started that process. And based on our schedule and timing, we feel like we're still on schedule to make a filing in the fourth quarter of '26 with FERC for that certificate of public convenience and necessity.

So you said that you thought this next potential open season could be fairly quick. Does that leave you adequate time to get something done in December?

Yes, we believe so. I think our approach would be to have a pretty quick turnaround to kind of finalize up anything in terms of a 2028 expansion. That would be the intent behind it is to be able to stay on track.

Can we presume that you would prefer to have the full magnitude of the expansion in the first phase as opposed to having a future expansion?

Yes, Chris, I think that's a fair assessment. I think just when you think of economies of scale and ultimately the rates that the shipper would pay, obviously, we want to try to maximize that initial expansion. It's just we continue to see -- receive inbound inquiries around kind of maybe additional needs down the road. And so we want to try to factor that in so we can be as efficient as possible with the expansion.

Okay. And lastly, the Nevada process for the alternative ratemaking, does that leave you with sort of a 3-month window of uncertainty as to filing? And how do you perceive that process so far? Does it seem like it's on your expected time line?

Yes. So the -- as I mentioned, the commissions going through the workshop process now. We're working diligently with stakeholders. I think to the extent we can get kind of consensus regulations that will help expedite the process. And if not, I think we've talked about in the past where part of the language of SB 417 allows us to use that rate case even if we made a filing after we filed the rate case, we could make a request for formula rates or alternative form of rate making after we filed our rate case as long as we do that within, I believe it's 6 months of a final decision of that rate case. So we feel really good about using this next case is really the basis for an alternative formula or an alternative ratemaking plan in Nevada.

And to your point, it's really going to -- we'll know more over the next couple of months on whether that's included upfront in the filing that we make that we're targeting in March or if it's something that happens at a subsequent date but is incorporated as part of that rate case process and they use the information included in the rate case to form the basis of that alternative ratemaking plan.

The next question comes from Paul Fremont at Ladenburg.

And to Rob, best wishes to you. It's been great working with you. And I guess my first question is how long does the company think it will take to find a CFO and who's going to be performing that function after December 1?

So as we announced in the press release, Paul, that we would be -- the Board has undertaken an internal and external review. We don't really have a specific time line that we have put forth. Our focus is on getting the right person in the job and having the right skill set for the company moving forward.

And I mean is somebody going to be performing the CFO function starting on December 1?

Absolutely. We have -- whether we would name someone in an interim position, if we don't haven't named somebody at that point, we will -- the Board would be making that decision. Otherwise, we have a very strong bench within my finance and controllers group, and they will be able to function without any problem in handling those duties.

Great. And then I guess I wanted to get a sense of the cash position and when you're actually going to start using that cash for construction. When would construction start, if you were to move forward on Great Basin?

Justin, do you want to address the time line on the Great Basin?

In what regard, Paul, sorry?

I just want to get a sense. I mean, are you going to put -- are you going to leave like the cash in treasuries between now and when you actually need it for construction? Are you going to have...

Paul, this is Rob. Yes, we obviously have put that cash to work in short-term funds and whatnot. So the cash is obviously earning the short-term rate in the interim. Justin Brown and his team are assessing the Great Basin project and the scoping of that. Obviously, there could be some long lead time deposits on various equipment that would be required. So as that project continues to get more refined, then we can comment more on the usage of the cash. But obviously, sitting on a very nice position and can move forward on that project given those balances. The -- I think beyond that, I don't know that there's much else to comment on.

So for modeling purposes, we should assume that it will remain in short-term investments until the actual construction starts to ramp up?

That's right.

And then last question. With Centuri gone, are you expecting to give EPS guidance on the fourth quarter call? Or are you going to stay with sort of net income guidance?

I think we've talked about that, and we kind of commented along the way that we do expect to give kind of more longer-term EPS guidance that I think to maybe Julien's earlier question too, would incorporate some of these potential opportunities along the line.

The next question comes from Tim Winter at Gabelli.

And congrats on the strong update. And Rob, best wishes in your future endeavors. We'll miss you. My first question, I think, is for Justin. If you could help me understand how the formula rate would work in Arizona or at least what your expectation is. So you'll file a historical test year in the first quarter at '26, maybe 15 months for a decision and then come what January 1 of '28. They'll look at the earned ROE and if there is an adjustment, is that made on a prospective basis or a historical basis? Or how is that going to work?

Yes. Those are all good questions, Tim. And what we're really kind of utilizing is the framework is really the policy statement itself. I think some of these nuanced details are going to get worked out as they start approving them as part of rate cases, which is why we're really focused on some of the pending rate cases right now to kind of help inform that as we go forward.

When you look at the policy statement itself, I think, generally speaking, the idea and as you look at the testimony that's been filed in some of these other cases, the idea would be, as you laid out, you have a rate case. At the end of that rate case, you would then have a period of time, but then you would -- I think they referred to it in the policy statement an annual true-up. I think some of that may come down to, are you including post test year plan in your rate case, are they not doing that anymore and they're just going to the formula, that may determine ultimately some of the timing there.

But I think when you look at it, it would be, to your point, you would file a case in '26, a decision in '27. We would look at probably making a filing sometime the end of '20 -- I'm sorry, at the beginning of '28. And again, there's a review period in different things on when before the rate actually goes into effect. And so our thought would be probably sometime in that '28 window is when we'd expect to see a true-up rate that goes in effect that would be the difference between what you've been authorized in your last case versus what you're actually experiencing and truing up rates to reflect that difference, and then you would do that annually for a period of time.

Okay. Okay. And then if I could move over to -- back to a Great Basin. Number one, are there any potential major obstacles that you're aware of? And then number two, assuming the high end of the range that you forecast in November '28 [ COD ], what would be the earning -- sort of the earnings profile going forward? I mean, would there be any AFUDC recorded during construction? Or how would the -- thereafter, would it be there a step-up or a ramp up? Or how do I think about that?

Yes, Tim, I'll start with the first part. In terms of major obstacles, we don't really see any as we've looked at the project. I think the biggest obstacle is just working with the different counterparties on kind of their timing, their capacity needs and getting that firmed up is really probably the biggest obstacle. But when we think about the project itself, once we actually have signed Precedent Agreements from counterparties, the project itself is really an upsizing of our existing system and the existing right of way with compressors. So we don't see any major concerns from a project execution standpoint.

Again, similar to what we mentioned earlier, I think when we think about the financial aspects of it, I guess, to answer your question, yes, we would anticipate accruing AFUDC during the project. But when we think about kind of the profile of that and timing, I think that's something that we would have better insight on at the February call just based on where we are in terms of getting -- kind of finalizing the scale of this project and working with the counterparties to get people signed up.

[Operator Instructions] The next question comes from Christopher Jeffrey at Mizuho.

Maybe just 1 last 1 on Great Basin. It seems like the price per dekatherm was updated to $18 per month. Just kind of curious how firm that number is now that it's in the Precedent Agreements and maybe what does it change, if anything, on economics versus when the range was $14 to $17 prior?

Yes. This is Justin again. Yes, we don't really anticipate that being a material change to the economics of the project. We had originally scoped it out as a $14 to $17 based on kind of initial feedback from the open season process. And then as we firmed up those inquiries and capacity requests as well as our internal designs, that's how we landed on the $18, and that's what was included in the Precedent Agreement. So that's kind of the most up-to-date number based on the capacity of 1.76 BCF that people had expressed interest in.

This concludes the Q&A portion of today's conference. I would now like to turn the call back over to Justin Forsberg closing remarks.

Thanks again, Joanna, and thank you all for joining us today and for your questions. This concludes our conference call. We appreciate your interest in Southwest Gas Holdings and look forward to speaking with many of you soon as we emerge from the quiet period.

This concludes today's Southwest Gas Holdings third quarter 2025 earnings call and webcast. You may disconnect your lines at this time. Have a wonderful day.