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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.