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Wednesday, Feb. 25, 2026 at 12 p.m. ET
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Southwest Gas Holdings (NYSE:SWX) completed its transition to a fully regulated utility business in 2025, culminating with the divestiture of Century and the full repayment of holding company debt, which led to a credit upgrade to BBB+ by S&P. Management advanced its regulatory agenda with new rate case filings in Arizona and Nevada, including the company’s first formula rate plan and the prospect of alternative rate making, which are intended to reduce regulatory lag and enhance earnings visibility. The 2028 Great Basin expansion project secured full capacity subscriptions via binding precedent agreements, underpinning a planned $1.7 billion capital investment that is expected to deliver a material margin step-change when in service.
Tyler Franek: Thank you, John, and hello, everyone. We appreciate you joining the call today. This morning, we issued and posted to the Southwest Gas Holdings, Inc. website our fourth quarter and full year 2025 earnings release and filed the associated Form 10-Ks. The slides accompanying today’s call are also available on the Southwest Gas Holdings, Inc. website. We will 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, Inc., Justin Forsberg, Chief Financial Officer and Treasurer of Southwest Gas Holdings, Inc., 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.
Karen Haller: 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 Century in September. An 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 Century, termination of the ICON Cooperation Agreement, and strong strategic position, I determined that after nearly three decades with the company, it is the right time for me to retire. One of the most significant responsibilities of a CEO and board of directors is to plan for the CEO’s succession. The Board was prepared for this milestone and appointed Justin Brown as 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 am confident that he is the right leader to guide the company in its next phase. I will remain involved as an advisor 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 environments, with the inclusion of Arizona formula rates and alternative rate making in Nevada, along with the opportunity we project to materialize at Great Basin Northern Nevada. Because of these opportunities, this growth is expected to be front-end loaded over the first three years, so we expect the earnings growth rate to be even higher in 2028 to 2029. Jay Ford 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 Century. 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 step of the Great Basin project, and preserving our balance sheet strength by implementing our 2026 financing plan.
On slide 7, I would like to highlight that following the completion of our Century disposition, S&P upgraded Southwest Gas Holdings, Inc.’s 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 had 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 would 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 will turn the call over to Justin for a regulatory and economic update.
Justin Brown: Thank you, Karen, for your generous words. More importantly, thank you for your leadership and contributions to Southwest Gas over the past 29 years. I am 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 am 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 in delivering safe, reliable, and affordable natural gas service. We have a strong foundation, a clear strategy, and the right team to deliver.
I am 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 would 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 rate making 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 timeline for how our alternative rate making 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 2025 by Governor Joe Lombardo, authorizes alternative rate making plans. 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 rate making adjustments to begin as early as 2028.
In Arizona, the Arizona Corporation Commission adopted a policy statement in December 2024 signaling their openness to having regulated utilities propose 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. 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 have 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 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 Commissioner review and approval.
Moving to slide 11, we are initiating 2026 and 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 the Great Basin expansion including engineering, environmental reviews, permitting, and other preconstruction activities necessary to support an efficient project timeline.
Over the next five 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 five-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 800,000 Mcf 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 fieldwork.
The FERC and NEPA review processes are expected to occur during 2027 with construction to begin following FERC approval and with an anticipated in-service date near the end of 2028. We recently achieved an important milestone with pre-filing 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 will turn the call over to Jay Ford, who will review our financial performance for the year.
Jay Ford: Thank you, Justin. Turning to slide 14. While consolidated GAAP earnings per diluted share for 2025 were $6.80, this included discontinued operations. During the year, the company completed the sale of its remaining shares of Sentry on 09/05/2025, representing a full exit and qualifying Sentry for discontinued operations reporting. The transaction generated a net gain of approximately $260 million, which, when combined with the Century 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, 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 over-collected purchase gas costs, and modestly higher operations and maintenance expense. Lower overall expenses at the holding company were driven by a significant reduction in interest expense following the full repayment of prior HoldCo debt using proceeds from the Century transactions. This debt payoff was the primary driver of the improvement in earnings shown on the table.
Turning to slide 15, you will 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 $203.9 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 two 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 in contributions to the Southwest Gas Foundation compared with 2024. Net interest deductions increased $19.4 million driven largely by the anticipated interest incurred on over-collected PGA balances and higher Variable Interest Expense Adjustment mechanism amounts in Nevada associated with IDRBs. As I mentioned a moment ago, the impact to operating margin and 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 will note that partially offsetting GAAP net income was a $16.4 million state income tax apportionment benefit associated with certain one-time events, and we have adjusted this 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 impacts 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 enter 2026 with a significant beginning cash balance of nearly $600 million, largely representing the remaining proceeds from the Century separation completed in September 2025, after having utilized a portion of those excess proceeds to pay dividends to stockholders during 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, Inc. at year-end 2026. During 2026, we expect approximately $325 million of net Southwest Gas bond issuances, along with modest revolver usage at 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 debt 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, Inc. during this investment cycle. For 2025, we calculate S&P-adjusted FFO to debt of approximately 19.7% at Southwest Gas Holdings, Inc., 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 forego high-volume equity issuances while utilizing the ATM for modest equity needs, as well as the reestablished 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 years. 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, Inc. 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 purchase gas costs or PGA balances. Notably, all of our outstanding debt is held by the utility.
You will 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 three 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 flow strengthen—particularly as the planned 2028 Great 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 will walk through our new 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 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 will 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 five-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, 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 five years ending in 2030.
This capital plan is focused on safety, system integrity, reliability, and new business distribution system growth of the utility, along with the incremental investment required to support the growing transmission business. We are also initiating a five-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 non-service 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.
Karen Haller: Thank you, Jay Ford. Before we move into the Q&A portion of the call, I would like to draw your attention to slide 23, where we highlight our commitment to delivering exceptional customer service, disciplined financial management, maintaining a constructive 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: Thank you. You may remove yourself from the queue by pressing star 2. We will take our first question from Julien Dumoulin-Smith from Jefferies.
Julien Dumoulin-Smith: Hey. Good morning, team. Just really nicely done, I have to say, at the outset. This incredible update. Lots to ask here, but really have to acknowledge it at the outset. And, obviously, Karen and 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 start at the top. I am sure others will have a bunch. Just talk about the equity. Right? I mean, big plan, big 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 yourself latitude in the FFO to metrics through the construction cycle here? Just trying to gauge. Obviously, you have disclosed 2026 equity or lack thereof, but how are you thinking about the ramp 2027, 2028? That is the first question. I have a follow-up.
Karen Haller: Thank you, first of all. I appreciate it. And I will let Jay Ford answer that question.
Jay Ford: Yeah. I appreciate the question, Julien. I think it is a good question. You know, when you think about the—yeah. I will start with kind of the credit metrics things. Obviously, we have more than 500 basis points above our downgrade threshold at this point. And we are committing to targeting that of 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 at the holding company first to sort of offset those with really minimal equity needs.
I think the way to think about it—obviously, you mentioned we do not anticipate needing anything in this year. But on a go-forward basis, I think the way I would put it is we have a shelf that expires at 2026; we will be renewing and extending that shelf. We do not anticipate upsizing our existing $340 million ATM.
Julien Dumoulin-Smith: Yeah. That—yeah. That—yeah. I suppose that is a signaling in and of itself as to how you think about the total equity you will need through the plan. Right?
Karen Haller: We think so.
Julien Dumoulin-Smith: Excellent. And then, look, let’s talk about the project itself. Right? I mean, you talk 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 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 interest that does emerge here. I mean, you talk 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?
Justin Brown: Yeah. Hey, Julien. It is Justin. And yeah, to your point, you know, we went through kind of an 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 have described in the past, at some point in time, we had to kind of coalesce around an in-service date that the majority were focused on. And so we picked the 2028 number. And that is really kind of what we locked in on. Those customers that were interested in service by, you know, kind of end of calendar year 2028, we had to kinda draw the line.
And so I think to your point, when we think about kind of future demand, future interest, I think there is definitely some there because we had received much more inbound requests than what actually signed up. 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 things as we move forward that I would encourage you to think about is, one, as 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 does not come in at that exact number. It is virtually impossible. So when we complete the design, we will compare that design, kind of efficient design, to what capacity it will actually hold. If there is an opportunity to do a supplemental open season to fill up any remaining capacity based on the design, we will 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 will continue to work with prospective shippers on kind of what their interest is, what their timing is, and we can always look to evaluate, you know, again, kind of maybe another open season for a different date down the road.
Julien Dumoulin-Smith: Right. Last nuance here, if I can squeeze it in, the cadence of earnings uplift. I mean, obviously, it is back-weighted here, but can you speak to, you know, that as well as what you are thinking on closing the gap on lag here in Arizona and Nevada as well as part of this updated plan.
Justin Brown: Yeah. I will start with the regulatory construct and how we are looking at our continual 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 have got two sizable rate cases we are getting ready to file. We think they are 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 are going to be designed, obviously, each state’s going to be a little bit different. But I think you could look at the UNS Gas decision from last week. I think that is 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. You know, I think we have always said we are hopefully able to reduce kind of what has been our historical gap of 160 basis points.
In combination with Nevada and Arizona, we are hoping to cut off about 100 basis points, which is our goal.
Jay Ford: Right. We have the run-rate base growth of the underlying utility of about 7%, which really supports something that you can sort of model through the whole five-year plan at that earnings trajectory. As we tighten up that lag, earnings should be aligned pretty well with rate base growth—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 anticipated in-service at Great Basin, that is where I pointed to the, you know, we see about 15% to 17% EPS growth rate over that 2028 to 2029 period from now.
Julien Dumoulin-Smith: Excellent. Thank you guys for clarifying. Best of luck and congrats again, I have to say.
Jay Ford: Thanks, Julien.
Karen Haller: Thank you.
Operator: Your next question comes from the line of Eli Johnson from JPMorgan Chase. Your line is now open.
Eli Johnson: Hey, guys. Thanks. Maybe just thinking about the kind of post Great Basin in-service earnings contribution. I know you have talked quite a bit about, you know, the back half versus the front half of the earnings CAGR. But can you just talk 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, you know, because it I could about some real inflection sort of in that 2030 time period based on those earnings contributions. Thanks.
Jay Ford: I think that is where we can point to the margin that 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 or toward the end-of-the-year in-service date 2028, that margin contribution expected fully in 2029 and in 2030. Because I will just remind you and everybody on the call that we are expecting once we—prior to in-service—that we would execute minimum 20-year transportation service agreements that would bring in that margin. And then so that is kind of the Great Basin contribution, if you will, for those outer two years to margin.
And then you have got, as I mentioned a moment ago, the 7% kind of rate base growth of the underlying utility.
Eli Johnson: Got it. And then I think you touched on it 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 and that language specifically.
Justin Brown: Hey, Eli. It is Justin. Yeah. I think that is 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 is a reasonable way to look at it.
Eli Johnson: Great. Thanks, guys.
Operator: Next question comes from the line of Christopher Ellinghaus from Siebert William Shank. Your line is now open.
Christopher Ellinghaus: Hey, everybody. How are you? 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?
Justin Brown: Hey, Chris. Yeah. You bet. So, you know, the legislation was passed last summer. They held their first workshop in September, held another one in January and February. And again, it is just kinda working through putting together kind of draft language, draft regulations. I think the good thing about the Commission is they really kind of put an emphasis on trying to get consensus among the stakeholders. So there is a lot of work around kind of just, you know, evaluating kind of the competing interests of different language people want, what is required by the legislation. There is just a lot of back and forth on working on that consensus.
We had our last workshop just last week, last Friday, I believe. And I think we feel pretty good about we are getting near 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.
Christopher Ellinghaus: Okay. That helps. Vis-à-vis the UNS Gas outcome, you got any thoughts about ROE and relative to your discussion about the 100 basis point improvement target, does that incorporate, you know, your thoughts about where their head is on ROE?
Justin Brown: Yeah. Chris, this is Justin again. I think generally speaking, I mean, the decision obviously just came out last week, but I think we have always kind of looked at that, and I think one of the things that we are 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 are going to, and I think they have 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 are 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, you know, 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 UNS Gas case, I think the fairway is kind of defined for everybody, and so we will be able to kind of all work and see where we end up with the different utilities.
Christopher Ellinghaus: 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 not necessarily consolidated in maybe the 2030 sort of endpoint is part of it. But that does not include any kinds of upsides that you see for Great Basin longer term. Is that right?
Justin Brown: Justin again. Yeah. You are spot on. That is just kind of when we think about, you know, the historical and kind of the current investment in the utility, that is really what that was designed is to kind of, we expect kind of consistent strong growth at the utility, and that is what that reflects. So it does not 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.
Christopher Ellinghaus: Okay. Lastly, when you are 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 cost into Great Basin?
Jay Ford: Yeah. I think it is a great question, Chris. You know, from our perspective, I think one way to look at that is we do not expect it to be permanent, I will say that, because we do expect—you know, I think where I will go with this is, you know, we sold Sentry, 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 will 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.
Christopher Ellinghaus: Okay. Let me ask you one more thing. You talked about maybe having some larger upside to the dividend growth later. Can we presume that once Great Basin is in service?
Jay Ford: Yeah. I think that is fair. Kind of along the same lines of what I just mentioned.
Christopher Ellinghaus: Okay. Great. Thanks a bunch. Appreciate the details.
Jay Ford: Thanks, Chris.
Karen Haller: Thank you.
Operator: As a reminder, if you have a question, please press 1. Next question comes from the line of Gabe Moreen from Mizuho. Your line is now open.
Gabe Moreen: Hey. Good morning, Eric. Good morning, everyone. Just congrats again to Karen and Justin. I just had one question around Great Basin, although it is 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 is E&C, compressors, you know, pipe, just kind of where you really stand in that process, and how you might be thinking about de-risking some of that at this moment. So maybe if you can address that, that would be great.
Justin Brown: Yeah, Gabe. It is Justin. Yeah. As I indicated in my remarks, I mean, I think we are working—we are trying to be very proactive from a supply chain standpoint, going through the pre-filing process with FERC to just really kind of mitigate any of those kind of typical project risks, if you will. Obviously, shipper risk is another one in terms of, you know, and that is why we went through kind of an elongated process to kind of make sure that we had firm precedent agreements signed up, in order to kind of again try to mitigate risk associated with the project. We will 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 is 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 will have an updated cost at that point in time. So I think that is a good marker for kind of, you know, we are going with what we believe is kind of our best estimate right now.
When we go through this process, we are going to know more in nine months, and when we make that filing with FERC, you know, we will be able to dial that in even a little bit more. And so that is kind of a good mile marker, if you will, to keep a lookout on in terms of kind of what we anticipate the final project cost to be.
Jay Ford: And maybe, Gabe, I can just add something. I think you are getting at as well. You know, it is a balance, which I think is what you are kind of pointing to, between trying to minimize the spending prior to getting a certificate from the FERC with making sure that we are mitigating some of these supply chain issues that Justin talked about, and 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.
Gabe Moreen: Thanks, guys. And I know I told you one question, but one minor follow-up. To the extent you are going through the open season and you got 800,000 a day of capacity, to what extent were not further upstream constraints on procuring gas or capacity a constraint on some of your customers here signing up for capacity?
Justin Brown: Yeah, Gabe. This is Justin again. I think that really is our understanding, our customers have not expressed any restrictions in that regard. Obviously, that is something that they are responsible for where we provide the pipeline for them to flow the gas supplies that they purchase through. But, yeah, we are not aware of that. I think our understanding is there is sufficient capacity on the upstream suppliers as well to meet those needs.
Gabe Moreen: Great. Thanks.
Operator: Your next question comes from the line of Ryan Levine from Citigroup. Your line is now open.
Ryan Levine: Hello. Had a couple of questions around just your guidance. In your by 2030, are you assuming that you are 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 is actually in your 2030 estimate?
Jay Ford: Yeah, I think that is a good question. I think the way 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 are—whatever we have in our plan, right—as far as offsetting the equity needs using some HoldCo leverage. So it is not necessarily by 2030. I think based on what I mentioned earlier in one of the Q&As around would Great Basin be able to—is that permanent debt at the HoldCo, which I said it is not. Right?
So you would actually see some, I think, some improvement in the current plan we have out there. We would see some improvement in the FFO-to-debt metrics above that trough year, which is likely that 2028 year.
Ryan Levine: 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, are those the key drivers of the outlook?
Justin Brown: Yes, Ryan, it is Justin. Yes, I think the guidance that we provide, we have made some reasonable assumptions around kind of the timing of formula rates and kind of what that might look like. So that is embedded in that range.
Ryan Levine: Okay. Well, congratulations to Karen and Justin, and appreciate the comprehensive update.
Jay Ford: Thanks, Ryan.
Karen Haller: Thank you.
Operator: Your next question comes from the line of Paul Tremont from Ladenburg. Your line is now open.
Paul Tremont: Congratulations on the update. And best wishes to Karen and also to Justin. Really two 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 of somewhere between 6/46–80. Am I thinking about that correctly, or am I missing something there?
Jay Ford: Yeah. Paul, I appreciate the question. Obviously, we cannot give you 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 of in-service. And so, obviously, it depends on how you think about the timing of modeling construction spending and associated AFUDC earnings as far as the ramp up when you look at that. But in terms of that full in-service year, that would be expected in the plan in 2029.
Paul Tremont: 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 is now a hearing that has been scheduled on their complaint. Any comments on that update and what you are expecting to come out of that.
Justin Brown: Hey Paul, it is Justin. Yeah, I think our thoughts are kind of consistent. I do not think anything has changed from how we viewed the challenge from RUCO from the beginning of the process where the court kind of denied it and then decided, the Superior Court, decided to give them 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 feel pretty strongly that there is a long precedent of the Commission being able to have exclusive jurisdiction over rate making 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 are not overly concerned. I have not seen anything that causes us to be overly concerned about that challenge or kind of the procedural posture that it is currently in.
Paul Tremont: I guess if I look at the initial court ruling, I mean, I thought it was more a 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?
Justin Brown: Yeah. My recollection, Paul, was there was kind of a couple different aspects, but you are 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 is kind of my understanding of posture of the case right now is that they have an opportunity to make their arguments with the appellate court.
Paul Tremont: Great. Thank you very much. That is it for me.
Jay Ford: Great. Thanks, Paul.
Karen Haller: Thank you.
Operator: 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.
Tyler Franek: 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, Inc. and look forward to speaking with many of you soon.
Operator: This concludes today’s Southwest Gas Holdings, Inc. fourth quarter and full year 2025 earnings call and webcast. You may now disconnect your line at this time. Have a good one.
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