Black Hills (BKH) Q1 2026 Earnings Transcript

Chief Executive Officer — Linden R. Evans

Chief Financial Officer — Kimberly F. Nooney

Vice President, Regulatory and Governmental Affairs — Marne M. Jones

Linden R. Evans: Thank you, Sal. Good morning, and thank you all for joining us today. I will provide a summary of our Q1 2026 results, our strategic progress, and our progress with our pending merger with NorthWestern Energy. Kimberly will provide our financial update, and Marne will provide our business update, including key projects, our progress with large load opportunities, and our solid regulatory execution. In April, our industry recognized Line Mechanic Appreciation Month. Let me start by pausing to recognize our remarkable team of men and women, many of whom are tuning in today.

You are often the face of our company and industry, which our customers and communities respect, admire, and rely on—ensuring our system is operating reliably, and restoring interrupted service as safely and efficiently as possible. When most seek shelter during a weather event, you are the team that heads out into the storm. Thank you for all you do and the sacrifices you and often your families make to keep the lights on and for what you do every day to keep our customers safe. Our first quarter strategic achievements are outlined on slide three.

Following an excellent year of results for our stakeholders in 2025, I am very proud of our team’s continued success, carrying our positive momentum into 2026. We continue to deliver safe, reliable, and affordable energy to our customers and communities while executing on our strategic growth opportunities. We are off to a solid start with reaffirming our earnings guidance range and maintaining our solid financial position and credit ratings. We made regulatory progress advancing our Arkansas rate review and requesting our first rate review in more than a decade for South Dakota Electric.

We also continued construction of our 99-megawatt Lang Two generation project, which is on schedule to be placed in service later this year, and the ongoing construction of our 50-megawatt battery storage project as part of our clean energy plan in Colorado that we commenced in Q4 2025. Large load customers, including hyperscale data centers, continue to offer significant growth opportunities representing more than 3 gigawatts of potential demand, including 600 megawatts by 2030 within our current five-year financial plan. We are also negotiating with high-quality partners to reach agreements to serve this pipeline.

This includes a 1.8-gigawatt data center being developed in Cheyenne, where we have executed an agreement that supports our reservations for generation equipment as part of the mix of resources to serve this potential customer, as we continue to advance negotiations toward reaching definitive agreements. Additionally, we are optimistic about the future upside potential of our current pipeline stemming from Microsoft’s recent announcement to acquire 3.2 thousand acres of land in Cheyenne, Wyoming, for future data center expansion. As a reminder, we approach our growth pipeline with caution, restricting it to demand that is covered by nondisclosure agreements and being actively negotiated.

The opportunities we are executing on today, along with this future potential for upside, provide depth and durability to our long-term growth profile. Slide four outlines our $4.7 billion five-year capital plan. We invest in our natural gas and electric customers’ core needs for safety, reliability, and growth. Our current capital plan includes minimal investments to support the 600 megawatts of data center demand already in our financial plan, which we expect to serve mostly through market energy procurement. We are also developing opportunities for investment that are not currently in our plan. This would include generation and transmission builds, part of a mix of resources to serve growing, large load customer demand.

Moving to slide five for an update on our merger with NorthWestern Energy. We made solid progress alongside NorthWestern in advancing our planned merger. Both companies received favorable shareholder votes on April 2, 2026. The Hart-Scott-Rodino Act’s antitrust waiting period expired on April 20, 2026, satisfying an antitrust condition to closing. And we made state regulatory progress with settlements with certain key intervenors in all three states—Montana, Nebraska, and South Dakota. We anticipate securing all state regulatory approvals and FERC approval to finalize the merger within the second half of this year.

As I wrap up my prepared remarks, we continue to deliver solid results for our stakeholders as we execute on our customer-focused capital plan, continue our regulatory progress through multiple rate reviews, meet the growing demand of our customers, and maintain positive momentum through our large load pipeline while maintaining protections for our customers, and complete our planned merger with NorthWestern. With that, I will turn the call over to Kimberly for our financial update.

Kimberly F. Nooney: Thank you, Linden, and good morning, everyone. We had a successful first quarter executing our strategy and delivering results within our expectations even with the impact of very warm weather. We are on track to achieve our earnings guidance as we maintained our solid investment-grade credit ratings and strong liquidity. On slide seven, we provide a bridge for Q1 2026 EPS compared to Q1 2025. We delivered GAAP EPS of $1.73, which included $0.05 of merger-related transaction costs. Adjusting for these costs, we reported $1.79 of adjusted EPS compared to $1.87 in Q1 2025. One of our warmest winters in history, including record warm temperatures in Wyoming and Colorado, weighed on demand by $0.18 per share compared to Q1 2025.

For the quarter, this reflected $0.13 of unfavorability compared to normal weather, which is our base assumption in setting our earnings guidance range. With this backdrop, I am proud of our team’s strong execution as we maintain confidence in our ability to deliver on our full-year earnings guidance. We delivered $0.24 per share of new rates and rider recovery margin and $0.10 of lower O&M excluding merger costs. These positive drivers offset $0.16 of higher financing and depreciation costs and a large portion of the impacts of weather and lower retail usage. We delivered favorable O&M for Q1, and excluding $0.05 per share of merger-related costs, we reduced our O&M expenses by $0.10 year-over-year.

This reduction was primarily driven by $0.04 of lower employee costs and other O&M reductions of $0.06 per share. Excluding merger-related costs, we are on track to deliver O&M within the earnings guidance target provided. Financing costs increased $0.10 per share, including $0.09 per share from the impact of new shares and $0.01 of higher interest expense net of AFUDC. Depreciation expense increased by $0.06 per share driven by new assets placed in service, including our $350 million Ready Wyoming transmission project placed in service at the end of 2025. Further details on year-over-year changes can be found in our earnings release and our 10-Q to be filed with the SEC later today.

Slide eight presents our solid financial position through the lens of credit quality, capital structure, and liquidity. We remain focused on maintaining a healthy balance sheet with our stated credit metric targets of 14% to 15% FFO to debt, which is 100 basis points above our downgrade threshold of 13%, and at or better than 55% net debt to total capitalization. Given stronger forecasted cash flows in 2026, driven by new capital projects placed in service, executing upon our regulatory initiatives, and increasing large load customer growth compared to last year, we expect a significantly lower total equity need of $50 million to $70 million in 2026.

During the first quarter, we issued $41 million of equity under our ATM program, positioning us well with minimal equity needs for the remainder of the year. Our next debt maturity is in January 2027, with $400 million of 3.15% notes to be refinanced. We are evaluating refinancing options for later this year. We maintain strong liquidity with approximately $500 million of availability under our revolving credit facility at quarter-end. Financial outlook is listed on slide nine. We reaffirmed our guidance range of $4.25 to $4.45 of adjusted EPS, which represents 6% growth at the midpoint over 2025.

New rates and rider recovery from capital projects, large load demand growth and other organic customer growth, and our solid financial position drive strong confidence in our ability to deliver in the upper half of our 4% to 6% long-term growth target. Our plan includes large load demand contributing more than 10% of growing consolidated EPS beginning in 2028, reaching 600 megawatts by 2030. Also, as Linden outlined, we are pursuing more than 2.5 gigawatts of large load opportunities, which represent significant upside to our current financial plan. To serve these opportunities, each of our customers desires a unique mix of resources with varying ramp schedules.

From a financial perspective, this complexity requires multiple negotiated agreements with earnings profiles designed to match the risks and considerations for each resource type under our Large Power Contract Service tariff in Wyoming. Slide 10 illustrates our industry-leading dividend track record. In January, we increased our dividend, extending our track record of increases to 56 consecutive years in 2026. Based on our current annualized dividend, we continue to target a 55% to 65% payout ratio. A dependable and increasing dividend is an important component of our strategy to deliver long-term value for our shareholders. I will now turn the call over to Marne for a business update.

Marne M. Jones: Thank you, Kimberly, and good morning, everyone. I will provide an update on our current capital projects, discuss progress on our large load demand pipeline, and finish with a regulatory update. Moving to slide 12. Our 99-megawatt Lang Two generation construction project, which will serve our customers in western South Dakota and northeastern Wyoming, continues on schedule and will be placed in service in the fourth quarter. The utility-owned natural gas-fired generation resource replaces aging generation facilities with modern Wartsila engines and supports updated reserve margin requirements. Recovery of this investment will be requested through the South Dakota generation rider, which we intend to file during the second quarter, and our Wyoming rate review request filed earlier this year.

Slide 13 outlines our Colorado clean energy plan. During the first quarter, construction continued on our utility-owned 50-megawatt battery storage project in Colorado, to be completed and in service in late 2027. During the first quarter, we also signed a 200-megawatt PPA for solar resources to serve Colorado customers as previously approved by the Colorado PUC. Together, these resources support our progress toward the state’s clean energy plan with an emissions reduction goal of 80% by 2030. Slide 14 outlines our flexible service model for large load customers and our data center demand pipeline of more than 3 gigawatts.

Our unique tariff offers flexibility in how we serve large load customers, enables speed to market, and provides customer protections while benefiting our Wyoming customers. Our data center demand in the financial plan of 600 megawatts by 2030 is primarily driven by Microsoft and Meta’s growth. We have successfully served growing demand from Microsoft hyperscale data centers for more than a decade through market energy procurement. Meta’s new AI data center in Cheyenne is progressing, and we expect them to begin ramping later this year. We are prepared to serve these customers primarily through market energy and contracted resources requiring minimal capital investment.

That said, we expect demand at or above 600 megawatts to drive the need for investments in generation and transmission infrastructure. We continue to make positive progress on additional opportunities and are advancing our negotiations with high-quality partners to serve more than 2.5 gigawatts of large load requests. Specific to a 1.8-gigawatt project in our pipeline, we are working through several agreements with counterparties that would ultimately support resources to serve this demand. We continue to focus on the reliability and resiliency of the overall system and customer protections as we design a portfolio of resources to meet the needs of our prospective large load customer.

As Linden mentioned, and I am pleased to expand on, we have executed a short-term generation reservation agreement with this prospective customer for company-owned generation. The agreement provides for customer-funded milestone payments to support the long-lead-time generation equipment as part of the broader resource mix needed to serve the 1.8-gigawatt project. To date, the customer has provided $201 million in refundable contributions in aid of construction to secure this generation equipment through the term of the agreement.

In parallel, we continue to advance negotiations toward a long-term definitive agreement under which company-owned generation would be a component of the portfolio of resources serving the project, with the intent that this reservation agreement transitions the parties into a long-term definitive generation facilities agreement. As you would expect, a project of this size and complexity involves multiple parties and interrelated contractual components. We are carefully structuring these agreements to protect customers while appropriately managing operational and financial risk. Consistent with our normal practice, we will provide additional detail as definitive agreements are finalized. Now shifting to a regulatory update on slide 15.

We continue to effectively execute on our regulatory plan with a cadence of three to four rate reviews per year across our eight-state service territory. Our rate review filed last December for Arkansas Gas continues to progress with new rates requested in the second half of this year. During the first quarter, we filed a new rate review request for South Dakota Electric. We are seeking recovery of our customer-focused investments and increased cost to serve customers in western South Dakota and northeastern Wyoming after holding our base rates stable for more than a decade.

In South Dakota, we requested $50.6 million of new annual revenue based on a 10.5% ROE and a capital structure of 47% debt and 53% equity. The request seeks interim rates within 180 days of filing. In Wyoming, we requested $5.1 million of annual revenue based on a similar ROE and capital structure as was filed in South Dakota. We also filed an abbreviated rate review in Kansas as allowed by the commission’s prior order. The request seeks recovery of capital invested through 2025 at the previously agreed-upon weighted average cost of capital, with rates requested early in the third quarter. And lastly, in South Dakota, wildfire liability legislation was enacted in March to be effective 07/01/2026.

Utilities in compliance with their wildfire plan filed with and published by the commission will receive significant liability protections similar to legislation in Wyoming and Montana. In Wyoming, we are awaiting approval of our mitigation plan, which is expected in the second quarter. We also continue to support the development of similar legislation in Colorado. In summary, our team is focused on executing with excellence on our customer-focused strategy. From day-to-day maintenance and outage response to delivering a new line to serve a neighborhood or business, we are ready to serve.

We are strategically managing and expanding our infrastructure to serve the needs of our customers and actively working with new large load customers to make their plans a reality as their energy partner of choice. With that, I will now turn the call back to Linden.

Linden R. Evans: Thank you, Marne. To summarize what we talked about today, we continue to make meaningful progress on our regulatory plan, our growth initiatives, and our strategic goals. Black Hills Corporation offers a compelling long-term value proposition driven by our customer-focused growth, competitive yield, and significant upside opportunities. Additionally, our planned merger with NorthWestern Energy will provide us with the advantages of increased scale and new opportunities as a larger, premier regional electric and natural gas utility company. Thank you for your interest and your trust in the Black Hills Corporation team, as we partner to grow long-term value for our customers and stakeholders. This concludes our prepared remarks, and we are happy to take your questions.

Operator: As a reminder, to ask a question, please press 11 on your telephone and wait for your name to be announced. To withdraw your question, please press 11 again. One moment for questions. Our first question comes from Andrew Marc Weisel with Scotiabank. You may proceed.

Andrew Marc Weisel: Hey, good morning everyone. Congrats, a lot of exciting updates here. My first question is regarding the agreement to reserve generation equipment for the data center customer. Forgive me, Marne—you ran through some details pretty quickly. Apologies if I missed them. I want to make sure I got it all here. Did you say it was around $200 million of short-term deals for company-owned generation? So this should be utility-owned resources falling into rate base and earning the typical 9.8% ROE. Did I get that right?

Marne M. Jones: Good morning, Andrew. I appreciate your question, and if I ran through a little fast, let us walk through a few of those details. Yes, it is a short-term agreement, really meant to provide some financing—or a financing bridge—as we think about serving long-term generation needs. Ultimately, we intend to put this into a company-owned generation facility that would have a longer-term agreement. When we talk about company-owned generation and a generation facilities agreement, there is a bit of a difference from how you described it. It would be specific to this ultimate end-use customer. We think about the return based on that customer and the unique needs for that specific customer as we talk about risk-adjusted returns.

This would not be part of overall rate base for retail customers in Wyoming.

Andrew Marc Weisel: Okay. So this would still be that negotiated, risk-adjusted approach—not a standard formulaic return—this would still be negotiated then.

Marne M. Jones: That is right. It would be a negotiated rate, but I would think about it more in the terms of a typical utility-like investment. This would not be the same as our microgrid management fee.

Andrew Marc Weisel: Okay, that is helpful. And just to understand, the short term is about the financing. The equipment would be utility owned for the life of the asset. Is that what you are saying?

Marne M. Jones: That is correct, yes. And just as a reminder, as we think about contracting these types of assets and we talk about customer protections, through these negotiations one thing we focus on is ensuring that we do not have stranded assets at the end of contracts, etc. So this is not something that would ultimately be on the customers of Wyoming. This is all contracted through that long-term contract that we are negotiating.

Linden R. Evans: And the $201 million that we received in the refundable contributions in aid of construction is another way of protecting customers. It helps us protect our balance sheet in the interim while we are working with these customers to serve their large load.

Andrew Marc Weisel: Great, very helpful. So that $201 million—that is more about financing. Are you able to give an indication of the size of the asset or assets in terms of megawatts? I mean, this is not the full 1.8 gigawatts, is it?

Linden R. Evans: No, it is not. And we are not yet ready to announce what kind of megawatts we would serve. We are still actively working with the customer on that. We have a direction with them, but there are a few balls in the air. As soon as we can let you know that, we will. But to date, we are still negotiating that with our counterparty.

Andrew Marc Weisel: Okay. Can you say big, medium, or small?

Linden R. Evans: Nice try, Andrew. Nice try.

Andrew Marc Weisel: Okay, one last one before I pass it over. In terms of the merger—congrats on the settlements you got there—does that accelerate the timeline for closing? I know you are still pointing to the second half, but can you get a little more specific? Do these help speed things up? And then subsequent to closing, do you and your friends at NorthWestern plan some sort of investor day or something like that to present the outlook for the combined company later this year?

Linden R. Evans: I would say it this way, Andrew. Settlements are always helpful. We have a hearing next week in Montana—we will see how that goes. We have had our hearing on the full settlement in Nebraska, and we have hearings scheduled next month in South Dakota. Will it speed it up? No, but it certainly did not slow it down. I think it gives a nice, solid foundation that regulators can use as they consider this merger and ultimately approve it, we hope. With respect to a combined investor day, I am the exiting CEO, so I will be cautious to commit someone else. It may be a good idea. We shall see.

Andrew Marc Weisel: Fair enough. Thank you so much.

Operator: Our next question comes from Christopher Ronald Ellinghaus with Siebert Williams Shank. You may proceed.

Christopher Ronald Ellinghaus: Hey. Good morning, everybody. So, Kimberly, this was a monumental weather impact, but you did not adjust guidance at all. Can you give us any color on what you are thinking about for offsets?

Kimberly F. Nooney: Maybe just to level set—looking back in any given year, we have had some pretty favorable and unfavorable weather swings. Specific to Black Hills Corporation’s history, we have had more significant unfavorable impacts; when I look back, it was around Q4 2021. My point is we are used to experiencing these types of impacts. As you noted, we are reaffirming guidance, and we will continue to manage the business to ensure that we are focused on mitigating risks while achieving our financial objectives. Just like any other utility, we will be focused on optimizing our O&M and the timing of our capital investments. That will be our strategy.

Linden R. Evans: That is a good answer. I would suggest that during the fourth quarter of last year, we had pretty mild weather—you might remember that, Chris. As a team across the whole organization, we continued to lean into the challenge of warm weather into the first quarter, which helped us as well. This is a chance for me to say thank you to our team. They have really done a wonderful job of ensuring that we hit our targets.

Christopher Ronald Ellinghaus: Along those lines, you have had some pretty unfavorable weather, particularly in the first and fourth quarters. Do you see a longer-term pattern of sort of filling in the bowl that you have for an earnings shape—where you see more loads headed into the middle of the year and maybe out of the first and fourth quarter? Is that something that you are contemplating as a reality today?

Kimberly F. Nooney: Based on the fact that we have a balanced mix of electric and gas resources, Q1 and Q4 have always been our most impactful, but this is not unique. One of the things that we have done over the past few years is really look back on weather impacts and how we assess those in the financials. We are very cognizant of it, we are paying attention to it, and we are ensuring that we are incorporating those types of impacts into our future strategies. Are we drastically changing our business model? No, we are not.

Linden R. Evans: I would add we are also working closely with our regulators for weather normalization, as you might recall. We have a pilot we are doing in Nebraska this year that was helpful this quarter and in the fourth quarter of last year. I would also say a benefit of large load customers is that they are high power-factor customers, and to the extent that they can help smooth out our earnings through the year, that would be another benefit to our other customers. That is something we are working on too.

Christopher Ronald Ellinghaus: Linden, you are the expert on data centers in Wyoming, so maybe you can shoo me off of this question too. There has been a lot of difficulties with that data center. Can you give us some color on what is happening locally? I know there have been some efforts politically to try to move that along. Can you give us some sense of what some of the holdups are locally?

Linden R. Evans: Chris, I guess my challenge is your fact pattern. Yes, there are a few local entities asking that the commissions take caution about the data centers—are they doing it right? On the other hand, we are also seeing initiatives by local folks to actually accelerate permitting. So it is a balance. For us, and the data centers that we are working on, we are not seeing any slowdown due to decisions or permits or anything of that nature. All of ours are currently right on track. CPCNs are being granted, local permits are being granted, etc. I think we are in nice shape with the customers that we are currently dealing with.

Christopher Ronald Ellinghaus: Along the same lines, have you got a sense at all of when you might file a CPCN for generation?

Linden R. Evans: I am going to let Marne address that issue.

Marne M. Jones: As I mentioned, we have the short-term reservation agreement, which we would ultimately like to see convert into a long-term definitive agreement for generation. Once those agreements are in place—not just the generation but all the agreements that are needed—is when we would expect to see a CPCN for generation.

Christopher Ronald Ellinghaus: I am not trying to figure out what the size is, but can you talk about what type of generation that you are pursuing?

Marne M. Jones: The reservation is for long-lead-time equipment items. We are looking at gas engines, transformers—dispatchable generation will be really important.

Christopher Ronald Ellinghaus: And one last thing. In Montana and South Dakota, have you got a sense of what to expect for the duration of those two hearings?

Marne M. Jones: We are scheduled next week in Montana for a Tuesday-through-Friday hearing. In South Dakota, I would have to check the precise schedule, but I believe it is scheduled for two or three days in June.

Christopher Ronald Ellinghaus: I do not recall Montana ever accomplishing anything in four days, so that would be some kind of record.

Marne M. Jones: As was mentioned earlier, we have reached a lot of settlements. We do not have a full settlement in Montana, but we have reached many settlements. That hopefully bodes for a much more efficient process.

Christopher Ronald Ellinghaus: You are a great optimist, Marne.

Christopher Ronald Ellinghaus: Okay. Thank you for the color. Appreciate it.

Operator: Thank you. Our next question comes from Paul Fremont with Ladenburg Thalmann. You may proceed.

Paul Fremont: Thanks. My first question has to do with the short-term reservation agreement—I guess it is for $200 million. If the project were to move forward, is that the aggregate amount that you would contemplate spending? If not, how large an investment would you contemplate?

Kimberly F. Nooney: Hey, Paul. Good morning. I will start, and then my team members can fill in. This is really, as noted, a reservation agreement. These are milestone payments associated with procuring the actual investments that Marne mentioned. This is what we think of as a bridge agreement to ensure that we maintain balance sheet strength through this period until we get to definitive agreements and are able to start constructing. We are not talking about the final size yet because we are still in negotiations. We will contemplate the right financing strategy overall. We have not given the magnitude of the project beyond 1.8 gigawatts and the fact that it will be served with a variety of resources.

Paul Fremont: Should we think of the $200 million as extending through some period in time—in other words, the next two or three years of spend?

Linden R. Evans: The reservation payments are the payments that we are making to these suppliers, and we are being reimbursed by the customer we are negotiating with as part of that agreement, Paul. That is where the $201 million comes from. That is what we are paying to hold these resources in place so that we can put them in service for a customer. In the short term, we are working through June 30, 2026, as a milestone. I encourage our stakeholders to think in terms of June 30 as a deadline we are working toward as an organization.

If we do not announce something by June 30, please do not assume that means we are not going to have an agreement with this customer. That is a milestone that we are working to achieve.

Paul Fremont: And according to the AEP conference call, it sounded like if there is nothing in place by June 30, there is another six-month extension in terms of the Bloom equipment. Should we assume that December 31 is an absolute date by which the parties need to reach an agreement?

Linden R. Evans: I would not call it an absolute date. We are certainly working toward getting a contract in place by then, but I would not see it as absolute. To date, the parties are working very well together and extending things by agreement. These are complex agreements with lots of parties. We want to get it right—especially us at Black Hills Corporation. We have to get it right on behalf of our entire customer base to ensure we have the best deal we can to serve these customers appropriately. We both know the time value of money; we need to work efficiently, and we are.

Paul Fremont: Is any of the CapEx related to this project significantly additive to the current compound annual growth rate? Also, if you need to build more resources for this, who should we assume will provide the funding, and is the incremental CapEx going to be 50% equity funded?

Marne M. Jones: When we talk about CapEx, we have 600 megawatts of load in our current five-year plan that ties back into our $4.7 billion of CapEx. Anything above that—this project would be above and beyond—is part of the pipeline that is not included in our current plan and would be additive to our overall capital investment opportunity. If we needed to build more resources, whether generation or transmission, those would be incremental to what we currently have in the plan.

Kimberly F. Nooney: And on financing, our overarching perspective is to maintain credit quality. We have set our credit quality targets of 14% to 15% FFO to debt and maintaining our debt-to-total capitalization at 55% or below. That is the guiding principle. We would think about this as a utility-like investment with a utility-like capital structure in the range you are noting.

Paul Fremont: Great. I think that is it in terms of questions.

Linden R. Evans: Thank you, Paul. We appreciate your questions.

Operator: Thank you. I would now like to turn the call back over to Linden R. Evans for any closing remarks.

Linden R. Evans: Well, thank you very much for participating in our call today and for your interest in Black Hills Corporation. We have a compelling long-term value proposition—hope you are starting to see that develop through our comments today and the responses to your questions. Once again, I want to thank our team for leaning in so hard, doing it safely, and doing so well to serve our customers. We are grateful for that. I encourage you to have a Black Hills Corporation safe day. Thanks for joining our call.

Operator: Thank you. This concludes the conference. Thank you for your participation. You may now disconnect.

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Black Hills (BKH) Q1 2026 Earnings Transcript was originally published by The Motley Fool