NorthWestern Energy Group (NWE) Q3 2025 earnings call transcript

Thank you, Prilla, and good afternoon, and thank you again for joining NorthWestern Energy Group's Financial Results webcast for the quarter ended September 30, 2025. Joining us on the call today are Brian Bird, President and Chief Executive Officer, and Crystal Lail, Chief Financial Officer. They will walk you through our financial results and provide an overall update on the progress this quarter. Northwestern results have been released and our release is available on our website at NorthwesternEnergy. com. We also released our 10Q free market this morning. Please note that the company's press release, this presentation, comments by presenters and responses to your questions, may contain forward-looking statements. As such, I will direct you to the sponsors contained within our SEC filings and safe harbor provisions included on the second slide in this presentation.

Also note that this presentation includes non-GAAP financial measures and information regarding the pending merger transaction. Please see the non-GAAP disclosures, definitions, reconciliation, and merger-related disclosures included in the appendix of the presentation. Webcast is being recorded. The archive replay will be available today shortly after the event and remain active for one year. Please visit the financial results section of our website to access the replay. With those formalities behind us, I'll hand the presentation over to Brian Burt for his opening remarks.

Thank you, Travis. On our recent highlights, we reported GAAP diluted EPS of $0.62 per share, non-GAAP diluted EPS of $0.79 per share for the quarter. We are affirming our 2025 earnings guidance range of $3.53 to $3.65. During the quarter, we integrated our Energy West Acquisition of the natural gas assets, we've also integrated the customers and employees, and we've really tucked that business in seamlessly. Very, very excited about that opportunity. I'll tell you what, something even a bit more excited about is the announcement of our agreement with Black Hills Corporation for an all-stock merger of equals. Even though we did that announcement in mid-August, we have already filed our joint applications for the transaction approval with the regulatory commissions in Montana, Nebraska, and South Dakota.

In addition, during the quarter, we filed a tariff waiver request with the NPSC for recovery of our operating costs associated with the Vista coal strip interest. And recently, we submitted a 131-megawatt natural gas generation project in the Southwest Power Pool expedited resource adequacy study. And that project, if we move forward, will be approximately a $300 million project, which is currently not included in our five-year CapEx plan. And lastly, a dividend declared during the quarter 66 cents per share, payable December 31, 2025, to shareholders of record of December 15, 2025. Moving forward to the Northwestern value proposition with a dividend yield between 4% to 5%, add that to a base capital plan providing a 4% to 6% EPS growth gives us a total return of 8% to 11% total return.

And if you think about that CapEx plan, the vast majority of that is in a T&D investment throughout our total system on both the gas and electric side of our business. Obviously necessary to serve our customers. If you consider the incremental opportunities we have, certainly with data centers and large load customers, FERC regional transmission, and any incremental generating capacity, some of which I just spoke to, You could see the dividend yield plus that greater than 6% EPS growth, giving a total return even greater than 11%. And with that, I'm going to turn it over to Crystal to talk about the third quarter financial review.

Thank you, Brian, and good afternoon, everyone. We are coming to you from beautiful Butte America today, following a board meeting here. And based off those highlights, it feels like we might have had a little bit of a busy quarter. I will cover and update you on our third quarter results and outlook for closing out the year and then turn it back to Brian for some really exciting strategic updates and where we're at otherwise with the business. We are pleased to deliver a solid quarter in line with our expectations here for the third quarter of 25 and are on track to deliver on our earnings guidance and financial targets for the year. For the quarter, earnings were $0.62 on a gap basis compared to $0.76 in the prior period.

On an adjusted basis, we delivered $0.79 as compared with $0.65. In the upcoming slides, I'll dig in a bit on the details of those drivers, but I would note and highlight what you just caught, which is comparability year over year. There's a couple of items I would just highlight that are impacting that. That includes the merger-related costs that are included in third quarter 25, and also remind you that in the third quarter 2024, we had a tax benefit.

Moving to slide nine from a year perspective that leaves us at from a gap basis compared to Last year again on an adjusted basis that in 2025 year compared to in 2024 Slide 10 shows you the third quarter drivers of EPS compared to that same period in 2024. I would note that despite mild weather, margin improvement drove $0.52, which was offset in some regards by higher operating costs, again, including those $0.12 of merger-related costs I referred to, higher depreciation and interest, and inclusion, again, in the prior year of an $0.11 tax benefit.

Moving to slide 11, for further detail on margin, again, I highlighted that that was 52 cents of improvement. Of that 52 cents, rates drove 35 cents of margin improvement. As a reminder, we worked really hard on that regulatory execution to be able to recover our costs and close that gap on earning returns. That $0.35 is certainly key to that, and we are currently awaiting our outcome in our Montana rate review, and I'll address that in a little bit later. Also, customer usage provided $0.08 of improvement, and electric and gas transmission and transportation provided another $0.05. These are offset by a couple of things we had highlighted previously of trends for 2025, and that includes the market sales impact in our PECAM, and that is a detriment during the quarter.

As well as the effects of Montana property tax legislation that are also a detriment to it in the quarter, reducing some of that favorability in the margin line. Moving to slide 12, I'll discuss again those adjusted items to hopefully make the quarter make a bit more sense for third quarter 25 versus third quarter 24. Again, mild weather in this third quarter impacted us by about five cents, and that's compared to, again, an addback of five cents, an addback of one cent in the third quarter of 2024.

Also, in 2025, we've incurred 12 cents of merger-related costs. And then, as I mentioned earlier, the 2024 results included an 11-cent tax benefit related to prior year gas repairs once that final guidance came out. All of that gets us to, if you look at the adjusted columns, $0.79 of earnings in the third quarter of 2025 compared with $0.65 in 2024.

Moving to slide 13, you've heard our commitment to credit quality and maintaining that. We've largely executed on our financing plans, and those remain unchanged as we continue to focus on making sure we're keeping that FFO to debt number where it needs to be and expect to see a bit of improvement even on that as we close out the year for 2025.

Moving to slide 14, our financial performance year today reinforces our confidence in delivering on the financial commitments that we've made, and we expect a final outcome in our Montana Root Review, as I alluded to earlier, during the fourth quarter, and as such, we continue to maintain a wider range of $0.15 as we look to close out 2025. We also expect to provide our 2026 outlook during our year-end call in February, so you can all look forward to that.

Moving to slide 16, you'll see that our capital investment slide and forecast here remains unchanged from what you've seen from us before. Brian mentioned the opportunities, and we talked many times about what might be incremental to our current plan, but the opportunity for incremental generation investment in South Dakota under the SEP expedited resource adequacy study. That is not reflected in these amounts, and as I just alluded to with our 26 earnings outlook, we expect to roll forward and update our capital plan also on the Q4 call in February.

So with that, I will turn it back to Brian.

Thanks, Crystal. On 18, we talked about our merger with Black Hills update, and August 18 seems like a long time ago, but it was about two months ago. And in that short period of time, we with our Black Hills friends have worked collectively to make three filings with each of the three states that we needed to make filings in. We filed with the MPSC and the North Dakota Public Service Commission, the South Dakota PUC. Those filings are made, and we continue to work on other filings necessary for the transaction. Continue to work on the S-4 and joint proxy statement. Expect to release that in Q1 of 2026. In terms of shareholder meetings, sometimes a Q2 or Q3, our respective companies would hold shareholder meetings on a vote on the transaction.

And then developing transition integration implementation plans. What I'd say there is we collectively are talking to independent integration consultants, hope to make a decision relatively soon there. And just really in early planning stages, things will really get going here, I'd argue, in the December-January timetable as we continue planning moving forward. And lastly, receiving approvals and closing the merger, I'd like to think that can happen sometime in the second half of 2026.

Moving on to the next page regarding large-load customers, off to the right, I think all of you are well aware of the three LOIs that we currently have with SABI, ATLAS, and Quantica. I mentioned the development agreement with SAVI here shortly, but on the left-hand side of the page, just a quick focus on Montana and South Dakota. We do anticipate making a filing with the NPSC to propose a large load tariff in the fourth quarter of 2025, and we'd like to do that in conjunction with an ESA with SAVI. So going in arm-in-arm, making sure that we're protecting customers in essence, but also providing what we need to move forward with data centers in the state.

In South Dakota there continues to be significant indications of interest and any new large load customers require incremental capacity and in South Dakota PUC already has an established process for large load customers The other thing I'd just say in South Dakota, we and certainly other utilities of the state have seen good progress in between legislative sessions on a sales tax exemption bill. I just saw a draft of one here shortly, not too long ago, and so I'm excited about that opportunity, and hopefully we can deal with that issue in the next legislative session, and so we can have a better means to attract data centers in the state of South Dakota. So I think really good progress in both states.

Regarding that process on slide 20, we continue to lay out for you kind of left to right the process. We have seen good progress here. From a data center request, we've moved three of those parties into a high-level assessment. As a matter of fact, of the LOIs, what we've done here recently of our three LOI parties, we've entered into a development agreement. What's that? Notice we show those kind of hand-in-hand here, maybe an incremental step of the LOI portion, if you will. But the development agreement is primarily to make sure that we have a commitment, in essence, to fund the studies, and we've received development deposits along the way to fund those studies necessary, impact studies, facility studies.

And that's an important step. We anticipate the other two LOIs. We could see development agreements with those other two LOIs before the end of the year as well. All with the hopes of getting to energy service agreements as quickly as we can. Moving forward, pull strip transaction overview. I'm just in the far right. I think I need to provide a bit of a history lesson for folks. Back in January of 2023, we acquired the Avista piece, and you may recall that our IRP talked about the necessity of incremental 200-plus megawatts of capacity. And that Vista portion provided resource adequacy for us in Montana. And it also brought our ownership interests in the coal strip facility from 15% to 30%.

Unfortunately, 30% interest wasn't going to be high enough, if you will, to protect ourselves from other owners of the plant for various reasons. Their states didn't necessarily want them to own coal-fired generation, and thus there could have been an incentive for them to actually close down the coal strip facility. For us to protect our existing interest, 222 megawatts and the Avista interest in coal strip, in July of 2024, we acquired Puget's 370 megawatts. What that did is, it allowed us to move from a 30% ownership to 55% ownership, providing us a clear advantage to provide the direction for where CoalStrip's going to go on a going-forward basis, and protecting ourselves and our customers from a capacity standpoint.

And so we're excited that January 1, 2026 is not too far away. I think we'll sleep better knowing we have those resources to serve our customers on the coldest days of the year. Those combined interests, of course, will deliver substantial benefits to our existing customers, communities, and investors, but also support now the integration of some large-bode customers. And primarily, that would be the Puget issue. So one of the things we did to protect ourselves.

Starting on 1-1-26 as quickly as we can here, for the Avista portion, we filed a temporary PCAM tariff waiver request with the MPSC. We did that in August. We provide a near-term cost recovery mechanism that is expected to largely offset the $18 million of incremental annual operating costs resulting from the transfer. Decision is expected on that the first quarter of 2026. I think it's clear, you understand with a historic test year in Montana, if we'd not done this, we would be at risk of not recovering our operating costs of that union unit, if you will, the incremental 222 megawatts until our next rate review. And so this is a prudent means to try to make sure we protect our financial integrity, and hopefully we'll see a good outcome from the Montana Commission.

I think they will respect the concept of we are buying incremental capacity to serve our customers at a zero upfront cost. And all we're asking here is to get recovery of our operating costs and to a point where upsetting, if you will, sales from that unit, to offset those, at least to have those sales cover our operating costs before we actually move into the 90-10 sharing mechanism. I think it's a very reasonable ask, and hopefully the Montana Public Service Commission will see that as well and hopefully see it as quickly as we get into 2026.

On the Puget piece, we anticipate signing a contract in Q4 2025 to sell electricity through late 2027. The revenue from that contract is expected to largely offset the $30 million of incremental operating costs from that transfer. We've already filed with FERC for cost-based rates in October 2025 for that portion and expect approval during the fourth quarter of 2025. I want to spend a little bit more time on Puget. I think the question could be asked, you know, why FERC regulated and not MPSC regulated for that 370 megawatts, the Puget portion. While we received comments through the MTSC that provides uncertainty around how we will or can serve large load customers in Montana. And clearly the 370 megawatts were not identified in our IRP as needed for resource adequacy on 1 And so that reason enough to move things to a FERC regulated perspective And I think the other question you might have is why would you plan to enter into a PPA with another party for the full 370 megawatt output of the Puget portion?

But first and foremost, that really avoids any affiliate issues that we'd have with our regulated business. Secondly, having a FERC-regulated, fully contracted output with an investment-grade counterparty not only reduces market risk, but it allows us to largely offset our operating costs at the facility.

Lastly, the term of that agreement would be through Q3 of 2027 in order to have 370 megawatts available for large load customers in Q4 of 2027.

Ideally, this 370 megawatts, we will ultimately like to move that into our MPSC regulated business sometime in 2027 or beyond, but we certainly need to persuade the MPSC. That is in the best interest of not only all of the customers in Montana, but make sure also for their existing customers in Montana.

So with that, I'll conclude just by saying I want to thank all of your interests. As Crystal pointed out here earlier, we've been extremely busy. And I just wanted to point out I'm pretty proud of this company for our ability to not only handle our day-to-day jobs, to not only run this business, but work with our friends at Black Hills, to, we think, put together a company that will be better together, certainly much larger, much more financially strong, have the scale, if you will, to better serve not only our shareholders, but equally important, our customers and our employees as well. And with that, Meyer, to hand a Q&A.

Thank you, Brian. That was a good update.

Hey, Aidan, can you hear us?

Yeah. Yeah, just want to hone in on the data center front first. Looks like there was some activity in the request in high-level assessment stages. Could you just clarify if this was a simple pull forward of some of the request stage into the high-level assessment, and then maybe one just got added to the request stage? And then I just curious, you know, on top of that, you know, what sort of timeline you might be able to kind of convert the high-level assessments into incremental LIs?

Great questions. I think the data center requests, the Q count there went up one, but more importantly, net-net, we've increased the Q count and the high-level assessment by three. I'll tell you that I can't give you a specific time. One thing I've learned through this process, it takes two to tango, in essence, to when things move to that next level. But I do think there are at least one of those that could show up in that box relatively soon, that LOI box, if you will, or directly to a development agreement.

Sure, I'll take that one. You know, I think both MISO and SPP put out this summer an expedited resource adequacy study window. So we submitted, based off that study, a facility that would get us to resource adequate and meet the requirements by 2030. We've received initial feedback from SPP that what we've submitted meets their initial requirements, and we expect to hear on the transmission piece in early 2026.

As such, we will wait to put it into our capital plan until we roll forward that refresh here in probably the fourth quarter call in the February timeframe.

Well, thank you so much. I just, again, I want to reiterate the kind of support we've had, certainly since the announcement, and I think the feedback we've received, and I know our friends at Black Hills have received tremendous support for the merger. I will just tell you that we both collectively seem to be working really well together to make things happen here and continue to move this process along, and both endeavor and understand the importance of this merger, and we'll work really, really hard to make sure it happens. And like I said, hopefully as soon as the second half of 2026.

And so with that, again, thank you for your participation today.