NorthWestern Corporation Aktie

Hello, everyone. Thank you for joining us, and welcome to the NorthWestern Energy Third Quarter 2026 Financial Results Webinar. [Operator Instructions] I will now hand the conference over to Travis Meyer, Director of Corporate Development and Investor Relations Officer. Travis, please go ahead.

Thank you, Ellie. Good morning, and thank you for joining NorthWestern Energy Group's financial results webcast for the quarter ending September 30, 2026. Joining us on the call today are Brian Bird, President and Chief Executive Officer; and Crystal Lail, Chief Financial Officer. Brian and Crystal will walk you through our financial results and provide an overall update on the progress we've made this quarter.

Before handing it over, however, a few reminders regarding today's call. NorthWestern's results have been released, and the release is available on our website at northwesternenergy.com. We also released our 10-Q premarket this morning. Please note that this company's press release, this presentation, comments by presenters and responses to your questions may contain forward-looking statements. As such, I'll direct you to the disclosures contained within our SEC filings and the safe harbor provisions included on the second slide of 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 and reconciliations and merger-related disclosures included in the appendix of today's presentation materials. This webcast is being recorded. The archived replay will be available shortly after the event and remain active for 1 year. Please visit the Financial Results section of our website to access the replay. With those details behind us, I'll hand the presentation over to Brian Bird for his opening remarks.

Thanks, Travis. The recent highlights, first of all, reported GAAP diluted EPS of $0.50, non-GAAP diluted EPS of $0.58. We're affirming 2026 earnings guidance range of $3.68 to $3.83. We're also affirming our long-term rate base and EPS growth rate targets of 4% to 6%. Also for the quarter, we're declaring a dividend of $0.67 per share payable December 1, 2026. This payment date and the November 17 record date align with Black Hills corporate dividend dates and is intended to simplify the closing mechanics in the merger.

Regarding the merger itself, we have received approvals from the Nebraska PSC, the South Dakota PUC and FERC. Our final order expected from the Montana Public Service is November 12, 2026. If final, with a satisfactory approval is received, we anticipate completing the merger with Black Hills Corporation by the year-end of 2026. With that, I'm going to turn it over to Crystal for the third quarter financial review.

Thank you, Brian, and good morning, everyone. Thank you again for attending our earnings call for Q3 here today. In my comments, I will take you through details on our third quarter performance, how that ties into our year-to-date results and an update on our 2026 earnings outlook. Starting with Brian's overview comments for the third quarter, we reported GAAP earnings of $0.50 compared with $0.62 in the third quarter of 2025. On a year-to-date basis, we are reporting GAAP earnings of $1.93 as compared to $2.22 in 2025.

Moving to Slide 8. I'll spend some time on the key drivers for the quarter. Notably, to provide more transparency and visibility into the full impact of our incremental Colstrip ownership, we've provided a detailed breakout in our waterfall slides for the quarter and year-to-date. You will note margin improved due to slightly favorable weather and the absence of PCCAM sharing versus the prior quarter. While volumes were impacted by favorable weather, particularly in July, this was offset by slightly unfavorable weather in August and September and also overall lower usage per customer.

The margin improvement overall was offset by higher operating costs, depreciation and interest. The slide provides detail on the impact of our incremental Colstrip interest, as I mentioned previously for the quarter. The detriment for those 2 pieces, both the Avista and Puget piece is $6.1 million or $0.10 -- due to weak market prices overall, the PCCAM tariff waiver provided no recovery of costs for the Avista portion during the quarter.

With that, I'll move to Slide 9 to discuss our adjusted earnings reconciliation for the quarter. My comments on weather, again, a bit of favorable weather in July offset in August and September. Weather was overall favorable by $0.01 for the quarter versus what we would expect for normal. The quarter also included $0.04 of merger-related costs. Also note, we are adjusting out $0.05 of detriment related to the Avista portion tied to designated sales contracts.

However, as noted in my prior comments, the full impact of both the Puget and Avista share is around $0.10, and we are only adjusting out here $0.05. You'll see the reconciliation from left to right, GAAP $0.50. With those adjustments, we are reporting $0.58 on an adjusted basis versus in the prior period in 2025, $0.79 on an adjusted basis.

Moving to Slide 10 and our year-to-date results. Margin improvement reflects new rates in Montana in the first half of the year compared with 2025, offset by mild weather, higher operating costs, depreciation and interest. Again, on this slide, we've broken out detail as it relates to our incremental interest from Colstrip Puget and Avista, which represent a $16.4 million detriment or $0.27 on a year-to-date basis.

In a similar fashion on the quarter results, the PCCAM tariff waiver related to the Avista portion tied to certain designated contracts has not resulted in recovery of costs. I'll take you to Slide 11 to discuss on an adjusted basis, our results for the year. And remind you that we started out 2026 with an extremely mild winter and year-to-date have largely continued that trend.

We've added back $0.17 of weather versus normal in our '26 results. Merger-related costs are $0.13. And again, we are adjusting only a portion of the Colstrip impact related to the Avista designated sales contracts related to $0.15. You'll note that we are adjusting from $1.93 to an adjusted basis of $2.39 as compared to an adjusted results in 2025 of $2.41, so $0.02 lower on a year-to-date basis than last year.

Again, we're looking to provide transparency as to the impact of the incremental Colstrip interest and remain consistent with how we've presented our results in prior quarters. If we were fully adjusting the Colstrip impact, which I'll remind you is $0.27 year-to-date, that would reflect an incremental $0.12 on a year-to-date basis. With that, I will move to Slide 12 and talk about our guidance.

With our performance year-to-date, we are reaffirming NorthWestern's stand-alone 2026 adjusted earnings per share guidance range of $3.68 to $3.83, with a bias towards the lower half of the range. While the agreement to take additional ownership in the Colstrip facility provide much needed capacity to serve our customers when they need it most and provide for a 55% voting share of the facility, near-term market prices have impacted our ability to fully cover our costs.

Our guidance range notes that assumptions include approval of the PCCAM waiver note that is only approved on an interim basis and power prices sufficient to recover operating expenses from the incremental Avista and Puget Colstrip interest. The Pacific Northwest has experienced extremely mild weather in both the winter heating season and summer cooling, leading to broadly low market prices.

In working to offset this, we remain focused on cost control and expect to be in the lower half of our guidance range on a stand-alone basis for 2026. Notably, as to how we think about those assets going forward, we have discussed in our Q2 earnings call that addressing cost recovery of the Avista portion will require a rate review in Montana. While we are still pending a determination on our motion for reconsideration from our prior case, we do expect to file a rate review in Montana by the end of 2026 to address these costs.

We also look forward to the MPSC scheduled hearing next week and associated implications regarding our Puget interest, which Brian will discuss further. Moving to Slide 13. Our capital plan of $3.2 billion, investing on our customers' behalf to remain reliable and provide good service to them remains on track. We expect to provide a CapEx refresh in early 2027. And with that, I'll turn it back to Brian.

Thanks, Crystal. Obviously, folks are waiting for November 10, the hearing on the merger with Black Hills. Obviously, the slide here talks about benefiting stakeholders. I think both sets of shareholders from NorthWestern and Black Hills understand the benefits to shareholders if you consider the votes that we had and the high turnout and also the high amount of votes for the merger, obviously, increasing scale, being able to achieve a higher EPS growth rate, expanding our opportunities to invest and better finance those opportunities, a strengthened balance sheet and obviously enhanced business diversity certainly is a benefit to shareholders.

Equally important, this is substantial long-term value for customers. Not only are we bringing together 2 complementary teams, we're going to provide reliable service like they have in the past, but even better on a combined basis. But any cost savings achieved from this merger ultimately going to accrue to customers' future rate reviews.

And lastly, as we prepare for the combination with Black Hills, employees are excited about being part of something bigger and about the 2 companies being better together as one company. So we're very excited about the opportunity. Obviously, we need one last approval. And with that, I'd turn your attention to Slide 16.

That last approval is from the Montana Public Service Commission. And as highlighted there by the dotted box, you could see that our final order is expected by November 12, the hearing on November 10. And if we do -- if we're fortunate enough to receive an approval with a satisfactory written order, we would plan to close shortly thereafter.

So moving forward, we're also, as you know, working on data centers. From a data center request perspective, combining the request and assessments, our Queue count has gone from 14 to 16. We're seeing a bit more interest in South Dakota. On a development agreement, you've noticed the Queue count went down from 3 to 2. I had mentioned in previous meetings, Sabey had issues with land for its build in and around Butte, Montana and as a result, has since exited from the development agreement.

So our Queue count from a development agreement is down to 2. Speaking about that on 18, we talk about those large load customers. The 2 remaining with development agreements is Atlas, of course. There's an expectation with a customer they ultimately could go from 75 megawatts up to 150 starting in late 2027. And then also Quantica is from a studying load at this point, 25 megawatts going up to 1.1 gig. It notes a targeted start there of early 2029.

In recent discussions, that could actually occur sometime earlier than that. So excited about the progress made there with Quantica. Lastly, on Slide 19, from a NorthWestern value proposition perspective, again, approximately a 4% dividend yield and just yield and take into consideration our base plan of a 4% to 6% EPS growth, you have in and of itself an 8% to 10% total return.

If in fact, you think about opportunities around data centers, FERC regional transmission, incremental generating capacity in obviously, Montana and South Dakota, those possibilities could show us with a return greater than 10%. Having said all that, obviously, combining with Black Hills, we think we will be better together and that total return picture would be even better. And with that, we will open it up to Q&A.

[Operator Instructions]

Your first question is from the line of Shar Pourreza with Wells Fargo Securities.

This is Whitney Mutalemwa on for Shar. 3Q's update states Montana is served by a portfolio that is long capacity from 2026, while the IRP shows winter shortfalls by '27. How much of the 75 megawatts to 1,250 megawatts is in your load forecast? And does the corrected IRP change what you'd build or serve to Atlas and Quantica?

Yes. I think the issue for us is the 200 megawatts is something that we continue to think about in terms of serving large load of the 370. And that's what we continue to discuss with folks. Ultimately, we'd love to be able to do that on a regulated basis, the full 370 and be able to serve large load customers with that. And that's ultimately our plan.

We ultimately need the commission to approve our large new load tariff in order for that to happen. And so that's our plan as we sit here today in order to essence help serve not only our existing customers, but having excess capacity to serve large new load customers as well.

Understood. And then just as a quick follow-up. You had previously pointed to year-end for those ESAs. With the large load tariff still unscheduled, is that date still realistic? Or could it move by a quarter?

Yes. I would say this. I think certainly with Quantica, we're still attempting to sign an ESA and the other various agreements by the end of the year. In essence, from a large new load tariff perspective, we'd have to have those agreements from Puget 370 on a nonregulated basis. But in order for speed to market, we need to be more flexible with these customers. And ultimately, they understand that we'd like to ultimately transition them to regulated customers. But in order to meet their needs, we need to move forward on an unregulated basis in the meantime.

Your next question is from the line of Nicholas Campanella from Barclays.

Maybe just starting on Colstrip. I think you're kind of calling out like roughly a $0.10 hurt. On a stand-alone basis, as we think about your -- I think you're going to refile or you're going to file a rate case in Montana next year. On a stand-alone basis, should we continue to expect that type of drag in our '27 numbers?

Hi, Nick, it's Crystal. I was in my comments there, giving you the indication that we do need to file a rate case to recover those Colstrip costs on the Avista side, as Brian was referring to the separate Puget piece and what that might enable strategically in the future as to growth in serving others. We are pending the Montana direction, I'll call it next week in the merger outcome. But how you're thinking about '27? We expect to file a rate case. The commission has outwardly been extremely supportive of that Avista interest and the ability to serve customers with that, we'd be seeking to recover those costs so that you wouldn't continue to see drag in '27.

Obviously, the impact here, we expected to be able to cover some of these costs in '26 with essentially indexed market sales. We happen to be capacity long at a year when prices have been lower than we've seen in a long time. Sometimes timing is everything. But as we continue to '27, we are focused on addressing that drag and filing a rate case to recover those costs in base rates.

Okay. That's great. And then maybe just -- I know you highlighted that you submitted this large load tariff in Montana in March of '26. You're also kind of talking about still having confidence in getting an ESA done potentially by year-end for some of these customers. Can you just talk about how those 2 interplay and just what the latest status update is on the new large load tariff?

Nick, I'll start and Brian will back clean up on this one. One, on the large new load tariff, we are -- the commission did take quite some time to notice and start a procedural on that. Obviously, complex issues that I think you see in the election this week, lots of folks have thoughts on them. We are in discovery and discovery has been very significant. Lots of data requests in that docket as to how you should think about the context of serving these large new load customers.

So that docket is progressing. We will work together with staff and the commission. Obviously, they have a few other dockets of consequence in front of them that we would like them to consider first. Obviously, the merger being top of that heap, but also our prior motion for reconsideration of PCCAM and other things. So the docket is progressing.

That will set the context as to how we would serve customers under a fully regulated approach. As a reminder, and I think Brian was touching on this, Montana deregulated in the past is reregulated and there's customer choice. So we do have the option to continue negotiating with customers toward an ESA where we could serve them as a choice customer and eventually hopefully bring them in to a fully regulated customer if the Montana Commission wants that or if they prefer to keep them separate as a choice, we could do that.

So the 2 definitely interplay, but we are continuing to have conversations with customers to get to an ESA while the Montana Commission takes its time to address, I think, appropriately the large new load tariff and how they may want us to serve those customers in the future. Brian?

Yes. I would just add, I think people may recall that the thought was to file the large new load tariff with a customer and an ESA. And this has taken longer than we initially thought. So we decided to -- let's be transparent with what that large new load tariff would look like. We made the filing in March, as you pointed out.

And the hope is, by the time we ultimately are going down the path in terms of approval, we'll have an ESA. We'll have someone to actually make a filing, a large load customer to make a filing and put that in front of the commission, so it could be fully observed at that point in time.

That's great. And if I could just sneak one more in, and I appreciate all the comments on that. How are you kind of thinking about as you get approval in Montana for the merger, would the unveil for the pro forma company be on the fourth quarter update? Or would there be kind of an Analyst Day update shortly thereafter, just given you would plan to close this year, it seems.

Yes. Thanks, Nick. I would say, first of all, we need to get approval first, make sure we remind everybody of that. But assuming if we did get approval, the plan would be at our February earnings call to not only talk about what our long-term EPS growth rate would be, but to get guidance for '27 at that time.

Your next question is from James Ward with Jefferies.

Building on Nick's question, I think just the data center bill that Montana's interim committee moved forward in September said that it would apply retroactively, right, to proceedings begun. I think it was after the start of '25. If it passes with that language, how should we think about the potential impact on your large new load rule and any agreement you signed before it's enacted?

I think from what I understand from the legislative perspective, a large new law, it's relatively in line with what we're doing from a large new load tariff perspective. So I'm not too concerned about that, James.

Okay. Okay. Terrific. And you now expect a PCCAM decision in the first half of next year. Your deck shows 90-10 sharing. It was pretax $8.2 million in 2025. But if sharing comes back, how should we think about the annual pretax exposure that you might expect now that you're long capacity?

Yes. It's a great question. And so one is sharing coming back. I think if you looked at staff's memo on the topic, they're suggesting that sharing ends. And obviously, we're reflecting that in our numbers effective, I think, February 1 in 2026. So I would like to think sharing is a bad idea that shouldn't have never been there and will go away quite candidly. If it did come back, you still have a similar exposure in the sense that before we were short and at the mercy of market prices, on a detrimental basis.

Now that we're long, you continue to be -- we -- obviously, if I could, I would, but I don't control broader power prices. So you would continue to have exposure there. But I do think staff has made a strong case in their memo as to why sharing should go away and why it doesn't make sense, in my view, has never made sense. You're looking to regulated utilities to earn a return on invested capital, not to make money in the market on power sales or purchases.

So as to sensitivity there, I'd like to think that's a done topic, and we won't see that going forward. If for some reason, that PCCAM docket sharing does not go away, then we have more clarity on sensitivity there. Again, we are many times now long in the market. So it's really the -- it's still the price of market now sales instead of purchases. But I'd like to think certainly also if we combine into Black Hills, hopefully soon, that the sensitivity of that around our earnings would be minimal as well.

I'd add to that. The only thing I'd add is if you think about when sharing was instituted, we were still very, very short from a capacity standpoint. So even the argument could be had in terms of how we go about filling that portfolio with market sales. Obviously, we're in a much different place today. I think the commission has acknowledged at least through the staff comments that we're in a different position, and there's no reason to have sharing on a going-forward basis.

Your next question is from Aidan Kelly with JPMorgan Securities LLC.

Can you hear me now?

Yes, I thought I was going to have to ask you a question.

Good on my end. I guess on the data center, like request and assessment stage, it looks like there was some slight uptick there, I guess, despite the Sabey termination on the development agreement side. Could you just help us understand the underlying momentum in customer interest and whether you're seeing improving conversion prospects among these early-stage requests?

I know, Brian, in your opening remarks, you kind of said South Dakota was a bright spot there. So just curious how we should think about the potential for additional development agreements beyond Atlas and Quantica heading into the new year?

Yes. I think there's 2 things going on, Aidan. I think, first and foremost, I think you know that there's certainly -- there's a move from data centers they've kind of saturated urban areas. They're starting to move into rural areas, obviously. So we're getting more attention from that perspective. We're also seeing, secondly, in the United States, a lot of pushback in certain states that may have been deemed pro data center states in the past no longer being in that case.

And so I think there's just been more interest. I think we're also getting closer to legislative sessions. And so I think there's -- and I think South Dakota is doing some more things to be helpful on some fronts. So I just see a bit more positive momentum in that state.

Your next question is from Paul Fremont with Ladenburg Thalmann.

With Sabey sort of being eliminated from the development agreement, are they included in the other bucket? Or are they eliminated entirely?

No, they're eliminated entirely. The Queue count, yes, they don't jump back in the data center request assessment. They come out of the development agreement. So they are completely off of Slide 17.

Okay. And then you used to have sort of 2 buckets, data center request and high-level assessment. Can you sort of just walk us through the logic of -- it looks like combining those 2 buckets?

Yes. I think we were getting a lot of specific questions about various buckets themselves. And obviously, we're -- until you get to a development agreement where you're actually putting money down towards studies, I think that's where people should be focusing their attention. I think it's appropriate to see how much demand is people looking in our states. But until you see folks in the development agreement bucket, I don't think anyone should be counting their chickens before they hatch, if you will.

Great. And then last question for me. I guess, previously, you had commented about the potential of having both Quantica and Atlas signed by the end of the year. Is that still the case?

I think Atlas is less apt to be done by the end of the year. I still feel really good about Quantica. But as Paul, as we found out, I think others find out these things do take a little longer than you initially expect, but we're certainly targeting with Quantica to be done by the end of the year.

There are no further questions at this time. I will now turn the call back to Brian Bird for closing remarks.

Well, first of all, I want to just thank everyone's patience through this process. It's been a long time since we announced the merger. Investors have patiently waited and as we have, and I think about all the 4,000-plus employees of the combined entity patiently waiting and anxious about this. Everyone's worked extremely hard to ultimately get to an approval. And as you know, we've gotten approvals from everyone else that we need approvals from.

Hopefully, Montana Commission will also understand the benefits associated with the merger, and we'll get that approval as well. And I think we can demonstrate to all of you if we get the chance that we'll be better together as we move forward as [ Bright Horizon ]. But as CEO of NorthWestern today, I just want to thank you for your continued support as you continue to evaluate us as an independent entity up until that time that you no longer have to do that. So hopefully, we'll talk the next time from an earnings call perspective from a different spot, if you will.

But in the meantime, thank you for your support. Appreciate it.

This concludes today's call. Thank you for attending, and you may now disconnect.

Hello, everyone. Thank you for joining us, and welcome to the NorthWestern Energy Second Quarter 2026 Financial Results Webinar. [Operator Instructions] I will now hand the conference over to Travis Meyer, Director of Corporate Development and Investor Relations Officer. Travis, please go ahead.

Thank you, Kendra. Good afternoon, and thank you for joining NorthWestern Energy Group's financial results webcast for the quarter ended June 30, 2026. Joining us on the call today are Brian Bird, President and Chief Executive Officer; and Crystal Lail, Chief Financial Officer. Brian and Crystal will walk us through the results and provide an overall update on the great progress we've made this quarter.

Before handing the call over, however, a few reminders regarding today's call. NorthWestern's results have been released and the release is available on our website at northwesternenergy.com. We also released our 10-Q premarket 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 disclosures contained within our SEC filings and the safe harbor provisions included on the second slide of this presentation.

Also note that this presentation includes non-GAAP financial measures and information regarding the pending merger transaction. See the non-GAAP disclosures, definitions and reconciliations and the merger-related disclosures in the appendix of today's materials. The webcast is being recorded. An archived replay will be available shortly after the event and will remain active for 1 year. Please visit the Financial Results section of our website to access the replay.

With those details behind us, I'll hand the presentation over to Brian Bird for his opening remarks.

Thank you, Travis. For recent highlights for the quarter, we reported GAAP diluted EPS of $0.40 and non-GAAP diluted EPS of $0.50. We're also affirming our 2026 earnings guidance range of $3.68 to $3.83, and also affirming our long-term rate base and EPS growth rate targets of 4% to 6%.

Regarding the merger, during the quarter, we received approvals from the Nebraska PSC, the South Dakota PUC, and FERC. We also had our Montana hearing and the final briefing is now completed, and we're awaiting the final order.

Lastly, in terms of dividend, we declared $0.67 per share payable September 1, 2026. You might note there's a change in the payment date and the August 17 record date to make sure we align with Black Hills Corporation's dividend dates, which was intended to simplify the closing mechanics in the merger.

And with that, I'm going to hand it over to Crystal to cover the second quarter financial review.

Thank you, Brian. I will begin my comments on Slide 7. And in my comments today, I will cover our second quarter results, our 2026 earnings outlook and our capital plan.

As Brian mentioned, for the second quarter, we delivered GAAP earnings of $0.40. That $0.40 includes merger-related costs, costs related to incremental Colstrip ownership and weather impacts. On an adjusted basis, we delivered $0.50, which reflects a $0.10 increase from 2025.

Moving to Slide 8. On a year-to-date basis, we have GAAP earnings of $1.43 versus $1.60 in the prior period. On an adjusted basis, that's $1.81 versus $1.62. I'll remind you that we started off the year with an unseasonably warm winter, reflecting a significant adjustment to adjust out that weather impact for Q1 impacting our year-to-date results.

Slide 9 moves to a bit more of the key drivers for the quarter in particular. Key drivers include improved margin, net of weather, offset by higher costs, depreciation and interest expense. Increased operating costs includes $0.12 from incremental full-serve ownership, which we spoke about a lot on our Q1 call as to the impact of us owning those assets and the importance to resource adequacy.

Moving to Slide 10, I'll discuss in more detail our margin impact, including the $0.38 improvement over the prior period. Margin for the second quarter reflects new rates in Montana. We'll remind you that we implemented rates in the rate review from 2024 and May of 2025 towards the end. So you can see the continued improvement from that and impacting the first half of the year for us. It also reflects the sales from the Puget Colstrip interests and growth in transmission revenues.

Moving to Slide 11 to address our adjusted second quarter earnings. Again, as I alluded to, while the first quarter had a very significant weather impact, we returned to a closer to normal impact here. You'll see weather was unfavorable by $0.01 versus normal. The quarter also included $0.04 of merger costs and $0.05 of operating expenses from Colstrip that were not recovered. These adjustments move from a $0.40 on a GAAP basis to $0.50 delivered on a non-GAAP adjusted basis versus $0.40 in the prior quarter of 2025 as compared and again, noting that, that growth was really driven off of improved base rate recovery versus last year.

Moving to Slide 12. As Brian indicated, we are pleased with our start to 2026, and it is in line with our expectations, and we are reaffirming our guidance. We have executed any financing plans for the year and expect that to not have an impact in the back part of the year.

Moving to Slide 13 and concluding my comments. Our capital plan of $3.2 billion from '26 through 2030 remains on track and unchanged and is driven by the essential investments we need to meet our customers' needs. This plan does not include any incremental investment that may be driven by additional opportunities related to regional transmission growth or serving large loads, and we're excited to continue pursuing those opportunities.

With that, I will turn it back to Brian for a further business update.

Thanks, Crystal. My comments on Page 15, specific to the merger with Black Hills and the benefits to stakeholders. We certainly have talked quite a bit about the benefits to shareholders and certainly want to thank all of those who voted on the approval from a shareholder perspective of the transaction and acknowledge the overwhelming support. That also took place in the second quarter.

And also opportunity on this page, in the center of the page, also remind folks that there's also substantial long-term value for customers. Not only are we bringing together 2 strong teams from a service perspective, we're going to continue to provide great service on a going-forward basis on a combined basis. And not only that, any benefits that are accrued for putting these 2 companies together from a cost savings perspective that will ultimately accrue to customers in future rate reviews.

Moving forward to Page 16. If you think about the time line, we now have all the necessary approvals other than the MPSC commission's approval. As you note on this page, you see a lot of green checks. As a matter of fact, like we said earlier, shareholder approval, FERC, Nebraska, South Dakota. If you think about what was all done in the second quarter, it was a pretty busy quarter from a merger perspective.

We also -- as we sit here today, we're working extremely hard with our friends at Black Hills from an integration planning perspective. And so we're prepared. We will be prepared if, in fact, we do get approval from the Montana Commission to close and actually start providing the benefits of the merger to our customers and other stakeholders.

Speaking of the decision and waiting on a decision from the Montana Public Service Commission, we note on this slide that that's in the fourth quarter. I think people understand from the timing that is in front of the commission that we believe that upon our filing our briefing in mid-July that we would see a decision sometime in 90 days to -- it can extend another 30 days. So 90 to 120 days, we should see a decision. That should mean a decision sometime between mid-October and mid-November. And so we are certainly cautiously optimistic about that decision and working really hard that we're prepared to provide benefits to stakeholders on a going-forward basis if, in fact, we get that approval.

Moving forward to data centers. We continue to work hard on the data center process on Page 17. I think you can see some change in the high-level assessments. We're still very active in terms of folks looking at primarily in Montana and South Dakota from a data center perspective. More importantly, we continue to work with those folks that we have development agreements with and striving to get to ESAs with those parties. And as I mentioned on the prior quarter's call, I noted no guarantees, but I mentioned on that call, and I do it again, no guarantees here. We still expect to have ESAs within 2 of those 3 parties. And reason 2 of those 3 -- 3 of the last quarter, 2 parties, Quantica and Atlas, we still believe by year-end.

The issue where we sit here today with SEBI is they still are dealing with land procurement items. And so until that happens, it's difficult to say we would have an ESA done with them by the end of the year as we sit here today. But we continue to work with all 3 parties and those parties in the -- both the data center request and high-level assessment to continue to move forward to ultimately have data center load that we can provide in Montana and South Dakota.

Moving forward, just a little bit more on large-load customers. I think you're also aware in March of this year, we did submit our Large New Load tariff. The hope at that time when we filed it, we'd be filing it with an ESA. We did not. We wanted to make sure that people were aware that we're trying to protect customers with this large load tariffs, and we wanted to get that in front of the commission. It's there for people to see. In addition, we'd like to, when we do sign an ESA, file that ESA with the large load tariff and ultimately have a decision on that ESA as well.

In South Dakota, any New Large Load customers we require incremental capacity, but we do have an infrastructure rider there to help us with generation cost recovery. And the South Dakota PUC already has an established large load tariff that we can serve large-load customers with. The one issue in South Dakota continues to be the sales tax issue on equipment purchase, and we're hopeful in the upcoming legislative session, that issue will be dealt with.

On the right-hand side of the slide here, I continue to show from a megawatt perspective, each of those 3 entities in the development stage, nothing has necessarily changed there. So we continue to forge ahead with them on their current plans.

Lastly, on Slide 19 is our stand-alone value proposition. With an approximate 4% dividend yield with our base capital plan, we can achieve a 4% to 6% EPS growth, ultimately today provide an 8% to 10% total return. If we're able to take an opportunity and execute on data center and other large load opportunities for regional transmission and any incremental generating capacity, we should be able to grow at a faster rate in that above the 6% range, that plus that dividend yield I talked about earlier, around 4%, we could see total returns greater than 10%.

Obviously, that's our stand-alone proposition. As we sit here today, we think we could be able to deliver a 5% to 7% EPS growth on a combined basis in the merger with Black Hills. That's ultimately what we believe is the best thing we can do from a shareholder perspective. But as I mentioned earlier, another thing we really want to do for customers in particularly this day and age where affordability is a key issue, we want to make sure we continue to be as efficient as we can and even more so on a merged basis to provide those cost-saving benefits to customers on a going-forward basis.

And with that, I'll turn it back over to Kendra to conduct the Q&A session.

[Operator Instructions] Your first question from the line of Aidan Kelly with JPMorgan Securities.

Yes. I just want to hone in on the Quantica project first. I think many are focused on the quoted 7.2 gigawatt interconnection request laid out there, which is clearly a substantial number. And I understand when you capacity adjust, it could be closer to like the 3 gigawatt range, but still clearly implies some upside beyond Phase 1, what you've disclosed. So I would just be curious to hear your take on the probability of realizing the full 7 gigawatts and any physical considerations that come to mind here?

I put in this context, Aidan, I don't want to speak for Quantica here. I think as you noted on the document we shared here, 1.1 gig is what we're talking about from a Quantica perspective. I think we all need to have success at these lower gigawatt levels. And if we're ultimately in an ESA perspective, and we're moving forward with Quantica, we'll let them talk about their relative success and how to ultimately build up to that level. But as we sit here today, we're focused on the 1.1 gig.

Understood. Understood. And then just maybe wanted to ask a high-level question on the Colstrip ownership pieces. In the 10-Q, you guys laid out that the PCCAM tariff waiver was insufficient to contribute to the recovery of the O&M for the Avista share. Could you just remind us on the action plan for getting better protection on these costs and how are you thinking about the timing there?

Aidan, I'll take that one. It's a fair question. We've laid out the impact year-to-date, and we do have a tariff waiver currently for how that -- the impact of those sales flows through PCCAM. If you listen to the merger hearing, you would have heard a lot of commentary from the commission on their overall support for Colstrip and their view on what that asset means to Montana and keeping costs low. So our action plan eventually is to file a rate review and put that asset into base rates where it should be.

The thing that I would mention and remind you all of is we are waiting for a motion for reconsideration on our 2024 rate review. And by my clock here, we're close to the last day of July of 2026. So we need to see that order. We're continuing to invest significantly in Montana. And to your point, on action plan for ultimately adjudicating that piece of Colstrip with the commission. I think we'll need to file a rate review to address that, and that is something that we're considering timing of. And meanwhile, the PCCAM docket where that tariff waiver progresses that was granted on an interim basis, and we expect that docket to move through probably time line of Q4 of this year and maybe into early of 2027.

Your next question is from the line of Shahriar Pourreza from Wells Fargo Securities.

This is Whitney Mutalemwa on for Shahriar. So I'm looking through the IRP materials, and they show available import capacity on your transmission path declining through 2028, even before accounting for the large load pipeline. Obviously, there's the North Plains Connector and the utility has 10% stake that's still contingent on permits. Is that 300 megawatts enough to matter given how much load you're now discussing? Or does the real transmission answer have to be a bigger Bright Horizon's led project rather than a minority position in someone else's line?

I would -- I feel bad that I didn't include our regional transmission materials in the presentation, which we've certainly spoken about in the past. North Plains Connector is certainly something that we think is necessary.

Our Montana to Idaho line that we're working with, we think is also crucial to provide capacity on a going-forward basis. Those are in addition to some other opportunities on Path 8, which is our current Colstrip line that we share with other partners that serve the West, there are opportunities to expand the capacity on that line. And that, as you would expect, is a little easier to do than other greenfield projects and even reconductoring. So there's some work on that line that we think is extremely easy to do on a relative basis to other opportunities, but we're going to pursue those.

We're also looking at Path 80 as an opportunity. But I'd argue that there's a lot of transmission capacity that we're going to need, particularly if there's going to be growth in the Pacific Northwest and certainly in Montana. So we're excited about that opportunity and our ability to invest in transmission on a going-forward basis.

Sounds good. Well said. And then just to squeeze in a tiny question. There have been a run of local pushback this quarter. There were the moratorium discussions and a couple of counties, a couple of ballot petitions. Just zooming out, is that changing how you and developers approach siting, more pre-engagement, more flexibility on location, that kind of thing? Or do you see it as pretty contained to a handful of communities? That will be all.

Yes. I could spend half an hour talking on this topic. I would say it this way. We as an industry and certainly the data centers themselves and the developers that may be between the utilities and the data centers, we all need to do a better job in terms of communicating and working with communities to find out what the communities want, not necessarily what we think they want.

And I think there is a lot of misinformation about data centers. We believe data centers are going to be great thing for our service territory, and we think it's going to help our communities. In so many ways, we're going to continue to be supportive of their efforts. But we have to work collectively as a group and demonstrate benefits in a more concise way so they understand that these are actually good projects that are going to help their communities.

And so there's work to be done. I'd argue that's something that needs to be done in all states, not just the 2 states that we operate in from an electric perspective. I think it's more of an industry issue than just a NorthWestern Energy issue. There are certain states, of course, that support this, support data centers, and we can certainly name those states. But even those are running into some public pushback.

I think as we continue to educate folks around energy use and around water use, I think what has been recently done here in terms of an acknowledgment by utilities and data centers that we're not going to pass on higher cost to customers that data centers are going to pay their own way. Those commitments are going to help deal with some of these issues. But this is going to be a continuing issue for the industry for some time.

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

Crystal, can you give us a breakdown of the weather adjustment by segment?

Chris, I think that's in our appendix, but I'd remind you for Q2, it's only $0.01. So it's pretty small as it relates to the quarter. Obviously, a much bigger impact for Q1 as we saw really mild weather there. [indiscernible] of this.

Yes. And we haven't disclosed that, Chris, by segment. So I assume you're looking between electric gas, South Dakota and Montana. We don't disclose that. That's something we can consider in the future, but...

Okay. That would be helpful. The weather seems like it was pretty warm for July, certainly across Montana anyway I saw. Crystal, can you give us any sense of how you see the progression of the 2 Puget and Avista Colstrip pieces through the rest of the year, particularly with what the third quarter weather looks like so far?

Sure, Chris. And by the way, I will comment that I did see that you come around to our way of thinking on the weather. So I don't know if that's been a 10- or 15-year running conversation, but glad to see we finally got to there.

The next question is after a super mild kind of winter weather in the whole Pacific Northwest and a normal, call it, Q2 shoulder, what that had done, and we had talked a lot about market prices and the impact of finally being resource adequate in Montana, having assets where we could sell into the market and seeing really low market prices that obviously continued through the first and second quarters.

I will tell you here in July that we have seen -- I think we set a new balancing area record again. So we've seen warmer temps and demand on our system. I will tell you the market prices for a variety of reasons that our supply folks can get into haven't necessarily -- there haven't been kind of those big peaking events that you sometimes see in the market, but certainly an improvement as you're about through July here as to what we've seen for prices and the ability to cover our costs of those assets.

What that continues into late summer and fall, I don't know that I'll be on record for predicting the weather since meteorologists can't see to do it for the next day or so. But I will say we did see some improvement here in July based off that demand and being higher across the West and hope to see that continue as we go through the year. Obviously, we'd like to see those markets that will impact our ability to cover those costs and Colstrip and hopefully earn back a bit of what happened in the first half of the year, but I won't give you any predictions as to where that might be.

Okay. That's helpful. That's helpful. Brian, one more thing. Now that Baltimore is gone from the MPSD (sic) [ MPSC ], do you still stick to the sort of 90- to 120-day expectation? Does that sort of slow or speed the process of the merger approval? And how does that affect the large tariff docket also?

Yes. Chris, I assume you're talking about Commissioner Molnar. I don't think that has bearing on the timing here. But I think the 90 to 120 days still should hold. And my expectation is, as folks know, there are many times when commissioners aren't present to vote. And as long as there's a quorum, they can continue to vote on any matters. And I expect that to be the case here as we move forward.

Your next question from the line of Paul Fremont from Ladenburg.

I guess I'd like to start with the high-level assessment pool, which seemed to have doubled to 8 customers. Can we get a sense of sort of the megawatt size of demand that's in that queue?

Paul, no, we haven't shared nor do we share who's in that queue nor do we share the megawatts that folks are talking about at this point in time.

Well, how about in terms of -- with the customers doubling, should we assume that, that also represents a doubling of the megawatt demand in that bucket?

I'd say it this way. I wouldn't concern yourself too much with megawatts until you see development agreements.

And then it looks like 2 may have come from the data center request bucket and that 2 of those customers are -- would have come from somewhere else. Like is that a fair way to look at it?

Yes. I'd say what happens many times when you get to assessment, some people fall away because they find out they've got a preliminary idea of what the costs are going to be, and so they may fall away. So I can't speak to how the bucket shifted from requests to the high-level assessment. But typically, what happens when you get to a certain point, you actually know your cost. You do see some folks fall away. You also see some folks that work pretty quickly through that process.

And then maybe last question for me, is there sort of anything you can tell us about the geography of where those new high-level assessment customers are looking? Is it South Dakota? Or is it Montana?

I mean I will say it this way. I think in those 2 earlier buckets, we're seeing interest in both states.

Your final question comes from the line of Rex Savage with Clear Street.

I wanted to ask a version of a prior question on the commissioner status and so forth. It appears that commissioner is challenging his removal in Lewis and Clark State Court. I was wondering if you have any thoughts about that, plus it appears the governor is maybe moving to replace him after this 1-year period. Does that potentially change the 90 to 120 days?

And then a related question is on Quantica, which was brought up, I believe, on the first question, that 7.2 in the filing did seem to activate one of the opposers on the merger docket to ask to reopen the record. Are we past that point? Do you believe that the commission is going to look at it as is?

From my understanding, I think the commission is forging ahead here. I don't think -- I think they've done a good enough job through this process to say that this transaction is not about data centers. I think that conversation was had frequently during the hearing. And so I do not believe we're going to see a delay as a result of anything that's happening with Commissioner Molnar at this point in time or any incremental information that may have happened since the hearing.

There are no further questions at this time. I will now turn the call back to Brian Bird for closing remarks.

From a closing remarks perspective, I just want to say this again. I think we think about what we need to do as a company to grow and what's changing in the energy space. This merger is really important, not only, obviously, to the folks listening to this call today, but our customers and ultimately, our employees. We need to be bigger. We need -- it's more of a competitive environment we sit in today than utilities have seen and certainly in their first 100 years of existence. And so it's critical that we move forward, we become bigger. It allows us to better serve our customers and all of you. We continue to be very, very focused on that as do our friends at Black Hills. And we hope to be talking about that with you, if not in October, sometime shortly thereafter. And until that next time, I want to continue to thank you for your support of both NorthWestern Energy and obviously, our friends at Black Hills. Thank you very much.

This concludes today's call. Thank you for attending. You may now disconnect.

Good afternoon, and welcome, everyone, to the NorthWestern Energy first quarter 2026 financial results webinar. Today's conference is being recorded. [Operator Instructions]

At this time, I'd like to turn the conference over to Travis Meyer.

Thank you, Audra. Good afternoon, and thank you for joining NorthWestern Energy Group's financial results webcast for the quarter ended March 31st, 2026. My name is Travis Meyer, and I'm the Director of Corporate Development and Investor Relations Officer for NorthWestern.

Joining us on the call today are Brian Bird, President and Chief Executive Officer; and Crystal Lail, Chief Financial Officer. They'll walk you through our financial results and provide an overall update on what great progress we've had this quarter.

NorthWestern's results have been released and the release is available on our website at northwesternenergy.com. We also released our 10-Q pre-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'll direct you to the disclosures contained within our SEC filings and the safe harbor provisions included in the second slide of this presentation.

Also note that, this presentation includes non-GAAP financial measures and information regarding the pending merger transaction. Please note these non-GAAP disclosures, definitions and reconciliations and the merger-related disclosures included in the appendix of today's presentation materials. This webcast is being recorded. The archived replay will be available shortly after the event and will remain active for 1 year. Please visit the Financial Results section on the website to access the replay.

With those details behind us, I'll hand over the presentation to Brian Bird for his opening remarks.

Thanks, Travis. On our recent highlights for the quarter, we reported GAAP earnings -- diluted EPS of $1.03 and a non-GAAP diluted EPS of $1.31. We're affirming our 2026 earnings guidance range of $3.68 to $3.83. And we're also affirming our long-term rate base EPS growth rate targets of 4% to 6%.

From a merger progress perspective, I'm sure all of you listening have noted that we received shareholder approval of our pending merger with Black Hills and received approval of all proposals. And we've also put in place constructive settlements with each of our key interveners in Montana, Nebraska, and South Dakota associated with the merger dockets. From a regulatory and legislative standpoint, we've had constructive wildfire legislation passed in South Dakota, and we recently submitted a Large New Load tariff proposal with the MPSC.

Regarding data centers, we're happy to announce we've signed another development agreement, this time with Quantica Infrastructure, now for a total of 3 development agreements associated with data centers. And lastly, for dividend, we declared a dividend of $0.67 per share payable June 30th, 2026, the June 15 record date.

And with that, I'm going to pass it over to Crystal for our first quarter financial review.

Thank you, Brian. In my comments today, I will cover our first quarter results, our 2026 earnings outlook and our capital plan, and then I will turn it back to Brian to give you some of the exciting updates that he mentioned as we started the call.

I will begin my comments on Slide 7. We delivered GAAP earnings of $1.03, which includes impacts of a historically warm first quarter, merger-related costs and costs related to incremental Colstrip ownership. On an adjusted basis, we delivered $1.31 or 7.4% increase off of our 2025 first quarter results.

Slide 8 provides a bit of detail on these key drivers for the quarter. That includes improved margin, albeit net of the weather I just mentioned, offset by higher operating costs, depreciation and interest expense.

With regards to those operating costs, that includes $0.12 of an increase from the prior quarter due to our incremental ownership of Colstrip and $0.04 driven by labor and benefits. We've talked many times about the rationale for owning additional Colstrip and the importance of that facility to serving our customers in Montana, and we expect the annual operating costs to be approximately $48 million related to that incremental ownership.

So on a quarterly basis, you can think about that generally running about $12 million a quarter, and you will see that we have offset approximately $8 million of those costs here in Q1. The recovery of these costs was certainly impacted by low market power prices, impacted by overall conditions, driving power pricing lower than our expectations.

Moving to Slide 9 to give you more detail with regards to margin. Margins for the first quarter reflect new rates in Montana. You'll recall the timing of our rate filing last year and not having interim rate recovery in the first quarter, you'll see that increase here. Also noted are the sales from the Puget Colstrip interest, and also continued growth in our transmission revenues in the Bulk Electric System. This was offset by weather as Montana experienced the warmest winter in over 100 years.

Moving to Slide 10. That warm weather impacted us as an unfavorable $0.17 versus what we would expect as normal volumetric loads. As I mentioned, very mild weather in Montana and that continued off of our fourth quarter results as well. The quarter also included $0.05 of merger costs and $0.05 of operating expenses from Colstrip that were not recovered that I just mentioned. Those adjustments result in on an adjusted basis, $1.31 of earnings again for the first quarter of 2026 as compared with $1.22 in the prior quarter.

Moving to Slide 11. Brian noted that we are reaffirming our guidance for 2026. Looking ahead to the timing of our next rate reviews, which you all typically would expect us to announce our timing of rate reviews here in Q1. The settlement agreement that Brian will give you more detail on related to the merger do include some stay-out provisions both in Nebraska and South Dakota. For Montana, we have not determined the timing of our next rate review as the 2024k still remains under reconsideration.

In addition, critical to our long-term earnings profile, as we've talked about where we want to be from a 4% to 6% earnings growth perspective are the developments that Brian referred to with relation to development agreements with Quantica and also the large load care filing, all underpinning our ability to reaffirm our guidance both for 2026 and beyond.

Slide 12 gives you more detail on our capital plan. This remains unchanged from our fourth quarter call of $3.2 billion from 2026 through 2030. And I'll remind you that, that is driven by essential investments to meet our customers' needs. It does not include incremental investments that may be driven by additional regional transmission opportunities that we are very excited about or serving any of these large loads. It does include, however, what we adjusted for at Q4, which is to include the incremental generating capacity in South Dakota related to the SPP Expedited Resource Adequacy Study.

We are delivering on our base capital plan without issuing new common equity and have no equity needs in 2026. As we updated you on our Q4 call, incremental capital in 2027 related to the generation capacity in South Dakota will require some equity needs in 2027 and beyond.

And with that, I will turn it back to Brian for the rest of the update.

Thanks, Crystal. On Page 14, we've got good news in terms of South Dakota wildfire bill. Senate Bill 36 was passed to the South Dakota legislature with broad bipartisan support and has been signed into law. And I would just say, first and foremost, no strict liability. Strict liability cannot be applied to utility operations unless to have caused wildfire-related damage. In fact, the legal protections for providers and damages also shown on Page 14, you will find it's extremely similar to what we have in our Montana legislation.

As a matter of fact, if you want to go back and compare this page to our Montana page, it's very, very similar. So we're very excited about the protection that we have in our 2 electric states from a wildfire perspective, some of the best wildfire protection in the United States at the state level.

We plan to submit our wildfire mitigation plan for the South Dakota PUC approval in the second half of 2026, and we expect to update that plan every 2 years going forward.

Last thing I would say here from a wildfire perspective, I look back 3 years ago and what we've been able to do from a legislative standpoint and an operational standpoint and a situational awareness standpoint, we feel much better about how we will mitigate wildfire risk in our states, but also acknowledge there are -- it is going to be a difficult fire season in front of us, and we need to be cognizant of that as we continue to monitor our systems in those 2 states.

Regarding the merger with Black Hills and how that benefits stakeholders, I think certainly, we spent a lot of time talking to shareholders about this. Obviously, the increased scale and our ability to go from a 4% to 6% EPS grower to 5% to 7% and being able to putting these 2 companies together, double our rate base on a going-forward basis.

Expanding investment opportunity, having more resources, not only from the financial standpoint, but from a personnel standpoint, putting the right amount of resources at these opportunities.

A stronger balance sheet, 2 strong companies coming together to even have a stronger balance sheet on the other end. and obviously enhanced business diversity in terms of an expanded footprint and a much larger company for both entities. That's certainly a benefit to shareholders, and that combination represents a highly attractive value creation opportunity. And I think that's been supported by our shareholders, approximately 86% of our shareholders voted. And of those that did, 99.7% voted in support of the merger. So obviously, trying to do the right thing from a shareholder perspective, but this merger will benefit many stakeholders and certainly customers.

What I want to say about customers, not just taking 2 companies that provide great service and do it in a reliable and a cost-effective manner. But on a going-forward basis, any cost savings that these 2 companies will achieve ultimately accrue back to customers in future rate reviews. And so we're excited in this time period when the affordability is front and center in front of all of our customers, doing the things that we need to do to help in that regard. And the merger is certainly one of those. And so we hope as we move forward with each of the 3 states we're working with, we ultimately can get those approvals.

And with that, on Slide 16, talking about the time line itself, we did acknowledge here earlier in the call, reaching settlements in each of the 3 states that we have filed applications for approval. And we actually had a hearing already in Nebraska, and we'll have hearings in Montana and South Dakota in the May and June timetable, respectively. So continued good progress there. And again, having key intervener settlements are key at this point in time.

In addition to from a state perspective, we certainly filed back with FERC way back in December. And if you look at the 180-day approval time line, hope to hear back from FERC by the end of June. From a FERC perspective. In terms of the S-4 and joint proxy, obviously, the shareholder approvals were received here not too long ago. And the Hart-Scott-Rodino, we've satisfied that based upon the waiting period expiring for that. So really a lot of green checks on this page and this time line, that's fantastic. But we're still certainly waiting on not only FERC, but the 3 states to ultimately make a decision. And obviously, we have to have hearings in 2 of those states.

So lots of green checks. We'd like to think we could get something sooner rather than later, but we still believe that an outcome will finally be achieved here. And obviously, getting the approvals we need, we expect to have that in the second half of 2026.

Regarding data center process and progress, I would say we continue to quite a bit of demand. We actually increased our data center request queue from 6 to 8 since the last time you've seen this page. High-level assessments actually come down. I think as people go through the process and understand what they need to do in essence to put forward a deposit and think about the costs associated with moving forward. We had one of those fall away down to 4 in that high-level assessment. Hopefully, we can continue to move folks there to a development agreement.

And by the way, speaking of that, you can notice on Slide 17, we've kind of grayed out letters of intent. When Quantica signed the development agreement, we no longer have any LOIs per se, we've moved those to the development agreement stage. And as we move forward with folks in the high-level assessment, we would want to move them directly to a development agreement, and so that's the hope there.

And of the 3 in the development agreement phase, we'd like to move all of those to an ESA or an Energy Service Agreement. And I would say this, instead of guaranteeing a timing of any ESAs, I would put it in this context. All 3 of those parties, those developers, would like to have an ESA done by the end of 2026. We on our end we're doing everything we possibly can to deliver that we're ready from a 2026 perspective, but we'd also point out that they need to do certain things on their aspects as well.

So the hope is we could bring some of these development agreements to ESA by the end of the year, but certain things certainly must get done, and we will work with them and all of us desire to make that happen by the end of the year.

On Slide 18, from the regulatory front in terms of large load customers, the big news in this quarter is we did submit our Large New Load tariff with the MPSC in March 2026. Certainly, a lot of questions about data centers and protecting customers. If you take a look at our Large New Load tariff, that is definitely what the intent is, not only protect customers and the company, but also just give the guidelines in terms of where we're going to go if, in fact, we can serve large load.

So that was a significant development during the quarter. And I think the rest is relatively the same in Montana and South Dakota. We're ready to move forward if, in fact, we get the large load tariff in Montana, but we're ready today with an ability to serve large load in South Dakota.

Regarding that, I mentioned earlier, we're seeing some demand. We were disappointed. We were not able to achieve any sales tax relief from a data center perspective in South Dakota, but we're still seeing quite a bit of interest in South Dakota, nonetheless. And so we'll continue to be -- work with folks to see if we can come to any agreements there anytime soon.

In terms of the 3 parties that we're working with, I'm sure many of you read Sabey has had some issues procuring the land necessary for their data center. They continue to work through that issue, and we're certainly being patient with them in that process. Atlas continues to move along the process necessary to get from development agreement to ESA. And then Quantica, of course, the big news as of late is our development agreement with Quantica for their load, which goes from 25 megawatts ramping up to 1.1 gig with a targeted start date of early 2029.

As is common in these transactions and particularly at this phase of the process, a customer has not been named at this point and will certainly be named at the point in time that if, in fact, we do enter into an ESA with that customer.

Colstrip on Slide 19. The reason I want to cover this slide, just to make sure there's no confusion about our intent with our 2 pieces of incremental Colstrip. I think everyone is aware, we acquired the Avista portion of Colstrip to get to resource adequacy with that particular level, 222 megawatts. And we procured the Puget 370 megawatts to go from 30% with Avista to 55% to make sure we have control over the Colstrip and the future of Colstrip and is in our hands instead of at the hands of some others who may not think about Colstrip on a long-term basis.

And so that's really important for the state. I think you also know the Puget piece is currently in a FERC-regulated entity and will be there until we have an indication on our Large New Load tariff. And if, in fact, that Large New Load tariff is actually put in place, it would be our desire to move that asset into our Montana state regulated business. But until we have an outcome on the Large New Load tariff, we will continue to have that as a FERC-regulated asset.

I think many are aware of the NorthWestern value proposition as a stand-alone business with a 4% dividend yield and our 4% to 6% EPS growth based upon a $3.21 billion capital program, which is divided relatively evenly between our transmission distribution and supply businesses, but executable and low-risk critical capital to our customers, we could still that investment, that growth rate can achieve an 8% to 10% total return.

We do have incremental opportunities, we believe that can help us grow faster than 6%, but we have to deliver on those. And none of these opportunities, I'm going to talk to you about today are in our current plan. There's no data center in our current plan and off to the left in terms of capital investment, there's no FERC regional transmission. There's no incremental generating capacity other than the South Dakota capacity that we've talked about. This will be incremental above and beyond that. Those are not in our plans today. But if, in fact, we were to deliver on that, we could see total returns greater than 10%.

The other thing I would say here is back to the merger conversation, we believe we can execute on this plan even better, better together with our friends at Black Hills. And so obviously, the merger continues to be important to even maximize more so that value proposition.

And with that, that concludes our presentation, and we'll take any questions at this point in time.

[Operator Instructions] We'll take our first question from Shahriar Pourreza at Wells Fargo.

This is Whitney Mutalemwa on for Shar. Congratulations on the quarter. You stated that there's a need for large loads to get things done on their end before getting to the ESA stage. Does the recent Sabey land situation reinforce the need for stricter milestones just around site control, permitting before NorthWestern really begins to treat a project as part of a planning baseline? And then I have a follow-up.

I think I would say in this context, initially, when we wanted to file the large load tariff, the intent was for us to take an ESA with one of these large load customers and jointly go in and talk about the large load tariff. One of the things we want to do is to make sure that we continue to work with these parties in -- it's going to take a while, I believe, to get ultimately a resolution of the large load tariff. In the meantime, we'll be able to continue to work with these 3 developers on all the necessary things they need to do and we need to do to ultimately bring us to an ESA position.

That's actually sounds pretty good. And then just to move on to just thinking about large load numbers. Today's update was notably stronger just on the aggregate level with demand tied to the 3 large load customers now scaling to 1,500 by 2030 versus the prior 1.1 gigawatt framing. Can you help bridge what's actually driving the increase from the prior outlook? I understand that it's mostly Quantica, but is it better visibility on existing counterparts or just a broader change in how you're underwriting the pipeline?

Yes. The primary change here was specifically to Quantica. I think you might see prior, I think we had something in the 500 range for them, obviously, 1.1 gig from them today. So I think the change is primarily associated with Quantica.

We'll move next to Aidan Kelly at JPMorgan.

Maybe just going back to the large load front. Clearly, you've demonstrated some good progress on getting your third development agreement this quarter. I guess ahead of ESAs, I'd be curious to hear what the latest resource planning assumptions are for each of these projects. And if like you could comment on what NorthWestern's ability is to participate in generation opportunities. I think in the past, Brian, you mentioned like build-own transfer as an opportunity, but I would appreciate if you could just tee up where we are today and kind of walk through the playbook of what utility participation looks like at this time.

Aidan, it's a great question, and I could talk about this for about half an hour. So I will try to keep it as brief as I can. We definitely would like to participate. I think one of the things I've talked about in the past is concerns about the procurement rules in Montana in terms of IRPs, RFPs and pre-approval, it's a long process. And our data center partners certainly would like to move faster than that. So one of the things that we're looking to do with them is to say is their ability to participate in some form or fashion through a build on transfer process.

And they obviously want to be working, I think you heard data centers say, we'd rather be served by the utility through a portfolio than stand-alone behind the meter resources. And so that's ultimately what we'd like to do, but our procurement rules and their desire to move quicker is going to be tough. So I think we're going to have to work together and try and necessarily find a way to do that. Obviously, the Puget interests are available, if you will, for large load tariffs. So that's certainly helpful. Our existing portfolio is really there to serve our existing customers, but the Puget 370 portion certainly can help.

And our long-term IRP does have some cases associated with data center build-out, but it would have to be in the back half of some of these opportunities. And so we will work with each of these developers in their resource planning and ultimately come together where we can participate together, but certainly on a lesser interest maybe than some utilities who have procurement rules that allow them to actually provide all of these resources.

So again, we want to participate certainly as much as we can from a generation perspective, and we'll plan to do as much as we can there with the timing we have. But remember, there's going to also be a tremendous amount of transmission opportunities associated with this as well. So we're excited about our ability to invest along with our development partners from a data center perspective.

And then just one more question on my end. I wanted to pivot to the regulatory front. Just any thoughts on the upcoming Montana Commissioner elections and how this might influence your strategy in the state?

Well, in terms of our strategy in the state, I would put it this way. We don't have a strategy in the state in terms of what commission is ultimately elected. We're obviously going to work with whoever gets elected and want to, obviously, with the commission to do the right things for our customers in Montana. If you have a question regarding what the races are looking like, I can certainly go there, but I'm not necessarily sure specifically what your question is there.

I guess just like the filing cadence, how you kind of think about that as the election kind of some momentum into this fall and just thoughts on that.

Yes, Aidan. I think there's always lots of things that go into our filing cadence. And we've been very clear with -- and obviously, being a state with elected commissioners, all 3 of ours actually that regardless of when elected commissioners may come or go, we're going to need to recover our costs. We're investing significantly to serve our customers in Montana. So those are going to be fairly frequent cadences. And while there is an election, there's 2 seats up for this year, one with one terming out and the other with a commissioner running for reelection.

Either way, we're going to continue our cadence of needing to recover our costs at historic rate making and I alluded to the fact that '23 test period, '24, no measurable filing and its 2026 end of April, I think, and we still don't have the final outcome. So we're going to need to work within that historic rate-making context and keep filing. So while the elections may come and go, it doesn't necessarily change our broader strategy of recovery.

We'll go next to Chris Ellinghaus at Siebert Williams Shank.

Crystal, was that the largest weather deviation from normal you've ever had?

Funny you asked that question, Chris. We're actually prepared for that one. I think first quarter of 2019, we actually had a slightly larger deviation, and that one happened to be a colder weather event. So we actually saw incredibly cold weather that winter. So we did go back and take a look. So it isn't the most material weather impact, but its overall average warmth, I would tell you, between both Q4 and Q1, I would suggest that was probably the most significant we've seen.

Brian, you said you would discuss how the races are going. So how are they going?

Well, I think I would say that we have a commission up for election in both South Dakota and Nebraska. And in terms of primaries there relatively quiet, what I can see in Montana, I know commission Dr. Bukacek has got 2 Republicans running against her in the primary there and I think an unchallenged Democrat. It's early innings here in terms of what we can say there. The Panoche seat is open, and there are a couple of Democrats running for that seat and I think an unchallenged Democrat.

And again, regardless, Chris, obviously, whoever gets elected, we're comfortable working with, and we'll continue to watch. But as we sit here today, I think the primary, I think you know are coming up in the June timetable and the time period for others to get into those races in Montana, I think, is passed. So stay tuned.

So given the speed that Montana sort of operates at, I think when I look at your sort of diagram of merger approval expectations, certainly, the other states operate in sort of a more normal kind of timeline for decisions. But Montana is particularly slow. And given that the hearings start the middle of next month, if you just took a rate case, for instance, as an example, it could be many, many months following the hearing before you get orders. So is there any reason you have some confidence in getting approvals in Montana by the end of the year?

Thanks, Chris. It's a good question. Obviously, we say the latter half of 2026. I'd say I'm confident, first of all, we don't know what the outcome is, and we hope to acquire certainly the appropriate amount of votes in order to get a good outcome. The reason, I think the speed of that outcome should be relatively quickly. For 2 reasons, one, the important interveners, if you will, large customer group, obviously, the Montana Consumer Council. And obviously, you saw a handful of other interveners have agreed and settled here.

And so in essence, we've gotten to a point where people are comfortable with the merger such to be in settlement with us. That's the first reason. So I think we've taken a lot of the issues, if you will, off the table. And we have 2 interveners that really remain that we need to have a hearing with and have a contested issue. So I think the fact that we've got a lot of progress from these settlements should help in the speed.

The second thing I'd say is there's a $10 million benefit that will accrue to customers shortly after the merger. And I think if that benefit... I would expect that the commission would want that benefit to get to customers as quickly as it possibly can. So I would think taking those things into consideration, I'd like to think this would move faster than slower.

You were talking about wanting to take an ESA with you to the commission to talk about the large load filing, is there not enough precedent in other states? There have been some really good mechanisms built into particularly Southern states and some of the Midwest [Technical Difficulty] for adding new resources. So is that not enough to be able to take some of that presidential evidence to the commission good enough relative to being able to take a customer specifically?

Yes. 2 things, Chris. First and foremost, the nice thing about the utility space is we do see what our neighbors do, and we think we've taken really the best of all of the large load tariffs that we've seen out there. And I think you've seen kind of a middle of the fairway proposal that's in line with what you've seen elsewhere in the industry and one that's in such a position that it protects customers.

The second thing I'd say is that we were at a point in time, I believe that we would have an ESA some time ago. As you know, Sabey run into some land issues that were not... we were not aware of until here most recently. So I think the timing of a large load tariff and that ESA, we thought they would be about the same time. And why not bring with it into that large load tariff. From our perspective, we want and there's a lot of questions out there, Chris, about how we're thinking about data centers and how we're going to protect customers. We felt it was in the best interest of everybody for that dialogue to make this Large New Load tariff filing.

And you're right, it does... if you think about it, it's very, very similar to the other protections utilities are seeking for their customers. And so we certainly have an opportunity to look at what others are doing.

And Chris, I would just add on our filing for those who don't read the devil in detail of the filings, it is a good spot to be in because you can reference all these others states that have already found a path to making sure there's not cost shifting, reasonable stranded asset protection. Our framework does exactly that and does specifically benchmark all those other tariff filings that have gotten there. So I think brings us to a point that there's a great basis to your question there that the commission can consider without having a specific customer contract to look at.

And hopefully, we will have one of those soon, but they can consider that, that tariff framework provides adequate protections for customers in the state while allowing for the great benefits that you could see on needed system investment that large load customers pay for that.

Maybe I could rephrase the question a little bit. So obviously, you guys see what everybody else is doing. But sort of the rhetoric that you've heard throughout certainly last year quite a bit was seem to suggests that maybe some of the commissioners in Montana had not sort of been filing how these other jurisdictions were going and the protections that are provided and the customer benefits provided. So do you think they're watching?

Yes, I can't speak for the commissioners. My expectation they and the staff are following what's happening in other states. I certainly would hope so. I just like them to understand that what we're trying to do, and as Crystal also pointed out, we're trying to do something similar protections that have already been done and accepted in various states. And I think testimony has certainly provided to give examples of that.

Sure. And like you said, with the settlement in Montana for the merger has benefits, it's not just protections, there's customer benefits that come from these as well that you would think they would want to speed along to customers. Anyway.

Yes. Chris, I'd argue in all 3 states, obviously, it's credit in Montana, but even the moratorium in South Dakota, Nebraska provides protections for customers in all 3 of those states.

We'll take our next question from Paul Fremont with Ladenburg.

Congratulations on the good quarter. Starting with sort of Quantica over, what period of time would it take for them to reach 1,100 megawatts?

That's a good question, Paul. From a ramping perspective, I think about 2 years, starting in '29 and about 2 years.

Yes. I think our materials is around 2031, they be a full ramp.

And then when I think about your 4% to 6% and the fact that no data centers are included in the current 4% to 6%, would Sabey and Atlas keep you within the 4% to 6%? Or would you expect that Sabey and Atlas could put you above sort of the 4% to 6% EPS growth?

Paul, the way I would answer that is each of these deals are going to be specific to the needs of the customer and what's the needed investment that will be driven by where that customer is located, where they want to be. So we've consistently said, A, we can't specifically quantify it until we get to an agreement with them and can then clarify what that impact is to earnings. But all things considered equal, certainly pushes us upwards in the range.

And then should we assume that the Avista portion of Colstrip would likely be the source of generation that would serve Sabey and Atlas?

No, we shouldn't assume that. The Avista portion is -- I think you may recall, and Paul, we talked about this for some time at this company, we certainly did not have the appropriate reserve margin in our business. We're not resource adequate. The Avista piece got us to resource adequate to serve our existing customer needs. The Puget piece, remember that, as I described earlier in the call, that got us from an ownership perspective at Colstrip that made us more comfortable that we had control certainly over the future Colstrip.

But that $370 million not necessary for customers today and nor did we want to burden our customers with $330 million of operating costs that for assets they don't need today. But that $370 million is available to serve large customers.

So then if the Puget piece serves those customers, what potential other spending would you see that would be associated with Sabey and Atlas if they were to come online?

Yes. You're speaking specifically here from a generation perspective. Obviously, there's going to be transmission investment and other investment necessary to support that. And I think as Crystal pointed out, when we have an ESA, we'll be able to talk a little bit more about that.

Paul, I would also add that our large load filing in that framework, the premise is that each customer would pay the current embedded rate in the large load tariff and that you would surcharge for any incremental investments such as transmission or generation. So the other way to think about that is they would come on paying the rate that is set in each base rate case, and that sets the floor of rates they would pay and contribute to the systems.

And then beyond that, we would be able to surcharge based off each individual's customer needs, and that's where you get to the question you're going to of how do you think about this and model the opportunity, which is when we are able to sign a specific ESA, we'll know what that needed incremental investment might be.

And then how realistically would you serve the Quantica load if it were to ramp beyond sort of what's available out of the Puget piece of Colstrip?

Yes. I think in that timetable that they're talking about, as we talked about in our current IRP, we talked about the ability to serve in a base load, our base plan didn't talk about serving data centers, but we had scenarios where data centers are included. But I think in essence for them to for us to participate on the back end of that, we're going to have to maybe catch the back half of that 2031 with some generation. But I think in our discussions with them, they're going to have to bring their own generation and particularly for the 29 and 30, and I'm going to guess from their needs, all of that load, certainly a good portion of the 31 as well.

We'd like to participate, but it's going to be in the back end. And we like to make sure in what they do build, we would like to have the opportunity from a build on transfer in anything they build.

Great. And my last question has to do with, I think the large customers suggested that they wanted to see you pursue greater integration of your system with Black Hills post-merger, can you maybe give us an idea of the type of integration work that you think would make sense to better serve the customers of both systems?

Yes. I would think from the generation needs to serve our customers, I think the generation closest to our customers are likely to continue to be built in our service territory. The biggest opportunity out of the blocks would be looking at Path 80 from a transmission interconnection perspective. I shared that in the past as one of those paths. But I think as we continue to look at North Plains Connector and other opportunities for regional transmission, being able to be combined with Black Hills certainly, I think, gives us better opportunities to participate in all of the regional opportunities we're looking at.

And like the KV size of that line and how many miles roughly would that be in terms of construction?

Well, North Plains Connector, we're talking about a 10% or a 300-megawatt interest. And I'm not sure what's publicly stated in terms of the dollar amount associated with that project as we sit here today. It was a pretty sizable investment for us. We're evaluating that. We're evaluating, of course, continue to invest in the Colstrip transmission line and the upgrades associated there. Paul, we're looking at our Montana, Idaho opportunity in terms of investment there and also Path 80, obviously, being able to connect ourselves between Black Hills and our system.

We have a slide associated with that regional transmission we shared in the past. In terms of the dollars associated with that, we're still in relatively early phases of development. And until we get to certain stages there, we're going to probably stay away from sharing what dollar amounts would be. We think those investments would be.

And that concludes our Q&A session. I will now turn the conference back over to Brian Bird for closing remarks.

I appreciate the comment earlier about a great quarter. I just want to say this. I think you think of the progress thus far on the merger, the shareholder vote, the 3 settlements. I just wanted to thank my team. I want to thank the Black Hills team, great coordination to make that happen and the timetable that we have.

Great work here at NorthWestern to not only be able to make progress on the merger, but to deliver all the things that we're -- all the other things we're talking about here on this quarter and to continue to serve our customers as well as we do each and every day. So really, really proud of our group and the great quarter we've had. So thank you very much.

And this concludes today's conference call. Thank you for your participation. You may now disconnect.

Thank you for standing by. My name is Jordan, and I'll be your conference operator today. At this time, I'd like to welcome everyone to NorthWestern Energy 2025 Year-end Financial Results Webinar. [Operator Instructions] I'd now like to turn the call over to Travis Meyer. Please go ahead.

Good afternoon, and thank you for joining NorthWestern Energy Group's financial results webcast for the full year ended December 31, 2025. As Jordan said, my name is Travis Meyer. I'm the Director of Corporate Development and Investor Relations Officer for Northwestern. 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 progress this quarter.

NorthWestern's results have been released, and the release is available on our website at northwesternenergy.com. We also released our 10-K premarket 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'll direct you to the disclosures contained in our SEC filings and the safe harbor provisions included on the second slide of 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 and reconciliations and the merger-related disclosures included in the appendix of the presentation materials. This webcast is being recorded. The archived replay will be available shortly after the event and remain active for 1 year. Please visit the financial results section of our website to access the replay.

With that behind us, I'll hand the presentation over to Brian Bird for his opening remarks.

Thanks, Travis. Speaking about 2025, first and foremost, I want to talk about how we've done in terms of executing on our strategic initiatives. First and foremost, we announced our agreement with Black Hills Corporation for an all-stock merger of equals. We patiently waited and ultimately closed our acquisition of the Avista and Puget Colstrip interests as of 1/1 26. We recently submitted a 300 million or 131-megawatt South Dakota natural gas project to SPP's expedited resource adequacy study, and we are now including that project in our ongoing capital plan.

And we acquired the Energy West in Cut Bank Gas natural gas distribution assets. On the legislative and regulatory front, -- and we have very, very good outcomes in 2025. On the legislative front, Montana Satipel 301 was Simon Mila, providing greater confidence for transmission investment. -- in Montana and Montana House Bill 490 signed into law, which clarifies and limits wildfire-related risks, protecting our customers, communities and investors. So again, a very good legislative outcome in '25.

On the regulatory front, speaking of wildfire, we also -- as part of that legislation, we need to get our wildfire plan approved, and we did get that approval from the Montana Commission in 2025. And then also on the regulatory front, we did complete our Montana electric and natural gas general rate reviews. And then moving forward, thinking about the data center growth opportunities, during the year, we signed our third letter of intent with Quantica for 500-plus megawatts data center and we progressed with SEBI from a letter of intent to a development agreement. So that's 2025.

More recently in talking about financial results, and Kristen will get into that here shortly, but the financial results for the full year we reported GAAP diluted EPS of $2.94 and our non-GAAP diluted EPS of $3.58. We are increasing our quarterly dividend by 1.5% to $0.67 per share. We're initiating our 2026 earnings guidance range of $3.68 to $3.83. And we're updating our 5-year capital plan to $3.21 billion, a 17% increase over our prior plan.

Speaking of the merger with Black Hills, which we anticipate closing in the second half of 2026. We filed joint request for a merger approval in the States Montana, Nebraska and South Dakota, but we also filed with FERC, and we recently filed also our Form S-4 and joint proxy. Regarding the Montana IRP, we initiated -- or submitted, I should say, our Draft 126 integrated resource plan here about a month ago. And from a Montana data center perspective as of yesterday, we advanced our friends at Atlas Power from an LOI perspective to a development agreement. And I'll speak to all of these topics a bit more after Crystal's presentation.

With that, Crystal.

Thank you, Brian. In my comments today, I will cover our fourth quarter and year-to-date results. I will also cover, as Brian mentioned, our outlook for 2026 and our updated capital and financing plan. after listening to Brian there, it's been a really, really busy 2025 with a lot of accomplishments. And our team has worked super hard to also deliver on our results for 2025, achieving 5.3% growth off of 2024 on a non-GAAP basis. We delivered GAAP earnings of $2.94, which included impact of merger-related costs, the regulatory outcome rate case in Montana and a very warm fourth quarter. I'll describe those adjustments in a bit detail -- further detail here on a later slide.

Adjusting for those items, as I mentioned, we delivered $3.58, and that's the efforts after quite a few headwinds during the year to deliver upon our shareholders.

Moving on to Slide 8. On an adjusted basis for the fourth quarter, we delivered $1.17 and our improved margin reflects new rates, a lot of regulatory execution involved in getting to those numbers, which were offset a bit by mild weather, as I alluded to in the fourth quarter very warm for us and impact of market prices in our Montana PCAM mechanism. That margin improvement was offset by a onetime charge in the Montana rate review, higher operating costs and operating costs certainly include merger-related costs as well and then depreciation and interest expense increases as well.

Moving to Slide 9 to talk about some of the adjustments for the quarter. Weather for the quarter was unfavorable by $0.03. But when you compare that a very mild 2024. However, compared to normal, weather represented a $0.13 impact to us in Q4. The quarter was also impacted by $0.03 of merger costs, the onetime charge for the Montana rate review outcome related to the Elstone County generating station and the disallowance of certain costs related to that was $0.38 and $0.03 related to the PCAM, reflecting the final order there -- reflecting cessation of the sharing amount there, offset by a $0.12 tax benefit. You'll see that resulted in the $1.17 of adjusted earnings compared to $1.13 in the fourth quarter of 2024.

On a year-to-date basis, moving to Slide 10, our performance is driven by, again, that improved margin driven by regulatory execution, offset by detriments of PCAM within that of $0.09 from a full year basis. On an O&M perspective, certainly higher given new maintenance at the Yellowstone County generating facility is the maintenance at our other electric generation, the amount we're spending importantly on wildfire mitigation and also insurance that is increased in labor and benefits. We also incurred higher depreciation expense of $0.27 and interest expense of $0.23.

What I would highlight on this slide is that taxes in the current period includes a $0.12 benefit while 2024 included a $0.39 benefit, which is a good segue to the next Slide 11 to hopefully give you clarity on quite a few things that moved within our earnings from a 2025 full year basis. Weather, again, was unfavorable by $0.05 compared to normal weather that was $0.18 of detriment for us as we think about our impact of results for 2025. It was a very mild back half of 2025. Most of you won't recall, but we actually started the year through first quarter with favorable weather. So that reversal was really significant for us and impacts also as we'll talk about later, cash and the impact of financing plans.

In addition, merger-related costs were $0.15 and the Montana rate review just launch I spoke to was $0.38, which notably we have thought reconsideration of that disallowance, but we do not have a clear time line as to when we might see any impact of that. But that would certainly be a 2026 item if so. In addition, I spoke to tax benefits and quite a bit of noise within our tax number between last year and this year, there was $0.12 of discrete items benefit in 2025, and that compares to, if you'll recall, 2024, we had $0.28 in the prior period. All of that, if you'll follow the slide alone gets us to $3.58 of adjusted earnings for our 2025 number, which as I alluded to earlier, was 5.3% of an increase over 2024, and my comment there is, given the significant headwinds, we've talked about the headwinds in our financials from our PCAM mechanism, which again, I'll take a positive out of the Montana review outcome, indicating that the sharing part of that will be suspended on an ongoing basis. That's important, but that was about $0.09 of impact to us in 2025 total, which we've adjusted out the fourth quarter here.

And then also property taxes being higher. We collect a significant amount of property taxes through our rates, those increase, and we only recover a certain portion of that between the rate cases. Those were pretty significant headwinds for us during the year. So we are pleased on top of the mild weather that I talked about and the ongoing impact to our financials, we are pleased that delivering $3.58 for 2025.

Slide 12. Looking forward from a guidance perspective, we are initiating earnings guidance in the range of $3.68 to $3.83 per share. which represents 5% growth at the midpoint off of our 2025 results and remains anchored to our 2024 base. A significant part of that is moving to Slide 13 and updating our capital plan. Brian mentioned the inclusion of the 131-megawatt generating facility in South Dakota. And also, we've updated to include our incremental Colster ownership, we're very product closing those transactions effective January 1, 2026, and being resource acuate to make sure that we can serve our customers. Those 2 things drive a 17% increase in our overall capital plan over what we've reflected before.

You'll recall our dedication to having a self-funded capital plan and only issuing equity when it is accretive on an ongoing basis. I would tell you that the base capital plan that underlies the $3.2 billion you see here continues to be self-funded. With the incremental South Dakota generation investment reflected here, we do expect to need equity beyond 2026 to fund that investment, which we expect if you think about that to be on a 50-50 debt-to-equity basis that we would manage that incremental capital, and that's consistent with our overall commitment to maintaining high credit quality in our ongoing plans.

Moving to Slide 14 to talk about financing for 2026. Again, I just mentioned that the incremental South Dakota generation investment, that would be beyond 2026. We expect to issue debt to refinance existing maturities and fund our existing capital plans. We closed out 2025 at a lower FFO to debt. That was driven by the things I mentioned earlier, the combination of lack of margins from very mild weather affecting our cash flows and also being significantly under collected as supply costs on the Montana side. Those 2 things really drove us closing out the year at a lower level than we would like to, but we remain committed to getting above and staying above our downside thresholds.

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

All right. Thanks, Crystal. On 16, we speak to the merger with Black Hills and the benefits to really to all stakeholders. And obviously, the strategic combination represents a highly attractive value creation opportunity for both companies. On this slide really speaks to, certainly from a shareholder perspective, but also customers. So let me start with shareholders and it increases scale, position and growth. I mean, think of moving 2 companies from a 4% to 6% EPS growth to 5% to 7%, doubling of each company's rate base totaling approximately $11 billion both companies having significant growth opportunities and ability to take advantage of this merger to truly capture those. And as it points out, a little bit lower on the slide as a larger company, we'll be able to expand our investment opportunity. And I should also acknowledge it reduce risk as a larger company with risks, like wildfire risk and other risks that we have in our business, we certainly can sustain those as a larger organization.

Also strengthen the balance sheet and the credit metrics. You heard Crystal speak to that just a moment ago. Obviously, as a combined entity, we have the financial wherewithal to invest more in our businesses as a larger company and do that cost effectively for our customers. And lastly, enhanced business diversity, not one entity will have more than 1/3 in terms of ownership, in terms of representation by jurisdiction. I think their largest would be approximately 31% on a particular jurisdiction, but also a very, very good mix of electric and gas and what makes these 2 great companies, both combo utilities, even stronger on a combined entity.

And then the center of this page, and this is really the center of all we do certainly in NorthWestern I'll speak for our friends at Black Hills. We think about our customers and the substantial long-term value for our customers for bringing these 2 teams together who are very complementary, and we both provide excellent customer service to our customers and are great operators. And I will tell you the savings generated from putting these 2 companies together, ultimately improve to customers in future rate review proceedings. And so obviously, in this -- the time when people are thinking about affordability, our 2 companies are thinking about that certainly as we contemplate this merger on a going-forward basis.

Moving forward, in terms of a time line, I mentioned earlier that we filed joint applications for approval in 3 states, Montana, Nebraska and South Dakota. We did that in Q4, and we have hearings expected in the second quarter of '26 for those states. We also filed at FERC in Q4 of '25. We filed our S-4 joint proxy statement on January 30, and we have shareholder votes both scheduled for April 2. Beyond that, we've also started our integration planning effort, and we do expect or anticipated approvals and closing in the back half of 2026.

Moving forward, kind of thinking about large-load customers. And obviously, that leads you to discussions around data centers. On Page 18, I mentioned on the far right, you see the Montana large-load opportunities. first and foremost, say, I'm sure you've been reading about. They've had some issues in terms of property, in terms of their project. They have 2 sites, certainly that they're considering. And right now, they continue to -- they've got a favorable vote here recently to move forward, but they're still looking at the land concerns and they're dealing with those issues. They have land both inbuilt and in a condo that they're considering. So we continue to work through them as they work through those challenges. We have a development agreement, and we expect to get to an ESA here, hopefully, by the end of Q2 2026.

Also, we announced here recently Atlas Power. We've moved from an LOI to a development agreement, and they have been moving much, much quicker is good signs. I think would think from an off-taker or a customer from their perspective, they're getting ready to move forward. That's good news for us. with that development agreement. I would just tell you in the benefit of development agreements, these 2 entities now are putting skin in the game. Let's think of upwards of $500,000 of investment, if you will, for all the studies that are necessary that we need to complete this utility. And so skin in the game, if you will, for those 2 entities as we move forward. And I expect, as I moat at least one of those ESA to be completed for those 2 by the end of Q2 2026.

Quantica also making great progress. And hopefully, we'll see a development agreement from them relatively soon. As I think about the 2 states that we provide electric business off to the left, one thing I would say about Montana, we ultimately hope to serve these large low customers on a state jurisdictional basis. And when we have an ESA with one of these parties, we'd like to make a filing with the MPSC along with a large lot of tariff that protects customers, and we like to think we're going to do that here in the first half of 2026.

Regarding South Dakota, there is a significant indication of interest by data centers in the state. The benefit there is any new large customers that require incremental capacity. We have infrastructure riders that could help us with the that generation cost recovery. And also, the South Dakota PUC has an established process for large load customers with a deviated rater.

The last thing I'd say about South Dakota as we sit during this legislative session, we're waiting on sales tax reform in the state, which is something that is very, very important to data centers before they move forward in South Dakota. So watch that in the coming weeks.

The second slide I have on data center, Slide 19. The middle of that slide shows letter of intent and development agreements, obviously, moving from 2 letter of intents and the 1 development agreement to 1 letter of intent 2 development agreements shows progress there. We'd like to move all of those over into the ESA category to the right here relatively soon in 2026. To the far left, I would also talk about data center requests and high-level assessments. You may note that the Q count is actually down a little bit. there. And I think what happens, there's a lot of developers here and they get to a certain point. And if they can't move forward and fast enough, you can't find an offtaker or a customer, that count can reduce, not necessarily surprised. I think from a high-level assessment, there are some in there we believe certainly can move into that middle category of [indiscernible] development agreement. So we're we're excited there. We do see some sales tax movement in South Dakota. I expect both of those Q counts to actually go up in 2026.

Moving forward on Colstrip, happy announce announced earlier that we closed those 2 portions of Colstrip and in addition to our owned 222 megawatts and -- we've added the Avista 222 that not only allowed us to achieve resource adequacy in Montana, but increased our ownership from 15% to 30%. But knowing that we have not as much control certainly has a 30% owner matter if we didn't have control of the facility as a whole. The incremental PG piece did 2 things for us. It moved us from 30% to 55%, giving us that ability to drive strategic direction for the overall facility, but also gave us the ability now to serve large load customers. And so both of those interests are closing this plant, those interests are operating well for us, and we're excited to have them in the fleet. I'll tell you what I think much sounder when cold weather does come to us in Montana and South Dakota.

One thing I'd just say real quickly about Avista and Puget. I think you're well aware we acquired both of those units for 0, which is a fantastic thing for our customers, certainly from an affordability and reliability standpoint. But we do need to cover our operating costs. in Montana. For the Avista portion, we filed a temporary PCAM tariff waiver with the MPSC in August, and that would be -- provide a near-term cost recovery that expected to largely offset the -- approximately $18 million of incremental annual operating costs. That waiver by the way, was temporarily granted in January 2026. So hopefully, we'll learn more about that waiver in '26, hopefully get full recovery for the full year of those operating costs at some point in the future.

From the Puget perspective, we signed a contract in October 2025 to sell that electricity through late 2027, think of when data centers could come on in the state. And that revenue, we -- from that contract is expected to largely offset the approximately $30 million of incremental annual operating costs resulting from the transfer. I think you're all well aware, we filed with FERC for cost base rates in October 2025, and we expect approval from that filing in the first quarter of 2026.

Lastly, the Northwestern value proposition slide, you might have noticed 2 changes on this slide. The first Crystal talked to is the 17% increasement in investment over on the right-hand side, up to $3.21 billion. Second is noting the dividend yield at the top of the page, you might recall that used to say 4% to 5% and I argue today, we're stayed approximately 4%. Keep that in mind as you think about our base plan on the left and our incremental opportunities there in the center. From a base plan, taking that dividend yield plus our 4% to 6% EPS growth, you're looking at an 8% to 10% total return just doing -- and I'd argue what utilities are typically doing from electric and gas distribution, transmission, supply investment.

This is a kind of bread-and-butter utility investment. And so even with that, thinking about an 8% to 10% total return and obviously, we were able to capture any data center growth, any FERC regional transmission, any incremental generating capacity, that return can certainly go over 10%.

And so with that, I'm going to -- from a conclusion perspective, I think you've seen this conclusion slide for many years. I'm just going to turn it over for Q&A.

[Operator Instructions] Your first question comes from the line of Shahriar Pourreza from Wells Fargo.

[indiscernible] for the update and great capital plan roll forward. My first question is, previously, you indicated that you filed a large load tariff in to expense cost for new data-centric loads. Can you update us on the timing and scope what's changed versus stakeholders should expect a solid tariff PS.

Yes. [indiscernible], you're cutting out a little bit, but I'll take that question. We had said we will file a large load tariff, but I would note that, that was tied to signing an ESA. So we want to go hand in hand to file a tariff with a specific contract. Part of that conversation, we have an existing GSI tariff today. We think we could serve customers off of that tariff, but you want to strengthen that tariff and certainly get ahead of this argument that data centers aren't paying their fair share, et cetera. We expect to file that once we have a signed ESA so that we can walk through the specific mechanics with the Montana Commission what that looks like and why indeed they pay their fair share and likely contribute broadly to the system benefit. So once we have a signed ESA, we will plan to file that large tariff inthinc with us.

Yes. And the only thing I'd answer that as I said in the presentation, there's an expectation we would do that by the end of the second quarter. And the reason being, that's when I expect an ESA to occur. And I would say that the tariff is ready to go. We're waiting for an ESA perspective.

Okay. Sounds good, hopefully, I'm much more audible now. Just for another follow-up on the merger, there's been focus on large low data across -- sorry, data center cost position. stakeholders need or want education, not just on the process. Can you give us an update on how the education plan to stakeholders to demonstrate no harm and affordability has been so far? That's it for me.

I think you're talking from a public process perspective. I think in -- where data centers have gotten quite a bit of attention as you're well aware, throughout the country. And I would argue in Montana, in the community of Butte, obviously, most of the discussion because [indiscernible] furthest along in the discussion there. And I think the Butte Server Bowl allowed a lot of conversation with the community ultimately voted 9 to 3 and 4 were letting say move forward. So I think I'd argue that the data centers are getting to be more vocal talking to the benefits. We utilities certainly have been supportive of that effort. And I think what we need to demonstrate -- all of us need to demonstrate is from a tariff perspective, and that's our plan and allow the MPSC to approve a tariff that we would put a tariff in front of them that's going to protect customers.

And I think when customers understand that, they're going to feel much, much better about it. Obviously, they're reading what's happening in other parts of the country, and how customers have been impacted by data centers, and it's easy to jump to conclusions. And so I think there's been a decent dialogue about this topic. Certainly, I and others have been out talking about it. But I'm not saying it's going to be easy either for data centers. But I think thus far, we're making good progress with [indiscernible] and Atlas and [indiscernible], as I know is out there talking about this as well. So we feel pretty good about where we're.

Your next question comes from the line of Aidan Kelly from JPMorgan.

Just wanted to touch on the load fund first, if I could. It seems like there's been a number of quarters in the past that we've been waiting for -- and Brian, you mentioned in your prepared remarks some friction on the landing considerations with SEBI perhaps going longer than expected. Do you see this issue kind of percolating to other prospective loads, such as Atlas and others? I mean just in general, like what do you think is needed to push these development agreements into the goal line at this time?

Yes. I think you've seen -- I'll take a bit of [indiscernible] here and myself. I think we're thinking at ESAs we at times were to hold up to getting these ESAs done, and we're ready to go from our perspective. And then unfortunately, for [indiscernible], they ran into this land issue. And obviously, they're working through that. So I think -- this is not just on the utilities to get these things done. In many cases, developers also need to find customers and before they're ready to sign ESA sometimes they need to have that done. It's much easier for hyperscalers, of course, who don't need to find customers. So I do think that Savis working awfully hard to get to an ESA Atlas, obviously, moving to a development agreement. The next step is to get to an ESA.

So I've seen it, it's taken a bit longer nationally for this process. And certainly, it's impacted us a bit here. But I'm also very confident in terms of where we sit with these 3 providers today are these potential data centers, I feel very good about where we ultimately will get to.

Got it. Makes sense. And then just turning to the growth outlook, if I could. I see you affirmed the 4 to 6 rate base CAGR post the South Dakota plant, which I believe, is directionally around maybe $300 million in CapEx. And then obviously, you mentioned in the remarks, it's perhaps like a 50% equity source. So I guess my question would be what do you see as the offsetting factors to that share dilution that kind of gives you the confidence of that reaffirmed 4% to 6% EPS CAGR?

Sure. The great thing about -- and we've talked about this, what are the incremental opportunities that total return, the incremental opportunities to the right side, the incremental generation in South Dakota, we recover cash during construction. There's a phase-in rate plan rider that allows us to recover AFUDC is great. It's accretive to earnings, but it isn't accretive to cash as we've talked about, how do you finance those things a long time. So the opportunity that presents itself with meeting the resource adequacy requirements to SVP, owning that generation here and building that facility, that's the right kind of incremental CapEx that we've looked to layer into our plan. We're excited to do that. That's certainly the kind of stuff that gives us confidence to maintain or even push upward on our earnings range while also expanding that in terms that makes sense. So that's where we've been pretty clear. That's the type of incremental CapEx we are looking for. That's the incremental to our base plan. So we'll fund that in a 50-50 kind of approach. Will recover cash during construction with the phase-in rate plan and then obviously, ultimately, see growth off of earnings out of that once it's in service. .

Your next question comes from the line of Nicholas Campanella from Bank of America.

I just wanted to kind of clarify on the overall like ESA strategy is also my prior understanding was that like the system is long. So you may not need for the first couple of deals, a dedicated framework to pay for the depreciation of the interest and what would be associated with new build, but just this ESA will inform how you propose an overall tariff for all of that in this upcoming first half year? Is that just the general strategy? I'm sorry to make you go back and repeat yourself?

Yes. I think as an example for how we want to make sure we're protecting customers. And I think we're -- the discussions we're having in data centers, they want to protect customers to the folks that we're certainly talking to. And so going hand in hand with them with an ESA and a tariff that is the plan and as is in the plan by the first half of '26.

And Nick, I would add on to that, just every data center site specific. Some of them, to your point, we are long generation, what is the transition needs, what is maybe some of them are not much CapEx. All of that -- we do have an existing tariff. I know we talked about that a year ago. We felt like we can serve customers under that. We do still today. As you know, the national narrative on data centers has changed a bit, and there's a lot of what I would call misinformation about what they can do to certainly help shoulder the cost of the grid and in fact, subsidize some of your other customers.

I think everywhere you're going to see commissions want to understand that better. We got feedback from the Montana Commission and we certainly want to be transparent with them and bring that forth so that you have a positive construct under which you're doing that. So while each one is unique, bringing something forth that demonstrates the value that a data center can have a large load facility can have on the grid and that they are indeed paying their fair share while we would be comfortable serving them under our existing tariffs, I think there's also a lot of value to making sure your regulators are understanding that. And of course, then the public sentiment around that maintain positive.

Yes. One thing on that, too, Crystal -- the thought for me. I think this issue of protecting customers. I think there's been confusion around why the Puget portion was put into a FERC regulated entity. Our intent here is actually protect customers. The need here really for the Puget piece, we needed it to get control of the facility. But from a an energy perspective, we certainly didn't need it until the 2027 time table. So instead of and posing $30 million of costs on our existing customers, we found any means to deal with that and protect customers while that's on a FERC regulated entity. And if our hope is, as I mentioned earlier, ultimately to move that into a state regulated entity when we have large load customers we can serve through that. And so that is ultimate we're trying to do. We'd love to see everything on a state-regulated basis, but we do want to serve large loan customers in any way that is best to serve our customers today.

Okay. appreciate it. And then maybe just going back to the financing plan quick and the prepared. You just kind of mentioned the 13% FFO debt is all incremental CapEx at this point going to require some equity now? And just can you talk a little bit about if these ESAs materialize and you get the slow on the system, how that changes the equation on the financing for you guys?

Sure. We've said repeatedly that we size our base capital plan based off our cash flow availability and to hit our credit quality metrics. Obviously, I mentioned 2025. The key drivers there are falling below the 14% FFO is lack of cash, and that comes from the very mild weather and the margins we would have expected to have and then also material under collection and the Montana supply tracker, I think that's around $80 million. So we expect that to come back in 2026. But we're always planning our capital plan to maintain a solid balance sheet and have credit quality. So your question of what happens with incremental capital? And again, as I alluded to the Aberdeen Generating Station, we recovered cash construction of that. If you think about the ramp period of any data center and incremental capital that would be required there, you'd have a very similar funding mechanism that you see cash during construction, and that's the kind of stuff that's accretive, and we certainly would look to issue equity for that kind of accretive growth.

So that's where we've had a dividing line all along is we will be very disciplined about our base capital plan, and that's a regulatory lag. That's 18 to 24 months off of putting that in the ground to recovery for that kind of stuff, we need ongoing cash flows to support that for stuff that drives growth as anything large load would, that's the type of stuff we'd look to maintain equity issuances where that makes sense. But again, nothing in '26 just to make sure I was clear.

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

My first question has to do with -- for the South Dakota plant, do you have a -- are you in the queue for turbine? And what would be the commercial operation date of that plant?

I'll start with the commercial operation date. We're looking -- first of all, we have a plant in construction now. I think you're speaking to the 131 megawatts, that's $300 million investment. We're already making an investment in '26 for turbines -- and so I'd say approximately 1/3 of that investment will be made in 2026. -- to get our turbines in place and the plant is expected to be completed in 2030.

Okay. And you're in the queue or you have -- if the terpene are lined up for that 2030 in-service date?

We're buying turbines. .

My next question has to do with if the endangerment finding is reversed at EPA, what is that -- does that change the potential investment in environmental upgrades at Colstrip? And can you also update us on where things stand in terms of environmental upgrades?

Yes. I think, obviously, we'll do whatever we need to, in essence, to keep [indiscernible] long as it's economic. And obviously, if we're forced to do something we think is not necessary. We would probably invest in a gas plant if we're required to do something sooner rather than later. It has always been our hope here with this investment in Colstrip. We can keep that plant open and operating through the depreciable life that we expected into the 2040 timetable. And again, hopefully, that technology possibly nuclear, possibly long-duration storage, whatever that is, to help us replace Colstrip with something that's cleaner. But if we're forced to do something sooner, either investing in environmental controls, if you will, or ultimately building a gas plant, we will do that, too. We need to serve our customers with Colstrip or its replacement. And so it's hard to answer that question today, Paul, until we see ultimately what's happening, but I have to say what we're expecting out of the administration is certainly helpful for our long-term plans for Colstrip at this point in time.

I would also just clarify our 5-year capital plan, we did roll in Colstrip related CapEx, but that's maintenance CapEx volatile I would refer to that -- there's no material environmental CapEx in that number. So if something changes over time, certainly, we talk about that at the time. We had talked about the mass ruling previously and how that might impact Colstrip, but we never had any numbers on our capital plan related to that.

And is there -- I mean, is there any update in terms of whether those rules will be voted on or applied by the EPA? Or for the time being, should we just assume that nothing is moving forward along those fronts -- along that front?

Yes, I think we're -- we've been expecting to hear something on this any day now. And I guess until we actually see what the rules say, I'll kind of hold off and how to respond to that.

And then lastly, any updates on the remaining portion of Colstrip ownership where the parties most likely will need to divest their ownership interest?

Well, we just grab these 2 pieces from Puget and Avista, that 592. We're extremely happy with those. We'd like to certainly understand how the commission looks at it and ultimately how things are working out with data centers. we're extremely happy with being able to get to 55% ownership, and I'll stop there.

Right. But I mean theoretically, how would those costs be picked up if the other owners were forced to exit?

Are you talking environmental costs that have to be applied?

Well, in other words, if the other partners are forced to exit the planned ownership because of state laws then what would happen to their share of the operating cost? Or would they -- I guess, would they still be on the hook for that? Or how would that work?

Yes. I think they would be in a tough spot. I'm guessing all of them are looking for means to exit other than Talent doesn't need to exit. But I'm sure they're talking to folks about.

Your next question comes from the line of [indiscernible].

I wanted to ask just quickly on merger state regulatory. We've seen a bit of a delay in South Dakota. I was curious if there's anything to be concerned about there. And in the Montana review, it looks like some of the interveners have made the claim that the application is in complete perhaps because there's not a benefits study that's in there maybe for other reasons. So do you feel comfortable with the Montana time line as it stands? Or might we also see a delay in Montana?

Sure. I'll take that one. So first, your question with regard to South Dakota and the time line there. South Dakota has a 6-month statute, which I would acknowledge as a bit of a quick shot clock on getting through all the process and procedure and making sure they're comfortable that we are working with staff on resetting a bit of an extension to that procedural schedule. I don't have any concerns there. They're asking the right questions and going through the right process. They just need a little bit more time and they would have been in front of both Nebraska and Montana. So we're working with them on resetting the procedural.

I still think that they'll likely in the end, be well ahead of Montana order, even with the revised procedural schedule. So no concern there. You've also seen it progressing in Montana and what I would say is a bit normal given the nature of the intervenors there and who they are. So we've responded to the motion there. So intervenor [indiscernible] to come in. And overall, again, exactly as we would expect the docket to progress. There's comments as to maybe commitments that we could make, what they'd like to see to better understand that. We do certainly recognize that in each of the jurisdictions we serve, not just the ones we're in a big part of your local commitment is your utility, and we want to make sure we work through that in the right source of way.

So I wouldn't say there's any concern on how those pockets are progressing the concerns expressed are, I think, typical for each of those intervenors. And the intervenor testimony, I think, paints the path towards the direction of the things they want to make sure are considered in an eventual outcome.

And as a follow-up on Montana, I believe you're going through this IRP process now as well. How does that, if at all, fit in to the review, maybe not necessarily review directly, but the timing of the review for the deal versus the review of the IRP. I believe the final draft is due in maybe a couple of months, but please correct me if I'm wrong.

Yes. The IRP is out and we had a chance to see. I don't anticipate there's any connection between the IRP and the merger process.

That concludes the question-and-answer session. I'll now turn the call over to Brian Bird for closing remarks.

Well, I think Crystal pointed out earlier on the call, we actually -- it was a really very, very good '25. I mean, obviously, we ran into some issues in terms of the rate review and I'll come there. But I remember the -- I think we need to think about the revenue requirement associated with that. That certainly continues to help us invest as those things we need to, to continue to provide good service to our customers. But if you think about our ability to certainly announce the merger and now the work we're doing with our friends at Black Hills to get that to goal line, think about our ability now to have Colstrip to be resource adequate in Montana and certainly in this age when people are certainly very, very concerned about reliability and affordability to feel much, much better about that in terms of how we serve our customers and also thinking about longer term, how can we continue to make the investments we have, but also earn the appropriate returns we have for our shareholders. And I think 2025 set us up very, very good for that on a going-forward basis.

And with that, I just want to thank all of you for your support of the company and your interest in what we're doing here at Northwestern. And we certainly want to thank everyone at NorthWestern for all the hard work in 2025 as well. So with that, I want to say thanks.

That concludes today's meeting. You may now disconnect.

Thank you for standing by. Welcome to the NorthWestern Energy Third Quarter 2025 Financial Results Webinar. [Operator Instructions]

I would now like to turn the conference over to Travis Meyer, Director of Corporate Development and Investor Relations Officer. You may begin.

Thank you, Perella, 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's results have been released, and our release is available on our website at northwesternenergy.com. We also released our 10-Q premarket 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'll direct you to the disclosures contained within our SEC filings and safe harbor provisions included on the second slide of 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, reconciliations and merger-related disclosures included in the appendix of the presentation. Webcast is being recorded. The archived replay will be available today shortly after the event and remain active for 1 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 Bird 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. We -- 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 we've been 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 MPSC for recovery of our operating costs associated with the Avista Colstrip 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, we'll be approximately a $300 million project, which is currently not included in our 5-year CapEx plan. And lastly, dividend declared during the quarter, 66% -- $0.66 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 GAAP 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 of '25 and also remind you that in the third quarter of 2024, we had a tax benefit.

Moving to Slide 9. From a year-to-date perspective, that leaves us at $2.22 from a GAAP basis compared to $2.34 last year. Again, on an adjusted basis, that's $2.41 in 2025 year-to-date compared to $2.27 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 the margin, again, I highlighted that, that was $0.52 of improvement. Of that $0.52, rate drove $0.35 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 PCCAM, and that is a detriment during the quarter as well as the effects of Montana property tax legislation that are also a detriment to us 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 of '24. Again, mild weather in this third quarter impacted us by about $0.05, and that's compared to, again, an add-back of $0.05 and add-back of $0.01 in the third quarter of 2024. Also in 2025, we've incurred $0.12 of merger-related costs. And then as I mentioned earlier, the 2024 results included an $0.11 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-to-date reinforces our confidence in delivering on the financial commitments that we've made, and we expect a final outcome in our Montana REIT 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 we -- our capital investment slide and forecast here remains unchanged from what you've seen from us before. Brian mentioned the opportunities, and we've talked many times about what might be incremental to our current plan, but the opportunity for incremental generation investment in South Dakota under the SPP 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 talk about our merger with Black Hills update in August 18 seems like a long time ago, but it was about 2 months ago. And in that short period of time, we, with our Black Hills friends have worked collectively to make 3 filings with each of the 3 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 and expect to release that in Q1 of 2026.

In terms of shareholder meetings, sometimes in Q2 or Q3, our respective companies would have 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 3 LOIs that we currently have with SEBI, Atlas and Quantica. I'll mention the development agreement with SEBI 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 MPSC 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 SEBI. 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 in the state have seen good progress in between legislative sessions on a sales tax exemption bill. You 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. And we have seen good progress here. From a data center request, we've moved 3 of those parties into a high-level assessment. As a matter of fact, of the LOIs, what we've done here recently of our 3 LOI parties, we've entered into a development agreement. What's that? We 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 2 LOIs, we could see development agreements with those other 2 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, Colstrip transaction overview. I just on 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 Avista portion provided resource adequacy for us in Montana. And it also brought our ownership interest in the Colstrip 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 Colstrip facility for us to protect our existing interest, 222 megawatts and the Avista interest in Colstrip. 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 Colstrip is 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 load customers. And primarily, that would be the Puget issue.

So one we think -- 2 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 PCCAM tariff waiver request with the MPSC. We did that in August that'll provide a near-term cost recovery mechanism that is expected to largely offset the $18 million of incremental incremental annual operating costs resulting from the transfer expected on that the first quarter of 2026. I think it's clear you understand with the historic test year in Montana, if we've not done this we would be at risk of not recovering our operating costs of that units, if you will, those incremental 222 megawatts until our next rate review.

And so this is a prudent means to try to make sure we protect their financial integrity and hopefully, we'll see a good outcome from the Montana Commission. I think they will respect the concept that we are buying incremental capacity to serve our customers at a 0 upfront cost. And all we're asking here is to get recovery of our operating costs and to a point where offsetting, if you will, sales from that unit to offset those at least to help 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 has 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 base 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, why FERC regulated and not MPSC regulated for that 370 megawatts, the Puget portion. While we've received comments through the MPSC that it 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 1/1/26. And so that's a reason enough to move things from a FERC-regulated -- 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. Well, 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.

And 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 2027. And ideally, this 370 megawatts, we will ultimately like to move that into our MPSC-regulated business sometime in 2027 and beyond -- 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 interest. As Crystal pointed out here earlier, we've been extremely busy. And I just want 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 handle Q&A.

Thank you, Brian. That was a good update. Prella, we'll open the lines for Q&A.

[Operator Instructions] Your first question comes from the line of Aidan Kelly with JPMorgan.

Yes. I just want to hone in on the data center front first. It looks like there was some activity in the request and 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 just on top of that, what sort of time line you might be able to kind of convert the high-level assessments into incremental LOIs?

They're great questions. I think the data center requests, the queue count there went up 1. But more importantly, we've -- net-net, we've increased the queue count in the high-level assessment by 3. 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 here relatively soon, that LOI box, if you will, or directly to a development agreement.

That's helpful to know. And then maybe just pivoting to South Dakota. I am also curious on time line there for getting approval of the gas plant. And then ultimately, how should we think about that kind of flowing into CapEx in the rate base?

I'll take that one. I think both MISO and SPP put out this summer an expedited resource adequacy study window. We submitted based off that study, a facility that would get us to resource adequate and meet the requirements by 2030. We've received feedback -- initial feedback from SPP that our -- 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 time frame.

[Operator Instructions] And I'm showing no further questions at this time. I would like to turn it back to Brian Bird for closing remarks.

Well, thank you so much. I just -- again, I want to reiterate the tremendous 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.

Thank you. And this concludes today's conference call. Thank you all for joining. You may now disconnect.