NorthWestern Energy Group, Inc. Q3 FY2021 Earnings Call

Good afternoon, and thanks for joining NorthWestern Corporation's financial results webcast for the third quarter 2021. My name is Travis Meyer. I'm the Director of Corporate Finance and Investor Relations Officer at NorthWestern. Joining us today to walk you through the results and provide an overall update are Bob Rowe, Chief Executive Officer; Brian Bird, President and Chief Operating Officer; Crystal Lail, Vice President and Chief Financial Officer. We also have other members of the management team with us today on the line as well to address your questions as appropriate. NorthWestern's results have been released and the release is available on our website at northwesternenergy.com. We've 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 in our SEC filings and safe harbor provisions included in the second slide of this presentation. Please note also, this presentation includes non-GAAP financial measures. Please see the non-GAAP disclosures, definitions and reconciliations also included in the presentation. With that, I'll hand the presentation over to NorthWestern CEO, Bob Rowe.

Thank you very much. Well, we just concluded a very productive Board meeting here in Helena, Montana, the Queen City of the Rockies on the shores of the Missouri River, with two of our dams in the Montana hydro system nearby. We concluded the meeting with just a great discussion with Governor Gianforte and his energy advisor. Governor Gianforte talked about the exciting things he's doing to grow the Montana economy, the results seen so far, and how important our role is as the provider of the state's critical infrastructure and essential service. Our Board was just delighted that the governor spent an hour with us. It was a great conclusion to our meeting. Net income for the third quarter increased $5.7 million as compared to the same period last year. Diluted EPS increased $0.10 as compared to the same period in 2020. After adjusting for weather and a noncash liability adjustment, non-GAAP adjusted EPS increased $0.06 as compared to the same period last year. The Board declared a quarterly dividend of $0.62 per share, payable December 31 to shareholders of record on December 15. During the quarter, we issued just over 1 million shares of our common stock under our equity distribution agreement at an average price of $63.13 for net proceeds of $64.8 million. We had $121 million net proceeds received in total under the announced $200 million program. And with that, I will turn it over to our Chief Financial Officer, Crystal Lail.

Thank you, Bob. And as Bob indicated, there was another solid quarter for us, in line with our expectations with net income of $35.2 million compared with $29.5 million in the prior quarter, which represents a $5.7 million or 19.3% improvement with diluted earnings per share of $0.68 versus $0.58 in the prior quarter. With that, I'll take you to Slide 5 to give you a bit more color from a gross margin perspective. $227.3 million as compared with $212.6 million in the prior quarter, which is an improvement of $14.7 million or 6.9%. Of that, the drivers are a continuation of what we spoke about in Q2 with transmission revenue being higher by $10.1 million. That really reflects market conditions where those are using our lines to transmit power, and it’s a reflection of both higher loads and rates with the continuing warm and dry conditions to both the west and south of us. The other thing is solid retail volumes as well with $8.4 million of improvement at that line. That reflects both weather; in particular, July was very warm in our service territories in Montana and South Dakota, along with customer growth and improved residential and commercial loads for the quarter. Those were offset a bit by, one, the 10% sharing in our Montana supply recovery mechanism, which was a $2.1 million detriment. Again, we just spoke about the conditions of the summer with hot and dry weather. With that, power prices were higher, and we took a charge of $2.1 million during the quarter, reflecting again that 10% sharing in our mechanism in Montana. We also had a $1.3 million detriment related to a queue-up adjustment that we discussed in Q2, which is really a mark-to-market adjustment of that position. With that, the next slide shows you weather. I've already alluded to the conditions driving our margin improvement and the ongoing pattern relating to transmission. With that, we estimate favorable weather in Q3 resulted in a $3.4 million pretax benefit as compared to normal conditions, and a $4 million pretax benefit as compared to Q3 2020, as weather was not favorable in that quarter. Slide 7 gives you more detail on our operating expenses for the quarter. Operating, general, and administrative expenses were $80.9 million, compared with $73.3 million in the prior year, which is an increase of $7.6 million. I would highlight a couple of items; and again, continue things from what we discussed with you in Q2, with $3.3 million of higher employee benefit costs, which cover both compensation and medical costs, seeing a bit of a rebound in that trend from the prior quarter. We also have higher technology implementation and maintenance costs of $1.8 million, and $1.3 million related to generation maintenance. Additionally, we took a charge related to the initial preliminary costs associated with the Aberdeen facility that we had proposed to construct during the quarter, and we'll talk about that later as to not moving forward with the facility at that location. Those were offset, in part, by lower uncollectible accounts or bad debt expense. You've seen that trend throughout this year as you think about the previous year, which was a COVID-impacted period, compared to this year as we resume to normal uncollectible accounts. Overall, that's a $5 million change in OG&A that falls to the bottom line as an increase there. I would also mention property and other taxes, $43.6 million compared to $45.3 million, which is a decrease, driven a bit by lower valuation in Montana while we still have higher plant investments. With that, I'll move to the next page, Slide 8. Operating income of $55.7 million compared with $49.7 million in 2020, showing a $6 million improvement or 12.1%. Again, that's thematically overall margin improvement offset by higher operating costs. Improvement is also seen in interest expense and other income. Those favorables are really driven by the debt and equity portion of AFUDC. Moving to Slide 9. Cash flow is continuing our themes here, you’ll see that our operating cash flows are significantly lower than the prior period. We talked about these in Q2, having been impacted primarily by supply costs. That trend continued while we're collecting some of the gas costs that we incurred in the first quarter of 2021. We did continue to see an under-recovery of electric supply costs, and you see that impact reflected in a $106.9 million increase overall year-to-date in electric supply or overall energy supply costs, with the breakout at the bottom between electric and natural gas. From a quarter perspective, that’s about a $20 million continuing trend as we think about it year-to-date. Slide 10, the non-GAAP earnings slide. I'll point you to a couple of things here. Again, we've already talked about the ongoing impact of favorable weather, and you’ll see for the quarter, $0.05 of favorable weather that we've removed; that compares to $0.01 of unfavorable weather in the prior quarter. The other item I would mention is that the mark-to-market as the QF liability adjustment was $0.02. So, when you look at the quarter, $0.68 on a diluted EPS basis adjusted to $0.65 on a non-GAAP basis compared to the prior period of $0.58 of earnings adjusted to $0.59. So that’s $0.65 on a non-GAAP basis compared to $0.59, again driven by margin improvement offset by higher operating costs. Slide 11, I would mention that the quarter was consistent with our expectations. I'll remind you that in Q2, we narrowed our guidance a bit. We had a wide range as seen here of $0.20. We narrowed that down to $0.15 and have reaffirmed our guidance for 2021 at $3.43 to $3.58 per diluted share. At Q2, we also discussed that we expect proceeds of $200 million in 2021 from our equity offering driven by higher capital, but also remind you that we had delayed equity from 2020. In 2021, we are executing on that. We are on track for $450 million of capital in 2021, which is a higher number than we've seen in prior years. So with that, we expect to stay consistent with our guidance for 2021. And then broadly, we're close to EEI here in a couple of weeks. With that, we're looking forward to discussing our plans in 2022, including both guidance, capital program and also where we will be going from an equity need perspective. So Bob, back to you.

Crystal, it sounded like you were selling tickets to EEI. Good job. A couple of regulatory items. First, concerning the power cost credit adjustment mechanism, we requested approval to increase the base forecast given that the existing PCCAM really is energy-driven, not capacity-driven. We implemented an interim adjustment of about $17 million. Pardon me, I lost my place here. Anyway, we implemented the interim subsequently; then the Consumer Council filed a motion arguing that the PCCAM can only be adjusted in a general rate case. We were disappointed that the Commission granted that motion to dismiss. However, we have not seen a written order. When we do see that, we will evaluate and certainly have the opportunity to request reconsideration. Our view is that under the tariff, the PCCAM base may be reset outside of a rate case. Second, concerning our decoupling mechanism. As you know, we requested that it be suspended early on in COVID because the disparate direction of the residential and C&I sector highlighted that the mechanism was a mismatch to its intended purpose, and the Commission voted to grant our request to suspend. We consider that a real positive. The Consumer Council had requested reconsideration, and that was denied. So that’s a very good outcome. Finally, I know we'll come back and talk about this. On May 19, we filed a request for approval of three capacity resources, including our Laurel plant. We withdrew that request simply to manage the supply chain issues, and we're very much going ahead with the Laurel plant. Brian will come back and talk about that. A couple of other regulatory matters that are below the radar: FERC has initiated a routine audit covering years 2018 to present. We've responded to quite a few data requests. We haven't yet received a report, but that is expected within the next six months. We can't really speak to the outcome of that. A couple of weeks ago, WECC, Western Electricity Coordinating Council, initiated one of their audits; Brian, our Vice President for Transmission, Mike Cashell, and I all participated in the kickoff with our WECC audit team. We consider those to be constructive and important processes, and we're looking forward to the results. Moving on to the capital plan. As Crystal mentioned, we will be updating our plans and discussing that with you at EEI. As reflected here, we currently have a $2.1 billion overall capital plan over the next five years, which we expect to finance with cash flows from operations, first mortgage bonds, and equity issuances. As always, financing plans are subject to change. Two important highlights of this current plan: first, the plan includes about $60 million for a 30- to 40-megawatt flexible generating plant near Aberdeen, and we decided to discontinue our plans there due to significant increases in estimated construction costs and the overall supply chain challenges. We will continue to monitor our customers' needs in South Dakota and make appropriate decisions to address those. On the other hand, these projections do not include about $275 million of anticipated investment in the 175-megawatt generation facility to be constructed near Laurel. This overall level of capital is anticipated to result in an annualized rate base growth of 4% to 5%. With the acceleration of the Laurel project and the discontinuation of the Aberdeen project, we anticipate providing an update at EEI coming up in just a few weeks. Now I'll turn it over to Chief Operating Officer, Brian Bird, for an update on the generation portfolio and to report our progress on ESG matters.

Thanks, Bob. As Bob pointed out, we withdrew our filing associated with the Laurel project, but we are certainly moving ahead with the project. In fact, we want to take advantage of the fixed-price contract and protect our customers from rising costs that everyone is seeing. We want to get moving as quickly as we can on the project in case unforeseen supply chain issues arise. In addition, the Beartooth Battery Contract, since the time period to build that facility is much shorter than the Laurel plant, we do plan to bring that in front of the Commission as a stand-alone preapproval filing. We plan to follow that relatively soon. Additionally, the Powerex contract, which will go into effect in early 2022, will provide protection to our customers during the coming winter season. Regarding South Dakota, we are constructing a 60-megawatt plant, and it's going relatively well. With COVID and some supply chain issues, it has been pushed out to early 2022, but we're excited about seeing that come online here soon. As we pointed out, as Bob mentioned, regarding the Aberdeen plant, we looked at the rising costs. We did not have an opportunity to lock in prices associated with that project. We're still in the development phase, negotiating those prices. But as we saw those prices increase, we collectively agreed with the South Dakota Commission that it was prudent to hold off on the project until we can see a more reasonable pricing landscape and possibly consider different alternatives down the road. Moving on to ESG, one of the big advantages of being a member of Nasdaq is they have services, one of which is OneReport. It's a tool that helps us track all our ESG-related information. We've used that tool in the first half of the year to record everything we can currently capture and loaded it into OneReport. We have disseminated that information to those who rate us from an ESG perspective. We also separated that into the release of our new webpage, where ESG is prominently featured. We're seeing some improvement in our scores and expect to see even more as evaluators continue their assessment of our information. With that, I'll turn it back to Bob.

Okay. And with that, we're ready for your questions.

Thank you, Bob and team. It looks like we have our first question in the queue from Ryan Greenwald at BofA. Ryan? Is your line unmuted?

Can you hear me?

Yes. Now we can.

Awesome. Can you talk a bit about the latest conversations with the rating agencies following the withdrawal of the pre-approval application and the PCAM order from the Commission? I know it sounds like we're going to get some more information at EEI here, but anything preliminary you can say just in terms of potential equity needs into '22 and the initial thoughts around timing and cadence, whether it be a block or another ATM?

Ryan, Crystal here. Thanks for the question. First, I'll take the first part of your question. We did speak with each of the rating agencies as we made the decision to move forward with the Laurel project and the importance of that, given, as Brian alluded to, having fixed-price contracts on the table, being able to progress quickly, and to execute on that from a customer perspective. I think the rating agencies understand the perspective of that side moving forward from a business side. We also understand the other piece of that is you're looking for us to get recovery in rates, and that will be at the forefront of our plans as we work with the Montana Commission to accomplish that. Regarding your question about '22, happy to talk about that at EEI, and I'm looking forward to it.

One footnote on the rating agencies: Just a couple of weeks ago, Moody's did an excellent presentation to the Montana Commission laying the foundation for what the rating agencies do, how they look specifically at utilities, and how they evaluate NorthWestern Energy. That was really well received by the Commission; a lot of good discussion. I think the presentation, at least the video, is available online. The South Dakota Commission is very interested in having a similar presentation. Of course, our view is the more regulators understand, the better for all.

Understood. And then can you help quantify the magnitude of the inflationary pressures you saw with Aberdeen before opting not to move forward with the project? Was the balance sheet a limiting factor at all, or were the concerns really just oriented around elevated rates with the higher costs?

No. I think we were seeing prices upwards of 50% higher than we originally saw. That’s why, based upon that news, we thought it made sense to sit down and chat; we collectively made a good decision, we believe. The balance sheet, certainly, we want to invest as much capital as we need, but that was not the determining factor for why we decided not to move forward.

Understood. And then maybe just lastly, I know you alluded earlier in terms of the fixed costs for Laurel here. But is there anything that's open in terms of that contract in terms of the $275 million that could be subject to price movement?

Not that I can think of, Ryan.

We'll take our next call from Jamieson, or as his friends call him, James Ward from Guggenheim. James?

You guys have tripled the mute, I think, here. Can you hear me now?

Now I can.

Yes.

The question on Aberdeen has already been asked and answered; a 50% increase is very clear. I understand that capital expenditures and how you plan to finance them will be part of the discussion at EEI. Will the 2022 EPS guidance be provided at the same time, or will it be released later?

Absolutely. We'll be talking about both '22 EPS guidance along with capital plans. Obviously, with things shifting with both Laurel accelerating and Aberdeen moving, we'll be updating capital, EPS, and all financing plans.

Beautiful.

So you've got to be there.

Well, certainly will be. The final question that I have is on Laurel; you mentioned in the release that towards the end of last week, there was unfortunately another lawsuit filed and noted the potential for that to delay construction. How should we think about the timing on when you could start construction, how this could impact financing, etc.?

Well, I will say a couple of things and turn it over to our COO. Obviously, we were disappointed by the litigation. It seemed to be untimely concerning the administrative process followed. We were encouraged to hear today from the Governor that we will be side by side with the department in defending the lawsuit. But obviously, this is Monday. We've received that just several days ago, so our legal team is evaluating. Brian?

Yes. What I would add is the biggest time factor at this point in time is getting the engines manufactured. From a site preparation standpoint and permitting, there are certain things that we're working on, and we'll continue to work on during this process. But it's the engines that will take time. I think there will be a lot of time that can transpire on the lawsuit that we can be working on some other aspects.

Got you. It sounds like you have some great support there, which is encouraging to hear. My last question is regarding the construction engines. Where will that be happening? Some of the RICE units are from Europe; others come from different locations. Rather than making assumptions, I thought it would be best to ask directly. Where will that be taking place?

We have had the engines in the past for DGGS produced in Germany and shipped, and we'll be doing the same here for Laurel.

Beautiful. Look forward to seeing you at EEI.

Thanks, James. We'll take our next question from the line of Jonathan Reeder at Wells Fargo. Jonathan, don't forget to triple unmute.

All right. Can you hear me now?

Yes.

Yes.

Just kind of piggybacking on that last question. Just to be clear, you've given the contractors for Laurel the notice to proceed, right? We're definitely moving forward. It's not that you intend to do it sometime in the future when you have to execute it on the fixed price?

Yes. We're in the final stages on the final notice to proceed. I'll leave it at that.

Okay. And then not to front run the CapEx refresh, but it sounds like despite this environmental lawsuit, you are going to be rolling that Laurel plant into the forecast, even though that has the potential to derail it?

Absolutely.

Okay. Is it safe to assume these global supply chains and inflationary pressures are also impacting the base CapEx budget? Thus, if you want to accomplish the same amount of work as contemplated in the current budget, it might cost more to do so?

Yes, it’s a good question. In fact, that's a question that was raised by the Board yesterday. When we get the capital budget approved, I would say it in two ways: At the time, the capital budget was put together in July, we considered an increase in cost from an inflationary standpoint. But I'd argue that since July, we're seeing additional change. It's something that we certainly want to keep our eyes on. An offsetting factor to some increased costs is concerns about the supply chain, which could slow construction as well. We believe we'll end up in the range we initially planned.

You're saying where you planned initially from a dollar perspective, but not necessarily from a...

From a dollar perspective.

Okay. And then, I guess, in terms of although getting a certain amount of work actually done going forward, you'll have to look at what it's going to cost to get that done, balance that against your expected rate impacts and figure out what the sweet spot is?

Correct.

The other comment on supply chain is the Board management is paying a lot of attention to supply chain issues, both sides: cost and availability, as is the entire industry. We're participating in the industry effort to manage through this. Certainly, the challenges don't seem transitory in the sense that they will evaporate in a period of weeks or months.

And I think just to be a bit more clear from my perspective, obviously, the supply chain issues and other issues that could cause work to slow are more about pushing projects out into the future, rather than cutting them altogether.

Got it. That makes sense. I was thinking of a follow-up question, but I lost my train of thought. Just a quick question: was the $2.7 million pretax reversal of the previously written off uncollectible accounts expected in the '21 guidance, or was it an unexpected benefit?

I would say that was within line with our expectations.

Thanks, Jonathan. I think our Monday morning call has received a question from the queue. The last four digits are 3425.

Guys, can you hear me?

Yes, we can. Who do we have?

This is Eric Peterson from Millennium. Just real quick on the project up in Aberdeen. Can you give us any flavor on whether the capacity need will still be there in the next iteration of the IRP next year? And then...

Absolutely. Yes, if you have another question, I'll pause and let you continue.

Okay. Yes. Just separately, was that charge-off adjusted out in your non-GAAP earnings this quarter?

No, I will let the CFO answer that question. I will take the first question. I think the capacity need still exists in South Dakota. We will continue to manage that and use other means to close that gap in the short term and evaluate our longer-term plans. Understanding the future impact of pricing, we will return at some point for the next IRP to make a decision.

And Eric, this is Crystal. The second part of your question: Was the charge-off related to those initial costs at Aberdeen non-GAAP-ed out? It was not. It is in our earnings.

Looks like we have one more question in the queue that we're trying to get through here. We'll see if this works. It's from the line of Matt Davis, I believe. Matt, we just enabled you to speak if you're able to...

Guys, can you hear me?

Yes, we can.

Perfect.

I have a question regarding the Aberdeen project. I understand that the pricing has increased by about 50%. Considering the current trends in the energy market and the capacity market in your region, given the significant costs, and since it's anticipated that the project will commence in 2024, why make the decision to proceed now? Additionally, is the 50% rise in project costs sufficient to counterbalance the trends in the energy and capacity markets?

Yes. I think the main point is that when we meet with the Commission, we want to give them advance notice. If we decide to proceed with this project now, this is what we anticipate. We discussed alternatives, and we all agreed it probably makes more sense to wait. We noted that there are definitely other options we can explore in the short term, and we plan to review those in the next Integrated Resource Plan. You might recall that the Aberdeen project was not initially included in our first plan, but we believed we could move forward with it quickly. We were definitely planning to go in that direction. However, the productive conversations we have with the Commission led us to the shared decision not to proceed.

And then just one other question. In terms of thinking about the moving pieces around the capital program, I get that your base plan probably has some inflationary measures. But is it just as simple as thinking about putting in Laurel and subtracting out Aberdeen? Or are there other pieces to consider?

We'll be discussing the updated capital plan in great detail at EEI. We're honestly excited about the good and important work ahead of us. So it's not a simple matter of trading out one for one.

Thanks, Matt. It looks like we have one more question in the queue from Andy Levi. Andy, we're opening your line.

Unmute. Okay. Did that work?

That worked.

Okay. So just two questions. First, just on natural gas in general. If I remember correctly, you guys made several acquisitions on the natural gas side as far as resources, is that correct?

Correct.

And are those still flowing gas? Are those still producing gas?

Yes.

Okay. And could you explain how significant that is as far as helping you this winter on supply and price-wise?

I'll say a couple of things and turn it over to Brian, our COO. In Montana, in particular, think about the integrated system that has some owned supply, with a lot of storage and transmission at both ends of the system. That gives us flexibility in terms of bringing gas in at several points on the system, purchasing and storing gas in the off-season when prices are relatively more attractive, and moving the gas around the system. This puts us in, I think, a much better position than if we were simply a local delivery system. So that's a real positive.

Yes. I would say two things. First of all, we thought that buying gas reserves made sense. Some rules were changed at the Commission, making it difficult for us to do more of that. We would like to have done more, particularly for events like this with higher prices. I would say that about 10% to 15% of that purchased gas is available to us right now. The storage in our system allows us to fill it up and save it for peak periods in the winter season, which accounts for about 50% of the gas that we use. So that provides a nice advantage to our system.

When you say 10% to 15%, that's your total supply, not what you're using from the reserves that you have, is that correct?

Total supply. Total supply, Andy.

Right. Okay. It's been a while since we discussed this. What is the total amount of reserves you have or produce on an annual basis?

Andy, years ago, we used to have those slides in our deck, but we're talking about it.

Okay. Okay. That's fine. We can discuss at EEI. And then I have a bigger picture question about that. I understand it's a rate base project; at the same time, you need equity, and obviously, equity affects rates and the customers as well. Have you ever thought of monetizing those assets in lieu of doing equity?

That would be a no.

Okay. Fair enough. Stuff that pops in my head.

Yes. It's good. We always appreciate your ideas.

Okay. Well, some people do. The last question I have is again about the amount of equity you need, not the actual dollar amount, but your thoughts on the ATM affecting your stock price relatively. What do you think about that compared to someone like me or others buying shares from you all at once to relieve some pressure off the stock since it doesn’t trade that much volume? It’s the same question I ask every quarter.

Andy, we appreciate your resounding interest in our stock. We think it's a good holding, too. We hear you on the comments on technical execution; would be the only thing I had to say about that. We hear you.

I'll help you out, Andy. Just to clarify your previous question: You asked the amount of reserves, and if my math serves me right, I think it’s about 3 Bcf.

Okay. That's great, guys. I'll see you guys soon in Florida. I look forward to seeing you in person. Can you hear me?

Yes.

Yes. Thank you. Looking forward to it. Take care. Be safe.

It looks like we have another call coming in from the line of Paul Patterson. Paul, we're opening up your line now.

Can you hear me?

Yes.

Okay. My question is basically with the Aberdeen increase of 50%, it sounds a little like hyperinflation. Was there any specific driver or drivers? Or can you give a little more color on it? I apologize if I missed it.

No, I didn't give any specific drivers. I'm thinking about the total cost, and it wasn't just one component. But from a total cost perspective, it was upwards of a 50% increase, all-inclusive.

Okay. So it's just everything just came together? Is that it? It just seems so big.

Yes, it does.

All right. With that, I think we have now exhausted our queue. I'll hand it back to Bob for a close.

Okay. Thank you all for your interest and a very good discussion. The theme here is we're all going to have lots to talk about at EEI. Looking forward to seeing many of you in person and some of you probably online. Take care. Be safe.