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NorthWestern Corp
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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. [Operator Instructions]
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, Queen City of the Rockies on the shores of the Missouri River with 2 of our dams in the Montana hydro system nearby. We concluded the meeting with just a great discussion with Governor Gianforte and his energy adviser. And Gianforte -- 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 that was 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, 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 $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. That's an improvement of $14.7 million or 6.9%. Of that, the drivers really 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, $8.4 million of improvement at that line. That reflects both weather, in particular, July was awfully warm in our service territories in Montana and South Dakota, along with customer growth and then continued both residential and improved commercial loads for the quarter. Those were offset a bit by, one, the 10% sharing in our Montana supply recovery mechanism. That's 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 queue-up adjustment that we have discussed in Q2, and that's really a mark-to-market of that position.
With that, the next slide shows you weather. Again, I've already alluded to the conditions driving our margin improvement and ongoing [ fact pattern ] as it relates to transmission. With that, we estimate favorable weather in Q3 resulted in a $3.4 million pretax benefit as compared to normal and then a $4 million pretax benefit as compared to Q3 2020 as weather was not favorable in that quarter.
Slide 7 gives you a bit more detail on our operating expenses for the quarter. Operating, general and administrative expenses were $80.9 million as compared with $73.3 million in the prior year. That's an increase of $7.6 million. I would call out a couple of items and again, continuing things from what we discussed with you at Q2, which is $3.3 million of higher employee benefit costs that covers both compensation and medical costs, seeing a bit of a rebound in that trend from the prior quarter, also higher technology implementation and maintenance costs of $1.8 million, $1.3 million related to generation maintenance.
And then we also 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 a little bit later as to not moving forward with the facility at that location. Those were offset, in part, a bit by lower, uncollectible accounts or bad debt expense. You've seen that trend throughout this year as you think about the prior year, COVID-impacted period, to this year, resuming to normal, uncollectible accounts. Overall, that's a $5 million change in OG&A that falls to the bottom line of an increase there.
I would also mention property and other taxes, $43.6 million compared to $45.3 million. That is a decrease, and that is 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 as compared with $49.7 million in 2020. That's a $6 million improvement or 12.1%. Again, that's thematically overall margin improvement offset by a bit higher operating costs. I would also mention some improvement 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, again. And continuing our themes here, you'll see that our operating cash flows are significantly lower than the prior period. We talked about those 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 under recovery of electric supply costs and you see that impact reflected in $106.9 million increase overall year-to-date in electric supply or overall energy supply costs, and you can see 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 would point you to a couple of things here. Again, we've already talked about the impact ongoing 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 here is, again, that mark-to-market as the QF liability adjustment there 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 $0.65 on a non-GAAP basis compared to $0.59, again driven by margin improvement offset by some higher operating costs.
Slide 11, I would mention that the quarter again was in line with our expectations. I'll remind you that in Q2, we narrowed in 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 '21 at $3.43 to $3.58 per diluted share. At Q2, we also discussed that we expect proceeds of $200 million in '21 from our equity offering, and that's driven by higher capital. But also remind you, we had delayed equity from 2020. And in '21 are executing on that. We are on track for $450 million of capital in 2021, which is a higher number than we've been at in prior years. So with that, expect to stay consistent with our guidance for 2021. And then broadly, we're close to EEI here in a couple of weeks. And with that, we're looking forward to discussing with you 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 had requested -- we requested approval to increase the base forecast given that the existing PCCAM really is energy-driven, not capacity driven. We implemented an interim and -- of about $17 million -- [ lost my place here ], pardon me. Anyway, so 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, that be suspended early on in COVID as the disparate direction of the residential and C&I sector is really 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.
And then finally, I know we'll come back and talk about this. On May 19, we had filed a request for approval of 3 capacity resources, including our Laurel plant. And 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 really below the radar. FERC has initiated a routine audit covering years 2018 to present. We've responded to quite a few data requests. Haven't yet received a report, but that is expected within the next 6 months. We can't really speak to the outcome of that.
And then just a couple of weeks ago, WECC, Western Electricity Coordinating Council, initiated one of their audits. Brian and 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 there.
And then moving on to the to the capital plan. As Crystal mentioned, we will be updating our plans and discussing that with you at EEI. But as is reflected here, we currently have a $2.1 billion overall capital plan over the next 5 years, which we expect to finance with cash flows from operations, first mortgage bonds and equity issuances. Then as always, financing plans are subject to change.
Two important highlights to this current plan. First of all, the plan, as depicted here, does include about $60 million for 30- to 40-megawatt flexible generating plant near Aberdeen, and we decided to discontinue our plans there as a result of significant increases in estimated construction costs and the overall supply chain challenges. We will obviously 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. So this overall level of capital is anticipated to result in an annualized rate base growth of 4% to 5%. And with the acceleration of the Laurel project and the discontinuation of the Aberdeen project, we anticipate -- we do anticipate providing an update at EEI coming up in just a few weeks.
And now I'll turn it over to Chief Operating Officer, Brian Bird, for an update on the generation portfolio and also to report to our progress on ESG matters.
Thanks, Bob.
As Bob pointed out, obviously, 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 for rising costs that everyone is seeing. And also to get moving as quickly as we can in the project in case unforeseen -- the supply chain issues arise.
In addition to that, the Beartooth Battery Contract, since the time period to build that facility is much, much shorter than the Laurel plant, we do plan to bring that in front of the Commission as a stand-alone preapproval filing. And in fact, we plan to follow that relatively soon.
In addition to that, the Powerex contract, which will actually go in effect in early 2022, will be available to provide protection to our customers coming up in the coming winter season.
In regards to South Dakota, we are in construction of a 60-megawatt plant, and that's going relatively well. With COVID and some other supply chain issues, it has been pushed out to early '22, but we're excited about seeing that come online here relatively soon.
As we pointed out, as Bob pointed out, in terms of 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, and we were negotiating those prices. But as we saw those prices go up, we, I think, did the prudent thing and talked with the South Dakota Commission and talked about the expected increase in the price of that project and collectively agreed with folks. We discussed the matter, decided to put a hold on the project and come back at what we hope is a more reasonable pricing and then possibly with different alternatives at some time down the road.
Moving on to ESG. I guess I would say 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 we could track all of our ESG-related information. We've certainly used that tool in the first half of the year, recorded everything that we can capture today and loaded it into OneReport. We've now disseminated that information to those folks that rate us from an ESG perspective. And we also dovetail that into the release of our brand-new web page, which you'll see that ESG is very, very prominent in that. We're already seeing some improvement in some of our scores, and we expect to see a bit more as people continue their process of looking at our information.
And with that, I'll send it back to Bob.
Okay. And with that, we're ready for your questions.
Thank you, Bob and team. [Operator Instructions] It looks like we have our first question in the queue from Ryan Greenwald at BofA. Ryan? Ryan, is your line unmuted?
Can you hear me?
Yes. Now we can.
Awesome. Can you talk a bit about latest conversations with the rating agencies following withdrawal of the preapproval application and the PCCAM order out of 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 ratings 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 be able to execute on that from a customer perspective. I think the ratings agencies understand the perspective of the -- that side of it moving forward for our business side of it. We also understand the other piece of that is you're looking for us to get recovery in rates, and that will be [ chief of mind ] for us as to how we progress with the Montana Commission and work together to accomplish that. With your question with regard to '22, happy to talk about that at EEI and looking forward to it.
One footnote on the ratings agencies. Just a couple of weeks ago, Moody's did an excellent presentation to the Montana Commission of laying the foundation for what the ratings agencies do, how they look specifically at utilities and then 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. 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 inflationary pressures you guys saw with Aberdeen before opting not to move forward with the project? Was the balance sheet a limiting factor at all? Or was -- were the concerns really just oriented around elevated rates with the higher cost?
No. I think we were seeing prices upwards of 50% higher than we originally seen. And that's why based upon that news, it -- we thought it made sense to sit down and chat and collectively made a good decision, we believe. The balance sheet, certainly, obviously, we want to invest as much capital as we need, but that was not the factor as to 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 mutes, I think, here. Can you hear me now?
Now I can.
Yes.
So what -- the question on Aberdeen was already asked and answered, 50% higher is very clear. 2022 EPS guidance. I understand CapEx and presumably how you're going to finance that in some way, shape or form, will be part of the discussion at EEI. Will 2022 EPS guidance come at the same time? Or will that come 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 mentioned the potential for that to delay construction. How should we think about the timing on when you could start construction, how this could impact -- well, maybe I'll just start it there. How could this affect timing and then start date, end date, financing, etcetera?
Well, I will -- I'll say a couple of things and turn it over to our COO. Obviously, we were disappointed by the litigation. It seemed to be untimely in terms of 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. And from a site preparation standpoint and permitting, there are certain things that we're working on, we'll continue to work on during this process. But it's the engines that will take time. And so I think there will be a lot of time that can transpire, if you will, [ on the ] lawsuit that we can be working on some other things.
Got you. And it sounds like you've got some good allies there, which is very nice to hear. It -- and last question would be just on those -- the construction of those engines. Where would that be taking place? Some RICE units are European in origin, others come -- rather than just assuming, I figured I'd just ask the question. Where would the...
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.
Sure can, Jonathan.
Yes, it takes a little while for that unmute button to pop up, so apologies for that. Just kind of piggybacking on that last question. Just to be clear, you've given, I guess, the contractors for Laurel the notice to proceed then, right? We're definitely moving forward. It's not that you intend to do it before -- 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, I guess, that has the potential to derail it?
Absolutely.
Okay. Is it safe to assume these global supply chains and inflationary pressures are also impacting kind of 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. A matter of fact, the question that was raised by the Board yesterday. When we get the capital budget approved, I would say it in 2 ways. At the time, the capital budgets put together in July, and we considered increase in cost from an inflationary standpoint. But I'd argue that since July, even we're seeing a bit more change there. So it's something that we certainly want to keep our eyes on. I think what might be an offsetting factor to some increased cost is concerns about supply chain, concerns about other things that could slow construction, too. So we kind of felt that we probably would end up about where we had planned initially.
Okay. You're saying where you planned initially from a dollar perspective, but not necessarily from a...
From a dollar perspective. From a dollar perspective.
Okay. Okay. And then, I guess, in terms of though -- like 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, I guess, expected rate impacts and figure out what the sweet spot is there?
Correct.
Okay. And then…
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, and 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, things get -- because I don't think it's in essence of cutting projects as much as pushing projects out into the future.
Got you. No, that makes sense. And then -- I'm trying to think I had a follow-up on that, and I lost my train of thought. Just to -- kind of a housekeeping item. The $2.7 million pretax reversal of the previously written off uncollectible accounts, was that anticipated in the '21 guidance? Or was that kind of an upside surprise?
I would say that was within line with our expectations.
Thanks, Jonathan. And with that, we -- I think our Monday morning call has -- oh, we did just have one come into the queue here. It is the last 4 digits 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, I think -- I'm sorry, I didn't -- interrupt -- if you had a further question, I'll pause and let you keep going.
Okay. Yes. Just separately, was that charge-off adjusted out in your non-GAAP earnings this quarter?
No. I -- well, I'll let the CFO answer that question. I'll take the first question. I think the capacity need still exists in South Dakota. I think we just want -- we'll continue to manage that and use other means to close that gap in the short term, but continue to evaluate what we want to do longer term there. And again, understanding what pricing has done in the future, come back at some point in time, the next IRP to make a decision here.
And Eric, this is Crystal. The second part of your question is -- was the charge-off as 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 allowed you to speak if you're able to...
Guys, can you hear me?
Yes, we can.
Perfect.
So I just had a question on the Aberdeen project. I mean I understand that the pricing has gone up roughly 50%. But what -- based on what you're seeing in the energy market as well as in the capacity market in your region with the extreme cost as well as I believe the project was expected to come online sometime in 2024, so a little bit later in the planning horizon, why go ahead and make that decision now? And how do you -- and is the 50% increase in the project cost enough to kind of outweigh what you're seeing in the energy and capacity markets?
Yes. I think the main thing was when you sit down with the Commission and tell -- you want to give them a heads-up. If we move forward with this project at this point in time, this is what we expect to see. And we talked about alternatives, and then we collectively agreed it probably makes sense to wait. And we -- and asked if there's certainly other things we can do in the short term, we did say we had alternatives, and we would collectively look at that in the next IRP. If you might remember, we initially -- Aberdeen was something we didn't necessarily contemplate in the first IRP, but we thought from an expeditious standpoint, we could forge ahead with that. And we were certainly planning to head that direction. But again, the good dialogue we have with the Commission, it just was a collective decision to not move forward.
And then just one other one. 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 simply as thinking about at putting in Laurel and subtracting out Aberdeen? Or are there other pieces to the puzzle?
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 2 questions. First, just on natural gas in general. If I remember correctly, right, 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 flowing gas?
Yes.
Okay. And so could you just -- I have a couple of questions around that, but could you kind of just explain how significant that is as far as helping you this winter on supply and I mean that price-wise?
I'll say a couple of things and turn it over to, again, Brian, our COO. In Montana, in particular, think about the integrated system that does have some owned supply, that has a lot of storage and transmission and storage at both ends of the system. So that gives us flexibility in terms of bringing gas in at several points on the system, storing -- purchasing and storing gas in the off-season when prices are relatively more attractive than moving the gas around the system. So that puts us in, I think, a much better position than if we were simply a local delivery system. So that's a real positive.
Brian?
Yes. I would say 2 things. First of all, we thought that buying gas reserves made sense. The -- some rules were changed at the Commission that made it difficult for us to do more of that. We would like to have done more, particularly for events like this with higher prices. But I would say we're about 10% to 15% of that purchased gas is available to us at this point in time. And the nice thing Bob mentioned, the storage that we have in our system, we're able to use that storage and fill it up and save it for peak periods in the winter season, and that provides about 50% of the gas that we use. So we certainly -- that's a nice advantage of 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. And what -- and how -- I know it's been a while since we discussed this. What do you have as far as reserves? Like what's the total amount that you have or that you actually produce on an annual basis?
Andy, years ago, we used to have those slides in our deck, and we're talking about the...
Okay. Okay. Okay. So that's fine. You don't have it right now. That's fine. We can discuss at EEI. And then I have like a bigger picture question about that. I understand it's a rate base type of project -- product, okay? At the same time, you need equity and obviously, equity affects rates and affects the customer as well. Are there any thoughts -- and again, it's kind of paying its dividend this year, but also the price of gas has gone up so dramatically and the price for assets has gone up so dramatically that 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. And then the last question I have is just again around the amount of equity that you need, not the actual dollar amount. But just again, you're thinking on -- because I truly believe that the ATM has affected your stock price on a relative basis. And so any thoughts kind of around that versus just someone like myself or in -- other people just kind of buying the shares from you all at once and then taking that pressure off the stock since it doesn't trade that much volume? Same question I ask every quarter.
Crystal?
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, on your previous question. You asked the amount of Bcf and if my math serves me kind of on that 10% to 15%, I'd argue it's about 3 Bcf.
Okay. That's great, guys. I'll see -- okay. 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.
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.
We lost you now.
Can you hear me?
Barely.
Look, I'd sent you a text.
Got it. We can hear you now.
We can hear you.
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 just 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 particular component. But from a total cost perspective, it was upwards of 50% increase all in.
Okay. Okay. So it's just everything just pretty much 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. And the theme here is we're all going to have lots to talk about at EEI. So looking forward to seeing most of you, many of you in person and some of you probably online. Take care. Be safe.