Good afternoon, and thank you for joining NorthWestern Corporation's financial results webcast for the second quarter of 2021. My name is Travis Meyer. I'm the Director of Corporate Finance and Investor Relations Officer for NorthWestern. Joining us today to walk through the results and to provide an overall update are Bob Rowe, our 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 on the line with us to address questions as appropriate. All participant lines are currently muted. After the presentation, we have allowed time for a question- and- answer session. I will provide instructions for asking questions at that time.
However, if you intend to ask a question and are joining us by computer, please set your Zoom identity to your first and last name and firm name so we can call on you to let you know when your line is open. 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 will direct you to our disclosures contained in our SEC filings and the safe harbor provisions included on the second slide of this presentation. Please also note this presentation includes non-GAAP financial measures. Please see the non-GAAP disclosures, definitions, and reconciliations also included in this presentation today. The webcast is being recorded.
The archive replay of today's webcast will be available for one year, beginning at 6:00 P.M. Eastern today and can be found on our website at northwesternenergy.com under the Our Company, Investor Relations, Presentations and Webcast link. With that, I'll hand the presentation over to NorthWestern CEO, Bob Rowe.
Thank you, Travis. I've just finished a very good board meeting. This was our first board meeting together in a year and a half. The first meeting chaired by our new Board Chair, Dana Dykhouse, CEO of First PREMIER Bank. We've gotten a lot of work done in the system so far this year. I'm sure we'll come back and talk about some of that. Yesterday, we hit a new peak in our Montana balancing authority of over 1,909 MW. The balancing authority, of course, includes load in addition to our retail load. What was significant was that required over 1,000 MW of import. That was a hot day in July where our system was heavily dependent on imports. We've seen the same pattern in February with very cold temperatures.
It's just a reminder of the importance of our infrastructure, but also, again, our critical exposure to the regional capacity market and the importance of our plans to address that. End of sermon. Net income for the second quarter increased to $15.7 million as compared to the same period last year. Diluted EPS increased $0.29 as compared to the same period last year. After adjusting for weather differences and a non-cash liability, non-GAAP adjusted earnings per share increased $0.14 as compared to the same period last year. The board declared a quarterly dividend of $0.62 per share, payable on September 30th to shareholders of record as of September 15th. In April, we entered into an equity distribution agreement having an aggregate gross sales price of up to $200 million.
During the three months ending June 30th, we issued 879,309 shares of common stock at an average price of $64.91, for net proceeds of $56.3 million. In June, after two and a half years of very hard work, we joined the Western Energy Imbalance Market, this real time within-h our energy market will provide our Montana customers with economically efficient energy to resolve imbalances and variations in load and generations. It was a tremendous lift, made even more challenging by COVID. We heard from CAISO, the market administrator, that it was one of the smoothest entries that they have seen. Again, a lot of credit to our leadership and the people doing the work, and we look forward to realizing those benefits for our customers going forward. With that, I'll turn it over to Crystal Lail.
Thank you, Bob. As Bob mentioned, it is rather nice to sit in a room with my colleagues again and do meetings in person and begin to feel like we're resuming back to normal in some regards. With that, I'll take you to slide four with the P&L. As Bob mentioned, net income of $37.2 million as compared with $21.5 million last year in Q2, or a $15.7 million increase or 73%. Really a solid quarter in line with our expectations on a GAAP basis and driven by really improved gross margin, offset by a bit of higher operating costs. With regard to gross margin on slide five, gross margin of $230.3 million as compared with $208.3 million in the prior period, an increase of $22 million or 10.6%.
You look at the amount of that gross margin change that falls to the bottom line, that's approximately $20.2 million. I'll touch on multiple pieces of that here. First, with regard to the transmission piece of that, there's really two parts in that $9.1 million increase. That includes the release of a deferral of interim rates on our transmission rates related to the ultimate resolution through a compliance filing with the MPSC. I'll remind you all that our wholesale rates ultimately become a credit in our Montana rates retail side. That was the ultimate resolution of that.
Here in the second quarter, certainly contains some prior period amounts to that. The remainder of that increase of electric transmission is really driven by conditions in the market in the second quarter here, with both a combination of higher loads and rates with warm and dry weather, both to the south and west of us. The second piece here is the electric QF liability adjustment. This is something we typically adjust every year in Q2 and can be a bit noisy. I'll speak to this in a couple of parts too, as we did pull a piece out of this as a non-GAAP adjustment. The pieces that you're typically used to hearing about, one, we adjust for output and pricing. That was a little bit favorable this year. The offset to that is there is a contract in which there's price escalation on an annual basis.
That was unfavorable. The net-net of those two pieces is approximately $2.6 million of unfavorable impact, which offset the non-GAAP portion that we pulled out of $8.7 million, which was a revision to an estimate based off clarification of contract terms. As we don't expect that to recur, that's reflected as a non-GAAP item. As usual, there's a page in the exhibit that will give you more information on that and a clearer breakout than I probably just covered verbally for you. Again, $6.1 million on a GAAP basis, contribution to margin for the quarter. The next piece I'll speak on is electric retail volumes. We did experience overall warmer spring weather, and certainly a piece of that is driven by customer growth of the overall $5.6 million. With that, our residential usage and impact was about flat, and commercial was an improvement over prior year.
As we think about the second quarter of last year, certainly the lowest usage and most COVID impact that we saw comparatively. Certainly a rebound from that. As we think about the ultimate trends there and the trends on a use per customer basis, we continue to see what would be higher residential loads than normal, but not quite as high as they were in Q2 of 2020. We also continue to see lower commercial and industrial usage, but again, those are better than last year. A bit of a move in the trend, but the trend continues to be there, of a bit of a shift in use per customer. I'll speak to that a little bit more as we get into guidance for the rest of the year later. With that, I will turn to weather on slide six.
Weather, you'll see that April and May were a little bit cooler, made up for with warmer weather in June. I will highlight a couple of things. One, second quarter is always a bit of a shoulder quarter for us. Secondly, you'll see some pretty big percentages on the cooling degree days of 153% warmer and 66% warmer. The thing I would point you to is that's a relatively small amount of ultimate cooling degree days there. The ultimate impact of that in mostly again June, was a favorable weather impact of $2 million as we think about it compared to normal, and $1.5 million as compared to the same period in Q2 of 2020. Again, I'll address that a little bit more when we talk about our GAAP to non-GAAP adjustments. Slide seven gets into operating expenses.
Operating general administrative expenses were $77.1 million in the quarter as compared with $71.7 million in the prior period, or an increase of $5.4 million or 7.5%. Again, the amount that falls to the bottom line is approximately $3.2 million of that variance. There's a couple of things driving that. One, an increase of about $2 million related to generation maintenance at our electric facilities. In addition, about $1 million related to employee benefits. That's primarily driven by an increase in medical costs, also an $0.9 million increase related to implementation of technology and the associated maintenance costs with that as well. The thing I would note of those increases, a bit of an offset is our uncollectible accounts. We're certainly seeing ultimate collections from our customers come back in that regard, that offset those increases by approximately $2.8 million.
The other thing that I would note here is that we do expect headwinds in the back half of the year driving toward a more sustainable and normal amount of costs on an ongoing basis. From a property tax perspective, we're about flat to the prior year and $0.3 million increase, and then depreciation, a $2 million increase driven primarily on plant additions. With that, slide eight, operating income of $59.1 million as compared with $44.8 million the prior period or a $14.3 million, 31.9% increase. Again, driven primarily at the gross margin line. Interest expense and other income are immediately below that. Those both show a favorable net adjustment there with a decrease in interest expense and increase in other income. Both of those are driven by the debt and equity portions of AFUDC for a favorable impact on those quarter-over-quarter.
From an income tax perspective, I would highlight that we have income tax expense in the current period as compared to a benefit in the prior year or prior period. That's driven primarily by higher pre-tax income, partially offset by higher flow-through deductions. From a cash flow basis, you'll see on slide nine our cash flows for the six months ended 2021 compared to 2020. You'll see a decrease of $114.7 million. Most of that decrease occurred in Q1, and we talked about that then, I'll reiterate a couple of things. An $82.8 million increase in market purchases of supply. Again, most of that was experienced in Q1, though we do continue to see higher overall market prices of electricity out there. Most of that was a Q1 impact.
In addition, as we've talked about, we had a refund to our FERC customers of approximately $20.5 million. That has impacted cash flows as well during the period. Slide 10. I'll walk you through and just remind you of what we just discussed from a non-GAAP adjustment perspective. One, weather impact. You'll see the $2 million we discussed, as compared to normal with a $0.5 million in the prior period. Net over the period is $1.5 million. In addition, we talked about our QF liability adjustment and that we pulled out the piece of that that we don't expect to recur, which is a clarification of contract terms of approximately $8.7 million. Favorable adjustment there. With that, reducing GAAP net income to $29.2 million for the quarter or $0.56, as compared with $21.1 million in the prior quarter or $0.42 on a non-GAAP basis.
Slide 11 provides our earnings guidance for the year, and as I've mentioned, the quarter for us was in line with our expectations. One of the things that we had talked about before when we've announced 2021 earnings guidance is that we had a bit wider range of $0.20, which was $3.40-$3.60. With the quarter here and our performance so far halfway through the year, we've narrowed that in a bit to a $0.15 range of $3.43-$3.58. We've also updated a couple of assumptions that I would mention as key to how we think about the back half of the year, and there's still a lot of the year left to go.
One of the things is we are continuing to see the pattern, as I mentioned earlier from a usage perspective, of commercial industrial volumes being off from what we would consider normal and residential offsetting that a bit. We do expect that to continue in the back half of the year. The other thing that I mentioned is, again, while we've had a strong first half of the year, we do expect operating costs in the back part of the year to increase, and those would reflect a more sustainable level. We expect those pressures in the back part of the year as well. The other thing I certainly would highlight is that we've updated the diluted shares outstanding of approximately $51.8 million to $52 million. To increase that, i t was previously $51.5 million-$51.8 million.
The other thing that we've noted is that increased share count updates the reflection that we expect to issue the full $200 million of equity that we had indicated a need for previously. That does adjust that timing sooner than we had initially indicated. The thing I would comment on that is that's in response to certainly the need to support the growth that we are experiencing from the company's basis, and also certainly to support and maintain our credit ratings. I would also remind you that we are on track for the $450 million of CapEx spend in 2022. That compares to approximately $400 million in 2020. Oh, I should say 2021. I think I got maybe wrong. $450 million in 2021. I'm getting a year ahead already. Compared to $400 million in 2020.
In 2020, we did expect to do equity and ended up not doing that. That compares to more of a $300 million number from before that. The thing I would indicate in the sense of the amount of equity we expect to do this year is again, in support of our credit ratings, but also the amount of growth we have in front of us as a company. With that.
Thank you. I'll point out that year is the only number you've got wrong since you've been the CFO. Crystal and Travis and the whole finance department continue to do just great work. Touching lightly on some of the regulatory matters, we don't expect to file a general rate case in any of our three jurisdictions this year, which is still 2021. We have made several other important regulatory filings in our Montana jurisdiction. In April, we filed a request to delay implementing our fixed cost recovery mechanism pilot, that's the Montana version of decoupling, for another year until at least July of 2022, due to the continued uncertainties created by COVID. On June 29th, the Montana Commission did grant that delay. We have not seen a written order. We are, of course, eager to see that. We appreciate the workload of the Commission.
That was very much a positive. Also in April, we filed a request to approve an increase to the forward costs used in developing rates for the recovery of our electric power costs in Montana through the Power Costs and Credit Adjustment Mechanism, our friend the PCCAM. That would be approximately $17 million. This is really intended to better align the base costs in the PCCAM with the costs that our supply team is facing in the market and incurring on behalf of our customers. On June 29th, the commission did approve implementing interim rates reflecting the $17 million increase in that because it is an interim is, of course, subject to refund. There again, a written order is pending. In May, we filed a request to approve acquiring electric capacity resources that are critically important to address our customers' exposure at peak to the regional power market.
This was based on the 2020 RFP that we've been discussing with you for quite some time. Brian will come back and discuss that in much more detail. We've finally been able to fully wrap up the FERC rate case that was the parallel, the follow-on to our last Montana general electric rate case. We're pleased to have reached a settlement refunds there and have implemented the new rate structure, which we think will be a benefit all around. Crystal is doing a great job in her new role. Meanwhile, Brian has transitioned. He's replaced the consonant with a vowel in his title. I'll set up the capital plan just briefly, then turn it over to Brian to go into some of the details.
We always share this slide with you, and we do have a robust capital plan looking out a full five years into the future. As Crystal mentioned, we are on track to meet our capital plans for this year. It involves over $2 billion of total investment over the five-year period, financed with a combination of cash flows from operations, from mortgage bonds, and equity issuances. During the second quarter, as you know, we did initiate the $200 million ATM program, and we expect to issue the remainder of that this year in order to support our current capital program and protect our credit ratings. Capital investment in response to the Montana RFP and the supply resource investments would be incremental to these amounts. Of course, finance plans are subject to change depending on CapEx, regulatory outcomes, internal cash generation, and then market conditions.
The South Dakota resource investment is well underway, about $100 million. That is included in the 2021 through 2023 periods. We expect that this level of capital should result in annualized rate-based growth of 4%-5%. Again, the projects do not include the investments necessary to support the Laurel Generating Station. If approved by the commission, that should be an additional $250 million, excluding AFUDC, spread primarily over 2022 to 2023. In his new role as COO, Brian has been spending a lot of time in the field across all three states, making the rest of us very jealous and doing a great job working with our executive team and management in the operations area to really enhance the already high level of cooperation there.
As a result of that, we are poised to continue investing in and delivering our customers the highest possible level of service. Off to you.
Thanks, Bob. As Bob mentioned on the capital slide, we had a tremendous amount of investment. All areas of the operation are extremely busy in terms of this higher level of capital spend. We anticipate with Laurel coming online, ultimately enabled to make that investment to continue these high levels of capital investment. On slide 14, speaking to the generation portfolio in Montana, you remember back in May, we made our filing associated with to acquire electric capacity through resources identified in our January 2020 RFP. From that, two of those entrants, if you will, the Laurel Generating Station and the esVolta energy storage contract, we included in that filing. Laurel being 175 MW RICE units located in Laurel, Montana, which we intend to invest $250 million and is expected to be in commercial operation in late 2023, early 2024.
The 50-MW battery facility from esVolta to be located near Billings, and entering that through a 20-year agreement to fill the five-hour duration tier identified in the RFP. Not included in that filing, but should be included in our PCCAM, is the Powerex transaction, a five-year power purchase agreement for 100 MW of capacity and energy projects originating predominantly from hydro resources. Earlier this week, the MPSC concluded that the application met the minimum filing requirements. That starts the shot clock for 270 days of receipt of an adequate application. We hope, certainly near the end of this year, we'll have an outcome. Hopefully we can get going on the project at that point in time.
Moving over to South Dakota, our project in Huron, the Bob Glanzer Generating Station, is going along extremely well, and we expect to have it online by the end of this year. We plan to move forward with Aberdeen, and as Bob mentioned, the South Dakota capital already included in our capital plans. We expect to have the Aberdeen unit also online by the end of 2023, much like the Laurel Generating Station. Moving on to slide 15. We really took the first half of this year to go after those things from an ESG perspective that we haven't had appropriately disclosed. We worked extremely hard to tie that to the release of a brand-new webpage that we expect to have coming online within days.
Once that happens, it'll be much easier for investors and those folks from an ESG who rate us to actually find updated information. The total company effort to capture this information and record it. As a result, we're going to be able to provide new reporting, new reporting from a SASB perspective, from a TCFD. We'll have an AGA ESG Methane reporting template. All of those are being new. We'll have updated our EEI ESG Carbon reporting template. We're just going to have a plethora of sustainability statistics updated and expanded. We're really excited really for two reasons. The webpage is going to look great. You're going to see a very large focus on ESG. From our perspective, it's going to be very easy for the folks that rate us from an ESG perspective to capture that information.
From our perspective, better depict our scores on a going-forward basis. With that, I'll pass it back to Bob.
Great. Thank you, Crystal. Thank you, Brian. We are ready for questions.
Thanks, Bob. If you're joining us by computer today and would like to ask a question, please signal your intent by using the Raise Hand button that is typically found at the bottom of the toolbar, at the bottom of your screen. You can also simultaneously press Alt and Y on a PC or Option Y on a Mac to raise your hand. Please ensure that your microphone is unmuted if you're in the queue to ask a question. If you're dialed in by phone, you can press star nine to raise your hand and star six to unmute your line. Again, that's star nine to raise your hand, star six to unmute your line. We'll give it a few seconds to get our first question in the queue.
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Thank you for the reminder, Bob. Okay, we will take our first question from Ryan Greenwald at BofA Securities. Ryan, your line should be open. Please proceed.
Good afternoon, everyone.
Hey, Ryan. How are you?
Appreciate you taking our questions. Maybe first, how should we think about the puts and takes through the rest of the year here relative to the prior walk that you guys had previously included in the slide deck? You have this additional equity, but can you talk a bit about any other moving pieces here and what factors might be keeping the midpoint unchanged?
Crystal.
Sure, Ryan. I think a couple of things. One, the first half of the year is in line with our expectations for where we expect to be performing. The other thing we updated a bit is we do expect a bit of headwinds in the back part of the year with continued load trends, as I alluded to from a customer usage perspective of seeing lower commercial and industrial usage while admittedly better than the prior year, still not back to what we would call normal. Offset in part by improved residential usage, but again, not quite as good as it was last year. That's certainly a piece of it. The other headwinds I alluded to is on the operating side, and I think we've provided that walk as to where we expect operating expenses to be, from a full year basis. Again, 2020 wasn't normal.
2021, we're moving back toward what I think is a more sustainable level of O&M and G&A. I certainly expect an increase in the back half of the year there. While we don't give quarterly guidance, there's certainly not a, what I would call it, even spread across quarters there.
Got you. Was the transmission deferral expense anticipated?
Yes.
Maybe just lastly on the equity, how should we think about this in terms of ongoing from here outside of the additional generation into 2022? Does this kind of limit the equity needs in 2022?
I would say two things. Obviously, we're investing a lot of CapEx in the business, and we have a good problem to have there in the sense the amount of growth in front of us. The other thing I would say, just as you think about 2022, we've updated where we expect to be from a 2021 basis. As we get closer to 2022, obviously, we'll update you on our plans there, but certainly, always expect to be mindful of our credit ratings along with the growth in front of us.
Got it. Maybe just one more, if I may. In terms of financing the generation, any initial thoughts in terms of an ATM or equity block or how you're ultimately thinking about that?
You're ahead of us on technical execution there. I think our comment has been we'll be roughly 50/50. As we get closer to that, and obviously proceed with the approval docket, we'll have more to come on that.
Fair enough. Appreciate the time.
Thanks, Ryan. We will take our next call to the line of Jonathan Reeder at Wells Fargo. Jonathan, your line is open.
Hey. Good afternoon. Can you guys hear me okay?
Yep. Sure can.
Great. Maybe just piggybacking off of Ryan a little bit, regarding the decision to now issue all $200 million in 2021. Was this decision at all influenced by some of the positive drivers, in particular, the transmission strength, not the deferral portion, but just the strength in general, partly driven by the hot weather out West and maybe the thought that you could opportunistically strengthen your credit metrics a little more now without adversely impacting your ability to hit guidance?
I guess, Jonathan, I would answer your question in a couple of parts. One, the sense of the additional equity, as we had talked about coming out of Q1, we're on a negative outlook from Moody's perspective, so we're mindful of where we're going from a credit rating perspective. The other key factor certainly is the amount of CapEx and investment in the system at this point. Obviously, from a guidance perspective, I think we've talked to a bit of what we had from our performance through the first half of the year is in line with our expectations.
Okay. Regarding that PCCAM base request, do you have what your final base that you're going to be supporting? I know the interim was based on $156 million, the plan was to kind of update a final request off of forward power prices as of the end of June, I think. Do you know what that updated number is? Just trying to get a sense.
Yeah, I think the final number is $165 million for base.
$165 million. Okay, great. Thanks so much for taking my questions. Appreciate it.
Thanks, Jonathan. We will take our next call from the line of Brian Russo at Sidoti. Brian, your line should be open.
Yeah. Hi, good afternoon.
Brian.
Could you elaborate on the dynamics of the transmission margins outside of the interim rate? You mentioned hot and dry weather in the south and west of you. I would imagine that's continued into July. Does your guidance capture the transmission revenue potential upside above normal in July?
A couple of things I would say about that is obviously the conditions that drive that. There's long-term firm transmission, there's a short-term market, and that short-term market is more what's driven and day to day, that can be different. Certainly we've moved into a formula rate environment. We've captured that in our expectation for the remainder of the year. The thing I would just highlight at a high-level perspective is we've continued to highlight where we have margin headwinds. There may be puts and takes in there, but from a guidance perspective and nearing in that range, we expect that the performance through the first half of the year and where we expect to be in the back half of the year, obviously transmission is good news if that continues.
Great. In essence, third parties are utilizing your transmission to wheel power to the West where demand is needed.
Yes.
Mm-hmm. Okay.
The South.
Mm-hmm. Brian, you mentioned earlier that you were hopeful to have a Montana pre-approval decision by the end of the year. I think the clock is 270 days plus another 90 days, which would be a total of one year. I'm just curious, why the expectations for the end of the year, and why don't you think the Commission would take the full amount of time?
Well, in fairness, you're absolutely right. If you did the math, I'm focused on 270 days. The extra 90 days, of course, puts us a full year. I was eternal optimist, Brian. There's always an opportunity they could be done by the end of the year. You're right. If you actually do the shot clock from 270 days, you're going to be around the end of the first quarter.
Got it. On the second RFP that you alluded to in the press release during 2022, I would imagine you want to wait for this pre-approval process to be over. In terms of the size or components of the next RFP, would it be similar to the one that was just concluded?
I think the best thing to say at this point in time, like you said, you're absolutely right. Let's get Laurel approved and move forward, and I think we'll assess at that point in time our needs, and we'll size accordingly.
Okay, great. Just lastly, on the balance sheet, you have the 50%-55% debt to cap. Even with the equity issuance and the solid first half of 2021, the debt to cap is still at 53% or so. Are you targeting just the midpoint through the end of the year and going forward or are you targeting the lower end or the higher end?
I think I'll stick to my 50%- 55% range in that regard, Brian, but also just say that obviously we're focused on the FFO metrics that we would need to be at from a credit ratings perspective.
Okay, got it. Thank you.
Okay, we will take our next call from the line of Andrew Levi at HITE Hedge Capital . Andy, your line is open.
Can you hear me?
Sure can. Can you hear us? Andy?
Can you hear me?
Now we can, Andy.
Yeah. My phone is glitching. Hold on. Okay. Hello, everybody.
Hi, Andy.
Hope all is well. Good presentation. Couple questions. The first one is just on load, specifically commercial and I guess to a lesser degree, industrial. Again, we've only had a couple samples this quarter as companies reported, as I said, on the earlier side. We've seen quite a recovery in commercial loads in other parts of the country. Could you kind of just talk about that and why? Again, I understand that you said they have recovered, but this is going slower than others because some are at pre-pandemic levels. How much incremental load would it take to kind of get to pre-pandemic levels on the commercial and industrial side?
I think the thing I would just highlight there, Andy, is a couple of things. One, we did see improvement in commercial loads, certainly as you look at compared to the prior period, but not back to what we would term normal. I think if you look at the detail we have in either the appendix of the investor deck or in our materials, you would see that we're continuing to trend under what would be, if you think back to 2019 levels, what would be a more normal amount of commercial loads there. Certainly some improvement. I guess I started to say I won't give commentary, but I don't think it's obviously the prior year was shutdown related.
This year, I think if I had to weigh in, it's more workforce issue related and other factors in the economy, so different drivers. Again, we're seeing some improvement there, but not back to what we would call normal. On the residential side, again, you haven't heard from probably many utilities, but we continue to see strong residential usage, but not as strong as prior years. The thing that I think is indicative of that is that you kind of see flat residential revenues, even though we had a warmer quarter in certain ways. I think about it that way. We're continuing to monitor it, as I mentioned, from a guidance perspective, with the back half of the year, there's still quite a bit of uncertainty there as where those trends will go.
And just-
The color I would add to that is just that the three economies we serve are among the very strongest in the country. Just as Crystal said, we don't know everything that's going on. Very clearly, one of the challenges is a severe workforce constraint. I know that's occurring in other parts of the country, too. We have a number of communities we serve where the unemployment rate, rather, is actually slightly negative. That is a constraint on businesses getting back to full operation.
Yeah. We certainly saw improved commercial usage, right? While it's not back to what we would call normal, it's considerably better than it was last year.
If you kind of had the netted all out longer term, if you got back to a more commercial, and I guess on the industrial side, too, a more like pre-pandemic load and residential, probably is going to always be a little bit stronger than what it was pre-pandemic. Would that mean kind of like a neutral earnings outlook just relative to that? Would there be looking at the base upside, if you got back to a more normal situation?
I guess I would answer it this way is, we will see where, and I hate the term the new normal, but we will see where the new normal is. Ultimately, the other thing I would remind you of is we have solid customer growth in our service territory. Just from a customer count perspective, are seeing good indicators there, solid economy. All those things are certainly something I would look to as favorable indicators.
Okay. Kind of transitioning to the customer growth and also what you mentioned in your press release. I guess, you're saying by, I forget, I think it's 2025, maybe it's a little bit longer, the 700+ MW of needed incremental capacity? I'm assuming the $250 million of CapEx, that project, that's addressing some of the 700 MW, right? If I'm not mistaken. On top of that leaves 500+ MW needed. What type of customer growth are you assuming in that? I guess, is there upside to about 700 MW shortage? At the same time, if you kind of had the perfect world, because you got to kind of address what's best for the customer, what's best for your balance sheet, what you can do.
How many megawatts, if you would be able to win all of them, I'm not saying that's what you want to do. How many megawatts do you think you could reasonably do yourself if you were to fulfill that deficit?
Andy, I'll take that. I think I'm just going to go back to what I said earlier. From a longer-term basis, we're continuing to address our capacity needs, and there's still a lot of moving parts that we see in Montana and around us from a resource perspective. We'll give more clarity around that in our upcoming RFP, and then ultimately in our RFP that follows.
Okay, that's fair. When will that RFP I'm sorry, I missed it. When will that be final?
Our RFP is in sometime in 2022, as Brian mentioned earlier. The expectation that you would basically get an outcome on Laurel, that's probably, at the earliest then, be mid-2022.
Right. Okay. Got it. Then my last question is just around the equity. ATM versus, I mean, it's not a lot of equity that you need to do. I guess a lot, relative to how many shares you have outstanding, but as far as people like us putting up capital, it's really not a lot of capital, a lot of equity to dedicate to you guys. The ATM, you did about $56 million in the second quarter. I guess it could kind of be about the same in the third and fourth quarter, and ultimately, get that $200 million done. Why not come to us, stock's cheap, and just kind of get it done, even if it's at the end of the year, just kind of dribbling it out.
I've asked this question before, but I'm under the belief, and especially since there are a lot less hedge fund money around. There's plenty of long-only money around. The volumes are much lower than they traditionally have been. I think it affects your equity a little bit more doing the ATM. Again, has anything changed in that thought pattern? Obviously, I've asked you this question before.
Crystal will give you the CFO answer. What I will say is it sounds like you are very enthusiastic about supporting NorthWestern Energy stock, and we appreciate that very much.
With Bob's comment there, I would say the key piece here is we wanted to set your expectations for the amount of equity as to the rest of the year. With regard to the technical execution, we'll worry about that as we close out the year.
You have to push mute, unmute or whatever it is.
Okay, thank you. I've taken enough time just by getting in.
Thank you.
Thank you.
Have a good one. Goodbye.
Okay, we will take our next call from Matt Davis at Coann Capital . Matt, your line's open. Matt, you're not unmuted. You'll need to unmute your line.
Hey, guys. Can you hear me?
Yep.
Sure can.
Okay, thanks. Sorry about that. Good afternoon. Just a quick question. Maybe I'm missing something, but I just wanted to go back to the load commentary before with the improvement that you're seeing in margin. When I look at slide 21, it looks like the volumes, megawatt hours, were actually down period on period for the electric segment. Can you just reconcile that if I'm missing something, and how that circles with your commentary on the $5.6 million of upside year-over-year?
Getting to that page, give me just a second here. I think from a commentary perspective, you'll see that residential is roughly flat, right? That's a key piece of it there. The other piece that I would say is that commercial, you see certainly an improvement from the prior period, the offsetting headwind there is the industrial loads are off a little bit. Again, the key piece there between the megawatt hours and what you would see in our revenues is also a piece of what falls to the bottom line. The trend-wise, I think we're highlighting the right pieces for you, from a margin perspective, the ultimate impact there's certainly a retail volume improvement between those.
Okay. Thank you.
Thanks, Matt. We will take our next question from the line that ends in zero two three one. Your line should be open. Remember, star six to unmute your line.
Hello?
Yes.
Can you guys hear me?
We can now, yes.
Hi, this is Sophie Karp, KeyBanc. Thank you for taking my question.
Hey, Sophie.
Hey, I was just wondering, on transmission, there's a lot of conversations happening in the West right now about transmission planning, especially in, as it relates to California load, but others as well. As you think about your RFP next year or even beyond that, is there room for you to maybe add transmission into that thinking process? Thank you.
What I would say, and then I'll hand it off to Brian, is we are, and have always been, very deeply involved in all of the Western discussions around transmission. Most of those are relatively informal because this is not an organized market. Many of the most structured discussions around transmission come in the context of regional resource adequacy work being led by the Northwest Power Pool. As we look at how we're going to meet our Montana retail customers' needs, we're very aware of the constraints on our transmission system in terms of being able to import power, which is one of the reasons it's so important to have generation within our balancing authority. More generally, we've had a pretty active transmission investment program now certainly for the last decade within our service territory. That's transmission to serve our customers.
Beyond that, as transmission projects rise or fall in the West, that is certainly something that we want to stay close to and consistently have. Brian?
Yeah, Bob, I think you said spot on. All I would add is we're very concerned about both electric and gas transmission constraints. Obviously, there's an opportunity for us to invest in increasing transmission on gas or electric. We're more than happy to do that to actually access ourselves to markets outside of Montana, and we would gladly do that. In the meantime, we're also going to be focusing on what we can do within Montana from both electric and gas perspective to make sure we have supply and able to meet our needs within Montana. I think that's an opportunity now to protect our customers, to deliver to them on a daily basis every day, and particularly during peaks, but also for us for a great opportunity for investment as well.
Thank you.
Thanks, Sophie. It looks like Jonathan Reeder from Wells Fargo has a follow-up question. Jonathan, your line should be open again.
Hey, I just figured I'd ask the obligatory inflation question, what you guys are seeing on that front, any pressures and your ability to combat them?
I'll take my first crack at it, and then I know Brian will have something to add and maybe Bob too. I think from a couple of regards, one, as you think about our CapEx plan here in 2021, I think I meant, a lot of those costs are already baked in where I would expect you would consider inflation as more in the out years of 2022, 2023 if the trends continue. Whether they're a short-term trend or a long-term trend, time will tell. If so, then certainly your cost per to do the same work, we would certainly expect that to ultimately impact us and customer bills.
All I'd add is that inflation's certainly a concern going forward. Obviously, that's apt to increase operating costs potentially and obviously capital investment. I'd also tell you that we're running into some supply chain issues. We've done a really nice job of managing that thus far. We're having great success this year, and we wanted to actually expand our implementation of AMI in Montana. It was going so well, but due to supply chain concerns there, we're going to have to keep to our original schedule. Otherwise, things are going pretty well, but we are keeping our eyes out for concerns around inflation, concerns around supply chain.
Got you. The other one, just kind of wildfire activity. I know there's been some in Montana. Anything that we should be aware of that's kind of impacting you all or a concern? Maybe just remind us how, I guess, any incremental costs associated with either wildfire mitigation or, I guess, fighting them or whatever, how that recovery process works?
What I would say is we've been very active planning for wildfires and other events for a number of years. We participate in a lot of good regional analysis, but have developed our own strategy in terms of it includes everything from hazard tree clearance, those are danger trees outside the right of way, down to a really sophisticated analytical program to identify the line segments that need particular investment. Because of the nature of the program, that's a capital item, not an expense item. We could talk to you about it for two hours. In fact, we did just a couple of weeks ago, have a great two-hour meeting with the Montana Commission, giving them a good presentation of what our fire team within asset management is doing. We also spent a good time at the Board of Directors this meeting, talking about the program.
The Montana Commission did give us support specifically for hazard trees in the last general rate case. I think we're seeing the benefits of all that work during this very dry year. There's always more that we can do just in maintenance of the system. The foresight of our distribution and transmission folks is really paying off. Brian?
Yeah, I'd just add, Bob mentioned earlier today that we had a peak load as of yesterday. Obviously there are fires in Montana. You're reading about them in the paper. They impact our system. We manage around it. We continue to provide that service with very little interruption to our customers. It just speaks to the quality of our operations at this company. I think the other thing I'd say is I get reminded at least by the T&D folks at this company, we've been dealing with forest fires through the over 100 years we've been in operation.
Great. Thanks.
Thanks, Jonathan. With that, it looks like your queue is exhausted. Before I hand it back to Bob, though, I would invite everybody over to the pool party at Andy's house.
Great.
Sounds like they're having fun over there. Bob, with that?
You left me speechless, which is really hard to do, but it's a great visual image. I wish we were all at Andy's pool. Enjoy the rest of your summer. Very much look forward to seeing you in person over the rest of the year. Take care, everybody.
Thank you.