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NorthWestern Corp
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Good day, and welcome to the NorthWestern Corporation Financial Results Conference Call and Webcast. At this time, I would now like to turn the conference over to NorthWestern's Director of Corporate Finance and Investor Relations Officer, Travis Meyer. Please go ahead, sir.
Thank you, Casey. Good afternoon, and thank you for joining NorthWestern Corporation's financial results conference call for the quarter ending September 30, 2020. Northwestern's results have been released and the release is available on our Web site at northwesternenergy.com. We also released our 10-Q premarket this morning.
Joining us on the call today are Bob Rowe, President and Chief Executive Officer; Brian Bird, Chief Financial Officer, along with other members of our executive team on the call with us today to address questions if necessary.
Before I turn the call over for us to begin, please note that the company's press release, this presentation, comments by presenters and responses to your questions may contain forward-looking statements and non-GAAP financial information. As such, I'll remind you of our safe harbor language.
During the course of this presentation, there will be forward-looking statements within the meaning of the safe harbor provisions of the Private Securities Litigation and Reform Act of 1995. Forward-looking statements often address our expected future business and financial performance and will often contain words such as expect, anticipates, intends, plans, believes, seeks or will. This information is presented based upon our current expectations, our actual future business and financial performance may differ materially and adversely from our expectations expressed in any forward-looking statements.
We undertake no obligation to revise or publicly update our forward-looking statements or this presentation for any reason. Although our expectations and beliefs are based upon reasonable assumptions, actual results may differ materially. The factors that may affect our results are listed in certain of our press releases and disclosed in the company's 10-K and 10-Q along with other public filings with the SEC.
Today's presentation also includes non-GAAP financial measures. Please refer to the definitions and reconciliations of these measures that are included in our webcast materials. Following the presentation, we'll open the phone line to allow those who are dialed up the teleconference to ask questions. The archived replay of today's webcast will be available for one year beginning at 6:00 p.m. Eastern and can be found on our Web site, again, at northwesternenergy.com under the Our Company, Investor Relations, Presentations and webcast link.
I'll now hand the presentation over to our CEO, Bob Rowe.
Thank you very much, Travis. If you're looking at the deck, you'll see that Travis included some beautiful fall foliage. Unfortunately, well, for better or for worse, if that picture were taking today, it to be white, at least I've been out shoveling snow a couple of times already. It's like I get to shovel of a couple more times over the next few days as well, but it's a beautiful photo.
Well, for the third quarter, net income increased $7.8 million as compared to the same period last year. This was primarily due to higher gross margin, lower OG&A and favorable income tax, but offset in part by higher depreciation and higher property taxes. Diluted EPS increased $0.16 or 38.1% as compared to this period last year. Diluted non-GAAP EPS increased $0.09 or 18% per share after adjusting for normal weather. The Board at our meeting this week declared a quarterly dividend of $0.60 per share, payable on December 31st to shareholders of record as of December 15th.
We've talked a lot about how our employees have just done such an incredible job during the now year of COVID, and that continues to be the case. So we have a shot out to them at the bottom just in terms of exceptional employee safety, and we now include health and our safety focus and great customer satisfaction, both in either near or all-time highs, and this is despite the COVID emergency operating structure continuing in place.
Now I will turn it over to the most talented and admired Chief Financial Officer in the business, Brian Bird.
Thanks, Bob. One thing you should consider, Bob, if a snowblower might make a good Christmas gift for you.
On Page 4 of the deck are our financial results for the quarter, it was a good quarter. It's nice to see margin was up, operating expenses were down. Other income was up. And we had a nice tax benefit for the quarter, resulting in $7.8 million improvement in net income or approximately 36% from a diluted EPS perspective, $0.58, that was a $0.16 or 38% improvement for the quarter.
Going to the next page, associated with gross margin. Gross margin was up $2 million or approximately 1%. If you look at those items and gross margin that have an impact on net income, the one I'll focus my most attention on is the electric retail volumes and demand. We did have favorable weather versus the prior year that plus customer growth were partially offset by COVID impacts and industrial loads.
Speaking of COVID impacts, we did forecast $2 million to $3 million net impact due to lower commercial industrial usage, partially offset by increased residential usage. So that was, again, the biggest driver for the $2.9 million change in gross margin was the impact to electric retail volumes and demand. Those items that didn't impact gross margin that are offset elsewhere in the P&L, totaled unfavorable $900,000 for an increase in gross margin of $2 million.
Moving ahead to weather. I'll be pretty brief here versus our historic average or we deemed normal, we were unfavorable about $600,000. Cooler, Montana weather more than offset the warmer South Dakota weather. We were $5.1 million though better on a year-over-year basis and better because we were both warmer in Montana and South Dakota than we were in 2019.
Moving to operating expenses on Page 7. Operating expenses were actually down $1.4 million or approximately 1%, driven by the nice reduction, nearly 5% reduction in operating, general and administrative expenses. Focusing there $2 million reduction in employee benefits, down just over $1 million in hazard trees in labor and nearly that much in generation maintenance were more than enough to offset the $2.4 million increase in uncollectible accounts for the quarter for a net change those OG&A items impacting net income of $3.1 million net decrease.
Below those items offset elsewhere in the P&L, they totaled $600,000, so for a net decrease in OG&A of $3.7 million. Back to COVID, we did note that the $2.4 million increase in uncollectable accounts was partially offset by other COVID related expense items that were about $1.2 million lower. I'll give a full P&L impact here in a moment. Also, on the operating expense side, we did see an increase in property taxes, increase in depreciation expense, primarily due to increased plant additions.
The next page, operating to net. On Page 8, operating income up about $3.3 million or 7%. Below that we had flat interest expense, a nice improvement in other income, primarily due to AFUDC for a pretax benefit of $4.6 million or nearly 21%. And below that we had $3.3 million favorable year-over-year tax item, which netted then $7.8 million or 36% improvement in net income.
Speaking of income taxes on Page 9. At the bottom of the page, you'll see in the first -- or for the three months ended September 30, 2020, we had $2.7 million benefit, that was $3.3 million improvement over the prior year period. We had better flow through repairs, better production tax credits. And our prior year permanent return to accrual adjustment was better on a year-over-year basis. Those more than offset the tax item associated with higher pretax income.
Moving forward, on the balance sheet, really not much to report here. Not a lot of changes. But at the bottom of the page, we focus on debt to cap, expected change you could see during the year in September versus a year end number. It's well within our 50% to 55% debt to cap.
On cash flow on Page 11, $69 million improvement in cash flow, primarily driven by an improvement in working capital. That is primarily driven by improved supply cost recovery. And then you might recall, in 2019, we had TCJA refunds that we gave to customers. Those are the biggest drivers on a year-over-year basis in working capital. That improvement of $97 million improvement in working capital is offset to a great extent by the reduction in net income on a year-to-date basis and, again, a net $69 million improvement. That increase in operating cash flow allowed us to invest approximately $40 million more in PP&E for the first nine months, and we continue to have an accelerating capital program and a had nice incremental cash flows certainly helpful in that regard.
Moving on to Page 12 is our adjusted non-GAAP earnings for the third quarter. The bottom of the page, you see diluted EPS on a GAAP basis of $0.58. We did add back $0.01 to get to $0.59 for the quarter, that compares to a $0.50 2019 three months ended September 30 that was adjusted for unfavorable weather as well. So $0.59 versus $0.50 or $0.09 improvement on a non-GAAP basis, 18%, very nice for the quarter.
If you look in the middle column, the non-GAAP variances comparing non-GAAP year-over-year. Gross margins still down, which makes sense when you back out the favorable weather and you think about coal, if you think about some of the industrial impacts. But that was more than offset by the improvement by OG&A and the improvement in income tax for the quarter for a net improvement, again, on a non-GAAP basis of $3.9 million or 15%.
Turning to the next page. On our diluted earnings per share, we affirm our previously revised earnings guidance of $3.30 to $3.45 per diluted share. I'll mention, highlighted here two of the assumptions. We have continued to see COVID impact our business. I think it's manageable and certainly to hit our guidance. If we're somehow wrong in terms of those assumptions that could impact our guidance certainly. Next, we also expect regulatory recovery of COVID-19 related to uncollectible account expense and are looking forward to seeing the final order from the Montana Commission on that topic.
Should also point out on the bottom of the page. We did, I guess, back away from the 6% to 9% total shareholder return in light of a very attractive dividend yield close to 5%, as we felt it more important to switch to a long-term earnings growth rate. 3% to 6%, we'll grant it, that's a pretty wide range. But I think folks know, we have to -- in order to get recovery of our invested capital, we need to go in for rate cases, that can result in lumpy results. But it's also at the high end of that range, if we're able to execute on our generation growth, we feel confident we can achieve that higher end of that range.
In light of that, I would say from a TSR perspective, if in fact we felt the long term range, if you will, from a dividend yield perspective, was a 4%, I would argue that our TSR is probably more 7% to 10% going forward. And I also would say we're getting quite a few questions. When you talk about long-term earnings per share what is your base here. And what I'd say in that regard is, think of 2020 as a base year. But also think since 2020 was impacted significantly by COVID, we should do better than 3% certainly in that regard. So again, the 3% to 6% is a long term rate, but for using 2020 as a base year, we should do better than 3%.
Moving forward, Page 14. We did update our earnings bridge. We had quite a bit of continued COVID impact in the third quarter, and we expect to continue into the fourth quarter. As a result, we did reduce our expectations from gross margin by $0.08. But as we pointed out in the last quarter, we do expect to continue to, if that's the case, to stay focused on cost control and we do expect some recovery there from an OG&A expense perspective and from income taxes to offset that.
That's on the far right, you can see on that page. To the far left, we do see our actual Q1 to Q3. We've done a nice job from an OG&A expense perspective, offset gross margin. But you can see why we needed to revise earnings guidance, if you will. Through the first three quarters we certainly didn't -- weren't able to do enough to offset property tax, depreciation and interest expense. So behind $0.17 on a year-over-year basis through the first three quarters.
Our forecast for the fourth quarter is in the middle of that page. And you might be curious as to why we think we'd do $0.08 to $0.14 in gross margin in the fourth quarter. One thing to point out is two lines below that is property and other tax expense. We did have a favorable adjustment in the fourth quarter of last year and thus, we have headwinds of $0.10 to $0.11 of property taxes this year. Remember, we do get recovery of that in our tracker 75%. So that is an add to gross margin up above. We also mentioned on earlier calls about unbilled timing should have a favorable impact on our fourth quarter results as well. Those two favorable items will be offset to a degree by COVID in the fourth quarter.
We also point out an improvement of $0.06 to $0.09 from OG&A. As you can see in Q2 and Q3, we were able to achieve $0.18. We feel confident we can continue at that high level of cost control and mentioned property taxes and lastly, incremental tax benefit. I did talk about timing. And also, I think people understand the fourth quarter is a large earnings quarter for us. On a proportionate basis, we get a lot of our favorable tax attributes and proportionate to our earnings. So we do expect some favorable improvement in the fourth quarter there as well.
Turning to the next page. COVID impacts on margin expectations. We were really good at forecast in the second quarter, not so good in the third quarter. But we weren't very good on residential either and we did quite a bit better on the residential side, worse on the commercial and significantly worse on industrial. I'd point out that the big reduction in industrial though were two choice customers Bitcoin operators, they're primarily -- their choice customers invest their bills primarily made up of demand charges, so less of an impact from an earnings perspective for us and part of the $2 million impact mentioned associated with industrials.
Fourth quarter, we are forecast to be slightly different than our original forecast, a little bit higher in residential, a little bit worse on commercial and certainly in industrial. We do expect one of those large industrial customers back online in the fourth quarter. Again, we will continue to be focused on O&G expense control to offset impacts of COVID.
Moving forward on the expense expectation. Expenses were pretty much in line with our expectations associated with COVID in Q3. We weren't able to receive the recovery mechanisms in the third quarter. Hopefully, this both come in the fourth quarter and that will help us in that regard but otherwise, in pretty good shape. At the upper right of this page, we do show a table, the second quarter shaded. We had $0.06 to $0.07 of EPS impact. We show $0.05 to $0.06 in the third quarter, a little bit better than Q2.
With that, I'll hand it back over to Bob for Page 17.
Brian, thank you very much. We'll start with the capital forecast, and you've seen versions of this over the last few quarters. And here, we're reflecting $1.8 billion of total capital over the next five years. I'll provide just a little bit more color on that. But we anticipate financing with a combination of cash from operations, aided by NOLs, first mortgage bonds and equity issuances. As we discussed, we expect to issue equity in 2021 and the A goal of that, of course, is to maintain and protect our current credit ratings as we balance that with our capital needs and plans.
This is a great long-term capital plan. It does include, as reflected in the chart, $80 million of incremental capital for South Dakota generation between '20 and '21. It does not include investments necessary to address other identified generation capacity issues, particularly in Montana, and these could increase the capital forecast. Notably, at this week's meeting, the Board of Directors approved going forward with needed generation at Aberdeen, South Dakota that would be capital between '21 and '23 of about $65 million total. This is an important investment. We're very excited that the Board has supported that.
We're really still finalizing our capital program right now. We've got a robust capital process focused on the projects with the greatest value on our system, sequencing the projects, prioritizing them and coordinating them. And what significant is in addition to the supply needs that there tends to be quite a focus on, we will be investing substantial amounts in really all aspects of the business. And this has to do with ensuring reliability but also the long term modernization of the delivery network. So we'll be talking to you more at EEI, for example, as our capital plans develop. But it really is very, very exciting for us.
A couple of other items and we'll come back and talk more about these. We did request accounting orders in Montana and South Dakota, allowing us to defer uncollectable accounts. Associated with COVID, the South Dakota Commission issued an order in August, authorizing deferral of costs for possible recovery in future rate cases. Montana Commission held a work session in October. We expect to receive a final order from the Montana Commission in the coming weeks.
As you know, in the last Montana rate case, the Montana Commission did approve a pilot fixed cost recovery mechanism. And then as COVID set in, we did request the commission to delay that pilot for one year. So that it would start July of 2021 and the commission granted that request. We have the companion FERC rate case for our Montana FERC jurisdictional transmission assets spending. We are well into settlement discussions there. When that case is resolved then we would file a compliance filing with the Montana Commission and adjusting for credit in our Montana retail rates.
Obviously, you're following the proceedings associated with our agreement with Puget Sound Energy to purchase their share of Colstrip Unit 4. As you know, Cowen talent exercised its right of first refusal. So at this point, the focus is on the remaining 92.5 megawatts of Colstrip. There are parallel proceedings at the Washington Utility and Transportation Commission and the Montana Commission, bit of an update there.
The WUTC issued an order yesterday, suspending the hearing that had been scheduled for November 23rd, and there will be a status conference concerning the docket on October 29th. Each year we of course submit filings for recovery of electric natural gas and in Montana for property taxes, the commissions review these trackers and make the determinations based on either statute or a frequency determination. And inevitably, we have dockets pending there.
Turning to the subject of resource planning. We talked about some of these projects already in South Dakota. Construction is already underway on 60 megawatt flexible reciprocating internal combustion engine, an ICE, to be online late 2021 and construction costs will be about $80 million. Concerning the Montana RFP, initial bids were submitted earlier this year. We're looking for up to 280 megawatts through a competitive solicitation. And that is essentially a blind process to us. So we do not know the outcome of the current round. We have submitted, or I should say, on the behalf this have been submitted proposing nonduration flexible capacity in excess of 200 megawatts. Those bids, like all the others, are being evaluated by the third party. And we expect the successful projects to be selected and announced by the first quarter and to meet our customers' needs to be online by 2023.
And as I mentioned, we continue very robust investment programs in transmission and distribution. Those include, of course, the basics but also really accelerating the evolution of our delivery system, particularly on the distribution side, where we are well into a multiphase process to stand at the distribution operations center. We're already seeing benefits in terms of just visibility into the network and also moving ahead with automation at the substation level, we are moving towards -- we have completed the AMI deployment in the electric parts of our South Dakota and Nebraska network, and we will be moving ahead with AMI deployment now in Montana as well. We're also on schedule to enter the Western Energy Imbalance Market in April. And from experience in an SPP, we're certainly encouraged that this could mean lower energy costs for our Montana customers, more efficient use of renewables and greater power reliability.
I've highlighted this before as well that really just as important as going into the EIM is our work with the Northwest Power Pool on the regional resource adequacy. And there the goal is to really get a common tool to measure resources, to assign capacity values and ultimately to determine as a region as well as at the company level what our resource adequacy position is.
And I believe with that, we can open the call for questions and discussion.
[Operator Instructions] We will take our first question from Michael Weinstein of Credit Suisse.
Could you give a little more, I guess, color on what kind of a fourth quarter you're assuming for COVID-19? And in order to make guidance, how much extra savings do you have to come up with in order to offset your latest expectations?
I think the bridge, Mike, I try to give an idea, the reason for the gross margin change on the bridge of $0.08 really is the answer to that question. We looked at kind of how things were trending in Q3. Expectation is we're certainly seeing in our service territory. COVID is here certainly more so than we forecasted way, way back in April. So I would argue that's the best place to capture that is in the bridge, the $0.08 there. And to answer your question, how we going to offset that $0.03 incremental OG&A savings, $0.04 more taxes and then everything else nets for another penny.
And you think the taxes will come through. I mean OG&A I can see having more control over, but do you have that kind of control over the tax [breaks]?
Well, taxes, we certainly -- I mentioned the attributes. We kind of have an idea in terms of expectations on fourth quarter based upon our pretax income during the quarter. We also had a favorable third quarter adjustment. And so from that net-net we feel comfortable with the fourth quarter with the $0.08 to $0.12.
Is there any color you can share on the docket for cost recovery that I guess, I think I heard you say it would be another couple of weeks if we'll get a decision in Montana?
The commission kind of hold session couple of weeks ago, they actually did because they were concerned to get it out the door, gave staff direction to issue a notice of commission action, approving our ability to issue and account for anything on the retirements on the pension funding side in terms of the COVID-related expenses. The discussion by the commissioners was very, very favorable, sympathetic. One commissioner made the comment that maybe we should have asked for more than just recovery of the incremental bad debt. But because there wasn't a direction to staff to just issue an NCA, we really do have to see the language in the order before our accounting department gets comfortable with making a decision. Brian?
Yes, Bob, if we waited with bated breath for the accounting order final quarter as ready.
So currently, it's about $0.09 of guidance, I think are relying on getting that cost deferral?
You're saying COVID thus far?
Yes. I guess in the guidance, I think you were assuming regulatory recovery of expenses. I think so far to date, through September 30, I'm counting around $0.09.
Yes, you're right. For Q2 and Q3, if you add this up, it's about $0.09. We expected we're going to get some recovery, if you will. During the fourth quarter, we are disconnecting for nonpayment during this time period right now, that's reducing that total. And thus, the net REG asset that we recorded, we expect it to be around $0.05, not the $0.09.
And is, I guess, are there any updates you can give on the RFP, I guess you expect successful projects to be selected and announced by first quarter of '21 to be online by 2023. Is there any additional color on that? Any reason that you might have to wait longer, let's say, than first quarter, or is it…
I guess we'll have to wait longer. The commitment we made is that if we hear that our projects don't make it into the next round, we'll let you know about that. So I've been quoting the Jazz standard do nothing until you hear from me. And so far, we haven't heard anything. We take that as positive.
One final question. Maybe just talk about the election coming up and how -- what we should be looking for at the commission in terms of how things are shaping up?
There's an election coming up. There are three open seats, one incumbent in billings is running for reelection, two of the incumbents Lake and Koopman are termed out and the campaigns are extremely, extremely active. There's no polling, at least no public polling on public service commission races. So we'll all be eager to see the outcomes. What you heard me say probably every two years is regardless of who's elected, we're very, very eager to begin really taking them as deep as they're willing to go into our operations and our obligations to serve our customers and their constituents. And the reality of those jobs is there's just an incredible amount to learn.
And in fact, really, there are opportunities I think for both the equity side and the credit ratings agencies to help with that educational process because what we do is invest in critical infrastructure and provide essential service. We can't do that without the confidence and support of both debt and equity investors. But in terms of where the commission elections are likely to go, I would really hesitate to make any predictions.
I guess one final question on that same thing. Is Colstrip then a part of the election conversation or the campaigning at all or is it…
I'm sure that it has -- it certainly doesn't mean you're talking about PSC races. There is lots of discussion around certain environmental issues, things like that. I couldn't point to specific comments around Colstrip one way or the other. And of course, there's the potential that anyone has elected is going to be past to make decisions around Colstrip. So I'd say, prudent candidate would want to be careful about making any overly prescriptive statements.
Thank you. And we will take our next question from Julien Smith of Bank of America.
That is actually Ryan Greenwald on for Julien. Can you guys provide some clarity on how you're thinking about the timing of equity into next year now? I know at one point, you guys were saying late this year, early next year. But just curious how your thoughts have evolved there in terms of potentially mitigating dilution for 2021. And as we await resolution on bad debt recovery in Montana, is the outcome there going to influence how you guys are thinking about it and the magnitude?
Actually, Ryan, 1 thing that's going to really drive the magnitude is whether we're successful or not on the RFP. And we hope to be talking about the size of an equity that we'll need in the February, April timetable. And we certainly feel comfortable going into 2021. But that would be about the time you'll hear something from us on that.
Are you able to provide any color just in terms of like thinking about potential upside to CapEx into EEI and beyond, in terms of financing, in terms of sense on incremental dollars invested?
We've got to have something to get you excited to meet with us in three weeks.
Fair enough. And then lastly in terms of the further acceleration of cost cuts this year, how would you frame O&M into '21 and timing of potential future rate cases given the historical test year?
I would say we'll speak to kind of our thoughts on '21 in three weeks, too. But I’d have to tell you the company continues to be extremely focused on cost control. Heading into this year, we did better than we anticipated to do and a lot of those things will continue into '21.
Thank you. We will take our next question from Shar of Guggenheim Partners.
Just a couple of quick questions here. Just on the newly initiated -- the earnings growth rate. Just curious sort of like how you frame the top end. You guys have talked about sort of being really comfortable with sort of the base spend run rate being around $400 million a year. So does that top end includes sort of the backfilling of the current CapEx trajectory. And then so how do we also think about Montana Generation spend, which could obviously, as you've highlighted, reached $200 million. So is that sort of incremental to the 6% that you've just initiated?
I would say this, and again, depends on how successful we are in RFPs. But I would put it in this context. If we're able to, as you point out, get timely recovery on $400 million investment in each of those years, and I'm not saying that's exactly what it's going to be. But we should be more in line with the middle of that range. I'm saying if we're successful from an RFP perspective, we certainly should be at the top end of the range. And it depends on how much investment there is and the time of recovery, is it possible to do better. I imagine it is, but I think we're comfortable with that 3% to 6%.
And then can you just remind us just on the equity question, and obviously, we're waiting for it. But where are you as far as the protected and unprotected added refunds? And under the assumption that you may see higher corporate taxes. Can that mitigate sort of some of your incremental equity needs that we're still waiting some disclosure on? I guess, how do we sort of think about the interplay between potential higher corporate taxes and your equity needs and kind of where you are as far as the refunds of the added?
Obviously, as Bob pointed out, there is election going on. And we all know that TCJA had a tremendous impact on companies from an equity perspective. Shar, we have not contemplated anything from an election perspective into our plans from an equity raise. We're looking at status quo at this point in time. I would expect, again, with timely recovery, much like we did had timely recovery when we had to pay refunds to our customers. Obviously, an increase in the tax rate ultimately is going to be beneficial to us from a cash flow perspective. And so we'll also have that information around that February and April time to be able how to think about that as well.
And then just lastly, with you joining EIM, and we've seen some of the companies that have joined EIM the sort of the bill savings that you're getting as a result of it, the headroom, some of the utilities have been able to pull forward some CapEx. Given sort of the balance sheet, given sort of the bill headroom you've gotten as being part of EIM. Have you sort of quantified sort of what potential savings you could see as you join the EIM? And if you have additional bill headroom as a result of EIM. Could you pull forward some additional spending opportunities similar to what we've seen with some of the other sort of members?
That's not the way I would look at the imbalance market, at least near term. And honestly, we have not used the phrase, bill headroom, in the context of either Cal ISO or SPP. In SPP, which is a complete market, we have seen substantial supply savings to our customers. But in order to get the full benefits of SPP, that has certainly been another factor supporting our retire rent replace approach to our oldest assets in South Dakota.
In terms of moving Montana into the EIM, we were later than some of the other Western companies. We sit on the Eastern edge of the Western interconnect, because we needed to get comfortable that there was a positive return benefit for our customers for moving forward. As the Western market developed, we could see that. But again, in the EIM, it's not a capacity market, it's an intra hour market and we need to have resources that dispatch in order to fully participate.
I think the longer-term benefits will depend on how that Western market evolves. But certainly, we believe there will be savings and other benefits as well for moving into EIM, but we don't anticipate anything that would look like a step change. And then you have to factor in other considerations moving in the opposite direction, such as, as Brian was just discussing a substantial change in the federal tax policy.
Bob, if I could. I think it's fair to say as that market does develop, and if it becomes a full function market like SPP. I mean, we have seen the 6% to 7% improvement for customers' bills participating in that market. And I think that's ultimately where we'll get to. And I agree, Shar, that will provide headroom. But Bob talked about there's a lot of reasons we want to participate in EIM, that ultimately would be one as well.
And that's much longer proposition. And as we looked at joining EIM, we very much wanted to be part of the longer-term development of that market.
And we will take our next question from Chris Ellinghaus of Siebert Williams.
Brian, as far as the incremental estimated bad debt expense from COVID-19, is that 100% deferred at this point?
No, we're booking at bad debt expenses. We normally would. We did have a slight adjustment for South Dakota in the third quarter, but we're hopeful in the fourth quarter, depending, again, on the accounting order, to have an adjustment at that time once again, we see the final order.
Okay. That's what I want to clarity on. So in the fourth quarter, pending the order in a couple of weeks, that benefit can flow through in the fourth quarter. Correct?
Correct. And as I pointed out also, Chris, just earlier on, just to avoid confusion. We've mentioned $0.05 in the past. And if you argue today, it's $0.09. But again, we have been and certainly seeing benefits of our AMI system in South Dakota. We've had ability from a disconnect for nonpayment to capture some of that incremental bad debt, and we're also currently right now doing the same in Montana, albeit without AMI, but we're seeing some progress there as well. So unfortunately, we run into winter rules. And so the ability to disconnect and have the same impact slows here relatively soon. So we've got to continue to work hard at it to try to reduce that amount of bad debt expense as best we can with or without an accounting one.
Well, what I was kind of getting at. Just so that everybody has clarity, that the fourth quarter range, which is a pretty substantive one, incorporates both weather and this potential for the accounting order to be a pretty sizable benefit, right?
Yes. As I've said, that that is about $0.05 item and we're expecting to get favorable regulatory treatment in our guidance.
Just looking at the CapEx, I presume that the drop-off in the natural gas CapEx four years is merely just the imperfect forward estimate of capital, and that's part of what we'll hear about at EEI.
I just would say this. I think you know, typically, we have this downward sloping and sometimes things can change priorities change as well as we move forward in terms of where that capital spend goes, and we move some things around to fit projects in. But that's all I have to say there.
And I would add just that we do have a robust gas investment program, both distribution and really particularly on the transmission side. And there certainly is a fall-off in the last couple of years, but the averages are still significant. Of course, that's a big -- it's not as big a part of the overall business, but we do have some significant gas transmission investments coming up and we visited with the Board about those even this week.
Thank you. And we now have Brian Russo of Sidoti.
Just a lot of my questions were asked and answered, but just on the timing of the RFP outcome. Is there a deadline for the winning bidders to be announced by the independent third-party in the event that it's a self-build scenario to have that generation available in early '23?
There isn't a deadline for the announcement. We've been -- as you know, we extended the open period for bid submissions but have been able to hold all of the rest of the date. And we are very concerned to get supply available to meet our customers' needs. Just as you said, we're in the whole, not just in 2023. We're in the hole now, been in the hole for a number of years. And we're very concerned about our customers' increasing exposure. So we're comfortable with the first quarter timing based on what we've seen from across the wall, we think that will be doable.
So even early 2023 commercial availability, I mean, even that's somewhat fluid, right? It could be mid 2023 or is it time with maybe short-term PPAs rolling off? Just a little insight there?
Well, there's not a lot of insights to give. We need the capacity resources now and we think 2023 is realistic. And by just point of comparison, if you look across the border to the east to South Dakota, you see how quickly we've been able to go from plan to execution to meet the needs in South Dakota. And as important as those needs are, we're not facing 45% capacity shortfall with South Dakota by any means. So we have a sense of urgency in Montana, and we think it would be appropriate for the state of Montana [urgency].
And just curious, how did the PCCAM function in the third quarter of 2020 when we saw that volatility in the Western power markets in August. Just curious were you above or below the baseline in rates?
Brian, we have a schedule in the back of our deck that kind of shows the PCCAM impacts, and it's 36 of the deck in there. We show for the '20 expense is about $400,000 to the detriment, if you will, and on a year-over-year basis, it's $500,000 variance.
Thank you. We will take our next question from Jonathan Reeder of Wells Fargo.
I just wanted to go quickly back to Montana and the COVID related expense recovery and the final order. I thought in that work session there’s some sort of like 5% net income threshold before any sort of recovery would be afforded. Is that not the way, I guess, you've interpreted things or have they changed that opinion? Can you just kind of update there?
That's really what we are waiting to see in the order.
Bob, that's what I was going to share.
But that 5% net income threshold is withheld or upheld in the quarter and presumably, you won't get that $0.05 recovery, right?
If in fact there's a restraint, if you will, and depending on how that restraints worded, it could have an impact on us recording a REG asset. That's correct. And it also depends on how that would be applied is that impact just on bad debt or is it all impacts associated with COVID. Jonathan, there's a lot of unknowns yet, and we need to see in that final order.
No, I thought there was still some uncertainty there. But yes, I misinterpreted Bob's comments that it sounded like everything was really positive. So just want to check to make sure that was still there. And then going back also to…
The discussion at the commission was extremely positive. And there was just some noise around that particular issue. So we're eager to see the order.
And then back to the whole point with Colstrip and the Washington Commission spending their hearing. What was kind of the rationale behind that? I missed yesterday with some other merger activity going on.
Really what was going on yesterday, tell us about that.
I have no idea. Do you want an M&A-related costs question as a follow-up though?
No. I shouldn't have opened that particular can. Most of you are probably following this but in sequence. We've talked about Cowen asserting its ROFR. So Cowen looked at the deal and said, Northwestern negotiated a very good deal for its customers and for the state, we want half of that. Then in Washington, first, the commission staff, which appears as a party , filed some testimony critical of the proposal in a number of ways, including saying that the deal was too favorable to NorthWestern. And then another party also filed a testimony that was problematic and in fact, that was Avista.
So based on that, then the PSC requested that the schedule will be postponed, Washington Commission approved that, and there will be now a scheduling conference set on the -- or status conference set on the 30th. We were certainly disappointed that Avista chose to participate in the way that it did. I honestly don't know why they did that. And we believe that the transaction would provide real benefits all around. And obviously, Puget, which is a very sophisticated company, concluded that it was an important part of its strategy to, on the one hand, meet the Washington state carbon deadline in 2025, while meeting its customers' needs between now and then. We believe that it helped fill that toll we've been discussing on this call for our customers for a significant period of time.
We also believe it really gave the state of Montana the opportunity to have meaningful control over this part of its critical infrastructure and provided benefits to the community in Colstrip. So again, big picture. We think the proposal that Puget and we negotiated did an awful lot of very important things. But the status will likely be determined in front of the Washington Commission, and we will all know more in the coming weeks.
So at this point, you think -- I mean, getting the Washington approval is obviously key. And without that, there is no way for you to move forward in any forward fashion on Colstrip, and I guess you would just address the short fall in, again, through success of RFPs?
Yes. We'll have to make that decision depending on what happens in Washington. But you're right. For this deal to go forward, there has to be an approval in Montana, of course, but there has to be an approval in Washington for the sale of the regulated assets. And depending on how that all comes out, we will make an evaluation. But at this point, we were counting on the 92 megawatts to help meet our customers' needs. We believe there was value in the PPA back to Puget that would have had the net dedicated towards future remediation costs for our existing ownership share with Puget retaining the responsibility for what they currently own.
So again, there's just a lot of very, very attractive pieces to all of this for both parties. And I really believe that if it doesn't go forward, it will be a big loss all around. In fact, really a big loss for the Colstrip owners that aren't direct participants in the transaction. But we'll have to evaluate what we do next once we get some clarity.
All right. No, I appreciate that clarity in response and look forward to speaking at EEI. Thank you.
Thank you [Operator Instructions]. Now we have a follow-up question from Michael Weinstein of Credit Suisse.
I was going to ask a lot of the same questions about Colstrip. I mean, maybe just a follow-up to it, I mean, can Unit 3 operate on its own if the sale of Unit 4 doesn't go through and eventually, you wind up having to shut Unit 4, let's say. Can Unit 3 operate on its own? Is there enough plant there to…
Yes, more probably the scenario would be the opposite. There's an owner's operating agreement that covers both units, and there's a reciprocal sharing agreement between the two units. But yes, the two units can operate independently. And our existing ownership interest is in Unit 4, what we were proposing to purchase is in Unit 4. We don't own any of Unit 3.
Well, I'm just thinking about -- I don't know, maybe you can make a comment on the broader region. And what does supply look like across the entire Pacific Northwest over the next few years? I mean, at what point do you wind up with load overcoming supply, nothing else is getting built going forward. When do you wind up with the lower [Multiple Speakers] regionally…
Yes, that is exactly the reason that we are so bullish on the Northwest Power Pool regional resource adequacy work. We are, as a region, facing those concerns. If you do kind of a ranking of the reserves available to all of the companies that operate in the Pacific Northwest, everybody is a little bit scared and maybe getting a little bit naked, but we are incredibly, incredibly exposed and we need dispatchable resources to meet peak. We need resources to help integrate and balance the intermittent resources that continue to come on in a very large number. And that, unfortunately, is not what's being built but that is what is being retired.
Another kind of interesting point of comparison is the California outages this summer, and actually [travels] could include in future appendix a pretty good comparison of the resources in Cal ISO to the resources on our system. And effectively, these are rough numbers but you could say California has probably right now, I don't know, 50% dispatchable resources, primarily including natural gas and a relatively -- surprisingly, relatively lower percentage of intermittence and renewables, whereas we have a very, very high percentage of intermittence and nondispatchable resources and a very, very low percentage of dispatchable resources. And of course, in Montana haven't brought any new thermal resources on in about a decade.
So for all those reasons, yes, this is a concern for the Western United States, it is a concern for the Pacific Northwest, and it is a bigger concern by far for Montana than for any other state in the West.
And yet, this is not an election issue, right? I mean, it's not even being talked about in the legislative election contests as, you know, I mean…
There is awareness. There is increased awareness. It's a tough thing to get your arms around. There are certainly political leaders who understand it and want to help address it, but it's a tough issue. And long-term decisions are very, very hard to make. I understand that, too. That's what electric and gas companies do, make long term decisions. But we can't do that if we don't have support from politicians and policymakers.
And just to be clear, you guys are not affected by any of the wildfires yet? Hopefully, never, but it's not really affecting your system at all, right?
No, we have fires virtually every year. And we have certainly the beetle infestations, things like that. But if you go back to when we started our distribution system infrastructure plan over a decade ago, we've always put substantial resources into vegetation management. Now we have a very aggressive hazard tree program. We are participating with the other Western utilities in what you could call kind of a GAAP analysis, sharing our various strategies, deciding what strategies that other electric companies in the West are using that might make sense for us and what strategies don't but then doing some other things.
So we do have fire exposure. We are focused on it, have been for a very long time. We did have fires this year, not on the scale, mining names of what has happened on the coast. Our largest fire this year was just North of Bozeman in just a very beautiful area, it's a north and east of Bozeman and then we have other smaller fires as well, certainly.
But not enough to raise any alarms I’m thinking either the legislature or the commission. Despite the fact you can point to California, you can point to California as an example of what could happen right there in…
We have been briefing the Montana Commission on the subject for quite a few years, and they do understand it, and they do support the expenditures that we're making from the vegetation management side to the investments that we're making in the system. I'm going to get a little bit more detail for you. One of the things that we are doing just because our planners have so much data is what we would call the electric segment identification program or ESIP. And what we're doing is taking the data to identify subsegments of these very, very long lines we have in much of Montana and then being able to target our work at those line subsegments and effectively rebuild those as capital projects, by the way, but use our resources as efficiently as possible. There are benefits in terms of fire preparedness or avoidance but also real benefits in terms of reliability and resilience.
All right, thanks Bob.
More than you wanted, but thank you for listening.
One thing I should point out, Bob, just to be clear. We didn't start those fires. Those fires just happen to happen in Montana, correct? Just want to make sure that that's clear.
[Operator Instructions] At this time, we have no further questions.
Brian, I think you and I talked them into submission, mainly me.
That's right. Good at that snow shovel, Bob.
Well, thank you very much for joining us. It is too bad that we're not going to be together in person at the EEI meeting, but I'm sure it's still going to be a great, great conference. Have a great weekend.
Thank you, ladies and gentlemen, for your participation in today's call. You may now disconnect.