NorthWestern Corp

NASDAQ:NWE

Earnings Call Transcript 2019-Q3

[Operator]

Good day, and welcome to the NorthWestern Corporation's Third Quarter 2019 Financial Results Conference Call and Webcast.

At this time, I would like to turn the conference over to NorthWestern's Investor Relation Officer, Travis Meyer. Sir, please go ahead.

[Travis Meyer, executive]

Thank you, Katie. Good afternoon, and thank you for joining NorthWestern Corporation's financial results and conference call for the quarter ending September 30, 2019. NorthWestern's results have been released, and the release is available on our website at northwesternenergy.com. We also released our 10-Q this morning.

On the call with us today are Bob Rowe, President and Chief Executive Officer; Brian Bird, Chief Financial Officer, and we also have other members of the management team in the room with us today to address questions, if needed.

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 question may contain forward-looking statements. As such, I will 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 Reform Act of 1995.

Forward-looking statements often address our expected future business and financial performance and often contain words such as expects, anticipates, intends, plans, believes, seeks or will. The information in this presentation is 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 Form 10-K and 10-Q, along with other public filings with the SEC.

Following our presentation today, we will open the phone lines to allow those dialed in to the teleconference to ask questions. The archived replay of today's webcast will be available for 1 year beginning at 6:00 p.m. Eastern today and can be found on our website, again, that's at northwesternenergy.com under Our Company, Investor Relations, Presentations and Webcast link.

With that, I'll hand it over to our CEO, Bob Rowe.

[Robert Rowe, executive]

Good afternoon. Thanks very much for joining us today. We are in Brookings, South Dakota, a great dynamic community that we're privileged to serve. As always, when we meet out in the field, we started things off with a community reception the other night, and that was hosted in the meetings facilities at Dykhouse Stadium and our South Dakota Board member, Dana Dykhouse, was the champion for developing that great facility. If you're a football fan, you might have seen the game on ESPN GameDay on Saturday between the Jackrabbits and the Bison of North Dakota. And we have kind of a friendly rivalry between our North Dakota Board member, Tony Clark, formerly of the Federal Energy Regulatory Commission, and Dana Dykhouse. And of course, Tony and his team won the game, but it was sure a great show for Brookings. And then this morning, we had a good breakfast meeting with our employees here in Bookings and from around the area.

Turning to third quarter highlights. Net income for the quarter decreased $6.5 million or 23% as compared to the same period last year, and the decrease was mainly due to higher operating costs, lower demand to transmit energy across our system and lower electric retail volumes due to mild weather. These decreases were partly offset by a reduction in revenue in 2018 due to the impact of the Tax Cuts and Jobs Act, higher recovery of our Montana Electric supply costs and an increase in Montana Electric retail rates associated with the pending rate case, that being subject to refund. Diluted EPS decreased $0.14 or 25% as compared to the same period last year. Weather-normalized non-GAAP adjusted EPS was $0.50, which is $0.08 or 13.8% lower than this period last year.

In June, the Federal Energy Regulatory Commission issued an order accepting our filing with FERC for our Montana transmission assets, granting interim rates, again, subject to refund, effective July 1 and establishing settlement procedures, and then terminating the related Tax Cuts and Jobs Act implementation filing. So the FERC process is also moving ahead through a settlement conference, several tactical meetings. And, the next tactical meeting will be in Butte this week. Also, we announced the results of our South Dakota competitive solicitation process for new generation. We'll come back and talk about that in just a few minutes. And then the Board declared a quarterly dividend of $0.575 per share payable December 31 to shareholders of record as of December 13.

And then today, the Montana Commission approved the revenue requirement stipulation in the rate case along with a stipulation concerning development of green pricing alternatives, and we'll come back and talk about that a little bit more as well.

So with that, I'll turn it over to our Chief Financial Officer, Brian Bird.

[Brian Bird, executive]

Thanks, Bob. As Bob pointed out, net income was $21.7 million, $6.5 million or 23% less than the prior year period. Gross margin was up $2.9 million or 1.4%, but that increase was not enough to overcome increases in operating general expenses, property taxes, interest expense, other expense and income tax for the quarter, thus resulting in a decline on a year-over-year basis.

Getting into more details on these gross margin. Just in fairness, it was a disappointing quarter, and gross margin certainly points to that. If you take into consideration $2.9 million increase, most of -- almost all of that coming from the electric side of the business, that 1.4% increase was not enough to cover our costs and again, disappointing. In more detail on those increases in gross margin, the first 2, there are Tax Cuts and Jobs Act impact in the Montana Electric supply cost recovery really were 2018 detriments to the benefit on a year-over-year basis as a result of not having those items in 2019. Those were pretty much offset by lower transmission revenue through Oasis. We're seeing fewer people utilize our transmission system primarily as a result of activities at -- lack of activity at the Colstrip plant and some other items that impact gross margin.

When you look at things that kind of are our underlying business, on the electric side of our business, the $1.6 million increase in Montana Electric rates that we recorded for this quarter based upon the stipulation was not enough to cover the shortfall of electric retail volumes. And in fact, on the gas side, the small increase in natural gas retail volumes was not enough to cover the step-down that we had in Montana natural gas rate. So those changes all netted up to a very flat margin increase of $0.3 million. And so as I said, disappointing from a margin perspective.

The other item shown here, property taxes and PTCs and other operating expenses flowing through trackers, those netted to an increase of $2.6 million for the total increase in gross margin of $2.9 million.

Moving forward to weather on the next page, it was a bit of a perfect storm for a very weak weather quarter for us. Heating degrees are shown at the top. There's very little heating degrees that we received in the third quarter. It's typically a cooling quarter for us. But even in September, when we might get some heating degree days, it was the only month that we were actually warm in Montana. So we had very little heating degree lowered, if you will, during the quarter. And again, the third quarter being a cooling, as you can see by the map down below, your 2 months where you'd expect to see most of your cooling, July and August, we were colder in all our jurisdictions during that time period. So it was a bit of a perfect storm. As you can see, we estimate unfavorable weather in Q3 2019 resulting in a $5.7 million pretax detriment as compared to normal and a $4.6 million pretax detriment as compared to Q3 2018.

Then move forward to operating expense on the next page. Operating expenses were $164.3 million or $4.4 million or 2.8% increase on a year-over-year basis. Focusing on those, the changes in OG&A actually impact net income. The things we've talked about on previous quarters, things that we have made good decisions to invest in during the years, putting more money into our pension. We have an underfunded position, particularly in Montana, and then investing higher dollars in hazard trees are the 2 biggest drivers for this increase in OG&A during the quarter. We also have higher labor and legal costs and some other costs offset by some generation maintenance -- primarily some timing of some generation maintenance during the quarter. Those things added up to a change in OG&A items, impacting net income of $6.2 million. Offsetting those to a degree were $3 million in items that are offset elsewhere within the P&L. Those totaled $3 million for a total increase of $3.2 million in OG&A for the quarter.

In addition to that $3.2 million increase, we also had a $1.6 million increase in property taxes, primarily result of plant additions. And then lastly, depreciation depletion actually was down $400,000. That's primarily a result of the depreciation adjustment to the rate case stipulation, offset partly by plant additions.

Moving forward, in terms of operating to net income, taking all of those matters into consideration, you'd have an operating income of $46.4 million, which was $1.4 million or 2.9% worse than the prior year period. We did have higher interest expense, primarily due to higher borrowings. We had other expense increase of $2.4 million, primarily as the offset to those items shown as elsewhere on the P&L in the gross margin as an offset, a $2.4 million increase in other expense there. That -- those things contributed then to income before taxes of $22.2 million or 5.6% or 20.1% worse than the prior year period.

And lastly, we did have income tax expense increase of $1 million on a year-over-year basis, netting to net income of $21.7 million.

If we move -- speaking of income taxes, as we move to the next page in terms of the reconciliation there. Income taxes, as you might expect, might be down because of lower pretax income, both on the federal and state side, but we did have a prior year permanent return to accrual adjustment or think of it this way, adjustment that reflects the filing of our tax return, we had a swing there of $3.6 million and really offsetting a reduction in taxes as a result of lower pretax. That change of $3.6 million on a year-to-year basis or $0.07 is the primary driver for an income tax expense increase on a year-over-year basis.

Moving forward to the balance sheet. Not a lot to report here from the balance sheet perspective. It is nice to see shareholders' equity to go over $2 billion at the end of September 30, 2019. Also, good to see a ratio of debt to total capitalization be on the lower end of our 50% to 55% range. That's very, very helpful.

Moving forward to the cash flow statement. We have seen, as we did report in the last quarter, a decline in cash flow on a year-over-year basis through 9 months. Cash flow from operations was down $92 million really driven by 4 things. We had credits that we had to give to customers through Tax Cuts and Jobs Act that was resolved in 2018, but the benefits flowed back to customers in 2019. We've had an under collection of supply costs during the year for generation interconnection. We have refunds we had this year compared to deposits in the prior year. And then lastly, we had a very small insurance proceeds in 2018. Most of those items were all the first 6 months of the year. Cash flow as a whole for the quarter was relatively flat. Nonetheless, on a year-to-date basis through 9 months, down $92 million. That, coupled with an increase in investing activity, is about $32 million as a result of us to have to issue more debt during the year of it, certainly on a year-over-year basis.

Moving forward to adjusted non-GAAP earnings. As you know, since you have followed us for some time, we like to show GAAP on the outer edges of this page and then move with the adjustments towards the center of the page, so you can easily compare the non-GAAP numbers from '19 to '18. During the quarter, the only 2 adjustments -- well, the only adjustment really was unfavorable weather in 2019 and unfavorable weather in 2018. Taking those into consideration, those adjustments that actually impacted net income, our GAAP EPS in 2019 went from $0.42 to $0.50, and that compared to a non-GAAP number of $0.58 from a prior year perspective and so down $0.08 or 13.8%.

As I look at those items and kind of work through the P&L, the same could be said on a non-GAAP basis. We did have a decent increase in gross margin, 3.6%. But again, increases in OG&A, property taxes, interest expense and income taxes were more than offset as improvements in gross margin. I would say, again though, that difference of $0.08, just the tax adjustment alone of $0.07 of really turning up to the tax return could explain away the difference on a year-over-year basis.

Moving on to summary financial results on the next page. Gross margin, I should give -- from a total amount, net income was $142.1 million or up 11.6% or 8.9% on a year-to-date basis. Primary result there is improvement in gross margin, $11.4 million. We did have higher operating expenses on a year-to-date basis and higher interest expense and other income, but we did have a sizable tax benefit in the second quarter, netting in the net improvement $11.6 million on a year-over-year basis through the first 9 months of the year.

We also showed that on a non-GAAP basis, in this case, this year and last year, of course, we had the favorable weather adjustment in this case, on a year-to-date basis. And then in 2019, if we remove the tax benefit I spoke about earlier, in 2018 remove the QF benefit that we received, on a net-net basis, we would be year-to-date through 2019, $2.24,versus $2.32, a reduction of $0.08 on a year-to-date basis as well.

Reason we wanted to share with you the 9 months information as well, we typically don't do that in the quarter, is we are initiating our guidance through -- for 2019. And I think as a result of the news today in terms of commission of approving the stipulation and the fact that, in essence, before we could really talk about 2020 at EEI, it's very helpful for you to have '19 -- 2019 as a base. We'll -- I'll walk through that very quickly for you here. And to be clear, I will speak more to this at EEI in the coming weeks.

We start, obviously, at 2018's non-GAAP adjusted EPS of $3.39. When you take kind of the low end and the high end of those anticipated changes, you'd add $0.02 on the low end and $0.12 on the high end and you get to $3.41 to $3.51. However, with the share count dilution of $0.03 in either case, as a result of a year-over-year basis in terms of equity issuance that took place last year, we actually will show an ultimate range for 2019 of $3.38 to $3.48.

Clear to say that in our assumptions, we always assume normal weather the remainder of the year. And then obviously, we'll get a final settlement, final order from the commission. But it's good news that the stipulation is approved. We also have an income tax rate range of 0% to 5% and diluted shares outstanding of approximately 50.7% at the end of the year.

It's important to point out on this call, and -- particularly as we get prepared to talk to you about 2020 at EEI in a couple of weeks, to remind investors that we are -- continue to stay focused on our targeted long-term 6% to 9% total return to our investors through a combination of earnings growth and dividend yield. And again, we'll speak more of that at EEI. Certainly, as we talk about 2020, we're going to commit to try and achieve those as well. But it's also encouraging, and Bob will speak to this more about our ability to add more resources to our capital plan and the good news about our South Dakota resources, we'll talk about in a moment.

We -- if you think about 2019, how do we achieve that range? If you go to the next page, $3.38 to $3.48, in order in the fourth quarter, that's going to require us to have $1.14 to $1.24, a midpoint of $1.19. You compare that with $1.07 in the fourth quarter last year, it looks like you're a heavy lift. But I'd like to let you know that from our perspective, we expect to see expenses to be down a bit in the fourth quarter versus last year. And I think that's going to be a primary driver to help us achieve those numbers.

And lastly, I'd say, again, we'll speak to more clarity around all of this at EEI. And with that, I'll pass it over to Bob.

[Robert Rowe, executive]

Thank you, Brian. Well, since we're in South Dakota, let's start with the South Dakota electricity supply plan. Plan was published fall of 2018, focused on modernization of our fleet to improve reliability and flexibility and particularly, to maintain our compliance in the Southwest Power Pool and then lower overall operating cost. The plan identified 90 megawatts of existing generation that needed to be retired and replaced over about 10 years. On April 15, we issued an RFP for 60 megawatts of flexible capacity resources to begin serving our South Dakota customers at the end of 2021. We went through a competitive solicitation process. And we anticipate now being able to construct and own natural gas-fired reciprocating internal combustion engines, or RICE, units at a brownfield site in Huron, South Dakota. It's dependent on selection of the manufacturer's technology, but we anticipate about 55 to 60 megawatts of new capacity to be online by late 2021, a total investment of right around $80 million. And the selected proposal is, of course, subject to execution of construction contracts and then obtaining the applicable environmental and construction-related permits. So I think it's very, very good news for continued great service to our customers in South Dakota and certainly, we're excited about the opportunity to refresh our fleet here in South Dakota.

Turning to the Montana electricity supply plan that was ultimately submitted to the Montana Commission in August of 2019, they will be holding 2 public meetings, one in the afternoon, one in the evening on December 9 to receive any further comments on the plan. That plan supports the goal of developing resources to address the really dramatically changing energy landscape in Montana, but really around the west and to meet our customers' electricity needs in a reliable and an affordable manner. And the the real vulnerability in Montana and in the west is at peak. So currently, we're short 630 megawatts at peak. We procure that in the market, and that is an increasingly scarce and expensive product. And we forecast that our energy portfolio was going to be about 725 megawatts short by 2025, again, in Montana. And considering the expiration of contracts and a modest increase in customer demand, we think that's an appropriate, in fact probably conservative forecast.

We plan to solicit competitive all-source proposals later this year for peaking capacity to be available for commercial operation in early 2023. We expect to use an independent evaluator to administer the solicitation and to evaluate proposals, and we expect the process will be repeated in subsequent years to provide a resource-adequate energy and capacity portfolio by 2025. And the process will, of course, specify the need to be met but will be resource-specific, both demand side and supply side. And there's a potential capital spend, again, of course, depending on the outcome of a process of up to $200 million or so over 5 years.

Other key matters starting in Montana. In May, we reached a settlement in our Montana electric rate case that would result in an annual increase to electric revenue of about $6.5 million. That's based on a 9.65% return on equity and the capital structure as filed and also a $9 million decrease in depreciation expense. Hearing was held in May, briefing was completed in late August. In September, we wrote a staff memo recommended approval of the settlement. And then as you've heard today, there was a vote on 2 important components of the overall case, particularly a 5-0 vote to approve the revenue requirement stipulation and a 5-0 to approve the green tariff stipulation. Ultimately, there are other significant issues for the commission to address in subsequent work sessions, and the intention is to issue a final order in the case by December 26.

So obviously, we're very pleased with that outcome. Legislatively, the primary focus has been on implementation of 2019 Montana legislation that revised the electricity cost recovery statute to prohibit a deadband and to require 100% recovery of qualifying facility purchases and a 90% customer, 10% shareholder sharing of costs above or below a baseline. So this is a follow-on legislative action to essentially correct Montana Commission implementation of previous legislation. We view this as a relatively straightforward matter, should be a straightforward matter, and the commission is looking at implementation now.

Next, we do continue to invest in our transmission and distribution infrastructure really across the company, electric and gas. We're well into a comprehensive infrastructure program focused on safety, capacity, reliability on the natural gas side, investment is particularly driven by safety requirements and then also, grid modernization is a primary focus, looking at advanced distribution management and advanced metering. In fact, as we conclude the metering deployment, the AMI deployment in South Dakota and Nebraska, we do plan to begin the deployment in Montana next year.

We're well underway with plans to join the Western Energy Imbalance Market targeting April of 2021. And based on certainly what we've seen in SPP with a more complete market as well as our analysis of the western market, we do believe that can mean lower energy costs for our Montana customers, more efficient use of renewables and greater power grid reliability.

As Brian mentioned, we continue to monitor costs, labor benefits and property taxes. We are recognized as one of the most efficient operators in the sector, certainly among our peer group and have made expenditures on some -- what we think are especially important items over the last year.

Turning to our capital investment forecast. As you know, we give a 5-year look really by business segment and focus on projects that are known and identifiable. Based on what's depicted on the graph, we would anticipate funding the expenditures with a combination of cash flows aided by NOLs and then long-term debt issuances. Obviously, with the successful conclusion of the RFP, we can add to that about a $20 million expenditure -- probably $40 million expenditure on the first portion of the supply investment and, in addition to that, the AMI investment in Montana. So essentially, our capital plan going into next year is right around $400 million. And that's something we're very excited to take on.

The last thing I will say is we did announce the addition of 2 new Board members. This is part of really the ongoing Board renewal. And I think many of you have met our Board members. We are proud of the governance that they provide and our governance is recognized, again, really as best-in-class. Mahvash Yazdi will be joining us in December. She's got just an extraordinary record, starting out with the Edison companies. 38 years of experience focused on strategy, technology. This is just a wonderful person that's going to add an awful lot to the board. I imagine most of you know Jeff Yingling. He's currently a Senior Adviser in Investment Banking for Power, Energy & Renewables at Guggenheim. He also has just an extraordinary career working in this industry over 35 years. He was a participant at this Board meeting, and everyone, management and the Board, really appreciated the way he jumped in with both feet and made some real contributions just right throughout the meeting. So we could not be happier than to welcome both Jeff and Mahvash to the Board.

And that's the end of my filibuster except that Brian referred to the perfect storm of weather. And Brian, I would -- it sounds to me as you were describing it, it was the imperfect storm.

[Brian Bird, executive]

Yes, the imperfect storm is probably better, Bob.

[Robert Rowe, executive]

And with that, after your questions.

[Operator]

[Operator Instructions] The first question will come from Michael Weinstein with Crédit Suisse.

[Michael Weinstein, analyst]

Just to make a run at kind of a preview of what you guys are going to be talking about at EEI. With a -- the rate increase is about $6.5 million of actual revenues coming in this year. Most of it has actually already flowed into results for this year, right, since April. And I'm just wondering what -- given that most of that's already kind of in there and the impact is pretty small relative to the 6% to 9% total return target. What kinds of other factors might help boost earnings growth going into next year to get you to actually into that target range?

[Brian Bird, executive]

Michael, this is the only information I'll give before the next couple of weeks, but it's really going to be a combination of 2 things. We're not only going to have, as you might expect, relatively low growth from a gross margin perspective, think of our organic growth, but there will be some organic growth from a margin perspective. But we intend to actually decrease expenses on a year-over-year basis in order to achieve that growth rate.

[Michael Weinstein, analyst]

Okay. I mean I know you said it's the only thing you're going to say, but is there -- are there any specific categories of expenses that might be -- we will be focused on?

[Robert Rowe, executive]

We'll provide you a nice chart with ranges in a couple of weeks.

[Operator]

Our next question comes from Julian Dumoulin-Smith with Bank of America.

[Julien Dumoulin-Smith, analyst]

All right. Let me take a second run at this, if I can. So with respect to this cost reduction effort, you said in your remarks that 2019 might otherwise look like a heavy lift, but for cost reductions that you're pursuing in the fourth quarter. How do you think about the sustainability of those cost reductions? And truly, is the fourth quarter run rate and implicit decline a good way to think about those cost reductions you just alluded to '20? Am I thinking about that right?

[Brian Bird, executive]

I think it's fair to say that directionally that will help. I don't think that will paint the full picture, and I'll stop there, Julian.

[Julien Dumoulin-Smith, analyst]

Got it. And can I elaborate -- can you elaborate on what's driving at least the fourth quarter here in terms of sources?

[Brian Bird, executive]

I think we -- I would just say this, there's certain -- we went after certain expenses we've talked about during the first 9 months of the year, and we made great progress. Certainly, some of that spend we don't expect the same high levels in the fourth quarter. And I think on a year-over-year basis, they're pretty high spend in the fourth quarter last year. And I think timing is probably the best way to describe it.

[Julien Dumoulin-Smith, analyst]

Got it. All right. Excellent. And then can I -- if I can ask at a higher level, you talked about the 6% to 9% long-term total shareholder return off of 2019. How do you frame that into 2020, again, given some of the dynamics that you just alluded to? And then more importantly, just over the longer term, how do you think about the sort of potentially lumpy nature that given the timing for the next rate case? And that might be a back-headed way to ask you about rate case timing in your jurisdictions.

[Brian Bird, executive]

Yes. I think we'll give you more clarity on that in April as we usually do, and we'll talk about all jurisdictions at that time and the timing. I think it is fair to say, from our perspective, that in light of the low -- relatively low organic growth in our business, there's going to be more frequent rate cases than we've had historically. And I'll leave it at that.

[Julien Dumoulin-Smith, analyst]

That is a fair statement. So perhaps, if I can just squeeze in another real quickly here. As you think about the balance sheet side of ledger and you've alluded to some of the South Dakota CapEx here, how do you -- how should we think about incremental financing needs, et cetera, just again, high level? I know that we're going to get some more CapEx details here in a little bit, but at least kind of preliminarily and maybe even specifically to South Dakota.

[Brian Bird, executive]

I would say this -- we did say, and then Bob alluded to the fact that in our capital plans, our current plan, as you see in our 10-K and we've shown in this document as well, we do not need equity to finance that. As we add generation and approximately $80 million of incremental generation will have pressure, and we'll be focused on our FFO to debt coverages, and we want to make sure we maintain our BBB flat ratings. And as a result, we may have to issue equity in order to finance that incremental growth. So we're keeping an eye on that. My expectation is, if we were to do anything like that, you might utilize an ATM or some other means like an ATM program to finance that. And in light of the fact that this is going to take 2 years to build, the timing of when you would do that is certainly not something we would contemplate today, but maybe later in the -- in 2020 or potentially even 2021.

[Operator]

Our next question comes from Brian Russo with Sidoti.

[Brian Russo, analyst]

Just to clarify the 2019 guidance of $338 million to $348 million, that assumes normal weather for the entire year. So at year-to-date, you're kind of at a net positive of about $0.10, but that's excluded from the guidance, correct?

[Brian Bird, executive]

Yes. I would just say, on a year-to-date basis, that's already a -- we're starting -- our starting point, if you will, is a weather-adjusted number already. So then the assumption is assuming weather for the last quarter as well.

[Brian Russo, analyst]

Okay. Got it. And then just on the cost side, year-to-date costs are up quite noticeably, not unexpected, and I think it's partly due to pension expense and accelerated tree trimming. So is that something that's going to reoccur as we move forward? Or like other utilities for industry reasons, I guess, have accelerated expenses into 2019, which could alleviate some of those expenses beyond 2019?

[Brian Bird, executive]

Yes. I would say this, that our vegetation management is extremely important to us. Hazard trees are important as well in light of what's happening in west of us. I think we've made great strides in terms of accelerating those expenses this year, maybe a bit more even than we initially had planned. And so as a result of that, it made great progress, but we'll still have a relatively high spend from a vegetation management perspective.

[Brian Russo, analyst]

Okay. Got it. And also, just to be clear, the assumption in guidance for interim rates, is that beginning April 1 of 2019, so you'll see a lift for new rates in the first quarter of 2020?

[Brian Bird, executive]

On a year-over-year basis, first quarter '20 versus first quarter '19, yes, would be higher in '20 because of the rates we showed that go on in effect as a result of the stipulation at April 1 of 2019.

[Brian Russo, analyst]

Okay. So you're going to see the benefit of both the lower depreciation plus whatever the $6.5 million of annualized revenue is in the first quarter?

[Brian Bird, executive]

Only revenue.

[Brian Russo, analyst]

Only revenue. Okay. Okay. Got it. And then on the South Dakota self-build, what's the regulatory process? I believe you're going to need a rate case to recover that and will just collect AFUDC in the meantime?

[Robert Rowe, executive]

We'll be looking at regulatory options as there's more definition around the project. What I'd say at this point is we've had good communication with the commission throughout the RFP up to the decision, but we'll be making specific regulatory decisions over the coming months, and we'll be able to discuss those with you.

[Brian Russo, analyst]

Okay. So another option besides a rate case could possibly be a rider?

[Robert Rowe, executive]

South Dakota has a phased-in rate plan statute that was actually originally adopted to moderate rates as generation was developed, but then subsequently, it was extended to electric delivery infrastructure as well. So we'll look at that as an option, probably -- possibly in conjunction with other approaches.

[Brian Russo, analyst]

And when might you expect to get more clarity on the ultimate size of the plant or the cost to then move forward on the regulatory recovery side?

[Robert Rowe, executive]

I'd say by the second quarter.

[Brian Bird, executive]

Would you say -- and I would say by February, I think, February, we have that information by then.

[John Hines, executive]

Yes, we -- this is John Hines. We're looking at it no later than mid-January at this point in time for final selection to contract signed.

[Brian Russo, analyst]

Got it. And then just from an AFUDC perspective, should we just average it over the 2 years? Or is it going to be more front-end loaded, back-end loaded?

[Brian Bird, executive]

I think for your assumption purposes, that sounds like a good way to do it.

[Brian Russo, analyst]

Okay. And when can we expect comments from the Montana Commission on the supply plan that was filed in late August?

[Brian Bird, executive]

What we know is they've scheduled the 2 public meetings for December 9. And we don't know what specifically they might do after that.

[Brian Russo, analyst]

Okay. So in that forum, they can convey comments? They will receive comments, but will they give?

[Robert Rowe, executive]

Correct. Yes. And you probably know that we had posted the draft plan online and set up a vehicle for receiving comments online and then responding to those comments there as well. And all of that is incorporated in what we filed with the commission.

[Brian Russo, analyst]

Okay. And then are there any brownfield sites available in or around the state of Montana?

[Robert Rowe, executive]

Montana is an industrial state. There are all kinds of locations. I really don't want to say anything more about what might be bid in by anyone.

[Operator]

Our next question comes from Vedula Murti with Avon Capital.

[Vedula Murti, analyst]

I guess I'm wondering what items are still outstanding in terms of the Montana settlement that need to be signed off by the commission. I think the items -- based on the items that you, I think, articulated earlier, I'm not sure whether equity ratio and ROE and some other items or rate base were -- are still outstanding. What are the other moving pieces that are still outstanding since they didn't just simply sign off on the entire settlement as was proposed?

[Robert Rowe, executive]

So the revenue required -- we obviously have to wait to see the specific language in the commission's order, but the vote was 5-0 to approve the revenue requirement stipulation, 5-0 to approve the stipulation concerning green pricing. There's also a stipulation ending concerning various policies to promote energy efficiency and to align energy efficiency investment with the business. There is the specific proposal from NRDC for a version of decoupling, which we supported. There is the important issue of addressing the intra-class cross subsidy in the current net metering pricing structure. And there, we and the consumer counsel had both proposed that the net metering and non-net metering portions of the current residential class be separated and that a demand charge at some level be established and various other rate design issues, particularly for the residential class that weren't included in the overall revenue requirement stipulation.

[Vedula Murti, analyst]

So essentially, the fact that you've had interim rates based on the stipulation would mean as long as the remaining items are approved that are consistent and any potential incremental refund or adjustments is unlikely. But the fact is, is that the current rate structure and going through until -- from now to April 1 when this is first initiated is consistent?

[Robert Rowe, executive]

We really need to see a final order to answer every part of your question. I think in a general sense, we're obviously very pleased with the commission's action today. And the fact that it was unanimous, and the fact that they've laid out a proposal to address the remaining issue, which obviously, we have great interest in the decisions that are still in front of the commission. And what I'm particularly concerned with is to move towards the situation that better aligns public policy with the business plan and without costs are incurred. If we can make a few more steps along that pathway, I think that would be great. But the decision the commission made today really was key and was important and was constructive.

[Vedula Murti, analyst]

Okay. And I want to make sure I'm not confused in terms of, I think, you said December 9 in terms of, like, the resource plan that you provided. My recollection is, is that it will simply be accepted as something that would then go through a full process? Because my recollection is, is that the capacity that you're seeking to have an opportunity to provide to deal with the -- your resource deficiency, you believe exists. A final decision where you and us would all know whether you'd be able to make those capital investments isn't -- would not be adjudicated until about this time next year. Is that correct?

[Robert Rowe, executive]

John, why don't you go ahead and speak to that?

[John Hines, executive]

Okay. The RF -- the procurement plan process is what goes through what we call a non-contested case process, where the commission will receive comments from external parties. That's what's taking place in public meetings on December 9. Some point after that, they will provide comments on the plant. These are nonbinding comments and informational in nature. Obviously, we take them into consideration. However, the plan is very specific on the critical need for the replacement of capacity, especially as Pacific Northwest becomes shorter and shorter in capacity and the roll-off of Colstrip 1 and 2 in Montana. And so we will be moving forward with a competitive solicitation process likely at the end of Q4 here in 2019.

[Vedula Murti, analyst]

And then that's the -- after you initiate that solicitation, it'll be devaluation of solicitation and then that termination that will occur towards about this time next year, such that any potential self-build options that might -- that could help address the shortage that you see, we'd know whether you've been chosen or not?

[Robert Rowe, executive]

That's correct. And the solicitations, as I mentioned, will be open to bill transfer to PDA to demand management approaches. It will be truly all-source but focused on the identified need. As John said, the process in Montana is non-adjudicative in contrast to different states, but it still is a very important process, and the commission will have the opportunity to issue comments as it did on the 2015 plan. Beyond that, what I would say is, in 2015, we had a pretty robust agenda of outcomes from the plan. We were able to move forward on most of those, but in part because of decisions made by the Montana Commission at that time in almost unrelated dockets in terms of symmetry of contract length, we had to cancel that RFP, which really allowed the capacity hole that we're in to just get that much deeper over the intervening years. Now since that time, there has been really almost unanimous appreciation of the situation that we face in Montana and in the region. The entire region is concerned about capacity shortage. In fact, there was a regional meeting that a number of us participated in just about a month ago. Lots of studies have been done. Part of that, obviously, has to do with the retirement of existing resources. For our Montana customers, the situation is that much more acute, both because the peaks are more severe and more sustained and because still the vestiges of supply deregulation we have -- we're the only company in the west that has a negative reserve margin, negative 27%, as you know. So we are in a hole. We're trying to be responsible and efficient about working with others in Montana to get out of the hole.

[Vedula Murti, analyst]

And just so I'm clear, though, I mean when we come see you in a couple of weeks here in Florida and then when you report year-end in February, the capital program that we currently see here, the only updates aside from the base program and putting in the South Dakota RFP allocation to you, there will not be the ability to put in anything relating to your efforts in Montana because you will simply not have a conclusion there, and that's going to be something that would be towards the end -- towards about this time next year and that would be in the roll forward capital program for -- come late '20 for 2021 and beyond.

[Brian Bird, executive]

Yes. I would say it this way, Vedula, for 2020, we can speak to that with some more clarity at the -- at EEI. For February, this is when we update our 10-K for our capital plan out for 5 years, you should not expect to see anything in there for Montana self-build. We obviously have no idea, and so there will not be any of this built in our capital plan for that.

[Vedula Murti, analyst]

Okay. And also, I read something about someone who wants to be the Chairman of the MPSC, who I think seems to like the more competitive markets and having alternative providers for meeting the generation depths that you guys are seeing or whatever. Can you kind of speak just to kind of how the environment has changed since Mr. [ Kabila ] has left? And was kind of thought that things would be such a free market type or more like wanting to have assets built by third-parties? How that's -- whether -- how are you seeing things here?

[Robert Rowe, executive]

Sure. There will be several -- in Montana, several Public Service Commission elections. In some cases, there will be primaries as well as a general and then ultimately, the members of the commission select who the chair is. I think your reference was somebody running to be chair. We want everyone who's running for those positions or others running for other office in our service territory to have as much information about the company, about our responsibilities in that jurisdiction as we possibly can. So we're eager to provide good factual information, specifically as to supply planning, the commission is -- the commissions are really functions of the authority granted them by the legislature, number one. Number two, we are using competitive solicitation processes for electric supply planning, both in South Dakota and in Montana. Number three, in Montana, there was a comprehensive electric supply planning statute passed with the leadership of another legislator who's running for the Public Service Commission, and that was legislation that we supported.

[Vedula Murti, analyst]

So is this an election that's going to be happening this November here in 2019? So we'll have a new composition that's going to then be evaluating the resource plan and the solicitation that's kind of being developed right now?

[Robert Rowe, executive]

No. Candidates are out, beginning to talk. We don't know, ultimately, who will be running for what office beyond the folks who have announced. There will be primary elections next spring and then general elections in November of 2020 to take office in January of 2021.

[Operator]

[Operator Instructions] Our next question will come from Jonathan Reeder with Wells Fargo.

[Jonathan Reeder, analyst]

Bob and Brian, I just wanted to clarify one quick thing. On the CapEx budget, in your prepared remarks, Bob, did you say you expect to spend like $400 million next year?

[Robert Rowe, executive]

Yes. We expect our all-in capital budget next year will be right around $400 million, yes.

[Jonathan Reeder, analyst]

And that's driven by the South Dakota opportunity? And then did you say AMI in Montana?

[Robert Rowe, executive]

Yes. The capital that we've been discussing for a number of months is a pretty robust capital project overall. The additions coming out of our Board meeting are the generation in South Dakota and beginning work on AMI in Montana.

[Brian Bird, executive]

If I could, Jonathan, just for everybody, the pretty simple math is, if you take 2020 from that schedule of $332 million, add approximately $40 million for the South Dakota generation and another $25 million from Montana AMI, you're at $397. So in essence, that might not be exactly the number for -- but to Bob's point, it's going to be approximately $400 million.

[Jonathan Reeder, analyst]

I like you putting it down like that for a simple guy like myself. I appreciate it. Brian, if you could, could you kind of go through what the miscellaneous items were both gross margin and cost-wise that have really piled up year-to-date? And how we should think about those? I guess going forward, are they timing related? Do they go away in 2020?

[Brian Bird, executive]

Yes. I would tell you on the margin front, in both cases, unbilleds are the biggest drivers. I mean there are quite a few things that add up to the $2.3 million for the quarter and $2.1 million, I think, for the other, if I recall those numbers. But the biggest drivers in each of those cases were unbilleds that jump out for me on the margin front. On the cost side -- and there are pretty big others. And I think as a company, we made some conscious decisions in this year to catch up on some expenses. And we also had an IRP process. We had a South Dakota RFP. We had some insurance reserves. We had some higher BT costs. We've had some compliance costs that we had to. And these things, as a stand-alone basis, don't add up. But Jonathan, there's literally about 2 dozen things I could quantify, if you want to talk about things that are in the $100,000 range. And so I'm not going to go through that. But I kind of mentioned maybe the bigger hitters.

[Jonathan Reeder, analyst]

Okay. Because, yes, I mean on the cost side, I think, it was like over $6 million year-to-date, which -- that's a big number for you guys. So it sounds like for those we should expect the bulk could go away. You'll obviously still have IRP costs with Montana and stuff. But is that kind of fair that, that's one of the buckets, I guess, we should be thinking about when we look at overall cost for next year?

[Brian Bird, executive]

Yes. Again, these are all costs that are under $1 million that I've just specified. And so some, you're right, are going to be repeated, some from our perspective, we don't expect to see next year. So I can't really answer that directly, Jonathan.

[Jonathan Reeder, analyst]

Okay. And then my other question is just the lower transmission revenues. Is that going to be, I guess, kind of a new normal going forward since you said it was related to lower activities at the Colstrip plant?

[Brian Bird, executive]

Yes. I think in fairness, we -- at Colstrip, some long-term contracts have rolled off, and we've just seen -- as a result of that, we've seen fewer activity during the quarter. We have seen, when there's some more variability in pricing that there is some more movement, if you will, across our lines. But I think I would put it in this content -- context, I don't expect us to see higher oasis in 2020.

[Robert Rowe, executive]

The thing to add to that is that there is renewed interest in developing renewable resources in Montana for exports. There's an awful lot of activity around that, more than we've seen in probably a decade. So we certainly welcome that and want to work with those parties.

[Operator]

Our next question comes from Vedula Murti with Avon Capital.

[Vedula Murti, analyst]

Just a couple of other little follow-ups here. Can you remind me, at least historically, or what we should -- in terms of maybe the current rate stipulation, there's always like a structural lag in terms of items that are excluded in terms of relative to the ROE that's underlying. Could you remind us dollar value and the basis points that's usually tied to that?

[Brian Bird, executive]

Vedula, I'm not sure if I'm following your question. Are you getting at generally at lag as a whole or...

[Vedula Murti, analyst]

Yes. Like for instance, just like historically, if you're under your normal operations here, I'm going to make up the number, let's say, you're earning, you're authorized at 9.5%. My recollection is just like there's usually 70 or 80 basis point structural lag because there are expenses that simply are not granted that would then effectively turn 9.5% into like 8.7% or an 8.8% or whatever?

[Brian Bird, executive]

Yes. I don't have -- I don't know what that would be. It's my expectation that, that is a pretty small delta, but I don't know, for sure.

[Robert Rowe, executive]

You're talking about things like stock-based compensation, for example.

[Vedula Murti, analyst]

Yes. Yes. Exactly. And -- there's always certain things that seem like that's always there.

[Robert Rowe, executive]

And that would be the case, but again, as Brian said, pretty small.

[Vedula Murti, analyst]

Okay. Also, I'm looking at the [ DD&A ], it's like on an annualized basis entire run rate that's looking like about $175 million. So if I'm thinking about that versus CapEx, if -- should -- is that basically going to be like fairly reasonable going forward and with some modest increases? Or are there any major changes that should we think about with [ DD&A ]?

[Brian Bird, executive]

Think we might be able to share some more light on that at EEI, but I...

[Vedula Murti, analyst]

Okay. All right. And one last thing, given the cost initiatives you're -- you discussed earlier and that you're just trying to get a rate stipulation approved, there -- is there any reason for us to think that you'll file immediately this year? Or do you feel like the cost initiatives and having stipulation can at least buy you years, so you can wait and see what happens with some of the RFPs and then contemplate a potential refiling year...

[Brian Bird, executive]

You might have missed that earlier on the call, Vedula, but I've mentioned that we would talk about any particular rate case filings in April, but that's our normal cadence, we'll speak to all jurisdictions at that time.

[Operator]

[Operator Instructions] So I'm currently showing no further questions. I'd now like to turn it back over to management for closing remarks.

[Robert Rowe, executive]

Okay. Great. Well, again, thank you all very much. It was low-teens today across South Dakota and below 0 in Montana. So that's yet another reason we're looking forward to seeing you all at Disney World in a couple of weeks.

[Operator]

Thank you, ladies and gentlemen. This concludes today's teleconference. You may now disconnect.