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 Relations Officer, Travis Meyer. Sir, please go ahead.
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 your questions if needed.
Before I turn the call over for us to begin, please note 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 company's Form 10 ks 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 into the teleconference to ask questions.
The archived replay of today's webcast will be available for 1 year beginning at 6 p. M. Eastern today and can be found on our website. Again, that's at northwesternenergy.com under Our Company, Investor Relations, Presentations and Webcasts link. With that, I'll hand it over to our CEO, Bob Rowe.
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 Dijkhouse Stadium, and our South Dakota Board member, Dana Dijkhouse, was the champion for developing that great facility. If you're a football fan, you might have seen the game on ESPN Game Day 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 Brookings and from around the area. Turning to Q3 highlights. Net income for the quarter decreased $6,500,000 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 percent 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 technical meetings, and the next technical 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 the 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 Burke.
Thanks, Bob. As Bob pointed out, net income was 21,700,000 dollars 6,500,000 or 23 percent less than the prior year period. Gross margin was up $2,900,000 or 1.4 percent, 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 the 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 $2,900,000 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.
And in more detail on those increases in gross margin, the first two there are Tax Cuts and Jobs Act impact in the Montana Liquids Supply Cost Recovery really were 2018 detriments of 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 or lack of activity at the coal strip plant, and some other items that impacted gross margin. When you look at things that kind of are underlying business on the electric side of our business, the 1,600,000 dollars increase in Montana electric rates, that we received or recorded for this quarter based upon the stipulation was not enough to cover the shortfall on 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 rates.
So those changes all netted up to a very flat margin increase of $300,000 And so as I said, disappointing from a margin perspective. The other items shown here, property taxes and PTCs and other operating expenses flowing through the trackers, those netted to an increase of $2,600,000 for the total increase in gross margin of $2,900,000 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 receive in the Q3. 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 load, if you will, during the quarter. And again, the Q3 being in cooling, as you can see by the math down below, your 2 months where you'd expect to see most of your cooling, July 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 $5,700,000 pretax detriment as compared to normal and a $4,600,000 pretax detriment as compared to Q3 2018.
Then move forward to operating expense on the next page. Operating expenses were $164,300,000 or 4 point $4,000,000 or 2.8 percent increase on a year over year basis. Focusing on those, the changes in OG and E and actually impact net income. Things we've talked about on previous quarters, things that we made good decisions to invest in during the year is 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 and 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 and A items impacting net income of 6,200,000 dollars Offsetting those to a degree were $3,000,000 and items that are offset elsewhere within the P and L, those totaled $3,000,000 for a total increase of $3,200,000 in OG and A for the quarter. In addition to that $3,200,000 increase, we also had a $1,600,000 increase in property taxes, primarily a 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 the net income, taking all of those matters into consideration, you'd have an operating income of $46,400,000 which was $1,400,000 or 2.9 percent worse than the prior year period.
We did have higher interest expense primarily due to higher borrowings. We had other expense increase of $2,400,000 primarily as the offset to those items shown as elsewhere on the P and L in the gross margin as an offset, dollars 2,400,000 increase in other expense there. That those things contributed then to income before taxes of $22,200,000 or 5.6 percent or 20.1 percent worse than the prior year period. And lastly, we did have income tax expense increase of $1,000,000 dollars on a year over year basis, netting to net income of 21,700,000 speaking of income taxes, if 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 of it this way, adjustment that reflects the filing of our tax return, we had a swing there of $3,600,000 and really offsetting reduction in taxes as a result of lower pretax, that change of $3,600,000 on a year over 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 $2,000,000,000 at the end of September 30, 2019. Also, good to see ratio of debt to total capitalization being in 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 92,000,000 dollars 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've 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 1st 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 $92,000,000 That coupled with an increase in investing activities about $32,000,000 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 and 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 2019 to 2018. During the quarter, the only two adjustments 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 and L, the same could be said on a non GAAP basis. We did have a decent increase in gross margin, 3.6%.
But again, the increases in OG and A property taxes, interest expense and income taxes were more than offset those improvements in gross margin. I would say again though that difference of $0.08 just the tax adjustment alone of $0.07 of really churning 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 $142,100,000 or up 11.6% or 8.9% on a year to date basis. Primary result there is improvement in gross margin $11,400,000 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 of $11,600,000 on a year over year basis through the 1st 9 months of the year.
We also show 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, dollars 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 20 for 2019. And I think as a result of the news today in terms of the commission 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 2019 as a base. I'll walk through that very quickly for you here.
And to be clear, we'll speak more to this at EEI in the coming weeks. We start obviously in 20 eighteen'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 acquisitions 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 was 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 continued to stay focused on our targeted long term 6% to 9% total return 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. If you think about 2019, how do we achieve that range? If you go to the next page of $3.38 to $3.48 In order in the Q4 that's going to require us to have $1.14 to 1.24 dollars a midpoint of $1.19 You compare that with $1.07 in the Q4 last year, it looks like 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 4th quarter versus last year. And I think that's going to be a primary driver to help us achieve those numbers.
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.
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 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 megawatts to 60 megawatts of new capacity to be online by late 2021, a total investment of right around $80,000,000 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, 1 in the afternoon, 1 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 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 7 25 megawatts short by 2025, again in Montana. And considering the expiration of contracts and a modest increase in customer demand, so we think that's an appropriate that probably conservative forecast. We plan to solicit competitive all source proposals later this year for peak 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 $200,000,000 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 6,500,000 dollars That's based on a 9.65 return on equity and the capital structure as filed and also a $9,000,000 decrease in depreciation expense. Hearing was held in May. Briefing was completed in late August. In September, a staff memo recommended approval of the settlement.
And then as you heard today, there was a vote on 2 important components of the overall case, particularly a five-zero vote to approve the revenue requirement stipulation and a five-zero vote 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 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 20 21. 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 tax as 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 $20,000,000 expenditure probably $40,000,000 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 $400,000,000 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. Mavash 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 who's going to add an awful lot to the Board. I imagine most of you know Jeff Yingling. He's currently a Senior Advisor in Investment Banking for Power, Energy and 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 Mabash to the Board. And that's the end of my filibuster, except that Brian referred to the perfect storm of weather. And Brian, it sounds to me as you were describing it, it was the imperfect storm.
Yes, imperfect storm is
probably better, Bob. And with that, off to your questions.
Thank you,
sir.
First question will come from Michael Weinstein with Credit Suisse.
Hi, guys. Michael. Hey, just to make a
run at kind of a preview of what you guys are going to be talking about at EEI. With a rate increase is about $6,500,000 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 69% 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?
And 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.
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 more focused on there?
We'll provide you a nice chart with ranges in a couple of weeks. Okay, great. I'll wait until then. Thanks.
Thanks, Mike.
Thank you. Our next question comes from Julien Dumoulin Smith with Bank of America. [SPEAKER
JULIEN DUMOULIN SMITH:]
Hey, howdy. Good afternoon.
Julien. And how are you?
Hey, good, great. 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 4th quarter run rate an implicit decline a good way to think about those cost reductions you just alluded to into 2020? Am I thinking about that right?
I think it's fair to say that directionally that will help, but I don't think that will paint the full picture. And I'll stop there, Julien.
Got it. And can you elaborate on what's driving at least the Q4 here in terms of sources?
I think we I would just say this, there's certainly we went after certain expenses we talked about during the 1st 9 months of the year and we made great progress. Certainly, some of that spend, we don't expect same high levels in the Q4. And I think on a year over year basis, there are pretty high spend in the Q4 last year. I think timing is probably the best way to describe it.
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 of that given the timing for the next rate case? And that might be a backhanded way to ask you about rate case timing in your jurisdictions.
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 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.
That is a fair statement. So perhaps if I can just squeeze another real quickly here. As you think about the balance sheet side of the ledger and you've alluded to some of the South Dakota CapEx here, how do you how should we think about incremental financing needs, etcetera? 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 in South Dakota.
I would say this. We did say and Bob alluded to the fact that in our capital plans, our current plan as you see in our 10 ks and we've shown in this document as well, we do not need equity to finance that. As we add generation and approximately $80,000,000 of incremental generation will have pressure and will 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 2020 or potentially even 2020
1. All right. I'll leave it there. Thank you very much.
Thank you. Our next question comes from Brian Russo with Sidoti.
Hi, good afternoon.
Hey, Brian. Just to
clarify on the 2019 guidance of $3.38 to $3.48 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?
Yes. I would just say on a year to date basis, that's already 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.
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 20 19, which could alleviate some of those expenses beyond 2019?
Yes. I would say this, 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.
Okay. Got it. And also just to be clear, the assumption in guidance for interim rates is that beginning April 1, 2019? So you'll see a lift for new rates in the Q1 of 2020? On
a year over year basis, Q1 of 2020 versus Q1 of 2019, yes, it would be higher in 2020 because of the rates we show that go in effect, as a result of the stipulation at April 1, 2019.
Okay. So you're going to see the benefit of both the lower depreciation plus whatever the 6 point 5 $1,000,000 of annualized revenue is in the Q1? Only revenue. Only revenue. Okay.
Yes.
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 recover that and we'll just collect AFUDC in the meantime?
Yes. We'll be looking at regulatory options as there's more definition around the project. But 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.
Okay. So another option besides a rate case could possibly be a rider?
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.
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?
I'd say by the Q2.
What you say, I would say by February, I think. With February, we'd have that information by the way.
Yes. This is John Hynes. We're looking at no later than mid January at this point in time for final selection contract signed.
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?
I think for your assumption purposes, that sounds like a good way to do it.
Okay. And when can we expect comments from the Montana Commission on the supply plant that was filed in late August?
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.
Okay. So in that forum, they can convey comments?
They can't. Except not for
the they'll receive comments, but will they give comments? 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 that is incorporated in what we filed at the commission.
Okay. And then are there any brownfields sites available in or around the state of Montana?
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.
Okay, got it. Thank you very much.
Thanks, Brian.
Thank you. Our next question comes from Vedula Murti with Avon Capital.
Hi, good afternoon. Hi Vedula. Hi. 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 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?
So the revenue required and we obviously have to wait to see the specific language in the commission's order, but the vote was 50 to approve the revenue requirement stipulation, 50 to approve the stipulation concerning green pricing. There's also a stipulation pending 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 Council have 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 then there are various other rate design issues, particularly for the residential class that weren't included in the overall revenue requirement stipulation.
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 then any potential incremental refund or adjustments is unlikely, but the fact is that the current rate structure and going through until from now through April 1 when this was initiated is consistent?
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 it was unanimous and the fact that they've laid out a proposal to address the remaining issues. 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 a 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, was important and was constructive.
Okay. And I want to make sure I'm not confused in terms of I think so good to December 9th in terms of like the resource plan that you provided. My recollection is that it will simply be accepted as something that would then go through a full process because my recollection 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 doing would not be adjudicated until about this time next year. Is that correct?
John, why don't you go ahead and speak to that? Okay.
The RF or 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 plan. These are non binding 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 coal strip 12 in Montana. And so we will be moving forward with a competitive solicitation process likely at the end of Q4 here in 2019.
And then that's the after you initiate that solicitation, it will be the evaluation of solicitations 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? That's correct.
And the solicitation, as I mentioned, will be open to bill transfer to PPA 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 some 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're in a hole. We're trying to be responsible and efficient about working with others in Montana to get out of the hole.
And just so I'm clear though, I mean, when we come to a couple of weeks here in Florida and then the new report year end in February, the capital program that we currently see here, doing 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 that would be in the roll forward capital program for come late 2020 for 2021 beyond?
Yes. I would say it this way Vedula. For 2020, we can speak to that with some more clarity at EEI. For February is when we update our 10 ks 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 anything built in our capital plan for that.
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 deficit you guys are seeing or whatever. Can you kind of speak just to kind of how the environment has changed since Mr. Kabula has left? And it was kind of thought that things would be kind he was such a free market type of guy or more like wanting to have assets built by 3rd parties.
How that's whether how are you seeing things here?
Sure. Well, 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 or the commissions are really functions of the authority granted them by the legislature, number 1. Number 2, we are using competitive solicitation processes for electric supply planning both in South Dakota and in Montana. Number 3, 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.
So is this a 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?
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'll be primary elections next spring and then general elections in November of 2020 to take office in January of 2021.
Okay. Thank you very much.
Thank you. Our next question will come from Jonathan Reeder with Wells Fargo.
Hey, Bob and Brian. Just wanted to
clarify one quick thing. On the CapEx budget in your prepared remarks, Bob, did you say you expect to spend like $400,000,000 next year?
Yes. We expect our all in capital budget next year will be right around $400,000,000 yes.
And that's driven by the South Dakota opportunity and then did you say AMI in Montana?
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.
If I could, Jonathan, just for everybody, the pretty simple math is if you take 2020 from that schedule of 332,000,000 dollars at approximately $40,000,000 for the South Dakota generation and another $25,000,000 for Montana AMI, you're at $397,000,000 So in essence, that might not be exactly the number for but to Bob's point, it's going to be approximately $400,000,000
Yes. I like you breaking it down like that for a simple guy like myself. I appreciate it. Brian, if you could, can 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?
Did it go away in 2020?
Yes. I would tell you on the margin front and in both cases, unbilled are the biggest drivers. I mean, there are quite a few things that add up to the 2.3 for the quarter and the 2.1 I think for the other, if I recall those numbers. But the biggest drivers in each of those cases were unbilled that jump up for me on the margin front. On the cost side and they 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.
These things as a standalone 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.
Okay. Because yes, I mean on the cost side, I think it was like over $6,000,000 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 costs for next year?
Yes. Again, these are all costs that are under $1,000,000 that I've just specified. And some of you are 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.
Okay. And then my other question is just the lower transmission revenues. Is that going to be, I guess, kind of the new normal going forward since you said it was related to lower activities at the Coalsworth plant?
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 there's some more movement, if you will, across our lines. But I think I would put it in this context.
I don't expect us to see higher Oasis in 2020.
Okay. 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.
Okay, thanks. Look forward to seeing you guys in the
Thanks, Jonathan. Look forward to seeing you as well.
Thank you. Our next question comes from Vedula Murti with Avon Capital.
Hi. 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 things. Can you remind us the dollar value and the basis points that's usually tied to that?
Juul, I'm not sure if I'm following your question. Are you getting at generally as a whole or?
Yes. For instance, just like historically, if you're under your normal operations, if you're I'm going to make up the number, let's say you're earning, you're authorizing 9.5%. My recollection is it's like there's usually like a 70 or 80 basis point structural lag because there are expenses that simply are not granted that would then effectively turn a 9.5% into like an 8.7% or an 88% or whatever.
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.
You're talking about things like stock based compensation, for example.
Yes, yes, exactly. And there's always certain things that seem like that's always there.
And that would be the case, but again, it's pretty small.
Okay. Also I'm looking at the DD and A, it's like on an annualized basis, the entire run rate that's looking like about $175,000,000 So I'm thinking about that versus CapEx. If should is that basically going to be like fairly reasonable going forward with some modest increases or are there any major changes that should we think about with DD and A?
I think we might be able to share some more light on that at EEI, but I
Okay. All right. And one last thing, given the cost initiatives you discussed earlier and that you're just trying to get a rate stipulation approved. 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 a year so you can wait and see what happens with some of the RFPs and then contemplate a potential refiling year down.
You might have missed that earlier on the call Vedula, but I 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.
Okay. Well, thank you very much.
Thank Sir, I'm currently showing no further questions. I'd now like to turn it back over to management for closing remarks.
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.
Thank you, ladies and gentlemen. This concludes today's teleconference.