And welcome to the NorthWestern Corporation Second 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. Please go ahead, sir.
Thank you, Christina. Good afternoon, and thank you for joining Northwestern Corporation's financial results conference call and webcast for the quarter ending June 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 pre market this morning. On the call today with us are Bob Rowe, President and Chief Executive Officer Brian Bird, Chief Financial Officer and other members of the management team in the room with us 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 questions 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 contains orders such as expects, anticipates, intends, plans, believes, seeks or will. This information is presented 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. These factors that may affect our results are listed in certain of our press releases and disclosed in the company's Form 10 ks and 10 Q along with other public filings with the SEC. Following our presentation, we will open the phone lines to allow those who are 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 at northwesternenergy.com under the Our Company, Investor Relations, Presentations and Webcasts link. With that, I'll hand it over to our CEO, Bob Ruhl.
Thank you very much and thank you all for joining us. Today, we're speaking with you from Bozeman, Montana. Bozeman is one of the most the Bozeman area, including Bozeman, Big Sky and over down towards Yellowstone Park in the Paradise Valley, one of the most rapidly growing areas anywhere. 2 nights ago, we had a tremendous community event. Our Board members and community leaders, lots of discussion about the partnership in growth in this area and responsible approaches to growth and truly is a great partnership.
Also lots of appreciation for our employees' volunteer activities in Bozeman, which is true across the company. In fact, on Friday and coming back over to help with a trail build. Tomorrow, a number of our board members are going down into Yellowstone Park to meet with crews who serve that area. And whenever I'm meeting with those folks, I remind them that the 5,000,000 people who go through Yellowstone every year couldn't have the experience they do if it weren't for the service that our employees provide. Turning to 2nd quarter highlights.
Our net income for the quarter increased $3,900,000 8.9 percent as compared to the same period last year. And this increase was mainly due to an income tax benefit in 2019 and a reduction in revenue in 2018 due to impacts of the Tax Cuts and Jobs Act for customer refunds. And these improvements were largely offset by lower gross margin due to the adjustment of a qualifying facility liability and also mild spring weather along with planned higher operating expenses. Diluted EPS increased $0.07 or 8% as compared to the same period in 2018. In May, we reached a settlement with all parties who filed comprehensive revenue requirement, cost allocation and rate design testimony in our Montana electric rate review.
If the Montana Public Service Commission approves this settlement, it will result in an annual increase to electric route of approximately $6,500,000 and that's based upon a 9.65% ROE and rate base and capital structure as we file as well as an annual increase a decrease in depreciation expense of approximately $9,000,000 The Board of Directors declared a quarterly dividend of $0.575 per share payable September 30 to shareholders of record as of September 13. And with that, off to Brian.
Thanks, Bob. I have to note that the Q2, though it's a shoulder quarter or definitely our smallest quarter during the year, it did have a lot of moving parts. I'd first point out on this page and show the summary financial results for the 2nd quarter, Our gross margin was down $14,600,000 or 6.4 percent, primarily as a result of a lower QF benefit on a year over year basis. Our operating expenses were up in total $5,800,000 or 3.6 percent. The OG and A, I think higher pension, higher hazard trees, things that we forecasted to be higher in 2019 versus 2018, plus we had scheduled maintenance, that being offset to a degree by the lower depreciation Bob mentioned earlier.
Those things netted to lower operating income on a year over year basis and pretax income. Finally, we did have much lower income taxes, dollars 25,300,000 lower income taxes, primarily as a result of the release of recorded tax benefits, resulting in total net income increase of $3,900,000 or 8.9 percent. Moving on to more detail on gross margin. Total gross margin was 215,000,000 dollars 14,600,000 in the prior year period, as I mentioned earlier, down 6.4%, nearly all of that decline was in the electric segment. Decrease in gross margins due to the following factors, really three drivers, the primary drivers, if you will.
The QF liability adjustment, again, a smaller QF liability adjustment benefit in 2019 versus 2018. That's partially offset by the Tax Cuts and Jobs Act impact. If you think of it this way, there were no revenue deferrals associated with TCJA in 2019 versus 20 eighteen's deferral. And the other offset, the Montana Electric supply cost recovery, and think of that primarily as the result of the elimination of the dead band within the PCAM. And so recording that benefit for the quarter.
That and some other items led to change in gross margin of approximately $14,000,000 We do have some other items that impact gross margin, but are offset within net income as a whole, totaling $600,000 for a total decrease of 14.6 $1,000,000 for the quarter. Moving on to weather, as Bob mentioned earlier, we did have a mild Q2. You do it's the quarter where you have both heating degree and cooling degree days. To point out, from a heating degree day, we had very little heating load during the quarter and for all intents and purposes, particularly since Montana has doesn't have the same air conditioning load as you expect a lot of states, we have really effectively had no cooling load whatsoever. And as a result, again, 2nd quarter is shoulder and it's always our lowest loads for the year.
Some weather we did estimate unfavorable weather in Q2 2019 resulted in a $300,000 pre tax detriment and that as compared to normal and then a $1,100,000 pretax benefit as compared to Q2 2018. So think of 2019 as a little less worse weather than 2018. Moving on to operating expenses. Operating expenses were $166,100,000 or $5,800,000 or 3.6 percent higher than the prior year period. In the operating, general and administrative expenses, they were up $7,000,000 or 9.5 percent.
I'll discuss that a little bit more below. Property taxes were up slightly primarily due to additional additions to PP and E. And depreciation and depletion were down 2,500,000 dollars as a result primarily of the adjustment consistent with the proposed settlement in our Montana Electric case. A little more detail on the OG and A expenses. We did have $3,000,000 of the $11,200,000 of change in OG and A that impact net income, dollars 3,000,000 of that was generation maintenance expense.
All of that was all planned maintenance that did that occurred in 2019 that didn't occur in 2018, thus the increase on a year over year basis. As we discussed, we're certainly spending more on hazard trees and we're spending more on employee benefits, primarily pension in that regard. And just to remind folks, we've made it clear from a trending perspective that we do expect to have $4,000,000 more pension expense in 2019 versus 2018 on a full year basis and $4,000,000 to $6,000,000 more hazard tree expense in 2019 versus 2018. Those items I mentioned, maintenance generation, maintenance expense, hazard trees and employee benefits are primary drivers of that $11,200,000 We do also have items that change OG and A, but they're offset elsewhere within the P and L, leaving us to the net impact of a $7,000,000 increase in OG and A. Moving on to operating income, I mentioned that's down.
It's down $20,400,000 or 29.5 percent. Below that interest expense up slightly primarily due to higher borrowings. Other income, there's some moving parts there. Obviously, we mentioned the slight change due to the deferred comp and pension offset in OG and A and those items were partly offset by AFUDC during the quarter. And that gets us a pretax income down 21.4 $1,000,000 or 45.6 percent for the quarter.
Below that though, again, the income tax benefit, the $25,300,000 and again that's primarily driven by the $23,200,000 of unrecognized tax benefits recorded during the quarter. And I'll talk about tax reconciliation on the next page. And regarding that, you see the 25.3 $1,000,000 benefit at the bottom of that page on a year over year basis. The primary drivers, of course, we talked about the unrecognized tax benefit of $23,200,000 but we also did have lower pretax near the top of the page, dollars 4,500,000 benefit there. Those are partly offset by lower flow through and production tax credits for the quarter.
I wouldn't acknowledge that those items are relatively close on a year over year basis on a year to date basis. Last thing I'd just say about income taxes, you may have seen in our 10 Q that we are expecting negative 7% to negative 12% ETR on a GAAP basis for the year. And we also reiterate the 0% to 5% ETR on a non GAAP basis for the year. Moving forward to the balance sheet. A little change to the balance sheet on a year to date basis.
PP and E is up approximately $100,000,000 and think of that being offset liabilities and equity about $50,000,000 increase to debt and $50,000,000 increase to shareholders' equity. At the bottom of the page, we did have a slight reduction in our debt to cap on a year to date basis. Moving on to the cash flow statement. We did see a significant decrease, if you will, in cash provided by operating activities on a year over year basis, almost all driven by changes in working capital. We do a good job to the right to identify what those big drivers are.
But again, approximately 80% of that change in the $100,000,000 reduction in working capital, dollars 80,000,000 of that is $39,000,000 is really a swing from an over collection position in 2018 to an under collection position in 2019. We also had to refund the customers approximately $20,000,000 associated with TCJA that was in the beginning of 2019, so on a 6 months year to date basis. And then lastly, we have been providing folks that interconnect to our system that make deposits as they those QS come in line, we refund those deposits that was approximately 19 on a year to date basis. So there was a significant change there. We did also have a higher PP and E additions during the quarter and those items were funded by certainly issuance of debt higher than we had in the prior year basis.
Moving forward to adjusted non GAAP earnings. Very quickly, what were the items in for the quarter in 2019? We had slightly unfavorable weather. We talked about that effectively a penny associated with unfavorable weather. But we did remove $0.45 associated with the unrecognized tax benefit.
And so moving from $0.94 to $0.50 that comparative to a prior year period where we had unfavorable weather and the QF gain, went from $0.87 to $0.63 So comparatively $0.50 down from $0.63 on a non GAAP basis the prior year. One thing I'd point out primarily for the quarter, though results on a non GAAP basis are down on a year to date basis or a year over year basis, excuse me. We are actually quite pleased with our results on a year to date basis. Those are relatively flat on year over year basis. We do anticipate certainly on year end to manage results to provide a total shareholder return expectations that we've communicated to the Street.
I'd also say we've had good progress certainly on the PCAM release and great legislative outcome there. We've had good progress on the rate case. We've been addressing hazard trees and the pension expense and expenses we certainly needed to go after and feel really good about the quarter as a whole and certainly where we sit year to date as a whole. And with that, I'll give it back to Bob.
Thanks, Brian. And just following up on the point where Brian left off, I'll give you a preview of some of the things we're working on, and I know you'll have questions after that. Regulatory front, of course, the last 2 months have been all about the Montana Electric Rate Review, where we did reach a settlement with the major interveners and settlements involved an increase to revenues of $6,500,000 based upon a 9.65% return on equity, coupled with a decrease in depreciation expense of $9,000,000 and we expect to file an order from the commission during the Q4. In May, we submitted a filing with the Federal Energy Regulatory Commission for our Montana transmission assets. In June, the FERC issued an order accepting the filing and also granting interim rates effective July 1 and of course subject to refund And they established settlement procedures as well as terminating our related Tax Cuts and Jobs Act filing.
As you know, FERC has a robust settlement process, a settlement judge has been appointed. We expect the 1st settlement conference to take place in early August. As Brian mentioned, on the legislative front, which we had a very successful legislative session in all of our states, but particularly in Montana. And there, our real focus was trying to bring the legislative electric supply tracker to back in line with what the legislature had really intended in 2017. And in fact, the legislature did revise the cost recovery statute to prohibit deadband and to require 100% recovery of qualifying facility purchases as well as a 90% customer, 10% shareholder overall sharing of costs above or below an established baseline.
We continue to invest in our transmission and distribution infrastructure. I mentioned the growth we're seeing, particularly in our Bozeman division. That is certainly a part of it. But more generally, on both the gas and electric side, we're investing to ensure safety, capacity and reliability. In addition, on the natural gas side, pipeline investments are driven by safety compliance requirements.
We take those very seriously. And then finally, grid modernization and resilience, and that includes an advanced distribution management system and advanced metering infrastructure. And on the advanced metering, we have a deployment underway in South Dakota and Nebraska, essentially moving from north to south. And based on that, we will, in the coming years, shift to a deployment in Montana. Very, very big undertaking jointly between our electric supply and electric transmission teams is moving into the Western energy imbalance market.
And you see the map of the Western participants on Page 13 of the deck. Challenge for us was that as we've discussed over the months, we sit on the far eastern edge of the western interconnect, and we needed to make decisions that were appropriate for our customers and for our system that we do see significant benefits to our customers from moving into the Western market. And then, of course, ongoing cost control efforts, monitoring costs, including labor benefits, property tax. As Brian mentioned, we've made several important commitments over the last few months that we think are appropriate over the long term pension and building on our already very robust efforts to deal with vegetation management. Turning then to energy supply resources and other critical responsibility.
Our South Dakota Electric Supply Plan is well into implementation. The plan was published last fall, focusing on modernization of the fleet to improve reliability, flexibility and to maintain compliance with our obligation in the Southwest Power Pool. And Montana and South Dakota are non electrically interconnected. Over the last several years, we have moved into SPP, and we're not really seeing benefits there. But in significant part, our South Dakota plan is focused on meeting the compliance requirements in SPP, but also being able to get the real benefit out of full participation.
So the plan identifies 90 megawatts of existing generation that should be retired and replaced over the coming decade. On April 15, we issued a request for proposals for 60 megawatts of flexible capacity to serve South Dakota and beyond line by the end of 2021. Responses are due actually by the end of this week. And using a third party, we'll be evaluating proposals with outcomes determined by the end of the year. The Montana Electric Supply Plan, a draft was released in March.
We will be finalizing that in the Q3. It's an extensive comprehensive document, an awful lot of input, very good analysis went into that. The plan supports the goal of developing resources that will address the changing energy landscape in the West, the Pacific Northwest and specifically in Montana. And that landscape is changing rapidly. We have plenty of energy.
We are severely challenged in terms of meeting capacity needs. And that's true throughout the Northwest, driven in significant part by plant retirements. It's doubly or triply true in Montana because we have still a negative 27% or so capacity margin. We're the only we continue to be the only electric company in the West with a negative margin. And in part, that's a result of continued legacy from deregulation and divestiture in the late 1990s.
We made a lot of progress in really communicating the exposure that our customers face during peak times in the summer, during peak times in the winter. The analysis that our supply department has undertaken emphasizes that the risk is a price risk and we see that when we are in the market on behalf of our customers during periods of peak. But increasingly with plant retirements and growth in peak demand, it is a reliability risk as well. Currently, 6 30 megawatts short of
your peak, we're in the
market to procure that. But even with strong assumptions around growth and efficiency and alternate delivery models, we got conservative estimate is that we could be 7 25 megawatts short, really in just a very few years, 2025. So we expect to file the plan in the coming weeks. We will continue to communicate with our customers and decision makers about the approach and the plan, the identified need and the risk. And then we will move to the first of several all source proposals late in this year seeking peak capacity to be available by the end of 2022.
And I emphasize again that it will be for any resource, any kind of resource to meet our customers' needs. We expect, just as we did in South Dakota, we would use an independent third party to conduct the RFP
as a result of the
fact that there will be an RFP, in well, it will be and is in South Dakota. We haven't included this associated capital investment in the 5 year forecast. But obviously, these additions could increase our capital spending over that 5 year horizon. And turning to the capital forecast, we anticipate $1,600,000,000 total capital over the 5 years, continue to be funded with a combination of cash flows supported by NOLs that will be available now through 2020 as well as long term debt issuances. As we say every quarter, it seems significant capital not included in the above projections could or further negative regulatory actions either 1 could necessitate additional equity issuances.
The point of the 5 year capital forecast is to continue to meet the needs of our customers for safe, reliable service, adequate capacity to meet their needs today and in the future. And as always, you see over time, the identified capital projects really appropriately distributed by jurisdiction and by function as well. With that, we will open it up to your questions.
Thank We'll take our first question from Michael Weinstein with Credit Suisse.
Hi, guys.
Hi, Mike.
Hi, Mike. Hi. Sorry if you covered this before, maybe I missed it. But on Colstrip, Unit 34, I understand you're in negotiations with Westmoreland over coal pricing. And I'm just wondering what the status of that is?
Like when do you think you'll have something locked down, you'll be able to say that, that plant is going to be operating?
I'd say we're in a good position in terms of reaching a final coal contract that's based on, I think, constructive management new management at Westmoreland is the management new management at Westmoreland is pursuing. So we feel actually quite good about being able to announce a coal contract in the near future.
Got it. And also on the unrealized tax benefits this quarter, are there any
other situations that are similar to that that are awaiting a statute of limitations to expire going forward?
Well, if
you've noted, we've got $35,000,000 noted, but there's no timetable associated with that. If in fact, there's a timetable, you usually talk about that a year in advance of anything like that. And if you see the language, we don't have any language associated with anything in the near future. Got you. Okay.
Thank you very much.
Thanks, Mike. Thanks, Mike.
And we'll take our next question from Julien Dumoulin Smith with Bank of America.
[SPEAKER JULIEN DUMOULIN SMITH:]
Hey Julien.
This is
actually Ryan Greenwald on for Julien. Hey, Ryan. How is it going?
Good.
Thanks for taking our questions. So as you guys progress with the plans in South Dakota and Montana, I know you're still saying at least $200,000,000 in opportunities, but are you able to provide a little more color on the cadence around potential investments?
No, not really. And the RFP, as we've discussed, administered by a third party, the focus is on meeting the identified needs. And I really don't think we can say anything more than that at this time. Certainly, we will be able to share more detail over the coming months.
Fair enough. But would you be eligible to own the whole amount potentially?
I would say we will have the opportunity to participate in the RFP and we expect that we're putting forward very solid proposals.
Got it. And I guess to set a little differently with respect with regards to Montana,
You said
that the 7 25 megawatts is conservative. How high could that potentially go?
I just don't even want to speculate on that. We've got such a big hole to climb out of. I think that needs to be the focus. And the point I was making was that we were making assumptions about continued success for things like energy efficiency programs.
Got it. And then just lastly, in terms of the Montana supply plan, it anticipates coal strip remains supply source, right?
Correct.
What's the contingency plan if a new supply contract can't be reached?
For a new coal contract?
Yes.
At this point, we're feeling better and better as I mentioned that we will reach a good outcome on the gold contract.
Got it. And if I could just ask one more. With regards to the tax rate, you guys are saying 0% to 5 percent and then gradually increasing to 10% to 11% in 2023. Is that still kind of the current trajectory or has that changed?
Yes, by 2023, as you said that's what you said, correct? I did. It's up by around 10% by that time period, yes.
Got it. Thanks a lot guys.
And we'll take our next question from Chris Ellinghaus with Williams Capital.
Hey, guys. Good afternoon. Hey, Chris. Brian, I believe you said that you decreased depreciation and amortization by $4,500,000 I assume that is inclusive of your sort of pro rata portion for the Q1 as well?
It is from a year to date basis where we sit from a depreciation perspective.
Okay.
As far as the supply cost recovery for
the quarter, that's not all entirely from the Q2. That includes some prior period recovery, I assume?
Are you speaking to the deadband recovery itself?
I think,
hang on, let me see if I can find the numbers, dollars 4,500,000 or something like that, dollars $5,600,000
Yes. We look at when we recorded, obviously, the dead band impact was in 2018. We looked at the dead band is from a tracker period from 7.1 of 2019 to 6.30 or 2018 to 6.30 of 2019. And so from our perspective, last year, we had no adjustments associated with PCAM on a non GAAP basis. And this year, we have no adjustments to from a PCAM on a non GAAP basis.
Okay, great. Bob, as far as the RFP goes for Montana, I assume you don't want to talk about what the capacity number is, but can you give us any kind of sense of what proportion of that 630 megawatts is that equates to your $200,000,000 of CapEx potential?
Well, I would be uncomfortable going there if I understand what you're asking.
Yes, basically trying to figure out how much that relates to. And then the $200,000,000 is just a 5 year horizon and sort of if I recall the draft supply plan, there's a good piece that comes at right after that 5 year horizon, if I'm not mistaken, is that right?
Yes. The $200,000,000 is associated with the $5,000,000 and just Chris, I just want to make sure we're not talking past each other. The $200,000,000 we talked about is both kind of Montana and South Dakota, just to be clear.
Yes. Yes. But you gave us the 60 megawatts for South Dakota. So you could back into the rest. But I think the supply draft, there was another piece coming in 2025, if I remember correctly,
A bigger piece? You're saying from Montana's perspective or South Dakota now?
Montana.
Yes. I think you're going to see in both places we're going to have significant amount of investment in Montana certainly by 2025. And that full 90 megawatts that we talk about in South Dakota should be around there shortly thereafter. Okay.
If it wasn't for your capacity needs and just the changing dynamics in the region, would you have any I don't know what's the right way to say it is. You don't have any reason why additional renewables aren't in your draft plan other than the current specific capacity needs. You would be interested in additional renewables when you've set your capacity equivalency requirements in the future?
The plan doesn't identify any particular resource. And to me, the word renewable is a little bit slippery. As you know, in Montana, existing hydro isn't renewable. So I think rather than a label, I would focus on the attributes of a resource and you could include environmental attributes. As you know, in the Montana plan, we have various carbon related scenarios too.
But obviously, in terms of the conventional renewables, solar and wind, there's a lot on or poised to come on our system through the QF process. And then more broadly in terms of our portfolio in Montana right now, we're 70% carbon free and a lot of the resources we have in the Montana portfolio online in Montana provide little or no benefit to help us meet our peak. The hydro system obviously does.
Okay. Thanks for the details guys. Appreciate it.
Thank you. Thanks, Chris.
We'll take our next question from Vedula Murti with Avon Capital.
Good afternoon.
Hey, Avon.
A few things here just to make sure I understand. 1, given the difference between the interim rates that was granted and the settlement amount, are you reserving the difference or are you simply booking only the settlement amount and revenues as you're in the fashion like you're recognizing depreciation expense that's reflected in the settlement?
We're our accounting estimate is at the $6,500,000 not the interim rates. The $6,500,000 stipulated with the parties associated with the rate case. So we're booking to that level, not the interim rates.
Okay. So then so okay. So while there will be a true up on a cash basis on a financial statement basis, you're already reflecting the lower settlement amount? Correct. Okay.
When you talk about sources and uses of cash for CapEx, you say specifically about the aided by NOLs available into 2020. What happens when can you remind me the amount of NOLs that are available right now in 2019 2020 as part of sources that will not be available on a go forward basis then?
Well, I'll get you that number in a second Vedula. But yes, we do plan to eat through our NOLs at that point in time as noted. And we continue to try to manage our taxes as best we can to minimize our taxes. But I'll get you that number in a moment.
Okay. Let's see. You talked about the legislative session and the successes there, Especially with the QF recovery and the now ninety-ten on power costs. If we look forward in the second half of this year, if you're recovering full out QF recovery, is there a benefit or is there a benefit that you'll see over the second half because you didn't recover last year when we see variances?
Could you repeat that question? First of all, I'll answer your NOL question. It's $257,000,000 that's left. But could you repeat that last question?
The last question was, now that you're able to fully recover QF incurred costs, if we look forward to 3Q and 4Q, if you're recovering 100%, is there a benefit to you for in comparisons because there was an amount perhaps in last year's 3Q and 4Q that you didn't recover that will aid you in the second half?
And I don't anticipate that would be a material benefit that you could show on a year over year basis.
Okay. And you said the NOLs were $257,000,000 Well, I guess what I'm really trying to get a sense of is, if I go forward from, say, 2020 to 2021, in terms of the cash flow effect, in terms of the reduction of cash flow?
Yes. I can't give you that idea in terms of what that impact would be in 2021 at this point in time.
The slide implies that basically does do 0 and then going forward at 0?
Yes. We still have some PTCs and AMT benefit, but I'm not comfortable giving you an exact dollar amount at this point in time.
Okay. And I guess in terms of the in excess of $200,000,000 over the next 5 years, That basically would that fully just cover the pending South Dakota RFP and the soon to be initiated RFP in Montana? It's just those two items.
It would be our the first two RFPs that you'd see, one from South Dakota and one from Montana.
And in terms of that capital, is it reasonable to think that the proportionality of South Dakota relative to Montana is similar to what we see in the capital program, which is generally 10% to 15%. So if we're thinking of in excess of $200,000,000 that in theory, 10% to 15% of that realistically would be considered South Dakota?
I think I would say we've given pretty much pretty good guidance already on the $200,000,000 as is. I would just tell you obviously on a going forward basis, the opportunity set in Montana is significantly higher than
it is in South Dakota. And that's for two reasons, obviously. The Montana jurisdiction is larger, but secondly, the whole arena is just that much deeper.
No, I understand, especially that this is only Phase 1, I get that. What I'm really trying to make sure I've kind of baseline is the $200,000,000 related to what exactly? I'm just I guess in a way to kind of going back to what the clarification I think Chris was requesting in relation to the total shortages versus what this first period would attempt to address?
Vijil, I've given you as much guidance as I can on that 200,000,000
dollars Okay. All right. Okay, thank you very much.
And we'll take our next question from Jonathan Reeder with Wells Fargo.
Hey, how's it going?
Good, Jonathan.
Hey, just one question for me. The Montana supply resource plan, it seems like it keeps kind of slipping when you're actually filing it. Can you kind of outline what's going on, why it has gotten kind of pushed back and if there's anything we should read into that, whether good or bad?
Oh, gosh. No. What I would say is we prepared a draft plan. We posted that for public comment. We received a very robust comment.
Our supply folks are analyzing those and the plan is nearly ready to hit the streets. So I don't I'm not at all concerned about delay. What I would say, going back to the 20 15 plan, and there was a lot of noise at the end of that plan. And ultimately, we weren't able to implement the RFP that we went out with after that plan. And that's a shame because subsequent events, the real capacity needs that have been exposed both summer and winter just demonstrated how critical it is to move ahead.
And it's a shame from our customers' perspective that we weren't able to move ahead on the RFP following up on the 2015 fund. I really do feel very, very good about where we are with this year's plan.
Okay. So when you do have a final plan, Bob, I mean, do you feel there will be kind of a consensus throughout much of the state at least, what the needs are and how to move forward like by operating those party comments and working with
your other constituents?
What we've done is a plan that really is focused on identifying the need. And we have various scenarios that are modeled. I've referred to those before. But ultimately, any project of any kind that is able to help us meet our customers' needs, we'll have the opportunity to bid in, be evaluated by a third party. And certainly, there will be there are strong views about what resources are best able to meet the need.
But at this point, I certainly hope that experience even over the 2 years should lead thoughtful people to agree on what the need is. And I'll highlight just a couple of things there. Within the Northwest region, there are now multiple studies, including by very reputable, really environmentally oriented firms such as E3 identifying the current and growing capacity needs. Randy Hardy, former BPA administrator, wrote another paper just describing how the region has been leaning on the investments made, the resources built going back to the 1950s. That actually includes supply resources, but also truly transmission resources.
The Montana Commission has spent time now looking at some of those reports. There was a great joint presentation by E3 and our transmission department and our supply department talking about the capacity needs. Just last month, Chairman Johnson of the commission wrote an op ed that was carried around the Montana newspaper that said Montana needs base load power. And that's a real change in tone. And I think a recognition by the commission, certainly recognition by other policymakers around the state that we have a need.
And again, there'll be plenty to discuss and debate over how best to meet that need. But I can't imagine anyone looking at the situation not recognizing we have a reliability need, from reliability risk and a price risk if we don't move ahead to address the capacity need.
Thanks for the answer. And then, Bob, any more kind of activity around resurrecting kind of coal strip longer term with, I guess, that need for baseload power? Or is that still kind of let's get the settlement approved and all that and then maybe go back and revisit
it? Colstrip is a valuable resource within a diverse portfolio. The concept that was considered in the legislature, actually had a lot of support, was a good concept, would have produced an immediate net savings for our customers, would have taken down an increment and far, far, far from the majority, but an increment of the exposure we had would have addressed the transmission risks that we face as well and really would have used that resource as a bridge to resources that are emerging now, but that are currently in many cases, not very attractive from a cost performance. So it's a resource and approach that was compelling when the legislature was in session. It's still compelling
now. Okay.
Thanks so much, Randy.
But the focus right now really is on to the earlier question, getting the plan filed and moving ahead.
Okay, great.
Thanks Bob.
Thank you.
We'll take a follow-up question from Vedula Murti.
When you get the plan, when you put out the proposal in late 2019 for Montana, how long will the turnaround be before the actual conclusion is reached?
Well, let's say the plan is released and filed in the next month or so. We want to go out for an RFP later this year and move ahead on that. And there's no reason to believe that, that RFP would have to be interrupted the way the RFP coming out of the following plan was. And then we moved from there to selection and hope to see a good outcome in terms of resource choice.
So we'd know the outcome of that say mid-twenty 20?
I'd say that seems reasonable. Of course, we don't know what happens between now and then, but that's I think a reasonable guess.
Yes. I think the main thing there is the timing associated with when that will make an outcome there. Clear thing is we have to have that capacity in by the end of 2022. So it's important for us to get going.
We need resources in order to participate in the imbalance market.
Okay. And as I recall, there are times where various policymakers, regulators, etcetera have raised questions about the desirability of the utility to own assets as opposed to simply contracting from third parties to meet these needs. I'm wondering how that may how that type of thought may have evolved and whether you're able to compete equally on an equal comparable footing with any third party as part of this process such that there's no that type of historical bias for lack of a better term is not relevant?
Yes. There are roles for contracted resources and for owned resources and they are complementary. If you take a look at how deep we are in the market at periods of peak and what is happening in that market, it's pretty tough to make the argument that we ought to be more exposed to the market than we already are. And I think honestly, people who lean too heavy too heavily on a market solution to meeting our peak needs are not very in touch with recent history in Montana. And as you know, that the defining act in that history was deregulation and divestiture of supply, leaving us exposed to the market.
The responsibility we have to our customers is to plan long term and the least cost actually really is what we organize around.
And in this RFP, whatever the physical capacity is that ends up being determined. To your point in terms of relying on the market, if it's new physical resources that actually are added to the system, is there an advantage or an imperative that you own it as opposed to a 3rd party building it and basically contract even you contract it from?
3rd parties will be on an equal footing with any proposal we make. And the 3rd party administrator to the process will ensure that.
Okay. All right. Thank you.
Thank you.
It appears there are no further questions at this time.
Great. Well, thank you very much for the very good discussion and your interest and support. I will be seeing many of you over the coming months.