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, thank you for joining NorthWestern Corporation's financial results conference call and webcast for the quarter ending June 30th, 2019. NorthWestern's results have been released, 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, 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 words 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-K 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 archive replay of today's webcast will be available for one year beginning at 6:00 P.M. Eastern today and can be found on our website at northwesternenergy.com under the Our Company, Investor Relations, Presentations and Webcast link. With that, I'll hand it over to our CEO, Bob Rowe.
Thank you very much, and thank you all for joining us. Today, we're speaking with you from Bozeman, Montana. The Bozeman area, including Bozeman, Big Sky, and over down toward Yellowstone Park in the Paradise Valley, one of the most rapidly growing areas anywhere. Two 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, I'm 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 our crews who serve that area.
Whenever I'm meeting with those folks, I remind them that the 5 million 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 second quarter highlights. Net income for the quarter increased to $3.9 million, 8.9% as compared to the same period last year. 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. 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 revenue of approximately $6.5 million, and that's based upon a 9.65% ROE and rate base and capital structure as we filed, as well as an annual decrease in depreciation expense of approximately $9 million. The board of directors declared a quarterly dividend of $0.575 per share, payable September 30th, to shareholders of record as of September 13th. With that, off to Brian.
Thanks, Bob. I have to note that the second quarter, 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 is so the summary financial results for the second quarter. Our gross margin was down $14.6 million or 6.4%, primarily as a result of a lower QF benefit on a year-over-year basis. Our operating expenses were up in total $5.8 million or 3.6%. The O&M, think higher pension, higher hazard trees, things that we've 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 pre-tax income.
We did have much lower income taxes, $25.3 million lower income taxes, primarily as a result of the release of unrecorded tax benefits, resulting in total net income increase of $3.9 million or 8.9%.
Moving on to more detail on gross margin. Total gross margin was $215 million, $14.6 million in the prior year period, or as I mentioned earlier, down 6.4%. Nearly all of that decline was in the electric segment. Decrease in gross margin is 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 deferral associated with TCJA in 2019 versus 2018's deferral. The other offset, the Montana electric supply cost recovery. Think of that primarily as the result of the elimination of the dead band within the PCCAM, and so recording that benefit for the quarter.
That and some other items led to a change in gross margin of approximately $14 million. 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 million for the quarter. Moving on to weather. As Bob mentioned earlier, we did have a mild Q2. 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. For all intents and purposes, particularly since Montana doesn't have the same air conditioning load as you'd expect a lot of states, we really effectively had no cooling load whatsoever. As a result, again, second quarter 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 $1.1 million pre-tax benefit as compared to Q2 2018. Think of 2019 as a little less worse weather than 2018. Moving on to operating expenses. Operating expenses were $166.1 million or $5.8 million or 3.6% higher than the prior year period. In the operating general administrative expenses, they were up $7 million or 9.5%. I'll discuss that a little bit more below. Property taxes were up slightly, primarily due to additional additions to PP&E. Depreciation and depletion were down $2.5 million as a result primarily of the adjustment consistent with the proposed settlement in our Montana electric case. A little more detail on the O&M expenses.
We did have $3 million of the $11.2 million of change in O&M that impact net income. $3 million of that was generation maintenance expense. All of that was all planned maintenance 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. Just to remind folks, we've made it clear from a trending perspective that we do expect to have $4 million more pension expense in 2019 versus 2018 on a full year basis and $4 million-$6 million more hazard tree expense in 2019 versus 2018. Those items I mentioned, maintenance generation, maintenance expense, hazard trees, employee benefits are primary drivers of that $11.2 million.
We do also have items that change O&M, they're offset elsewhere within the P&L, leading us to the net impact of a $7 million increase in O&M. Moving on to operating income. I mentioned that's down. It's down $20.4 million or 29.5%. Below that, interest expense up slightly, primarily due to higher borrowings. Other income, there's some moving parts there. Obviously, we mentioned a slight change due to the deferred comp and pension offset in O&M, those items were partly offset by AFUDC during the quarter. That gets us to pre-tax income down $21.4 million or 45.6% for the quarter. Below that, though, again, the income tax benefit, the $25.3 million, again, that's primarily driven by the $23.2 million of unrecognized tax benefits recorded during the quarter. I'll talk about tax reconciliation on the next page.
Regarding that, you see the $25.3 million 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, the 23.2, but we also did have lower pre-tax near the top of the page for $4.5 million benefit there. Those are partly offset by lower flow-through and production tax credits for the quarter. I would 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 a -7% to -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. Little change to the balance sheet on a year-to-date basis.
PP&E is up approximately $100 million. Think of that being offset liabilities and equity, about $50 million increase to debt and $50 million increase to shareholders' equity. At the bottom of the page, we did have a slight reduction in our debt to capital on a year-to-date basis. Moving on to the cash flow statement. We did see a significant decrease, if you will, of 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. Again, approximately 80% of that change in the $100 million of reduction in working capital, $80 million of that is $39 million, 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 million associated with TCJA.
That was in the beginning of 2019, on a six months year-to-date basis. Lastly, we have been providing folks that interconnect to our system, that make deposits as those QFs come in line, we refund those deposits. That was approximately $19 on a year-to-date basis. There was a significant change there. We did also have a higher PP&E additions during the quarter, and those items were funded by certainly issuance of debt higher than we had on the prior year-basis. Moving forward to adjusted non-GAAP earnings. Very quickly, what were the items for the quarter in 2019? We had slightly unfavorable weather. We talked about that, effectively $0.01 associated with unfavorable weather. We did remove $0.45 associated with the unrecognized tax benefit. Moving from $0.94 to $0.50.
Comparative to a prior-year period where we had unfavorable weather and the QF gain, where it went from $0.87 to $0.63. 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 a year-over-year basis. We do anticipate, certainly on year-end, to manage results, provide total shareholder return expectations that we've communicated to the Street. I'd also say we've had good progress, certainly on the PCCAM release and great legislative outcome there. We've had good progress on the rate case. We've been addressing hazard trees and pension expense, some expenses we certainly needed to go after.
Feel really good about the quarter as a whole and certainly where we sit year-to-date as a whole. With that, I'll give it back to Bob.
Thanks, Brian. 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 two months have been all about the Montana electric rate review, where we did reach a settlement with the major interveners. Settlement involved an increase to revenues of $6.5 million, based upon a 9.65% return on equity, coupled with a decrease in depreciation expense of $9 million. We expect a final order from the commission during the fourth quarter. 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.
They established settlement procedures, as well as terminating our related Tax Cuts and Jobs Act filing. As you know, the FERC has a robust settlement process. A settlement judge has been appointed. We expect the first settlement conference to take place in early August. As Brian mentioned, on the legislative front, we actually had a very successful legislative session in all of our states, but particularly in Montana. 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. 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. 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. Then finally, grid modernization and resilience. That includes an advanced distribution management system and advanced metering infrastructure. On the advanced metering, we have a deployment underway in South Dakota and Nebraska, essentially moving from north to south. Based on that, we will, in the coming years, shift to a deployment in Montana. Very big undertaking jointly between our electric supply and electric transmission teams is moving into the Western Energy Imbalance Market. 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 Interconnection, and we needed to make decisions that were appropriate for our customers and for our system. We do see significant benefits to our customers from moving into the Western market. 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 two 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 to energy supply resources, another 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. Montana and South Dakota are not electrically interconnected. Over the last several years, we've moved into SPP, and we are really seeing benefits there. 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. The plan identifies 90 MW of existing generation that should be retired and replaced over the coming decade. On April 15th, we issued a request for proposals for 60 MW of flexible capacity to serve South Dakota and be online by the end of 2021. Responses are due actually by the end of this week.
Using a third party, we'll be evaluating proposals with outcomes determined by the end of the year. The Montana electric supply plan draft was released in March. We will be finalizing that in the third quarter. It's an extensive, comprehensive document. An awful lot of input, a very good analysis went into that. The plan supports the goal of developing resources that will address the changing energy landscape in the West Pacific Northwest and specifically in Montana. 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 continue to be the only electric company in the West with a negative margin.
In part, that's a result of a 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. Increasingly with plant retirements and growth in peak demand, it is a reliability risk as well. Currently 630 megawatts short at peak. We're in the market to procure that. Even with strong assumptions around growth and efficiency and alternate delivery models, a conservative estimate is that we could be 725 megawatts short, really in just very few years, 2025.
We expect to file the plan in the coming weeks. We will continue to communicate with our customers and decision makers about the approach in the plan, the identified need, and the risk. 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. I emphasize again that that will be for 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, will be and is in South Dakota, we haven't included the associated capital investment in the five-year forecast. Obviously, these additions could increase our capital spending over that five-year horizon.
Turning to the capital forecast, we anticipate $1.6 billion total capital over the five 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, or further negative regulatory actions, either one, could necessitate additional equity issuances. The point of the five-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. 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 you. If you would like to ask a question, please signal by pressing star one on your telephone keypad. If you are using a speakerphone, please make sure your mute function is turned off to allow your signal to reach our equipment. Again, press star one to ask a question. We'll take our first question from Michael Weinstein with Credit Suisse.
Hi, guys.
Hey, Mike.
Hey. Sorry if you covered this before, maybe I missed it. On Colstrip unit three and four, I understand you're under negotiations with Westmoreland over coal pricing, I'm just wondering what the status of that is. When do you think you'll have something locked down, you'll be able to say that that plant's 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 discussions with the other owners and also a very constructive approach that the new management at Westmoreland is pursuing. We feel actually quite good about being able to announce a coal contract in the near future.
Got it. Also on the unrealized tax benefits this quarter, are there any?
Yes
other situations that are similar to that are awaiting statute of limitations to expire going forward?
Well, you've noted we've got $35 million noted, but there's no timetable associated with that. If in fact, there's a timetable, you usually talk about that one year in advance of anything like that. 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.
We'll take our next question from Julien Dumoulin-Smith with Bank of America.
Hey, Julien.
This is actually Ryan Greenwald on for Julien.
Hey, Ryan.
How's it going?
Good.
Thanks for taking our question. As you guys progress with the plans in South Dakota and Montana, I know you're still saying at least $200 million in opportunities, but are you able to provide a little more color on the cadence around potential investments?
No, not really. The RFP, as we've discussed, administered by a third party, the focus is on meeting the identified needs. 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. Would you be eligible to own the whole amount potentially?
I could say we will have the opportunity to participate in the RFP, and we expect that we'll be putting forward very solid proposals.
Got it. I guess, said a little differently with regards to Montana. You said that the 725 megawatts is conservative. How high could that potentially go?
Boy, I 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. The point I was making was that we were making assumptions about continued success for things like energy efficiency programs.
Got it. Then, just lastly, in terms of the Montana supply plan, it anticipates Colstrip remains the 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 coal contract.
Got it. If I could just ask one more. With regards to the tax rate, you guys are saying 0%-5% and then gradually increasing to 10%-11% in 2023. Is that still kind of the current trajectory, or has that changed?
By 2023, that's what you said, correct?
Yes.
Around 10% by that time period. Yes.
Got it. Thanks a lot, guys.
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 $four and a half million. I assume that is inclusive of your sort of pro rata portion for the first quarter 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 second quarter. 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 number. It's four and a half million dollars or something like that, $4.6 million.
Yeah. When we recorded, obviously, the deadband impact was in 2018. We looked at the deadband as from a tracker period from 7/1/2019 to 6/30/2018 or 6/30/2019. From our perspective, last year, we had no adjustments associated with PCAM on a non-GAAP basis, and this year we have no adjustments 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 million of CapEx potential?
Well, I would be uncomfortable going there if I understand what you're asking.
Yeah. I'm basically trying to figure out how much.
Yeah
relates to. Then the $200 million is just the 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?
Yeah. The 200 is associated with the five-year. Just, Chris, I just want to make sure we're not talking past each other. The 200 we talked about is both kind of Montana and South Dakota, just to be clear.
Yeah. You gave us the 60 megawatts for South Dakota, so to get back into the rest. I think that 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.
Yeah. I think you're going to see in both places, we're going to have a significant amount of investment in Montana, certainly by 2025. That full 90 megawatts that we talk about in South Dakota should be around there or shortly thereafter.
Okay. I don't know what 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. To me, the word renewable is a little bit slippery. As you know, in Montana, existing hydro isn't a renewable. I think rather than a label, I would focus on the attributes of a resource. You could include environmental attributes. As you know, in the Montana plan, we have various carbon-related scenarios, too. 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. 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 Vidula Mirchi with Avon Capital.
Good afternoon.
Hey, Vidula.
A few things here just to make sure I understand. One, 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?
Our accounting estimate is at the $6.5 million, not the interim rates. The $6.5 stipulated with the parties associated with the rate case. We're booking to that level, not the interim rates.
Okay. 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. Can you remind me the amount of NOLs that are available right now in 2019 and 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, Vidula. Yeah, we do plan to eat through our NOLs at that point in time as noted. We continue to try to manage our taxes as best we can to minimize our taxes. 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 90/10 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, to answer your NOL question, it's $257 million that's left. 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 three Q and four Q, if you're recovering 100%, is there a benefit to you in the comparisons? Because there was an amount perhaps in last year's three Q and four Q that you didn't recover, that will aid you in the second half.
I don't anticipate that would be a material benefit that you could show on a year-over-year basis.
Okay. When you said the NOLs were $257 million, 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.
Yeah, 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 it basically goes to zero and then going forward is zero.
Yeah. 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. I guess, in terms of the in excess of $200 million over the next five years, 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 the first two RFPs that you'd see, one from South Dakota and one from Montana.
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%-15%? If we're thinking of in excess of $200 million, that in theory, 10%-15% of that realistically would be considered South Dakota?
I think I would say we've given pretty good guidance already on the $200 million 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.
That's for two reasons. Obviously, the Montana jurisdiction is larger, but secondly, the hole we're in is just that much deeper.
No, I understand, especially that this is only phase one. I get that. What I'm really trying to make sure of, a kind of baseline is, the $200 million related to what exactly? I guess in a way to kind of going back to the clarification I think Chris was requesting in relation to the total shortages versus what this first period would attempt to address.
Vidula, I've given you as much guidance as I can on that $200 million.
Okay. All right. Okay. Thank you very much.
Just as a reminder, if you'd like to ask a question, please press star one at this time. Again, that is star one to ask a question. We'll take our next question from Jonathan Reeder with Wells Fargo.
Hey, how's it going?
Hey, Jonathan.
Hey, just one question from 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, The plan is nearly ready to hit the streets. I'm not at all concerned about delay. What I would say, going back to the 2015 plan, you know there was a lot of noise at the end of that plan. Ultimately, we weren't able to implement the RFP that we went out with after that plan. 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. It's a shame from our customers' perspective that we weren't able to move ahead on the RFP following up on the 2015 plan.
I really do feel very good about where we are with this year's plan.
Okay, when you do have a final plan, Bob, 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?
Well.
incorporating 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. Ultimately, any project of any kind that is able to help us meet our customers' needs will have the opportunity to bid in, to be evaluated by a third party. Certainly, there are strong views about what resources are best able to meet the need. At this point, I certainly hope that experience, even over the last two years, should lead thoughtful people to agree on what the need is. 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 newspapers that said Montana needs baseload power. That's a real change in tone, and I think a recognition by the Commission, certainly a recognition by other policymakers around the state, that we have a need. Again, there'll be plenty to discuss and debate over how best to meet that need.
I can't imagine anyone looking at the situation not recognizing we have a reliability need, a reliability risk, and a price risk if we don't move ahead to address the capacity need.
Thanks for the answer. Bob, any more kind of activity around resurrecting Colstrip 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?
Colstrip is a valuable resource within a diverse portfolio. The concept that was considered in the legislature, and actually had a lot of support, was a good concept, would've produced an immediate net savings for our customers, would've taken down an increment, and far from the majority, but an increment, of the exposure we had, would've addressed the transmission risks that we face as well, and really would've 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. It's a resource and approach that was compelling when the legislature was in session, and it's still compelling now.
Okay. Thanks so much for answering that.
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 Vidula Mirchi.
Yeah. 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 that 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. 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. We'd move from there to selection and hope to see a good outcome in terms of resource choice.
We'd know the outcome of that, say, mid 2020?
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.
Yeah. I think the main thing there is the timing associated with when that will make an outcome there. The clear thing is we have to have that capacity in by the end of 2022. It's important for us to get going.
We need resources in order to participate in the imbalance market.
Okay. As I recall, there are times where various policymakers, regulators, et cetera, 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 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 type of historical bias, for lack of a better term, is not relevant.
Yeah. 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. I think, honestly, people who lean too heavily on a market solution to meeting our peak needs are not very in touch with recent history in Montana. As you know, 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, least cost, least risk. The least cost statute really is what we organize around.
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 third party building it and basically you contract it from?
Third parties will be on an equal footing with any proposal we make. The third-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. 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.