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Edited Transcript of NWE earnings conference call or presentation 12-Feb-19 8:30pm GMT

Q4 2018 NorthWestern Corp Earnings Call

Sioux Falls Feb 13, 2019 (Thomson StreetEvents) -- Edited Transcript of NorthWestern Corp earnings conference call or presentation Tuesday, February 12, 2019 at 8:30:00pm GMT

TEXT version of Transcript

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Corporate Participants

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* Brian B. Bird

NorthWestern Corporation - CFO

* John D. Hines

NorthWestern Corporation - VP of Supply & Montana Government Affairs

* Robert C. Rowe

NorthWestern Corporation - President, CEO & Director

* Travis Meyer

NorthWestern Corporation - Director - IR & Corporate Finance

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Conference Call Participants

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* Michael Weinstein

Crédit Suisse AG, Research Division - United States Utilities Analyst

* Nicholas Joseph Campanella

BofA Merrill Lynch, Research Division - Research Analyst

* Paul Patterson

Glenrock Associates LLC - Analyst

* Paul Thomas Ridzon

KeyBanc Capital Markets Inc., Research Division - VP and Equity Research Analyst

* Vedula Murti

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Presentation

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Operator [1]

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Good day, and welcome to the NorthWestern Corporation Year-End 2018 Financial Results Conference Call and Webcast. Today's event is being recorded.

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

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Travis Meyer, NorthWestern Corporation - Director - IR & Corporate Finance [2]

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Thank you, Chelsea. Good afternoon, and thank you for joining NorthWestern Corporation's financial results conference call and webcast for the quarter ending December 31, 2018. NorthWestern's results have been released, and the release is available at our website at northwesternenergy.com. We also released our 10-K premarket this morning.

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

Before I turn the call over for us to begin, please note this 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 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 statement. 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 on reasonable assumptions, actual results may differ materially. The factors that may affect our results are listed in certain of our press releases and disclosed in the company's Form 10-K and 10-Q along with other public filings with the SEC.

Following our presentation today, we will open the phone lines to allow those dialed in to the teleconference to ask questions. The archived replay of today's webcast will be available beginning at 6 p.m. Eastern Time today and can be found on our website at northwesternenergy.com under the Our Company, Investor Relations, Presentations and Webcasts link. The audio replay of the call is available at (888) 203-1112, then access code 3377935.

I'll now hand our presentation over to our CEO, Bob Rowe.

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Robert C. Rowe, NorthWestern Corporation - President, CEO & Director [3]

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Thank you, Travis, and greetings from South Dakota where the sun is out today, which is a little bit unnerving after the winter weather we've been enjoying so we're wondering we've done something to displease the snow gods. We just finished our board of directors meeting. A number of you have met members of our board, and my reflection on the last several days was we have a remarkably engaged board from a governance perspective. They spent time on all of the key governance and growth initiatives and really are at the core of our strength as a company.

Jumping into 2018 highlights. Net income for the year increased $34.3 million or 21.1% as compared with the same period in 2017. And this increase was primarily due to a gain related to the adjustment of our electric QF liability, the demand for electric transmission, customer growth and favorable weather at South Dakota as well as the net impact of the Tax Cuts and Jobs Act. And these improvements were partly offset by an increase in depreciation expense.

Diluted EPS increased $0.58 or 17.4% as compared to the same period last year. Then after, adjusting to remove benefits of the QF gain and TCJA and the small amount of favorable weather, non-GAAP earnings per share increased by $0.09 or 2.7% as compared to the same period in 2017. And Travis has included the bridge at Page 30. And I would characterize our adjustments GAAP to non-GAAP as conservative and transparent.

We filed an electric general rate review with the Montana Public Service Commission at the end of September. And we're requesting a $34.9 million or 6.6% annual increase to our base revenues, primarily as a result of increases in property taxes and capital investment. And then the board declared a quarterly dividend of $0.575 per share payable March 29 to shareholders of record as of March 15. 2 comments before I hand it over to Brian to go deeper on the financial side.

First of all, a reflection on last year. 2018, as you all know, was a challenging year for us. We knew that going in, think of where PCCAM was even before the start of 2018, fall of 2017, add to that TCJA implementation in 3 jurisdictions, add to that rate case preparation, add to that preparation of 2 supply plans and then, most fundamentally, significant capital expense budgets we've committed to our transmission and distribution operations. And as the Bernie Taupin song says, we're still standing.

And then from a customer perspective, most importantly, we had the best year ever in terms of customer satisfaction. Best year that our Distribution Vice President, Curt Phol, or any of us, can recall from a [system and reliability] perspective and a very strong year yet again on employee safety. So where it counts and with your support, we really are delivering for our customers, and I'd like to think of us as the little company that could.

The other thing I want to highlight is what's been going on in our region, Montana, South Dakota and Nebraska over the last few weeks. The [typical] winter weather pattern has moved in and stayed in. And every part of our system has contributed: electric and gas, supply and transmission, distribution, everyone in customer care. The investments we've made over time in all aspects of the system have paid off to certain of our customer. But most importantly, our extraordinary employees who are, whether they are on the phone, at their desk or particularly the folks who have been out in the field in some very, very dangerous weather, keeping our customers safe and warm, and fundamentally that really is what it's all about, and we sincerely appreciate all of your support in making that possible.

With that, I'll turn it over to Brian.

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Brian B. Bird, NorthWestern Corporation - CFO [4]

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Thanks, Bob. On Page 4 is a summary of the financial results. Bob did touch upon these, but on the Summary page, you see net income was $197 million, an increase of $34.3 million or 21%, resulting in diluted earnings per share of $3.92 a share, a $0.58 improvement or 17.4%. And lastly, dividends paid, $2.20, which was a $0.10 increase or almost a 5% increase on a year-over-year basis.

Turning to the next page, talking about gross margin on a full year perspective. Gross margin was $919.1 million. That was a 23.7% or 2.6% increase for the year. As you can see, that was primarily derived from our electric side of our business. When you consider the increase in gross margin due to those factors that actually impact net income, gross margin actually was increased $30 million or 3.3%.

Speaking of those items, what were the primary drivers? The electric QF liability adjustment we talked about in the second quarter of this year. For the full year basis, our electric transmission business was up $6.2 million. We've seen increased utilization of our system during the year. Natural gas retail volumes, $3.3 million improvement. Think customer growth and primarily a significant contribution from our South Dakota business, which was much colder, and I'll mention that in a minute. Offsetting those improvements, you see a $6.1 million reduction in gross margin, the impact of the TCJA or the Tax Cuts and Jobs Act. And think of that as effect of the amount that we paid over the tax benefit that we actually received, if you will, from TCJA.

All of those items netted to the $30 million change in gross margin impacting net income. Below that, those items that do not -- are offset elsewhere in the P&L and do not impact net income, first and foremost, $17.4 million. Think of that as going to be the current year method, if you will, the finalized current year method if you did for TCJA, and that is the impact that is offset in taxes. Offsetting that $17.4 million item is the $11.7 million recovery of property taxes during the year. Those 2 items make up the majority of the $6.3 million negative change in gross margin, netting for the total gross margin of $23.7 million.

Moving forward to weather on Slide 6. It's pretty clear looking at these that Montana was much milder than it has been, particularly on the cooling degree day but certainly flat on heating degree and as a whole was unfavorable for the year. But South Dakota and Nebraska, to a big degree, were quite helpful in terms of being much colder in the winter and much hotter in the summer and so have helped with -- in addition to customer growth of a South Dakota weather that primarily carried the day from a margin perspective. We did estimate favorable weather in '18 of about $1.3 million pretax benefit compared to normal and about a $2.1 million pretax detriment when compared to 2017.

Moving on to operating expenses on Page 7. Operating expenses for the full year were $652.9 million, a $29.4 million increase year-over-year, about 4.7%. It was consistently -- or along if you think -- OG&A was up 4.2%. And both property tax and depreciation were up about 5%. When you take into consideration those increase in OG&A that actually impact net income, that was actually only up $2.1 million or 0.7%. So again, if -- when you consider just of those items impacting net income, we managed to keep OG&A flat for the year. Those primary drivers of that $2.1 million increase, we did have an increase in employee benefits. Think higher medical costs and think higher incentive costs on a year-over-year basis. We did spend more on hazard trees in 2018.

Offsetting those 2 increases, the DSIP program, which was completed last year, so we had lower costs associated with that in 2018. And we had lower labor costs really driven by 2 reasons: one, we had a lower headcount on a year-over-year basis; and the headcount we had remaining, of course, spent a lot of time working on capital projects. And lastly, lower maintenance costs, it was -- not scheduled outage here for Colstrip, and so we had other lower maintenance costs as a whole. Those items equate to about a $2.1 million change impacting net income.

Items not impacting net income, the primary driver there is the pension and other postretirement benefits of $10.3 million. I think all of you are now aware that, that change, if you will, was offset in other income. Taking all of those factors in consideration, the increase, again, $12.3 million increase in OG&A. And as I mentioned earlier, approximately an $8 million increase of both property taxes and in depreciation associated with planned additions made during the year.

Moving on to Page 8. Operating income, $266.3 million, actually, down $5.5 million or 2%. Below that, interest expense, relatively flat year-over-year. Other income, actually up $7.4 million. Again, this is the $10.3 million decrease in other pension expense shown here in other income, but that was partly offset by a lower AFUDC. And with -- taking those things into consideration, pretax income $178.3 million, up $2.2 million or 1.2%. And below that, obviously, the big income tax benefit during the year of $32.1 million, that was really the combination of both $19.8 million final assessment of excess deferred tax liability, I'll talk about in a minute, and other impacts of TCJA. And taking those changes into consideration got you to the final net income number of $197 million that we discussed earlier.

Turning to Page 9 is where we talk about income tax reconciliation. This is the $32.1 million benefit on a year-over-year basis, really, driven by 3 primary factors. Obviously, the change of the Fed rate from 35% to 21% drove a $24.2 million benefit. That and also the $19.8 million, which is effectively when we looked at TCJA in our excess deferred tax liability, resulted in a gain. That particular deferred tax liability was primarily associated with goodwill and was nonjurisdictional, if you will, to the rest of our business. That benefit, those 2 items were offset by lower flow-through repairs deductions. If you think about a certain amount of capital spend that is eligible for repairs deduction, when you have a lower tax rate, you get less of a benefit from flow-through repairs. So that was a bit of an offset, leading us to approximately the $32.1 million I mentioned earlier in terms of benefit.

Moving on to the next page in terms of the balance sheet. From a debt to capital perspective, we've seen improvement on a year-over-year from 53.7% to the end of '18 to 51.7%, driven by, obviously, improvements in the business from a financial perspective but also the equity we had raised in the latter half of '17 and early part of '18. And by moving to these better capital structure, if you will, gives us more room, if you will, from an FFO coverage ratios with the rating agencies as well.

Moving on to cash flow on Page 11. Cash flow, just over $381 million, primarily increased to almost $60 million due to higher net income, improved customer receipts and some insurance proceeds during the current period. We used that improved cash flow, really, to do 2 things. From an investing standpoint, we have higher investing activities primarily as a result of the Two Dot Wind acquisition earlier in the year. And then remaining cash, we actually paid down more debt on a year-over-year basis.

Moving on to Page 12 is adjusted from a GAAP to non-GAAP basis. At bottom of that page, you see we started with a $3.92. We had 3 adjustments during 2018. We removed $0.02 of favorable weather. We removed $0.25 of the qualifying facility, a gain that we had in the second quarter. And then here in the fourth quarter, we're removing $0.25 associated with the impacts of TCJA, and I'll talk about that more in a minute. Those adjustments resulted in a $3.39 outcome. That compared to $3.30 on a year-over-year basis. $3.39, I think everyone knows, within the guidance range we provided earlier in the year.

And speaking of guidance, one thing I would want to point out at this point in time, you may have noticed we did not provide any guidance for 2019. Obviously, a significant rate case -- rate review year for us as a company, and as a result, we will not be providing guidance. I do want to make sure that people are well aware that we still intend to deliver a 6% to 9% total return as a result of our business and where we sit today.

Just real quickly on the 3 adjustments for 2018. I talked about favorable weather earlier. We've talked in the past on the gain on the qualifying facility. I think if you recall, that $17.5 million adjustment to cost of sales was the result of looking at the future liabilities associated with the QF, and that had not increased at the level that we expected it to from an accelerated cost perspective. So that was a benefit to us.

And then lastly, TCJA is made up of several components. First and foremost, think of it this way, we looked at when we provided guidance how we were going to do from a current year method perspective. And one thing I was -- I pointed out earlier, the $6.1 million that we added back here was the differential between what we expected to get as an outcome from TCJA versus what we ultimately settled. So if you think of $23.5 million, that's the settlement between Montana and South Dakota that we paid out. Take that versus the $17.4 million differential, as I mentioned, in terms of the true current year method benefit, that's the $6.1 million we're adding back here.

We also made an adjustment to OG&A. We did not intend to have $3.3 million of expenses hit our P&L this year. The reason being is when we made our filing from a current year method perspective, there was an expectation from an expense standpoint that we would pay 50% of the benefit back to customers in cash and receive a benefit that would go towards hazard tree spend during the year. Obviously, the settlement that took place did not convey that way with the $20.5 million that we paid out in Montana plus the $3 million in South Dakota was all paid in cash to our customers during the year.

On hazard trees, though, one thing that we did receive the settlement as we discussed the settlement in the past. It was the idea that, that $3.3 million would not be disputed as known and measurable in the upcoming rate review.

Those 2 items, the $6.1 million and the $3.3 million of OG&A recovery of hazard trees, net back of $9.4 million, when you tax effect that, that's a $2.4 million adjustment. That and the $19.8 million excess deferred tax liability adjustment I discussed earlier make up the $22.2 million income tax adjustment to get to the $12.8 million net income item there.

I know it's a lot of stuff on Tax Cuts and Jobs Act, but everybody knows how difficult that was to deal through in 2018.

Having talked through all of those items, when you look at the non-GAAP earnings through the P&L perspective on a year-over-year basis, gross margin up about 1.6%. Think of our customer growth around 1%. And some better weather and better transmission revenues seems to make sense around 1.6% improvement there. OG&A expenses, as you can see, flat and no adjustments for property or depreciation, gives us a total operating expense increase of about 2.6%. Other -- our operating income remains relatively flat. Other income is, as mentioned, AFUDC, slightly lower. We had some projects that wrapped up in '17. Invested lower AFUDC in 2018. That gives us a pretax decrease on a year-over-year basis of 2.2%, but all of the net of impacts of taxes and the lower rate gives us a $13.3 million improvement, resulting in the improvement of net income of approximately 6%. We did issue shares into '18, and that dilution on a year-over-year basis impacted EPS on a non-GAAP basis year-over-year of 2.7% increase in diluted EPS.

And with that, I'll hand it back over to Bob.

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Robert C. Rowe, NorthWestern Corporation - President, CEO & Director [5]

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Thank you, Brian. I'll highlight several things then come back and discuss a number of those in more detail. First, on the regulatory front. Obviously, the primary focus is the Montana electric rate case we filed in September. And we're working hard now on a parallel FERC case to be filed in the first quarter, concerning our FERC jurisdictional Montana transmission asset. Ongoing investments in transmission and distribution infrastructure as we discussed on previous calls. We take a comprehensive approach to our electric and natural gas infrastructure, focusing on safety, capacity and reliability and cost-effective technology investments.

Natural gas, safety-related investments are an important part of that as is grid modernization, including an advanced distribution management system we're deploying this year and advanced metering that we're actively deploying, really moving from north to south in South Dakota and Nebraska, in both electric and natural gas systems. A notable and, I think, important development is we have decided to join the Western Energy Imbalance Market, and that's a real time energy market that could potentially lower the cost of energy for our customers but also provide more efficient use of renewables and reliability, also greater access potentially for developers in Montana to the market.

Off to the right, you see a graphic that's really indicative of where we sit in our Montana electric operation in relation to the rest of the Western grid. We are on the very edge. So before committing to the Western market, we did consider other alternatives and had to determine ultimately that joining the Western Energy Imbalance Market would be a cost-effective decision for our customers and a good decision for the state.

And then you have the time line. We actually have an important meeting in several weeks to kick that process off, culminating into an entry in 2021. Cost control efforts are important. We think we benchmarked very well against our peers and, in fact, even outside of our peer group. And then we have moved ahead on both our South Dakota and Montana electric supply plants.

Turning to the tracker. And this was a huge regulatory focus over much of 2017, and essentially all of 2018. Ultimately, the commission issued an order in January establishing a baseline of power supply costs. A symmetrical deadband of plus or minus $4.1 million from an established baseline. Supply cost variances above or below the deadline are shared 90%, 10% with customers and shareholders, respectively. Implementation is retroactive to the effective date of the enabling legislation, which was July 1, 2017.

So our 2018 results, including net reduction in the recovery of supply costs from customers, about $1.5 million as shown in the Consolidated Statements of Income. And that includes the following, as described on Slide 14.

For 2017 and '18, actual costs were below the base revenues by about $3.4 million, so that resulted in no refund under the formula to customers. However, for 2018 and '19, actual costs were above base revenues by about $11.8 million and that then, applying the formula, resulted in a regulatory asset for collection from customers of about $6.9 million as well as a $4.9 million reduction in recovery of supply costs for the first 6 months of that period. It's also notable that our controller has determined that the most prudent response is to adjust based on actuals on a quarterly basis to -- rather than let volatility run too far out.

A little bit more on Tax Cuts and Jobs Act. We did reach conclusions in all 3 jurisdictions. In Montana, in December, the commission approved a settlement providing for $20.5 million onetime customer credit to electric and natural gas customers. And in addition, the settlement provides $1.3 million in annual reductions in natural gas rates beginning in 2019, recall we had a natural gas case in Montana last year and one is not contemplated this year, and additional funds for low-income energy assistance and weatherization. And as Brian highlighted, I think it's extremely important going forward, agreement of the parties not to oppose our request to include up to $3.5 million of costs to address hazard tree removal in our 2018 electric rate review filing. The settlement in order also then addressed issues related to the reevaluation of deferred income taxes, and those ultimately will be addressed in the rate review.

In South Dakota, in September, the PUC approved a settlement that resulted in a $3 million customer credit in the fourth quarter and a 2-year rate moratorium until January 1, 2021. In Nebraska, in August, the Nebraska Public Service Commission approved a settlement to evaluate the impact of TCJA on an annual basis. And for the period under review, there was no impact on our financial statements.

The consolidated impact in 2018 includes a net benefit relative to TCJA, an income tax benefit of $19.8 million due to the final reevaluation of deferred income tax liabilities; a net loss of $6.1 million resulting from $23.5 million in customer credits from the approved settlements. And that's partly offset by a $17.4 million reduction in income tax expenses to the reduction of federal rate. And $3.3 million expenses related to our hazard tree program as agreed to in our Montana settlements. Our initial filing with the -- you'll recall, the initial filing with the commission, instead it proposed using a portion of the TCJA benefits to fund the expenditure, again, as Brian referenced.

So we expect a reduction in our cash flows from operations ranging from $20 million to $22 million this year as a result of customer credits. And then due to our existing NOL position and other tax credits, we expect to be a cash taxpayer now during 2020, with credits reducing our cash tax obligation into 2022. And we estimate that our effective income tax rates will range from 0% to 5% this year.

Next, moving to the 2 electric supply plans. First, in South Dakota. Published the plan last fall. The plan focuses on modernization of our fleet to improve reliability, flexibility and to maintain compliance with Southwest Power Pool requirements as well as the lower operating costs. And the plan identifies 90 megawatts of existing generation that should be retired and replaced over the next 10 years. And that's in addition to 8 megawatts of mobile generation that will be installed by the end of this year. And that program is well underway. But we also expect to issue an all-source request for proposal in the second quarter of 2019 to replace 60 megawatts of combustion generation by late 2021. And that would be located in Huron, South Dakota. And indeed press release went out on that today. HDR, the engineering and consulting firm, will work with us on that process.

Turning to Montana. The draft plan will be filed in the first quarter 2019, is expected to be finalized midyear after a 60-day public comment period in front of the commission. The plan is focused on our significant generation capacity deficits and our negative reserve option. Our current peak requirement for energy in Montana is about 1,400 megawatts. And we're currently 630 megawatts short. This is, of course, all subject to market purchases. We forecast that our generation portfolio will be actually 725 megawatts short by 2025. Add to that, regional concern about planned regional retirements of 3,500 megawatts of coal-fired generation. That's a forecast from Northwest Power and Conservation Council that could potentially cause lots of low probably -- regional shortages as early as 2021. And I think of this as lots of straws sipping in the same drink, and the drink is getting pretty depleted.

So we expect to solicit competitive all-source proposals in 2019 for up to 200 megawatts of peaking capacity to be available by 2022. And these supply additions would meet about 25% of our projected need in 2025. And we would essentially wash, rinse and repeat. We would repeat the process in subsequent years to provide a resource-adequate energy and capacity portfolio by the end of that process. And note that the all-source capacity addition that I've been discussing here are subject to competitive solicitations, administered by independent evaluators, and as a result, we have not included the necessary capital investment in our current 5-year capital forecast. These additions could increase capital spending in excess of $200 million over the next 5 years.

Turning to the rate case. And today is a significant day in the rate case. This is our first Montana general electric case since 2009. We efficiently managed our operating administrative expenses over that time period, but this filing was driven, from our perspective, by the increased Montana property taxes, which are only partially recovered through trackers and then the significant investment that we have been making particularly in our T&D system driving the request for relief. We filed with the commission in September based on a 2017 test year and a $2.34 million rate base. We've requested $34.9 million in an annual increase to electric rates. This reflects a 6.6% increase to Montana electric revenues, including a 7.4% increase to typical residential bills. We've requested a 10.65% ROE, a 4.26% cost of debt, a 49.4% equity and a 7.42% return on rate base. We've also requested $13.8 million of interim relief. Our initial request was to be effective November 1, 2018. We expect action on our interim request after intervenor testimony is received and reviewed by the commission. Of course, if the commission does not issue an order within 9 months of the filing, new rates could be placed into effect on an interim and refundable basis.

We've requested, as part of the filing, items, including approval to capitalize demand-side management costs, to establish a new baseline for PCCAM costs, to place Two Dot Wind in rate base and to approve a new net metering customer class applicable only to new residential private generation customers and the new rates. The time line [for entering their] testimony is due today. And it's significant that we've made this key date in the testimony with no notable slip in the schedule, just from the 8th to the 12th. Then NorthWestern will file its rebuttal and cross-intervenor testimony, we'd also be doing on April 5. And the hearing is scheduled to commence on May 13. So this has been a substantial undertaking by employees in a great many parts of the business, and their work is sincerely appreciated by all of us.

Turning finally, to the capital forecast. You see, again, as you have every quarter, relatively stable capital commitment over a five-year period. We'd highlight once again that this includes only -- the only supply capital reflected in this is the South Dakota mobile units and some small amount for hydro upgrades in Montana. So essentially, this is a transmission and distribution capital forecast of $1.6 billion of total capital over 5 years. The -- and an increased investment in the first 3 years is primarily the result of the AMI program that I've described. We anticipate funding these investments with a combination of cash flows that's still aided by NOLs into 2020, along the long-term debt issuances. Significant capital investments that are not in these projections or further negative regulatory outcomes could necessitate additional equity funding. And again, capital investments do not include anything necessary to address capacity issues identified in either the South Dakota or Montana resource supply plans.

And with that, we can go to questions.

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Questions and Answers

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Operator [1]

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(Operator Instructions) And our first question will come from Nicholas Campanella from Bank of America.

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Nicholas Joseph Campanella, BofA Merrill Lynch, Research Division - Research Analyst [2]

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Hey, so I just have a quick question first on the resource planning. I know you said $200 million to the next 5 years. Is it safe to assume that's just for the 60 megawatts in South Dakota and 200 in Montana? Or is there more spend associated with that $200 million per year from 2020 to 2025?

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Brian B. Bird, NorthWestern Corporation - CFO [3]

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Yes, I want to just be -- make sure, Nick, you're following us here. The $200 million per year, Bob was talking about the Montana plan itself when he talked about that over, actually, a 4-year period. We'll be asking for RFPs here in each year associated with 200 megawatts. The 60 megawatts for South Dakota was completely separate from that discussion.

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Nicholas Joseph Campanella, BofA Merrill Lynch, Research Division - Research Analyst [4]

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Got it. Okay. But in -- all in, we should be thinking about $200 million for these programs in capital?

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Brian B. Bird, NorthWestern Corporation - CFO [5]

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Well, I think what we said here is, from our perspective, we're not including any of the capital from South Dakota or Montana from these RFPs that are going out, sort of our resource plans in Montana. [Except that] we're not including anything in our capital plans. We're saying we hope to and could expect to when -- up in excess of $200 million associated with that. So we're not saying that Montana, South Dakota or anything at this point in time.

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Robert C. Rowe, NorthWestern Corporation - President, CEO & Director [6]

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The RFPs in each case would be run by a third party. We have the opportunity to participate, but the RFP will select the option best for customers.

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Nicholas Joseph Campanella, BofA Merrill Lynch, Research Division - Research Analyst [7]

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Absolutely got it. And then Just on the no equity comments on the CapEx the slide. can you just, Brian, give us a sense of where your AFFO to debt metrics were on a trailing basis this year and then where you see them going in your current capital plan, barring any upward revisions in the CapEx from successful RFPs?

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Brian B. Bird, NorthWestern Corporation - CFO [8]

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Yes, Nick, I think when you look at '18, and this is thinking about how the rating agencies do that, I see results being the high 15s and expect it to stay in that level and improve a bit over time, which is quite a bit above kind of a 14% and a mid BBB, Baa2, if you will, at Moody's. At those levels, we think we -- as long as we're above 14%, we're going to be in pretty good shape. And so right now, our plans are in good shape and should be able to manage this capital plan appropriately. But as Bob pointed out, if we're successful in any of these RFPs or if there's anything else that comes up from a negative regulatory standpoint, obviously, things could change, but we feel good with our capital plan that we're going to be in good shape with the rating agencies.

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Nicholas Joseph Campanella, BofA Merrill Lynch, Research Division - Research Analyst [9]

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Great. And then my last question was, and I'm sorry if you touched on it already, but I know you guys aren't giving '19 guidance given the pending rate review. Is there any kind of tangible drivers that you could kind of call out for the year in either direction? I know that you have the 0% to 5% tax guidance out there, but where would you see O&M or property taxes going in that time period?

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Brian B. Bird, NorthWestern Corporation - CFO [10]

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Yes, we're not prepared to talk about that at this point in time, Nick.

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Operator [11]

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Our next question comes from Michael Weinstein with Crédit Suisse.

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Michael Weinstein, Crédit Suisse AG, Research Division - United States Utilities Analyst [12]

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Hey, so the $6.1 million negative impact in 2018 from the TCJA, is that -- since that is based on 18 months settlement versus the original 12 months that you had originally put into your guidance -- or actually, reserved for, I guess, right? So the $6.1 million is the additional impact of the of the additional 6 months. Is that basically reversed in 2019 because if it accounts for taxes, it'll be [paid] in 2019?

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Brian B. Bird, NorthWestern Corporation - CFO [13]

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I guess I'd look at it this way. The settlement on the electric side was handled in '18 and so there's going to be no detriment or deferrals, if you will, in '19 associated with the electric side of the business. We'll continue to, on a cash side, the $1.3 million on a going forward basis so that referral, if you will, continued. But we did settle in '18 for all of electric. And until new rates go in effect from the rate case, we're done with TCJA.

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Michael Weinstein, Crédit Suisse AG, Research Division - United States Utilities Analyst [14]

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Right, okay. So basically -- but it is kind of a pull-forward of $6.1 million of earnings impact, right, from taxes into 2018 that would have occurred in 2019?

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Brian B. Bird, NorthWestern Corporation - CFO [15]

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Yes, I could say at least for the half year. I'd argue that half of that would have rolled into '19 had we not settled, right, because of the rate case goes into effect July 1.

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Michael Weinstein, Crédit Suisse AG, Research Division - United States Utilities Analyst [16]

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Right, right. And then on the EIM, have you guys thought about what kind of transmission infrastructure might be needed in order to comply with EIM rules by 2021? Is there any potential CapEx there that might come up?

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Robert C. Rowe, NorthWestern Corporation - President, CEO & Director [17]

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What I would say is we're an active participant in the regional market. EIM will increase that activity. Certainly, we would look for any opportunities.

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Michael Weinstein, Crédit Suisse AG, Research Division - United States Utilities Analyst [18]

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Okay. And also just one last question. When you look at the rate cases and -- the rate case in the RFPs, what do you think at this point this year might give you enough confidence? At what point would you have enough confidence to perhaps raise the total return guidance back to the old 7% to 10%?

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Brian B. Bird, NorthWestern Corporation - CFO [19]

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You know what? That's a great question. Until we see good traction on the resource plan and actually us being able to invest, obviously, we don't know how we're going -- how that's going to work out. But I thought I made it pretty clear in the past that you'd see us move up within that range, that 6% to 9%, if we're making some investment in the electric supply side. So I don't see there's any change in that dialogue until we're successful, if we are to ever become successful in that regard.

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Robert C. Rowe, NorthWestern Corporation - President, CEO & Director [20]

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Brian, wanted to answer that question.

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Michael Weinstein, Crédit Suisse AG, Research Division - United States Utilities Analyst [21]

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Actually, I do have one more question. It has to do with the tax repair deductions. So there's a benefit of that -- there's a benefit from that in 2018 earnings. How is that being proposed to be treated in the rate case?

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Brian B. Bird, NorthWestern Corporation - CFO [22]

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Well, if you're talking about the $19.8 million excess deferred tax liability adjustment. If you're talking about that particular item, I'm not sure if the question -- if you're talking about that, since that was associated goodwill, that's not going to be dealt with in the rate case. That's a nonjurisdictional item. I'd make sure I'm understanding your question, Michael.

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Michael Weinstein, Crédit Suisse AG, Research Division - United States Utilities Analyst [23]

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I think that's right -- I mean that's right. Yes, I'm just wondering, is that being disputed though, that it's nonjurisdictional? Or is it not?

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Brian B. Bird, NorthWestern Corporation - CFO [24]

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Disputed, it's associated with goodwill. I think you did -- I thought you might have said the words repairs, that's what kind of threw me off there, Michael.

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Michael Weinstein, Crédit Suisse AG, Research Division - United States Utilities Analyst [25]

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Oh, yes, yes, yes, I'm thinking specifically about the repairs deduction.

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Brian B. Bird, NorthWestern Corporation - CFO [26]

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Now repairs, I think, will be dealt with in the rate case. Other deductions -- all taxes will be captured in the rate case, including how we handle repairs.

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Michael Weinstein, Crédit Suisse AG, Research Division - United States Utilities Analyst [27]

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Are you booking a benefit from that right now?

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Brian B. Bird, NorthWestern Corporation - CFO [28]

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Well, we continue to take repairs deductions during the year, correct.

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Operator [29]

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Our next question will come from Paul Ridzon with KeyBanc.

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Paul Thomas Ridzon, KeyBanc Capital Markets Inc., Research Division - VP and Equity Research Analyst [30]

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Where do you see your request for interim rates stand? And what's that process look like?

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Robert C. Rowe, NorthWestern Corporation - President, CEO & Director [31]

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Typically, the Montana commission waits until intervenor testimony is received. As you know, that's coming in today. And then we would expect them to schedule a work session in the next several weeks to decide whether and -- if yes, how much interim relief to grant it. Practically, Montana, they want to see the delta between the filing parties' ask, and particularly, the Consumer Council's, [specifically].

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Paul Thomas Ridzon, KeyBanc Capital Markets Inc., Research Division - VP and Equity Research Analyst [32]

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And when would that be retroactive until?

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Robert C. Rowe, NorthWestern Corporation - President, CEO & Director [33]

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That would be up to the commission. It's included in our request.

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Paul Thomas Ridzon, KeyBanc Capital Markets Inc., Research Division - VP and Equity Research Analyst [34]

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So there's no fixed date after you file when interim rates would kick in?

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Robert C. Rowe, NorthWestern Corporation - President, CEO & Director [35]

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No.

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Operator [36]

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Our next question comes from Paul Patterson with the Glenrock Associates.

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Paul Patterson, Glenrock Associates LLC - Analyst [37]

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So just there's a lot of moving pieces here with respect to capital opportunities that you guys have. And just sort of looking forward here, I mean, some of these things might have offset -- like grid mods, in theory, might have lower costs associated with operations and what have you. Just sort of wondering, how do you guys think about the trajectory for rates given sort of the robust CapEx that you guys have got going in and given the other puts and takes, if you follow me? And how should we think about you guys going in for regulatory relief?

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Brian B. Bird, NorthWestern Corporation - CFO [38]

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That's an excellent question. I think, from our perspective, we factor in the impact on customers rates as we look at our capital plan, and we certainly don't want to see that exceed inflationary pressures. I think you have seen us also manage our costs significantly to try to keep it as low as possible. And so we think that the capital levels that we have in place, that is going to do exactly that, keep rates relatively flat but increasing at inflationary pressures.

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Robert C. Rowe, NorthWestern Corporation - President, CEO & Director [39]

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History over the several years, and certainly for the last decade, has been one of thoughtfully scheduling investments in traditional infrastructure and as well as in technology to do just that. And on both the electric capacity side, we've managed to maintain rates significantly below national averages, and that's even with the unique contribution that Montana, definitely its property tax, makes to our customers' bills. So we have done a good job managing costs to customers, and our staged approach to capital is in part a reflection of that.

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Brian B. Bird, NorthWestern Corporation - CFO [40]

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I'd also add to that. I think one thing that we've had success in the past when we have made investments in supply resources, we've offset the other costs that passed through to our customers. So that impact, if we were to increase our capital spend for any of those things, isn't going to have a significant impact on customers either. So that's also our hope.

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Paul Patterson, Glenrock Associates LLC - Analyst [41]

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Okay, great. And then just on the FERC 2019 case that you plan on filing. Could you give us a little bit of a preview as to what you're sort of thinking of there and sort of what's driving all that? I apologize for not being more on top of it.

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Brian B. Bird, NorthWestern Corporation - CFO [42]

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I...

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Robert C. Rowe, NorthWestern Corporation - President, CEO & Director [43]

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Go ahead. All I was going to say was read it when it comes out. We are anticipating looking at more of a formulaic approach. But the ultimate point is to reconcile what happens in FERC jurisdiction, with what happened in this case in the Montana jurisdiction and to keep us in our shareholders hold.

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Paul Patterson, Glenrock Associates LLC - Analyst [44]

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Could you elaborate a little more on that? I apologize. So are you saying you want to -- the way you talk about having to match each other, could you, I'm sorry, could you tell us little bit more about that?

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Robert C. Rowe, NorthWestern Corporation - President, CEO & Director [45]

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So that we are neither under-recovering or over-recovering in either jurisdiction. So that essentially nothing falls off the gap -- between the kind of gap between the 2.

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Operator [46]

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Our next question comes from Vedula Murti with Avon Capital.

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Vedula Murti, [47]

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A couple of things. I just want to make sure I'm kind of clear on this. The 60 megawatts RFP in South Dakota, and when will you know whether -- I assume you'll be allowed to put in your own proposal with others and third party evaluates. When do you find out the winner?

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John D. Hines, NorthWestern Corporation - VP of Supply & Montana Government Affairs [48]

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This is John Hines. We're going to be issuing the RFP in April. Approximately by the end of third, fourth quarter, we'll have an idea of what of those bids are and will make the determination of whether we're successful. We'll be part of an EPC bid with the -- at the existing site in Huron. And when we have the determination in early '20, we'd hopefully -- constructions begin soon thereafter.

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Robert C. Rowe, NorthWestern Corporation - President, CEO & Director [49]

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And John is our Vice President for Electric and Gas Supply.

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Vedula Murti, [50]

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Okay. So you will be able to tell us that whether or not your proposal was the least cost or most effective one, it looks like, call it, like a 4Q of '19?

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John D. Hines, NorthWestern Corporation - VP of Supply & Montana Government Affairs [51]

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Correct.

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Vedula Murti, [52]

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Okay. And construction is how long?

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John D. Hines, NorthWestern Corporation - VP of Supply & Montana Government Affairs [53]

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We can't tell with any definition right now because it'll be depending upon the bid, but we expect it to be operational by 2022.

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Vedula Murti, [54]

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And is there like a general dollar range that we should be kind of boxing things off of?

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John D. Hines, NorthWestern Corporation - VP of Supply & Montana Government Affairs [55]

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Again, I'd be reluctant to give a dollar range right now until the competitive solicitations are complete and evaluated.

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Vedula Murti, [56]

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But I think I was going back to the Nick's question about the $200 million. Is the 60 megawatts a subset of that $200 million? Or the 60 megawatts is completely separate?

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Brian B. Bird, NorthWestern Corporation - CFO [57]

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I think it depends. If you are talking about the $200 million of these additions could increase our capital spending in excess of $200 million over the next 5 years. If you're talking about that, our opportunity to participate in this would be considered in that.

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Vedula Murti, [58]

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So it would be part of that. Okay. And then in Montana, the RFP there is for $200 million. Correct?

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Robert C. Rowe, NorthWestern Corporation - President, CEO & Director [59]

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[Indiscernible] out of the plan when filed from the time we signed the plan.

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John D. Hines, NorthWestern Corporation - VP of Supply & Montana Government Affairs [60]

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Yes, it's up to 200 megawatts beginning this year.

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Brian B. Bird, NorthWestern Corporation - CFO [61]

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Yes, I think what Bob mentioned earlier in the call was when he said that rinse and repeat is we're going to be doing 200-megawatt RFPs in multiple years after that.

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Vedula Murti, [62]

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So if you have an RFP -- is this RFP already outstanding -- in motion?

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Robert C. Rowe, NorthWestern Corporation - President, CEO & Director [63]

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No. The -- as part of the planned development, there was a request for information. But an actual RFP soliciting proposals to build or contract any kind of facility or any demand side activity would come after the plan has been filed and presumably after a 60-day comment period in front of the commission. So that is a future event.

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Vedula Murti, [64]

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So based on previous experience, at what point would this RFP be issued?

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Robert C. Rowe, NorthWestern Corporation - President, CEO & Director [65]

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At some point, if the schedule holds, I would say no earlier than later this year.

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John D. Hines, NorthWestern Corporation - VP of Supply & Montana Government Affairs [66]

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That's correct. The urgency, I think, as we've talked about before is a pretty strong given what we'd see there as the regional shortages coming up as well as our deficit internally. And so we will be moving as quickly as possible to move to get these RFPs in action year-over-year.

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Robert C. Rowe, NorthWestern Corporation - President, CEO & Director [67]

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And our customers -- we are already seeing significant price volatility at peak in both summer and winter periods. And that is -- the price risk is an indicative of on underlying supply risk and so forth.

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Vedula Murti, [68]

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So will we know by the end of '19 the outcome of the RFP Montana?

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Robert C. Rowe, NorthWestern Corporation - President, CEO & Director [69]

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No.

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Vedula Murti, [70]

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We will not know until 2020?

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Robert C. Rowe, NorthWestern Corporation - President, CEO & Director [71]

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Correct.

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Vedula Murti, [72]

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And once we know in...

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John D. Hines, NorthWestern Corporation - VP of Supply & Montana Government Affairs [73]

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I was just going to say what Bob is referring to is the regulatory uncertainty depending on when we get the plan out, when we get the 60 days and the time frame necessary to conduct the competitive solicitation. We may have that information by the end of 2019 or early 2020. We just cannot give a firm date until we actually undergo the process.

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Vedula Murti, [74]

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When you say end of '19, early '20, that would be total resolution of knowing what happened?

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John D. Hines, NorthWestern Corporation - VP of Supply & Montana Government Affairs [75]

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That's correct.

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Operator [76]

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Our next question will come from Paul Ridzon with KeyBanc.

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Paul Thomas Ridzon, KeyBanc Capital Markets Inc., Research Division - VP and Equity Research Analyst [77]

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Bob, how often these rinse and repeat? How often do you do that?

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Robert C. Rowe, NorthWestern Corporation - President, CEO & Director [78]

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It would be developed during the planning process, but realistically, 3 to 4 times.

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Paul Thomas Ridzon, KeyBanc Capital Markets Inc., Research Division - VP and Equity Research Analyst [79]

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And annually or...

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Robert C. Rowe, NorthWestern Corporation - President, CEO & Director [80]

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(inaudible) by the way.

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Brian B. Bird, NorthWestern Corporation - CFO [81]

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Paul, it will be 4 times in order to meet our needs by 2025.

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Paul Thomas Ridzon, KeyBanc Capital Markets Inc., Research Division - VP and Equity Research Analyst [82]

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By 2025?

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Robert C. Rowe, NorthWestern Corporation - President, CEO & Director [83]

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Yes...

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Brian B. Bird, NorthWestern Corporation - CFO [84]

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But in order to get the RFPs in place, actually, get construction and get these resources up and ready by 2025, we're going to need approximately 800 megawatts, if you will. After that, those 4 RFPs are going to have to accumulate to 800 megawatts and, in essence, are going to have to be carried out over a time period to fill that gap by 2025.

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Paul Thomas Ridzon, KeyBanc Capital Markets Inc., Research Division - VP and Equity Research Analyst [85]

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So that's basically it, Bob. Every year you're going to do an RFP, is it, sounds like?

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Brian B. Bird, NorthWestern Corporation - CFO [86]

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Correct.

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Paul Thomas Ridzon, KeyBanc Capital Markets Inc., Research Division - VP and Equity Research Analyst [87]

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And each of those is $200 million? Or accumulatively $200 million...

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Brian B. Bird, NorthWestern Corporation - CFO [88]

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200 megawatts. 200 megawatts.

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Paul Thomas Ridzon, KeyBanc Capital Markets Inc., Research Division - VP and Equity Research Analyst [89]

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$200 million of potential capital, is that for the first RFP?

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Brian B. Bird, NorthWestern Corporation - CFO [90]

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Again, the $200 million of capital is our capital. It has the ability to participate in all of these efforts, and we're saying that our expectation is we could do an excess of $200 million of capital on all of these activities.

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Paul Thomas Ridzon, KeyBanc Capital Markets Inc., Research Division - VP and Equity Research Analyst [91]

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Okay. So you get a slice of each RFP or one RFP or something like that?

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Brian B. Bird, NorthWestern Corporation - CFO [92]

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Absolutely. Something in Montana, something in South Dakota. I'm not going to share what our expectation is of capital by projects.

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Robert C. Rowe, NorthWestern Corporation - President, CEO & Director [93]

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Just a minute more on the process, and John can add to that. In Huron, the South Dakota process, as we've described, is well underway, very well defined. In Montana, the RFPs would flow out of the plan. The plan follows a variety of scenarios, focuses on what is our customers' critical unmet need. And again, that is for dispatchable sustained peak, the kind of resources that you need multiple times during the year to offset availability and price risk. A fair question given how deficit we are, why are you doing this over a period of years rather than simply going out once and eliminating that risk? What we're doing, back to the earlier question about rate requests, is managing cost to our customers and taking advantage of the likely diversity proposals over time and likely, we hope, changes in price and changes in technologies that might become available. So we are emphatically not selecting particular favored resources. We are setting up an independent process to identify the very best resources to meet our customers' needs and designing a process that will be open to alternate technologies as those technologies become cost-effective.

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John D. Hines, NorthWestern Corporation - VP of Supply & Montana Government Affairs [94]

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Yes, I'd say there's 3 main things to take away, I would suggest, that will be coming out of this plan: One, the customers in Montana, their portfolio is significantly short. Two, the region which NorthWestern purchases power is becoming shorter and shorter, especially from a capacity perspective. And three is the regulatory expectation is that we run competitive solicitations. And so that's our plan to fulfill all 3 of those over the next 5 years.

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Operator [95]

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We have another question from Vedula Murti with Avon Capital.

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Vedula Murti, [96]

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I've got a few here. But in 2018, what was the earned ROE in Montana compared to your ROE request in the current case?

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Brian B. Bird, NorthWestern Corporation - CFO [97]

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Yes, Vedula, we'll be coming out with our Montana annual report shortly after we've made our FERC Form 1 filing, and we'll display at that point in time our Montana ROEs. So you have to wait a bit for that.

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Vedula Murti, [98]

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Okay. And I assume that's the same for the FERC ROE with respect that filing as well?

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Brian B. Bird, NorthWestern Corporation - CFO [99]

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We'll have a FERC ROE in the filing itself. Correct.

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Vedula Murti, [100]

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Okay. Because it would be -- I'm sure it'd be overly simplistic to basically think that if you took your current Montana request and zeroed it out and, basically, took what would seem to be the after-tax effect that, that is kind of what you earned. That's overly simplistic. That's why I kind of was trying to figure that out.

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Brian B. Bird, NorthWestern Corporation - CFO [101]

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Yes, I wish I can help you on that.

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Operator [102]

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All right, and there are currently no further questions in the queue at this time.

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Robert C. Rowe, NorthWestern Corporation - President, CEO & Director [103]

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Okay. All right. Well, thank you very much for joining us today, and look forward to visiting with all of you next quarter and many of you over the next few weeks. Thank you.

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Operator [104]

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Thank you. Ladies and gentlemen, this concludes today's teleconference, and you may now disconnect.