Good day, welcome to the NorthWestern Corporation, NWE, 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.
Thank you, Chelsea. Good afternoon, thank you for joining NorthWestern Corporation's Financial Results Conference Call and Webcast for the quarter ending December 31st, 2018. NorthWestern's results have been released. The release is available at our website at northwesternenergy.com. We also released our 10-K pre-market 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 management 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 in response 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 on 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 Form 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 6:00 P.M. Eastern Time today. It 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. Access code 3377935. Again, that is 888-203-1112, access code 3377935. I'll now hand our presentation over to our CEO, Bob Rowe.
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. We're wondering whether 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, and 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%, which compared with the same period in 2017.
This increase was primarily due to a gain related to the adjustment of our electric QF liability, to demand for electric transmission, customer growth, and favorable weather in South Dakota, as well as the net impact of the Tax Cuts and Jobs Act. These improvements were partly offset by an increase in depreciation expense. Diluted EPS increased $0.58 or 17.4%, if compared to the same period last year. After adjusting to remove benefits of the QF gain and the 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. Travis has included the bridge at page 30. 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. The Board declared a quarterly dividend of $0.575 per share, payable March 29th to shareholders of record as of March 15th. Two 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 two jurisdictions. Add to that rate case preparation. Add to that preparation of two supply plans.
Most fundamentally, the significant capital expense budgets we've committed to our transmission and distribution operations. As the Billy Joel song says, we're still standing. From a customer perspective, most importantly, we had the best year ever in terms of customer satisfaction. The best year that our distribution vice president, Curt Pohl , or any of us can recall from a customer reliability perspective, and a very strong year yet again on employee safety. Where it counts, and with your support, we really are delivering for our customers. The whole company looks good. 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, transmission, distribution, everyone in customer care.
The investments that we've made over time in all aspects of the system have paid off to serve our customers. Most importantly, our extraordinary employees who are, whether they're on the phone at a desk, or particularly the folks who've been out in the field in very dangerous weather, keeping our customers safe and warm. Fundamentally, that really is what it's all about. We sincerely appreciate all of your support, in making that possible. With that, I'll turn it over to Brian.
Thanks, Bob. On page four is a summary of the financial results. Bob did touch upon these, on the summary page, you see net income of $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 of 17.4%. Lastly, dividends paid, $2.20, which is a $0.10 increase, or almost a 5% increase on a year-over-year basis. Going to the next page, talking about gross margin on a full-year perspective. Gross margin was $919.1 million. That was a $23.7 million 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 is up $6.2 million. We've seen increased utilization of our system during the year. Natural gas retail volumes, a $3.3 million improvement. Customer growth and primarily a significant contribution from our South Dakota business, which was much colder, 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. Think of that as effectively 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 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 current-year method, if you will, the finalized current-year method, if you did for TCJA. 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 two 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 six. If you're looking at this, that Montana was much milder than it had been, particularly on the cooling degree day, certainly flat on heating degree, as a whole, was unfavorable for the year.
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. It helped with, in addition to customer growth in the South Dakota weather, that primarily carried the day from a margin perspective. We did estimate favorable weather in 2018 of about $1.3 million pre-tax benefit compared to normal, and a $2.1 million pre-tax detriment when compared to 2017. Moving on to operating expenses on page seven. Operating expenses full-year were $652.9 million, a $29.4 million increase year-over-year, or 4.7%. Consistently along, OG&A was up 4.2%. 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%.
When you consider just those items impacting net income, we've managed to keep OG&A flat for the year. Those primary drivers for the $2.1 million increase did have an increase in employee benefits, higher medical costs, and higher pension costs on a year-over-year basis. We did spend more on hazard trees in 2018. Offsetting those two increases, the DSIP program, which was completed last year, so we had lower costs associated with that in 2018. We had lower labor costs, really driven by two reasons. One, we had a lower headcount on a year-over-year basis, and the headcount that we had remaining, of course, spent a lot of time working on capital projects. Lastly, lower maintenance cost. It was not a scheduled outage year for coal stripping, so we had lower maintenance costs as a whole.
Those items equate to about the $2.1 million change impacting net income. Items not impacting net income, the primary driver there is the pension, other post-retirement benefits of $10.3 million. I think all of you are now aware that that change, if you will, is offset in other income. Taking all of those factors into consideration, the increase of the $12.3 million increase in OG&A, and as I mentioned earlier, approximately an $8 million increase in both property taxes and in depreciation associated with plant additions made during the year. Moving on to page eight, operating income, $266.2 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 on the pension expense shown here in other income. That was partly offset by lower AFUDC.
With taking those things into consideration, pre-tax income, $178.3, up $2.2 million or 1.2%. Below that, obviously the big income tax benefit year-on-year of $32.1 million. That was really the culmination of both $19.8 million final assessment excess-of-current-tax liability I'll talk about in a minute, and other impacts from TCJA. Taking those changes in consideration gets you to the final net income number of $197 million that we discussed earlier. Turning to page nine is where we talk about income tax reconciliation. This is the $32.1 million benefit on a year-over-year basis, really driven by three primary factors. Obviously, the change in the federal 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 and our excess-of-current-tax liability, resulted in a gain.
That particular tax liability was primarily associated with goodwill and was non-jurisdictional, if you will, to the rest of our business. That benefit, those two items were offset by lower qualified 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 qualified 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 see an improvement on year-over-year from 53.7% to the end of 2018 to 51.7%, driven by obviously the improvements in the business from a financial perspective, but also the equity that we have raised in the latter half of 2017 and the early part of 2018. By moving to this better capital structure, if you will, gives us more room from an equitable 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 insurance proceeds during the current period. We used that improved cash flow really to do two things. From an investing standpoint, we had higher investing activities compared to earlier, as a result of the Two Dot Wind acquisition earlier in the year.
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 the bottom of that page, you see we started with the $3.92. We had three 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. Then here in the fourth quarter, we're removing $0.25 associated with the impact 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 that we provided earlier in the year.
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 review year for us as a company, as a result, we will not be providing guidance. We 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 three adjustments for 2018. We 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 in cost of sales was a result of looking at the future liability associated with the QF, and that had not increased to the level that we expected it to from an accelerated cost perspective. That was a benefit to us. Lastly, TCJA is made up of several components. First and foremost, think of it this way. We looked at when we provided guidance for how we were going to do from a current year method perspective. One thing, as 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.
If you think of $19.5 million+ 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 the $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 the benefits that would go towards Hazard Tree spending in the year. Obviously, the settlement that took place.
It did not convey that way that the $20.5 milliion that we paid out in Montana, + $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 in the settlement, as we discussed the settlement in the past, was the idea that that $3.3 million would not be disputed as a known and measurable in the upcoming rate review. Those two items, the $6.1 million and the $3.3 million of OG&A, recovery of Hazard Trees, net back of $9.4 million. The new tax effect that, it's a $2.4 million adjustment. That and the $19.8 million taxes 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, everybody knows just 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 transition revenues. Seems to make sense, around 1.6% improvement there. OG&A expenses, you can see, flat and no adjustment to the property or depreciation. Gives us total expense increase about 2.6%. There our operating income remains relatively flat. Other income, as I mentioned, AFUDC is slightly lower. We had some projects that wrapped up in 2017, thus lower AFUDC in 2018.
That gives us a pre-tax decrease on a year-over-year basis of 2.2%, with all of the net impacts of taxes and the lower rate gives us an additional $13.3 million improvement, resulting in the improvement of net income of approximately 6%. Did issue shares into 2018, and that dilution on a year-over-year basis impacted EPS and on a non-GAAP basis year-over-year, 2.7% increase in diluted EPS. With that, I'll hand it back over to Bob.
Thanks, Brian. I'll highlight several things and 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 jurisdictional Montana transition assets. Ongoing investments in transmission and distribution infrastructure. As we've 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, both our electric and natural gas systems.
A notable and important development is we have decided to join the Western Energy Imbalance Market. 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, and 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. 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. You have the timeline.
You 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 benchmarked very well against our peers, and in fact, even outside of our peer group. We happen to have on both our South Dakota and Montana electric supply plans. Turning to the tracker, 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 with a symmetrical deadband of ±$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 1st, 2017.
Our 2018 results include a net reduction in the recovery of supply costs for customers of about $1.5 million. As shown in the consolidated statements of income, that includes the following, as described on slide 14. For 2017 and 2018, actual costs were below the base revenues by about $3.4 million. That resulted in no refund under the formula to customers. However, for 2018 and 2019, actual costs were above base revenues by about $11.8 million, and that, 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 supply costs for the first six months of that period.
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 for the rest of all the customers run too far out. A little bit more on Tax Cuts and Jobs Act. We did reach conclusions in all three jurisdictions. In Montana in December, the commission approved a settlement providing for $20.5 million one-time customer credit to electric and natural gas customers. In addition, the settlement provides $1.3 million in annual reductions in natural gas rates beginning in 2019. You recall, we had a natural gas case in Montana last year and one is being contemplated this year, and additional funds for low-income energy assistance weatherization.
As Brian highlighted, and this is extremely important going forward, an 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 filing. The settlement order also addressed issues related to the revaluation 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 two-year rate moratorium until January 1st of 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 revaluation 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 due to the reduction in the federal rate. $3.3 million of expenses related to our hazard tree program, as agreed to our Montana settlement. You'll recall their initial filing with the commission, instead it proposed using a portion of the TCJA benefits to fund the expenditure. Again, as Brian referenced. We expect a reduction in our cash flows from operations ranging from $20 million-$22 million this year as a result of customer credits.
Due to our existing NOL position and other tax credits, we expect to be a cash taxpayer during 2020, with credits reducing our cash tax obligation into 2022. We estimate that our effective income tax rates will range from 0%-5% this year. Next, moving to the two 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 to lower our operating costs. The plan identifies 90 MWs of existing generation that should be retired and replaced over the next 10 years, and that is in addition to 8 MWs of mobile generation that will be installed by the end of this year. That program is well underway.
We also expect to issue an all-source request for proposal in the second quarter 2019 to replace 60 MWs of combustion generation by late 2021, and that would be located here in South Dakota. There will be a press release put 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 of 2019, expected to be finalized mid-year after a 60-day public comment period in front of the commission. The plan is focused on our significant generation capacity deficit and our negative reserve auction. Our current peak requirement for energy in Montana is about 1,400 MWs, and we are currently 630 MWs short. This is, of course, all subject to market purchases. We forecast that our generation portfolio will be actually 725 MW s short by 2025.
Add to that regional concern about planned regional requirements of 3,500 MWs of coal-fired generation. That is a forecast from the Northwest Power and Conservation Council that could potentially cause loss of load probabilities, regional shortages as early as 2021. I think of this as a lot of straws sitting in the same drink, and the drink is getting pretty depleted. We expect to solicit competitive all-source proposals in 2019 for up to 200 MWs of capacity to be available by 2022. These supply additions will meet about 25% of the projected need in 2025. We would essentially wash, rinse, and repeat. We would repeat the process in subsequent years to provide a resourced, adequate energy and capacity portfolio by the end of that process. Note that the all-source capacity additions that we are discussing here are subject to competitive solicitations administered by independent evaluators.
As a result, we have not included the necessary capital investment in our current five-year capital forecast. These additions could increase our capital spending in excess of $200 million over the next five years. Turning to the rate case. Today is a significant day in the rate case. This is our first Montana general electric case since 2009. We have efficiently managed our operating administrative expenses over this time period. This filing is driven, from our perspective, by the increased Montana property taxes, which are only partially recovered through transfers, 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 case. We have requested $34.9 million in an annual increase to electric rates.
This reflects a 6.6% increase in Montana electric revenues, including a 7.4% increase to typical residential bills. We've requested a 10.65% ROE, 4.26% cost of debt, 49.4% equity, and a 7.42% return on rate base. We also requested $13.8 million of interim relief. Our initial request was to be effective November 1st of 2018. We expect action on our interim request after intervener testimony is received and reviewed by the Commission. Of course, if the Commission does not issue an order within nine 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 their new rates. The timeline. Intervener testimony is due today. It's significant that we've made this key date in the testimony with no notable slip in the schedule. This is from the eighth to the 12th. NorthWestern will file its rebuttal, cross-intervener testimony would also be due on April 5th. The hearing is scheduled to commence on May 13th. 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'll see, again, as you have every quarter, a relatively stable capital commitment over a five-year period. I would highlight, once again, that this includes the only supply capital reflected in this is the South Dakota mobile units, and some small amount for hydro upgrades in Montana. Essentially, this is a transmission and distribution capital forecast. A $1.6 billion of total capital over five years. The increased investment in the first three years is primarily the result of the AMI program that I've described. We anticipate funding these investments with a combination of cash flows, facilitated by NOLs in 2020, along with long-term debt issuances. Significant capital investments that are not in these projections or further negative regulatory outcomes could necessitate additional equity funding. Again, capital investments do not include anything necessary to address capacity issues identified in either the South Dakota or Montana resource proposals.
With that, we can go to questions.
Operator, 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 that your mute function is turned off to allow your signal to reach the system. Again, please press star one to ask a question. Our first question will come from Nicholas Campanella of Bank of America.
Hey there. How are you?
Good.
Hey, I just had a quick question first on the resource planning. I know you said $200 million to the next five years. Is it safe to assume that's just for the 60 MWs in South Dakota and 200 MWs in Montana, or is there more spend associated with that 200 per year from 2022 to 2025?
Yeah. I want to just make sure, Nick, you're following us here. The 200 MWs per year, Bob was talking about the Montana plan itself when he talked about that over, actually a four-year period. We'll be asking for RFPs here in each year, it's for 200 MWs. 60 MWs for South Dakota was completely separate from that discussion.
Got it. Okay. In all in, we should be thinking about $200 million for these programs in capital.
I think what we said here is, from our perspective, we're not putting any of the capital from South Dakota or Montana from these RFPs that are going out with our resource plans in Montana, South Dakota. We're not including anything in our capital plans. We're saying we hope to and could expect to win in excess of $200 million associated with that. We're not saying that's Montana, South Dakota, or anything at this point in time.
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 that's best for customers.
Absolutely. Got it. Then just on the no equity comment on the CapEx slide, can you, Brian, give us a sense of where your FFO statement metrics were on a trailing basis this year and then where you see them going in your current capital plan, barring any board revisions in the CapEx from successful RFPs?
Nick, I think when you look at 2018, this is thinking about how the rating agencies do that, I see ourselves being in the high 15s and expect to stay in that level and improve a bit over time, which is quite a bit above kind of a 14% and a BB B, BA A 2, if you will, at Moody's. At those levels, we think as long as we're above 14, we're going to be in pretty good shape. Right now, our plans are in good shape and should be able to manage the capital plan appropriately. As Bob pointed out, if we're successful in any of these RFPs, if there's anything else that comes up from a negative regulatory standpoint, obviously things can change. We feel good with our capital plan, and we're going to be in great shape with the rating agencies.
Great. My last question was, I'm sorry if you touched on it already, I know that you guys aren't giving 2019 guidance given the pending rate review. Is there any kind of tangible drivers that you can call out for the year in either direction? I know you have the 0%-5% tax guidance out there, where would you see O&M property taxes going in that time period?
Yeah. We're not really prepared to talk about that at this point in time, Nick.
All right. Thank you.
Okay.
Thank you. Our next question comes from Michael Weinstein with Credit Suisse.
Hi, guys.
Hey, Michael.
Hey, Michael.
Hey. The $6.1 million negative impact in 2018 from the TCJA, since that is based on an 18-month settlement, versus the original 12 months which you had originally put into your guidance or had reserved for it, right? The $6.1 million is the additional impact of the additional six months. Is that basically reversed in 2019 because it accounts for taxes that will be paid in 2019?
I guess I look at it this way. The settlement on the electric side was handled in 2018, and so there's going to be no detriment or deferrals, if you will, in 2019 associated with the electric side of the business. We'll continue to on the gas side, the $1.3 million on a going forward basis. That deferral, if you will, continue. We did settle in 2018 for all of electric, and until new rates go in effect from the rate case, we're done with TCJA.
Right. Okay. Basically, but it is a kind of a pull forward of $6.1 million of earnings impact right from taxes into 2018 that would have occurred in 2019.
Yeah, I could say at least for that half year, I'd argue that half of that would have rolled into 2019 had we not settled. Right? Because if the rate case goes back to R1.
On EIM, have you guys thought about what kind of transmission infrastructure might be needed in order to comply with EIM rules for 2021? Is there any potential CapEx in there that might come up?
What I would say is we're an active participant in the original market. EIM will increase that activity. Certainly, we would look for any opportunities.
Also, just one last question. When you look at the rate cases and the RFPs, what do you think at this point this year might give you enough confidence? Do you have enough confidence to perhaps raise the total return guidance back to the old 7%-10%?
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 that's going to work out. I thought I made it pretty clear in the past that you could see us move up within that range, that 6%-9%, if we're making some investment in the electric supply side. I don't see there's any change in that dialogue until we're successful, if we are ever become successful down the road.
Brian wanted to answer that question.
Actually, I do have one more question. It has to do with the tax repairs discussion. There's a benefit from that in 2018 earnings. How is that being proposed to be treated in the rate case?
Well, if you're talking about the 19.8 tax-as-to-protect liability adjustment, if you're talking about that particular item, I'm not sure of the question. If you're talking about that, since that was associated with goodwill, that's not going to be dealt with in the rate case. That's a non-jurisdictional item. Make sure I'm understanding your question, Michael.
I think that's right. I mean, that's right. I'm just wondering, is that being disputed, though, that it's non-jurisdictional?
It's not disputed. It's associated with goodwill.
Okay, all right.
I thought you might have said the words repairs. That's what kind of threw me off there, Michael.
Oh, yeah. I'm thinking specifically about the repairs deduction.
No, repairs-
Okay, sure. Yeah.
Repairs will be dealt with in the rate case.
Yeah.
All taxes will be captured in the rate case, including how we handle repairs.
Are you booking a benefit from that right now?
We continue to take repairs deductions during the year, correct.
Okay, thanks.
Thanks, Mike.
Our next question will come from Paul Ridzon with KeyBanc.
Good afternoon.
Hey, Paul.
Where does your request for interim rates stand, and what's that process look like?
Typically, the Montana Commission waits until intervener testimony is received. As you know, that's coming in today. 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 they're going to. Practice in Montana is they want to see the delta between the filing party's ask and potentially the consumer counsel's.
When would that be retroactive to?
That would be up to the commission.
Okay.
We put it on our request.
There's no fixed date after you file when information is okay?
No.
Thank you very much.
Thanks, Paul.
Thank you. Our next question comes from Paul Patterson with Glenrock Associates.
Good afternoon, guys.
Hey, Paul.
Just, there's a lot of moving pieces here when you think of the capital opportunities that you guys have. Just sort of looking forward here, some of these things might have all kinds of in theory might have lower costs associated with operations and what have you. I'm 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 and given the other circumstances, if you follow me, and how should we think about you guys going in for regulatory relief?
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've seen us also manage our costs significantly to try to keep that as low as possible. We think at the capital levels that we have in place, that is going to do exactly that, keep rates relatively flat and increasing at inflationary pressures.
History over the last several years, certainly for the last decade, has been one of thoughtfully scheduling investments in traditional infrastructure as well as in technology to do just that. On both the electric and capacity side, we've managed to maintain rates significantly below national averages. That's even with the unique contribution that Montana, in the way it does property tax makes to our customers' bills. We've done a good job managing costs to customers, and our staged approach to capital is a part of a reflection of that.
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 other costs that pass through to our customers. 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. That's also our hope.
Okay, great. 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.
Bob.
All I was going to say was, read it when it comes out. We are anticipating looking at more of a formulaic approach. The ultimate point is to reconcile what happens in the FERC jurisdiction with what happens, in this case, in the Montana jurisdiction and to us and our shareholders whole.
Could you elaborate a little bit more on that? I apologize. Are you saying that you want when you talk about having them match each other, could you tell a little bit more about that?
That we're neither under-recovering or over-recovering in either jurisdiction. That essentially nothing falls off the table between the gap between the two.
Okay. Thanks so much.
Well, thank you. The next question comes from Vedula Murti , Avon Capital.
Good afternoon.
Hi, Bill.
A couple of things. I just want to make sure I'm kind of clear on this. The 60 MW RFP in South Dakota, when will you know whether you'll be allowed to put in your own proposal with others and third-party evaluate? When did you find out the winner?
This is John Hines. We're going to be issuing the RFP in April. Approximately by the end of the third, fourth quarter, we'll have an idea of what those bids are, and we'll make the determination of whether we're successful, who will be part of an EPC bid, the existing site in Huron. When we make the determination in early 2020, with hopefully construction to begin soon thereafter.
John is our Vice President for electric and gas supply.
Okay. You'll be able to tell us that whether or not your proposal was the least-cost, most effective one, should I call it, fourth quarter of 2019?
Correct.
Okay. Construction is how long?
We can't tell with any definition right now because it'll be dependent upon the bid, but we expect it to be operational by 2022.
Is there, like, a general dollar range that we should be kind of, working things off of?
Again, I'd be reluctant to give a dollar range right now until the competitive solicitations are complete and evaluated.
I think I was going back to Nick's question about the $200 million. Is the 60 MWs a subset of that $200 million, or 60 MWs is completely separate?
I think it depends. If you're talking about the $200 million of the additions could increase our capital spending in excess of $200 million over the next five years. If you're talking about that, our opportunity to participate in this would be considered in that.
Would be part of that. Okay. Then, in Montana, the RFP there is for $200 million, correct?
That's our metal. Out of the plan when filed and the comments on the plan.
Yeah, it's up to 200 MW beginning this year.
I think what Bob mentioned on earlier in the call is when he said, rinse and repeat, because we're going to be doing 200 MW RFPs in multiple years after that.
If you have an RFP, is this RFP already outstanding and in motion?
No. As part of the plan development, there was a request for information, but an actual RFP soliciting proposals, to build or contract, any kind of facility or any kind of demand-side activity would come after the plan has been filed, and then presumably after a 60-day comment period in front of the commission. That is a future event.
Based on previous experience, at what point would this RFP be issued?
At some point, if the schedule holds, I would say November, but later this year.
That's correct. The urgency, I think, as we've talked about before, is pretty strong given what we see as the regional shortages coming up as well as our deficit internally. We will be moving as quickly as possible to get these RFPs in action year-over-year.
Our customers, we are already seeing significant price volatility at peak, in both summer and winter periods. That is the price risk is indicative of an underlying supply risk at some point.
Will we know by the end of 2019, the outcome of the RFP in Montana?
No.
We will not know until 2020.
Correct.
Once we know. Over.
I just want to say, what Bob's referring to is the regulatory uncertainty, depending on when we get the plan out, when we get the 60 days, and the timeframe necessary to conduct the competitive solicitation. We may have that information by the end of 2019, or early 2020. We just can't give a firm date until we actually undergo the process.
Would you say end of 2019 or early 2020 of the total resolution of knowing what happened?
That's correct.
All right. Thank you. Our next question will come from Paul Ridzon, KeyBanc.
Bob, how often does rinse and repeat, how often do you do that?
It could be developed during the planning process. Realistically, 3x to 4x .
Annually or?
By the way.
Paul, it will be 4x in order to meet our needs by 2025.
By 2025.
Yep.
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 about 800 MWs, if you will. After that, those four RFPs are going to have to accumulate to 800 MWs. In essence, they're going to have to be carried out over a time period to fill that gap by 2025.
That's basically every year you're going to have to do an RFP, is it sounds like?
Correct.
Okay. Each of those is $200 million or cumulatively $200 million?
200 MWs. 200 MWs.
You threw out the $200 million of potential capital. Is that for the first RFP or is that-
No. Yeah, the $200 million of capital, of our capital, is the ability to participate in all of these efforts. We're saying that our expectation is we could do in excess of $200 million of capital in all of these activities.
Okay, you get a slice of each RFP or one RFP or something like that?
Absolutely. Something in Montana, something in South Dakota. I'm not going to share what our expectation is of capital by project.
Understood. Thank you very much for clearing that up.
Just a minute more on the process, John can pick it up here. The South Dakota process, as you described, is well underway, very well-defined. In Montana, the RFPs would go out at the plan. The plan models a variety of scenarios, focuses on what is our customers' critical unmet need. Again, that is for dispatchable, sustained peak 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 of proposals over time. Likely, we hope, changes in price and changes in technologies that might become available.
We're emphatically not selecting particular favored resources. We're 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 different technologies as those technologies become cost-effective.
I'd say there's three main things or takeaways I would suggest that will be coming out of this plan. One, the customers in Montana, their portfolio is significantly short. Two, that the region which NorthWestern purchases power is becoming shorter and shorter, especially from a capacity perspective. Three is the regulatory expectation is that we run competitive solicitations. That's our plan to fulfill all three of those over the next five years.
Thank you.
All right. Thank you. We have another question from Vedula Murti with Avon Capital.
Sorry to come off to you here. In 2018, what was the earned ROE in Montana as compared to your ROE request in the current case?
Yeah, Vedula, we'll be coming out with our Montana annual report shortly after we make our Form 1 filing, and we'll display at that point in time our Montana ROEs. You'll have to wait a bit for that.
Okay. I assume that the same for the FERC ROE with respect to that filing as well?
We'll have a FERC ROE in the filing itself. Correct.
Okay. It would be overly simplistic to basically think that if you took your current Montana request and zeroed it out and basically took what would be the after-tax effect, that that is kind of what you earned. That's overly simplistic. That's kind of why I was trying to figure it out.
Yeah, I wish I could help you on that.
Okay. I have currently no further questions in the queue at this time.
Okay. Great. Well, thank you very much for joining us, and look forward to visiting with all of you next quarter and many of you over in the next few weeks. Thank you.
Thank you, ladies and gentlemen. This concludes today's teleconference, and you may now disconnect.