Good day, and welcome to the Northwestern Corporation's Year End 2018 Financial Results Conference Call and Webcast. Today's conference 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 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 ks premarket report. 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 to 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 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 ks and 10 Q along with other public filings with the SEC. Following our presentation today, we will open the phone lines to allow those dialed in to the teleconference to ask questions.
An archived replay of today's webcast will be available beginning at 6 pm Eastern Time today and can be found on our website at northwesternenergy.com under the Our Company, Investor Relations, Presentations and Webcast link. The audio replay of the call is available at 288 203-eleven twelve and access code 3,377,925. Again, that is 888 203-1112 access code 337,975,935. I'll now hand our presentation over to our CEO, Pablo.
Thank you, Travis, and greetings from South Dakota where the sun is out today. Is a little bit unnerving after the winter weather. We've been enjoying so we're ordering 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 effectively 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 $34,300,000 or 21.1 percent, which 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 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. And these improvements were partly offset by an increase in depreciation expense.
Diluted EPS increased $0.58 or 7 0.4% as compared to the same period last year. And after adjusting to remove benefits for the QF gain in 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. And Travis is in pretty good range 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 are requesting a $34,900,000 or 6.6 percent annual increase to our base revenues, primarily as a result of increases in property taxes and capital investments.
And then the Board declared a quarterly dividend of $0.575 per share payable March 29 to shareholders of record as of March 15. Two comments before I hand it over to Brian to go deeper on the financial side. First of all, a reflection on last year. 20 18, as you all know, was a challenging year for us. We knew that going in.
I think where PKAN was even before the start of 2018, fall of 2017, add to that TCJA implementation of certain jurisdictions, and that rate case preparation, and that preparation of 2 supply plans. And then most fundamentally, the significant capital expense budgets we've committed to our transmission and distribution operations And as the 30% song says, we're still standing. And 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 Kurt Bole or any of us can recall from
a consumer liability
perspective, we've had a very strong year yet again on employee safety. So where it counts and with your support, we really are delivering for our customers. I think of us as a whole company that could. 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 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 that we've made over time in all aspects of the system have paid off to serve our customers. And most importantly, our extraordinary employees who are whether they're on the bone at a desk or particularly the folks who have been out in the field in very, very dangerous weather keeping our customers safe and warm. Fundamentally, that really is what it's all about and we sincerely appreciate all of your support in making that possible. And I'll turn it over to Brian.
Thanks, Bob. On Page 4 is a summary of the financial results. Bob didn't touch upon these, but on the summary page, you see net income was $197,000,000 an increase of 44.3 percent or 21%, resulting in diluted earnings per share of 3.9 $2 a share, a $0.58 improvement of 17.4%. Lastly, dividends paid 2.20 dollars which was a $0.10 increase, 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 $919,100,000 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 increased $30,000,000 or 3.3%. Speaking of those items, what were the primary drivers? The electric QF liability adjustment we talked about in the Q2 of this year.
For the full year basis, our electric transmission business is up $6,200,000 We've seen increased utilization of our system during the year. Natural gas retail volumes, dollars 3,000,000 improvement in 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 $6,100,000 reduction in gross margin impact of the TCJA or the Tax Cuts and Jobs Act. And 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 $30,000,000 change in gross margin impacting net income.
Below that, those items that are offset elsewhere in the P and L and the impact net income, 1st and foremost, dollars 17,400,000 Think of that as going to be current year method if you are the finalized current year method if you did for PCJA and that is the impact that is offset in taxes. Offsetting that $17,400,000 item is a $11,700,000 recovery of property taxes during the year. Those two items make up the majority of the $6,300,000 negative change in gross margin, netting for the total gross margin of $23,700,000 Moving forward to weather on Slide 6, we're looking at this that Montana was much milder than it had been particularly on the cleanest day, but certainly flat on heating degree and as a whole was unfavorable for the year. But South Dakota and Nebraska, a big degree were quite helpful in terms of being much colder in the winter and much hotter in the summer. So it helped with in addition to customer growth in the sub for the weather that primarily occurred today from a margin perspective.
We did estimate favorable weather in 'eighteen of about $1,300,000 pretax benefit compared to normal and $2,100,000 pretax detriment when compared to 2017. Moving on to operating expenses on Page 7, operating expenses for the full year were $652,900,000 a $29,400,000 increase year over year, up 4.7 percent. Consistently along, if you think OG and A was up 4.2%, both property tax and depreciation were up about 5%. When you take into consideration those increase in OG and A that actually impact net income, that was actually only up $2,100,000 or 0.7%. So again, when you consider just those items impacting net income, we've managed to keep our G and A flat for the year.
Those primary drivers were $2,100,000 increase. We did have an increase in employee benefits, and higher medical costs and higher incentive costs on a year over year basis. We did spend more on hazard trees in 2018 offsetting those two increases. The D SIP program which was completed last year, so we had lower costs associated with that in 2018. And we had lower labor costs driven by two reasons.
1, 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. And lastly, lower maintenance cost. It was not a scheduled outage year for Colstrip and so we had other lower maintenance costs as a whole. Those items equate to about the $2,100,000 change impacting net income items not impacting net income. The primary driver there is detention and other post retirement benefits of 10,300,000 dollars I think all of you are now aware that that change if you will is offset in other income.
Taking all of those factors in consideration, the increase in the $12,300,000 increase in OG and A. And as I mentioned earlier, approximately an $8,000,000 increase in both property taxes and in depreciation associated with plant additions during the year. Moving on to Page 8, operating income 266,200,000 actually down 5,500,000 or 10%, below that interest expense relatively flat year over year. Other income actually up $7,400,000 Again, this is the $10,300,000 decrease in other pension expense shown here in other income, but that was partly offset by lower AFFT. And taking those things into consideration, pre tax income $178,300,000 up $2,200,000 or 1.2 percent.
And below that, obviously, the big income tax benefit during the year of $32,100,000 that was clearly the combination of both $19,800,000 final assessment of excess deferred tax liability I'll talk about in a minute and other impacts from TCJA. And taking those changes in consideration, to the final net income number of $197,000,000 that we discussed earlier. Turning to Page 9 is where we talk about income tax reconciliation. This is the $32,100,000 benefit on a year over year basis, really driven by 3 primary factors. Obviously, the change that federated 35% to 21% drove a $24,200,000 benefit.
That and also the $19,800,000 which is effectively when we look at TCJA and our excess deferred tax liability resulted in a gain that particular deferred tax liability is primarily associated with goodwill and was non jurisdictional if you will, to the rest of our business. That benefit, those 2 items were offset by lower flow through repairs deductions. As you think about a certain amount of capital spend that is eligible for repairs deduction, when you have a lower tax rate, you need less of a
benefit from flow through repairs. And so that was kind of
an offset leading us to approximately $32,100,000 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 year over year from 53.7 percent to the end of 'eighteen to 51.7% by obviously improvements in the business from a financial perspective, but also the equity that we have raised in the latter half of 'seventeen and the early part of 'eighteen. And moving to this better capital structure, if you will, gives us more room, if you will, from an effort to coverage ratios with the rating agencies as well. Moving on to cash flow on Page 11. Cash flow just over $381,000,000 primarily increased to almost $50,000,000 due to higher net income, improved customer insurance proceeds during the current period.
We used that improved cash flow really to do 2 things from an investing standpoint, and we have higher investing activities per carriers resulted in our wind acquisition earlier in the year and 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. On that page, you see we started with the $3.92 We had 3 adjustments during 2018. We removed $0.02 of favorable weather. We removed $0.25 dollars of the qualifying facility, the gain that we have in the 2nd quarter.
And then here in the 4th quarter, we're removing $0.25 associated with the impact of TCJA and I will talk about that more in a minute. Those adjustments resulted in a 3.39 dollars outcome that compared to $2.30 on a year over year basis, dollars 3.39 if everyone knows within the guidance range that 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. We want to make sure that people are well aware that we still tend 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, we talked about favorable weather earlier. We've talked in the past and the gain on the qualifying facility. If you recall that $17,500,000 adjustment in cost of sales is a result of looking at the future liability associated with the QF and that had not increased 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.
1st and foremost, think of it this way, we looked at and we provided guidance how we were going to do from a current year method perspective. And one thing as I pointed out earlier, the $6,100,000 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 $13,500,000 that's the settlement between Montana and South Dakota that we paid out, take that versus the $17,400,000 differential as I mentioned in terms of the true current unit benefit that's the $6,100,000 we're adding back here. We also made adjustments to OG and A. We did not intend to have $3,300,000 of expenses to hit our P and 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% benefit back to customers in cash that we see benefits that would go towards hazard tree spend during the year. Obviously, the settlement that took place did not convey that way with the $25,000,000 that we paid out in Montana, dollars 3,000,000 in South Dakota was all paid in cash to our customers during the year. On Project Trees though, one thing that we did receive in the settlement has been discussing settlement in the past, was the idea that that $3,300,000 would not be disputed as an unmeasurable in the upcoming rate review. Those two items, the $6,100,000 and the $3,300,000 of SG and A, recovery of hazard, trees, netback of $9,400,000 dollars The new tax effect of that is a $2,400,000 adjustment. That and the $19,800,000 excess deferred tax liability adjustment I discussed earlier making the 42.2 percent income tax adjustment to get to the 12.8 percent net income item there.
I know it's a lot of stuff on tax cuts and jobs acts, but everybody knows that was built through in 2018. Having talked through all of those items, when you look at the non GAAP earnings through the P and L perspective on a year over year basis, gross margin up about 1.6%. I think our customer growth around 1% and some better weather and better transition revenues it makes sense around 1.6% improvement there. OG and A expense, as you can see, flat and no adjustments for property depreciation. This is total occupancy increase about 2.6 percent.
Our operating income remains relatively flat. Other income is, I mentioned, AFUDC is slightly lower. We had some projects that wrapped up in 'seventeen and thus lower APDC in 2018. That gives us a tax increase on a year over year basis of 2.2% It's all of the net impacts of taxes and the lower rate consistent with $2,300,000 improvement resulting in the improvement of net income of approximately 6%. We did issue shares in 'eighteen 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.
And with that, I'll hand it back over to Bob.
Thank you, 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 Q1 concerning our jurisdictional Montana transition assets, ongoing investments in transition and infrastructure. As we've discussed on previous calls, we take a comprehensive approach to our electric and natural gas infrastructure particularly 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 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 with electric and natural gas systems. A notable and important development is we have decided to join the Western Energy Inviolence 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 or 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 here on the dairy edge. So before committing to the Western market, we did consider other alternatives and had to determine ultimately that joining the Western Energy and Balance market would make a cost effective decision for our customers, the decision for the state. Then you have the timeline. You actually have an important meeting in several weeks to take that process off, culminating into an entry in 2021. Cost control efforts are important.
We think we benchmark very well against our peers, in fact, even outside of our peer group. And then we have to add on both the South Dakota and Montana electric supply lines. 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 $4,100,000 from an established baseline. Supply cost variances above or below the deadline are shared 90%, 10% with customers and shareholders respectively.
The limitation is retroactive to the effective date of the enabling legislation which was July 1, 2017. So our 2018 results include a net reduction in the recovery of supply costs for customers of about $1,500,000 as shown in the consolidated business income and that includes the following as described on Slide 14. For 2017 'eighteen, actual costs were below the base revenues by about $3,400,000 that resulted in no refunds under the formula to customers. However, for 2018 'nineteen, actual costs were above base revenues by about $11,800,000 and that then applying the formula results in a regulatory asset of customers of about $6,900,000 as well as a $4,900,000 reduction in recovery supply costs for the 1st 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 at least the most of all the businesses 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 20,500,000 dollars onetime customer credit to electric and natural gas customers. And in addition, the settlement provides 1 point $3,000,000 in annual reductions in natural gas rates beginning in 2019. Recall, we had a natural gas case in Montana last year and what is contemplated this year and additional funds for low income energy assistance for weatherization.
And as Brian highlighted, it's extremely important going forward. The commitment of the parties not to oppose our request to include up to 3,500,000 dollars of costs to address hazard tree removal in our 2018 electric rate filing. The settlement in order also then addressed issues related to the revaluation of deferred income taxes and those ultimately will be addressed in the late review. In South Dakota, in September, the fees to the approved settlement resulted in a $3,000,000 customer credit in the 4th 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 $1,000,000 due to the final revaluation of deferred income tax liabilities, a net loss of $6,100,000 resulting from $43,500,000 in customer credits from the approved settlements and that's partly offset by a $17,400,000 reduction in income tax expenses due to the reduction in the February 8 and $3,300,000 of expenses related to our hazard free program as agreed to our Montana settlement. Our initial filing would be if that if you recall, our initial filing with the Commission and instead it proposed using a portion of the PTC benefits to fund the expenditure, again, as Brian referenced. So we expect a reduction in our cash flows from operations ranging from $14,000,000
to $22,000,000 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 rate will range from 0% to 5% this year. Next, moving to the 2 electric supply plans, 1st in South Dakota. We 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 lower our operating costs.
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 total 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 Q2 2019 to replace 60 megawatts of combustion generation by late 2021 and that would be located here on South Dakota and a Visa press release without on that today. HDR, the engineering consulting firm will discuss on that process. Turning to Montana. The draft plan will be filed in the Q1 of 2019 and 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 1400 megawatts and we're currently 630 megawatts short And this is, of course, all subject to market purchases. We forecast that our generation portfolio will be at 725 Megawatts for high 2025. Add to that regional concern about planned regional retirements of 3,500 Megawatts of coal fired generation that we're forecasting in Northwest Power and Conservation Council
that could potentially
cause loss of gold probabilities, regional 3 week regional shortages as early as 2021. I think of this as lots of straws sitting in the same drink and drink is getting pretty depleted. So we expect to solicit competitive all source proposals in 2019 for up to 200 megawatts of heating capacity to be available by 2022. And these supply additions will meet about 25% of the projected need in 2025 and they would essentially wash, rinse and repeat. We would repeat the process in subsequent years to provide resource adequate energy and capacity portfolio by the end of that process.
And note that the all source capacity that we're discussing here are subject to competitive solicitations administered by independent evaluators and as a result, we've not included the necessary capital investment in our current 5 year capital forecast. These additions could increase capital spending in excess of $200,000,000 over the next 5 years. Turning to the rate case. FTE is a significant day in the rate case. This is our 1st Montana General Electric case since 2009.
And we have efficiently managed our operating administrative expenses over this time period. But this filing is driven from our perspective by the increased Montana property taxes, which are only partially recovered 2 factors and then the significant investment that we have been making particularly in our P and D system driving the request for relief. We filed with the commission in September based on a 20 17 test year and a $2,340,000 rate case. We've reposed to $34,900,000 and an annual increase to electric rates. This reflects a 6.6% increase in Montana Electric Revenues, including a 7.4% increase to residential bills.
We've requested a 10.65 percent ROE, 4.26 percent comp of debt, 49.4 percent equity and a 7.42% return on rate base. Also, we're attested $15,800,000 of interim relief. Our initial request was to be adopted 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 the NAND side enhancement costs, establish a new baseline for peak N costs to replace 2.Wid in rate case and to approve a new net metering customer class only to new residential private generation customers and the new rates. The timeline at our dinner testimony is due today and it's significant that we have made this key date in the testimony with no notable step in the schedule just from the 8th to 12 in the Northwestern oral style rebuttal and cross disciplinary testimony would also be given on April 5th, and the hearing is scheduled to commence on May 13th. This has been a substantial undertaking by employees and a great many parts of the business, and their work is sincerely appreciated, all of us. Turning finally to the capital forecast, you'll see, again, as you have every quarter, relatively stable capital committed over a 5 year period. I would 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 Canada.
So essentially, this is a transition and distribution capital forecast of $1,600,000,000 of total capital over 5 years. The NNG increased investment in the 1st 3 years is primarily the result of the AMI program that I described. We anticipate funding these investments with a combination of cash flows, estimated by NOLs in 2020, along with long term debt issuances. Significant capital investments that are not in these projections or for the negative regulatory outcomes could necessitate additional equity funding. And we think capital investments do not include anything necessary to address capacity issues and insights in either the South Dakota or Montana resource development.
And with that, we can go to questions.
Our first question will come from Chris Catania with Bank of America.
So I just had a quick question first on the resource planning. I know you said 200,000,000 dollars 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 per year from 2020 to 2025? Yes.
I want to just be sure, Nick, you're calling us here. The $200 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 each year, so it should be 200 megawatts. 60 megawatts for South Dakota was completely separate from that position. Got it.
Okay. But in all in, we should be thinking about $200,000,000 for these programs in capital? Well, I think what we said here is from our perspective, we're not quitting any of the capital from South Dakota or Montana from these RFPs that are going up for the resource plans in Montana, we're not including anything in our capital plans. We're saying we hope to and could expect to win in excess of $200,000,000 associated with that. So we're not saying that's Montana, South Dakota or anything.
The RFPs in each case would be run by a 3rd party. We have the opportunity to participate
that the RFP will both
select the option as customers.
Absolutely. Got it. And then just on the no equity comments on the CapEx slide, can you just, Brian, give us a sense of where your FFO to date features were on a trailing basis this year and then where you see them going in your current capital plan, barring any quarter visions in the CapEx from successful RFPs? Yes, Nick. I think when you look at 'eighteen, and 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 14% and then BBB, AA2 if you will at Moody's.
But 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 the capital plan appropriately. But 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. But we're good with our capital plan and we're going to be in great shape and creating. Great.
And then my last question was, and I'm sorry if you touched on it already, but I know that you guys aren't giving 'nineteen guidance given the pending rate review. Is there any kind of tangible drivers that you can kind of call out for the year in either direction? I know you have the 0% to 5% tax guidance out there, but where would you see O and M property taxes going in that time period? Yes, I agree that prepared to talk about that at this point in time, Nick. All righty.
Thank you.
Thank you. Our next question comes from Michael Weinstein with Credit Suisse.
Hi, guys. Hey, Michael. Hey, Michael. Hey. So the $6,100,000 negative impact in 2018 from the TCJA, Is that since that is based on an 18 month settlement versus the original 12 months that you had originally put into your guidance or as you reserve for it.
So the $6,100,000 is the additional impact of the additional 6 months. Does that basically reverse 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 'eighteen and so there's going to be no detriment or deferrals, if you will, in 'nineteen associated with the electric side of business. We'll continue to continue to on a gas side of $1,300,000 going forward basis.
So that deferral, if you will, continue. But we did settle in 'eighteen for all of electric and until new rates go in effect from the rate case we're done with CCJA.
Right. Okay. But it is kind of a
pull forward of $61,000,000 of earnings impact, right, from taxes into 2018 that would have occurred in 2019? Yes. I could say at least for that half year, I'd argue that a half of that would grow into 'nineteen, probably not settled, because of the rate case going back to I-one. Right. And 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 there that might come up? What I would
say is we're an active participant in the regional market. PIM will increase that activity. Certainly, we would look for any opportunities.
Okay. And also just one last question. When you look at the rate cases and the rate case and the IRPs, what do you think at this point this year might give you enough confidence, probably if you have enough confidence to perhaps raise the total return guidance back to
the old 7% to 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 we're going 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 69% 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 ever become successful. Way. Brian wanted to answer that question.
Actually, I do have one more question. It has to do with the tax and tariffs reduction. 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? If you're talking about the 19.8 percent excess deferred tax liability adjustment, if you're talking about that particular item, I'm not sure the question, but you're talking about that since I was associated with goodwill, that's not going to be dealt with in the rate case.
That's a non jurisdictional item. I'd make sure I'm understanding your question, Michael. I think that's right. I mean that's right. Yes, I'm just wondering is that being disputed though or that it's non jurisdictional?
It's associated with goodwill. I thought you might have said the words repairs. That's what kind of threw me off there, Michael. Yes, yes, yes. I'm thinking about the repairs assumption.
The repairs, I think we dealt with in the rate case. All taxes will be captured in the rate case, including how we handle repairs. Are you booking a benefit from that right now? Well, we continue to take repairs deductions during the year, correct. Our next question will come from Paul Ridzon with Cowen.
Credit. Where does your investor interim rate stand and what's that process look like? Like?
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 several weeks to decide whether and if yes, how much interim belief difference. Practice again is to want to see the delta between the filing party DASK and Vision 3, the consumer councils.
And when would that be retroactive, Phil? That would be up to the commission. We put it on our request. So there's no fixed date after you file when instruments are taken? No.
Okay.
Our next question comes from Paul Patterson with 1Rock Associates.
Good afternoon, guys. Hey, Paul. So just there's a lot
of moving pieces here when you
think of the capital opportunities that you guys have.
And just sort of looking forward here, I mean, some
of these things might have offset Sid Mob 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 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? 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 them as close as possible. And so we think at the capital levels that we have in place that is going to do exactly that steep rates relatively quietly increasing at inflationary pressures.
Okay. This for you 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.
And on the electric and gas side, we've managed to maintain rates significantly below national averages. And that's even with the unique contributions that's Montana, that's why this property tax makes it to our customers' bills. We've done a good job managing cost to customers and our staged approach to capital is a
partner of question. I'd also add to that. I think one thing that we've had success in the past and we have made investments in supply resources, we've offset other costs that pass 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.
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. 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 for a jurisdiction with what happens in this case in the Montana jurisdiction to us and our shareholders' whole.
Could you elaborate a little bit more on that? I apologize. So are you saying that you want to when you talk about having them match each other because you're I'm sorry. Could you tell a little bit more about that?
So that we're neither under recovering or over recovering in either jurisdiction. So essentially that falls off the table, the gap between the 2. Okay. Thanks so much.
Thank you. Our next question comes from 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 Once you find out the winner?
This is John Hynes. We're going to be issuing the RFP in April. Approximately by
the end of the 3rd, 4th quarter, we'll have an idea of what those
bids are and we'll make the determination of whether we're successful. We'll be part of the EPC bid with the existing site in Huron and when we have determination in early 2020 with hopefully constructions begin soon thereafter.
And John is our Vice President for Electric and Gas Supply.
Okay. So you'll be able to tell us that whether or not your proposal was the lease cost most effective one, if I call it, like 4Q of 2019?
Correct.
Okay.
And construction is how long?
We can't tell with any definition right now because it will be dependent upon the bid, but we expect it
to be operational by 2022.
And is there like a general dollar range that we should be kind of ripping things off of?
Again, I'd be reluctant to give a dollar range right now until the competitive solicitations are complete
and evaluated. But just going back to Nick's question about the $200,000,000 is 60 megawatts a subset of that 200,000,000 or 60 megawatts is completely separate?
It depends. If you're talking about the $200,000,000 of these positions could increase our capital spending in excess of $200,000,000 over the next 5 years. If you're talking about that, our opportunity to participate in this would be considered in that.
Would be
part of that. Okay. And then in Montana, the RFP there is for 200, correct?
That's our metal. Out of the plan when filed and the comments on the plan.
It's up to 200 megawatts beginning this year.
And I think what Bob mentioned earlier in the call is when he said rinse and repeat, we're going to be doing 200 megawatt RFPs multiple years after that.
So if you have an RFP is this RFP already outstanding and you're in motion?
No. As part of the planned development, there was a request for information, but actual RFPs, listing proposals to build a contract, any kind of facility or you can expand site activity would come after the plan has been filed and then presumably after a specific comment period in front of the commission. So that is a future event.
So based on previous experience, at what point would the RFP be issued?
At some point, if the schedule holds, I would say, no more than 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. And so we will be moving as quickly as possible to move these RFPs in action year over year.
Our customers, we are already getting significant price volatility at peak in both summer and winter periods and that is the price risk is indicative of an underlying supply risk at some point.
So will we know by the end of 'nineteen the outcome of the RFP in Montana? No. We will not know until 2020? Correct. And once we know
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 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 would be a total resolution of knowing what happened?
That's correct.
Our next question will come from Paul Ridzon with KeyBanc. Bob, how often is rinse and repeat? How often do you do that?
But they develop during the planning process, realistically, 3 to 4 times.
Annually or By the way. Paul, it will be 4 times in order to meet R and D by 2025. By 2025? Yes. In order to get RFPs in place, actually get construction, get these resources up and ready in 2025, we are going to need about 800 megawatts, if you will, after that those 4 RFPs are going to have to accumulate 800 megawatts.
And in essence, they're going to have to be carried out over a time period to fill that gap between 25. Yes. Basically, every year, you're going to have to do an RFP, is it, sounds like? Correct. Okay.
And each of those is $200,000,000 or cumulatively? 200 megawatts. 200 megawatts. $200,000,000 of potential capital, is that for the first RFP? Yes, the $200,000,000 of capital, our capital has ability to participate in all of these efforts.
And we're saying that our expectation is we could do in excess of $200,000,000 of capital in all of these activities. Okay. So 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 projects. Understood. Thank you very much for clearing that up. Just
more on process and John can talk about here. The South Dakota process, as you described, is well underway, very well defined. In Montana, the RFPs would go out of the plan. The plan models a variety of scenarios, focuses on what is our customers' critical And again, that is for dispatchable, sustained heat, the kind of resources that you need multiple times during the year to offset scalability 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.
But we're doing back to the earlier question about labor costs is managing cost to our customers and taking advantage of a likely diversity of 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 favorite resources. We're having 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? Yes.
I'd say there's 3 main things to takeaways I would suggest that will be coming out of this plan. One, the customers in Montana, their portfolio is significantly short. 2, that the region with Northwestern Purchase
this power is becoming shorter
and shorter, especially from a capacity perspective 3 is the regulatory expectation is that we run competitive solicitations. And so that's our plan to fulfill all three of those over the next 5 years.
We have another question from Shukla Murphy with Avon Capital.
Sorry to come a few here. But in 2018, what was the earned ROE in Montana as compared to your ROE request in the current case?
Yes. Bill, it will 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 have to wait a bit for that.
Okay. And I assume that's 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. So is it be overly simplistic to basically think that if you took your current Montana request and zeroed it out and basically took the after tax effect that that is kind of what you earned. That's overly simplistic. That's why I was trying to figure that out.
Yes, I wish I could help you on that.
Okay. And there are 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 this 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.