Well, good day everyone, and welcome to today's NorthWestern Corporation first quarter 2018 financial results conference. Just a reminder that today's call is being recorded. At this time, I'd like to turn the conference over to the Investor Relations Officer, Mr. Travis Meyer. Please go ahead, sir.
Thank you, Lori. Good afternoon, thank you for joining NorthWestern Corporation's financial results conference call and webcast for the quarter ending March 31st, 2018. NorthWestern's results have been released, and the release is available on our website at northwesternenergy.com. We also released our 10-Q pre-market this morning. On the call with us today are Bob Rowe, President and Chief Executive Officer, and Brian Bird, Vice President and Chief Financial Officer. We also have several other members of the management team with us in the room today to address your questions. Before I turn the call over for us to begin, please note that the company's press release, this presentation, comments by presenters, and responses to your questions may contain forward-looking statements. As such, I will remind you of the 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, often contain words such as expects, anticipate, 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 statements. We undertake no obligation to revise or publicly update our forward-looking statements or this presentation for any reason. Although our expectations and beliefs are based on reasonable assumptions, actual results may differ materially. The factors that may affect our results are listed in certain of our press releases and disclosed in the company's Form 10-K and 10-Q, along with other public filings with the SEC.
Following our presentation, we will open the phone lines to allow those dialed into the teleconference to ask questions. The archived replay of today's webcast will be available beginning at 6:00 P.M. Eastern today and can be found on our website, again, at northwesternenergy.com under the Our Company, Investor Relations, Presentations, and Webcasts link. To access the audio replay of the call, dial 1-800-485-8312, access code 4517992. Again, that's 800-485-8312, access code 4517992. I'll now hand the presentation over to our CEO, Bob Rowe.
Thank you, Travis. Good afternoon, everyone, thank you for joining us. We're calling in from our general office, in Butte, Montana, where they're still looking out the window at snow on the mountains, we think it may finally be spring. As we start, I should say, if you hear the throaty growl of a Harley through the window, it is not Brian Bird's midlife crisis. It's Travis' midlife crisis. We had a successful board meeting yesterday. The board last night had dinner with our Leadership NorthWestern class, which is one of our very vital employee development programs, had a good annual meeting this morning. All of the proposals passed overwhelmingly, we certainly thank you for your participation. Very importantly, this was Dr. Linn Draper's last meeting as board chair. He's guided us since 2004 has been an extraordinary mentor, leader, and friend.
Very good news is the board has selected Stephen Adik, who many of you know as the long-serving chair of the audit committee, to step up now as board chair. Steve will, in his own way, continue the focus and the dedication that Linn displayed, also that Steve displayed as a very effective and engaged audit chair. We continue to be fortunate with the board leadership that we enjoy. Turning to first quarter highlights. Operating income decreased $3.3 million as compared to the same period in 2017. However, if you adjust to remove the $7.3 million revenue deferral that was recorded during the quarter relating to the Tax Cuts and Jobs Act, operating income would have actually increased by $4 million or 4.6%.
Net income for the quarter was up $1.9 million, 3.4% as compared to the same period in 2017. That was primarily due to colder weather, an increase in Montana natural gas rates, increased demand for electric transmission, and lower operating general and administrative expenses. As a result of the increased average share count, diluted earnings per share increased less than net income to $1.18, as opposed to $1.17 during the same period in 2017. Adjusted non-GAAP earnings per share were $1.11 as compared to $1.13 during the same period in 2017. The board acted yesterday to declare a quarterly dividend of $0.55 per share payable on June 29th to shareholders of record as of June 15th, 2018. Brian will now begin with the summary of financial results.
Thanks, Bob. On page four in the summary financials, net income is $58.5 million, which was a $1.9 million or 3.4% increase on a year-over-year basis for the quarter. Bob mentioned the diluted earnings per share of $1.18 on a GAAP basis, $0.01 or nearly 1% better than the prior year period. Moving on to page five. Gross margin was $245.4 million, which was down $2.1 million or 0.8%.
On a year-over-year basis for the quarter. That decrease in gross margin, when you look at it from a change in gross margin that actually impacts net income, that was actually up $4.1 million or up 1.7%, primarily a result of both our gas and electric business performing well during the quarter. The area where we had a change in gross margin that offset within net income, where it's offset elsewhere in the P&L, we had a large deferral, $7.3 million of revenue deferred due to the change in income tax law in terms of how we're handling giving back our customers the income tax benefit that we'll be receiving in 2018. Those changes, with some other tracker changes that are offset elsewhere in the P&L, total to a decrease of $6.2 million net.
Of those two items, the $4.1 increase and the $6.2 decrease, net $2.1 decrease in consolidated gross margin. Moving on to page six, looking at weather for the first quarter, we were colder in all jurisdictions versus the prior year and versus historic average. I would point out and remind folks that Montana, of course, is the largest share of our business, greater than 80% of our business, though slightly colder in 2017 on a year-over-year basis, and obviously much colder in South Dakota and Nebraska on a year-over-year basis. I would argue that the favorable weather in Q1 contributed approximately $4.8 million pre-tax benefit compared to normal, and $1.6 million pre-tax benefits compared to Q1 2017. We'll talk about that more later in the presentation. Moving on to page seven in terms of operating expenses.
Operating expenses were $160.9 million, an increase of $1.2 million, or again, an increase of 0.8% on a year-over-year basis. Looking at the components of that, though, operating general administrative expenses were actually down $4 million or just over 5%. The explanation for that below shows that when you actually exclude the non-employee director's deferred comp and the employee benefits, one being a decrease, if you will, and one being an increase, those are both offset primarily in other expenses. Looking at the remaining items, though, decrease in maintenance expense, labor expense, less DSIP costs, because of the elimination of the amortization associated with DSIP and other costs coming down. We continue to manage our costs well to help offset slower margin growth than we've seen historically.
Below that, from a property taxes and depreciation perspective, those are both up 7% and over 5% respectively, again, primarily due to plant additions at the company. Moving forward to page eight. Top of the page, operating income, $84.5 million down $3.3 million or 3.8%. Below that, interest expense down slightly, $0.4 million or 1.7%, primarily a result of the refinancing that occurred last year, offset by slightly rising interest rates. Other expenses being flat, leads us to income before taxes of $60.4 million, a decrease of $2.8 million or down 4.4%. Lastly, income tax expense, $4.7 million favorable on a year-over-year basis, primarily a result of the 21% tax rate compared to 35% tax rate last year. It's a little lower pre-tax income, and those benefits partially offset by lower flow-through repairs deductions. I'll talk about that more in a moment.
Lastly, net income, again, as we pointed out, $58.5 million, $1.9 million improvement year-over-year. Page nine, I think, is a good way to think about the quarter. This display is our first quarter 2017-2018 pre-tax income reconciliation. What I point out here, it was actually a pretty positive quarter when you look at it from an expense standpoint and from a margin standpoint. All of those items shown in blue are for improvements on a year-over-year basis in pre-tax. There's really two negatives I can speak to. One is the deferral, largely offset in the tax expense line, and then property taxes and depreciation. Again, if we're a growing company, expect an increase in that on a year-over-year basis. That led us to, if you take into consideration all of those factors, pre-tax income goes from $63.2 million down to $60.4 million, which is a 4.4% decrease.
If you exclude, again, the deferral, which again is offset in income taxes, our actual pre-tax income would have been up 7% on a year-over-year basis. Moving to page 10 on the income tax reconciliation. At the bottom of the page, again, remember, income tax is $1.9 million for 2018, a $4.8 million improvement on a year-over-year basis, and that equated to an ETR of 3.2%. The moving parts associated with income taxes. The income tax calculated to the federal statutory rate was $9.4 million better. The lion's share of that, of course, is associated with the lower rate and partially also includes the lower pre-tax number. Below that, in terms of the permanent or flow-through adjustments, there's a big swing, if you will, in state income tax. Really two things going on there.
The loss of bonus depreciation impacted the benefit that we typically receive in that particular line item, and also the lower rate had an impact. The flow-through items associated with repairs deductions and plant depreciation items also are impacted by the lower rate. Negatively impacting us. Lastly, the share-based compensation, which is primarily driven by changes in our stock price, also had a slight negative to net to drive our total change on a year-over-year basis of $4.8 million. Moving forward to the balance sheet. Primarily, I'd point out there, as you can see at the bottom of the page, we continue to focus on the business, utilizing our ATM program and other means to continue to de-lever the company. Our ratio of debt to total capitalization has gone down since the end of the year from 53.7%-52% at the end of the first quarter.
Moving forward to page 12 on the cash flow statement. Two main items moving there up in the cash provided by operating activities is up to $15.8 million, primarily the result of insurance proceeds and improved collections in our supply costs during the year. We used that improvement in cash flow to increase our repayments of short-term borrowings almost by a similar amount. Obviously reducing short-term debt during the quarter. Lastly, I'd say on this page, there were no issuances of our ATM in the first quarter, but we continue to anticipating using up all of our ATM program before the end of 2018. Moving on to page 13. 13 is adjusted non-GAAP earnings slide.
Those of you who've seen this slide many times, what we try to do is look at GAAP earnings on the far left-hand side of the page compared to GAAP earnings on the far right side of the page, remove those non-recurring items, if you will, as we go towards the center of the page to compare non-GAAP 2018 versus non-GAAP 2017 for the quarter. At the bottom of the page, we had a GAAP diluted EPS of $1.18. We removed $0.07 of favorable weather to get us to $1.11. We compared that to $1.13 on a prior year basis, down $0.02 or down 1.8%. Looking at the items throughout the P&L, at the top of the page, you see after adjusting out favorable weather in both of the two years, we actually show gross margin down $3.7 million or down 1.5%.
Again, the deferral is the primary driver there. If in fact, you remove the deferral, we would actually had an increase in gross margin on a non-GAAP basis of a positive 1.5%. Moving down the P&L from an operating expense standpoint, continued good cost control. You can see G&A down 2.3%, property tax and depreciation continued to increase. Total operating expenses up 2.1%. Operating income and pre-tax income down -8%, -7%, respectively. An improvement in income taxes, as you'd expect, of $4.7 million gets us down to our net income on a non-GAAP to non-GAAP basis of a $0.3 million or 0.5% improvement on a year-over-year basis. The primary reason why diluted swings and diluted EPS swings in the other way is, of course, the dilution of the additional share issuance on a year-over-year basis. Moving to slide 14 on our 2018 earnings guidance.
Reaffirming our $3.35-$3.50 per share. Obviously, for the remainder of the year, expect to see normal weather. We talk about our tax rate of being 0%-5% for the remainder of the year, and our diluted share count of 50 million-50.2 million. Also want to point out, expect a reasonable treatment in both our Tax Cuts and Jobs Act filings with our three jurisdictions we made filings in thus far and a reasonable recovery in our PCCAM filing in Montana. With that, I'll pass it back over to Bob.
Well, that was a great setup, Brian. I'll touch on a few things at a higher level, come back and discuss several in more detail and anticipate that you'll want some further discussion during the Q&A. First, the regulatory items, just following up exactly on Brian's comments. We have the three pending tax reform dockets. We've had good discussions with staff at the state level, our focus is on providing a long-term benefit to customers, being able to make some necessary expenditures in the Montana system, and keeping investors whole. That really is the bottom line. That has to be the lodestar in all of these proceedings.
We are continuing to work through the Power Cost and Credits Adjustment Mechanism in Montana that we go into hearing at the end of May. We are in all-hands-on-deck mode, preparing a comprehensive electric general rate case to be filed in Montana by the end of September, based of course, on a 2017 test year. As you look at our capital planning, there's a heavy focus on transmission and distribution, building on the great success of our Distribution System Infrastructure Program. Now moving to more of a whole system approach, taking a similar approach on the natural gas transmission side with PHMSA compliance. Then grid modernization, which actually includes both the gas system as well as the electric system as to metering. One thing we talked frequently about our use of stakeholder groups, it proved to be very, very valuable in scoping our DSIP project.
Last year, we had successful stakeholder groups in South Dakota looking at both the electric and gas operations. They provided great guidance as we think about Growth and investment in that system. Similarly, had a Montana infrastructure stakeholder group that was really very valuable as we thought about the evolution of our system and of our services in Montana. Two big projects in the supply area this year. First, South Dakota will be filing a new South Dakota electric resource plan by the end of the year. A big activity currently is looking at our fleet and considering situations where for operational and economic reasons, it may make sense to retire and replace specific units. You'll be hearing more about that over coming quarters, and our supply folks have done a good job keeping the South Dakota PUC informed of our thinking about all of that.
In Montana, we'll be filing our next plan by the end of this year. Montana does have a statute governing the planning process. Our goal is a long-term, least cost, least risk approach to addressing overall needs. The focus is on intermittent capacity and reserve margin needs. We also work with a stakeholder group, a technical advisory committee, to develop the Montana plan. They've had several more public sessions as well for the larger group to learn about the plan and weigh in. We continue to look for opportunities, obviously, to acquire natural gas reserves, when and if it makes sense, and our cost control efforts have been successful. When we look at benchmarking to other companies, we think we're doing a very good job. Just a note, the beautiful photograph is the Black Eagle Powerhouse, where the Missouri River heads north through Great Falls, Montana.
The hydro system is not static. We've talked before, we've successfully used the hydro system to integrate a range of resources. To really change the way our overall Montana electric system operates. The system also isn't static in that we have opportunities to cost-effectively add generation consistent with current FERC licenses at a number of sites. Our supply team has been doing that, typically a project a year. Turning in more detail to the regulatory and legal front. Firstly, Montana property tax tracker filing. As Brian and I both mentioned, we've made filings in all three jurisdictions. Montana is by far the largest, simply as a result of the size of our investment in Montana. Also some differences in the tax treatment over the years. In late January. First let's start with the property tax tracker. I'm sorry.
The property tax tracker is a major driver in Montana. The Montana Commission, as you know, has expressed some real concerns about the size of our tax burden, and we share that concern. The commission went through a rulemaking process last year, think of it as a minimum filing approach for the property tax tracker. Went to a hearing and ultimately issued an order based on our 2017 property tax tracker filing that changed the methodology. As a result, we were unable to recover an additional $3.5 million that affected equally both 2017 and 2018. This was a change as a result of simply applying an alternate methodology that lowered the allocation to Montana jurisdictional retail customers as opposed to FERC jurisdictional customers. We don't have a tracker mechanism currently in place on the FERC side.
We filed a motion for reconsideration, ultimately, the commission did grant our motion for reconsideration as to the retroactive application, we obviously greatly appreciate that action by the commission and consider it to have been very constructive. Turning next to the Power Cost and Credits Adjustment Mechanism. As you know, the 2017 legislature in Montana eliminated the statutory electric tracker and replaced it with commission discretion. The commission had, in urging that change, referenced the tracker currently in place for Montana-Dakota Utilities in its Montana electric operation. We've worked through many of the complexities in the early stages of that docket. Ultimately, in July, we filed an electric PCAM proposal that we believe was very much in line with the commission's advocacy in the legislature. I think you're, in a general sense, familiar with that.
In December, the Montana Commission issued a notice of additional issues stating that the range of options identified in the parties' testimony was not sufficient and directed parties to consider alternative risk-sharing features of a possible PCAM. On February 7th, we filed our additional issue testimony. Intervenor additional issue testimony was filed in March. Our rebuttal is now due from us on April 30th, with discovery underway, and this is scheduled to go to hearing beginning on May 31st. It is possible the decision will apply the variable costs on a retroactive basis to July 1st of last year, which was the effective date of the legislative change. Turning to Dave Gates Generating Station, as you know, we received an adverse order from the FERC in April of 2014. The order concerned cost allocation between retail and wholesale, state and federal jurisdictional customers.
Our request for rehearing was denied in 2016, we were required to, and did, make refunds totaling $30.8 million. We appealed to the U.S. Court of Appeals and received a negative decision affirming the FERC decision in March, we consider that matter now closed. Turning to Colstrip Unit 4 and the disallowance of replacement power costs. In May of 2016, the Montana Commission issued a final order disallowing recovery of certain costs associated with a 2013 outage at Colstrip. In September of that year, we appealed the order to Montana District Court, arguing the decision was arbitrary and capricious and in violation of state law. We expect a decision on this appeal sometime within the next nine months. Turning to the estimated impact of the Tax Cuts and Jobs Act. I mentioned we have filed cases in all three jurisdictions.
As Brian described, our proposal was based on a current year methodology, making the specific change in the books for this year. We've deferred, as a result of this, $7.3 million of revenue associated with the change to a regulatory liability account, which would be between $15 million-$20 million for the full year of 2018. The deferral is anticipated to be offset by a similar reduction to income tax expense and should have minimal impact on net income. At the request of the commissions, we also filed a so-called restated historic calculation. This essentially goes back to the last rate case and would insert the updated tax methodology into that method. In our case, we don't consider this to be an appropriate adjustment because, again, we would be, and our shareholders would be, harmed as a result of that adjustment.
That obviously was not the intent of federal tax reform. If the Montana Commission were to adopt the restated historic calculation, that could result in approximately an $8 million-$12 million additional pre-tax earnings and cash flow impact. Again, we don't believe that is an appropriate result, nor a result that could possibly have been intended by Congress in passing the act. Utilization of the deferred revenue or the regulatory liability will be determined in the pending dockets. Procedural schedules have not yet been established. As a result of the tax reform, we've updated our effective tax rate assumptions included in 2018 guidance to from between 0%-5%, and previously we were at 8%-12%. NOLs are now anticipated to be available through 2020. Previously, that was 2021. We also reduced our deferred tax liability by $320 million as of December 31st, 2017.
This reduction was again offset in regulatory assets and liabilities. It's important to note that based on our filing, barring further negative regulatory actions, we believe that our debt coverage ratios will be adequate to maintain existing credit ratings. Negative actions by the regulators could lead to credit downgrades and could necessitate additional equity issuance. Again, we do not believe that that would be remotely an appropriate result. Turning to the capital spending forecast before we open it up for your questions. What you see is, as we've discussed before, really a stable and balanced capital investment by part of the business and by year.
Notable updates, we have removed $123 million of previously included investment in what we believe is very important capacity generation. That's been removed from, I should say, has been removed pending the update of our resource plans in Montana and South Dakota that I described earlier, which should be done by the end of this year. We have added approximately $126 million of investment associated with grid modernization and automated metering infrastructure for Montana. Previously, similar expenses were included for South Dakota and Nebraska in approximately $28 million. Cumulatively, over a five-year period, the capital spend is almost $1.6 billion. We do anticipate being able to fund these important investments with a combination of cash flows aided by NOLs through 2020 and the remainder of our current equity distribution program and long-term debt issuances.
If significant capital investments that are not included in the above projections, or if further negative regulatory actions occur, that could necessitate additional equity issuances. With that, we'll open it up for your questions.
Thank you to our audience today. If you'd like to ask a question at this time, please press star one on your touch-tone telephone. Just a reminder, if you're joining us via speakerphone today, make sure your mute function is turned off to allow the signal to reach our equipment. Once again, star one for any questions. We'll go first to Michael Weinstein at Credit Suisse.
Hi, guys.
Hi, Michael.
Hey. On equity issuances for the ATM, can you elaborate on why no sales in the first quarter? Do you think the remaining sales of $46 million for the remainder of the year will be evenly spread, or will it be back-end weighted or front-end weighted in some way?
Well, I'll start on the first part of your question. We weren't really crazy about our share price in the first quarter. As you know, tax reform had a significant impact on our share price. We had noted we would do the full $46 throughout the year. Expectations on a going forward basis is we'll probably get on with the program, Michael, and I'll leave it at that.
Okay. You've stated that any unfavorable regulatory outcomes might require equity issuances. Do you think that that would just be an expansion of the ATM or block issuances? How are you thinking about that?
No, that's a good question, and we're still thinking through that, Michael. I think one thing that's beneficial of the ATM program is we've been talking about, for some time, any growth above and beyond our capital plan may require equity. Having an expanded ATM is certainly helpful in that, and that's one thing that we think about from an equity perspective. There are some things, as Bob pointed out, on the generation front that we could be investing some capital. There may be needs for equity associated with that. In addition to that, we're looking at the remainder of the $46 million in the ATM program from a credit rating perspective.
If we have continued impact based upon difficult regulatory decisions and it impacts our cash flows such that our FFO to debt were to go below 15%, we may have to look at utilizing additional equity there. How we do that is yet to be determined. Hopefully it's not necessary.
Just one last question. On the restated historic calculation methodology for the income tax docket, what is the exact cause of the $8 million-$12 million harm that would be created by that? Also, how are both proposals handling prior period deferred tax revenues in terms of how many years are they going to be amortized out?
I would say this on the first part of your question. We've been experiencing lower tax rates for a number of years and doing a lot of things on the tax front to keep our tax rates down. Our belief, the spirit of tax reform is whatever your tax rate was this year, and after tax reform, whatever that tax rate would go to afterwards, we would want to make sure that we would give that benefit to customers, of course, grossed up in the revenue line associated for that change. What we're trying to do is make ourselves whole from a net income perspective. Having experienced lower tax rates over the years, that results in a lower give back, if you will, to customers. If in fact, if you go back into previous filings, we may have had higher tax rates in those particular filings.
That incremental benefit, if you would be passed on to customers. The problem with that is one of the reasons we haven't been coming in for rate cases is because we've been experiencing these lower tax rates over the years, which have offset the increase in costs that we've had throughout our businesses. Plus, we've not even asked for the recovery of the capital investment, if you will, and for the $400 million we've invested in DCF. The customers have already benefited from these lower tax rates over the year. Now you're asking them to double dip, if you will, by using the historical test year. What we're trying to do, again, from the spirit of tax reform, is only give to our customers what they're deserved to receive based upon the change in our current year tax rates.
Okay. Thank you very much.
We'll go next to Julien Dumoulin-Smith from Bank of America Merrill Lynch.
Hey, good afternoon.
Hey, Julien. Afternoon, Julien.
Hey. Perhaps just to follow up on the last point, just to kind of pick that up, can you elaborate a little bit more on the puts and takes on the CapEx? I suppose the question that I would have on the other side of it is, how do you think about the timeline for approval of AMI and how that, apologies, could that slip here on the Montana piece, and could we see some positives and some negatives here? Could you kind of walk through a little bit more on that?
Well, I think you saw the total amount in the capital slide associated with that. I think what we're doing right now is we're leading with those investments in South Dakota, really at the end of 2018 and into 2019, then we're going to start to ramp up for Montana, if you will, end of 2019 and start 2020 and 2021, really into those programs. The timing, of course, could vary depending on how things move through South Dakota. That's our plan as we sit today.
Got it. Excellent. How do you think about the capital budget here? Let me ask you this. The 15% FFO to debt and the potential incremental equity. I suppose there's a few other points that you brought up on the call with respect to cash flows, if you could elaborate. First, could you comment on the potential retroactivity, I suppose, back to July of PCAM? Separately, can you comment on the potential, I suppose you put, and perhaps I don't want to read too much into it, the potential retroactive piece of tax reform with the $8 million to $12 million of additional pre-tax earnings and cash flow impacts that are presumably a reduction, right? I just want to understand the timeline for potential equity in light of those two potential decisions as well as the CapEx.
I think, Julien, you've asked a lot there. I think I'll start with the PCAM. Can't really gauge how much the impact from a dollar perspective, I could argue the range on PCAM is pretty large and nebulous at this point, it's difficult to ascertain where that will come out, let alone know what the 2017 aspect of that would be. On tax reform, we've pretty much laid out, based upon those two methods, what the amount would be. I'd put it into context. We're going to know within 2018 outcomes on those two cases. Obviously, we also will have a rate case the following year with an outcome in 2019, and we'll have a pretty good idea what our earnings and cash flow will be from that as well. We have to look at the short-term impact in 2018 up until the rate case.
may have a better understanding what the impact will be from those two filings and the outcomes of those two filings on both our earnings and cash flow and understand how they impact FFO to debt. I don't know how else to explain it other than that, Julien.
The only addition I would make to that is, we've talked about the possible retroactive application of the new PCAM regime. As a result of the additional issues layer in the case, that's added quite a lot to the overall timeline. The Consumer Council, at a high level, you could characterize as saying, obviously they do advocate a different tracker mechanism, but also suggested that changes to the mechanism be on a going forward basis. Again, the most important point I think Brian made was that we'll know the results, whatever those results are, during the year, and then that will inform our decisions.
Got it. If I can read between the lines there, you're not going to know the outcome for the PCAM piece of this as well as the tax reform piece for a little bit of time here. That might delay any further equity needs for a little bit, pending on the outcome.
I would argue this, we're not issuing any additional equity at all other than what we have to do in the remainder of our ATM program until we know the outcome of one or the two of these regulatory matters.
Right. Yeah, exactly. That's what I'm trying to get at. Another point I wanted to bring up real quickly was on the District Court case, I suppose recently. Can you comment potentially around any read-throughs or potential applicability? I mean, certainly one could say that that was a win on your side. Is there anything else we should be thinking about in the context of how that court case and the Col strip case could be applied elsewhere?
Well, it was a significant decision, obviously, and the court focused on good administrative practice and on due process. We consider, and I consider it very positive that the Commission has now decided to open a proceeding to look at due process and how it conducts its proceedings, and we very much welcome that.
Excellent. Sorry, last quick one if I can squeeze it in here. On the QF side of things, obviously, we saw you pursue two projects here. I suppose there was the first, there was an 80-megawatt wind project and a separate eight megawatts. Can you talk about prospects for additional renewables on a rate base context in light of QFs out there? Then also the context under which you would be able to convert the 80 megawatts into a rate base opportunity perhaps down the line.
Any significant resource additions are going to be driven by our plan unless they really are opportunistic. This was an opportunistic acquisition because we were able to take an existing resource that our customers are paying for and lowering the cost to customers while at the same time producing an opportunity for shareholders. We need to get through a FERC process before we get to the state process on that side. The other contract you referred to was more of a straightforward QF. That was good news for customers in that the terms were extremely favorable. Although we do focus significantly on the applicability of the Commission's 15-year contract rule to rate-based owned resources, we do note that the Commission has made very good decisions about QF pricing and avoided costs, and those are positive for customers.
One thing I'd add, Bob, is that the QF, of course, Beethoven in here, Two Dot Wind. These are opportunities as a result of right of first refusals that we build into these QF contracts. As future opportunities arise as a result of that, we evaluate those. How can we make that more cost-effective to customers and also helpful for us from a rate basing perspective? Things have to kind of fall into place in order for us to capture these opportunities.
Got it. Excellent. Thank you all very much.
Thanks, Julien.
Once again, ladies and gentlemen, star one for any questions. We'll go next to Jonathan Reeder at Wells Fargo.
Good afternoon, gentlemen.
Hey, Jonathan.
Hey, how are you doing?
Good.
Hey, just wanted to get, I guess, a little bit of background as to what prompted you to present this kind of restated historic calculation methodology for giving back the benefits of tax reform. Is it just out of an abundance of caution or did the MPSC kind of request this perspective as well?
We saw in instructions, if you will, a methodology in terms of how they would look at this calculation. Taking that into consideration, we felt that it was important for us not to ignore that calculation from a filing perspective.
Okay. They wanted to see it from the fact of restating from basically the last rate order for each applicable, I guess, kind of business or asset.
Correct. Yes.
Okay. Regarding DGGS, if I remember correctly, the first quarter resulted in about like $8 million-$9 million of lowering or revenues than you believe were necessary to fully recover the plant at the time. I know you've been operating the plant differently than originally contemplated, particularly following the addition of the hydro assets. What's the shortfall now and what's your strategy for trying to get the full recovery for DGGS going forward? Is it via the upcoming Montana rate case or perhaps even as part of the FERC case? Can you kind of talk through your strategy there?
Brian, why don't you talk about the shortfall first?
Yeah, I think the shortfall, you're absolutely correct. Our expectation is we are using that plan differently associated with the hydro and the expectation of the gap, if you will, it would be smaller. In order to capture that gap, of course, we have to do filings in both jurisdictions, both Montana and FERC, to capture that and then demonstrate to both commissions how we're using that plan differently.
Okay.
Yeah, I think the other thing that, Jonathan, the other thing to think about, a lot of time has passed also on that asset. It's been, I wouldn't say significantly depreciated, but it's been depreciated quite a bit since we put it in service back in 2011.
Okay, sorry, go ahead.
Oh, no. There is still obviously a substantial asset on the books. It is nowhere near fully depreciated, but it is significantly depreciated. Key issues in the twin FERC and state rate cases will be allocation between jurisdiction, and that will include studies of the cost of integrating resources relatively between the jurisdictions.
Okay. You don't have to go completely back to Montana to hopefully bridge that gap. There's still some assets on the federal side.
Sure, yes. That's correct.
Okay, that's all I had. Thanks.
Thanks, Jonathan.
We'll go next to Paul Ritson at KeyBank.
Good afternoon.
Hey, Paul.
Just on the historical look at tax reform, I mean, this would be fixed in the rate case, right?
Well, it's an excellent point, Paul. Our viewpoint is if you're going to do something like that and ask us to go back and do things on a historical standpoint, why not wait for the rate case? The benefit we're providing here is on the current year method, as we point out, we're going to provide the benefit that we receive in 2018 up until customers, up until the time of that rate case. That's our viewpoint. If you want to go back on a historical look, let's just take care of everything in the rate case. Until that time, let's use the current method we've displayed.
Just on potentially incremental new generation, what's the potential capital and the timeline for figuring that out?
I would really want to push back on assigning a number. As we highlighted in the presentation, we've removed over $120 million from the capital forecast. We're deep into new plans in South Dakota and Montana, and we've talked about some opportunistic activities. Really the bulk of any investment is going to be driven by the outcome of the plans.
The plans both expected to be out by the end of this year.
Okay. Thank you very much.
Thanks, Paul.
Just a final reminder to the audience, if you do have a question, please press star one at this time. We'll go back to Julien Dumoulin-Smith at Bank of America.
Hey, guys. Sorry to keep asking here. Just wanted to follow up and clarify on the restated historic impact, the $8 million-$12 million. Is that upside the 2018 earnings guidance or is that already reflected? I just want to make sure we understand this.
What we're saying in our guidance is we're utilizing our current method. If that $8 million-$12 million of additional pre-tax hit would hit us, that's not included in our guidance. We baked into our guidance utilizing our current year method where net income has stayed whole as a result of tax reform. That would be downside pressure on our earnings this year.
Sorry. Okay. That's what I was unsure about. Thank you very much for clarifying that.
Thanks, Julien.
Gentlemen, no additional questions at this time. We'll turn the program back over to you.
Okay. Thank you for your support and interest throughout the quarter. We'll be visiting with you at a couple of conferences over the coming month or two and hopefully talking to many of you next quarter. Thank you.
Ladies and gentlemen, once again, that does conclude today's conference. Again, I'd like to thank everyone for joining us today.