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. And 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, Laurie. Good afternoon, and thank you for joining Northwestern Corporation's financial results conference call and webcast for the quarter ending March 31, 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 Byrd, Vice President and Chief Financial Officer.
We also have several other members of the management team with 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 and often contain words such as expects, anticipates, intends, plans, believes, seeks or will.
The information in this presentation is based upon our current expectations. Our actual future business and financial performance may differ materially and adversely from our expectations expressed in any forward looking 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 ks 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 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-eight hundred-four eighty five-eight thousand three hundred and twelve, then access code 457,992.
Again, that's 800-485 8312, access code 4,517,992. I'll now hand the presentation over to our CEO, Bob Rill.
Thank you, Travis. Good afternoon, everyone, and thank you for joining us. We're calling in from our general office in Butte, Montana, where they're still looking out the window with snow in the mountains, but 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 and then had a good annual meeting this morning and all of the proposals passed overwhelmingly. And we certainly thank you for your participation. Very importantly, this was Doctor. Lynn Draper's last meeting as Board Chair and he's guided us since 2004 and has been an extraordinary mentor, leader and friend.
Very good news is the Board has selected Steve Haddock, many of you know as the long serving Chair of the audit committee to step up now as Board Chair. And Steve will in his own way continue the focus and the dedication that Lynn displayed and also that Steve displayed as a very effective and engaged audit chair. So we're we continue to be fortunate with the Board leadership that we enjoy. Turning to Q1 highlights. Operating income decreased $3,300,000 as compared to the same period in 2017.
However, if you adjust to remove the $7,300,000 revenue deferral that was recorded during the quarter related to the Tax Cuts and Jobs Act, operating income would have actually increased by $4,000,000 or 4.6%. Net income for the quarter was up $1,900,000 3.4 percent as compared to the same period in 2017 and was primarily due to the cold winter 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. And the Board acted yesterday to declare a quarterly dividend of $0.55 per share payable on June 29 to shareholders of record as of June 15, 2018.
And Brian will now begin with the summary of financial results.
Thanks, Bob. On Page 4, on the summary of financials, net income was $58,500,000 which was a $1,900,000 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 is $0.01 or nearly 1% better than the prior year period. Moving on to Page 5, gross margin. Gross margin was $245,400,000 which was down $2,100,000 or 0.8 percent on a year over year basis for the quarter.
However, 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 $4,100,000 or up 1.7%, primarily a result of both our gas and electric business performing well during the quarter. The area where we had to change the gross margin that offset within that income, it was offset elsewhere in the P and L. We had a large deferral $7,300,000 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 and L totaled to a decrease of $6,200,000 net and of those two items the $4,100,000 increase and the $6,200,000 decrease net 2.1% decrease in consolidated gross margin. Moving on to Page 6, looking at weather for the Q1.
We were colder in all jurisdictions versus the prior year and versus historic average. I would point out that and remind folks that Montana, of course, is the largest share of our business, greater than 80% of our business and those 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 $4,800,000 pretax compared to normal and $1,600,000 pretax benefit as compared to Q1 2017, and we'll talk about that more later in the presentation. Moving on to Page 7 in terms of operating expenses. Operating expenses were $160,900,000 an increase of 1,200,000 dollars or again an increase of 0.8 percent on a year over year basis.
Looking at the components of that though, operating, general and administrative expenses were actually down $4,000,000 or just over 5%. The explanation for that below shows that when you actually directors deferred comp and the employee benefits, one being decreased, 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 D SIP costs because of the elimination of the amortization associated with D SIP 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 planned additions at the company.
Moving forward to Page 8, top of the page, operating income $84,500,000 down $3,300,000 or 3.8 percent. Below that, interest expense down slightly $400,000 or 1.7 percent, primarily result of the refinancing that occurred last year offset by slightly rising interest rates, expenses being flat, leads us to income before taxes of $60,400,000 a decrease of $2,800,000 or down 4.4%. Lastly, income tax expense, dollars 4,700,000 favorable on a year over year basis, primarily a result of the 21% tax rate compared to 35% tax rate last year, so a lower pretax income and those benefits partially offset by mostly repairs deductions. I'll talk about that more in a moment. Lastly, then net income, again, as we pointed out, dollars $60,400,000 improvement year over year.
Page 9, I think is a good way to kind of think about the quarter. This displays our Q1 2017 to 2018 pretax income reconciliation. What I point out here is actually a pretty positive quarter when you look at from an expense standpoint and from a margin standpoint, all of those items shown in blue for improvements on a year over year basis in pretax. There's really 2 negatives I can speak to and one is the deferral, largely offset in the tax expense line. And then property taxes and depreciation again for a growing company, I'd 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 $63,200,000 down to $60,400,000 which is a 4.4% decrease. But if you exclude again the deferral, which again is offset in income taxes, our actual pretax 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, we can again remember income tax is $1,900,000 for 2018, a $4,800,000 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 $9,400,000 better. The lion's share of that, of course, is associated with the lower rate and partially also includes a lower pretax number. But below that, in terms of the permanent or flow through adjustments, there's big swing, if you will, in state income tax, really two things going on there. The loss of the bonus depreciation impacted the benefit that we typically see in that particular line item and also the lower rate had an impact. The flow through items associated with payers, deductions and planned depreciation items also are impacted by the lower rate negatively impacting us.
And then lastly, the share based compensation, which is primarily driven by changes in our stock price, also had a slight negative to net net to drive our total change on a year over year basis of $4,800,000 Moving forward to the balance sheet, primarily a 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 delever the company. Our ratio of debt to total capitalization has gone down since the end of the year from 53.7% to 52% at the end of the Q1. Moving forward to Page 12 on the cash flow statement. 2 main items moving there up in the cash provided by operating activities is up 15,800,000 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.
And so obviously reducing short term debt during the quarter. And lastly, I'd say on this page, there were no issuances of our ATM in the Q1, but we continue to anticipate in 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 and then remove those items, non recurring items, if you will, as we go towards the center of the page, we can compare non GAAP 2018 versus non GAAP 2017 for the quarter.
At the bottom of the page, we had GAAP diluted EPS of $1.18 We removed $0.07 of favorable weather to get us to 1.11 dollars We compared that to $1.13 on a prior year basis, so down $0.02 or down 1.8%. Looking at the items throughout the P and L, at the top of the page, you see after adjusting out favorable weather in both of the 2 years, we actually show gross margin down $3,700,000 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 and L from an operating expense standpoint continued good cost control.
You can see OG and A down 2.3%, but again property tax and depreciation continuing to increase. Total operating expenses up 2.1%. Operating income and pretax income down minus 8%, minus 7% respectively. Improvement in income taxes, as you would expect, dollars 4,700,000 gets us down to our net income on a non GAAP to non GAAP basis of $300,000 or 0.5 percent 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 additional share issuance on a year over year basis.
Moving to Slide 14 on our 2018 earnings guidance, reaffirming our 3 $0.35 to $3.50 per share. Obviously, for the remainder of the year and expect to see normal weather, We talked about our tax rate of being 0% to 5% for the remainder of the year and our diluted share count of 50 $1,000,000 to $50,200,000 Also want to point out expect a reasonable treatment in both our Tax Cuts and Jobs Act filings with our 3 jurisdictions we made filings in thus far and a reasonable recovery in our PKAN filing in Montana. And 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 than anticipate that you'll want some further discussion during the Q and A. First, the regulatory items just following up exactly on Brian's comments. We have the 3 pending tax reform dockets. We've had good discussions with staff at the state level, and 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.
I think that really is the bottom line that ought to be the lodestar in all of these proceedings. We are continuing to work through the power cost credit and adjustment mechanism in Montana. We're going to hearing at the end of May And 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 plan and now moving to more of a whole system approach, taking a similar approach on the natural gas transmission side with FINSA compliance and then grid modernization, which actually includes both the gas system as well as the electric system as to metering. We talked frequently about our use of stakeholder groups for the very, very valuable in scoping our DCIP project.
Last year, we had successful stakeholder groups in South Dakota looking at both the electric and gas operations. They provided great guidance. And we think about growth and investment in that system. And similarly, we 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. 2 big projects in the supply area this year.
1st, South Dakota, we will be filing a new South Dakota electric resource plan by the end of the year. 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 DUC 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 and our goal is a long term lease cost, least risk approach to addressing overall needs and the focus is on intermittent capacity and reserve margin needs.
We also work with a stakeholder group, technical advisory committee to develop the Montana plan that 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. And when we look at benchmarking to other companies, we think we're doing a very, very good job. Just a note, the beautiful photograph is the Black Eagle Powerhouse with the Missouri River heads north through Great Falls, Montana and the hydro system is not static. We've talked before, we've successfully used the hydro system to integrate a range of resources and to really change the way our overall Montana electric system operates.
The system also isn't static and then we have opportunities to cost effectively add generation consistent with current FERC licenses at a number of sites and our supply team has been doing that typically a project a year. Turning in more detail to the regulatory and legal front. First, the Montana property tax tracker filing. And as Ryan 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, but also some differences in actually, first, let's start with the property tax cracker, I'm sorry.
Actually, first, let's start with the property tax tracker. I'm sorry. So, 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 rule making 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.
And as a result, we were unable to recover an additional $3,500,000 that affected equally both 2017 2018. And this was a change as a result of applying an alternate methodology that lowered the allocation to Montana jurisdictional retail customers as opposed to FERC jurisdictional customers. We don't have a traffic mechanism currently in place on the FERC side. We filed a motion for reconsideration and ultimately the commission did grant our motion for reconsideration as to the retroactive application and we obviously greatly appreciate that action by the commission and consider it to have been very constructive. Turning next to the power cost and credit adjustment mechanism.
As you know, the 2017 legislature in Montana eliminated the statutory electric tracker and replaced it with commission discretion. The commission had been urging that change, referenced the tracker currently in place for Montana Dakota Utilities and 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. And 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 party's testimony was not sufficient and directed parties to consider alternative risk sharing features of a possible P CHEM. On February 7, we filed our additional issue testimony. Intervenor additional issue testimony was filed in March. A rebuttal is now due from us on April 30 with discovery underway. And this is scheduled to go to here in beginning on May 31.
It is possible the decision will apply to variable costs on a retroactive basis to July 1 last year, which was the effective date of the legislative change. Turning to NIMH 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 reorder was denied in 2016 and we were required to and did make refunds totaling $30,800,000 We appealed to the U.
S. Court of Appeals and received a decision, a negative decision affirming the FERC decision in March and we consider that matter now close. Turning to Coal Strip 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 9 months now. 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, we have been 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 $7,300,000 of revenue associated with the range to a regulatory liability account, which would be between $15,000,000 $20,000,000 for the full year 2018. And 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 restated historic calculation. And this essentially goes back to the last rate case and it 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. But if the Montana Commission were to adopt the restated historic calculation, that could result in approximately $8,000,000 to $12,000,000 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 of the regulatory liability will be determined in the pending dockets and procedural schedules have not yet been established. As a result of the tax reform, we updated our effective tax rate assumptions included in 2018 guidance to from between 0% 5%, and previously we were at 8% to 12%. NOLs are now anticipated to be available through 2020, previously 2021. And we also reduced our deferred tax liability by $320,000,000 as of December 31, 2017.
And this reduction was again offsetting regulatory assets and liabilities. It's important to note that based on our filing and 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. And 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 stable and balanced capital investment by part of the business and by year. Notable updates, we have removed $123,000,000 of previously included investment in what we believe is very important capacity generation and that's been removed from I should say, it 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. And we have added approximately $126,000,000 of investment associated with grid modernization and automated metering infrastructure for Montana. Previously, similar expenses were included for South Dakota and Nebraska in approximately $28,000,000 So cumulatively over a 5 year period, the capital spend is almost $1,600,000,000 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 necessitate additional equity issuance.
And with that, we'll open it up for your questions.
And thank you to our audience today. And 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 Q1? And do you think the remaining sales of $46,000,000 for the remainder of the year will be evenly spread? Or will it be like 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 Q1. As you know, tax reform had significant impact on our share price. And so we had noted we would do the full 46 throughout the year and expectations on a going forward basis is we'll probably get on with the program, Michael, and I'll leave it at that.
Okay. And if you've stated that there any unfavorable regulatory 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. And so 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.
And so there may be needs for equity associated with that. But in addition to that, we're looking at the remainder of the $46,000,000 in the ATM program from a credit rating perspective. But 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 and 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 income tax, the income tax docket. What is the exact cause of the $8,000,000 to $10,000,000 or $8,000,000 to $12,000,000 of harm that would be created by that? And how would also how are both proposals handling prior period deferred tax revenues in terms of how many years they're 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 in the tax front to keep our tax rates down. I believe the spirit of the 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 with 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 giveback, 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. And so that incremental benefit with you would be passed on to customers. The problem with that is one of the reasons we haven't been coming in for rate is because we've been experiencing these lower tax rates over the years, which have offset these 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 $400,000,000 we've invested in DC. So 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. So what we're trying to do again in the spirit of tax reform is only give to our customers what they deserve to receive based upon the change in our current year tax rates.
Okay. Thank you very much.
And we'll go next to Julien Dumoulin Smith from Bank of America Merrill Lynch.
[SPEAKER JULIEN
DUMOULIN SMITH:]
Hey, good afternoon.
Hey, Julien. Good afternoon, Julien.
Hey. So 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 and the capital slide associated with that. And I think what we're doing right now is we're leading with those investments in South Dakota really at the end of 'eighteen and into 'nineteen and then we're going to start to ramp up for Montana, if you will, end of 2019 and start 2020 2021 really into those programs. And the timing, of course, could vary depending how things move through South Dakota. But that's our plan as we sit today.
Got it. Excellent. And then how do you think about the capital budget here? I mean, let me ask you this. So the 15% of the voted debt and the potential income of 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 PKAM? And then 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 $8,000,000 to $12,000,000 of additional pre tax earnings and cash flow impacts that are presumably a reduction, right? So I just want to understand the timeline for potential equity in light of those two potential decisions as well as the CapEx?
I think, Julian, 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 can argue the range on PCAM is pretty large and nebulous at this point and it's difficult to ascertain where that will come out, let alone know what the 2017 aspect of that would be. And on tax reform, we 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. And 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. So we have to look at the short term impact in 2018 up until the rate case and also may have a better understanding what the impact will be from those two filings and the outcomes of those two filings on both 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 the same. We do want obviously, they do advocate a different tracker mechanism, but also suggested that changes to the mechanism be on a going forward basis. And 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. So that might delay any further equity needs for a little bit, depending on the outcome of that?
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 you know the outcome of 1 or the 2 of these regulatory matters.
Right. Yes, 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 Colstrip 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 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. And sorry, last quick one if I can squeeze it in here on the QS side of things. Obviously, we saw you pursue 2 projects here. I suppose there was the first either was an 80 megawatt wind project and a separate 8 megawatts. Can you talk about prospects for additional renewables on a rate based context in light of QS out there?
And then also the context under which you would be able to convert the 80 megawatts into a rate based 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're 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 a more of a straightforward QF.
That was good news for customers in that the terms were extremely favorable. And although we do focus significantly on the applicability of the commission's 15 year contract roll 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 the QF of course Beethoven and here 2.1 these are opportunities as a result of right of first refusals that we build into these QF contracts. And so 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 from us from a rate base in perspective. And so 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, Jimmy.
And 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 benefit of tax reform. Is it just like out of an abundance of caution or did the MPSC kind of request this perspective as well?
We saw instructions, if you will, a methodology in terms of how they would look at this calculation and taking that into consideration, we felt it was important for us to not to ignore that calculation from a filing perspective.
Okay. So 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. Okay.
And then regarding DGGS, if I remember correctly, the Q3 resulted in about like $8,000,000 to $9,000,000 of lower annual 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 those gas or the hydro assets. So kind of what's the shortfall now and what's your strategy for trying to get the full recovery for DDGS going forward? Is it via the upcoming Montana rate case or perhaps even as part of the FERC case? Can you kind of talk
to your strategy there? Brian, why don't you talk about the shortfall first?
Yes. I think the shortfall, you're absolutely correct. Our expectation is we are using that plant differently associated with the hydro and the expectation of the gap, if you will, and it would be smaller in order to capture that gap. Of course, we have to do filings in both Montana and FERC and to capture that and then demonstrate to both commissions how we're using that plan differently. Yes.
I think the other thing to Jonathan, the other thing to think about a lot of time has passed also on that asset and 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 'eleven. Okay.
But not all of
sorry, go ahead.
No. There is still obviously 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. So you don't have to go completely back to Montana to hopefully bridge that gap. There's still some math on the federal side?
Sure. Yes, that's correct.
Okay. That's all I had. Thanks.
Thanks, Jonathan.
And we'll go next to Paul Ridzon at KeyBanc.
Good afternoon. Hey, Paul. Just on the historical look at tax reform, I mean, this would be fixed in the right 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 historical standpoint, why not wait for the rate case?
And 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're receiving in 'eighteen up until customers, up until the time of that rate case. And so 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. But until that time, let's use the current method we've displayed. And then just on potentially incremental new generation, kind of what's the potential capital and the timeline for figuring that out?
So, I would really want to push back on assigning a number. As we highlighted in the presentation, we removed over $120,000,000 from the capital forecast. Now we're deep into new plans in South Dakota and Montana, and we've talked about some opportunistic activities. But really the bulk of any investment is going to be driven by the outcome of the plans.
And the plans both expected to be out by the end of this year. Okay. Thank you very much. Thanks, Paul.
And we'll go back to Julien Dumoulin Smith at Bank of America. [SPEAKER JULIEN
DUMOULIN SMITH:] Hey, guys. Sorry to keep asking here. Just wanted to follow-up and clarify on the restated historic impact, the to $8,000,000 to $12,000,000 Is that upside of 2018 earnings guidance or is that already reflected? I just want to make sure we understand this.
That would be what we're saying in our guidance is we're utilizing our current method. If that $8,000,000 to $12,000,000 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, Julian.
And gentlemen, no additional questions at this time. I'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 months or 2 and hopefully talking to many of you next quarter. Thank you.
And ladies and gentlemen, once again, that does conclude today's conference. Again, I'd like to thank everyone for joining us today.