NorthWestern Energy Group Inc (NWE) 2018 Q1 法說會逐字稿

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. 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 premarket this morning.

On the call with us today are Bob Rowe, President, 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'll remind you of the safe harbor language.

During the course of this presentation, there will be forward-looking statements within the meaning of 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, and 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 in to 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, then access code 4517992.

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

Thank you, Travis. Good afternoon, everyone, and thank you for joining us. We're calling in from our general office in Butte, Montana, where there's still -- looking out the window, it's snow on the mountains, but we think it may be 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's 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 Dr. Linn Draper's last meeting as Board Chair. He's guided us since 2004 and has been an extraordinary mentor, leader and friend. Very good news is the board has selected Steve Adik, who many of you know is 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 Linn displayed and, also, that Steve displayed as a very effective and engaged Audit Chair. So we continue to be fortunate with the board leadership that we enjoy.

Turning to first quarter highlights. The 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 related 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, and that's primarily due to 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 29th to shareholders of record as of June 15, 2018. And Brian will now begin with a summary of the financial results.

Thanks, Bob. On Page 4, on summary financials. Net income was $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, again, basis of that, $0.01 or nearly 1% better than the prior year period.

Moving on to Page 5, gross margin. Gross margin was $245.4 million, which was down $2.1 million or 0.8% 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 $4.1 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 was 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 getting 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 totaled to a decrease of $6.2 million, net. And of those 2 items, the $4.1 million increase and the $6.2 million decrease, net $2.1 million decrease in consolidated gross margin.

Moving on to Page 6, 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 that -- and remind folks that Montana, of course, is the largest share of our business, greater than 80% of our business and though slightly colder in '17 in a year-over-year basis and, obviously, much colder in South Dakota, Nebraska on a year-over-year basis. I would argue that the favorable weather in Q1 contributed approximately $4.8 million of pretax benefit compared to normal and $1.6 million 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 $160.9 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 and administrative expenses were actually down $4 million or just over 5%. The explanation for that, below shows that when you actually exclude the nonemployee 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 DSIP costs, because of the elimination of the amortization associated related with DSIP and other costs coming down, we help -- we continued to manage our cost well to help offset slower margin growth than we've seen historically.

Below that, from a property taxes and depreciation perspective, those are up -- both up 7% and over 5%, respectively, again, primarily due to plant additions at the company.

Moving forward to Page 8. 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, leads us to -- and other expenses being flat, leads us to income before taxes of $60.4 million, a decrease of $2.8 million or down 4.4%.

And 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 from the lower pretax income and those benefits, partially offset by lower flow-through repairs deductions. I'll talk about that more in a moment.

Lastly then, net income, again, as we pointed out, $58.5 million, $1.9 million improvement year-over-year.

Page 9, I think, is a good way to kind of think about the quarter. This is -- displays our first quarter 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, are 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. And for 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, pretax income goes from $63.2 million down to $60.4 million, 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 -- again, remember income tax is $1.9 million for 2018, $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 at 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 pretax number. But below that, in terms of the permanent or flow-through adjustments, there's a big swing, if you will, in state income tax. Really, 2 things going on there, the loss of the bonus depreciation impacted the benefit that we typically -- we see in that particular line item, and also, the lower rate had an impact.

The flow-through items, associated repairs deduction and plant depreciation items also were impacted by the lower rate, negatively impacting us. And lastly, the share-based compensation, which is primarily driven by changes in our stock price, also had a slight negative, net-net, to drive our total change in 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 page, we continue to focus on the business, utilizing our ATM program and other means to continue to delever the company. Our ratio to debt to total capitalization has gone down since the end of the year, from 53.7% to 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 $15.8 million, primarily the result of insurance proceeds and improved collections on our supply costs during the year. We use 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 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 our adjusted non-GAAP earnings slide. Those of you who have seen the 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, nonrecurring items, if you will. As we go towards the center of the page, we compare non-GAAP 2018 versus non-GAAP 2017 for the quarter. At the bottom of the page, we had to -- GAAP diluted EPS of $1.18. We removed $0.07 of favorable weather to get us to $1.11. If you compare that to a $1.13 on a prior year basis, so 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 2 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 removed the deferral, we would actually have 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 OG&A down 2.3%. But again, property tax and depreciation continued 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, of $4.7 million, gets us down to our net income on a non-GAAP to non-GAAP basis of $0.3 million or 0.5% improvement on a year-over-year basis. The primary reason why diluted swings -- diluted EPS swings in the other way is, of course, the dilution of additional share issuances on a year-over-year basis.

Moving to Slide 14, on our 2018 earnings guidance. Reaffirming our $3.35 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 million to 50.2 million. Also, I want to point out, expect a reasonable treatment in both our Tax Cuts and Jobs Acts filings with our 3 jurisdictions, we made filings in thus far and a reasonable recovery in our PCCAM filing in Montana. And with that, I'll pass it back over to Bob.

Well, that was a great set up, Brian. I will touch on a few things at a higher level, come back and discuss several in more detail and anticipate that you'll want to have some further discussion during the Q&A.

First, on the regulatory items just following up exactly on Brian's comments, we have the 3 pending tax reform dockets. We've got good discussions with staff at the state level. And our focus is on providing a long-term benefit to customers, being able to mix necessary expenditures in the Montana system and keeping investors whole. That really is the bottom line and 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. That would go into 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 the 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 PHMSA 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 new stakeholder groups, 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, if you think about growth in investment in that system. And similarly, we had the 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, we'll 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. So 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 that we're 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 least-cost, least-risk approach to address an overall need, and 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 have several more public sessions as well for a larger group to learn about the plan and weigh in.

If we continue to look for opportunities, obviously, to acquire the natural gas reserves when and if it makes sense. And our cost control efforts have been successful. And 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, where 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 isn't also static. And then we have opportunities that cost-effectively add generation consistent with current FERC licenses at a number of sites, and our supply chain has been doing that, typically, a project a year.

Turning in more details on the regulatory and legal front. First, the Montana property tax tracker filing. As Brian and I both mentioned, we have made filings in all 3 jurisdictions. Montana is by far the largest, simply as a result of the size of our investment in Montana but, also, some differences in the tax treatment over the years. In late January -- 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 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 $3.5 million that affected equally both 2017 and 2018. And 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 tracking 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 Adjustments Mechanism. As you know, the 2017 legislature in Montana eliminated the statutory electric tracker and replaced it with a commission discretion. The commission had, in urging that change, referenced the tracker in -- currently in place where in Montana they can put our utilities and its Montana electric operation. We worked through many of the complexities in the early stages of that docket. Ultimately in July, we filed an electric PCCAM 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 PCCAM.

On February 7, we filed our additional issue testimony. Intervenor additional issue testimony was filed in March. That rebuttal is now due from us on April 30 with a discovery underway. And this is scheduled to go to hearing beginning on May 31. It is possible the decision will apply to variable costs on a retroactive basis to July 1 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, and we were required to and did make refunds totaling $30.8 million. 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 closed.

Turning to Colstrip Unit 4, in the disallowance of replacement power costs. In May of 2016, the Montana Commission issued a final order disallowing recovery of certain costs associated with the 2013 outage at the Colstrip. In September of that year, we appealed the order to Montana District Court, arguing the decision was arbitrary and capricious and a violation of state law. We expect a decision on this appeal sometime within the next 9 months.

Now turning to the estimated impacts of the Tax Cuts and Jobs Act. I mentioned, we have filed cases in all 3 jurisdictions. As Brian described, we had 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 the $7.3 million of revenue associated with this change into a regulatory liability account, which would be between $15 million and $20 million for the full year of 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, probably, restated historic calculation. And 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 the federal tax reform. But if the Montana Commission were to adopt the restated the historic calculation, that could result in -- approximately in $8 million to $12 million additional pretax 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, 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 and 5%, and previously, we were at 8% to 12%. Our NOLs are now anticipated to be available through 2020. Previously, it was 2021. And we also reduced our deferred tax liability by $320 million as of December 31, 2017. And this reduction was, again, offset in regulatory assets and liabilities.

It's important to note that based on our filing regarding 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 issuances, something that 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, a really 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. And that's been removed from -- I should say, that 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 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. So cumulatively, over a 5-year period of capital spend, it's almost $1.6 billion. We do anticipate being able to fund these important investments with a combination of cash flows aided, by NOLs for 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.

And with that, we'll open it up for your questions.

(Operator Instructions) And we'll go first to Michael Weinstein at Cr?dit Suisse.

On equity issuances. For the ATM, can you elaborate on why no sales in the first quarter? And do you think the remaining sales of $46 million 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 first quarter. As you know, tax reform has significant impact on our share price. And so we had noted we would do the full $46 million throughout the year and expectations. On a going-forward basis, we'll probably get on with the program, Michael, and I leave it at that.

Okay. And if -- you stated that any unfavorable regulatory outcomes might require equity issuances. Do you think that that would be just an expansion of the ATM or block issuances? How are you thinking about that?

That's a good question. We're still thinking through that, Michael. I think one thing that's beneficial with 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 a 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 million 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 flow 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 this 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 million to $10 million -- or $8 million to $12 million 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 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 -- then 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 consumers. 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 these -- the increase in costs that we've had throughout our businesses. Plus, we've not even asked for a recovery of the capital investments, if you will, for the $400 million we've invested in DSIP. So the customers have already benefited from these lower tax rates over the years. 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're deserved to receive based upon the change in our current year tax rates.

And we'll go next to Julien Dumoulin-Smith with Bank of America Merrill Lynch.

So perhaps just a 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 in the CapEx. I suppose the question that I would have on the other side of it is, how do you think about that time line 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. And I think what we're doing right now is we're leading with those investments in South Dakota, really, at the end of '18 and into '19. And then we're going to start to ramp up for Montana, if you will, end of '19, and start '20 and '21 really into those programs. And that timing, of course, could vary depending on 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 [revolving debt] and the potential incremental equity, I suppose there's a few other points that you brought up on a call with respect to cash flows, if you could elaborate. First, could you comment on the potential retroactivity, I suppose, back to July of PCCAM? And then, separately, can you comment on the potential, I suppose, you've 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 pretax earnings and cash flow impacts that are presumably a reduction, right? So I just want to understand the time line for potential equity in light of those 2 potential decisions as well as the CapEx.

Well, I think, Julien, you've asked a lot there. I think we'll start with the PCCAM. I can't really gauge how much of the impact from a dollar perspective. I could argue the range in PCCAM 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've pretty much laid out, based upon those 2 methods, what the amount would be. I'd put it in the context we're going to know within 2018 outcomes on those 2 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 2 filings and the outcomes of those 2 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 of that is we've talked about the possible retroactive application of the new PCCAM regime as a result of the additional issues layer in the case that's added quite a lot of the overall timeline. The Consumer Counsel, at a high level, you could characterize as saying, "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 PCCAM 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 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 we 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 saw 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 in the Colstrip case could be applied elsewhere?

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 in 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 QF side of things. Obviously, we saw you pursue 2 projects here, I suppose. There was the first -- I think it was like an 80-megawatt wind project and a separate 8 megawatts. Can you talk about further prospects for additional renewables on a rate-based context in light of QFs 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 are 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 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 QF, of course, Beethoven, and here, Two Dot wind, these are opportunities as a result of right of first refusals that we build into these QF contracts. 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 for us from a rate-basing perspective. And so the things have to kind of fall into place in order for us to capture these opportunities.

(Operator Instructions) And we'll go next to Jonathan Reeder at Wells Fargo.

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 like out of an abundance of caution? Or did 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 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 FERC order resulted in about $8 million to $9 million of lower annual revenues than you believed weren't necessary to fully recover the plant at the time. I know you've been operating the plant differently than originally contemplated, particular 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 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 to your strategy there?

Brian, why don't you talk about the shortfall first.

Yes, I think the shortfall -- you're absolutely correct. And our expectations 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 jurisdictions, both Montana and FERC and -- to capture that and then demonstrate to both commissions how we're using that plant differently. I think the other thing that -- Jonathan, everything 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 in service back in '11.

There -- it's still obviously substantial, our asset on the books. It's 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 on the federal side.

Sure, yes, that's correct.

And we'll go next to Paul Ridzon at KeyBanc.

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 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'll receive in '18, up until customers, up until of 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 have at this point.

And then just on potentially incremental new generation, kind of what's the potential capital and the time line for figuring that out?

I would really want to push back on assigning a number. As we highlighted in the presentation, we removed over $120 million from the capital forecast. Now we're deep into new plans in South Dakota and Montana. And we talked about some opportunistic activities. But really, the bulk of any of investment is going to be driven by the outcome of the plans.

And the plant both expect to be out by the end of this year.

(Operator Instructions) And we'll go back to Julien Dumoulin-Smith at Bank of America.

Sorry to keep asking you. Just wanted to follow up and clarify on the restated historic impact, the $8 million to $12 million. Is that upside to 2018 [earnings variance]? 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 million to $12 million of additional pretax hit -- would hit us, that's not included in our guidance. We baked into our guidance utilizing our current year method where net income is staying whole as a result of tax reform.

There would be downside pressure on earnings this year.

Sorry. Okay. That's what I wasn't sure about. Thank you very much for clarifying that.

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 month or 2 and hopefully talk 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.