Good day, ladies and gentlemen. Thank you for standing by. Welcome to the NorthWestern Energy second quarter 2018 financial results conference call. Today's conference is being recorded. At this time, I'd like to turn the conference over to your Investor Relations Officer, Mr. Travis Meyer. Please go ahead, sir.
Thank you, Catherine. Good afternoon, and thank you for joining NorthWestern Corporation financial results conference call and webcast for the quarter ending June 30th, 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, Brian Bird, Vice President and Chief Financial Officer, as well as several other members of the management team with us in the room today to answer 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. I will remind you of our safe harbor language.
During the course of this presentation, there will be forward-looking statements within the meaning of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. Forward-looking statements often address our expected future business and financial performance, and often contain words such as "expects," "anticipates," "intends," "plans," "believes," "seeks," or "will." The information in this presentation is based 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-K and 10-Q, along with other public filings with the SEC.
Following our presentation today, we will open up 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 Time and can be found on our website. Again, that's northwesternenergy.com under Our Company, Investor Relations, Presentations, and Webcast link. To access the audio replay of our call, dial 888-203-1112, access code 7508519. I'll hand it over to Bob to run through the results.
Travis, thank you very much, and thank you all for joining us this afternoon. We are in Aberdeen, South Dakota, known as the Hub City, and it's a major trading hub in South Dakota. As you know, the partnerships we have with our communities is very important to us, and there's no place that more exemplifies that than Aberdeen. Over the last several days, we had a great community meeting, a meeting with our employees this morning, and yesterday got a chance to see some of the exciting growth and development in Aberdeen. It's a trading city, also a real center for what you could think of as industrial and agricultural work, and we are very much a part of that. In fact, our area manager also leads much of the economic development work in the Aberdeen region. It's been a great several days.
Turning to the board, a number of you know Stephen Adik, who just stepped up as Board Chair, and Linda Sullivan is now Chair of our Audit Committee. We continue to have just a very strong and constructive board of directors. It has been a good meeting with a lot of good work done. Turning to highlights for the quarter. Net income increased $22 million, or 100.6% as compared to the same period last year. This increase was primarily due to a gain related to the adjustment of our Qualifying Facilities liability. Brian will take you much, much deeper into that, along with favorable weather and, to a lesser extent, increased demand for electric transmission service. Diluted EPS increased $0.43 or 97.7% as compared to the same period last year.
Adjusted non-GAAP earnings per share increased $0.16 to 34% as compared to the same period. The board declared a quarterly dividend of $0.55 per share payable on September 28th to shareholders of record as of September 14th. With that, I'll turn it over to Brian to go deep into the financial results.
Thanks, Bob. On slide four, summary financial results for the second quarter. As Bob pointed out, a net income of $43.8 million at $22 million or just over 100% improvement quarter-over-quarter from a diluted earnings per share, $0.87, a $0.43 or approximately 98% improvement again, quarter-over-quarter. The quarter is primarily driven by an improvement in gross margin, and I'll get into that more in a minute. $29.7 million improvement, approximately 15%. Continue to control cost, particularly in the Operating, General & Administrative expenses, and that led to the results for the quarter. Speaking of gross margin, on page five, I'll get into the actual specifics. We had $229.6 million of gross margin. That's a $29.7 or nearly 15% improvement. The primary improvement, particularly in the change in gross margin impacting net income, came from a $25.1 million electric QF or Qualifying Facilities liability adjustment.
I'll speak to that more in a moment. In addition to that, we had good volumetric improvement on a year-over-year basis. Retail volumes on the electric side up 2.5 and on the gas side up 1.5 million. Continued good use of our electric transmission system of $1.4 million improvement on a quarter of the primary items. Again, moving gross margin that actually impacts net income
We have some things that impact gross margin that are offset elsewhere within the P&L. We had a $6.2 million reduction or a decline on a year-over-year basis due to the Tax Cuts and Jobs Act deferral during the quarter. That was offset partially by a $3.5 million recovery of property taxes in our trackers. That net change for those items in gross margin are offset elsewhere in the P&L with minus $2.4 million, netting to the $29.7 million increase in consolidated gross margin. Speaking about the $25.1 million improvement in Qualifying Facility earnings benefit, the reduction in that liability is really broken out into two parts. The first part, a $17.5 million benefit, was resulting from the reduction of an estimated future liability or a forward-looking look at our unrecoverable QF costs. Those out-of-market costs are expected to be $23 million less, and on an NPV basis, $17.5 million.
That reduction in that liability, we actually backed out of our non-GAAP results, similar to how we handled the loss from this calculation back in 2015. The other component of the benefit was a $7.6 million benefit due to the annual adjustment to reflect lower actual output and pricing of QF-related supply costs. That was driven largely by outages at two of our QF facilities. Due to the annual nature of that adjustment, we have not excluded that from our non-GAAP earnings. Moving forward onto page seven, just to speak about weather for a moment. We point out in the red box on that page that we estimate unfavorable weather in the second quarter was a $1.4 million unfavorable compared to normal and approximately $0.6 million favorable as compared to the prior year.
Speaking as I look at it, the best way to describe it from my perspective in terms of versus normal, we had unfavorable weather in Montana. It was a bit warmer during our heating months there, even though it was a bit colder in South Dakota and Nebraska. That helped offset that. It was a bit warmer in South Dakota as you actually captured some cooling degree days. The Montana unfavorable, if you will, versus normal, overwhelmed the South Dakota favorable. You can see that actually on the map to a great extent as you look at the weather in Montana. It certainly wasn't cold enough in April and May when we're getting heating degree days. There's very little load, if you will, from a cooling degree day in Montana. South Dakota did its part.
It was certainly cold in April, as you can see. It was warm in May and June, and we actually had quite a bit of cooling degree days associated with South Dakota. Versus the prior year, the South Dakota favorable actually slightly overwhelmed the Montana unfavorable on a year-over-year basis. Moving forward to operating expenses on page eight. Operating expenses of $160.3 million, or a $6.7 million improvement, approximately 4.4% on a year-over-year basis for the second quarter. Operating, General & Administrative expenses up $1.2 million or just under 2%. Property taxes up $3.5 million or almost 9%, and depreciation depletion up $2 million, almost 5%. If you look at the increase in the OG&A piece, we really look at that in kind of two pieces, though.
When you look at the change in OG&A expenses actually impact net income, we actually were down $1.9 million on a quarter-over-quarter basis. We did have an increase in employee benefits. We've had higher medical claims than we had the prior year. Slightly higher pension costs on a year-over-year basis primarily drive that. We did have favorable variances in terms of maintenance costs, lower labor costs. The DSIP program ended in 2017 and some other favorables that helped to keep our cost from that perspective, those things that impact net income down on a year-over-year basis. Those changes in OG&A that actually are offset elsewhere in other income, we had from a non-service cost component. We have an increase in OG&A that's offset in other income of $2.6 million. As you know, our non-employee directors' deferred comp impacts both OG&A and other income as well. That was $500,000.
The change, the total of those two items is $3.1 million. The net effect of all of that was a $1.2 million increase in Operating, General & Administrative expenses. Property taxes are up $3.5 million, as I pointed out earlier, primarily higher plant additions and higher annual estimated property valuations, and depreciation depletion up $2 million, primarily due to plant additions. Moving forward, page nine in operating and net income. Operating income is $69.2 million to $22.9 million or nearly 50% improvement. Below that, interest expense was relatively flat on a quarter-over-quarter basis. Other income was an improvement of $1.4 million, primarily as a result of things I talked about previously, the decrease in other pension expense and increase in value deferred shares from a non-employee director deferred comp basis. Both of those were offset a bit by lower capitalization allowance funds for use during our AFUDC purposes.
Those items lead up to an income before taxes of $46.9 million at $24.5 million improvement or 109%. Below that, of course, income taxes were up $2.5 million, and primarily a result of higher pre-tax income, offset partially by a lower statutory federal tax rate in 2018. Speaking of income tax reconciliation on page 10, we talked about the increase of $2.5 million. The primary driver for that, as you can see at the top of the page, is the increase in pre-tax income. Even at a lower rate, we did have a higher increase on the income tax calculated at the federal statutory rate. Below that, three items also had an impact. The state income benefit was actually $1.3 million less. That's primarily as a result of the loss of bonus depreciation.
Flow-through repairs was slightly less as well, primarily as a result of the lower federal statutory rate. Production tax credits. The benefit actually slightly better as a result of higher pre-tax that we've had thus far through 2018. One other thing I'd point out on that page is the effective tax rate for the quarter is 6.6%, but we do anticipate our year-end ETR to be, again, between the 0% to 5% range. Moving on to the balance sheet. Total assets stayed flat. Property, plant, and equipment are up just under $100 million. We also see a decline in accounts receivable, similar to what you'd see from the seasonality that we have in our business. On the liabilities and equity side, again, relatively flat. Shareholder's equity was up $100 million.
Think the improved earnings and think of the incremental utilization of our ATM program helping out there, offset by $100 million reduction in debt. That activity, as you can see at the bottom of the page, impact our ratio of debt to total capitalization now down to 51.1%, comfortably in our 50% to 55% range. Continue to look at means to de-lever the company. Moving forward from a cash flow perspective on Page 12. We had a $68 million improvement in cash provided by operating activities, primarily due to the higher net income, but also improved collection of customer receipts and increased recovery of certain costs through our supply trackers. Incremental cash flow plus the benefit of the proceeds from the issuance of our common stock allowed us to have a bit of an increase in our cash used in investing activities.
We did invest in Two Dot Wind, made an acquisition, small acquisition there to continue to grow our generation fleet. We also used that incremental cash, as I noted earlier, to pay down just approximately $100 million of debt. Moving on to Page 13, adjusted non-GAAP earnings. Those of you who are with us on a quarter-to-quarter basis certainly understand how this schedule works. Effectively what we do is take the GAAP earnings from the end of the quarter. 2018 is in the far left margin, and the GAAP from three months ended in 2030 and 2017 on the far right margin. We move towards the middle to get to the non-GAAP numbers for comparison purposes. We do exclude certain items on a going-forward basis. We do exclude weather. We did have unfavorable weather both in '17 and '18 in the third quarter.
This particular quarter in 2018, we also excluded $17.5 million of the liability reduction for the QF liability. That's shown as well. We also have two other items that are just primarily there to, from a non-GAAP basis, properly display what we believe a better display of our OG&A expenses, since both the pension items and the non-employee deferred compensation I talked about earlier are effectively offset in OG&A and other income. When you take all those items into consideration, as I mentioned earlier, our diluted earnings per share was $0.87 for the quarter. Adding back $0.02 for unfavorable weather and taking out $0.26 for the gain on the QF liability, we had a non-GAAP diluted EPS of $0.63 for the quarter. That compared to $0.47 for the prior year quarter.
Also looking at the variances throughout the P&L, when you make those adjustments, we still had strong improvement in gross margin of about 5.7%. Continue to stay on top of our operating expenses. Even though we had increases in property taxes and depreciation, we were able to actually manage on a non-GAAP basis our OG&A to a decline. That helped keep total operating expenses up only 2.3%, which certainly helped operating income at 17% and flowed through down to pre-tax income of 26% and net income at 38% improvement. A good quarter from that perspective. Moving on to Page 14, our 2018 earnings guidance. Just the chart at the top of the page are the blue bars, and the square boxes demonstrates over time from 2012 to 2017, a 6.8% non-GAAP adjusted EPS growth rate, plus the history of meeting our guidance.
To the far right of that chart shows our 2018 guidance of $3.35-$3.50. We're reaffirming that guidance during this quarter. One thing I would like to remind folks in terms of what's in our guidance and what's not, those assumptions there, I think you all are well aware, we always assume normal weather. We provide an income tax rate, which is 0% to 5% of pre-tax income. We provide a guidance in terms of our diluted average shares, 50.1 million. No change in that from prior quarters, so thus not planning any additional equity for the remainder of the year. I do want to point out, though, our guidance does include, I should be clear, equitable regulatory treatment on our Tax Cuts and Jobs Act filing, in line with our filing, and then a recovery amount to energy supply costs as proposed in our pending PCAM filing.
Lastly, continued investment in our system to serve our customers and communities expected to provide a targeted long-term growth of 6% to 9% total return to our investors through a combination of earnings growth and dividend yield. Turning to page 15 and talking more about our full-year non-GAAP guidance. At the top left side of the page, you see our six-month ended June 30, 2018, actual results, reported GAAP of $2.00, again, on a year-to-date basis, $2.05 diluted EPS. When you remove on a year-to-date basis favorable weather of $0.05 and remove the gain on the QF liability of $0.26, it brings us down to an adjusted non-GAAP year-to-date, $1.74.
In order to achieve our $3.35-$3.50 for full-year EPS to the far right in the top of the page, we'll have to achieve in quarters three and four, a total of $1.61-$1.76 of EPS. Looking at our actuals down below for the six-month end of June 30, 2017, you can see in Q3 and Q4, we achieved a non-GAAP number of $1.70, which is comfortably in between what we need from the remainder of 2018, the $1.61-$1.76. Moving forward, I guess I pass it back to Bob. Actually, looking forward.
Thank you, Brian. Great segue, whether planned or not. Starting very high level on the regulatory front, obviously we will continue to focus on ensuring fair treatment of implementation of federal tax reform. We do have proceedings underway in multiple jurisdiction there, the ultimate goal is simply to ensure that the benefit does flow through to customers in some way, while very importantly, keeping shareholders, keeping investors whole. We've proposed mechanisms to ensure that that occurs. Secondly, continuing to move ahead on implementation in Montana of a new Power Cost and Credit Adjustment Mechanism. The third, working on preparation of an electric rate case to be filed by the end of 2018 based on a 2017 test year. We have been consulting with a stakeholder group, our latest stakeholder group in Montana, the Customer Vision Group.
What we're engaging them to discuss really is future-looking policies to allow us to be aligned as much as possible, ultimately with our customers' interests. Our core investment, you'll see this in our capital plan, continues to have a very strong transmission and distribution infrastructure focus. There we've transitioned from successful implementation conclusion of our distribution system infrastructure plan to really an end-to-end infrastructure investment plan. In Montana, that was with guidance from an infrastructure stakeholder group, in South Dakota, guidance from a parallel group. An area of particular interest in South Dakota with what we call our Network South Dakota Infrastructure Group, was really creative ways to build out our natural gas service to more communities. Talk about that in more detail over coming quarters.
Obviously, safety and compliance are important values. We do have significant investment associated with the PHMSA integrity verification process and requirements. Grid modernization, we've taken a conservative approach to grid mod, focusing initially on the basic infrastructure, but now moving into both advanced metering infrastructure and advanced distribution management systems. We're moving towards implementation first in Nebraska and South Dakota. Our supply group is actively updating our two electric supply plans. In Montana, the focus is least cost, lowest risk approaches to address our core needs, that is for sustained intermittent capacity and reserve margins. We've discussed those needs, that exposure in detail on previous calls. You can look out for a Montana plan towards the end of this year.
A major activity in the Montana plan has been the release of a request for information. Responses to the RFI are due by the end of this month, then those will be an input into the Montana plan. In South Dakota, the focus has been a generation fleet assessment to evaluate economic retirement and replacement opportunities that potentially provide benefits, not just on the supply side, but also on the local distribution side. I think you can look forward to us discussing the South Dakota plan and implementation in more detail in our October call. We are a low-cost operator, particularly marking against our peers. We continue to monitor costs, including labor benefits and, of course, property taxes, I think have done a good job of mitigating those increases. Cost control is an important ongoing value.
A little bit more detail on implementation of the Tax Cuts and Jobs Act. As I mentioned, dockets have been initiated in each jurisdiction to ensure that customers do receive benefits in ways that are fair to investors as well. We do have filings open. We don't expect material impacts from Iowa, deferred, or Nebraska filings. As of June 30th, we deferred approximately $13.5 million associated with tax act implementation, but the revenue deferral was offset by a corresponding reduction in income tax expense. As a result, no impact to net income. We calculated the customer benefits using two alternate methods, one based on current expenses and one using an historic test method. The concern, of course, with the historic method is it's very difficult to go back and recreate all aspects of an historic test year.
If you're not able to do that, essentially turn back the clock or reopen all the books, there's a real concern, I think, about asymmetry and fairness to investors. The expected full year 2018 revenue reduction for the current period method would be $18 million to $23 million, which again, would be offset by an equal reduction in income expense and therefore would have no impact to net income. On the other hand, application of the historic method could result in customer refunds that do exceed the 2018 tax benefits, and therefore would result in a $5 million to $10 million of additional pre-tax earnings and cash flow detriment for the year. Use of the deferred revenue of a regulatory liability will be determined in the pending dockets in Montana. An August 30th hearing has been scheduled. South Dakota and Nebraska schedules are pending.
As a result of tax reform, we've updated our 2018 ETR assumption to between 0% and 5%, and previously that was 8%-12%. We've also reduced our deferred tax liability by about $320 million as of December 31st of last year, and this reduction is offset in regulatory assets and liabilities. NOLs are now anticipated to be fully used in 2020. Previously, we had projected 2021. We currently, and this is important, of course, believe our debt coverage ratios will be adequate to maintain existing credit ratings. However, further negative regulatory actions could lead to credit downgrades and could necessitate additional equity issuances. Both those sentences are important. Turning to the capital forecast for 2018, we've discussed this before.
We see really a level capital projection based on current plans out over the next five years, and also a good balance between jurisdictions and between electric and gas. The cumulative current five-year estimate is $1.596 billion. We anticipate funding these investments with a combination of cash flows, again, aided by NOLs through 2020, as well as the equity distribution. I should note that the equity distribution is now complete and at a gross average share price of just below $58. We consider that to have been a successful program. Significant capital investments that are not in the above projections or further negative regulatory actions could necessitate additional equity issuances. Based on the plans as reflected in this capital forecast and assuming no negative regulatory actions, we don't anticipate further equity issuances at this time.
As we've discussed previously, the changes in the 2018 forecast involve, first, $123 million of previously included capacity generation has been removed, pending issuance of the jurisdictional supply plans, included has been about $126 million of incremental investment related to grid modernization and AMI infrastructure, starting first in South Dakota and Nebraska. Should note again that for those two jurisdictions, we did previously include about $28 million in investment. With that, we can open up the bridge for questions, and I did ask our operator to queue up the easy questions first.
Thank you. Ladies and gentlemen, if you'd like to enter the queue to ask a question, you can do so by pressing star one on your telephone keypad. If you're on a speakerphone, please pick up your handset and make sure your mute function has been turned off to allow your signal to reach our equipment. Once again, that's star one. We'll go to Michael Weinstein with Credit Suisse.
Hi, guys.
Hey, Mike.
Hey, it looks like on slide 15, you are excluding the QF gain from guidance as well, right? It's not going to be part of your means to reach guidance for this year, right?
That's correct. The $17.5 million we excluded-
Yeah
is not included in our guidance, correct.
Okay. Just wanted to confirm that. Can you just confirm that you will be filing the rate case no later than September 30th, even if the PCAM case is not resolved by that time?
All systems.
How do you do that? How do you file the rate case without knowing how the generation side's turning out?
We will have to work through that. There certainly will be noise, but we will get it done.
Okay. Could you just give a little bit more color on bifurcation, the ruling on that, and why you think Commissioner Kavulla might choose to recuse himself from the case?
We can't speak for Commissioner Kavulla, he would serve through the end of the year, that would be the early stages of the case. That really is a question for Commissioner Kavulla. In terms of bifurcation, our experience has been, I think the commission's experience has been, that bifurcation has really allowed the cleaner and more orderly conduct of cases. We think that's a positive in that scenario. Revenue requirement is an input into cost allocation and developing a pricing structure, and that's worked well. We have concern about the commission's approach to our bifurcation request, effectively leaving the revenue requirement open. We think that creates an extended period of uncertainty, and certainly is troublesome from an investor perspective as well.
Right. I think, is it true that Commissioner Kavulla recused himself from the bifurcation decision?
To point out that in terms of the, if you're referring specifically to the work session earlier this week, we don't have a written order on our motion for reconsideration yet.
Okay. Thank you.
Thank you. Bye.
Thank you. Bye.
Our next question comes from Julien Dumoulin-Smith.
Hey, good afternoon, guys.
Hey, Julien.
Hey. A few different questions here. Maybe to pick up on where Mike left off on the QF stuff, can you comment a little bit more specifically on the $7.6 million benefit to the annual adjustment? First, is that in your guidance, just to be very clear when you contemplated, I imagine not? Can you give a little bit more thought process around how the outages relate to the, or if at all related to these price escalations? Why this impact now, maybe?
Well, the outages have an impact because we're actually able to procure power at a lower cost than the QF costs that are in the particular liability itself. The outages certainly helped. To your first question, in terms of any amount in guidance, we did have a small amount in guidance at the start of the year because one of the QFs actually was out of service for a period of time in the fourth quarter, and we knew that going into the period of time. It certainly wasn't the level of the $7.6 million benefit that we had this year. Should also point out, we did have a $2.1 million benefit last year as well. The $7.6 million was the increase, if you will, on a year-over-year basis.
Right. More importantly, the outage element here doesn't necessarily impact this on an ongoing basis. This, as you say, is a year-over-year impact based on a specific outage.
That's right. That's just year-over-year. It doesn't impact things on a going-forward basis unless these QFs were out of service for a long period of time.
Right. To be clear, you had some amount of this not necessarily defined in your guidance based on what was already looking like a setup into 2018 with some degree of outage on this asset.
Yes. Correct.
All righty. Excellent. I'm going to just keep going here. Can you give us a little bit more of a sense of the earnings impact if you use an asymmetric sharing band in PCAM? Can you give us a little bit of a sense of maybe even the sensitivities to think about that real quickly? Maybe in tandem with that, obviously the process is ongoing here. Is there any chance to settle here, just to kind of hit that?
I'll speak to the second question. We are always open to constructive discussions with parties. On the other hand, we can't discuss settlement discussions specifically. We're always open to talking to parties.
On the first question, Julien, it's very difficult for us to ascertain the impact of asymmetrical sharing of dead bands and the like, and certainly not comfortable talking about this on this call.
That's fair enough. I know it's a little tricky. Oh, sorry.
I'm going to add one thing. I know that for some parties, including us, and this is a generic comment, but the ability to settle a case depends on some comfort with how the regulator in that particular case will view a settlement and how much confidence you might have that a settlement will ultimately be approved as agreed to.
That's a fair comment. Perhaps just a last quick question. Can you confirm the $5 million-$10 million of pre-tax earnings impact from applying the historic method with regards to tax reform is a one-time element, or is that an ongoing element into 2019 and onwards, if indeed adopted?
Well, I'd argue it's an annual impact until you get a rate case resolved, right? You could argue an annual impact for 2018 and a portion of 2019 could be an impact as well. Again, if the historic method, of course, on a going forward basis, they will capture our new tax structure, but we'll also capture all the increases in cost elsewhere, which would have been an appropriate way to handle this issue to begin with.
Your expectation is basically by the time that you get new rates, insert whatever date that may be, this should effectively roll out?
Correct.
Okay. Excellent. All right. Excellent. Well, thank you.
Thanks, Julien.
Our next question comes from Paul Ridzon with KeyBank.
Good afternoon.
Hey, Paul.
Can you just quickly review the calendar on the PCAM and tax dockets?
Sure. Let us pull that up quickly. On PCAM, briefing is ongoing. Reply briefs are due on August 31st. We don't expect a decision until September at the earliest, and obviously the commission needs time to review the brief schedule work sessions and then ultimately decide. The window would open essentially in September. Concerning the Tax Cuts and Jobs Act implementation in Montana, opening intervener testimony has been filed. Rebuttal and cross-intervener testimonies filed. Rebuttal testimony is due August 2nd, and the hearing will be held on August 31st, with briefs and deliberations sometime after that. In Nebraska, a tentative settlement reached. Nebraska is a little bit of a different approach, where we typically negotiate regulatory decisions with the municipal jurisdictions, and then those are submitted to the Nebraska Public Service Commission for review. At this point, we're waiting for an order from the Nebraska Commission.
In South Dakota, there's active settlement discussions with the commission staff, and those are positive to date. At the FERC, there's no real deadline by which the FERC needs to make a decision. However, earlier this spring, the FERC did indicate that it intended to act on all of these filings, and they of course, have many, within 180 days, which would move you into September or November.
Any commentary on any legislative intervention on the PCAM issue? Have legislators become involved in this with the commission?
The interim legislative committee certainly has an oversight function and is aware of the docket and developments in the docket. I have no comments beyond that.
Okay. Thank you very much.
We will now hear from Jonathan Reeder with Wells Fargo.
Hey, Bob, did I miss you give a more specific timeframe of when you think the tax reform treatment in Montana would be decided?
Yeah. In Montana specifically, there will be a hearing starting on August 30th. Subsequent to the hearing, there will be presumably some kind of a briefing schedule, then that would push the decision off potentially till later in the year.
Okay. Other than before year-end, no real specifics at this juncture?
It would be hard for us to say anything beyond that.
Okay. Did the parameters of the potential kind of historic test period method kind of get tweaked? I thought on the Q1 call you gave some bit higher numbers, like an $8 million-$12 million range, as opposed to the $5 million-$10 million cited today.
Yeah.
Yeah. Brian, go ahead.
Oh, go ahead. They did change slightly. Obviously, we're through the midpoint of the year, and we looked at adjusted numbers a bit, and the expectation that could change, but also take into consideration the total. You'll notice that we increased the range for the current year method, but also decreased the range from the historical method. One would argue the differentials decreased a bit.
Okay. I gotcha. Finally, can you give a little more color on the Customer Vision stakeholder process in Montana, and how, if at all, it's shaping the way you're approaching the rate filing and what you plan to request?
Yeah. Well, the original notion was to work with this group to at least narrow differences, identify areas of key interest, and then use those to inform the rate design filing in a second part of the case. Given where we understand the commission is at this point, we intend to file a complete soup to nuts case at the end of September. We've had tremendous success with stakeholder groups, certainly over the last 10 years that I've been with NorthWestern. We take them seriously. We find the input valuable. In this case, we've got a very diverse group, an expert external facilitator. The rate filing will be a backdrop to discussions in the Customer Vision Group.
Really what we're trying to do is identify the set of policies that are appropriate, at least for this company in Montana, going forward to help address some of the disconnects, we think, between the current regulatory structure, customer expectations, and public policy. What we're doing in that process right now is trying to gather information from outside of Montana, stick our heads up and look around a little bit, but look at situations that might be of interest and relatively more relevant to Montana. Actually, on Monday, Ann McCabe, a former Illinois commissioner who was in the middle of regulatory reform in the early stages of grid modernization in Illinois, is going to be speaking to the group. Last month, we heard about a very broad, sustained effort in Minnesota.
We're also going to be looking this fall at some interesting things that Green Mountain has been doing when Mary Powell, the CEO from Green Mountain, comes out. We're putting a pretty diverse set of perspectives in front of this group, but trying to look at some examples that might be a little bit more relevant to Montana than would, for example, the New York REV or whatever is happening in California would be.
Okay. It's a very, I guess, kind of broad, big picture kind of focus, stakeholder group. Nearer term, I guess it would influence your rate design aspects of the case.
As originally conceived, it was going to be an input. Again, now we will be filing a complete rate case at the end of September. That filing will be based on our views, not really on input from the group, because that discussion really is still in the, not entirely, but primarily in the information sharing stage.
Okay. All right. Well, I appreciate you taking the time to answer my questions, and good luck as you press into the important stuff with the commission coming up.
Thanks, Jonathan.
Thanks, Jonathan.
Our next question comes from Andrew Levy with ExodusPoint.
Hi, guys. Can you hear me?
We can hear you, Andy.
Actually, most of my questions were asked already. Just two simple ones. Just where do we fall as far as your guidance range right now, do you guys think? Are you leaning in the middle, the low end, high end, based on what you've seen thus far?
Brian is thinking.
Again, excluding any regulatory changes.
Yeah. Andy, we have reaffirmed our 335-350.
Okay. You're kind of trending towards the middle, is that what you're saying?
Nope, it wasn't a simple question, was it? We're reaffirming our 335-350.
Okay, that's fair. The second one, I guess is more for Bob. Where do you guys fall as far as your view on M&A? I know we've discussed this before, Bob, but in the context of NWE, whatever you'd like to say, in context of continuing consolidation within the industry.
Really, at this point, no comment. We've offered our philosophical views previously, I really don't have anything to add to that.
You guys don't have much to say.
We're kind of a quiet bunch here in Aberdeen.
Okay. Thank you. You guys have a good weekend.
Thanks, Andy.
Thanks, Andy.
Yep.
As a reminder, that's star one for questions. We'll go to Paul Patterson with Glenrock Associates.
Hey, good afternoon.
Hey, Paul.
One of my questions been answered, just a few quick ones. Just on the $17.5 million that benefit that's not included in your ongoing earnings. How does that work over time as the contracts work their way through, if you follow me? Is there any earnings impact that we should think about that going forward?
Yeah, we have non-cash interest associated with that liability that as a result of the reduction of liability, we'll see an improvement in non-cash interest of about $1.3 million each year. That's a periodic liability adjustment, you can have adjustments made. I mentioned the last time we made an adjustment was in 2015 for that. There's exposure. By the way, back in 2015, that was a loss that we recorded that year. There's going to be potential impacts on earnings, that contract that provides that particular exposure goes through 2024, so that's the period of time that we could have exposure to that contract in terms of some volatility to earnings.
In addition to that contract, as we talked about the other component of the QF liability is each and every year, there's an issue in terms of what's the actual production from these units and what's the actual pricing. Those impacts come into play as well.
Okay. If I understand you correctly, there might be a benefit going forward, but the fact that this thing's always being adjusted, et cetera, means that there's not a lot of predictability to it. Does that make sense?
That's a great summation.
Okay. Then, the comment that you made with respect to equity issuance not needed in the absence of a negative regulatory outcome, is that just sort of a generic statement? Just to sort of put a finer point on it, should we think about this in relation to the PCAM or with respect to the upcoming rate filing? Could you just elaborate a little bit more on that? You're just sort of highlighting that because of the regulatory environment that you're in. Do you follow what I'm saying?
Yeah. I'm comfortable with your question. First of all, let me speak about the rate case. It has nothing to do with the rate case whatsoever. Matter of fact, we're looking forward to the rate case. There's been a tremendous amount of investment we've made in this company, and we think we've done customers the right thing to try to stay out of rate cases for years, but it's time to get recovery on that investment. We look forward to the rate case. We just see a tremendous amount of exposure on tax reform and PCAM, and don't know what those outcomes, and as my earlier question, it's difficult to gauge what those outcomes would be. We're not sure where PCAM ultimately will end up. It's easier to kind of understand the differential on tax reform.
We just want to be clear that there's a potential that we could have to do something from an equity perspective, but I also want to tell you, certainly it's our intent to try to manage any outcome without having to raise equity, to try to manage our business accordingly.
Okay. I appreciate it. Thanks so much and have a great weekend.
Thank you.
Thanks, Paul.
We have a follow-up from Michael.
Hi. Hey, one quick follow-up on the guidance. The $17.5 million benefit from the QFs, that's excluded and not benefiting guidance. The $7.6 million benefit from the outages, related to the outages, that's the ongoing adjustment. That is actually in the guidance, and that was about a $5 million improvement over last year. Did I read that right?
Yeah. Mike, let me just straighten you out a little bit, though you're directionally correct. Since the 7.6, that was the increase on a year-over-year basis. There was a $2.1 million gain last year, $7.6 million increase this year. We had a small amount, I'm not going to give you the actual amount, of an impact built into our margin guidance associated with the fact that we were aware of outages at the end of the year. It wasn't certainly anything near the 7.6 number.
Yeah. That's right. You figure if you were assuming the same thing as last year, you're about a little over $5 million more this year. That's like almost $0.07 a share. Is there any reason why we didn't move up the guidance range at all for that? Or is it being conservative? What's your thinking on that?
My thinking is we've reaffirmed our guidance at $3.35, Michael.
Okay. Thank you.
There's quite a bit of the year left, too, from our perspective, and I kind of want to see how things play out.
Yeah. It's only second quarter.
The nerve.
All right. Thank you very much. Have a good weekend.
Thank you.
Thanks, Mike.
Thank you. Oh, it looks like we have a follow-up from Andrew Levy as well.
Okay. Let's try this one more time. If you have normal weather, normal conditions between now and the end of the year, and you book that extra $7.4 million, so everything kind of comes in as expected, and as the year had been guided to, would that amount lead to earnings above the midpoint?
I appreciate you trying again, Andy. My answer's the same. We're reaffirming our $335-$350.
What I wanted to say is thank you for the follow-up questions. This is great practice for when Brian's on the stand in a month or so in the tax docket.
Well, if you needed someone else to testify for you, I'll help, too.
Come on out.
Have a good weekend.
Thanks.
Gentlemen, no additional questions.
Just to wrap it up, we obviously appreciate the good discussion and interest over the quarter. At page 20, we summarize some, we think, key characteristics of the company. We've talked about these best corporate governance practices. I spent a minute at the top of the call talking about directions of our board. The fact we are a pure electric and gas utility, great foundations. We paid attention to those basics. We do have strong earnings and cash flow. We talked about attractive, I would say maybe more actionable future growth prospects. Those are things to keep in mind. I did my pitch for the Aberdeen Chamber of Commerce at the top of the call. The photo here on page 20 is Mystic Dam, right on the edge of the Beartooth Wilderness.
It is one of the most amazing places. I think, since you cover the company, you owe it to yourselves to come out, and we'll take you on a hike up there. If it's in June, our supply vice president, John Hines, will put you in a kayak. I've touched on this. The hydro system obviously has been such a great asset for us. We have realized so many values out of the hydro system beyond the energy that was really priced into the transaction. This is very much a part of that. Again, thanks for joining us on the call. Look forward to seeing you over the coming months and visiting next quarter.
Thank you. Ladies and gentlemen, again, that does conclude today's conference. Thank you all again for your participation. You may now disconnect.