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NorthWestern Corp
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Good day, ladies and gentlemen. Thank you for standing by. Welcome to the NorthWestern Corporation’s Second Quarter 2018 Financial Results Conference. Today’s conference is being recorded. At this time, I would 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 30, 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 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 our Safe Harbor language. During the course of this presentation, there will be forward-looking statements within the meaning of the Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995. Forward-looking statements often address our expected future business and financial performance and often contain words such as expects, anticipates, intends, plans, believes, seeks or will. The information in this presentation is based on our current expectations. Our actual future business and financial performance may differ materially and adversely from our expectations expressed in any forward-looking 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 at northwesternenergy.com under Our Company, Investor Relations, Presentations and Webcasts link. To access the audio replay of our call, dial 888-203-1112, access code 7508519.
With that, I will 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 is no place that more exemplifies that than Aberdeen. Over the last several days, I have had a great community meeting, meeting with our employees this morning and yesterday got a chance to see some of the exciting growth in development in Aberdeen, it’s a trading city, also a real center for what you could think of is industrial and agricultural work and we are very much a part of that. In fact, our area manager also leaves much of the economic development work in the Aberdeen region. So, it’s been a great several days. Turning to the board member of you know, Steve Adik, who just stepped up as board chair and Linda Sullivan is now chair of our Audit Committee and we continue to have very strong and constructive Board of Directors. So, it has been a good meeting with 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 and this increase was primarily due to a gain related to the adjustment of our Qualifying Facilities liability and Brian will take you much, much deeper into that along with favorable weather and to a lesser extent increased demand for electric transmission services. 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 and the board declared a quarterly dividend of $0.55 per share payable on September 28 to shareholders of record as of September 14.
And with that, I will turn it over to Brian to go deep into the financial results.
Thanks Bob. On Slide 4, summary financial results for the second quarter, as Bob pointed out, net income of $43.8 million, a $22 million or just over 100% improvement quarter-over-quarter from a diluted earnings per share $0.87, a $0.43 or 97% – approximately 98% improvement again quarter-over-quarter. Quarter was primarily driven by an improvement in gross margin and I will get into more in a minute, $29.7 million improvement, approximately 15% continuing to control cost, particularly in the operating general and administrative expenses that led to the results for the quarter.
Speaking gross margin on Page 5, I will get into 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 Qualified Facilities liability adjustment. I will speak to that more in a moment. In addition that, we had good volumetric improvement on a year-over-year basis, retail volumes on electric side, up 2.5 million and the gas side up 1.5 million, continued good use of electric transmission system of 1.4 million improvement on the quarter, 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 $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 $3.5 million recovery of property taxes in our trackers that met change for those items in gross margin that offset elsewhere in the P&L with minus $2.4 million netting to the $29.7 million increase in consolidated gross margins.
Speaking about the $25.1 million improvement in Qualified Facility earnings benefit, the reduction that liability has really broken out into two parts: the first part is $17.5 million benefit was resulting from the reduction of an estimated future liability or forward-looking look at our unrecoverable QF costs, those out-of-market costs expected to be $23 million less and on an NPV basis $17.5 million and so 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 the $7.6 million benefit due to the annual adjustment to reflect lower actual output and pricing in QF related supply costs and that was driven largely by outages at two of our QF facilities and due to the annual nature that adjustment, we have not excluded that from our non-GAAP earning.
Moving forward on to Page 7 just to speak about whether for a moment I will 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. And 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 bit warmer during our heating months there even though it was a bit colder in South Dakota and Nebraska that helped offset and is a bit warmer in South Dakota actually capturing some cooling degree days, but Montana unfavorable if you will versus normal overwhelmed the South Dakota favorable. And you can see that’s actually on the math to a great extent as you look at weather in Montana certainly wasn’t cold enough in April and May when we are getting heating degree days certainly and then there is very little load if you will from a cooling degree day in Montana, but South Dakota did its part certainly cold in April as you can see and it was warm in May and June and we actually had quite a bit of cooling degree days associated with South Dakota. So 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 8, operating expenses of $160.3 million or $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%; 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 have had higher medical claims than we had the prior year slightly higher pension cost on a year-over-year basis primarily drive that, but 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 keep our cost from that perspective, those things did 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 and as you know our non-employee directors’ deferred comp impacts both OG&A and other income as well that was $500,000 change, the total of those two items is $3.1 million and the net effect of all of that was a $1.2 million increase in operating, general and administrative expenses. Property taxes are up $3.5 million as I pointed our earlier, primary higher plant additions and the annual estimated property valuations and depreciation completion up $2 million primarily due to plant additions.
Moving forward to Page 9 in operating and net income, operating income was $69.2 million, a $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 of deferred shares from a non-employee director deferred comp basis, both of those were offset a bit by lower capitalization loss of funds used during our AFUDC purposes. Those items lead up to an income before taxes of $46.9 million, a $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 tax, 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 and even at a lower rate we did have a higher increase on the income tax calculated 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 to peers was slightly less as well, primarily as a result of lower federal statutory rate and production tax credits that benefit actually slightly better as a result of higher pre-tax that we have had thus far through 2018. One other point thing I’d point out on that page is the effective tax rate for the quarter of 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 would see from the seasonality that we have in our business. On the liabilities and equity side, again relatively flat, shareholders’ equity was up $100, thank the improved earnings and thanks to the incremental utilization of our ATM program helping out there offset by a $100 million reduction in debt and that activity as you can see at the bottom of page impact our ratio of debt to total capitalization now down to 51.1% comfortably in our 50% to 55% range, so 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 to our supply trackers. An incremental cash flow plus the benefit of the proceeds from the issuance of our common stock allowed us to have bit of an increase in our cash used in investing activities. We did invest in [indiscernible], made an acquisition, small acquisition there to continue to grow generation fleet. We also used that incremental cash as I noted early to pay down just approximately $100 million of debt.
Moving on to Page 13, adjusted non-GAAP earnings and those of you who are with us on a quarter-to-quarter basis certainly understand how this schedule works, but effectively we do is take the GAAP earnings from the end of the quarter 2018 is in far left margin and the GAAP from 3 months ended 2030 and 2017 on the far right margin and 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.
If you take all of 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 have strong improvement in gross margin about 5.7%, continue to stay on top of our operating expenses and even though we had increases in property taxes and depreciation, we are 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 flow through down to pre-tax income of 26% and net income of 38% improvement, so a good quarter from that perspective.
Moving on to Page 14, our 2018 earnings guidance, just the chart at the top of the page, the blue bars and the square boxes demonstrates over time from 2012 to 2017, 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 to $3.50 and we are 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 a normal weather. We provide an income tax rate which is 0% to 5% of pre-tax income and we provide 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. We do want to point out though that our guidance does not include any – it does include, I should be clear equitable regulatory treatment on our Tax Cuts and Jobs Act filing in line with our filing and then recovery of Montana Energy supply cost is proposed in our pending PCCAM 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 the 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 page, you see our 6 month ended June 30, 2018 actual results, reported GAAP of $2, 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 at $1.74. In order to achieve our $3.35 to $3.50 for full year EPS to the far right in the top of the page, we will have to achieve in quarters three and four a total of $1.61 to $1.76 of EPS. And looking at our actual down below for the 6 month ended 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 $1.61 to $1.76.
Moving forward, I guess I’d 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 historic fair treatment of implementation of federal tax reform, we do have our proceedings underway in multiple jurisdictions there. And the ultimate goal is simply to ensure that benefit does flow through to customers in some way, while very importantly keeping shareholders – keeping investors proposed mechanisms to ensure that, that occurs. Secondly, continuing to move ahead on implementation in Montana of annual power cost and credit adjustment mechanism. And then third, working on preparation of electric rate case to be filed by the end of 2018 based on our 2017 test year and they have been consulting with a stakeholder group, our latest stakeholder group in Montana, the customer vision group and there what we are engaging them to discussion really is future looking policies to allow us to be aligned as much as possible ultimately with our customers’ interest.
Of our core investment, you will see this in our capital plan continues to have a very strong transmission and distribution infrastructure focused. There we have transitioned from successful implementation in conclusion with 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 and in South Dakota guidance from a parallel group and area of particular interest in South Dakota with what we call our network South Dakota infrastructure group of really creative ways to build out our natural gas service to more communities and talked about that in more detail over the coming quarters. Obviously, safety and compliance are important values and we do have significant investment associated with the PIM’s Integrity Verification Process and requirements.
On our grid modernization, we have taken a conservative approach to grid MOD focusing initially on basic infrastructure, but now moving into both advanced metering infrastructure and advanced distribution on management systems and we are moving towards implementation first in Nebraska and South Dakota. Our supply group is actively updating our two electric supply plans in Montana. Their focus is lease cost, lowest risk approaches to address our core needs and that fits for sustained intermittent capacity and reserve margins and we have discussed those needs that exposure in detail on previous calls and even look for in Montana plan towards the end of this year. A major activity in the Montana plan has been the release or the request for information and the sponsors to the RFI are due by the end of this month and then at least will be in the Montana plant. In South Dakota, the focus has been generation fleet assessment to evaluate economic retirement and replacement opportunities that potentially provide benefit much to the supply side, but also on the local distribution side. I think you can look forward to us discussing the South Dakota plans and implementation in more detail in our October call. We are a low cost operator particularly marketing against our peers and we continue to monitor costs, including labor benefits and of course property taxes and I think they have done a good job of mitigating those increases. So, cost control is an important ongoing value.
Still a 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 fairer to investors as well. So, we do have filings open, we don’t expect impacts from my view or Nebraska. As of June 30, 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, so 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 and concerned of course with the historic method is it’s very difficult to go back and recreate all aspects of an historic test year and if you are not able to do that essentially turn back the clock or reopen all the books and there is a real concern I think about asymmetry and fairness to investors.
We expected full year 2018 revenue reduction for the current period now that 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 flows detriment for the use of the deferred revenue of a regulatory liability will be determined in the pending dockets in Montana and August 30 hearing has been scheduled South Dakota and Nebraska schedules are pending. So as a result of tax reform, we have updated our 2018 EPR assumption to between 0% and 5% previously that was paid to 12%. We have also reduced our deferred tax liability by about $320 million as of December 31 of last year and this reduction was offset in regulatory assets and liabilities. NOLs are now anticipated to be fully used in 2020. Previously, we have projected 2021 and we currently – and this is important of course, we currently 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 are important.
Turning to the capital forecast for 2018, we have discussed this before, we see really a level capital projection based on current plans out over the next 5 years and also a good balance between jurisdictions and between electric and gas and the cumulative current 5-year estimate is $1.596 billion. We anticipate funding these adjustments with a combination of cash flow again dated by NOLs through 2020, as well as the equity distribution should note that the equity distribution is now complete and had a gross average share price just below $58, so 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. But based on the plans as reflected in this capital forecast and certainly no negative regulatory actions, we don’t anticipate further equity issuances at this time.
As we have discussed previously, the changes in the 2018 forecast involved first about $123 million of previously included capacity generation has been removed pending issuance of the jurisdictional supply plans and included there has been about $26 million of incremental investment related to grid modernization and AMI infrastructure starting first in South Dakota and Nebraska and should note again this, for those two jurisdictions we did previously include about $28 million in adjustment. So, with that, we open up the stage for questions and I did ask our operator to queue up the easy questions first.
Thank you. [Operator Instructions] We’ll go to Michael Weinstein with Credit Suisse.
Hi, guys.
Hi, Mike.
Hi, Mike.
Just it looks like on Slide 15 you are excluding the QF gain right from guidance as well, right it’s not part of your means to reach guidance for this year, right?
That’s correct. The $17.5 million we excluded from that, included in our guidance, right.
Okay, just wanted to confirm that. And could you talk a little bit about can you just confirm that you will be filing the rate case no later than September 30 even if the PCCAM case is not resolved by that time?
All systems go, yes.
So, I mean, how do you do that, how do you file the rate case without knowing how the generation side is turning out?
We will have to work through that and there certainly will be noise that we will get it done.
Okay. And could you just give a little bit more color on bifurcation, the ruling on that and why you think commissions although they might choose to reduce themselves from the case?
We can’t speak for Commissioner, but he would serve through the end of the year and that would be the early stages of the case, but that really is there is a FERC industry could rollout. In terms of bifurcation our experiences has been and the Commissioner’s experience has been the bifurcation has really allowed cleaner and more orderly conduct in cases. So, we think that’s a positive in that scenario than revenue requirement is an input into cost allocation and developing 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 it’s troublesome from an industrial perspective as well.
Right. And I think is it true that Commissioner to rollout from the bifurcation decision?
I should point out that in terms of the – if you are referring specifically to the work session earlier this week, we don’t have a written order on our motion for reconsideration yet.
Okay. Okay, thank you.
Thank you.
Our next question comes from Julien Dumoulin-Smith.
Hey, good afternoon guys.
Hey, Julien.
So few different questions here. Maybe to pickup on where Mike left off on the QF stuff, can you comment a little bit more, 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, but then can you give a little bit more thought process around how the outages are laid or if at all related to these price escalations or why this impact now maybe?
Well, the outages have an impact, because we actually able to procure power at a lower cost than the QF costs that are in the particular liability itself. So, the outage has certainly helped. And to your first question in terms of any amount and guides, 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 this period of time, but it certainly wasn’t the level of the $7.6 million benefit that we had this year and should also point out this is, we did have a $2.1 million benefit last year as well. So the $7.6 million was the increase if you will on a year-over-year basis.
Right. But more importantly, the outage element here doesn’t necessarily impact us on an ongoing basis, but as you say the year-over-year impact based on the specific outage?
That’s right. That’s year-over-year, doesn’t impact things on a going forward basis and must these QFs were out of service for a long period of time.
And 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?
Correct.
Excellent. I am going to just keep going here on can you give us a little bit more of a sense of the earnings impact if you are using asymmetric sharing band in PCCAM, just can you give us a little bit of a sense of maybe even the sensitivities to think about that real quickly? And then 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 will speak to the second question. We are always open to constructive discussions with parties. On the other hand, we can’t discuss the settlement discussions specifically, but we are always open to talking to parties.
And 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 the call.
Fair enough. I know it’s a little tricky. Now, just the last – sorry…
I am going to add one thing, I know that for some parties, including us the ability to – this is a generic comment, but the ability to settle the 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 the last quick question, can you confirm the $5 million to $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 ‘19 and onwards if indeed adopted?
Well, I’d argue, it’s an annual impact until you get a rate case resolved right. So, you could argue annual impact for ‘18 and a portion of ‘19 could be an impact as well. Now, again if the historic method of course on a going forward basis, they will capture our new tax structure, but we will also capture all the increases in costs elsewhere which would have been an appropriate way to handle this issue to begin with.
So your expectation is basically by the time that you get new rates, insert whatever date that, that maybe this should effectively rollout?
Correct.
Okay, excellent. Alright, excellent. Well, thank you.
Thanks, Julien.
Our next question comes from Paul Ridzon with KeyBanc.
Good afternoon.
Hey, Paul.
Can you just quickly review the calendar on the PCCAM and tax dockets?
Sure. Let us pull that up quickly. On PCCAM, our briefing is ongoing due on August 31. So, we don’t expect a decision until September at the earliest and obviously the commission leaves time to schedule work sessions and then ultimately decide but the window we opened essentially in September, in turning the Tax Cut and Jobs Act implementation in Montana, opening testimony has been filed for rebuttal and cross intervener testimonies, rebuttal testimony is due August 2 and the hearing will be held on August 31 with deliberations sometime after that. In Nebraska, the 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 Nebraska Public Service Commission for review. So, at this point we are waiting for from the Nebraska Commission. In South Dakota, we are in the active settlement discussions with the Commission staff and those are positive to-date. At FERC, there is 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. They of course have many within 180 days, which would move you into September or November.
Any commentary on any legislative intervention on the PCCAM issue and has legislators become involved in this with the Commission?
The interim legislative committee certainly has an oversight function and is aware of the docket in developments in the docket, but 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 as when you think the tax reform treatment in Montana would be decided?
Yes. In Montana specifically, there will be a hearing starting on August 30. And subsequent to the hearing, there will be presumably some kind of a briefing schedule and then that would push the decision potentially to later in the year.
Okay. So other than before year end, no real specifics at this juncture?
I would be hard pressed to say anything beyond that.
Okay. Did the perimeters of the potential kind of historic test period method kind of get tweaked on the Q1 call you gave you some bit higher numbers like an $8 million to $12 million range as opposed to the 5 to 10 cited today?
Yes, Brian, go ahead.
I’d say they did change slightly. I mean, obviously, we are through the midpoint of the year and we looked at adjusted numbers a bit and the expectation that, hat could change, but also taking consideration of the total you will notice that we increased the range for the current year method, but also decreased the range from the historical methods and one would argue there is differentials decreased a bit.
Okay, got it. And then 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 are approaching the rate filing and what you plan to request?
Yes. 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 that we have had tremendous success with stakeholder groups certainly over the last 10 years, that I have been with Northwestern. We take them seriously. We find the input valuable. In this case, we got a very diverse group, an expert external facilitator. The rate filing will be a backdrop to discussions in the customer vision group, but really what we are 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 are 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. So, 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 the Illinois is going to be speaking to the group. Last month, we heard about a very broad sustained effort in Minnesota. We are also going to be looking this fall at some interesting things that Green Mountain has been doing when Mary Powell, the CEO of Green Mountain comes up. So, we are 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 for example the New York REV or whatever is happening in California would be.
Okay. So it’s a very I guess kind of big picture kind of focus, stakeholder throughput, near-term I guess it would influence your rate design aspects of the case?
As originally conceived, it was going to be an input, but again how we will be filing a complete rate case at the end of September, so that will – that filing will be based on our views not on – not really on input from the group, because that discussion really is still in the, not entirely, but primarily in the information of sharing stage.
Okay. Well, I appreciate in taking the time to answer my questions and good luck as you present to the important stuff with the Commission coming up.
Thanks Jon.
Thanks Jonathan.
Our next question comes from Andrew Levi [ph] 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, so just where do we fall as far as your guidance range right now, do you guys think are you really in the middle, the low end, high end based on what you have seen thus far – again excluding any regulatory changes?
Andy, we have 3.35 to 3.50.
Okay. So you are kind of trending towards a little the middle, is that what we are seeing?
We are reaffirming our 3.35 to 3.50.
And the second one I guess is more for Bob, where do you guys fall as far as your view on M&A and I know we have discussed this before Bob, but in the context of NWE, whatever you would like to say and obviously the context of continuing consolidation within the industry?
Really, at this point no comment. We have offered our philosophical views previously and I really don’t have any guide to that.
Based on how much you say?
We have a quiet bunch here in Aberdeen.
Okay, great. You guys have a good weekend.
Thanks Andy.
[Operator Instructions] We will go to Paul Patterson with Glenrock Associates.
Great, good afternoon.
Hi Paul.
One of my question has been answered, but just quickly on the $70.5 million that benefited 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?
Yes. We have non-cash interest associated with that liability that as a result of reduction of liability we will see an improvement in non-cash interest of about $1.3 million each year. But we are that’s the periodic liability adjustment and so you can have adjustments and I have mentioned the last time we made an adjustment was in 2015 for that. So there is exposure probably back ‘15 that was a loss that we recorded that year. So there is going to be potential impacts on earnings, but that contractor that provides that particular exposure goes through 2024, so that’s the period of time that we could have exposure to that contradict in terms of some volatility to earnings. And in addition to that contract as we talk about the other components of the QF liabilities each and every year, there is an issue in terms of what’s actual production from these units and what’s actual pricing, so those impacts come into play as well.
Okay. So there might be a – if I understood you correctly there might be a benefit going forward, but the fact that this thing is always being adjusted etcetera, means that there is not a lot of predictability to us?
Excellent, great.
Okay. And then the comments that you made with respect to equity issuance not needed in the absence of a negative regulatory outcome is that sort of a generic statement or I mean is there just to sort of put a finer point on it, should we think about this in relation to the PCCAM or with respect to the upcoming rate filing or could you just elaborate a little bit more on that, I mean or is it just sort of – you are just sort of highlighting that because of the regulatory environment that you are in? Do you follow what I am saying?
Yes. I am comfortable with your question. First of all, I mean, to speak about the rate case, it has nothing to do with the rate case whatsoever, matter of fact, we are looking forward to the rate case. There is tremendous amount of investment we have made in the company and we think we have done customers the right thing to try to stay on our rate cases for years, but it’s time to get recovery on that investment. So, we look forward to the rate case. We just see tremendous amount of exposure on tax reform and PCCAM and don’t know what those outcomes. And as my earlier question, it’s difficult to gauge what those outcomes would be. We are not sure where PCCAM ultimately will end up. It’s easier to kind of understand the differential on tax reform. We just want to be clear that there is a potential that we could have to do something from a active perspective, but I also tell you there is 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.
And we have a follow-up from Michael.
Hi, hey. One quick follow-up on the guidance, so the $17.5 million benefit from the QFs, that’s excluded and not benefiting, but the $7.6 million benefit from the outages, related to the outages, that’s the ongoing adjustment that is actually in the guidance and it was about a $5 million improvement over last year. Is that a fair read through?
Yes. But Mike, let me just straighten you out a little bit though you are directionally correct, since the $7.6 million, 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 and so we had a small amount, I am not going to give you the actual amount of that impact built into our margin guidance associated with the fact that we are aware of outages at the end of the year. It wasn’t certainly anything near the $7.6 million number.
That’s right. So I mean, if you were assuming the same thing last year, you are about a little over $5 million more, this year, it was almost like $0.07 a share. Is there any reason why we didn’t move up the guidance range at all of the matter or is it being conservative what’s your thinking on that?
My thinking as we have reaffirmed our guidance at $3.35, Michael.
Okay, thank you.
There is quite a bit of the year left to from our perspective.
Alright. Thank you very much. Have a good weekend.
Thank you.
Thank you. And it looks like we have a follow-up from Andrew Levi as well.
Okay, let’s try this one more time. So, if you have normal weather and normal conditions between now and the end of the year, do 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 are trying again, Andy and my answer is the same. We are reaffirming our $3.35 to $3.50.
Andy, what I wanted to tell you is, thank you for the follow-up questions. This is great practice for when Brian is on stand in a month or so in the tax docket.
Alright. We needed someone else to testify it for you, I will help too. 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 summarized some we think key characteristics of the company. We have talked about these best corporate governance practices, I spent a minute at the top of the call talking about corrections of our board. In fact, we are a pure electric and gas utility freight foundations. We paid attention to those basics. We do have strong earnings and cash flow and we talked about attractive, I would say maybe more actionable future growth prospects. So, those were things to keep in mind. I did my fetch for the Aberdeen Chamber of Commerce at the top of the call and 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 and I think since you cover the company, we owe it to yourselves to come out and we will take you on a hike up there and if it’s in June, our Supply Vice President, John Hines, will put you in a kayak and this is if I touched on this the hydro system obviously has been such a great asset for us and we have realized so many values out of the hydro system beyond the energy that was really priced into the transaction and this is very much part of that. So, 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.