Good day, and welcome to the Northwestern Corporation Third Quarter 2018 Financial Results Conference Call. 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, Ryan. Good afternoon, and thank you for joining Northwestern Corporation's financial results conference call and webcast for the quarter ending September 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 premarket this morning. The call with us today are Bob Rowe, President and Chief Executive Officer Brian Bird, Vice President and Chief Financial Officer.
We also have several other members of the management team in the room with us today to address your questions if needed. Before I turn the call over for us to begin, please note that this company 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 contains words such as expects, anticipates, intends, plans, believes, seeks or will.
The information in this presentation is based upon our current expectations. Our actual future business and financial performance may differ materially and adversely from our expectations expressed in any forward looking statements. We undertake no obligation to revise or publicly update our forward looking statements or this presentation for any reason. Although our expectations and beliefs are based on reasonable assumptions, actual results may differ materially. The factors that may affect our results are listed in certain of our press releases and disclosed in the company's Form 10 ks and 10 Q along with other public filings with the SEC.
Following the presentation, we will open the phone lines to allow those that are dialed into the conference to ask questions. The archived replay of today's webcast will be available today at 6 p. M. Eastern Time and can be found on our website, again, northwesternenergy.com, under the Our Company Investor Relations Presentations and Webcast link. To access an audio replay of the call, dial 888-203-1112, then access code 333,9321.
With that, I'll hand the presentation over to our CEO, Bob Rowe.
Thank you very much, and good afternoon, and thank you all for joining us. We're dialing in today from Great Falls, Montana. Just to give you a feel for this part of our service territory, Great Falls sits on the Missouri River as it heads north out of the mountains onto the plains. And it's the operating center for our North Central division in Montana. It's a huge piece of real estate.
In addition to electric and gas distribution, we have the head end of our gas gathering storage and transmission system north of here at Cut Bank. 1 of our board members was with us last week, really touring a lot of the state and got up to Cut Bank and out to a new compressor station on our transmission gas transmission system that is within eyesight of Glacier Park. And then of course here in the city of Great Falls, we have 5 of the hydroelectric dams as well. Earlier this week, the Board had a great meeting and discussion with community leaders and we did that at the History Museum. That room was jam packed with leaders of the Great Falls community from the mayor, legislators on.
Both of the Public Service Commission candidates were present and it's a great opportunity to have good discussions there as well. And the conversation was really about our partnership with the community, our investments in the community and our role of providing essential infrastructure for Montana. This morning, the Board had a breakfast meeting and discussion with all of our Great Falls area employees, both in the division, electric and gas distribution operations and also all of the hydro team from this part of Montana. Great discussion and the neatest comments were made by one of our veteran linemen who stood up at the very end of the breakfast after all the board members had spoken and just said how much he appreciated really being part of a team that was committed to safety, committed to doing the right thing and how much you value the Board members being there. That was that really summed up how the whole week has been here in Great Falls.
So with that, turning to Q3 highlights, net income for the quarter decreased $8,200,000 or 22.6% when compared to the same period in 2017. And the decrease was primarily due to unfavorable weather, reduced recovery of energy supply costs in Montana and increased operating expenses. And these increases were partially offset by lower interest and income tax expense. Diluted EPS decreased $0.19 or about 25.3% as compared to the same period last year and adjusted non GAAP EPS decreased $0.16 or 21.6% as compared to the same period in 2017. As you know, we filed a much anticipated long awaited electric general rate review with the Montana Public Service Commission in September and we're requesting a $34,900,000 or 6.6 percent increase to base revenues.
The Board of Directors declared a quarterly dividend of $0.55 per share payable on December 31 to shareholders of record as of December 14, 2018. And with that, I will turn it over to Brian Byrd. I would ask everyone to go easy on Brian. He's getting over a nasty cold.
Thanks, Bob. On Page 4, the summary financials, Bob gave you the net income totals 8,200,000 dollars worse than the prior year and $0.19 on a diluted earnings per share worse than the prior year. And in summary, we've had lower gross margin on a year over year basis. Obviously, that isn't helping us cover an increase in operating expenses. So operating income is down.
Though we had better other income and interest expense and income taxes, it wasn't enough to ultimately show again with net income down $8,200,000 or 22.6 percent for the quarter. Moving on to Page 5, we talk about the individual components of the P and L. From a gross margin perspective, total gross margin was $207,700,000 down $4,700,000 or 2.2 percent. For the quarter, As you can see, that's all shown up in the electric side of the business and I'll talk about weather impact in a moment. But as you look down in the decrease in gross margin due to the following factors, those that have a change in gross margin impacting net income of $3,900,000 there were really 3.
Our electric retail volumes were down $3,200,000 We did have a net adjustment on the PCAM of $1,800,000 and those were partially offset by an improvement on electric transmission on a year over year basis in the 3rd quarter. Below that, we did see some decreases in margins due to our Tax Cuts and Jobs Act deferral and some production tax credit flow through, but those were primarily offset by recoveries in trackers, particularly in property taxes and other operating expenses. So for a net decrease in gross margin of total of $4,700,000 Moving on to Page 6, I mentioned weather in the 3rd quarter is an interesting quarter. It's the only place you're really going to see heating degree days and cooling degrees in the same spot. In Montana, we only have 5% of our heating degree days show up for the year within the Q3, but 95% of our cooling degree days.
Unfortunately, in Montana, it was quite a bit colder, in the Q3 versus normal and versus the historic average, which slightly helped our gas business, but certainly ended up hurting our electric business. And matter of fact, we estimate the unfavorable weather in Q3 resulted in a $1,100,000 pre tax detriment as compared to normal and $1,500,000 pre tax detriment as compared to Q3 2017. South Dakota and Nebraska tried to help out a little bit, but again because of the sheer size of our Montana, our overall business couldn't help offset the negative detriment from Montana during the quarter. Moving on to Page 7 from operating expenses perspective. Total operating expenses were $159,900,000 up $11,600,000 or 7.8 percent showed pretty sizable increases in operating general property taxes and depreciation and depletion.
One thing I'd say about operating general administrative expenses, it says it's up 9%. When you look at those changes in OG and A that actually impact net income, it's really only up $1,200,000 or approximately 2%. So we continue to manage our costs as best we can. Talking about those costs, we did see decline in several cost categories, but we did have a net increase. I primarily attribute that to our line clearance costs.
We are starting to tackle hazard trees outside of our right of way and obviously that's an increase on a year over year basis as we start that program here in 2018. For those expenses that have a change in OG and A, but are offset elsewhere in the P and L, pension and other post retirement benefits and non employee directors deferred comp, those expenses are up, but those are offset by an increase in other income. We also had some other operating expenses recovered in trackers. But net net, the total increase in operating, general and administrative expenses again $6,100,000 Property taxes up primarily due to planned additions and higher estimated property valuations up $3,400,000 and obviously depreciation depletion up due to planned additions 2,100,000 dollars Moving on to operating net income. Operating income, dollars 16,300,000 worse or down 25% on a year over year basis.
Below that interest expense, slightly favorable, primarily due to the refinancing that we did in 2017, partly offset by rising interest rates and its impact on our short term borrowings. Other income shows up $3,800,000 but as I noted before, pension and non employee director deferred comp offsets a portion of that. Those improvements were partially offset by lower capitalization of our AFUDC. Income before taxes down 11.4%, nearly 29% just over 29% and below that income tax benefit $3,200,000 on a year over year basis, primarily due to lower pretax income and obviously the lower 21% federal corporate tax rate. Moving on to the tax rates on Page 9, you see at the very bottom there income tax improvement of $3,200,000 on a year over year basis.
The 2 favorable adjustments, if you will, during the quarter is obviously, as I mentioned, the lower pretax and the lower tax rate, the primary driver there was $7,900,000 favorable benefit. But we did also have a prior year permanent return accrual during this quarter that was a $2,200,000 favorable variance on a year over year basis. Those were both slightly offset by less state income benefit, lower flow through repairs tax benefit than we had from the prior year. Again, net net, dollars 3,200,000 better taxes on a year over year basis. Moving on to the balance sheet on Page 10, all I'd quickly say is total debt to capitalization at the bottom of the page improved since the end of the year.
Some of that's seasonal, but some of it's also a function of our shareholders' equity being up 100,000,000 dollars obviously earnings, but we also raised equity during the first half of the year and we used that to pay down $100,000,000 of debt and thus improved that ratio as a whole. Moving on to Page 11 from a cash flow perspective, I'll say the primary drivers of improvement in cash flow, we had $43,000,000 improvement in cash flow, but we also raised $40,000,000 of equity. Those funds helped pay down debt about $67,000,000 and also helped us acquire 2 Dot Wind for approximately 18,000,000 dollars during the quarter. Moving into our quarterly adjusted non GAAP earnings on Page 12. I'll note at the very top of the page and those items that we reverse out on a non GAAP basis, it was a pretty simple quarter from that perspective.
This quarter, we backed out unfavorable weather and as compared to the prior year's favorable weather, a $1,500,000 swing, as I mentioned earlier. With those changes at the bottom of the page, you see near the middle of the page, the comparison diluted EPS $0.58 versus $0.74 from the prior year. So a disappointing quarter, no doubt, as you kind of go from the top of the P and L in the middle of the page, gross margins down about $3,200,000 We mentioned PCCAM is one of those things $1,800,000 We did also have a wetter quarter that impacted irrigation load that we typically see, a little lower commercial volumes as well. And obviously, I talked about deferrals net of trackers having some impact on gross margin as well. From an OG and A perspective, you can see again they're approximately 2% when you back out some of those items, they're offset elsewhere in the P and L.
So again, keeping an eye on OG and A, continue to do a good job on that. Matter of fact, on a year to date basis, we're actually still behind. We're spending less from an OG and A perspective on a year to date basis, but for this quarter still up about 2%, Property tax depreciation again up as a result of our investment and total operating expenses up just over 7,000,000 dollars getting us to an operating income being down on a year over year basis about $10,000,000 or 17%. That flows down to pre tax income of approximately the same amount. We did see some improvement in income taxes as we discussed earlier, net net getting us to net income of down $7,200,000 approximately 20 percent on a year over year basis.
We did as a result of the additional shares, again, showed some incremental dilution, getting us to the net detriment of $0.16 on a quarter over quarter basis. Moving on to Page 13, we did reaffirm guidance, dollars 3.35 to $3.50 for the quarter as we talk about those adjustments or those things that we consider are major assumptions, obviously normal weather for the Q4, also expecting equitable treatment on the Tax Cuts and Jobs Act decision in Montana. And lastly, I'd point out here, we did not make any adjustment from a non GAAP basis for PCAM as we look at that as an ongoing part of our business going forward. So we did not exclude any of the PCAM adjustment for the quarter from a non GAAP perspective. Moving on to Page 14, in essence to get to our earnings guidance, let me start with just our 9 months actual where we sit.
We had a reported GAAP on a year to date basis of $2.61 backing out for the again on a year to date basis favorable weather of $0.03 backing out a portion of the gain of the QF liability of $0.26 gets us to $2.32 That's slightly behind the adjusted non GAAP number from the prior year. More importantly, for this year, we would need to get to $1.03 to $1.18 in order to hit our $3.35 to $3.50 Seeing that last year's 4th quarter amount was $0.95 a good question would be how do you expect to get to $103,000,000 to $118,000,000 if you only had $0.95 last year. I think as we look at the Q4, the two things we expect to help us get within that guidance range is higher margin, expect to see similar lift in margin as we've seen in the Q1 and lower OANG on a year over year basis in the Q4 helping us to get to that level. Having said that and anticipating your questions in the Q and A, I do expect that there's a higher probability that we would be in the lower half of that 335 to 350, but certainly see an opportunity to be within the full range.
With that, I'll give it back to Bob.
Thank you, Brian. Starting on the regulatory side matters you've all been following. First, we're focused on the final treatment of tax reform and determining the best way to provide the long term benefit to our customers and system while ensuring that you, our investors are kept whole. 2nd, the Montana Commission has voted on a new power cost and credit adjustment mechanism, but has not yet issued a final order. So, our view of that is really informed by the commission's discussion and particularly the staff memo.
And then 3rd, we did file a much anticipated general rate review, electric rate review in Montana in September. We'll come back and talk about those. 2nd area, the capital, 5 year capital forecast, we'll discuss really is a transmission and distribution overall infrastructure plan, building on the success of our D SIP and moving to an end to end approach. And we've got substantial capital commitments to electric gas, Nebraska, South Dakota and Montana distribution and transmission. On the gas transmission side, a lot of emphasis on integrity verification process and the FMS requirements.
And then grid modernization is a real focus on the electric side, including deployment of advanced distribution management system, ADMS, this year and our 1st meter scheduled in the coming months as part of an AMI deployment first in South Dakota, Nebraska and ultimately then in Montana as well. 2 major areas of focus in the supply area, electric supply in this case, the South Dakota electric plan was published in September and implementation is very much in process right now. In Montana, the focus is at least cost, lowest risk approach, really addressing intermittent capacity and reserve margin needs. We expect that to be released in the middle of December. We've taken an unusual approach and we have or by the end of the process will hold 3 public meetings taking public input on the plan as well as incorporating the active input of a technical advisory committee.
We continue to monitor and I think do a very good job controlling all of our controllable costs, labor benefits, property taxes continues to be a challenge for us in Montana, the ad valorem tax. I'm just giving a little more detail on some of the regulatory matters. We'll take a short walk back memory lane. In May 2017, the Montana Commission initiated a docket to implement House Bill 193, and that had removed the statutory language that mandated an electric supply cost tracker and replaced that with language to give the commission discretion concerning an electric tracker. In July of 2017, we filed a proposal for the what became the PCAM that incorporated a sharing ratio of 90.10 between customers and shareholders for supply expenses above and below an established baseline.
The commission held a work session and voted to approve a PKM, in some ways similar to our initial proposal. And again, we haven't actually seen the final order yet. But the commission's action does establish a base amount for supply costs consistent with our proposal. There is a sharing mechanism that includes a plus or minus $4,100,000 deadbound around the bases with the differences beyond that deadband shared 90% customers and 10% shareholders. And then also retroactive implementation to the effective date of HB 193, which was July 1, 2017.
We do expect the final order to be issued in the Q4 and we have recorded a $1,800,000 net reduction in revenue to be recovered from customers. And this includes an approximately $3,300,000 increase in revenue for what would have been the PKAN period for 2017 2018 that would be offset then by an approximately $5,100,000 reduction in the revenues for the 1st 3 months of the 2018 2019 peak AMP period and the electric tracker is essentially on a July through June year. Next, as you know, in May of 2016, the Montana Commission issued an order disallowing recovery of certain costs associated with an outage at Colstrip. In September of 2016, we appealed that commission order to Montana District Court arguing the decision was arbitrary and capricious. In July of 2018, the District Court issued a decision upholding the Commission's order disallowing recovery of replacement power costs and we have decided not to appeal the District Court decision to the Supreme Court.
Next major area implementation of the Tax Cuts and Jobs Act in South Dakota. In September, the PUC approved a settlement agreement resulting in a one time refund to both electric and natural gas customers of $3,000,000 by October 31, 2018. This occurs as a bill credit. And this does also include a 2 year rate moratorium ensuring that customers' rates remain stable until January 1, 2021. In Nebraska, in August, the Nebraska PSC approved a settlement between us and the cities of Grand Island Kearny in North Platte, reflecting our Nebraska service territory to evaluate the impact of the TCJA on an annual basis.
And this is consistent with our proposal to use any calculated customer benefit to defer planned future rate filings. Therefore, it would have no impact on our financial statements. In Montana, in March, we submitted a filing to the MPSC calculating the estimated benefit of the TCJA related savings to customers using 2 alternate methods. First, the current method was calculated based on the expected tax expense reduction in 2018, but with no impact to net income. On the other hand, the historic method was calculated by revising the revenue requirements in the last applicable test years.
For our electric customers, we proposed to use 50% of the benefit as a direct refund to customers and to use the other 50% to remove trees outside of our electric transmission and distribution lines right away rights away. And these pose a threat, those risks to our system, including disruption of service, property damage, and or forest fires. We have had a very active vegetation management program for years and it was an important element of our DCIP program that was focused on trees within the right of way. Given the pine bark beetle in Montana and other concerns, we've substantially increased our focus to include hazard trees outside of the right of way. And in fact, we have begun significant work on that.
I think we're actually really ahead of many other companies in addressing this concern. So in fact, as of September 30, we've deferred $700,000 for free removal and have deferred $13,300,000 of revenue, again associated with the tax law changes. The NTSC held a hearing in August and we expect the decision in this matter also by the end of the year. The expected full year 2018 total company revenue reduction for the current method is $18,000,000 to $23,000,000 that would be 3,000,000 dollars for South Dakota, plus $15,000,000 to $20,000,000 for the Montana current year method. And that would be offset by a nearly equal reduction in income tax expense and therefore would have no impact in net income.
On the other hand, application of the historic method in Montana would result in customer refunds that exceed the expected benefit of the TCJA and would therefore result in an additional reduction in pretax earnings and cash flow of approximately $5,000,000 to $10,000,000 So as a result of tax reform, we've updated our 2018 effective tax rate assumption to between 0% 5% and that compares to 8% to 12% prior to TCJA. And we reduced our deferred tax liability by $321,000,000 as of December 31 last year. Then this reduction was offset in regulatory assets and liabilities. NOLs are now anticipated to be fully used in 2020 and previously that 2021. So we currently, and this is an important note, believe our debt coverage ratios are adequate to maintain our existing credit ratings.
However, further negative regulatory actions could lead to credit downgrades and couldn't necessitate additional equity issuances. Turning to a couple of other key matters. I mentioned that the South Dakota Electric Supply Resource Plan has been filed. We've actually started some exciting implementation activities under that plan. And recall that in South Dakota, we are relatively new participants in the Southwest Power Pool, and that creates some great opportunities for our customers and for the company.
Northwestern and HDR Engineering under the plan investigated various retirement and replacement scenarios for our South Dakota fleet to assess potential for modernizing our generation fleet and improving reliability and operational flexibility. And you see on the slide a set of 7 scenarios. Scenario number 5 really checks all the boxes quite literally as the best solution to meet the Southwest Power Pool's 12% planning reserve margin and benefit the system overall. And that would include through improved reliability, lower losses, improved restoration, increased natural gas supply diversity, adding localized ancillary services and then stage using a staged approach to incorporate new technologies into the system and adjusting to change load centers and also moderating customer rate impacts and would also have the effect of broadening tax base with multiple economic development opportunities across several communities. And this is over a period of years, I think an exciting opportunity for us and for our customers.
Initially, the focus will be on a series of mobile units actually combining generation and mobile substation capability. So as you can see that creates an opportunity to address local needs in terms of both supply and reliability. Turning to the Montana electric rate review. We last filed a general electric case in Montana in 2,009. The company has changed substantially since then.
We've either done a very good job efficiently managing all of our expenses, even with the challenges of the Montana property tax, but we have made significant investments in transmission and distribution over that time as well as the supply investments that have been reflected in typically asset specific filings. We filed in Montana in September based on a 2017 test year and a $2,340,000,000 rate base. We're requesting a $34,900,000 annual increase in electric rates and this reflects a 6.6% overall increase to Montana Electric Revenues and then through the cost allocation analysis, a 7.4% increase in typical residential bills. We've requested a 10.65 percent return on equity, 4.6% cost of debt, 49.4 percent equity and then a 7.42 percent overall return on our rate base. We've also requested a $13,800,000 interim increase effective on November 1.
Additional notable items in the filing, 1st to approve capitalizing demand side management costs. This is something that Montana did in the 1990s when Montana Power, our predecessor, served the state, would establish a new baseline for, the power cost credit adjustment mechanism, would include 2 Dot Win in rate base and then would approve a new net metering customer class and rates for new residential private generation customers under our proposal existing private generation customers would be grandfathered with their current treatment. So we expect a decision on interim rates by the end of the year. And if the MPSC does not issue an order within 9 months of our filing, New rates may be placed into effect on an interim and refundable basis. A procedural schedule has not yet been issued, but the commission staff has released a draft procedural schedule for comments.
Comments are due by November 1 and a hearing under the draft proposal will be contemplated in mid May. And then finally, turning to our capital investment forecast, you see 5 years of consistent and balanced investments, as I mentioned, across jurisdictions and across platforms really. This is think of this as a transmission and distribution capital plan. It does not include specific investments at this point for any issues identified under either the South Dakota plan that has been filed or the to be filed Montana plan. But this is a $1,600,000,000 estimated cumulative 5 year capital program that would be funded with a combination of cash aided by NOLs through 2020, as I mentioned, and then long term debt issuances.
Importantly, significant capital investments that are not in the above projections or on the other hand further negative regulatory actions couldn't necessitate additional equity issuance. With that, we look forward to questions and discussion.
Thank Our first question will come from Julien Dumoulin Smith with Bank of America. [SPEAKER JULIEN DUMOULIN SMITH:]
Hey, good afternoon. Can you hear me? Hey Julien. Hey, howdy. So let's first, if I can focus on the generation projections now with the $255,000,000 in CapEx.
Can you reconcile just one, just the dollar per kilowatt involved here? Just I imagine the distributed nature of the investment is why the relatively high metric, but I'd be curious on that. And then separately, I'd also be curious to understand, you talked about the South Dakota capacity requirements in the top left of that slide. And I'm again, I'm not sure if I'm interpreting the slide right. So that's where I'm looking for the clarity is.
How much are you short relative to the 90 megawatts that you all are looking to build? And maybe that gets out a little bit of the question of timing of when exactly you're looking to put the 90 megawatts in?
John, go ahead. John Heinz, Service Supply Vice President.
We have two issues here that are embedded in there. One is the growing capacity need. That need is relatively small, but also the retirement piece that we've talked about through the HDR study, that's fairly significant. And that's a reliability issue and an ability to execute in the SPP market when called upon and there's significant opportunity there for us.
Sorry, maybe let me try to make sure I heard you right. Is that projected delta, the short capacity as you have the arrow in the chart there? Is that basically trying to say that that's excluding the retirements and there's a further chunk of need that's coming from retirements that's incremental to that?
That is correct.
And what's the timing on that retirement relative to the need there? Just to make sure and maybe this is a backhanded way to ask, what's the cadence of installing that 90 megawatts as you think about it today?
We're taking an approach that we're looking at opportunities to replace that and that means we're going to have to test the market as well as our own, but we expect over the next 5 years to be implementing around 60 megawatts or so of at least 60 megawatts of additional capacity.
Got it. So would you say 60% of the 255 over the next 5 years, is that again, it's not quite there, but that's effectively what you're saying?
I'm not saying that as far as the dollar amount. I'm just saying that's about how much megawatts we're expecting to need.
Got it. Okay. All right. Fair enough. And then if we sorry, go for it.
South Dakota, the mobile generation investment is underway. We actually had a really good discussion with our technical folks and the Board this morning and that's something that has been very well received in South Dakota. Then beyond that, under the South Dakota plan, we do need to test the market, consult with the commission and ultimately do the right thing for our customers. But we've identified a customer need for the reasons that John has described over the next, say, 5 years, it really is significant.
I think I'd add this is Brian. What I would add here is we're going to speak to our capital plans at the February meeting. And I think at that point in time, we'll be able to speak to more when this investment would be in each of the coming years. The thing I would say is the slide that Bob walked through on the capital slide itself, my expectation is you know that starting in 2019 years past, it's a kind of a declining slope for that line. Our hope is as we start layering in generation, we start to see that being upward sloping starting in 2020 beyond.
Got it. And also if I can reconcile this, I know we're focused on South Dakota here, but how do you think about Montana in the same resource planning context today, given the existing regulatory situation as well as projected need?
As you know, under the 2015 plan, we were successful in some of our actions, particularly optimizing the fleet, but driven by the commission's symmetry discussion at that point, we had to back off of the RFP that requested essentially 20 year proposals. The need that was identified is still very much there. In the plan to be filed this year, the focus will be on, again, long term lease cost capacity. We do expect we'll be going out with RFPs to identify any range of resources to meet that need. And as I think everyone on the call is aware, we are unique in the West and having a negative reserve.
That's something that we simply have to address. And to some extent, we're resource agnostic. One of the things that's particularly exciting and again we spent some time on this subject, at this board meeting is the opportunity to add incremental generation to pretty much the entire Montana hydro fleet, at less than $10 a megawatt hour. And that's very compelling. And of course the hydro system has a great capacity factor and availability.
So that's something that is ongoing. And again, John, anything you'd want to add to that?
Just the hydro system continues to provide not just energy, which is well how the transaction was originally priced, but capacity values and we're also allowing ancillary services to be executed through the hydro system. So providing additional benefit and we're looking at providing incremental upgrades at numerous dams at this point in time. And as Bob noted, they're extremely cost effective.
Got it. Thank you very much. Just two quick logistical or administrative questions, if you will. 2019 guidance, would you expect to issue that with 4Q given the rate case? And then secondly, just to clarify on any incremental CapEx here that you're thinking about, whether it's South Dakota or Montana, that presumably at this point you would equity finance a portion of that?
Yes. Let's go to the first one. The first one expectation is we typically given drivers at EEI in light of the rate case itself and some other things, uncertainties as we go into the end of the year in terms of TCJA and how that impacts us going into 2019. I don't expect to see any drivers at EEI. In terms of guidance for 2019 as a whole, obviously, with the rate case and hopefully, obviously, some recovery of costs from that rate case for a portion of 2019, We'll evaluate whether we'll provide guidance at all in February at that time.
Excellent.
And then can we ask your second question again Julian? I'm sorry.
Yes. I just was curious. I mean, to a certain extent, I imagine this is self evident, but the incremental CapEx given where you are on the balance sheet at this point for the South Dakota generation, would you expect some portion of that equity financed?
I'll be prepared to talk about that when we layer in the timing of this CapEx in February.
Excellent. Thank you. Thanks, Julien.
Thank you. We'll take our next question from Michael Weinstein with Credit Suisse.
Hi, guys. Hey, Michael. Hey.
So on the Colstrip outage, the $5,100,000 impact on the PCAM for the 20 eighteen-twenty 19 time frame, is that most is most of that driven by the coal strip outage or is that something else?
I would say that it's certainly a combination. The coal strip outage certainly contributed to that, but we experienced in the 3rd quarter as many people did very high prices during the Q3. And regardless of the close to aboutage or not, we would have been procuring power because of not owning a significant share of our own fleet. We have to go procure power in the marketplace and when power prices are up, we have to procure those. It's a risk we have with our PKAN today.
And the PKAN does cover it would cover purchases for an outage of Colstrip. There's nothing exclusive in there that would exclude it in some way, right?
That's correct.
Okay. Can you quantify the impact of the coal strip outage in isolation from everything else? Is that something that's been provided?
Yes. Okay. That's Michael.
Got you. And the $2,300,000 increase in O and M on Slide 7, I know you said most of the impact of higher O and M was from the line?
Yes. There are some different lines there too. And then there's also quite a few smaller things in the all other category, but as things shifted out, the thing that stood out was the line clearance. Okay.
That's a 2.3 is a large number.
Agreed. And I would tell you on a year to date basis, we continue to look good on an OA and G perspective and continue when we show year end numbers, we'll look good on a year over year basis as time. Got
it. And also I appreciate you anticipating our questions on the 2018 guidance reiteration.
I was listening on the last call, Michael.
Why do you expect higher margins in Q4? And also what categories of cost cutting are you thinking of to get into that range?
I think I'll start with your second question first. As an executive team, all of us are responsible for various budgets and we're all focused on doing the best we can to manage our budgets. And so I'm not going to stick on any particular area there. Back to your first question from a margin perspective, we see in terms of customer growth and other aspects, we'd see more closer to kind of a 1.5% margin growth we saw in the Q4 excuse me, in the Q1 repeating itself in quarter.
Okay, great. And is there any one last question. The effective tax rate for this year is like 0% to 5%. Is there any kind of number you can give for next year's effective tax rate? I mean, I know you're not going to provide guidance right now, but is that something you can talk about?
That's a good one for EEI. We got to tell you something at EEI. That's probably
a good thought, but
we'll save it, Michael. Okay. Thank you.
Making a note.
Thank you. We'll take our next question from Paul Ridzon with TD Securities.
Nicky, can you hear me?
Hey Paul, we can hear you.
Just a question with regards to reaffirming guidance. What are you assuming with regards to interim rates? And I assume that assumes you get reasonable and fair treatment on Montana taxes?
Yes. On the second point, Paul, as I made I thought I made it clear in my discussion in terms of guidance that assumes a favorable outcome on a as expected outcome on our current year method on TCJA in our guidance. So first and foremost, that's the first thing. Regarding interim rates, the two things, there's a possibility we don't get interim rates and then there's a possibility if we get interim rates, we wouldn't get them immediately in 2018. So our guidance does not at this time include any recovery of costs from interim rates.
Okay. Thank you very much. Those are my questions.
Thanks, Paul. Thank you. It looks like there are no questioners in the question queue. That is from Jonathan Reeder with Wells Fargo.
Hey, Brian. So just a quick clarity, was the $1,800,000 net impact in the BCAM that was recorded in Q3 then?
Yes. The full amount was recorded in Q3.
The full $1,800,000 net impact?
Correct.
Okay. And then in terms of the tax issue, thinking back to the hearings and everything, do you have any sense like which way the commission is leaning or is it really just
up in the air at this point?
Yes, it's hard to say. I think we thought we made a very strong case in terms of what's fair, giving all of the benefit to customers in terms of only the benefit that we received. We thought that was fair and even after having done that, obviously, it impacts our credit statistics. And I think that resonated with commissioners. I think certainly speaking to hazard trees also resonated with commissioners.
But obviously, I think the interveners had points that certainly they made as well to the commission and it's really hard to tell. And we're
in briefing at this point, so it is early to speculate.
Okay. And the exact timing, is it December that they're supposed to rule on it?
It? By the end of the year, there'll be change at the commission. So we'd certainly expect a decision by then.
Okay. And I'm assuming, Bob, you don't want to comment on the pending change at the commission?
I do not. As I mentioned, both of the candidates in this district, there are 2 seats that are contested. The 2 candidates to step into Commissioner Camilla's position We're both at the meeting. Our view is we want anyone who is running for the commission to be as informed as possible and to meet our employees, to understand our operations and to really understand the role that we play providing critical infrastructure and essential service including in communities like this. And I was pleased that both of the candidates took the time to come to the meeting and learn a little bit more.
Okay. And then any engagement with Johnson's Challenger at this juncture?
We really do very much the same thing there. Obviously, Chairman Johnson knows the company very well. We've been in for informational meetings as well as in the contested cases. And we've also met with the other candidate too. We want him to be fully informed as well.
Yes. Do you think, I mean, the Senate race in the state, is that going to highly influence the way that the commission, I guess, elections go? Or do they stand on their own historically in Montana?
I don't have much appreciation of how what are called the down ballot races go. I think like everywhere in the country, turnout will likely be high for midterm and lots of people are mailing in their ballots early. So certainly just an awful lot of interest and enthusiasm for the election just across the board. So I certainly think that would translate into relatively high turnout for a public service commission race.
And I
know all the candidates are out working hard and trying to communicate their positions.
Yes. Okay. Well, we'll watch and see
what happens November 6th and
we'll see you guys out at EEI.
Thanks, Jonathan. Thanks, Jonathan.
Thank you. Okay. It looks like there are no more questions at this time.
Just one final comment turning back to the P Chem subject. We and you have all focused on that for a very long time now. We were pleased to get the commission's vote and are working off of the staff recommendation essentially. So it's important for us to see the PSC's final order and understand that directly. But back to 1 or 2 of the earlier questions, you can think about the way electric supply decisions had been made in the Montana trackers previously, we felt we had real success resolving issues over a period of years.
So the trackers became much, much more focused and stable. And then that process reversed and more and more single items came up and there was a lot less predictability in that approach. That was essentially a prudence review. Logically, if you can go down a prudence review path or you can go down a formulaic path and here the commission has gone down a formulaic path. And I think consistent with the commission's representations to the legislature, once you've made that election, it doesn't seem logical.
I can't imagine it will be the commission's intent to preserve any kind of the prudence approach. So one or the other, the commission made decisions about allocation of risk and we'll again, we'll just have to see what the order says and go from there. But certainly it's positive that the commission has made a decision and now they and the staff are busy writing an order. With that, any other questions?
Looks like we have one final question, if you would like to take that.
Sure.
Our final question will come from Julien Dumoulin Smith with Bank of America.
Hey, there. It's Nick Campanella on. Just one quick follow-up. One quick follow-up. The South Dakota, the spend, the $255,000,000 is that going to require approvals or can you just walk through that process on the regulatory side?
Typically, South Dakota is very thorough, but they're also very efficient. So we've had active conversations with the South Dakota Commission as the plan was being developed and implemented, we certainly will be using procedures to test the market. We'll be consulting with the commission. We want to get their guidance. I don't anticipate going through something like a preapproval process, for example.
John?
I would just this is Brian. I would essentially say recovery here will be like we've had with other generation investments. When you think of what we did from pollution control perspective, we took care of those through a rate case process and as you pointed out, Bob, very efficiently.
Thanks so much.
Thanks, Nick. There are no more questions at this time.
Great. We'll look forward to seeing many of you at EEI in just a few weeks. And thanks for your interest in the good discussion.
Thank you, ladies and gentlemen. This concludes today's teleconference. Please disconnect your phones and have a wonderful day.