NorthWestern Corp

NASDAQ:NWE

Earnings Call Transcript 2018-Q3

[Operator]

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.

[Travis Meyer, Director, IR & Corporate Finance]

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.

On 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 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 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 IR company, Investor Relations, presentations and webcasts link. To access an audio replay of the call, dial 888-203-1112, then access code 3339321.

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

[Robert Rowe, President, CEO & Director]

Thank you very much. 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, so a huge piece of real estate. In addition, to electric and gas distribution, we have the head end of our gas transmission gathering, storage and transmission system north of here at Cut Bank. One of our board members was with us last week, really touring a lot of the states and got up to Cut Bank and to a new compressor station on our transmission, gas transmission system that is within eyesight of Glacier Park. And of course here, in the city of Great Falls, we have five 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 is jampacked with leaders of the Great Falls community, from the mayor, legislators, [indiscernible] both of the Public Service Commission candidates were present and it was 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 providing 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 board members had spoken and just said how much he appreciated really being part of the team. He was committed to safety, committed to doing the right thing and how much he valued the board members. That really summed up how the whole week has been here in Great Falls.

So with that, turning to third quarter highlights. Net income for the quarter decreased $8.2 million 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 $34.9 million or 6.6% 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 Bird. I would ask everyone to go easy on Brian. He's getting over a nasty cold.

[Brian Bird, VP & CFO]

Thanks, Bob. On Page 4, the summary of financials Bob gave you. The net income totals $8.2 million, worse than the prior year and $0.19 on a dilutive earnings per share, worse than the prior year. 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 in interest expense and income taxes, it wasn't enough to help them to show a gain with net income down $8.2 million or 22.6% for the quarter.

Moving on to Page 5, we talked about the individual components of the P&L. From a gross margin perspective, total gross margin was $207.7 million, down $4.7 million or 2.2% 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 $3.9 million are really 3: Our electric retail volumes were down $3.2 million, we did have a net adjustment on the PCCAM of $1.8 million and those were partially offset by an improvement in electric transmission on a year-over-year basis in the third quarter. Below that, we did see some decreases in margins due to our Tax Cuts and Jobs Acts deferral and some production tax credit flow through, but those were primarily offset by recoveries and trackers, particularly in property taxes and other operating expenses, so for a net decrease in gross margin of total $4.7 million.

Moving to Page 6. I mentioned, weather in the third quarter. It's 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 third quarter, but 95% of our cooling degree days. Unfortunately, in Montana, it was quite a bit colder in the third quarter versus normal and versus the historic average, which slightly helped our gas business, but certainly ended up hurting our electric business. And a matter of fact, we estimate the unfavorable weather in Q3 resulted in a $1.1 million pretax detriment as compared to normal and $1.5 million pretax 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 for our overall business, it couldn't help offset the negative detriment for Montana during the quarter.

Moving on to Page 7, from operating expenses perspective. Total operating expenses were $159.9 million, up $11.6 million or 7.8%, showed a pretty sizable increases in operating, general, property taxes, and depreciation and depletion. One thing I'd say about operating, general administrative expenses, it sets us up 9%. When you look at those changes in OG&A that actually impact net income, it's really only up $1.2 million 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, obvious, 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&A but are offset elsewhere in the P&L, pension and other postretirement benefits and nonemployee directors deferred comp, those expenses are up, but those were 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 expense is again $6.1 million.

Property taxes, up primarily due to plant additions and higher estimated property valuations up $3.4 million and, obviously, depreciation and depletion up due to plant additions, $2.1 million.

Moving on to operating net income. Operating net income, $16.3 million, worse or down 25% on a year-over-year basis. Below that, interest expense, slightly favorable primarily due to refinancing that we did in 2017, partly offset by rising interest rates and its impact on our short-term borrowings. Other income shows up $3.8 million, but as I noted before, pension and nonemployee 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 million or nearly -- just over 29%. And below that, income tax benefit, $3.2 million on a year-over-year basis primarily due to low 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 $3.2 million on a year-over-year basis to favorable adjustments, if you will during the quarter, obviously, as I mentioned, the lower pretax and the lower tax rate, and the primary driver there was $7.9 million favorable benefit. But we did also have a prior year permanent return accrual during this quarter that was a $2.2 million 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, $3.2 million that are taxes on a year-over-year basis.

Moving on to the balance sheet on Page 10. All I'll quickly say is total debt to capitalization at the bottom of the page improves since the end of the year. Some of that is seasonal, but some of it is also a function of our shareholders' equity being up $100 million, obviously, earnings. But we also raised equity during the first half of the year and we used that to pay down $100 million 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 are improving the cash flow. We had $43 million improvement in cash flow, but we also raised $40 million of equity. Those funds help to pay down debt of $67 million and also helped us acquire To Dot Win for approximately $18 million during the quarter.

Moving into our quarterly adjusted non-GAAP earnings on Page 12. I'll note at the very top of the page, those items that we reversed on a non-GAAP basis was pretty simple quarter from that perspective. This quarter, we backed out unfavorable weather as compared to the prior year's favorable weather, a $1.5 million swing, as I mentioned earlier, with those changes at the bottom of the page, you see, near the middle of the page, a comparison, diluted EPS, $0.58 versus $0.74 from the prior year. So at this point in the quarter, no doubt, as you kind of go up from the top of the P&L in the middle of the page, gross margins down about $3.2 million. We mentioned PCCAM is one of those things at $1.8 million. We did have a weather quarter that impacted irrigation mode that we typically see, a little lower, commercial volumes as well and, obviously, I talked about deferrals and net of trackers having some impact on gross margin as well.

From an OG&A perspective, you can see again the approximately 2% when you back out some of those items they offset elsewhere in the P&L. So again, keeping an eye in OG&A, we continue to do a good job on that on. A matter of fact, year-to-date basis, we're actually still behind. We're spending less from an OG&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 million, getting us to an operating income being down on a year-over-year basis about $10 million or 17%. That flows down to pretax income of approximately the same amount. We did see some improvement in income taxes, as we discussed earlier, net-net, getting us to a net income of down $7.2 million, approximately 20%. 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. $3.35 to $3.50 for the quarter. As we've talk about, those adjustments or those things that we consider are major assumptions. Obviously, normal weather for the fourth quarter. 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 PCCAM as we look at that as an ongoing part of our business, going forward, so did not exclude any of the PCCAM 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 nine months actual, where we sit and we had a reported GAAP on a year-to-date basis, at $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 on 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 fourth quarter amount was $0.95, a good question would be, how do you expect to get to $1.03 to $1.18 if you only had $0.95 last year. I think, as we look at the fourth quarter, 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 first quarter and lower OG&A on a year-over-year basis in the fourth quarter, helping us to get to that level.

Having said that, and anticipating your questions and the Q&A, I do expect that there's a higher probability that we would be in the lower half of that $3.35 to $3.50, but certainly see an opportunity to be within the full range.

With that, I'll give it back to Bob.

[Robert Rowe, President, CEO & Director]

Thank you, Brian. Starting on the regulatory side matter, as 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. Second, 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 third, we did file the much anticipated general rate review, electric rate review in Montana in September. We'll come back and talk about those.

Secondary, the five year capital forecast will discuss, really, as a transition and distribution, overall, infrastructure plan of building on the success of our DSIP and moving to an end-to-end approach and with that, 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 PHMSA requirements, and then the grid modernization is a real focus on the electric side, including deployment of advanced distribution management system, ADMS, this year and our first meter scheduled in the coming months as part of an AMI deployment first in South Dakota, Nebraska and, ultimately, then in Montana as well.

Two 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 on least cost, lowest risk approach, really addressing intermittent capacity and reserved margin needs. We expect that to be released in middle of December. We've taken an unusual approach in that we have, or by the end of the process, we'll hold three 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 we're doing 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. That's getting 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 '17, we filed a proposal for what became the PCCAM that incorporated the sharing ratio of 90-10 between customers and shareholders for supply expenses above and below an established baseline.

In September of 2018, the commission held a work session in order to approve a PCCAM, in some way, 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's a sharing mechanism that includes a plus or minus $4.1 million deadband around the basis. What the difference is beyond that deadband, 90% customers and 10% shareholder's and then also retroactive implementation to the effective date of HB 193 which was July 1, 2017. We do expect a final order to be issued in the fourth quarter and we have recorded a $1.8 million net reduction in revenue to be recovered from customers. This includes an approximately $3.3 million increase in revenue for what would have been the PCCAM period for 2017 and 2018. It would be offset then by approximately $5.1 million reduction in its revenues for the first three months of the 2018 and 2019 PCCAM 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 outstrip -- 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 million by October 31, 2018. This occurs as a bill credit. And this does also include a two 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, Kearney and 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, and therefore, had 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 two alternative 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 propose 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 rights of way. And this posed a threat to -- posed 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 DSIP 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've begun significant work on that yearly ahead of many other companies and addressing this concern. So in fact as of September 30, we deferred $0.7 million of tree removal and have deferred $13.3 million of revenue, again, associated with the tax law changes. The MPSC 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 million to $23 million. That would be $3 million for South Dakota plus $15 million to $20 million for the Montana current year method, and that will be offset by nearly equal reduction in income tax expense and therefore, would have no impact in net income.

On the other hand, the 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 million to $10 million. So as a result of the tax reform, we've updated our 2018 effective tax rate assumption to between 0% and 5%, and that compares to 8% to 12% prior to TCJA. And we reduced our deferred tax liability by $321 million as of December 31 of 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 was 2021. So we currently, and this is an important note, we believe our debt coverage ratios are adequate to maintain our existing credit ratings. However, further negative regulatory actions could lead to credit downgrades and could 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'll see on the slide, a set of seven scenarios, scenario number five 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 using a staged approach to incorporate new technologies into the system and adjusting to changed load centers and also moderating customer rate impacts, and also have the effect of broadening tax base with multiple economic development opportunities across several communities. And this is over a period of years, 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 2009. The company has changed substantially since then. We've, I think, done a very good job, efficiently managing all of our expenses, I think, with the challenges in 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 billion rate base. We're requesting a $34.9 million annual increase of 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 requested a 10.65% return on equity, 4.6% cost of debt, 49.4% equity and then a 7.42% overall return on our rate base. We've also requested a $13.8 million interim increase effective on November 1.

Additional notable items in the filing. First, to approve capitalizing demand-side management costs, this is something that Montana did in the 1990s when Montana Power, our predecessor, served the state. That would establish a new baseline for the Power Cost and Credit Adjustment Mechanism. It would include Two 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 nine months of our filing, new rates may be placed into new 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 the hearing under the draft proposal will be contemplated in mid-May.

And then, finally, turning to our capital estimates forecast. You see five years of consistent and balanced investments, as I mentioned, across jurisdictions and across platforms, really. This is a transmission and distribution capital plan. It does not include specific investments at this point for any issues identified and derived with the South Dakota Plan that has been filed or to be filed Montana Plan. But this is a $1.6 billion estimated cumulative five year capital program, to be funded with a combination of cash, aided by NOLs through 2020, as I mentioned, the mid-long-term debt issuances. Importantly, significant capital investments that are not in the above projections or neither in further negative regulatory functions could necessitate additional equity issuances.

With that, we look forward to questions and discussion.

[Operator]

[Operator Instructions]. Our first question will come from Julien Dumoulin-Smith with Bank of America.

[Julien Dumoulin-Smith, Bank of America Merrill Lynch]

First, if I can focus on the generation projections now with the $255 million CapEx. Can you reconcile just one, just the $1 per kilowatt involved here? 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 just -- again, I'm not sure if I'm interpreting the slide right, so that's why I'm looking for the clarity. How much are you short relative to the 90 megawatts that you all are looking to build? And maybe that gets a little bit of a question of timing of when exactly you're looking to put the 90 megawatts in?

[Robert Rowe, President, CEO & Director]

John, go ahead. John Hines, our Supply Vice President.

[John Hines, VP, Supply & Montana Government Affairs]

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 the ability to execute in the SPP market when called upon. And there's a significant opportunity there for us.

[Julien Dumoulin-Smith, Bank of America Merrill Lynch]

Sorry, 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?

[John Hines, VP, Supply & Montana Government Affairs]

That is correct.

[Julien Dumoulin-Smith, Bank of America Merrill Lynch]

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?

[John Hines, VP, Supply & Montana Government Affairs]

We're taking a -- 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 five years, to be implementing around 60 megawatts or so of -- at least 60 megawatts of additional capacity.

[Julien Dumoulin-Smith, Bank of America Merrill Lynch]

Got it. So would you say 50% of the $255 million over the next five years? Is that -- again, it's not quite there but that's effectively what you're saying?

[John Hines, VP, Supply & Montana Government Affairs]

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.

[Julien Dumoulin-Smith, Bank of America Merrill Lynch]

Got it. Okay. All right, fair enough. If we -- sorry, go for it.

[Robert Rowe, President, CEO & Director]

South Dakota, the mobile generation investment is underway, we've had a really good discussion with our technical folks in 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 previous instance that John has described or the next, say, five years, really insignificant.

[Brian Bird, VP & CFO]

Julien, 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 and 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 and years past, it's a kind of a declining slope for that line. Our hope is as we start layering generation, we start to see that being upward-sloping starting in 2020 and beyond.

[Julien Dumoulin-Smith, Bank of America Merrill Lynch]

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 date?

[Robert Rowe, President, CEO & Director]

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 that we filed this year, the focus will be on, again, long-term lease cost capacity. We do expect we'll be going out with RFP's to identify any range of resources to meet that need. And as everyone in the call is aware, we are unique in the West in 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 that we spend some time on the 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 that you want to add to that?

[John Hines, VP, Supply & Montana Government Affairs]

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.

[Julien Dumoulin-Smith, Bank of America Merrill Lynch]

Got it. Just two quick logistical 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 South Dakota or Montana, presumably, at this point, you would equity-finance a portion of that?

[Brian Bird, VP & CFO]

Yes, let go to first one. The first one, expectations we typically give and drivers, in light of the rate case itself and some other things, uncertainties, as we go to the end of the year, in terms of TCJA and how that impacts us in 2019. We don't expect any drivers at EEI. In terms of guidance for '19 as a whole, obviously, with the rate case, healthily, obviously some recovery cost from that rate case for a portion of '19. We'll evaluate whether it will provide guidance at all in February at that time. Can you ask your second question again, Julien?

[Julien Dumoulin-Smith, Bank of America Merrill Lynch]

Yes, I was just curious, 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?

[Brian Bird, VP & CFO]

I'll be prepared to talk about that when we -- later in the timing of this CapEx in February.

[Operator]

[Operator Instructions]. We'll take our next question from Michael Weinstein with Crédit Suisse.

[Michael Weinstein, Crédit Suisse]

So on the Colstrip outage, the $5.1 million impact on the PCCAM for the 2018-'19 time frame, is that mostly -- is most of that driven by the Colstrip outage, or is that something else?

[Brian Bird, VP & CFO]

I would say that it's certainly a combination. The Colstrip outage certainly contributed to that, but we experienced in the third quarter, as many people did, very high prices during the third quarter. And regardless of the Colstrip outage or not, we would have been procuring power because it's 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 the risk that we have with our PCCAM today.

[Michael Weinstein, Crédit Suisse]

And the PCCAM does cover -- it would cover purchases for an outage at Colstrip, this is nothing exclusive in there, exclusive in some way, right?

[Brian Bird, VP & CFO]

That's correct.

[Michael Weinstein, Crédit Suisse]

Can you quantify the impact of the Colstrip outage in isolation from everything else? Is that...

[Brian Bird, VP & CFO]

I can't [indiscernible], Michael.

[Michael Weinstein, Crédit Suisse]

Got you. And the $2.3 million increase of O&M in Slide 7. And I know you said, most of the impact of higher O&M was from the line.

[Brian Bird, VP & CFO]

Yes, there's some favorable items there to -- and 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.

[Michael Weinstein, Crédit Suisse]

Okay. I would choose that large number?

[Brian Bird, VP & CFO]

Agree. And I would tell you, on a year-to-date basis, we continue to look good on an OA&G perspective, and continue -- when we show you end numbers, we'll look good on a year-over-year basis.

[Michael Weinstein, Crédit Suisse]

And also, I appreciate you anticipating our questions on the -- our 2018 guidance reiteration.

[Brian Bird, VP & CFO]

I was listening on the last call, Michael.

[Michael Weinstein, Crédit Suisse]

Why do you expect higher margins in the fourth quarter? And also, what categories of cost cutting are you thinking of to get into that range?

[Brian Bird, VP & CFO]

I think I'll start with your second question first. For the 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 speak 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've seen more closer to kind of a 1.5% margin growth we saw in the fourth quarter, excuse me, in the first quarter continuing itself into the fourth quarter.

[Michael Weinstein, Crédit Suisse]

Okay, great. And is there any -- one last question. The effective tax rate for this year, like0 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?

[Brian Bird, VP & CFO]

You know, that's a good one for EEI. We've got to tell you something on EEI. That's probably a good thought. But, we'll see that Michael.

[Operator]

[Operator Instructions]. We'll take our next question from Paul Ridzon with KeyBanc.

[Paul Ridzon, KeyBanc Capital Markets]

Just a question with regards to reaffirming guidance. What are you assuming with regards to interim rates? And I assume that as soon as you get reasonable and fair treatment on Montana tactics.

[Brian Bird, VP & CFO]

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 as expected outcome on our current year method on TCJA on our guidance. So first and foremost, that's the first thing. Regarding interim rates, there are two things. There's a possibility we don't get interim rates, and there's a possibility 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.

[Operator]

[Operator Instructions]. It looks like we have another question, and that is from Jonathan Reeder with Wells Fargo.

[Jonathan Reeder, Wells Fargo Securities]

Brian, so just a quick clarity. Was the $1.8 million net impacting the PCCAM, that was recorded in Q3 then?

[Brian Bird, VP & CFO]

Yes, the full amount was recorded in Q3.

[Jonathan Reeder, Wells Fargo Securities]

The full $1.8 million net impact?

[Brian Bird, VP & CFO]

Correct.

[Jonathan Reeder, Wells Fargo Securities]

Okay. And then in terms of the tax issue, as you get back to the hearings and everything, do you have any sense of which way the commission is leaning? Or is it really just up to the mayor at this point?

[Brian Bird, VP & CFO]

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, that impacts our credit statistics. And I think that resonated with commissioners. I think, certainly, speaking to hazard trees also resonated with the commissioners. But, obviously, I think the interveners had points that, certainly, they made as well to the commission, and that's really hard to tell.

[Robert Rowe, President, CEO & Director]

We're embracing, at this point, so it is early to speculate.

[Jonathan Reeder, Wells Fargo Securities]

Okay. And the exact timing of this, is it December that we're supposed to move on it?

[Robert Rowe, President, CEO & Director]

By the end of the year, there'll be change at the commission. So we'd certainly expect a decision by then.

[Jonathan Reeder, Wells Fargo Securities]

Okay. And I'm assuming, Bob, you don't want to comment on the pending changing of the commission, huh?

[Robert Rowe, President, CEO & Director]

I do not [indiscernible]. As I mentioned, both of the candidates in this district, there are two seats that are contested, the two candidates to step into Commissioner Kavulla's position were 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.

[Jonathan Reeder, Wells Fargo Securities]

Okay. And any engagement with Johnson's challenger at this juncture?

[Robert Rowe, President, CEO & Director]

We really do very much the same thing there. Obviously, Chairman Johnson knows the company very well. We've been in informational meetings as well as in the contested cases. And we've also met with the other candidate. We want him to be fully informed as well.

[Jonathan Reeder, Wells Fargo Securities]

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, election go? Or do they stand on their own, historically, in Montana?

[Robert Rowe, President, CEO & Director]

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 higher for midterm, and lots of people are mailing in their ballots early. So there's certainly just an awful lot of interest and enthusiasm for the election just across the board. So I certainly think that would translate into a 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.

[Operator]

[Operator Instructions]. Okay, it looks like there are no more questions at this time.

[Robert Rowe, President, CEO & Director]

Just one final time I'm turning back to the PCCAM subject. We and you have all been focused on that for a very long time now. We were pleased to get the commission's votes 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 a real success resolving issues over a period of year, 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 to predictability in that approach. And that was essentially a prudence review. Logically, you didn't go down a prudence review path or you could go down a formulaic path. And here, the commission has gone down a formulaic path, and it's consistent with the commission's representations to the legislature. Once you made that election, it doesn't seem logical, I can't imagine it would 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 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?

[Operator]

It looks like we have one final question, if you would like to take that.

[Robert Rowe, President, CEO & Director]

Sure.

[Operator]

Our final question will come from Julien Dumoulin-Smith with Bank of America.

[Nicholas Campanella, Bank of America Merrill Lynch]

It's Nick Campanella on. Just one quick follow-up. The South Dakota, the spend, the $255 million, is that going to require approvals? Or can you just walk through the process on the regulatory side?

[Robert Rowe, President, CEO & Director]

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, and we'll be consulting with the commission. We want to get their guidance. I don't anticipate going through something like it for the approval process, for example. John?

[Brian Bird, VP & CFO]

This is Brian. I would essentially say that 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 rate case process, and as you pointed out, Bob, very efficiently.

[Operator]

There are no more questions at this time.

[Robert Rowe, President, CEO & Director]

Great, we look forward to seeing many of you at EEI in just a few weeks, and thanks for your interest in the good discussion.

[Operator]

Thank you, ladies and gentlemen. This concludes today's teleconference. Please disconnect your phones and have a wonderful day.