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

Robert Rowe -- President and Chief Executive Officer

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. 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, who was with us last week, really touring a lot of the state 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. Then, 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. The 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 she appreciated really being part of a team that is committed to safety, committed to doing the right thing and how much she 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 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 of 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 are 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 31st 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 -- Vice President and Chief Financial Officer

Thanks, Bob.

On page 4, the summary financials Bob gave you. The net income totals $8.2 million worse than the prior year and $0.19, on diluted earnings per share, worse than the prior year. In summary, we 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 $8.2 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 showing up in the electric side of the business, and I'll talk about weather impact in a moment.

But as you look down, and the decreasing gross margin due to the following factors, those that have a change in gross margin impacting net income of $3.9 million, there were really three. 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 on 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 Act deferral and some production tax credit flows-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 on to page 6. I mentioned weather. The third 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 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 matter of fact, we estimate the unfavorable weather in Q3 resulted in a $1.1 million pre-tax detriment as compared to normal and $1.5 million 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 Montana for our overall business, couldn't help offset the negative detriment from Montana during the quarter.

Moving on to page 7. From an operating expenses perspective, total operating expenses were $159.9 million, up $11.6 million or 7.8%. Showed pretty sizable increases in operating, general, property taxes and depreciation and depletion. One thing I'd say about operating, general and administrative expenses, I said it's 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, and 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&A, but are offset elsewhere in the P&L, pension and other post retirement benefits and unemployed directors deferred comp, those expenses were 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 expenses, again, $6.1 million.

Property tax was 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 and net income. Operating income, $16.3 million 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 $3.8 million, 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 million, nearly -- just over 29%. And below that, income tax benefit, $3.2 million on a year-over-year basis, primarily due to lower pre-tax 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. The two favorable adjustments, if you will, during the quarter is -- obviously as I mentioned, the lower pre-tax and the lower tax rate primary driver there with $7.9 million favorable benefit. But we did also have a prior-year permanent return to 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 better taxes on a year-over-year basis.

Moving on to the balance sheet on page 10. All I 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 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 of improvement in cash flow -- we had $43 million improvement in cash flow, but we also raised $40 million of equity. Those funds helped to pay down debt about $67 million and also helped us acquire Two Dot wind 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, and those items that we reversed out in a non-GAAP basis, it was a pretty simple quarter from that perspective. This quarter, we backed out unfavorable weather as compared to the prior year's favorable weather, a $5 million swing as I mentioned earlier.

With those changes at the bottom of the page you see -- the middle of the page, 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&L in the middle of the page, gross margin is down about $3.2 million. We mentioned PCCAM was one of those things with $1.8 million. We did also have a weather 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&A perspective, you can see, again, the approximately 2% when you back out some of those items. They are offset elsewhere in the P&L. So again, keeping an eye on OG&A, continuing 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&A perspective on a year-to-date basis, but for this quarter still up about 2%. Property taxes, depreciation, again up as a result of our investment. And total operating expenses up just over $7 million, getting us to an operating income of being down on a year-over-year basis about $10 million 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 $7.2 million or 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 talk about those adjustments, or excuse me, those things that we consider our 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 we 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 of $2.61. Backing out -- again, on a year-to-date basis, favorable weather of $0.03, backing out 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. 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 a similar lift in margin as we've seen in the first quarter and lower OA&G on a year-over-year basis in the fourth quarter helping us to get to that level. Having said, and anticipating your questions on the Q&A, I do expect that there is a higher probability that we would be in the lower half of that $3.35 to $3.50 but certainly seeing opportunity to be within the full range.

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

Robert Rowe -- President and Chief Executive Officer

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 told. Second, the Montana Commission has voted on a new power cost and credit adjustment mechanism, but have 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.

Second area -- the capital -- five-year capital forecast we discussed really is a transmission and distribution overall infrastructure plan building on the success of our DSIP 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 the integrity verification process and the terms of 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 first meter is scheduled in the coming months as part of an AMI deployment first in South Dakota, Nebraska and ultimately that 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 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 that we'll have by the end of the process will 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 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.

Just 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 '17, we filed a proposal for the -- again to PCCAM that incorporated a 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 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 $4.1 million deadband around the basis with the differences beyond that deadband share 90%/10% shareholders, and then also retroactive implementation to the effective date of HB 193 which was July 1 of 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. And this includes an approximately $3.3 million increase in revenue for what would have been the PCCAM period for 2017 and 2018 that could be offset then by an approximately $5.1 million reduction in net revenues for the first three months of the 2018-2019 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 at -- 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 31st 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 of 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 was consistent with our proposal to use any calculated customer benefit to defer planned future rate filings and therefore 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 two 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 rights of way. And these pose a threat -- pose 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 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 30th, we deferred $0.7 million for 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 a 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 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 pre-tax earnings and cash flow of approximately $5 million to $10 million.

So as a result of tax reform, we've updated our 2018 effective tax rate assumption to between zero 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 31st of last year. Then this reduction was offset in regulatory assets and liabilities. NOLs are now anticipated to be fully used in 2020. Previously that was 2021. So we currently -- and this is an important note -- I 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 the 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 seven 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 improve reliability, lower losses, improve restoration, increase 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 changed load centers, then 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 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, 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 the 2017 test year, and a $2.340 billion rate base. We're requesting a $34.9 million annual increase in electric rates and this reflects a 6.6% overall increased Montana electric revenues, and then through the cost allocation analysis a 7.4% increase in typical residential bills. We've 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, a predecessor, served the state that would establish a new baseline for the power cost credit adjustment mechanism, would include Two Dot wind 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 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 1st, and a hearing under the draft proposal would be contemplated in mid-May.

And then finally, turning to our capital investments forecast. You see five 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 adjustments at this point for any addition -- 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 $1.6 billion estimated cumulative five-year capital program, to be funded with a combination of cash, aided by NOLs through 2020 as I mentioned in that long-term debt issuances. Importantly, significant capital investments that are not in the above projections or any other and further negative regulatory actions could necessitate additional equity issuances.

With that, we look forward to questions and discussion.

Questions and Answers:

Operator

Thank you. (Operator Instructions) First question will come from Julien Dumoulin-Smith with Bank of America.

Julien Dumoulin-Smith -- Bank of America -- Analyst

Hey, good afternoon. Can you hear me?

Brian Bird -- Vice President and Chief Financial Officer

Hey, Julien.

Julien Dumoulin-Smith -- Bank of America -- Analyst

Hey, Howdy. So let's first -- if I can focus on the generation projections now with the $255 million 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 talk with 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 what I'm looking for the clarity. How much are you sure 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 are looking to put the 90 megawatts in.

Robert Rowe -- President and Chief Executive Officer

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

John Hines -- Vice President-Supply

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 is significant opportunity there for us.

Julien Dumoulin-Smith -- Bank of America -- Analyst

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?

John Hines -- Vice President-Supply

That is correct.

Julien Dumoulin-Smith -- Bank of America -- Analyst

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 -- Vice President-Supply

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 five years to be implementing around 60 megawatts or so of -- at least 60 megawatts of additional capacity.

Julien Dumoulin-Smith -- Bank of America -- Analyst

Got it. So would you say 60% of the 255 over the next five years, is that -- again, it's not quite there, but that's effectively what you're saying?

John Hines -- Vice President-Supply

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 -- Analyst

Got it, OK. All right. Fair enough. And then, if we -- I'm sorry, go forward.

Robert Rowe -- President and Chief Executive Officer

The South Dakota -- the mobile generation investment is under way. We actually 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 reasons that John has described over the next, say five years really is significant.

Brian Bird -- Vice President and Chief Financial Officer

I think -- and 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 -- 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 in generation, we start to see that being upward sloping starting in 2020 and beyond.

Julien Dumoulin-Smith -- Bank of America -- Analyst

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 all -- given the existing regulatory situation as well as projected need?

Robert Rowe -- President and Chief Executive Officer

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 and 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 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 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 want to add to that?

John Hines -- Vice President-Supply

Just the hydro system continues to provide not just energy, which is 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 -- Analyst

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?

Brian Bird -- Vice President and Chief Financial Officer

Yes, let's take -- let's go to the first one. The first one, expectation as we typically giving drivers at -- 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, so don't expect to see any drivers at EEI. In terms of guidance for '19 as a whole, obviously with the rate case, hopefully, we'll see some recovery of cost from that rate case for a portion of '19. We'll evaluate whether we will provide guidance at all in February at that time.

Julien Dumoulin-Smith -- Bank of America -- Analyst

Excellent. Thank you.

Brian Bird -- Vice President and Chief Financial Officer

Ask your second -- your second question, again, Julien. I'm sorry.

Julien Dumoulin-Smith -- Bank of America -- Analyst

Yes. I just was curious -- It just -- 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 would expect some portion of that equity financed?

Brian Bird -- Vice President and Chief Financial Officer

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

Julien Dumoulin-Smith -- Bank of America -- Analyst

Excellent. Thank you.

Brian Bird -- Vice President and Chief Financial Officer

Thanks, Julien.

Operator

Thank you. (Operator Instructions) We'll take our next question from Michael Weinstein with Credit Suisse.

Michael Weinstein -- Credit Suisse -- Analyst

Hi, guys.

Brian Bird -- Vice President and Chief Financial Officer

Hey, Michael.

Michael Weinstein -- Credit Suisse -- Analyst

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

John Hines -- Vice President-Supply

I would say, 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 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 PCCAM today.

Michael Weinstein -- Credit Suisse -- Analyst

And the PCCAM does cover -- it will cover purchases for an outage at Colstrip. There's nothing exclusive in there that would exclude it in some way, right?

John Hines -- Vice President-Supply

That's correct.

Michael Weinstein -- Credit Suisse -- Analyst

Okay. Can you quantify the impact of the Colstrip outage in isolation from everything else? Is that that's something (multiple speakers)?

John Hines -- Vice President-Supply

I can't.

Michael Weinstein -- Credit Suisse -- Analyst

Okay. Got you. And the $2.3 million increase of O&M on slide 7. I know you said most of the impact of higher O&M was from the line.

Brian Bird -- Vice President and Chief Financial Officer

Yes. There are some favorable items there too and then there is also quite a few smaller things in the all other category. But it has things shifted out. The thing that stood out was the line clearance.

Michael Weinstein -- Credit Suisse -- Analyst

Okay. I'd say 2.3 is a large number.

Brian Bird -- Vice President and Chief Financial Officer

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

Michael Weinstein -- Credit Suisse -- Analyst

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

Brian Bird -- Vice President and Chief Financial Officer

I was listening on the last call, Michael.

Michael Weinstein -- Credit Suisse -- Analyst

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

Brian Bird -- Vice President and Chief Financial Officer

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 pick on a 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 fourth quarter -- excuse me, in the first quarter retaining itself in fourth quarter.

Michael Weinstein -- Credit Suisse -- Analyst

Okay, great. And is there any -- one last question. The effective tax rate for this year is like zero 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 -- Vice President and Chief Financial Officer

That's a good one for EEI. We've got to tell you something at EEI. That's probably a good thought, but we'll save it, Michael.

Michael Weinstein -- Credit Suisse -- Analyst

Okay. Thank you.

Operator

(Operator Instructions) We'll take our next question from Paul Ridzon with KeyBanc.

Paul Ridzon -- KeyBanc -- Analyst

Guys, you can hear me?

Brian Bird -- Vice President and Chief Financial Officer

Hey, Paul, we can hear you.

Paul Ridzon -- KeyBanc -- Analyst

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.

Brian Bird -- Vice President and Chief Financial Officer

Yes. In the -- and 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, an as expected outcome on our current year method TCJA in our guidance. So first and foremost, that's the first thing. Regarding interim rates, you know, 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 cost from interim rates.

Julien Dumoulin-Smith -- Bank of America -- Analyst

Okay. Thank you very much for answering my questions.

Operator

Thank you. It looks like there are no questioners in the question queue. (Operator Instructions) It looks like we have another question and that is from Jonathan Reeder with Wells Fargo.

Jonathan Reeder -- Wells Fargo -- Analyst

Hey, Brian. So just a quick clarity, was the $1.8 million net impact on the PCCAM, that was recorded in Q3 then?

Brian Bird -- Vice President and Chief Financial Officer

Yes. The full amount was recorded in Q3.

Jonathan Reeder -- Wells Fargo -- Analyst

The full $1.8 million net impact?

Brian Bird -- Vice President and Chief Financial Officer

Correct.

Jonathan Reeder -- Wells Fargo -- Analyst

Okay. And then in terms of the tax issue, thinking back to hearing and everything. Do you have any sense like which way the Commission is leaning or is it really just up in air at this point?

Brian Bird -- Vice President and Chief Financial Officer

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.

Robert Rowe -- President and Chief Executive Officer

Like we're embracing (ph) at this point, so it is early to speculate.

Jonathan Reeder -- Wells Fargo -- Analyst

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

Robert Rowe -- President and Chief Executive Officer

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

Jonathan Reeder -- Wells Fargo -- Analyst

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

Robert Rowe -- President and Chief Executive Officer

I do not (multiple speakers). 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 learned a little bit more.

Jonathan Reeder -- Wells Fargo -- Analyst

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

Robert Rowe -- President and Chief Executive Officer

We really do very much the same thing here. 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. We want him to be fully informed as well.

Jonathan Reeder -- Wells Fargo -- Analyst

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 for -- do they stand on their own historically in Montana?

Robert Rowe -- President and Chief Executive Officer

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 mid-term and lots of people are mailing in their ballots early. So certainly it's 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 our Public Service Commission race. And I know all the candidates are out working hard and trying to communicate their positions.

Jonathan Reeder -- Wells Fargo -- Analyst

Yes. Okay. Well, we will watch and see that on November 6 and see you guys at EEI.

Operator

(Operator Instructions) Okay. It looks like there are no more questions at this time.

Robert Rowe -- President and Chief Executive Officer

Just one final comment, turning back to the PCCAM subject. We and you are 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 one or two, 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 years so the trackers became much, much more focused and stable. And then that process reversed, and more and more single items came up -- there was lot and lot less predictability in that approach. That was essentially a prudence review. Logically, if you 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 well, 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 like to take that.

Robert Rowe -- President and Chief Executive Officer

Sure.

Operator

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

Nicholas Campanella -- Bank of America -- Analyst

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

Robert Rowe -- President and Chief Executive Officer

But typically, South Dakota is very thorough. But they're also very efficient. So we 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, will be consulting with the Commission. We want to get their guidance. I don't anticipate going through something like a pre-approval process for example. John?

John Hines -- Vice President-Supply

I would just describe -- 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.

Nicholas Campanella -- Bank of America -- Analyst

Thanks so much.

Operator

There are no more questions at this time.

Robert Rowe -- President and Chief Executive Officer

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

Operator

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

Duration: 55 minutes

Call participants:

Travis Meyer -- Investor Relations Officer

Robert Rowe -- President and Chief Executive Officer

Brian Bird -- Vice President and Chief Financial Officer

Julien Dumoulin-Smith -- Bank of America -- Analyst

John Hines -- Vice President-Supply

Michael Weinstein -- Credit Suisse -- Analyst

Paul Ridzon -- KeyBanc -- Analyst

Jonathan Reeder -- Wells Fargo -- Analyst

Nicholas Campanella -- Bank of America -- Analyst

More NWE analysis

Transcript powered by AlphaStreet

This article is a transcript of this conference call produced for The Motley Fool. While we strive for our Foolish Best, there may be errors, omissions, or inaccuracies in this transcript. As with all our articles, The Motley Fool does not assume any responsibility for your use of this content, and we strongly encourage you to do your own research, including listening to the call yourself and reading the company's SEC filings. Please see our Terms and Conditions for additional details, including our Obligatory Capitalized Disclaimers of Liability.

More From The Motley Fool

• 10 Best Stocks to Buy Today

• 3 Stocks That Are Absurdly Cheap Right Now

• 5 Warren Buffett Principles to Remember in a Volatile Stock Market

• The $16,728 Social Security Bonus You Cannot Afford to Miss

• The Must-Read Trump Quote on Social Security

• 10 Reasons Why I'm Selling All of My Apple Stock

Motley Fool Transcribers has no position in any of the stocks mentioned. The Motley Fool has no position in any of the stocks mentioned. The Motley Fool has a disclosure policy.