Black Hills Corp (NYSE:BKH) Q4 2017 Earnings Conference Call February 2, 2018 11:00 AM ET
Jerome Nichols - Director, IR & Corporate Communications
David Emery - Chairman and CEO
Richard Kinzley - CFO and SVP
Julien Dumoulin - Bank of America Merrill Lynch
Michael Weinstein - Crédit Suisse AG
Christopher Ellinghaus - The Williams Capital Group
Insoo Kim - RBC Capital Markets
Christopher Turnure - JPMorgan Chase & Co.
Good day, ladies and gentlemen, and welcome to the Black Hills Corporation Fourth Quarter and Full Year 2017 Earnings Conference Call. My name is Brian, and I will be your coordinator for today. [Operator Instructions]. As a reminder, this conference is being recorded for replay purposes.
I would now like to turn the presentation over to Mr. Jerome Nichols, Director of Investor Relations of Black Hills Corporation. Please proceed, sir.
Thank you, Brian. Good morning, everyone. Welcome to Black Hills Corporation's Fourth Quarter and Full Year 2017 Earnings Conference Call. Our materials for the fourth quarter and full year 2017, including our earnings release and webcast presentation, can be found at our website at www.blackhillscorp.com.
Leading our quarterly earnings discussion today are David Emery, Chairman and Chief Executive Officer; and Rich Kinzley, Senior Vice President and Chief Financial Officer.
During our earnings discussion today, some of the comments we make may contain forward-looking statements as defined by the Securities and Exchange Commission, and there are a number of uncertainties inherent in such comments. Although we believe that our expectations and beliefs are based on reasonable assumptions, actual results may differ materially.
We direct you to our earnings release, Slide 2 of the investor presentation on our website and our most recent Form 10-K, Form 10-Q and other documents filed with the Securities and Exchange Commission for a list of some of the factors that could cause future results to differ materially from our expectations.
I will now turn the call over to David Emery.
Thank you, Jerome. Good morning, everyone. Thanks for joining us this morning. For those of you following along on the webcast slides, we'll be starting on Slide 3. We'll follow a similar format to that of previous quarters. I'll give a quick update on the quarter and the highlights for both the quarter and the full year. I'll turn it over to Rich Kinzley, our Chief Financial Officer, to update financials. And then, I'll visit a little bit about strategic overview and forward plans.
So moving on to Slide 5, fourth quarter highlights. For our utilities subsidiaries, on December 15, our Arkansas gas subsidiary filed a rate review with the Arkansas Public Service Commission seeking to increase annual revenues by approximately $30 million, with rates effective hopefully by the fourth quarter of 2018.
On November 17, our Northwest Wyoming gas utility filed a rate review with the Wyoming Public Service Commission seeking to increase annual revenues by approximately $1.4 million, effective in the third quarter of 2018.
Moving on to Slide 6, utility highlights, continuing those. On October 3, Rocky Mountain Natural Gas, which is our intrastate pipeline in Colorado, filed a rate review with the Colorado Public Utilities Commission seeking to increase revenues by approximately $2 million a year, effective in the third quarter of 2018. We're currently reviewing the impacts of tax reform related to all three of those active rate reviews, and we may need to amend our request, if needed. I will have a little more detail on that later.
On August 4th, our Colorado Electric Utility received bids related to a request for proposals for an additional 60 megawatts of renewable energy resources to be in service by 2019. Those are required to meet Colorado's renewable energy requirements.
The Colorado PUC approved the delay in our process to allow bidders time to adjust for the recently enacted tax reform. Now we're currently evaluating bids and plan to present the results, including our recommended project to the Colorado PUC on February 9.
Moving on to Slide 7, our corporate highlights for the fourth quarter. On January 31, our board declared a quarterly dividend of $0.475 per share, which is equivalent to an annual dividend rate of $1.90 per share. That annual equivalent of $1.90 would represent a 5% increase compared to the 2017 total dividend of $1.81. It would also represent our 48th consecutive annual dividend increase. During the quarter, both Moody's and Fitch affirmed their corporate credit rating of Black Hills Corporation at Baa2 and BBB+, respectively. Finally, related to discontinued operations, which was previously reported as our oil and gas segment. As of this Monday, we've now closed transactions or signed agreements to sell more than 90% of our oil and gas properties for an aggregate value of $75 million.
We've executed agreements to sell all of our operated properties and have only minimal value in nonoperating assets remaining to be sold. We expect to wrap up that process by midyear. I'll talk a little bit more about that later. And then, obviously, Rich will discuss this, but the segment is reported as discontinued operations beginning with the fourth quarter.
Slide 8 provides a reconciliation of our fourth quarter income from continuing operations as adjusted compared to the fourth quarter of last year. Rich will provide the segment details in his financial update here shortly. Slide 9 provides a similar reconciliation of full year 2017 results compared to 2016.
With that, I'll turn it over to Rich for the financial update.
All right. Thanks, Dave, and good morning. I'm going to jump right in on Slide 11. On Slide 11, we reconciled GAAP earnings to earnings from continuing operations as adjusted a non-GAAP measure. We do this to isolate special items and communicate earnings to better represent our ongoing performance. As shown on this slide, we now report our oil and gas segment as discontinued operations, given our ongoing exit of that business. We also experienced other special items not reflective of our ongoing performance in each of the last five quarters.
The first special item is acquisition-related expenses such as advisory fees, financing and other third-party consulting costs, associated with the SourceGas acquisition and integration. We completed the vast majority of the integration work related to the acquisition in 2016 and finished the remaining items in 2017.
The second special item relates to income taxes, and is predominantly the result of tax reform. The corporate tax rate changed from 35% to 21%, required a onetime revaluation of our deferred tax assets and liabilities, which resulted in a net reduction to income tax expense. I'll talk more about tax reform in a few minutes.
These special items are not reflective of our ongoing performance. And accordingly, we reflect them on an as adjusted basis. As adjusted EPS for the fourth quarter was $0.98 per share compared to $1.06 per share in the fourth quarter last year.
For the full year, as adjusted EPS increased over 7% in 2017 to $3.36 per share compared to $3.13 per share in 2016. This growth was driven mainly by a full year of earnings contribution from the SourceGas acquisition, which closed in mid-February, 2016.
Slide 12 displays our fourth quarter revenue and operating income. Consolidated revenue and operating income were effectively flat comparing fourth quarter 2017 to fourth quarter 2016. It's important to note that since we re-classed our oil and gas results to discontinued operations, allocated corporate costs, which had previously been charged to oil and gas, have now been reallocated to our other business segments for 2017, slightly impacting results at each business.
Slide 13 displays the full year revenue and operating income. Revenue increased 9% and operating income increased 11%, as we closed the SourceGas acquisition on February 12, 2016 and enjoyed 42 more days of operating results in 2017 from those Gas Utilities.
Operating income improved at each operating business segment in 2017 other than our Electric Utilities segment. I'll discuss each operating segments quarterly and annual results on the following slides.
At the Corporate segment, the notable improvement reflects the reduction in internal labor charges to acquisition and integration activities in 2017 as compared to 2016. With the substantial completion of the integration in 2016, our employees moved on to other projects and initiatives in 2017, and the associated internal labor costs have predominantly been charged to our Utility segments in 2017.
Slide 14 displays our fourth quarter and full year income statements. Comparing 2017 to 2016, we delivered growth in operating income and income before taxes for the fourth quarter and the full year. Gross margin, operating expenses and DD&A showed small increases for the fourth quarter compared to 2016, while the full year for those line items showed substantial growth year-over-year, reflecting a full year of the SourceGas Utilities in 2017. As I noted, we closed that acquisition midmonth in 2016, so we picked up 1.5 month of the heating season at those utilities in 2017.
Acquisition costs decreased in 2017, as we completed the vast majority of that work in 2016. Interest expense was flat in the fourth quarter compared to 2016, as debt balances were fairly consistent in each year's fourth quarter.
But interest expense for the full year was higher as we had a higher average debt balance in the first half of 2017 compared to 2016. In the fourth quarter of 2017, we recognized a $19 million onetime reduction in income tax expense, most of which related to tax reform. I'll address tax reform shortly.
If you were to add this $19 million tax benefit to our tax expense for the fourth quarter and full year 2017, our effective tax rate would've been approximately 32% for the quarter and approximately 30% for the full year. The loss from discontinued operations is reflective of our oil and gas segment and includes substantial noncash impairments in all periods shown.
The noncontrolling interest represents the 49.9% interest in the Colorado IPP plant we sold to a third party in May 2016. After adjusting for discontinued operations in the special items, income from continuing operations as adjusted increased 11% from $167 million in 2016 to $185 million in 2017. EBITDA grew by $52 million or 9%. I'll take a moment to provide further color around our share count. Diluted shares outstanding increased by 1.8 million in 2017 over 2016 due to 2 factors. First, approximately 1.2 million additional weighted average shares are included in 2017 compared to 2016, from issuances of equity through our At-the-Market equity offering program during 2016.
Second, an additional approximately 600,000 weighted average shares are included in 2017 due to the application of the treasury stock method of accounting for our unit mandatory convertible securities. We issued the unit mandatories in Q4 2015 to help fund the SourceGas acquisition, and these will convert from debt to equity prior to November of this year, resulting in approximately 6.3 million additional shares being added to our basic share count.
Until that conversion occurs, we are effectively phasing in the dilution through the treasury stock method. Whereby, if the average stock price during the reporting period is above the conversion price, a portion of the dilutive effect is reflected in the fully diluted share count. With a reference conversion price of $47.29 and an average share price of $65.85 during 2017, we will require to add approximately 1.8 million shares to the diluted share count in 2017 as compared to 1.2 million shares in 2016.
Since we've had some confusion around our diluted share count surrounding the unit mandatories, I will tell you that in our 2018 guidance, we are including approximately 56 million weighted average fully diluted shares outstanding. We don't plan to issue any new equity this year. And after the unit converts later this year, we will have approximately 59.5 million basic shares outstanding as we move into 2019. Considering other small dilutive items such as equity compensation that are typically included in fully diluted share count, our weighted average fully diluted share count in 2019 should be around 60 million shares. So that's 56 million shares for '18 and 60 million for '19.
Slide 15 displays our Electric Utilities gross margin and operating income. The Electric Utilities gross margin was effectively flat for the fourth quarter compared to 2016, and increased nearly $20 million for full year 2017 compared to 2016. Investments in new generation and transmission, as well as increased commercial and industrial sales, drove the increase in gross margin year-over-year.
Operating expenses were higher for the fourth quarter and full year as a result of increased expenses associated with new generation and transmission investments plus higher generation outage in major maintenance expense. Also 2017 O&M at the Electric Utilities include substantially more allocated costs, reflective of employee cost that were charged to corporate in 2016 related to integration activities, as well as allocated corporate cost that have been charged to our discontinued oil and gas business prior to the fourth quarter of 2017.
Operating income decreased by $6.9 million for the fourth quarter in 2017 compared to 2016 and by $3.2 million for full year 2017 compared to 2016. The Electric Utilities placed 2 significant investments in service towards the end of 2016. The first was the 40-megawatt gas combustion turbine in Colorado. This project had a construction financing rider in 2015 and 2016, which began to increase earnings into 2016 ahead of the actual in-service plan.
The second investment was the Peak View Wind Project in Colorado, which generates a large portion of its return to production tax credits. These credits amounted to $4 million more in 2017 than in 2016 due to a full year production in 2017 versus only 2 months in 2016. These credits are reflected in reduced income taxes rather than through operating income. Because of these factors, the Electric Utilities' year-over-year operating income performance doesn't fully reflect the economic contributions from these two investments.
Moving to Slide 16. The results at our Gas Utilities for the fourth quarter this year were fairly flat compared to 2016, as increased margins were nearly offset by increased depreciation and property taxes. The Gas Utilities saw an increase of nearly $52 million in gross margin and $23 million in operating income comparing full year 2017 to full year 2016, with nearly all of these increases attributed to the addition of SourceGas.
As I noted earlier, we closed that acquisition mid-February and picked that extra 1.5 months up in 2017 compared to 2016. As was the case in the Electric Utilities, the Gas Utilities had substantially more allocated cost in 2017 due to employee costs that were charged to corporate in 2016 related to integration work, as well as costs that have been charged to the discontinued oil and gas business prior to the fourth quarter of 2017. Despite those increased allocated costs, the Gas Utilities showed excellent growth in 2017.
Next, I'll talk about weather and its financial impacts at both Electric and Gas Utilities when compared to normal. For both the fourth quarter and full year in 2017, weather was more mild than normal. In the fourth quarter, our Gas Utilities gross margin was negatively impacted by an estimated $2.1 million and our Electric Utilities gross margin was negatively impacted by approximately $600,000.
For the full year, weather negatively impacted our Gas Utilities gross margin by an estimated $9.1 million, and our Electric Utility gross margins by an estimated $1.8 million.
On Slide 17, you see the power generation operating income increased $1.1 million for the fourth quarter of 2017 compared to 2016, and increased by $1.3 million year-over-year, primarily from annual increases in power purchase agreement prices. The Power Generation segment continued to realize strong contract availability from its generating units and it continued its strong cash flow contributions to Black Hills.
On Slide 18, in the fourth quarter, our mining segment had an $800,000 operating income decrease compared to the fourth quarter in 2016. For the quarter, revenue was $1.5 million higher, with favorable pricing offset by increased cost to move 10% more overburden in 2017 and increased cost from timing on major maintenance. For the full year 2017, mining operating income increased by $2.1 million. Revenue was $6.3 million higher as tons sold increased 10% compared to full year 2016, primarily driven by an extended outage at the Wyodak plants in 2016. We sell over 1/3 of our coal to this plant annually.
Keep in mind though the revenue increase from these additional tons sold on that contract does not drop straight to operating income, as revenue-related royalties and taxes increase accordingly.
On the cost side, we had increased cost of $4.2 million for the year, driven primarily by 14% more overburden yards moved in 2017, as we continued north into a higher strip ratio area of the mine.
Our mine continues to perform at a high level, with sales almost entirely to on-site [indiscernible] plants and roughly half our sales based on a cost-plus pricing methodology.
Slides 19 and 20 lay out the impacts to Black Hills' related to tax reform. First, I'll address the 2017 impact of tax reform. As required, we revalued our deferred taxes at year-end based on the lower corporate rate, resulting in a $300 million reliability, with a corresponding decrease to deferred taxes. That regulatory liability will generally be amortized over the remaining life of the associated assets sold 30 to 40 years. And the amortization will not affect the income statement. It will merely impact cash flow by roughly $5 million to $10 million a year. Also, it will take a few years to get to that level of amortization, as the amortization won't start in each jurisdiction immediately.
We also recognized a $15 million noncash reduction to 2017 tax expense as a result of the deferred tax revaluation. Relating to 2018, we expect tax reform to impact earnings minimally, as the reduced tax benefit on holding company debt will be largely, but not completely, offset by the reduced tax expense on our nonutility earnings.
We expect to maintain deductibility of our interest expense, including interest expense from holding company debt associated with the purchase of utility properties. From a cash flow perspective, we expect our cash flows to be negatively impacted by $35 million to $45 million annually, due to the lower revenue collection as our utility customers benefit from tax reform. Dave will address our -- a planned approach to regulatory matters on tax reform later.
Slide 21 shows our capitalization. At year end, our net debt-to-cap ratio was 65.9%. This is down 120 basis points from year end 2016. Our $299 million of unit mandatory securities are reflected as debt on our balance sheet until the units convert to equity in the second half of this year, which will strengthen our capital structure.
By year end 2018, we expect our net debt-to-cap ratio to be well under 60%. Despite some pressure from the effects of tax reform, our internally generated cash flows will largely fund our capital expenditures and dividends for the foreseeable future. We do not expect to issue any equity to fund our currently planned future capital expenditures or dividends, but we're keeping our At-the-Market equity offering program available in the event we need to finance additional capital spending not currently planned. In 2017, we did not issue any shares through the At-the-Market program.
Slide 22 demonstrates that we're in good shape relative to upcoming debt maturities. In the first quarter of 2016, we executed significant debt financings to help fund the SourceGas acquisition. And in the third quarter of 2016, we accessed the debt markets at a time when conditions were beneficial to successfully refinance debt we assumed through the acquisition and term out other upcoming maturities. We also successfully implemented a commercial paper program in Q1 2017, which helped to minimize our short-term borrowing costs. We will need to remarket the debt associated with the unit mandatory convertibles in the second half of this year, and we will be evaluating our 2019 maturities for additional opportunities to refinance and/or term out the upcoming maturities.
On Slide 23, you can see our current credit rating and outlook from each rating agencies. We are committed to maintaining our current solid investment-grade credit ratings and our forward forecasted credit metrics got those ratings, even when considering decreases in future cash flows expected to result from tax reform.
Moving to Slide 24. We revised our 2018 earnings guidance range by $0.05, on both the top and bottom end to $3.30 to $3.50 per share. The primary drivers for this change are increasing short-term interest rate assumptions and the impact of tax reform. The assumptions for the 2018 guidance range are listed in the press release and on Slide 24.
Slide 25 illustrates our track record of creating shareholder value. We are focused on long-term value creation, and Dave will touch on that more now in his strategic overview. Dave?
Thank you, Rich. Moving on to Slide 27. We group our strategic goals into 4 major categories, profitable growth, valued service, better every day and great workplace, with the overall objective of being an industry leader in all we do. On Slide 28, from a strategy execution perspective, we are focused on delivering strong long-term total shareholder returns. We plan to accomplish that by achieving long-term EPS growth rate above the utility industry average, targeting a 50% to 60% dividend payout ratio, while we retain the flexibility to increase the dividend more during periods of slower EPS growth and continuing our track record of 48 consecutive annual dividend increases.
Slide 29, related to strategy execution, we are in a period where we're in the process of transitioning earnings growth drivers from an acquisition and integration focus back to a more traditional utility growth strategy. In the near term, we expect slower earnings growth, since we're entering test years in preparation for rate review filings or commencing filings in certain jurisdictions. As I noted earlier, we've already filed the request for 3 rate reviews during the fourth quarter. All are still pending.
In the long term, we expect higher earnings growth, driven by strong capital investments to meet our customer needs, our continued focus on standardization and efficiency improvements and more regular rate review filings.
On Slide 30, as we focus on delivering long-term shareholder value, our fuel and service territory diversity reduces our business risk and drives more predictable earnings.
On Slide 31, our acquisition and rapid integration of SourceGas has been a great success, adding substantial value for both customers and shareholders now and well into the future. This slide demonstrates the significant G&A and O&M cost savings per customer from the successful integration of SourceGas into Black Hills.
On Slide 32, our utility acquisitions have created much larger transmission and distribution systems. With that increase in size comes increased opportunity for investment to serve a much larger customer base. Our long-term capital investment required to serve our customers is even greater than we estimated when we purchased an integrated SourceGas.
Slides 33 and 34 outline the substantial investment that will be necessary to maintain our natural gas utility infrastructure. A lot of that, obviously, was acquired with the SourceGas opportunity.
Moving on to Slide 35. Strong capital spending has and will continue to drive much of our earnings growth. We plan to invest approximately $1.3 billion over the next three years to serve our customers.
Slide 36 illustrates our historical capital spending and depreciation amounts. As you can see, capital spending far exceeds depreciation, contributing to earnings growth.
Slide 37 provides a regulatory update for our utilities. As I mentioned earlier, during the fourth quarter, we filed 3 rate reviews at Arkansas Gas, Rocky Mountain Natural Gas and our Northwest Wyoming Gas utility.
And I also mentioned that our Colorado Electric Utility were currently evaluating renewable energy bids and plan to present our recommendation to the Colorado Public Utilities Commission a week from today. Related to tax reform, as noted earlier, we're working proactively with utility regulators in each of the states we serve to address the appropriate mechanisms to provide benefits of lower corporate income taxes to customers. It's early in their process and our approach will likely vary by state. But for service territories in which we don't have an active rate review filing, we believe it would be in our customers' best interest to utilize an existing rider mechanism, such as a fuel or purchase power clause, to promptly provide benefits to customers.
We would then intend to true-up deferred tax and balance sheet-related items during the next full rate review for each of those territories. For the 3 active rate review processes we have underway today, we are reviewing those filings to assess the impacts of tax reform on our requests, and we may amend those requests as needed.
Moving on to Slide 38. We're extremely proud of our dividend track record of consecutive annual dividend increases, including stronger increases the past several years. As I noted earlier, we have flexibility to use relatively larger dividend increases during periods of lower earnings growth. As you can see from the graph, even after two dividend increases in 2017, we're still well within our targeted 50% to 60% dividend payout range.
Slide 39, we focus every day on operational excellence. Our newly completed corporate headquarters in Rapid City will help us continue to drive efficiencies across our entire organization in all of our utilities benefiting the communities and customers we serve.
On Slide 40. We've made great progress towards the exit of our oil and gas business since announcing our plans in November. As of the 29th of January, this Monday, we've closed transactions or signed contracts to sell more than 90% of our oil and gas properties for an aggregate value of approximately $75 million after the payment of approximately $20 million to satisfy projected future minimum daily quantity shortfalls in the gas processing contract. $75 million of value received approximates book value.
We've signed agreements to sell all of our operated properties in the San Juan, Piceance and Powder River Basins, and have only nonoperated assets with minimal value left to the vest.
We expect to receive bids for those assets today and expect to complete the sale of all remaining assets by midyear. Since the sales of our assets are to private companies, and the individual transactions are not material to our overall results, we don't intend to provide any more detail or discuss the terms of individual asset sales transaction.
On Slide 41, excuse me, just illustrates our progress towards divesting oil and gas wells. Next quarter will likely be the last time we include any discussion of oil and gas on our quarterly results, and even that disclosure will be hat minimal.
Finally, our scorecards, on Slides 42 and 43, these are the way that we hold ourselves accountable to you, our shareholders, setting forth our goals for the year, at the beginning of the year and providing progress updates as the year progresses.
Now that concludes our prepared remarks. We'd be happy to entertain any questions.
[Operator Instructions]. Our first question comes from the line of Julien Dumoulin from Bank of America.
Just wanted to follow-up on the tax reform stuff. Just want to be very clear. How are you seeing this impact your FFO to debt metrics? And what are the Agency saying thus far? I know you've all have talked about kind of 15%, 16% historically of -- what is the impacts of tax reform, particularly given sort of the upcoming filings that you all anticipate to make with the states? Are we to understand that basically you have fully reflected the impacts pending the clarity with the states? Or you kind of initially reflecting the lower cash flows in the updated '18 guidance? And then you're going to see how that moves from there?
Well, I can start out, Julien, this is Rich, with the credit rating agencies. And then Dave, I think, probably will address the situation with the state -- individual states. We've had communication with the rating agencies. We feel good about where we're at. There is some deterioration, obviously, in FFO to debt. But even with the impacts of tax reform, we still think we're probably going to be in the mid-teens on that FFO to debt, and it will improve as each year passes. So we feel good about where we're at. We'll continue our dialogue with the rating agencies. And Dave, you want to address the state issue?
Yes. And we have made assumptions that, obviously, we don't know the final details, but we made what we believed to be reasonable assumptions on impacts on our cash flows and incorporated those into our guidance for the year.
Okay. Everyone just to clarify there, so is it fair to say that you're effectively assuming some kind of modest deleveraging to address with the reduction in cash flows? Or maybe could you quantify that a little bit?
No, no. No, as I said in my comments, we don't expect to have to issue any equity to cover our CapEx and dividends, even in considering the -- $35 million to $45 million a year is our estimate, as Dave said, based on reasonable assumptions that we have at this point for the impact -- from tax reform on cash flows. Not enough to move things that we're going to have to issue equity.
Right. Just the slight change in the financing plan on the leverage?
Yes, we may have to borrow a little more money, obviously, as we go out, but it's not moving the needle enough that to concern us.
Got it. And how do -- what's the implication on the states kind of going back to that second question there?
Yes, like I said earlier, Julien, we're still working on specific discussions and what we would propose on each state. We've talked to all of them. We did it immediately after tax reform past and told them that it would be our intent to come in and try to provide benefits to customers as quickly as practical. As I said earlier, where we don't have active ongoing rate cases and rate review processes underway, our preference would be to use a rider mechanism in all states, because it gives the money back to customers much more quickly. If we were to try to go through full blown rate cases in those jurisdictions, you're looking at almost a year before customers realize any savings. But we don't think that's really the best approach. So again, subject to deciding state by state, many of those jurisdictions will likely go in and ask to pass the benefits through via an existing rider. The three states we've already filed rate cases in were reevaluating our request there and may adjust those depending on the finalization of those reviews. And we've been in dialogue with those commissions in those three circumstances as well.
Got it. But conceptually speaking, as you think about these filings, it shouldn't -- your expectations for earned ROEs, obviously, pending the outcome of these rate cases isn't necessary changing as a function of tax reform, if I'm hearing you?
Our next question comes from the line of Michael Weinstein from Crédit Suisse.
Just a follow-up on Julien's questions. Is the -- are you proposing to pass back 100% of the tax benefits through the riders? Or is it just a portion of it? I mean, I know that this is probably early phase discussions with the regulators, but is there any more flavor you can add to that?
Well, essentially, the difference in the tax rate, the impacts. I mean, it's not as simple as just the change in tax rate, there's some changes in deductibility and some other things. But the net benefit of that largely would be passed on to customers. Now again, it depends on state-by-state analysis and where we are in regulatory proceedings and future planned proceedings in each of those states. On the nonutility side, obviously, we expect to retain those benefits.
Right. And considering that the Arkansas rate filing was your own choice, do you think the increases, or do you think the tax reforms increase the chances of a favorable outcome there? I mean, is this something that you can -- is this something in your back pocket so to speak as you go into negotiations there?
Well, the bottom line is anything that is a positive to customers is positive to the process, certainly. The difference in tax rate certainly would have an impact on our revenue request and we're analyzing that, discussing how and if to incorporate that into our filing, but we've had discussions with the commission staff there and we're working on that issue now.
Right. And just one last question. How have the tax reform impact to cash flows affected the plan to get down to the, I think, the low to mid-50s debt ratio by, I think, after 2019 or so?
Obviously, it impacts that. We still think we can get close to the mid-50s by the end of our kind of five-year planning horizon. But it impacts it by 100 to 200 basis points by the time you get out 5 years of cumulative compounding of that, right?
And our next question comes from the line of Chris Ellinghaus from Williams Capital.
Can I get a little clarification on what in guidance on a couple of issues? You said that -- I don't remember what the word was, but favorable outcomes in the pending rate cases. Can we assume that whatever you've assumed for the rate case outcomes is effective on those dates? You were talking about third quarter, fourth quarter?
Can we assume that you've assumed that the rate outcomes are somewhat below your ask in those cases?
Well, put it this way. Historically, it's pretty rare for utility to be granted its full rate request.
Okay. Also you mentioned normal weather in guidance. It looks like the early part of the first quarter might be a little bit below normal. Did you reflect that already in the guidance?
Yes. It's been a mixed bag on the weather front through January in our service territories. We're just getting the books closed obviously, so it's a little too early to tell exactly. But while we've had some cold come through, we've also had some warm spells. It looks like it's probably not impactful, I guess, compared to normal in January.
Okay. As far as the tax reform strategy for using riders and clauses, have you gotten much feedback thus far? And have you made any specific filings to-date?
We have not made any specific filings to-date. We've had preliminary discussions basically notifying the staffs, and this was immediately after the first of the year that hey, we want to work with you to get this done and really back to customers as quickly as practical. And so at least, mentioned the riders is perhaps the best mechanism to do that. But beyond that, we haven't gone any further yet, where we want to firm up numbers before we engage in real meaningful discussions with them.
Okay. One last quick one. The confusion about Wyoming Electric customer expansion from last year, have you gotten any greater clarity on those customers and timing?
I think you might have been talking about Colorado Electric. You're talking about a couple of the things we discussed in our guidance revision?
I'm talking about the potential customers that weren't realized last year as you expected.
Yes, that was largely in Colorado, and a little bit in the other territories. But yes, we've certainly worked pretty hard to get our hands around those forecasts.
And believe we have reasonable assumptions related to that baked into this year's guidance.
Our next question comes from the line of Insoo Kim from RBC Capital Markets.
In terms of, I guess, the number of rate cases that you may be filing in the next few years. If we see an uptick in rate case filings more near term, would that be mainly as a result of commissions requesting or requiring you to file due to tax reform? Following that, it would -- has any contingent it's interest to [indiscernible] -- want to file sooner than later?
Yes, I would say, the discussion we had at our analyst meeting, where we said we may be filing up to 10 cases in the next five years, that's still valid. It really hasn't changed materially. Again, we need to work our way through the process of tax reform. If we are successful in the approach that we would like to pursue, which is getting the benefits to customers as quickly as possible through rider mechanisms, it really shouldn't change our 8-K's schedule meaningfully.
Got it. Okay. And then, somewhat related to tax reform. Do you -- how much boost to rate base do you foresee as a result of that? And related to that are you -- do you -- are you still considering potentially providing a rate-base case or figure for the electric and gas utilities sometime in the future?
We've talked a lot about disclosing a little more detail around our forward utility capital spending plans, and we are working on that. I can't promise you when and if we'll deliver it, but we want to be very confident in it before we put it out.
And obviously, the way it's going to change how -- the tax reform is going to change the impact to rate base growth, it's obviously positive. It's going to take a while to work through that, because that the way that large deferred tax assets -- the deferred regulatory liability transferred from deferred tax assets, you have to go through every asset and a lot of detailed calculations. So it's just going to take a little way while for that to play out into.
Well, and certainly, then there's a bonus depreciation going forward, so that's additive as well.
Yes, exactly. I'm sorry, just one more. How much parent debt are you assuming that maybe hit as a result of the lower tax shield?
Well, it's about $500 million, roughly. $500 million to $600 million.
Our next question comes from the line of Christopher Turnure from JPMorgan.
I just wanted to get more color on the reallocation of E&P expenses. I know you've given us a message before about, I think, half of the debt income from that or that drag from that segment being reallocated, but can you give us a more precise dollar amount now that it's out? And also can we look at the actual reported 2017 segmented O&M as already reflecting a full year of that now?
Yes, I think, if you look in the press release, the back part of the press release where we give our segment information, you're going to find that information, Chris. We, basically, in 2017, we did that reallocation, if you will, the costs that were in E&P are now in our gas and electric utilities and to a lesser extent, our other 2 business units. We did not go back prior to 2017 and apply that because they won't match our FERC filings and so forth from those years.
Okay. But in terms of the numbers that you presented to us today, 2017 is a clean starting point?
You'll find them in the press release.
Yes, '17 is clean corporate allocations for the subsidiaries other than these coops which obviously we removed it.
Okay. And then going back to the Arkansas rate case, it's a pretty big number. As you mentioned, it does not include a benefit from tax reform yet. What are kind of the main drivers of that ask capital O&M sales volume, et cetera?
Yes, the one single issue there was, we spent $160 million in that territory since we bought it. The growth there has been fantastic. So that's a big piece of it. We actually need and are requesting additional labor resources to keep up with the growth there. Those are really the bigger drivers, then obviously, cost inflation and all the other pieces that typically make up our rate case request.
Okay. So it sounds like a combination of capital and operating expenses more so than sales volumes?
They are largely driven by growth and trying to keep up with the growth in the area, which I think is a positive.
At this time, there are no questions in the queue. [Operator Instructions]. And our next question comes from the line of Julien Dumoulin from Bank of America.
Just following up, can you break down a little bit the tax -- well, the change in guidance between tax reform and short-term interest? What was what? And then also, to the extent which you have a tax reform EPS impact expectation for '18, can you break that down a little bit more? I imagine the bulk of that, obviously, is the holdco offset as you said in your remarks by the unregulated businesses, but just wanted to clarify if there was any flow through on any of those unregulated businesses?
No, I don't -- no, we'll provide more detail there. I mean, we moved it down $0.05. It's a combination of interest expense and impact of tax reform, both of which were fairly minor. But we felt enough that we should move down a $0.05 on each end of the range.
Got it. But just to be clear about this, with respect to your forecasting in Nebraska and other states, that's still fairly on track versus what you guys had contemplated perhaps quarter-over-quarter?
And I'm seeing no further questions. I will now like to turn the call back to David Emery for closing remarks.
All right. Thank you. Thanks, everyone, for attending the call today and listening in. We appreciate your continued support. Have a great rest of your day.
Ladies and gentlemen, thank you for participating in today's conference. This concludes today's program, and you may all disconnect. Everyone, have a great day.