Black Hills Corporation (BKH) Q2 2018 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and welcome to the Black Hills Corporation Second Quarter 2018 Earnings Conference Call. My name is Daniel, 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. David Soderquist, Investor Relations Analyst of Black Hills Corporation. Please proceed, sir.

Thank you, Daniel. Good morning, everyone. Welcome to Black Hills Corporation’s Second Quarter 2018 Earnings Conference Call. 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 and Form 10-Q 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’ll now turn the call over to David Emery.

Thank you, Dave. Good morning, everyone. Thanks for attending our call this morning. For those of you following along on the webcast slide presentation, I’ll be starting on Slide 3. Today, we’ll follow a similar format, as we have in previous quarters. I’ll give a review of the second quarter, some highlights from the quarter. Rich Kinzley, our CFO, will give the financial update. And then I’ll discuss forward strategy, followed at the end by questions. Moving on to Slide 5, second quarter highlights. Starting with the utilities. Most of these highlights occurred during the quarter, but I will also mention a few that occurred during the month of July as well. On July 25, our South Dakota Electric subsidiary placed into service the first 48-mile segment of a planned $70 million 175-mile transmission line that will run from Rapid City, South Dakota to Stegall, Nebraska. The remaining segment of that line will be in service by the end of next year. On July 16, our Northwest Wyoming Gas subsidiary received approval of a rate review that had been in process. Those new rates will take effect September 1. And then early in July and in late June, we set new all-time peak loads for both of our Wyoming Electric and Colorado Electric subsidiaries. Moving on to Slide 6, continuing with the utilities highlights. On June 1, Rocky Mountain Natural Gas, which is our intrastate gas pipeline in Colorado, implemented new rates following the settlement of its rate review process. In mid-May, our Wyoming Gas subsidiary filed with the Wyoming Public Service Commission for a certificate of public convenience and necessity. We plan to construct the new $54 million, 35-mile pipeline in Central Wyoming outside of CASPER. That line will provide additional sources of natural gas supply, increased capacity into the area and also improve reliability for customers. We hope to have a decision from the Wyoming Public Service Commission in the fourth quarter of this year and construct the pipeline next summer, placing it in service by the end of next year. On April 25, our Colorado Electric subsidiary received approval from the Colorado PUC to contract with our independent power subsidiary, Black Hills Electric Generation, to purchase 60 megawatts of wind energy through a 25-year power purchase agreement. That additional 60 megawatts will make up the balance of what we need at Colorado Electric to comply with Colorado’s Renewable Energy Standard of 30% renewable energy by 2020. Moving on to Slide 7, still on utility highlights. During the quarter, we reached agreements with regulatory commissions in Colorado, Iowa and Nebraska to pass on to our utility customers the benefits of the 2017 corporate federal income tax reform. We reached a similar agreement with the commission in Kansas during the first quarter. So we’ve completed four states now. In addition, the benefits of tax reform were included in the rate reviews recently completed for Rocky Mountain Natural Gas and our Northwest Wyoming Natural Gas territory, and tax reform is also included in our ongoing rate review in process for Arkansas Gas. Related to tax reform, the Arkansas Public Service Commission recently issued an order that requires all investor-owned utilities to submit plans within 30 days on how they intend to pass on tax reform benefits to customers. Since we already have a rate review process pending, this recent request deals primarily with the tax reform impacts from January 1 until the date our new rates will become effective as a result of our ongoing rate review. So we’re reviewing that recent Public Service Commission order in relation to our current rate review, then we’ll decide how best to respond. Moving on to highlights for our Power Generation segment. As I noted previously, our IPP subsidiary was selected to provide a 60-megawatt wind farm to our Colorado Electric utility. Construction of that $71 million Busch Ranch II wind project is expected to commence next spring, and the project should be placed in service during the fourth quarter of next year. Slide 8, corporate highlights for the second quarter. On July 30, we amended and extended our $750 million corporate revolving credit facility, extending the term to July 30, 2023. We also amended and restated a $300 million term loan, which was due next year, now has a maturity of July 30, 2020. On July 25, our board declared a quarterly dividend of $0.475 per share, which is equivalent to an annual dividend rate of $1.90. And that dividend will be payable September 1. And then, finally, related to discontinued operations on the divestiture of our Oil and Gas subsidiary. As of the end of June, essentially all of our Oil and Gas assets have been sold. We have essentially one remaining asset, a couple little minor things. We expect to finalize that sale and complete all the final accounting in the third quarter, and our Oil and Gas office will close in August. As we wind down our Oil and Gas operation, I want to extend a sincere thank you to those employees for their contributions to the company over the years, and certainly their dedication to the work throughout this divestiture process. Selling the company is very difficult process, and I thank them for their efforts to make sure it gets done well. Slide 9 provides a reconciliation of our second quarter income from continuing operations as adjusted. Compared to the second quarter of 2017, you’ll see the most significant improvement being in our electric utilities. I will let Rich explain the additional variances in his financial update. Rich?

Very good. Thanks, Dave, and good morning, everyone. We did enjoy a solid second quarter earning $0.45 of EPS this year compared to $0.42 for the same quarter last year. And as Dave noted on the last slide, our electric utilities drove the improvement year-over-year. I’ll jump in on Slide 11, where we reconciled GAAP earnings to earnings, as adjusted, to non-GAAP measure. We do this to isolate special items and communicate earnings that better represent our ongoing performance. This slide displays the last five quarters and trailing 12 months as of June 30, 2018. As you can see, we did not have any adjustments this quarter. We did experience special items not reflective of our ongoing performance in each of the past four quarters. And as I reported in prior quarters, the first special item related to a one-time acquisition cost incurred as part of the SourceGas acquisition and integration. The remaining special items relate to income tax matters, including tax reform and the tax benefit of illegal restructuring effectuated in Q1 2018. These items were not indicative of our ongoing performance and, accordingly, we reflected them on an as adjusted basis. Again, our second quarter as adjusted EPS was $0.45 compared to $0.42 for the second quarter last year. At the bottom of the slide, you’ll see our EPS performance of $3.58 for the trailing 12 months, which represents 6% growth over $3.39 for the same period in the prior year. Turning to Slide 12. Slide 12 illustrates major drivers bridging the differences from Q2 2017 to Q2 2018. All amounts on this chart are net of taxes. You’ll note weather was a positive driver year-over-year at both gas and electric utilities, where we achieved margin growth despite recording revenue reserves in Q2 2018 related to passing tax reform benefits on to our customers. As Dave explained, we reached agreement in a number of our jurisdictions to pass the benefit of tax reform on to our utility customers, and continue to work with regulators on our other jurisdictions to complete this effort. Slide 13 displays our second quarter income statement. Gross margin increased $7.4 million year-over-year despite the revenue reduction related to tax reform. Operating expenses increased to support our growth initiatives. DD&A was up as a result of new utility investments. Operating income was down slightly, largely due to revenue reserves related to tax reform, which is offset by reduced income tax expense below the operating income line. Moving below the operating income line. Interest expense increased slightly year-over-year due to higher interest rates on our variable-rate short-term debt. As you know, the front end of the interest rate curve has risen substantially this year. Income tax expense was down from the prior year, driven by tax reform’s corporate rate reduction. Moving down to income from continuing operations as adjusted. We generated $24.3 million for the quarter, up over 5% from $23.1 million last year. You’ll note our diluted share count decreased year-over-year. This is due to the application of the treasury stock method related to the unit mandatory securities we issued in late 2015 to help fund the SourceGas acquisition. Until the securities convert to equity in November of this year, we are required to apply the treasury method of accounting, whereby we include a portion of the shares in our diluted share count. The number of shares we include is based on the average daily closing price of our stock during the reporting period. We added approximately 1.1 million shares to our diluted share count this quarter compared to approximately two million additional shares in Q2 last year. As I noted in our year-end earnings call, on February second, we are assuming approximately 56 million weighted average shares in our full year 2018 guidance, as we will have approximately 60 million diluted shares beginning November 1 after the conversion occurs. Considering the increase in as adjusted net income and reduced share count, as adjusted EPS grew $0.03 or 7%. I’ll now discuss each business segment. Slide 14 compares our electric and gas utility segment’s Q2 2018 gross margin and operating income to Q2 2017. And our electric utilities gross margin increased $3 million, and operating income increased $600,000. We saw the benefits of favorable weather, new transmission investment recovery and higher commercial and industrial demand. Also new this year in margin for the electric utilities is rent income for our new corporate headquarters, which is owned by South Dakota Electric, and charged out to all other operating subsidiaries. The net impact on consolidated results is awash. these gross margin increases at the gas utilities were partially offset by a reduced – by a reserve recorded to reflect tax reform benefits to customers. Operating expenses increased $2.3 million as a result of higher property taxes and depreciation on new utility capital investments. Moving to the right side of the slide, the results at our gas utilities for the second quarter reflected $5.5 million higher gross margins and a decrease of $1.7 million in operating income. Our gross margins were higher, driven by favorable weather, strong transport volumes and an increase in our capital right of recovery. Like the electric utilities, these gross margin increases at the gas utilities were partially offset by a reduced – by a reserve recorded to reflect tax reform benefits to customers. We saw an increase in expenses from higher employee and facility costs, along with an increased reserve for any collectibles on higher revenue. Additionally, depreciation was higher in 2018 as a result of new utility capital investments. As a reminder, our natural gas utilities generate nearly all of their earnings in the first and fourth quarter, with earnings near breakeven in the second and third quarters. Results for the second quarter met our expectations. Next, I’ll talk about weather impacts compared to normal at both our electric and gas utilities. The second quarter is composed of shoulder months outside the main cooling season at our electric utilities, which occurs in the third quarter, and heating season of our gas utilities which occurs in first and fourth quarters. Heating degree days were 1% below normal in Q2 2018 compared to 9% below normal in Q2 2017. Cooling degree days were 109% above normal in Q2 this year compared to 14% above normal in Q2 last year. While that represents a big increase on a percentage basis, there aren’t a lot of cooling degree days in the second quarter. So the outsized percentage increase minimally impacted margins. In total, weather positively impacted our Q2 gas utility margins by an estimated $300,000 and Q2 electric utility gross margins by an estimated $1.1 million compared to normal. The estimated positive EPS impact of weather compared to normal was $0.02 for the second quarter. And year-to-date, it’s approximately $0.07 positive. On Slide 15, you’ll see the Power Generation operating income decreased $1.3 million, primarily from increased maintenance expenses related to a planned power plant outage and higher depreciation. The Power Generation segment continued realized strong contract availability from its generating units outside of planned outages, and is positioned to continue its strong earnings and cash flow contributions. Also on Slide 15, you’ll see our Mining segment had a $700,000 operating income increase. For the quarter, revenue was $2 million higher, thanks to 4% more tons sold and 5% increase in price per ton. Operating costs increased by $1.3 million, primarily due to increased overburden removal and higher royalties and production taxes on the increased revenues. Our mine continues to perform at a high level, with sales almost entirely to on-site mine-mouth plants and roughly half our sales based on a cost-plus pricing methodology. Slide 16 shows our capitalization. At June 30, our net debt to capitalization ratio was 64%. That’s a 210 basis point improvement from year-end. That improvement was driven by the increase in retained earnings, thanks to strong earnings in the first half of 2018 as well as by year-to-date cash flows that allowed us to reduce our total debt from year-end. Our $299 million of unit mandatory securities are reflected as debt on our balance sheet until the units convert to equity on November 1 this year. After conversion, we expect our net debt to capitalization ratio to decline below 60%. While we may need to increase our short-term borrowings from time-to-time over the next 2.5 years to fund our forecasted capital expenditures, we don’t anticipate the need to issue any new equity to fund our currently disclosed CapEx. If additional capital investment opportunities emerge, it’s likely we will need to issue some equity to help fund these incremental expenditures. Our At-the-Market equity program is available if equity needs arise. Slide 17 shows our debt maturity schedule. The unit mandatories require us to remarket the debt, noted as a 2018 maturity on the schedule, which I’ll discuss on the next slide. And as Dave noted, on June – excuse me, July 30, we extended our $300 million term loan into 2020 and extended our revolving credit facility through mid-2023. We’re in good shape from a liquidity perspective, and our debt maturities are very manageable. Slide 18 references our equity units I mentioned earlier. Our $299 million of equity units settle with the issuance of new equity on November 1 of this year. Each of these equity units is comprised of a contract to purchase Black Hills' common stock and an interest in our 3.5% junior subordinated notes due in 2028. The junior subordinated notes must be remarketed no later than October 29, and we have elected to open our optional remarketing period effective tomorrow, August 8. The proceeds from the remarketing will be escrowed until used to settle the stock purchase contracts on November 1. In connection with this remarketing, we are considering upsizing the total issuance and using any additional proceeds to pay down short-term debt. Additionally, we prefer to exchange the junior subordinated notes for senior unsecured notes to simplify our debt portfolio. After we receive the proceeds from the settlement of the stock purchase contracts on November 1, we plan to use them to retire our 2.5% $250 million notes due January of 2019 as well as pay down short-term debt. With the reduction, the total debt outstanding and increase to equity, we expect our debt to capitalization ratio to drop below 60%, as I noted earlier. And also, as I mentioned, fully diluted shares will reach approximately 60 million at the settlement date on November 1. Slide 19 shows our investment-grade credit ratings. There were no changes during the quarter. We’re committed to maintaining our strong investment-grade credit ratings, and our forward forecasted metrics support those ratings. On Slide 20, we’re reaffirming our 2018 earnings guidance of $3.30 to $3.50 per share based on the assumptions listed on Slide 21. We’ve had – while we’ve had strong earnings performance in the first two quarters, we’re holding our guidance at the level initially issued. We have a major outage planned for the Wygen I power plant and some other substantial O&M projects in the second half of 2018. We also have six months of additional weather impacts to consider. Also, while we are not providing 2019 earnings guidance until we release third quarter earnings later this year, as you start thinking about 2019 EPS, remember that we will need to grow net earnings by approximately 7% to 8% to stay flat with our disclosed 2018 EPS guidance range due to the increase in share count from the equity units conversion I just described. I’ll turn it back to Dave now.

Thank you, Rich. Continuing on with the forward strategy, I’ll start on Slide 23. Consistent with what we’ve done for the past several years, we grouped our strategic goals into four major categories, profitable growth, valued service, better every day and great workplace, and with the overall objective being an industry leader in all we do. On Slide 24, from a strategy execution perspective, we’re focused on delivering strong long-term total shareholder returns. We plan to accomplish that by achieving a long-term EPS growth rate above the utility industry average, targeting a 50% to 60% dividend payout ratio, while retaining the flexibility to increase the dividend during periods of slower EPS growth, and continuing our track record of 48 consecutive annual dividend increases. On Slide 25, we’re currently in the process of transitioning our earnings growth drivers from an acquisition and integration focus, post the acquisition of SourceGas, now back to a more traditional utility strategy. In 2018 and 2019, we expect slower earnings growth as we’re entering test years, preparing for rate review filings. We’re commencing those rate review filings in certain jurisdictions. And as I already mentioned, we have a couple that are ongoing or completed a couple and have one that’s ongoing currently. Over the longer term, 2020 and beyond, we expect higher earnings growth, driven by strong capital investments to meet our customer needs, continued focus on standardization and efficiency improvements and more regular and frequent rate review filings. On Slide 26, as we focus on delivering strong long-term shareholder returns, our fuel and service territory diversity reduce our business risk and drive more predictable earnings. On Slide 27, our utility acquisitions over the years have created a much larger transmission and distribution system, both on the electric and the gas side. With that increase in size comes increased opportunity for investment to serve a much larger customer base. On Slide 28, strong capital spending has in the past and will continue to drive much of our earnings growth. We plan to invest more than $2.3 billion over the next five years to better serve our 1.25 million utility customers. At that level of investment, which far exceeds depreciation, that will help drive earnings growth into the future. Slide 29 provides a detailed capital spending forecast for our gas utilities. That breakout also includes kind of breakdowns by state, by investment type and by recovery mechanism. This quarter, these numbers have been increased, largely for the proposed Wyoming Gas pipeline project. Slide 30 provides a similar capital investment detail for our electric utilities. And then moving on to Slide 31, our regulatory update. That slide provides an update for our utilities, which highlights the status of our active rate review filings and most recently completed as well as federal income tax reform dockets by state. As I noted earlier, we have just one active rate review filing, that’s in Arkansas, and we’ve completed the process of determining the customer benefits resulting from federal income tax reform in four states so far. I’ve already noted the other key regulatory items on this page, with one exception, and that is related to our ongoing appeal of the Colorado Public Utilities Commission’s decision in our 2016 Colorado Electric rate case. We notified the PUC that we do not intend to pursue further appeals at the current time. That being said, we may, in the future, attempt to address the rate treatment related to our Colorado Electric gas turbine and future rate filings for Colorado Electric. Moving on to Slide 32. We have three different states in which we own multiple gas distribution utilities: Colorado, Nebraska and Wyoming. We strongly believe that consolidation of those entities within a single state will provide long-lasting benefits for all of our stakeholders. Consolidation simplifies the customer billing process and improves customer service. Having fewer jurisdictional entities lowers the risk, complexity and quantity of rate reviews, regulatory filings and reporting requirements, and it will also streamline our corporate processes and provide tax benefits. The timing for our consolidation request in each state will be driven by the need to file a rate review in that state. As a result, the timing will vary between the three states. On the bottom of that slide, we lay out all three states and our current plans regarding the required steps and the timing for consolidating our gas utilities in each state. Colorado will be first. We already need a rate review for our gas utilities there. So we intend to file a request to legally consolidate our two gas LDCs during the quarter, the third quarter. And once that’s approved, we intend to file a consolidated rate review request, hopefully prior to year-end of this year. Wyoming will likely follow next, hopefully with a consolidation legal filing in late 2018, and then the balance of the process during 2019. And then Nebraska, we’re still evaluating our timing there. Moving on to Slide 33. We’re extremely proud of our annual track record of dividend increases, including the stronger increases we’ve had in the past several years, which reflect our confidence in strong future earnings and cash flow growth. As I noted earlier, we have the flexibility to use larger dividend increases during periods of slower earnings growth to help deliver solid total shareholder returns. Even after the relatively strong dividend increases over the past several years, we still remain well within our targeted 50% to 60% dividend payout range. On Slide 34, we focus every day on operational excellence. Our safety performance continues to be really exceptional. Our Wyodak Mine recently was awarded the Governor’s Workplace Safety Award for the fifth consecutive year, truly an extraordinary accomplishment by that group. We’re also proud to have recently received recognition as one of America’s best employers and the most trusted Midwest utility brand. Slide 35 is our scorecard. This is something we’ve done for quite a few years now. It’s our way of holding ourselves accountable to you, our shareholders. As we accomplish our objectives for the year, we literally will check the boxes and demonstrate our progress to you, so you can keep this accountable for managing the business. That concludes our prepared remarks today. We’d be happy to entertain any questions.

[Operator Instructions)] Our first question comes from Michael Weinstein with Credit Suisse. Your line is now open.

So the – you’re going to file for the reconciliation filing first in Colorado soon. And then after that, you’ll file for a rate case for the combined entity once it’s completed. Do you have any kind of like indication of timing between those four different filings, and when we can expect the full filing?

Well, we would hope to – the first filing is basically to consolidate the two legal entities. And once that’s approved, which hopefully will be a relatively straightforward process, we would hope to file the combined rate review request in the fourth quarter of this year.

Got you. Separate question. On Page 51, you note that the Wygen I plant has a purchase option that goes to 2019. And I’m wondering, is there anything you could tell us about the resource planning process in Wyoming currently? And what kind of considerations are being given for this plant to possibly be a rate base at some point?

Yes. We’re in the process of working on our Electric Resource Plan for our Wyoming Electric utility right now. We would expect to kind of wrap up that process close to year-end. And hopefully, included in that will be a recommendation related to Wygen I, whether we would extend that contract or whether we would seek to rate-base it. Those things will all be included in that resource plan.

Is there – what other kinds of considerations might go into that? Would you have to have a competitive RFP attached to that?

Yes, it’s possible. It really depends. I think that’s an extremely economical resource. It’s a great baseload resource. It’s been part of Cheyenne’s portfolio since it came online in early 2003, very – meets a very critical need for them. If we were to transfer it from IPP, if you will, to a rate-based asset that would likely require some approval by FERC and other things, we’ll probably need at least a market comparison there. But we’re still in the process of evaluating that whole process of what it would take, but likely would have to do some kind of a market comparison with the competitiveness of the resource.

Okay thank you very much.

Thank you. And our next question comes from Julien Dumoulin-Smith with Bank of America Merrill Lynch. Your line is now open.

Good morning can you hear me? So just following up on some of the comments you just made. Just want to

Good morning Julien.

So just following up on some of the comments you just made. Just want to elaborate a little bit on additional equity. Obviously, you have the process of Wyoming from a generation perspective ongoing. Is it basically outside of the time line for frac wage just as your balance sheet either sort of – you see improving cash flows? Or would that apply here per your prior comment?

Yes. We have to see what the ERP shows us when we get that filed and done, Julien. We know have other large projects. We’re working on two. Certainly, the addition of $125 million to CapEx this year between the Colorado IPP project and the Natural Bridge has kind of pushed us to the point where we have to – for future major capital additions, we’re likely going to have to sprinkle some equity in to help fund those. But as I said earlier with our currently disclosed CapEx.

Got it. All right. Excellent. And then just following up here. For 2019, I know it’s a little early, but just wanted to understand the factors in the second half of the year here. You talked about an outage presumably. Can you elaborate on what the impact is on earnings in 2H 2018? And also to the extent to which we’ll roll forward on 2019, obviously, we’ve got the dilutive impacts, anything else we should be considering to keep in mind as you roll forward there?

I don’t think there’s anything to really keep in mind, Julien. I think, basically, we talked about the couple of things that are planned for the second half of the year, basically is the reason why we’re leaving guidance on where it is, even though we’re off to a pretty good start for the year. We do have a planned outage at Wygen I and a couple other O&M projects that will likely be slight negatives in the second half. So we’re maintaining our guidance level where it is. Plus, we’re early in the summer cooling season until we get through July and August and early September in particular, never know how electric loads will develop. So that’s critical. But basically, we’ve decided to maintain our guidance where it is for those factors. But 2019, as Rich said, with the dilution of the equity units, we’ve been talking about this for over a year now, we’re going to have to drill 7% or 8%, which is a pretty hefty clip to maintain 2019 in line with our currently disclosed guidance for 2018. But that’s not new news. I mean, we’ve been talking about that for a while.

Excellent. Yes. No, absolutely. Can I turn back to the Arkansas Gas? Just noticing low revenue – lower revenue requirement or revenue number in the slides. Just what is that related to, the 30 going to the 2018? If I can follow up there. And then separately, maybe just on the regulatory front. Can you comment a little bit on thoughts on equity ratios across your jurisdictions, especially Colorado, you see to make that filing later this year on a consolidated basis?

Well, in Arkansas, that’s predominately tax reform, Julien, because the initial filing was before we did it in early December, ahead of tax reform. So it’s nearly all tax reform. On the capitalization ratios, each quarter, we’re looking at all our subsidiaries and capitalizing appropriately. I don’t know what beyond that you have for question there.

Well, as I said, I was thinking. A lot of your peers have been filing for higher equity ratios across their jurisdictions as they go back in and, obviously, to the extent to which you’re collapsing these utilities that the capital structure itself might be somewhat evolving as well. So I figured just asking on the equity ratio, specific to Colorado in this instance.

I mean, in general, we finance each individual utility separately within our company notes, independent of the consolidated capitalization. We generally try to maintain between a 50% and 54% equity ratio at our utilities. And I don’t think we have any goal of radically ratcheting that up, for example, but we’d like to maintain in that ratio. Obviously, a little bit on the higher end is good. We think that’s a prudent way to capitalize those utilities, and we will continue to do so.

Sorry. And one quick cleanup from the last question from Mike. Just in Wyoming on the process, how does the PCA figure into the map around potentially bringing Wygen into the fold?

Yes. I think if you look at the Wygen I contract today, part of that process of going through the resource plan and making the decision, whether you recontact or extend the contract or rate base is a comparison between the contract price and what the cost would be to customers under rate basing. That contract was entered into way back in like 2001, and then amended several years ago. It’s got a relatively decent price to it. Would probably be better long term for customers to have a rate-based asset, but that’s part of the process we’re going through now to determine that with certainty prior to making a decision on resource plan recommendations.

Excellent David thank you very much.

Thanks.

And our next question comes from Lasan Johong with Auvila Research Consulting. Your line is now open.

David, the consolidation of the gas utility is a great idea, but you didn’t mention whether would cost do all that – I mean, what kind of savings will achieve?

We haven’t specifically talked about it, Lasan, as far as the savings. I think a lot of it’s going to be ongoing O&M savings and ongoing filing savings, make it a lot of simpler for customer service, for example, where we have multiple pairs in the same states. The regulators on their side, obviously, a lot less rate cases, less regulatory filings, routine filings and otherwise. We’re trying to do to – change the timing or plan the timing, such that it’s not a special standalone process. So when we need a rate review in that state anyway, we’re going to go through the process of consolidating. So we’re hopeful that by doing it, when we need a rate review anyway, we’ll reduce the amount of incremental cost of actually consolidating the entity. Might be a little more testimony, a little more completed rate case, but in general, shouldn’t add significantly to the expense of going through the process.

Great. Is this pertaining to creating one utility, gas utility for the whole Black Hills complex? Or are you going to keep them state separately?

By state.

So you’re going to keep it by state separately? So there’s no consolidation beyond the – within the inside of the state?

That’s one of the advantages I think we have, Lasan, as we really only have one entity that crosses state lines from an ownership standpoint. So it makes the regulatory process a lot simpler. We’re not the fighting between jurisdictions on expectations for regulators, et cetera. Each state would be set up as a separate gas LDC. Now it’s set up that way. We just got multiple LDCs in three of those states. But it’s a lot more straightforward from a regulatory perspective, and a lot easier to manage. And frankly, it helps mitigate business risk.

I Yes, that make sense, perfect sense. Just a couple of administration stuff. Peak load, do you guys existentially assist the problems, particularly from wind?

No. The peaks went fine. As it usually occurs for us when we set a new peak load, either winter or summer, we usually get very little contribution from our renewable resources. They weren’t zero – they weren’t zero this time, but they certainly weren’t at capacity either. Generally, when we have real hot days or real cold days in our part of the world, that has a tendency to be quite still. So we have plenty of other resources to fill in the gap on those days.

And lastly, just general overall question. U.S. economy seems to be accelerating. Do you see any kind of demographic changes, either service territories for the better or for worse? I have seen for the better, if anything.

I don’t think so, no. I would say, overall trends, service territory is pretty stable. We have good growth going on. But in some of our territories, China and Wyoming has been growing strong, Colorado Gas in particular is growing very well, kind of slow and steady in South Dakota, but no major shifts in demographics, politics, et cetera. I would say it’s kind of status quo, the way they have been for the last years. So it’s pretty consistent.

That’s great. Thank you very much,

[Operator Instructions] Our next question comes from Andrew Weisel with Scotia Howard Weil. Your line is now open.

Thank you, good morning guys. First question is a few small moving parts in the CapEx plan for 2018 to 2019. I’m looking at pages 28 and 44 in the slides. So you were pretty clear that the overall increase of about $50 million in 2019 related to the gas pipeline. I understand that. It looks like you added around $12 million of Mining CapEx this year, and pulled about $19 million of CapEx at Power Generation from 2019 to 2018. Sorry if I missed it, but what explains those two deltas?

Well, the $12 million on the call is we bought a new shovel that’s going to help us be more productive in the future. It was a good opportunity, so we jumped on it. That will be in service by the end of the year. And then the acceleration on the Power Gen is related to the Peak View Wind or the Busch Ranch II wind farm that we announced earlier this year. We’re going to more of that done this year. So we’re just pulling it forward from next year into this year.

That makes sense. Okay. next question is on the jurisdiction simplification update. You’ve previously talked about ballpark of average of two rate cases per year. If all of these consolidations go forward, how should we think about an approximate pace of filings for the larger combined entities?

It’s really driven by spending levels and investments in those territories. We’re doing everything we can to try to control the O&M side of the equation. So the rate case timing by state will be driven by the growth and spending required in those states. So it’s really hard to make a generalized statement. Certainly, as we consolidate entities, we’ll reduce the number of rate cases. We said with the current number of entities we have, we’re probably looking at running two or three rate cases a year. As we keep consolidating those entities over the next, say, three years or so, it will reduce the number of rate cases. The timing, again, is going to be dependent on growth in each individual territories, some maybe 4, 5, 6 years in between, some maybe as close as 2 or 3. States like Arkansas, for example, we bought it two years ago, and we already spent $160 million on the system there, and needed to file a rate case. So it’s really going to be dependent on the level of investment required to keep up with customer demand in those states.

That makes a lot of sense. And then lastly, if you’re able to comment, we see some media reports about Pueblo having a meeting next week to discuss potential meetings utilization. Any high-level thoughts on maybe your interest in divesting, your ability to prevent that? Or any similarities or differences versus some other instances of similar decisions from Colorado cities?

Yes. We’ve been in active dialogue with the city of Pueblo. Our local leader there has spent a lot of time visiting with them about that. Our personal – our opinion, as a company, is that we really don’t have any interest to divest. We’re a utility company. We buy utility assets to grow as a utility company. The size of our current asset base helps keep cost low for all of our customers through shared services, et cetera. So it really makes no sense for us to divest a utility. We did respond to – I wouldn’t really call it a formal offer, but we got an inquiry from the local co-op there. I think in interest of trying to serve the city in our stead, it was woefully inadequate, and we responded and actually made the decision to publish that response letter in an 8-K. I think that pretty clearly lays out our position on interest in selling the business. We believe that we’re doing a good job managing the city’s electric supply. Circumstances required us to build a lot of generation in a short period of time. That is behind us. And so now we have the luxury of a little bit more stable rates with that capital investment already being made. We have the most modern fleet and cleanest fleet in the state, all renewables and gas-fired. It’s all new highly efficient, fuel-efficient and everything else. So we feel pretty confident that although our rates are relatively high – they’re not the highest in the area, but they’re relatively high in Pueblo, that the surrounding utilities will be catching to us as they modernize their generation fleets over the next several years, as we’ve already done. And they have to comply with the renewable standards and continue to deal with CO2 regulations, et cetera. So we feel pretty good about where we’re at there. We’re making good positive progress. It’s going to be a slow process. We take seriously the municipalization discussions in Pueblo, and we’re engaged in those discussions and we’ll continue to be. But our plan is to continue business as usual. If you want to look in an example of an attempted municipalization in Colorado, I think you could look at the highway at Boulder and see how long that’s been going on. And I think it’ll give you at least a relative sense of what it takes to actually accomplish that, which is basically how we kind of look at it.

Alright, appreciate all the time Emery.

Thank you. And I’m not showing any further questions at this time. I would now like to turn the call back over to David Emery for any closing remarks.

Well, thank you all for attending our second quarter call today. We very much appreciate your attendance on the call and your interest in Black Hills. Have a great rest of your day.

Thank you for your participation in today’s conference. This concludes the presentation. You may now disconnect. Good day.