Black Hills Corp (BKH) 2017 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Black Hills Corporation third quarter 2017 earnings conference call. My name is LaToya, 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, LaToya, and good morning, everyone. Welcome to Black Hills Corporation's third quarter 2017 earnings conference call. Before we begin today, I would like to note that Black Hills will be attending the EEI Financial Conference starting November 5 in Lakeway Buena Vista, Florida. The company will host one-by-one meetings and deliver a presentation to investors on Thursday, November -- or Tuesday, November 7.

Our presentation materials and webcast information will be posted on our website at www.blackhillscorp.com under the Investor Relations heading after market close today. 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 will now turn the call over to David Emery.

Thank you, Jerome. Good morning, everyone. Thanks for joining us for our third quarter call this morning. For those of you following along on the slide deck for the webcast, I'll be starting on Slide 3.

The agenda today will follow a format similar to that that we've follows in previous quarters. I'll give a quick update on the quarter, Rich Kinzley, our CFO, will give the financial update for the quarter and then I'll hit on long-term strategic issues and then we'll take questions.

Moving on to Slide 5, third quarter earnings per share from continuing operations as adjusted were $0.50 per share. That's about a 4% improvement compared to the $0.48 per share in the third quarter of last year. And despite that improvement, earnings were lower than our expectations.

From an operational and strategic perspective, however, we had a great quarter and we demonstrated really strong cost control while achieving excellent operational metrics such as power plant availability and safety. Also from a strategic perspective, we finalized a key decision to exit the oil and gas business. We increased our dividend for the second time this year and continued to make excellent progress on several other key initiatives including revising upward the future capital investment we believe will be necessary to serve our customers.

Third quarter highlights on Slide 5, starting with our utilities, on the 3rd of October, Rocky Mountain Natural Gas, which is our interstate -- intrastate -- gas transmission pipeline in Colorado, filed a rate review with the Colorado PUC, seeking to increase annual revenues by approximately $2 million. In September the Mountain West Transmission Group, which includes our 3 electric utilities of Black Hills Corporation plus 7 other electric providers in the region, announced its interest in joining the Southwest Power Pool RTO. If membership is deemed beneficial both by the members of the Rocky Mountain Transmission Group and the existing members of SPP, we'll prepare filings with FERC and state public utilities commissions in mid-2018, hopefully gaining approval and actually integrating our group into SPP in late 2019.

On August 4 our Colorado Electric subsidiary received bids related to a request for proposals we had issued earlier seeking another 60 megawatts of renewable energy resources that will be in service by 2019 in order to meet Colorado's renewable energy requirements. We are currently evaluating bids with the assistance of an independent bid evaluator, and we plan to present the results to the Colorado PUC by year end for their approval. We did submit some bids of our own into that RFP.

Moving on to Slide 6 and continuing with utility highlights, on July 19 our Wyoming Electric subsidiary set a new all-time peak load of 249 megawatts. That's more than 5% higher than the previous peak, which was set last July.

Shifting gears to the nonregulated side of the business, our oil and gas subsidiary, on November 1 our board approved the sale of all remaining oil and gas assets and an exit of that business. Beginning in the fourth quarter that segment will be reported as discontinued operations. We retained advisers to support our ongoing property sales efforts, and we plan to divest all of our remaining properties as soon as practical but no later than the end of '18. Very recently we signed agreements to sell our operated San Juan Basin natural gas assets in New Mexico and a portion of our Powder River Basin assets in Wyoming, namely a handful of operating oil wells and some exploration acreage, for a combined total of $28 million.

Moving on to Slide 7, corporate highlights for the quarter. On November 1 our Board of Directors moved up our 2018 dividend increase by 1 quarter and approved a 6.7% or $0.03 per share increase in the quarterly dividend to $0.475 per share. The total dividend payout for 2017 will be $1.81. Also during the quarter, both Fitch and S&P affirmed their investment-grade credit ratings for the company. We filed a new shelf registration statement and renewed our ATM equity program.

Slide 8 provides a reconciliation of our third quarter net income from continuing operations as adjusted compared to the third quarter of last year. As Rick goes through his financial update, he'll provide the details on the individual segments in his report.

I'll now turn it over to Rich. Rich?

All right, thanks, Dave, and good morning, everyone. I'll jump right in on Slide 10, where we reconcile GAAP earnings to earnings as adjusted, a non-GAAP measure. We do this to isolate special items and communicate earnings better representing our ongoing performance. We display the last 5 quarters and trailing 12 months as of September 30 for 2017 and 2016.

As detailed on the slide, we experienced special items not reflective of our ongoing performance in each of the last 5 quarters. The first special item is noncash asset impairments at our oil and gas business that occurred last year.

The second 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 nearly all the integration work related to the acquisition in 2016 and are finishing the few remaining projects in 2017. These acquisition-related costs and noncash impairments are not indicative of our ongoing performance and accordingly, we reflect them on an as-adjusted basis.

Our third quarter as-adjusted EPS was $0.50 as compared to $0.48 last year. Despite year-over-year growth, third quarter results fell short of our expectations, as Dave already mentioned. Specifically, we experienced lower gross margins at our gas utilities related to agricultural irrigation loads and that our electric utilities' commercial and industrial gross margin growth didn't materialize as we'd expected. As a result, we lowered our 2017 earnings guidance yesterday. I will discuss these variance items and our guidance for 2017 and 2018 in more detail on the following slides.

At the bottom of the slide we present EPS as adjusted for the trailing 12 months. As shown, we achieved EPS as adjusted growth of $0.58, a 21% increase for the trailing 12 months ended September 30, 2017, compared to the trailing 12 months ended September 30, 2016. The trailing 12-months earnings uplift is due primarily to a full 12-months ownership of the SourceGas utilities, which were acquired in mid-February last year.

Turning to Slide 11, you see our third quarter revenue and operating income compared to last year. On the left side of the slide you'll note that 2017 revenues for Q3 exceeded those in 2016 by 2.5% due to revenue improvements at each of our business segments except oil and gas. On the right side of the slide you'll see that year-over-year operating income increased by 4%. The operating income improvement was driven by increases at our electric utility, mining and corporate segments. These improvements were partially offset by quarter-over-quarter decreases in operating income at our gas utility, power generation and oil and gas segments. I'll discuss each of the operating segments in more detail later.

The corporate segment improvement relates to the reduction of internal labor charges in 2017 to acquisition and integration activities as compared to 2016. As I noted on the previous slide, with the integration of SourceGas substantially complete, our employees have largely moved on to other projects and initiatives and the associated internal labor costs have predominantly been charged to our utility segments in 2017.

Slide 12 displays our third quarter income statement. Gross margin is up 1% this quarter compared to the same quarter last year, reflecting improvements at the electric utilities and mining segments, with other segments essentially flat or slightly down. We reduced Q3 operating expenses compared to last year despite normal inflationary pressures as we continue to achieve acquisition-related synergies and other efficiency improvements. DD&A increased slightly on additional plant in-service balances. Before special items, operating income increased 4%. For Q3 2017, the only special item was minimal acquisition-related costs. Last year Q3 included special items for oil and gas impairments and more significant acquisition-related costs.

For below-the-line items, interest expense for the quarter was relatively flat to prior years. Q3 debt balances were consistent year-over-year. The effective tax rate for the quarter was 30.4%, below the 35% statutory rate. There are a variety of items contributing to the lower effective tax rate, the largest of which is production tax credits at our Peak View Wind Farm in Colorado. The line item for noncontrolling interest reflects our sale of a 49.9% interest in Colorado IPP in Q2 last year. I'll talk more about this on the power gen slide.

Moving to the as-adjusted net income line, we reported $27.9 million for the quarter compared to $26 million for Q3 2016, a 7% increase. Diluted shares increased by 1.7 million or 3% in Q3 2017 over Q3 2016 due to two factors. First, approximately 1.1 million additional weighted average shares are included in Q3 2017 compared to Q3 2016 from issuances of equity through our At-the-Market equity offering program in 2016.

Second is the accounting application of the Treasury stock method related to our unit mandatory convertible securities. We issued the unit mandatories in Q4 2015 to help fund the SourceGas acquisition, and these will be converted from debt to equity prior to November 1, 2018, 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 reference price, a portion of the dilutive effect is reflected in the fully diluted share count. With a reference stock price of $47.29 and an average share price of $69.42 in Q3 2017 and $60.92 in Q3 2016, we're required to add approximately 2 million shares to the Q3 2017 diluted share count compared to approximately 1.4 million shares in Q3 2016.

Finally, at the bottom of the slide you'll see that Q3 EBITDA increased by $3.1 million quarter-over-quarter, about 2.5% improvement.

Moving to Slide 13, on the left side it displays our electric utility's gross margin and operating income. The electric utility's gross margin increased $7.1 million in the third quarter over Q3 2016. The gross margin increase resulted primarily from returns on our Peak View Wind Project, which went into service in Q4 2016 and transmission and other investments. Operating income increased $2.6 million or approximately 5% for the third quarter compared to 2016. Operating expenses including depreciation were $4.5 million higher as a result of expenses associated with our new generation and transmission investments plus higher generation outage and major maintenance expense. Also, depreciation and property taxes increased over 2016, given the investments made.

I'll also note that a substantial component of the return on our Peak View Wind Project is realized through production tax credits, which are reflected in reduced income taxes rather than through operating income. These credits to our income tax amounted to over $700,000 in the third quarter and approximately $3.2 million year-to-date.

Moving to the right side of Slide 13, the results at our gas utilities for the third quarter reflect a decrease of $2.3 million in operating income. Q3 gross margin was unfavorable to last year by $2.1 million, primarily because margins from our agricultural irrigation customers were lower due to different weather conditions in Q3 2017 as compared to Q3 2016. This is our second year with the SourceGas utilities, and we continue to learn the nuances of these businesses compared to our legacy gas utilities.

The SourceGas utilities have a substantial number of agricultural customers who use natural gas to drive their irrigation units. Last year the weather was hot and dry in those service territories during the third quarter, which required heavy natural gas usage for irrigation. This year the weather was more normal in those service territories. We estimate the impact of reduced irrigation to our gross margins was more than $3 million negative, comparing Q3 2017 to Q3 2016. On the expense side, gas utility operating expenses were effectively flat year-over-year for Q3.

Because 2017 is the first complete year of our ownership of the SourceGas utilities, I'll expand on the September year-to-date results at the gas utilities. The gas utility saw an increase of $22.6 million in operating income comparing the first 3 quarters of 2017 to the first 3 quarters of 2016, with most of this increase attributed to the addition of SourceGas. We closed the acquisition on February 12, 2016, so we picked up 42 days of SourceGas operating results in Q1 2017 as compared to last year. At our legacy Black Hills gas utility operations, operating income improved by over $7 million for the first 3 quarters of the year, a 13% growth rate year-over-year, benefiting from strong cost management as well as synergies realized from the SourceGas acquisition.

Next I'll talk about weather and its financial impacts at both our electric and gas utilities when compared to normal. In the third quarter our electric and gas utilities results were not materially impacted by weather other than related to the irrigation load I just talked about. Year-to-date through 9 months, weather negatively impacted our gas utility gross margins by an estimated $6.3 million and our electric utility's margin by an estimated $1.2 million, mainly due to mild weather during the heating season in the first half of the year. As I noted earlier, the irrigation customers used less natural gas irrigating their fields this year compared to last year, negatively impacting margins by $3 million year-over-year for Q3. It's difficult to compare actual irrigation load to a load resulting from normal weather, but we believe this year's volumes for that particular load were close to normal.

On the left side of Slide 14 you'll see that power generation was flat year-over-year. The power gen business unit continues to realize strong contract availability with its generating units and continued its cash flow contributions to Black Hills. Our power generation segment includes the Colorado IPP Plant, which is contracted to our Colorado Electric utility, plus the Wygen I Plant, which is contracted to our Wyoming Electric utility.

Colorado IPP accounts for approximately 60% of the operating income in our power generation segment. The numbers reflected on Slide 14 include 100% ownership of Colorado IPP. In April 2016 we sold a 49.9% interest in Colorado IPP. We consolidate 100% of Colorado IPP's results in our financials and then back out the 49.9% noncontrolling interest at the bottom of the income statement.

On the right side of Slide 14 you'll note our mining segment had a slight increase in operating income compared to the third quarter last year. Our mine continues to perform at a high level, with sales almost entirely to onsite mine-mouth generation and roughly half our sales based on a cost-plus contract pricing mechanism.

Moving to oil and gas on Slide 15, we had an operating loss in the third quarter of $1.9 million compared to an operating loss of $1.4 million for Q3 2016 excluding asset impairment charges taken last year. Third quarter volume sold decreased as oil and gas production declined from the prior year, primarily due to property divestitures. The decrease in revenue from lower volumes was partially offset by lower operating expenses and lower DD&A. Since we now formally plan to exit the oil and gas business, we will begin to report this segment as discontinued operations beginning in the fourth quarter.

I'll point out that as you look at the historic and forward earnings benefit to consolidated continuing operations once oil and gas is reported as discontinued, it will not be as simple as adding back the operating loss from this segment. Approximately half of the $7.5 million year-to-date operating loss from our oil and gas segment is a result of allocated corporate costs. Beginning with our reporting of fourth quarter results in our 2017 10-K, most of these allocated costs will be retained within continuing operations since they will continue to be incurred and will be reallocated among our remaining business units. Dave will talk more about our exit strategy for the oil and gas segment shortly.

Slide 16 shows our capitalization. As we look through 2018, we expect our debt-to-total cap ratio to decline through growth in stockholders' equity from earnings. We don't expect to add any significant debt in the near term, as our internally generated cash flows will largely fund our CapEx and dividends through 2018. Additionally, the $299 million of unit mandatories I mentioned earlier are reported as debt on our balance sheet until the units convert to equity. By year end 2018 we expect our net debt-to-cap ratio to be under 60%.

I'll also mention that on the equity side, we haven't issued any shares under our At-the-Market equity offering program in 2017. As Dave mentioned, we renewed the program and we'll keep it active to provide financing flexibility as we move forward, but we intend to issue very few if any shares through the program in the near term.

Slide 17 demonstrates that we're in good shape relative to upcoming debt maturities. In the first quarter last year we executed significant debt financings to help fund the SourceGas acquisition. In the third quarter last year we accessed the debt markets at a time when credit 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 this year, which helps minimize short-term borrowing costs.

Slide 18 shows our current credit ratings. As you can see on the slide, Fitch recently affirmed their BBB+ rating with a stable outlook, and we are rated BAA2 with a stable outlook from Moody's and BBB with a stable outlook from S&P. We're committed to maintaining our investment-grade credit ratings with BBB flat to BBB+ equivalent being our target. Our forward-looking metrics support these ratings.

Slide 19 illustrates our track record of growing operating earnings and EPS. Our history shows periods where our earnings growth is occasionally lower for short periods of time, but our long-term trend of growing earnings is excellent.

Moving to Slide 20, we reduced our full-year earnings from continuing operations as adjusted to a range of $3.30 to $3.40 per share. We lowered our 2017 range to reflect a number of items. First, the negative impact from the lower agricultural irrigation demand in our gas utilities in Q3 relative to our performance in the prior year, as I mentioned earlier. Second, our forecast utilized for the previous earnings guidance range included commercial and industrial load at our electric utilities that didn't materialize. Third, we included pricing and volume assumptions for some of the SourceGas utilities that did not properly reflect the tariffs in place.

Our aggressive synergy realization and cost control across the organization in 2017 masked the fact that these gross margin assumptions were not being fully realized through the first half of the year. However, as we closed the books for the third quarter, it became apparent that actual margins were short of our expectations.

Additionally, we've had to recognize approximately 600,000 more shares in our diluted share count in 2017 than what our original assumptions included due to our strong year-to-date stock price performance and the resulting impact of the Treasury stock accounting method associated with our unit mandatory securities. Finally, our June 2017 settlement agreement with the South Dakota PUC requires us to amortize certain costs over 6 years beginning July 1, 2017, resulting in approximately $1.3 million of additional amortization in 2017 that our original assumptions did not consider. We have updated all these assumptions for the remainder of 2017 and in our 2018 earnings guidance.

Which brings me to Slide 21. In yesterday's press release we initiated our guidance for 2018 earnings from continuing operations as adjusted to be in the range of $3.35 to $3.55 per share. The assumptions for the 2018 earnings guidance range are listed in the press release and on Slide 21.

One item I'd like to further clarify is the effect on our share count related to the unit mandatory securities. When we do the conversion from debt to equity, 6.3 million shares will be added to our basic share count. As I noted earlier, we are already phasing in some of this dilution into our share count in 2017 to the tune of roughly 2 million shares. In 2018 until the conversion occurs, we will continue to apply the Treasury stock method of accounting for these securities.

So as an example, if we did the conversion on September 30 of 2018, for the first 3 quarters of 2018 we would apply the Treasury stock method, and then for the fourth quarter we would see the full impact of the 6.3 million shares. When you do all that math in very round numbers and assuming a consistent stock price, approximately 2 million shares of the dilution from the unit mandatories will impact 2017, approximately 3 million shares of dilution will impact 2018 and the full 6.3 million share dilution will be reflected in 2019. Of course, the number of shares ultimately recognized in our fully diluted share count will depend on the timing of the conversion and the actual average share price until the conversion occurs.

In closing, I'll mention that we've continued to refine the CapEx opportunities across our utility service territories and have increased 2018 CapEx in our assumptions from the levels we disclosed at Analyst Day in early October. Dave's going to cover this in more detail shortly, but the increased CapEx, combined with the increased dividend, will continue to deliver value for our shareholders.

And with that, I'm going to turn it back to Dave for his strategic overview.

Thank you, Rich. Moving on, long-term strategy on Slide 23. Consistent with the last several years, we group our strategic goals into 4 major categories -- profitable growth, valued service, better every day and a great workplace -- with the overall objective of being an industry leader in all that we do.

Slide 24. We discussed this concept quite a bit at Analyst Day, but from a strategy execution perspective, there's really 3 key issues listed on this slide and in the 2 that follow. First, we target a long-term total shareholder return in the top quartile of the industry. We plan to accomplish that by achieving long-term earnings per share growth in the top quartile, targeting a 50% to 60% dividend payout ratio while retaining the flexibility to increase the dividend during periods of slower EPS growth, and then we plan to continue our track record of 47 consecutive annual dividend increases.

On Slide 27, the second item related to strategy execution, we are in a period for the next couple of years where we're transitioning our earnings drivers from an acquisition and integration focus back to a more traditional utility growth strategy. So since closing the SourceGas acquisition in February of '16, we've had relatively slower earnings growth expectations, a heavy emphasis on SourceGas acquisition and the associated integration savings, a very focused capital spending to reduce regulatory lag and minimal rate review filings.

Over the next couple of years we'll be transitioning back to relatively higher earnings growth expectations, much stronger capital investments to meet our customer needs and more regular rate review filings associated with that capital investment. We will still focus on further business standardization and efficiency improvements as we go forward.

On Slide 26 related to strategy execution is that our fuel and service territory diversity really reduces business risk and drives more predictable earnings. We like both the diversity in fuel between the gas and electric and our diversification by regulatory jurisdiction. No single state has a huge impact on our overall results.

Moving on to Slide 27, our past utility acquisitions 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. Our long-term capital investment requirement to serve our customers is even greater than we thought when we purchased and integrated SourceGas.

Moving on to Slide 28, strong capital spending has and will continue to drive much of our earnings growth. Since the second quarter results and our announcement and our Analyst Day discussion, we've continued to refine our capital investment needs that will be required to serve our customers into the future. As a result of that review, we've increased our forecasted 2017 through 2019 total capital spending by an additional $100 million to a total of nearly $1.3 billion. A lot of that capital will be spent on growth and line replacements in our gas utilities as well as additional transmission and other items on the electric side.

Slide 29 illustrates our historical capital spending and depreciation amounts. Importantly, capital spending far exceeds depreciation, helping contribute to both rate base and earnings growth.

Slide 30 provides a regulatory update for several of our utilities. We're continuing our appeal of the Colorado PUC's decision related to our 2016 rate review. That review was related primarily to a simple cycle turbine we added at our Pueblo Airport Generating Station. In July we filed an appeal with the Denver County District Court. The briefing schedule related to that filing runs through November, and then the timing of a ruling is uncertain thereafter.

As I mentioned earlier, Rocky Mountain Natural Gas filed a rate review request with the Colorado PUC to recover a lot of investments we've made for safety and integrity of our pipeline system during the last 3 years. That review seeks to increase annual revenue by $2 million.

And finally, we expect to make 2 additional rate review filings prior to the end of 2017. One of those is for our Northwest Wyoming Gas utility that we acquired back in 2015, and the other is for the Arkansas Gas utility that we acquired from SourceGas. We've seen very strong growth in our Arkansas service territory, driving added expenses and a lot of capital investment.

On Slide 31, as I stated earlier, we plan to exit the oil and gas business before the end of 2018. To that end, we continue to divest assets, recently agreeing, as I said earlier, to sell our San Juan Basin assets in New Mexico and some of our Powder River Basin assets for a combined $28 million. Both of those deals have been signed and not yet finally closed.

Slide 32 illustrates our progress towards divesting our oil and gas wells. We showed this slide at Analyst Day, and it previously illustrated progress towards divesting noncore assets only. With the recent decision to exit the business, we've revised the slide to illustrate our progress toward a divestiture of all oil and gas properties. As you can see, we've already sold nearly half of our total properties in the oil and gas segment.

On Slide 33 related to the dividend, we're extremely proud of our dividend track record. We've increased our annual dividend to shareholders for 47 consecutive years. Also, as I noted earlier, we have flexibility to use relatively larger dividend increases during periods of relatively low earnings growth. As you can see, even after 2 relatively large dividend increases during 2017, we're still well within our targeted 50% to 60% dividend payout range, giving us future flexibility as well.

On Slide 34 we focus every day on operational excellence and also focus on helping our nearly 800 communities that we serve to grow and thrive.

Slide 35 is our 2017 scorecard. This scorecard's our way of holding ourselves accountable to you, our shareholders. We've done this for several years now, where we set forth our goals at the beginning of the year and provide regular updates to you related to our progress.

Finally, in conclusion, while our near-term's earnings guidance is lower than we would prefer, the flexibility we have to raise the dividend, the increased capital necessary to serve our customers and the exit of the oil and gas business set us up to continue delivering excellent long-term value for our shareholders.

That concludes our remarks. We're happy to take questions.

[Operator Instructions.] The first question comes from Michael Weinstein of Credit Suisse. Your line is now open.

First question about the comment you made about gross margins at SourceGas not being what was expected for the first part of the year and that they were being masked by synergies. Maybe you could clarify that a little bit more. I'm assuming that unless you're trying to say that the synergies are disappearing going forward, shouldn't the masking continue? What exactly are you saying about forward guidance, and are you going to have to restate anything for the previous part of the year?

No, no. I think the comment was more that we've done a really good job achieving the synergies, the targets that we thought we were going to hit with the acquisition we have. And earnings through 2 quarters were what we expected. The third quarter is when you have a lot of construction going on. There were some commercial loads that we expected in industrial in our electrics that just haven't materialized. And then the irrigation issue that I talked about a couple times during the call surprised us in the third quarter when we closed the books. Those are the big drivers. Dave, would you add to that?

Yes, no, that's right, Mike. I think if you look at the SourceGas acquisition, I would say some of the agricultural loads in particular, we're probably not as accurate at forecasting as we would like to be. We're getting a lot better at it very quickly, but it's been a bit of a challenge for us. That's a much larger portion of their business than it was of ours in some of those same states.

That being said, I think as we look at the capital investment opportunities for the SourceGas properties we've acquired, we're very excited about those. And that's driving part of the increase in the $100 million in capital spending in the next couple of years. States like Arkansas are growing very rapidly and we're excited about that. Overall, I'd say net positive. Timing's the issue.

What about the fact that 2018 guidance is only about 3% above 2017 guidance? So those factors are going to continue into next year in your guidance? Is that the right way to think about it?

Yes, I think Rich made the comment that all those adjustments that we made, we've made on a forward basis. To the extent that they continue -- they don't all; some of them are more short term and some are longer term -- we've tried to account for all of that. As we've gone through all that, then we've revisited -- and we talked about this a little bit at Analyst Day -- we've revisited our schedule when we're going to need rate reviews in all of our jurisdictions. That's based on capital investment, cost trends, revenue trends, et cetera. A lot of the increase in capital spending is driving a need for rate cases earlier than we thought we would. So that's changing the dynamic on when savings are realized versus when a capital investment and the increase in rate base is realized. The timing's changing of some of those things, largely due to an increase in capital spending that's been necessary sooner than we thought it was going to be, which is a good thing in the long run. It's just a timing issue.

Which negative factors do you think will disappear or could disappear, get mitigated, by 2019?

Some of those, it's hard to say, but certainly weather's a variability that -- our ability to forecast it, I think, is getting better and understand what it means, particularly on the agricultural side. The other factors, I think we continue to work on costs; we continue to work on standardization of our business. That's very helpful, and we've got several initiatives on that front. So I think as time progresses, we'll continue to get more and more efficient. Those things, I think, will continue forward in a positive way. We have revisited our load forecasts and things. Some of those are timing; some of it's load that we just don't think is going to show up. We visit with customers every year and prepare those forecasts based on what they know about the business. We generally review those ourselves and handicap them some. They're typically always more optimistic than we are. But in this case, some of those loads will materialize just later and some of them won't materialize at all, or not for several years. And we've tried to build all that into our forward forecast.

And when you think about your top-tier earnings growth target, is that a 3-year target or a 5-year target? Maybe you could give a little more clarity about how you're thinking about that.

We use the term long term, which means it certainly isn't a 1-year or a 2-year, but it's a rolling, probably 3- to 5-year period. We're not defining it super robustly. But when you look at utilities, there's typically fluctuations in earnings from year to year, given build cycles, et cetera. So averaging over at least a 3-year window, I think, is appropriate, and depending on what's going on, maybe a year or 2 longer than that. But we feel pretty good about our ability to invest that capital, and it's needed to serve our customers and realize the benefits from doing that.

And on the apparent drag that's going to remain after the sale -- or disposition of E&P, it's about $0.05? Am I reading that right from what I heard?

About half of what our loss is for this year, roughly.

$0.10 is the loss, right? So half of that.

Well, we're $7.5 million operating loss through 3 quarters. That's probably fairly linear for the year, and about half it's retained.

Got it. One last question, then I'll give it to somebody else. With a little bit of a struggle in understanding the margins coming from SourceGas, does this -- and the longer period, I think, it's going to take to get to top-tier earnings growth with the existing assets, how does this change your view of M&A going forward? Because I think in the past you've been kind of indicating that you're interested in it, and I'm wondering if that's changed now.

Yes, I don't think it's really changed our outlook on M&A at all. You know what we said earlier and we had a good discussion about this at Analyst Day, is the smaller things that we can buy easily, given our capital structure today, and integrate them quickly, we will continue to look at those, and we are. We keep looking at some of the smaller municipal systems and other things.

The larger transactions, until we get our balance sheet back a little bit closer to where we need to be from a debt-to-cap standpoint -- which will be later this year or next year when the equity and its convert -- it's going to be hard for us to compete for a large one. We just wouldn't be able to apply the leverage necessary to be competitive if it's an open-bid type process, which we've been seeing pretty frequently lately. So I don't think it has any bearing on our readiness to acquire or anything else. I think we're pretty confident in our ability to buy and integrate utilities. It's just the timing's kind of the same as it has been for the last year or so when we've had those discussions.

I'll add to that. We've been pretty clear, it's got to be the right fit if it's a big one, which SourceGas was. We still feel very good about that acquisition because of the capital opportunities Dave's talked about and the synergies we've already achieved. But looking forward for a big one, it's got to be the right fit. We're not looking to buy anything. It's got to be the right fit.

We'll be very disciplined.

Right.

The next question comes from Insoo Kim of RBC Capital Markets. Your line is open.

Maybe just to follow up on Michael's question on the stuff that goes into the drivers for the guidance, I know it's agricultural customer impact, some C&I low growth and then the margin stuff that you mentioned. So I guess that implies that the O&M synergies that you guys have achieved are still there, which means when you are going in for rate cases in the next year or so, you'll still have to work through managing the give-back of the O&M synergies while you earn -- while you're offsetting that with CapEx. Is that a fair assumption?

Yes.

Yes.

Got it. And then just the level of the margin stuff that you mentioned -- was it -- it seems like that's still the bulk of what made the change given, I think, the agricultural customer stuff was $3 million impact for the quarter? I don't know if you detail what the C&I low-growth changes were versus prior...

We have not. No, we have not.

Okay.

But the items that Rich mentioned were the key drivers, obviously.

Got it. And then as you said, the E&P, the $0.05 to $0.06 of benefit is already incorporated into '18? It just seems like, when I was doing back-of-the-envelope math on the guidance that you guys gave, initially it seemed like a reset of the allowed -- the earned ROE's closer to the allowed. But with the -- I'm just a bit confused because on top of that, it seems like there's comments on the margin assumptions that are going to change, so I don't know how that fits into your thinking. Just kind of stating my mind, so I'm -- it's a long-winded process to say I'm a bit confused.

Yes, a lot of it, I think, Insoo, is kind of related to the explanation I gave Michael, and that is the timing. We've spent more money and invested more things sooner than we thought we would have to, which is driving us to file for rate reviews sooner because we've made a lot more investments for our customers sooner than we originally thought we would have to. In the grand scheme of things, that's very positive. It's just essentially a timing difference. So your question on synergy retention versus the next rate review and the capital investment that offsets that from a revenue standpoint, that's really the issue. It's about the timing of that occurring more so than anything else.

The next question is from Julien Dumoulin-Smith of Bank of America. Your line is open.

So I don't mean to beat too much on this, but I'd love to hear. How do you think about the year-over-year comparison of average share increases outstanding into 2019 versus '18? Obviously, given the commentary for a little bit more rolling in now. Net-net, what's the actual ultimate increase into '19 if you think about it?

Well, if you look at our basic share count, Julien, just add 6.3 million to it. That's the simple answer. If you look at today's basic share count for 2019, if you add 6.3 million shares to that, that's what our share count's going to be in 2019 because this Treasury method thing will go away when the convert occurs. Does that make sense?

Yes, absolutely, yes, that's all very straightforward. All right, let me go for another...

Well, one clarification there. It's not today's fully diluted share count that you add the 6.3 million to; it's the basic.

And that, of course, assumes there's no additional large capital investments or anything else that would lead us to have to use our ATM program. We've said we don't plan to issue any shares under that, but if we were to announce a big project or something, we may have to do that.

And there are a few other little things that impact fully diluted share count, but this Treasury method's the big one right now on the units.

Okay, can I follow up a little bit on that, Dave? Because you commented about improving credit quality, I think, in your opening remarks. Is there a potential that you accelerate CapEx in the near term here? Is there anything that we should be following here that could result in that? Obviously, there's the RFP. Could that drive CapEx as soon as 2018 to shift your financing plan?

Well, it's possible. We don't expect it today, or if we had a project to announce, we'd announce it. But certainly the one item that's not in our forecast is if we end up doing something where we would own a portion or all of the renewables for Colorado. I'm not sure that would necessarily drive the need to issue more equity, but that's something we could determine.

We're always looking at projects, though, and we're doing some integrated resource planning for our other electric utilities in Wyoming and South Dakota, actively doing that in Wyoming right now. So there's always a chance another opportunity could come along. Absent that, we've said that we expect to use our ATM program very minimally and have just a little bit of incremental shares coming in through the DRIP plan. And that's our intent today. But that's always subject to change.

We have increased, and we said that today, our 2-year, plus this year, but really 2 years and a couple months, capital spending plan by a little over $100 million, just on this call today. So that's a good thing from a long-term earnings growth perspective.

Yes, absolutely. Let me just clarify this about the oil and gas business and earnings reflected in this guide. When you think about the timing here, if you were to sell the remainder of the business, let's say tomorrow, such that you had a full year ex anything, how much of an uplift in your guide would you see from that ultimately here? Obviously, sort of appreciating the allocated SG&A piece here. That's really what I'm trying to understand.

The earnings guidance range that we put out for '17 and '18 basically reflect E&P or oil and gas as a discontinued operation, Julien. So there is no additional uplift from when we start reporting that as disco ops.

But would that change your SG&A allocation such that you would see a shift in your core earnings? Sorry, that's what I really was getting at.

No, we've kind of factored that into the guidance already. Basically, when we start reporting that as a discontinued operation with our fourth quarter results and our 10-K, and then next year with all our Qs, that G&A that we are retaining will be reallocated back to the other businesses. But the E&P direct loss will be under -- below the line as a discontinued operation. Again, the guidance numbers we issued take that all into account. There's no additional uplift from the fact that it's going to be disco ops.

The reallocation, I think it's a timing issue is really your question, Julien. The reallocation of that allocated corporate cost that is going to oil and gas now stops immediately once we start reporting that as discontinued operations, which is essentially no, so for Q4.

Right, so the reallocation in terms of timing when you sell it doesn't really matter. You've already effectively done that and reflected it in your '18 guide.

Yes, absolutely.

Correct. 2017.

Right, sorry, absolutely. Just to clarify this, obviously, you've accelerated your rate cases. Is there an angle in which '19 versus '18, just trying to think forward here a little bit -- or '20 -- could you see yet again an improving trend in the earned ROE off of what you're talking about today, or are we talking about kind of stabilizing the earned ROE where we are?

In aggregate, that's kind of a hard question to answer. I think what we see is the opportunity to file for rate reviews, which would suggest we need one in several of those territories. So I think that would lead you to think at least in the areas where we have to file one, that we need an improvement. But as time goes on and you have continued growth and you don't file a rate case, your other territories gradually get lower. So the net-net is hard to -- the entities we file rate cases for.

Got it. It wouldn't be decisive, shall we say, to the extent to which if there were to be an improving one?

Probably reasonable.

The next question is from Christopher Turnure of JP Morgan. Your line is open.

I just wanted to clarify, for example, in the fourth quarter of this year, if we compare it to the fourth quarter of last year, you're going to have a nice tailwind, I think, from normalized weather. If that's the case, you're going to have at least a small tailwind from the E&P business noncorporate drag piece going away. But if I'm doing the math correctly, there's still a pretty substantial drop there year-over-year. Is that basically due to the factors that you detailed for the lowering of the full year 2017 numbers? Is it all really that backweighted?

The third quarter, certainly as we described, wasn't to our satisfaction, and some of those factors are carrying into the fourth quarter, Chris. Weather -- hard to say if we're going to get an uplift there or not. It's cold in Rapid City and our other service territories today, but we've got 2 more months to go through.

Normal weather would be very welcome. And obviously, the reason for the range, still, is largely weather dependent for our '17 guidance range.

And are you prepared to give the number for the South Dakota amortization that you mentioned and the impact to the full year or 2018?

What I indicated in my comments was for the second -- we had to start that amortization on July 1. It's a 6-year amortization period and it's $1.3 million for the second half of 2017. And you'll see in the Q, when the Q comes out later today, there's some disclosure on that that should help you with that.

Okay. Is that reflective of kind of the half-year run rate?

Yes, basically yes.

And that's a pretax number?

Correct.

Okay. And then just to maybe zoom out a little bit on the irrigation customers and some of the C&I load that's fallen short on the electric demand side, I appreciate you guys being honest there about misforecasting a little bit. But kind of going into those rate cases that you've previously done in those jurisdictions, was it more that you had priced in a peak to kind of what was going on and didn't expect that decline? And then absent the cost-cut impacts that are going to have to be given back to customers, do you not have a chance to get a fair shot at earning an authorized ROE going forward once you get those rates reset?

Oh, sure. Yes, I think we feel pretty good about when we end up increasing our spending and going in for additional rate reviews, we feel pretty good about where we're at. Really, the issue isn't about what we're earning as much as what we thought we would earn. We had some loads. We work with, particularly some of our larger commercial and industrial customers, at what their loads will be and try to forecast those quarter-over-quarter. And a lot of that activity, like when they're adding onto facilities, expanding facilities -- a lot of that stuff tends to happen in the summertime. And some of that work got pushed out and isn't going to get materialized. And a couple of the things that we thought would happen, we don't know if they're going to happen now. Some of them, it's just taking longer. All of that's been kind of factored into our forward forecast.

And then on the agriculture, Chris, I said in my comments this as well. But last year was pretty hot and dry, particularly in Nebraska where there's a lot of center-pivot irrigations in those SourceGas service territories, and we knew we got some uplift from that last year. We didn't realize the extent to which that was the case. This year was probably more normal, and that's that $3-plus million delta.

Yes, it's not as simple as heating or cooling degree days. You have a moisture-related issue and the timing of those makes a really big difference. And that's what we're really getting our arms around on the forecasting side.

Okay. I know it's hard to generalize, but I guess if things were maybe pretty strong last year and then they're obviously not so strong this year, is it fair to say that the overall volume on either the electric or gas side, as you currently expect it to be, is kind of in line with what's baked into the last rate case cycle, or is it below the last rate case cycle?

Depends on the jurisdiction.

Yes, it depends on the jurisdiction. That would be a hard -- that's a hard one to generalize, I think, Chris.

The next question is from Lasan Johong of Auvila Research Consulting. Your line is open.

David, just a few questions on the oil and gas side. I think you might be expecting some of these. The valuation of the San Juan-PRB sale, can you tell me what it was on an MCF basis?

No, we haven't disclosed that yet. As I mentioned earlier, we literally just signed those and have not closed them yet. So terms, specifics, buyers, specific locations, all that are not going to be disclosed yet, if at all.

Assuming you're going to be opening up a data room?

Yes, what we've done, Lasan, we're not going to sell the whole company in a single transaction, so the advisers we've engaged are to sell a couple specific properties. So they're not huge transactions that are going to probably attract a lot of large buyers. We think that's the optimum way, given the properties we have left to divest those. So we will have a data room or two, likely, but for basically the sales of single assets. So one deal or one area or something like that. And that will happen over the next...

I understand, okay. Let's get to the main event, then, the Mancos shale. How much of that has been recorded as proved undeveloped?

Very little. If you looked at our overall reserve report, we have almost no proved undeveloped reserves on our books. There's some, but that's detailed in the 10-K -- very little. You would classify most of our Piceance assets as probable or possible. And at current price levels, a lot of them probably wouldn't be categorized as either probable or possible because by definition, reserves mean it's economical to recover at current prices. That's a definition of a reserve. So we would categorize a lot of those as a resource right now rather than a reserve, either probable or possible.

So, then, despite the 9 wells that you've drilled there, what you're saying without actually saying it is that the pricing on the Mancos shale is likely to be going as if it were even speculative reserves or possible reserves, but not as PUDs?

Correct, they're not PUDs.

The last question will come from Joe Zhou of Avon Capital. Your line is open.

So I just have a question, so first on share count in '19. Should I use 60 million, plus or minus?

Well, if you take our basic share count and add 6.3 million, that's about where you're at.

Okay. And a second question is at your midpoint of '18 guidance, which is -- I'll take $3.45. Do you still see you are confident that, with this share count, is it still possible to grow into '19 as the long-term EPS CAGR as you indicated?

We don't give a long-term earnings guidance, so we do 1 year at a time. Long term, I'm not talking year-to-year, but long term we believe we have good potential to grow and achieve our objective of being a top-quartile total shareholder return. But year-to-year, I wouldn't infer that.

Okay, so you say your top quartile is more on a long-term basis?

Absolutely, which gets back to, I think, the question Mike Weinstein asked a little bit as well.

Thank you. Since there are no further questions, I will now turn the presentation back over to David Emery for closing remarks.

All right, well, thank you, everyone, for attending this morning. We appreciate your continued interest in Black Hills. We're excited about the future. Like I said, we've got some timing issues right now related to earnings and earnings growth, but we're very excited about our dividend increase, our decision to make the strategic decision to exit the oil and gas business and our long-term capital spending prospects are even better than we had previously thought, so that's a great, great issue for us. Those of you who are going to be at the EEI Financial Conference, we look forward to seeing you there. 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.