Black Hills Corporation (BKH) Q2 2013 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and welcome to the Black Hills Corporation 2013 Second Quarter Earnings Conference Call. My name is Glenn, 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, Glenn. Good morning, everyone, and welcome to the Black Hills Corporation 2013 Second Quarter Earnings Call. With me today are David Emery, Chairman, President and Chief Executive Officer; and Tony Cleberg, Executive Vice President and Chief Financial Officer. Before I turn over the call, I need to remind you that during the course of this call, 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. Good morning, everybody. I'll start on Slide 3 of the webcast presentation for those of you who are following along. Our agenda today will be very similar to the format we've had in previous quarters. I'll give an update on key activities in the quarter. Tony will cover financials for the quarter, and then I'll discuss strategy and forward-looking issues. Moving to Slide 5, highlights of the second quarter. From a business standpoint, we had colder weather than normal in our gas utility service territories, quite a bit colder, about 20% colder than normal from a heating degree days and at a standpoint of about 70% -- 72% more heating degree days than last year during the same period. If you recall, last year, we had an extremely mild spring. Highlights for the utilities. Construction on our Cheyenne Prairie Generating Station is on schedule and within budget. That project is going very well. At Colorado Electric, we filed a resource plan in April. We discussed that on the last call. But in that plan, we identified a 40-megawatt gas turbine as the replacement for the 42-megawatt Clark power plant, which is a coal-fired plant that has been retired. We also recommended retirement of a couple of small gas-fired units in Pueblo for a total of 29 megawatts. And then we filed certificates of public convenience and necessity, seeking approval for the new turbine and the retirement of both of those 2 smaller gas-fired units. We do have a hearing date set for November regarding the resource plan and the CPCNs and hope to receive approval, so we can start work on that turbine project. Also at Colorado Electric, we issued a request for proposals for up to 30 megawatts of wind in April. We have received those bids. We used an independent third-party evaluator to evaluate those. That process has been completed, and the bid results were submitted to the Colorado PUC last Friday. Our IPP subsidiary did submit a bid into that RFP. The hearing to go over results of that bid results will be on September 4 through 6. Black Hills Power, we filed a rate request late last fall in December. Interim rates were implemented on June 16 subject to refund, and we have hearing dates scheduled in October for that rate case. In the meantime, we're responding to discovery requests and at least trying to reach some settlements with some of the parties in the case. Also at Black Hills Power, we filed a request with the South Dakota PUC for a construction financing rider for our Cheyenne Prairie Generating Station. That rider is very similar to the one already approved in Wyoming. In South Dakota, we have hearing set in September, but we did implement the rider on an interim basis on April 1, again, subject to refund. And then finally, our gas utilities purchased another small municipal gas system. We've continued our efforts to do that, and in this case, we added a few hundred additional customers. Moving on to Slide 7, highlights for the nonregulated energy subsidiaries. On the Power Generation side, we announced in May that we had reached an agreement with the City of Gillette, Wyoming, to sell them our CT II or Combustion Turbine II at our Gillette Energy Complex. That sale will close next year, about a year from now, after the current power purchase agreement from that unit expires. Included with that transaction is a 20-year economy energy agreement with Gillette, whereby if we can purchase energy for them cheaper than they can run that unit, we share in the savings from that. And that agreement continues for 20 years, so there are some still some decent earnings potential for us from that unit going forward. Finally, as I mentioned earlier, our IPP subsidiary did bid into the Colorado Electric wind RFP. On the oil and gas front, we drilled 2 wells on the Mancos Shale formation in the Piceance basin. Those are the 2 Wells we talked about last quarter in which we will earn 20,000 net acres in exchange for drilling and completing those 2 wells. To date we've drilled and cased them, waiting on completion operations until we finish a waterline into the wells for frac water and then make sure all the gathering system is in place, so we can turn the wells as soon as they're completed. We expect both wells to be producing by year end. And just a reminder, that agreement with the third-party that allows us to earn that acreage has real strict confidentiality provisions, so there's very little that we can disclose as far as specific well results reserves or production information. Moving on to Slide 8, highlights from the corporate perspective. We made excellent progress toward our goal of improving our credit rating during the quarter. 2 of the 3 agencies increased our corporate rate -- rating during the quarter. S&P increased to BBB from BBB- and now have us on a stable outlook. Fitch raised it's rating to BBB from BBB-, and they have us on a positive outlook. We closed the $275 million term loan that expires in June of 2015, basically replacing 2 other term loans that we had that were set to expire this year, essentially allowing us a couple of years of flexibility to complete the long-term financing associated with that. And then finally, our Board of Directors declared another dividend, $0.38 a share, equivalent to $1.52 on an annual basis, which continues our 43rd consecutive year of dividend increases. Slide 9. During the second quarter, we earned $0.40 per share from continuing operations as adjusted compared to $0.34 last year, an improvement of about 21%. Slide 10 illustrates the changes in our income from continuing operations as adjusted for the second quarter of this year compared to last year. Basically, we had lower performance in the electric utilities, and Tony will cover the details of that here shortly. And that lower performance in the electric utilities was more than offset by improvements in all of our other business segments. Now I'll turn it over to Tony for the financial update. Tony?

Thank you, Dave. Good morning. As Dave mentioned, second quarter performance continued to show strength from 2012. Moving to Slide 12. We reconcile our earnings from continuing operations on a GAAP basis to earnings per share as adjusted, which is a non-GAAP measure. We do this each quarter and feel by isolating special items, the earnings per share as adjusted better communicates our most relevant ongoing performance. During second quarter of 2013, we have one special item, which was the reduction of a $0.28 noncash mark-to-market gain on our $250 million worth of interest rate swaps. The gain reflected an increase in long-term interest rates during the quarter. So considering this special item, the second quarter's earnings per share as adjusted from continuing operations was $0.41 compared to $0.34, a 21% increase. Also, I'd like to point out that our trailing 4 quarters EPS as adjusted was $2.38, and this is an improvement of 32% over the comparable fourth quarters ending June 30, 2012. Slide 13 displays our second quarter revenue and operating income. Later, I'll explain major differences between years. But here, the main point is we're predominantly a regulated business, generating 86% of our operating income from electric and gas utilities in the second quarter. Our operating income improved by $1.5 million compared to 2012, driven by improvements in Power Generation, Coal Mining -- and the Coal Mining segments. Utilities in total were flat year-over-year, with improved performance in the gas LDCs, offset by lower electric utility performance. I'll give more color on the operating income changes on a later slide. Slide 14 displays our second quarter income statement. On later slides, I'll discuss the segment revenue and operating income in more detail, but here, I want to mention several other noteworthy items that impacted the second quarter performance compared to Q2 of the prior year. The first item, interest expense net of interest income declined by $3.8 million as a result of the debt declining by $183 million. As you may recall, we paid off $225 million of 6.5% notes in Q4 of 2012. On a segment basis, almost all of the interest expense reduction from 2012 accrues to the corporate segment. The second item relates to a 34% tax rate in the second quarter. The tax rate was slightly lower than expected due to increased R&D credits, including the 2012 benefit of R&D credits. The third item relates to performance incentive costs that are included in our operating expenses. Our performance plans are directly aligned with our stakeholders. Consequently, the 11% improvement in the stock price in the second quarter generated an additional compensation of expense of about $1 million. These expenses are allocated to each one of the segments. The last noteworthy items is our EBITDA. During the quarter, we achieved $84.7 million in EBITDA, a decline of $5.3 million from 2012. The oil and gas segment's EBITDA declined by $8.5 million, primarily because we sold Williston Basin oil and gas wells in Q3 of 2012. Moving to the next slide. On top of Slide 15, we displayed our Electric Utilities segment revenue and operating income. The Electric Utilities revenue increased in the second quarter by $8.3 million from 2012 due to increased rates of about $5 million and increase off-system sales about $3.5 million. This was partially offset by lower demand, driven by 13% fewer cooling days. Our second quarter operating income as adjusted declined $3.7 million year-over-year, reflecting primarily increased O&M costs. Gross margins were relatively flat with the improvements in CWIP riders and higher rates offset by an energy cost adjustment and 1.2% lower retail wholesale megawatt demand. Our O&M cost increased for higher compensation expense, depreciation and property taxes. Moving down Slide 15. Gas utilities revenue increased $35 million or 50%, driven by 72% increased heating degree days. Operating income improved by $3.5 million or by 49% in the second quarter compared to 2012. Distribution dekatherms sold increased about 65% year-over-year and was driven by higher-than-normal heating degree days. As you will recall, last year was unusually mild with heating degree days lower than normal by 31% in the quarter. Gross margins increased by $7.2 million offset by O&M expenses of $3.7 million, including higher costs for incentive compensation. All in all, the gas utilities performed very well in the quarter. The next segment, on Slide 16, Power Generation improved compared to last year's performance. We're pleased with the performance and the availability and the earnings and we -- that we continue to see from Colorado IPP. Moving down, Slide 16. The Coal Mining segment we saw the operating income improve in the quarter by $1.8 million from 2012. The tons sold increased by 10%, and the mining cost per ton decreased by 13%. The lower cost per ton reflects the reduction in removal of overburden. We are encouraged by the continued improvements that we see at our coal mine. Moving on to oil and gas on Slide 17. The segment performed as expected. Two major items in 2012 impact the year-over-year comparison. First is we delayed our natural gas drilling program last year because of low prices, so our gas production declined by 27% year-over-year. The second item is we sold most of our oil-producing properties in the Williston Basin last fall, so our oil production declined by 58% year-over-year. Overall, production in the second quarter declined by 34% compared to 2012. From a cost perspective, our O&M expenses declined by $8.2 million with lower depletion of $7.8 million. The actual depletion rate during Q2 was $1.82 per MMcfe, which was higher than our initial guidance assumptions. Some of the non-operated wells in the Bakken came online near year-end 2012, which increased our cost pool. Sequentially, from the first quarter to the second quarter, total production declined by 6%, driven by a 33% decrease in oil production and a 3% decline in our gas production. Again, sequentially, from first quarter, prices received increased by 6% for oil and decreased by 21% for natural gas. Moving on to our capital structure. Slide 18 shows our current capitalization. At quarter end, our net debt capitalization ratio was 50%, about flat with the first quarter. Our credit metrics continued to improve since the first quarter earnings release. As Dave said, both S&P and Fitch have upgraded our credit ratings. Both S&P and Fitch now rate our unsecured credit at a BBB. With the cash flow from operations and our debt capacity, we have ample funding available to support our growth over the next few years. In the press release, on Slide 19, we reaffirmed our 2013 earnings guidance in the range of $2.20 to $2.40. This is for EPS as adjusted and excludes special items. We've not changed our published assumptions because we believe, in total, the assumptions are reasonably accurate for the guidance range. Moving to Slide 20. To conclude, we are pleased with the second quarter performance and our outlook. In Q2, the cool weather helped our gas utilities perform well, and we continued to manage all of our operations effectively. With those comments, I'll turn it back to Dave.

Thank you, Tony. Moving on to Slide 22. We have 5 major strategic objectives, really focused primarily on being an industry leader in everything we do. We want to be a leader in operational performance, earnings growth, our earnings upside opportunities primarily provided by our oil and gas properties, and our track record of 43 consecutive annual dividend increases. We also want to continue improving our credit rating, and we've made great progress in that regard. Moving on to Slide 23, related to operating performance. There are several metrics on here. All exhibit exceptional performance relative to our peers in the areas of safety, reliability and several other efficiency measures. On Slide 24, this illustrates our superior plant availability and starting reliability. It also demonstrates that we have an extremely modern generation fleet, as you can see by the fleet age there, and that our power plant construction safety record is great. We've provided an update on that chart with 0 accidents to date on our Cheyenne Prairie Generating Station. Slide 25 sets on our generation by fuel type but further illustrates the recent and ongoing modernization of our generation fleet. When we look at the impositions of new government regulations, from a customer impact perspective, we're essentially through the majority of that impact once we complete the Cheyenne Prairie Station. So our fleet's very modern and won't require a lot of additional modifications. On Slide 26, from an earnings growth standpoint, we expect continued strong earnings growth driven by capital spending. That spending will be done to meet customer needs in our utilities and also to grow our nonregulated energy businesses. Now for the next several years, capital spending is projected to continue to be far in excess of our depreciation. Slide 27 simply provides more detail regarding both historical and projected capital expenditures by business segment, gives you an opportunity to see, particularly in the Electric Utility business, where we're spending some of that capital and then really breaks that schedule out by individual subsidiary. Slide 28. Helping to drive our future earnings growth is our Cheyenne Prairie Generating Station, which I talked about earlier. That new 132-megawatt plant is jointly owned by Black Hills Power and Cheyenne Light. Construction commenced in April, and progress has been excellent. We still expect that plant to be in service by the fourth quarter of next year, and so far, from a budget standpoint, we're well within budget as well. Slide 29 provides an update -- regulatory update for our utility properties. Essentially all of this information has been covered in a previous slide I just provided in a summary format here, particularly key dates for various regulatory proceedings kind of in the bottom-right corner of the slide. Moving on to Slide 30. From an earnings upside perspective, we're very focused on proving up and capturing the substantial value of our existing oil and gas properties. We're going to focus on those existing properties, primarily the Mancos resource we've been discussing, and also participate in some limited exploration opportunities, focusing primarily on oil plays that have impactful reserve potential. Our 2013 program I discussed earlier, we've drilled those 2 horizontal Mancos Wells, and we'll complete those wells in the fourth quarter, which will allow us to earn the 20,000 acres of additional leasehold in the Mancos from a third party. We're also evaluating some selective oil well exploration drilling and may drill 2 or 3 crude oil wells in the Powder River Basin between now and the remainder of the year. I probably won't disclose a lot of details about those wells until they've been drilled and completed. Moving on to Slide 31. Our existing oil and gas leases in the Piceance and San Juan Basins have a net resource potential in excess of 2 trillion cubic feet of natural gas. We believe that's a fairly conservative number based on current well spacing in that play and believe that it could be higher as we get more information from a technical standpoint. The table does not include the 20,000 net acres that we have yet to earn from the third party for drilling the 2 wells this year. Once we do that, it will increase our Mancos holdings by almost 27%. On Slide 32, we continue to be very proud of our track record of increasing dividends for 43 consecutive years, and as you can see, this year, our annualized rate is a larger increase than the annualized increase we've had over the last several years, reflecting our confidence in the balance sheet, as Tony elaborated on, and the strength in cash flows from some of the larger projects we've completed over the last couple of years. Now finally on Slide 33, we remain focused on improving our credit rating. And as we discussed earlier, we've made excellent progress with 2 out of the 3 rating agencies. We'll continue to focus on getting an upgrade from the third. Slide 4 (sic) [Slide 34] , this is our scorecard, which sets forth our key objectives for 2013 and illustrates our progress to date toward those objectives. This is something that we've done for several years, basically holding ourselves accountable to you, our shareholders, to make sure we're accomplishing our strategic objectives. And then, lastly, on the following slide, is just a brief reminder of our Analyst Day for you sell-side and buy-side analysts. If you're interested in participating, please contact us at the Investor Relations contact information. That concludes my remarks. I'd be happy to entertain any questions anybody might have.

[Operator Instructions] And your first question comes from the line of Kevin Cole with Crédit Suisse. Kevin Cole - Crédit Suisse AG, Research Division: I'll start with the Mancos today, some on the 2 tests wells. Are you expecting reserves in line with the 68 Bcf that you realized in the past or highlighted on Slide 31 as well?

Yes. From a reserve perspective, Kevin, we're not comfortable disclosing anything based on the terms of our confidentiality agreement. I would say the drilling and everything have gone very much according to plan to date. But beyond that, I'm really not comfortable commenting on specifics, reserves or anything else. Kevin Cole - Crédit Suisse AG, Research Division: Have you provided the idea, the well technology, like the expected length of the lateral and the number of frac stages that you're going to use?

We have not. Kevin Cole - Crédit Suisse AG, Research Division: Okay. And then, I guess, back to your -- to the original 74,000 acres, what is the status of the BLM approval to allow you to start drilling wells there as well?

Yes. We have 6 permits that have been approved. Two are what we would consider to be ready now. Four of them have conditions of approval, which we felt were overly onerous. In a nutshell, basically, they're requiring us or trying to require us to do a whole bunch of environmental studies, which are well beyond the scope of the drilling activity we're proposing. And so we're working with the BLM, really trying to get a couple of those conditions removed. We could drill the wells and cooperate with those conditions, but I think they're a very large overreach by the BLM. And so we're trying to be careful about how we proceed with those but don't feel that some of those studies are necessary. So we're visiting with them to try to see what we can work out for an arrangement between us. We are in the process of filing several more permits. And really, the intent is to have around 18 permits available by next spring in the Piceance Basin. Kevin Cole - Crédit Suisse AG, Research Division: Okay. And I guess, sorry, to what you said, there's 2 permits that could be ready to go?

Yes. Kevin Cole - Crédit Suisse AG, Research Division: Are you willing to -- are you expecting to drill those this year as well?

We have not made a decision to do that yet, probably will not. Kevin Cole - Crédit Suisse AG, Research Division: Okay. From -- I guess, from where you sit today, are those 2 wells, those locations looking to be kind of in line with what we saw in 2011? Or you're thinking they're maybe like more prolific or...

Well, I think the issue that's going to affect productivity and reserves really comes down to lateral length and frac stages, in your earlier question. I think we would anticipate drilling these next wells that we drill with longer laterals, probably 8,000 or 9,000 feet instead of a 4,000 to 5,000 that we drilled in late 2011. And 30 to 40 frac stages instead of 20-ish like we did last time and would expect a proportionate increase in reserves associated with that. We have not finalized our specific well procedures for those wells yet. We just got the permits, and we're not prepared to drill those yet. But I would expect we'd have a little bit different procedure than the last time. Kevin Cole - Crédit Suisse AG, Research Division: That's great. And then, sorry, one last question then, onward the general play, I saw the general Mancos, where are we at in determining the proper acre spacing from 160 to 80 to eventually 40?

Yes, good question. Some of the offset operators are continuing to talk about their results, and in particular, I think you might want to review some of WPX's public information. They don't disclose specifically what they say they're anticipating spacing or anticipated spacing is, but if you look at their resource recovery per acre, it's significantly higher than what we're disclosing. So I can't specifically answer what others are thinking about spacing other than to say it's the same rock basically. So they're projecting a lot higher reserves per spacing unit or per acre than they have to be looking at reduced spacing that's quite a bit tighter than what we're showing currently. WPX has some good information on that, that could answer some of your questions. Kevin Cole - Crédit Suisse AG, Research Division: Sorry, one last E&P question. On one of your last E&P slides, you indicated that you're in the process of looking to acquire more oil property?

Yes, not so much acquire, but in a more -- maybe acquire some leasehold and drill some prospects. Powder River Basin, in particular, is a very mature oil basin, and that still has some good opportunity left, particularly in the oil price ranges $80, $100. And so we're looking at those, and there is a chance we may drill up to 3 wells yet this year in the Powder River Basin.

And your next question comes from the line of Chris Ellinghaus with Williams Capital.

Do you feel that this quarter is indicative of where you're headed in terms of your coal run rate?

I would say it pretty much met expectations. There wasn't anything unusual in the quarter.

Please, let me rephrase that. Do you feel like you've completed the ramp-up of the sort of turnaround and the improvement in margins?

Chris, the improvement that we saw this quarter, we're probably not going to see that kind of improvement consistently. So this was a big step function this quarter. We were up $1.8 million on operating income, but we hope to continue to get a little bit of improvement out of that.

We'll keep focusing on efficiencies, but all of our staff reductions and production levels and all of those things are largely completed.

Okay. And given the quarter for oils -- for EMP's performance, have you got any update on your thinking about how negative EMP can be sort of on a continuing basis?

Not really. I think if you look at EMP's results, they're not really different from what our expectations were and continued results from E&P in that range are included in our guidance range, if that answers your questions.

Okay. On a corporate level, should we be seeing sort of, on a whole, the corporate drag slightly increasing over time, as you complete -- you go through the construction phase on Cheyenne Prairie?

I don't think so, Chris. The big improvement in corporate line this year is really the interest expense reduction.

Right. So I'm just thinking as you go through the construction phase on Cheyenne Prairie that interest expense will start to run up a little bit more.

It probably will, but most of it should be recoverable. So the interest expense will increase but the way the writers work is it should show up in operating income.

And assuming that South Dakota approves a rider?

Yes, that's our assumption.

[Operator Instructions] At this time, we have no further questions, and I would now like to turn the call over to David Emery for closing remarks.

All right. Thank you. Thanks for attending the call this morning, everyone. We appreciate your continued support and your interest in Black Hills. Enjoy your day. Thank you.

Ladies and gentlemen, that concludes today's conference. Thank you for your participation. You may now disconnect, and have a great day.