Black Hills Corporation (BKH) Q3 2013 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and welcome to the Black Hills Corporation 2013 Third Quarter Earnings Conference Call. My name is Dominique, and I'll 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, Dominique. Good morning, everyone, and welcome to the Black Hills Corporation 2013 Third 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, everyone. Thanks for joining us today. I will start on the webcast presentation on Slide 3 and we'll conduct this call in a manner similar to our previous quarters. I'll give a quick highlight on the quarter; Tony Cleberg, our CFO, will go through the financials for the quarter; and then I'll talk about the strategic overview and the go-forward information. So moving on to Slide 5, highlights from the third quarter. From a business environment perspective, it was a little cooler in our Electric Utility service territories compared to the prior year. Not a lot, but certainly a little bit cooler. Highlights from the utilities side, several notable accomplishments during the quarter. Black Hills Power, we received approval from the South Dakota Public Utilities Commission for our rate case settlement, which authorized an increase of about 6.4% in annual electric revenue and that was effective June 16. Also for Black Hills Power, we received approval from the PUC for the construction financing rider for our Cheyenne Prairie Generating Station. That was effective April 1, which is -- essentially was the construction date. We now have riders in place in both Wyoming and South Dakota for Cheyenne Prairie. Construction on now plant is ongoing. It's a $222 million, 132-megawatt gas-fired plant in Cheyenne, Wyoming. Progress has been great. All 3 turbines have been delivered to the site and the project continues to be on schedule and within budget. You will notice that in our material this quarter we referred to the project as $222 million. In the past we've shown you $237 million and $222 million, the difference being potential financing costs. With the construction financing riders approved in both Wyoming and South Dakota now, it's a $222 million project. At Colorado Electric, the Colorado PUC denied our application for approval of a 30-megawatt wind solicitation. An independent evaluator had reviewed those bids and recommended that the bid be awarded to our Power Generation subsidiary. The commission indicated its preference for dealing with renewable acquisition within our Electric Resource Plan docket, which has hearings in the next week or so rather than deal that in a separate transaction. Our gas utilities purchased another small municipal system during the quarter. That's 4 year-to-date, adding almost 900,000 (sic) [900] customers. And Black Hills Power, in early October, this was not in the quarter, but we experienced what was deemed the Winter Storm Atlas, which was a severe blizzard resulted in an extensive system outage for us at Black Hills Power, one of the worst in our history. With the help of our neighbor utilities, Otter Tail, Northwestern and Excel, and in numerous contractors, our employees did an extraordinary job restoring the service to our customers. In fact, we've received a lot of compliments from state local officials and our customer base for our handling in a storm and its challenges. We'll talk a little bit more about that later in the call. Moving on to Slide 6, highlights for our nonregulated energy subsidiaries. The Power Generation subsidiary, I already mentioned, and the Colorado wind project issue. Moving on to oil and gas. We have drilled and cased 2 wells in the Mancos Shale formation in the Piceance Basin. We have now commenced completion operations on those wells and hope to have both wells completed and producing prior to year end. On Slide 7, highlights of the corporate level. During the third quarter, we achieved our goal of a BBB equivalent credit rating from all 3 credit rating agencies. We received upgrades during the quarter from both Moody's and Standard & Poor's. We'd previously received one earlier in the year from Fitch. And also our board declared a quarterly dividend of $0.38 a share, which is equivalent to the annual rate of $1.52. Again, reminding you this is our 43rd consecutive year of dividend increases. Moving on to Slide 8. We earned $0.47 per share from continuing operations as adjusted during the quarter compared to $0.40 -- $0.42, excuse me, from the same quarter last year. A good strong improvement of about 12%. Slide 9 illustrates the changes in income from continuing operations as adjusted for this quarter compared to the same quarter last year. In summary, lower performance in our Gas Utilities and Oil and Gas segments was more than offset by improvements in our other business segments. That concludes my highlights for the quarter. Now I'll turn it over to Tony Cleberg for a discussion on the financials for the quarter. Tony?

Thank you, Dave. Good morning. As Dave mentioned, our third quarter performance continued to show strength, strength in terms of a 12% improvement in EPS as adjusted and strength in terms of our balance sheet. We are pleased that over the last 2 quarters, our improved financial performance has been recognized with upgrades by all 3 credit agencies. Moving to Slide 11. We report GAAP earnings and reconcile to earnings as adjusted, a non-GAAP measure. We do this each quarter to isolate special items and report an earnings amount that we feel better communicates our most relevant ongoing performance. During the third quarter of 2013, we only had 1 special item, which was a $0.05 noncash mark-to-market gain on our $250 million of de-designated interest rate swaps. The gain reflected increases in the long-term interest rates. So considering this special item, third quarter earnings per share as adjusted from continuing ops was $0.47, compared to $0.42 in 2012, a 12% improvement. And for the trailing 12 months, the EPS as adjusted was $2.43. This represents a 30% increase over the 4 comparable quarters ending September 30, 2012. Slide 12 displays our third quarter revenue and operating income. As you'll note, we are predominantly a regulated business, generating 79% of our operating income from electric and gas utilities in the third quarter. Looking at our performance during the quarter, operating income as adjusted improved by $1.6 million compared to 2012. The improvements were driven by a better performance in utilities and operation -- Power Generation and Coal Mining, offset by a decline in oil and gas of $2.3 million. I'll get more color on the operating income changes later in my remarks. Slide 13 displays our third quarter income statement. On later slides, I'll discuss segment revenue and operating income in more detail, but here I want to comment on several noteworthy items that impacted our third quarter performance. The first noteworthy item, interest expense. Net of interest income declined by $3.1 million as a result of lower average debt during the third quarter of '13, and lower interest rates. As you may recall, we received $227 million for the sale of the Williston Basin assets at the end of third quarter 2012, reducing our net debt at quarter end. On a segment basis, almost all of the interest expense accrues to the corporate line. The second noteworthy item was our Q3 effective income tax rate of 36.6%, which was higher than the same period of 2012 because of the true-up adjustments primarily related to filing the 2012 income tax return. Comparing the year-to-date rate to 2012, we're flat at 34%, which is a fairly normal rate for us. The third noteworthy item was our EBITDA. During the quarter, we achieved $92.1 million in EBITDA, which is a decline of $3.1 million from 2012. The oil and gas segments' EBITDA declined by $9 million, primarily because we sold the Williston Basin assets last year, and the other segments actually improved by $6 million year-over-year. Lastly, I just want to point out that if you recall last year's performance, we were very challenged by a mild winter, so we really had to squeeze our expenses to achieve the kind of results that we needed last year. This year, we still managed our expenses with rigor, but if you look year-over-year, expenses generally increased, which we believe was necessary for the business. On top of Slide 14, we displayed our Electric Utilities segments. From a revenue perspective, the Electric Utilities increased by $16 million in the third quarter compared to 2012. About 75% of the increase was attributable to higher rate recovery and about 20% was attributable to better off-system sales. Our retail megawatt usage was flat year-over-year, primarily due to fewer cooling days. At the beginning of August, the weather during the Sturgis Motorcycle Rally was quite mild so we did not achieve the expected usage for Black Hills Power. Our third quarter Electric Utilities operating income as adjusted improved year-over-year by $3.3 million, reflecting better cost recovery in our rates. Gross margins improved by $11 million, reflecting CWIP riders, energy cost adjustments and returns on capital investments. During the quarter, O&M costs increased by $7.6 million compared to 2012, which reflected higher cost for tree trimming, labor and benefits, depreciation and property taxes. Moving to the bottom of Slide 14, our gas utilities revenue increased by $4 million, or 7%, primarily driven by 5% higher volumes for residential and commercial customers and slightly higher gas prices. Operating income declined by $1.5 million in the third quarter compared to 2012, resulting from a $900,000 increase in margin from customer charges and returns on capital investments, offset by higher O&M expense of $2.2 million. The higher O&M expense was driven more -- by a more normal uncollectible customer accounts and increased property taxes. The uncollectible customer accounts were abnormally low in 2012 and so the 2013 experience reflects a more normal expense level. All in all, our gas utilities performed well for a shoulder quarter. The next segment, Power Generation, on Slide 15, improved by $2.3 million compared to last year's performance. About 1/2 of the improvement was due to better off-system sales. The other half of the improvement was due to lower expenses, primarily transmission expense and property taxes. Looking to Q4, we commenced an outage for maintenance at our Wygen I. So we estimate lower earnings in Q4 for this segment compared to the prior year. This impact has been included in our 2013 guidance range, which I'll discuss later. Moving to the bottom of Slide 15. Coal Mining segment saw an operating income improved during the quarter by $1.2 million. The tons sold increased 3% and the mining cost per ton decreased by 7%. The lower cost per ton resulted from a better stripping ratio, meaning we produced more coal while removing less overburden. We are continued to be encouraged by our improvements at the coal mine. Moving to Oil & Gas on Slide 16. This segment performed as expected. Compared to Q3 2012, the operating income declined by $2.5 million, driven by 2 major items. The first was we delayed our natural gas drilling program last year because of low prices, so our gas production declined by 23% year-over-year. The second item was that we sold most of our oil-producing properties in the Williston Basin at the end of Q3 2012. So our oil production declined by 54% year-over-year. Overall, our production in the third quarter declined by 32%, compared to the same period in 2012. From a cost perspective, our O&M expenses declined by $7.8 million, driven by lower depletion of $6.3 million. The year-to-date depletion through third quarter was $1.92 per Mcfe, which was higher than our initial guidance that we gave last year and $0.12 higher than the first 6 months. Some of the drivers to the higher depletion rate include increased spending on oil well drilling, and higher drilling costs for our working interest in the Whittaker Flats in Colorado. As mentioned before, we received rights to 20,000 leasehold acres for drilling these wells. Enough on year-over-year comparison, let me comment on some positive sequential performance. From the second quarter to the third quarter, our total production increased by about 5%. This was driven by a 29% increase in oil production, primarily from non-operated wells in the Bakken and a 1% decline in natural gas production. Again, sequentially, from Q2, prices recede by 1% for oil but improve for natural gas by 20%, which is a real positive sign for us because of our natural -- large natural gas exposure. So to reiterate, oil and gas segment performed as expected. Now moving to our capital structure slide, Slide 17, shows our current capitalization. At quarter end, our net debt to capitalization was 51%, up 1 percentage point from the second quarter as we continue to construct the Cheyenne Prairie Generation Station. Our credit metrics continue to show strength. With Moody's upgrade in September, all 3 agencies, S&P, Moody's, Fitch have all rated our corporate unsecured debt at BBB or a Baa2. Both Moody's and Fitch have some positive outlook. Moving to Slide 18. We displayed our long-term debt maturities and, as you may recall, we have $250 million with a 9% notes coming due in 2014. So we will be looking closely at the timing of the replacement financing for these notes and other potential long-term issuances, particularly considering the current low-rate interest environment. We're pleased with the credit upgrades, to have those in place with the financing on the horizon. As we look forward, our cash flow from operations and our debt capacity provide ample availability to fund and support our growth over the next few years. Moving to our earnings outlook, Slide 19. In our press release, we narrowed the 2013 earnings guidance to $2.28 to $2.40. This is for EPS as adjusted and excludes special items. Our guidance range assumptions include normal weather or normal operations from today to year end, but the assumptions also include the impact of the severe winter storm that occurred in the first week of October and a planned 10-day outage for Wygen I. Looking forward to 2014, we initiated our guidance range for earnings per share as adjusted at $2.40 to $2.60. There are a number of assumptions that are listed on Slide 20. These are included also in our press release. We expect almost all of the improvement in the earnings to be generated from improved operating income and we expect to be profitable in the Oil and Gas segment. Another key assumption includes an in-service date of October 1, 2014, for the Cheyenne Prairie Generation Station and reasonable outcomes for the related rate cases for Black Hills Power and Cheyenne Light. So we are projecting another year of earnings growth. Moving to Slide 21. Just to conclude, we feel good about the third quarter as it -- it performed as expected and we look forward to and feel very good about extending our trend of earnings growth. And with those comments, I'll turn it back to Dave.

Right. Thank you, Tony. Moving on to Slide 23, Strategic Objectives. We've got 5 major strategic objectives focused primarily on being an industry leader in all we do. We want to be a leader in operational performance, earnings growth, the earnings upside opportunities from our oil and gas operations, and of course, our track record of 43 consecutive annual dividend increases. Now, we also plan to maintain our BBB equivalent credit rating, which we've now obtained from all 3 agencies. Slide 24 exhibits exceptional operational performance relative to our peers in several areas: safety, electric reliability and several other efficiency measures. Slide 25 illustrates our superior power plant availability and starting reliability. It also demonstrates that we have an extremely modern generation fleet and that our power plant construction safety record is one of the best in the industry. Slide 26 sets forth our generation by fuel type and also further illustrates the ongoing modernization of our generation fleet as we retire older plants and construct new ones. Slide 27, related to earnings growth. I mean, we expect continued strong earnings growth driven by capital spending to meet our customer needs in our utilities and also to grow our nonregulated energy businesses. Capital spending is projected to be far in excess of depreciation for the next several years. Slide 28 provides some detail on historical and projected capital spending by business segment. You will note, there's been an increase in overall CapEx and also some changes between years for the years 2013 through 2015, as compared to the figures we presented on our Analyst Day last month in New York City. Our board approved our budget last week and also finalized our strategic plan for the next 5 years. And so, with this quarterly release, we've revised those numbers. Overall, an increase in CapEx forecasted for those 3 years total. Slide 29, which is essentially just a subset of 28, providing a little more detail for select major utility projects. Moving on to Slide 30. Helping drive our future earnings growth is our Cheyenne Prairie Generating Station. Again, a $222 million, 132-megawatt facility that's jointly owned by 2 of our Electric Utility subsidiaries, Cheyenne Light and Black Hills Power. As I mentioned earlier, the progress on the project has been excellent. We do expect it to be in service in October 2014 on budget. Slides 31 and 32 provide regulatory update summary for our utilities. Many of these are covered previously, with a couple exceptions really listed near the bottom of Slide 31. For the Cheyenne Prairie Generating Station, both Black Hills Power and Cheyenne Light plan to file rate increases in Wyoming and South Dakota in late 2013 or early 2014 to request rate increases to be effective with the in-service date of the plant. We should be filing those in the next several months in both states. Also for Cheyenne Light, we've talked about this previously, but Cheyenne Light has an option to purchase Black Hills Wyoming's 76.5% interest in the Wygen I plant between the years of 2013 and 2019. That option's part of the power purchase agreement between Black Hills Wyoming, which is one of our nonregulated power generation subsidiaries, and Cheyenne Light. We're in the process of evaluating the timing for that. Essentially we plan to propose that Cheyenne Light exercise the option, essentially at the point where the customers will be rate mutual comparing the power purchase agreement and the rate basing of the plant. So we're still evaluating the timing of that option exercise. Skipping Slide 32 then, and moving on to 33. From a value upside perspective, we're very focused on our oil and gas growth strategy. We plan to prove up and capture the substantial value of our existing oil and gas properties and also to participate in some limited exploration opportunities. Those we will focus primarily on oil plays with impact for reserve potential. For 2013, I've already mentioned the 2 Mancos wells. We're also doing some selective participation in non-operated wells in various basins, small non-operated interests and then doing a little bit of selective oil exploration drilling as well. On Slide 34, our existing oil and gas leases in the Piceance and San Juan basins have a net resource potential in the Mancos formation in excess of 2 trillion cubic feet in natural gas. As we've described previously, that does not include the 20,000 net acres of Mancos leasehold that we will earn by drilling the 2 wells we drilled this year in the Mancos. On Slide 35, we continue to be very proud of our dividend track record. We've increased our annual dividend to shareholders for 43 consecutive years, one of the longest streaks in the utility industry. On Slide 36, as I stated earlier, we've met our objective of achieving a BBB-equivalent credit rating from all 3 rating agencies. In addition, 2 of the 3 agencies have us on a positive ratings outlook as well. Slide 37 is our scorecard. This is our way of holding ourselves accountable to you, our shareholders. The scorecard sets forth our key objectives for 2013 and really illustrates the excellent progress we've made year-to-date towards meeting those objectives. That concludes my remarks. We'd now be happy to open it up to questions.

[Operator Instructions] Your first question comes from Kevin Cole of Credit Suisse. Kevin Cole - Crédit Suisse AG, Research Division: Hope, I guess maybe dissect the E&P guidance a little bit, 13.4 to 14.4 Bcf. I guess, should we think about it broadly? I guess you have 3 categories right? You have the legacy operations, you have the southern Piceance, you have the 2 test wells there plus the 6 appraisal wells you're going to do this year and then some new oil opportunities that you're looking at? I guess, of the 13.4 to 14.4 Bcf, how much of that is the new oil that you mentioned today?

I don't know specifically, Kevin, as a percentage. I'd say a large portion of the growth in production from this year to next year is going to be coming from the Mancos wells. Those are big-volume wells. It doesn't take fairly many to produce a couple of Bcf pretty easily. So the lion's share of the growth in production, it's going to be coming from our Mancos activity. We do have some non-operated interests, as you talked about in the Bakken. Slight increases there, perhaps, and few other plays that we have going on, but on a lion's share of the increase is going to come from the Mancos drilling. Kevin Cole - Crédit Suisse AG, Research Division: I guess, so for 2013, you got it for 9.3 to 10.3. And so I'd imagine if I just subtract the 2 midpoints, that's probably not the right magnitude from the Southern Piceance because of the natural decay of, I guess, decline in E&P from legacy operations, I guess. So If I were to start off with the 9.3 to 10.3 of pre Southern Piceance, given the level of CapEx that you deployed in '13 and '14, that same group of assets that's produced that's resulting in your 2013 production. Where would that be for 2014? I guess it be lower, right? But can you help me with any level of magnitude? Then we I can properly capture the step up from '13 to '14 from Southern Piceance and as well the new oil.

Yes. We haven't disclosed our specific decline on days production, Kevin. Again, I'd say a typical assumption, you can assume, some reasonable decline level, probably less than a 20%, 25% a year kind of a number and that varies pretty widely depending on the types of wells that you're talking about. So it's really difficult to answer that question with any specifics. Again, most of the barrels are going to come from the Mancos wells we drill throughout the year, next year and the 2 that we'll be putting on around the first of the year. Kevin Cole - Crédit Suisse AG, Research Division: Have you indicated for the Southern Piceance wells if you're going to do the 10,000-foot lateral type curve, that's the expectations that you've kind of highlighted?

Yes, Kevin, we've mentioned at our Analyst Day that we drilled the longer laterals and we also included a type curve, which gives you at least a good indication of production rate versus time over the life of those wells. So that should help you a lot, I think, figure out the impact of the Mancos production. Kevin Cole - Crédit Suisse AG, Research Division: For the -- last question, so with the CapEx step up from the Analyst Day to today, was that simply to support the 6 wells in 2014? Or is there any CapEx being aimed anywhere else, like in infrastructure pulled out? Or anything else we should know about?

Kevin, are you talking about oil and gas? Kevin Cole - Crédit Suisse AG, Research Division: Yes, I'm sorry.

Yes. Essentially, some of that's related to the Mancos. Some of it's infrastructure related to the play itself, water, gas, gathering things like that. Again, as I mentioned, we also have a few other things going on, some small non-operated interests in various plays, which are some capital that we didn't have anticipated, say, 6 to 12 months ago. So all added together, none of it at any single large piece, but a few million here and a few million there, basically. Kevin Cole - Crédit Suisse AG, Research Division: Actually, just one last question. So I guess, WPX had another good well, a couple of weeks ago. I guess, on your map that you guys -- is that like on, Slide 60, I guess? Do you know where that well sits on your map? And how indicative do you think that well as to your property?

Yes. It's roughly between their other large well and our acreage block. Still, there's a fairly significant difference between where they're located and where we're located in that. They're deeper and a little more overpressured. So that would suggest the well results were probably be a little bit better than ours. You never know until you drill the wells, but they do have a higher pressure regime than we do in our area. But the well's roughly halfway in between their first big well and our acreage block.

[Operator Instructions] And our next question comes from the line of Chris Turnure of JP Morgan. Christopher Turnure - JP Morgan Chase & Co, Research Division: My question is around the CPUC denial of the Wind RFP for your IPP segment. How significant is that? And do you have a chance when they review it in the comprehensive nature of the long-term resource plan there?

Yes. When you look at that issue, what we tried to do is give an initial 30 megawatts done and approved in order to capture the benefit of the production tax credit, which is set to expire at the end of the year. Expansion of our Busch Ranch site was a very obvious way to do that, that we believe to have some benefits to customers. I think the commission indicated its preference really to deal with those as part of a longer inch resource planning process. If you look into our resource plan, we do show additional increments of wind being added in the out years of the plan. Now, where they come from remains to be seen. Colorado has the competitive bidding resource requirements and we would expect to continue doing that. They also have a cap on how much incremental cost to ratepayers can come from the renewable additions. And absent an extension of the tax credits, it's going to be very difficult to continue adding renewables without having a detriment to customers essentially. So I would say it remains to be seen, but in our Resource Plan, we do show additional acquisition of wind, whether that's self-build or through an RFP process. It's a transaction-by-transaction issue. Christopher Turnure - JP Morgan Chase & Co, Research Division: Okay. And then my follow-up question is on future acreage purchases. Has anything changed over the past months since the Analyst Day? Are there any kind of new opportunities that you can give us a little bit of color on, on that front and what you're looking at?

Yes. We're not actively seeking the increase on a leasehold dramatically. We've mentioned a couple of these exploratory projects that we're always working on. We don't typically disclose them because they're exploratory in nature. One, we don't want to tell people where they're at, because we do buy some leases as we see results. And then two, of their exploration wells, which the likelihood of a success is less than the likelihood of a failure typically in exploration. So we don't typically talk much about those until they're done. But we haven't made any significant change in plans regarding leasehold acquisition in any play since the discussion we had at the Analyst Day.

[Operator Instructions] There are no additional questions at this time. I would like to hand the call back over to Mr. David Emery, Chairman, President and Chief Executive Officer for closing remarks.

Thank you. Well, thanks for your attendance this morning, everyone. We certainly appreciate your continued interest in Black Hills. And for those of you who plan to be at the Edison Electric Institute Financial Conference here in the next week or so. We look forward to seeing you there. Have a great day.

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