Black Hills Corp (BKH) 2014 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Black Hills Corporation 2014 third-quarter earnings conference call. My name is Adrian, 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.

Thank you, Adrian. Good morning, everyone. Welcome to Black Hills Corporation's third-quarter 2014 earnings conference call. Leading our quarterly earnings discussion today are David Emery, Chairman, President and Chief Executive Officer; and Tony Cleberg, Executive Vice President and Chief Financial Officer.

Before we begin today, I would like to note that Black Hills will be attending the EEI financial conference next week in Dallas, Texas. You can find our presentation materials and webcast information on our website at www.BlackHillsCorp.com under the investor relations heading.

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 call over to David Emery.

Thank you, Jerome, and good morning, everyone. I'll start on slide 3 of the webcast deck for those of you who are following along. Our format will be similar to previous quarters. I'll give a quick overview of the quarter, Tony Cleberg will talk about financials and give an update there, and then I'll give an overview of forward strategies.

Moving on to slide 4, just incidentally that is a picture of our new Cheyenne Prairie generating station, if you're interested. Slide 5 is third-quarter highlights. We had a very busy and productive quarter.

From a business environment standpoint, we had cooler weather in our utility service territories that benefit our natural gas utility, especially in September, but tempered results a little bit earlier in the quarter at our electric utilities.

Highlights for our utility subsidiaries, recently we announced an agreement to acquire a small natural gas utility, a little under 7,000 customers, in Northwest Wyoming. We still have to file for regulatory approval and don't expect that to close until probably around midyear next year.

Black Hills Power filed for approval in both South Dakota and Wyoming to construct a new 144-mile, $54 million transmission line that will originate Northeast Wyoming and end in Rapid City, South Dakota. That process we expect to evolve over the next couple quarters.

Our Cheyenne Prairie generating station, our new $222 million, 132-megawatt gas-fired -- natural gas-fired power plant was placed into commercial service on October 1 on time and on budget. The new rates for Wyoming customers of both Black Hills Power and Cheyenne Light were in effect October 1. We've implemented interim rates in South Dakota effective October 1, and we have a rate hearing in South Dakota in January.

Black Hills Power and Cheyenne Light, the two owners of the plant, also closed on the financing for the plant during the quarter.

Moving on to slide 6, a continuation of our utility highlights. Cheyenne Light recorded a new all-time peak load in July. Our power generation subsidiary submitted both solar and wind bids on July 31 in response to Colorado Electric's request for resource proposals. Colorado Electric is currently evaluating those bids, and we would expect to select a bidder and negotiate a reasonable contract and then seek Colorado LPC approval prior to the end of February next year.

In April of this year, Colorado Electric filed a request with the Colorado PUC to increase revenues to recover increased operating expenses and infrastructure investment. We've had a hearing there with an administrative law judge. And last week on October 28, the ALJ issued his recommended decision, which was relatively favorable for the Company. The ALJ's recommended decision is subject to exceptions and final commission approval. We expect that to be obtained and rates to be effective about year end.

On October 24, our Kansas Gas utility reached a settlement agreement to increase base rates. We have a hearing scheduled there for November 12 with the Kansas Corporation Commission and would expect to implement new rates effective in mid-January.

Power generation, we closed on the sale of our Gillette combustion turbine number II to the city of Gillette, Wyoming, for about $22 million. As part of that deal, we will operate the plant for Gillette, and we also have an economy energy agreement which is good for 20 years. Basically, if we can buy energy for the city cheaper than we could run the plant for them, we share in the savings to them for that 20-year period.

Our coal mining subsidiary completed negotiations for a coal price reopener for the Wyodak power plant and the operator of the plant. The new coal price is $18.25 a ton, which is an increase of approximately $4.75 a ton effective July 1.

On the oil and gas side, we are continuing to make progress on our Mancos drilling program in the southern Piceance Basin. We've drilled and cased and cemented two wells. Have a third well drilling and will commence completion operations on the two wells prior to the end of the year. I'll elaborate a little bit more about that here in a little bit.

Moving on to slide 8, corporate highlights. Last week, our Board of Directors declared a quarterly dividend of $0.39 a share, which is equivalent to an annual dividend of $1.56. We also announced several executive leadership changes following our Board meeting last week on October 29. Those changes follow an extensive succession planning effort that's been going on for a couple of years.

Notably, Tony Cleberg, our Executive Vice President and CFO, will retire at the end of March. Replacing him effective January 1 will be Rich Kinzley; he's our current Vice President and Controller. He will become Senior Vice President and Chief Financial Officer on January 1. And then effective November 1, Brian Iverson, who is our current Vice President and Treasurer, assumes the role of Senior Vice President of Regulatory Government Affairs and Assistant General Counsel. Both of them will report directly to me, and they'll both retain their current duties as Controller, Treasurer respectively until those positions are filled sometime in the next couple of months.

Slide 9, third-quarter financial highlights, we earned $0.60 per share as adjusted compared to $0.47 per share in the third quarter of 2013, a strong increase of 20%. Most of our businesses were stronger; a little bit weaker particularly in the oil and gas subsidiaries.

Slide 10 provides a reconciliation of our Q3 2014 income from continuing ops as adjusted for the third-quarter 2013 results.

Now I'll turn it over to Tony Cleberg for the financial update. Tony?

Thank you, Dave. Good morning. For everyone on the call, thank you for taking the time to listen today. Many of you are very knowledgeable about our Company about who we are, where we've been and where we're going.

Our third-quarter performance continued to bridge our path to the future by delivering both on business execution and financial results. As far as the third-quarter financial results, we improved our adjusted earnings per share by 28% year over year. Two large contributors coming from lower interest expense and an improved tax rate.

As you will recall, the weather helped us outperform in the first quarter of this year; but in the second and third quarter, we experienced very mild weather that dampened our operating income. If you compare our adjusted earnings per share for the first nine months of 2014 to the same period in 2013, we improved by 22%.

Moving to slide 12, we report GAAP earnings and reconciled earnings as adjusted, a non-GAAP measure. We isolate special items, communicate earnings that we believe better indicate our ongoing performance. This slide displays the last five quarters. And in 2014, we have had no special items, so our third-quarter GAAP earnings per share of $0.60 compares to our 2013 adjusted earnings per share of $0.47.

The 2013 adjusted earnings per share excluded a mark to market gain of $0.05 on interest rate swaps that we settled near the end of last year.

Slide 13 displays our third-quarter revenue and operating income. Later, I'll describe the year-over-year changes by segment, but here the main point is we are predominantly regulated, generating 82% of our operating income from our utilities in the third quarter.

Our operating income declined by about 2%, or $1.2 million, compared to the same period in 2013. And this was driven by our oil and gas segment performance, which was lower by $2.1 million compared to 2013. Mild weather during the quarter minimized the lift we expected from our electric utilities.

Moving to slide 14, we display our third-quarter income statement. Some of the key points include interest expense declining by $5.9 million. This resulted from actions taken in the fourth quarter of 2013. Number one, we refinanced debt at a lower rate; and number two, we settled $250 million of interest rate swaps. Settling the swaps eliminated a monthly interest charge.

Another key point during the quarter is we received information from the IRS that allowed us to record a tax benefit of $1.3 million, lowering our tax rate. Another key point is while our operating income declined by about 2% primarily to the oil and gas performance, our EBITDA was flat [since] 2013 during the quarter.

And lastly, comparing the first nine months of 2014 to the same period in 2013, our EBITDA and our operating income improved in that mid-3% range.

Moving to slide 15, we display our utility segments' revenue and operating income. On the left side, you can see the electric utilities' third-quarter revenue increased by $3 million compared to the same period in 2013. This was due primarily to riders and higher fuel costs. Gross margins were lower by $1.7 million compared to the prior year. Mild weather lowered our margin by $3.4 million, and this was partially offset by increases for riders and for industrial demand. The average cooling days declined by 26% during the quarter compared to the same period in 2013 and lowered our residential demand.

We saw our operating income improve slightly year over year, driven by lower expenses which offset the shortfall in the margin.

Looking at the right side of this slide, you'll note that the gas utilities had strong performance, particularly considering it was a shoulder quarter. In contrast to the electric utilities, the cooler weather in the gas utilities increased revenue. For the quarter, heating degree days were about 6% above long-term averages. But compared to the same period in 2013, heating degree days increased by 73%. The cooler weather increased our retail decatherms sold by 13% year over year.

Our O&M expense increased year over year by $1.2 million, primarily due to increased bad debt expense which was driven by higher revenues. Compared to 2013, the third-quarter operating income improved by $800,000. So looking at our overall utility performance, cooler weather helped the gas utility; but in the electric utilities, the improved rates were dampened by the mild weather.

Both of our utility segments had good expense management, and we continue to see annual customer growth at about 1%.

The next segment, power generation's operating income as adjusted declined by $800,000 compared to last year's performance. During the quarter, power generation saw strong operational performance. The decline in operating income was almost all attributable to higher property taxes.

Moving to the right side of slide 16, the coal mine segment saw an improvement of $1 million in the third-quarter operating income compared to 2013. This resulted from a mixture of 5% higher prices, 6% lower mining costs per ton, and 5% lower tons sold. Strong cost management offset the impact of a higher stripping ratio of 0.9 compared to 0.6 in 2013.

During the quarter, we saw about $300,000 improvement for the impact of the new contract pricing to the Wyodak power plant. So we had good performance in our mining segment.

Moving to oil and gas on slide 17, we saw higher total volumes compared to 2013 offset by lower prices for both gas and oil. Our overall third-quarter production increased 6% compared to the same period in 2013.

Breaking down our production improvement, we saw a 5% increase in natural gas volumes, 40% increase in natural gas liquids, and this was partially offset by a 2% decline in oil.

We had good performance from a cost perspective. Our lease operating expenses and overhead expenses were flat year over year. Production taxes increased about $800,000 on volume increases. The DD&A increased $1.4 million compared to 2013. From an operating income standpoint, our loss in this segment increased by $2 million compared to the same period in 2013, primarily due to production increases offset by 12% lower average net price received. The depletion rate increased by 16% compared to Q3 of 2013, due primarily to adding higher-cost oil drilling to our cost pool for non-operated wells.

Sequentially, from second quarter to third quarter production declined slightly by 4%. Natural gas production decreased less than 1%. Oil production declined by 10%, and natural gas liquids declined by 21%.

So with the declines in production and price, our Q3 oil and gas revenue was down by about 11% sequentially compared to the second quarter. And the operating loss increased by $2.1 million.

Moving to our capital structure slide shows our current capitalization. We had Moody's and Fitch and an equivalent of a triple B plus, an S&P at a triple B flat. At quarter end, our net debt to capitalization rates show had increased by 0.5% from December 31, and it was at 53.4%. With the cash flow from operations and our debt capacity, we have ample funding available for capital expenditures and dividends through 2015.

Slide 19, in the press release we improved our 2014 earnings guidance to a range of $2.80 to $2.95. So we expect another year of strong double-digit earnings growth. For 2015, we initiated our earnings in the range of $2.90 to $3.10. This is based on a number of assumptions listed in the press release and on slide 20. These assumptions address similar items that we've included in the past. One reminder in our 2014 performance includes a positive of about $0.08 for weather and the $0.03 for the tax benefit that we saw in the third quarter.

On slide 21, to conclude, our third-quarter performance continues to deliver solid earnings growth. We are proud to continue to perform in an excellent mentor for our customers and our shareholders. And with those comments, I'll turn it back to Dave.

Thank you, Tony. Moving on to slide 23, forward strategy. We group our strategic goals into four major categories with the overall objective of being an industry leader in all we do.

On slide 24, related to growth, our strong capital spending drives our earnings growth. We project strong capital investments far in excess of depreciation for the next several years.

Slide 25 provides a detail related to historical and forecasted capital spending by business segment. Slide 26 is a subset of the information on slide 25, really just provide some more specific detail for some of our select major utility projects and includes a little bit of spending in the 2016 and beyond timeframe to show some future projects that we have planned.

Slide 27, as I mentioned earlier, helping drive our earnings growth in 2015 and 2014 as well is our Cheyenne Prairie generating station. Construction was completed there on October 1. As I said earlier, the plant was on time and on budget, a tremendous accomplishment for that jointly owned facility by Black Hills Power and Cheyenne Light. We had a fantastic safety record on the project as well with a total case incident rate of less than 0.9 and zero lost time accidents, a pretty remarkable accomplishment by our generation construction group.

Moving on slide 28, another earnings growth opportunity we are pursuing is a utility cost of service gas supply program, or rate basing of reserves, if you will. We discussed this initiative in more detail during our October 6 analyst day, and there was more information included in that analyst day deck which is also on our investor relations tab of our website.

We are in the process of meeting with utility commissioners' staffs and consumer advocates across our service territory. Those meetings continue to go well. We have had a second round of meetings now where the first round was more general information meetings. The second round is what we are calling technical workshops, where we are going into a little bit more detail, getting into some of the nuts and bolts on how we could propose a program and how it would work technically.

We are still evaluating properties for inclusion in the constant service cash program. If we find the right opportunity, we would look at purchasing that. Obviously, we also have oil and gas properties of our own. And when they get to the right state of maturity, it's possible those could be included in the cost of service gas program as well. We hope to sometime in the next year so get to the point where we can propose a formal program; need all the pieces to come together. Regulators, obviously, have to be on board, and then we have to have a property that we are comfortable proposing to the regulators. But we are headed in the right direction.

Moving on to slide 29, our oil and gas assets offer substantial value upside for our shareholders. From a strategy perspective, we plan to prove up and capture the value of our existing oil and gas properties. We also plan to continue to pursue disciplined oil exploration opportunities, especially in plays that have impactful reserve potential.

We are very focused on the execution of our Mancos Shale drilling program. As we've said before, we plan to drill and complete 6 wells each in 2014 and 2015. Once we get through that program, we should have a reasonable handle on the value of the Mancos properties to us. With those results, we'll consider strategic options after 2015.

On slide 30, which is a continuation of our oil and gas strategy, that slide provides a little more detail of our 2014 Mancos program. As I said, our plan was to drill and complete 6 Mancos wells in the southern Piceance Basin during the year. We are running a little behind schedule. We have drilled, cased and cemented 2 wells that are being drilled on a single pad. A third well from that same pad is currently being drilled at a depth of about 15,000 feet. We have drilled about 7,000 feet of the horizontal lateral net well, and we've got about 3,000 or so feet to go. We will then case and cement that well, move the drilling rig to a separate pad to drill 3 more wells. Once the drilling rig has been moved, we'll come in and frac and complete the first 3 wells. Hope to have those fracked and at least flowing back before the end of the year.

We'll place them on production late in the year and probably continuing into the first quarter.

The second 3 wells we are drilling will be completing in the first quarter of next year.

Slide 31, we continue to be very proud of our dividend track record, having increased our annual dividend to shareholders for 44 consecutive years. As I mentioned last week, our Board declared a $0.39-a-share quarterly dividend.

Tony mentioned our credit ratings already, but, on slide 32 we have made significant progress in improving our credit rating over the past several years. And now two of the three major agencies have our credit at the equivalent of a BBB plus.

Slide 33 provides an update of our pending regulatory activity. Much of that is rate case related, where we are seeking a fair return on the substantial capital investments we've made in our utility businesses to better serve our customers. I've spoken about most of these already. We'll highlight the Black Hills Power South Dakota rate case a little bit. That hearing is scheduled for January 27 to 30. We did implement interim rates effective October 1. We would expect new rates to be approved and finalized in the first quarter of 2015.

Slide 34 exhibits our superior power plant availability and starting reliability compared to our industry peers. It also demonstrates that we have a very modern generation fleet. Now with our recent coal plant retirements in the last year and commercial operation on Cheyenne Prairie, our average fleet life is about 12 to 13 years, which is very young.

Slide 35 illustrates some of our continued progress we've made to improve our operational efficiency and enhance our customers' experience in doing business with us.

Slide 36 illustrates our strong performance related to electric reliability. We continue to perform in the top quartile there. That's a key goal and objective for our overall electric utilities.

Slide 37 highlights our safety record and also lists several recent recognitions we've received that demonstrate our focus on operational excellence. And finally, slide 38 is our 2014 score card. The score card is our way of holding ourselves accountable to you, our shareholders, for what we accomplish during the year. It does include several items that have been updated based on progress through the third quarter.

That concludes our remarks. We'd be happy to take questions if anyone has any.

(Operator Instructions) Dan Eggers, Credit Suisse.

It's actually Matt Davis. So just a question on the drilling program with being a little behind this year -- and you're going to get the three wells, I guess, producing some time at the end of the year or in the first quarter. What's the confidence level being able to drill those additional 9 wells next year and not seeing an additional delay go kind of push into 2016? How are you kind of laying out that program across 2015?

Yes, we believe that we'll be able to take the drilling rig we have and just continue drilling in the spring on those next 6, Matt. We don't think that our results this year will really have any significant impact on our plan for next year, barring any unforeseen circumstances. Our plan is to just continue to drill continuously until we finished all 12 of the 14 existing wells.

And then how many days of production do you look to get out of the well before you feel comfortable kind of putting that information out into the market? I know we had discussed somewhere around 30, 60 or 90 days. I just want to get a better feel for how much you felt comfortable with from those wells.

Yes, it really depends on the production behavior. Typically once we get most of the frac water cleaned up, which can take two to four weeks on just that part, another 30 days is usually reasonable. Sometimes it takes more; it really depends on the individual well behavior. But once we get 30 to 60 days of good continuous, relatively clean production, we are typically comfortable releasing that information. You know, we may not be completely comfortable booking reserve yet, but sometimes we want to watch the decline behavior for a few months. But we would be comfortable putting out initial production once we hit 30 to 60 days of good clean production history, typically.

So would that be around -- that would be probably in the second-quarter call. Is that correct timing-wise for these wells that you guys are drilling right now?

Yes, possibly. I'm hopeful we'll have a little bit of information in time for the first -- or the year-end call, if you will, that occurs in February. We'll just have to see how things go in completion operations. I think as long as the weather holds we might have some information by then. But, realistically, most of it will be in the next quarter after that.

So the first quarter, excuse me, for --

Yes.

And then can you just talk a little bit about the tax benefit that you had this year and, kind of looking forward, if there's anything else that we can be on the lookout for that could help you on your tax rate?

The tax rate, we've got 2009 and -- excuse me, 2007 through 2009 under examination right now. And so we've gone through it. We believe we've got it recorded correctly. We have taken a certain position, and we were delighted that the IRS saw the position that we took was accurate. But we probably weren't as confident of recording the expense related to that, and that's why we had the positive impact this quarter.

So it's pretty hard to assess whether or not we're going to be up or down on the tax impact from an expense standpoint. We hover right in at that 34% rate, though, pretty consistently -- 34%, 35%.

Okay. Thank you very much, guys. Congratulations on a good quarter.

(Operator Instructions) Matt Tucker, KeyBanc Capital Markets.

Congrats on nice quarter. First question on the guidance. I know you don't give guidance by segment, but could you just talk a little bit about the key drivers we should think about underlying your growth assumptions for next year?

Most of its related to all the activity we have with spending. We do expect a little more production on the oil and gas side. That number is included in the guidance. But we have got a lot of rate case activity that we are finishing up late in the year here. All the Cheyenne Prairie generating station obviously is one of our larger items, but we've got several rate cases. I think grand total, we will have completed 6 cases this year or early next year, so that's one of the biggest drivers. Had a lot of investment in most of our utilities driving that.

That makes sense. Thanks. And I guess specifically on oil and gas, can you give us a sense of how much earnings improvement you're expecting there? Or at least do you expect it to be profitable in 2015?

Well, we're going to lose money in 2014 for oil and gas segment at the operating level, and we expect to reduce that loss quite a bit in 2015.

Got it. Thanks. And your forecast also suggests pretty nice production growth next year. How much of that should we assume is driven by the six Mancos wells that you plan to drill this year?

Well, this year and the wells we plan to get on next year, that's going to be one -- a pretty significant driver. We do have some scattered drilling elsewhere that will contribute to production in a semi-meaningful way, but the Mancos is going to drive a lot of it.

Got it. Thanks. And shifting gears, could you give us the overall cumulative weather impact so far this year in terms of earnings or margin? Sorry -- versus normal?

Yes, that's the $0.08 I talked about from the reminder in the earnings guidance that we have about $0.08 positive for the year due to weather.

Got it. My apologies; I missed that.

That's okay.

And then just on the RFP in Colorado, could you comment on how many bids you received that were not from your power generation business?

No, we really can't. We've got a real strict internal wall between our bid evaluation team and the people who have knowledge of what we submitted for bids. So we did get a number of bids -- and I can share that much -- in addition to our own. But a specific quantity and who they're from, I really don't know, frankly, and can't know at this stage.

Okay. Fair enough. And then just on the Wyodak coal price increase, could you tell us when exactly that took effect? And I believe you mentioned a $300,000 improvement related to that. I just wanted to clarify, was that in terms of earnings?

Yes; that improved operating income in the third quarter. And the contract started July 1. We put in there that the [improvement] pricing by $4.75 per ton. The thing that you need to remember is that we are digging -- that stripping ratio that increased from 0.6 to 0.9 is going to increase quite a bit again next year. So our cost will go up, but we'll still have quite an improvement in our per-ton profitability on that contract.

The other thing to remember on coal price is royalty and tax burden is pretty heavy on that, and that comes off right off the top -- typically runs in that 30% to 40% range. So that takes a big chunk right off the top of the increase.

Sure. Thanks. One last follow-up since you mentioned the strip ratio, it has remained somewhat stable this year while higher than last year; still significantly below where it was for several years prior to that. So you mentioned it increasing next year. How sharp of an increase should we expect? And does it kind of revert back to that 2 times, 2 times plus type ratio almost immediately, or is there more gradual ramp towards that type of ratio?

I think what you're going to see is you're going to see sort of the same type of degradation that we saw this year. So 0.6 to 0.9, you can expect it to -- it went up 50%, it's probably going to be somewhere around there again next year.

Yes, one place you can look is in the analyst day deck that we should you on October 6, and that webcast deck is on our website. It has a specific map that shows the overburden by year, and that will give you a real good sense. I think the strip ratio for next year averages about 1.4, 1.5. But it is specifically on that slide in the analyst day deck. And it is listed for the next several years, so you can see how our overburden costs will be increasing there.

Perfect. Very helpful, guys. Thank you.

You bet.

Sir, there are no more questions in the queue at this time. I'd like to hand the call back to David Emery for closing remarks.

All right. Well, thanks for your time and attention today, everyone. We appreciate your continued interest in Black Hills. We are excited about our quarter, and we're excited about our future opportunities. Thank you for your time and attention and your continued interest in the Company. Have a great day.

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