Black Hills Corp (BKH) 2014 Q1 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Black Hills Corp. 2014 first-quarter earnings conference call. My name is Whitley and I will be your operator for today. At this time all participants are in listen-only mode. Following the prepared remarks there will be a question-and-answer session.

(Operator Instructions). As a reminder, this conference is being recorded for replay purposes. I would now like to turn the presentation over to Val Simpson, Finance Manager of Black Hills Corporation. Please proceed.

Thank you, Whitley. Good morning, everyone; welcome to Black Hills Corporation's first-quarter earnings call for 2014. With me today are David Emery, Chairman, President and Chief Executive Officer, as well as Tony Kleberg, Executive Vice President and Chief Financial Officer.

Before I turn over the call I need to remind everyone 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, Val; good morning, everyone. Thank you for joining us today. I will start on slide 3 of the webcast presentation for those of you who are following along. Today's discussion format will be similar to previous quarters. I will cover the quarter and highlight. Tony Cleberg, our Chief Financial Officer, will cover the financial update for the quarter and then I will come back on and discuss some strategic go-forward issues.

Moving to slide 5, highlights from the quarter. From a business perspective we experienced colder than normal weather really throughout most of our utility service territories compared to both last year and to normal weather primarily providing a positive impact to our Gas Utilities segment.

Highlights in the Utilities side of the business, we had a lot of activity in our Utilities during the quarter.

Our Cheyenne Prairie Generating Station construction remains on schedule and within budget, still expected to begin commercial operation in October.

Black Hills Power filed a rate request at the end of March with the South Dakota Public Utilities Commission for a $14.6 million revenue increase to cover increased expenses and infrastructure investments to serve customers primarily related to the Cheyenne Prairie Generating Station, the South Dakota customer portion of that plant.

On March 21 Black Hills Power retired three older coal-fired power plants due to federal environmental regulations, namely the EPA Boiler MACT rules.

On January 17 Black Hills Power filed a rate case with the Wyoming Public Service Commission for $2.8 million in revenue, again primarily related to the Cheyenne Prairie Generating Station, the share of that that will be dedicated to our Wyoming customers.

Moving on to slide 6, a continuation of our Utilities highlights.

Cheyenne Light last December filed both electric and gas rate cases with the Wyoming Public Service Commission to recover both increased operating expenses and investments in infrastructure for both electric and gas primarily driven by the Cheyenne Prairie plant.

After quarter and on April 30 Colorado Electric filed a request with the Colorado PUC to increase revenue by about $8 million to recover increased operating expenses and continued infrastructure investments in Colorado including the Busch Ranch Wind Farm, which was placed in service a couple years ago.

Then on February 25 our Colorado Electric Utility received a final written order from the Colorado PUC approving a settlement agreement that allows us to construct a new 40 megawatt gas-fired combustion turbine to replace the 42 megawatts W.N. Clark station that we retired as a result of the Colorado Clean Air Clean Jobs Act.

Also after quarter end, April 29, our Kansas Gas subsidiary filed the first rate case we've filed there since we acquired that utility in 2008 for approximately $7.3 million to recover additional investments and expenses since we acquired the utility.

Then finally our Utilities continued their emphasis on trying to purchase small systems in or adjacent to our service territories. We completed one small acquisition in Kansas adding about 70 new customers. We also filed for regulatory approval in Wyoming to close the transaction of 400 customers that we announced in January of this year. We don't expect that transaction to close until in the late second maybe third quarter some time.

Moving on to slide 7, oil and gas highlights, a new third-party cryogenic gas processing plant with a capacity of 20 million cubic feet a day was placed in service and started serving our production in the southern Piceance Basin on March 6.

The two Mancos Shale wells that we drilled in the Piceance Basin last year were placed on production during the quarter. The first 30 days of total production for the two wells was approximately 80 barrels of oil a day and 11.3 million cubic feet of gas a day. That gas had a Btu content of around 1,200 Btus per cubic foot and a natural gas yield of more than 1.25 gallons per mcf.

The rates were somewhat limited during that 30-day period as the plant experienced some minor operational challenges following start up where they were up-and-down periodically through that period.

The delay in not getting that production on until March, we had originally hoped to have it on early in the year, plus some other minor delays in our drilling program has led us to reduce our production guidance for the year. Tony Cleberg will talk a little bit more about our guidance assumptions when he discusses the financials here in a little bit.

Now we have disclosed some production information for those two wells, as I noted, but, as we've talked about previously, we do have a pretty strict confidentiality agreement that governs the operations of those wells. And so, our disclosure is going to be very limited on what we can discuss about those.

On the corporate side we declared a quarterly dividend of $0.39 a share during the quarter, which is a $1.56 equivalent annual rate and that represents our 44th consecutive annual dividend increase, a record we are very proud of. And then finally on January 30 Moody's upgraded our credit one more notch. That is the second upgrade from them in the past little over a year.

Moving onto slide 8, Q1 financial highlights. We earned $1.08 per share as adjusted compared to just $0.87 per share in the first quarter of 2013, representing a solid increase of about 24%.

Slide 9 provides a reconciliation of our first quarter 2014 income from continuing operations as adjusted against our Q1 2013 results. As you can see from the graph, strong performance in our Gas Utilities, Electric Utilities, Power Generation and Coal segments were partially offset by weaker performance in Oil and Gas.

Now I will turn it over to Tony Cleberg to give the financial update. Tony?

Thank you, Dave; good morning. As Dave mentioned, the first-quarter performance was very strong due primarily to the effective operational performance and the unusually cold weather in our Gas Utilities territories. Compared to 2013, our EPS increased 24% year over year to $1.08 for the quarter.

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 communicate earnings that better indicate our ongoing performance. This slide displays our last five quarters.

During the first quarter of 2014 we had no special items, so our EPS of $1.08 compares to the 2013 as adjusted EPS of $0.87. The 2013 as adjusted EPS excluded an $0.11 non-cash mark-to-market gain on the interest rate swaps and those were settled in the fourth quarter of 2013.

Slide 12 displays our first-quarter revenue and operating income. I will later explain the differences between the years. But here the main point is we are predominantly regulated generating 88% of our operating income from the Electric and Gas Utilities in the first quarter. Our operating income was strong, increasing $9.8 million or 12% compared to the same period in 2013. The cold weather in 2014 accounted for about two-thirds of the improvement in operating income.

Slide 13 displays our first-quarter income statement. On later slides I will discuss the segment revenue and operating income in more detail. But here I want to mention a couple of things that are noteworthy that impacted our first-quarter performance.

The first item, interest expense, declined by $6.1 million as a result of the refinancing debt and lower rate and settling the $250 million worth of interest rate swaps in the fourth quarter of 2013. Settling the swaps eliminated monthly interest expense charges.

The second noteworthy item is our EBITDA, the earnings before income tax, depreciation and amortization. During the quarter we achieved $126.5 million of EBITDA driven by the improved operating income. This is a 10% increase year over year.

Moving to slide 14, the left side of the slide displays our Electric Utilities segment revenue and operating income. The Electric Utilities revenue increased in the first quarter by $19.5 million from 2013 and this really reflects the higher fuel cost of about $14.6 million and an improved margin of $4.8 million from riders and higher industrial demand.

Operating income during the first quarter for the Electric Utilities improved $1.1 million, or 3% year over year. And this results from increased margin offset by higher expenses for employee costs and property taxes.

Looking at the right side of slide 14, you will note that the Gas Utilities revenue increased by $59 million resulting from increased gas volumes driven by the cold weather and the higher natural gas prices. Year over year fuel costs increased by $50 million and operating and maintenance expense increased by $2.2 million.

Compared to 2013, first-quarter operating income improved by $6.9 million. Both the distribution dekatherms sold and the operating income increased about 19% year over year. As you will recall, last year was slightly colder than normal and 2014 was unusually cold.

The cold weather was the primary driver of the improved operating income. So overall we are very pleased with the continued strong performance that we are seeing out of our Utilities.

The next segment on slide 15, Power Generation's operating income improved by $1.9 million compared to last year's performance. During the current quarter Power Generation saw strong operational performance and price increases for the PPAs that we have in place.

Moving to the right side of the slide, Coal Mining segment, we saw operating income improving the quarter by $2.1 million. About $700,000 of the improvement resulted from a favorable coal tax adjustment. Tons sold increased by 3% and the mining cost per ton decreased by 5%.

Part of the improved performance was attributed to a lower stripping ratio which declined from 1.0 to 0.8 and lowered the overburdened removal cost. As you may recall just over 50% of our coal production is priced on a cost-plus basis. We are encouraged by our continued improvement at our mine.

Moving to Oil and Gas on slide 16. The segment started slow hampered by difficult weather. Our two new gas wells in the Piceance Basin were constrained in January and February due to the delayed completion by a third-party of an additional take away capacity.

Overall, first-quarter production decreased 3% compared to the same period in 2013. The production increases in natural gas by 2% and the natural gas liquid by 20% were offset by a 23% decline in oil production. So our March production from the two new gas wells offset a year of decline curves on our existing gas production.

From a cost perspective our first quarter O&M expenses increased by $800,000 and our DD&A increased by $1.3 million compared to 2013. The actual depletion rate during the quarter was $2.25 per MMcfe, which was slightly higher than our original guidance. With a small production base and our development efforts the depletion rate can vary noticeably.

Sequentially the production from fourth quarter of 2013 to the first quarter of 2014 were aimed about the same in total with a 4% increase in natural gas and a 17% decrease in oil and a 30% increase and natural gas liquids. Prices received increased by 25% for natural gas and 2% for oil.

Moving to slide 17, our capital structure shows us at a debt to cap rate of 52.5%. This is a slight improvement from year end. With cash flow from operations and our debt capacity we have ample funding available for the capital expenditures and dividends throughout the year.

In the press release on slide 18, we increased our 2014 earnings guidance to the range of $2.65 to $2.85. This estimated range excludes special items and has been updated for the strength that we saw in the first quarter.

Slide 18 lifts the primary assumptions we use to develop our earnings guidance. We have also updated the assumptions related to the Oil and Gas segment which reflect a later start for the take away capacity in the Piceance Basin.

To conclude on slide 19, we are very pleased with our first-quarter performance. We continue to manage our operations effectively and we were helped by the cold weather. The midpoint of our 2014 earnings guidance continues to deliver double-digit earnings growth to our shareholders, a very important accomplishment that we consider. And with those comments I will turn it back to Dave.

All right, thank you, Tony. Moving on to slide 21 and the strategic objectives. As we discussed in some detail at our October Analyst Day in New York City, we have grouped our major strategic goals into four major categories with the overall objective of being an industry leader in essentially all that we do. Those four major goal categories include -- profitable growth, valued service, better every day and a great workplace.

Moving onto slide 22, in the profitable growth category. Strong capital spending drives our earnings growth. And we expect to spend about $1.2 billion in 2014 through 2016 with CapEx projected to be far in excess of depreciation. Much of that capital expenditure will be directed towards our utilities at continuing to provide excellent service to our customers by adding necessary infrastructure to serve their needs.

Slide 23 provides detail on both historical and projected capital spending by individual business unit and also breaks out our Electric Utilities into a few subcategories, generation and transmission being the notable ones broken out.

On slide 24, which is a subset of slide 23, we just provide more detail for select major utility projects and also give you some indication of some spending in the 2016 and beyond time period.

Slide 25, helping drive our strong earnings growth in the next couple of years is our Cheyenne Prairie Generating Station. Again, that is a $222 million, 132 megawatt plant jointly owned by two of our utilities, Cheyenne Light and Black Hills Power, and, as I said earlier, it will be in service by October and we expect it to continue to be on time and on budget. As you can see from the photos on that slide, we are making great progress on the project.

On slide 26 from a value upside perspective we remain very focused on our Oil and Gas assets. We plan to prove up and capture the substantial value upside of our existing Oil and Gas properties. We also plan to continue to pursue disciplined oil exploration opportunities in plays with impactful reserve potential.

Our primary emphasis is on the execution of our Piceance Basin Mancos Shale drilling program. As I stated earlier, we completed the two wells that we drilled in 2013, those wells are on production now.

In 2014 we plan to drill and complete up to six additional horizontal wells on the Mancos formation in the Piceance Basin and also continue infrastructure improvements in the Piceance Basin, primarily gas and water infrastructure to help us make our drilling program more efficient there. And we also plan to do some selective oil well exploration drilling during the year.

Moving on to slide 27. We are very proud of our dividend track record having increased our annual dividend for 44 consecutive years, one of the longest streaks in the utility industry.

Slide 28, during 2013 we achieved our goal of being rated a BBB equivalent or higher by all three major credit rating agencies and, as I stated earlier, Moody's upgraded us an additional notch in late January of this year.

Slide 29 is a summary of pending regulatory activity, much of which is rate case filings where we are seeking a fair return on the substantial capital investments we have made in our utility infrastructure primarily to better serve our customers. That slide lays out each regulatory filing, some detail on the filing and then a proposed timetable that we assume we'll be able to reach a decision or receive a decision in each of those pending hearings.

Slide 30 talks about operating performance and 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, one of the youngest in the industry.

Slide 31 also points out our exceptional operational performance relative to peers and also includes some things we've done to improve our customer experience, particularly in the technology area.

And then on slide 32, it illustrates our great safety record both in operating safety and in construction safety for our power plants and then highlights the quality of Black Hills Corporation as a place to work. We're particularly proud of some of the recognitions we received related to being a great workplace and an engaged workplace.

Finally slide 33 is our scorecard. You've seen this before -- we reformatted it a little bit this quarter to be consistent with the four major strategic goals I mentioned earlier. But the scorecard is our way of holding ourselves accountable to you, our shareholders.

We set forth our goals at the beginning of the year and allow you to follow along on our progress towards achievement of those goals as we go through every quarter during the year. That concludes our remarks, we would be happy to entertain any questions if people have them.

(Operator Instructions). Dan Eggers, Credit Suisse.

Dave, we appreciate the data on those two wells kind of running or being up and running at least for a month in the quarter. Can you maybe help us or is there a way to help us ferret out maybe what the performance would have been in the quarter if the process and equipment would have worked like it was supposed to?

I don't know how much more we were -- how much harder we would have pulled those wells, Dan. I mean we had one of the wells flowing at a rate of up around 8 million a day. But one of the things we learned when we completed some of our earlier wells in the 2011 program is by bringing the wells on a little bit slower we seem to have better estimated ultimate reserves.

And if you look at our San Juan Basin data, which in our appendix we always put that production information in there that shows our well relative to a couple offset wells drilled by another company. We believe pretty strongly that the way we brought that well on it, which was a little slower initially, is going to result in a quite a bit better ultimate recovery.

So while we pulled the wells a little harder in the first quarter and may have done it a little bit harder if the plant had stayed operating continuously I don't think we would have pulled them that much harder. Just again, because we think we will get better ultimate results.

Do you have a view on when you will have more perspective watching these performances what the reserve recovery is going to be out of these wells?

Yes, realistically you need at least a few months of production to have a real good estimate. Because until your production rate actually starts the decline, starts to flatten a little, you are just basically using a type curve based on other wells to project your reserves. So it really is going to take a while.

Now that being said, I don't think we are seeing any behavior in these wells that we would view as abnormal compared to expectations. So we are happy with what we see and assume they will perform as we expected. And we do have a type curve in the back for Piceance Basin wells based on the lateral length that we have. We would expect these to perform according to that based on what we know today.

So you would expect them to -- the 8 million a day if you ran them at those levels I guess people talked about kind of well performance in that area 10, maybe a little over 10 a day. If you would have pulled them hard is that -- do you think you would have performed at those levels and this is just a preference as to reserve recovery strategy? Or did your wells kind of give a different look than what we have seen at other folks?

We were very pleased with the way the wells performed and the production rates are really a function of two things -- one is a preference not to pull them too hard and then the other the up-and-down nature of the cryo plant, which of course was beyond our ability to control.

And then, Dave, do you think if you have three more months between now and say second-quarter results are you going to be able to talk more about kind of reserve recovery potential out of these wells once you see more performance or does the agreement limit what you will be able to say on that front?

Well, the agreement significantly limits what we will be able to say and we did have some discussions with our partner there at least related to releasing some production information and they agreed to let us do that. But it doesn't necessarily mean they will agree to let us release additional information if we ask.

So we may or may not be able to give you that data in the next quarter. I know that is not what you want to hear, but we have got to get cooperation from the third-party to release anything. So we will continue to try to give you what we can under the terms of the confidentiality agreement.

And then what has kind of varied the decision of how many wells actually get drilled this year? Meaning up to six, is interest in delineation but you have got nine months left. So I would assume you have to have kind of a view of how many of those six get done.

Yes. I mean, it is hard to over drill all six. In oil and gas drilling you always have some unknowns -- rig availability, frac crew availability, timing of getting certain rights of way agreements and things like that. We don't anticipate any problem and we hope to get started kind of late second, early third-quarter drilling and should be able to make pretty good progress on those.

But there is always some uncertainty. So we had our bed a little bit and say up to six. But it is our intention to drill six whether we will get them all completed and producing by year end kind of depends when we get started and some other factors.

And I guess I will ask another question since you have other businesses. Can you just give a rundown on any implications of CSAPR coming back to life? Or is there more attention on coal ash? Can you just remind us where you guys stand on that and what environmental CapEx obligations you might have to remediate?

Yes, we really have very little -- our fleet is about as modern as they get absent CO2 scrubbing, we are about as clean as anybody in the country if not cleaner than most. So we really don't have any concerns about that.

The coal ash rule is obviously a little bit of a concern for us. I don't think it would be a major issue for us. We dispose of our coal ash in our pit as part of our mine backfill and we have a permit that allows us to do that, we have done extensive testing on groundwater leaching and things like that as part of that permit process.

But the worst-case scenario is if we had to we might have to line a pit and put the ash in it and then seal it as we reclaim our mine. It wouldn't be a huge cost driver for us. I mean certainly it would be some of a cost driver and that would be reflected eventually in our utility rates. But probably not a huge issue for us and certainly the CSAPR rules I don't think are either.

Great, thank you, guys.

(Operator Instructions). David Arcaro, Sidoti.

I had a quick question, so in the power generation and coal mining segment operating profit was quite a bit higher than it has been in the last couple of years. Wondering how repeatable are those results or how repeatable are the drivers of results in those two segments?

We operate it at a very high level of availability in the power generation. When you operate that high unfortunately there is only one way to go. The other side is each year we have purchase price adjustments that come into play in the first quarter for some inflationary cost increases. So that helped step it up a little bit too.

The coal mining, I did mention the $700,000 coal tax adjustment, that is a catch-up. Someone else made a settlement, we made the same argument and we were able to get an adjustment for coal tax. So, but and then the other thing is the overburden removal, the 0.8 was unusually good for us. So the overburden stripping ratio will increase in the future.

But on the same token, David, as you recall, we are going into pricing changes for the -- about 35% of the coal that goes to PacifiCorp, so that should improve margins again later this year.

Got it.

So we will have some cost increases in coal mining for the overburden, but we will also have an improvement in the margin from the standpoint of this new contract.

But it sounds like on the PPA side, those PPA adjustments that happened in the first quarter, they are good through the end of the year?

Yes.

(Multiple speakers) [provision]? Okay.

Yes.

And then you also -- it looked like you posted some pretty strong electric volume growth. Wondering if there was anything interesting or unusual driving that?

There was an increase in the industrial load is what really drove it. And so -- yes. If you have a business in your area that is cranking up and responding then we will see the type of an industrial load increase.

And then one more quick question. It looked like there was a pretty high level of natural gas liquids that you sold this quarter. What drove that? It looked like 30% I think quarter over quarter growth.

Yes, a lot of it came from the Mancos Wells in the Piceance Basin, not all but quite a bit of it did.

Got it. Okay, great. Thanks very much.

(Operator Instructions). There are no further questions in queue. I would now like to turn the call over to Mr. David Emery. Please proceed, sir.

Thank you. Thanks for your time and attention this morning, everyone. We certainly appreciate your continued interest in Black Hills. And as Tony said and certainly I did as well, we are pretty excited about our performance in the quarter and have a great outlook for the rest of the year.

So thanks for your continued interest. And for those of you who are going to be at the AGA conference here in a couple weeks, we will see 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.