Black Hills Corp (BKH) 2005 Q3 法說會逐字稿

Welcome to the Black Hills Corp. quarterly earnings conference call. At this time, all participants are in a listen-only mode. Later, we'll conduct a question-and-answer session. Instructions will be given at that time. (OPERATOR INSTRUCTIONS). As a reminder, this call is being recorded. I would now like to turn the conference over to our host, Chief Financial Officer, Mark Thies. Please go ahead.

Good morning, everyone and welcome to Black Hills Corporation's third-quarter earnings call. I would like to refer you to our cautionary language regarding forward-looking statements relating to any forward statements we make. We have that language in all of our press releases as well as our quarterly and annual filings with the SEC. So please read that in conjunction with what we're going to talk about here today.

We are here to talk about the results in the third quarter for Black Hills Corporation in which we had a net loss of 23.9 million or $0.73 a share compared to income of 17.1 million and $0.52 a share in the third quarter of last year. For the nine months, we had net income of 6.6 million or $0.20 a share compared to 38.2 million or $1.17 a share. Included in that, we pre-released a week ago or last Friday certain unanticipated items and those items did impact our third-quarter and nine months ended results.

For the year, income from continuing operations was down $31.8 million or $0.96 a share and that included a $0.99 a share or $32.7 million non-cash impairment charge at our power production facility in Las Vegas that we call Las Vegas Unit Number I. In addition, we had 6.1 million or $0.18 a share of increase in corporate costs and that included an $0.18 per share write-off of certain development costs, substantially all of our development costs that were capitalized in the third quarter as well.

Our electric utility was down $4 million or $0.12 a share in the quarter and we had previously released in the second-quarter release an unanticipated powerplant outage or unplanned powerplant outage at our Neil Simpson Unit II in our utility and that -- due to the -- that is one of our lowest cost powerplants and we had to go out secure additional power. We had said that we had 5 to $0.07 a share loss expected there and we were in that range for that.

We had a $1.7 million decrease or $0.05 a share in our marketing and transportation earnings and that included again another unanticipated item, a settlement, a legal settlement on a class-action litigation that we had previously disclosed in our 10-Q and our 10-K and that was approximately $0.05 a share. We did increase our earnings from our oil and gas business 2.3 million or 85%, $0.07 a share, due to stronger production and stronger prices.

In our release, in recognition of our belief that we have continued confidence in our businesses going forward, we did put out fourth-quarter 2005 earnings guidance of $0.55 to $0.60 a share as well as full-year 2006 guidance of $2.10 a share to $2.25 a share, expectations for next year. Historically, we don't issue quarterly guidance but we felt it necessary with all the unanticipated items in the third quarter that occurred to put out the fourth-quarter guidance so the shareholders could have a sense of where we expect to be as well as full-year guidance.

From our business perspective, our oil and gas business continues to operate very strongly. We had a 13% increase in our production in the quarter. For the year-to-date, we're 14% ahead of last year in our oil and gas production and that is in line with our expectations in which we say we like to grow our oil and gas production at 10% a year. So we are slightly ahead of that for this year and we do expect to continue to grow our production next year as well in our 2006 guidance.

We included the effects of the strong product prices. We have certain hedges on our oil and gas. We have historically said 25 to 50%, including the internal hedge, business hedge, with our internal usage at both our electric utility and our Las Vegas I facility. Las Vegas I recall was the only plant that we had that we had exposure to long-term natural gas prices. The rest of our plants are either tolling arrangements or are electric utility. Our electric utility has some impacts for gas and then we have one coal plant in which we control the fuel for our nonregulated generation assets. So our oil and gas business is going very strong and we expect that to continue into next year and we expect the effects of our hedging, certain of our hedges roll off in October and we will continue to monitor where we will be in our hedging but the current strong product prices lead us to believe that we will get a good result going forward or an increased result from our oil and gas business in our 2006 guidance.

We included in that specific prices to give the shareholders an opportunity to have a relative expectation in where our oil and gas business will be. We included the average received prices of $7.94 for gas compared to the NYMEX price of $10.11 for Mcf, not per share, I'm sorry, for natural gas.

In our generation business, again, we had very strong or very consistent results as we had 97%, 97.8% availability at our powerplants. They continue to run very strong and have great availability and recall that is what -- with our tolling arrangements, we get paid based on our availability. So we believe that is run very strong. We had no change at 964 megawatts of capacity in our generation business.

Our marketing and transportation business, again, was impacted primarily by a settlement, a litigation settlement, that we made in the quarter as well as our oil marketing was down primarily due to the effects of Hurricane Rita that occurred in the quarter and shut down that operation for a period of time.

Our coal mining business had a very, very flat impact with $1.6 million of income this year versus 2.5. They were affected. That's more than flat. I apologize. But we had a tax settlement and tax reserve adjustment that affected last year's income by $1 million and we were affected by the Neil Simpson outage.

One additional impact, our electric utility with that powerplant down, we also set a new peak of 401 megawatts within the quarter and we had to purchase additional power to serve our retail customers and our retail load and that was at a time when we had one of our lowest cost resources off so we had to buy higher priced gas and that affected our electric utility results as well in the quarter.

I would now like to turn the conference call over for questions.

(OPERATOR INSTRUCTIONS). Michael Worms, Harris Nesbitt.

Quick question for you or two. The unplanned outage at the Neil Simpson plant, we have had some unplanned outages earlier in the year and I think there was some unplanned outages last year as well. Why do these things keep recurring? I know plants go down all the time but the Neil Simpson plant going down during the summer doesn't help things.

No, that was really the first -- we had some planned outages this year for the Wyodak plant. We don't control that. PacifiCorp controls, operates that plant and we are a 20% owner. Originally when we were looking at 2005, they had a spring outage. They then move that to a fall outage and then they move that to an outage next year. So we do have, within our guidance, an expectation of an outage next year at the Wyodak plant, which is our largest coal customer and provides 72 megawatts of power Black Hills share and that will be in the spring and that is included in our guidance. But we did not have outages this year. The Neil Simpson plant is the first major unplanned outage this year.

We did have an outage last year as well as some transmission difficulties in our ability to move power from the tie because things that occurred in Nebraska shut down our ability to access power to the east. So when the Wyodak plant had an unplanned outage last year, we had to go out and buy power and we were impaired from our ability to get power from the east because of things that occurred.

But this year, this is the first significant outage that affects Black Hills and we -- our powerplants historically have run at very, very high availabilities. For coal plants, they run in 90% plus availability, which is very good. But outages do happen. And we did have -- we had just taken that plant down last year. That might be what you're referring to. We had a planned outage last year for Neil Simpson Unit number II and we did a maintenance overhaul in the spring last year but that was not unplanned. That was a planned outage. So it occurred this year and it was an unplanned outage but otherwise, our plants, our fleet, runs very well. Certain things just happen.

On another note, can you give us an update on the status of the -- at E&P with the drilling down to 8000 feet? Where do you stand on that and when might we see some indication of where you stand on that on a forward going basis?

We have begun drilling some of the deeper horizons in our New Mexico property but until we get several locations drilled and can prove those up, our independent engineers won't allow us to add significant reserves or add reserves based on that until we get a number of locations. So I don't know that we expect that to be this year but we do to continue to look at that as an opportunity to continue to drill.

Drilling, we have opportunities to continue to drill out that location for the next two to three years and depending on our success, that could extend a little bit longer in our drilling program. But any specific individual wells, that is going to be dependent on how many locations around that we can get and our success or lack of success in that program. Until we are relatively certain that we're very confident that we can book those reserves, we won't see that result. I don't know that we will be able to get that done this year or not, just trying to drill a variety of locations. We have begun that process as we have the deep rights. We have begun to drill test wells but that may not occur until next year where we can really book all the reserves or the reserves relative to that.

Jim Bellessa, DA Davidson.

This is actually Bryan Nichols, Jim's associate. But we just have a couple questions. Affecting your coal mining operations, you also mentioned decreased train loadout sales. Could you provide some more detail regarding these train load-out sales reductions? Is that --?

That is really more of a timing issue. We have a contract with PacifiCorp to serve their Johnston facility and we serve up to about one million tons a year and they schedule their trains. They are required to take that amount of coal from us through our train facility and they are the only train loadout customer that we have at this point. And depending on the timing of their needs and scheduling that we may have a quarter in which we don't have as much as we did in the prior quarter of last year. And that really depends on their scheduling of needing coal. But from an overall annual perspective, they still take approximately one million tons a year and they are contracted to do that. So we would expect that to occur. We had a timing difference with what they took last year in train loadout sales versus this year.

In your wholesale energy marketing, or wholesale energy operating statistics, it seems that the crude oil barrels transported is a newly reported item. Is that true and if it is, will that information be provided or is it available on a historical basis?

It is. We do have that in there. I don't recall if we have historically done that. We will do that prospectively to do that. That is really related to the pipeline, the two crude oil pipelines we have down in Texas and really the largest point and the point to make in this one. We had the effects of the hurricane and we were also out for a scheduled pipe testing that we performed. We had contract that expired in the second quarter. Then we had the pipeline down for required testing and then we began a new contract within the third quarter going forward on one of our pipelines. So we wanted to put that statistic in there as it is not consistent with the prior year due to events that occurred this year. Hurricane Rita as well as the change in the contract from May -- beginning in August because of the required pipeline testing. But that is overall not a significant part of the overall business.

Michael Weinstein, Zimmer Lucas Partners.

In the press release, you guys talked about DD&A increasing 44%. I was wondering if you could talk about more about why that is. It sounds very high and also what you would estimate the increase to be for next year and the year after?

The DD&A increase, you will see, it is a much lower increase on an annual basis, which we have in our 10-Q, which was filed yesterday but we did -- every quarter, you have to look at your amount of capital that you have as well as your reserves that you expect for production over the course of time and adjust that. In the third quarter, we looked at it. We completed a lot of our drilling in the third quarter and some in the second quarter but you drill a lot in the summer. So we had increased capital costs and until we get to year-end and have our independent engineers look at our overall reserves, we have to make some adjustments. So part of the increase in the fourth quarter was due to just a lot of drilling that we're doing in the capital costs and we need to update our reserves as we go forward.

The other component of it is we have seen increased drilling rig costs and just the cost of our drilling has increased. So part of that is that goes into capital and then you have to amortize that over the future production that you will have and when you do that, you also have to update, based on currently available information, what your future development costs of those fields are and at the current higher rates, we do expect some higher capital costs going forward to drill. So we have to include that in our calculation and then amortize that over the life of those reserves or the expected recoverable reserves.

We have seen an increase in those -- drilling rig costs have increased substantially since the prior years and you not only include that in the current year but you have to include that in your forward expectations for drilling when you do that DD&A test.

Does this mean that we can expect to see similar increases in the fourth quarter and then also next year?

No, not to that level. Again, we made a calculation to catch us up in the third quarter. But if you look at what the average for the year is, I believe it is approximately $1.17 per Mcf. I can look that up in the 10-Q. That is what we would expect to have consistently going forward.

(OPERATOR INSTRUCTIONS).

And I will add it was $1.19. I looked at the wrong number. I quoted it. So it is $1.19 per Mcf going forward for DD&A.

Peter Hark, Talon Capital.

A couple of questions on power generation. I didn't get to clear up with you down in Florida. First on the LV I, the write-down there. I just don't quite understand what happened. I thought you had a tolling contract with LV I.

No. LV I was the only project that we didn't have a tolling contract with. All our other projects -- LV II has a tolling contract. It sits at that same site and it is a 230 megawatt facility. LV I has a long-term contract through 2024 with Nevada Power as the offtake. It is a qualifying facility and we had the fuel risk -- we had a long-term fuel contract in place and prior to 2001, we had a hedge on the gas price with Enron. Enron had their difficulties and declared bankruptcy at the end of 2001. There was a lot of volatility in the market. At that time, longer-term as Enron was a big provider of longer-term hedges that we were unable to extend any meaningful hedge on that plan.

In October of 2002, we announced the acquisition of Mallon Resources, our natural gas business down in New Mexico, primarily in New Mexico. And we closed that deal in March of 2003. So we looked at it as we had production in the San Juan basin that we could get that natural gas to and viewed that as an internal hedge. The accounting does not allow us to have an internal hedge. They have to look at each individual asset, not the value of our oil and gas reserves, combined with the value of our plants. So we had to evaluate the recoverability of our asset in which we had a little over $60 million in Las Vegas I and we took a $50 million impairment charge pretax in the third quarter because given that the significant increase in the third quarter in not only current natural gas prices but forward natural gas prices, we had to evaluate that as if we did not have an internal hedge and would we recover the value of our asset.

Once we do that, if we fail the first part of that test in recovering our asset, we have to discount that cash flow stream. Given it is a long contract, we did that and that is how we determined through --. You have to use a number of scenarios, not to bore you with the accounting, you have to use a number of scenarios and weighted average the results of each of those and we came up with a $50 million impairment charge.

I got you, Mark. So this isn't just a matter of writing down the gas, the value of the gas contract itself. The facility gets written down from 60 to 10 and do you realize therefore a benefit going forward on your D&A line?

Yes.

What happens on the Mallon side? You said you were kind of backstopping the gas supply needs for LV I.

The value of our natural gas assets, oil and gas assets, at current market prices, is significant. But you're not allowed to write-up the value of the assets. You just recover that through income going forward. As you produce your natural gas and your crude oil, you will get the benefit over time of that at that price level assuming that the prices stay at those levels, which you never know what those are going to do. You're not allowed to write-up the value of your oil and gas assets.

Perfectly understood. What is going to be the decrease in the annual depreciation expense?

$50 million, you assume you have a -- the contract goes through 2024. That would make it a 30 year asset because it was 1994 when it was put into operation.

1.7 million.

You have 20 years remaining under the contract; you can look at the math.

Got you. Then secondly on the Harbor facility going to straight line recognition of revenue. How were you recognizing revenue from that contract previously and what is the revenue differential then?

The contract is now treated more akin to a lease and so you just take your full period revenues and divide by the full period, the length of the contract. Whereas you may have had differences in that the price may increase or decrease within that contract. Because it is treated as a lease, you have to just straight line amortize your revenues relative to that contract. We had an old contract and had payments received but we have to amortize that over the life of the new contract.

But will you disclose what the revenue --?

I don't think it is significant to our revenues.

(OPERATOR INSTRUCTIONS). Eric Beaumont, Copia Capital.

I just want to make sure I heard something right earlier. You gave the guidance for next year and you gave the NYMEX price. Did I hear you say a 794 realized price?

Yes, that's what we have in our release.

And that is realized at the hub or realized to the Company?

To the Company net of hedges.

You know you've gone through the Q, you are at 640 for this year. I guess what are the real variances we are looking for for next year because if you just were to take -- obviously it is not a done deal but if you take that variance and just apply it to your expected production increase, there is somewhat of an inconsistency compared to what you're guiding this year and next year. Am I missing something?

The prices have increased. We had some hedges through the course of this year, some of which have rolled off, some of which will roll off on the natural gas side that impacted this year's earnings that we don't have next year. Again, we hedge two to three seasons out, a season being April to October and then November to March. And within this year, in 2005, we had some of last year's hedges on, which were at lower prices and this year, we disclosed that in our Q what our hedges are. We have some that roll off in October and the ones that we put on for November to March or April to October for next year are at higher levels than what we had impacting '04. '05, I'm sorry.

Just to make sure then. The 794 realized though is for -- is it basically embedded in the guidance for your expected production or just hedged?

Hedged. No, no, and expected. We expect whatever our other production is to have the market price. NYMEX back to the wellhead.

John Hanson, Imperium.

I just want to get little bit into the drilling costs outlook. I know costs have been up a lot this year. What particular areas are up the most or which items most concern you about costs for next year as you look into the season and maybe it is demands for rigs or anything like that as well?

I don't know that it is an area of concern on cost but we have been able to secure a rig and continue to do all of our drilling. The costs of those rigs have gone up and the cost to some extent of labor has gone up. I saw an article in the Journal that just energy employees are short in supply. In the oil and gas industry, that has probably multiplied because over the, I don't want to say boom/bust as a euphemism, but over the period of time, that business has been shrinking and now it is expanding in this higher price environment. So trying to get additional people has been a little bit more expensive.

But relative to value in continuing to drill, we see tremendous value in continuing to drill and grow our reserves and increase our production. Again, our expected production increases are 10% a year and we believe for the next two to three years, we have just internal projects. Depending on the success of that, we could extend it. I look at it as we will have some increase costs in drilling, most of which are capitalized and that affected our DD&A rate that we talked about earlier. But I think that is included in what we expect going forward. I know that is included in what we expect going forward.

So you included these costs in your outlook going forward.

In our outlook, yes.

(OPERATOR INSTRUCTIONS). Mr. Thies, there are no further questions at this time. Please continue.

I would like to again thank everybody for their interest in Black Hills Corp. and have a great day. Thank you.

Ladies and gentlemen, this conference will be available for replay after 11:45 AM Mountain time today through November 17th at midnight Mountain time. You can access the AT&T teleconference replay system at anytime by dialing 1-800-475-6701 and entering the access code 802168. International participants can dial 320-365-3844. Those numbers once again 1-800-475-6701 320-365-3844 with the access code of 802168. That does conclude our conference for today. Thank you for your participation and using AT&T teleconferencing. You may now disconnect.