Black Hills Corp (BKH) 2005 Q4 法說會逐字稿

Ladies and gentlemen, thank you for standing by and welcome to the Black Hills Corporation quarterly earnings conference call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session. Instructions will be given at that time. (OPERATOR INSTRUCTIONS)

As a reminder, this conference is being recorded today, Wednesday, February 8, 2006. I would now like to turn the conference over to our host, Mr. Dale Jahr, Director of Investor Relations.

Thank you and thank you to the audience for joining us on our quarterly conference call, this time to discuss fourth-quarter and year-end 2005 results. I remind the audience that this conference call may include forward-looking statements as defined by the SEC. These statements concern our plans, expectations, and objectives for future operations.

Such statements are based on what we believe are reasonable assumptions and based on current expectations of industry and economic conditions and other factors. However, risks and uncertainties could cause results to differ materially from those in forward-looking statements. I refer you to the cautionary language published in our press release and other public disclosures.

To lead us off, we will have our Executive Vice President and CFO, Mark Thies, give an overview.

Thank you, Dale. Good morning, everyone, and thank you for joining us on our fourth-quarter conference call today. We had a terrific fourth quarter with net income of 26.6 million or $0.79 a share, compared to 19.4 million or $0.59 a share in the fourth quarter of 2004. Earnings from continuing operations in the fourth quarter were the same, $26.6 million or $0.79 a share, and compared to $21.1 million or $0.64 per share in 2004.

For the year-to-date, we ended up at 33.3 million or $1.00 per share and 35.8 million or $1.07 per share from continuing operations, compared to 57.7 million or $1.76 per share in 2004 and 61.2 million or $1.86 from continuing operations per share.

Several items in the fourth quarter. We had very strong results from our Energy marketing operations. And typically the Energy marketing operations are the strongest in the fourth quarter and the first quarter. With market conditions, there was volatility and increased market prices, and our Energy marketing operations, through a variety of their ability to move gas through transportation and storage and just delivery of gas, was able to increase their earnings 7.8 million or $0.23 per share as compared to the fourth quarter.

We also increased our Retail Services earnings. That is due in part to two things. We had increased off-system sales offsetting some higher purchase power cost due to the higher natural gas prices in our electric utility. And we added in 2005 Cheyenne Light, Fuel & Power, which is our retail electric and gas subsidiary, and their earnings were included in the fourth quarter of this year as opposed to not in last year. That was a January acquisition.

We also increased our Coal Mining earnings slightly. We had a slight decline in our oil and gas earnings and I'll go over that a little bit later in the call. We had decrease in our Power Generation earnings.

We had a very, very good year in 2005. We are very excited about it. We did have certain items that affected us, primarily in the third quarter, and I'll touch upon those slightly, but the biggest of which being the $32.7 million or $0.98 a share impairment of the Las Vegas I Powerplant that we had in the third quarter of last year, primarily due to a significant rise in natural gas prices caused us to evaluate that plant and take the impairment.

On the other side of that internally, we have much more value in our oil and gas reserves that we are not allowed under the accounting to write up in value and we will disclose that amount in the 10-K, what the value of our reserves are.

For 2005, we experienced record oil and gas production, 9% production growth for the year, and we look to continue our production growth. Again, our target is 10% production growth. We look to continue that in 2006.

We began construction on the Wygen Powerplant that is expected to serve customers in Cheyenne. That is $170 million 90-MW coal-fired plant that sits atop our mine. We've spent approximately $23.8 million in 2005 on it and we are on track with that construction. We expect that to go into service early in 2008.

Our Electric Utility experienced record new customer growth and a 5% increase in MW hour sales, so despite a milder weather, we continue to see some good growth in our Electric Utility service territory.

We sold in June -- as a review, we sold our communications business -- more of a reminder, and we really focused our financial foundation and future going forward. We are well positioned to continue to grow our assets in 2006 and beyond, and based on our strong performance and those expectations, our Board of Directors raised our common stock dividend for the 36th consecutive year. That happened just last week, so that is a very good positive as we look to the future.

In the future, we have a number of things that we're looking at. We did sign a confidentiality agreement with NorthWestern Corporation and we are committed to our offer for a proposed combination with NorthWestern Corporation, provided that that combination maximizes shareholder value and really strengthens the long-term strategy of both companies. We remain committed to that, to our offer that has been out there publicly.

We do have a lot of things going on in the upcoming year, not just looking back. As we look forward, we expect to complete the pending sale of our Oil Marketing and Transportation business. We do have affecting us -- and it is included in our expectations -- the major plant outage at the Wyodak Plant, which affects both our Electric Utility, Black Hills Power, and our coal mine, as that plant is our largest coal customer.

We expect to continue, as I mentioned earlier, our oil and gas production growth and we look to grow both reserves and production in our oil and gas business. We do have to manage the oil and natural gas commodity price volatility. That does impact our business, both on the oil and gas side, the volatility on the marketing side, and the prices at our Electric Utility to some extent.

We have to address some maintenance issues at our Las Vegas power plants. Las Vegas II experienced an unplanned outage in January of this year. We expect the impact, the negative financial impact of the outage to be $0.05 to $0.08. And we do expect to continue to operate in simple cycle mode. Those are combined cycle units, and we expect to get those on in the second quarter.

At our Las Vegas I Powerplant, the extensive maintenance that we began in the fourth quarter of 2004 continues and we expect to have that plant back on by April of 2006.

In addition, we also have the market volatility that affects our marketing business. Our marketing business was very strong in the fourth quarter. We had good volatility and we were able to take advantage of that by moving gas. That is an impact to us and we had mark-to-market accounting that required us to record earnings in 2005 that $1.3 million of those earnings after-tax is expected to reverse into 2006.

From an oil and gas perspective, again, we had very good production, 9% production growth. We were down slightly in the fourth quarter as weather and some equipment impacted us. The winter can be a challenging time, primarily in our East Blanco Field, which is our largest gas field, and that delayed some of the production to offset normal field declines.

We had lower production in our oil business. We are focused on increasing our oil production through a drilling program, and we haven't drilled significant oil wells in a long time there and we believe that we have an opportunity now to do that, and we expect to increase our oil production in 2006 through a drilling program. So we are addressing the lower oil production.

On natural gas, we had a reserve decline, slight decline in our total reserves, primarily due to a revision in our estimates. Based on experience of what we found in drilling wells and putting them online, initial rates for wells drilled late in 2004 and early 2005 were lower, and that caused us then to look at all the offsetting wells or production that we have in the proved, undeveloped and nonproducing estimates.

Another reason for not a significant increase in our reserves is we did add 25 Bcf of reserves, which more than covered production in reserves -- production of our reserves in 2005. We drove a lot of undeveloped. Those are included as proved properties, but they don't necessarily add to the overall reserves. They just get us to increase our production. We expect to continue to do that in the future, and that is one of our strategies -- acquire properties that have some production, but drilling undeveloped locations.

We did close a transaction in the fourth quarter in the Piceance Basin that we expect to have additional -- we are in that area already and we will have additional drilling opportunity. So we do expect for the next several years to have the drilling capabilities to continue our production growth.

I would now like to open up the conference call for questions.

(OPERATOR INSTRUCTIONS) Michael Worms, Harris Nesbitt.

A couple of questions for you. First, can you just get us an idea of what impact on earnings the sale of your oil marketing business will have in 2006?

We have not disclosed any of the details currently. We have signed a definitive agreement. We do expect that transaction to close either late in the first quarter or early in the second quarter. So at that point, we will provide the details, but at this point we have not disclosed any details of that transaction.

Okay. Moving on to the lower production rates from the new wells drilled, can you give us a little bit more color on that? I'm not quite sure I understand what's happening there.

Well, when you bring a well online, typically you have higher initial production rates and then they have to settle into a normal production rate. And when we made our estimates of reserves previously on those wells, we did not have all of that information. And as they produced through 2006 and settled into their levels -- 2005, I'm sorry -- and settled into their production levels, they were lower than our initial estimates. So then that affects the expectations of wells that are offset acreage that we drill around that.

What occurs there, Mike, is you'll drill a well and find your reserves and have the production and then you'll be able to record offsetting locations as proved, undeveloped properties. And so when you determine that they are higher or lower -- it can go either way -- production rates coming out of the wells, you can then infer to those offsetting locations similar characteristics in a field.

Has this kind of occurred at other wells, other players in that area as well?

It occurs throughout the oil and gas business, and it just depends on the type of well that you have. If we would have had higher production rates out of them, we would have had the reverse of that. That's just a normal -- I'm not an oil and gas engineer or geologist, but that is a normal process. You look at adjacent locations and look at the geology, and then you can determine what the expectations are.

So it's not unusual for us. And in this field, again, we continue to make progress in drilling up this field and we will expect to do that as we go forward. They're is still good productive wells. They were just lower than we have expected prior as we have more knowledge now based our drilling program.

One last E&P question. On the new properties that you have acquired, how quickly will they begin to be developed? And what will be the incremental production costs?

We are already in that location. We've been in the Piceance Basin for some time. I believe 2001 was our first acquisition in the Piceance Basin, so we have been operating in that area. And we don't -- specific field-wise, we don't put out what the production. Our overall production expectations are we expect to grow production on a long-term basis by 10%, and we believe we have the opportunities to do that through the drill bit, and this acquisition just continues that.

We will have opportunities to drill. We are familiar with the area and we will be able to drill and grow our production. It is one of the areas that we have. We have a number of different areas where our oil and gas is, primarily still in New Mexico. That's still the largest individual area in the East Blanco Field, but this is just another good core area for us.

One last question and I'll let someone else ask some questions. Vegas I, what is going on there? What is the maintenance program related to? It was my understanding that that plant hasn't been running very much over the last year or so because of the high cost of gas.

No, the plant had run. We took an impairment in the third quarter and we did have a long-term fuel contract, which we terminated in the fourth quarter. And we identified that as one of the impacts in the fourth quarter -- it was an after-tax $1 million related to that fuel contract in the higher gas prices. We did not have -- that the only plant we had that was not a tolling arrangement or, with one exception -- we do have the Wygen I plant, which is coal-fired but it is our coal mine, so we believe we have the ability to manage the fuel.

All the other plants are tolling. This one wasn't. So it was running and we were losing money on it due to the higher gas prices. But we took the impairment. We did have -- we do have the ability to do maintenance on that plant in certain periods, so we took that plant down in the fourth quarter for planned maintenance and plant repairs and that continues. And again, we are expected to get that back up in April of 2006.

Thank you.

Gavin Tam, Natexis.

Actually it's Gordon Howald. Could you talk about the type of problems that you have experienced at Las Vegas II? Is this something related to the technology? Have you been cycling the plant that ended up causing some problems? Could you just get into a little bit of the color on what the problems there are?

Well, we had an unplanned outage, and really it was an operational -- we identified -- it tripped, we looked at one of the units, identified that there was some damage. Then said, well we better look at the other unit to see if it has the same thing and identified that it didn't.

It was in the steam turbine so it was a combined cycle impact. We can still run in a simple cycle mode, so we expect it to have capacity -- we have resumed capacity of two-thirds of its capacity and availability through simple cycle generation. But it was in the steam turbine that we had the issue. Once it was identified, we took it down for repairs and looked at the other one.

Those plants have been running all-out -- they are not necessarily built for just running all the time, and they have been running all the time. So we have to look at that, but that is really up to Nevada Power. They have all of the energy that's available they are allowed to take, and again, it speaks highly to the location and the benefit of those plants. But we did have some operational problems that we are addressing. We're fixing it and we're looking at making sure, or trying to assure, that that doesn't occur again when we bring it back online.

Right, okay. Understood.

We have got the expected impact identified.

Right. I can appreciate that. Could you provide any color on your announcement of further anticipated acquisitions at E&P? Have you budgeted anything for 2006? Maybe just a little color on that.

Well, we always look to see if there are opportunities. There continues to be a very strong price environment, so those opportunities have to be select that we can bring value. We look for opportunities that have some proved producing reserves, but also opportunities to have undeveloped acreage. And the acquisition that we closed in December was really the first acquisition of significance since the Mallon acquisition in 2003.

So we are fairly selective in what we do, but we are always open to continuing to do that if we find a property that we think makes economic sense to us and brings value to our shareholders. We were able to do that in the fourth quarter, and going forward, we are always looking for those opportunities. If we find them, we will put them in and announce them.

But nothing budgeted --?

What we really look for in the budget, we budget more and focus more for our drilling. We may have some small property additions within our own fields that they've put in, but it's not material. The primary growth is through the drill bit, and if we get an acquisition, we'll announce it.

I appreciate that. One last quick question. I know there were a lot of charges in the third quarter, more charges here in the fourth quarter. Are you guys kind of cleaning items up here or is this -- can we expect anything else as we look out towards 2006 in terms of unusual items?

You're exactly correct. We had a number of items that impacted our 2005 amounts, but a lot of those we would look at as charges that were unusual. You can't really talk about non-GAAP numbers and all that, but the development costs we no longer have -- we have identified, gone through all of our projects, and we really looked at those and say, what factors affected each of those projects? We took a significant amount in the third quarter, because market conditions changed. And we had all that in our press release related to the third quarter.

In the fourth quarter, we finished up on the two projects that we had looked at and capitalized. So we have no capitalized development costs at the end of the year and that is just based on information and facts that occurred at those times.

Looking forward, we still expect to have costs associated with growing our business. That's just part of growing your business. You have to look for new opportunities, and in doing that, you will incur some costs. We have included that in our expectations. The one that you see in specifically identified was the proposed combination with NorthWestern, and we did sign a confidentiality agreement yesterday.

So we do expect to incur costs going forward, but that is included in our stated guidance of $2.10 to $2.25 per share.

Got you. Very good. I appreciate your responses here. Thanks.

James Bellessa, D.A. Davidson & Company.

The table of reserves shows acquisitions of 6.1 Bcf. Is that the Piceance Basin acquisition?

Well, there's a combination. That would include that, but we might have some others. Like I said on the earlier question from Gordon Howald, we may acquire certain properties that are not significant from time to time throughout the year. That would be the total of our acquisitions in 2005.

Have you indicated what you paid for this acquisition at the end of December?

No, we have not.

The table also shows revisions for previous reserve estimates and it is a negative number, and you'd talked about that. Does that have anything to do with what you say about ongoing audit of pre-acquisition royalty payments?

No, that doesn't have anything to do with the reserves. That was an issue that we were aware of when we acquired the property, that there was a dispute. And we had accrued an amount. The MMS and tribal organizations got back to us with their expectations of what the dispute was. We had to increase our accrual based on that information, which we got in the fourth quarter. They sent us a letter.

We still intend to negotiate with them and work through that, but that was really related to -- we knew we had a dispute when we acquired the property. We have accrued an amount at that time and we got additional information. We are continuing to work through that. That is an accrual at this point.

At the end of the release, you talk about a dispute with PPM Energy that is in arbitration. What is the potential liability that you might have?

Don't really -- that is in arbitration and Pacific Power Marketing initially filed their suit at $20 million. We believe that we filed back that we were owed. That is there to identify that it is in arbitration and the arbitrator could get back to us, and we believe that they will get back to us, based on comments. But until they do, we don't really have a good idea of what that number will be.

But if it occurs prior to the filing of the 10-K and is material, we would have to record that in 2005 earnings so they have the potential to differ, if we were to get that additional information prior to filing our 10-K. But we don't have a number that we could say is probable, because if we could, we would have to record it under the accounting rules. But we don't have that, and that is from our legal counsel.

You have indicated that you've signed a confidentiality agreement with NorthWestern. Previously, you had indicated that some of the terms that they were asking for were onerous and you wouldn't sign the agreement. What changed?

You know, I'm not really at liberty to speak to any of the terms of the agreement. We were able to sign it. You know, we signed an agreement that we were comfortable signing, and that is really all I can say about that. And because we have an agreement, I can't really talk about -- a confidentiality agreement, can't really talk about anything else on that.

We do have our offer for a combination out there. That has been public. We believe that such a combination makes sense, but that is really all I can say.

Thank you very much.

Eric Beaumont, Copia Capital.

A couple quick questions that's a little housekeeping. Back when you originally gave '06 guidance, you gave the $2.10 to $2.25. Then you gave the [1086] NYMEX, which using differentials, you come out [8] somewhere in the San Juan basin. Obviously, that has come off a little bit and you also now have the Vegas Cogen II that you are saying is $0.05 to $0.08.

I'm just curious, A, can we get look at the hedges or are we going to have to wait for the K? B, has hedging philosophy changed at all? And C, where are we making up for some of these negative variances to keep the guidance range the same?

The year really hasn't even hardly begun and we have looked at it and we believe that we can. We believe we are on track to achieve our guidance and we do have some impact, as you mentioned, the $0.05 to $0.08. But we believe we have -- our opportunities are we will still be on track to meet that guidance.

The NYMEX price change that we tried to identify, really the short end of the price curve came off, but the long end of the current strip is pretty strong. It remains pretty strong. And as our production grows, it is towards the end of the year. So based on our expectations, we believe we will be able to achieve our stated guidance range.

With respect -- what was your other -- I'm trying to make sure I got all of them. Oh, the hedging side of it. We will disclose that in the 10-K, but we believe we are in line with our historical targets of 25 to 50% hedged.

I guess just last, obviously, the back end of the curve hasn't moved much. Outside of hedges, though, your general practice is still to sell on the front months, is that correct?

Yes, that's correct.

Just making sure. Thanks, guys.

Kathleen (indiscernible), W.H. Reeves.

I was wondering if you guys could talk a little bit about the electric demand that you mentioned being up, I believe, 5%. What was weather and where did that demand growth come from? You had talked in the past about the customer adds in the 1% area, so how do you account for a stronger demand level?

In the year-to-date -- or in the quarter, excuse me, our degree days were up 6% and our year-to-date we were up 3%. So to some extent, that is weather driven, but we also increased our customer base again, and that helps as well incrementally.

Okay, great. Thanks.

(OPERATOR INSTRUCTIONS) John Hanson, Imperium Capital Management.

Just a quick question on the coal operations for next year. With the outage on the big plant, is there any ability to sell that coal in the market if you don't supply it to that unit?

Is very limited. I mean, opportunistically we always try to sell some of our coal on the market. But given the coal quality that we have, it doesn't travel well long over rail. We do sell -- we have one rail customer, the Dave Johnson Plant for PacifiCorp that we sell approximately 1 million tons to by rail. But otherwise, if we are able to opportunistically sell coal, we will and we will continue to do that, but that has not historically resulted in significant sales.

So what we do when we have a plant outage similar to what the Electric Utility does, is they do all their maintenance on their outage. We work on the mine to the extent we have opportunities to uncover more overburden and prepare the mine for when it comes back up. But if we are able to sell coal on the rail, we will, but we have not factored in a significant benefit from that.

Okay, thanks.

(OPERATOR INSTRUCTIONS) At this time, I'm showing we have no additional questions. Please continue.

I would like to thank everyone for their interest in Black Hills Corporation. Have a great day.

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