Black Hills Corp (BKH) 2006 Q2 法說會逐字稿

Ladies and gentlemen, thank you for standing by and welcome to the Black Hills Corporation quarter earnings conference call. [Operator Instructions] As a reminder, this conference is being recorded today, Thursday, August 10, 2006. I would now like to turn the conference over to our host, Mr. Dale Jahr, Director of Investor Relations. Please go ahead.

Thank you for joining us and welcome to our conference call. 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.

Our discussion this morning will be led by Mr. Mark Thies, our Executive Vice President and CFO. Mark would like to start with a review of recent results before opening the call to your questions. Mark.

Thank you, Dale. Good morning everyone and thank you for your interest in Black Hills Corporation. It is August and, again similar to last year, if you hear in the background a large rumble, it's due to the Sturgis Motorcycle Rally, in which 400,000, 500,000 people descend upon Rapid City and the Black Hills to enjoy a Harley ride. So, hopefully, our-- we won't be interrupted by that and I don't imagine we will. It's early in the morning for the bikers.

But, we do want to talk about our second quarter results and they were down from the previous year, as we had net income of $0.35 a share, versus $0.45 a share in the prior year, and income from continuing operations of $0.37 a share, versus $0.46 a share.

But, we did have several previously disclosed items that impacted our quarter, primarily two major outages at different power plants. One, the Wyodak plant, which is one of our largest resources for our electric utility, and our largest coal customer. And the expectations for that were $0.06 to $0.08 and we were in that range in the second quarter for the impact of that outage. That plant came back on line at full capacity in the first week of July. So, relatively on schedule for such a major overhaul and that's-- that's a good thing to get back on line for the summer season, as we've had, you know, record heat across the nation and we had that in Rapid City in July-- a very hot July. So, having that low cost asset back on line was a very good thing from an operating perspective and financial perspective.

Secondly, the Las Vegas I and II-- Las Vegas I came back on line in April and has been operating since then at the contracted capacity levels. And Las Vegas II came back on line-- recall, we were operating at two-thirds capacity in simple cycle mode and we came back on line at full capacity on Las Vegas II and are operating at contracted levels there, again, the first week of July there.

So we will have a very slight impact in the third quarter, but largely those two assets were back on line as expected and the impact on Las Vegas I and II was in the range as well of the $0.05 to $0.08 that we had previously disclosed. So, those two items operationally were back on line and that's a strong positive for us.

In the quarter, that was the primary driver for both our utility, our coal mine and our power generation results, were those outages. And everything else reflected fairly normal operations for the second quarter. Historically, the second quarter is one of our weakest quarters, as first, third and fourth are our stronger quarters.

From an oil and gas perspective, our production increased 6% on overall basis with a 10% increase in natural gas and an 8% decline in our crude oil.

The crude oil decline is primarily due to a change in federal royalties in that for stripper wells, we were receiving-- we were paying a reduced royalty and that impacted our crude oil by approximately 8%, which is really the amount that we are down. So, it's not necessarily a production issue. It's more a taxation or royalty issue and that was because the price of oil was high, so the reduced royalties that we were paying went away, and we now pay a full federal royalty, which is 12.5%.

From an operational perspective on oil and gas, we did see higher LOE costs, leased operating expenses, and that's primarily due to the additional work that we are doing in-- we brought an amine plant on in New Mexico and we also, in June, brought one on in our Piceance Basin assets. Those assets include the Koch acquisition, which we had previously disclosed.

And in this release, we disclosed an additional acquisition of the same properties from [Questar] that is pending and expected to close in the third quarter. That acquisition will provide about 22 Bcf of proved reserves and most of those, almost 18 Bcf, are proved undeveloped. This positions us very well to continue our drilling program, which has been where we believe we can add the most value is through the drill bit.

So, these acquisitions are primarily undeveloped acreage in which we will be able to drill up. We have currently three to four years of prospects in our portfolio to continue our drilling program. So, we're very excited about that opportunity.

In addition, we saw an increase in our depletion substantially over the prior year. That really had occurred toward the end of last year and in the first quarter. That-- at $1.77-- that's up 51% due to higher capital costs or future development costs and our level of reserves. We do anticipate, given the properties that we have and activity we have, we do anticipate being able to meet our targets for production and reserves, assuming that we have successful completion as we go forward in our drilling program.

But, we do have the wells and the opportunities to meet our targeted levels for production and reserve growth in our oil and gas business for 2006. We won't come out with any specifics on our total reserves until the end of the year when we have an independent review by our independent engineer.

One of the strongest points in the quarter was our energy marketing results. And they had a-- they had a very-- this is the third quarter in a row that we had very strong results from our energy marketing business. And that's in part due to the volatility. We've always said that volatility is good for the marketing business. And we saw some volatility on the downward side in natural gas prices, but we were able to take advantage of that from the marketing business and had a very strong second quarter.

Historically, second quarter is not a strong quarter for marketing-- it's fourth quarter and first quarter. But we had a very good second quarter in our marketing business and we see opportunities, you know, again, coming into the winter season, to have good results in the winter season from our marketing business.

All that said, we have-- you know, it was really a quarter that we expected to be down because of the power plant outages and everything else seemed to go as we expected. We did file on our electric utility rate case. We have not had a rate case in 11 years at Black Hills Power. And we filed a rate case for a 9.5% increase and we are asking for that increase to become effective January 1, 2007. So, we are currently in that process and the South Dakota regulators are evaluating our request for a rate increase.

With respect to our guidance, our guidance has remained the same from $2.10 to $2.25. We are, given the reduction in natural gas prices, based on recent natural gas prices, we believe that we will be towards the lower end of that range, but we do expect to be in our range for 2006, just towards the lower end. And primarily due to the reduction in natural gas prices that occurred this summer.

I would now like to open up the call to any questions.

[Operator instructions] Our first question comes from Michael Worms, Bank of Montreal Capital. Please go ahead.

Good morning, Mark and Dale.

Mark Thies and Dale Jahr: Good morning, Mike.

I do apologize. Mr. Worms, if you could please queue up again. Eric Beaumont is now, from Copia Capital, is now on the line.

Morning, guys. How are you doing?

Morning, Eric.

I just want to walk through a couple of things, make sure I understand things properly. Originally, when you give guidance, you talk about a 10 86 NYMEX number, so whatever discount you want to call it, you know, somewhere in the $8.00 for San Juan.

Well, historically, it's been about $1.60, is what we've said as our basis--

Yes, but--

That's for San Juan.

Yeah. Yes, so. I guess I'm looking at average price received to look at unhedged amounts and kind of working that through and also looking at then the hit you took in the power gen for the plant issues in Vegas. And, I guess, can you just walk me through where the offset is coming. I mean, obviously, that adds up to a little bit, you know, looking at the [front month] gap now, works a little more than the $0.15 taking, you know, than your middle range, high range, not at the low end. Is energy marketing making it up? I just want to understand contribution-wise what we're thinking about the mix and going forward for the year.

Well, for the first six months we had very strong results from our energy marketing business, you know, the volatility. There is-- there is some balance within our companies, you know, overall we generally prefer higher natural gas prices as a corporation, primarily due to the oil and gas, and there's still volatility for the marketing. But, even when it's down, marketing has an opportunity to make money and we were able to do that.

So, marketing results were very strong in the first six months of the year, which has allowed us to overcome some of the reduction on the oil and gas side from the pricing.

On the other side, we do benefit slightly from lower natural gas prices to the extent we are a user of natural gas in our electric utility and one of our plants, the Las Vegas I plant, has open fuel from a-- from a price perspective. And that impacts us as well. So, the lower prices are an incremental benefit there.

You know, we do expect to continue to have production growth over the next-- over the next six months. And we believe that will come back in prices in the winter months, anyway, have remained relatively strong on the natural gas side.

Yeah, no, I agree. There's still, you know, they're still well below what we're-- what we were looking at, you know, when original gas [Inaudible]. I guess, you know, the production growth in-- you always say 10% net-- and I know it's not meant to be a one year thing. It's meant to be over a longer term. But, you know, is 10% kind of the right number to think about this year and, if so, is that 10% including the kind of the half the year that we're looking at the new acquired Koch properties? And, if so, can you kind of reconcile that to the [inaudible].

Well, the 10%'s an overall-- an overall target, long term growth, from-- on the production side. The acquisition by, you know-- they were largely undeveloped properties. So, yes, we are including in the incremental production, but I don't know that that's a significant amount, however you want to look at that. You know, the Questar production, assuming we close in the third quarter, that will be even a smaller percentage, just for the rest of the year.

So, we do have-- what I really want to, to focus on, is we do have opportunities in wells that, you know, we're working on in our inventory that we are drilling that we believe, you know, we will be able to get that. In the past, we have had permitting issues where we couldn't get permits and drill the wells up. We believe at this, you know, for this year, we've-- we're through those and we actually have the opportunities to add production now. We have to have expected results from those wells, you know, there's always a risk when you drill. But, we do think we can get there with our production.

Okay. And just two more questions real quick. One is, you did a pretty good job of explaining that the depletion makes sense and understanding why we had to jump. I'm just curious, what should we be anticipating with regard to the trend of the depletion expense per MGFE for kind of the remainder of the year and going forward.

Well, that is dependent on two primary issues, is are we going to have the success in our drilling? We have a fairly balanced drilling program between undeveloped properties and exploratory or other opportunities. The undeveloped properties, when you drill those up to some extent, it's just moving within the proved categories. You go from proved undeveloped to proved developed, but your total proved is still the same. So, the extent that our costs to drill are within our expectations should not have a significant impact on depletion.

The exploratory properties can add reserves and as long as we can add reserves at a lower overall cost, which we believe we can, we should expect a reduction, or we would expect a reduction, if we could add reserves at a lower overall cost. Our cost increases are largely reflected in what we have today. We have seen significant cost increases over the past year and that not only impacts your LOE expense, or your leased operating expense, but it impacts your-- your drilling costs and your future development costs. And since we have significant undeveloped properties, that number grew and that's what caused our depletion expense to go up was the future cost to develop the reserves that we have, the proved reserves that are undeveloped.

We don't believe that that will increase. You know, based on what we know today, you know, those costs appear to be levelizing or the rate of increase has stayed somewhat. And so, it really comes down to our ability to add reserves, additional reserves, through the drill bit at an overall cost of lower than what our existing depletion is. And we believe we have the opportunity to do that, but that's going to depend on the results. And really, that will be-- we'll have a much better idea at the end of the third quarter as, you know, the summer months are very good months for getting a lot of drilling and completion. It's what the time that you drill and do your work because you have nice weather and, you know, and then at year end, we will have our independent review to go through our reserves.

Okay. Thanks for that. And the last one is just, now that, you know, you've gotten Vegas cogen II back in combined cycle and issues that you formed, where [inaudible], should we be thinking about kind of from this point forward getting back to the 16 million run rate a year for that division, for power gen that you had talked about in the past?

The only-- the only caveat to that is-- in gas prices-- we do have-- I mean, based on our expectations, yeah, we should have-- that's a reasonable expectation for run rate and those are all contracted plants. If gas prices move significantly, that does impact our Las Vegas I plant, because it has-- we don't have the price hedge on that. We have a fixed revenue, but we have the open fuel. We view that as an internal hedge with our oil and gas business, but we don't have that direct by segment.

But, yes, we would expect to be back to normal operations in our power generation business at historical levels.

Thanks a lot, guys. I appreciate the time.

Thank you, Eric.

Our next question comes from the line of James Bellessa, D.A. Davidson and Company. Please go ahead.

Good morning, Mark and Dale.

Good morning, Jim.

The $0.05 to $0.08 that you mentioned drag from the Las Vegas plants, was that spread over more than one quarter, or is that just the second quarter effect?

No, some of that impacted the first quarter, because they were out in the first quarter. I don't know that I would say it's-- it's exactly even, but it's-- it was-- our guidance was in the first six months and we are in that range for the first six months. We didn't go into the specifics of which quarter, but it did impact the first quarter as well.

You've just talked about higher depletion expense in the most recent quarter DD&A went up by $1.5 million. Do you expect it to hold at this level for the next rest of the year?

Well, from a DD&A expense perspective, you know, we expect that the rate of depletion will be reasonably similar, as I just discussed, to what we've had, but, you know, as production increases, your overall expense will increase. So, if you're looking at it from a financial statement impact on the expense line, as production increases, the expense line will increase. But, we don't expect it to be at a rate higher than where we are. Does that make sense, Jim?

Yes.

Okay.

In the 10Q, you have a footnote on materials, supplies and fuel and then you classify how much you had in gas held by energy marketing. And there's a footnote on that that you make market adjustments related to natural gas held by the energy marketing business. Why-- why do you make those adjustments? Why can't you just leave it as-- as stated?

Well, that-- it includes that as stated and that's largely due to the hedge-- the hedged out position that you have a financial instrument hedging your inventory or forward sale, which is a derivative hedging your inventory. But, your inventory is sold forward. So, we have a fixed margin on what we will get on the majority of our inventory. So, any market changes in price we're required to account through the inventory level.

On page 49, you talk about some oil and gas properties being acquired in August of 2006. On the call you said that you-- you're still pending on the Piceance?

Piceance.

Well, whatever it is.

The Piceance Basin.

Yeah, Piceance Basin. Tell me, are these different properties that you acquired in August of 2006, or is just the time reference there?

No, well, the-- you know, again, that's a-- we have signed a definitive agreement to acquire those properties. We expect that to close in the third quarter. So, it is-- it is currently a pending acquisition. It is a follow on acquisition to the properties that we acquired earlier from Koch and those properties were in the Piceance Basin and we had-- I don't recall off the top of my head the specific working interest-- but we didn't own 100% of those assets.

So, we acquired from the other party that owned those assets some additional assets in those same-- the same properties. So, what that will allow us to do is really leverage our staff and our resources to have a greater percentage ownership in those particular properties and not really change the-- the requirements of what we need to drill those up. We will own-- we will own a larger percentage of those similar properties, assuming we close the acquisition.

And the-- you call out that you're developing an East Blanco amine plant. Tell us what that's about, why you would be into, I guess, that's ammonia?

It removes CO2 from the gas, so really, it's to get the natural gas that's in the ground up to pipeline specifications and we need that amine plant-- we've had that amine plant, we just moved it. It was on the Hicoria Apache reservation and we moved that to off the reservation and started that up again. And we've also added that-- for the acquisition of the Koch properties, we've added an amine plant as well. And that's really just to get the gas up to the pipeline specifications so we can sell it. That's what that is. It's part of our operating expenses.

Thank you very much.

Thank you, Jim.

Our next question comes from the line of [Kathleen Bughtek], [WHE Reed]. Please go ahead.

Good morning.

Good morning, Kathleen.

I was wondering if you could talk a little bit about how the construction of the coal facility is going and how you look at your generation capacity versus forecasted demand.

We-- we, in the past-- and I'm trying to remember the specific day. I think it was the first quarter of '05, we filed an integrated resource plan with the Wyoming Public Service Utility Commission or Public Service Commission, that really lays out our expected demand and our resources. Over a long period of time. Those are 20-year forecasts that really look at that.

The plant that we are currently constructing, Wygen II, is really not necessarily specific just to demand, but our Cheyenne Light and Utility purchases all their power on an all-requirements contract from Public Service Company of Colorado, which expires 12/31/07. And we work with the-- you know, we looked at it and said we believe that we can provide that and make Cheyenne Light an integrated utility and own generation as a rate-based asset. And began-- got that through the commission and began construction on that plant that we expect to be in Cheyenne.

So, that will get us to really serve-- we already serve Cheyenne with 100 MW via contract, you know, through [PESCO] and through the end of '07 and then it reverts back to Cheyenne, 60 MW of our Wygen I unit, which is a coal-fired plant, and 40 MW of a gas turbine. So, with this additional plant, which will be 90 MW, very similar to our others, you know, we expect to be able to cover Cheyenne's loads.

Okay. I was-- great. I was wondering-- I should have been more specific. Is the plant on schedule and on budget? And secondly, you've been very successful in adding increments to your generation capacity. Once this plant is done, are there further opportunities to expand generation at that site?

Okay, yes. If the construction-- as we said in the first quarter, we had a relatively mild winter and so we believe that we're, you know, ahead of schedule and on target for that construction. We still have another winter to go and so we don't expect that to be on line until the end of, you know, the fourth quarter of '07 or the first quarter of '08. So, we are on track with that construction. It's slightly ahead of schedule, because of the milder weather in the winter. And that's a good thing.

With respect to other opportunities, you know, we are permitting-- in the process of permitting another plant at our mine site, Wygen III we call it. And, you know, that permitting process takes up to a year, so we expect by the end of this year or early next year, we will be through that permitting process. Then we would look to either use that as a utility plant for Black Hills Power or have partners, because there is need in the Powder River Basin with increased demand. We may contract that asset or have an equity partner on that asset. We would like-- we would expect to operate that asset and sell coal to that asset.

So, we are in the permitting stage, so, yes, we do believe there's an opportunity for another plant. Once this construction gets done, we'd like to just move right in to construction of another one. But, that's in progress right now. I can't say that we've contracted the construction at all. But, we are-- that is part of our longer term plan to add another asset there.

Great. Thanks so much.

Thank you, Kathleen.

Our next question comes from the line of Michael Weinstein, [Inaudible]. Please go ahead.

Hi, this is Michael Weinstein. Just curious--

Hi, Mike.

Hey, how you doing? Just curious about the royalty issue at the oil production. How does the increase in federal royalties actually decrease your net share of production? Is that-- are you actually producing less or is it just the way that you're accounted for?

No, it's the way it's accounted for. It's a-- you get less ownership of the production. The wells are still producing. Again, like I said, largely, our oil production was flat, but we reported less production, because our share was less based on federal royalties. And that was a law that was passed for stripper wells. To the extent prices were low, you got a reduced royalty, a reduced federal royalty on that. To the extent oil prices have been high that went away. So, we pay a full royalty on it.

Right, and the royalty is in the form of production. So, like the federal government is taking a piece of the production, right?

Effectively, yes.

Okay, gotcha. Thank you.

Thank you.

[Operator Instructions] I'm showing no further questions at this time, so please go ahead.

Well, we thank everyone for their interest in Black Hills and have a great day. Thank you.

Ladies and gentlemen, this call will be available for replay after 11:45 Mountain Time today through Thursday, August 17th at midnight, Mountain Time. You may access the AT&T Executive Replay System at any time by dialing 1 800 475-6701 and entering the access code 837578. International participants may dial 320 365 3844. The number again is 1 800 475-6701, 320 365 3844 and access code 837578.

Ladies and gentlemen, that does conclude our conference today. Thank you for your participation and for using AT&T Executive Teleconference. You may now disconnect.