Black Hills Corp (BKH) 2005 Q1 法說會逐字稿

Ladies and gentlemen, thank you for standing by, and welcome to the quarterly earnings call. At this time all participants are in a listen-only mode. Later, we will conduct a question-and-answer session, and you'll be given instructions at that time. (OPERATOR INSTRUCTIONS) And as a reminder today's conference is being recorded.

I would now like to turn the conference over to Director of Investor Relations, Dale Jahr. Please go ahead.

Good morning, and welcome to our conference call, which is held in conjunction with the release of first-quarter 2005 results. Thank you for joining us.

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 cost results to differ materially from those in forward-looking statements. I refer you to cautionary language published in our press release and other public disclosures.

Our discussion will be led by Mr. Mark Thies, our Executive Vice President and CFO. Mark would like to start with a review before we open the call to your questions. Mark?

Thank you, Dale. Good morning, everyone. We appreciate your interest in Black Hills.

We announced on Monday our first-quarter results, and we had $15.7 million of net income, or $0.48 a share. That compares to last year's first quarter in 2004 of 9.7 million or $0.30 a share.

Income from continuing operations was nearly identical at $0.48 a share and $0.30 a share compared to the same period in the prior year. As expected, our generation earnings led the way and were increased nearly $6 million, or $0.18 a share. That is primarily due to having a contract on our Las Vegas Cogeneration II plant in the first quarter of 2004. That plant operated as a merchant plant in difficult market conditions. So we did get back to our improved earnings from our power generation business.

In addition, we had increased in earnings from our oil and gas production as our production was up 13%, and overall our earnings were up 35%, or $1.3 million, due to a combination of improved product prices or commodity prices and the increase in production.

Our communications business improved $0.09 a share -- or $0.03 a share and $0.9 million. That improvement will move to discontinued operations -- is expected to move to discontinued operations in the second quarter, as we expect to close the sale of that business segment. We announced the sale earlier this year in April for $103 million, and we expect to close that transaction by the end of June.

The first quarter really represented a continuation of our recently historical earnings pattern. Recall in 2004, the first two quarters were low, and then in the last two quarters we had a continuation, or back to normalized earnings with our expectations. We continued that again in the first quarter.

In addition, we announced or we closed in the first quarter Cheyenne Light, Fuel & Power. We are pleased with that acquisition. That added a couple of cents a share in the first quarter, as that is typically a stronger quarter for Cheyenne. But we also filed with the Wyoming Public Service Commission a rate case that would be, if approved, would be effective January 1 of 2006, and would increase revenues by approximately $5 million.

We also filed with the Wyoming Public Service Commission an integrated resource plan and how we intend to -- or plan to serve the Cheyenne load. With that, we expect to build -- begin construction, or propose to begin construction of another 90 megawatt coal-fired power plant at our Wyodak mine site. This would be a triplet to the two plants we have already got out there, the Neil Simpson Unit #2, and the Wygen Unit #1, which went in service in 1995 and 2003, respectively.

We would look to begin construction this year, and we are in the process of -- going through the process to get all of the permitting finalized and be prepared to begin construction later this year.

In addition, in the first quarter, or after the first quarter, we increased our guidance by $0.05 a share to $1.90 to $2.05. Certain factors affecting that, the Wyodak plant, of which we own 20% and PacifiCorp owns 80% and is the operator, has deferred its major maintenance outage. That was originally expected to be in the fall of this year, and it has been moved to the spring of 2006. We did experience certain unplanned outages with that plant, 18 days in the first quarter. So we remain cautious regarding its operations until it gets to its maintenance overhaul -- now expected to be in the first quarter or second quarter of 2006.

Also, the impact has also included the announced sale of the communications business, and we expect to close that sale in the second quarter, and we will move those operations to discontinued operations.

Operationally we had, as I mentioned, a 13% increase in our oil and gas production. Recall our guidance -- our previous guidance for that is 10% production growth year-over-year. So we appear on track with that. Our coal mine was down slightly in production, 4%, 1,153,000 tons. And again, that is primarily due to our largest coal customer, the Wyodak plant being down 18 days in the first quarter.

Our plants for the generation -- we added a disclosure, or a plant availability in our press release and in our 10-Q. And that is really intended to demonstrate the tolling arrangements that we have. We get paid to be available -- to have our plants available. In addition, we incrementally benefit via energy sales, but the majority of our revenue stream and our earnings are contracted with load serving utilities. And as you can see, we had very strong plant availability, and we have had that historically. So we added that to our press release, and we will expect to continue to add that disclosure.

In the first quarter also, we had for the 35th consecutive time an increase in dividends. And we paid $0.32 a share, which is an equivalent of $1.28. And we are pleased with that record that we have had over the past 35 years.

Finally, we did enter into a five-year credit facility. It is a $400 million revolving credit facility that expires in 2010. And that will replace two existing facilities that we have totaling $350 million, which were set to expire in May of 2005 and in August of 2006. This provides us with adequate liquidity going forward to continue to grow our businesses.

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

+++ q-and-a.

(OPERATOR INSTRUCTIONS) Michael Worms, Harris Nesbitt.

A couple of questions -- in the Q you indicated that you had some legal expenses that you incurred in the first quarter in the utility. Can you kind of explain what is going on with that? What is it related to? And how much of that -- how much it was of an impact, and whether or not this is an ongoing thing for the rest of the year? Should we be factoring that into our numbers?

We did experience additional legal costs. We do have, as disclosed in our 10-Q, we do have some -- or 10-K -- I don't know if I -- litigation or an issue with Pacific Power Marketing. And we continue to work through that issue with them. And we incurred additional legal costs. We did not disclose the specific amounts of that. We would expect that to some extent to continue through this year as we continue to work through that issue.

Could you just give us a little bit more color as to what the issues are about? What are the --?

The issue is -- I can't really -- I am not really at liberty to speak to the issues of the case, as it is an ongoing case. But it revolves around the contracts that we have with PacifiCorp and Pacific Power Marketing specifically. But other than that, Mike, I am not at liberty to really talk about that case, since it is an ongoing case.

Okay. The filing also indicated you had incrementally higher professional fees? What was all that about?

Primarily, the incrementally higher professional fees relate to the ongoing Sarbanes-Oxley audits and accounting that we have had. We had additional fees there which we did not incur as much in the first quarter of last year. That was more incurred throughout -- towards the end of the last six months of the year, where we incurred more of those costs, whereas, being in the second year, we're continuing to do that on an ongoing basis. But we expect those costs overall to be slightly less on a comparative year-over-year basis. But in the first quarter, they were slightly higher compared to the prior year.

And in relationship to the $3.1 million mark-to-market loss in the first quarter, are you expecting that to reverse itself throughout the balance of the year?

Well, there are a number of factors that go into that calculation. A lot of that is dependent on the positions that we have. Primarily, what gets marked-to-market in the accounting rules, and not to delve into too much detail with respect to all the accounting rules, but on certain storage agreements and transportation, you can only mark one side of the transaction to market. The other side is in the -- just value or economic value, which is why we include that additional disclosure of a non-GAAP measure in our 10-Q and in our 10-K.

So the timing of that depends on the positions we have on and the price in the market. The price ran up in the market at the end of the first quarter. And when you have a storage deal in which you have got a forward sale, economically, you are hedged, but you would have to mark your forward sale to market.

So as an example, if we had bought gas at -- and I am just going to use a theoretical price of $5 -- and sold it forward at $5.50 as an example, the market price of that forward sale, if gas prices moved up to say $6, is out of the money. And we have a negative impact in the unrealized mark-to-market. Yet, the value of our inventory, or gas in storage, does not receive the same treatment. It is still valuable, and we still have the forward sale in our margins, but we are unable to do it. So we would expect that some of that, depending on the positions we have on, as that rolls off it should roll through realized margins.

Last question relates to oil and gas production. Although it was up 13% over the first quarter last year, it looks like it is kind of flat with the fourth quarter. What should we be looking for in terms of oil and gas production on a quarterly basis going forward? I mean, is 3.5 Bs the kind of number we should be looking at?

We haven't really specifically given quarterly guidance as to our oil and gas production. We have said that we would expect it to be 10% greater than the prior year. And that was 12.7 Bcf equivalent in the prior year. And we would expect that to -- that is our stated guidance.

You begin -- as you have drilling, the drilling usually occurs in the summer. We don't do a tremendous amount of drilling in the first quarter because of winter. So then your additional production come on in the third and fourth quarters historically. But we don't specifically give quarterly guidance on our oil and gas production.

Paul Debbas, Value Line.

I have a couple of questions about the Wyodak plant. Why is PacifiCorp shifting the outage from this fall to next spring? And how much would it be in the budget as far as your share of the costs go?

With respect to our share of the costs, we are a 20% owner, so we would have 20% of the cost of that outage. It is a jointly owned facility, and we are 20% owner and PacifiCorp is an 80% owner.

With respect to why is PacifiCorp deferring that plant outage until the spring, that would be their determination of their fleet and their system, and when they want to bring their plants down. We at Black Hills don't control that. So they could be, as a speculation purely, they could be looking at -- we want that plant available in the fall, looking at where prices are -- power prices are. But I can't really answer the specifics of that, because that is their determination. We don't have input as to when they take that plant down. They are the plant operator.

But as far as the costs go, how many millions of dollars are going to be shifted from '05 to '06?

Well, the determination -- we haven't specifically come out with the determination of what would be expense and what would be capital. When you do a major overhaul there is some of the dollars that are capitalized into that plant, and it is not just expense dollars, if that is what you are getting at. The impact on Black Hills with that outage is we now have 72 megawatts of capacity available in the fall, and we don't have to look to purchase power to replace that. And that is an efficient source of power for us, as well as they are our largest coal customer, as we serve all the requirements of that coal plant. So we will have an expectation of additional coal sales this year, though that does move into next year in 2006, where we will be impacted by not having the 72 megawatts available and not having the coal sales in next year.

We have not specifically identified what the income impact is, but as we have moved our guidance up somewhat, we are cautious on the plant availability throughout the summer. We always have that operational risk that our plants run in the summertime when we peak. But given the historical operation of that plant -- of the Wyodak plant, down 18 days in the first quarter, we have remained cautious in our expectations of the availability of that resource.

Paul Clegg, Natexis.

Most of my questions have been answered, but let me see if I can do some follow-ups here. With reference to the switch over -- and I'm sorry if you just answered this; I got interrupted for a second. But with the switch over to the Wyodak outage for '06 instead of '05, how much of an incremental benefit is there to you for doing it in the spring versus the fall, if you can quantify that from an earnings perspective?

We have not historically specifically said what the incremental benefit or the even the incremental negative of having that plant outage is. Historically, the spring is a better time to do your maintenance, because hydro in the West is more prevalent. Now last year in 2004, we took our plant down in the spring, and gas came on the margin, and we were negatively impacted. So that doesn't always hold true. But incrementally, it is historically better to take your plants down in the spring in the West because of the strong prevalence of the cheaper hydro resource. So a number of companies, not just Black Hills, a number of utilities do their maintenance outages in the spring. So we believe it would be incrementally better, but we have not specifically identified what those amounts would be.

Also the $0.18 year-over-year improvement in power gen, obviously a lot of that is due to Las Vegas II being contracted. Can we assume that because you had -- it looks like you had some negative offsets in that category, as well -- would we be right in assuming that more than 100% of that is from Las Vegas II being contracted?

I don't know that I would say we would assume. What we have stated in the past was the fourth quarter of 2004 had approximately $4 million in net income from our power generation unit. And we believe that that was a reasonable expectation going forward, because if you will recall in 2004, we did not have the Las Vegas II plant contract in the first quarter. We made $3.9 million in the first quarter. So that is very, very reasonable to our expectations on a normalized basis.

Those plants are all -- I think were 95% contracted, so that should be a very stable earnings stream as long as our plants are available. That is how we get paid on capacity payments under our tolling arrangements. So as you can see in the first quarter this year, as well as the first quarter last year, our expectations were met. We had very high availability at 98.9%. So that is really what is going to drive as our plants are -- our plants available. And they were in the first quarter, so that is a fairly normal impact for us for the first quarter earnings-wise, and we would expect that to continue.

The one negative we do have is we have one plant, the Las Vegas I plant, a 51 megawatt plant that we have 50% of. It is a QF, qualified facility. It does have open fuel risk. It is the only plant that we have open fuel risk at. And with gas prices higher, that did have some negative impact to that plant. But all in all, our power generation business performed very well and as expected.

Okay, I appreciate that. And just one last thing -- looking beyond Wyodak II, is it too early to start talking about other potential generation opportunities in the West?

Well, it wouldn't necessarily be Wyodak II; it would be Wygen. Wyodak is a large plant (multiple speakers) PacifiCorp owns, just to be clarifying.

We also in our integrated resource plan that we filed with the Wyoming Public Service Commission, had an additional plant after the Wygen II facility to come on after that. And we continue to look at opportunities in the West at our sites that we have and some other development. We continue to look at opportunities in -- again, the concentration of load pockets, our Las Vegas site is a good site. Our California site is a good site. And our Colorado site is a good site, serving the load serving utilities in those areas. We do continue to look at opportunities to expand those sites, but we have nothing at this point that we can announce.

James Bellessa, D.A. Davidson & Co.

Congratulations on a good quarter. The average wellhead price for oil, for example was, according to this press release, $53.14 a barrel. And in your Q, you talk about your average oil price received net of the hedges was $32.73. So less than $20 below the wellhead price. But explains that?

Well, some of the explanation is our wells are in Wyoming, and we get a significant basis difference with respect to that. So the wellhead in the reserve report was as of -- also as of the end of the quarter. That is a period end price as opposed to throughout the period. And we also had additional -- we had hedges, as you can see in a 10-K and in our 10-Q, we have added the hedge activity. We do have -- we had a significant amount of our production hedged at a lower price. When we put those hedges on before prices ran up throughout 2004. But we had hedges on for our production, and it was a significant portion of our production and we -- that we hedged out. So it is affected by our hedging activity that had been done previously.

If you look at the first quarter, just the difference in the hedges -- we had some on -- we have some on for 2005 at $27.90 and $34, and then in calendar '06 it is $41. So as we forward-hedged that price improved, but when we put those on prior to the price run up, that does impact our overall price received.

And when you say average wellhead at the period end price, is that your wellhead price, or is that some benchmark that you are looking at?

In the reserve report, generally, you do try to take it back to the field in the wellhead that we have, within some reason. You can take it to a liquid point is all you can take it to. You can't take it all the way necessarily to the field other than net of some transportation to get to that liquid point.

Early on the conference call in response to one of the questions, you referred to some non-GAAP measure, and I didn't catch what that non-GAAP measure was.

Well, it is disclosed in our 10-K as well as our 10-Q -- GAAP accounting, or generally accepted accounting principles -- that is what GAAP is -- requires mark-to-market accounting on certain transactions in our marketing business. Included in those are storage gas that is sold forward. We mark-to-market one side of that. The derivative contracts as defined by the accounting authorities is a mark-to-market item, whereas the gas and storage is not. And I am using that as an example. There are certain other transactions that have mark-to-market accounting.

So we marked through our financial statements. We took a $3.1 million mark-to-market loss, or negative, in the first quarter, and that reflects forward sales. In my example that I gave, Jim, assumed as a hypothetical we bought gas at $5, put it in storage, entered into a contract to sell that gas forward at $5.50, and the market price for that gas at that pricing point moved up to $6. So our forward sales at $5.50 is out of the money. We have to mark that to market on a negative basis reflective of the volumes of that contract. Yet the storage gas does not get mark-to-market treatment under the accounting literature.

So what we have done is put in the 10-K -- we have done that for the last several quarters in our Q, and did include it in our 10-K in 2004, to identify that there can be some volatility in the marketing business earnings because of mark-to-market. This is really one of the first quarters where we have had any impact of any significance from mark-to-market -- or one of the first quarters.

But we had in there the fair value of our positions as to what we have in our positions, and then the economic value, the overall economic value of our forward positions. And at the end of the first quarter, excluding a liquidity reserve, which assumes that -- the liquidity reserve is designed to say if you have what I will call a fire sale and had to immediately liquidate your portfolio, you would do that.

We expect to hold our positions and closeout those positions in the normal course of business. And as you can see, in our 10-Q, we have $2.5 million of economic value or forward margin in that book. So we do have a positive. But the accounting requirements under generally accepted accounting principles require us to mark that as I have described. And there is a lot of detail that go into that -- go into those calculations, but that was a general example.

Can you give us an idea of what the Cheyenne acquisition revenues were last year? And do you expect them to be on the same footing this year, or are the gas prices significantly higher under a purchased gas mechanism, and therefore, and not very comparable this year to last year?

Well from an overall perspective we had stronger revenues in Cheyenne. But the first quarter -- and with respect to gas prices, the first quarter is the winter, and that is where you have more of your consumption or usage, and they are a winter peaking utility. So the revenues from that business are higher than -- in the first quarter that we would expect on a full year basis.

But their contribution, again to restate it, it was stronger in the first quarter. We expect it to be a nominal impact for the year until we get to the rate case. If approved by the Wyoming Public Service Commission, that would improve our earnings back to a utility-like return, which we have talked about in the past on calls, of 10.5 to 12% return on equity on a 50/50 capital structure. We have filed the rate case with the Wyoming Public Service Commission, and we expect to have that ruled upon by the end of the year.

Another way to ask the question, I guess, would be how much increase in revenues were there in the first quarter as a result of higher purchased gas costs being passed onto rate payers?

Well, the purchased gas costs in the Cheyenne utility is -- it is a pass-through. But just because it wasn't the first quarter, that has a delay mechanism into it for recovery, so we get deferred recovery of those costs under our rate structure and design with the Wyoming Public Service Commission. So you would not see a significant recovery of the revenues due to the higher gas costs. That gets deferred and recovered over the course of time.

We make -- I believe, it's in October -- don't necessarily quote me on the October, but I believe it is an October filing in which we can recover deferred gas costs. So you wouldn't necessarily see that in the first quarter. Our revenues from Cheyenne in the first quarter were $27 million.

I see in the Q had you owned it for the whole year, it would have been $36 million. And I look at that $36 million, and what I thought was the revenue base, and it seems like your run rate is higher than I would have thought. And that is why --.

Well, again, the first quarter is a stronger quarter, not just because of the higher prices, but because of usage on the gas business.

And can you give us a comparison if you had owned it for the whole quarter, the 36 million you cited in the Q was relative to what a year ago?

I don't have that with me, Jim. I would be happy to -- if we have the data from before on a pro forma basis -- but I don't have that specific data with me at this point.

John Hanson, Imperium Capital Management.

Just a follow-up question on the Wyodak outage that you did have this quarter. What kind of issues did you run into here for that 18 days?

Well, it wasn't just one straight 18 days. They were just normal maintenance items that occur in a power plant. You could have just operational issues, two leaks or a circuit going off. I don't know the specifics of -- all the specific details. It wasn't down for 18 consecutive days. It just had some minor maintenance where it would be out two or three days at a time at different points.

Okay, that's good. Let me ask a little bit about the cash balance now is down a bit, having acquired Cheyenne. You are going to sell the communications business. Can you recap again what the cash implications of that sale will be, and how does that replenish the coffers a bit?

Well, the gross purchase price is $103 million. We expect to pay some taxes -- the difference between your tax basis and your assets and your book basis and your assets. We will have a tax gain. We do have an expected $0.09 loss on the sale from a book perspective, but we will have to pay some taxes on the tax side just due to accelerated depreciation. So we expect to use those proceeds to either to reduce debt, but also to continue to deploy capital to grow our businesses. And the one project we expect to begin this year that we have actually talked about is the building of another coal plant at our mines site in Gillette, another 90 megawatt coal plant.

Okay. Growing your business, you also mentioned plant sites that you have in other locations that are promising as well. Might you be looking at other plant acquisitions and development besides the coal plant?

Yes. We continue to look at opportunities. We just -- until we have an announceable deal, we don't speak to those publicly. But I mentioned the sites because the sites -- the existing sites we have existing infrastructure and the capability with additional capital to expand. But our historic practice, we still remain with that. We don't build unless we have a contract. It is not our intent to operate merchant plants. So we look to continue to work with our customers, the load serving utilities, to see if we can provide them additional wholesale power through plant expansion or site expansions.

In addition, we look at other opportunities to develop assets throughout the West, not only on the power generation side, we look at midstream assets and opportunities in the retail sector and in the wholesale oil and gas sector. Right now, oil and gas is -- those opportunities are expected to come more through drilling up our properties. But long term, we still expect to continue to grow in the West.

Adriano Almeida, DGHM.

It seems most of my questions have been asked. But I have one that hasn't. It relates to the -- back in the fall you took about 100 million or so in inventory, gas inventory, in the marketing business. And I noticed that that has unwound a little bit. I was just wondering if you can give some color where you are at in terms of reducing that line item or to actually unwind that particular position?

Well, we did -- a lot of what we see we did unwind some of that position in the first quarter. We expect to a little bit in the second quarter as well. Our overall inventory, we now look to calendar spreads to continue to add that. We had approximately $40 million of inventory held by Energy Marketing at the end of the first quarter. Some of that is expected to roll off still in April, but then we begin to look at calendar spreads to have opportunities to put new storage positions on through the summer and do a summer/winter spread, if those are economic to do so. So yes, we did still have, again, $40 million of inventory as of March 31.

Okay, but on a run rate basis, would you say that the amount of capital that is committed to that particular type of business will have a lower run rate going forward than it was in the fall?

A lot of that come depends on the market conditions. If there are opportunities to make economic transactions and have storage with forward sales, then we would do that. If there are not, then we wouldn't. Having a specific amount -- last year, we had an ability to have a higher amount of gas in storage because of capital availability and the market conditions for those opportunities.

To the extent those exist in the first quarter, and it is economic to do so, we would look at doing that. But I can't forecast or predict specifically what those will be. If we make our hurdle rates or our returns on those, we will deploy the capital for those opportunities. If we don't, we won't.

Okay, is the mark-to-market adjustment you took, is it related to that?

It is -- in combination with the market factors -- as I explained earlier in the call, market prices move up, and we have to mark the forward sales. We also have certain transportation contracts that we have to mark-to-market as well. It is not solely storage, but the majority of it is storage. So to the extent that we have positions on and forward sales, it does relate to that, yes.

Okay, and I guess another -- a one here. You mentioned you were kind of still a little bit cautious on the Wyodak potential to have these minor outages. Has something occurred after the quarter closed?

We haven't disclosed anything significant. If there was something significant, we would disclose it. But we remain cautious primarily for the summer, as we are a summer-peaking utility, and it is one of our efficient resources. We have that risk of operations every year that our plants run during the summer. But given the historical performance and having some outages, some unplanned minor outages, we remain cautious in what we set for our forward expectations in our guidance. But there is nothing that I would say that we know of that is a significant negative at this point. We just want to remain cautious looking forward.

Okay. And how do you feel about the opportunity to get some better wholesale margins here in the summer?

A lot of that depends on the different markets, the weather factors, and our plants. Hydro has improved some in the West. They have had some spring water. They are still below normal, but they are not as significantly below normal as they were. But being still below normal, we believe that there are still opportunities because of our location and strategic location that we can move between East and West that we believe there are opportunities there. But the way -- in the summer, that typically isn't as big of a driver for Black Hills because that is when we peak, so we use our resources primarily for our own customers. It is really the shoulder periods of kind of the spring and fall to the extent that those opportunities are there, we will take advantage of them. I don't see a significant change, but a lot of that depends -- that is a day-to-day and week-to-week business.

We are able to take advantage of those opportunities, and do so. You can see our utility wholesale off systems sales that we did report some increase, but the margins were fairly thin in the first quarter. We had a 14% increase, or 231,000 megawatt hours over 2002 in the prior year. But the margins were very thin in the first quarter. A lot of that is due to the higher gas prices. And the gas price differential with the Kern River pipeline going in, the Rockies gas has come up significantly. That benefits us on our oil and gas business. It makes it a little more difficult on the wholesale power business.

Okay, well, thank you very much. Nice quarter. Keep it up, guys.

(OPERATOR INSTRUCTIONS) Peter Hark, Talon Capital.

On the Las Vegas II plant, remind me again when that tolling contract became effective? Was it second-quarter '04?

April 1.

April 1.

2004.

Okay, so it was fully in effect for last year's second quarter, is that right?

Yes, but not at all in the first quarter.

Got you. Okay and then secondly, you mentioned maybe expanding the Power Generation segment. Pinnacle West at Silverhawk -- made available there in the Las Vegas market. I didn't know if you were expressing any interest in that facility?

There are a number of plants that are available in the West. And we look at the opportunities to see if they make sense for us. When I mentioned the expansion, I mentioned it really with respect to our site in North Las Vegas, the Las Vegas Cogeneration I and II site, that we would be able to expand that. We look at opportunities throughout the West, but until we have something that we would consider announceable we don't speak to them. But we are active in looking at opportunities.

Okay, fair enough. What was the quarter end cash balance? I'm sorry.

It was 64 or 66 million (multiple speakers). That is 67.6 million.

And there are no further questions at this stage. Please continue.

We appreciate your interest in Black Hills, and thank you for your time.

Ladies and gentlemen, this conference will be available for replay at 11:45 AM today through midnight May 18. You may access the AT&T Teleconference Replay System at any time by dialing 1-800-475-6701 and enter the access code, 781071. (OPERATOR INSTRUCTIONS).

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