Black Hills Corp (BKH) 2004 Q2 法說會逐字稿

Welcome to the 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. I would now like to turn the conference over to our host, Dale Jahr. Please go ahead.

Good morning, and welcome to our conference call. Thank you for your interest in Black Hills Corporation and for joining us today. 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 of recent results will be led by Mr. Mark Thies, our Executive Vice President and CFO. Mark would like to start off with a review of these results before we open the call to your questions. Mark?

Thank you, Dale, and good morning, everyone. Thanks for joining us on our call. We're here to reported second-quarter earnings which we pre-released a few weeks ago regarding our expectations for the quarter. And at that time we had an announcement that we came right in the middle of our range.

We had 11.4 million, or 35 cents a share for the second quarter, and that included some discontinued operations. So our income from continued operations was 9.6 million, or 29 cents a share. This compares to 13.5 million, or 44 cents a share in the prior year's quarter in 2003. A number of factors affected our performance in 2004 relative to 2003. We had a decline of 12 cents a share, or $4 million, in our power generation unit, and that really is represented by three main items.

We had some fund investments with energy investor funds that had a marked-to-market valuation that declined versus an increase or an increase in market value at 2003, and that was 9 cents a share. And we had 8 cents a share difference, or $2.6 million, from our Las Vegas II contract relative to last year, in which we had a contract with Allegheny Energy Supply. So we had a decline there. The plant was contracted beginning April 1, so we are under contract for that. And then we had an additional 5 cents a share increase from our other plant operations.

In addition, we were down in our electric utility $2.9 million, or 9 cents a share, primarily related to increased purchased power and maintenance expenses. We had a planned outage, which is normal for Black Hills and many utilities to do their maintenance in the April/May timeframe. That is usually a swing period with less load and higher hydro availability. We did have an event, an unplanned outage, and we had a higher cost as gas came on the margin in the West. So our purchased power cost increased significantly, and that caused a decline in our electric utility.

And then the third item affecting the results for 2004 was a revenue accrual error that occurred in the second quarter really related to the first and second quarter. When you get to six months to date, the total impact is approximately 1 cent a share -- just under a penny a share. But it did impact our second quarter 6 cents a share, $1.8 million.

We have had operationally very strong results. We've increased our oil and gas production by 12 percent. We've increased our marketing volumes on natural gas by 35 percent. Our utility was slightly up, with firm sales up a percent in the second quarter and wholesale sales up 11 percent, albeit at lower margins. And our communications business continues to improve slightly as we added overall customers. We had a slight decline in residential customers, but overall we added customers for our communications business.

From a balance sheet perspective, we did file our 10-Q yesterday. So this is one call I can actually speak to more of the balance sheet items. We still have $104 million in cash on the balance sheet. That is down significantly from the first quarter of $191 million, but that is due to several factors.

We paid off an additional $25 million in debt. We repurchased some corporate notes. We had an increase in inventory in our marketing business as that -- we are allowed -- we've seen the market come to buying gas inventory and selling it forward in the winter season. So we've used $32 million to acquire inventory which we will sell later in the year. And we had some normal working capital differences as well that totaled about $25 million. So we did see a decline in cash in the quarter. Our debt-to-equity percentage is right around 52 to 53 percent, so we have a very solid balance sheet. We have strong cash flows from operations as the cash flowed -- our dividend and our capital expenditures. And we expect that to continue.

With respect to capital expenditures, we did revise our forecast for capital expenditures. Every quarter we try to update our expectations on what we believe we will spend, and we have now revised our capital forecast for this year and going forward. And that is really based on opportunities that we see today. We don't have any opportunities that are announceable. We're working very hard to try to continue to find opportunities to deploy capital and continue to grow our businesses, but at this point, we have reduced our capital expectations for 2004 to just under $180 million. And that does include the expected closing of our pending acquisition of Cheyenne Light Fuel and Power later this year.

In addition, we decreased our 2005 and 2006 capital expenditures. And those are primarily decreases related to development capital. Previously, we had expected to spend $200 million a year in development capital, and we are not seeing those opportunities in the market that we can have -- maintain that expectation. Should those opportunities come available to us, we would revise our forecast upward in the future.

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

(OPERATOR INSTRUCTIONS). Mike Weinstein, Zimmer Lucas.

I wanted to talk to you about the guidance that you gave a couple of weeks ago for 2005, $1.85 to $2. I'm wondering if we can break that out a little bit more about what your expectations are for various lines of business? For example, the energy marketing business I have making 47 cents a share in '03, and I'm wondering whether that takes a hit or if it's the utility that's taking most of the hit? I think it would be helpful to kind of break that out a little bit more.

The one thing we did mention with respect to the guidance for next year really did relate to the utility as we have a large plant that's expected to undergo a major overhaul next year. So we would expect utility. And that also is a large coal user, so we would expect the coal mine to also decline from lack of coal sales for a major overall. And those occur five to seven years; every five to seven years you take your plants down for major work. And we just have one scheduled next year, so we would expect the utility to decline some next year relative to that major overhaul.

With respect to the marketing business, we don't expect to see any significant decline from the marketing. They have continued to be profitable and we continue to have strong results from our gas marketing business, so we wouldn't expect a decline there. On the oil pipeline side, we may see some slight decline as contracts -- we have a contract on that pipeline, and we continue to have a slight change in margins. But I would not expect any significant difference from our marketing business this year versus next year, and not a significant change. We do expect increases and continued increases from our oil and gas business. As we said, this year our expectations for the second half of the year are to increase up to 50 percent of production versus the first six months, and we would expect to continue to grow our gas production going forward.

So it sounds that in the lowering of the, I guess, the expectations for '05, it sounds like most of the pain is coming from the utility in terms of where -- compared to the previous guidance for '04.

Well, that, and this is the second time in seven months we've had to do this. And we looked at our forward guidance. Typically we don't -- we haven't given forward guidance for years, and we decided in this case to do that since we lowered this year based on our first six months -- compared to expectations, and then wanted to get 2005 with an expectation out there. We do -- we probably are looking at this conservatively because we don't know what the market will bring next year, and we want to make sure that we have a forecast we believe we can hit.

Jeff Gildersleeve, Millennium Partners.

Just a few questions. Number one -- in the Q, you talked about at the utility the purchased power being around $31, and the per megawatt hour cost to generate the gas units as $81. Just with that, in that context, you also mentioned that there's a 78 percent decrease in megawatt hours generated from the gas turbines year-over-year in the second quarter because you were able to purchase more power. Could you -- what are the megawatt hours that were generated in the second quarter for the gas units? And then also, do you have for the third quarter last year how many megawatt hours were generated from the gas units?

We don't typically go through, Jeff, and go through the specific differences. We're always making a decision -- or the system control is always making a decision on what is the cheapest supply opportunities to serve our customers, whether that is running our own units or purchasing power either from the East or the West markets because we have access to the East and West markets. So that is a daily determination and over a weekend. So we did have a significant decrease in megawatt hours because it was -- and that's the point in the 10-Q -- because it was cheaper to purchase power from the market in that time period. And whether we run our turbines are not is really market driven as to what is the best supply for our customers, or for our company to supply our customers the energy.

Okay, sure. I'm just wondering -- it sounds like you did run the units to some extent, then given that the price or the cost of power is so -- there's a huge gap between the purchased power cost and the unit to generate -- I was wondering what makes that decision then, if it's not purely cost?

We have to deliver. We have a regulated utility, and our larger power plants had an outage, and we needed to replace that power from the units that were down with either market power or gas turbines. We have to serve our customers; that is our -- as a regulated utility that is one of the measures we are evaluated upon by our commission. So we determined that the cheapest to deliver is the way to do it, and that's where you go through that analysis of either purchase or generating. But if purchasing is not available or there are system constraints -- we did have some system constraints within the quarter from the Eastern market because of storms in Nebraska, which we had previously reported in our press release. So that took away one of our options during that time period, so we had to either buy from the West or generate that power. It's largely cost-based evaluation when we're doing it, but we still have to generate the power and serve the customers.

Yes, that's helpful. I guess I was just wondering you know, why not purchase all the power. I guess what you're saying is that certain times there are constraints where you're not able to purchased all the power for your needs, and you have to run the gas generation.

In the instance in which the Eastern market was down, that is true. Generally speaking, we have that available and we can arbitrage between the markets and get the best price, or at least have supply. If not, and power is not available, then we have to run our units.

Just moving on quickly, second question -- on the new Las Vegas Cogen II contract, you mentioned in the Q there's an 8 cents, I think, impact year-over-year mainly from that contract, the new contract versus the old Allegheny contract?

Yes.

When we are looking at the rest of the year, that contract -- is there a seasonal element to it, or is that a fair run rate?

There is -- we do have a summer and winter test from a megawatt perspective, so there may be some slight differences relative to the megawatts under which we get paid under that contract under that tolling arrangement. But generally we would expect that difference to occur, and that difference is relate relative to the power generation business. We did receive $114 million in cash, and that -- the impact of having that additional cash is not included in that. We do get some earnings off of that cash. (indiscernible) phenomenal amount, but we are trying to reduce -- continue to look at ways to use that cash, whether through capital deployment or reducing debt. So that -- the 8 cents is directly related to just that specific segment and does not count that additional cash. But we would expect that to continue within a fairly narrow margin going forward.

When did the Allegheny contract expire last year again?

September.

You mentioned in the Q that you guaranteed up to $10 million of payments related to the Sempra Energy contract. Why are you guaranteeing the payments versus Sempra? How does that work?

Sempra is our counterparty, and they've asked for -- it's really a performance guarantee, that we perform under any type of deals that we would do with Sempra. And that just depends on if they supply us gas or purchase the power, that we will pay them. And that guarantee is to the extent we have any deals with Sempra; we don't expect that. It's cancelable within five days upon notice, and it's for gas supply in Las Vegas I, which is a -- it's the 51 megawatt Cogen facility in which we own 50 percent. So it's really a performance guarantee for that subsidiary. We do that from time to time, but we expect to honor our obligations and wouldn't expect any call on that guarantee.

Finally, cutting back the CapEx budgets significantly -- could you talk about any plans besides debt reduction? Do you have any plans as far as share buybacks, dividends? Or again, if you could talk about trying to redeploy that cash?

There's really four things you can do with your cash -- you can redeploy it into businesses, and either existing or new opportunities would be one; we continue to look for those opportunities, but at this point don't anticipate closing -- other than the Cheyenne acquisition -- any significant transaction this year, which is why this year's capital spending declined. You always have the opportunity or alternative of the debt repurchase or stock repurchase as a use of cash. We did acquire -- reacquire $25 million of debt within the quarter on our 6.5 percent corporate bonds. We did close that in the second quarter, and we continue to look at our alternatives -- the other being dividends, and we've had a long-standing history of dividend increases in the 4 cent range. And we would expect that our dividend policy would continue. We don't expect to have any significant onetime dividend, but we would expect to continue to have our normal dividend policy as we go forward. And that is dependent on, obviously, results and impacts at that time the Board makes that decision. But we have increased -- over 30 years we have increased our dividend annually.

Paul Patterson, Glenrock Associates.

Just to circle back here on the accrual from the oil and gas business, the 6 cents there. Could you elaborate as to what actually caused that?

It was an accounting error in which we made accruals, and in that business you always accrue for your production then reverse out when actual production comes in. Because you have expectations of what your production is. It's just accrual accounting, and we did not properly reverse out the amounts. It was really a first quarter versus second quarter impact. The total impact for the year -- there was a nominal amount of a penny a share from last year, but it was really first quarter versus second quarter in which we overstated revenues in the first quarter and understated revenues in the second quarter. So at six months it's effectively a non impact. And the first quarter we didn't believe it had any impact. We had a low first quarter, as we've previously announced, in that it wouldn't have made any change to that expectation. It still would have been a low first quarter.

The fair value mark-to-market decrease in the power fund -- what caused that?

We account for our investment in the power fund under the equity method -- and not to bore you with our accounting requirements -- but we take the results of those partnerships and take our share on our percentage ownership and record that. In 2002 -- and this goes back a little ways -- the partnerships elected a fair value method of accounting in which they valued their plants, their investment in power plants on a market value basis. And that can change based on their views, the partnerships' views of the market value of their plants. And we merely record our percentage share of that so that we do have some volatility. That's not a significant part of our business, as the investments in our investment section of our balance sheets are about $27 million and the fund investments are approximately half of that. So we only have about $13 million in those funds, and it's really a melting ice cube in that the funds are continuing to look to exit -- sell their plants, and as they do that we'll take the cash and be done. But it does cause some volatility. And in 2003 we had a gain in market value from the fund investments, and in 2004 we had a loss. So the difference, the change quarter-over-quarter was about 9 cents a share, or $3.1 million.

I guess what I'm trying to figure -- I mean -- what I'm trying to figure out is there seems to be some change in the valuation that's actually happening with the underlying assets. Do you understand what is actually causing that on the part of your partners in terms of evaluating the investment as being less valuable, and can this continue going forward?

Some of it is -- and I don't know all the specifics and details of how the partnership goes through the evaluation of the market value of those plants, the location of the plants and the value of their assets. They use their valuation methods. One -- the instance in which (indiscernible) caused the '04 impact was they did have a sale of an asset that closed in July, but -- so they went back to their June 30th market valuations, and if they knew they had to close in July they would apply that value to it. And you know, that was slightly lower than the book value so they adjusted it.

But going forward I guess you're not really expecting anything to change in that? Is that the idea?

We would expect that they would do their market value test every quarter. And at this point we don't expect significant changes, but that just depends on market conditions at the time. We don't control that.

Plant outages in 2005; what was the amount that you guys are -- if you could, remind me what was the amount that you guys are actually expecting that to cost you guys again in 2005?

We have not come out with specific guidance on what the plant outage will cost us. It is a major plants outage for our Wyodak plant, which is a large resource for us; it's a 372 megawatt plant. PacifiCorp controls that plant and operates that plant. We're a 20 percent owner. And they have scheduled that outage, so we have to have that in our expectations. Whether they actually take that plant down or not will depend on what they do next year. But in their plans is to take that plant down for a significant major overhaul, and that effects both our electric utility from an electric supply perspective, as well as our coal mine, as they are our largest coal customers. But we haven't come out and said specifically the impact of that on a cents per share basis.

Right. But I guess from Mike's previous question, it sounded like that was what you thought was one of the big challenges that you guys had in 2005, and that that wouldn't be around afterwards -- sort of as an unusual item.

It's unusual for 2005, but from a perspective of that, maintenance is usually -- every five to seven years we do plant maintenance, (multiple speakers) that scheduled. (multiple speakers) that is impacting our expectations for '05 downward to (indiscernible), and it is included in our guidance for '05.

The property tax accrual at the communications business that seemed to benefit you guys -- what happened there? What was the benefit there, and how is that going to be treated going forward?

That was just really an impact (indiscernible) we always accrue our property taxes, and then we work with the state and come to final resolution. And in our final resolution we had accrued more in property taxes than we ended up owing with respect to our communications business. So that was just a true-up to actually what we owed, and we do that on an ongoing basis; we try to make the best estimates we can based on information available. And to the extent we're able to settle with the taxing authorities, then we true-up to what we actually owe. And that's what that was.

So it's sort of a quarterly situation, sort of an unusual event there? Is that right?

Somewhat. It's an ongoing -- you're always making estimates, Paul. And you try to make those estimates based on the best information you have. And to the extent you true-up your accruals, then that is what -- that's the impact that you have.

When you guys last spoke about the communications business, you guys were concerned that your breakeven part had sort of been pushed out a bit further, as I recall -- correct me if I am wrong -- because of the competition that you were encountering there? And it now sounds like you guys don't -- it sounds -- I'm trying to understand it. It sounds like the communications business did better in spite of the fact that your guys had this price competition with the competitor. And if you could elaborate a little bit on that. In other words, what is driving the results here is that you were able to gain market share -- is that what it was -- even though you were offering lower prices?

What happened was in the fourth quarter of last year, our competition came out with a discount program for six months for new customers, to take customers from Black Hills FiberCom, our communications subsidiary. We matched some of that for certain of our customers, and then with that required longer-term contracts to be signed. But that all rolls off through June 30, the pricing discount -- the impact of that is done within our business, assuming that we have no further competitive pressures, and we're back to our normal earnings from that business. We do have some minor impacts going forward for --

So in other words, the prices were increasing? In other words, those are temporary rate discounts (multiple speakers)

Yes, they were temporary rate discounts that affected the first six months.

And as a result that's going away now. And as a result it's helping (multiple speakers)

Michael Worms, Harris Nesbitt Gerard.

Just a couple of questions for you. Can you give us a brief update as to what the situation is of any changes on the regulatory side?

We continue -- our rate freeze expires January 1, 2005, and we continue to do a detailed analysis of our rates and our business. At this point you could look at it and say well the utility was down, but outages -- when a commission looks at it, they normalize your results and they don't take outages and take that as a rate. So if we used 2004 as an example for normal utility rates, they would normalize the outages that we did have. So we continue to evaluate whether we would seek any additional rates, but nothing changes when 2005 comes. And we have said this before. Our rates stay in place and we would not expect anything to change. We continue to evaluate the higher gas costs and the impacts of that on our electric utility, because we do burn some gas; it's largely cold, but we do burn some gas. And we look at that impact overall to the return that the utility earns, and if that would fall below an expected return in a regulatory environment, we would look to file an increase. At this point, I don't see any anticipation of a filing affecting our rates at this point, based on our earnings for our utility and our expectations of earnings for our utility.

Okay. Back to the question before on the Las Vegas plant. The way I understand it, it's a tolling arrangement and you just basically get a capacity payment. So the inflow of cash, theoretically, should be pretty even quarter by quarter? Is that not true?

That's true other than some small differences between a winter and a summer test, Mike. We do have a test in the winter and a test in the summer for output, and that is the megawatts that we are paid upon. But it's -- generally speaking it is a very consistent cash flow. In addition, we also get some incremental income to the extent that plant is run as part of Nevada power system. And they have run that plant a fair amount of time, but -- we don't disclose specific amounts -- but they have run that plant a fair amount of time to meet their system needs. So we do get incremental earnings in the summer primarily as they're trying to meet their peak loads. So we do get incremental. But generally it's a very inconsistent cash flow and earnings stream.

Just two other questions. One would be -- I understand the potential uses for cash, but with -- there doesn't appear to be any significant acquisitions on the horizon near-term. How long are you willing to sit with that cash before you do something with that other than an acquisition? What is the point of no return and then you just go ahead and do something?

That's a continual evaluation, Mike. And we do have the Cheyenne acquisition that is pending that we expect to close this year, and we would expect to use -- just fund that internally with cash, and we do assume some small amount of debt that they have on their books. But we would expect to use our cash there. We did move in the second quarter to repurchase $25 million of debt. We continue to evaluate what makes the most sense, whether it be additional debt repurchase. Always looking at opportunities to deploy capital and grow our businesses. And then the third alternative really is assuming the constant dividend policy which we have had historically, would be to repurchase shares. And we continue to evaluate what makes the most sense. Whether there is a trigger that says now is the time to do one or the others other than capital deployment, it's always a judgment call. And we look at that on a regular basis and will act accordingly for what we think is best for the Company going forward.

One final question. On the E&P side, are all the pipeline issues that caused the problems in the second quarter and the lack of drilling approvals -- are they all now behind you for the most part?

The pipeline in the storage -- those facilities are up and running, and they are largely behind us. From a drilling permit perspective and drilling opportunities, that is an ongoing operational activity in that you need to continue to get increasing -- additional drilling permits so we can continue to increase our drilling activity and hopefully our production and our reserves. With that, we believe that we have resolved most of the issues there. But that is an ongoing timing issue. And our ability to continue going forward to get drilling permits and drill out primarily that Mallon Field, which has been a very good production source for us, and really has been the source of most of our production increases to date.

Eric Beaumont, Copia Capital.

Most of my questions were answered, but I guess to the extent you can, can you just help us think about what we should really be looking at going forward? With having the investment capital coming up on some good opportunities, and obviously the whole challenge next year with the large plant outage, what should we really be looking at for growth targets over a three or five-year period, and where would the contributions be coming from?

For a three top five-year period, we look at it -- and we have reduced our capital deployment expectations based on what we know now. The market does change over a period of time, and we continue to be actively looking for opportunities as we go forward. So on a longer-term timeframe to have increasing growth, we will have some expectation of additional capital deployed in our businesses, either acquisitions or new development opportunities. So that would be one area I would expect that though we have reduced our expectations at this point -- but that market changes and there are opportunities we're still looking at. We haven't just completely given up on opportunities; we've just come out and said -- look, at this point in time based on what we are seeing in the market, we don't see that the opportunities are going to be there to the extent we had previously thought, which was 200 million a year. We still see opportunities. We do expect to continue to increase from our oil and gas production, that is with the drilling of the Mallon properties; we expect that to be a two to three-year program. As we continue to drill out those properties, and we have been successful in doing that today, then we would expect that to continue. So we would expect our oil and gas operations to increase.

We will also have the addition of Cheyenne, so we have the opportunity with respect to Cheyenne to continue -- we will increase our customers with that acquisition, over 30,000 gas and electric customers. That provides us opportunities also to be efficient with our utility operations. And they are a T&D customer. They have a power supply agreement from Public Service Company of Colorado through the end of 2006 or 2007, and we would expect to look at that opportunity as to whether we recontract our purchase power or we develop generation assets. And that's a planning process that's going on right now for an opportunity to provide that generation as opposed to just contract it. In addition, we expect continued improvement from our communications business. It may be incremental, but as we trend in the three to five-year period to profitability, we would expect some incremental benefits from that as well.

Can you just remind us -- everything is still on schedule with regard to Cheyenne closing?

Yes. We expect that to close this year.

If my recollection is right, I mean, it was about -- your rate base was somewhere in the upper 80 million. And you were saying, I believe -- was it 12 percent return?

You look at a normal -- and you can look -- normally utility is probably 10.5 to 12 percent is the return on equity in a utility environment. So we would expect that we would be in that range for an expectation of return. And it is approximately mid 80 millions for total assets.

Raymond Hanch, AG Edwards.

Very Informative. Just like the previous questioner, I think you've answered a lot of my questions. But what caught my eye in studying your company a little bit was this low sulfur coal, gas, natural gas and oil. And I suppose these days reserves are pretty important; you know, they keep popping up in the paper. And my question basically is, without having to go through everything all over again for you folks, can you give us a little more insight into these -- the reserves, for example, and what you have in the ground?

We have -- in our release on the oil and gas reserves we have 155 Bcf equivalent of reserves that the equivalent is really for oil and natural gas, but it's primarily natural gas. So that's the reserves we have as of June 30. We continue to drill out new properties and we have production. The way reserves are impacted by is you produce reserves, so it's declining. And you want to have your replacement of reserves through your drilling program and new opportunities -- drilling or acquisitions. So that's the reserves we have on the oil and gas business. And in our coal mining segment we have 262 million tons of low sulfur coal, and that really supplies the power plants that are on-site, plus some trainload out. But we do have opportunity to expand that at our site, and we have a permit of up to 500 megawatts of new generation at that site, which would provide us an opportunity to have, again, a multiple revenue stream with earnings from the power plant on the energy side, as well as earnings from the coal mine. And we do have that fuel supply. That's been a very good advantage for us historically.

Thank you very much. And if I may get a note in here, please keep up the good work. You have a very interesting company.

James Bellessa, DA Davidson & Co.

On Cheyenne Light Fuel and Power, and your capital expenditures of almost 180 million expected for this year -- you just told us that the asset base of that utility is about in the mid $80 million range. How much of the 180 million CapEx are you expecting to be attributed to Cheyenne Light and Fuel and Power?

We do expect to assume some debt, so we would expect about $60 million approximately, give-or-take 5 million. Some of it depends on what their working capital is at the time, and under the contract that we have with XL to acquire that. So we would expect to assume some debt, but the CapEx is approximately $60 million -- again, give-or-take 5 million. Jim.

And the equity position that you'd be taking down for return on equity, 10.5 to 12 percent, would that be 30 to $40 million or so?

We would expect -- a normal capital structure in a regulatory environment is 55 percent debt, 45 percent equity, on rate base.

What is the rate base of that entity?

We haven't disclosed the specific amounts for what the rate base is, and that's really a determination with the utility commission of Wyoming. But their assets are largely transmission and distribution, so that's the bulk of their assets.

Turning to the oil and gas business, you've given for the first time prices per barrel and prices per Mcf. Are you planning to do that in the future or was this just a onetime sharing of that data to help explain the revenue accrual correction?

No, it had nothing to do with that. We generally -- if you're speaking to the prices on which our reserve base is calculated, we have done that historically as to what the pricing is on our reserve base.

Mark, I'm talking about the average realized price per barrel and per Mcf that you had during the quarter. In your press release you said you had average realized oil prices of $25.99 and average natural gas prices of $4.73.

We have historically tried to put that in the 10-Q, but Jim, yes-- I think we would expect to continue to have what our average prices are affecting that business. I thought we have had that in the past; I know we've had it currently.

Historically what I think has happened is you've shared with us the percentage change but never told us what the price point was, or average realized price.

Okay. Well, we would expect to continue to have that.

If you're going to go forward with that, which is a good deal, do you expect to share the historical data?

On a relative basis, we can look at that. As to what it was in the prior quarters for comparative purposes, yes, we can look at that.

In the most recent data that you gave on a per unit basis, that is before the correction -- revenue accrual correction -- is that right?

Yes.

Now, you're talking about production going up as much as 50 percent in the second half, which is quite a jump. Can you explain how that occurs and the shape of that production increase?

A lot of that -- we expect it to continually increase as we go forward. A lot of that is relative to getting the additional pipeline and compression stations and gathering systems in the Mallon properties on, which we, again, we're largely through -- there was a delay in that -- as well as additional drilling. We have had expectations out there that we would expect to continue to increase that, and our drilling budget nearly doubled versus previous years relative to that property, primarily recall we more than doubled our reserve base with that acquisition. And that provided us a number of drilling opportunities in which we are actively working to increase production and reserves out of that field. So it was delayed in the second quarter. We had previously expected that that would be higher in the second quarter, and due to operational delays we were unable to do that. But we still expect to be on track. And we're largely through with the pipeline and compression stations. That is done and up and running, so we would expect that increase to be in the third quarter as well as the fourth quarter. And that is why we set up the 50 percent of production, really to put out an expectation that -- in our guidance we do have a strong expectation for increases in our production.

The realized prices of the second quarter, are they pretty good bogey for what might happen in the second half?

That's largely dependent on what the market does. We do hedge 25 to 50 percent of our production as it exists. As we continue to increase production we're always looking at that and evaluating our positions there. But the difference is on the market prices. So as we look at it, we've based it off the forward strip prices adjusted back to our wells, and believe that that would be a reasonable bogey, as you put it, for expectations. Should the market change, that could impact our expectations on forward prices. We use the forward curves and evaluate that on a regular basis.

You're talking about the 50 percent production increase in the second half; that would put the position in the area of as much as 9 million Mcf equivalent sales. Doubling that for an annual basis would be 18. Do you think that that 18 million would be kind of a benchmark production for the following year?

We would expect the -- what you have in oil and gas, Jim, is you have strong production, then you have to replace those reserves because of normal decline curves in the reserves. And we do have long life reserves, so we don't have necessarily a steep decline curve. But with an average life in the seven to 10 years, you are going to get a 10 to 12 percent decline curves with that. So that would be dependent on additional production and additional -- or additional production from a continued drilling program, which we expect to have. So we would expect to return in the future to normal increases in our production, which have historically been in the 10 to 15 percent range. We bumped that up last year and then with an expectation this year because of Mallon. A couple of years of drilling, and then beyond that it's dependent on our ability to continue to find new reserves and new production. Because once you put a well on there is a normal decline curve. So we would not expect the same increase as we have this year over last year, but we would expect an increase over this year's production.

Jeff Gildersleeve, Millennium Partners.

You mentioned the plant outage or the potential plant outage for next year, and I assume that's in your projections? I'm just wondering how can you hedge out for that period of time, or what are your plans to fulfill that gap in production?

Historically, when we take our production down -- and it did not happen this year -- but historically you have a very cheap supply of market power in that hydro runs strong in the spring, and so purchasing power from the market is the cheapest supply. And we would look at having that opportunity. We can look at -- going forward we can look at potentially hedging power purchase requirements in the market with certain counterparties. We've not done that in the past because there's generally been a cheap supply that we could pull off the market. On the coal side, we are not able to hedge that; that's just a loss of production. They are our largest coal customer, and when their plant is down we don't produce the coal to serve that plant. But on the power side, we can look at that opportunity. But generally, the reason you do your overhauls in the spring is because you have a cheap supply or a cheaper supply relative to summer for replacement power. And our loads are generally lower at that time, just in a normal market. The second quarter historically is our lowest period for our own utility needs. So we could look at that for a portion; some of it you have to be cognizant of. We don't want to speculate on power. That's not our business to purchase power per se, on the chance that we wouldn't -- we may not have access to it in the market. Under normal operating conditions we can replace power, and a cost for that is factored into our expectations for what that replacement power is.

Should we assume that assumption is in line with sort of the factors we saw in the most recent second quarter?

No. We look at that expectation from more of a normal market conditions. The market conditions in the second quarter, again, were unusual historically for the April/May timeframe in that hydro was lower in that time period, and a number of plants were down and gas came on the margin; and with gas prices where they were, increased our costs. But in a normal year, that -- that was an unusual event relative to a normal year. We would expect -- in our plans we generally plan for normal market conditions.

Michael Weinstein, Zimmer Lucas.

Just wanted to go back to the 2004 guidance, $1.70 to $1.85. You listed three things that are the reasons for that -- right? And one is the lower oil and gas operations. And I guess this is in order of priority. Number two was the electric utility, and number three is the energy marketing operations. Can we quantify the amounts of each of those things and how much you expect each -- like for instance, the utility to be of the $1.70 to $1.85 in the oil and gas? And I'm also assuming going forward that one of the things that's happening with oil and gas is that you're at just a lower level now because of the delays. And so the reason we don't see an immediate bump in 2005 from that is because you're permanently at a lower level of production? Is that --

That's the timing. To the extent you don't your things done, that production is just pushed back to get out of the ground. We had delays in the second quarter and that's pushed back, so it pushes everything out a few months. And as you expect to continue to grow, that just pushes that growth slightly back. The difference is, the utility -- we would expect the utility to return to normal operations. We are always impacted by potential for weather and operational issues, but that is a normal risk we have with our utility at any time. So we would expect our utility to return to a more normal level of results. And the effects of the second quarter are done. That has occurred and we have announced that. So we would expect the utility to return to normal levels, and we would expect -- we do expect the increase in production for the oil and gas business. And then the marketing business we expect to have normal operations. That's been a profitable business for us for years, and consistently profitable. We would expect that to continue.

Can you talk about the ROE that you guys are earning now at the utility? Is that possible?

We don't disclose or talk about the specific ROE; we evaluate whether or not we would go in for seeking a rate increase or a rate modification, is dependent on whether we believe that based on our expectations and expected costs for the utility and the rate base that we have, if we would be earning a fair return within that parameter. So we do have a separate 10-Q that we file -- we haven't filed it yet; we file it in a few days -- for Black Hills Power. So you can get more specific information as to the Black Hills Power balance sheet and look at that calculation. But we don't talk about what our return is for the utility per se. If we felt we were under-earning significantly we would go in and seek a rate increase.

So it sounds like the difference -- going into '05 from '04, the oil and guess is going to continue at a lower level, and that's why we don't see it a big pop there. And then the utility also is going to have additional outages next year, so we don't see a pop there either. I'm just trying to figure out why the guidance for '05 is so close to the guidance for '04. And then, for energy marketing -- energy marketing made 47 cents last year. Is that approximately what you are anticipating this year, because it does say that you expected lower results from energy marketing this year?

We expect a slight improvement over the remaining period.

For the remaining period, but --

We expected it would be approximately what we had last year. That business can be somewhat dependent on market conditions. We have seen a significant increase in our margins, or -- I'm sorry -- in our volumes, with the decrease in our margins. But we would expect that to be reasonably stable to slightly increasing from marketing (indiscernible) marketing.

The reason I ask is (multiple speakers)

It's not a (indiscernible) change year-over-year, Mike.

The only reason I ask is because you list it as one of your reasons, one of the three reasons why you're lowering your guidance for -- or why you have --

(multiple speakers) the second quarter was lower than expectation. The quarter is gone. Going forward we expect more normal conditions. In the second quarter -- we had a very strong first quarter and less in the second quarter. Unfortunately that's history, but history can't be brought back. We don't expect to make it up in the remainder of the year.

Jim Harmon, Lehman Brothers.

Real quick, I don't want to take up too much time. If I go back over the last 12 to 15 months, you have issued equity, you've issued debt, now you're in the process of repurchasing debt. Even with lower guidance, even at the bottom range and then some, your credit metrics appear to be on track for improvement from this point forward. If you don't spend any more money on CapEx you've got more money to make further improvements on your balance sheet. Can you give us some color as to maybe what the rating agencies are looking at? Are they looking at an operational issue, an execution issue that maybe keeps their -- that's keeping their paw on the Company's tail?

The rating agencies have been probably most uncomfortable historically with the addition -- the capital expenditures that were in our forecast. They look out on a forward-looking basis. We had $200 million a year in our expectations for capital deployment. And not knowing where that would go, they make the assumption that it will be in more risky businesses. And so, with the reduction of the expectation for capital deployment going forward, as well as with our strong cash position and expectations, I would expect that it wouldn't hurt our position with the rating agencies at all. But they haven't -- we haven't -- this is a new revision that they haven't seen. We did come out -- they did come out -- Standard & Poor issued a comment after we had provided our initial guidance for the second quarter a few weeks ago, and said it didn't impact our ratings. We believe we have very strong credit metrics and improving; they want to see a demonstration of that improvement before I would anticipate them changing. But the capital deployment expectation would -- from a ratings perspective would be beneficial.

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Well, we thank everyone for their interest in Black Hills, and we appreciate you taking the time to be on our call. Thank you.

Ladies and gentlemen, this conference will be available for replay after 11:00 AM today through midnight August 17, 2004. You may access the replay service by dialing 1-800-475-6701 and entering the access code 739979. (OPERATOR INSTRUCTIONS). This concludes our conference for today.