Black Hills Corp (BKH) 2003 Q2 法說會逐字稿

Ladies and gentlemen, thank you for standing by, and welcome to the Black Hills quarterly earnings conference call. At this time, I would like to turn the conference over to the Director of Investor Relations Mr. Dale Jahr.

Thank you and welcome to our conference call held in conjunction with the release of second quarter 2003 earnings. I will 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 release and other public disclosures.

Our discussion of recent results will be led by Mr. Mark Thies, our EVP and CFO. Mark has a few opening remarks before we open the call to your questions.

Thank you, Dale, and good morning everybody and welcome to our second quarter results call. We had a very good second quarter. A lot of things occurred in the second quarter. We made a lot of progress on a number of fronts. Our earnings were 54 cents a share compared to 51 cents a share last year, and on a continuing operations basis, we are 54 cents for both quarters, which is consistent with what we have said for the market in that earnings will approximate 2002 results due to that dilutive effects of a common equity offering we did in the first quarter.

That includes a few things that were unusual in nature. One, a 10 cent per share charge related to the settlement of the investigation with the CFTC, which we settled in July and recorded an accrual for that in the second quarter. In addition, we had 6 cents positive earnings due from certain energy funds, and that was an unusual item for a net of 4 cents, which then in total got us to a difference between the 54 cents and the two unusual items would get us to 58 cents a share. That is compared to 54 cents last year, which did include an unusual benefit of 7 cents.

Integrated Energy, our non-regulated energy business unit, had very strong earnings, up 38 percent in the year and due to a number of fronts. We brought on two significant powerplants in the first quarter, and we are seeing the effects of that in the second quarter earnings with the Las Vegas project as well as the Wygen plant which were brought in right at the first of the year for Las Vegas and in March or in February for the Wygen plant. That drove the earnings of the non-regulated energy unit. In addition, we closed the Mallon acquisition on the oil and gas side in March of this year and saw the benefits of that in the second quarter with improved results from our oil and gas unit.

In addition, in the second quarter, we have taken several significant steps as everyone is aware with respect to our liquidity capitalization and our balance sheet. In April, we issued 4.6 million shares of common equity to net $118 million, and we also had a $250,000 ten-year note offering in May which significantly improved our liquidity and which we have no borrowings outstanding under our revolving credit facilities. Our total debt to capitalization has also improved significantly from last year to 56 percent from approximately 64 percent at March 31st. So we continue to strengthen our balance sheet and improve liquidity as we have $80 million of cash on the balance sheet with approximately 39 million subject to certain restrictions to the parent company but still available for operations at those units.

We are in the process of renewing our $200 million credit facility or $195 million credit facility which we expect to complete in August of this year. Earnings at our electric utility were down in the second quarter, and that was primarily due to three things -- the interest cost from the $75 million bond offering issued last year in August, additional pension costs which we disclosed previously in our 10-K and our 10-Q and that is primarily related to the utility, and lower margins at the utility.

We had strong sales still in total but lower margins due to higher gas costs in the utility. The second quarter is typically the lowest quarter for the utility -- it is a shoulder quarter -- and we expect that to improve with the third and fourth quarters as we get into our summer peeking utility season.

Our communications business improved significantly primarily due to the issuance of our first directory published in the service territory. It is a natural extension of our communications business as we continue to become the dominant provider in the market. The publishing of a directory was a natural extension to take advantage of our customer base, and we published that providing revenues of $2.4 million, and we continue to incrementally increase our customer base. The rate of growth as we have said in the past will slow, but we do expect to continue to add customers, and I think that shows up in our results this quarter.

With respect to earnings guidance, as I mentioned earlier, we have our 2003 guidance. The only specific guidance we give is we expect results to approximate last year's results, and we did have, again, the equity offering that we did in April, which was 4.6 million shares of stock which was effective for a full year over 15 percent dilution. But we will cover that dilution and be flat on earnings this year. We did make a slight change to guidance going forward with respect to we had previously stated ate to 10 percent, and we believe now that given the current market conditions and the availability of capital projects that we revised that guidance to 8 percent on a long-term basis.

With respect to capital projects, we have indicated that for this year we expect to revise down. We don't have any significant projects we expect to close this year, so we are moving down our capital expenditures to the $110 million range from the 10-K, which is about $270 million approximately. We continue to actively look at projects primarily in the generation non-regulated energy business. The generation, we have historically done contracted generation oil and gas opportunities and midstream assets, and we continue to be very active in looking for opportunities with our expectation of closing one the remainder of the year. At this point, we have removed that from our capital forecast.

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

Michael Worms, Harris, Nesbitt, Gerard.

Good morning. Just a couple of questions for you. On the energy marketing business, you reported a $3.9 million loss. If you take out the settlements, it is still a -.9, and can you talk us through that, what happened -- talk about the unrealized mark-to-market losses?

That is not an unrealized loss. That is a change. The loss -- we had $2.4 million last year in the second quarter in earnings. That is a change, so we had a approximately - $1.5 million including the $3 million settlement. So we were actually profitable in the second quarter from operations in our marketing. They were lower margins, and there were some nominal downward impact due to unrealized mark-to-market on certain contracts, but overall we were still profitable in that business segment, except for the recording of the $3 million settlement with the CFTC.

On the oil and gas business, you indicated that part of the increase reflects Mallon. We were under the impression that Mallon's production would not really start to kick in because you were not going to start the development process until later in the year?

No. We expected with the Mallon acquisition, if you recall, we did expect to increase our production because they did have proved producing properties, and we expect to increase our production by approximately 50 percent. That is what we have said in the past about Mallon, the existing production, and then we expect to continue to increase that as we fully develop that property.

So we did expect with our prior releases that we would have an increase in production because they did have through proved (inaudible) properties that were producing when we acquired them, and I believe -- I would have to go back and look -- but I am fairly confident that we did indicate we did expect to increase production by approximately 50 percent, and that is really what we have done with the 53 percent increase. It is in line with what we expected.

If you can comment a little bit on what is going on with the coal mining business? You have higher costs. Are they onetime in effect, and will they continue to come up over time?

Certainly. There are several small pieces that aggregate to the total, certain of them are accruals for taxes and for expenses and obligations we would have. Others are slight increases in operating costs. The increase in production when you are looking at the significant increase in production brought on primarily by the sales to the Wygen plant and the long-term contract itself that we announced last year are incrementally profitable, but they are lower margins. There are not at the historical coal mining from the long-term contracts that we have that on-site generation. They are more akin to market type pricing. They are profitable sales, but not as high a margins.

One last question. On the utility side, you state that you have had higher purchased power and natural gas prices. Can you explain that a little bit? I thought you had more than enough excess capacity for your own needs, though I am not quite --

Well, we do. We do have substantial capacity. If we are able to purchase power because of our position in the market where we are between the Eastern and Western grids, it we are able to purchase it cheaper than we are able to deliver it, we will do that. And in the high gas cost markets, there are opportunities where we can purchase power maybe cheaper than some of our gas units can generate it. So we will do that. Or we have certain wholesale sales that are linked to a purchase that we would make in an offsetting sale that we would incrementally provide profit to us.

Paul DeBase (ph), ValueLine.

I have a couple of questions. First, do you have a pretax and after-tax dollar amount of the unrealized gains from the investments in the energy fund?

Do you mean the total impact was 6 cents on the energy bonds, the unusual component there. Which 6 cents a share at approximately 30 million shares is 1 million 8 after-tax increase which is in our release.

Do you have a pretax number on that?

You can assume a tax rate with the federal and some of it -- 35 to 40 percent may be get a pretax number.

Is there any change to your CapEx forecast for the years beyond 2003?

No. We would expect to continue to grow our business and continue to deploy capital consistent with what we have said in the 10-K.

Thank you.

Michael Malarky, Markson (ph).

I have two questions. The 8 percent growth, is that topline growth or is that EPS growth?

EPS growth. We focus on earnings on net income.

Okay. Your comment that you do not expect to close any acquisitions in the energy area for the rest of the year. Is that because prices are too high? Is that because the regulatory hassle is too intense?

We continue to look at -- what we do as we look at the CapEx is we try to provide guidance on what we reasonably think we can do in the year, and at this point, we are working on a number of opportunities and we look at a number of different projects. But to have an impact this year and get it closed, we have said that we would not expect to spend those funds this year.

We continue to expect to look at opportunities, and we are evaluating a number of those opportunities that we would expect when we have an ability to announce something we would do that. But at this point, we don't have anything we would close or expect to close, and we thought we should provide that in this report.

Is there any --

But there are not regulatory hurdles to it, or if there are commodity prices are high, but we continue to look for opportunities in our businesses.

How unique is your ability to access both the Eastern and Western groups? Are you one of a half-dozen players that can do that, or are you one of the --

There is less than three or four I believe -- I don't know the exact number -- but we are somewhat unique in that ability. Because we do have the access to the Western markets and the Eastern markets, that has been a very good ability to arbitrage to keep our costs to our customers and our utility reasonable as well as provide benefits to the shareholders.

Is there any way to massively capitalize on that as opposed to just giving a lower-cost to the utility? (multiple speakers). Is there any way to play on a larger national scale rather than basically being -- rather than playing in a regional area? Is there any way to leverage that into playing on a larger national stage?

No. Because it is limited and constrained by the access to transmission, the requirements of the markets that demand and supply characteristics of those two regions, so we're able to incrementally improve it. But on a national basis, no, I would not say we can expand that. We are improving that ability with the tie, an AC/DC tie, which links those two grids which is expected to go into service late in the third quarter, early fourth quarter, which is the 200 megawatt tie of which we own 35 percent. We would have an additional 70 megawatts of capacity to increase that, but otherwise it is constrained by the size.

When I mention it is not really lower the cost to the utility, it is we are under a rate freeze, and we are able to efficiently maintain that so we can continue to have our rate freeze in place. It provides stability and reliability to utility customers. All the benefits do drop to the shareholder.

Thanks.

Norman Greenburg, Goldman Greenburg.

You guys are doing great. A couple of questions. One, communications, when do you expect that to go to the black?

2004, next year.

What kind of return are you looking for when that does go to black?

It did cost more when we initially put it in. We expect to get it to profitability, and it becomes more of a consistent earnings stream. We have not really targeted -- you can play around with capital structure -- we don't do that. We expect to get a fair return for the shareholder and get that as sufficient as possible and be profitable as opposed to having losses which we have generated. But there is not a particularly targeted return for that.

Now you have improved the capitalization ratios considerably. The nature of your business is a little bit different than most utilities. I was wondering what kind of objectives are you looking for in capitalization ratios given the slightly different nature of your business from a lot of others?

Well, in the different nature, I will assume that contracted generation has historically had an ability to have a higher amount of debt associated with that on the strength of the contracted parties. You have got 90 percent of our generation under long-term contracts in primarily tooling arrangements, which takes out the fuel risks, so we really have operating risks, and we feel we are very very strong and good operators.

But in the market the things that have changed is the rating agencies have not provided benefit for nonrecourse financing. We have significant $360 million of nonrecourse financings, project financings, on our books that they have put back into our calculations, and they have both made moves to move us to still investment-grade ratings but one step away.

We are working to make sure we have a solid investment-grade company, and we are committed to that. We believe that the capitalization in the mid 50 percent for debt is a good range for us given our lower risk strategy of contracted generation and our coal mine and strong utility in improving communications.

I have a lot of respect for the rating agencies. At the same time, I agree with you on looking at your business as your business and evaluating your risk. You are looking at somewhere in the area of 50 percent debt of being objective (inaudible).

No. Mid-50s. 50 to 55 percent would be on the conservative side. Again, we have a significant portion of our assets with nonrecourse project debt and long-term contracts. So we believe that our business risk profile is reasonable, and we just need to continue to execute. We have just brought on, in a little bit of deference to the rating agencies -- we don't run our business by the rating agencies -- but we have just brought on two significant plans, which at the time they reviewed the credit was under construction. They are brought online, and we are able to demonstrate in this quarter and coming quarters the value and the cash flows from those businesses. We believe that will be beneficial.

The common equity ratio you are looking at is what? Is it the whole balance or what?

In the mid-50s for debt and then the mid-40s for equity.

Okay. That is common equity?

Common equity, yes. We have a very very small percentage of preferred, less than a percent like .3 percent or something.

How about your customers? Are you seeing any trouble spots with the customers, or are they in pretty good shape now?

No. We have very good customer relations with all of our customers. We do have -- in the utility, we did have one industrial customer have a fire (inaudible) which we have done, but we have continued to go through there. The business climate and economic climate in our area is stable.

With respect to wholesale customers, we do have a contract on the Las Vegas plant with Allegheny Energy Supply, and they are performing under that contract. They have announced that they expect to exit the Western business, and they have announced a sale of one of their contracts to a unit of Goldman and settlement of one of their towing arrangements with Williams. We continue to have discussions with them, and if it makes sense to Black Hills to have some contract settlement with them, we would look at it if it is economic to us. But there is nothing. We continue to have discussions.

That plant is a great plant, located in Las Vegas. It is one of the highest growing areas in the country in the West in our target area, and we believe we will be able able in the event that we did have a contract settlement with Allegheny we would be able to contract that plant on a long-term basis.

That is what I was really driving at if whether (inaudible) you backed off from them for one reason or another, whether the (inaudible) could still be sold profitability?

That is a very efficient plant. It is a 7800 (inaudible) rate, and again it is located inside the grid in Nevada, which is a significant user of power. In fact, they have several requests for proposals for power because they have a high need for power in the Las Vegas area. We continue -- we do have a contract so we continue to work with our contracted party as well as have discussions with others about the output of that plant.

Okay. That is fine. Just one final question. Could you comment a little bit on dividend policy?

We have consistently increased our dividend over the past 30 plus years. We have grown in the 3 to 4 percent range. We would expect that to continue and still have our earnings growth, and our long-term guidance is ate percent. So we would somewhat reduce our payout ratio over time, but continue to increase our dividend as we have in the past.

Thank you very much. I think you are doing a great job. Just keep it up.

James Bellessa, D.A. Davidson.

Good morning. When you file your 10-Q, on what consolidated income statement line item will the $3 million CFTC penalty payment be included?

In the operating expense administrative expenses.

Operating (multiple speakers) administrative and general expenses, okay. Your utility in the first half, according to my calculation, has earned 39 cents versus 54 cents? Do you expect that business will be down for you on an EPS basis this year?

Well, again consistent -- I don't know -- we are coming into two strong quarters for the utility, but they are historically strong year-over-year. But we did have the additional debt that we did in August of last year, the $75 million first mortgage bonds that increased interest expense at the utility as well as the increased pension expense that we have. Those are two things that occurred this year or have a full year effect this year versus the partial year last year on the interest and then the full year on the pension, so it would be plausible because we could be down slightly year-over-year. Yes.

And then the rest of it is dependent on weather and operations and our ability to access office system sales with high gas prices. Should they continue that we still are able to selloff system sales as you have seen in this release, we have good sales but the margins are less.

Have you been benefiting from the peak that occurred in the last month?

That is really a third quarter event because it is primarily more July, so we will have to see how the whole third quarter goes. We are just into it, but it has been warm at least through July. I don't know the statistics of how much more than normal right away.

So your own needs for cooling degrees for air-conditioning would be up? How about off system sales?

Typically in this quarter off system sales because we have a strong utility load and utility need, we serve our customers. So the off systems sales may be down slightly should that occur. But with the residential sales and the sales to our existing customers, that is a decent margin for us as well as opposed to the margins on wholesale sales. So it may be down if we have a very hot third quarter, but we would expect strong results from residential sales and commercial and industrial if that is the case.

Your pending sale of your Hydro business in New York, it said in the press release to contribute on an annualized basis 7 cents per share. Is that seasonal? Are there certain parts of the year you are getting that 7 cents and other parts not?

Yes, generally in the spring depending on when the snow melts, it could be late first quarter, early second quarter that has historically had stronger results. Then in the summer months, when you have less waterflow, they are somewhat based on waterflow. So seasonally, yes, that does occur. But what we have provided in the 7 cents is an expectation of what the annualized impact was not regarding seasonality. Just an annual effect based on 2002's results.

Have you made some assumption that this business would be gone by the third quarter, and therefore that is factored into the 233 estimate, $2.33 estimate, that I am discerning that you're saying?

For this year, yes. Now that is correct. We expect to close this in the late third quarter, in the third quarter of this year. That is we would not change our guidance with respect to that.

So it has already been factored in?

Yes.

For next year, do you think we will be able to recoup that lost 7 cents somewhere somehow?

On a long-term basis, our long-term growth rate expectation is ate percent. That could vary, but we have brought on the production. We expect to continue to improve our communications, our utility. We expect to have normal internal growth as well as the oil and gas. As we continue to develop the Mallon site, we would expect to have improvements in results there.

And you have indicated when you to took on the Mallon that you would probably not have accretive earnings in the first-year, that they would be fairly neutral impact on you. Have you found that is the case so far?

I think we have gotten some benefit due to strong prices, strong commodity prices. We have hedged consistent with our past performance certain of our production, but the prices relative to when we announced that transaction have been strong this year. So incrementally as you see our oil and gas business is up year-over-year 1 million 3 for the quarter.

Now that you have added under your belt for more than a quarter, have you seen any problems? Is the drilling progression and opening up of the field on track, on schedule?

We are moving forward with our drilling. There are always operational things as you go through a big program like this, but we are working through all of them, and I think we believe it will be on track. (multiple speakers)

Edmund Griffin, Blackrock.

Good morning. A follow-up question on this EMP (ph) business. Do you have any production target for '04 and longer-term?

We expect as we continue to drill out that property to update. We don't particularly say what our targeted growth is. It has been 15 to 20 percent historically on an average basis improvement in production, and we would expect to be consistent with that. As we have this major undertaking with respect to the Mallon properties, we would expect to have further announcements as developments occur. Since we are just beginning to drill out and develop that property to the extent we have updates, we will include those in future announcements.

Okay. And so what do you typically hedge for or sell for?

We have typically hedged 25 to 50 percent of our production.

And that is when you are out?

Generally one to two years out, generally one year out depending on the timing of when you do it.

Okay. With regards to the lower margins with the coal sales to the Wygen plant, what is that really a result of?

When we constructed the plant -- it is an on-site plant, and the margins from the coal, that is really margins on coal sales. We get multiple revenue streams. That is probably the best integrated effort we have, and we get margins on the coal sales, but we also get margins on the power sales and the generation.

So we have additional margin, and that is why the generation segment of our integrated energy business is up as well because so the power sales. Those sales are under 10 year contracts with Cheyenne Light and Power and a municipal in Nebraska. So the coal sales is incremental to the coal mine coal on the coal, and then we get the additional margins in the power sales and the capacity.

Okay. Thank you.

Michael Malarky, Markson.

Just two quick questions. Four years from now, what do you think the communications business will look like? Will you have done any additional buildout, will you have done any acquisitions, or will it basically be a stable asset throwing off cash without any material need for CapEx?

We believe at this point the latter. We expect to get that to profitability and run that primarily based off of our electric utility service territory and get efficiencies between those two companies. So we would expect it to provide exactly what you said, provide stable cash, have some nominal CapEx, but we don't expect at this point to be going to other areas to deploy capital and grow that business. We expect it to be a local business.

Then the Las Vegas plant. So Allegheny Energy is essentially exiting the Western area, and they are selling their obligation to Goldman, so you're going to get the opportunity to negotiate with Goldman? Is that the bottom line?

No. They have sold the California or L.A. DWR or Los Angeles Department of Water Resources, they had a contract with them. They settled that contract. They had some dispute with the DWR and FERC, and they settled those, and they sold that contract to J. Air & Company (ph), a unit of Goldman Sachs. That was not -- our contract is for our plant in Las Vegas for 224 megawatts. They are not tied in any way to each other.

So they are expecting they put out their releases that they expect to close by the end of the year and receive the proceeds of that sale. They have then also announced that they have settled with Williams. They had a contract with Williams on 1000 megawatts, and they did a contract buy-out of that that is still pending. We continue to have discussions with them, but our contract is not tied to the California contract.

What is the difference between the market rates today and what they are obligated to pay right now? In other words, --

That is a discussion for which we will try to settle -- if we were able to reach agreements and have a contract settlement, that will be the discussion, so I am not really at liberty to discuss the differences. They will have their views and we will have our views, and we have talked with people, a number of different parties with respect to that.

Okay. But basically it is your belief -- I am asking this -- if you do a contract, if they pay to get out of their obligation, you continue to run the plant, and do you anticipate any kind of even a nominal pickup in the numbers? How would them exiting probably affect your numbers?

We would like to keep it obviously as nominal as possible with the amount -- if there was settlement payment that they would make, then that would provide cash to Black Hills, and then our ability to contract that plant with another party and replace the revenue stream or nearly replaced the earnings would be our expectation. But to any specifics, we are still in discussions with them, and I don't really have any specifics because they continue to operate under their existing contract.

But the bottom line is as shareholders we may be facing something that is analogous to what happened in the communications business where we had one set of expectations, then reality set in and we had to lower our expectations modestly. Is that a fair characterization?

I don't know exactly your analogy to communications. I think as we know information, we have tried to continue to provide what our expectations are based on the market at that time. We continue to have that plant operate and get paid, and if we enter into negotiations, we obviously have the shareholder in mind. With any type of agreement that could be reached, we would evaluate that and disclose that at that time.

Thank you very much.

Barbara Coletti (ph), Harris Nesbitt.

Good morning. I just had a question. If you have made a decision yet on the Wygen lease, if it's going to be brought on the balance sheet?

Yes. Unless we would have made any changes and we did not, then on July 1 that was required, so that would be brought on the balance sheet.

And the same kind of impact per share you had talked about --(multiple speakers)

As was disclosed previously.

Patrick Keene, RBC.

Getting back to the business with the Allegheny, if in fact you did have to go into the market with some of that capacity, what is your sense of the need for peaking capacity in that region?

It is not necessarily just a peaking, it is a combined cycle unit. So we would have an ability to run that as a (inaudible) unit, and it is a very efficient unit. 7800 (inaudible) rate and startup is very quick for that unit. So the peaking, that can really depend on the parties that are serving the load for that aspect to look through their whole supply side and their demand-side and what types of units they want. But we believe that area significant needs power by the fact that Nevada Power is out for significant piece for additional capacity.

We look at that as an opportunity that plant can also get to the Mead substation, which allows it to get to the Southwest and to California, so we have a number of options with respect to that plant. But again we are still under contract with Allegheny, and they are current with all their obligations.

We do have a $15 million of credit which supports up to six months of capacity payments for us in the event they were not current. We believe that would give us sufficient time to negotiate a different contract if that was warranted.

Can you can tell me if, in fact you did enter some peak arrangements, are they done on a take or pay basis?

Historically our contracts have been we do have certain peaking arrangements in Colorado on contracts, and they are really capacity payment driven in which we get a capacity payment for the availability of that plant and have done them on towing arrangements. So if you are not familiar with towing arrangements, we don't take the fuel risks, but the buyer of the power also is required to bring the fuel. So we just have to be available and operate our plant. If there were contracts similar to that, we would look at those from a prospective of not having to having fuel risk and getting a consistent revenue stream through a our capacity payment.

James Bellessa.

Conceptually you have talked about maybe having that Allegheny towing agreement moved over to somebody else and/or the load would be serving Nevada Power possibly? This is just conceptually.

Again they are the native utility in which that plant sits. They would be a logical candidate. We can also move that power to the Mead substation which can get to Arizona and California, so I am not limited it to any credit to any particular party by any means. We have the ability to move that power to a number of different markets, and conceptually if Allegheny, we were to reach a settlement with them, we would look at a number of parties and do what we felt was best for the Company and the shareholder in contracting that plant and have to negotiate with several parties.

If we saw a headline saying that you struck a deal in buying the power for Nevada Power, would that be viewed as jumping from the frying pan into the fire?

No. I don't think that would be the case in that to some extent, the commission in Nevada has approved their RFP process and would approve contracts. Nevada Power is subinvestment grade, and they have had some difficulty with prior recovery of costs. We would have some comfort that it is a negative load serving utility. Allegheny was the only non-native load serving entity that we had on our contracted parties.

So we would view that as incrementally favorable from a prospective of serving utility customers as well as having commission approval should that occur in any of the parties that we would potentially contract with. We would view that as incrementally positive and a better credit than a marketing entity that does not have the native load customers.

At this time, I am showing no further questions.

Well, thank you very much everybody for your interest in Black Hills. We appreciate it.

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