Black Hills Corp (BKH) 2011 Q1 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Black Hills Corporation 2011 first-quarter earnings conference call. My name is Jenata, and I will be your coordinator for today. At this time, all participants are in a listen-only mode. Following the prepared remarks, there will be a question-and-answer session. (Operator Instructions) In order to get as many questions answered as possible, we ask that the participants reenter the queue after asking 1 initial question and 1 follow-up question. (Operator Instructions) As a reminder, this conference is being recorded for replay purposes.

I would now like to turn the presentation over to Mr. Jerome Nichols, Director of Investor Relations of Black Hills Corporation. Please proceed, sir.

Jenata, thank you very much. Good morning, everyone, and welcome to the Black Hills Corporation 2011 first-quarter earnings call. With me today are David Emery, Chairman, President, and Chief Executive Officer, and Tony Cleberg, Executive Vice President and Chief Financial Officer.

Before I turn the call over, I need to remind you that during the course of this call, some of the comments we make may contain forward-looking statements as defined by the Securities and Exchange Commission, and there are a number of uncertainties inherent in such comments. Although we believe that our expectations and beliefs are based on reasonable assumptions, actual results may differ materially. We direct you to our earnings release, slide 2 of the investor presentation on our website, and our most recent Form 10-K and Forms 10-Q, filed with the Securities and Exchange Commission, for a list of some of the factors that could cause future results to differ materially from our expectations.

I will now turn the call over to David Emery.

Thank you, Jerome. Good morning, everyone. Consistent with prior quarters, I will give the operating update for the quarter, and turn it over to Tony for the financial update. And then, I will again give the forward-looking update on progress towards several of our key growth initiatives.

Moving to slide 5, for those of you who are following along on the webcast presentation here, the first-quarter summary. We posted net income as adjusted of $0.59 per share versus $0.82 per share in the first quarter of 2010. We were very pleased with the performance of our Utility businesses during the quarter, which showed increased income year over year despite a 4% decrease in gas volumes sold, which was primarily the result of milder winter weather. We had a reasonably cold winter in our territories, but not near as cold as the very severe winter we had last year.

On the non-regulated energy front, however, we're pretty disappointed with our first-quarter results. Compared to the first period last year, our income was down in 3 of our 4 non-regulated business segments -- Energy Marketing, Oil and Gas, and Coal Mining. Only Power Generation showed a slight year-over-year improvement.

Moving on to slide 6, our Utilities, we had several key accomplishments in our Utility businesses during the first quarter. We continued to make excellent progress on our new 180-megawatt power plant being constructed for our Colorado Electric utility. And on April 28, we filed a $40.2 million rate case with the Colorado PUC related to that plant.

During the quarter, we also announced $167 million in new utility growth capital investment opportunities. One gas turbine in Colorado, and wind projects in both Colorado and South Dakota. We also began preparing integrated resource plans for all 3 of our electric utilities, and we've talked about this before. At Black Hills Power, we have some plants that we may have to retire based on pending EPA regulations, and so we are evaluating the replacement or upgrade of those through this next resource plan. At Cheyenne Light, evaluating current and future generation needs, and really anticipate needing some additional peaking resources there.

And then finally, at Colorado Electric, the resource plan we intend to file there will address primarily how we intend to meet the renewables mandate in Colorado over the next several years. We expect to file all 3 of those resource plans before the end of the year, and certainly to the extent they demonstrate the need for additional generation, we will file for certificates of public convenience and necessity on those projects as appropriate.

Moving on to the non-regulated energy summary on the next slide, again, we made excellent progress on our Black Hills Colorado IPP Power Plant, the 200-megawatt facility which is co-located with our utility plant near Pueblo, Colorado, about 55% complete and still on schedule and on budget there. We are continuing to evaluate our oil and gas business, and that has been ongoing for about a year now. One of the key decisions in that whole process is evaluating the potential of the shale gas opportunity beneath our existing acreage holdings in the San Juan and Piceance basins in New Mexico and Colorado.

We've announced last year and early this year that we intended to drill 3 horizontal test wells in those 2 basins. We have commenced drilling on the first well, which is located in the San Juan basin. We expect to drill all 3 of those wells in the next couple of quarters, and have results towards year end. We also increased slightly our projected capital expenditures for our E&P unit, mostly driven by certainly the Mancos Shale testing, but then additional drilling for the Bakken crude oil formation in North Dakota.

Despite our relatively low levels of capital spending in 2010 and even year-to-date 2011 in our E&P unit, our overall volumes were up about 3.5% compared to the first quarter of 2010. And crude oil, mostly due to our activity in the Williston basin in North Dakota in the Bakken play, was up almost 23% compared to the same period last year. It has certainly been a while since we've shown quarter-over-quarter production growth, so we're pretty pleased with that, even with our low levels of capital investment.

I will elaborate a little bit more on Coal Mining results here on the next slide, so I won't spend any time on that. And then, on the Energy Marketing Company, continue to struggle there, primarily driven by market conditions. We are optimistic that the diversification of our commodities being marketed at Enserco, our marketing Company, will help us to improve earnings going forward, but as of yet they are not showing up in the income statement.

Moving on to slide number 8, in light of the performance of our Coal Mining segment this quarter, we've included some additional information on the mine. And it's contained on that slide. The financial performance of our coal mine has been negatively impacted really by 3 major factors -- the location of our current mining activity or our active pit operation in relation to the boundaries of our mining permit; the structure of our existing coal sales contracts; and several significant cost increases. While we were certainly aware of the first 2 issues, where we are mining and the structure of our contracts, the extent of the significant cost increases was not fully known at the time our 2011 earnings guidance was issued last November.

Related to the first issue, the location of our current mining activity, our active coal mining is taking place at the far northern boundary of our mining permit, in an area far from our plant complex, which is, of course, our primary coal customer. As a result, we have relatively long conveyer distances for coal, and long over-burden haul distances compared to prior years. We are also in an area of the mine that has a very high over-burden ratio. For example, in 2007 our over-burden stripping ratio was 1 to 1, that is 1 cubic yard of over-burden per ton of coal. Now that ratio is 2.5. So not only do we have more over-burden to haul, we have to haul it farther.

In addition, as our mining activity has progressed away from the power plant complex over the last several years, we've extended an overland coal conveyer to transport the coal back to the plant. This conveyer has now reached its maximum length, which is nearly 7,000 feet. A portion of the cost of that conveyer infrastructure was capitalized in prior periods, and is not any more now that it's reached its maximum length.

Regarding our coal sales contracts, we have 2 primary types of long-term contracts. The first type, which consists of about 35% of the tons sold, are priced based on actual cost, plus a return on mining capital. These contracts are with our affiliate utility plants, and our partners in those plants. Another 55% to 60% of our coal is sold under 2 contracts that have escalators which increase the price of coal based on published indices, such as Consumer Price Index and other Bureau of Labor standards indices such as fuel, labor, mining equipment, and others.

The increase in the price of coal under these contracts has not grown as quickly as our mining costs, particularly in the last year or so, reducing the margin from those sales. One of those contracts is a train load-out sale that comprises almost 30% of our tons. It is our lowest-priced contract, and expires at the end of 2011. It is not currently providing a positive sales margin. The other is a long-term contract that runs through 2022, and comprises about 25% of our tons sold. That contract has a price re-opener in 2014, which, based on current market conditions, should result in a significant price increase in 2014.

Finally, related to the unanticipated cost increases I referenced earlier, there are several costs which are negatively impacting mining results, and may continue to do so for some time. First is fuel, most notably diesel. Those costs have increased considerably due to the price of crude oil. Fuel use and the cost of fuel, that is compounded by the fact that we were hauling even larger quantities of over-burden farther distances. The greater haul distances have also resulted in increased equipment maintenance.

Our drilling and blasting costs have increased. We've had to increase the density of our drill holes, plus explosive costs have also risen. We now have to man our train load-out facility 24 hours a day in order to avoid certain railroad charges. That wasn't the case really until this year. The train load-out is currently utilized to serve only the 1 coal contract that I talked about previously, and that contract expires at year end.

Finally, in the unanticipated cost category, we have a clay parting, or a clay layer, that lies within the middle of our coal seam. And historically, we've had layers of clay within our coal seam similar to this one, but they are typically a few inches thick. And as such, we've simply mined the clay along with the coal, and it really doesn't cause any major impacts other than it increases the ash content of your coal slightly. In the area where we are currently mining, and will be for the next year or 2, this clay layer has increased in thickness to nearly 5 feet. And at that thickness, we must separately remove the clay layer, which adds considerably to our expenses.

So in summary on the coal mine, while we anticipate an operating income loss for that business segment this year, we intend to aggressively pursue opportunities to both reduce mining expenses and increase revenues in order to mitigate those impacts in 2011 and beyond.

Slide 9, the corporate summary, a couple of highlights here. We are very proud of our dividend track record. It is something we continue to focus on, and will. Very important to our shareholders, and we know that. We do expect to get significant benefits from bonus depreciation over the next few years from the capital that we placed in service in 2010 and '11. And finally, we expect to settle our equity-forward transaction in the fourth quarter of this year.

Slide 10 is our strategic initiatives timeline. You've seen this before. It has been updated for recent project announcements and progress on current projects.

I will now turn it over to Tony Cleberg for the financial update. Tony?

Thank you, Dave. Good morning. As Dave stated, our overall first-quarter financial performance was disappointing. And while our Utilities operating income continued to improve, our non-regulated segments under-performed significantly. On later slides, I will address the drivers for the quarter.

Moving to slide 11, this is our EPS analysis, consistent with past quarters. We adjust our income from continuing operations to display a non-GAAP earnings measure. This is done to better communicate the relevant performance. Special gain and loss items recorded during each quarter are excluded to compute a non-GAAP measure. This slide displays the last 5 quarters.

The only special item included in the first quarter of 2011 was a subtraction of $0.09 for a non-cash unrealized gain on our $250 million worth of interest rate swaps. So with that adjustment, the quarter's income from continuing operations was $0.59 per share, which compares to the $0.82. Looking at last year's first quarter, the reconciliation included a $0.05 addition for an unrealized loss on the same interest rate swaps, and a $0.04 subtraction for a gain on sale of assets. The $0.23 decline in the 2011 first quarter compared to 2010 was driven by our non-regulated segments, which I will discuss later.

Slide 13 displays our income statement for the first quarter of 2010 and '11. And as you will note, the EPS declined by $0.13. This resulted from a combination of the decline in operating income of $14 million, an increase in interest expense of $2.2 million, offset by the pre-tax mark-to-market improvement of $8.5 million for our $250 million of interest rate swaps. The lower operating income I will discuss in more detail, but in summary it reflects stronger performance in the Utility segments and weaker performance in non-regulated. The increased interest expense reflects the higher debt levels.

Continuing down the income statement, the first-quarter effective tax rate was 32.4% for 2011, compared to a 34.4% tax rate in 2010. The improved tax rate reflects primarily the benefit of the R&D tax credit. Moving to the bottom line, the resulting first-quarter GAAP EPS was $0.68 per share compared to $0.81 per share in 2010.

Looking at operating income, slide 14 displays a segment roll-up of revenue and operating income for the first quarter of '10 and '11. The Electric Utility segment year-over-year revenue was flat, with a corresponding $4.1 million improvement in operating income, reflecting the benefits of last year's rate case settlements. During the quarter, the megawatts to retail customers were flat to 2010, so the higher rates drove the improvement in operating income. For off-system power sales, the megawatts declined by 16%, while the prices declined even more from 2010. The low energy prices resulted from an over-abundance of high hydro power in the northwest and the impact of low natural gas prices.

Moving to the Gas Utilities segments, decatherms sold during the quarter for residential and commercial declined by 4% from 2010. Our gas territories were colder than normal in both 2010 and 2011. The operating income, excluding the gain on sale of the Elk Horn property, improved by 6.5% over 2010, as a result of rate case settlements. So our Utilities continue to perform well and continue to show solid improvement.

Moving to Oil and Gas, our operating income declined by $3.9 million from 2010. The decline primarily resulted from lower prices. For oil, the price received declined by 10%, while volumes increased by 23%. For gas, the price received declined by 21%, while the volume declined by 1%. As you may recall, our hedging program hedges about 50% of the production 2 years out, and in the first quarter of 2010 we were still enjoying the higher prices of the first half of 2008.

Our depletion expense continues to increase year over year, as we add higher-cost oil wells to our depletion cost pool. These projects have strong economics at the current oil prices, however, the drilling cost pool is depleted over our average gas and oil production. The result is an increasing depletion rate.

The next segment, Power Generation, produced $2.4 million in operating income, a decline of $1.3 million from 2010. The decline resulted primarily from a combination of low energy prices for our excess energy, and increased G&A expenses related to the Colorado IPP construction project.

Moving to the next segment, Coal Mining, the operating income declined by $4.5 million from 2010, as a result of higher mining costs. Dave mentioned a number of factors impacting our performance, so I will not repeat those here. For Energy Marketing, our next segment, operating income was $3.4 million loss for the quarter, and was lower by $7.6 million from 2010. Natural gas gross margins declined by $7.7 million from last year's first quarter, reflecting low transportation margins and lower storage margins. Margins on crude oil were lower this quarter compared to 2010, resulting in a decline of $2 million.

Coal marketing continued steady performance, contributing $2.7 million in margin. Even though Energy Marketing lost money in the first quarter, we remain optimistic that the marketing of our diversified set of commodities, we will have the opportunity to improve the results throughout the year.

Let me just stop here and talk about our guidance a little bit. With the performance we saw in the first quarter, we are reducing our EPS guidance for the year from the range of $1.90 to $2.15 to an adjusted range of $1.70 to $1.95. There is a slide later in the presentation refreshing our assumptions, but with the lower earnings in the first quarter and the continued challenges at the coal mine, and even with some improvements in our other segments, we lowered our range by $0.20. This range is based on net income as adjusted, so there is no impact for special items such as the mark-to-market on the interest rate hedges.

Moving to our capital structure, slide 15 shows our debt to equity. We feel our present capital structure supports our needs through 2011 into 2012. Our net debt-to-capitalization ratio is presently at 56%, but giving consideration to the equity forward, the pro forma calculation for net debt to equity is 51%. So we are in good shape from a debt-to-capitalization position. Our pro forma calculation assumes we delivered the shares under the equity forward at the end of the first quarter.

Again, our overall financial performance is not what we expected for the first quarter, particularly in our non-regulated segments. And although we have lowered our guidance based on what we know today, we will continue to look for every opportunity to improve our financial results for the year. So with those comments on the first-quarter financial performance, I will turn it back to Dave.

Thank you, Tony. Moving on to slide 17, and looking at forward business strategy here, our business assets and income are now comprised 70% to 80%, to even higher, utility. This will provide steady earnings and cash flow, and certainly will help us fund future dividends and our growth capital investment programs. On slide 18, we have a very clearly defined capital investment program that will help us drive future earnings growth. This slide, which you have seen before, has been updated for changes in projected capital spending announced during the quarter, including the $167 million in new utility investments that I referenced earlier.

On slide 19, our 2 Colorado generation projects are progressing according to plan. I mentioned that earlier. The utility project at the end of March was about 76% complete. The IPP portion of the project was about 55% complete. And, of course, those numbers are changing daily. We have revised our capital cost estimates for both projects now that we are nearing completion, and have most of our construction and procurement contracts are awarded. The utility project has been lowered from $250 million to $260 million, now down to approximately $227 million for our final estimate. So we will be significantly under-budget there. There is some additional transmission investment related to that project, but that's covered elsewhere in the financials.

On the IPP project, previously we had estimated that at $250 million to $260 million. Our forecast based on current information is kind of right at $260 million. So we will be right on budget for that project. Both are still on schedule to be completed and in service by January 1, 2012.

The next slide, slide 20, this is a little different look at some slides that we've shown you previously. Really trying to give you a feel for the cumulative impact of all of the current pending and proposed regulations, primarily that impact power generation facilities. We've discussed some of these regulations previously, particularly the EPA boiler rules and things, and how they may impact some of our facilities. Our opinion hasn't really changed about that, and that we have a few facilities, Osage, Ben French, Neil Simpson I, and the W.N. Clark, that are going to be impacted in some way by those regulations. And most likely, will probably have to be retired rather than retrofit. We are still working through the cost estimates for retrofitting.

Many of the rest of our plants are in pretty good shape. But there is a chance that a couple of our older -- not older, but older new-vintage plants, which would be like 1995 and 2000, 2003 vintage plants, may need some retrofitting. We're still assessing the impact of those potential regulations. As the utility boiler rules are finalized by EPA this fall, we will have a much better sense for that.

Slide 21 is a revised look at our growth capital investment opportunities for the period 2012 to 2015. We have shown these to you before, but in a little different format. These growth opportunities are substantial, and certainly will drive strong future earnings growth. As you can see, in the announced category, we already have almost $321 million worth of projects that we've talked about. These are after the completion of the 2 large Colorado projects we're currently building. So these are 2012 and beyond projects.

There's also significant other projects currently under evaluation, dealing with the environmental upgrades and replacements, additional renewable projects, other needs such as peaking resources. I mentioned we may need peaking resources at Cheyenne Light, and certainly transmission. All of those are listed there in ranges that we think are reasonable for this next 4-year time period. The IPP, and Oil and Gas are going to be dependent on opportunities, and certainly Oil and Gas will be dependent on the finalization of our review on our strategy there as well.

Slide 22 is simply a summary of our Black Hills Energy Colorado electric rate request. I don't need to cover the details of that, you can see those for yourself. Slide 23 outlines the activity in our Oil and Gas segment. I covered that already, and that we are drilling 3 Mancos shale gas test wells in the San Juan and Piceance basins. We do have 73,000 net acres prospective for the Mancos formation in those 2 basins. The majority of that acreage is held by production from other zones. So it's not going to expire, we don't have any issues there.

The Williston basin, we're going to continue our program at least through the end of this year, maybe partly into next year with our current lease-hold position. We are trying to buy existing leases there, tough going, very expensive, so we don't expect a lot of expansion in that play as far as our lease position. There is some future upside opportunity in the event that well spacing might get reduced, for example from 1 well per 1,280 acres to 2 wells per 1,280 acres.

Moving on to slide 24, this is our score card, our strategy score card, that we've shown you before. This one is updated to include our 2011 initiatives, and clearly define all of those initiatives for you, and certainly to mark progress towards those. And as per the last couple of years, we will continue to update this as the year goes on.

Slide 25 mentions the $0.20 reduction in earnings guidance. Tony already spoke about that, so I won't talk about it additionally here, other than to say the revised assumptions upon which the guidance is based are listed in detail on the slide as well as in our press release.

On slide 26, while we are not happy with our quarterly financial performance overall, the quarter certainly had a lot of bright spots. We're very proud of our continued dividend track record. Our Utility performance was very good. Very good operations as well as the benefits of the cost recovery we got last year through several rate cases.

Our large capital growth projects are on track. The Colorado power plants and our electric transmission projects are going according to plan. As I mentioned earlier, during the first quarter we announced an additional $167 million in new utility growth projects. So we're very excited about the opportunity that those pose for future earnings growth.

And finally, while we lowered our 2011 earnings guidance range to $1.70 to $1.95 per share, we are very excited about the earnings growth potential in 2012 and beyond from all our current capital projects, as well as the long list of future growth capital that I just spoke about.

That concludes my comments. We would be happy to entertain any questions people may have.

(Operator Instructions) Your first question comes from the line of Daniel Eggers with Credit Suisse.

If we could explore what's going on in the Coal business in a little more detail, maybe. The unexpected cost bucket in the first quarter, that third list. How long does that stick around from your perspective? Are these costs going to be with us all year? And the year-on-year negative, the $0.07, is that something that is going to linger on? Or, is there something that's going to help reverse those tougher year-on-year comp as we play out the course ever the year?

A lot of the cost increases, certainly there is no immediate relief in sight there. Diesel fuel and some of those other large ones. There will be a point in the next year to 2 years where the location of our mining actually changes, and we start moving back towards our power plant complex, where those costs won't be as near as substantive any more. We will have already uncovered a portion of that coal, so we won't have that expense. The over-burden won't be quite as thick. Some of those things. Certainly, that is one of the primary factors and why we are saying we expect operating losses for this year, is that we don't expect all those to continue. They may not necessarily look quite as bad as they did in the first quarter, but we don't expect them to get a whole lot better for a while. Now that being said, we've got a lot of Management attention focused on both opportunities to increase revenue and means of reducing expenses in what we are doing for current operation there as well. We do have some potential relief in sight, in that one of the contracts expires at the end of this year. That contract is currently under water.

So, we should be assuming that the drag sticks with us, I guess is the answer for an extended period. Then on the re-contracting, Dave, of the 30% of the volumes, where do you see that being sold? Is that going to be re-upped to the same customer on more market-esque terms? Or, are you going to have to find a new buyer for that output?

I would say it's hard to say with certainty, Dan. More than likely, we would either renew the contract or sign a new contract with the existing counter-party at significantly better prices. Or, we would probably not sell that coal, which would require some reconfiguring at the coal mine and things. It's not a sale that we have to make by any means. And if it's not profitable, we won't continue it.

Okay. And then, if we turn the page to Enserco a little bit. It seems like a series of things worked against you in the quarter. What are you seeing to get confidence that ,that business is going to liven up as the year goes on? Are there contracts in place that are looking economic that have to be monetized? Or, is there just a hope that volatility comes back and goes your way from the run rate where we are right now?

I think there are several things. One thing, if you look at Enserco, we did have -- and we talked about this late last year, where we had some mark-to-market that actually accelerated into 2010 from an earnings perspective. Those were earnings that may have otherwise occurred in the first quarter of 2011. They gave us a boost in the fourth quarter of last year, so it's more of a timing issue on that one. The other one is that, particularly our power and environmental marketing areas. Although we've technically been in those for awhile, we didn't even have our staff hired until right at the first of the year. We had a person or two on late last year and then a couple joined us right at year-end. So, they are really kind of just ramping up their activity, and we are pretty optimistic about that. The Coal Group continues to do well. We are seeing some additional opportunities on the Gas side. There has been some recent volatility there. So, I think the combination of all of those factors, we still feel that, that business will do reasonably well for the year. And we've said in our guidance we expect it to do a little bit better than it did last year.

How much capital do you have deployed in that business right now? Are you running at that $150 million level? Are you seeing any ability to get an adequate return on the capital deployed right now?

We're certainly not seeing an adequate return at present. So, that's why we really have to continue to stay on the business. And the outlook, we start to make headway towards a better return. But, we're certainly not there today, and we have to improve quite a bit to see an adequate return on our capital in that business.

Your next question comes from the line of Brad Donovan with George Weiss Associates.

I just want some clarity on slide 8. You mentioned that a lot of these rising costs were unanticipated. I'm trying to get my arms around that. Because what I don't understand is that fuel and blasting is tied to diesel, and oil has gone from $80 to $100. Staffing levels at the train-out facility, I'm assuming you were aware that you had to staff that 24 hours or be fined. The thickness of clay obviously was a surprise, but you also mentioned you've got higher-cost wells coming on. I don't understand where the surprise came from.

Several things. Certainly, crude oil has continued to increase subsequent to year-end, and where diesel prices were last fall when we were forecasting, they weren't anywhere near the levels that they are now. You are correct in that, that's a major component of blasting as well. Explosive costs have also increased, which is a factor. The train load-out is a little bit different situation. Historically, we've always been able to get away with loading during daylight hours only, or calling out crews on an as needed basis. We only sell coal to one rail-served customer, and so it really doesn't make sense for us to man that facility 24 hours a day.

And historically, the railroad has been flexible in working with us. They stopped being flexible about the end of the year. Essentially, if we don't man that facility 24 hours a day, they are going to charge us [demiurge] costs for leaving the train [weight.] So, we've had to increase staffing there, which -- we have been selling coal out of that facility since 2001, and we've never had to do that before. And, I think that plays into the issue related to that 1 contract, where that is even more expense than we would have otherwise expected to have for that contract. It just doesn't work for us currently with that going on.

The follow-up is the 11% reduction in your guidance, does that assume that all the costs that you've described stay at the exact same level through the end of the year? Or, have you built in some cost decreases between now and year-end in that guidance?

I would say we are anticipating that those costs continue through the end of the year to some extent. I wouldn't say we expect the income to be exactly the same as it is in the first quarter for the next 3. But, we do expect our cost structure to stay somewhat similar. Don't expect any significant relief on explosives, drilling and blasting, fuel or any of those items. And our haul distances and things will stay pretty similar as well throughout the whole year.

Your next question comes from the line of Gordon Howald with East Shore Partners.

We've seen commodity bubbles appear before ,and it's possible that we are seeing one again. Given where the oil strip is, above [$100] through 2014 and almost [$100] through 2020, would you consider hedging oil out further than 2 years, and possibly going above 50% in 2012? Or, are there too many uncertainties on the oil production side? How do you view that?

On crude oil, right now we have in place this 2-year-out hedging philosophy. It doesn't mean that it's not something that we are reviewing, and I think when you have a situation where you have got real high forecasted commodity prices, it may make sense to evaluate that as an opportunity.

We typically hedge a little more than 50% of our crude oil. When Tony said we hedge about 50%, that's probably kind of the average. But on the crude side, we typically hedge at least 50%, if not even a little bit more, particularly in a couple of our fields. The production is pretty well distributed amongst a number of wells. We don't have a risk of if we lose a well we have a naked hedge, basically, or anything like that. As prices get high, we have a tendency to creep up that crude oil hedging number. In the past, we've had it up as high, literally, as almost 90%. It's been a few years since we've done that. But, if it appears advantageous to do so, certainly something we would consider. And, now is a good time to consider those things.

If I could follow up on Dan's question earlier today on coal. Again, I'm just looking for some clarification. Why are you limited to capitalizing further conveyer costs after, I think you said, 7000 feet and how much did that actually cost you from an O&M standpoint in the first quarter?

I can explain the operating perspective. I don't know if we have the numbers out there, Gordon. But essentially, you've been there. Essentially what happens, is we extend that conveyer out to the far reach of the mine, and then we retract it as we move back towards the plant complex. So, we are essentially done building this particular conveyer now. Some years into the future, we will have to build another one when we mine a different part of our permit. But for now, we are done with this one, and so cost that as we constructed it, we were capitalizing. We are essentially done with that conveyer construction now. I don't know about the numbers.

I don't think we've disclosed those numbers.

Was it a fairly significant portion of the O&M increase in the first quarter? Or, is it something that we shouldn't expect to continue?

It's just one of many things, Gordon. I wouldn't call it out as -- particularly fuel costs were more impacted than this item.

Your next question comes from the line of James Bellessa with D.A. Davidson & Company.

It appears that your revised 2011 EPS guidance assumes the fourth quarter settlement of the equity-forward agreement. What settlement assumption were you using in your prior forecast, your previous EPS guidance range?

We had a mid-year equity issuance. It wasn't necessarily a forward. I think we put an approximate amount of equity in a dollar range, I believe. And, said we expected it to occur mid-year. It's in there, in our previous guidance. I don't have that in front of me.

It's a little different than that. We assumed that we were going to settle a piece of it in the end of the second quarter, but not all of it. And settle the remainder in the fourth quarter. That was our original assumption.

If you had taken your former forecast and applied this fourth quarter settlement, how much more EPS would there have been in your former guidance?

It's a few cents.

How much? $0.05?

No, not that much. A few cents.

I heard that gas deliveries were down 4%. And at one moment in the conference, I heard that it was milder temperatures. But, when I look at the 10-Q, I see that the combined gas utilities heating-degree days were slightly above the last year's figure. Then, I heard Tony, I think, say perhaps it was colder. So, I'm just trying to get a clarification.

That is a little confusing. I don't know that heating-degree days exactly correlates as well as it should. But, both years were much colder than normal. It's just that this last winter was a little warmer than the previous winter. So, that's what really drove the 4% less dekatherms that we delivered. The way we looked at it is, our Gas utilities did better than planned, because, in effect, we plan at normal levels. But, they just didn't perform as well as they did the previous year.

When you say that there was a 4% decline, when I look at the total volumes sold by the Gas Utility, they were down 6%. So, I'm trying to track down why you say 4%.

4% is the residential and commercial, and then the rest of it is transport. Transport, although it was down, our margins on transport are extremely slim.

Your next question comes from the line of Neil Stein with Levin Capital. Please proceed.

Can you talk about -- the guidance reduction, there is a lot of attention on Coal. Is the entire reduction related to the difficulties of the Coal business?

No. I think it's just a recognition of both the Coal and the challenges in our non-regulated businesses in general. In 3 of the 4, we just did not do very well in the first quarter. And, although we do think that we are optimistic about Marketing and things doing a little bit better, we may not be able to recover the first-quarter performance. We're $0.23 under for the quarter. We don't really expect the mine to come back. And, we may not be able to recoup, say, in Oil and Gas or in Energy Marketing enough to really get back on track guidance-wise. So, we pulled down $0.20.

I guess you were below plan in the first quarter, let's say on those 3 businesses. You've talked specifically about Coal being a continuing drag versus where you had hoped to be for the remainder of the year. But, I guess you're assuming where you had been for the remaining 3 quarters for E&P and the Marketing business?

In the neighborhood of that.

Did you reduce expectations?

I would say overall, we anticipate that the $0.20 captures where we think we're gong to be low on those 3 businesses combined. Certainly, a big chunk of it is from the coal mine. But, the other 2 businesses are incorporated into that as well.

As we think about beyond 2011, could you talk about what you think your ability is to reverse the various negative drivers at the Coal business by next year?

I think the key one for next year in the Coal business is the one contract, which is 30% of tons. And, we are not making positive margins on that contract today. Things like the train load-out discussion and other things we just had, make that even worse. So, that's a key one for us, and it's certainly one that will be addressed by year-end one way or the other.

The other things, we are really looking hard at cost structure and anything else we can do to improve the efficiency of our mine, and are working aggressively on those. Certainly, hope to come up with something that will improve, as well. The very nature of where we are in the pit will provide some relief here in the next year or 2 as we essentially start mining back toward the power plant complex. We've already uncovered a portion of that coal to install as conveyer, and so we won't have the over-burden expense that comes along with that particular coal that's sitting under that conveyer now. We do anticipate that improving as we go forward, but the primary driver for next year is gong to be the one contract.

Could you be more specific? Do you think you could get back close to the run rate that you had hoped to be at this year when you get to next year? Will the expiration of that contract be sufficient to do that? Or, will it be only a more minor improvement?

It won't be a minor piece. I don't think it's enough to completely make up for all of the cost increases. When we disclose the structure of the contracts, 35% are cost-plus basically, so they will be fine. The other ones have these indices. So, even to the extent we eliminate, for example, that 30% or we raise the price to a point where we are making a profit, we still have another almost 30%, 25% to 30% of our tons that are under a published indice type escalator. That does have fuel adjustments and things, but they tend to lag. So, we will recover part of it. The escalators will help recover more to the extent fuel and labor and things are included in there. But, probably won't get all the way back up to where we had hoped we would be for this year.

And now, a related strategic question, now that you're having -- there is clearly value at this business, but you're not making any money in it, and it's causing earnings volatility which, overall, is having an adverse impact on your stock price. Might the business might be worth more to someone else, who is more focused on that business? And, maybe it makes sense for you to exit this business, or at least study the alternatives for either remaining in it or scaling back.

That's a valid point. I think one thing to point out, though, is that our mine is specifically designed to sell coal to on-site power plants. It really is not designed to compete in the normal coal market, if you will, particularly the train load-out sales coal market. Our coal is relatively low quality compared to other coal in the Powder River Basin. It also is single-rail-served. There is only 1 rail that comes to our mine location as opposed to 2 rail carriers in the southern part of the basin. And, our whole mine pit design and everything else is built around mine-mouth power generation. It may be attractive to someone else, but it would be a stretch. Not that it's not worth continuing to investigate, but it's just not a typical Powder River Basin coal mine, let's put it that way.

We have a follow-up from the line of Michael Worms with BMO.

Just a quick question, a lot of what I had was already covered. I think in your remarks, Dave, you suggested that going forward for the remainder of the year, you were going to try to increase revenues and at the same time, reduce costs at the coal mine. Can you give us some specifics around what you are looking at to mitigate all of this?

I think, obviously, issues related to coal sales and prices on existing contracts and other things are areas that we will focus on. And then, certainly on the cost side, we're looking at everything we're doing over there on a cost basis. We still run a daylight operation, for example. Could we go to longer days and reduce expenses? There's lots of things we are evaluating there. Not sure yet as to how successful we will be. But, I'm optimistic we will at least find some ways to improve overall results over there as the year goes on.

Okay. And just another question. Just generally speaking, not just in Coal but Energy Marking and Oil and Gas, we continue to see rising costs pressure the business. What's the outlook for the costs in these other segments as we go forward? Will we continue to see this pressure? What can you do to alleviate it?

The oil and gas business, I think, we have been managing the LOE and those kinds of G&A costs pretty well, so we are pretty flat there. But, the issue that we have there is just the hedges have rolled off. That's what really drives it. The other issue that I mentioned, is as we do our drilling on oil wells, that cost is a lot higher than what we have in the cost pool. On an economic basis, it makes a lot of sense, but from an accounting basis it drives up our depletion rate. So, you may see our depletion rate drift up, but it's still the right decision because from an economic standpoint, those oil wells will produce for us.

We have a follow-up from the line of Daniel Eggers with Credit Suisse.

A couple things to round out. Number 1, Dave, with the bouncing around in the non-reg businesses, are you guys giving any more thought to maybe thinking about guidance between the utility, non-utility operations, trying to keep a better base line and focus on the core of the Company?

Certainly, Dan, that's something we've talked about. I would say, obviously at this point, we are not ready to do that yet. But, we hear you and it's something we've considered doing. Trying to avoid getting into the segment guidance. But, we do hear you and we've contemplated whether or not we should start doing something like that. Have not made any decisions other than obviously for now, we are not doing that.

Then the next question, when you guys gave the update on Cap Ex for the Colorado power plants. Can you explain how you were able to bring the costs down on the regulated side, but saw the high end of the range in the non-regulated side? Just what caused the variance in plants that are fairly similar looking?

A lot of it has to do with just the specifics of how some of the shared capital gets shared between the 2 facilities. That had an impact on it. When we put out the estimate for the original, the first plant, that was a stand-alone announcement. We hadn't even completed the RFP or anything for the second facility. So, we assumed it was going to have to bear all the costs of infrastructure, water lines, gas lines, those sorts of things. When you co-locate a non-regulated facility with the Utility facility, then there is some sharing of those capital and operating expenses for some of those. And so, that's essentially what the difference is there.

Okay, and maybe 1 last question on the Coal business. If you were to think about the 3 buckets of volumes, the piece that is showing you some negative margin and then you have one is exceptionally profitable and one is in between. How far off is the index piece of the business relative to the target return rate? Is that missing by a couple hundred basis points? Or, is that earning a low single-digit return that there is a lot of movement up even on that piece of the volume pie today?

The one contract, we said it's basically under water. The other one, the utility contract, we've talked about, that one. The way that works is, we earn a return on the mining capital allocated to the utility sales, that's A-rated utility bonds plus 400 basis points. The other contract, which is the one that has the 2014 price re-opener, it actually has a composite escalator. Little complicated, but I think there's 6 different factors that are part of that escalator. They are labor, they're mining equipment, they're fuel, they're explosives. And a couple of others that aren't on the top of my head.

And those escalators are weighted to somewhat approximate the actual cost of mining coal. So, although they lag, theoretically they should kind of keep up. We've just gone into a period here where the over-burden piece of it is not something that gets escalated for. So, the margin is getting squeezed there. When we get to that price re-opener in 2014, I would expect that to be a very profitable contract again. It's not under water. It's not earning returns that we would probably invest capital for today. And the margins are getting squeezed right now. But, it's an acceptable contract still, and over the long haul, will be an extremely profitable contract for us. Has been historically.

We have a follow-up from the line of James Bellessa with D.A. Davidson & Company.

On the Dodd-Frank rules, are they causing you consider closing out your interest rate swap?

We 're not driven by Dodd-Frank on that. Right now, our strategy is still as we've said. We have a fair amount of debt that has to be refinanced in '13 and '14. But, it's something that we continue to look at, Jim.

On the clay parting issues, how do you separate clay from coal?

Essentially, what you do is you mine the coal off the top of the clay and then you come in with equipment and remove the clay layer and then you mine the coal underneath it. And that requires Cats and scrapers and things, not shovels and trucks like we typically operate. We even have to subcontract that activity to somebody else. We don't expect that parting to remain in place for longer than a couple years or so. So, it's not worth us making the capital investment in the equipment to do it. So, we're going to contract that operation which, of course, makes it even a little bit more expensive.

Is the clay level or does it vary in depth?

It's fairly consistent. I wouldn't say the top or bottom are completely flat. It's predictable enough that they can remove it sufficiently. And again, they don't have to remove it all. They just have to get most of it. If it's only a few inches thick, you can really just mine it along with your coal and you see a slight increase in your coal ash, but it really doesn't have a big impact. We just can't tolerate 4 or 5 feet of it. Previously, we just didn't identify that, that parting was there based on some of our drill-hole data we had, that was widely spaced. We didn't see the parting which was kind of in between some of our drill-hole data.

I have some reclassification questions, but they are probably served best offline. Might I get a return call later today?

You bet.

At this time, we have no further questions. I would now like to turn the call back over to Dave Emery for any closing remarks.

Thank you, everybody, for your attendance today. We appreciate your interest in Black Hills. For those of you who are going to be at the AGA Financial Conference starting this weekend, we look forward to visiting with you there. Thanks, everyone.

Thank you for your participation in today's conference. This concludes the presentation. You may now disconnect. Good day.