Jason Ketchum – Director, IR David Emery – Chairman, President and CEO Tony Cleberg – EVP and CFO

Lasan Johong – RBC Capital Markets Gordon Howald – Calyon Mike Worms – BMO James Bellessa – D. A.

Davidson Oliver King – Zimmer Lucas

Thank you, operator. Good morning and welcome to Black Hills second quarter 2008 earnings call.

Before we get into the presentation, I would like to refer you to slide two, the forward-looking statements. This presentation includes forward-looking statements as defined by the Securities and Exchange Commission, or SEC.

We make these forward-looking statements in reliance on the Safe Harbor protections provided under the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical facts, included in this presentation that address activities, events or developments that we expect, believe or anticipate will or may occur in the future are forward-looking statements.

These forward-looking statements are based on assumptions which we believe are reasonable based on current expectations and projections about future events and industry conditions and trends affecting our business. However, whether actual results and developments will conform to our expectations and predictions is subject to a number of risks and uncertainties that, among other things, could cause actual results to differ materially from those contained in the forward-looking statements, including the risk factors described in Item 1A, Part I of our 2007 Annual Report on Form 10-K filed with the SEC, Item 1A, Part II of our June 30, 2008 Quarterly Report on Form 10-Q, and other reports that we file with the SEC from time to time, and the following.

Our ability to obtain adequate cost recovery for our utility operations through regulatory proceedings; to receive favorable rulings in periodic applications to recover costs for fuel, transmission and purchased power in our regulated utilities, and our ability to add power generation assets into our regulatory rate base; our ability to successfully integrate and profitably operate any recent acquisitions; the amount and timing of capital deployment in new investment opportunities or for the repurchase of debt or stock; our ability to obtain beneficial income tax treatment to defer gains associated with asset dispositions; our ability to successfully maintain or improve our corporate credit rating; our ability to complete the planning, permitting, construction, start-up and operation of power generating facilities in a cost-effective and timely manner; our ability to meet production targets for our oil and gas properties, which may be dependent upon issuance by federal, state, and tribal governments, or agencies thereof, of drilling, environmental and other permits, and the cost and availability of specialized contractors, work force, and equipment; the timing, volatility and extent of changes in energy-related and commodity prices, interest rates, foreign exchange rates, energy and commodity supply or volume, the cost and availability of transportation of commodities, and demand for our services, all of which can affect our earnings, liquidity position and the underlying value of our assets; changes in or compliance with laws and regulations, particularly those relating to taxation, safety and protection of the environment, renewable portfolio standards, climate change and greenhouse gas legislation; industry and market changes, including the impact of consolidations and changes in competition; the outcome of any ongoing or future litigation or similar disputes and the impact on any such outcome or related settlements; capital market conditions and market uncertainties related to interest rates, which may affect our ability to raise capital on favorable terms; other factors discussed from time to time in our filings with the SEC. New factors that could cause actual results to differ materially from those described in forward-looking statements emerge from time to time, and it is not possible for us to predict all such factors, or the extent to which any such factor or combination of factors may cause actual results to differ from those contained in any forward-looking statement.

We assume no obligation to update publicly any such forward-looking statements, whether as a result of new information, future events, or otherwise. With that said, I would now like to turn the call on to our CEO, David Emery.

Thank you, Jason. And welcome everybody this morning.

I’m glad you could be with us. As Jason said, we do have a presentation posted and I’ll be following that somewhat.

If you don’t have it, I don’t think it will pose a problem, but if you do, at least try to refer to the slide number periodically as I go through our information this morning. With me today is Tony Cleberg, our new Executive Vice President and Chief Financial Officer.

We announced Tony’s arrival. He started on July 16th.

His appointment as Principal Accounting Officer and Principal Financial Officer is effective today, with him starting after the end of the second quarter didn’t seem appropriate to have him be responsible for second quarter financial results. So I’m finishing those up and then his appointment as our Chief Financial Officer, really responsibility for financial results and other things jointly with me will be effective today.

I will ask Tony to say a few words when I’m done here going through our information this morning before I take questions. And then next quarter I’ll anticipate Tony taking a more active role in the earnings call.

With that said, there are several things I want to talk about and review today with you second quarter highlights obviously including financial results for the second quarter, I’ll go through those in some detail, particularly related to the discontinued operations of our IPP divestiture, and then also looking forward what we see for future opportunities coming up in the near and longer term future. Finally, then after Tony has a few comments, I’ll take questions.

Turning to slide number five, highlights of the second quarter. Several things worth note there.

First is we had a good second quarter. We had a couple business segments that were up from last year, we had a couple that were down from last year, but overall earnings results were very respectable.

Some one time events related to the Aquila and some of the pre-closing costs associated with that acquisition, and in particular, the IPP divestiture and the re-classing of a portion of those results to discontinued operations leads to some kind of strange optics when looking at year-over-year, quarter versus quarter on an EPS only basis. Hopefully through the course of the call here today, I’ll be able to shed some light and add a little clarity on what the actual results comparison is.

Starting out with the utility, our utility had an excellent quarter, very strong performance, both operationally and financially, of the addition of Wygen II as the rate base asset for Cheyenne Light has had a large impact on our utility operations results. And as expected, rate base power plant contributes significantly to earnings and has in this quarter.

We also had an excellent quarter at Black Hills Power and off-system sales through utilization of our AC/DC tie here in Rapid City. We are able to move energy back and forth between the eastern and western transmission groups.

Our Wygen III construction project that we’ve started in March, expect to complete in mid to late 2010, is on schedule and on budget and progressing very well. We’ve had a good summer construction season thus far.

On the non-regulated energy side, oil and gas earnings were up strong 64%, primarily related to oil and gas commodity prices. Production was down 9% compared to the same quarter last year, primarily as a result of decreased capital spending.

We’ve had permit delays and weather delays at a couple of our properties that we’ve talked about in the first quarter. Some of those results built over into the second as well, particularly the permitting delays.

And then reduced activity at some of our non-operated properties has had a pretty significant impact on production. Three areas in particular; our Woodford Shale play in Oklahoma, Central Montana gas play that we have, and Central Wyoming gas play that we have, all within the last year or so have had a change in operator-ship or were being prepared for sale.

And through the turnover of those assets and new operators, we are looking at drilling plans and things we’ve just had some delays. Still very valuable properties for us, but something that we as a small minority interest owner really can’t control our drilling schedule.

As a result, we’ve reduced our capital expenditure forecast for E&P this year by approximately $30 million, which was also noted in the press release and 10-Q. On the energy marketing side, certainly posted lower earnings than last year, but when comparing to the best year we’ve ever had, really resulting as bad as the optics would appear.

Certainly basis differentials out of the Rockies have been fairly weak early in the year and the calendar spreads, which impact our storage business in energy marketing and have been real weak as the spreads have been pretty flat. The seasonal spreads have been pretty flat.

If you look into next year, you are starting to see some improvement in those, particularly in the basis differentials out of the Rockies, and we’re adding significant value to our book for 2009 and beyond. Coal mining earnings were down a little, primarily as a result of overburden expenditures.

As you’ll see from some of our statistics, we are moving a lot more overburden for the same amount of coal due to what we’ve talked about previously, and that is essentially mining through a hill of overburden covering our coal currently. We expect that to continue for at least several years as we continue to mine our way through the hill.

The power generation side for both quarters, this year and last year, reflect losses and that’s primarily related to the reclassification of certain things to discontinued operations. We sold seven power plants in our divestiture to Hastings.

Those plant assets and associated earnings and expenses were re-classed to discontinued operations. However, inter-company interest that had been charged to those specific facilities that we sold and allocated indirect corporate costs that had been charged to those facilities were not re-classed to discontinued operations.

So it looks as though those segments had a loss for those periods. Going forward, those inter-company interest charges and the indirect overhead allocations will be re-allocated on a different business mix.

So, things will look quite a bit different in the third quarter and beyond with the addition of the Aquila properties and other things. On the corporate costs side, we had about $3.1 million increase in unallocated corporate costs, most of that’s related to the Aquila acquisition.

We had said we originally hope to close the acquisition by the end of the first quarter. We needed to add significant staff and open a new call center and other things in order to be ready to close that.

And with the delay in closing – and actually we had those people for longer than we originally contemplated prior to actually having the properties that they would operate. We made good use of their time in ensuring a very, very successful transition, which I’ll talk more about later.

But we didn’t contemplate having that additional expense for an additional quarter. Another item worth mentioning related to the quarter, in our utility segment we had a couple planned and unplanned plant outages, primarily at our Ben French and Osage plants.

Those plants, we either started that as a planned outage or an unplanned outage. And then as we got into, they made the decision to extend both of those outages and do significant additional repairs, which will help us particularly with Ben French where we won’t need to take an outage that we had planned for 2009 now, and we’ve restored that facility back to its full rated capacity.

Moving on to page seven, talking specifically about a couple of the segments on an earnings perspective. On the utility side, our income increased to $9.6 million compared to $5.9 million last year.

As I mentioned earlier, both segments were up, both Black Hills Power and Cheyenne Light. Notably strong off-system sales, which I already mentioned, and then the impact of the Wygen II power plant really increased margins for Cheyenne Light, really two-fold effect there.

The first is the increase in revenue from the rate case that was associated with the addition of that plant into rate base. The second is the significant decrease in fuel and purchase power costs.

The lower cost coal-fired generation at Wygen II is much cheaper obviously from a fuel cost and some of the gas fired and purchase power that we were utilizing previously. Also noteworthy as we did set a new peak load on August 1st for Cheyenne Light, Fuel & Power of 174 megawatts, which was about 3 megawatts above the peak that we’ve set last year at 171 megawatts.

On the non-regulated energy side, income was roughly half of last year, little bit over $7.5 million versus $14.4 million. The majority of the difference is due to the energy marketing segment, which I already discussed.

The power generation segment I discussed as well, primarily the impacts of the discontinued operations. The oil and gas segment, as I said earlier, the earnings were up strongly there, which helped offset some of the negative energy marketing and the coal mining.

On the coal mining segment, we’ve talked specifically about our overburden increase. Basically that number has increased 73% over the same quarter of last year.

And as I stated earlier, we expect that to continue to remove higher quantities of overburden. We did have some -- rapid acceleration of some of the operating expenses associated with gearing up the mine for the additional overburden and the additional tonnages with Wygen II.

And we expect those to settle back to a little more normal pace going forward. On the financial side, moving on to slide ten.

This slide provides a real good income reconciliation and shows the true impacts of the discontinued operations in our IPP side. If you look at the fact that we had a record year in 2007 at Enserco, this really represents a real solid quarter.

And if you look at the bottom line, including the add-back of results of discontinued operations, really looking at a number of about $0.58 per share compared to $0.66 last year, again very solid results. On the discontinued operations side, I already talked about this, but the inter-segment interest expense that was not re-classed to discontinued operations and the indirect corporate costs that were not re-classed totaled $4.9 million and $1.6 million respectively.

So, those do have a significant impact on the current quarter’s earnings for the generation segment. And as I stated earlier, those will be reallocated going forward.

The generation segment will get a portion of those costs, but because there are significantly less assets and employees and income in the generation segment, they will be allocated considerably less of those expenses going forward. We’ve talked about the IPP divestiture already, but I think it’s worth noting again that the proceeds significantly helped our ability to fund the closing of the Aquila acquisition.

We needed to do a $380 million draw on our bridge acquisition facility, but we don’t anticipate having to do any long-term equity issuances related to the purchase of Aquila. We will have to do some long-term debt financing to replace the bridge by February of next year.

One of the most notable items I think is through the tax planning that we were able to do in the combination of the two transactions, we were able to defer between $135 million and $165 million in cash tax payments. So it’s obviously a considerable impact on our ability to finance operations, including the Aquila acquisition and our ongoing capital expenditures.

Looking forward now, a few recent events on page 13. I’ve talked plenty about the IPP and the Aquila transactions, don’t need to mention those again.

But a new one that we announced this quarter is the transaction with MEAN, the Municipal Energy Agency of Nebraska. We have a letter of intent to sell a portion of the Wygen I plant to MEAN at a price that approximates the replacement cost, which is roughly equivalent to Wygen III.

We currently have a contract to sell them 20 megawatts of energy out of the facility. That contract expires in 2013.

We’ve been working with them to either negotiate an extension or to negotiate their purchase of an equity ownership in the plant. We’ve obviously elected the duty equity ownership route.

We expect to close that transaction prior to the end of 2008. Wygen III, we’ve talked about previously, we have finalized the third-party ownership in that plant.

In previous quarters we’ve talked about that we were looking or potentially considering a third-party investor in that facility. MDU Resources, Montana-Dakota Utilities has agreed to take a 25% interest in the plant.

We provide all their energy requirements for the City of Sheridan, Wyoming. And as part of the contract renewal for that contract a couple of years ago, MDU had an option to participate in any future plant we would build -- in our future plant that we would build, namely this one.

And they are planning to exercise that option. And the transaction isn’t closed and completed yet, but when that’s done probably close to year-end, we would expect to have in place kind of life-of-plant contracts for site operations, site leases, and coal supply agreements with MDU.

We also announced in this quarter’s release that we are commencing two small expansion projects that our coal-fired power plants in Gillette, Wyoming. We are expanding our air-cooled condensing systems on both the Neil Simpson II plant, which is the Black Hills Power asset, and Wygen I, which is a non-regulated power plant.

Those additions, which will cost us roughly $16 million in total for both plants, will add about a little over 8 megawatts of base load capacity to each facility at an installed capacity of just under $1,000 at KW, about $995. That’s significantly less than half of the cost of the Wygen III construction.

So those are very economical capacity additions for us. We expect to complete those in mid 2009.

On the regulatory front, there is plenty of activity but nothing new since we last updated you upon the closing of Aquila with the exception of the filing of our Colorado Electric Resource Plan on August 5 for the former Aquila Southern Colorado utility. On slide 15, we talk a little bit about that electric resource plan.

We are proposing the construction of 250 megawatts of natural gas fired generation and the addition of about 64 megawatts of renewable energy supply. As we’ve talked about previously, the Colorado electric utility has a very unusual situation and that its power purchase agreement expires in the end of 2011, and literally will be faced with replacing about 75% of their energy supply in the course of one day beginning in January 2012.

The Colorado Public Utilities Commission is aware of the situation, and certainly we filed our resource plan with them and look forward to working with them to gain approval of the plan. One thing notable there, we have mentioned previously, especially last year that we were evaluating the opportunity to maybe add some base load coal resources, maybe even in Wyoming to serve some of the Colorado electric load.

With the rules in Colorado related to renewable portfolio standards and then the Governor’s executive order on CO2 emissions and greenhouse gas reduction targets, coal is not currently a viable option. We believe that situation possibly could change as we go forward in the future.

But for now and to meet the immediate needs of our customers on January 2012, we are pursuing gas-fired and renewable generation in adding that to the existing coal-fired generation that the utility in Colorado holds today. We do believe, as we’ve stated repeatedly for Black Hills Power and Cheyenne Light, the utility-owned rate base generation provides the best long-term rates for customers.

The ownership of the utility plant in rate base is a benefit for customers. They gain the value of the plant as the plants depreciate over time and help add rate stability for them, and we believe firmly in the integrated vertical – vertically integrated utility model.

We must go through the resource planning process and the hearing [ph] process in Colorado to demonstrate to the PUC that our plan is indeed in the best interest of our customers and we intend to do just that. Moving on to slide 16, a quick update on the Aquila integration.

I won’t spend a lot of time on this because you can certainly look at the statistics. But I won’t say that things have gone incredibly well.

A very, very successful transition. Notably, really no disruption in gas or electric service, which of course is critical.

The customer service has gone very well. Our customer service statistics are exceeding the standards in any of the states that we have particular customer service metrics.

We’ve done a huge amount of systems and communications work, and things are going very, very well. We are almost a full month into the acquisition.

And billing and customer service quality and reliability and other factors are all doing very, very well. We are really pleased with where we are at.

Certainly it’s not an accident. Our employees as well as the employees who came to us through the acquisition have spent a lot of time preparing for this day one of the acquisition since February of 2007, early when the deal was announced.

Certainly we are happy that all our hard work and effort paid off with a very successful transition so far. We look forward to continuing that success going forward.

As we look at things on an overall corporate basis, we are in excellent financial shape. Moving on to slide 17 here, we’ve got a great base upon which to continue adding value for our shareholders through additional growth in power plant construction and growth in our non-regulated side as well.

We have made a very conscious shift to increase the amount of utility earnings and cash flow and assets in our overall portfolio. They will help reduce our overall corporate risk profile, improve our credit metrics long-term, and allow us to really have a good foundation upon which to continue to grow.

Our capital structure currently is 46% debt to total capitalization. And as far as permanent financing for the Aquila acquisition goes, we don’t need to issue any additional common stock.

So there won’t be any added dilution for shareholders on the earnings side related to that. We do anticipate a long-term debt issuance probably late this year to retire our bridge acquisition facility.

On slide 18, we are proud of our 38 consecutive years of dividend increases and the fact that we’ve averaged 15% annual total shareholder return over the course of the last five years and hope we continue that well into the future as we continue to grow. On slide 19, I wanted to give you a sense of our long-term strategic plan and some real key goals that we have going forward that demonstrate the excellent growth opportunities that we have and also gives you a snapshot in our progress in executing on those opportunities.

Really is a great balance of opportunities between utility and non-regulated generation and generation construction, increased coal production to accompany the Wygen III plant, and then continuing to grow both our oil and gas and energy marketing businesses going forward. Finally, we’ve talked about issuing new earnings guidance.

Given the completion of these two largest transactions in our history, the Aquila deal and the IPP divestiture, we suspended our guidance in the second quarter and planned to issue new guidance for the remainder of 2008 and initial guidance for 2009, as well as hosting an additional investor conference call at that time around mid-September, within the next 30 days or so. Given the fact that we’ve had two mid-month closes for both of these transactions and obviously this quarter-end and a lot of other activity, really want the additional 30 days to make sure we can put forth some real good numbers, well thought out numbers for 2008 and 2009 in the way of guidance, and then also incorporate permanent financing plans into that guidance going forward.

With that, I’ll turn it over to Tony Cleberg to make a few remarks and then I will come back on and answer any questions you may have at that point. Tony?

Thank you, Dave. Well, I’m excited about joining Black Hills for a number of reasons.

One reason is just the change in industry will really create both challenges and opportunities to excel. Another reason is the Aquila acquisition I look forward being part of the team that really levers this integration into a much stronger company.

And the last reason I’ll mention today is just I’m joining a team of people who have a strong desire to take this company to a much higher level and really improve the performance. And that’s very appealing to a new CFO.

My early focus that Dave has me out looking at the businesses and getting to understand the operational people and gaining insight [ph] into how we make money and how do we use financial information for decision making. One area that recognize as will be a key focus of mine will be just refining our measurements that link the strategies and actions to the shareholder value creation.

Our team at Black Hills is very much interested in driving up the stock price. So we need to ensure that our actions really align with that goal.

So again, I’m very excited about joining the team here at Black Hills and I look forward to reporting to you in the future. Thank you.

Thanks, Tony. I’d be happy to entertain any questions now.

Great, thank you. I want to ask a few questions on the E&P capital spending.

It’s down about $30 million to looks like $65 million and production continues to lag. And I understand why that’s so in this particular instance, but I want to bring up the issue of divesting this business again.

It does seem like a lot of difficulties meeting targets, not necessarily due to Black Hills’ fault but because it’s third-party operated. And there is a lot of volatility involved relative to the underlying assets, the utility assets, and there is potential threat of callback situation at the gas utilities.

Why do you want to keep on holding to this asset? Is there something we can do to make this asset more predictable and more attractive to Black Hills shareholders?

Hi, Lasan. The primary issue for us, and we’ve talked about this before, is that we believe that the assets that we hold have significant upside opportunity in value there.

And the best way to recognize that value as a shareholder is primarily through the drill bit. And we’ve got a group (inaudible) of folks to implement the plan to develop those properties and had a few obviously some delays that we are not particularly pleased with, but still believe overall in the value and the true value creation from a shareholder perspective will be through the development of those properties rather than the divestment of the property.

When do you think you might realize on this value, like starting next year you think?

Yes, certainly we hope that. As things move forward here, and we get some of these questions I earned out, couple of the properties recently are changing hands on the non-operated side and on the operated side, this gearing up our drilling permit effort.

We’ve had delays particularly in the Piceance Basin that we would expect things to start improving going forward. Even now, I mean, we’ve got a fair amount of drilling activity going on and we would expect the production numbers to improve a little bit as the year goes on.

We’ve said last quarter that we thought it would be challenging to meet our production numbers in 2007 this year, given the weather and permit delay starts that we have. But I would expect the numbers to improve somewhat from where they stand today.

Okay. On the coal side, you said the increased overburden has shut the operating costs up.

Is there any other contributing factor, materials, labor? I hear that access to skilled labor is particularly difficult these days.

Yes, labor is an issue, not a huge issue for us, but it is an issue. The labor market in Gillette is very, very tight, whether it’s in oil and gas, or coal, or any field up there -- power generation, the labor market is tight.

The primary drivers on the cost side though are the overburden expense is a huge one. Obviously diesel costs are up considerably.

That one is also a key driver, particularly when you are looking at hauling all that additional overburden that drives up your diesel expenses quite a bit. Things like tires and other materials are up considerably as well.

So there are several things. But the primary driver of that is the overburden increase itself.

I mean, we are moving a tremendous amount of additional material.

Are you able to pass that costs through to ultimate users in terms of their coal price?

Yes, it depends on the contract, Lasan. Our utility coal contracts are essentially cost based.

And so that does get passed on. We typically true up that calculation on an annual basis and windmills costs are included.

The coal sales to the affiliates are based on cost plus a return on investment concept, more of a utility rates type concept. So those costs will be able to be passed on to our utility coal customers.

On the other side, some of those costs are able to be passed, some are not. A couple of our larger contracts have a fixed price, but they have an escalator.

And those escalators are essentially compositive kind of key cost drivers in our coal mine, which would include things like labor and fuel and materials. And we use annual published indices to calculate how the coal contracts escalate.

So there is a little bit of a lag when those costs rise. But the coal price does escalate at a rate that approximates the increase in the cost of mining coal.

That’s cool. On the $317 million CapEx plan for ’08, can you give us an update on how much of that is maintenance and how much of that is growth?

Well, if you look at the numbers, I’d say the primary growth drivers in there obviously are the Wygen III plant and the oil and gas. And there’s some transmission in the utility, which we’ve talked about those numbers as well.

As far as transmission investment, $40 million kind of number for transmission investment. And then the balance of it is more maintenance type CapEx.

Okay. So that’s 65 from oil and gas, 40 from trany [ph].

I forgot what the Wygen number was, but those three are your growth CapEx, the rest is maintenance?

Yes, for the most part. There are some few minor exceptions to that.

I mean, these air-cool condenser projects and a few little things like that. But the majority of the growth capital is in those three items.

Okay, great. And you said you’d give updated guidance for mid-September.

Are you guys coming out (inaudible) to do that, or is it going to be like there is sort of webcast or how do you intend to do it? Are you going to do some marketing around the new Aquila acquisition?

Yes. We intend to do a webcast and conference call to release the initial information and then certainly we’ll plan on a series of meetings with investors and analysts, update people on the benefits of the Aquila acquisition and just our overall plan and plan for growth going forward.

Great. Thank you.

Hi, thanks guys.

Hi, Gordon.

Good morning. Just following up on Lasan’s question here.

What portion of E&P production is from operated and what percentage is non-operated? Also since you won’t be purchasing coal assets at this point, would you consider adding more E&P assets?

And lastly along that same vein, what’s your policy on hedging and E&P? How could that change given the addition of gas-fired generation in Colorado?

Okay. I’ll see if I can remember them all here, Gordon.

First on operated and non-operated, we have not previously disclosed what the percentage of operated and non-operated production is. The majority of our production is operated, but we haven’t disclosed specific percentages of that.

The potential for additional acquisitions, whether it’s – we are probably not too interested in looking at coal properties, but again it depends on where they are and how they would potentially fit into our operation. But oil and gas acquisitions are always something that we are looking for, but we’ve discussed previously that (inaudible) what I would call open bid real competitive situations.

Those typically don’t work very well for us. I mean, we are just not willing to bid the low returns, but some of the bidders in those auctions are willing to bid.

So we don’t typically acquire properties through what I’d call an open auction process and usually don’t even bother to try frankly unless we have a – what we think as a real competitive advantage or a real knowledge of the area. We do have an occasional acquisition on the oil and gas side on a negotiated basis if there is properties in an area where we are very familiar with that we can acquire and add value to or there are properties we already have an interest in, which are very excellent adds because you don’t really add any additional costs associated with those.

And we are always looking for those. When you are in a price environment where you’ve had real prices, it’s difficult to buy.

And certainly when you had real high prices very recently and prices come down like they have, it’s probably even harder to buy because anyone who might be willing to sell remembers that just a few weeks ago they were getting a few bucks more for their gas price. So it’s probably not a real good time to buy right now, but that doesn’t mean there won’t be opportunities and we’ll continue to look for those.

Right. Last question is on hedging –

And then on hedging – yes, the hedging piece, we typically try to hedge between 50% and 75% of our gas and crude oil going forward. And we usually hedge it for about a two-year period from the current date.

We don’t hedge anything we haven’t drilled yet. So we look at our current production.

We forecast the decline rate for that going forward for a couple of years and then we try hedging 50% to 75% of that. And we typically layer those hedges in about a quarter of time.

So this quarter we would be hedging two years out for the same quarter typically. So we are layering them in.

We are not really trying to really second guess the market as we’re just trying to add some stability to the cash flows there. And we do a combination in – we publish the list of our hedges that we typically do a combination of swaps and quotes.

So we can retain a significant portion of the upside, but then also do some swaps to lock in some good prices as well.

Great. That’s excellent quarter.

Thank you very much.

Yes, thank you.

Thank you. Hi, Dave, how are you doing?

Great, Mike, how about you?

Fine, thank you. Two questions.

One, can you quantify for us how much the unplanned plant outages impacted earnings in the quarter? How long were those plants out?

The outage days are described in the 10-Q, Mike, but both of the plants were pretty small. So I’d say the overall impact on earnings is relatively small.

Not – a small impact, but nothing real large. And the days are in the Q, but a couple of them are fairly substantive.

I think the Ben French plant (inaudible) immediate to pretty small facility, 20-some megawatts.

Thank you. And then the other question would be, with regard to oil and gas production numbers, have you revised those numbers now that you are going to be spending some $30 million less than you had planned?

As far as planned production goes?

Yes, for the year.

Yes, I know we have not, but we’ve said that when we come out with our updated earnings guidance, we would also refresh any of our other segments in addition to the Aquila properties that we’ve acquired. And so we would anticipate essentially giving new guidance around the whole corporation, including oil and gas and IPP and other things when we come out.

We won’t necessarily give the guidance by statement, but we’ll put out the key assumptions, production numbers and prices and things like that.

Fair enough. Thank you.

All right. Thank you.

Dave, hi, Jim Bellessa here.

Hi, good morning, Jim.

Say, the production has declined for three quarters in a row. You say in this press release that the production is down due to lower than expected capital spending and then you go on to say that you are lowering your capital spending.

At what point do we see production increases from your oil and gas business?

Well, several issues. I think one is that we’ve talked about this year we expect to delay.

We expect to be challenging to get to last year’s production numbers. But as I said to Lasan, I do expect the production numbers to start improving.

And we do have rigs running now and we are seeing some good results in our programs. So I would expect that that number would get a little bit better as we go through the rest of the year and exit the year, and then hopefully next year we can be back and do a little more normal (inaudible) production.

That would be our current anticipation. But in answer to Mike’s question, we have not published what we think those numbers will be at this point, but would anticipate doing so when we issue new guidance.

In the Q, you indicated that there was July sales of NOx credits, and I’m wondering if this sale was after the US Court of Appeal has vacated the Bush administration’s Clean Air interstate rule or did you get the high price prior to that rule being overturned?

The sale of the credits was before that rule, Jim. But the specific impact that that would have on the price, I really couldn’t say.

Was it just fortunate or did you know the rule is going to get overturned?

No, we didn’t know the rule is going to get overturned. I mean, we’ve talked about a couple of those facilities, that one in particular is something that we had taken an impairment charge on last year and we are looking to kind of wind down the operations there.

So it made sense to kind of look at anything that we could do to recover some cost to offset the decommissioning cost there, including selling those credits was something that we’ve been looking at for sometime.

Now the year ago second quarter had also transition and integration costs for Aquila in there, is that correct? And so the – you say that, in the Q, the increase in these costs was $1.7 million in the most recent quarter.

Can you tell us what the amount was a year ago and then we can figure out how much you’ve spent this year second quarter as well?

Well, out of the top of my head, Jim, I couldn’t tell you what we expensed last year. I mean, we’ve had ongoing integration expenses on Aquila since we announced the deal.

And lot of the costs pre-close have been capitalized. We really ramped up our expenses in the last six months or so, really after the 1st of the year because we were starting to staff up to take it over.

As we talked about in the announcement of the deal and subsequent to that, we had to add significant corporate support group staff to be able to handle additional five utilities because we weren’t getting any of the corporate support groups as part of the transaction. We just got the utility properties and those employees elected to come -- all come to work for us.

So we had to add significant corporate staff and then we also needed to add a call center here in Rapid City to support the Aquila utilities. So, starting about January we really were ramping up that hiring to be ready to close and be ready to be fully operational on day one.

So the majority of that expense money really would be showing up in the first and second quarters of this year, primarily the second quarter because we were – we essentially had to be ready to close by that March and April 1 time frame. So we had the majority of those people hired and we are training or had them trained already by that point in time.

Should we still anticipate some of these transaction costs will be seen in the third quarter?

Yes, I would say for a period of time we’re going to have some expenses in there extra, kind of one time expenses. There is a lot of activity going on.

One of the things we’ve talked about is that our longer-term goal is to consolidate customer information systems and accounting financial systems, things like that. Right now we are operating multiple systems in some cases.

And that adds a little extra expense for us as we go forward. We would anticipate it over time as we migrate our current utilities and other businesses on to the same platform from both the customer information and accounting systems standpoint that we’ll see some reduction in those costs.

But realistically for the rest of this year in particular, you’ll see some added cost there and a little bit of that lingering on into next year.

Thank you very much.

Thank you.

Hi guys.

Hello, Oliver.

What kind of ROEs are you seeing at your utilities for ’08? And how much (inaudible) purchase power savings are you going to see from Wygen II for 2008?

The specifics of our returns aren’t typically disclosed, but we do issue separate financials for Black Hills Power, which you can see what we’ve got there for Black Hills Power. And then Cheyenne Light side, we disclosed what we were allowed to earn in our last rate case, which – that number was a 10.9% return on equity, with 53% or 54% equity component – 54% equity component in it.

But we haven’t disclosed the specific standalone financials of Cheyenne. And we haven’t done that for obviously the acquired Aquila utilities either at this point.

Okay. Can you talk about what was allowed in the rate – or what was in the rate case filing in terms of savings from Wygen II coming online?

Yes. As far as the savings in fuel and purchase power?

Yes.

I don’t recall that number out of the top of my head. Yes, I really don’t.

And all of that, of course, is a pass-through to customers anyway. But I don’t recall what that number was.

Okay. And sort of like a longer-term picture, what do you guys target in terms of capital structure and dividend payout ratios?

Well, we’ve talked about capital structure. We want to maintain a utility like capital structure, which is basically consistent with maintaining an investment grade credit rating.

So you wouldn’t expect to see us with a capital structure much higher than 50-some percent debt. Maybe that’s 3%, 4%, 5% debt somewhere in that range, just kind of depends.

But we would anticipate maintaining an overall capital structure consistent with the utility structure. With some of our non-regulated operations being a little more risky from a credit rating agency perspective, we typically tend to be a little bit lower in those ranges than we might otherwise be on a cap structure basis.

Okay. And in terms of dividend payout ratio, where you guys--?

Yes. Dividend payout ratio would probably be different going forward than it has been in the past, given our significant increase in utility properties.

We’ve said previously in past years, talked about it that we like to maintain payout ratios in that 60% range or less. No, we haven’t talked specifically about it and certainly haven’t mentioned it since we’ve acquired the Aquila utility.

So I would say that’s kind of stale information at this point.

Okay. Thank you very much.

Thank you.

Thank you. Couple quick follow-ups.

You had mentioned that in Colorado you are looking to do some renewables. Are we talking wind or something else?

Primarily wind.

Of 65 megawatts.

Yes, that’s the most viable option there. Aquila has a Canon City coal-fired power plant and they are doing a little bit of biomass there, blending it with the coal and getting some credit for that for renewables there.

But the majority of it is going to have to be wind. Colorado has a solar requirement, however, as part of their rule.

And we just announced here a couple of weeks ago that we worked with Colorado State University in Pueblo to install a one megawatt solar facility there that they are actually installing, but we – part of the solar requirement has to be on the customer side of the meter. And so the addition of that facility will help us meet some of those renewable requirements.

And we are investigating some small solar on our side of the meter as well, as that’s part of the mandate in Colorado.

Okay. And then, MDU, you said bought about 25% of Wygen III.

Did that buy that at cost or did that buy that at a premium to what your bill cost is?

Yes. They will be in at cost essentially.

Why make that decision, with that [ph] decision that you had no choice in making? Why would you not be able to sell it at a price higher than your cost?

Your cost is pretty cheap.

Yes, it is really inexpensive compared to what others are paying for coal-fired facilities right now. As I mentioned earlier, Lasan, when we renegotiated our oil requirements power supply contract to serve MDU’s Sheridan, Wyoming load, that was one of the provisions of the contract that they have the right to participate for up to – and I believe it was 25 megawatts of participation in a future power plant that we may build.

We originally signed that Sheridan contract back in 1995 and I think it took effect in 1996. And the original version also had an option for them to participate in a future built power plant, and at that point they elected to pass on that.

We included the same provision in this renewal of the contract and this time they elected to exercise.

I see. Any chance that you can buy that little piece of their business?

I’d love to, but I don’t think they want to sell it. But it’s the only electric utility property they have in the western transmission grid.

So they don’t have any generation liquids to serve it directly. That’s why we serve it for them on an oil requirement basis.

But now with this 25 megawatts of equity ownership, they will be able to serve at least the portion of the base load of that contract with the Wygen III resource. But yes, I mean, we are always looking to acquire additional utilities that fit into our system, but you have to have a willing seller and a willing buyer and that isn’t always the case on this one.

Sounds like it would be a good opportunity if you could. Okay, thank you very much.

You bet. Thank you, Lasan.

All right. Well, thank you everybody for being on the call this morning.

We appreciate your attendance. We also appreciate your continued interest in Black Hills.

Look forward to sometime in the next 30 days or so getting out with updated earnings guidance for ’08 and new guidance for 2009 and letting you know how we are standing with our future plans now that we have acquired the Aquila property. So, thanks for your attendance today, we appreciate it.