Black Hills Corp (BKH) 2008 Q2 法說會逐字稿

Ladies and gentlemen, thank you standing by, and welcome to the Black Hills Corporation quarterly earnings call. At this time all participants are in a listen-only mode. Later we will conduct a question-and-answer session. Instructions will be given at that time. (OPERATOR INSTRUCTIONS). As a reminder, this conference is being recorded. I'd now like to turn the call over to Director of Investor Relations, Mr. Jason Ketchum. Please go ahead.

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 2, 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 1-A, Part 1 of our 2007 Annual Report on Form 10-K filed with the SEC, Item 1-A, Part 2 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 and periodic applications to recover costs for fuel, transmission and purchase power in our regulated utilities, and our ability to add power-generation assets into our regulatory rate base. Our ability to successfully integrate and properly 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-supplier volume; the cost and availability of transportation of commodities and demand for our services, all of which can affect our earnings, liquidity position and underlying value of our assets.

Changes in or compliance with laws and regulations, particularly those related 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 filing 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 a 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 over to our CEO David Emery.

Thank you, Jason, and welcome everybody this morning. Glad you could be with us. As Jason said, we do have a presentation posted, and I will be following that somewhat. If you don't have it, I don't think it will pose a problem. But if you do, I will at least try to refer to a 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 16. His appointment as principal accounting officer and principal financial officer is effective today. With him starting after the end of the second quarter, it 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. We will 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.

Moving to slide number 5, 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 acquisition 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 today I will be able to shed some light and add 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. The addition of Wygen II as a rate-based asset for Cheyenne Light has had a large impact on our utility operations results, and as expected, rate base power plant contributed 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 ACDC tie here in Rapid City, we are able to move energy back and forth between the Eastern and Western transmission grids. Our Wygen III construction project that we started in March, I 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 a strong 64%, primarily related to oil and gas commodity prices. Production was down 9% compared to the same quarter last year, primarily the result of decreased capital spending. We've had permit delays and weather delays in a couple of our properties that we talked about in the first quarter. And some of those results spilled 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 are 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 operatorship or were being prepared for sale. And through the turnover of those assets and new operators re-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 can't control a drilling schedule. As a result, we have reduced our capital expenditure forecast for E&P this year by approximately $30 million, which was also noted in the press release in 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 the results aren't 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 have been real weak as the spreads -- or have been pretty flat, the seasonal spreads have been pretty flat.

You look into next year, you are starting to see some improvement into those, particularly the basis differentials out of the Rockies, and we are adding significant value to our book for 2009 and beyond.

Coal mining earnings were down a little, primarily the result of over-burden expenditures. As you'll see from some of our statistics, we are moving a lot more over-burden for the same amount of coal due to what we talked about previously, and that is essentially mining through a hill of over-burden 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. That's primarily related to the re-classification of certain things to discontinued operations. We sold seven power plants and 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 in direct 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 indirect overhead allocations will be reallocated 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 cost side, we had a $3.1 million increase in unallocated corporate costs. Most of that is related to the Aquila acquisition. We had said we originally hoped to close that 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, obviously we had those people for longer than we originally contemplated prior to actually having the properties that they would operate. But we made good use of their time in ensuring a very, very successful transition, which I will 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, is 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 as a planned outage or an unplanned outage, and then as we got into them 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. We've restored that facility back to its full rated capacity.

Moving onto page 7, talking specifically about a couple of the segments on an earnings perspective. On the utilities 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. And 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 a twofold effect there.

The first is the increase in revenue from the rate case that was associated with the addition of that plant and rate base, the second is the significant decrease in fuel and purchase power cost. The lower-cost coal-fired generation at Wygen II is much cheaper obviously from a fuel cost than some of the gas-fired and purchase power that we were utilizing previously.

Also noteworthy, is we did set a new peak load on August 1 for Cheyenne Light Fuel & Power of 174 megawatts, which was about three megawatts above the peak that we'd set last year at 171 megawatts.

On the non-regulated energy side, income was roughly half of last year, a little bit over $7.5 million versus $14.4. 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 at energy marketing in the coal mine. In the coal mining segment, we talked specifically about our over-burden 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 over-burden.

We did have some -- a rapid acceleration of some of the operating expenses associated with gearing up the mine for the additional over-burden and 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 onto slide 10 -- I think this slide provides a real good income reconciliation and shows the true impacts of the discontinued operations in our IPP side. If you look the fact that we had a record year in 2007 at Enserco. This really represents a real solid quarter. 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'll be allocated considerably less of those expenses going forward. We have talked about the IPP divestiture already, but I think it is 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 t 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 and $165 million in cash tax payments, which has obviously a considerable impact on our ability to finance operations including Aquila -- the Aquila acquisition and our ongoing capital expenditures.

Looking forward now, a few recent events on page 13. I 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 have been working with them to either negotiate an extension or to negotiate their purchase of an equity ownership in the plant. They have obviously elected to do the equity ownership route. We expect to close that transaction prior to the end of 2008. Wygen III we have talked about previously. We have finalized the third-party ownership in that plant. In previous quarters we have 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 years ago, MDU had an option to participate in any future plant we would build -- in a future plant that we would build, namely this one. And they are planning to exercise that option.

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 a life of plant contracts for site operation site leases and coal supply agreements with MDU.

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

Those additions, which will cost us roughly $16 million total for both plants, will add a little over 8 megawatts of base load capacity to each facility at an installed capacity of just under $1,000 of 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 350 megawatts of natural gas-fired generation, and the addition of about 64 megawatts of renewable energy supply.

As we have talked about previously, the Colorado electric utility has a very unusual situation in that its power purchase agreement expires 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 had 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 and adding that to the existing coal-fired and gas generation that the utility in Colorado holds today.

We do believe, as we have stated repeatedly, for Black Hills Power and Cheyenne Light, that 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 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 onto 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 will say that things have gone incredibly well. 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 in. We have 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 is 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 really 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. We are moving onto slide 17 here. We've got a great base upon which to continue adding value for our shareholders through additional growth and power plant construction, and growth on a 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. It 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 in -- 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.

Slide 18, we are proud of our 38 consecutive years of dividend increases and the fact that we have averaged 15% annual total shareholder return over the course of the last five years, and hope to 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. It demonstrates the excellent growth opportunities that we have, and also gives you a snapshot in our progress and executing on those opportunities. Really is a great balance of opportunities between utility and non-regulated generation and generation construction, increased coal production to the Company, the Wygen III plant, and then continuing to grow both our oil and gas and energy marketing businesses going forward.

Finally, we have 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 plan 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 have 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 our financing plans into that guidance going forward.

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

Thank you, Dave. I'm excited about joining Black Hills for a number of reasons. One reason is just the changing industry will really create both challenges and opportunities to excel. Another reason is the Aquila acquisition. I look forward to being part of the team that really levers this integration into a much stronger company. And the last reason I will 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 gain insight into how we make money and how do we use financial information for decision-making. And one area that I recognize will be a key focus of mine, will be 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 would be happy to entertain any questions now.

Thank you. (OPERATOR INSTRUCTIONS) Our first question will come from the line of Lasan Johong with RBC Capital Markets. Please go ahead.

Thank you. I wanted to ask you a few questions on E&P capital spending. It is down about $30 million to, it looks like $65 million? Production continues to lag. I understand why that is so in this particular instance. But I want to bring up the issue of divesting this business again. It does seem like there is a lot of difficulties meeting targets, not necessarily due to Black Hills fault because it is third-party operated. And there's a lot of volatility involved ,relative to the underlying utility assets, the utility assets, and there's potential threat of callback situation at the gas utilities. Why do you want to keep on holding onto this asset? Is there something we can do to make this asset more predictable and more attractive to Black Hills shareholders?

Hi Lasan. Yes, the primary issue for us there, and we have talked about this before, is we believe that the assets we hold have significant upside opportunity and value there. And the best way to recognize that value for shareholders is primarily through the drill bit, and we have a great group of properties and a great group of folks to implement the plan to develop those properties. We have had a few -- obviously some delays that we are not particularly pleased with, but still believe overall in the value, in 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? Starting next year you think?

Yes, certainly we hope that as things move forward here and we get some of these questions ironed out -- you know a couple of the properties recently are changing hands. On the non-operated side and the operated side, just gearing up our drilling permit effort. We've had delays, particularly in the Piance Basin, that we would expect things to start improving going forward. Even now, 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.

On the coal side, you said the increased over-burden has shot the operating costs up. Is there any other contributing factor, materials, labor -- I hear 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 is 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 over-burden expenses. The huge one, obviously diesel costs are up considerably. That one's also key driver, particularly when you're looking at hauling all that additional over-burden, 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 over-burden increase itself. We're moving a tremendous amount of additional material.

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

It depends on the contract, Lasan. Our utility coal contracts are essentially cost-based. So that does get passed on. We typically true up that calculation on an annual basis and those costs are included. The coal sales to the affiliates are based on a cos- plus 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 through, some are not. A couple of our larger contracts have -- they are fixed-price, but they have an escalator, and those escalators re essentially a composite 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 thee's 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.

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?

If you look at the numbers, I would say the primary growth drivers in there obviously are the Wygen III plant and the oil and gas.

Right.

And there is some transmission in the utility, which we have talked about those numbers as well. As far as transmission investment,t $40 million number for transmission investment. And then the balance of it is more maintenance type CapEx.

Okay. So that's $65 million for oil and gas, $40 million from [tranney] -- I forgot what the Wygen number was, but those three are your gross CapEx with regards to maintenance?

Yes, for the most part. There are some few minor exceptions to that -- these air-cooled condenser projects and a few little things like that. But the majority of he growth capital is in those three items.

Great. You said -- you gave updated guidance for mid-September. Are you guys coming out to New York to do that or is it going to be web cast, or how do you intend to deliver it? And are you going to do some marketing around the new Aquila acquisition?

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

Great. Thank you.

Your next question comes from the line of Gordon Howald from Calyon Securities.

Good morning. Just following up on Lasan's question. 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 is your policy on hedging E& P and how could that change given the addition of gas-fired generation in Colorado?

Okay. See if I can remember them all here, Gordon. First on the 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 -- 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 have discussed previously that in these what I would call open bid, real competitive situations those typically don't work very well for us. We are not willing to bid the low returns that some of the bidders in those auctions are willing to bid. So we don't typically acquire properties through an open auction process ,and usually don't even bother to try, frankly, unless we have what we think is a real competitive advantage or 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 we are familiar with that we think we can acquire and add value to or if there are properties we already have have an interest in, which are very excellent because you don't have any additional costs associated with those. We are always looking for those. When you are in a price environment where you;you've had real high prices, it is difficult to buy. And certainly when you've had real high prices very recently and prices come down like they have, it is 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 the gas price.

So it's probably not a real time to buy right now. But that doesn't mean there won't be opportunities and we will continue to look for those. 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 from a about 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 years and we hedge 50% to 75% of that/ And we typically layer those hedges in about a quarter at a 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 much as trying to add some stability to the cash flows there. We do a combination and we publish a list of our hedges but we typically do a combination of swaps and puts so we can retain a significant portion of the upside but then also do some swaps to lock in some good prices as well.

That's excellent. Thank you very much.

Thank you.

Next we will go to the line of Michael Worms with BMO Capital. Please go ahead.

Hey, 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 would say the overall impact on earnings is relatively small. Not huge, a small impact but nothing real large. The days are in the Q, but a couple of them were fairly substantive. I think the Ben French one was a few months, but it's a pretty small facility, 20-some megawatts.

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

As far as planned production goes?

For the year.

o, we have not. But we have said 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 segment,t but we will put out the key assumptions, production numbers and prices and things like that.

Fair enough.

Alright, and thank you.

Our next question will go the line of James Bellessa of D.A. Davidson & Co. Please go ahead.

Dave, hi. Jim Bellessa here.

Good morning, Jim.

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 talked about this year we expect a delay. We expect to be -- to be challenging to get to last year's production numbers. But as I said to Lasan, I do expect the production to start improving. We do have rigs running now and we are seeing some good results from our programs.So I would expect 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 yea,r we can be back into a little more normal drill times for 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 indicate there was a July sale from Knox Credits, and I'm wondering if this sale was after the US Court of Appeals vacated the Bush Administration's Clean Air interstate rule, or did you get a 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.

So was that just fortunate or did you know the rule was going to get overturned?

No, we didn't know the rule was going to get overturned. We talked about a couple of those facilities. That one in particular was something that we had taken an impairment charge on last year, and were looking to wind down the operations there. So it made sense to look at anything that we could do to recover some costs to offset the decommissioning costs there, including selling those credit was something we had been looking at for some time.

The year-ago second quarter had also transitioned an integration costs for Aquila in there? Is that correct? 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 spent this year second quarter as well?

Off the top of my head, Jim, I couldn't tell you what we expensed last year. We have had ongoing integration expenses on Aquila since we announced the deal. A lot of the costs, pre-close, have been capitalized. But we really ramped up our expenses in the last six months or so, really after the first 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 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 were really ramping up that hiring to be ready to close and be ready to be fully operational from 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 -- 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 were training or had them trained already by that point in time.

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

Yes, I would say for a period of time we are going to have some expenses in there and they are extra kind of one time expenses. There is a lot of activity goes on. One of the things we have talked about is 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 ads a little extra expense for us as we go forward. We would anticipate that over time as we migrate our current utilities and other businesses onto the same platform from both the customer information and accounting standpoint that we will see some reduction in those costs. But realistically for the rest of this year, in particular, you will see added costs there and a little bit of that lingering on for next year.

Thank you very much.

Yes, thank you.

Next we will go to the line of Oliver King of Zimmer Lucas. Your line is open.

Hey, guys. What kind of ROEs are you seeing at your utilities for ' 08, and how much fuel and 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 have got there for Black Hills Power. And on the Cheyenne Light side,we have disclosed what we were allowed to earn in our last rate case. That number was a 10.9% return on equity with a 53% or 54% equity component -- 54% equity component. But we haven't disclosed the specific stand-alone 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 -- what was in the rate case filing in terms of the savings from Wygen II coming online?

As far as the savings in fuel purchase power?

Yes.

I don't recall that number off the top of my head. 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?

We have 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% debt. Maybe that's 3, 4, 5% debt somewhere in that range, it just kind of depends. But we would anticipate maintaining an overall capital structure consistent with a utility structure. With some of our non-regulated being a little Morris key from a red credit rating perspective we tend to be a little bit lower in those ranges than we might otherwise be in a cap structure basis.

In terms of dividend payout ratio?

It would probably be different going forward than it has been in the past given our significant increase in utility properties. We have said previously in past years, we have talked about it that we like to maintain payout ratios in that 60% range or less. But we haven't talked specifically about it and certainly haven't mentioned it since we have acquired the Aquila utilities. I would say it is stale information at this point.

Thank you very much.

We do have a follow-up with RBC capital markets. Your line is open.

Thank you. Couple quick follow-ups. You mentioned that in Colorado you are looking to do some renewables. Are we talking wind or something else?

Primarily wind.

65 megawatts.

That's the most viable option there. Aquila has a Canon City coal-fired power plant and they are doing a bio-mass, blending it with the coal and getting credit for it there, getting renewables there. The majority of that will be wind. Colorado has a solar requirement as part of the rule. We announced a couple weeks ago we worked with Colorado to install a one megawatt solar facility there that we are installing. But part of the solar requirement has to be on the customer side of the meter, so the addition of that facility will help us meet some of those renewable requirement assists. We are investigating some small solar on our side of the meter as well as that is part of the mandate in Colorado.

What about 25% of Wygen III. Did they buy that at cost or or at premium of what your cost was?

They will be in at cost essentially.

Was that a decision you had no choice in making? Why would you not be able to make it at -- sell it at a price prior than what you purchased it?

As I mentioned earlier, when we renegotiated our all requirements power to MDU's Wyoming load that was one of the provisions of the contract, that they have the right to participate up to 25 megawatts 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. The original version also had an option for them to participate in a future-build power plant and at that point they elected to pass on that. We included the same revision in the renewable of the contract and this time they elected to exercise.

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

I would love to but I don't think they want to sell it. It is the only electric utility property they have in the Western transmission grid. They don't have any generation through which to serve it directly. That's why we serve it for them on an all-requirements basis. With this 25 megawatts of equity ownership, they will be able to serve at least a base load of that contract with the Wygen III resource. We are always looking to acquire additional utilities that fit into our system, and you have to have a willing seller and buyer and that's not always the case.

Sounds like it would be a good opportunity if you could. Thank you very much.

At this time, there are no further questions in queue.

ell, thank you everybody for being on the call this morning. We appreciate your attendance and appreciate your continued interest in Black Hills. We look forward to getting out with some new guidance for ' 08 and 2009 and let you know how we are standing with our future plans now that we have acquired our Aquila properties. Thanks for your attendance today. We appreciate it