Jason Ketchum – Director, IR Tony Cleberg – CFO Dave Emery – Chairman and CEO

Dan Eggers – Credit Suisse Gordon Howald – East Shore Partners Eric Beaumont – Copia Capital Ella Vuernick – RBC Capital Markets James Bellessa – D.A. Davidson Vedula Murti – CDP Michael Worms – BMO Jeff Gildersleeve – Millennium Partners

Thank you, Regina. Good morning, everyone and welcome to the Black Hills Corporation 2010 third quarter earnings call.

With me today are Dave Emery, Chairman and CEO and Tony Cleberg, CFO. Before I turn over the call, I need to remind you that during the course of this call, some of the comments, we make may contain forward-looking statements as defined by the Securities and Exchange Commission and there are a number of uncertainties inherent in such comments.

Although, we believe that our expectations and beliefs are based on reasonable assumptions, actual results may differ materially. We direct you to our earnings release, slide two of the investor presentation on our website and our most recent Form 10-K and Form 10-Q, filed with the Securities and Exchange Commission, for a list of some of the factors that could cause future results to differ materially from our expectations.

I will now turn the call over to Dave Emery.

Thank you, Jason. Good morning, everyone.

Thanks for being with us today. We want to cover several things today.

Obviously, a review of the quarter which I will do, Tony will then cover financials, I’ll speak a little to forward-looking strategic issues and then Tony will provide an update on our guidance for both 2010 and new guidance for 2011. Moving on, some of you, I know, might be following along on the webcast presentation and if you are I will try to cite some page numbers periodically, so you can know where we are at.

Moving on to slide five, we had an excellent third quarter. A substantial improvement in adjusted income from continuing operations as compared to the third quarter of 2009, essentially $0.38 a share this year as compared to $0.07 a share for the same period last year.

Utility results are up nearly $11 million, primarily driven by a gain on sale of a 23% interest in Wygen III plant and also an increase in revenues from several completed rate cases. On the non-regulated energy side, results are up approximately $6 million, driven by improved performance in energy marketing and oil and gas, partially offset by slightly lower coal mining reserves.

Moving on to utility highlights, several key things going on in the utility side of our business in this last quarter. First item is construction is well under way on our utility gas fire and generation facilities for our Colorado Electric utility.

That plant, which is located in Pueblo, Colorado is progressing very well. We’ve made a tremendous amount of progress since construction began in late July.

We have completed four rate cases year-to-date for a total annual revenue increase of approximately $44 million. We recently reached a settlement in an Iowa gas rate case and the Iowa utilities board held a hearing here just in the last week or so related to that settlement, we’re waiting on an order but that would be for another 3.4 million, if they accept the settlement as it was presented to them.

Another notable item related to our southern Colorado utility, is we were successful in extending our franchise agreement with the city of Pueblo in August ,that’s a 20-year extension of that franchise, which is real key, given the huge amount of capital investment, we’re making to serve that utilities generations needs right now. In October, Black Hills power suspended operations on our Osage coal-fired power plant, it’s over 60-year-old facility, a 35-megawatt coal-fired facility in Wyoming and we’ve suspended operations as we notified people at that time.

And then, finally, our smart meter projects are on track, progressing very well. We have over 50% of our meters installed and trying to accelerate as much of that activity into the current year as we possibly can.

Moving on to Non-regulated Energy segment, we are making excellent progress there as well on our 200 mega watt IPP-owned gas fire power plant that will serve our Colorado Electric customers. We also commenced construction that is co-located with our utility plant.

So construction commenced there in July as well. On the energy marketing front, we do have a slight improvement in energy marketing results over the last year.

We had solid unrealized coal marketing margins this quarter, some of which was related in new deals entered into during the quarter and the other was related to increased coal market prices and a long coal position that we had in that business from when we acquired it last quarter. We’ve since locked in most of the margin and placed most of that long contract position that we have, the long coal position.

We increased the crude oil volumes that were marketing at Enserco as well, which contributed to revenue increase and towards the end of the quarter, we added a power and environmental marketing to Enserco’s product portfolio. Marketing activities began early this month.

We’re still waiting on a FERC license to sell physical power. So we don't expect much business there until we get that license.

We’re just continuing on the review of our oil and gas strategy and properties and we’ll continue to update you as that project progresses. On slide eight, corporate highlights, several key thing, we did complete a $200 million public debt issuance earlier in the quarter.

We talked about that before. We’re also making great strides in our integration efforts.

We’ve talked about in the past, we have seven major systems projects we wanted to complete to really unify the old former Colo properties in the prior Black Hills Corporation properties. We are through five of those projects now as of this quarter.

We have two left, both related to our electric utilities SCADA system for the operation of our transmission and distribution system and then an outage management system which we expect to complete early next year. We did reorganize the company in August – late August and that was a previously announced, essentially to try to improve the efficiency of our operation, take a fresh look at the way we operate and realize more benefits between our regulated, non-regulated businesses and also between our electric and gas utilities.

And then yesterday, our board of directors supported our dividend track record with a $0.36 dividend per share for the quarter which continues to be equivalent to an annual rate of a $1.44. With that, I will turn it over to Tony for the update on the financials for the quarter.

Tony.

Thank you, Dave. Good morning.

As Dave indicated since our last quarterly, we have been focused on a number of initiatives, more importantly we have accomplished a number of key milestones that continue to position us for growth. From an earnings standpoint, we are very pleased with the third quarter performance.

Highlights include a nice gain on the Wygen sale. Another highlight was a strong performance by the utility segment reflecting both rate case settlements and cost reductions.

Operating income, excluding the Wygen gain increased 92% in utilities year-over-year. Another highlight was the improved performance of buyer energy marketing segment reflecting solid performance in coal marketing.

Another highlight includes a successful outcome on tax issues. Overall, our operating income, excluding the Wygen gain improved a 147% year-over-year.

On the challenged side, the continued decline in long-term interest rates negatively impacted the interest rate swap during the quarter. But overall, per shoulder quarter, we are very pleased with our performance, particularly pleased with the strength in the utilities.

Moving to slide 10, to the quarterly EPS analysis. This is consistent with past quarters.

We adjust our income from continuing operations to display non-GAAP earnings measure to better communicate the relevant performance. The non-GAAP measure excludes a special gains and losses recorded during each quarter.

This slide displays last five quarters with the third quarter amounts for 2009 in the boxed – two outside boxed columns. Focusing on the column for the 2010 third quarter, the first special item included a $0.23 edition for the non-cash unrealized loss on interest rate swaps.

Since quarter end, there has been a $0.13 recovery already but the long-term rates do remain extraordinarily low. The first special gain item subtracted was the sale of the 23% interest in Wygen III, which netted $0.10 per share and more importantly provided us with $62 million worth of cash.

The second gain item that was subtracted related to an IRS settlement, which amounted to $0.06 per share and will generate $16 million of cash later this year or early next. So with the pluses and minuses, the quarter’s adjusted income from continuing operations was $0.38, which compared to $0.07 in 2009, a very strong improvement from the previous year.

Last year, included in the – was $0.15 for the unrealized loss on the same interest rate swap, only $0.02 addition for integration cost. The trailing four quarters now add to $1.96 for income from continuing operations as adjusted.

Moving on to slide 11, here we display our income statement for the third quarter. Highlights include operating income year-over-year reflecting stronger performance in four of our segments and lower performance in the other two.

I will compare the operating profit performance by segment later. Moving down the income statement, interest expense increased $3.6 million from 2009, reflecting higher interest rates on long-term debt compared to short-term debt.

As you may recall, we placed additional long-term debt in both the fourth quarter of 2009 and in July of this year. Also interest expense increased for the settlements on the interest rate swaps as a result of a larger mark-to-market balance.

Continuing down the income statements, from mark-to-market on interest rate swaps hit a $13.7 million loss in 2010 compared to an $8.7 million loss in 2009. The interest rate swaps relate to the $250 million of debt swaps, which were placed, put in place in 2007 per expected 2008 financing.

The financings were pushed out due to the market meltdown in 2008. Consequently, these swaps were de-designated requiring any mark-to-market changes to be recorded in the income statement.

We chose to leave the swaps in place because of our expected future need for financing the capital projects and future maturities of debt. Continuing down the income statement, the income tax expense in the third quarter, 2010 and 2009 were unusual.

In 2009, the effective rate was 47%. It was high because we had a small net loss causing the tax rate to be less meaningful.

The 2010 income tax reflects a positive income in the third quarter and resulted from a combination of a $2.4 million IRS settlement and the impact of a rate case settlement which reduced our tax expense by $2.2 million. The $2.2 million is included in our adjusted income from continuing operations because it is rate-case related and will provide recurring benefits.

The resulting 2010 GAAP income from continuing operations for the quarter was $12.4 million compared to a loss of 3.9, a much stronger quarter than a year ago. I'm moving to slide 12, just drilling into the income statement.

This displays a comparison of 2010 third quarter to 2009 third quarter for segment revenue and segment operating profit. The operating income increased $8.7 million year-over-year for the electric utilities.

Although the degree day's percentage increased substantially during the quarter compared to the same quarter last year, the absolute number of degree days remained moderate. So we did not see an impact in the year-over- year comparison.

In fact, mega watts sold during the quarter declined by 2% from 2009. So the profitability improvements we saw were driven by rate case settlements and continued cost improvements.

Also, we saw softness in the off-system sales compared to 2009 primarily in terms of a 7% decline in pricing. However, margins increased by $1.9 million due to lower resource costs, driven by a change in the stacking methodology as a result of a rate case settlement.

Moving to gas utility segment, we have solid performance for the shoulder quarter with operating income increasing $7.4 million. The largest driver in the improvement was the improved cost recovery due to settling the rate case in Nebraska and implementing interim rates in Iowa.

Dakota sold to residential and commercial customers were flat in 2010 compared to 2009. So both in the electric and the gas utilities, the improvements in operating profit was driven by the rate case settlements and cost efficiencies.

Moving to oil and gas performance, during the quarter, we saw our average hedge prices improve year-over-year. Average hedge prices received, oil improved by 34% and for natural gas by 3%.

Our production volumes for oil increased year-over-year by 10%. While the production volumes for the natural gas decreased by 11%.

That combination, along with improved operating cost efficiencies continued to be an improvement in operating income of 1.5 million year-over-year. Moving to the next segment, power generation, we saw a slight decline in performance of $500,000 during the quarter compared to 2009.

This segment is impacted by non-capitalized costs related to the IPP construction at Colorado Electric. As mentioned before, this segment absorbs expenses now but the first revenue is projected in 2012 for its Colorado Electric IPP.

Moving to the next segment, coal mining, revenue declined by 6% as a result of a 6% decline in tons sold and flat prices. The lower volume resulted from lower tonnage to other utilities, partially offset by increased tonnage at Wygen III.

Operating cost increase reflecting a 7% increase in the overburden removal. Operating income declined by 900,000 on a combination of lower sales volume and increased operating costs.

For the next segment, energy marketing, the operating income improved year-over-year by 8.4 million. Third quarter operating income of $2.5 million primarily represents unrealized mark-to-market gains of 9.7 offset by related incentive compensation and G&A.

Over half of the mark-to-market gain was driven by coal marketing as a result of new positions entered into during the quarter and long positions with rising coal prices. At quarter end, we had approximately a 1.5 million tons of fix price length whereas we currently have 200,000 tons which reduces our exposure to future price changes.

Almost all of the remaining run realized mark-to-market gains relates to natural gas and include price movements for the storage for proprietary trading and transportation. The market conditions for natural gas continue to challenge this business segment in terms of tight basis spread, both seasonal and locational and in terms of low prices which reduces the margin opportunities, all of which contributed to a realized margin loss of 700,000 in the quarter.

We feel positive about the addition of coal marketing and power environmental marketing, which allows to diversify our energy marketing business and allows us to leverage our knowledge of existing assets and our knowledge of existing operations around natural gas, crude oil, coal, power and environmental product. Moving to the corporate level, we had a nominal improvement.

So again looking at operating income, we were very pleased with the improvements. Now, moving to slide 13.

We have improved the balance sheet and some of these, we’ve talked about before the $62 million in cash at Wygen III, the completed notes for the 10 year, five and seven-eighth percent unsecured note. Also, during the quarter, we contributed $30 million for the defined benefit – defined pension benefit plan.

And the reason is, is because this $30 million was due during the next year, from now until next September. So by making the contribution now, we actually are able to reduce our pension expense for next year.

The last item here to mention is the IRS settlement which provides 16 million bucks either later this year or early next year. Moving to slide 14, here we display our capital structure.

In the far right column, you can see our current debt and equity. Our debt to capitalization increased from 53% to 55% during the quarter, our net depth capitalization increased to 54% from 52%.

During the quarter, the spending on capital projects was a strong edition and also the $30 million contribution to the pension plan. With a new bonus depreciation that was signed into law during the quarter, we planned to accelerate some capital expenditures that were planned for first quarter next year and pulled those into the first quarter of 2010.

We expect our cash tax rate to be very low this year and 2010 because of the bonus depreciation. As we have mentioned in the past, we expect to issue equity later this year or next to maintain a strong capital structure and target to achieve a net debt capital of 55% or less upon completion of the generation projects in Colorado.

So we could bump up over that 5% as we are going here but our target is to make sure that we are back at 55% or less by the time, we go live with the project at the end of 2011. So with those comments on quarterly financial performance, I will turn it back to Dave.

Thank you, Tony. Moving on to slide 16 and looking to the future here, we continue to be well positioned for growth.

We’ve a strong well defined capital spending plan. As Tony mentioned still a strong balance sheet and demonstrated access to the capital market.

Tony also alluded to the fact that we are increasing our projected 2010 capital spending to about $512 million. Essentially accelerating some planned 2011 spending into 2010 in order to take advantage of some of the bonus depreciation tax benefits.

Slide 17 outlines our major growth capital investments. We’ve shown you this slide for a couple of years now.

This year and next year, we are looking at $570 million to $600 million of investments in growth capital projects, not including our base maintenance capital or those types of expenditures, so exciting growth opportunities that we’ve continued to talk about in the last couple of years. Slide 18 just outlines a timeline of events and major projects.

We continue to update this every quarter based on new news and updates in each of the things that we have already identified on this schedule. Moving on to slide 19, as I said earlier, two Colorado generation projects are progressing very well, both are on schedule and on budget.

The Colorado Electric utility generation project, a 180 megawatts, $250 million to $260 million project, we are really excited about the progress to date. We are getting close to having all of our procurement construction contracts rewarded and we’ve spent $131 million to date.

Notably, our first turbine and generator step-up transformer arrived last week and were delivered to the site and set in place. So real excited about that progress and the second turbine will soon be on the way, so exciting progress.

Slide 20 shows a few picture of our construction project there. And as you can see, we’ve made huge progress in the three months since the receipt of our air permit on July 22nd.

Things are going very, very well, as we expect. Slide 21, an update on the IPP project for Colorado Electric, that's the 200 megawatt, $240 million to $265 million project.

We are not quite as far along on that project as we’re on the utility phase or the project simply because we started the IPP portion a little bit later. We are making very good progress on procurement and construction contracts and we have spent nearly $105 million to date on that project.

Construction is well underway. We are anticipating delivery of turbines there occurring in the first quarter of 2011, again both projects on schedule, to be completed in service, in serving our Colorado Electric customers by January 1, 2012.

Slide 22 is a regulatory update. As I said before, a very good regulatory successes so far this year.

We’ve completed four cases year-to-date with an annual revenue increase of $44.5 million. We have the one active case in Iowa, where we have a settlement proposed and awaiting an order from the Iowa utilities board.

Slide 23 is the legislation and regulation update and there are really three items that deserve some discussion. Two of those relate to bills past this year in the Colorado state legislature and the third relates to potential new emissions rules and regulations from the U.S.

Environmental Protection Agency. First, the Colorado House Bill 1001 passed this last legislative session in Colorado.

The increased the renewable energy standard in Colorado from a 20% renewables by 2020 from the previous – or 30%, I'm sorry, by 2020 from the previous 20%. We intend to file our renewable compliance plan in the next week or so with the Colorado PUC.

It will include a combination of wind and solar resources and we hope to be able to rate base a portion of those related investments. Our final recommendations will be included in the comprehensive electric resource plan that we intend to file with the Colorado PUC next fall, probably in October.

It is worth noting that we recently suspended our solar rebate program for customers in Colorado. Under that program, we provided rebates to customers who installed solar units on their home or businesses.

The Colorado PUC allowed us to recover those costs, the cost of those rebates through a charge to all of our customers equal to about 2% of our total customer revenues. Given that, we have nearly $11 million in rebates that we have yet to recover and collect from our customers, we believe it will take several years for us to collect those outstanding rebate amounts, given that current 2% limitation.

So continuing to offer that program would simply extend the time required for our customers to fund the program. So we felt it was prudent to suspend the program until we could thoroughly assess the long-term customer impacts of continuing it.

Second piece of legislation was Colorado House Bill 1365, that requires investors and utilities in Colorado to reduce emissions from coal fire power plants. The law provides an incentive to retire coal fire plants, essentially by allowing the rate basing of the replacement generation resources.

We have one coal-fired power plant in Colorado, the WN Clark plant which is a 42 megawatt facility located in Canon city and it was constructed in the 1950s. In August, we submitted a plan to the Colorado PUC, stating that we were evaluating two options for that plant.

One was possibly converting it to a biomass facility and the second option was replacing it with a natural gas-fired facility. Today, we intend to file testimony with the Colorado PUC, which recommends the closure of the Clark plant in the next several years, essentially stating that converting the plant to biomass is not a viable option for customers.

Under the provisions of that legislation, we intend to replace the Clark plant with utility owned generation and we will prepare an electric resource plan, which we intend to file with the Colorado PUC in February, that specifically deals with the capacity shortfall we will have upon the retirement of Clark. One of the options, we will consider in that resource plan is adding a third GE LMS100 turban to our Pueblo generation site, which – as we’ve talked about before is currently under construction.

We have adequate space and have plan for our future expansion slot at that facility. So that among other options will be evaluated as part of our resource plan and filed in February.

Finally on a regulation front, the EPA is proceeding with several new environmental rules that could substantially increase costs to our customers. Notably, in April, the EPA published or proposed emission standards for hazardous air pollutants from major sources, which seeks to impose strict limits on mercury, hydrogen chloride, carbon monoxide, particulate matter and other emissions.

Those standards include a rule specifically relating to industrial and commercial boiler, maximum available control technology. That orders expected to take effect on January 16 of 20011 and provide only three years to comply with the new, much lower emissions standards.

As far as how that impact Black Hills, all of our coal-fired facilities that have been constructed since the 1970s, are equipped with essentially state-of-the-art emissions control and should not be impacted significantly by the new rule. However, we do have four small, older coal-fired power plants, with a total capacity of about 124 mega watts that would be negatively impacted by the proposed rule, assuming it is enacted as it is currently written.

Those four plants are Black Hills Powers Ben French plants in Rapid City, South Dakota. There’s Black Hills Powers also each plant in Wyoming and as I noted previously we have already suspended operation, at least temporary at that facility.

Black Hills Power’s Neil Simpson I plant in Wyoming and Black Hills Energy’s Clark facility in Canon City, Colorado which I also just mentioned. Once the rule – the final rule is published and enacted, we will determine whether to suspend operations at those facilities or attempt to upgrade them to meet the new emissions standards.

This obviously will require a real thorough analysis of our options, financial modeling of the business and customer impacts and discussions with the Public Utilities Commissioners in the states of South Dakota, Wyoming and Colorado. Under either scenario, either the upgrade or the retirement and replacement, I would expect substantial increased cost to customers resulting from this new rule.

Moving on to slide 24 on oil and gas, beginning last quarter, we have been attempting to provide additional information relating to our oil and gas activities. Particularly in response to questions we received from investors and analysts.

Last quarter we provided the description of our properties and activities in the Williston Basin of North Dakota and Montana, specifically related to the Bakken oil shale play. This quarter we have updated that information and also added a discussion related to our current and planned activity in the San Juan Basin in New Mexico and the Piceance Basin in Colorado.

In those two basins we currently produce a total of nearly 17 million cubic feet of natural gas. We operate all of that production.

And it's from several different producing horizons. But in addition to the primary producing zones, our current acreage position is underlane by the Mancos shale formation.

And the Mancos is the stratigraphic equivalent of the Mesaverde formation which has been attracting a lot of positive attention in press due to submerged successful horizontal wells in Northeastern Colorado and Southeastern Wyoming. Other operator, in both the San Juan and Piceance Basins have been drilling horizontal Mancos formation wells near our acreage positions there.

And we intend to conduct some limited testing of the Mancos potential in both of our basins and our position in those basins late this year and throughout next year to better evaluate the Mancos potential on our acreage blocks. We believe, currently that we have nearly 63,000 net acres that would be perspective for the Mancos in the event that our testing proves successful.

Nearly all of that acreage is held by production, meaning that the leases will not expire as long as we maintain production and as I noted earlier, we have production from other zones besides the Mancos, so we really don't have to be driven by lease explorations or anything as far as drilling goes. We can take our time and be careful about investing and evaluate success before we would, potentially ramp up any kind of a drilling operation on the larger scale, depending on how the testing and evaluation process goes.

We do hope and are hopeful that by the end of 2011, we’ll have a good idea of true Mancos potential on our acreage in both the San Juan and Piceance basin. Moving on to slide 25, our strategy score card, it's been updated this last quarter to note the completion of several key goals that we finished during the third quarter, so we are very pleased with that progress.

Finally on slide 26, in summary of the quarter, we had an excellent quarter. As Tony mentioned, very strong financial results for what is typically a shoulder quarter for us.

Our gross spendings progressing very well. We continue to demonstrate access to the capital market, which is very important when you're in a growth mode like we are.

We have had very strong results from several utility rate cases, our non-regulated energy businesses are showing improvement over last year. And we continued our solid track record of paying a great dividend for shareholders.

So that concludes the discussion of the quarter. And I will turn it back to Tony to talk about a revision in our 2010 earnings guidance and new guidance for 2011.

Tony?

Thank you, Dave. As you saw, I'm on slide 28 – as you saw in the press release, we tightened our 2010 guidance, excluding special items to the range of $1.80 to $1.95.

So far in October we have seen continued price decline in natural gas. And this – which impact both our oil and gas segment, our off-system sales and our energy marketing segment.

So we hope to improve year-over-year but we are being very cautious in our guidance here, because of the low natural gas prices. I might add that our expected operating performance for the fourth quarter is an improvement in the electric utilities and actually a decline in our non-regulated segments.

Looking ahead, on slide 29, for 2011, as you have seen in our press release, we are projecting a range of $1.90 to $2.15. We’ve listed a number of major assumptions in the press release and I don't plan to repeat them here.

But realizing the difficulty for other parties to estimate energy marketing earnings, we would like to share with you how we think about this segment in our guidance. We only expect modest improvement in this segment in 2011, driven by improvements in marketing coal, oil and the addition of environmental and power marketing.

That combined with a natural gas market similar to 2010. In addition with bonus depreciation for assets acquired in 2010 and placed in service by the end of 2011, we expect a very low cash tax rate next year.

So the assumed equity of 125 to 150 million is expected to be sufficient to complete the Colorado generation build out and have the appropriate debt-to-cap ratios by year-end. So with that guidance, I will turn it back to Dave.

We will be happy to entertain any questions if anyone has any.

Hey, good morning guys.

Good morning, Dan.

I guess my – your first question is on the CapEx increase for this year, looks like that’s all at your power gen, so I assume that’s Colorado based. Can you just give me a little color on what’s getting that CapEx up?

Yeah, it’s absolutely what we are trying to do, Dan, is just accelerate delivery of some of the major components for the facility, turbines, generations step-up transformers things like that. We need to take title to them this year and have them in service next year in order to qualify for the bonus depreciation, so anything that we can accelerate and then most of that really in our IPP project, a lot of it because it's a little farther behind on the schedule on the utility plant and that's essentially most of the difference.

We are looking at every business and things like our AMI project and other things if we can accelerate a little to 2010. We are trying to do that but that's the primary driver.

Okay. And then how much bonus depreciation are you guys expecting to get out of this year, next year?

If we were to quantify how much cash is coming in?

I think we are going to be very, very low cash tax rate. Sort of the map on it, Dan, is we have about $200 million that’s going to go into play this year.

So it's 50% turns 35%. And then if you look at next year and say that we will probably have around $300million that we have this year that will be placed into service next year.

And, again, if you go through the math of 50% turns 35%, those are the kind of numbers that we are looking at. And that might actually add to a little more than what we have for federal income tax.

So the only place we will really have tax is probably at the state level.

Okay. And then the comments on the Colorado renewable energy standard efforts, I guess it's a series of dates.

We are going to have new plans on indifferent resource needs in Colorado, so you are going to be busy there. But on the renewable site, is there a feasible way to get anywhere near that 30% level as you guys are also confronted with a 3% rate cap, given where your rates are today?

I would say it will be increasingly challenging as that threshold continues to increase towards the 30% number and stay underneath that rate limitation. It depends on a lot of other factors, what happens to the price of natural gas, what happens related to some of this other generation, for example, retirements of plants and other things?

All those factor into what your total cost is, which then sets the limit on how much you can spend on renewables. So difficult to give a definitive answer, but I do think you're on track and that it will be real challenging in the out-years as you creep up on that 30% number to do that and stay under that rate cap.

So it may indeed be a little less than that.

Okay. And I guess one last question.

If I look at the 2011 guidance, you've got rate cases done pretty much across the board that all should map out pretty clearly. The power generation and the coalmining businesses are going to be – should be pretty straightforward as far as contractual nature.

Is the swing in numbers next year really a function of where Enserco comes out relative to where we're starting today?

Dan, what I mentioned was that we are not expecting much improvement out of energy marketing next year.

Okay.

So what we're really seeing is the rate cases taking hold for the entire year and in effect our utilities improving strongly. And the non-regulated with natural gas prices down in our oil and gas segment, we're not seeing a lot of help from that side of the business.

Okay. All right.

Thank you, guys.

You bet. Thank you.

Good morning, Gordon.

Good morning. How are you?

Great. Thank you.

Good. Jim touched on this question, but on the Colorado resource plant, how much of the wind and solar resources do you believe you'd be able to rate base?

And maybe a better way to question this is, is there any precedent from utilities thus far in Colorado on that front?

Well, not a whole lot. We are kind of cautiously optimistic that maybe we can justify the rate basing say half of it or so, Gordon.

But it's really – you have to work your way through process. So we'll have to file the resource plan, identify specific recommendations for projects, probably go through the process of potentially some competitive bidding analysis of rate basing versus competitive bids and very similar to the process we went through with the gas-fired generation for Pueblo.

In that case we were successful essentially having half of it utility-owned and then the other half was contracted and we were able to bid in our own resources on the contracted portion. We would try to do something similar to that.

It's just very difficult to predict exactly where you're going to come out and there is not a lot of precedent yet as to how the Colorado Commission is going to handle those facilities on the renewable side, particularly.

Sure. Understood.

A follow-up on that, how did the commission in Colorado feel about you repealing the tax incentive offering that you had for solar insulation? But I understand the rationale, but economics and politics don't always go hand in hand.

Got an issue?

We're just in the process of – No, I think they were supportive. We met with them before we suspended the program and explained that we just think it's time to evaluate the impact on customers and I don't think there was any dramatic reaction one way or another.

I think they appreciate our, kind of, careful cautious approach where we are considering our customer interests first. Clearly though in Colorado there's a big push for increasing renewables.

So we are hearing from some folks about wanting us to reinitiate that program, as you might expect.

Sure. And I understand the rationale that for sure.

I appreciate it. Thanks, guys.

You bet. Thank you.

Good morning, Dave. Good morning, Tony, How are you?

Good morning. Eric.

A couple of quick questions. One, just kind of a housekeeping how should I think about the AFUDC flowing for the two plants both this year and next year as far as that impact goes?

The AFUDC will increase quite a bit next year on the utility from quarter-over-quarter basis. On the IPP, we don't have it – so in effect we are just capitalizing interest there.

Okay. And LDCs looked great this quarter.

One question I really wanted to look at it with all the rate cases you guys did a good job getting good result, has there been a significant shift of few fixed components versus variable on those and did that help drive kind of the shoulder period? Or is it just simply pure rates?

Yeah. Most of that – we continue to try to increase the fixed component in the rate cases that we file, Eric.

I would say we are making kind of slow gradual progress, so I don't think that's a huge driver. But it is something we are continuing to work on.

We are also continuing to work on thing like capital additions trackers or integrity capital trackers. We requested one of those in Iowa.

It's not final that we are going to get it yet, but continuing to do thing to improve our regulatory lag and things like that and promoting energy efficiency programs as well.

Okay. Great.

And one last thing, just with regards to the guidance two things, obviously you been for '011, AFUDC you consulted with (inaudible) and on the equity you said 125 to 150 million, I think you said you were assuming a mid-year issuance '11 is that accurate?

That's what we put in our model.

Okay. So obviously you'll time as market conditions allow but for guidance assumptions we should assume mid-year.

Yes.

Okay. Perfect.

Thank you, guys.

Good morning. Some of my questions have been answered, but if I could turn, please, to oil and gas.

In 2011, it looks like your assumptions included somewhat higher gas price, however pretty constant CapEx at that division and fairly flat to maybe at the high end a little bit higher production guidance. Could you comment a little about that?

Yeah, we've said – for the last couple of years, Ella that in this low-price environment, particularly on the natural gas side. We were only going do projects that we thought made real good economic sense and we are in a position where most of our acreage is held by production so we are just not really doing a whole lot of gas drilling.

A little bit as we talked about this Mancos Shale testing a few things like that. But real measured in our capital deployment and a fairly large portion of our planned capital will be related to oil plays such as the Bakken oil play in the Williston Basin in North Dakota.

But, we've said for a couple years with prices being somewhat depressed and all the construction we have going on, we are really trying to limit spending at E&P to approximate our cash flow there. So, in that $40 million kind of neighborhood that's not a hard and fast rule, and if we found a really good project, we would potentially entertain the concept of doing it anyway but for planning purposes that's what we are looking at, doing some testing that really sets us up for future as gas prices improve and we have a significant increase in cash flows from operations upon completion of the Colorado power plant.

Okay. Great.

Thank you. And then turning to coal, I see that there's still some continued customer plant outages, do you have any visible in to how that might play out for the next year?

Yeah. Well, we don't have the anticipation of large outages – at least unplanned outages like we are having this year.

There's been some thing going on at, remote customer facilities outages, long duration outages and even lower demand for power in some of their territories where they are just not running their plants as much. We’re predicting a little more of a normal year next year with planned outages counted in our numbers.

Great. Thank you.

The rest of my questions have been answered.

All right. Thank you.

Good morning.

Hi, Jim.

I have, perhaps the wrong figures that I was working with on the gain on the sale of the Wygen III plant. Can you tell us what the dollar amount or the gain was pre-tax and then what tax rate you used or I guess, I can calculate it because you've identified that was a $4.1 million after tax?

It's $6.2 million pre-tax.

Okay. Thank you very much.

We have that rate, yeah.

Good morning.

Hi, Vedula.

A couple of things, one, with regards to the sanction of equity, should we assume this is straight-forward common stock or has any thoughts been given to a mix of common and hybrid?

This is Tony. We are considering all kinds of options of how we do an equity issuance.

So, whatever is sort of what we feel the lowest cost approach.

Okay. And if we take a look forward to ‘10 and ‘11, I think, your slide show that you, capital expenditures were about $1 billion and $1.1 billion.

If we were to move forward given the growth opportunity that you cited here, what – what should we be kind of thinking about ballpark ventures ongoing CapEx in the next couple of years and in the – in throughout years of '12 and '13?

So far we haven't been really specific about some of those plans we are doing based on some of these regulations in particular, I mean, what we may end up doing or coal – these coal plants or the potential House. Bill 1365 in Colorado, renewables in Colorado, really quite a few moving pieces to that.

So until we get a better hand on that, probably not comfortable putting numbers out past that '12, '13 timeframe.

And for us to get a better handle we really have to understand exactly how this is going to play out. We know what the legislation is, but we just have to make sure we understand how the rest of it plays out.

And a lot of its going to be contingent on resource planning. I mean, we’re – we will have to file, as I mentioned before really two plans, one kind of an abbreviated one in Colorado in February and then a full-blown plan in October or so in Colorado.

But we're also coming up on the time to file a resource plans for both Black Hills power in Cheyenne Light, as we look at those future customer needs and customer growth, which we are having in some of our territories. And we're going to have to reassess capital needs there as well.

So until we really work our way through this 2011 resource planning process, big moving target as far as how much capital that could require. We are positive that we do think we're going to have some projects come out of the process but very difficult, at this point to ascertain how big they will be and what they will cost.

All right. Thank you.

You bet. Thank you.

Hi. Good morning, guys.

Good morning.

Good morning, Mike.

Just a quick question. With regard to the equity offering pushed out to the midpoint of 2011, just wondering what's allowing to you do that because it's a six or seven-month delay from the end of the year and just trying to get a little color as to what is driving the pushout?

Well, I think, if you put it in your model that way, I think that helps, put us into the guidance range that we have proposed. There are various options that we could employee, such as a forward or some type of transaction like that.

So there's different types of transactions that make that a reasonable assumption.

The only bottom line Mike is, in order to give you a good guidance number we have to have an assumption that.

Yeah.

I mean it doesn't mean that that's for sure when we're going to issue, if market conditions are right we could go earlier. We would go a little bit later.

I think one point is that it is possible and Tony mentioned this earlier that, I mean, our debt could creep up to over that 55% number as long as we are comfortable that we are ready to go and issue equity and we've got our financing plans in order. So, we are not necessarily driven to say, okay, it's 55% today.

So we have to go issue right now. But we've talked about that a little bit, that during construction here that number may creep up just a little bit higher than that.

So we don't have a real definitive time but realistically we're going to have to do it sometime in 2011, before the end of '11 and probably, that mid-year assumption was basically as good as I need to put out in order to calculate a guidance number.

Okay. Fair enough.

See you in a couple days.

All right. Thank you.

Thank you.

Good morning. How are you?

Good, Jeff.

Good morning, Jeff.

Just looking at the lament guidance slide again. The – it says you've assumed a modest increase in energy marketing, but then to earlier question, you said you thought it would be pretty flat, maybe I misunderstood is it?

Yeah. It's how you describe it.

I think at some place between flat and modest.

Okay, okay. But not a big increase?

No.

We earlier, we said we expect a little bit of improvement early in the coal and power, marketing and environmental side and then I think Tony's specific comment was gas we just expected to be flat. We really didn't expect any improvement in gas market conditions.

Right. I know in the past you've had storage contracts and things, so you have good visibility to at least part of the earnings and marketing.

Any color on sort of how – what percentage you have visibility on at this point of that forecast?

Yeah. We don't have the color on the forward look.

I think in the Q we'll have statistics on kind of what we've realized and unrealized for earnings from the various pieces of that business that we typically provide some update on. That should be coming out here in next week.

Next week.

Okay. Good.

And then, now to circle back again, but on the equity assumption for financial modeling, you said mid '11. I think, Tony, before you said, sorry, you're still looking end of this year, early '11?

That's right.

Okay. Okay.

Then – okay, so that's sort of the same as what you've said before?

Yes.

Okay. Thank you.

All right. Thank you, Jeff.

All right. Well, thank you, everybody.

We appreciate your attention to Black Hills and for your participation on the call today. As we said before, we're excited about the quarter, it was a good one, and are also very excited about our future prospect.

So thanks for your attendance today and thanks for your interest in Black Hills.