Black Hills Corp (BKH) 2011 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Black Hills Corporation 2011 third quarter earnings conference call. My name is Janayda, and I will be your coordinator for today. At this time, all participants are in a listen-only mode. Following the prepared remarks, there will be a question-and-answer session. (Operator Instructions).

As a reminder, this conference is being recorded for replay purposes. I would now like to turn the presentation over to Mr. Jerome Nichols, Director of Investor Relations of Black Hills Corporation. Please proceed, sir.

Thank you, Janayda. Good morning, everyone, and welcome to the Black Hills Corporation 2011 third quarter earnings call. With me today are David Emery, Chairman, President, and Chief Executive Officer, and Tony Cleberg, Executive Vice President and Chief Financial Officer.

Before I turn 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 could cause future results to differ materially from our expectations.

I will now turn the call over to David Emery.

Thank you, Jerome. Good morning, everyone. Thanks for joining us. For those of you following along on the webcast presentation, I will be starting my comments on slide five.

Third quarter net income as adjusted was $0.37 a share, comparable to $0.38 a share for the third quarter in 2010 . Utility net income was up about $2.6 million compared to the third quarter of last year, largely driven by rate cases which were implemented throughout 2010. On the Non-Regulated Energy side, net income was down $2.7 million compared to the third quarter of last year. That decrease largely the result of continued challenges in our Coal Mining and Energy Marketing segments.

Moving on to slide six, some key operational highlights for the quarter,some of which I'll discuss and expand upon a little later in the presentation. Our two power plants which are under construction near Pueblo, Colorado, a $487 million project, is on budget and on schedule for a January 1 commercial operations date. The rate case related to that plant construction is under way and Commission hearings commenced on the 1st of November,earlier this week.

Several other Utility growth initiatives are progressing. Our request to add a third utility-owned turbine at the Pueblo Airport generation site; we reached a tentative settlement there and a settlement hearing was held last week. We hope to have an order on that project in early December. The Colorado PUC has approved our request to construct and own 50% of a wind project in Colorado.

And then finally, earlier this week, Cheyenne Light and Black Hills Power filed a joint request for a Certificate of Public Convenience and Necessity with the Wyoming Public Service Commission to build a 132 megawatt natural gas-fired project in Cheyenne at a cost of $237 million.

In our Oil and Gas segment, we're very excited about the initial production test results of our San Juan Basin horizontal Mancos formation shale gas test well. We'll elaborate on that a little more later.

On November 1st, we settled the equity forward that we entered into about a year ago by issuing 4.4 million shares and receiving $120 million in net proceeds. We also, during the quarter, extended a term loan for two more years on similar terms at $100 million. And finally, the Board of Directors approved a quarterly dividend of $0.365, consistent with our $1.46 pace for this year.

Now I'll turn it over to Tony Cleberg to review the financial results for the quarter.

Thank you, Dave. Good morning. As Dave indicated, our overall third quarter financial performance on an as-adjusted basis was comparable with the prior year. But as a reminder, last year our third quarter operating income increased over 145% from 2009,so we're pleased we were able to almost match last year's performance.

This year's third quarter recurring operating income includes a 12% increase for our Utilities from 2010, offset by a decline in our Non-Regulated segments. We continue to be encouraged by the improvement we see in our Utility segments. On a later slide, I'll address the performance drivers by segment.

Moving to the EPS analysis on slide 8, consistent with prior periods, we adjusted our net income to display a non-GAAP earnings measure that we feel communicates our relevant performance. Special gain and loss items are excluded to compute net income or EPS as adjusted. This slide displays the last five quarters.

The only special item that we had in third quarter of 2011 was the addition of a $0.63 for a non-cash unrealized mark-to-market loss on our interest rate swaps. So with that adjustment, the quarter's EPS as adjusted was $0.37 compared to $0.38.

Looking at last year's third quarter, the reconciliation included a $0.23 addition for the unrealized mark-to-market loss on the same interest rate swaps, a reduction for a gain on sale of assets of $0.10 and a reduction for an IRS settlement of $0.06. So now for the fourth quarter's trailing, our EPS as adjusted is $1.69.

Slide 9 displays our income statement for the third quarter of 2011 and 2010. Our GAAP EPS declined by $0.59 driven by the mark-to-market decline of $38 million on the interest rate swaps, offset by a slight improvement in an interest expense of $1 million.

The operating income drivers will be discussed in more detail on a later slide, but in summary, it reflects improved performance in the Utilities, offset by a decline in Non-Regulated groups. So we're about flat year-over-year in operating income. The slight improvement in interest expense reflects increased capitalization of interest on our construction projects.

Continuing down the income statement, the third quarter tax rate of 44% compares to 13% in 2010. Both years recorded tax benefits versus tax expense, even though last year third quarter we had a pretax income.

Two items that positively impacted last year's third quarter include an IRS settlement and a regulated requirement related to a rate settlement that required us to flow through the tax benefit related to certain capital expenditures that we had previously capitalized for tax purposes. This had the impact of lowering our tax rate.

Now, if you exclude the impact of the mark-to-market losses in both years, and you exclude last year's tax impact of the IRS settlement and the catch-up for the flow-through impact, the tax rate in both years for the third quarter would be about 27%,and we expect to be in the 27% to 30% range for the total year of 2011.

Moving to the bottom line, third quarter GAAP EPS for 2011 was a loss of $0.27 compared to an income of $0.32 in 2010.

Looking closer at the operating income, slide 10 displays the segment roll-up of revenue and operating income for the third quarters. The Electric Utilities recurring operating income in the quarter improved by $5 million, or 18% year-over-year, reflecting the benefits of earning returns on increased rate base and increased retail volumes. You'll note that for the recurring income comparability, we exclude the gain on sale in both the 2010 and 2011.

Overall, the megawatts sold during the quarter declined by 1% compared to 2010, driven by lower off-systems sales. The major positive was an increase of 2.7% in the retail megawatts sold, driven by unusually warm weather in July and August.

The megawatts sold for the off-system power sales decreased by 13%, while the margins improved, resulting in an increase in about $300,000 in operating income compared to 2010. The off-system sales margins continue to be low as a result of the abundance of energy in the region and low power prices that are influenced by low cost of natural gas.

Moving to the Gas Utilities, for a shoulder quarter, we achieved good performance. The operating income declined by $4 million from last year. Volumes increased slightly, but expenses increased even more with higher wages and benefits as a result of union settlements. This was partially offset by a $1.3 million improvement in workers' compensation where we we've made great progress in 2011 on safety, which has a positive impact on the worker comp claims.

The decatherms sold during the quarter for residential/commercial/industrial increased by 4%. The transport volumes increased by 5%, but these are very low margin sales.

Moving to Oil and Gas, the performance was similar to last year. Our operating income and production declined slightly compared to 2010. Oil prices received were up slightly. Gas prices were down. From a cost perspective, small increases in DDNA were almost offset by decreases in O&M expenses.

The slightly lower oil volumes in the quarter resulted from natural production declines from producing properties, offset by production increases in the Bakken drilling program,which experienced some delays at the beginning of the third quarter.

The next segment, Power Generation, decreased by $700,000 in operating income from 2010. The decrease was attributable to higher costs for maintenance, transmission, coal, and corporate allocations. The corporate allocation increase relates to the increasing asset for the Colorado IP and consequently an increased allocation.

Moving to the next segment, Coal Mining, the operating income declined by $1.7 million from 2010 as a result of higher mining costs. We've had various cost issues at the mine this year, but we've made sequential progress in the third quarter and reduced the operating loss by $600,000 compared to second quarter.

In July, we changed the operation of the mine to a 24/7 schedule from a daily seven schedule. We're seeing efficiency in mining operations. In effect, by mining the same amount of tons in 24 hours versus eight hours, you have less start-up time and a lot less wait time and other types of experiences in the mining operation.

For Energy Marketing, our next segment, we reported operating income of $1.1 million for the quarter, a decline of $1.4 million from 2010. Our natural gas and crude oil commodities performed well during the quarter, and the power and coal commodities incurred losses. We still expect strong performance in the fourth quarter from Energy Marketing. Some deals expected in the third quarter had actually slipped into October,so we have that visibility.

Moving to the Capital Structure slide, slide 11 shows our capitalization. We feel our present capital structure supports our needs through 2011 and 2012. Our net debt to capitalization ratio at quarter end was 60% but on a pro forma basis, assuming the equity forward shares were delivered at quarter end, our net debt to capitalization was 54%, so capital structure is in good shape. As Dave mentioned, we delivered the equity forward shares on last Tuesday.

Moving to the Guidance section of the presentation, we are updating our guidance for 2011 and announcing our guidance for 2012. Slide 13 lists some of the major assumptions we've had around 2011 guidance. Basically, we have three quarters completed and we are narrowing our previous EPS guidance range to $1.70 to $1.85. This assumes normal weather and no unusual events such as those described in our 10-K risk factors.

This range is based on net income as adjusted , so there's no impact for special items such as mark-to-market on the interest rate swaps. I might add that we expect our Non-Regulated segments to deliver much stronger performance in Q4 than we've seen all year. Our Energy Marketing segment, based on transactions we're seeing, we expect the total year earnings to exceed the $3.3 million that we saw in 2010.

Looking ahead, slide 14 lists our primary assumptions we've made regarding the 2012 guidance. Our projected EPS range for 2012 is $2.15 to $2.40, exclusive of special items. We have made assumptions about rate case settlements, normal weather, plan availability, oil and gas prices, production rates, and other factors.

As a reminder, our Gas Utilities performance has been particularly strong in 2010 and 2011 due to unusually cold weather in our territories. Our guidance uses normal weather assumptions.

Overall, we expect significant improvement in our Non-Regulated segments, driven by power generation for the Colorado IPP and strong improvement in our other Non-regulated segments. Realizing the difficulty for others to estimate Energy Marketing earnings, we expect the improved performance we're forecasting for 2011 fourth quarter to continue. So we expect Energy Marketing earnings to at least double in 2012.

So to conclude, we are pleased with our overall financial performance for the third quarter, particularly the continued strengthening in our Electric Utility segments and as we consider our guidance for 2012, we are encouraged by the year-over-year improvement we expect to achieve. And with those comments, I'll turn it back to

Thank you, Tony. Moving on to slide 16, our business mix continues to reflect the strong Utility focus we've had since the acquisition by the utilities from Aquila in mid-2008. As of September 30, our Utilities comprised about 68% of our assets, nearly 97% of our operating income. That provides a real strong foundation upon which to continue growing both our Utilities and Non-Regulated energy businesses.

Slide 17 is an updated timetable illustrating our key strategic initiatives and the progress we either have made or expect to make on those initiatives. Slide 18, as we've spoken about in the past, we have a very well-defined capital investment program with a heavy emphasis on Utility growth spending. That spending will drive continued strong earnings growth.

We show, as you can see here, between 2010 and 2014 several consecutive years of spending in excess of $400 million. For 2013, on this particular slide we identify a $468 million number, which is kind of at the low end of our anticipated range. In our 10-Q we will probably include the expected most likely value of capital spending, which will probably be closer to $525 million, which is within the range footnoted here on this slide.

On slide 19, we list many of our longer-term growth projects, some of which are included in the capital totals on the prior pages. Obviously the 2014 and 2015 capital spending would not be included. We have a very well-defined spending program in our Utilities; still defining potential spending on the Non-Regulated side. ENP is becoming more clear and we'll talk a little bit more about our planned Oil and Gas spending later. Under any circumstances, though, growth capital in the $600 million to well in excess of $1 billion over the next four years, I think, bodes well for future earnings growth.

Moving on to slide 20, a little more detail on our current regulatory initiatives in Colorado, which has been a huge focus for us lately. The rate case, as I mentioned earlier, was filed in April. We did reach a partial settlement and filed a stipulation agreement with the Commission on the 27th of October, which settles some of the issues in the rate case with a portion of the parties in the rate case. So it's not a complete settlement by any means.

The Commission heard testimony related to that settlement on the 31st of October, and then the normal rate case hearings began on the 1st of November, continuing into next week. We do expect to have a decision from the Commission in December, prior to commercial operations date of January 1 on our Pueblo generation facility.

We had mentioned previously that we had an obligation to provide an Integrated Resource Plan in Colorado this fall. I think it was an October filing. Because of the other generation projects we have pending in Colorado, we asked for and received this six-month extension on filing that plan. It's not really possible for us to file a Resource Plan when we still have a couple assets that we've asked permission to construct that are still outstanding. So we need an answer to those regulatory proceedings before we can complete our Resource Plan. That plan will be primarily focused on adding renewable resources to meet the renewable portfolio standard in Colorado, which is 30% by 2020.

I already mentioned that we had received approval to proceed with our wind project. We have commenced that project. We've signed some contracts for turbines and other things and the construction process is initiated. We expect that project to be done by year-end 2012.

I also noted earlier that we're proceeding on adding the third LMS-100 turbine at our Pueblo site. That turbine would be partially owned by the utility under a settlement agreement that we reached. Essentially we would have a partner for seven years in that turbine. At the end of that seven-year period, the utility would purchase the remaining 46 megawatts of the plant and rate base that going forward.

We had a settlement hearing on the 25th of October. Hope to have a decision by the end of the year and would expect to start construction immediately after receipt of the decision, with hopes of having the plant in service the first quarter of 2014.

Moving on to slide 21, this is an update specifically on the Pueblo projects. I think the key here is that our plant commissioning is very much on schedule or ahead of schedule. We're on budget in both of those projects.

We've completed the first firing on all of our units there. Six turbines have been synchronized with the grid. The only ones that have not are the two heat recovery steam generators on the combined cycle units. We're in the process of working on those.

Finally, I think it's very noteworthy to mention that we have a phenomenal safety record on this project. This entire project's been constructed so far in just a little over 15 months, which is an unbelievable pace for construction of a facility like this. Our total case incident rate on a safety metric is only 1.4, literally about a fourth of the national average for projects of this nature. Something we're very, very proud of.

Moving on to slide 22, the wind project. I mentioned that. We've spent to date about $3.1 million out of a planned $27 million. We have initiated and signed contracts for turbine purchases and working on construction permits and getting bids from contractors and things like that.

Slide 23 is an update on our other regulatory activity. I've mentioned all these already so I won't spend a lot of time on them, but the Cheyenne Light project we announced this week. Black Hills Power and Cheyenne Light filed for a jointly owned project. Black Hills Power completed its Integrated Resource Plan. Cheyenne Light had previously done an Integrated Resource Plan, which was filed on August 1st.

Those two plans addressed different things. Black Hills Power's Resource Plan was primarily driven by new Environmental Protection Agency regulations on industry boiler air quality regulations,essentially necessitating that we retire three older coal-fired units by March 2014. Cheyenne Light's Resource Plan was driven by primarily by local load growth. Those two have been filed.

On November 1st, we did file an application for the Certificate of Public Convenience and Necessity to construct a project there, $237 million. One simple cycle 37 megawatt peaking unit, which would be owned wholly by Cheyenne Light, Fuel & Power, and then a combined cycle unit 95 megawatts jointly owned by Black Hills Power and Cheyenne. That project will be within the city limits of Cheyenne. We've filed for our air permits in late October. Those are proceeding.

And then finally, it's noteworthy that this project does replace an earlier project we'd filed for Cheyenne Light, which was $158 million, 120 megawatt facility. In reviewing Black Hills Power's Resource Plan in conjunction with Cheyenne, it became very apparent that a combined facility would be much more economical for both sets of customers,Cheyenne Light's and Black Hills Powers'. Allows us to share infrastructure, operating staff and things, and reduce the overall rate impact for customers, so we amended that project as filed on Monday -- Tuesday, sorry.

On the Gas Utilities side, we were obligated to file a gas rate case in Colorado in the fourth quarter of this year. Given all that regulatory activity going on in Colorado and the fact that we're earning at least a reasonable return at that utility today, we asked the Commission to extend that to get us through this current rush of regulatory proceedings in Colorado, if you will,and then delay that potential filing until mid next year.

We're in the process of analyzing rate filings for both our Kansas gas utility and a natural gas related rate filing for Cheyenne Light. If we determine that we need to file cases for those two territories, that would be done next year as well.

Slide 24 is a slide we've been showing you here for quite a while related to proposed and actually enacted rules, primarily from the Environmental Protection Agency. Two noteworthy items here. Under the industrial boiler rules, the Osage, Ben French, and Neil Simpson 1 plants, all 60-year-old or older coal-fired plants, will be replaced by mid-2014, actually March 2014, under that rule by the combined Black Hills Power/Cheyenne Light project that we announced earlier this week.

Finally, the utility boiler rules, which the EPA was going to issue by November 16, they've now deferred those about a month or so. Probably would impact one other facility, which is our Neil Simpson No. 2 plant in Gillett, Wyoming. In that instance, we may have to do some pollution control upgrades there, and we've talked about those before. As we get final rules from the EPA, we'll be able to be a little more definitive on what we would need to do to make that facility compliant with the new rules.

Moving on to slide 25, which is an update on our Mancos shale gas testing program in both the San Juan Basin in New Mexico and the Piceance Basin in Colorado. A reminder that these are held by production assets, which means that the leases are held by production from other zones other than the Mancos. So we're not driven by any time limits of leases expiring or anything else, which is a real great position to be in here.

We've said at the beginning of the year we were going to drill and complete three test wells this year. We're making excellent progress. In the San Juan Basin, where we have a little less than 20,000 net acres, we've completed our test well. Established its initial potential test on September 28th of this year. It flowed 6.2 million cubic feet of gas and about 475 barrels of frac load water per day.

That's right in line with what we expected based on performance of some other Mancos wells operated by others in the area. Currently making in excess of 5 million cubic feet a day and very in line with expectations. Little early, only a couple months in, to be able to accurately forecast reserves, but so far production behavior is very consistent with that of offset operators.

In the Piceance Basin, where we have about 55,000 net acres in the Mancos, we've drilled, cased, and cemented two wells, our Homer Deep Unit and our Horseshoe Canyon Unit. The Homer Deep Unit has been -- we've commenced fracture stimulation on that well. Completion operations are well under way. Hope to complete here in the next week, week and a half, and then begin production testing on that. Should conclude our production testing in the fourth quarter if all goes well.

The Horseshoe Canyon well is scheduled for fracturing later this month. Again, the plan would be to get that well tested as much as possible prior to year-end.

This plain, we've been talking about this recently here, truly has the potential to be pretty transformational for our Oil and Gas business segment. We have the opportunity to drill up to 460 wells on 160 acre spacing; four wells per section, essentially, which is what some of the offset operators in both the San Juan and Piceance Basin are drilling their wells on currently. There's room for even reduced spacing beyond that. We'll see what happens in that regard.

Our engineers' estimates of the reserves from the offset operators' Mancos wells approximate 6 to 8 billion cubic feet per well, so very, very meaningful. We believe that we can get well costs down with a regular drilling program in the $1.30 to $1.40 per net MCF range, which would be very economical, even with $4 gas.

Moving on to slide 26, we talked last year in midyear so that we weren't satisfied with the results of our Oil and Gas operation over the past several years. And in May 2010, we asked John Vering, one of our Board members with extensive oil and gas executive experience, to really come in, give us an unbiased look as the interim leader of our Oil and Gas segment; review our assets, our plans, and our opportunities for that business. I would say the one thing that's become very visible throughout that process here is the ultimate potential the Mancos shale has and the potential that it has to be an extremely valuable asset for the Corporation.

I mentioned before we're very encouraged by early results, and I think you can't understate the value of having that leasehold being held by production. We're not driven by artificial time limits. We have the ability to watch others continue to enhance the technology being used in the basin. We can sit back and watch some of the larger operators prove up the completion techniques and drilling techniques that are optimal, if you will. Gives us a very enviable position to be in with such a large asset.

With that Mancos opportunity in mind, the Board has approved our go-forward strategy for our Oil and Gas unit. We will pursue primarily our Rocky Mountain strategy focused on optimizing shareholder value from the Mancos shale opportunity in the San Juan and Piceance Basins. First order of business there is to hire a permanent leader for that business segment to replace John Vering, so he can go back to being happily retired and an independent member of our Board.

Our plans currently are to commence a San Juan Basin Mancos drilling program in mid-2012. It's obviously contingent on final test results of these initial wells and rig availability. We intend to continue to very closely monitor the activity of offset operators in the Mancos to help us optimize our well spacing, drilling and completion procedures, et cetera. And really want to continue to preserve all of our potential opportunities relative to maximizing the value of both the San Juan and Mancos properties.

So we can either retain and drill those properties ourselves; we can bring in a joint venture partner; or we can sell the properties outright, or any combination of those with the two basins. Certainly based on the results of a San Juan program in 2012, we would evaluate initiation of a similar program in the Piceance Basin perhaps in late 2012 or 2013.

Along with the Mancos emphasis, we would continue our participation in our Non-Regulated -- or non-operated, excuse me, Bakken horizontal oil plain in North Dakota and our operated Powder River Basin properties, and also continue to conduct some limited selective crude oil focused exploration. Not a large portion of our budget, probably 10% or so, but trying to focus on projects that have the ability to add meaningful reserves at relatively low up-front risk dollars.

Moving on to slide 27, it's just an updated scorecard. This is a process, again, which we do every year. We lay out our key goals, key strategic initiatives for the year, and this is our way of holding ourselves accountable to you, our shareholders, for accomplishing those results during the year. There are several updates included in this particular version.

On slide 28, the quarter in summary. Our Utility performance continues to be strong. It reflects a reasonable return on the large Utility investments we've made over the last several years. We obviously expect that growth to continue.

Our generation plants in Colorado are on schedule and on budget. That's a big project for us and just under half a billion dollars, very meaningful impact expected come January 1st upon commercial operations.

We've also announced during the year so far an additional $329 million in Utility growth projects. Very needed assets to continue to provide service for our customers. We believe very cost effective additions, excellent opportunities for continued growth.

As I mentioned, very excited about the early results of our shale gas drilling program and we continue to be very proud of our dividend track record and our 41 consecutive years of dividend increases.

That concludes my remarks. We would be happy to open it up for questions if anyone has any.

Thank you. Ladies and gentlemen, we are ready to open the lines for your questions. (Operator Instructions). Please stand by for your first question. Your first question comes from the line of Kevin Cole with Credit Suisse. Please proceed.

Hi. Good morning, guys. Thanks for taking my call. I guess on your comments on the Mancos, I guess with the commencement of a drilling program in mid-2012, I guess it sounds like you believe that time is on your side, so you just want to shore it up a little bit in order to get a better price for it upon monetization or the decision to fully develop? Is that the right takeaway?

I would say we've seen enough encouraging results that continuing a modestly paced drilling program is something that we want to do. At this point, Kevin, we're thinking a single rig program, so it's not going to be a huge program by any means, but we have enough locations there that we believe are comparable to our first test well that we really do think it's in our best interests and certainly in our shareholders' best interest to begin a modest program, if you will. As the completion and drilling techniques continue to evolve in both basins in that formation, we'll continue to very carefully follow what others are doing and modify our procedures and processes accordingly to make sure we're optimizing value there. But with one well drilled in an entire basin, it doesn't allow you to really accurately project what your total value is for that property.

Okay. Thank you. I guess I have a few questions on the 2012 guidance, slide 14. Are the drivers listed to get you to the midpoint of the range?

Well, it is a range, and in effect, we try to bound it. That's what we're trying to do, Kevin.

If all of these occur, will you be at the top end or will you be at the mid-range, the middle of the range?

I wouldn't say we have listed everything that would push us to the top. If you had market conditions change; if you had much better results on drilling those sorts of things, you could easily push higher in the range. I don't think we've attempted to give you all the drivers that would either push us to the top or lower to us the bottom. We've listed the assumptions that if they come true or most of them come true, we should be within the range.

Okay. I see the Colorado plants aren't listed, and so just to make sure I understand this right. So the IPPs earning mechanism is already set, it's just now that the regulated earnings power is just -- and that will be determined in the settlement outcome?

Correct. Essentially correct, yes.

Are you able to give a range of what you think that EPS would be for the consolidated IPP and regulated plains?

No.

No? Okay. Sorry, my last question. Then with the Electric Utility CapEx, it looks like you're targeting roughly $232 million for 2012. Are you able to kind of break that up between maintenance and growth CapEx?

Well, we don't typically give that breakdown, not for any reason in particular, but we haven't disclosed it. I would say we typically give a very detailed breakdown on our growth CapEx. Now, we haven't broken it into year, but certainly a big chunk of that's going to be our ongoing growth projects. If we get started on, for example, a third turbine in Colorado and some of the other things that we're looking at, that would drive a pretty large portion of that capital expenditure.

Of course. I guess I'm looking at slide 19, your long-term growth opportunities. And so if I were to take that $232 million and back out depreciation just to get to a rough growth CapEx number, it looks like this number is dependent on the new Cheyenne Light/Black Hills Power JV getting approved and somecapital being deployed? Is that right?

For 2012?

Correct.

Probably not a lot of capital included in there for that project in 2012. We need approval on the CPC end before we would really commit to any major expenditures. We may have some minor ones, but things like ordering turbines and things that really start to drive CapEx, we don't typically do those until we have at least our Certificate of Public Convenience and Necessity.

Okay. It looks like you have roughly about $175 million of CapEx aimed for the Electric Utility. I'm just trying to figure out where that's all coming from. If there's any help there?

Kevin, are you taking the $428 million and subtracting the $329 million? Is that what you're saying?

I'm looking at slide, let's see, slide 18. You have total electric utility of $232 million for the CapEx, and then I'm just taking that minus your electric depreciation and trying to get to a rough growth number. And that appears to be around $175 million of CapEx. I'm just trying to figure out where that growth is coming from.

Yes. I think it's a combination of multiple projects, Kevin. Again, we haven't been explicit about where it comes from. I think there's a little more detail in our 10-Q but not a whole lot.

Okay. All right, I'll take a look and follow back up. Thank you, guys.

That would be great, thank you.

Your next question comes from the line of Michael Worms with BMO. Please proceed.

Good morning, Dave, Tony. How you doing?

Good, Mike, how about you?

Fine, thank you. On the guidance for 2012, can you give us a little built more color around the financing? Will you need to do any equity in 2012? We'll start with that one.

Michael, from that standpoint, what we'll do is we're trying to maintain our capital ratios and we would like to be 55% or less debt to cap. And in some of these -- some of the projects that we do have teed up on capital, they could slip a little bit. We tend to be pretty -- at least we plan what we would expect, but also it's a pretty disciplined spend plan. So it depends on capital expenditures and other kinds of things of what we might do from a capital financing standpoint. It depends on maybe selling other assets or other kinds of things.

Okay.

So what we've tried to do, we've tried to put that -- if any of that type of thing happens, we've tried to include that in our guidance range.

Okay. Fair enough. And then on the Energy and Marketing guidance, what's driving the significantly higher results in 2012?

In the third quarter we're getting better performance out of our natural gas. We continue to get really strong performance out of the crude oil and we're seeing some things in coal, although we didn't see them in the third quarter. But we're seeing things in coal and power that would help us believe that we're going to hit higher numbers. If I take a look at the last eleven years, Michael, I know the last three years haven't been good, but out of eleven years, we've had seven years that we've made over $10 million in that business. We've tried to diversify over the last year or so and try to build up that kind of earning power again.

Okay, fair enough. And my last question is, on the CapEx numbers for 2012, it now looks like the total for that year is going to be over $100 million greater than what you had showed us -- shown us at the conference last month. Is most of that related to the shale development?

The shale development's up a little bit but it's not that kind of a number, Michael.

Okay.

It's kind of increases in multiple different areas, I think, as far as when we really fine-tune our forecast for next year.

Okay. Fair enough. Thank you very much.

All right, thank you.

(Operator Instructions). Your next question comes from the line of Nicholas [Hillis] with Gabbeli & Company. Please proceed.

Hi, how are you? I'm just trying to get a little bit better handle on guidance. Can you just give me a breakdown of what the Oil and Gas production levels are for 2011 that are vacant to guidance and the level of Energy and Marketing earnings?

Well, we can't give -- well, what we've said for the Energy Marketing earnings for 2011 is that we would exceed 2010, which Tony said was $3.3 million.

Okay.

What I said is 2010 was $3.3 millionand I said we expect to do better than that this year in 2011 and we would expect next year to more than double.

Okay.

Then on the production, we've got the price listed in our assumptions. We expect to be up and we've got our BCF range in there also, the 12.3 to 13 BCF next year.

And what are you expecting for this year? Or what have you -- ?

This year our production would be consistent with our previously issued guidance, which off the top of my head, I think was 9 plus BCFE, something like that.

Yeah.

Okay.

But that assumption is still pretty consistent with where we expect to be.

Okay, great. That's all I have.

Operator: Your next question comes from the line of Beth [Olollan] with [Rebel] Bank International. Please proceed.

Good morning. I was wondering if you could provide us with some color on the drivers behind the improvement and gross margins for natural gas and crude oil energy marketing? And then in the same vein if you could provide us with some color on the declines and gross margins for the coal and the losses in power marketing.

You're talking year-to-date through September?

Correct.

The natural gas, we've done well at least in the proprietary trading. There's been a little more volatility in the market, at least where we're at. The crude oil is really just -- we're in the Bakken basin and we've established a number of relationships. That's very much a producer services business, and so our gross margins are substantially more than last year for the first nine months. We've more than doubled. The natural gas, although we've had good performance in the third quarter, we're actually down on a gross margin basis for the first nine months compared to last year. And then on the coal, we're below where we were last year. We're still positive for the first nine months, but we did have some proprietary losses in the third quarter that reduced our year-to-date number.

If you look at the Utility segments, which I think you also asked about, the Electric earnings are essentially driven by the rate cases. We completed five rate cases last year throughout the course of the yearand so we're starting to see the full year benefits of those in 2011. And that's really the principal driver there. It's offset by a few things, but the primary margin enhancement is due to rate cases for the capital that we've been spending over the last several years and earning a reasonable return on that. On the Gas Utilities side, the last couple years we've had very favorable weather which has really helped. The other thing is that they're receiving a smaller allocation of corporate costs, and that's because those are allocated -- one of the issues, one of the factors in the formula is capital, so as we build, say, this $500 million power plant complex in Colorado, that complex is receiving increasing amounts of general corporate costs, reducing some of the allocations to the other businesses, and I would say natural gas utilities have benefited from that. So those are probably the two larger drivers on the natural gas side as well. So does that answer all your questions?

Yes, that helps. Just to step back to make sure I understood on the coal side, just to recap. You mentioned you were below where you were last year?

Are you talking coal mining?

No, on the Energy Marketing side.

Okay.

In terms of the gross trading margins, you're below where you were last year on a quarterly basis. Is that correct? Or was that on a nine-month basis?

It's on both.

On both. Okay. And that was due to prop trading losses?

In the third quarter of this year, yes.

Okay. And what do you anticipate for fourth quarter in that, on the coal side?

Well, we don't differentiate by specific marketing segment. We've just discussed what we expect for overall results from marketing.

Got it.

In order to get that, we need decent performance out of most of our commodities.

Yes. Okay. Thanks very much.

You bet. Thank you.

(Operator Instructions). And please stand by for the next question.

And at this time we have no further questions. I would now like to turn the call back over to Mr. Dave Emery for the closing remarks.

All right. Thank you. Thanks for your time and attention today, everyone. We appreciate your participating in our call. We certainly appreciate you being shareholders, and as I said before, we're very excited about the some of the opportunities we have for the future and excited about the earnings growth associated with those opportunities. So thanks for your continued interest in Black Hills and have a great weekend.

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