Black Hills Corp (BKH) 2010 Q4 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Black Hills Corporation 2010 fourth-quarter and full-year earnings conference call. My name is Jeneta, and I will be your coordinator for today. At this time, all participants are in a listen-only mode. Following the prepared remarks, there will be a question and answer session. (Operator Instructions)In order to get as many questions answered as possible, we ask that the participants re-enter the queue after asking one initial question and one follow-up question. (Operator Instructions)As a reminder, this conference is being recorded for replay purposes.

I would now like to turn the presentation over to Mr. Jason Ketchum, Director of Investor Relations and Corporate Communications of Black Hills Corporation. Please proceed, sir.

Thank you. Good morning, everyone, and welcome to the Black Hills 2010 full-year and fourth-quarter earnings call. With me today are Dave Emery, Chairman and CEO, and Tony Cleberg, CFO.

Before I turn over of 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 our expectations and beliefs are based on reasonable assumptions, actual results may differ materially. I direct you to our earnings release, slide 2 of the investor presentation on our website, and our most recent form 10K and form 10Q 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 joining us today. Consistent with prior quarters, I will give a quick overview and highlights for both the quarter and the year. Tony Cleberg, our Executive Vice President and CFO, will cover the financial updates for both the quarter and the year, and then I'll discuss a forward-looking strategy discussion as well.

Moving to slide 5, I will discuss overall highlights for the quarter and the year, and I will touch briefly on a few of the earnings highlights for the quarter and the year, but as I said before, I'll leave most of the accounting details to Tony to discuss here later. On slide 5 for the fourth quarter, our results were lower than the prior year. Income from continuing operations, as adjusted for special items, was $0.41 per share compared to $0.57 per share in the fourth quarter of 2009. Our utility income increased $2.6 million compared to last year, while income from our non-regulated energy group decreased by nearly $8.2 million.

On slide 6 for the full year of 2010, we demonstrated strong earnings growth compared to the prior year. Earnings per share from continuing operations as adjusted increased 27% from $1.43 in 2009 to $1.81 in 2010. Utility income was up significantly, driven primarily by rate case activity in five different jurisdictions. Although market conditions continued to challenge our non-regulated energy marketing and oil and gas businesses, our overall non-regulated energy earnings also improved considerably compared to 2009.

On slide 7, there were several key highlights for our utilities businesses in 2010, in addition to achieving strong earnings growth. On April 1, Black Hills Power's new 110-megawatt coal-fired mine-mouth power plant Wygen III began commercial operation ahead of schedule and under budget. As I noted earlier, we completed utility rate cases in four jurisdictions, and implemented interim rates in a fifth jurisdiction during the year, with a total annual revenue increase of about $47 million. In July, we commenced construction on our 180-megawatt gas-fired power plant that we are building as a rate-based asset of our Colorado electric utility. That plant is being constructed near Pueblo, Colorado. And we also completed a transmission project for Black Hills Power and made substantial progress on several automated metering projects. We completed AMI Meter Installations in all three of our electric utilities, and expanded AMR Meter Installations in our gas utility territories as well.

Moving to slide 8, we also made significant progress on several key non-regulated energy initiatives during the year. In July, we commenced construction on our 200-megawatt gas-fired IPP power plant near Pueblo, Colorado, that is also being built to serve our Colorado electric customers. That plant will be providing energy to our customers on a long-term power-purchase agreement.

During the year, we diversified our energy marketing business through the addition of coal power and environmental credit marketing, essentially mitigating the risk of that business by diversifying our income stream there somewhat. We've also continued the review of our oil and gas strategy that we announced in May of 2010. Although that review is not yet complete, we are optimistic about the potential value of our existing oil and gas holdings.

In 2011, we plan to focus on drilling several wells to evaluate the potential of the Mancos Shale formation beneath our existingly sold acreage in both the San Juan and Piceance basins of New Mexico and Colorado. We plan to continue participation in the Bakken Oil Shale play in the Williston basin, and may also participate in other select oil prospects during the year as well.

Finally, in early January of 2011, we sold our 50% ownership interest in two small non-regulated power plants in Idaho, the Rupert and Glenns Ferry facilities, with a total net capacity of only about 11-megawatts That sale will not have a material impact on our financial results.

Moving on to slide 9, corporate highlights for the year, during 2010 we completed several debt and equity financings, and Tony will talk more about those. Notably, one of them was the completion of an offering of 4.4 million shares of common stock through an equity-forward transaction. That transaction provides sufficient equity financing to complete our two Colorado generation projects by the end of this year. We completed substantially all of the core business process and systems projects necessary to fully integrate the operations of the utility of properties that we acquired from Aquila in mid-2008. Finally, in January, just last week, our Board of Directors approved an increase on our quarterly dividend for shareholders, marking our 41st consecutive annual dividend increase.

On slide 10, this provides an updated timeline of events relative to major key strategic-type projects. As you'll note from there, we've dropped 2008 and part of 2009 off of this chart, and added a little more for 2011 and 2012, adding several new items particularly related to utility resource planning, and some other activities I will talk more about a little later.

That completes my highlight discussion. I will turn it over to Tony for the financial update.

Thank you, Dave, and good morning. From a financial standpoint, our 2010 year improved significantly over 2009. Although our earnings were within the guidance range internally, we expected more in the fourth quarter, particularly from the non-regulated segments. In my comments I will address both the fourth quarter and the total year.

Moving to slide 12, here we do an EPS analysis consistent with past quarters, and we adjust our income from continuing operations to display non-GAAP earnings measures. This is done to better communicate the relevant performance. Special gain and loss items recorded during each quarter are excluded to compute a non-GAAP measure. This slide displays the last five quarters and the calendar year amounts for 2009 and '10. The only special item included in Q4 of 2010 was a subtraction of $0.44 for a non-cash unrealized gain on certain interest rate swaps. With that adjustment, the quarter's adjusted income from continuing operations was $0.41 per share, which compares to the $0.57 in 2009. The $0.16 decline from 2009 was driven by our non-regulated segments, which I will discuss later.

I will mention here that I will discuss the fourth quarter, and there are a number of moving parts to be considered to understand the performance. Looking at last year, fourth quarter included a $0.30 subtraction for an unrealized gain on the same interest rate swaps, and a $0.03 addition for integration costs. The income from continuing operations, as adjusted for the total year 2010, was $1.81, which is a 27% increase from 2009.

Slide 13. On our income statement for the fourth-quarter 2009 and 2010, and as you'll note, the EPS remained flat. This resulted from a combination of a decline in operating income of $5.2 million, an increase in interest expense of $2.3 million, and a decline in other income of $1.6 million. All of which were offset by a pre-tax mark to market improvement of $8.6 million on our $250 million worth of interest rate swaps.

The lower operating income I will discuss in more detail on a later slide, but in summary it reflects stronger performance in our utility segments, and weaker performance in our non-regulated segments. The increased interest expense reflects higher debt level and higher rates. The decline in other income resulted because 2009 included a $1.1 million sale of SO2 credits.

As a reminder, our interest rate swaps were put into place in 2007 for expected financing needs, and we've chosen to leave those swaps in place because of our expected future need for financing of capital projects, and future maturities of debt in 2013 and 2014. Continuing down the income statement, the fourth-quarter income tax rate of 31.5% for 2010 improved from the 34.4% in 2009. The improved income tax rate reflects the benefit of R&D tax credit and the impact of using the flow-through method of expensing certain costs related to property, some of which I spoke to in the third-quarter call. The resulting GAAP income from continuing operations for the quarter was $0.85 compared to $0.84 in 2009.

Looking closer at the operating income, slide 14 displays the segment roll-up of revenue and operating income for the fourth quarter of 2010 and 2009. The electric utility segment year-over-year income increased by $7.3 million. The improvements were attributable to rate cases and improved margins of off-system power sales.

During the quarter, the megawatts sold to retail customers were flat compared to 2009, so pricing drove the improvement in operating income. For off-system power sales, both the megawatts declined by 9%, and the prices declined by 14% from 2009. However, the operating margin actually improved by $600,000. This is a result of the costing methodology change in the settlement of the South Dakota rate case, which allows for a more equitable sharing of margins of off-system power sales.

Moving to gas utilities, the decatherms sold during the quarter for residential and commercial declined by 13% from 2009. As you may recall, our gas territories were unusually cold last year. The operating income declined by only 6%, so most of the volume decline was offset by the impact of rate case settlements, and the continued emphasis on cost management.

Moving to oil and gas performance, the major drivers of the $3.7 million decline from 2009 was a $2.6 million adjustment for depletion in Q4. The primary reason for the adjustment was higher future development costs included in our reserve analysis for oil and gas. The higher costs relate to oil development for the Bakken Play in North Dakota. The remaining decline from 2009 of $1.1 million resulted primarily from a combination of price and volume. For oil, the price received declined by 14%, while volumes increased by 34%. For gas, the price received declined by 20%, while the volume declined by 4%. As you may recall, our hedging program hedges about 50% production two years out, and the fourth quarter of 2008, the prices for commodities were dropping dramatically.

The next segment, power generation, produced $2.7 million operating income, a decline of $1.1 million from 2009. The decline resulted from a combination of increased G&A expenses that are not capitalized on the Colorado IPP construction project, and some additional expenses for the overhaul of a combustion turbine during the quarter.

Moving to the next segment, coal mining, operating income declined by $3.8 million from 2009. As you may recall, fourth-quarter 2009 included a $3 million improvement related to the completion of reclamation studies, and an improvement of $700,000 for the settlement of the Black Lung tax issue. This area included $7.5 million increased depreciation in the quarter, but much of this was offset by reclamation credit. During the quarter, we have continued to capture benefits from the reclamation studies, and these improvements in the Q4 of 2010 were offset by inter-company transfer pricing true-up of mining costs passed on to our utilities.

For our next segment, energy marketing, operating income was negative for the quarter. It decreased from 2009 by $2.6 million. The realized gross margin increased by $8.8 million to $18 million, while the unrealized gross margin declined by $13.1 million to a negative $18 million. So margins were about zero for the quarter, the loss represents the operating expenses.

Incremental improvements in natural gas and oil were offset from the start-up of power and a decline in coal, where we gave back some of the gains we earned in prior quarters. One item worth mentioning and that impacts operating income of several segments, is depreciation expense. During the quarter, depreciation increased by $9.5 million over the last year. The increase impacted primarily oil and gas, and coal mining segments, and brought the total depreciation expense for the year to $127 million.

On slide 15, we display our income statement for the full year compared to the prior year. The operating income improved significantly by $67.1 million, and was the result of a combination of improved operating performance of $41 million, and a difference in the special items of $26.2 million. I will describe the drivers of those improvements on a later slide.

The interest expense increased $8 million over 2009, primarily driven by increased debt levels, higher rates on our credit facility, and long-term debt, offset by a $4.9 million increase in AFUDC. The mark-to-market interest rate swaps changed from a sizable positive in 2009 to a negative in 2010, consistent with the decline in the Treasury rates, the long-term Treasury rates.

Other income declined by $6.3 million, primarily due to reduced equity income from AFUDC, $2.9 million, lower interest income of $900,000, and also that 2009 included a catch-up billing for rent income on the Wygen III land lease of $1.2 million, and 2009 included a $1.1 million sale of the SO2 credits. The 2010 tax rate of 27% compared to 30% in '09 was driven by a $2.4 million benefit from an IRS settlement during the third quarter.

Looking closer at the operating income, slide 16 displays our total-year segment roll-up for revenue and operating income. Electric utilities operating income improved by $22 million, or 31% over 2009. The drivers of the improvement include rate case settlements and improved margins of $3 million for off-system power sales. The gas utility earnings improved by $11.1 million, or 20% over 2009. The improvement was driven by rate case settlements, which more then offset the 2% decline in decatherms sold.

Moving to oil and gas, the improved operating income for 2010 reflect better prices on lower volume, and improvements in both the lease operating expenses and the administrative expenses. For oil, the price received improved by 28%, and volumes increased by 3%. For gas, the price received improved by 3%, and the volume declined by 13%. We made solid improvements in this segment, even though the natural gas prices remained low.

Moving to power generation, the operating income declined by $4.3 million from 2009. The major variance resulted from an outage at Wygen I in the second quarter, and other variance resulted from incurring G&A expenses that are not capitalized on the Colorado IPP construction project.

Moving to coal mining, the tons mined were flat with 2009. The overall costs for the year were relatively flat. 2009 did contain a $700,000 settlement for the Black Lung tax.

Moving to energy marketing, here we saw a $7.7 million improvement in operating income from 2009, but the performance is still below the earnings we expect from this segment. The margin from commodities marketed improved by $14.6 million, reflecting incremental improvements in natural gas, oil and coal, with an offset from the start-up of power. The margin breakdown was positive $32 million realized, and negative $4.5 million unrealized. The operational expenses increased due to incentive compensation, higher bank fees, and staffing for the new commodities. So overall, operating income, excluding special items, 2010 increased 26% for the utilities, and 32% for the non-regulated segments; a very solid year of performance improvement.

Slide 17 identifies the various transactions that strengthened our capital and improved liquidity during the year. Many of these items I've discussed on previous calls; the last two items are new to the fourth quarter. We completed the equity-forward transaction for 4.4 million shares of common stock. This gives us certainty of price when we need to issue the shares later this year. Another item completed in the fourth quarter was a $100 million term loan, which gives us additional liquidity. These funds, which we borrowed at LIBOR plus 1.375%, were used to pay down the credit facility debt, and will save us on interest expense.

Slide 18 shows our capital structure, and at the bottom of the slide you will notice our net debt to capital remains at a healthy 56%, particularly considering that we've completed the equity forward, so we have the commitment for the additional capital to strengthen our balance sheet.

With those comments, I will turn it back to Dave.

Thank you, Tony. Looking to the future here from a big picture strategic perspective, starting on slide 20, as we've discussed for the past several years, our assets and earnings have shifted dramatically from being mostly non-regulated in the year 2007, to mostly regulated in the current year, 2010. This shift really provides a more stable cash flow and earnings for shareholders, but also an excellent foundation on which to continue to grow all of our businesses.

On slide 21, over the past several years we've made substantial investments in our existing businesses to provide the earnings growth for shareholders, spending nearly $500 million in 2010, with another $426 million planned for 2011. On slide 22, our 2012 earnings growth potential is being driven primarily by the construction of our two power generation facilities in Colorado. One of those being the utility plant, and the other the IPP facility. We've made great progress on both of those facilities, in just, literally, half a year since we commenced construction in July.

In 2010, we took advantage of the bonus tax depreciation benefit, which has now been extended into this year as well. But we accelerated more than $40 million of capital into 2010 in order to take advantage of that -- prior to that benefit being extended. We've already spent nearly $350 million out of the $500 million to $520 million total we expect the two projects to require.

At the bottom of the page, there's a couple pictures that I think you will find of interest. We've made fantastic progress in just six months of construction. You'll see literally a midsummer photo of nothing but the topsoil stripped, and a late December photo with literally all four units under construction there. So, pretty impressive progress in a very, very short period of time. We are real excited about how well the project is going.

Moving on to slide 23, in the last couple of months we've also advanced our next growth project, which is constructing a third 92-megawatt GE LMS100 turbine at that utility plant in Colorado. In mid-December the Colorado Public Utilities Commission approved our plan to comply with the Colorado Clean Air Clean Jobs act. That Act essentially requires the closure of older coal-fired facilities if they can't be retrofit to eliminate emissions from those facilities. Under that approval, the Commission approved the retirement of our 42-megawatt WN Clark plant, which is a coal-fired facility in Canyon City, Colorado. It's about 65 years old, or so. They also granted a presumption of need for 42-megawatts of replacement energy for that plant and capacity with a gas-fired turbine.

We intend to file a certificate of public convenience and necessity in Colorado in the first quarter of this year that will provide justification to construct an additional 50-megawatts of generation capacity for a total of 92-megawatts. So then our proposal is to construct a third 92-megawatt LMS100 unit at that Pueblo generation site. The capital investment, at this point we are estimating $85 million to $95 million, including any smaller transmission investments we might have to make.

That plant will not require any additional air permitting. The air permit that we filed for on the plant project initially, included space for three of these LMS100 turbines, and that air permit was approved on the 22nd of July last year, and so we have the air permit we need to commence that construction. We will have to do some additional facility permitting, construction permitting, but that can be done relatively quickly. Assuming approval of our CPC and by the Colorado PUC, sometime in 2011, we expect that plant should be online and ready to serve customers by the end of 2013, and we will update you with our regulatory progress as we proceed there.

On slide 24, our growth opportunities beyond January 2012 are really plentiful. I talked about the third LMS100 engine at Pueblo. I would say that represents the first defined project, if you will, from this list on page 24. But we are actively pursuing several other projects that we hope to advance in the next couple of years, namely some renewable generation opportunities in Colorado, additional generation in our utilities. I mentioned the one for Colorado on the gas-fired turbine, but we think there will also be some opportunities for Black Hills Power and Cheyenne Light there as well, which I will explain in a minute. Continued investment in transmission, potential IPP opportunities, and then again, depending on our strategic review of oil and gas, we may have some significant investment opportunities on our oil and gas properties.

Moving on to slide 25, some of those growth opportunities I just talked about will be driven by regulatory compliance and regulatory policies. The first one that I already spoke of was essentially a result of the Colorado Clean Air Clean Jobs Act. Colorado also has a renewable energy standard, which they increased last year to 30% by 2020. It had previously been 20% by 2020. We are in the process of planning our compliance with that standard, and anticipate filing a resource plan with the Colorado PUC in late 2011 that will outline our plans to comply with the renewable mandate. It should provide some opportunity hopefully for some addition of rate-based wind projects into that Colorado electric utility.

Finally, several emissions rules issues, and particularly the EPA has rules pending for coal-fired boilers both large and small. We expect the ones that will impact our plants to be issued on February 21. Not knowing what the final version of those rules looks like, we would expect approximately three years to comply with those new emission rules for these older coal-fired facilities that we have.

We have four older coal-fired plants in our three electric utilities. Total capacity of about 124 megawatts, and probably all will be impacted by this rule, and will need to be replaced. 42 megawatts is the coal-fired Canon City plant that I already spoke of, but we have several facilities at Black Hills Power totaling about 82 megawatts that may have to be replaced as well.

We would expect to complete electric resource plants for both Black Hills Power and Cheyenne Light during 2011, and then presumably we will request, as part of that process, the ability to replace those coal-fired plants if we need to retire them to comply with EPA rules. We would propose replacing them with gas-fired generation. So again, we will provide updates as we work our way through that regulatory process for both of those utilities also.

On slide 26, we had a tremendous amount of regulatory activity in 2010. I already mentioned the rate cases; we completed four, settling three and litigating one. We also have one pending case, which is our Iowa Gas rate case. We did implement $2.6 million in interim rates there last year, which is part of that $47.1 million in improvement that we cite. We have a settlement pending with the Iowa Utilities Board for $3.4 million now, and I hope to hear on that here in this first quarter. We also intend to file an electric rate case in Colorado, probably in the late first or early second quarter of 2011, that will include the costs associated with the new gas-fired generation we are constructing there.

Slide 27 provides an update on our oil and gas activities. I mentioned this briefly before, but I will elaborate a little more here. First we intend to focus our efforts this year on testing and evaluating the Mancos Shale gas potential of our existing sold acreage in both the San Juan and the Piceance basins. During 2010, we re-completed two vertical wells in the San Juan basin, which had been producing from another formation into the Mancos, in order to test that zone prior to drilling horizontal wells, which are quite expensive from a capital standpoint. We've been encouraged by the results of those two tests to-date, and now plan to drill a horizontal Mancos formation well in the San Juan basin in 2011. Ideally we will commence drilling on that well in late first quarter or maybe early second quarter, somewhere in that time frame.

In the Piceance basin, we also intend to re-complete a vertical well into the Mancos formation during the first quarter of 2011 before we drill two horizontal wells in the Mancos formation and the Piceance basin. With the results of that Mancos formation testing during the first half or so of this year, we expect to be in a position to really finalize our strategy review of our oil and gas operation.

During 2011, as I mentioned earlier, we also plan to continue our participation in the Bakken Oil Play in the Williston basin in North Dakota and Montana. Although we have a relatively small amount of operated position in that play, we are seeing some very excellent well results with year-end net production for Black Hills totaling nearly 400 barrels of oil per day now. We expect our Bakken drilling program to continue throughout the year, with at least one drilling rig operating continuously during the year.

On slide 28, I want to highlight a change in the way that we intend to report results for our energy marketing business going forward. Last year, our Form 10-K included an expanded disclosure on energy marketing, which really illustrated gross margins by business strategy, including producer services, gas storage, gas transportation, and proprietary trading. Given our recent product diversification efforts, on a going forward basis we now intend to provide gross margin figures primarily by commodity, namely crude oil, natural gas, coal, electric power, and environmental credits. We'll also attempt to break-out the amount of margin that comes from producer services or other stable more asset-based activity, to try to give you a better sense of what we would consider to be the more fee-based or repeatable-type business at Enserco.

As you review slide 28, you'll notice that we have three graphs illustrated there, which are a little different than what you have seen previously. The first depicts gross margin by strategy, again, trying to give you a sense of what is more producer services or asset-based strategy compared to more trading-type activity. The second graph depicts gross margin by commodity, as I discussed, and the third illustrates total realized gross margin, total unrealized gross margin, and then total gross margin over time. We hope that additional information will assist you in continuing to evaluate our energy marketing operations going forward. There will be a little bit of additional disclosure and some details behind these numbers disclosed in the 10-K, as well.

Moving on to slide 29, our strategy score card, this is our way of holding ourselves accountable to you, our shareholders, for the activities we are undertaking, particularly large strategic-type activities that are intended to build shareholder value. We have provided this for the last couple of years. This year you will notice that we've added a few new items, and after this quarter we will remove the 2010 completed items, and probably add more goals and targets that we intend to complete in 2011.

Finally, on page 30, 2010 showed real strong improvement over 2009, and we are excited by the year. As Tony said, our adjusted earnings per share were up about 27% year-over-year. Capital projects are on track, which will provide our growth for this year, next year, and beyond. The financings that we completed provide flexibility and liquidity for those growth initiatives and I think we are very well positioned for future earnings growth for shareholders. Finally, as part of our earnings release, we did reaffirm the earnings guidance range and assumptions that we previously issued on October 28, 2010.

That concludes my comments. We'd be happy now to take any questions.

Ladies and gentlemen, we are ready to open the lines up for questions. (Operator Instructions)As a reminder, in order to get as many questions answered as possible, we ask that the participants reenter the queue after asking one initial question and one follow-up question. Please standby for your first question. Your first question comes from the line of Dan Eggers with Credit Suisse. Please proceed.

Hello, good morning.

Good morning.

This is actually -- on your 2011 guidance, it seems like the electric utilities, the gas utilities, the power generation, and core earnings are all pretty much de-risked and locked down. Are you able to offer us any better color on the earnings breakdown between regulated or non-regulated? And just variabilities you foresee in the guidance range?

I would say we don't break out how we give guidance for the regulated and non-regulated segments. In sum total I think we are pretty comfortable putting those numbers out there. Most of them, by looking at the assumptions, you can see were the potential variability is going to be. Particularly things like oil and gas prices. If those vary, obviously, from our assumptions and production assumptions, things like that, you would be able to see those as we go through the year on how those may vary.

If we expect those variabilities to have an impact on our overall guidance number, we would modify our guidance. But if we don't expect those individual subsidiary variations to change the overall number, we typically don't provide an update.

Okay. And then on bonus depreciation, can you share the likely range in receipts as well, what Colorado's rate treatment is against rate base, and if there could be any impact on the PPA pricing for the IPP unit.

Dan, there could be impact on, because of the 100% depreciation. We put the 50% into our thinking, but the 100% that actually has more of an impact -- on the utility. It could be as much as 15%, is the way we are looking at it, and you might ask why doesn't the rate base go down more than that? The reason is because you end up with a tax asset for the depreciation deduction and that tax asset will, in effect, offset the deferred liability. And 15% is as high as we would ever think it could reduce the rate base, but it could be quite a bit less also.

And also, we don't expect any change in the IPP contract pricing, that's a firm contract. And so those benefits are essentially going to be benefits for shareholders from the tax depreciation on the IPP project.

Okay, and then was there any manufacturing tax credit baked into 2011 that we should know about?

No, there wasn't.

Okay, and then my last question would be on M&A, it feels like you are constructing this around the commodity prices. Is taking the conversation towards M&A of E&P companies, or other commodity leverage bases, is that correct and can you share with us your target mix between the regulated and non-regulated earnings?

Yes, I would say -- I wouldn't infer anything related to particularly focus on acquisition of commodity -based businesses. As we've talked about before, we are always looking for acquisition opportunities, but I think that if you look at our existing oil and gas business I think we are optimistic about the properties we have now. In the basins where the activity is encouraging and economics are very good, prices are very high. I don't think that bodes well for potential acquisitions in those types of locations.

We are always looking for opportunities, and particularly related to utilities. As we've said before, they don't always come available when you are looking for them, but we are at the point now where I think our integration activity is essentially complete. And we would be in a position to look seriously at an acquisition again if the opportunity presents itself. And certainly we are working on some of those ideas; at least keeping the focus on where we might be interested.

Great, thanks.

You bet, thank you.

Our next question comes from the line of from Lasan Johong with RBC Capital Market. Please proceed.

Thank you, good morning, everybody. Tony, can you go through the special tax reduction of $2.4 million? Is that an ongoing item? Is that a one-time cumulative effect? What are we talking about?

The $2.4 million, we identified that as a one-time item because it was a catch-up or a settlement that we had in the third quarter. The other items that are impacting the tax rate, the flow-through method and the R&D tax credits and things like that, those kinds of things are more recurring. The R&D tax credit, you have to be spending money for construction and things like that, but you assume that you're going to be continuing to spend the money on constructing certain projects.

Okay. You mentioned in the oil and gas segment there was some sort of accelerated depreciation. I'm assuming that was also a one-time item?

We do a reserve analysis at year end, and we, in effect, take a look at what we've been using for a depletion rate. Part of that calculation is what are your future development costs. Our future development costs on the oil side increased quite a bit just because of the scarcity in the Bakken Play, and consequently that had an impact of how you do the calculation, and the calculation is very prescriptive by the SEC.

It doesn't necessarily make sense to me because the economics on oil are so much better right now, than on natural gas. The fact is, that cost went up, and therefore you have to look and spread it over your entire pool. We believe that's a one-time adjustment.

That was also $2.4 million?

That was $2.6 million. That's a pre tax number.

Right. David, what's taking so long with the E&P study? The second quarter this coming year would make it over a year, or close to a year and a half. The Company's been looking at the E&P business. Can you give us an idea of what the extent of the holdup is?

I wouldn't classify it as a holdup, Lasan. I think in our discussion, when we announced that John was going to take over and help us conduct that review as it was probably at 12 to 15 or 18 month process. I think we are right on schedule with where we thought we would be.

One of the things that's evolved since we started that exercise last May is the potential of the Mancos Shale. And there's been a lot of drilling activity by other operators in both the Piceance and San Juan basins, and they're holding a lot of that well information confidential, which they can do for only a specified period of time before it has to be released. As more and more of that information is available to us, and we are doing some of our own testing, as I mentioned, we are getting a lot more optimistic about that and we have pretty significant acreage holdings in both of those basins.

I think it would be very premature for us to, quote unquote, conclude our review of our strategy until we really know what that's worth, and what the drilling economics in that play will be for us. As I said before, that is our focus for early 2011 here, is to ascertain that, and what the true potential of the Mancos formation is. And then I think we can give the Street a pretty good feeling for what we intend to do after that.

Forgive me for the follow-up, but I was under the impression that Black Hills was going to wait for results from other producers Mancos program before taking any steps to drill additional wells in your project area. But it sounds like you've changed your mind about that and said maybe the opportunity is now to start drilling. Am I characterizing this incorrectly?

No, we've seen results from offset operators. Some of these wells that were drilled a year, year and a half ago, they have released the information publicly, and it is pretty encouraging. So that has led us to -- we wanted to do a couple things to basically prove that, at least the presence of gas and pressures and things like that were comparable on our acreage to the areas just off of our acreage where these other operators are drilling.

So the first thing we did is we re-complete these old vertical wells that were depleted in their current zone into the Mancos formation, and then use the newer fracturing technologies to stimulate those. And then get a sense for volumes and pressures and things. A vertical well is nowhere near representative of what a horizontal well will do for volumes. But the pressures, the gas, those things, are -- we get a good idea of some of those factors.

We are doing that and then planning to go ahead and drill the horizontal wells because there has been sufficient activity from offset operators that we are comfortable going ahead with those expenditures.

Got it, thank you.

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

Thank you, good morning. A question for you Dave, I think in the press release you suggest that in terms of discussing the outlook for 2011 that you're looking for improved performance from the energy marketing business. Can you give some color as to what's going to drive that other than the new businesses you've gotten into? Is there something more there that is going on?

Well, a couple things, a couple things. Certainly, the new businesses we have gone into are a big part of it. I think we are pretty optimistic about the addition of coal, power and environmental marketing. We started out kind of slow there last year. Coal, we've basically acquired a whole team. The power and environmental side, we just hired a couple of people last year and we hired a couple more, kind of right at year end. We're finally fully staffed there, so we expect that both of those commodity areas will show some significant improvement on the earnings side.

The other area that has been doing well for us at Enserco is the producer services area, primarily on the crude oil side. With all the activity in the Rockies, particularly North Dakota and Montana and the Bakken Shale, we've been active there in working with the smaller producers in those plays. And that has been a very profitable growth area for us as well. So I don't expect large improvements on the natural gas side, but modest improvements. And as some of our longer-term transport contracts roll off, some of those pipeline contracts have been hurting us a little because the basis differentials are less than the pipeline tariff, so that will show a little improvement as well.

Thanks, and the second question I have would be, just in terms of CapEx going forward into 2012, I know there are a lot of moving parts with EPA rules coming out and the like. But when do you think you will be in a position to give us some firm numbers as to what you are looking to spend in 2012?

I think a lot of it will depend on these resource planning processes that we are going through. We've got several, essentially three. One for each of our electric utilities. In Colorado we talked about the one project, which is the $85 million to $95 million that will be in the '12, '13 time frame.

We also have renewable generation we would like to do, that we have to file a resource plan for that. In Black Hills power and Cheyenne Light, we probably have two things to deal with there. One is the potential retirements of these older, 50 or 60 year old coal plants. The other is that we believe we may need some additional peaking resources and the combination of those two utilities.

I would expect, it's probably going to be maybe third quarter, even early fourth quarter before we file those resource plans and complete all that analysis. Once we file those plans we'll have a pretty good idea, assuming they get approved, we'll have a pretty good idea on what we are proposing. But until then we don't know what the specific resource will be, where it will be, or what it's going to cost, that's why we have to go through that resource planning process. So probably late next year is the short answer to your question.

Thank you.

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

Good morning. A couple quick questions. You noted you were evaluating additional rate cases in 2012, after all the rate cases were completed, where are you under earning, or where do you expect to be under earning, just a little color on your thought process there?

I don't know if we are under earning at all. I think there's a couple territories where we will want to continue to evaluate. One of those is our Kansas gas territory. We agreed to a three rate moratorium when we acquired that, and we are evaluating whether we should file a case there or not. The moratorium is essentially over now. That is one of the areas we will evaluate and make a decision on whether we want to file there.

We also haven't had a case in Colorado on the gas side for a while. I think it had been initiated under Aquila's ownership and finalized under ours. That's another territory that it's been several years, two and a half years, or whatever, since we've had a case. That is one we will look at. We've got a couple of those that we haven't done cases on for a while. All the other territories we basically completed a case on last year. And then Colorado electric, we said we had to file a case for the generation there.

Is that a simple process that is expected? What is the process?

It's very much expected, and the commission asked us to disclose what we thought what our rate requests would be, or the increase would be as a percent, and we publicly said to the commission in the 8% to 15% kind of request. And we are still evaluating that in the context of all these things like, accelerated appreciation and other factors, but we would hope to file that in the next few months.

Consistent with the way we've done these other large plant projects in the past, we like the rate case to be complete and effective on the first commercial operation date of the power plant. The commission expects us to file that case. We did a case last year on Colorado electric for other costs in the changes and structures since we acquired it from Aquila.

So really, all of that is up-to-date if you will, it's only a year, year and a half old. The only real new additions to rates are primarily revolving around the addition of the generation in Colorado. It should be pretty straightforward, but it's a big case and there will be a lot of work associated with it.

If I can ask one other quick question. There was legislation proposed in Colorado recently to rescind 30% renewable portfolios and bring it down to 10%. I know similar efforts in California have failed. Is there any legitimacy to this in Colorado, and how are you as a Company considering the possibility of that as it relates to your resource plan?

As we look at that I guess personally I would project that wouldn't happen, but my opinion is no better than anybody else's so it's certainly a possibility the RPS could be peeled back, if it's not 10% maybe it's something else. The new governor said he is supportive of all of the environmental regulations and renewables and other things that are in place, but may not be looking to push any new agenda items in that area.

So we will see how that evolves as he gets more comfortable, he's only been in his role a month or less here. As far as our strategy, and how we plan to comply, I don't think we really want to get way out of head of the renewable schedule. The renewable requirement ramps up to that 30% between now and 2020, and I don't see any incentive to get way out ahead of it. And that way if something does happen, like they repeal it and pull it back, we are not hanging out there with a lot of extra renewables that people may be questioning the recovery and rates for that generation.

So we'll probably take a pretty cautious approach. As we've said before, we'd like to rate base at least some of that renewable generation, but we will go cautiously and make sure we stay a little bit ahead of the mandated schedule for increasing up to the 30%, but I don't see any incentive to get way out ahead, just in case some of these political pressures would result in that mandate being pulled back a little bit.

Sure, thank you very much. I appreciate that.

Your next question comes from the line of Matt Fallon with Talon capital.

Hello. I'm just wondering on the Mancos Shale, if any of those that have -- drilled test wells, if they've gone ahead and decided they are going to start production given where current gas prices are?

Well if you look at drilling permit activity, particularly in both the San Juan and Piceance basins, some of the operators there have been pretty active. They've been filing a lot of drilling permits. Now, what that infers, I don't know. Are they permitting ahead of hopeful increases in gas prices? Or do they believe that current gas prices supports their drilling activity? I guess time will tell, but they are actively permitting still, and actively drilling. So I think that's a good sign.

Okay, and we'll get a sense of what you are thinking in terms of current gas prices sometime midyear? Is that right? And how the Mancos may play out for you?

I would hope that by midyear sometime in the third quarter, we would be able to at least give the results of the three tests we are doing, and give you a sense for how we feel those are from a drilling economic standpoint.

Alright, great. Thanks a lot.

Matt, just the fact we are planning on moving forward, at least preliminarily, we think that the economics work quite well. I mean, otherwise we wouldn't be doing anything.

(Operator Instructions)The next question comes from the line of James Bellessa with DA Davidson and Company. Please proceed.

Good morning. For modeling purposes, what is your advice for when the forward equity sale will be completed or settled?

Well, we've said we reaffirmed our earnings guidance. And one of the assumptions in there that we use to determine the guidance range was a mid-year equity issuance timing. I think that is still as good of that assumption as any.

We've said, publicly, that we would like to delay it as long as we can, and if we can delay it all the way to November, which is the latest we can delay it, we will try to do that. But if our debt to equity ratio climbs up a little too much, or rating agencies get a little nervous, whatever, it's possible we could do some or all of that a little bit sooner than November. For our earnings guidance calculation it assumes a mid-year issuance.

Thank you very much.

At this time there are no further questions in the queue. Sir, please proceed to closing remarks.

Thank you everybody. We had a great 2010 strong improvement in earnings and we are real excited about the growth opportunities we have going forward. Thanks for your attention and your attendance this morning, and your continued interest in Black Hills.

Thank you for your participation in today's conference, this concludes the presentation and you may now disconnect.