Thank you, Chaneda. Good morning, everyone, and welcome to the Black Hills Corporation 2011 Fourth Quarter and Full Year 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 2 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 David Emery.

Thank you, Jerome. Good morning, everyone.

Thanks for your attendance this morning. For those of you following along on the webcast presentation, we will give slide numbers periodically, so you'll know which slide we're speaking from.

On Slide 3, an agenda here, similar to previous calls, I'll cover fourth quarter and full year highlights and review of our accomplishments. Tony Cleberg will go over the financials for both the quarter and the full year, and then I'll talk about strategy and forward-looking information on new projects.

But before I start with a specific discussion of some of the webcast slides, I want to comment on our 2011 earnings as disclosed in our earnings press release issued late yesterday.

As a result of our January 18 announcement regarding the pending sale of our Energy Marketing business, our 2011 financial statements will reflect Energy Marketing as discontinued operations. However, since the announcement of that sale occurred subsequent to year-end.

In our earnings release, we also presented a non-GAAP adjusted earnings per share number for 2011 that included Energy Marketing results. We did that for the purposes of more accurately comparing 2011 results against the prior year and also against our previously issued earnings guidance.

So on that basis, our 2011 earnings per share as adjusted and including Energy Marketing was $1.92 per share, a 6% increase compared to $1.81 in the previous year. As you might recall, following a real challenging first quarter of 2011, we revised our initial earnings guidance of $1.90 to $2.15, downward $0.20 per share to $1.70 to $1.95.

We later even narrowed that range further. We're very pleased with the achievement of $1.92 per share, which not only represents the 6% improvement against 2010, but it's also within the lower end of our original guidance range, I think despite a very challenging start to the year.

So throughout the webcast slides, as I mentioned Energy Marketing will be presented as discontinued operations. But I felt it was important to provide you some perspective on how we're viewing our earnings performance in 2011 without the noise, if you will, of the discontinued operations discussion.

So starting on Slide 5, fourth quarter summary, our income from continuing operations as adjusted were $19.7 million compared to $17.4 million in the fourth quarter of 2010, an increase of nearly 13%. That was driven primarily by strong performance in our Electric and Gas Utilities and some slight improvement in our nonregulated energy businesses as well.

On Slide 6, 2011 full year income from continuing operations as adjusted was $67.7 million compared to $64.8 million in 2010 for an increase of 4%. That increase was driven primarily by strong performance in our Utilities partially offset by a lower results from our Energy Marketing group.

On Slide 7, highlights for the Utilities in 2011. We made significant progress on several key strategic goals during the year that will yield some significant earnings growth in 2012 and beyond.

Notably, we completed the Colorado Electric's 180-megawatt power plant in Pueblo, Colorado on-time and on budget. It began serving customers on January 1.

The rate increase associated with the plant was effective on January 1 as well. That project had an extremely aggressive construction timetable.

We literally completed all construction in less than 18 months. And while we're pretty proud of that, we're even more proud of the fact that our safety incident rate on that project was more than 75% below the national average for projects of that nature.

We're very proud of that.

In addition, our first month plant availability was just slightly under 100%, which is phenomenal for a new Power Generation facility.

We also made during the year substantial progress on other utility growth initiatives. In Colorado Electric, we received approval for and commenced our 29-megawatt wind project.

We also continued to regulatory approval process to construct a third utility owned 88-megawatt gas turbine at our Pueblo generation site. That process is still ongoing.

At Cheyenne, Wyoming we announced the joint facility that will be owned by Cheyenne Light and Black Hills Power, 132-megawatt, $237 million plant. We're in the process of seeking a Certificate of Public Convenience and Necessity for that facility now and expect hearings to commence at the end of July.

Finally, we were also advancing several transmission projects in our utilities, that 2 largest of which are in Colorado, but $45 million to $50 million total for those transmission projects underway.

On the nonregulated area, for 2011, really our year there was highlighted by refinement of strategies in 3 of our 4 nonregulated energy businesses. In Oil & Gas, we've been undergoing complete strategy and business review.

We completed that as announced last year and recruited a strong new leader who joined the company in mid-December. Our Mancos shale test drilling program in Colorado and New Mexico showed extremely promising results, and we'll talk about that more later.

We did book some significant reserve quantities at year-end. And importantly, after a couple of kind of challenging years that ENP business and this one continued but notably our volumes sold were up 4% for the year and our crude oil volumes driven primarily by our Bakken Shale activity in North Dakota, were up 20%.

Energy Marketing, we announced the decision to divest of our Energy Marketing segment on January 18, we still expect to close that prior to the end of the first quarter and expect net cash proceeds through the closing process to total $160 million to $170 million.

The independent Power Generation side, we completed Colorado IPP's 200-megawatt project for Colorado Electric our utility again on time and on budget was put in service on January 1 as planned and has a 20-year power purchase agreement with an affiliate Colorado Electric utility, which has been approved by the Colorado PUC. That plant also had first month availability just slightly under 100% which again is very excellent for the first month of operation on a new power plant.

At our coal mine, we made substantial progress during the year in reducing our cost and improving financial results. At year-end, we fulfilled a third-party train load-out contract and that was the contract that was our worst contract as far as economics go.

We lost approximately $4 a ton on that contract in 2011. That contract is terminated.

We made the strategic decision after that contract expired to focus almost exclusively on a mine mile strategy with Coal Mine. We idled our train load-out facility and implemented a 17% workforce reduction associated with the decrease in production.

Moving on to Slide 9, corporate highlights for the year. We did recognize non-cash unrealized mark-to-market loss on our interest rate swaps of about $42 million in '11 that was compared to only about $15 million loss in '10.

We also completed several key debt and equity financings during the year. And on February 1 of this year, we refinanced our $500 million revolving line of credit on very favorable terms.

Notably in both 2011 and then recently in 2012, we increased our dividend to shareholders. And most recently in January of this year, we increased the dividend to $0.37 a share, equivalent to an annual rate of $1.48.

That increase represents the 42nd consecutive year of dividend increases for the company, a track record we're extremely proud of.

I'll now turn that over to Tony to comment on the financial statements. Tony?

Thank you, Dave. Good morning.

From a financial standpoint, our full year for 2011 improved over 2010 even with the earnings shortfall that we saw in the first quarter. Our first quarter earnings per share as adjusted and excluding Energy Marketing, was $0.10 below the prior year.

So we feel good about our progress over the last 3 quarters, and the fact that we finished $0.02 ahead of 2010.

In my comments, I will continue to address both the fourth quarter and the full year.

Moving to the earnings per share analysis on Slide 11. Consistent with prior periods, we adjusted our net income to display a non-GAAP earnings measure that we feel better communicates our relevant performance.

Special gain on loss items are excluded to compute net income or earnings per share as adjusted. This slide displays the last 5 quarters and the full year for 2011 and compared to 2010.

The only special item included in the fourth quarter of 2011 was the addition of $0.02 for the non-cash unrealized mark-to-market loss on the $250 million of interest rate swaps. So with that adjustment, the quarter's earnings per share as adjusted from continuing operations was $0.46 per share compared to $0.44 for 2010.

Looking at last year's fourth quarter, the reconciliation included a $0.44 reduction for a unrealized mark-to-market gain on the same interest rate swaps. Our full year continuing operations as adjusted was $1.69 compared to $1.67 for 2010.

The discontinued operation line includes our Energy Marketing segment, which we're divesting. And also the discontinued operation excludes indirect corporate expenses related to Energy Marketing.

These are now charged or reclassified to continuing operations, which is a GAAP requirement.

At the bottom of this slide, the earnings per share impact is shown for reclassified expenses. So with these adjustments, the full-year net income as adjusted was $1.92 compared to the previous year of $1.81.

Slide 12 displays our 2011 and 2010 income statement, both for the fourth quarter and the full year. For the fourth quarter, our GAAP income from continuing operations declined by $16 million, driven by improved operating income of $5.3 million and reduced interest expense of $1.7 million, all of which is offset by the large swing in the mark-to-market valuation on the interest rate swaps.

Last year, fourth quarter had a $26.5 million gain on the interest rate swaps compared to a $1.4 million loss this year.

Continuing down, the tax rate for the quarter was 35.6% compared to 31.6% in the fourth quarter of 2010, and that's due to the 2011 not benefiting to the same extent from permanent tax differences.

Looking at the full year performance, operating income before the gain on sale of assets improved by 7%. The interest expense was flat and the mark-to-market changes on certain interest rate swaps resulted in a $26.8 million loss compared to 2010.

Other income decline primarily due to lower AFUDC equity income.

Continuing down the income statement, the full-year tax rate of 31% compares to 26% in 2010. Last year's income tax benefited from an IRS settlement that accounts for about 3 points of that 5-point difference.

Both years benefited from the regulatory requirement that required us to flow through the tax benefit related to certain expenditures that have been previously capitalized for tax purposes. Albeit, 2010 had a larger benefit and accounted for most of the remaining 2 points difference.

The discontinued operations includes the Energy Marketing business. And as you can see, it improved significantly year-over-year and exceeded our expectations in the fourth quarter.

The segment was still under performing on a risk-adjusted basis, which is a big part of our decision to divest.

Looking closer at operating income, Slide 13 displays our segment roll-up of operating income for both the quarter and the full year. The Electric Utilities recurring operating income in the fourth quarter improved by $2 million or 11% year-over-year, and that reflects the benefits of earning returns on increased rate base and increased megawatts sold.

The overall retail megawatts sold during the quarter increased by 2.6% compared to 2010. The off-systems megawatts sold increased by 40%.

With the low energy prices, the increased off-system power sales increased margins by the $600,000 in the quarter compared to 2010. Also, the quarter included $700,000 of a catch up adjustment for off-system sales margins that have been deferred and settled as part of the Colorado Electric rate case.

Overall, off-system sales margins for the full year increased by $300,000 compared to 2010.

And looking at the year for the Electric Utilities, operating income excluding the sale of assets increased almost 17% over 2010. And this is just reflecting earning returns on prior capital investments, that is the primary driver.

Moving to Gas Utilities, operating income improved 7.3% in the fourth quarter compared to 2010. Retail decatherms sold decreased year-over-year by 1.5% primarily driven by warmer weather in the latter part of the year.

So operating income improvement was driven by earning returns on prior year's capital investments and lower expenses.

For the full year, operating income excluding the gain on sale of assets, it increased 15% driven by rate settlements and lower costs.

During the year, we made great progress on safety, which had a positive impact on workers comp claims and lowered our expense.

Moving to Oil & Gas. For the quarter, we were at about break even in operating income.

But this is an improvement of $2.7 million from 2010. During the quarter, overall production increased 13% from 2010 with oil sold increasing 39% and natural gas increasing 6%.

The average hedged price received was flat from 2010 for the natural gas and was higher by $16 a barrel for oil. Overall, the revenue increased by 46%.

From a cost perspective, depletion increased $3 million in the quarter compared to 2010 and production taxes increased $1 million. The depletion includes a $4.3 million true up, that was $1.6 million higher than the fourth quarter of 2010.

The higher cost associated with the Bakken drilling program was a major contributor to the increased depletion rate.

For the year, operating income was down about $2 million compared to '10, resulting from 12% lower price on natural gas on flat volume, partially offset by a 20% increase in oil production with a 5% improvement in price.

The next segment, Power Generation, we saw the operating income increase by $800,000 for the quarter and by $1.2 million for the year compared to 2010. The increase was attributable to lower expenses and better coal plant availability in 2011.

Moving to the next segment, Coal Mining. The operating income declined by $2.2 million from 2010.

As a result of higher mining costs partially offset by increased pricing for a portion of our production. We have had previous -- we have various cost issues at our mine throughout the year and the third-party fixed price contract which was under water by about $4.

During the quarter, the final shipments were made under this contract and exceeded the previous quarter by 200,000 tons. So we lost an extra $800,000.

It contributed to sequentially increasing our quarterly loss by about $0.5 million.

Unfortunately -- fortunately, this contract expired at year-end and with the various initiatives implemented during the year, we expect a substantial improvement in operating income from Coal Mining in 2012.

Moving to our capital structure, slide 14 shows our capitalization. We feel our pricing capital structure supports our needs through 2012.

Our net debt to capitalization ratio at the quarter end was 57%, which is a little higher than we'd like to be but with the new generation in Colorado and the proceeds that we expect out of the Enserco divestiture, our credit metrics will improve quickly.

In addition, we closed a renewed credit facility this week. We renewed early because the pricing was better and a five-year term gave us much better flexibility.

The last point I'd like to make is in the press release, we reaffirmed our 2012 guidance range of $2 to $2.20 that we issued on January 18. And although we have some downward price movements since then on Oil & Gas over the last week, we are reaffirming that range.

So to conclude, we're pleased with the overall financial performance in the fourth quarter and the full year, and particularly with the continued strengthening that we're seeing in the 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 Dave.

Thank you, Tony. Moving on to Slide 16.

During the past several years, we've accomplished a major transformation of the company, from being primarily driven by non-regulated assets and earnings, to now being driven by much more stable assets and earnings, our strategic accomplishments over those last several years provide much more focus on our core Utilities, Power Generation and fuel production businesses, which in turn provide more stable future in cash flow and earnings as well as earnings growth for investors.

Slide 17 is just an update to our strategic initiatives timeline. This is provided to give you an estimated timing that was with regard to many of our key projects and initiatives.

Slide 18. Our clearly defined investment program will drive strong future earnings growth, with nearly $1 billion in capital spending plan for 2012 and 2013.

Slide 19 provides the detailed breakdown of our key long-term growth opportunities for the 2012 to 2015 timeframe. This slide doesn't include maintenance capital expenditures or other smaller projects, just primarily focuses on what we would deem large growth-oriented type projects.

It's been updated also to provide a little more timing detail for you on some of the announced projects as far as which year those expenditures will occur and to what amounts.

Slide 20, regulatory approval in Colorado. We received approval from the Colorado Public Utilities Commission for the rate case associated with our new utility power plant for our Colorado Electric utility.

Those rates, as I mentioned earlier, went into effect January 1 of this year, same day as commercial operations of the new power plant.

On other fronts in Colorado, we have an electric resource plan that we expect to file in the second quarter there. That resource plan will deal primarily with how we intend to meet the renewable portfolio standards in the state of Colorado having this completed 2 new power plants that need to do a lot of additional resource planning around baseload or peaking facilities, has been mitigated quite a bit.

So that plan will focus primarily on renewables.

As I also noted earlier, we're still in the regulatory process on this proposed 88-megawatt turbine that we'd like to add to our Pueblo complex. That's the replacement facility for the W.N.

Clark coal-fired plant in Canyon City, Colorado that we agreed to retire under the Colorado Clean Air Clean Jobs Act. We're in the process of working our way through the regulatory process there, expect a ruling from the PUC, hopefully, sometime this month, which will give us a little more clarity.

We do have the right to own the replacement resource for the Clark plant, the 42 megawatts that we're losing there. So regardless of the outcome of this specific hearing, we do still have the right to own that replacement resource and we'll see how the regulatory process plays out over the next month or so here.

Slide 21. Our 2012 earnings growth is going to be driven largely by 2 new natural gas-fired generation projects that started serving our Colorado customers on January 1.

I won't reiterate those 2 projects again, but I will reemphasize that we had an exceptionally short construction schedule on this facility, literally 18 months start-to-finish. The projects were completed on time, on budget and with a phenomenal safety record and excellent first month availability.

So truly speak, volumes of the quality of our Power Generation, construction and operating team. They're literally world class.

Slide 22. We received approval during 2011 for and we're proceeding with our 29-megawatt wind project for Colorado Electric.

As you can see, we're about halfway through the process of awarding construction contracts and procuring materials and expect to start construction soon as weather permits with the intent of having that facility completed and in service prior to year-end.

Slide 23, other regulatory updates. I mentioned previously that on November 1, Cheyenne Light and Black Hills Power filed a joint request for a Certificate of Public Convenience and Necessity to build a new facility, 132-megawatt project in Cheyenne, Wyoming.

That generation serves 2 purposes. One is replacement of some older coal-fired generation in Black Hills Power that we'll have to repair under the new EPA regulations which I'll discuss shortly.

And then also to meet ongoing demand requirements, particularly, in the Cheyenne, Wyoming area. We had initial hearing date set at the end of July on that CPCN, assuming approval, we would expect to have the plant completed and commercially available by the second quarter of 2014.

And then finally on December 1, Cheyenne Light filed an electric and gas rate case requesting an additional $8.5 million of increase in annual revenues there. That case is not related to the proposed new power plant.

It's just related to cost increases. Since our last rate case in Cheyenne.

Moving on to slide 24. New EPA regulations governing air quality on power plants and industrial facilities have received a lot of attention over the last year or 2.

Two of those rules have a specific impacts on our facilities. One is what's called the boiler MACT rules which covers small utility boilers and primarily industrial boilers.

Those rules were effective May of this year with a March 2014 -- 2014 compliance deadline.

Based on those regulations, we anticipate retiring 3 of our smaller coal-fired units at Black Hills Power for a total of about 82 megawatts. All those facilities are 60-plus years old have little-to-no remaining book value and cannot be economically retrofit to meet the new pollution control standards.

As I mentioned earlier, we would replace those resources with the proposed gas-fired unit in Cheyenne and in Black Hills Power's proportionate ownership for that facility.

The new utility MACT rules which were issued on December 1 and we've yet to finalize publication in the federal register, which I think, is supposed to occur this month, will be effective in approximately 3 years. We're evaluating the impact of that final rule on our generation fleet.

But our initial analysis suggests that only our Neil Simpson II coal-fired plant, which was placed in service in 1996, will require any additional upgrades to be compliant with those emissions standards. Still doing some preliminary engineering work on that, but estimate $30 million to maybe $50 million or a little more capital cost associated with bringing that facility into compliance.

We'll provide additional details as we make decisions along the way on our plans to break that facility into compliance.

Slide 25 provides details regarding the impact of various new EPA air emissions regulations, provide that just for your information. I won't spend much time on it today.

On Slide 26, Oil & Gas update. We finished drilling and completing our 3 Mancos formation test Wells.

Two in the Piceance Basin of Colorado and one in the San Juan Basin of New Mexico. This slide provides detailed well test information and reserve information for the 3-well drilling program.

The well results have met our initial expectations and gross reserves averaged more than 6 billion cubic feet per well.

One of the 3 wells was not completed and tested in time to book reserves prior to year-end. But despite that, we still included a total of more than 42 billion cubic feet of gross reserves from the 2 producing Mancos wells and 5 offset proven undeveloped locations in our year-end reserve study.

We do expect to book additional reserves associated with that third well sometime in this first quarter of 2012.

Moving on to Slide 27. As we've discussed previously, our 74,000 acres of Oil & Gas leases in the San Juan and Piceance Basin include nearly 460 potential Mancos formation drill sites, based on 160 acres spacing per well.

Our targeted well cost for an ongoing Mancos drilling program were in the $1.30 to $1.40 per net in Mcf equivalent basis.

Our leases are held by production from other zones, and they won't expire as long as we maintain that production. So unlike other operators and many other shale place, we're not forced to drill sub economic wells, just to hold leases.

In the way of ongoing plans, in the third quarter of this year, we intend to commence a single rig drilling program in the San Juan Basin, targeting the drilling of 4 additional Mancos Wells before year-end. We probably won't have all 4 wells completed and producing by year-end, but hope to have at least 2 finished.

We believe these wells will still generate an acceptable return on our investment even at current natural gas strip prices. They play a very important role in continuing to assess the very large potential opportunity we have with our holdings in the Mancos Shale.

Slide 28 is our 2011 scorecard. As a reminder, this is our way of holding ourselves accountable to you, our shareholders.

At the beginning of the year, we try to set out our key strategic initiatives and goals for the year and then monitor our progress as the year progresses. We had an excellent year in 2011 completing many key objectives.

Slide 29 is a new scorecard for 2012, winning on our key goals for this year.

And finally, Slide 30, in summary for the year, 2011 was a very good year for us. We're very focused on serving our customers and building shareholder value.

We refined our strategy and business mix. In the Oil & Gas the area, we announced a new strategy much more focused on some limited oil exploration in our Mancos shale development.

And our coal mine, as I discussed earlier, we made the decision to discontinue train load-out sales and focus primarily on our mine mouth operations there, and we divested our Energy Marketing business or made a decision to divest our Energy Marketing business. During the year we had very strong execution on several key major projects that will drive earnings growth notably the 2 power plants in Colorado that will serve our electric utility there.

We also announced during the year over $300 million in new growth projects slated to be completed in the 2013 and '14 timeframe that will also help us drive strong earnings growth. We're very well-positioned to take advantage of future opportunities.

So all of these things I think will help us provide solid long-term earnings growth and good shareholder return for our shareholders well into the future.

That concludes my remarks. I'd be happy to entertain any questions if anyone has some.

The question, I have is related to the press release where you discussed the Colorado rate decision. You mentioned that you received an additional $17.5 million for other cost including purchase power and transmission.

Now just, I assume the purchase power part of that piece relates to the merchant plant at Pueblo as well. And then the other question would be regarding transmission.

Exactly what was the transmission project? And why wouldn't transmission be included in base rates rather than in the other -- the other category?

The answer is on the IPP, the purchase power definitely includes the impact of the new 20-year power purchase agreement that we have with our own IPP subsidiary. And one of the things that we did through the rate case and worked this out with the staff and others that things like additions to transmission, fuel and other things will not be included in base rates.

And that we'll deal with them essentially entirely in the riders or cost pass-through mechanisms. So some of the newer transmission projects and things will go through in that account, if you will, or that portion of our rate structure rather than be included in base rates, some of that relates the timing of the projects and other things.

And then future additions, if you recalled there in Colorado, there's a provision that allows us to do future additions to the transmission system and recovery a return on those without going back through a general rate case.

Fair enough, thank you. And then the other question I had was regarding the coal business.

It looks like in the fourth quarter, O&M expenses went up dramatically over the same period in 2010. And so we can you just kind of discuss that a little?

Is that the continuation of the cost pressures you had at the coal mine. And then secondly, I think, Tony was suggesting that earnings would improve for coal in 2012.

I was just wondering if you could give us a little bit more color around what will -- what the drivers will be and how we should look at the cost structure at the coal business in 2012?

On the -- I mean, let me take the last question first. The main thing there, Michael, is by in effect having this contract expire at year-end.

If you take 4 bucks times 1.7 million tons, we should get that improvement right away. And then we've got ongoing efficiencies, things that we've done to try to reduce cost.

So we expect not the same kind of improvement, but some nominal improvement for those also.

As far as fourth quarter expenses, Mike, one of the drivers there is we moved significantly more overburden that quarter than we did in the prior year, coal tonnage was similar. But we did move quite a bit more over burdened in that quarter, which will drive costs.

Yes. I think our stripping ratio went up to 2.9 versus 2.6.

So that really gets at it.

One of the things we've done which also I think speaks to 2012 coal mine expectations and we mentioned it briefly in our webcast presentation materials is that, we've applied for a new mining permit at wide act which essentially allows us to reverse the order in which we mine a portion of the coal mine. And what that will do is to allow us to in the next few years mine some lower overburdened areas of the mine.

And then in a couple of years, we have a price reopener in one of our larger contracts that we discussed a little bit last year, we'll be back into the higher overburdened areas, but our revenue will be higher as well. So it allows us to kind of matchup the timing of our mining expense with our coal prices at current levels.

We're in the process of amending that permit. We hope to have approval in the second quarter and maybe be able to commence different mining operation in the third quarter, which will also reduce expenses primarily just overburdened.

All right. Well, thank you.

We certainly appreciate everybody's time today and your interest and your continued interest in Black Hills. Have a good weekend.

Thank you.