Thank you, Janeda. Good morning, everyone, and welcome to the Black Hills Corporation 2012 First 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 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.

All right. Thank you, Jerome.

Good morning, everyone. Thanks for being on the call this morning.

Our agenda for today will be very similar to previous quarters. I'll cover the highlights of the quarter, turn it over to Tony to cover the financial discussion for the quarter.

And then I will get back on for the forward strategy discussion, and then we'll take questions at that time.

As most of you are aware, we're always trying to improve the quality of our investor communications, really to make them more useful to you. And we've made several format changes to this webcast presentation, starting out with the first quarter here in 2012, most of those primarily intended to make things easier for you to review.

The slides are more visual, higher use of graphs, things like that. So please let us know if you like the improvements.

For those of you following along on the webcast presentation, I will be starting on Slide 5. We experienced a very challenging business environment in the first quarter.

Literally record-breaking warm weather across all of our utility service territories, literally a collapse in the natural gas price with the lowest prices since 2001. Both of these factors negatively impacting our financial results.

But despite these challenges, we really have made excellent progress on a number of key strategic goals and objectives during the quarter.

On the Utilities side, we placed in service our new power plant for Colorado Electric and implemented the new rates on January 1. We commenced construction on a wind project to serve our Colorado Electric utility, and we made progress on our Certificate of Public Convenience and Necessity filing for a new $237 million generation project that will be jointly owned between Black Hills Power and Cheyenne Light.

On the wholesale power generation side, our IPP subsidiary placed in service the new 200-megawatt facility in Pueblo, Colorado. That sells via a wholesale contract to our electric utility there.

That was in service January 1 as planned and has been performing great.

At the end of the year, we had a coal contract expire, an unprofitable coal contract expire at our coal mine, and we've been very focused, in addition to that, on improving the efficiency of our mine. And the results are up considerably for the quarter compared to last year.

Oil & Gas, a very positive 23% increase in total sales volumes, driven primarily by our non-operated activity in the Bakken shale in the Williston basin and the gas production from our Mancos gas shale formation test wells in the San Juan and Piceance basin.

On the corporate side, we refinanced our revolving line of credit on very favorable terms, increased our dividend yet again, which is the 42nd consecutive year of increases. And notably, we did close on a divestiture of our Energy Marketing business on the last day of February.

Moving on to Slide 6, financial highlights for the quarter. Income from continuing operations as adjusted was $28.5 million in the first quarter of 2012 versus $25.6 million last year.

$0.65 per share versus $0.64 in the prior year. Recall that we issued almost 4 million shares late last year, which accounts for the difference between the increase in the EPS as opposed to the increase in income.

The increase was driven really by 2 new power plants in Colorado, improvements at the coal mine and increased oil and gas production, really offset by the warm weather at our utilities and the collapse in the price of natural gas.

On Slide 7, this slide really highlights the changes in income from continuing ops as adjusted from the first quarter of last year to the first quarter of this year. Similar to the previous slide, you can see the weather impacts on our utilities more than offset by positive improvements in our 3 non-regulated energy businesses.

With that, I'll turn it over to Tony to go over the financials for the quarter. Tony?

Thank you, Dave. Good morning.

As Dave mentioned, we had several positives in the first quarter that were offset by warm weather. And although EPS as adjusted improved slightly, we had expected stronger improvement from our Utilities and our Oil & Gas segments.

Moving to Slide 9. We've got our earnings per share analysis consistent with prior periods.

And here, we adjust our net income to display a non-GAAP earnings measure that we feel better communicates our relevant performance. This slide reconciles total earnings per share to an as-adjusted earnings per share from continuing operations.

Special gain and loss items are excluded from the GAAP EPS to compute EPS as adjusted from continuing ops. This slide displays the last 5 quarters.

And during the first quarter of 2012, we had 2 special items. The first was a subtraction of $0.18 for a non-cash unrealized mark-to-market gain on our $250 million worth of interest rate swaps.

The second was an addition for a write-off of deferred finance fees related to an old revolving credit facility that was replaced February 1. The old facility had a remaining 15 months to expire, but was replaced early to capture savings and to lock in better terms.

So with the adjustments, the quarter's earnings per share as adjusted was $0.65 per share compared to $0.64 in 2011.

Looking at last year's first quarter, the gain -- the reconciliation included a $0.09 reduction for an unrealized mark-to-market gain on the same interest rate swaps. On Slide 10, this displays our 2012-2011 income statement for the first quarter.

On later slides, I'll discuss revenue and operating income in detail. But from an overview standpoint, there are several notable items that impacted the first quarter's financial performance.

The first notable item was the commencement of operations for our new Colorado generation complex, which increased not only our earnings but also the O&M expenses, property tax and interest expense. Another notable item in the first quarter was an increase in our pension expense of $1.5 million over the prior year.

The pension expense increase resulted from using a lower discount rate, combined with lower return assumptions.

Another notable item was the higher effective tax rate, 35.9% compared to 32.4% in 2011. The 2011 tax rates included the benefit of state R&D credits.

Another notable item during the quarter was the loss in discontinued operations which relates to the sale of Enserco. This loss is comprised of the loss on the sale of the business, plus the operational loss incurred for January and February as we reduced the book of business.

The last item worth mentioning is our EBITDA performance for the first quarter. EBITDA was $110.3 million and represents an increase of about 20% over the first quarter of 2011.

We are pleased with the improvement, and we would expect this level of improvement to continue for the year.

Moving to Slide 11. As you're aware, on February 29, we closed the sale of Enserco.

The cash proceeds were $166 million, right in the middle of what we had estimated. We are satisfied with the result, and we are moving forward.

You might notice that the sale price is actually $108.8 million, but we distributed cash prior to close of $57.5 million. And it's the combination of what we were looking for to get out of that business.

Moving to Slide 12, this is a revenue operating income for total company, and it compares the first quarter of 2011 with 2012. The revenue was up -- or was down significantly, and that's really driven by a $50 million decline just in the Gas Utilities.

Operating income improved 20% over 2011, and that was driven by the new generation and in the improvements in the coal mine.

Moving to Slide 13. This displays our Utilities segment revenue and operating income.

The Electric Utilities operating income in the first quarter improved by $3 million or 12% year-over-year. And this was the benefit of earning returns on an increased rate base, offset by lower retail megawatts sold.

Overall, retail megawatts sold during the quarter decreased by 2.4% compared to 2011.

We estimate that the warmer weather reduced the load and probably lowered the electric utility earnings by at least $0.02 in the quarter. A positive during the quarter was a 30% increase in our off-system megawatts sold.

But with low energy prices, the margins improved only by $600,000 compared to 2011.

Moving to Gas Utilities, operating income declined by 15% or $5.5 million in the first quarter compared to 2011. Retail decatherms sold decreased year-over-year by 21% as a result of warmer weather and had the impact of reducing EPS by about $0.11 compared to 2011.

With continued progress on safety, we continue to have lower workers comp claims.

Moving to Slide 11, (sic) [Slide 14] we have our power generation. And here, we saw the operating income and revenue increase due to the operational commencement of the 200 megawatts of generating facility in Colorado.

Operating income year-over-year increased by $9 million and was primarily driven by the Colorado IPP. We've had a good start, and we are pleased with our performance.

Moving to the Coal Mining segment. The operating income improved by $3.5 million over 2011, primarily driven by the completion of the train load-out contract that had been producing a loss.

The tons sold decreased by 19%. However, the average price increased by 20%.

We expect to continue to make progress on our mining costs and expect improvements over the course of the year as we implement a revised mining plan.

Moving to Oil & Gas. For the quarter, we improved operating income by $1.5 million from the prior year.

Overall, sales volumes increased by 23% during the quarter compared to 2011, but we had planned for a better natural gas price. So it's positive that we improved our operating income, but we had expected more.

We're pleased to see the higher output with oil volumes sold, increasing 40%; and the natural gas volumes sold, increasing 19%. From a pricing standpoint, the oil received improved by 17%.

However, the natural gas received declined by 22%. From a cost perspective, depletion increased by $2 million in the quarter compared to $11 million, and the depletion rate increased by about 5%, reflecting the higher drilling cost added to the depletion pool.

Without a recovery in natural gas, we will be looking at impairing assets for the ceiling test in the second and third quarter and, possibly, even into the fourth. Just for our reference, if you flatline natural gas at $2 per Mcf, the impairment could be in the range of $45 million to $50 million.

This is a non-cash charge and has not been included in our guidance for EPS as adjusted.

Moving to our capital structure, slide 16 shows our capitalization. We feel our present capital structure supports our needs through 2012.

Our net debt to capitalization ratio at quarter end was 54%. The cash proceeds from the Enserco divestiture was a positive, both from lowering our debt and improving our credit metrics.

We feel our capital structure is in good shape for the year, albeit we plan to consider terming out some of our short-term debt. In addition, we closed a new credit facility during the quarter.

We replaced the facility early because of the positive economics of the current pricing, and the 5-year term gave us greater flexibility.

Moving to Slide 17. In our press release, we revised 2012 guidance from a range of $2 to $2.20 to the range of $1.90 to $2.10.

This is for EPS as adjusted and excludes special items. We've identified a number of initiatives to improve earnings over the remainder of the year and believe we can overcome the impact of the winter weather that we saw in the first quarter.

But the collapse of the natural gas prices have caused us to lower our guidance range. The midpoint of our guidance range still achieves an 18% year-over-year improvement.

So to conclude, we achieved improved financial performance in areas we control and like the improvement that we saw from the Colorado generation and from the coal mine. The unseasonably warm weather and the low natural gas prices hurt our performance and create challenges for the remainder of the year.

But as I mentioned, we have a number of initiatives that we will implement to achieve the revised guidance range.

So with those comments, I'll turn it back to Dave.

All right. Thank you, Tony.

Moving on to Slide 19. From a long-term strategic growth perspective, our strategy remains essentially unchanged, primarily focused on continuing to grow organically from our core businesses and primarily driven by growing our investment and rate base vertically integrated assets.

Primarily generation and transmission in our Electric Utilities. As Tony mentioned, extensive control of costs and a focus on operational excellence, continuing to improve the efficiency of what we do every day, ensuring timely recovery of our invested capital and operating expenses for our utility properties.

We will continue to prove up the tremendous value on our Mancos shale assets in both the San Juan and Piceance basins, acknowledging that the pace of that development may be dependent on gas price levels. And then finally, we'll grow our IPP business as opportunities arise.

We want to target a long-term debt-to-cap ratio less than 55%, which is in line with where we are currently, and we'd love to improve our investment grade credit ratings to at least a BBB.

On Slide 20, we have a very clearly defined capital investment program that will drive strong earnings growth for the next several years. This particular slide, we revised our format to provide more detail on our plans, especially for our Utilities, primarily on the Electric side.

It should give you a better sense for our growth-related capital as opposed to our ongoing capital needs for both the Electric and Gas Utilities.

Slide 21 provides a little additional detail on our capital spending plans particularly focused on the growth capital, breaks that down a little more specifically by project and provides more detail really for the capital numbers on the previous slide.

Moving on to Slide 22. This is an update on our 29-megawatt wind project in Colorado.

We commenced construction on that project in March and expect to have it in service well before year end. Having essentially awarded all of the contracts and purchased contracts for the materials.

So things are progressing very well.

On Slide 23, this provides an update on regulatory proceedings for several of our utilities. Our Certificate of Public Convenience and Necessity for the proposed jointly owned Black Hills Power, Cheyenne Light power plant, a $237 million, 132-megawatt gas-fired facility which we're proposing be located in Cheyenne, Wyoming, that proceeding is progressing.

We have a hearing scheduled with the Wyoming Public Service Commission late July, early August. And then pending that approval and the approval of our environmental and industrial citing permits, we would expect to commence construction and have commercial operation achieved in the second quarter of 2014.

We have electric and gas rate cases pending for Cheyenne Light, a total requested increase of $8.5 million in annual revenues. Hearings are currently scheduled for July 18 through the 22.

We do anticipate holding settlement discussions with the Office of Consumer Advocates and some industrial intervenors in the case. Prior to the hearing, we'll see if we're successful in any of those discussions or not.

And then finally, on Colorado Electric, we were granted a 90-day extension to file our Electric Resource Plan in Colorado. We expect to file that prior to July 28.

Moving on to Slide 24, which discusses the impacts of recent EPA emissions rules on our generation assets. Now we've talked about most of these impacts before.

Two rules that impact our generation at this point, so more to come. But the industrial boiler rule, or Boiler MACT as it's called, we've already disclosed that we anticipate retiring 3 older coal plants for Black Hills Power.

Neil Simpson I, Osage and Ben French. We would have to do that prior to the March 21, 2014 compliance deadline for that rule.

All of those plants are in the neighborhood of 50- to 60-plus years old, too small to be able to economically be retrofit to comply with the rules. It makes more sense to retire them, and then our proposal for the new Cheyenne station essentially would offset a large portion of the capacity lost through those retirements.

The Utility MACT Rule, published in February, the more recent rule which covers the larger sized boilers, we're still impact -- evaluating the impact of the final rule on our fleet. But our initial analysis says that really, only Neil Simpson II, which was put on line in 1995, a coal-fired plant at our Wyodak Energy Complex in Wyoming, that's the only plant we expect to really be significantly impacted.

It may require some significant upgrades there. The other plants probably just will require some real minimal upgrades to allow us to comply with some of the start-up rules and things in the new regulation.

Total capital for all of those projects we estimate in the $50 million to $70 million range. We've used $60 million for the purposes of our capital forecast, prior pages.

On Slide 25. This just provides details about our generating fleet and relates to the specific types of pollution control equipment we have there, and then any that we plan to change or upgrade in response to the new EPA regulations.

Moving on to Slide 27. The specific focus of our Oil & Gas business remains unchanged as well.

I mean, we're really focused on proving up the tremendous upside potential of our Mancos shale gas holdings while optimizing our existing properties in the production from those and continuing to pursue additional oil-focused projects. However, in light of current natural gas prices, I think it's important to emphasize that for our Oil & Gas segment, all of our capital expenditures may vary, depending on the oil and gas pricing environment.

So we're constantly evaluating project-by-project economics and considering current levels of prices and making those decisions and will continue to do that.

We do have plans to continue our San Juan Mancos shale gas project this year. We are evaluating that in light of current gas prices, haven't made any decisions yet.

But certainly, as prices continue to fall, we're making decisions or trying to make decisions about what best to do with that capital, whether we spend it now or defer it. We'll continue to focus on our non-operated properties in the Williston basin and the Bakken shale and looking at new crude oil opportunities as they arise as well.

Slide 28 is a Mancos shale play update. In late 2011 and early 2012, we drilled and completed 3 successful Mancos test wells.

One in the San Juan basin and 2 in the Piceance basin. We've booked reserves on 2 of those wells.

The first one in the Piceance and a well in the San Juan basin. We have yet to finalize reserve estimates for the second Piceance well which was put on in the first quarter.

Notably though, that second well in the Piceance basin did produce condensate and higher-Btu-content gas, which will help from an economic perspective on the play in that area. We do anticipate further delineation drilling being required to fully assess the value of our properties there, which, again, will be dependent on drilling economics and natural gas prices.

One benefit we have is that essentially, our entire position in the Mancos is held by production. So we don't have any lease expiration deadlines driving us to drill marginally economic wells.

So if economics don't justify drilling, we don't have to, to hold any leases.

Slide 29 is simply an updated score card related to our strategic goals for 2012. We present this to you every year to show what we intend to accomplish for the year and then let you know our progress throughout the year as we go quarter-to-quarter.

Finally, on Slide 30, the summary of the quarter. While we had to revise our earnings guidance downward slightly, predominantly due to the sustained low natural gas price environment, we're very focused on continuing to serve our customers and build long-term shareholder value.

Put a lot of time and attention into efficiently operating our existing properties and a lot of effort in the continuous improvement in cost-reduction efforts, which we anticipate will offset the impacts of the warmer-than-normal weather in the first quarter for our utilities.

Very excited to have both of our power plants operating in Pueblo, Colorado. Availabilities have been extremely high for brand-new facilities and very pleased with progress that, that project is completed and operations are going as well or better than planned.

The expiration of our unprofitable train load-out contract at the coal mine and the focus on cost-containment measures there, and a revised mining plan that will allow us to mine an area of our mine property that has lower overburden and shorter haul distances for the next several years will really help us improve results at the coal mine. They showed up in the first quarter and will continue as we go forward.

We've got several key initiatives in our facilities and really had a good start to the year, absent the storm, weather and the gas price collapse.

That concludes our remarks. We'd be happy to open it up for questions.

By the way, I think Jerome and Val did a great job with the presentation. And so on the guidance revision.

So I see you lowered the range by 10%, but weather was negative $0.13 and E&P looks like maybe $0.15 worse than expected, which I guess still kind of paints the challenge in your head. Can you help me better understand, I guess, where you're going to find the cost reductions and if they're more one-time in nature or permanent?

And then also, kind of where else do you see help coming from?

Some of them will be permanent. Others will be just one-time from the standpoint that a fair amount of our compensation has a variable portion.

So if we don't achieve our plan, in effect, we save money. So that cost will just automatically go down.

But as we build the next year's plan, it'll come back into our expenses. But a number of the initiatives that we've got going, we've got both not only cost initiatives.

There are other ways -- other items that we're looking at to improve recovery or improve our revenue. So it is a combination.

Okay. So I guess it's going to be a mix of like some hold co cost and then just kind of some pennies here and there, just across all the businesses?

Yes. And we're essentially looking in every business for opportunities, both for revenue and for cost, Kevin.

And there are things like deferring hiring or trying to reorganize in certain circumstances so we don't have to replace departures as people leave, not filling new positions that might have been planned for the year. There's a lot of that kind of activity going on right now, as well as just really turning down the screws on expenses period.

Deferring some maintenance expenditures, different things to the following year if it's feasible to do so without taking any risks, things like that.

Okay. That's helpful.

And then on the conventional E&P side, can you help me understand the driver of the average hedge price, given that it looks like it almost fell one-to-one with the well-head costs which implies, I guess, a low hedge ratio? So I guess, just help me to understand like how hedge is the business for the rest of the year, and that percentage ties to the $270 price?

Part of the hedge pricing or the average hedge price includes the unhedged portion average. So as -- in effect, the price of gas just comes down.

Then in effect, it impacts our average. But your question of how hedged are we for the rest of this year?

We're quite a bit hedged, much more than 50% for the remainder of this year.

Okay. The next -- so I guess, is it safe to say that the reduction in production came from the natural gas side?

We were up in our sales volume in natural gas, but the price was down significantly. Yes.

That's the first quarter. Was that your question?

I guess for the full year?

Yes. We still expect that production will be up for the full year.

But...

Okay. So it's in line with your prior guidance then?

Pretty close, yes.

Pretty close, yes.

Okay, okay. So I must have misread that.

I think we might have adjusted the bottom end down just slightly. [indiscernible] It's pretty similar for total expectations.

Yes. Very nominal.

And then maybe this qualifies as a follow-up, so don't get the operator mad at me, but on the Mancos, did you say that you would consider delaying, I guess, your development plans if natural gas stays kind of constant where it's at? Or I guess, maybe -- or should I think about it as, I guess, spread between where natural gas trades versus your $1.30 to $1.40 well-head costs?

Yes. Well -- and you've got lease operating expenses and royalties and everything else in there.

We believe that an ongoing program -- certainly not feasible at a $2 NYMEX gas price, and we're evaluating whether we want to spend the capital to even do the delineation drilling at that level. If we expect prices and we see some encouraging signs kind of in the third and fourth quarters that maybe prices will at least continue to go up to acceptable levels, we would like to spend that drilling capital because we believe it's very important for us to spend a little bit of capital in both base and to prove up the full value of our holdings.

We wouldn't expect to undergo a full-blown drilling program at these price levels by any means. And prices stay at $2, I think it's questionable whether we really want to go out and spend that money late this year.

We might defer some of that into next year if we just don't see any improvement there.

Do you have like, I guess, a breakeven number in mind? I think you kind of mentioned it was like $3 or $2.50?

Yes. Don't have one specifically.

I mean, we've made the comment before that we think that at a $4 natural gas price, that play would be very economic, and we'd be very encouraged by that. Certainly, we would be willing to drill delineation wells at a price lower than that, because they would still generate acceptable returns.

Might not be what we really want, and so we would spend as little capital as possible to do the delineation drilling. But we don't want to do it if our returns are negative or below our cost of capital.

So that's really where we're sitting, and $2 is clearly south of that. Somewhere between $2 and $4 is probably a decent assumption.

But it varies depending on the size of your program, how many wells you do. That affects your purchasing power for rigs and supplies and pipe and all of those things.

So it's kind of hard to give you a specific number if you're only drilling a few wells at a time.

Is there an increase in, I guess, pipe development around that territory to tighten up the bases relative to NYMEX?

I wouldn't say there's any real significant ongoing projects now.

Just wanted to ask you on some of the comments on the Oil & Gas side. It seemed like a renewed interest in some crude opportunities.

Just wonder if you could expand on that, please.

Yes. I wouldn't say it's a renewed interest, Jeff.

When we finished our strategic review of our Oil & Gas segment last year, we were pretty clear in stating that we wanted to define the potential of our Mancos; focus on some oil opportunities, maybe even some isolated oil exploratory opportunities; and maybe invest 10% to 15% in some of our capital budget in more oil-related exploration opportunities that had significant upside impact for us. To the extent we have some good oil development opportunities, the Bakken shale is a good opportunity to the extent we can either accelerate or increase our activity in some of those areas.

We'll be focused a little more on that as gas prices are so weak. Now, of course, everyone else is doing the same thing.

So you have to qualify it a little bit, that we're not anxious to run out and pay too much to get involved in an oil project. That's not our objective.

So it's continuing to be very prudent in what we look at. What can we do with existing oil assets?

We have our existing oil plays we're in, and maybe look at a new project or 2, particularly kind of more on the exploratory step-out development type areas.

Okay. Yes.

I just -- on the slide, it said pursue new crude oil opportunities with large-scale reserve potential.

That's the exploratory nature. We really don't want to do an exploratory project unless -- if we're going to commit a couple of million dollars to an exploratory project, we'd like something that has enough reserves to significantly move the needle.

So...

I do like the new format of the press release. It gives the information that I've been asking for, and it's well laid out.

I also like the slide show, particularly that picture of the Pueblo facility, with the sun going down and every light on that plant on. And it looks like it's surreal.

I don't even know how you staged that.

Pikes Peak in the background. Yes.

It's a beautiful picture. Thank you.

And anyways, a couple of questions. I think Tony said that in Electric, EPS was off $0.02 due to the weather.

Did you say, Tony, how much Gas EPS was off due to the weather?

I did. It's about $0.11.

for Gas year-over-year. And what I said about the Electric, that's a little harder to pin down, but it's at least $0.02.

We know that.

Okay. Then on the Electric Utilities side, and I learned quite a bit with your new information, and I was underestimating how much DD&A was.

How much interest expense was. But I was surprised on your going to the full tax rate on the electric utility, 40.9% in the most recent quarter versus 30.4% a year ago.

Can you explain the reasons why you had the full tax rate or even higher?

The tax rate for the quarter was 35.9%.

At the electric utility?

Oh, at the electric utility. Oh, I'm sorry.

Some of those are state true ups and a little bit of moving taxes among the segments. So I...

You may not see this high of a rate for the rest of the year?

No, no. We will not be at that high of a rate.

There'll be a little more information in the Q as well if you would like to clarify some of that.

Yes, that lays it out.

Just a quick question for you on the Coal Mining business. You indicated that there's going to be a revised plan.

You're going to relocate the mining operations to areas that are closer to, I guess, the plants and a shorter overhaul and all that, which will result in reduced costs. Can you give us some detail in terms of how much costs -- first of all, when are you beginning this new plan?

And then secondly, how much of the cost savings will be captured in 2012 versus the cost related to the plant or the mine in 2011?

Well, we just received approval for our revised mining permit, which allows us to kind of change the direction in which we're mining right now, Mike. And that essentially allows us, as you said, to move closer to the plants with our current mining activity, and it reduces both the overburden, which is lower there, and it also reduces the haul distances we have for the overburden, which reduces expenses as well.

When you open a new cut like that, it's a process. So we're actually going to still be mining coal at the far north end of our pit and moving overburden kind of at the south end, closest to the plant.

So you won't see -- at least not immediately. I think the impact will gradually get better as the year goes on here.

So we haven't put out a quantification of what we expect the 2012 numbers to be, but you should see kind of a gradual improvement quarter-to-quarter as we continue to get that new pit developed on the south end.

Okay. So the impact will probably be more impactful in 2013 than 2012?

Yes, yes, because it will be in place for the full year. We only have 1/2 year of impact this year, and it's going to take a little while to get the new cut open and getting it up to full production from that location.

All right. Thank you.

Thanks, everyone, for your time and attention this morning. As always, we appreciate your attendance on our call.

And for those of you who are headed to the American Gas Association Financial Forum, we look forward to seeing you there. Thanks, everyone.