Good day, ladies and gentlemen, and welcome to the Black Hills Corporation 2012 Third Quarter Earnings Conference Call. My name is Stephanie, and I'll be your coordinator for today. [Operator Instructions] I would now like to turn the presentation over to Mr. Jerome Nichols, Director of Investor Relations of Black Hills Corporation. Please proceed, sir.

Thank you, Stephanie. Good morning, everyone, and welcome to the Black Hills Corporation 2012 Third Quarter Earnings Call. With me today are David Emery, Chairman, President and Chief Executive Officer; and Tony Cleberg, Executive Vice President and Chief Financial Officer. Before I turn over the call, I need to remind you that during the course of this call, some of the comments we make may contain forward-looking statements as defined by the Securities and Exchange Commission, and there are a number of uncertainties inherent in such comments. Although we believe that our expectations and beliefs are based on reasonable assumptions, actual results may differ materially. We direct you to our earnings release, Slide 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. Similar to prior quarters, we'll follow our same format. I'll give an update on highlights of the quarter, turn it over to Tony Cleberg for financial updates, and then I'll come back and talk about strategy, in particular going-forward initiatives and things like that, before we open it up for questions. Starting on Slide 5, for those of you following along in the webcast deck, third quarter highlights. From a business environment perspective, a couple of things impacted our business. July was the warmest month recorded in the continental U.S. But the impact on electric sales was mitigated somewhat by significantly lower humidity in our service territories. So although the heating degree days or cooling degree days, I'm sorry, were much higher, sales aren't increased proportionally because of the lack of humidity. Similarly, low natural gas prices, which have impacted us for better part of a year plus now, continued to negatively impact our Oil and Gas business. Highlights in the utilities area for the quarter. All approvals and permits were received for our 132-megawatt Cheyenne Prairie Generating Station. All major equipment has been ordered and we expect commencement of construction next spring. Related to that plant, the Wyoming Public Service Commission approved a construction financing rider, which allows us to make small quarterly rate adjustments during construction, the first of which occurs November 1 of this year. We're considering a similar filing in South Dakota. In Colorado, our 29-megawatt Busch Ranch wind project and the associated transmission line was completed and placed into service on October 16. A hearing was held related to our Colorado rate case -- Colorado Gas rate case settlement. We anticipate the Colorado PUC to decide on that in the first quarter of 2013. We set a new peak…

Thank you, Dave. Good morning. As Dave described, our third quarter performance produced a strong year-over-year earnings growth. For the shoulder quarter, we're pleased with our earnings from continuing operations as adjusted, and the 20% improvement over the previous year. Earnings from our utilities, as adjusted, compromised -- comprised 78% of our operating income during the quarter. And also, we recorded a large gain from the sale of the Williston Basin properties that I will discuss later. Moving to Slide 11. We reconciled our earnings from a continuing operations on a GAAP basis to earnings per share as adjusted, which is a non-GAAP measure. We feel by isolating special items that the resulting earnings per share as adjusted better communicates our relevant performance. This slide displays the last 5 quarters. And during the third quarter of 2012, we had 3 special items. The first special item was a reduction of $0.01 for a non-cash, unrealized mark-to-market gain on our $250 million of de-designated interest rate swaps. This was a result of a slightly increase in the long-term interest rates during the quarter. The second special item was the reduction for the gain on sale of the Williston assets. Part of the gain was offset by the third special item related to additional incentive compensation attributable to the sale. Looking at the last year's third quarter, the reconciliation included a $0.63 addition for an unrealized mark-to-market loss on the same $250 million of interest rate swaps. Though considering these special items in the third quarter, our earnings per share as adjusted from continuing operations was $0.42 compared to $0.35 or the 20% increase. Slide 12 displays our third quarter income statement for 2012 compared to 2011. On later slides, I'll discuss the revenue and operating income in more detail, but here,…

Thank you, Tony. Moving on to Slide 21. We have 5 major strategic objectives focused primarily on being an industry leader in all we do. We want to be a leader in operational performance, earnings growth, earnings upside opportunities and, of course, our track record of annual dividend increases. We also want to improve our credit rating to a BBB flat for senior unsecured credit. On Slide 22, related to operating performance. This exhibits exceptional performance and customer service O&M cost per customer, electric reliability and safety. Slide 23 also related to operating performance, demonstrates several things, our superior power plant availability and turbine starting reliability. It also demonstrates that we have one of the most modern generation fleets in the country, and that our power plant construction safety record is fantastic. Slide 24 relates to earnings growth. We expect strong earnings growth driven primarily by capital spending far in excess of our depreciation in both our utilities and our nonregulated energy operations. Slide 25. Helping with our earnings growth, our new Colorado Electric wind project, as I mentioned earlier, was placed in service October 16, way ahead of schedule and on budget. Notably, during construction, we had more than 50,000 man hours worked on that project without a single recordable or lost time accident. Slide 26. Another source of significant future earnings growth is our Cheyenne Prairie Generating Station. That plant is 132-megawatt facility jointly owned by Black Hills Power and Cheyenne Light. It will be constructed in Cheyenne, Wyoming. The construction costs and the associated transmission for that facility are estimated to cost $222 million, and then we've added $15 million for approximate financing cost for the project. That $15 million will be impacted somewhat by our construction financing rider in Wyoming and then what we may choose…

[Operator Instructions] Your first question comes from the line of Kevin Cole with Credit Suisse. Kevin Cole - Crédit Suisse AG, Research Division: I guess with -- I guess, I'll start with a high-level question of given you guys have made pretty good headway in derisking the business through the sale of Enserco, and I guess, trimming down E&P, at what point would you feel more comfortable to offer some of the longer-term regulated focused growth rate?

We talked about that in the past. I don't know. We've said that rather than specific growth rate percentages, we lay out our capital spending forecast instead. And we've done that for several years. And while we consider -- continue to consider whether we should put out a specific growth rate or not, I think the capital expenditure forecast kind of speaks for itself. Kevin Cole - Crédit Suisse AG, Research Division: And I guess, if I look at the CapEx forecast, it does seem reasonable for me to, I guess -- to assume that the EPS growth should be at least the high-single digits to low-double digits between now and 2015?

I mean, that's a reasonable assumption. I mean, if you look at the capital spending forecast for our utilities there, they are certainly pretty strong for the next several years. I won't comment on a specific number but, I mean, we do expect strong earnings growth and we've said that. Kevin Cole - Crédit Suisse AG, Research Division: Okay. And I guess with the dividend, what is your thoughts now with, I guess, 18% growth last year, 15% this year? Is there -- are you going to track the dividend with EPS growth at some level ?

I don't think we have any stated objective of a dividend growth rate percentage. Obviously, our 42-year track record of dividend increases is very important to us. And while we continue to spend a lot of capital, we also recognize that we've made significant improvements in our cash flow and balance sheet. And we typically make the decision to increase dividends and announce that in the first quarter. And we would expect to do that again this coming year. So we haven't made any decisions on the amount of the increase, if you will. Kevin Cole - Crédit Suisse AG, Research Division: Okay. But we shouldn't expect like an EPS like reset and a growth reset in the dividend?

We certainly don't have any stated objective of linking earnings growth to dividend growth rates. Kevin Cole - Crédit Suisse AG, Research Division: Okay. And then, Tony, on the interest expense savings for 2013, are you able to put any numbers around that? Or, I guess, give any visibility on further debt reduction that you plan to take off?

Kevin, I think, the easiest way to look at that is the $225 million that we redeemed, we're probably not going to replace that until towards the end of the year. So you would expect that kind of savings for at least 9, 10 months of the year.

[Operator Instructions] And your next question comes from the line of Michael Worms with BMO.

Just a question on the Colorado renewable portfolio standards. Now that you've completed the -- this first phase, the wind project. Are there any other renewable projects that you're looking at down the road?

We don't have any specific plans to expand our renewables, at least company-owned renewables right now. As you may be aware, Mike, in Colorado, there's the 30% RPS standard, but it's also subject to a 2% rate cap, 2% annual increase related to the addition of renewables. And where we're at now and especially with the low price of natural gas, it appears that it would be very difficult to add additional renewables this time until the price of natural gas increases without triggering that rate cap. So we don't have anything on the drawing board right now. That site, the Busch Ranch wind site, is expandable at least a couple of hundred more megawatts. It's directly interconnected with our system via our own transmission line and so it makes logical sense if we're going to add renewables that that's a great place to do it. But right now, we really can't add anymore and stay underneath our rate cap.

Okay. And just for clarification then, what takes precedence over what? Is it the actual 30% number or is it the 2% rate cap that dictates the next level of renewable build?

It really is the 2% rate cap, Mike. We don't -- essentially, we don't have to meet and can't meet for all practical purposes, the 30% standard and the stairs stepping up to that standard if we would trigger the rate cap. So we'll only add renewable additions to the extent we can stand on the rate cap.

Your next question comes from the line of Tim Winter with Gabelli & Co. Timothy M. Winter - Gabelli & Company, Inc.: I was wondering if you could talk a little bit more about your process for proving out the reserves. The CapEx numbers on Page 24, what's included for the Oil & Gas business there proven that out? And how are you thinking about potential partners? And just a little more color there, if you could.

Yes. The specific Oil and Gas CapEx is included in the earnings guidance assumption list there, Tim. It's got a range, but it's like $90 million to $105 million, I think, is listed in there. And basically to prove up our Mancos reserves, and we've talked about this before of the potential there, we think we need several things to happen. First is we want to drill at least 2, maybe as many as 4 more wells in each basin, both the Piceance and the San Juan. Probably we'll focus our efforts on the Piceance first because the gas is richer, and there's also some liquid yield there. So during this period, a low natural gas prices is probably -- the economics are better to drill there first. But we do need to drill several more wells in each location. Basically what that will do is that will prove up the presence of the Mancos and the productivity of the Mancos under most of our acreage block. And then we still have 2 more questions really to answer related to the productivity of that, what our ultimate resource potential is. One is well design. How long should the horizontal lateral be? How many fracture stages should be performed on each horizontal lateral? Our current wells, the 3 that we've drilled have been about a 4,000- to 5,000-foot horizontal lateral with maybe 15 frac stages. There are other operators drilling wells that are 8,000- or 9,000-feet horizontal lengths and as many as 30-plus frac stages. So the combination of the work other operators are doing, plus the wells that we plan to drill, hopefully we'll get a better sense of what's the optimum well design, which answers a lot. It's per well reserves. It also dictates kind of you're finding a development cost. And then finally, well spacing. Our estimates in here to come to the 2.2 trillion cubic feet of resource potential. Those are based on 160 acres per well. We know that another operator in New Mexico has received approval for 80-acre spacing , which essentially would double that resource number. We also think there's the potential to go as low as 40-acre spacing. So again, those 3 questions, so proving up our acreage, proving up well design and proving up well spacing, those 3 things really need to be done before we ultimately know the true potential of our block. I think that realistically, it's probably going to take at least 2013, maybe part of 2014, to adequately answer those questions. And at that point, then we would be considering alternatives, whether to keep it all and drill it, whether to bring in a partner, whether to bring in a partner for one basin and maybe not the other. We could sell a portion of it. All those alternatives, we want to leave open until we fully understand the true potential of our property.

[Operator Instructions] A follow-up question comes the line of Kevin Cole with Credit Suisse. Kevin Cole - Crédit Suisse AG, Research Division: I just want to maybe dig a little deeper in the 2013 guidance. And so for the power and coal, I noticed in the comment at the conversation in the guidance was a little bit lighter than normal. Are you expecting power to be somewhat a steady-state now with the Colorado project fully in service? And so '13 should look a little bit like '12? And then for the coal side, what should we think about for improvement off of 2012 numbers?

I would say in the Power Generation, the one thing we got a little bit of an extra kicker this year just because of the way the property taxes get graduated in. So flat to slightly down, that's how to think about Power Generation, just for the property tax issue. The second one is on Coal Mining. We expect continued improvement there because we really didn't get the implementation of our revised mine plan until into the third quarter. So we expect year-over-year to continue to improve in that area. Kevin Cole - Crédit Suisse AG, Research Division: And then, I guess, with E&P, with the production of 9.3 to 10.3 Bcfe. I guess, given the asset sale, I guess, my hedge numbers are a little off. Can you give me some color on the -- of those numbers expectations? Do you expect a split between oil and natural gas and for 2013, '14, '15, what's your hedge profile looking like these days?

Well, if you look at the percentage of production, Kevin, if you look at what we did for the third quarter and then we also disclosed how much oil was related to the assets that we sold, you can get a pretty good handle on kind of what the Oil & Gas split is, at least for now. We don't anticipate a radical change in that, basically the big change is going to be the asset sale on the Williston. And we put out both our total expected production number for next year, and we've also put out what we sold through the 9 months of 2012. Yes, that's pretty much the expectation. Kevin Cole - Crédit Suisse AG, Research Division: Then what is the hedge profile for '14 and '15?

Hedging results will be out, including some of the revisions. We had some hedges on the crude oil we sold, which we closed out and did some other hedging during the quarter. That will be updated in the Q, which will come out later today. Kevin Cole - Crédit Suisse AG, Research Division: Okay. And then, I believe, last quarter, you were bracing us for a ceiling test? Did the recovery in that surpass, just kind of take that issue away?

It's is really the sale of the Williston Basin assets and reducing the cost basis by $200 million. We got a total of 2 27. So we took part of that gain and that $200 million reduction in our cost basis really eliminates the need for any ceiling test. Kevin Cole - Crédit Suisse AG, Research Division: Okay. And then with the -- I noticed the normal slide with the CapEx by year, by project, is that no longer being provided? It's just not in the earnings handout.

We don't have it in here.

Yes. Kevin Cole - Crédit Suisse AG, Research Division: Will it come out for EEI?

We haven't decided that yet. Kevin Cole - Crédit Suisse AG, Research Division: And then for the regulated CapEx, can you give me an idea of -- I guess, 2 questions here is what is the shaping of the Prairie Generation for 2013, given that the orders have been put in place? And so should the CapEx be rather chunky towards the beginning of the year so you have greater realization of the AFUDC in your earnings? And then as well, what is the shape of the CapEx during the project build cycle?

I don't know that we've laid that out yet, formally. I mean, we have it internally. I would just mention again that on the Prairie Generation Station, we've identified the actual cost, the $222 million and then the $15 million of financing. And with Wyoming giving us the rider, in effect, what you have is you have 60% of those assets where we will receive the financing cost during construction. And we're going to go forward and talk with South Dakota to try to get the same kind of an arrangement. So AFUDC would not be recorded on that 60%. But in fact, what we had received is we would receive revenue and income as we're constructing the asset that would offset any interest expense. And it's actually better than the interest expense. That help? Kevin Cole - Crédit Suisse AG, Research Division: Yes, it kind of does, yes. And so, I guess, given that the project is located in Wyoming, is the first half or, I guess, the good chunk of the spending at the beginning kind of fit under the CWIP portion, so you're getting more cash returns for the fund of the project?

Well, 60% of the customer ownership essentially is going to be in Wyoming. So that's the portion that will be covered by the rider. Roughly 40% of the asset is going to be dedicated to serving South Dakota customers, and we're still evaluating whether to file a similar rider for construction financing in South Dakota. Kevin Cole - Crédit Suisse AG, Research Division: So if I'm thinking again about the spending, should the project spend cycle look a lot like the Colorado projects if I look at the lumpiness of the spending...

Yes. I mean, it's going look like a gas project. Upfront, all you're doing is making progress payments on turbines and things like that until you actually start taking delivery of major components.

With no further question in queue, I will turn the call over to Mr. David Emery for closing remarks. Please proceed.

Well, that concludes our call this morning. Thank you, all, for your interest in Black Hills. We appreciate your attendance on today's call. Have a great day.

Thank you for your participation in today's conference. This concludes the presentation. You may now disconnect, and have a great day.