Good day, ladies and gentlemen, and welcome to the Black Hills Corporation 2013 Fourth Quarter and Full Year Earnings Conference Call. My name is Esteban, and I will be your coordinator for today. [Operator Instructions] As a reminder, this conference is being recorded for replay purposes. I would now like to turn the presentation over to Mr. Jerome Nichols, Director of Investor Relations of Black Hills Corporation. Please proceed, sir.

Thank you, Esteban. Good morning, everyone, and welcome to the Black Hills Corporation 2013 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 statements. 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 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. On Slide 3 of the webcast presentation, for those of you who are following along, our format will be similar to prior quarters. I'll give an update on the quarter and the year from a highlight perspective. Tony Cleberg will go through the financials. And then I'll talk about the forward-looking strategic overview. So skipping to Slide 5, fourth quarter highlights. From a business environment perspective, we had colder weather in the quarter, both compared to last year and even compared to normal. While the cold weather certainly is good for our utility business, is it does create some challenges in some of our other subsidiaries. For example, it slows down things like drilling and completion in connecting new wells in our oil and gas subsidiary and things like that. But overall, very positive impact of the weather for the quarter. Highlights on the utilities side. Black Hills Power here, just a couple of weeks ago, filed a request with the Wyoming Public Service Commission to increase our electric revenue in Wyoming from Wyoming customers primarily related to the Cheyenne Prairie Generating Station. Black Hills Power also plans to file a case later this quarter with the South Dakota PUC. That case will also be related to the Cheyenne Prairie Generating Station. In early January, Black Hills Power also received an order, an accounting order from the South Dakota PUC, basically allowing restoration costs from a severe October blizzard that we had here in the Black Hills to be classified as a regulatory asset. That's until we apply for our next general rate case at which we'll propose amortizing those costs. Really, there's only several million dollars worth of incremental O&M there and all of those have been recorded as a regulatory asset. We…

Thank you, Dave. Good morning. As Dave described, we're very pleased with our fourth quarter and our full year performance. Compared to 2012, our earnings from continuing ops as adjusted grew 3% for the quarter and 17% for the full year. You may recall our Q4 earnings in 2012 improved 48% over the fourth quarter of 2011. So we were encouraged by another increase in this quarter. For the full year, our earnings exceeded our upper end of the range. And, as Dave mentioned, that it was primarily driven by weather, and specifically, more specifically, a very cold December. Moving to Slide 12, we report GAAP earnings and reconciled earnings as adjusted. A non-GAAP measure. We do this each quarter to isolate special items and communicate earnings that better indicates our ongoing performance. This slide displays our last 5 quarters and the full year. During the fourth quarter of 2013, we have 3 special items. The first special item was a reduction of $0.01 for a mark-to-market gain on $250 million worth of de-designated interest rate swaps. For the full year, the 2013 gain on those same swaps was $0.44, compared to $0.03 in 2012. As we announced in December, we settled these de-designated swaps once we completed the $525 million worth of financing. The next 2 special items relate to financing activity in the fourth quarter. We calculated the impact of these items as if the financing had been completed on December 31. So the settlement cost, negative carry and interest savings during the quarter, were netted to calculate the impact of these special items. The first special financing item was an addition of $0.15 for the settlement of swaps on project debt and the write-off of related deferred finance fees in our Power Generation segment. We paid off…

Thank you, Tony. Moving on to Slide 26, out strategic objectives. Consistent with our prior quarters, we have 5 major strategic objectives, all of which are focused primarily on being an industry leader in everything we do. We want to be a leader in operational performance, earnings growth, earnings upside opportunities and certainly, our track record of 44 consecutive annual dividend increases. We also plan to maintain our minimum BBB equivalent unsecured credit rating. As you may recall, that was an objective to achieve a BBB credit rating and that's a goal we met this calendar year or last calendar year 2013. Slide 27 exhibits exceptional performance relative to our peers in safety, reliability and several other utility efficiency measures. On Slide 28, you can see our superior plant availability and starting reliability. Slide also demonstrates that we have a very modern generation fleet. It's very new. And then our power plant construction safety record is great. Related to the power plant availability and starting reliability, I mean, those are keys from a customer perspective and that we're able to better utilize our generation assets which saves customers money in the long-term. Slide 29 illustrates our generation by fuel type and further demonstrates the ongoing modernization of our fleet as we continue to add new resources and have now retired, or in the process of retiring, a couple of our older both gas-fired and coal-fired plants. Slide 30 related to earnings growth. Tony talked about our 5-year trend. We expect continued strong earnings growth, driven primarily by capital spending to meet customer needs in our utilities and also to grow our nonregulated energy businesses. Capital spending is projected to be far in excess of depreciation. Slide 31 provides a little more detail on historical and projected capital spending and it's…

[Operator Instructions] Looks like our first question comes from Kevin Cole with Credit Suisse. Kevin Cole - Crédit Suisse AG, Research Division: I'm just trying to reconcile the rate base slide, the Slide 21. It looks like in 2013, your rate base fell. And if I just compare that versus your Slide 30, where you have the CapEx versus depreciation, your rate base should have increased. Is this rate base number just the summation of all prior approved rate basis and not necessarily the hypothetical rate base that should be today?

What we're trying to estimate, Kevin, is what our rate base is as of the end of 2013. On that slide, it certainly doesn't include all the capital expenditures on Cheyenne Prairie and some of the things that still have to go into rate base from that standpoint. But we did -- we do have some movement on the deferred taxes. As you know, with all utilities, we really enjoyed large deferred taxes on the -- because of the bonus depreciation. And so we're getting some movement in that which partially offset some of the increase for the capital expenditures. Kevin Cole - Crédit Suisse AG, Research Division: Okay and so should we expect rate base to fall into '14? Or once you get Cheyenne Prairie service it should -- then you'll get the full true up for Cheyenne Prairie?

Right, that's right. So as always, things get a bit lumpy with a construction. Kevin Cole - Crédit Suisse AG, Research Division: And then I guess with EMP, so on the Summit project. What was the cause of the delay and when is it expected to be up and going at full capacity?

Yes, they were originally planning on being on late last year and weather and construction delays and other things related to their plant construction have delayed that. That facility is still not yet producing. We hope that it will be producing here literally any day, but it's restricting the wells' output on the 2 new wells we've put on because we don't have a takeaway capacity without the plan. So we're producing the wells, we're cleaning them up after the frac and completion but we're certainly not producing them at anywhere near full rate right now because the plant did not yet completed. Kevin Cole - Crédit Suisse AG, Research Division: Does the Summit project should be completed by the time to get your 6 other wells done this year?

Well I certainly hope it doesn't take that long. We won't start drilling until spring and it certainly should be done -- really should be done now, hopefully will be done at least this month, if not sooner. Kevin Cole - Crédit Suisse AG, Research Division: Okay. And then on the additional 20,000 acres that you earned, is there a requirement for you to have an active drilling program of that acreage to keep it?

There's some minimal requirements, Kevin, but nothing major. Kevin Cole - Crédit Suisse AG, Research Division: Okay. And then I guess our last question on Slide 38. Is the 6 to 8 Bcf per well assumption still the right number?

Well, based on a 4,000- to 5,000-foot lateral, it is. We drilled these more recent wells with longer laterals. And as I said, we can't disclose individual well results. So we can't provide an update really to that slide until we can publicly disclose the results of those reserves. But with longer laterals you would typically expect higher reserve numbers per well. Kevin Cole - Crédit Suisse AG, Research Division: Just can you remind me then when the confidentiality agreement ends or when your 6 wells, that you're going to drill outside of the confidentiality agreement, will come online?

Well, the confidentiality agreement, I'm not 100% sure of this, Kevin, but I believe it's at least 6 months from the date of first production on those wells. So you're looking at midyear at a minimum for the CA and it could be longer. And then the other wells, basically, our intent would be to start drilling those in the spring. We've got -- some of the areas, we've got wildlife restrictions and other things that preclude us from commencing drilling until April, May, maybe even a little later than that. And somewhat weather depended if they have a really wet spring, we'll probably wait until the mud goes away before we move in. And then it takes a month plus, 1.5 months per well to drill and then several more weeks to complete. And we would just plan on doing it pretty continuous activity. But we will be drilling several wells from a single pad. So when you do that, you drill for a few months and then you move your drilling rig and you complete all the wells at the same time. So you don't see production coming on one well at a time, which will delay production, probably until at least mid to late third quarter, before you're seeing any new production, possibly later than that. Kevin Cole - Crédit Suisse AG, Research Division: Okay, that's helpful. And then, sorry, one last question. Are you giving your role for the CapEx plan? Do you still expect to be equity free through this 2016 planning period?

Yes.

We made a statement to that affect in the 10-K that will come out here soon.

Our next question comes from Eli Kraicer with Millennium.

It's Jeff Gildersleeve. I just wanted to look at Slide 59, your guidance assumptions for the commodity, you have of NYMEX gas at $3.70 and wellhead of $2.37. We've seen a lot of volatility, so I just wanted to take your perspective on those assumptions.

Yes, I mean, as Tony said, those are the assumptions we had when we put out our guidance in November 5. And we don't update those typically during the year, unless there's some major change. Things are always moving one way or the other. And we talked a little bit about, for example, some of plants being a little slower. I mean, some of those, we don't typically update our guidance for price movements unless we see -- we've got actual earnings in related to that price increase than we do. But we hedge a fair amount of our gas and oil. And so there's not a lot of incremental production except new production that comes on that is unhedged, typically. So we end up hedging 2/3 kind of number of our total production.

Okay. Yes, because I mean, I think the 14 strip's like 4.60, and then when you look at the -- your hubs, your gas hubs out there, can you just remind us what hubs in the Piceance and San Juan that you're going into?

Well, in the San Juan, we're typically at San Juan. And then depending on where the gas is in the Northern Rockies, Northwest Rockies, typically.

Okay. Yes, because there's been a lot of spot volatility, as you said, you're hedged a lot and the excess gas hasn't come on. But there's some pretty extreme prices out there now. So you said you're 2/3 hedged on your production?

Roughly or more.

And we disclose our specific hedges in doing the K, Jeff, so it's very easy to figure out the total hedged volumes when you see the K.

Okay. But you wouldn't typically update your assumptions if they changed throughout the year?

No, not unless. If we were to raise guidance driven by say, just pure price increase or something, we might change that assumption. But typically, we leave our assumptions the same unless there's something that leads us to raise our guidance and then we typically would revise at least a few of the assumptions there.

Our next question comes from Shelby Tucker with RBC Capital Markets.

In your conversations with the commissioners, do you have any updates on the idea of rate basing natural gas reserves somewhat what you see in Utah?

No. That's something that we know others are doing and certainly it's something that we've at least contemplated. But haven't really had any substance of discussions certainly with commissions related to that. It's something that's certainly intriguing to us with the natural gas holdings we have, but we really haven't gone a whole lot further than that at this point, Shelby.

[Operator Instructions] Our next question comes from Matthew Barnett with Jet Capital.

Could you just remind us on the size of the gas processing plant with Summit and whether or not that size is meant to satisfy the 2 wells being drilled or the entire drilling program?

Well, it's not going to satisfy the entire drilling program. It'll certainly help -- the way that plants designed is it's designed to be brought on in 20 million cubic feet a day increments. And so they'll build it basically 20 million cubic feet of capacity at the time based upon our request. And then the first phase is going to be 20 million a day and that's the phase we're waiting for.

There are no more questions in queue. I would now like to turn the call back to David Emery, please proceed.

All right. Thank you. Well, thank you, everyone, for joining us this morning. We very much appreciate your time and your continued interest in Black Hills. We're very excited about our performance in 2013 and expect good continued growth going in 2014 as well. So thank you, have a great day and a good weekend.

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