Good day ladies and gentlemen, and welcome to the Black Hills Corporation's First Quarter 2016 Earnings Conference Call. My name is Andrew, and I will be your coordinator for today. At this time, all participants are in a listen-only mode. Following the prepared remarks, there will be a question-and-answer session. [Operator Instructions]. 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 go ahead sir.

Thank you, Andrew. Good morning everyone. Welcome to Black Hills Corporation's first quarter 2016 earnings conference call. Leading our quarterly earnings discussion today are David Emery, Chairman and Chief Executive Officer, and Rich Kinzley, Senior Vice President and Chief Financial Officer. Before we begin today, I would like to note that Black Hills will be attending the American Gas Association Financial Forum next week in Naples, Florida. Our presentation materials and webcast information will be posted on our website at www.blackhillscorp.com under the investor relations heading. During our earnings discussion today, 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 two of the investor presentation on our website and our most recent Form 10-Q and Form 10-K 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 being with us this morning. For those of you following along on the webcast slide deck, I will be starting on slide 3. We will follow a similar agenda to what we’ve done in previous quarters. I will give a quick overview of the quarter. Rich Kinzley, our CFO will cover the financial highlights for the quarter. I will visit briefly about strategic forward issues and then we will take questions. Moving to slide 4, with the closing of the SourceGas acquisition we’ve largely completed our nearly 12 year transition to a pure-play utility company. We now serve more than 1.2 million customers in eight states, and our utility operations account for the large majority of our earnings, assets and employees. In addition, all of our non-utility businesses either support directly or are being transitioned to provide support directly to our own utility business. As a result and effective this quarter, we made some changes to the way we will now report operating and financial results going forward. Those changes have also been made to previous periods to allow for direct comparisons. Most notably we won't continue to report by our two major business groups, Utilities and Non-Regulated Energy. Rather we’ll simply have five reporting segments, those are the Electric Utilities, Gas Utilities, Power Generation, Mining and Oil and Gas. We’ll also report Cheyenne Light's gas distribution results within our Gas Utilities business segment. They were previously reported within the Electric Utilities segment. And then finally, we recently rebranded all of our utilities under the name Black Hills Energy. That’s a name we’ve used since 2008 for many of our utility properties, and we’ve just finished that process with SourceGas and then our two legacy utilities, Cheyenne Light and Black Hills Power.…

Thanks, Dave. Good morning everyone. As Dave indicated, it was a busy first quarter. We’re pleased we closed the SourceGas acquisition on February 12, ahead of expected timing, which allowed us to pick up part of the heating season from those gas utilities. Integration activities around the SourceGas acquisition are progressing as planned as Dave noted, and despite mild weather in the first quarter, we are pleased with our operating results. On slide 13, we reconcile GAAP earnings to earnings as adjusted, a non-GAAP measure. We do this to isolate special items and communicate earnings that better represent our ongoing operating performance. This slide displays the last five quarters and trailing 12 month as of March 31 for each 2016 and 2015. During each of the past four quarters, we incurred significant acquisition expenses related to SourceGas such as advisory fees and financing and other third party costs. We also incurred non-cash ceiling test impairment charges at our Oil and Gas business in each of the past five quarters, due to continued low crude oil and natural gas prices. The acquisition expenses and impairments are not indicative of our ongoing performance, and accordingly we reflect them on and as adjusted basis. Our first quarter as adjusted EPS was $1.23 per share compared to $1.08 per share in the first quarter last year. Comparing Q1 2016 to Q1 2015 at a high level result in 2016 benefited from a partial quarter ownership of the SourceGas Utilities and corporate tax benefits. These positive items were partially offset by increased share count from our November equity issuance, higher interest expense from higher debt balances and milder weather. I’ll detail these items in the following slides. Trailing 12 months as adjusted EPS increased by 7.5% to $3.14 per share. Slide 14 displays our first…

Thank you, Rich. Moving on to slide 26, consistent with our past practice for the last couple of years, we group our strategic goals into four major categories, with the overall objective of being an industry leader in everything we do. Moving on to slide 27, our profitable growth objective; our strong capital spending drives our earnings growth. We forecast a total of more than $1.2 billion of investment from the 2016 through 2018 period, positioning us very well to continue our track record of strong earnings growth. It is important to note that we have not included results from our Cost of Service Gas Program in our earnings guidance or our [cap] expenditure forecasts. While we fully expect to implement a Cost of Service Gas Program, the timing and the specific amount of capital expenditures are difficult to forecast currently. Hopefully, we can provide some updates to that forecast after we get through the regulatory process by the end of the year. Moving on to slide 28, as I mentioned earlier, we continue to make excellent progress, constructing our new $65 million, 40-megawatt gas turbine for Colorado Electric. And as I mentioned earlier, we filed [8-K] yesterday to recover both the investment and the expenses for that turbine. Construction is about one-third complete and progressing very well. Slide 29 related to the $109 million, 60-megawatt Peak View Wind project, which will serve our Colorado Electric Utility customers, construction commenced in February, we expect commercial operation by the end of the year. Again as a reminder, that project is being constructed by a third party, and we will assume ownership upon commercial operation. Slide 30, we continue to actively pursue our utility Cost of Service Gas Program, which if approved by our regulators will provide a long-term stable price for…

[Operator Instructions] our first question comes from the line of Insoo Kim from RBC. Your line is open.

Just starting off at Cost of Service Gas, in Colorado specifically other than the procedural reason for potentially dismissing the original filing, do you have any color as to your conversations with them on some issues I raised regarding the program?

No, not really. I think the biggest single issue for us so far Insoo is that we have not yet received the written order, so we don't know specifically if there is any additional issue. Until we see that, it’s kind of hard to speculate. We did certainly get the impression that there might be a preference on the part of the commissioners to consider the two phases in a single proceeding. But other than that, it’s pretty hard to provide any color without reading the written order.

Understood. And could you remind us again for this program to be beneficial to customers around what gas level is needed on a longer-term basis?

You mean percent of gas in the program or --?

No, just the natural gas price level needed for the program to be more beneficial to customers to enter in to this type of program?

I think it’s hard to say exactly, because no one knows exactly what gas prices are going to do. But our interpretation as you know you are at a time now where gas prices are probably certainly at a low compared to any recent history, and likely to stay there for at least a period of time, maybe a year or so, maybe a little longer, and we expect them to stay relatively low. If you can lock in gas prices for customers in $3 to $4 dollar range, I think that’s a tremendous long-term result for customers. When you are locking in for the life of the property that’s a tremendous benefit, and now is an opportune time to do that, perhaps one of the best times in the last decade or more to implement a program. So we are optimistic about that. It’s hard to say exactly what the price will be again, not knowing what the forward strip is going to look like at any given point in time and really emphasizing this is about long-term customer cost of gas, not about beating the market in any individual time period.

Understood, and in the Oil and Gas segment given the recent bounce in oil prices from $30 levels, do you expect to be a little more active in trying to make some non-core asset divestitures near-term?

I don't know if that in and of itself is going to drive our timing on anything. I would say we are already looking pretty aggressively at especially our smaller properties and non-operated interests. We’re working pretty hard at looking at those and we are trying to divest the ones that really don't make sense for us to hold onto. I don't think the little bit of bump in oil price affects our timing much. It certainly would be incrementally positive, but the reality of it is, if we divest all those properties it’s not going to be terribly meaningful from a balance sheet perspective anyway.

Got it, and then just last for me for now, in terms of focusing on de-levering the balance sheet beyond 2017, does that imply that you could potentially see continuing a similar level off on the ATM program?

At this point in to our plan it’s just to utilize that through the end of 2017. In 2018, the unit mandatory converts, we think by then we’re going to be back to pretty close to where we like to be, which is 55% debt-to-total cap range, so we’ll see where we are at, at that point. But right now our intent is to utilize the program through the end of 2017. You can see what we’ve included in our guidance relative to that program, and that’s probably as far as we’d go with it at this point barring some other major acquisition or new activity.

Our next question comes from the line of Chris Ellinghaus from Williams Capital. Your line is open.

A couple of questions; Rich, have you got the details on what the bridge financing costs were in the first quarter?

Yes, it’s on the income statement, you can see it there. It’s lined out on that slide as 1.1 million and that ended when we closed on February 12. That was the end of that.

Right, and I’m curious, obviously there were a lot of different moving parts (inaudible) of what I would call unusual items. I am just curious why, as far as the internal labor cost for the merger, why you don't exclude that as well?

That’s just our policy, and I think GAAP or internal labor should not be classified as one-time in nature, that’s cost that we will incur next year. They will be redeployed to other activity.

All right, and on page 4, I’m a little bit confused, you mentioned on page 3 in the corporate section the 5.1 million tax benefit that you also referenced in your remarks. But in the footnote on page 4 for corporate, it says tax benefits of 4.4 million. What’s the difference between those two?

The $5.1 million is made up of two things, Chris, the $4.4 million, the bulk of it was a life time exchange transaction we did back in 2008 when we sold a bunch of power plants and recognized a big gain but deferred that into the Aquila properties. So that was the main item of contention with the IRS that we settled in the first quarter. The additional 00,000 relates to R&D credits that were also in dispute that we’ve settled, and those are scattered across the business units.

Our next question comes from the line of Lasan Johong from Auvila Research. Your line is open.

I’m kind of a little confused here, or maybe I'm not doing the math right. But did somebody actually pay you double the construction cost of your Colorado IPP $2150 per KW?

Well we constructed that plant for $260 million and placed it in service in 2012, and sold 49.9% of it for $215 million this year.

Okay, so close to your double your construction costs. So somebody actually did pay you that. That’s not a mathematical error or anything?

No, and you did your math right.

Okay, any more details on those (inaudible)? Seriously, I mean if somebody is willing to pay you that kind of money, why not sell the whole portfolio?

We don't really have much left Lasan; you know that that one made sense. We’d received several inbound inquiries about that plant, because it’s contracted and it’s in a great location and it’s very clean, and it’s state-of-the-art, a lot of great attributes to that property and in a great market (inaudible) center, everything else. It’s very important for us to continue to own and operate a chunk of that because it’s in the middle of our plant complex that we operate and serve our customers at Colorado Electric, and we thought it was critical for us to maintain control there. But it made sense especially in the context of the SourceGas transaction to sell a minority interest.

Okay, so you think this plant is fundamental to the operations of your (inaudible)?

Absolutely. Yeah, we've got several units on that complex and our wind is interconnected with it. We use it to firm our wind resource in Colorado. It’s very critical to our operation and we prefer to maintain control. It’s best for our customers I think that we do maintain control of that facility.

On the other hand you could build a plant almost double the size for free. But anyway, that’s another story at another time. Getting back on the Oil and Gas situation, look, I hate to put Jerry on the spot here, but he is painting this (inaudible) shale play as something that is kind of akin to a general giga-normous whale, if you want to put it in terms of in those terms. And it kind of makes the Marcellus look like child's play with three-times the pay zone, good porosity or reasonable porosity and permeability for a shale play. So there are several ways that you could pursue the development. One is to just do a straight development program like you would normally do in oil and gas program. And the alternative is that if you do your Cost of Service Gas Program, which seems like it’s going to move forward, you could make it part of that program, and I'm kind of wondering which way you’re leaning towards; number one, and number two, I think you and I can agree that right now putting together a Cost of Service Cash Program it’s a slam dunk. It is a no-brainer, right, because gas prices being where they are, fundamentals being where they are, it’s an easy decision. But I think we can both agree that initial setup on the program isn't where you are going to find problems going forward. It’s when you have to buy reserves at a certain point in time down the road that you’re going to get a lot of pushback in this and that and (inaudible) gas prices happen to be higher that you would want to pursue this. So if that’s the case, then the second part of the question is, if you’re pursuing the Cost of Service Gas Program with the (inaudible) shale play in mind, would it not be prudent to use that asset as kind of a drop-down asset to your Cost of Service Gas Program as opposed to just going on developing the Mancos Shale, as if it were a normal oil and gas play where you would (inaudible) in the open market, and this way you can protect your back-door problem with the Cost of Service Gas. So I’m kind of thinking about how you would play the Mancos Shale over a longer period of time. If you could address some of those issues, that would be great.

Sure. I can try to add a little color there. Obviously Lasan one of the things that we are working on is getting through this phase 1 approval process. With that we’ll establish some criteria with the various commissions on what are the properties, the features of a gas property that they would like included in the program and that is step one. I firmly believe that a long term drilling program is a better solution for customers long-term than trying to buy reserves opportunistically. As you know, if you buy reserves in the ground at any given day, the price of those reserves is going to be directly proportional to the forward strip price for natural gas. So right now that’s a good price, and it may make sense for us to buy some properties to kick start if you will the Cost of Service Gas Program. Long-term, we would like to include properties that are similar to the Mancos whether it is the specific Mancos or not but properties like that where you have a good gas resource, very low if almost zero risk of dry holes, very economical, more gas manufacturing if you will, those types of properties are great long-term properties to add for cost of service gas. You can drill them for years; continue to have customers benefit from that program regardless of what the spot price of gas is doing. You are not dependent on the spot price of gas to buy properties to put in the program in any given year. So we like that, we like that feature a lot. Now that being said, the Mancos as a play is not near as mature as the Marcellus. So the production rates, the costs, things like that have not been proven as definitively as the Marcellus. Certainly at the current time the Mancos economics are not as good as the Marcellus so that is part of what we are contemplating is how and when do we propose gradually including the Mancos in a Cost of Service Gas Program if that is what makes sense based on the feedback we get from the commissions going through the process. I do think the Mancos or properties similar to the Mancos make the best long-term sense for customers and that is the direction we prefer to head. We just have to work our way through the regulatory process and get some feedback from the regulators before we make any definitive decision there.

A little curious, because the way it was described to me, the Mancos has 1000 foot pay zone versus the Marcellus, the thickest portion is about 300 feet. Second, your recover reserves per well, I thought was in the 8 to 9 Bcf range versus the Marcellus at a 3 to 5 Bcf range. How is your economics not as good as your Marcellus plays?

Well, there are several things there. The pay thickness isn't necessarily indicative of how many reserves you’re going to recover, because you can only drain certain vertical area anyway. It may provide an opportunity to vertically stack horizontal wells, because of the pay thickness which isn't true in the Marcellus. But the Marcellus, some of the initial production rates there and reserve numbers are substantially higher than what we’ve seen in some of our Mancos.

(inaudible) right?

Yeah, and again, it’s a timing thing. There’s only been probably 30, 40 wells drilled in the Mancos in our general area at that depth, and the infrastructure and things aren't completely built out yet, to where you can really get the economies of scale that they are realizing in the Marcellus right now. I do think a lot of that will come in time, but it is a way off still.

Okay. So it isn't out of the question that you could use Mancos if developed properly, kind of your solution to longer term replenishment of your Cost of Service Gas reserves?

Yes, it would be a fantastic property for Cost of Service Gas. It’s just a timing issue I think.

Okay, so you’re not thinking of the necessary development of the Mancos as an independent oil and gas play?

No.

[Operator Instructions]

Alright, hearing no additional questions, I want to say thanks to everyone for your attendance today. We certainly appreciate your continued interest in Black Hills. We’re excited about what the future holds for us here at Black Hills. We've got a lot of great work going on, tremendous growth projects, and a lot of integration activity so stay tuned. We've got an exciting year in store. Have a great day.

Ladies and gentlemen, thank you again for your participation in today's conference. This now concludes the program, and you may all (inaudible) your telephone lines at this time. Everyone have a great day.