Good day, ladies and gentlemen, and welcome to the Q4 2014 Black Hills Corporation Earnings Conference Call. My name is Greta, and I will be your operator for today. At this time, all participants are in a listen-only mode. Later we will conduct 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 conference over to your host for today, Mr. Jerome Nichols, Director of Investor Relations. Please proceed.

Thank you, Greta. Good morning, everyone. Welcome to Black Hills Corporation's fourth quarter and full year 2014 earnings conference call. Leading our quarterly earnings discussion today are David Emery, Chairman, President and Chief Executive Officer; and Richard Kinzley, Senior Vice President and Chief Financial Officer. 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 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, and good morning, everyone. I will be using the Investor deck on the webcast starting on Slide 3. We're going to follow a similar format today as in previous quarters. I'll do an overview of the fourth quarter and the full year, and then a financial update will be provided by Rich Kinzley, our new Senior Vice President and Chief Financial Officer. And then I'll provide a strategic overview and we'll take questions. Moving on to Slide 5, fourth quarter highlights, we had another very busy and productive quarter. We had warmer weather in our utility service territories compared to the same period last year, which impacted our business results a little in our utility. From a utility highlights perspective, we had several things going on during the quarter. We closed the $6 million transaction on January 1 of this year to acquire a small natural gas system in northeast Wyoming, very small, serves a little more than 400 customers. We also announced during the quarter a $17 million transaction to acquire another gas utility system with about 6700 customers in northwest Wyoming. Our Cheyenne Prairie Generating Station, our new power plant in Cheyenne, Wyoming was placed into commercial operation in our October 1 on-time and on-budget. We had a lot of rate case and financing activity around that plant that was completed during the quarter as well. First, Black Hills Power and Cheyenne Light closed on long term financing for the plants. Moving on to Slide 6, new rates for Black Hills Power and Cheyenne Light customers in Wyoming were implemented, October 1. We also implemented interim rates in South Dakota on October 1. Black Hills Power’s filed rate request is still pending with the South Dakota Public Utilities Commission. We had hearings, January 27 and…

Thanks Dave and good morning. We are very pleased with our fourth quarter and full year performance in 2014 and encouraged by another year of strong earnings growth. Despite mild weather during the high load summer months, our Electric Utilities performed well and benefited from the on-time, on-budget in service of Cheyenne Prairie Generating Station. Cold weather in the first quarter aided our gas utilities in posting another solid year. Overall, we continue to see steady growth across our utilities as our utilities customer count increased by approximately 1% in 2014. We enjoyed strong improvement in operating results at the coal mine , and Power Generation delivered solid results as well. The strong financial performance across these segments was partially offset by lower than expected results from our oil and gas segment. Our earnings in 2014 benefited from lower interest expense compared to 2013 resulting primarily from financing activity in the fourth quarter of 2013. On Slide 14, we report GAAP earnings and reconcile to earnings as adjusted a non-GAAP measure. We do this each quarter to isolate special items and better indicate our ongoing performance. This Slide displays the last five quarters in each of the last two full years. In 2014 we had no special items, so our GAAP earnings are equal to our adjusted earnings. In 2013 we had three special items. The first item related to quarterly mark-to-market gains on certain interest rate swaps, and the other two special items related to financing activity in the fourth quarter of 2013, as you will recall we placed $525 million of 10-year notes at $4.75% in the fourth quarter of 2013, and used the proceeds to settle those interest rate swaps, and to pay off other higher cost debt. After accounting for the special items in 2013, our…

Thanks Rich. I’ll move on to Slide 27. We group our strategic goals under four major categories, really with the overall objective of being an industry leader in everything that we do. Slide 28; shows strong capital spending and how that drives our earnings growth. We project $1.3 billion of investment far in excess of depreciation for 2015 through 2017. Slide 29; provides a detail related to both historical and forecasted capital spending by business segment. Slide 30; is the sub-set of the information on Slide 29, it provides additional details for select major utility projects. Moving on to Slide 31; another growth opportunity we’re pursuing is the utility cost of service gas supply program. Under a program - a cost of service program, our direct investment in natural gas reserves will provide longer term price stability for customers while also providing increased earnings for shareholders. Related to that effort we're continuing our discussion sessions with Utility Commissioner, staff and consumer advocate staffs, in many of our states. I would categorize those discussions, as being a very health dialogue, pretty constructive and we feel like we’re making good progress in educating our regulators on the concept of cost and service gas. We’re still also evaluating the purchase of potential producing properties and or drilling prospects for inclusion in a cost of service gas program. Those properties include our Mancos Shale Gas properties in Colorado and New Mexico. While it’s difficult to predict exactly when we'll file for approval of the program, we hope to propose a program when the timing is right, preferably later this year, but that remains to be seen on how much work we can get done in the meantime related to properties to actually put into the program. Moving on to Slide 32; our oil and…

[Operator Instructions] Your first question comes from the line of Dan Eggers with Credit Suisse. Please proceed.

Good morning, guys. First question, just on the gas reserves and rate base. The CapEx guidance for 2016 and 2017 now layers in some assumed spending for those projects. Can you maybe share a little bit of what you think is underlying that CapEx opportunity, how many states you need to sign on to get those kind of dollars to work, and what sort of penetration does supply needs you have kind of underlying those dollars going to work?

What we’ve outlined is just a long-term objective. We talked about this in the Analyst Day presentation that we did back in our October. We think it's very reasonable to have a long term objective of providing roughly 50% of our gas for both our gas LDC business and our electric fuel for our generating fleet from cost to service gas. Now that is a big number, it’s like 39 Bcf a year. If you look at that relative to our current E&P production, which has been in the nine or ten range, it's obvious you need a pretty big increase. So you know, I guess my point is that with the spending we have forecasted and that you’ll see in the 10-K as well, that really isn't going to put a huge dent in that cost of service program. It will help us grow it quite a bit, but we won’t be anywhere near the 50% with that level of spending. So we really view it’s having plenty of spending opportunity there if we get approval in all six states. We’re still deciding the specifics on filing for approval and when we would do that, and if we would file in all six states simultaneously. That’s probably our preference, but I think we’ve got to continue the dialogue in each state and then make kind of a final judgment call on where we want to apply in the first round as we get a little close to that actual date.

And Dave, when do you think that actual date is going to be based on the conversations, the outreach so far?

We would like to do it this year, Dan. We kind of have a dilemma in that we don't have a property right now that we are comfortable recommending to be included in the program. So, then you’re in a chicken and egg situation if you will, on do you apply for the program without a property to put in it and apply using general guidelines for properties that will be put in the program. And that's clearly an alternative that we are considering or do we wait until we either prove up the Mancos or find a producing property and use that property to jumpstart the program if you will and then we would file at that time. That's what we’re still trying to decide and that's based on our dialogue with the different commissions and staffs and consumer advocate staffs. Our objective, really though would be try to get something filed by the end of the year, we’ll just have to play it by ear a little bit.

And Dave, on the Colorado RFP, the capacity you guys did not clear on this, so far when you guys go -- your decision end of February hopefully -- how quickly do think it could be before you guys could announce prospectively a partnership or some kind of buyback agreement?

Its hard to say, but you know, realistically, once you select a bid, once the commission ticks, what it deems is the best bid for customers that’s one we that would have a potential involvement, and you’re probably looking at a month, maybe even two to just get the negotiations completed and all the agreements worked out and signed, and all that stuff before you'd even be close to being able to release anything.

Kind of the last one, just on the E&P side of the Mancos. With these wells coming on in February, what timeline do you assume to have some credible or confident data you would be willing to share on, on well performance?

It varies by well, but in general when we get 30 to 60 days, I’d prefer 60 rather than 30, but it really depends on the wells. We are fairly comfortable with how they’re doing. The reason for the uncertainly, and this depends on how the individual wells clean up. In other words, how quickly they flow back frac fluids, and the frac fluids kind of stops coming back largely. Once you get to that point, you’re pretty confident with the production rates that you have, and that varies and depends on individual wells, but typically in a 30- to 60-day range, you get some pretty good information that you’re comfortable with. What we’re looking for is, you know, we’ve published what we view is our type curve for production rates and decline behaviors for those long laterals. It's in our investor deck towards the back there. We’re looking for performance that’s consistent with that type curve, and the more of that we get, the more confident we get in the play.

At these commodity prices somewhere in this ballpark versus the $100 oil we saw last year, what is your confidence, your comfort with A, developing this program out further as planned right now, and are you seeing any reduction in service costs or drilling costs associated with the slowdown elsewhere?

Let me take those in reverse. I wouldn’t say we have seen a lot of reduction in service costs, although I do think they will start coming fairly quickly as rigs continue to get laid down and the rig count drops every week. I know our E&P folks are in active discussions with our suppliers on what they can do everything from drilling mud to pipe to drilling rigs to flat costs and everything else. So they understand that, this is kind of mid $3 play for us to really have good economics and at $3, it’s less acceptable. So, I think they will really work with us to the extent they can. And I think that’s true across the entire industry. So they are working on trying to get those costs down. Now that being said, we’ve got two reasons to drill Mancos wells right now, one is to fill up our volume commitment on the Summit plant, and we do need some additional volume there. We are short today, so we need to get those wells drilled for that reason and then obviously proving up the play, so we could include it potentially in a cost of service gas program. Absent those two things, I'm not sure we would be drilling those wells today, I mean its close, but probably, we’d probably wait until the strip was a little bit better, not a lot, but a little bit, but I think given those two key factors, we are pushing ahead at current price levels.

Got it. Thank you, guys.

And you next question comes from the line of Chris Turnure with JPMorgan. Please proceed.

Good morning guys. Just a point of clarity on the kind of chicken and the egg situation as you described it with regulators and rate basing the gas reserves. Did you indicate that there is a scenario where you could go ahead and do a filing in a number of the states before year-end without a property in mind, and then later down the road once you find a property, that would be a much faster situation where you could get that actual property specifically approved?

Yeah what we intend to do when we file and again this is still a little bit a sate of flux, but what we intend to do is, when we file for approval either with or without a property to include in that initial filing, we plan to file a list of criteria if you will for both producing property acquisitions and drilling prospect that in the future we may choose to add to the program basically with the intent of getting the commissions to agree, which types of properties we plan to include. So we don’t have to get approval every single time we add a property or a well to the plan. So with or without a property to file for approval, we are still going to file those lists of criteria and would hope to get those approved along with that initial filing, so then if we did find something later hopefully we could slide it in very quickly maybe even without a separate approval of that first property and be up and running.

Okay. And then, other than that particular issue, you mentioned that your conversations with the regulators have advanced over the past quarter or so. Can you give us a little more granularity there, where is the pushback, what are some of the key issues that are kind of going better or worse than you might have expected?

I think the key issues are just really understanding what the program is and how it will work. I wouldn’t say we’ve got any real dramatic pushback there is always a couple of who are, they have kind of a negative outlook on proposal like this and particularly where they might involve an affiliate. But I would say overall the discussions have been very positive. We've talked about things related to the percentage of gas and why we think it's an advantage to be as high as 50. We've talked about issues, about the affiliate transaction, and maybe having our E&P subsidiary operate those wells on behalf of our cost of service gas entity. And frankly most of those discussions on the affiliate issue have gone quite well. Most of the commissions I think realize the benefit of having an E&P expertise in-house and that should be a value then to customers rather than a detriment. So, I think we are making good progress. The biggest challenge is until you have real specifics to propose it's hard to really walk up through the mechanics of making the cost of service filings and all those things without a real life example. We've been using some hypothetical ones, but you know, it’s just not quite the same, without real numbers, real properties and real impacts to customers and when we get those on the table I think they will be able to get their arms around it pretty quickly.

Okay, great. Thank you very much.

[Operator Instructions] Your next question comes from the line of Matt Tucker with KeyBanc. Please proceed.

Good morning, congrats on a strong year. Most of my questions have actually been asked. I think you made this pretty clear, but just to be certain, the change in 2015 guidance, was that solely related to the oil and gas business?

Yes.

Thanks. Would you be able to comment on how the well costs for these three wells you recently drilled and completed came in relative to your expectations?

Yeah I would say without talking about specific numbers because I don’t have them in front of me. We’ve showed you those as they become available I would say we were very pleased with the way the drilling has gone so far. I'm pretty happy with our continued improvement in reducing drilling costs, getting more efficient in the operation, more efficient in the frac stimulation and those sorts of things. When we get all those numbers finalized, we’ll release those. We are pleased with the progress we’re making independent of the earlier questions that Dan asked, is are we getting discounts from suppliers. We are pleased with our progress before any market discounts and hopeful that with some market discounts those costs will continue to come down.

Great, thank you. And you guys commented on NGL production growth in the fourth quarter being pretty strong and, really, all year it necessarily outpaced your growth in gas and oil production. Could you comment just a little bit more on what's driving that?

: Yeah Matt, this is Rich. Really the Whitaker wells, the wells that we drilled late last year that came on, so that production would not have been, yeah, it wouldn’t have been in the fourth quarter last year, but we recognize the benefit of that throughout this year.

Got it, thanks. And then some of the RFP in Colorado, can you give us any sense of what the potential size of the capital opportunity could be there? And is there anything in your current CapEx guidance for that?

No there is nothing in our capital guidance for it and unfortunately no I cant give you an indication of the size, because we’ve got confidentiality agreements on some of those bids that regarding our potential participation. So until they are actually selected and we could work out some terms and we are not comfortable putting those numbers out there, but they are not in our capital forecast.

Got it. Fair enough. Thanks guys. That’s all I had.

Your next question comes from the line of Mitchell Moss with Lord, Abbett. Please proceed.

Not sure if I missed this, but on the EPS guidance for 2015, should I view that $2.90 versus the $2.89 in 2014, that proportion of utility and non-utility earnings is going to stay the same, around 85/15 for 2015?

We don't give segment guidance. The one comment I did make is that we do expect operating income to grow despite the challenges in E&P. So, the ratio shouldn't move a lot I guess if you think of it that way that you talked about.

You expect operating income at E&P to grow, but not necessarily -

The total for the company.

Okay. I guess you had previously discussed, I know, the earnings mix would be about 85% regulated, so should I think that isn't necessarily the case going forward, if I don't -- if you're not willing to give that level of segment guidance?

Yeah I think, well we’ve talked about that in the past that's kind of generalized statement. I think it depends on the year and the circumstances. As a rule, our utilities and utility like properties are Coal Mine and our Power Generation segment make up a very large portion of our earnings and operating income 80% to 90% plus depending on the year. I don’t see that changing and in fact when oil and gas prices are real poor like they are now, that number has a tendency to be even higher just because you got loses on the oil and gas side. So I think that’s probably a fair assumption.

And then looking at the capital investment on Slide 29, just what is the other under the Electric Utilities? What are some of the big projects? That seems to be where a lot of the utility growth CapEx is.

Most of that is what we would call routine distribution capital. So that new customer grows, that’s new substations and neighborhoods for new growth that sort of thing. Replacement of old infrastructure, kind of the catch all its vehicles, its equipment, it’s everything else. And it also includes, we’ve embarked on an initiative to really automate our field operations, GPS tracking of all our field vehicles, computer dispatching of trucks to minimize travel distances and all those things. There is some capital in that for that system as well, but most of that other line is what I would consider just routine utility, maintenance capital and new growth capital that obviously isn't generation or transmission, it’s just everything else.

So if I think about that, that looks like it's about $30 million to $50 million of growth CapEx compared to the last couple of years. Does this mean you need to go through a rate case soon to recover that, or is there any type of recovery mechanisms, already built into rates for that?

From a rate case perspective I would guess, we don’t talk about specifically when we’re going to file future cases, but we’ve just gone through a case in all three of our Electric Utilities and some of our capital especially the transmission is eligible for riders. That allow us to file periodically and get recovery of that without having to go through the rate case. But on the electric side, we don’t have the infrastructure riders if you will like we do on the gas side where if we’re replacing steel or cast iron or whatever we have riders for that We don’t have that same mechanism on the electric side primarily transmission riders and environment riders.

Last question then. I don't know if I missed this, but do you have your 2013 actual earned ROEs in the presentation?

We do not. When we file our form one for our utilities, those numbers you can typically derive them from there, but we don’t typically publish those.

Okay. Thank you.

And your next question comes from the line of Insoo Kim with RBC. Please proceed.

Good morning. Just on the oil and gas side, how are you thinking about your hedging levels for the oil and gas prices? Are you trying to stay more open during the time right now when commodity prices, are you going about at a more scheduled hedging rate?

I would say we are not terribly excited about putting a whole bunch of additional hedges on at current price levels. We do try to exercise some discipline in our hedging policy and we try not to second guess the market too much, but you know, that being said, it’s awful difficult to get excited about walking in these current prices for long term.

When our K comes out here in a couple of weeks, you will see all our current hedges that we have in place.

Got it. In terms of the potential impairment charges for the oil and gas assets, what is roughly the timeline that will take for it to reassess and potentially put on the impairment charge?

Essentially it’s a quarterly process, but we look at it pretty frequently. If you recall a few years ago, the SEC changed the pricing methodology for computing the net present value of your reserves and that is, you use an oil price and a gas price that's the average of the first day of month price for 12 trailing months. So if you think about it in that context and when we disclose our 10-K and our reserve data for the year, you’ll see the average prices that we ran those reserves at for this year. And then basically if you average in these lower prices, every quarter it’s going to continue to come down that 12 month drilling average price. So it’s hard to anticipate whether that would be a second quarter event, a third quarter event or what because it also depends on the additional spending we have on a going forward basis. But the price is going to drop pretty rapidly every quarter if you look at replacing three months $4 or so for gas, high $3 prices and $100 for oil where prices were down and $3 for gas and $50 for oil. That average is going to come down pretty fast.

Got it, okay. Thank you very much.

And your next question comes from the line of Larry Lau with JPMorgan. Please proceed.

Thanks for taking my question. Just wanted to take one the June term loan. I know you guys are solidly investment grade, but given your exposure to E&P, has there been any change of view on that capital market access?

We are valuating that, we are likely to do renewal on the term that we have in place there, but we are certainly looking at the opportunity to term that out and as you point out rates are looked in pretty good, so we'll continue to valuate that as the year goes along.

All of our forecast - rating agency forecast and others at that most recent round have all been looked at in light of lower oil and gas results. So I don’t think there is any negative issue with the banks related to our credit quality.

Okay. Thank you.

[Operator Instructions] At this time, there are no questions in the queue. This concludes the question and answer portion of the conference. I would now like to turn the conference back over to David Emery for final comments.

Thank you. Thanks for listening this morning everyone. We certainly appreciate your continued interest in Black Hills, and have a great rest of your day. Thank you.

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