Good day, ladies and gentlemen, and welcome to the Black Hills Corporation First Quarter Earning Conference Call. My name is Teron, and I’ll be your coordinator 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 proceed.

Thank you, Teron. Good morning, everyone. Welcome to Black Hills Corporation's first quarter 2015 earnings conference call. Leading our quarterly earnings discussion today are David Emery, Chairman, President and Chief Executive Officer; and Rich Kinzley, Senior Vice President and Chief Financial Officer. Before we being today, I would like to note that Black Hills will be attending the American Gas Assocaition’s Financial Forum in two weeks in Palm Desert, California. 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 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.

Good morning, thank you, Jerome. Welcome everyone to our call; we appreciate your attendance this morning. I will be starting on Slide 3 of the webcast deck and will follow a format similar to that we’ve used in previous quarters. I'll give a quick overview of the quarter, Rich Kinzley, our CFO will cover the financials for the quarter, I’ll talk about forward looking strategic issues and then we’ll have a question-and-answer session. We have made a few changes to our investor presentation this quarter that’s part of our constant efforts to continue to improve the quality of our investor materials, notably we increased the amount of information we related to our Mancos drilling program in response to request by many of you, if you have comments on the deck, please convey those to Jerome Nichols, we are always interest in your opinions. Moving on to Slide 5, first quarter highlights, we had a great quarter, strong execution despite some challenges from milder weather than the prior year and a decline in oil and gas prices. From weather prospective we have moderate weather this year compared to much colder than normal weather during the same period last year. And that tempered results from our utilities. Highlight from our utilities, The Black Hills Power received an order from South Dakota PUC approval to $6.9 million increase in annual electric revenue, this was our last and our final rate case associated with the Cheyenne Prairie Generating Station which was put online in the fourth quarter of last year. Colorado electric received bids for 60 megawatts of renewable energy resources as part of an RFP we were conducting there out of the Colorado PUC deemed those bids not cost effective due to our gas prices assumption and the recent decline in gas prices.…

Thanks, Dave. Good morning. We’re pleased with the first quarter financial performance. Compared to the first quarter of 2014, our electric utilities coal mine, and Power Gen segments posted strong operating results. While low commodity prices impacted our oil and gas business and milder weather tempered results at our gas utilities. Considering these challenges this year’s first quarter EPS of $1.07 measured up favorably to the first quarter of 2014 when EPS was a $1.08. We have implemented cost control efforts to across the company to mitigate the negative impacts of commodity prices and weather. Moving to Slide 10, in the past we’ve reconcile GAAP earnings to earning as suggested a non-GAAP measure. We do this to isolate special items and communicate earnings to better indicate our ongoing performance. For the past five quarters we’ve had no special items. Slide 11 displays our first quarter revenue and operating income, strong performance at our electric utilities coal mine and power gen more than offset decreased performance at the gas utilities in oil and gas business in total, first quarter 2015 operating income increased nearly 3% over 2014. I’ll provide details on each business segment in the following slides. Slide 12 displays our first quarter income statement, comparing first quarter 2015 to first quarter 2014, you will note increased depreciation and interest expense primarily resulting from additional plant and service and additional borrowings associated with our October 1, 2014 in service of the $222 million Cheyenne Prairie Generating Station. Cost control measures implemented early in 2015 allowed us to limit overall operating expenses to 1% increase compared to 2014 despite the addition of expenses associated with Cheyenne Prairie. While net income was flat year-over-year, EBITDA increased by 4%. Slide 13 displays our electric and gas utilities gross margin and operating income. We've…

All right thank you Rich. Moving on to Slide 20 from a strategic objectives perspective, we group our strategic goals into four major categories with the overall objective of being an industry leader in everything we do. Those four goals are profitable growth, values services, better every day and great work place. Regarding profitable growth, Slide 21 shows strong capital spending which drives our earnings growth. We forecast a total of $1.3 billion of investment from 2015 through 2017 with $501 million for 2015. Our projected capital spending far exceeds depreciation helping us drive strong earnings growth. Moving on to Slide 22, a significant growth opportunity that we are pursuing is utility cost to service gas supply program, under our cost to service gas supply program our direct investment in natural gas reserves would provide price stability for customers while also providing increased earnings for shareholders, it’s truly a win-win situation. We are continuing dialogue with our regulators throughout our service territory meeting with PUC commissioners, staff, and offices of consumer advocates. We are also evaluating producing properties and drilling prospects for inclusion in the program, those properties including our Mancos Shale Gas property. We hope to propose a program to our various state commissions when the timing is right and notably when we have a good property to recommend for inclusion ideally later this year. Slide 23, our oil and gas assets continue to offer substantial value upside. Our long-term oil and gas strategy has not changed, but due to the current low oil and gas price levels our focus for 2015, will primarily be on completing our 2014 and 2015 Mancos Shale appraisal program in the Southern Piceance Basin. Our plans are to drill, complete and test approximately 12 horizontal gas wells in the Mancos. As I stated…

Thank you. [Operator Instructions] First question is from Daniel Eggers of Credit Suisse. Your line is open.

Thanks. Just thanks for the detail in the slide today. I guess Dave we jumped to slide 24, I want to make sure I heard you correct that the wells initial flow rates were about $8 million a day but you guys choked them back for the month is that correct?

Yes, we don’t there is two things that to play there Dan. One is the capacity of the plan, the other one is we intentionally trying not to pull the well as hard. There is increasing evidence that you are better off restricting flow little bit early in the life of these horizontal wells and you will get better ultimate reserve recovery. So really the combination of those two essentially we produce the wells at 6 million to 7 million cubic feet a day. We did test them for a day or sometimes a little more than a day at rates around 8 million a day, but we would anticipate bringing wells on 6 million or 7 million a day range even if we had a little more plant capacity we probably wouldn’t exceed 8 million.

Dave, when you look at the kind of the shape of that production, little more of a choke back levels you guys show onwards slide 26 or 28 I guess the curve of production, how if you were to keep drawing that line further from where you guys cut of that chart - slide 27, but does that productions still to look pretty consistently flat or are you starting to see depletion at day 45 or day 60 or what have you.

Yes, I mean its staying we’re keeping the plant loaded, so its staying relatively flat, you will see, if you go back to that prior page where we the show the long term decline curves on the long lateral wells and the basin. We expect the overall decline behavior to follow that curve. It might be a little flatter for the first few months just because we do have the wells choked back but then after that by and large we expect it to follow those decline curves. We do mention and we show on the slide though that we have forecasted reserves of about 10 bcf per well for these first three wells we've put on and that is an improvement from around the 8 bcf we were forecasting for previous wells. So we’re pretty please with that performance.

Do you have enough data to think that that 10 bcf is the right repeatable number or what’s going to help you get comfortable to assume that’s the repeat rate.

You know it’s really just completing more wells, and we've said that all along its really about we've got have enough repeatability of results to gain confidence in drilling cost production rates and reserves and that’s what we are working and we don’t have any reason to believe that the other wells we’re working on now will come in less, but we just need to put them on and prove that.

What are you guys thinking as far as processing capacity additions in the area and if you think about these being limited back and you keep adding wells over the course of the year, it just feels like you’re going to squeeze back on production of what you’ve already done?

Yes we certainly will be restrained for a while. Within a year, most of these wells will be down and at 2 million to 3 million cubic feet a day range, so if you think about that in the context of a dozen wells or so, within a year we’re going to be producing at least relatively close to capacity with the wells we have, we will have a little excess, but not a lot. Regarding ordering additional capacity, you know when we ask them to expand the plant, we would have to commit to another 20 million cubic feet a day for 10 years. That is roughly 73 Bcf or still of gas over that 10 year period, would require another 10 or 12 wells. Right now we’re not ready to do that because of current forward price. We’re drilling these first 12 wells because we want to prove up the play, we want to prove up the economics at $3 gas prices the economics look a little less than the desirable and we probably wouldn’t continue drilling beyond this initial set of 12 wells or so unless we decide to include this in cost of service gas program. So as we get more data as the year goes on, we will determine really one of two courses of action which would lead us to expand the plant after the plant be expanded and that is either we decide to continue drilling next year for cost of service gas or gas prices improve and we’re comfortable with our economics where we want to continue to drill regardless of whether we include this in cost of service gas. If not we would probably finish up the 12 wells we have planned and then wait a little while before we would contemplate additional drilling beyond the little bed that is necessary to stay at $20 million a day. It’s about 12 month to 18 months process from lead time perspective when we give notice to them that we want additional capacity that is about the time it takes to get it.

Okay. Thank you guys.

You bet.

Thank you. Our next question is from Chris Turnure of JPMorgan. Your line is open.

Good morning guys.

Hey good morning Chris.

I just wanted to look at it little bit further obviously you have given a lot of color so far on the plans for drilling in 2015, but I just wanted to understand what you’re putting in to 2016 and 2017 CapEx as a placeholder right now, I know well drilling counts there versus infrastructure needs, just to support the current well in addition to what you just mentioned regarding having to get that block of 20 million cubic feet a day for a new capacity?

Yes we haven’t put out specific drilling plans for the 16 years and 17 years, we’ve got the capital in there and that assumes continuation of kind of a moderate bankers program and hopefully the rebound in prices to where will do some of the other drilling that we do in some of the other areas as well. So you know kind of forecasting a normal if you will E&P year for those couple of years consistent with what we’ve done over the last several years from a drilling activity perspective.

Okay. And then switching gears to the utilities in Colorado at the Colorado electric utility, could you just give us a sense as to what the failed renewable bids were compared to on the cost basis versus kind of expectations going in there for the commission and then what are your options here to redo what you have this kind of 60 day window to redo those specific bids, but then if those do not work would you be able to kind of start from scratch and redo the whole process at some point on the road?

Yes let me start with the end of that first. We absolutely have the ability to start over if we so choose and as part of our formal resource planning process and other things going forward. This specific issue really relates to what has happened in short term gas prices for our bid evaluation process, we use a longer term forecast that we used in other resource planning documents that we filed with the commission for consistency, it obviously doesn’t acknowledge the real short-term drop in gas prices. Predicts prices more in that $4, high $3 long term range. So when you evaluate the cost of the renewables against that gas price of the renewables look fairly decent. If you look at them compared to $2.50 to $3 gas prices where they are right now, they don’t look as good and so the Commission basically said well, we know we’ve got the statute that requires you to implement these but short run, these look a little too expensive. We prefer that you just (ph) [buy Rex], for mutual compliance in the short term and then go from there. They did remind us in the order that we always have the ability to go back, revisit our bids and then re-evaluate them against the lower gas price forecast which acknowledges the short term low levels of price in file again. We’re still evaluating our options related to that, whether we want to do that or whether we just want to differ and wait till we go into a more comprehensive resource planning process in the next year or so.

Okay. So it sounds like from what you’re saying that it’s going to be a little bit tough to get this off the ground in the near term with this immediate re-file?

Got you. Thanks.

Yes.

Thank you. [Operator Instructions] Next question is from Matt Tucker of KeyBanc Capital. Your line is open.

Good morning.

Good morning, Matt.

I have some more questions on the oil and gas side, it looks like on slide 25, looks like you’ve changed the plan drilling locations versus your slide presentation on the fourth quarter call, and you’re drilling more now in the Homer Deep unit, it looks like you’re drilling in the Whittaker flats unit, where you had drilled this two previous wells earlier instead of drilling kind of farther to the east and you no longer plan to drill in the Winter flats. Could you talk a little bit about what prompted the decision to change those locations?

It’s kind of a series of things and typically we always have more permits working than we have wells to drill. There is issues related pipeline right away, infrastructure necessary to read some of those areas, other things, overall economics, so those decisions all played into that. We looked at drilling where we know we’ve got plenty of water and gas infrastructures today to go ahead and get drilling. With the ability to pick up two additional rigs, we needed to go where we had permits ready now rather than where we might have permits ready say in July or August and so that really led to the decision to go where we’re at.

Okay. Thanks. So you made the decision to pick up the traditional rigs and increase the CapEx, knowing that you would be drilling in these new locations, relative to the old plan.

Yes. Essentially, it’s just the trade-off was we had a couple rigs of available to us at pretty economical rates, that we can pick up and kind of accelerate our overall evaluation program which is pretty important strategically for us probably more important that we do that than drill wells a little bit farther to the east for example. I think we’ve got a pretty good feeling about what we expect in that Winter Flats area to the east, might be a little more liquids rich or to the west I mean, little more liquids rich then the Whittaker flats area but the Whittaker flats is pretty indicative of what we expect over there. So we decided to go ahead and drill the Whittaker flats wells, they do have a higher liquids yield and better economics than say the Homer Deep area.

Got it. Thanks. And could you talk a bit about the liquids content that you saw with these Homer Deep wells and any surprises there one way or another?

No. There really isn’t. We expected them to be quite dry and they’ve met expectations. So there really isn’t a whole lot of liquid in that area and we didn’t expect that to be. So I would say they were right in line with what we expected for gas out of that unit.

Got it. Thanks. And then just looking at the completed well cost for these three wells, do you see opportunity to bring those costs down for these next 10 wells you’re planning to drill?

We certainly hope so, those wells are completed late last year and early this year and certainly the sustained period of decreased oil and gas prices has a tendency to drive down service cost. So we do expect cost to improve when they are for rigs and frac fleets and things like that. Now that being said, we’re always optimizing the things that we’re doing so frac stages things like that, we may elect the pump of few more frac stages if cost were cheaper rather than just have a absolute lower well cost. So, on a cost per Mcf basis they might continue to get more efficient with the overall well cost may not go down as much as you might expect. That some of the things we’re working on as we continuing to trying to optimize our overall completions in the play but we’re certainly seeing decreases in service cost. From my perspective, the longer oil and gas prices stay down, the more you will continue to see service cost come down.

Got it. Thanks and just last one with respect to potentially including as Mancos assets and the cost of service gas program based on the details you provided for these wells if the rest look pretty similar, I mean do you have any sense whether this is something that would be attractive to your regulators for inclusion that type of program in the current gas environment?

We think if we can get those costs down in that $1.20 to a $1.50 range, so last few wells have been in that $1.50 range. As we continue to put the cost number down a little bit, these are really good long term resources, are they going to compete with spot prices, no they’re not, but the intent to cost of service gas program is to get away from spot prices is part of your supply. Not all of it but part of your supply and so, if you look at a long-term hedge on gas essentially a life of well hedge on gas which is would cost of service gas program provide. We think these Mancos wells put that program very well; we need to continue to prove that up through back to Dan Eggers question to repeatability of results and confidence that we can do it for a consistent cost number. If we get comfortable with that, I think this is an excellent play to include in a cost to service gas program.

Great. Thanks and thanks for the detailed slides, it’s really helpful.

You bet. Thank you.

Thank you. Our next question is from Insoo Kim of RBC Capital Markets. Your line is open.

Hi, good morning. Just a couple of questions, the first on CapEx seems like for 2017, CapEx for that year is lower by about $45 million to $50 million versus where you guys had at last time is. Our plan is guess, are your plans to kind of ramp that up with other potential projects to keep it more level to the 2016 levels or and you expect potentially the CapEx gain down at these levels after 2016?

Yes, Insoo this is Rich. On the past we’ve talked about as you as if we go out with our capital schedule it typically does have a drop off like that but as we approach those years it typically goes back up, we don’t want to include things on that schedule unless we’re pretty confident that they’re going to happen. So I would expect the number to go up as we approach 2017.

It really just depends on what projects, come up between now and then that’s something that we’re always working on but you can’t, we’re not comfortable putting things in our capital forecast unless we’re really sure we’re going to do them. So that’s pretty typical behavior for us if you see that three year projection, easily trails off pretty good as Rich said, we’re always working try to figure out how to fill it out? Doesn’t mean we will but it’s certainly means we’re going to try.

Okay. I just want to confirm that and the other question I had was the O&M, I guess the cost continue guys at this quarter is there you guys have some kind of guidance for O&M growth for this year, sure going to get one?

Yes, we typically don’t give segment guidance nor particular guidance about an issue like that. We’re certainly clamped down on discretionary spending this year given commodity prices and expect to continue that.

Really our objective is to do without cost containment to try to make up for the difference in oil and gas prices compared to what we had put out with our original guidance and we feel comfortable so far in reaffirming the guidance despite the oil and gas decrease. So this is from a magnitude perspective, I think that might help you a little bit.

Okay. Thank you very much.

You bet, thank you.

[Operator Instructions] There are no further questions at this time. I’d like to turn the call over to David Emery for any closing remarks.

Well thank you for your time and attention today. We appreciate your listening in to our first quarter earnings call. As I said before, we’re excited about the quarter, we had a couple of challenges and certainly did a good job of overcoming those and from a strategic perspective, I think we’re making great progress on some good projects and oil and gas in particular and some other. So we’re happy where we sit after the first quarter and look forward to the rest of the year. Thanks for attending today. We appreciate it.

Ladies and gentlemen, thank you for your participation in today’s conference. This concludes the presentation. You may now disconnect. Good day.