Black Hills Corporation (BKH) Q4 2014 Earnings Report, Transcript and Summary

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 28 last week, and we expect the Commission's final decision during the first quarter of this year. Colorado Electric this spring issued an all-source generation request including up to 60 megawatts of renewable resources. As we have stated previously, our generation subsidiaries submitted solar and wind bids into that RFP. Our independent evaluators submitted their report on December 23rd for the Colorado PUC and confirmed their ranking of the bids. Our standalone bids from our Power Generation segment were not among those highest ranking bids. The highly ranked bids though may still provide some capital investment opportunities for Black Hills in the form of either possible joint venture or build transfer options on some of those bids. The commission’s deliberation on RFP is scheduled for February 11, and we hope to have a decision by the end of February. Moving on to Slide 7, also related to our Colorado Electric subsidiary, we received approval from the PUC to increase our annual revenue by about $3.1 million. At the same time, the commission also approved the implementation of a rider that allows us to recover construction costs for a new $65 million combustion turbine we plan to add at our Pueblo Airport Generating Station. Our Kansas Gas subsidiary, we received approval from the Kansas Corporation Commission to increase base rates there by $5.2 million effective January 1. At our Coal Mining subsidiary, we completed negotiations for a coal price reopener related to the Wyodak power plant there. The coal price increased approximately $4.75 per ton, effective July 1. On the oil and gas front, we continued to advance our Mancos Shale drilling program in the Southern Piceance Basin. We completed drilling and completion activities for three horizontal wells. Those have been fraced and flow back operations are starting soon and we expect them, all three to be placed on production some time in February. We are also in the process of drilling another three wells from a single pad. Those wells we expect to be completed in the second quarter and placed on production, and we’re still looking on planning and location building and things like that for an additional six wells planned for 2015. Moving on to Slide 8, corporate highlights for the quarter. Last week our Board declared a quarterly dividend of $0.405 per share, equivalent to an annual dividend rate of $1.62. That $0.06 effective annual dividend increase shows our commitment to share our earnings growth with our shareholders, and still retain sufficient capital to fund our long-term growth opportunities. The dividend increase represents our 45th consecutive annual dividend increase for shareholders. Finally on the corporate side, we announced a couple of additional leadership changes on January 5, Kimberly Nooney was appointed as Vice President and Treasurer; Esther Newbrough was appointed as Vice President and Controller. Slide 9 is our fourth quarter financial highlights. We earned $0.76 per share from continuing operations as adjusted compared to $0.70 per share in the fourth quarter of 2013, an increase of 9%. Most of our business units did fairly well in the quarter, couple of them having some negatives, particularly oil and gas. Moving on to Slide 10, our full year 2014 financial highlights: EPS from continuing operations as adjusted increased to $2.89 from $2.45 in 2013. That's an increase of 18% year-over-year, continuing our multiple year track record of good strong earnings growth. Slide 11 provides a reconciliation of our fourth quarter 2014 income from continuing operations as adjusted compared to 2014 results for the same quarter. And Slide 12 provides a similar reconciliation of full year 2014 income from continuing ops as adjusted to 2013 results. We had strong improvement in all of our business segments except oil and gas. Obviously, we've been disappointed in the performance, getting production and drilling done on time and certainly oil and gas prices haven’t helped us either. With that, I'll turn it over to Rich for the financial update.

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 EPS as adjusted was $.0.76 for the fourth quarter of 2014 compared to $0.70 for 2013, an improvement of 9%. For the full year, our EPS as adjusted was $2.89 for 2014 compared to $2.45 for 2013 representing 18% year-over-year earnings growth. Slide 15; displays our fourth quarter revenue and operating income. Our operating income declined slightly during the quarter compared to 2013 reflecting mixed results across our business units. Strong performance of the Electric Utilities and Coal Mine were offset by lower results at Gas Utilities and our oil and gas segment. I'll review our individual segments operating results in subsequent slides. Moving to full year on Slide 16, revenue increased by $118 million primarily as a result of higher pass through gas prices at our Gas Utilities and higher revenue at our Electric Utilities. Operating income improved at all our segments in 2014 other than oil and gas. In total year-over-year operating income increased by 1.9%. Our utility and utility like businesses operating income increased 4.8%. Slide 17; displays our income statement for the fourth quarter and full year. Again I’ll review our individual segments operating results in subsequent slides. Here, our key takeaway is significant decrease in interest expense due to our successful financing activities in late 2013. As I mentioned earlier in the fourth quarter of 2013 we placed $525 million of 10-year notes at $4.75% percent and paid off higher interest rates debt and interest rate swaps. In 2014 we successfully extended our revolving credit facility through May 2019 under more favorable terms, and placed a $160 million of first mortgage bonds associated with the in service of Cheyenne Prairie Generating Station. These actions reduced our average all-in interest rate and lowered interest expense significantly in 2014, a key driver in our EPS improvement from 2013 to 2014. I'll also point out we continued our EBITDA growth trend in 2014 with a 3.2% EBITDA growth over 2013. Slide 18 displays our Electric Utilities revenue and operating income. The Electric Utilities revenue increased in the fourth quarter by $5.5 million over 2013 and by $32 million year-over-year. These revenue increases resulted from rate cases including riders. Operating income increased by $3.2 million or 9% during the fourth quarter compared to 2013. This improvement was the result of increased electric rates in the fourth quarter related to the October 1st in service of Cheyenne Prairie, as well as higher technical services income from certain industrial customers. For the full year operating income increased $3.6 million or 3% over 2013. Full year results benefited from riders relating to Cheyenne Prairie, a 15% increase in industrial megawatt hours sold, and a nearly 1% customer count increase. But second and third quarter results were tempered by mild weather, cooling degree days were 12% lower than normal in our electric service territories in 2014, while they were 7% higher than normal in 2013 Moving to Slide 19; as compared to 2013 the Gas Utilities revenue increased $11 million in the fourth quarter and $78 million year-over-year driven by a 21% higher delivered pass through gas price in 2014 for both the quarter and the year. Operating income declined $2.6 million or 10% in the fourth quarter compared to 2013. Q4 heating degree days in our gas service territories were 3% below normal in 2014 compared to 11% above normal in 2013 contributing to residential and commercial dekatherms sold decreasing by 8% comparing Q4 2014 to Q4 2013. For the full year operating income improved by just under $1 million. Heating degree days were 6% above normal for the full year in 2014 and 9% above normal in 2013. Although heating degree days were 3% lees favorable in 2014, we increased our customer count in the Gas Utilities by 1% in 2014 and sold 2% more dekatherms to residential and commercial customers for the full year. We estimate that colder than normal weather in 2014 contributed approximately $0.08 to EPS. On Slide 20: you'll see the Power gen operating income had a slight decrease in Q4 2014 compared to Q4 2013, due in large part to a planned outage at Wygen 1. For the full year operating income improved $1.4 million due primarily to PTA price increases in 2014. We sold one of our generating unit; CT II to the city of Gillette, Wyoming in Q3 2014. We have an agreement to operate the facility for the city over 20 years and sharing savings we generate by purchasing economy energy on their behalf. This was a great economic deal for the city and for Black Hills. Power gen delivered another solid year for the company. On Slide 21; you’ll note that our coal mining segment had an outstanding year recognizing substantial increases in operating income in both the fourth quarter and for the full year, when comparing 2014 to 2013. We enjoyed significant revenue per ton increase in mid-2014 on a third party coal contract as a result of a contractually scheduled price reopener. This found track represents approximately 35% of our production and the price per ton increased our revenue by approximately $2 million in the fourth quarter comparing 2014 to 2013. Keep in mind, the revenues increase from this price adjustment does not drop straight to operating income as we pay revenue related royalties and taxes on the increased price. We continue to make progress in controlling our mining costs and executing our revised mine plan which began in 2012. Our stripping ratio in 2013 was 0.74 and in 2014 increased to 1.08. In 2015 we expect our striping ratio to increase to approximately 1.5 as we mind back into higher overburden areas. We are pleased with our mines strong performance in 2014 and have successfully executed the revised mine plan to coincide the increased cost of higher overburden with the price reopener on the third part contract. Moving to oil and gas on Slide 22; we incurred an operating loss for the fourth quarter of $5.3 million compared to an operating loss of $1.2 million in Q4 2013. Fourth quarter production increased 2% from 2013 driven by a 56% increase in MGL sales volume. Natural gas and crude oil sales volumes were essentially flat. From a price received perspective, crude oil increased by 15% and natural gas decreased by 10% comparing Q4 2014 to Q4 2013. For the full year we incurred an operating loss of $15.1 million compared to an operating loss of $7.3 million in 2013. 2014 production of 10 Bcfe represents a 5% increase over 2013 and was driven by a 53% increase in MGL sales volume with a 2% increase in natural gas sales volume and flat crude oil sales volume. Comparing price received in 2014 to those received in 2013 natural gas increased by 8%, while crude oil decreased by 11%. In total, revenue was flat year-over-year. Operating expenses increased 6% in 2014 with much of this increase incurring in the fourth quarter as we accelerated activity in our effort to drill our Mancos wells. The depletion rate for 2014 was $2.21 per Mcfe compared to $1.83 per Mcfe in 2013 and increased as we added more liquids rich reserves to our depletion pool. Slide 23; displays our capitalization. At year end, our net debt to cap ratio was53.7%, a modest increase from 2013 and still low enough to fund our capital program without issuing equity while maintaining solid credit metrics. During 2014, two of the rating agencies upgraded our corporate credit rating with Moody's moving us to BAA1 and Fitch moving us to BBB+. Looking forward we expect to be able to fund our 2015 capital program without issuing equity while maintaining BBB+ equivalent credit metrics. Also I'd point out that our long term debt to total debt ratio is lower at year end 2014. This relates to our $275 million two year term loan coming due in June that is classified as short term at December 31st 2014. We expect to renew this loan for another two year term or otherwise refinance it before June. On Slide 24; we address our earnings guidance. In the press release we revised our 2015 earnings guidance downward by $0.10 on each end of the range to revise the EPS range of $2.80 to $3.00 per share. Given the recent collapse in crude oil and natural gas prices, we changed our assumptions related to these commodities from our initial 2015 guidance issued in November. Further at lower prices, we plan to reduce oil related drilling activity, lowering the expected range of oil and gas production. Our new assumptions for the commodity prices and production are outlined on this slide. The earnings release lists all our assumptions regarding revised 2015 earnings guidance. Please note this revised guidance is for EPS as adjusted and excludes special items. If crude oil and natural gas prices remain at current levels, it is probable we will have a non-cash ceiling test impairment charge to our oil and gas reserves in 2015. On a consolidated basis and excluding any ceiling test impairment charge, we expect improved 2015 operating income over 2014, despite the challenging commodity price environment and its impact on our oil and gas segment. To conclude, we achieved strong financial performance for both the fourth quarter and the full year. We are proud of our track record of improving financial performance as stated on Slide 25. And with those comments, I’ll turn it back to Dave.

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 gas assets offer substantial value upside - long term upside. Obviously the current short term product pricing issues have an impact on short term value. 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 be on executing our Mancos Shale drilling program. We plan to do that by completing and testing a total of 12 wells during the year. Moving on the Slide 33; which is a continuation of our oil and gas strategy, an update on the activity of our drilling program to date, we have drilled and completed three horizontal wells in the Mancos from a single pad. As I said earlier, those wells are being flowed back and we hope to have them all in production towards end of the month. We also have drilling operations going in the horizontal laterals for three additional horizontal wells. We expect to frac and complete those, and test them and get them flowing by the end of the second quarter. We’re also preparing locations and doing design work and other things to prepare for an additional six wells to be drilled this year. Related to oil prospects, we’re carefully evaluating our economics for any oil related activities and frankly any additional gas related activities besides our Mancos Play. We expect real minimal activity outside of the Mancos this year. Lot of activity, especially the oil plays, are just simply not economic at current product price levels. Slide 34; we are very proud of our dividend track record, having increased our annual dividend to shareholders for 45 consecutive years. Our $0.06 equivalent increase last year, as I said earlier, maintains our commitment to share our growth with our stockholders and still retaining sufficient capital to continue our strong earnings growth. Slide 35; Rich mentioned our credit ratings, we have continued to make excellent progress improving our credit ratings with two upgrades during 2014. Slide 36; provides a summary of recent and pending regulatory activity much of, which is rig-case related. In those cases we’re seeking a fairly turn on the large capital investments we’ve made in our utility businesses to better serve our customers. Slide 37; exhibits superior power plant availability and starting reliability compared to our industry peers. It also illustrates that our generation fleet is continuing to get younger with the retirements and plans we had last year and the addition of our Cheyenne Prairie generating station. Slide 38; demonstrates some of the progress we've made to improve our operational efficiencies. Something we focus on everyday and it also enhances our customer’s experience as well. Slide 39; clearly shows our top quartile electric reliability performance, a record were very proud of. Then on Slide 40; it shows our safety record and also lists some recent recognitions we’ve received that demonstrate our focus on operational excellence. We’re not satisfied with our safety performance in 2104. Frankly we went the wrong way on our statistic there. We simply need to do better and have the organization focused on efforts to do just that. Slide 41 is our 2014 scorecard. We’ve done that for several years now. These scorecards are our way of holding ourselves accountable to you our shareholders. We set forth our planned goals for the year and then literally check the boxes as they’re accomplished this one obviously is for 2014. Slide 42 outlines our 2015 key objectives that we plan to complete this year. That completes my remarks. I’d be happy to entertain any questions.

[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.