Black Hills Corporation (BKH) Q1 2015 Earnings Report, Transcript and Summary

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. We’re currently reviewing our options to determine whether we will attempt to secure new bid pricing and resubmit a renewable proposal to the commission. Our previously announced natural gas utility acquisition in northeast Wyoming is moving forward, hearing is scheduled with Wyoming Public Service Commission on May 14 and we expect the transaction approval and hopefully a closing prior to June 1. Moving on to Slide 6, non-regulated energy highlights, our oil and gas subsidiary accelerated its Mancos Shale drilling program in the Southern Piceance Basin during the quarter. Three horizontal gas wells replaced on production early in the quarter, strong production results to-date that exceeded our expectations, we’ll talk more about that in a little bit. We also recently contracted for two additional drilling rigs in the play bringing the total to three. We currently have drilling operations ongoing for ten additional horizontal gas wells in the Mancos on three separate surface pads. From the corporate highlight perspective we’ve implemented some corporate wide cost contained in initiatives in an attempt to mitigate some of the negative impact from the low oil and gas prices and moderate weather and those helped us keep our earnings pretty much in line with the prior year. We declared a quarterly dividend of (ph) [$0.40.5] per share which is equivalent to an annual dividend rate of a $1.62 and finally we closed the new $300 million unsecured term loan for two years that improved pricing. We used the proceeds to repay $275 million term loan, we have that was coming to in June and in other corporate purposes. Term loan allows us to continue to take advantage of low short term interest rates, but also provides some flexibility to term to debt out when interest rate starts to rise. Slide 7, financial highlights for the first quarter, we earned a $1.07 per share compared to $1.08 per share in the first quarter of 2014. Overall an excellent result considering the reduction in heating degree days and then the reduction in oil and gas prices compared to last year. On Slide 8, we've provided a reconciliation of our first quarter 2015 income from continuing operations as adjusted compared to the first quarter of 2014. Overall, we had strong performance in our electric utilities offset by lower performance and our gas utility in oil and gas businesses. With that I’ll turn it over to Rich Kinzley to talk about the financials from the quarter. Rich.

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 changed from discussing revenue to gross margin on our utilities as we feel gross margin is more relevant to understanding ongoing results as revenue includes fuel cost pass through. On the left side of the Slide you will see our electric utilities 2015 first quarter gross margin increased by $13.1 million from 2014. This increase was driven primarily by new rates from completed rate cases in South Dakota, Wyoming and Colorado and higher commercial and industrial demand. Gross margin also benefitted by $2.1 million in the first quarter of 2015 from a non-recurring settlement in Colorado related to our Busch Ranch Wind farm. Residential usage was unfavorable across our electric service territories and total down 6% comparing first quarter 2015 to first quarter 2014. Heating degree days in our electric utility service territories in 2015 were 14% below 2014 reducing gross margin $3.2 million year-over-year. Operating income during the first quarter for our electric utilities improved $9.8 million or 27% year-over-year as a result of increased gross margin and strong cost management. Operating expenses including depreciation increased only $3.3 million year-over-year despite the addition of Cheyenne Prairie which accounted for $2.7 million of that $3.3 million increase. Looking to the right side of Slide 13, our gas utilities gross margin decreased by $3.3 million mainly due to milder weather in 2015 compared to 2014. First quarter 2015 heating degree days in our gas utility service territories was slightly above normal or 9% below 2014 resulting in a $5.3 million weather related margin reduction year-over-year, partially offsetting this weather impact gross margin benefited from new rates in Kansas and solid customer growth as we added 4800 meters year-over-year across the gas utilities. First quarter 2015 operating income decreased $3.9 million compared to 2014 largely due to reduced gross margin. Strong cost management was demonstrated by essentially flat operating expenses year-over-year. Overall across our electric and gas utilities weather impacts in the first quarter of 2015 reduced gross margin by approximately $2 million compared to normal. On Slide 14, you will see Power Gen’s operating income improved by $500,000 compared to last year’s performance. Power Gen benefited from annual power purchase agreement price increases offset by decreased capacity payments since we sold the 40-megawatt CT2 to the City of Gillette in the third quarter of 2014. These lost revenues were partially offset by the cost sharing benefits we enjoy as we operate this facility from the city. On the right side of Slide 14, our coal mining segments operating income improved in the second quarter by $850,000 from 2014. Our average coal price received increased 10% comparing Q1 2015 to Q1 2014, the result of a significant increase in July 2014 in the price per ton on the third party contract. This contract represents approximately a third of our production. Tons sold were down for the quarter due to an unplanned outage at one of the power plants and the closure of Neil Simpson I in March 2014. Cost controls and mining efficiencies resulted in reduced major maintenance and blasting cost and we also benefited from lower diesel costs in 2015. We continue to be pleased with the performance of Power Gen and coal mining. Moving to oil and gas on Slide 15, you’ll see we sustained a $7.7 million operating loss for the quarter. Commodity prices significantly impacted results in the first quarter of 2015 as our average received prices including edges were down 26% for crude oil and 34% for natural gas as compared to the first quarter of 2014. Overall, first quarter production increased 23% compared to the same period in 2014 driven largely by a 28% increase in natural gas production. We brought on three new horizontal Mancos Shale wells in the first quarter and we're pleased with the production results from these wells. From a cost perspective our Q1 O&M expenses increased slightly comparing 2015 to 2014 due primarily to lower ad valorem and production taxes on lower revenue. DD&A increased $1.5 million compared to 2014 due to higher production volumes. Sequentially production from fourth quarter of 2014 to first quarter of 2015 increased 20% with a 33% increase in Natural gas production and small decreases in crude oil and liquids production. While low commodity prices will likely continue to hamper our oil and gas financial results in 2015, we are pleased with the momentum we have proving up our Piceance Mancos Shale play. We recently contracted for two additional drilling rigs and drilling operations are ongoing for 10 additional horizontal wells on three separate surface pads. Due to the partial carryover of 2014 plan Mancos and other drilling and completion capital to 2015 and the addition of one more Mancos well to the 2015 drilling program, we've increased our plan 2015 CapEx for oil and gas o 167 million from 123 million. We expect to substantially complete our drilling completion and testing program in the Southern Piceance as we work through 2015. Dave will talk more about this in a few minutes. Slide 16 shows our current capitalization, at quarter end, net debt to cap was 52.9% an improvement from year end resulting from strong cash flows in the first quarter. Given the expected cash flow from operations for the remainder of the year and our revolver capacity, we have ample funding for planned CapEx in dividends throughout 2015. Moving to Slide 17, in our earnings release yesterday we reaffirmed our 2015 earnings guidance range of $2.80 to $3. Given the expectation of continued low crude oil and natural gas prices through 2015, we implemented cost control measures earlier in the year and expect to continue these efforts through 2015 to achieve earnings in this range. This estimated range is for |EPS as adjusted and excludes special items. If crude oil and natural gas prices remain at current low levels, we may have a non-cash ceiling test impairment charge related to our oil and gas reserves in 2015. Slide 38 in the appendix lists he primary assumptions we use to develop our earnings guidance. Slide 18 demonstrates our strong earnings growth performance over last six years; we're pleased with the first quarter results as our businesses demonstrated strong operating performance. While low crude oil and natural gas prices impacted our oil and gas segment results in the first quarter. 2015 is a transitional year for our oil and gas business as we work to prove out our Piceance Mancos reserves and will continue to operate all our businesses as efficiently as possible. And with those comments, ill turn it back to Dave.

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 earlier, we placed three horizontal wells on production in the first quarter and we achieved excellent results from those and drilling operations are ongoing for ten additional wells on three different pad is increased separate drilling rigs currently. We previously have disclosed plans to drill and complete a total of 12 wells in the Mancos in 2014 and 2015. As I just noted, we put three wells on production in the first quarter, and we have drilling operations on going for ten additional wells. That makes a total of 13 wells as appose to 12. One of the pads we decided to drill this year will require four wells to drill up the adjacent lease hold acreage rather than three. It’s much more economic to drill all four wells at once, rather than drill just three wells now and have to bring a drilling rig back at a later date to drill the fourth well. So while we plan to drill in case 13 wells, our plans are to complete and test just 12. Due to the capacity of our gas processing plant, we will have to alternate wells through the plant for testing, it’s possible that we may still be testing a few of the wells early into 2016. Slide 24, which is a new addition this quarter, provides well-by-well detail for our Mancos well drilling program. It includes details for all wells that we’ve drilled beginning in 2013 with the two wells we drilled then, and then the wells we’ve got on going for 2014 and 2015. Slide 25 is a map illustrating that ongoing activity for the Mancos Shale; it shows all of the horizontal wells we’ve drilled there, the 2013, 2014 and 2015 programs plus the two wells that we drilled in 2011. Slide 26, illustrates the production versus time graph, for all of the long lateral Mancos wells that is laterals that are greater than 7,000 feet drilled by us or other operators in the Southern Piceance Basin in the area of our acreage over the last several years. The graph shows six different wells, but it does not include the three wells we placed on production in the first quarter. They haven’t been on production long enough to show up meaningfully on this graph, those results are listed on the next page. Slide 27, contains the graph of the daily production rates for our three new wells that we put on production in the first quarter. Total production is restricted to approximately 20 million cubic feet a day due to the capacity of the processing plant. Overall, our production results are excellent when compared to the other long lateral wells in the basin which I showed in the previous page. They meet or exceed our expectations, all three wells tested at rates of around 8 million cubic feet a day, we weren’t able to sustain flow rates at that level and essentially have them chocked back to between 6 million and 7 million cubic feet a day due to plant capacity issue. On Slide 28, the slide demonstrates our continued progress reducing our drilling costs, and improving predictability of drilling results, we continue to make great progress there with each successive well and efforts that will be ongoing as we continue to program. On Slide 29, that slide demonstrates the progress we are making and reducing our overall finding and development cost towards our goal of $1.20 to $1.50 per Mcf equivalent. As you can see we’re making great progress towards that objective. Switching gears to dividends on slide 30, we continued to be very proud of our dividend track record. We’ve increased our annual dividend to shareholders for 45 consecutive years. One of the longest track records in the utility industry and something we’re very proud of. Moving on to Slide 31, we’ve got a great balance sheet and excellent credit rating, last year two agencies upgraded our credit. All three agencies now have us on BBB or BBB+ equivalent ratings with stable outlooks. Slide 32 illustrates the focus we place every day on operational excellence. Throughout the year will include various examples of our continued progress on the slide. There is four examples contained here but, we focus everyday on trying to be industry leaders and everything we do. Finally Slide 33 is our 2015 scorecard this is something we’ve been doing for several years, it’s our way of holding ourselves accountable to you our shareholders, we layout our goals for the year and then denote progress as the year continues, we're off to a good start this year and has some excellent goals set forth for the year which we plan on accomplishing. That concludes our prepared remarks, we would be happy to entertain any questions.

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.