Black Hills Corp (BKH) 2015 Q1 法說會逐字稿

Good day ladies and gentlemen, and welcome to the Black Hills Corporation first quarter earnings conference call. My name is Tyrone, and I will 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 call over to Mr. Jerome Nichols, Director of Investor Relations of Black Hills Corporation. Please proceed.

Thank you Tyrone. 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 begin today, I would like to note that Black Hills will be attending the American Gas Association'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 two 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 three of the webcast deck, and will follow a format similar to what 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, as part of our constant effort to continue to improve the quality of our investor materials. Notably we increased the amount of information related to our Mancos drilling program, in response to requests by many of you. If you have comments on the deck, please convey those to Jerome Nichols. We are always interested in your opinion.

Moving on to slide five, First Quarter Highlights. We had a great quarter. A strong execution despite some challenges from milder weather than the prior year, and a decline in oil and gas prices. From a weather perspective, we had more moderate weather this year compared to much colder than normal weather during the same period last year, and that tempered results from our utilities. Highlights from our utilities Black Hills Power, received an order from the South Dakota PUC approving a $6.9 million increase in annual electric revenues. 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 resource, as part of an RFP we were conducting there. The Colorado PUC deemed those bids not cost-effective, due to our gas price assumptions, and the recent decline in gas prices. We are 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 northwest Wyoming is moving forward. A hearing is scheduled with the Wyoming Public Service Commission on May 14, and we expect a transaction approval and hopefully a closing prior to June 1.

Moving on to slide six, 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 were placed 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 a corporate highlight perspective, we implemented some corporate-wide cost containment initiatives in an attempt to mitigate some of the negative impacts 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 $0.405 per share, which is equivalent to an annual dividend rate of $1.62. And finally, we closed a new $300 million unsecured term loan for two years at improved pricing. We used the proceeds to repay a $275 million term loan we had that was coming due in June. And then other corporate purposes. The term loan allows us to continue to take advantage of low short-term interest rates, but also provides some flexibility to term the debt out when interest rates start to rise. Slide seven, Financial Highlights of the first quarter, we earned $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 eight, we provide 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 in our gas utility and oil and gas businesses. With that, I'll turn it over to Rich Kinzley to talk about financials for the quarter

Thanks Dave. Good morning. We are 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 $1.08. We have implemented cost control efforts across the Company to mitigate the negative impacts of commodity prices and weather.

Moving to slide ten, in the past we've reconciled GAAP earnings to earnings as adjusted, a non-GAAP measure. We do this to isolate special items and communicate earnings that better indicate our ongoing performance. For the past five quarters, we have had no special items. Slide 11 displays first our quarter revenue and operating income. Strong performance at our electric utilities, coal mine, and power gen, more than offset the increased performance at the gas utilities and 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'll note increased depreciation and interest expense, primarily resulting from additional plant in 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 a 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 have 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-throughs. On the left side of the slide, you'll 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 benefited by $2.1 million in the first quarter of 2015, from a non-recurring settlement in Colorado related to our Busch Ranch windfarm. Residential usage was unfavorable across our electric service territories in total down 6% comparing first quarter 2015 to first quarter 2014. Heating degree days in our electric utility service territories in 2014 were 14% below 2014, reducing gross margin $3.2 million year-over-year.

Operating income during the first quarter for the 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 utilities service territories while slightly above normal, were 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 4,800 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'll see power gen's operating income improving 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 for the city. On the right side of slide 14, our coal mining segment saw operating income improve 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 a third party contract. This contract represents approximately one-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 1 in March 2014. Cost controls and mining efficiencies resulted in reduced major maintenance and blasting costs, 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 hedges 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 were 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 ten additional horizontal wells on three separate surface pads. Due to the partial carryover of 2014 planned 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 planned 2015 CapEx for oil and gas to $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 expected cash flow from operations for the remainder of year and our revolver capacity, we have ample funding for planned CapEx and dividends throughout 2015.

Moving to slide 17 in our earnings release yesterday, we reaffirmed our 2015 earnings guidance range of $2.80 to $3.00. Given the expectation of continued low crude oil and natural gas prices through 2015, we implemented cost control measures early 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. The crude oil and natural gas prices remain at current low levels, we have a non-cash ceiling test impairment charge related to our oil and gas reserves in 2015. Slide 38 in the Appendix lists the primary assumptions we used to develop our earnings guidance.

Slide 18 demonstrates our strong earnings growth performance over the 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 of our businesses as efficiently as possible.

And with those comments, I'll 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, valued service, better every day, and great workplace. Regarding profitable growth, slide 21 shows strong capital spending which drives our earnings growth. We have 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 an utility cost of service gas supply program. Under a cost of service gas program, our direct investment in natural gas reserves would provide longer term price stability for customers, while also providing increased earnings for shareholders. Truly a win/win situation. We're continuing dialogue with our regulators throughout our service territory, meeting with PUC Commissioners, staff, and offices of consumer advocates. We're also evaluating producing properties and drill prospects for inclusion in the program. Those properties include our Mancos shale gas properties. We hope to propose a program to our various state commissions when the timing is right, 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 '15 Mancos shale appraisal program in the southern peons 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 have achieved excellent results from those. And drilling operations are ongoing for ten additional wells on three different pads, using three 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 ongoing for ten additional wells. That makes a total of 13 wells as opposed to 12. One of the pads we decided to drill this year will require four wells to drill up the adjacent leasehold acreage, rather than three. It's much more economic to drill all four wells at once, rather than just drill three wells now, and have to bring a drilling rig back at a later date to drill a fourth well. So while we plan to drill and 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 ongoing 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, and 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 contain as graph of a daily production rates for our three new wells that we have 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 plants. Overall, our production results are excellent when compared to the other long lateral wells in the Basin, which I showed on 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 choked back to between 6 million and 7 million cubic feet a day, due to plant capacity issues.

On slide 28, this 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, an effort that will be ongoing as we continue the program. On slide 29, that slide demonstrate the progress we're making in reducing our overall finding and development costs 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, the dividends on slide 30, we continue to be very proud of our dividend track record. We have 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 onto 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, we'll include various examples of our continued progress on this slide. There are four examples contained here, but we focus every day on trying to be industry leaders in everything we do. Finally slide 33 is our 2015 score card. This is something we've been doing for several years. It's our way of holding ourselves accountable to you, our shareholders. We lay out our goals for the year, and then denote progress as the year continues. We're off to a good start this year, and have some excellent goals set forth for the year, which we plan on accomplishing. That concludes our prepared remarks. So we would be happy to entertain any questions.

Thank you. Ladies and gentlemen, we are ready to open our lines for your question. (Operator Instructions). Please stand by for your first question. The first question is from Daniel Eggers of Credit Suisse. Your line is open.

Hi guys. Thanks for all the detail in the slides today. I guess, Dave, we jump to slide 24, I want to make sure that I had heard you correctly 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, there are two things at play there, Dan. One is the capacity of the plant. The other one is we intentionally try not to pull the wells as hard. There's increasing evidence that you're better off restricting flow a little bit early in the life of these horizontal wells, and you'll get better ultimate reserve recovery. So really the combination of those two, we essentially 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. We would anticipate bringing wells on in that 6 million 7 million a day range, even if we had a little more plant capacity, we probably wouldn't exceed 8 million.

Dave, when you like at the shape of that production, a little more of a choked back level you will guys show on 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 off that chart, sorry slide 27, does that production still look pretty consistently flat, or are you starting to see depletion at day 45 or day 60, or what have you?

Yes, I mean it's staying. We're keeping the plant loaded, so it's staying relatively flat. You will see if you go back to that prior page, where we show the long-term decline curves on the long lateral wells in the Basin. We expect the overall decline behavior to follow that curve. It might be a bill 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 the decline curves. What we do mention and we show in the slides, though, that we have forecasted reserves of about 10 BCF per well for these first three wells that we've put on. And that is an improvement from around the 8 BCF we were forecasting for previous wells. So we're pretty pleased with that performance.

Do you have enough data to think that 10 BCF is the right repeatable number, or what's going to help you get comfortable to assume that's the repeat rate?

Yes, it's really just completing more wells. And we've said that all along. It's really about, we've got to have enough repeatability of results to gain confidence in drilling costs, production rates and reserves, and that's what we're working on. 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 thinking 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 in that 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'll have a little excess. But not a lot. Regarding ordering additional capacity, when we ask them to expand the plant. We would have to commit to another 20 million cubic feet a day for ten years. That's roughly 73 BCF or so of gas over that 10-year period. It would require another 10 or 12 wells. Right now we're not ready to do that, because of current forward prices. 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 desirable, and we probably wouldn't continue drilling beyond this initial set of 12 wells or so. Unless we decide to include this in a cost of service gas program.

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, ask that 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 bait a little while before we would contemplate additional drilling, beyond the little bit that's necessary to stay at 20 million a day. It's about a 12 to 18-month process from a lead time perspective when we give notice to them that we want additional capacity. That's 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.

Good morning, Chris.

I just wanted to look at it a little bit further. Obviously you've 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 the 2016 and 2017 CapEx as a place holder right now, out of well drilling counts there versus infrastructure needs just to support the current wells, in addition to what you just mentioned regarding having to get that block of 20 million cubic feet at day for capacity?

Yes. We haven't put out specific drilling plans for the 2016 and 2017 years. We've got the capital in there. And that assumes continuation of kind of a moderate Mancos program. And hopefully the rebound in prices to where we'll do some of the other drilling that we do in some of the other areas as well. So 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 a cost basis, versus kind of expectations going in there for the Commission, and then what are you 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 down the road?

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's happened to short-term gas prices. For our bid evaluation process, we used a longer term forecast that we've 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, 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, 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 buy reccs to meet your 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 reevaluate them against a lower gas price forecast, which acknowledging the short-term low levels of price and file again. We're still evaluating our options related to that, whether we want to do that, or whether we just want to defer and wait until 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 refile?

I mean certainly very low gas prices make renewables look expensive on the margin. There is no question. I think it's possible that we could have a project that is viable, and we're still evaluating that. But we've got to look at whether we view that possible and economic now for customers, versus maybe next year or something. We still believe all of the alternatives are still viable. It's really just a timing issue relative to currently low gas price levels.

Got you. Thanks.

Yes.

Thank you. (Operator Instructions). The next question is from Matt Tucker of Keybanc Capital. Your line is open.

Hi, good morning.

Morning, Matt.

I have some more questions on the oil and gas side. It looks like on slide 25 it looks like you've changed the planned drilling locations versus your slide presentation on the fourth quarter call. 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 those two previous wells earlier, instead of drilling farther to the east, and you're no longer planning to drill in the Winter Flats. Could you talk a little bit about what prompted the decision to change those locations?

Yes, it's kind of a series of things, and typically we always have more permits working than we have wells to drill. There's issues related to pipeline rights of way, infrastructure necessary to reach 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 infrastructure 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, so that really led to the decision to go where we're at.

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

Yes. Yes. Essentially it's just the trade-off was we had a couple rigs available to us at pretty economical rates that we could pick up, and kind of accelerate our overall evaluation program here, 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. It might be a little more liquids rich, or to the west I mean. Little more liquids rich than 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 little bit about the liquids content that you found 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 have met expectations. So there really isn't a whole lot of liquid in that area, and we didn't expect there to be, so I would say they were right in line with what we expected for it was out of that unit.

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

We certainly hope so. Those wells were 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 costs. So we do expect costs to improve, and 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 to pump a fuel more frac stages if costs were cheaper, rather than just have absolute lower well costs. So on a cost per MCF basis, they might continue to get more efficient, but the overall costs may not go down as much as you might expect. That's some of things we're working on as we continue trying to optimize our overall completions in the play. But we're certainly seeing decreases in service costs, and from my perspective, the longer the oil and gas prices stay down, the more you'll continue to see service costs come down.

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

We think if we can get those costs down in that $1.20 to $1.50 range, the last few wells have been in that $1.50 range. As we continue to creep 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 of a cost to service gas program is to get away from spot prices as part of the your supply. Not all of it, but part of your supply. So if you look at a long-term hedge on glass, essentially a life of well hedge on gas, which is what cost of service gas provides, we think these Mancos wells fit that program very well. We need to continue to prove that up through, back to Dan Egger's question, through 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 of service gas program.

Great. Thanks a lot and thanks for the detailed slides. It's really helpful.

You bet. Thank you.

Thank you. Our next question is from [Insue] Kim of RBC Capital Markets.

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

Insue, this is Rich. In the past we've talked about as 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. 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. It's something that we're always working on. But we're not comfortable putting things in our capital forecast unless we're really sure we're going to do them. That's pretty typical behavior for us if you see that three-year projection. It usually trails off pretty good as Rich said. We're always working to try to figure out how to fill it out. It doesn't mean we will, but it certainly means we're going to try.

Right. I just wanted to confirm that. And the other yes I had was the O&M, the cost containment you guys had this quarter, do you guys have some kind of a guidance for O&M growth for this year?

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

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

Got it. Thank you very much.

You bet. Thank you.

(Operator Instructions). There are no further questions at this time. I would 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, oil and gas in particular, and some others. 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