HighPoint Resources Corp
Q4 2014 Earnings Call Transcript

Published: 25 Feb 2015

[Operator:]

Good day, ladies and gentlemen, and welcome to the Fourth Quarter 2014 Bill Barrett Corporation Earnings Conference Call. My name is Tracey, and I'll be your operator for today. [Operator Instructions] As a reminder, this call is being recorded for replay purposes. I would like to turn the call over to Jennifer Martin, Vice President of Investor Relations. Please proceed ma'am.

[Jennifer Martin:]

Thank you, Tracey. Good morning, everyone and thank you for joining us. Speaking today will be Chief Executive Officer, Scot Woodall; and Chief Financial Officer, Bob Howard. A few quick notes before we get started. We have posted slides to accompany our discussion this morning on our Web site, on the homepage. So pull those down because we will be referencing those slides during the call. As usual, I need to remind everyone to read the disclosure statement provided in the earnings release and in the IR presentation, both are posted to the homepage of our Web site. We would discuss forward-looking statement such as guidance as well as reserves and well performance for which there are cautionary statements provided in the earnings release and IR presentation. During our discussion we make a reference to non-GAAP measures such as discretionary cash flow, adjusted net income and pre-tax PV10, reconciliations to the appropriate GAAP measures may also be found in the earnings release. With that, I will turn it over to Scot to get started. Scot?

[R. Scot Woodall:]

Thank you, Jennifer. Good morning and thank you for joining us. My comments today are focused on two key messages for you today, to highlight our strength and exceptional positioning to operate in the current commodity price environment. First, our finance position is very strong. We are well-positioned to maintain a strong balance sheet, liquidity and favorable debt metrics through the downturn with a flexible profitable development plan. Second, our asset quality and portfolio position in the DJ Basin is very strong. The DJ basin offers top-tier returns among the basins in the lower 48, and I'm very pleased with our initial result and execution. I will go into each of these points in a little bit more detail. We are exceptionally well-positioned to run our business in the current commodity price environment for a number of reasons. We had $165 million in cash on hand at year-end 2014 and just received a $43 million refund this quarter for relinquish leases in association with the settlement of the Cottonwood Gulch litigation. We have $375 million line of credit that is undrawn with no need to tap it in 2015. In combination we have ample liquidity. We have approximately 100% our 2015 production hedge at very favorable commodity prices, around $90 a barrel for oil and around $4 MMBtu for gas, and for the strong hedging positions going to '16 as well. Those hedges have a current value of approximately $180 million and will ensure cash flow from operations in 2015 that supports our capital program. We have insignificant drilling commitments to hold our acreage. Our investment decisions for our 2015 capital program are based on the merits of the drilling and completion returns pre-hedged. Of course, along with lower commodity prices comes lower drilling and completion costs, we enter 2015 with no long-term contractual obligations for drilling and completion services. This positioned us to take full advantage of declining cost. We are already currently realizing significant reductions in our 2015 drilling and completion cost specifically for DJ basin XRL well, we are currently receiving approximately 25% reduction versus our cost in 2014. So one can see, we are financially well-positioned as we enter into 2015. Now let's talk about what we're doing in the DJ basin. While we are still in the very early stages of getting results, we are clearly meeting our expectations and confirm our decisions to make DJ our preferred investment choice. We have all been anxiously awaiting results, so today we thought we would update everyone on the information we have today. I want to go into some details here so you will see the source of my enthusiasm. We have drilled and completed 24 extended reach laterals wells today. There has been some time delay and disappointment out there I think about reporting the 30 day IP rates on only 13 wells. So I want to share with you the most current data that I'm seeing. I'll refer to the slides that Jennifer referenced. So we will start on page 7 in the associated slide deck. This is the slide, production slide of our first seven area multi-well XRL pad. And actually this is the very first XRL pad that we drilled and completed. It is a three well pad. If you look at the graph, production is plotted along the y-axis, time along the x-axis. We implemented a fluid control flowback during the production phase. The controlled fluid flowback consist of maintaining a constant flowback that produce water, in this example 30 barrels per hour until first oil production. Then production rates, when the produced water and oil combine maintaining that same 30 barrel per hour production rate. This practice is designed to maintain higher downhole pressure during early time production which has been found to improve the peak oil performance. And I would also add, and we'd also believe peak long-term performance as well. These wells achieve a 30 day IP and or peak month volume in the third month. Slide also illustrates the production fluctuations and impact in late December and early January due to the weather and third-party downtime that we previously disclosed. These were the company's first extended reach lateral completions which utilizes sliding sleeve technology, each one is completed with 40-stages, and approximately 940,000 pounds per foot of propant. We go to the next slide, and now I'm on slide on page 8. This is another three well pad. This one is located in the northern area of our Northeast Wattenberg acreage. There were two different flowback practices be implemented during early time production, only fluid control and also gas production control. The controlled fluid flowback is the same as on the previous pad that we just described. The controlled gas flowback was also implemented and is designed to keep gas in solution and maintain a lower GOR for an extended period. The current gas control practice maintains gas volumes between 200 and 300 mcf per day until gas breakout occurs and cannot be suppressed any longer. Both of these practices are designed and maintained higher downhole pressure during early time production which has been found to maximize peak oil performance. These practices do lengthen the time needed to get 30 day IP and or peak month, to about four to five months. These were the first completions to utilize plug-and-perf technology. Each of these wells were done with 40-stages and approximately 970,000 pounds per foot of proppant. So we keep going out to take the realize examples I just showed on the previous two slides. On page 9, is a kind of hypothetical flowback model that we use for our planning and modeling purposes. So if you look at page 9, this slide illustrates the four periods of a typical extended reach that Treadwell goes through to get the 30 day IP and or a peak month. The first period here is the controlled water flowback, period number 2 is the oil buildup period where the well starts producing oil and gas. At the end of this period the well will reach a peak day rate and begin the 30 day IP flow period, period number 3. And then period number 4 is the peak month for the well. These current flowback practices maximize peak rates that require a longer buildup period to get to those peak rates. This slide also provides an update on the flowback status of the 24 wells. So if you look there across the top, we have labeled where 2 wells are in the water flowback period, 13 are in the buildup period or the 30 day IP period, just not complete, and 9 wells have the 30 day IPs. Of the 9 with the 30 day IPs, 3 wells also have the peak month associated volume with them. So I think I've illustrated with actual current production examples of our preliminary flowback results and the length of time it takes to deliver 30 day IPs. I think you're seeing the most current information if you notice there on the axis there, we are even showing some daily production rates in the month of February. I will make the point that true well performance will take more time than just 30 days, but we are committed to continue to update well results as they become available. Now we will turn to slide number 11. Here we are trying to provide a sample of illustrative economics for the DJ extended reach laterals stress tested at various flat commodity prices. The top table shows a range of per well drilling and completion cost. I stated earlier that our drilling completion costs are down 25% and so we are achieving a $6.25 million for a typical extended reach lateral well in the DJ basin. The lower table shows a range of EUR expectations. As seen on the previous slides, it's only to speak to a precise EUR but we feel confident based on the preliminary data we have to date, that are well should fall in the ranges illustrated in this table. One can conclude that the play is still economic even at a flat $50 oil price. So, why are managed flowback techniques that delay reporting 30 day IP results, the preliminary results are very encouraging. I would also add none of these preliminary results discussed today incorporate our latest completion technologies where we do more stages, namely 55 stages and more sand, and all of those are plug-and-perf. We have put forth some preliminary only indications of rate of return would be clearly expected to continue to improve on those throughout the year. Now let me move and touch on our year-end reserve report. Year-end proved to reserves were 122 million barrels of oil equivalent. This includes nearly doubling proved reserves in the DJ basin. We adapted a very conservative strategy to revision and reserve ads this year for two reasons. First the contracts of the current cheap price against the $95 per barrel and $4.35 per MMBtu year-end 2014 SEC pricing. It is likely that there will be downward pressure on this pricing at year-end 2015. Second, we are contemplating reduced capital development programs over the next several years based on this commodity price forecast. This could lead to downward reserve pressure based on the SEC five year PUD development rule. I think our conservation proved reserve bookings reflects sound business judgment. Our reserve volunteers also took a very conservative approach to the extended reach lateral reserve bookings at year-end based on our limited production history available at the time the year-end process was ongoing. Year-end reserve assignments for extended reach lateral wells were based on a multiple of extended reach lateral length versus a normal 640 acre length lateral. Now that we have more extended reach lateral production history we have evidence that the year-end reserves may understate actual performance by 20 or 30%. This same ratio would translate similarly to the offset PUDs. Our 3P reserves were 477 million barrels of oil equivalent which is up 22% at our core properties. 3P locations are 3700 gross which equates to a 72 year rig inventory in the DJ and a 44 rig year inventory in the UOP area. Clearly the company has significant amount of inventory. In DJ we expected the extended reach lateral development will occur on more than 80% of our acreage in the Northeast Wattenberg. Also today we put forth our 2015 operating plan. Our plan favors protecting our long-term financial position while continuing to develop and deliver value from our highest rate of returns. I will now turn the call over to Bob to expand on our 2015 guidance and other key details in the release.

[Robert Howard:]

Thank you, Scot. The tables in our earnings release combined with slides 19 through 26 with the slide deck posted this morning provide our 2015 guidance and a detailed 2014 operating financial results including the pro forma results for the asset sales in 2013 and 2014. I'll start my comments with the review of our guidance for 2015. Our projected capital expenditures for 2015 are $240 million to $280 million, which is less than one-half of our 2014 expenditures as we balance efficient asset development with a focus on our balance sheet. The 2015 expenditures are focused on the Northeast Wattenberg area of the DJ basin. The capital program reflects reducing the DJ rigs from 3 to 1 as of this month and maintaining a one rig growing program in the DJ basin through the remainder of the year to drill 20 to 25 operated wells plus participation in non-operated wells. We anticipate as the majority of the 2015 growing activities will be extended reach lateral wells. Current XRL well cost in the DJ basin are approximately $6.25 million. Our 2015 plan includes a rig in the East Bluebell area of the Uinta oil project for part of the year to drill nine operated wells. We expect a minimal participation in non-operated wells in the UOP. East Bluebell well costs are expected to average $1.6 million, a 40% decrease from 2014. Our first quarter CapEx is estimated approximately a $115 million which is higher than our run rate for the rest of the year as we reduce our activities in both the DJ basin and the Uinta basin throughout the first quarter. We expect our drilling and development plan will result in the capital outspend of approximately $75 million in 2015 to be funded by our cash on hand. We are planning that capital expenditures will be generally funded by cash flow in the second half of the year. On a pro forma basis for asset sales we anticipate that 2015 production will grow by approximately 10% compared to 2014 with quarterly production of a roughly 1.4 to 1.5 million barrels of oil equivalent for each quarter. Our production exit rate is forecasted to be flat to slightly up compared to 2014 putting our production rate on solid footing to begin in 2016. We're modeling oil price differentials of about $10 per barrel in the DJ basin for the year. DJ differentials are currently $9 to $11 per barrel and we expect that to narrow by $1 to $2 per barrel later in the year when the Pony Express lateral and the White Cliffs Pipeline expansion both come online. In the UOP oil price deductions have improved over the past month as local postings have narrowed from $18.75 of WTI prices to $8.75 before considering trucking charges of approximately $4 per barrel. ROV is projected at $46 to $50 million, which is roughly $8 to $9 per barrel of oil equivalent. As we discuss last quarter our DD&A expense rate related to the DJ and Uinta oil properties are higher than the historical DD&A rate for gas properties. For the fourth quarter of 2014 our DD&A averaged $33.10 per BOE after considering the third quarter asset sales. This rate is down slightly from the $34.32 per BOE reported on a pro forma basis for the third quarter. The modeling purposes on a going forward basis, a DD&A of $33 to $34 per BOE is probably the best starting point. Excluding non cash stock based compensation expenses general administrative expenses were $42 million in 2014. Reduction of $7 million compared to 2013. In conjunction with asset sales and the focus capital activity in 2014 and '15 we're able to further reduce G&A cost by additional 10% through a 2015 guidance range of $36 to $40 million. As a legacy from our gas properties we continue to hold long-term firm natural gas transportation contracts for the Overthrust and Ruby pipelines with a cost of $4.5 million per quarter. Beginning with the fourth quarter of 2014 these costs are being classified as a separate operating expense item apart from our gathering transportation and processing expense line since these contracts are not associated with any of our current production. I'd reiterate Scot's message that the company is well positioned in the current environment. Our balance sheet liquidity and hedge positions are solid and position is favorable in today's uncertain environment. We have a $375 million borrowing base in our bank line of credit. The semi-annual borrowing base re-determinates will be conducted in April based on discussions with our lenders and internal evaluation of our year-end reserves and hedge position we believe that the borrowing base following the April re-determinates will remain in the $350 to $375 million range. As shown at our presentation our 2015 hedge position of 4 million barrels of oil at a WTI price of over $90 per barrel and 7.1 billion cubic feet of gas at over $4 per MCF provides a solid cash flow base and greatly reduces our sensitivity to changes in commodity prices. Combining our reduced capital activity with our cash on hand we do not plan to draw on our credit facility during 2015. As we line down the multi rig growing program in the DJ basin we expect that our capital expenditures will be lined with cash flow for the second half of the year. We are committed to keeping the balance sheet and debt metrics in order during 2015. We have a long term outlook for our development programs and will not forego program returns for short term production growth. At the end of the year we expect to be well positioned for 2016. Throughout 2015 we'll be formulating our 2016 plans based on our property base, the operating environment and our financial resources. As 2015 unfolds we will be in a better position to discuss our plans and our expectations for 2016. And that concludes our prepared remarks and operator would you please open up the call for questions.

[Operator:]

[Operator Instructions] Your first question comes from the line of Jason Wangler with Wunderlich Securities. Please proceed, Sir.

[Jason Wangler:]

Thank you and good morning. Just was curious, as far as the obvious pretty significant oil cost you seeing come down, I know it'd be kind of a field question, but is there an idea of what those are actually in the cost coming down from vendor concessions of things versus -- obviously you guys getting a little bit better as you've gotten 25-30, these under your belt, I mean is there a decent mix between the two?

[Scot Woodall:]

Yes, Jason, there definitely is some efficiencies that we're gaining through the drilling and completion and mostly related to time. And then also I would say that now that we've got more infrastructures in place, just in roads and pipelines and gas lift operations, compression all those things also lead to better efficiencies as well also. So it's kind of a combination of both service costs concessions and our own efficiencies.

[Jason Wangler:]

Okay. And then just curious as far as and the slides, were helpful as far as the IRRs and things in the DJ. Around those edgy look going forward and I think Bob has kind of commented on -- will know more as the year goes on and I can appreciate that, but is there is a level where you guys looking so okay, there is the threshold here what we would look to ramp up, whether it is rate of return or an oil price or just what are your thoughts out there?

[Robert Howard:]

I think this is probably a little early to be discussed, clearly bringing on peak production in a $50 price environment doesn't seem to make good business sense to us. So I think you'd like to see some stronger signals on commodity pricing to make is kind of feel about ramping up. Clearly we have all of the pieces in place to be able to pull the trigger and ramp-up. We were just a few short months to go obviously contemplating increased activity, so clearly we have the land negotiations, the permits, all those things in place that we could be pretty flexible. And it just seems like this is probably a year that you want to just maintain flexibility and be able to react and respond, and that is probably should be one of the strength of the company of our size, is we should be able to react and respond very quickly to changing environment.

[Operator:]

Thank you for your question. Your next question comes from the line of Michael Kelly of Global Hunter Securities. Please proceed sir.

[Michael Kelly:]

Very helpful color on the three phases of the XRL wells, I’ve got to ask on it, is that become pretty -- is that the industry standard to complete wells like that or are you guys doing something different that peers in the basin, and along those laterals.

[R. Scot Woodall:]

I don’t know if I can exactly answer that one Mike. I think most of the industry has talked about doing some sort of controlled flowback operations instead of just going out there and putting the wells on full force, they are doing exactly like us. It’s kind of hard to tell, one of our peers that has the most extent of each lateral production history, most of the production plots they've shared publicly start at peak month and so you’ve missed all of the early time flowback data. So it’s kind of hard to judge or compare to what others are doing.

[Michael Kelly:]

Got it, thanks and maybe, that’s an answer to my second question but in terms of the ability to flat year-over-year in your production here while you're cutting the rig count throughout the year, is that a function of kind of the lag time of these wells on buildup or what's, driving that? It does seem setting up nicely for ’16.

[R. Scot Woodall:]

You are right. We were still running three rigs in the DJ and one in Utah into January. So you clearly have some inventory of left-over drilling from ’14 that helps the production occur in ’15 and you're right some of – this is a taking four to five months to kind of the get the peak month on most of that activity that helps the production in ’15 is well. I've prior made some comments, I think both in the third quarter and fourth quarter that we probably could spend, almost zero CapEx dollars and still achieve double-digit production growth in ’15 based on the activity at the end of the fourth quarter.

[Operator:]

Thank you. Our next question comes from the line Pearce Hammond from Simmons. Please proceed sir.

[Pearce Hammond:]

Thank you for taking my questions. My first question, I’d love to get some color, I know you are allocating some of your CapEx to the Uinta and it seems like you’ve got such good and better rate of return and the DJ, so why would you allocated all the DJs because you have some minimum obligations that you have to meet in the Uinta.

[R. Scot Woodall:]

And you are dead-on Pearce. We are doing a little bit of drilling in January in the Uinta play and relay that and I hate to use to the word science but we went ahead and we are in the middle of drilling a 40 acre like pilot area, coupled with the coring the well and coupled with the micro-seismic work that we were doing there. And it just seems like that is such a huge resource to the company that continuing on and gathering that data and gathering that information and beyond the work that data in 2015 just seem like it was the right technical decision that set us up for future activity out there. So there is some spending in the first quarter that associates with that and then there is some spending modeled in the third quarter, which is a handful of obligation wells in the range of four to five wells that we have to go do to maintain our acreage position.

[Pearce Hammond:]

Thank you. That’s a good color and then you all have done a good job in the past with your hedging and you are very well hedged for ’15 and have hedges in place as well through for ’16. How do you thinking about hedging now and sort of the lower oil price environment but also at lower service costs environment.

[Robert Howard:]

If we aren’t hedge well in ’15 and ’16 then we continue to look at the hedging positions forward with the market may bring us in ’16 but right it seems like we want to commit to that price in today's environment. We are setting our capital expenditure based on the current commodity price environment and we are comfortable as we get later into the year, we will continue to look at our hedge positions and we will make some decision. We look at it almost on a monthly basis but today there to add more hedges in ’16 we aren’t quite there yet and I think we are well positioned with the capital expenditure versus our hedges for ’15. So dynamic activity within the company. And we're comfortable where we're now and we will continue to look at it but to start we're willing to enter into any new hedges right now.

[Pearce Hammond:]

Thank you Bob, and then just one last one from me. Scot, are you both deferring any completions this year?

[R. Scot Woodall:]

No, we're not. And I've heard of that strategy by some of our peers, but I don't know if there is enough can tango in the curve right now. That says delaying on the handful of months leads to a much greater rate of return and it seems like that if you are spending the capital at drilling, you might as well go and spend the capital to complete them.

[Operator:]

Thank you for your question. Your next question comes from the line of Jeffrey Connolly, Clarkson Capital Markets. Please proceed.

[Jeffrey Connolly:]

Can you give us a decline rate for PDPs in the DJ and the Uinta?

[R. Scot Woodall:]

Sure. If you look at the base PDP production '14 over '15, its about 20% to 25% in the DJ and about 30% in Uinta, which will then put the overall company somewhere in that 25% to 30% range.

[Jeffrey Connolly:]

Thanks for that. And then is there any way that you guys could buy out or terminate the contracts for the unused capacity of the Ruby or Overthrust pipelines or anything you can do to get that kind of off your books?

[Robert Howard:]

Yes, we could but right now the value is pretty much at the futures cash flow. There is little discounting and there is a much value between the current prices, the pricing points to cover the transportation. So it certainly could be in some manner structured for that, but just there is not much value pickup from what we'd be able to get to drive our conservative cash.

[Operator:]

[Operator Instructions] Your next question comes from the line of Jeff Robinson of Barclays. Please proceed.

[Jeff Robinson:]

Scot, is your acreage in the DJ, can you just remind us that how suitable it is in terms of the blocking us for the XRL lateral.

[R. Scot Woodall:]

Sure. If we just think about the 40 plus thousand acres in the Northeast Wattenberg area, right now we would say that it's probably more than 80% would be developed on extended reach laterals and I think there is some land things that we can do that may even push that higher.

[Jeff Robinson:]

So, about 80% of the drilling locations that you all are showing would be the XRLs, at least as of today.

[R. Scot Woodall:]

Yes, for the Northeast Wattenberg area. So you think about our acreage position if -- you know we have the 80 plus thousand acres in all of the play, the 40 plus thousand in the Northeast Wattenberg, yes that’s and 80% or 90% XRL development. The rest of it, we haven't worked as hard and probably is more 640 acre development. We haven't been able to block it out this much. But if you think about the Northeast Wattenberg area, with that being so blocky and we clearly think that you can get superior rate of return associated with the extended reach lateral, I think we are in a very strong unique position there.

[Jeff Robinson:]

And then in the 2015 drilling program, can you just talk about where on your acreage you will have new data and what that will help, telling yield by year-end, as far as the prospectivity of all of it?

[R. Scot Woodall:]

Sure, you know Jeff if we refer back to the flight on page 9, you can kind of see where the first 24 wells are in that flowback period, so obviously in the ensuing next few months we are going continue get more and more data from there. The 20+ something wells that we will drill out there, in '15 we'll have some data on -- somewhat only, and that's kind of scattered between North and South throughout the year. I don't think that we are going to be touching every single corner of the acreage, but I would add that in the fourth quarter of 2014 we scored well way out Southeast to gain information about not only the not barely B and C, but also the A and the Greenhorn. We also cored a well up to the very northern end of our northern acreage, same thing to get data on the A to B, the C and the [indiscernible], so all in the fourth quarter, we accord the wells in various parts of our acreage position to continue that data gathering and understanding of our acreage position.

[Jeff Robinson:]

Thanks, and Bob just a follow-up on the gas contract. Is there anything you all can do to lay off some of that capacity on to anybody else, is there any market for it?

[Robert Howard:]

Yes, there is Jeff, at percent the values very low. We do release capacity from time to time and pick up some value on it and that's reflected in our cost structure, but it's just that the markets are pretty flat on the gas price between our delivery or our receive point delivery point.

[Operator:]

Your next question comes from the line of Ryan Oatman from SunTrust. Please proceed.

[Ryan Oatman:]

To make sure the detail on the slides, I wonder if you could speak a little bit more broadly as to what you have learned from your varying test of completion designs and in areas in the DJ, what stays out, are there any areas or designs seem preferable to you at this point?

[R. Scot Woodall:]

I'll probably correct you by saying obviously it's early but it sure seems like that the plug-and-perf wells look like they are going to exceed the sliding sleeve type wells. And then I think we believe that the 55-stage XRLs are going to exceed the 40-stage XRLs. So if you looked at what we showed today and I'd say we are showing production all the way through February, neither of those examples are 55-stage plug-and-perf. So clearly we think that there is an improvement even upon those that will be coming over the next several months. In our base plan that we’re doing in 2015 the way we're modeling everything from a cost stand-point is the 55-stage plug-and-perf.

[Ryan Oatman:]

Got you. I know that there was kind of my next question. So that 6.25 million -- is that the cost for 40-stage well or is that a cost for a 55-stage well.

[R. Scot Woodall:]

It’s a 55-stage plug-and-perf with normally 1000 pounds per lateral foot. So roughly 9 million pounds if you assume, 9,000 foot lateral. So 9 million pounds 55-stages plug-and-perf.

[Ryan Oatman:]

Got you, so apples-to-apples and then the cost savings would be sort of even greater than that at 25 percentage stock. You can take it about a 40-stage lateral, you know kind of being at the base case, is that the rate that you would think about it?

[R. Scot Woodall:]

Not exactly, I do think that the 8.25 number that we kind of lobbed out there for Q4 '14 was the same design. Apples-to-apples comparison is 6.25 to 8.25.

[Ryan Oatman:]

Got it, so that’s already apples-to-apples. I appreciate that. On the metrics on page 11, you show a 5.5 going to our well cost. Should we look for that? That 10% or so in further cost reductions when we move forward?

[R. Scot Woodall:]

The goals that my drilling and completion Vice President certainly have that number in there.

[Ryan Oatman:]

So I will make sure it's in, so two more questions on the unused capacity. I know you guys have talked about this before. First, can you jus remind us when those charges rolloff? And then second, are those charges included in the OpEx guidance or is that really just for kind of that core OpEx in the separate line item?

[Robert Howard:]

The unused capacity charges rolloff, I think at 2021. I didn't quite capture second part of that question, Ryan, sorry.

[Ryan Oatman:]

No worries. The OpEx guidance was out there, is that for sort of that separate OpEx line item or would it include these unused capacity charges as well?

[Robert Howard:]

We have a separate line item and that's a separate list with separate line item on the guidance. We got a separate line item in our financial statement. OpEx doesn’t include that, so that there are two separate charges now underway, we are treating it.

[Ryan Oatman:]

Makes sense, finally one last question from me. With Unita sort of rig expected to come back at the end of the year, should we look forward that's 2016 CapEx to be up from some of that second half run rate that I'm sort of packing preliminarily at 45 to 50 million per quarter, or is it just kind of too early to say?

[R. Scot Woodall:]

It's probably too early to say, clearly we have to drill those four or five obligation wells and then we'll have to look at our commitments '16 and also kind of look commodity pricing is due in at that time, if that -- we have some better color on '16 commodity pricing. It might tell us how our activity level should correspond.

[Operator:]

There are no more questions waiting at this time. So I would now like to turn the call over to Jennifer for closing remarks

[Jennifer Martin:]

Thank you, everyone, for joining us. And I look forward to speaking with many of you in the coming days to work through your models and any other questions, thank you

[Operator:]

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