HighPoint Resources Corp
Q2 2015 Earnings Call Transcript

Published: 7 Aug 2015

[Operator:]

Good day, ladies and gentlemen, and welcome to the Bill Barrett Corporation Second Quarter 2015 Earnings Conference Call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session and instructions will be given at that time. As a reminder, this conference call is being recorded. I would now like to turn the conference over to Mr. Larry Busnardo, Senior Director, Investor Relations. Please go ahead, sir.

[Larry C. Busnardo:]

Good morning. And thank you for joining us today for the Bill Barrett Corporation second quarter earnings call. Joining me on the call today are Scot Woodall, Chief Executive Officer; and Bob Howard, Chief Financial Officer. A few quick notes before we begin, I need to remind everyone to read the disclosure statements provided in the earnings release posted to the homepage of our website at billbarrettcorp.com. During our discussion, we may make reference to non-GAAP measures, such as discretionary cash flow and adjusted net income. Additional information may be found in our second quarter 10-Q which was filed yesterday afternoon. With that, I will turn the call over to Scot Woodall to get started. Scot?

[R. Scot Woodall:]

Good morning and thank you for joining us this morning to discuss our second quarter results. Before I provide the second quarter operational highlights, I would like to speak about the current status of the company. While our industry faces many headwinds in this challenging commodity price environment, the company is well positioned and more importantly, delivering execution as demonstrated in our second quarter and first half performance. We have repositioned the company and are investing in one of the top five financially performing basins in the country. Our acreage position and execution delivers sound economics even in this period of low commodity prices. Financially we remain solid with $101 million in cash, a hedge book worth today $168 million with 80% of our projected volumes hedged in 2015 and 40% of our volumes hedged in 2016. Additionally, we are undrawn on our $375 million credit facility. Strategically our focus has been to maintain flexibility in our portfolio, our operations and financially. These factors, coupled with our execution, positions our company to succeed in the current environment. I will now provide a summary of our operational highlights for the quarter before turning the call over to Bob to do the financial results. In many ways, the second quarter was a continuation of the first quarter as we posted very solid results and continued to execute on our strategic plan, meet all of our operational objectives and continue to demonstrate that our DJ Basin extended reach lateral program is a top tier asset. Our positive momentum is driven by our execution of the items we control, production, capital and lease operating expenses. First, we maintain a sharp focus on execution of production. This can be seen in our second quarter production volumes which exceeded our guidance by 9%. Similar to the first quarter, the production beat is a direct result of the performance of our extended reach lateral program in the Northeast Wattenberg field. Clearly, our extended reach lateral program is delivering results and is a testament to the strength of our entire operations team. Our excellent performance through the first half of this year allows us to increase our 2015 production guidance for the third time. We are now guiding to a production guidance of a range of 6.1 million to 6.5 million barrels of oil equivalent and this translates to a 23% growth over 2014 at the midpoint of our guidance range when excluding asset sales, with oil volumes increasing approximately 25%. This performance is expected to provide growth as we look forward into 2016. We are highly encouraged by the early production data from our extended reach lateral program as we implement technology refinements and operational efficiencies to deliver improving results. Our preferred completion design is proving to be the best method to complete our extended reach lateral wells and is delivering strong early well performance. We now have 90-day production history for our initial four wells and they continued to meet our expectations and are clearly outperforming wells with early completion designs. We continue to demonstrate capital cost reductions. Our second quarter 2015 capital costs in DJ were 25% lower than they were in Q4 of 2014. We expect further reductions in the second half of 2015 as we continue to drive efficiencies. On a dollar per BOE basis, our second quarter 2015 LOE was 20% lower than in Q1 despite inclement weather in May. The company's total LOE was $7.01 per barrel in the second quarter versus $8.72 in the first quarter. Our flagship asset, the DJ, was $5.84 per barrel in Q2. Recapping, strong execution in all areas, production, capital and LOE. I'd now like to talk a little bit more about our extended reach lateral program. As discussed on our last call, our preferred completion technique includes completing the wells with plug-and-perf versus sliding-sleeve, using approximately 1,000 pounds of sand per foot, completing with 55 stages versus 40 stages and controlling both the water and gas flowback. Although it is still early in the life of the extended reach lateral program, we now have several additional months of data from these wells that we reported last quarter. This data continues to validate our performance assumptions about the play and provides increasing confidence as to its potential. The latest four extended reach lateral wells placed on sales now have 90 days of production history. Each of these wells was completed with plug-and-perf and 55 stages. Today we're reporting that these wells have an average 30-day IP rate of 649 barrels of oil equivalent per day, a 60-day average rate of 615 barrels of oil per day and a 90-day IP rate of 580 barrels of oil per day. We are pleased with these early results as the wells are performing significantly better than previous wells that were completed with older techniques. This data is confirming our view that wells utilizing our techniques will exhibit shallower production declines. During the second quarter, 10 extended reach laterals were placed on sales with peak initial oil production expected to be reached in the fourth quarter. In addition, extended reach lateral wells were placed on early – four additional wells were placed online in early July. All of these wells were completed with plug-and-perf and 55 stages. So you can see we have a significant number of extended reach lateral wells that are in the early flowback stage and we anticipate they'll reach peak production later in the fourth quarter providing a significant news flow later in the year. Lastly, we TD'd our initial well in the Niobrara A formation. This well is an extended reach lateral well that is located in the northern part of our acreage position. Moving on to cost, we continue to maintain discipline as our contracted Northeast Wattenberg extended reach lateral wells are averaging $6.25 million to drill and complete. We have been able to garner significant efficiency gains thanks to faster drilling times on these wells. Specifically, the seven most recent extended reach lateral wells, with laterals of about 9,500 feet were drilled 40% faster than earlier pads. This will positively impact our estimated drilling and completion cost. Our most recent pad averaged 10 days to drill and included a best-in-class well of eight days. While we continue drive operating efficiencies and identify opportunities to lower the overall cost structure. In summary, we have worked extremely hard over the past two years to successfully reposition the company. We believe the DJ Basin in a high-quality asset that provides a large multi-year inventory of high-margin drilling opportunities. It is providing to be an exceptional asset that positions us to achieve our strategic goals while providing a strong foundation heading into 2016. Although these are currently challenging times for our sector, we remain focused on the items we can control – operational performance and execution – to increase the efficiencies of our overall operations. Now I'll turn the call over to Bob to discuss more detail about our financial results.

[Robert William Howard:]

Thank you, Scot. We are pleased to report very good second quarter financial results as our adjusted earnings, cash flow, EBITDAX and production volumes were all above consensus estimates. This strong outperformance can be attributed to continued execution of our DJ Basin drilling program and lower lease operating cost. Although we and the entire industry are experiencing a challenging macroeconomic environment, we maintain a strong financial position with a significant cash balance and undrawn revolving credit facility that provides ample near-term liquidity. I'd like to discuss some of the key items for the second quarter. Second quarter production volumes of 1.6 million barrels of oil equivalent exceeded our guidance of 1.5 million barrels of oil equivalent by 9%. Total equivalent volumes in the DJ and Uinta Basins increased 29% compared to 2014, and oil volumes were 31% higher on a year-over-year basis. DJ Basin quarterly production grew 76% from last year and was up 8% sequentially, which more offset declines from the Uinta basin. Importantly, first half production surpassed our initial forecasted guidance by over 10% and was 35% higher compared to the first half of 2014. Our strong performance is a primary driver behind the increasing 2015 production guidance. We are now projecting that production will average 6.1 million to 6.5 million barrels of oil equivalent for 2015. This is the third time we have increased guidance this year. At the midpoint, guidance represents a 23% increase over 2014 volumes from the DJ and Uinta Basins and is 11% greater than the midpoint of our initial guidance. We expect third quarter production will be 1.5 million barrels of oil equivalent, which is down slightly to the second quarter due to timing of well completions of our XRL program and the fact that we reduced drilling activity to one rig for a portion of the first half of this year. As discussed last quarter, we continue to expect that uptick in production volumes for the fourth quarter. Total cash operating cost for the second quarter averaged $9.92 per Boe which was a 9% production (sic) [reduction] from the first quarter. Lease operating expenses averaged $7.01 per Boe and were 20% lower than the first quarter due to operating efficiencies and reduction of workover activity in the Uinta Basin. We also reduced LOE by shutting in certain Uinta Basin oil wells that are uneconomic in the current lower oil price environment due to higher unit operating cost. I'd also like to note that LOE in the DJ Basin was $5.84 per Boe in the second quarter, which is significantly lower than the Uinta Basin LOE. We expect LOE per unit will stay relatively flat for the remainder of the year. Capital expenditures for the second quarter were approximately $65 million which came in19% below our guidance of $80 million, primarily due to the timing of drilling and completion activities in the DJ Basin. First half 2015 capital expenditures totaled $179 million. CapEx continues to trend within the $320 million to $350 million guidance range for the full year, but the split of capital expenditures between the third and fourth quarters of 2015 will depend on the timing of completions that are currently scheduled for the third quarter. G&A came in at $11.9 million for the quarter which is higher than the first quarter due to certain accruals and expense payments made during the quarter. We are projecting that G&A for the second half of the year will be lower than the first half of the year, but it appears G&A will come in near the higher end of $36 million to $40 million guidance range. Lastly, based on our expected production for the remainder of the year, we should be roughly 80% hedged at a WTI oil price of $89.81 per barrel and a Rockies natural gas price of $4.13 per MMBtu with no NGL hedges. For 2016, we have approximately 40% of expected oil and gas volumes hedged at a WTI price of around $80 per barrel and a Rockies gas price of $4.10 per MMBtu. At the end of June, our hedge position was valued at $119 million. You will find a full summary of our hedge position on the hedge table in the press release. Turning to the balance sheet, we remain well positioned in the current low oil price environment. We have zero drawn on our $375 million revolving credit facility with $349 million available when taking into account a $26 million letter of credit. As we contemplate the midyear borrowing base redetermination, we anticipate that the increase in proved producing reserves will offset the impact of lower commodity prices. We ended the quarter with cash and short-term investments of $101 million. In June, we established an at-the-market equity offering program to increase our financial flexibility to fund our capital expenditure program if needed. To date, we have not issued any shares under this program. We do not expect to increase debt during the year with our cash and short-term investments being used to fund the amount that capital expenditures will exceed discretionary cash flow. And we continue to main operational flexibility with no long-term drilling contracts or commitments related to our drilling and completion program. We will remain capital disciplined and fiscally responsible as we preserve the strength of our balance sheet, balanced with maximizing the value of our assets. In summary, we have a strong liquidity position, excellent hedges in place and reiterate our operational outlook is looking good with Northeast Wattenberg operations going very well. We are continuing build momentum as evidenced by our second quarter results and we look to expand on this momentum during the second half of 2015. That concludes our prepared remarks. And operator, could you please open up the call to questions.

[Operator:]

Thank you. And our first question comes from the line of Brad Carpenter from Cantor Fitzgerald. Your line is open.

[Brad Carpenter:]

Hey. Good morning, guys. And congrats on the great quarter.

[R. Scot Woodall:]

Thanks, Brad.

[Brad Carpenter:]

Scot, it was good to see the updated 60-day and 90-day rates for the XRLs using your preferred completion technique. I know it's still early innings, but I was hoping you could provide some commentary on how you see the new wells performing with respect to potential type curve shapes and when you think we might be able to expect an updated type curve for the program going forward?

[R. Scot Woodall:]

Sure, Brad. So, yeah, we're extremely pleased with these four wells which are utilizing all the techniques that we described. And what it appears like is that they're outperforming our early time type curve, and then like I say, more importantly, is the flatness that you're observing in that 60-day and 90-day rates. Clearly, we'd like to see a few more months to see how that decline settles out kind of in the next three months or so. But all indicators, it's definitely better than what we were doing six months ago. And if we can do this and repeat this for the next 1,100 wells, we have an excellent play. In terms of publishing type curves or things, probably still want another two or three months of data. So I kind of look for that to be more towards the end of the year that we would actually put out that type of information. Clearly, if you go back to like, the investor relations materials that we have out there, if you take kind of our type curve of roughly that 700,000 barrels of oil equivalent in the current capital cost and assumptions, you're delivering pretty acceptable rate of returns. So we still think that's a very valid example of our economics.

[Brad Carpenter:]

Okay. Great. And then I guess just following up on that, on economics, it was good to see another downtick in well cost. But given front month WTI settling just north of $44 or trading right now, could you provide some color on how rates of returns are looking in this environment?

[R. Scot Woodall:]

Sure. We took a – if you take like a strip, which I might be a couple of days out of date on that strip price, but with our current set of assumptions, it still delivers about a 30% rate of return. So, clearly, with the volatility of commodity prices, we look at it very frequently and are also very mindful of our capital spend and want to make sure that we have those things aligned.

[Brad Carpenter:]

Okay. Great. That's helpful. I'll let someone else hop in. Thanks for your time.

[Operator:]

Thank you. Our next question comes from Jason Wangler from Wunderlich. Your line is open.

[Jason A. Wangler:]

Hey. Good morning, guys. I actually wanted to maybe jump over to Uinta just from the commentary. Do you have an idea how much production you shut-in there and just kind of the cost savings that you're seeing from that?

[R. Scot Woodall:]

Sure. We shut-in kind of in the middle of the second quarter about 1,000 barrels of oil equivalent per day. And so when you think about still seeing that type of growth in Q2, clearly, that adds another layer of efficiencies and productivity to the DJ Basin because the DJ Basin absorbed that shut-in volume and the normal decline of Utah, so really that leads to that continued outperformance in DJ. In terms of overall costs, yeah, we did see an associated LOE drop with those wells in Q2 and that's what you're seeing. Primarily the drop in LOE is associated with improving efficiencies in our Utah operations and the shut-in wells.

[Jason A. Wangler:]

And is that 1,000 net, Scot?

[R. Scot Woodall:]

Yes, it is.

[Jason A. Wangler:]

Okay. Yeah. That's really impressive. And just maybe kind of dovetailing that, maybe the same kind of discussion, but it looked like differentials were very strong in the second quarter. Could you just maybe talk about what you're seeing there, whether it's kind of the same thing with more DJ production really bringing those down or if there's other things in play right now?

[R. Scot Woodall:]

Yes. Sure. Absolutely. As DJ becomes more and more of our portfolio, it positively impacts kind all facets of our business as – since we were just talking about LOE, I'll throw that in. The LOE of the DJ is $5.80-something, where Utah is $9 or $10. So the more the DJ becomes an impact, or a higher proportionate, obviously the LOE will continue to trend downward. Same with the differentials. We still model about a $9 differential for DJ, but we have observed most recently that differential has been less than $8. So it seems like it's trending the same way. So when you kind of think about all the things that we can impact, I think we're doing it positively when you think about differentials, lease operating expenses, capital, and just overall production well performance. It all seems like it's going our direction.

[Jason A. Wangler:]

Great. I'll turn it back. Thank you.

[Operator:]

Our next question comes from Brian Corales from Howard Weil. Your line is open.

[Brian Michael Corales:]

Good morning, guys.

[R. Scot Woodall:]

Good morning, Brian.

[Brian Michael Corales:]

Just a question, you all are TD'd on your first A bench well. Can you remind us, have you all tested the C or what other benches have you all tested?

[R. Scot Woodall:]

We have tested the C and the B and some Codell on the west side of our acreage, but predominantly it's been B and C.

[Brian Michael Corales:]

Okay. And all the extended laterals that you all have done, has that all have been in the B?

[R. Scot Woodall:]

No. There's been a proportion of those that are in the C as well, and I don't have that breakout sitting right here in front me, Brian, but, yes, it's something along the lines of two-thirds B, one-third C, roughly.

[Brian Michael Corales:]

Okay.

[R. Scot Woodall:]

And then the A test is going to be kind of interesting, and that's kind of stemming from all the work that our G&G group has done. If you remember, we discussed going and taking some cores throughout our acreage position and try and take that information, coupled with the seismic and a lot of hard work has gone into determining that we think the A has some prospectivity over that Northern portion of the basin, which has led to us doing this test.

[Brian Michael Corales:]

Okay. And is there any other A test planned or are you going to wait to see the results here before decide what you do going forward?

[R. Scot Woodall:]

I think we'll see the results. So those wells are like (20

[Brian Michael Corales:]

Okay. Thanks, guys. It was helpful.

[R. Scot Woodall:]

Yep.

[Operator:]

Our next question comes from Steve Berman from Canaccord. Your line is open.

[Stephen F. Berman:]

Thanks. Good morning. Scot, can you talk about the $6.25 million XRL well cost? How much more do you think you can take out of it, and how much of that would be from further efficiencies versus further service cost reductions?

[R. Scot Woodall:]

Sure. First off I'll just say, when I quote capital cost of the $6.25 million, that's actually what we're performing to-date. So that is not a target cost. That's an actual cost to-date. Clearly, our operations team has goals and targets that are significantly below that. In terms of additional cost savings, I would expect that we could see another 5% or 10% materialize in the second half. And that's probably a combination of some service cost. But I think more importantly, it's probably more driven by our own efficiencies. When you think about those drilling times that I quoted of a 40% reduction that definitely translates into cost. The completions team is doing a lot of things in terms of water management. The production team is doing a lot of things in terms of how we are spending money doing the flow-backs and facilities. So, it definitely is a lot that's coming from our side of driving efficiencies going forward.

[Stephen F. Berman:]

Okay. And one more, if I may. Just your general thoughts on the infrastructure in the DJ. We've got Lucerne II ramping up, just your overall thoughts there?

[R. Scot Woodall:]

Definitely Lucerne II is going to help us. Almost all of our gas flows towards Lucerne II, and since it has had some pretty good run times here of recently, I think we are observing a plus-or-minus 100 psi drop in wellhead pressures because of Lucerne II.

[Stephen F. Berman:]

Great. Thanks a lot.

[Operator:]

Our next question comes from David Beard from Coker Palmer. Your line is open

[Robert William Howard:]

Hi. Good morning, gentlemen. And congratulations on the good quarter.

[Robert William Howard:]

Thanks.

[David E. Beard:]

Most of my questions have been asked. So I wondered if you could give us some color relative to raising additional capital if – how long or would you – or how low would oil prices need to stay for you to reconsider that? And then, maybe a different big picture question. Scot, you've been at the company for a while, what do you think has changed to drive these just much better completion results all the way around. What's changed inside the company?

[R. Scot Woodall:]

Well, I'll take your latter question because I like talking about this, and maybe I'll let Bob talk about...

[David E. Beard:]

Yeah. I figured you would. That's okay.

[R. Scot Woodall:]

...the capital raise and some of those things. Clearly, the company has been through a huge transition. When you think back a couple of years ago when we're – don't have the properties in the DJ Basin at all. We don't have part of our Utah properties and we're still a 96% natural gas company, you've got a lot of things changing inside the organization. The portfolio is changing. The types of skill sets you need to move from a natural gas exploration company to a resource exploitation development company, all those things factor in. And then kind of in the middle of that, once we kind of repositioned the portfolio – and by the way, I think we did an excellent job of getting into one of the top five basins in the United States by going into the DJ Basin. Halfway through 2014, we flipped 180 degrees from drilling the standard-length laterals to the extended-reach laterals, which obviously causes some turmoil in your planning, in your forecasting and your execution. The way I see things now, obviously, we're doing basically one type of well, one type of completion, and we're just going to continue to do it for the remainder of this year and for the foreseeable future. You should get very good at what you're doing. So I have all the confidence in our operations team to be out there and go and repeat and deliver and drive those efficiencies. Similarly, I have all the confidence in our forecasting teams that they ought to be able to predict this one type well and just repeat it a number of times. So I would expect us to be able to plan very accurately and continue to drive efficiencies and execute. And I think you're starting to see that in Q1. You saw it again in Q2. I would feel pretty confident that we'll do it again in Q3. So inside the company, we feel pretty good about where we stand and our performance.

[Robert William Howard:]

And I'll address some of the where we are financially with respect to our operations. And we're very deliberate on how we invest the money. We're still generating pretty good cash flow from our operations, and we have the hedge positions to protect that in the current environment. I realize oil prices are low, but we have the hedges in place to protect against that in the foreseeable future and have a nice established hedge position for next year. Also have cash on the balance sheet. We have the credit facility that's undrawn, and we'll be going through the redetermination here soon. But kind of our expectations are that availability should not change much. We still have some properties that aren't being invested that there may be a market for. So those are all primary sources with which to fund our activity levels, and we'll balance that against those sources. As we mentioned in the call notes and as everyone knows, we did put an ATM into place a couple months ago. And that was with the intent of giving us flexibility and the ability to continue to manage the profitable investment in our programs. It's there. We think it's a good option to have available to us if needed. But we have a lot of other sources to put to work in our business first. And we aren't anxious to try to issue equity, but we appreciate having the ability to do so when and if needed.

[David E. Beard:]

Good. Great. Appreciate it. And thanks for the color on both questions.

[Operator:]

Our next question comes from John Gerdes from KLR Group.

[John J. Gerdes:]

Scot, in terms of your thought process – yours and the board's thought process on this ATM program, can you walk us through kind of what the thinking was and maybe give a sense of maybe where you see the sequencing or timing of possible execution in that program, or is that even potentially just a contingent program rather than something that probably does occur in terms of capitalization as you move out into next year? And thank you.

[R. Scot Woodall:]

Sure, John. I guess I kind of look at it as the ATM program is another tool to put into our tool box when we think about maintaining the health on our balance sheet, and that's just kind of – like I say, that's one tool. Obviously, it's – we have asset sales of non-core things that could be executed, that could be a source of capital. Clearly, driving the well performance like we are and reducing capital spend and reducing LOE drives cash flow as well. So we thought the way we approach the ATM, it was just good business sense to have another tool in the tool box and to have some flexibility when we think about managing through these trying times. Obviously, our intent is not to dilute our shareholders to someplace that we don't like. Obviously, it was not our intent – back in May or June when we put this in place, we didn't like the share price, and we did not execute any shares or do a block deal. And so we thought this was kind of the right balance and the right tool. Specifically, when you think about at the time, we had $150 million in the bank. Today we have $100 million in the bank and we can use that. We don't have an immediate need to put additional money in the bank and earn basically 0% interest on that money. And then also, as Bob said, we're completely undrawn on that credit facility right now, and we do expect it to probably get reaffirmed again this fall at the same level. So when you think about the cash and you think about an undrawn credit facility, those seem like better sources of capital today than issuing shares underneath the ATM. But we put it in place as an option to have, and I think it still sits there as an option to use going forward.

[John J. Gerdes:]

Scot. You just laid out a whole series of liquidity alternatives which is great. In a way then why even lay out there this as an alternative and I guess maybe to build on that for just a moment, my sense is from your commentary and correct me here please, is that the probabilities are somewhat limited, or remote, or could I characterize as nil. In the use of this program and again if any kind of sense that you would give in terms of the equity price levels and the magnitude of this program that you may use would be helpful and thank you.

[R. Scot Woodall:]

Sure. And I'll back up to kind of the earlier part of your question. We put it in place because we were adding the second rig and we're spending more money. And it just seems like that you have to address liquidity when you think about continuing to spend more capital and I thought that was the right thing to do versus saying, we're going to go out and sell $100 million worth of assets and then go to our business development team and say, you have to sell $100 million worth of assets in the next 60 days. Guess what, whoever you are going to sell them to is probably going to lowball your prices. And so you don't really want to put that sitting out there, I guess. And so all the things that we have within our control I would like to do on our timeline versus with like a gun to our head if you kind of understand what I'm trying to say there. So we put it in place to give us choices and to give us flexibility. And as you picked up from my earlier comments, we do have a number of sources for capital and for liquidity. I probably can't comment on a share price of when we would issue things or anything like that, but clearly we're in a much different position than most people with the cash and the undrawn credit facility.

[John J. Gerdes:]

Do you have any sense of probability of the utilization of this program, any kind of rough sense? 25% a quarter it gets used, any rough sense of what you would envision with what you can understand today about the marketplace, what you would envision in terms of the exercise under that program?

[R. Scot Woodall:]

I'd probably not like to comment, John, just because there are just so many moving parts of everything. So probably wouldn't want to comment on that one.

[John J. Gerdes:]

Scot, thank you for your responses.

[R. Scot Woodall:]

Sure.

[Operator:]

Our next question comes from the line of Neal Dingmann from SunTrust. Your line is open.

[Neal D. Dingmann:]

Good morning, guys. Say, Scot, could you just talk a little bit – I'm looking at just Northeast Wattenberg – your thoughts? Have anything changed really on the thoughts about the space in between the Northern area, Central, Southern? I'm just kind of looking at the wells per 1,280.

[R. Scot Woodall:]

No. I think we're still at 80 acres per bench. So, if you have 1 bench, 8 wells; 2 benches, 16 wells. That's still kind of our basic thinking right now.

[Neal D. Dingmann:]

Got it. And then, secondly, some guys were talking on this BioVert that some of your other peers are using to break rock in some of these things. Are you looking at anything like that?

[R. Scot Woodall:]

We actually have pumped a number of those tests, both in new wells and in some older re-frack wells, and those have all been done just in the last couple of months, so it's probably early to comment on production results. But, yes, it is a product that is something that we're considering and actually did pump on a number of wells.

[Neal D. Dingmann:]

All right. Thanks, guys. That's it for me.

[Operator:]

Our next question comes from Ryan Oatman from Cowen & Company. Your line is open.

[Ryan Oatman:]

Hi. Good morning.

[R. Scot Woodall:]

Good morning, Ryan.

[Ryan Oatman:]

As already discussed a couple of times, I noticed the updated 90-day production history for the first four XRL wells was better than that of the first one, suggesting that the latest three have been stronger. I wanted to see if you can kind of provide any color there, any key differences between these well results whether it's geography, line pressure, et cetera.

[R. Scot Woodall:]

Not really. They're on the same pad. So obviously, when you got one well data set versus four-well data set, there's a little bit of variations to it, but they're on the same pad.

[Ryan Oatman:]

Got you. Got you. And moving forward, are you experimenting with any sort of differences in terms of completion, lift and landing or do you feel like moving forward, it's almost kind of a cookie cutter deal at this point?

[R. Scot Woodall:]

I guess if I characterize that the basic design that we have now is probably not going to change. But I think as an operations organization, you're always tweaking little things. So you're always tweaking sand volumes or fluid volumes or how you're running your gas lift and how you're flowing the wells back. So I think there's always minor tweaks. But I guess I would say that by and large, we don't see things changing too much.

[Ryan Oatman:]

Okay. That's helpful. And then I wanted to make sure I heard you correctly on the fourth quarter. Third quarter obviously down a little from 2Q levels. Can you just confirm fourth quarter you're looking for sequential growth from third quarter?

[R. Scot Woodall:]

I think the answer to that question is yes. So, if you kind of picked up on the math, we've got 10 wells flowing back in the early flowback stages. We have four more wells that have started flowing back in the early flowback stages. And then we are about to move off of a nine-well pad that those completion operations will take some place somewhere in the third quarter. So you've got 10 wells plus 4 wells, plus 9 wells that all should be contributing at various levels to Q4 production, so I would think it is sequentially higher than Q3.

[Ryan Oatman:]

That's helpful. And then on – I guess more of a macro question here. With so many pipeline changes across the United States here, your experience with Rockies gas historically, I was curious if you guys have any views on Rockies gas prices and any thoughts on sort of hedging the Rockies differential here?

[R. Scot Woodall:]

Not really. Since we're kind of more of an oil company I'm not even sure I'm informed anymore.

[Ryan Oatman:]

That's totally fair, totally fair. Figured I would try it. All right. I'll hop back in the queue. Thanks.

[Operator:]

Thank you. Our next question comes from Dan McSpirit from BMO Capital Markets. Your line is open.

[Dan E. McSpirit:]

Good morning, folks, and thank you for taking my questions. Looking into 2016, can you speak about the relationship of CapEx to cash flow next year and what that means for leverage to achieve the 10% to 15% production growth at strip pricing?

[Robert William Howard:]

As we planned into 2016, we haven't set everything up for 2016 yet. We're still doing the budgeting and we'll be looking at all those numbers where we end with the funds available because again we have the credit facility available and be able to fund that. And that will likely, as we look next year at current commodity prices, we are hedged somewhat. But we'll have a capital investment need into next year. We want to keep the balance sheet in good shape. We do look at our debt to EBITDAX levels and that's one of our drivers of some of the decision-making and how we manage the capital allocation. And it gets up towards 4 times, that just probably a level that we need to try to manage around and manage to keep it under that and try to bring it down as we continue to increase production 2016 into 2017. So we've got some levers we'll need to pull on that, but that's kind of the benchmark we have as we plan into next year with the programs that – we're still learning what the programs can do. We've put out some indicative numbers for 2016 just to kind of get people thinking the same way we are. The performance we get at the end of this year and what we're able to do, both well costs and production, and bring in cash flows from that will be very much determinant to how we plan the whole year, and the timing, and then how the balance sheet works out. But we do have some guidelines on the balance sheet that we want to stay within.

[Dan E. McSpirit:]

Okay. Great. And as a follow-up to that question, does the 2016 production growth guidance of, again, 10% to 15% incorporate any positive revision to the EUR or the momentum that's starting to build in the DJ Basin, at least based on the current rates?

[R. Scot Woodall:]

I would say no, Dan. Those numbers we put out back in May or June and probably have not been updated since then. It was kind to provide some directional sideboards is the way I would look at that.

[Dan E. McSpirit:]

Okay. Great. And then just quickly, maybe one or two more here, when do you achieve peak rate on the XRL wells? That is, how long do they take to clean up, and is there much change when the wells are completed with the preferred technique versus, say, the old technique?

[R. Scot Woodall:]

I would say to get to that peak 30-day production rate is about five months, and that's the way that we budget or plan our timing. In terms of changes, the biggest change, it's really just in doing the controlled flowback of both the gas and the water. And so, that probably is irrespective of number of stages or number of volumes of sand or of water. It's more trying to keep the gas in solution, maintain a particular flowing barrel per hour type of a rate and kind of all coming into that pressure-dependent perm and keeping the gas in solution. So, that number, I think, is going to be pretty solid going forward even as we tweak other operational things in that five-month range.

[Dan E. McSpirit:]

Okay. Very helpful. And then, lastly here, just kind of revisit the subject of field level returns in the current price environment. What is the economic limit or breakeven in the UOP versus what you're drilling in the DJ Basin, that is, what is the NYMEX WTI price that covers your hurdle rate?

[R. Scot Woodall:]

It's significantly higher. So I don't know – I don't have that sitting in front of me, Dan, but I would guess it's in that $70 to $80 type of a range.

[Dan E. McSpirit:]

Okay.

[R. Scot Woodall:]

And that kind of is an average across the entire Uinta Basin. East Bluebell numbers would be something lower. South Altamont might be something lower. Blacktail Ridge might be something higher. But as an aggregate across the whole 160,000 acres, maybe something like that.

[Dan E. McSpirit:]

Got it. Thank you. Have a great day.

[R. Scot Woodall:]

Thanks.

[Operator:]

Our next question is from Josh Silverstein from Deutsche Bank. Your line is open.

[Josh I. Silverstein:]

Hey. Good morning, guys. Just a follow-up question, I guess, to one a few ago. Now that you guys have a better understanding of the production profile here in that it takes kind of five months to seven months to peak production, can you just talk about the pad development going forward? Needing to balance CapEx and cash flow, are these maybe going to be smaller four-well pads or are you thinking you can get better efficiencies off of the bigger 10-well pads?

[R. Scot Woodall:]

Right now, what we've been drilling most recently is 4-well pads, but we may go ahead and do like an entire section. So if you think about the – if there's like eight wells, maybe if we're only targeting the Niobrara B, we would do two 4-well pads and drill those with two rigs. And so that way, you're accelerating the cash flow a little bit. And then similarly, there's times that we can bring in two frac fleets and do that. So you are accelerating the cash flow, you're still doing the flowback period of the five months, but it kind of moves that cash flow forward. So when you think about if we have a section that had B and C potential and you're doing something like 16 wells, we might split that into four 4-well pads and do it with the two drilling rigs and the two frac fleets and manage things that way. So we are trying to accelerate the cash flow, but still maintain our discipline on how we flow these things back because, clearly, we think it's impacting our production declines.

[Josh I. Silverstein:]

Got it. That's helpful. And then as you move into the 2016 program with the XRLs, any thoughts of whether there would be a difference in performance in wells kind of North, East, South or to the West in terms of whether the declines would be any different or flow-back would be different?

[R. Scot Woodall:]

I don't think it would be any different. We primarily have been drilling the Western portion of both the North and the South, and the 2016 program is very similar to that. We're very methodically stepping out. We aren't jumping out into whole new areas really because of our infrastructure, and we're being very methodical about how we lay out the infrastructure and how we pick location. So, we haven't observed any difference yet.

[Josh I. Silverstein:]

Great. Thanks, guys.

[Operator:]

Thank you. Our next question comes from Mo Dahhane from Northland Capital. Your line is open.

[Mostafa Dahhane:]

Yeah. Good morning, guys. Appreciate you guys providing us with the 30-day IP rates and 60-day, as well as the 90-day for the extended reach lateral wells. I'm just curious if you guys can provide us with oil cut for those averages?

[R. Scot Woodall:]

The oil cut is just short of 70%. So, we run about like a 69% oil cut in our model.

[Mostafa Dahhane:]

And it's pretty much flat throughout the 90-day?

[R. Scot Woodall:]

Yes.

[Mostafa Dahhane:]

Okay. Appreciate that. And just quickly, do you guys have any plans to drill an extended reach lateral into the Codell formation maybe sometime early 2016 or what are your thoughts on that?

[R. Scot Woodall:]

Don't know quite yet. I haven't seen the drilling schedule and plan from our technical teams yet to know if we've got Codell slated for 2016 or not.

[Mostafa Dahhane:]

All right. Appreciate it. Thank you.

[Operator:]

Thank you. At this time I'd like to turn the call back over to management for any closing remarks.

[Larry C. Busnardo:]

Okay. We'd like to thank everyone for joining us again today. Please feel free to contact us if you have any questions and we look forward to updating you on future quarters. Thank you.

[Operator:]

Ladies and gentlemen, thank you for participating in today's conference. This does conclude the program and you now may disconnect. Everyone, have a great day.