Cimarex Energy Co.
Q1 2015 Earnings Call Transcript

Published: 5 May 2015

[Operator:]

Hello, and welcome to the Cimarex Energy First Quarter Earnings Conference Call. All participants will be in listen-only mode. After today's presentation, there will be an opportunity to ask questions. Please note, this event is being recorded. Now, I'd like to turn the conference over to Karen Acierno; Ms. Acierno, please go ahead.

[Karen Acierno:]

Good morning and welcome to the Cimarex first quarter 2015 conference call. Last night, we updated – we posted an updated presentation on our website. We'll be referring to this presentation during our call today if you'd like to take a look at it. And as a reminder, our discussions will contain forward-looking statements. A number of actions could cause actual results to differ materially from what we discuss. You should read our disclosures on forward-looking statements in our latest 10-K and other filings and news releases for the risk factors associated with our business. So today's prepared remarks will begin with an overview from our CEO, Tom Jorden, followed by an update on our drilling results and activities from John Lambuth, VP of Exploration; and finally Joe Albi, our COO, will update you on our operations including production and well costs. Paul Korus and Mark Burford are also here in the room to help answer any questions. So with that, I'll turn it over to Tom.

[Thomas E. Jorden:]

Thank you, Karen, and thanks to everyone who's participating in today's conference. We appreciate your interest in Cimarex. I'd like to take a few minutes to share my thoughts on the current environment before turning it over to John and Joe for the details of our first quarter results and our plans for the rest of 2015. During this call, you'll hear about new wells that are outperforming our expectations, which has led to our Q1 production beat. We have several new long laterals in the Delaware Basin that are in the Wolfcamp on line and they've reaffirmed our enthusiasm for the long-term potential of this play for Cimarex. Our improved well performance is primarily driven by ongoing well optimization, but is also driven by certain changes in our horizontal landing zone. You'll also hear some of the results from our second Bone Spring oil play in our Eddy County, White City acreage. These wells are among the best in our portfolio with multi-year running room. We've always been a company that emphasizes the science and that emphasis is yielding results in spacing pilots, well design, completion design and unraveling geologic complexity. We will also update you on our continued success in the Cana-Woodford shale and the emerging Meramec plays. Oil prices have recovered modestly since our last call, but are still at a level that we view as unsustainable. Natural gas prices remain depressed. Our projected 2015 cash flow outlook is similar to what it was at our last quarter call in February. Owing to our commitments to be fiscally disciplined, our 2015 capital expansions remain at the $900 million to $1.1 billion that we've previously announced. We have seen service costs decrease 15% below Q4 levels and we look forward to further service cost reductions. For now, we intend to leave within cash flow and not incur additional debt during the remainder of 2015. We view debt as a long-term commitment and we're hesitant to make long-term commitments in this volatile environment. Our focus has been on asset quality. As we have high graded our activity, we have continually scrubbed our project returns to ensure that we're investing wisely and not destroying capital in this depressed commodity environment. The robustness of the returns in our portfolio has surprised us to the upside. We've a deep inventory of projects that make great sense in today's environment and when the time is right for acceleration, we're ready to roll. The quality of our inventory is a testament to technology, innovation, and great geo-science that have become hallmarks of Cimarex. There's also a splash of luck in there too; our assets are in great basins with tremendous multi-pay geologic targets. Finally, as always, our focus is on creating shareholder value. These depressed commodity prices make our task more difficult. (04

[Operator:]

Pardon me. This is the operator. Please continue to hold the line. We are attempting to reestablish connection. Again, please continue to hold the line. (04

[Operator:]

This is the operator. Once again, please continue to hold the line. The speakers will reconnect shortly. Thank you. (07

[Operator:]

Pardon me. This is the operator; I have reconnected to speaker's location.

[Thomas E. Jorden:]

I thank you for your patience. Apparently our emphasis on technology does not include telephone technology, but I'm not sure where we got cut off; but I was just saying that oil prices have recovered modestly and we're so committed to the $900 million to $1.1 billion that we previously announced for 2015 CapEx. And also, I think I it was fading when I was telling you that we've seen service costs come down 15% since the fourth quarter and we're expecting further service cost reductions but we intend to remain within cash flow for the remainder of 2015, and that's based on our core hesitation to incur addition debt in this volatile environment. Our focus has been on asset quality, and as we've managed through this price correction, we've continually scrubbed our returns and looked to make sure that we are funding the very best projects and that we are not destroying capital. And as we've done that, the robustness in quality of our well level returns have surprised us to the upside. We've got a great inventory of projects. We have lots to do in current environment, and when the time is right for us to accelerate, we'll be ready and we got lots teed up. And as I was saying, the quality of this inventory is really a testament to our organization, our emphasis on technology and innovation, and great geoscience; and it's nice to have a little luck as well. Our assets are in great basins; they're multi-pay basins that really allow us to leverage technology and play against our core strengths. And finally, as always, our focus is on creating shareholder value. These depressed commodity prices make our task more difficult while but are uncompromising on our focus on shareholder value. We have the organization and the assets to emerge from this down-cycle stronger than ever. With that, I'll turn the call over to John Lambuth who'll provide additional detail.

[John Lambuth:]

Thanks, Tom. I'll start with a quick recap of our drilling activity in the quarter before getting into some of the specifics about some of our latest results. Cimarex invested $308 million during the first quarter drilling and completing wells. 67% of that investment was in the Permian region with the rest going toward activities in Mid-Continent region. Companywide, we brought 53 gross, 33 net wells on production during the quarter. Our Permian operations are in the Delaware Basin where we completed 30 of those 33 net wells during the first quarter. We focused on completing our backlog of Avalon wells and Wolfcamp long laterals. We also began production on several new second Bone Spring wells located in our White City area. We continue to have exceptional results drilling second Bone Spring wells in this area since incorporating larger frac jobs into our completion design. We've gone from 9 stages to 15 stages in order to achieve these results. We now have 15 wells with 30-day peak averages of 1,344 barrels of oil equivalent per day. Oil represents 68% of the production stream on a three stream basis with the 15 wells averaging just over 900 barrels per day for 30 days. As of today, we have identified approximately 100 second Bone Spring locations on our White City acreage with the vast majority being located on acreage which is held by production. Our long lateral program in the Wolfcamp D in Culberson County continues to provide solid results. Eleven long lateral wells are now producing and seven wells now have enough data to provide an updated average 30-day peak IP of 2,378 barrels of oil equivalent per day. As I said on our last call, we continue to work on optimizing our frac design to both maximize IP rates while paying close attention to costs. In fact, we've recently brought on a number of Wolfcamp wells with various frac designs in order to determine the best design for our next spacing pilot. Based on these recent well results, we have chosen a stimulation design which places the same amount of sand per well as the previous pilot had, but we accomplished this with fewer stages. As for this pilot, which we just recently began to fracture stimulate, we are testing the equivalent of six wells per section with the wells spaced 880 feet apart. A diagram of this pilot can be found on slide 15 in our new corporate presentation. The new pilot was drilled directly south of our first Culberson down-spacing pilot, thus enabling us to be able to review well results without worrying about geologic variation. Also in the Delaware Basin, I'd like to give you an update on the status of our stack staggered Wolfcamp A pilot in Reeves County. This pilot was designed to test the down-spacing and the viability of landing more than one lateral in the fifth Wolfcamp A section. After delays caused by the September flooding, these wells began producing in early December. I'll refer you to slide 18 in our presentation for a diagram of the pilot. The wells landed in the upper part of the Wolfcamp A produced at higher rates than the lower wells, achieving a peak 30-day average of 1,068 barrels of oil equivalent per day, of which 59% was oil. The wells in the Lower A had a peak 30-day average rate of 761 barrels of oil equivalent per day, 56 barrels of that being oil. Slide 19 shows the production of the upper and lower wells for the first four months. We had a very difficult time placing sand in the wells landed in the lower A, which we attribute to a poor choice of landing zone, which led to a higher amount of carbonate instead of shale in the lateral. We have reviewed the landing zone in question and are confident with a small landing zone adjustment we can achieve much better results in future wells landed in the lower part of the A. In 2015, our Wolfcamp capital will continue to be focused on drilling additional long lateral wells in Culberson County as well as meeting our leasehold obligations in Reeves County, which we expect can be fulfilled by spudding eight wells in 2015 at a cost of $70 million. Now on to the Mid-Continent; we brought three net wells on production in Mid-Continent region in the first quarter. The rest of the wells drilled are awaiting completion. You may recall that we began drilling on the Cana-Woodford Row 4 infill development program late last year. We and our partner are nearly finished with the drilling on this row and expect to begin completions around mid-summer. To help ensure we use the most effective fracture stimulation on Row 4 wells, we recently completed and are currently flowing back eight wells in the Haley section. We varied our completions on these wells with changes in total sand pump ranging from 9 million pounds to 12 million pounds or, same way of saying it, 1,800 pounds per foot to 2,400 pounds per foot, as well as varying stage count from 24 to up to 30. We will monitor these well results and then choose the appropriate frac design for Row 4 wells. In our emerging Meramec play, we now have enough production data on seven 5,000 foot laterals to give you an average 30-day peak IP rate of 10 million cubic feet equivalent per day. The seventh well, the Peoples 1-29H, had an average 30-day peak IP of 9.8 million cubic feet equivalent per day or 1,628 barrels of oil equivalent per day. This well has a very high oil yield averaging 788 barrels of oil per day. We will watch the performance of all the wells drilled to date as we continue to delineate our position, refine our geologic model, and further enhance our frac design. We currently have two Meramec wells flowing back with a third being completed right now. We have also recently commenced drilling the first of several 10,000 foot laterals in the Meramec. Results from the long laterals shouldn't be expected before our third quarter call in November. Cimarex has approximately 115,000 acres prospective for the Meramec, 70,000 of which have been de-risked by our and competitor drilling activity. From a capital standpoint, current plans are to invest $70 million in Meramec drilling in 2015. Once we have finished Row 4 drilling, one of the rigs that is currently working the Mid-Continent will be redeployed to the Permian Basin, bringing our rig count to three in each region. With that, I'll turn the call over to Joe Albi.

[Joseph R. Albi:]

Thank you, John. And thank you all of you for joining our call today and especially for bearing with us during our little phone technicality there; and hopefully things are working well and it sounds like they are at least with the phone, for the call. I'll touch on the usual items, our first quarter production, update you on our second quarter and full year production outlook, and then I'll follow up with a few words on operating and service costs. We had another great quarter for production. Despite expected shut-ins of approximately $30 million a day for January weather and February pipeline and facility maintenance in the Permian, our first quarter net equivalent daily production came in at 947 MMcfe a day; that was virtually flat to our record company production level that we posted last quarter. We were up 28% from a year ago and we beat our guidance of 920 MMcfe to 940 MMcfe a day, so a strong quarter from that perspective. Really guided by our strong 2014 exit rate; and with that, our Q1 2015 total company reported volume was up 206 MMcfe a day from a year ago with our Permian equivalent production up $141 million a day or 41% from Q1 2014. And our Mid-Continent production up 73 MMcfe a day or 20% from last year, both statistics reflecting our strong activity levels in each of those areas over the last year. As we mentioned last call with our – with the – excuse me, the geographic focus of our drilling program and the shifting of rigs as we moved into the year, we forecasted our early 2015 production growth to come primarily from the Permian and we saw just that in Q1. Despite freezing and pipeline maintenance issues, our first quarter Permian equivalent volume of 488 MMcfe a day was up 42 MMcfe a day or 9% from fourth quarter. Oil production drove the increase with our Q4 Permian oil volume of 43,089 barrels a day – excuse me, our Q1 Permian oil volume of 43,089 barrels a day up 13% or 4,843 barrels a day over Q4. With that, the Permian now makes up 52% of our total company equivalent production and 84% of the net oil we produce as a company. As we mentioned during our last call, that with fewer net Mid-Continent completions planned for the first half of the year, we projected our Mid-Continent volumes to drop somewhat through mid Q3 of this year. Our Q1 Mid-Continent production came in accordingly at 444 MMcfe a day, down slightly from the 488 MMcfe a day that we posted in Q4, yet still up 20% from the 371 MMcfe a day that we posted a year ago. Nothing has changed at our modeling, where we project our Mid-Continent production to pick up in the second half this year as we bring on our Cana infill (20

[Operator:]

Yes. Thank you. We will now begin the question-and-answer session. And the first question comes from Andrew Venker with Morgan Stanley.

[Thomas E. Jorden:]

Good morning, Drew.

[Drew E. Venker:]

Hi, Tom. I just want to start with the Culberson density pilot; just curious aside from the spacing, are you doing anything different on the completions versus that first density pilot?

[John Lambuth:]

Yeah, Drew. This is John Lambuth. As I mentioned for this particular pilot, which as I said directly located south of the first pilot we did, we are changing the frac design some based on some recent well results. We're not changing total amount of sand. We're still at around 6 million pounds over the length of a 5,000 foot lateral. But we're going to do it with fewer stages; instead of 20, we're going to do it with 16 and then what we're also doing is adding more clusters within each stage. We have a few wells that recently came on with this type of design and although we don't have a lot of production on those wells just yet, the early time data we see from those particular wells is encouraging and that's why we're making this particular change for this pilot.

[Drew E. Venker:]

And is that a cost savings measure, a capital efficiency measure, or do you really think that well design just gives you the best performance?

[John Lambuth:]

Yeah. Clearly, it was a decision of best performance. That said, because we're going to less stages, there will be some amount of cost savings because we haven't quantified that just yet.

[Joseph R. Albi:]

This is Joe. I'll elaborate. We've seen significant reductions in our service cost per stage, upwards of 30%, 40% per stage just over the last three months as a result of not only the market itself, but our efficiencies in pumping the jobs. So really, all those cost components are intermixed in us changing these designs, but overall we anticipate that to be down slow – somewhat from our prior jobs.

[Drew E. Venker:]

Okay, thanks. And then, just as far as the completion design and the landing zones overall for Culberson, can you talk about how that's evolved and how much room you think there is for improvement from here? Have you played around with, I guess, the landing zone a fair amount, and where do you think you're on the completions?

[John Lambuth:]

Well, on the landing zone front – I'll take that first. This is John again. We have a lot of wells drilled now that we've tried many different landing zones and so I think we're getting a good sense of where its best to land a well in terms of both achieving the best EUR, being able to actually place all our sand and even getting a very high drill rate through the rock. All those things come together to leading to the most economic wells. I think we're very comfortable now saying the Wolfcamp D as to where we want to be there, and I think we're definitely getting there on the Wolfcamp A from Culberson as well. As far as the completion design, I don't know we'll ever probably reach the optimal design. Obviously, year and year-and-a-half ago, we had a major step change when we went from 10 stages to 20 stages and we are very pleased with that outcome. In the case of Culberson Wolfcamp, we actually took it even further, going to 30 stages and we did not really get our bang for the buck doing that. And that's when we start to ask ourselves, well maybe we want a little too far on stage count and those are the things that we've been testing, as I said. These latest wells where we backed off on the stage count, but still were able to place the equivalent amount of sand just doing it with less stages but more clusters. Again, as I said, early time data is encouraging to us, but I am sure we'll find ways to even adjust that as we go along with our future wells.

[Thomas E. Jorden:]

Yeah, this is Tom. I just want to comment on that. Having the two basins really makes us better, and you've heard us talk about that. We get a technology arbitrage from basin-to-basin from time-to-time. And although in 2014, we hit a major step change in our Cana-Woodford completions, we're kind of undergoing another one right now. We're trying some things in Cana that are leading to significantly better results and we are discussing what implications that may have on the Permian. So I think that this advancement in completion and well performance is still well underway and it would be, I think, foolish for us to say that we've got the right recipe in the Permian, because we're learning some things in Cana that causes us to rethink some core assumptions.

[Drew E. Venker:]

That's helpful color, Tom. Just one last one; Tom, you mentioned in your prepared remarks that you would be ready to accelerate when the time is right. Can you give us any color on if there's specific criteria there that you're looking for, or is it just kind of a different feeling of the environment?

[Thomas E. Jorden:]

Well, a lot of it is feeling and that's the hardest to get specific on. I will say I think we'd like to see what happens at the OPEC meeting in June, and at least get some kind of a directional confirmation of oil prices. It's been nice to see oil prices firm up a little bit over the last couple of weeks; we'd like to see that trend continue. And every increase is a big positive to our cash flow and our outlook. So, we've said in the past that our current capital program is a snapshot in time and we'll be reevaluating that here, I think, come midsummer and make our best determination. We are absolutely getting ready to accelerate, if indeed it's prudent.

[Drew E. Venker:]

Thanks for the color, Tom.

[Operator:]

Thank you. And the next question comes from Brian Gamble with Simmons & Company.

[Brian David Gamble:]

I'll take a stab at the other county that you have the spacing pilots down for; maybe you could walk us through the Reeves County issues with the lowers, just – what was different on the landing zone? I'm assuming you landed in a similar spot to the parent well, but how much variability do we think that is there and just other lessons learned that may not have been part of the prepared remarks?

[John Lambuth:]

Yeah, this is John Lambuth. I think what it just shows is there is a quite bit of variability in terms of the Wolfcamp in regards to these inter-bedded carbonates that we encounter from time to time. And indeed, that's what occurred with those lower wells on this particular pilot. What we didn't do, which we would do now is if we do encounter that, we will be more aggressive in our directional planes to get out of that and get back into shale, and that's something now we do do with the wells we're currently drilling. And then furthermore, we will pay more careful attention to the local well control to make sure we avoid those particular zones. That's really what it comes down to is just ensuring that you place most of that lateral in good shale because we've seen now when we do that, we're able to get our sand, our frac jobs off, and we get the best wells. And so that's really the main lesson we learned from that particular pilot on those lower wells.

[Brian David Gamble:]

And when are we going back into the lower with another similar spacing pilot? Is that something that's ongoing?

[John Lambuth:]

We don't have a current spacing pilot right now lined out for Reeves. We're still looking at this one as well as our previously mentioned 80-acre Spacing Pilot and monitoring those results very carefully over time. Secondly, really, what we're doing now is doing more long laterals in Reeves. We have a quite a number of 10,000 foot laterals that are coming on now. And it's really the combination of these two different spacing pilot results along with long laterals that will help us better line out what does development look like for that particular area; so that's kind of where we're at right now.

[Brian David Gamble:]

Great. And then one bigger picture question. Tom, on the M&A market, maybe give us an update on any sort of changes in bid/ask spread as oil prices have increased, appetite for different deals, things that maybe you've seen come across your desk. Any update there would be helpful.

[Thomas E. Jorden:]

Yeah. This is Tom. We really haven't seen a lot of assets recently, but I think our viewpoint is probably what's out there in the writings that there's still, I think – what did I see, a quote from CERAWeek, whistling past the graveyard; they said that our industry is whistling past the graveyard. If we get into a lower longer environment, we're expecting that bid/ask spread to collapse a little, but we have not seen it yet.

[Brian David Gamble:]

I appreciate it, guys.

[Operator:]

Thank you. And the next question comes from Jason Smith of Bank of America.

[Jason Smith:]

Hey. Good morning, everyone.

[Thomas E. Jorden:]

Good morning, Jason.

[John Lambuth:]

Hi, Jason.

[Jason Smith:]

Hey, Tom, so to follow up on the earlier acceleration question, the returns on your Culberson long laterals per your slides were, I think, about 100% at current commodity prices. So when you think about moving up from six rigs, where does the potential for hedging fit in?

[Thomas E. Jorden:]

Well, boy, I wasn't expecting this.

[Jason Smith:]

Well, I am wondering if you're something to protect your downside versus, if your trends are that good then...

[Thomas E. Jorden:]

It's a good question. I want to say first off, when we talk about our returns, they're well level returns; they're not fully burdened, I want to be clear on that. Although fully burdened, they still look very, very good. And then when you have a program, things go wrong and you have opportunity for over expenditures. So I wouldn't want to represent that our entire inventory anywhere in our program is 100% after-tax rate of return. We do have a fair amount of that, but we have a mixture of a return landscape. But your core question is on hedging; we're discussing a different hedging approach at Cimarex. I think one of the things that philosophically appeals to us is some kind of a program hedging where we would take volumes periodically and just commit to hedge them without making a determination whether price is high or low; layer them in and kind of have a feather over time of a hedge book. But the tough question is, all right, when you're going to start that. And I think we're kind of reluctant to layer in a lot of hedges at these price environments. We were at a dinner recently where an individual we really respect made the comment at the heels of a big discussion on hedging, he just kind of quieted the room when he said if Cimarex were to hedge today at $60 oil and prices were to recover to $90, there'd be a riot. And, you know, we maintain that balance sheet. We're fully equipped to ride through the down cycles and participate fully in the uptick. So, yeah, we're arguing about it, but I wouldn't be waiting with bated breath for some new approach.

[Jason Smith:]

Got it. Okay. So then that the three rigs I think, Joe, you mentioned that the third rig is going to move back to Permian, could you just talk about where those are going to concentrate? Is it going to be all Culberson? And I guess what I'm curious about is you guys completed 16 wells in the Avalon; you said some of that was running through backlog, but obviously one of your peers this morning had some pretty positive results out of that place. So can you maybe just talk about what you're seeing there and how that fits into the portfolio going forward?

[John Lambuth:]

This is John. In regard to the rigs in the Permian, the three rigs for the rest of the year, they will almost primarily be Wolfcamp wells, either in Culberson or Reeves. A lot of that is to ensure we hold our acreage; some of it is delineation as well, but that's primarily what they will be doing for the remainder of the year. In regards to the Avalon, we did, in fact, bring on beginning of the year around 18 gross Avalon wells. Those wells were really spread across four different sections and they were essentially spacing pilot wells. We were testing both spacing and turns of 80 acres and 107 acres or the equivalent of eight or six wells a section. We also in one section stack and staggered and on another one, we even varied frac. So there's a lot going on there. All of those wells are flowing back now and really we need a little bit more time to review those results and I feel pretty confident by probably next earnings release, we'll be able to give you a good update on the result of that – of those wells in the Avalon at that time.

[Jason Smith:]

Thank you. And just one last quick one from me, I know you guys aren't focusing there this year, but just your thoughts on the Ward County acreage and how that kind of fits in the portfolio. And maybe you can talk with any acreage exploration issues in 2015 and 2016 there that would cause you to have to drill.

[John Lambuth:]

Yeah. In regards to Ward County, it is a struggle. Ward County has not been a good rate of return area for us at Wolfcamp so far. And we still talk about it and we still monitor not just our own but competitor wells to make sure we fully understand that asset. We don't have any major explorations, but they really start coming in pretty big next year in 2016. We're currently looking at that acreage and asking ourselves, is there anything left that we haven't tested on it to see that we can try, but so far, within our portfolio of Wolfcamp opportunities, the Ward County is much lower prospective than the other two.

[Thomas E. Jorden:]

Yeah. This is Tom. One of the things we've seen in Reeves County, and I think we have a little bit of work to do in Culberson County, is so much subtle changes in landing zone are having a fairly significant impact on well performance. And we did a fair amount of (39

[Jason Smith:]

Appreciate the answers. Thanks, guys.

[Operator:]

Thank you. And the next question comes from Dan Guffey at Stifel.

[Daniel D. Guffey:]

Good morning, guys. You gave rates on your four 7,500 foot Wolfcamp A laterals and Culberson, and I'm curious if you can kind of walk through – I know they're more oil rich, but they come in – come on at lower rates. I guess, can you walk through and compare the economics versus the D? And then on top of that, how many locations have you identified and are 10,000 foot laterals feasible, across your acreage?

[John Lambuth:]

Yeah. This is John Lambuth. I'll take a stab at that. The Wolfcamp A wells and Culberson are definitely higher yield, higher condensate, but they do come in at a little bit lower rate and that's simply because you're a little bit less pressure than you are in the D. But that said, those lower rates are more to make up for because of the amount of oil we do make; but right now, just as I speak on a comparative basis, the Wolfcamp A laterals to us look just as good economically as do the Ds. The first few A wells are 7,500 and that's just a matter of the way that acreage laid there in Culberson. We share that JVA with Chevron, and we just have an odd number section so at some point, not all of them could be 10,000 foot laterals so in this case, those basket of wells were 7,500. The remaining of our acreage, we fully anticipate to be 10,000 foot for A, and in fact, I think we have one of our first ones coming on here right now. So the lateral length, it's just because of the acreage itself not because we don't think we can't do 10,000 in the A and that would be our plans going forward for the A.

[Daniel D. Guffey:]

Okay. And then, on locations and how much of your acreage you think is prospective across Culberson and then does the A thin, I guess, as you move across your acreage to the north and to the west?

[John Lambuth:]

As far as the A is concerned, it does begin to thin as we go toward the west and a little bit to the north. But to be honest, we haven't really determined how thin is still good. We haven't pushed that edge yet so it's hard for me to say, how much of the acreage is good for A or not. Those are some of the things we'll have to do here in the coming – with the drilling program is to test that boundary. We don't know the answer to that. I mean, clearly, we started in an area where we had a very good thickness in the A; but again, to be honest, and it's kind of nice, there are other competitors drilling wells nearby us, testing some of these thinner intervals of the A that will go a long way to helping us to determine just how prospective is our entire acreage there in Culberson. But I don't really have an answer for you today, but stay tuned; over time, we'll be able to give more clarity as we get more wells on line.

[Daniel D. Guffey:]

Okay. Great. And then just two follow-ups kind of defining acreage in the Avalon, just piggybacking on the last question; previously, you guys have talked about 200 plus locations. You guys are obviously doing down spacing test among the others that you listed. I guess what is your identified inventory in the Avalon at this time and I guess what base assumptions are you using to back that up?

[John Lambuth:]

Yeah. This is John. I think in today's commodity price and cost environment, we see around 186 gross, 5,000-foot laterals and that's, I believe, based on six wells per section. So that could change dramatically based on the spacing pilot results. But that's just how we see it today, but that number is always changing. That's just as of today, that's how we see it.

[Daniel D. Guffey:]

Okay. Great. And then switching gears over the Meramac, you guys have talked about 70,000 net acres you feel is de-risked and 115,000 net acres total. You guys have provided a map and you guys have mapped that geologically with significant well control across your acreage. I'm wondering how much do you feel is kind of in the up-dip – up-dip kind of normalized pressure versus the down dip over pressured regime?

[John Lambuth:]

This is John. I don't remember the numbers off the top of my head. Clearly, we have a good representation of acreage both in the up-dip as well as the down-dip, but I don't recall the break – breakout of their – off the top of my head. We could probably follow-up with you on that to give you that breakdown; I just don't have it with me.

[Daniel D. Guffey:]

Okay. Yeah. That'd be great. Thanks for all the color today, guys.

[Operator:]

Thank you. And the next question comes from Jeffrey Campbell with Tuohy Investment Research.

[Jeffrey L. Campbell:]

Good morning.

[Thomas E. Jorden:]

Good morning.

[John Lambuth:]

Good morning.

[Jeffrey L. Campbell:]

I appreciate the color you just gave a few minutes ago on the Wolfcamp A and Culberson. Just kind of like to extend the idea a little bit and ask, is the prospectivity of the Wolfcamp D and the Wolfcamp A similar across – I'm looking at slide 11, across the Culberson acreage or are there different parts to the acreage that are discretely prospective for each zone?

[John Lambuth:]

Give me a minute while I get to slide 11. The Wolfcamp D is prospective over all of our acreage there in terms of thickness. The Wolfcamp D is much thicker. I think the only issue we have there is, of course, like in the Delaware Basin, as we go from east to west, you begin to lose your yield as you go to the west. And it just becomes a matter of economics at that point as to how far west you can go. We don't really – we haven't really defined it as of yet. But the D is a much thicker interval across the breadth of our acreage than what the A exhibits, thus, more prospectivity.

[Thomas E. Jorden:]

This is Tom. The nice thing about this Culberson block, when we're talking about economic limits, is we have a wide open playing field for long laterals. In fact, 10,000 foot laterals, I think, will be the standard out here and that gives us tremendous range of economic liability. And that's going to be true on the A and the D. And then I also do want to discount the C. We've talked about the C not competing with D and the A. But when we go to full development, I would anticipate that the C will be developed alongside of it.

[John Lambuth:]

I'll follow-up with Tom's comment. That's especially true when we look at the C on a 10,000 foot lateral basis; then it becomes more economically viable for us. And it starts to make sense that in a full development mode, while you're there you'd want to capture that interval while you're doing the D as well. And that's something we'll clearly need to be testing once we get further along and actually into development mode whenever that occurs here.

[Thomas E. Jorden:]

And this speaks back to our opening remarks on asset quality. When we look at our Culberson block, and that Eddy block – Eddy County block to the north of it, there you have also great Wolfcamp prospectivity and then our central Reeves acreage, all of it is nicely blocked out. So the opportunity for longer horizontal wells is pretty deep in our inventory and that allows us a lot of robustness.

[Jeffrey L. Campbell:]

And it sounds like from what you just laid out that there's certainly going to be some potential for maybe A, C and D in some locations when you're full bed development.

[John Lambuth:]

That is especially true on the eastern side of our block. And then as we move to the west we'll just – we'll have to take a wait and see based on well results. But certainly, the eastern side of Culberson definitely aligns itself up to that and with further drilling, we'll see how far we can push that full three stacked opportunity.

[Thomas E. Jorden:]

Although we don't have results to discuss, there's also a push for a second D landing zone. So it's too premature to even hint that we may have two zones in D, but we're testing it.

[Jeffrey L. Campbell:]

Look forward to some color on that one, when it comes out. On slide 22, you showed, by my count, six locations in the Meramec, so it looks like maybe the seventh one hadn't shown up on that slide yet. I was just wondering was the seventh completion an updip or down-dip well?

[John Lambuth:]

No. This is John. I believe there are seven stars; just got to look up to the north, west or up.

[Jeffrey L. Campbell:]

Oh, there it is; yeah, so which one was the seventh?

[John Lambuth:]

That was the seventh.

[Jeffrey L. Campbell:]

Okay. So you've also tested a little bit further away from kind of the area where you've been drilling.

[John Lambuth:]

Yes. That was a delineation up there. Yes.

[Jeffrey L. Campbell:]

Okay. Great. And then as a final question, I just wanted to go back to the lower A landing zone subject in Reeves County. I just wanted to make sure that I understood it correctly. Is it – based on the need to move the landing zone, does this affect the amount of acreage that you thought – previously thought was prospective for the lower landing zone? In other words, is this an adjustment that you can make in your – within your existing vision and prospectivity or does it change anything?

[John Lambuth:]

It really doesn't change any prospectivity as far as acreage. It just means we have to be a little more careful when we drill those laterals and pay a little more careful attention to what we are in. To us, like I said, it's literally a very small adjustment to lateral zone and then very careful attention to why we are drilling that lateral, if we do encounter a carbonate to quickly adjust and get out of it. And no, we don't see that as a hindrance at all going forward. It's just a lesson learned. A tough lesson learned, but we've learned our lesson there in regards to how we will drill those wells going forward.

[Jeffrey L. Campbell:]

Okay, great, thanks. I appreciate it. Good quarter.

[Operator:]

Thank you. And the next question comes from Michael Hall with Heikkinnen Energy Advisors.

[Michael Anthony Hall:]

Thanks, good morning.

[Thomas E. Jorden:]

Hi, Michael.

[Michael Anthony Hall:]

I guess maybe one on the Mid-Con first. Just curious around what sort of discussions have you had, what's the thought process behind any additional row development with your partner in the Cana-Woodford as we think about formulating a 2016 plan.

[John Lambuth:]

This is John. We have lots of discussions with our partner and there are two rows currently being discussed as future development. Potentially, even to the point we began drilling on at least one of those rows later this year. So there's still funny to do here and both us and our partner are very pleased with returns we're seeing from our development, which is leading toward the discussion I just mentioned about a couple more rows of development that potentially may begin later this year and go into next year. As we firm up those plans, then certainly we'll let you know probably by next quarter's call, we'll see. But discussions are underway about more development in the Woodford.

[Michael Anthony Hall:]

Okay. And I guess maybe just high level then, thinking about just the capital cycle 2015 and 2016, is it fair to say then that 2016 might be a similar look to 2015 as it relates to Permian outperforming in the first half and the Mid-Con coming in in the second half in a stronger way? Is that...

[Thomas E. Jorden:]

Yeah, this is Tom. It's really premature to get that granular with 2016. We're still wrestling with what 2015 is going to look like. So we've got lots to do, but how we stage it and what that will look like, it's way premature for that.

[Michael Anthony Hall:]

Okay. That's fair. And then I guess jumping over to the Permian, can you give a little more color around the thought process on the six well spacing versus the tighter spacing on the prior pilings in Culberson and what you're hoping to learn outside of the varying completion designs from a spacing perspective?

[John Lambuth:]

This is John. I'll take a stab at that. I think we all recognize that when we do go to development mode on the – in Culberson, that's a very critical step for us; lot of capital and we want to make sure we do it right. And so we knew all along that one pilot would not be sufficient to answer that question. And we kind of knew all along that we would have to do a couple pilots where we varied the spacing, in essence so we can bookend results in terms of what does six wells looks like per section versus eight. Please understand it, us going to six wells a section with this particular pilot in no way infers that that's what we think our spacing would be. It just helps us with those results and our previous pilot really hone in on what is the right spacing from a standpoint of both rate of return and PV. And that's why we are doing that, it is to kind of create those bookend results and then review that, and then make an informed decision on how to go about and develop that acreage. So that's the thought process.

[Michael Anthony Hall:]

That's super helpful color. Thanks. And then just in the Permian program in 2015, how much of the program is on full two-mile laterals at this stage for rest of the year?

[John Lambuth:]

This is John. All of Culberson is either 7,500 feet or 10,000 feet in regards to Wolfcamp; and in regards to Reeves, I would say the majority of the wells are 10,000 foot. There are some that are 5,000 foot just simply because we don't have the acreage to do 10,000 foot, but we're at that point even in Reeves that if the acreage allows us, then we're drilling 10,000 foot.

[Thomas E. Jorden:]

The one exception, the pilot we've discussed is 5,000 foot. We choose to do – to the extent we're doing science and it's an experiment, we like to go with a more cheaper well.

[Michael Anthony Hall:]

Yeah. Thanks. And then last one on my end, in that Reeves pilot, the mix shifted a little bit over the course of the 90 days in the lower A. Is there anything to read into there or is that, again, somewhat a function of the carbonates encountered during drilling?

[John Lambuth:]

I don't know there's a lot to read into that. Obviously, over time, these wells tend to – our GOR does go up as we produce these wells, so I think you're seeing a little bit of that there. But in the course of four months, I don't know you can read too much into those numbers just yet.

[Michael Anthony Hall:]

Okay.

[Thomas E. Jorden:]

Yeah, this is Tom. You know, when we forecast these wells, we forecast the declining oil yields and that's built into our economics and we have raging debates internally as to whether we've got that forecasted correctly. I think there's some organizations would think we're a little conservative in our forecast, but we just need to have a few more years of production history.

[Michael Anthony Hall:]

Fair enough. I appreciate the color. Thanks.

[Operator:]

Thank you. And the next question comes from Ipsit Mohanty with GMP Securities.

[Ipsit Mohanty:]

Good morning, guys. Most of my questions are answered, but if I could just – I couldn't stop but notice your impressive results in the Second Bone Spring in White City. But if I understand correctly, you're probably not going to do much on it for the rest of the year. Is that a component of HBP there and no need to go back there?

[Thomas E. Jorden:]

Well, yes. It is held by production, and our need to go back there is our need to generate top tier returns and it's about the best in our portfolio. I will say this, as I've said repeatedly, our current plan is a snapshot in time and if we were to accelerate activity, I think you'd find that to be a strong contender for increased activity. We're ready to go there and those wells are phenomenal.

[Ipsit Mohanty:]

Got you. And as you think about the second half of the year, sort of more held up by Cana – Cana's program, what's the extent of longer laterals – the longer laterals that you're going to drill there? What's the percentage of other wells that you're going to drill on long laterals?

[John Lambuth:]

Yeah, this is John. Clearly, Tom talked about this, how we leverage off each region. And clearly, based on our experience now in Culberson, we've gotten extremely comfortable as a company in terms of drilling and completing long laterals. So we haven't – but done but one of those 10,000 foot laterals in Woodford so far, although we have a few 7,500. But without a doubt, we have areas now where we have a large acreage position that we operate and control where we envision long laterals being our go-to method for developing that acreage. We're not there yet, we still talk internally about it; but we do make plans that eventually we will be developing with 10,000 foot laterals in the Woodford. Because again, we've gained great confidence in our ability to do that based on our experience in the Permian.

[Thomas E. Jorden:]

And then to follow-up on John's comment, I want to just remind our listeners, at our Meramec program, the wells we've announced, are all 5,000 foot long horizontal wells and you will be comparing those with competitor wells that are largely 10,000 foot long horizontal wells. We've – are just in the process of our first 10,000 foot long Meramec well and we're very, very interested to see what that will generate.

[Ipsit Mohanty:]

Yeah, that's great color. But would you be drilling any longer lateral Woodford wells in the second half?

[Joseph R. Albi:]

As of today, we don't have any definitive plans, but plans can change. I mean we are talking about, quite frankly, maybe one or two where we further delineate our acreage with 10,000 foot laterals, but nothing has been approved just yet.

[Ipsit Mohanty:]

Great. The rest all sounds good. Thank you.

[Operator:]

Thank you. And the next question comes from Paul Grigel with Macquarie. Paul Grigel - Macquarie Capital (USA), Inc. Hi, good morning.

[Thomas E. Jorden:]

Good morning. Paul Grigel - Macquarie Capital (USA), Inc. Your previous production guidance that assumed CapEx at the low end of the range. How should we view the latest production guidance relative to CapEx and how much flexibility is built into production and CapEx?

[Joseph R. Albi:]

Yeah. This is Joe. We've done the same this go-round as we did last. So what we've really done is just incorporate the first quarter well results that we've had and our projected timing and anticipated volumes for the remaining part of the year with the same budget. Paul Grigel - Macquarie Capital (USA), Inc. Okay.

[Thomas E. Jorden:]

It's the low end of the range.

[Joseph R. Albi:]

It's the low end of the range.

[Thomas E. Jorden:]

Yeah. And we've – although we're always updating our projection based on our latest well results. Some of the improvements we've made, we're modeling in in our projection, but we're testing a lot of things, and we don't have any future improvements modeled in. We're modeling current CapEx and current well performance. Paul Grigel - Macquarie Capital (USA), Inc. Okay. So just to be clear there, there's no acceleration or anything assumed; it's just the current program of six rigs running forward for the rest of the year and that's the production.

[Thomas E. Jorden:]

That's correct. Low end of our range and 900 MMcfe is our guidance.

[Joseph R. Albi:]

And as we talked about last call, because our (01

[Joseph R. Albi:]

Ironically enough, our Q4% gas was running around 49% and we'll end up there this year, at around 49%. We'll have some – a little bit of a dip in there in Q3 as we transfer out of the Permian into the – into Cana. Paul Grigel - Macquarie Capital (USA), Inc. Okay. That's all for me. Thank you guys.

[Operator:]

Thank you. And as there are no more questions at the present time, I would like to turn the call back over to management for any closing comments.

[Karen Acierno:]

Thank you, Keith. So I guess we'd just like to thank everybody for participating in the call and please let us know if you have any further questions. Thanks very much.

[Operator:]

Thank you. The conference is now concluded. Thank you for attending today's presentation. You may now disconnect.