Cimarex Energy Co.
Q2 2013 Earnings Call Transcript

Published: 7 Aug 2013

[Operator:]

Good day, and welcome to the Cimarex Energy Second Quarter 2013 Earnings Conference Call. [Operator Instructions] Please note, this event is being recorded. I would now like to turn the conference over to Mr. Mark Burford, Vice President, Capital Markets. Please go ahead, sir.

[Mark Burford:]

Thank you very much, Denise, and thank you, everyone, for joining us today for our second quarter conference call. On the call today here in Denver, we have Tom Jorden, President, CEO; Joe Albi, EVP and COO; and John Lambuth, Vice President, Exploration. We did issue our financial and operating results this morning. A copy of our news release can be found on our website. And I need to remind everyone that today's discussion will contain forward-looking statements. A number of factors could cause actual results to differ materially from what we discussed. And you should read our disclosures on forward-looking statements in our latest 10-K, other filings and news releases for risks associated with our business. So we had a good quarter this quarter and a lot of details to cover, so I'll just go ahead and turn the call over to Tom.

[Thomas E. Jorden:]

Thank you, Mark. Welcome, everyone. We appreciate your interest in Cimarex. I'd like to take a few minutes to go over the highlights of the quarter before turning the call over to Joe and John for a more detailed look at our operations. We had a solid second quarter. Production averaged 687 million cubic feet equivalent per day, slightly ahead of our expectations. This represents growth of 16% over second quarter 2012. Our oil production increased an even greater 29%, averaging 36,878 barrels per day this quarter. Capital expenditures totaled $390 million, funded principally from our $322 million in cash flow from operating activities, $44 million in proceeds from asset sales and $22 million in bank debt. We still expect to invest about $1.5 billion in 2013 on high rate of return projects, primarily in the Delaware Basin portion of the Permian Basin and on the Cana-Woodford Shale. Our Permian program continues to provide great returns, and that's where we'll invest $950 million or about 63% of our capital this year. Our results have been particularly positive in the Horizontal Wolfcamp. In our Culberson County focus area, we signed a joint development agreement with Chevron, which greatly enhances the future development plan for this significant resource. We've also had encouraging results in the Wolfcamp and Reeves County, where 2 new wells had first 30-day production rates averaging 925 barrel of oil equivalent per day. It's -- ultimately, it's about execution and making sure that each of our major programs is performing. And how do we define performance? After-tax rate of return, maximizing net present value and building a portfolio that exposes Cimarex to profitable long-term growth. Ultimately, the long-term becomes a series of quarterly results, and results are what we like to talk about. There's been a lot of buzz this week around the Delaware Basin-Wolfcamp play. On this call, you'll hear about some of our excellent recent results in this trend in some detail. As we studied our results and studied those of our competitors, we've reassessed and enlarged our estimate of the potential this play holds for Cimarex. John will discuss these results and opportunities in more detail later in the call. We remain focused on ways to improve our returns in each of our areas. We've made wonderful strides in our drilling cost and drilling days, and we have opportunities to optimize, experiment and improve our completions. We also continue to generate new ideas with good long-term growth potential. We have an active leasing program underway in the Permian Basin and elsewhere, a leasing program that's grounded in our discipline of full-cycle return on invested capital. Cimarex is having a good year, we had a good second quarter, and we're looking forward to discussing it in detail on this call. Now I'll turn the call over to our Chief Operating Officer, Joe Albi.

[Joseph R. Albi:]

Thank you, Tom, and thank you, all of you, for joining our call today. I'll touch on our second quarter production, update you on our third quarter guidance projections, and then follow up with a few words on our operating and service costs. As Tom mentioned, we had a good strong second quarter, with reported net equivalent daily volumes coming in at 686.7 million equivalent cubic feet per day, that's above the midpoint of our guidance of 667 million and -- to 692 million and up 16% over last year. When adjusting for our 2012 year-end property sale, we were up 19% as compared to 2012. We achieved this production growth despite seeing about 9 million to 10 million a day of downtime during the quarter, that being associated with ethane rejection in various plant and facility shut-ins, primarily in Permian and in Cana. If you look deeper into the numbers, our second quarter Mid-Continent volume came in at 343.2 million cubic feet equivalent per day, up 14% or 43 million a day from Q2 '12. The increase was driven by Cana, which grew 38% year-over-year to 216.1 million a day during Q2 '13. That said, due primarily to ethane rejection and a lull in our second quarter Cana completion activity, our second quarter Mid-Continent production fell 5% from Q1 '13, where we reported a level of 360.6 million a day. With both our operated and non-operated Cana completion activity picking up steam again here during the second half of the year, we're projecting our Cana volumes to see an upward trend starting here -- later in Q3 and extending into Q4. In the Permian, our second quarter net equivalent volume of 319.6 million a day was up 29% or 72 million a day from a year ago. Our growth in the Permian has been driven all by oil. With Q2 Permian oil production averaging 30,137 barrels a day, that's up 8,113 barrels a day or 39% from last year. As compared to the first quarter of '13, our Permian net equivalent volume was up 44 million a day or 16%, while our net Permian oil volume was up an incremental 4,305 barrels a day, which exceeded Q1 by 17%. Jumping to guidance. Despite reducing our Q3 '13 projected volumes by approximately 12 million to 15 million a day for ethane rejection, the midpoint for our full year 2013 production range remains unchanged from our previous guidance of 690 million a day. Our tightened full year guidance range of 680 million to 700 million a day reflects a 9% to 12% increase over 2012, which when we adjust for property sales, equates to a healthy 11% to 14% year-over-year production growth. With ethane rejection built into our Q3 guidance, our forecasted Q3 NGL volumes have been reduced by about 2,500 barrels a day. That said, the projected drop in NGLs is being offset by higher forecasted oil production from the Permian. Our year-to-date Permian drilling results continued to exceed our original program projections. And as a result, we've revised our total company projected year-over-year increase in oil production, now twice during the year. From 1% to 5% at the beginning of the year to 13% in our last quarter call, and now to a respectable 13% to 16% increase over 2012. Shifting gears to OpEx. Our second quarter lifting cost came in at $1.11 per Mcfe, that's down $0.06 from our first quarter cost of $1.17 per Mcfe. During the quarter, our production team did a very nice job of keeping our total LOE in check. With that, however, we continue to see cost pressure in certain areas such as compression, power and fuel rework and maintenance, particularly, in light of our 2013 emphasis on stepping up our well reviews and lease inspections in order to optimize our production from, and the appearance of, our wells. With Q2 coming in at $1.11, our first half 2013 lifting cost comes in at $1.13 per Mcfe, and as such, we've made no change to our previous full year guidance range of $1.10 to $1.22 and see ourselves as having a good chance of coming in on the low end of that range by the end of the year. On the service cost side, with regard to drilling costs, we continue to see most cost compliments remain relatively in check. Day rates have held flat during the quarter. Although we are seeing signs of the softening market, with rig availability and offered well-to-well contracts, versus the term contracts, we saw, let's say, a year ago. In the Permian, although a high demand for tools and equipment can sometimes create a challenge, we've been able to procure that equipment, those services, all the while seeing our costs continue to remain flat. Through operating efficiencies, as Tom mentioned, we've made some good strides in our drilling program, and it's reflected itself in our drilling cost, especially in the Permian, where we've made slight modifications to program design and implemented more aggressive use of bit technology and downhole tools, which has really allowed us to reduce our drilling days. On the completion cost side, we've seen signs of market softening in the Permian, particularly, in the Delaware now, with more available horsepower and competition amongst the service providers. And as a result, our second quarter average, overall, per well Permian frac cost is down about 20% from Q1. The bottom line of all this is continued improvement in our Permian total well cost. Depending on debt, our current New Mexico 2nd Bone Spring AFEs are running $6.1 million to $6.7 million, that's down about $200,000 from last quarter. Our shallower Texas 2nd Bone Spring AFEs are running about $5.3 million to $5.5 million, that's down $200,000 to $400,000 from the numbers we quoted last call. And our Culberson-Wolfcamp wells are running flat to last quarter at $7 million to $7.5 million total well cost. That's down $1 million from where it was a year ago. And our West Texas 3rd Bone Spring AFEs, also held flat from Q1 at $6.4 million to $6.6 million. Again, that's down considerably from late last year. In Cana, our program drilling has kept our total well cost in check. They're running about $6.8 million, $6.9 million, that's down about a $0.5 million from last year. The bottom line is we've made good strides to get our well costs down. And along the way, we've set some milestones we're proud of in our active programs, which we believe are competing well with our peers. So in a nutshell, Tom talks about results. I mentioned 3 of them in our call here today. Our production continues to grow. It's a positive result. We've trimmed our lifting costs down during Q2, likewise, and have made some tremendous strides in controlling and reducing our drilling and completion cost. All of these are certainly pointing in what we believe to be the right direction. With that, I'll turn the call over to John Lambuth, our Vice President of Exploration.

[John A. Lambuth:]

Thanks, Joe. I'll cover some of the specifics of our Permian and Cana drilling programs. We had an active first half of 2013. We've completed 179 gross, 95 net wells this year, investing $800 million in exploration and development capital. 65% of our capital was invested in the Permian basin, while 33% with the Mid-Continent region. We still expect our total annual exploration development capital to be approximately $1.5 billion for 2013. As planned, our capital investment has been front-end loaded this year. In the second half of the year, our Cana capital will be down slightly as a result of going from 4 to 2 rigs. Also in Culberson County, our capital will be lower in the second half as a result of the joint development agreement we signed with Chevron. I'm going to first start with our Mid-Continent region. This year, we've drilled and completed 87 gross, 35 net Mid-Continent wells, essentially, all of which were in the Cana-Woodford shale play. In Cana, we've drilled and completed 74 gross, 31 net wells, most of which have been operated by our partners. We currently have 2 operated rigs working in Cana. Including non-operated activity, we're on track to drill and complete slightly more than 50 net wells this year. Our Cana capital is projected to be just over $350 million for this year, of which, about approximately $250 million would be attributable to the nonoperating part for the program. Our returns in Cana for this year are tracking about where we expected in the mid to low 20% after-tax internal rate of return. I'm going to move on now to the Permian Basin. Permian Basin is our most active area. We've drilled and completed 90 gross, 59 net Permian basin wells this year. Most of our drilling has been focused on the Bone Spring and Wolfcamp formations in the Delaware Basin. We've had a very active New Mexico Bone Spring program, where we've drilled and completed 42 gross, 23 net wells. This program continues to deliver very strong results for us. Our per-well first 30-day gross production from these wells averaged approximately 650 barrels of oil equivalent per day, of which, 85% was oil. In our Ward County, Texas 3rd Bone Spring program, we drilled 21 gross, 15 net wells, with a per-well first 30-day average gross production rate of approximately 965 barrels of oil equivalent per day. These wells were 80% oil of that production. This program also continues to deliver great results for us. I'm going to now move on over to our Culberson County, Texas focus area. As Tom mentioned, Culberson County and our adjoining acreage in Southern Eddy County, New Mexico has become a key area for us. We continue to drill Wolfcamp C and D, as well as 2nd Bone Spring wells here in this area. We also still see additional upside in the Wolfcamp Bay, as well as the shallower Delaware Sand interval. Year-to-date, we've drilled 9 gross, 6 net Bone Spring wells, which have had a per-well first 30-day average gross production of 850 barrels of oil equivalent per day and were 58% oil. We currently have 2 rigs drilling 2nd Bone Spring wells in this area. Depths are less than 8,000 feet, and we're able to drill these wells in about 20 days. Well costs are now around $5.3 million to $5.5 million. These wells, with that type of well cost, generate great returns, as good as any of our Bone Spring drilling program throughout the Delaware Basin. Moving onto the Wolfcamp. We've drilled 8 gross, 6 net horizontal Wolfcamp wells in Culberson County in 2013. This brings total wells in the area to 39 gross, 35 net, per-well first 30-day production rates on all of the Wolfcamp wells drilled to date in this area have averaged 6.2 million cubic feet equivalent per day comprised of 43% gas, 27% oil and 30% NGL, assuming full NGL recovery. At the end of the second quarter, we signed a joint development agreement with Chevron. This agreement will enable us to be more efficient in our field development, as well as enable us to start drilling long laterals. In fact, regarding long laterals, earlier this year, we drilled a 7,500-foot extended lateral, which achieved the first 30-day IP rate of 8.7 million cubic feet equivalent per day. We have about 5 months of production history on this well, and we expect about a 50% after-tax rate of return based on the results we see. Because of this well, as well as now having that Chevron JDA in place, we are now planning a 10,000-foot lateral we'll be drilling in the third quarter of this year. We also continue to plan a Wolfcamp D downspacing pilot, which now looks like it will probably begin in the first quarter of 2014. Moving on the Reeves County, Texas. We drilled and completed 2 Wolfcamp Bay wells. The first 30-day production rates were 983 barrels of oil equivalent per day and 865 barrels of oil equivalent per day. This production is comprised of 63% oil, 20% NGL and 17% gas. These are really good wells with 30-day averages of 600 barrels of oil per day plus another few hundred barrels equivalent of NGLs and gas. We have also now drilled a 2-mile lateral in Reeves County, which we recently finished frac-ing, and we're currently in the process of flowing back. Our plan is to drill an additional 5 Wolfcamp wells in Reeves County over the remainder of this year. So wrapping it up, we're having a great year. Our team, as always, are focused on maximizing returns on our drilling, and they are doing a great job. As we stand now, we see at least 200 to 300 remaining Bone Spring Sand locations in Texas and New Mexico, with further upside for the Avalon in New Mexico. As for the Wolfcamp, we have a very strong land position. If you look at the Wolfcamp trend going from our Southern Eddy County Culberson area, and then move over into Reeves and further into Ward County, we have over 170,000 net acres under lease. Quite frankly, that number could actually even be bigger just based on some of the more recent results that we're seeing from other companies. Narrowing into our Culberson and Southern Eddy County area, which accounts for around 100,000 net acres of the 170,000 that I mentioned, we have significant future potential there. Depending on spacing and whether we require multiple stack laterals, there could be several thousand locations just in this area. And then moving back in the Reeves County, where we have over 40,000 acres, we've seen some very encouraging results from our first 2 wells we've drilled, and thus, there could be ultimately hundreds of locations located just in this area as well. In summary, we have a huge amount of future drilling locations in the Permian Basin, not to mention the thousands of wells we still have to drill yet in the Cana area as well. Now with that, I'll turn the call back to the operator for Q&A.

[Operator:]

[Operator Instructions] The first question will come from Phil Jungwirth of BMO Capital Markets.

[Phillip Jungwirth:]

The oil cut in the 2 Reeves County wells was a little bit higher than what I think a lot of us expected, given some of the industry results to date. What would you attribute that to? And then do you expect to see much variability in the GOR across your 40,000 acres?

[John A. Lambuth:]

Well, let's keep in mind, it is only 2 wells, and they are fairly close to each other geographically. Whereas there's a wide distribution of wells that never reported [ph] over a broad area. So I think it's safe to say that as we drill more wells, there will certainly be variability in that GOR. I don't know that we really have it dialed down yet, that we understand it just yet. But again, I think, what you're seeing is some of the variability over a broad geographic area, so far.

[Phillip Jungwirth:]

And then on your Ward-Winkler County area acreage, where you've historically targeted the 3rd Bone Spring, we've had some industry results also targeting the Wolfcamp last week. Do you have rights to the Wolfcamp? And if so, do you have any plan to test that later this year or next year?

[Thomas E. Jorden:]

Yes, this is Tom. The answer is, we have fairly significant exposure to the Wolfcamp in that area. As John said, we've revised our acreage numbers upward to our exposure in that trend. And a lot of that revision is based on some of those recent industry results. So the answer is yes, we do have exposure, and we do have plans to test and develop it.

[Operator:]

The next question will come from Brian Gamble of Simmons & Company.

[Brian D. Gamble:]

Just wanted to actually just stay on that first topic for a second. The Reeves wells, you mentioned 5 more this year, these first 2 being pretty close together. Is there going to be more geographic variability from the remaining 5? Or are they all going to be pretty close together this year, and then spread out as we go forward?

[Thomas E. Jorden:]

Yes, Brian, this is Tom. One of the interesting things that we really like about the Permian Basin is it's not a basin where you have to create every new data point. You have a lot of competition helping you out. And there's been a lot of results that have been announced by our competitors out there. And if you take our acreage position and you plot all the other results that have been announced, it really does help define our position. The oil cut is encouragingly high for much of Reeves County. The GOR changes, a fair amount, as you go across from east to west, but based on our other industry competitors, we're going to be testing a fair amount of our geography. But we feel pretty confident that now, if we just talk about Reeves County, our acreage is in several different pockets, but we have a fairly concentrated acreage position in Reeves County, we're currently up over 40,000 net acres, we're adding to it. We're in the process of developing takeaway solutions. And that's worked its underway there. But we're planning on -- we see most of that acreage -- in fact, I'll say most, if not all, of that acreage, is pretty well delineated by our drilling and that of our competitors. Now we'd prefer to be talking about our own results and not those of our competitors, but we're pretty encouraged by how that points to our acreage.

[Brian D. Gamble:]

That's great. And then the oil growth, obviously, great for the quarter, seeing it bump up a couple of times this year already, obviously, is good as well. What sort of expectations for the back half of the year baked into the new guidance. Are you expecting continued improvement, because it seems like it's difficult not to continue to improve that. Is that 13% to 16% a conservative number on your viewpoint? Or does it give you room for -- or the need to continue to grow that -- to hit that number for the year, as far as what you're seeing on results?

[Mark Burford:]

This is Mark Burford. We have been undershooting what we expected or hope growth will be for the year. Pretty consistently, we continue to try to retune that up and make it more fine. We're not trying to sandbag our numbers, but we do expect continued good growth in the Permian in the second half of the year, and, hence, good consistent growth in oil as part of that -- being a big part of that program. So I mean, I don't think the 4,000 barrels a day we grew from the first to second will trail in the second half. That was a pretty normally high growth rate first or second. But we should see a good continual growth in order for us to hit that new upward band of our 13% kind of growth -- 13%, 16% gross for oil. So we should see good growth second half of the year, Brian.

[Operator:]

Our next question will come from Joe Magner of Macquarie Capital.

[Joseph Patrick Magner:]

I just wondered if you might be able to dive into some of the results that you're seeing out of the Culberson County-Wolfcamp C and D. It looks like the -- at least some the statistics you've provided in the release have moved around a little bit over the last couple of quarters. I'm just curious if you can maybe discuss some of the relative performance between those 2 different zones?

[John A. Lambuth:]

This is John. I think what you're seeing is we keep showing the averages, and of course, as we drill additional wells, those averages change. I think also what you're seeing is both on those averages, whether we're in C or D, but also just geographic, we are still stepping out in some ways in part of Culberson. And sometimes the step outs are very good, and sometimes they're not as good, and that does affect the average overall performance there. In terms of just C and D itself, we definitely see a higher yield, a higher NGL content in the C relative to the D. But I would also say that we're still kind of early. We don't have as many D wells as we do C, and we're still trying to just get a better handle on what that ultimate production will be like in the D and -- I mean, excuse me, in the C. We're far more comfortable with the D wells, because that's where the majority of our wells have been so far. It still looks good. It's just -- we still need a few more wells online to get a better feel for how good the C will be relative to the D.

[Thomas E. Jorden:]

Joe, this is Tom. If I could just add to what John said. We've talked in the past about the C being higher yield but lower absolute rates because of that yield. So some of that is an overprint of a mixture of C and D results. We're still seeing very good returns out of both those benches. One of the things, I talked to my opening remarks about completion optimization. And we're really just at the advent of a lot of opportunity in this trend. Our wells have still been essentially for garden variety 5,000 foot lateral, we're pumping 12 stages. And we need to -- we do have plans to experiment with more stages. And I think that we yet, couldn't pound the table on any bench as to what we think it's ultimate potential's going to be. It's a very fixed section. There's tremendous resource in place, and we have a lot of work yet to do. I'm sure somebody is going to ask us about the Wolfcamp A in Culberson County. We still don't have our well down and completed yet, so it's drilling now. And that's another very seminal test for us in defining the potential of the area. So very encouraging results, but we yet are still calibrating the ultimate potential of this area.

[Joseph Patrick Magner:]

Good. I guess with my one follow up. Any plans, I guess, what are the latest plans of timing on when you might drill a stacked C and D lateral, like those and other testing initiatives that you had talked about pursuing?

[John A. Lambuth:]

Yes, this is John. The stacked C and D lateral is scheduled to be drilled in the fourth quarter of this year. We have a location picked, and we are moving forward with that. And so that will be drilled in the fourth quarter with completion flowback. We really won't be able to say much about that until probably second quarter next year, but we are moving ahead with that for sure.

[Operator:]

Our next question will come from Matt Portillo with Tudor, Pickering, Holt.

[Matthew Portillo:]

Just a few quick questions for me. In terms of the 7,500-foot lateral, could you give us an idea of the well cost there? And then, over time, how you guys think about the well cost in the Wolfcamp in terms of the potential to move those costs down as you get more towards the development program?

[John A. Lambuth:]

This is John. I don't have the actual well cost right in front of me. But by memory, we were right around in the 8.5 range for that well. We were very pleased with that well as far as the drilling of it. We can get back to you for sure with the actual cost, just to make sure I'm close on that. But it drilled very well, it completed well, we were very pleased with the results of that well. And now, again, with that Chevron agreement in place, we now have the freedom, so to speak, to now go and push it to 10,000-foot, which is essentially the beauty of that agreement, enabling us to combine those adjacent sections in that way. So that's what we're moving forward to. Again, we're very, very pleased with results of that well. And we think going to 10,000, we think we can get even better type results. Because once we get in that lateral, the drilling goes very fast. So it doesn't add that much more in the way of days to go another 2,500 feet. So we're pretty excited about the potential for that well.

[Joseph R. Albi:]

This is Joe. I'll just make a quick comment on that. The majority of the cost increase we anticipate to see, as John mentioned, we're making tremendous time in the laterals using rotary steerable tools. And so what it really comes down to, it's a completion. And there are stages that are associated with the the longer lateral like that.

[Matthew Portillo:]

Great. And as we compare the Delaware Basin drilling program to maybe what we're seeing from offset operators in the Midland Basin, do you think ultimately that the longer laterals in higher stage completions will be utilized on the wells you're drilling today. And in terms of the wells we've seen to date, I just wanted to make sure I clarified that, those wells have been drilled on 5,000 foot laterals with 12 stages, is that correct?

[John A. Lambuth:]

Yes, this is John. That is correct. As Tom alluded to, up until now, we've kind of stuck with the same type of completion program. In some ways, that makes sense because we're trying to derisk that area. But quite frankly now, we're at a point now where we're looking to maximize returns with every well we drill. So the things that we will be testing in the near future are as just Tom alluded to, on a 5,000-foot lateral, we'll certainly go to more stages, 20 stages, if not slightly more. Likewise, when we then scale up to a longer lateral, a 10,000-foot lateral, then there's a good chance again that we'll be scaling up in the stages in that as well. The 7,500-foot lateral would have essentially had the same equivalent stage with -- as with a 5,000. So we really didn't change that design as much as all we did is added additional stages for that length. So there's definitely some additional upside here with the improvement in our frac design in this program.

[Thomas E. Jorden:]

Again, we hope to be able to discuss particular results in future calls. We're flowing our 10,000-foot lateral in Reeves County back now. We'll have 10,000-foot lateral in Culberson County. But based on our existing 7,500-foot lateral, as John said, we think we see this as having the potential, which is our current completion design, to be north of 15% after-tax rate of return. And so we see a lot of upside on that number. So yes, we're very optimistic. We're forging ahead as fast as we can. But this sure looks does like it's working and working well.

[Matthew Portillo:]

And just my last question on the back of that. In terms of your capital program as we look out over the next few years, from a philosophical perspective, if you start to generate these high rates of return with potentially very repeatable asset base here, how do you think about capital outspend over the next few years in terms of accelerating the Permian? Has your view changed at all in terms of the way that you're willing to flex your balance sheet?

[Thomas E. Jorden:]

Yes, this is Tom. I'll take it from the back -- you asked question first. Our view hasn't changed at all. We are very willing to invest capital if we can do it with a good rate of return and making sure that with reasonable commodity downside protection, we don't destroy capital. And so we run our commodity downside, as well as $60 oil, and we look at flat $3 gas, flat forever on both commodities, less local D there [ph]. If we can get a good return on capital, we're very confident that, that's indeed the case, we will accelerate. And so we're looking at just that case in the Permian now. And with the opportunities that we have in front of us, with the balance sheet we have available to us, I would say accelerating this program in future years is not off the table for us, it's under act of consideration.

[Operator:]

Our next question will come from Drew Venker of Morgan Stanley.

[Andrew Venker:]

I was hoping you can talk about the potential for other Wolfcamp zones in your Reeves and Ward County acreage, below, I guess, what the Wolfcamp Bay you've tested so far?

[John A. Lambuth:]

Yes, this is John. As we mentioned, our first 2 wells were A tests. And even the long lateral we drilled has been an A test. That said, we are aware of a couple of competitor wells that had been located in the deeper C, D interval. And indeed, we have -- I'm aware of at least one test coming up, but we'll be testing that interval on our acreage. So yes, we recognize it as an opportunity, and we will be testing it with the well here coming up soon.

[Andrew Venker:]

Okay. And on the Ward County acreage, do you have any concerns that there may be depletion in the Wolfcamp over there due to your fairly extensive 3rd Bone Spring drilling?

[John A. Lambuth:]

This is John. I'll start with that question. I'll just simply say, as we look at it, the Wolfcamp is a pretty thick interval. And we see that there is quite a bit of vertical separation that we can achieve, where we can put a lateral and separate ourself from that third 3rd Bone lateral that we feel comfortable, at least going forward, in testing that. I'll put it that way. But there is an uncertainty there, I won't deny that.

[Andrew Venker:]

Okay. So do you see Wolfcamp B, C, D on that Ward County acreage as well?

[John A. Lambuth:]

Yes -- I can't -- I just -- I'll just say that we see Wolfcamp intervals. I'm not as familiar with that right now. I mean, we see its perspective. I'll put it that.

[Thomas E. Jorden:]

This is Tom. I just want to caution -- this is a blocking- and tackling-type project. It's very difficult to wave your arms at this type of expanse and make simple rules. The Wolfcamp B that works very well in Culberson County, there are places in Reeves County, where it'll produce too much water to be economically perspective. So we're -- what we've talked about today, with the acreage potential, the well potential, we are absolutely confident on that. Now could it be better? You bet. But we're just not going to look at that section and say, "Hey, let's do acreage math and run with it." It's too complex. That's the way --- we look at it as very detailed. And we'd certainly encourage everybody to understand. It's very dangerous to wave your arms around this type of real estate.

[Operator:]

The next question will come from Jason Smith of Bank of America Merrill Lynch.

[Jason Smith:]

Just following up on Reeves. Can you just remind us what your drilling requirements are to hold acreage there, maybe over the next 12 months? And then also, as you and other producers in the area start to ramp up production, can you give us an update as to where infrastructure stands today as well?

[John A. Lambuth:]

This is John. I'll take the first part of the question. In regards to Reeves and holding our acreage, we have about -- well, we need to spend about $170 million drilling program next year. And with that program, we'll be in good shape to hold all of our acreage in that area. And that's, obviously, very doable for us. As far as the marketing, I'll hand it to Joe.

[Joseph R. Albi:]

Yes, this is Joe. We have, right now, currently an infrastructure in place that we feel can accommodate the short-term going schedule. And we are currently, also, working with purchasers and processors in the area to attain more firm capacity to deliver gas for processing. As far as salt water disposal goes, we're aggressively looking at the drill schedule, and what we need to do to get ahead of that from a SWD perspective.

[Jason Smith:]

Got you. And I know you guys took the acreage up in the last few months from 35,000 to 40,000. Are you still seeing opportunities to add there?

[John A. Lambuth:]

This is John. Yes, the answer is yes. We are still actively pursuing additional acreage. Obviously, with all these competitors and their release, it gets -- it's getting a little bit tougher, but absolutely. We are still aggressively trying to pursue more acreage.

[Operator:]

The next question will come from Gil Yang of DISCERN.

[Gilbert K. Yang:]

To follow on Jason's question there. How much is acreage costing that you're adding in that area?

[Thomas E. Jorden:]

Gil, this is Tom. We're just not prepared to talk about what we're paying for acreage. I would say to our competitors, it's way too expensive, and you probably don't want to afford it.

[Gilbert K. Yang:]

Fair enough. And could you characterize it? Is it filling in chunks of holes within the acreage blocks you have? Or is it also trying to expand the overall footprint?

[Thomas E. Jorden:]

Again, Gil, we're in a competitive situation. And I'm just going to pass on that. We have an active acreage acquisition program this year, and we're building. So if you'll just indulge me to be that vague.

[Gilbert K. Yang:]

Fair enough, Tom. I may have missed it, but how much are your -- those Reeves County well costing?

[Joseph R. Albi:]

Well, they should be a little bit more expensive. They're a little bit -- this is Joe. they're a little bit deeper, so I'd probably tack on another $500,000 to $750,000 to our regular Wolfcamp.

[John A. Lambuth:]

This is John. I guess, I have more recent information, because we're just looking at decisions the other day on this wells. And that particular AFE was around $7.3 million. It is what I recall for our latest Reeves County-Wolfcamp well.

[Gilbert K. Yang:]

That was a -- was that a 10,000 foot lateral or?

[John A. Lambuth:]

No, no that was not. And, in fact, I should just go and stand corrected now. On our 7,500-foot lateral in Culberson, our actual costs were, actually, more in the $10 million range, not $8.5 million. And I want to stand corrected on that. So around $10 million, $10.5 million is what we spent there.

[Thomas E. Jorden:]

But those return on capital numbers were fully [indiscernible].

[John A. Lambuth:]

No, no those -- no, absolutely. The return on capital is definitely against that actual well cost. I want to be clear about that.

[Gilbert K. Yang:]

Okay. All right, so $7.3 million for the Reeves 5,000-foot lateral and $10 million for the 7,500-foot Culberson lateral?

[John A. Lambuth:]

Yes.

[Thomas E. Jorden:]

That's our actual. That's not -- we're getting better. So that -- we're just quoting our actual and we're -- our landscape of improving results.

[Gilbert K. Yang:]

And then just last question. You mentioned early on that the completion cost, I think, are coming down. Is that because of additions to pumping capacity in the area? Or is it -- that other operators are beginning to slow their activity down or changing the mix of what they're doing?

[Joseph R. Albi:]

This is Joe. I'll answer that. It's really due to, I think, what I'd call a competition moving over from the Midland Basin into the Delaware Basin. The majority of our cost decrease have come on both the service side and the material side. And, really, a result of just having more competition and available horsepower in the Delaware.

[Thomas E. Jorden:]

But you know, Gil, I want -- I think about completion cost a little differently. I think about drilling cost. There's no argument on why you wouldn't want your drilling cost to be as cheap as it can be, given that you're having a good clean, safe operation. Completions are a little different, because as we optimize, we've talked about going from 12 to 20 stages on a type -- 5,000-foot lateral. We may elect to spend more in our completions if we think that those are generating superior returns. So I wouldn't necessarily look to see our completion cost uniformly come down. That's a decision we'll make based on optimizing the performance.

[Operator:]

[Operator Instructions] The next question will come from Ray Deacon of Brean Capital.

[Raymond J. Deacon:]

I was wondering if you could talk about expectations for the oil NGL split for the remainder of the year? It seems like you're a good bit higher than your guidance that you gave out at the beginning of the year and just wondering what the second half would look like?

[Mark Burford:]

Do you want to do that?

[Thomas E. Jorden:]

The other one [ph]...

[Mark Burford:]

Yes, Ray. So yes, our first -- our oil component has been going up. That's right. The growth is being faster in oil. But our split is about 50 -- our split last year was up 31% oil, 8% NGL, 53% gas. And we should be up slightly. This quarter, we are closer to what -- we are at 30% -- excuse me, actually, I'm finding my split in front of me here. But our percent of oil should go up by 1% or 2% through the range of the year, and with the -- 50% gas, 32% oil, 18% NGLs. The percent of oil might tick up 1-or-so percent rate for the second half of the year for the full year.

[Joseph R. Albi:]

This is Joe. The only thing I'd add to that is, in our modeling, we've assumed ethane rejection for Q3, but don't know anything about Q4 enough to feel comfortable making an estimate there. So to the effect ethane rejection occurs in Q4, that could skew some of those numbers.

[Operator:]

The next question will come from Cameron Horwitz of U.S. Capital Advisors.

[Cameron Horwitz:]

I guess a question for John. John, can you just -- can you do a little comparison on Wolfcamp A, seeing Culberson versus what you saw on Reeves. I mean, it seems like operators are seeing better productivity and potentially some higher oil yields moving up in the zone, in the Wolfcamp in Reeves County. And was there -- do you think that'll be analogous to what happens in Culbertson?

[John A. Lambuth:]

Well, this is John. I sure hope so. As Tom stated, we're drilling that well right now. And yes, I mean, if I would to state what our expectations is, I think that's what we'd hope to see. All I can say is, just as we look at it from our logs and from the subsurface, we like to look at the A in Culberson. But I don't have a well producing there to tell you whether it's good or not. That's why we're doing it. And so, hopefully, we'll have results here by -- at some point that we can talk about, and be very proud of. But that's where we are right now. We're drilling the well, and that's what we're hoping that the results will be.

[Cameron Horwitz:]

Okay. I appreciate it. And Reeves County, and I know it's still early there, but I think one of those wells, you'll probably have a little bit more extended production history on. Can you just talk a little bit about how you think that curve is going to shakeout? I mean, is it similar to what you see in Culberson?

[John A. Lambuth:]

I would say, like for any of the shale wells, so far, they have a decline profile that, that's not unexpected. I mean, that they are declining about how we'd expect them to. Again, a lot of these shale wells are really somewhat dependent upon those early 30-day IP rates. That's really a telltale sign of how good a well you have. And as you can tell, we have some pretty good 30-day rates, so we're very pleased with those wells so far. And so far, based on the production, we like it enough that we're going to commit to the amount of capital I talked about next year, the $170 million, to hold it. It's looking good so far.

[Thomas E. Jorden:]

Yes, and I just want to underscore, we only talk about 30-day rates. I know a lot of people are out there talking about peak rates, 24-hour IP, our experience is the only rate that's really meaningful in evaluating the quality of well is that 30-day average. And we've got very, very solid, very good 30-day averages.

[John A. Lambuth:]

I would concur. Yes.

[Operator:]

And ladies and gentlemen, that will conclude our question-and-answer session. I would like to turn the conference back over to Mark Burford for any closing remarks.

[Mark Burford:]

Thank you very much for joining us today. Appreciate the interest and look forward to continue reporting our results to you in the coming quarters. And I hope to see you at conferences coming up, here in Denver, next week, EnerCom and then further into the fall. But thanks, everyone, for your interest, and I look forward to seeing you soon. Take care. Bye.

[Operator:]

Ladies and gentlemen, the conference has now concluded. We thank you for your participation. You may now disconnect your lines.