Seeking Alpha
We cover over 5K calls/quarter
Profile| Send Message|
( followers)

Cimarex Energy (NYSE:XEC)

Q2 2014 Earnings Call

August 06, 2014 1:00 pm ET

Executives

Mark Burford - Director of Capital Markets

Thomas E. Jorden - Chairman, Chief Executive Officer and President

John A. Lambuth - Vice President of Exploration

Joseph R. Albi - Chief Operating Officer, Executive Vice President and Director

Karen Acierno - Director of Investor Relations

Analysts

Brian D. Gamble - Simmons & Company International, Research Division

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Jason Smith - BofA Merrill Lynch, Research Division

Jeffrey Campbell - Tuohy Brothers Investment Research, Inc.

Andrew Venker - Morgan Stanley, Research Division

Ipsit Mohanty - GMP Securities L.P., Research Division

Cameron Horwitz - U.S. Capital Advisors LLC, Research Division

Irene O. Haas - Wunderlich Securities Inc., Research Division

Operator

Good afternoon, and welcome to the Cimarex Energy second quarter earnings conference call and webcast. [Operator Instructions] Please note that this event is being recorded. I would now like to turn the conference over to Mr. Mark Burford, Vice President of Capital Markets and Planning. Please go ahead, sir.

Mark Burford

Thank you very much, Denise, and welcome, everyone, to the Cimarex second quarter 2014 conference call. Speaking today here in Denver will be Tom Jorden, President and CEO; Joe Albi, EVP and COO; John Lambuth, VP of Exploration; and also here in Denver represented, Paul Korus, our CFO; and Karen Acierno, our Director of Investor Relations. We did issue our financial operating results financial release yesterday after the close. A copy of the release can be found on our website. We also posted our latest presentation, which we may make some references today on today's call. I need to remind you today that today's discussion will contain forward-looking statements. A number of factors could cause actual results to differ materially from what we've discussed. 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.

With that, I'll go ahead and turn the call over to Tom.

Thomas E. Jorden

Thank you, Mark, and thanks to all of you participating in today's conference. We appreciate your interest in Cimarex as always. I'd like to take a few minutes to touch on some of the highlights for the quarter before turning it over to John and Joe for a more detailed update.

The second quarter of 2014 were strong in many fronts. Production of 839 million cubic feet equivalent per day led the day and was up 22% year-over-year, 13% sequentially and above the upper end of our guidance. This, coupled with strong product prices, led to revenues of $623 million. Cash flow from operations of $443 million came close to covering the 488 -- $498 million we invested in exploration and development during the quarter. We closed our $238 million acquisition of properties in the Cana-Woodford area and raised $750 million of high-yield debt at the low price of 4 3/8% interest. Cimarex ended the quarter with $129 million in cash. And on July 31, we closed on the sale of our Kansas properties for an additional $136 million of cash.

As always, we're happy to report our quarterly results and look forward to a detailed discussion and question-and-answer session, but as you've heard us say time and again, we do not manage around quarterly goals. We're looking to maximize the rate of return of our projects over the long haul. We're looking to maintain a focus on solid execution and innovation and keep a disciplined approach as we do that. We're going to be giving you a number of updates on a number of fronts and we look forward to some good questions. But I will say that a lot of it is work in progress. We're wholly encouraged across many fronts. But one of the things we've learned in our history is that you have to keep that discipline and focus, don't make early calls, stick to your knitting and make sure that you understand before you proceed. So we'll give you all the detail we can.

Our progress continues in the Permian Basin. 3 of the 4 pilot programs begun earlier this year are now producing and generating good returns, while providing valuable information for use in our future development. We've seen markedly improved results with long laterals in Culberson County and improved results in Reeves County with changes to our frac design. And we have successfully applied larger completions to Bone Spring wells, which should generate higher returns. In the Mid-Continent, our new completion is allowing us to redefine the core of the Cana-Woodford shale, and we're intrigued by the early results in the Merrimack formation. We sit in an enviable position in that we have 2 premiere basins on which to balance our portfolio. Both the Mid-Continent and the Permian are generating top-tier returns, and that's giving us tremendous flexibility in investing our cash flow for the highest rates of return.

With that, I'll turn the call over to John and Joe to discuss the details of our progress and look forward to any questions you may have following their comments.

John A. Lambuth

Thanks, Tom. I'd like to quickly cover some of the highlights of our overall program before getting into the Permian region. I'll then finish with our Mid-Continent region and the results in Cana.

Cimarex drilled and completed 85 gross, 51 net wells during the quarter, investing $498 million. 71% was invested in the Permian region, and the rest went toward activities in the Mid-Continent region. Of those 85 wells, 47 were in the Permian region where we continued to be focused on the Bone Spring, Avalon and Wolfcamp formations in the Delaware Basin. Bone Spring activity in the second quarter included 12 net wells in New Mexico and Texas. Results continue to be good, generating some of the highest -- some of the company's highest rate of returns, with oil volumes representing up to 84% of first 30-day production. Cimarex has drilled some exceptional Bone Spring wells in the White City area, which is located in Southern Eddy County, New Mexico, just north of our Culberson County, Texas acreage. In particular, the Marquardt 12-H was completed in the 2nd Bone Spring sand and had a 30-day average IP of 1,620 barrels of oil equivalent per day, including 1,047 barrels of oil. The Bone Spring in White City is similar to what we see to the south in Culberson County, a fixed section with more gas and higher rates. The Marquardt well was completed with a 15-stage frac, a larger completion than we've traditionally used in the Bone Spring. We have now completed several Bone Spring wells using upsized frac jobs and are pleased with the results so far.

As you know, about half of the Permian drilling capital this year, approximately $685 million, will go toward further delineation of the company's Wolfcamp opportunities in the Delaware Basin. This includes downspacing pilots, wells drilled to hold acreage, testing long laterals and delineation wells designed to help us understand this vast resource. We have increased our acreage position to 235,000 net acreage in our Wolfcamp fairway, up from 225,000 acres the last time we spoke. This is the result of the acquisition of about 4,000 additional acres in Reeves County and an increase of 6,000 acres in Culberson County. We are currently producing from 6 distinct Wolfcamp zones across this Wolfcamp fairway.

One of Cimarex's innovations during the first quarter was proof of concept with regards to long laterals in the Wolfcamp. We define a long or extended lateral as anything over 5,000 feet. We now have 11 extended laterals producing across our acreage, 6 of which are in Culberson County. Between now and year end, we have 14 long laterals planned in the Culberson area, with 8 being in 10,000-foot laterals, while the remaining 6 are 7,500-foot laterals. 3 of those 3,500-foot tests will be located in the Wolfcamp A interval. We also have 8 long laterals planned in Reeves County, all located in the Wolfcamp A. One of those wells is being completed as we speak with you today. That well is a 10,000-foot lateral, which is an offset to the RUBY well which we announced on our earnings call a year ago. The RUBY was the first 10,000-foot lateral Cimarex drilled in the Wolfcamp and has accumed [ph] 190,000 barrels of oil in its first year of production, a very good well.

To more fully understand our excitement about long laterals, I'll refer you to Slide 13 in our presentation. This chart updates our previous chart, which illustrated the increased returns we have experienced from upsized fracs. You'll see we've added a new line in green, which plots the performance of the Gallant Fox, a 10,000-foot Wolfcamp D well that was completed using 43 stages. Simply put, the result is amazing. Even at a downside chase of $75 oil and $3 gas, this well generates a before-tax internal rate of return of over 100%.

We continue to work on an optimization of our completions in Reeves County. When we started using the larger fracs in Reeves, we saw uplift but less than we experienced in our Culberson wells. We've been able to improve that result and recently completed the LIVINGSTON well, a 5,000-foot lateral, which had a peak 30-day IP of 1,368 barrels of oil equivalent per day, a 30% uplift to our previous Wolfcamp A completions. When we started in Ward County, we tried a landing zone and a completion style similar to Reeves County. Just like Reeves was different than Culberson, Ward has proven to be different than Reeves. We do see a large resource in place in Ward, but are slowing down our activity to 1 rig while we work on the proper completions and landing zone for this area.

Lastly, in the Delaware Basin, I'd like to give you an update on the status of the spacing pilots we currently have underway. Please refer to Pages 16 and 17 of our presentation for an illustration of the designs. I'll speak to them by area, starting first with Culberson County where the 2 pilots drilled earlier this year are now producing. The stacked lateral tests did confirm that the Wolfcamp C and D are separate benches, with the wells exhibiting different initial yields and flowback pressures. We are still evaluating the performance of the wells in order to determine our next step. The same can be said of the 4-well, 80-acre downspacing pilot in Culberson County. We have preliminary production data, with the 4 wells having a 30-day average IP of over 1,100 barrels of oil equivalent per day. While generating good economics, this is not enough production data from which to draw any conclusions on spacing yet. That said, we do have plans in place to drill another 80-acre downspacing pilot in Culberson later this year, where we'll be making some adjustments to the initial design, such as staggering the landing zones vertically between wells within the deep edge.

Our 4-well, 80-acre downspacing pilot in Reeves County is now producing, although it's too early for 30-day rigs. And like the Culberson pilot, more data will be needed before we can draw any type of conclusions. The fourth pilot is our stacked and staggered pilot in Wolfcamp A and Reeves, which will test for the downspacing and the viability of landing more than 1 lateral in the fifth Wolfcamp A section. The sixth and final well for this pilot is drilling now, with the completion of all the wells planned for September.

Now on to the Mid-Continent area. We are pleased to report that our ongoing efforts to introduce upsized completions in our Cana program continues to provide good results. In addition to applying the larger frac to development wells, we are also testing the concept on acreage outside of the core development area. Success outside of the core means additional acreage and locations available for development. We are pleased with the results we've had so far. We drilled and completed a delineation well called the Leota 1-19H in an area up dip to the Cana core area. The Leota is a 5,000-foot lateral completed with a 20-stage frac. It achieved a peak 30-day average IP of 11.4 million cubic feet equivalent per day, including 662 barrels of oil. The 8 offsetting wells had an average 30-day IP of 3.9 million cubic feet equivalent per day. Those 8 wells, of course, have the older-style frac, thus, the Leota's IP is a threefold uplift to that to the surrounding wells.

We have 5 more Woodford delineation wells planned for later this year, with one of them being a nearby offset to the Leota designed to confirm this excellent result. We've also completed our first long lateral in the Woodford. The Bomhoff 1H-11X was a 2-mile lateral completed using 41 stages. This well has been on production for over 70 days and has an average 30-day IP of 12.9 million cubic feet equivalent per day, including 436 barrels of oil per day. Another outstanding result.

Finally, we drilled our first Merrimack test, located in the same section as the Woodford long lateral, the Bomhoff 2-11H had a peak 30-day average IP of 9.4 million cubic feet equivalent per day, including 306 barrels of oil per day. Our preliminary mapping of this interval would suggest that we have between 50,000 to 100,000 of perspective acreage for the Merrimack, although further delineation wells will need to be drilled in order to confirm this. We currently have plans to drill 4 additional Merrimack wells this year. Inasmuch that we are encouraged by this first well, we are a long way from determining the ultimate potential for this geologic interval.

With that, I'll turn the call over to Joe Albi.

Joseph R. Albi

Well, thank you, John, and thank you, all, for joining our call today. I'll touch on the usual suspects, first, hitting on our second quarter production. I'll discuss our revised 2014 production outlook, and then follow up with a brief discussion on where we see our operating and service costs.

Our second quarter net equivalent daily production came in at 839 million equivalents per day. As Tom mentioned, that is 9 million a day, above the upper end of our guidance range, which was 810 million to 830 million. And in doing so, we set a new record, once again, for the company. We had a great quarter from a production standpoint, with very nice production contributions from both our new well completions, as well as solid performance from our base properties. At the total company level, our second quarter production was up 6% from our Q1 reported volume of 740 million cubic feet a day and 22% from our Q2 '13 production level of 687 million a day. We saw production gains in both the Mid-Continent and the Permian, wherein both programs, we set new records in all product categories, whether it be gas, oil, NGLs, total liquids or equivalent volumes.

In the Mid-Continent, our Q2 '14 volume of 426 million a day was up a healthy 15% for Q1 and 24% from second quarter last year. Cana continued to be the driver here, with our second quarter Cana volumes coming in at 309 million a day. That's up 21% or 54 million a day from where we were in the first quarter in Cana. In the Permian, our second quarter equivalent volumes of 393 million a day were up 13% or 46 million a day from the prior quarter and 23% or 74 million a day from our Q2 '13 volume of 320 million a day. Permian oil production continued its growth trend during Q2 coming in at 33,317 barrels per day, and that was up 5% from Q1 '14, or the first quarter, at 11% over where we were in the second quarter last year.

So looking forward. With solid production during Q1 and Q2 and strong momentum going into Q3 and Q4, we've upped our full year total company guidance range to 860 million to 875 million a day. That's reflecting a 24% to 26% growth over our 2013 average of 692 million a day. To get there, our model is projecting our Q3 production to fall in the range of 920 million to 945 million a day. That's a forecasted increase of 28% to 32% from Q3 '13 where we averaged 717 million a day.

A couple of things to talk about with regard to what's happening underneath the hood with our guidance. Built into our projection is anticipated production acceleration from our Permian program during Q3 and Q4. Through June, we completed 51 net wells in the Permian, that's approximately 40% of the total wells that we plan to drill for the year. As such, our model incorporates 80-plus new Permian wells to come on during Q3 and Q4. That's a 60% increase in the number of Permian wells in the latter half of the year as compared to what we completed in the first half of the year. Also, with the larger mix of our higher oil-producing Reeves County-Wolfcamp wells and our Avalon completions coming on in Q3 and Q4, we're modeling our Permian oil production to accelerate as we close out the year. As an example, we completed 7 of our Reeves County-Wolfcamp wells in the first half of the year and we have plans to complete 20 more additional wells in the second half of the year. Likewise, we had 2 Avalon completions in Q1 and Q2 and we're planning to have 11 more in Q3 and Q4. And that's what's really driving our accelerated oil production growth as we close out the year.

Our revised full year guidance is up from our previous 2014 production update, which projected an average of 835 million to 860 million a day when incorporating the Cana acquisition. That's a midpoint increase with a revised guidance of 20 million a day, and I want to emphasize that our latest increase in guidance to 860 million to 875 million a day is entirely due to our new well and base property results, not the inclusion of our Cana acquisition, which has been incorporated into both our current estimates and obviously, our prior update.

The drivers to our full year guidance increase are coming from multiple fronts, strong new well performance in both the Permian and the Mid-Continent, our focused attention on our base property production, focusing on reducing downtime, accelerating -- enhancing our compression run time, our reworks, our cleanups, et cetera. That's all having an impact. And in addition -- on top of that, excuse me, we also have seen some improved recoveries in the Permian. So all these factors are coming into play. The improved recoveries in the Permian are particularly due to us obtaining 2 new takeaways off the Triple Crown system. Those takeaways are providing higher netbacks in their processing than we've seen on the system and have impacted our NGLs in the second quarter, and I anticipate for that to continue as we close out the year. In addition to gas takeaway out of Triple Crown, we've got a good focus on a long-term solution, to move oil out of Culberson County by lane, are planting the seeds now for the addition of an oil-gathering system, along and around the vast project area.

Shifting gears to OpEx. Our Q2 lifting cost came in at $1.13 per Mcf, that's flat with Q1 and at the low end of our full year guidance range of $1.12 to $1.18. Although we're seeing cost pressure in areas such as labor, compression, rentals and SWD, our strong production levels and the continued focus on controlling cost have kept our lifting costs in line. So with Q1 and Q2 coming in at $1.13, as well as a good number of our liquid-rich Permian wells yet to come online by the end of the year, we did pull down the top end of our lifting cost guidance range down to $1.17, which then gave us a projected range for the year of $1.12 to $1 17.

A few comments on service costs on the drilling side. Top drive rigs continue to be in short supply, with the delivery dates for newbuilds now extending into 2015. Despite the pressure for rigs, all other drilling component costs continue to seem to remain in check and has been that way for the last few quarters. And with the service cost relatively flat, our drilling team continues its focus to reduce total well cost via operating efficiencies. And a good example is in our Culberson-Wolfcamp program, where our average days between spud and rig release have dropped from 57 days when they first started the program in 2010 to 32 days in 2013, to 29 days here in the first half of 2014.

On the completion side, we've seen some slight cost pressure in the market for services and materials, primarily associated with the transportation of crop, not the raw material cost from crop. Any significant cost increases that we've seen on the completion side are directly associated with pumping bigger jobs, more stages, more fluid, more crop. And as a result, completion costs are now making up 60% to 70% of our total well cost in programs like Cana in the Mid-Continent, and Avalon, Bone Spring and Wolfcamp in the Permian. With the larger jobs, our total well costs have increased. However, our well results and totals to incremental benefits are definitely worth the additional cost.

As we continue to experiment with our upsized frac design, our current Cana total well costs are now in the $7.2 million to $7.6 million range. And that's up from the $6.3 million to $6.5 million levels we saw in early Q1 when we were employing the smaller fracs. The increase in Cana is entirely attributable to our upsized frac. Our initial AFEs for a 2-mile Woodford well in Cana, with an upsized frac, are now coming in the range of about $11 million to $12 million.

In the Permian, our current AFEs for 4,500-foot second and third New Mexico Bone Spring well is running in the range of $5.9 million to $7 million depending on depth and frac size now as we begin to experiment with more frac stages in the Bone Spring. And our shallower White City in Culberson's 2nd Bone Spring program, our AFEs with the larger fracs are running in the $5.7 million to $5.9 million range. And our current Avalon wells are running in the $7.3 million to $7.6 million range, also incorporating these larger fracs.

As we continue to experiment with upsized fracs in our Wolfcamp program, our current AFEs for a 4,500-foot lateral remain in the $8.5 million to $9 million range depending on the geographical area that we're drilling and the size of a frac. And our 2-mile Wolfcamp lateral AFE is running in the neighborhood of $13.2 million to $14.2 million range, again, highly dependent on frac design.

So in closing, we had a great second quarter. A strong new well, production adds and solid production performance from our base properties resulted in us exceeding our guidance. With strong wind in our sails, we've raised our full year production guidance. We're keeping our LOE and service cost in check and we're making good progress fine-tuning our completion design to optimize our new well production. We're extremely proud of our entire organization for hitting on all cylinders.

And with that, I'll turn the call over to question-and-answer.

Question-and-Answer Session

Operator

[Operator Instructions] And our first question will come from Brian Gamble of Simmons & Company.

Brian D. Gamble - Simmons & Company International, Research Division

I think, first, let's start with that Slide 13 and that wonderful green line. Maybe you could talk about how you plan to replicate that through all of your locations? I know that you're planning another 20 10,000-foots or -- excuse me, 20 long laterals by the end of the year. How much variability do you think you're going to see in the rest of those wells, as well as how many 10,000-foots do you think you have in both counties, in Culberson and Reeves, if you've thought about that ultimate number yet?

John A. Lambuth

This is John. I guess I'll take the first stab at your question. Obviously, we're very pleased with the Gallant Fox result, but I will just point out that the Gallant Fox itself is just a confirmation of the Montrose, which we talked about earlier. So it's a nice confirmation that these 10,000-foot results in Culberson are repeatable so far. But now I must caution you that, obviously, we need to duplicate this over the broad acreage position we have in Culberson. So it's hard for me to sit here and tell you that every 10,000-foot lateral is going to be a Gallant Fox throughout that whole area. But so far, obviously, we've been very pleased with what we've seen there. As far as the total number of 10,000-foot laterals, I don't have that number right off the top of my head. I mean, obviously, the beauty of the shares on JDA is that entire acreage position is entirely set up for 10,000-foot laterals, and that's why it's such a wonderful acreage position to have with Chevron there. In regards to Reeves County, our ability to drill 10,000-foot laterals is strictly a subject of continuity of acreage. We have quite a few long river tracks, which enable us to drill wells like the RUBY. But I would also point out, we have areas which we call Grisham, which is a nice continuous block that, indeed, we intend to set up with 10,000-foot laterals there as well.

Thomas E. Jorden

Yes, Brian, this is Tom. I'll just chime in here. When you look at Culberson County, the entire acreage block is available for long laterals, and that's because of their joint development agreement. A block in Eddy County where we're also getting outstanding results is mostly available for long laterals. I wouldn't quite say all, but close to all of those available for long laterals. And then our working land model in Reeves County, so it's about half of it is going to be available for long laterals. And that's 7,500 feet to 10,000-foot long laterals. So we have tremendous runway ahead of us to exploit that green curve.

Brian D. Gamble - Simmons & Company International, Research Division

Great. That's perfect, Tom. And then switching gears, first, Merrimack well. That number sounds pretty good to me as far as having the first test down. 4 more wells this year. I guess how far apart are you planning on drilling these wells? I mean, you mentioned 50,000 to 100,000 potential net acres. How spaced out of the remaining 4 are going to be as far as trying to delineate that to some degree?

John A. Lambuth

Well, this is John again. Clearly, these additional wells we're drilling are designed both to step out in the range of 5 to 10 miles away in some cases. I mean, they're designed to do many things. They're designed to test different yield expectations within the rock itself. There's even 1 design just to reconfirm the results we've had right there. So we've given a lot of thought as to where these delineation wells will go, all of it geared towards just getting a better handle over what ultimately decides the price here. And I would just point out, inasmuch as we say there's 4 wells now, there will be many more depending on the early results. If we get any encouragement from those initial wells, you're going to see us then layering even more wells to further delineate this position. Let me just finally say that the acreage number we quoted, which is a wide range, the 50,000 is kind of what we see based on this well, and how we map it is something that we feel pretty good about. But we need those delineation wells to even carry that out even further to possibly up to the 100,000-acre number that we quoted.

Thomas E. Jorden

Yes. And then the other issue with the Merrimack, as John pointed out, is yield. We think we're in a window of that play that's quite thick and has excellent deliverability. And the deliverability may be increasing as you go from the liquids into the gas. So we need to test that deliverability. There will more likely be an economic limit where it goes to dry gas. We're rather suspecting that the rates will be eye-opening, but the economics will be great because it will lose our liquids contribution. We don't know that until we get down there and drill it. And we're always ready for surprises and we'll react when we get them.

Brian D. Gamble - Simmons & Company International, Research Division

And just to that point real quick, Tom. The NGL and gas cut, if you could, of that well you gave the oil cut, and can you give the other breakdown?

Thomas E. Jorden

John is looking for that. I don't have that committed to memory.

John A. Lambuth

I don't have it either. I can calculator it.

Thomas E. Jorden

Why don't we go on? Why don't we go to the next question, and we'll come back in with that answer while we look for it.

Operator

The next question will come from Matt Portillo of Tudor, Pickering, Holt.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Just 2 questions for me on the Delaware side. I continue to hear a lot of positive industry commentary around the Avalon, and I was wondering if you could provide a little bit of context on some of the delineation work you're doing, kind of further south of your lead position. And then I guess the second question in regards to the inventory depth that you provided. I think that's based on a 4-well per section downspacing. But curious how you guys are thinking about the downspacing opportunity within the Avalon Shale in and around acreage position given kind of other industry success so far?

Thomas E. Jorden

In regards to the Avalon, a, yes, we are trying to delineate and expand the opportunity for what we consider to be the oil window for the Avalon within the Delaware Basin. As of right now, I don't have any results to talk to you about, but we are definitely looking at ways to expand the opportunity set for the Avalon. As far as spacing, we have noticed a number of operators initially started 4 wells. We now see people going even tighter, spacing 6 wells, even tighter than that. We have a number of pilots that we have planned that will be coming on here later this year where we'll be testing a much tighter spacing. I would just say, let us get those under our belt before we say anything more clear about what we think the ultimate spacing will be there. But without a doubt, what we observed in the trend in this play is too much tighter spacing than the original 4 wells per section that people originally talked about.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Great. And then just a second follow-up question on the completion front. Kind of 2 different points. I guess, on the first, I know that I think you guys were testing a tighter density stage frac in Culberson County. It was up to 30 stages on a 5,000-foot lateral, and I was wondering if that has been flowing back? Or if there's any color that you can provide on how that well is performing? And then a second question in regards to the profit. I know that you guys have really moved the needle on the Delaware Basin for the amount of profit you're using per well. We're starting to hear about an additional increase on the Midland side of the play as guys move to kind of 1,600, 1,700 pounds per foot. And I was curious if you're looking at potentially even upsizing your fracs from what you've done so far in the play?

Joseph R. Albi

I'll take that. Second question, first. We're studying that hard as to what the optimum pounds per foot is, and it's not always clear to us that more is better. I mean, we're looking at stage spacing. We're looking at cluster design. And then we're also looking at optimizing our fracs, but depending on whether we've got a parent well or an infill well. Our pilot project has given us a lot of data to chew on, and one of the things that we're setting is that the proper frac for an infill well may not be the optimum frac when you go to put them 80 acres apart or 660 feet side-by-side. So that's something we need to seriously test. We also are testing landing zones, and John mentioned that and I just wanted to underscore that, that we are -- our current pilots, with the exception of the one in Reeves County that we're still drilling on, were landed in the same stratigraphic zone, and that Wolfcamp is a very thick zone. So we're looking at a follow-up pilot where we'd still go into that same 8-well per section, but we would stagger the landing zone. So we think that may be an important innovation. So a lot of things still in the works. We're not anywhere close to figuring this out, but we're very pleased with our results. We've got a tremendous resource in place in the acreage position, and it's working.

Thomas E. Jorden

Yes, in regards to your question about the wells -- a well in Culberson, where we went from 20 stages to 30 stages on a 5,000-foot lateral, I would just say we definitely saw an improvement in the performance of that well. But so far, the economics don't really lead us to believe that that's the optimal design just yet. But I'll also caution you that when you go to 30 stages like that, some of that uplift may be in the longer-life production of the well, that we -- it would be surprise -- it won't surprise me one bit that 6 months from now, we'd look at that well and go that it's a much better design for us. We don't know. But as of right now, it wasn't a tremendous uplift like we've experienced with some of the recent changes.

Joseph R. Albi

But it's a close call. I mean, essentially, that 30-stage job, initially we looked at it, and we said, no, it's probably not giving us the uplift we need. And then a month or 2 down the road, we looked it and said, well, wait a minute, this thing's looking like it's holding in a little stronger. And so it's a close call. And it just underscores that you can make these calls off 30-day data. I mean, you can do an okay job on the parent wells. You go into these infill wells and you don't want to fool yourself. That decline is one of the critical elements that parameterizes success or failure.

Operator

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

Jason Smith - BofA Merrill Lynch, Research Division

So Tom, CapEx this year is still 75% Permian, but you're starting to add a bit of incremental capital to the Cana. So with the confirmation success in the Cana, how should we think about capital allocation now going into '15? And I guess what I'm getting at is where does that rig count go from today?

Thomas E. Jorden

Well, in Cana, the rig count's increasing. We have plans to do additional infill drilling starting late this fall and in the first quarter of 2015. So there will be some additional infill drilling. We've committed 2 additional rigs moving in. And we'll be picking up the pace of Cana. The -- we haven't formed our 2015 plans yet, but I will say that every decision we make will be around rate of return. And as we look at some of these recent results in Cana-Woodford, I can say that we're becoming almost indifferent as to whether that capital lands in the Permian or lands in Cana-Woodford. I mean, that's how good our Cana-Woodford returns are. I don't want anybody to mishear me. The Permian, we love as much as ever. But all of a sudden, the Cana-Woodford, with this new completion design and the delineation we're doing, is looking to us like it's delivering heads-up comparable returns. And that gives us tremendous flexibility. The Permian is under a lot of pressure as to a midstream standpoint, from markets, from field availability, from service availability, and it gives us a relief valve on our capital program. So as we look, we'll probably do a little more in Cana, probably a little higher percentage than it was this year as we look into 2015. We haven't figured out yet what that will be, but it's a great problem to have.

Jason Smith - BofA Merrill Lynch, Research Division

And you guys provided some color on gas price sensitivity for the Culberson long laterals. With the upsized fracs in Cana, can you just talk about what gas price you would potentially have to reconsider there?

John A. Lambuth

Well, again, this is John. I would just state that with those summer prices that I quoted, we always run our downside sensitivities, and those wells are still very attractive to us at both the $3 flat and $75 oil, a very good rate of return on that. I don't have it right in front of me, but still, they generate good returns.

Karen Acierno

We ran a case on the Golden Section, just the section that is in the book that we illustrated, and we ran a downside case to 2 50 and still had returns that were close to 50%. So...

Thomas E. Jorden

Yes, that may not be the average. I mean, that's a good result. The sensitivity is a judgment call, and we run sensitivities to oil price, we run sensitivities to gas and NGL price, and then you kind of have to lay back and say, all right, are they going to all fall together? Or is one going to fall and the other not? So I'll say this. If we have a Cana play that can stand $3 or $2.50 gas, that looks pretty good to us. And so we're quite happy with these results in Cana from a top line rate of return standpoint.

Jason Smith - BofA Merrill Lynch, Research Division

Got it. And if I can throw maybe one more quick one in on Ward County. I know water has been an issue there. I mean, so I might have missed this in the prepared remarks, but are you guys looking at altering the completion design? And as you kind of go down to 1 rig, are there still delineation tests planned for the B/C?

John A. Lambuth

Yes and yes. We are definitely altering our completion design. Again, as I stated in our remarks, we definitely recognize that what works well in Reeves doesn't necessarily work well in Ward. We've made some significant changes to our completion design and we have several wells that are in the process of either flowing back or have been stimulated with these new designs. And we're monitoring those wells very carefully. Likewise, yes, we are currently drilling a lateral testing the B/C zone, as well, within there. This, I would just say, is no different than what we experienced, and as I said earlier on in Culberson and what we experienced early on in Reeves, and that you don't get it right the first time. What's important and what we recognize is, again, there is a tremendously thick resource in place there, and it's just a matter of us finding the right recipe in order to capture good economics out of it. And that's exactly what we're doing. I will also point out though, again, that we have the luxury of going down the 1 rig, essentially the 2 rigs that we moved out, one went to Reeves, one went to Culberson, because of the breadth of opportunity we have, we can do it right in Ward. We're not in hurry, we're going to get it right.

Operator

Our next question will come from Jeffrey Campbell of Tuohy Brothers Investment Research.

Jeffrey Campbell - Tuohy Brothers Investment Research, Inc.

The first question I wanted to ask was what percentage of your Cana liquids production is condensate?

Thomas E. Jorden

Yes, on average, it's 5% over the bulk of...

Joseph R. Albi

Condensate. It's all condensate.

Thomas E. Jorden

I'm sorry. What percentage is condensate? Yes, it's all condensate. Thank you. I was giving you a percentage of the total stream.

Jeffrey Campbell - Tuohy Brothers Investment Research, Inc.

What did we end up with, what percentage?

John A. Lambuth

Cana will be -- we call it oil in Cana. It is the condensate in Cana, what we produce there.

Jeffrey Campbell - Tuohy Brothers Investment Research, Inc.

Okay. So I was just wondering, I mean, is it -- are the volumes significant enough now, or are they going to get significant enough with your growth that you could consider taking advantage of any of the recent Department of Commerce decisions to allow stabilized condensate exports without license? We've heard from some other operators say that they're getting a significant price uplift by trying to reach the export market.

John A. Lambuth

Yes, Jeffrey, we are obviously marketing our condensate barrels through purchasers, and they might be working on applications to export those condensate barrels which hopefully translate to better realization to us. But no, we're not looking to make applications to export directly.

Jeffrey Campbell - Tuohy Brothers Investment Research, Inc.

Okay. And the other thing I wanted to ask about today is, I just want to confirm that I thought this -- you seem to outline that there is going to be an increase in Permian completions in the second half. And I was wondering is that -- was that just due to faster drilling than you had planned? And if so, what were the primary drivers of the faster drilling, or was it something else?

Joseph R. Albi

This is Joe. That was basically nothing more than how we scheduled our rig lines. And most of our early-year development activity was focused particularly on the Wolfcamp because it generate -- takes up such a good chunk of our budget. Our Wolfcamp was really focused on Culberson in the first half of the year and teeing up our Reeves County projects really culminated, and then coming online here at the end of the year. So it's nothing more than a product mix and rig timing, and so forth and so on, how it all played out.

Thomas E. Jorden

This is Tom. As much as you'd like to think that if you have 18 or 30 rigs running, it ought to be smooth, it tends to be lumpy and it just works out that way. And our program is going to be lumpy in the second half. It will be lumpy for a while.

Jeffrey Campbell - Tuohy Brothers Investment Research, Inc.

Okay. And if I could ask one last one real quick. You said you're going to drill 4 more Merrimacks in 2014. But do you know how many you'll likely complete? And I mean, how many more results we might hear before the end of the year?

John A. Lambuth

This is John. We just now have spudded and are drilling the first of those 4 that I mentioned. And again, I say 4. It could even expand. But we're on the first one now, which to me implies we won't get completion for another 2- to 3-months production. You probably won't hear from us until probably sometime in early '15 on any additional Merrimack results, now because we're just now getting started on those delineation wells.

Operator

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

Andrew Venker - Morgan Stanley, Research Division

I just wanted to go back to the stacked lateral tests in Culberson. It sounds like you had positive results versus what you're hoping to test, the independence of the zones producing from one another, but you mentioned you want to see similar of the performance. Can you speak to us specifically what you're looking for?

John A. Lambuth

Yes, this is John. There are several things that we want to monitor closely in order to ultimately determine how much communication, if any, is between those laterals. We, quite frankly, even have a lot of science that we haven't fully evaluated for that stacked lateral, whether it's microseismic or tracer data. And so there's a lot of outstanding data that we're still looking at, accumulating, that we want to look at before we can really set -- put a marker down as to what truly was the outcome for that stacked lateral. We at least wanted to give you a little bit of flavor of what we saw initially, which is, as I've described, different yields, different flowing pressures. But again, time will tell what that stacked lateral and what its implication would mean for us.

Thomas E. Jorden

Another test that we have yet to do is we have a tremendous amount of work to do on landing zones. We've already done a lot, but those 2 laterals are pretty close together, and we have a lot of flexibility to lower that detest. We haven't determined yet whether they are in pressure communication. It looks to us like they're most likely not. They're producing different yields as we had to expect and hope. But yes, as John said, we have a lot of science to do, and we just have to be disciplined and focused on making sure we get it right.

Joseph R. Albi

This is Joe. I'd just comment one other thing. It's not, and you hit on this, Tom, it's not those first 30 days. It's what happens to that well 30, 60, 90. How does your decline rate change? How does your yield change, if it does? And what is that really telling you about communication and landing zones and then resource recovery?

John A. Lambuth

I'll just -- a final follow-up. I mean, Joe is right. From these wells, we have an expectation of what a parent well decline should look like. So 30 days out, 60, 90, we have an idea, we put our tight curve on it, what it should do. That's what we're looking for. We're looking for that they perform along that same type of a profile.

Andrew Venker - Morgan Stanley, Research Division

And Tom and Joe, just to go back within -- you mentioned the landing zone. How much experimentation have you done to date with different landing zones within the D?

Thomas E. Jorden

We've done a small amount of experimentation. We're looking now -- the pilot, for example. If we do a follow-up pilot, one thing that's being discussed is landing those little deeper and staggering them. So we can put -- we have latitude in the D to put wells 80 to 100 feet apart in vertical separation, and it would still be D wells. So we've been all over with landing zone. We haven't really tried it, though, side-by-side, stacked with staggered. So we have a lot of data yet to collect on that.

Andrew Venker - Morgan Stanley, Research Division

That's really helpful. And one last one just on the marketing side. Have you any efforts underway to get your crude to the coast, either Gulf Coast or West Coast?

Joseph R. Albi

Yes, this is Joe. What we're -- we have been focused on and will continue to be focused on is direct purchase to a purchaser off the lease. Where we see some potential relief is, come early 2015 when there are -- there's new infrastructure between the Delaware Basin and Colorado City and then alternatives to the Coast, and we're hoping that we'll see that reflected in the pricing, which would take into account the Midland [indiscernible] differential. Our project, and I can't elaborate too much on it, in Culberson would consist of not only just the gathering of that oil off the Culberson system, but hopefully, a good long-term takeaway solution out of the Delaware.

Operator

The next question will come from Ipsit Mohanty of GMP Securities.

Ipsit Mohanty - GMP Securities L.P., Research Division

You introduced the upsides to Delaware in the quarter before. Last quarter, you did that in Cana. I just wonder, as you stand right now, what's the extent of your application of upside across Bone Spring, Wolfcamp and the Delaware and then in the Cana, are all wells, going forward, going to be all upsized fracs?

John A. Lambuth

This is John. I'll try to answer your question. Upsize is a phrase we throw out fairly common. I want to be clear. With each play, we're constantly asking ourselves, is our frac optimal for that particular well. And what we have experienced over the last year is in the areas like you mentioned, in Wolfcamp and Avalon and Cana, that clearly, no, that our previous frac design wasn't optimal. We've made changes. With each play, those changes are different. There is no one recipe within -- in each play. So if anything, I would say that every play is kind of upsize for us now. I mean, we're always looking to say what is the right recipe to get the most hydrocarbons out of that well. We've been a little bit, I would argue, slower in the Bone Spring. Here, recently, we made changes in the Bone Spring and we're very pleased with what we're seeing. That will probably not be the last change we make, and we'll probably test something else there. And I think that's probably the message you should take, is that in all of our plays, we're going to always be constantly asking ourselves, are we optimal and should we be trying something else? And that's really the message you should take from us in regards to these frac designs.

Ipsit Mohanty - GMP Securities L.P., Research Division

Okay. And then just a slightly broader question on your development strategy into Delaware. Look, it sounds like as you -- there's a lot of data to do before you can declare a win in the stacked concept. So as you get -- as you develop the great wells in Wolfcamp D and some of the other ventures like A, what's your base of trying to delineate the various stacks? Or what's your motivation for trying to go ahead with the stacked concept versus just drilling some of these highly profitable wells in the separate ventures going to be?

Thomas E. Jorden

Yes, well, I'll take a stab at that. A year ago, we talked about getting teed up and ready to go to development in the Delaware Basin. And these pilots initially were designed for us to make decisions that will allow us to go in the full development mode into 2015. Now if we had to do that, we would do that. And I think that our results have been very good, and if we had to make decisions today to proceed based on what we know today, we would achieve very nice rates of return if we were to go into full development. But then something wonderful happened to us. The innovations that we've been experimenting with in the Permian Basin, we applied to Cana, and we had an absolute game-changing result at Cana. So today, we have the flexibility of taking that capital, redirecting it to Cana and doing additional science in Permian. So we don't have a schedule today for when I would say we'll be going into full development mode in the Delaware Basin. I will say that our top line capital will be growing, assuming that prices hold up and our cash flow holds up. And we have outstanding places to invest in out of the Permian or Cana. But we'd like to do a little more science and get it right. Because you only get one chance to get it right. If you're in development mode and experimenting as you go, you really run the risk of wasting capital, and we want to get the best returns we can. And right now, we think that's probably deferring full development for a while, and the nice thing is we don't sacrifice an iota of rate of return because of what we're seeing in Cana.

Ipsit Mohanty - GMP Securities L.P., Research Division

Got you. And then one last on acreage. You mentioned you added some acreage in the Culberson. Do we assume it's going to bolt on to where you were already? In other words, is that something you can leverage to extended lateral, as well?

Thomas E. Jorden

We're always looking to add acreage. The Culberson was really a recounting. I mean, we -- as silly as it sounds, you always circle up. You want to make sure you understand your ownership, you understand your right, and that was just kind of truing up on accounting of our acreage, not necessarily leasing new acreage. We do always look for new opportunities. We've recently leased new acreage. And I will say we recently chose not to lease new acreage because it's gotten highly competitive, and we think our returns -- it has to compete for returns.

Operator

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

Cameron Horwitz - U.S. Capital Advisors LLC, Research Division

You guys have obviously been at the forefront of the upsized frac phenomenon in the Permian. And I was hoping you could just give us some comment about some of the steps you may be taking to secure the sand supply that you're obviously going to need and just the logistics of getting all that sand to the well site?

Joseph R. Albi

Yes, this is Joe. We have not procured any long-term relationship with the sand mines, what-have-you, but we are working hand-in-hand with the 2 majors, Schlumberger and Halliburton, laying out our frac schedule, if you will, 2-year out. We've got a well-to-well cruise assigned and lined up and we're trying to stay well out ahead of our frac schedule with our materials and getting them in place. We have had absolutely no indication, at least from our end, that there's a shortage of getting this stuff. We're trying to procure it. The only -- we've seen a very modest increase in service cost, but we've offset that with our optimal performance in getting our stages done quicker. The materials have remained relatively in check. The cost of crop has stayed somewhat flat, but it's the transportational profit is where we've seen any kind of cost increase. And most of that is due to the trucking. And you're up in more sand, you got to truck more sand, and that's kind of the supply/demand relationship that happened there. It's maybe, in start, white sand cost up from about $0.08 of a pound a year ago to $0.11 now. So where I'm heading with all this is although about a year back, we did look at a potential relationship with an outfit to provide the sand and then we transport it to our wells. It's a heck of a lot easier for us just to work with our service provider to arrange for that.

Thomas E. Jorden

We've talked in the past about as we're putting a lot more effort in the planning, and that effort is an ongoing and ever-going process. We've got an active 5-year plan where we look ahead to our rig schedule and we're scheduling all the resources that we think will be required to execute our program. That includes sand, as you've mentioned, it also includes rigs, it includes water, water disposal, electrification, includes services, field services, materials, and most importantly, people. And we're ahead of the game. We've met with vendors and midstream companies. We think we have a good plan. We think we have an execution and path forward. And we're putting a lot of energy into it. We typically try to avoid long-term commitments, if we can. We're generally market-takers, and the markets are very efficient at adjusting to supply and demand.

Cameron Horwitz - U.S. Capital Advisors LLC, Research Division

Great. I appreciate that color. And then I just had one more quick one, and moving over to Cana, I'm realizing it's obviously very early, but are you detecting any evidence from the longer laterals there that you're going to see a better decline profile? I think you said maybe you had 70 days under your belt, and just maybe remind us about how the acreage is set up over there in terms of if you were to go to a longer lateral program and what the dynamic is from a lease standpoint there?

John A. Lambuth

This is John. While we're 70 days in, that well has taken quite a while to clean up. So -- and quite frankly, we have yet to even reach our peak 30-day average. What we gave you was a trailing 30-day average. So the well, I mean, we're very pleased with the well, but we're long ways from making any comment about what the decline profile will look from that well.

Thomas E. Jorden

Yes, I mean, the rate is still increasing, still playing out.

John A. Lambuth

It is. We drilled that well specifically in an area where we have a great acreage position to leverage that toward long laterals. If we choose to do that in the future, there's upwards of around at least 8 contiguous sections, which lend themselves -- operator sections, lend themselves to long laterals. But that's something that we just have to wait and see how this well performs, and then possibly even follow up with another one before we get comfortable, looking at that from a development standpoint. But yes, our position, our acreage position is well-suited for this if we decide to go that route.

Operator

Our final question today will come from Irene Haas of Wunderlich Securities.

Irene O. Haas - Wunderlich Securities Inc., Research Division

A question on the Merrimack. Just trying to get my head around the whole exploration process. So you have an area towards the north that's probably more liquid-rich, and as you go to the southwest, you got a little gassier. How many wells do you think you would need to get comfortable with how continuous the trend is? And are you targeting different zones? How continuous is your reservoir? And really, ultimately, what kind of reservoir is it? Does it have a lot of water issue? These are my questions on the Merrimack.

John A. Lambuth

Well, my first comment is you ought to come work on our exploration test. Maybe you can help us answer those questions. Yes, as we've said about the Merrimack, there's a lot still -- believe it or not, we don't understand about the Merrimack. Although, we are actively acquiring data with the core data, logs, and so on. Some of the things that we are recognizing that is similar to the Woodford, we believe, there will be a variation in yield as you go, let's say, from immature up-dip various, to more mature down-dip various. And so that's one thing that these delineation wells are going to try to test, is the boundaries of essentially that yield expectation. As Tom alluded to earlier, we -- I think we kind of know where dry gas is going to be. We certainly know, as you get very far up dip, where some of our competitors are, we kind of think we know where the oil window is. What we're still trying to figure out is just what is the true sweet spot. Obviously, we're very pleased with the first well, but that doesn't mean we're in the right spot yet. The other thing I would say is, yes, it's very thick. And we happen to choose this one particular landing zone, quite frankly, based on where a lot of competitors were landing. I will tell you that if we're drilling our next well right now, we had a very healthy debate internally as to where we should land that well. Again, we're learning as we go along here. I would argue, a good -- we talked about 4 wells, probably in the range of 8 to 10 wells under our belt before we really start getting a good handle over what the true opportunity set is here that we have in front of us, is the way I would think about it.

Thomas E. Jorden

Yes, Irene, one of the challenges that we see is it's not a reservoir that just jumps out on longer slots and you say, wow, look at that, let's go drill it. It's a combination of core data, month-long shows. But there are also empirical results from ours and competitors' wells, and we look at those carefully. So we don't know what the thickness cutoffs are, we've got a ream of maps, but until we get out there and test it, we are forging new ground. And one of the challenges to Cimarex is most of our competition is north and east of us in an oilier part. So we're in a little different maturity fairway, and we're very encouraged by that based on our well and 1 or 2 competitor wells, but it means that we don't have a tremendous amount of analogs. The competitor wells are generally drilled in a little different oil/gas mix. So we're going to have to sample the reservoir. It does appear to produce less water than we were expecting. I will answer your question there. Production tends to dry up a little faster than what we observed in the Woodford, for example.

Irene O. Haas - Wunderlich Securities Inc., Research Division

And is it a true shale or is it a mixture? Is it really deposit on base in offsetting, or is it a slope kind of thing?

John A. Lambuth

This is John. I think it kind of a -- the answer to your question depends on how you define a shale. How's that? We debate that a lot even internally, in terms of that -- if you show shale could be a matter of grain size or the fizzled nature of it. Depending upon who you ask, some would say this is a shale. Some would say, no, it's more of a dirty silt stone. Again, it depends on who you ask. What we care more about is just how do we measure it, how do we map it, and how do we prosecute it? Whatever you want to call it, that's what we're concentrating on.

Thomas E. Jorden

And Irene, I want to just trend along with John. The rock type is different, and so we don't look at this rock and just make automatic arm-waiting facing assumptions to what downspacing there may now look like. We are really early time here. We are wholly encouraged by what we've seen thus far, and we just need to keep our focus and do the work.

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 his closing remarks.

Mark Burford

Thank you, everyone, for joining us today. I appreciate your attention. We look forward to reporting our continued progress on different plays going in the future. And ultimately, that we have in the week after next, we'll teach you some in the Enercom Oil & Gas Conference here in Denver. But again, thanks for your participation, and if you have other follow up questions, please reach out us. Thank you very much.

Operator

Ladies and gentlemen, the conference has now concluded. We thank you for attending today's presentation. You may now disconnect your lines.

Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited.

THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY'S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY'S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY'S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS.

If you have any additional questions about our online transcripts, please contact us at: transcripts@seekingalpha.com. Thank you!

This Transcript
All Transcripts