Cimarex Energy Co.
Q1 2013 Earnings Call Transcript

Published: 7 May 2013

[Operator:]

Good morning. My name is Jared, and I will be your conference operator today. At this time, I would like to welcome everyone to the Cimarex Energy First Quarter Results Conference Call. [Operator Instructions] Mr. Burford, you may begin.

[Mark Burford:]

Thank you, Jared. Welcome, everyone, and thanks for joining us today on our first quarter conference call. On today's call, we have Tom Jorden, President and CEO; Joe Albi, COO; Paul Korus, Senior Vice President and CFO; and John Lambuth, Vice President of Exploration. We issued our financial and operating results news release this morning, a copy of which can be found in our website. I do need to remind you that today's presentation will contain forward-looking statements. However, a number of factors could cause our actual results to differ materially from what we discuss. You should read our disclosure on forward-looking statements in our latest 10-K and other filings and press releases for the risk factors associated with our business. And with that, I'll just go and turn the call over to Tom and let him jump into the details.

[Thomas E. Jorden:]

Thank you, Mark. Welcome, everyone, and I want to say we appreciate your interest in Cimarex. I'd like to take a few minutes to go over the highlights for the quarter before turning the call over to Joe and John for a more detailed look at our operations. Cimarex reported this morning a very solid first quarter in line with our expectations. Production average 661.1 million cubic feet equivalent per day, growing 10% from first quarter 2012. Our oil production grew 12%, which is actually 20% after adjusting for the property sales. Our first quarter oil volumes averaged 33,154 barrels per day. So we're seeing some very, very nice growth in our oil production. Capital expenditures for the quarter totaled $409 million, funded with internally generated cash flow and $120 million in debt. We expect the bank debt will reach roughly $300 million by the end of the year, and that, of course, is up from 0 at January 1. And that says, our opportunity set continues to exceed our projected cash flow. In total, Cimarex will spend about $1.5 billion in 2013 on high rate of return projects, primarily in the Delaware portion of the Permian Basin and the Cana-Woodford shale. John and Joe will give you a flavor of that in detail but we see an outstanding opportunity set and great flexibility as we prosecute it. Our Permian program continues to provide great returns, and that's where we'll invest $900 million or about 64% of our total capital this year. Results have been particularly noteworthy in Culberson County, Texas, where we believe the Horizontal Wolfcamp can provide decades of drilling opportunities for Cimarex. In addition, we see encouraging results in the Second Bone Spring in Culberson County. We also see potential in other zones in the stacked pay opportunity and believe this area is on its way to becoming a legacy asset for Cimarex. We're very proud of the work that our teams have done in Culberson County and are extremely optimistic about the development potential, multi-zone. For the rest of 2013 and into 2014, our Permian program will focus on holding our Culberson acreage. A lot of that acreage is term acreage, and we're on a program to make sure that every prospective acreage gets held by production. So we'll de-risk the acreage as we test other areas and other zones. We're still currently identifying economic sweet spots for potential future infill development. And as John will show, it's a big area. We still have a lot of drilling to do. And as we drill our way forward, we're finding new sweet spots we didn't anticipate. We'll also be doing an evaluation of multi-zone stack lateral development, and that's especially in various ventures of the Wolfcamp shale, along with the Second Bone Spring sand. We're at very early time there and need to have some field experiments before we can definitively comment on ultimate spacing. And then finally, we'll develop our infrastructure and takeaway strategies to accommodate our growing production. We've put a lot of energy into that in Culberson County, and we're in a commanding position there when it comes to infrastructure. And there are opportunities elsewhere in the basin, and we'll be attacking that. So a good quarter, good execution out of our organization. And with that, I'll turn the call over to Joe Albi, our Chief Operating Officer.

[Joseph R. Albi:]

Thank you, Tom, and thank you, everyone, for joining our call today. I'll touch on our first quarter production, update you on our second quarter guidance projections and then follow up with a few words on operating costs and service costs before handing the call over to John. As Tom mentioned, our first quarter volumes came in at 661 million a day, that's a good strong quarter for us. We're above the midpoint of our guidance of 642 million to 667 million, and up 10% from where we were 1 year ago in Q1 '12. If you adjust for our 2012 year end property sale, which took about 15 million a day off the books, we were up 12% from Q1 '12. We saw solid production growth during the quarter despite incurring some downtime associated with plant facility shut-ins, freeze offs and some pipeline maintenance, which equated to about 7 million a day, and most of which came from the Permian. If we dig a bit deeper into the details, our Mid-Continent region continued to set records for all product categories, whether it be gas, oil, NGLs, total liquids and equivalent volumes. Our Q1 Mid-Continent equivalent volume of 361 million a day was up 15% from Q1 '12, and 3% from last quarter. Cana continues to drive the production increases that we're seeing in the Mid-Continent, with our first quarter volumes of 229 million equivalents a day, up 42% or 68 million a day from a year ago and 15 million a day from last quarter. In the Permian, our Q1 '13 net equivalent volume of 275 million a day was up a strong 15% or 35 million a day from Q1 '12. Our Permian oil production averaged 25,832 barrels a day, that's up 18% over last year. As compared to Q4 '12, however, our first quarter equivalent volume was down 17 million a day, and this is more or less a direct result of our Permian asset sale on December and the downtime that I mentioned we experienced during the quarter. As we move into the second quarter, however, we've made up that gap. We're seeing a nice, strong upward trend in our Permian production. Looking at our guidance, we've made no changes to our previously announced full year guidance range of 675 million to 705 million a day. That represents an 8% to 13% increase over 2012. And when adjusting for the December 2012 property sale, we're really projecting a true apples-to-apples increase of 10% to 15% over last year. If you look under the hood of our projection, however, you'd see that we've changed our projected commodity mix. As a result of lower processing yields and new markets, primarily in the Permian, we've lowered our projected NGL volumes for the year. However, offsetting that drop is stronger performance we're seeing from our oil projects, also in the Permian, which, in essence, have kept our total equivalent volume projection unchanged. Where we had originally projected a 1% to 5% increase in our oil production during 2013, we're now projecting an increase of 8% to 13%. In total, we expect liquids to represent about 50% of our production this year, that's another gain in our total liquid percentage, up from 48% last year. To help get us to our full year projection, you've seen our Q2 guidance range of 667 million to 692 million a day, and what that's really reflecting is that ramp up of production I just mentioned from Q1 and most of that coming from the Permian. Shifting gears to our OpEx. You may note that our Q1 LOE came in at $1.17 per Mcfe, that's up $0.11 from the fourth quarter and slightly above our 2012 average of $1.13. A couple of factors are coming into play here. We're seeing some increased compression costs, we've had increased power cost on our new wells, some higher chemical costs during the quarter associated with our early quarter freezing issues, just to name a few. But the largest factor was our increased workover activity, primarily in the Permian, which, by itself, added $0.10 per Mcfe over our 2012 average. As we may have talked about before, as part of one of our 2013 company goals, our production group has put a strong emphasis on stepped-up well reviews and lease inspections to optimize the production from and the appearance of our wells. The attention that we're giving the wells comes at a cost, however, and as a result, we've revised our full year LOE guidance up just slightly from $1.10 to $1.22. Just a few comments on service costs before turning the call over to John. On the drilling side, we'd characterize the market as stable with current day rates about where they were last call. But that's down about 3% to 5% from where they were in Q4. That said, however, we're seeing the benefits of some nice cost reductions, primarily in the Permian. The reductions that we've seen on the drilling side have been, I'll call them, performance-related rather than by market. With enhanced use of the PDC bits, tweaking our fluid designs, employing more use of downhaul motors and rotary steering technologies, we've cut down on our drilling days. On the completion side, we've realized some nice reductions as well, not only to a competitive market, but through more efficient operations, in addition. As a result, we're seeing meaningful cost reductions in our Bone Spring program, with our generic New Mexico Horizontal Second Bone Spring AFEs now running $6.3 million to $6.9 million. That's down about $200,000 from the numbers we've quoted last call. And our West Texas Second Bone Spring wells are now running $5.7 million, with them seeing the same benefits as well. The same goes for our West Texas Third Bone Spring AFEs, which are currently running around $6.4 million to $6.6 million. That's down $600,000 from our last call. We've really made some great progress in that program. Our Wolfcamp Horizontals are still running around $7 million to $7.5 million, about flat to where they were last call. But remember that those numbers are down more than $1 million from where they were 9 months ago. In Cana, our program drilling efficiencies continue to shave dollars off our AFEs, with our current estimates now running $6.9 million, down $100,000 from, again, what we quoted last call, which was 500 -- and we're $500,000 down from where we were 6 months ago. We are very, very excited about the improvements we've made in our drilling program. Quite proud of our drilling team to accomplish what they've done, the results of which are certainly helping the economics of our program. All that said, we'll stay focused on demonstrating further improvement to get things better yet. So in summary, we've had another good quarter. Q1 production came in strong. Our guidance remains unchanged and continues to reflect an 8% to 13% increase in our production, and our drilling costs are certainly headed the right direction. So with that, I'll turn the call over to John.

[John A. Lambuth:]

Thanks, Joe. I'll cover some of the specifics of our Permian and Mid-Continent drilling program. It's been a very busy first quarter for us. We drilled and completed 87 gross, 47 net wells during the first quarter. I'm going to start first with an update on our Mid-Continent region. This quarter, we drilled and completed 52 gross, 20 net wells, essentially all of which were in the Cana-Woodford shale play. We continue with our infill Cana core drilling. This brings then our total well drilling in Cana to 532. We currently have 4 operated rigs working in Cana. We're still on track to drill and complete approximately 35 operated wells, and we will participate in 90 outside operated wells, with the majority of them being drilled by Devon. Our drilling and completion capital is still projected to be around $350 million for this year. Certainly, a bit higher first quarter gas prices are a relief, and they are helping our Cana's projected returns, as are some of the cost reductions in our drilling completion that Joe just mentioned. Our Cana program is performing well, and we're working to minimize those costs and increase productivity to enhance our returns there. Moving on to the Permian. The Permian region was our most active region as we drilled and completed 35 gross, 27 net wells during the first quarter. All of these were completed as producers. Our drilling has focused in the Delaware Basin of Texas and Southeast New Mexico, targeting the Bone Spring and Wolfcamp formations. Nearly half of our first quarter drilling was in our New Mexico Bone Spring program where we drilled and completed 18 gross, 11 net wells. We continue to have very strong results in this program. Our per well 30-day gross production from these wells averaged over 650 barrels of oil equivalent per day, with the majority of that 89% being oil. We also have had another solid quarter in our Ward County Texas Third Bone Spring program where we have drilled 7 gross, 6.5 net wells. These wells had a per well 30-day average gross production rate of over 970 barrels of oil equivalent per day, 77% of which was oil. For both of these programs, again, as Joe just mentioned, we're seeing significant reductions in our drilling and completion costs, which just leads to even better rate of returns that we're experiencing there. We've also had an active Texas Bone Spring program -- sorry, as Tom mentioned, Culberson County, as well as what we call White City or Southern Eddy County has become a key area for us. We continue to have success drilling both in the Wolfcamp C and D intervals, as well as Second Bone Spring wells. And we see additional upside in the Wolfcamp A and the shallower Delaware sands. We drilled and completed 3 Wolfcamp and 3 Bone Spring wells this year. We now have 4 Bone Spring wells drilled to date in Culberson County, which have had a per-well 30-day average gross production of over 900 barrels of oil equivalent per day, of which 59% is oil. I'd like to mention here that of these 4 wells, one was a very significant step out to the Southern area in Culberson, away from where the existing wells have been drilled. That well has done a nice job of proving up additional areas for us to drill in Culberson. The Wolfcamp wells now total 34 gross, 32 net in the area, and our per-well first 30-day production rates on all of the Wolfcamp wells drilled in the area to date have averaged 6.4 million cubic feet equivalent per day, comprised of 43% gas, 27% oil and 30% NGL. In addition to the Wolfcamp C and D interval, as well as the Second Bone Spring, we think there are additional opportunities on our Culberson acreage in both the Wolfcamp A interval as well as the shallower Delaware sand. We, in fact, plan to drill a Wolfcamp A test in Culberson later this year. Some other things we're looking forward to trying include a dual completion of the Wolfcamp C and D. The Wolfcamp interval is the very thick interval, and we are fairly confident that the C and D are not basically communicating with each other. So we plan to drill a stacked lateral, one in the C and one in the D, to verify that indeed we get a unique reserves with each zone. With those results in hand, we will then plan our infill development program sometime probably in early part of next year. Finally, a quick word on another area where we're drilling, Wolfcamp test, which is in Reeves County. We have one well that has been on production for a while now, and its results are extremely similar to other operator wells in the area. We're very excited about it. We have also now drilled a second well and have just finished completing it. It is just now in early stages of flowback. And we're now in the process of drilling our third well. We're very excited about this area so far, although there's still a lot to be determined based on future drilling as to how good it will eventually be for us. Finishing up, I just want to say that we are off to a great start this year. Our teams are always focused on maximizing returns on our drilling, and they are doing a great job. Looking forward, we have a very significant opportunity set. Quite frankly, our prospect inventory has never been as rich as it is right now. In the Permian region itself, as we sit here today, we recognize between 200 to 300 Bone Spring sand locations, with further upside available for us in the Avalon on the same acreage. When we look at the Wolfcamp in Culberson White City, we see several thousand potential locations, that, of course, depending on our ultimate spacing that we determined based on our infill pilot, as well as whether or not how many stacked laterals we are able to drill within that interval. We, of course, also see potential for the shallow at Delaware and the deeper Cisco/Canyon shale wells as well. We have huge amount of future drilling inventory in the Permian, not to mention the thousand of wells we have still yet to drill in Cana. Now with that, I'll turn the call back to the operator for Q&A.

[Operator:]

[Operator Instructions] And your first question comes from Mario Barraza.

[Mario Barraza:]

Just can you talk a little bit more about the Culberson County area? Where do you feel -- I know it's early days, but where do you feel these potential 5 zones could spread out? Do you think they're prospective across the entire 100,000 net acres you have here?

[John A. Lambuth:]

Potential, yes. Can we definitively say that at this point? No. Obviously, future drilling will dictate that. What we do know is we certainly have established a good program in the Wolfcamp C and D today. Likewise, we here recently with the results have established at a very good 8 tack [ph] rate of return program in the Second Bone Spring. How far does it go? Well that's just a matter of further development drilling, stepped out drilling, which we have not achieved just yet. So the potential is there, but can we quantify that on all the acreage? At this point, I guess, I'd say the jury is out, but the potential is definitely there for a majority of those intervals.

[Thomas E. Jorden:]

Mario, this is Tom. I don't think all zones will be prospective everywhere. So we're currently delineating and, of course, this is a big area and a very thick section. That Wolfcamp alone is 6,800 feet thick. We have the Second Bone Spring and then we have the Delaware above it. So given that area and that stratigraphic column, we have a lot of delineation still to do. Certainly, the C and D are fairly well calibrated, where we drilled it and we're still defining it. So we see the C and D as prospective overall, say, much of that acreage although that's still being defined. Whether that will support stacked laterals or not, we need to experiment. And then we haven't tested the Wolfcamp A in Culberson County. We haven't tested the Delaware at Culberson County. So not to be vague with our answer to your question, we certainly see -- it's not hard to do the arithmetic and get thousands of locations even on the down case here, but we're still defining the potential, and we don't have a lot of granularity as to how they will sum up.

[Mario Barraza:]

No, I appreciate that, the color you can provide today. And then Culberson isn't extremely populated. Do you guys have -- if you were to further accelerate the activity there heading into next year, are there any material infrastructure investments you still have to make here?

[Thomas E. Jorden:]

Again, this is Tom. We've made infrastructure investments there over the last few years, and we got ahead of that, we saw the potential early on, and we are in very good shape from an infrastructure position. We've got our gathering system, we have a little processing plant we put in. We have multiple outlets for wet gas stream. There's still some infrastructure to be built as we keep pace with our drilling program. But we've got the infrastructure there that allows us by and large to control our own destiny. And so it was a very fortuitous decision we made 2 or 3 years ago to get ahead of that program and build that infrastructure.

[Operator:]

The next question comes from Ryan Todd.

[Ryan Todd:]

A question for you on CapEx. How should we think about CapEx and sensitivity to cash flow? So if commodity prices hold at current levels, should we think of the $1.5 billion number as a cap or would you consider spending more if you could still keep your borrowing under a certain limit?

[Thomas E. Jorden:]

Ryan, this is Tom. We have flexibility there. We've not made any rules. We've provided guidance, but we've also been very clear saying that we're going to make decisions as we move forward. We have tremendous opportunity, not only in the Permian Basin which is, of course, the major focus, but we have some emerging opportunities in the Mid-Continent that we may want to fund this year. So our intent is certainly to stay within that capital guidance that we've laid out. But if we think we can get a great rate of return and it has downside protection to some commodity sensitivity, we wouldn't hesitate to go beyond what we've announced.

[Paul Korus:]

This is Paul. Similarly, 3 months ago, we said our number would be 1.4 to 1.5. All we were simply doing there was allowing for weakness in the gas market in which case we might have tweaked back to 1.4. But I'll tell you, our number has always been right around 1.5, we just gave ourselves that flexibility back then. Where we sit today, we've kind of eliminated the down side case, and so our best estimate now is 1.5. If there's any bias, it would be higher. And by the same token, we gave wide enough production volume guidance to handle any of those cases. I mean, you can kind of drive a truck through our production volume guidance for the year. And that, of course, gives us plenty of wiggle room for things to go well. But it also allows for situations like well freeze offs, which we did experience. We are going into the suburb where we've seen ethane rejection and things like that. So we -- that's why we choose to give wide guidance as opposed to very narrow because a lot of things happen. And that way, we won't have to change guidance if they do.

[Ryan Todd:]

That's great. And you've seen some great -- I mean, it sounds like you've seen some great progress on reduction of well costs there. I mean, should we think of that as being -- are those well costs at the point now where they're below your official budget where you started the year and should we think that, for example, in the Permian, if you still spend the $900 million, that there could be upside to the actual number of wells drilled over the year?

[Thomas E. Jorden:]

Ryan, the upside, there's a little bit of cost in there, and Joe went over that. But one of the things we're finding is we're drilling our wells much faster. Now generally that will translate into cost savings. But when you think about the components of drilling a well, you have your tangibles, your intangibles and your completion costs, and so drilling them faster doesn't really save on tangibles or completion costs. So what we're finding is that when we look at the Permian, we're drilling these wells significantly faster than we modeled. So we're getting a lot more done with the same rig fleet, and that's putting a little upward pressure on our capital, not downward pressure. So yes, we are seeing some cost savings, but mostly, we're seeing drilling time reduction. And so if we keep our current fleet and don't adjust, we'll probably be on that higher end.

[Joseph R. Albi:]

And this is Joe. What I might add to that is for the same dollars, we'll drill more wells. So the positive side of that is more wells, more reserves, more production that comes along with it which affects our cash flow.

[Operator:]

Your next question comes from Joe Magner.

[Joseph Patrick Magner:]

Just I wanted to, I guess, follow up on the Cana program, with the rally we're seeing in gas prices and cost savings that you alluded to. Just curious where you are on decision, what to do with those rigs for the second half of the year.

[John A. Lambuth:]

This is John Lambuth. As I said, we are at 4 rigs right now. But that said, in the immediate near future, we'll be going down to 2 rigs. But to be honest, that reduction in rig has more to do with just the overall infill development that's ongoing there. As we stated, there's kind of a ballet going on between us and the other operators to line up our sections in kind of an east-west sequence. And so right now, we don't want to keep the rigs because we get too far ahead versus what the other operators are doing. So the prudent thing for us is just to pull back a little, again, to work in concert with the others, and so that's what we're going to do for the remainder of the year with those 2 rigs. More than likely, as we enter next year, you'll probably see us come back with a couple of those rigs back into the program.

[Joseph Patrick Magner:]

Okay. And is there a plan to move those rigs to other opportunities in Mid-Continent or shift them over to the Permian? Has there been some discussion about that throughout the year?

[John A. Lambuth:]

Well, we have sent one of the rigs down to the Permian. These rigs, we really, really like, as Joe mentioned, they've really done a phenomenal job for us in terms of drill rate, number of days. And so one of those rigs is moving down to the Permian, especially to help us with -- that rig's really built for longer laterals. So it's going down there to assist us with those type of wells. The other rig is one that we have released.

[Joseph R. Albi:]

So what I might add there is that most -- all of these rigs that we've had in Cana, we've run for quite some time. So we've developed some efficiencies, we know how they work, they know how we work, to the extent we can keep them in our program, working within our budget, and as you mentioned, move them down to the Permian where we might take a 1,500-horsepower rig and put it into a situation -- or hydrated rig and put it down there where, even at a higher day rate, it's outperforming some of the other rigs, we're going to jump on that.

[Joseph Patrick Magner:]

Okay. I just wanted to clarify, the guidance for the year, did that include the potential, I guess, drop down to 2 rigs or was it a drop of all 4 rigs, and a shift for the second half? I just want to sort of be clear on what was included and how the current plan is.

[Joseph R. Albi:]

This is Joe, again. What that incorporates is our current projection for all of our rig activity. So to the extent we're going from 4 to 2, it's certainly in there.

[John A. Lambuth:]

Yes, this is John. I'll just comment that regardless of 4 or 2, any of the wells we drill now in Cana don't even show up in this year's production. Basically, those wells will end up getting completed early first quarter. So really, it has no impact on this year's production guidance.

[Thomas E. Jorden:]

That's correct. That have more of an impact on '14.

[Joseph Patrick Magner:]

Okay. And just on the plan to drill a dual stacked lateral, can you just talk about the impact on overall well costs relative to drilling 2 separate laterals. And any associated risks with that type of a well design that we should keep in mind?

[John A. Lambuth:]

Well, this is John, again, and maybe I wasn't as clear as I needed to be. But those will be 2 independent wells, just side-by-side, where one would target the C zone, the other well would target the D. We're not talking about 2 laterals out of 1 bore hole. They will be 2 independent wells targeting each independent zone. Is that clear?

[Joseph Patrick Magner:]

Yes, that's helpful. Okay. I'll leave it there.

[Operator:]

Your next question comes from Gil Yang [ph].

[Unknown Analyst:]

Just going back to well cost, and I apologize if you have addressed this. But if you look at your -- in the presentation, if you look at the E&D budget versus the net wells. The wells are more expensive in the Permian this year than last year. Is that just the budget, and we should expect that those well costs should be down from it or...

[Thomas E. Jorden:]

Well, there are a couple of elements there. One, we're drilling more long lateral horizontal wells. So our well complexion is more expensive, we're drilling more Wolfcamp wells. We've got a very active Third Bone Spring program, and those are a little more expensive wells. We're also drilling few Yeso wells this year. So those -- if you look at our well count in the prior years, they've had a fair amount of those $2 million, $2.2 million vertical wells. And there are very few of those in this year's program. So a lot of that difference in average well costs is made up by the types of wells we're drilling, not necessarily a change in cost.

[Unknown Analyst:]

Got you. Okay. So the change in cost you're talking about is sort of apples-to-apples cost changes and this is a mix issue that the wells themselves are...

[Thomas E. Jorden:]

That's right.

[Unknown Analyst:]

Yes, okay. Got you. And then just following up on in terms of the Permian. In Culberson, do you have any drill to depths -- or hold to depth issues that will induce you to drill to the deeper horizons first?

[Thomas E. Jorden:]

Yes, that's certainly a part of our overall strategy there. And one of the things that we did, we got it down in the Culberson. When we started putting this acreage together in 2006, at that time, our primary objective was the Penn Shale or locally it's called the Cisco Canyon. And that's a nice productive interval. We drilled some wells, made some nice completions in that, both in Eddy County, we have fair amount of experience. But it's dry. Although it's an economic objective at current cost and current gas prices, it's not something we're pursuing. So then we've moved to the Wolfcamp, and on our drill to hold, we're holding at least to the basin of Wolfcamp. And we're looking at lease by lease. Some leases hold the entire Wolfcamp, some leases, it's depth drill. And we've got a fairly complex analysis on where we need to drill. But we're definitely attempting to hold the deepest producing Wolfcamp horizon and everything shallower. So that does color our drilling strategy. We get asked a lot, why don't you guys do Wolfcamp A? Well, we are, but we're kind of fitting that in with wells that are targeting the D and C to hold those deep rights.

[Unknown Analyst:]

Okay. So in some cases, you need to drill the Wolfcamp E to hold the whole thing. But in some cases, if you drill the Wolfcamp A, you can hold A, C, D, E?

[Thomas E. Jorden:]

That's correct. Now we don't have -- we only have 1 Wolfcamp E test in Culberson County. That was a vertical test for a conventional reservoir, and that was unsuccessful. So currently, our deepest horizontal objective is the Wolfcamp D.

[Unknown Analyst:]

Okay. And with your Penn drilling, Penn Shale drilling, did you hold a sufficient amount of acreage or is that pretty de minimis?

[Thomas E. Jorden:]

Not in Culberson County. That's de minimis.

[Unknown Analyst:]

So overall, how much is held by production at this point?

[Thomas E. Jorden:]

For Penn Shale or for overall?

[Unknown Analyst:]

Probably just overall. For the Wolfcamp, ultimately which you're targeting now.

[Thomas E. Jorden:]

Yes, we don’t have that. John is guessing 1/3. I don’t -- we don't have that number readily available but we can get that for you.

[John A. Lambuth:]

Yes, I can tell you that we are on a capital program, that we've identified the minimum amount of capital we have to send in Wolfcamp drilling, and we're on a path to hold everything or essentially everything that we see as prospective. And that minimum amount, I think, was 125 million this year. It will be between 225 million and 250 million next year. And then it steps back down to the 100s for the year following. So without inordinate amount of capital, we're going to be able to hold all those Wolfcamp rights.

[Unknown Analyst:]

Okay. So it's not going to govern your CapEx program at the levels we're at?

[Thomas E. Jorden:]

I'm sorry, Gil?

[Unknown Analyst:]

So it won't govern -- it won't moderate or attenuate your program, given where we are today?

[Thomas E. Jorden:]

Well, it's -- yes, I wouldn't say it will moderate or attenuate, it certainly is an overprint. And right now, we have 2 rigs drilling Wolfcamp wells. With those 2 rigs, we can get this done. We will add a rig or 2 next year. But we did add, in addition to our 2 Wolfcamp rigs, we brought in 2 additional rigs to drill Second Bone Spring wells in Culberson County. And that was completely additive, that was without regard to the acreage holding to depth, and that was just because those Second Bone Spring wells are delivering lights out rates of return. But we're going to get those Wolfcamp rights held just fine.

[Operator:]

Your next question comes from Brian Gamble.

[Brian D. Gamble:]

I wanted to focus on the production side for a minute. I think Paul had alluded to it, the continued wide, I guess, train-size gap you've got for loan in high end of production. Is it safe to assume that with the...

[Thomas E. Jorden:]

That was a truck, that was not train, that was a truck.

[Paul Korus:]

It was a truck.

[Brian D. Gamble:]

A truck, sorry. I'm sorry, Paul. I didn't mean to put words in your mouth. We'll call it truck-size hole. At $1.5 billion and with all the success that you've been having, it seems like you're saying that the upper end makes more sense than the lower end, is that a fair assumption at this point?

[Paul Korus:]

We make no such assumptions. Like Yogi Berra said, forecasting is difficult, especially when it has to do with something in the future. And we don't know what's going to happen with ethane rejection over the upcoming months. And that always has an impact on our NGL volumes, we get a little uplift in gas volumes. But net-net, it's a negative on production volumes. We don't know whether we're going to experience that in 1 month, 2 months, 3 months, 4 months. It's not predictable.

[Brian D. Gamble:]

And that production gap right now includes how much rejection over the next few months?

[Joseph R. Albi:]

This is Joe. What we built into it is about 10 million or 11 million a day potential ethane rejection here during Q2. Now we don't know what it's going to be in Q3 so we didn't model that. But the other thing Paul is alluding to is there are some risks with takeaway capacity, particularly in the Permian that we're concerned about. We're seeing lower recoveries from the processing facilities that we're sending our gas to. We hope that, that's alleviated come Q3 with additional NGL takeaway coming into play from Sandhills. So all that being said, we're trying to forecast what we know right now with regard to recoveries in ethane rejection. To the extent it improves, I guess, it could bump the number up a little bit. But we're kind of modeling the world as we see now, and that midpoint of that range that I will call the Nissan small truck can drive through, that we feel like we can certainly attain.

[Brian D. Gamble:]

But you're never going to drive Nissans in Texas, come on now.

[Joseph R. Albi:]

Well, they're smaller trucks.

[Paul Korus:]

And in the Permian, as Joe mentioned, when the recoveries go down or one of the processors we go to is at capacity, one of the very smart things that has been done is that we have another outlet for the gas, for the wet gas. We may all end up regretting going to 3 stream reporting someday as an industry because these processed volumes of NGLs can really change, whereas our produced in metered volumes do not. So we may take a wet gas stream to a market because we can when we're shut out of capacity to process. Our produced volumes on a wet gas basis remain the same. But the way we count production from a reporting purpose, the way we all model it and what not, look different. So again, there's so many moving parts that -- my goodness, it's only May. To leave enough room or a wide enough production volume guidance is what we think is appropriate to do. As we get to the latter half of the year, as always, we'll tighten it down some.

[Brian D. Gamble:]

And then one other clarification point on that, you mentioned the 7 Mcf that was down during Q1. I'm assuming that a part of this ongoing saga that is downtime and what's up and what gets rejected, that 7 has carried over into Q2 to some extent?

[Joseph R. Albi:]

This is Joe. What we've seen, and I don't have the numbers right handy right in front of me now, but as you may recall last year, in particular in the Permian, things are getting tight. So we have seen 3 million up to 15 million a day type impacts on a particular month due to either turnaround or takeaway issues. The first quarter was really hit a little bit harder with the weather, and we have a lot of freezing issues, in particular on the Triple Crown facility that came into play there. So to the extent it's incurred, we don't necessarily sit up there and say, okay, let's just subtract 4 million or 5 million a day here or there. We're trying to forecast what we know we're seeing consistently, and we're not counting on bad things to happen, we're also not counting on great things to happen.

[Brian D. Gamble:]

Great. And then one more for me. Different topic, on the AFEs. Now correct me if I'm wrong, you rolled through them pretty quickly, but the best quarter-on-quarter change was in the Third Bone Spring's number down to 6.4 to 6.6 on AFEs. Was there anything specific that caused that 600k improvement quarter-on-quarter that either could potentially be rolled into the other wells or any other zones or was that just happened to be a great quarter?

[Joseph R. Albi:]

This is Joe again. There are things that we're doing in the Third Bone that we certainly hope to carry forward into where I'd say our next viable target is, obviously, the Wolfcamp. Without getting into the specifics of it, it really just means cross-pollinating technologies between the different groups in our drilling department, whether it be in Tulsa or the Permian, but be a little bit aggressive with our use of PDC bits, motors, our hole design, we're testing different fluids. And to the extent they work in one program and we're in the same darn area, I think you'll see us trying to apply it elsewhere.

[Operator:]

Your next question comes from Matt Portillo.

[Matthew Portillo:]

Just a few quick questions from me. I was wondering if you could give us a little bit of clarity on your Wolfcamp C and D results, if there's any difference in the liquids yields that you're seeing at this point. And as you move forward with that drilling campaign, is there a preferred interval that you're targeting from here?

[John A. Lambuth:]

This is John. Yes, so far within Culberson County, between the C and D, we do see a difference in the liquid content. And that as we move up in the section, from the D to the C, we definitely get richer in terms of our condensate NGL. Going forward, we still have our very -- and we will still make very good rate of returns in the D. And so as someone mentioned earlier, in terms of HBP in our acreage, we're always cognizant of making sure we're at least holding the deepest interval by HBP for future drilling. Furthermore, because of that change we see going from D to C, that kind of gives us encouragement in what we potentially might see when we finally get this A test done later this year. I mean, that has the potential to be even more liquids rich interval, but that said, we won't know until we actually get that well drilled.

[Matthew Portillo:]

As we think about kind of the wells we've seen so far, kind of in the 45% gas range, could you give us, I guess, maybe just a little bit of color around what the gas to liquids yield might be on the C? Just trying to get a better sense of what the liquids yield.

[John A. Lambuth:]

Well, of course there's a wide variation, it's a big area. But on average, in the D, I would say, we're seeing condensate that comes in between 80 and 100 barrels per million. Our recent wells are probably in the higher end of that range out of the D. We have some C wells that are significantly higher than that. In fact, we have a C well that's 200 barrels per million condensate. So we see much richer stream out of the C. That's also a reason why we suspect that they are independent reservoirs. They are 150 to 200 feet apart and that stacked lateral will be a really seminal test for us because we're strongly suspecting that they'll be able to be developed as completely independent horizontal targets, but we don't have that experiment yet.

[Matthew Portillo:]

And just on your Wolfcamp A result, you mentioned that the initial well result there was very encouraging. Could you give us some color on how we should think about the IP rate? I think you guys have a 30-day IP there. And maybe how we should think about the liquids yield on the Wolfcamp A in Reeves County.

[Thomas E. Jorden:]

Again, this is Tom. I was expecting earlier in the call we'd be grilled on the Wolfcamp A in Reeves County. So here's what we'll say about it. First off, this is a very competitive area. It's a big area and it's a competitive area. And so we're still out there competing for opportunity, and we're probably going to disappoint a lot of listeners in that we're not going to give granular detail on individual well results. A lot of other companies are and we listen to those carefully, and I will tell you that we're seeing results that are very consistent with what's being discussed in the industry. Wolfcamp A is an emerging target in Reeves County, we're very high on it. We are in the midst of a competitive leasing environment, and it's a major focus of ours. I will also say that we have plans to spend at least $160 million a year drilling Wolfcamp A targets over the next 2 years. And obviously, it's high in our list. But we're just not, at this point, it's just not in the interest of Cimarex shareholders for us to be giving detailed well-by-well results at this time.

[Matthew Portillo:]

Understood. And then just my last question on your emerging liquids plays, I was wondering if there's any update there. Or how many wells have you guys have tested and maybe when we should expect to get some color on the results you guys have seen?

[John A. Lambuth:]

This is John. Really no update, per se. I mean, we continue to look for new opportunities, as we've said. But just like we just had a discussion on Wolfcamp A, typically we're fairly conservative in talking about new plays, and we just don't have anything to say about any new opportunity for us right now. Are we pursuing them? Absolutely. We have a number of things in the hopper that we're looking at, formulating plans, potentially drilling, but really nothing that I can give any color to today.

[Thomas E. Jorden:]

Yes, I'll probably go a step further there. We had a couple of projects which we talked about in vague terms. One, I'll tell you, we think is not going to work. The second one, we're currently in the process of drilling in. It's our third well on the play, and we'll say a little more about it in the future.

[Operator:]

[Operator Instructions] Your next question comes from Gail Nicholson.

[Gail A. Nicholson:]

I just was kind of curious on the longer lateral that you're drilling in the Permian. If you could give any color on what you're seeing there and is that kind of, I guess, the way you're going to kind of drill these wells in the future.

[John A. Lambuth:]

This is John. Well, we're very early in terms of our long lateral drilling. We have a number of examples in some of the different intervals. And although we are encouraged by what we see out of those, there are some things we have to overcome. Cost. Drilling longer laterals, it definitely takes more money. But that said, we definitely see for a number of plays where longer laterals is probably where we are headed. Now again, that's also a matter of acreage, what we have available to us, where we can drill those longer laterals. But I would say, it would not surprise me in the coming year or 2, that you're going to see more and more of our program go -- head more toward those greater than 5,000-foot type laterals. I think that's a fair statement.

[Thomas E. Jorden:]

We just don't know yet. We did drill a long lateral in Culberson County, a Wolfcamp D lateral. The Delaware Basin is different than the Midland Basin. And certainly, we're well aware of the long laterals in the Midland Basin and the logic behind those, cost savings improvement that they observe. Delaware Basin, we're deeper and we're more pressured. And both those work against long laterals. Our long lateral in Culberson is kind of a betweener, as far as -- it's a good well, but does it justify taking that risk to drill a long lateral? We're kind of on the fence there. We do have a long lateral in Reeves County that we haven't completed yet. And we just don't know. So we're very much interested in looking at long laterals as a way to increase our returns. But it's a little more complex than that because we are deeper and more pressured and that can lead to mechanical problems and there can be a situation where you say it's just not worth messing with.

[Operator:]

Your next question comes from Jeb Bachmann.

[Joseph Bachmann:]

It's just a quick one for me on kind of looking forward towards year end. First, looking back at year end '12, you guys didn't have any PUD bookings in the Permian, and looking forward to the end of this year, just wondering kind of what's your philosophy is regarding that. I don't believe you have a down spacing pilot in the Wolfcamp yet. But looking at the Bone Spring, just kind of any color you guys can provide on that.

[Joseph R. Albi:]

Yes, this is Joe. I'd say we'll give you the same answer as I believe we gave last call. Cana, by far, has lent itself to the PUD bookings because we felt very comfortable in the pilot project that we have done and with our infill projects. So it lent itself to PUD bookings. We don't know the spacing on the Wolfcamp. I'll just take it as an example that we'll drill down to. So without a pilot, you won't see us just jumping out and booking a bunch of PUDs there. To the extent the Bone Spring is call bookable, those locations are kind of one leads to the next to the next to the next. And with that, it doesn't lend itself to a broad booking of PUD reserves. If we can get a pilot under our belts in the Wolfcamp, I certainly see us being in a position where we're going to feel comfortable doing that. And then most importantly, we're very strict about the 5-year rule with the SEC. What we book, we want to make sure we can drill within the 5 years. So to the extent it plays into our overall budget, it's going to have a role in their decision as well.

[Thomas E. Jorden:]

Yes, Jeb, what we will probably do here, as we get into the year, in the Permian, we'll probably do exactly what we did at Cana. Rather than go aggressive on PUD booking, we'll choose to be just more forthcoming of the inventory as we see it. And then let the investing public value it as they will. But we do take a fairly conservative viewpoint on actually booking PUDs, as Joe mentioned, for a lot of reasons, not the least of which is the 5-year rule. But we'll be more forthcoming, I think, on what we see our future investment potential.

[Joseph Bachmann:]

And Tom, do you guys have an idea yet when you'd actually drill that down spacing pilot in the Wolfcamp?

[Thomas E. Jorden:]

It won't be this year. This year, what we are hoping to do is, one, get a Wolfcamp A and get a Wolfcamp C, D stacked lateral. But while we're -- I'd like to say next year, it will be on our list. We fully recognize that it's to our benefit to understand that spacing early on the play, not later. But right now, Jeb, we don't have it on the docket. It's not on our rig schedule.

[Operator:]

Your next question comes from Cameron Horwitz.

[Cameron Horwitz:]

Tom, I know you don’t want to get into specifics on Reeves. But can you just give us the -- where you guys are in terms of HBP-ing that acreage and what you have to do to maintain that? I think you were at 35,000 acres there.

[Thomas E. Jorden:]

Well, we've only drilled a few wells. So you can kind of do your math there, that 160 million a year is to hold our acreage. So we're going to get after it, and our plan today is to hold that acreage primarily with Wolfcamp A drilling. I think that answers your question.

[Cameron Horwitz:]

It does, yes. And then just in terms of the well cost, do you expect well cost there to be similar to Wolfcamp [indiscernible]?

[Thomas E. Jorden:]

So far, that's our viewpoint. I mean, we're looking forward to getting that drill time and cost down, but right now, a Wolfcamp A AFE, we see a 7, 7.2.

[John A. Lambuth:]

Yes, this is John. It is right in the mid-7 range right now. But again, we're early in that play. So like any other play, we expect that to come down as we drill more of those wells.

[Operator:]

And we have no further questions at this time.

[Thomas E. Jorden:]

Thank you, everyone, for joining us today on the call. We look forward to seeing you in the future conferences, and report back to you next quarter. Thanks a lot. Talk to you later. Bye.

[Operator:]

Thank you for your participation. This concludes today's program. You may now disconnect.