Cimarex Energy Co.
Q3 2013 Earnings Call Transcript

Published: 6 Nov 2013

[Operator:]

Good afternoon, and welcome to the Cimarex Energy Third Quarter Earnings Conference Call. [Operator Instructions] Please note, this event is being recorded. I would now like to turn the conference over to Mark Burford. Please go ahead, sir.

[Mark Burford:]

Thank you, Chad. Welcome, everyone, and thanks for joining us today for our third quarter conference call. On today's call here in Denver, we have Tom Jorden, President and CEO; Joe Albi, EVP and COO; Paul Korus, Senior Vice President and CFO; and John Lambuth, Vice President of Exploration; and Karen Acierno, Director of IR. We did issue our financial and operating results news release this morning, a copy of which can be found on our website, and I need to remind you today's discussion will contain forward-looking statements. A number of factors could cause actual results to differ materially from what we discuss. You should read our disclosures on forward-looking statements in our latest 10-K and other filings, and news releases for the risks associated -- factors associated with our business. So with that, we have a lot of good things to cover today. I'll go ahead and turn the call over to Tom.

[Thomas E. Jorden:]

Thank you, Mark, and I want to thank all of you for participating in today's conference. We sincerely appreciate your interest in Cimarex. I'm going to take a few minutes here at the outset to touch on some of our highlights for the quarter, and then I'll turn the call over to John and Joe for a more detailed update. We reported another great quarter of production, averaging 717 million cubic feet a day, which was above the upper end of our guidance. Solid production, coupled with strong product prices led to adjusted cash flow from operations of $394 million, which was more than enough to fund our exploration development expenditures for the quarter. Our debt-to-cap stand at 19%, a slight drop from June 30, as our debt increased only slightly while strong earnings added to our shareholder equity. Operationally, this has been an exciting year for Cimarex and the third quarter was no exception. I want to complement our entire organization for delivering these results. We're a focused team. We're a talented team, and everybody's dedicated to bring it for our shareholders, and it really was a nice quarter. We have a great group of people throughout our organization, and they're firing on all cylinders. We're able to report very encouraging results from 2 new complete -- 2 completion techniques in the Wolfcamp, and I'll touch on that in a moment. In Culberson County, we completed the Tim Tam well to the Wolfcamp diesel in using a 5,000 foot lateral and a 20-stage frac. This is the new completion technique that we've talked about. The incremental cost of $700,000 provided us with a 25% uplift to the 30-day IP rate [indiscernible]. That rate increased to 7.8 million cubic feet a day compared to our historical Wolfcamp results of 6.2 million cubic feet a day. That well is 31% oil, 30% natural gas liquids and 39% gas. So it's a stellar well. As most of you are aware, the Wolfcamp is especially attractive in Culberson County because of the stacked pay potential offered in the Wolfcamp D, C and A sections. During the third quarter, we drilled our first Wolfcamp A test in Culberson, and although we don't yet have a 30-day IP, the early results look very encouraging. This well is also completed using the 20-stage frac design. We'll release the specifics on this well when we have 30 days of production. Obviously, as I said, we're encouraged, but we find 30 days to be a more meaningful number than in the instantaneous so we're going to defer the release of that. In Reeves County, we announced the Ruby 139H, a Wolfcamp A test, using a 10,000-foot lateral. It's a stellar well with a 30-day IP of 1,816 barrels of oil equivalent per day, 56% of which is oil, which is over 1,000 barrels a day on average for its first 30 days. This compares favorably with our previous 2 Wolfcamp A wells in Reeves that were completed using 5,000-foot laterals and had an average 30-day IP of 925 barrel of oil equivalent per day, which was 63% oil. The Wolfcamp play is continuing expanding in the Delaware Basin. It's moving east where the Wolfcamp A thickens. It's moving into the Ward County area where we've historically had our Third Bone Spring development. In September, Cimarex added 10,000 acres in Ward County. We now have 1 rig drilling wells in Ward County. So we have a nice position there. This is really an exciting emerging play for us, and as we get more data, we're getting more and more excited about it. So far, we drilled 44 Wolfcamp wells on our 180,000 net perspective Wolfcamp acres, and it's fair to say we're just getting started. We haven't released our 2014 capital guidance yet. But as we look into 2014, I'll say, we're really looking at 2014 in this Wolfcamp play with several different goals. We want to continue to hold our acreage. We want to delineate the play and really understand the extent of it, but we also are asking ourselves question of working our program so that by December of 2014, we'll be able to have the information we need to make ultimate development decisions. And that means information on spacing, both laterally and vertically, so we need to know are we at 80-acre spacing, are we at 40-acre spacing, are we at 160-acre spacing. How many zones that applies to and can we stack them on top of one another. So in 2014, we'll have quite a few different pilot projects going, quite a few different stack lateral projects going. And by the end of the year, we'll have the information we need to make good investment decisions on the structure of the project and the timing as we go to down spacing. We have long-term plans that we're currently formulating, and we have to make those plan so that we plan our infrastructure. We plan on our financing. We plan on our ultimate development. So it's an exciting emerging play. It's one that, obviously, our recent results are making look better and better, and these tests go a long way in getting Cimarex the information we'll need to make development decisions for 2015 and beyond. We look forward to sharing those results with you as we go. So with that, I'll turn the call over to John Lambuth to discuss our drilling results in a little more detail.

[John A. Lambuth:]

Thanks, Tom. I'll cover some of the specifics of our Permian and Mid-Continent drilling programs. Cimarex has had an active 2013 program, investing $1.2 billion to drill 291 gross, 147 net wells so far this year. 65% of that investment was in the Permian Basin with another 31% going to our Mid-Continent region. We estimate our total E&D capital this year will be around $1.55 billion to $1.6 billion, up slightly from our last call, mostly as a result of the expansion success of our leasing efforts in the Permian region. I'm going to first cover the Mid-Continent area. The Cana-Woodford Shale play continues to drive activity in our Mid-Continent region. So far this year, we've participated in 134 Cana-Woodford wells, and estimate that Cana will represent $400 million of the $475 million we'll spend in Mid-Continent capital this year. Including non-op activity, we're on track to drill and complete about 35 net wells in Cana in 2013. As Joe will discuss in further detail, well costs in Cana have dropped significantly, which is having a positive impact on our returns in this liquid-rich gas area. Cimarex is now operating 3 rigs in Cana. One more operated rig is actually scheduled to begin drilling later this month, bringing our total operating rig count to 4. We are adding these rigs to keep pace with our partners development plans between now and end of the year. Our intention is to move these 2 new rigs down to the Permian Basin by the end of this year. Speaking of the Permian Basin. We've drilled and completed 132 gross, 87 net Permian Basin wells this year. Our drilling program has been focused on the Bone Spring and Wolfcamp formations in the Delaware Basin. We've had a very active Bone Spring program in 2013. We have drilled and completed 106 gross Bone Spring wells in New Mexico and Texas. Results continue to be good, generating some of the company's highest rate of returns, with oil representing up to 84% of first 30-day production. I'll refer you to the press release or most recent presentations for specifics on each of the Bone Spring programs results year-to-date. We have around 200 to 300 Bone Spring locations identified, the majority of these located in Culberson County, where we have identified a thick, highly productive Second Bone Spring sand. In fact, during this past quarter, we finished drilling 5 new -- or essentially 5 wells per section in the Second Bone Spring interval, essentially new development wells in addition to the existing initial well. The performance of these new development wells is on par with the original wells. We're very encouraged with those results in that play. Moving on to the Wolfcamp. Culberson County has a number of very exciting developments, including upsized fracs and a Wolfcamp A test. As Tom mentioned, we have drilled our first Wolfcamp A well in Culberson, and completed it using a 20-stage frac. The well named the Twenty Grand 26 #1H is currently flowing back, and as anticipated, has a higher liquid yield in the C or D interval. This is the second well we've completed using this upsized frac design. We've also completed the Tim Tam 24 #1H with the larger 20-stage frac. This Wolfcamp D test has a 30-day average rate of 7.8 million cubic feet equivalent per day, which, as Tom mentioned, has a 25% increase over our average Wolfcamp D well. At a drilling complete cost of $8.7 million, this well generates an A-tax rate of return of over 40%, a very good result. Moving now East in the Reeves County, we drilled and completed the Ruby 139H, a 10,000-foot lateral drilled into Wolfcamp A. As mentioned, this is a stellar well with first 30-day IP average production of 1,816 barrels of oil equivalent per day, 56% oil, 21% NGLs and 23% gas. Of note though is the 60-day average rate, which is holding in at 1,728 barrels of oil equivalent per day, 58% oil. This, again, is typical of what we've seen from our log laterals, and that we see slower declines from these type of wells. This is pretty amazing well, especially considering it's not even using our newest stimulation. This was our old stimulation for this well. We'll be watching this performance as well as trying upsized fracs in the other Reeves County wells to better gauge how to achieve the best completions going forward. Our teams are doing a great job of focusing on maximizing returns on our drilling and generating future drilling inventory. We have a strong land position, including 180,000 acres in what we call the Wolfcamp fairway, which extends from our Southern Eddy Culberson area over to Reeves, and continues into Ward County. We have lots going on across our acreage. In Culberson County, we're currently drilling our first 10,000-foot lateral in the Wolfcamp D interval, and are planning a stacked Wolfcamp CD test, as well as a down space pilot for the first quarter of 2014. We continue to add acreage, as Tom mentioned, Ward County, where there, we'll soon be testing Wolfcamp A wells and currently plan to have 1 rig drilling continuously in that area. We have also found the completion technique that looks like it could potentially unlock the Avalon Shale on a portion of our acreage. We look forward to continue testing of the oil Avalon in Southeast of Mexico. Wrapping up this exciting time at Cimarex, we have a great asset base, and are well positioned to take advantage of this significant opportunity set. With that, I'll turn the call over to Joe Albi.

[Joseph R. Albi:]

Well, thank you, John, and thank you, all of you for joining our call today. I'll touch on the typical items, our third quarter production, update you on our fourth quarter guidance projections, and then I'll follow up with a few words on our operating and service cost. As Tom mentioned, we had a great quarter. Our Q3 volumes came in at a record $717 million a day. That was well above the upper end of our guidance of $675 million to $700 million a day. It was up 30 million a day from last quarter, and up 13% from Q3 last year. If we adjust for the property sale that we had at the end of last year, which equated to about 15 million a day of production during Q3 '12, we were up 16% from the third quarter of '12. Although we saw limited impacts from plant facility downtime during the quarter, we did continue to see ethane rejection in Cana, which reduced our quarterly equivalent volumes by approximately 12 million to 14 million a day. We're anticipating that to continue, at least, for the remainder of this year and we, therefore, built that type of reduction into our fourth quarter guidance. As we dig deeper in the details, our Q3 Mid-Continent volume of 338 million a day was up 4% from Q3 last year when we reported 324 million a day. Cana drove the increase, continues to drive the increase. Cana came in at 217 million a day here in our Q3 '13. That's an 18% increase from a year ago. Sequentially, our Q3 Mid-Continent production was down 1% from the second quarter level of 343 million a day, but we had a couple of factors coming into play here. First, we saw ethane rejection for the entirety of the third quarter as compared to just 2 months in Q2. And secondly, the majority of our production adds from our operated Cana completions came on in late Q3, and therefore, Q3 didn't see the full benefit of that increase in production. In the Permian, our reported net equivalent volume of 352 million a day was up 28% or 77 million a day from Q3 '12. Permian oil production was the driver here. We averaged nearly 32,000 barrels a day from the Permian, oil-wise, during Q3. That's up nearly 7,000 barrels a day from a year ago or up 28% from last year. As compared to the second quarter, we also saw significant growth with our Permian equivalent volumes up 10% or 32 million a day, and our Permian oil volumes up 6% or 1,856 barrels a day. All of this, a direct result of our very active Delaware Basin program. With our strong third quarter and the positive overall results of our programs, as you've noted, we bumped our 2013 full year guidance range to 695 million to 700 million a day. That increases the mid-year of our full year guidance to 698 million a day. That's a nice jump from our previous midpoint estimate of 690 million a day, especially when considering they were incorporating anywhere from 12% to 15% -- 12 million to 15 million a day of reduction into our fourth quarter numbers due to ethane rejection in Cana. With our fourth quarter guidance projection of 714 million to 734 million a day, we anticipate yet another quarter of sequential growth for Q4, albeit not forecasted to be as strong a jump as we saw from Q2 to Q3, and there's a few things that work here as well. In addition to varying working interest, rates, product types, recoveries, projected timing to first sales for all the wells that we'll complete during the quarter, we slipped in the drilling of a salt water disposal well into one of our Permian rig lines, which took the slot of a producer. And we have accounted for some likely downtime for the maintenance of our triple crown system later in the quarter. The end result, when it does settle, however, is that we will see continued significant quarter-to-quarter production growth for Q4, again, a direct result of our activity in both the Permian and Cana. We're pretty proud of where we see ourselves ending the year. With the full year guidance range of 695 million to 700 million a day, we're projecting year-over-year production growth of 11% to 12% as compared to 2012. If we account for the property sales at the end of last year, we're projected to be upwards of 14% year-over-year with our production growth. On the LOE side, our Q3 lifting cost came in at $1.15 per Mcfe, slightly below the midpoint of our full year guidance range, which was $1.10 to $1.22, and fairly well in line with our Q1 average of $1.17 and our Q2 average of $1.11, although we're seeing some cost pressure for our increased activity for the most part in items such as SWD, compression, power, fuel and rentals, our operations group has done a good job keeping our lifting cost in check, I'd say so, especially in the Permian, where we generally see higher operating expenses for items such as lift, compression and SWD. In fact, with our focus on LOE over the last 3 years, we've been able to reduce our Permian lifting cost from $1.88 per Mcfe in 2011 to $1.50 in 2012, and we're currently on track to see levels of around $1.47 here for 2013. So with Q3 coming in at $1.15 per Mcfe, we did end up tightening our 2013 lifting cost guidance range to $1.11 to $1.16. That did drop our midpoint to $1.14 for the year, and that's down $0.02 from our previous projection. With regard to service cost, we continue to see most drilling costs components remaining relatively in check, it's been that way for the last 2-plus quarters. Day rates continue to hold flat with rigs still available, and there does seem to be ample availability of tools, equipment and services for each of our programs. With flat cost for most of the year, the cost reductions we've seen to date have come through our operating efficiencies. We continue to focus on cutting down days to drill, and we've made some pretty good strides, especially in the Permian. As an example, we continue to use of bit technology and rotary steerables during Q3. We decreased the average days to TD in our Culberson Second Bone program down to 15 days, which is a drop from 17 days in Q2 and a drop from 25 days in late 2012. On the completion side, we've had no difficulty securing frac equipment and crude, and we continue to experiment with different frac designs. In general, our per well frac cost have stayed fairly well in check, with this partially offsetting the cost of larger jobs with increased efficiencies and reduced material costs. In Cana, after numerous years of program drilling, we continue to see cost improvement. Our recent core wells are now falling in the range of $6.5 million. That's a marked improvement from last quarter when we quoted total well cost of $6.8 million, and well below the $7 million to $7.5 million levels we saw in late 2012 as cost reductions, as John mentioned, have had a significant impact on generating some nice healthy rate of returns in the Cana program. In the Permian, our most mature Second and Third Bone Spring programs have seen the greatest benefit from program drilling. Our current New Mexico Second Bone Spring AFEs are running $5.7 million to $6.5 million, depending on debt. That's down slightly from last quarter, but down $400,000 to $500,000 from where we started at the beginning of the year. Our shallower Texas Second Bone Spring AFEs are running around $5.1 million. That's about flat with the number we quoted to you last quarter, but we're down about $0.5 million from Q1. In our West Texas third Bone program, we're seeing AFEs continue to hold flat around $6.4 million to $6.5 million. Again, that's well below the $7.5 million-plus numbers that we were seeing in 2012, all of this as a result of program drilling. In the Wolfcamp, we're still in the early stages of our program drilling, especially when we consider the broad geographic area we're testing with the play. The 180,000-acre position we have extends from Southern Eddy County, New Mexico down into Culberson Reeves and over to the east into Ward Counties and Texas, fairly broad area. And as we've drilled across that area, we've encountered some fluid loss issues in some portions of the play. In particular, the Southern Culberson area, which has forced us to experiment with and even alter the design of our wells. Second factor that's coming into play, as John mentioned, is we've also upsized our completions into Wolfcamp. And albeit at the same time seeing some very favorable results, those upsizes and completion techniques are adding about $700,000 to our total well cost. And so now, as we go forward to account for both those items, our current generic Wolfcamp AFEs are running in the range of $7.8 million to $8.7 million, with our Culberson wells on the higher end of that range and our Reeves, Ward County wells on the lower end of that range. To the extent we push out the lateral lengths in the Wolfcamp with only a few wells under our belt, and I want to emphasize that, this is only with a few wells underneath our belt, we see our early total well cost for a 2-mile lateral to fall in the range of $13 million to $14 million, depending on whether or not we drill a pilot hole, and then obviously depending on the size of the completion. And if we were to drill a 7,500-foot lateral, we would take approximately $2.5 million to $3 million off those numbers. But again, we've drilled less than a handful of long laterals down there. And as we do with every well, each and every well, we learn more. As Tom mentioned, we're really just getting started in the Wolfcamp, not only from the geologic and reservoir side, but also on the drilling side. We're certainly in the early stages of fully understanding and developing the play. That said, similar to what we've seen in Cana and Permian with our Bone Spring programs, we fully anticipate program efficiencies to take root in the short term here in the Wolfcamp and show up in the form of decreased well cost as we take the program forward. So in closing, we had a great quarter. As John mentioned, our programs are doing well, seem to be hitting on all cylinders. We saw record Q3 production. Our LOE's in check, and we continue to see improvements in our development cost for program drilling. So with that, Chad, I suppose we'll turn the call over to question and answers.

[Operator:]

[Operator Instructions] Our first question comes from Brian Gamble with Simmons & Company.

[Brian D. Gamble:]

Wanted to start with the longer laterals and the increased frac stages. Maybe you could go through both. How many more wells of each type are you guys thinking about doing before making that a standard? And then to that end, are there pieces of your asset base where those sorts of techniques don't work? Or is it just a matter of determining that that's the best use of a well in each location as the case may be?

[John A. Lambuth:]

Yes, this is John. Let me first address the increased frac size jobs. I will tell you that we've seen enough, not just in the wells that we've talked about today, but even the wells that are early flow back, that we're very encouraged with the results we're seeing there. Going forward, right now, all of our Wolfcamp wells, regardless of Culberson or Reeves or wherever they are located, all off them are planned with an upsized frac job going forward. Now obviously, we will monitor those results as we go forward to make sure that the increased cost is justified. But as I mentioned earlier, so far, every early indication, including the Tim Tam well will say that this is the right thing for us to do. In regards to extended laterals, no, that one is something that we just don't have that many under our belt. But again, I would say, so far, the few we do have, we're very encouraged with the type of production profile we see from them and the type of rate of returns that they're generating, but that's also a function of our acreage. Some acreage may allow us to do that, some may not, and it also will be a function of just how comfortable we get with just the drilling and completing of these. As Joe mentioned, we've done a just a few of them, and then they're not easy, especially the 10,000-foot laterals. We do run in to some completion difficulties that I think we're going to overcome over time, but when it comes to extended, that's going to take a little bit more time on our part before we get more comfortable. Broad strokes saying we do that everywhere.

[Brian D. Gamble:]

Great. And then as my follow-up, Tom, you mentioned you wanted to have the Wolfcamp essentially fully delineated by the end of the year. It seems like a pretty bold task. Maybe you could walk us through how you're trying to get your guys to think about it and how many one-off wells that really means, how many down spacing wells that really means to fully understand that play in the next 12 months.

[Thomas E. Jorden:]

Yes, hopefully, if I use the word fully, I'll go back and edit the transcript, but we're just -- we have long-term plans. I mean, this is an asset base, when we look at it, when you look at our acreage position, there are -- it's really emerged as multiple zones almost everywhere. I mean, we've talk about Culberson County. We knew we had a D zone that was productive. We knew we had a C zone, and we speculated that we'd have an A zone. And now at least, with the 1 well we've tested, I think we can say we've had very encouraging results. Even in Reeves County, one of the things that's changed in the last 3 to 4 months is that it's also emerging as a multiple zone. We think there may be as many as 3 or 4 independent zones in Reeves County, and that's based on our own experience, but also some of our competitors are helping us there. So what we're doing is we're looking long-term with an asset that size. Our first goal, of course, is we're going to hold every acre that we view as perspective, and so we're still drilling to hold acreage. We're still acquiring new acreage. But we're also looking ahead to when it will be appropriate for us to go into a development mode. And it's probably going to be a case where we'll go into development mode in some portion, while we're still holding to drill acreage in other areas of the play. So in order to make good decisions on development mode, we have to know spacing in terms of how many wells per section, how many zones per section, and can we put those directly on top of one another, do we stagger them. So just to repeat what I already said, in 2014, we're going to be doing some spacing experiments both vertically and horizontally to make really good, at least, intermediate-term development decisions. And why? Well, one is some of our best returns are coming from development and we like returns. Secondly is we have to think ahead in terms of getting the midstream take away capacity to facilitate development, and then third is we have a great balance sheet. We're outstanding position, but we don't want to be surprised by financing these either. So we're really looking at some long-term plans. I don't know that we'll have it fully delineated in 2014, but we are steering our experiments to gather as much of those critical pieces of information so we can make some really good decisions on development.

[Operator:]

Our next question is from Ryan Todd with Deutsche Bank.

[Ryan Todd:]

I know you won't give official 2014 guidance until early next year. But can you talk a little bit about general trends in 2014 spending levels, how much you might be wanting to spend relative to cash flow? And possibly, any granularity that you can provide around maybe year-on-year increases in County or Wolfcamp versus Bone Spring, anything of that order?

[Thomas E. Jorden:]

Sure, Brian, this is Tom. Yes, we've talked openly that we would be comfortable increasing our borrowings next year a little bit. I think we wouldn't have hard time borrowing $200 million to $400 million next year, and that's certainly not a limit on that. I mean, we're going to look at our programs. We're going to look at our opportunity set, look at the prudent pace of development. I would expect -- so our capital next year, I think it's reasonable to think it will be up a little, given that commodity prices hold and we continue to have the kind of success we're having. And I would look for a slightly larger percent to be in the Permian than it was this year. I mean, we're -- we'll be upsizing our Permian program. We have a great opportunity set and lots to do. As far as Bone Spring versus Wolfcamp, I think it's going to be a higher Wolfcamp program as a percent of our total capital, and that's just naturally evolving to -- for us to develop this really premier resource play.

[Ryan Todd:]

Are there any areas of the Wolfcamp, in particular, where you see -- like over the next 12 months, where you see infrastructure being more of a bottleneck than in other places?

[Thomas E. Jorden:]

Well, there's the Delaware Basin involves infrastructure planning. And so everywhere we're working, we're putting a lot of energy in the infrastructure. Our operations, our marketing, our midstream group has done a phenomenal job getting ahead of it. We're currently planning very diligently, and I'm very confident that we're going to be ready for program when they come online. Joe, do you want to add to that?

[Joseph R. Albi:]

Yes. I'd echo what Tom said here, as far as our 2 biggest areas, the Triple Crown area, we've obviously got our main 34 mile trunk line that we're trying to stay out 6 months ahead of our anticipated development from a well standpoint to make sure our laterals are in place, our CDP is in place, our CDPs are in place. We're looking forward to salt water disposal wells to try to get out ahead of any water disposal, in particular, in Reeves County where we're seeing more water. In Triple Crown, we're looking for and have obtained additional markets coming off the middle of that pipe. So we will have, at least, have gotten further down the road of trying to maintain and capture some of that market optionality that we have out there in the area by now, have the markets to the north in the middle and to the south with our own JT. In Reeves County, we're putting the infrastructure together to be able to handle a fairly healthy Wolfcamp Bay development program, not only from the gas takeaway standpoint, but also from the salt water disposal infrastructure and even the oil takeaway. So we are -- that is one of those areas that we have to be out ahead of this type of development in these plays.

[Thomas E. Jorden:]

Yes, this project, as you can tell from our release, as we get more information, it's getting better and better. And the mandate we have to our organization is let's get that infrastructure out ahead, so that if we increase our capital, we're ready for it. So we're planning for success.

[Ryan Todd:]

And I guess if I could ask one -- that's very hopeful, and if I could just ask one more. You mentioned a tighter spacing test you did in the Culberson County Second Bone Spring. I think 5 wells in the section rather than the traditional 4, and that the results were kind of in line with expectations. Is that -- should we expect that to be from your base case from now on or is that something you feel like you need to test more broadly across the play?

[John A. Lambuth:]

Ryan, this is John. I think it's safe to say for similar net thicknesses across the section, then that certainly would be our base case, going forward, in that immediate area, and I want to stress, that immediate area. But I would also say there's still room to test additional things there. I mean, this was not much of a step-up to go from 4 to 5, but we are very encouraged by that. And so even internally, we ask ourself, is that still the right spacing, but so far, we've been very pleased just with those initial 5 well results to date.

[Operator:]

The next question is from Gil Yang with DISCERN.

[Gilbert K. Yang:]

Yes, maybe following on to that question. Is it probably fair to say that while you don't know what the spacing should be in the Bone Springs, are you closer than what it might be for the Wolfcamp because of the tighter formation?

[Thomas E. Jorden:]

Gil, this is Tom. We don't know. I mean, we haven't tested it yet. And one of the things, of course, these upsized fracs we're talking about, it's taking the industry by storm. It's not just Cimarex. If you look from basin to basin, you obviously -- a lot of our peers are coming forward with the same evolutionary or even revolutionary change in completion technology. And the primary benefit, in addition to uplift in production, is greater near wellbore recovery and potentially a tighter spacing. So with this upsized completion technique, we're probably now more interested in exploring tighter spacing than we were before, and we were obviously deeply interested. So we need to get out and test it. I mean, this Wolfcamp is a thick, thick section, and we might still be underestimating the number of laterals we can put in it. So we've got to get out there and test it. We can do all the forward modeling in the world, but until you to drill, test and have empirical evidence. Your confidence is very low.

[Gilbert K. Yang:]

So it sounds like, not only are you going to be testing the lateral spacing, you're also going to be staggering the wells, Chevron-ing them within a thicker section so that the -- they may still be relatively far apart, but when you look down upon in sort of the helicopter view, they're close together?

[Thomas E. Jorden:]

Yes, no, Gil, you said Chevron-ing, we may get there. Our first test will be putting them directly in the top of one another just to see if that works. And then if we can stagger a Chevron, then we can do that as well. But it's -- as I said, it's a huge resource. And in Culberson County, there are now 3 independent zones producing, and in Reeves County, there are now 3 independent zones producing. Now we don't have those 3 independent zones, but if we look at our competitor activity, there are at least 3 different landing points in the Wolfcamp producing, and so a lot and lot of work to do to find its ultimate potential.

[Operator:]

Our next question is from Ipsit Mohanty with Cannacord.

[Ipsit Mohanty:]

Just looking at your Wolfcamp curve that you've provided before and then seeing your press release, it kind of seems like the oil percentage in the yield mix has gone up. Is that a function of doing more of the Wolfcamp C? You've talked about how maturity sort of reduces as you go shallower, and that's where we look forward to the A as well. But is that a function of more of Wolfcamp C versus D?

[Thomas E. Jorden:]

Well, first off, I guess the tight curve that we published is on the average compilation of a lot of D wells that we've drilled. Pretty sure, it's just D, the tight curve. And you have to keep in mind that even within the D, geographically, as you move throughout Culberson, you're going to get variations in yield. And so there is an overprint of geography relative to just that tight curve. So that overprint is probably there. In terms of this latest well we announced, it does seem to have a slightly higher yield. But I don't know that I could say that that's a definitive trend yet or not. I mean, we need more wells on our belt to really establish that that's happening.

[Thomas E. Jorden:]

Yes, but the A is oilier than the C and D. So as we bring a lot more of our Reeves and Ward County into development, we're going to see an oilier overall mix, and the A in Culberson looks like, as we predicted, it's oilier than the C and D.

[Ipsit Mohanty:]

And just moving a bit for a second to the Avalon, is it too early to ask you sort of number of potential locations that you can talk about? And in addition to that, what's your leftover locations left in the Bone Spring to drill?

[Thomas E. Jorden:]

Well, first, on the Avalon, given our current acreage position, we see around 200 to 250 locations currently with our position just in that kind of Southern Southwestern part of Lea county. And I'd just caution because that's really where we see right now the really good returns, and that's where we focus our efforts. So 200 to 250 locations there. When it comes to Second Bone Spring, it's as we've always said, it's the revolving inventory that, as we drill up, we come up with new ideas. We keep adding and we're still sitting there with that 200 to 250 locations for Bone Spring as well. Culberson is now taking a bigger share of that. Obviously, as we drill more and more in Culberson, we get more and more confident of additional locations there, but it's still that ever-moving kind of 2-year program, and that's kind of how it's been a trademark for us for the last 4 or 5 years.

[Ipsit Mohanty:]

And my last, if I may, then how comfortable you would be yet. But you gathered some acreage in Ward County. That's getting a lot of good positive vibe. Would you care to comment on the cost play that you've got there, how much did you spend per acre?

[Thomas E. Jorden:]

Well, we -- yes, this is Tom. We bought it at a public sale, so it's public record and then...

[John A. Lambuth:]

Yes, we've advertised that at the sale, we picked up approximately 10,000 acres, and we spent $25 million. So 2,500 an acre at that sale.

[Ipsit Mohanty:]

That's a great buy.

[Thomas E. Jorden:]

Hope so. we'll get back to you on that.

[Operator:]

Our next question is from Jeb Bachmann from Howard Weil.

[Joseph Bachmann:]

Just wondering, Tom, if you can give us an idea of the rig count, operated rig count exiting this year in the Permian and where those rigs will be working.

[Thomas E. Jorden:]

Well, we currently have 12 rigs working in the Permian. And of those 12 rigs, 8 of them were drilling Bone Spring plays, and that's several different Bone Spring plays, but those are sands, more conventional reservoirs, and 4 of them are currently drilling in the Wolfcamp shale. Of those 4 in Wolfcamp shale, 2 of them are in Culberson County. One is in Ward County, and one is in Reeves County. So amongst that Wolfcamp play, we have 4 active rigs. As John said, our plan is probably not by year end, but probably around year end, we'll have 2 additional rigs moving into the area, and certainly, we'll see an increase in Wolfcamp drilling. So I think you'll probably see, going into next year, we'll probably, early on the fourth quarter, have 14 rigs running and probably the increase will be Wolfcamp.

[John A. Lambuth:]

No, that's right, Tom. I think you can anticipate that beginning of the year kind of about an even split between what we call Bone Spring Avalon versus Wolfcamp. But keep in mind, at any one time, we move those rigs around. I mean, there's a lot of moving parts there to rig schedule in terms of permitting or what's ready to be drilled, but that's a fair look at it going forward into '14.

[Joseph Bachmann:]

Okay, great. And then just quickly on the Avalon, give us the cost on that first well there.

[John A. Lambuth:]

Our generic AFEs for Avalon are running around $7.3 million, $7.4 million.

[Thomas E. Jorden:]

I think we've been hitting that. We're doing a nice job there.

[John A. Lambuth:]

No, it's right just north of $7 million, drilling complete.

[Joseph Bachmann:]

Okay. And then last one for me. Any idea what's causing the fluid loss in Culberson?

[John A. Lambuth:]

Well, yes. There's area there where we have, in the shallower section, a highly fractured interval, mostly Avalon. And as we drill through that, we take massive losses, and so we don't see that -- we don't see that most parts of the play, but we have experienced it with quite a number of wells, and so we adjust. As Joe alluded, we'll either make adjustments to our pipe program or we'll make adjustments just to the ability to just take those losses and get our way through it, and then get pipes up through it. But we're making plans now that we don't see this as something we can't overcome fairly quickly.

[Thomas E. Jorden:]

Jeb, I want to just chime in. This is Tom. We like to talk about what we're spending. We don't typically talk about target well cost, and our drilling group has done a remarkable job when they've had a reputable program of not only getting our efficiencies down, but also our cost. So this is something that I'm highly confident we're going to get these costs down. But the real news, and that shouldn't be lost, is even with these increased costs because of some of these drilling issues, we've seen a significant uplift in our return on invested capital. I mean, this is very good news and it will only get better. So we're -- obviously, we're focused on cost. We're going to, I think, achieve what we've set out there and getting them down, but our turns are improving, not degrading. We're really seeing some nice results on invested capital.

[Operator:]

Our next question is from Matt Portillo with TPH.

[Matthew Portillo:]

Just a few quick question for me. Just wanted to confirm on the Reeves 10,000 foot lateral, how many stages you guys ran in that well?

[Thomas E. Jorden:]

That would have been a normal frac job. I'm pretty sure it would have been around 20 stages, 20 to 22. It would not have been the upsize job, as I mentioned. Our typical jobs in the past were around 10 on a 5,000. So I think it was a natural uplift. That's why I would say, why we're very encouraged off of that results because that was again more of our normal job and not the upsized tighter stage job. I can tell you that, going forward, our next 10,000-foot lateral, we currently plan to -- that job is planned for 35 stages, for that job. So that's a pretty hefty uplift from what we did with that first 10,000-foot lateral, the Ruby that we talked about.

[Matthew Portillo:]

Great. And then just last conference call, you guys mentioned your first 7,500-foot lateral in Culberson, and it had an initial uplift to the production rate, and maybe a little bit slower decline than expected. I was wondering if you could give us an update on how that's performing, and if you've been encouraged at all by the longer lateral length there?

[Thomas E. Jorden:]

Yes, it's continuing to perform very well. We're very, very pleased with that well. It -- in no way has it diminished at all from our last conference call, which is why we're very again excited about the site of the extended laterals. I think our challenges is, again, as we go longer and longer, there are operational issues that we have to deal with as we do that, and so we'll get past those, but yes, still, the day start, the 7,500-foot lateral still looks very, very good to us.

[Matthew Portillo:]

Great. And then just one last quick question on the drilling side. Maybe just curious if you could give us a little bit of color in terms of where your targeted depth is in the play in Culberson and Reeves for the Wolfcamp. And as we've seen, you squeeze a lot of the cost out of the Bone Springs moving towards a full development, what kind of opportunities exist in the Wolfcamp play today? Is it days to drill, is it the pad development? Can you give us maybe a little bit of color on how you potentially see some of those costs coming down over time? And then just my last follow-up question to that is, on these wells, as you complete the wells, how long do they flow on natural production versus being put on artificial lift? And that will be it.

[Joseph R. Albi:]

Okay, this is Joe. I'll let John answer more specifically the landing points for the Wolfcamp wells when we get there. But bigger picture is take a look at Cana, we've drilled hundreds of wells that's taken 5 years. We looked at Barnett, we looked at our days to TD. In Cana, we've made a ball projection early on in that play internally that we should be able to see that same reduction in days that operators saw on the Barnett, which is about a 40% improvement in number of days to TD. Our early Cana wells are running $8.5 million, $9 million there in the quarter. We're down to $6.5 million today. That's due to drilling hundreds and hundreds of wells, and then you throw on top of that the program efficiencies of pad drilling and consolidated batteries and everything else, and you can create those types of benefits. The Wolfcamp, holy cow, it covers 4 separate counties. And if you just do a straight line through all the counties, it's like 200 miles swath of area. So we're talking about hundreds of square miles of potential development. We've drilled 40 wells. In Cana, we've drilled hundreds. In the Second Bone Spring, we've drilled hundreds. So 40 wells, although it sounds like a fair number of wells, it's still young in that play, learning how the heck to drill it. So I just want you to understand that. From the standpoint of improvements that we've seen with bit technology, rotary steerables, consolidated equipment, hydrating our rigs, all those things, in general, at least in the Bone Spring, heck, it knocked 10% to 20% off some of the early AFEs. So I anticipate that as we go into full-scale development, if we start focusing in on any one particular area that has the same common characteristics, we'll see similar type of reductions in the Wolfcamp. We're pretty excited about what we think we can be able to do down there. We just got to get the program going. Now the other thing, as far as when we put these wells on lift, we're -- a lot of that depends on the product mix, the flowing pressures, is it more gassy than oil or is there a lot more water being produced, so forth and so on. Some of our wells have gone a year-plus without needing any kind of lift or even compression for that matter. We've had some long stretches there. So it's a matter of whether how long it takes to get our flowing pressures down to lime pressure. As to when we've even think about putting them on compression, and we can put them on compression without having them on gas lifts. Our practice to date has been to equip these wells with gas lift on tubing that we snug in early so that if and when we do get to that point where we need to lift it, we're able to flip a switch, so to speak, and put the wells on gas lift. But we're even challenging ourselves there with that design and looking at where we set the tubing inside the lateral length. Bone Spring wells, we'll need to put on compression and gas lift quicker than we might a Wolfcamp well. So a lot of it just varies on the product type, the pressures and so forth. And I know it's a very vague answer, but that's about what we're saying.

[Thomas E. Jorden:]

All right. I'll just add a little color. The depth range, again, because it's such a broad area, varies, as you move from Culberson to Reeves to Ward, you go shallower to deeper. You're typically in the 10,000-foot range, down to 12,000-foot over the course of the play. But then you have to consider the interval itself is over a gross interval 1,000 to 1,500 feet or more thick. So it depends on what zone you're targeting and then where you're planning to land. So shallower over in Culberson, and then we pick up a couple thousand feet as we go, and finally, head our way off into Reeves and Ward.

[Operator:]

Our next question comes from Jeff Robertson with Barclays.

[Jeffrey W. Robertson:]

Tom, as you drill longer laterals, is it difficult to keep the bit in zone in any of this or more difficult at any of these formations than others to keep in the landing zone you're trying to target?

[Thomas E. Jorden:]

Jeff, that's not really an issue here. It's such a large broad zone. We don't really micro steer, and it's such a thick, organic rich resource that we don't have any problem getting out of zone. The challenge is, we've had challenges building the curve, you get at 10,000 feet, you're on the hole a long time. It's pretty easy to leave a fish in the hole, and then you end up fishing. Just longer lateral just gives you opportunity for more things to go wrong, just in the everyday course of business.

[Jeffrey W. Robertson:]

Do the -- does the enthusiasm for these plays, Tom, make you think any differently about how much acreage is the right amount to have in the Delaware Basin, given the focus on after-tax rate of return?

[Thomas E. Jorden:]

Well, yes, absolutely. We look at that very carefully, and we ask ourselves how much is enough. When we lease land, and yes, you know this, but indulge me here, we look at the capital required to bring that land to be held by production. So when we add leases, we look at the long-term capital that that requires. And then we'll also look at permutations at downside of commodity case. We're looking at $75 oil or $60 oil, and then we'll also look at a case where we say, "Okay, what if we lease this land and we delay the drilling for 1 to 4 years". And we'll look at the value of that. So we look at the broad range of value. To make sure, one, we're not biting off more than we can chew; two, that we have the capital to bring that net present value forward; and three, that we have the luxury that if we do defer it, we're not destroying capital in the process. So it's a fairly complex formula, but we're disciplined. And that's one thing that when people look at Cimarex, they need to understand that fully. We are about return on invested capital. We're not about growth. We're not about having nice pretty slides about a wonderful resource play. We're about return on invested capital. And so I think we might approach the problem slightly different than our peers, and that's beauty of our balance sheet. We can still add a little asset here, and we have plenty of wherewithal to develop and create value for the shareholders.

[Jeffrey W. Robertson:]

And lastly, Tom. As you think about laying out a 2014 capital program and even looking out into 2015, I guess, with some of the answers you hope to get on these plays, over the next 12 months or so, are there other assets within the company today that just from a rate of return standpoint, all the way in, you all would consider selling as a way to fund what maybe an outspend in '14 and '15?

[Thomas E. Jorden:]

Well, we always ask that question, and we do have assets that would be non-core, that we'd consider divesting. We don't have to do that. I mean, we really look at it against cost of our borrowing, our overall balance sheet structure, but we do look at that. I'll say one thing, Permian Basin is a wonderful place right now. We're getting absolute top tier returns, very oily and the oil price is our dominant revenue phase, but we still like to have gas in our portfolio. We wouldn't want to sacrifice that balance. So although the Permian is obviously a topic of today's call, we really like having Cana in our portfolio. It gives tremendous optionality to shareholder for future increases in gas price.

[Operator:]

Our next question is from John Nelson with Citigroup.

[John C. Nelson:]

Hoping, first, just as a clarification, I missed it. The Ruby well in Reeves County, did you guys give the oil cut on the 60-day rate, if you could repeat that?

[Thomas E. Jorden:]

I think I quoted a percentage of oil. Did I not?

[John A. Lambuth:]

Yes. That's right.

[Thomas E. Jorden:]

Oil cut as a percent of oil water?

[John C. Nelson:]

Yes, exactly.

[John A. Lambuth:]

58% of..

[Thomas E. Jorden:]

Oil and water, yes, it's...

[John C. Nelson:]

Okay, we could follow up. I guess, just staying on that well. You noted the 60-day rate, the decline was pretty shallow. Are you choking back the well or can you just give us sort of any color on why you think the decline was so shallow there?

[Thomas E. Jorden:]

Well, no, we're not choking back the well, per se, as much as that so far has been kind of a characteristic of the longer laterals. I mean, that was certainly true of our first extended lateral on the Day Star we talked about last call to where we're very pleased with the shallower decline we saw on that well. And so far, and again, I'll caution, so far, given the 60-plus days of production we have, we've been very pleased with what we've seen out of it as well in terms of its decline profile, but it's early, and we'll have to monitor over time to see if we continue to see that type of shallower decline in what a normal 5,000-foot well will do.

[Joseph R. Albi:]

This is Joe. To some degree, we are still above line pressure, but the flowing pressure has dropped over the period of time that it's been flowing, and hence that will have an impact of potentially supporting the rates. So as we get closer to line pressure, we expect the well and even below that when we get on the compression, obviously, we could maintain those higher rates as well. So when we get to the point where we are at the bottom end of our pressure capability on the tube inside, the well will most likely start to climb quicker than it is today.

[John C. Nelson:]

That's helpful. And then just the 2 other, I guess, I'll call them shorter laterals, but the 5,000 laterals in Reeves County that you guys disclosed last quarter, just any comments on sort of how they're holding up and sort of the oil percentage longer on?

[Joseph R. Albi:]

Again, so far, very good wells. Very, very pleased with the results out of those wells. They're pretty much on forecast of what we expect out of them. And so no, there's been no degradation whatsoever in the production out of those wells.

[Thomas E. Jorden:]

Yes, and we -- this is Tom. We look at that daily. We have some engineers that send out a update of some of those new wells, and they include all of our old wells, as kind of a benchmark. We currently are flowing back 5 wells with our new frac style. We're having the executive team watching them very carefully, and it's nothing but encouraging. You talk about the long laterals having shallower decline. These upsized fracs also have shallower declines. So this really does look like a potential game changer for our returns.

[John C. Nelson:]

That's great. And the last one for me, I think I have an idea of the answer I'll get, but I'll go ahead and try anyway. The Culberson County-Wolfcamp A, you mentioned that it sort of has a higher oil and liquids mix. Can you maybe just give us a ballpark on sort of where that range might be?

[Thomas E. Jorden:]

Well, no, but I'll answer your question in vague terms. We talked about the Wolfcamp B, the deepest zone has oil rate that's roughly 90 barrels per million cubic feet of gas, so 90 barrels of oil per million cubic feet. As you move up to Wolfcamp C, we talked about some of our wells having oil rate of 150, give or take, per million cubic feet of gas. There's some more, some less. And we said early on before drill the well that we -- we're anticipating the Wolfcamp A would extend that trend and be oilier than the D and C, and be trending that way. And we've said in this call that, yes, it is confirming our model that it's oilier. But right now, it's not that we're trying to be coy. It's just that we really want to stick to our knitting. We like to talk about 30-day averages. If we don't have a 30-day average, we're just going to wait until we do.

[Operator:]

Our next question is from Jason Smith with Bank of America.

[Jason Smith:]

Just wanted to -- a quick clarification in Reeves. I think you guys talked about industry testing multiple zones. You guys have been focused on the A zone, I mean, are you guys looking to test in the other zones as well?

[John A. Lambuth:]

Well, yes, we are. We currently, in fact, have finished a well in the C zone that we actually started frac-ing just today. So that's an additional zone in the A. But also, we are recognizing that given the thickness of the A in Reeves, we're noticing the trend to try, and in fact, at least 1 operator stacking laterals in the A. And we also will be doing that, probably early first quarter, the same type of test that is putting 2 laterals in the A itself, stacked above each other. So that right there potentially, depending upon results, could lead to 3 unique intervals that one could put laterals in, in Reeves County that we're currently going to test.

[Thomas E. Jorden:]

Yes, and this is Tom. In Reeves County, just to follow-up on what John said, we have wells that have are landed in the upper part of the A. We have wells that are landed in the lower part of the A, and now we have a well we're completing that's in the C. So we've tested at least 3 different zones. We just need to confirm that they are in 3 different zones, and you can stack laterals and have independent wells.

[Jason Smith:]

Good color. And where is the focus initially going to be on the A zone or you're going to test the multiple zones there as well?

[Thomas E. Jorden:]

It's, right now, as we look at it, it's A -- that's how we look at it. It's a very thick A over there. Right now, we just want to get some of those under our belt just to see -- hopefully, we've seen some results from other operators. We're very encouraged, what we've seen from other operators. So we just want to go there and get a few wells down ourselves, and then we can worry about whether want to stack or do other things. Right now, it's just strictly A.

[Operator:]

This concludes our question-and-answer session. I would like to turn the conference back over to management for any closing remarks.

[Mark Burford:]

Thanks, everyone, for joining us today. We had a really exciting quarter, and have a lot more wells coming up and look forward to reporting to you our further continuation of our Wolfcamp extension and understanding. But thanks again for participating in today's call, and we'll hopefully see you soon. Thanks.

[Operator:]

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