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Cimarex Energy (NYSE:XEC)

Q2 2012 Earnings Call

August 02, 2012 1:00 pm ET

Executives

Mark Burford - Vice President of Capital Markets and Planning

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

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

Analysts

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Ryan Todd - Deutsche Bank AG, Research Division

Mario Barraza - Tuohy Brothers Investment Research, Inc.

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

Operator

Good afternoon. My name is Tony, and I will be your conference operator today. At this time, I would like to welcome everyone to the Second Quarter Earnings and Operation Results Conference Call. [Operator Instructions] Thank you. Mr. Burford, you may begin your conference.

Mark Burford

Thank you very much, Tony, and welcome, everyone, and thanks for joining us today on our second quarter conference call. Here in Denver, we have Tom Jorden, President and CEO; Joe Albi, EVP and COO; Paul Korus, Senior Vice President and CFO; and Jim Shonsey, Vice President and Controller.

We did issue our financial and operating results and news release this morning, a copy of which can be found on our website. I need to remind you that today's presentation will contain forward-looking statements. However, a number of factors could cause the actual results to differ materially from what we discuss. You should read our disclosure on the forward-looking statements in our latest 10-K, other filings and press releases for risk factors associated with our business.

Thank you very much for joining us, and I'll just go ahead and turn the call over to Tom.

Thomas E. Jorden

Thanks, Mark, and welcome, everyone. We had a solid second quarter even with falling commodity prices. As you saw from our release, we reported net income of $64.3 million or $0.74 per diluted share. Our adjusted cash flow from operations this quarter was $240 million, and that's down from $340 million last year.

Our second quarter 2012 production volumes averaged 590 million cubic feet equivalent per day, that's up slightly from a year ago of 585.7 million cubic feet equivalent. We continue to see strong growth in the Permian and Mid-Continent, which, combined, averaged 547.7 million cubic feet per day -- cubic feet equivalent per day, growing 17% over last year. And that includes a 37% increase from Permian Basin oil volumes, which averaged 21,694 barrels of oil per day this quarter. Our total company oil production grew 8% to 28,000, 686,000 -- 28,686 barrels per day. Liquids accounted for 46% of our equivalent volumes and 80% of our 343 million of oil, gas and NGL revenue.

We saw a decrease in oil, gas and NGL prices this quarter compared to last year, and that didn't surprise anybody. Oil price realizations decreased 12% to $87.81 per barrel. Natural gas prices fell 49%, averaging $2.42 per Mcf. And NGL prices fell $0.36 to average $29.02 per barrel.

What we can control is going very well. We're seeing excellent results in our Permian drilling program, and our Cana team is doing a fantastic job, making returns in a difficult natural gas and NGL environment.

And I just want to say to underscore that, for those of you who have seen our production table and our area-by-area break down, we've had a tremendous headwind to overcome this year with our Gulf Coast decline, and we've talked about that, ad infinitum in past calls. And I just want to tell you how deeply proud we are here in the executive team of our organization, that's picked up the pace, and the fact that we've overcome that decline in the Gulf Coast is really a testament to our engine of growth we have in that Permian and Mid-Continent program, both our exploration team, our operations team working together, our marketing team. We've had a lot of very difficult challenges so far this year with plant downtimes, and Joe will get into that in some detail. Our core focus is on execution, being good at the business and working our way through the cycles. And we're very proud to report the way this organization has responded to the cycle we're in so far this year.

In the first half of this year, we've drilled 160 gross, 91 net wells, investing $782 million on exploration development. Of our total expenditures, 52% were invested in projects located in the Permian, 44% in the Mid-Continent and 4% in the Gulf Coast and other.

And now, we'll move on and give a region-by-region summary, and I'll start with the Permian, which of course is our largest area. We drilled and completed 94 gross or 64 net Permian Basin wells during the first 6 months of 2012, completing 95% of those as producers.

Permian E&D capital for the first half was $409 million or 52% of our total capital. Year-to-date, 2012, in our New Mexico Bone Spring program, we drilled and completed 31 gross, 16 net wells, and we're continuing to see outstanding results in that play. Per well, 30-day gross production from the 2012 Bone Spring wells averaged over 600 barrels equivalent per day, 87% of which was oil. We're drilling some of the best wells we've ever seen. Not only are we drilling some very nice wells, we're certainly in the process of, I think, demonstrating to people that we've overcome some of the challenges we had in the last year with high water cuts. A lot of these wells are in extensional new areas, and we're very, very pleased with the results we're seeing out of that program.

Our team has done a great job in this program, maximizing well performance and stepping out in some of these new areas.

Moving onto the Texas Third Bone Spring. Our Texas Third Bone spring drilling this year has totaled 19 gross and 12 net wells. The per well 30-day gross production rate in this year's wells have averaged 850 barrels equivalent per day, 79% of that being oil. Really nice results out of that program.

And then finally, in the Permian, I'd like to update you on where we are in our Wolfcamp play. We're continuing to see strong results from our Delaware Basin Wolfcamp shale drilling. And as we've outlined in the past, our Wolfcamp play is focused in Southern Eddy County, New Mexico, we call that our White City program, and Northern Culberson County, Texas, where we have approximately 80,000 net acres. Year-to-date, we have drilled and completed 6 gross or 5.9 net horizontal Wolfcamp wells, bringing our total wells in the play since inception to 24 gross or 22.7 net.

Our per well first 30-day production from the wells brought on this quarter averaged 6.7 million cubic feet equivalent per day or 1,120 barrels of oil equivalent per day. That stream out of the Wolfcamp is comprised of 2.6 million cubic feet a day of gas and, of course, I'm quoting the 30-day averages of our first quarter. So the average is 2.6 million cubic feet a day gas, 345 barrels per day of oil and 335 barrels per day of natural gas liquids, or that's 39% gas, 31% oil and 30% NGL.

We've done a lot of experimenting, both regional and stratigraphically, to see if we can increase that oil yield. I will say that our most recent wells are seeing a fairly significant increase in our oil yield. Our play average is about 55 barrels per million. Our recent wells are coming in at about 70 barrels per million. We're still de-risking our acreage. We've yet to fully define on that play. We're still drilling one well per section, and so there's a lot we don't know about that play. We don't know the full regional extent. We don't know the yield breakdown once we have our acreage entirely de-risked. We also don't know how many wells per section ultimately this play will generate for us. But what we do know is we're seeing very nice results, we're getting reasonable returns even at today's costs and commodity pricing environment and we're very excited about this play for what it will be for us in 2012, 2013 and as a legacy project for Cimarex.

Our per well first 30-day production rates in all the wells we've drilled to date, and that's from soup to nuts, short laterals, long laterals, high costs, bad completions, good completions, 30-day average for everything, no holds barred, 6.5 million cubic feet equivalent per day. And again, that's comprised of 2.8 million cubic feet equivalent gas, 270 barrels per day of oil and 350 barrels per day of natural gas liquids. So that's 43% gas, 25% oil and 32% natural gas liquids.

So again, we don't know the scope of this play. We certainly think it has many, many years of drilling potential for us as we de-risk our acreage. And then, we need to ultimately determine our spacing, whether it will be 80-acre spacing, 160-acre spacing or some other number, as yet, we don't know. But certainly, that play has earned a slot in our highlights reel.

Moving on to the Mid-Continent. In the first half of 2012, we drilled and completed 64 gross or 26 net Mid-Continent wells, and our Mid-Continent first half exploration development capital was $345 million or 44% of our total capital. And essentially, all of that activity year-to-date has been in our Cana-Woodford, where we've drilled and completed 60 gross or 25 net wells. At quarter end, there were 57 gross and 24 net Cana wells waiting on completion, and that compares with 13 gross or 4.9 net wells waiting on completion at year-end 2011.

So we're building a little bit of a backlog in Cana, and that's purely a function of our infill development program, and that our drilling is outpacing our completion. That increase on waiting on completions as compared to year end is something that will be with us for a while as we're completing these wells. Frac-ing in our infill row started on May 23, flowback of the first well began in late June and first sale started mid-July. So we don't yet have 30 days of a flowback on our infill program.

So we're now in the manufacturing process in Cana. We have a frac crew working continuously, working their way down the 7-section infill row that we're currently completing and we're completing a frac job every 3 to 4 days. It's a great project. We've put a lot of energy into infrastructure, both from gathering systems, water, water disposal. And I'm sure Joe will talk about that in some detail. And we're still seeing reasonable returns. At current costs and current strip pricing, our returns -- when we quote returns on an infill project, it's an east-west row. All of these infill rows will be east-west, and so east-west in the core Cana goes from a more liquids rich to a drier portion. So the liquids rich has the higher rates return, the drier portion has a lower rates return. And in that row, those rates return vary from 18% to 40% after tax on our drilling dollars, current cost, current pricing.

So we're still seeing successful rates of return at Cana. It's turning into a manufacturing project. We currently have 7 rigs running in Cana. As we've talked in the past, we're planning on redirecting some of those rigs to some other oilier or Mid-Continent plays that we're testing. We're still in a bit of a state of flux. We moved some of our Cana rigs to the Permian as we redirected our capital. Our current plan, if things unfold as the way we currently see them, is we would ramp down our Cana fleet to 4 rigs and exit the year with 4 rigs, working on that infill row in Cana or additional infill drilling in Cana.

We also are experimenting with long laterals in Cana. There have been a number of long laterals drilled by the industry in the Cana core. We have a history of -- there are currently 3 laterals by other operators they are currently producing. There's one flowing back, and then there are spattering of others. We have drilled our first long lateral. We are waiting on completion there. We didn't get the entire lateral length down, so we're still -- don't have anything definitive to say in our opinion of the role of long laterals in Cana, but we are experimenting with them.

Elsewhere in the Mid-Continent, we're quite pleased. We've talked in the past about some emerging plays in the Mid-Continent. We'll be testing some ideas. We've got some ideas that we are in process of testing and in a talk going on in Cleveland. We have some other ideas we haven't talked about and we'll be testing them soon. And hopefully, in the next call or 2, we'll be able to give you some results and what kind of exposure those may have for us going forward.

In the Gulf Coast, we began prospecting on a new 3D shoot that we recently got off the field. We have some new data in our processing. We're trying to see what kind of inventory we'll build. We don't have a definitive look at that yet, so that will be an update for further calls.

So just in conclusion, as we look at our results today, where we are, where we're going, it's been a solid first half. We focused on execution. We're very pleased with where we are. We're right on target to deliver the guidance that we've promised. And I just want to reiterate again that we're very proud of the operational and overall performance of our organization as they've had to overcome a fair amount of headwind this year.

And with that, I will turn the call over to Joe.

Joseph R. Albi

Thank you, Tom, and thank you all of you for joining our call today. I'll quickly touch on our second quarter production, hit on our remaining year guidance and then I'll finish up with a few comments on where we see service costs.

Despite seeing higher pipeline and facility shut-in volumes than we expected, our second quarter average net daily equivalent production came in at 590.1 million a day. That's about as expected and right at the midpoint of our guidance that we issued of 580 million to 680 million a day. As you may recall from our last call, our Q2 guidance incorporated a reduction of approximately 10 million to 12 million a day for what we saw as anticipated Permian and Mid-Continent pipeline and facility shut-ins, as well as the likely ethane rejection during May and June for our processed gas out in Cana.

When the dust settled after we closed the quarter, our plus or minus 3-million-a-day estimate for the Q2 impact for ethane rejection was right in line, but our facility shut-ins ended up being slightly higher than we anticipated, primarily in the Permian. And as a result, our production was negatively impacted to the tune of 17 million to 19 million a day during the quarter versus the 10 million to 12 million that we have predicted. Nonetheless, we came in right at our midpoint. And when accounting for those shut-ins, we're about flat or possibly even a little bit higher than where we would have been in Q1.

We continued to set new records in the Permian, although 12 million to 13 million a day of our second quarter shut-ins did happen in the Permian. Our reported net equivalent Permian production of 247 million a day is a new high mark for the region, as is our 28,011 barrels per day of total liquid production.

As compared to Q1 '12, our second quarter combined Permian and Mid-Continent equivalent production of 547.7 million a day was down slightly, 1%, and this is due to the pipeline and facility shut-ins that I mentioned, the ethane rejection and our planned deferred completion of our Cana infill wells.

All the while, our Gulf Coast production of 42.4 million a day came in a little bit better than we had expected, down just 6.8 million a day or 14% in Q1.

But despite the shut-ins, we continued to demonstrate significant year-over-year production growth in the Permian and the Mid-Continent. As we compare ourselves to Q2 '11, our combined Q2 '12 Permian and Mid-Continent equivalent net production was up 80.7 million a day. That's up 17% from Q2 '11, with the Permian up 65 million a day and Cana up 41 million a day, both of which are 36% increases. And both are directly related to where the focus of our capital has been over the last year.

Outside of the ethane rejection and larger-than-expected facility shut-ins during the first half of the year, our 2012 production has really been performing quite well, and in essence, hitting our plan. As we mentioned when we first issued our 2012 guidance and we reiterated again last call, the significant portion of our anticipated 2012 production adds were projected to occur in the latter half of this year, And that's driven primarily by our Cana infill well frac schedule. As we mentioned last call, as of March 31, we have 39 gross or 18 net Cana wells waiting on completion. And as Tom mentioned, at June 30, this figure had grown to 57 gross and 24 net wells waiting on completion just in Cana.

Although we initiated our infill frac operations in late May and in essence completed 6 of those gross wells, 2.4 net, by the end of the quarter, our production adds from these wells were really not anticipated to be seen until the Q3 timeframe.

So really, nothing has changed in that regard. The only items that have played a significant role in our year-to-date production as compared to our beginning year guidance really have been just the facility shut-ins and the ethane rejection that we've experienced. The impact of these 2 items were more pronounced in Q2 than Q1. But over the first half of the year, they've averaged about 11 million to 13 million a day that didn't show up on the scoreboard.

So looking forward, our current full year guidance model does incorporate the Q1 and Q2 impact of the shut-ins and ethane rejection. And we also incorporated an estimated 8-million- to 9-million-a-day reduction during Q3 for a projected ethane rejection from Cana during the quarter. With continued anticipated production growth from the Permian and Cana, our modeling continues to support the full year guidance projection we issued last quarter, which was 612 million to 632 million a day, and our Q3 volumes are projected to average 610 million to 640 million a day, a significant jump-up from Q2.

Our projected third quarter combined Permian and Mid-Continent volumes of 575 million to 590 million a day reflect a continued year-over-year increase in production with an estimated 18% to 21% increase from where we were in Q3 '11. And again, that's simply a direct result of our activity in those 2 areas.

With our focus on oil and liquids rich gas, we anticipate that we'll close the year with liquids averaging approximately 48% of our 2012 total company production, and that's up from 44% that we reported in 2011.

And another note I want to point out, as implied by our guidance, we're also projecting a strong exit rate for 2012, which certainly will springboard us into 2013.

Shifting gears to OpEx. With the overall cost increases the industry has seen over the last year, LOE has become an even more important focus for our production group. Our immediate focus has been on reducing SWD costs, primarily in the Permian, and to implement measures to reduce workover costs company-wide.

In conjunction with that, we've put some capital into infrastructure costs that Tom briefly touched on future benefits of those, and our LOE really will never be seen. And that's some of the benefits that we'll get out of putting in our own saltwater disposal facilities, our own trunk lines, our high-pressure and low-pressure gas service for gas lifts, central delivery points, common points of compression, getting out ahead of the infrastructure for power to reduce our power generator costs and so forth and so on.

So a lot of those will show up down the road. We won't see it yet, but overall, when we look at the lifting cost figure from this point forward, we are anticipating to see future improvements.

So as a result, our Q2 lifting costs came in at $1.16 per Mcfe. That's down $0.07 or 5.7% from Q1. With our continued focus on cost controls, like I've measured, and as well as the reduction we saw in Q2, we've slightly revised our full year LOE guidance down to $1.15 to $1.30 per Mcfe simply by just lowering the upper end of the range that we issued last quarter.

Finally, on the service cost side, we've seen the majority of service costs, such as rigs, mud, directional, cementing, bids, et cetera, stay fairly flat over the quarter. And for that matter, over the last few quarters, as far as the rig market is concerned, 1,500 horsepower top drives continue to appear to be in demand, but we see the market showing some signs of softening.

A rig may become available and may be available for a short while, and then it gets picked up, but it's not as tight as we saw the market a quarter ago.

In Cana, we continue to see the benefits of our program drilling efficiencies with the average days to TD for our Cana core wells now running about 40 days as compared to 50 days in 2011 and the 64 days we saw when we first began the program in 2007 and 2008. And that's a real testimony to the improvements we've been able to make where the efficiencies are associated with program drilling.

Despite slightly larger fracs, our current Cana core AFEs are running about $7.5 million. That's down about $100,000 from the number we gave you last quarter and it's at or below the levels that we saw over a year ago.

With our infill efficiencies that we're just starting to see, we're projecting that some of our recent faster drilled Cana infill wells may come in well below $7 million once we've finished our completion work.

So we're seeing tremendous improvements through efficiencies in Cana. As far as the Permian is concerned, although availability for nearly all tools, services and equipment can be a challenge and require a good planning. Really outside of trucking for heavy equipment, we haven't noted any significant changes in cost components. And as such, our Permian well costs remain relatively unchanged from last quarter.

Our 8,000- and 9,000-foot TVD Second Bone Spring New Mexico well with a 4,700-foot lateral are still running around $5.8 million to $6.5 million. That's flat with our Q1 estimates. And as we've talked about before, as TVDs approach 11,000 feet going deeper into the basin, that generic well will run closer to $6.8 million to $7.1 million.

Our generic West Texas Third Bone Spring AFEs are running about $7.5 million to $8 million. That's down $1 million to $1.5 million from where we were at the end of last year and the beginning part of this year due primarily to the program efficiencies we mentioned and also our completion design changes that we've made in that program by going to cemented liners, fewer stages and using white sand in our completions.

In our current Wolfcamp, AFEs continue to come in around $8 million to $8.5 million. That's right on track with the estimates that we provided last call.

So in summary, we had another good quarter. Our Q2 production came in as planned. Our full year guidance remains unchanged and our Q2 LOE reduction is certainly headed in the right direction, with our drilling and completion costs remaining in check. So as we move in to the second half of the year, our teams simply will just keep their focus on maximizing production and improving our LOE and well costs where we can.

So with that, I think now I turn the call back over to the operator for any questions that you all may have.

Thomas E. Jorden

That's right.

Question-and-Answer Session

Operator

[Operator Instructions] The first question comes from the line of Brian Lively.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

I wanted to start just by clarifying the ethane commentary. I'm not sure if I missed this, but for your Q3 guidance, how much ethane have you backed out for potential curtailment there?

Joseph R. Albi

Brian, this is Joe Albi. The modeling that we're using is approximating about an average of 8 million a day of a reduction for specifically ethane rejection. And the only place we're seeing it is at our Cana processed gas that is tied to a Conway price.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Okay, that's understandable. On the Permian side, I think you guys have given 600,000-barrel recoveries for the New Mexico Bone Spring and something like 730,000 for the Third Bone Spring. Can you update, based on the new well data, what you're seeing from an EUR standpoint and maybe add some commentary on the Wolfcamp?

Mark Burford

Brian, you're right. We have given those numbers in the investor presentation. Those numbers are reflecting some of the wells in the second quarter, and we are incorporating some of those, Brian. So I don't think our averages will change materially from what we have described in those averages there.

Thomas E. Jorden

Brian, this is Tom. We are you seeing an increase on our EURs in both plays based on, I think, better geological targeting, better stratigraphic targeting and better completions. So our recent wells, depends on the average, I'm looking at a table here, that's in our investor material. But if you look at our average from 2009 to the third quarter 2011, in the Second Bone Spring, we've increased our average 50%. I mean, we're currently at a tight curve that's 600 or better Mboe in the Second Bone Spring. And then, likewise, if you look at a period of time from 2006 to the third quarter of 2011 and you compare that with the third quarter 2011 to current, we've had a 60% increase on our Third Bone Spring EURs. And there's a fair amount of variance in those EURs, as you know. But we're certainly seeing, I would say, 700 to 800 Mboe in the Third Bone Spring play per well.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

That's great. And then I think that you guys had some commentary in the past about possibly targeting some of the oilier Avalon intervals. Can you provide an update on that? I mean, have you all tested any of those wells yet?

Thomas E. Jorden

Yes. We've drilled a few Avalon wells. We brought a few Avalon wells online this year in Southern Lea County, and they're okay wells. I mean, we're not talking about specific wells there. We have a great exposure to the Avalon play, but we currently don't see us competing for capital with some of our other opportunities. We have a fairly tremendous inventory of Avalon opportunities. Again, we know probably less about it than some of the experienced operators, but we have some pretty good exposure. We just don't model it right now competing with capital with some of our other opportunities.

Operator

The next question comes from line of Ryan Todd.

Ryan Todd - Deutsche Bank AG, Research Division

A couple of questions for you. On the -- as you ramp down to a 4-rig run rate in Cana, which I'm assuming is that 4 rigs and 1 frac crew on your infill pads, what's the right way to think about the run rate on CapEx of that level in Cana?

Thomas E. Jorden

This is Tom. We're -- right now, of course, Cana is not just Cimarex. And so with 4 rigs, there's a pretty good chance that we may have as much or more non-op capital as we do operating capital. Right now, we're carrying as a placeholder for 2013. If we exit with 4 rigs and we stay with 4 rigs, it looks like we'll be at about $350 million for Cana. It could be as low as $250 million, so I'd give you a range of $250 million to $350 million. And the swing there is how much outside operating capital we're exposed to. We certainly like what we're seeing at Cana, so we're staying in everything. And we're not setting in stone that we'll be exiting with 4 rigs. It's just what we're looking at as we look to the remainder of 2012 going into 2013. I think you can expect us to be much closer to cash flow next year than we have been this year. This year, we spread a little to really, quite frankly, overcome that Gulf Coast headwind, which was a decline both in gas and oil production. One of those Gulf Coast wells were pretty oily. So we're in an outspend situation this year to try to catch that, and we've done a nice job. And so next year, we're still putting our plans together. But if we go with that 4-rig program in Cana, the direct answer to your question is we we'd be between $250 million and $350 million bold net exposure, and that swing is on outside operated.

Ryan Todd - Deutsche Bank AG, Research Division

Great, I appreciate that clarity. I mean, is it right to think of it, from a completion level, the fact you alluded to completion program that you started in late May will continue at a fairly steady pace for the 12 months following that through...

Thomas E. Jorden

Yes, so we will be completing wells through May of 2013 on our current infill program, completing continuously.

Ryan Todd - Deutsche Bank AG, Research Division

And then just broadly, if we look at the Permian, you obviously have -- I mean, you've spoken and given some good color in terms of downtime that you had in some of the facilities in the Permian in the quarter. More broadly on your infrastructure in the Permian Basin, what are you seeing right now across your areas on infrastructure? Potential bottlenecks or sources of concern over the next 18 months?

Joseph R. Albi

Well, this is Joe. We do have concerns about takeaway issues and it's not so much the immediate capacity or processing availability of that. As much as there's NGL takeaway capacity, we're aware of the certain infrastructure that's contemplated by the industry to remedy that. But that's like 2013 and into '14, and then downstream of that, you've got the petrochem side of it. So we can't control any of that. What we can do is what we have been doing, and that is to put in our own infrastructure, process our own gas if we have to at the same time that we're working with other processors out there to try to firm up capacity where we can. That's kind of a vague answer, but the bottom line is there is short-term capacity that we see. The disruptions that we have seen have not necessarily been due to us not having a market as much as it has been due to the patchwork on the processors and gather site to increase capacity where they can.

Operator

Your next question comes from line of Mario Barraza.

Mario Barraza - Tuohy Brothers Investment Research, Inc.

Just want to dig a little deeper on the Wolfcamp shale wells on the Delaware Basin. I know you've only drilled a few, but the oil cut looks to be significantly higher. Do you have any idea on what percentage of your acreage here might be perspective for this higher oil cut?

Thomas E. Jorden

Yes, this is Tom. We haven't de-risked enough our acreage to say. I mean, one of the things we do know is, in general, it's getting oilier as we go to the east on our acreage, and yet there are some other factors in the play there. I wouldn't just simply say east is good. East is also a little deeper, maybe a little higher water. So there's a lot of factors in play. I don't have, and I would -- I don't have an answer to your question on how many -- our perspective for high oil cut. But I will say with all the wells we've drilled, our average has been about 55 barrels per million. So we're seeing good oil cuts throughout much of the play. And then there are a lot of things we're experimenting with. This is a section that's 600- to 800-feet thick, so oil cut varies east to west, but it also varies with depth. It varies with stratigraphy, and we're playing around with that. And I will say some of our higher oil cuts are functions of, I think, some real creative success our teams have with addressing those questions. But how it's going to average out to all of our acreage, it would be foolish for me to try to even answer that question, and we're too early to know.

Mario Barraza - Tuohy Brothers Investment Research, Inc.

Okay. And then on the cost side, I appreciate all the color you guys gave. I guess, where do you think in the Delaware Basin kind of on the Wolfcamp where you -- I know we're early here, where ultimately would you like to get your well costs to?

Thomas E. Jorden

Again, this is Tom. We're very optimistic on the cost side, and our drilling completion group has really been focusing on that lately. Some of the lessons, learnings from Cana where we replicate the same wells over and over. It's all about efficiency, running new ideas, sharing information on any advance. A lot of our learnings in Cana, we're directly applying to the Wolfcamp. We've put that infrastructure in place. We're ready to roll to drill the same type of well over and over. And that when we give our operations group that opportunity, every time they'd have that opportunity, they've shined. And I'm very optimistic. One of the things we have seen over the last quarter is our well costs are holding flat and in the Permian, that's a wonderful thing to say. They had been increasing, creeping up over time. So to answer where do I want them to be, we're currently at, a, in some change on the Wolfcamp. I would certainly look for a 10% or better reduction on that. Joe, you're going to want to be the one to make that happen, what's your answer?

Joseph R. Albi

Well, I certainly agree with what Tom is saying, and I think the best model is Cana by itself. When we started that project in 2007, 2008, when they really kicked it off, we have data that we prepared back then saying, "Hey, here's this program, 4 years from now, where do we think it can be from just a drill-time standpoint?" And we had projected that we could get our time to TD down by 60% or 40% to 60% of the days that it was taken. [indiscernible] numbers there that basically did just that. So 4 years later, we were successful in reducing our drilling time by 40%. That alone, on the drilling cost side, gives you an idea, a ballpark of the cost reduction, I guess, that could come out of that, especially when you take our total well costs and you say about half of them are on the completion side. So maybe 40% of the drilling cost side will get you right about to the number Tom's talking about.

Thomas E. Jorden

If you look at it, and we're seeing these improvements now, they're showing up in performance first, and then from that will come costs. Same thing we saw on Cana. In Cana, we saw tremendous improvements with our days drilling, and those improvements lead cost improvements. But if you look at our Wolfcamp drilling from inception to date and you line up our wells, you had a 40% reduction in drilling days. So we're absolutely moving in the right direction. I think, as Joe has talked, this infrastructure we put in, in the Culberson County has been exactly the right move for us. We have a nice consolidated asset and we are well positioned to do what our operations group does well. And then you give them something that's repeatable, concentrated and let it rip. And I really do expect these costs to show great improvement over time.

Operator

Your next question comes from line of Cameron Horwitz.

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

Can you just remind me how much acreage do you have in Reeves County? And do you guys have any plans to drill any Wolfcamp test here over the next year or so?

Thomas E. Jorden

We do have a fair amount of acreage in Reeves County, I don't know the answer.

Mark Burford

Cameron, this is Mark. I think we talked about Third Bone Spring acreage, which is a lot of it being at Reeves County. It's about 35,000 net acres in the Third Bone Spring position we have there.

Thomas E. Jorden

We also have some acreage aside from that that's in more of the Wolfcamp Fairway, and we're talking about that now. There are some drilling by others out there that we don't have to always do the first tear [ph] on the campaign. So there's a fair amount of activity out there that hopefully we'll be able to leverage. But we have drilled some initial wells, kind of in the Central Reeves County that produced a little more water than we were expecting. And again, this is a fixed section, so there's a lot of variables that you can fix that. And so that's a long winded way to say I don't have any acreage and what we're going to do with it. But we do have a position in Reeves County.

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

No, that works.

Thomas E. Jorden

We're focused on Culberson, but I will say that just, parenthetically, we have a lot of opportunity. We talked about moving this organization to cash flow, that's going to be a bit of a shock to a lot of our teams because we have a lot of opportunity. And so one of the things that I'm asking you to one of our operating groups to present is what's your minimum capital, the whole acreage and not let things we like expire. And so they've been sending me that list as we look at the years ahead. And that was the first thing Permian said. And some of this Central Reeves acreage, it may change because we may want to get out there and drill it and save it and then they may look really good to us. So it really is a debated point here that's influx.

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

Okay. And also staying on the Wolfcamp, is the longest lateral you drilled that 4,500-foot or if you guys tried some longer laterals there yet?

Thomas E. Jorden

We've not tried a 2-section lateral. I think our actual longest lateral is a little longer than that because those are big sections. Those are not 640-acre sections. They're -- I forget how many acres they are. I don't think they're quite 700, but they're larger sections so you can get a little longer lateral. We've not yet drilled a multi-section lateral. We have a couple of them on the books. I think we'll probably get 1 or 2 done this year. And right now, they look expensive, but they also look like they may be exactly what this play needs.

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

Sure. So there's no reason why you couldn't extend those in terms of looking at -- I guess in the Bone Spring, you got some geologic risk when you extend. But here, you could see this going up to maybe 8,000-foot laterals?

Thomas E. Jorden

We could. It becomes a land challenge at that point. You certainly have to control enough of the adjacent sections to make that worth a headache, but that's absolutely on our shortlist of play development ideas.

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

Okay, great. And then just last one for me, jumping on the Bone Spring. I mean, you said in the past, you guys have been pretty aggressive or at least trying to be aggressive in terms of adding to your position. How do you think your inventory trends from here? I mean, can we expect any kind of upgrade to that 200-plus locations that you guys have been put out there over the next year or so?

Thomas E. Jorden

Well, again, this is Tom. Of course, we've had that number for about 5 years running. We continue to recharge. I will say, it's getting extremely competitive land-wise. At the most recent federal sale, we had a block or 2 where we thought -- we really like them and we thought we were putting extremely aggressive bids on, which we were, and we were not the high bidder. People are paying prices for this acreage, and I would consider everything goes well money. If everything goes well, you get exactly the model that you're predicting, which is a fairly aggressive model. You have no operational issues, no cost overruns, no production delays. If everything goes well, you'd get a reasonable return. But that's a very difficult bill to foot for us because we've got enough experience in the business to know you'd better offer a little windage [ph] if you're looking for a return on your investment. Not everything goes well. So we have a lot of ways to acquire acreage in that trend. We have a very aggressive team in Midland that is a great set of dealmakers. They do section-by-section deals. Part of that land is controlled by people that don't have the stomach for a deep horizontal well. They may control the land because of shallow production and they're amenable to a conversation about market. So we're continuing to work it. We're continuing to add opportunity. Will we have a material change in our 200- to 300-well inventory? I can't promise that. All I can say is that we get up every morning and work on it.

Operator

[Operator Instructions] There seemed to be no further questions at this time.

Mark Burford

Great. Thank you, Tony, and thank you all for joining us today. We appreciate the team for joining us, and maybe Tom and I can see you down in Houston at the Tudor, Pickering Conference or Paul might see you in New York at the Tuohy Brothers Conference next week. So again, thank you for participating in the conference call today, and we look forward to continue reporting to you as we run in the future. Thank you very much.

Operator

Ladies and gentlemen, this does conclude today's conference call. You may now disconnect.

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