Cimarex Energy Co.
Q3 2017 Earnings Call Transcript

Published: 8 Nov 2017

[Operator:]

Good morning and welcome to the Cimarex Energy Third Quarter Conference Call. All participants will be in listen-only mode. After today's presentation, there will be an opportunity to ask questions. Please note this event is being recorded. I would now like to turn the conference over to Karen Acierno, Director of Investor Relations. Please go ahead.

[Karen Acierno:]

Thanks, Phil. Good morning, everyone, and welcome to Cimarex's third quarter 2017 conference call. An updated presentation was posted to our website yesterday afternoon. We will be referring to this presentation during our call today. And as a reminder, our discussion will contain forward-looking statements. A number of actions 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, news releases, for the risk factors associated with our business. We expect to file our 10-Q for the three months ended September 30 later today. So as usual, we will begin our prepared remarks with an overview from our CEO, Tom Jorden, followed by an update on our drilling activities and results from John Lambuth, SVP of Exploration. And then Joe Albi, our COO, will update you on operations, including production and well costs. Mark Burford, our CFO is also present to help answer any questions. And just one reminder, so that we can accommodate more of your questions during the hour we have allotted, we'd like to ask that you limit yourself to one question and one follow-up. You can always feel free to get back in the queue if you like. So with that I'll turn the call over to Tom.

[Thomas E. Jorden:]

Thank you, Karen, and thank you to all of you who are on the call today. We look forward to updating you on our operations and outlook as well as answering your questions. Cimarex had another very good quarter. Production for the third quarter averaged 1,143 million cubic feet equivalent per day or 190.5 MBoe per day. This was slightly above the high-end of our guidance range. Consequently, we are modestly increasing our full year production guidance to 1,134 MMcfe per day to 1,147 MMcfe per day, or 189 MBoe per day to 191 MBoe per day. 2017 production guidance has increased 5% at the midpoint since we first provided guidance in February. And our exploration and development capital is now expected to come in at $1.2 billion, the upper end of our original guidance given in February. This is a testament to the strong operating performance of our 2017 program. We are achieving excellent returns on our capital investments. Our current returns on both the well level and total program are better than those we achieved during the halcyon days of 2013 and 2014, which were of course in a much higher commodity price environment. These increased returns are due to significantly increased well productivity, lower costs, and the growing capital efficiency of our infill development projects. I'd like to refer you to a couple of new slides in our investor presentation to illustrate this point. I'll start with slide 9, which shows the improvement in productivity of our Delaware Basin Wolfcamp wells from 2013 to early 2017. Well productivity, when adjusted for lateral length, has increased 20% in that timeframe. We chose to show the average daily production per well for 180 days, instead of the usual 30 days, to give you a more complete picture of well performance. On the next slide, we've taken a look back to the third quarter of 2014 at what our forward looking returns were at that time for a 10,000-foot Wolfcamp well in Culberson County. We've compared those to our current estimated returns for that same well type today. We've used the same price forecast for both cases, $50 oil [per barrel], $2.50 gas [per mcf], and $17.50 (sic) [$16.67] per NGL barrel, all held flat for the life of the well. But we've kept everything else, well costs, production, LOE, drilling time, as it was or is in each appropriate timeframe. For example, our well cost peaked in the third quarter of 2014 at $13.5 million for a 10,000-foot Wolfcamp well, versus the $11.2 million today. As you can see, the well level returns have increased dramatically for both the Upper and Lower Wolfcamp, again a testament to the productivity improvements we've achieved. We've recently been on the road, speaking with existing and prospective owners and have been impressed with the shift in investor sentiment in the past few months. There is a consistent theme around fundamental questions about the E&P business model, the philosophy around value creation, living within cash flow, managing through the commodity cycles, and making sure that companies have executive team incentives that are aligned with shareholder interest. At Cimarex, we welcome these conversations and the scrutiny they invite. It is entirely fair to challenge us to articulate our value proposition. Our mission is simple, to increase net asset value per share. We believe that the best way to accomplish this is to consistently invest capital at high rates of return. We account for unknown future commodity prices by stress testing our investments at draconian downside cases. Profitable investment of capital is our mission. Growth is a consequence of good investment decisions, not a primary goal. Our corporate culture is based upon results. There are two primary ingredients to superior results, great assets and an organization that is capable of executing on complex projects. Cimarex has both. We define results by achieved rates of return measured by objective, transparent analysis of fully burdened return on invested capital. Half cycle or drilling only returns are interesting, but they do not reflect the actual return on the capital invested. Fully burdened returns account for all investments, land, geoscience, infrastructure, salt water disposal systems, and overhead. Our shareholders do not see the difference between a 2,500 barrel of oil per day horizontal well and a company operated gathering system. It all boils down to a simple equation, capital in and cash flow out. Any analysis that fails to account for every single investment misrepresents actual returns. Companies that consistently achieve good fully burdened, full cycle returns will have a higher return on capital employed, higher debt adjusted per share of production growth, higher debt adjusted per share reserve growth, and higher debt adjusted per share cash flow growth. Furthermore, companies that generate good results with these metrics should be able to achieve them while living within cash flow. At Cimarex in a $50 flat oil and $3 flat gas future, we have the assets and organizational capability to generate double-digit growth and generate free cash flow as far as the eye can see. Results are what matter to us and results are what matter to you. Let me make a few comments about capital investment as we end 2017 and look ahead into 2018. Although we're not prepared to give a specific outlook for 2018 capital, I can offer some thoughts on how we approach the opportunities ahead. Looking ahead into 2018, more and more of our capital will be devoted to pilot development projects in the Permian and Anadarko Basins. We expect the Permian to get the lion's share of 2018 capital, perhaps even a greater share than 2017. John will walk you through some of the projects on our plate in both the Permian and Anadarko. We very much like both basins, but the Permian is currently more shovel ready for development than the Anadarko. Cimarex is moving forward in our premier investment portfolio, our deep inventory, and with a commitment to maintain a strong balance sheet. We anticipate an active year in 2018. And as we have in 2017, we will manage our portfolio for continued strength in well productivity and fully burdened returns. With that I'll turn the call over to John.

[John Lambuth:]

Thanks, Tom. I'll start with a quick recap of our drilling activity before getting into some of the specifics of our latest well results and plans for the remainder of 2017. During the third quarter, Cimarex invested $335 million on exploration and development activities. 60% of our third quarter capital was invested in the Permian region with 39% going toward activities in the Mid-Continent region. We invested $280 million of the $335 million on the drilling and completion of new wells. Company-wide we brought 77 gross, 30 net wells on production during the third quarter of 2017, bringing our total net wells year to date to 74. Our 2017 exploration and development budget is now $1.2 billion from the $1.1 billion to $1.2 billion originally estimated with $900 million to $925 million allocated for drilling and completing wells. Driving us to the upper end of our original guidance was an increase in salt water disposal wells and higher working interest in our Meramec drilling than originally planned. For the full year 2017, we plan to invest 61% of our capital in the Permian region with the remaining earmarked for Mid-Continent. We currently operate 14 gross rigs, 9 in the Permian region and 5 in the Mid-Continent. We currently plan to exit the year with 10 rigs in the Permian and 4 in Mid-Continent. Now on to some specific well results. I'll start in the Permian region, where we have exciting results to share with you regarding a successful well in the Lower Wolfcamp in our White City acreage position located in Southern Eddy County, New Mexico. While we have drilled many Lower Wolfcamp wells in White City, this is the first 10,000-foot lateral completed using our latest generation completion design. This well, the Marquardt 12-13 Fed Com 4H (sic) [11H], had an average 30-day peak IP of 2,766 barrels of oil equivalent per day, of which 47% was gas, 19% oil, and 34% NGL. This well's strong early time performance is helping us gain greater confidence and an ability to drill high rate of return Wolfcamp wells in multiple benches across the breadth of our White City acreage position. Drilling has also begun on the Animal Kingdom infill development, which consist of eight 10,000-foot laterals being drilled from two pads, testing the equivalent of 14 wells per section by both decreasing the spacing in between wells and the bench, plus adding an additional landing zone in the top part of the Lower Wolfcamp, which is a zone we used to refer to as the Wolfcamp C. A wine rack display for this pilot can be seen on Page 15 of our presentation. First production from this pilot is expected in the second quarter of 2018. We now have early production results on our Wolf – Upper Wolfcamp Seattle Slew spacing pilot, which consisted of six gross wells of 7,500-foot in length from two pads, which are testing the equivalent of 12 wells per section. As can be seen on the cumulative production versus days plot on slide 16 of our presentation, the Seattle Slew wells after a cumulative production after 60 days is tracking with the 60-day average of the Gato del Sol and Sunny Halo's (sic) [Sunny's Halo] wells, which respectively tested six and eight wells per section. These early results are certainly encouraging. And we look forward to providing further updates for this pilot over time. Finally, I want to talk about the increased activity we have planned in Lea County, New Mexico, for the remainder of 2017 and the first quarter of 2018. Within our Red Hills acreage block located in Southern Lea County, we will be drilling two 10,000-foot laterals in the Upper Wolfcamp and three 10,000-foot wells in the Avalon interval in order to further test completion design. Additionally, we will soon begin drilling a spacing pilot in the Upper Wolfcamp that will be comprised of six wells from two pads that will test the equivalent of 12 wells per section within one bench. We will also be spudding an Avalon spacing pilot, which will consist of six wells from two pads that will be testing the equivalent of 20 wells per section in a stacked/staggered pattern within one zone. All these wells are expected to have first production by mid-year 2018. Now onto the Mid-Continent, where we have some meaningful results to talk about. I will start with the results of our increased density infill in the Woodford Shale. The Clyde Copeland tested both 16- and 20-well spacing with 8 wells drilled from two pads. As you can see on the cumulative production versus time plot on page 23 of the presentation, early well results show production as virtually the same under both spacing scenarios and also compares favorably to the nearby parent wells. These early results are a nice confirmation that our completion design is achieving our predictive result. Furthermore, what we are learning from this pilot will have a meaningful impact in the design for our upcoming long lateral development in the Leota Jacobs area, of which the exact timing is still being worked out, as well as future infill development across the rest of our Woodford acreage. Finally, page 24 of the presentation highlights an emerging area we call Lone Rock, which is a Woodford play where we have over 16,000 net contiguous acres. After many years of testing different landing zones as well as frac designs, we have now honed into a well design that is creating some of the best after tax rate return drilling opportunities within the company. The cumulative production versus base plot on page 24 demonstrates the dramatic improvement in production with the implementation of each new completion design. The three lines represent different vintage completions, with the blue line showing our most recent. As was mentioned in our press release, the recently completed Hines Federal 1H-0235X well achieved an initial 30-day average peak production of 15.2 million cubic feet equivalent per day, of which 40% was oil. This well is a further confirmation that our landing zone and frac design recipe for this area is working very well. With that I'll turn the call over to Joe Albi.

[Joseph R. Albi:]

Well, thank you, John, and thank you all for joining us on our call today. I'll cover the usual items, our third quarter production, our updated 2017 production outlook, and then I'll finish up with a few comments on LOE and service cost. As Tom mentioned, we had a very good quarter for production in Q3. Our net equivalent volume came in at 1.143 Bcfe per day. That slightly beat our upper end of our guidance range, which was 1.1 Bcfe per day to 1.14 Bcfe per day. Gas volumes really drove our guidance beat, with our predominantly gas Mid-Continent Clyde Copeland project, which John just talked about, coming on stronger and a bit sooner than we had projected. On the oil side, we are right on top of where we forecasted the quarter to be. With strong activity levels in both the Permian and Mid-Continent, we've seen nice production gains in both of the areas. Our Q3 2017 Permian posting of 628 million [cubic feet equivalent] a day is up 21% from Q3 2016, while our Mid-Continent volume of 513 million [cubic feet equivalent] a day is up 20%. Looking forward, our current model has little departure from last call, with our late Q3 and Q4 completions in both regions projected to ramp our Q4 volumes. With the activity, we're forecasting our Q4 net equivalent production to range from 1.175 Bcfe per day to 1.225 Bcfe per day. And which would be an increase of 3% to 7% over Q3 2017 and up 22% to 28% from Q4 2016 and really providing us with a great springboard as we enter 2018. Driven by Permian, the Upper Wolfcamp, and Mid-Continent/Meramec completion activity, our fourth quarter oil volumes are projected to grow 32% to 37% versus fourth quarter 2016. Incorporating our Q4 guidance, our full year 2017 production is now estimated to average 1.134 Bcfe to 1.147 Bcfe per day, up from last call's guidance of 1.12 Bcfe to 1.14 Bcfe per day and an increase of 18% to 19% year-over-year production growth over 2016. With strong well performance during the year, we've increased our 2017 guidance each quarter. And as Tom mentioned, since giving our initial 2017 guidance in February, we've increased the midpoint of our 2017 equivalent projection by 5%. With this year's focus on oil and liquid rich projects, the midpoint of our current projection for total company 2017 oil production equates to 26% growth over 2016. Shifting gears to OpEx. Our Q3 lifting cost came in at $0.62 cents per Mcfe, at the low end of our guidance range of $0.60 to $0.70 per Mcf. With that our year-to-date lifting cost also computes to $0.62 per Mcfe, that's down 6% from our 2016 average and 25% from our 2015 posting. Our production team is focused to maintain the reduced operating cost structure we worked so hard to achieve with a goal of keeping our overall lifting cost in check. As such, remaining year guidance, we've kept our previous lifting cost range of $0.60 to $0.70 per Mcfe. And lastly, some comments on drilling and completion cost. In general, we continue to see stability in most all drilling cost components, including tubular and wireline cost, which increased earlier in the year. We did see some cost pressures in quoted rig day rates during the quarter, as well as some pressures on cementing ops in the Mid-Continent. To fight any of the drilling cost pressures we've seen, we continue to keep our focus on efficiencies. As an example, our current median for days from spud to rig release for our 2-mile lateral Wolfcamp wells is running at 25 days, as compared to 29 days in 2016. And likewise, we've seen similar gains at our Meramec program with our normalized 2-mile Meramec drill time currently at 32 days, down from 40 days last year. On the completion side, the per unit cost pressures in service and prop costs that we'd seen earlier in the year seem to be flattening somewhat. That said, we stay focused on refining our completion designs to offset the cost pressures we've seen to date, all the while concentrating on improving well productivity. Completion and efficiency has become the name of the game to control our total well cost. We continue to experiment with fewer stages. We're varying the volumes of fluid and sand that we pump. We're actively exploring regional sand sourcing alternatives. And we're executing zipper fracs where we can to control our cost. To ensure crew efficiency and adequate prop sourcing, we maintain a consistent number of frac fleets and plan our resource needs well in advance. As such we have not had any significant issues procuring the resources that we need, when and where we need them. With our continued focus on efficiencies and some stability in per unit completion cost, we've made no changes to the well cost estimates we provided you last call. In the Permian, our current Wolfcamp 2-mile AFEs are running in the range of $10.5 million to $12 million. While still pumping larger fracs in our Bone Spring program, we've kept our current 1-mile lateral AFE in the range of $5.5 million to $6.7 million. In Cana, our 1-mile lateral Woodford AFEs are running $7.3 million to $8 million. And with our completion design changes and efficiency gains in the Meramec now taking root, we're maintaining our 2-mile lateral AFE range of $10 million to $11.5 million. In closing, with Q3 coming in better than expected and Q4 projected to provide a nice ramp in production, we're forecasting solid 18% to 19% year-over-year production growth for 2017. Our focus on oil during the year is paving the way, with the midpoint of our total company oil projection equating to 26% growth over 2016. The projected record production in Q4, with an anticipated 43 net wells either drilling or waiting on completion at year end, which will provide us with great momentum going into 2018. With production – with our production up, our constant check, and great returns from our drilling projects, we remain very confident about our program. And we're excited about our 2017 results. So with that I'll turn the call open – over to Q&A.

[Operator:]

Okay. We will now begin the question-and-answer session. The first question comes from Drew Venker with Morgan Stanley. Please go ahead.

[Drew E. Venker:]

Hi, everyone. Tom, you talked in your prepared remarks about the capacity to generate free cash flow, while delivering strong growth. And just hoping you could speak to how you guys think about balancing shareholder preferences for overall more free cash flow generation? With the really strong asset base you have and the really high rates of returns that you can generate. Because it sounds like just those may be a little bit at odds or at least there's different pressures from different sides.

[Thomas E. Jorden:]

Well, thank you, Drew. The conversations have been fascinating to us. And I think there is certainly different viewpoints, depending on which shareholders you speak with. I think our long term owners would like to see us invest our cash flow, make sure that we protect ourselves on draconian downside. We've talked in the past, we stress test at $40 oil, $30 oil. We stress test at $2.50 flat gas and $2 flat gas. And these are all NYMEX prices. And as long as we can achieve outstanding returns and we have protection well above our cost of capital, at a draconian downside, our bias is going to be to invest our cash flow. Now we do pay a dividend. We cut our dividend last year, and we weren't very happy about that. We did it as a matter of necessity in a declining cash flow environment. In February, we'll reopen a discussion about dividend. And I think our bias is going to be to get that dividend back on a growth profile. But we're not actively looking at any share buyback program. We're in the business to make good investments, as long as we're getting the kind of historically outstanding returns that we are in this environment. That's our business.

[Drew E. Venker:]

Thanks for the color, Tom. Just one follow up on the 2018 outlook. You guys talked about conducting additional spacing pilots. And I was really hoping that by this quarter you guys would have, I guess to use your term, broken the spacing across the whole portfolio. It seems like you just can't make that happen quite yet. So as you think about trying to find the optimal design and development spacing and configuration, where are you going to be testing those limits? If there's any specific area? Maybe it's just across the board for next year?

[John Lambuth:]

Drew, this is John. I guess I'm kind of glad I don't have to use the word broken yet. But I think in some ways it's a testament that we're getting very good at being able to understand the overall resource in place we're trying to develop and understand what our frac design is doing. As I said, with the Clyde Copeland, the outcome we're seeing from Clyde Copeland kind of fit what our preconceived model said it should do. It's performing very well. So in some ways I think we're very – we're getting pretty good for each distinct interval of understanding what that resource in place and what its full potential is. Now still we're going to push the boundary. I could argue right now the pilot I'd mentioned – the two pilots in Lea County, where we're going to be testing much tighter spacing, both in the Avalon and in the Upper Wolfcamp in Lea County, that's probably tighter than anybody else has done so far up there. I feel confident we wouldn't go out there with that design if we didn't feel like we had a chance of achieving it. But there is some risk that maybe we do break it up there. But I think it's also again, as I said, a testament that we're just getting much better at understanding what we're doing with these pilots. And how our frac is interacting or working in terms of the ultimate production we get.

[Thomas E. Jorden:]

Let me just add to that. There seems to be a bit of a nomenclature shift between – with the word pilot and the word development. As long as we're drilling pad projects, multiple wells off each pad, it's really development. And the fact that we're testing some things and learning along the way is a side benefit. We're already achieving the capital efficiencies and the savings from multi-pad development. And by continuing to test spacing, continuing to optimize our frac design, we are extracting more value for each acre we own. And we're going to continue to push that envelope for as long as we're in business. I mean there's – so if you're looking for us to come up with a stamp that we can just replicate and put our curiosity aside, you're talking to the wrong management team.

[Drew E. Venker:]

Thanks, Tom, and thanks, John.

[Operator:]

The next question comes from Jeanine Wai with Citigroup. Please go ahead.

[Jeanine Wai:]

Hi. Good morning, everyone.

[Thomas E. Jorden:]

Hi, Jeanine.

[Joseph R. Albi:]

Morning.

[Jeanine Wai:]

Hi. So my questions, they fall into the Mid-Con area. So in the Meramec, well, at times it looks like the [Leota] Jacobs development is probably deferred at this point. What size program could the Meramec footprint handle at this point in time? Or what size do you think would be prudent, given what you know or what you don't know about the rocks?

[John Nelson:]

This is John. I will tell you, we're still working up our 2018 plans for Anadarko. And you're right, we still need to work with Devon regarding the bigger long lateral development, although I think there's strong sentiment that that Leota Jacobs will probably get pushed into late 2018, early 2019. Right now we have quite a bit on our plate to still achieve in the Meramec. One of the big issues still is understanding what the ultimate spacing looks like in the Meramec. We – as we talked about a lot, there are a lot of pilots ongoing that we have an interest in, that we keep watching carefully. And then we our self are looking at several additional pilots that we'll probably be funding next year to again better understand what our potential is in the Meramec. That's kind of what our thought process is right now for the Meramec. We're certainly – of all the plays we have, and Tom kind of mentioned this, the Meramec is probably the one – the least one where we're ready to go to any form of development, where we still have a lot of questions in both how many zones can we land in? How many wells per each zone? And even more importantly, what is the appropriate frac design? So those are some of the things that we'll be trying to address in 2018 within the Meramec program.

[Jeanine Wai:]

Okay. And then my follow-up is on capital allocation. And maybe I'm just bringing the pendulum too far to the right here on this one. But how far do you think you would ever tilt the capital program towards the Permian, given however you frame operational risk from a company-wide level? Or your framework for just capital allocation in general? I think from an investor standpoint it oftentimes seems that the more Permian, the better for you guys. But I know that might not be how you're thinking about the program?

[Thomas E. Jorden:]

Well, Jeanine, we think about the program purely in terms of rate of return. And as John said in his remarks, this Lone Rock area has rates of return that compete every bit, heads up with our Permian. And some of the Meramec competes every bit, heads up with Permian. So when it comes to capital allocation, we're kind of agnostic on basin. I know that there seems to be a real preference out there for Permian. But we don't really see the difference between cash flow from one basin to another, as long as the returns are there. I think certainly, as I said in 2018, I think we'll have probably a capital allocation that's equal to or greater towards the Permian than we did this year. But that's – some of that's just about the evolution of the projects more than the returns. We like both basins. And we're not interested in being a one basin player. We think that the flexibility of the two basins really helps us manage the cycles of our business more effectively.

[Jeanine Wai:]

Okay. Great. Thank you for taking my questions.

[Operator:]

The next question comes from Irene Haas with Imperial Capital. Please go ahead.

[Irene Haas:]

Yeah. Hi, everybody. A question on Anadarko Basin, the Lone Rock project that's really exciting. Just wondering, in addition to the Woodford, how is the Mississippian looking for that specific area?

[John Lambuth:]

Boy, that is a great question. We are looking at that very carefully. In fact, we recently took a whole core through the Mississippian as well as the Woodford. We're aware of some outside operated wells nearby that look rather interesting. And so we our self will be testing the – what we call the equivalent Mississippian or Meramec interval sometime and early 2018 as well, and then we'll see what that potential is.

[Irene Haas:]

Great. Thank you.

[Operator:]

The next question comes from Mike Scialla with Stifel. Please go ahead.

[Michael Stephen Scialla:]

Morning, everybody.

[Thomas E. Jorden:]

Morning.

[John Lambuth:]

Morning.

[Joseph R. Albi:]

Morning.

[Michael Stephen Scialla:]

Wanted to ask you about the Pagoda pad, looks like you've got quite a bit of data there now. Are you comfortable with that data to kind of declare victory and use that as your – I know you want to push the limits. But is 16 wells per section in the Upper Wolfcamp Pagoda, is that going to be the standard or minimum I guess for that area going forward?

[John Lambuth:]

This is John. Yes, we're very, very pleased with the Pagoda results. As you can see, we're almost 180 days into it, and they're holding up very well. The only other comment I'd make though is that certainly that well design of 16 is very appropriate for the equivalent thickness or resource in place. So I can't necessarily rubber stamp over all of our Wolfcamp acreage in Reeves County. But there's a good part of it where 16 looks pretty good. We are going to be testing actually even tighter coming up here soon. We're going to add a third bench and go a little bit tighter still based on the Pagoda results. So as Tom said, we're not going to rest on our laurels. We're going to keep pushing that boundary in terms of how many wells can we get in to that very prolific Upper Wolfcamp section there in Reeves.

[Thomas E. Jorden:]

But I just want to add to that, that tighter spacing is adding another bench.

[John Lambuth:]

Yeah. Right.

[Thomas E. Jorden:]

It's not necessarily tighter well in well spacing. And then I really want to underscore something John said. It's not a one size fits all, and this is particularly true in the Anadarko Basin, where our spacing tests are applicable everywhere however we look at thickness, we look at resource in place. And a particular spacing derived in one section of that play may not be appropriate for another, because the rocks may thicken and thin.

[Michael Stephen Scialla:]

Got it. Thanks. And you mentioned, John, the results from the 10,000-foot laterals over in Culberson look pretty solid. Is 10,000 feet going to be the goal there now? And I understand it's going to depend on acreage configuration. But also think you guys were talking about trying some laterals even longer than 10,000 feet. Is that something that's still in the works?

[John Lambuth:]

Yeah. Well, first comment is if the acreage allows us, then we are always a minimum at 10,000 feet in the Wolfcamp as well as any of our other intervals. That's our going standard length of lateral. That said, we do have a lateral, because the acreage allows us to do this, down south of Culberson. We have some acreage that we're doing 2.5 miles on. And, yes, there's still a lot of debate about whether we should go even further. I know our drilling department is very anxious to talk about doing that. And again it's going to be a question of, will the acreage allow us to do that? There are places within the JDA. But we've talked about it. We're right now, because of the way the sections line up, we've been doing 7,500 – opposing 7,500-foot laterals. There are still areas there where we could instead go 3 miles with that section. So we are internally talking about it. Like I said right now the longest I'm aware of is we're doing a 2.5-mile right now down south of the JDA.

[Michael Stephen Scialla:]

Thank you.

[Operator:]

The next question comes from Neal Dingmann with SunTrust. Please go ahead.

[Neal D. Dingmann:]

Morning, all.

[John Lambuth:]

Morning.

[Neal D. Dingmann:]

Maybe question for you, John. Just wondering on – the spacing that you showed on the Clyde Copeland, and I see kind of where that is. Do you anticipate sort of continuing to push that even further north? I'm just trying to get an idea of that greatest – that tight of spacing and how phenomenal that looks in that particular area. Could we see this as it moves over either to the eastern core or up to the Leota Jacobs? I'm just trying to get a sense of how – what the potential is for this type of spacing?

[John Lambuth:]

Well, we ourselves are looking very carefully at the Clyde Copeland results. We still have some more work to do with that pilot. We have what we call individual well strut-ins (37

[Neal D. Dingmann:]

And then, John, I know you don't have a full 2018 plan out yet. But with these details and the success you've seen both in the Del now and in the Midland now with the down spacing, does this make you more inclined to do much more, I guess, batch drilling next year? Versus just maybe two or three? I'm just trying to get a sense of how large sort of the average development will be next year?

[John Lambuth:]

Well, that is a very excellent question. It's something that we our self are asking all the time in terms of what is the best capital efficiency from a development standpoint? Is it a half section? A full section? Three sections? What works best for us? And that's something we're spending a lot of effort on. One thing I need to make clear, no matter whether it's a half or full or whatever, all of them are from multi – are from multiple wells from a pad. There is a clear efficiency gain by putting a certain number of wells per pad. Now we also struggle with, you may hit a point where you have too many wells on a pad. That's something we're looking at. But it's fair to say just about everything we do now is in mind where you're going to have multiple wells off of a single pad, regardless of whether it's a half, full, or is multiple section development.

[Thomas E. Jorden:]

Yeah. This is a complex problem. In fact, John and I were discussing this earlier this morning, because there's a – we get a lot of questions about, all right, when are you going to go into full development? And that question suggests that full development is many, many wells manufacturing, let's say 50, 60 wells in a project. And that sounds good from a top line, because you can have efficiencies, you can have cost savings, you can have infrastructure savings. But the capital required for a project like that and the time delay between first investment and first production is also a significant consideration. It may be that there is some optimum that's much smaller than that. I don't know if it's 8, 12 [wells]. I mean, we'll figure it out as we go. But again we view this problem through a lens of fully burdened rate of return, and that that includes first investment to first production. It includes parent-child interference. It includes infrastructure investment required. It includes production bottlenecks. If you have too many wells flowing into a system, you have to overbuild it to accommodate peak production. And so there's a very, very complex set of criteria. We will view this problem in order to manage and maximize our full cycle rates of return. And so our engineers are hard at work on this. There's some good creative thinking going on. I had some discussions with our Permian team on this this morning. They're asking all the right questions. And I can't tell you today whether our optimum answer will be dozens of wells per project or something a dozen or fewer. It may be different depending on the area. John, you want to add to that?

[John Lambuth:]

No. I think in fact I could argue based on what I see – Tom hit on it very well. Probably the bigger governing factor is not our ability to go out there and drill 20 or 30 wells and complete them, it's infrastructure, especially in the Permian. Your SWB needs, your compression needs, just all of that has to come into play. And you're absolutely right. On a full cycle basis, it does us no good to go out there and overbuild just to handle that peak production of 30 wells and then have that facility sitting there. So we're giving a lot of thought to what is optimal, especially from a return on capital invested standpoint.

[Joseph R. Albi:]

And this is Joe. What I'd add there is, just from the simple example of the battery itself. If you had a nine well battery, and we drilled all the nine wells at once and turned them all on at once, that size of that battery is going to obviously need to be bigger than if you drilled three, come back later drill another three, drill another three. And that can have a significant impacts on economics. So it's just all this balancing of everything Tom mentioned, John mentioned. And even on the facility side, the production facility side, it's a complex animal.

[Karen Acierno:]

It's already happened in Reeves too, where we've said, okay, we want to – we've had a couple of small developments based on spacing that we've tested and where facilities are available and acreage is available. So we go in and drill with the pad. It may be a couple wells or three wells or whatever. But they're being drilled based on our results on these spacing pilots. So we're already applying it.

[Neal D. Dingmann:]

Very good. And thanks for all those details, very helpful.

[Operator:]

Okay. The next question comes from Jeffrey Campbell with Tuohy Brothers. Please go ahead.

[Jeffrey L. Campbell:]

Good morning and congratulations on the quarter. First of all, I just want to kind of get some background color on this Lone Rock thing. I mean was this legacy acreage that you took another look at? Or was this a dedicated organic acquisition? And can you tell us how Lone Rock attracted your attention? And how long it took you to build your position?

[John Lambuth:]

This is John. Lone Rock has been with us for quite a while. It was a position that we originally acquired in our early entry into the play. But early on the wells were very, very disappointing. And so over time we keep going back to Lone Rock and we keep doing the hard work of trying to understand, why is this area different than other areas? And I will tell you perseverance really paid off in the case of Lone Rock. We saw the potential in terms of the resource in place. But let me just say there's something else very unique about Lone Rock. It's an area where we have much higher pore pressure than adjoining fault blocks or areas next to it. And that in turn we believe is leading to much better yield potential. And quite frankly with our latest frac design and the lateral length we're drilling, much lower decline rates on these wells. So that's what's leading to some of these superior returns we're seeing. But it was not been an easy a nut to crack. It's taken many, many iterations of both frac design – but I will tell you without a doubt landing zone has been probably the most critical issue in Lone Rock, because there's a lot of variability in the Woodford Shale vertically in this interval here. And our team has done a phenomenal job of understanding that and really honing in on where exactly we need to place these laterals. Now that we've gotten to where we are, we're very, very excited. So much so that we've been doing our best to enhance our position. And that's something we've been working on over the last year or two years. Such that for the most part now at Lone Rock we pretty much operate the majority of that position. That's really where we wanted to get to, which is why we for the longest time have held back wanting to talk about it, as we go and did a number of trades to get us to this position.

[Jeffrey L. Campbell:]

Okay. Thank you. That was really great color. And then another quick question I'll ask is just looking at the slide on the Leon Gundy, it said that the next phase of work there was to work on the completion sequence tests. And just wondered if you could give a little bit of color on what exactly are we talking about here?

[John Lambuth:]

Sure. We recognize now that over a good part of our undeveloped acreage, especially in what we call Township 14 North Range 10 West, that we have the opportunity to co-develop the Woodford and the Meramec. And what we are still working on is exactly how that sequence should take place. Can we do, for instance, Meramec only, and then follow with Woodford? Or vice versa? Or if we find that we cannot do it independently that because of a lack of let's say, frac-ed area, we have to do them all together, even in that scenario, what is the right order in terms of when you frac or stimulate? Do you do Meramec first and then do Woodford right afterwards? Or vice versa? And those are the things that we're trying to answer. We're trying to be very deliberate about it, because as I said, we have a large, large amount of acreage that appears to have that potential to be co-developed Meramec/Woodford. So right now we have a number of two- and three-well tests that we've done that are just now flowing back that are testing that frac order. And we'll be watching those carefully to help better formulate our go-forward plans for that acreage block there.

[Jeffrey L. Campbell:]

Okay. And if I can follow that up and not get Tom mad at me at the same time. Because I wouldn't want to argue about development versus testing. These tests that you have here, when do you think that you're going to start to get an update? Or that you can maybe at least pick some sweet spots and really try to experiment with these developments you're talking about? Maybe pick an area and say, okay, we're going to do the Meramec or the Woodford in this order based on these tests. I mean when do you think it'll happen?

[John Lambuth:]

Well, I think there is a lot of work being done right now to do just that as part of 2018 in terms of picking off a section or two and getting it out there and testing these things at a bigger scale. So I would just say just hold tight and wait to when we talk about 2018. And then I think you'll get a better feel for what our plans are for that.

[Jeffrey L. Campbell:]

Okay. Perfect. Thanks very much.

[Operator:]

The next question comes from David Deckelbaum with KeyBanc. Please go ahead.

[David A. Deckelbaum:]

Morning, Tom, Joe, and John. Thanks for taking my questions. Tom, I just wanted to clarify your remarks. In your prepared remarks you said that the Permian could see a greater share of capital next year, because it's more shovel ready for development. Is that a comment around being more logistically ready for some more full field development or larger pads? Or is it more of a comment around geological understanding and spacing?

[Thomas E. Jorden:]

Well, I think it's a little of both. But I'll just follow on what John said. I mean the Leon Gundy and the sequencing is a perfect example. We do think that it may matter which order you complete the Meramec and Woodford. And so we're just hesitant to march off and drill 12, 16, whatever the number of wells are on a particular pad project and get that wrong. We have some early indications that this may be a significant problem. And so we're – you know, we don't have those complications. We're a little further along in the Delaware Basin. It's all to the good. I think the Anadarko is hard at work, getting these things ready. And I think you'll see us move into development there in short order. But as we sit here today looking at 2018 capital plans, we think we've got a little further understanding of some of these issues in the Delaware.

[David A. Deckelbaum:]

I appreciate that, Tom. And I guess on the Lone Rock area, I understand some of the differences here with the sensitivity of the landing zone and higher pore pressures that you're seeing. I guess how would you contrast it I guess at a high level to the rest of your Cana play I guess on how you're viewing mix? I know it's very early on the spacing side. But I guess how do you think about this area generally? Or you just see it as a more productive or more saturated interval?

[John Lambuth:]

I think that the way we look at it is, as I said earlier, it is an area of much higher pore pressure, relative to the depth you drill to. It's much better yield content. And because of a certain makeup of the rock, we see these much lower decline rates. And that just leads to very good IPs, but lower decline and very excellent well performance. It doesn't carry itself across all the Woodford acreage that we see. But there are other areas that have similar characteristics. I could argue again part of Leota Jacobs I think has similar opportunities in terms of the yield content and the opportunity there. That's also an area of a little bit higher pore pressure, pretty good yield. So in some ways I do see some of the things we're doing in Clyde Copeland translating well to Lone Rock. I will point out though that at Lone Rock, we don't have quite the amount of thickness as we do say at Clyde Copeland. So as Tom said, I cannot directly take those excellent results from Clyde Copeland of 16 and 20 wells and easily translate it to Lone Rock. That would be foolish, because I don't have near the resource in place from a thickness standpoint. I'm probably more likely in to 10- to 12-well range, which is something we will be testing in that area here very soon.

[David A. Deckelbaum:]

Do you think that that area benefits at all from having less prior development around it relative to some of the areas further north?

[John Lambuth:]

No. No, I don't, because basically we still have to drill individual wells per section just to get it to an HBP status. So it's not unlike anywhere else that we have developed Woodford. We always have typically an existing parent well on that section. So we're very familiar with having a parent well and understanding its potential relationship to future development. That's something we've been doing a long time here. So, no, there is no drainage issue at the Woodford from a parent well. I can assure you of that, just given the tightness of the rock and the low permeability of it. I don't foresee that to be an issue at Lone Rock. It is again more – Lone Rock is very unique in its structural set up from a pressure yield standpoint that it's leading to the kind of returns we're seeing there.

[David A. Deckelbaum:]

Great. Thanks, John.

[Operator:]

The next question comes from John Nelson with Goldman Sachs. Please go ahead.

[John Nelson:]

Good morning. Thank you for taking my questions. I was just curious, what is the appetite for maybe paring some of your longer dated inventory? I ask because you keep seem to having success in getting more wells on the same level of acreage. I'm just trying to see if there is a – if it's being considered as a – asset sales are being considered as a way to maybe improve returns and unlock shareholder value?

[Thomas E. Jorden:]

Well, John, we're always looking at things that are potential divestment candidates. And we do have some things that currently are on our list to divest. They're more things that I would call non-core and probably not in the arena that we've discussed on this call. They're good quality assets, but for whatever reason they're just not currently a focus. So from a valuation standpoint, they're probably more valuable in somebody else's hands right now. But in our core Cana play, in our core Delaware play, we're probably not going to be looking at divesting any time soon.

[John Nelson:]

So I guess that sounds like more kind of normal course portfolio rationalization, as opposed to seeing the inventory as so deep that you'd potentially want to pull some of it forward by monetizing it?

[Thomas E. Jorden:]

Well, we're – this is not theology with us. In fact, one of the things that John has a new ventures group that's always working on new things. And one of the things I tell them repeatedly is success would be we find a new area that's so much better than what we've got that we end up shedding some of what we've got in order to let it be supplanted by new stuff.

[John Lambuth:]

Yeah.

[Thomas E. Jorden:]

So, yeah, we're constantly looking at a refresh. And I appreciate the – just the observation that decades and decades of inventory is wonderful to talk about, but from a net present value standpoint, anything out more than 5 years or 10 years is not terribly high on net present value. So we constantly look at this. It's an open conversation here at Cimarex.

[John Nelson:]

Great. Oh, I'm sorry.

[John Lambuth:]

Yeah. I was just going to add one quick comment. I mean behind the scenes there are always lots of smaller deals going on, acreage trades where we're constantly enhancing our positions. So there are like smaller acreage blocks from time to time we will divest, nothing that's newsworthy. But it's always in an effort to get us to that nice contiguous block of operated acreage that gets us in a much better position from a standpoint of future development.

[John Nelson:]

That's fair. And then, Tom, I appreciate the very thoughtful prepared remarks at the outset on the E&P business model. As we think about maximizing returns, is there a level at which you would say the company is under-levered?

[Thomas E. Jorden:]

Well, many people would say we're there. But the experience that we've had the last few years has told us that under-levered is in the eye of the beholder. And I will tell you that having lived through $26 oil, we were faced with many difficult decisions. We were faced with some tough days. But we were never faced with an existential threat of Cimarex. We always were able to focus on the right things, how to get our cost structure where it needed to be, how to make sure our assets could perform in a lower cost environment. We came into this party with a lean organization and low debt. And our learnings from that are, both of those are good. So I don't think – I know from time to time we get criticism from people that perhaps are more financially sophisticated than I am on the proper use of leverage. But we're going to be in business for many decades to come. And staying low levered is a pretty good insurance against commodity fluctuations. Mark, do you want to comment on that?

[G. Mark Burford:]

Yeah, John. I guess I'd comment that right now our debt to EBITDA ratio, the ending – trailing 12-month third quarter is 1.4 times. We've talked openly in the past that 1.5 times or less is probably an objective that we want to maintain. And we're there now. But I just – as Tom mentioned, the volatility in the cash flows were – kind of keep approaching our target rate or a little less, and that's we want to see that 1.5 times debt to EBITDA or less. And as we go into the future years, we see that decreasing further as our EBITDA is growing. But it is the conversation that we have in the future is that as our EBITDA grows, and whether or not we'd want to use more leverage or not?

[Thomas E. Jorden:]

Well, yes. It's the debt metrics we look at.

[G. Mark Burford:]

Right.

[Thomas E. Jorden:]

Not the actually – the debt level.

[G. Mark Burford:]

That's right.

[Thomas E. Jorden:]

But, John, let me say this. And we get asked this a lot. We've looked at a number of opportunities to purchase assets over the last few years. And we haven't found anything that we've pulled the trigger on. But we're always looking. If we found something that we thought had long term strategic value and that we could get really good full cycle fully burdened returns through that transaction, and it involved a higher degree of leverage than we've historically operated at, we would consider that seriously. So if we temporarily went into a period where we had higher leverage, we'd probably look at a much more aggressive hedging program to protect ourselves. But this – our balance sheet is a tool. And we recognize that. And we'd be prepared to use it.

[John Nelson:]

Very thoughtful. I appreciate that again. I'll let somebody else hop on. Congrats on the quarter, guys.

[G. Mark Burford:]

Thank you.

[Operator:]

Okay. The final question comes from Matt Portillo with TPH. Please go ahead.

[Matthew Merrel Portillo:]

Good morning, guys.

[Thomas E. Jorden:]

Morning.

[Joseph R. Albi:]

Morning.

[John Lambuth:]

Morning.

[Matthew Merrel Portillo:]

John, just a quick question. Noticing some Bone Spring wells starting to pop up on your map in the Northern Delaware Basin. And just curious...

[John Lambuth:]

Yeah.

[Matthew Merrel Portillo:]

...how you guys are looking at that delineation program, as your results and also peers seem to be having some success? And then heading into 2018, could this become a larger development for you at this point?

[John Lambuth:]

Yes. We are continuing as we always are to drill the occasional Bone Spring well. And we have quite a number we're doing. In fact – well, just in general, I will tell you just in the fourth quarter alone, the combination of Bone Spring, Avalon, and Wolfcamp, we'll drill 13 wells in Lea County, gross wells in the fourth quarter. And quite a few of those will be Bone Spring wells, both Second and Third Bone Spring. And you'll see us occasionally drilling more of those during the course of next year. It's just – it's a very nice complement to our overall program. I don't know. You could maybe envision a half to a full rig's worth of drilling across the entire breadth of the year that we will scatter in. And yes, what we – one other comment I'll make is, based on other operators' results, it is kind of redefining now what we see as perspective. Whereas before we maybe – we may have high graded to a point. We said there wasn't much left to do on our existing position. I cannot say that anymore. And that we definitely see more potential in our acreage. And you'll be seeing us drill more of those wells in the coming year.

[Matthew Merrel Portillo:]

Great. And then as my second follow-up. You drilled two wells this year in Ward County, targeting the Wolfcamp. Just any updated thoughts on the results so far? And how you guys are thinking about that part of your portfolio going forward?

[John Lambuth:]

Yeah. We have drilled two. We have another one coming up. And we're still monitoring results. Ward is one – I kind of – I'm not – sometimes I think of Ward like what I talked about with Lone Rock and that – what I mean by that is, we see great resource potential there. We just haven't fully cracked the nut so to speak in terms of perfecting returns there. I see the potential. The overhang we have is of course the existing Third Bone [Spring] production and drilling we did many, many years back. And what its interaction or interplay is to the current drilling we're doing now. That said, I still see a lot of resource potential there, even when I account for those existing wells. We're just trying to figure out – again kind of like Lone Rock – where is the best place to land those wells and frac them to bring them to a level or rate of return profile that they will start – compete with the other programs for capital. So that's where we are right now with that program.

[Matthew Merrel Portillo:]

Great. Thank you very much.

[Operator:]

This concludes our question-and-answer session. I would like to turn the conference back over to President and Chief Executive Officer Tom Jorden for any closing remarks.

[Thomas E. Jorden:]

Yeah, I just want to thank everybody that we've had some great questions here this morning. And we're going to continue to work hard to post results like we have in this quarter. We're very excited about the progress we're making and really appreciate the thoughtful questions that you brought before us. So we look forward to next quarter. Thank you.

[Operator:]

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