Cimarex Energy Co.
Q2 2017 Earnings Call Transcript

Published: 9 Aug 2017

[Operator:]

Good morning. And welcome to the Cimarex Energy Second Quarter Conference Call. All participants will be in listen-only mode [Operator Instructions]. 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. Please go ahead.

[Karen Acierno:]

Good morning. And welcome to the Cimarex’s second quarter 2017 conference call. An updated presentation was posted to our Web site yesterday; we will be referring to this presentation during our call today. As a reminder, our discussion will contain forward-looking statements; a number of actions could cause actual results to differ materially from what we discussed. You should read our disclosures on forward-looking statements in our latest 10-K and other filings and news releases for the risk factors associated with our business. We expect to file our 10-Q for the three months ended June 30, 2017 later today. So today, 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 our operations including production and well costs. Our CFO, Mark Burford, is also present to help answer any questions. So that we can accommodate more of your questions during the hour we have allotted for the call, we’d like to ask that you limit yourself to one question and one follow-up. Feel free to get back in the queue if you like. So with that, I’ll turn the call over to Tom.

[Tom Jorden:]

Thank you, Karen. Thank you to all of you here on the call today. We look forward to updating you on our operation and outlook as well as answering your questions. Cimarex had another very good quarter production for the second quarter averaged 1,156 million cubic feet per day or 193,000 Boe per day. This was above the high end of our guidance range driven by continued improvement in our well results, un-drawing excellence in our field execution and timing of our well completions. As a result, we are modestly increasing our full year production guidance to 1,120 to 1,140 million cubic feet per day or 187,000 to 190,000 Boe per day. Our full year exploration and development capital remains unchanged at $1.1 billion to $1.2 billion. I’d like to take a minute to comment on two topics which have particular interest during this earnings season, infill development well performance and gas ore ratio or GORs. First, a few comments on infill well spacing. As the Delaware Basin and stack place have developed most of the headline grabbing well results have been parent wells. These parent wells standalone and although representative of the reservoir deliverability and completion efficiency, they may not be good indicators of expected well response in infill development. Parent wells are unbounded by nearby wells and therefore do not compete for reserves with nearby wells. As infill development wells are drilled, they may exhibit interference with one another and consequently reduce performance compared to the unbounded parent well. In each area, we seek to find that ideal infill well spacing that optimizes resource capture, rate of return and net present value. The ideal infill well spacing is a function of reservoir properties, completion techniques and commodity pricing. It is a non-unique solution. At Cimarex, we've put tremendous effort into optimizing our infill development well recoveries and economics. Most of this effort has been focused on understanding the down-hole physics of our stimulations. Our goal is to generate highly efficient near wellbore stimulations and maximize the value for developed sections. You'll hear about some of these results during this call. We want to focus on results, actual well production and actual cost. The asset test of the success or failure of any infill development pilot lies in how we use the learnings in the planning and execution of the next spacing pilot. Are we putting our next batch of development wells closer together or farther apart? We are very pleased with the progress of our teams in this regard. Across our asset base, our next generation of infill development pilots is testing tighter well spacing and additional development zones. We are pushing the envelope based upon our growing understanding. Jon will discuss our results as well as upcoming pilots. Each infill development pilot tests something new. As I said, the goal is to maximize resource recovery, minimize well to well interference and increase the economic value of our projects. Furthermore, by pushing well spacing tighter and tighter, we further expand our deep inventory of top tier drilling locations. As always, results are what count. Secondly, I'd like to say a few words regarding the ongoing discussion of GOR. We've been at this a long time and detailed reservoir of our management, engineering and forecasting are in our DNA. Our current drilling and completion activity spans two prolific basins with deferring in situ hydrocarbon types, reservoir properties, pressure regimes and depths. GOR is not a one size fits all issue and can exhibit tremendous variability depending among the fluid phase and the reservoir among other factors. The phenomenon of decreasing yield or increasing GOR is different for each area for each pressure regime, for each reservoir and for each completion style. All of our type curves all of our forecasts and all of our economics account for either decreasing yield overtime or an increasing GOR overtime. And we performed look-backs our historical production to make sure that we are properly modeling these effects. We have intentionally studied this issue for many, many years and are confident that we are properly accounting for these phenomena in our reserve bookings and in our type curves. Finally, let me make a few comments about capital investment as we look ahead into 2018. This has been a subject of much discussion during the past few months with some voices issuing a siren-call for the industry to exercise capital discipline in response to the macro oil environment. Capital discipline is one of those catch phrases that mean something different to everyone who utters it. Although, we’re not prepared to give a specific outlook for 2018 capital, I can offer some thoughts on how we approach the problem. In 2016 and 2017, year-to-date, we have achieved excellent returns in our capital investments even by historical standards. As we look back on the past five years, our 2016 and 2017 returns exceed the returns we achieve during the halcyon days of 2013 and early 2014. This is due to significantly increased well productivity, lower cost and the growing capital efficiency of our infill development projects. We stress test every investment down to $40 and $30 flat NYMEX oil and $250 and $2 flat NYMEX gas to ensure our return on capital, if prices were to fall further. Cimarex is moving forward with a great investment portfolio, a deep inventory and a commitment to maintain a strong balance sheet. The macro environment will do what it may, we will navigate through it. It makes no sense for us to sit on the sidelines and wait for a better macro environment. If each company responds individually to the quality of their investment opportunities and manages their balance sheet as they individually see fit, free markets will sort out the macro; some will succeed and some will fail; Cimarex is moving ahead. We are committed to be clear and transparent on these and other topics in our investment communications. We look forward to entertaining any follow-up questions you may have on development infill spacing, GOR or any other topics. With that, I’ll turn the call over to John for operational detail.

[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 remainder of 2017. During the second quarter, Cimarex invested $296 million on exploration and development activities. About 54% of our second quarter capital was invested in the Permian region with the rest going for activities in the Mid-Continent region. We invested $216 million of the $296 million on the drilling and completion of new wells. Companywide, we brought 51 gross, 18 net wells on production during the second quarter of 2017. Our 2017 exploration and development budget is unchanged at $1.1 billion to $1.2 billion with $850 million to $950 million still earmarked for drilling and completing wells. For the full year, we plan to invest 62% of our capital in the Permian region with remaining earmarked for Mid-Continent. We currently operate 14 gross rigs, eight in the Permian region and six 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 another successful down-spacing project in the Upper Wolfcamp. This pilot took place on the Pagoda state lease and Reeves County, Texas. We drilled four 10,000 foot laterals testing the equivalent of 16 wells per section spacing. As mentioned in our press release, these wells had an average 30 day peak initial production of 1,922 barrels of oil equivalent per day, of which 956 barrels per day was oil or 50%. Slide 20 shows the performance of these wells since coming online in late April. As you can see after 60 days, this pilot is performing as well as the Wood State development, which tested 12 wells per section. Based on the Pagoda results, we now plan to test the equivalent of 18 wells per section in the Upper Wolfcamp in the nearby Snowshoe section. This spacing pilot will consist of eight 10,000 foot laterals stacked/staggered in three different ventures within the Upper Wolfcamp. This pilot will spud in the fourth quarter of 2017 with first production expected in third quarter of 2018. In Culberson County, we continue to delineate our Upper Wolfcamp acreage with two 10,000 foot laterals coming on line in the second quarter. These two wells achieved an impressive average 30 day peak IP rate of 2,950 barrels of oil equivalent per day of which 51% was oil. Staying on the Culberson County area, the Lower Wolfcamp, Tim Tam pilot, has been on production for a little over six months. As shown, on the cumulative production versus days plot on slide 17 of the presentation, these infill wells are performing as well as nearby parent wells with similar landing zones. Our learnings from the Tim Tam pilot have helped us design our next Lower Wolfcamp pilot. Called Animal Kingdom, this eight well 10,000 foot lateral pilot will be testing the equivalent of 14 wells per section by both decreasing the spacing between wells and a bench plus adding an additional landing zone in the top port of the Lower Wolfcamp, a zone that we used to refer to as Wolfcamp C. A wine rack display for this pilot can be seen on page 17 of our presentation. We plan to spud this pilot in the fourth quarter of 2017 with first production expected in the second quarter of 2018. In Lea County, New Mexico between now and year-end, we plan to drill two 10,000 foot laterals in the Upper Wolfcamp in our Red Hills acreage block. The results of these wells will go a long ways to helping us finalize a plant Upper Wolfcamp spacing pilot on this acreage with our preliminary design calling for testing the equivalent of 12 wells per section and one landing zone. Additionally, in the fourth quarter, we’ll be spudding an avalanche spacing pilot that will be testing to equivalent of 20 wells per section, and a stacked/staggered pattern within one zone. Now on to the Mid-Continent. We continue to grow Meramec wells that both delineate, while holding our Meramec term lease position. We completed seven Meramec wells in the second quarter of which four were 10,000 foot laterals. These four wells achieved an average 30 day IP rate of 2,073 barrels of oil equivalent per day of which 52% was oil. We continue to be on frac to HBP all of our Meramec for makers by the end of this year. And then finally, wells in our Woodford eight well increased density pilot that is testing both 16 and 20 Woodford wells per section are now online. Results from this pilot, along with a nearby two well Meramec Woodford stack test, will help determine our plans for future developments, including our operative sections adjacent to the upcoming Leota‐Jacobs drill. We will be participating in the three non-operative sections with an estimated spud date in December of 2017. With that, I’ll turn the call over to Joe Albi.

[Joe Albi:]

Well, thank you John. And thank you all for joining our call today. I’ll recap the usual items; our second 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 great quarter here in the second quarter. Our net equivalent production came in at 1.156 Bcfe per day that’s beat our upper end of our guidance by 26 million a day and it’s setting new records for total company production. With our focus on Permian and high liquids Mid-Continent projects, we saw a solid 11% sequential quarter increase in our oil production with oil volumes up in both the Permian and the Mid-Continent. Our total Company oil volumes had a record of 57,871 barrels per day. With the strong contribution from the Reeves County Pagoda state infill project, which John mentioned, our Q2 17 Permian net equivalent volume came in at 645 million a day, up 12% from Q1 17 and 27% from Q2 16. We brought on a total of 11 gross and 10 net Permian wells during the quarter, and we had 27 gross and 13 net wells waiting on completion at quarter end. We also saw a nice gain in our Q2 Mid-Continent volumes with continued production adds from our East Cana infill project and our Meramec program. Our second quarter Mid-Continent net equivalent production came in at 509 million a day, up 5% from Q1 17. In total, we brought on 40 gross and eight net Mid-Continent wells during the quarter with 71 gross and 16 net wells waiting on completion at quarter end. Looking forward into 2017, we've updated our model to incorporate Q2 results and our projected drilling and completion schedule for the remainder of the year. With that, we've increased our full year guidance to 1.12 Bcfe to 1.15 Bcfe per day, that's up from the 1.09 Bcf to 1.13 Bcf per day reported in our last call and it reflects the 16% to 18% increase over the 963 million a day that we reported in 2016. With our 2017 capital focused on high-liquid Permian and Mid-Continent projects, we continue to project significant oil growth in both the Permian and the Mid-Continent for the remainder of the year, forecasting total company year-over-year oil production growth in the range of 24% to 29%. Our projected 2017 capital allocation remained skewed with 62% to the Permian and 37% to the Mid-Continent. We anticipate bringing 61 net Permian wells and 34 net Mid-Continent wells online during 2017. As we mentioned in last call, we're forecasting Permian and Mid-Continent continent completion activity to ramp up here in late Q3 and into Q4. And as a result, we're modeling Q3 volumes to be relatively flat with Q2, followed by a very nice ramp in Q4. Third quarter volumes are projected to range between 1.1 Bcfe to 1.14 Bcfe per day with forecasted Q4 volumes to be in the neighborhood of 1.16 Bcfe to 1.20 Bcfe per day, a strong 21% to 25% increase over Q4 16. With 44 net wells projected to be either drilling or waiting on completion at the end of the year, we anticipate having a great bit of momentum going into 2018. Jumping over to OpEx. Our second quarter lifting cost came in at $0.59 per Mcfe, that's just below the lower end of our guidance of $0.60 Mcfe to $0.70 per Mcfe and down from our first quarter average of $0.65. Although, we are seen some recent cost pressures in items such as water hauling, well servicing and equipment and maintenance, we kept our lifting cost in check during the quarter and we’ll continue our focus to maintain the reduced operating cost structure we've worked so hard at obtaining and have been able to achieve. The remaining year guidance, we've kept our previous lifting cost range of $0.60 Mcfe to $0.70 per Mcfe, which takes into account the fluctuating nature of workover expenses and our 2017 focus on high-liquid projects. And finally, some comments on drilling and completion costs. As compared to Q1, most drilling cost components remained relatively flat with the exception of tubulars, which are up 10% to 12% and wire line services, which have increased around 15% to 20% during the quarter. To help offset any growing cost increases, we’re keeping our focus on drilling efficiencies. As an example, in our Wolfcamp program, we’ve reduced the medium days from spud to rig release from 29 days in 2016 to 25 days in 2017. With completion cost, representing 60% to 70% of our total well cost, we continue to refine our completion designs to offset the recent cost pressures we’ve seen. All the while, we remain focused on improving well productivity. We’ve been able to offset a good portion of the service and prop cost increases by utilizing fewer stages and pumping zipper fracs where we can, and continue to focus on long lead time planning to ensure adequate prop sourcing and availability. That said, as compared to Q4 ’16, market increases have increased our average per well frac cost by approximately 300,000 to 500,000 per well, which again is dependent on so many variables, such as lateral length, number of stages, pounds pumped, chemical, et cetera. After incorporating market and completion design changes, as well as our continued efficiency gains, we’ve made some slide modifications to our total well cost estimates. In the Permian, our current Wolfcamp 2-mile AFEs are running $10.5 million to $12 million with a slightly raising the upper end of the range from last call for market, while keeping the low end the same for efficiencies gained for zipper fracs, water recycling and multiple well facilities. With the design change to much larger fracs in our Bone Spring program, we’ve raised our current 1-mile lateral AFEs to a range of $5.5 million to $6.7 million. In Cana, with efficiencies and completion design changes, we’ve dropped the low end of our Woodford 1-mile lateral AFE to $7.3 million while keeping the upper end at $8 million. And with design changes and efficiency gains in the Meramec, we’re keeping the low end of our over 2-mile lateral AFE at $10 million, while lowering the upper end to $11.5 million. In closing, we had a great second quarter. We’re seeing results of our oil focused development program, which generated another production beat for us in Q2 and is targeted to provide us with a nice production ramp here into Q4. With a forecasted strong second half year production, as a springboard, we’re projecting year-over-year production growth of 16% to 18% and a very strong start to 2018. We will stay vigilant for our cost and maximize the returns from our program, despite the changes we are seeing day-to-day in the market. We stay excited and confident about our program and our 2017 results. So with that, I’ll turn the call open to Q&A.

[Operator:]

We will now being the question-and-answer session. Please remember to limit yourself to one question and one follow up [Operator Instructions]. Our first question comes from Arun Jayaram with J. P. Morgan. Please go ahead.

[Arun Jayaram:]

Tom, my first question is in the Mid-Continent. I want to get your thoughts on the Leota Jacobs pad. I think Devon had talked about 40 to 50 gross wells would have been theirs and then maybe four to five drilling units. How are you thinking about your participation in that project? And if you don’t, where would you think about allocating that capital relative to this year with to be 62% in the Permian and 37% in the Mid-Continent?

[Tom Jorden:]

I’ll just gear key it for John. We really like that project, but it’s something that we’re just looking at as we go into 2018. And it's really going to have more impact on 2018, at this point, almost minimal impact on ’17. We haven’t made a decision as to what we’re going to do with those two operated sections. But I’ll let John comment on that.

[John Lambuth:]

First and foremost, I want to again emphasize when we look at that project, we like very much the rate of return that that project generates. From a long lateral perspective, a more liquid rich area of Woodford, it looks very attractive for us. But we have a lot of moving parts. We have our latest spacing pilot that I mentioned that’s testing much tighter spacing in the Woodford. It is flowing back right now in the coming months, I think we’ll start to get a strong understand of what that impact would have on future spacing in the Woodford. And quite frankly, if it shows, we can go a lot tighter than that almost leads to how many specs as we could do. And then secondly, we have what I would mention, which is a stack Woodford Meramec little tests that where we’re continually looking at the frac and the frac order and understanding if we’re going to co-develop. Because we still think for maybe Meramec potential there is well, so there is a lot of moving parts there. And then the last part we look at is just the overall capital that we would invest in such a large project and the cycle times to it. We’re very, very comfortable again with participating with Devon on the initial free sections. We’re just now asking ourselves how much more do we want to then operate. And as Tom mentioned, we really, quite frankly, don’t need to make that decision to later this year for if whether we do one or two additional operative sections, we will not be deploying rigs on that until at the earliest second quarter ‘18. So we have a little time here before we have to make an ultimate decision of how we’re going move forward with that project.

[Arun Jayaram:]

And my follow up. Tom, in the Permian we’ve learned the importance of the execution really this quarter. I was wondering if you could talk about some of -- it sounds as you’re saying in terms -- you talked about cost in terms of OSS availability and how that could impact the industries cycle times. And also I was wondering if you could maybe just elaborate on your management of water in the Permian, and what’s the unique about your water strategy?

[Tom Jorden:]

Well, those are couple of good questions. I’ll give a overview and then John, Joe I am sure want to comment. The managing of the oil field services, we manage through good relationships. We use major service providers and we give them plenty of advance notice on the resources we’ll need. We have constant interactive conversation, and really if managed through good relationship management. We have not to-date chosen to unbundle our services. So we still look at major service providers that give us soup to nut service. And although we’re constantly evaluating that, right now, that’s our approach and we think it’s working for us. On the water side, we put lot of energy into water management, both the sourcing and disposal side. I think we’ve got some very creative environmentally responsible solutions that we’re implementing. And it’s a challenge. As we go into these big development projects, it's one thing to say how much water each project requires, it's another logistical challenge to deliver that water at the pace we needed, particularly when you’re on pad drilling with zipper fracs. And with that, I'll let Joe comment on either one of those issues.

[Joe Albi:]

Tom, I think hit it right on the head. What we started to do is keep ongoing solid business relationships with service providers that we've known over the years and trust. On the frac side, I think we talked about this in prior calls. We’re not want to jump from two crews to three to four to five to six, and then back to three. We’re currently running four crews right now and have a very consistent operation going where we’re moving the crews between the two different areas, we know the crews they know our operations that it becomes and efficient operation. By doing that, we’re not constantly out in the market trying to find fleets. In particular, like on the completion side, if we were to go out and trying out of a fleet, I'm guessing we’d be looking at three to four weeks before we could line one up and have it on a well location. If we do that add it and then drop it, it's not really doing us much good. And this why we’re able to work our completion schedule no different than we would our rigs schedule, shuffling wells around optimizing fleets that we have. That relationship that we have with our serviced provider for the fracs and stimulation, we've been able to ensure adequate prop sourcing and availability by long lead times planning and let them use their size and scale to procure the supplies that we need, and that’s worked out just fine. It's pretty much the same on the drilling side, the providers that we’re using are all established providers that we have solid business relationships and have had over the years. They know we’re going to have an active drilling program year-over-year after year and that just pays off in stage as far as been able to obtain rigs and keep them working. So I don’t know if that help answer your question, but that should be the thoughts that I would add.

[Operator:]

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

[Neal Dingmann:]

Tom, my first question for you or Jon, I was just looking at I think it was on slide 10 where you just talked about the change or actually not much change really in profit over the years I guess. Just one slight change I did see was in the Woodford where you took the prop down a little bit. Could you just talk about that? It seems like nothing all, but others are starting to do back away a little bit on profit and still seen equally as good wells, if you could just, Jon, if you and Tom could just comment on the completion technique around there?

[John Lambuth:]

This is John. I guess as I've always say when this question comes up, stand pounds for the lateral foot is an interesting statistic, but it's not one honestly when we talk about our completion designs we focus on. We really focus all our attention on the cluster, the amount of sand per cluster, how many per stage in order to get the most effective stimulation to achieve, like Tom mentioned, that near bore-hole conductivity and then high productivity an offshoot of that design then is our -- then you then get sand for lot of foot. We don’t really design for that. And again, we look at it just in terms of what sand per cluster what achieves at best. I guess you could -- by the numbers, it looks were flattening out. If I felt like then we can get a better approve well by adding sand and we would do that. Right now, most of our changes are along like I said the number of clusters, how many can we treat within the stage, just become a very important thing we look at because again that helps on the cost side of it. But in the end, it's still the result of the well, so that's kind of we're at today.

[Neal Dingmann:]

And then just looking at slide 13, where you talked about just the Lower Wolfcamp, the Tim Tam infill and again, certainly performed very well. Could you talk about in that area and Tom, I think you were talking about potentially further infill projects. I don't know number one, what's the plan for further infill projects around that area? And if so, will most of those continue to be in the Lower Wolfcamp?

[Tom Jorden:]

Well, John will give you little more color that. But that Animal Kingdom he mentioned that's a Lower Wolfcamp project it's just south of Tim Tam. The volume rack for that is on slight 17, page 17. That's a significant test for us, because it tests three landing zones in that Lower Wolfcamp. That Lower Wolfcamp is prolific over just about all this acreage. It yield or oil content will change over the acreage but we see it as a very strong economically viable target throughout this asset, particularly with 10,000 foot laterals. So we're pretty excited about this Animal Kingdom test. John do you want to…

[John Lambuth:]

The only other comment I'd make is I just can't tell you how excited we are about the Tim Tam. As you can see on the display on page 17, in my remarks, I talked about how the infill wells are matching the parents. Quite frankly they're exceeding the parents now. So I think this just speaks to -- this is really all with our frac design and we've really homed in with this interval in terms of the appropriate frac design to lead to achieve that type of result. And give us the confidence to go even tighter, both between wells and to add that third bench as we're about to do in Animal Kingdom. So yes, we're very excited about the opportunities that here in the Lower Wolfcamp as we are with the Upper Wolfcamp of course in Culberson. And as I keep reminding folks, the nice thing is they are completely independent, the upper and the lower from a development standpoint, meaning we can develop one and come back at a much later date and develop the other and have no intention upon the production stream from the other interval. So it's a great position.

[Neal Dingmann:]

So would that mean you would have one, I mean you did infill on each, you’d have one still a separate parent on each of those then?

[John Lambuth:]

Well, in terms of parents, we probably in each area have one parent as an earning well to hold our acreage, early-on on this acreage in order to ensure that we held our entire Wolfcamp rights a lot of lease called for the, essentially you got to the deepest depth that's why a lot our early wells weren’t Lower Wolfcamp. We're at a point now where we have great optionality to choose where we want to go with those bore holes in that acreage. And like I said, we may choose to go develop an Upper Wolfcamp interval first and then come back many years later and develop lower. We're in a very good position to have that optionality there.

[Operator:]

Our next question comes from Drew Venker with Morgan Stanley. Please go ahead.

[Drew Venker:]

I want to just chop on the questions around inflation and service providers. You obviously sound like you're very happy with having an integrated service offering as that helps you in a lot of ways. But you also alluded to self sourcing some of those elements. So just curious if you think self sourcing would actually lead to cost savings, keeping in mind that it might lead to other issues. Or is it really minimal potential amount of savings and the execution benefit is really why you stick with integrating providers?

[Joe Albi:]

When you look at the frac, you’ve got the water, the sand and then for the most part, the service cost. The water we are self sourcing and we’re doing everything we can to be as efficient with not only the source of the water but been able to recycle the water and optimize and reduce our cost there. I mentioned that we’re procuring our sand basically through business relationships that we have. If we were to breakout the components of the frac into service cost and sand and look at the average cost per well, the real driver in the same are service costs. And what we’ve seen is that we saw a rapid increase in the dollars per stage to pump our frac from Q4 into the tail end of the first quarter. And that same has seem to have flat toed, and we believe that it has a very good chance of staying that way for the remainder of the year. What we’re doing to offset that is kind of and everything John said as a result of our completion design changes, not necessarily because the cost but because of the design changes, we’re pumping less sand, so that cost the well has gone down. We’re pumping fewer stages so we’ve been able to reduce the overall impact of those cost and the bottom line is that when you look at our average cost to pump a frac job per well even though we’ve seen way over 20%, 30%, 40% increases in some of these cost items, we kept our completion cost in check. And so that’s the angle that we’re taking and we believe it’s working well for us.

[Tom Jorden:]

This is an ongoing discussion, and our answer is certainly not ideological. If we felt like it was a real add to our rate of returns to unbundle and source these individually, we would do that and we look at that on ongoing basis. But I’ll just make -- I will make one philosophical comment. Our organization is effective because of its focused and we’re lean and that makes us a better company than if we had laid out parts of the organization far and wide. We manage by eye contact and we are a discipline focus company. So if you tell me we’ll have a group of people that are going to be distracted by worrying about what truck fleet will bring sand from one mine to our location, I really have those people worry about efficiency of our completions, efficiency of our production and gaining our well performance the absolute top tier that it did. So there is a little bit of a philosophical bias towards focusing here. And if we have good vendors, I can do that and if the close call on cost, we’re probably going to maintain our focus on things that really count.

[Drew Venker:]

And then on the Culberson County Upper Wolfcamp, you talked about a nice couple of well results this quarter. Can you talk about how that zone currently stacks up within your opportunity set? And are there any meaningful design change with those two wells that drove the stronger performance?

[John Lambuth:]

I mean we really like the outcome. And what I really like is I think people have noted we continue to get even better those wells. And so yes we continue to tanker with both the completion design but also the landing zone within that Upper Wolfcamp interval. We’re a little bit -- later in our understanding a bit like we are in the lower, so we’re still coming up the learning curve. With each change we make, it’s just keeps getting better and better. So we’re very, very pleased with -- the latest results in that interval and the fact that it seems to now be an interval that seems very perspective over all of our acreage throughout that Culberson JDA, which I don’t know that we could have said that a year-ago. So it's really turned into a top tier opportunity for us throughout that asset there.

[Operator:]

Our next question comes from Jeb Bachmann with Scotia Howard Weill. Please go ahead.

[Jeb Bachmann:]

Tom, just to close it up I guess on the service side, talk about mitigating cost. Just wondering, are you guys looking at maybe using some of the localized sand products that are going to be available on larger quantities in 2018 doing san that kind of stuff to help lower completion cost?

[Tom Jorden:]

Yes, we've looked at that. We haven’t used that local sand yet. I think others have talked about it. We've looked at crushing strength of that sand, and it’s couple of thousand PSI less than what we’re currently sourcing. We will -- that maybe okay and we may experiment with it, but we haven’t done that just yet. Joe, do you want to add to that?

[Joe Albi:]

The only thing I would add is I think most all of those deals, if you will, are going to require some kind of commitment or certain poundage over some period of time. We don’t make that many commitments and when we make them, we fulfill them. And we want to be able to have flexibility to start-stop, do whatever we need to without having some overhead. So to the extent that we’d require committing to large volumes of sand on a frequent consistent basis, it's something where you look hard and long before we even think about doing.

[Jeb Bachmann:]

And I guess my follow-up and I'll try to get an answer for this one. But the Northern New Mexico play that you guys have built an acreage position in that I guess you talked about you participating in a well going forward, or doing that well. Can you give any details on that at this point?

[John Lambuth:]

I would just simply say we have a lot of different opportunities in the Mexico. I mean I can also tell you that we have quite a few wells coming up in the Mexico. But in particular, I think the well you’re talking about is one that we have drilled and we’re evaluating. And that’s all I’ll really say about it right down.

[Operator:]

Our next question comes from Michael Hall with Heikkinen Energy Advisors. Please go ahead.

[Michael Hall:]

First, I wanted to ask on the -- in the context of all the development pilots you have ongoing with, the Animal Kingdom pilot, in particular, adding that Wolfcamp C inerrable. Is that -- I'm just trying to understand little bit I guess the thought process behind that. Is it something where you feel like you potentially need to develop that concurrently with D and therefore, you are seeing how they could develop pattern would look and perform? Or is it just something where you think you potentially can enhance the fractured network by layering those intervals on top of one another? Just trying to understand a little better the thought process on that.

[John Lambuth:]

And in some ways in doing this pilot, we’re going to try to answer all those questions. First, let me just take it real quick. We, in the past, have had excellent results in the lower Wolfcamp, especially and what we would call the lower D or D4 member. And up until recently, we have struggled some in the C member, the upper part of lower. But now we have some newer well results that’s given us a lot of encouragement that that particular bench looks as perspective economically as the rest of the lower Wolfcamp, which is why we want to go after and do this test, to add that additional bench there. And as you alluded to convince ourselves exactly how best do we have to develop, but do we have to do it all at once or can we do it independently. Our suspicions is that at that particular lower Wolfcamp is one continuous hydrocarbon system, so it they may be most effective if we co-develop it altogether. But that’s what we want to test, that’s what the Animal Kingdom is designed to tell us.

[Tom Jorden:]

The way I think about this is, in my opening remarks I talked about parent wells always being the best indicators, but they’re meaningful indicator. And the fact that our well responses on these infill projects are coming in so strong compared to those unbounded wells, is really something that there’s some attention. It's speaking to our capital efficiency and the returns of this deep inventory. So when I look at the Animal Kingdom pilot, we look at that entire lower Wolfcamp system and being able to get 14 or more wells out of that. These wells individually stand in their own they’re great returns. And so it’s just efficient resource capture. We’re really interested in that experiment, and it’s a direct benefit to the science work we’ve been going through the last couple of years.

[Michael Hall:]

And then I also just wanted to hit on the GOR topic, and appreciate the new context provided in the opening remarks. I guess, there’s been some commentary, some within the industry and investor group that condensate reservoirs could have somewhat different characteristics, and that’s straight oil reservoirs that you’ve see in the Midland Basin. And in that context, Culberson County has been brought up. Any commentary you can provide, specific to Culberson County, as it relates to oil yield over time and what give you confidence that retrograding will not be an issue overtime, and has not been in the past?

[Tom Jorden:]

Well, let me just take a stab at and then John or Joe may want to jump in here. Our lens is rate to return. I mean this issue is interesting, but we properly model our response. I think many of you who have followed us know we do a very exhaustive annual look back, we go back 15 years and we update the production on every well we’ve ever drilled. We update the cost, we update the commodity price file and produced into and we update our returns. And that’s a really important exercise for us, because it levels and grounds our future decision. And we’ve got a very confident analysis of our production history, including Culberson County. Culberson County does go from oil into reservoir to gas into reservoir. So there are varying issues around that play. But as long as we’re properly modeling that stream, that hydrocarbon stream, rate of return is that lens that means something to us. And these are lights out outstanding rates of return. But specific to reservoir issues, I am going to let John or Joe either comment…

[John Lambuth:]

I’ll just say real quick is, as Tom alluded, we have a large acreage position and a multi-variable hydrocarbon system there that any one well or project we looked at has its own design GOR or yield profile. We don’t try to slab the same yield profile over life of the well across all that acreage, we would never do that; it’s variable across the acreage depending upon both the pressure, we know that the reservoir to be at and the initial yield; and then from there, our expectation of what that yield will do overtime. And I’m very proud to say because of like Tom said the look backs we do, the checks we do, I feel very confident, and the economics presented to me is a true representation of what that well and how well will perform, both on its gas and its oil.

[Joseph R. Albi:]

I guess how I would answer that is, the phase behavior is different for all different types of hydrocarbon composition, as you know. Alluding to what Tom said if that phase behavior it's characteristics will ultimately show up in how wells produced. And so for using older wells and how they produce it's given us a DNA print of that phase behavior. Those are wells those forecasts are what we’re using to predict our new wells. So in our mines, we are truly modeling in the phase behavior of the reservoir. The type curves that we put together are oil; the in place calculations that we make when we perform biometrics are oil; the recovery calculations that we come up with are based on oil; we’re forecasting an oil curve; the gas relationships to that curve, the gas becomes a secondary hydrocarbon by-product. To the extent that GOR goes up, the well makes more gas for the same barrels of oil that we’re forecasting. And so that’s how we’re looking at it. And the bottom line is what is those forecasts for oil and for gas ultimately, from a rate on return on our capital investment.

[Operator:]

Our next question comes from Jeff Robertson from Barclays. Please go ahead.

[Jeff Robertson:]

Tom, just the question is how you’re thinking about the business now. It sounds like you’re moving more towards bigger pilots where you will drill a number of wells that may have six to nine month type lead times. Can you just talk about how you balance the answers you’re trying to get from those pilots and the capital that’s required to implement them until production? And how that tracks in with sources and uses and things like that?

[Tom Jorden:]

Well, that’s a harder the matter, Jeff. It’s frustrating, because these projects have long lead times. And so to the extent that you’re trying to turnaround, one turnaround your investment, you make the investment you want to get cash flow as soon as possible. That lead time is hard to swallow. And then to the extent that you’re testing a concept, we go crazy waiting for the results. And so we’re trying to kind of parse them up in the byte size pieces. You’ll see in the lot of our pilot, they maybe three, four, rather small experiments. That’s a challenge in and of it-self because a meaningful infill pilot needs to have meaningful number of bounded wells. But there is no right answer there. But the good news is our returns, as I said at the outset, are moving up. I mean we really are in an era of very good returns on historical basis. So I’m willing to live with that lumpiness as long as it’s modeled-in in our return profile and the time value to money that’s deployed in that infill project, it's properly accounted for then the lumpiness is with the lumpiness say. And we’ve always tailored and spoken to that long-term investor then our stands at and isn’t going to get nervous quarter-by-quarter. You’re going to see a little bit of lumpiness. But we will generate consistent long-term returns. And then finally you asked about how we’re viewing the business. We're probably in the new normal. We don’t wake up every day and wait for that rescue ships. At the beginning of this downturn, 2014, I say at the time that we told our organization that the rescue ship is not coming we need to figure out how to make a living in this environment in these conditions, and not wait for the ship over the horizon. And that's kind of where we are. We can make a good living in this environment. Our assets can support it and we're moving ahead. I mean this is the new normal.

[Jeff Robertson:]

Tom, do you show in terms of capital efficiency. Is there a sweet spot as far as what the size of these pilots needs to be for capital efficiency? Or is it more just getting you know what questions you’re trying to get the answers to and figure out the right spacing to try to see if that provides the answers?

[Tom Jorden:]

I am going to let John handle that one.

[John Lambuth:]

Again, that's an excellent question, something that we looked at a lot in terms of -- and I wouldn’t even use the word pilot, I would call development. I mean the reality is we're getting pretty close, saying Culberson and upper Wolfcamp to where we’re thinking about development. And the things we look at is; how much at a time, a half section, a full section, two sections; the cycle time for that, the amount of capital it tied up; and then the optionality of it is, that even in our best interest to do it that way or is it better to do in multiple sections. And that's something we're putting a lot of effort into. And I'll tell you some of the things that govern that, doesn’t even matter of capital, it's like someone mentioned before, can you source all the water you need to get that done, can you get enough frac crews, is it enough sand. So that's something we’re putting a lot of attention to right now, because we see ourselves moving, making that progression to where it isn’t pilots anymore, it's development. And I really, I think you could argue like in some areas we’re already there. And so we're asking ourselves how much do we want to do at each time, and it is that optimal, both capital but also effected this at wells in terms of when you come later and drill next of them. I feel very good about where we’re getting to, especially in Reeves and Culberson. And again, I think what you’re going to see here us slowly talk about more about what development really likes on this large acreage position that we’re fortunate to have.

[Tom Jorden:]

Jeff, another thing I’ll add is things go wrong and much as we hated, things go wrong. And so one of the challenges is, if you’re going to march off on a 100 well project and first flow back is, by the time you’re already committed to the full project and something wobbles off, it's not very pleasant. So you do like to get some feedback along the way, particularly if we’re testing something new.

[Operator:]

Our next question comes from Matt Portillo with TPH. Please go ahead.

[Mat Portillo:]

Just a quick question in regards to the Northern Delaware basin, I was hoping that we might be able to revisit a bit your delineation plans in the second half of the year. And specifically, it appears the industry having a bit of a renaissance in the central and northern part of Lea County. And I'm just curious as to your thoughts on some of the resource potential that might emerge in both the Wolfcamp and Bone Spring horizons?

[John Lambuth:]

We love it. We love the opportunity. We love our acreage position there. I can tell you that, for the remainder of the year, we will be drilling three Avalon, two Bone Springs and three Wolfcamp, upper Wolfcamp wells in New Mexico for the rest of the year. So we are moving up into there. And we’re very, very excited about our acreage position and the returns. Likewise, as I mentioned, we have several pilots that we’re envisioning up there. In fact, already committed to the Avalon pilot and we’re still working on our Wolfcamp pilot. So we’re getting there. But it’s also nice, because as we keep saying, a lot of that acreage is HBP, so it is not bad to have others drill around you and pick their learnings so that when we get there, we’re getting the maximum value out of our acreage. But we are moving in that direction with the rigs later this year.

[Tom Jorden:]

Our Permian team has some pretty interesting wish list for Lea County as we enter 2018. We’re looking at their proposals and we have an allocated capital. But it’s pretty exciting when you look at what they want to do with some of these pilots. And again, as I said, the proofs in the pudding is to what the companies do on the follow ups, and they’ve got some aggressive follow ups that they’d like done up there. So that’s we love it.

[Mat Portillo:]

And then just a quick follow up question regards springs area, obviously an impressive early result there. And you mentioned an 18 well down spacing test in the Wolfcamp. Does that include any sand targets to the XY horizon, or is that just in the upper section of that Wolfcamp development?

[John Lambuth:]

I think, again, we tend to think that as one contiguous hydrocarbon system. We tend to roll then those XY sands and our overall resource in place and feel pretty confident that based on our landing zone, especially in the upper part of the Wolfcamp that we’re more than likely accessing those sands. I don’t know that we necessarily have to put the lateral on the sand to assume that we’re not accessing them. So in some ways what we’re going to try next with the Snowshoe and adding that extra bench of wells, we are in some ways implying that we’re intending to grow up in to that. And again, we see it as a phenomenal resource there. We really, really like what we see out of Pagoda’s, which is why now we want to go ahead and move this quickly as we can test that even tighter spacing with the Snowshoe.

[Operator:]

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

[Tom Jorden:]

I just want to thank everybody for your questions, a lot of good questions out there today. And look forward to updating you with future results. And thank you very much for your attention and support at Cimarex.

[Operator:]

The conference is now concluded. Thank you for attending today’s presentation. You may now disconnect.