Cimarex Energy Co.
Q1 2017 Earnings Call Transcript

Published: 10 May 2017

[Operator:]

Hello and welcome to the Cimarex Energy First Quarter Earnings 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'd now like to turn the conference over to Karen Acierno. Please go ahead, ma'am.

[Karen Acierno:]

Thanks, Keith, and good morning, everyone, and again, welcome to the Cimarex First Quarter 2017 Conference Call. An updated presentation was posted to our website this morning. 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 an amended 10-K for 2016 and our Form 10-Q for the three months ended March 31 later today. Our prepared remarks will begin 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; and 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. With that, I'll turn the call over to Tom.

[Thomas E. Jorden:]

Thank you, Karen, and thanks to all of you who are joining us for the call. Cimarex had a very good first quarter. Our production beat was driven by continued improvement in our well results, operational excellence and field execution and a bit of luck, as we had not experienced any significant weather or field outage events during the quarter. Hats off to our organization for outstanding execution during the quarter. As a result, we're raising our full-year production guidance to 1.09 Bcf equivalent per day to 1.13 Bcf equivalent per day. Our full-year exploration and development capital remains unchanged at $1.1 billion to $1.2 billion. We're pleased to be sharing a trove of operational updates with you during the call this morning. John will be updating you on a number of important projects as he will describe these projects of tested well spacing, the stacking and staggering of wells, landing zone selection and completion optimization. Our results in these projects have been highly encouraging. Quarterly results are interesting, but we focus on the long term. Our core belief is that shareholders are best served by reinvesting their cash flow at the highest rates of return we can manage. Our industry tends to be trendy as certain plays and basins fall in and out of favor. Our focus remains on full cycle, fully burdened return on capital employed. We strive to build a portfolio that can deliver superior returns through the cycles. We have never felt more confident in our assets, our ongoing results and our ability to execute on our mission. We are achieving excellent return on capital and are extending our inventory life through tighter well spacing, opening up additional zones and through exploration leasing. The rate of change within Cimarex is accelerating, driven by increasingly positive results. As the song goes, the future's so bright, I gotta wear shades. We have spoken at length regarding our commitment to science, innovation and an understanding of the downhole physics behind landing zone selection and completion innovations. These understandings have tremendous implications to well bore spacing, well performance and net asset optimization. We also speak directly to return on capital, asset life and depth of inventory. Being good at the science tends to extend inventory life. The results you will hear in this call are no accident. They are the direct result of an organization that is focused on innovation, honestly examines its failures as well as its successes and strives to be an open, transparent culture where technical debate is highly encouraged. We relentless study our competition and try to learn from their successes and failures. As we look across the fence, we occasionally see infill projects that have significant well-to-well interference, resulting in meaningful degradation from parent well response. We understand these challenges and at times have faced these disappointments ourselves. Success or failure on these fronts will be a strong differentiator among E&P companies. We are pleased to report the results you will hear in this call. They are the result of tremendous persistence on the part of our geoscience and operations teams. As I said, it is no accident. Finally, before I turn the call over to John, allow me to comment on the recent release of our accounting error. We recently discovered an error in the calculation of our ceiling test impairment. It was a simple error, but one that should never have been made. We immediately reported the error to our auditors, set about correcting our financials and put additional controls in place to make sure that this never happens again. Nothing is more important to us than our credibility. We will do better. With that, I'd like to turn the call over to John for some highlights from our program.

[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. During the first quarter, Cimarex invested $306 million on exploration and development activities. About 69% of our first quarter capital was invested in the Permian region, with the rest going toward activities in the Mid-Continent region. We invested $197 million of the $306 million on the drilling and completion of new wells. Company-wide, we brought 70 gross, 26 net wells on production during the first quarter 2017. As Tom mentioned, our 2017 exploration and development budget is unchanged at $1.1 billion to $1.2 billion, with $850 million to $900 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 the remaining earmarked for Mid-Continent. We entered 2017 with 11 operated rigs with 6 located in Mid-Continent and 5 in the Permian. During the month of April, we brought on three additional rigs in the Permian, which increased our total operated rig count to 14. Now, on to well results. I want to start with the Permian region where we have some exciting results to share with you regarding a delineation test in the Upper Wolfcamp interval located on our White City, New Mexico acreage position. The Pintail 23-36H (sic) [Pintail 23-26H] well, whose location can be seen on slide 12 in our investor presentation, achieved a 30-day peak IP of 1,557 barrels of oil equivalent per day, of which 64% was oil. This well result, along with some recent competitor well results in the area, is helping us gain confidence that we have a highly economic target in the Upper Wolfcamp interval, along with the de-risked Lower Wolfcamp zone on our entire Eddy County, White City, New Mexico acreage position. Staying in the Culberson County area, the Lower Wolfcamp, Tim Tam pilot, has been on production long enough in order for us to share with you their results. As shown on the cumulative production versus days plot on slide 16 of the presentation, these infill wells are performing as well as nearby parent wells with similar landing zones. The five 10,000-foot infill laterals achieved an average 30-day peak rate of 13.9 million cubic feet equivalent per day, with oil percentages varying from 26% to 36% depending upon landing zone. This result confirms that we can very economically develop the Lower Wolfcamp interval at a minimum of six wells per section. In fact, due to the exceptional performance of these wells, we are formulating plans to test even tighter spacing in the Lower Wolfcamp later this year. In Reeves County, we have encouraging results to share with you regarding our Wood State, Upper Wolfcamp infill project which is testing the equivalent of 12 wells per section. Excluding the Wood State 47-26 2H (09

[Joseph R. Albi:]

Thank you, John, and thank you all again for joining our call today. I'll recap on the usual items, our first quarter production, our updated 2017 production outlook, and then I'll finish up with a few comments on LOE and service costs. While we're off to a great start in 2017, our Q1 2017 net equivalent production came in at 1.063 Bcf a day, beating the upper end of our guidance by 13 million a day and setting a new record for total company production. With quarter-to-quarter production gains in both the Permian and Mid-Continent, our Q1 total company net equivalent volume was up 11% from our Q4 2016 posting of 960 million a day and 9% from our Q1 2016 volume of 973 million a day. With our focus on Permian oil and high-liquid Mid-Continent projects, we saw a solid sequential quarter increase in oil production, reporting a total company Q1 oil volume of 52,181 barrels of oil per day, up 15% from Q4 2016 and 13% from Q1 2016. Our oil volumes were up in both the Permian and the Mid-Continent, with our Q1 Permian oil production up 13% and our Q1 Mid-Continent oil production up 20% from Q4 2016. With a strong contribution from our Reeves County Wood State project that John mentioned, our Q1 2017 Permian net equivalent volume came in at 577 million a day, that's up 13% from Q4 2016 and 21% from Q1 2016. We brought on a total of 25 gross, 16 net Permian wells during the quarter and we had 14 gross and 11 net wells waiting on completion at quarter end. We also saw a nice gain in our Q1 Mid-Continent volumes with continued operated and non-operated production adds from our East Cana infill project. Our Q1 Mid-Continent net equivalent production came in at 484 million a day. That's up 9% from Q4 2016. In aggregate, we brought on 45 gross and 10 net wells in the Mid-Continent during the quarter and we have 68 gross and 15 net wells still waiting on completion at quarter's end. Looking forward into 2017, we've updated our model to incorporate our actual Q1 results and the projected drilling and completion schedules for the three Permian rigs we added in mid to late April. With our Q1 production beat and our revised projections, we've increased our full year guidance to 1.09 Bcf to 1.13 Bcf a day. That's up from the 1.06 Bcf to 1.11 Bcf a day we reported last call and it reflects a 13% to 17% increase over the 963 million a day that we reported in 2016. The 2017 capital remains focused on high-liquid Permian and Mid-Continent projects. As a result, we continue to project significant oil growth in both the Permian and the Mid-Continent during the year, which results in total company forecasted year-over-year production growth in the range of 24% to 28%. Our projected capital and completion activity remains skewed, approximately 60% to the Permian and 40% to the Mid-Continent. We anticipate bringing on 60 net Permian wells and 39 net Mid-Continent wells during 2017, and that's up from the 30 and 31 respective net wells that we completed in the two areas during 2016. With our strong tailwind from Q1, we're modeling Q2 production to be in the range of 1.08 Bcf to 1.13 Bcf a day. That's up 2% to 6% over Q1, and it's an 11% to 16% increase over Q2 2016. We're forecasting a number of our Permian and Mid-Continent spacing projects to come on online later in the year, and that will accelerate our capital and completion activity forecast into the Q3 to Q4 timeframe. As such, we're modeling Q3 to be relatively flat to Q2 followed by a nice production ramp in Q4. Our production calls for Q4 2017 exit rate in the neighborhood of 1.13 Bcfe to 1.19 Bcfe a day, and that's a strong 18% to 24% increase over Q4 2016. On top of that, we'll have approximately 44 net wells either drilling or waiting on completion as we forecasted at the end of the year. So with that, we anticipate having great momentum going into 2018. Jumping over to OpEx, our first quarter lifting cost came in at $0.65 per Mcfe. That's right at the midpoint of our guidance of $0.60 to $0.70 and just below our 2016 average of $0.66 per Mcfe. Our Q1 posting was approximately $0.07 above the $0.58 mark that we reported in Q4, and that's primarily a result of increased workover activity in Q1 as compared to not only Q4 2016, but several recent past quarters. We are starting to feel some LOE cost pressures in items such as compression and water hauling. That said, our production team remains vigilant to maintain the reduced operating cost structure that they've worked so hard to achieve. Taking into account the fluctuating nature of our workover expenses and our 2017 focused on high-liquid projects, we're maintaining our 2017 lifting cost guidance of $0.60 to $0.70 for the year. That's well below the $0.83 per Mcfe we posted in 2015 and the $1.08 we reported in 2014. And finally some comments on drilling and completion costs. On the drilling side, although a number of cost components have remained in check, we've seen 5% to 10% increases in items such as day rates and directional services. And with less availability on the ground, we've seen 15% to 25% increases in the cost of our tubulars. With our dry hole cost or drilling cost representing only about 30% to 35% of our AFEs, at the total well cost level, the largest cost pressure we're seeing is on the completion side. In addition to seeing increased cost – service cost to pump our fracs, we're also experiencing a tighter market for prop, which also appears to have limited supply on the ground. We've been able to offset a good portion of the service cost increases by optimizing our job design, utilizing fewer stages and pumping zipper fracs where we can, and we've focused on long lead time planning to ensure adequate prop sourcing for our program. As compared to Q4 2016, we've seen our current total company per well average frac cost increase 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 and so on. Although we focused our drilling and completion efficiencies to limit the impact of these frac cost increases, we've experienced some modest increases in our total well costs. In the Permian, we've raised our current Bone Spring 1-mile lateral AFE with larger fracs, approximately $300,000 to $500,000 per well, with a range of $5 million to $6 million. In the Wolfcamp, we've increased our AFEs for larger completion, 2-mile lateral Wolfcamp wells in Culberson by $300,000 to $10.5 million to $11.7 million per well. That's still down from the late 2015 cost levels we had and with a much larger completion today. In Cana, our current Woodford 1-mile lateral AFEs are running in a range of $7.5 million to $8 million, that's up $400,000 to $500,000, again, all driven by higher frac cost. And as we continue to experiment with frac design, we bumped the midpoint of the cost range for current 2-mile Meramec AFEs by about $250,000 with a range of $10.5 million to $12.5 million per well with frac design again being the largest cost variable. So in closing, we're off to a great start here in 2017. Our diversified oil-focused development program generated a great production beat in Q1. With that as our springboard, we're forecasting continued production growth coming here into Q2 with forecasted year-over-year total company production growth of 13% to 17% and just as important a strong exit rate to enter 2018. We stay focused on finding cost pressures in order to keep our cost structure healthy and strong and our overall program continues to generate positive results, all that despite the modest cost increases we've seen in our total well costs. All in, we remain very excited about 2017. So with that, I'll open it up to Q&A.

[Operator:]

Yes. Thank you. We will now begin the question-and-answer session. And the first question comes from Jeanine Wai with Citigroup.

[Jeanine Wai:]

Hi. Good morning, everyone.

[Thomas E. Jorden:]

Good morning, Jeanine.

[John Lambuth:]

Good morning.

[Jeanine Wai:]

Just back to the oil production for the quarter. You provided guidance during the last earnings call of 30% to 35% growth 4Q to 4Q and just given the strong oil production during 1Q, is there upside to that prior commentary or is the strong 1Q oil number mainly a function of timings? And we also noticed as you mentioned that you did more wells in 1Q than expected, but that Q2, number of completions went down.

[Joseph R. Albi:]

This is Joe. The way I would answer that question, we – in total, as you look at the year, the net well completions quarter-to-quarter, we had a good number of completions in Q1. We'll see that slow down a little bit in Q2 and ramp back up into Q3 and then taper off just a smidge in Q4 as wells come online, and with that parallels our projected oil production and our oil growth. We're still projecting that our oil growth will continue to extend itself into the fourth quarter and surpass slightly the ranges that we quoted last call.

[Jeanine Wai:]

Okay. Great. And then my related or unrelated follow-up, in terms of the rig count for the year. You guys have 14 right now and we noticed in the updated presentation that the commentary of 18 rigs by 4Q dropped off to 5? So, just wondering if the 18 rigs are still the plan for this year or was that just – we're reading too much into that?

[John Lambuth:]

This is John. It's still quite frankly little bit of flux as to when those additional rigs will come on. It's a matter of timing between us and our partner in the Mid-Continent region with our next major development project. We're still working with them, trying to decide the overall scope and size of the project. And based on what we finally settle on would dictate whether the rigs show up late this year or early next year. So we're still working on that right now.

[Thomas E. Jorden:]

Jeanine, I'll just add to that, those additional four rigs, as John mentioned, are for our development project on the Western side of our stacked asset. Those wells, whether we added them – those rigs whether we add them this year or next year, we're going to be flowing in the – John, correct me, it's East side. Yeah. East side.

[John Lambuth:]

East side, the more liquid-rich of the Woodford.

[Thomas E. Jorden:]

But the rigs were going to be deployed for drilling and the completion would flow into 2018. So it's really not a big impact on – it's zero impact on this year other than whatever drilling capital it would've had. But as John mentioned, we're still working through the timing there.

[Operator:]

Thank you. And...

[Joseph R. Albi:]

And this is Joe. I'll add that we have, as forecasted, approximately 44 wells that we'd still be drilling and waiting on completion with the – just the Permian rig counts that we've got in our current plan at the end of the year.

[Operator:]

Thank you. And the next question comes from David Tameron with Wells Fargo.

[David R. Tameron:]

Good morning. Couple questions. Lea County, it seems like there's been a lot of activity there lately or a lot, I guess, results coming out between yourselves, EOG had some nice wells. I know Devon's doing some down-spacing in there. Can you just talk about, is this something different or I know you've been up there and you're testing tighter spacing, but can you just talk a little, I guess, more general about the area and what you're seeing?

[Thomas E. Jorden:]

Yeah. David, let me start, and then John will follow up. We've always loved Lea County. One of the reasons that we haven't aggressively developed our acreage at the multiple levels is because it's really quite good and we wanted to make sure that we got our spacing and our science right because you can always back up and get a do over. There have been some offset well results. We've extended our mapping, and the play has just extended. And we're quite bullish on the outset, not only for the Wolfcamp, but a number of different zones.

[John Lambuth:]

Yeah. I would just say that you'll see more of our activity moving into Lea County later this year. We have quite a bit of drilling we want to do up there. It's not – like Tom said, we've always loved Lea County. It's just over the last few years, with the pull back in our capital, most of our drilling has been to hold acreage that we needed to hold down in Culberson and Reeves. We are very fortunate that almost all of our position in Lea is a well-held HBP acreage, be it a previous drilling we've done mostly in the Bone Spring and other targets. So we're just now starting to focus more energy to get in there and then taking advantage, as Tom said, of the fact that a lot of our competitors are "delineating" our acreage for us. So it looks very, very attractive and thus resulting in the updating we gave on the increase in the acreage there.

[David R. Tameron:]

Okay, and just to clarify. So, compared to three to six months – or whatever, six to nine months ago, this is – or compared to the original 2017 guidance is maybe the better way of looking at our development schedule, this has moved up and you're probably moving that in and moving something else out. Is that fair?

[John Lambuth:]

To be honest, no, we already had plans to be in Lea County. I think right now, incrementally may be a well or two, but certainly, it will have a bigger impact as we look into 2018. And, again, we have the luxury of having that HBP position. So, we want to make sure – if we go up there because that acreage is very precious to us, we want to make sure we develop it right. So we have a very good plan. We have a couple spacing pilots that's always been planned for later this year, one in the Wolfcamp, one in the Avalon. And from that, we'll formulate more plans to get probably a little bit more activity when we get into 2018.

[David R. Tameron:]

Okay. And then just as a follow-up, and thanks for the completion schedule in the slide deck, but what's your appetite, I guess, to – I guess this is to Tom, what's your appetite to increase CapEx? Obviously, you have the balance sheet for it. You have the dollar sitting there if you need it. How are you thinking about acceleration – or potential for acceleration beyond the current plan?

[Thomas E. Jorden:]

Well, we – our plan is our plan, so you're asking me to speculate, and that's something I'll do that. We really are quite positive on our assets. John and I spent all day yesterday with the Culberson County team looking at that asset, and it's just tremendous. Not only are we seeing fantastic well-level results, we're seeing real good improvements in our science around infill drilling and spacing. And then, when you look at that asset where we have a huge arena of 10,000-foot long horizontal wells that we can drill without regard to the lease line, it's pretty easy to get pretty excited about it. And that's just one part of our program. And so as we look ahead, we do have the wherewithal to accelerate. We have the balance sheet to accelerate. We have the projects to accelerate. And although we don't publish inventory numbers, you can read between the lines, the way we look at it internally, our inventory has increased significant because of the work that our organization has done. So, yeah, we'd like to bring that net asset value forward and we have the wherewithal to accelerate. Now that said, there are some macro events that are going to overprint that. We want to make sure that we're drilling into an acceptable cost and commodity structure and we're going to manage that balance sheet pretty carefully. But I think definitely as you look at us, there is a chance that we have some bias to the upside here.

[David R. Tameron:]

Okay. No. I appreciate the color. I appreciate the speculation. Thank you.

[John Lambuth:]

Thanks, Dave.

[Operator:]

Thank you. And the next question comes from Irene Haas of Wunderlich.

[Irene O. Haas:]

Yes. To carry on David's question. Zooming back to Lea County, you mentioned that you pretty much remapped your play outline, that you're going to be drilling your first well in Lea County. Can I ask when and what target horizon? Then my second question is your recompletion. You're using bigger fracs and got quite a stunning uplift. I was wondering where the location of that well – is it 23 South, 33 East? And also, a little more color as to what you exactly did there. I'm very curious.

[John Lambuth:]

Okay. Well, I will answer certainly your first question in regards to Northern Lea County. Yes. We have undertaken better mapping of the Wolfcamp up in that northern part of our acreage. We're starting to appreciate, it doesn't take as much net thickness within the Wolfcamp to still have a very good outcome and that is leading to us getting much more bullish on our acreage up there. And, of course, that, coupled with some competitor results nearby, never hurts either. We've actually already drilled a Wolfcamp well in Lea County. I guess we need to make sure we get our map updated, and that well has been known for quite a while now, and it's a very good well. And we have plans now to go up to that Northern Lea County area that we've expended our polygon on, and there, we'll be testing again the Wolfcamp up there. Based on competitor results, we have high expectations for that well. And with that in hand, hopefully later this year, we'll get even more bullish in terms of future drilling we want to do there next year. Regarding the recompletion though...

[Thomas E. Jorden:]

Yeah. We're not sure which well you're talking about, Irene, Were you referring to the Pintail well that John mentioned in Eddy County?

[Irene O. Haas:]

No. Triste Draw 25 7H. I think you guys went in and saw quite a bit of uplift. That is also in Lea County.

[John Lambuth:]

Well, we did. But the latest Triste Draw I'm aware of is an Avalon new drill well.

[Irene O. Haas:]

Oh, the new drill. Okay.

[John Lambuth:]

Which is a very good well, but we don't have enough production to speak to that well just yet, if that's the one you're referring to.

[Thomas E. Jorden:]

Yeah. Irene, as you know, we like to have at least 30 days of established production, on some of these longer laterals we like to have even more than that. So, we'll typically want to make sure that we have something definitive about a well before we talk about its results.

[Irene O. Haas:]

Okay. Fine. Then with the Northern Wolfcamp well, is it in the Wolfcamp D or B or A?

[John Lambuth:]

It would be what we would just call the Upper Wolfcamp. Others would call A. That would be the primary target for that acreage up there. And that's what we'd be going after.

[Irene O. Haas:]

Okay. Great. Thank you.

[Thomas E. Jorden:]

Hm'hmm.

[Operator:]

Thank you. And the next question comes from Mike Scialla with Stifel.

[Michael Scialla:]

Yes. Good morning, everybody. I'm wondering, the land and seismic CapEx for the first quarter is a little bit higher than we were anticipating. Just wondering, did you actually add any acreage or was that just a lease retention cost or anything else you can talk about there?

[John Lambuth:]

Sure. This is John. That was acreage additioning (33

[Thomas E. Jorden:]

Yeah.

[John Lambuth:]

And then, we'll go do it again. But that is what was going on in that first quarter.

[Thomas E. Jorden:]

Just by way of overall program, we want to always be making land investments. But what we do is we look very carefully full cycle at the return on our investment, fully burdened with land, corporate overhead, all associated costs, and then we look at our total program and make sure that land is not too high a part of the overall expenditure. And we've always managed the company that way. We look at it on an ongoing basis. You have to make the land investments. Otherwise, you're essentially liquidating the company. You may be liquidating on a 50-year time horizon, but we always want to be bringing in new things to replace what we drill. And so from time to time, you're going to see that land investment swing up and down. It's a part of our ongoing business.

[Michael Scialla:]

Can you say where that new opportunity is, or is it going to remain kind of in the stealth mode for a while?

[John Lambuth:]

Stealth mode.

[Michael Scialla:]

Okay. At this point – I'm going to ask one more on the prices. It looks like you had pretty good realizations for your products in the Permian for the first quarter. There have been some concern about where those prices may head. I just wanted your thoughts on that potential for adding firm transportation or further hedging?

[Joseph R. Albi:]

This is Joe. On the gas side, yeah, I think, overall, that differential increase is kind of stemming around concerns about Mexico infrastructure and demand and maybe secondly the pipe outlets to the Gulf Coast. And we're having no problem selling our gas right now. We are seeing the hit of the differential. Long term looking out, we're looking at the various options for pipe out of Waha to the Gulf Coast because we think it will be something that we're going to need to secure ourselves with. We do have Perm on El Paso coming off the tailgate of our Hidalgo plant and we're looking at possible other open seasons as well. So, we're taking a proactive stance to try to secure the Perm that we think makes sense relative to our volumes and then think long term on how to better get our gas out of the basin. With regard to the oil side, we believe that there's capacity that does exist right now. Current supply or surplus capacity on takeaway out of the basin we think is sufficient for the short term. Long term, we're going to look – again, like I mentioned on the gas side, at possible solutions as well. As far as Delaware, gravities being a little bit higher than Midland. We do see a variation in our gravities from Reeves over to Culberson and our contracts to sell both those will allow for us to blend and we're well below the minimums on those contracts. So, we've had no problems right now getting oil or gas out of the basin. So hopefully that answers your questions.

[Joseph R. Albi:]

Hey, Mike, I'll just add on that. On the first quarter, we did see a positive Midland – Cushing differential, which definitely benefited our realization in the first quarter. It's something in the neighborhood of $0.60 positive. Looking forward in the second quarter on the futures market, that's probably going to go up to maybe $0.80 to $1, currently at $0.70 at today's spot price. And looking out in the third or fourth quarter, this may be up to just over $1. And out into 2018 on a fourth trip (37

[Michael Scialla:]

Very good. Thank you, guys.

[Operator:]

Thank you. And the next question comes from Neal Dingmann with SunTrust.

[Unknown Speaker:]

Hey. Good morning. This is actually Ray (38

[John Lambuth:]

Yes. This is John. Yes, we plan to drill quite a few more wells up in the White City area, both in the Upper Wolfcamp and the Lower Wolfcamp. And yes, we will be testing upwards to the Northern part of that contiguous acreage block. I think if we looked at slide 12, you can see where the Pintail is located, but you'll see we have more acreage located further to the north and we do have plans, as I said, to test both upper and lower, and that part of it. I'll also just add, again, there's quite a few competitor wells that come on in and around that acreage block. And that has given us quite a bit of encouragement that a lot of that acreage is going to be very prospective for both towns. And so, hopefully, in the coming quarters, you'll hear us talk more about some results up there.

[Thomas E. Jorden:]

Within that acreage block, that ends up on our Culberson County map is up in Eddy County. It's higher working interest. We don't have a partnership around that acreage. And depending on where you draw the outline, this 35,000 net acres to 40,000 net acres, we've been up there for quite a while. In fact, our first Wolfcamp well in our program – first horizontal well was drilled up there in 2010 in the Lower Wolfcamp. We've done a fair amount of development up there in Bone Spring and are still doing so, and this well that John's spoken of, the Pintail well was our first Upper Wolfcamp test up there. It's highly encouraging and it opens up most, if not, all of that acreage to Upper Wolfcamp in addition to Lower Wolfcamp and that's also a fairly contiguous block that supports long laterals. So it's a real significant data point to us in terms of our future program.

[Unknown Speaker:]

Okay. And as you guys continue to test and delineate your Mid-Con, just want to get an – if there's an update on thoughts around timing for full-on development there.

[John Lambuth:]

Well, when you say full-on development, I'm assuming you're referring to incorporating the Meramec into our development plans because of course we have been developing the Woodford now here over the last several years, what I would call full development. What I would just say is that the spacing pilot result that I commented on, the Leon Gundy's is extremely encouraging to us in regards that the Gundy's or the Meramec wells responded very nicely to our design, such that it really points the way to quite a bit of our acreage could be receptive to that 19 wells per section development and that is something that we're looking at very intensely. We have some additional testing we're going to do of that concept in terms of stacking two layers into Meramec and one into Woodford. Well, we have a few small projects that we're doing later in the year to test that. But we're also developing plans to get to that type of 19-well-per-section development sometime next year in 2018 on some of our acreage. So we are getting there. And then to continue on that, of course, us and Devon still are formulating plans for long lateral development there in that Eastern part. Right now, it's still focused on Woodford, but we still have some plans to go forward with that long-lateral development plan probably, like I said, late this year, early next year.

[Unknown Speaker:]

Okay. Great. Thanks for the color.

[Operator:]

Thank you. And the next question comes from Matt Portillo with TPH.

[Matthew Merrel Portillo:]

Good morning, guys. Just a follow-up question to Lea County. Just wanted to ask you about the Bone Spring opportunity. I know it is an area where you've historically focused on legacy development. And I was curious how target lateral landing might change your views on delineating and further testing in the Bone Spring. We've seen some really strong industry results around Central Lea, and if that's in your plans this year.

[John Lambuth:]

I'll take a stab at that and I'm sure Tom will want to follow up. For most of our Northern Lea County, we have already done a lot of legacy drilling in the Bone Spring. That's quite frankly where the whole play started. But we also recognize that that was technology from seven, eight years ago that when we look at our footprint there and look at those existing wells we have, we see wells that clearly did not have the most optimal stimulation. We see potential white space, I'll call it, along the lateral of potential undrained reserves. And we obviously do not even feel like we see it like you mentioned that we may be tested all in our landing zones appropriately with those wells. So we have looked at going in and doing some additional infield drilling up on that acreage with modern stimulation and that's something we're still formulating and I'm sure we'll be doing some of that in the coming – rest of this year.

[Thomas E. Jorden:]

Yeah. The only thing I would add is – keying on what John said, that Bone Spring section really is multiple benches, multiple targets, many of which have not been tested. Our historical development is focused on sand benches in the second and third Bone Spring and it's a fairly target-rich section. So, we anticipate that being a part of our program for a long time. It's just we have lots to do and when you're going to get to it is the question.

[Matthew Merrel Portillo:]

Great. And just as a follow up to the exploration side of the story here. Just curious on your thoughts going into the back half of the year on incremental test in Ward and if there's any update to your drilling program around the Wolfcamp there?

[John Lambuth:]

This is John. We have now drilled one 10,000-foot lateral in Ward. We're still monitoring that well closely and we have plans in the coming months to drill a second 10,000-foot lateral in Ward. Once we get those to kind of under our belt, we'll then be giving you an update on what we have found in terms of the new drilling with the new stimulations and what our expectations will be going forward for that acreage position.

[Matthew Merrel Portillo:]

Thank you very much.

[Operator:]

Thank you. And the next question comes from Joe Allman with FBR.

[Joseph Allman:]

Thanks, operator. Good morning, everybody.

[Thomas E. Jorden:]

Hi, Joe.

[John Lambuth:]

Good morning, Joe.

[Joseph Allman:]

Hey, Tom. In your presentations, when we see the cumulative production curves that are straight lines with little or no bend, why is that happening and what do you take away from that and what message do you have for us in terms of modeling and estimating EURs and type curves and so on?

[Thomas E. Jorden:]

Well, that's a great observation and that's one of the things that is very exciting about our long lateral program. Not only are we seeing really nice top-line production rates out of these wells, but a much lower decline. Now, we have a lot of debate internally as to what the explanation of that is and then we'll probably have some debate here on the call amongst ourselves. I think certainly, you could address that situation with plumbing, probably larger casing design would advance those production rates. But there's costs and operational issues associated with that. There's also the question of surface facility. So, it's a fairly complex matrix of cost than benefit. Yes, there's one school of thought that would say those slight declines are a negative because that means that a lot of hydrocarbons are waiting in line to get out of the wellbore, but there's no school of thought that says, you know what, those are great outcomes because it allows you to make more efficient use of your surface facilities. You keep them full for longer. And one thing I can tell you is the top-line returns out of those products are outstanding. And I'll give Joe or John the opportunity to comment on that.

[Joseph R. Albi:]

Yeah. This is Joe. The only comment I'd make on that front is that in particular in Reeves County where we have higher liquids, we see it more prudent to run in the hole with tubing gas lift and any capillary treating mines at the time that we turn the well on. And this saves us from shutting in the well and doing it and as we get further down the road and that – down the road not being that far away before we feel like we'll see some detrimental flow due to lifting issues. But when you have the tubing in there, you're somewhat limited by which you can flow. And so that has a lot to do with what we're seeing in Reese County.

[Thomas E. Jorden:]

Yeah. And there's also – you never want to forget the water. It's one thing to look at the oil, but these wells make a lot of water as well. And so the surface facilities, disposal, all of that goes into your equation as to how you're going to design and flow these wells back.

[Joseph Allman:]

That's helpful. And just any additional comments you have on that just in terms of what it means for EURs and type curves and any message you have for us on that. And then I've got a follow-up question. Is there anywhere besides the Cana-Woodford where you've already decided on the optimal spacing and optimal completion and drilling technique and completion design such that you're ready to pretty much go full bore, full scale development?

[Thomas E. Jorden:]

Well, we haven't decided that in the Cana-Woodford. I mean, we've got some really good test results that as we've talked about in the past, 12 wells per section. We're currently completing or about to complete a project at 16 to 20 wells per section. So, this is a constant evolution here. As our understanding of the downhole system improves, that has direct implications to spacing. So, I hope it doesn't stop. We're going to have to just continue to learn as we go and have continuous improvement.

[John Lambuth:]

This is John. I think the good news out of all that is – and I would echo what Tom said, is in some ways, we don't really know optimal for every single target we have. But because we have so many of them, it's not as though we're not able to deploy capital because we have a lot of different opportunities in the Meramec, the Woodford, both benches on the Wolfcamp as well as the Avalon to continue to test those spacing issues and still get good well results until we get capital in the ground, that we kind of have that luxury. When will we get to that point? I don't know. Again, like Tom said, we just reviewed Culberson County yesterday. We were looking at the Tim Tam wells, very exciting wells for us. And immediately, we're all drawing what the next wine rack would look like for the Lower Wolfcamp and what would we do and how many wells could it be. And in the end, that is a wonderful thing in terms of the ultimate inventory and more importantly the ultimate PV value to this company with that acreage block. So, in some ways, I don't know. I don't know that we want to be in too much of a hurry. We want to make sure we get it right. But as I said, we're fortunate that we have enough of a portfolio that, trust me, we got enough places to go with the rigs to get this testing done, yet still get some very top-line results.

[Joseph Allman:]

That's all I have. Thank you, guys.

[Operator:]

Thank you. And the next question comes from Jeffrey Campbell of Tuohy Brothers.

[Jeffrey Campbell:]

Good morning. Congratulations on the quarter.

[Thomas E. Jorden:]

Morning.

[Jeffrey Campbell:]

I wanted to ask you about slide 20, the Triste Draw Avalon well that showed that huge increase on (50

[John Lambuth:]

Yes. This is John. That would be comparable to, say, a year or two generation frac design behind with the same lateral length. That is correct.

[Jeffrey Campbell:]

So, I'm not criticizing the Culberson results because they're great, too, but when we look at slide 13 and the Culberson uplifts, a similar cumulative uplift, there's a lateral length portion of it, and then there's the effect of the completions portion of it. It seems like here, the effect of the completions by itself is much more dramatic. I just wondered if you had any thoughts on that.

[John Lambuth:]

Well, I mean, number one, I would say within the Avalon, we're very excited about the – simply by redesigning our completions, we got that kind of uplift for a well that's landed (51

[Thomas E. Jorden:]

But I would say your observation is fair. I mean, we're – in our portfolio, we have a lot of different stratigraphies, lot of different lithologies, and they don't all respond similarly to frac optimization. You also have gas versus oil in the reservoirs, in some places, we're in a retrograde condensate, in other places, we're black oil in the reservoir. I would say, we share your observation that the Avalon play is probably the play where frac optimization has had this biggest just percent increase.

[John Lambuth:]

Yes, on the first generation change, absolutely, unequivocally, it has.

[Jeffrey Campbell:]

Yeah. Well, this is a high-class problem, that's for sure. But I just wanted to discuss that because it really kind of stood out. For my second question, I just wondered, could you add a little color on the Wood State well that is requiring remediation, just what went on there?

[Joseph R. Albi:]

Yeah. This is Joe Albi. Late last quarter when we were cleaning out that well, we stuck bottom-hole assembly and coil tubing and made the decision after retrieving the majority of it that we would rather shut the well in, produce the offset well, slower any possible pressure in and around that well a bit and then come back in later to retrieve the fish. And so we currently have ongoing operations right now to retrieve that fish and are getting close to home.

[Thomas E. Jorden:]

Yeah. They're making good progress. That's just one of the maddening things, particularly when you go to pad drilling. And we talked about this on our last quarter call, where you have six or eight wells that are all close proximity. If you have an operational issue on one, it could delay the production on the entire set. But we're getting after it and I really want to credit our operations group for coming up with a creative, inventive solution that lets us get back on that well, produce the offsets and do so with a strong, strong emphasis on safety.

[Jeffrey Campbell:]

And just to finish the thought, I mean, based on what you know now, do you expect that that well is going to be able to perform to its potential once you get the fishing done?

[John Lambuth:]

This is John. I think our expectation is, and based on our experience in the past, is that yes, ultimately when we get that well back on, we will achieve the same EUR expectation. It's just it will not have the same kind of IP rate only because there's still – it's been sitting there with a lot of water both – the stimulation water both from its own well and other wells. So, it will take a while for that well to clean up. But in the end, no, we still have high expectations we'll get about the same EUR for it.

[Thomas E. Jorden:]

Yeah. This has nothing to do with the rocks, just the plumbing.

[John Lambuth:]

We had floated for a while, it's basically downhole restricted flow.

[Thomas E. Jorden:]

Right.

[Jeffrey Campbell:]

Okay. Thanks for the clarification.

[Operator:]

Thank you. And the next question comes from David Deckelbaum with KeyBanc.

[David A. Deckelbaum:]

Thanks for taking my questions guys and nice jobs on the ops update in the quarter. Just was curious if you can give some color, you discussed sort of deferring some of the cost increases...

[John Lambuth:]

It was cut out.

[Operator:]

I'm sorry, his line (55

[Thomas E. Jorden:]

Well, the only thing I would say is thank you very much for your interest and we appreciate your support. We're working hard to continue to post these kind of results and look forward to continual operational updates. As you know, it's always nice to talk about results. That's what we're all about. And we look forward to bringing you additional results as the year goes on. Thank you very much.

[Operator:]

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