Alpha Metallurgical Resources Inc (CTRA) — Q2 2019 Transcript

Good morning, everyone. Welcome to our second quarter 2019 conference call. An updated presentation was posted to our website yesterday afternoon, and we may reference that presentation on our call today. As a reminder, our discussion will contain forward-looking statements, a number of actions that could cause actual results to differ materially from what we discussed. You should read our disclosures on forward-looking statements on our news release and in our 10-Q, which was filed yesterday, and of course, our latest 10-K for the year ended December 31, 2018, for the risk factors associated with our business. We'll begin today our prepared remarks with an overview from our CEO, Tom Jorden, and then Joe Albi, our COO, will update you on operations including production and well cost. A replay of expiration, John Lambert and Margaret Ford are here to answer any questions you might have. So with that, I'll turn the call over to Tom.

Thank you, Karen, and thank you to all that joined us on the call this morning. Cimarex had a good second quarter in a challenging market environment. Our production, both barrel of oil equivalent and oil production, came in above the midpoint of our guidance range. Total oil grew 5% sequentially with Permian oil growing almost 9% sequentially. Oil growth is projected to continue with sequential growth expected for the remainder of 2019 and into 2020. Permian oil growth is expected to offset the declining volumes in the Mid-Continent. We reaffirmed our CapEx for the full year while raising our annual guidance by 1,000 barrels per day at the midpoint. Commodity prices had an impact on our cash flow and earnings. Given the price environment we're facing, particularly for natural gas and natural gas liquids, it would have been foolish to expect otherwise. However, in spite of these headwinds, we expect to exit the year without incremental borrowing. Furthermore, we are pleased to be returning cash to shareholders in the form of our dividend, which we intend to grow over time. We're bringing some outstanding projects online that are delivering excellent returns. As we look ahead, we are completing the transaction to a more consistent operational cadence. Field consistency provides our best opportunity for consistent returns, value creation, and cash flow generation. Constant stops and starts lead to field inefficiencies and increased costs. Our organization is focused on field consistency, smooth execution, and cost control. We continue to benefit from the tremendous work we have put into understanding resource site development. Optimum development comes from understanding four key elements: first, understanding the stimulated fractured network, both along the borehole and away from the borehole; second, understanding parent/child interface and reservoir effects; third, understanding proper well spacing; and fourth, configuring an optimum project size and design. Cimarex has discussed our learnings on each of these four key points. There is no one-size-fits-all approach. The optimum answer to each of these four issues is a function of the reservoir properties, infrastructure requirements, and economic conditions. Through years of testing, we have gained a good, and growing understanding of the requirements for profitable development within good capital efficiency. I would again refer you to slides 24 and 25 in our presentation, which provides a window into our approach on the well spacing issue. As we've studied development projects in all of our operating areas, we have grown more confident in our ability to design capital-efficient development projects, to observe projects through our operating areas, and to predict their outcomes. This has given us insight into some non-operated projects. Our results so far this year speak for themselves. We wouldn't be making detailed comments on our productivities in our prepared remarks; I’ll give you a quick overview of 2019. Our capital is primarily allocated to the Delaware Basin, with the majority going to Upper Wolfcamp. Four of the five Culberson developers are online. Three of the five Reeves developments expected online in 2019 are already producing. Andrew Obin, our single development in Reeves County this year, is currently flowing back. We have three additional that will be in production later this year. Operations are underway on several projects that will impact 2020. We currently have eight rigs running in the Delaware along with two completion crews. Now I'll turn it over to Joe Albi, who will discuss operations in more detail.

Thank you, Tom, and thank you all for joining us on our call today. I'll touch on our second quarter production, our Q3 and 2019 full year production guidance, and then I'll finish up with a few comments on LOE and service costs. With the nice jump in our second quarter production, we continue with our strong start to 2019. Our Q2 net equivalent production came in at the company record of 275,000 BOEs per day, right at the top end of our guidance range of 263,000 to 275,000 BOEs per day. Our Q2 '19 net equivalent production was up 6% over Q1 '19 and 30% over Q2 '18. On the oil side, our company record Q2 oil volume of 83,400 BOEs per day came in approximately 1,000 barrels per day above our guidance midpoint, and was up 5% and 35% from our Q1 '19 and Q2 '18 postings, respectively. The Permian drove the increase. With our Q2 Permian oil volume of 70.7 thousand barrels per day, up 45% over the 48.8 thousand barrels a day we produced in Q2 '18. The Permian now accounts for 85% of our total company production. As we look forward into 2019, we're reiterating our full-year 2019 capital guidance and activity levels. We've tightened our full year net equivalent production guidance to 263 to 262 MBOEs per day, keeping the same midpoint as our previous guidance, and we've raised the midpoint of our full year net production guidance by 1,000 barrels per day with the range of 83,000 to 87,000 BOEs per day. For Q3, we are projecting net equivalent volumes to average 265 to 279 MBOE per day, with our net oil volumes forecasted to average 85,000 to 91,000 barrels per day, up approximately 5.5% from the midpoint of Q2. Shifting over to OpEx, with revenue properties now on our books, our Q2 lifting costs came in at $3.51 per BOE. That's just slightly above the midpoint of our guidance of $3.20 to $3.70, and it's down $0.11 per BOE from our 2018 average of $3.62. With our continued Permian focus, we're tightening our full year lifting cost guidance to the range of $3.30 to $3.65 per BOE. Lastly, some comments on growing and completion costs; we've seen general market conditions remain relatively flat since our last call on both the drilling and the completion side. That said, with our continued focus on challenging completion design and operating efficiency, we've reduced our completion costs by 5% to 6% since April, which translates to total well cost reductions in the range of $300,000 to $500,000 for each of our two-mile lateral wells depending on the program. Our Wolfcamp program, with a tweak in completion design, has dropped our two-mile completion AFE by $400,000. As a result, our conventional Reeves County, two-mile Wolfcamp well is running $10 million to $12.5 million, depending on facility design and frac logistics. That’s down $400,000 from last call, and down $900,000 from our estimate late last year. Our shallower Wolfcamp A wells in Culberson County are running about $600,000 less than Reeves County Wolfcamp A wells, within an AFE of $9.4 million to $11.9 million. I want to point out that with the efficiency gains derived from our multiple development drilling projects, our average treatment well costs are trending at the low end of these ranges. In the Mid-Continent, with refined completion designs and improved operating efficiencies, we have reduced completion costs in both our Woodford and Meramec programs. Our current two-mile Meramec AFEs are running $9.5 million to $11 million. That's down another $500,000 from the last call, down $1 million from late 2018, and down more than $2 million from costs quoted in early 2018. So in closing, our solid second quarter gives us a great springboard into the second half of the year. With nine net wells previously planned for early Q3 first production coming online during the last two weeks of June, we are forecasting a ramp in our production in Q3 and Q4, resulting in an increase for our full-year oil guidance of 1,000 per day at the midpoint compared to our guidance last call. Our cost structure is healthy. We're projecting similar full-year lifting costs guidance as compared to last call, and we've derived significant well cost reductions through efficiency and completion design. We remain very well positioned to deliver the capital activity and production plan that we laid out for you at the beginning of the year. So with that, I'll turn the call over to Q&A.

Tom, I was wondering if you could elaborate on some of your prepared comments when you're talking about your expectations on sequential growth into the second half of the year per your guidance and into 2020? And how you're thinking about capital allocation next year just given some of the headwinds we've seen on the NGL and gas side of the equation?

Well, yes, Arun. Certainly, 2020 feels like a long way right now. I will tell you that we're putting a lot of energy, as I said in my remarks, into just planning our field effectiveness and smoothing out our full cadence. We talked about this in past quarters. We would be ready to go for sequential oil growth. Now, that said, we haven't formed our 2020 plans. The commodity headwinds are certainly a major factor. We're probably a little more bullish on oil as a contribution to our revenue, and you're not surprised to hear me say that, particularly with the environment we're seeing on gas and energy pricing. So although we haven't formed 2020 plans, I'd say that to the extent of allocating capital, we're probably going to want to emphasize oil, and while we'll be prepared for sequential growth, we haven't informed our 2020 plans, and we'll make our decisions when more appropriate.

Arun, this is Joe. For the most part in Q2, the impact of high gravity on our pricing has already been reflected. The index, comparing WTI now to May, shows the push is now less than $1. We expect to have one contract fall under the WTL basis by September. In terms of the volume contribution relative to our total Permian oil price, I anticipate it could lead to a 30% to 35% overall reduction in our total received oil price based on the current strip. Right now, with a basis of less than $1, we are receiving a premium against that, along with the revised contract we are considering for September.

Tom, you mentioned about the consistent cadence. I'm just wondering how do you and John think about balancing that with the optimal size of a Delaware play going forward?

Well, those are really two related, but independent issues. The optimum size stands alone from cadence. We look at infrastructure requirements, we look at the amount of water handling at peak, we look at take away capacity. But first and foremost, we look at the reservoir and to what extent the reservoir is forgiving of add-ons and what extent add-ons introduce competitions in the parent-child issue. So we look at all of that. I will say this: if all else were equal and the resource were forgiving, we would probably go for smaller projects and maybe 6 to 8 wells per project rather than these large projects, and just for a whole host of reasons. But let me let John comment on that.

Well, I think Tom hit most of the relevant points. I think what controls for us is the amount of infrastructure required when you bring on, both on the gas side. What we can find in many of our areas that Tom alluded to is that 6 to 8 wells at a time is a pretty good cadence and also seems to fit well in terms of the pace of our infrastructure investment. If we were to go much beyond that, then, frankly, I think we'd be subject to potential problems with getting consistent growth because there's a lot of moving parts out there. So right now, whether we're looking in Culberson or Reeves or even up in New Mexico, typically most of the projects that we're driving are in that 6 to 8 well range right now.

Yes. Among the many factors we consider, we evaluate the economics of our assets throughout their life cycles. One of the considerations in determining size is when we will come back to add-on and what impact that production will have on efficient development, both the impact of production we'll have on future development and what impact future development has on that production. As we gain an understanding, area by area and reservoir by reservoir, that's an important consideration for us. Some reservoirs are very forgiving; you can come back and they will have no impact. Some reservoirs are very unforgiving. It also involves understanding where your frac barriers are within your vertical section. Again, it’s not a one-size-fits-all. We'd like to make daily decisions around particular projects.

Great. Great. Just one follow-up. You talked about capital expense specifically. How do you arrive at the midpoint of CapEx for the year? It looks like you've already brought on about 60% of the wells and it was about 50% of the CapEx budgets, so if you could address that.

Yes. This is Joe. When you look at what we report and what we're forecasting for CapEx, there are a lot of moving parts. We've got carry over dollars that we're incurring from '18 activity, and dollars that we're going to spend in '19 that are carrying into 2020 activity. We've got infrastructure dollars, we've got soil water dollars and then on top of that, we've got the timing of activity relative to when dollars are ultimately recorded. In June, we completed and brought online 13.1 net wells, 9.4 of those wells came on during the last two weeks. As a result, we're anticipating that carry over is going to blow over in Q3 and then ultimately will contribute to our plans that we've given you.

I was wondering if you might be able to elaborate a little bit on the completion design optimization and what may be driving some of those costs that you highlighted at the beginning of the call?

Well, I'll take a stab at that. There are lots of knobs that one has to turn on completion design. And certainly, spacing, cluster type design, number of clusters per stage, amount of sand and fluid, pump rates, and whether you're zipper fracking or not, all of those add up to the speed and efficiency in the field. But first and foremost, we’re focused on completion effectiveness, and we've done a lot of work on downhole effectiveness. We want to have a balance between cost effectiveness in completion and productivity effectiveness. We're always getting better and always questioning our core assumptions. But I'd just finish and let John comment; first and foremost, you have to understand your downhole geometry or you can make some really bad assumptions as it flows through the other decisions.

Really to add on what Tom just said, we've been tweaking a few of our parameters. I'm not going to go into details on those parameters. What is nice to see is that over time, we're starting to see the benefits of those tweaks. We're starting to see a little bit faster cadence with a little bit of wiggle. So we're seeing a nice cause-and-effect, and yet, with those minor tweaks, we're not degrading the performance of the well. The jobs are getting done a little bit better at lower cost, and we're not going to set back the overall performance of the well. I think we're starting to see more and more with the adjournment of the project that we’re bringing on.

And I guess I'd add on top of that, that on the design, the fluid times the amount of sand, etc., efficiency of execution out in the field is paramount. So quicker cleanouts, quicker stages, all that translate itself into an overall more efficient and cost-effective program.

Great. And then a follow-up question around 2020. I know things are still in the works in terms of the planning projects there. But I was wondering if you could comment a bit, I guess, on just given where the strip is at the moment for gas and NGL prices, how you're thinking about capital allocation to the Mid-Continent next year versus how things should compare this year in 2019? And then, Tom, I was wondering if you could flush out a little bit more of just some of the comments you mentioned at the beginning of the call in terms of the potential for continuing to show sequential oil growth quarter in and quarter out as you move into 2020? Maybe indications from a high-level perspective about year-over-year growth on oil volumes into 2020? And I know things are kind of in the works, but just any incremental comments might be helpful.

Yes. I think I'll take a stab at both those. Although we haven't formed our 2020 plans, I would not anticipate our capital allocation significantly changing. Now we can argue about what significant means. We're in the process in the Mid-Continent of finding and developing into new plays and some new concepts. We've talked about in the past that we really like the Anadarko Basin, and we'd like to find some new things there. That will probably be our dominant focus in the Anadarko Basin, which will lean towards capital allocation that will, again, be disproportionately in favor of the Delaware Basin. Regarding the comments I made that you’ve asked me to follow up on, on sequential growth, I would say that as we look into 2020, we certainly have capacity for meaningful oil growth and delivering that in a sequential fashion. We haven't formed our 2020 plans. There's going to be some soul-searching on what the macro environment is and what we’ve got to do with our capital. We've put a lot of work in field efficiencies, organizational effectiveness, and planning, and we certainly have made tremendous progress, as we've discussed in the past, on smoothing out field operations and being able to deliver consistent quarterly execution. We have that capacity, we have that ability, but we haven’t yet formed the specifics of our 2020 plan.

Tom, no question that your execution excellence continues to show exactly what you’ve focused on over the years: focus on returns, and focus on capital discipline and so on. My question is really more of a high-level philosophical question as to how do you position Cimarex today to compete with the broader market? Because clearly, what’s happening in energy is putting pressure on us all, and it relates to investor appetite for exposure to the space. So what is the right growth rate? How do you compete with the broader industrial sector? And how do you think about potentially repositioning the company in this somewhat challenging time we're in right now?

Well, those are great questions, Doug. I think all of us have to ask what is the proper growth rate, if at all? We have the capacity to grow, but I think we are also asking what a growth rate we think is appropriate? What amount of free cash can we and should we generate? And then what do you want to do with the free cash? All of these are good questions, and we are being challenged to behave like good manufacturers, and I’d say, at Cimarex, we accept that challenge. We've had to do a little bit of internal work, as we talked about in terms of getting our field cadence more predictable, but once we had that work done, which I believe we do, now it's upon us to get to work and deliver consistent returns and return those returns to shareholders. I’ll say this: I think that if we can open the door and let people look inside at some of the capital projects that we're executing, I think we would stand out for prudent investment decisions and generating returns that show us that the effort we've put into development learnings is paying off. These are all good questions, and it's something we're wrestling with. I think you'll see our 2020 plans reflecting that wrestling, and we accept the challenge. Mark, do you want to comment on that?

Yes, Tom. That's definitely the items that we contemplate. As we've discussed in past and future conferences, the competitiveness of our energy companies needs to step up against broader industries and make our EMP business attractive to the broader markets while also generating free cash flow and committed growth returning it to shareholders through different measures. This is something Cimarex will focus on. We've always focused on return on investment, making sure we're getting full cyclic returns, and taking the next steps on how we can further make our stock attractive and demonstrate that we're returning to shareholders.

I’m going to finish, Doug, by saying philosophically that we’re all very short-term in our thinking. Markets are subject to it. We often think that current conditions are the new normal and will be permanent. We’re in a cyclic business. We’ve seen lots of cycles, and we remain focused on the long-term, on developing and executing a business that's sustainable, that can withstand the cycles in commodity prices. We're confident that the world needs the products we produce for decades to come. The things we're being asked to do—show capital discipline, show that we can grow modestly and generate free cash flow, demonstrate to the markets to what extent we are prudent stewards of capital and make investments that are efficient and effective—those are good things to do regardless of changes in the macro environment. While we're going to get after it, I want to remind ourselves that we're in the business for the long-term, and the things we see and feel today may not be around forever. That’s certainly been our experience. We're here for the long haul.

I appreciate you answering the question, Tom. You're certainly right in answering the question. I agree with you on that. If I may, just a quick operational follow-up. There's a lot of moving parts on infrastructure, obviously, going on in the second half of the year, going into 2020. So I just wondered if you can kind of sum up the prognosis for you guys as it relates to gas and NGL, with any prognosis, if you like, for how you see your differentials evolving? I realized there was some volatility in your gas realizations this quarter, but any help for 2020 as you see that moving into next year.

Doug, looking at the prices, starting in the second half of '19, looking at Waha and the gas price index, we're looking around $1.50 in Q3 going into Q4. We're averaging a little bit over $1.20 for the second half of the year. We see that improving into the second half of the year with Gulf Coast Express coming on. Future pricing is reflecting that, and we expect our second half natural gas realizations to improve. You mentioned some of the reported realized prices relative to accounting policies that have processing costs against them, and in Q2, there was $0.40 in Mcf for processing and transportation costs against the realized price. That will continue as we assimilate that cost into our models for the amounts related to future pricing.

There's a transfer of said, though, on that?

That's right, Doug. There’s a transfer of said. That’s exactly right. I mean going into 2020, we see a forward curve that oscillates a fair amount into 2020. Our first year, our first orders hire $1.70 and going to $0.80 in the second, but either premium prices or going to $1.30 to $1.40, similar type improvements or realization compared to what we’ve seen in the second quarter this year.

A couple of follow-ups that I wanted to ask earlier. First, come on the Mid-Con. You talked about concepts that you'd be working on that you are working on. Can you just talk to where those stand? And what you would need to see to allocate more capital there in 2020?

Well, I don't want to comment on any particular plays or the evolution of them. What I can tell you is that we need to see material returns that compete with the Delaware Basin. A lot of what we have in the Mid-Continent can be capital allocated as it Mid-Continent because it heads up what you are seeing with Delaware. The robust inventory there is not the same; we have a deep inventory of those things from the Delaware that compete for capital. For that you, we would need to see a deep inventory and some great returns from the new and emerging plays.

And would you allocate rigs back on a normal basis among the base legacy plays relative to current levels?

Brian, I would send rigs to the moon if you would make good profits doing so. We're here to make money and that's our only bias: to make money and be able to make money through the commodity cycle. So absolutely, we would relocate capital if it was in the best interest for our shareholders.

And then my follow-up is, you've touched on this a bit earlier, but maybe it's part of your soul searching process for 2020. It sounds like you're trying to find that precise optimal point of growth that doesn't prioritize free cash flow, but any calculus with respect to the importance of free cash flow as you think about that 2020 plan versus asset-level or corporate-level returns?

Well, yes. I do know that we're doing deeper, broader soul-searching than anybody else. I think we're all asking the question—clearly growing someone’s maximum capacity is not what we need to be doing right now. We're wrestling with the tension between our drive to want to grow and if so, the decision on a pullback may generate free cash flow and what we do with it. I am repeating myself, but I think anybody in the EMP sector that's paying attention is asking the same questions, and we will all have different answers based on our portfolio, balance sheet, and assets.

My question is around capital allocation. I think it was a year ago on your call. There was a lot of discussion about whether the company would initiate a buyback. I recall that you looked into it, talked to the board, and at that point in time, you guys decided not to do one. Fast-forward today, you’re talking about how half of it was than all prices are down a little bit, but I’m wondering, especially as you alluded to, what would you do with the free cash flow if you went into a no-growth state? Why is there no discussion currently, at least to us, about a buyback? The stock is down tremendously, and the NAV, by anybody's measure, is much higher than the current stock price. With liquidity and a stock trading where it is, can you give us an update on your thoughts as to what management is thinking?

Well, certainly, your points are well taken, and the argument for buyback is more persuasive today than it was a year ago or two years ago. But we will announce any decisions that we make once we make them. I mean we're always looking at it, and it's a question of how much free cash do you have, and is that where you want to deploy it? I mean we are not a team that likes to get drawn into speculation. You've made good points, and we certainly think that our share price is at the point where an analysis of that in the past is outdated. Mark, do you want to follow on that?

Yes. I think that we are continually evaluating the buyback relative to stock valuations versus investments. Currently, we are at a neutral position, but as you look forward, we expect to generate free cash flow, and we're going to look for the time between what we think the stock valuation is compared to other investments that. This could be the time. If we had free cash flow right now, and cash on the balance sheet, we would definitely, I think, be evaluating that.

I just leave it with, I think, pretty strong on investors that the company recognizes the value of its own stock, especially given the long reserve that we have and the significant discount you have on the valuation.

We agree with that and appreciate your comment.

My first question is on efficiency. So far this year, you completed more wells than anticipated due to better efficiencies. Can you quantify some of these efficiencies in terms of drilling or completion days? And comment on how sustainable you think you guys are going forward? I know you discussed in your prepared remarks the end result, which is your cost, but I'm just looking for a little bit more detail?

Yes, Jeanine. The efficiencies that are evident in the arrests that show up as a night in Q2 versus Q3 are really about 2 to 3 weeks' worth of benefit that we saw from an ability to turn on and have first production. So when we put our models together, we are using charts, etc., trying to line up everything, including relapse and what have you, and we've just seen, over the last quarter, some very good efficiencies out in the field without any hiccups. We've also seen these wells ready for production when we were done drilling and our plugs with facilities in mind, and they started cutting hydrocarbons earlier than we had forecasted as well. So we built a little cushion into our forward-looking guidance, and those results beat it.

Okay. And then my follow-up call is just discussing the additional net wells we did plan. Can you talk about the process of eliminating those wells in the back half of the year? It sounds like to make up for it in the schedule. Can you discuss that process in terms of maintaining the operational consistency that you talked about? It sounds like the quarterly timing shift might not be that big of a deal because of how many of those extra wells were. And the way we see it, you've got a lot of density at the end of the year, heading into 2020 if you choose. Just to ask a popular question, but is there a scenario where you would consider just pulling forward some of the 2020 wells because it's the best thing to do operationally? You mentioned that you can adapt to the current environment, but also that the market is a bit short-term focused right now.

Well, when you dissect a plan, what we really thought were just some small accelerations of wells coming online from Q3 into Q2, and I’m talking weeks on that, not months. Some of the Q4 wells getting pulled earlier into Q4 and/or even maybe the tail end of Q3. The end result as far as this year is concerned, we're pretty much right on top of what we thought we might do from a technical standpoint. And looking at about the same amount of wells at the end of the year. As far as trying to do anything in acceleration for '20 and '19, we're going to be very, very cognizant of our capital and how much money we're spending in '19.

Just wondering now that you've finalized your transfer agreement for natural gas, if you revisited your thoughts on transferring for oil at all?

Yes, we have actually. We've been looking at and have entered into an agreement for take away to the Gulf Coast out of the Mid-Continent, which also gives us an off-road into and from the Permian. It's about a 10,000 barrels per day commitment, expandable up to 20,000, and it begins in the first quarter of 2021. It's going to give us the ability to get to the Gulf Coast, Houston ship Channel with our oil whether it’s out of the Mid-Continent or the West Texas area. When you look at the specifics of what we're doing, it’s not only on the oil side. We've also entered into a long-term arrangement for gas and have secured a quantity of West Texas into Waha. With our getting into the reserve project, we are looking at all the ways to get out of the basin that we can, while simultaneously locking up our gas for residue for the majority of 2020. It's really insurance flow and trying to get to the better markets.

Do you think you're done in that regard at this point? Or is that more so to go there?

We’re not really speaking; we’ve taken some steps above and beyond where we’ve been, and we're going to continue to take additional steps going forward.

Good. Okay. I just wanted to ask, from an operational standpoint, last quarter, you talked about the Sir Barton and Brokers Tip pads. Just wondering what the end result was there? I know you were testing different sands and some spacing. What did you learn there?

Yes. Both of those pads, Sir Barton and Brokers Tip, those were seven wells each that we brought on. They were indeed testing as part of the development different landing zones with some of them being pushed up into what we call the Y sand instead of our regular landing zone. Both projects are very economic for us, and we are very pleased with them, but there are some important learnings. We are definitely seeing if we can get those landings further up and achieve a little bit more vertical separation with the lower tier landings, we definitely like the results of those wells versus when they are a little bit more crowded on a vertical basis. We are incorporating that into the next open projects, which is Carryback. From a cost standpoint, we’re excited about the learnings we've gained. We're also seeing about $1,000 per foot cost on that development project combined for both of those, which is a very, very good number and something we expect going forward, especially in the personal side, where it's a little shallower, a little lower pressure, and thus much quicker drilling for us.

I wanted to ask two parts. We’ve been talking some about the new plays that we're trying down in the Mid-Continent. The first question I want to ask is, can any of these efforts take place on existing acreage? And the second one is, if there is some success here, would this increase any provision for M&A? Or is this going to be an entirely organic effort?

Well, certainly, yes. We have a very large increase footprint in Anadarko, and I have high expectations that are among the footprint. Yes, there will be opportunities for other landing zones or other intervals that might lead to a much better returns than say, what was originally listed. A lot of acreage was acquired and drilled at a time when natural gas prices were much higher, which essentially established that footprint for us. We have the luxury of digging in, understanding the overall column, and looking for those intervals that clearly have the kind of hydrocarbon mix; in this case, oil, that the right drilling completion cost would yield competitive returns with our Permian program. As far as could this lead to M&A? I don't know. That's an option we might consider, but first and foremost, we have to convince ourselves that we have found a zone that is sustainable for capital on an ongoing basis, and if that scenario comes to pass, then yes, I think we might explore looking at other opportunities that could complement that beyond our existing acreage footprint.

Appreciate the color, and we will see you in New York on Thursday.

I just wanted to talk about capital a little bit. If you look at your year-to-date oil volumes and then into the third quarter guide, it kind of indicates the fourth quarter oil midpoint around 89 MBOE per day, which was basically flat to maybe relative to 4Q '18 pro forma for the Resolute deal. Is that a fair way to think about? Then if we look at the 2019 capital, is it fair to think about 2019 capital as basically kind of a maintenance level for your oil volumes at this point? Or is that kind of a transfer of factors that may suggest that the inappropriate way of looking at that capital efficiency at this point?

Yes, Michael, there are many ways to assess capital efficiency. If we look at capital on a pro forma basis, we had a strong exit rate in the fourth quarter, reflecting the achievements of the year. The maintenance capital with Resolute aimed to keep flat from the fourth quarter of last year. Our capital on a pro forma basis has decreased year-over-year due to an abundance of capital and cash leading into 2019. I want to emphasize that Resolute was experiencing significant outspending, and as we integrated that asset, we encountered a commodity environment that we had anticipated. We decided to advance the combined entity within cash flow while being very satisfied with those assets. Although we haven't discussed much operational detail in this call, I want to mention that we are currently bringing back production at the Sandlot project, which extends a development project that Resolute had undertaken through two phases. In our extension, we included some earnings, and as we start to flow some of those wells back, we are observing performance that matches the project's average. We're experiencing strong oil recovery, and the future plans for these assets are promising, confirming our reasons for acquiring them.

Okay. And I guess there is a follow-up. As you think about the completion count at the end of the year, relative to expectations around exit rig count, how does that look relative to normal? And what sort of timeframe—if that’s above normal, what sort of timeframe would you suggest is to think about that normalizing back down? Just trying to think more predictably and efficiently.

I'm not certain what you're alluding to. Are you talking about the number of, let's say, frac plays that we're running right now versus the beginning of the year?

No. Just regarding the completion count that you provided for year-end 2019. If you look at that relative to expectations of rig and completion crews at the end of the year, how does that compare to normal and should we…?

At a normal level, we have gone from two factors to two; there's some bearing on that. At the year-end '18, we had 20 projects that we kind of waiting for first production. That has increased, and obviously, 42 projects waiting for production at the end of '19. But it is up a little bit but it is sufficient from three crews to two crews. As we go into '20, we expect that to go back to three, and it's one of our bigger timing projects that we’re developing, and it depends on the size of the different projects. That’s the biggest book offering.

I think those nine net wells kind of slipped a couple of weeks in Q2 are really playing a role in how we are being perceived out there. Last quarter's guidance for the rest of the year, we're projecting 34 net wells for the last half of the year, and right now, we're at 27. So all that happened is a few wells slid into Q2 right at the very end of Q2.

I'm a big fan of Slide 13, which highlights your productivity, Culberson relative to other counties in Delaware. With this in mind, I was hoping to have you guys elaborate on what we can expect from the Reeves County acreage in terms of productivity, and ultimately, the returns versus Culberson acreage, acknowledging that Reeves is a massive county and ideally would be in more sweet spots. Just wanted to get your thoughts there.

We're not yet. When you look at the site, I'm a big fan of the upside as well, that it certainly highlights, in a very significant way, the performance of Culberson, which basically, when you see Culberson, that's Cimarex. I mean that's pretty much comprised of those wells. Whereas what we've done is of course gone to the state that the end amalgamated or the 2-mile laterals from all the operators into making that craft. Without a doubt, as you said, Reeves is a very big county, and as you can see on that particular graph, Reeves tends to fall after 18 months to a lower end. I can tell you that we've looked at that graph separately just with Cimarex wells, and yes, we definitely separate ourselves from what that background trend shows. Yes, we feel very good about the acreage that we have and have recently acquired through Resolute being some of the rhetoric that does need better commutative production than what you see as an average for the entire county.

And I can’t help but notice you’ve got this next line of said in the water infrastructure. I just wanted to get your high-level thoughts on what you think is a good value, then we could potentially peg in that event system? And if there’s any kind of updated thoughts on your desire to monetize that?

Well, value is becoming a bigger and bigger part of the Permian Basin business. We're always obsessing over it, and I've talked in the past, and I'll say again; there may be a time when monetizing some of our midstream assets makes sense to us. Right now, I'd say the value we get out of it is operational cost, access to water for recycling, and a really good environmental footprint with the way we've designed the water infrastructure. With these monetization needs, it ultimately becomes a trade-off between CapEx and OpEx. We're investing capital in that system; if you were to select, you would have higher operating costs through a fee structure. But this analysis remains evergreen; we assess it as a business, and there may be an appropriate time to decide to monetize it. But right now, the biggest benefit for us is operational efficiency, low operating costs, and it’s really helping us also have capital savings in water recycling. It's a great asset. Our team has really done an accretive job in building it, and it’s something we're very proud of, both from an operating efficiency and informative footprint perspective.

To elaborate further on Tom's point, just the recycling alone is potentially saving anywhere from $350,000 to $550,000 per well from a development cost perspective. So many months, rather by the number of wells, potentially in Culberson, we're talking a considerable amount of capital reduction by virtue of owning it.

Your thoughts on shifting to a consistent activity pace and can you just talk about kind of what that looks like? And where the right level of activities, assuming that the cash is fully funded for rig count or frac crews? Some more high-level ways to qualify that measure?

Well, yes. We're currently running rings in the Permian, and I think that's a reasonable cadence going forward. Of course, this also involves what we decide to do in 2020. I’d say the biggest decision we make is how many frac crews to deploy, and that often depends on our particular projects. We need to keep three frac crews continuously deployed and be efficient in doing that. What we don’t want to do is bring in a third crew and then release it. One of the things that we talked about on prior calls, we are in an area where two-thirds or more of our well cost is in the completion and facility side, and that means that as we plan our field events, the drilling rig itself no longer needs to control total project timing. So we’re looking to smooth out that completion facility capital to bring things on in a more consistent pace, distributing the field work so it's not peak demand, slowdown, peak demand, slowdown. We’re learning a lot and getting better at how to manage these projects. As for the right activity level, it will be a function of what we decide to do as we look into 2020. But I'll say, our organization has become tremendously improved at just project management and understanding how to eliminate these peaks and valleys in activity.

Thanks for that color, Tom. I guess one follow-up on that: you guys have made a lot of progress on reducing well cost. Is there much room for additional cost reductions? And how would that more consistent activity cadence play into that?

I would say that we are always looking for well cost reductions. The 5% to 6% reduction that we saw in completion costs just since April was due to the focus on design and operational efficiencies. We’re looking at a plethora of data that we've been able to obtain over the years as we’ve completed these wells, and we’re trying to optimize these ingredients to the frac to see the potential to continue to find ways to reduce our well costs. So I don’t know what the cap is, but I do know that there are opportunities to be more efficient and potentially improve net asset value through smarter completion design.

Yes. In closing, I just want to thank everybody for the good questions. We had a good quarter. We are looking forward to continuing to deliver excellent results and look forward to talking to you next quarter. Thank you.