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Cimarex Energy Co (NYSE:XEC)
Q2 2019 Earnings Call
Aug 6, 2019, 11:00 a.m. ET

Contents:

  • Prepared Remarks
  • Questions and Answers
  • Call Participants

Prepared Remarks:

Operator

Good day, and welcome to the Cimarex Energy Co., XEC, Second Quarter '19 Earnings Release Conference Call. [Operator Instructions] I would like to turn the conference over to Karen Acierno, Vice President and Investor Relations. Please go ahead.

Karen Acierno -- Director of Investor Relations

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 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, in 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 costs. EVP of Exploration, John Lambuth, and Cimarex CFO, Mark Burford, are here to help answer any questions you might have. [Operator Instructions]

So with that, I'll turn the call over to Tom.

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

Thank you, Karen, and thank you to all that've joined us on the call this morning. Cimarex had a good second quarter in a challenging macro 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 declining volumes in the Mid-Continent. We reaffirmed our capex for the full year, while raising our annual oil guidance by 1,000 barrel per day at midpoint. Commodity prices had an impact on our cash flow and earnings this quarter.

With the price environment we have faced, 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 fully burdened return. As we look ahead, we are completing the transition 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 cost.

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 play development. As we've said in the past, optimum development comes from understanding fourth key elements: first, understanding the stimulated fractured network, both along the borehole and away from the borehole; second, understanding parent/child interference and reservoir effect; third, understanding proper well spacing; and fourth, configuring an optimum project size and design. Cimarex has discussed our learnings on each of these 4 key points. There is no one-size-fits-all approach. The optimum answer to each of these 4 issues is a function of the reservoir properties, infrastructure requirement and economic conditions.

Through years of testing, we have gained a good and growing understanding of the requirement 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 have 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 throughout our operating areas and to predict their outcomes. This has also given us the insight to stand out of some non-operated projects. Our results thus far this year speak for themselves. We won't be making any detailed comments in our development activities in our prepared remarks.

I'll give you a quick overview of 2019. Of course, we're prepared to answer any additional questions you may have. As you know, our 2019 capital is primarily allocated to the Delaware Basin, with majority going to Upper Wolfcamp development in Culberson, Reeves and Lea County. Four of the five Culberson developments are online; 3 of the 5 Reeves developments expected online in 2019 are already producing; and the Vaca Draw development, our single development in Lea County this year, is currently flowing back. We have 3 additional developments that will be on production later this year. Operations are under way on several projects that will impact 2020. We currently have 8 rigs running in the Delaware along with 2 completion crews.

Now I'll turn it over to Joe Albi, who will discuss our operations in more detail.

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

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 cost. With a nice jump in our second quarter production, we continue with our strong start to 2019. Our Q2 net equivalent production came in at a 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. With the mark, our Q2 '19 net equivalent production was up 6% over Q1 '19 and 30% over Q2 2018.

On the oil side, our company record Q2 oil volume of 83,400 BOEs per day, came in early 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 MBOEs per day, up 45% over the 48,800 barrels a day we produced in Q2 '18. With the posting, the Permian now accounts for 85% of our total company oil production. As we look forwarded 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 272 MBOEs per day, keeping the same midpoint as our previous guidance, and we've raised the midpoint of our full year net oil production guidance by 1,000 barrels per day with a 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 -- or at midpoint from Q2. Shifting over to OpEx. With Resolute 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 with a new range of $3.30 to $3.65 per BOE. And lastly, some comments on drilling 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 AFEs by 5% to 6% since April, which translates into an attractive total well cost reduction -- or reductions in the range of $300,000 to $500,000 for each of our 2-mile lateral wells depending on the program. In our Wolfcamp program, with a tweak in our completion design, we've dropped our 2-mile completion AFE by $400,000. As a result, our generic Reeves County 2-mile Wolfcamp A 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 with an AFE range of $9.4 million to $11.9 million.

I want to point out that with the efficiency gains derived through our multi-well development drilling projects, our average development well -- development project per well costs are falling at the low end of these ranges. And in the Mid-Continent, with the refined completion design and improved operating efficiencies, we've reduced completion costs in both our Woodford and Meramec programs. Our current 2-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 the cost we quoted in early 2018. So in closing, our solid second quarter gives us a great springboard into the second half of the year.

With 9 net wells previously planned for early Q3 first production coming online during the last 2 weeks of June, we are forecasting a nice ramp in oil production in Q3 and Q4, resulting in an increase for our full year oil guide of 1,000 barrels per day at the midpoint as compared to our guidance last call. Our cost structure is healthy. We're projecting similar full year lifting cost guide as to -- 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.

Questions and Answers:

Operator

[Operator Instructions] Your first question comes from Arun Jayaram from JPMorgan. Please go ahead.

Arun Jayaram -- JPMorgan -- Analyst

Yes, Good morning, Tom, I was wondering if you could elaborate on some of your prepared comments when you're talking about your expectations on sequential oil growth into the second half of the year per your guide 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?

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

Well, yes, Arun, certainly, 2020 is -- feels a long way away right now. I will tell you that we're putting a lot of energy, as I said in my remarks, on just planning our field effectiveness and smoothing out our field cadences. 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 macro environment we're seeing on gas and NGL pricing. So although we haven't formed 2020 plans, I will say that to the extent that we're allocating capital, we're probably going to want to be emphasizing oil, and then although we'll be prepared for sequential growth, we haven't formed our 2020 plans and we'll make our decisions when more appropriate.

Arun Jayaram -- JPMorgan -- Analyst

Great. Great. And just my follow-up maybe for Mark, but I was wondering if you could talk through your marketing arrangements around your Permian crude? I know there's a new West Texas Light benchmark out there. So just wondering if you can give us some thoughts or help as we model your Permian differentials on a go forward basis?

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

Arun, this is Joe. Really, for the most part in Q2, to the extent that WTL was -- or the higher gravity was an impact on our pricing, we had already seen a gist of that in the -- during the second quarter. The index, as we're seeing it, the WTL index compared to May the push is now less than $1. We anticipate we'll have one other contract fall under the WTL basis here by September. And when we look at the volume representation of that contributor relative to our total Permian oil price, I am anticipating that, that might have anywhere, based on current strip, in the neighborhood of maybe a $0.30 to $0.35 overall hit on our total received oil price. So right now, the -- with the basis at less than $1, we're getting a premium to that WTL in the revised contract that we're looking at in September. I don't know if that helps you, Arun?

Arun Jayaram -- JPMorgan -- Analyst

That's helpful. Just an approximate mix of your Permian output, how much of that would be leveraged and maybe the WTL posted new contracted versus WTI? That would be helpful.

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

Arun, let's see if I can give you a ballpark here. You're forcing me to look, Arun. I'd say it's probably about 1/3 to 1/2 in the end. But again, a lot of that pricing is already in place.

Arun Jayaram -- JPMorgan -- Analyst

Okay, all right, thanks a lot Joe.

Operator

Your next question is from Neal Dingmann with SunTrust. Please go ahead, Dingmann. Your line is open.

Neal Dingmann -- SunTrust -- Analyst

I apologize. Good morning, guys. Tom, you mentioned about the consistent cadence. So I'm just wondering how do you -- you and John and guys think about this balancing that with the optimal size of your Delaware pads going forward?

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

Well, those are really 2 related but independent issues. The optimum size is -- it kind of stands alone from cadence. We look at the infrastructure requirements, we look at the amount of water handling at peak, we look at takeaway capacity, but first and foremost we look at the reservoir and to what extent is the reservoir forgiving of add-ons and to what extent there are add-ons introduced complications in the parent-child issue. So we look at all of that. I will say this, if all else were equal and reservoirs were infinitely forgiving, we would probably go for smaller projects and then maybe 6 to 8 wells per project rather than these large projects just for a whole host of reasons. But let me let John comment on that.

John A. Lambuth -- Senior Vice President of Exploration

Well, I think Tom hit the -- most of the points relevant to that. I think the biggest thing that controls that for us is just the amount of infrastructure required when you bring that many wells on, both on the water side, on the gas side. And what we tend to find in many of our areas that, as Tom alluded to, that 6 to 8 well at a time is a pretty good cadence, but also seems to fit well in terms of the pace of our infrastructure investment. If we were to go much beyond that, then, quite frankly, I think we'd be subject then 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 projects that we're approving, the development projects are in that 6- to 8-well range right now.

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

Yes. But among the many factors we consider, we value the economics of our assets throughout the asset life. So if we do a project and one of the considerations in determining its size is when will we come back to add-on and what impact will that production have on future development, both, the impact your production will have on future development and what impact will the future development have on that production. And so we -- as we've gained an understanding area by area and reservoir by reservoir, that's an important consideration to us. Some reservoirs are very forgiving, you can come back and they'll have no impact. Some reservoirs are very unforgiving. It also involves understanding where your frac barriers are within your vertical section. And so, I'll just say again, it's not a one-size-fits-all. We like to make tailored decisions around particular project.

Neal Dingmann -- SunTrust -- Analyst

Great. Great. And then just one follow-up. You talked about addressing your capital spend, specifically how do you arrive at the midpoint of capex of the year? It looks like you've already brought on about 60% of the wells and -- with about 50% of the capex budget, so if you could just address that.

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

Yes. This is Joe. When you look at what we report and what we're forecasting for capex, there's a lot of moving parts. We've got carryover dollars that were incurred '19 for '18 activity. You've got dollars that we're going to spend here in '19 and to carry into 2020 activity. We've got infrastructure dollars, we've got saltwater disposal dollars. And then on top of that, we've got the timing of activity relative to when dollars get ultimately recorded. In June, we completed, brought it online 13.1 net wells, 9.4 of those wells came on during the last 2 weeks. And as a result of that, we're anticipating that, that carryover is going to blow into Q3 and then ultimately equate into the branch that we've given you guys.

Neal Dingmann -- SunTrust -- Analyst

Alright. Good, thank you.

Operator

The next question is from Matt Portillo with TPH. Please go ahead.

Matt Portillo -- TPH -- Analyst

Good morning, guys. I was wondering if you might be able to elaborate a little bit on the completion design optimization, and what maybe driving some of those cost tailwinds that you highlighted at the beginning of the call?

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

Well, I'll take a stab at that. We -- there's lots of knobs that one has to turn on completion design. And certainly, spacing, stage facing, cluster, types of cluster, design, number of clusters per stage, amount of sand and fluid, pump rate, are your zipper fracking or not, I mean, all of those add up to the speed of efficiency in the field. But first and foremost, we focused on completion effectiveness, and we've done a lot of work on downhole effectiveness. We wanted to have a balance between cost effectiveness and completion and productivity effectiveness. And so we look at all of that and try to strike the right balance, I think we do an excellent job of it. We're always getting better and always questioning our core assumption. But I'll just finish and then let John comment. First and foremost, you have to understand your downhole fracture geometry or you're going to make some really bad assumptions as it flows through to your other decision.

John A. Lambuth -- Senior Vice President of Exploration

Really to just add on what Tom just said. We have been tweaking a few of our parameters, I'm not going to go into details on those parameters. What is nice to see is, over time, we're starting to see the benefit of those tweaks. We're starting to see a little bit faster cadence with each well that we complete. So we're seeing a nice cause and effect. And yet, with those minor tweaks, we're not in anyway degrading the performance of the well. So it's kind of what we've always wanted to do that we feel like in some cases we have a pretty optimal design from an EUR well performance basis. And now we're making the smart tweaks just in overall design that leads to a few more efficiencies. The jobs get done a little bit quicker, which leads to a little bit lower cost, but still not sacrifice the overall performance of the well. I think we're starting to see that more and more with a number of these development projects that we're bringing on.

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

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

Matt Portillo -- TPH -- Analyst

Great. And then a follow-up question around 2020. I know things are still in the works in terms of the planning process 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-Con next year versus kind of how things shook out this year in 2019? And then, Tom, I was wondering if you could flush out a little bit more just some of the commentary 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 next year, maybe the implications for -- from a high-level perspective kind of year-over-year growth on oil volumes going into 2020? And again, I know things are kind of in the works, but just any incremental color you might be able to provide there.

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

Yes. 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 trying to develop some new plays and some new concepts. We've talked in the past that we really like the Anadarko Basin, and we'd like to find some new things there. And so that will probably be our dominant focus in the Anadarko Basin, which will lead to a capital allocation that will, again, be disproportionately in favor of the Delaware Basin.

And then in terms of the comments I made that you've asked me to follow up on, on sequential growth, I will say that as we look ahead into 2020, we certainly have the capacity for a meaningful oil growth and delivering that in a sequential fashion. But we haven't formed our 2020 plans. And there's going to be some soul-searching on what the macro environment is and what we got to do with our capital. But we put a lot of work into field efficiencies, we put a lot of work into organizational effectiveness and planning, and we certainly have made tremendous progress, as we discussed in the past, on smoothing out our field operations and being able to deliver consistent quarterly execution. And we have that capacity, we have that ability, but we haven't yet formed the specifics of our 2020 plan.

Matt Portillo -- TPH -- Analyst

Thank you.

Operator

Your next question is from Doug Leggate with Bank of America. Please go ahead.

Doug Leggate -- Bank of America Merrill Lynch -- Analyst

Thanks, good morning everybody. Tom, no question that your execution excellence continues to do the -- exactly what you've guided us toward over the years, focus on returns, focus on capital discipline and so on. My question, I guess, 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 pretty unprecedented as 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 are you thinking about potentially repositioning the company in this somewhat challenging time we're in right now?

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

Well, those are great questions, Doug. I think that all of us have to ask question as what is the proper growth rate, if at all? We certainly have the capacity to grow, but I think that we are asking fundamental questions, all right, what's the growth rate that we think is appropriate? What amount of free cash can we and should we generate? And then what do we want to do with free cash? I mean those are the similar questions right now. We're all being challenged to behave like good manufacturers, and I'll say at Cimarex, we accept that challenge.

We've had to do a little bit of internal work that we talked about in terms of getting our field cadence more predictable, but then once we have that work done, which I believe we do, now it's beholding upon us to get to work and deliver consistent returns and deliver those returns to shareholders. I'll say this, I think that if we could open the hood 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 are showing us that the effort we've put into development learnings are paying off. But these are all good questions, we're wrestling with that. I think you'll see our 2020 plans reflecting that wrestling, and we accept the challenge. And, Mark, do you want to comment on that?

Mark Burford -- Vice President and Chief Financial Officer

Yes, Tom. That's definitely the items that we contemplate. And Doug, as we discussed in the past at your conference that there -- about the competitiveness with E&P trying to stack itself up against other industries and make it more attractive for the broader markets, and be able to generate free cash flow and some amount of growth, returning it to shareholders through dividends and other measures are making our E&P business and our sector more attractive and that's something at Cimarex we're definitely focused on. We've always had a focus on return on investment, making sure we're gaining full cycle returns and take that next step, how else can we further make our stock and our -- demonstrate that return to shareholders, so.

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

You know, I'm going to finish, Doug, by making a -- you've invited to me be philosophical, and I'm going to take you up on that. We're all very short-term in our thinking, and we're subject to it, markets are subject to it. And we always think that current conditions are the new normal and will be permanent conditions. We're in a cyclic business. We've seen lots of cycles, and so we remain focused on the long-term, on developing and executing a business that's sustainable, that can withstand the cycles and commodity. We remain cognizant of the fact that 1 or 2 world events could change this conversation materially.

We're confident that the world needs the products we produce for decades to come. And finally, 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 external markets that we're prudent stewards of capital and making investments that are efficient and effective, those are good things to do regardless of changes in the macro environment, right? So we're going to get after and we're going to demonstrate that we can adapt. But we're also going 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. So we're here for the long haul.

Doug Leggate -- Bank of America Merrill Lynch -- Analyst

I appreciate answering the question, Tom. You've certainly been very consistent in that message. I'd certainly credit you with 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 could kind of sum up the prognosis for you guys as it relates to gas and NGL with prognosis, if you like, for how you see your differentials evolving? I realize there were some accounting funnies on your gas realizations this quarter, but any help on line of sight as to how you see that moving into the next year? And I'll leave it there.

Mark Burford -- Vice President and Chief Financial Officer

Doug, looking at the -- starting in the second half of '19, looking at the Waha and El Paso Permian gas price index, we're looking around a $0.70 index for Q3 going to $1.50 on the futures curve for Q4. They're averaging just a little over $1, $1.20 or so for the second half of the year. So we see that improving into the second half of the year with Gulf Coast Express coming on, the futures spark is reflecting that, and we expect our second half gas realization to improve. And then you mentioned some of the differences with our reported realized price relative to -- with accounting ASC 606, which has some transportation and processing costs netted against it, which in Q2, there was $0.40 an Mcf of processing and transportation costs net against our realized price and that will continue. So in order to model the forward price, you'll need to incorporate that differential for 606 netting against our price, but we gave you the magnitude of that impact in our press release in the table.

Doug Leggate -- Bank of America Merrill Lynch -- Analyst

And there's a transportation -- there's a transport offset, though, right, in terms of the guide?

Mark Burford -- Vice President and Chief Financial Officer

That's it. That's right, Doug. So it's a transport offset, exactly right. I mean going into 2020, we see a forward curve that oscillates a fair amount into 2020. I mean, the first half year, our first quarter, you see as high as $1.70, going to $0.80 in the second and a $1, but on averages -- averaging -- the Permian prices were averaging around a $1.30 to $1.40, similar type improvements on realization relative to what we've seen in the second quarter of this year.

Doug Leggate -- Bank of America Merrill Lynch -- Analyst

Got it. I appreciate the answers, guys, thanks for your time.

Operator

The next question is from Brian Singer with Goldman Sachs. Please go ahead.

Brian Singer -- Goldman Sachs -- Analyst

Thank you. Good morning. Couple of follow-ups to the ones that have been asked earlier. First on the Mid-Con, you talked about new play concepts that you'd be working on or 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?

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

Well, I don't want to comment on any particular plays or the evolution of them. We'll talk about them when we have results to talk about. But the second one is easy. What we need to see here, material returns that compete with our Delaware Basin. Certainly, a lot of what we have in the Mid-Continent today compete, certainly we're -- the capital we're allocating is allocated to Mid-Continent because it competes heads up with what we're seeing at Delaware. But the robust inventory there is not the same. We have a deeper inventory of those things from the Delaware that compete for top tier capital than we do in the Anadarko. And so what we would need to see is deeper inventory and some great returns out of new and emerging plays.

Brian Singer -- Goldman Sachs -- Analyst

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

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

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

Brian Singer -- Goldman Sachs -- Analyst

Great. 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, asset level returns, corporate level returns and free cash flow, but can you kind of talk to those waitings a bit and particularly the importance of free cash flow as you think about that 2020 plan versus asset or corporate level returns?

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

Well, yes, I don't know that we're doing any deeper, broader soul-searching than anybody else. I mean I think we're all asking the question of, all right, what -- clearly growing at maximum capacity is not what -- we're not getting market signals, but that's what people want, and we're listening loud and clear. We're also deeply cognizant of the fundamentals of supply and demand and that we certainly have some market bottleneck. So we're -- I'll just say this, many of us -- throughout our industry, I'm not just speaking about Cimarex, but many of us grew up in a world where we grew at the maximum rate we could sustain.

And clearly today, that's not what we need to do. And so it's a tension between, "All right, do you want to grow at all?" And then -- and so, doing and making that decision, if you throw out your bag, your growth bag, you may generate free cash flow and then what do you do with it? I mean I am just repeating myself here, but I think anybody in the E&P sector that's paying attention is asking the same question. And then -- and we'll all have different answers based on our portfolio, our balance sheet and our assets.

Brian Singer -- Goldman Sachs -- Analyst

Great, thank you.

Operator

The next question is from Mike Foss with Brown Advisory. Please go ahead.

Mike Foss -- Brown Advisory -- Analyst

Hi guys. My question is along the lines on capital allocation. I think it was about a year ago on the second quarter earnings call, there were some questions and a lot of discussion about whether the company would initiate a buyback. And I think I recall that you looked into it, talked to the Board, and at that point in time, you guys decided not to do one. If we fast-forward to today, the stock is about half of where it was then. Oil prices are down a little bit, but I am just wondering, especially as you alluded to, what would you do with the free cash flow if you went into a no-growth state. Why there's no discussion currently, at least to us, about a buyback? The stock is down tremendously. The NAV, by anybody's measure, is much higher than the current stock price. With liquidity and the stock trading where it is, can you give us an update on your thought as to what management is thinking?

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

Well, certainly, your points are well taken, and the argument for a buyback is more persuasive today than it was a year ago or 2 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 it's that where you want to deploy it? We're really not a team that likes to get drawn into speculation. You made good points, and I acknowledge them. And we certainly think that our share price is at a point where any analysis we've done in the past is outdated. Mark, do you want to follow up on that?

Mark Burford -- Vice President and Chief Financial Officer

Yes. I think that's continuing to evaluate it. I think it's buyback of itself, it's probably looking at the valuation, relative valuation of your stock relative to other investments is something we've always taken into account. And right now, with our stock price where it is, relative attractiveness has only increased. And so we have to continue to evaluate it. And I think as if we had free cash flow at this point, we're still kind of neutral at this point. But as you look forward into outreach periods, we still expect to generate free cash flow. And I think we're going to be looking at always the value -- delta between what we think our stock valuation is and relative to the other investments. And this would be the point in time, if we had free cash flow right now and cash in the balance sheet, we definitely, I think, would be strong advocates of utilizing that.

Mike Foss -- Brown Advisory -- Analyst

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

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

We agree with that, and appreciate your comment.

Operator

The next question is from Jeanine Wai with Barclays. Please go ahead.

Jeanine Wai -- Barclays -- Analyst

Hi, good morning everyone.

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

Hi, Jeanine.

Jeanine Wai -- Barclays -- Analyst

My first question is on efficiencies. So, so far this year, you've 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 these are going forward? I know you discussed in your prepared remarks the end result, which is lower well cost, but just looking for a little more detail.

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

Yes, Jeanine, the efficiencies that we really saw that, I guess, are evident in the 10 extra wells that show up as online in Q2 versus Q3, they're really about 2 to 3 weeks' worth of benefit that we saw from when we were able to turn on, turn wells online and start to see first production. So when we put our models together, we're, obviously, using Gantt charts, Etc, trying to line up everything, including drill outs and what have you. We've just seen, over the last quarter, just 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 our plugs with facilities and flow lines, and they started cutting hydrocarbon earlier than we had forecasted as well. So we built a little bit of cushion into our forward-looking guidance, and those wells just beat it.

Jeanine Wai -- Barclays -- Analyst

Okay. And then my follow-up call is kind of following up on a couple of the other questions. So regarding those 10 extra net wells that you did in 2Q than planned, can you talk about the process of eliminating those 12 wells in the back half of the year? It sounds like to make up for it in the schedule, can you discuss the process for that 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 late in the quarter those extra wells were. And the way we see it, you've got a lot of DUCs at the end of the year for optionality heading into 2020, if you choose. And then maybe an unpopular question, but is there a scenario where you would just consider keep going and pulling forward some of the 2020 wells into 2019 because it's the best thing to do operationally, so perhaps short-term pain for medium-term benefit. I know you mentioned demonstrating that you can adapt in the current environment, but also that the market is a bit short-term focused right now.

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

Well, when you dissect our plan, what we really saw is just some small accelerations of wells coming online from Q3 into Q2, and I'm talking weeks on that, not like way a month in advance. And 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 darn right on top of what we thought we do from a total net well standpoint. We're looking at about the same amount of DUCs at the end of the year. And then 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.

Jeanine Wai -- Barclays -- Analyst

Okay, thank you very much.

Operator

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

Mike Scialla -- Stifel -- Analyst

Yeah, good morning. Just wondering now that you've entered a firm transport agreement for natural gas, have you revisited your thoughts on firm transport for oil at all?

John A. Lambuth -- Senior Vice President of Exploration

Yes, we actually have. We've been looking at and have entered into an agreement for take way to the Gulf Coast out of the Mid-Continent, which also gives us an offload into or from the Permian. And it's about 10,000 barrel a day commitment, expandable up to 20,000, and it begins the first quarter of 2021. So it's going to get us the ability to get out to the Gulf Coast. Beaumont, Corpus Christi, Houston Ship Channel with our oil and taking that oil either out of the Mid-Continent and/or the West Texas area. When you look at the spectrum of what we're doing, it's not only on the oil side. We've put together long-term arrangement for our Mid-Continent gas with Cheniere. And then in the Permian, we've gone ahead and got some fair amount of West Texas into Waha and then with us getting on to the Whistler project add up to 125 million a day. We're looking at all the means to get out of the basin that we can. And at the same time, we've locked up all of our gas sales for all of our residue gas through majority of 2020. And so it's really assurance of flow and then now trying to get to the better markets.

Mike Scialla -- Stifel -- Analyst

Do you think you're done in that regard at this point? Is that sort of still more to go there?

John A. Lambuth -- Senior Vice President of Exploration

We're always looking. So it's -- we've taken some steps above and beyond where we've been, and we're going to continue to take additional steps going forward.

Mike Scialla -- Stifel -- Analyst

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

John A. Lambuth -- Senior Vice President of Exploration

Yes. Both of those pads, Sir Barton and Brokers Tip, those were 7 wells each that we brought on. They were indeed testing as part of that development, different landing zones with some of them being pushed up into what we call the Y sand instead of our more regular upper A landing zone. Both projects are very economic for us. We're very pleased with them, but there's been some important learnings. We are definitely seeing that if we can get those landings further up and get a little bit more vertical separation with the lower tier landings, we definitely like the results of those wells versus when they're a little bit more crowded on a vertical basis. And so that's something that we're incorporating, in fact have incorporated into our next development project on the west side of Culberson, which is carryback.

Also, I would just say, so far from a cost standpoint, and Joe alluded to this, we're very pleased, especially in that western side of Culberson that what we're seeing so far on a cost basis, and I would just say this is specifically just these 2 projects, but so far, we're 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 that we expect going forward, especially in that western side, where it's a little bit shallower, a little bit lower pressure and does much quicker drilling for us.

Mike Scialla -- Stifel -- Analyst

Very good. Thank you.

Operator

The next question is from Jeffrey Campbell with Tuohy Brothers Investment. Please go ahead.

Jeffrey Campbell -- Tuohy Brothers Investment -- Analyst

Good morning. I'll keep my question to one with a kind of a two-parter. We've been talking some about the new plays you're trying to fair down in the Mid-Con. And the first question I wanted 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 potential for M&A? Or is this going to be an entirely organic effort?

John A. Lambuth -- Senior Vice President of Exploration

Well, certainly, yes. We have a very large acreage footprint in Anadarko, and I have high expectations that among that footprint, yes, there will be opportunities of other landing zones or other intervals that might lead to much better returns, then say why we originally leased it, but let's face it. A lot of acreage was acquired and then drilled at a time where natural gas prices were much higher. So that essentially established that footprint for us. And as we've said in the past, all of that acreage is held by production. So we had the luxury of digging in, understanding the overall stratigraphic column and then, as Tom alluded, looking for those intervals that clearly have the kind of hydrocarbon mix, which in this case means oil, that with the right kind of drill and complete cost could lead to returns that could be competitive with our Permian program. As far as could this lead to M&A, I don't know. I mean, obviously, that's an option. But first and foremost, we have to ourself be convinced that, a, we have found a zone that will compete for capital on ongoing basis, which means there must be size there, it must be sustainable. And in that scenario, then, yes, I think we would then see what other opportunities might be out there that could complement that, that's above and beyond our existing acreage footprint.

Jeffrey Campbell -- Tuohy Brothers Investment -- Analyst

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

Operator

The next question is from Michael Hall with Heikkinen Energy Advisors. Please go ahead.

Michael Hall -- Heikkinen Energy Advisors -- Analyst

Thanks, Good morning. I appreciate the time. I just wanted to think about or look at capital efficiency a little bit. If I look at your year-to-date oil volumes and then third quarter guide, kind of indicate the fourth quarter oil midpoint around 89 MBOE a day, which show us basically flat to maybe a hair down 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 let's say there are kind of transitory factors that maybe suggest that's an inappropriate way of looking at capital efficiency at this point?

Mark Burford -- Vice President and Chief Financial Officer

Yes, Michael, there's a lot of ways to look at capital efficiency. And if you look at the capital, the pro forma capital along with pro forma cap from Resolute and Cimarex for the quarter, both are ramping significantly into the fourth quarter, both had a very high exit rate in the fourth quarter accomplishes that year. That definitely has an overplay on how you'd look at relative fourth quarter to fourth quarter rates. And the maintenance capital with Resolute and us combined, trying to maintain a flat fourth quarter to fourth quarter. I guess, we are -- our capital on a pro forma basis is down significantly year-over-year as we balance our capital plans with our cash flow into 2019. So I guess so if you'd want to argue that with adjustments in our capital by holding our capital or production roughly flat, then that's maintenance capital, I wouldn't maybe dispute you on that.

John A. Lambuth -- Senior Vice President of Exploration

Yes. I just want to remind you that Resolute was on a pretty massive outspend. And as we pulled that asset and certainly faced the commodity environment that was a little more hostile than what we had anticipated, we made the decision to bring the combined entity forward within cash flow. But I also want to say, we are very, very pleased with those assets. And we haven't talked a lot about operational detail in this call, but I will share with you that we're currently flowing back that Sandlot project, which was essentially an extension of a development project that Resolute had done 2 phases on, on our extension. We incorporated some of the earnings that we brought. And as we flow those wells back, we're seeing significantly higher performance out of our new wells than had been the average on that project and prior. We're seeing high oil recoveries, better returns. And so we're -- we really like those assets, and we are seeing fruits of all the reasons why we wanted them in our hand.

Michael Hall -- Heikkinen Energy Advisors -- Analyst

Okay. Appreciate that. And then, I guess, as a follow-up, as you think about the waited on completion count, at the end of the year, relative to your expectation around exit, rig counts and crew counts, how does that look relative to normal? And what sort of time frame -- if that's above normal, what sort of time frame would you suggest is fair to think about that normalizing back down, just trying to think about 2020 capital efficiency?

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

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 beginning of the year?

Michael Hall -- Heikkinen Energy Advisors -- Analyst

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

Mark Burford -- Vice President and Chief Financial Officer

Michael, I would apparently call it a normal level, but we have gone from 3 frac crews to 2 in the second half of the year, so it has some bearing on that. At the year-end '18, we had 28 net wells that we're kind of waiting on first production. Those -- that has increased, where it's, obviously, projecting now 42, we're expecting they'll be waiting on production at the end of '19. So it is up a little bit, but it's false reflection we're going from 3 crews to 2 crews. As we go into '20, we expect that crew count to go back to 3. And it still always is more of a bigger -- overprint and it's just the timing of the projects we're developing and the size of the different projects. That's the biggest overprint.

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

I think those 9 net wells had kind of slid a couple of weeks in Q2 are really playing a role in how I guess, being perceived out there. But last quarter's guidance, for the last half of the year, we were projecting 34 net wells for the last half of the year, and right now, we're now at 27. So all that's happened is a few wells slid into Q2 right at the very end of Q2.

Michael Hall -- Heikkinen Energy Advisors -- Analyst

Okay. As I just think about -- I was trying to think about like 2020 -- potential tailwinds to 2020 capital efficiency from that backlog of waited on completion wells, it doesn't really sound like that's particularly out of normal, particularly if you're going to pick up a completion crew affair?

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

No. Indeed. The docs are virtually about the same, in fact a little bit more from our current forecast. So again, it's just some slight moving of a couple net wells is all that's really going on.

Michael Hall -- Heikkinen Energy Advisors -- Analyst

All right, thanks guys.

Operator

The next question is from Mike Kelly with Seaport Global. Please go ahead.

Mike Kelly -- Seaport Global -- Analyst

Thanks guys, good morning. I'm a big fan of the Slide 13 you have in here, which highlights your oil productivity in Culberson relative to other counties in the Delaware. With this in mind, I was hoping to have you guys maybe comment what we could expect out of your Reeves County acreage in terms of oil productivity, and ultimately the returns versus your kind of core Culberson acreage, acknowledging that Reeves is a massive county too and you guys hopefully would be more in sweet spot? But just wanted to get your thoughts there.

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

Yes. I know when you looked at the slide and I am a big fan of that slide as well that it certainly highlights in a very significant way the performance at Culberson, which basically -- when you see Culberson, that's Cimarex. I mean that pretty much who comprises those wells. Whereas what we've done is, of course, gone to the state data and amalgamated all the 2-mile laterals from all the operators into making that craft. And 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 the lower end. I can tell you that we've looked at that graph separately just with Cimarex wells, and yes, we definitely separate ourself from what that background trend shows. And yes, we feel very good that the acreage that we have and have recently acquired through Resolute is some of the better acreage in Reeves County that does lead to better cumulate production than what you see as the average there for the entire county.

Mike Kelly -- Seaport Global -- Analyst

Okay. Great to hear. And I can't help but notice you've got this nice slide also in here in the water infrastructure. And just wanted to get your mid-to-high level thoughts on what you think is a good value that we could potentially peg on that system? And if there's any kind of updated thoughts on your desire to monetize that?

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

Well, value is -- of course, water is becoming a bigger and bigger part of the Permian Basin business. We are always assessing that, and I've talked in the past, and I'll say again, that there may indeed be a point in time where monetizing some of our midstream assets makes sense to us. Right now, I'll say the value we get out of it is low operating costs, access to water for recycling and a really good environmental footprint with the way we've designed that water infrastructure. With these monetization deals, it ultimately becomes a trade off of capex or OpEx. I mean certainly, we're investing capital in that system. If we were to sell it, we would have a higher operating cost through a fee structure.

But we keep that analysis evergreen. We look at it as a business and there may indeed be an appropriate time where we'll decide to monetize it. But right now, the biggest benefit for -- from us is operational efficiency, low operating cost and it's really helping us also have capital savings in water recycling. So it's a great asset. Our team has really done a creative job in building it. It's something we're very proud of, both from just an operational efficiency, but also an environmental footprint. And monetizing it is not off the table. But I'll just say this, we look at it constantly and when we think it makes sense, we'll move forward.

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

To elaborate a little bit further to Tom's point, just the recycling alone is potentially saving us anywhere from $350,000 to $550,000 per well from a development cost standpoint. So when you multiply that by the number of wells, potentially at Culberson, we're talking a fair amount of capital reduction by virtue of owning it.

Mike Kelly -- Seaport Global -- Analyst

Got it. Appreciate the color.

Operator

The last question is from Drew Venker with Morgan Stanley. Please go ahead.

Drew Venker -- Morgan Stanley -- Analyst

Hi, everyone. Tom, you talked about shifting toward more consistent activity pace. And can you just talk about kind of what that looks like? And where the right level of activity is, assuming the cash flow to fully funding of rig count or frac spreads or some more high level way to quantify that measure?

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

Well, yes, you bet, Drew. I mean we're currently running 8 rigs in the Permian, and I think that's a reasonable cadence as we march forward. Of course, this also involves what we decide to do in 2020. I'll say that the biggest decision we make is how many frac first to deploy, and that's often the function of the particular projects that we have and can we keep 3 frac crews continuously deployed and be efficient in doing that? What we don't want to do is bring a third crew and release the third crew and bring a third crew and then release the third crew.

One of the things that -- again, we've talked about this in prior calls, we're in an area where 2/3 or more of our well cost is on the completion facility site, and that means that as we plan our field cadence that the drilling rig itself no longer needs the demand and control total project timing. So we're looking at smoothing out that completion facilities' capital to bring things on in a more consistent pace, distribute the fieldwork, so it's not peak demand slowdown, peak demand slowdown. And we're learning a lot on how to manage these projects. We're getting a lot better, and I'm not particularly answering your question on what the right activity level is. It will really be a function of what we decide to do as we look into 2020. But I'll say, our organization has gotten tremendously better at just project management and understanding how to eliminate these peaks and valleys in activity.

Drew Venker -- Morgan Stanley -- Analyst

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

John A. Lambuth -- Senior Vice President of Exploration

I would answer that, that we're always looking for well cost reduction. So the 5% to 6% reductions that we saw in completion costs at least from April really were due to the focus of design and operational efficiencies. And we're looking at a plethora of data that we've been able to obtain over the years that we've been completing these wells and trying to optimize, I'll call it, all the ingredients to a frac and see the potential to continue to find ways to reduce our well cost. So I don't want to throw a percent out there that's possible because I don't know that it is, but I do know that there's data out there that says we can get more efficient and we can potentially produce a higher net asset value well, maybe that may not have as high a peak rate, but certainly from a capital investment standpoint provide better economics. So we're looking at everything.

Drew Venker -- Morgan Stanley -- Analyst

Thanks, Tom.

Operator

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

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

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

Operator

[Operator Closing Remarks]

Duration: 64 minutes

Call participants:

Karen Acierno -- Director of Investor Relations

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

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

John A. Lambuth -- Senior Vice President of Exploration

Mark Burford -- Vice President and Chief Financial Officer

Arun Jayaram -- JPMorgan -- Analyst

Neal Dingmann -- SunTrust -- Analyst

Matt Portillo -- TPH -- Analyst

Doug Leggate -- Bank of America Merrill Lynch -- Analyst

Brian Singer -- Goldman Sachs -- Analyst

Mike Foss -- Brown Advisory -- Analyst

Jeanine Wai -- Barclays -- Analyst

Mike Scialla -- Stifel -- Analyst

Jeffrey Campbell -- Tuohy Brothers Investment -- Analyst

Michael Hall -- Heikkinen Energy Advisors -- Analyst

Mike Kelly -- Seaport Global -- Analyst

Drew Venker -- Morgan Stanley -- Analyst

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