Good morning and welcome to the Cimarex Energy XEC 4Q '19 Earnings Release Conference Call. All participants will be in a listen-only mode. [Operator Instructions] After today's presentation, there will be an opportunity to ask questions. [Operator instructions] Please note this event is being recorded. I would now like to turn the conference over to Vice President of Investor Relations, Karen Acierno. Please go ahead.

Thank you, Ian. Good morning everyone and welcome to our fourth quarter and full-year 2019 conference call. An updated presentation was posted to our website yesterday afternoon, and we may reference that presentation on our call today. Just 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-K for the year ended December 31, 2018 for risk factors associated with our business. We plan to power 10-K for the year ended December 31, 2019 by the end of next week. We will begin our prepared remarks with an overview from our CEO, Tom Jorden; then Joe Albi, our COO, will update you on operations including production and well costs. CFO, Mark Burford, is here to help answer any questions along with Blake Sirgo, VP of Operation Resources. As always and so that we can accommodate more of your questions during the hour we have allotted for the call, we'd like to ask that you limit yourself to one question and one follow-up. Feel free to get back in the queue if you like. With that, I'll turn the call over to Tom.

Thank you, Karen. and thank you all for joining us on the call this morning. I will briefly discuss our operational highlights and focus followed by our CEO, Joe Albi, who will provide a more detailed breakdown on the quarterly details. Despite the challenging macro environment, Cimarex had a solid fourth quarter and solid results for the full year 2019. Our oil production came in above the midpoint of our guidance range and was up almost 3% sequentially, led by Permian oil volumes which grew 5% sequentially. Permian oil growth is projected to continue into 2020 with Permian volumes up 14% at midpoint, leading estimated total company oil growth of 9% at the midpoint of our guidance. Capital for 2019 was well below our guidance range. This was driven by significantly lower completion costs in the fourth quarter coupled with the incorporation of changes to frac designs that we tested during the quarter. The result was total capital investment for the year of $1.32 billion including our midstream investment. Guidance was 1.37 to 1.47 including midstream. Commodity prices continue to be a challenging headwind, particularly for natural gas and natural gas liquids. In spite of these headwinds, we were able to generate free cash flow in excess of our dividend and had $95 million in cash at year-end. Our outlook for 2020 and beyond looks quite good. We are using a $50 WTI price and $2.25 NYMEX gas price and our capital planning over the next 3 years. With activity similar to that in 2019, we expect to generate similar results of approximately 10% of growth per year and grow our free cash flow year-over-year. We're quite pleased with the organizational progress we're making on several fronts. Last year, we identified five major pillars upon which we are focusing our…

Well, thank you, Tom, and thank you all for joining us on our call today. I'll touch on our fourth quarter and full year production, our Q1 and full year 2020 production guidance, and then I'll follow up with a few comments on LOE and service cost. Looking at Q4 with continued strong execution, we posted another company record during Q4 with our net oil volume coming in at 92,000 barrels per day, beating the midpoint of our guidance by 3,000 barrels per day and putting us up 3% and 15% over our Q3 '19 and Q4 '18 postings respectively. The Permian drove the increase with our Q4 Permian oil volume of 78.4 thousand barrels a day, up 5% over Q3 '19 and 27% over a year ago in Q4 '18. With that, the Permian now accounts for 85% of our total company oil production. Completion timing played a role in our beat, with 12 net wells previously slated for sales in early 2020, coming online and mid to late December which added approximately 1,200 barrels a day the quarter. Our Permian activity also boosted our Q4 net equivalent production, which came in at 293,000 barrels equivalent per day, feeding the top end of our guidance and setting a new record for the Company. As far as capital is concerned for '19 with increase operational efficiencies and lower service costs for full year 2019, total capital came in at $1.315 billion at 7%, below the midpoint of our previously issued guidance, and Tom touched on that to some degree in his discussion. Looking forward into 2020, our forecasted production model reflects our focus on the Permian and it's all predicated on the $50 per barrel WTI and $2.25, Henry Hub pricing that we've just mentioned. Our 2020, total capital guidance…

[Operator Instructions] Our next question comes from Gabe Daoud of Cowen. Gabe, please proceed.

I was hoping we could start maybe on the free cash flow guide for 20 in the outlook. I guess as gas prices were to stay where they are today alongside, I guess NGL prices also staying relatively stable from here. How much flexibility is built into the program this year in order to allow you guys to cover the dividends? What do you think about potentially deferring that Mid-Con rig or a third crew in the Permian? Just any thoughts about flexibility would be helpful.

Yes. Gabe, the free cash flow we projected for 2020 in the $50 price deck, we're only assuming out of nickel realization, which doesn't beat a negative price for the second quarter this year for realization and for Permian. If prices there to be more significantly lower than that, we would be evaluating always, as we always do, our capital allocation. We do have flexibility in our plans and we would think about it. I think that premium gas price alone is probably not a factor in which we make major changes.

Gabe, this is Tom. Yes, we do have tremendous flexibility and that we don't have services under contract. But Mark's answer is the right one that we've baked in a pretty draconian estimate of differentials.

And then, I guess, just as a follow-up. Could you maybe talk a little bit about the decision to allocate some capital to the Mid-Con in 20? Is there anything different going on there that you guys are doing to perhaps increase returns versus the legacy program?

Well, we've always said, we've got some great opportunities in the Mid-Continent and so we decided to advance a couple of projects. One major project is Meramec development that looks just fantastic on all fronts. I mean, it competes, heads up with the Permian on rate of return and in all fronts, it was ready to go. It fits nicely in our capital plan and it does take some of the operational pressure off of our Permian group as well. So, yes, it was a pretty easy decision based on return on capital and capital allocation.

I would mention also that the reductions that we've seen in our well cost very helped to build momentum to that project.

Just a quick clarification that you're 2020 Permian AFE per foot guide, does that assume the legacy completion or the new value engineer completion that you've tested in the 4Q?

Well, it actually has a fairly conservative completion design, but yes, that's the one we're going with. We're not sandbagging. We're doing a lot of experimentation. We're looking at flow back and we're just not quite ready to commit to a lower cost. That said I'm going to tell you, I think we're going to hit that. We're really challenging our group to be innovative to look at cost as a critical component, to make sure that we get the most valuable well, and not necessarily the most productive well. I mean, there are situations where your value increases, if the cost savings can override any production reduction. So, we're seeing a lot of encouragement. But as we go into 2020, I will tell you that our plan, our base completion is probably on the conservative side on expenditure.

Our next question comes from Arun Jayaram with JP Morgan.

Tom, I was wondering, if you could give us more insights into the three-year plan. In particulars just wondering, what type of rigor went into the analysis? Is this a top down view or more bottoms up involving, call it sticks on the map, identified projects, et cetera?

Arun, I think I've mentioned that in my opening remarks. This is very much bottom up. We have -- our focus on planning involves our entire organization from the operations team up the C-Suite. And if there's any lesson that we've learned in the last few years, it's that, you need your operations people intimately involved in crafting the plan because they're the ones that are going to have to execute it. They understand the logistics and difficulties of a complex plan. And so that, the plan that we announced this morning is real, it's fixed on the map. There's a commitment for organization executed. But I'd also want to reiterate the single and most important variable in that plan is our cash flow, which is driven by commodity prices. But given the parameters we outlined, we're going to execute that plan.

And when you made the comment Tom about ratable activity levels, I was just wondering, if you could maybe provide a little bit more color around that kind of comment?

That wasn't my word, but Mark, do you want to comment on that?

Arun, we're talking in terms of ratable activity, certainly in our rig and completion cadence in the rig levels in our capital deployments and certainly also around our frac crew cadence. We are not operating our frac crew cadence and are still in development, all of that being in the plans built out of a ratable consistent basis to be the most operationally efficient. But there is still always an element of our production profile, even as Joe mentioned, issue with some of the production profile still not as it is ratable. That's also reflection of the timing of the completion of the different infill developments. And even with a consistent operational cadence, depending on the timing of the different infill development, you will still see some variability in that production cadence.

I'd also add that, we talked about activity versus capital. When we did this, put this plan out a year ago, the locked down capital will be 1.5 billion every year. This year, our capital really more tied around 50 and 225 that we're using to budgets from. And then, we have a goal of basically growing 10% as a minimum. So, there you go. So, we're not tied to a specific level of capital every year. In fact, in 20-year, we're spending a little bit less than '19.

And just my follow up, Tom, I was wondering, if you could provide us maybe a little bit more color on these less than tense attract designs that you've been testing, particularly in the fourth quarter. Can you give us a sense of fewer stages? Or what exactly have you been testing? And perhaps what type of cost savings on $1 per foot basis are you yielding on these new frac designs?

Arun, you're going to have to forgive me, if I decline to discuss the specifics of what we're testing. I mean, obviously, there are many variables that go into frac design, there's cluster spacing, there are clusters per stage, there's perforation style, there's pump rate, there's fluid and sand for cluster. There's composition and type of sand and any other additives either diverters or surfactants and many other variables that go into that. Probably, I will just in general tell you that, one of the variables that has the largest impact can be stage length because that tells you how fast you can get on and off the job and that's certainly a significant variable. We did see fairly significant cost reduction in our simulations quarter-over-quarter. We're not committing to that going forward. Joe, do you want to comment on the cost reductions?

Yes, as I'm hearing you guys talk, it's underneath the hood here. There's so many things that work. It's the cost of the products and then your efficiencies pumping the job. The longer stage length that Tom mentioned, says, hey, I don't need to pump as many stages to that well. So what we've been able to do over the last year, Arun, is pretty remarkable in my opinion. We've cut through our efficiencies alone. We've cut the number of days to frac a 2-mile Wolfcamp well for about 9.9 to 6.5 on the average, and that's the 30%-ish reduction in time while you're charged for that time, right. And so, when we look at the overall reduction on the completion side, I would say the overwhelming elements of that reduction has been our ability to take advantage of the market and our efficiencies to create the cost reductions that we're seeing. These additional design stages are only going to sweeten the pot if they make sense when we go to complete the well, and we see the results that we get. And all in this thing and that's our preferred number, there's so many elements to this. And what I love about it, it's going to focus our and does focus our business units to look where they can grow longer laterals, to look where they can grow multi-well pads where they can add to existing multi-well batteries, where they can recycle, where they can zipper frac. The bottom line is, the whole thing added up is creating these dollars per foot metric that we love challenging the organization with to optimize the overall program.

Let me just make one last comment. Our cost is a critical element, but it's not a driving element. The driving element for us is value created. And so, there are a lot of elements that we look at when we look at completion design. Certainly, cost and well productivity are critical elements. But what's also critical element is the impact it may have on well spacing, the impact it may have on well interference, the impact it may have on full section development. We're trying to maximize the value and cost commodity pricing, well productivity, those are outputs from a focus on value and that's the way we do this problem.

Our next question comes from Betty Jiang of Credit Suisse. Betty, please proceed.

I have a question on New Mexico like from what I can tell, Cimarex New Mexico performance has been sourced from the best in the portfolio in 2019. So two parts; first, is it fair to say that you have determined the best optimal development approach in terms of targeting and spacing for that area, I guess specific Lea County. And then second, is there room for New Mexico to be an even greater percentage of capital allocation over three years beyond where you already increased the two for this year?

Yes, Betty, certainly, we have not optimized the point where we're satisfied. No, we're never satisfied. We've made a lot of progress, but I will not say that we think we found the secret sauce and the formula will be unchanged. We think we have progress to make in New Mexico throughout our portfolio and we were hyper-focused on that right now. I'm really glad you asked about New Mexico because New Mexico carries into our discussion on costs. Our returns in New Mexico are fantastic, but we also see some shorter laterals in the Mexico, they're not all 2-mile long. And so the way we view costs is we ask our organizations to put the program together that generates the most value and then we look at that program and on that we take a cost target. So, we don't want to discourage them from drilling 1 or 2 or 1.5 mile laterals because the cost of target comes first. And really that whole emphasis and what I just described is driven by New Mexico because we love New Mexico, and we would never want an arbitrary costs target to discourage some of the incredibly profitable activity in the Mexico. We do think we can increase activity in New Mexico your latter question. Now, New Mexico has some unique issues that Texas doesn't. We're generally on state and federal leases. Our permit time can be long. We have environmental constraints with some species protection. You hear us talk about the prairie chicken, the horn muscle and the sand dunes lizard. I mean, these are all things that limit your ability to just turn a crank up at will. New Mexico takes great planning and again, I'm going to come back to that pillar on planning. This organization has made a tremendous amount of progress, but we're very, very high on our New Mexico asset and the potential over the next few years.

And then, I also just want to sort of clarify the three year outlook. Maybe I'm reading a bit too much into what you say in a press release, but you've sort of talked about based on this ratable level of activity at the minimum, we could see similar production growth that was increasing free cash flow. I guess just on that minimal standpoint, other look is the confidence level that things could be in line to better that what would show in this slide deck? And then also just when we look at 2021 and 2022, is it fair to assume that those two years have a fairly similar profile instead of in terms of growth and free cash flow?

Yes, I'll kick it off and turn it over to Mark. I think we have tremendous upside within that capital plan. We have cost upside. We've execution of side. We've well performer upside. So, I'm incredibly optimistic right now about our ability to just flat out, get better at our business, and that will show up in a better performance with same capital investment. So, Mark, I'm going to let you handle the remainder that.

Yes, Betty, just to clarify. So, you're concerned about the ratable activity leads to 10% growth, is that leads to your question? What, that what you're trying to understand here?

Yes, I'm trying to understand sort of when the free cash flow and the growth shows up over that 3-year timeframe. We know 2020, but what 2021 and 2022 generate, both of them generate similar level of growth and free cash flow in each of those years.

Yes, Betty, so, yes, the 3 years actually the '21 and '22, of course we don't have disability individually for. Our growth in oil is as strong or started and what I would say that we're experiencing in '19. And on equivalents, we actually see the equivalent portion of our volumes growing more consistently in the '21 and '22 time periods as well. Our capitals fairly consistent around that $1.3 billion and there's a little variability between the years that just again, timing of our projects, but we have 2 things came just the capital hitting to any on the rig schedule. We have built up rig schedules and completion schedules for all these plans. And it's just some variability in those schedules, but we see a growing cash flow each year and actually in 2022. One thing to point out in all of our analysis even on the flat sensitivities, we do use four gas differentials as the basis for our valuation relative to NYMEX. So, in '21 and '22, with some of the improving thesis differentials, we do get that benefit for building into our forecast.

Our next question comes from Doug Leggate with Bank of America. Doug, please proceed.

Tom, I love the pronunciation. I'll go with it. I think the previous question we have actually touched on something I wanted to ask, and it was really on slide 10 and 11 of your book. I just want to make sure I'm reading this correctly. The gas price assumption has been there. I think you just said you're using strip differentials, if I read correctly. Is that right? That wasn't actually my main question, but I just wanted to check out the point we're making.

Yes, that's correct. So when we look at the flat NYMEX price to 2.25, we still use its 4 differentials and dedicate that NYMEX price, we use the ratios like, right now the NYMEX price is a little bit lower than 2.25 in '19, but slightly better than that in '20, but we use ratio, the differential stood at NYMEX price come up with the basis price and those flat price cases.

Doug, that's true of all of our capital planning. We really want to level our capital plan, the actual well received price. So, yes, not that, we're pressuring and getting it right, looking ahead, but we're certainly trying to have the most realistic look.

The real root of my question was and I hate to do this, Tom. You did say that you didn't want to get pressed too much on use of cash because you want to generate the cash first. But let's assume the Street space case is probably around 55 PI. If I'm looking at this chart by Slide 11, this implying about a one, I guess, $1.1 billion of free cash after dividends in 2021 and 2022. Is done the message or am I reading that wrong? Because if I'm not reading it wrong, that's better than a 10% free cash flow yield after dividends. And my question, I guess would be buy your stock in that scenario?

Well, I have no good answer for that. As I said in my remarks, a share buybacks is very much something that we discuss. Now, I want to repeat what I said, we're also really trying to manage our balance sheet, and we're carefully looking at the debt markets, and they open and close. And so, retiring debt is also in that list of priorities. Certainly, I list the three things, increasing dividend, debt retirement, and share buyback. And all of those are things that we are deeply interested in.

So my second question, that was actually my first question. So, my second question is really more. I want to get back to pricing and inventory and specifically want to touch on the NGL or something you guys are using. And what your economic inventory that's looks like, at the current pace? And I guess my maybe really the big delta here is. What are you -- how confident or comfortable are you with the assumption you're making around the NGLs given there is a lot of new infrastructure and so on, but that's obviously a pretty big factor in determining the economic inventory? I'll leave it there, thanks.

Well, I'll just take your last point first. How confident are we on future pricing? Not confident at all and anybody on the call that wants to help us out there, please press your button. Yes, we -- that's why we managed with a healthy balance sheet. That's why we do a lot of downside sensitivity. Every investment we make, we look at it as many different price files. And we always want to make sure, that's a good investment even in our most conservative case. But of all the things I worry about Doug, I will tell you that, as I sit on this call today, the economic inventory is almost off my list. We have seen our inventory increase. I'm looking forward to talking about some of these new landing zones we tested. We have never been more bullish on our economic inventory and I'll just leave it there. It's just not on my worry list and I've spent a lot of time worrying.

Our next question comes from Mike Scialla with Stifel. Mike, please proceed.

Tom, I want to see if you could give any more detail on, on the things you're doing on automation and machine learning front. And you said, it caused you to revisit some long held assumptions, any color you can add to that comment?

Well, only in the most broadest sense because we're not ready to talk about it, but I will tell you that we embarked on a machine learning project that looked at our completion methods. And imagine all the hundreds of decisions that we've made over the last few years and how to complete our wells, each individual decision has been made with an economic plan, but each individual decision has led us down a particular path. And we're very pleased with where we are, but the power of machine learning is it lets us throw in every one of those decisions and goes through millions of simultaneous solutions to try to find what other paths we didn't contemplate, might have been taken to lead to a different answer. And I'm just going to leave it by saying, we have some results that are challenging our conventional wisdom, and we're really, really excited about that. We're very committed to this and will be field testing this week, -- excuse me this year. As far as automation goes, our organization has really emphasized automation and it does so much for us. It gives us the ability to be real-time monitoring our facilities. It gives us the ability to use data analytics to predict, it gives us the ability to see very quickly when we have upset events and we're flaring, so we can very quickly address it. It gives us the ability to have safety shutdown systems. So, if we have any field event or a failure in our system, our system automatically shuts down and we avoid field interruptions. It's -- automation is the way of the future, in fact, many industries are well ahead of us and we're catching up, but we have a great team deploying this. We're really excited by the illumination it offers CR assets in real time and make really good operational decisions.

And you said you were not ready really to talk about the new completion design in detail, but just broadly speaking. Is it fair to say that you're looking at a less intense completion? And do you have any data to suggest, how well performance with the new completion stacks up against this your prior completion designs that recognized there's all kinds of different areas and different designs everywhere, but just broadly speaking, want to get your thoughts on that?

Well, I'll be broad and sufficiently vague that you will know I'm talking about. I'll say, no. We don't have specific field tests yet although that's just because we haven't gotten to it yet. We will be trying some things on existing wells. But yes broadly, what I would say, in an ideal world, what would you hope for, you'd hope for a completion design that adds more value and significantly less cost, and that's kind of where we're leaning and that's what we're guessing.

Fair enough. Thank you.

But I just thought. Yes, just let me say, we're always excited about technology. We like to talk about results, but I want to give you a flavor of what we're doing internally. This organization is active alive, and across our platform, we're getting better at the business and this is one area I am particularly excited about. But I get excited a lot of things that don't ultimately work and we really look forward to talking to you about results.

Next question comes from Jeff Campbell with Tuohy Brothers Investment. Jeff, please proceed.

Good morning. And thanks for all the wealth of guidance over the three year period. And I'll just say, firstly, I'm really excited by this faster than I expected turn of significant free cash out of the operation. It doesn't seem that long ago that you had a different attitude and it's really quite impressive. On Slide 13, I was just wondering, you had the four counties laid out for the Permian. I was just wondering because you identified what the primary zone or zones are that you're going to go after in each one of those areas. Just kind of wondering, if it Wolfcamp B versus A that kind of thing?

Well, first off, I want to share your excitement. This organization, it's a tribute to organization through our hallways in the field. We really have a focused organization and are focused around the right things. So, referring to Slide 13, I mean, certainly, our major topics or our major target is upper Wolfcamp. I mean, throughout the four counties, you're going to see upper Wolfcamp B a really important part of that program. Now in Lea County, there's a fair amount of Bone Spring and there's a little bit of Bone Spring everywhere, but I would generally if you -- I had to just really be broad brush. I'd say it's generally dominated by upper Wolfcamp with second being Born Spring.

And looking at Slide 24, it lays out a number of sales agreements that -- for oil and nat gas are described as through 2020, but I also see a lot of long-term agreements identify as well. So just kind of wondering, are these -- when I look at this slide, are these agreements essentially set the tone? Or is there some flexibility be it there beyond 2020?

This is Joe. These agreements are the ones that we currently have in place. The end game for us on the gas side, the residue takeaway side is, ensure flow -- ensure product flow. So that's the basis for our commitment to Whistler. We're also looking at other projects and ultimately where we're going with this is, is not only to ensure product takeaway out of the base, but it's to give us a little bit more diversification with different end and markets and get a little bit more Gulf Coast exposure. On the oil side, we feel very comfortable that there's enough capacity to get out of the basin. And on NGL side, all of our -- as we've talked about before, all our contracts are tied to processors that do have the pipe out of the basin. So, it's all about ensuring flow and trying to diversify the end market where we can take advantage of each geographic price metric.

Our next question comes from Michael Hall with Heikkinen Energy Advisors. Michael, please proceed.

I guess you've added a couple of quick underline and a lot been addressed. The increase in wells in progress over the course of the year, what's about processing and driving force behind that? I mean, how is that played out over the course of the next -- the rest of the three-year plan? Is that drawn down? Or is that just basically the kind of normal stable operating backlog?

Well, I'll kick it off and then turn it over to Joe. I would say that Cimarex has typically not had a big documents or it's real incomplete as well. And, yes, I could talk for next 30 minutes and why that's the case. And we still would love to complete it well and bring it on immediately, but we find that limits are flexibility in the field. And then having a certain number of drilled and uncompleted wells in our inventory is the really nice thing for our field people and our flexibility in operations. If we have some interruption and interruption can mean a lot of things. There might be an offset operator that's drilling a well and we decide, oh my goodness, we don't want to be fracking during that operation. There might be a restriction in our ability to get water. There might be a delay in a land issue. And so, when you're cutting it with no slack, it can really challenge our field people. They behaved valiantly. But having a few and not a lot, but having some inventory of wells that are waiting to be completed, is really pretty good project management.

Yes, I'll just follow up with that. The benefit is truly flexibility. Our completions guys love the idea. I mentioned the time savings that we're seeing to pump our wells where our frac crews are catching up with our rigs. And if we ever get to the point where they're waiting on the rigs then we got a little bit of an issue. So having those wells available for us at the end of the year is truly beneficial there both the operations logistics aspect of the field. What I like about it too is, they can help us get away from some of these start stop-type production cadences levels that we see it, as in this year where we have a lot larger production growth in the second half of the year versus the first half. We can smooth that out a little bit, if we have some ducks in our head pocket.

That's helpful and it makes sense. And I guess in the context of that as it played out through the course of '19, we did see quite a few additional wells in the fourth quarter which was adjusted there earlier, but I'm just want to make sure and be clear. Any expected capital associated with those wells that we should be mindful of as you think about the first quarter of this year? Or was that really all accounted for?

Yes, Michael, that was that was a kind of for '19. And those well coming off production a matter of weeks early, is more of the production counting of those wells. The capital had been scheduled for those wells in that period. It's always fair timing when we complete activity completion or ended. In our first pod date, we have some rules that we use to target for when the first pod will occur post completion. The capital is scheduled. Timing of the production did come a bit quickly, but this capital already scheduled in '19. And just a further point on the wells waiting on completions or wells in progress, at the end of '19 with those 12 wells, it would have been about 49 wells in progress. But technically, we were kind of remodeling those, would be coming on in the first quarter. We did come on a few quick early that reduced our in-progress at the end of '19. We step forward in the '20, the 54 we described or so, those are pretty stable out in a '21 and '22 year earlier part of your question. And it just comes back as Tom mentioned, we try to have a pretty stable plan and have a ratable frac connectivity relativity rig. So without rig level about 10 rigs in the Permian, 2 frac crews going to 3, that kind of in progress is just kind of a natural outcome of our cadence.

Okay, that's super helpful. And I guess last to my end would be the Slide 14 is super helpful as it relates to additional granularity on the projects this year in the Permian. It seems like there's also some not included on that. In terms of the activity not included on that slide on a net basis, is that mostly just non-op or how should we think about that? And in earnings particularly our county area where that's concentrated, just trying to think of how it dispersed throughout the Permian footprint?

Well, the slide is going to show development. So, there are multi-wells projects that the first response to it who say because the number of wells doesn't total.

Yes, when you look at Bone Spring end of the plan, these are the larger well projects. So, these are touching, looking at the slides you got one 2 wells project that carried back, but there is a number of other smaller projects that we have throughout the year that might be 2 to 3 wells type projects that are on that slide.

I don't think the Bone Spring is accounted for either, right so, yes.

Okay, that's just helpful. That's not necessarily non-op or anything along those lines. It's just smaller, smaller projects that didn't make the "development cut".

That means when I looked at it and prep for the call, there's like 22 when I'll call projects and there's only 15 on this slide.

It's certainly a highlight real, we didn't really.

That's what I thinking. Okay. Thank you. I appreciate it.

Our next question comes from Neal Dingmann of SunTrust. Neal, please proceed.

My first question centers on the capital discipline. I know you talked a bit about this, but I want to make sure I understand. You all were one of the few to slightly sequentially increase the D&C spending this year. Well, with that announcing the higher-than-peer average sequential production growth guidance. So again, while I believe you made the appropriate call, I am just curious as to how you weigh sort of when looking at growth versus just a pure capital discipline?

Well, we look at a lot of ways. I mean, first and foremost, we ask ourselves, is this capital well deployed? Now, we absolutely confident that we're creating value with that capital. We're not driven by growth targets for doing my value. But we also looked at the components of our revenues, the components of our cash flow, and we have some great results. We're really firing all cylinders and we saw '20 is an opportunity to step it up on our oil growth. And so, we're really looking to maximize your profitability, maximize our out year your cash flow, and we have the wherewithal to do it. We didn't really spend too much angst looking at our capital level in '19 as a marker, and we didn't have too much angst on whether we were slightly above or slightly below. We think our capital for 2020 is the right number and we're off to the races to execute.

And then, my second question centers on Slide 7, where you lay out your wells by quarter. I'm just wondering you talked a bit about this already too. Could you just give details, if you could in regards to just what working interest are on some of these upcoming wells for the first half of the year? I know there was some kind of chatter on the prior wells about that. I just want to make sure, I'm sort of sure on kind of more cadence what type of wells and run that the working interest of those coming on here shortly?

Well, in that wells, Neal, that are coming on, I mean, we could go through the individual projects if you want. Maybe we could do that off-line, I'd be happy to give them to you, but we just don't have it at the fingertips.

But the critical point is, those are nat wells. So explicitly, our working interest is 100% on every one of those. Yes, our working interest still is very high.

When you look closer at it at a high level, first half of the year, we've got 40 gross wells, 29.4 nat, second half 58 gross, 39.2.

Our next question comes from Jeanine Wai of Barclays. Jeanine, please proceed.

My first question is on your three year free cash flow outlook and just following up on some of Betty's questions. You anticipate free cash flow in 2020 and Slide 11 suggests that it compounds from there. So can you discuss the assumptions that are embedded in your bottoms up through your outlook? You're very encouraged on the upside to the business, it sounds like things are going really well. So, any color on trends and well productivity or efficiencies that you're envisioning in that year 2 or 3 would be really helpful?

Yes, Jeanine, as far as the productivity improvements, we are not taking in additional productivity improvements that we already have captured and the cost structure is consistent. What we're forecasting for this year was not making adjustments to those components of our three year plan. As I touched on, there is some benefit in the outer period with improving gas price differentials. We do definitely see those helping us in those future '21 and '22 periods as you've got some additional pipeline takeaway and improving out in the 4 differentials.

Yes, Jeanine, I just want to reinforce on just Mark just said. When we look at plans, we don't bake-in hope. So, they're anchored on actual costs, actual well results, actual cycle time, and anything we can do, that's to the upside and operational improvement of well, productivity, that's all to the upside.

My second question is on inventory additions. And it's just, how are you thinking about the cost that's adding Tier 1 inventory? I know that you said that you don't stay awake at night, thinking about lack of inventory. But specifically, how do you think about the cost of moving current inventory into the Tier 1 bucket true testing and appraisal, which can be costly depending on how it goes versus adding locations? The exploration that you mentioned during your prepared remarks versus I guess lastly, the option is inorganic addition through M&A, given what you're seeing in the market?

Well, I think a lot about that and my experience and we just yesterday reviewed our annual look back. And our history of investing, what's worked? What hasn't? What do we want to emphasize? What do we want to correct? So a lot of this is very fresh in my mind. There's no governor in our business that controls our profitability stronger than your entry costs. If we -- you've asked about acquisitions, our acquisitions are great from a top-line, but you're typically buying your discount rate down to a point where, however wonderful the asset, it's a low return project as you had to prepay for your returns in order to acquire that asset. The thing about exploration is you have a proprietary advantage. In the acquisition market, there's very few proprietary advantages. Everybody's got lots of money and everybody's going to be bidding. So being the high bidder in auction isn't our value creation strategy. We want to find proprietary ideas and capture that value for our shareholders and that's a low entry talk. So the way I think about inventory is, we're always trying to find more profitable things. Of course, yes, the easiest is a new landing zone in our existing footprint. There's no incremental land cost. And it just -- it's often a landing zone that can be co-developed with your existing activity. So, that's -- if you ask me what do I hope for? Its people walk into my office and tell me, we have twice the number of targets in the given asset we already control. But we do also explore off our footprint, we look very carefully at our entry costs, both on a per acre basis, but also what percent of our total capital. We really want to have that be a very small and manageable part of our total capital. So, we have our own philosophy there. It's all about value creation and it's all about entry costs.

Our last question comes from Joe Allman of Baird. Joe, please proceed.

Tom, is there a strategic shift happening at Cimarex? Or is there a tactical shift happening at Cimarex? And what's driving that? And the reason why I asked is because I'm hearing different language and here I am hearing about the 5 pillars. So that's making me ask that question.

The first time we talked publicly about our pillars. I can say everybody in organizations tired of hearing about it because I talked about it constantly and introduce that in the middle of last year. Joe, these are tough times. I mean, although I find myself incredibly optimistic about this company. We have really difficult headwinds and in that you know it better than I do. And so, these pillars are a chance to focus organization on things we can control. You heard me say in past down cycles that we're not shipwreck victims. Cimarex is not an organization that's dead in the water, waiting for the rescue boat. We are going to control our own destiny. We're going to use this climate to reform ourselves and get fundamentally better in our business. That's what these quarterly results are about. That's what our three year outlook is about. And it's absolutely what our pillars are about. Whether it's planning, whether it's cost control, whether it's finding your assets, whether it's using information technology in a way to make ourselves more effective or whether it's responding to this conversation around environmental impact. Cimarex is the Company on the move, we're getting better. And, we're a much better company than we were a year ago. I'm excited to be able to say that publicly and will be a much better company a year from now.

That's very helpful comment. And my follow-up and last question is, in terms of your natural gas and NGLs and oil, I know that insuring flow is one of the key drivers that you try to guarantee. But what you're doing that from maximize the value? Are there some key things to look for in terms of contracts or agreements so we look forward to have a nice year or two? That will help you beyond just the next three years even longer term.

Well, Joe, if you think about the maturity of the Permian, years back, there was hardly any processing infrastructure and not a heck of a lot of pipes that came out of there. So those contracts that we entered into back then were probably a little bit more owners and you get today. So, we're in the process now of either renegotiating those contracts and/or when we renew them, there's a heck of a lot better contract term associated with them. So, it's kind of you build it and they will come kind of thing happening out there and it's creating competition and we're seeing it. We see it on the processing side. We see it on the NGL side. And we've seen it on the oil and the rescue side. We've improved our oil net back dramatically. Right now, we're about 2 hours and 70 some odd cents off of the Midland-Cush differential. That number wasn't that number four or five years ago. So there, I think the market by itself is creating more opportunity for us to get a better net back.

But Joe, let me just add something to that. Our focus on planning really ties into your question, because, we're in a business where we're highly client business. And so, commitments the long haul pipeline, if your assets are in high decline, that's really a commitment to future capital, because you need to drill new wells to achieve and meet those volume commitments. And so we've always been reluctant to do that because we're in a cyclic business where our cash flow can rise and fall unpredictably. But with our focus on planning, we're getting much, much better at understanding our level of activity around long-term price stand. And we're getting more confident to make commitments that give our marketing group the ability to get those net back Joe was talking about. So, I think you're going to see a different posture out of us going forward, still conservative, still really embracing flexibility, but willing to backstop our increased planning capability with some commitment.

This concludes our question-and-answer session. I'd now like to turn the conference back over to Cimarex for any closing remarks.

Yes, I just want to thank everybody for your energy on the call. We've had some great questions. I really appreciate flushing out there. You focused on the right things. We're very excited about the data we've announced this morning. We're very excited about the plans and we look forward to delivering future results. And thank you again.

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