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Cimarex Energy Co (XEC)
Q4Â 2019 Earnings Call
Feb 20, 2020, 11:00 a.m. ET
Contents:
- Prepared Remarks
- Questions and Answers
- Call Participants
Prepared Remarks:
Operator
Good morning, and welcome to the Cimarex Energy Company XEC 4Q 2019 Earnings Release Conference call. [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.
Karen Acierno -- Director of Investor Relations
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 a reminder, our discussion will contain forward-looking statements. A number of actions could cause actual results to differ materially from what we discussed. You should read our disclosures on forward-looking statements in our news release and in our latest 10-K for the year ended December 31, 2018, for risk factors associated with our business. We plan to file our 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 Operations Resources. [Operator Instructions]
With that, I'll turn the call over to Tom.
Thomas E. Jorden -- President and Chief Executive Officer
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 COO, 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 billion to $1.47 billion, 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 in our capital planning over the next three years. With activities similar to that in 2019, we expect to generate similar results of approximately 10% oil growth per year and grow our free cash flow year-over-year. We are 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 organization. Our goals are simple: to improve our performance, create enduring value and better position Cimarex for the future.
These pillars are: one, better short and long-range planning; two, better cost control; three, effective exploration and smart risk-taking; four, digital innovation; and five, a reinvigoration of our commitment to be a leader in environmental stewardship. Our organization has made tremendous progress on all these fronts. I'd like to walk you through these pillars and the work that's under way. First, let's discuss planning. Our new slide deck, which is posted on our website, shows an updated three year plan. The plan is based on real locations, real working interest, actual costs and actual well performance. We have the locations, the development schedule and the wherewithal to execute this plan and deliver the indicated results. This is a result of our focus on capital discipline and effective project management.
This outlook results in significant free cash generation. I know that many of you are wondering what we will do with this cash. First off, I need to say that we would like to generate the cash before we get too drawn into speculation on what we'll do with it. Future commodity pricing is the single biggest variable that drives our multiyear outlook and the amount of free cash that we will generate. That said, we manage the company for our owners and make long-term decisions with their interest in mind. We intend to increase our dividend over time. Balance sheet health is a top priority. And to that end, we keep a close eye on the financial markets. We do not have any near-term debt maturities. Our next maturity is $750 million due in 2024. When we generate free cash as planned, debt retirement will be a high priority. Share buybacks will be an additional option on the table.
We analyze this on an ongoing basis and see this as a viable option for our free cash. Now on to costs. Costs have decreased significantly, driven by a combination of lower service and material costs and value engineering. Our operational team has done an outstanding job of optimizing our field operations. Our reservoir and completion engineers continue to optimize our completions, spending less and getting more. Our facilities group has continued to develop fit-for-purpose production facilities, implement state-of-the-art automation and safety systems and deliver them at lower costs. Total well cost, measured by dollars per lateral length, decreased 24% from 2018 to 2019. We expect to drive those costs down further in 2020. We had a great fourth quarter with total well costs below $1,000 per foot.
This was driven by a combination of value engineering of our completions and outstanding field execution and reduced cycle time. Exploration. Exploration on and off our existing footprint is an ongoing priority for us. One of the most effective ways to generate great returns is to have a low entry cost. Exploration is ultimately about risk and whether it means testing a new concept, testing a new landing zone or experimenting with new technology is a critical part of value creation. We successfully tested some new landing zones in 2019 that will offer significant potential for us in the years ahead. We look forward to further delineation and hope to be discussing them later this year. We are testing some new ideas and modestly leasing on a couple of emerging ideas. We also hope to discuss them in the future. They are not without risk, but smart risk-taking is a key to low entry costs. Digital innovation.
We are focusing on digital innovation and building tools to provide better real-time data to our decision makers. We are redesigning our databases to allow for more effective data management and data delivery. We have a major effort under way to increase fieldwide automation, which is a critical element of smart production management, effective safety systems and real-time monitoring of our environmental footprint. We have major projects under way on machine learning and are seeing results that are causing us to revisit some long-held assumptions. We have field tests of these emerging concepts on our 2020 schedule, it's about getting better. Finally, I'd like to make a few comments on our environmental efforts. We, like so many of you, have followed the climate discussion with great interest and with amazement in how fast the conversation is evolving. Although the rhetoric can be a bit extreme, our industry must demonstrate real commitment to a cleaner future if we're to be taken seriously in energy policy discussions. The world needs the products that our industry produces.
This is obvious to all of us on this call. Demand for our products is on the increase and is expected to continue to increase for decades to come. Underinvestment in our sector will lead to long-term bad consequences for our country and for our world, but we should never underestimate our ability to make terrible public policy. In order for our industry to participate in setting energy policy, we need to earn a seat at the table through our actions on reducing emissions. Our organization is rising to the challenge to reduce our emissions, reduce flaring, increase water recycling, increase electrification and further improve our safety record. Our board has approved 2020 corporate goals that set numerical targets to reduce our emissions and the incidence of flaring. Our performance on these goals will directly impact executive team compensation. We willingly embrace this challenge. These five pillars: planning, costs, exploration, digital innovation and emissions reduction, are guiding our organization to improve our business and deliver consistent top-tier results.
Now I'll turn the call over to Joe Albi to discuss our operations in more detail.
Joseph R. Albi -- Executive Vice President and Chief Operating Officer
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 costs. 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 2019 and Q4 2018 postings, respectively. The Permian drove the increase, with our Q4 Permian oil volume of 78,400 barrels a day, up 5% over Q3 2019 and 27% over a year ago in Q4 2018. 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 in mid- to late December, which added approximately 1,200 barrels a day for the quarter. Our Permian activity also boosted our Q4 net equivalent production, which came in at 293,000 barrels equivalent per day, beating the top end of our guidance and setting a new record for the company.
As far as capital is concerned for 2019, with increased operational efficiencies and lower service costs, our 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 is all predicated on the $50 per barrel WTI and $2.25 Henry Hub pricing that we've just mentioned. Our 2020 total capital guidance is $1.25 billion to $1.35 billion, which includes $950 million to $1.05 billion for drilling and completion activity, $100 million for midstream and saltwater disposal infrastructure and $200 million for other capital. At the midpoint, we expect our total 2020 capital to be down 1% from 2019. Approximately 90% of our projected drilling and completion capital is targeting the Permian, a little bit more than this past year, and incorporates the operating efficiency and marketing and market cost savings we've discussed last call, particularly on the completion side.
With an emphasis on longer lateral, multi-well development projects, we're projecting our Permian all-in 2020 total well cost dollar-per-foot metric to come in between $1,025 and $1,125 per foot. That's down approximately 4% and 27% at the midpoint from our 2019 and 2018 averages, respectively. I want to mention again that this estimate includes all necessary costs to bring a well online. It's drilling, completion, stimulation, facility and flow back costs. Over the year, we expect to bring 90 net wells online, 77 in the Permian and 13 in the Mid-Continent. Although we're forecasting a fairly even capital spread during the year, our projected completion activity is skewed slightly to the second half of the year, with 60% of our completions forecasted to occur in Q3 and Q4.
With our activity, we anticipate increasing our inventory of net wells in progress by 16 to a total of 54 wells in progress at the end of 2020. With our modeled completion cadence, we're projecting our 2020 oil growth to really begin in Q3, with the resulting 2020 full year net oil guidance range of 91,000 to 97,000 barrels a day, that's up 6% to 13% over our 2019 average of 86,000 barrels a day. With limited capital directed to the Mid-Continent and the strong likelihood of ethane rejection during the year, we're projecting that our 2020 net equivalent volumes will fall in the range of 270,000 to 286,000 BOEs per day, which puts a midpoint, basically, in essence, flat to 2019. Bottom line, with projected flat equivalent production as compared to 2019, we're projecting our oil volumes to increase 6% to 13%. For Q1, we're projecting our net oil volume to be in the range of 87,500 to 91,500 barrels per day.
And our net equivalent volume to average 272,000 to 288,000 barrel equivalents per day, both down slightly from Q4 2019 but up significantly from a year ago, with our projected Q1 oil and equivalent volumes up 10% to 15% and 5% to 11% versus Q1 2019, respectively. Jumping to opex. We had a great quarter again for our lifting cost in Q4 with a posting of $3.07 per BOE. We were down 10% from Q3. And it put our year-to-date lifting cost of $3.34 per BOE just slightly above the low end of the guidance range we issued last call, $3.30 to $3.55, and it represented a drop of 9% from our 2018 average of $3.66 per BOE. Looking forward into 2020, with our 2020 Permian focus and our forecasted range for 2020 equivalent production being relatively flat, we're projecting our full year 2020 lifting cost to be in the range of $3.10 to $3.60 per BOE. And lastly, some comments on drilling and completion costs. With the exception of a slight drop in the cost per tubulars, the majority of our drilling and completion cost components have held relatively flat over the last few months.
That said, our ops team has done a great job capitalizing on the Q4 service cost reductions, operating efficiencies and program design cost reductions that we achieved in late Q4 and early Q1, again, particularly on the completion side. We're now executing on those total cost estimates, the same ones that we provided last call with our generic Reeves County 2-mile Wolfcamp A AFE running $9.3 million to $11.8 million, depending on facility design and frac logistics. And our shallower Wolfcamp A well in Culberson County, running about $500,000 less with an AFE of $8.8 million to $11.1 million. As we've stated before, the efficiency gains that we derive through our multi-well development drilling projects really put our average development project per well cost at the low end of the guidance ranges I just gave you. Both of those AFEs that I mentioned, reflect costs, which are down approximately $700,000 per well from Q4 2019 and $1.1 million from early 2019 or 2019 and down $1.6 million from where we were in Q4 2018. And in the Mid-Continent, our current 2-mile Meramec AFE is running $8.5 million to $10 million.
That's down $1 million from late Q4 of last year, $1.5 million from earlier in 2019, and $3 million from the costs that we quoted in 2018. We've made tremendous progress on our well costs and our ops team is fully committed to maintain the progress that we've made to reduce these costs. In addition to working with our service providers to capture further efficiency gains, we stay focused on the operations, which ultimately will lower our total cost per lateral foot. That's multi-well pad drilling and batteries, it's water recycling, it's zipper fracking and the optimal use of our midstream and saltwater disposal infrastructure. Our goal is to push our 2020 Permian program all-in well cost to the low end of the $1,025 to $1,125 per foot range that I just mentioned. In closing, we had another great quarter in Q4. With guidance speeds, we set new company records for net oil and equivalent production. We closed the 2019 books with 27% and 25% year-over-year gain in oil and equivalent production. We're capitalizing on the low development and operating cost structures that we worked so hard to achieve, and we're well positioned to execute on the capital activity and production plan that we've laid out for us here in 2020.
With that, I'll turn the call over to questions.
Questions and Answers:
Operator
[Operator Instructions] Our first question comes from Arun Jayaram of JPMorgan. Our next question comes from Gabe Daoud of Cowen. Please proceed.
Gabriel J. Daoud -- Cowen and Company, LLC -- Analyst
Thanks. Good morning, Was hoping we could start maybe on the free cash flow guide for 2020 in the outlook. I guess if 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 dividend? When you think about potentially deferring that Mid-Con rig or a third crew in the Permian, just any thoughts around flexibility would be helpful.
Mark Burford -- Senior Vice President and Chief Financial Officer
Yes, Gabe, in the free cash flow we're projected for 2020 in the $50 price deck, we're only assuming out realization, which doesn't be a negative price for the second quarter of this year through our realization in Permian. If prices were to be 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. But I think that Permian gas price alone is probably not a factor which would make major changes.
Thomas E. Jorden -- President and Chief Executive Officer
Yes, Gabe, this is Tom. Yes, we do have tremendous flexibility in 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.
Gabriel J. Daoud -- Cowen and Company, LLC -- Analyst
Understood. 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 2020. Is there anything different going on there that you guys are doing to perhaps increase returns versus the legacy program?
Thomas E. Jorden -- President and Chief Executive Officer
Well, the 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 fit nicely in our capital plan. And it does take some of the operational pressure off our Permian group as well. So it was a pretty easy decision based on return on capital and capital allocation.
Mark Burford -- Senior Vice President and Chief Financial Officer
I would mention also that the reductions that we've seen in our well cost really help to add a little momentum to that project.
Gabriel J. Daoud -- Cowen and Company, LLC -- Analyst
Understood. That makes sense. And just a quick clarification. You 2020 permian AFE per foot guide, does that assume the legacy completion or the new value engineered completion that you tested in 4Q?
Thomas E. Jorden -- President and Chief Executive Officer
Well, it actually has a fairly conservative completion design, but that's 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 you 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 of our expenditure.
Operator
Next question comes from Arun Jayaram of JPMorgan. Please proceed.
Arun Jayaram -- JP Morgan Chase & Co -- Analyst
Tom, I was wondering if you could give us more insights into the three year plan. In particular, 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? Yes.
Thomas E. Jorden -- President and Chief Executive Officer
Well, Arun, I think I 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 to 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 plan that we announced this morning is real. It sticks on a map. There's a commitment for our organization to execute it. But I also want to reiterate, the single 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.
Arun Jayaram -- JP Morgan Chase & Co -- Analyst
Got it. And when you make 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.
Thomas E. Jorden -- President and Chief Executive Officer
So that was in my word, but Mark, do you want to comment on that?
Mark Burford -- Senior Vice President and Chief Financial Officer
Arun, we're talking in terms of ratable activity, certainly in our rig and completion cadence in the rig levels in our capital deployment. And certainly, also around our frac crew cadence. We're not offloading our frac crew cadence and are still in development. All of that is being in the plants built out on a ratable, consistent basis to be the most operationally efficient. But there is still always some element of our production profile. Even as Joe mentioned this year with some of the production profile still not as ratable. That's also a reflection of the timing of the completions of the different infill developments. And even with a consistent operational cadence, depending on the timing of the different infill developments, you will still see some variability in the production cadence.
Karen Acierno -- Director of Investor Relations
I would also add that we talked about activity versus capital. When we did this put this plan out a year ago, we locked down capital will be $1.5 billion every year. This year, our capital is really more tied around the 50 and two 25 that we're using to budget from. So and then we have a goal of basically growing kind of 10% as a minimum. So there you go. So we're not tied to a specific level of capital every year. In fact, in 2020, we're spending a little bit less than 2019.
Arun Jayaram -- JP Morgan Chase & Co -- Analyst
So great, great. And just my follow-up, Tom, I was wondering if you could provide us maybe a little bit more color on these less intense frac designs that you've been testing, particularly in the fourth quarter, is this could you give us a sense of fewer stages? Or what exactly have you been testing? And perhaps what type of cost savings on a dollar per foot basis, are you yielding on these these new frac designs?
Thomas E. Jorden -- President and Chief Executive Officer
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 per cluster, there's composition of type of sand and any other additives, your diverters, surfactants and many other variables that go into that. Probably the 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 stimulations quarter-over-quarter. We're not committing to that going forward. Joe, do you want to comment on the cost reduction?
Joseph R. Albi -- Executive Vice President and Chief Operating Officer
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 efficiency is pumping the job. The longer stage length that Tom mentioned, says, "Hey, I don't need to pump as many stages for that well." But 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 from about 9.9 to 6.5 on the average. And that's a 30-some-odd, what, 30-ish percent 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 element to 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 changes 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. But all in this thing, in that dollar per foot number, there are so many elements to this. And what I love about it, it's going to focus our intense focus our business units to look where they can drill longer laterals, to look where they can drill 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 dollar per foot metrics that we love challenging the organization with to optimize the overall program.
Thomas E. Jorden -- President and Chief Executive Officer
Let me just make one last comment. 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 a critical element is the impact that 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 value. And costs, commodity pricing, well productivity, those are outputs from a focus on value, and that's the way we view this problem.
Arun Jayaram -- JP Morgan Chase & Co -- Analyst
Great, thanks a lot.
Operator
Our next question comes from Bryan [Phonetic] of Credit Suisse. Please proceed.
Bryan -- Credit Suisse -- Analyst
I have a question on New Mexico. Like from what I can tell, Cimarex New Mexico performance has been serve some of 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, specifically 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?
Thomas E. Jorden -- President and Chief Executive Officer
Yes, Betty. Certainly, we have not optimized the point where we're satisfied. Now 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 and throughout our portfolio, and we are 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 New Mexico. They're not all 2-mile long. And so the way we view cost is we ask our organization 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 one or 1.5-mile laterals because the cost target comes first. And really, that whole emphasis on what I just described is driven by New Mexico because we love New Mexico, and we would never want an arbitrary cost target to discourage some of the incredibly profitable activity in New Mexico. We do think we can increase activity in New Mexico, to 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 Lazard. 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.
Bryan -- Credit Suisse -- Analyst
Great. Helpful. And 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 the press release, but you sort of talked about, based on this ratable level of activity at the minimum, we could see similar production growth with increasing free cash flow. I guess, just on that minimal standpoint, are there what gives the confidence level that things could be in line to better than what's showing the 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?
Thomas E. Jorden -- President and Chief Executive Officer
Yes. I'll kick it off, and I'll turn it over to Mark. I think we have tremendous upside within that capital plan. We have cost upside with execution upside with well performance 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 of the same capital investment. But Mark, I'm going to let you handle the remainder of that.
Mark Burford -- Senior Vice President and Chief Financial Officer
Yes. Betty, just to clarify. So you're concerned about the ratable activity leaves that 10% growth, is that based to your question, is that what you're trying to understand?
Bryan -- Credit Suisse -- Analyst
Yes. I'm trying to understand sort of when that free cash flow and that growth shows up over that three year time frame. We know 2020, but what 2021 and 2022 generate both of them generate a similar level of growth and free cash flow in each of those years?
Mark Burford -- Senior Vice President and Chief Financial Officer
Yes, Betty. So yes. So the three years, actually, for 2021 and '22, personally, we don't have visibility individually for. Our growth in oil is as strong or stronger than what I would say that we're experiencing in 2019. And on equivalents, we actually see the equivalent portion of our volumes growing more consistently in the 2021 and '22 time periods as well. Our capital is fairly consistent around that $1.3 billion. And there's a little variability between the years. But that's just, again, timing of our projects, but we have existing cadence and just the capital hitting to any on the rig schedule. We have built up rig schedules and completion schedules for all these plans and just some variability in those schedules. We see a growing cash flow in 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 2021 and '22, with some of the improving basis differentials, we do get that benefit or building that into our forecast.
Bryan -- Credit Suisse -- Analyst
Right, thank you for that.
Mark Burford -- Senior Vice President and Chief Financial Officer
Thank you.
Operator
Our next question comes from Doug Leggate of Bank of America. Please proceed.
Douglas George Blyth Leggate -- BofA Merrill Lynch, Research Division -- Analyst
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 that correctly. Is that right? That wasn't actually my main question, but I just wanted to check out the point you were making.
Mark Burford -- Senior Vice President and Chief Financial Officer
Yes, Doug, that's correct. So when we look at the flat NYMEX price of two 25, we still use the four differentials embedding against that NYMEX price. And we use the ratio because, like right now, the NYMEX price is slightly lower than two 25 million in 2019, but it's slightly better than that in 2020, but we use the ratio of the differentials to that NYMEX price to come up with the basis price in those flat price cases.
Thomas E. Jorden -- President and Chief Executive Officer
Doug, this is that's true of all of our capital planning. We really want to level our capital plans to the actual well received price. So not that we're pressured in getting it right, looking ahead, but we're certainly trying to have the most realistic look.
Douglas George Blyth Leggate -- BofA Merrill Lynch, Research Division -- Analyst
So 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 right slide 11, it's implying about a one I guess, $1.1 billion of free cash after dividends in 2021 and 2022. Is that 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, why wouldn't you buy back your stock in that scenario?
Thomas E. Jorden -- President and Chief Executive Officer
Well, I have no good answer for that. And as I said in my remarks, a share buyback is very much something that we discussed. 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 listed three things: increasing dividend, debt retirement and share buyback. And all of those are things that we are deeply interested in.
Douglas George Blyth Leggate -- BofA Merrill Lynch, Research Division -- Analyst
Okay. I appreciate that. 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, I want to touch on the NGL assumption you guys are using and what your economic inventory that 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 assumptions you're making around NGLS, given there's a lot of new infrastructure and so on. But that's obviously a pretty big factor in determining the economic inventory, and I'll leave it there.
Thomas E. Jorden -- President and Chief Executive Officer
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, pressure, but we that's why we manage with a healthy balance sheet. That's why we do a lot of downside sensitivity. Every investment we make, we look at it at many different price files, and we always want to make sure that it'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 said on this call today, economic inventory is almost off my list. We have seen our inventory increase, looking forward to talking about some of these new landing zones we've 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 spend a lot of time worrying.
Douglas George Blyth Leggate -- BofA Merrill Lynch, Research Division -- Analyst
Appreciate the answer thanks so much.
Operator
Our next question comes from Mike Scialla of Stifel. Please proceed.
Michael Stephen Scialla -- Stifel, Nicolaus & Company -- Analyst
Tom, I want to see if you could give any more detail on the things you're doing on the automation and machine learning front. You'd said it caused you to revisit some long-held assumptions. Any color you can add to that comment?
Thomas E. Jorden -- President and Chief Executive Officer
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 on how to complete our wells, each individual decision has been made with the economic plans 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 we'll be field testing this week. Not 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 to see our assets in real-time and make really good operational decision.
Michael Stephen Scialla -- Stifel, Nicolaus & Company -- Analyst
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 your the prior completion designs. Because I recognize there's all kinds of different areas and different designs everywhere, but just broadly speaking, I want to get your thoughts on that.
Thomas E. Jorden -- President and Chief Executive Officer
Well, I'll be broad and sufficiently vague that you all know I'm talking about. Okay. I mean, I also know, we don't have specific field test yet, although that's just because we haven't gotten to yet. We will be trying some things on existing wells. But 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 at significantly less cost. And that's kind of where we're leaning and that's what we're testing. 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'm particularly excited about. But I get excited about a lot of things that don't ultimately work. And we really look forward to talking to you about results.
Operator
Our next question comes from Jeff Campbell with Tuohy Brothers Investment. Please proceed.
Jeffrey Leon Campbell -- Tuohy Brothers Investment Research -- Analyst
Good morning Thanks for all the wealth of guidance over the three year period. And I'll just say, personally, 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 were you had a different attitude and it's really quite impressive. On slide 13, I was just wondering, you have the four counties laid out for the Permian. I was just wondering, could you identify what the primary zone or zones are that you're going to go after in each one of those areas? I'm just kind of wondering if the Wolfcamp B versus A, that kind of thing?
Thomas E. Jorden -- President and Chief Executive Officer
Well, first off, I want share your excitement. This organization, it's not it's a tribute to our organization throughout our hallways, in the field. We really have a focused organization and they're focused around the right thing. But referring to slide 13. I mean, certainly, our major topic or our major target is Upper Wolfcamp. I mean, throughout the four counties, you're going to see Upper Wolfcamp be 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 I had to just really be broad brush, I'd say it's generally dominated by Upper Wolfcamp with the second being Bone spring.
Jeffrey Leon Campbell -- Tuohy Brothers Investment Research -- Analyst
Okay, great. I appreciate that. And looking at slide 24, it lays out a number of sales agreements that for oil and nat gas that drive us through 2020. But I also see a lot of long-term agreements identified as well. So just kind of wondering, are these when I look at this slide, are these agreements essentially set in stone? Or is there some flexibility there beyond 2020?
Joseph R. Albi -- Executive Vice President and Chief Operating Officer
Yes, this is Joe. These agreements are the ones that we currently have in place. The end game for us on the gas side, residue takeaway aside 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 not only to ensure product takeaway out of the basin, but it's to give us a little bit more diversification with different end 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 the NGL side, all of our as we've talked about before, all of 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.
Jeffrey Leon Campbell -- Tuohy Brothers Investment Research -- Analyst
Okay, great. Thank you.
Operator
Our next question comes from Michael Hall, Heikinen Energy Advisors. Please proceed.
Michael Anthony Hall -- Heikkinen Energy Advisors, LLC -- Analyst
Thanks. Appreciate it. Thanks for the time. I guess, just a couple of quick ones on my end, a lot have been addressed. The increase in wells in progress over the course of the year, what's the thought process and driving force behind that? And then how has 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 a kind of normal, stable operating backlog?
Thomas E. Jorden -- President and Chief Executive Officer
Well, I'll kick it off and then turn it over to Joe. I will say that Cimarex has typically not had a big DUC inventory, drilled uncompleted wells, and I could talk for the next 30 minutes on why that's the case. And we still would love to complete a well and bring it on immediately. But we find that, that limits our flexibility in the field and then having a certain number of drilled and uncompleted wells in our inventory is a 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 going 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 behave 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.
Joseph R. Albi -- Executive Vice President and Chief Operating Officer
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 and 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, the operations, logistics aspect of the field. What I like about it, too, is it can help us get away from some of these start-stop-type production cadence levels that we see 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 had some DUCs in our hip pocket.
Michael Anthony Hall -- Heikkinen Energy Advisors, LLC -- Analyst
That's helpful, makes sense. And I guess, in the context of that, as it played out through the course of 2019, we did see quite a few additional wells in the fourth quarter, which was addressed a bit earlier, but I just want to make sure and be clear. Any expected capital associated with those wells that we should be mindful of as we think about the first quarter of this year? Or was that really all accounted for?
Mark Burford -- Senior Vice President and Chief Financial Officer
Yes, Michael. We that was accounted for and those wells coming on production in a matter of weeks early. There's more of the production accounting of those wells, the capital had been scheduled for those wells in that period. It's always the retiming when we complete activity completion ended in our first product, we have some rules that we use to try to determine when the first pod will occur post completion. The capital is scheduled, timing of the production did come in a bit quicker because this capital is already scheduled in 2019. And just a further point on the wells waiting on completion or wells in progress. At the end of 2019, with those 12 wells, we'd have been about 49 wells in progress, with pedicle, we would have kind of remodeling those to be coming on in the first quarter. It did come on a few weeks early. It reduced our in-progress at the end of 2019. As we step forward into 2020, the 54 we described or so, those are pretty stable out in the 2021 and '22, your 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 CRE activity relative to rigs. So with our rig level around 10 rigs in the Permian, two frac crews going to 3, that kind of in progress is just kind of a natural outcome of our cadence.
Michael Anthony Hall -- Heikkinen Energy Advisors, LLC -- Analyst
Okay. That super helpful. And then I guess last on my end would be the slide 14 was super helpful as it relates to additional granularity on the projects this year in the Permian. Seems like there is 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 I mean, how should we think about that? And are there any particular counties or areas where that's concentrated. Just trying to think about how it's dispersed throughout the Permian footprint.
Karen Acierno -- Director of Investor Relations
Well, the slide is meant to show development. So there are multiple well projects. That's the first response to it usually because the number of wells doesn't total.
Thomas E. Jorden -- President and Chief Executive Officer
Yes. When you look at spring, or in the end of the plan. These are the larger well projects. So these are touching looking at the slide, you got 1, two well project that carry back. But there's a number of other smaller projects that we have throughout the year, there might be 2- to 3-well type projects that aren't on that slide.
Karen Acierno -- Director of Investor Relations
I don't think the Bone Spring is accounted for either, right?
Michael Anthony Hall -- Heikkinen Energy Advisors, LLC -- Analyst
Okay. So OK, that's helpful. So it's not necessarily non-op or anything along those lines. It's just smaller projects that didn't make the "development cut".
Thomas E. Jorden -- President and Chief Executive Officer
I mean, when I looked at it in prep for the call, there's like 22, what I'll call projects, and there's only 15 on this slide. Sector highlights real. We didn't really
Michael Anthony Hall -- Heikkinen Energy Advisors, LLC -- Analyst
Okay, thank you ever appreciate
Operator
Our next question comes from Neal Dingmann of SunTrust. Please proceed.
Neal David Dingmann -- SunTrust Robinson Humphrey -- Analyst
Nice update. My first question centers on the capital discipline. I know you talked a bit about this, but I just want to make sure I understand. You all were one of the few to slightly sequentially increased the D&C spending this year. What would that announcing a higher than peer average sequential production growth guidance. So again, while I believe you made the appropriate call, I'm just curious as to how you weigh sort of when looking at growth versus just a pure capital discipline?
Thomas E. Jorden -- President and Chief Executive Officer
Well, we look at a lot of ways. I mean, first and foremost, we ask ourselves is this capital well deployed. We're absolutely confident that we're creating value with that capital. We're not driven by growth targets, we're driven by value. But we also looked at the components of our revenue, the components of our cash flow and we have some great results. We're really firing on all cylinders, and we saw 2020 as an opportunity to step it up on our oil growth. And so we're really looking to maximize our profitability, maximize our out-year cash flow, and we have the wherewithal to do it. We didn't really spend too much angst looking at our capital level in 2019 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.
Neal David Dingmann -- SunTrust Robinson Humphrey -- Analyst
Got it. And then my second question is centers on slide seven where you will 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 how you 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 your more cadence on what type of wells and around the working interest of those coming on here shortly.
Karen Acierno -- Director of Investor Relations
Those are net wells, Neal, that are coming on. I mean, we could go through the individual projects as you want, maybe we could do that offline. I'd be happy to give them to you. But we just don't have it at our fingertips.
Thomas E. Jorden -- President and Chief Executive Officer
The critical point is those are net wells. So implicitly, our working interest is 100% on every one of those. But our working anteriorly is very high.
Joseph R. Albi -- Executive Vice President and Chief Operating Officer
When you look closer at it at a high level, first half of the year, we've got 40 gross wells, 29.4 net. Second half, 58 gross wells, 39.2.
Neal David Dingmann -- SunTrust Robinson Humphrey -- Analyst
No, that's exactly what I was getting after. That's it.
Joseph R. Albi -- Executive Vice President and Chief Operating Officer
Thank you.
Operator
Our next question comes from Jeanine Wai of Barclays. Please proceed.
Jeanine Wai -- Barclays Bank PLC -- Analyst
My first question is on your 3-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 three year outlook. You're very encouraged on the upside to the business, it sounds like things are going really well. So any color on trends in well productivity or efficiencies that you envision in that year two or three would be really helpful.
Mark Burford -- Senior Vice President and Chief Financial Officer
Yes, no. As far as the productivity improvements, we are not baking in additional productivity improvements than what we've already have captured and the cost structure is consistent with what we're forecasting for this year. We're not making adjustments to those components of our three year plan. As I touched on, there is some benefit in the outer periods with the improving gas price differentials. We do definitely see those helping us in those future 2021 and '22 periods as you've got some additional pipeline takeaway and improving outlook and the forward differential.
Thomas E. Jorden -- President and Chief Executive Officer
Yes, I just want to reinforce what Mark just said. When we look at plans, we don't bake in hope. So they're anchored on actual cost, actual well results, actual cycle time. And anything we can do as to the upside and operational improvement, well productivity, that's all to the upside.
Jeanine Wai -- Barclays Bank PLC -- Analyst
Sounds like there be some good things to look forward to there. My second question is on inventory additions. And it's just how are you thinking about the cost of adding Tier one 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 one bucket through 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 additions through M&A, given what you're seeing in the market?
Thomas E. Jorden -- President and Chief Executive Officer
Well, I think a lot about that. And my experience, and we just yesterday reviewed our annual look back at 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 cost. If we you asked about acquisitions. 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 because 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 has 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 cost. So the way I think about inventory is we're always trying to find more profitable things. Of course, 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, it's that people walk into my office and tell me we have twice the number of targets in a given asset we already control. But we do also explore off our footprint. We look very carefully at our entry cost, 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. And so we have our own philosophy there. It's all about value creation, and it's all about entry cost. Okay, thanks, Tom. I really appreciate the detailed answer.
Operator
Last question comes from Joe Allman of Baird. Please proceed.
Joseph David Allman -- Robert W. Baird & Co. -- Analyst
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 ask is because I'm hearing different language, I'm hearing about the five pillars. And so that's making me ask that question.
Thomas E. Jorden -- President and Chief Executive Officer
Well, the first time we talked publicly about our pillars. I can tell you everybody in the organization is tired to hear about it because I talked about 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 you know it better than I do. And so these pillars are attempts to focused organization and things we can control. You've heard me say in past down cycles that we're not shippers 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 are 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 new 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 a company on the move. We're getting better, and we are 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.
Joseph David Allman -- Robert W. Baird & Co. -- Analyst
That's very helpful, Tom. And my follow-up and last question is, in terms of natural gas and NGLs and oil, I know that ensuring flow is one of the key drivers that you try to guarantee. But what are you doing to maximize the value? Are there some key things to look for in terms of contracts or agreements that we can look forward to over the next year or two that will help you beyond just the next three years, even longer term?
Thomas E. Jorden -- President and Chief Executive Officer
Yes. Go ahead, go ahead.
Joseph R. Albi -- Executive Vice President and Chief Operating Officer
No. 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 pipe that came out of there. So those contracts that we entered into back then, we're probably a little bit more onerous than 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 terms associated with them. So it's kind of you build it and they will come kind of thing happened out there, and it's creating competition. And we're seeing it. We've seen it on the processing side, we've seen it on the NGL side. And we've seen it on the oil and the residue side. We've improved our oil netback dramatically. Right now, we're about $2.70-some-odd cents off with 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 netback.
Thomas E. Jorden -- President and Chief Executive Officer
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 a high-decline business. And so commitments to 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 band and we're getting more confident to make commitments that give our marketing group the ability to get those netbacks Joe is 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 the commitment.
Operator
The conference is now this concludes our question-and-answer session. I would now like to turn the conference back over to Tom Jorden for any closing remarks.
Thomas E. Jorden -- President and Chief Executive Officer
Yes, I just want to thank everybody for your energy on the call. We've had some great questions. I really appreciate flushing out. 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.
Operator
[Operator Closing Remarks]
Duration: 69 minutes
Call participants:
Karen Acierno -- Director of Investor Relations
Thomas E. Jorden -- President and Chief Executive Officer
Joseph R. Albi -- Executive Vice President and Chief Operating Officer
Mark Burford -- Senior Vice President and Chief Financial Officer
Gabriel J. Daoud -- Cowen and Company, LLC -- Analyst
Arun Jayaram -- JP Morgan Chase & Co -- Analyst
Bryan -- Credit Suisse -- Analyst
Douglas George Blyth Leggate -- BofA Merrill Lynch, Research Division -- Analyst
Michael Stephen Scialla -- Stifel, Nicolaus & Company -- Analyst
Jeffrey Leon Campbell -- Tuohy Brothers Investment Research -- Analyst
Michael Anthony Hall -- Heikkinen Energy Advisors, LLC -- Analyst
Neal David Dingmann -- SunTrust Robinson Humphrey -- Analyst
Jeanine Wai -- Barclays Bank PLC -- Analyst
Joseph David Allman -- Robert W. Baird & Co. -- Analyst
