Alpha Metallurgical Resources Inc (CTRA) — Q4 2019 Transcript

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 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 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 COO, Joe Albi, who will provide a more detailed breakdown on the quarterly results. 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, 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 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 for our capital planning over the next three years. With activity similar to that in 2019, we expect to generate approximately 10% growth per year and increase 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 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 in all these areas. I'd like to walk you through these pillars and the work that's underway. First, let's discuss planning. A 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 multi-year 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 interests in mind. We intend to increase our dividend over time. Balance sheet health is a top priority. 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 onto costs, costs have decreased significantly due to 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 lower 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 local cost 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 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, it 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 discuss 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 key to low entry cost. Digital innovation, we're 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 underway 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 underway on machine learning and are seeing results that are causing us to revisit some long-held assumptions. We have field-tested 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, amazed at how fast the conversation is evolving. Although the rhetoric can be a bit extreme, our industry must demonstrate a 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 with 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 us 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.

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 in mid to late December, which added approximately 1,200 barrels a day to 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 increased operational efficiencies and lower service costs for full year 2019, total capital came in at $1.315 billion, 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 is 1.25 to 1.35 billion, which includes 950 million to 1.05 billion for drilling 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 to $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, including drilling, completion, stimulation, facility, and flowback 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 that fairly even capital spread during the year, our projected completion activity is slightly skewed 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 model 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 the 2019 average of 86,000 barrels a day. With limited capital directed to the Mid-Continent, and the strong likelihood of handling rejection during the year, we're projecting our 2020 net equivalent volumes to fall within the range of 270,000 to 286,000 BOEs per day, which puts a midpoint basically 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 barrels equivalents per day, both down slightly from Q4 '19, but up significantly from a year ago, with our projected Q1 oil and equivalent volumes up 10% to 15%, and 5% to 11%, respectively versus Q1 '19. Jumping to OpEx, we had a great quarter again for our lifting costs in Q4 with a posting of $3.07 per BOE. We were down 10% from Q3, putting our year-to-date listing cost at $3.34 per BOE, just slightly above the low end of the guidance range we issued last call of $3.30 to $3.55, representing a drop of 9% from our 2018 average of $3.66 per BOE. Looking forward into '20, with our 2020 Permian focus and our forecasted range for 2020 equivalent production being relatively flat, we're projecting our full year 2020 lifting costs to be in a range of $3.10 to $3.60 per BOE. Lastly, some comments on drilling and completion cost. 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 Q4 service cost reductions, operating efficiencies, and program design cost reductions that we achieved in late Q4 and early Q1, again particularly on the completions side. We're now executing on those total cost estimates same as those 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 wells in Culberson County running about $500,000 less, with an AFE of $8.8 million to $11.1 million. As we stated before, the efficiency gains that we derive through our multi-well development joint projects really put our average development project per well cost at the low end of the guidance range I just gave you. Both of those AFEs I mentioned reflect costs which are down approximately $700,000 per well from Q4 '19, $1.1 million from early 2019, and down $1.6 million from where we were in Q4 '18. 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 '19, and $3 million from the cost quoted in 2018. We've made tremendous progress in 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 will ultimately lower our total costs. The 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 premium program all-in well cost to the low end of the $1,025 to $1,125 per foot range I just mentioned. In closing, we had another great quarter in Q4. With guidance fees, we set new company records for net oil and equipment 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 hard to achieve. We are well positioned to execute on the capital activity and production plan we've laid out for us here in 2020. With that, I'll turn it over to questions.

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 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 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 have 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 takes 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 we've seen in our well costs have helped to build momentum for that project.

Just a quick clarification that your 2020 Permian AFE per foot guide, does that assume the legacy completion or the new value-engineered 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 ensure that we get the most valuable well, and not necessarily the most productive well. 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 of expenditure.

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 bottom-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. 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 will have to execute it. They understand the logistics and difficulties of a complex plan. The plan we announced this morning is real, it's fixed on the map. There's a commitment from the organization to execute it. But I'd also want to reiterate that 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.

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

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're not operating at our frac crew cadence, and we're still in development; all of that being in plans built out on 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, with some of the production profile still not as it is ratable. That's also a reflection of the timing of the completion of the different infill developments. 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 put this plan out a year ago, the locked down capital will be $1.5 billion every year. This year, our capital is really more tied around the $50 and $2.25 budget from, and we have a goal of basically growing 10% as a minimum. So, there you go. We're not tied to a specific level of capital every year. In fact, in 2020, 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 intense frac 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 a dollar 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, clusters per stage, perforation style, pump rate, fluid and sand composition, and type of sand with 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 are so many things at work. It's the cost of the products and then your efficiencies pumping the job. The longer stage length that Tom mentioned means, 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 from about 9.9 to 6.5 on average, and that's about a 30% reduction in time while you're charged for that time. When we look at the overall reduction on the completion side, I would say the overwhelming elements of that reduction have 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. The bottom line is that this all adds up and our preferred number is that there are so many elements to this. What I love about it is it's going to focus 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, 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. There are many elements that we look at when we assess completion design. Cost and well productivity are critical elements, but what's also a critical element is the impact it may have on well spacing, well interference, the impact it may have on full section development. We're trying to maximize the value and cost and commodity pricing; well productivity are outputs from a focus on value, and that’s the way we solve this problem.

I have a question on New Mexico. 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 to Lea County? And then second, is there room for New Mexico to be an even greater percentage of capital allocation over the three years beyond where you already increased the two for this year?

Yes, Betty, certainly, we have not optimized to the point where we're satisfied. We are 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 remain unchanged. We do think we can increase activity in New Mexico. Your latter question is interesting because 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. These are all things that limit your ability to just crank up at will. New Mexico takes great planning and again, I am going to come back to that pillar on planning. This organization has made tremendous 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 talked about based on this ratable level of activity at a minimum, we could see similar production growth that was increasing free cash flow. I guess just on that minimal standpoint, how confident can we be that things could be in line to better than 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 then turn it over to Mark. I think we have tremendous upside within that capital plan. We have cost upside. We have execution upside. We have 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 better performance with the same capital investment. So, Mark, I'm going to let you handle the remainder of that.

Yes, Betty, just to clarify. So, you're concerned about the ratable activity leading to 10% growth, is that leading 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 three years, actually the '21 and '22, of course we don't have visibility individually for. Our growth in oil is as strong or started and what I would say that we're experiencing in '19. 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 relates to the timing of our projects, but we have built up rig schedules and completion schedules for all these plans. Just some variability in those schedules, but we see 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 built into our forecast.

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. When we look at the flat NYMEX price to $2.25, we still use its four differentials and dedicate that NYMEX price. We use the ratios like right now that the NYMEX price is a little bit lower than $2.25 in '19, but slightly better than that in '20, but we use ratios, the differentials to arrive to our price based on the flat pricing cases.

Doug, that's true of all our capital planning. We really want to level our capital plan around the actual well-received price. We’re really 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 using cash because you want to generate the cash first. But let's assume the Street’s base case is probably around 55 PI. If I'm looking at this chart on Slide 11, this implying about $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 would you buy your stock in that scenario?

Well, I have no good answer for that. As I said in my remarks, share buybacks are very much something 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 as they open and close. Retiring debt is also in that list of priorities. Certainly, I list the three things: increasing dividend, debt retirement, and share buyback. All of those are things that we are deeply interested in.

My second question is actually more focused. I want to revisit the topic of pricing and inventory, specifically regarding the NGL and what your economic inventory appears to be at the current pace. Additionally, I'd like to understand how confident you are in the assumptions you're making about the NGLs, considering the new infrastructure developments, as this is a significant factor in assessing the economic inventory. I'll stop there, thanks.

I'll start with your last question about future pricing. We aren't confident at all, and anyone on the call who has insights can share. We maintain a healthy balance sheet and conduct thorough downside sensitivity analyses. Every investment is evaluated from multiple price scenarios, ensuring it's sound even under the most conservative outlook. However, concerning economic inventory, I can say that it’s no longer a concern for me. We have seen an increase in our inventory, and I’m eager to discuss the new landing zones we've tested. Our outlook on economic inventory has never been more positive, and I want to emphasize that it's not something I worry about anymore, despite having spent considerable time on it.

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

We have initiated a machine learning project focused on our completion methods, analyzing the numerous decisions we've made over the past few years regarding well completions. Each decision was guided by an economic plan and directed us along a specific path. We're pleased with our current position, but machine learning enables us to consider all those decisions and explore millions of simultaneous solutions to identify alternative paths we may not have previously considered. We have some results that challenge our conventional wisdom, which is very exciting for us. We are committed to this effort and will be field testing it this year. Regarding automation, our organization has placed a strong emphasis on it, and it has greatly benefited us. It allows for real-time monitoring of our facilities, predictive data analytics, and rapid responses to upset events like flaring. Additionally, we have safety shutdown systems to manage field events or system failures, which helps prevent field interruptions. Automation represents the way forward, and while many industries are ahead of us, we're making progress with a great team dedicated to deploying this technology. We're excited about the insights it provides for making informed operational decisions in real time.

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 prior completion designs? I recognize 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. But I just thought, yes, I just want to 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 about a lot of things that don't ultimately work, and we really look forward to talking to you about results.

Good morning. Thank you for all the wealth of guidance over the three-year period. 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's Wolfcamp B versus A that kind of thing?

Well, first off, I want to share your excitement. This organization, it's a tribute to the organization through our hallways in the field. We really have a focused organization and are focused around the right things. Referring to Slide 13, I mean, certainly, our major target is upper Wolfcamp. 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 I had to just be broad-brushed, I'd say it's generally dominated by upper Wolfcamp with the second being Bone Spring.

Looking at Slide 24, it outlines several sales agreements for oil and natural gas that are indicated through 2020, but I also notice many long-term agreements as well. So I am curious, when I examine this slide, do these agreements essentially set the tone, or is there some flexibility after 2020?

This is Joe. The agreements we currently have in place are focused on ensuring product flow, particularly on the gas and residue takeaway side, which underpins our commitment to Whistler. We are also exploring additional projects, aiming not only to secure product takeaway from the basin but also to achieve greater diversification with various end users and increased Gulf Coast exposure. On the oil side, we are confident in the capacity available to exit the basin. Regarding NGL, all our contracts are linked to processors that have access to pipelines out of the basin. Our goal is to secure flow while diversifying the end markets to capitalize on the geographic pricing variations.

You've mentioned some key points, and many have been addressed. Regarding the increase in wells progressing throughout the year, what is the driving force behind that? How does this play out in the remainder of the three-year plan? Is it expected to decrease, or is it simply a 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 backlog of drilled but uncompleted wells. Yes, I could talk for the next 30 minutes on why that's the case. We still would love to complete a well and bring it on immediately, but we find that limits our flexibility in the field. 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, 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. Having a few and not a lot, but having some inventory of wells 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 team loves the idea. I mentioned the time savings we're seeing to pump our wells where our frac crews are catching up with our rigs. If we ever get to the point where they're waiting on the rigs then we've got a little bit of an issue. Having those wells available for us at the end of the year is truly beneficial for 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 cadence levels that we see in this year where we have much 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 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 accounted for in '19. Those wells 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 when the first pod will occur post completion. The capital is scheduled. The timing of the production did come a bit quickly, but this capital was already scheduled in '19. 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. Technically, we were kind of remodeling those, expecting them to come online in the first quarter. We did come on a few quickly that reduced our in-progress at the end of '19. We step forward into '20, the 54 we described or so, those are pretty stable out in '21 and '22, which relates to your earlier question. It just comes back as Tom mentioned, we try to have a pretty stable plan and have a ratable frac connectivity relative to rig. So without rig level about 10 rigs in the Permian and 2 frac crews growing to 3, that's kind of in progress is just kind of a normal outcome of our cadence.

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 view of your outlook? You're very encouraged on the upside to the business, and it sounds like things are going really well. Any color on trends in well productivity or efficiencies that you're envisioning in year 2 or 3 would be really helpful.

Yes, Jeanine, as far as 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 periods 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 improving out in the four differentials.

Yes, Jeanine, 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 costs, actual well results, and 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. How are you thinking about the cost of 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 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 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 reviewed our annual look back yesterday. Our history of investing; what's worked? What hasn't? What do we want to emphasize? What do we want to correct? 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. Our acquisitions are great from a top-line perspective, 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 are very few proprietary advantages. Everybody's got lots of money, and everybody's going to be bidding, so being the high bidder in an auction isn't our value creation strategy. We want to find proprietary ideas and capture that value for our shareholders; that’s a low entry cost. 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 often leads to a landing zone that can be co-developed with your existing activity. So, if you ask me what I hope for, its people walking into my office and telling me we have twice the number of targets in the given asset we already control. 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 want to make sure to have that be a very small and manageable part of our total capital. We really want to focus on value creation and on entry costs.

Tom, is there a strategic shift happening at Cimarex? Or is there a tactical shift happening at Cimarex? And what's driving that? The reason why I asked is because I'm hearing different language 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 the organization is tired of hearing about it because I talk about it constantly and introduced that in the middle of last year. Joe, these are tough times. Although I find myself incredibly optimistic about this company, we have really difficult headwinds and in that you know it better than I do. These pillars are a chance to focus the 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, costs, exploration, 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. We're a much better company than we were a year ago, and I'm excited to be able to say that publicly; we will be a much better company a year from now.

That's very helpful comment. My follow-up and last question is in terms of your natural gas, NGLs, and oil. I know that ensuring flow is one of the key drivers that you try to guarantee. But what you're doing that to maximize the value? Are there some key things to look for in terms of contracts or agreements so we look forward to having 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. Those contracts we entered into back then were probably a little bit more onerous than you get today. 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. It's kind of a 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. We've seen it on the oil and the rescue side. We've improved our oil net back dramatically. Right now, we're about $2.70 some odd off of the Midland-Cush differential. That number wasn't that four or five years ago. 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 cyclical. Commitments to long haul pipelines, if your assets are in high decline, that's a commitment to future capital because you need to drill new wells to achieve and meet those volume commitments. 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. We're getting more confident to make commitments that give our marketing group the ability to get those net back that Joe was talking about. 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.

Yes, I just want to thank everyone 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.