Alpha Metallurgical Resources Inc (CTRA) — Q4 2018 Transcript

Good morning, everyone. Welcome to our fourth quarter 2018 results and 2019 guidance conference call. An updated presentation was posted to our website yesterday afternoon, and we will refer to this presentation during today's call. This morning's discussion will focus on Cimarex's historical results and our 2019 guidance. Due to the pending transaction with Resolute, we will not address related matters. However, if conditions are satisfied, including the approval of Resolute shareholders, we expect to close the acquisition on March 1. Our full year guidance assumes the acquisition of Resolute closes on that date. We will refrain from commenting on Resolute until after the expected closing. This also is not a discussion of the securities involved or a solicitation of any vote or approval. You are encouraged to read the public filings with the SEC that contain information about the pending transaction. Additionally, our discussion will include forward-looking statements. Various actions could cause actual results to differ significantly from what we discuss. You should review our disclosures on forward-looking statements in our news release and in our latest 10-Q for the year ended December 31 that was filed yesterday, as well as other filings related to risk factors associated with our business. As always, we will start our prepared remarks with an overview from our CEO, Tom Jorden; followed by an update on our drilling activities and results from John Lambuth, SVP of Exploration; and then Joe Albi, our COO, will provide updates on operations, including production and well costs. CFO, Mark Burford, is also here to assist with any questions. I will now turn the call over to Tom.

Thank you, Karen. Good morning, everybody. Cimarex had a great year in 2018. We invested $1.57 billion in exploration and development and achieved excellent investment returns. We generated earnings per share of – excuse me, earnings of $792 million or $8.32 per share on revenues of $2.3 billion. We finished the year strong, with solid execution and beat consensus estimates for both production and CapEx. All in all, it was an excellent year, and I commend our organization for flawless execution and performance that exceeded our targets. You will recall that we sold assets in Ward County in 2018, the proceeds of which will help to finance the announced acquisition of Resolute Energy Corporation. That acquisition, as Karen said, is expected to close on March 1. As we move forward into 2019, looking at our activity on a combined basis, we are committed to cash flow neutrality in 2019. Simply put, we will not borrow money. Our planned exploration and development capital of $1.35 billion to $1.45 billion will put us in a cash flow neutral position, including the payment of our quarterly dividend at a $52.50 NYMEX oil price. Before considering our dividend, we will be cash flow neutral at a $50 NYMEX oil price. However, we do not consider our dividend to be discretionary, so we internally discuss cash flow neutrality after payment of the dividend. You may have also noticed that we increased our dividend yesterday to $0.20 per share per quarter. We will have an active year in 2019, driven primarily by development projects. John will provide more detail on this. The work we have done these past few years has greatly increased our understanding of optimum development. Our learnings here include reservoir behavior, well interference, and the project economics of multi-well developments. These understandings are a result of experiments across our portfolio including Wolfcamp, Bone Spring, Woodford and Meramec. Our conclusions on well spacing and incremental economics are not obvious, but we are confident that we can find the value sweet spot in developing our assets. Our 2019 plan includes projected exploration and development capital of $1.35 billion to $1.45 billion, 85% of which will be invested in the Permian Basin. Our total production is expected to increase 18% at the midpoint, including oil growth of 23% at the midpoint year-over-year. As a result of the progress we have made, we have a multiyear outlook where our assets and organization will deliver good growth and free cash flow at a $50 NYMEX oil price, including the dividend. I would like to refer you to Slide 10 in our latest presentation, where we present a 3-year cash flow sensitivity at a $50 and $55 NYMEX oil price. Our assets can generate cumulative free cash flow after the payment of our dividend of $100 million to $600 million over the next 3 years while delivering oil growth averaging 15% per year. The chart on the left is a comparison of cash flow over the last 3 years versus our outlook for the next 3 years. We will be spending about 20% more capital on average, generating about 35% more oil growth on average and see a potential swing of over $1 billion from outspending $532 million over the 2016 to '18 period to generating $100 million to $600 million in free cash flow during the period 2019 to 2021. The $600 million in free cash flow at $55 NYMEX oil is 11% of our total cash flow we expect to generate in that period, calculated as a percentage. Cimarex has hit our stride. 2019 will be another year of solid execution. We're seeing the benefits of our emphasis on science and innovation, as well as our organizational capability and focus on economic returns. 2018 was a year that showed our ability to execute as planned. In 2019, we will do it again. With that, I will turn the call over to John to discuss some of the highlights.

Thanks, Tom. During the fourth quarter, Cimarex invested $380 million in exploration and development activities, bringing the total for 2018 to $1.57 billion. $1.3 billion or 86% was invested into drilling and completion of new wells. These investments yielded excellent results for Cimarex, including growth in both reserves and production. We drilled or participated in 349 gross, 122 net wells in 2018, with 70% of our capital spend in the Permian region and 30% in the Mid-Continent. For 2019, our estimated total exploration and development capital is $1.35 billion to $1.45 billion, with $1.1 billion to $1.2 billion going toward the drilling and completion of new wells. This amount of drilling and completion capital represents 83% of our total exploration and development investment. We currently operate 11 gross rigs, with 10 in the Permian region and 1 in Mid-Continent. We plan to spend approximately 85% of our drill and complete capital in the Permian in 2019, with the rest going to the Mid-Continent region. This capital investment will result in a total of 83 net wells brought online during 2019, with our company-wide average lateral length increasing from 7,512 feet, which was the 2018 average, to 9,050 feet. Now on to some specifics about each region. I will start in the Permian region, where we brought on 40 gross, 32 net wells in the fourth quarter, bringing the total for the year to 80 net wells. A very significant delineation well brought online in the fourth quarter was our first Third Bone Spring landing test located on the western part of our Culberson acreage block. The Kingman 45 State Unit 3H had an average 30-day peak production rate of 2,917 barrels of oil equivalent per day, including 1,965 barrels of oil per day. This outstanding result continues to expand the prospective hydrocarbon window for the Upper Wolfcamp in Culberson County, which will lead to greater development well densities for this area. Another significant result for this quarter is the Crawford 27-26 FEE 2H, located on our Southern Eddy County acreage block we call White City, and I'll refer you to Page 16 in our investor presentation for its location. This 10,000-foot Upper Wolfcamp delineation test achieved a peak 30-day average rate of 2,455 barrels of oil equivalent per day, including 1,701 barrels of oil per day. This step-out well helps confirm the strong rate of return opportunity we have in this Southern Eddy acreage position. Also coming online in the fourth quarter was the Animal Kingdom infill development, which consists of 8 10,000-foot laterals testing the equivalent of 14 wells per section. These 8 wells achieved a combined peak 30-day average rate of 3,500 barrels of oil per day and 81 million cubic feet of gas per day. Although we do not have any Lower Wolfcamp developments planned for 2019, the early results from this project would suggest future Lower Wolfcamp developments would be planned at spacing much tighter than the previously announced and successful 6-well per section Tim Tam pilot. We have allocated 85% of our capital to the Permian region in 2019, which equates to a 5% increase in absolute spending over 2018. We have a total of 9 development projects spread across our Delaware Basin acreage position planned for '19, all of them targeting the Upper Wolfcamp interval. Five of these are located within our Culberson joint development area. Planned spacing for these 5 pilots will vary from 8 to 12 wells per section, depending upon the overall thickness of the hydrocarbon section for each project. Three more development projects will come online in Reeves County, Texas, and one more development project will be drilled on our highly prolific Red Hills acreage block located in Southern Lea County, New Mexico. All 4 of these projects will be drilled at the equivalent of 12 wells per section. Finally, our average operated lateral length in the Permian has increased from 7,617 feet in 2018 to 9,169 feet in 2019. So although we have 14% fewer operated wells versus 2018, our laterals are 20% longer, resulting in a 4% increase in total lateral feet drilled for the year. Now on to the Mid-Continent. In the fourth quarter, the Mid-Continent region brought online 6 net wells, bringing the total for the year to 42 net wells. Of note was the 10,000-foot Meramec development project called Dupree, which was drilled at 3 wells per section. Average 30-day peak rates for the 2 additional development wells were 2,972 barrels of oil equivalent per day and 1,574 barrels of oil per day. Our better understanding of the in-place hydrocarbon potential of the Meramec is leading to better well spacing decisions for the rest of our undeveloped Meramec position. This year, we will be completing and bringing online three Meramec development projects in the second quarter. The spacing for these three projects varies from 3 to 5 wells per section. Finally, due to the size of the project and resulting capital required, the previously planned Leota Woodford infill development project will be delayed until possibly 2020. With that, I'll turn the call over to Joe Albi.

Thank you, John, and thank you all for joining our call today. I'll touch on the usual items: our fourth quarter production, our Q1 and 2019 full year production guidance and then I'll finish up with a few comments on LOE and service costs. As Tom mentioned, we ended 2018 with a very solid quarter for production. With 38 net wells coming online during Q4, our reported net daily equivalent volume came in at 251.3 MBOEs per day, beating the upper end of our guidance and setting new records for company and regional production, and those are records in all product categories. Oil production drove our strong quarter-over-quarter production ramp, with our Q4 oil volume coming in at 79,900 barrels per day, surpassing the upper end of our guidance range by nearly 2,000 barrels a day. With Q4 in the books, our reported 2018 full year equivalent and oil production volumes exceeded our guidance ranges that we gave last call and reflect strong year-over-year production gains, with our 2018 reported equivalent volume up 17% and our oil volume up 18% over 2017. So looking forward into 2019, our forecasted production model reflects our focus on the Permian and incorporates three primary inputs. One is a constrained capital investment, which is tied to cash flow neutrality at $52 NYMEX oil. The second is the transition into a much smoother completion cadence. And third is our continued investment in high rate of return drilling projects. Our drilling and completion capital assumptions that we've used in the model are based on late 2018 total well cost estimates and include approximately $80 million for program-related infrastructure such as SWD and power, as well as a little extra windage for select science projects such as pilot holes and upsize frac experiments. As such, the recent potential well cost reductions I'll touch on in just a bit are not built into our current 2019 capital spending projection. The model integrates the addition of the Resolute volumes beginning on March 1, and reflects a slowdown in our Q1 net completions as we transition into the smoother completion cadence I just mentioned beginning in the second quarter. The result is lower 2019 drilling and completion capital and a net completion count lower as compared to 2018, with our projected first quarter volumes flat to Q4 '18, followed by quarter-over-quarter production growth beginning in the second quarter. For Q1, we're projecting our net equivalent daily volume to average 245,000 to 250,000 barrels of oil equivalent per day, with an oil volume in the range of 75,000 to 81,000 barrels of oil per day, both virtually flat to Q4 '18, but up significantly from a year ago, with our projected first quarter equivalent volume up 19% to 25% and our oil volume up 15% to 24% from our reported Q1 '18 volumes. With our net completion cadence projected to increase and smooth out beginning in Q2, our 2019 net equivalent daily volumes are forecasted to average 250,000 to 270,000 BOEs per day, with our full year net oil volumes projected at 78,000 to 88,000 barrels of oil per day, both up significantly from 2018, with our 2019 equivalent volume projection up 13% to 22% and our full year oil projection up 15% to 30% over last year. Switching gears to OpEx. With our Ward County properties now off the books and also with the reduction in our expense workovers during Q4, as well as the ramp in production that we saw in Q4, we posted a great quarter for lifting costs in the fourth quarter. Our Q4 lifting cost came in at $2.87 per BOE, well below the low end of our guidance range that we gave of $3.35 to $3.80, and down $0.92 or 24% from where we were in Q3. As we look forward into 2019, with continued market cost pressures on items such as SWD and compression, our increased 2019 Permian drilling focus, and the acquisition of the Resolute properties, we're projecting our full year lifting cost to be in the range of $3.20 to $3.70 per BOE. With the Resolute properties added to our books beginning on March 1, we're projecting Q1 '19 to likely come in at or below the full-year guidance range I just mentioned. And lastly, some comments on drilling and completion cost. On the drilling side, with rig rate increases we talked about last quarter now in place, we've managed to hold the drilling portion of our AFEs in check since our last call. But on the completion side, we recently realized additional cost decreases in both the Permian and in our Mid-Continent programs, via service cost reductions, local sand sourcing, water recycling, zipper fracking, and by challenging the completion design for each and every one of our programs. As a result, we've just recently lowered our total well cost AFEs. The majority of our 2019 program is focused on the Wolfcamp in the Permian, where depending on area, interval, facility design, and frac logistics, our most current Wolfcamp 2-mile AFEs are running $10.4 million to $12.9 million. That's down $500,000 from our estimate last quarter. In the Mid-Continent, with a refined completion design and local sand pricing now in place, we've just lowered our 2-mile Meramec total well cost $500,000 with a new range of $10 million to $11.5 million. That's down more than $1.5 million from the cost we quoted a year ago. As I mentioned just a bit earlier, with us just now on the forefront of realizing these potential cost savings, they have not been fully incorporated into our current corporate planning model for wells we have yet to drill and complete. So in closing, we had a great Q4, beating the upper end of both our equivalent and oil production guidance ranges. With that, we closed 2018 with solid year-over-year equivalent and oil production growth. We further improved our overall cost structure with significant drops in both lifting cost and development cost. We're in great shape to execute a disciplined 2019 capital program, with our entire organization focused on optimizing cost and continuing to generate profitable growth. So with that, I'll turn the call over to Q&A.

Tom, I have a quick question on capital efficiency. Perhaps it's a bit simplistic, but what we did was we looked at your E&D budget in '18 versus '19, and we just divided by the number of wells or drills you're projecting in '19 and just compared it to 2018 actual. So if you just looked at this on a per well basis, the costs go from just under $13 million to $17 million. I know lateral lengths are increasing some, but I just wondered if you can discuss that increase as well as the drivers of the capital efficiency improvement that you're modeling in 2020 and 2021 versus 2019 levels?

Well, I'll tee it up and then I'll turn it over to Joe to give you detail. But Arun, one thing I'll say from a very high level, is we are absolutely committed to live within cash flow. And that means we don't want to borrow money. So if there is a bias in our numbers, it's probably a little bit to the upside. We didn't want to come in with a capital that's flying close to the ground, because then if we were to go over that number, we would end up going into a debt situation. So we've actually built in a little money into our program for potential cost overages. We see them every year. We do occasionally stick tubing on a drill-out. We do occasionally have to sidetrack a well. And so we've looked historically at what that is and we've built in a little bit of windage there. But I'll say, I know there is a little bit of confusion. We do have some infrastructure dollars. We have some facility dollars. But when we look in our internal numbers, we do not see a per unit cost increase. So we would push back on that there is a decrease in our capital efficiency. And then the last thing I'm going to say before I turn it back over to Joe, is we have a fairly rigorous project internally going on right now, looking at our cost, trying to squeeze what we can out of reengineering our programs. Some of it's not up for grabs. We build facilities that are clean, they're safe and they're built to last. But with that, I'm going to turn it over to Joe.

Yes, Tom, I'll elaborate a little bit further on what Tom mentioned about the windage. We've got capital in our current model right now, number one, that's based on later AFEs in the year that we were putting together. And very simplistically, on the frac side, I can tell you that we've seen about a 20% reduction in our frac cost per foot since late Q3 to current today numbers. And so to the extent that those higher completion costs are built into the model, there's a little bit of bias on the conservative side there. When we break out the capital and we deduct the infrastructure cost and we compare the cost per foot, per lateral foot to 2018, we're seeing actually at the total company level, a slight reduction from where we were in 2018. And lastly, what I'll say without trying to quantify numbers exactly, at any given year, with the number of multi-well development projects that we have, we have capital that may be spent at the latter part of the year that doesn't reflect itself in the number of wells that are brought online during that year. And we have some capital in our model, obviously, that's associated with our 2020 program that, doing the simplistic calculations you are doing, may not be the correct way to take a look at it.

That's helpful. And my follow-up, Tom or John, I was wondering if you can give us an update on your thoughts on exploration and potentially broaden out the portfolio beyond the Permian, Mid-Continent. The 10-K did confirm that you have a reasonable position, looks like 130,000 acres, in Louisiana now, for similarly, for the Austin Chalk play. I was wondering if you can maybe comment on those 2 points.

Arun, this is John. I wasn't aware that our 10-K was disclosing that. It's new information to me, but we have indeed accumulated a substantial acreage position in Louisiana, and we are actively pursuing an exploration initiative there. That's part of our usual approach. As we've mentioned before, if any of that proves to be significant and we obtain good results, we will provide more details. So yes, we have established a position there, and we'll see what happens.

Arun, our aim is to increase our assets, and we believe that organic growth is our preferred method. If we come across a suitable bolt-on opportunity, we're interested, which is what the Resolute deal represents. However, I want to highlight that growing our assets encompasses many aspects. Exploration plays a vital role in that, along with leasing, generating new ideas, and expanding our footprint, and we are consistently working on these areas. Additionally, we have the opportunity to grow our assets by enhancing our understanding of our development, optimizing well spacing, and exploring new target zones. I want to reiterate a couple of points made by John. The Third Bone Spring well in Culberson County represents a new target zone that coincides with our assets in the area. This discovery is a significant development for Cimarex. There was a considerable amount of risk involved with that well, as it was based on a creative geological and engineering approach. When looking north up dip, where one might expect oil to be more prevalent across the basin, those landing zones are actually wet. Conversely, our geological hypothesis suggested we might be in the right section of the basin for oil. We tested that well, and the outcomes were outstanding. That interval aligns and overlaps with nearly all of our entire asset. Therefore, we want to expand our assets through innovative internal strategies, and while we need to do more of that, I just want to emphasize that there are numerous ways to achieve our goals.

Tom, I was hoping you can talk a little bit about how your priorities for use of free cash flow are, in your mind, ordered right now? And how you may plan to increase that return of cash over the next couple of years?

Well, our first priority is to execute and generate it. And so we're pretty confident we can do that. Yes, you know we're going to continue to grow our dividend, we're committed to that. And that's taking a not insignificant part of our cash flow. As we look ahead, we're just going to have to see. I mean, first thing we have to do is demonstrate that we can execute and bank that cash. We will be running our cash on our balance sheet down post Resolute closing. So after we close on Resolute, we won't have the cash on our balance sheet that we're used to over the last couple of years. I'll say what one of our directors used to say, and that's 'Cash does not spoil.' I mean, we don't like to keep cash on our balance sheet, but that said, we're not always nervous about it, either. We'd love to find additional bolt-ons, and we are committed to return cash to shareholders. So that will certainly be forefront of our mind. But first and foremost, we need to execute and generate that free cash.

Understood, Tom, thanks for the insight. As a follow-up, have you considered the options for returning cash to shareholders beyond dividends, such as possibly a special dividend or buyback?

Well, yes, of course, we think about it. We think about it constantly. We get asked about it. But I don't have anything new to say on that than what we've already said. We are committed to our owners. We understand who we work for and that's what our plan is all about.

This is Kalei Akamine on for Doug. I've got a couple of questions here. So the 2019 plan really looks like a full pivot to the Permian Basin. And obviously, that's positive for oil growth, cash margins, and so forth. But the shift in activity also begs the question just how core is the Mid-Continent to our portfolio? I'm wondering if you can address how the Mid-Con fits into your future plans, which now appear framed by $50 CapEx?

Well, this is John. I'll take a stab at that. First off, without a doubt, given the disparity between oil and gas price, Permian shines relative in a portfolio manner to our Anadarko Basin. And we have much better oil opportunities in Permian than we do in Anadarko. Now that said, there are oilier opportunities in Anadarko. The other thing, though, is that's leading to this investment decision is Permian is much further ahead in our confidence to be able to deploy this capital in a full development mode and achieve both the volumes and the returns. We're further ahead of the game there in the Permian and in fact, I think we demonstrated that strongly in our fourth quarter, with the number of the development projects that we were able to bring on, on time, and even in some ways, exceeding our expectations in volumes. And a lot of it was Permian. So a lot of confidence in our ability to deploy that capital right now in Permian and get it done. And then the last thing I'll say is in Anadarko, we don't really have any obligation that we have to spend in terms of maintaining our acreage position. We still have a pretty significant amount of capital that has to be deployed in Permian and we're happy to deploy it to maintain our acreage position. So all of that led to this year's investment decision. Not with all that said, I will tell you that in Anadarko, we are challenging that region to come up with the type of development projects that will compete with Permian, and we'll be working on that throughout the year. And I fully expect to see them fighting for capital as we go into 2020. Yes, I'll just add to that. Anadarko Basin is a wonderful basin. It's pressured, it has multiple targets, multi-pay. If we had to come up with a punch list of what we're looking for in new basins, Anadarko Basin fulfills almost all of them. And in addition to that, the State of Oklahoma, as is Texas and as is New Mexico, are places where you can plan your business and deal with a regulatory environment that's constructive. And so I just want to tell a little bit of history here. In 2009, we laid down all of our rigs in the Permian Basin, and we challenged the organization there to figure it out and come up with things we wanted to do. And they came up with a novel new idea in Lea County called Second Bone Spring, drilled a horizontal well, and we were off to the races. So we've issued a similar challenge to our Anadarko region to be creative, look through that basin, find things that compete for capital. We're a highly competitive organization, both externally and internally. And I am highly confident that we're going to surprise to the upside in what we can find and do in the Anadarko Basin.

Given the plan for 2019, what kind of decline do you expect for the Mid-Con BOE and natural gas?

We're pointing to Joe for that. He's looking at, yes. He's pulling his papers out, yes.

Yes, overall, at a BOE basis, we're projecting that 2019 might be down 5% to 7% in the Anadarko. And most of the majority on the equivalent growth side is obviously on the Permian side and that's 35% plus.

Awesome. Just as a follow-up, I was wondering if you can speak to the gas takeaway situation in the Permian Basin. Now in the Permian, you guys have some really powerful oil assets, but they just happen to produce a lot of natural gas. So given your yield, your insights in value, do you see this market evolving in the near term as important? Just wondering if you can talk to your expectations for pricing? And since then, you've also finalized 2019 plans, can you give us an update on your projected Permian sales agreement through December 2019, which I think previously stood at around 98%?

Yes, this is Joe. I’ll make a few comments and then pass it to Mark regarding what we are seeing in the basin and how it impacts hedging. On the gas side, there has been no change. We have secured the same sales arrangements and are currently at about 97% of all our residue gas in the Permian through pre-sales arrangements for the first quarter of 2020. We aimed to extend beyond 2019. There are expansions in takeaway, not just for gas by the end of Q3, but also for NGL and oil. We haven’t encountered issues on the liquids side. Our NGL production is tied to sales with processing facilities that have long-term sales arrangements for those volumes. Similarly, for oil, 78% of our production is transported via pipeline, and approximately 90% of our new oil wells in the first and second quarters will also be put on pipe. We expect that percentage to continue. More importantly, those pipelines have access out of the basin, and we have sales agreements in place. We feel as confident now as we did 3 to 4 months ago about our ability to sell our products. I haven’t noticed any real changes in that aspect. Mark, do you want to discuss what we are observing regarding the differentials?

Sure. Kalei, this is Mark. When considering the differentials based on the forward strip for Panhandle Eastern, which includes Waha and a passive Permian, we are anticipating prices around $1.50 to $1.25 for the next few quarters. There is an expected improvement in the fourth quarter, raising it to about $1. For the annual average in 2019, we are looking at approximately $1.25. I should mention that we are nearly 40% hedged for the 2019 calendar year using Waha and passive Permian collars. These collars are generally positioned in the range of $1.45 to $1.80. Additionally, we have part of our realization secured with collars in the Permian. As we look at 2020 and the forward strip, prices are projected to improve further due to ongoing pipeline expansions.

First question is on, going back to Mid-Con. Since it had to fight for capital, you've described that, can you add some color on the locations that have made the grade? Are these discrete Woodford Meramec locations? Or will there be some multi-zone development of the 2 together?

Well, as I said in my remarks, we have 3 sections' worth of development that we've already drilled and we'll be bringing on in the Meramec in the second quarter. We very much look forward to the returns we'll get from there. We think we're spacing those wells appropriately and we think those type of wells are leading to kind of capital that can compete. I think the bigger question is just we have a number of great opportunities, especially in the Woodford. But typically, for those type of opportunities, they take a lot of capital. Honestly, when we go to develop Woodford, it's a large capital investment and the kind of cycle time we see there. Right now, we kind of like what we, again, have coming out of Permian in terms of our ability to deploy that capital and get that capital refresh rate quicker. Other than that, there are good investment opportunities, but again, we're just trying to get to the point where we're more confident in making those investments and how ultimately they'll compete versus these Permian development projects.

Yes, I'll just add to that. One of the issues in the Woodford, in much of our Anadarko portfolio, really is generating very, very nice returns. But the Woodford is a different reservoir than many of the other reservoirs we play with, in that it is subject to well-to-well interference phenomenon. And that means that if you're going to do a development, a 6- or 8-well development, which may be perfect for the Permian, is something you really want to be suspicious of in the Woodford. And that's because you want to protect your boundaries. And because of well-to-well interference phenomenon, it does lend one to consider larger projects. And that's one reason that's contributed to our capital allocation, in that a lot of the same things we have teed up and ready to roll in the Woodford, although good returns are just larger chunks of capital.

I appreciate that color. First of all, I apologize, I missed the earlier part of the call, if you'd already covered some of that.

No problem. You missed some very eloquent remarks.

But that brings up an interesting point. You mentioned that while 2019 might not be a significant year, you aim to transition towards a multiyear planning cycle. Once you feel comfortable with that in place, would it make the investments you discussed in the Woodford a bit more feasible compared to the current situation?

No, absolutely. In fact, as I said, we have plans as we look forward into those multiyears. Because again, as Tom said, when we look at the different metrics that we like to see on a development project, there are a number of Anadarko projects that look attractive. It's just, again, the amount of timing it takes to get those put together. And as Tom alluded to, also working with your offset partners to get everybody lined up to get it moving forward. So it just takes a little more upfront planning, which ultimately could lead to some good investments, again, probably in 2020 for a number of those projects. That said, they still have to compete with Permian development projects. And we're always going to hold that level of making sure we're making the best investment that we can.

This is a high-class problem, because our Anadarko assets are, by and large, all held by production. So we do have the luxury to stage it as we see fit. Yes, I know it looks odd from the outside looking in, but from our standpoint, it's a pretty nice problem to have.

Right. And just to follow up on what you had said earlier, it sounds like then, having discussed this, the challenge that you're going to make to your Mid-Con team is to try to figure out how to get cycle times down to as short as feasible. Is that right?

I think cycle time is one aspect, but more importantly, as Tom alluded, and trust me, we spend a lot of time, we look very carefully at these well-to-well interference things we see on development projects. And quite frankly, we have a lot of energy going toward taking steps to minimize the impact, say when you come develop next to an existing development and wells in the ground. And so yes, just a major change in that, and I'm kind of excited by some of the things we're looking at. If we can just get more comfortable with that, that then would allow us to design the type of developments that would get us to quicker cycle times and refresh rates. So they're up to the challenge, as Tom said, and we're putting a lot of energy into it. And if we can have just a small breakthrough on some of these things, they'll be competing, for sure.

I appreciate that color, because I think the simple minds' thing is just, well, if it's $50, and if this doesn't work. But it sounds like there is, obviously, a lot more involved and also problems that you can solve. I certainly took note of the Third Bone Spring well in Culberson and just wanted to ask a couple of quick questions. One, how many wells do you feel like you need to drill to get a good handle on prospectivity throughout your Culberson acreage? And so far, does this Third Bone Spring zone have any communication with any lower zones? Or does it seem capable of standalone development?

Yes, we now have mapped the extent of our Culberson position, and it appears very promising. We have several wells planned for this area to further define it as a landing zone. Regarding your second question, I can’t provide details about overall vertical communication and drainage, as this was just one well. In the near future, we will incorporate this as a landing zone in some of our developments and assess its drainage compared to other wells. This will inform our decisions about the total number of wells we will place in this section. It's encouraging to see that over the years, we have been able to push the upper landing zone higher in the section, which will allow for more wells per section as we continue to develop this acreage.

My first question is on the three-year guide. You previously commented that you wanted to level out the completion cadence and that it would take a couple of quarters to get there. And it looks like you're probably getting there in the back half of this year. With CapEx being roughly flat over the next 3 years in the plan, what does the oil growth trajectory look like when you get out to 2020 and 2021? And I guess, specifically, do you see continued improvement in your capital efficiency such that you could see flat or maybe even sequential growth in 2021?

Yes, Jeanine, this is Mark. During the 2020 and 2021 period, as we move beyond 2019, we are still striving to stabilize and predict the completion cadence. We anticipate a 15% annual growth in oil averages during that time. We are actively working on those plans, and as we progress, the completion cadence in those years is gradually becoming more consistent with steady growth. Improvements in capital efficiency will allow us to allocate more of our capital toward full development. We expect to see continual enhancements in capital efficiency through 2021.

Okay, great. That's helpful. My second question is about the Wolfcamp, and I apologize if I missed this earlier in the call. I noticed in the presentation that the returns for the Upper and the Lower Wolfcamp in Culberson County have declined since the last update. Can you discuss what might be driving this change? Is there a shift in the spacing assumption or the completion technique that could also impact other areas of your portfolio? Or is this just an isolated incident?

I’ll go ahead and address that. We conduct these sensitivity analyses regularly, and we updated them about six months ago. We utilize forward-looking type curves that represent a blend of curves across our acreage. Some upper zones may not be included in this analysis. The adjustments we see are mainly related to these type curves. While they may have decreased slightly, they remain quite high overall. I wouldn’t be overly concerned about these fluctuations; it's more important to focus on the improvements with price. Even at $50 oil, the Lower Wolfcamp shows good returns. If we consider $45, which corresponds to our $50 scenario, we’ve had this information for a while. The minor changes in type curves account for the adjustments we see from quarter to quarter.

As soon as we hang up, we'll put the old and new curve on top of one another on the light table, if we still can find a light table.

Tom, given your comment about focusing more on organic growth, could you talk about how just your thoughts going forward on further consolidation, not only in the Delaware, but I think in the past, you mentioned DJ and other things, just in a broad sense, any colors or comments you might have on that?

I believe consolidation can be quite beneficial, especially when the assets being consolidated are better managed by the consolidator. Our transactions in 2018 exemplify this, as Ward County was better off with the purchaser who would invest more attention and resources into it. We are also excited about acquiring the Resolute assets for similar reasons. However, it's important to consider the price when looking at consolidation. We are very interested in pursuing opportunities that create value, and we have been actively looking for years. We are looking forward to closing the Resolute deal next week, and if we come across another opportunity that makes as much sense as Resolute, we would be eager to pursue it, though such opportunities are rare, as our goal is to enhance value for Cimarex shareholders.

Great details. I expected you would go in that direction. One last question for Mark or John regarding the overall CapEx of the $1.35 billion to $1.45 billion projected for 2019. How much of that is allocated for exploration in new areas like Louisiana as outlined in the K, or other regions?

Well, this is John. We don't typically discuss those types of high-risk exploration opportunities. However, if we were to pursue a specific drilling project, it would be so minor compared to the $1.35 billion or $1.45 billion that it would hardly make a difference. We're not drilling ten of these wells; they are very strategic, and we generally don't allocate much of our budget for them. These are unique opportunities that arise, and I would argue that they represent only a small fraction of the overall exploration and development capital we set aside for the company.

Can you discuss some of the activities you are undertaking in 2019 to prepare for 2020? It seems that production growth is expected to improve in 2020 with a similar level of capital expenditures. Are there any plans to prioritize certain assets over others or any significant programs you can highlight?

Well, this is John. I can tell you that we have significant drilling activity planned for the latter part of 2019 on various development projects in our Delaware Basin position, which will contribute significantly to 2020, even though they won't be producing in 2019. Some of these projects are on excellent acreage. However, I’m not sure this will lead to a noticeable change in oil growth. I do anticipate growth over time, but I don’t think we have factored in aspects like utilizing existing infrastructure. While we do consider that, I'm uncertain about what might lead to the conclusion you're suggesting. I'm not sure, Mark, or...?

I would also like to mention that I don't believe we see '20 as providing an extraordinary advantage. In '20 and even more so in '21, as our model transitions to full development, the benefits we anticipate from multi-pad development in '21 will likely represent a greater improvement compared to just '20.

Got it. No, that's helpful. And then can you talk about how you're thinking about capital allocation split between the Permian and the Mid-Con between 2019? And can we get a sense on what is the activity level needed to keep Mid-Con oil volumes flat?

I can take care of the first part. Mark or Joe can address the second part. We're in a competitive situation regarding capital allocation, and we aim to maximize value each year. While we have some ongoing projects, we evaluate everything anew every year. If we find better opportunities for value creation in one area compared to another, that's where we will direct our capital. We have significant long-term potential in both regions, which we believe is a sensible strategy. Since our assets are production-based and require us mainly to allocate capital to the most productive areas, the fact that we're investing 85% of our capital in the Permian this year does not necessarily indicate what will happen next year.

Although I believe the three-year plan includes that assumption, to Tom's point, it is uncertain. Any changes we consider would be aimed at improving the situation.

Yes, regarding capital, our three-year plan still allocates a significant portion, nearly 80%, to the Permian in 2020 and 2021. I don’t have specific figures for the breakeven oil forecast for Anadarko, but it's important to note that these plans are constantly being updated. As Anadarko seeks more capital, these plans will continue to develop, and we expect to see improvements as we refine our focus and identify better opportunities.

Yes, a plan is formed at a particular point in time. So as this point in time looks, yes, we look at the next three years and say it will be overwhelmingly Permian heavy. But as John said earlier in the call, we've really challenged our group to find some things that compete. And if and when they do, our plan gets modified.

I wanted to just ask you to talk a little bit about Lea County. I know it's a relatively small part of your budget for the year, but in the release, it talked about you have 3 really good wells, Third Bone Spring about, almost 1,500 barrels a day IP. So I was just wondering sort of about your expectations there for you going forward? And as for those wells you reported, I think 30-day IPs, just getting a sense of roughly when those were drilled? Are they just at the beginning of production? Or is this over a number of months?

This is John. I think the wells we made reference to are all drilled across our Lea County acreage. They're Third Bone Spring wells and most of them were brought on in the middle of the latter part of the fourth quarter. So we achieved 30-day rates, thus we could give you those averages. We still continue to hold a nice inventory. Third Bone Spring drilling, what's really nice about Third Bone Spring, is we talk about this in terms of cycle time, we can drill them one at a time. We don't like to do that; we like to at least do 2 wells, so that we can go multi-pad. But there is great flexibility with that program. The biggest issue you have is just whether your permits and whether you get them lined up soon enough to get that going. We have quite a bit of investment going on in Lea County, not just further Third Bone drilling, but we have a couple of really nice development projects, one that I already mentioned, which is Wolfcamp in Red Hills. And then later in the year, we'll be doing an Avalon development as well in the Red Hills area. So a good portion of our capital is going to Lea County. We see great returns there and we're very pleased with the position we have there.

That's great. I wanted to go back to the Mid-Continent. You've discussed the relative economics, but I'm curious, at this stage of the STACK play at Meramec, have we reached a point where there are many expired leases coming up? I'm wondering if you're seeing any farm-in opportunities for those unable to access their leases, which could represent some low-hanging fruit for you in that area.

This is John. In general, I'd say the answer is no, because at the initiation and the enthusiasm of the STACK play, just about every operator, just like us, went after and drilled at least one well on every section to get at HBP. So for the most part, within the areas that you care about the Meramec, or STACK, I would argue that no, I don't think you're going to see that big a churn, in that most of that acreage now is held by production. And it's just a matter of timing as to when people go forward and develop the acreage.

It's also a fairly active arena for a handful of small, well-funded private equity players.

Tom, while I understand you can't comment on the Resolute acquisition, there appears to be significant concern regarding the expected decline in capital efficiency in 2019 compared to 2018, followed by an anticipated improvement in 2020. Resolute recently issued an 8-K indicating that they expect first-quarter production volumes for oil to be lower than those in the fourth quarter. It seems like they may have paused operations after the acquisition was announced, especially since they had projected a considerable increase before that. Can we infer that some of the changes in capital efficiency you are observing are related to the steep decline you will face when you take over this acquisition? Will that affect the figures that people are examining?

Well, I don't know if it has an influence on capital efficiency, but look, we love this asset. We know it well. It's in our focus area in Reeves County. But I want to be clear, Cimarex is going to live within cash flow in 2019. Now the Resolute team did a fantastic job with that asset, but they were also on a fairly significant outspend. And so when we combine those two assets, when I say we're going to live within cash flow and not borrow money, that has an impact on both assets. It just logically does. So you can do the arithmetic and figure out what that means. And we look forward to being able to talk about it in a fuller way at the end of our closing next week. But we'll have a fair amount of activity, but the fact that we're going to live within cash flow and we're committed to that is certainly an overprint here.

I want to see if you can share any insights on Triste Draw, specifically regarding the 20 wells per section test in the Avalon, even though the data is still early. Also, what testing do you have planned for the Vaca Draw area in relation to the Avalon? Will it involve a similar 20-well per section test?

Yes, this is John. We are closely monitoring the Triste situation. To be frank, we anticipated that we were testing the upper limits of spacing. However, that can be beneficial, as it allows us to get quick answers to refine our approach for optimal results. It's reasonable to say that the landing zones selected for the Avalon test were too closely spaced with 20 wells. Nevertheless, we have plenty of additional acreage, and we are using those insights to enhance our strategy, particularly for the Vaca Draw section where we plan to develop Avalon. We have not yet determined the spacing for Avalon. We are evaluating the Triste findings as well as benchmarks from competitors. In the upcoming months, we aim to finalize the best development approach for Avalon in that region. I can confidently state that when appropriately spaced, Avalon yields some of the highest returns in our portfolio. It’s an exceptional reservoir, but we need to be cautious about avoiding overdevelopment. We will consider the Triste outcomes and soon determine the best way forward, especially regarding the upcoming development pilot for Vaca Draw Avalon scheduled for this year.

I was hoping you could provide some more color on around the performance drivers as outlined on Slide 10. And maybe specifically, hit on the increasing well productivity and the lowering of the production capital cost?

Well, I'll take a stab, and I'm sure others will chime in here. As I look at this list of our performance drivers, certainly, program efficiencies are a big piece. As we go into multi-well development, it really keys off to the third point of leveraging infrastructure. We have a lot of capital required with our program. The fact that our operating costs are so low is really a function of smart investments. And so saltwater disposal is one of those. The right facility size is another. Taking advantage of multi-well pads, all of those are strong performance drivers. And with development mode, you really can maximize the efficiency and leverage that. Well productivity is still a big part of our story. That's not only on a per well basis, but that's understanding new landing zones. And even a new landing zone can allow you to stagger your wells and make each well more productive. And then we're really focusing on engineering lower costs. We'd love to have lower cost from our vendors, but we're also looking at how can we engineer to shave 5%, 10% off our cost structure. So these are things that are real. They are things that a good learning organization should focus on, and we're absolutely focused on that. And Joe or John, do you want to comment on that?

From my perspective, we have invested significantly in our infrastructure, which has allowed us to be confident in the development potential of our acreage. We are now in a position to prioritize our development efforts based on where we can leverage our existing infrastructure, thereby reducing our upfront costs as we advance each project. We are just beginning to find our rhythm in this area. Our drilling program is increasingly being shaped by our current infrastructure rather than merely by acreage requirements or specific characteristics. This approach enables us to keep our overall costs down. Joe, do you have anything to add?

Yes, all these things we're talking about go into cost efficiencies. And you've heard Tom and John both mention leveraging our infrastructure. I'll give you an example that kind of coincides with us transitioning into smoother completion cadence: Our Brokers Tip and Sir Barton development projects. At the end of the year, we had 28 wells waiting on completion and just 6 coming on here in Q1. We intentionally pushed out those 2 development projects so that we could operate with one frac fleet so that we could make sure that we are fulfilling 100% of our water needs by recycling the water for those projects. In other words, we could have accelerated the crews, but then we would have had to haul water and buy water to finish the deals. So what it ended up doing was, I think it was 2/3 of our total well cost now on the completion side, we're really focusing on how to optimize all those costs. In that case, those wells slide into Q2, it's going to give us a smoother production cadence. It's going to help us save money. The drilling group is constantly focused on days to TD. They're challenging themselves with casing designs. On the completion side, John and our stimulation guys are constantly challenging ourselves on how to get cost down. I mentioned a few statistics that we obtained in that regard. Zipper fracs can save us anywhere from $200,000 to $400,000 per well when we can do them. Recycling, $0.5 million on a Wolfcamp well and what we're doing with local sand is having a big impact on our program, too. So these are all things that are in our working, day to day, with every one of our groups that's focused on cost efficiency.

Great. In your prepared remarks, you mentioned that the number of Delaware wells per section will be fewer in 2019 compared to some of the pilots from the second half of 2018. I'm curious about how much this change in development is influenced by a shift in strategy regarding the balance between rate of return and NPV versus positioning the company for $50 oil or the performance of some of the second half pilots.

Well, I want to clarify that in my opening comments, I didn't suggest less spacing in the Permian, but rather more so in the Mid-Continent, specifically in the Meramec section, where we're drilling anywhere from 3 to 5 sections compared to the previous expectations of 8 to 12. If anything, with the opening of the Third Bone Spring interval in Culberson, we might actually focus on increasing the number of wells per section in our Delaware position. So I'm not sure which comment you are referring to.

We have a strong economic philosophy regarding our developments. We are a learning organization, and although we observed that in hindsight we may have drilled our wells a bit closer than optimal in the Triste Draw, we don't simply retreat from that experience. Instead, we analyze it closely, considering well-to-well interference in terms of return rates and net present value. Our team recently reviewed another Avalon development, and we were very pleased with the thoroughness of their recommendations. We look forward to sharing more insights about our philosophy as the year progresses. This is a result of extensive scientific research we've conducted over the past couple of years. You might find that our conclusions are not immediately apparent, and as we provide more details on our approach to development, construction, and design, you'll see that our efforts have been highly beneficial.

Yes, I just want to thank everybody, there's been some great questions. Hopefully, we provided some color. We look forward to a further update once we get the Resolute acquisition closed, but I want to thank you for your interest and really just congratulate our organization on a great quarter and a great 2018. Thank you.