Good morning, and welcome to the Cimarex Fourth Quarter 2018 Earnings Release Conference Call. [Operator Instructions]. Please note, this event is being recorded. I would now like to turn the conference over to Karen Acierno. Please go ahead..

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 be referring to this presentation during the call today. The call this morning is focused on a discussion of the historical results of Cimarex and our 2019 guidance.

Due to the pending transaction with Resolute, we do not intend to address matters related to the same. However, subject to the satisfaction of conditions, including the approval of the Resolute shareholders, we expect to close the acquisition on March 1. Our full year guidance assumes the acquisition of Resolute closes on March 1.

We do not have comments on Resolute until after the expected closing. Also, this is not a discussion of securities involved or a solicitation of any vote or approval. You are urged to read the public filings with the SEC that contain information about the pending transaction. In addition, our discussion will contain forward-looking statements.

A number of actions could cause actual results to differ materially from what we discuss. You should read our disclosures on forward-looking statements on our news release and in our latest 10-Q for the year ended December 31. That was filed yesterday and there is also other filings for the risk factors associated with our business.

As always, we will begin 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 update you on operations, including production and well costs. CFO, Mark Burford, is here to help answer any questions as well.

[Operator Instructions]. And so with that, I'll 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 salute 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 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 percent. 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 83 net wells brought online during 2019, with our company-wide average lateral -- operated 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, these being 2 stream numbers.

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. I refer you to Page 22 in the presentation for the location of the Dupree.

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.

And then finally, due to the size of the project and resulting capital required, the previously planned Leota Woodford infill development project for now 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, really, 3 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 in -- 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 in March, 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 the mark, 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..

[Operator Instructions]. The first question will come from Arun Jayaram of JPMorgan..

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 tills 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 guess I didn't realize our 10-K was disclosing that. News to me, but yes, we do have a -- we've been able to accumulate a very nice acreage position in Louisiana and we are actively pursuing an exploration idea there. And that's what we always do.

And as we've often said, if indeed any of that is impactful, we have good results at some point, then we will speak more to it.

But yes, we have accumulated position there and then we'll see, okay?.

Arun, our goal is to grow our assets. And we think doing it organically is our preferred way. If we can find a bolt-on that makes sense, we love it. And that's what the Resolute deal is. But I want to say growing our assets can mean a lot of things. Certainly, exploration is an important part of that.

Leasing, finding new ideas, extending our footprint, and we're always working on that. But you know, there is also an opportunity to grow our assets by understanding our development and getting our well spacing right and then opening up new target zones. And I just want to reemphasize a couple of things John said.

That Third Bone Spring well in Culberson County is a whole new target zone that overlaps over our asset in Culberson County. That's a significant new data point for Cimarex. That was a well that had a fair amount of risk attached to it. In fact, that was a creative geological and engineering idea.

If you look north up dip, where you would think the oilier part would probably reside in a basin-wide fashion, those same landing zones are wet. And yet down dip, we had a geological idea that maybe we were in the right part of the basin for it to be oil bearing. We tested that well and it was a remarkable success.

And that interval maps and overlaps over almost most of that entire asset. So we want to grow our assets, and we want to do it through creative internal science and we -- as always, we need to do more of it, but I just -- I want to point out there's a lot of ways to do that..

The next question will come from Drew Venker of Morgan Stanley..

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 in 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 color.

I guess just as a follow-up, have you thought about the form that might take in addition to dividends, whether -- maybe 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..

The next question will come from Douglas Leggate of Bank of America Merrill Lynch..

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 expectation 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, and I'll make a few comments and hand off to Mark with regard to what we're seeing differential-wise in the basin and if that leads into hedging or whatever. But on the gas side, nothing has changed. We've secured those same sales arrangements.

We're very comfortably sitting at about 97% of all our residue gas in the Permian through pre-sales arrangements through the first quarter of 2020. We wanted to go out and beyond 2019. I'm sure you know that there is expansions in takeaway, in not only the gas side by the end of Q3, but also on the NGL and the oil side.

We've had really no issues on the liquids side. Our NGL production is linked to sales at the processing facilities with the processors for whom either have purchaser-backed or established long-term sales arrangements in place for those volumes. And likewise, on the oil side, same situation with who we are selling to. 78% of our oil is on pipe.

All of our -- I shouldn't say all, about 90% of all of our first quarter and second quarter oil new wells are going to be put on pipe. So we're anticipating that percentage to go forward. But more importantly, it's on pipe with people who have pipe out of the basin, and we've got sales arrangements put in place with them.

So we feel comfortable, as we did 3, 4 months ago, about the position that we're in to get our products sold. And from my end, I haven't seen any real changes in that regard.

Mark, I don't know if you want to speak to what we're seeing on the differentials?.

Sure. Kalei, this is Mark. Looking at differentials using the forward strip for Panhandle Eastern -- or for Waha and a passive Permian, you know, we're looking at it in $1.50, $1.25 for the next couple of quarters. Improving in the fourth quarter, it's up $1. Annual difference for '19 is looking at right around $1.25.

I will point out we are about almost 40% hedged for calendar '19, with Waha and the passive Permian collars. And that's obviously, in the range of those -- those collars are in a range of $1.45 to $1.80-type range collars. We do have some portion of our realization covered with collars in the Permian.

And as you look out into '20, you look at the forward strip, that price continues to improve with some of the pipeline expansion, so..

The next question will come from Jeffrey Campbell of Tuohy Brothers Investment Research..

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 is 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 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 actually brings up an interesting point and that's that you've discussed, I know '19 is not a big year, but you've discussed that you want to start to move to more of a multiyear type of planning cycle.

And once you kind of have that -- have comfort with that in place, would that actually lend itself to making the kind of investment you've talked about in the Woodford a little bit more practical as opposed to right now?.

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?.

Well, the answer to your first question, yes, we do now, as much as we have mapped its extent, and I think Tom alluded to that, it looks very prospective. We do now have a number of wells across the breadth of our Culberson position that we're going to be teeing up over the year to further delineate that as a landing zone.

I can't really -- as part of your second question, I can't speak to just overall, let's say, vertical communication and drainage, because this was just one well.

What we will be doing quickly in the near future is in some of our developments, we'll be adding this as a landing zone and then trying to determine how much is it draining relative to other wells, and then that will then lead to further decisions about the ultimate number of wells we'll put in this section.

Suffice it to say, it's very encouraging and exciting that we have been, over the years, pushing that upper landing zone higher and higher up in the section, which certainly is going to lead to more wells per section as we go and continue to develop this acreage position..

The next question will come from Jeanine Wai of Barclays..

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. In the '20 and '21 period, as you get out past '19, we are still working to get those cadence of predicted completions more steady and into those periods as well. But we do see, and as we discussed, in that 15% kind of annual growth in oil averages that period.

So but we're still working those plans, this initial kind of run-through those outer years, are still working '20 and '21 as we speak. But it's in that -- the cadence is in those years also improving in a flatter cadence and a steady growth.

But it is improving through '21 through efficiencies that we can continue to have more portion of our capital in full development. And see, as we do see capital improvements, efficiency improvements through '21..

Okay, great. That's helpful. And then my second question is on the Wolfcamp, and apologies if I missed this somewhere else in the call. But we noticed in the presentation that the returns for the Upper and the Lower Wolfcamp in Culberson County have declined since the last update.

And can you just talk about maybe what's driving this change? Is there some kind of change in the spacing assumption, or maybe the completion technique that might also assume -- have a similar effect in other parts of your portfolio? Or is this just a one-off?.

Jeanine, I'll jump in and answer that. So we run those sensitivities every -- I think this was six months ago that we updated it. So what happens is we use these forward-looking type curves and it's a blend of type curves across the acreage. What might not be included in here are some of the upper zones and things like that.

But it's really just adjustments to types curve. They may have come down, but in fact, they're all still very high. So I wouldn't get too concerned about movements and be more interested in just the improvement at -- with price.

And even the Lower Wolfcamp has good returns at -- I'm turning to look at John -- so at $50 oil, right? So let's say $45, which would be our $50 cage, so. It's just something that we've had in there for a while. It's slight changes in type curves that would cause those adjustments 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..

The next question will come from Neal Dingmann of SunTrust..

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?.

Well, I'm probably going to be pretty predictable in my answer. I think consolidation can make great sense. It can make the best sense when the assets that get consolidated are better off in the hands of the consolidator than they are in the original owner. And certainly, our 2 transactions in '18 were all about that.

We -- Ward County was better off in the hands of the purchaser. It wasn't competing for capital and they'll pay more attention to it. And we're pretty excited to be bringing in the Resolute assets for the same reason. And so I think consolidation can make sense. Now the consolidation can't be looked at in absence of the price.

So we would be very interested in consolidation, but only if it's a value-creation type transaction. So we're always in the hunt. We've been in the hunt for years. We'll continue to be in the hunt. We're delighted to be closing Resolute next week.

If there is another one that makes the kind of sense that Resolute does, we'd love to find another bolt-on, but they are few and far between, because we want to create and add value for the Cimarex shareholder..

Great, great details. I thought you'd kind of go down that line.

And then one last one maybe for Mark or John, just on overall CapEx of the -- I think the $1.35 billion, $1.45 billion you've got for '19, guys, how much of that is for some of that exploration, either newer plays like Louisiana, I guess, that you've outlined now in the K, or just any other areas?.

Well, this is John. We don't really -- like I said, a, we hardly ever talk about those type of rank wildcat opportunities, but even b, all -- if indeed, we embarked on a particular drilling well, it would be so small relative to $1.35 billion, $1.45 billion, that it would be a rounding error. It's not like we're out there drilling 10 of these wells.

They're very strategic and what we do typically, I don't even know that we spend much time in terms of budgeting for them. These are more just unique opportunities that we see. And I would, again, argue that they tend to be more of a rounding error on the overall E&D capital that we lay out for this overall company..

The next question will come from Betty Jiang of Crédit Suisse..

Can you please talk about what type -- some of the activities that you're doing in 2019 in preparation for 2020? It does seems like production growth improves in 2020 for a similar CapEx level.

So just wondering if there are some high grading of the program from one asset to another? Or if any high-impact program that you can point to?.

Well, this is John. I guess, all I can tell you is, and is, and I think Joe alluded to this, we have a lot of drilling activity going on towards the latter part of '19 on a number of development projects throughout our Delaware Basin position that will contribute greatly to '20 that do not come on in '19.

Some of them are -- yes, some of them are on some very good acreage positions. But I don't know that, that necessarily would lead to a significant change in the oil growth.

I do expect over time, but I don't think we've modeled that in, things such as taking advantage of existing infrastructure, and we do look at that, but other than that, I'm not sure what would lead to maybe the conclusion you are coming to.

I don't know, Mark, or...?.

I guess I would also comment is that I don't think we see necessarily '20 as being an outsized benefit.

'20 and '21, even more in the '21, as our model moves more to full development, and some of that spacing and some of the benefits we do see from -- benefits of multi-pad development in '21 is probably even a bit more of an improvement as opposed 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?.

Well, I can handle the former. I'll let Mark or Joe handle the latter. It's a jump ball here for capital allocation. We really want to generate the greatest value in any given year. And although we have some projects that have great continuity, we look at it fresh every year, and as I say, it's a jump ball.

If we have better opportunities for creating value in one basin over another, that's where we want our capital to flow. We've got lots of long-term opportunity in both basins. So that -- we think that's a prudent way to approach it.

Particularly to the extent that our assets are held by production and not requiring us to do anything other than flow capital to where it's most productive. So the fact that we're putting 85% of our capital in the Permian this year doesn't necessarily presage what's going to happen in next year..

Although I think that the three year plan makes that assumption, but to Tom's point, it's a jump ball. So anything that we would -- any changes we would make, we would think, would make it better..

Mark, you want to...?.

Yes, the only comment I'll make, just on capital, but we do, on the 5-year -- on the three year plan, it does have still a good proportion amount going to the Permian, nearly 80% going to the Permian, and '20 and '21 as well.

So as far as the trend has a breakeven oil forecast, I don't have a statistic on what the capital for breakeven Anadarko oil forecast is. But I'll just comment, again, it's still these plans are continually being evolved and as Anadarko were to compete for more capital, these plans would continually evolve.

But if anything, they'd be going to be improved as we high-grade and continue to see 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..

The next question will come from Noel Parks of Coker & Palmer..

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 a 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 terrific. I was wondering, just turning a bit back to the Mid-Continent.

I know you talked a lot about just the relative economics and everything, but I was just curious, at this -- at this stage of the play of the STACK at Meramec, have we hit a horizon where there is a fair amount of expired leases on the horizon where I was wondering if you were seeing anything like farm-in opportunities for people who can't get to their -- their leases out there, sort of a low-hanging fruit in that play for you?.

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..

It is..

And that's increased competition..

The next question will come from Mike Scialla of Stifel..

Tom, I know you said you can't say anything about the Resolute acquisition, but there seems to be a lot of concern about your projected decline in capital efficiency in 2019 versus '18 and then anticipated improvement in 2020 over 2019.

I know Resolute put out an 8-K here recently saying they anticipated first quarter production volumes, at least on the oil side, were actually going to be down from fourth quarter. I assume they kind of put things on hold once the acquisition was put in place, because I know they were forecasting a pretty steep ramp prior to the acquisition.

Is it fair to say that some of the capital efficiency changes you are seeing here are in relationship to -- will you are going to have to fight a steep decline when you take over this acquisition? Does that have an influence on the numbers people are seeing there?.

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..

That makes sense.

I want to see if -- I know there's just early data at this point, but anything you can say on Triste Draw, with the 20 wells per section test in the Avalon? And what kind of tests are you planning for the Vaca Draw area in terms of the Avalon? Is it a similar 20-well per section test there?.

Yes, this is John. We obviously are still watching the Triste very carefully. We knew, I'll just be very upfront, we knew going into it that we were pushing the upper limit on spacing there. But sometimes, that's good to do, because I'd rather get that answer right away, so that I can really hone in on what's optimal.

I think it's fair to say that for the landing zones we chose for that Avalon test, 20 wells was too tight. But that's okay. We still have a lot of additional acreage, and we're taking that learnings, that we then optimize our plan, say, like I mentioned earlier, for the Vaca Draw section, where we will be developing Avalon.

We have not finalized now what that spacing will be in the Avalon. We're looking at the Triste results as well as other competitor results. I hope to, in the coming months, we'll settle on exactly what's the best way to develop that Avalon in that area. What I do know is when properly spaced, Avalon generates some of the best rate of returns out there.

It's a phenomenal reservoir for us. But you definitely want to be careful in terms of not overdeveloping it.

So we'll take those Triste results and then here in the near future, we'll settle in on what's the right path forward for us, especially with the upcoming Vaca Draw Avalon pilot we're going to -- development pilot that we're going to do this year..

The last question today will come from Phillip Jungwirth of BMO Capital Markets..

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 sign -- 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?.

The only thing I'd add is from my perspective, we've made quite a bit of investments in our infrastructure, to the point now that -- and more importantly, that we've become very comfortable with the full development opportunity of the breath of our acreage that we're at a point now where we can pick and choose where to develop where we maximize the existing infrastructure.

That then minimizes our upfront cost as we go forward and bring forward each of these development projects. We are just hitting our stride in that regard.

I think more than ever, our drilling program, in some ways, is no longer being driven, say by acreage needs or obligations or maybe even a particular attribute, but more so by our existing infrastructure and taking advantage of that so we can keep our overall per costs down.

And Joe, as well...?.

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 can 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. And then in the prepared remarks, you commented about how the number of Delaware wells per section will be fewer in 2019 than some of the second half of '18 pilots.

And I was just wondering how much of the change in development is driven by a shift in thinking around balancing rate of return and NPV versus reposition -- or positioning the company for $50 oil or maybe performance of second -- some of the second half pilots?.

Well, I want to make -- this is John, and I'm clear that I believe that in my opening comments, I didn't really, in any way, infer less spacing in the Permian, more so in the Mid-Continent and specifically in the Meramec section, where we're going down anywhere between 3 to 5 sections versus previous expectations people had of 8 to 12.

If anything, because of our now opening up this Third Bone Spring interval in Culberson, we would tend to lean more forward to more wells per section in our Delaware position. So I'm not sure what comment you're referring to..

But I'll just follow up that we have a strong economic philosophy on our developments. We are a learning organization, and even as John said, things like the Triste Draw, where we see that we drilled the -- our wells probably in hindsight a little closer than optimum, we don't just look at that like we've touched a hot stove and back off.

We study it, we look at the elements of well-to-well interference, both from a rate of return and net present value. And our team was up here last week looking at another Avalon development. And they -- we were just so pleased with the thoroughness they brought to that recommendation.

We look forward to sharing some more data on our philosophy there as the year goes on. It's an outgrowth of a lot of the science we've done in the last couple of years.

I think you'll find that the conclusions are not obvious and that when you tear it apart and we're able to be more forthcoming with how we view our development, construction and design, I think you'll see that a lot of the effort that we've put into this has been really, really worth it..

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

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..

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect your lines. Have a great day..