Karen Acierno - Cimarex Energy Co. Thomas E. Jorden - Cimarex Energy Co. John Lambuth - Cimarex Energy Co. Joseph R. Albi - Cimarex Energy Co..

Drew Venker - Morgan Stanley & Co. LLC Michael Stephen Scialla - Stifel, Nicolaus & Co., Inc. Kalei Akamine - Bank of America Merrill Lynch Jeffrey Campbell - Tuohy Brothers Investment Research, Inc. Matthew Merrel Portillo - Tudor, Pickering, Holt & Co. Securities, Inc. Leo P.

Mariani - National Alliance Securities LLC Michael Anthony Hall - Heikkinen Energy Advisors LLC Josh Silverstein - Wolfe Research LLC Michael Dugan Kelly - Seaport Global Securities LLC Noel Parks - Coker & Palmer, Inc..

Good day, and welcome to the Cimarex Energy Second Quarter (sic) [Third Quarter] (00:03) 2018 Conference Call. All participants will be in listen-only mode. [Operator Instructions] After today's presentation, there will be an opportunity to ask questions. [Operator Instructions] Please note, this event is being recorded.

I would like to turn the conference over to Karen Acierno, Director of Investor Relations. Please go ahead..

Thanks, Francesca. Good morning, everyone, and welcome to our third quarter 2018 conference call. An updated Cimarex presentation was posted to our website yesterday, so we may be referring to this presentation during the call today. As a reminder, 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 three months ended September 30 which was filed yesterday and our 10-K and other filings for the risk factors associated with our business.

So as always, we will begin our prepared remarks with an overview from our CEO, Tom Jorden, followed by an update on drilling activities, and results from John Lambuth. And then Joe Albi, COO, will update you on operations, including production and well costs. Our CFO, Mark Burford, is here to help answer any questions you may have.

And as always so that we may accommodate more of your questions during the hour we have allotted to the call, we'd like to ask you that limit yourself to one question and one follow-up, feel free to get back in the queue if you like. And with that, I'll turn it over to Tom..

Thank you, Karen, and thank you to all who are joining us on the call this morning. We're pleased to report that Cimarex had a very good, active third quarter. We invested $500 million in exploration and development activities. $400 million of that was drilling and completion.

We completed, flowed back and analyzed some important development projects which furthered our growing understanding of optimum economic development of our reservoirs. We are seeing excellent robust returns on our invested capital. As always, return on invested capital is our guide.

Production growth is an outcome of our focus on returns, not a primary driver. Our net daily production averaged 218,600 barrels of oil equivalent per day which was above the high end of our guidance. We averaged 63,909 barrels of oil per day in the quarter which was in line with our guidance.

Also, during the quarter, we closed the sale of our Ward County assets and further increased our dividend. We generated strong earnings and cash flow during the quarter and are on track to deliver solid performance during the fourth quarter of 2018 as well.

Our definition of solid performance is very good return on invested capital underpinned by seamless field execution. As we complete the transition to development projects, field coordination and timing of multiple moving parts have increased the execution challenges. Our organization has adapted and risen to the challenge with few operational hiccups.

Our production ramp continues. We brought 46 wells on line during the third quarter and expect another 34 to be on production by year-end, bringing the total to 119 wells for the year.

On a pro forma basis, adjusting for the Ward County sale, we project total production to increase 17% to 18% year-over-year with oil production set to increase 21% to 23% year-over-year. Furthermore, we project that our Q4 2018 oil production will increase 29% to 38% over Q4 2017.

Most importantly, this production ramp is a result of a program that is generating outstanding returns. We have the economies of scale to deliver increasing capital efficiency and maintain an industry leading cost structure. Furthermore, we have great confidence that our assets and organization make these results highly repeatable.

We are well-positioned for the environment ahead with decades of high quality inventory. We can compete with the best.

As our program transitions to one that is dominated by large scale development and we transition to a more repeatable multi-year development pattern in 2020 and beyond, we think establishing a consistent program within cash flow and returning excess cash to shareholders is a prudent approach that fits our business.

Our experience tells us that capital programs that expand and contract with rising and falling commodity prices and cash flows leads to inefficiencies. Furthermore, these complex development projects require long lead time for planning, design, permitting and infrastructure. Effective execution requires a multi-year plan.

Beginning in 2019, we will formulate our multi-year program budget around a flat NYMEX oil price. This will allow us to plan on consistent, repeatable programs that allow us to maintain and improve capital efficiency. We have the assets for it. We have the organization for it. And as we have demonstrated over the years, we have the discipline for it.

Our strong consistent profitability is no accident. As we look ahead, we expect to have an active 2019 with a capital program that modestly outspends cash flow. As we have previously discussed, we'd like to deploy some of the cash on our balance sheet into high return development projects.

This is entirely discretionary and driven by the outstanding returns within our portfolio. We can grow our assets and generate cumulative free cash flow over the next three years at a flat $55 WTI price. Keep in mind, we define free cash flow as cash flow from operations less our full exploration and development and midstream capital expenditures.

Finally, good science counts in our business. During the year, we've continued our habit of curiosity and continue to collect and analyze data that has led to a deeper understanding of optimum development. Furthermore, we have also studied our competitors' results in each of our operating neighborhoods.

We are confident that we have gained a more complete understanding of optimum reservoir development calibrated by both our study of our results and our competitors' results. Our philosophy of optimum development differs from many of our peers.

As we have said in the past, optimum development involves a tradeoff between maximizing rate of return and maximizing net present value. We seek to optimize net present value at a discount rate in excess of the standard 10%, such that the last incremental dollar invested competes for capital within our portfolio.

Our philosophy here is a direct consequence of our culture of science, innovation, and our relentless focus on value creation. We're ready to go into full development in a manner that creates value and does not over-drill nor under-drill. We invite you to watch us as we further develop our assets. As they say, the proof is in the pudding.

I look forward to sharing a more detailed outlook with you soon. With that, I'll turn the call over to John for additional detail..

Thanks, Tom. During the third quarter, Cimarex invested $500 million in exploration and development activities of which $400 million was invested in the drilling and completion of new wells. 74% of our drill and complete capital was spent in the Permian region and 26% in the Mid-Continent during the quarter.

We brought 120 gross, 46 net wells on production during the quarter and are currently operating 16 gross rigs with 12 in the Permian region and 4 in Mid-Continent. We now have three completion crews working across our acreage. Now, onto some specifics about each region.

In the Permian, we brought 40 gross, 26 net wells on line during the third quarter, including 8 wells in the Snowshoe project, an Upper Wolfcamp spacing test in Reeves County, Texas. On line since mid-August, these wells are contributing to our second half production ramp with early results matching our pre-drill expectations.

Our second spacing pilot in the Wolfcamp section, the Animal Kingdom, consists of 8 10,000-foot laterals in the Lower Wolfcamp in Culberson County, Texas. These wells which, we are testing the equivalent of 14 wells per section, began producing in late September with all 8 wells contributing to fourth quarter volumes. Moving into Lea County.

We have 30-day rates on several exceptional new wells drilled in the Red Hills area. Highlighted on slide 16 of our presentation, you can see the Red Hills Unit 17H. This is a long lateral Upper Wolfcamp well that had a peak 30-day production rate of 3,611 barrels of oil per day, 5,164 barrels of oil equivalent per day.

We drilled another long lateral Upper Wolfcamp well called the Vaca Draw 20-17, also in Red Hills, that had at a peak 30-day IP of 3,032 barrels of oil per day, 4,645 barrels of oil equivalent per day.

On the same Vaca Draw lease, we also drilled a Leonard well that had a 30-day peak IP of 2,522 barrels of oil per day, 3,413 barrels of oil equivalent, and an Avalon well that had a 30-day peak IP of 2,051 barrels of oil per day, 2,733 barrels of oil equivalent per day, all fantastic long-lateral results.

In Northern Lea County, we continue to have good results drilling wells in the Third Bone Spring. The Lea 7 Fed 2H (00:11:03), a one-mile lateral, had a 30-day peak IP of 2,165 barrels of oil per day, 2,638 barrels of oil equivalent per day. And last but not least, we have completed a sixth Upper Wolfcamp well on the western side of Culberson County.

The Carry Back 6 State A 1H, which was our first lateral landed in the ex sand (00:11:20), had a 30-day peak IP of 2,446 barrels of oil per day, 4,220 barrels of oil equivalent per day. That brings our average on the wells drilled in this area to 1,933 barrels of oil per day, 3,427 barrels of oil equivalent per day.

As we look ahead, the Delaware Basin holds a vast opportunity for Cimarex. The 12 rigs we currently have running are drilling multiple development projects across our acreage position. We look forward to giving you more details on these projects when we announce our 2019 plans.

Now onto the Mid-Continent, completion operations are finished on the Meramec Steve-O development project which consisted of six 10,000 foot laterals stack staggered in two benches. This pilot which is currently flowing back, is testing the equivalent of eight wells per section spacing.

We are now currently drilling or completing on four additional Meramec development projects across our acreage position with first production expected from these new projects in the first quarter of 2019.

In the Woodford Lone Rock area, the Shelly and JD Hoppinscotch spacing pilots began production in the third quarter, with both contributing to our end of the year production ramp. We also drilled and brought on two impressive 5,000 foot laterals in the liquid rich portion of Lone Rock.

The Sweeny 8-24H achieved a 30-day peak rate of 1,755 barrels of oil equivalent per day, 667 barrels of oil per day while the Kim Anderson Farm 1-23H had a peak rate of 2,164 barrels of oil equivalent per day, 717 barrels of oil per day.

And then finally, we are also getting ready to commence drilling in the Woodford on our Leota section located in the liquid rich 13 North-8 West Area. This 11 well, long lateral development project would begin drilling by year's end with completion of the wells currently scheduled in the second quarter of 2019.

With that I'll turn the call over to Joe Albi..

Thank you, John and thank you all for joining us on our call today. I'll touch on the unusual items. Our third quarter production, our Q4 and resulting full year production guidance, and then I'll follow up with a few comments on LOE and service costs.

With the reported net daily equivalent volume of 218,600 BOEs per day, we had another solid quarter for production in Q3, beating the upper end of our guidance range of 206,000 to 215,000 BOEs per day and once again setting a new company record for equivalent production.

Our guidance beat was driven primarily by NGL volumes which came in higher than forecasted. With 46 net wells coming on line during the quarter, our Q3 oil volume came in at 63,900 barrels per day, slightly above the midpoint of our guidance range of 61,500 to 64,500 barrels per day.

We remain on track with our projected ramp up in completion cadence during the second half of the year. Year-to-date through Q3, we've completed a total of 84 net wells with more than half coming on line this past quarter. We're forecasting another 34 to come on line in Q4, resulting in a total of 118 net wells for the year.

This is six fewer wells than we quoted last call, primarily related to completion timing and scheduling changes. Even with the slight changes, our strong completion momentum which began in September is projected to significantly ramp up our Q4 volumes.

Our updated model is projecting Q4 net equivalent daily volumes to average 238,000 to 247,000 barrels equivalent per day, with Q4 oil volumes in the range of 73,000 to 78,000 barrels per day, giving us an oil midpoint just above the low end of the range that we quoted last call.

This slight shift in our Q4 oil guide is solely related to slight timing adjustments and not due to any change in anticipated well performance, With early estimates for October on the oil side of production now just coming in, we have high confidence in our current Q4 oil guidance range.

Adjusting for the Ward County asset sale, our Q4 2018 equivalent volume guidance range is forecasted to be up 23% to 28% over Q4 2017 with our Q4 2018 oil guidance up 29% to 38% over Q4 2017 oil volumes.

For the year, we're projecting total equivalent volumes of 218,000 to 221,000 BOEs per day with oil volumes in the range of 66,000 to 67,200 barrels per day, in line with our estimates last quarter of 214,000 to 221,000 BOEs per day for equivalent production and 66,000 to 68,000 barrels of oil per day for oil production.

Jumping to OpEx, our Q3 lifting cost came in at $3.79 per BOE, that's slightly below the low end of our guidance range of $3.80 to $4.30 and down $0.33 per BOE from where we were in Q2.

Although we continue to see cost pressures on items such as saltwater disposal, compression and power and fuel, with the closing of our higher production cost Ward County properties now behind us and our focus on controlling LOE, we've dropped our projected lifting cost guidance to $3.35 to $3.80 per BOE.

And lastly, some comments on drilling and completion cost. On the drilling side, we've recently seen rig rates go up 10% to 15%. And we've also seen some minor cost pressures in items such as diesel and oil-based mud. That said, with our focus on efficiencies, the drilling portion of our AFEs have stayed mostly in check.

On the completion side, we've seen some recent softening in service cost and have also realized additional cost savings through local sand sourcing in both the Permian and in the Mid-Continent. And as a result, through operational efficiencies, local sand sourcing and water recycling, we've lowered our total well cost AFEs.

In the Permian, depending on area, interval, facility design and frac logistics, our current Wolfcamp 2-mile AFEs are running $10.9 million to $13.4 million. That's down $100,000 from our estimate last call.

Our deeper 1-mile New Mexico Bone Spring AFEs in Northern Eddy and Lea Counties are also down about $100,000 from last quarter with a range of $6.9 million to $8.4 million. In our East Lone Rock area, with the benefits of local sand pricing, our 1-mile lateral Woodford AFEs are running $7.3 million to $7.8 million.

That's down $200,000 from last quarter. And with local sand pricing and a refined completion design, we've lowered our 2-mile Meramec AFE $1 million from last quarter with a range of $10.5 million to $12 million. So in closing, we're coming off a great third quarter. We beat the upper end of our Q3 equivalent volume guidance.

Our Q3 oil production came in above our guidance mid-point. We're projecting pro forma Q4 2018 oil growth of 29% to 38% over Q4 2017. Our lifting cost and our total well costs are down from last quarter and our drilling program continues to churn out favorable results. So with that, we'll open it up for question and answer..

We will now begin the question-and-answer session. First question comes from Drew Venker of Morgan Stanley. Please go ahead..

Hi, everyone.

Can you hear me okay?.

Yes. Thank you..

Hi, Tom. I was hoping you'd just give a little bit more color on that multi-year planning process you spoke about in terms of lead times from spud to first production.

How many wells per pad you typically have and how much (20:30) on those bigger pads in general? And then you mentioned a kind of static commodity price for that multi-year budgeting process. If you have a price in mind there, that'd be helpful to hear..

Well, there's a boat load of questions in there, Drew..

Sorry, Tom..

We're certainly looking at multi-year planning because it's what our business guides us to. These development projects take a lot of coordination of multiple moving parts.

And if you look at – it's one thing to say you put it on paper and you say we're going to drill 12, 18, I mean, you pick the number of wells, but by the time you look at the various elements that have to come together so it's all coordinated and ready when you're flipping the valve on first sales, it's a lot of moving parts and we need a long lead time to plan, to innovate, to design, to debate.

And so, annual planning cycles don't fit our business anymore. We've always carried multi-year plans but we've just been hesitant to commit to multi-year plans. Well, the world is changing and we change with it.

We're at a point now where we're willing to say that we'll commit to multi-year programs, and in doing so we'll underpin that with an estimate of our cash flow and cash available to invest that's based on a price file we feel good about. Now, we deliberately didn't give a number.

I will say that the budgeting price file's going to be a flat NYMEX price that's below the current strip average to leave us a little cushion so that we can plan and deliver that capital program we execute on.

So, the particular number is less important than the fact that I think you can count on it being a number that's conservative and leaves us some room for downside fluctuation in our cash flow. As far as your question on how many wells, that is going to be area-by-area, section-by-section.

I mean, I really want to underscore what I said in our opening remarks. We have learned a tremendous amount about managing these reservoirs and we really want to go for optimum development. And that will change over a play. It can change over the course of one or two miles. But we don't want to leave any stranded assets.

We don't want to leave any stranded value. And you're going to see us embark on fairly robust, well-planned, well-executed development..

Thanks for that, Tom. As a follow-up, the operational results were very impressive this quarter. Lea County, in particular, stood out in my mind. Is that an area you would expect to increase activity in 2019? And maybe you can just talk more broadly about the whole program.

I think you've had a wealth of learnings this year probably from your program as far as which areas really stood out in terms of surprising to the upside or just being bright spots within the portfolio that would draw more capital next year..

Yeah, Drew. This is John Lambuth. As we stated in the past, we've always known that Red Hills is a very attractive investment opportunity for us and that's been demonstrated by the wells we just brought on. I don't think they were that big of a surprise.

I mean there's a lot of other competitors drilling around us, but I would say with our frac design and the way we go about it, yeah, we're very pleased with that area and we do expect to invest some additional capital in that area along with our other very high rate return areas like Culberson and Reeves, and other parts of New Mexico.

The other thing we still are exploring, even within there, and all of our assets in the Permian, we're still looking at other landing zones. As Tom alluded to when we get the full development, we want to make sure that we are capturing all the resource potential there.

And so in each of our areas we still continue to do that as evidenced by the Carry Back well that I announced which was that ex sand (00:24:44) landing in Culberson. And that's a very key part of our program. As Tom said, to make sure when we go to development we're not leaving any resource behind..

Thanks for the color, guys..

The next question is from Michael Scialla of Stifel. Please go ahead..

Yeah, good morning, everybody..

Morning..

Morning..

I wanted to follow up on the multi-year plan. Is that something you're willing to share with investors and Tom, you mentioned part of that would be returning cash to investors.

Is the preference there for a dividend increase or would you be willing to have a share buyback program as part of that?.

Well, the first answer is yes. I don't know how granular we'll be, but we will be communicating what our outlook looks like and that includes a multiyear. As always, these things are subject to change and that's one of the things that has always led to some hesitancy on us. But if we're going to commit to it internally, we'll communicate it.

I think that's only fair. As far as returning cash to shareholders, nothing's off the table and that's always been our position. We certainly want to have a healthy and growing dividend, and who's to say what that means in the future.

I mean, I think one of the things that we'll say is we find dividends to be more sustainable, more predictable from an investor standpoint but nothing is off the table. If we have excess cash, we think it's fair that our owners would expect us to share that with them..

Very good. Thanks. And then, I want to ask on just your development. You said you're part of this three-year plan is by 2020 it sounds like you're going to be well into full development in most of your areas. Can you say where you are right now in terms of development versus delineation.

I don't know how to – if it's in terms of number of wells that you're bringing on percentage wise. I guess, when I look at your well performance I don't know if I'm comparing apples-to-apples when I compare it to peers.

My gut feeling is you're further along in the development and you're drilling more development wells than a lot of your peers are at this point..

Well, we're always going to be learning as we go and with John's comment on new landing zones, that's an important point. That Carry Back well was a landing zone that was new to us, at least in Culberson County.

We continue to be surprised by additional landing zones and the challenge is with the reservoirs that we currently have and currently understand, we could go in full development mode with a high degree of confidence that we would understand the required well spacing and do it in a way that's prudent and not wasteful.

Now, we probably couldn't have said that 12 or 18 months ago. But today, we have a high degree of confidence that whether we're talking about the Woodford, the Wolfcamp or I'll even add the Meramec, we really have a high degree of confidence that if we were to go into development, which we are, that we'll space those reservoirs appropriately.

Challenge is, we're still getting surprised to the upside with some of these new landing zones, a number of which we haven't discussed and aren't ready to discuss. But when you have a new landing zone, if it's in hydraulic communication with the reservoirs you're developing, you need to incorporate that upfront.

So, there are areas where we're ready to roll and over the next few years that will certainly populate our program and we'll have a high degree of confidence. But our assets continue to surprise us to the upside and that's an exciting thing to be able to say to you..

Thanks, Tom..

The next question comes from Doug Leggate of Bank of America Merrill Lynch. Please go ahead..

Hey. Good morning, guys. This is Kalei Akamine on for Doug..

Good morning..

Good morning..

So, Permian production in the quarter was flat despite bringing on two times more wells as in the prior quarter. Just wondering what was holding back growth in this quarter? And here in 4Q, you're slacking frac capacity.

What's the rationale there? Will 4Q be drilling-focused and 1Q be more completions-focused? And can we expect this cadence quarter-in, quarter-out through 2019?.

Yeah. This is Joe. With regard to your question about the Permian completion count, most of those wells were completed in the later part of the third quarter and have a cleanup profile associated with them. So the majority of their production is obviously contributing more to the fourth quarter than it was the third.

So you've got that timing built into all that. And as far as the frac utilization, our plans are to continue with the three frac leads that John mentioned in his call for the remainder of this year to knock out the majority of the wells that we had scheduled for the fourth quarter.

And on that note, I'd mention that about half of those 34 that we mentioned for Q4 have already been fracked..

Sure. How do you guys think about maintaining your operational momentum? Does it at all hurt you to rotate the frac crews in and out? Surely at some point, you'll be picking up additional frac crews..

Yes. This is Tom. We really do like to have a consistent operational footprint. Doing herky-jerky, bringing crews in and out really does lead to lowered operational efficiency. And just to your prior question, our goal here is to get our program to one that's more consistent on well count quarter by quarter.

We really see that as in our benefit operationally. It's going to take us a little time to transition into that but certainly as we look ahead, we're going to be achieving a more uniform quarterly cadence..

Thanks for that. And for my follow-up, just on NGLs. So this was a really strong quarter where realizations beat across the board, particularly for NGLs. Obviously, there is a price disparity between Conway and Belvieu.

Can you talk about your ability to sell into premium markets and find premium pricing? And as a broader comment, can you talk about the status of the industry frac capacity whether they're full or not? And do you see this being a bottleneck to near-term growth?.

Yes. This is Joe. Our – as we mentioned in our prior calls, all of our NGLs are – the sale of which are linked to processing facilities with whom we have either purchased or backed firm or established long-term sales arrangements in place. So with regard to concerns about constraints, we feel very confident there.

I think you saw today, there was an announcement about an additional 55,000 barrels a day of capacity being expanded in Texas and Louisiana. That's on top of that entity's recent 150,000 barrel a day announced expansion.

So to tell you what the outlook is going to be for the industry from a frac space standpoint, I can't give you the exact numbers but what I can tell you is that we feel that our products are adequately covered, number one.

And we're seeing a number of these brownfield projects hit the radar just like we saw in gas and oil that hopefully get us through this tight space..

Thanks for answering my questions, guys. We'll look forward to seeing you next week in Miami..

The next question is from Jeffrey Campbell of Tuohy Brothers. Please go ahead..

Good morning. Results from Devon's Mid-Con spacing test north and northeast of your 14N-10W area lead them to conclude four to eight wells per section, Upper Meramec targeting and flowback control will best enhance capital efficiency, production volumes and advantaged oil cut.

I don't typically ask comparative questions about other companies' results, but I know that Cimarex and Devon have a relationship and I am guessing you were either involved in some of these tests or were watching them closely. So I was curious about your view of their conclusions.

And I noticed that their numbers seemed very consistent with some of the ongoing tests that you're conducting that are broadly in the area..

Yeah. This is John Lambuth. You are correct in that we do have line of sight to Devon's operations. And that particular one you're mentioning, we have analyzed their data and we see the well results there. I would just simply say, our go forward model in the Meramec is basically three to five wells per section and that's where we are.

In order to achieve a maximum PV rate of return as Tom mentioned, we are at three to five wells per section..

Yeah. That's on our assets. That's not to speak to anybody else's assets. We don't have overlap..

Right..

But we're pretty confident. And I'll just say one other thing. As I've said in the past, we love the Meramec. We're getting outstanding returns in the play. We are also carrying a fairly low entry cost into the play. And it is competing for capital with the best of the best. We are and have had outstanding results in the Meramec.

But clearly from John's answer, the well spacing is probably a little less than I think what was initially represented, not for Cimarex but perhaps by others. And our go forward is full steam ahead and we're very enthusiastic about the play..

Well, I appreciate that color. And just as a quick follow up to that question. Am I correct when I look at the – let me make sure I give you right slide here. When I look at slide 19, it looks like that you're testing a little bit tighter spacing in the Lone Rock area, which of course is pretty far away from where we're talking about right now.

Is that correct?.

Well, it is except – what you're alluding to. Lone Rock is Woodford drilling and not Mississippi and our Meramec drilling.

So that's a different spacing, okay?.

Right.

So we're basically, we're saying that the Woodford may potentially be able to support tighter spacing but the view on the Meramec is three to five going forward?.

Yeah. No, Woodford spacing is without a doubt much tighter. In fact, as I alluded in remarks. Our next big development project which is Leota we'll be drilling 11 additional wells in that section, in addition to the parents, so that's 12 wells per section in the Woodford.

So yes, much tighter spacing, and we do that with very great confidence in our expectation of well results there..

And I just want to add when we quote three to five, that's an average over the bulk of our assets. I mean there are places where you're going to have eight so we're not we're not saying that the reservoir won't support that but we're talking about the way we view the play on average..

No, understood. All these plays have oil sweet spots but I follow you.

And if I could ask as a follow up question, and again I want to make sure I'm interpreting this correctly, when I look at slide 16 and all the little colored dots on there it looks like that Vaca Draw is the only area where you've actually tested three zones within roughly a fairly close together area.

And I was just wondering, I mean they're being developed in some proximity. I was wondering is this – moving forward is this a simultaneous multi-zone approach.

Could there be one in the future or are these always going to sort of be discrete from each other?.

Well, I would say number one we're not alone out here that a lot of our competitors have tested many of these zones in addition to us. So we have a lot information from them that tells us what's prospective or not.

And then secondly we see a lot – I mean there's optionality that we can develop Upper Wolfcamp independent of, say, Avalon, independent of Bone Spring. So we don't see that they have to be co-developed. We tend to think of it more that we would do one bench.

And then as those decline off, take advantage of our infrastructure and then come in and do the follow-up bench..

Okay. Great. So yeah, that's very good color. I appreciate that. And you're right, there's no question it's a very active area with great results. So thank you, again. Congratulations on the quarter..

Thank you..

The next question is from Matt Portillo of TPH. Please go ahead..

Good morning, all..

Hi, Matt..

Good morning..

Just one quick question for me. Tom, you have a large cash balance build post the sale of your Ward County asset and a capital program that appears to be inflecting towards a fairly material free cash flow profile beyond 2019.

Just curious how you guys are looking at the potential use of proceeds from that asset sale, especially given your under-levered balance sheet and an equity that's trading at a steep discount to long-term value..

Well, that's certainly a question and we've had it before. And we'll deploy some portion of that cash in 2019. I've already said that. And that will – depending on what happens with our cash flow in 2019, we'll have cash balance on our balance sheet at the end of the year. Matt, all I can tell you is we're going to be opportunistic.

We're going to be disciplined. And I would rarely say trust me, but I'm going to say that here, that we've had a long history of making good, prudent decisions with our shareholders' money and we will do that. There's lots of things that are on the table and nothing is off the table.

I said that in my opening remarks that would be – certainly deploying the capital, but also returning it to shareholders remains on the table. So I think you can count on us using that cash prudently. The fact that I don't have a specific answer, specific for you this morning is just something I'm going to have to tell you trust us..

Thank you. We'll look forward to some incremental color in 2019. Thanks, guys..

The next question comes from Leo Mariani of NatAlliance Securities. Please go ahead..

Hey, guys. I was hoping to dig in a little bit more to some of these very strong well results you had in New Mexico. I know you guys said that you weren't surprised by them; obviously there's been some very strong industry results.

But just curious to see if there were any major changes maybe made to drilling or completion design over the last say several months which kind of led to better wells.

What can you sort of tell us about that?.

Well, this is John. I would just say as a follow-up to what Tom said, we do a lot of science on our completions, our design of our completions and I think that shows through with our well results. I think we are top notch when it comes to how we design our frac designs. And I think the proof is in those results themselves.

So I'm very proud of our team and to be fair, we do learn a lot from our neighbors. I mean we keep an eye on our neighbors and how they drill their wells, where they land them, how they complete them. And I think that shows through with these results we have here..

Okay. And I guess just want to go back to last quarter's call, where I think you guys talked about potentially slowing down Permian completions a little bit in 2019 if diffs were wide. I guess we're now in a position where diffs have narrowed considerably. Just wanted to get a sense of sort of where we stand on that..

Well, what I communicated poorly in the last call was that any incremental activity in the Permian wouldn't show up till second half when diffs would narrow. We ran a lot of sensitivities around having our activity mirror this diff and we came to the conclusion that that's chasing our tail. So we're forging ahead with a consistent level of activity.

We're delighted to see that the differentials have narrowed as they were predicted. I think as we talked at the time, we thought some of the fear that was baked into that was perhaps emotional rather than data driven. But we're going to live through it and we're glad to see them narrow..

All right. Thank you for the color..

The next question comes from Michael Hall of Heikkinen Energy Advisors. Please go ahead..

Thanks. Congrats on a very solid update. I just wanted to I guess kind of come back to this multi-year planning process and kind of think about it I guess in the context of the current program as well as some of the disclosures you guys have in the deck, I think slide 30. That growth sensitivity case is a good bit below the current capital program.

I mean, on our numbers on the strip, you have a pretty modest little outspend if you keep a similar looking capital program next year than this year.

So I guess I'm just trying to think through like, are – is this slide 30 intended to anchor us in any particular place? If not, then like how should we think about the program going for – relative to how much free cash flow you really want to be generating on a go-forward basis? Are there any sort of target metrics we can calibrate around – or just any additional thought process on how much free cash flow you guys are contemplating would be helpful..

Well, the slide 30, the $1.2 billion on growth sensitivity or the $700 million on maintenance CapEx, that's drilling and completion capital. And so, when you look at our total capital, it includes – we always look at total capital when we talk about our top level returns.

But I'm going to sound like a broken record, which is one of my most charming traits. We don't target growth; we target investing capital prudently.

And so, when we look at multi-year plans and we talk about doing that on a flat case such that we can commit to those plans, that's really about giving ourselves the opportunity to deliver outstanding returns as we go into development mode.

Now, the nice thing is – and we will be giving you some additional color on this when we can and not – but we've got a very, very good outlook. We can grow significantly, investing significant amounts of capital in a cash flow program that's healthy, robust at fairly modest commodity price assumptions.

So we don't really have upper or lower bounds on our desire to grow. What we want to do is invest our shareholders' money to get industry-leading returns. Our profitability, our return on capital employed, and our history, I think, speaks to that and we're not changing our stripes..

Okay. I guess, as a follow-up, maybe I'll come more near term, you guys have a lot of wells obviously that came on here in the third quarter, a lot of wells coming on in the fourth quarter, a pretty big uptick on oil production.

Is that level of oil production sustainable do you think as we head into the first half of 2019, let's say? I'm just trying to think through how sustainable you see that..

Yeah. This is Joe. I'll take a stab at that. I mean, we're not going to be talking about 2019 oil volumes in this call. But what we are seeing, I mentioned in my initial discussion that we had some early results for October and those early results for October give us very high confidence in the volumes that we're quoting here for Q4.

We've obviously tapered down our completion activity, dropping from six frac fleets and down to our current level, three. So, some of that's going to play into the tail end of Q4 and into early 2019..

Okay. Thanks for the time..

The next question comes from Josh Silverstein of Wolfe Research. Please go ahead..

Yeah. Thanks. Good morning, guys. A lot of questions have been asked already but you mentioned a little bit of the transition to get you on this consistent path.

Is that something that comes in the first half of 2019 where it's a bit of a flatter outlook, that then puts you on a bigger ramp towards 2020 and then starts the consistency in growth then?.

Well, we really haven't given any color on 2019. And we'll do so soon, but not – we're not ready on this call.

But what I said is ideally when we get to steady state in a perfect world, we'd have steady state quarter by quarter by quarter and have a level of activity and well completions that are evened out and not subject to large ramps during the year. It's going to take us two or three quarters to get there.

So although – I say that, let us defer that to when we show you our 2019 capital plans. But if I leave you with the only answer we can definitively give you today is that we are committed to that goal and we're going to get there..

Got it.

And then just in terms of the consistency as far as activity goes or growth goes, is it more consistency in terms of at a flat crude oil price the rig count is going to stay or well count is going to stay at a certain level, or can – if we're assuming $55, does the rig count still grow and then free cash flow continues to grow with it?.

Well, we do have the ability to grow our cash flow and we have the ability to grow our program. But it's going to be a function of things that we don't foresee. It's certainly a function of outlook on commodity prices. It's a function of supply and demand. It's a function of our outlook on our business and what our assets deliver.

I mean, we do have the optionality to grow fairly significantly within our cash flow. So I'm not answering your question, but what I want you to take away from that is that it's at our discretion..

Yeah. Got it.

And I guess maybe just in terms of capital allocation, is there any reason to think it would shift much from what it's been in 2018 going forward or is it still kind of roughly that maybe 70-30 split, around there?.

Well, this is John, and again we're not really talking about 2019. But as Tom said earlier, we chase the best returns. And right now, given commodity prices being where they are with oil and gas, our top flight returns are in the Delaware Basin which is reflective of how our capital is going there.

That's not to say again we do have excellent return opportunities in Anadarko such as the Meramec and such as the Leota project that we announced. But by far, the larger inventory of that is in the Delaware and that's reflective of what we're doing now.

And I would just say if prices stay about where they are, it'd probably be reflective how we go forward..

Yeah. But as we said in the past, if we rank our top 10 type curves, typically three or four of them are in the Anadarko Basin and six or seven are in the Delaware Basin. So our capital allocation is directly consistent with our returns and every, every, every well we drill has competed for capital to get on our schedule..

Understood. Thanks, guys..

The next question comes from Mike Kelly of Seaport Global. Please go ahead..

Thanks. Good morning, guys..

Good morning..

Good morning..

Historically, I think you've provided some really insightful thoughts on M&A and E&D (00:50:54) in the market and quite honestly some really good sound bites too. And I'd love to hear kind of your current thoughts.

It seems like the dynamics may have changed a little bit in the last year and there's some smaller producers would seem to have hold really kind of high quality positions, willing to take stock, this idea of scale being a big benefit is there.

Just wondering how your thoughts have evolved and if that's part of the optionality equation as you go forward. Thanks..

Well, that's always been an optionality part of our business. The – as we've said in the past, the challenges for a company that focuses on full cycle returns, fully burdened returns, that upfront cost is an important part of the equation. But we are always on the hunt for assets and we're always in the hunt for things that fit us strategically.

We're always in the hunt for things that make sense with our existing program and we'll continue to do so.

Very hard to predict – I mean, a specific answer to your question, these things tend to be episodic or at least with us they are because our core business is about return on invested capital and – but we're going to maintain an opportunistic focus and who knows..

Okay. All right, fair enough. And for my follow up, I was interested in your comments where you said, one of the things that, I won't say hold you back, but certainly you have to consider when you move into this full development program is the upside associated with additional zones.

And was just curious looking at the map here for you guys if there's any areas in particular where you have to be more cognizant on that front and might preclude you from entering into that full development mode come 2019..

Well, I would first say, that's the beauty of the Delaware Basin. It's so rich in hydrocarbons throughout that section, that's why at times, we are cautious. But then that said, what helps us is when we determine what we know are zones – we're able to delineate because of what we call a frac area. We say, okay, that's good.

No matter what happens above it. That's a zone that's good. So we have some areas there where we know, say, in Reeves County. We feel very strongly about what that hydrocarbon zone is now. We feel very good about going to develop it.

Contrast that with Culberson where we consistently keep moving those wells up because there is no natural frac barrier and we're just trying to ultimately define how high is that hydrocarbon column.

So it varies depending upon our acreage position, but again it's something we're very cognizant of and trying to address as quick as we can before we get to development mode..

Got it. Thanks, guys..

The last question comes from Noel Parks from Coker Palmer Institutional. Please go ahead..

Hey. Good morning. I wanted to talk a little bit regarding the long-term planning about the cost side. And if you want to talk about the Delaware, that's fine. But I guess I was thinking a little bit more about the STACK, particularly the Meramec.

As you do your planning and run it out through multiple years, how far are we from the point where on the cost side you kind of hit that plateau of bringing costs down where the well cost equation kind of becomes steady state going forward? Is that something that's close, a matter of quarters, is that something that because of the learning curve is longer? Do you have any thoughts on that?.

Yeah. This is Joe. I guess I'll take a stab at it. The fact of the matter is that our well costs even through this increase in price cycle that we've just last seen have managed to stay fairly flat. And I just quoted to you that they've dropped here in the fourth quarter due to efficiencies.

Our organization does realize that two-thirds of our total well costs are in the completion stage and that's why you see – you hear the comments that John just made about us continuing to challenge our organization with regards to how to optimize those costs.

And that's not just reducing cost; it's what kind of result do you get for the dollars you spend. And as we go forward in our planning cycle, we look at current AFEs, we look at if there was to be inflation to those AFEs and we also look at the possibility if we were to cut costs, what that could equate to from a cash flow standpoint.

So just like pricing, we look at the cost cycle in pretty much the same manner..

Great. And turning to the Permian, again, regarding your planning, do you assume a certain year or certain range of years where sort of like the infrastructure build out there by the industry is more or less done. So what you model now especially considering your differentials in third quarter, what we're seeing today certainly isn't steady state.

Do you have an assumption out there for when sort of infrastructure variability is more or less off the table for good?.

This is Joe again. We don't try to tie our well plan into some kind of prediction for what that infrastructure might look like from a larger scale takeaway perspective.

What we do internally is understand what the volumes that we're projecting that are associated with our capital plan are going to be and on what systems, and do everything we can to ensure the takeaway of those products. So I don't know if that fully answers your question but that is how we internally predict our volumes of sales..

We will expect things to be steady state sometime after world peace and the U.S. population largely loves our industry that we'll look for that after those things occur..

Okay. Thanks a lot..

Thank you..

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

Yes. So, I want to thank everybody for your participation. And I just want to leave you, if you take nothing away from our call, I hope that perhaps we've reminded you that we're a company that focuses on our business, focuses on execution, focuses on real measurable value creation and really are good stewards of our fantastic assets.

I really appreciate the great questions you've asked, and we look forward to continuing and deliver results we can talk about in the future. Thank you..

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