Karen Acierno - Director of IR Thomas E. Jorden - Chairman, President and CEO John Lambuth - SVP of Exploration Joseph R. Albi - EVP and COO Mark Burford - VP and CFO.

Drew Venker - Morgan Stanley Neil Dingmann - SunTrust Robinson Humphrey Arun Jayaram - JP Morgan Jeffrey Campbell - Tuohy Brothers Matthew Portillo - Tudor, Pickering, Holt & Co. David Deckelbaum - KeyBanc Capital Markets John Nelson - Goldman Sachs Joseph Allman - Baird Equity.

Good day everyone and welcome to the Cimarex Energy Fourth Quarter Conference Call. All participants are currently in a listen-only mode. [Operator Instructions] After today's presentation, there will be an opportunity to ask questions. [Operator Instructions] Please also note today's event is being recorded.

At this time, I'd like to turn the conference call over to Ms. Karen Acierno, Director of Investor Relations. Ma'am, you may begin..

Thank you. Good morning everyone and welcome to the Cimarex Fourth Quarter and Year-End 2017 Conference Call. An updated presentation was posted to our Web-site yesterday afternoon and we will be referring to this presentation during the call today. Our discussion will contain forward-looking statements.

A number of actions could cause the actual results to differ materially from what we discuss. You should read our disclosures on forward-looking statements in our latest 10-K and other filings and news releases for the risk factors associated with our business. We expect to file our 10-K for the end of the year next week.

We will begin our prepared remarks with an overview from our CEO, Tom Jorden, followed by an update on our drilling activities from John Lambuth, our SVP of Exploration. And then, Joe Albi, our COO, will update you on operations, including production and well costs. Mark Burford is also present to help answer any questions.

Again, so that we can accommodate more of your questions during the hour we have allotted for the call, we'd like to ask you that you limit yourself to one question and one follow-up, and then feel free to get back in the queue if you like.

So, just one last thing before I turn the call over to Tom, you may have noticed our new and improved Web-site, which we went live with last weekend. In addition to the updated Investor Relations page, we have added quite a lot of information under the Corporate Responsibility tab, especially with regards to the environment.

There are new sections on Seismicity, Hydraulic Fracturing, and Spill Prevention, as well as expanded disclosure on Water Management and Air Quality. So we hope you find it useful and appreciate any feedback you might have. So, with that, I'll turn it over to Tom..

Thank you, Karen, and thank you for everyone for joining our call. Cimarex had an outstanding year in 2017. We invested $1.28 billion and achieved excellent investment returns in both the Anadarko and Permian basins. Our overall program returns were excellent by historical standards.

Our operating group delivered seamless execution in 2017 as we avoided operational hiccups that plagued many of our peers. Our investment and operational performance led Cimarex to achieve top line annual production growth of 19%, including 27% growth in our oil production.

More importantly, we achieved a 15% growth in debt/adjusted production per share and 13% growth in debt/adjusted reserves per share. We accomplished this while living within cash flow and cash on hand. All in all, it was an excellent year and we [exclude] [ph] our organization for accomplishing these results. Our challenge now is to do it again.

Our 2018 plans call for us to invest $1.6 billion to $1.7 billion, 70% of which will be in the Delaware Basin. The remaining 30% will be directed to highly profitable Woodford and Meramec projects in the Anadarko Basin.

Our top-tier assets near Anadarko and Delaware basins and contiguous land positions provides for greater capital efficiency as our programs further move into development projects. We expect to deliver 11% to 16% total production growth and 21% to 26% oil growth in 2018.

Once again, as in 2017, we plan to achieve these results within cash flow and cash on hand. In 2018, oil sales will account for 62% of our revenue, NGL sales for 19% of our revenue, and residue gas sales will account for 18% of our revenue.

Our ongoing emphasis on the Delaware Basin and the liquids rich portions of the Woodford and Meramec plays will continue to balance our exposure to swings in commodity prices. In developing capital plans, we also look hard at the percentage of total capital that goes into drilling and completion.

Setting production capital aside, these drilling and completion dollars are the engine of our profitability. All other costs, which include land, midstream, saltwater disposal, and G&A, must be carried by the profitability of our drilling program.

Thus, we look carefully at the percent of our total E&D capital that is drilling and completion dollars, and the percent of our total expenditures that are drilling and completion dollars. Our 2018 program has a good mix year, well above the average for the past 13 years.

Our experience guides us to view this as a key metric to sustaining long-term profitable growth. One attribute of Cimarex is that we measure ourselves relentlessly. We take apart each of our programs and study them to calibrate our actual results compared to our pre-drill expectations.

We look at actual to expected costs, actual to expected production, and actual to expected reserve bookings. Our goal in studying these metrics is to calibrate our decision-making, understand what is and what is not working, and seek to make better decisions going forward. We cannot always control the outcome but we can control the decision.

We strive to have actual to expected results that are in close agreement. This gives us greater confidence in making future investment decisions. Our 2017 overall program exhibited strong repeatability, as measured by actual to expected results.

In laying out our 2018 capital plans, this consistency of results gives us confidence to increase our pace of activity. Furthermore, we will direct a higher proportion of our total capital to Delaware Basin in 2018. This decision is driven by the outstanding returns and programmer feasibility. Simply put, these are great investments.

We learned a lot in 2017 as we experimented with numerous downspacing projects in both the Anadarko and Delaware basins. Having a footprint in each basin makes us stronger in both. Our organization is adept at bringing learnings from one basin to the other and we expect our geosciences and operations staff to stay curious.

During 2017, our understanding of well spacing, optimum completion design, landing zone selection, and optimum facility design, increased dramatically because of the pilot projects we completed. We are ready for the challenge to repeat that operational excellence in 2018. Finally, I'd like to make a few comments on our value creation thesis.

Cimarex has long held to the thesis that our goal is to increase net asset value per share and that the best way to do this is to reinvest our cash flow in the most profitable projects we can find.

There is an ongoing conversation among energy analysts and investors that this is an indictment of the industry for destroying value through the commodity cycles. We are highly sympathetic to the spirit of this to date, although we do not think this was a one-size-fits-all approach and that we do not think that's the appropriate response.

Each company needs to respond in a manner that fits their assets, their investment performance, and their balance sheet. If our sector is guilty of destroying capital through the cycles, we do not necessarily think the solution is to do less of it. We think the solution is to fix the core problem.

How can we invest through the cycles and create real value over time, this is Cimarex's focus. We perform an annual look-back on every year, every program, and every well we have drilled since the inception of Cimarex in 2003. There are over 4,000 wells in our look-back.

We take each well and bring it current with actual production over time, actual revenue received, and actual expenditures incurred since it was drilled. This look-back is a critical part of calibrating ourselves and making sure that we understand our real value creation over time.

There is a treasure trove of data within our annual look-back and we mine it thoroughly. We look at the impact of commodity prices, actual to expected production, actual to expected reserves, and actual to expected expenditures. This analysis helps us understand the relative influence of each factor in our value creation.

We are in the business of investing and this analysis identifies where we are doing well and where we need to do better. We are fully committed to value creation and we understand that it is not measured by growth. We are confident that our 2018 capital program is the right solution for Cimarex.

We are achieving top-tier returns on invested capital and the 2018 program will continue that momentum. Service cost inflation is a factor as we look into 2018 and we have factored this into our plans. And as I said, we are in the process of incorporating lessons from our look-back in order to protect our investment returns.

Our commodity downside stress test on each investment we make is a critical discipline point for us. We will be discussing lessons from our look-back more fully as the year goes on. Nonetheless, we are confident that our 2018 capital program will deliver robust full cycle returns and is the right answer for Cimarex.

Enough of the preamble, we have some exciting results to update you on today. We had a great year in 2017 and look to repeat it. Our strong 2017 results calibrate our acceleration into 2019. We are seeing the benefits of our emphasis on science, our organizational capability, and the focus on fully burdened investment returns that permeate our culture.

With that, I'll turn the call over to John..

Thanks Tom. During the fourth quarter, Cimarex invested $344 million in exploration and development activities, bringing the total for 2017 to $1.28 billion. $980 million 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 319 gross, 98 net wells in 2017, with 59% of our capital spent in the Permian region and 39% in Mid-Continent. As you've heard, our 2018 plans estimate total exploration and development capital at $1.6 billion to $1.7 billion, with $1.3 billion to $1.4 billion going towards the drilling and completion of wells.

This amount of drilling and completion capital represents 82% of our total exploration and development investment, up from 77% in 2017. We currently operate 14 gross rigs, with 10 in the Permian region and four in Mid-Continent. We plan to spend nearly 70% of our drill and complete capital in the Permian, with the rest going to Mid-Continent region.

Mainly due to increases in working interest, in particular higher working interest in Permian than Mid-Continent, these 14 operated rigs will be drilling 28% more lateral feel than the 13.25 average gross operated rigs drilled last year. Now I'll turn to some specifics of each region. I will start with the Permian region.

We completed and brought online several Permian spacing pilots in 2017. The Tim Tam pilot, which consisted of five 10,000 foot laterals at equivalent of six well spacing in the Lower Wolfcamp came on production early last year and has yielded a great result with a calculated after-tax internal rate of return of 67% for this project.

Drilling is underway on the Animal Kingdom infill development in Culberson County, which consist of eight 10,000 foot laterals, testing the equivalent of 14 wells per section by both decreasing the space between wells in a bench plus adding an additional landing zone in the top part of the Lower Wolfcamp.

These wells are expected to be on production around midyear. Another important test, the Seattle Slew pilot, has now been on production for 120 days. These six 7,500 foot wells tested equivalent of 12 wells per section in the Upper Wolfcamp.

The learnings from this project along with the results of the other two Upper Wolfcamp spacing pilots of Gato and Sunny's Halo which tested six and eight wells per section, have enabled us to gain greater confidence on how best to design the ultimate development spacing for the vast majority of our Culberson County Upper Wolfcamp position.

We have five development projects planned for the Upper Wolfcamp across our acreage position in 2019, with two of them located in Culberson County. Lastly, I want to talk about the increased activity we have planned in Lea County, New Mexico.

In the fourth quarter 2017, we started drilling on our Red Hills acreage block two 10,000 foot laterals in the Upper Wolfcamp and three 10,000 foot wells in the Avalon interval. These wells will assist us in the confirmation of the appropriate frac design for this area.

We have also begun drilling a spacing pilot in the Upper Wolfcamp that will test the equivalent of 12 wells per section within one bench and we have spud an Avalon spacing pilot that will be testing the equivalent of 20 wells per section in a stack/stagger pattern within one zone.

All of these wells are expected to have first production around midyear 2018. This is an exciting area where due to our high percentage of contiguous acreage, we have the opportunity to develop with 10,000 foot laterals. Now, onto the Mid-Continent. We had a very productive year at Mid-Continent region during 2017.

We completed the obligation drilling associated with our Meramec position and now hold all of our 115,000 Meramec acreage by production. I will refer you to Slide 24 of our presentation as I discuss some of the recent highlights in the region.

First, we completed a three well stacked Woodford/Meramec test in the 14-10 township in Canadian County, Oklahoma. This test called the Woolfolk/NIB confirmed results of our Leon Gundy spacing pilot and it included two [landings] [ph] in the Meramec and one in the Woodford.

Further, this test shows that changes in cadence of the well completion has had a positive impact on overall results. Another Cimarex-operated Meramec test nearby, the Mike Com 1H-1720X had a very encouraging result with an average 30-day peak IP of 4,353 barrels of oil equivalent per day, of which 10% was oil, 29% NGL, and 61% gas.

Cimarex operates nearly all of the 24,000 gross acres within the 14-10 township area with an average working interest of 62%. For 2018, we intend to operate four Meramec development projects across our acreage position.

Based on math variations within the Meramec interval as well as ours and other operators' recent pilot results, these development projects are being custom designed for each section in order to maximize both returns and present value.

Thus, the range of spacing that we will be drilling is from 3 to 10 wells per section, again based on the thickness of measured hydrocarbon in place for each section that we will develop.

Drilling activity continues in the high return Lone Rock area where Cimarex has six long lateral Woodford wells on production with average 30-day peak initial production of 1,806 barrels of oil equivalent per day, 35% of which is oil, 36% gas, and 29% NGL.

The Company is currently drilling the Shelly spacing pilot in Lone Rock with first production expected mid-summer and has plans for a second spacing test with JD Hoppinscotch later this year. 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 update you on the usual items of our fourth quarter and our full-year 2017 production, our outlook for 2018 production, and then I'll finish up with a few comments on LOE and services costs. As Tom mentioned, we had a solid fourth quarter from a production standpoint.

With reported equivalent volume of 1.204 BCF per day, we came in above the midpoint of our guidance and set Company records for all products in both the Permian and Mid-Continent regions as well as at the total Company level. With mark, our equivalent production was up 5% over Q3 2017 and 25% over Q4 2016.

Oil volumes drove the growth with a fourth-quarter net oil production of 61,771 barrels a day, up 36% over the fourth quarter of 2016, a direct result of our 2017 capital allocation focus on high rate of return liquids projects in both the Permian and Mid-Continent.

With Q4 in the books, our 2017 average net equivalent production came in at 1.142 Bcfe per day. That's up 18.6% over 2016.

Strong activity levels in both the Permian and the Mid-Continent generated the growth, resulting in nice year-over-year net equivalent production gains in both regions, with our 2017 Permian posting of 631 million a day, up 25% over 2016, and our Mid-Continent volume of 509 million a day, up 11%.

Moving on to our 2018 production outlook, with more than 55% of our production now comprised of liquids and the deep inventory of high liquid growing projects in our portfolio, we're now providing production guidance and other metrics in oil equivalent rather than gas.

With our continued focus on Permian and Mid-Continent high liquids project, our current model projects our 2018 production to average 211,000 to 221,000 BOE per day, an increase of 11% to 16% over 2017. Similar to 2017, we're projecting another strong year for oil growth, with forecasted 2018 oil volumes up 21% to 26% over 2017.

We also built into the model a very small property sale which we closed in January, which reduced our volumes by approximately 1,100 BOE per day. Our 2018 program includes a significant number of multi-well infill projects in both the Permian and the Mid-Continent.

Significant production contributions from our Animal Kingdom, Hallertau, Snowshoe, and Triste Draw projects in the Permian as well as our [indiscernible], Shelly and Steve O projects in the Mid-Continent are forecasted to occur during the second half of the year.

As a result, with approximately 45 net wells anticipated to come online in the first half of the year and 82 net wells forecasted in the second half of the year, we're projecting fairly flat production levels through Q2 with a strong ramp in production during Q3 and Q4.

With the ramp, we are forecasting fourth quarter oil volumes to be up 29%c to 34% over Q4 2017, mirroring what we did this last year.

After incorporating our property sale and additional January Permian production downtime of about 4,000 to 5,000 BOE per day associated with weather, compression maintenance, repair, and construction related type set-ins, we're forecasting our Q1 2018 output to average 198,000 to 207,000 BOE per day, relatively flat to slightly up from our last quarter Q4 2017 and up 12% to 17% from first quarter a year ago.

Shifting gears to OpEx, our Q4 lifting cost came in at $3.89 per BOE, right at the midpoint of our guidance of $3.60 to $4.20. Our resulting full-year 2017 OpEx averaged $3.77 per BOE. That's down 5% and 25% from our 2016 and 2015 postings respectively.

To date, our production team has been able to fight off cost pressures and maintaining operating cost structure we've worked so hard to achieve, ultimately keeping our overall lifting cost somewhat in check.

Looking into 2018, with the fluctuating nature of workover expenses and our liquids-rich drilling focus, we're projecting our full year lifting cost to be in the range of $3.75 to $4.35 per BOE. And lastly, some comments on drilling and completion cost.

On the drilling side, although rig day rates seem to be somewhat in check, we are seeing some cost pressures on ancillary services such as surface rentals and labor, and as a result, and again depending on area, we've seen slight increases in the drilling portion of our AFEs.

As always, we continue to fight off these cost pressures through drilling efficiencies. On the completion side, we've seen additional upward pressure in the cost per frac operations, in particular the cost for services and for proppant.

As an example and on a total Company average basis, we've seen our service cost per stage pumped increase approximately 20% and our cost per proppant increase approximately 10% since the third quarter of 2017.

As such, we stay focused on refining our completion designs to offset the cost increases, all the while concentrating on improved well productivity. To reduce associated costs, we're executing zipper fracs and recycling water where we can and we continue to explore sand-sourcing potential in the Permian.

To ensure crew efficiency and adequate prop sourcing as in all quarters past, we maintain a consistent number of frac leads and plan our resource needs well in advance, and as a result we've had no significant issues procuring the resources when and where we need them.

The drilling and completion cost increases has made their way into our current AFEs. In the Permian, depending on area, the interval, facility design, and logistics for frac efficiencies, our current Wolfcamp 2-mile AFEs are running $11 million to $13 million.

With our New Mexico Bone Spring development now extending from the shallower areas of Southern Eddy County into the deeper areas of Northern Eddy and Lea counties, our 1-mile Bone Spring AFEs are now running $7 million to $8.5 million.

And in Cana, with the revised completion design to help offset cost increases, our 1-mile lateral Woodford AFEs are running $7.5 million to $8 million. And finally, with our current frac design, our 2-mile Meramec AFEs are running $11.8 million to $12.8 million, up from the levels we quoted last call of $10 million to $11.5 million.

So, in closing, 2017 worked according to plan. With a solid Q4, we closed the year with record production and year-over-year production growth of about 19%. Our 2017 liquids-rich focus generated sizable production gains in both the Permian and the Mid-Continent and we demonstrated 36% oil growth from Q4 2016 to Q4 2017.

With similar projects slated for 2018, our strong Q4 2017 exit rate is forecasted to hold flat until the middle of the year when our Permian and Mid-Continent multi-well infill projects are forecasted to generate another sizable production ramp, a ramp projected to result 11% to 16% year-over-year production growth and a Q4 of 2018 oil volume in 29% to 34% above our record Q4 2017 level.

We're working hard to fight off cost pressures on all fronts. Despite the pressures we've seen, we continue to generate great returns from our drilling program. The stage is set for another successful year here in 2018 and we're excited to execute our plan. So with that, I'll turn the call open to Q&A..

[Operator Instructions] Our first question today comes from Drew Venker from Morgan Stanley. Please go ahead with your question..

Tom, I want to start on your prepared remarks addressing costs and specifically costs other than D&C, it sounds like you think there's potentially some evidence to reduce those in the future.

Maybe you could speak to what you've looked at and reviewed recently that could potentially impact the 2018 spend and if you see ways to improve on that going forward?.

As you know, we compile a lot of data and we look at that ratio carefully. As I said in my remarks, the percentage of our total capital, our drilling and completion cost is a really important metric.

Not only have we seen our program be stronger if that ratio is high, but we've also seen some of our peers from time to time that have gotten into trouble, and carry it back to seeing that ratio get out of balance. You have to make some of these other investments. Land investments are critical part of our projects.

Certainly the midstream investments we're making, although we attempt to minimize them where we can, they do contribute to the profitability of our production base. And then we have to make saltwater disposal investments in order to also facilitate our production.

Now, would I love to see our drilling and completion dollars be 100% of our total capital? Yes, absolutely, because those are our most profitable investments and the other investments service those. But that's not feasible. Now, we are looking at some things that we can explore to try to minimize that.

We don't have anything specific we can talk about, but I will say this. We look at those ratios and our ratios for 2018 are really, really healthy. And I quoted a 13-year average.

That's only because that's as far back as I have good accounting data to really compare that, that's going back to 2006, but we're in very good shape with our 2018 capital program as to how those profitable drilling and completion dollars are balanced against total capital..

Excellent color, Tom. And then just on the spending philosophy and the capital plan, you guys raised money back in 2016 and you guys are still working on spending that in addition to cash flow.

I'm thinking, beyond when you spend that cash balance, what do you think is the right spending philosophy relative to cash flow or otherwise longer-term, does it make sense to return cash to shareholders at some point as you kind of bear the fruit of all these investments, whether buybacks or dividends, or maybe is that too long a term to think about at this point?.

No, it's not too long-term at all. We've always said that we would like to maintain the balance sheet where our debt to cash flow is 1.5x or less, and we haven't changed our strives there. Now as we look ahead, I think in this commodity environment what we've been in the last few years, we will probably have a strong reluctance to not borrow.

That's not a promise but I will say that we work very hard looking at our future and our bias is to live within cash flow or minimize our borrowings. As far as returning cash to shareholders, we do pay dividend. I've talked at length that we cut that dividend in 2016.

None of us felt particularly good about that, although that was the right decision at the time. And our Board, I will tell you I think is going to be looking at that and our bias is to recommend restoring that dividend to its high watermark as much as prudently possible.

That will be a decision for the full Board but we'd like to see that dividend get back to its high watermark and then on a good growth trajectory. I don't know that you can expect share buyback out of us. We are really achieving great returns on invested capital.

I will tell you, as an owner of Cimarex, I'd rather have Cimarex invest the returns that we are achieving rather than give the cash back, and I think many of our long-term owners feel the same, that not that share buybacks are off the table but we're going to have a bias to increase our dividend and just make sure that we're making good profitable investments with our remaining cash.

Mark, you want to comment on that?.

No, I think you said it well, Tom..

Thanks for the color, Tom..

Our next question comes from Neil Dingmann from SunTrust. Please go ahead with your question..

Tom or John, or even Joe, my question really addresses your production timing.

Recognizing that you have the 2018 guidance out, nothing beyond, could you all talk about the type of impact on total production these large pads like the Animal Kingdom or Snowshoe will have? Really guys what I'm trying to get a sense of, if essentially the benefit of these large A+ type well pads will essentially be more in 2019 than 2018, obviously recognizing you don't have any sort of 2019 guidance out?.

This is Joe. By virtue of me just saying that we're going to be flat from basically Q4 through Q2, and then all of a sudden we talk about the fourth quarter oil growth and the year-over-year production growth, there is a strong ramp. This is going to give us a real nice accelerate into 2019.

Surely no different than years past where we've had these program ramps. Other than from my standpoint, we have like seven of them now, and all of them are coming on at the same time. So, as you really look to us getting more into development mode, I think this is going to kind of be the norm.

We're going to have a number of projects where you got six to eight or god knows how many wells all coming on at once, and I think we're gone from the days where you've got this steady single well growth to program platform growth like we're seeing.

So, I'm kind of dancing around your question at 2019 because we really haven't modelled that in tremendous detail, but what I will tell you is that it's a very strong ramp going into the fourth quarter and it's not beginning in the fourth quarter or it's beginning in the third quarter.

So, from a timing standpoint if it were to get delayed, it's not going to, the ones I hate are the ones that all come on around November/December, and if you have any hiccup, it's pushing to the next year.

But you know what, this production thing, maybe to philosophize it a little bit like Tom just did, we're measured quarter to quarter and you're looking at quarter to quarter production. What we're looking at is net asset value growth and the returns that are being generated by those production ramps are what are key to us.

And if they move out a month or move forward a month, it's not what we are focused on. We're focused on a return on invested capital..

John, you comment, because I know you study this hard as far as the impact of these big projects and what should we do when we [split them up] [ph]..

No, I think as we look at our per unit drilling cost, absolutely the big projects make sense from our standpoint. I do want to add a little bit color and I want to be clear, it's not like we plan for these projects all to come home in the second half. There are some in this particular case mitigating circumstance. One is our Avalon pilot.

Basically we ran into, we could start the completions and then we have to become very inefficient because we run into what we call the prairie chicken season and we'd have to then shut down there a period of time. Thus, we decided it's best to delay it after that. That pushed it back later in the year.

And then secondly, our Shelly pilot, we're doing a lot of science with that including surface micro-seismic, and so we've imposed a single frac crew on that particular pilot. Again, in normal operations we'd expect to have two frackers out there. That further delays it. So there are some operational things that are also pushing it.

I would expect that as we get more and more to these individual developments, I think you'll see it line out more than always being in backend loaded. It's just this particular year a couple of our more – we had a little bit longer delay than what they normally would..

Great answer, guys, and I absolutely agree. Given the cost basis, this seems to make a lot of sense.

Just one quick follow-up, John or Joe, any indication or just thoughts about, I know it's early, but around the Lone Rock area as far as indications or thoughts around spacing there?.

That's why we've drilled both the Shelly pilot and why we've gone ahead and moved to the next pilot I mentioned. We want to get that one in the ground too. We feel very good about eight wells. That's what we're testing.

The additional pilot that we're going to start drilling here very soon is on the more eastern side, so it's the more liquid-rich side, so now we'll have nice book in pilots on either end of our Lone Rock position.

I think with both of those outcomes in hand, we'll be in very good shape to move forward pretty confidently in terms of how we would build that acreage..

Yes, our team is confident to bet on the 10,000 foot long development projects that are just waiting to be [numbered] [ph]..

Yes, they are..

Very good, guys. Thanks so much..

Our next question comes from [indiscernible] from JP Morgan. Please go ahead with your question..

This is Arun Jayaram from JP Morgan. Couple of questions. I just wondered if you could talk a little bit about your Lea County program. It looks like 225 million of capital.

Could you just highlight some of the projects in the Triste Draw and the Red Hills area in 2018?.

This is John. If you go to Slide 21 in our presentation, we highlight both where the Triste Draw is as well as the Hallertau. Really both of those are again spacing pilots to really get us further along in terms of what we think ultimately spacing will be both in the Upper Wolfcamp as well as in the Avalon.

Furthermore, in the Red Hills area itself, we were looking at that slide. Off to the east, you see the large acreage position, kind of what we call the Main Red Hills Park.

That is where we have several long laterals that we are drilling, as I mentioned in my prepared remarks, where we're just reconfirming our expectation of results with the frac design. There are some outstanding wells that are drilled in close proximity to that acreage position. This is an area that we've been wanting to get to.

It's an area that we've often said is HBP. So it's not something we need to drill the hole. But now we've decided to move quite a bit of capital in there because the returns look fantastic. And so, we're very excited about getting back up in the Lea County. I think the one thing I want to point out is we're also expanding or delineating.

We have a number of wells trying to push the boundaries of in terms of what we think is profitable Wolfcamp and Avalon drilling. I think that's going to again put us in a much better position going forward in the 2019 for further development in that area.

But it's without a doubt, when I look at our overall drilling program, this area in particular generates some of the most top tier returns we have..

Great. And just my follow-up gentlemen, your outlook highlights a lot of completions in the third quarter, I think over 50. Could you talk about kind of the organization's ability, Tom, to meet that number? And just wanted to follow up also, what are your key LFS supplies? Halliburton had highlighted this morning some delays on the sand side.

I just wondered if you could talk a little bit about that, is that perhaps impacting your 1Q completion schedule. I think you did say, you're self-sourcing some sand, but wondered if you could highlight or talk about these two points..

I'll just speak to that and then turn it over to Joe. We are very confident in our ability to execute those completions. We do sit and talk to our service suppliers and line out our program. We've had very good success working at these problems. I'm very, very confident that we're going to be able to handle these logistics.

Joe, you want to talk about sand bottlenecks?.

As far as the logistics, I mentioned that we plan well in advance with crews and what have you and we've probably increased our crews from three to five here in the next few months and we've already got the crews lined up with our providers. So I don't see any issues there.

Our batteries are constructed in quick fashion along with the fracs and so forth to getting the wells online. Unless of course we have any issues fracking the wells or what have you, we see no delays there. From what I understand about the sand build issue, the Permian right now is directly related to rail, which is directly related to weather.

And we're seeing, from our guys' standpoint, it's kind of being a relative hiccup and the sand that we've already procured in advance of our upcoming operations should not be affected at all by that. If it were to continue, then we'd probably see a slight problem..

Yes, as you said, we haven't heard what remarks Halliburton made this morning, but we've had a lot of conversations with them about the short-term hiccup and it's not giving us any material concern. But go ahead..

I was just going to say, did that have any impact on your 1Q completion count? Sounds like the answer is no..

No..

Okay, great. Thanks a lot..

Our next question comes from Jeffrey Campbell from Tuohy Brothers. Please go ahead with your question..

Good morning and congratulations on the quarter and all these multicenter projects coming up.

I wanted to ask you with regard to Slide 13, are you at liberty to say how many new locations have been created by the successful Western Culberson Upper Wolfcamp results, of if you prefer, can you talk about how many acres this might open up for further exploration?.

This is John. First off, we're very, very pleased with those drilling results on the western side of Culberson County. The deliverability from those wells is just incredible. And furthermore, the yield content has been quite frankly a little bit higher than even we anticipated. So, they are generating outstanding rate of return results.

I think what that's done, that drilling has kind of given us greater confidence now that the vast majority of that Culberson position looks extremely profitable from a development go-forward basis for the Upper Wolfcamp.

Now, in terms of what this development look like across the breadth of all of that acreage, we recognize there's variations there, so no one-size-fits-all, but I can at least say with confidence that the minimum average number of wells in Upper Wolfcamp will be at least eight, if not more than that, across the breadth of all that acreage.

Now in some places it will be even more and some maybe a little less, but certainly over the vast majority of that acreage, there will be at least eight wells per section on average developed there. That's kind of what the pilots are leading us to now.

I will point out, what will change that for us is we are currently testing additional shallower landing zones in the Upper Wolfcamp in Culberson. We have a number of wells now that we have landed, and what's called the X and Y sands which sit right above the very rich shale part of the Upper Wolfcamp.

Up until recently, we've put all our wells in the shale itself, but now we've moved even higher, and as we continue to watch those results, if we get strong encouragement, then that alone may increase the number of wells we can do just in terms of adding another bench.

That is something that we'll be monitoring through the year and certainly adjusting our plans if those results are encouraging..

So, we didn't answer your question. We don't publish well counts but that whole area between the Upper and Lower Wolfcamp is just amazingly prolific. John talked about spacing the Upper Wolfcamp, our Animal Kingdom test 14 wells in the Lower Wolfcamp. Those are independent zones.

We can develop one and come in years later and develop the other, and there's not a concern about [fairness] [ph]. So, it's just an absolutely wonderful arena and we can drill 2-mile laterals at will. There's discussion about even testing a 3-mile lateral there. So, we'll be working out here for decades to come..

Actually I appreciate your answer a lot. I thought there was plenty of good color there. I just want to make sure I understood the last part that John was talking about.

Are you saying that you're testing the XY in Culberson?.

Yes..

A lot of the XY testing that I've seen has been further the east..

Yes, it has. And we have, per experience of our other drilling in other parts of the basin as well as other operators, we are very intrigued with that section. Thus, we have moved up into it with a number of tests and hopefully in the coming releases I'll be able to talk about those wells. So, we'll see..

Yes, we'll look forward to those results.

If I could just as a follow-up ask a broader question, when I look at a slide like Slide 28 for the Shelly spacing test and you've talked about that in response to an earlier question, I'm just trying to understand, are these and of course other tests elsewhere, are these sort of iterative exercises in highly similar geology or does an eight-well test in one place and a 12-well test in another already illustrate a view that some of the acreage is more likely to support additional wells versus other acreage?.

This is John. First off, obviously we've done a lot of drilling development in the Woodford Shale, and so I think we have a pretty good understanding in terms of, for instance like our latest Clyde Copeland results, we learned a lot from that in terms of what ultimate spacing might be.

But the reason you might look at a Shelly and ask yourself, why they are doing 8 and 12, testing both in one pilot, it's simply as we move to the south, we are dealing with a little bit different thickness, a little bit different in terms of pressure regime, and even a little bit different in terms of hydrocarbon content.

So, as much as we're confident in what that spacing will look like, we still need to test kind of some of the [in-member] [ph] balance of it, then we have greater confidence when we do go full development on the acreage.

So that's why you go out with a Shelly type pilot, just to kind of reconfirm our expectation for the rest of that Lone Rock acreage..

We had a lot of debate on this. We wanted to try a little tighter spacing because of our really interesting results in our Clyde Copeland test.

Our Clyde Copeland test was testing 16 and 20 wells per section, little thicker part of the Woodford, and we also discovered in our Clyde Copeland test a really meaningful result when we stack/staggered for the low Chevron pattern in our wells.

So, it was really based on that result that we wanted to just go a little bit tighter in Shelly, but it's not thick enough there to do the stack/stagger, so we kind of just said, we'll just try a little tighter, we'll do 8 and 12. We call these things pilots. They are really development projects.

We're just going to try some things along the way and continue to learn..

If I could real quick, if you look at Slide 27 in fact, we show the updated Clyde Copeland results and you will now see that indeed the 20 well spacing wells are even starting to separate themselves over time, and again, that's that learning of staggering within that thick Woodford Shale.

That was a very important learning for us and something we're going to incorporate in future development projects in the Woodford where we have sufficient thickness to do that..

Right. This is really great color. I guess what I'm getting from this is, this project really is unique and that goes in line with what you just said that these are really development projects.

And also, if I can just add as a follow-up, you mentioned that you're doing some science in Shelly and it sounds like the reason for doing that is because there is actually several different variables that you're trying to test.

Is that the way to think of it?.

Yes, you can think of it that way.

One of the biggest outcomes that also came from Clyde Copeland is, we did deploy what we call surface micro-seismic, and we learned a lot from that in terms of our efficacy of our frac design, the interaction between individual wells and a development like that, and we felt it was crucial that we deploy the same type of science with that first pilot down at Lone Rock.

We really think that getting that done now early, we're going to learn a lot about how best to for example the cadence of which wells to complete first within a major developed section, we are zipper-fracking but then there's things we look at in terms of the staggering of where we are in the bore hole.

There's a lot we've learned by having that science out there, and as I mentioned, we've decided to get the best benefit out of that pilot, we'll do that which is one frac crew..

Okay, great. Thanks. I appreciate. Always learn something on these calls, that's why I look forward to them..

Our next question comes from Matt Portillo from TPH. Please go ahead with your question..

Just a quick follow-up question in regards to service cost inflation.

Are you currently baking in benefit from the acceleration of use on zipper fracs and then sourcing of regional sand, or does that potentially help mitigate some of the cost inflation as you move into 2018?.

This is Joe. I'll take a stab at that. To the extent, and John can jump in to the greater percentages that we'll come at on wells, in particular in the Wolfcamp we'll grow our first well and build a battery that is not only going to accommodate the first well but plan for up to seven additional wells on that battery.

So when I quote a Wolfcamp cost range, you could assume that the first well is probably going to be on the upper end of that range and the additional add-on wells would be on the lower end of that range.

The economies of scale that you see there are reduced battery cost and then those add-on wells you are usually growing multiple number of wells, so that's where you can see some cost gains or cost benefits, excuse me, associated with zipper fracking and water sourcing.

So, yes, to the extent that the inventory of wells that we have in our budget are add-on wells, they are going to reflect those costs, and if it's a first well, it's going to reflect the other cost. The sand sourcing part of your question, no, the benefits from sand sourcing are not in the equation yet.

We think we're right around the corner from having some in place there that could have sizable cost benefits to us..

I'll follow-up with Joe. The only thing I would add is, what we're representing new, as Joe said, our go forward expectation for this possibility today. I mean we crude up [indiscernible] as best we can to represent what we think we'll be spending per well.

But I will tell you, in terms of some of these plays, Meramec in particular, we are looking long and hard at our current frac design and looking at in fact some of our offset operators and asking ourselves could we perhaps get similar results with maybe a change, a systematic change in design, it may actually save a little bit on the cost side.

I think we're at that part in the Meramec where, and let me be clear, we're extremely pleased with our Meramec program over the course of the latter half of 2017, now we're at that point we're saying, okay, are there some tweaks we can make to the design that may pull back the cost a little and still get still superior returns, and that's something that we're discussing right now internally..

Are increased costs baked into our capital budget plan? The answer is, yes. And it's reflected, you can do simple math and just look at the cost increases that I quoted for the Meramec program as well as the Wolfcamp program and do some back of the envelope calculations to see that those represent a fair portion of the capital budget this year.

With sand sourcing, through the efficiencies John is talking about, it's our intention to get those costs down and keep our productivity where it is..

Great. And then as my follow-up just a quick two-part question I think for John.

One, we noticed that you guys are adding some incremental activity to Ward County in 2018 and I was wondering if you could provide any color on results from last year and how you're thinking about that asset moving forward? And then two, just a quick follow-up on the XY, obviously a new target that you're testing, do you already have results in hand and do you have any thoughts around just the liquids yields on that asset in Culberson?.

In regards your second question, I'm not going to really comment on that because it's still early on the flowback of the wells, so we'll just have to wait and see. As to the first part in Ward, we do have two wells on production now and we are learning a lot from that. There are a couple of comments I'll make.

There is always a concern on our part that with that existing layer of Third Bone wells, how would new wells interact with that. I think we're getting more confident now that we can land in that upper part of the Wolfcamp and achieve pretty good results and not have a detrimental effect on those Third Bone Spring wells, that's been a good outcome.

We're getting better at understanding one of the things in Ward is – one of the things I look at is just water cut that's a huge component to the returns. I think we're getting a better handle on our expectation there.

And then quite frankly the thing that's helping us there are a lot of competitor wells that have come on recently, some outstanding wells that are quite frankly very close to our existing position.

So we're very excited to go out there and test some of those Upper Wolfcamp landing zones nearby some recent competitor wells that look pretty attractive to us. So we have a number of, I think it's around four or five wells that I think we'll be drilling this year in Ward, scattered throughout the year as we continue to test across our acreage..

Our next question comes from David Deckelbaum from KeyBanc. Please go ahead with your question..

Tom, I wanted to ask because you highlighted the progress you made in 2017, how you think about creating value for shareholders as you look into 2018 with more of these larger projects? You highlighted in the release I think a lot of, you've talked about in the past, retaining efficiency gains.

With the move to larger pads and a greater contribution in the Permian, do you still see the efficiency gains holding on sort of a per well basis or cycle time as relative to 2017, are you factoring in perhaps some expanded cycle times on a sort of per well basis as you kind of go to more of these large projects?.

There's a lot in your question, David. When it comes to efficiency, a course – we quickly want to bring that conversation to rate of return. These large pads we think generate superior rates of return. We think long laterals and our pad development gives us some efficiencies or facilities to generate outstanding returns.

But there is the timing delay and we study that hard as to do we want to do these big projects or do we want to split it up into smaller projects and get the production on faster. There are a lot of elements to that problem, one of which is well-to-well interference.

So, you really have to understand what happens to the boundaries of that project if you split it up into smaller pieces. But we're fairly confident that our program as crafted is generating great returns. That's our lands.

I mean I'm a broken record here, but production is interesting but full-cycle returns, modeling in production delays, modeling in the capital lag between first investment and first production, that's all baked in when we look at our returns and we're very confident that the program as designed is generating our optimum returns.

You want to comment on that, John?.

No, I absolutely agree. I think we have put a lot of effort, as Tom alluded, to making sure that some of these developments aren't too big. I mean that is one lesson we learned from our Woodford development where we get out there and do six contiguous sections of development.

The time lag is not something we like, and it exposes you in a way over the course of a year plus. So, we've worked hard. For instance, most of these developments in the Upper Wolfcamp that we're talking about, in Culberson and Reeves, typically are half section size is what we're doing. You're thinking six to eight wells each of them.

And so, we've made that adjustment. Again, I would like to think especially – I'm not making any comment on 2019 here, but as we get to more and more of those types of developments and that becomes a regular part of our routine, I don't think you're going to see this type of lumpiness or end of the year.

I think there are some other mitigating factors, as I alluded to earlier, that has pushed more of the production to later in this year because of some of the things I talked about.

I think on a go forward basis, I think the cadence would be you'll see more of a normal production increase off of these individual projects we do as we do more and more of them..

But you know, David, I really salute your question because we debate this constantly internally, and let me give you a very quick example. Where we know we're going to have larger development on the section, particularly in the Delaware basin, we'll go ahead and pre-build the facility, the flowback facility, to accommodate more wells.

We may initially have one or two wells coming in but we'll go ahead and build the facility to be ready to accommodate additional six or so additional wells. And we're asking ourselves, is that the prudent thing? I mean our first pass on that was, so yes, that's a smart thing because you know you're going to come back in.

But I will tell you, our operating group, rightly because I said at the outset, our rate of return discussion permeates our culture, and they are asking that question as maybe that's not the right approach, maybe smaller facilities that we build will be needed as a better investment of capital.

So, these are great questions and I think any good operator ought to constantly be debating this internally, as we do..

Sorry to throw in such a loaded one towards the end of the call..

We didn't even bring in the midstream. You don't want to give us an opportunity to talk there..

My only follow-up, I guess something lighter, on the Woolfolk/NIB, you commented I think in your prepared remarks, John, that you're changing your cadence of completion as enhanced results.

Can you just give a little bit more color on what you were describing there?.

Sure.

I think the biggest difference there is we recognize – there is a big difference, and when you talk about a Woodford Shale relative to a Meramec which is more of a silty interval and how they frac, and what we've learned is when you're in that type of development where you have both Woodford and Meramec opportunity, in particular you want to frac the Woodford well first.

It needs to go first, it needs the chance to have every chance to break that rock. And then you can follow-up with the Meramec, and that was really one of the things we were testing, as we have with a couple of other tests, and that seems to be leading to very good results for both the Woodford and the Meramec wells.

So we're very pleased with that outcome. That really is shining a light on that 14-10 area where we're looking at it as a major future development area for us in the coming years, and as well there are just some really outstanding results for us..

And also we're plugging here for our science, because we had a lot of history out here and our conventional wisdom and our experience led us to exactly the opposite conclusion.

And it was because of some science we were collecting on micro-seismic data and some really heads-up curious behavior on a couple of our geo-scientists that they noticed the phenomenon that at first we looked at and we thought, could that be right, because it was absolutely not what we expected, it led us to do some further testing and it is a lifetime success in understanding of the right way to develop these reservoirs..

And it's absolutely critical for us, I want to emphasize this that the 14-10 area in particular is unique in that you have wonderful thickness in the Meramec that we are absolutely convinced at a minimum you get two benches to develop, but you also still have sufficient thickness in Woodford to generate superior, very good return.

So, it's one of the few areas across that whole STACK play where you have thickness in both that leads to that co-development and we're very excited about that for future drilling opportunity for us..

Thanks for the comments, guys, and your responses..

Our next question comes from John Nelson from Goldman Sachs. Please go ahead with your question..

Congrats on the quarter and thanks for squeezing me in here. Just more couple of housekeeping type questions. There were I guess a bit more cryptic comments on oilfield service cost inflation and kind of how we can back into it. I guess if I look at the well costs that you guys have up year-on-year, it's in that kind of 10% range.

So is that kind of what you're saying is baked into, just flat from here is kind of what's baked into the 2018 guidance or can we get a little bit more color on that?.

This is John. From a simple standpoint, if we've bumped up our midpoints for the Meramec program and the Wolfcamp program by 10%, if you just take the number of wells that we're quoting for each of those programs, you'll get to a number.

We really didn't kind of look at the budget and say, okay, what do we want to bake in for inflation and then put a top level adjustment in there.

We looked at what we thought the actual cost ranges were based on the frac designs for each one of these type wells and we're kind of brushing over the complexities of the total well cost associated with frac design, build for one, plan for four, build for one, plan for eight, and all the other implications that Mark and I looked at the back of the envelope calculations yesterday and thought maybe it's somewhere around $75 million to $80 million, if you look at what it represented as compared to what we would have done three or four months ago..

The only other comment I'll add to that is I will tell you in particular for Anadarko where a pretty large portion of our budget is outside operated wells. We took a really hard look at 2017 in terms of the wells we participated in and they are very good return wells.

We felt like we made good decisions but we also felt like that we needed to adjust that capital higher relative to what we were represented as being the expected costs. Clearly, those wells were coming at much higher, so we have adjusted in 2018 an expectation of higher capital for those individual outside operated wells..

So, John, we took our best guess at it and certainly we're not perfect at anticipating, and Joe mentioned this local sand sourcing in Delaware, when it comes online will I think be a big help here. And then our range, I will say the high end of our range kind of anticipates a little bit of inflation.

So, if we didn't see any inflation, we'd probably be at the lower end of that, just checking from here on out. So, we took our best guess..

One other comment I'd like to make too is if you look at the midpoint for the 1-mile Woodford AFE that I quoted in the call, it's barely up at all, and even with the same inflationary pressures on service cost and proppant and basically every cost category associated with completions, while we changed our frac design.

And so, especially in Meramec, I think there's tremendous potential to keep experimenting there and we can see cost reductions there. The sand sourcing can have a significant impact in the Delaware. And so, obviously our goal is to get those numbers down, but those are where current AFEs are and that's what's in our current capital plan..

That's really helpful.

So, just to be clear, it's expectations of kind of flat from here is probably around the midpoint of your range and then a cushion for insulation is kind of the high end of the range?.

Correct, John, yes, so kind of the low end of the range is kind of expectation that we currently see some inflation already built in and the upper end of the range could allow for some additional inflation if we experience it, which we hope to offset with some of the operational changes we'll make with local sourcing and other maybe frac design changes.

But that's right, just amongst the uncertainty of what that range could be into the future, but we have some room in our range..

Great. And then I just wondered if you can comment kind of ballpark the amount that was spent in Lea County in 2017? Seems like a pretty significant pickup and you had some of the best rock there as we've seen..

We don't have that in front of us. Mark is searching for it. It is a huge pickup because as we've said in past calls, our Delaware Basin [indiscernible] a bit on Lea County and we wanted them to understand some of the multi-pay development. They have made tremendous progress on [indiscernible] this year..

Yes, there was a lot of drilling activity in the latter half of 2017..

About 70 million..

Yes, but we haven't really – now we're getting to where we're completing those wells. So, we'll bear that fruit this year from the drilling activity that we embarked on at the end of 2017 in Lea County..

Did you hear that, John, it was about 70 million for basically [indiscernible] our effort this year..

That's great. All right, thanks again. Congrats on the quarter..

Ladies and gentlemen, we have time for one additional question. This question comes from Joe Allman from Baird. Please go ahead with your question..

Tom, a question on free cash flow, so how much is being free cash flow positive a factor in the capital decision-making or do you really see it as an output? So, in other words, if you have the right assets and you do the right things and you have reasonable commodity prices, over time you're naturally going to spend that cash flow, partly because you build upper base at relatively low decline in production.

So what I'm getting at, I'm just trying to figure out what kind of iterations you ran when you thought about 2018 spending and what are the governors, balance sheet, production growth, I mean what are some of the governors you consider?.

Thank you for that question, Joe. We do treat free cash flow as an outplay. We think that a company that has good investments, high rate of return, good operational execution, ought to be living within cash flow and generating certainly some growth. I mean it will depend on company to company. But our greatest concern is in our balance sheet metrics.

You know, free cash flow, that's certainly become kind of the mantra. I will tell you, at Cimarex we look at our debt, we look at our debt-to-EBITDA, we look at our coverage statistics, and we want to be growing those over time, and we want to be over time growing our financial health.

When we look to 2018, we had such a strong year in 2017, we looked at that cash on the balance sheet and said, why would we have that cash sitting there, and all the choices were available to us. I want to be totally clear and transparent here.

We could have embarked on some modest share buyback, we could have returned that cash to the shareholders, or we could have invested it.

That's why I said at the outset that when we looked at that, we said, look, this is a very challenging commodity environment, so we better make sure that our actual to expected results are really well calibrated, and we tore our 2017 results apart and we saw that we had tremendous repeatability, in fact we went back to 2016 and 2017 and we saw that we had great repeatability that gave us a high degree of confidence that we could hit what we aim for.

And so, we said we're going to invest that cash. When we reported our capital plan, we reported with a plan that we would invest that cash over a couple of years, 2018 being one, and that was what went into it. Our bias is to invest that cash. We raise that money with that promise and that promise is still something we want to honor.

So, that's kind of how we look at the world, Joe..

I appreciate, Tom. And just a quick follow-up, so you've always been about executing and focusing on rates of return and NPV and growing shareholder value. Your stock is not necessarily reflecting your successful execution.

So, are you thinking about doing any different, sort of close any gap that exists between what is your Company's worth and where the stock is trading?.

We try not to pay too much attention on an hourly basis toward share price, but you can't ignore it either. I think there's some confusion out there about Cimarex.

We have assets second to none, we have an organization second to none, but we are trapped in an environment where people are really questioning the basic value of the energy space and people are looking for things to worry about, and Cimarex has a foot in a couple of the camps people are looking to worry about.

We didn't get asked today about gas price differentials. We certainly are exposed to that. But we model all of that in, and as I said at the outset, gas is only 18% of our revenue right now. So, we think we are in a pretty good shape there and we see some light at the end of the tunnel.

I can't sit here and talk to the investment community about what they should value. I'm obviously extremely high on Cimarex and I think our track record speaks for itself. I'll tell you what we value. How we approach, how we think we can invest and add value over time, we've got a good track record, and I welcome that conversation.

So, from time to time there will be disconnects. Right now there's this mantra around free cash flow, and I think in some sense anybody that deviates from the herd is going to be punished in the short run, but if we have a strategy that's well-crafted and we execute it well, it will get figured out in the long run..

Got it, great, very helpful. Thank you, Tom..

Ladies and gentlemen, this will conclude our question-and-answer session. At this time, I'd like to turn the conference call back over to Tom Jorden, President and CEO of Cimarex, for any closing remarks..

I want to thank everybody for your participation and I know these are challenging times. We are looking forward to a strong 2018, and I'll just say in closing that we're a very result-oriented company, we focus completely on results, and we expect you to measure us based on our results.

We appreciate our fans and we appreciate our critics, and I mean that most sincerely. This whole conversation about value creation is a great one. We debate these things at Cimarex. I look forward as the year goes on to discuss some of the learnings from our look-back more thoroughly.

We are debating changing our approach and some of the ways we measure ourselves. So, I just really want to tell you, we love this business, we love getting up every day and being challenged to be better at it, and that's our mission at Cimarex. So, thank you very much for everything you bring to us..

And ladies and gentlemen, with that we'll conclude today's conference call. We do thank you for attending today's presentation. You may now disconnect your lines..