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

Arun Jayaram - JPMorgan Securities LLC Drew E. Venker - Morgan Stanley & Co. LLC David R. Tameron - Wells Fargo Securities LLC Pearce Hammond - Simmons Piper Jaffray Neal D. Dingmann - SunTrust Robinson Humphrey, Inc. David A. Deckelbaum - KeyBanc Capital Markets, Inc.

Jason Smith - Bank of America Michael Anthony Hall - Heikkinen Energy Advisors LLC Joseph Allman - FBR Capital Markets & Co. Jeffrey L. Campbell - Tuohy Brothers Investment Research, Inc. Paul Grigel - Macquarie Capital (USA), Inc. John Nelson - Goldman Sachs & Co. Mark Hanson - Morningstar, Inc. (Research).

Good morning, ladies and gentlemen, and welcome to the Cimarex Energy Third Quarter 2016 Earnings Conference Call. All participants today will be in listen-only mode. After today's presentation, there will be an opportunity to ask questions. And please note, this event is being recorded. Now I'd like to turn the conference over to Ms.

Karen Acierno, Director of Investor Relations. Please go ahead..

Good morning everyone, and thanks for joining us. Today's prepared remarks will begin with an overview from our CEO, Tom Jorden, followed by an update on our drilling activities and results from John Lambuth, EVP of Exploration, and then Joe Albi, our COO, will update you on our operations, including production and well costs.

Our CFO, Mark Burford, is also present to help answer any questions. Yesterday afternoon we posted an updated presentation to our website. We may be referring to this presentation during our call today. As a remainder, 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 in our latest 10-K and other filings and news releases for the risk factors associated with our business.

So that we can accommodate more of your questions during the hour we have allotted for the call, we'd like to once again ask that you limit yourself to one question and one follow-up. Feel free to get back in the queue if you like. So with that, I'll turn it over to Tom..

Thank you, Karen, and thanks to everyone who's participating in today's conference call. As always, we appreciate your interest and look forward to your questions during the question-and-answer portion of the call.

On the call today, John will walk us through our recent results and describe our progress on of the delineation projects that we have underway, and then Joe will follow John with a detailed operational overview. For the first time in a long time, our production came in below guidance.

We averaged 947 million cubic feet equivalent per day in the third quarter, slightly below our guidance of 950 million to 980 million cubic feet equivalent per day. We expected the third quarter to represent the low point in our production for the year.

However, we face delays in our completion owing in large part to the timing effect of our upside stimulations. We did not properly plan for the significant impact for setting in offset wells during completion operations, nor did we fully account for the 7 million cubic feet equivalent lost to higher ethane rejection.

The combined effect of these factors caused us not only to miss on the third quarter, but to bring down the fourth quarter outlook as well. We don't like to miss our forecasts on any of these items, and quite frankly, we need to do better. I think it's worthwhile to put the delay in our production trajectory into context.

Cimarex responded swiftly and deliberately to the downdraft in commodity prices that reached its nadir in February of this year. In the fall of 2014, we had 26 operated rigs running. We reached a low in summer of 2016 with four operated rigs.

As we ramped our activity in the second half of 2016, a disproportionate amount of our operated and non-operated drilling was on large, multi-pad pilot development projects. This concentration of effort on a handful of large projects put our production ramp at particular risk to timing delays. That said, we offer no excuses.

We need to do a better job of risking these potential delays and building them into our forecasts. We've learned the hard way, the wisdom of Yogi Berra, who said "it's tough to make predictions, especially about the future." Our 2016 exploration development capital budget is now $785 million, that's up $35 million from previous estimates.

The increase is tied primarily to the activity associated with rig additions this year, and approximately $15 million in seismic and acreage acquisitions we made in third quarter. Even though our production ramp has been delayed into Q1 2017, much of the completion cost associated with this ramp will be incurred in 2016.

In yesterday's release, we gave preliminary guidance for 2017. And I want to be clear that this is preliminary. We wanted to give some clarity on what 2017 looks for us, but these numbers for capital, for production, these are baseline numbers. We certainly have tremendous wherewithal to accelerate.

We'll enter 2017 with great momentum as the aforementioned deferred completions come roaring back. We currently model total production growth in 2017 to be 9% to 14% year-over-year, with an overweight in oil production embedded in this growth. We also gave guidance on drilling and completion portion of our capital.

Based on our current plans, we plan to invest $600 million in those activities next year. $600 million is within our cash flow for 2017 as we currently model it. So again, we think of this as a baseline. We have the ability to add activity as the year unfolds, and in fact, we're currently looking hard at several projects we have on the drawing board.

As always, we will give you an updated look at our capital plans in our next call. That will be in February, and that will include our total E&D expenditures as well as our first-quarter 2017 production. By then, I expect to have tremendous clarity and additional projects and what it looks like as we move ahead on that baseline.

Enough about production. I want to spend a few minutes talking about what we're really excited about. We continue to push the envelope in completion, optimization and innovation. We are seeing outstanding results that have implications for well spacing and landing zones.

In both the Delaware and Anadarko basins, we're planning pilots for 2017 that will test even tighter well spacing. These tests have tremendous implications for the depth and richness of our inventory. We built Cimarex on exploration, and we are hard at work developing new ideas.

We have challenged our organization to develop new play concepts and opportunities where the cost of entry is low and real value is created for our shareholders. Our organization has responded accordingly, and we are working on a number of ideas that hopefully will be subjects for future quarterly calls.

Idea generation, execution and innovation have always been the heartbeat of Cimarex, and it's what distinguishes us from an outstanding field of competitors. We are playing to our strength as we seek that proprietary edge that lets us slip in ahead of the crowd. We have some of the finest assets and one of the finest organizations in the business.

Stay tuned. With that, I'll turn the call over to do John to provide further color on our program..

Thanks, Tom. I'll start with a quick recap of our drilling activity in the quarter, before getting into some of the specifics of our latest results and more color on our remaining 2016 plans. Cimarex invested $175 million on exploration and development during the third quarter.

About 61% was invested in the Permian region, with the rest going toward activities in the Mid-Continent region. Companywide, we brought 42 gross, 17 net wells on production during the quarter. We had an average of five operated rigs running during the quarter. These rigs were busy working to hold acreage in both the Wolfcamp and Meramec plays.

We have recently added three rigs, one in the Anadarko and two in the Delaware Basin, and we have plans to add another rig in Anadarko by year-end. While we work through our completion backlog, we will pick up the pace on our drilling activity as we head into 2017.

As planned, during the third quarter we brought the six 7,500-foot long lateral Upper Wolfcamp wells online that comprise our spacing pilot in the Upper Wolfcamp in Culberson County.

These completions used about 2,400 pounds of sand per foot, while also incorporating design parameters such as stage spacing, cluster count and cluster spacing from some of our more recent parent-well frac designs. These wells have been flowing back now for just over 90 days, and yet we still have not achieved a peak 30-day average rate.

This result is not unexpected, since it usually takes our upper Wolfcamp wells much longer to clean up and reach their peak production rate relative to the Lower Wolfcamp Culberson Wells. The results of this spacing pilot are especially meaningful in light of a recent result to further delineate the Upper Wolfcamp interval in Culberson County.

Earlier this year we completed the Kingman 45 State Unit 2H, which is located in the western half of our Culberson acreage. On our presentation, slide 10 identifies the location of the Kingman well. Before this well, most of our Upper Wolfcamp drilling had been in the southeastern part of our acreage.

This 10,000-foot lateral had a 30-day peak average rate of 2,057 barrels of oil equivalent per day, of which 1,192 barrels, or 58%, was oil. The Kingman was completed with 1,700 pounds of sand per lateral foot and came online in late April.

In its first 180 days, the well has cumulative production of 308,000 barrels of oil equivalent, including 169,000 barrels of oil. This excellent delineation result opens up our acreage on the western half of Culberson County, where we plan to do further testing in 2017.

We also just finished drilling an Upper Wolfcamp well north of the Kingman well in Eddy County, which, depending on results, could open up even more acreage for development in the Upper Wolfcamp. Completion of that will is planned to begin in mid-January. We've completed 17 gross, 10 net wells in the Permian during the third quarter.

Fourth quarter capital in the basin will be focused on completion activities and acreage obligations across our Wolfcamp position in both Culberson and Reeves County. We currently have five rigs running in the Delaware Basin. Now on to the Mid-Continent.

You will recall that we began drilling the latest Woodford development project on the east side of the Canaccord in the fourth quarter of 2015. This development covers six sections, of which Cimarex operates two sections.

Completion of the wells began in mid-September, with all the Cimarex operated wells now completed and beginning early stages of flow back. These wells, along with partner operated wells, should be coming on production over the next two quarters. We also completed the Leon Gundy wells, our stacked/staggered Meramec-Woodford spacing pilot.

These wells were brought on production in mid-October, thus it is too early to discuss any results. We look forward to discussing these wells in more detail on our next call. We also continue to both delineate and hold our Meramec acreage, with our most recent well results in this play performing as expected relative to our pre-drill expectations.

Of the four rigs we plan to operate in the Anadarko Basin next year, three of them will be dedicated to holding our Meramec acreage. 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 start first with our third quarter production results, then go into some detail on our revised Q4 2016 forecast and the resulting 2016 production outlook, and then, with an underneath-the-hood look at our forecasted late Q4 ramp up in production, I'll give you a glimpse of our preliminary 2017 production outlook.

I'll then finish up with just a few comments on LOE and service costs. As Tom mentioned, with reported net equivalent daily volume of 947 million cfe a day, our third quarter production came in just shy of our guidance range of 950 million to 980 million cfe. Two main factors came into play when comparing our actual results to our guidance.

First, we saw an unanticipated net volume reduction of approximately 7 million a day as a result of ethane rejection associated with the processing of our share of outside-operated Mid-Continent gas during the quarter.

And secondly, we experienced approximately 13 million a day of production downtime due to slightly longer than anticipated completion times and the shut-in of the wells associated with those completions. These two factors alone pulled us away from the midpoint of our guidance.

If we look at Q3 by region, with the pickup of our Permian completion activity in mid-Q2, our third quarter Permian volume of 517 million cfe a day was up 2% from Q2 2016, while our third quarter Mid-Continent volume of 427 million cfe a day was down 2% from the second quarter, a result of our beginning-of-the-year slowdown in Mid-Continent completion activity, which we just recently picked up, as John mentioned, up here in late Q3.

Looking forward, before touching on our fourth quarter guidance, I want to provide a little color on our frac fleet utilization strategy.

To provide consistency in our frac fleet utilization and operational results, and to maintain full control of the timing and scheduling of our frac operations, we've opted to retain a consistent number of fleets to complete our wells.

With a fluctuating rig schedule and a good mix of multiple and individual well completion projects, we carefully plan our inventory so as to minimize adding and dropping crews. If we did add and drop crews, we'd risk the ability to pick up the crews (13:35) with which we've worked so hard to develop our operational efficiencies.

Which means that when any completion operation takes longer than expected, either due to an operational or weather issue, or as a result of changing completion design on the fly to pump a larger, more time-consuming job, there's a domino effect on the timing of all completion operations following in queue.

Our Wood State completion is a great example. When we provided Q3 guidance, the then-planned job size required an 18-day time period to complete each three-well pad. Subsequent to providing guidance, we changed the job design, which required a 30-day time period to pump, and pushed back other wells and projects in queue.

We saw this in the Mid-Continent as well, and as a result we pushed out first production for some significant wells and projects that were previously forecasted to add production in early Q4, now to come on later in Q4, and pushed others out into 2017.

So in a nutshell, at the total company level, we've moved a number of our significant completions into late Q4, and a total of 10 net wells previously slated for late Q4 into early 2017.

With large anticipated production increases from our pilot and infill projects, simply sliding first production two to four weeks has a big impact when projecting volumes for 12-week quarterly time period, and as a result, our Q4 production forecast dropped from our last quarter estimate.

We have a number of significant infill projects forecasted for Q4 in both the Permian and in the Mid-Continent. In the Permian, we revised our first production timing for our Wood State project in Reeves County, with first production now forecasted for late November/ early December, versus our last quarter estimate of October.

With the revised completion timing, we've also moved first production for five net Permian wells, including production from our Tim Tam project, into early 2017.

Similarly in the Mid-Continent, revised timing for frac operations has pushed out the timing for first production from our East Cana infill project, with our operated Nancy Condrey (16:49) sections now scheduled to come online in November and December, and our non-operated project sections now forecasted to come on in the December to early 2017 timeframe.

As a result, five projected net Mid-Continent wells have also moved into 2017. So when the dust settled, our updated Q4 production guidance now sits at 945 million to 985 million cfe a day, with a fast production ramp forecasted for the latter half of the quarter.

With the increase, we are projecting December total company net equivalent volumes to be in excess of a Bcf a day. As Tom mentioned, we have put together a preliminary nine-rig plan for 2017, funded comfortably with projected 2017 cash flow projections using our current strip.

With the carryover of our Q4 '16 completion activity, and the anticipated ramp-up in associated production into 2017, we're projecting a preliminary estimate of 1.05 to 1.1 Bcfe a day for our full-year 2017 production.

As compared to the midpoint of our current 2016 full-year production guidance, this represents a 9% to 14% increase in production during 2017. As Tom did, I want to again emphasize as well, this is a very preliminary plan.

The plan can change as a result of many factors, including changes in commodity prices and/or changes in any of our activity levels, our project selection, and the timing of our capital deployment.

Shifting gears to OpEx, we posted another nice guidance beat with our third quarter LOE, and we owe it all again to our production groups' continued efforts to reduce our operating cost structure.

We commend their efforts, and with their focus we continued to realize significant cost reductions during the quarter, seeing some nice reductions in equipment and maintenance, contract labor, and rentals in particular.

As a result, our Q3 lifting cost came in at $0.61 per Mcfe, at the low end of our guidance range of $0.60 to $0.75, down 6% from Q2 and down 27% from the $0.83 we posted for an average in 2015.

After incorporating our continued cost control efforts and the fluctuating nature of workover expenses, we're projecting our remaining year lifting cost to be in the $0.60 to $0.70 range. And finally, some comments on drilling and completion costs.

We continue to see our drilling cost components remain relatively in check, and have seen our completion cost components for the most part level off. That said, we're beginning to feel upward pressure on completion costs, with any increase most likely to occur after the beginning of the year.

With that, we continue to focus on efficiencies on the drilling side by cutting down drilling days, and on the completion side by optimizing our completion design, optimizing our water sourcing, and optimizing our pumping operations. With our costs in check, our generic well AFEs are flat to last quarter in the Permian.

Our current Bone Spring 1-mile lateral AFEs are ranging $4.7 million to $5.1 million. That's flat to last quarter, but down 6% from earlier in the year. In the Wolfcamp, with larger completions, our current generic 2-mile lateral Culberson Wolfcamp AFE continues to run in the $10.2 million to $11.2 million range.

That again is flat to last call, but down 5% from Q4 2015 and down 23% from late 2014. With our larger frac design, our Cana core 1-mile lateral Woodford AFE continues to run in the range of $7.1 million to $7.5 million.

That's up from the $6.6 million to $7 million range we quoted with smaller fracs earlier in the year, but we're still down 10% from late 2014.

And finally, as we continue to experiment with frac design, our current 2-mile lateral Meramec AFEs are running in the range of $10.5 million to $12 million, with frac design really being the largest cost variable in the total well costs for our Meramec wells. So in closing, we had another good quarter.

We continued to make strides to reduce our operating cost structure, we stayed focused on efficiencies to reduce and optimize total well cost, and we continue to make progress maximizing the productivity and profitability of our wells.

Although we've seen our completion timing push out first production for a number of our bigger projects, due primarily to pumping bigger and bigger jobs, we're very pleased about our well results, and for that matter, we're very pleased about our entire program. So, with that, I'll turn the call over to Q&A..

Thank you. We will now begin the question-and-answer session. Please limit yourself to one question and one follow-up. At this time, we will pause momentarily to assemble our roster. Our first question comes from Arun Jayaram of JPMorgan. Please go ahead..

Yeah, good morning. My first question, Tom, is just thinking about the 2017, call it preliminary outlook. A couple of questions around that. One is, if I look at your spending in the quarter, you spent $175 million, and if you annualize that you'd be at $700 million, and your rig activity is ramping.

So I'm just trying to put that into context relative to an initial D&C spend of $600 million? Because it does like you are accelerating from that $175 million that you spent in Q3?.

Yeah. Arun, I'm going to give you an overview answer and then I'm going to turn it over to Mark for the detail. The quarterly spending is really a function of drilling rigs but also completion timing. And it's driven not only by the pad development timing, but there's also a fair amount of non-operated timing.

That preliminary $600 million is an annualized rate if we kept those nine rigs running throughout the course of the year. Quarterly spending can fluctuate depending on how that gets bunched up.

Mark, do you want to add to that?.

Yeah, Arun, we have a little choppiness in our capital spend levels with the amount of completion dollars we have in any one quarter.

Actually you'll see in the fourth quarter, applied guidance has quite a uplift in capital costs for completions, of which we will have a number of completions occurring in the fourth quarter, a lot of them later in the quarter. But you'll see an upward kick into 2017.

And as Tom said, it's a nine-rig program timed out with the capital and completion dollars with that program..

Arun, just to finish that thought, we're feeling really solid about the quality of our returns, the quality of our program, and the things we want to accomplish.

So even though I know oil markets are a little nervous here in the last week, we're feeling a little better about some of the fundamentals, and so our bias as we sit today – and again this is just today – but our bias is going to be to lean forward on that capital number, and we're looking at a lot of things that we want to get done, and we'd like to get them done sooner rather than later.

So I think there's a pretty good chance we'll be giving meaningful updates here in our next call..

Okay. And if I could just elaborate on that point, because the initial, and again understanding its initial, but right now if you look at our forecast and consensus, it's between $1 billion to $1.1 billion of EBITDA, so the number that you put out there last night would suggest quite a bit of free cash flow generation.

So I'm just trying to understand is if you guys are thinking how you plan to balance growth versus potential free cash flow, and is there an intention, as we think about modeling for next year, to spend your cash flow? As you know, this is a market that is rewarding growth to a decent extent?.

Well, the market will reward what the market rewards. There's a pretty big difference between a spreadsheet and iron deployed on the ground. And we're poised for increased activity. We have lots of things to do, and our bias is going to be – we don't have a great interest in keeping cash on our balance sheet; our bias is going to be to activity.

And we focus on the returns on that investment, and as you know, you all get tired, I sound like a broken record, I think growth is a nice outcome of really good, prudent investments. And we're feeling pretty confident about those investment opportunities.

Mark, do you want to comment on that?.

Yeah, Arun, as we talked in the past, over the last six months, we've been continuing to watch for stabilization in commodity prices. It's been seeming that some more stabilization occurring lately, but obviously even more recently there'[s some more pressure on oil recently, with some of the OPEC discussions.

But certainly, with the Street forecast probably embeds a low mid $50 oil price, if that kind of environment starts to play out into 2017 and we feel that's a good price to be working off of as far as capital generation, certainly want to increase our capital level..

Yes, I will say from my viewpoint, I have a strong bias to spend our cash flow. And if we have any kind of signals of stability – and we think we are seeing those signals. We've talked a lot about structural reset in the markets, and we feel like we are starting to see that.

And so our bias is going to be to spend our cash flow, and possibly – that cash on our balance sheet is there to be invested. So we're looking at it carefully. It's a good question, and you're right on point with the way we're viewing that..

Thank you very much..

Our next question comes from Drew Venker of Morgan Stanley. Please go ahead..

Good morning, everyone..

Hi, Drew..

Hi, Tom. So on the 2017 program, the capital plan indicates to me, at least, a really big uptick in capital efficiency. And I think that's clearly occurred on the well productivity side.

Is there an element of cost improvements at the well level for the further efficiencies that Joe talked about? And I did catch that he said costs really haven't gone down at all from 2Q, so was hoping you could provide some color there?.

Yes. Mark, why don't you take the capital efficiency, and I know Joe will make some comments on costs..

Yeah, right. Drew, there is definitely more of a program going with longer laterals and we also have the efficiency improvements we've seen in our uplifts and our frac design. There is some capital efficiency embedded in it.

But certainly there's also some efficiency gained from the fact that we are bringing forward wells from 2016 into 2017, that's a big part of what's happening into this next year's forecast, is the fact that we have carryover, as we mentioned in the release, 10 wells carrying over from 2016 that we previously thought would in the fourth quarter into 2017, so that's helping, getting that front-loaded production into 2017..

And this is Joe.

I'd say that's the primary driver to the capital efficiency calculation there, that you've got our significant East Cana infill projects coming online right at the end of the quarter, you've got the Tim Tam, you've got the Wood stage, you've got big chunks of new production starting off the year in 2017 with the capital deployed in late 2016..

Okay. Thanks for the color. And then if we can go over to the Culberson Wolfcamp A, I think is one of the highest rate of return assets in your portfolio, if not the highest.

And so given the successful delineation you've had across a lot of that position there, do you expect to move into more of a development mode in 2017?.

Yes. This is John. Yes.

I mean, there is both a combination, we still have some acreage obligation we need to do, and I need to point out what's really, really nice about that Kingman result is it gives us great encouragement to, quite frankly, put more wells over there on that west side, which further helps us secure our acreage across the entire Culberson position.

So that was a really significant outcome for us, we're really pleased with that well. Likewise, as we continue to monitor our current spacing pilot, the Sunny-Gato pilot, we're already in plans for the next development phase of Upper Wolfcamp.

We have a couple of sections in mind, and really the thing we're debating it just how tight do we want to put the wells. And again, a little bit of time here as we continue to watch the flow back of our current spacing pilot.

And I just want to make another comment, as much as I can't talk a lot about it because we haven't gotten our "peak rate," I would still consider a very encouraging sign that we're still seeing continued improvement, that is, the wells are continuing to clean up.

I think we're encouraged by that, and hopefully by next call we'll be able to give you a lot of color on those actual results of those wells..

Thanks, John.

And I guess with that in mind, does that give you comfort that you'll be able to incorporate the results of that spacing pilot in time for budgeting for 2017? Or would it still be kind of, prior learnings would be the basis for your capital plans in Wolfcamp A?.

Well, I think the only thing I would say is, within our budgeting for 2017, we've incorporated some development in Upper Wolfcamp. What might change, again, is maybe a well count on a section where we'll maybe add an additional well or two. But the full scale of the budget, I don't think that will have a huge impact on it.

But, no, our intention is to incorporate the results from that pilot to then help dictate how we go forward with our future development in the Upper Wolfcamp. But those Upper Wolfcamp developments currently on the schedule, I believe, aren't really start drilling until late second, early third quarter, last time I looked at it..

Yeah, Drew. the word development doesn't mean what it used to mean. Everything we do, we're testing something. The beauty of our assets is that we're making really good returns while we test it.

But there's some great innovative thinking going on in our organization on stimulations and well spacing, and we've got some significant tests to look at that could have meaningful implications for our overall inventory. So we can use the word development, but everything we do has learnings that impact future operations..

Thanks..

Thank you. Our next question comes from David Tameron of Wells Fargo. Please go ahead..

Good morning. I'm going to go back to 2017 again.

If I just think about the big pad completion coming online in the first quarter, how should we think about your quarterly kind of production run rate through the year? Should it be flattish to a slight incline drought the year, or how should we – any guidance you can give me there? Any color you can give me there?.

Yes, this is Joe. As modeled, with the larger projects coming on at the first part of the year, and then as we look out through the remainder of 2017, the placeholders that we currently have in place are more single-well project in nature. You'll probably see a ramp in the first two quarters of 2017, and then relatively flat for Q3 and Q4.

But again, this is just a preliminary plan that we put together based on capital assumptions for 2017..

Okay, thanks for that color. And then I guess Tom, if I look at – I'm looking at slide 13 of the new deck, which is those Upper Wolfcamp completion design, those four Wells in Culbertson.

And I look at that and then I look at the prior – same slide from a couple months prior, and it looks like the blue and the red line are – that increase is decreasing over time, so that gap's narrowing over time?.

And I'm just getting back to this, there's this debate a couple years ago that's kind of got lost lately, but are you pulling more value forward? Are you really increasing the EUR? What exactly – what's the endgame as far as these higher completions? Can you – can I look at these four wells and make a determination based on that? Or can you give me more color, what you think, as far as ultimately what the – is the sand really driving higher EURs, or are you just accelerating that value, I guess?.

Well, I'm going to just set the stage, and then John will take it from there. The devil's in the details, and one of the things that completion and optimization really allows you to focus on is rate of return. So we don't really judge it by production uplift nor EUR uplift.

We look at the return, and that's usually defined by certainly your first 18 to 24 months of production. And there's a raging debate as to at what point we end up accelerating and at what point we're having a new reserves.

But as long as we focus on the return on an incremental completion investment, and we use really good, well-grounded data in doing that, that's not really a first order of concern. It's something that we will learn over time. Now, again, the devil is in the details when you compare this blue to the red curve.

There's lots of optimization in the Wolfcamp that we haven't experimented with, and I'm going to let John take it from there..

Well, the first thing I would say is I would again emphasize what Tom just said. When we look at these additional costs on our frac uplifts or optimization, we are always looking at it from the standpoint of the incremental cost relative to the rate of return that that well achieves, and that is our first and foremost measure.

We certainly also look at – we debate a lot internally over, yes, how much of this – is there a component of acceleration versus how much of this is new reserves? And honestly, there's still a lot of that to be determined as these wells continue to perform, and we'll watch that very carefully.

As far as innovation, yeah, I don't – I do not believe, for either the Upper or Lower Wolfcamp, that we still have achieved the optimal frac for an individual well. And we talk about that all the time internally.

And we have a lot of experimentation, in fact a well in particular coming up that we're going to test a lot of concepts and ideas, where we still think there's possibilities to achieve – or recover more reserves out of that rock. So I guess all I could tell you is, we watch it carefully.

We monitor it carefully as far as the incremental cost to make sure it's a good decision, and we're going to keep trying to innovate on it..

I might just finish with one point, I'm not – we wouldn't look at slide 13 as necessarily the guiding light to make this decision. There are lots of things that are second-order advancements or innovations, and that would include cluster spacing, it would include pounds of sand and fluid per cluster.

And so it could be that the blue and the red curve may lie on top of one another, but if we can get more wells per section, that's a huge, huge advance for us. So again, the devil is in the details on this..

All right. I appreciate the color though, helpful..

Thank you. Our next call comes from Pearce Hammond of Simmons Piper Jaffray. Please go ahead..

Color on 2017.

My first question is, when you look at well cost per lateral foot, do you think that's starting to level out, and maybe even start to move up as the intensity of the completions increases, as well as just service costs moving up?.

Yes, this is Joe. I'd say the general answer to that is yes, but it's, like we've been talking about, here too, the types of design of your frac, the pounds of sand, the amount of fluid, your cluster spacing, your science projects, what have you; I tend to look at it more on the basis of cost components, because they're the variables we can measure.

And what we're seeing on the drilling side are relatively flat cost components. On the completion side, it's no secret, you've heard the likes of Halliburton talking about increasing their service costs, we anticipate that it's entirely possible we may see somewhere, 5% to 7% some-odd increase in our completion service costs as we move forward.

But overall, when you put it in the blender and turn it on, there is so many variables. How efficient can we be at sourcing our water, and we're spending a heck of a lot of time on that. And again, optimizing the cost-benefits of the different frac designs, so that whatever the cost is we see the optimal side of it on the production side.

These are all things that we're constantly scrutinizing and studying, and the end result is what Tom and John have both alluded to, what's our best rate of return? So I kind of danced around your question, but I think I left you with some flavor..

No, that's helpful. Thank you.

And then my follow-on just sort of grows from that, but when you put out your preliminary 2017 capital budget, have you done those services to kind of lock them in, so that you don't have the incremental service cost inflation on top of the guidance that you've already put out?.

No. We've got just wonderful relationships with our service providers, and I think we know well in advance about what our cost structure is going to be looking like the next three to six months out. We have strong confidence that we'll be able to manage our cost, particularly on the completion side, through the duration of 2017..

Thank you for taking my....

I just want to follow-up on that. We typically don't prefer to do long-term service contracts. And I know there's lots of people that see that problem differently. Locking in, that's – works on both sides, and I'm not sure who is locked in. We like flexibility. We like the ability to adapt our program up and down depending on changing conditions.

So we're typically market takers. We look for good relationships, as Joe said, we look for high quality service companies, we look for safe, responsible service companies, and our history as a company has steered us away from long-term contracts..

Thanks, Tom..

Our next question comes from Neal Dingmann of SunTrust. Please go ahead..

Morning, Tom, and great detail so far. Say, Tom, just when I was looking up at slide 10 of yours particularly that talks about the Culberson and Wolfcamp details, and you guys have certainly added just a large amount of new oil gathering.

And so some of your peers mentioned maybe being constrained next year, or having the infrastructure limit what they can grow.

Is that going to be any sort of issue for you all, particularly in the Delaware Basin, that would limit your growth in any regard?.

We don't see that as a constraint over the next couple of years. We always model that out, both on a local and a basin-wide level. And certainly we've got a good relationship in Culberson, Plains is our gatherer and they've got good takeaway capacity and we're in very good shape there.

There's been a tremendous amount of processing capacity built out in the Delaware Basin.

We look at not only that, we look at gathering, and we also look at basin takeaway, and we're typically looking two to three years out, because that is usually the window in which if you have to lock up firm or do some kind of contractual obligation with a midstream Company you can build in advance, but we currently don't see that as an intermediate-term constraint.

Do you want to comment on that, Joe?.

I agree entirely. We've – when we put our project together with Plains, we had done a number of multiyear models on targeted drilling programs – or projected drilling programs and the resulting throughput. And we have a high degree of confidence in the capacity of the oil pipeline system that's currently in place in Culberson.

And then likewise on the gas side, adequate processing and at least, given where we are today with the number of projects that are out there, two, three years' worth of capacity on the processing side and also on the takeaway side. So we feel very comfortable about both the gas side and the oil and NGL side – all three of them, I guess..

So, guys, does that just – again, it seems like others have to use a lot of their capital to do some of this build-out themselves.

But you all, certainly – is it because of your great relationships and looking this far out with some of these third-party partners that you don't have to use the capital, and you have more than needed?.

Well, we do spend midstream capital. And in Culberson, in particular, we do own and operate our gathering system, and that's been a great benefit to us, as our Permian production manager reminds me every chance he can get. It's been a really, really smart thing for us, and we reached out and did some risk in doing that.

And – but we have capital discipline. We really look at our midstream investments carefully. We want to make sure they're balanced against our drilling and completion capital and not get ahead of ourselves. And that's been important to us.

So I think Cimarex probably does view midstream a little differently than some of our peers, and we like just-in-time midstream investments.

I'm going to finish by saying that both those outlets in Culberson, the Plains and the MarkWest plant that was built, that was a really great outcome through the partnership we have with Chevron – the joint development agreement with Chevron. And I think it's been well crafted, and it's a great benefit for both companies..

Okay.

And then just lastly, really quick, Tom, just on bolt-on opportunities, either Permian or Mid-Con, what's your thoughts as you look into 2017?.

Just for general opportunities?.

Yes, sir.

Just for bolt-ons there for either one, just to sort of block up either of those -continue to block up those positions?.

Well, we look at every asset on the market. And I get asked from time to time, do we just count our money differently? And maybe we do. We have a very difficult time with some of the acreage prices that are becoming commonplace. But we look, and we would love to do bolt-ons.

We're also seeing a lot of operators come together now and have a greater willingness to swap acreage, so we can drill 10,000-foot laterals.

John, do you want to comment on that?.

Well, yeah. I think over the last year or two – and I'm proud to say, I think we led that way with our long lateral results, you had a number of other Wolfcamp operators who were kind of stranded with their sections with only 5,000-foot laterals.

And now we're starting to see more and more other companies willing to talk about trading acreage, section for section, such that they as well as us can leverage long laterals. And we're getting a few more of those deals done with a couple of different companies out there.

And I would not be surprised you'll see more of that happening where each company tries to kind of block of their own acreage. So then you get those capital efficiencies, with the long laterals as well as the midstream assets and disposal. So we'll see more of that. Would I love to get more bolt-on acreage? Absolutely.

And as Tom said, we look at every deal possible, especially adjoining to our position. And we just can't seem to come to the same valuations that others are able to in this current market..

Great. Thanks for the details, guys..

Thank you. Our next question comes from David Deckelbaum of KeyBanc. Please go ahead..

Morning, Tom and everyone, thanks for taking my questions. I was hoping just to go back to – I know you guys gave a lot of information around the discussions and the delays in Cana.

I just wanted to clarify little bit, the increased time – you talked about the impact obviously of the ethane rejection, but the increased time, was a created from having to shut in wells? Was the time itself just related to the frac job itself? And is there an expectation of significantly longer time for these wells to be cleaning up once they're on line?.

This is Joe. The answer is not embedded and it's taking longer for the wells to clean out. It's entirely tied to the timing of the frac itself and the duration of the operation of the frac.

And the loss, I guess if you want to call it that, as compared to the previous forecast in production with a longer timeframe for a given well that is newly completed. But also in conjunction with that, we are offsetting wells in and around the wells that we're fracking.

And the delays that we see there is going to get a little bit multiplied, if you will, by some number based on the number of wells that are offset. So it's a combination of both.

It is entirely due to when we anticipated a frac to start in our Q3 guidance, and end, and the wells that would be associated with that frac that were shut in and the volumes that would have been deferred..

So the shut-ins were anticipated, just the duration of it was not?.

Correct..

Okay. I appreciate that. And then....

David, I just want to add to that. One of the challenges is, with these pads, the shut-ins are longer in duration than we're typically used to, and it's more significant than it's been to us historically.

Some of these shut-ins, if you are on some of these significant pads, you might be shutting in offset wells for a couple of months while you complete them. And that's a little different issue..

Yes. Especially I would say operationally in the Permian. I think we're more used to it in the Woodford because that's how we've been developing our acreage. We do multi-section development, so we anticipate the significant shut-ins.

Honestly, up until this year in the Permian most of our shut-ins were always associated with a one-off parent well, and typically then we'd only experience a week of shut-in.

Now when you go to major six-well developments like Wood, and then you incur a little bit longer time because of the frac design change, that certainly then led to far longer shut-ins than we typically had been used to. Obviously now we're adjusting, and we will plan for it accordingly, going forward.

But that's really what, hit us pretty hard in the Permian here, in this last few quarters..

And gaining a better understanding of the wells that will most likely be associated with that operation, to be shut-in..

I appreciate that. And my last one was just, you talked about the three rigs, I guess, running in Meramec next year to HBP, and I guess want to delineate. Can you just remind us how much of your acreage will be held, then, with the three rigs? And then I guess with the one delineation well, I guess you're testing various pilots.

What area of your acreage do you think there's sort of the most debate about that you'd like to do some density tests on, and to which zones?.

Let me be clear in terms of my statement. The three rigs that I referred to will be holding acreage while delineating Meramec acreage, it's kind of a combination of two things. Those three rigs through the end of the year will pretty much ensure that we keep all of our Meramec acreage intact, with those three rigs throughout the rest – all of 2017.

The fourth rig that will run in Anadarko will more – most of the time be dedicated to more Woodford drilling in areas where we're testing other Woodford concepts.

Again, the three rigs will be both holding acreage but also delineating, in a sense, because we still have areas in the Meramec that we'd like to get results in and get a good idea of how well it will perform.

I will say that a lot of our acreage holding in the Meramec will be in more of that northwest part of the map, that's where we got out ahead a couple years ago, that's where a lot of our term acreage is. And so that area where I think previously we announced the Peterson well, as well as the People's well.

We have a lot of acreage to hold up in that area, so we have a lot of rigs headed – a lot of drilling to do next year in that area. And so far, both ourselves as well as some of our competitors have announced some very impressive wells in that area.

So inasmuch as we're holding acreage, we're holding acreage with what appears to be some really good rate-of-return opportunities with the rigs we'll be running there..

Thanks very much for that color, John. I appreciate the answers..

Thank you. Our next question comes from Jason Smith of Bank of America. Please go ahead..

Hi, good morning, everyone.

Tom, just coming back again to the 2017 guidance – and I wanted to touch on slide six really quickly – can you help clarify what oil growth looks like, relative to total growth in MBOEs next year?.

No. We didn't give specifics on oil growth, Jason, but if – what I said is, we're talking about a top-line growth number, and oil growth that underpins that that will be substantially larger than that top-line number. We'll give some color on that on our next call.

But I will go ahead and tell you we're pleased with what we're seeing in oil growth for 2017, but I think I'd like to defer specifics until we can come back at you with much more detail on our capital program.

Was I sufficiently evasive there, Jason?.

No, I appreciate that and I appreciate. It's a bit of a moving target right now. But – and maybe sticking on that front, in the Cana, your partner yesterday led out a pretty optimistic picture with a nice step-up in oil yields relative to legacy production.

So as you move beyond your current set of completions, can you just talk about how the Cana-Woodford fits from a capital allocation standpoint into next year, and maybe just the timing around your next set of completions?.

Well, I'll start and John will still add on to this. Certainly a lot of what we're looking at in the Woodford next year is on that eastern corridor, which is much oilier. It's offering outstanding returns, and I think you will see a joint project along that eastern corridor in 2017.

And we're in the process of formulating that, but yeah, it'd be an oilier project.

John?.

Yes. It's an exciting project because, as our partner elaborated – I saw their write-up on it – it is a long lateral development project. It's 10,000 foot laterals in an area where we get very good condensate yield, with very good rate of returns.

I will tell you, the biggest questions we have regarding that, quite frankly, is how many wells per section do we want to put? Based on our previous results in what we call Row 4, Armacost Phillips, where we pushed the spacing even tighter, we've been very pleased with those results.

Likewise the current developed section, the eastern core infill, our partner has a number of sections were they again are testing tighter spacing. Those results, as well as perhaps even some other things we want to test, might lead to even more wells per section within that development, which even makes it more appealing to us.

So there's a lot of discussions with our partner about that, and we fully anticipate, certainly in the second half of next year, that we will be deploying rigs on that development project in the Cana area..

Thanks, guys. Appreciate the answers..

Thanks, Jason..

Thank you. Our next question comes from Michael Hall of Heikkinen Energy Advisors. Please go ahead..

Thanks. Good morning. I guess one more follow-up on the 2017 outlook. Certainly sounds, like you've said, your current view is preliminary and the bias is towards more activity.

I am just curious on what sort of timing is required, in terms of how quickly you need to lean into that budget to really impact 2017 growth?.

Yeah, Michael, that's a great question. Certainly these projects have fairly significant legs to executing and before you see production. I will tell you that our bias is sooner rather than later.

I think that one of the lessons we've learned is these projects that are second-half projects that roll into the following year, it just adds noise to our reporting that is artificial. It has nothing to do with the quality of our assets, the quality of the program, but it's just noise.

And so if we had a choice between getting something done early in the year or later in the year, I think you know where we're going to land there is earlier in the year. So between now and our next quarter we're going to be hard at work trying to line some things out.

We would like to get it done so that we are not having these fourth-quarter discussions..

Makes a lot of sense.

And then I guess a follow up on my end, you've talked a bit about exploration in the prepared remarks, just curious kind of how you think about the exploration announcement that we all got regarding the area to the south of you in Culberson County, and potentially missing that opportunity? And then second question within that, is there a Woodford or Barnett possibility underlying your Culberson block?.

Well, I'll just say that we studied that play for a while, we've been watching the activity. As far as missing an opportunity, we could probably have a museum full of plays we've missed; that's just part of our business. We have a lot of respect for Apache and we root for them.

I think it's an interesting concept, obviously they have some challenges between now and commerciality, but they've talked about that and they know how to do that. As far as other opportunities, I will let John handle that..

We – internally we have quite a number of step-out exploration ideas that we're churning, and some quite – in fact, one that we're drilling on right now. These are – this is what we do as a company.

We have tasked our regions and our groups to come up with new ideas, new exploration opportunities where quite frankly we could get ahead of the crowd and get reasonable leasing opportunities at reasonable cost and then take the risk on the drilling side. And we are doing that. And we have a number of those that we will be doing over the coming year.

As typical for us, you won't hear a peep out of us about it until we ourselves have convinced ourself that we have something that is material to the company, and then only then will we talk about it.

But rest assured, we are pursuing a number of exploration ideas, and we will always be doing that because, quite frankly, that's where we find we get the biggest bang for our buck from a value creation standpoint for this company..

Very good. Make sense. Appreciate it, guys..

Thank you. Our next question comes from Joe Allman of FBR. Please go ahead..

Thank you. Hi, everybody..

Hi, Joe..

Sorry if I missed this, but what is your preliminary guidance on other spending besides the $600 million for D&C? So in 2016 you're spending about $175 million on infrastructure and leasehold and capitalized interest and capitalized G&A and other.

So what's the guidance for that for the same items for 2017?.

Hi Joe, it's Mark. We'll give out guidance to the other components in the February call, but you're on the point as far as what we're incurring for other capital for this year.

So it's – we still have to make some assumptions on, some leasehold assumptions as far as what leasehold acquisitions we want to build into our budget and so those components and production capital will have to be settled out as well. But we'll make those guidance figures when we give our February guidance.

And also to make a point on the runway to $600 million, which we did give guidance for was drilling and completion capital only, and actually, as Arun actually asked earlier, that $175 million is total capital, which is not comparable to the $600 million of drilling and completion capital.

We actually incurred $125 million of drilling and completion capital in the third quarter. That's the comparable number to the $600 million. So the run rate is for drilling and completion only of $600 million, and that's on a nine rig program..

Okay. That's helpful, Mark. Thank you..

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

Good morning. Not to put a damper on wanting to spend more, but I actually thought 9% to 13% 2017 growth on a flat spend was rather impressive.

Can you characterize what portion of the growth is completion carryover from 2016? Maybe improved year-over-year well performance, or other factors like more efficient D&C?.

That's a hard number to dissect, which is the component of carryover completion capital.

We will be having a nice ramp into the fourth quarter from the wells we're completing by December, as Joe mentioned; by exit rate would be over a Bcf a day, so we're going to have a nice ramp going into next year, but dissect what component of next year is volume contributions from carryover activity versus improved performance, it's hard to dissect that..

I mean, there are some. Clearly we borrowed a little from 2016 into 2017 in our capital spending level, but it's not a bunch. We just haven't calculated that..

This is Joe. What I would say there is that Q3 of 947 Mmcfe, and I mentioned December at over 1 Bcfe, so there's 50 million cfe a day of brand-new production just entering 2017, and there's still a climb (61:24) into the first quarter with the other carryover that I mentioned of the ten wells coming into 2017.

So I wouldn't be surprised, if we dissect it, that there's a fair percentage that it is carryover..

Maybe another way to think of it, this may be getting out over our skis too early, but based on what you are thinking about now, if you did do a nine-rig program, if that's what it ultimately ended up being, could you create similar growth in 2018?.

On a nine-rig program, a similar type growth into 2018 I think would be difficult..

But again, that's – we haven't really gone into detail there. The thing that we like where we sit right now, as we look at our assets, at current conditions, we're in an environment where spending within cash flow, we can generate growth and great profitability.

And that's something that a couple of years ago, if you had said, in a $50 oil environment, was that a possibility, we'd have been pretty challenged to say yes.

But it's really a testament to the quality of our assets and what our organization's done in innovation on our stimulations, but also getting our cost structure down, that LOE decrease is significant to us in what it does to our margins.

So just leading into your opening question, we are pretty pleased with what the landscape looks to us as we model out-years..

It sounds like you've got great flexibility and we'll look forward to see how it – how the next couple of months unwind. Thank you..

Our next question comes from Paul Grigel of Macquarie. Please go ahead..

Hi, good morning. Just on the 2017, to hit one last item, on the non-op spend, some of your partners have talked about what could be a pretty material ramp in 2017 in a rig count.

How do you guys think about that, and how much of that has been factored into that $600 million?.

This is John. First off, I'll just simply say in the Permian we don't have a lot of non-op that necessarily drives our program. We're basically 100% operators on most of our acreage besides the Culberson JDA with Chevron, but in Culberson we are the operator since we dictate the budget there. The bigger issue clearly is in Anadarko.

First off, of course, we have an AMI partnership with Devon, and we work hand in hand; we are constantly feeding each other exactly our plans. And so we are able to easily put that into our budget forecasting.

The area where it gets a little more cloudy, especially in the Meramec is, yes, there's a lot of – all of a sudden we are getting hit with a lot of outside-operated wells scattered throughout that play. A lot of activity. That has caused probably little bit more capital what we originally planned, but it's not a huge component.

But we'll certainly – we will be accounting for that going into next year, as well.

I will point out again, just like I said early in the Permian, what you will see shake out in Anadarko is once everybody gets to the position of holding their acreage, then you get into where people start doing acreage swaps, or trying to block up, and then that gives you big greater control again over your capital plans.

So in the short, we do account for it. We recognize it, but I don't see it as being a major component, or something that's going to completely lead to a large outspend for us..

Okay, no, that's helpful. And then just a follow-up on the Permian side. You guys make a note in the presentation that you're revaluating 28,000 acres in Ward County.

Could you provide some more color about what the revaluation process is?.

Well, this is Tom. We've talked about that. We do have some new ideas, and Ward – Ward again is looking very interesting to us. And all I can say there is, stay tuned.

We had said in past years that Ward was challenged for a lot of reasons, not the least of which is some of the prior development, and that it would take a new idea in order for Ward to again be at the front of our plate, front burner, and right now it's front burner..

And is that driven by new completion techniques, or is it more on drilling or something else?.

Well it's kind of all of the above. And we're having to tests some things. So we will be commenting on that in future calls..

Thanks, guys..

Our next question is from John Nelson of Goldman Sachs. Please go ahead..

Good morning, thanks for squeezing me in here.

I guess just on the 2017, I know we will get more color in February, but there is $700 million of cash on the balance sheet, so we think about your potential desire – assuming we do see some stability – to lean in, is all that on the table, or how should we think about the magnitude of potential outspend?.

Well, It's all on the table. We raise that capital to bring our net asset value forward, and that's still what it's sitting there waiting to do. Now we'll probably deploy that over a couple of years; I don't think you see us say, hey, Katy bar the doors we're going to run through that money in one year.

But I think that is certainly there, poised for meaningful acceleration, and that's our bias. I mean, that's what we want to do. We have no interest in keeping cash on our balance sheet..

Great, very clear. Thanks guys. Take care..

Thank you..

Thank you. Our next question is from Mark Hanson of Morningstar. Please go ahead..

Thank you. Good morning, guys. Just inking about the mix there of long versus "short" laterals as we head into 2017, I guess all else equal your preference is for long laterals, I think you said that in the past.

But as we think about the 2017 plan, one versus 1.5 versus two-mile laterals, if you could comment on that, that would be great?.

Yeah. This is John. It's very simple; if the acreage is there and allows us to, we always plan to go two miles. It's just that simple. We are that convinced that our best rate of returns that we can achieve is by drilling a two-mile lateral.

Quite frankly, some of the drilling want to go longer than 2 miles, and we talk about doing even that, and we may eventually test a longer than a two-mile lateral. But the simple answer is, if the acreage allows us – and fortunately the majority, the vast majority of our acreage allows us – then it is our preference to go long.

The only time you're going to us consciously choose not to drill a long lateral is like some of these spacing pilot tests, where we're trying to get vital information on how tight to put the wells next to each other. And quite frankly, the length of the lateral doesn't really dictate that result.

And so in that regard, we kind of see that as an efficient way to spend our capital, is just to do it is a 5,000 and get the result, and then leverage that quickly to 10,000-foot laterals in development. So I guess the simplest answer is yes, our bias in any opportunity or any chance is to go long with our wells.

And almost – the vast majority of all the wells that we'll drill in 2017 will be extended laterals, in both basins..

Thank you..

This concludes our question-and-answer session. I would now like to turn the conference back to Karen Acierno for any closing remarks..

Thank you, Nan, and thanks everybody for joining us.

Tom, I don't know if you had anything that you wanted to close with as well?.

Thank you, Karen. I just want to thank you for your interest. We're pretty excited about the landscape ahead of us, and we really do look forward to our next call. We're going to be hard at work between now and then.

Given I know there's been a lot of questions about 2017, we kind of opened a can of worms with what we have said today, and hopefully you've gotten a flavor of just the quality of our program, and we'll come back with a lot more detail here on our next call. We'll be hard at work between now and then. I want to thank everybody..

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