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..

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc. Jason Smith - Bank of America Merrill Lynch Drew E. Venker - Morgan Stanley & Co. LLC Jeanine Wai - Citigroup Global Markets, Inc. Jeff L. Campbell - Tuohy Brothers Investment Research, Inc. Pearce Hammond - Simmons Piper Jaffray David R.

Tameron - Wells Fargo Securities LLC Joseph Allman - FBR Capital Markets & Co. Phillip J. Jungwirth - BMO Capital Markets (United States).

Good day, and welcome to the Cimarex Energy Fourth Quarter and Full Year Earnings Conference Call. All participants will be in listen-only mode. After today's presentation, there will be an opportunity to ask questions. Please note, this event is being recorded. I'd now like to turn the conference over to Karen Acierno, Director of Investor Relations.

Please go ahead..

Good morning, everyone, and welcome to the Cimarex fourth quarter and year-end earnings conference call. In addition to earnings, in a separate release yesterday afternoon, we put out our 2017 capital plans and production and expense guidance for the year. An updated presentation was also posted to our website yesterday afternoon.

We will be referring to this presentation during our call today. As a reminder, our discussion will contain forward-looking statements. A number of actions could cause actual results to differ materially from what we discuss.

You should read our disclosures on forward-looking statements in our latest 10-K and other filings and news releases for the risk factors associated with our business.

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, Senior VP of Exploration; and then Joe Albi, our COO, will update you on our operations, including production and well costs. Cimarex's CFO, Mark Burford, is also present to help answer any questions.

So that we can accommodate more of your questions during the hour we have allotted for the call, we'd like to ask that you limit yourself to one question with one follow-up. And then of course feel free to get back in the queue if you like. So with that, I will turn the call over to Tom..

Thank you, Karen, and thanks to everyone who is participating in today's conference. As always, we sincerely appreciate your interest and look forward to your questions during the Q&A portion of the call. On the call today, John will give a rundown of our recent results and some of the delineation that we have underway in 2017.

Joe will provide an operational overview, including the tremendous progress we're making on field optimization. I'd like to kick off the call with some overview remarks on our 2016 results, as well as our outlook for 2017 and beyond. Cimarex had a very good year in 2016. It was to say the least an interesting year.

It's hard to believe that NYMEX oil prices one year ago today closed at $29 per barrel. We had three stated goals for 2016; preserve our assets, preserve our organization, and preserve our balance sheet. Today, Cimarex stands in the best position we have ever been in.

Our cash flow is strong and improving, our assets are delivering outstanding results and plentiful future opportunity, and our organization is intact and forging ahead. Our investment program generated historically good returns in 2016.

As we look to the future, we see a landscape in which Cimarex is able to sustainably live within cash flow, generate top-tier returns and consistently grow at a healthy rate. Now as always, our focus is on capital efficiency and full cycle return on investment.

When faced with the choice between superior returns and quick production hits, we will opt for the superior investment returns always. In 2016, Cimarex added reserves have replaced 128% of the company's production. Although, our total proved reserves remained relatively flat from year-end 2015 levels, a quick look under the hood explains this.

Proved developed reserves increased 5% year-over-year, and our PUD volumes decreased 17%. We ended 2016 with 21% PUDs, down from 25% PUDs at year-end 2015.

Although the complexion and nature of our undeveloped assets did not change, we chose to adopt a less aggressive stance on PUDs due to the difficulties of managing around the SEC five-year development rule for PUD reserves.

On the financial front, the fourth quarter was the first quarter in two years with both GAAP and non-GAAP adjusted earnings for the quarter. This was a reflection of the increase in commodity prices and our first quarter in seven quarters without a ceiling test write-down.

Production was 960 million cubic feet equivalent per day for the fourth quarter and 963 million cubic feet equivalent per day for the full year, which was within our guidance. Production was down 2% year-over-year, which was a natural consequence of the decrease in drilling activity.

As I said a moment ago, we enter 2017 with renewed optimism and confidence that should oil remain in the $40 to $60 per barrel range, Cimarex will consistently generate attractive returns and solid growth.

In 2017, at the midpoint of our guidance, we expect to grow our overall company production 13%, which will be led by a 25% increase in oil volumes. Furthermore, we project our Q4 2017 oil volumes to increase 30% to 35% over Q4 2016 oil volumes.

The capital program we announced yesterday will have significant carryover into 2018 and provide a springboard into 2018 and beyond. We made significant progress on several technical fronts in 2016. In the Delaware Basin, our Sunny's Halo and Gato del Sol pilots performed remarkably well.

They confirmed eight wells per section in the Wolfcamp A zone of Culberson County. We have a follow-on test underway that will test even tighter well spacing. In the Anadarko Basin, we had encouraging results from Woodford spacing as tight as 12 wells per section and we're underway testing tighter well spacing.

We continued our rapid fire pace of completion innovations, delivering better and better wells and a deeper understanding of the downhole processes that govern our stimulations. As with almost all innovation, the trajectory is not always upward. Our teams are hard at work tearing into some of the mysteries and remaining challenges.

John will provide detail on some of these important pilots and individual wells in his remarks, and will give you a flavor of how our capital will be invested in 2017. 2017 exploration and development capital is estimated to be between $1.1 billion to $1.2 billion, up 56% from 2016 levels.

Of that, about 76% or $850 million to $900 million will be spent drilling and completing wells. This drilling and completion capital tilts toward the Delaware Basin, with 66% of our total drilling and completion capital earmarked for the Delaware. At strip prices, this capital program is funded with cash flow from operations.

We have cash on the balance sheet to fill in the gaps or to expand our program further should we decide. We continue to emphasize our core strengths of idea generation and innovation. In 2017, the challenge to our organization is to do it again. With that, I'll turn the call over to John to provide further color on our program..

Thanks, Tom. I'll start with a quick recap of our drilling activity before getting into some of the specifics of our latest results and more color on our upcoming 2017 plans. During the fourth quarter, Cimarex invested $246 million on exploration and development, bringing the total to $735 million for the year.

About 59% of our 2016 capital was invested in the Permian region, with the rest going to our activities in the Mid-Continent region. Companywide, we brought 55 gross, 25 net wells on production during the fourth quarter, bringing the total to 153 gross, 61 net wells for the year.

We increased our operated rig count from five in the third quarter to 11 currently running. These rigs are busy working to hold acreage in both the Wolfcamp and Meramec as well as drilling multi-well pads to further test spacing the completions in both regions.

Three of the 11 are currently drilling an increased density spacing, down spacing pilot in the Woodford. I'll go into more detail on that later. Permian region is first up regarding drilling results, where we have initial results to share with you on our spacing pilot in the Upper Wolfcamp in Culberson County.

This pilot located on the Sunny's Halo, Gato del Sol sections was drilled using 7,500-foot laterals that were completed using our most recent updated frac design. Slide 17 in our investor presentation gives a summary of the results to-date.

As can be seen on the average cumulative production versus days plot, we see very similar results for both the six and eight-well per section spacing pilots. Given this outcome, it is now our plan to test equivalent of 12 wells per section with six new wells spudding in the first quarter of 2017.

Earlier this year, we completed the Upper Wolfcamp Kingman 45 State Unit 2H which is located on the Western half of our Culberson acreage. We have now completed another Upper Wolfcamp well in this area, the 10,000-foot Lord Murphy 10 State A 2H well, which had a peak 30-day IP average of 2,207 barrels of oil equivalent per day, of which 60% was oil.

The location of this latest Upper Wolfcamp well can be seen on slide 13. We have plans to drill more Upper Wolfcamp wells in this area of Culberson during 2017.

Completion operations were recently finished with early flow back underway on an Upper Wolfcamp well located on our Eddy County White City acreage, which depending upon results, could open up even more acreage for development in this zone. Now, on to the Mid-Continent.

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

Completion of the wells began in mid-September with all of the Cimarex operated wells now completed and on production. Our partner continues to complete their wells with an expectation that all of these wells will be on production during the second quarter of 2017.

We also completed the Leon Gundy wells, our stacked/staggered Meramec-Woodford spacing pilot. These wells were brought on production in October, and we continue to monitor the flow back very carefully. We look forward to discussing results of this pilot in more detail on our next earnings call.

Now, I'd like to spend a little time talking about our plans for 2017. Yesterday, we announced an exploration and development budget of $1.1 billion to $1.2 billion, of which $850 million to $900 million is earmarked for drilling and completing wells. We have a number of exciting projects to pursue in 2017.

First, in the Permian region, where we plan to spend two-thirds of our drilling and completion capital in 2017. We entered the year with five rigs in the Permian with plans to add three more by April. The majority of this capital, around $294 million, will be spent on Wolfcamp long lateral wells in Reeves and Culberson County.

Some of this drilling will be for new pilots, such as the aforementioned Upper Wolfcamp spacing pilot in Culberson County, as well as an Upper Wolfcamp pilot in Reeves County, which is testing 16 wells per section and a four-well test on what we call the Pagoda section.

We also plan to spend capital, around $109 million, drilling Avalon and Wolfcamp wells on our acreage located in Eddy and Lea County, New Mexico. Included in this capital are a couple of increased density pilots in the Avalon that will test the equivalent of 12 and 20 wells per section.

As a reminder, we have seen no degradation in well performance with our most recent eight-well per section Avalon pilots. A vast majority of the remaining Permian budget, around $116 million, will go to drilling Bone Spring wells in Texas and New Mexico. We expect to spend about 1/3 of our drilling and completion capital in the Mid-Continent in 2017.

This includes about $120 million for drilling Meramec wells to further delineate and hold acreage. This capital, which is comprised mostly of three-rig lines, will HBP the vast majority of our Meramec acreage by the end of 2017.

Initial drilling in the Woodford will be an eight-well increased density pilot that is testing both 16 and 20 Woodford wells per section, as diagramed on slide 25 of the presentation.

We intend to use our learnings from this pilot to determine spacing as we move forward on the next big Woodford infill, which is scheduled to begin drilling in the fourth quarter. See the map on page 24 for the location of the Leota‐Jacobs project, which is tentatively planned to cover 13 sections and will be co-developed with our partner.

We currently operate six rigs in Anadarko region with plans to add four more in the fourth quarter. As is becoming more and more the case, timing is everything when it comes to the drilling, completion and ultimately the production and cash flow from these multi-well projects.

Slide 10 illustrates the timing of completions in 2017, which are pretty evenly distributed throughout the year, but the number of wells expected to be drilling or waiting on completion at year-end 2017, as shown in the bar to the far right, illustrates the momentum we expect going into 2018. 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 recap our fourth quarter production results, discuss our 2017 production outlook, and then finish up with a few comments as usual on LOE and service costs.

Our fourth quarter net equivalent production came in about as expected with our reported volume of 960 million a day, up 1.4% from our Q3 reported average of 947 million a day, and as Tom mentioned, within our guidance range of 945 million a day to 985 million a day.

As we projected in our last call, our late Q3 and Q4 completion activity ramped up total company production from our Q3 average of 947 million a day to a December posting of over 1 Bcf equivalent per day. Our fourth quarter net equivalent Permian volume came in at 511.5 million a day, that's down 1% from Q3 2016.

But our Q4 Permian oil volumes of 36,253 barrels a day were up 1% from Q3. We brought on 11 gross and eight net Permian wells in the fourth quarter. Five of the eight net wells were in Reeves County in our Upper Wolfcamp play, including the 100% Wood State five, six and seven wells.

Our fourth quarter Permian volumes were negatively impacted by approximately 5 million a day as a result of operational issues on our Wood State two, three and four pad. Fishing operations to retrieve stuck coil tubing in the number two well prevented us from bringing the pad on during the fourth quarter.

After temporarily suspending fishing operations on the number two well, we initiated production from the three wells in early Q1, with plans to get back on to the number two well and continue fishing operations after our flowing pressures have declined.

Our Q4 Mid-Continent net equivalent volume came in at 446 million a day, that's up 4% over our third quarter average of 427 million a day.

Q4 higher yield East Cana infill development activity bumped our Mid-Continent oil volume up to 9,205 barrels a day, that's an 8% increase over Q3 2016 and in aggregate it's really driven by the 44 gross and 17 net Mid-Continent wells that we brought on during the quarter.

Looking at 2017, we've extensively reworked the preliminary nine-rig production plan that we provided you in the last call. Under current model, we're adding rigs through Q2 and Q4, as John mentioned, we're incorporating tighter spacing projects in both regions, and really shifting our areas of focus.

And as a result, our revised model projects total company 2017 net equivalent production average 1.06 Bcfe to 1.11 Bcfe per day with the midpoint increase of 13% over 2016. We've directed more capital to Permian and our higher liquid project areas in the Mid-Continent with a focus on oil.

And as a result, we're projecting significant oil growth in both the Permian and the Mid-Continent areas, but forecasted total company year-over-year oil production growth in the range of 22% to 27%. Our projected capital and completion activity is skewed 2/3 to the Permian, 1/3 to the Mid-Continent.

We anticipate bringing 60 net Permian wells, and 37 net Mid-Continent wells on production during the year, that's up respectively from the 30 and 31 net wells we completed in the two areas in 2016.

We're forecasting a ramp in our rigs beginning in Q2, as John mentioned, from a current total of 11 to a total of 18 by the end of the year with 10 working in the Mid-Continent, and eight in the Permian. And as a result, we're modeling both capital and completion activity to really accelerate in the Q2 and Q3 timeframes.

With that, we're projecting a strong Q4 2017 exit rate in the neighborhood of 1.11 Bcfe per day to 1.17 Bcfe per day, that's a 16% to 22% increase over where we were in Q4 2016, and we'll have approximately 47 net wells either drilling or waiting on completion at the end of the year.

That well inventory and the nice exit rate we believe are going to give us some very nice tailwind as we head into 2018.

For Q1, our revised model projects total company net equivalent production to be in the range of 1.01 Bcfe per day to 1.05 Bcfe per day, that's up 5% to 9% from our Q4 2016 average and 4% to 8% from where we were a year ago in Q1 2016. Jumping over to operating expense, we posted another great quarter with our LOE.

Our Q4 lifting cost came in at $0.58 per Mcfe, that's down 5% from our Q3 2016 average of $0.61 per Mcfe and it beat our guidance of $0.60 per Mcfe to $0.70 per Mcfe. With that, our full year lifting cost came in at $0.66 per Mcfe, that's down 20% from the $0.83 per Mcfe that we posted in 2015, and 39% from the dollar rate we reported in 2014.

Our production group has worked extremely hard over the last two years to reduce and control our operating cost structure, get it to the levels that they're now and they're dedicated to continuing their efforts to keep the cost in check as we move forward.

After we've incorporated our current operating cost structure, the fluctuating nature of our workover expenses and our 2017 drilling focus on liquid rich projects, we're projecting our 2017 lifting cost to be in the range of $0.60 per Mcfe to $0.70 per Mcfe. And finally, a few comments on drilling and completion costs.

With the exception of a slight increase in the cost of tubulars, we continue to see drilling cost components remain relatively in check.

That said, we've begun to see upward pressure on our completion costs, primarily in the service costs to pump our frac operations, but also in the cost for wireline operations and 100 mesh sand, where we've seen just slight increases as well.

In general, the cost components for our completion operations really hit a low for us in Q3 2016 and are currently at levels that we saw in the Q1 2016, Q2 2016 time periods. As a result and depending on the program in frac design as is always the case, we've seen our go-forward completion at these increased 4% to 15% from our Q4 2016 levels.

With that, we continue to focus on efficiencies on the drilling side by reducing our days to rig release. In Cana, as an example, our days to TD in 2015 were at 30 days. We've got that number down to 24 days in 2016 and on the completion side by optimizing completion design, water sourcing and pumping operations.

As a result of our efficiency gains, our current total well cost AFEs have not changed dramatically from the estimate that we provided to you last quarter. In the Permian, we've raised the upper end of our current Bone Spring 1-mile lateral AFE with a range $4.7 million to $5.5 million.

Likewise, in the Wolfcamp, we've also raised the upper cost stand of our large completion 2-mile lateral Culberson Wolfcamp AFE with a range of $10.2 million to $11.4 million. That's down 4% from the $10.8 million to $11.6 million that we saw in Q4 2015.

In Cana, our current drilling AFEs are down 9% to 10% with lower day rates resulting from our long-term rig contract rolling off, which helped to offset the 15% completion cost increase we've seen on our larger fracs.

And with us hitting the low end of our previous cost guidance before the completion cost increases, we've opted to keep our 1-mile lateral Woodford total well cost estimate in the range of $7.1 million to $7.5 million, that's still down from late 2014 by 10%.

And similar to our Woodford AFEs as we continue to experiment with frac design, we're still quoting our current 2-mile lateral Meramec AFEs in the range of $10.5 million to $12 million, again with frac design being the largest cost variable in the total well cost.

So in closing, with a ramp in production in Q4 2016, we're off to a great start here in 2017. We've stepped up our activity, put together a diversified 2017 drilling program that's focused on oil. We're projecting a nice ramp in production to springboard us into 2018.

Our cost structure remains healthy and strong and our overall program continues to generate positive results. We're very excited about 2017. So with that, we'll turn the call over to Q&A..

Thank you. We will now begin the question-and-answer session. Our first question will come from Neal Dingmann of SunTrust. Please go ahead..

Morning, guys. Tom, for you or the guys, was wondering how – I'm looking at specifically slide 20 where you outline your Mid-Continent overview and you talk about sort of the Meramec play outline and the Woodford play outline. Two questions there.

You have a bit of acreage that we've heard a lot of chatter recently on the northwest part up in Blaine, Dewey – might be outside of that.

And just wondering what you thought about acreage a little bit further northwest, and how that compares to where you've got sort of the deem, (25:32) that Meramec play outline and the Woodford play outline?.

Well, I'll kick it off and turn it over to John. As we see that Northwest extension, it's really being opened up with empirical results. There are a couple of wells that we're watching carefully.

As with much of that section, and I'm – people talk about, everybody has a different word for it, but I'll just say that Mississippian section, that's Osage, Meramec and then even the Chester above it. It's not always obvious on wireline logs exactly what will produce at what rate, and what the optimum target zone is.

And so we're very interested in that northwest piece. We map it as having a fair amount of variability. We don't see it as perhaps having the regional extent that we would assign to the Meramec, but we're watching well results and I'll let John comment on that..

The only thing I'd add, I think Tom summarized it pretty well, is simply, we are learning a lot with every well out there from an empirical standpoint, because there's still a lot we don't understand, so it is interesting. We have noticed a couple of those wells up there that a certain company announced.

And we've looked at our maps and we kind of recalibrate our maps at that point, we say okay, that's a different expectation than maybe what we may have originally had. But that – I got to be honest, that's been kind of true for this entire Meramec play from the very beginning.

And so there will be some surprises to the positive as well as to the negative as we go along here, and we continue to monitor it very closely..

Great details. And then just one follow-up, John, for you or Tom. On slide 11, where you show the pounds of sand per lateral foot in your various plays. I think myself and others consider you all certainly the pioneers of a lot of these enhanced completions.

My question is, it looks like from July 2016 to January 2017, you didn't really step up the sand, and I'm wondering your thoughts.

Have we hit diminishing returns in some of these areas, and you're comfortable with that new, or is this just sort of something temporary on that?.

Yes, this is John. I guess I'll give you my standard reply. First is, I rarely ever track pounds per sand myself, that's something I know from the investment public that they like to see. We focus all our energy in our meetings more on the pounds and fluid we pump per cluster, which is the entry point into the rock.

That's where we spend all our talk, and that's where we concentrate. And yes, we're focusing a lot in terms of those entry points and how much sand and fluid do we need in terms of the best stimulation, especially from a development standpoint.

Now, out of that comes a pound per sand calculation and so far, yes, it's remained static, but I don't know that that's necessarily going to be true going forward.

All I know is right now we really are focusing on that individual cluster, and how well is it simulating a rock and I think that focus then has led us to gain more confidence in what we talk about today in terms of the tighter spacing pilots we're about to embark on, because I think we're understanding better what rock we are stimulating along that lateral and thus giving us confidence to go even tighter, where in the past we never thought we would be there..

Yes. I want to just follow up on that. We're really analyzing down to the minute detail the efficacy of our completions. And our understanding really rocketed ahead in 2016, and we're continuing to do some very interesting experiments that are gaining a clearer and clearer understanding.

We may find that we go to lower pounds per foot and yet we think we're more effectively stimulating the rock. This has tremendous implications to our spacing. It has tremendous implications to our cost structure.

We are learning some things that may allow us to be much more effective in how we stimulate these rocks and that will be a way we can perhaps compensate for what Joe talked about with our increased simulation cost. So, that pounds per foot is a pretty fuzzy look at what is a lot of detail..

Great granularity, guys. Thanks so much..

Our next question will come from Jason Smith from Bank of America. Please go ahead..

Hey, good morning, everyone..

Morning, Jason..

Tom, I just wanted to come back to the updated guidance. At the high end of the capital program by our numbers, I think you will be spending just a little bit of your cash at strip prices. I think in the past, you've talked about potentially spending that cash over two years.

Just want to get your updated thought process now on that cash balance, just in terms of spending it, keeping on the balance sheet or maybe even M&A..

Well, I will be very clear on that. It's an easy question to answer. That cash is there to be deployed. Now, the nature of our assets are such that in increasing our capital, it's really a fairly complex planning process. If we're going to add three rigs here or three rigs there, we really want to deploy those rigs where they count for us.

And so we're still trying to deploy where we learn some things and we're really trying to not be wasteful with our assets over the long-term. And anybody who works at Cimarex can tell you that we have really, really beat on one another to make sure that we've developed these assets with the full development in mind. We don't want to be wasteful.

And so it takes some planning. Now, when we first started, we made a decision in November that you know, we really thought we had the wherewithal, we had the returns, and we had the interest to step it up a little bit above and beyond what we discussed in our last call.

Well, this morning, Mark and I reviewed a model that we put together in late November, where we had capital, approximately what we announced yesterday, and yet it showed us burning through our cash on hand over the next 18 months to 24 months. And what's happened in the interim is our cash flow is up.

And so, when we made the decision to increase our capital, we thought we were going to be deploying a fairly significant amount of our cash on hand. And turns out, because the quality of our assets and the commodity moving up a little bit, our cash flow's really, really recovering nicely.

So, I said in my remarks, we had a wherewithal to do yet more and we'll be studying as the year goes on, but that cash on the balance sheet is kind of moving target and it's being kind of preserved by a very healthy increase in cash flow. Now, you also mentioned M&A. We're always in the hunt for good opportunities, but the hurdle is high.

It's going to have to compete with the other internal investment opportunities that we have for that cash flow. We are exploring, John's going to want to spend a little money on land this year and we really salute that, but it's a moving target..

Thanks for the color on that, Tom. My second question is maybe a little bit different direction. Crude in Culberson is higher – typically higher API it has to take some deducts and may have some transport issues.

So, just given the growth in this area from both Cimarex and your peers, especially as you focus on them, the more oily Upper Wolfcamp, do you see any issues on this front, I mean I guess how are you guys and the industry set up to cope with it?.

This is Joe. I can answer that. In Culberson, we've put together an arrangement with Plains to truck and haul our oil out of the basin. We typically have not had issues with regard to the gravities that we're producing out of the basin. We've got about, I want to think, 70-some odd percent on pipe. I got that number right here in Culberson.

Culberson is 70% on pipe. Takeaway has not been an issue with the announcement of the three larger pipes out of the basin. We also feel that won't be an issue downstream and our contracts are such that we are able to sell the high gravity and control the RVP on the crude..

Thanks, Joe. Thanks, everyone..

We've not had an issue there..

Thank you..

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

Morning, everyone..

Morning, Drew..

I was hoping you could talk as a follow-up just to Jason's question about the spending appetite.

If that cash balance weren't there, Tom, if you could speak to the appetite to outspend cash flow, the willingness to outspend cash flow, assuming the returns are there? If that's kind of a outspend the (34:55) cash flow plan going forward, assuming, let's say – assuming we didn't have the cash balance or whether there is some other considerations in mind?.

Well, we grow with our return on investment and we can do the math on borrowing money at 4% and investing it at many, many multiples of that, it makes good financial sense. So, we're willing to borrow to fund our drilling program.

That said, one of our goals continues to be preserving our balance sheet and we probably have a little more conservative view on where we want our balance sheet to be than many out there. We've been asked from time to time what our debt tolerance is and we've said that we would like to see debt at or below 1.5 times EBITDA.

Now, it's above that today, because our EBITDA fell. We didn't borrow any money over the last couple of years. But we see that returning to very nice cushion on that. But on an ongoing basis, we're very willing to continue to borrow.

We look at our overall debt metrics and want to maintain a debt level at or below our comfort zone, but that's what our balance sheet is for..

Thanks for that, Tom. And can we just touch on the new concepts, you guys mentioned new place.

Can you give any color at all as far as what are your preferences, things like over-pressured reservoirs or blanket formations or anything like that?.

Well, this is John. I guess my preference is those things that will lead to good rate returns that will compete with what we currently have, that's one of the criteria when we look at these new opportunities. That's a hard measure, when you're early on in a concept, but that is something we do look at. Outside of that, it's about rate of return.

And so, no, I could tell you we're making investments on a number of fronts on opportunities that are very oily and maybe even a little bit lower pressure, but also are there more dry gas and high pressure, it's about the return. And more importantly, it's also about that initial entry cost to get to that opportunity.

We look at that carefully as well as the timing. I mean, we have enough experience now with these new play developments that the timing becomes very critical in our decision, whether we want to embark on a new opportunity, because if you're looking at something with a really short cycle time on your leasing, it takes a lot of capital upfront.

It just and again has to fit within everything we're trying to get done. So what I can say is, our organization has responded to the challenge that literally we laid down last year that we want more opportunities, more exploration, and quite frankly, we probably have more than we can fund right now..

Yes, Drew, I am very clear with John on what I am looking for. I want opportunities that offer outstanding returns, little risk with very cheap entry cost, and that seems reasonable to me to ask for that..

Yes..

And take away from....

Yes. Yes, and would take away..

Yes..

I think we all are.

So, if you happened to have find the Holy Grail, would you be open to I guess what somebody will call cutting the tails and selling off some of your inventory you wouldn't get to for 20 years?.

Well, we would. What I tell our organization is, our assets today don't look anything like they did five years ago or six years ago. And we will continue to evolve, and I am very willing for our assets five years or six years from now look totally unlike they do today. We just want the best returns we can find.

And I really want to emphasize the point John made, this has been a theme that we really – as 2016 began to feel a little better, this is the theme we really have had throughout our organization, let's get back to generating new ideas, that's what we do best.

And the organization has responded just remarkably well, making it very difficult for us to not stretch that balance sheet to fund some things. So, but in answer to your question, we are totally willing for Cimarex to evolve over the ages..

Thanks for the color, everyone..

Our next question will come from Jeanine Wai of Citigroup. Please go ahead..

Hi, good morning, everyone..

Hi, Jeanine..

Good morning..

Getting back to Jason's question on the outlook, I'm just wondering if you can walk us through how you frame the activity this time around, give some interesting color that you'd reviewed your old plan that you – one of your old scenario plans that you provided back in November? And just for example, was your plan this time around anchored and whatever level you felt comfortable in a downside price scenario or was it more project-based and driven by what you saw you can get done in an efficient manner? I think you stressed before that.

There is a lot to do, but it's very complex..

Well, I'll take a stab at that. This is John. I think from November, when we had that initial look, we've had a lot of good outcomes throughout the regions, I would point out in Anadarko.

I think some of that initial plan that we had in place had us going to drill I believe some longer lateral dryer gas Woodford wells, which even today have a nice return. But now we have some really nice results in the more updip, both Meramec and Woodford part of our play.

And those areas tend to be oilier and they just look that much better from a rate of return standpoint that we'd rather move the capital over to there. I will tell you that those type of wells don't tend to come on at quite the same high rate as those downdip gas wells do, but they are flatter in their profile.

In the end, our decision is based more on, it's just a better rate of return, and that's why a lot of that capital moved from there to where we previously had it back in November.

The other thing I'll comment on is like within the Permian, it's fair to say that there was a lot of thought that we'd go maybe more toward development on somebody's banks and yet based on the spacing pilots, we actually feel like we need to go even tighter with these pilots.

And it is fair to say because we are going tighter and I think Joe alluded to that. That introduced as a little bit more risk on the guidance and a little bit more on the timing side, because we are doing those pilots and so that changed the overall nature of that program.

But for the betterment, we think that's the right thing to do for the long-term for this company..

Okay, great. That's really helpful. And then, my follow-up is just in terms of you mentioned timing a couple of times already.

What does the timing of the rig ramp-up to the 18 rigs depend on and what situations would that ramp be faster or slower?.

Well, we currently are 11 rigs and we plan on bringing three additional rigs into the Permian here within the next month..

They'll all be here by April. I mean, we have contracted and those three rigs will be here..

Okay. And then we have in the Anadarko we plan of bringing additional rigs in, four rigs that will come into the fall..

Yes, those four rigs really it depends on us and our partner come in to a good understanding on how we move forward with that large development project there in that East Cana, the long lateral development.

Right now we have that placeholder in place for those rigs coming in, but we still got a little bit of work to do, but that's what our current plans call for..

Yes. We could increase beyond that. But I think you asked what are the signals. We've talked for the last 18 months about that $40 oil floor, being what we were kind of looking for, and I think we're fairly confident as we look ahead. We stress test all of our investments down to a $40 and even a $30 oil case.

And we have a lot of cushion in our returns certainly at that $40 downside and depending on the project many of them look very healthy at that $30 downside and that's in our presentation, those are real and now we have results to back that up. So we're feeling fairly confident in an increase in capital program as we look ahead..

Okay. Great. Thank you for taking my call..

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

I just wanted a few. First of all, could you just kind of help me pull together these variables that are going on in the Cana infill program? Your partner talked about type curve outperformance and some 5,000-foot laterals which they had completed in an adjacent project. Slide 26 illustrated larger completions in infilling.

I'm wondering is one variable I think more important than the other. Do you see the push for longer laterals in the Cana, kind of the go-forward method? Just any color you can give me there would be helpful..

Yes. This is John. Well, first off, I think both us and our partner very much recognize that on a go-forward basis from a development standpoint, long laterals is where we want to be in the Cana-Woodford.

They actually have four long laterals on the current development that they're fracking that, we're all paying close attention to, but we have high expectations for.

And so, I would say that the first thing that we'll really lever greater rate of returns for that development is indeed going to longer laterals, which is what our plans currently call for later in this year.

But I'll also say, we've been very pleased with this rock and as Tom stated, we got this tightest 12 wells per section and do not feel like we're seeing any degradation in the performance of those wells. And so, that's why we stepped out to do this much tighter spacing product that we're currently drilling, right now.

We'd like to get that under our belt and see what that result looks like and then use that to influence what that later long lateral development look like there in the Eastern part of Cana..

Okay. Thank you. That's helpful. And maybe a little simpler one here.

Slide 12 mentions Ward County reevaluation, I haven't heard too much discussion about Ward today, I was just wondering if you could add some color on it, what you are looking for there and will it receive any activity in 2017?.

Yes. This is John. We have just finished recently completing an Upper Wolfcamp well on Ward County. We have plans for second one there. Some of this is driven by some recent competitor wells that come on in the area. It's also being driven by our frac innovation.

I will tell you about two years ago to three years ago, we drilled a number of Ward County wells and that they were underperformers. We now go back and look at those wells and we now realize, A, we probably landed them in the wrong zone and, B, we completely did not frac them appropriately.

And so, we're taking another look at that acreage, and that's kind of where we find ourselves. Now obviously the proof will be in the results of the wells, but we're encouraged so far with what we've seen from other operators, and that's why we've gone back into that acreage..

Yes. Ward County is a wonderful fairway. The challenge is that a lot of our acreage is sitting where the Third Bone Spring has already been developed with horizontal wells and that Third Bone Spring is really right at that Wolfcamp Bone Spring boundary.

So you're coming in right below an existing fracture network and that's what John talked about completion innovations. It's threading the needle and the challenge has been, can you come in underneath those older depleted fractures and make a new modern completion. So, we're very optimistic.

We have some things we're trying that are direct consequences of some of our learnings over the last year or two years, and as John said, we're flowing our first well back now..

Okay. And if I could just ask a follow-up real quick, just on what you just said. I just want to make sure I understood the problem.

Is it more that there may be some concern that there is some reservoir exhaustion because of all the Third Bone Spring development or is this more like, say, in the DJ Basin where there's just a million wellbores all over the place and you've got to kind of sneak around them to not get into trouble or is it a little of both?.

I would argue it's actually neither of the two. We don't have a resource in place issue in terms of how we see it. It's more of the – what we start to observe is the existing fracture network that the Third Bone Spring wells created.

And how we can ensure that when we come in with a new borehole in the Upper Wolfcamp that a lot of our frac energy doesn't go right back into that fracture network, essentially that that well fundamentally changed the stress properties of the rock.

And so what we look at is how we can tailor our design to kind of stay away from that and maximize what still looks to be a very good resource there in the Wolfcamp. That's kind of what we're trying to as Tom said thread the needle with..

Okay. Well, thank you. I appreciate that clarification. Thank you..

Our next question will come from Pearce Hammond of Simmons. Please go ahead..

Hi. Good morning and thanks for taking my questions. There was helpful commentary in the prepared remarks about current well cost, so thank you for that.

I just want to clarify, I think you had mentioned a 4% to 15% increase from Q4 and was that just on completion cost?.

Yes. This is Joe. That was just for the completion side of the equation. So that would be your water sourcing, fracking, stimulation and initial flow back. And there is a tremendous degree of variability there, because the size of the job, John mentioned some of the experiments we are doing.

And your total well cost is obviously, then – completion cost is a function of service cost, your sand cost, your chemical cost, your sourcing cost. So how all those play together, it's hard to come up and just say, hey, here is our increase. What I can tell you is that the service side has been the biggest increase that we've seen.

If you look at our service cost per stage as compared to Q3 2016, it might be upwards of 20-plus percent per stage, but we've managed to control other costs through efficiencies of sourcing and what have you.

And so it's really just – the range I gave you is kind of where our current AFEs on the completion side are now, taking into account current frac designs and the current cost today..

Great.

And then, John, as far as the capital budget for this year is concerned, how much service cost increase is baked into that?.

Yes, Pearce, this is Mark Burford. We have a small amount built into the upper end of our range.

If you look at our range of $850 million to $950 million on drilling and completion cost, if you looked at our completion cost component for the second half – or last three quarters of the year, and looked at some minor amount of inflation has to be built into the upper end of the range for that capital guidance..

Okay. Great. Thank you. Yeah, go ahead..

This is Joe. I might add some too. The previous guidance that we issued in Q3 or the Q3 call, really didn't take into account any of this. And so to some degree, yes, I think it was $600 million that we quoted, that did not account for any completion cost escalations going into 2017..

Prefect. Thanks, guys..

Our next question will come from David Tameron of Wells Fargo. Please go ahead..

Good morning. Couple of questions. Just big picture, as I start thinking about potential increase in service costs, or I guess the increase in service costs. And overlaying that, as far as the higher intensity wells relating to frac jobs et cetera.

Is there – when you start talking about your costs – or starting to equate where you were in the first part of the year in 2016, how do we think about productivity gains versus – is there any template or any framework you can give me as far as, if service costs go up 30%, then we start having to back off some of the sand because the frac job doesn't make sense anymore.

Is there any color along those lines as far as that toggle going forward?.

Well, I can take a stab at that. We've had pretty good luxury of being able to innovate with costs on a per unit basis being exceedingly low. One of the numbers we track is what it costs us to pump a pound of sand in a stimulation cost.

So take all the cost, water, pressure pumping, sand, chemicals, throw them all together and just what does it cost us to place a pound of sand in the reservoir..

Okay..

In 2014, we were at $0.34 per pound of sand. Now, during 2016, we hit a low of $0.106 per pound of sand. So our cost per unit of sand went down two-thirds, and that gave us the tremendous latitude to experiment with tighter and tighter stages, tighter clusters, much more sand, much more fluid, because our cost per unit went down.

Now, you asked, how do we view it? I'll tell you exactly how we view it. We view it through a rate of return lens. We look at what's the incremental stimulation dollar and what's the incremental production in cash flow that the well will produce, and is that a good incremental return on that incremental dollar.

And that's exactly the lens that will carry us forward in an era of service cost inflation. We will look at probably dialing back a little bit. If service costs inflate above and beyond what we're currently discussing, we will be pressured the other way.

We will be pressured to find cheaper and cheaper ways to stimulate our wells, and that's what John and Joe and their groups are doing with the innovations that we're currently working with.

We have a toolkit in place that if costs go up, I expect we are going to be able to dial back, keep a pace and not suffer from a well performance or a return standpoint.

But the proof will be in the pudding, but our lens will be rate of return and we get asked about this all the time, we're certainly going into it with our eyes wide open and a modest degree of concern – but a modest degree of concern. We will deal with it from a rate of return lens when the time comes..

Okay. That's helpful. So if I think about, let me just ask a follow-up on the rate of return.

What I think about how you, I guess you were to rank your assets, if you will, on rate of return, if Wolfcamp Culberson was number one before, or just today versus six months ago, any change as far as how you rank your assets on a rate of return basis?.

This is John. No, not really, I mean still to this day, these Upper Wolfcamp, Culberson wells are just tremendous wells in terms of the makeup of the hydrocarbon, the amount of oil, and then more importantly the profile.

We have shown often how, on a cum timeslot for the first six months these wells would just stay flat, and that just leads to incredible returns but I'll tell you we're awfully excited about a number of our plays like we're going to go back to drilling in the Avalon.

We had some tremendous results last year that we talked about in the Avalon and we don't think we've even scratched the surface in terms of frac innovation in the Avalon. That rock has a tremendous amount of resource in place and I think we're just now recognizing that.

And then even up, I would just say there are parts of the Meramec that look very good, very, very good from a long lateral, especially long lateral perspective.

And then finally, there are parts now of the Woodford and the more liquid rich part where some of the long laterals we'll bring it on testing in are more liquid rich areas that we'd really like to return to, seeing out of that. So, I think our rate of return profile looks very, very attractive for us.

But we're always constantly challenged especially with service cost to always try to find ways to make it even better and that's kind of our metric, that's what we do every day here.

How can we make it better both from a cost standpoint, but also from a well performance standpoint?.

And this is Joe. I might add that those experiments, if you will, lot easier to take on in a falling cost environment as compared to stable or escalating cost environment, but nonetheless in either case you want to look at the overall economics of design A or B or program A or B, yes..

Thanks. Thanks for all the color..

Our next question will come from Joe Allman of FBR. Please go ahead..

Thank you. Hi, everybody..

Hi, Joe..

Hi, Joe..

So, I think you answered this somewhat, but I just want to see if there are any other factors. So, in your new guidance, your D&C CapEx is up about 50% and your production is up only about 1%. So, I know you under-spent in the fourth quarter by about $50 million.

Could you just go over the factors that caused that fairly big increase in CapEx but relatively small increase in production?.

Well, I'll take a stab and then Joe can give little more detail. Certainly the timing of when that capital is spent and the nature of the projects are the biggest coupler between when the production comes. And, Joe, I'll say we had a little angst over this. We looked at it and said will the Street misunderstand this.

And I'll tell you that at the end of the day we looked at this and said we could deploy that capital in other areas that gave us quicker production hits and we said no way. These are outstanding returns, the production will come when the production will come.

And as you know, we manage and view Cimarex on a longtime horizon to generate full cycle returns for our shareholders. And so, the fact that the production in many cases is pushed at the tail-end of the year into 2018, as John said, in some cases these are projects that have very flat production profiles, but don't have quick hits on production.

We made a decision around the return on the invested capital. And that's the only consideration. And so when we look at the timing of the projects when the production hits and also the nature of the projects, some of these are development, it is what it is.

Now, from what we telegraphed in November to today we have also redirected a lot of our capital to the Permian because of the outstanding results we're seeing there, we want to take advantage of that. But those are our main considerations.

Joe, you want to touch on that?.

I think Tom hit them all on the head. I mentioned earlier, Joe, that the $600 million number we quoted before didn't include any cost escalation. So there is some component of that.

We add the rigs into this year's program and they show up Q2 and near the end of the year get a good chunk of our drilling done by the end of the year and all of a sudden what we find is that our capital deployment is middle to the end of the year. Our production coming on is middle to the end of the year.

The complexion of the portfolio mix to oil is going to have a little bit different Mcfe per day, add for a given oil well versus if there was a Cana gas well. And when you put it into blender and turn it on, and you get what you get, that's where our number came out, and Tom hit it on the head.

It's all about rate of return and that's what we're worried about. And when you look at the plan, springboard into 2018 looks nice. We got a great exit rate, and a heck of a bump in our oil, and so we're pretty excited about the forecast and not too worried about how it looked compared to last quarter..

Joe, I'll just finish with that because I know it's on everybody's mind and I appreciate the question. We also as you know had some delays in our production in 2016, and we – we like to hit our guidance, who wouldn't? We like to issue guidance that's real that we believe and that we're going to achieve.

We like it to be stretch goals that pressure us to do our best in getting there. But when we looked at some of the things that bid us in 2016, we risked 2017 fairly aggressively. Now, it is what we think it is, but it's risked in a way that's probably a little more than we've done in the last couple of years..

Yes. This is Joe. The Wood State is a great example of that. Those delays in getting a three-well pad on production impacted Q4 production by 5 million a day. And so the timing risk, we can't control, we don't predict when we're going to have operational issues or any kind of delays in the plan of development..

So, in a world where everything goes right, there are no hiccups at all, we're probably too conservative, and we wait every day for that world..

That's very helpful. Just other few quick ones. Your DUC count at year-end 2017 appears to be about 29 based on one of your slides.

What was that DUC count at year-end 2016?.

Yes, Joe, we'll have to follow up with you offline on that. I don't have that handy on the year-end picture.

Is it in the press release?.

Yes..

We heard 2015?.

Did you say 2015, Joe..

2015..

He said 2015, yeah, year-end 2015..

Sorry..

Okay. That's helpful. And then, John, you mentioned, you focus on pounds per cluster..

Yes..

And so assuming the trend there has been an increase in the sand per cluster.

But I just want to check that, has the cluster, the number of clusters moved up more than the amount of sand or vice versa?.

Well, each play I would tell you, Joe, is a little bit different.

But I think it's fair to say that we are deploying far more clusters in a typical borehole than we ever did say a year ago, year-and-a-half ago, and that has been a big change for us where there is a feeling that you couldn't get those clusters too close, but we've kind of broken through that wall and based on our monitoring what we see, we focus a lot both on that sands per cluster, but more importantly, how tight can I put that cluster, because again that's the entry point to that rock, and I would argue – I say often the more entry points, effective entry points I have for that rock, the better chance I have of having a well stimulated rock, so yes.

Part of that pounds per foot is really driven by the total number of clusters going up in the sands per lateral..

Yes, Joe, there is some irony there, because some of our first generation stimulations that may have had 800 foot to a 1,000 foot – a 1,000 pounds per foot, we think we're very ineffectively stimulated.

So I think our direct answer to your question would be, we think we are pumping less pounds per cluster today than we were three years ago or four years ago, but we think we're getting better distribution along the borehole and more effectively stimulating the lateral.

And that's the challenge, and there are about eight different knobs that lead to that conclusion. And as we said early in the call that pounds per foot number is probably the least effective measure of those knobs..

And we have time for one more question. Our next question will come from Phillip Jungwirth of BMO. Please go ahead..

Thanks, good morning.

Your year-end 2017 rig count of 18 rigs, if you were to hold that activity level flat into 2018, would you anticipate outspending cash flow at current strip or given the high quality nature of the asset base strong returns, is there a chance that you could still be within cash flow?.

Yes. Hi, Phil, this is Mark. If you look out in the 2018 the current at that level of capital spend that would be increasing from 2017 to 2018, but since we right taking these rigs in through the year, our increasing capital would be another 30% to 40% over what we are experiencing in for 2017.

At that level of capital we probably would be at the strip of around $55 oil royalty or gas price to using up a bit of that cash into the 2018..

Okay. Great. And then....

So we couldn't maintain that pace with cash on hand, but we haven't made that decision yet..

Okay. Great. And then of 2017 Culberson Wolfcamp program how much is going to be focused on the Upper versus the Lower clearly returns in the Upper are superior.

And then over the next couple years, how would you anticipate this mix changing?.

Well this is John. I don't have that exact number of breakdown.

What I'll tell you is, yeah, so far right now the upper areas are looking very strong from the standpoint of return, but I also tell you, we love – like we've seen in the past lower with the Flying Ebony well, we now have the Tim Tams coming on which is taking that, that frac design and we have high expectations for that.

We are however in a very fortunate position based on all the drilling we've done to date that yeah, we are going to have that optionality kind of going forward. Most of our acreage now is held that it doesn't force us to have to – as you know in the past, we've always wanted to drill lower first to ensure we hold all rights.

So yeah, you could argue going forward, there probably will be a greater mixture for upper and lower, but I don't have that right off the top of my head right now..

Great. Thanks guys..

Ladies and gentlemen, this will conclude our question-and-answer session. I would like to turn the conference back over to Mr. Jorden for any closing remarks..

Well, I want to thank everybody for your good questions. This has been a great discussion this morning, and we look forward to delivering strong results throughout 2017, and beyond. Thank you all very, very much..

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