Karen Acierno - Director of Investor Relations Thomas E. Jorden - Chairman, President & Chief Executive Officer John Lambuth - Vice President-Exploration Joseph R. Albi - Chief Operating Officer, Director & EVP G. Mark Burford - Incoming Chief Financial Officer Paul Korus - Outgoing Chief Financial Officer & Senior Vice President.

Drew E. Venker - Morgan Stanley & Co. LLC Brian David Gamble - Simmons & Company International Phillip J. Jungwirth - BMO Capital Markets (United States) Irene Oiyin Haas - Wunderlich Securities, Inc. Jason Smith - Merrill Lynch, Pierce, Fenner & Smith, Inc. John Nelson - Goldman Sachs & Co.

Ipsit Mohanty - GMP Securities LLC Jeanine Wai - Citigroup Global Markets, Inc. (Broker).

Welcome to the Cimarex Energy Second Quarter Earnings Conference Call. All participants will be in listen-only mode. Please note, this call is being recorded. I would now like to turn the conference over to Karen Acierno. Please go ahead..

Thanks, Amy. Good morning, everyone. Welcome to the Cimarex second quarter 2015 conference call. Last night, an updated presentation was posted to our website. We will be referring to this presentation during the call today. As a reminder, our discussions 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.

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, VP of Exploration; and then, Joe Albi, our COO, will update you on operations, including production and well costs.

Paul Korus and Mark Burford are also here in the room to help answer any questions you might have. With that, I will turn it over to Tom..

Thank you, Karen, and thanks to everyone who's participating in today's conference. We appreciate your interest in Cimarex. I'd like to take a few minutes to share my thoughts on the current environment before turning it over to John and Joe for the details of our first quarter results and our plans for the rest of 2015.

During this call, you'll hear about new wells that are outperforming our expectations, leading to another production beat. We now have 18 long laterals with over 30 days of production in the Delaware Basin Wolfcamp, several of which have been online for more than six months.

We're gaining a much better understanding of the production characteristics and potential of these longer horizontal wells. The data we've gathered has strengthened our enthusiasm for the long-term potential of this play for Cimarex.

We've always been a company that emphasizes science and innovation, and this emphasis is yielding results in spacing pilots, well design, completion design, and unraveling geologic complexity. The second quarter was punctuated by advances in each of these areas.

Of particular interest, subtle changes in our horizontal landing zone have had enormous impact on well optimization. We're now at a point where we're ready to move ahead in our first development project in the Wolfcamp D in Culberson County with drilling scheduled to begin in January on a six-section project. More about that in a moment.

Also in the Delaware basin, Second Bone Spring results continued to impress. These wells are among the best in our portfolio with multiyear running room. We will also update you in our continued success in the Woodford Shale and the Meramec play. The Cana-Woodford shale and Meramec continue to be a laboratory for continuing improvements in innovation.

We have further delineated our acreage, optimized our simulations, and are testing new landing zones. We remain quite bullish on the long-term multi-pay potential of our Cana and Delaware basin assets. To that end, we see the opportunity for a modest acceleration as we move into 2016.

We have $730 million of additional capital following our issuance of equity in May. As a result, our 2015 capital expenditures have an increase by $100 million which will fund the beginnings of several exciting projects including a Wolfcamp A, downspacing pilot in Culberson County and more Bone Spring and Meramec activity.

But perhaps most exciting is what we have on tap for 2016. In addition to Cimarex beginning its first Wolfcamp D development in Culberson County, the first development in Reeves County will begin as well. We're also planning additional infill in the Woodford and Meramec, including the possibility of a long lateral development later in the year.

We'll conduct down spacing pilots in the Meramec as well as stack testing of the Woodford and Meramec for future development. These development projects in the Delaware and Anadarko Basins are complex and require considerable planning. The multi-zone stack potential of our asset provides tremendous opportunity and challenges.

We have the opportunity to significantly increase capital efficiency by exploiting multiple zones within a single development project. We have challenges in that this requires careful planning and understanding of the geologic complexity, for you cannot always back up and capture a zone that was missed in the initial development.

Our organization is hard at work preparing for effective execution of these projects. John will provide additional color on these efforts. We intend to live within our current capital structure, and with the recently added equity funding to not incur additional debt during 2015 or 2016.

We do debt as a long-term commitment, and we're hesitant to make long-term commitments in this volatile environment. We have seen service costs further decrease.

Looking at current well cost in two of our most often drilled well designs, a Cana-Woodford infill well and a Wolfcamp D long lateral, we've seen total well cost decline 30% and 20%, respectively, from their peak in 2014. We've also made significant progress on lowering lease operating expenses driven primarily by reducing saltwater disposal cost.

Joe will give additional detail on this during the call. Since our last call, the recovery we saw in oil prices was short-lived, and natural gas prices remain depressed. Despite this negative backdrop, Cimarex is moving forward, investing in our exceptional assets.

The conversation since last fall has been dominated by discussions regarding the commodity price cycle and expectations of a recovery. I said at the time that Cimarex was adapting to this new environment and figuring out ways to survive and thrive in it. Our challenge is to adapt our business to be sustainable in this new normal.

There is good news to report. With the reduced cost environment and advancements in well performance, we have a deep portfolio of opportunities that offered very attractive returns.

Regarding our plans for modest acceleration, we've been asked, why now? Isn't it more prudent to wait for the macro environment to settle out and recover? To that I'd say, we have no special insight on the future direction and timing of commodity prices.

We view the world through a lens of greater return, and through this lens, we see the opportunity to modestly accelerate projects that offer outstanding returns, provide a cushion against further commodity downside and strengthen the foundation of the company as we look ahead into 2016, 2017 and beyond.

We have the wherewithal to fund these projects and are ready to go. Although we would enthusiastically welcome a recovery in commodity prices, we've always managed Cimarex with commodity cycles in mind. We'll survive and thrive through this one. Finally, as always, our focus is on creating shareholder value. We are uncompromising in this focus.

We have the organization and the assets to continue to deliver shareholder value through the cycles. As I tell our employees, we are building an ark, not a party boat. With that, I'll turn the call over to John Lambuth who will provide additional detail..

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 planned activity increases. Cimarex invested $190 million during the second quarter drilling and completing wells.

66% was invested in the Permian region, and the rest went toward activities in the Mid-Con region. Company-wide, we brought 45 gross, 33 net wells on production during the quarter.

Our Permian operations are in the Delaware Basin, where we brought on 16 of those 23 net wells during the second quarter, meaning we have now worked our way through the backlog of completions we had built up at year-end. That backlog was caused by some severe weather in the second half of 2014 and in addition to a lot more activity overall.

We had 18 rigs running in the Permian region at 2014. We then dipped to a low of two in the second quarter, and are now operating three rigs with plans to add more. I'll share some of those details a little later. But first, we continue to have exceptional results drilling second Bone Spring wells in the Culberson White City area.

We've drilled several wells using a larger, 15-stage completion with very favorable results, of which you can see in the presentation on slide 17. Cimarex recently completed a 7,000-foot lateral in the second Bone Spring sand section called the Klein 33 Federal Number 5H.

This well had an average 30-day peak IP of 2,753 barrels of oil equivalent per day, which included 1,870 barrels of oil per day. This outstanding well result gives us greater confidence that a combination of our upsized completions along with the extended laterals in the second Bone Spring can generate superior rate of returns.

Our long lateral program in the Wolfcamp D in Culberson continues to provide solid results. We have 30-day peak IPs averaging 2,255 barrels of oil equivalent per day from 11 long lateral Wolfcamp D wells. We continue to work on optimizing our frac design to both maximize IP rates while paying close attention to cost.

As Tom mentioned in his remarks, optimal landing of the horizontal leg can be the key difference between a good well and a great one. This is clearly illustrated by one of our most recent long lateral well results in the Wolfcamp A interval in Reeves County.

The Big Timber 57-25 Unit 1H had an average 30-day peak production rate of 3,309 barrels of oil equivalent per day, of which 50% was oil. This well was drilled and completed in the Upper Wolfcamp A zone, the first Cimarex long lateral in Reeves County to be landed in this zone.

We now have plans to drill a number of additional long laterals in this Upper A in order to determine repeatability of this very economic zone. In Culberson County, we have results from our second downspacing pilot in the Wolfcamp D.

As you can see on slide 15, these 5,000-foot laterals have strong 30-day initial peak production rates that average 1,340 barrels of oil equivalent per day. This pilot was drilled on 107-acre spacing, the equivalent of six wells per section.

It's fair to say we've learned a lot from these two spacing pilots, and, when coupled with the data from the stack CD test completed in the first half of 2014, we are now ready to move forward on our first development in the Wolfcamp D.

As illustrated on slide 16, this will be a six-section development that would be drilled with 7,500 foot laterals, essentially four 1.5-mile sections of development each. Drilling will begin in January on the southern sections.

First production isn't expected until early third quarter, as completions will coincide with the start-up of the recently announced MarkWest processing plant in Culberson. We plan to drill 14 7,500-foot development wells in the Assault and Sea Hero 1.5 mile sections, bringing the total well count to 16 when you include the two existing current wells.

These infill wells will be staggered in the thick D interval. The two northern sections, which we call Sunday Silence and Silver Charm, will begin drilling in the third quarter 2016 with completion set for early 2017.

As you can see in the wine rack illustration on slide 16, the Silver Charm 1.5 mile section will include an additional row of wells in the Wolfcamp C, whereas the Sunday Silence 1.5 mile section will test an increased density of 10 wells per section in the D.

As far as Wolfcamp capital plans for the rest of 2015 is concerned, we plan to start a six-well Wolfcamp D spacing pilot in Culberson County later this year with the rest of the capital allocated toward meeting our leasehold obligation in Reeves County. Now on to the Mid-Continent.

You will recall that we began drilling on the Cana-Woodford Row 4 infill development program late last year. Completions on this 57 gross wells covering seven sections has finally begun. In preparation of these completions, we recently completed eight wells in the Haley Section with a variety of frac designs.

Total sand pumped ranged from 9 million pounds to 12 million pounds or, put another way, 1,800 pounds per foot to 2,400 pounds per foot and we varied the stage count from 24 to 30 per well.

As seen on slide 21 of our presentation, the Haley wells achieved a 30-day average peak rate of 10.3 million cubic feet equivalent per day with a 90-day average of 8.8 million cubic feet equivalent per day, very good results.

Based on learnings from these wells, we plan to make use of primarily a 30-stage frac design on our Row 4 wells and will pump between 13 million to 16 million pounds of sand or again the equivalent of 2,600 pounds per foot to 3,200 pounds per foot. In our emerging Meramec play, we now have enough production data on ten 5,000-foot laterals.

These wells have an average 30-day peak IP rate of 9.3 million cubic feet equivalent per day with oil yields that vary from 15 barrels per million to 330 barrels per million. Our first 10,000-foot lateral in the Meramec is in early flowback while our second one is drilled and awaiting completion.

We plan to provide you with an update on these wells during next quarter's call. In the meantime, we will be participating in our first downspacing pilot in the Meramec as well as drilling our first two-well stacked test in the Meramec, which we've actually commenced operations on now.

Additionally, we now have plans to drill a stacked stagger pilot within the combined Woodford and Meramec intervals. All of these are critical data points as we think about development of this potentially vast resource. In closing, I'd like to summarize our capital plans for 2015 and 2016 as we see it today.

There are two slides in the presentation that illustrate this. First, on slide seven, you'll see our capital allocation for 2015. As Tom mentioned, we've added $100 million to our capital investment plan this year. This is really the kickoff to the increase in activity we have planned for 2016. Slide eight shows how we see allocating capital in 2016.

While we're haven't given you a dollar amount, we've based this allocation on what we project our cash flow will be based on the current strip, and then adding in the remaining equity proceeds of $630 million. The Wolfcamp and Woodford make up 90% of our 2016 drilling and completion dollars.

While that may come as no surprise, the complexion of the Wolfcamp capital has changed, with about half of the investment in 2016 being earmarked for development drilling. With that, I'll turn the call over to Joe..

our second quarter production; our Q3 and full-year production outlook; and then I'll follow up with a few comments on LOE and service costs. Q2 was another great quarter for us.

With little impact from weather or pipeline downtime, we proudly surpassed the 1 Bcf a day mark for the first time as a company, with our total company second quarter net equivalent volumes coming in at a record 1.026 Bcf a day.

That's up 22% from the 839 million a day we produced a year ago and it handily beat our second quarter guidance of 965 million to 985 million a day. Our guidance beat comes as a result of two areas. One, the strong new well performance that we should see in our completions. In fact, they way outperformed our projections, in particular in the Permian.

And then, strong execution from our production group operating our base properties with their focus on minimizing downtime and optimizing production from the wells.

And as a result, our Q2 2015 Permian equivalent production hit an all-time high of 595 million a day, up 202 million a day, or 51% from Q2 2014, while our Mid-Continent production came in about as we expected at 419 million a day, virtually flat to Q2 2014 which we reported 425 million a day.

And we anticipated the production of Mid-Continent to hold flat as we waited for our Cana-Woodford Row 4 completions to begin here in late Q3.

As we've mentioned in our last few calls, with the geographic focus of our drilling program and the timing of our new well completions as we move throughout the year, we forecasted our early 2015 production growth to come from the Permian and we saw just that. Our second quarter Permian equivalent volume came in at a record 595 million a day.

That's up 107 million a day or 22% from the first quarter, all the while setting new region record marks for oil, gas and NGLs.

With our Q2 Permian oil production of 48,448 barrels a day, up 12% over Q1; our Permian gas production of 189 million a day, up 26% from Q1; and our Permian NGL production of 19,169 barrels a day, up 46% of our first quarter volumes.

With a significant production growth, Permian now makes up 58% of our total company equivalent production, and more impressively, 86% of our total company oil production.

As we also discussed in our last two calls, with fewer net Mid-Continent completions planned for the first half of the year, we've projected our Mid-Continent volumes to drop somewhat through mid-Q3. Our Q2 Mid-Continent production came in accordingly at 419 million a day, that's down slightly from the 444 million a day we posted in Q1.

We're still on track with our plan, projecting our Mid-Continent production to pick up here in late Q3 as we bring on our Cana infill project. We completed just nine net Mid-Continent wells in the first half of 2015 as compared to our projected 30 net wells to be completed during the second half of the year.

As we look forward, with our strong Q1 and Q2 results, our current model projects our 2015 total company net equivalent production to be in the range of 960 to 980 million a day. That's reflecting 11% to 13% growth over 2014, and it's up from our previous guidance for the year of 920 to 950 million a day.

As was the case of our beginning year forecast, our projections reflect the geographic focus of our activity, with the Permian driving production during the first half of the year and our Cana infill project providing the catalyst for production during the last half of the year.

Our Q3 guidance of 920 to 940 million a day reflects our anticipated slowdown in Permian completions, along with approximately 20 million a day of planned Permian pipeline and facility maintenance here in early Q3, and just modestly, Q3 contribution from our Cana infill completion operations, which will begin late in the quarter.

With our current drilling schedule and the anticipated Q4 production contribution of our Cana Row-4 project, we project our Q4 2015 production rate to be up from Q3, with us exiting the year slightly above Q4 2014 – our Q4 2014 average of 949.5 million a day. Jumping over to OpEx, Tom mentioned a little bit about this.

We had a great quarter from an operating expense standpoint here in Q2 and that was really driven by both strong production results and our production group's diligent focus on LOE. Our Q2 lifting cost came in at a very strong at $0.76 per MMcfe and that was well below our guidance of $1 to $1.10.

It was down $0.20 from our Q1 2015 average of $0.96 per MMcfe and down $0.32 per MMcfe from our 2014 average of $1.08. We're extremely proud of the effort of our production group has put forth to reduce operating costs.

Over the last six months, they have realized sizable reduction for items such as rentals, SWD, compression and well servicing, and our results continue to progress.

As we look forward into the last half of the year, accounting for a number of items including our Q1 and Q2 results, our forecasted production in Q3 and Q4 and the variable nature of workover expenses, we're guiding our remaining year lifting costs to be in the range of $0.90 to $1.05 per MMcfe, down from the $1 to $1.10 mark or range we quoted in our last call.

On the service cost side, with the slowdown in industry activity, we continue to see a somewhat soft market in drilling and completion costs, although we see our overall total well costs that will quote in this call, somewhat flat since our last call.

We do feel that on both the drilling and completion side, service companies understand the importance of market share, which is helping to maintain a soft competitive market and perhaps more cost relief as we continue into the latter half of the year.

On the drilling side, since our last call, we've seen a majority of our cost components stay flat, all the while, supplier costs for tubulars have come down slightly.

Day rates for idle, I'll call them top-notch rigs, 1,500-horsepower rigs, are more than negotiable today than they've been in a long while, down significantly from the rates of $26,000 to $27,500 per day quoted last year to levels today at $17,500 to $18,000 a day.

On the completion side, as we mentioned last call, beginning about February, we started seeing 10% to 40% decreases in all of the major frac cost components, whether it be sand, transportation, chemicals or service cost.

The end result was that at the total company level, our average Q1 per well frac cost were down 15% to 20% from Q4 with us pumping an average 12% more fluid and 20% more sand. In Q2, we kept our average company per well frac cost in check while pumping bigger jobs yet, 30% more fluid and 16% more sand than we did in Q1.

The bottom line is today, we are pumping much bigger jobs than we did in Q4, perhaps 45% more fluid, up to 40% more sand, and we're pumping them at a reduced cost. The end result is we've kept our total well costs flat while pumping the bigger jobs, with current – total well costs – down 13% to 20% from where they were at the end of 2014.

Our current Cana Core 1-mile lateral well, Woodford well is still in the range of $6.7 million to $7.1 million with our larger frac. That's down approximately 15% from the $7.9 million to $8.4 million range we quoted last year.

In the Meramec, as we continue to get more wells under our belt, we expect to see our current single-mile lateral wells fall closer to the lower end of our range of $7 million to $7.4 million, and that range is down about 13% from where we were in Q4 of last year.

In the Permian, our primary focus as we've mentioned this year is our long lateral development and the Culberson-Wolfcamp program. Our gain in drilling efficiencies are hitting the chart and market cost reductions have kept our 2-mile lateral cost in check, and we're running anywhere from $11 million to $11.8 million per well with our AFEs.

That's down 17% to 20% from where we were in Q4. So in closing, we had another great quarter. Our strong first-half results and operating efficiencies resulted in a nice production beat. We're proud to be over that Bcf a day mark.

Our drilling program is generating positive results, despite the lower commodity prices, and we've seen some excellent cuts in our LOE. While the organization is focused in keeping our development cost in check, all the while we're optimizing our program results. So, with that, I guess we'll turn the call over to question-and-answer..

Thank you. Our first question comes from Drew Venker at Morgan Stanley..

Good morning, everyone..

Good morning, Drew..

Tom, I was hoping you could just provide a little more color on when we would get to that 16 rig program? Is that by January 1? And then if you can provide maybe just some bookends, general thoughts on volumes for 2016, whether we – should be accelerating growth somewhat similar to 2015? Could you help us there?.

Well, partially, yes. The rig ramp we have, all that John commented on, were – we had a plan there to ramp up so that we'd be essentially at 16 rigs as we enter the year – but we're obviously working our development projects and it's a flux issue.

John, why don't you comment on that?.

Yeah. As Tom said, we're not talking, of course, single individual wells now. We're talking lots of wells that we have to plan for. I think our latest schedule will have us at 16 rigs right pretty much at the beginning of February next year. But that can slide and move forward just depends on how well we put those plans together.

But that's what it will show right now as of today. And then Mark Burford's here. I'm going to let him comment on production next year..

Yeah, Drew. Just in terms of production, with the fact that, as we mentioned, in the Permian, half our capital is going now transitioning from single wells, individual wells, and half our capital now will be going to infill development.

And if you look at Culberson County itself, specifically the Wolfcamp D in Culberson County, three-quarters of our capital will be attributed to those infill development projects. So, we had a major shift in the complexion of our capital compared to 2015 to 2016.

And as we point out on slide 16 of our presentation, those two secs – that six-section development – the first completions don't occur on that until June of 2016 and the northern sections don't complete until the first quarter of 2017.

So, we definitely have a mixture change in the complexion of our programs, so the efficiency – previous capital efficiencies probably don't hold true going into 2015 as we transition to infill development. And production is delayed in those areas and even in Reeves County where we have infill development in Reeves County.

So, our overall Permian program, half of it now is infill development. So it does have the impact, the major production are more lumpy and more backend-loaded..

This is Joe. Just a couple of comments there, too. When we have these development projects, depending on how many wells per section and how many sections, we won't begin completion operations typically until all the wells are drilled and completed. And Cana Row-4 is a great example of that.

We drilled those wells all throughout the first half of this year. We're not going to see the production until the tail half of next year.

To the extent that our development program becomes the majority of our capital expenditures, we're going to start to see this roller coaster type production profile that may not coincide with a January 1 to January 1 timeframe..

Okay.

Maybe, so maybe just to make sure I have it right, due to the timing of completion in these big pads, does it make sense to think about 2016 as potentially a little bit slower growth and then 2017 probably much stronger growth?.

Drew, that's logical. Yes. That's the way – yes. It's the way the development plans work. Yes. That would be logical, yes..

Yeah, Drew. We're a strong growth profile. It's going to be lumpy, but I think that's probably fair. Our acceleration into 2016 is going to be quite a bit back-end loaded because of the nature of these development projects..

Okay. That's all very helpful. And maybe we could just dig in on the Culberson County, Wolfcamp C and D infill program a little bit. I was somewhat surprised to see you're already going into development with – mode – with two zones and the Wolfcamp D.

Can you just provide some color on how you settled on that configuration?.

Yeah. This is John. A lot of debate, I would say, internally. I mean, what's nice is as I mentioned, we have those two spacing pilots. In addition, we have that stack pilot. We've incorporated those results. In addition, we have a lot of individual parent wells that have been landed in different zones within the D itself as well as the C.

When we take all that information, we come away with a model that would clearly suggest to us that we have plenty of room within the D itself to stagger and stack, which is what we intended to do to start with, and feel very confident with that initial design, again, based on our spacing pilot results and based on leveraging that – the 7,500-foot laterals – that we're going to achieve very nice rate of returns.

The way this schedule sets up then is we will get those online; we'll get early production from it. If it's meeting our expectation, then that just gives us even greater confidence to move forward to even more tighter, as you see in those follow-up sections.

So, I would say that the two sections we call Sunday Silence, Silver Charm are somewhat dependent on the result of Assault and Sea Hero and that's why we built that schedule that way.

But again, we really are looking at the results of those pilots and looking at our landing zone results from a number of other parent wells, and come away very convinced that this initial design is going to work very well for us in this interval..

Yeah. I just want to remind you that this Wolfcamp is a really thick zone. And every play is different and has its own attributes. But in some plays, you worry about resource in place and the overall storage capacity. That's not the concern here in the Wolfcamp.

The Wolfcamp is really a mechanical issue and what's the best way to poke straws in there, frac the wells and space them to recover it. So, we're – based on our experience – we're highly confident that this rock can support this development plan..

Just wanted to clarify again, I know in the past you had done a C and D stack test.

Have you tested two laterals stacked or staggered in the D as of yet or is this the preliminary test of that?.

Well, maybe I – let me just put it this way. I guess I would love that we go forward, that we don't even call it the C, D. We just call it lower Wolfcamp. Really, we don't – C and D is more of a geologic marker.

What you really should think about is it being a very thick, over 500-foot to 800-foot thick interval, and that going forward, we're going to start with initial stack of two wells that we feel good about. And then based on results, then potentially add a third level to it with the next set of development. That's really what we're talking about here..

Drew, we have tested stack in the Wolfcamp A in Reeves County..

Yes..

And so that the analogy is direct here and John is absolutely right. In fact, our technical team is discouraging us from even using the nomenclature C, D. It really is one large section..

Thanks for the color, guys..

Our next question is from Brian Gamble at Simmons & Company..

Hey, guys. Maybe we can jump to the other exceptional results for the quarter in either the Bone Spring or the Wolfcamp A, whichever one you want to tackle first. But I guess, specifically on the Bone Spring well, huge oil cut there.

Anything other than the stages going up that you did differently in that well?.

This is John. No. That one made use of what would be equivalent of a 15-stage for 5,000-foot lateral. The difference being is it was 7,000-foot. It's just an outstanding well and it's just – it's a replication of what we've been able to do in other areas with that particular design. I think what's exciting to me is we don't think we're optimized.

We still think that there's perhaps still room to go with that frac design. And so, we do have further wells planned in the area to go in and test the limit of that design. So, it's just – the way I look at it is, again, a nice confirmation that we can take it and go a little bit longer with the lateral and still get a very good result..

So essentially confidence in the repeatability is pretty high.

Is that what you're saying essentially?.

In this immediate area, yes, we feel very good about our acreage position and the well results there. Thus, why that was the first incremental rig we added was immediately to this type of drilling program..

Great. And then, same thing kind of on the Wolfcamp A, you mentioned trying to more landing them in the upper part of the A.

Was this the first landed in the upper or was this just the first long lateral landed in the upper part of the A?.

Yeah. This would be our first long lateral, but I will remind you that we did have our spacing pilot which was the ANACONDA which was a stacked/staggered pilot where we had upper A and lower A.

And right away, from those results, we could tell that that upper A zone was giving us superior performance to the lower A, even as you recall, we've talked about some issues with the landing the lower A. But even in the wells where we did not feel we had an issue, the upper A was clearly performing.

But I will tell you than when we plan this well, we had high expectations for it, to the point that we even worked very hard as a collective group to make sure our production facilities, everything was in line for this well, because we had high expectations and it's met those expectations. We've been very pleased with that well result.

We have a nice, large, contiguous acreage position there where this well is. And yes, we have plans now to go and see if we can't duplicate this result with a few more long laterals..

But like the C, D, it's not either/or. I mean that A is a very fixed section and I anticipate multiple landing zones in the development scenario..

And then, one last one from me, guys, the kind of extrapolation of your comment, cash flow plus $630 million and/or using the 16-rig count. That puts your capital up, by my rough math, at least 30% next year.

Is that a reasonable starting point year-over-year?.

Brian, this is Mark. I'm sorry, 30% what, increase in....

In total capital..

Total capital from year to year. As you probably know, we constructed eight-rig program – actually it's based on a $50 oil price deck and a $3 gas price deck. And even at that price level, those price decks, we'd expect to have some remaining cash in the neighborhood of $100 million in excess at the end of the year.

So, the $630 million, right now, the eight-rig program doesn't contemplate quite using all the equity proceeds. We expect to have some remaining cash at the end of the year and fund that program from cash flow. So, the absolute capital, we still would like to maintain some flexibility in that.

But the eight-rig program at $50 and $3 price deck, we wouldn't expect to quite use all the remaining proceeds..

That's helpful, Mark. Thank you..

Our next question is from Philip Jungwirth at BMO..

Hi. Good morning..

Hi, Phillip..

Good morning..

So, the Wolfcamp C, D development section you laid out in the presentation, I noticed it's focused in the northeast corner of your acreage block there in Culberson County. I know in the past you've talked about how the (38:00) you move west.

So, as development eventually does move west and south, do you think this configuration of laterals and spacing is going to be applicable across the position or is it going to vary and can you provide some preliminary thoughts around that?.

Yeah, this is John. It will vary. I mean, as you pointed out, we do recognize yield variations, and that will have to factor into both our rate of return and PV calculations as far as the development plans.

The overall thickness itself is pretty consistent at least on that entire eastern side of our block, and then we do thin a little bit as we go to the west, but not to the point that I think we would lose a row necessarily.

Again, I think it'd be more a matter of economics because, I mean, it is fair to say we do tend to lose our yield a little bit as we go to the west, but that would just be a decision we'd have to make at that time. I guess that would be how I'd answer it..

Okay. And I think you've talked also in the past about the C bench in Culberson being a bit lower return than the D or the A.

So, is there a reason that the C's included in the initial infill development as opposed to a D/A development? And then, can you still come back at a later time and target those A bench reserves?.

Yeah. I'll take a stab at that, and I know Tom's itching to answer it, too. Let me just make clear that from our well results, the Wolfcamp A in Culberson is mutually exclusive from the lower Wolfcamp C, D.

So we can come back at any time and layer in wells and, say, in these developed sections in A and not worry about any type of impingement on those wells. So, that we've clearly have established from our drilling program.

In regards to the C, D, it is fair to say that our well results do indicate that Cs tend to have a little bit lower rate of return, but we are fairly convinced that if we were to develop, we wouldn't need to do it all the same time.

And so, that's why we have the plans you see there with those upper northern sections that we'd like to move forward with that and demonstrate to ourselves what kind of returns we would generate, and that full development pipe scenario, because I don't think we're convinced that we could come back and necessarily go in with the Cs at a later date.

So that's why we're stepping into this the way we are with this plan..

Yeah. The challenge here, as John mentioned, is we've really pushed our organization to say we want to take a long-term view of how we optimally develop this asset. And so to the extent that we can't go back later and get a layer, even though it may have a lower rate of return, we don't necessarily want to orphan it and abandon it for all time.

And so, we're making those decisions on a case-by-case basis, but we're really trying to develop this asset with multi-year look so that we don't find ourselves in a position five or seven years from now looking back and saying, boy, I wish we had done this differently.

And so, that requires a lot of forethought, a lot of planning, but we want to get that while we can..

Okay, great.

And can you talk about the reason why the Culberson B/D development is going to be based on 7,500-foot laterals as opposed to two-mile laterals? Do you think medium-length laterals are optimal for development or did this just have to do with the acreage configuration?.

No. This is strictly based on the way that our JVA was set up such that these particular sections were just three sections. So, for long laterals we have to divide it up in a section-and-a-half, nothing more than that. Our plans for the rest of the acreage is 10,000-foot. This is just a matter of just geography, just the way the sections laid out..

Great. Thanks, guys..

Our next question is from Irene Haas at Wunderlich..

Yes. My question has to do with the Reeves County, Upper Wolfcamp A.

Is this a typical shale or are you really kind of looking for better porosity streaks within the Upper Wolfcamp A? And if yes, how continuous would the interval be?.

This is John. This is a – it's a shale – the Wolfcamp of course is a shale with interbedded carbonates. The way we see it, there is some definite variability to it but for the most part I would say, in immediate area from our well results, we tend to see some consistency in well results from section to section. So, we do expect some repeatability.

When we make a good well in a particular landing zone, if we are to move a section over, our expectation would be that we would still be able to achieve that type of result.

As far as the Upper A itself, you know what, I'm just going to say, we do a lot of work with our rock data, our log data – and coupling that with frac design and well results – that help us internally get more comfortable with that Upper A, B and A an attractive target. And I'll just leave it at that..

So what do you see in specific that makes these wells so much better?.

Well, to be honest, I'm not really going to answer that question. That's something we do internally. I mean, we work very hard with our technology to understand this, and so, I'll just sat be happy with our result and leave it at that..

Okay. I understand. Thank you..

The next question is from Jason Smith of Bank of America..

Hey. Good morning, everyone..

Good morning..

So, on the Avalon, can you just talk about the tests you performed there and the results you've seen so far? And I guess, I'm trying to see if there's a significant difference, particularly between the 6- and 8-well sections, that you guys have tested?.

This is John. We did update our slide. For those who have the presentation, slide 19, although we didn't have comments in our opening remarks. But we're very, very pleased with the results from our pilots that we've drilled in the Avalon. And as we've mentioned, we tested a variety of spacing to help the Avalon.

And I would just tell you that, on a go-forward basis, based on these results, we are very comfortable with eight wells per section within an individual bench. And in fact, see multiple benches as being opportunistic on quite a bit of our acreage. So we're very happy and pleased with that play.

As we've mentioned several times, our acreage position is HBP [held by production]. There's no obligation drilling we have to do there. And it's a really nice thing to have in our back pocket that if we need to, we can throw rigs at it at any time..

Well, I think, I might add there that in testing and delineating optimum spacing, there's an approach that says, you test it until you break it..

We haven't broken..

We have not broken it yet. So there is a debate that eight wells is not tight enough..

That is a fair comment, Tom, that eight is a minimum at this point..

Eight or more..

Yes..

Got it. So maybe, John, just to follow up on that, I mean, in your comments on HBP, I understand that. But your mix of CapEx, I think, for 2016 shows nothing at least at this point for the Avalon.

Are you guys doing anything in the balance of this year? And as you said, I mean, what changes your opinion there? What makes you kind of go back to work and ramp in that area relative to somewhere else?.

I will say we do have plans for another Avalon test, where we're once again going to land with a pad well and test a newer frac design that we think could even leverage better rate of returns. And outside of that, again, I think it's nice to have that flexibility of having that acreage sit there because quite frankly, not everything goes as planned.

And so, it's nice to be able to throw rigs over to it when we need to or more importantly, if we need to deploy more capital. It's sitting there waiting for us and that's kind of how we look at it right now..

Yeah, Mike. So, the way it looks from my desk is, as we manage our capital expenditures and come up with our overall capital plans, these development projects take a lot of capital. And so, not every great project is getting funded.

So, please do not infer from the fact that Avalon doesn't have a bigger slice, that it means that we're – we like it any less. So, it's just you prioritize and these development projects are our top priority right now..

Thanks, Tom, I appreciate that. And on Ward County, I feel like I get to ask this question every quarter. Given the improvements you've seen in Reeves County, what, if anything, are you thinking about implementing there? I think you guys have mentioned where you have some HBP requirements in 2016.

So, is there any capital going there or is that something that maybe you'd consider letting expire?.

Well, as of today, we've really not come up with a way to achieve sufficient rate of returns in Ward County. It's just as simple as that. We always constantly monitor; there's still wells being drilled there by competitors. We keep a close eye on what they are doing relative to frac design, landing, length of lateral.

But I – to be honest – we just haven't been able to come up with the right recipe to date that makes that an attractive rate of return for us. So, unless we see a major breakthrough somewhere, there's a good chance that we will not be able to hold that acreage next year..

I want to just add to that, and Ward County is our poster child for why we want to do forethought on the development. Ward County, a lot of our acreage was developed in that Third Bone Spring; we had drilled horizontal wells prior to the ultimate potential of that Upper Wolfcamp being understood.

Had we not done that, I think we would be developing Ward County. Had we not done that, I think we would be developing Ward County and we would be developing a Third Bone Spring in at Upper Wolfcamp. The problem with most of our Ward County position is we're drilling into a depleted fracture network in that Third Bone Spring.

So, it's not to say we're disparaging the Ward County, we're not. If we didn't have that Third Bone Spring there, we'd be having a whole different conversation..

I appreciate the color. Thanks, guys..

The next question is from John Nelson at Goldman Sachs..

Good morning, and congratulations on a great quarter..

Thank you, John..

Also, congratulations to Mark in his new role, and I guess best of luck to Paul.

For my first question, is you guys talked about transitioning into 2016 into a development program, I'm just curious if there's any guidance on how we should think about infrastructure spend, either over the back half of 2015 or as we move into 2016?.

Well, I'll let Joe comment on that specifically, but we're studying that long and hard. And there's a lot of issues around infrastructure with gathering systems, how you develop your facilities and how you handle your water sourcing and water disposal. And we're looking at the full-cycle model in trying to really optimize the return on these projects.

We're very wary of paving the future with gold bricks on infrastructure. We want to balance having the efficiency of taking advantage of the development and not overspending on upfront costs.

So it's a bit of a balancing act and we haven't decided where we're going to land there, but we're trying – I will say this – we're trying to optimize our capital efficiency and minimize our infrastructure spending wherever we can. And Joe, you can comment on that..

I think, Tom, you hit it right on the head. In many, some ways, it's a matter of where we develop in these areas. And a majority of the big dollar infrastructure items have already been put in the ground, our major trunk lines, our laterals and so forth.

And to the extent these development projects lie along those existing laterals, there's a minimal amount of infrastructure associated with it. To the extent they're further removed, it obviously becomes a little bit more pricey.

So what, John and the midstream and the production guys are doing, they're working in concert to try and develop these areas in such a means and such a way that we're optimizing our capital spending.

If you ask me for the budget we have this year, I would say, it'd probably line up pretty close to what we did this year with our infrastructure dollars, primarily because a lot of that is driven by compression..

And this year's number was $50 million to $80 million.

Is that correct?.

Yeah. In 2014, we spent about $75 million. This year, we'll probably going to spend about $50 million for midstream projects. So I would say, somewhere between last year's and this year's is probably a good run point for starting to look at 2016..

It all depends on the timing of when we need compression. Compression's a big part of it. But a lot of that existing trunk line or what have you is already in place. But as far as an overall percentage of our total Permian CapEx, I would say, it's a small part..

Okay.

And just to interpret some of those earlier comments, is that to say that you guys don't necessarily want to overbuild production handling facilities such that we might think about, especially in something like that Wolfcamp C/D development area, some of those wells maybe being facility constrained early on, but ultimately, still having a positive standpoint, kind of a flatter, flat and longer production profile? Is that kind of what you're saying?.

Well, we've looked at a number of wells. Our 7,500-foot Bone Spring lateral is an example of that where what was the cost to design for peak rate versus what was the cost to not design for peak rate. And it was a very valuable exercise to our team.

So, we're trying to understand all the efficiencies that need to come into play and that give us a maximum rate of return..

But there is an argument for that – that it used to be in five or six years ago – the well was always the driving force. We would drill a well and we would build facilities in order to produce it at its maximum allowable – the maximum rate we could do.

Today, where we have potentially 12, 16 or more wells a section, we're studying, is it better to optimize our facility size and then drill to keep those facilities full and at peak capacity. And it's a tradeoff, and we're modeling the rate of return to that very carefully, so that we get the greatest capital efficiency.

It doesn't necessarily do us any good to drill a dozen or 16 or 24 wells, build facilities for peak production, and then find six months down the road those facilities are underutilized. That would be very wasteful.

And so, we don't have the answer on this call, but that's what our organization is hard at work studying, not only studying economic models, but we're studying our competitors very carefully, how they've done it, where they've had success and where they've had failures..

And just to follow up on that facility, in this case, doesn't necessarily just mean the battery. It can mean the pipe size; it can mean the compression, a variety of factors that need to come into play..

That's very helpful and good problems to have..

It's a good problem to have..

Second one for me, I can appreciate that you guys don't want to give out a 2016 CapEx number. But just when I think about your working interest levels in those two areas you highlight that's getting nearly 90% of the CapEx, it can be kind of a wider or lower kind of band.

Is the 2016 rig number, is that purely operated? Is that a minimum? Or is there some level of sort of non-op spend that you also envision happening in 2016, or any color when we think about sort of relating what's on that slide up to an aggregate number?.

Yeah. This is John. When we quote 2016, that's 2016 operated. So, it's fair to say we definitely anticipate quite a number of non-operated partner wells in the Woodford as we always have. Typically, they've been running around six rigs here recently.

So, that certainly factors into our capital model as well in terms of what they plan to do in addition to what we will do..

Great. I'll let somebody else hop on. Congrats on the quarter..

Thank you..

Thank you..

The next question is from Ipsit Mohanty at GMP Securities..

Hey. Good morning, guys, and congrats, Mark, in person. Just a quick – I couldn't help but notice comparing slides of 1Q over 2Q that you're Permian was a tad gassier than – in 2Q than 1Q.

Could you comment why?.

Yeah. I'll take a stab at it first. I think you're just seeing, number one, if I think about the different programs, quite a bit more drilling in Culberson and the Wolfcamp, especially Wolfcamp D. And so that does tend to be a little bit more gassier than, say, Reeves County or other areas.

Secondly, even the Bone Spring for us, traditionally a lot of our Bone Spring wells were more in New Mexico in terms of Lee, Eddy. We're still in New Mexico, let me be clear about Western New Mexico, White City and Culberson. They tend to be a little bit more gassier.

But I will tell you, they're far better wells from a rate of return standpoint in terms of the type of productivity we get from those wells. So, I think that's just what's driving that slow change you're seeing and getting a little bit more gassier. It's just where the nature of our rigs have been on that western side of the Delaware Basin..

Okay. And then, I think you alluded to this in a separate question. But when you look at slides seven and eight – 2015, 2016 over 2015 – you said the Avalon would be missing because you have HBP and you have that description going into 2016.

But when I look at Meramec and Bone Spring, two of the regions that you've highlighted in your presentations and seeing improvement, you see them sort of shrinking as a percentage of capital allocation.

Is there something to read into that?.

Yeah. Development versus single well..

Yeah. I think number one, again, as we keep saying, when we go to development, whether it be Wolfcamp or Woodford, that's a major investment from a standpoint of deploying 17 wells or 20 wells. The Bone Spring itself, I think, from a capital standpoint, I don't think it's that much different from year-over-year.

You're seeing just at our capital, the pie is bigger. We still plan to have a similar type healthy drilling program. The Meramec, I would say, yes, it's going to slow down because we've reached the point where we delineated, we think we feel comfortable where we have good rate returns from an individual well standpoint.

But as I said in my comments, now we need to understand how do we develop it. And so, we have a number of major pilots ongoing between us and our partner, spacing pilots, stack/stagger pilots so we can better understand on our acreage how do we develop the Meramec concurrent with the Woodford.

And so, that's why, prudently, we'll be slowing down some of the Meramec while we get those pilot results and understand how we move forward to get that acreage properly developed..

I also want to add that this is a snapshot in time, and we want to give you color directionally as to where we see the remainder of 2015 and 2016 going. But it's by no means set in stone. And, for example, there is a chance that in this Woodford development, we may have a layer of Meramec to add to it.

And so, we may increase Meramec along with the Woodford development. But we're still working our way through that, but we wanted to give you our best read today on the direction. We maintain a lot of flexibility as we work our way through this..

All right. Appreciate it. And then, seems like as you go over quarter-over-quarter, having followed you, it seems you've gotten very comfortable with the longer laterals across your asset base.

Is going on from here, as you go forward the remainder of 2015 and 2016, what percentage of your drilling are longer laterals, just across Bone Spring, Wolfcamp and Woodford?.

I'll take a stab at that. This is John. Essentially, all the Wolfcamp is extended laterals, I mean, pretty much where we can. I think the lone exception might be the occasional pilot where we find that we can achieve the answers we need from a capital standpoint through 5,000-foot instead of 10,000-foot.

But outside of that, almost every Wolfcamp well, if the acreage allows us, is an extended lateral at least 7,500-foot to 10,000-foot. Woodford, traditionally, we have been a 5,000-foot lateral developer.

But I will tell you, because of our comfortableness with drilling 10,000-foot, a lot of our future development plans that we review now incorporate 10,000-foot as our go-to for development. Now, that's not going to happen right away.

But as Tom mentioned in his comments, we are looking at some areas, probably mid to later next year, that we will move toward long lateral development even in the Woodford. And again, I think that just speaks to something you mentioned. We're getting very comfortable with our ability to drill and complete and flow back those wells..

And we've taken a little different approach than some of our competitors. To the extent that we're delineating or we're testing spacing, we prefer to do that with 5,000-foot long horizontal wells, get the results a little quicker and spend a little less per well while we're doing experiments.

In particular, if you look at our Meramec program, Cimarex – our wells are dominated by 5,000-foot wells. Many if not most of our competitors, have chosen to go straight to 10,000-foot wells. We're fairly confident that that was the right decision for Cimarex..

Thanks. Congrats on another great quarter..

Thank you..

Thank you..

The next question is from Jeanine Wai at Citi..

Hi. Good morning, everyone..

Good morning..

In your prepared remarks, you mentioned that you built your 2016 program around rate of return given that you don't have a crystal ball on future prices. So I was wondering if you could just give us an update and rank in order of rate of return in your plays.

I know in the current presentation you gave an updated 78% rate of return for the Culberson Wolfcamp D.

So how can we slot in the other programs like the Wolfcamp A, Reeves A, Bone Spring, Cana Infill, et cetera?.

Yeah. This is John. I think before I answer that, again, there are so many moving parts that go to building that program, that clearly, yes, rate of return is one of the first things we look at. But there are obviously other mitigating factors such as takeaway concerns, obligation drilling to hold acreage.

So there's many things that go into that program. So, I just want to be clear about that, but rate of return is certainly one that we focus on strongly.

From a program perspective, right now, first and foremost, White City, Culberson, Bone Spring wells generate by far superior rate of returns, and we're very pleased with where we are with that program.

Once you step from there, the long lateral Culberson program, as you mentioned, is very healthy, looks very strong for us going forward, both in the A and in the D, which we've gotten very good results recently from the A now. So, we literally have two different intervals generating very strong results.

I would argue now with the latest results from Reeves, with the well we just spoke about, if we can continue to duplicate that type of result in that Upper A, then Reeves becomes extremely competitive relative to Culberson with that type of result.

And then finally, you get to Woodford, where Woodford, right now, are very, very good rate of return results. I think what excites us about the Woodford is what I mentioned earlier, when we start thinking about it from a long lateral standpoint.

When we look at Woodford and we look long lateral, then those returns all of a sudden get to a point we get very excited about relative to, say, a Culberson long lateral. So, that would be just my take on it, based on the current commodity price and what we see going forward..

And then, I also want to add and I think everybody knows this. When we talk about rate of returns, to the extent we quote a number, those are what's being called half-cycle returns. Those are drilling-only returns. They're not burdened by all the other things that make up a true investment profile.

But there'd be incremental decisions that we make every day..

Okay. Great. That's all for me. Thanks very much..

Thank you..

Our last question is from (01:03:42)..

Good morning, guys.

Just a few on the Meramec, just wondering – there's, I guess, a pilot, doing an 80-acre downspacing test that you guys had an interest in, if you had any kind of feedback on that result yet?.

This is John. No. We have no comments to make about that pilot as of yet. We're carefully monitoring but no comments..

Okay.

And then, John, I guess the location of those downspacing and stack tests in the Meramec, are those going to be in the up-dip or down-dip sections?.

They are in the up-dip, as far as the spacing pilot, as well as the stack test, they would be in what we have called the up-dip. Yes, that's where they're located..

All right. And then just last one for me. There's been some talk about the variability of the geology in the Meramec across the play.

Just wondering if you guys think that your acreage is going to be fairly consistent on the characteristics?.

Well, this is John. I would say again, to date, we've been very pleased with the results of our wells. But I will point out that we have 10 wells that go into our average. It is fair to say that of those three new wells, one of them was quite a bit of a step-out for us. And yes, it underperformed relative to the rest of the wells.

That's what happens when you try to delineate your acreage. And so, there's no surprise that we have reached a point where at least with that well, we would start to think that maybe that particular area is not as prospective as others – from a 5,000-foot standpoint – let me be clear.

We do recognize there's a variability to this, but I would also again point out that we've been pleased with the overall consistency of our results to date..

But the – John mentioned the three new wells – two of the three were choked back during a significant portion..

Yes. So, to be clear, of the three new wells, one of them was a significant step-out that definitely underperformed relative to our average. The other two wells, just to give you a little color, are wells that are in an area that we consider very prospective.

We upsized the fracs quite a bit on both those wells and because of that, we're trying to manage the flowback on those wells from a standpoint of both water and sand control. Those wells were conservative on their choke settings, thus, we didn't achieve the same kind of 30-day average rates that the other wells have.

But we're very pleased with those well results, those two wells, based on what we're seeing to date..

All right. I appreciate it..

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

Yeah. I want to thank everybody for joining us. And in closing, I'm glad it was mentioned in our call, I want to congratulate Mark Burford on becoming our CFO. He's ready for the job and will just do a fantastic job. But I especially want to commend Paul Korus for the contributions he's made to this organization over time.

Many of you on this call know Paul well. We're going to miss him deeply. It would be impossible for me to overstate what he's meant to this organization, to our shareholders, and to the building of Cimarex. It's with a lot of bittersweet that we let him go. We're going to miss him.

And part of the great contribution that Paul has given us is grooming and choosing his successor. But Paul's contribution is something that we're very grateful for. And I know many of you share me wishing Paul all the best and just deep, deep gratitude for the role he's played as a founder of this company. So with that, I want to thank him very much..

Thank you..

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