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 - VP-Capital Markets & Planning.

Drew E. Venker - Morgan Stanley & Co. LLC Phillip J. Jungwirth - BMO Capital Markets (United States) Brian D. Gamble - Simmons & Co. International Joe D. Allman - J.P. Morgan Securities LLC Matthew Merrel Portillo - Tudor, Pickering, Holt & Co. Securities, Inc.

Ipsit Mohanty - GMP Securities LLC Michael Anthony Hall - Heikkinen Energy Advisors Irene Oiyin Haas - Wunderlich Securities, Inc. Cameron J. Horwitz - USCA Securities LLC.

Hello, and welcome to the Cimarex Energy Fourth-Quarter and Full-Year Earnings Conference Call. All participants will be in listen-only mode. Please note, this event is being recorded. Now, I'd like to turn the conference over to Karen Acierno, Director of Investor Relations. Mr. Acierno, please go ahead..

Thank you, Pete. Good morning, everyone. Our speakers today will be our CEO, Tom Jorden, followed by John Lambuth, VP of Exploration; and Joe Albi, our COO will conclude our prepared remarks. Paul Korus and Mark Burford are also here in the room. Last night, an updated presentation was posted to our website.

We will be referring to this presentation on our 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 risks associated with our business. With that, I'll turn it over to Tom..

Thank you, Karen, and thanks to everyone who is participating in today's conference. We sincerely appreciate your interest in Cimarex. I'd like to take a few minutes to share some thoughts on the current environment before turning it over to John and Joe for details of our results and our plans for 2015. Cimarex had a great year in 2014.

During this call, you'll hear details of our accomplishments, our challenges, and our prospective as we look ahead into 2015 and 2016. We had some great well results to report. Our operations group achieved outstanding production growth in-spite of some severe weather events and unplanned downtime.

We executed on some well time strategic asset purchases and sales. We finished the year strong and entered 2015 with over $400 million cash on hand. In these difficult times, Cimarex stands out with quality assets, the strong balance sheet and an organization that is eager and ready to face today's new challenges. What a difference a quarter makes.

During October, we met with a number of our current perspective owners in the midst to the drop in oil prices from the mid $90 per barrel to the mid $70 per barrel. At that time, we said that Cimarex would view the changing situations through a lens that focused on three key questions.

Does our portfolio contained investments are look attractive at current commodity prices and service costs? Do we have the balance sheet and cash flow to fund these opportunities? And once the overall market psychology and how should that impact our capital discipline? In other words, will the industry slow dramatically and drive service costs further down? Since that time in October, the situation has deteriorated further, but the conversation still about asset quality, balance sheet held and capital discipline.

First and foremost, Cimarex has great assets. Our Delaware Basin assets are providing excellent investment returns in the current environment. Innovation and optimization continue to produce improved well results. Our Anadarko Basin assets are top tiered. The Woodford Shale is delivering solid returns.

We've continued to de-risk our Meramec position they are gaining increasing confidence to say that it provides some of the very best returns in our portfolio. We have a great acreage position in the economic sweet spot of the play. John will provide additional details on this.

Secondly, our balance sheet remained strong and we planned on keeping it that way. We do not know how deep or sustained this down cycle will be, preserving a health of the company and our financial flexibility is paramount. Finally, we're committed to being highly disciplined in this volatile environment.

We may not have seen the bottom of this correction yet. We do expect to see further service cost reductions. Our go forward approach will be characterized by a mix of long-term and short-term thinking. We're going to take a long-term approach with our assets and organization.

With few exceptions, our 6-rig program can hold our acreage in 2015 without difficulty. We'll let a little acreage go, but it will all be second-tier acreage in which we've had marginal results. Our organization is focused and fully deployed on adding value and capturing opportunity in this environment, and I'll speak more on that in a moment.

We'll take a very short-term approach to our balance sheet and capital investments. Our goal in 2015 is to live within cash flow and cash on hand. We view debt as a long-term commitment, and we are highly reluctant to incur additional debt, until we see commodity prices and service cost stabilize.

Although, we're guiding 2015 CapEx in the $900 million to $1.1 billion range. We aren't really thinking about this as an annual budget. The $900 million to $1.1 billion estimate is a snapshot in time. We remain poised and ready to increase activity on the moment's notice.

Our decision to contract the six rigs as the prudent course of action, until we see signs of stability that can have the confidence in the robustness of our investment returns. At our current pace of activity, will go production 3% to 8% year-over-year.

Furthermore, we've projected Q4 2015 exit rate, which is essentially flat or down only slightly from our Q4 2014 exit rate. We can manage this downturn without sacrificing future growth. Finally, I want to comment on the opportunities with this down-cycle will present. There will be acquisition opportunities.

We've already been presented with a number of them, but the bar is high. Any corporate or asset transaction will need to be value accretive from the Cimarex shareholder or we're not interested purely. Our balance sheet gives us great flexibility, and we're under no pressure to do anything other than play it smart.

Make sense deals are rear, but will be ready. Cimarex has a staff that is focused, dedicated and hungry to continue to innovate and optimize. We are not shipwreck victims waiting for rescue. The mandate throughout organization is to figure out how to make a living and drive in today's environment.

We're not ideally waiting for commodity prices to bounce back to the pre-correction levels. None of us can know where commodity prices will stabilize, but we are proceeding on the assumption that the days of $90-oil are long gone. In this new era, the efficient low-cost resource producer will be the one that survives and prosperous.

Cimarex is dedicated to emerge from this current environment as a better, more productive company. We're using this downtime to refocus and retool our organization, we'll be measured by what we've always been measured by results and we face this challenge without looking back.

In the end, there is no substitute for great assets, a great balance sheet and an outstanding organization. During 2014, we continued to demonstrate that Cimarex has some of the best assets and the organizational capability in the business.

With that, I'll turn the call over to John and Joe, who will describe the progress we made in delineating and developing our outstanding portfolio..

Thanks, Tom. I'd like to quickly recap our activity in the fourth quarter and for the year before getting into some of the specifics about our new drilling results. Cimarex drilled and completed 87 gross, 53 net wells during the quarter, investing $457 million.

78% was invested in the Permian region and the rest went toward activities in the Cana region including the drilling of both Meramec and Woodford wells. Our Permian operations are in Delaware Basin, where we grew up 39 net wells during the fourth quarter.

Our activities in this area were focused on drilling and completing Wolfcamp long laterals; second Bone Spring wells in our White City area; and Avalon wells. We've had exceptional results drilling second Bone Spring wells in our White City area in Eddy County, New Mexico.

I'll refer you to slide 10 of our presentation which illustrates the uplift we've seen in production using a larger completion. We've gone from nine to 15 stages in order to achieve these results. Similar to the second Bone Spring wells in Culberson County.

These wells have a higher gas components than our traditional Bone Spring wells, which increases productivity and improves overall economics. As of today, we have identified approximately 90 second Bone Spring locations on our White City acreage with the vast majority of those being located on acreage, which is currently held by production.

In our press release, we've mentioned results from six new Culberson County, Wolfcamp long laterals. Five of those were Wolfcamp D wells, which had averaged 30-day peak IPs about 2,236 barrels of oil equivalent per day.

And while we are very pleased with these results, we continue to work on optimizing our frac design to both maximize IP rates, while also paying close attention to cost. Currently, we have five long laterals flowing back with varying frac designs including some with pure equivalent stages.

These wells have been completed are in the early stages of flow back thus no conclusions can be reached yet for these wells. We've adjusted our Wolfcamp acreage position slightly since our last update, but still have a total exposure of 235,000 potential net acres.

In 2015, our Wolfcamp capital will be focused on drilling additional long lateral wells in Culberson County, as well as meeting our leasehold obligations in Reeves County, which will be fulfilled by drilling eight wells in 2015 at a cost of $70 million.

Lastly, in the Delaware Basin, I'd like to give you an update on the status of our fourth pilot drilled in 2014, which is the Stacked/Staggered Wolfcamp eight pilot in Reeves County. This pilot was designed to test both down-spacing and the viability of landing more than one lateral in the thick Wolfcamp A section.

After delays caused by the September flooding, these wells began producing in early December and have been online for about 75 days.

However, due to intermittent downstream processing issues during December, a good number of our Reeves County wells, including this pilot were hampered with sporadic production down times thus making a 30 day IP meaningless for the purpose of this call.

With the addition of a new processing outlet in the area, we anticipate having smoother production information as we get further into the quarter and thus enable us to better determine the true potential of this facing pilot. Now on to the Mid-Continent region.

We drilled 57 net wells in Mid-Continent region in 2014 with 42 of those wells being Woodford wells. We also drilled seven Meramac lineation tests, all of which are now producing. We now have enough production data on six of the seven Meramac wells to provide you with a peak 30 day average IP rate of 10.2 million cubic feet equivalent per day.

As was mentioned in the press release, these wells have a wide range of oil deal. In fact I need to issue a correction to the release and that the oil percentage range for these wells is actually 7% to 55% instead of the 20% to 55% that was stated in the release.

As illustrated on slide 18 of our presentation, you can see that wells on the up-dip side of the line have a much higher percentage of oil averaging 49% versus down-dip wells which average 16%. We are very encouraged with these wells results, especially when you take in account that all of these delineation wells were just 5,000 foot laterals.

Our 2015 plans are to continue to delineate our acreage position with 5,000 foot laterals, while we also embark on drilling a number of 10,000 foot laterals in the Meramec.

If we achieve similar uplift and going from 5,000 foot to 10,000 foot, I've seen in other plays, then these wells will generate some of the highest rate of returns within our portfolio drilling opportunities. Current plans are to invest $70 million in the Meramec drilling in 2015.

Regarding our acreage position, Cimarex has approximately 115,000 acres that are prospective for the Meramec, 70,000 acres of which have been de-risked by our and competitor drilling activity. And then finally, in November, we commenced a seven-section infill development program in the Cana-Woodford shale.

Originally planned to be 10 sections, commodity prices caused this year's development to be downsize. We will operate two of these sections. Drilling capital allocated for the Woodford infill program in 2015 is approximately $180 million for both operated and non-operated wells. With that, I'll turn the call over to Joe Albi..

Thank you, John. And thank you, all of you for joining our call today.

I'll touch on the usual items, our fourth quarter production, our first quarter and full year 2015 production outlook and guidance and then I'll follow up with a few comments on (13:55) really drove the increase there with Q4 Permian oil volume of 38,246 barrels a day, being at the 11.5% or 3,947 barrels a day over Q3.

Over last year, we've seen exceptional production growth overall in the Permian, not just in Q4. Our Q4 2014 equivalent volume was up 34% or 114 million a day from a year ago and our Q4 2014 Permian oil volume was up 29% or 85,095 barrels a day over the same time period last year.

On an annual basis, our average 2014 Permian equivalent production came in at 399 million a day, that's up 79 million a day or 25% over our 2013 average of 320 million a day. As we anticipated, with fewer net Mid-Continent completions coming online in the latter half of 2014, we saw our Mid-Continent net equivalent volume drop slightly from Q3 to Q4.

We completed 35 net wells during Q1 and Q2 of last year in the Mid-Continent, as compared to the 9 that we completed during Q3 and 14 that we completed in Q4. And as a result, our Q4 Mid-Continent equivalent production averaged 488 million a day, down slightly from the 518 million a day that we posted in Q3.

That said, we posted nice production gains overall in the Mid-Continent during 2014. Our Q4 2014 Mid-Continent exit rate of 488 million a day was up 42%, or 144 million a day from Q4 2013. And our full year 2014 Mid-Continent average of 451 million a day was up 30% or 105 million a day over our 2013 average of 346 million a day.

So overall, at the company level, it was a great year for us from a production standpoint. We set record marks in all production categories, whether it'd be oil, gas, NGLs or equivalent volumes, at the company level, as well as at both the Permian and the Mid-Continent regions, we're pretty proud of that.

With the contributions from the Permian and the Mid-Continent, our full year 2014 total company net equivalent production average of 869 million a day was up a 176 million a day or 25% over our 2013 reported average of 693 million a day.

When you throw in the 2014 property sales that we had, on a year-over-year, apples-to-apples basis our production growth was 27%.

As we look forward into 2015, our 2015 total company average equivalent volume guidance of 895 million a day to 935 million a day is modeled using the low-end of our 2015 productions or capital projection, and results in the 3% to 8% projected growth over 2014.

The carryover the current geographic focus of our drilling program into 2015, coupled with our reduction in shipping of rigs as we move further into the year, results in our 2015 production growth coming from the Permian early in the year and the Mid-Continent later in the year.

With our current 2015 rig and completion schedules, we're focusing approximately 50 net wells to be completed in the Permian during 2015, with 35 to 40 of those wells projected to come online during the first half of the year.

With that, our current modeling calls for Permian production to continue to grow in 2015 with projected Permian equivalent volumes up 13% to 19% over our 2014 levels.

In contrast, we're targeting 30 net wells to 35 net wells to be completed in the Mid-Continent during the year, but five to six of those wells coming on production in the first half of the year and 25 to 30 coming on in the second half. That coincides with our Cana-Woodford development.

With the back-end loading of completion activity, our Mid-Continent production is expected to drop somewhat through mid Q3, and then increase significantly during Q4, and really reaching a peak with the full development of row 4 in December of 2015.

The bottom line at the Mid-Continent level – is that the Mid-Continent will see relatively flat year-over-year production as compared to 2015 – 2014.

As we start-off into the year, we've issued our Q1, 2015 guidance of 920 million to 940 million a day, which incorporates a negative impact of 25 million to 30 million a day for early Permian downtime, associated with weather in January and some pipeline facility maintenance that we're doing in Culberson and Reeves County here in February.

With our current drilling schedule, our projected fourth quarter 2015 exit rate is forecasted to be as Tom mentioned flat to down slightly, compared to our fourth quarter 2014 exit rate.

But again this forecast is based on the low end of our capital spending projection, and as Tom emphasized just a minute ago, we have a lot of flexibility in that regard, as we watch the market conditions react accordingly. Any changes in our capital spending will obviously affect our current production forecast.

Jumping over to OpEx, with the continued focused on our LOE, our Q4 lifting cost came in at a $1.05 per Mcfe, puts us in our full year average of $1.08 per Mcfe, right at the bottom end of our guidance of $1.08 to $1.12 and down $0.05 from our 2013 average of $1.13.

Our production group is keeping their focus on reducing cost in all areas and we're seeing signs of modest cost relate here in Q1 for items such as saltwater disposal, rentals, chemicals, contract labor and well servicing.

The purpose of the guidance will project in our 2015 lifting cost to come in at a $1.07 to $1.17 which takes into account the front-end loading of our projected higher lifting cost Permian new production in the first half of the year.

Our service costs are concerned with the precipitous drop in industry activity, we've seen significant drops in service cost since just the beginning of the year. First, we saw on the drilling side, and more recently on the completion side. Geographically, the reduction seem to come quicker in the Mid-Continent then in the Permian.

Most likely result of the backlog of industry Permian activity during Q3 and Q4, especially on the completion side. That said, current costs are now down in both areas.

On the drilling side, we've seen anywhere from 5% to 15% reductions in day rates and 10% to 20% plus reductions in virtually all other cost components the mud, rentals, bits, directional tools just to name a few. And just recently we've seen drops on the completion side.

The significant decreases in all of the major frac cost components whether it'd be sand, transportation, chemicals or service. As a result, at the total company level, our current average per well frac costs are down about 20% from late Q4 levels, all the while we're pumping on the average 10% more fluid and 40% more sand.

The bottom line is that depending on the program, our total well costs currently are down 13% to 20% from where they were just two months ago. Our current Cana Core Woodford AFE is in the range of $6.8 million to $7.2 million, that's down approximately 14% from the $7.9 million to $8.4 million that we quoted last call.

In the Meramec, with just a half dozen wells under our belt, the current single mile lateral AFEs are running in the $7.2 million to $7.6 million neighborhood, that's down 13% more they were in late Q4. In the Permian, our focus in 2015 will be the Wolfcamp, primarily in Culberson, primarily during long laterals.

The cost reductions we've seen today uphold our projected two-mile lateral in Culberson, down 15% to 20% to levels of $11.3 million to $12.3 million.

With our Reeves County two-mile Wolfcamp laterals running slightly higher at $12.1 million to $13.1 million, primarily a result of the need to add for us to run additional string of pipe in certain portions of the Reeves County area. In closing, we had a great 2014, with strong contributions from both our Permian and Mid-Continent programs.

We set new records for the company in all production categories. Both our proved reserves and our net production were up 25% over 2013 with the strong fourth quarter and carryover of our 2014 activity were set up for production growth again here in 2015, despite falling in the range on our capital program, while we preserve our balance sheet.

And with some nice decreases already under our belt, we continue to focus on reducing LOE and total well cost, so as to be that, low cost resource producer to be able to capitalize on whatever the market throws at us here in 2015.

We want to commend the organization for the great year that they had in 2014 and for the great job they've done early on in the year retrenching us to make the best and a very successful year for us in 2015. And with that, I'll turn the call over to question-and-answer..

Yes. Thank you. We will now begin the question-and-answer session. And the first question comes from Drew Venker with Morgan Stanley..

Good morning, everyone..

Hey Drew..

Just wanted to get some color on how are you thinking about capital allocation between Cana and the Meramec, the return is obviously for both programs look great on current prices, but Meramec looks a bit higher.

Are there infrastructure needs that prevent you from flipping that to be selling more in Meramec or is it just too early to have a great sensitive production profile there?.

Yeah Drew, this is John Lambuth. I'm not aware of any infrastructure issue whether on drilling Meramec or Cana. They have fairly similar production flow stream. So, that's not a hindrance to us in terms of our decisions there. It really comes down to in the case of Cana or the Woodford shale, there we're pretty much in development mode.

And so, there it's kind of that dance we do with our partner Devon and ensuring that we're working together and we've already laid out a plan in terms of what will be developing this year and that's the amount of capital we talked about.

As far as Meramec, really it's still all about delineation for us, further expanding the opportunity set here as far as what acreage is perspective.

And then as I stated, there's also the need to get after and get a few 10,000 foot laterals under our belt, get some production history under those to get more confident as to what kind of returns those will generate. So that's kind of the balance we're striking right now for this year as we go forward..

Yeah. Jerry, this is Tom. I would add to that. A lot of that's baked in. We started this development project in the Woodford last fall. We're pleased to have and the returns are excellent.

To the extent that we have additional capital, and it's competing, Meramec is going to be top tier and probably we'll be getting additional capital if indeed we accelerate..

That's very helpful color. Then I was just curious, if you've seen longer production history on these upsides Cana completions. Can you talk about the decline rates in the production profile on the new completion versus the old style. Is that just a one-to-one shift up in a curve.

Does that come off, that improvement come off somewhat as you get further out in the production profile?.

Well, this is John Lambuth again. I mean so far we're very pleased with what we're seeing with those upside fracs, and what we're seeing at the production of those wells. We're not falling off, let's say faster than what the – say the old style frac was doing.

And I guess I'll reference you to slide 21 which actually shows some relative data as far as flow back time to both the Golden and the Hartz wells.

Let me also say that we are still not fully optimized within the Woodford when it comes to our frac design, we are currently fracking wells right now where we're testing even more stages and more sand, I will tell you that embedded within that Hartz section which what we're showing you there is an average result of Hartz, we have a number of wells, two of them in particular where we did go to even more stages and those wells definitely exhibited better production rates.

So we're pretty confident that we're actually going to be able to get even more out of this rock based on those results, and again we have some wells right now we're fracking, that we think will lead us to the ultimate design that we'll use as we go forward on well four and its development..

Thanks for the color, John..

Thank you. And the next question comes from Phillip Jungwirth with BMO..

Yeah, good morning..

Good morning..

Good morning..

You mentioned the 3% to 8% growth was based on the low end of the budget or $900 million.

So, do you anticipate spending at the low end of the range based on this six operated rig program and the range assumes the potential of second half increase? And then, could you give us a sensitivity in terms of growth rate year-over-year, it is a higher CapEx meaning we were to spend at the midpoint this could add an extra 200 basis points or 300 basis points to grow or is this just help your exit rate in 2015?.

Yeah, this is Tom. I'll – I'm going to take that in the back going forward. Yeah, we have modeled that.

I just want to remind our listeners that it's only been within the last 10 days or 2 weeks that we've seen oil prices inch up slightly and we were in an environment where prices were self-falling so fast and it was very difficult to have any capital model that allows you to make intelligence statements about what your balance sheet would be at the end of the year.

So we made a decision to go to six rigs and we stand behind that decision, even in today's environment we think what is that exactly, where we are to be. So we modeled our production at that low end of our capital. But as I said in my opening remarks, we don't think about this as an annual plan.

It is a snapshot in time that's appropriate for today and in fact, we may make a decision to accelerate a rig or two here next week, if we really are confident that the situation is stabilized.

Our capital model for 2015 as we'd currently plan under current conditions, involves us having cash on our balance sheet at the end of the year, and we don't see the need to have cash on our balance sheet. So we do have the wherewithal to increased activity.

Now, guilty as charged that we have not come out with a production model that captures any increased activity. Our production model we released this morning is at that lower level of activity, where I want to just ask for your indulgence in reminding you that was made in a following commodity price environment.

So, we'll see as we go, we're poised to accelerate..

Yeah. This is Joe. Couple of the points I'd like to make with regard to that too, there is so many other factors that play here. Drilling and completion costs, do they reduce further or are they flat? How that affect our activity and our production? The timing of that CapEx.

If we were to increase our capital expenditures as of Q1, Q2, Q3, Q4, is it applied to road drilling in Cana where we drill wells first get them all drilled and then come back and complete them later or is it single wells in the Permian.

All these factors really tell us that if we were to accelerate our capital spending this year chances are, it's not going to have an immediate impact on the middle of the year projection and would most likely show itself up in the latter part of the year..

And to that point, what's your ability to accelerate or increase net activity in the Chevron, JVA and if you were to add back rigs with which place do you think would see the first incremental dollar allocated to them?.

This is John. We have plenty of locations in the building to bring rigs back into Culberson, with Chevron. We're in constant communication with them, and they see as we see some of the great way to returns we see there. So, we are tied up to do just that indeed, that's one area as we talked about where we see very good returns.

But likewise, just north of there in the White City, our Bone Spring wells are generating some outstanding returns as well. And we have a very nice inventory wells permitted, ready to go there as well. And then as someone else mentioned, we have lots of Meramec locations that we can nearly get after as well.

So, this is not a question of the opportunity set, we are ready to go, we're just waiting for the right conditions to tell us it is time to go..

Yes. This is Tom. It's a lot easier to start than stop. The decision to lay down rigs can take 60 days to 90 days depending on the rig and what project it's on. Decision to add a rig can be executed in the matter of couple of weeks. So, we're poised and ready..

And then last question. During the 2009 downturn if memory serves me right, you guys used that as an opportunity to focus on efficiencies and really kicked off the Bone Spring play into Mexico as a horizontal play.

Just wondering if there is any less obvious efficiency improvements that are worth highlighting that you're focused on this cycle as you look to do more with less capital?.

Well, yes. This is Tom. We are absolutely looking at becoming better executors at resource play development. We have huge resource plays in our inventory and those involve very complex project management challenges.

It involves not only drilling the wells, it involves infrastructure, it involves water sourcing, water disposal, it involves electrification, it involves air quality, it involves a host of things that in order to be a low cost operator, demand is strategic focus.

And in the high growth high level of activity, in some sense, we've been in reactive mode more than the kind of strategic planning mode, there that will take to become that low-cost operator in a lower margin business. And we are absolutely focusing our organization on this challenge.

So our organization is highly engaged and we're building plans for when we come back with a roar. And I appreciate your – reminding us and reminding the listeners of the downturn in 2008, 2009.

I think if you look at that periods in Cimarex history, it was some of our finest efforts and we came out of that correction a far far better company than we came into it and we are fully dedicated to do that again..

Okay. Thanks a lot, guys..

Thank you. And the next question comes from Brian Gamble with Simmons & Company..

Good morning, guys. Couple of things, one on the upside, just looking at some of the well results in the Permian for the quarter.

It looked like some of the IPs maybe a little bit short of what you'd recognized through third quarter, but the oil cuts were outstanding, is there anything specific that was being done in each of those plays to change that, or is it just the matter of geography, maybe you could walk through that a little bit?.

Yeah. This is John. I think in particular, you're making reference to our Culberson long laterals entity (34:47). And you hit it right on the head, one of the biggest factors there is geography. We're obviously delineating more and more of our acreage with those wells. And in some areas, it's very good, in some areas, it's not.

And so that's one driver to that. And then the other is, we always are tinkering with our frac design. And some of the newer wells, we've been really pumping a lot of fluid. And quite frankly, and flowing back those wells that will in some ways have an impact on the overall IP 30 rate.

We don't think it's really material to the EUR of the well, but it does have some potential impact on the flow back on that well. But mostly, it's geographic diversity as we continue to explore across our large acreage position there..

Great. And then maybe on the strategy side of things, Tom you kind of mentioned that it's obviously the flexibility is the keyword, taking it down to six as we've – if we call a bottom here on crude in the low $50s, looking at the slide that you have provided. The (35:53) are still pretty impressive in multiple areas.

And when you think about ramping capital up from the low-end, do you need to see improvement in the oil price to make that happen or do you just need to have – I guess from a company standpoint, some reasonable certainty or some reasonable comfort with the current levels because even at current levels it seems like your returns are more than acceptable?.

Yeah. Brian, you hit the nail on the head there. We have great assets, and there's lot of things I am grateful for. There is no substitute for asset quality, and we have great assets. Assets that in today's climate with current costs and current service costs generate very-very nice returns. So, that's not a barrier, just picking up activity.

It's we want them to just become convinced that we can see a stable future. There is still some speculation out there that we haven't seen the bottom in the oil markets. And the last thing we want to do is get out there and accelerate and then see oil slide into the $30s.

Now, maybe that's not going to happen, maybe we've seen the bottom, and if you're willing to call it on this call Brian, I think that'd be great. We're just going to watch this a little while. And I want to be clear here, we're not committing to what a little while means.

We may go next week and say, it's time to add a rig or two, but we want to be very forthcoming with you today as to how we see it and our most prudent course of action is to say you know what, we're just going to watch this until it clarifies.

So no, we have great assets and we think our assets can generate acceptable returns in today's commodity pricing..

Great.

And then one quick last one on the Meramec, you mentioned either the plans or the future possibilities of drilling 10,000 foot laterals, are we drilling a 10,000 foot Meramec in 2015, should we expect that before year-end or is that a 2016 event?.

This is John. We definitely are drilling in 2015. In fact, we have one come up here real soon on the schedule.

We right now have three scheduled and really in drilling those, we're trying to place them close to – we have an established 5,000 foot lateral that way we can measure the uplift and get a good sense of is that a good investment decision for us.

So, we have quite a few planned for 2015 and as we get that data and get the production data in hand we'll give you an update on it..

And John, do you want to throw an approximate AFP on that 10,000 foot?.

This is Joe. I'd probably run it somewhere in the $11 million to $12 million range..

Great, Joe. It's very helpful. Thanks guys..

Thank you. And the next question comes from Joe Allman with JPMorgan..

Thanks, operator. Hi, everybody..

Hi, Joe..

Hi, Tom, I know, we're just trying to figure out what you guys are going to do next week or next month.

But can you just help us think about 2016 in terms of – I know you're not going to give your budget, you don't have one but just give us kind of the guidelines and the parameters given that as of right now you're going to be running six rigs, would you expect to see production decline in 2016, given the status quo? You mentioned you expect to have cash on hand, would you expect to have cash on hand at the end of 2015 close to the level at the end of 2014? And anything in particular to consider about 2016 from an operations perspective?.

Well, let me take the last question first. No, we're going to – the cash on hand issue – we currently model somewhat less than $100 million cash on hand at the end of this year. And as I said, we don't see any virtue in keeping cash on our balance sheet.

So, I would not anticipate that we have cash on hand at the end of 2015 that would be comparable to 2014. Now as we look into 2016, we are looking at plans for when will be the appropriate time to accelerate and after that balance sheet is formed, and we've said that for years and we mean it.

So we're willing to tap that balance sheet as long as our investment returns are excellent, and as we've always said they can stand that downside test. So, you know Joe, the issue is accelerating in 2016, is what's the downside test? In October, when oil was $75, we pulled our group together, and said, look, let's run a new flat case on oil of $50.

And at the time, we thought, well, that's just ridiculous, and we blew right through the bottom of that.

So, before we would make a decision to accelerate, we would want to have confidence in knowing what our downside case was because we wouldn't want to borrow and wake up and find that our credit statistics are well outside the balance of what we're comfortable with. So, we have not abrogated growth in 2016 under any way, shape or form.

We think we have the assets demanded and the balance sheet that supports it. But as you started out your question, we are taking this in kind of day-by-day right now..

Okay. It sounds – that's helpful. And then a different question maybe it's for Joe or for John. You guys talked about 4Q, 2014 to 4Q, 2015 flat-to-down slightly.

Could you just give us a break out by product, oil – how do you see oil over the same timeframe and that gas and NGLs?.

Mark, you want to add..

Yeah Joe. Yeah I'll take that. This is Mark Burford. We look at our production mix and the combination or components or commodities, Joe. We see it fairly stable oil, gas, NGL mix.

In the fourth quarter, we averaged 49% gas, 27% oil and 23% NGLs and look out into 2015 it might be a percent of variability in oil, as Joe mentioned the front-end loaded nature of the Permian and then the second nature of the Beacon (42:24) into the fourth quarter for our average 2015, oil breakdown is still about 48% gas and oil 29% and 22% NGL.

So very similar mixture of oil, gas, NGLs going into 2015 with some variability quarter-to-quarter depending on the ramping of the Permian in the first half of the year and ramping in the second half of Mid-Continent..

Okay. I think it's helpful.

I'll work with that and contact to you guys offline, but just one final question with the new completion designs, are you increasingly confident that not only are you increasing production, but you are actually increasing reserves per well?.

This is John. I think we are gaining confidence with every months of more production day that we have from those wells yes, so they clearly are getting – they're giving book at a higher EUR. And so now, we don't think this is in anyway just acceleration. I would also point out though that, we are really-really focused way to return.

And so way to return in some ways is really driven by those first three months of production and clearly these wells are generating much higher production rates than what the over spot fracs were doing..

All right. All very helpful. Thank you guys..

This is Joe Albi. I wanted to clarify some to the previous question on the two-mile Meramec. Our current AFEs are probably closer to range of $10 million to $11million rather than $11 million to $12 million..

Thank you. And the next question comes from Matt Portillo with TPH [Tudor, Pickering, Holt].

Good morning, all..

Good morning..

Good morning, Matt..

Just one quick clarification on the cash comment.

You mentioned that you could be down to $100 million in cash by the end of 2015 and I was just curious, under that scenario and kind of the $900 million capital program, what commodity deck would you be assuming to kind of generate that sort of cash draw down?.

Yeah, hi Matt. This is Mark. Yeah.

We have run (44:33) primarily measure when we look at our cash flow projections in that one that we're looking at more recently was Friday the 13 strip price that we most recently ran into that, that's about $56 oil, about $3 gas – and into that strip environment, and strip price, that price environment we were looking at just a little south of $100 million in cash exceeding the year at the $900 million capital plan..

Okay, perfect. And then I guess just a follow-up question in regards to the activity levels. I believe the majority of the rigs here are under contract right now or are currently running in the Cana.

As you guys wrap up your operated drilling program in the first half of the year, how should we think about kind of rig allocation between the Cana and the Permian into the back half of 2015?.

Yeah. This is John Lambuth. Essentially, by the time we hit June – May, June, we will be at the six rigs. Three of them will be operating in Mid-Continent and three of them will be in the Permian region..

Thank you. And then, my final question just is in regards to your 2015 plans in the Wolfcamp in Culberson County.

You guys highlighted you're focusing in the Wolfcamp A and D, and I assume the D is because of the strong well results you've seen so far and the ability to hold the depths in the A, given the higher oil cut, could you talk a little bit about the Wolfcamp C wells, you've seen to-date and how does that compares on a rate of return basis or how that fits into your program in the medium term?.

Yeah, this is John again. Well, clearly right now, both the D bench and the area are generating the best returns for us in that particular acreage block in Culberson. Our C results are not as strong, as they are in the D and the A. We still need to do some work on the C to try to get it to a level that it would justify further expenditure for us.

Now, again, you made a good point there. By drilling our D wells, we don't sacrifice those opportunities in the future. And indeed as we keep working at it, we see may at some point raise its level from a rate of return standpoint that we'll want to go and capture it.

But right now, today, based on our results, it's the D and the A that clearly shine best in that region..

Yeah. I might add to that, this is Tom. Well, we're going to full resource development. There is a pretty good chance, we're going to exploit all three of those benches and not leave those reserves stranded. So we've a lot of work to do and plan for that.

We're not for – if it's a-la-carte the A and D are certainly sharing the day for this – it's full payable service. We're going to probably develop that C simultaneously..

Thank you very much..

Thank you. And the next question comes from Ipsit Mohanty with GMP Securities..

Yeah, hi. Good morning, guys. My first question is on Meramec. You showed a variation in oil cut across up dip and down dip and not to know – knowing you guys don't throw out a curve without adequate confidence in the play.

How does your program look like in 2015? Are you going to focus on up dip, and have you held what is needed to be held by production? Any more color that you can provide?.

Yeah, this is John. Let me first say on the acreage side of things. Of our upside acreage, almost 85% of it is already HBP. And so we really don't have much of the lease exploration issue at all for the Meramec for us, and what little we have will be easily satisfied with the wells we have planned both this year and the coming years.

So that's not of a concern to us. In times, what are we targeting? We are still trying to fill our way across this fast position as to where are the best returns. Clearly, some of those up dip wells are outstanding wells.

But I will also tell you some of the down dip wells have some phenomenal gas rates associated with them, and still generate very nice returns even for 5,000 foot lateral. So right now as far as 2015 goes, we are not going one area using other we are again trying to expand the opportunity set with our delineation wells.

And then we'll see as we go further long. But again, right now, the returns look good whether on one side of that mine or the other right now..

Yeah, I just wanted to add. This is Tom. It's the wrong viewpoint only to look at commodity mix, when you look at the Meramec. A very very significant over (49:13) is pressure. And as in so many place up dip to down dip, you go from essentially normally pressure to overpressure.

And we think we really like our position in aggregate and we've got a lot of energy in that reservoir, we're over pressured, where we have our acreage. And I'm not sure if the map was all clean and we're releasing today, we're not clear (49:38) for our acreage exactly where it is..

Okay.

And then just looking at the first quarter, is it going to be very frontend – frontloaded with completions? Are you going to exhaust your entire backlog coming from 2014? And my related question would be, would you run if you keep your rigs as is, would you run a risk of not having kind of any headroom or any kind of backlog going into 2016?.

This is John, with our rigs moving from the Permian and to the Mid-Continent, we're obviously going to finish up all the completions that we have in the Permian. So as far as future wells are concerned, we've got a number of them permitted and queued up and ready to go.

So it's just a matter of drilling on them and then getting them fracked and back on the frac schedule. If I understood your question....

Yeah.

I think the only comment I'd add is that, are waiting on completion well (50:35) against the derivative of, I don't know, which are running and assist (50:41) the client from completing drilling the well and completing it, that's what the backlog as of the year-end represented albeit we're low (50:47) on our rig counts, that backlog will decrease until this represent what (50:51) that rig finishes drilling?.

So certainly, by the way, we're looking at it from a capital expenditure standpoint. We don't say drilling or completing, we just say dollar spent. And that carryover evolves from 2014 and 2015 as capital associated with them, that we incorporated and we're fine and that's completion capital..

Got you. And with predominantly, you're moving into longer laterals, extended laterals. I was just curious if you've got the operational risks that are generally associated with during such laterals if you got it into science now, looks like you're.

But if you can talk about how well you understand the risks involved in drilling such laterals, especially when you are in a capital constrained environment?.

This is Joe. Knock on what we are gaining that that efficiency in our operations and find very, very comfortable drilling two-mile laterals whether it's in Cana in the Woodford or the Meramec or in the Wolfcamp..

Great. Thank you..

Thank you. And the next question comes from Michael Hall with Heikkinen Energy..

Thanks. Good morning. I guess first of mine is on the Cana program, correct me if I'm wrong, I think in the past call or early last fall or late last summer, you'd initially talked about I think a full 10 section development as a part of that infill program versus like seven now.

Is it right, number one, I want to guess is that right? And then number two is, is it right to think about that as your just – you'll still be developing that full 10 section row, but it will just take longer and so that program that really then just bleeds into 2016 and provides a nice tailwind as you move into the 2015 period?.

Well, this is John and you're absolutely correct. Again that as we're planning for this well development, given our commodity prices, we have fully expected to do 10 sections led to development. Commodity prices have changed.

And so right now, a number of the sections we find right now not to be of a sufficient return that we want to make the investment today. Those sections don't go away, they're always BT (53:19).

So, we have made the election to only develop seven of those for now and just essentially save the other three for another day when commodity prices justify making an investment then..

Okay. So, it sounds like maybe it's more about the economic sensitivity of the unit as oppose to just overall decision to slow the pace of the development of....

Well, it was a little of both. I mean the wells that we've decided not to drill this year are down the drier gas portion, but they still generate reasonable returns. And depending on our results with the infill project, we've discussed as recently as this morning that we could add additional development sections on to that development this year.

And so, that certainly I would say this, an additional extension of that development program is among our options that are active that we wanted to up our capital slightly this year..

And I'll call off with that. Tom's absolutely right and that couple of those sections are queued up permitted ready to go and we have that optionality. And so, don't be surprised if indeed we add on from seven. We will – Mark, obviously make that decision as we monitor the commodity prices, as well as our capital and what we want to do..

Okay, great. That's helpful. And maybe it's a little too granular, but is it fair to say that that's the low point from a quarterly perspective this year would be second quarter.

Is that the right way to think about it?.

Actually Michael, this is Mark again. This is actually our third quarter will likely be our low point for the year, but (55:05) activity in Permian in the first quarter and second quarters as it'll be growing, it's going to be pretty flat and in the third quarter it'd be – it looks like our low quarter..

Well I think (55:14)..

Ish, we'll put a big ish after it..

All right..

Okay. And then last one's on mine, I think on the Meramec good update there. I guess any way you provide a range of the DOE or MMTSE (55:37) flow rates across those fits, I'm just trying to get a sense for like you said there is maybe quite a bit of dry gas rate associated with those down dip wells.

I'm just trying to better understand how the distribution looks around that average?.

Well, I mean for now we've elected to give you the average rate for those wells. I'll just put it this way, there is still a lot of drilling to do and there is also quite frankly some leasing to do. So as much as we're very proud of these results. There is still a lot to be done here.

So I think what we've given you is I think is a good snapshot of the kind of results we're having right now..

Okay. Great. And then....

(56:28) in that average. These are really good wells..

Okay. On the economic comparison you put on slide 20.

Is that well I assume that's the averages of the hydrocarbon mixed in average well or is that...?.

Yeah. That's just not taking a generic type curve for both ways. And giving you an idea of what those returns are like. But clearly, depending upon where you are those numbers can swing quite a bit one way or the other but that's just the generic type curve the book plays (57:01)..

Great. It's all very helpful color. I appreciate it..

Thank you..

Thank you. And the next question comes from Irene Haas with Wunderlich Securities..

Yes. My question, and going back from there, Meramec has turned around to understand (57:22) it's still delineating. So far, the wells have been – they have been really good.

So, should we think of this spread as having very low exploration risk, and really what I'm after is, how continuous is this interval, or how heterogeneous the play really is and so how many more wells would you need to truly understand the reservoir architecture?.

Well, I'll try to answer that first. This is John. We did talk about on an acreage position that we consider to be delineated, meaning that from those wells, we feel very good about going forward from an investment decision.

I will tell you and again, Tom mentioned this, we've been very pleased that along those wells that formed that average – as Tom said, there's not a dog among them. And so, that does, in some way, speak to the lateral consistency of results that we're getting across that position. And then, so that's encouraging, very encouraging to us.

But we're only technically seven wells into it. So hang on, let us get more wells drilled. But so far, I would say, we're very encouraged again for that immediate variable, we drilled our wells to the consistency we've seen from the production of those wells..

Yeah, Irene, this is Tom. I mean, we're in the business of being romanced by upside and the Meramec offers tremendous romance. And one of the things that we don't know and I really want to be clear, we don't know – we don't know what the spacing will be. But we also don't know if there will be multiple zones. I mean the Meramec is a fixed section.

And there are some of our competitors out there testing stack laterals and as we look at that section and we have indeed varied our own landing zone, as we drill these wells, we will be testing that there could be multiple zones in the Meramec, possibly a couple of layers to this. So, we just don't know.

And John's point is really the right one that with just six wells or seven wells an area this large, we have a lot of work to do before we can really get too granular with it on what this asset can deliver. So, I think, very encouraging so far..

It's great. Thank you..

Thank you. And the last question today comes from Cameron Horwitz with U.S. Capital Advisors..

Hi. Good morning..

Good morning..

Hi, Cameron..

Hey Tom, you referenced in deal flow early in the call. I was hoping you could just talk about what you're seeing out – out there from that perspective.

I guess asset quality wise, if you've seen any reconciliation of some of the wide bid/ask spread that we've heard so much about? And also maybe just the competitive landscape? And how that's maybe changing here over the last few months, seems like there's been quite a bit of an influx of private capital competing, looking to take advantage of some of the same opportunities that you all are, so hoping you could just give us some color there?.

Well, I'd be happy to and none of what I'm about to say is news to you. There's a lot of capital in our sector in chasing opportunities, and there's a lot of private equity money on the hunt. Now there are some assets for sale and they're good assets, but there is still that bid/ask spread.

I think that there's still a sellers' intent to try to find last year's work if you will, I mean, I think – I think asset prices have to rationalize around current commodity over look and we haven't seen that yet.

There is also corporate opportunities that get whispered to us from time-to-time, we've looked at a couple of them and wouldn't surprise you to hear that some of these companies have a lot more debt than we do and when we do a pro forma, we're – you got to just love the asset in order to take on that burden.

And it's – as I said the outset, our hurdle is high, but – I think a lot of these management teams out there are going to try weather through this to the extent they can, it's just going to be a function of how brutal does this get and how sustainable it will be.

As I said in my opening remarks, we're not waiting around for a recovery, I mean at Cimarex we've got assets that can work in this environment and we're getting our cost structure, so that we can move forward and not looking back.

And I think there is going to be have to be more sellers with that viewpoint before there's going to be pricing that makes sense..

Okay. Thanks for the color on that Tom. And then can you just talk about how Ward County kind of fits into the strategic picture, I think you talked about that somewhat falling down in terms of the (62:16) on the Wolfcamp and just some of the challenges there some of the water and stuff.

Can you talk about and how you think about Ward County is that they're better potential monetization candidate for you or is that just kind of wait and see how things evolve.

How are you tracking that in obviously a much more constrained environment?.

This is John. It is clear to us that Ward County currently based on our drilling results doesn't compete versus Reeves or Culberson and that was even true at a much higher oil environment and there are challenges in Ward County that we've yet really been able to overcome with our drilling program. That said, we don't have a lot of exposure this year.

I think at last we're looking at about 3,000 acres of explorations in 2015. And so and as much as we're not going to be actively drilling there. We will certainly be monitoring other companies who have assets around us who will be drilling, and pay careful attention on what they do.

But I'll just say as of right now, we have no plans to do any drilling this year for Ward County..

And we haven't really explored monetizing it. I think our – always our first preference is to figure it out, and Joe and John's right we're going to be starting it, and watch our competition carefully..

Thanks, Brian..

Cameron, (63:44), once the Culberson County is going to work and now it's out there in our portfolio..

Sure. I appreciate all the color. Thanks a lot..

Thank you. And with that, I would like to turn the call back over to management for any closing comments..

I don't think we have any comments, just thanks for participating, and have a good day..

Thank you. And the conference is now concluded, and you may all disconnect your phone lines. Thank you..