Good day, and welcome to the Cimarex fourth quarter and yearend 2013 results conference call. (Operator Instructions) I would now like to turn the conference over to Mr. Mark Burford, Vice President of Capital Markets and Planning. Mr. Burford, the floor is yours sir.

Thank you very much, Mike, and thank you, everyone, for joining us today on our fourth quarter conference call. And today here in Denver, speaking will be Tom Jorden, President and CEO; Joe Albi, Executive Vice President and Chief Operating Officer; John Lambuth, Vice President, Exploration; and also present will be Paul Korus, Senior Vice President and CFO; and Karen Acierno, Director of Investor Relations. We did issue our financial and operating results this morning, a copy of which can be found on our website, along with our latest presentation, which might be you finally find useful, when I make the references to it during the call today. And I need to remind you that today's discussion will contain forward-looking statements. A number of factors could cause actual results to differ materially from what we discuss. And you should read our disclosures on forward-looking statements and our latest 10-K, other filings and news releases for the risks factors associated with our business. With that, we'll have a full call. I'll get the call turned over to Tom.

Thank you, Mark, and thank you to all of you on the lines, participating in today's conference. We sincerely appreciate your interest in Cimarex. I'd like to take a few minutes to touch on some of the highlights of the year before turning it over to John and Joe for a more detailed update. We ended 2013 with 2.5 Tcf equivalent in proved reserves, which was an 11% increase over 2012. Production was up 11% year-over-year as well and we look forward to grow roughly 13% in 2014. Because of our efforts in the Permian region, 26% of our proved reserves are now oil. Revenues reached a record $2 billion in 2013 and our debt increased to $924 million, which represents 19% of our total capitalization. Operationally, 2013 was a remarkable year for Cimarex. We saw continued high rates returns from our Bone Spring drilling in both the Mexico and Texas. We unlocked oil-prone Avalon Shale development in our Lea County, New Mexico acreage through new completion technology. And we saw opportunity in a multi-pay Wolfcamp shale expand across our Texas acreage. Without a doubt, the sheer size of Cimarex's Wolfcamp opportunity became much clear in 2013. One of the things that happened in 2013, as we saw a dramatic increase in competition in the Delaware Basin. We normally don't welcome competition, but it added a lot of data points, the information floor accelerated greatly, and the stars aligned deploying to the high-quality of Cimarex's core position in that play. We started the year with a good, but albeit fragmented opportunity in Culberson County, which was based mainly on the development of the Wolfcamp D bench. Later in the year, we proved that the Wolfcamp C and A were also productive, and in June we signed a joint development agreement…

Thanks, Tom. I'd like to quickly cover some of the highlights of our overall program before getting in to the Permian region. I'll then finish with our Mid-Continent drilling program. Cimarex had a busy 2013, we drilled and completed 365 wells during the year, investing nearly $1.6 billion, 65% of that was invested in Permian region and over 30% in the Mid-Continent region. In 2014, we estimate capital expenditures to be $1.8 billion, up over $200 million from 2013, a result of the continuous success we've had in the Permian region. Speaking of the Permian, in the fourth quarter we drilled 43 wells bringing our total wells to 175 for the year, which equates to 115 net wells contributing to our growing production and reserve base. Throughout 2013, our drilling was focused on the Bone Spring and Wolfcamp formations in the Delaware Basin. The 2013 Bone Spring program included 18 net wells in the Mexico and Texas. Results continue to be good, generating some of the company's highest rate of return with oil volumes representing up to 84% of the first 30-day production. The 2014 program looks to provide similar returns on the $375 million of invested capital plan for the year. Although our inventory of Third Bone Spring wells in Ward County is dwindling, we continue to have about a 200 location inventory Bone Springs, which equates to about two year inventory of drilling. These locations identify throughout our acreage in the Mexico and in Culberson County, where we've identified a thick highly productive Second Bone Spring sand. Moving to the Wolfcamp, as Tom mentioned, 2013 was an exciting year. With the drilling of 26 wells we worked our whole acreage, while adding production from five new Wolfcamp zones, the Wolfcamp A and C in Culberson; the Wolfcamp A…

Thank you, John, and thank you all for joining our call today. I'll touch on usual items, our 2013 production. I'll talk about our 2014 and first quarter of production outlooks, and then I'll follow-up with a few words on our operating and service cost. While we closed out Q4, reporting average net daily production for the quarter of 704.5 million equivalents a day. That came in about as expected, after accounting for the late November and early December whether in pipeline shutting impacts that we reported to you in our December press release. And as we're all aware, we've had an extremely cold winter this year, and its impacts on our production, not only impacted us in Q4, but also a flowed a little bit into Q1, albeit not to the extent we saw at the end of last year. And I'll touch on Q1 here in a minute. With Q4 coming in at 704.5 million a day, our full year 2013 average net daily equivalent production equated to 692.6 million a day. That was above the midpoint of our beginning year guidance, which if you recall, we gave and issued at 680 million to 700 million a day. It was also a record for the company and an increase of over 11% over 2012. As you recall, we had some property sales at the end of 2012, which if we incorporated that into our numbers for 2013, as the impact of that, we were up 13% over 2012 and we're pretty proud of that statistic. With our focus on the Permian, our 2013 oil production jump to a record 36,659 barrels a day. That's up 17% from 2012, and if we adjust that for those yearend 2012 property sales, our Permian oil was up a very respectable, 23%.…

(Operator Instructions) The first question we have comes from Drew Venker of Morgan Stanley.

In your opening remarks, you talked about multiyear development planning, just hoping you could talk about Culberson County to begin with, I guess going through, how long you need to hold your acreage there? How many wells that entails? When you might be able to be drill more Wolfcamp A wells, and I guess, also when do you think you might be drilling more of those 10,000 foot laterals?

Well, Drew, this is Tom. We are indeed looking at a multiyear time horizon and we have to. I mean, we've got decisions to make today that will impact 2018, 2019. We have to collect the science and do the spacing pilots in order to come up with prudent development plans. We don't know what ultimate spacing will be. I mean John talked about 80 acre spacing. He talked about 105 acre spacing. Today, we can't tell you that it's not 40 acre spacing. We just don't know until we go out there and test it. And we're looking carefully at competitors, but right now we're not throwing a lot of spacing pilots going on the Delaware Basin, other than our four. We have one competitor doing another space pilot issue, but we're having to create these data points to setup our out years. So we have to do the science required for out year developments. We have to build the infrastructure and we have to club the financing plan. So we are looking at that year at out years. You asked about Culberson County, overall in the Basin, we're on a glide path to hold all of our acreage, certainly all of that we see perspective, which is darn near every acres. And that's a very manageable program. If we do the minimum, it would probably be $350 million a year for the next few years, but we're accelerating that and we'll front load that, so we can get that held earlier. Your question also was about Culberson County and Wolfcamp A, Wolfcamp C, Wolfcamp D. It depends by large on the lease. Some of our leases, we can hold all Wolfcamp with one well, so we can choose the zone. Other leases, we have to drill the deepest target first in order to hole the deepest interval, but a lot's changed since we have gone into this project, and one of which there was a day when we would have said, we think the Wolfcamp A is our most economic target. Today, we don't know. That Montrose well was landed to Wolfcamp D. And it's arguably the best economics of any well we've drilled in basin. And so we don't know, if leases were a concern, I can't tell you today, which would be our primarily target. We've got a lot of experimentation with these long laterals and upside fracs, before we can make that kind of economic high-grade. And finally, you asked about future development. We do have a development plan and its changing everyday, based on these pilot projects, that's why we're doing them. We don't think we're going to have any issues with land going into full development, whether that would be Culberson Reeves or Ward we don't know today, but we're getting for it.

I guess, going back to the HBP question. Do you have a sense of when do you might have that Culberson position held? And then I guess going back to those long laterals, what would I guess changed your -- how many wells you're drilling on that 10,000 foot lateral basis?

I can address right off about the laterals. We have drilled two now, I mean we have talked about one. Going forward, currently in Culberson for the rest of this year, we have three more 10,000 foot laterals planned, One into D, two into C. We also have seven 7,500 foot laterals. Now you might ask yourself, why not 10,000, and quite frankly that's because of the way the acreage lined up, we were able to drill 7,500 because of the way the o sections were. We have seven of those going forward, four into D and three in the A. So we have quite a few now that that we're planning. And obviously from the results we talked about we're very excited and trying to move quicker towards the path and towards drilling those type of wells. I mean, as far as holding our acreage, I mean we have a schedule and we kind of know each year what kind of capital that schedule requires. We do tend to front in that, meaning we try to get ahead of it. It's safe to say, with certainly by the end of 2017, we'll have a majority of that held or maybe just a few wells maybe we have to do, but we'll be in pretty good shape by '17 for sure.

I want to make one follow-up point. All of our pilots are 5,000 foot laterals and we don't see that as -- in everything we learn on the pilot, we view it will be directly applicable to a longer lateral. And so we're doing our pilots on 5,000 foot laterals, quite frankly, because we can get them drilled faster, completed quicker and we spend a little less per well as we experiment, but everything we're learning in this pilots should directly translate to longer laterals.

One last one for you, do you have exposure to the stack play in Merrimack in Oklahoma? Is that something you've been testing?

As we recognized the play, as we see what our competitors are doing and as we map it, we do feel as though that that interval definitely carries over into our Cana HBP acreage. Quite frankly it looks very perspective based on where they're putting their laterals. And we are developing plans to aggressively move forward and tested here in the near future on our acreage, at least some initial tests.

Next would Cameron Horwitz of U.S. Capital Advisors.

Question, Tom, you talked about Culberson being pretty well set out to moved along longer lateral development there. Can you just talk about the setup and reason Ward counties? How much of that do you think you can move toward the longer lateral development?

We have a fair amount, and I'll let John chime in, but certainly in Reeves County, there is a fair amount of our acreage that would support long laterals. I'm looking at John, half maybe?

I would say, at least half.

The challenge in a lot of these areas is it's parsed up land-wise. So it's a nice thing when you get these continuous acreage blocks. Ward County, we have some good continuous acreage blocks, but whether that will be -- I don't know if that will support for 10,000 foot lateral. We may have some 7,500 foot laterals to drill there. But when we think long laterals, based on what we seen, we're going to do it everywhere we can. But it really harkens back to the real value of that agreement between Chevron and Cimarex. Long laterals were strong motivator for both companies to enter into our joint development agreement and the results we're seeing are really, really reinforcing that decision.

And I guess sticking with that topic, I mean can you just talk about the interplay with moving the longer lateral, I mean obviously you're getting much more right upfront and just how that dovetails with thinking about facility and midstream build out there?

It obviously plays a big role in that. The resources needs not only, as far as batteries, equipment, but also people. And as we continue to look forward down the road as to our resource needs, this all plays a big role in that. So we're trying to optimize every which way we can. There is not only just operational efficiencies to be gained, we also firmly believe there is tremendous capital efficiencies to be gained as well.

And then just jumping, same to Culberson, and then jumping at Bone Spring, it looks like you had a pretty nice uptick in terms of the average productivity on those wells from last quarter. There is some talk about some upsize frac from some initial comments in that area. Was that playing at all into the results or is that in the balance of just the natural variability.

I would probably lean more towards the natural variability. We have played with the frac design. Tom mention, it is kind of nice in Delaware Basin that there are a lot of competitors, and we pay very close attention to what others were doing. We learn from that. In the case of the Bone Spring, we have tried some upside fracs. I would say, right off the bat, we got the kind of uplift we were looking for, but still the jury is still out. Those wells are still in early flow back. I would also point out that we're just getting more and more comfortable with that region in terms of what we're looking for, in terms of what we're putting those laterals in the Bone Spring. I think that's what's showing up in the kind of activity results we're getting there. I mean it's turning out to be, without a doubt, that Second Bone Spring in Culberson, some of the highest rate of return wells we're drilling right now.

And then just lastly Permian. I know it's not a focus area for you guys, but I think you drilled a few wells over in Reagan County. Just kind of curious what the plan is there, if that's an area where you look to expand or potentially a monetization candidate?

Probably in that case more monetization and we have some legacy acreage there. Our team did a nice job of identifying the potential there and there was enough acreage to justify what's going out there and doing a couple well test. We're still in flow back on those wells, but we were encouraged enough from the results that we have budgeted some money this year to drill some additional wells on that acreage block. But this is not a very big position for us at all. It's more about just taking advantage of having that relatively small track of land right there in Reagan and drilling on it.

Next we have Jason Smith of Bank of America Merrill Lynch.

When thinking about the drivers behind your production guidance growth for 2014, have you assumed any uplift from the upsize fracs like you've seen from Tim Tam or from the longer laterals or is there a bit of conservative in both in there?

When we first put our plan together, we had limited data. So the answer to your question at a fairly high level is, yes. We've incorporated production uplifts on a risk basis for our Wolfcamp program and that's built into our numbers.

And with your initial Ward well out of the way and with you saying earlier that you probably don't have as much acreage to drill longer laterals on there. Should we expect you to maintain a fair amount of activity there or do you expect to shift the focus really back to Reeves and Culberson? And what do you have to hold acreage-in in Ward?

Well, we expect to be still fairly active in Ward. We do have acreage to hold. As you know, we picked up a nice block of acreage last year that we will need to overtime here drill on. But, no, the actively level will be pretty good at Ward, because we have a lot of acreage there, but we also have a lot of testing delineations still to do there. Of the three areas is the one where we've done our lease drilling. So we still have a lot to do to learn and understand how perspective that acreage is, I'll just point out, not just in the A, but I would argue throughout the entire Wolfcamp section there. We haven't really stepped down into the deeper section yet, although we talk about doing that at some point later this year in Ward.

We're quite high on Ward. It's not a stepchild by any means. We currently have 18 rigs running in the Delaware Basin and four them are in Ward County. So it's a good project.

And I'd like to squeeze one more, and you guys haven't talked at all about potentially testing the Delaware zone. Do you have any plans to do that, as you go through this delineation here?

We don't have any plans as of right now, as we always talk about, we recognize it. It's just obviously our first primary purpose, when we drill the well in a new section like that is to hold acreage and so we're going to the deepest target, where we can get good rate of returns. We will get there eventually, but as of right now, we don't have any plans.

There's no mystery there. We like the Delaware group. We've drilled a lot Delaware in our history. The thing is it's relatively uncontrolled out here. It's a big thick package, sands come and go, and you need to map it with control. So every time we drill a Wolfcamp well, we add another point of control, we're mapping as we go and we see it as future objective, but it certainly will be part of our 2014 program.

The next question we have comes from Phillip Jungwirth of BMO.

There were some well in Ward County had a pretty comparable IP rate to the typical Third Bone Spring well that you've drilled in the past over there. But is there any reason to expect that you might see a shallower decline rate in the Wolfcamp than you've seen in the Bone Spring?

We don't know. I think honestly just time will tell in that case. I don't know that -- I guess I'll just say we don't know. We just need more production history here to tell us whether or not we can get a different type of decline profile than what the typical Third Bone Spring sands do. So we'll just have to wait and see.

And then on Slide 14 in the presentation, where you mentioned Ward County, in that slide are you saying that you don't think the Wolfcamp B through D is perspective and Ward that you just haven't tested that yet?

And you're referring to Reeves County?

Ward County?

Right now, I can't really comment on D. Honestly, when we look at Ward County, the next sound that we get really excite about is really the B/C. Now, I don't know that really look much at D, I think it does thin there some, but I can't really comment. Nobody's, really to my, recollection has drilled a D well in Ward County.

Just on Slide 14, our wells and targets that we're currently exploiting that we view our economic. So in Ward County, we only have one target there, because that's all we've drilled. We will be testing the B/C as John said. It looks highly perspective to us. We didn't include on the slide, because we don't have any results.

And then on Slide 12, the old curve looks like the 5.5 Bcf case from last year. But I was wondering what the EUR assumptions are for the Tim Tam well? Just looking at the graph and the PV10, it looks like it could be a little bit higher than the 30% increase in IP range that you've talked about from upside fracs?

We're not prepared to comment on EUR for a well for which we just have a few months of production. We're going to have to watch it. And it does look like it's a little shallower decline in our original wells. And we're seeing greater than a 30% uplift certainly on sustained rate. But time will tell our EUR there.

Then the last question, how much opportunity is there to expand your existing Avalon oil acreage and then also the Reeves County acreage positions?

I must say that Avalon position we have is right in kind of the sweet spot of where the best Avalon wells are being made. And so it's pretty tightly held by a number of operators. We're fortunate enough to have the position we have to develop those locations. So I don't see much in a way. There is no acreage necessarily just go out there and lease, it's tied up pretty tight. Your second question? I'm sorry.

Reeves County, Wolfcamp?

In terms of additional acreage?

Yes.

Well, it's safe to say, yes. We are still actively trying based on our mapping to continue to acquire acreage, and we continue to be somewhat successful in doing that. But we still are having some success picking up new leases in that play.

Next we have Brian Gamble of Simmons & Company. Brian Gamble - Simmons & Company: Guys, just a follow-up on the acreage question over there. As far as your position in Culberson and the relative availability of the longer laterals, does that new tactic of doing this many long laterals as you can, focusing more attention on potential acreage swaps and bulking up acreage in prices where you and some of your neighboring operators will be benefited from that sort of agreement.

Well, boy, I'd love to think we could do that. Obviously, what made the Chevron JDA so perfect for that is because it was a check report. Essentially they were the white squares and we were the black. So by putting that together it was a natural fit. In other areas, it all kind of depends on how your acreage flows relative to your competitors and your peers and what you could do there. I mean if there was a situation, where we felt like there was someone who had a comparable acreage position that we paired up it would lead to longer laterals, we would probably entertain talking to them. But I just don't know if there is going to be that many situations, just given the lay to land there. Brian Gamble - Simmons & Company: And then you mentioned stack, you mentioned plans to test it, any sort of timeframe you wanted to put around that, as we talk in to something that's eminent, something that's a back half '14 event?

No. I would argue it's more of a latter first, second quarter event for us.

This time we're obviously watching our competitors carefully on that and we see their enthusiasm for the play. We also understand that there are a lot of technology challenges that were faced and dealt in that play. We understand those technical challenges probably. And we see the potential, but boy, there is so much we don't know. We don't know what the yield will be, is it oily, is it gassy, what the deliverability will be. We're going to test it and we'll report back when we have some results. Brian Gamble - Simmons & Company: And Tom, you kind of alluded that with [indiscernible].

That's underway and we'll report, it will be midyear. Brian Gamble - Simmons & Company: And last one from me, as you guys walking through the Q1 production impacts and how those wells come on in the very variability of timing of things. It seemed to indicate that the run ramp for production obviously starts in Q2, but the back half of the year from a percentage gains basis would probably be stronger, is that a fair assumption to make?

I mean to get to the 760 to 780 and start off where we are in Q1, it's obviously a ramp up. And the ramp up as we've currently got it scheduled and all this can vary with completion schedules, frac schedules, crews and what have you, calls for a good ramp up here in the later part of Q2.

And reality always can intervene on the best plants, but I'll say this, we have shy of one rig of the rigs that are fully baked into that plan and we're on track here. So the model is what the model is. It's back half loaded.

This is the exact same type of profile that we put out in front of you guys last year and we did it.

The next question will have comes from Jeff Robertson of Barclays.

Can you all talk about the time you need to evaluate these new frac techniques to figure out if you're having the right recipe before you start deciding whether or not there is a variable you need to change?

I guess it would depend on which engineer I talk to because depending on who I talk to, they all wanted a difference amount of time. There are certain things we look for, obviously what's and rather so excited about Culberson is just that initial IP and that 30-day rate we see, that clearly was a step change relative to our other wells as our graph shows. But I'll be honest, some of these other wells, it doesn't really show up some times early on in the production, but it definitely shows up a good 90 days, 120 days later in the client profile. So sometimes it could take a good 90 days to 120 days before you really sell like you've made a type of change that's going to be material in terms of that overall EUR.

Do you think you'll have data by the time you start completing some of the wells, some of that pilot test you're drilling on pads in the second quarter.

Well, we feel very good about our frac design right now, especially in Culberson, very good. Now, I would argue in Reeves, we haven't drilled as many wells. And I would argue that we still have potential to dramatically change that frac and do even better Reeves. The resource there is very thick. It maps very good for us. And so we still have some homework to do their in Reeves in terms of optimizing that frac, but I'd like the job, we have right now that we're doing as evidenced by some of the results we've talked about in the past. So going forward, we feel very good about our current stimulation for that area.

John, I think you mentioned you all are going to take that technique or some variation of it up to Cana this year? Did you say how many wells you have on inventory?

What I can speak to is we have taken from the Culberson completion and we've taken it to one of our sections and we have completed four wells now in Canada using that frac style and we are inflow back, and again you can sit here and argue how many months is it going to take to tell whether it makes a different or not. But I'll just simply say, as I said earlier, the early signs to us are encouraging. And certainly that's something probably by next earnings call, we'll have a lot more information to tell you about on those wells.

Last question on the Reeves County where you all will drill the stacked pilot in the Wolfcamp A, in Culberson or in Ward is a Wolfcamp A where you show it beginning a little bit thinner, is it thick enough or is it there trying to do any kind of a stacked spacing test as well.

We don't know. I would argue. We will probably test it, since we just don't know.

Is it thick enough? Is it sufficiently thick to absorb to pilots and stack them and we're going to probably test it.

We are constantly amazed based on what others are doing not just within the Delaware Basin, but other Basins and how tight people are starting to put these laterals, vertically from each other. And so that's something we recognize, and yes, and in Culberson A we will more than likely touch that.

The next question we have comes from Abhi Sinha of Wunderlich Securities.

I just had couple of questions. One on Avalon, just trying to get how uniform the acreage is or how continuous the acreage is basically, so I'm trying to evaluate how did you get to 200 locations? Is it just like acreage or spacing or there is more specific location wise?

Again, we're very lucky in the Avalon. There is a lot of drilling that's taking place. A lot of pilots have gone forward. And right now, everyone is kind of gravitating to six wells a section. So really there's nothing more than just taking our current perspective acreage position and then planning out to six wells per section to get to that well count.

So just as a follow-up. The technician that you've brought in Avalon versus what you experienced last time. My guess is like in the last experience, three years ago, when you drilled some wells, you experienced a high decline rate. And the techniques that you're applying right now is geared towards getting a higher IP. Are you doing something to tackle the high decline rate in terms choke size or anything like that or is it more towards getting higher IP, which will get you higher returns.

In the cast of Avalon, you're absolutely right that early on in that program when we drilled the completed wells, we've got very good IPs, but then they would fall like a rock within the first 30 days to 60 days. Quite frankly, with this new frac design, we don't really experienced very high IPs at first, but over time the wells continued to clean up to whereafter 30 days to 60 days, we then reached our peak IP. And then we see much slower decline. So that's what's been the biggest change as per that frac design, which has led to that kind of result we're having. So we've fundamentally had changed kind of the flow back profile of those wells based on that frac.

And on the Wolfcamp side, can you comment if you have any presence of Wolfcamp in your New Mexico counties like Lea or any counties like one of your smaller competitor just reported a well in Lea County I guess having the Wolfcamp presence?

We have acreage in that play, especially up in the White City area. But we also recognize that that it could expand even beyond there. We just haven't got to the point of testing it just yet in the areas like Lea County like you're mentioning.

White City is in Eddy County, and that's actually where we drilled our first Wolfcamp well in 2009.

An area quite frankly we're looking back at now from along lateral standpoint. It to us right now that area looks very perspective now, because of these long laterals.

And lastly, could you just remind us, how your rig distribution looks like right now? I mean considering you increased the rig count in Permian from 12 to 16 and it decreased in the Mid-Continent, but I'm not sure what the non-activity looks like in Mid-Content and how the rig distribution look likes versus Bone Spring versus what you have in Wolfcamp?

Well, I can tell you exactly, what's going on today, but also in 30 days it will change, because obviously any one rig we have could move from a Bone Spring to a Wolfcamp well. But as we speak right now, we have nine wells, soon to be 10, drilling Wolfcamp wells. Six wells drilling Bone Springs and then one well drilling in Avalon, and then there is another rig testing other types of concepts for us right now. So right now that should bring you to 18 with the 19 rig coming some time in the April, May timeframe. In terms of Cana, we have the two operated rigs and then we have a partners has six rigs. But our understanding is they will be winding down the rig count to essentially zero some time here in the second quarter, if not sooner in Cana.

Matt Portillo of TPH.

Most of my questions have been answered, but I want to do just follow-up on a few. In terms of your acreage position, you mentioned perspective acreage in Reagan, and then also some perspective acreage in the stack. I was wondering if you could put any context behind that in terms of the size of those positions?

Well, I can say this much in terms of the Midland Basin right now we have seven wells scheduled for Midland on that acreage. Again, the 2014, I think there is some follow-up ones in '15. It's not a huge position.

It's not going to be more than a few dozen wells in absolute total.

And then in terms of stack, I honestly I don't know, we really have a good number on acreage right now. We're still trying to map it to get a better definition of it. We have a lot of acreage over, I'll just say that much.

I can tell you that most of what we know about stack, we've gleamed from the internet. And we see the same mystery that our competitors do and that the long response look somewhat enigmatic and competitive that's ahead of us to call core, and now is unlocking the play to them. We've taken a long-haul core, it's currently being analyzed. As John said, as we map that interval it comes over most if not all of our 75,000 acres held by production acreage. And I just told you about the full technical analysis. We're analyzing the rocks. We are going to test it and the proof will be in the pudding. But one of the many unknowns, two of them are the rate, the ultimate deliverability and the hydrocarbon type. And we can do all the science in the world, and then the well will tell us the answer and that's underway.

And then in terms of the Avalon, I was wondering if you could put any context behind how you guys are thinking about the EURs in the play, even if it's kind of a wide range around it, just trying to get a sense of what your recovery maybe there?

I'm not going to quote an EUR as much as I'll just say again, the rate of returns right now on our Avalon wells are pretty much competing right there with our Bone Spring wells. It's turned into a wonderful rate of return play for us. So we're very, very pleased. And then thus you see the amount of capital we're going to allocate to it this year and aggressively drill it this year.

And then just last question, Gulf Coast has become kind of diminished within your overall portfolio. I wondered if you could give us some color on the plans there kind of in 2014 and then on a go-forward basis on what you maybe looking at doing?

It saddens me to say being a geophysicist that at the end of '13 we've made the decision to close down our Gulf Coast region, as an active exploration region. It really reached to point where with the totality of all the opportunity we had in the Permian and quite frankly Mid-Continent and the type of rate of returns we're generating, we just felt like the Gulf Coast cannot be as impactful as it has for us in the past. And quite frankly, we have extremely talented people in the Gulf Coast that we felt like we could better deploy in both the Permian and the Mid-Continent efforts. So at the end of '13 we did that. We have at best maybe one or two prospects remaining that we like, that we may drill in the '14 and then that would pretty much close the door on our Gulf Coast exploration program.

It's showing that we have reached an hour, we will go ahead and conclude with our last question for today. It will be Ryan Todd of Deutsche Bank.

So a couple of quick ones for you. Following-up on the Avalon, the couple of hundred locations you have talked about in Avalon so far, is that spread across all acreage review as perspective there. Do you have any upside to that potential in Avalon acreage?

I mean, when we quote those locations, we're really talking specifically to that one area in southwestern Lea, that that quite frankly the best wells are being drilled. And that's where we concentrate our effort. As I said earlier, for the previous call, that acreage is tied up very tight. There is not a lot of additional opportunity to expand upon that. So right now that that's where we're concentrating our efforts.

The Avalon is perspective over a very broad part of the Basin. In fact, our one of the best Avalon wells drilled, there's a well we drilled in Eddy County, a very gassy well, a very high deliverability. So could the Avalon expand? Absolutely. It's a function of product price. So it's reservoir and it produces over much of the Basin.

Speaking of price, obviously, has pretty strong gas prices and slightly better NGL prices than we've had in a while. Any thoughts on use of -- I mean I would imagine given the commodity prices that we have right now. I know it's early in the year, cash flow is probably tracking ahead of budget and ahead expectations. Any thoughts on how you'd prioritize use of potential excess cash? And whether you think about increasing activity at all maybe Cana in or targeting opportunism in gas.

We have not changed our capital program expectations for the year, yet. We're still at $1.8 billion. Coming into the year, we envisioned outspending our cash flow by $300 million or $400 million. The higher product prices and higher revenues simply mean, we'll most likely borrow less.

And gentlemen, did you have any closing remarks at this time.

Thank you everyone for joining us today on the conference call. I appreciate your attention and I will look forward to seeing you in future. Any follow-up calls, please give Karen Acierno or myself a call and we'd loved to discuss any other question you might have. But again, thanks for attending and we look forward to report you further in the future. Thanks very much.

And we thank you, sir and the rest of management team for your time today. The conference call has now concluded. We thank you all for attending today's presentation. At this time we may disconnect your lines. Thank you and take care everyone.