Joe Foran - CEO
Matt Hairford - President
David Lancaster - EVP, COO and CFO
Ryan London - VP and General Manager
Billy Goodwin - VP, Drilling
David Nicklin - Executive Director, Exploration
Brad Robinson - Vice President of Reservoir Engineering and CTO
Matador Resources Co. (MTDR) 2013 Analyst Day December 12, 2013 11:00 AM ET
Greetings everyone. Welcome to the second Matador Analyst Day. We're glad to have all of you and appreciate your interest and support for Matador over the course of the year. I’d like to recognize a couple of people here as we get started. First, I’d like to recognize our lead director, David Laney who is here today, who will be available to you for questions and for the competition of the presentation. And in addition to David, I'd like to recognize the Matador staff and we have them here. So you can meet a few of them and see the kind of depth, particularly in the young people, the young cadre of professionals that are coming together, that are making larger and larger contributions. And we'd like to have them stand, please.
All right. And then stay there, and then our Vice Presidents, please stand. And most of us had worked now 10 years together. So it’s been a nice journey with them. And Matt, aren't you going to stand with them or? All right good. And so that’s him, and they’ve done a lot of work, pulled this together and responsible for the results.
Then next I’d like to recognize Don McKennerney [ph]. Don is the head of our commercial lending bank group of eight banks with RBC. He has done a great job and also I understand Don, it’s your birthday today. Is that right? Will you all join me in wishing him a happy birthday?
Next I would like to say that this is very different, standing up here this year, than we did last year. Not just the room change, but the overall growth of Matador has been pleasant. Last year at this time we were about $500 million in market cap. And today I think we are somewhere around $1.3 billion. So it’s been a great past year. And as I said in the news release, we are expecting nothing less than a 40% to 50% growth in our oil production and when that happens, you know all the other numbers really seem to take care of themselves.
So that’s why we think it’s the essential number and as we achieve that and we have programmed the edges, then I think we look back in the year from now and feel good about what we’ve all accomplished. Now having introduced that thought, I would like to move. You’re going to see a lot of graphs and a lot of numbers today. But I’d like to move to what is my favorite slide, favorite graph, and that’s this. All right. And if you didn’t understand why this is our favorite, it’s nice to see the price go up over time but really it behind it represents a lot of hard work by the staff and a lot of planning on their part and gives us a lot to talk about.
Now it may seem pretty simple and pretty corny to say this but our formula really is pretty simple. I have always tried to get good people, particularly with strong technical skills and mix them with some good properties and have a good plan, and when you put good people with a good plan as like last year, the good people tend to make their good plan a little bit better.
And then when you put the good people and the plan with good properties, the good people tend to make the properties perform better than expected. And that’s also what happened last year. But it’s also what I think, while we feel so confident about the year ahead, is the staff is better today and stronger than even a year ago with some additions, we’ve added to our skill sets. Our processes have improved. There’s one thing when people ask me about, being public, I would say my answer may surprise you a little bit. Being public has made us a better company, in large part, because it has made our processes better. And what that leads to is a very sustainable growth.
So we are presenting to you that we are going to grow 40% to 50% in oil production this year. But we feel good about the years ahead, 2015, 2016, and the sustainability of what we are putting together here. And then we will continue to make these kinds of value adds in growth.
And something else that we have tried to accomplish in the two years we have been public, we have operated for a 30 years in one format or other and have, of course as many of you have heard, the Matador story with a legacy of shareholders, but we’re trying to build, continue build our credibility with the market.
When we went public, we told people essentially three things. That first if you would invest with us, that we were moving Matador from just being a Haynesville player to being an oil player in the Eagle Ford. So you have both oil and gas. And we did that. When we went public, we had that 200 to 300 barrels a day of production and today we are over 6000 barrels, headed to over 9000 barrels during the course of the year. And we’ve increased our oil production 15 times on our growth and reserves, probably something like 12.
Now the second thing that we said we would do on going public that we weren’t going to rest, with just having the Haynesville and the Eagle Ford, we would develop a third leg most likely in the Permian. And we’ve done that over the course of this year. We’ve developed a 40,000 acre position there. It’s larger than 40,000 and is growing, and we’re continuing to add in all of our areas.
And finally back to that first graph, I said that we told people on our IPO road show, some of you that were with us will remember, we had about $350 million in oil and gas assets and told people that if you will entrust the $136 million in IPO proceeds to us, we will double the value of the company, and we’ve done that. So we feel good that we can go back to the people we’ve seen and said we’ve done what we’ve said. And then when that happens, that’s what’s great about the oil and gas business. It’s win-win. When everybody does what I say they are going to do then everybody comes out ahead. And that you can see the results.
Now, just to put things in perspective as we were meeting lot before we came over here, just to touch base, we were talking about in 2009, just four years ago, basically to the day, we were looking at EBITDA for Matador at $15 million for the year, and we were pretty excited about that ahead of that time. And we feel good about it, but we had no idea really or little idea. We felt we could grow, but it’s been pleasant to look back now in four years’ to growth that from $15 million to $180 million. We’re looking forward to $250 million as a midpoint for next year and that appears so much easier to do than that first 100 million that we went through. The trend continues.
So what happened, what made the value increases in 2013 and will they continue into 2014? We think they will, obviously. The technical improvements that the operating group has achieved, they’re going to continue on. We’ve gotten drilling cost down, the fracs are better and we’ve built a significant acreage position in the Permian. The oil growth that we had for 2013, we grew it from 1.2 million barrels to 2 million. And in 2014, they are going to go from 2 million to 3 million barrels. The EBITDA growth is going to stay, grew 60% last year. We expect it to go into approximately $250 million as a midpoint.
We successfully completed an equity offering. So if you joined us on the IPO, you went from $12 to $20 today. We’re one of the highest performing, two or three highest performing stocks in the Russell 2000. And if you joined us on the secondary offering, that came out at $15.75, you’ve made money there too and should do well in 2014.
It’s nice to come to you and say we did a 154% and that’s one of the difference between the private investors I had for so many years and the public. When I tell that to a private investor, they lack the year-over-year metrics. But being public and working more at the institutions, it’s a little more of that what have you done for me lately. That’s nice but what are you going to do next year. So, we’re going to get right into that now and you can hear the operating plan.
But I realize that past success is no guarantee of future success. But it’s still, you feel like when you have past success, they’re like a winning tradition in a sports team. It’s more likely to occur if you’ve had past success that you’ll enjoy future success. So we like to build and we believe the oil and gas business is a business that builds on itself that you learn, you learn the technology and you learn the areas and that one year builds upon the other. So we feel comfortable in turn. Here is our plan for 2014. We expect to have good performance but it’s going to lead into years 2015, 2016, and beyond.
And with that, I’d like to introduce our new President, Matt Hairford, and ask Matt to step up here and take over up here. And we work together and I’d like to recognize Matt for having put together a superb operating staff and had excellent execution these past 10 years that we worked together. And he joined us just before we drilled our first well, and has overseen each well we’ve drilled since. But the whole staff has a long history of working together and we’re -- as we’ve grown we’ve to shift some task and you always like give it to somebody such as looking over the operations and execution that you feel will do it even better than you did it yourself.
So Matt, if you’ll come up here and help present, introduce the team and the operating plan, I’d appreciate it.
Thank you, Joe, and I also want to thank Joe and the Board and the Matador team for the great opportunity. This is a fantastic company. It’s a great opportunity within this company. So thank you for that and Joe mentioned I’ve been here almost 10 years and I did ask Joe when I came down and interviewed back in 2004, I came visited with the staff. It was a smaller staff than we have now but I really, really like these guys. In fact I left here, Bradley Robinson, our Vice President Reservoir, he took me back to love field, to get to own a plane. So I got in a car, I get in the airport, I call my wife, I’m talking to her about 30 seconds. She finally says we’re moving, aren’t we? I’m like yes, most likely. So Joe did wait. I got here, we went and drilled the first well and I’m proud I’ve been here for all the wells we’ve drilled so.
So Joe mentioned the staff and he is absolutely right. We’ve got a fantastic staff. I think we’ve put together a group of very high level performers. They’re very efficient. We do a lot with a very small group, and they achieved results which you will see here shortly. In addition, Joe talked about growth and with growth we have the need to add staff, which we’ve done. We have added people over the last year two or three years. We have added people over the last two or three months.
We’ve been very careful to make sure that when we add those people, they’re the right kind people. We want the hard workers, the high performers, very efficient people. So we’re very happy with the ones that we’ve added and most recently, they will come and make good contribution. So we’re looking good there.
On the properties, we have got great properties in great areas. I think everyone is familiar with our Eagle Ford position and Ryan London, our Vice President and General Manager, he’s going to take us through the Eagle Ford, but I think you’ll see we’re in good neighborhoods, and we’ve got good acreage blocks, and we’ve made significant progress. So we’re going to take that same progress, those same learnings, those same processes and go into the Permian.
And so we will talk a little bit about the Permian, where again, great neighborhood, great acreage positions, we’re really pleased with what we’ve got. We’re ready to repeat what we did in the Eagle Ford out in the Permian. So we’ll talk a little bit about that.
And then also the process that Joe mentioned, that’s very important for how we progress. And so you’ll hear about drilling progress, you’ll hear processes, you’ll hear about exploration processes, you’ll hear about completion processes and then they all tie together. So the low hanging fruit is usually easy to harvest. So we’ll do that but then it’s a bunch of little things that we all put together to make us, as we say drill better wells for less money. The process is important, the staff is important and we’ve got great properties.
So that being said I did want to talk a little bit about how Joe; David Lancaster, our EVP, Chief Operating Officer, Chief Financial Officer, how we worked with the entire management team to ensure the success of Matador. I think we have really good chemistry amongst the whole group as the collaborative culture we have at Matador and so we’re going to maintain that. So moving forward you’ll see us operate very similar to what we’ve done in the past.
So thats being said, we’ll kind of walk you through the agenda and make some introductions here. Leading off on 2014 capital investment plan will be David Lancaster. David is our Executive Vice President, COO and CFO. Most of you know David. David actually came to us through Dr. Steve Holditch, who is a board member, that Joe, when he started this second Matador up and Joe was looking to fill the staff and Joe went and asked Dr. Holditch who are some of the best engineers in the business and David is the one that came in mind.
So Dr. Holditch said, a consulting engineering firm that he put together and it was sold to Schlumberger. So David went with that and took the leadership role at Schlumberger. So Joe went and harvested him away from Schlumberger. So most of you know David and if you know David, you want kind of guy he is. He is a topnotch, first grade, first class individual, and he has a total grasp of the numbers. And if you want to know about Matador, you can ask David. We refer to him as the quarterback of the team. So David will take you through the capital investment plan.
And the next Ryan London, our Vice President and General Manager, who will talk about the success we’ve had in the Eagle Ford. We are really happy with what we’ve done there. I just said, we did what we said we’re going to do and Ryan is going to kind of walk us through that and talk about what we’re going to do going forward. Ryan is an interesting guy. He joined us actually as a college student. He was working on his master’s degree at the Colorado School of Mines. We hired him as an intern for couple of summers, liked his work so much, we just hired him. And so Ryan went in the Reservoir Group. He kept hanging around the operations guys, asking questions and kind of getting our business a little bit. So we just said, Ryan you want to join us and he did. So we merged him in the drilling program and the completion program. And so now he is running our asset teams. So he is responsible for how we conduct our business.
Next, Ryan will be joined by David Nicklin, our Executive Director of Exploration. David also comes to us from a referral from a board member. Marlan Downey many of you know, a legendary oil finder. He and David worked together at ARCO. David was a Chief Geologist at ARCO and then Marlan said, you need to get his guy. So we grabbed hold of David. And during the activity in Haynesville, David convinced us early on how important it was to really study these rocks. He told us we need to get an appropriate amount of data, we need to collect rotary cores; rotary sidewall cores, hull core in some instances and log the information on a lot of these early wells.
And what that’s allowed us to do is back to Haynesville, we figured out, we understand how gas molecule will move through the rock. We took that same technique and went to the Eagle Ford and determined how an oil molecule moves through the rock. So we will take that same type of mentality in Permian Basin. We collected the hull core and David will talk about a lot about this in his presentation as he explains the geology.
And then Brad Robinson, our Vice President of Reservoir Engineering and Chief Technology Officer. He’s going to walk us through Haynesville and other gas assets. So we’re kind of, our Haynesville assets are all held by production for the most part. So, the way I kind of like to think about it is the fine bottle of wine. We’ve got the wine cellar, we’ve got this nice bottle of wine. We’ll just keep it in the cellar for a special occasion and with gas prices doing what to do most recently, that special occasion maybe sooner than later. We don’t know but it’s a great asset and we’re glad to have it. Brad. Brad was actually one of the first members of the new Matador that didn’t come from the old Matador and Brad has an interesting way to accept a job offer. Brad came and interviewed, visited with Joe, Joe might be offer. Brad went home and he had a photograph of the small group, what was it; seven or eight people at the time, the original Matador and Brad actually photoshopped himself back in the photograph and sent it back to Joe. So I think it’s a pretty clever way to accept a job offer. Brad helps us, not only with reservoir engineering but evaluating prospects, evaluating acquisitions and so Brad will take us through the gas assets.
Then we’ll finish up with Joe has some closing remarks. We’ll have a Q&A session and then we’ll have lunch. So, we invite you guys to join us for the lunch. We’ll continue the Q&A discussion during lunch and the management team will be here to walk you through that.
So, David, if you will take us through the capital plan?
Good morning everybody. I’m David Lancaster. Very nice to have you all here today and I’m very excited to take you through our 2014 capital investment plan. I would like to just thank and acknowledge the Matador staff in the room with me here today who has done lot of hard work in helping me pull all this together. So, sometimes I get way more credit for this than I deserve but I’m really pleased to take you through it today.
Okay. Let me start the presentation by just taking you little bit through a snapshot of where we are today. Looking at the map here on the left, as you probably know and as Joe mentioned, we started of course in the Northwest Louisiana and East Texas in the Haynesville and in the Cotton Valley and that’s where we begin working and that’s still an important part of our production today. Most of it is natural gas of course but we’re still producing an excess of 20 million a day in natural gas from that particular area.
Of course, over the last several years, last couple in particular, we’ve spent most of our capital investments here in the Eagle Ford and South Texas and that’s why where we’ve really made a lot of progress and grown our oil production substantially of course since the time of the IPO.
We’re currently producing, as of the end of the third quarter, we were producing well over 6,000 barrels a day of oil from the Eagle Ford and about probably 40% of our natural gas comes from this area as well. Then of course up here in the Permian, we have a little bit of a foothold of acreage, but it’s sort of next leg of the stool for Matador and we, currently as you’ve heard put together about 40,000 acres up there now, begun drilling wells and we’re very excited about working in this area, running a rig out there in 2014.
Just wanted to highlight, I’m not going to go through all the numbers here on the right hand side, but I did just want to highlight that our current locations, our engineered locations are about 1,100 gross and about 560 net and you can see how those are spread across the Eagle Ford and the Permian. Certainly in the Permian it’s a very early estimate of locations from that area and we think as we continue to drill and develop our acreage in that area, that that is going to grow significantly. But even at that and looking at the wells that we have planned to drill this year, you can pretty quickly see that we’ve got 10 or so years of inventory at the current pace. So, I think we feel very good about our inventory going forward.
Okay. So, let’s move into the capital investment plan. This is a summary of the plan for 2014. It’s going to be a three rig program that we designed for 2014. We’ll have two rigs running the Eagle Ford and one rig running in the Permian. As you may recall, when we did the offering in September, we said that one main reason that we did that was to help us raise some additional capital to put a rig to work full time in the Permian and in fact that’s what we’ve done. So, today we are running two rigs in the Eagle Ford and one rig in the Permian.
Our estimated capital expenditures for 2014 are $440 million, and that will be up about 20% from what we will do in 2013. I want to emphasize to you that the Eagle Ford is going to continue to be the principle driver of our growth in 2014. And as I’ll take you through the plan, you’ll see that the majority of the CapEx and oil production will still continue to come from the Eagle Ford in 2014.
In fact if you look at the little pie chart down here to the lower left hand corner, you can see that the Eagle Ford will occupy about $318 million or about 72% of our expected capital expenditures, while the Permian will get about 25% of the budget in 2014.
Our objective with the Permian program for 2014 is really to further evaluate our acreage position. So we'll be drilling all across our acreage position, in hopes of, and expectation of defining a more robust development plan for 2015. We'll be looking really to add rigs and ramp-up our program in 2015 with success. So that's the purpose of what we're doing in 2015.
The Haynesville development, it really assumes only participation in some non-operated wells, about 1.5 net non-operated wells in 2014, and so it occupies only about 3% of the budget. Again, you can see on the little pie chart on the right hand side that our drilling and completions will be almost $400 million. So most of this money is going into the ground. We do have about $45 million that’s set aside for land and seismic and facilities.
This is just a little more detail on the plan. I won’t go through this line-by-line, but one point I'd definitely want to emphasize is the fact that about 97% of our 2014 capital investments are going to be directed toward oil and liquid-rich target. So very similar to what we did in 2013. Our focus is still very squarely on oil and liquids-rich targets.
You can see that we’ve indicated we expect that we'll drill 89, drill or participate in 89 gross and about 60 net wells in 2014. That includes about 50 gross wells, 47 net in South Texas, most of that in the Eagle Ford, 12 wells about 10 net in the Permian basin and again about 26 gross but only about 1.5 net in the Haynesville. So overall CapEx budget again about $440 million with about 72% going to the Eagle Ford and 25% going to the Permian and about 3% in the Haynesville area.
As far as our expectations on production for 2014, that's reflected here in this slide on Page 16. You can see that our 2014 estimated oil production is between 2.8 million and 3.1 million barrels. Now that represents an increase of 40%-50% in oil production over 2013 and that's despite the fact that we'll continue to be shutting in wells, and having batch drilling from time-to-time. So we estimate that probably 5% to 10% of our production capacity is going to be shut-in on average throughout the year. That will vary from time-to-time, but that's probably a pretty good average number.
We see our oil production growing to over 9,000 barrels a day by the end of 2014 and we still estimate that the big portion, as you can see, about 87% of our production will be coming from the Eagle Ford in 2013. Certainly the Permian will start slow but ramp-up as we go through the year.
Our quarterly production growth as I mentioned will continue to be a little bit variable, but it will be less so than in 2013 I think, but there will still be some timing effects due to batch drilling, due to shut-ins. We’re going to continue shutting in offsetting wells when we frac the new wells, and so that contributes to a little lumpiness in our production.
On the natural gas side, the estimated natural gas production is 13.5 to 15 Bcf. That's an increase of about 14% from 2013 probably reflects primarily the additional participation in these Haynesville non-op wells over 2013. We still think about 50% of our production will come out of the Haynesville, our gas production in 2014 with the other 50% coming out of the Eagle Ford and the Permian.
Just wanted to point out that the liquids-rich gas that we do get out of the Eagle Ford and that we expect out of the Permian, these numbers reflect the Eagle Ford but where we have the NGLs, that’s usually reflected in our realized gas price since we're a two stream reporter and we've been seeing most recently on the order of $2 to $2.50 uplift due to the NGLs in our gas price.
As far as the financial estimates go, this slide takes you through what we expect to achieve financially in 2014. So the first -- the graph is on the right hand side of this slide, our expectations of oil and natural gas revenues at the mid-point of a range for 2013-2014 and again our adjusted EBITDA is in the lower right hand portion of the slide.
We'll mention, just to begin with that the revenues and the adjusted EBITDA growth is impacted a little bit by the fact that we've used slightly lower realized oil price estimates for 2014, as compared to 2013. So in our schedule for 2014, we have an average realized oil price of about $95 a barrel and we probably actually will achieve something just over $100 a barrel for 2013.
That’s important I think, because $5 plus or minus on oil price at 3 million barrels can make about $15 million in revenue and a corresponding difference in EBITDA. On the gas side we've used an average of about 425 for a realized gas price. That’s pretty similar to 2013. Obviously things are a little better right now than they were this time a year ago in natural gas prices. And so we may do a little better there. Certainly if we get $0.50 better, we’d be talking $7 million or $8 million on revenue at 15 Bcf.
Our estimated oil and natural gas revenues are a $325 million to $355 million for 2014, and that’s up about 31% from 2013. Our estimates on adjusted EBITDA are $235 million to $265 million and that’s an increase of about 35% from the $180 million to $190 million that we had in 2013.
As far as the production and revenue composition, we are expecting that our oil will be about 55% by volume, probably approaching about 60% of volume by year end. And on the revenue side about 82% of our revenue expected to come from oil, approaching about 85% by year end.
Just briefly on the operating cost side. You can see the various operating costs that we’ve estimated on average per BOE for 2014. Just want to point out here that the operating cost, excluding interest that we are targeting are about $17.75, which compares to about $19, is where we are going to come out in 2013. So about a 5% to 7% decrease we anticipate in and are shooting for in 2014. I will note that these costs vary a little bit of course over the course of the year. They’re little bit higher in the first part of the year and sort of ramp down, become a little lower, plus or minus 5% over the course of the year.
As far as funding the capital plan for 2014; we anticipate that we are going to fund this through cash flows and borrowings under our credit facility. So that’s how we did things until the time of the offering last year. And with the offering, we are in a much stronger liquidity position and feel like that we have the sufficient liquidity to execute our program throughout 2014.
We’ve also got 2.4 million barrels of our oil production that’s about 80% to 85%. That’s hedged with flows of about $88 for 2014. So we feel like our cash flows are going to be very well protected. Again I think as you may know about Matador, we have a very simple capital structure; no high-yield debt, no convertibles, currently on the balance sheet. Really the only debt we have is just revolving debt at the current time.
We are in a very strong liquidity position at the current time. Our current debt-to-adjusted-EBITDA is less than 1, and really by the end of next year it will grow but still should be less than 2 by the end of next year. We feel like we have got a lot of flexibility to manage our liquidity. Most of our drilling is operated. We don’t have any significant non-operated drilling commitments.
In addition, as Matt mentioned, our Haynesville as pretty will held our production. A vast majority of our Eagle Ford is held by production. And now we’re just getting started in the Permian, we still have a lot of time running on those leases. So we don’t have a lot of time issues associated with our drilling program. We deal about $30 million in this budget, which is discretionary for seismic and land if we needed to trim on that. And I think equally important, we have no long term drilling or service contract commitments. So we feel like we have a lot of operational flexibility around their liquidity.
This just gives you a little more detail on our hedging. I won’t spend a whole lot of time on this. But again just to reiterate, probably got about 80% to 85% of our estimated oil production hedged between $88/Bbl and $99/Bbl for 2014. We got about 10.8 Bcf of our gas. So 70% to 75%; also hedged in 2014 between $3.42 and about $5 on the top. And then we have got about 7.6 million gallons of our natural gas liquids that are hedged for 2014.
Just thought to give you a little update on the credit agreement and the status there. First of all we do feel like we enjoy a very strong supportive bank group at Matador. That’s led by RBC and Joe recognized Don McInerny (ph) and Don, again, I would like to thank you just for all your help and support and all that we’ve received from RBC and all the banks in the group in 2013. You guys have really stepped up and helped us a lot in executing our plan in 2013. We look forward to continuing that relationship with all of you in 2014. I really appreciate everything the banks have done for us.
Our current borrowing base is $350 million. That’s based on our June 30th reserves. Our current borrowings are at $175 million today. That will probably trend up to about $200 million by the end of the year. We have the ability to request quarterly borrowing base increases as and if we need them, due to growth in our oil and natural gas reserves throughout 2014. Just might mention that -- I am not going to go through the tiers of the credit agreement; you can see that for yourself, but we are currently borrowing at about tier 3 and so our borrowing is 225 plus LIBOR. So our borrowings are at about 2.5% currently.
All right. With that I want to take you through a little more detail, now, that we carried on to the summary, just a little more detail on each of these areas and what we are planning to do in 2014. So in South Texas, we are looking at capital expenditures of about $318 million. It’s a 2-rig program as I mentioned. We are going to drill or complete about 50 gross and 47 net wells.
The 2014 Eagle Ford program is really development drilling. And most of our locations in 2014 are going to be at 40-acre spacing, and Ryan will talk to you a little bit more about the early results of our 40-acre spacing, a little bit later on. We actually don’t have any upper Eagle Ford test plans for 2014. We get that question sometimes. It is something that we are looking at, but currently we haven’t budgeted any 2014 upper Eagle Ford test.
We are going to drill one exploratory well in the Buda on our Glasscock Ranch acreage. In 2013 we shot seismic and we had that process, we’re currently interpreting it, but we’re looking to try to extend some encouraging results that are just to the south and west of our acreage there at Glasscock Ranch and southeast of all the county. Dan Hughes, Sage, Crimson, Contango, others in that area have made some really pretty exciting wells there and high volume, lower cost, high rate of return type wells and so we’re looking to do a test of that Buda and if that’s successful it can set up a nice little program for us in the Buda on Glasscock Ranch.
Really the key objectives of our 2014 plan, if you remember nothing about what I say about 2014 other than I think we’re just here to block and tackle in the Eagle Ford in 2014. So if I’m the quarterback, I hope the people in front of me are blocking and tackling, particularly blocking. And that’s really what we’re all about in the Eagle Ford in 2014.
We’re going to be batch drilling to continue to reduce our cost and reduce our times. We do plan to pick up a second walking rig that’s going to essentially take us to oil batch drilling in the Eagle Ford. We’ve made a lot of progress with our stimulation. Ryan is going to take you through that. But we plan to just continue to do that and advance the generations of the improvements in our fracturing.
Continued improvement in our artificial lift programs, and ultimately we want to try to reduce the LOE throughout all of our properties in South Texas. We also expect to achieve successful implementation of our 40 acre down spacing across the Eagle Ford and of course we will continue to add acreage in the Eagle Ford as opportunities arise. If we’re going to drill 50 wells a year and we could drill in that 40 acre spacing, if we can pick up 2000 -- 2,500 acres a year, it doesn’t sound like whole bunch but it’s sort of replenishes your drilling program. So that’s what we’ll continue to do.
This is just a map showing you our Eagle Ford position. I’m sure you’re very familiar with this. You’ve seen it in many of our investor presentations. But as you know, we have acreage from the southwest to the northeast across the Eagle Ford position. What I’ve done really with this map is simply to highlight in the little circles with the numbers in them, how many wells we plan to drill just to give you an idea of how our 50 wells are going to be distributed across the acreage position. So you can see up in the east and central area we’re planning to drill about 16 wells in 2014 and the other 34 will be drilled down in the western portion of our acreage, primarily in La Salle County.
Up in the east, we’ll be drilling the couple of wells at Lewton. We’ll be drilling nine wells at Danysh Pawelek and we’ll be drilling five wells at Lyssy, which is at least that we haven’t begun drilling on before and we’re excited to begin drilling there. We have probably 20-25 locations that we can drill there at Lyssy.
Then in La Salle County, we’ll be drilling quite a few more wells at Martin Ranch, which has certain been one of our best properties but also we’ll be drilling at Northcut, Pena and Newman up the northwest La Salle. Here is the Buda test at Glasscock Ranch that you can see. And then we have about five non-op wells on our Troutt acreage which are operated by El Paso.
As far as the 2014 Permian plan goes, just a little more detail there. Again this is a one rig program in the Permian. We’re going to be working in Lea and Eddy Counties in New Mexico and in Loving County in Texas. We estimate we’ll drill 12 gross and about 10 net wells. This also includes about 30 million for land and seismic. We frequently get asked are we going to continue to add to our acreage in the Permian and the answer is yes, we will be doing that.
So the key objectives of our Permian Basin program, like I said we just want to continue to further evaluate our acreage position and set us up for an expanded development program in 2015 and beyond. And with success, we’re preparing for a multi-rig program beginning, maybe as early as late 2014 but certainly by 2015. Hope that we can leverage and transfer some of the knowledge that we’ve gained in the Haynesville and the Eagle Ford and expect to do so to our operations out in the Permian. And as I mentioned we’ll continue to add to this acreage position as well.
I wanted to give you a little snapshot today of our Permian Basin acreage position. You know it’s been growing quite a bit over the course of the last several months. Today throughout the Permian Basin we have about 65,000 gross and about 41,000 net acres. We have delineated the acreage positions, where they are and how much acreage we have in each area on the map shown here to the left. Certainly in previous presentations we’ve talked about our Ranger Querecho acreage, the Indian Draw and the Wolf area down in Loving. But one area we hadn’t talked a lot about until today is up here in the northern part it’s, a prospect we call Twin Lakes.
And one reason that we hadn’t talked a whole lot about that is that we’ve been pretty actively leasing in this area, it’s been fairly competitive and so we didn’t want to give up any competitive advantage by talking about it too soon. But we’re really pleased. We put together almost 20,000 acre block up here in this area, very excited about it, like the rocks David Nicklin will take you through it a little bit more. But we think that it offers multiple targets in addition to a very interesting Wolfcamp D or Cline equivalent play and David will take you a little more through that in his presentation.
So this is our acreage position currently in the Permian and we will be continuing to add to it in each of these areas. I might mention that we also have acquired about 1,600 gross and about 1,300 net acres in Howard County over on the Midland side or the Eastern side of the Permian Basin. And we’re probably look to add some to our acreage on the Midland side as well. But our focus has continued to be here in the western portion of the Permian Basin.
Again, we’ve got an estimated 233 gross and about 172 net locations that we’ve currently identified. Again this is really primarily in Ranger, Querecho, Indian Draw, and Wolf. We haven’t yet assigned any locations up in Twin Lakes as we begin to work this prospect. All our locations are assigned at 160 acre spacing.
So I think we’ve been very conservative, and I feel like that this is only just going to grow and grow as we begin to get more familiar with our acreage position. As you know, we drilled three wells in 2013, two up in Ranger, one down in here Wolf, and Ryan is going to share with you little more the results of that here in his presentation following me.
As far as the drilling plan for 2014 in the Permian Basin; again we’re going to drill about 12 gross, 10 net wells. We have drilled -- this is where they’re going to be. We’ve got six wells targeted for the Ranger and Querecho planes area, three wells at Indian Draw and Rustler Breaks, two wells down at Wolf and then one initial well up in the Twin Lakes area where we’ll be drilling a pilot hole, taking detailed core and logs to learn more about that area.
We are going to be testing targets from the first, second, third Bone Spring, the Wolfcamp, both Wolfcamp A and D targets. Primarily, we’ll be testing the Wolfcamp A down here, testing several of the targets here in Ranger and then over here working primarily with the Wolfcamp B and then second Bones Spring.
Finally, I just want to mention very briefly about the Haynesville plan. Again only it’s about 3% of the budget. We’ve been participating in some non-operated wells there again. As Matt said, this is area where our acreage is pretty much entirely held by production. So we have the operational flexibility to drill wells when and if we want to. We have no plans to drill any operated wells in Haynesville at the present time.
I did want to mention that we’re pending the completion of a new gas gathering agreement, which we hope will close by the end of the month here and that’s on a portion of our Haynesville gas, which will help to reduce the cost and improve our pricing in the Haynesville for 2014.
Really the main takeaway again is that Haynesville and Cotton Valley continue to present a large gas bank that provides a lot of value to Matador and its shareholders as natural gas prices improve. We think it has competitive well economics above 450 and in the real core area where a lot of our acreage is, that could be breaks of return of 40% to 100%.
This is again a map you’ve seen before, but it just shows our acreage position. Again the area shaded in pink tier is what we considered the Tier 1 where wells are going to be 6 Bcf to 10 Bcf or more. The bigger red spot of course that you see here, surrounded by the oval in the middle of the map is our core Embryo property where we dealt with Chesapeake several years ago and sold down some of our interest, still retain a 25% participation interest in all wells drilled in this area, and this area here is really I think ground zero for the Haynesville. This is where some of the best wells in the play have been and are going to continue to be drilled and certainly they’re going to be in the 9 to 12 Bcf kind of range.
You can see there is a few sections that are highlighted in and around where we have little Matador logo and they’ll show you sections where we are the operator, we have picked up addition acreage in Haynesville in 2013 and some of those have been in sections where we would be able to operate going forward. So we feel like we’ve added to our ability to operate in the Haynesville as a result of those acquisitions in 2013.
And with that, I just want to summarize what I’ve told about and present our guidance for 2014. Again, in summary we’re going to be running a three-rig program throughout 2014, two rigs in Permian, two rigs in the Eagle Ford, and one rig in the Permian. The Eagle Ford is going to be continue to be the major driver and the Permian is to set us up for an expanded program in 2015 and beyond.
The guidance on capital spending, just to summarize $440 million, up about 90%, total oil production 2.8 million to 3.1 million barrels, up about 44%, the gas production 13.5 to 15 Bcf, up about 14%, oil and natural gas revenues $325 million to $355 million, up about 31% and adjusted EBITDA $235 million to $265 million, up about 35%. We are very pleased with this plan and we’re very pleased with the growth that it’s going to help Matador to achieve, and we’re actually looking forward to getting started on it.
So with that I will wrap up my presentation and I will introduce Ryan London, who is going to take you through the Eagle Ford work that we’ve have been doing and our operations there. Ryan is our Vice President and General Manager, head the asset teams here at Matador; and I think as you’ll see just one of the best young engineers that you’re going to have the pleasure to listen to. So, Ryan?
Thank you, David. So as David said, my name is Ryan London. I’m Vice President and General Manager. I want to take a few minutes and introduce the rest the Vice Presidents real quick. Firstly we have Craig Adams who is seated. Craig is Executive Vice President of Land & Legal. Craig is resident marathon runner. He recently ran the New York Marathon and he ran 26 miles. Divide that by the nine Vice Presidents and we all get about 3 miles of exercise. So, we rely on him for all the exercise we get.
Van Singleton right here is our Vice President of Land. Van is one of those deal guys that can go out for a cup of coffee in the afternoon and come back with two deals. So Van is the one that gets all of the acreage in the Permian. He continues to filter in acreage in the Eagle Ford.
Gregg Krug seated. Gregg came to us about the time of the IPO. He was really instrumental in getting us the prices we get now. Gregg was running buddies with Matt when they were little kids. So, they have a long history together. They always tell inside jokes that I’m not part of.
Billy, once again known Matt since college. They went to college together. He is a former marine. So you don’t mess with him. And he’s drilled wells all over the world, domestic, international, onshore, offshore and if there is a well out there that can drilled, Billy can do it. He has really made a big difference, as I’ll show you in a minute on our drilling in the Eagle Ford and what we expect to do in the Permian basin.
With that I’ll jump over to the Eagle Ford. I’m the leader of the South Texas technical team. And if everyone can stand in here that’s on the part of the South Texas team for Matador, I’d appreciate it. That’s great. And these guys have done a phenomenal job this year. And this by the way, this is not the entire South Texas technical team. We’re not that lean. We have some guys up. So we have two rigs running full time, so we have to have somebody watching things. But, they have done a phenomenal job this year. So, it’s been an amazing year for us and it’s not just, you guys can sit back down.
They’ve done a phenomenal job and I’m going to show lot of slides today on drilling completions and we’ve been drilling wells or better wells, faster wells and cheaper wells than we were in 2010 and what you’re going to see is just constant improvement. As we move through the years from 2010 to the 2013, you’re going to see just consistent improvement. It’s not big jumps and big gains, it’s just every single day we get little bit better. It’s individually, it’s as a team and it’s through advanced technology, and we’ve really made a big difference. But it’s not just drilling either it’s the geologist, our operations geologist who are drilling wells straighter with more precision, the marketing guys like Gregg, he’s getting us better price realizations. The land guy is Van. He’s filtering in land all the time by artificial lift. It’s everywhere across the board, the entire technical team has really a big difference in our Eagle Ford asset.
So, before I move on, I just want to kind of highlight I think David Lancaster, our EVP highlighted most of this stuff well but we are going to have two rigs running in the Eagle Ford full time next year, one predominantly in the west, one predominantly in the east. We’re going to spend around $318 million and this is going to be for drilling and completing wells, facilities, seismic and some more land.
We’ll drill 50 wells, we’ll complete 45 and we’ll turn 40 of those to sale, but we’re going to have the annual guidance that David gave mostly coming for the Eagle Ford, although we have approximately 5% to 10% of our annual production capacity shut in. And we have an inventory, a healthy inventory of 270 gross, 222 net locations.
So with that I’ll jump right into the map. I think you all are familiar with this. David showed this few minutes ago. How we look at the Eagle Ford, our Eagle Ford position? We had it broke up into three main areas, our Eagle Ford west, our central, and our east. And what separates these is really depth and the depth is it impacts the pressure and the heat. The western acreage, shallower 8,500 to 9,500 feet through vertical depth. So we have little bit lower well cost here. $6 million to $7 million we’re down to right now. Actually, here at the end of 2013, we’ve been little closer to 6 than to 7. We’re getting a little better.
These wells have 300 and 500 MBOE. As you march to the central, we get a little bit expensive, $7 million to $8 million. That’s really a function of the depth. We’re a little bit harder there, we’re deeper higher pressure and that’s really manifested and the higher pump pressures and a little bit longer time to drill the wells. As we march over to our eastern acreage, we get a lot deeper, 13,000 feet through vertical depth. These wells require sometimes a third string of casing and the pressure and the heat requires us to pump propane and you see that the well costs are $8 million to $10 million, but these wells are also 600 to 1000 MBOE. This is the territory where you see a lot of the really high rate wells come online. This is a fantastic well. Interestingly, the wells in our eastern acreage central and western acreage are all very comparable in rate of return, just by virtue of the balance between the cost and productivity of the wells.
This chart really shows, if you just squint your eyes, you look at the bar graphs, the bar graphs tell the story. The ones on the left are high bars and the ones on the far right are low bars. It’s just constant improvement; everywhere we are, we’ve cut drilling times, we’ve cut frac costs and that really sums up to lower well costs. We think that the cost cutting is not done now. We think we can save an additional 10% next year and this lower left hand down here, this little table is an indication of what we think we can do on the drilling side.
By moving from pad drilling into batch drilling, we think we can save approximately $300,000 per well on a long term basis. Interestingly, when we brought our walking rig into the South Texas in September of this year, we drilled our first four well batch pad and on the first out of the box we saved over $325,000 per well and shaved days off the well.
Another interesting note, our surface casing hole. Our surface hole on the first batch pad was the fastest surfacing casing we’d ever drilled as a company. We walked the rig over to the second surface hole. That became the fastest surface hole we’d ever drilled as company. So walked that rig to the third hole. That became the fastest surface hole. And then we walked it to the last one and that became the fastest surface hole we'd ever drilled as a company.
So that's an indication that we're getting better and I think that we can probably even do better. I mean I think we, sometimes we talk in conservative terms in what we think we can do and who knows, we may be able to even do better than this. And I certainly think that it's not isolated to the drilling side, I think the completion guys, the completion guys we have working for us, they're thinking of new ways to cut costs on the completions too, and I'll talk more about the fracs here in a minute.
So, I've introduced the concept of batch drilling and I know everyone's probably heard the term batch drilling and everyone's familiar with what pad drilling is, and pad drilling we drill multiple wells on a single location, which obviates the cost of additional locations as we move from well-to-well, and that's been a big savings for us, but batch drilling is something fundamentally different and so I've put this cartoon together to illustrate the big difference. And so you see on a pad drilling, we're going to drill three wells on one pad, we have to pick up the drill pipe first, we have water based mud and we’re going to drill a surface hole through a fresh water bearing zone. We then convert to oil based mud and drill our lateral, that we then have to lay the rig, the pipe down.
We then skid the rig over to the next hole, we pick up the pipe once more and swap to water based mud and we drill our surface hole through the fresh water zone. After we're done with that we convert to oil based mud and drill the production hole. We once again lay the drill pipe down, we skid the rig and then we're going to convert back to water based mud. We then pick up the drill pipe and then we drill our surface hole through the fresh water bearing formation. We then drill our last production hole and then we lay the drill pipe down.
So you'll notice that the benefits of pad drilling is, we actually don't have to rig the rig down. We actually just skid the rig. We can't skid the rig with a pipe in the derrick. So we have to lay the pipe down each time. So we pick up the pipe, we lay the pipe down. Since we're drilling a fresh water zone with water based mud and then we go into an oil bearing formation, we have to swap mud systems. So you see that it's kind of efficient but it can be done better, and that's the concept of batch drilling.
So batch drilling’s fundamentally different. We're going to approach this in a different way. We start off the same way, we pick up the drill pipe, we have water based mud and then we're going to drill our surface hole through the water bearing formation, we're going to walk the rig over, stay with water based mud and drill the next two and three surface holes. We then covert to oil based mud and we drill our horizontal. We walk the rig over, drill our next horizontal, and we walk the rig over and drill our last horizontal. We then lay down the drill pipe a single time. So you see that we’ve actually become much, much more efficient with the batch drilling. We've only picked up the drill pipe once and we’ve laid down the drill pipe once. We've only converted from water based mud to oil based mud a single time.
All of those things cost money and they take time. And so what we’ve become is much more efficient with the batch drilling. And see this is the cause of the $300,000 we're going to save on a per well basis. We can do this because we have better rigs. We have walking rigs. They enable us to do the batch drilling. Well they enable us to do the batch drilling, but we also have to have guys like Billy Goodwin, who's our Vice President of Drilling. He's coupled his expertise with the advancement in technology of these rigs and we’ve become much, much faster, and like I showed on the slide, a couple of slides ago, we’re faster than we were in 2010, and we think we can get even faster than that.
And so this is a little table that shows where we started in the Eagle Ford back in 2010. It was a mechanical rig and as we've moved through the years we’ve picked -- we've let go of the old rigs and picked up the more advanced technology rigs. Where we are now is rig 203, rig 250 and rig 239. These are the most cutting technology rigs on the market, and in March of 2014 we’re going to let 203 go, which is out in West Texas currently and we’re going to move 250 out to West Texas and we’re going to pick up rig 279 and will have two walking batch capable rigs running in the Eagle Ford fulltime.
And I’d like to, I'm not going to pretend to eloquently describe the different facets of what these rigs have. So I'd like to ask Billy to stand and just give a few words on what these rigs can do. He can say it much better than I can.
All right. Let me first say we have a couple of senior drilling engineers here; Darren Bird, John [indiscernible], please stand up when I introduce these guys, these are the guys who make it happen; young energetic guys that go 24hrs a day, and seven days a week to get it done.
I’d also like, like Ryan was saying, as you move from left to right across this slide, you see us moving from the old mechanical type rig that we could find. We started out in the Eagle Ford, no top drive on this rig. It was the old style type rig you see in the movies you know, is loud, noisy, and I mean we have really good control on that rig high and low. So we have moved from there and all the way across to the other side and that's what you're seeing with electric, moving from mechanical to electric SCR, and now the AC drive rigs. You have a lot better control, as you all know the directional tools, are running in the hole we got to take care of them, they'll take care of us.
You need a concise control of over your weight, your reaming speed and you get rid of driller hair with the new rigs the joystick controlled touchpad, you can put it exactly where you want, you get it back and that's enabled us to really make a good hole and giving us good results. Those other equivalent that you see there that come with these newer technology rigs, we don’t have to wait for the equipment to get out there and spending the time rigging the equipment up and down.
And just move forward, a step forward in automation, and moving just to the cutting-edge technology, we move to the walking rigs and Ryan gave you example of how well we have done; the first four-well pad. I’m not saying we are looking to get to that $300,000 savings on wells. But we never expected on the first pad drilling -- batch drilling opportunity we had that we’d see that ran off the bat, probably a new rig, new consultants, new equipment and right off of that, we were successful. It is really exciting to us because we know we are only getting to get better from there.
Thanks Billy. Yes, the new rigs are pretty neat. They actually look one like a spaceship when you are inside the doghouse, than what you would think a rig looks like. But that’s a little flavor of what the rigs are like and we are going to have two batch capable walking rigs running fulltime in the Eagle Ford starting March. We have one currently.
So with that, I think that’s the reason for this slide. This slide, what it shows is improvement in the efficiency that we have had with the rigs. And it is because of the rig technology and guys like Billy, Aaron and Josh. So if you look at what we drilled in 2010; we drilled about around 250,000 feet horizontally in the year. It was right around three wells, that was in exploration phase. We drilled those well vertically first, then went horizontal. We drilled them vertically to collect core, rotary sidewall cores and then a full suite of all the more sophisticated logs. So that was kind of an exploration year.
As we moved into 2011 we drilled with two thirds of rig or eight months of the drilling rig and that year we drilled around 50,000 lateral feet. In 2012, the year we went public, you can see we’re starting to transition from an exploration base into a development base. We drilled with two fulltime rigs in the Eagle Ford and drilled close to a 150,000 lateral feet. This year we drilled with 1.5 rigs. If you remember, we had two fulltime rigs running in the Eagle Ford. We took one of the rigs for a portion of the year out of West Texas. When our new rig came -- our walking rig came in September, we resumed two fulltime rigs in the Eagle Ford. But at the end of this year we’ll have effectively drilled 1.5 rigs.
We drilled obviously same amount of lateral feet this year with 1.5 rigs as we did in 2012 with two fulltime rigs, an impressive feet. And we project that in 2014 we’re going to drill close to a quarter million feet horizontally throughout the year. We are going to do that with two fulltime rigs and we are going to do it because we have batch drilling. You see that this year we are going to be drilling almost all of our wells of batch drilling, a couple of wells before our next walking rig comes, in March, we will drill with pad style and we drill a couple of single wells early in the year, one of these being the Buda test. It’s going to be a single well.
You see the transition between what we did in the exploration phase. We were drilling all single well pads and we’ve moved to batch style and pad style drilling. This has been instrumental and our ability to drill these many lateral feet with such few rigs. What that translates into is between 2012 and 2014, our rig efficiency has increased by 60% to 70% in terms of lateral feet drilled per year. It’s an impressive feat.
So that is how we are doing and this is going to be in effect for 2014. This is a snapshot of our drilling schedule in our Eagle Ford West area. And you can see though the arrangement we have at the wells is a batch style arrangement in the West. These blue bars, these small ones, these are the surface holes that I showed we’re going to drill -- like in the cartoon -- we’re going to drill the surface holes successively. Then we are going to swap over and then we’re going to drill our three production holes. After the rig moves off, we’re going to frac these wells. We are going to frac them in succession, all simultaneously. Afterwards on fracing, the green bar here illustrates, when we intend to turn these wells to sales. The black bar is when this well becomes shut-in for an offset frac.
This level of sophistication in our drilling schedule is what allows us to have the precision we do in our forecast. And what we have done is we forecasted from here throughout the end of our drilling schedule in years to come, exactly when we are going to shut in all these well, exactly when we are going to drill and frac all these wells. That enables us to really have a good grasp of what we are going to do from the production standpoint.
And so for a little more color on the shut-ins, you can see that this cluster of wells that are shut in here, they’re being shut-in for these three fracs. So when we are fracing these three wells, these three wells get shut-in. Those shut-in volumes are actually subtracted right out of our forecast of the year, and that’s where we get our guidance from.
So this is the batch drilling, and David Lancaster, our COO, CFO and EVP mentioned this earlier, about the lumpy production that we experienced. And we talked about this a lot for this year, that we were going to have lumpy production. This is really an illustration why. You see that these three wells, when we bring them to sales in mid-April, we don’t have another set of wells coming on until June. And so there is a month and a half to two months of drought of production and it’s because of the batch drilling, also these shut-ins. Those affect our volumes. So it creates a big waviness in our production forecast of year. That’s one consequence of doing it, but we’ve experienced so many benefits, the reduction cost in the better wells, that it certainly makes sense to do it this way.
Our East, there is another snapshot in the East, and you see real quickly that until the new rig comes here in March, we are going to be drilling pad style drilling and one single well drill. So once March comes around, we have the rig 279 come in, which is the batch style walking rig. We are going to then convert over to batch drilling for the duration of the year starting in March in our Eastern acreage.
So let’s change the list and talk about artificial lift for a minute. The artificial lift has been a really big success in 2013 and I don’t see Bill in here but Bill and Mike Ernest, they’ve been the ones that have really put all this together, worked really hard on making progress out here. What this shows is a typical production -- this is a fake well. I just used a sample data. This is what a well would look like in the Eagle Ford, if it came online. It would start off really high and as it produced, it would deplete and as it gets to around 100 barrels a day you see here, the production starts to wobble little bit. That’s simply because the well has a difficult time removing the fluid out of the well. There is still a lot of power and a lot of pressure in the well at the bottom of the hole. But it has got a full column, 10,000 feet of fluid sitting on top of it, which suppresses some of the oil.
So what we have to do is install artificial lift and this is throughout the Eagle Ford, everyone is installing artificial lifts; predominantly two different methods, rod pumps and gas lift. If you were to install a rod pump down here at 100 barrels a day, this is about what we’d look like. The only issue with the rod pumps is that a rod pump -- let’s say you have an oil well making a 100 barrels of oil per day, which probably has 100 barrels of water a day associated with that. So effectively it’s producing 200 barrels of fluid per day. So if you put a pump on it, a pumping unit can only pump so much. That pump can only go up and down so fast and that’s right around 200 barrels of fluid per day, which makes a 100 barrels of oil a day about the right number.
If you put a rod pump on this well any sooner, your production would drop down to 100 barrels a day and you’d get the same line. So what we’ve started doing is installing artificial lift or gas lift immediately after we frac our wells. We run tubing. It has the gas let valves in it, already installed and then when it comes time to around 300 barrels per day we start injecting gas into the well, effectively turning on the gas lift mechanism at 300 barrels per day. And what that does is it just shallows up the decline curve.
Now if you were to fast forward 40 or 50 years, you would, a well that’s on rod pump is going to use the same amount of oil as it will that’s on gas lift. So you don’t get any increase in production EUR, but what you do as you take some of that oil that you’re going to produce in year 30, 40 and 50 and you accelerate it up to right here. And so we’re taking some of that oil, we’re going to have long term, we’re moving it forward to where it has more value for us. And so that’s one of the benefits of gas lift. It really accelerates the production.
The other big benefit of the gas lift is it reduces LOE. Rod pumps are very expensive, they’re very mechanical, they have rod parts they have a lot of issues that cost a lot of money. Gas lift is very set it and forget it. And once you install it, it’s all automated. It runs off a series of automatically opening-closing valves, it’s much better. And so since it’s so much simpler, it reduces the maintenance. You don’t have to have a lot of intervention like you will with a rod pump.
And the other thing that’s been really beneficial that we didn’t even expect is that by installing gas lifts we can actually help recover our wells after they’ve been fracked into. So say we have a producing well and your neighbor drills a well right next to you and they frac their well and some of that fluid comes in and floods your producing well; well, the rod pumps have a real difficult time getting all that fluid off and it takes a lot longer for them to do it. When we install the gas lift, the gas comes in, gets that fluid off the well and the wells that are on gas lift return to their original production profile much better and faster than you would of the rod pump. So it’s been a really big benefit to our production for the year.
So now let’s talk a little bit about the completions. So the completions are something that’s very important to me. I’ve been responsible for the completions at Matador for last six or seven years. And it’s a been very important concept for the company. I think as David Lancaster mentioned, he and Brad Robinson worked for Dr. Steve Holditch before they came to Matador and Dr. Holditch who is the former Head of the Department of Petroleum Engineering at Texas A&M. He is about to be honored as one of the frac legends by the Society for Petroleum Engineers. Before he was working at A&M, he sold his company to Schlumberger. This is a frac -- he is the frac guy. So we have a very strong culture of very technical nature professionals when it comes to fracing and completions at Matador.
And so we take it very seriously. We don’t call Halliburton or Schlumberger and ask them to design our fracs for us. We don’t look over the fence to see how the people are fracing them. That influences how we do things but we’re very proactive. It all starts when we collected the core in 2010. We take that core and we pull the rock mechanics out of it, we understand the permeability, just the different mode of fracturing that takes place with this specific rock. And we input that into our models.
What our models told us in generation two was that as we pump more and more fluid there is such a little leak off at such a low permeability in this rock that every barrel we pump, every additional barrel we pump we get that much more volume of fracture. So you get the extent of these fractures as a function of how much fluid you pump. Well, you can open up these fractures but those fractures don’t do you any good until you prop them. So with an incremental increase in fluid we also have a proportional increase in propane. And so that’s what you see from generation two to generation five, constantly escalating the amount of fluid and constantly increasing the amount of profit.
The other impact we can have on the fracture stimulation treatment is by the proliferation schematic. So we can change the geometry of the fractures by altering this proliferation schematic. Hence you see early on in generation two, we put six clusters spaced 50 feet of apart in a 300 foot section of our lateral. And as we’ve illustrated here, we feel like we were leaving some hydrocarbons behind. The permeability is not such that we can drain from this point to this point. And this is mostly in our western acreage, where the permeability is a little bit lower, we don’t quite have the bottom hole pressure and we don’t have gas in the reservoir.
In our eastern acreage we have much higher perm, or higher pressure in gas. So the transmisability is much greater. So we can drain greater distances with the fractures in the east. So this shows it. We don’t just take the same frac and apply it to all of our acreage. It’s very tailored for the rock in a given location. So in the east we’re going to have wider spacing, in the west we’re going to have tighter spacing.
As you move to the generation five design, which was the production I’ll show you here in a minutes, our most recent design; we show that we have increased amount of fractures up to nine clusters per stage, roughly 35 foot spacing. And we’ve gotten much, much better with all of our production as we’ve stepped from generation two through generation five, it’s been really impressive.
Generation six, so this is the one that was born in my office about a month ago. I grabbed Aaron, I grabbed Kelly, Adam, Tom. We all sat in my office, we looked at the data as we do pretty frequently. We take a lot of look back time, as we do pretty frequently. We take a lot of look back time. We looked at what we’re trying to do. We felt like, we’re creating a good enough fracture network; we’ve got enough of that but we need more conductivity. And we can get conductivity in several ways. We elected to go with even more propane. So the generation six design is going to have 11,750 barrels or 40 barrels per foot, and it’s going to have roughly 2000 pounds per foot of propane.
The other thing that you’ll notice is the fracture pattern here. As I mentioned earlier, we can change the geometry of these fractures by alternating our proliferation schematic. And what this is, is we’ve taken the generation five design with nine clusters and amplified that to where we’re at 12 clusters per stage now. If you take the same amount of fluid and you divide it up into more fractures, you can shorten you fracture half lengths. So you see here our fracture half lengths have shortened and we’re getting a much more efficient pattern near wellbore. You can really see the tightness and the complexity of the fracture network in the near wellbore. And of course this is just an illustration but the concept remains the same. We want a better, more efficient frac near wellbore that doesn’t go out and affect its neighbor.
One more thing I’ll say about the fracs, now I’m talking about fracs a lot because I’m biased. But we’ve also, and beyond just becoming better fracres and be getting better wells, we’ve kept the cost the same between cost per foot, between generation two to generation five. There is a lot of reasons for that. One of the reasons is just our attention to detail. Adam is here, Kelly is here. These guys are the guys that got on the fracs, and they’ll out there on every frac. We send a guy down just like I did when I was fracking all the wells, we’re there. We go there, we make sure the fluid rheology is appropriate. We check the pH, we checked the crosslink time, we do all these things.
But it also can have an impact on efficiency. For example, this is a couple of years ago when I was on fracs. I had a tally book and I was keeping track of times as we went through each cycle. We’re wasting six minutes here, we’re wasting eight minutes here, two minutes here. And doesn’t sound like a lot but when you multiply that by, it happens 15 times, you can pretty quickly get to three hours of wasted time and what we did is we noticed people who were not in their position ready to go when it was it was appropriate, when it was time. So we starting sounding a horn 10 minutes before the frac ended. This alerted everyone, got them ready, got their harnesses on in place in the man basket, and lo and behold, we saved seven minutes and this sounds like a lot of work for seven minutes, but that happens 10 times and we ended up fracing more stages in a given day.
When you frac more in a day, the service companies want to work for you. They get paid by the frac not by the day. So if they can pump five fracs with you in a day and four with somebody else, they want to work for you. And that's why I think we've gotten a lot of the attention that we have with some of the guys, the service providers we have specifically Schlumberger. We have a provision in our contract that guarantees us the same pricing in West Texas that we have in South Texas.
In the West Texas, it is a much high price environment currently. So I think those types of things the relationships we have with the service providers are a reason why we get the prices we get and why we've been able to drive the cost down while we've made wells better. This slide shows I think this proves that the fracs are better and what we have here is four different examples these are cumulative production versus time slots. The time is 360 days with the first year production. The Y-axis here is 125,000 barrels. These are all zero times slots so we've taken all the wells pulling back the time zero so we can really compare them with one another.
They're normalized to 5000 feet, so all of the oil is divided by it's lateral length and multiplied by 5000. So the only thing is different within these groupings is the frac generation. So we've coated them appropriate colors. The green colors, they're all generation two design. The blue colors, generation three. Yellow, generation four and the reds are generation five designs. So if you look in the upper left-hand corner here in the example in the Eagle Ford West, you really see that how closely clustered these wells are, these are three wells right here. The only thing different about these was there a pump generation two designs just shows you the impact that the frac can have, that's really what's driving the production out here.
If you look at the next four wells, these are generation four designs and look at the incremental increase we've got by just going into the generation four design then you look at the two reds curves are most recently generation five design. And I think that team is consistent throughout all of these. You see that as we move from generation-to-generation of frac design, we've consistently gotten better wells. In the upper right-hand corner, a dramatic increase, this red well here has produced around 60,000 barrels in its first 140 days, I believe, that's more than a generation two designed in its first year. It's a dramatic increase and so that's why we're consistently trying to modify it and evolve the design.
If you look in the Eagle Ford West down here on the lower left-hand corner, it's an example from our western acreage, same phenomenon. Green is good, blue is better, yellow is a lot better. And if you go to the bottom right hand corner same thing green; blue, blue is much better. And you look at this red one, this one is a little bit different because this red well is a 40-acre space well. This 40-acre space well with a generation five design is far out performing, it's green and blue [indiscernible] so and I'll talk a little bit more about 40 acres spacing on the next slide, but that's a really good indication that our 40-acre spacing's working really well.
So as promised here's our down-spacing program, so what we did early on in the Eagle Ford is we developed a proper inventory of engineered drilling locations. We took maps just like this for all of our leases. We identified a surface hole location, a bottom hole location. I took the names off but we actually gave here everything a well named and we put it into a spreadsheet. We had developed scoping cost for it. We have equal well projections for all these wells. We have a very good grasp on what all of our inventories are going do. And we obviously developed everything on 80 acre spacing, this was several years back. So we came in and we drilled our first well. After we drilled the first well about eight months later, we came in we drilled 240 acre test wells.
We were so pleased with the results from these 40 acres test wells that we went in on this list and changed all of our locations to 40 acre locations. So, we've taken all of our wells and put a well between and we did it here, we did it for most of our west and central acreage and the east is still a little bit, we're not sure about yet because like I mentioned earlier on the frac slide we have higher permeability, better transmissibility and better pressure out in the east. So, it may not be 40 acres it maybe 60 acres that's still to be determined. But in our west and central we feel very strongly the 40 acres is the appropriate spacing.
So, as promised, here's the production graphs on our 40 acre spacing, these are the same graphs, these are the cumulative production versus time diagnostic plot we use to forecast how well our wells are doing. It's too early for a new projection, as you can see we only have the most production day we have less than 200 days. But what we can do is a relative comparison between the 40 acre wells with the 80 acres wells with the frac mixed into.
So, in the upper left hand corner, this is the example I showed in the lower right hand corner two slides ago. This is in our central acreage, it's of course zoomed in and this is actually two wells. There is two 40 acres spaced generation five wells right here just sitting right on top of each other just pumping along, not pumping along, just flowing along.
But you can see that how much outperforming they are over the blue and the green curves, the generation two and three designs. If we look over in our central acreage, we've got another example, these two are 40 acre wells are generation five, are exceeding the generation two and on a launch path to hit the generation four.
You look in the lower right hand corner, you see the same phenomena which is in the middle of the fair way, we feel like we're just, we have great wells, so 40 acre spacing and so we're really excited about 40 acre spacing, it's the right way to go, we're going to make more money, we can make more well, we're going to make more money too drilling 40 acre wells that we would be if we drilled 80 acre wells. So, that's why we converted our inventory over the 40 acre spacing.
The example down here in the bottom left hand corner is a unique example, this is in our Northwest [indiscernible] County where there is very little pressure and we drilled, this is actually the example I showed in the prior slide. Our first well we drilled out here came on around 300 barrels a day with 1,000 pounds flowing pressure.
So, it doesn't sound like a very strong well but that well previous 300 barrels a day with the 1,000 pounds for the first eight months before it dropped lost any pressure or any rate and that's pretty well illustrated here, this is as flat as it can be, so this well has just rocked long for good eight months, we drilled these two 40 acre wells on the east side of the lease and they're tracking right along with the 40 acre wells. It's really positive indication that 40 acres is the right spacing out here. So, I say, we're really excited about 40 acre spacing and we're also really excited about the impact the generation six frac design is going to have on these wells. You noticed that all the 40 acre wells here of the dash lines, they're all red where we have all pump generation five designs on them. We feel that when we go to the generation six design we are going to improve upon that because it's the most appropriate for that type set that space well.
So, we're really excited about 40 acre spacing and that's all I have for my presentation, I'd like to hand it over to David Nicklin now, David Nicklin is Head of Exploration and he's former Chief Geologist of ARCO, been all around the world and I've learned a lot from David and I think everyone in here probably will today too.
Good morning everybody. I am going to move along here to first of all talk about our [indiscernible] in South Texas. The first thing to note here is that the bulk of the -- successful Buda activity is within this green bubble here which is the Pearsall oil field on the Pearsall Arch. And Matador has the [indiscernible] which is 9,000 acres of contiguous property all held by production were on the no immediate pressure to do anything with that right now but what we're doing is we're observing this activity in the south east corner of the Zavala County and you can see some of these rigs. Some of these rigs are very strong. Five months, 507 barrels a day that's a 30 day average, that's a cumulative production of 77,000 barrels and 78,000 million cubic feet of gas.
Similarly with the Contango 310 barrels a day, the cumulative production here is 9,000 in the first month, some very promising results, very close to the Glasscock Ranch. Now, the reason, I think this is exciting for us is we have recently acquired a 3D seismic survey out here over the Glasscock Ranch and we're still working on the preliminary, what's called the fast track data pack. And what we've identified in that already is a series of seismic artifacts which have a very strong parallel ventilation to fracture patterns that we know from the region. These are regional fracture patterns that are published but also when we drill our Glasscock #2H well we ran a start tool in that well to identify to count up an identify the number of fractures. And what we found is that the down hole fractures correspond very well with the seismic attributes.
Now the other thing that we've observed out here is there seems to be a relationship between the high productivity Austin Chalk wells and the high productivity Buda wells and there is a reason for that. It's because there is coincidence between the fracture networks in the upper Austin Chalk with the fracture networks in the Buda. They are both brittle rocks, they get bent over this Pearsall Arch, they both fracture in the same manner, so here is the high productivity area that people at Dan Hughes and Texas American are drilling and you can see the lateral wells here, this is just literally a few miles away from the Southeast corner. We happen to have in our area, as well as down here some of the very best upper Austin Chalk wells.
So what that does indicate to us is there's a very high likelihood particularly in view of some of the things we're seeing into the seismic of equally high production capability in the Southeast Vascog. Now the other exciting thing about this is, these are pretty healthy rates but these wells are not wells that we drill and frac in the same way we do in the Eagle Ford, these are much cheaper wells, so the rates of return on wells in the Buda with this kind of rates are well up in the 100% type of range, so very healthy return. So we're excited, we're watching this and we're going to drill our first test well next year and it will probably be in this Western half of the lease. Now I'm going to move on, I'm going to talk about the Permian exploration operations and give you an introduction to this. Joe has asked me to talk about how we got here, how we selected this and how the process that we followed has led us from the Haynesville to the Eagle Ford and then into the Permian. But before I do that I would just like to acknowledge the Permian technical team. Ryan said we've had a fantastic year, the Permian team have had a fantastic year, when you all stand the members of the Permian team.
As Ryan was saying not everybody is here and of course I'd like to include Vanna in this too, because Vanna's just done a fantastic job of getting us that 40,000 acres. What these guys have done, you can sit now gentlemen, thank you. What these guys have done this year, we drilled all of the things that we said we were going to drill. We've drilled a range of 12 data well, this is a vertical well that was intended to capture rotary side wall cores, whole core, full sets of logs and for us to study that and we are doing that, and that's ongoing and we have the added bonus of it is actually flowing oil from that well, but the big one is the range of 33, the second well, this was a horizontal well that was completed and is now flowing back and it's flowing very healthily, we're only in the early stages of flow back, we've only got a relatively small portion of the water back but we're already over 500 barrels a day and that's climbing, and I'll hand this over to Ryan a little later and he will go over that and explain that in more detail.
We've also drilled the Wolf well, the Wolf well down in the southern parts of the area, we had to resort to manage pressure, drilling techniques here because we have such a strong hydrocarbon flow while we were drilling, we were flaring, all the cuttings coming back have very strong indications of porosity and the well was very-very well drilled with a very narrow window or 100% in zone, so Ryan will talk a little bit about that as well. We should have the frac crews there to complete that well after Christmas. Then the rig has now moved to our fourth location in Russell Breaks so, so far, so good. All of the outcomes so far have been consistent with our expectations and we're very excited about the 2014 program that David laid out, it looks like very much an ex-growth leg, so with that I'm going to move to the Permian but I will just say one last thing. There is a lot of talk around our office, we talk a lot about how similar, how the feel of the early Permian program is to the early Eagle Ford program a couple of years ago, and some of the things that we've learnt in the Haynesville, some of the things, a lot of the things we've learnt in the Eagle Ford we're going to be bringing forward and applying them to the Permian wells, and so, with that I'm going to get started here.
So why the Permian, while there's a number of bullets on this slide, but what I want you to take away from this slide, what I think is important is, we like to go, we like to look for new oil where there's lots and lots of old oil, where there's a lot of knowledge, a lot of history, a lot of background, a lot of infrastructure and where there's lots and lots of oil and multiple stacked petroleum systems, that's my dream, that's what I go for, and that's what this slide is saying, it's also saying a couple of other things. One is, when we went out here to the Permian we did see a good amount of opportunity at that time, I feel like we were ahead of the curve, we were, when we came out here, it wasn't anywhere near as hot as it is today, and the other thing is that the old the Matador 1, was one of the top 15 producers in Southeast New Mexico, and because of that we have a team here that quite a number of the old members came forward, and we have that database, there's a lot of experience working in the Delaware, in the Permian basin, so that's been very-very helpful.
So that they were the drivers. I also wanted to say that we have consistently applied, a set of measuring criteria and we did that at a basin scale, when we're looking to go into a new area, but what's most important when you start really zeroing in, is this target, Pay-zone scale criteria. Now I've listed these, I'm not going to go through them. A lot of these are actually now, are fairly industry standard, but when we first started doing this back in the Eagle Ford days, we were using these and they weren't industry standard then. So we still consistently followed these, but they are under refinement at all times. And we have a saying around the office. We reserve the right to get smarter and we're always looking at these.
So let's move to the next, let me just go back. What this is really about is the fact that it is all about the rocks. That's what, as Matt was saying, that's where I think the answer is particularly with difficult reservoirs, with resource plays, with things that require unconventional, you don't have the luxury that you do with conventional plays. So you have to really understand the rocks.
So the first thing we did when we started looking at the Permian basin, was we went back to basics. And what this slide shows, I don't want to go into too much details, but what it shows is the environment of deposition at the time of during the Permian. And the reason this is important is because when we figure out how these rocks are structured, distributed; it enables us to predict better reservoir properties and that impacts where we pick our acreage.
So in this slide, what I demonstrated here is that this is a basin, this is a marine basin with lots of sediment coming into it. And there is a background sediment indicated in gray, that dominates all over the basin and this is fine organic rich mudstone and this is what the Wolfcamp A, B, and D are comprised of. There's also a bunch of organic matter in some of the bone spring sediments. But the bone spring sediments tends to be dominated more by the sandstones and the limestones and dolomites. If you can see the difference here between the two, the sands tend to be confined to these channels and distributory systems.
So if you are going to try and identify the best quality rock, you need to understand where these distributory systems are and how they develop. So the other thing also is there are also carbonates particularly around the flanks of the basin and the same thing there. The first bone springs, second and third bone spring carbonates all of which can be perspective reservoirs, they tend to occur in some deposits around the edges of the basin. So when you put all of this together and you start looking at specifically the stratigraphic column in the basin, what you will find is that the Wolfcamp section here tends to be dominated by this gray color. This gray rock are these are the shales, the mudstones. These are the organic rich rocks. These are the source rocks.
As you go up into the Bone spring you see more of these yellows and blues. These are the inter-bedded sands and limestones. But what you can see the green indicates the oil distribution. The oil is distributed right up and down this section and this was one of the things that draw our attention to this particular basin was the strength of the hydrocarbon shows throughout. So up at top here we have the low permeability sands and [indiscernible]. These are very-very good targets today with unconventional completion techniques.
And of course we have the source rocks. Now the source rocks are very important for another reason. Where the oil migrates to in this basin is a really important element and why you pick where you pick as well. So in this slide here, this is a map in the southwest lower corner of the slide. And it shows the Delaware basin and the Midland basin and the Central platform. The pinks are designed to illustrate where the source Kitchens are, and the greens are all the oil fields that exist around the flanks. And these are all the conventional oil fields that has been drilled and developed for the last 100 years or so.
But what's important here is to understand the source kitchens, and this is what's happening. Here is the Wolfcamp, and some of the older source rocks are down in here too, thins like the Barnett and Woodford and the Simpson. And you can see as the oil charges out of these source kitchens, it starts to migrate towards the flanks of the basin. And you can see these arrows are indicating where this oil is moving in the system. These arrows are not too far off a detailed analysis that we've done of this basin. These are exactly where these migration pathways are.
And so if I go to the next slide, this is a detailed look now at our leases, and you can see our leases relative to these hydrocarbon pores and you can see the basin flanking conventional field tier and along the eastern edge of the Delaware. This is the main part of the Delaware basin. This is the basin center kitchen and the oil is moving up towards the outer edges of the basin. It migrates up through a particularly deep trough that runs through here and charges these fields here. It runs around the north and it charges back towards the Twin Lakes area, over up in here, and it's still migrating up through something we call the [indiscernible] channel which runs right in through here and it's moving up and filling up all of these fields around the side.
These have been some of the things that have influenced why we picked where we picked. What we tried to do as a team here, is we've tried to identify places where the oil is moving through the rocks and the range of 12 well for an example was a test specifically to try to evaluate the rocks right in one of these migration pathways and that's what we're studying today and we'll continue to study for quite some time. The Wolf acreage down here was a migration out of the center of the basin towards the south. There is an awful lot of oil production down to the south of us and so the Wolf is on we believe on those migration pathways and similarly with that area over there. So in the [indiscernible] area.
So these are our primary targets in these areas we're going primarily for the Bone Spring Sands and the Wolfcamp A, B and D. These are the primary targets. And these are the areas that I've talked about. So we're going to now move to a phase -- we're going to start talking a little bit about the results of our drilling and I'm going to hand this back to Ryan to talk through some of the specific wells. But before we do that I'm going to talk about the Twin Lakes area since this is the first time you will have seen it. So the Twin Lakes areas in our opinion a very-very interesting area here is a closer look at it. And you can see where our leases are. These are a series of very large, very substantial fields. This is the Vacuum Field this one this particular pool in the San Andres and [indiscernible] is 690 million barrels and right next door to it you've gotten Maljamar Field which is almost 200 million barrels. But these numbers are actually a little deceiving they are actually bigger than that and you just come out because there are more zones.
And as you come down here into the some of the flanking fields over here you're getting well over 1 billion barrels in those fields. And then you have Lovington which is if you put the two lobes of Lovington together and you have over a 100 million barrels here you have about 50 million barrels up in these two fields and so it goes 43 million barrels up in here. Now these guys are all being charged by the Wolfcamp what we believe is the Wolfcamp the Wolfcamp D interval. So if I look at this cross section from A to A prime what this shows you is that the reformation. Here is the Wolfcamp D Cline and it's very fit on the west side and as you move through towards our acreage we still have about 400 feet of it here. And if you remember one of my first criteria remember the Eagle Ford is only about 100 feet thick.
So we have about 400 feet and these logs these logs we have done a lot of correlation work between this area and the Midland Basin and the Delaware Basin. The reason we think that's valid is because of the time of deposition before the growth of the Central Basin platform all of these were one single basin called the [indiscernible] basin. So it's reasonable to expect that if there are all from the same basin they should have very similar well characteristics and that is indeed what we see here. So we're very excited about what the potential is in this Wolfcamp D or Cline in this particular area of the Permian Basin. And as you can see on this, this is the last point there are a number of wells that have produced from the formation just underneath it series of wells, these are all vertical wells. So this 268 barrels a day these are nice numbers, nice numbers to have.
And there is also production tests higher up I don't have the numbers on this slide of what they produced but there is considerable production in the shallower as well, and that's very encouraging because I think it's coming from here. So with that I think I'll hand this back to Ryan and he will give you the results [indiscernible] us so far.
Thank you, David. So as David mentioned this is our Ranger area for West Texas. And as he mentioned first of all it’s a data collection well where we performed a series of injection tests and currently we're in the Avalon so testing out there we're actually producing oil from the well.
The Ranger 33 is where we went next, we drilled our first horizontal well out there in the Second Bone Springs and we've fracked it about two months ago now and on the next slide I'll show the production data from that well. Some of the other wells in the area are pretty phenomenal results one of the best wells in the county the Concho Stratojet well 360,000 barrels in its first two years. The Concho AirCobra well 300,000 barrels in its first two years so we are in a really good neighborhood.
How we fraced the well. We took a lot of what we've learned in the Eagle Ford and we applied that to our thinking but what we did is we took the cores in the Ranger 12 hole logs and we tuned our frac model. That enabled us to really understand the frac the motor fracture propagation out here which is fundamentally different than the Eagle Ford. You see that the rock is such that you're going to create much longer more plainer fracs out here in the Bone Spring than we do in the Wolfcamp where we get the complex fracture network.
The rock is still such that you're going to have a main dominant frac and you're going to have these plays that come off these fracs. So what we did is we designed this the perforations schematic to where we did five clusters per stage and around 50 feet between the frac clusters. This area is a little different from the Eagle Ford probably looking forward on generation two, three and four we'll probably expand the distance between the perforations. But I think on our first one we did a very good job of starting in the right place. We pumped a very big job we're going to pump bigger jobs in most of on the people in Permian out here. We've pumped 18 total stages all 450,000 pounds per stage with the first 400 white sands in the last 50,000 pounds was a resin-coated [propane] and so we pumped the big fluid design with the big [propane] that's going to who we are out here. We believe in bigger fracs we think we're going to make much better wells out here by doing so.
So the results and I think the results speak for themselves. You see the oil rig in green here it's on a constant escalating pattern. The last data point we show here up over 1650 barrels a day, we remained consistent in how we're going to flow these wells back. We learned in the Eagle Ford that the worst thing you want to do is open these wells up. We think that by choking the wells back we can actually make a better well and its just more about patients for us. And that's what we were showing here. We started the well on a 14 choke and we worked it up to a 20 and right now we're on a 23/64, choke.
This point right here in the middle is where we were elected to run tubing, so if you just take that out you can see the growing oil production and the other thing that's interesting is the pressure. So coming along with that oil rate and that choke size, we have a much higher pressure than a lot of the other wells in the neighborhood. At this point during the IP or the early flow period of some of the other wells, we have a higher pressure and just because we have a lower choke, but we think that's going to make a better well on the long run. So as we look forward in future for the next two, three, four months, we expect for this oil to continue to rise. We're hoping that the pressure stays in there and right now we have no indication that it won't. The pressures remain rock solid out here. So we can't be more excited about this well. When we brought it online, we first started to look at the data and we were thinking it would be good and I think it exceeded all of our expectations out here. So we're very excited about this area.
Next, we move the rig after the range of 33 down to the Wolf area and we drilled out Dorothy White #1H. We're landing this in the Wolfcamp A and then specifically into a real small high-porosity street in the Wolfcamp A sandwiched in between proper shale metrics. So above our and below us is Wolfcam shale and we landed our lateral right in this high-porosity zone and I'll show that to you in a second. We're in a really good neighborhood up here as well. I think the geologist did a pretty good job of putting us in the right areas because you can see this OXY Reagan-McElvain is first nine months over 100,000 barrels.
This Energen Black Mamba, 213,000 barrels in this first year. These are all Wolfcamp A producers and we have over 5000 acres here, so Van did a good job too. They got good land and good properties. So we're pretty excited about this area. And I think as David mentioned, we plan to frac this well after Christmas hopefully before the end of the year. This is what I was talking about our where we landed the well. And our geologist and Keith Svatek in particular did a fantastic job of just nailing this target. This is a 10-foot thick zone. And keep in mind this is 2 miles down in a earth. And he was able to nail that zone within 10 feet and stay in for the duration of the lateral.
And we did that and we were flaring the whole time and we had all sorts of flaring issues. We had managed pressure drilling techniques where we were drilling all the indications we were getting out of this well. The cuttings were coming back with the visible porosity. We are so excited about this well just because of the indications we got when we're drilling. And we know it's in a good area too. We were in the neighborhood of a bunch of good wells. The geology all looks like it should be a very good area. So we're really excited about this area and we landed right in the zone, have I mentioned that?
And we tick edthe rig after the Dorothy White moved out to our Indian Draw-Rustler Breaks Area, where we're currently drilling right now. This is going to be a Wolfcamp B zone and we're in a really good area here as well. You can see that there is a bunch of really good production in this area. Another thing about this area is it just looks fantastic on the logs. If you look at the section, the Wolfcamp B section out here, it's very reminiscent of the rock that we see in the very prolific Eagle Ford and Haynesville wells. It's a very pregnant shale look to it and typically where you find that look in a rock it has very good promise.
So we're excited about this area and again this area is, I didn't mention this on the other two slides, but most of ours zones are all have particular horizons on all the Bones Springs and Wolfcamp and this area is not different. So that's all we have for the Permian and I'll now hand it over Brad Robinson. Brad, as Matt mentioned, former Holditch & Associates guys, and I've heard a lot from this guy over the years, and he's our Vice President of Reservoir Engineering. Thank you.
I'll just add one thing to what Ryan said about these areas in the Delaware Basin that we're really excited about and that the Wolfcamp here is geopressured, so much like the eastern part of Eagle Ford acreage and the Haynesville, we look for areas as David pointed out where you have geopressure that helps the energy and helps get those liquids out of the [indiscernible]. As most of you all probably know natural gas prices have been up over the last week in fact about 10% I think they closed, Greg told me about $4.40 so that makes my talk a lot more fun today to talk a little bit about our Haynesville properties. I am really excited about that.
As David pointed out, we have considerable Haynesville position and the map here shows our acreage in the Tier 1 areas and we have about 64 net locations in the Haynesville, in the tier 1 area that we think has a potential for reserves that 8 to 10 bcf per well. We also have a considerable position in the Cotton Valley and as noted here the Cotton Valley we estimate to have about 6 bcf per well. So, when you add up the total number of net locations that we have in both the Haynesville and Cotton Valley, you really get about over 600 bcf of resource that we're excited to have the potential to develop if gas prices continue to hold up at around this $4 to $4.50 level. We have been able to add to our acreage position here, I want to ask Tom [indiscernible] to stand up, Tom is one of our young engineers that have joined us in this past year.
And Tom has taken over the Haynesville assets and is been managing them and he has been able to add to our acreage position and improve our area or ability to add additional development drilling opportunities, as was Mitch and Gregg, Kurg who's our Vice President of Marketing has been working on our gas contract in this area and has actually renegotiated the transportation cost and has enabled us to reduce our cost by about $0.60 to $0.90 per MMBtu and as a result that's going to substantially improve our economics on our wells in this area we believe the Haynesville has about 8 to 10 bcf of reserves the wells in this area generally run between $8 million and $9 million to drill and complete and showed on this graph the rate of return for wells with metrics of this type at about $4.50 we can see that the rate of return on the tier 1 Haynesville is around 70%. So it becomes very competitive for capital and makes it very attractive.
I'll speak just a few minutes about the Gracie project, we've had lot questions about the activity up here. This is our Southwest Wyoming and Idaho and Utah acreage that we've put together. We did drill last year, our Crawford Fed #1H well successful drilled a horizontal well and we just recently completed a 5-stage hydraulic fracture treatment on this well, we've been flowing the well back and recovering some of the load fluid, it's gotten real cold up there, as you all can imagine, up in Wyoming in the mountains and snowing. So, we've [indiscernible] the well and we're going to come back in the summer and continue our testing program and we'll be looking forward to reporting those results to you next year.
With that, I'll turn it back over to Joe for some closing remarks.
[Indiscernible] you can signal, we'll leave the phone line open for the question period and would like to just open the floor now for some questions.
Question on the gen 6 frac, when will you do that on your first wells and then also when you sit back and look at it do you expect that you are going to be very similar to gen 5 and if I can throw one more on that, does this have any implications to getting tighter spacing than the 40 acre spacing.
Unidentified Company Representative
Well, let me turn to Ryan to answer those three, but basically yes, I think to most of your questions here. But Ryan?
Let me see if I can answer these questions one by one. I think the first question was when do we intend to pump our first generation 6 design, we pumped in the most recent batch of four wells we drilled with the batch rig in one ranch through those wells, we experiment with the generation 6 design in and amongst the other two with generation 5 design. So, we have a good comparison tool there.
Moving forward, we're going be fracking again before the end of the year on another of batch well of that pad of three different wells that we're going to start with the generation six deigns. To see the next question…
We fully expected the generation 6 designs are going to outperform the generation 5 designs and we're not sure how much, we're never sure how much and we're very sure we will. In terms of the 40 acre wells, or tighter spacing of the 40 acre wells, I tell people that this time two years ago we bought 80 acres was the appropriate amount that 40 was unachievable, we thought that when we started off 160 spacing. So, it's impossible for us to know right now, we're going to need to much more production history from all the wells until we understand really where we can go from here and likewise over the Eagle Ford East, we're not really sure yet where the appropriate spacing is out there.
Unidentified Company Representative
All right, Bryan.
Hi it's [Bryan Browse with Howard Wheel]. Ryan this product for you is well, the inventory that you list in the Eagle Ford I think is about 220 net locations, what is that, is that based on 40 acre spacing, 60 acre spacing, how is that.
Yes, I mean what we said, throughout the year we already have some 40 acre locations in our inventory. The remaining potential 40 acre locations are predominantly out in the eastern portion of our acreage, we were unsure so we elected to put those into the inventory yet, but yes the 270, 220 net does contain some 40 acre locations.
And then on the leasing front, is there really much to be had, I mean on a realistic basis, what do you think you can expand over the next couple of years, you know in the Eagle Ford.
Unidentified Company Representative
Ryan, let Van take this question. You'll be surprised, my experience, that's how I came up into the land side, and you'll be surprised there's always some acreage out there for one reason or another, you're not going to find large tracts. You know 10,000 acres, but you'll be surprised how you add, that's what I think Van can tell you has happened the last few years, he just nibbled away, Van.
Unidentified Company Representative
That's actually the right job, you look for opportunities all the time and you're constantly building relationships with other companies and individuals so, when those opportunities come up you're the first one they call, that's served us well in the past few years and I don't see any reason why it won't continue to serve us well.
Unidentified Company Representative
Bryan, also in this case one thing is, Van's been successful on a number of trades, you know trade down with other, large companies that has helped us block up some acreage, so it's added locations even though you haven't added acreage, so, we continue to add locations and more than replace acreage for all these last three years.
Maybe the cost of the recent acreage.
Unidentified Company Representative
Well we don't want be to too specific.
Unidentified Company Representative
Now we can't for competity, but you'd be surprised how reasonable most of this acreage is. We haven't gone into, we'll say we haven't gone up there into having figures, is that above 10,000, there's still, it's still below, well below 10.
Unidentified Company Representative
All right, Irene, then I'll get to you Neil.
Okay the Rangers' 33 wells and my question for you is, there has been probably other producers a pretty good support so can you give me a little background as to how the other producers produce their well, what I'm really getting after is when would you reach your 30 day peak rate, is it going to be a month, two months, I mean what are the common practices in the region?
Unidentified Company Representative
That's a good question, the common practices in our specific area and expanding outward are people flow their wells back on a much larger choke, it often times, actually more than half the time open chokes. In the wells in and around our neighborhood, we've actually got a table that shows, all the wells within five miles will flow back on 38 chokes or higher and so we're certainly different in that regard, we're flowing our well back on a 22 up to 28 size choke, and there was a second part to your question.
When would you hit your 30 day peak rate?
Unidentified Company Representative
We're not sure, right now, it's just been going up and up and up, so we're excited. We hope we don't ever hit the peak rate and just keep going on.
Also, one more follow up, the second well you're going to go in and drill, what kind of modifications would you make now that you've got your first well done.
Unidentified Company Representative
In the, on our Dorothy White #1m our Dorothy White #1 is going to be fundamentally different, the second Bone Springs in our ranger 33, so it's going to have a much different mode of fracture propagation, it's going to be, once we get, once we frac out of that high porosity zone that 10 foot exin, we'll get into proper shale metrics, so we will have fracture propagation, reminiscent of Eagle Ford fracs, so we'll probably put a design on it, not probably, we will put a design on it that much more resembles our Eagle Ford south fracs. It's going to be big volumes of fluid, propane and tired enclosure spacing and that's going to again, that's going to differentiate us from all the other operators in the neighborhood and in the Permian Basin as you know.
Unidentified Company Representative
All right, Neil.
Joe or Ryan, either one. Just wondering, I was looking at like the twin lakes and looks like the primary target is the Wolfcamp D, just wondering you said, it's a newer prospect for you Joe, when you have prospects like this it looks like, you know you've got a lot of potential in the A, all the way down to the D, so as you attack a lot of these, you know, kind of what's the plan over the next year, how do you anticipate, I mean seems like you have just numerous, obviously formations to attack in addition to different amount of pilot plays here.
Unidentified Company Representative
Neil, again you ask a very good question and internally the way we approach a lot of it is without saying that one of the speakers referred to, we reserve the right to get smarter, we go down there of course with what we believe is a primary target, much like I think a coach entering the game with a game plan that you're going to run these plays. But afterwards as you start to run the plays and you see how they're set up the operating environment, you change, I mean you alter that plan so, really what's been very helpful about getting the cores and petrophysical work they do is once you know you think it's going to look like this, but once you get into it, it often behaves a little differently and you adjust the frac and you make the adjustments elsewhere. So that is our target. That seems to make more sense today based on what we know. But as we add to that geological and engineering knowledge we won't hesitate to change it to try to find a more robust zone in fact and then we do that in our follow-up wells. We may spin a little more time. You know in the range of 33 the Wolfcamp, we were down just test looks very interesting. We programmed it on the next well. But sometime it's going to be testing.
And just one follow-up, as far as hedging, I think, it was David or rather mentioning their [indiscernible] your guess and about how this uplift, you know what that means for EBITDA, at certain points have you really started hedging even at these prices.
At the NGLs?
NGLs and just in the dry gas.
We are. And if you will look on that hedging page you will have the numbers but we have always hedged oil gas and NGLs.
Unidentified Company Representative
I would just say that we have always tried to be very opportunistic in terms of our hedging and so when we get little bump in the price, I can tell you [indiscernible] working to add to that. I think that's the [indiscernible] you go in there and yes we do.
I thought the entrant in the Howard County specifically was interesting in the Midland basin. Can you talk about, does that need to grow to a certain scale, or you think about the Midland position in Howard County is within the Permian. And then what will that scale level be.
John, as we go into a basin we try to rank the areas and then build a position and so we want to be in the Delaware part of the basin first and we've built our position there. And we're going to continue to add to that. The Midland reflects a little bit what we've said about Van and then he will go out for coffee and come back with two deals. He happened to come back with his acreage in the Howard county and it was too good a price and too good of an area for us to just not to say, yes, that looks interesting and particularly when we felt like maybe we could add to that position later.
And one last thing, I always stress about shale prospect and shale oil and shale gas you don't need a huge volume of acreage just to see. It's much more important to be selective. And I will point to example the Haynesville map. You know we're in that little, we're concentrated in that area and we sell the Chesapeake just 7500 acres but it was over $200 million in value. So it didn't amount so much as where it's located. And we hope eventually to build our position across anywhere in the Permian where David and his team like the rocks, to build elsewhere, we don't want to limit ourselves just to this. But we want to do it in a methodical fashion where based on our rankings – and our rankings were first in these four areas that we've got and Lea and Eddy Counties and Loving County, that's what we write it first and we will continue to add to that as we go along.
And then just to clarify, of these wells, the first wells in the Permian, will they all be horizontal and will any be in Howard County?
We don't expect any in Howard County. All the wells in the Delaware part should be horizontal wells. There may be one more Data well in the Twin Lakes which would be a vertical, to go down and meet the core. So 11 horizontal, one vertical but it will be equipped if we later decide to take it horizontal. But initially only vertical Data well same way the range of 12 was. All right. It's it.
Almost getting to afternoon. So good afternoon guys. As expected solid technical presentation, but just a couple of quick questions, one each – one each of the basin.
Unidentified Company Representative
I couldn't hear it, what did you say?
I said congrats on your solid technical presentation.
Could you say that a little louder?
I will repeat it at the end again.
Okay. Thank you.
Well, let me just quickly shoot at Eagle Ford first. In one of your charts you show how your generation in fact compared across 40-acre and 80-acre. The 40-acres are coming in slightly below your 80-acre. So if you could care to talk about the level of interference you are seeing and your decision to go developing all of them on 40-acre. What's the decision behind it? You've talked about more hydrocarbons but I am just a little more color on that?
In taking that question, I am going to ask Ryan to comment on it, but I don't think it's right to say that there is the degradation in all instances where you drilled at 80s to 40s, because in some places the 40-acre has been doing better than the 80-acre. So you can't quite generalize but Ryan would you give a little more technical response.
I think when we look at the four examples we have of our down space wells we have some that exceed expectations and some of the ones that Joe mentioned and then we have some that are little less than the generation, the other generation fives. And I think you're going to have just some that look over of [indiscernible] 80 or that level of air in one of these wells. But what's consistent about all of them is they are really good wells. And so when we look at them individually without any relative comparison they do very fantastic the economic wells. So that is what plays into decision we can get more wells and they're very good wells they make a lot of return.
And I said earlier we're making the more we're also making more money with these wells 140 acre spacing than with the number of locations we have on 80 acre locations. So we don't have any of those numbers and EURs we'll be staying always in the past when giving out those -- that granularity of numbers. But what we can tell you is that the relative comparisons are also indicate they're good but we've done the due diligence that they are doing.
One other fact to keep in mind if said is that on these wells not only are they performing well on the EUR basis it some cases better than a fifth generation 80 acre well but the costs are less because again Billy and his group and on the fracs they've continued to improve on that and particularly with this walking rig they'll be even better than that. For example on the west you remember the earlier question the last wells we've drilled we're getting close to $6 million which is really adds to your rate of return. And I don't know exactly how much each 200,000 to 300,000 lowers or improves the rate of return but it's very-very significant.
And so if it even make seem we're close I mean all those wells are for the same well is making a much better rate of return because Billy in the [indiscernible] cost 30-40 in some cases half of what the first well on the leased in. Matt were you going to add to that I'm sorry you're standing out.
No that's it Joe I was just going to talk about the cost and I agree I mean the when actually drills on the well that are almost [indiscernible] so as you interfere your both sides of that thing I think we're going to get this generation six I agree we're going to get better wells out of that but we're also continue to drill cheaper.
Just a quick follow up on your booked prospected in Loving County now I know you're completing it. But given the core samples you gathered and as you've looked at wells at on some of them really impressive and recently and what's your outlook on that, what kind of early stage data gives you confidence about that particular area?
So what are the early indications that the Dorothy White is going to be a good well. So right now what we have going on is the offset production data which proves that's we're in a good neighborhood. We have all the log data everything looks fantastic on the logs everything checks all those boxes. And right now the only additional information we have is what we encountered when we're drilling the well. You can ask for much more of the flavor managed pressured drilling and core cuttings that [indiscernible] rocks are coming back with visible porosity in it.
So until we frac the well we're not going to know for sure anything. And as you know that's nothing different in any of these but right now everything we check all the boxes and everything looks fantastic. I don't know if that really answers your question but…
Unidentified Company Representative
Yes, Ryan but he's got some to…
Unidentified Company Representative
I was just going to add on the map that Ryan showed there was a well right in the middle of the lease the Wolf well is an old vertical well and made about 60,000 barrels of oil just out of it all vertical completions so what we're trying to do of course is go horizontal and do five, six, eight, 10 times that amount. So we're really excited about that interval of the Wolfcamp.
So just looking at it like this, as you got -- you know you've got oil in place, you've got analog productions, you've got pressure, you've got visible porosity you've got a flair. So what's there not to like?
Unidentified Company Representative
I think it stinks.
Any other questions. Yes, Ben back here and then we'll come to you Jeremy. And I'll get back.
Yes. Joe, maybe just curious if you guys could talk a little bit about you've clearly labeled kind of your primary targets out in the Permian. How should we think about each of those zones working do you guys [indiscernible] what are primary target because you think it's all for instance in Ranger that each of the Wolfcamps and the Second Bone Springs work across the entire Ranger area or should we think of the 75% of its perspective for each of those zones, how should we think of that?
David Lancaster or either David Nicklin or David Lancaster…
That whole area the Ranger area has multiple base there is we're mapping that in a greater detail we're watching a lot of that other companies that we're drilling wells out in those areas by continuing to refine our own mapping and along those lines as we did that we're tracking the production from all of those different horizons. At the moment I will tell you that the main producing horizon in that area appears to be the Second Bone Spring side but we're also very much like the Wolfcamp. The Wolfcamp in that area looks very exciting and there is also an Upper Bone Spring formation called the Avalon which is also very productive in that area. But when we drilled those wells particularly when drilled Ranger 12, one of things that we're very impressed with was the extent and height of the oil column all the way from the Delaware mountain formation from the upper part of the Bell canyon and Cherry canyon and Brushy canyon all way down through the Bone Spring and into the Wolfcamp. And in my opinion, it's still very early days in terms of ranking all of those opportunities. It's a very good problem to have to deal with.
Unidentified Company Representative
Thank you, David. [Indiscernible] all right coming up who is next, Jeremy.
Just thinking about well cost in the Eagle Ford for a second and you're talking about how it varies from east to west since you ticking with completions in drilling and all that, what is your current like D&C split and are you seeing that consistent across the acreage?
Unidentified Company Representative
So our currently split on the map we show is into west for about $6 million to $7 million for well. And keep in mind, these are normalized for a 5000 [indiscernible] so something around 8000 [indiscernible] multiple higher. In the central, it's about $7 million to $8 million. In the east, it's $8 million to $10 million. And really since we've had those numbers out there, we're pretending to land on low side of all those cost. I think Matt mentioned a moment ago, we've actually drilled a couple of those less than $6 million in the west.
Right when I was thinking about drilling versus completion rate, what percent?
Unidentified Company Representative
Okay, so, this is where Josh and Irene get to take credit here because this fleet has come down considerably on the drilling side. He's drilling wells in the west for $2 million or less and so we're the ones, Adam and Kelly, who are the ones spending a lot of the money now. So there is higher ratio now of the completion cost versus the drilling cost in that well, that number.
And also when moving to the walking drilling rates, are you seeing like those more expensive on a daily basis but you're using them for fewer days?
Unidentified Company Representative
That's right. I'm sorry I interrupted you. That's right we're couple of thousand more dollars a day for rigs, I mean, what's the exact number. Yes, so listen that. And really the whole of our all operation is $75,000 a day for the entire operation, so the actual rate component that's pretty small fraction. When you can really drill the well in a day, if you drill well on a day less at $70,000 a day one day it overcompensates for that extra $1000 to $2000 days that the rig has.
Unidentified Company Representative
Well, if I can answer that the answer would be something a lot of my competitors would really like to know. So, Irene is very early day right now to define the exactly height of the column. To the my way of looking at these things, it's pretty spectacular but I don't know when I can't know is exactly what the saturations are oil versus water down that entire column and I don't know just how each of the different formations are going to respond to the frac treatments we invited them as we go forward.
So the next year, 2014, is going to be very interesting year for us because we're going to continue do a lot of geoscience in the area. And because we worked well in teams, the geologists and engineers will be working together to try to come up with this very nice rest of before [indiscernible] completions in these different formations; one thing I will say is that the sands and when you talk about porosity in sand or fine sand or fine shale, it's quite a different talking about porosity in a shale like in the Eagle Ford. And one of the things we're wrestling with right now is how they perform, that's what we're going to do, how each of the different ones perform.
It's not necessarily that you can set criteria for a sand as you do for a shale; and one of the thing that's what we're going to be working on. I don't know if I answered your question but.
I am interesting in one thing Irene. I think there are, you're right, there're going to be we think multiple targets in each of these areas and we're like if you take the Ranger area for example, this year we're going to test in the first Bone Spring in the second Bone Spring in third Bone Spring and then the Wolfcamp, okay. So because we think that there is potential in that area for all of those just as an anecdote, I will tell you that when we drilled the Ranger 33 well, we went there to drill the second Bone Spring and we really liked the second Bone Spring, but the third Bone Spring also looked awfully good, in that well.
And so there were some days around [indiscernible] where we actually – after we had the vertical all three there where there was some discussions about, look at [indiscernible] I think there we'll be seeing that kind of things in this area here.
Just listening to that question I guess what would it take sort of -- can you help us how we should think about an acceleration of Permian will it really just be cash flows for the growing quicker, I mean the capacity to do it or there is certain number of wells or sort of the delineation activity that you guys you really need to work through over 14 before you know what you have to sort of push forward.
Unidentified Company Representative
I think here in the early days John that as we work through '14 we'll get in that deal, it's certainly looks this way that yes this is really working out well, we want to bring a second rig there, we're pretty methodical. So, yes its part of the game plan as to give it to a point where you regionally improving step up from one rig to two rigs that that just be a matter of time we're working through the result that we get there.
In the Twin Lakes area, are you all aware of anyone else that is targeted the client or the Wolfcamp D at this point in time and in any other kind of analogs since in the vertical wells how they performed if they approved that area?
Unidentified Company Representative
On the first question, I'll just tell you there are some other people must be targeting because you can look at acreage process analog they've reasoned very dramatically, we've [indiscernible] some of that competition is and it's a growing interest obviously, as far as production from the Wolfcamp D you've got again several large fields driving in that immediate area, it's a large Wolf fields but as far as within the mile or two of producing for the Wolfcamp D. You have at cost section which show production both above and below and I'm sure some of those perforations were also the Wolfcamp D. But just Wolfcamp D, I'm not aware of one in…
I'm not aware of that at this -- any of this point. But one of the things that is quite interesting is that as you go further to the west the Wolfcamp is productive from the [indiscernible] because you go through [indiscernible] changes so when you start finding the production from the carbonates, laterally equivalent to the client it does tend to reinforce the story that that client is a source of charging into those carbonates. So, I know we're anybody specifically testing the client up there as yet.
Seeing some recent activity in [indiscernible] County and didn't look like you guys had any plans to do anything there next year. Just wondering if that is an area you've planned to possibly divest or is there any opportunity to trade acreage there or what are your plans for that acreage.
Unidentified Company Representative
I think some of that activity that you're seeing [indiscernible] is a little bit to the South where our acreage is. As you know that acreage is, we've got about 21% working interest in that, its operated by UGE. So, we're a little bit dependent on what their plans are for that acreage and they've been working in other areas. We don't have any immediate plans to drill any wells or even to the west.
We certainly have talked about the possibility of trading that for some other opportunities of that if that were to arise, I think we could consider that.
And then when you look at your well cost, I was wondering what's imbedded in your 2014 capital plan is it Ryan showed and you've talked about your range of well cost are using kind of a mid-point for 2014 or what you're looking at, what's imbedded in the 2014 plan.
Unidentified Company Representative
Sure. It's not a mid-point, it's very much a schedule of individual wells and each one of them has an AFE associated with it. So, we have a very much a specific cost to each location that we planned drill, it's a function of where it is, how long the laterals are going to be, what kind of frac we think we're going to put on it. I mean to a large extend really all these wells are planned at this point and they have very specific cost associated with them. And they just have the roll up.
Just wondering in the higher cost area on these side in [indiscernible] have you tried drilling any of their without a third string and have you tried -- you mentioned you used propane there, did you tried [indiscernible].
Unidentified Company Representative
Couple of things just to clarify on that question, first of all I think when Ryan was talking about, when he's talking about the places where we use the three strings pad, he's talking more [indiscernible] County. So the step that we the wells that we're completing in Kern's County don't require, that's more the central region. So, they aren't the higher cost wells, they're more the $7 million $8 million wells that Ryan was referring to and those are trending also down towards the low end of the range, as far as Dewitt goes, we have, we are really using resin coated sand there not ceramic propane and to my knowledge we haven't pumped a job with white sand there yet, that's correct, isn't it Greg, and probably would not, I think we feel like that you at least need the resin coat there.
And last one from me David, you gave us the realized prices for your very series, I was wondering what the kind of benchmark prices you're basing those off of for your 2014 plan.
Unidentified Company Representative
You know basically, Mike, we were using something in the, well we were using something in the kind of low to mid 90s benchmark WTI you know with maybe still getting a little bit of uplift, you know on the OLS, I think we still get a tiny bit right now but have pretty much just washed that out, you know, so, pretty much just going with kind of a benchmark WTI type price and then on the natural gas really I was just looking primarily at sort of what we've had this past year and expecting that you know our thinking that the gas market will be pretty similar in 2014 as to what it was in 2013.
Unidentified Company Representative
Thanks Mike, anybody else.
Unidentified Company Representative
We thank you very-very much for your coming today, we'll have food served, if you have time and I want to leave you just with this last thought. Because again we think, a lot of people tend to think our business is very complicated and there are parts of it that are, but basically we all know for all the technology and tackle that this business requires its still is a judgment business, it comes down to people, and if you get good people they'll make the good plans better, they'll find a way to make it work, and they'll take good properties and find a way to make them perform better than expectations. I'm very as you can see pleased and proud to serve with the professionals that Matador has in this room, I'm very pleased to stand before you. A year ago when we're able to introduce that we're continuing to build a young category of people and build our tool box out and that confident that we'll stand here a year from now and point that we raised our production from two million barrels to three million barrels and that we're looking forward to 2015 and 2016 with similar success. Once you get these processes going they're really very powerful in finding ways to improve, so I want to just thank you very-very much for your attendance and your time, and hope that you'll come up we'll continue to get better acquainted over lunch and so everything else, I will entertain a motion to adjourn. I see Bryan Lapierre smile.
Is it barbeque?
Unidentified Company Representative
Amanda, what is the menu today?
Unidentified Company Representative
She's left, it's a mystery.
Unidentified Company Representative
Unidentified Company Representative
Just a couple of minutes and it'll be ready.
Unidentified Company Representative
All right, we have Cajun food for you today, in honor of our roots in Louisiana like it, but thank you all very much, I'll entertain the motion to adjourn so I move, and do I have a second.
Unidentified Company Representative
All in motion favor [indiscernible] by standing.
Unidentified Company Representative
All right, thanks.
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