Ross Craft - President and CEO
Megan Hays - Manager, IR
Joe Allman - J.P. Morgan Securities Inc.
Approach Resources Inc. (AREX) J.P. Morgan SMid Cap Conference November 28, 2012 10:15 AM ET
Joe Allman - J.P. Morgan Securities Inc.
Thanks everybody. So our presentation is Approach Resources and from Approach we have Ross Craft, who is the President and CEO and Megan Hays who is the Manager, Investor Relations. Ross?
I appreciate you are having us today. I'm going to fly through this presentation kind of quickly and then we will roll into Q&A. The main thing is we are an energy company obviously. Basically a 100% of our stuff for the most part is in the Permian basin in the Southern Midland basin. So let me find it quicker. Cautionary statements as we always have to do to. Read that and get onboard.
Alright, basically as I said Permian basin in our premier operating area, we have a 167,000 gross acres in the Permian, 148,000 net, half a billion barrels of resource potential in the Wolfcamp. When we found this Wolfcamp play in 2009 actually started working on it in 2005 and in October 2010, we presented the analyst in New York. This play has taken off quite a bit. We will go into who operates in the play and what kind of well results we are seeing. All driven, no doubt about it, the third quarter production was 8.1000 BOEs per day, that's even with a curtailment of 340 BOEs per day due to a pipeline [failure]. So we are moving up in the scheme of things.
When you look at a couple of highlights and we are going to break each one of these highlights down by categories as we get through them. So I'm not going to spend much time. I do want to point out a couple of things, as I said all focus on pure play. Our track record speaks for itself and we will get in some slides that justify that shortly.
We have a multi-year drilling inventory. Right now we have over 2,900 locations on this acreage. We've been playing in this area since 2004 actually chasing the deeper Canyon, Strawn and Ellenburger. We came across the Wolfcamp only because as most energy companies do we don't find something by design, we find something by accident and that's basically what we did here.
When you look at our program 2,900 wells, obviously its going to take a long time to do this and a lot of capital to develop this. Us being a small cap we have to be concerned with our capital deployment. I think the key of any small cap company right now is having a clean balance sheet which we do.
We are right now accelerating our redevelopment and we will get into the different benches, right now this play we are going to talk about has got three benches A, B, and C. Each bench has a lateral in or a new well in it. We will go through that as we get into it deeper. Right now our B is in development stage, our A is going into development in the first year and our C is dragging behind just a little bit only because we hadn't had time to drill more Cs. Recently EOG announced a C well that was their best well in the last third quarter. So the C is working as well as B and the A is.
Our balance sheet is strong as I said before that’s the key to any small cap. We have $280 million borrowing base and as of September 30, we had $222,000 of liquidity. As I said, our track record speaks for itself. Since 2004 when we started drilling in this play we started with zero production, zero reserves, zero acreage and a $5 million capital commitment. Today it’s changed; the complexity of the company has changed quite a bit.
If you look at it since 2004 our reserve growth from a compound annual growth rate is about 33%. Our production growth rate is 37%. When you look at the 2010, ‘11 and ’12, one thing you will notice is the sudden jump in the oil production that’s from the Wolfcamp. Wolfcamp shale to shale play is predominantly oil, these wells are about 450,000 BOEs per well. The make up on the average of these wells are over 50 year life is about 57%, 58% or on the full 50 years.
About 22%, 23% NGLs are remaining natural gas. If you look at the mid-year reserves, we were up 25% year-over-year and 9% over the year in ‘11. We do a mid-year reserve report sometimes it hurt you sometime it doesn’t. I don’t like mid-year reserve reports and probably I don’t like to publish them because it depends on where you are in your lifecycle anyway. We are getting ready to finish our 2012 year which I think you will be very impressed with the additions we are going to make in 2012.
Also production has jumped up. 2011 production increased 50% year-over-year right now we are targeting 20% to 24% for 2012 and we think we can carry the same growth rate for the next several years with our current drilling program as outlined.
This is kind of the make up of the 2,900 locations. As you can see over in the lower left on this graph, 500 horizontal locations, let me clarify on that, this is what we started out with. This is based on 1,000 foot centers and based on two-thirds B bench, one-third C bench, there is no A benches in here.
As I said earlier, we are getting ready to take the A bench for full development. So to look at this for every B bench well you will have an A bench well. So that’s going to add quite a bit location as well. Also down spacing going from a 1,000 foot to 650 foot between wells, you are going add somewhere around 200, 250 locations just on the down spacing alone. So what's you are going to see is a pretty substantial increase in horizontal locations. You will see a decrease in vertical locations.
We are showing vertical locations 1,825 [no] reason, why we are going to say a decrease because in areas that we thought, at once we are going to be develop vertically now through seismic and through our vertical development, we know we can drill those areas with horizontal wells. Horizontal wells are better return right now.
And then we have all these recompletions. We drilled probably 500 wells out here chasing the deeper stuff since 2004. All this is behind pipe, this is up the whole, so we have the deep inventory of recompletion projects coming up from Strawn and Ellenburger, Canyon up into the WolfCamp. And then we have our typical bread and butter Canyon locations, obviously, Canyon is predominantly gas and we would like to see a gas price of 4 to 4.50 before we crank this program back up. It doesn't mean the reserves are go anywhere, it just means we have multiple targets so we can pick and choose depending on the commodity prices at the time.
As far as our capital programs, 2012 was a big year for us. We did a couple of things in 2012, when you look at a program like this a horizontal program; you look at getting your drilling cost down. The key to this program is getting your drilling cost to below $6 million a well that's the key.
Right now, if you look at our well cost, D&C basis it’s running about 6.5 to 6.3, part of this capital we spent in 2012 for infrastructure, it’s a road map and I go through the roadmap on how we get down to our targeted 5.5 or lower in a few sides forward, but we had to spin this money on the infrastructure that's water, the saltwater disposal lines, that's frac lines, that's gas lines, that's oil lines, that’s completely regenerating and building new gas pipelines to go to a better market and we had to do all that for 2012.
What you are going to see is a substantial reduction in drilling cost in 2013 and you will see a substantial reduction in LOE as well because of this infrastructure we've put into place. This infrastructure is designed to carry this project all the way through. We won't have to add on to it.
In 2013 it looks like our CapEx budget is going to be around 216, as you could see the big change in that is we don't have much infrastructure in place and a majority of these wells are going to be horizontal as I said before. Horizontals in today's times are the bigger bank for your buck. All these projects have a very nice rate of return but horizontals where you want to go.
This is your roadmap. These are the savings you are going to see on our horizontal well by doing infrastructure, by replacing your water with from replacing fresh water with [gyp] water. We are going to save roughly $450,000 per horizontal well we drill around [gyp] well at 700 feet. If you go into on the processing and installing water transfer and salt water conversion lines, you are going to save roughly on that, you are going to save probably $450,000 per horizontal well and this all is part of the D and C cost. Right there you had $900,000 in savings in those two items alone.
And then you look at the LOE savings. You are going to see because we have our own salt water disposal wells, you are going to see a reduction from $5 to $7 a barrel disposal fees to $0.50 per barrel. That's what's going to cost us, maybe lower. So that's a huge LOE reduction, that's why I said you will see the LOE drop in 2013. Also flow back equipment. We have self sourcing from our own sources now, and we are not renting that and that's going to save some money.
Also the gas lift operations is key and gas lift on these wells, you have to gas lift these horizontal wells. They don't have enough pressure to flow by themselves. Once you flood them with 250,000 barrels of frac water, and gas lift alone by cutting the gas lift and individual water compression and going with your standard sales compressors we already are paying for, you can save $6500 to $6300 a month just off of that alone and that's part of our infrastructure as well.
And then our oil pipeline, we are laying a pipeline that goes to the North about 14 to 15 miles, so we transport all of our oil by pipeline. That's going to take our trucking differentials completely out of there. We are looking at differentials on this pipeline once completed which is second quarter or first quarter of 2013, and we are looking at different (inaudible) anywhere from $2.50 to $2 to $4 on that system which is a big change what we had before.
As I have said gas pipelines, we have completely revamped our system. All of our gas now as of Monday its going to the south to the DCP facility, that's a 95% POP contract, 4% fuel and shrink, a very attractive contract and when you look at especially with the NGLs we also have fixed recoveries on the NGLs. And so this project has really saved us a lot of time and also a lot of money. We weren’t anticipate in drilling this pipeline so quick, but I'm glad we did.
The resource shale play Wolfcamp, basically its in the southern midland basin. This is a premier source rock for the midland area of the Permian basin. When you look at what we are doing right now, we've transitioned the Wolfcamp B zone into full development, the A is soon to follow, and the C will follow once we get another two or three wells in the C zone. It’s being tested and with success at North of us, EOG is doing that. So what you are going to look at when you look at the same 10 years from now you could see up to three laterals or three individual wells for pad and what you are looking at is anywhere from 14 wells to 21 wells from a mile distance. These wells are mile and a half long 7,500 feet and so you can really recover a lot of resources that way.
This is kind of the activity at the Southern Midland basin right here. When we first started out here there wasn’t many people, there were a lot of goats and deer and that was about it. Us and EOG started, EOG started out testing the horizontal aspect of the play, we started out testing the vertical aspect of play. All geological textbooks said this play wasn’t over here. But because of all the wells we drilled we had logs and we knew it was. So in 2009 that’s when we started working on it.
As you can see to have a shale play you have to have a large area. It’s got to be consistent across a large area. This cross section represents 67 miles going from west to east across the acreage. As you can see the A, the B and the C is very consistent across the acreage. Each one of these zones is productive, and we will be focusing our attention on each one going forward. This is just kind of how it looks when you are prepared. This is a conceptual vision of each pad you will have three individual wells. These well costs hopefully when we get them down that infrastructure will be somewhere below 5.5 million, but 5.5 is our target price.
EOG is actually drilling and completing their wells below five right now. And so I think we are well on our way to get there. We are probably the second most advanced operator out here because it’s just the time we have been in the play. A lot of questions come up in discussions through different presentations at the further South you go the gassier it gets. Well this is just simply not correct.
Based on the data that we have been able to collect from public information, this shows you what the percent (inaudible). This is IFP, this is at the highest producing rate, and this is IFP numbers. And what it shows you, even though you get deeper going to the north west, the oil percentage is about the same, its about 82% across the whole play there. In this area represents about 2 million acres. So the play is working well, very consistent, similar results across the basin and various depths. So when you see something like that it’s always pleasing to know.
The next slide is just our activity. As I said, we have quite of bit of acreage out here, we’ve de-risked about a 100,000 acres, and when you look at it the southern portion of our acreage is the only area that we haven't de-risked at that point that's where we’ve drilled a bunch of vertical wells in the past and we are still working on frac modifications to get to work.
We haven't assigned any reserve or any locations to that 60,000 acres. Everything we have assigned to is a 100,000 acres to the north. Now this is what you all have been waiting to see, and this is which I should be waiting to see. This is a scatter plot of all of our wells, the session of the first three wells we drilled horizontally and we didn't know what we are doing at the first three wells that’s when we left them out, they are pretty poor wells.
But as you can see from the scatter plot, majority of these wells are B bench and then the ones in red are A bench wells. As you can see this is our 450,000 barrel equivalent type curve, we generate this about a year and half ago. This type curve is holding in there nicely. As you can see we have wells that are way above that, we have wells below that. So when I tell you 450 number that's a statistical number. So if you do 50 wells you know your average is going to be in the 450 range. We’ve got wells that are going to do 600; we’ve got wells that are going to do 200, that's the nature of the shale play, its variable.
You are not going to get the same well result even if you drill offset another well. It’s just the way it works. But statistically, that’s why shale plays work so well, you can model them and once you get enough data and we have probably in here we probably have 20 wells in here, or something like that, 18 to 20 wells. As you can see it’s tracking our type curve and the most important thing is tracking our type curve in the later time regions. So it’s working nicely. We are very happy with the curve.
Economics on this deal, this is a key, getting your cost down. But targeted $5.5 million cost obviously at various oil prices in the 450 you know it’s a pretty solid rate of return, you are up around 40%, 42% at $100 and then on down to 30% as you go down in the 90s and so on and so forth. If you drive this cost even further to 5 to 4.8 your rate of return sky rockets, that's why I say $6 million is your cut off, if you can get everything done for $6 million or less, you are golden in this play.
Our other projects that we have in the play consist of the recompletions in the vertical programs. When you think about our vertical program it’s nothing more than Wolfberry. Everybody has heard the Wolfberry play, vertical program is Wolfberry. We have a lot of locations but right now we like the horizontal concept better, but you can see the economics are quite good on the vertical play as well as recompletions.
Recompletions we use as our any day projects. If we need to add some, we go in and hit six or seven recompletions. They are very quick. So that makes a lot of sense. This is just a breakout of reserves as allocated by the different projects as you can see, this review (inaudible) will come up to about 0.5 billion barrels equivalent.
Deep inventory, a lot of drilling, long, long life to these wells. So it’s really a nice position to be in. At the end when you look at it, we have a concentrated geographical footprint in Southern Midland basin. We are kind of we are the pioneers on this deal. We have a strong growth track record, I'm an engineer, I do a lot of the engineering still.
We all are very good at what we do in our company. We are a small company but we had very talented individuals. Our technical evaluation which led to this discovery is stellar. The team works very hard on this. Qingming Yang is the pioneer on this. No pun intended, he came from Pioneer but Qingming Yang and I started looking at this and Qingming was the guy that came in and basically put it together for us. I had no shell experience. Mine is entire gas and unconventional reservoirs.
I knew I had something but I couldn’t put it together. Qingming being the geologist came in and when I handed him the information I said Qingming tell me if I have something and after about a year of work we did have something. We have gone a rigorous product program to derisk the 100,000 acres. Every well we drill we gain more knowledge but at this point we derisked the B bench, soon A bench and soon to follow is the C bench.
Capital discipline, that I can't overstress that these wells are expensive wells. For a small company like us you better make sure it works and so we've taken a very slow but methodical approach developing this. Some of the operators out here that are only six and seven rigs at it but they are the operators like BHP, El Paso, Apache, and things like that. We are the small guys in the block but I think our technical capabilities and along with our discipline has proven itself well. And that really sums it up. I have 10 seconds to go so I thought I did pretty good.
Joe Allman - J.P. Morgan Securities Inc.
You did great actually Ross. Certainly we have about 20 minutes for questions. So I have got several questions but anyone in the audience have any questions to start us off?
Joe Allman - J.P. Morgan Securities Inc.
I guess two questions, one the type curve that you showed, how many of those wells did you actually go out to 7,000 feet lateral length on all of them or how many…
All of these wells are on the side curve or between 7,300 feet and 8,000 feet.
Joe Allman - J.P. Morgan Securities Inc.
Okay, and because you mentioned Pioneer I mean they are saying they can do well cost for 6 to 6.5 once they do development phase and they have their own pressure pumping equipment and you are throwing out numbers 5.5 and you even mentioned going to 4.8, so I am just curious I know you outlined how you are going to get there, but when are we going to see $5.5 million well cost?
Well we got to put back a little bit on this gas pipelines we had to build to DCP. So that slowdown on infrastructure build out and so when you look at our infrastructure build out now it probably won’t be completed till the first quarter. As soon as the infrastructure is completed in the first quarter we have already finished on Pangea West then you will see the immediate reduction at that point because then we can (inaudible) water, reuse the flow back water and that’s the key and then use our gas lift from our main compressor stations and not have to run equipment anymore. And so you will see it probably in the second quarter of 2013, you will start seeing it hit the books and start seeing these lower costs, but the key in the lower costs pressure pumping services has gotten so cheap.
Our stage cost is around 60,000 a stage now as compared to 140,000 a stage when we started. And so pressure pumping for us is pretty cheap, also what we are seeing and this is important even though we are drilling long laterals what we are seeing is we did what everybody else do we went from 21 stages to 24 stages to 28 stages to 30 stages to 35 stages. We saw no increase in reserves going 35 to 28 from 28 to 35, likewise we didn’t much of an increase going from 24 to 28. So what we are doing right now is running some logs some fractured identification logs, while drilling and it’s showing us where the fracture systems are and then what we are doing is reducing our stage and we are getting the same reserves because now the reason why across on drilling people frac so many stages because they don't know where and how to frac. They are statistically bonding this whole lateral. Well, now we know where the frac, where the frac systems are and so that's going to help us to reduce the cost of those fewer stages.
Joe Allman - J.P. Morgan Securities Inc.
And then lastly I want to ask your balance sheet, CapEx is going down sequentially year-over-year but you still felt the need to issue equity a couple of months ago. Can you just tell me because I know you said here you have the strong balance sheet but you are not, you don't seem to want to use it, so can you just explain what the optimal amount of debt you guys feel like you can take on and where we are going to be back here next year asking for more equity?
Well, the debt optimal debt our boys have been a little averse any debt but obviously you will have to have it 30% or 40% would not, a play like this would not be out of the question at some point. Obviously, that would be the high yield market or something like that we will approach. The reason why we went out with this equity offering this last around is simple, the economy, the instability with the EPA right now and all that.
We want to make sure that we kept our debt loading down, we want to make sure we had a clean balance sheet because what's going to happen, we are not sure with this commodity prices are going to do, they are fluctuate up and down. If you are maxed out or if you are really high leverage on your debt facility and then you have a sudden reduction in oil prices, certain reduction in NGL which you already have, reduction of gas prices then there is a redetermination that's you will have to do.
And that's not a position anybody wants to get into, it’s a critical and disastrous position to be in. We felt like with the infrastructure we have infrastructure process we had, it was prudent at this point, we weren’t quite big enough to do high yield that was prudent to do and raise some more equity. We don't have to do anything else going forward.
We have the infrastructure in place. The way we have our drilling model scheduled at a rig about every year will add additional horizontal rig up till about six horizontal rigs and we can do that under our facility right now without doing anything else. That's why we saw a reduction in the CapEx from 2012-2013 because now we are focusing on bringing the reserves out of ground and not building infrastructure, not building other things. Any other questions, yes.
I was wondering what kind of off-take agreements you have or you will have for the NGLs. Will those be processed on the site or those be piped to the Gulf, will the chemical companies take those from you. How does that work?
Yeah, well, the beauty about the relationship we have with DCP was they have recently announced two years ago about their expansion of their NGL pipeline down the Eagle Ford from West Texas and then across the Sweeny, ConocoPhillips Sweeny facility up to Mont Bellevue. There's plenty of takeaway capacity on that. DCP has plenty of plans to the southern portion of this play down in Sonora, down in Crockett.
Remember this whole area was a gas play originally. They have the newer plants, some more efficient plants. So that's why we were able to get a 95% POP contract. Not only that but we've got a fixed recoveries. For example ethane 80% minimum, for propane we are at 95% and the 97% for Isopentane, isopropane and all the way through the natural gasoline. And so what that allows us to do, they sell, they buy it from us at the plant, they sell it. So as far as and what we get is a spot price whatever it is.
Obviously when you look at our make up of our NGLs; about 40% of our NGL volume is going to be ethane, about 35% is going to be propane. Well, its no secret ethane’s gone from $0.75 at the end of 2011 to about $0.30 right now. Ethane we are flood with ethane. I don't see any increase in ethane prices near term. Propane I think with the winter setting in propane will recover. We came off of last year with the inventory of propane that’s why propane is a little bit low right now. I would like to see propane get up to about $1.15 range per gallon, but as far as takeaway we haven't had a problem with takeaway on this facility other than major malfunctions on the Gulf coast, Sweeney play going down for routine maintenance or something like that, but storage capacity has been there stored. So I think that's going to be a good market for us.
Ross let's think about the near term a little bit. I know you drilled one C bench well and I think you didn't necessarily place that properly in the C bench. So you didn't necessarily lose a lot of money but you didn't make a lot of money there. So what's the next, when are we going to hear about the next C bench well and then can you just talk about any other data points that the market can look forward to that really kind of move the needle on the valuation.
Yeah, I think when we come out with our end of the year reserves, which will be in January, you will see a lot of data points that you haven't seen before. You will see the new well count, you will see the new development model. As we've always said, we are very cautious on how we do things. I want to have plenty of long term production before I make any radical changes and you won't see a radical change since the type curve is going to stay at 450. You won't even see it change the shape of the curve. It’s a perfect curve. I did it.
But what you will see is we will start working on the C bench. We've only drilled one C bench and the reason I brought this slide back up, we landed the C bench high and the C you can see the purples are C bench, and it’s hard to see with that lines separating the B bench and the C bench. If you will look closely you will see a spike on the curve up to your left, there’s a spike that runs all the way across it.
We thought that the C bench, we treat it just like we did with the B bench, land high on the B frac and go up to A and do the same thing. Well that’s a frac barrier, there is no question we run micro size. Frac goes up and spreads out, and so that’s a good thing. So now we are going to land deeper. The well EOG recently announced was 1300 BOEs a day out of the C bench, it was landed in the middle portion of the C and the well responded favorably.
So I think it was just a function of us getting the right landing depth, and for once I think EOG let us do their R&D on something. But you will see us drill some more C bench that we have them coming up, we have a C bench scheduled I think first quarter for sure. We are going to be doing stack laterals too in both Pangea West and Pangea. We have those in the books and the next few wells to do stack A and B and frac them simultaneously, and that will be our first venture in this two stack laterals to see the results of that.
So there is a lot of (inaudible) that’s going to be coming out in the first quarter along with the reserve updates, reserve should be nice what you see on that. So that’s when you will see and more well results obviously. But the reason why we want to put the scatter plot out there because for investors who want to see a play, you can hear me talk all day long, but you can’t argue with real data and this is real data and so we just now have enough data points to put that’s meaningful and so I think when you see that and see the way that the wells are performing, you say well at least they are following the type curve.
So now it’s just a function of cost. Let’s go ahead and bring the cost down into our targeted cost range, infrastructure will do that and then it’s gold and then it’s a development program. So we would like to get two more C bench wells here that’s our normal mode three wells and then we go development, and so we are going to be drilling two more Cs and one over Pangea West and one over in Pangea. We are bringing a third rig in January, third horizontal rig. So we will have two rigs in full developments, which means that they are going to get on one side of the lease and they are going to go well to well to well to well, just like what EOG doing
Our third rigs is going to be rotating around, it’s going to be moving around, its going to go away to the east, drill some wells over the east, its going to go to central Pangea and start drilling some wells in central Pangea and so its going to be [roar] and then in 2014, we are bringing fourth rig in, we will have three and four development, so that's kind of our method or madness right now. We just want to make sure that everything we do is we are gaining knowledge and we are reducing our cost and that's kind of where we are going.
Joe Allman - J.P. Morgan Securities Inc.
Okay, I got few more, anyone else got any questions. Okay, for 2013 so your plan is to drill 35 to 40 horizontal wells in the Wolfcamp play. So how many do you think will be in the B, how many in the A, how many in the See?
Most likely its going to be pretty good mix between A and B. We will probably have equal mix A, B and then Cs will probably be maybe 10 wells in the sea total.
Okay, so that's a pretty amount of C well actually considering (inaudible).
Yeah, the only thing we are missing on the C bench wells right now is couple a more data points. This latest data point EOG came up and EOG is just north of us. It was a very good data point and also was a data point to prove there, what we thought landing deeper in it and you can make well out of it. All of this was saturated hydrocarbon. So key is when you look at this the key is how are you going to efficiently get it out. When you look at in place reserves, for this in the Wolfcamp its about a 118 million barrels equivalent for sections 640 acres in the Wolfcamp alone. When you look at recovery factors in the Wolfcamp for oil we are using a 3.5% recovery for oil. That's a very low recovery.
We are using 10% for gas just based on relatively issues. So what we are trying to do and we think the stack laterals will help you do this and along with the verticals if we can go from 3.5% to 5% recovery on oil with that much oil in place it’s a huge number and so that's what we are working on right now and that's why we think the stack laterals will come in and also where the C bench will start showing up. On a long-term basis, to answer your question, until we have more C bench wells it won't be a full time C bench, there won't be three laterals per location, but from investor standpoint you look at it right now and you say two laterals for sure. Whether they are going to be A, B and C, or B and A or C and A that's yet to be determined.
And then will you spot the next C bench well in the first quarter?
Okay, got you. Is there any reason to believe that the A is I mean when you look at that, the result, the curve, it looks like the A is actually doing better than on average the average B well, you know t could be just statistical thing, you only got three A bench wells but is there any reason to believe that the A would be better than the B on average or any reason to believe that the C would be better than the B or…
No, right now you have to understand the A bench wells and these were based on our first two A bench wells from Pangea West. We were playing with some chemicals in this frac and you know most people don't realize the amount of chemistry that goes into what we are doing but we are designing, we are reverse engineering some chemicals, some surfactants to try to design them to do a couple of things or the normal surfactant which is nothing more than hand so what you get is a complete washing of the rock, you get this big eye piece but what we are looking for is a surfactant that goes in.
It attaches itself to the rock base and you get a more uniform release of the oil because the oil in a tight reservoir like this or relative oil versus gas is a big issue. These are very nano-darcy perm numbers I mean extremely tight. And so when you look at trying to force an oil molecule versus a gas molecule through this tight rock, it needs some help and so we verged in engineered some surfactants. What they do by doing this and it was a surprise to us, you've got a much slower release of oil. These wells unlike our original wells were after about 9% to 8% to 12% load recovery in the oil hits and the gas hits. These were much different.
So you start to pull them back slower but a steady increase over 30 days, 40 days, 60 days, it kept increasing. And that's basically what the surfactant was trying to do is it gives us a slower time release for the oil but a more uniform release and that's why I think you can see on this graph, you can see the red dots for the A bench that they are performing right now a little bit better. We also shot one of these wells of the log I was telling you about the image log and we shot it based on where the fractures were, that's our 60, that's our 6602 well and that well is actually a better well than 6601 which supported our concept of the image log as well.
I won't say that they are any better yet. We don't have enough data to say that but I think they are equivalent right now. With just two wells it’s hard to predict on statistical modeling or anything but we are very pleased with the results we are seeing. Now we have a third well on, it’s flowing back right now. And it’s doing pretty nicely as well. So we have three A bench wells going, getting (inaudible) to drill some more A bench. So you know I think mid-year you are going to see enough data on A bench so we can pretty much quantify what it looks like.
Unidentified Company Speaker
Could you repeat the question? Please, sorry. Could you repeat your question just for the webcast?
Yeah I think I was wondering who your buyers surfactants or frac and chemicals from and how important they are also cost operations (inaudible) like a dollar a pound or how much do you need?
Yeah, good question. If you look at the stage and let’s just take a typical frac stage that we are pumping, a typical frac stage consists of about 8,000 to 9,000 barrels of fluid. So what you need in that there is a couple of things you need, you need surfactant, you need scale inhibitors because there is barium in this stuff and you need breakers and friction reducing agents while friction reducing agents first address what we are getting from, there is only a handful of companies that make chemicals out there and everybody buys it from the same companies. Surfactant is soap basically; it might have some other stuff in it but its soap.
When you look at friction reducing agent that’s a polymer base that’s nothing more than what they make gel out of, then you look at your scale inhibitors, it is a fast forward scale inhibitor whatever you look at those. In the big scheme of things the cost basis it’s only about 60,000 to 70,000 a complete well. There is not much for example, on friction reducing agents we run about 0.35 gallons per 1,000 gallons. So that’s about a 190 gallons per stage. On the breakers which are breakers are just oxidizing agents because the polymer will plug the formation.
So you have to break it, there is nothing more than oxidized so you can use hydrogen peroxide it’s a good cheap one and very good oxidized one and that’s pretty cheap too. So you will run about 300 gallons per stage on that. On the scale inhibitor and things like that those are standard [shelf] items. So it’s not a big ticket item but what it does for you during the frac is remarkable. If you don't run it, we know what happen, we didn't run also and the well performance were poor.
It’s just part of the shale play but none of this is anything that's toxic, it’s just the shelf item most of the stuff you eat, or you wash your hands in. We have gone away from using any amount of (inaudible) for biocides, we are using a chlorine dioxide gas which is a 100% clean has a residual life span of about two days and that's really helped out. So we are basically running green completions on all this. When you look at the frac make up, there is not a lot of things in it other than a few chemicals.
Joe Allman - J.P. Morgan Securities Inc.
So Ross, just a last one. So what is talking on the figure out in the horizontal play what you are still trying to tweak, so it seems from your earlier comment it sounds like you are still trying to figure out the optimal number of stages, right? Is that true you are still trying to figure out, what other things you are still trying to tweak and figure out in the whole play?
Well, we got the drilling down, the first thing was to get our drilling times down, our drilling cost down, originally it was taking us 30 days to drill a well, now we are drilling and (inaudible) in 12 days. We think we can get down to eight days, EOG got theirs down to single-digit days as well, but your cost in that is only about $1.5 million in these things. So all of your cost is incompletion of this, so obviously to really impact your cost, you have to impact it on a completion side sourcing water big, stage size is big, the number of stages and that's the most important thing we are playing with right now and that's why we are running this image log in certain wells to run some test of fracking off the image log versus carpet bombing fracs just say. And that's what you will see us starting to do.
You will see us starting to reduce the stage. We won't lower the link lateral, we won't shorten that. But instead of running 200 foot point stages we might run 300 foot. If we use the image log we might run 600 foot in this stage, 200 foot in that stage and so on and so forth. We like to get our stages down to somewhere from I will just say openly 21 to 28 stages. And really targeting the 24-26 stages. We think its going to be optimum and so but that's what we are working on right now.
Joe Allman - J.P. Morgan Securities Inc.
Okay. Actually (inaudible) I am sorry we do have a minute left, any other.
So for the breakers, I think you mentioned in the third quarter earnings call that you are also taking breakers to your higher IP rates. So is there a combination of breakers and (inaudible) probably higher rates and a lower decline is that…
Well, the chemicals, the breakers, the surfactants will not do a whole lot for your overall decline rate, but what they will do and this is a good question and a lot of people get caught up on IPs. IPs as an engineer mean nothing to me. It just shows how effective I was at fracing the well at that point in time. Its our immediate point process. What I look for is 30 day, 60 day, 90 day, 120 days, so on and so forth because that's what tells me whether I'm making money or not.
We've got wells 1300 BOEs a day, here playing with surfactants and playing with these chemicals what you will see is, you'll see lower IP rates, but you will see decline rates that are very much in line or maybe a little bit higher, not higher decline but the production rates to be higher than type curve. We just don't have enough data to know at this point, if playing with surfactants will change our decline rates yet, we don't have enough.
But we are confident that we have it about where we need to be, and so that's why I keep going back to the 450 type curve. You hear different operators saying higher numbers, higher numbers, well EOG and us have been sitting, and EOG is at 430 and we are at 450. And we've been there for a long time. And so we think that's a good number, and I think if you just design on that you will be pretty good but the surfactants, the breakers and the breakers are very important because friction reducing agents even though it’s a slick water frac we run friction reducers so we can lower the pressure a little bit.
But it is a gel, a very low concentration of gel. But that low concentration in a nanodarcy environment plugs what you frac. So you are on the oxidizers because the oxidizers will break down the polymers and so you get more better clean up out of it. And that's why we run the breakers in it. Without breakers you get a very low producing oil. Without surfactants a low producing well. Surfactants allow the formability, built it firm for oil to overcome the formation types.
Joe Allman - J.P. Morgan Securities Inc.
Excellent. Thank you very much Ross, great presentation. Thank you.
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