Lynn Peterson - President and CEO
Kodiak Oil & Gas Corp (KOG) Bank of America Merrill Lynch Global Energy Conference November 14, 2012 8:00 AM ET
Thanks for coming. We have Kodiak Oil & Gas today really kick starting the day on this track. Kodiak as we all know, it’s been a well-established pure play Bakken player, being there for long and doing a lot of good things, including de-risking parts of the play that haven’t been done by some of the larger operators. Without wasting any more time, Lynn Peterson, the CEO of Kodiak. Lynn?
Good morning everyone. Thank you to the whole Bank of America team Merrill Lynch group for bringing us here today. We appreciate the invitation. Kodiak is a pretty simple story. We’re one base and play. We’re in the Bakken. Everything we’re doing is in the Bakken. We’ll kind of walk through this then we’ll have a Q&A session at the end of it. Just forward-looking statements, I think you’ve all seen enough of those and we can slide over that.
We’re about a $2.5 billion company. We’re very clean on the financial side as well. The only things we have on our balance sheet is $800 million in bonds due in 2019 and then our revolver, currently at $450 million and that is a situation we will continue to grow as we bring wells on to production and we’ve chosen to leave our borrowing base $375 million just because we don’t need it at this point.
This is the slide that always bring all the attention to Kodiak and what we’re doing and it has been a growth story. There are no questions. This year has been a year of execution, what we’re trying to accomplish. You’ll see our growth on the far right side. We’ve taken the company basically from 10,000 barrels a day as we entered the year and we hope to exit somewhere close to 27,000 to 30,000 barrels a day. We started the year a little bit slow. We had some acquisitions work that we brought in late 2011-early 2012, integrated that into our company during the first quarter. I think the second and third quarter has been a lot of fun.
We’re all of a sudden rocking on all cylinders here. We’re completing somewhere in the neighborhood of five to six wells with each of our fractures every month now. So we’ve got a busy fourth quarter scheduled, about 26 net wells that we anticipate completing, that’s comprised 23 that we operate ourselves approximately three not operated. So people ask how we’re going to get from our current 16 range that we exited Q3 with to 27 as pretty simple. The wells are there, we’ve got hold if the weather cooperates a little bit with us. We have two crews that are completing wells right now. So, on an average we’re getting 10 wells done each month.
I think as we looked at October, I think we completed 11 wells in October and we have got the balance to get here in the year and I’ll through all of these wells and really down through the core of our areas. We know what kind of numbers we are going to get. We don’t anticipate any surprises here.
I will call your attention to our appendix. We will go through these today but we have all of our production numbers in the back of our presentation on the 30-60-90 day basis at the 360 days. So you can look at the numbers, they are pretty consistent throughout blocks of acreage.
As we look at our plays that exist today, on the left hand side we try to demonstrate kind of where the margin on a barrel of oil is. You can see basically it’s is this $55 to $60 of barrel. It’s pretty consistent. We have driving our LOE cost down. We believe that that number should be in 500 to 550 range as we go through Q4 and into next year, driven primarily by our water handling as we give more and more of our wells tied into our gathering system and directly into our disposal wells, we should be able to drive that cost down a little bit more.
As far CapEx, we set it at about $750 million here as we left the third quarter. That’s an up size from where we started the year and it’s primarily just for drilling more wells. I will talk a little bit our efficiencies beyond, from drilling standpoint. I think if we look back a year ago, first part of this year, we were taking 35 days to 38 days on average to drill these wells. Today, that average is down between 20 to 25 days. We’re getting a lot of wells under 20 days as we speak.
So, we have just been able to drill a whole lot more wells with the rigs that we have. As a result, we have already dropped one rig and gone to seven rigs. We will probably drop one more here as we exit 2012 and go to six rigs for 2013. Again, we have begun looking at drilling about 10 wells per year per rig. Today, we think we are in that 12 to 13 range. So I would just speak to the efficiencies have been driven out of this play.
Again, people are starting to talk more about 2013 and 2012. We’ll come out with our numbers here, first part of December, I would expect a budget similar to what you see here though, what we have experienced in 2012. I will make quick comment on our non op. I will show you a little bit, our non-op is primarily driven by an area of mutual interest that we have with Exxon Mobile over in Dunn County. About half of our expenditures are related to that AMI.
The balance is a number of other operators, who will to continue to participate as we go through 2013. This is a chart, the way we look at the rate-of-return on these wells, we give three scenarios here, a 650,000 barrel of oil will, a 750 and an 850. These are not Boe, this are just barrels of oil here.
We use a $10.5 million well cast. We can talk a little bit of about what's happening in the universe up here. We're seeing a dramatic drop of cost. These wells have come probably from $11.5 million - 12 million, down to $10 million-$10.5 million. We think we’re going to go under to ten.
When we talk our wells cast, we're in talking of wells that’s using 100% ceramics. Again, most of our acreage, I'll show you a here is located in the higher pressure regime of play. We believe that these ceramics is mandatory to keep this fractures open as we drill this reservoir pressure down. So again this is a higher end of well cost up here.
We do a few areas, as we look around the basin, step up to the north, a little bit southwest where we’re going to start using sand or at least sand and followed by a little resin coated sand. So these well costs are coming down. I think we're headed kind of into the $9.5 million to $10 million here shortly, probably as we go into the first part of next year, we should be in that range. But as you can see, even at $10.5 million we use three pricing scenario at $95, $85 or $75. We take $10 off of that for differentials, that’s basin differentials and transportation included there. And again, you will see rate-of-returns on kind of the lower end being in the 25%, upwards to 70. That’s just a mix of acreage, I wanted to call a couple of areas. One is our polar block up, just north of the Missouri river here. The other one is the Smoky (ph) black here of the South.
The reason we do that, we're going to see you a pilot program we're going to do in each of those areas. We begin over here on the east side of Dunn County. To kind of orientate everybody this a partial fill, just to the North east. Obviously (inaudible) to the West and the same is developed and really what we find out is basically there is a circle here that all the wells within that area are really over pressured and again that’s where most of our acreage is located and that's where you see ceramic profit for completion methods.
This is kind of our 2013 goal, that we're working on here. We believe that at this point we pretty well evaluate our acreage from a standpoint of what the Bakken will yield, what the Three Forks will yield. Now there are several benches in the Three Forks. They are interval so we kind of refer to them as upper middle lower. Others are one, two, three benches and we believe in certain parts of the play that we see these additional benches, primarily west of the nesting in that Polar, Koala, Smokey area.
We believe on the east side in Dunn County, we did not have the lower three fourth number. So what we’re going to set out to do is two pilot programs here in 2013 and we’re going to begin drilling probably in January on our first block. It’s going to be located in our Polar area. We are going to take an undrilled 1280 and we anticipate to setting three rigs our here on it. We’re going to drill four wells with each of the rigs and our concept is to set the Bakken wells approximately 850 feet apart, which would allow us to set six wells into a drilling spacing unit because we 500 foot offsets on lease lines.
Now we’ve done a fair amount of work, trying to drill wells closer together, in various parts of our block. While we seek communication we don’t really see from a production standpoint and this is what we’re encouraged about and I guess the way we look at this as a downside is these wells will communicate.
It’s possible to get the oil out quicker. So from a present value standpoint, it should drive us forward. So we’re anxious to get this going to see what the results are. We then intend to look at the Three Forks and we’re going to do this a little different. Continental has got a project out here similar to what we’re doing but they look at it a little bit different. We’re going to set wells up in the upper and middle Three Forks, again which are commonly referred to as first and second benches. We’re going to drill six wells, but we’re going to alternate between the upper portion and the lower portion.
We believe in our case, the way we’re fracing these wells we are breaking through the interval that isolates these layers. Again we look at it as kind of one hydrocarbon system. Some companies will say they are separate reservoirs and we’re not convinced of that at this point.
So what we intend to do is alternate between the upper and the middle benches there and we believe our stimulation work will frac down or frac upwards, and we will be able to drain this whole area. So it will be a 12 well program between the two pilot programs. It’s about a third of our drilling for the year and we hope we can come back here and we bring two completion crews in, start on the outside and work from the outside in and get all these on production, see we have got here.
We think this is really a mandatory test at this point. Again, we’ve saved all of our acreage. We are in an HVP (ph) status. Now we got to figure out how we effectively drain this reservoir. We are closely monitoring what Continental is doing in the third bench, which again is down here in the great bottom. We’re not completely sold on it so we’re going to watch their results. We wish them the best. We do know that there is oil saturation in that zone, so it’s very likely that they will be successful. We felt that we can always come back and drill these two wells if we need to. So that’s going to be our big program here as we go into 2013.
Again, we’ll kind of walk through our block acreage. We’ll start over in the east side. Again just to depict this over, it’s all the names you recognize really throughout the sink and we’re seeing numbers here, 800,000 to a million barrels. We have got several wells we believe are in the million barrel range. Every well is very consistent.
So this is our area. We participate with Exxon Mobile. Up here to the upper right hand side is the AMI we have with them. We operate the west side of it. They operate the east side of it. We currently have two rigs over here. We are probably going to take one additional rig off of here and get down to one. Everything will be HPPed over here. So, we don’t have worry about any of the lease status.
Pipeline situation over here, we have oil, gas, and water in the ground. It’s a third party pipeline group and quite frankly it needs to have a little work on it. That’s where we are going pull off for a while, let them specific and upsize the system to better handle the volumes coming out of here.
I think when they initially built it out, they didn’t have any real concept of how large this play was going to be. So, that needs be engineered and upsized but we’re seeing numbers very consistently here, like I said in that 800,000 to 900,000 and upwards to 1 million barrels.
We have drilled a couple of wells in 2010, right in this area. That our first use of cemented liners on one of the wells. There was also, as you can see they were drilled very close together at the heel of wells. Those two particular wells absolutely communicated when we fraced them. When we look at the production status, we do not see that communication today. So, those are couple of our better wells and that’s part of what encourages us to put this little bit tighter together. So, that’s a first example.
We have also done a lot of work Three Forks and the Bakken here, roughly 600 feet apart. We absolutely have transferred fracs from the Bakken well into the Three Forks. We see it quite regularly. However, once you bring the frac energy off of these wells, they seem to heal almost instantaneously. The production again seems to be pretty independent.
We don’t see a lot of communication between the two reservoirs. We have got a crew over here working on completion right now. We have got I think seven wells over here to complete before the end of the year all listed left hand side. So, it is a pretty active area for us and we’ll get the job done.
Jumping over the west side over and we’ll start up in the McKenzie and Williams County. Again, this has been really what our emphasis has been mostly in 2012 and certainly as we go into 2013. Again one of our pilot program is going to be north of the river, the other one's going to be kind of down about 20 miles south of that area.
We're starting our Koala area. This is a very prolific area. We've just gotten great numbers of this whole block. We're currently completing three wells here on our Koala block. They're all flowing back in that 2,000 barrel a day range. We don't see anything different. So we go from really Bakken to Three Forks and I’d encourage you to look at our numbers in the back. To give you a little simple; our Three Forks wells are all identified by a three at the very end of our numbering system and you'll see, the first two wells that we drilled in this area are the wells here in five and six. One was a Three Forks well, one was a Bakken well and after 360 days one averaged right at 600 barrels. Three Forks was slightly less about around 530 I believe; so very similar type of production coming out of these wells.
We've got disposal wells drilled in this area, pipelines are being laid, oil lines, gas lines are already in place. So this is an area we’re going to continue to develop as we move through 2013. We got a rig sitting here just south of the river developing this whole stretch here right now.
Okay we'll talk about our first block. This is our pilot area and a Smokey area. We're going to do this a little bit different than a Polar area in that we've already drilled two wells in this area. We're going to frac them here in the fourth quarter. One's a Bakken, one’s a Three Forks. We have a rig sitting on the south side, we're going to drill three additional wells up to the north. So that'll give us a total five. We'll probably complete those in the first quarter or probably the second quarter and then we'll come back in and drill seven additional wells. So we're going to get a little bit idea (ph) if we pull a little pressure of these things what kind of communication we see between the two wells.
We have a four well pad that we've currently completing right now. On this block of acreage you'll see a lot of numbers come out, and again they look very strong. So they look very good. This is a second program again, we're going to go in right next to, these are a couple of good wells we have, we’re going to go right next to them. This is our 12/80 pilot program. This one is totally undrilled. So we're going to drill all these wells at the same time, more or less and then we're going to come in try to frac them with two crews and hopefully get them all completed within a pretty short time frame. We'll have our own disposal well drilled on this block of acreage, pipelines will be in here. So once we've turned these things to production we should be able to keep going. So we're excited about this. We gotten some prolific numbers out of this whole area and it's been quite good and this is a block of acreage we acquired late in 2011 and early 2012. Again we've got a whole list of wells over here to get completed. They all should be done here by the end of the year.
This is the area down the Southwest, kind of an extension of the (inaudible) area. This is a little unique over here and I think what we’re focused on, we’ve got a rig running currently down here in the bottom. We’ve going to drill two wells. They’re both in drilled in the Three Forks. Down here as we see, as we come from the Northwest and the Southeast, we see a thinning of the lower shale, we lose the middle Bakken and so basically you have Three Forks sitting underneath the upper shell. We think Three Forks is your primary play here.
There is some very strong Three Forks wells right down to the South here. This is kind of the Lois & Clark area that Winding (ph) refers to and they’ve got some really good wells out here. So we’re anxious to move along. Again, this is one of the area we’re probably going to go a sand and resin coated sand completion. We don’t have the reservoir pressure here that we have the deeper part of the basin. We can bring our well costs. We think we get down probably in that $7.5 million to $8 million range fairly quickly as we drill these things. So stay tuned.
Same way up here in the North. This is up in the Williams Divide area. Just most of our acreage is Williams. The county line moves right along the top. This is an area we had three wells drilled when we acquired these properties. We went in and completed the three wells in different manner. First we used full ceramics on just to mirror what we’ve done in another areas. Second we did pull sand and the third we did sand tilled with resin coated sand.
Again just an effort to bring our cost down, these are not for same (inaudible) up here. We’re chasing probably 400,000 plus or minus type numbers up here as compared to the larger ones I just went through in the other blogs. We’ve produced more water up here. We don’t have the gas. That’s all things that we look for in the other areas that we don’t have unless you don’t get high IPs, you got to put these wells on pump almost immediately.
We’ve got finally a couple of really nice completions here and really all three wells as we look at them, after we have finally got them on pump and understand the reservoir little better; they’re doing pretty well. So we’re going to continue develop this area. We’ve got pretty good infrastructure up here, we’ve got oil, we’ll be trucking our oil, we’ve got gas lines in place and we’ve got our water system in place. So you will see a little bit development here in 2013.
Talk about financial structures a little bit. Again I mentioned the bonds. We’ve $800,000 million in bonds out due 2019. We’ve got a little bit drawn on our revolver at this point. Other than that we’re absolutely plain. We continue to hedge our product as quickly as we can. We do have some limitations based upon our revolver. Generally speaking, we can get to about 80% of our proved reserves. So we’re going to continue the envelope to (inaudible) these on. We’ve done mostly slots in the past, just because the price of oil has been so strong. So we’ve got roughly 12,000 barrels I believe in 2013 hedged. Again, if we look for averages up in the 30,000 we need to push this number up a little bit. So you will see us layer additional hedges on here.
Talk a little bit about transportation up here in North Dakota. That’s been the big build out, I think from an infrastructure standpoint. I think today there is nearly 15 real facilities, capable of moving about 500,000 barrels a day, which is phenomenal I think, how quickly this has been developed. I think, it’s indicative also, when you look at the differentials in this basin, they’ve narrowed considerably and I think that’s a direct reflection of the oil moving by rail into different facilities.
Up in our Polar block, it’s near, it’s called Epping Rail facility. Some of that oil is actually going to the west coast, up to the (inaudible) refineries that (inaudible) owns. So that’s the first movement to the west that we’re aware of. Other oil is going into Philadelphia. There is talk getting up to Montreal. I think as we move through this thing you’re going to see these differentials tighten in the basement considerably.
Our opinion with the rail build out and the pipeline build out, we think we’re going to stay ahead of production. Our current production in I think is little over 700,000 barrels a day. Again, you can see 500,000 can move by rail. So we’ve got plenty capacity to date and I think there are several pipelines in the works to enlarge this. So we feel pretty comfortable as we move through this. Again, this is just kind of a map of the U.S. pipeline system. The whole key is really getting oil out of the Williston area, trying to avoid this bottleneck, Clearbrook down to Cushing and again via the rails I think we’re accomplishing this.
I guess in summary, I think the company is well financed at this point. We are not concerned about our financial capabilities here. We are going to push forward in 2013, again our rig counts coming down but let me point out our number of wells drilled will be the same or more, again because of the efficiencies we’re seeing out of the base.
I think at this point again, we feel very comfortable on the quality of our acreage. We are not concerned with the Bakken, what the Three Forks are going to yield. Now our whole focus is trying to figure out how many wells we can drill in these spacing units. I think, again, it’s paramount that we do this work early and we try to figure this out so we can get all of our wells spaced properly if we go forward.
We’ve got a great relationship with Halliburton. Again, we are running two frac crews. We’ll probably go to one as we go into the first of the year. The weather always gets a little colder up there and it’s little tougher to do completion. So we’re pushing as hard as we can to get as much work done before the weather really sets in and then try to back off a little bit and then we will wait spring, should have another flood of wells to come. So we'll keep moving forward in that regard.
Let me stress to the entire basin, how much the pressures come off the cost side of this thing. I can't tell you enough about what we've seen from that side of it. You've seen the service side really continue to expand out. There is now more service available, probably than ever. The rig count has dropped off a little bit but the rig count again is kind of a small part of this. It’s the number of wells being drilled that’s most important and I think that number is still about the same.
So, I feel good about the cost. I think we're going to see some additional reductions. There is also not cost from a standpoint that we think about. One of the things we’ve noticed, like in liked in Halliburton’s cases is that they continue to build our their equipment side of not bringing in new crews. So all of a sudden when we have breakdowns on the completion side, we can go to Williston or Dickinson and we can get a replacement part within few hours. We just have to wait a few days. So those are the efficiency's that you are going to see and that's how we're driving our cost down.
At this point, I think we’ll just open up it up for a little Q&A. Again we have several things in our appendix reserves, production numbers, inventory. This inventory, we took it out and put it back in the appendix because I think it’s kind of a moot issue at this point to figure out really the density of the well bores and we believe that we have a ten year plus inventory of wells to drill. So we’re not worried about having enough work to do here.
So, with that we’ll open up to Q&A.
Thank you Lynn. Just to let you guys know, there's a mic roaming around if you want to take it. Let me just start this Q&A session by asking you about something, a particular issue that investors in Bakken are pretty much hawkeyed on and that is well cost. You've guided to a well cost in the middle 10.5 million. We one of your similar operator in the Bakken yesterday presenting and they guided to a number almost 15% to 20% lower than the $10 million. Just specifically where do you see your well costs trending down and which specific buckets do you see as areas of, rather rooms of improvement?
So, again today, we kind of throw out this $10 million - $10.5 million number. I think our AFEs that we’re writing today with current well costs are below $10 million. I guess I’d have to know who it was and how the completions were because the biggest difference is between ceramics and sand and we use roughly 4 million pounds in completion of these wells. Sand is in the low teens, ceramics are about $0.50 plus or minus and so that is your biggest item. So you can quickly get $1 million, $1.5 million off these wells just by going to a sand or even a resin coated sand. You can drop each costs quite a bit. So we watch all these other operators, the well costs they put out. We also see their AFEs and we find that we’re all very similar. It’s not as big divergent as it appears in the public arena at times but it’s primarily the ceramics versus sand, that is your biggest cost difference between operators.
And given that you will continue to use ceramics, do you see that well costs sort of flat lining as is or do you see an area of improvement going forward?
I think they’re going to continue to improve. We are seeing cost continue to come down. Our biggest cost saver was obviously on the drilling side. The efficiency is weak driven out of the play, by changing our drilling base down, that was number one. But I would across the board you’re seeing probably 10% to 15% reduction in cost. Trucking is certainly much more available and used today. Those costs have come down all over across the board, I think, clearly today 65% of our well cost is in the completion side. It is pretty simple to see where we got to drive some more cost out. That’s where we’ve got to continue to get more efficient.
And then the next issue, there is a lot of folks out there who are excited about the potential for Three Forks. You’ve given a UR (ph) range; two parts to the question. First is you’ve given a UR (ph) range of 650 to 750 MBU for the middle Bakken, I’m guessing. If you could just explain why the range, where exactly are you seeing the lower or part of the numbers versus the higher and then with the limited amount of drilling you’ve done in Three Forks, how do you see those URs (ph) compared to the (inaudible)?
Good, when I go to our Bakken, and I think we’re probably 750,000 to a million. I’m talking about the majority of our acreage and we’ve got the numbers out there. We have got Netherlands sold as our third party reserve work. These are numbers that they’re giving us. These are not internally generated numbers.
When we look at the Three Forks, initially we thought it would be significantly less than the Bakken, it was going to be 60%. Again I would draw your attention to some of our production numbers. We’re not seeing that big a disparity between the two. So I think we’ve got some Three Forks wells that are probably certainly in this 650,000 to 750,000 range, maybe as much as 800 in some areas. So, we’re very pretty encouraged from what we are seeing of Three Forks.
Now we’ve drilled wells in the upper bench, middle bench and again we’re getting good wells out of both the areas. We’ve also drilled wells down the middle of those two and again we think we’re fracing into both of them. So we don’t really believe that they are separate reservoirs at this point but we don’t have update to say that one way to another and that’s part of what we’re trying to accomplish here in 2013. So, the Three Forks in certain areas is more prolific in the Bakken. You look around the basin, there are certain areas certainly around the Three Forks that’s incredible and probably exceed what the Bakken does.
I just wanted to add on that ceramic and sand question. A couple of operators, big operators here had presented in a day and what they told us like they have been using sand instead of ceramics and what they have realized like after, and in terms it may not even give you bigger IPs but after 12 to 15 months, the results from sand versus ceramics is almost the same. So like why not to go chose sand where you can offload $2 million and does it does anything to decline curve (inaudible) using sand versus ceramic?
So again it’s, where the wells are, what the pressures are and I don’t think it changes your IPs. We don’t think it changes your first year’s production at all. We think we can get same results from sand as you can ceramics. Our goal is actually what is our total decline rate? This is the hardest part about our business because it’s out there in the end of the well. Quite frankly, the first well drilled here completed, this was by EOG in 2006. So it’s five to six years old at this point. Our oldest well is only three years.
It’s hard to put a lock in. A lot of this our modeling work that we’ve done. We’ve done lot of science behind the ceramics, use of ceramics. What happens if we actually get a total decline rate of 6% as opposed to 7%; we model 7% today, and so it is encouraging us to, they think it’s going to be lower than that with what they’re seeing out of our wells. We think that’s what’s important. It’s not the initial IP rates, it is not your initial production. Sure that’s all great from a cash flow standpoint but we’re looking at this thing and trying to see what it’s going to take to keep this reservoir open for the full life of the well.
Again, there is a not a right or wrong answer, I think at this point. Another way we look at it, we think it probably takes 20,000 to 25,000 barrels of oil to cover our additional cost. I’ll give you, throw $2 million more cost. We achieved that with a pretty relatively small amount of oil. For a change in 800,000 EUR wells, we’re talking 3% or 4% of the well max.
It seems to be the right thing to do and again it’s interesting to watch other operators and and how they talk to the public and we see it from an operation stand but there's a lot of people using at least a portion of ceramics, maybe a mixture of two-third sand, a third ceramics. Our idea as well, okay you're going to save a little bit money by doing it that way but if your sand is crushing, it's clogging up the fractures that your ceramics are holding open, aren't you being a little bit foolish up front, spend a little bit more money and try to keep this thing open. We could be wrong guys. I can't sit here and tell you we're absolutely doing it the right way, but we do feel strongly. Again, where our acreage is located, the pressure tests we've done, we do believe the sand will crush. So, I guess we'll have to see in five years, six years whatever it is. Anyone else? Yes.
Because of others that, service costs have been coming down all year this year. Last year at this time service costs were obviously an issue. They've come down nicely throughout the year this year. When do you think we sort of hit bottom on the low hanging fruit of reducing the cost of all the services come off or do we get to point very quickly in 2013?
Yes, I think it's an interesting question and again I've focused probably on the completion side more than anything because that's where the big ball of our cost is right now. Again we use ceramics. That’s a big part of our cost structure. If you sit here and listen to this you would think there's got to be some cost reduction still to come in those type of items. There are more sources of ceramics than which I've asked. We've used lot of the U.S. stuff, carbo, single bane but we also use some Chinese stuff that's been stored, that’s QCed and we feel comfortable using it; we've had good results with it.
So I don't know when that cost is going to come down but we believe that’s some additional cost reduction in that direction. I think the other part of us, as we go to more and more pad drilling here, or more wells per pad -- we've drilled all of our wells on pads – but we're starting to go to four, we're going to try some larger pads. How much more efficient are we going to get? So it's not always cost reduction for our items, it's our efficiency that we can drive out of this thing. We were concerned, we went to cemented liners and all of our wells today we're running with cemented liners, where you use plug and purve technique when we complete these wells.
Initially we were very concerned from a cost standpoint it would take us too long to do this. So we went to the (inaudible) fracs and all that is, you complete one well while you're perforating another one, you just kind of go back and forth, so wire-ine time is critical item here because when you first started out 20,000 feet out from the surface, your wire-line time can be four to five hours. Well, we didn’t want to have that time sitting out so by doing those zipper fracs we can be fracing while we’re wire-lining the next one and keep on going. We’ve done as many as three wells at once. It worked quite effectively.
Again, I think there is some things we can internally do still to drive some of our time out of this and time is money and so I think if you look at the basin overall, it’s incredible what a change in years made. The infrastructure, restaurants, hotels, housing and everything in North Dakota is grown considerably over the past 12 months. I think the general attitude with the population is very positive. Unemployment is under 1%. It’s crazy, really it seems its (inaudible) is working and they’re happy they’re making good money and I just think the attitude is so positive here and I think that’s going to help drive down more cost because people are trying to do a good job. A year ago it was tough up here. People are worn out, they were fighting the weather, there was rigs everywhere. It’s just changed night and day from where we were a year ago. So I think those are the costs that are still to come down here and we will get more efficient.
And if I could push in a few more questions before you run out of time. You guided to a jump in the completions in 4Q. Is that over compensating for a possible downtime due to weather in the first quarter? Just pushing you bit on the ‘13 guidance, you said the CapEx would be more or less the same as service costs are trending down. Are you going to complete more wells? Are you going drill more? How do you think through that in terms of your drilling activity in ‘13?
Our game plan in all through 2012 was to bring a second crew in here for the late third quarter and fourth quarter and we’ve brought seventh rig in, we’ve brought an eight rig in through the year. Again we ended up to drill more and more wells with our existing rigs. So we ended up with a few more wells than we expected here at the end of the year. Thus our budget went up little bit but our production, I think at the end of the day is going to surprise people. We kept our exit rate, just because we’re tired of talking about it and we’ll get these wells completed and I think we’re going to surprise some people.
As we look in 2013 again, I see us a kind of working with a six rig count. I think we’re going to drill just the same number of wells we drilled this year. Our production is going see yet another good ramp and we’ll put all this stuff out there early December here and try to get the all information out there.
With that I think we’re at the time.
Exactly. However thanks a lot for coming, and we hope to see you more.
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