Lynn Peterson - Chairman and CEO
Kodiak Oil & Gas (KOG) Barclays 2012 CEO Energy-Power Conference September 6, 2012 ET
We like to get started with our next presentation. I am pleased to welcome to our conference Kodiak Oil & Gas. With us from the company today for the presentation is Lynn Peterson, Kodiak's Chairman and CEO and I'll turn it over to Lynn.
Good afternoon. Thank you Jeff for including this year. This year is our first opportunity for Barclays and we're glad to be here. I am going to preface my presentation that we just came from Williston. We spent a day in the field. I am very pleased what I saw. I think this place continues to improve on a daily basis almost. Things that we've all talked about in the past have been overcome. I think we have a bright future here.
We'll skip the forward-looking portion of this. You can read that at your own leisure. I think we're pretty easy story to understand. Kodiak is a one basin show at this point. Nearly all of our assets are in the Williston basin, primarily in North Dakota. We continue to have an interest in some acres in South Western Wyoming, we don't talk about much anymore but it's mostly a gas play there that continues to move along.
We’ll talk about a little financial situation we move through this. I think company has been in a great shape. We've taken out some debt over the last year. We've doubled the size of the company. I think we're in excellent position here as we move through 2012 and enter into 2013.
This is probably the slide that we get the most discussion on. It's our production growth. It's a big game changer going from one year to the next. It's something as we did our acquisitions late last year, early this year that we had some clean-up work to do; it took a little bit time to get out of the gate. I am extremely pleased to announce that I think we're clicking on all cylinders right now. From the drilling standpoint we've made great improvements in our drilling times. From a completion standpoint, we tried to lay this out to enter the Q2, how were going to achieve these particular numbers, average of something between 17,000 and 21,000 for the year and ex-rate of 27,000.
We currently have one full time completion crew. We are completing on average five to six gross wells, four to five net wells every month. We'll continue to do that through the end of the year with that crew. We'll bring a second crew on here late this month or early next month that will probably have for balance of the year. I'd like to know we're actually not trying to catch up; this is really just kind of the program that we laid out the first of the year as we brought on more rigs. Lot of our three and four well pad drilling is coming to the completion stage. We had some mechanical issues we've talked about in the past. We've got all those wells or most of those wells patched, ready to go. We anticipate having them all completed here by year-end. So we've got a lot of work to do in the next four to five months. We're excited about and I think these numbers that we've laid out to everybody are solid.
One of the things we've worked really hard on is trying to bring our lease operating cost down. I think it's very important. If you can see the change we made between Q1 and Q2, and probably more importantly even going back to Q3 and 4, 2011. We've driven these costs down in the $5, $6 per barrel range, largely through our work we've done on our water, both secure in water and then obviously the disposal of the water. This is our number one portion of the LOE. We hired some guy late last year. We've not got three guys involved in this part of it. We've seen a dramatic improvement. Are we going to continue to see a downward trend? We hope so, as probably it's not going to be as dramatic as you saw between the two quarters, but we think in this $5 to $6 range, it's certainly solid number to work forward on.
Our capital expenditures, we went out to $585 million budget. We tried to lay out that we do have some additional cost going into mostly non-operating properties. We put 650 on this; I think it’s a fair number probably at this point. We did say on the Q2 that we were running seven rigs. Couple of weeks later we moved to an eight rig and we did this because as the rig became available on the area we wanted to drill a few wells in, we think the economics of display are very solid right now. We brought our well cost down.
To give you an example, I think when we look back first half of the year, our well cost were probably run in the $11.5 million range. Again, I would focus on location of our acreage; we're in the deeper part of the basin. Typically our wells are going to run between 10,000 and 11,000 of vertical feet, may be 10.5 and 11.5 (ph). We've seen those well cost come down nearly 10 from that number already. We think today we are in that $10.5 million range. And a lot of that's been driven by the efficiency of our drilling team that has done a great job of bringing our drilling base down from kind of a mid-30s number to a low 20s number today.
We've also seen almost across the board reduction in costs. Again, I think this speaks to the volumes to the basin, this base under stress last couple of years. People were trying to save acreage. We were trying to get around, prove everything up; services are trying to catch up with the drilling rig count. I think we look today; the drilling rig count's been pretty stable, little over 200 rigs. I think the quality of all operators is improving out here. I think everybody's getting more efficient. The service side continues to build out. I know in our case we use (inaudible) for all of our completion. They've done a great job of bringing in additional equipment. We now have backups that we didn’t have two years ago or year ago or six months ago. So all of a sudden if we have a breakdown on our completion, we get a new equipment coming out of the field offices within hours, it used to be within days. So all these things are helping us improve our efficiencies here. And I think this place headed to better time certainly.
We are going to continue to run eight rigs probably for the next three months. At that point we do have one rig that we are considering laying down. It’s the only rig in our fleet that we have a skid package on or walking package. As we do all drilling on pads, two to four, we're going to try a six well pad, we want to see all our rigs be equipped with either the skid bags or pads. So we're a walking package. So you could see us go back to seen rigs as we go into 2013.
This slide of our EURs, again, we use $10.5 million well cost. I think it’s a very fair number today. These wells are really performing well. As we look to core areas of our acreage, when I speak for our areas, we have about 155,000 acres in total. I would tell you probably 25 of that is probably a tier two type property. The balance is pretty solid acreage and we are going to see EURs 650,000 up to 1 million barrels. There's been a lot of discussion and recent transactions. These numbers aren't unusual. We all have wells that are doing the same type of performance. We continue to talk a little bit lower numbers just from a public standpoint but these wells are really delivering today.
The other thing I think that comes into play here is the barrels of oil equivalent. As we move from the eastern side of our play over in Dunn County to the western side in McKenzie County, you see a dramatic change in the oil gas ratio. In Dunn County we see a 600 to 800 GOR ratio. On the west side you can see a doubling to more of that. From a gas standpoint and certainly when we look at the economics of the play, it’s the oil that's driving these present values. So I think there's a really solid economic well.
Lynn talked a little bit about our acreage, when we talk about the Dunn county, that's kind of our east of the Nesson, and we're going to break the presentation around these two eastern kind of west of the Nesson. So give you a little idea where we're headed.
Just quickly to remind everybody what we're talking about. We talked about two formations here. The middle Bakken which is sandwiched between the two shales, which are our source rock. We're working on the Three Forks. The Three Forks is a much larger interval. There's a lot of work being done on the various ventures at this point. From Kodiak standpoint, we mostly drill the upper bench; we're well aware what's going on out here. We're evaluating it.
We think it's all positive and we've got a slide in here we talk about drillable locations. This number is going to go up from where we're at today. It's not going down. So I think this is all positive, a highly private system continues to surprise all of us out here.
Speaking of our locations again, we show roughly 800. The way we do this is the areas we tested some well bore density, we're using four Bakken wells in most of these areas. We then drilled our first bench at the Three Forks down between those. So we show Three Forks, four Bakken wells, a total seven per drilling unit. Again this is kind of a math quiz but I think in reality as we look forward to hear, we continue to work on well bore density. We've taken wells from 1,300-1,400 feet apart down to about 1,000 now which is going to allow us to test more places that fit well within the Bakken formation here. Today which is still early, we have not seen communication issues. We're encouraged from what we're seeing. We're going to continue to push forward on that. We continue to use our four, but be aware that it's not only us, other operations in the basin do the same thing, I think we're all starting to get similar type results.
Again, we show three wells in the Three Forks. Does this go to a larger number? Certainly, I think it has very high potential doing that as we evaluate the second bench, look at communication, figure out what the best way to drain. So, we've got somewhere 10 and 12 year's inventory, we're delighted about it.
We'll start over on the east side, Dunn County; we started out in 2007 and 2008. We drilled probably the most wells in that particular area.
Again, we're looking for EURs of this 800 up to a 1 million barrels. They are very consistent where we're seeing across our block of acreage. We've tested the Bakken and all of our blocks we've tested the Three Forks and a lot of them. We're seeing real similar type of numbers. Generally speaking, we probably put a little bit lesser reserves on the Three Forks than we do the Middle Bakken. In some cases, we're surprised with the Three Forks delivering. So, at least give you an idea.
Again, drilling costs are coming down. We use $10.5 - $11 million just kind of be conservative, but we do believe this number is going to further south as we get more into development mode and the industry, service side continues to build out.
I'm not going to spend too much time on this. It kind of lays out. We've got three rigs running in this block right now. We've also got an AMI with Exxon Mobil over here. They have two rigs running on us, where we have 50% working interest with them. We spend a lot of money over here right now. These wells are performing extremely well. Again, we can document with third party reservoir engineering, the type of numbers that we just put out. We're going to probably compete between yearend a dozen wells over here. It's part of our program here through end of December.
Infrastructure's been build out here. We continue to have a little bit of growing pains. The system I think has some restrictions on it right now, that all of us operators would like to see improved. I think with time, we hopefully will see that. Right now, we're not able to sell much of our gas production. Fortunately as I mentioned earlier, our GOR over here is much lower than on the west side. So it's not material number to us but it's certainly something we want to improve upon. So again, we have oil, gas and water, all hooked up here for disposal. We need to continue to work on improving this.
To go over the west side here. What we're doing in the McKenzie County. Again, I think we're starting to see results from an oil perspective that are very similar to what we've seen in Dunn County. When you look at IPs again, I think some of the numbers on the west side, have a tendency to be a little larger because of the larger gas component of them. But certainly from an economic standpoint, its oil that carries the value here and so we look at these areas a little bit differently in that regard and I guess I would caution everybody to look at the oil side of this, not necessarily the barrels of oil equivalent because I think things can get a little bit skewed.
Again, well costs very similar. On the east side, we're about 10,500 vertical feet drawn out 10,000 foot laterals. Here on the west side, most of our acreage is in the deep part of the play. We're probably 11-11.5 vertical depth, again, 10,000 foot laterals. So, similar type cost somewhere in that 10.5 million plus or minus range.
The Koala block is right south of the Missouri river in the northern part of McKenzie County. So the first block that we acquired on the west side back in 2010. We've now drilled a series of wells up there. These are really good wells. We've tested both the Bakken; we've tested the Three Forks. All of our production numbers are back in our appendix. I'm not going to go into it. We put our 30-60, out to 365 day numbers out there. And you can go through all these well and I think you'll start to see a very consistent number through all of our wells.
We're on a three well pad right now. We just completed them last week. We're flowing the wells back right now. I can assure you these are good wells. They fall right into the same range that we've seen on the others. So, we're delighted this area. We've got a rig run on a current three well pad. We're on our last well of pads, so we'll get those wells completed probably here in the fourth quarter. But extremely good reserves. And again, I think they do compete with the Dunn County in that regard.
Just drop into the south, 12 miles. Again, these aren't very far apart. We tried to block our acreage out. You'll see we have typically pretty high working interest over here, anywhere from 85 to 95%. Again, we've got about a dozen wells to complete here by the end of the year. We have two rigs running on full well pads that are just about finish up here. We're getting them all done fourth quarter again. We'll be able to post some numbers for you. We did some work here in the Q2 and Q3. We're very pleased with the wells. Both as in Koala we spent a fair amount of time building out salt water disposal wells since last quarter. We've got them all drilled. We're still in the process, laying lines to them. Oil and gas in both of these areas are hooked up to third part. Pipelines and in both cases, we're able to sell nearly 100% of our gas produced and oil to repeat, is moving by pipeline.
Just north of Koala, as we go into southern Williams County, again, this is a block we put together and acquired late last year, early this year. We're delighted with the numbers. We started out doing some completion work off of wells that were drilled by the former owners. We do it little bit different style completions. We are believers in ceramic in the steeper part of the basin. So all of our wells we've talked about are completed with 100% ceramics. We use about 28 stages per well. So we're roughly around 325 feet per stage and that's kind of our completion methodology at this point.
We've drilled a series of wells up here since we took over. We currently have two rigs running. We'll basically have two to three rigs running as we exit the year and try for most of 2013. Again, I would put you back to the appendix, these numbers, the IPs, the 30-60-90 day numbers are very similar to what we're seeing in Koala. We're very pleased with the production coming out of this area.
This is the one area we still have some gathering work to do. We've got all the wells hooked up to gas pipelines. There is a little bit of work that needs to be done by One Oak and it's in the process right now of putting in some additional pipe in the ground. Hooking us up some additional compression which should allow us to sell a bigger percentage of our gas.
Again, this is one area we're probably flare more gas than we certainly want to be and I think this should be remedied here within the next 30 to 60 days. Certainly we go through the fourth quarter; we have seen improvement down there.
Again, I believe these wells are very similar to what we've seen at Koala, Smokey as far as the EURs. Somewhere in that call it, 750 to 1 million barrel range. We're very pleased with them.
The blocked end of the south west, McKenzie County we refer to as Grizzly. We see a little mixed bag down here. We have wells that we think are similar to our Smokey block and on the eastern side of this block of acreage. As we go to the west, we see a lesser type of reserve. Wells are getting shallow or well cost are becoming down. We're probably looking for reserves in this area say, 400 to 600 on the western side of this block. Again, probably 600 to 750 on the eastern side. So, spread out a little bit. I will reiterate as everybody wants to talk about IPs. They are a 24 hour number. When we look at these numbers, how these wells are going to Grizzly area, they don't come out to a big flush production numbers. We don't get that quick burst. The wells do not decline. I mean these wells are very flat from a production standpoint. So ultimately we're going to get a lot of oil out of this area. It's just going to be a different profile than we see from most of our wells.
We are going to continue to work this area. We'll have a rig down here, probably late this year, drill couple of more wells and see what we can bring forward. This is the only area of our block of acreage that I feel is really kind of a tier two property. Where we're looking for reserves either dramatically different than what we've just talked about.
We've got a total 24,000 acres up here out of our 155. Reserves up here we believe are going to be in that, call it 250 to 400 range. We're going to have a few 500, we believe that, but on general basis, we think they are going to be lower than we talk in other areas. We're also much shallow here. We'll come now to the basin, these wells can be drilled much cheaper than what we're doing down in the heart of this play.
We haven't drilled and completed anything ourselves. We completed two wells that we acquired as part of the acquisition work. When we look at an AFE in this area, I think we've got to drill these wells for somewhere around $7.5 million plus or minus and I think we're probably tend to achieve probably somewhere close to 20% rate of return. So, there was a day when we'd be pretty delighted about our 20% rate of return. We've got a little spoilt drilling down through the heart of this thing where we're achieving much higher rates. But we'll continue work this out as we go forward.
Hedging, we continue to layer these on. Certainly oil being back here in the mid-90s, is a good number for us. These wells work all day long at these prices. So we're actively pursuing this. We're starting to work mostly on 2013. With an end-game of time to at the end of the day, hopefully being about 50% hedged for the year, as we move forward, it's all based upon our accrued reserves and we're working with our banking group that continue to be excellent partners for us here, trying to protect our CapEx.
Infrastructure build out. We get this question a lot. I think one of the most encouraging things here is what we've seen build out in the rail. So I think there is five or six facilities today, most of these are moving anywhere from 60,000 to 90,000 a day of production. The most recent one, that's closest to our polar block that we just talked about, is the Epping facility. Noted that they finally delivered their first production to the Anacortes Facility out in Seattle. That was the first outlet to the west coast there. So I think that's really encouraging that the oil started to move by rail there. They get their unloading facility built. These are all positives and this really feeds into the differentials that we've all talked about. I mean it has been all over the board. It's fortunately, it tight in here in the last couple of months. I think September is going to be even better than august.
Again, I think a lot of this has to do with ability to move oil down the rail system now, get it down in to Louisiana area as opposed to moving by pipeline going over Clearbrook and down through cushion. So, in the long run, we still kind of focus on the $10 differential from WTI, that includes our transportation cost certainly to get over Clearbrook area, but we think that's probably a fair number to work forward on.
Got a hard map, a little bit into much, I think we know the system here, what needs to be done. Certainly there is continuation of build out; there's been a couple of pipelines announced. We think they will happen with time.
Kind of sum this up so we can do a little Q&A here in the room. We're absolutely where we're at. From Kodiak standpoint, this is the best we've ever been. Our operation team has done a fabulous job. I think we're actually clicking on all cylinders. It's not to say that something will happen tomorrow that will set us back it’s the industry we're in. but our drilling team has done a great job. Our completion group is moving along. We're getting better. We're getting our completion time down. We've done several two well pads, so we're completing two wells in eight days. We've been on three well pad that we did in about 12 days. So we're seeing some real consistency there.
The infrastructure is coming along. We're getting all those stuff tied in quickly. We're seeing improvement in our gas sales, NGL has obviously come down. So it's still a number that we like to achieve. It's not as big as it was here a few months ago.
We've got a great relationship with our pressure pumping services. We have a availability of services. We've got everything kind of locked and loaded here. Again, we put our numbers out; we've heard all comments about it. We're stand here, we're going to tell you, we like where we're at and I think we're going to be in great shape by the end of the year here.
With that, I'll turn it back over to Jeffery here on how we do this and go forward.
Lynn thanks, we do have some time in room for questions.
For your assumptions for the well location estimates, you assume four Bakken wells and Three Forks wells. Just wanted to know how much confidence you had in those assumptions. Have you seen anything, for example, any down space results for having to sit for over a year that allow you to basically make these assumptions or…
Okay, and please note, we take each of our blocks of acreage and we break them down differently. The areas that we show those numbers on, we feel very confident that those are our minimum numbers. Again, we're doing some work where we're tightening this up and we're not here to say that we're going to go to a tighter density by any means but I think there is some encouraging signs that certainly a possibility. I don't think we're going to go to fewer wells. I will be honest in that regard. So, Ian I think the Three Forks is probably the one area that we have a lot of movement still to come. When we put these numbers out, we're talking essentially the first bench here. As we start to develop more in the second bench, are there any communication, are they separate reservoir. Still we need time for all that to happen. Even if they are in communication, we'll probably have to drill more wells. It’s a big section and the fact that we're able to get oil out at all of this area is probably an increase in those numbers. But again, it's just to give you an idea of our runway ahead of us. We certainly have several years of inventory here to move forward with.
Lynn do you think that there will be a lot of variability across the different acreage blocks and how these eventually get spaced or is just going to be recoveries based on debts and things like that?
Well if you speak to (inaudible) blocks of acreage, I think we've actually worked most of our core areas and we feel good about that. And so we get on to the edges of the play, absolutely it does start to change. To step up north, we don't see the same density well bores that we do in southern Williams, McKenzie and Dunn. On the west side over McKenzie County, we look at that a little bit different than we do the other areas. From Kodiak standpoint, what we put out there is where really there is that we tested.
On cost, other than working on bringing LOE down through water disposal, and clearly longer term with infrastructure build out, are there any other ways to bring cost down and if so, what's the timing on that? What can we expect over…?
Well, I really believe we have brought cost down. We know brought cost down. Now, across the board, it's also on us too. We've gotten more efficient drilling these wells. On average like I said, we were probably in the mid-30s a year ago to drill well; we put liner in the hole. Today we are in the low 20s and that's a big difference for us, when you're thinking your burn rate out here on a daily basis. So those are big numbers. Now again, you're going to have your anomalies where you're going to have your problem wells. Believe me, not everything is perfect here but, we've seen that efficiency change and again, I give our drilling team a great deal of credit, change of bits, looking at things we can do. Almost across the board I would tell you that cost have come down probably in the 5 to 10% range, certainly some things are higher; some things are a little bit lower. We have seen some improvement on our ceramic pricing which for us is a big number. So all these things added together I believe, we do feel like we've driven nearly $1 million out of these wells at this point. So, where is it going to end up? I think it's going to be incumbent on our team again to continue to work some of these things, get more efficient from the completion side, continue to work on our drilling side, working our lease operating to drive all these cost down. Do I think there is some room? Absolutely. So, I like to trend on. And I will comment, it takes a while for all these things to flow through the financials. You drill well in one quarter, you complete it in a different quarter. So, it's going to take some time, but I think by the end of the year, you'll definitely see these numbers flow through.
You focused I think on core versus some of your peers, is there any more acreage to acquire in the core or can you roll up some more and then can you comment on the M&A market?
I thought we'd get this whole thing not talking about M&A, but I guess that's odd. We continue to scour this, we are very keen on looking at quality acreage, where it's located. Obviously there was a big transaction a few weeks ago, very quality acreage. The numbers didn’t surprise us at all. We believe these are real numbers for all of us. EURs that were presented are not unusual out here. We all believe we have similar type wells in particular areas. The acreage is getting picked over without a doubt, finding a block like 30,000 contiguous acreage, that's a challenge and that's why certain things go for good value. So, M&A, I can't really comment on that. Again, it's an area where well results are I think very, very solid. Well costs are coming down. I don't know too may plays that are better economic plays on what we got in the Bakken, especially when you look at the core area. The consistency between well bores, the true resource play in all sense of it, we've got a lot of work to do and our wells (inaudible) quality. So again, that brings spotlight onto the M&A side of it. So with that, that's all I am going to comment in that regard.
Lynn, I'd like to thank you for being here.
Thank you very much.